## Coal-Fired Power Plants in the United States: Examination of the Costs of Retrofitting with CO 2 

## 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 th e 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 info rmation, apparatus, product, or process disclosed, or represents that its use w ould not infringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwis e does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. Th e 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 CO 2 

### 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.govThis page intentionally left blankCoal-Fired Power Plants: Costs of CO 2 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 D ATA S OURCES .................................................................................................................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 S CREENING P ROCESS ......................................................................................................13 1.3 U NIT

- LEVEL C OST A NALYSIS .........................................................................................14 1.3.1 SO 2 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 .........................................................................................................................2 7 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 R ESULTS ...........................................................................................................33 2.2 B ASE C ASE (N O M AKE

- UP P OWER ) ................................................................................34 2.3 M AKE

- UP P OWER C ASE ..................................................................................................36 2.4 C OMPARISON WITH C ONESVILLE S TUDY R ESULTS .........................................................38 3. CONTINUING WORK .......................................................................................................39 APPENDIX A. EV SUITE DATA ELEMENTS ......................................................................40Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

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# List of Tables

Table ES-1. CO 2 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, Retr ofitting U.S. Coal Power Plants for CO 2 Capture ....... 2 Figure 1-1. Example MS Terraserver Imagery ............................................................................... 6 Figure 1-2. Example Google Ma ps 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 Se questration 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 Ca rbon Loading by Generation Type. ................ 12 Figure 1-9. Results of th e Screening Process ................................................................................ 1 4 Figure 1-10. Aerial imagery of the Coneseville plant ................................................................... 15 Figure 1-11. Let-Down Turbine Cost and Size Scaling ................................................................ 16 Figure 1-12. CO 2 Separation and Compression Co st and Size Scaling ........................................ 16 Figure 1-13. CO 2 Scrubber Cost and Size Scaling ....................................................................... 17 Figure 1-14. Current and Additiona l Recirculating Cooling Require d to Retrofit All Units with 90% CO 2 Capture and Compression at the Conesville Plant ................................................ 19 Figure 1-15. Complete Plant Retrofit........................................................................................... . 20 Figure 1-16. Example Showing 10 Percent Clos e-In Construction Difficulty and 10 Percent Landscape Construction Difficulty ....................................................................................... 22 Figure 1-17. Example Showing 30 Percent Cl ose-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 Cl ose-In Construction Difficulty, 0 Percent Landscape Construction Difficulty ....................................................................................... 24 Figure 1-20. Additional Land Requirements ................................................................................ 25 Figure 1-21. Assigned correction fa ctors for space limitations .................................................... 25 Figure 1-22. Fixed OPEX Cost Function ...................................................................................... 28 Figure 1-23. Variable OPEX Cost Function ................................................................................. 28 Figure 1-24. Feedstock OP EX Cost Function............................................................................... 28 Figure 1-25. Parasitic Load Scaling fo r Carbon Capture Retrofit Components ........................... 29 Figure 1-26. LCOE Equation and Para meters from Conesville Study ......................................... 30 Figure 1-27. Captured and Mitigated Carbon Costs ..................................................................... 31Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

iii Figure 2-1. Nameplate Capac ity as a Function of CO 2 Capture CAPEX by Unit ........................ 33 Figure 2-2. Base Case, Cumulative U.S. Coal Generating Capacity versus Incremental LCOE for CO 2 Capture Retrofit ............................................................................................................. 35 Figure 2-3. Base Case, Cumulative U.S. Coal Generating Capacity versus Retrofit CO 2 Capture Cost .......................................................................................................................... ............. 35 Figure 2-4. Make-up Power Case, Cumulative U.S. Coal Generating Capacity versus Incremental LCOE for CO 2 Capture Retrofit ........................................................................................... 37 Figure 2-5. Make-up Power Case, Cumulative U.S. Coal Generating Capacity versus Retrofit CO 2 Capture Cost ................................................................................................................. . 37Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

iv 

### Original Document (January 2010) Prepared by: Research and Developme nt Solutions, LLC (RDS) Jeffrey Eppink and Michael Marquis Enegis, LLC

Revised Version (Janua ry 2011) Prepared by: Phil DiPietro and Chris Nichols, NETL and Michael Marquis, Enegis, LLC

DOE Contract #DE-AC26-04NT41817Coal-Fired Power Plants: Costs of CO 2 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 Ener gy’s National Energy Technology Laboratory. This work was completed under DOE NETL Contract Numb er 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 Ener gy Analysis and PlanningCoal-Fired Power Plants: Costs of CO 2 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
CO 2 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
SO 2 Sulfur Dioxide TDE Top Decile Average Efficiency Ton short ton = 2000 pounds Tonne metric ton = 1000 kilograms USGS United States Geological Surv1 

## EXECUTIVE SUMMARY
Retrofitting existing coal-fired power plants to capture CO 2 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. CO 2 emissions. Also, retrofitting utilizes the base power plant and related infrastructure and so the cost and level of di sruption 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 co st and parasitic load for CO 2 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 scrubbe r, how much water is available for the unit to use, and how much space is available for the CO 2 capture and compression equipment were factored in to an estimate of CO 2 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 perfor med on AEP’s Conesville generating station. Year 2007 amine cap ture technology is assumed; 90% of CO 2 in the flue gas is captured and the solvent requires 3.6 GJ re generation energy per metric ton (mt) of CO 2 captured. Figure ES-1 summarizes the results. The 738 gene rating units are ranked from least to highest cost of CO 2 capture and unit-level cost of CO 2 capture is graphed against cumulative capacity. The cost of CO 2 capture in $/tonne (or $/mt) avoided is calculated from the cost of electricity (COE) and the CO 2 emissions of the generati ng unit with and without CO 2 capture as shown below.

Cost of CO 2 capture = [COE retrofit – COE base ] / [CO 2 /kWh retrofit, produced – CO 2 /kWh retrofit, 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 CO 2 capture of $42/mt CO 2 which places it at the 30% percentile. That is, 30% of the coal fired generating capacity has a CO 2 captured cost less than $42/mt CO 2 . The other 70% of coal-fired capacity h as a higher cost. Figure ES-1 shows an inflection in the curve where the cost of CO 2 retrofits begin to increase more rapidly. This inflection occurs at a capture cost of 50 $/mt CO 2 (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 CO 2 captured by roughly 5 $/mt CO 2 . Avoided cost, shown in equation {2} below, is an alternative evaluation metric.

Cost of CO 2 capture = [COE retrofit – COE base ] / [CO 2 /kWh base, emitted – CO 2 /kWh retrofit, emitted ] {2} The avoided cost calculation, unlike the capture cost above, includes charges for make-up power due to net power losses associated with CO 2 capture and compression. A coal-fired generating unit with CO 2 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 CO 2 emissions associated with the purchased power are included in the COE and CO 2 /kWh for the retrofit unit. Table ES-1 below shows the results for cost of CO 2 capture and avoided cost for the 10 th , 50 th , and 90 th percentiles. The avoided cost is $40 to $50 per mt CO 2 higher, based on a median cost for make-up power of 7.6 cents/kWh.Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

2 Figure ES-1. Cumulative Cost Curve, Retr ofitting U.S. Coal Power Plants for CO 2 Capture

Table ES-1. CO 2 Capture Retrofit for U.S. Coal-fired Power Plants, Summary Capture Cost and LCOE results (based on 85% Capacity Factor)

Cost of CO 2 capture ($/mt CO 2 ) Cost of CO 2 avoided ($/mt CO 2 ) 1

10 th percentile 34 73

50 th percentile 41 90

90 th percentile 57 107

Future work includes (1) developing cost curves for cases with advanced CO 2 capture and compression technology, (2) incorporating the possibility that the retrofits for CO 2 capture include refurbishment to improve the heat rate of the base generating unit, and (3) including the

1 Includes cost and GHG emissions for ma ke-up power which varies by the re gion. Median cost value is 7.6 cents/kWh (min/max 1.1/ 9.9). 

## (282 Power Plants)Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

3 cost for CO 2 transport and injection underground, taki ng into account the variation in pipeline distances and the injectivity of proximate sequestration repositories.Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

4 

## 1. METHODOLOGY The effort compiles relevant da ta 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), opera ting expense (OPEX), and parasitic load associated with retro-fitted carbon capture technology applied to th e 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 CO 2 at the plant gate. The cost of compression and purification to pipelin e conditions are included. Not in cluded are the cost of pipeline construction, CO 2 transport, and CO 2 injection and storage in underground geologic formations.



### 1.1 DATA SOURCES
This section identifies the informati on sources used to populate the model.

1.1.1 NETL Studies Results from the following NETL studies we re used. These reports can be found at http://www.netl.doe.gov/energy-an alyses/refshelf/Default.aspx . The primary reference used is the Conesville study (listed first). Th e report provides the base value for the cost and parasitic load associated with implementing retrofit CO 2 capture 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: Bitumi nous 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, Augus t 2008 (April 2009 Revision)

 Roadmap for Bioenergy and Biobased Products in the US (Bioenergy Roadmap study), Biomass Research and Developm ent Technical Advisory Committee, 2009Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

5 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 th at were used in the database. The database contains ten years of historical data. To provide a more valid re presentation of plant operations, the model uses ten-year averag e 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/energ y-analyses/refshelf/PubDetai ls.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. Th e 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 Te rraserver 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, requir ing screen capture an d georegistration, processes which were performed for this projec t. 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 ha d the best available imagery through Google Maps.Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

6 Figure 1-1. Example MS Terraserver Imagery

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

7 1.1.4 Water Availability Due to increased cooling loads associated with amine-based CO 2 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 captur e and compression cooling needs. Data on the renewable water supply was provided by the U.S. Geological Survey (USGS), 1984, National Water Summary 1983—Hydrol ogic Events and Issues: U.S. Geological Survey Water-Supply Paper 2250 . Renewable water supp ly is defined as the sum of precipitation and imports of water, mi nus the water not ava ilable for use through natural evaporation and expor ts. 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 ar eas 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 thos e plants in areas wher e further withdrawal from local aquifers is problematic.

Figure 1-3. Water AvailabilityCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

8 1.1.5 Potential CO 2 Storage Repositories GIS data on saline aquifers acceptable for carbon sequestration and the network of existing CO 2 pipelines was obtained from NETL’s NatCarb website www.natcarb.org

. Figure 1-4 shows these data. GIS data on existing oil and gas produc tion 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 producti on, or dry field. Figure 1-5 shows the USGS oil and gas data.
Data were available from NatCarb on volumes of CO 2 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 CO 2 / km 2 . It should be noted that not all areas identified in the NatCarb and USGS sequestration opportuni ty 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 DatasetsCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

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

Figure 1-6. NatCarb Sequestration QualityCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

10 1.1.6 Price Projections for Commodity Power Because the generation profile in a carbon-c onstrained world would significantly differ from the current power generation makeup, th e 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 Mass achusetts (Waxman-Markey) passed in the U.S. House in June, 2009. The Waxman-Marke y bill addressed many issues related to climate change, but required a 17 percen t reduction in greenhouse gas emissions, from 2005 levels, by 2020, and an 83 percent reductio n by 2050. The bill also required utilities to obtain 15 percent of their electricity from renewable source s, by 2020; and to demonstrate annual electricity savings from efficiency measures. Figure 1-7 shows the price for purchased po wer and the associated GHG emissions. There is a wide variation geographically so regional data from the NEMS Electricity Market Modules (EMM) were applied usi ng 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. Fi gure 1-8 shows assumed carbon loading that were inputs into the NEMS model a nd also regional generation results.Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

11 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 0.073Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

12 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 13TotalGeneration(10^9KwH)

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

‐ TypeCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

13 

### 1.2 SCREENING PROCESS Prior to performing the cost analysis, a por tion of the population of coal-fired power plants was screened out as being not amenable to CO 2 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 CO 2 repository within 25 miles.
Figure 1-9 shows the screening criteria app lied to the population of power plants. The left panel shows number of plants and the right panel s hows generation capacity. Fifty percent of the operating power plants we re excluded from the analysis, primarily consisting of smaller plants representing onl y 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 CO 2 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 operat ing at a site. The current analysis considers neither the injectivity nor CO 2 storage capacity, only the distance from a potential long te rm storage source to screen plants. A parallel task being conducted by NETL aims to de velop information on the “quality” of sequestration targets. That da ta 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 seque stration targets.Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

14 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 CO 2 capture retrofit. The following is a list of adjustments. Each is described below.

 Scale the let-down turbine and the CO 2 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 CO 2 scrubbers, CO 2 absorbers, sulfur scrubbers, and sulfur polishers)

 Add cost adjustment for generating units where the CO 2 retrofit will require moving coal piles, parking lots, or other struct ures (0-40% adjustment applied to CO 2 compression and cooling towers). This includes the co st of purchasing extra land where possible.

 Apply economies of scale discount for multiple un its at the same plant (4% applied to all costs)
The adjustments are relative to th e design set forth in the Conesville Study. Figure 1-10 is an aerial view of the Conesville generating station with the CO 2 capture and compression equipment drawn in consistent with the plot plan in the CO 2 retrofit design document. Notice the large footprint for the CO 2 compression facility and how far away it is from the CO 2 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 of seq. target Capacity, GW
Count of PlantsCountofPlants,#Capacity, GWCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

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

Scale Adjustments

The Conesville Study examined four cases with CO 2 capture percentages of 90, 70, 50 and 30 percent. The study’s cases were ach ieved by limiting the amount of flue gas diverted to the CO 2 absorbers—which allowed an imputed calculation of power plant size if the equipment for each of the cases was ope rative at 90 percent capacity. For example, scrubbing 50 percent of the CO 2 from a 435.5 MW Conesville Un it 5 is the equivalent of scrubbing 90 percent of the CO 2 from a 242 MW unit. Best f it lines were developed from the Coneville data points, Figures 1-11 and 1- 12, and applied to estimate the capital cost of CO 2 retrofit at each unit based on its starting nameplate generating capacity. Figure 1- 13 presents an estimated cost for the CO 2 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 properl y apply the adjustments for close-in and landscape space availability. Plant 1497, AES Conesville, Coneville OHCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

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

Figure 1-12. CO 2 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 1,000Cost 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 1,000Cost relative to Conesville 90% case

Original Capacity of System, MW CO2 Compression and SeparationCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

17 Figure 1-13. CO 2 Scrubber Cost and Size Scaling

1.3.1 SO 2 Removal

In plants without primary FGD systems, ne w construction costs of $230 per kilowatt capacity for the primary FGD system designed to remove 98 percent SO 2 , and a value of $94.60/ton 2 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 SO 2 removal percentage was estimated using emissions and coal data from the EV datasets. The marginal SO 2 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 ad ditional sulfur reducti on to 10 ppm. Again, the Conesville report was used as the basis for scaling the various SO 2 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 CO 2 capture cases contained in the 2008 NETL Oxycombustion Report, and to be compliant with environmental requirements, the CCM requires NO x emissions to be at or below 0.07 lbs NO x / million Btu for purposes of CO 2 capture. NO x 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 + 3.0266Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

18 the additional NO x scrubbing requirement. Using th e unit’s total Btu value and an installation cost of $300/tonne NO x , a value for NO x scrubbing cost was calculated.

1.3.3 Recirculating Cooling
The analysis is based on an assumption that all plants will be conve rted 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 syst em will be installed as a part of the retrofit process. The 2007 NETL Conesville Study di d not address the issue of additional cooling capacity required by the CO 2 retrofit. Current amine-based CO 2 wet-scrubbing technology requires cooling to maintain the ap propriate reactor temperatures. Multi-stage CO 2 compression also requires cooling. Based on the Water Requirements Report, it was determined that a retrofitted unit would re quire 30 percent more recirculating cooling capacity than an unretrofitted unit. The tota l area (in square meters) of recirculating, induced draft cooling towers currently instal led 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 operati ng at higher heat rates. This required area of retrofitted cooling is compared to the ar ea of currently installed cooling towers (if present) to determine the area of additional c ooling required.
Using this ratio, polygons representing the esti mated additional cooling for the Conesville plant were created. Figure 1-14 shows the cu rrent 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 additio nal 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 c ooling 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 Wate r 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 availabil ity factor of 1 (minimum) to 3 (maximum)

3 Estimated from the Baseline Study CAPEX costs.Coal-Fired Power Plants: Costs of CO 2 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 ar eas (but where water is still available for recirculating cooling) will cost three times that of the coo ling system at the Conesville plant. This factor was implemented and appl ied 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 lo cated in one of the two most-arid USGS watersheds, or if it was lo cated within one of the areas designated as having an overpumped reservoir west of the Mississippi Rive r (see Figure 1-3).

Figure 1-14. Current and Additional Recircula ting Cooling Required to Retrofit All Units with 90% CO 2 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 fi rst 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 wereCoal-Fired Power Plants: Costs of CO 2 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 co mplete retrofit of Conesville Units 4, 5, and 6 was modeled us ing the Conesville Study as a guide. Conesville then served as a baseline for comp arison of retrofit difficu lty at other plants. Figure 1-15 shows the AEP Conesville plant re trofitted 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, CO 2 scrubbers and absorbers, as well as the primary and secondary FGD’s require cons truction in close proximity to the turbine and flue stack. The layout of some plan ts can easily accommodate these additional components. However, for plants where spa ce is more crowded, an incremental factor was applied to account for anticipated difficu lty in construction. These factors ranged from 0 (easily constructed) to 40 percent (diffi cult to construct). Plants with a zero factor are assumed to have a construction difficulty co mparable 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 CO 2 compression and additional coolin g facilities could be combined into larger plant (as opposed to unit) -servicing component s. Note that, while some 4 5 6Coal-Fired Power Plants: Costs of CO 2 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 wo rk around with close-in construction at the Conesville site. The CO 2 compression facility and additional cooling towers can be built in proximity to the plant, allowing more lat itude 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 th e viable population was assigned close-in and landscape construction incremental difficulty factors ranging from 0-40 percent. These values are based on pr ofessional judgment and represent general increases in costs due to engineer ing and constructi on difficulties. Figure 1-16 shows Plant 2315 Cherokee in Denver, Colorado, a plant assigned a 10 percent close-in construction di fficulty. The primary difficulty at this four-unit plant is the CO 2 scrubbers. One scrubber interferes with a cooling tower and another interferes with other structures. The plant required no primary FGD, and appear s to have sufficient recirculating cooling to accomm odate 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 difficu lty. Note that primary FGDs and CO 2 scrubbers need to be constructed against the ri ver, and the letdown turbines and CO 2 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 Crysta l River in Crystal River, Fl orida. It was assigned a 15 percent close-in construction di fficulty due to the southern CO 2 scrubbers and letdown turbines. It was not assigned a landscape construction difficulty.Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

22 Figure 1-16. Example Showing 10 Percent Clos e-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 retrof it facilities. This is par ticularly true for landscapeCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

23 construction components. Using the EV La nd 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 assu mptions 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 New burgh, Indiana. A parcel totaling 19.2 acres was added to accommodate the landscape retrofit components.Coal-Fired Power Plants: Costs of CO 2 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 DifficultyCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

25 Figure 1-20. Additional Land Requirements

Figure 1-21 shows how many plants were assign ed correction factors. More adjustments were made for close in space limitations than for landscape

Figure 1-21. Assigned correction factors for space limitationsCoal-Fired Power Plants: Costs of CO 2 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:

CX TOT = [(CX LD +CX CS + CX SR + CX NO )*AF c * + (CX CC +CX CW )*AF L ]*AF MU + CX AL

CX LD = 0.004 * MW + 0.8
CX CS = 3x10 -12 * (MW) 3 + 2x10 -7 * (MW) 2 + 0.0054 * (MW) + 3.03
CX SR = CX SS + CX SP CX SS = if FGD then (0.98 – N ss )*MW*216 $/kW, else MW*230 $/kW
CX SP = (1-0.98)*MW*HR*(1/CL HC )*CL SU * 95 $/ton sulfur
CX NO = if NO x < 0.07 then 0 else (NO X - .07) lbs/mmbtu *HR*MW*8760*CF*20 yrs*300 $/mtNOx
CX CW = MW * [ if ARID then (if dry_cooling then 0 else MW * 98 $/kW) else (if recirc_cooling then 0 else 28 $/kW) ]
CX CC = 0.0017 * MW + 0.24 - CX CS

where: MW = unit nameplate generating capacity, MW HR = unit heat rate, average achiev ed between 2000 and 2008, btu/kWh
CX TOT = total capital expense for CO 2 retrofit, MM$
CX LD = capital expense for the let down turbine, MM$
CX CS = capital expense for the CO 2 capture and separation
CX SR = capital expense for sulfur scrubber/upgrade to existing sulfur scrubber
CX SS = capital expense for primary sulfur scrubber
CX SP = capital expense for sulfur polishing
CX NO = capital expense for NO x reduction/upgrade to existing NO x reduction
CX CC = capital expense for CO 2 compression
CX CW = capital expense for cooling water upgrade
CX AL = capital expense for additional land
AF C = adjustment factor for tight spacing within the unit (close in)
AF L = adjustment factor for tight spacing surrounding the unit (landscape)
AF MU = adjustment factor (discount) for multiple generating units at a single plant
N ss = efficiency of the scrubbing unit (SO x captured)
NO X = NO x emissions, tons/yr
CL HC = coal heat content, btu/lb
CL SU = coal sulfur content, wt%Coal-Fired Power Plants: Costs of CO 2 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 Feedst ock cost. Figures 1-22, 1-23, and 1-24 show these costs as a function of the generati on capacity of the power plant based on the scenarios in the Conesville Study. Note that the relationshi p between feedstock cost and nameplate, in Figure 1-26, does not fit a func tion well, but does show a general trend. This relationship is no t completely understood.
The Conesville Study gives OPEX as functions of total CO 2 captured. For the 90% capture scenario, a retrofitted Conesville Unit 5 would capture approximately 3.3 million tons of CO 2 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 pe r year in feedstock OPEX.Coal-Fired Power Plants: Costs of CO 2 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 = 0.3398e 0.0001x 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) OPEXCoal-Fired Power Plants: Costs of CO 2 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 SO 2 control equipment, the additional cooling, the actual CO 2 retrofit components, the parasitic h eat used for amine regeneration and compression. Energy requirements for trans portation, storage and monitoring were not included in this analysis. A parasitic loading function was developed ba sed on the Conesville Study cases for the retrofit equipment. Figure 1-25 shows th is as a function of nameplate capacity.

Figure 1-25. Parasitic Load Scaling for Carbon Capture Retrofit Components The parasitic load factors associated with NOx, SO 2 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 SO 2 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 CO 2 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 CO 2 -captured. Make up power cost wa s 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 1,000Parasitic Load (kW-h/tonne CO2

Original Capacity of System, MW Parasitic Load ScalingCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

30 1.3.9 Levelized Cost of Electricity
A levelized cost of electric ity (LCOE) was calculated for each plant using methodology consistent with the Conesville Study. Fi gure 1-26 shows the LCOE equation from the Conesville Study. The equation le velizes 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 re trofit 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 fact ors as the Conesville Study. For a 20-year levelization period, a capital ch arge factor of 0.175, a fixed and variable OM levelization factor of 1.1568, and a feed stock levelization f actor or 1.1651 were used.

Figure 1-26. LCOE Equation and Pa rameters from Conesville StudyCoal-Fired Power Plants: Costs of CO 2 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 Cone sville Study methodology. Figure 1-29 shows the captured and mitigated carbon cost e quations from the Conesville Study.
The CO 2 capture cost is a measure of leveliz ed cost of retrofit per tonne of CO 2 captured at the plant. Because the analysis assumes constant coal, the make-up power associated with the retrofit parasitic load must be ge nerated 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 associ ated 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 reintrodu ced through make-up power generation. Figure 1-27. Captured and Mitigated (Avoided) Carbon CostsCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

32 The LCOE equation, calculated fo r each generation unit, is adju sted as follows to account for make-up power.

LCOE MU = (1-PL) * LCOE base + PL * Cost MU

Where:
LCOE MU - Levelized cost of electricity in the make up power case ($/MWh)
LCOE base - Levelized cost of electric ity in the base case ($/MWh)
Cost MU - 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 CO 2 capture to CO 2 capture

The cost of CO 2 capture is unaffected by the make- up power assumption, but the cost of CO 2 avoided is impacted by the make-up power.
CO 2cp, MU = (1-PL) * CO 2cp, base + PL* CO 2MU

Where:
CO 2 - Carbon dioxide emissions, metric tons CO 2 / kWh
PL - parasitic load, percent re duction in unit generating capacity going from no CO 2 capture to CO 2 capture

cp Capture Plant

MU Make upCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

33 

## 2. RESULTS This section provides the analytical results of the analysis. It shou ld 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-specifi c imagery for carbon capture retr ofits for individual plants in the viable population.



### 2.1 CAPEX RESULTS CAPEX, OPEX, and parasitic cost s were calculated for the popul ation of viable plants for three scenarios with varied capacity factors of 65, 75, an d 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 emissi ons associated make-up power, and (2) a carbon mitigation case, which models the e ffects of Waxman-Markey assumptions for make-up power costs and carbon emissions. Figure 2-1. Nameplate Capac ity as a Function of CO 2 Capture CAPEX by Unit shows CO 2 capture CAPEX as a function of nameplat e capacity for the 738 individual analyzed units. Note that large units demonstrate re latively low CAPEX rates (green oval), while smaller plants demonstrate high CAPEX variability (red oval).

Figure 2-1. Nameplate Capaci ty as a Function of CO 2 Capture CAPEX by Unit $5 $10 $15 $20 $25

0 500 1000 1500CO2RetrofitCAPEX($/tonne)

Nameplate Capacity (MW) 

## 282 GW (738 Units)Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

34 

### 2.2 BASE CASE (NO MAKE-UP POWER)
This case determines the base LCOE a nd carbon capture costs. The LCOE was calculated without inclusion of make-up power. Levelize d carbon capture costs were calculated without consideration of carbon emitted through generation of make-up power, and essentially represent CA PEX and OPEX costs associat ed with physically capturing carbon from the flue gases. In Figure 2-2. Base Case, Cumulative U.S. Co al Generating Capacity versus Incremental LCOE for CO 2 Capture Retrofit, all the generating un its are ranked from least to highest incremental cost of power requi red to “cover” the cost of CO 2 capture. Figure 2-3 is a similar graphic that presents the cost of CO 2 captured versus cumulative generating capacity. Figure 2-2 is interpreted as follows. Reading off the 75% capacity factor line, the Conesville generating plant ha s a cost of incremental co st of electricity of CO 2 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 CO 2 . The other 70% of coal-fired capacity has a higher cost. Fi gure 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% incr eases the incremental COE by roughly $8/MWh. Figure 2-3 shows that roughly 70% of the genera ting capacity has an incremental cost of power of $70/MWh or less. After that th e curve flattens out and the costs begin increasing more rapidly. By comparison the CO 2 capture cost curves in Figure 2-3 are steeper. The explanation for this is partia lly seen in Figure 2-1 which shows a wide variation in CAPEX, the primar y determinant of LCOE. The CO 2 capture cost, however, is driven strongly by a unit’s e fficiency which has a much lowe r variation acro ss the fleet. A range of capacity factors was modele d (values of 65, 75, and 85 percent).Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

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

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

## (282 Power Plants)

(282 Power Plants)Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

36 

### 2.3 MAKE-UP POWER CASE A coal-fired generating unit with CO 2 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 ma ke-up power. That is, the owning entity buys power – either via a contract or on the s pot market, to “make-up” for the generation that is being consumed by the parasitic load of the CO 2 capture plant.
This case determines LCOE and carbon m itigation costs assuming NETL’s WaxmanMarkey (W-M) projections. LCOE was calcu lated including make-up power costs based on the cost of electricity in each unit’s E MM region. Levelized carbon mitigation costs were calculated with consideration of carbon emitted through generation of make-up power, and represents estimated costs associ ated 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 sp iraling 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 CO 2 Capture Technology and Improvements in Efficiency

37 Figure 2-4. Make-up Power Case, Cumulative U.S. Coal Generating Capacity versus Incremental LCOE for CO 2 Capture Retrofit

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

### (282 Power Plants)

(282 Power Plants)Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

38 

### 2.4 COMPARISON WITH CONESVILLE STUDY RESULTS The results for incremental COE, capture co st, and mitigation cost for the Conesville generating unit are different in this study than in the s ource study developed by NELT and AEP, Table 2-1. Table 2-2-2 shows th at 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 cu rrent study also assumes a higher price and regionally-based carbon emissions for ma ke-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 5Coal-Fired Power Plants: Costs of CO 2 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 worki ng to refine and enhance the analysis. The following are priority objectives to be contained in a revise d document, set to be posted in the Spring of 2011.

 Provide capability for the model to asse ss advanced retrofit technologies which reduce the costs and energy penalties for CO 2 capture

 Examine the potential synergy of refurbis hing units with efficiency (heat rate) upgrades in conjunction with CO 2 capture retrofits

 Provide additional hard cost and performance data points by integrating results from current engineering-level retrof it 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 cost s in the LCOE calculations

o Perform a full twenty-year cost leve lization using disc rete electricity prices and generation profiles by E MM by year using NETL’s projections

o Collect and integrate data on the timing of the installation of NO x and FGD equipment relative to efficiency drops

 Further characterize viable sequestrati on opportunities by type and capacity

 Incorporate costs for CO 2 transportation and storage into output metricsCoal-Fired Power Plants: Costs of CO 2 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, StatsCanad a, CFE, Global Energy Primary Research DESCRIPTION: The most commonly used name for a power plant. A facility containing prime movers, electric generators, and auxiliary equipm ent for converting mechanical, chemical, and/or fission energy into electric energy.
Data Item: Plant ID SOURCE: Global Energy DESCRIPTION: Unique Global Energy ent ity id corresponding to the plant name.
Data Item: Unit DESCRIPTION: Any combination of physically connected genera tor(s), reactor(s), boiler(s), combustion turbine(s), or other prime mover(s) operated together to pr oduce 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 st atus 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 CO 2 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 d eactivated 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 expr essed in megawatts (MW) and is usually indicated on a nameplate physically attached to the generator. INSTRUCTIONS: For EIA 860, 906 and NE RC 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 sour ces. These sources are detailed in the help for the EV Fully Loaded Tested Heat Rate Source field.Coal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

42 At the onset of this project, Global Energy analys ts used various resources to determine a low and high point for heat rate s by Generator Availability Da ta 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 data base and then moves down the list of sources looking to see if that unit has data for that source. If there ar e 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 th en be the value used for that un it in the EV Heat Rate item. If there is no EV Research data for that unit, the pr ocess 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 th ere are no data to support a heat ra te 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 conv erts energy to electricity directly (phot ovoltaic solar and fuel cells). Data Item: Supercritical (Y/N) SOURCE: Global Energy Research DESCRIPTION: The terms supercritical and ultr a-supercritical are derived from the definition of the temperature and pressure at which wate r vapor and liquid water are indistinguishable - known as the Critical Point. The Critical Poin t 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. Instea d, with the addition of heat or increase in pressure the fluid experiences a continuou s transition from wate r-like to steam-like characteristics. Pressure is said to be "supe rcritical" 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 subc ritical unit operates below the cr itical 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: SO 2 Control Equipment (Y/N)
SOURCE: U.S. EPA Clean Air Ma rkets Division facility attri butes 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 CO 2 Capture Technology and Improvements in Efficiency

43 SOURCE: U.S. EPA Clean Air Ma rkets Division facility attri butes and Global Energy Research
DESCRIPTION: Indicates whethe r unit is known to have one or more NOx control technologies in place
Data Item: SO 2 Annual Rate lbs/mmBtu
SOURCE: US EPA CEMS
DESCRIPTION: SO 2 emissions rate in lbs/mmBtu for the most recent complete calendar year of data available from the U.S. EPA CEMS databa se. (The EPA releases 4th quarter data in February of the following year.) hen aggregated this item will provide a wei ghted average value, weighted by Nameplate Capacity. IMPORTANT NOTE: Only units that report SO 2 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 wei ghted average value, weighted by Nameplate Capacity. IMPORTANT NOTE: Only units that report NOx emissions will be included in this average.
Data Item: CO 2 Annual Rate lbs/mmBtu
SOURCE: EPA
DESCRIPTION: CO 2 emissions rate in lbs/mmBtu for the most recent complete calendar year of data available from the U.S. EPA CEMS databa se. (The EPA releases 4th quarter data in February of the following year.) When aggregated, this item will provide a wei ghted average value, weighted by Nameplate Capacity. IMPORTANT NOTE: Only units that report CO 2 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 th e fuel specified, in millions of Btus. Note: this is the total quantity consumed for bot h electricity and, in the case of combined heat and power plants, process steam production.
Data Item: Net Generation MWh SOURCE: EIA 906, Ontario IESO, CEMSCoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

44 DESCRIPTION: This is the monthly net gene ration as reported (in MWh) on the EIA 906 or Independent Electricity System Op erator (Ontario) generator disc losure 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 prim e 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 Compre ssed Air Storage: When station use electrical demand exceeds the gross electrical output of th e plant, a negative number should be reported for net generation. Indicate ne gative amounts by using a minus sign before the number. Hydro Pumped Storage and Compressed Air Ener gy 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 a ssistance with these new instructions for storage facilities, contact the survey manager. Data must be reported in megawatthours (M Wh), 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 du ct burners and/or auxiliary boilers under steam turbine code (CA). CEMS (Continuous Emissions Monitoring System) Table
Data Item: Sum Total CO 2 Emissions tons (by ownership %)
SOURCE: EPA
DESCRIPTION: Total CO 2 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 SO 2 Emissions tons (by ownership %)
SOURCE: EPA DESCRIPTION: Total SO2 emissions for the y ear 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: EPACoal-Fired Power Plants: Costs of CO 2 Capture Technology and Improvements in Efficiency

45 DESCRIPTION: Total NOx emissions for the y ear 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 CO 2 Emissions Rate lbs/MWh SOURCE: EPA, Global Energy Primary Research DESCRIPTION: Average CO 2 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 CO 2 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 CO 2 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, t housands of barrels for oil and other liquid fuels, and thousands of mmBtu (billions of Britis h 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 qu antities of fuel received from a given supplier during the month for which no la boratory analysis is made, re port 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 estimate s, 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 sulf ur 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.