1

MEMORANDUM 

From: The Office of Air Quality Planning and Standards 

 U.S. Environmental Protection Agency 

To: EGU NSPS Docket (EPA-HQ-OAR-2013-0603) 

Date: June 2014 

Subject: Best System of Emissions Reduction (BSER) for Reconstructed Steam Generating Units and 

Integrated Gasification Combined Cycle (IGCC) Facilities1

 

Introduction 

As the thermal efficiency of a fossil fuel-fired electric generating unit (EGU) increases, less fuel is 

burned per gross megawatt of electricity produced by the turbine-generator and there is a corresponding 

decrease in carbon dioxide (CO2) and other air emissions. Efficiency is reported as the percentage of the 

energy in the fuel that is converted to electricity. Heat rate is another common way to express efficiency. 

Heat rate is expressed as the number of British thermal units (Btu) or kilojoules (kJ) required to generate 

a kilowatt (kWh) of electricity. Lower heat rates are associated with more efficient power generation. 

Efficiency improvements can be expressed in different formats; they may be reported as an absolute 

change in overall efficiency (e.g., a change from 40% to 42% represents a 2% absolute increase). They 

may also be presented as the relative change in efficiency (e.g., a change from 40% to 42% is a relative 

change in efficiency and fuel use of 5%). The relative change in efficiency is the most consistent 

approach, since it corresponds to the same change in heat rate. For coal-fired EGUs as a whole, as heat 

rates are reduced there are also reductions in fuel extraction related environmental impacts, in the rate of 

production of coal combustion byproducts (e.g., ash and gypsum), and in the thermal impacts on cooling 

water eco-systems. 

The electric energy output for an EGU can be expressed as either “gross output” or “net output.” The 

gross output of an EGU is the total amount of electricity generated at the generator terminal. The net 

output of an EGU is the gross output minus the total amount of auxiliary (or parasitic) electricity used to 

operate the EGU (e.g., electricity to power fuel handling equipment, pumps, fans, pollution control 

equipment, and other on-site electricity needs), and thus is a measure of the electricity delivered to the 

transmission grid for distribution and sale to customers. 

Multiple design and operation and maintenance parameters influence the efficiency of an EGU. The 

following is a brief summary of some of the design parameters that impact the CO2 emission rate of 

coal-fired EGUs. This summary is not intended to be a comprehensive list of all design parameters that 

influence the CO2 emission rate. 

Thermodynamic steam cycle

According to thermodynamic principles, the overall efficiency for converting the thermal energy into 

electricity is limited by the average temperature at which heat is supplied (i.e., steam temperature) and 

the average temperature at which heat is rejected (i.e., condenser temperature). Any changes that 

increase the average temperature at which heat is supplied or decrease the average temperature at which 

heat is rejected will increase the Rankine-cycle efficiency.2

 Similarly, increasing the steam pressure 

increases the efficiency of converting the thermal energy into electricity. Supercritical and ultra-

                                                            

1

 Referred to as “Best System of Emissions Reduction (BSER) for Reconstructed Electric Utility Steam Generating Units 

(EGUs) and Integrated Gasification Combined Cycle Facilities (IGCC)” in the proposal preamble 2

 Van Wylen, J. and R. Sonntag. Fundamentals of Classical Thermodynamics, Third Edition. John Wiley & Sons, New York, 

1985. Page 285. 
2

supercritical boilers take advantage of these improved efficiencies and operate above the critical point of 

water (approximately 374°C (705°F) and 22.1 megapascal (MPa) (3,210 pounds per square inch (psi))). 

The relationship between heat rate improvements and steam temperature and pressure is complex, but 

heat rate is improved by approximately 0.5% for each 5 MPa (730 psi) increase in steam pressure and by 

0.6% for each 10 oC (18 oF) increase in steam temperature. 

Additional opportunities to improve the efficiency of the thermodynamic cycle include using a double 

reheat cycle (which increases the efficiency of an EGU compared to a similar EGU using a single or no 

reheat cycle) and increasing the number of feed water heaters. Steam reheat cycles and feedwater heaters 

increase the overall energy efficiency by increasing the average temperature at which heat is supplied to 

the steam turbine. In a steam reheat cycle, steam is partially expanded to a lower pressure in the high 

pressure portion of the steam turbine and then sent back to the boiler to be reheated to a higher 

temperature prior to expansion through the lower pressure portions of the steam turbine. In feedwater 

heaters, a portion of the steam is diverted at an intermediate turbine stage to pre‐heat the condensed 

water instead of running through all pressure stages of the steam turbine. The International Energy 

Agency3 estimates that similar EGUs using a double reheat cycle would have a 1.5% improvement in 

heat rate compared to a similar EGU with a single reheat cycle. Conversely, EGUs without a reheat 

cycle would be 10 less efficient (i.e., have an 11% higher heat rate) than an identical EGU with a single 

reheat cycle. Optimized feed water configurations can improve the heat rate by about 3% compared to a 

simpler configuration. 

In addition to demonstrated technologies to improve the efficiency of the steam cycle, innovative 

technologies are emerging that directly convert waste heat into electricity.4

 These technologies rely on 

the thermogalvanic effect, which is observed when a battery is held at an elevated temperature (e.g., 60 

°C) during charging. Researchers have determined that approximately 5% of the heat energy entering the 

battery can be converted to electricity when the battery is discharged at a lower temperature (e.g., 10 °C). 

Applications of this technology in systems that use the waste heat from EGUs have the potential to 

further improve EGU efficiencies. In typical EGUs, more than half of the energy in the fuel is rejected to 

the environment at temperatures ranging from 35° C (in the condenser) to 135° C (in flue gas prior to 

desulfurization). Any waste heat that can be converted into electricity via thermogalvanic technologies 

can directly improve thermal efficiency. 

Coal rank and quality 

Burning higher quality fuels (e.g., bituminous coals) tend to be more efficient than EGUs burning lower 

quality fuels with high moisture content (e.g., undried lignite). Bituminous coals heaving a heating value 

of greater than 10,500 Btu/lb, lignite coals have heating values of less than 8,300 Btu/lb, and 

subbituminous coal heating values are between 8,300 Btu/lb to 10,500 Btu/lb. Multiple coal-drying 

technologies can reduce the moisture in coal and increase the heating value. Petroleum coke has one of 

the highest heating values (> 13,000 Btu/lb) of commonly used solid fuels. Figure 1 shows the estimated 

heat rate impact of coal heating value as estimated by the National Coal Council5

 and the Integrated 

Environmental Control Model.6

                                                            

3 Coal Industry Advisory Board to the International Energy Agency, Power Generation from Coal (Paris, 2010).

Available at http://www.iea.org/ciab/papers/power_generation_from_coal.pdf . 4 D. Chandler, “A new way to harness waste heat: Electrochemical approach has potential to efficiently turn low‐grade heat

to electricity,” http://www.sciencedaily.com/releases/2014/05/140521133611.htm, (May 21, 2014). 5 National Coal Council, “Opportunities to Expedite the Construction of New Coal‐Based Power Plants,” (2004). Available at:

http://www.nationalcoalcouncil.org/Documents/ExpediteNov30rpg.pdf. 6 Download available from: http://www.cmu.edu/epp/iecm/
3

Figure 1: Impact of Coal Quality on Heat Rate 

In addition, higher rank coals tend to have less CO2 per MMBtu than lower rank coals. Bituminous coals 

emit on average 205 lb CO2/MMBtu, subbituminous coals emit 212 lb CO2/MMBtu, and lignite coals 

emit 216 lb CO2/MMBtu. Therefore, operating at the same efficiency, a bituminous coal-fired EGU 

would emit 5% less CO2 than a lignite-fired EGU. Petroleum coke has one of the highest CO2 emissions 

rate (225 lb CO2/MMBtu) of commonly used solid fuels. Of the gaseous and liquid fossil fuels used in 

EGUs, natural gas combustion releases approximately 117 pounds of CO2 per MMBtu, distillate oil 

releases 161 lb CO2/MMBtu, and residual oil releases 174 lb CO2/MMBtu. 

EGU cooling system 

As described previously, reducing the condenser temperature improves the efficiency of a steam turbine 

converting the thermal energy in the steam to electricity. Once-through cooling systems can achieve a 

lower condenser temperature and have an efficiency advantage over recirculating cooling systems (e.g., 

cooling towers) and dry systems. However, once-though cooling systems typically have larger water 

related ecological concerns than recirculating cooling systems. The International Energy Agency7

estimates that similar EGUs with once-through cooling systems that use sea water and river water would 

have 2.4% and 1.5% lower heat rates (i.e., more efficient) respectively than an identical EGU using a 

recirculating cooling system. Conversely, an identical EGU using a dry cooling system would have a 5% 

higher (i.e., less efficient) heat rate. 

The Kalina cycle8

 is an innovative technology that more efficiently extracts energy from the working 

fluid in an EGU. Instead of using water as the working fluid, this technology uses a mixture of ammonia 

and water, which has a lower condensing temperature. This mixture allows the condenser to achieve 

lower pressures and more energy can be extracted through the turbine. Kalina-cycle plants currently in 

                                                            

7 Coal Industry Advisory Board to the International Energy Agency, “Power Generation from Coal,” (Paris, 2010).

Available at: http://www.iea.org/ciab/papers/power_generation_from_coal.pdf. 8 H.A. Mlcak, “An Introduction to the Kalina Cycle,” Proceedings of the International Joint Power Generation Conference ,

Volume 30 (2004). Available at: http://www.globalgeothermal.com/Technology.aspx, (June 5, 2014).  
4

commercial operation have demonstrated efficiency gains of 15-50 percent relative to conventional 

thermal technologies.9

 

EGU geographic location and ambient conditions 

The seasonal ambient temperatures and elevation at the facility site may potentially have an impact on 

EGU efficiency. Cooler ambient temperatures theoretically could increase the overall EGU efficiency by 

increasing the draft pressure of the boiler flue gases and the condenser vacuum, and by increasing the 

efficiency of the cooling system. Where the efficiency of once-through cooling systems is impacted by 

the cooling water temperature, the efficiency on recirculating cooling systems is influenced by the wet 

bulb temperature of the air, and dry cooling systems are impacted by the actual temperature of the air. 

Also, geographic location influences the type of cooling system that can be used (e.g., EGUs located in 

arid locations often cannot use once-through cooling). The International Energy Agency10 estimates that 

heat rate increases by 0.15% for each 1 o

C increase in ambient temperature. At higher elevations, air 

pressure is lower and less oxygen is available for combustion per unit volume of ambient air. However, 

the efficiency impact of this is minimal for coal-fired EGUs. 

EGU duty cycle & load generation flexibility requirements 

Operating an EGU as a base load unit is more efficient than operating an EGU as a load cycling unit at a 

lower duty cycle to respond to fluctuations in customer electricity demand. Figure 2 shows the 

International Energy Agency11 estimated impact of unit operating load on heat rate. 

Figure 2: Impact of Operating Load on Heat Rate 

As shown in Figure 2, supercritical units experience only about half the part-load efficiency degradation 

of a conventional subcritical unit. However, supercritical units have higher start‐up losses because 

                                                            

9 "Kalina Cycle Enjoying Commercial Success," Power Engineering, PennWell Power Sites, (2002). Available at:

http://www.power‐eng.com/articles/print/volume‐106/issue‐2/news‐update/kalina‐cycle‐enjoying‐commercial‐

success.html. 10 Coal Industry Advisory Board to the International Energy Agency, “Power Generation from Coal,” (Paris, 2010). 11 Ibid.
5

larger quantities of steam, and therefore heat energy, must be sent to the condenser during start‐up. 

Another factor which can significantly impact efficiency is the number of perturbations (transients) from 

steady state operating conditions. During each of these transients, the plant will not be operating at peak 

performance. Therefore, the more transients, the greater the reduction in efficiency. We have concluded 

that a reconstructed EGU would operate at a similar operational capacity factor as the BSER units so did 

not adjust this value. If a reconstructed EGU were operated at a lower load or with more transients, 

options to offset any loses in efficiency include integrating non emitting equipment or co-firing natural 

gas. 

EGU size 

EGU efficiency generally increases with size because the boiler and steam turbine losses are lower for 

larger equipment. However, as equipment size increases above approximately 2,000 MMBtu/h the 

differences in these losses start to taper off. Larger EGUs also tend to be more efficient because they are 

usually newer and use advanced technologies and economy of scale allows the use of higher cost 

improvements to be more economic, but these are not inherent differences in efficiencies. 

Other factors 

Pollution control devices require electricity to operate and increase the auxiliary (i.e., parasitic) loads 

and reduce the net efficiencies of EGUs. The auxiliary load requirements for nitrogen oxide (NOX) and 

particulate matter (PM) controls are each typically 0.5% of the gross output of the facility. The SO2

emissions are controlled using flue gas desulfurization (FGD) technology. The FGD auxiliary load 

requirements are typically between 1-2% of the gross output of the facility. In addition, some FGD 

processes use carbon-containing reagents (e.g., carbonates) that form CO2 as a byproduct of the 

chemical reactions with SO2. For a typical unit, the CO2 that is chemically created in a scrubber adds an 

additional 1% to overall GHG emissions, but it can be as high as 3% for facilities burning high sulfur 

coals. However, from an overall GHG emissions standpoint, the use of FGD technologies that do not 

form byproduct CO2, such as lime-based scrubbers, do not necessarily reduce emissions. Lime is 

manufactured by heating limestone in the absence of oxygen to remove a molecule of CO2 (CaCO3 + 

heat → CaO + CO2). Unless the CO2 is sequestered at the lime production facility, overall GHG 

emissions will be similar. A list of FGD processes used for controlling SO2 emissions from coal-fired 

EGUs is presented in Figure 3, identifying those processes that chemically form additional CO2. The 

BSER facilities are subbituminous-fired EGUs using lime based scrubbers. Therefore, we did not 

normalize for chemically created CO2. 

Another factor that can influence the thermal efficiency of the steam generator is the method used for 

bottom ash recovery. There are two systems used in the power sector for recovering bottom ash: dry 

bottom systems and wet bottom systems. Wet bottom systems extract the ash into a quench tank where 

the ash is cooled, collected, crushed and conveyed from the furnace (all under water). Dry bottom 

systems extract the ash in a solid form and completes the same steps in air. By completing the cooling 

and collection of bottom ash in air, additional useful heat is recovered. Additionally, dry bottom 

conveying systems use less auxiliary power than wet bottom conveying systems because of the 

additional water weight and friction imparted by the quench bath. Dry bottom systems are 0.15% to 

0.5% more efficient than wet bottom systems.12 

                                                            

12 "Ash Handling: Why Dry Bottoms Are Better than Wet Bottoms," Power Engineering, PennWell Power Sites, (2010).

Available at: http://www.powerengineeringint.com/articles/print/volume‐18/issue‐5/features/ash‐handling‐why‐dry‐

bottoms‐are‐better‐than‐wet‐bottoms.html.  
6

Figure 3. CO2 formation from coal-fired EGU flue gas desulfurization (FGD) processes. 

FGD Type Reagent Forms CO2 Overall Reaction(s) 

Wet Scrubbing Limestone (CaCO3) yes CaCO3 + SO2 + 1⁄2H2O → CaSO3•1⁄2H2O(s) + CO2; CaCO3 + SO2 + 2H2O + 1⁄2O2 → CaSO4•2H2O(s) + CO2 

Magnesium-enhanced lime; Dolomitic lime [Ca(OH)2•Mg(OH)2] no 10Ca(OH)2 + 11SO2 + Mg(OH)2 → 10CaSO3•1⁄2H2O(s) + MDual Alkali; Sodium solution and 

lime no 

2NaOH + SO2 → Na2SO3 + H20; 

H2O + Na2SO3 + SO2 → 2NaHSO3;

2NaHSO3 + Ca(OH)2 → Na2SO3 + CaSO3•1⁄2H2O + 3/2H2O

Na2SO3 + Ca(OH)2 → 2NaOH + CaSO3

Dual Alkali (Dowa) yes Al2O3•Al2(SO4)3 + 3SO2 + 3/2O2 → 2Al2(SO4)3; 2Al2(SO4)3 + 3CaCO3 → Al2O3•Al2(SO4)3 + 2CaSO4(s) + 3CSeawater yes 2NaHCO3 + SO2 → Na2SO3 + 2CO2 + H20; Na2SO3 + 1⁄2O2 → Na2SO4 Magnesium oxide (MgO) no MgO + SO2 → MgSO3 Hydrogen Peroxide (H2O2) no H2O2 + SO2 → H2SO4 Sodium hydroxide (NaOH) no 2NaOH + SO2 → Na2SO3 + H20; Na2SO3 + 1⁄2O2 → Na2SO4 

Dry/Semi-dry Scrubbing Hydrated calcitic lime (Ca(OH)2) no Ca(OH)2 + SO2 → CaSO3•1⁄2H2O(s) + 1⁄2H2O; Ca(OH)2 + SO2 + H2O + 1⁄2O2 → CaSO4•2H2O(s) 

Sodium bicarbonate (NaHCO3) yes 2NaHCO3 + SO2 → Na2SO3 + 2CO2 + H20; 2NaHCO3 + SO2 + 1⁄2O2 → Na2SO4 + 2CO2 + H20 Sodium sesquicarbonate (trona) yes 2(Na2CO3•NaHCO3•2H2O) + 3SO2 → 3Na2SO3 + 5H2O + 4

2(Na2CO3•NaHCO3•2H2O) + 3SO2 + 3/2O2 → 3Na2SO4 + 5

Sodium carbonate (soda ash, Na2CO3) yes Na2CO3 + SO2 + 1⁄2O2 → Na2SO4 + CO2 Pulverized limestone yes CaCO3 + SO2 + 2H2O + 1⁄2O2 → CaSO4•2H2O(s) + CO2 

Other Processes Ammonia (NH3) no SO2 + 2NH3 + H2O + 1⁄2O2 → (NH4)2SO4 

Activated carbon no SO2 + H2O + 1⁄2O2 → H2SO4 

Ref 1. Srivastava, Ravi K, Wojciech Jozewicz and Carl Singer, 2001. “SO2 Scrubbing Technologies: A Review,” Environmental Progress, 20(4):219-28. Ref 2. Srivastava, Ravi K and Wojciech Jozewicz, 2001. “Flue Gas Desulfurization: The State of the Art,” Journal of the Air & Waste Management Association, 51:1676-88.Ref 3. Davenport, W.G., et al., 2006. “Sulfuric Acid Manufacture. Southern African Pyrometallurgy,” South African Institute of Mining and Metallurgy, Johannesburg. Ref 4. Benson, Lewis, et al., 2003. “Control of Sulfur Dioxide and Sulfur Trioxide Using By-Product of a Magnesium-Enhanced Lime FGD System,” presented at ICAC Forum ’03 M

Strategies, Nashville, TN. October 14-15. Available at: http://www.carmeusena.com/files/files/techpapersreports/carmeuse_icac_20forum_2003.pdf. 

Ref 5. He, Boshu, et al., 2002. “Temperature Impact on SO2 Removal Efficiency by Ammonia Gas Scrubbing,” Energy Conversion and Management 44:2175-2188. Available at: 

http://www.sciencedirect.com/science/article/pii/S0196890402002303. 

Ref 6. U.S. Environmental Protection Agency (EPA), 2005. Multipollutant Emission Control Technology Options for Coal-fired Power Plants. EPA. EPA-600/R-05/034. U.S. Enviro

Risk Management Research Laboratory. Research Triangle Park, NC. Available at: http://www.epa.gov/airmarkt/resource/docs/multipreport2005.pdf. 

Ref 7. Shand, Mark A., 2009. “A New Look at SO2 Removal,” Available at: http://www.risiinfo.com/technologyarchives/chemicalsnews. Ref 8. Maziuk, John and John Kumm, 2002. “Comparison of Dry Injection Acid-Gas Control Technologies.” Presented at the 95th Annual Conference and Exhibition of the Air and W

Baltimore, MD. June 23-27, 2002
7

Best Performing Coal-Fired EGUs 

In order to determine the annual average emissions rate (lb CO2 per MWh) that is equivalent to the best 

system of emission reduction (BSER), we analyzed data reported by owners/operators of EGUs to the 

EPA’s Clean Air Markets Division (CAMD) to identify the best performing (i.e., the best operated and 

maintained) EGUs reporting CO2 emissions per megawatt hour of gross generation. To estimate the net 

output based emission rate, we assumed a 7.5% auxiliary load. We also reviewed data available from the 

Energy Information Administration (EIA) and the information collected for the Mercury and Air Toxics 

Standard (MATS) rulemaking. The emission data for the best performing facilities was then normalized 

assuming the design factors (steam cycle, etc.) would be improved for a theoretical reconstructed facility 

to increase efficiency and lower the CO2 emission rate using more efficient design parameters. For 

example, if a particular unit had no steam reheat cycle, the increase in efficiency for reconstructing the 

unit with a single reheat cycle was estimated. The EPA selected EGUs that reported the lowest 

normalized CO2 emission rate to account for (1) design factors influencing efficiency for which the EPA 

does not have information (e.g., the number of feedwater heaters, combustion and soot blowing 

optimization, an exposed structure or main building enclosure, etc.) and (2) operation and maintenance 

practices for which the EPA does not have information. A reconstructed EGU would be able to 

incorporate both of these into the design and operation and maintenance practices of a reconstructed 

EGU. This is deemed to be a minimum level of control, since to date no operating coal-fired EGUs have 

had a federal regulatory driver to minimize the CO2 emission rate. 

Factors for which owners/operators of reconstructed facilities have more limited influence include the 

condenser technology and ambient temperature. For example, designers can specify ultra-super critical 

steam conditions compatible with state-of-the art metallurgy, multiple stages of feedwater heating, and 

double steam reheat cycles to optimize efficiency gains attributable to increasing the average 

temperature at which heat is supplied to the cycle. However, designers on reconstruction projects have 

fewer options for lowering the temperature at which heat is rejected from an affected facility because 

this low-temperature constraint is largely determined by the available cooling reservoir and local 

ambient conditions. A minority of smaller existing EGUs (e.g., units located in arid regions reliant on air 

cooled condensers) currently use dry cooling technologies. If reconstructed, these facilities would either 

likely continue to use dry cooling technologies or switch to an innovative bottoming cycle to lower 

condensing temperatures to improve efficiency. We are not aware of any larger EGUs that use dry 

condensers, so the normalized calculations for larger EGUs were done assuming use of a cooling tower. 

To account for the impact of ambient conditions, we conservatively normalized the emission rate data to 

20 o

C, with one exception. Since coal refuse-fired EGUs are located in more temperate regions, we 

assumed 10 o

C for reconstructed coal refuse-fired EGUs. 

Twelve-month CO2 emission rates were calculated by dividing the sum of the CO2 emissions by the sum 

of the gross electrical energy output over the same period. That emission rate was then divided by 0.925 

to approximate the net output-based emission rate (i.e., 7.5% auxiliary load). Figure 4 shows the 

performance of the best performing facilities in terms of normalized CO2 emissions. Based on the 

performance of Weston Unit 4, the EPA has determined that the 12-month emission limit that 

corresponds to BSER is 1,900 lbs of CO2 per megawatt-hour of net electric output (lb CO2/MWhnet) for 

reconstructed EGUs with a base load rating of greater than 2,000 MMBtu/h. Even though the emission 

rate for the Wygen III facility is 2,320 lb CO2/MWhnet, based on the normalization of that data the EPA 

has determined that the 12-month emission limit that corresponds to BSER is 2,100 lb CO2/MWhnet for 

reconstructed EGUs with a base load rating of 2,000 MMBtu/h or less. 
8

Figure 4: Weston 4 and Wygen III Data 

Facility Weston 4 Wygen III 

Year in Service 2008 2010 

State Wisconsin Wyoming 

Primary Fuel Subbituminous Subbituminous 

Base load rating (MMBtu/h) 5,217 1,300 

MWe Rating 575 110 

Steam Pressure (MPa) 26 11 

Primary Steam Temperature 

(

o

C) 

585 541 

Number of Steam Reheat 

Cycles 

1 0 

Cooling Technology Cooling Tower Dry 

Average Ambient 

Temperature (oC) 

6.9 8.3 

Data Analyzed 2008 - 2013 2010 – 2013 

Average Operating Capacity 

Factor (Duty Cycle) 

78% 85% 

99% Confidence Emission 

Rate (lb CO2/MWhnet) 

1,890 2,320 

Figure 5 shows the normalization of the Weston 4 data using various steam cycles and fuels, and Figure 

6 shows the configurations that have been demonstrated would be able to achieve various emission 

standards. As shown in Figures 5 and 6, at the proposed emission rate on 1,900 lb CO2/MWhnet a 

reconstructed bituminous or subbituminous-fired EGU could achieve the standard using supercritical 

steam conditions, and a reconstructed lignite or petroleum coke-fired EGU could achieve the standard 

using ultra-supercritical steam conditions. More stringent emission rates would potentially require 

reconstructed EGUs to use higher quality coals and/or advanced ultra-supercritical steam conditions. 

Additional compliance options would include co-firing natural gas, a hybrid power plant, integration of 

non-emitting generation technologies, and combined heat and power. At less stringent emission rates, 

ultra-supercritical steam conditions would not be required, and reconstructed EGUS burning higher rank 

coals would be able to comply using subcritical steam conditions. One notable exception would be a 

reconstructed coal refuse-fired EGU. The EPA is only aware of one coal refuse-fired EGU that would be 

classified as a large EGU. If that facility were reconstructed, the use of ultra-supercritical steam 

conditions would be projected to achieve an emission rate of 2,100 lb CO2/MWh. 
9

Figure 5: Example Normalized Weston 4 Data13

Facility Weston 4 

(base) 

Normalize 1 (Advanced ultra-supercritical) 

Normalize 2 (Ultrasupercritical) Normalize 3 (Supercritical) 

Primary Fuel Sub Bit / Sub / Dried Lig / PC / 

Lig / Ref 

Bit / Sub / Dried Lig / PC / Lig / Ref 

Bit / Sub / Dried Lig / PC / Lig / Ref 

Steam Pressure (MPa) 26 37.5 30 24.1 Primary Steam Temperature (oC) 585 710 605 593 Number of Steam Reheat Cycles 1 2 2 1 Cooling Technology Tower Tower Tower Tower Average Ambient Temperature (oC) 6.9 20 (10 Ref) 20 (10 Ref) 20 (10 Ref) Average Operating Capacity Factor 78% 78% 78% 78% 99% Confidence Emission Rate (lb CO2/MWhnet) 

1,890 1,662 / 1,749 / 1,786 / 

1,793 / 1,827 / 1,971 

1,766 / 1,858 / 1,897 / 1,905 / 1,940 / 2,093 

1,831 / 1,926 / 1,966 / 1,975 / 2.012 / 2,170 

13 Values used for the normalization calculations 

Coal refuse = 5,000 Btu/lb & 227 lb CO2/MMBtu 

Lignite = 7,000 Btu/lb & 216 lb CO2/MMBtu 

Dried lignite = 9,000 Btu/lb & 216 lb CO2/MMBtu 

Subbituminous = 9,000 Btu/lb & 212 lb CO2/MMBtu 

Bituminous = 11,000 Btu/lb & 205 lb CO2/MMBtu 

Petroleum coke = 13,000 Btu/lb & 225 lb CO2/MMBtu
10

Figure 6: Summary of Demonstrated Technologies for Large EGUs14

Emission standard (lb CO2/MWhnet) Demonstrated by Technologies & Fuel 

2,100 Coal refuse-fired ultra-supercritical 2,000 Lignite or petroleum coke-fired supercritical 1,900 Subbituminous-fired supercritical 

Lignite or petroleum coke-fired ultra-supercriti

1,800 Bituminous-fired supercritical 

Lignite or petroleum coke-fired advanced ultra-supe

1,700 Bituminous or subbituminous-fired advanced ultra-super

14 Values used for normalization calculations 

Standard subcritical steam conditions = 16.5 MPa & 566 oC steam with a single steam reheat cycle 

Best subcritical steam conditions = 21 MPa & 570 oC steam with a single steam reheat cycle 

Supercritical steam conditions = 24.1 MPa & 593 oC steam with a single steam reheat cycle 

Ultra-supercritical steam conditions = 30 MPa & 605 oC with a double steam reheat cycle 

Advanced ultra-supercritical steam conditions = 37.5 MPa & 710 oC with a double steam reheat cycle 
11

Figure 7: Example Normalized Wygen III data 

Facility Wygen III 

(base) 

Normalize 1 (Best subcritical, Tower) 

Normalize 2 (Best subcritical, Dry) 

Normalize 3 (Standard subcritical, Tower) 

Primary Fuel Sub Bit / Sub / Dried Lig / PC / 

Lig / Ref 

Bit / Sub / Dried Lig / PC / Lig / Ref 

Bit / Sub / Dried Lig / PC Lig / Ref 

Steam Pressure (MPa) 11 21 21 16.5 Primary Steam Temperature (oC) 541 570 570 566 Number of Steam Reheat Cycles 0 1 1 1 Cooling Technology Dry Tower Dry Tower Average Ambient Temperature (oC) 8.3 20 (10 Ref) 20 (10 Ref) 20 (10 Ref) Average Operating Capacity Factor 85% 85% 85% 85% 99% Confidence Emission Rate (lb CO2/MWhnet) 

2,320 1,832 / 1,927 / 1,967 / 

1,976 / 2,013 / 2,139 

1,924 / 2,025 / 2,067 / 2,076 / 2,114 / 2,247 

1,862 / 1,960 / 2,000 / 2,009 / 2,046 / 2,175 

Figure 8: Summary of Demonstrated Technologies for Small EGUs 

Emission standard (lb CO2/MWhnet) Demonstrated by Technologies & Fuel 

2,300 All coal-fired EGUs at standard subcritical conditions and 2,200 Coal refuse-fired EGU with tower or dry coolin2,100 Lignite and petroleum coke-fired EGU with dry co2,000 Subbituminous-fired EGU with dry cooling 

Lignite and petroleum coke-fired EGU with cooling 

1,900 Bituminous-fired EGU with dry cooling 

Subbituminous-fired EGU with cooling towe

1,800 Bituminous-fired EGU with cooling tower 
12

Figure 7 shows the normalization of the Wygen III data using various steam cycles and fuels, and Figure 

8 shows the configurations that would be able to achieve various emission standards. As shown in 

Figures 7 and 8, at the proposed emission rate of 2,100 lb CO2/MWhnet a reconstructed EGU burning 

any solid fossil fuel other than coal refuse could achieve the standard using subcritical steam conditions 

and a dry cooling system. A reconstructed coal refuse-fired EGU could achieve the standard using 

subcritical steam conditions and a cooling tower. However, the EPA is not aware of any coal refusefired EGUs located in arid regions that currently use dry cooling. A more stringent emission standard of 

2,000 lb CO2/MWhnet has been demonstrated to be achievable by all coal types except coal refuse. The 

EPA is only aware of subbituminous-fired EGUs using dry cooling, so with the exception of coal-refusefired EGUs, this standard has been demonstrated as nationally achievable without additional control 

technologies. A more stringent standard would require reconstructed EGUs to use higher quality coals 

and/or cooling towers. Additional compliance options would include co-firing natural gas, a hybrid 

power plant, integration of non-emitting generation technologies, and combined heat and power. At less 

stringent emission rates, the best subcritical steam conditions would not be required. 

Cost of More Efficient Design Parameters 

The National Energy Technology Lab (NETL)15 has estimated that the capital costs for a supercritical 

EGU is approximately 1 percent more than a comparable subcritical EGU. However, the reduced fuel 

costs are significant enough that the overall costs to generate electricity is actually 2% lower for a 

supercritical EGU compared to a subcritical EGU. Therefore, supercritical EGUs are considered costeffective on strictly economic factors without accounting for the environmental benefits. Modern 

materials are widely available that can tolerate the maximum subcritical steam parameters. Therefore, 

we anticipate a low incremental cost of increasing steam parameters within subcritical conditions. 

Multiple sources support the trend that the overall cost to generate electricity decreases when moving 

from subcritical to supercritical/ultra-supercritical steam conditions. However, it is not clear that the fuel 

savings from the use of advanced ultra-supercritical conditions currently outweighs the additional capital 

costs. Nevertheless, the price premiums are relatively low and the environmental benefits of higher 

efficiencies have not been factored into the cost of generating electricity. For example, the NETL16 has 

estimated that due to the exotic materials required, the capital costs of an ultra-supercritical EGU are 5% 

higher and the overall cost of electricity is 3% higher than a comparable supercritical EGU. It should be 

noted that the price premium for the materials required for ultra-supercritical boilers could decline as 

more installations occur globally, and the recently constructed Turk facility in Arkansas, which uses 

ultra-supercritical steam conditions, was built without a federal regulatory driver to reduce CO2

emissions. 

                                                            

15 Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, 

Revision 2a (September 2013), DOE/NETL-2010/1397. Available at: http://www.netl.doe.gov/research/energyanalysis/energy-baseline-studies 

16 Cost and Performance Baseline for Fossil Energy Plants Volume 3b: Low Rank Coal to Electricity: Combustion Cases 

(March 2011), DOE/NETL-2011/1463. Available at: http://www.netl.doe.gov/research/energy-analysis/energy-baselinestudies