### 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 (B SER) for Reconstructed St eam Generating Units and

Integrated Gasification Combined Cycle (IGCC) Facilities 1



### 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 (CO 2 

### ) and other air emissions. Efficiency is reported as the pe rcentage of the

energy in the fuel that is converted to electricity. Heat rate is anot her 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. Lo wer 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 effi ciency (e.g., a change from 40% to 42% is a relative

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

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

rates are reduced there are also reduc tions in fuel extraction related envi ronmental impacts, in the rate of

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

water eco-systems.

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

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

output of an EGU is the gross output minus the total am ount of auxiliary (or parasi tic) electricity used to

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

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

transmission grid for distribut ion 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 CO 2 

### emission rate of

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

influence the CO 2 

### emission rate.

Thermodynamic steam cycle

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

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

the average temperature at which heat is rejected (i.e., condenser temperat ure). 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 conve rting the thermal energy into elec tricity. Supercritical and ultra-

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

(EGUs) and Integrated Gasification Combined Cy cle 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 s quare inch (psi))).

The relationship between heat rate improvements a nd 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 o 

### C (18 o 

### F) increase in steam temperature.

Additional opportunitie s to improve the efficiency of the th ermodynamic cycle incl ude using a double

reheat cycle (which increases the e fficiency 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 efficien cy 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 thr ough 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. Th e International Energy

Agency 3 

### estimates that similar EGUs using a double re heat 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 he at rate) than an iden tical 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 ba ttery is held at an elev ated 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 ba ttery is discharged at a lower temperature (e.g., 10 °C)

. Applications of this technology in systems that use the waste heat fr om EGUs have the potential to

further improve EGU efficiencies. In t ypical 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 th at can be converted into electrici ty 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., undrie d lignite). Bituminous coal s heaving a heating value

of greater than 10,500 Btu/lb, lign ite 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 incr ease the heating value. Pe troleum 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 valu e as estimated by the National Coal Council 5 

### 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/rel eases/2014/05/1 40521133611.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.or g/Documents/Expe diteNov30rpg.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 co als tend to have less CO 2 

### per MMBtu than lower rank coals. Bituminous coals

emit on average 205 lb CO2/MMBtu, subbituminous co als 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 CO 2 

### than a lignite-fired EGU. Petrol eum coke has one of the highest CO 2 

### emissions

rate (225 lb CO 2 

### /MMBtu) of commonly used solid fuels. Of the gaseous and liquid fossil fuels used in

EGUs, natural gas combustion releases approximately 117 pounds of CO 2 

### per MMBtu, distillate oil

releases 161 lb CO 2 

### /MMBtu, and residual oil releases 174 lb CO 2 

### /MMBtu.

EGU cooling system

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

converting the thermal energy in the steam to elec tricity. Once-through cooli ng 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-t hough cooling systems typica lly have larger water

related ecological concerns than recirculating cooling systems. The International Energy Agency 7



### estimates that similar EGUs with once-through cooli ng systems that use sea water and river water would

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

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

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

The Kalina cycle 8 

### is an innovative technology that more effi ciently extracts energy from the working

fluid in an EGU. Instead of using water as the work ing 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 thr ough the turbine. Kalina-cyc le 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.globalgeother mal.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 th e facility site may potentially have an impact on

EGU efficiency. Cooler ambient temperatures theore tically could increase the overall EGU efficiency by

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

efficiency of the cooling system. Where the effici ency 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 th e type of cooling system that can be used (e.g., EGUs located in

arid locations often cannot use once-through cooling). The International Energy Agency 10 

### estimates that

heat rate increases by 0.15% for each 1 o 

### C increase in ambient temperat ure. 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 effici ent 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 Agency 11 

### estimated impact of unit ope rating 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. Howeve r, 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 en ergy, must be sent to th e condenser during start

‐ up. Another factor which can significantly impact efficiency is the number of perturbations (t ransients) from

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

performance. Therefore, the more transients, the gr eater the reduction in effici ency. We have concluded

that a reconstructed EGU would opera te 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 becau se the boiler and steam turbine losses are lower for

larger equipment. However, as equipment si ze increases above approxi mately 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 ar e not inherent differen ces in efficiencies.

Other factors

Pollution control devices require elec tricity to operate and increase the auxiliary (i.e., pa rasitic) loads

and reduce the net efficiencies of EGUs. The a uxiliary load requirement s for nitrogen oxide (NO X 

### ) and

particulate matter (PM) controls are each typically 0.5% of the gro ss output of the facility. The SO 2 

### emissions are controlled using flue gas desulfur ization (FGD) technology. The FGD auxiliary load

requirements are typically between 1-2% of the gr oss output of the facilit y. In addition, some FGD

processes use carbon-containing reagen ts (e.g., carbonates) that form CO 2 

### as a byproduct of the

chemical reactions with SO 2 

### . For a typical unit, the CO 2 

### that is chemically crea ted in a scrubber adds an

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

coals. However, from an overall GHG emissions st andpoint, the use of FGD te chnologies that do not

form byproduct CO 2 

### , such as lime-based scrubbers, do not necessarily reduce emissions. Lime is

manufactured by heating limestone in the ab sence of oxygen to remove a molecule of CO 2 

### (CaCO 3 

### +

heat → CaO + CO 2 

### ). Unless the CO 2 

### is sequestered at the lime production facility, overall GHG

emissions will be similar. A list of FGD processes used for controlling SO 2 

### emissions from coal-fired

EGUs is presented in Figure 3, identifying thos e processes that chemically form additional CO 2 

### . The

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

normalize for chemically created CO 2



### .

Another factor that can influence the thermal effici ency of the steam generato r is the method used for

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

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

the ash is cooled, collected, crushed and conveye d 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 us eful heat is recovere d. Additionally, dry bottom

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

additional water weight and fric tion 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

.6Figure 3. CO2formation from coal-fired EGU flue gas desulfurization (FGD) processes.FGD Type Reagent Forms CO2Overall Reaction(s) ReferenceWet ScrubbingLimestone (CaCO3) yesCaCO3+ SO2+ 1⁄2H2O→CaSO3•1⁄2H2O(s) + CO2;CaCO3+ SO2+ 2H2O + 1⁄2O2→CaSO4•2H2O(s) + CO2Ref 1Magnesium-enhanced lime;Dolomitic lime [Ca(OH)2•Mg(OH)2]no 10Ca(OH)2+ 11SO2+ Mg(OH)2→10CaSO3•1⁄2H2O(s) + MgSO3+ 6H2O Ref 1,4Dual Alkali; Sodium solution andlimeno2NaOH + SO2→Na2SO3+ H20;H2O + Na2SO3+ SO2→2NaHSO3;2NaHSO3+ Ca(OH)2→Na2SO3+ CaSO3•1⁄2H2O + 3/2H2O;Na2SO3+ Ca(OH)2→2NaOH + CaSO3Ref 2Dual Alkali (Dowa) yesAl2O3•Al2(SO4)3+ 3SO2+ 3/2O2→2Al2(SO4)3;2Al2(SO4)3+ 3CaCO3→Al2O3•Al2(SO4)3+ 2CaSO4(s) + 3CO2Ref 3Seawater yes2NaHCO3+ SO2→Na2SO3+ 2CO2+ H20;Na2SO3+ 1⁄2O2→Na2SO4Ref 3Magnesium oxide (MgO) no MgO + SO2→MgSO3Ref 7Hydrogen Peroxide (H2O2) no H2O2+ SO2→H2SO4Ref 3Sodium hydroxide (NaOH) no2NaOH + SO2→Na2SO3+ H20;Na2SO3+ 1⁄2O2→Na2SO4Ref 3Dry/Semi-dryScrubbingHydrated calcitic lime (Ca(OH)2) noCa(OH)2+ SO2→CaSO3•1⁄2H2O(s) + 1⁄2H2O;Ca(OH)2+ SO2+ H2O + 1⁄2O2→CaSO4•2H2O(s)Ref 1Sodium bicarbonate (NaHCO3) yes2NaHCO3+ SO2→Na2SO3+ 2CO2+ H20;2NaHCO3+ SO2+ 1⁄2O2→Na2SO4+ 2CO2+ H20Ref 8Sodium sesquicarbonate (trona) yes2(Na2CO3•NaHCO3•2H2O) + 3SO2→3Na2SO3+ 5H2O + 4CO2;2(Na2CO3•NaHCO3•2H2O) + 3SO2+ 3/2O2→3Na2SO4+ 5H2O + 4CO2Ref 8Sodium carbonate (soda ash, Na2CO3) yes Na2CO3+ SO2+ 1⁄2O2→Na2SO4+ CO2Ref 8Pulverized limestone yes CaCO3+ SO2+ 2H2O + 1⁄2O2→CaSO4•2H2O(s) + CO2Ref 1Other ProcessesAmmonia (NH3) no SO2+ 2NH3+ H2O + 1⁄2O2→(NH4)2SO4Ref 1,5Activated carbon no SO2+ H2O + 1⁄2O2→H2SO4Ref 6Ref 1. Srivastava, Ravi K, Wojciech Jozewicz and Carl Singer, 2001. “SO2Scrubbing 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 ofMining 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 Multi-Pollutant Emission Controls &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 SO2Removal 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. Environmental Protection Agency, NationalRisk 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 SO2Removal,” 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 Waste Management Association,Baltimore, MD. June 23-27, 2002

### 7 

### Best Performing Coal-Fired EGUs

In order to determine the annual average emissions rate (lb CO 2 

### per MWh) that is equivalent to the best

system of emission reduction (BSER), we analyzed da ta reported by owners/ope rators of EGUs to the

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

maintained) EGUs reporting CO 2 

### emissions per megawatt hour of gr oss 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 info rmation collected for the Mercury and Air Toxics

Standard (MATS) rulemaking. The emission data for th e best performing faciliti es was then normalized

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

to increase efficiency and lower the CO 2 

### 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. Th e EPA selected EGUs that reported the lowest

normalized CO 2 

### emission rate to account for (1) design factor s influencing efficiency for which the EPA

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

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

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

incorporate both of these into th e design and operation and maintenan ce practices of a reconstructed

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

had a federal regulatory driver to minimize the CO 2 

### emission rate.

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

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

steam conditions compatible with state-of-the art me tallurgy, 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 rec onstruction projects have

fewer options for lowering the temperature at which h eat 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 ar id regions reliant on air

cooled condensers) currently use dr y cooling technologies. If reconstruc ted, 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 CO 2 

### emission rates were calculated by dividing the sum of the CO 2 

### 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-bas ed emission rate (i.e., 7.5% auxi liary load). Figure 4 shows the

performance of the best performing f acilities in terms of normalized CO 2 

### emissions. Based on the

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

corresponds to BSER is 1,900 lbs of CO 2 

### per megawatt-hour of ne t electric output (lb CO 2 

### /MWh net 

### ) 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 CO 2 

### /MWh net 

### , based on the normalization of that data the EPA

has determined that the 12-month emission lim it that corresponds to BSER is 2,100 lb CO 2 

### /MWh net 

### for

reconstructed EGUs with a base lo ad 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 ( o C) 6.9 8.3

Data Analyzed 2008 - 2013 2010 – 2013

Average Operating Capacity

Factor (Duty Cycle) 78% 85%

99% Confidence Emission

Rate (lb CO 2 /MWh net ) 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 ha ve 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 CO 2 

### /MWh net 

### a

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

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

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

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

Additional compliance options would in clude co-firing natural gas, a hyb rid 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 recons tructed 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-f ired 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 ac hieve an emission rate of 2,100 lb CO 2 

### /MWh.9Figure 5: Example Normalized Weston 4 Data13Facility Weston 4(base)Normalize 1 (Advancedultra-supercritical)Normalize 2 (Ultrasupercritical)Normalize 3 (Supercritical)Normalize 4 (Subcritical)Primary Fuel Sub Bit / Sub / Dried Lig / PC /Lig / RefBit / Sub / Dried Lig / PC /Lig / RefBit / Sub / Dried Lig / PC /Lig / RefBit / Sub / Dried Lig / PC /Lig / RefSteam Pressure (MPa) 26 37.5 30 24.1 21Primary Steam Temperature (oC) 585 710 605 593 570Number of Steam Reheat Cycles 1 2 2 1 1Cooling Technology Tower Tower Tower Tower TowerAverage Ambient Temperature (oC) 6.9 20 (10 Ref) 20 (10 Ref) 20 (10 Ref) 20 (10 Ref)Average Operating Capacity Factor 78% 78% 78% 78% 78%99% Confidence Emission Rate (lbCO2/MWhnet)1,890 1,662 / 1,749 / 1,786 /1,793 / 1,827 / 1,9711,766 / 1,858 / 1,897 /1,905 / 1,940 / 2,0931,831 / 1,926 / 1,966 /1,975 / 2.012 / 2,1701,868 / 1,966 / 2,006 /2,015 / 2,052 / 2,21413Values used for the normalization calculationsCoal refuse = 5,000 Btu/lb & 227 lb CO2/MMBtuLignite = 7,000 Btu/lb & 216 lb CO2/MMBtuDried lignite = 9,000 Btu/lb & 216 lb CO2/MMBtuSubbituminous = 9,000 Btu/lb & 212 lb CO2/MMBtuBituminous = 11,000 Btu/lb & 205 lb CO2/MMBtuPetroleum coke = 13,000 Btu/lb & 225 lb CO2/MMBtu10Figure 6: Summary of Demonstrated Technologies for Large EGUs14Emission standard (lb CO2/MWhnet) Demonstrated by Technologies & Fuel2,100 Coal refuse-fired ultra-supercritical2,000 Lignite or petroleum coke-fired supercritical1,900 Subbituminous-fired supercriticalLignite or petroleum coke-fired ultra-supercritical1,800 Bituminous-fired supercriticalLignite or petroleum coke-firedadvanced ultra-supercritical1,700 Bituminous or subbituminous-firedadvanced ultra-supercritical EGU14Values used for normalization calculationsStandard subcritical steam conditions = 16.5 MPa & 566oC steam with a single steam reheat cycleBest subcritical steam conditions = 21 MPa & 570oC steam with a single steam reheat cycleSupercritical steam conditions = 24.1 MPa & 593oC steam with a single steam reheat cycleUltra-supercritical steam conditions = 30 MPa & 605oC with a double steam reheat cycleAdvanced ultra-supercritical steam conditions = 37.5 MPa & 710oC with a double steam reheat cycle11Figure 7: Example Normalized Wygen III dataFacility Wygen III(base)Normalize 1 (Bestsubcritical, Tower)Normalize 2 (Bestsubcritical, Dry)Normalize 3 (Standardsubcritical, Tower)Normalize 4 (Standardsubcritical, Dry)Primary Fuel Sub Bit / Sub / Dried Lig / PC /Lig / RefBit / Sub / Dried Lig / PC /Lig / RefBit / Sub / Dried Lig / PC /Lig / RefBit / Sub / Dried Lig / PC /Lig / RefSteam Pressure (MPa) 11 21 21 16.5 16.5Primary Steam Temperature (oC) 541 570 570 566 566Number of Steam Reheat Cycles 0 1 1 1 1Cooling Technology Dry Tower Dry Tower DryAverage Ambient Temperature (oC) 8.3 20 (10 Ref) 20 (10 Ref) 20 (10 Ref) 20 (10 Ref)Average Operating Capacity Factor 85% 85% 85% 85% 85%99% Confidence Emission Rate (lbCO2/MWhnet)2,320 1,832 / 1,927 / 1,967 /1,976 / 2,013 / 2,1391,924 / 2,025 / 2,067 /2,076 / 2,114 / 2,2471,862 / 1,960 / 2,000 /2,009 / 2,046 / 2,1751,956 / 2,059 / 2,101 /2,110 / 2,150 / 2,284Figure 8: Summary of Demonstrated Technologies for Small EGUsEmission standard (lb CO2/MWhnet) Demonstrated by Technologies & Fuel2,300 All coal-fired EGUs at standardsubcritical conditions and dry cooling2,200 Coal refuse-fired EGU with tower or dry cooling2,100 Lignite and petroleum coke-fired EGU with dry cooling2,000 Subbituminous-fired EGU with dry coolingLignite and petroleum coke-fired EGU with cooling tower1,900 Bituminous-fired EGU with dry coolingSubbituminous-fired EGU with cooling tower1,800 Bituminous-fired EGU with cooling tower

### 12 

### Figure 7 shows the normalization of the Wygen III data using various steam cycl es and fuels, and Figure

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

Figures 7 and 8, at the proposed emission rate of 2,100 lb CO 2 

### /MWh net 

### a reconstructed EGU burning

any solid fossil fuel other than coal refuse could ac hieve the standard using s ubcritical steam conditions

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

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

2,000 lb CO 2 

### /MWh net 

### 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 w ithout additional control

technologies. A more stringent sta ndard would require reconstructed E GUs 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-em itting generation technologies, and combined heat and power. At less

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

Cost of More Efficient Design Parameters

The National Energy Technology Lab (NETL) 15 

### has estimated that the capita l costs for a supercritical

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

costs are significant enough that th e overall costs to generate electr icity is actually 2% lower for a

supercritical EGU compared to a su bcritical EGU. Therefore, supercri tical EGUs are considered costeffective on strictly economic f actors without accounting for the environmental benefits. Modern

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

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

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

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

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

costs. Nevertheless, the price premiums are relativ ely low and the environmen tal benefits of higher

efficiencies have not been factored into the co st of generating electricity. For example, the NETL 16 

### has

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

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

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

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

ultra-supercritical steam conditi ons, was built without a federal regulatory driver to reduce CO 2



### 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/energ y-analysis/energy-baselinestudies