MEMORANDUM 

From: The Office of Air Quality Planning and Standards 

 U.S. Environmental Protection Agency 

To: EGU NSPS Docket (EPA-HQ-OAR-2011-0044) 

Date: December, 2011 

Subject: Control of SO2 Emissions 

Introduction 

During combustion, the organic and pyretic sulfur in coal predominately oxidizes to sulfur dioxide (SO2) 

gas. A small portion of the SO2 further oxidizes to sulfur trioxide (SO3), which forms sulfuric acid mist 

(H2SO4) when combined with water. SO2 emissions from EGUs are typically controlled by precombustion, add-on controls, or a combination of the two. The two types of add-on controls applicable 

to EGUs include: in-situ combustion control (sorbent injection) and post-combustion flue gas 

desulfurization (FGD). In-situ control is used effectively in fluidized bed (FB) boilers, and may be used 

in a pulverized coal (PC) boiler by dry injection of sorbents. Post-combustion controls applicable to 

EGUs include wet scrubbing or spray dryer absorber (SDA) technology. Pre-combustion control limits 

the sulfur content of the fuel. Add-on control technologies rely on either absorption or adsorption 

processes that react SO2 with lime, limestone, or another alkaline material to form an aqueous or solid 

sulfur by-product. 

The present subpart Da SO2 emissions standard for owners/operators of new facilities is 1.4 pounds per 

megawatt hour gross output (lb/MWh gross) or 95% reduction of the potential emissions on a 30-day 

rolling average basis. The standard for owners/operators of reconstructed affected facilities is 1.4 

lb/MWh, 0.15 lb/MMBtu heat input, or 95% reduction in potential emissions. The standard for 

owners/operators of modified affected facilities is 0.15 lb/MMBtu or 90% reduction in potential 

emissions. The dual standard reflects that higher removal efficiencies tend to be more practical when 

there is a high concentration of SO2 in the flue gas, and vice versa. 

The amended subpart Da SO2 emissions standard for owner/operators of new and reconstructed affected 

facilities is 1.0 lb/MWh gross output or 97% reduction of potential emissions on a 30-day rolling 

average basis. We are not proposing to amend the SO2 standard for owners/operators of modified 

affected facilities or owners/operators of affected coal refuse-fired facilities. 

Add-on SO2 Control Technologies 

The following is a brief summary of some of the SO2 control technologies, including propriety 

technologies. This summary is not intended to be a comprehensive list of available technologies. The 

performance values given here are those that have been provided by the technology provider in 

publically available sources. Inclusion of a technology in this summary is not intended to be an 

endorsement of that technology by the US EPA the US Government 

Coal gasification 

The gasification process breaks coal apart into its chemical constituents (typically a mixture of carbon 

monoxide, hydrogen, and other gaseous compounds) prior to combustion. Sulfur in the product syngas is 

present as H2S and technologies such as Selexol, Rectisol and desulfurization sorbents can effectively 

reduce the concentration of H2S in the syngas stream prior to combustion in the downstream combustion 

turbine. Any residual H2S the syngas stream will be converted to SO2 in the combustion turbine. 

Gasification allows for the reduction of SO2 emissions by over 99% and is the only pre-combustion 

technique that is a feasible standalone NSPS control technologies. The other pre-combustion approaches 

are incapable of meeting the NSPS as a standalone approach. 
In-situ SO2 Control Technologies 

Furnace Sorbent Injection (FSI). Furnace Sorbent Injection is another once-through dry technology that 

utilizes dry lime or limestone as the reagent to absorb SO2. In the FSI technology, the reagent (e.g., 

finely crushed limestone) is injected directly into the furnace and the reaction product is collected in the 

downstream particulate control device. 

Limestone Injection Dry Scrubbing (LIDS). Limestone Injection Dry Scrubbing (LIDS) combines FSI 

and dry scrubber technologies. In the LIDS system, limestone is injected into the furnace and a spray 

dryer absorber is installed between the air heater and particulate collection device. A potential reagent 

used in the spray dryer is a hydrated reaction byproduct recycled from the particulate collection device. 

Fluidized-bed (FB) boilers. FB boilers generally control the majority of SO2 by adding finely crushed 

limestone along with the coal (or other solid fuel) to the fluidized bed. During combustion, calcination 

of the limestone (reduction to lime by subjecting to heat) occurs simultaneously with the oxidation of 

sulfur in the coal to form SO2. The SO2, in the presence of excess oxygen, reacts with the lime particles 

to form calcium sulfate. The sulfated lime particles are removed with the bottom ash or collected with 

the fly ash by a downstream PM control device. Fresh limestone is continuously fed to the bed to replace 

the reacted limestone. 

Post-Combustion SO2 Control Technologies 

Post combustion control technologies that rely upon chemical reactions to reduce the concentration of 

SO2 in the flue gas are often referred to as FGD systems. The potentially applicable add-on technologies 

for control of SO2 emissions can be classified as either once-through or regenerable. In once-through 

technologies, the SO2 is permanently bound with the sorbent, which must then be disposed of as a waste 

or utilized as a by-product (e.g., gypsum). Once-through ammonia- based FGD systems typically 

produce a liquid or solid fertilizer byproduct. In regenerable technologies, the SO2 is released from the 

sorbent during regeneration and processed to yield a potentially valuable by-product (e.g., sulfuric acid 

or elemental sulfur). The regenerated sorbent is then recycled for re-use. 

Both once-through and regenerable technologies can be further classified as either wet or dry 

technologies. Characteristics of a wet FGD system include low flue gas outlet temperatures of 50oC to 

60oC (120oF to 140oF), saturated flue gas conditions, and a wet reaction product. The particulate control 

system is typically located upstream of a wet FGD. This allows for particulate and FGD reaction 

products to be collected separately. Semi-dry FGD systems are located upstream of the particulate 

control system and operate at temperatures well above saturation, 120oC to 180oC (250oF to 350oF). True 

dry processes use dry sorbent injection without water addition. Locating the dry or semi-dry FGD 

system upstream of the particulate control system allows for a common collection location for both the 

fly ash and the FGD reaction product. 

Dry Sorbent Injection. Dry sorbent injection can be used to reduce SO2 and sulfuric acid (H2SO4) mist 

emissions from EGUs. The system works by injecting a powdered sorbent (such as hydrated lime, soda 

ash, limestone, or sodium bicarbonate) into the ductwork between the air pre-heater and the particulate 

collection device. Some systems use spray humidification followed by dry injection. SO2 is adsorbed 

and reacts with the powdered sorbent. The dry solids are entrained in the combustion gas stream, along 

with fly ash, and then collected by the downstream PM control device. The effectiveness of this control 

technology for removing SO2 emissions depends on the sorbent used and the injection rate. However, 

the SO2 removal efficiencies for existing dry injection systems are lower than for the other FGD 

technologies, ranging from approximately 40 to 60% when using lime or limestone, and up to 90% using 

other sorbants (e.g., sodium bicarbonate). 

Spray Dryer Absorber (SDA). The SDA is located upstream of the particulate collection system. The 

flue gas passes through a spray dryer vessel, where it encounters a fine mist of lime slurry. The SO2
reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate. When a fabric 

filter is used as the particulate control device, it allows for further reaction of the lime with the sulfur 

(and other acid gases) in the flue gas. This is because all flue gas must pass through the layer of porous 

filter cake containing the reagent on the surface of the filter. The collected waste product from an SDA 

system can be disposed in a landfill, sold as by-product, or recycled into the slurry mixture. The SO2

removal efficiencies of new lime spray dryer systems are generally greater than 90%. 

Advanced Semi-dry FGD Circulating Dry Scrubber (CDS). Circulating dry scrubber (CDS) systems 

utilize a fluidized bed of moistened reagent for absorbing SO2. The fluidization of the particles is 

accomplished by the vertical upward flow of flue gas through the reactor. The reagent is typically dry 

hydrated lime. Water is injected into the CDS reactor independent of the reagent. The CDS reactor 

promotes absorption of SO2 into the water and the reaction of SO2 with the hydrated lime by intense gassolid mixing. The reaction products include calcium sulfite and calcium sulfate. The reaction products, 

unreacted lime, and fly ash are then collected downstream in the particulate collection device. Several 

advanced semi-dry FGD technologies are similar to the CDS system, including Turbosorp®, flash dryer 

absorber (FDA) (also known as NIDS), and other circulating fluidized bed (CFB) dry scrubbers. 

Wet Scrubber. In a wet scrubber system, a reagent is slurried with water and sprayed into an absorber 

vessel located downstream of the particulate control device. Flue gas enters at the bottom of the absorber 

tower, continues vertically through the water spray, resulting in intimate liquid-to-gas contact, passes 

through a mist eliminator to control the re-entrained slurry drops, and then exits the tower. The intimate 

contact results in the SO2 absorption into the liquid and the reaction with the reagent. The by-products of 

the sorption and reaction are in a wet form upon leaving the system and must be dewatered using 

thickeners, centrifuges, or vacuum filters prior to transport/disposal. The final slurry may contain 10 to 

40% water by weight. A wet scrubber system consumes between 25 to 33% more water than a 

comparable SDA scrubber. The SO2 removal efficiencies of new alkali wet scrubbing systems are 

generally greater than 95%. 

Wet FGD systems can utilize a variety of alkaline mediums to remove SO2 from the flue gas. These 

mediums include lime, limestone, sodium carbonate, magnesium oxide, dual alkali, high alkalinity fly 

ash, and amine-based liquors such as ammonia. Seawater has also been used as a reagent, since it has a 

high concentration of dissolved limestone. All of these systems produce a byproduct that may either be 

disposed of or sold. Most installed wet FGD systems use lime or limestone scrubbing reagents. Since 

limestone is much less expensive, it is used more often. This is especially the case for medium to high 

sulfur coals. A common wet scrubber application utilizes limestone as the reagent and forced oxidation 

of the reaction by-products to form calcium sulfate (synthetic gypsum). An inhibited oxidation system 

will produce calcium sulfite that is more difficult to dewater and has very little potential for commercial 

use, and is typically disposed of in a landfill. 

Enhanced Wet Flue Gas Desulfurization. Enhanced wet scrubbers include (1) the use of buffering agents 

for the scrubber slurry, (2) novel methods of contacting the flue gas and slurry, and (3) methods for 

preventing flue gas sneakage through the scrubber (i.e., flue gas that has received little or no treatment). 

Buffering agents may reduce the operating costs by reducing the amount of liquid that needs to be 

recycled in the absorber tower. The buffering agents typically used are organic acids or salts of these 

acids. Other developments in wet FGD pollution control include design features within the absorber 

tower that minimize operating costs. The Jet Bubbling Reactor, developed by Chiyoda, and Alstom’s 

Flowpac systems are examples of designs that were developed to improve liquid-to-gas contact by 

forcing the flue gas to bubble through the slurry. This is done by utilizing a gas sparger design rather 

than spraying the flue gas with slurry. Another wet FGD liquid-to-gas contact design application is the 

perforated plate scrubber. Yet another developed design includes bidirectional sprays and wall rings to 

be used within the wet FGD absorber tower in order to reduce SO2 sneakage over the conventional FGD. 
All these wet FGD design technologies improve the liquid-to-gas contact while increasing pressure drop 

instead of increasing pumping requirements. Modern wet FGD designs can achieve 98 to 99% SO2

removal for medium to high sulfur coals on an annual basis. 

Regenerable Wet Scrubber. This technology uses sodium sulfite, magnesium oxide, sodium carbonate, 

amine, or ammonia as the sorbent for removal of SO2 from the flue gas. The spent sorbent is regenerated 

to produce concentrated streams of SO2 or other sulfur compounds, which may be further processed to 

produce other products. These FGD technologies may require additional flue gas treatment prior to the 

SO2 absorption process to remove other flue gas constituents, such as hydrogen chloride and hydrogen 

fluoride, that may affect the sorbent and/or final by-product. 

Multi-Pollutant Technologies 

Several multi-pollutant control technologies in various stages of commercial development are available 

to reduce SO2 emissions. These include, but are not limited to, the Airborne ProcessTM, the APTECH 

CST process, the CEFCO process, Eco Power’s COMPLY 2000, the copper-oxide (CuO) process, 

Powerspan’s Electro Catalytic Oxidation (ECO®) process, the electron beam (E-Beam) process, the 

Indigo Multi Air Pollutant System (MAPSystemTM) process, the Nalco Mobotec technology, The 

NOXSO process, the Pahlman process technology developed by Enviroscrub, ReACTTM, Skyonic’s 

SkyMine®, TOPSØE SNOXTM, and the SOx-NOx-Rox Box (SNRBTM) process. These technologies 

offer the potential for improved environmental performance at lower costs than traditional technologies. 

This list is intended to merely illustrate that the multiple technologies exist and may not include all 

available technologies. EPA and the U.S. government do not endorse any of the listed multi-pollutant 

technologies. 

SO2 Control Performance 

30-day SO2 emission rates were calculated by dividing the sum of the unadjusted emissions for all non 

out-of-control operating hours by the sum of the gross electrical energy output over the same period as 

reported to the Clean Air Markets Division (CAMD) of EPA. Out-of-control hours were defined as 

when either the unadjusted applicable emissions or gross output could not be determined for that 

operating hour. The reduction in potential SO2 emissions was calculated by comparing the reported SO2

emissions during a 30-day period to the potential emissions for that same 30-day period. Potential 

uncontrolled SO2 emissions were calculated using monthly delivered fuel receipts and fuel quality data 

from the Energy Information Administration (EIA) forms EIA-923 (utility and nonutility coal data post 

2007), EIA-423 (nonutility coal data prior to 2008), and FERC-423 (utility coal data prior to 2008), as 

applicable. For each operating day, the total potential uncontrolled SO2 emissions were calculated by 

multiplying the uncontrolled SO2 emissions rate for the applicable month as determined using the EIA 

data by the heat input for that day. For locations with multiple affected facilities burning different fuel 

combinations, we used the information submitted to the Toxics’ rule information collection request 

(ICR) on individual boiler fuel use data to apportion the fuels to the separate affected facilities. In 

addition, for locations with combustion turbines we used the fuel use data reported using EIA-906 and 

920 to subtract out the natural gas and/or distillate oil burned in the combustion turbines. Figures 1 

shows the performance of the best performing facilities in terms of percent reduction in potential SO2

emissions. 
Figure 1: SO2 Emissions Performance Data 

Facility Time Period Maximum 30-Day 

SO2 Emissions 

Rate (lb/MWh) 

Minimum 30-

Day % SO2

Reduction 

Cayuga 1 12/08 – 12/10 1.03 97.4 

Harrison 1 01/06 – 01/09 1.45 96.7 

Harrison 2 01/06 – 01/09 1.01 97.7 

Harrison 3 01/06 – 01/09 0.97 98.2 

HL Spurlock 1 06/09 – 12/10 1.83 96.9 

HL Spurlock 2 11/08 – 12/10 1.26 98.0 

HL Spurlock 3 01/09 – 12/10 1.45 96.5 

HL Spurlock 4 01/09 – 12/10 1.08 97.7 

Wansley 1 02/09 – 12/10 0.31 97.7 

Wansley 2 05/09 – 12/10 0.37 97.4 

Iatan 1 04/09 – 12/10 0.16 98.2 

Jeffrey 2 05/09 – 12/10 0.09 99.0 

Jeffrey 3 04/09 – 12/10 0.13 98.5 

Trimble County 1 01/05 – 12/10 1.14 97.6 

Mountaineer 1 05/07 – 12/10 1.15 97.6 

With the exception of the HL Spurlock 3 and 4 and Harrison facilities, all of the listed facilities use wet 

limestone based scrubbers. HL Spurlock 3 and 4 are fluidized bed boilers that remove the majority of 

SO2 using limestone injection into the boiler and then remove additional SO2 by lime injection into the 

ductwork prior to the fabric filter. The Harrison facilities use wet magnesium on demand lime scrubbing 

technology. Of the identified best performing facilities, we only have multiple years of performance 

data for the Harrison, Trimble County, and Mountaineer facilities. Based on the performance of these 

facilities, we have concluded that 97% reduction in potential SO2 emissions has been demonstrated and 

is achievable on a long term basis. Therefore, the proposed upper limit on a percent reduction basis is 

97%. Even though the Iatan and Jeffery facilities are achieving a 98% reduction in potential SO2

emissions we are not proposing this standard because it is based on relatively short term data. Based on 

the variability in SO2 reductions from the Harrison, Trimble County, and Mountaineer facilities, we 

have concluded that short term data does not necessarily take into account the range of operating 

conditions that a facility would be expected to operate or control equipment variability and degradation. 

The sulfur concentrations in the flue gas of EGUs burning medium and low sulfur coals is more diffuse 

than for EGUs burning high sulfur coals, and it has not been demonstrated that facilities burning these 

coals would be able to achieve 97% reduction of potential emissions on a continuous basis. Therefore, 

we are proposing an alternate numerical standard in conjunction with the percent reduction standard. To 

determine an appropriate alternate numerical standard, we evaluated the performance of several recently 

constructed facilities in addition to the numerical standards for the facilities in Figure 1. Figure 2 shows 

the maximum 30-day average SO2 emissions rate of facilities that commenced operation between 2005 

and 2008, that are emitting at levels below the current NSPS, that are reducing potential SO2 emissions 

by less than 97%, and that reported both SO2 emissions and gross electric output data to CAMD.
Figure 2: SO2 EMISSIONS PERFORMANCE DATA FOR NEW FACILITIES 

Facility Time Period In Service 

Date 

Maximum 30-Day SO2

Emissions Rate (lb/MWh) 

Minimum 30-Day % 

SO2 Reduction 

Weston 4 01/08 – 12/09 2008 0.61 90.0 

Cross 4 05/08 – 12/09 2008 1.02 96.5 

TS Power Plant 1 06/08 – 12/09 2008 0.56 91.8 

Wygen II 01/08 – 12/09 2008 0.95 92.5 

Walter Scott Jr. 

Energy Center 4 

07/07 – 12/09 2007 0.73 87.7 

Cross 3 01/07 – 12/09 2007 1.06 95.9 

Springerville TS3 04/07 – 12/09 2006 1.04 93.0 

With the exception of the Cross 3 and 4 facilities, which burn medium sulfur bituminous coals and use 

wet limestone-based scrubbers, the remaining facilities burn lower sulfur subbituminous coals and use 

lime-based spray dyers. To provide the maximum emissions reduction, we concluded that the alternate 

numerical standard should be as stringent as the numerical rates achieved by the facilities used to 

determine the percent reduction standard. If the alternate numerical standard were less stringent than the 

emissions rate achieved by the facilities used to determine the maximum percent reduction, those 

facilities would not be required to achieve the maximum percent reduction that has been demonstrated. 

In addition, the numerical standard should account for variability in today’s SO2 control technologies 

and provide sufficient compliance margin for owners/operators of new facilities burning medium sulfur 

coals to comply with the numerical standard and thereby provide an incentive to burn cleaner fuels. We 

are proposing 1.0 lb/MWh as the alternate numerical standard because it provides a comparable level of 

performance to the 97% reduction requirement and satisfies the criteria mentioned above. The numerical 

standard would require at least 80% reduction even from the lowest sulfur coals and would 

accommodate the use of spray dryer scrubbers for owner/operators of new facilities burning coal with 

uncontrolled SO2 emissions of up to approximately 1.6 lb/MMBtu. 

Based on the performance of the spray dryer at the Springerville TS3 power plant, the numerical 

standard would provide sufficient flexibility such that an owner/operator of an EGU could burn over 

90% of the subbituminous coals presently being used in combination with a spray dryer. This 

technology choice provides owners/operators the flexibility to minimize water use and associated waste 

water discharge, as well as reducing additional CO2 that is chemically created as part of the SO2 control 

device. Even though there is not necessarily an overall GHG reduction from using a lime based instead 

of a limestone based scrubber, lime production facilities have relatively concentrated CO2 streams. 

Capture and storage of CO2 at the lime manufacturing facility could potentially be easier since 

separation of the CO2 would not be necessary, as is the case with an EGU exhaust gas. Owners/operators 

of new and reconstructed facilities burning coals with higher uncontrolled SO2 emissions could either 

use IGCC with a downstream process to control sulfur prior to combustion, fluidized bed combustion, or 

a wet SO2 scrubbing system to comply with the standard. The proposed limit would allow the higher 

sulfur coals (uncontrolled emissions of greater than approximately 3 lb SO2/MMBtu) to demonstrate 

compliance with the 97% reduction requirement as an alternative to the numerical limit. 
Post Proposal SO2 Control Performance 

Post proposal EPA evaluated 2010 emissions data and recalculated the emissions averages using 30 operating day av

hour averages used as a proxy for a 30-day average in the proposal. This calculation approach is consistent with how 

determined. The revised approach results in slight changes from values listed in proposal, but nothing significant enoconclusions. Figure 3 shows the performance of facilities identified by EPA with minimum % reductions of 97% or 

Figure 3: SO2 Emissions Performance Data for Facilities Demonstrating 97% Reduction in Potential Emissions 

Facility Fuel 

Type 

Control 

Technology 

Nominal Uncontrolled 

SO2 Emissions Rate 

(lb/MMBtu) 

Maximum 30-Day 

SO2 Emissions 

Rate (lb/MWh) 

99% Confidence 30-

Day SO2 Emissions 

Rate (lb/MWh) 

Coffeen 1 (1/10 – 12/10) SUB Cyc + Wet FGD 1.1 0.15 0.15 Coffeen 2 (1/10 - 12/10) SUB Cyc + Wet FGD 1.1 0.14 0.12 Dallman 4 (11/09 – 12/10) BIT PC + Wet FGD 6.1 1.96 2.15 Cayuga 1 (12/08 – 12/10) BIT PC + Wet FGD 3.4 1.03 0.91 Cayuga 2 (6/09 – 12/10) BIT PC + Wet FGD 3.4 1.15 1.04 John E Amos 2 (4/10 – 12/10) BIT PC + Wet FGD 3.8 0.86 0.81 John E Amos 3 (1/10 – 12/10) BIT PC + Wet FGD 3.8 0.82 1.01 H L Spurlock 2 (1/08 – 12/10) BIT PC + Wet FGD 3.9 1.38 1.65 H L Spurlock 3 (1/09 – 12/10) BIT CFB + Dry Lime 3.9 1.54 1.50 H L Spurlock 4 (3/09 – 12/10) BIT CFB + Dry Lime 3.9 1.07 1.06 Iatan 1 (4/09 – 12/10) SUB PC + Wet FGD 0.8 0.16 0.12 Iatan 2 (10/10 - 12/10) SUB PC + Wet FGD 0.8 0.07 0.08 Jeffrey Energy Center 2 (5/09 – 12/10) 

SUB PC + Wet FGD 0.9 0.20 0.22 

Trimble County 1 (11/05 – 12/10) BIT PC + Wet FGD 5.4 1.35 1.23 Oak Grove 2 (5/10 - 12/10) LIG PC + Wet FGD 2.9 0.81 0.81 J K Spruce 2 (4/10 - 12/10) SUB PC + Wet FGD 0.8 0.18 0.18 Sandow 5B (10/09 – 12/10) LIG CFB + Dry Lime 4.1 1.27 1.18 Elm Road 1 (12/09 - 12/10) BIT PC + Wet FGD 2.6 0.15 0.15 Elm Road 2 (8/10 - 12/10) BIT PC + Wet FGD 2.6 0.10 0.13 The 99% confidence standard was calculated by adding (subtracting for % reduction) 2.57 standard deviation to the While multiple facilities are achieving greater than 98% reduction, this performance data is relatively short term and establishing a continuous standard that is achievable for the life of a new EGU. To account for long term achievabili

the sulfur content of the fuel being burned, EPA further limited the subset of EGUs demonstrating the best system of 

(BSER). Figure 4 shows EGUs with over 22 months of data. In addition, instead of using the monthly delivered fuel 

applicable month, we substituted the lowest value for the present month and the preceding 2 months to account unce

a conservative approach and accounts for the related uncertainty in the sulfur content of the coal actually burned dur
Figure 4: SO2 Emissions Performance Data – Substituted Monthly Coal Values 

Facility Fuel 

Type 

Control 

Technology 

Nominal Uncontrolled 

SO2 Emissions Rate 

(lb/MMBtu) 

Minimum 30-

Day % SO2

Reduction 

99% 

Confidence % 

SO2 Reduction 

Cayuga 1 (12/08 – 12/10) BIT PC + Wet FGD 3.2 96.5 97.3 H L Spurlock 2 (1/08 – 12/10) BIT PC + Wet FGD 3.5 97.5 97.1 H L Spurlock 3 (1/09 – 12/10) BIT CFB + Dry Lime 3.5 96.4 96.5 H L Spurlock 4 (3/09 – 12/10) BIT CFB + Dry Lime 3.5 97.3 97.6 Trimble County 1 (11/05 – 12/10) BIT PC + Wet FGD 5.2 96.7 97.3 Figure 4 shows that 97% reduction has been demonstrated as achievable for both fluidized beds and pulverized coal. To evalua

amended SO2 standard we evaluated the performance of facilities that commenced operation since 2007. Figure 5 shows the pe

facilities. 
Figure 5: SO2 Emissions Performance Data for Facilities that Commenced Operation Since 2007 

Facility Fuel 

Type 

Control 

Technology 

Nominal Uncontrolled 

SO2 Emissions Rate 

(lb/MMBtu) 

Maximum 30-Day 

SO2 Emissions 

Rate (lb/MWh) 

99% Confidence 30-

Day SO2 Emissions 

Rate (lb/MWh) 

Weston 4 (1/08 – 12/10) SUB PC + Spray Dryer 0.7 0.61 0.62 TS Power Plant 1 (6/08 – 12/10) SUB PC + Spray Dryer 0.7 0.56 0.51 Wygen II (1/08 – 12/10) SUB PC + Spray Dryer 1.0 0.95 0.86 Wygen III (2010) SUB PC + Spray Dryer 1.0 0.60 0.65 Walter Scott Jr. Energy Center 4 (6/07 – 12/10) 

SUB PC + Spray Dryer 0.7 0.87 0.80 

Springerville TS3 (7/07 – 12/10) SUB PC + Spray Dryer 1.7 0.90 0.93 Springerville 4 (12/09 – 12/10) SUB PC + Spray Dryer 1.7 0.91 0.95 Comanche 3 (6/10 – 12/10) SUB PC + Spray Dryer 0.6 0.87 0.88 Plum Point (7/10 – 12/10) SUB PC + Spray Dryer 0.7 1.26 1.36 Nebraska City 2 (5/09 – 12/09) SUB PC + Spray Dryer 0.7 0.91 0.91 Cross 3 (1/07 – 12/10) BIT PC + Wet FGD 2.8 1.06 1.15 Cross 4 (5/08 – 12/10) BIT PC + Wet FGD 2.8 1.02 1.15 Elm Road 1 (12/09 - 12/10) BIT PC + Wet FGD 2.6 0.15 0.15 Elm Road 2 (8/10 - 12/10) BIT PC + Wet FGD 2.6 0.10 0.13 Oak Grove 1 (12/09 – 12/10) LIG PC + Wet FGD 2.9 1.01 0.93 Oak Grove 2 (5/10 - 12/10) LIG PC + Wet FGD 2.9 0.81 0.81 J K Spruce 2 (4/10 - 12/10) SUB PC + Wet FGD 0.8 0.18 0.18 Sandow 5A (12/09 – 12/10) LIG CFB + Dry Lime 4.1 1.41 1.52 Sandow 5B (10/09 – 12/10) LIG CFB + Dry Lime 4.1 1.27 1.18 H L Spurlock 4 (3/09 – 12/10) BIT CFB + Dry Lime 3.9 1.07 1.06 Iatan 1 (4/09 – 12/10) SUB PC + Wet FGD 0.8 0.16 0.12 Iatan 2 (10/10 – 12/10) SUB PC + Wet FGD 0.8 0.07 0.08 Dallman 4 (11/09 – 12/10) BIT PC + Wet FGD 6.1 1.96 2.15 

With the exception of Plum Point, Cross3 and 4, and Sandow 5A, all of the EGUs that have recently commenced conemissions rates that what would be required by the amended standards. This is not unexpected since EGUs are subje(NSR) and other programs that require stringent controls. The Plum point facility has only been operating less than 6 provides 180 days to demonstrate initial compliance to account for commissioning so it is not unexpected that emiss

3 and 4 facilities use subcritical steam conditions (2,400 psi and 1,050 oF). A new facility using the same control con

supercritical steam conditions the same as Weston 4 (3,775 psi and 1,085 oF) would increase the heat rate sufficientl

numerical standard. Another option for either of the Cross facilities or the Sandow 5A facility would be to operate thbest performers. 
To evaluate the impact of including periods of startup and shutdown, EPA compared the emission rates of the John E. Amos fa

periods of startup and shutdown. Any hour with less than 24 hours of operation was considered a startup or shutdown day and dthe alternate emissions rate. The differences in the calculated 30-day emission rates between the data submitted to the docket an

the procedure used to calculate the 30-day averages. The EPA 30-day averages are calculated using the procedures described in emissions of the applicable pollutant divided by the sum of the gross output) and the commenter used the average of the hourly 

day period. As stated in the proposal, the EPA procedure result in lower numerical emission rates because hours with high emis

inputs (typically of startup, shutdown, and low load operation) are not weighted as heavily.

Figure 6: Impact of Including Periods of Startup and Shutdown on SO2 Emissions Performance Data 

Facility 99% Confidence 30-

Day SO2 Emissions 

Rate (lb/MWh) 

99% Confidence 30-Day SO2

Emissions Rate Without Startup 

or Shutdown (lb/MWh) 

99% 

Confidence % 

SO2 Reduction 

99% Confidence % SO

Reduction Without 

Startup or Shutdown 

John E Amos 2 (4/10 – 12/10) 0.81 0.73 97.4 97.6 John E Amos 3 (1/10 – 12/10) 1.01 0.94 97.5 97.6 As shown in Figure 6, if EPA were to exclude periods of startup and shutdown from the emissions standard the num

percent reduction standard would have to be reevaluated. Figure 7 graphically illustrates the amended standard compared to two alternatives suggested by commenters. The m

would essentially drive the market to the lowest sulfur coals. The less stringent standard does not represent the best s

reduction. 
86%

88%90%92%94%96%98%

100%

0 1 2 3 4 5 

Percent Reduction

Nominal Uncontrolled SO2 Emisisons Rate (lb/MMBtu)

Figure 7. Amended Standard Compared to Performace of Recent EGU

Alternate Standard: 0.70 lb/MWh or 98%Amended Standard: 1.0 lb/MWh or 97%Alternate Standard: 1.15 lb/MWh or 96%New EGU Minimum % Reduction