### MEMORANDUM

From: The Office of Air Qu ality Planning and Standards U.S. Environmental Protection Agency

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

Date: December, 2011

Subject: Control of SO 2 

### Emissions

Introduction

During combustion, the organic and pyret ic sulfur in coal predominatel y oxidizes to sulfur dioxide (SO 2 

### ) gas. A small portion of the SO 2 

### further oxidizes to sulfur trioxide (SO 3 

### ), which forms sulfuric acid mist (H 2 

### SO 4 

### ) when combined with water. SO 2 

### 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 combus tion control (sorbent injection) and post-combustion flue gas desulfurization (FGD). In-situ control is used effectiv ely in fluidized bed (FB) boilers, and may be used in a pulverized coal (PC) boiler by dry injection of sorbents. Post-c ombustion controls applicable to EGUs include wet scrubbing or spray dryer absorb er (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 SO 2 

### with lime, limestone, or another alkaline material to form an aqueous or solid sulfur by-product.

The present subpart Da SO 2 

### emissions standard for owners/opera tors 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/ope rators of reconstructed affected facilities is 1.4 lb/MWh, 0.15 lb/MMBtu heat input, or 95% redu ction in potential emissi ons. The standard for owners/operators of modified affected facilitie s 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 SO 2 

### in the flue gas, and vice versa.

The amended subpart Da SO 2 

### emissions standard for owner/operators of new and reconstructed affected facilities is 1.0 lb/MWh gross output or 97% reduction of poten tial emissions on a 30-day rolling average basis. We are not proposing to amend the SO 2 

### standard for owners/operators of modified affected facilities or owners/operators of affected coal refuse-fired facilities.

Add-on SO 2 

### Control Technologies

The following is a brief summary of some of the SO 2 

### 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. Inclus ion 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 (typi cally a mixture of carbon monoxide, hydrogen, and other gaseous compounds) prior to combustion. Sulfur in the product syngas is present as H 2 

### S and technologies such as Selexol, Rectisol and desulfurization so rbents can effectively

reduce the concentration of H 2 

### S in the syngas stream prior to combustion in the downstream combustion turbine. Any residual H 2 

### S the syngas stream will be converted to SO 2 

### in the combustion turbine.

Gasification allows for the reduction of SO 2 

### emissions by over 99% and is the only pre-combustion technique that is a feasib le standalone NSPS control technologies. The other pre-combustion approaches are incapable of meeting the N SPS as a standalone approach.

### In-situ SO 2 

### 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 SO 2 

### . In the FSI technol ogy, the reagent (e.g., finely crushed limestone) is injected directly into the furnace and the reaction pr oduct 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, lim estone is injected into the furnace and a spray dryer absorber is installed between the air heater and particulate co llection device. A potential reagent used in the spray dryer is a hydrat ed reaction byproduct recycled from th e particulate collection device.

Fluidized-bed (FB) boilers . FB boilers generally c ontrol the majority of SO 2 

### 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 lim e by subjecting to heat) occurs si multaneously with the oxidation of

sulfur in the coal to form SO 2 

### . The SO 2 

### , in the presence of excess oxygen, reacts with the lime particles to form calcium sulfate. The sulfated lime particle s are removed with the botto m ash or collected with the fly ash by a downstream PM control device. Fresh li mestone is continuously fe d to the bed to replace

the reacted limestone.

Post-Combustion SO 2 

### Control Technologies

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

SO 2 

### in the flue gas are often referred to as FGD syst ems. The potentially appli cable add-on technologies

for control of SO 2 

### emissions can be classified as either once-through or regenera ble. In once-through technologies, the SO 2 

### is permanently bound with the sorbent, whic h 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 bypr oduct. In regenerable technologies, the SO 2 

### is released from the sorbent during regeneration and processed to yield a potentially valuable by-pr oduct (e.g., sulfuric acid or elemental sulfur). The regenerated so rbent 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 in clude low flue gas outlet temperatures of 50oC to 60oC (120oF to 140oF), saturated fl ue gas conditions, and a wet reacti on product. The particulate control system is typically located upstream of a wet FGD. This allows for particulate and FGD reaction products to be collected separate ly. Semi-dry FGD systems are located upstream of the particulate control system and operate at temp eratures well above saturation, 120oC to 180oC (250oF to 350oF). True dry processes use dry sorbent inj ection without water addition. Lo cating 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 SO 2 

### and sulfuric acid (H 2 

### SO 4 

### ) 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 ai r pre-heater and the particulate collection device. Some systems use spray humidification followed by dry injection. SO 2 

### is adsorbed and reacts with the powdered sorbent. The dry soli ds 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 SO 2 

### emissions depends on the sorbent used and the injection rate. However,

the SO 2 

### removal efficiencies for existing dry injection systems are lower than for the other FGD technologies, ranging from approxima tely 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, wher e it encounters a fine mist of lime slurry. The SO 2

### 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 al lows for further reaction of the lime with the sulfur (and other acid gases) in the flue gas. This is be cause all flue gas must pa ss 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-pr oduct, or recycled into the slurry mixture. The SO 2 

### removal efficiencies of new lime spray drye r 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 SO 2 

### . The fluidization of the particles is accomplished by the vertical upward flow of flue ga s through the reactor. The r eagent is typically dry hydrated lime. Water is injected into the CDS reactor independent of the reagent. The CDS reactor promotes absorption of SO 2 

### into the water and the reaction of SO 2 

### with the hydrated lime by intense gassolid mixing. The reaction products include calcium su lfite and calcium sulfate. The reaction products, unreacted lime, and fly ash are then collected downst ream 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 slurri ed with water and spra yed 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, re sulting in intimate liquid-to-gas contact, passes through a mist eliminator to control the re-entrained sl urry drops, and then exits the tower. The intimate

contact results in the SO 2 

### absorption into the liquid and the reacti on with the reagent. The by-products of the sorption and reaction are in a wet form upon l eaving the system and must be dewatered using thickeners, centrifuges, or vacuum filters prior to tr ansport/disposal. The final slurry may contain 10 to 40% water by weight. A wet scrubber system c onsumes between 25 to 33% more water than a comparable SDA scrubber. The SO 2 

### removal efficiencies of new al kali wet scrubbing systems are generally greater than 95%.

Wet FGD systems can utilize a variety of alkaline mediums to remove SO 2 

### 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 byproduc t that may either be disposed of or sold. Most installed wet FGD syst ems use lime or limestone scrubbing reagents. Since limestone is much less expensive, it is used more of ten. 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 dispos ed 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 contac ting the flue gas and slu rry, 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 cont rol include design features within the absorber tower that minimize operating costs. The Jet Bubb ling Reactor, developed by Chiyoda, and Alstom’s Flowpac systems are examples of designs that we re developed to improve liquid-to-gas contact by forcing the flue gas to bubble thr ough the slurry. This is done by util izing a gas sparger design rather than spraying the flue gas with slurry. Another we t FGD liquid-to-gas contact design application is the perforated plate scrubber. Yet anot her developed design includes bidire ctional sprays and wall rings to

be used within the wet FGD absorber tower in order to reduce SO 2 

### sneakage over the conventional FGD.

### All these wet FGD design technologies improve the liq uid-to-gas contact while increasing pressure drop instead of increasing pumping requirements. Mode rn wet FGD designs can achieve 98 to 99% SO 2 

### 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 SO 2 

### from the flue gas. The sp ent sorbent is regenerated to produce concentrat ed streams of SO 2 

### or other sulfur compounds, whic h may be further processed to produce other products. These FGD tec hnologies may require additional fl ue gas treatment prior to the

SO 2 

### absorption process to remove other flue gas c onstituents, such as hydrogen chloride and hydrogen fluoride, that may affect the sorb ent and/or final by-product.

Multi-Pollutant Technologies

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

to reduce SO 2 

### emissions. These include, but are not limited to, the Airborne Process TM 

### , the APTECH CST process, the CEFCO process, Eco Power’s COMPLY 2000, the copper-oxide (CuO) process, Powerspan’s Electro Catalytic Oxidation (ECO®) pr ocess, the electron beam (E-Beam) process, the Indigo Multi Air Pollutant System (MAPSystem TM) process, the Nalco Mobotec technology, The NOXSO process, the Pahlman process tec hnology developed by Enviroscrub, ReACT TM 

### , Skyonic’s SkyMine®, TOPSØE SNOX TM 

### , and the SOx-NOx-Rox Box (SNRBTM) process. These technologies offer the potential for improved enviro nmental performance at lower cost s than traditional technologies. This list is intended to merely illustrate that th e 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.

SO 2 

### Control Performance

30-day SO 2 

### emission rates were calculated by dividing th e 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 SO 2 

### emissions was calculated by comparing the reported SO 2 

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

uncontrolled SO 2 

### emissions were calculated using monthly deliv ered fuel receipts and fuel quality data from the Energy Information Administration (EIA) fo rms EIA-923 (utility and nonutility coal data post 2007), EIA-423 (nonutility coal data prior to 2008), a nd FERC-423 (utility coal data prior to 2008), as applicable. For each operating day, the total potential uncontrolled SO 2 

### emissions were calculated by multiplying the uncontrolled SO 2 

### 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 facil ities in terms of percent reduction in potential SO 2 

### emissions.

### Figure 1: SO 2 

### Emissions Performance Data

Facility Time Period Maximum 30-Day

SO 2 Emissions Rate (lb/MWh) Minimum 30- Day % SO 2 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 Ha rrison facilities, all of the listed facilities use wet limestone based scrubbers. HL Spurlock 3 and 4 are fl uidized bed boilers that remove the majority of

SO 2 

### using limestone injection into the boiler and then remove additional SO 2 

### 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 facili ties, we only have multiple years of performance data for the Harrison, Trimble County, and Mountaineer facilities. Based on th e performance of these facilities, we have concluded that 97% reducti on in potential SO 2 

### 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% re duction in potential SO 2 

### emissions we are not proposing this standard becaus e it is based on relatively short term data. Based on the variability in SO 2 

### reductions from the Harrison, Trimbl e County, and Mountaineer facilities, we

have concluded that short term data does not nece ssarily take into accoun t the range of operating conditions that a facility would be expected to operat e or control equipment vari ability 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 numer ical 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 faci lities in Figure 1. Figure 2 shows the maximum 30-day average SO 2 

### emissions rate of facilities th at commenced operation between 2005 and 2008, that are emitting at levels below the current NSPS, that are reducing potential SO 2 

### emissions by less than 97%, and that reported both SO 2 

### emissions and gross electric output data to CAMD

.

### Figure 2: SO 2 

### EMISSIONS PERFORMANCE DATA FOR NEW FACILITIES

Facility Time Period In Service

Date Maximum 30-Day SO 2 Emissions Rate (lb/MWh) Minimum 30-Day %

SO 2 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 facil ities burn lower sulfur subbituminous coals and use lime-based spray dyers. To provide the maximum emi ssions reduction, we concl uded that the alternate

numerical standard should be as stringent as the numerical rates ach ieved by the facilities used to determine the percent reducti on standard. If the alternat e 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 re quired to achieve the maximum percent re duction that has been demonstrated. In addition, the numerical standard shoul d account for variability in today’s SO 2 

### control technologies and provide sufficient compliance margin for owners/ operators of new faciliti es burning medium sulfur coals to comply with the numerical standard and thereby provide an in centive to burn cleaner fuels. We are proposing 1.0 lb/MWh as the alternate numerical st andard because it provides a comparable level of performance to the 97% reduction requirement and satis fies the criteria mentioned above. The numerical standard would require at leas t 80% reduction even from the lo west sulfur coals and would accommodate the use of spray dryer scrubbers for ow ner/operators of new fac ilities burning coal with

uncontrolled SO 2 

### 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 su fficient flexibility such that an owne r/operator of an E GU could burn over 90% of the subbituminous coals presently being us ed in combination with a spray dryer. This technology choice provides owners/operators the flexib ility to minimize water use and associated waste water discharge, as well as reducing additional CO 2 

### that is chemically created as part of the SO 2 

### control device. Even though there is not necessarily an ov erall GHG reduction from using a lime based instead of a limestone based scrubber, lime production facilities have rela tively concentrated CO 2 

### streams. Capture and storage of CO 2 

### at the lime manufacturing facility could potentially be easier since separation of the CO 2 

### would not be necessary, as is the case w ith an EGU exhaust gas. Owners/operators

of new and reconstructed facilities bu rning coals with higher uncontrolled SO 2 

### emissions could either use IGCC with a downstream process to control sulfur prior to combustion, fluidized bed combustion, or

a wet SO 2 

### scrubbing system to comply with the standa rd. The proposed limit would allow the higher sulfur coals (uncontrolled emissions of greater than approximately 3 lb SO 2 

### /MMBtu) to demonstrate compliance with the 97% reduction requirement as an alternative to the numerical limit.Post Proposal SO2Control PerformancePost proposal EPA evaluated 2010 emissions data and recalculated the emissions averages using 30 operating day averages insteadof 720hour averages used as a proxy for a 30-day average in the proposal. Thiscalculation approach is consistent with how compliancewould bedetermined. The revised approach results inslight changes from values listed inproposal, but nothing significant enough to alter theconclusions. Figure 3 shows the performanceof facilities identified by EPA with minimum % reductions of 97% or greater.Figure 3: SO2Emissions Performance Data for Facilities Demonstrating 97% Reductionin Potential EmissionsFacility FuelTypeControlTechnologyNominal UncontrolledSO2Emissions Rate(lb/MMBtu)Maximum 30-DaySO2EmissionsRate (lb/MWh)99% Confidence 30-Day SO2EmissionsRate (lb/MWh)Minimum 30-Day % SO2Reduction99%Confidence %SO2ReductionCoffeen 1 (1/10 – 12/10) SUB Cyc + Wet FGD 1.1 0.15 0.15 98.7 98.8Coffeen 2 (1/10 - 12/10) SUB Cyc + Wet FGD 1.1 0.14 0.12 99.1 99.1Dallman 4 (11/09 – 12/10) BIT PC + Wet FGD 6.1 1.96 2.15 96.7 96.2Cayuga 1 (12/08 – 12/10) BITPC + Wet FGD3.4 1.03 0.91 97.4 97.7Cayuga 2 (6/09 – 12/10) BITPC + Wet FGD3.4 1.15 1.04 97.4 97.6John E Amos 2 (4/10 – 12/10) BITPC + Wet FGD3.8 0.86 0.81 97.4 97.4John E Amos 3 (1/10 – 12/10) BITPC + Wet FGD3.8 0.82 1.01 97.6 97.5H L Spurlock 2 (1/08 – 12/10) BITPC + Wet FGD3.9 1.38 1.65 97.5 97.2H L Spurlock 3 (1/09 – 12/10) BITCFB + Dry Lime3.9 1.54 1.50 96.5 96.7H L Spurlock 4 (3/09 – 12/10) BITCFB + Dry Lime3.9 1.07 1.06 97.6 97.8Iatan 1 (4/09 – 12/10) SUB PC + Wet FGD0.8 0.16 0.12 98.2 98.6Iatan 2 (10/10 - 12/10) SUBPC + Wet FGD0.8 0.07 0.08 99.0 98.7Jeffrey Energy Center 2(5/09 – 12/10)SUBPC + Wet FGD0.9 0.20 0.22 97.7 97.5Trimble County 1 (11/05 – 12/10) BIT PC + Wet FGD5.4 1.35 1.23 96.8 97.4Oak Grove 2 (5/10 - 12/10) LIG PC + Wet FGD2.9 0.81 0.81 97.3 97.3J K Spruce 2 (4/10 - 12/10) SUB PC + Wet FGD0.8 0.18 0.18 97.7 97.7Sandow 5B (10/09 – 12/10) LIG CFB + Dry Lime4.1 1.27 1.18 96.6 96.6Elm Road 1 (12/09 - 12/10) BITPC + Wet FGD2.6 0.15 0.15 99.5 99.4Elm Road 2 (8/10 - 12/10) BITPC + Wet FGD2.6 0.10 0.13 99.6 99.5The 99% confidence standard was calculatedby adding (subtracting for %reduction) 2.57 standard deviation to the mean emissions rate.While multiple facilities are achieving greater than 98% reduction, this performance data is relatively short term and not appropriate forestablishing a continuous standardthat is achievable for the life of a new EGU.To account for long term achievability and theuncertainty inthe sulfur content of the fuel being burned, EPA further limited the subset of EGUs demonstrating the best system of emissionsreduction(BSER). Figure 4 shows EGUs with over 22 months of data. In addition, instead of using the monthly delivered fuel values from EIA for theapplicable month, we substituted the lowest value for the presentmonth and the preceding 2 months to account uncertainty in fuel use. This isa conservative approach and accounts for therelated uncertainty in the sulfur content of the coalactually burned during a particular month.Figure 4: SO2Emissions Performance Data – Substituted Monthly Coal ValuesFacility FuelTypeControlTechnologyNominal UncontrolledSO2Emissions Rate(lb/MMBtu)Minimum 30-Day % SO2Reduction99%Confidence %SO2ReductionCayuga 1 (12/08 – 12/10) BITPC + Wet FGD3.2 96.5 97.3H L Spurlock 2 (1/08 – 12/10) BITPC + Wet FGD3.5 97.5 97.1H L Spurlock 3 (1/09 – 12/10) BITCFB + Dry Lime3.5 96.4 96.5H L Spurlock 4 (3/09 – 12/10) BITCFB + Dry Lime3.5 97.3 97.6Trimble County 1 (11/05 – 12/10) BIT PC + Wet FGD5.2 96.7 97.3Figure 4 shows that 97% reduction has been demonstrated as achievable for both fluidized beds and pulverized coal. To evaluatethe impact of theamended SO2 standard we evaluated the performance of facilities that commenced operation since 2007. Figure 5 shows the performance of thesefacilities.Figure 5: SO2Emissions Performance Data for Facilities that Commenced Operation Since 2007Facility FuelTypeControlTechnologyNominal UncontrolledSO2Emissions Rate(lb/MMBtu)Maximum 30-DaySO2EmissionsRate (lb/MWh)99% Confidence 30-Day SO2EmissionsRate (lb/MWh)Minimum 30-Day % SO2Reduction99%Confidence %SO2ReductionWeston 4 (1/08 – 12/10) SUB PC + Spray Dryer 0.7 0.61 0.62 90.1 90.0TS Power Plant 1 (6/08 – 12/10) SUBPC + Spray Dryer 0.7 0.56 0.51 91.8 92.0Wygen II (1/08 – 12/10) SUBPC + Spray Dryer 1.0 0.95 0.86 92.0 92.3Wygen III (2010) SUBPC + Spray Dryer 1.0 0.60 0.65 93.3 93.4Walter Scott Jr. Energy Center 4(6/07 – 12/10)SUBPC + Spray Dryer 0.7 0.87 0.80 87.2 87.1Springerville TS3 (7/07 – 12/10) SUB PC + Spray Dryer 1.7 0.90 0.93 92.3 91.7Springerville 4 (12/09 – 12/10) SUB PC + Spray Dryer 1.7 0.91 0.95 92.8 92.5Comanche 3 (6/10 – 12/10) SUBPC + Spray Dryer 0.6 0.87 0.88 82.1 81.8Plum Point (7/10 – 12/10) SUBPC + Spray Dryer 0.7 1.26 1.36 78.8 77.6Nebraska City 2 (5/09 – 12/09) SUB PC + Spray Dryer 0.7 0.91 0.91 81.5 82.1Cross 3 (1/07 – 12/10) BIT PC + Wet FGD 2.8 1.06 1.15 95.9 95.7Cross 4 (5/08 – 12/10) BIT PC + Wet FGD 2.8 1.02 1.15 96.5 95.9Elm Road 1 (12/09 - 12/10) BIT PC + Wet FGD 2.6 0.15 0.15 99.5 99.4Elm Road 2 (8/10 - 12/10) BIT PC + Wet FGD 2.6 0.10 0.13 99.6 99.5Oak Grove 1 (12/09 – 12/10) LIG PC + Wet FGD 2.9 1.01 0.93 96.5 96.8Oak Grove 2 (5/10 - 12/10) LIG PC + Wet FGD 2.9 0.81 0.81 97.3 97.3J K Spruce 2 (4/10 - 12/10) SUB PC + Wet FGD 0.8 0.18 0.18 97.7 97.7Sandow 5A (12/09 – 12/10) LIG CFB + Dry Lime 4.1 1.41 1.52 96.3 95.9Sandow 5B (10/09 – 12/10) LIG CFB + Dry Lime 4.1 1.27 1.18 96.6 96.6H L Spurlock 4 (3/09 – 12/10) BITCFB + Dry Lime3.9 1.07 1.06 97.6 97.8Iatan 1 (4/09 – 12/10) SUB PC + Wet FGD 0.8 0.16 0.12 98.2 98.6Iatan 2 (10/10 – 12/10) SUB PC + Wet FGD 0.8 0.07 0.08 99.9 98.7Dallman 4 (11/09 – 12/10) BIT PC + Wet FGD 6.1 1.96 2.15 96.7 96.2With the exception of Plum Point, Cross3 and 4, and Sandow 5A, all of the EGUs that have recently commenced construction are operating atemissions rates that what would be required by the amended standards. This is not unexpected since EGUs are subject to New Source Review(NSR) and other programs that require stringent controls. The Plum pointfacility has only been operating less than 6 months and the NSPSprovides 180 days to demonstrateinitial compliance to account for commissioningso it is not unexpectedthat emissions are high. The Cross3 and 4 facilities use subcriticalsteam conditions (2,400 psi and 1,050oF). A new facility using the same control configuration usingsupercritical steam conditions the same as Weston 4 (3,775 psi and 1,085oF) would increase the heat rate sufficiently to comply with thenumerical standard. Another option for eitherof the Cross facilities orthe Sandow 5A facility would be to operate the controls similar to thebest performers.To evaluate the impact of including periods of startup and shutdown, EPA compared the emission rates of the John E. Amos facilities with and withoutperiods of startup and shutdown.Any hour with less than 24 hours of operation was considered a startup or shutdown day and deleted when determiningthe alternate emissions rate. The differences in the calculated 30-day emission ratesbetween the data submitted to the docketand the EPA is attributed tothe procedure used to calculate the 30-day averages. The EPA 30-day averages are calculated using the procedures described in the proposal (sum ofemissions of the applicable pollutant divided by the sum of the gross output) and the commenterused the average of the hourlyemission rates for the 30-day period. As stated in the proposal, the EPA procedure resultin lower numerical emission rates because hours with high emission rates but low heatinputs (typically of startup, shutdown, and low load operation) are not weighted as heavily.Figure 6: Impact of Including Periods of Startup and Shutdown on SO2Emissions Performance DataFacility 99% Confidence 30-Day SO2EmissionsRate (lb/MWh)99% Confidence 30-Day SO2Emissions Rate Without Startupor Shutdown (lb/MWh)99%Confidence %SO2Reduction99% Confidence % SO2Reduction WithoutStartup or ShutdownJohn E Amos 2 (4/10 – 12/10) 0.81 0.73 97.4 97.6John E Amos 3 (1/10 – 12/10) 1.01 0.94 97.5 97.6As shown in Figure 6, if EPA were to excludeperiods of startup and shutdown from the emissions standard the numerical standardandpercent reduction standard would have to be reevaluated.Figure 7 graphically illustrates the amended standard compared to two alternatives suggested by commenters. The more stringentstandardwould essentially drive the market to the lowest sulfur coals.The less stringent standard does notrepresent the best system of emissionsreduction.86%88%90%92%94%96%98%100%0123456

Percent ReductionNominalUncontrolledSO2EmisisonsRate(lb/MMBtu)Figure7.AmendedStandardComparedtoPerformaceofRecentEGUsAlternateStandard:0.70lb/MWhor98%AmendedStandard:1.0lb/MWhor97%AlternateStandard:1.15lb/MWhor96%NewEGUMinimum%Reduction