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 NO X Emissions

Introduction

Nitrogen oxide (NO X ) is formed in a steam generating unit by the oxidation of molecular nitrogen (N 2 ) in the combustion air (thermal NO X ) and any nitrogen compounds c ontained in the fuel (fuel NO X ). The

formation of NO X from nitrogen in the combustion air is dependent on two conditions occurring simultaneously in the unit's combustion zone: high te mperature and an excess of combustion air. Under these conditions, significant quantities of NO X are formed regardless of the fuel type burned. New steam generating units being instal led today in the United States ro utinely include burners and other features designed to reduce the amounts of NO X formed during combustion.

Beyond the lower levels of NO X emissions achieved using com bustion controls, additional NO X emission control can be achieved for steam genera ting units by installing post-combustion control technologies. These technologi es involve converting the NO X in the flue gas to molecular nitrogen (N 2 ) and water. The existing EGU NO X NSPS is 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling average basis. The proposed subpart Da NO X standard is 88 ng/J (0.70 lb/MWh) on a 30-day rolling average basis.

NO X Control Technologies

The following is a brief summary of some of the NO X control technologies, including propriety technologies. This summary is not intended to be a comprehensive list of av ailable technologies. The performance values given here are those that have been provided by the technology provider in publically available sources. Incl usion of a technology in this summa ry is not intended to be an endorsement of that technology by the US EPA the US Government

Combustion Controls

Low NO X Burners (LNB). Low NO X Burners are designed to limit NO X formation by controlling the stoichiometric and temperature profiles of the co mbustion process. Contro l is achieved by design features that regulate the aerodynamic distribution and mixing of the fuel and air, resulting in one or more of the following conditions: (a) reduced oxygen in the primar y flame zone; (b) reduced flame temperature; or (c) reduced residence time at peak temperature. The most recent applications of LNB

are called ultra low NO X burners due to their improvements over previous LNB technology. These improvements include advances in control systems, combustion process modifications, and postcombustion carbon burnout technology that have further limited NO X formation. LNB are a mature technology for the reduction of NO X formation during combustion. Due to their cost effectiveness, LNB are expected to be furnished with a new boiler regardless of other post-combustion NO X emission reduction technologies employed.

Overfire Air (OFA). Overfire air, also referred to as air st aging, is a combustion control technology in

which 5% to 20% of the total combustion air is di verted from the burners and injected through ports located above the top burner level. OFA is a mature technology most often util ized concurrently withthe application of LNB. OFA compliments the stoich iometric to sub-stoichiometric operation of LNB by providing the air required to complete fuel co mbustion and limit the formation of CO and VOC. OFA is expected to be furnished with a ne w boiler regardless of other post combustion NO X emission reduction technologies employed.

Rotating Opposed Fire Air (ROFA ® ). Rotating opposed fire air diffe rs from OFA in that ROFA®

utilizes a booster fan to increase th e velocity of air to promote better mixing and to decreases excess air requirements. A modification of the ROFA ® process is Rotamix ® in which urea or ammonia is injected

with ROFA. The Rotamix ® technology reduces NO X emissions by an additional 45% to 60% with lower reagent use than SNCR.

Rich Reagent Injection (RRI) . Rich reagent injection is the process of adding a NO X reducing reagent in lower part of the furnace. The RRI process reduces NO X by 25% to 40% and results in little to no ammonia slip in comparison with other NO X reducing processes. Howeve r, since the injection takes place at between 1,300 o C to 1,700 o C (2,400 o F to 3,100 o F), it requires twice the amount of reagent compared to SNCR.

Induced Flue Gas Recirculation or Flue Gas Recirculation (IFGR). Induced flue gas recirculation recirculates boiler flue gas from the boiler outlet to the furnace wh ere it is reintr oduced into the combustion process. Fuel/air mixing in the combusti on region is intensified by the recirculated flue gas

when introduced into the flame dur ing the early stages of combustion. This intensified mixing offsets the decrease in flame temperature and results in NO X levels that are lower than those achieved without

IFGR. The level of NO X reduction is dependent upon th e burner and furnace design.

Oxygen-Enhanced Combustion (OEC). Oxygen-enhanced combustion is a method developed by Praxair Technology, Inc. that uses oxygen in the LNB instead of air to reduce the formation of thermal

NO X in the boiler. During testing, OEC was reported to reduce boiler NO X emissions by as much as 60% when compared to utilizing am bient air at the test facility.

Natural Gas Reburning (NGR). Natural gas reburning is a combus tion technology in which part of the main fuel heat input is diverted to locations above the burners, t hus creating a secondary combustion zone called the reburn zone. In NGR, the secondary (or reburn) fuel, natu ral gas, is injected to produce a slightly fuel rich reburn zone. Overfire air is added above the reburn zone to complete burnout of the reburn zone. As flue gas passes thro ugh the reburn zone, part of the NO X formed in the main combustion zone is reduced by hydrocarbon fragment s (free radicals) and c onverted to molecular nitrogen (N 2 ). NGR has been demonstrated to reduce NO X emissions by 39% to 67% on several existing coal-fired boilers in applic ations ranging in size from 33-600 MW in the United States and up to

800 MW overseas.

Fuel Lean Gas Reburning (FLGR TM ). Fuel lean gas reburning, also know n as controlled gas injection, is a process in which natural gas in injected above the main combustion zone at a lower temperature zone

than in NGR. FLGR TM is different from NGR because the inj ection of gas is done in a matter that optimizes the furnace's stoichiometry on a localized ba sis. By doing this, the process avoids creating a

fuel-rich zone and maintains overall fuel-lean cond itions. While NGR requires 15% to 20% of furnace heat input from natural gas and OFA, the FLGR TM technology achieves NO X control using less than 10% natural gas heat input without the requirement for OFA. FLGR TM has been demonstrated to reduce

NO X emissions by 33% to 45%.

Advanced Gas Reburning (AGR). Advanced gas reburning adds a nitrogen rich compound (typically urea or ammonia) downstream of th e reburning zone. The reburning sy stem is adjusted for somewhat

lower NO X reduction to produce free radicals that enhance the selec tive non-catalytic NO X reduction process. AGR systems can be designed in two wa ys: (1) non-synergistic, which is essentially the sequential application of NGR and se lective non-catalytic re duction (i.e., the nitrogen agent is injecteddownstream of the burnout air); and (2 ) synergistic, in which the nitrogen agent is injected with a second

burnout air stream. Demonstrated NO X emission reductions ranged from 50% to 76%.

Amine Enhanced Fuel Lean Gas Reburn (AEFLGRTM) . Amine enhanced gas injection is similar to AGR, except that burn out air is no t used, and the selective non-catal ytic reduction reagent and reburn fuel are injected to create local, fuel-rich NO X reduction zones in an overall fuel-lean furnace. The fuelrich zone exists in local eddies, as in FLGR TM , with the overall furnace in an oxidizing condition; however the reduction reagent participates with natural gas (or other hydrocarbon fuel) in a NO X reduction reaction. AEGI has b een demonstrated to reduce NO X emissions by 30% to 73% during fullscale commercial applications.

ECOTUBE . The Ecotube system utilizes retractable hi gh velocity air injecti on lance tubes positioned

inside the boiler above th e primary boiler zone in order to im prove furnace gas mixing which reduces local high furnace temperatures and increases the residence time for combus tion. The improved mixing

also lowers excess O 2 requirements. Additional NO X reduction can be achieved by injecting ammonia or urea along with th e high velocity air.

Post-Combustion Controls

Selective Non-Catalytic Reduction (SNCR). In selective non- catalytic reduction systems, a reagent is injected into the flue gas in th e furnace within an appropriate te mperature window. Emissions of NO X can be reduced by 30% to 50%. Because of lower r eagent utilizations rates, both ammonia and urea SNCR processes require three or four times as mu ch reagent as SCR systems to achieve similar NO X reductions. The temperature window for effici ent SNCR operation typically occurs between 900 o C to 1,100 o C (1,650°F and 2,000°F) depending on the reagent and condition of SNCR operation. When the reaction temperature increases over 1,000 o C (1,800°F), the NO X removal rate decreases due to thermal decomposition of ammonia. On the other hand, the NO X reduction rate decreases below 1,000 o C (1,800°F), and ammonia slip may increase.

Selective Catalytic Reduction (SCR). Selective catalytic reducti on systems use ammonia or urea injection in combination with a catalyst to reduce NO X emissions. Ammonia or urea is injected into the flue gas and mixed prior to enteri ng the catalyst. The use of base metal oxides, such as vanadium pentoxide, titanium dioxide, or noble metals, for both the active and support materials for the composition of the catalyst has been traditionally used. However, newer more sulfur-resistant ceramic catalysts have recently been used. A temperatur e range of 300°C to 400°C (570°F of to 750°F) is typical for the reduction process. If the catalyst bed is not located in the proper temperature zone, the reaction efficiency will be reduced if either the temperature is too low, resulting in excessive ammonia slip, or the catalyst may be damaged if the temperat ure is too high. SCR systems have been designed to

achieve NO X reductions of 80% and above, while ma intaining low ammonia slip. Low SO 2 to SO 3 conversion and erosion resistance ha ve also been achieved through modi fications to chemistry and the manufacturing process.

Ammonia-Free SCR (AF-SCR) . In the AF-SCR process, the furnace is operated with a high CO

concentration to achieve reduced exit NO X levels. A downstream base-met al catalyst then uses the CO as a reductant for the remaining NO X as well oxidizing the CO to CO 2 . An injection mode that injects activated carbon into the system is an option for this technology. W ith this injection, the activated carbon reduces mercury emissions, but also acts as a catalyst to convert NO X to N 2 and CO to CO 2

. There are potential cost savings relative to the SCR system becau se ammonia-related equipment and operations are not needed, and the ra w materials for the catalysts are ex pected to be less expensive.

LoTOx TM . The LoTOx TM technology involves low temperat ure, gas-phase oxidation of NO X by ozone injection to convert the insoluble NO X to soluble oxidized compounds , which are removed in adownstream wet flue gas desulfurization (FGD) pr ocess. This system has high auxiliary power consumption, although the capital costs ar e less, relative to a SCR system.

Catalytic Absorption/Oxidation (SCONOxTM). The SCONOxTM system uses a single catalyst to simultaneously oxidize carbon monoxide to carbon dioxide, hydrocarbons to car bon dioxide and water, nitrogen oxides to nitrogen dioxide, and then abso rbing nitrogen dioxide onto its surface through the use of a potassium carbonate absorber coating. The potassium carbonate co ating reacts to form potassium nitrites and nitrates, which are then present on the surface of the catalys t. When all of the carbonate absorber coating on the surface of the catalys t has reacted to form nitrogen compounds, NO X will no longer be absorbed, and the catalyst must enter the regeneration cycle. The regeneration of the catalyst is accomplished by passing a dilute hydrogen reducing gas across the surface of the catalyst in the absence of oxygen. The hydrogen in this gas reacts with nitrites and nitrat es to form water and elemental nitrogen. Carbon dioxide in the regeneration gas reacts with potassium ni trites and nitrates to form potassium carbonate, allowing the oxidation/absorption cycle to begi n again. This cycle is referred to as the "regeneration cycle." Because the rege neration cycle must take place in an oxygen free environment, a section of catalyst undergoing regeneration must be isolated from exhaust gases. This is accomplished using a set of louvers, one upstream of th e section being regenerated and one downstream. SCONOxTM technology has not been demonstrated on flue gas generated by coal combustion.

Hybrid Selective Reduction (HSR). The Hybrid Selective Reducti on is a combination of SNCR and SCR that is designed to provide th e performance of full SCR. In HSR, the SNCR system is used to

achieve some NO X reduction and to produce a controlled amount of ammonia slip that is used in a

downstream in-duct SCR reactor for additional NO X reduction. The NOxOUT CASCADE® process by Fuel Tech is an example of an integrated SNCR/SCR system. NO X reduction can reach up to 85%, and efficiency of the chemical reagent usage is mu ch improved over conventio nal SNCR processes.

THERMALONOx. The THERMALONOx technology has been developed by Thermal Engineering International. The technology is based on the oxidation of NO to NO 2 and then dissolving the NO 2 in water. The THERMALONOx technology is intended for use with a wet flue gas desulfurization (FGD) system used for SO 2 emission control. The NO oxidation is accomplished by injection elemental phosphorous into the flue gas stream in a gas reactor installed upstream of the wet FGD absorber. The

NO 2 becomes dissolved in the wet FGD absorb er and can be removed as elemental N 2 or various phosphate compounds that may be used as fert ilizer and/or animal food additives.

NOxStarTM . Doosan Babcock's proprietary NOxStarTM technology is a NO X reduction process that employs the injection of reagents (ammonia and hydrocarbon gas) throu gh a grid located in an existing cavity in the boiler's convective pass. This results in an autocatalytic plasma reaction that reduces NO X to nitrogen and water vapor. NOxStarTM eliminates th e need to install a solid catalyst layer and the associated potential problems of chemical pois oning, physical plugging, sinter ing due to temperature excursions, pressure drop requiring larger ID fans, and disposal of a hazardous solid waste. In the

NOxStar TM system, the conversion of SO 2 to SO 3 is said to be negligible . A single layer of in-duct catalyst (NOxStar TM Plus) is an option with this system. NOxStar TM is reported to reduce NO X by 80%

or more.

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’sSkyMine®, TOPSØE SNOX TM , and the SOx-NOx-Rox Box (SNRBTM) process. These technologies offer the potential for improved enviro nmental performance at lower costs 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.

NO X 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.

Figure 1 shows the maximum 30-day average NO X emissions rate of facili ties for the best performing facilities that reported both NO X emissions and gross electr ic output data to CAMD.

Figure 1: NO X Emissions Performance Data

Facility Time Period Maximum 30-Day

NO X Emissions Rate (lb/MWh) Boiler Type & Primary Coal

Rank
Havana 9 01/05 – 12/09 0.70 PC, Sub
Walter Scott Jr. 4 04/07 – 12/09 0.58 PC, Sub Mirant Morgantown 1 06/07 – 12/09 0.65 PC, Bit Mirant Morgantown 2 06/08 – 12/09 0.70 PC, Bit
Roxboro 2 01/09 – 12/09 0.67 PC, Bit
Cardinal 1 01/09 – 12/09 0.38 PC, Bit
Cardinal 2 01/09 – 12/09 0.46 PC, Bit
Cardinal 3 01/09 – 12/09 0.45 PC, Bit Muskingum River 5 01/08 – 12/09 0.60 PC, Bit
John E Amos 06/09 – 12/09 0.62 PC, Bit
Mitchell 1 01/09 – 12/09 0.59 PC, Bit
Mitchell 2 01/09 – 12/09 0.54 PC, Bit
Weston 4 07/08 – 12/09 0.48 PC, Sub H L Spurlock 4 05/09 – 12/09 0.67 CFB, Bit Wansley 1 02/09 – 12/09 0.67 PC, Bit Wansley 2 01/09 – 12/09 0.59 PC, Bit Nebraska City 2 05/09 – 12/09 0.60 PC, Sub
TS Power 1 07/08 – 12/09 0.49 PC, Sub Note: PC = pulverized coal CFB = circulating fluidized bed

Sub = subbituminous coal

Bit = bituminous coal

All of the facilities list ed in Figure 1 have demonstrated that 0.70 lb/MWh is achievable. Even though some facilities are achieving a lower emissions rate, the majority of facilities li sted in Figure 1 have less than a year of operating data. Proposing a more stringent standa rd might not provide sufficient compliance margin to account for expected vari ability in the long te rm performance of NO X controls. Although not all affected f acilities using SCR are presently achiev ing an emissions rate of 0.70 lb/MWh, all major boiler designs have demonstrated comb ustion controls that are able to reduce NO X emissionsto levels where the addition of SCR (or design modi fications and operating cha nges to existing SCR) or an alternate control strategy would allow compliance with a NO X emissions rate of 0.70 lb/MWh. We are therefore selecting 88 ng/J (0.70 lb/MWh) as the proposed NO X standard for new, modified, and

reconstructed facilities.Post Proposal NOXControl 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 2 shows the performanceof facilities identified by EPA with NOXemissions of 0.70 lb/MWh or less. Figure 3 shows theemission rates of EGUs that have commencedoperation since 2007, but that are not presently operating at 0.70lb/MWh or below.Figure 2: NOXEmissions Performance Data for Facilities Demonstrating an Emissions Rate of 0.70 lb/MWhFacility FuelTypeBoiler Type & ControlTechnologyMaximum 30-Day NOXEmissions Rate(lb/MWh)99% Confidence 30-Day NOXEmissionsRate (lb/MWh)Havana 8 ((1/05 – 12/10) SUB PC + SCR0.70 0.66Comanche 3 (6/10 – 12/10) SUB PC + SCR 0.59 0.59Dallman 4 (12/09 – 12/10) BIT PC + SCR0.67 0.67Walter Scott Junior 4 (4/07 – 12/10) SUB PC + SCR0.58 0.66Mirant Morgantown 1 (2/10 – 12/10) BITPC + SCR0.54 0.57Mirant Morgantown 2 (2/10 – 12/10) BITPC + SCR0.43 0.43Cardinal 1 (1/09 – 12/10) BIT PC + SCR 0.38 0.43Cardinal 2 (1/09 – 12/10) BIT PC + SCR 0.51 0.58Cardinal 3 (1/09 – 12/10) BIT PC + SCR 0.58 0.51Muskingum River 5 (1/08 – 12/10) BITPC + SCR0.70 0.63John E Amos 1 (1/10 – 12/10) BITPC + SCR0.37 0.42Mitchell 1 (1/09 – 12/10) BITPC + SCR0.59 0.63Weston 4 (7/08 – 12/10) SUB PC + SCR0.48 0.52H L Spurlock 4 (5/09 – 12/10) BIT CFB + SNCR 0.67 0.69Iatan 2 (10/10 – 12/10) SUBPC + SCR0.48 0.50Nebraska City 2 (4/09 – 12/10) SUBPC + SCR0.62 0.64Belews Creek 2 (4/07 – 12/10) BIT PC + SCR0.65 0.74Springerville 4 (4/10 – 12/10) SUB PC + SCR0.62 0.68AES Deepwater 1001 (6/07 – 12/10) PC PC + SCR 0.66 0.51Elm Road 1 (1/10 – 12/10) BITPC + SCR0.57 0.60Elm Road 2 (8/10 – 12/10) BITPC + SCR0.50 0.55TS Power 1 (7/08 – 12/10) SUBPC + SCR0.49 0.51Plum Point 1 (7/10 – 12/10) SUBPC + SCR0.62 0.66Wygen III (5/10 – 12/10) SUBPC + SCR0.43 0.45Northeastern (1/07 – 12/10) REF CFB + SNCR 0.85 0.80Figure 3: NOXEmissions Performance Data for AdditionalFacilities that Commenced Operation Since 2007Facility FuelTypeBoiler Type & ControlTechnology99% Confidence 30-DayNOXEmissions Rate(lb/MWh)99% Confidence 30-Day NOXEmissionsRate without Startup orShutdown (lb/MWh)Wygen II (1/08 – 12/10) SUB PC + SCR0.77 0.79Cross 3 (5/07 – 12/10) BIT PC + SCR0.79 0.75Cross 4 (6/08 – 12/10) BIT PC + SCR0.78 0.77Iatan 1 (4/09 – 12/10) SUB PC + SCR0.94 0.98Springerville TS3 (4/07 – 12/10) SUB PC + SCR0.73 0.76Sandow 5A (1/10 – 12/10) LIG CFB + SNCR0.90 0.93Sandow 5B (1/10 – 12/10) LIG CFB + SNCR0.76 0.82Oak Grove 1 (12/09 – 12/10) LIG PC + SCR0.72 0.72Oak Grove 2 (5/10 – 12/10) LIG PC + SCR0.78 0.78To evaluate the impact of including periodsof startup and shutdown in the emissionsaverage, EPA evaluated the emissions ratefor the AllenS. King facility with and without periods of startup and shutdown. The differences in the calculated 30-day emission rates between the datasubmitted to the docket and the EPA is attributed to the procedure used to calculate the 30-day averages. The EPA 30-day averages arecalculated using the procedures described inthe proposal (sum of emissions of the applicable pollutant divided by the sum of the grossoutput) and the commenter used the averageof the hourly emission rates for the 30-dayperiod. As stated inthe proposal, the EPA procedureresult in lower numerical emission ratesbecause hours with high emission rates but low heat inputs (typically of startup, shutdown, and lowload operation) are not weighted as heavily.Figure 6: Impacts of Startup and ShutdownFacility 99% Confidence 30-Day NOXEmissionsRate (lb/MWh)99% Confidence 30-Day NOXEmissionsRate without Startup orShutdown (lb/MWh)99% Confidence 30-Day NOXEmissionsRate (lb/MMBtu)99% Confidence 30-DayNOXEmissions Ratewithout Startup orShutdown (lb/MMBtu)Allen S King 1 (1/10 - 3/11) 0.92 0.88 0.125 0.092The different approaches yield significant differences in the impact of startup and shutdown periods. In this case, the EPA approach onlyresults in a difference of 4% and the calculations used by the commenter resulted ina 26% difference. As shown in Figure 6, ifEPA were toexclude periods of startup and shutdown from the emissions standard the numerical standard and percent reduction standard wouldhave to bereevaluated.As suggested in the comments, EPA evaluated the performance of existingfacilities with limited ability to use combustion controls to reduceNOXemissions to determine an appropriate standardfor modified facilities. Figure 5 shows the NOXemission rates for the best performingcyclone EGUs burningvarious coal typesFigure 5: Cyclone EGU NOXEmission RatesFacility FuelTypeBoiler Type & Control Technology 99% Confidence 30-Day NOXEmissions Rate (lb/MWh)Coffeen 1 (1/10 – 12/10) SUB Cyc + SCR 0.88Coffeen 2 (1/10 – 12/10) SUB Cyc + SCR0.68Baldwin 1 (1/05 – 12/10) SUB Cyc + SCR0.76Baldwin 2 (1/05 – 12/10) SUB Cyc + SCR0.81Allen S King 1 (1/10 - 3/11) SUB Cyc + SCR0.92Merrimack1 (1/09 – 12/10) BIT Cyc + Combustion Controls 3.58Merrimack2 (1/09 – 12/10) BIT Cyc + Combustion Controls2.82Leland Olds 1 (1/09 – 12/10) LIG Cyc + Combustion Controls3.52Leland Olds 2 (1/09 – 12/10) LIG Cyc + Combustion Controls3.76As described in the response to comments, cyclone boilers would be able to achieve the standard for modified EGUs. In additionto the boilertypes mentioned in the comments, EPA evaluated the 2010 NOXemission rates for the best performingEGUs for the specific boiler types inFigure 7. With the application of SCR to Kanahwa River 2, all boiler types have demonstrated that the amended standard for modifiedfacilities as achievable. Reconstruction takes such a large capital investment that burner designs could be alternated such that combustioncontrols would be sufficient to facility compliance with the amended new source standard.Figure 7: Annual Emission Rates for Boiler Types not Previously ListedFacility Boiler Type Control Technology 2010 Annual NOXEmissionsRate (lb/MWh)Pleasant Prairie 1 Dry bottomturbo-fired boiler SCR 0.69Pleasant Prairie 2 Dry bottomturbo-fired boiler SCR 0.68Big Bend 1 Wet bottom turbo-fired boiler SCR 0.93Kanawha River 2 Dry bottom vertically-fired boiler Low NOXBurners 2.29Figure 8 lists all of the data EPA collected on CO emissions from EGUs reevaluated using the corrected 30-day calculation procedure..Figure 8: Combined CO/NOXEmission Rates for All FacilitiesFacility FuelTypeBoiler Type & ControlTechnologyMaximum 30-Day NOX+ CO Emissions Rate(lb/MWh)99% Confidence 30-DayNOX+ CO EmissionsRate (lb/MWh)Limestone LIM1 (1/05 – 12/09) LIG PC + LNB 2.31 (0.44) 2.31 (0.45)Limestone LIM2 (1/05 – 12/09) LIG PC + LNB 2.53 (0.61) 2.71 (0.53)Northside 1A (1/05 – 12/09) PC CFB + SNCR 1.05 (0.24) 1.11 (0.29)Northside 1B (1/05 – 12/09) PC CFB + SNCR 1.23 (0.61) 1.17 (0.31)Walter Scott Junior 4 (4/07 – 11/10) SUB PC + SCR0.95 (0.51) 1.09 (0.95)WA Parish WAP 5 (9/05– 12/09) SUB PC + SCR1.05 (0.61) 0.95 (0.46)WA Parish WAP 6 (1/05– 12/09) SUB PC + SCR1.19 (0.81) 1.06 (0.55)WA Parish WAP 7 (6/05– 12/09) SUB PC + SCR1.95 (1.55) 1.85 (1.44)WA Parish WAP 8 (4/06– 12/09) SUB PC + SCR1.49 (1.11) 1.48 (1.09)Duck Creek (4/09 – 12/09) BIT PC + SCR4.47 (2.05) 3.69 (1.60)HL Spurlock 3 (1.09 – 12/10) BIT CFB + SNCR 1.41 (0.65) 1.43 (0.63)HL Spurlock 4 (3/09 – 12/10) BIT CFB + SNCR 1.37 (0.70) 1.34 (0.70)Iatan 1 (12/09 – 11/10) SUB PC + SCR 1.95 (1.09) 2.04 (1.14)Jeffery Energy Center 1 (9/08 – 12/10) SUB PC + SCR8.20 (6.55) 6.43 (4.68)Jeffery Energy Center 3 (1/08 – 12/10) SUB PC + SCR4.04 (2.03) 4.00 (2.05)Oak Grove 1 (12/09 – 9/10) LIG PC + SCR2.24 (1.57) 2.36 (1.72)Oak Grove 2 (5/10 – 9/10) LIG PC + SCR2.31 (1.62) 2.08 (1.45)Sandow 5A 10/09 – 9/10) LIG CFB + SNCR 1.40 (0.39) 1.33 (0.39)Sandow 5B (2/10 – 9/10) LIG CFB + SNCR 1.01 (0.29) 1.07 (0.29)TS Power 1 4/08 – 11/10) SUB PC + SCR 0.80 (0.47) 0.72 (0.35)Figure 8 shows that 1.1 lb/MWh is the best emission rate achievable by both fluidized bed and pulverized coal boilers. In addition, the best CO emissionsrate that has been demonstrated both both fluidized bed and pulverized coal boiler is 0.4 lb/MWh.