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 NOX Emissions 

Introduction 

Nitrogen oxide (NOX) is formed in a steam generating unit by the oxidation of molecular nitrogen (N2) 

in the combustion air (thermal NOX) and any nitrogen compounds contained in the fuel (fuel NOX). The 

formation of NOX from nitrogen in the combustion air is dependent on two conditions occurring 

simultaneously in the unit's combustion zone: high temperature and an excess of combustion air. Under 

these conditions, significant quantities of NOX are formed regardless of the fuel type burned. New 

steam generating units being installed today in the United States routinely include burners and other 

features designed to reduce the amounts of NOX formed during combustion. 

Beyond the lower levels of NOX emissions achieved using combustion controls, additional NOX

emission control can be achieved for steam generating units by installing post-combustion control 

technologies. These technologies involve converting the NOX in the flue gas to molecular nitrogen (N2) 

and water. The existing EGU NOX NSPS is 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day 

rolling average basis. The proposed subpart Da NOX standard is 88 ng/J (0.70 lb/MWh) on a 30-day 

rolling average basis. 

NOX Control Technologies 

The following is a brief summary of some of the NOX 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 

Combustion Controls 

Low NOX Burners (LNB). Low NOX Burners are designed to limit NOX formation by controlling the 

stoichiometric and temperature profiles of the combustion process. Control 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 primary flame zone; (b) reduced flame 

temperature; or (c) reduced residence time at peak temperature. The most recent applications of LNB 

are called ultra low NOX 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 NOX formation. LNB are a mature 

technology for the reduction of NOX formation during combustion. Due to their cost effectiveness, LNB 

are expected to be furnished with a new boiler regardless of other post-combustion NOX emission 

reduction technologies employed. 

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

which 5% to 20% of the total combustion air is diverted from the burners and injected through ports 

located above the top burner level. OFA is a mature technology most often utilized concurrently with 
the application of LNB. OFA compliments the stoichiometric to sub-stoichiometric operation of LNB 

by providing the air required to complete fuel combustion and limit the formation of CO and VOC. 

OFA is expected to be furnished with a new boiler regardless of other post combustion NOX emission 

reduction technologies employed. 

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

utilizes a booster fan to increase the 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 NOX 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 NOX reducing reagent in 

lower part of the furnace. The RRI process reduces NOX by 25% to 40% and results in little to no 

ammonia slip in comparison with other NOX reducing processes. However, since the injection takes 

place at between 1,300oC to 1,700oC (2,400oF to 3,100oF), 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 where it is reintroduced into the 

combustion process. Fuel/air mixing in the combustion region is intensified by the recirculated flue gas 

when introduced into the flame during the early stages of combustion. This intensified mixing offsets 

the decrease in flame temperature and results in NOX levels that are lower than those achieved without 

IFGR. The level of NOX reduction is dependent upon the 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 

NOX in the boiler. During testing, OEC was reported to reduce boiler NOX emissions by as much as 

60% when compared to utilizing ambient air at the test facility. 

Natural Gas Reburning (NGR). Natural gas reburning is a combustion technology in which part of the 

main fuel heat input is diverted to locations above the burners, thus creating a secondary combustion 

zone called the reburn zone. In NGR, the secondary (or reburn) fuel, natural 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 through the reburn zone, part of the NOX formed in the main 

combustion zone is reduced by hydrocarbon fragments (free radicals) and converted to molecular 

nitrogen (N2). NGR has been demonstrated to reduce NOX emissions by 39% to 67% on several 

existing coal-fired boilers in applications ranging in size from 33-600 MW in the United States and up to 

800 MW overseas. 

Fuel Lean Gas Reburning (FLGRTM). Fuel lean gas reburning, also known 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. FLGRTM is different from NGR because the injection of gas is done in a matter that 

optimizes the furnace's stoichiometry on a localized basis. By doing this, the process avoids creating a 

fuel-rich zone and maintains overall fuel-lean conditions. While NGR requires 15% to 20% of furnace 

heat input from natural gas and OFA, the FLGRTM technology achieves NOX control using less than 

10% natural gas heat input without the requirement for OFA. FLGRTM has been demonstrated to reduce 

NOX emissions by 33% to 45%. 

Advanced Gas Reburning (AGR). Advanced gas reburning adds a nitrogen rich compound (typically 

urea or ammonia) downstream of the reburning zone. The reburning system is adjusted for somewhat 

lower NOX reduction to produce free radicals that enhance the selective non-catalytic NOX reduction 

process. AGR systems can be designed in two ways: (1) non-synergistic, which is essentially the 

sequential application of NGR and selective non-catalytic reduction (i.e., the nitrogen agent is injected 
downstream of the burnout air); and (2) synergistic, in which the nitrogen agent is injected with a second 

burnout air stream. Demonstrated NOX 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 not used, and the selective non-catalytic reduction reagent and reburn 

fuel are injected to create local, fuel-rich NOX reduction zones in an overall fuel-lean furnace. The fuelrich zone exists in local eddies, as in FLGRTM, with the overall furnace in an oxidizing condition; 

however the reduction reagent participates with natural gas (or other hydrocarbon fuel) in a NOX

reduction reaction. AEGI has been demonstrated to reduce NOX emissions by 30% to 73% during fullscale commercial applications. 

ECOTUBE. The Ecotube system utilizes retractable high velocity air injection lance tubes positioned 

inside the boiler above the primary boiler zone in order to improve furnace gas mixing which reduces 

local high furnace temperatures and increases the residence time for combustion. The improved mixing 

also lowers excess O2 requirements. Additional NOX reduction can be achieved by injecting ammonia 

or urea along with the 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 the furnace within an appropriate temperature window. Emissions of NOX

can be reduced by 30% to 50%. Because of lower reagent utilizations rates, both ammonia and urea 

SNCR processes require three or four times as much reagent as SCR systems to achieve similar NOX

reductions. The temperature window for efficient SNCR operation typically occurs between 900oC to 

1,100o

C (1,650°F and 2,000°F) depending on the reagent and condition of SNCR operation. When the 

reaction temperature increases over 1,000oC (1,800°F), the NOX removal rate decreases due to thermal 

decomposition of ammonia. On the other hand, the NOX reduction rate decreases below 1,000o

C 

(1,800°F), and ammonia slip may increase. 

Selective Catalytic Reduction (SCR). Selective catalytic reduction systems use ammonia or urea 

injection in combination with a catalyst to reduce NOX emissions. Ammonia or urea is injected into the 

flue gas and mixed prior to entering 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 temperature 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 temperature is too high. SCR systems have been designed to 

achieve NOX reductions of 80% and above, while maintaining low ammonia slip. Low SO2 to SO3

conversion and erosion resistance have also been achieved through modifications 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 NOX levels. A downstream base-metal catalyst then uses the CO 

as a reductant for the remaining NOX as well oxidizing the CO to CO2. An injection mode that injects 

activated carbon into the system is an option for this technology. With this injection, the activated 

carbon reduces mercury emissions, but also acts as a catalyst to convert NOX to N2 and CO to CO2. 

There are potential cost savings relative to the SCR system because ammonia-related equipment and 

operations are not needed, and the raw materials for the catalysts are expected to be less expensive. 

LoTOxTM. The LoTOxTM technology involves low temperature, gas-phase oxidation of NOX by ozone 

injection to convert the insoluble NOX to soluble oxidized compounds, which are removed in a 
downstream wet flue gas desulfurization (FGD) process. This system has high auxiliary power 

consumption, although the capital costs are 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 carbon dioxide and water, 

nitrogen oxides to nitrogen dioxide, and then absorbing nitrogen dioxide onto its surface through the use 

of a potassium carbonate absorber coating. The potassium carbonate coating reacts to form potassium 

nitrites and nitrates, which are then present on the surface of the catalyst. When all of the carbonate 

absorber coating on the surface of the catalyst has reacted to form nitrogen compounds, NOX 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 nitrates to form water and 

elemental nitrogen. Carbon dioxide in the regeneration gas reacts with potassium nitrites and nitrates to 

form potassium carbonate, allowing the oxidation/absorption cycle to begin again. This cycle is referred 

to as the "regeneration cycle." Because the regeneration 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 the 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 Reduction is a combination of SNCR and 

SCR that is designed to provide the performance of full SCR. In HSR, the SNCR system is used to 

achieve some NOX reduction and to produce a controlled amount of ammonia slip that is used in a 

downstream in-duct SCR reactor for additional NOX reduction. The NOxOUT CASCADE® process by 

Fuel Tech is an example of an integrated SNCR/SCR system. NOX reduction can reach up to 85%, and 

efficiency of the chemical reagent usage is much improved over conventional SNCR processes. 

THERMALONOx. The THERMALONOx technology has been developed by Thermal Engineering 

International. The technology is based on the oxidation of NO to NO2 and then dissolving the NO2 in 

water. The THERMALONOx technology is intended for use with a wet flue gas desulfurization (FGD) 

system used for SO2 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 

NO2 becomes dissolved in the wet FGD absorber and can be removed as elemental N2 or various 

phosphate compounds that may be used as fertilizer and/or animal food additives. 

NOxStarTM. Doosan Babcock's proprietary NOxStarTM technology is a NOX reduction process that 

employs the injection of reagents (ammonia and hydrocarbon gas) through a grid located in an existing 

cavity in the boiler's convective pass. This results in an autocatalytic plasma reaction that reduces NOX

to nitrogen and water vapor. NOxStarTM eliminates the need to install a solid catalyst layer and the 

associated potential problems of chemical poisoning, physical plugging, sintering due to temperature 

excursions, pressure drop requiring larger ID fans, and disposal of a hazardous solid waste. In the 

NOxStarTM system, the conversion of SO2 to SO3 is said to be negligible. A single layer of in-duct 

catalyst (NOxStarTM Plus) is an option with this system. NOxStarTM is reported to reduce NOX by 80% 

or more. 

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. 

NOX 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. 

Figure 1 shows the maximum 30-day average NOX emissions rate of facilities for the best performing 

facilities that reported both NOX emissions and gross electric output data to CAMD. 

Figure 1: NOX Emissions Performance Data 

Facility Time Period 

Maximum 30-Day 

NOX 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 listed 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 listed in Figure 1 have less 

than a year of operating data. Proposing a more stringent standard might not provide sufficient 

compliance margin to account for expected variability in the long term performance of NOX controls. 

Although not all affected facilities using SCR are presently achieving an emissions rate of 0.70 lb/MWh, 

all major boiler designs have demonstrated combustion controls that are able to reduce NOX emissions 
to levels where the addition of SCR (or design modifications and operating changes to existing SCR) or 

an alternate control strategy would allow compliance with a NOX emissions rate of 0.70 lb/MWh. We 

are therefore selecting 88 ng/J (0.70 lb/MWh) as the proposed NOX standard for new, modified, and 

reconstructed facilities. 
Post Proposal NOX 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 2 shows the performance of facilities identified by EPA with NOX emissions of 0.70 lb/MWh or 

emission rates of EGUs that have commenced operation since 2007, but that are not presently operating at 0.70 lb/MFigure 2: NOX Emissions Performance Data for Facilities Demonstrating an Emissions Rate of 0.70 lb/MWh 

Facility Fuel 

Type 

Boiler Type & Control 

Technology 

Maximum 30-Day NOX

Emissions Rate 

(lb/MWh) 

99% Confidence 30-

Day NOX Emissions 

Rate (lb/MWh) 

Havana 8 ((1/05 – 12/10) SUB PC + SCR 0.70 0.66 Comanche 3 (6/10 – 12/10) SUB PC + SCR 0.59 0.59 Dallman 4 (12/09 – 12/10) BIT PC + SCR 0.67 0.67 Walter Scott Junior 4 (4/07 – 12/10) SUB PC + SCR 0.58 0.66 Mirant Morgantown 1 (2/10 – 12/10) BIT PC + SCR 0.54 0.57 Mirant Morgantown 2 (2/10 – 12/10) BIT PC + SCR 0.43 0.43 Cardinal 1 (1/09 – 12/10) BIT PC + SCR 0.38 0.43 Cardinal 2 (1/09 – 12/10) BIT PC + SCR 0.51 0.58 Cardinal 3 (1/09 – 12/10) BIT PC + SCR 0.58 0.51 Muskingum River 5 (1/08 – 12/10) BIT PC + SCR 0.70 0.63 John E Amos 1 (1/10 – 12/10) BIT PC + SCR 0.37 0.42 Mitchell 1 (1/09 – 12/10) BIT PC + SCR 0.59 0.63 Weston 4 (7/08 – 12/10) SUB PC + SCR 0.48 0.52 H L Spurlock 4 (5/09 – 12/10) BIT CFB + SNCR 0.67 0.69 Iatan 2 (10/10 – 12/10) SUB PC + SCR 0.48 0.50 Nebraska City 2 (4/09 – 12/10) SUB PC + SCR 0.62 0.64 Belews Creek 2 (4/07 – 12/10) BIT PC + SCR 0.65 0.74 Springerville 4 (4/10 – 12/10) SUB PC + SCR 0.62 0.68 AES Deepwater 1001 (6/07 – 12/10) PC PC + SCR 0.66 0.51 Elm Road 1 (1/10 – 12/10) BIT PC + SCR 0.57 0.60 Elm Road 2 (8/10 – 12/10) BIT PC + SCR 0.50 0.55 TS Power 1 (7/08 – 12/10) SUB PC + SCR 0.49 0.51 Plum Point 1 (7/10 – 12/10) SUB PC + SCR 0.62 0.66 Wygen III (5/10 – 12/10) SUB PC + SCR 0.43 0.45 Northeastern (1/07 – 12/10) REF CFB + SNCR 0.85 0.80 
Figure 3: NOX Emissions Performance Data for Additional Facilities that Commenced Operation Since 2007

Facility Fuel 

Type 

Boiler Type & Control 

Technology 

99% Confidence 30-Day 

NOX Emissions Rate 

(lb/MWh) 

99% Confidence 30-

Day NOX Emissions 

Rate without Startup or 

Shutdown (lb/MWh) 

Wygen II (1/08 – 12/10) SUB PC + SCR 0.77 0.79 Cross 3 (5/07 – 12/10) BIT PC + SCR 0.79 0.75 Cross 4 (6/08 – 12/10) BIT PC + SCR 0.78 0.77 Iatan 1 (4/09 – 12/10) SUB PC + SCR 0.94 0.98 Springerville TS3 (4/07 – 12/10) SUB PC + SCR 0.73 0.76 Sandow 5A (1/10 – 12/10) LIG CFB + SNCR 0.90 0.93 Sandow 5B (1/10 – 12/10) LIG CFB + SNCR 0.76 0.82 Oak Grove 1 (12/09 – 12/10) LIG PC + SCR 0.72 0.72 Oak Grove 2 (5/10 – 12/10) LIG PC + SCR 0.78 0.78 To evaluate the impact of including periods of startup and shutdown in the emissions average, EPA evaluated the emS. King facility with and without periods of startup and shutdown. The differences in the calculated 30-day emission submitted to the docket and the EPA is attributed to the procedure used to calculate the 30-day averages. The EPA 3calculated using the procedures described in the proposal (sum of emissions of the applicable pollutant divided by thoutput) and the commenter used the average of the hourly emission rates for the 30-day period. As stated in the prop

result in lower numerical emission rates because hours with high emission rates but low heat inputs (typically of starload operation) are not weighted as heavily. Figure 6: Impacts of Startup and Shutdown 

Facility 99% Confidence 30-

Day NOX Emissions 

Rate (lb/MWh) 

99% Confidence 30-

Day NOX Emissions 

Rate without Startup or 

Shutdown (lb/MWh) 

99% Confidence 30-

Day NOX Emissions 

Rate (lb/MMBtu) 

99% Confi

NOX Em

without 

Shutdown 

Allen S King 1 (1/10 - 3/11) 0.92 0.88 0.125 0The different approaches yield significant differences in the impact of startup and shutdown periods. In this case, the 

results in a difference of 4% and the calculations used by the commenter resulted in a 26% difference. As shown in F

exclude periods of startup and shutdown from the emissions standard the numerical standard and percent reduction s

reevaluated. As suggested in the comments, EPA evaluated the performance of existing facilities with limited ability to use combNOX emissions to determine an appropriate standard for modified facilities. Figure 5 shows the NOX emission rates f

cyclone EGUs burning various coal types 
Figure 5: Cyclone EGU NOX Emission Rates 

Facility Fuel 

Type 

Boiler Type & Control Technology 99% Confidence 30-Day NOX

Emissions Rate (lb/MWh) 

Coffeen 1 (1/10 – 12/10) SUB Cyc + SCR 0.88 Coffeen 2 (1/10 – 12/10) SUB Cyc + SCR 0.68 Baldwin 1 (1/05 – 12/10) SUB Cyc + SCR 0.76 Baldwin 2 (1/05 – 12/10) SUB Cyc + SCR 0.81 Allen S King 1 (1/10 - 3/11) SUB Cyc + SCR 0.92 Merrimack1 (1/09 – 12/10) BIT Cyc + Combustion Controls 3.58 Merrimack2 (1/09 – 12/10) BIT Cyc + Combustion Controls 2.82 Leland Olds 1 (1/09 – 12/10) LIG Cyc + Combustion Controls 3.52 Leland Olds 2 (1/09 – 12/10) LIG Cyc + Combustion Controls 3.76 As described in the response to comments, cyclone boilers would be able to achieve the standard for modified EGUs

types mentioned in the comments, EPA evaluated the 2010 NOX emission rates for the best performing EGUs for the 

Figure 7. With the application of SCR to Kanahwa River 2, all boiler types have demonstrated that the amended stanfacilities as achievable. Reconstruction takes such a large capital investment that burner designs could be alternated controls would be sufficient to facility compliance with the amended new source standard. Figure 7: Annual Emission Rates for Boiler Types not Previously Listed 

Facility Boiler Type Control Technology 2010 Annual NOX Emissions 

Rate (lb/MWh) 

Pleasant Prairie 1 Dry bottom turbo-fired boiler SCR 0.69 Pleasant Prairie 2 Dry bottom turbo-fired boiler SCR 0.68 Big Bend 1 Wet bottom turbo-fired boiler SCR 0.93 Kanawha River 2 Dry bottom vertically-fired boiler Low NOX Burners 2.29 
Figure 8 lists all of the data EPA collected on CO emissions from EGUs reevaluated using the corrected 30-day calculation pro

Figure 8: Combined CO/NOX Emission Rates for All Facilities 

Facility Fuel 

Type 

Boiler Type & Control 

Technology 

Maximum 30-Day NOX

+ CO Emissions Rate 

(lb/MWh) 

99% Confidence 30-D

NOX + CO Emission

Rate (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 + SCR 0.95 (0.51) 1.09 (0.95) WA Parish WAP 5 (9/05 – 12/09) SUB PC + SCR 1.05 (0.61) 0.95 (0.46) WA Parish WAP 6 (1/05 – 12/09) SUB PC + SCR 1.19 (0.81) 1.06 (0.55) WA Parish WAP 7 (6/05 – 12/09) SUB PC + SCR 1.95 (1.55) 1.85 (1.44) WA Parish WAP 8 (4/06 – 12/09) SUB PC + SCR 1.49 (1.11) 1.48 (1.09) Duck Creek (4/09 – 12/09) BIT PC + SCR 4.47 (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 + SCR 8.20 (6.55) 6.43 (4.68) Jeffery Energy Center 3 (1/08 – 12/10) SUB PC + SCR 4.04 (2.03) 4.00 (2.05) Oak Grove 1 (12/09 – 9/10) LIG PC + SCR 2.24 (1.57) 2.36 (1.72) Oak Grove 2 (5/10 – 9/10) LIG PC + SCR 2.31 (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 addit

rate that has been demonstrated both both fluidized bed and pulverized coal boiler is 0.4 lb/MWh.