MEMORANDUM 

From: Office of Air Quality Planning and Standards 

 U.S. Environmental Protection Agency 

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

Date: November, 2012 

Subject: Incremental Control Cost, Energy, and Environmental Impacts of Revisions to Electric 

Utility Steam Generating Unit NSPS under 40 CFR Part 60 subpart Da 

Introduction 

The New Source Performance Standards (NSPS) under 40 CFR 60 subpart Da presently regulate the 

emissions of filterable particulate matter (PM), sulfur dioxide (SO2), and nitrogen oxides (NOX) from 

new, modified, and reconstructed electric utility steam generating units (EGUs), as defined in the rule. 

The Clean Air Act (CAA) section 111(b)(1)(B) requires the U.S. Environmental Protection Agency 

(EPA) to periodically review and, if appropriate, revise NSPS to reflect improvements in emissions 

reduction methods. The EPA revised the NSPS for EGUs for PM, SO2, and NOX on February 16, 2012, 

(77 FR 9304) to reflect the performance achievable by the best demonstrated technologies for 

controlling these pollutants. 

NSPS are required under CAA section 111 to reflect the application of the best system of emissions 

reductions that EPA has determined to be adequately demonstrated (taking into account the cost of 

achieving such reductions, any non-air quality health and environmental impacts and energy 

requirements). The purpose of this memorandum is to provide additional analysis of the achievability 

and the cost, non-air quality environmental, and energy impacts of the revised PM emissions standard. 

Impacts Estimate General Approach 

PM Control technologies for steam generating units are based on pre-combustion controls, postcombustion controls, or a combination of approaches. Pre-combustion controls remove ash from the fuel 

before it is burned, and post-combustion controls remove PM from the flue gases before the gases are 

released to the atmosphere. To comply with the EGU NSPS, affected owners/operators of new coal-fired 

EGUs need to install post-combustion air pollution controls to meet the emissions standard for filterable 

PM. The specific control configurations used for an individual EGU will depend on site-specific factors 

including type and characteristics of the coal burned and the type of boiler used to burn the coal. The 

costs to install and operate these controls will be incurred regardless of the revisions to the PM 

emissions standard. Consequently, the control configuration used for a new coal-fired EGU to meet the 

previous EGU NSPS represents the reference point or “regulatory baseline” from which the additional 

control costs and associated non-air quality and energy impacts of complying with the current emissions 

standard are determined. 

Cost, non-air quality environmental, and energy impacts estimates were prepared for hypothetical 

“model plants” representative of the coal-fired EGUs and associated control system configurations that 

may be build in the United States in the foreseeable future. The basis for the PM control system cost 

estimates is a combination of control algorithms and procedures developed by the EPA Clean Air 

Markets Division (CAMD) (available at: www.epa.gov/airmarkets/progsregs/epaipm/docs/append5_5.pdf) and the Coal Utility Environmental Cost (CUECost) model (available at 

http://www.epa.gov/ttncatc1/products.html). The capital costs for the control systems were annualized 

using a capital recovery factor that assumes an interest rate of 7% and a period of 20 years. All costs are 

expressed as 2009 dollars. In addition, since the IPM cost procedures are primarily intended to estimate 
costs of retrofitting controls to existing units, the costs estimated by the IPM are reduced a retrofit factor 

of 0.77 to account for the controls being installed at model plants representing new EGUs. 

The costing algorithms and procedures used for this impact analysis are intended to provide “study 

estimate” costs. Cost values obtained by this type of cost estimation method are on the order of ± 30% of 

the presumed actual costs for the control system being modeled. The model plant EGUs selected for this 

impact analysis do not represent specific actual coal-fired electric utility power plant currently operating 

or under construction in the United States. Furthermore, the control costs estimated by this analysis are 

not intended to be directly applied to a specific coal-fired electric utility power plant location. Actual 

control costs for a given coal-fired EGU project will be determined by the detailed site-specific factors, 

and therefore can be higher or lower than the costs presented in this memorandum. However, the cost 

and impact values derived from a model plant analysis provide reasonable estimates for the purpose of 

evaluating the impacts of revisions to the existing EGU NSPS. 

Model Plant EGU Descriptions 

Costs for installing and operating the air pollution controls were estimated by assigning specific air 

pollution control configurations to seven model plants representing EGUs varying in characteristics of 

the coal burned, boiler types, and generating capacity. Five of the model plant EGUs represent 

pulverized coal-fired (PC-fired) boilers burning either bituminous coal, subbituminous coal, or lignite. 

The coal types were selected for these model plant EGUs to represent a typical low-sulfur, mediumsulfur, and high-sulfur content coal that would be burned in a new EGU. Two additional model plant 

EGUs represent boilers that use fluidized-bed combustion (FBC) technology and burn lignite or coal 

refuse. The boiler sizes were selected to approximately span the range of typical coal-fired EGUs 

expected to be built in the United States. Boiler sizes are expressed in terms of the model plant EGU’s 

gross electricity output in megawatts electric (MWe). 

The model plant EGU configurations defined for the impact analysis are described in Table 1. All of the 

model plant EGUs, with the exception of the 100 MW size boilers, are projected to have a gross 

efficiency of 38% (8,979 Btu/kWh) and assumed to be operated as base load units with an annual 

capacity factor of 85%. Supercritical steam turbines are not available below approximately 200 MW and 

coal refuse-fired EGUs tend to be less efficient than EGUs burning higher rank coals. To account for 

this, the 100 MW subbituminous and coal refuse-fired boilers were projected to have gross efficiencies 

of 36% (9,478 Btu/kWh) and 34% (10,035 Btu/kWh) respectively and annual capacity factors of 85%. 
Table 1. Coal-fired EGU “Model Plant” Configurations

Model 

Plant 

Boiler 

Type 

Coal 

Burned 

Gross 

Generating 

Capacity 

(MWe) 

Gross 

Heat 

Rate 

(Btu/kWh) 

Annual 

Capacity 

Factor 

A PC Low sulfur Subbituminous 

(Wyoming PRB) 100 9,478 85% 

B PC Low sulfur Subbituminous 

(Wyoming PRB) 500 8,979 85%

C PC Medium sulfur Bituminous 

(Armstrong, PA) 500 8,979 85%

D PC High sulfur Bituminous 

(No. 6 Illinois) 500 8,979 85%

E PC Lignite (Bryan Texas) 500 8,979 85%

F FB Lignite (North Dakota) 400 8,979 85%

G FB Coal refuse 100 10,035 85%

The regulatory baseline defined for each model plant used for the incremental impact analysis is 

presented in Table 2. The regulatory baseline PM emissions rate is the controlled emissions rate 

assuming the use of a fabric filter with an air to cloth ratio of 4.0 for PM control for all units. 

Table 2. Coal-fired EGU “Model Plant” Regulatory PM Baseline 

Model 

Plant

Emissions Rate 

(lb/MMBtu) 

Emissions Rate 

(lb/MWh) 

PM Emissions 

(tons) 

PM Controls 

Assumption 

Annual Fabric 

Filter Costs ($/y) 

Electricity 

Use (MWh) 

A 0.015 0.142 53 Fabric Filter 1,767,000 4,382 

B 0.015 0.135 251 Fabric Filter 6,157,000 18,988 

C 0.015 0.135 251 Fabric Filter 6,639,000 20,734 

D 0.015 0.135 251 Fabric Filter 6,750,000 21,141 

E 0.015 0.135 251 Fabric Filter 7,156,000 22,631 

F 0.015 0.135 201 Fabric Filter 5,174,000 15,492 

G 0.015 0.151 56 Fabric Filter 1,769,000 4,370 

PM Emissions Control Impacts 

Controls for filterable PM are well established, and the PM control that would be used by any new coalfired EGU would be use of a fabric filter (i.e., baghouse) or an electrostatic precipitator (ESP). Either of 

control devices can achieve the high control efficiencies needed to meet the existing limit and control for 

both coarse and fine filterable PM. For the impact analysis, the PM emissions regulatory baseline is 

assumed to be 0.015 lb/MMBtu and is defined to be installation of fabric filters on all units. It is 

assumed that to meet the amended PM emissions limit of 0.090 lb/MWh, this fabric filter would need to 

reduce the number of holes in the bag material and improve the maintenance practices by increasing the 

frequency of bag replacements to once every 3 years instead of the baseline of once every 5 years. Table 
3 shows the annual cost of the more frequent bag replacement schedule. The cost effectiveness is the 

total annual cost per ton of PM reduction compared to the baseline fabric filter. 

Table 3. Fabric Filter Costs with Increased Frequency of Bag Replacement

Model 

Plant 

Annual Costs 

($/y) 

PM Emissions 

(tons) 

Incremental 

Cost Effectiveness 

($/ton PM) 

A 1,804,000 34 1,900 

B 6,315,000 167 1,900 

C 6,812,000 167 2,100 

D 6,926,000 167 2,100 

E 7,345,000 167 2,300 

F 5,303,000 134 1,900 

G 1,799,000 34 1,400 

These incremental costs are considered acceptable, especially considering that the majority of the 

reductions will be fine PM. The only secondary environmental impacts would be the disposal of the 

extra bag material and the incremental PM that is collected. 

To provide additional analysis, we also estimated the cost of using a secondary control device after the 

fabric filter as an alternate to the more frequent bag replacement schedule. To meet the amended PM 

emissions limit, it is assumed that the addition of a wet electrostatic precipitator (WESP) downstream of 

the fabric filter would reduce additional filterable PM that is not collected by the fabric filter and be 

sufficient to achieve the required higher performance level. 

The current version of the IPM does not include a costing model for WESPs. Therefore, the WESP costs 

are estimated using the results from an EPA sensitivity analysis for the Clean Air Interstate Rule (CAIR) 

(available at: http://www.epa.gov/cair/pdfs/0053-2263.pdf). The EPA estimated the cost impacts for 

CAIR using the IPM. The cost method provided capital, fixed O&M, and variable O&M costs as a 

function of EGU size. A scaling factor was provided, as the base unit of the method was a 500 MW unit. 

The WESP costs from the CAIR analysis were in 2002 dollars. To calculate 2009 dollars, the Chemical 

Engineering Price Costing Index (CEPCI) was used for the capital cost, and an inflation rate of 2.5% per 

year was used for the variable O&M and fixed O&M costs. 

For those coal-fired EGUs using wet scrubber systems for SO2 emissions control to meet the existing 

EGU NSPS, it is assumed that the wastewater from the WESP would be recycled to the wet scrubber. 

Coal-fired EGUs without an existing wastewater treatment system capable of handling the additional 

wastewater stream from the WESP would need to build and operate a suitable wastewater treatment 

system. Costs for such a system are not included in the analysis. 

Table 4 presents the estimated incremental impacts of revising the EGU NSPS PM emissions limit for 

all of the model plant EGUs relative to impacts of using only a fabric filter to meet the existing PM 

emissions limit. While these costs are higher than improved fabric filter maintenance, the cost impact 

analysis for all model plant EGUs does not account for the benefit of additional SO2 and condensable 

PM emissions reduction that would occur with the use of the WESP. 
Table 4. Secondary WESP Control System Annual Impacts

Model 

Plant WESP Annual Costs

PM Emission 

Reduction 

(tons) 

Incremental 

Cost Effectiveness 

($/ton PM) 

A 806,000 19 42,400 

B- E 2,579,000 84 30,700 

F 2,193,000 67 32,700 

G 806,000 22 36,600 

Alternate PM Emissions Control Impacts Analysis 

A separate analysis was done assuming an ESP was the preferred primary baseline control device for the 

bituminous and lignite-fired PC units. To estimate the cost impacts under this scenario, we estimated the 

costs for 2 different approaches. The first approach would be to design a larger ESP with an improved 

capture efficiency to achieve the amended PM standard. The alternate approach is to design a relatively 

inefficient ESP to control the PM emissions down to 0.10 lb/MMBtu followed by either a WESP or a 

polishing fabric filter with an air to cloth ratio of 6.0 to reduce emissions down to 0.090 lb/MWh. We 

used the same ESP cost model as in the 2005/2006 NSPS amendments updated to 2009 dollars to 

evaluate the incremental cost effectiveness of the amended standard compared to the existing NSPS. 

Table 5 shows the differences for the two ESP designs. 

Table 5. Incremental Impacts of Improved ESP Performance 

Model 

Plant 

Baseline (0.015 lb/MMBtu) Amended Standard (0.090 lb/MWh) Incremental 

Cost 

Effectiveness 

($/ton PM) 

Specific 

Collection Area 

(SCA, ft2/1,000 

acfm) 

Annual 

Costs ($/y) 

Electricity 

Use 

(MWh) 

Specific Collection 

Area (SCA, 

ft2/1,000 acfm) 

Annual 

Costs ($/y) 

Electricity 

Use 

(MWh) 

C 391 5,797,000 19,258 444 6,318,000 20,734 6,200 

D 501 6,956,000 22,303 560 7,532,000 23,977 6,900 

E 1,203 14,042,000 42,125 1,336 15,249,000 45,816 14,400 

Table 5 shows that for facilities with ash characteristics amenable to collection by an ESP, the 

incremental costs are cost effective. 

 
Tables 6 and 7 show the costs for a less efficient ESP used in combination with a secondary WESP and 

fabric filter. 

Table 6. Incremental Impacts of Secondary WESP 

Model 

Plant 

ESP (0.10 lb/MMBtu) WESP Annual 

Costs ($/y) 

Incremental 

Cost 

Effectiveness 

($/ton PM) 

Specific Collection 

Area 

(SCA, ft2/1,000 acfm) 

Annual 

Costs ($/y)

Electricity Use 

(MWh) 

C 186 3,515,000 10,610 2,579,000 3,500 

D 265 4,403,000 12,729 2,579,000 310 

E 681 8,921,000 24,446 2,579,000 (30,300) 

Table 7. Incremental Impacts of Polishing Fabric Filter 

Model 

Plant 

ESP (0.10 lb/MMBtu) Fabric Filter Incremental 

Cost 

Effectiveness 

($/ton PM) 

Specific Collection 

Area 

(SCA, ft2/1,000 acfm) 

Annual 

Costs ($/y)

Electricity Use

(MWh) 

Annual 

Costs ($/y)

Electricity 

Use (MWh) 

C 186 3,515,000 10,610 5,161,000 17,253 34,300 

D 265 4,403,000 12,729 5,248,000 17,592 32,100 

E 681 8,922,000 24,446 5,562,000 18,832 5,300 

The calculated incremental cost effectiveness in Tables 6 and 7 combine results from different cost 

models and increase the uncertainty of the results. However, the results indicate that a combination of 

different controls may offer the lowest overall costs. 

 
Control of Filterable PM Emissions 

Particulate matter (PM) may be classified by particle size and as either filterable or condensable PM. 

Filterable PM originates from ash in the fuel, incomplete combustion products, and flue gas 

desulfurization (FGD) reaction products. Filterable PM consists of incombustible inert matter (ash), and 

condensable PM consists of gases that will condense into a liquid or solid upon reaching ambient 

temperature. For coal-fired boilers, condensable PM may contain sulfuric and nitric acids, high 

molecular weight organics, and other compounds. Total suspended particulate (TSP) encompasses all 

sizes of filterable PM. Particulate matter that is less than 10 microns in aerodynamic diameter is 

generally referred to as PM10. All particulate matter emitted from a controlled EGU stack is expected to 

be less than 10 microns in size. Particulate matter that is less than 2.5 microns in aerodynamic diameter 

is referred to as PM2.5. Condensable PM is included in this category because it is expected that all 

condensable PM is less than 2.5 microns in the atmosphere. Filterable PM2.5 and condensable PM are 

considered direct PM2.5 emissions. In addition to direct PM2.5 emissions, indirect PM2.5, or secondary 

PM2.5, is formed when precursors such as SO2, NOX, VOCs, and ammonia form PM2.5 through reactions 

in the atmosphere. 

The amended subpart Da filterable PM emissions standard for owners/operators of new facilities is 

0.090 lb/MWh gross energy output. 

PM Control Technologies 

The following is a brief summary of some of the PM 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 

Mechanical/Inertial Collectors (Cyclones/Multicyclones). A cyclone is a cylindrical vessel, usually with 

a conical bottom. The flue gas enters the vessel tangentially and sets up a rotary motion whirling in a 

circular or conical path. The particles are 'thrown' against the walls by the centrifugal force of the flue 

gas motion where they impinge and eventually settle into hoppers. The removal efficiency is between 

75 and 99% for particle sizes between 1.0 and 100 μm. Cyclones are robust technologies that can deal 

with the cyclic operation and load changes. However, their efficiency is moderate when compared with 

an ESP or fabric filter. 

Wet Scrubber. The basic principle of wet scrubbers designed for PM control is to provide sufficient 

contact between the flue gas and scrubbing liquid to facilitate removal of the PM. Venturi scrubbers are 

the most commonly used scrubber for particle collection and are capable of achieving the highest 

particle collection efficiency of any wet scrubbing system. In a venturi scrubber, water is injected into 

the flue gas stream at the venturi throat to form fine droplets. Fly ash particles impact with the droplets 

forming a wet by-product which then generally requires disposal. Many of the wet particulate scrubbers 

are designed to control both SO2 and particulates by utilizing the alkaline fly ash as sorbent. Lime or 

some other sorbent is frequently used to boost SO2 removal efficiencies. In general, venturi scrubbers in 

combination with a mechanical collector are not expected to reduce PM emissions to the level required 

by the NSPS. In addition, venturi scrubbers tend to have relatively high energy consumption and do not 

control filterable PM2.5 as well as a comparable ESP or fabric filter. 

Flue Gas Desulfurization (FGD). FGD technologies designed for SO2 control are also capable of 

reducing acid gases that are considered condensable particulate matter. An FGD is not a primary PM 

control technology; however FGD technology is a feasible control technology for reducing condensable 

PM emissions. 
Dry Electrostatic Precipitator (ESP). An ESP is a PM control technology that utilizes electrical charges 

to attract particulate matter present in the gas stream. An ESP consists of negatively charged discharge 

electrodes and positively charged collection plates. The negatively charged electrodes create a corona of 

electrical charges transmitting a negative charge to the particulate matter in the gas stream. The 

negatively charged particulate matter is then attracted to the ESP’s positively charged collection plate. 

Particulate matter accumulates on the collection plate until the plate is mechanically “rapped” causing 

the PM to fall into hoppers. The PM that collects in the hoppers is then removed by the ash handling 

system. An ESP consists of a series of the electrical fields described above in order to capture any PM 

that may be re-entrained in the flue gas stream during rapping. Some emissions during rapping of the 

last field are unavoidable. An ESP can be located either upstream of the air pre-heater (hot-side ESP) or 

downstream of the air pre-heater (cold-side ESP). Either location selected for the ESP operates at a 

temperature above the dew point of condensable particulate matter. ESPs are intentionally operated at 

high temperatures to prevent corrosion problems that can result from condensable acid gases. 

Particulate removal efficiencies in ESPs can be improved by flue gas conditioning. Flue gas 

conditioning involves injecting conditioning agents such as elemental sulphur, ammonia (NH3), and 

sulphur trioxide (SO3) into the flue gas prior to the ESP. The removal efficiency is between 99.00 and 

99.99% for particle sizes between 0.01 and 100 μm. 

Wet Electrostatic Precipitator (WESP). A WESP operates in saturated flue gas conditions, where the 

flue gas is below the dew point of many acid gases and other condensable PM. The collector plates of a 

WESP are washed with water. The process eliminates the need for rapping as the liquid film removes 

any deposited fly ash particles. Thus, problems with re-entrainment, fly ash resistivity, and capture of 

fine particles become obsolete. A WESP is a feasible control technology for reducing fine filterable and 

condensable PM emissions. However, WESPs require saturation of the flue gas stream with water and 

generate waste water and sludge. The power required collecting particulate matter in the WESP and the 

pressure loss across the WESP are the main operating costs of the WESP system. A WESP system may 

increase the amount of waste water that requires treatment and the WESP system auxiliary power will 

consume approximately 0.5% of the gross output primarily due to additional power requirements for 

collection. 

Fabric Filter Baghouse (FF). A fabric filter baghouse is a PM collection device that utilizes fabric filters 

or “bags” to collect PM. The design for a fabric filter is fairly simple. The flue gas enters an enclosure 

that contains compartmentalized groups of bags. The bags are operated in a manner to allow for 

cleaning, maintenance, and repair of one compartment (or group of bags) at a time. A compartment 

within the fabric filter includes the bags as the filter media, a tube sheet that supports the bags, a PM 

dislodging mechanism, and a hopper to collect the accumulated PM. As the flue gas enters the fabric 

filter enclosure, PM accumulates on the bags and a “filter cake” is formed. The “filter cake” will 

continue to accumulate on the bags until the pressure drop across a compartment has increased to a 

specified limit. Once the specified pressure drop has been attained the PM is removed by placing the 

compartment in cleaning mode. Several methods for cleaning a fabric filter compartment include 

reverse gas fabric filters (RGFF), reverse air with mechanical shakers, and pulse jet fabric filter (PJFF). 

Each of the above cleaning methods is capable of removing the PM that has accumulated on the fabric 

filter. Once removed, the PM is collected by the ash hoppers. In a dry FGD application, the baghouse 

operates at lower temperatures due to the cooling in the dry FGD. This lower operating temperature 

may increase the condensation and theoretically increases control of condensable PM. A FF has a 

higher pressure drop and greater energy penalty than an ESP. 

The specific fabric for an FF is selected based on the operating parameters, pollutant characteristics, and 

mechanical operation. The EPA has an Environmental Technology Verification (ETV) program to 

verify innovative pollution control technologies. The verified fabric filter products indicate the fabric 
can achieve PM2.5 emission levels as low as 0.0001 lb/MMBtu. The list of fabric filter products include 

felted bags and high efficiency microfiber felts, intrinsically coated (IC) bags, and membrane bags. 

Felted filters are often used on PJFF and do not require an initial filter cake to collect fine particulates. 

Felted filters are generally 2 to 3 times thicker than woven filters, which improves fine particle 

collection. High efficiency microfiber felts are similar to felted fibers, but they use ultra-fine fibers to 

enhance fine particulate matter control. Intrinsically coated filters are made from fibers that are coated, 

usually with a fluoro-polymer, such as Teflon®. These filters are highly durable and have a smaller 

pore size between fibers, which improves filterable PM2.5 control. Membrane filters have a 

polytetrafluoroethylene (PTFE) coating, such as Teflon®, on the fabric, as opposed to the individual 

fibers. This also provides enhanced control for filterable PM2.5. However, the use of either intrinsically 

coated or membrane bags tends to inhibit the filter cake formation. The filter cake formation can 

increases the effectiveness of the FF for controlling PM2.5 precursors and condensable PM2.5. 

Reactant/Sorbent Injection. Injection technologies to control condensable PM emissions utilize injection 

of a sorbent or reactant. The most common injection chemicals include sodium bisulfite (NaHSO3), 

sodium carbonate (Na2CO3) or trona, and hydrated lime (Ca(OH)2). Ammonia (NH3) and magnesium 

hydroxide (Mg(OH)2) have also been used. The sorbents or reactants utilize their physical and chemical 

properties to react with or adsorb condensable PM (e.g., H2SO4) to produce a solid byproduct that can be 

collected in the particulate control system. Sorbent injection is typically installed between the SCR and 

a fabric filter or ESP. 

COHPACTM. The COHPACTM technology combines an ESP with a high air to cloth ratio FF. The FF is 

placed in a separate casing downstream of the ESP (known as COHPAC I) or within the existing ESP's 

casing by replacing one or more fields of collecting plates with FF modules (COHPAC II). The 

technology is based on the fact that a FF collects higher levels of particulate-and finer particulate-than 

an ESP of equivalent size. The FF acts as a "polishing device". 

Advanced Hybrid Particulate Collector. The Advanced Hybrid Particulate Collector (AHPC) utilizes 

both electrostatic collection and filtration in a unique geometric configuration that achieves PM control 

with much less collection area than conventional PM devices. The design configuration of AHPC is 

unique because, instead of placing the ESP and FFB sections in series, the filter bags are placed directly 

between the ESP collection plates. The collection plates are perforated (45% open area) to allow dust to 

reach the bags. However, since the particles become charged before they pass through the plates, over 

90% of the PM mass is collected on the plates before it reaches the bags. When pulses of air are used to 

clean the filter bag surfaces, the dislodged particles are thrown back into the ESP fields where they have 

another opportunity to be collected on the plates. Tests to date show that the AHPC provides over 

99.99% particulate collection efficiency for all particle sizes, at a cost that is competitive with or lower 

than existing technologies. 

Max-9TM. The Max-9TM technology is an electrostatic precipitator/pulse-jet baghouse hybrid, employing 

high voltage discharge electrodes to charge the PM, but with fabric filters instead of collecting plates in 

the casing. Dust particles in the gas are charged by the discharge electrodes, and are attracted to the 

grounded metal cage inside the filter element. The negatively charged particles repel each other on the 

filter surface, resulting in a highly porous filter cake. The Max-9TM ESFF technology is reported to 

provide high collection efficiency while operating at significantly lower system pressure drop than a 

comparable FF. 

PM Control Performance 

Figure 1 shows the filterable PM emission rates for coal-fired electric generating units with the lowest 

PM emission rates, as reported to EPA as part of the EGU NESHAP information collection request 

(ICR). We used all performance data that was submitted. Figure 1 only includes facilities that reported 
more than 1 performance test. The 99% and 99.9% confidence level emission rates were calculated 

assuming the data was normally distributed and adding 2.57 and 3.39 standard deviations to the mean 

emissions rate respectively. The data shows that the amended standard is currently being achieved by 

electric generating units burning a variety of fuels, using different boiler designs, and using various 

control strategies. 
11 

Figure 1: Filterable PM Performance Test Data 

Facility Name

CAMD facility ID

Boiler ID

Maximum Emissions Rate (lb/MMBtu)

Minimum Emissions Rate (lb/MMBtu)

Mean Emissions Rate (lb/MMBtu)

Number of Performance Tests

Standard Deviation (lb/MMBtu)

99% Confidence Emissions Rate (lb/MMBtu)

99.9% Confidence Emisisons Rate (lb/MMBtu)

Unit type

Fuel Type

Fuel Ash Content (%)

Vermilion Power Station 897 2 0.0020 0.0010 0.0014 3 0.0005 0.0028 0.0032 PC SUB 5.2 Vermilion Power Station 897 1 0.0020 0.0010 0.0014 3 0.0005 0.0028 0.0032 PC SUB 5.2 Springerville Generating Station 8223 4 0.0019 0.0008 0.0012 3 0.0006 0.0028 0.0033 PC SUB 13.3 Mercer Generating Station 2408 2 0.0020 0.0008 0.0012 3 0.0007 0.0030 0.0035 PC BIT 4.7 Salem Harbor 1626 4 0.0030 0.0020 0.0027 3 0.0006 0.0042 0.0046 PC BIT 4.1 Havana 891 9 0.0027 0.0010 0.0019 2 0.0012 0.0050 0.0061 PC SUB 5.2 North Valmy 8224 1 0.0040 0.0025 0.0034 3 0.0007 0.0053 0.0059 PC BIT 9.0 Springerville Generating Station 8223 TS3 0.0044 0.0006 0.0019 5 0.0015 0.0057 0.0069 PC SUB 13.3 Milton R Young 2823 B1 0.0045 0.0035 0.0040 2 0.0007 0.0058 0.0064 Cyclone LIG 12.6 Cope Station 7210 COP1 0.0036 0.0016 0.0026 2 0.0014 0.0063 0.0074 PC BIT 8.3 Northside 667 2A 0.0046 0.0014 0.0029 6 0.0013 0.0063 0.0074 CFB PC 1.5 Rio Bravo Poso 10769 1 0.0054 0.0008 0.0022 5 0.0018 0.0069 0.0084 CFB Allen S King 1915 1 0.0076 0.0071 0.0074 2 0.0004 0.0083 0.0085 Cyclone SUB 5.6 Milton R Young 2823 B2 0.0062 0.0044 0.0053 2 0.0013 0.0086 0.0096 Cyclone LIG 12.6 Monroe 1733 4 0.0070 0.0027 0.0050 10 0.0015 0.0088 0.0101 PC SUB 6.1 Boswell Energy Center 1893 2 0.0100 0.0100 0.0100 2 0.0000 0.0100 0.0100 PC SUB 7.3 Laramie River 6204 2 0.0083 0.0047 0.0066 5 0.0014 0.0102 0.0113 PC SUB 6.2 H L Spurlock 6041 3 0.0065 0.0010 0.0036 4 0.0026 0.0103 0.0124 CFB BIT 12.7 Martin Drake 492 6 0.0009 0.0008 0.0008 2 0.0001 0.0011 0.0012 PC BIT 8.3 Mercer Generating Station 2408 1 0.0010 0.0009 0.0009 3 0.0001 0.0011 0.0012 PC BIT 4.7 Sandow Station 52071 5A 0.0010 0.0007 0.0008 2 0.0002 0.0014 0.0016 CFB LIG Northside 667 1A 0.0030 0.0007 0.0013 6 0.0009 0.0035 0.0042 CFB PC 1.5 J T Deely 6181 1 0.0033 0.0019 0.0026 2 0.0010 0.0052 0.0060 PC SUB 6.6 J T Deely 6181 2 0.0033 0.0019 0.0026 2 0.0010 0.0052 0.0060 PC SUB 6.6 Gallatin 3403 3 0.0043 0.0033 0.0038 2 0.0007 0.0057 0.0062 PC SUB 5.8 Gallatin 3403 4 0.0043 0.0033 0.0038 2 0.0007 0.0057 0.0062 PC SUB 5.8 Widows Creek 50 6 0.0047 0.0023 0.0033 4 0.0010 0.0059 0.0067 PC BIT 9.4 Marshall 2727 4 0.0051 0.0038 0.0047 3 0.0007 0.0066 0.0072 PC BIT 8.4 Centralia 3845 BW21 0.0057 0.0011 0.0032 6 0.0015 0.0070 0.0082 PC SUB 12.3 St. Clair 1743 3 0.0060 0.0028 0.0043 7 0.0012 0.0073 0.0082 PC SUB 4.8 Centralia 3845 BW22 0.0063 0.0009 0.0030 6 0.0021 0.0083 0.0100 PC SUB 12.3 Pleasant Prairie 6170 1 0.0062 0.0045 0.0053 2 0.0012 0.0084 0.0094 PC SUB 6.3 St. Clair 1743 1 0.0080 0.0077 0.0078 2 0.0002 0.0084 0.0086 PC SUB 4.8 Belle River 6034 1 0.0070 0.0054 0.0062 2 0.0011 0.0091 0.0101 PC SUB 4.7 St. Clair 1743 2 0.0063 0.0009 0.0031 4 0.0025 0.0094 0.0114 PC SUB 4.8 Cumberland 3399 2 0.0067 0.0043 0.0055 2 0.0016 0.0097 0.0111 PC BIT 7.2