1 

INFORMATION COLLECTION REQUEST FOR NATIONAL EMISSION 

STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAP) FOR COAL- AND 

OIL-FIRED ELECTRIC UTILITY STEAM GENERATING UNITS 

Part B of the Supporting Statement 

1. Respondent Universe 

In 2005, the number of coal- and oil-fired electric utility steam generating units (EGUs) 

at facilities owned and operated by publicly-owned utility companies, Federal power agencies, 

rural electric cooperatives, and investor-owned utility generating companies included 

approximately 1,332 units (boilers) that generated greater than 25 megawatts-electric (MWe), 

according to the U.S. Department of Energy/Energy Information Administration (DOE/EIA) 

Form EIA-767 database.1

 Currently, this database contains the most recent data available from 

DOE for coal- and oil-fired electric utility steam generating units but DOE/EIA states that (as of 

the writing of this supporting statement) the 2007 database is soon to be made publically 

available. The 2006 EIA-860 database covers some of the same units covered by EIA-767; 

however, this database also includes units owned and operated by non-utilities (including 

independent power producers and combined heat and power producers). EPA will query this 

database to determine if it includes any coal- or oil-fired EGUs that meet the CAA section 

112(a)(8) definition of an EGU. Additionally, EPA/OAR/Office of Air Quality Planning and 

Standards will coordinate with EPA/OAR/Clean Air Markets Division (to obtain an industry 

configuration database output from their electric utility sulfur dioxide (SO2) cap-and trade 

program) for help with the development of the final list of EGUs in this survey data collection 

effort. As facilities respond to Part I of the ICR data request, the Agency will modify this base 

list of units to represent all affected sources under this effort. 

2. Selection of Units to Provide Source Information

All coal- and oil-fired EGUs identified by EPA as being potentially applicable sources 

under the definition in CAA section 112(a)(8) as well as all integrated gasification combined 

cycle (IGCC) EGUs and all EGUs fired by petroleum coke will be required to provide 

 

1

 Note that units have been identified to the best of the Agency’s ability for the purpose of this ICR action only. 

Identification of any unit for receipt of the CAA section 114 letter requiring information be submitted or testing be 

conducted does not constitute a final Agency applicability determination related to the rule under development. 

Similarly, units not receiving a CAA section 114 letter may ultimately be determined to be subject to the final rule. 

Specific applicability definitions will be developed during the rulemaking process and will be subject to notice and 

comment. 
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information on the current operational status of the unit, including applicable controls installed, 

along with emissions information. The coal-fired EGUs identified for this effort are shown in 

Attachment 4; the oil-fired EGUs identified are shown in Attachment 5; the IGCC EGUs 

identified are shown in Attachment 6; and the petroleum coke-fired EGUs identified are shown 

in Attachment 7. 

3. Selection of Units to Conduct Stack Testing

Coal-fired units to be tested will be selected to cover four groups of hazardous air 

pollutants (HAP) that may potentially be regulated through the use of surrogate pollutant 

standards. At this time, we have made no final decision on the use of surrogate pollutants and 

any surrogate-based standard will be established only if consistent with the requirements of the 

CAA and applicable case law. The groups of HAP are acid-gas HAP (e.g., hydrogen chloride 

(HCl), hydrogen fluoride (HF)), dioxin/furan organic HAP, non-dioxin/furan organic HAP, and 

mercury and other non-mercury metallic HAP. Rationale for the selection of units for each 

possible surrogate group is discussed below. In the following stack testing, each facility is 

required to test after the last control device or at the stack if the last control device is not shared 

with one or more other units. In this way, the facility would test before any “dilution” by gases 

from a separately-controlled unit. Under certain circumstances, however, testing after a common 

control device or at the common stack will be allowed. 

EPA has selected for testing the sources that the Agency believes, based on a variety of 

factors and information currently available to the Agency, are the best performing sources for the 

HAP groups for which they will be required to test. In targeting the best performing sources, 

EPA is proposing to require testing for approximately 15 percent of all coal-fired EGUs for 3 of 

the HAP groups – metal HAP and PM; non-dioxin/furan organic HAP, total hydrocarbon, CO, 

and VOC; and acid gas HAP and SO2 – instead of only 12 percent of all sources. We will, of 

course, be obtaining emissions information from all sources in Parts I and II of the questionnaire. 

We are reasonably targeting the best performing coal-fired sources because the statute requires 

the Agency to set the MACT floor at the “average emission limitation achieved by the best 

performing 12 percent of the existing sources, (for which the Administrator has information)” in 

the category. By targeting the best performing 15 percent of coal-fired EGUs for testing, we 

believe this will ensure that we have emissions data on the best performing 12 percent of all 

existing coal-fired EGUs. For 3 of the HAP groups or individual HAP, to the extent the Agency 
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can establish that it has in fact collected data from all of the existing sources that represent the 

best performing 12 percent of existing sources, we intend to use data from sources representing 

the best performing 12 percent of all sources in any category or subcategory to establish the 

CAA section 112(d) standards. For oil-fired units, the bases for any surrogacy argument(s) are 

less well developed and will require more extensive testing (EPA is proposing to require 100 of 

the oil-fired units to test). 

Coal-fired units, acid gas HAP

The acid-gas HAP, HCl and HF, are water-soluble compounds and are more soluble in 

water than is SO2. (Hydrogen cyanide, HCN, representing the “cyanide compounds,” is also 

water-soluble and will be considered an “acid-gas HAP” in this document.) HCl also has a large 

acid dissociation constant (i.e., HCl is a strong acid) and it, thus, will react easily in an acid-base 

reaction with (i.e., be readily adsorbed on) caustic sorbents (e.g., lime, limestone). This indicates 

that both HCl and HF will be more rapidly and readily removed from a flue gas stream than will 

SO2, even when only plain water is utilized. In the slurry streams, composed of water and 

sorbent (e.g., lime, limestone) utilized in both wet and dry flue gas desulfurization (FGD) 

systems, acid gases and SO2 are absorbed by the slurry mixture and react to (usually) form solid 

salts. In fluidized bed combustion (FBC) systems, the acid gases and SO2 are adsorbed by the 

sorbent (usually limestone) that is added to the coal and an inert material (e.g., sand, silica, 

alumina, or ash) as part of the FBC process. The adsorption process is temperature dependent 

and the cooler the flue gas, the more effectively the acid gases will react with the sorbents. One 

mole of calcium hydroxide (Ca(OH)2) will neutralize one mole of SO2, whereas one mole of 

Ca(OH)2 will neutralize two moles of HCl. A similar reaction occurs with the neutralization of 

HF. These reactions demonstrate that when using a spray dryer, the HCl and HF are removed 

more readily than is the SO2. Given that even more water is available in a wet-FGD system, the 

same condition would also hold in that situation (i.e., in a wet-FGD, HCl and HF would be 

removed more readily than SO2). Thus, we are considering emissions of SO2, a commonly 

measured pollutant, as a potential surrogate for emissions of the acid-gas HAP HCl and HF. 

Although this approach has not been used in any CAA section 112 rules by EPA, it has been 

used in a number of State permitting actions (e.g., Arkansas/Plum Point; Kentucky/Spurlock 3; 

Nebraska/Nebraska City 2; Wisconsin/Elm Road-Oak Creek, and Weston 4). However, should 

emissions of SO2 be deemed inappropriate as a potential surrogate for emissions of the acid-gas 
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HAP, we are also gathering sufficient data on HCl, HF, and HCN to be able to establish 

individual emission limits. 

EPA has identified the 175 units with the newest FGD controls installed. EPA believes 

that these units represent those units having to comply with the most recent, and, therefore, likely 

most stringent, emission limits for SO2. Even though SO2 may not be an adequate surrogate for 

the acid gas HAP, efforts by units to comply with stringent SO2 limits will likely represent the 

top performers with regard to acid gas HAP emissions. The 170 units with the newest FGD 

controls installed would be selected from those identified in Attachment 8 and would be required 

to test the specified unit for HCl, HF, HCN, SO2, O2, CO2, and moisture from the stack gases, 

and chlorine, fluorine, and sulfur content, HHV, and proximate/ultimate analyses of the coal 

being utilized during the test. 

As units have been identified as meeting the criterion of being a “top performing” unit, 

substitution of units will not be permitted. However, for units selected for testing in this group 

that share an FGD system with another unit, testing after the FGD system will be allowed. Units 

not currently listed may be required to test if necessary to ensure that the approved number of 

units in the group actually test and provide the needed data to the Agency. 

This would yield an additional 170 data sets to be added to the data set we currently have 

for these pollutants. 

Coal-fired units, dioxin/furan organic HAP

Dioxin data were obtained in support of the 1998 Utility Report to Congress. However, 

approximately one-half of those data were listed as being below the minimum detection limit for 

the given test. Dioxin/furan emissions from coal-fired utility units are generally considered to be 

low, presumably because of the insufficient amounts of available chlorine. As a result of 

previous work conducted on municipal waste combustors (MWC), it has also been proposed that 

the formation of dioxins and furans in exhaust gases is inhibited by the presence of sulfur.2

 

Further, it has been suggested that if the sulfur-to-chlorine ratio (S:Cl) is greater than 1.0, then 

formation of dioxins/furans is inhibited.3,4 The vast majority of the coal analyses provided 

 

2

 Gullett, B.K., et al. Effect of Cofiring Coal on Formation of Polychlorinated Dibenzo-p-Dioxins and 

Dibenzofurans during Waste Combustion. Environmental Science and Technology. Vol. 34, No. 2:282-290. 2000. 3

 Raghunathan, K., and B,K. Gullett. Role of Sulfur in Reducing PCDD and PCDF Formation. Environmental 

Science and Technology. Vol. 30, No. 6:1827-1834. 1996. 4

 Li., H., et al. Chlorinated Organic Compounds Evolved During the combustion of Blends of Refuse-derived Fuels 

and Coals. Journal of Thermal Analysis. Vol. 49:1417-1422. 1997. 
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through the 1999 ICR indicated S:Cl values greater than 1.0. As a result, EPA expects that 

additional data gathering efforts will continue the trend of data being at or below the minimum 

detection limit. However, EPA believes that some additional data are necessary upon which 

either to base a surrogate standard or to establish an emission limit for dioxin/furan. Therefore, 

50 units have been selected at random from the entire coal-fired EGU population to conduct 

emission testing for dioxins/furans (Attachment 9). In addition, as a result of previous work 

done on MWC units, EPA identified activated carbon as a potential control technology for 

dioxin/furan control. Therefore, the above data set includes some units with activated carbon 

injection (ACI) systems installed. Each of these units would be required to test for 

dioxins/furans, O2, CO2, and moisture from the stack gases, and chlorine and sulfur content, 

HHV, and proximate/ultimate analyses of the coal being utilized during the test. 

EPA would entertain requests to test sister units at the same facility. EPA would also 

entertain requests, within 3 weeks of receipt of the CAA section 114 letter, to test similar units at 

other facilities under the company’s ownership or under an organizational umbrella (e.g., trade 

group) as long as the substituted unit was of similar size and type, utilized a similar coal, and had 

similar emission controls. The subject company would need EPA approval for any substitution. 

Units not currently listed may be required to test if necessary to ensure that the approved number 

of units in the group actually test and provide the needed data to the Agency. 

This would yield an additional 50 data sets to be added to the data set we currently have 

for these pollutants. 

Coal-fired units, non-dioxin/furan organic HAP

Emissions of carbon monoxide (CO), volatile organic compounds (VOC), and/or total 

hydrocarbons (THC) have in the past been used as surrogates for the non-dioxin/furan organic 

HAP based on the theory that efficient combustion leads to lower organic emissions.5

 However, 

although indications are that these emissions are low (and perhaps below the minimum detection 

level), there are very few emissions data available for these compounds from coal-fired utility 

boilers. EPA has identified the 175 newest units as being representative of the most modern, 

and, thus, presumed most efficient, units (Attachment 10). The 170 newest units would be 

selected from those identified in Attachment 10 and would be required to test for CO, VOC, and 

 

5

 U.S. Environmental Protection Agency. NESHAPS: Final Standards for Hazardous Air Pollutants for Hazardous 

Waste Combustors; Final Rule. 64 FR 52828. September 30, 1999. 
6 

THC. From these 170 units, 50 units would be required to test for polycyclic organic matter 

(POM), NOX, formaldehyde, methane, O2, and CO2, in addition to CO, VOC, and THC. All 

tested units would be required to test for moisture from the stack gases and HHV and 

proximate/ultimate analyses of the coal being utilized during the test. 

As units have been identified as meeting the criterion of being a “top performing” unit, 

substitution of units will not be permitted. Companies with units sharing an FGD or PM control 

system will need to contact EPA with the individual boiler’s specifics. Units not currently listed 

may be required to test if necessary to ensure that the approved number of units in the group 

actually test and provide the needed data to the Agency. 

This would yield an additional 170 data sets with data on the potential surrogates CO, 

VOC, and THC as well as 50 data sets on the potential surrogate relationships. 

Coal-fired units, mercury and other non-mercury metallic HAP

Emissions of certain non-mercury metallic HAP (i.e., antimony (Sb), beryllium (Be), 

cadmium (Cd), cobalt (Co), lead (Pb), manganese (Mn), and nickel (Ni)) have been assumed to 

be well controlled by particulate matter (PM) control devices. However, mercury (Hg) and other 

non-mercury metallic HAP (i.e., arsenic (As), chromium (Cr), and selenium (Se)), because of 

their presence in both particulate and vapor phases, have been reported, in some instances, to be 

not well controlled by PM control devices. Also, it has been shown through recent stack testing 

that certain of these HAP (i.e., As, Cr, and Se) tend to condense on (or as) very fine particulate 

matter in the emissions from coal-fired units. There are very few recent emissions test data 

available showing the potential control of these metallic HAP from coal-fired utility boilers. 

The capture of Hg is dependent on several factors including the chloride content of the 

coal, the amount of unburned carbon present in the fly ash, the flue gas temperature, and the 

speciation of the Hg. Based on available data, EPA believes that ACI may be an effective 

control technology for controlling Hg emissions in coal-fired plants. However, EPA has no 

direct stack test results showing how effectively these ACI-equipped plants reduce their Hg 

emissions. 

EPA has identified the 175 units with the newest PM controls installed. EPA believes 

that these units represent those units having to comply with the most recent, and, therefore, likely 

most stringent, emission limits for PM (Attachment 11). Even though PM may not ultimately be 

an adequate surrogate for some of the non-mercury metallic HAP, efforts by units to comply 
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with stringent PM limits will likely represent the top performers with regard to non-mercury 

metallic HAP emissions. The units selected also include a number with ACI installed. As units 

have been identified as meeting the criterion of being a “top performing” unit, substitution of 

units will not be permitted. However, units selected for testing in this group that share a PM 

control system with another unit, testing after the PM control system will be allowed. 

The 170 units with the newest PM controls installed would be selected from those 

identified in Attachment 11 and would be required to test after that specific PM control (or at the 

stack if the PM control device is not shared with one or more other units). Each of these 

170 units would be required to test the unit listed for Sb, As, Be, Cd, Cr, Co, Pb, Mn, Hg, Ni, Se, 

PM (total filterable, fine [dry], fine [wet]), O2, CO2, and moisture. All units would also be 

required to analyze their coal for the metals above (including Hg), chlorine, and provide the 

HHV and proximate/ultimate analyses of the coal being utilized during the test. 

As units have been identified as meeting the criterion of being a “top performing” unit, 

substitution of units will not be permitted. However, units selected for testing in this group that 

share a PM control system with another unit, testing after the PM control system will be allowed. 

Units not currently listed may be required to test if necessary to ensure that the approved number 

of units in the group actually test and provide the needed data to the Agency. 

This would yield an additional 170 data sets to be added to the data set we currently have 

for these pollutants. 

Coal-fired units, other

To be able to assess the impact of the standards (e.g., reduction in HAP emissions over 

current conditions), EPA has selected at random 50 units (identified in Attachment 13) from the 

population of coal-fired units not selected in any of the above groups to test for HCl, HF, HCN, 

SO2, O2, CO2, CO, VOC, THC, POM, NOX, formaldehyde, methane, Sb, As, Be, Cd, Cr, Co, Pb, 

Mn, Hg, Ni, Se, PM (total filterable, fine [dry], fine [wet]), and moisture from the stack gases. 

All of these units would also be required to analyze their coal for the metals above (including 

Hg), chlorine, fluorine, and sulfur content, HHV, and proximate/ultimate analyses of the coal 

being utilized during the test. EPA does not believe that data available through other sources 

(e.g., National Emissions Inventory (NEI), Toxics Release Inventory (TRI), data gathered for the 

1998 Utility Report to Congress) are of sufficient detail or completeness to be appropriate for 

this purpose. Utilities are not currently subject to a CAA section 112(d) standard and, therefore, 
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they are not required to collect HAP data, nor report them to States which then report them to the 

NEI. Further, the TRI data are based on “engineering judgment,” emission factors, or other 

methods of estimation rather than emissions tests. In addition, none of the data sources currently 

contain detailed data for all of the necessary individual HAP. Thus, EPA believes that gathering 

these data is necessary to conduct a credible assessment of the emissions of this important source 

category. 

EPA would entertain requests, within 3 weeks of receipt of the CAA section 114 letter, to 

test sister units at the same facility. EPA would also entertain requests, within 3 weeks of receipt 

of the CAA section 114 letter, to test similar units at other facilities under the company’s 

ownership or under an organizational umbrella (e.g., trade group) as long as the substituted unit 

was of similar size and type, utilized a similar coal, and had similar emission controls. The 

subject company would need EPA approval for any substitution. Units not currently listed may 

be required to test if necessary to ensure that the approved number of units in the group actually 

test and provide the needed data to the Agency. 

This would yield 50 data sets to be added to the data set we currently have for this 

analysis. 

Coal-fired units, IGCC

All IGCC units identified in Attachment 6 will be required to test for HCl, HF, HCN, 

SO2, O2, CO2, CO, VOC, THC, POM, NOX, formaldehyde, methane, dioxins/furans, Sb, As, Be, 

Cd, Cr, Co, Pb, Mn, Hg, Ni, Se, PM (total filterable, fine [dry], fine [wet]), and moisture from 

the stack gases. All of these units would also be required to analyze their coal for the metals 

above (including Hg), chlorine, fluorine, and sulfur content, HHV, and proximate/ultimate 

analyses of the coal being utilized during the test. 

Oil-fired units

The potential surrogacy arguments for coal-fired units are primarily based on compliance 

with recent, stringent emission limits that have generally resulted in the use of add-on control 

technologies, as in the case of the non-mercury metallic HAP (fabric filter or electrostatic 

precipitator) and the acid-gas HAP (FGD). For dioxin/furan organic HAP, the surrogacy 

argument may rely on the S:Cl value of the coal. However, the data obtained in support of the 

1998 Utility Report to Congress and the 2000 Regulatory Determination do not indicate any 

correlation between PM control and emissions of non-mercury metallic HAP from oil-fired units. 
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Further, no oil-fired unit has a FGD system installed, eliminating the potential basis for the use 

of compliance with an SO2 emissions limit that resulted in the installation of an FGD system as a 

surrogate for emissions of the acid-gas HAP from such units. In addition, it is not known if the 

S:Cl value has the same relevance for oil-fired units as it does for coal-fired units. Thus, EPA 

has no basis for determining which oil-fired units may be the “best performers.” Therefore, EPA 

is requiring that 100 units selected at random from the 180 known oil-fired units (Attachment 12) 

test their stack emissions for Sb, As, Be, Cd, Cr, Co, Pb, Mn, Hg, Ni, Se, PM (total filterable, 

fine [dry], fine [wet]), HCl, HF, HCN, SO2, dioxins/furans, CO, VOC, THC, POM, NOX, 

formaldehyde, methane, O2, CO2, and moisture. All units would be required to sample their oil 

for the metals (including Hg), chlorine, fluorine, sulfur, and provide HHV and 

proximate/ultimate analyses of the oil being utilized during the test. 

EPA would entertain requests to test sister units at the same facility. EPA would also 

entertain requests, within 3 weeks of receipt of the CAA section 114 letter, to test similar units at 

other facilities under the company’s ownership or under an organizational umbrella (e.g., trade 

group) as long as the substituted unit was of similar size and type, utilized a similar oil, and had 

similar emission controls. The subject company would need EPA approval for any substitution. 

Units not currently listed may be required to test if necessary to ensure that the approved number 

of units in the group actually test and provide the needed data to the Agency. 

This would yield an additional 100 data sets to be added to the data set we currently have 

for this category of units. 

Petroleum coke-fired units

All petroleum coke-fired units identified in Attachment 7 will be required to test for HCl, 

HF, HCN, SO2, O2, CO2, CO, VOC, THC, POM, NOX, formaldehyde, methane, dioxins/furans, 

Sb, As, Be, Cd, Cr, Co, Pb, Mn, Hg, Ni, Se, PM (total filterable, fine [dry], fine [wet]), and 

moisture from the stack gases. All of these units would also be required to analyze their 

petroleum coke for the metals above (including Hg), chlorine, fluorine, and sulfur content, HHV, 

and proximate/ultimate analyses of the petroleum coke being utilized during the test. 

4. Response Rates 

Since the information will be requested pursuant to the authority of CAA section 114, 

EPA expects that all respondents requested to submit information will do so within the time 

allotted for the information being requested. 
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Attachment 1. 

Draft Questionnaire Content 
Enclosure 1 Form Approved 12/24/2009 

OMB Control No. 2060-0631 

Approval Expires 12/31/2012 

11

ELECTRIC UTILITY STEAM GENERATING UNIT 

HAZARDOUS AIR POLLUTANT EMISSIONS INFORMATION COLLECTION EFFORT 

BURDEN STATEMENT 

Preliminary estimates of the public burden associated with this information collection 

effort indicate a total of 125,098 hours and $75,972,758. This is the estimated burden for 

537 facilities to provide information on their boilers, fuel oil types and/or coal rank, 1,332 units 

to provide hazardous air pollutant (HAP) emissions data and 12 months of fuel analyses, and 

512 units to conduct emissions testing. 

Burden means the total time, effort, or financial resources expended by persons to 

generate, maintain, retain, or disclose or provide information to or for a Federal Agency. This 

includes the time needed to review instructions; develop, acquire, install, and utilize technology 

and systems for the purposes of collecting, validating, and verifying information, processing and 

maintaining information, and disclosing and providing information; adjust the existing ways to 

comply with any previously applicable instructions and requirements; train personnel to be able 

to respond to a collection of information; search data sources; complete and review the collection 

of information; and transmit or otherwise disclose the information. An Agency may not conduct 

or sponsor, and a person is not required to respond to, a collection of information that is sent to 

ten or more persons unless it displays a currently valid Office of Management and Budget 

(OMB) control number. 

GENERAL INSTRUCTIONS 

[NOTE: It is EPA’s intent for the final version of this questionnaire to be in electronic 

format. The final format will include all questions noted herein.] 

Please provide the information requested in the following forms. If you are unable to 

respond to an item as it is stated, please provide any information you believe may be related. 

Use additional copies of the request forms for your response. 

If you believe the disclosure of the information requested would compromise confidential 

business information (CBI) or a trade secret, clearly identify such information as discussed in the 

cover letter. Any information subsequently determined to constitute CBI or a trade secret under 

EPA’s CBI regulations at 40 CFR part 2, subpart B, will be protected pursuant to those 

regulations and, for trade secrets, under 18 U.S.C. 1905. If no claim of confidentiality 
Enclosure 1 Form Approved 12/24/2009 

OMB Control No. 2060-0631 

Approval Expires 12/31/2012 

12

accompanies the information when it is received by EPA, it may be made available to the public 

by EPA without further notice pursuant to EPA regulations at 40 CFR 2.203. Because Clean Air 

Act (CAA) section 114(c) exempts emission data from claims of confidentiality, the emission 

data you provide will be made available to the public notwithstanding any claims of 

confidentiality. A definition of what the EPA considers emissions data is provided in 40 CFR 

2.301(a)(2)(i). 

The following section is to be completed by all facilities: 

 Part I - General Facility Information: once for each facility. A copy of Part I 

should be completed and returned to the address noted below within 90 days of 

receipt. 

The following section is to be completed by all facilities meeting the section 112(a)(8) 

definition of an electric utility steam generating unit: 

 Part II - Fuel Analyses and Emission Data: Additional copies of certain pages 

may be necessary for a complete response. A copy of Part II responses should be 

completed and returned to the address noted below within 90 days of receipt. 

The following section is to be completed by all facilities selected for stack testing: 

 Part III – Emissions Test Data: One emissions test (consisting of three runs). A 

copy of the emissions test report should be completed and returned to the address 

noted below within 6 - 8 months of receipt. Note the discussion in Part III as to 

when in the 6 to 8 month period the tested facilities results must be submitted. 

Detailed instructions for each part follow. 

Questions regarding this information request should be directed to Mr. William Maxwell 

at (919) 541-5430. 

Return this information request and any additional information to: 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Sector Policies and Programs Division 

U.S. EPA Mailroom (D205-01) 

Attention: Peter Tsirigotis, Director 

109 T.W. Alexander Drive 

Research Triangle Park, NC 27711 
Enclosure 1 Form Approved 12/24/2009 

OMB Control No. 2060-0631 

Approval Expires 12/31/2012 

13

 PART I: GENERAL FACILITY INFORMATION 

Process Information

NOTE: If any rank of coal or any grade of oil (including petroleum coke [pet coke]), in any 

amount, is fired, complete Parts I and II and return to the address noted earlier. If NO coal or oil 

is fired, complete only Part I and return to the address noted earlier. 

1. Name of legal owner of facility: ______________________________________________ 

_______________________________________________________________________________ 

_______________________________________________________________________________ 

_______________________________________________________________________________ 

2. Name of legal operator of facility, if different from legal owner: ____________________ 

_______________________________________________________________________________ 

_______________________________________________________________________________ 

3. Address of ____ legal owner or ____ operator: __________________________________ 

_______________________________________________________________________________ 

_______________________________________________________________________________ 

_______________________________________________________________________________ 

4a. Plant Name (as reported on U.S. DOE/EIA Form-860 (2007), “Annual Electric Generator 

Report,” schedule 2, line 1, page 37, question 1) OR Plant Name (as reported on U.S. DOE/EIA 

Form EIA-923 (2008), “Power Plant Operations Report,” schedule 2, page 1, question 1): 

_______________________________________________________________________________ 

_______________________________________________________________________________ 

_______________________________________________________________________________ 

4b. EIA Plant Code (as reported on U.S. DOE/EIA Form-860 (2007), schedule 2, line 1, 

page 37, question 2) OR Plant ID (as reported on U.S. DOE/EIA Form EIA-923 (2008), 

schedule 2, page 1, question 2): ____________________________________________________ 

5. Complete street address of facility (physical location): ____________________________ 

_______________________________________________________________________________ 

_______________________________________________________________________________ 

_______________________________________________________________________________ 

6. Provide mailing address if different: ___________________________________________ 

_______________________________________________________________________________ 
Enclosure 1 Form Approved 12/24/2009 

OMB Control No. 2060-0631 

Approval Expires 12/31/2012 

14

7. Name and title of contact(s) able to answer technical questions about the completed 

survey: ________________________________________________________________________ 

_______________________________________________________________________________ 

8. Contact(s) telephone number(s): ______________________________________________ 

 and e-mail address(es): _____________________________________________________ 

9. Is this facility considered to be owned or operated by a small entity as defined by the 

Regulatory Flexibility Act? ___ Yes ___ No ___ Don’t know 

10. Which of the following fossil fuels or other material(s) are fired in any steam generating 

unit at this facility? 

___ coal ___ oil (including pet coke) ___ natural gas 

___ other (specify in question 14 below) 

11. Which of the following fossil fuels or other material(s) are permitted6

 to be fired in any 

steam generating unit at this facility? 

_____ coal _____ oil (including pet coke) _____ natural gas 

_____ other (specify in question 14 below) 

12. If coal or solid fuel, as described below, derived from a fossil source is fired, indicate 

which rank of coal or solid fuel was utilized during the previous 12 months prior to the receipt of 

this ICR:7,8

__ lignite (% _____) __ subbituminous (% _____) 

__ bituminous (% _____) __ anthracite (% _____) 

__ coal refuse (including gob, culm, and subbituminous-derived coal refuse) (% _____) 

__ synfuel (including, but not limited to, briquettes, pellets, or extrusions which are 

formed by binding materials, or processes that recycle materials) (% _____) 

(please specify the type or form of synfuel used ________________________________) 

__ petroleum coke (% _____) 

13. If oil is fired, indicate which type of oil was utilized during the previous 12 months prior 

to the receipt of this ICR:9

 

6

 “Permitted,” in this context, refers to refers to the fuels that the permit anticipates will be combusted that the 

facility. 

7

 If the boiler is fired by a blend of coal ranks, please specify percentage (separately, on both a mass and on a Btu 

basis) of each coal rank (e.g., 85% subbituminous/15% bituminous). 

8

 In reference to footnote 6, if necessary, a notation can be added to a utilized fuel type that is not listed in the 

operating permit noting the reason the fuel type was combusted (e.g., “the permitting agency allowed this fuel to be 

combusted for special testing and research purposes”). 
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__ distillate (% _____) __ residual or bunker C (% _____) 

__ other (specify ___________) (% _____) 

14a. If “other” was checked in questions 10 or 11 above indicating that any non-fossil fuel or 

other material (including, but not limited to, plastics, treated wood, rubber belting or gaskets, 

whole tires, tire-derived fuel, boiler cleaning solutions, animal wastes, etc.) is either utilized or 

permitted to be used, please indicate below what materials are combusted in the boiler and in 

what quantities (specify whether this quantity is on a weight percentage or heat [Btu] basis). 

Also indicate (yes/no) whether you are permitted10 to burn non-fossil fuel(s) or other material(s) 

even if you do not actually burn them. 

 Other Material Permitted to burn Actually burn Quantity/year 

 ________________ _______________ ______________ ___________ 

 ________________ _______________ ______________ ___________ 

 ________________ _______________ ______________ ___________ 

 ________________ _______________ ______________ ___________ 

 ________________ _______________ ______________ ___________ 

 ________________ _______________ ______________ ___________ 

 ________________ _______________ ______________ ___________ 

14b. If “other” was checked in questions 10 or 11 above indicating that any non-fossil fuel or 

other material (including, but not limited to, plastics, treated wood, rubber belting or gaskets, 

whole tires, tire-derived fuel, boiler cleaning solutions, animal wastes, etc.) is either utilized or 

permitted to be used, were such material to be classified as “solid waste” under the Resource 

Conservation and Recovery Act and, thus, make the utilizing unit subject to CAA section 129, 

would you continue to utilize (i.e., use as a fuel) the material? __ Yes __ No 

Explain: ______________________________________________________________________ 

 9

 If the boiler is fired by a blend of fuel oil ranks, please specify percentage (separately, on both a volume and on a 

Btu basis) of each fuel oil rank (e.g., 85% residual oil/15% distillate). 

10 If necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting the 

reason the fuel type was combusted (e.g., “the permitting agency allowed this fuel to be combusted for special 

testing and research purposes”).
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15. Identification (or designation) of all coal- and oil-fired steam generating units (boilers) (as defined by Cle112(a)(8)) located at this facility. 

Boiler ID11

coal rank or type of oil) 

Original design fuel (i.e. 

Design heat input, 

(MMBtu/hr)12

Present maximum heat 

input, (MMBtu/hr)13

MWe Gross capacity 

summer 

MWe Net capacity 

summer 

efficiency (%, HHV) 

Original design gross 

Present operating gross 

efficiency (%, HHV) 

Design steam pressure 

(psig) 

Operating steam pressure 

(psig) 

Design steam temperature 

(°F) 

temperature (°F) 

Operating steam 

Design steam reheat 

temperature (°F)14

Operating steam reheat 

temperature (°F)15

Fuel16

Hours/year operated17

11 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 

greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator IDOE/EIA Form EIA-923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 

12 Per fuel burned in the boiler. Report this based on higher heating value (HHV). 13 Per fuel burned in the boiler. Report this based on higher heating value (HHV). 14 Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both. 15 Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both. 16 Indicate the fuels utilized for the indicated boiler, and percentages, as indicated in questions 11 - 13. 17 The “ hours/year operated” would be the average of the actual number of hours the unit operated in 1 year based on the last 3 years o18 This can be treated as CBI and can be submitted through the proper CBI procedure if desired. 
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Emission Control Technology16. For each boiler noted in Part I, question 15, provide the following information for each current emission c

installed and operating and/or planned (please designate the order of the emission controls – 1 for first coboiler, 2 for second control following the boiler, etc.): 

Boiler ID19 Type20 NOx control21 SO2 control22 PM control23 

19 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 

greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator IDOE/EIA Form EIA-923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 

20 Examples: tangential-fired; cyclone; wall-fired; circulating fluidized bed (CFB) 21 Examples: low-NOx burners; selective catalytic reduction (SCR); selective non-catalytic reduction (SNCR); over-fire air (OFA). In

control went online or planned operational date for new installation. If this boiler’s control configuration utilizes a SCR, please include 

which the catalyst is manufactured and the type of reductant used in with the SCR (e.g., anhydrous ammonia, aqueous ammonia, urea, oif the catalyst is specifically designed to reduce SO3 formation? 

22 Examples: wet flue gas desulfurization (FGD; any type); dry scrubbing (any type); specify whether calcium- or sodium-based. Incl

control went online or planned operational date for new installation. 

23 Examples: fabric filter; cold-side electrostatic precipitator (ESP); hot-side ESP; cyclone or multiclone; venturi scrubber. Include sp

went online or planned operational date for new installation. 

24 Please indicate systems installed specifically to control any other pollutants (e.g., Hg, SO3, etc.). Examples: activated carbon injecti

ECO®; dry sorbent injection or wet ESP for SO3 control; flue gas conditioning to control opacity (e.g., SO3 injection, ammonia, other); 

control (e.g., bromine; scrubber additives). Include specific date that control went online or planned operational date for new installatio

pollutants controlled by this other technology (e.g., control technology [pollutant controlled]).
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17. For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company coneach HAP-specific (e.g., mercury, hydrogen chloride) control technology that you have either contracted for, are installed for the purpose of participating in a control technology demonstration project25 (e.g., U.S. Department o

consent decree, etc.). 

Boiler Company (vendor) contact information 

ID26

Company (vendor) 

name Name Telephone Address 

25 A control technology demonstration project is defined as a U.S. Government (e.g., U.S. Department of Energy program) sponsored (

project or mandate (e.g., as a result of a consent decree) that adds a HAP control technology to a facility’s unit to demonstrate the techn

performance. 

26 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 

greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator IDOE/EIA Form EIA-923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8).
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18. For the control technologies identified in Part I, question 17, provide the date of actual start-up of the demcontrol is currently operating), the date of expected or projected start-up, the date the demonstration was completcontrol installed (e.g., sorbent and type; pre-combustion boiler chemical additive; combustion boiler chemical adHAP emission reduction or rate (if any), and the coal rank(s) in use or fuel type upon which the demonstration w

specify the format of the target HAP emission reduction or rate (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). target end-point is percent reduction, provide (1) an estimate of what an equivalent emission rate would be (and sthe equivalent emission rate), and (2) the basis for calculating the percent reduction (i.e., where the “inlet” and “o

Boiler 

ID27

Demonstration 

activity actual 

start-up date 

Demonstration 

activity projected 

start-up date 

Demonstration 

activity end-date 

or projected enddate 

Type of control 

(e.g., sorbent and 

type; chemical 

additive28) 

Desired HAP 

emission reductio

(%) or emission 

rate 

27 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 

greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator IDOE/EIA Form EIA-923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 

28 If additive is used, please indicate injection point.
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19. For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company coneach HAP (e.g., mercury, hydrogen chloride, etc.) control technology that you have either contracted for, are inst

installed for the purpose of providing a non-demonstration, full-scale operating system. 

Boiler Company (vendor) contact information 

ID29

Company (vendor) 

name Name Telephone Address 

29 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 

greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator IDOE/EIA Form EIA-923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 
Enclosure 1 F

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20. For the control technologies identified in Part I, question 19, provide the date of actual start-up (if the con

operating), the date of expected or projected start-up, the type of HAP control installed (e.g., sorbent and type; prchemical additive; combustion boiler chemical additive), the guaranteed HAP emission reduction or emission ratrate upon which the guarantee is based, and the coal rank(s) or fuel type upon which the guarantee is based. Pleaof the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the guarantee is percent reduct

estimate of what an equivalent emission rate would be (and specify the format of the equivalent emission rate), a

calculating the percent reduction (i.e., where the “inlet” and “outlet” are). 

Boiler ID30 Actual start-up date Expected or projected start-up date Type of control (e.g., sorbent and type; chemical additive)31 Guaranteed HAP emission reduction (%) or emission rate Sorbent or additive feed rat

on which guarantee is based 

30 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 

greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator IDOE/EIA Form EIA-923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 

31 If additive is used, please indicate injection point.
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21. For each boiler noted in Part I, question 15, provide the following information: 

Permitted emission limit (indicate type of permit and format of emission limit and avera

Boiler 

ID32 PM33 PM10(34) PM2.5(35) SO2

HCl 

and/or 

HF 

HCN Metal HAP36 Hg CO 

o(

32 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 

greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator IDOE/EIA Form EIA-923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 

33 If the boiler has separate permitted emission limits for filterable and condensable PM, respectively, please include those separate lim

compliance test method utilized. 

34 List the compliance test method utilized. 35 List the compliance test method utilized. 36 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium

all metal HAP for which a permit limit is in place.
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22. For each boiler noted in Part I, question 15, provide the following information: 

Most recent guaranteed emission rate for each pollutant for which there is a permitte

Boiler 

ID37 PM38 PM10 PM2.5 SO2

HCl 

and/or 

HF 

HCN Metal HAP39 Hg CO 

23. Was any other guarantee level sought or offered? Yes _____ No _____ Please elaborate. _____________________________________________________________________________________________________________________________________________________________________________________________37 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 

greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator IDOE/EIA Form EIA-923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 

38 If the boiler has separate guaranteed emission rate for filterable and condensable PM, respectively, please include those separate emi39 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium

all metal HAP for which a permit limit is in place.
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24. For each boiler noted in Part I, question 15, provide the following information: 

Required monitoring, recordkeeping, and reporting requirements for each pollutant for 

permitted emission limit 

Boiler ID40

PM41 PM10 PM2.5 SO2

HCl 

and/or 

HF 

HCN Metal HAP42 Hg 

40 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 

greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator IDOE/EIA Form EIA-923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 

41 If the boiler’s monitoring, recordkeeping, and reporting requirements require your company to monitoring, keep records, and report 

PM separately, please describe the separate actions required. 

42 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium

all metal HAP for which a permit limit is in place.
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25. For the control technologies identified in Part I, questions 17 and 19, provide the cost information reques

Facility Name / Unit No.: _________ Retrofit to existing boiler? ____ Installation o

Total Capital Investment: $: ______________ 

Total Annual Operating and Maintenance Costs: $: ______________ (Include base year for operatin

26. Are any other means of emission control (for any pollutant) employed on any boiler noted in Part I, quest

coal, coal or oil with low trace constituents, etc.)? Please specify. ____________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________

43 This can be treated as CBI and can be submitted through the proper CBI procedure if desired. 
Enclosure 1 Form Approved 12/24/2009 

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 PART II: FUEL ANALYSIS AND EMISSION DATA 

Fuel Analysis44

Each facility should provide the following information for each coal and oil shipment received 

during the preceding 12 calendar months. 

1a. Plant or facility name from Part I, question 4a: __________________________________ 

_______________________________________________________________________________ 

_______________________________________________________________________________ 

1b. Plant or facility code from Part I, question 4b: ___________________________________ 

 

44 The respondent should reply to this ICR with separate pages 18 through 24 (Part II) for each of their facilities. 
Enclosure 1 Form Approved 12/24/2009 

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2. For each individual coal and oil shipment received during the preceding 12 calendar 

months, provide the following information, as available (indicate N/A if not available; use 

additional pages, as necessary): 

Fuel source Amount 

received, 

dry basis, 

short tons45

ID # of 

boiler(s) 

firing 

fuel46 State/Country County47 Coal seam48

Fuel shipment 

method 

 

 

45 EPA recognizes that facilities have (sometimes) several months inventory and that the amount received is not 

necessarily the same as the amount fired. 

46 Boiler ID (as reported on U.S. DOE/EIA Form EIA-860 (2007), “Annual Electric Generator Report,” schedule 6, 

part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, 

line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA-923 

(2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 

47 If known. 

48 If known.
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3. For each individual coal and oil shipment received during the preceding 12 calendar months, provide the information49, as available (dry basis) (indicate N/A if not available): 

Sample ID # 

Total 

amount of 

fuel 

represented 

by sample, 

tons or 

gallons 

Total 

sulfur, % 

Ash 

content, 

% 

Higher 

heating 

value, 

Btu/lb 

Mercury, 

ppm 

Chlorine, 

ppm 

Fluorine, 

ppm 

N

49 To the extent that a vendor provides these data or that a facility is required by State or local agency to analyze its fuel for HAP consti

any metallic HAP (e.g., Hg, Pb, As, Se, etc.), EPA wishes the responding facility to provide those fuel analyses results. Otherwise, this 

requirement can be bypassed by the respondent. 

50 Metal HAP includes compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium
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4. Were the data provided in Part II, question 3 above, acquired pursuant to: 

__ permit requirements 

__ contractual obligations 

__ standard operational procedures 

__ other (please specify ____________________) 

5. Analyses provided in Part II, question 3 above, supplied by 

 __ Fuel supplier (name and address) ______________________________________ 

 _________________________________________________________________ 

 __ Other (name and address) ____________________________________________ 

 __________________________________________________________________ 

6. Name and address of laboratory performing analyses: ____________________________ 

______________________________________________________________________________

______________________________________________________________________________ 

7. In addition to the analyses required in Part II, question 3 above, for samples for which 

analyses of chlorine and/or any of the HAP metals were conducted, please provide copies of any 

analyses conducted over the preceding 12 calendar months for (a) complete proximate and 

ultimate analyses, (b) additional trace metals, and (c) the mineralogy of the ash that are readily 

available for the oil(s) or coal(s) listed in Part II, question 2 above. The Agency is requesting 

these data only as they may already be available; no additional sampling or analyses are required 

to provide these data. 
Enclosure 1 Form Approved 12/24/2009 

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Emission Data

8a. What emission test report(s), parametric monitoring data, and other data or monitoring 

are available for the boilers noted in Part I, question 15, for tests conducted since January 1, 

2005. Please consider reports prepared for all testing and monitoring programs, for all 

pollutants, including (but not limited to) those required under Title V, compliance with State or 

local requirements, fulfillment of contractual obligations, U.S. Department of Energy (DOE) 

programs, etc. (NOTE: EPA is not requesting copies of the test reports or data at this time; 

however we may request actual copies in the future.) Use additional pages as necessary. 

______________________________________________________________________________ 

______________________________________________________________________________ 

______________________________________________________________________________ 

______________________________________________________________________________ 

8b. Please indicate the date(s) and types (e.g., stack, fuel, parametric, etc.) of the test(s) and 

the constituents (including criteria and hazardous air pollutants) sampled for. 

 Date: _____ Type: _____ Constituents: ____________________________________ 

 Date: _____ Type: _____ Constituents: ____________________________________ 

 Date: _____ Type: _____ Constituents: ____________________________________ 

 Date: _____ Type: _____ Constituents: ____________________________________ 

 Date: _____ Type: _____ Constituents: ____________________________________ 

 Date: _____ Type: _____ Constituents: ____________________________________ 

 Date: _____ Type: _____ Constituents: ____________________________________ 

 Date: _____ Type: _____ Constituents: ____________________________________ 

 Date: _____ Type: _____ Constituents: ____________________________________ 

8c. Do any of these test reports reflect testing at a location upstream of any emission control 

devices? 

Yes _____ No _____ If yes, please note which reports and provide a detailed description 

of the location of the emissions sampling point(s). ____________________________________ 
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8d. Were any of these test reports conducted when use of other material(s) or non-fossil fuels 

were fired in the boiler? Yes _____ No _____ If yes, please note which reports and 

identify the other material(s) or non-fossil fuels used. _________________________________ 

______________________________________________________________________________ 

______________________________________________________________________________ 

8e. Do any of these test reports reflect testing during periods of startup, shutdown, and 

malfunction? Yes _____ No _____ If yes, please note which reports. ________________ 

______________________________________________________________________________ 

______________________________________________________________________________ 

8f. Did the unit’s control configuration differ from that shown in Part I, question 16, at the 

time of these test results? Yes _____ No _____ If yes, please list the unit’s complete 

control configuration at time of testing in a similar format to Part I, question 16. _____________ 

______________________________________________________________________________ 

______________________________________________________________________________ 

8g. Do any of these test reports reflect testing at a location upstream of a post combustion 

SO2 emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes _____ No _____ If 

yes, please note which reports and, in addition to the detailed description of the location of the 

sampling point(s) (question 8c above), include detail about how much, if any, bypass of 

unscrubbed flue gas was utilized at the time of testing (including percentage of total scrubber 

exhaust gas flow). Note by diagram where sampling ports were located in relation to the bypass 

ductwork. ______________________________________________________________________ 

_______________________________________________________________________________ 

9. What type of deviation reporting is required for violations of permit requirements? 

______________________________________________________________________________ 

______________________________________________________________________________ 

10. Are deviation reports available for malfunctions or other periods of noncompliance with 

permit terms and conditions? Yes _____ No _____ If yes, please note which reports. 

______________________________________________________________________________ 

______________________________________________________________________________ 
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11. Are continuous emissions monitoring system (CEMS) data available (e.g., mercury, 

continuous opacity monitoring systems) that are not already being provided to the U.S. EPA or 

permit authority, even if from short-term testing? Yes _____ No _____ If yes51, please 

note for which pollutants CEMS data are available and the period of time (both total period and 

calendar period) for which data are available. If CEMS data are being provided to EPA, please 

note to which Office the data are being provided. _____________________________________ 

_____________________________________________________________________________ 

12. For each boiler noted in Part I, question 15, provide the following information: 

Emissions test results (indicate format of emission data)52,53 

Boiler 

ID Date 

of test PM54 SO2 HCl/HF/HCN Metal 

HAP55 Hg56 CO 

Other 

organics 

(specify) 

 

 

51 Where units are monitored by CEMS (either following CAMR, State, or NIST QA/QC procedures), and where 

data are available, EPA requests that these CEMS data be submitted by the respondent. The respondent should also 

mark the periods of start up, shut down and malfunction events (SSM) in the data sets. 

52 Provide emission test data for all tests conducted since January 1, 2005. Please include test data acquired both 

before and after any control device. Use additional pages as necessary. EPA may, at some future date, request a 

copy of one or more emission test reports. Data generated to fulfill both Federal and State requirements must be 

provided. Note that data generated pursuant to CAA Title V must be maintained and available for 5 years. Also 

include averaging times and measurement units for all pollutants. 53 For each emissions test run the respondent should provide the following process information: Unit Load (MW), 

Net generation during run (MWh net), Flue gas moisture content (%), Flue gas flow rate (dscfm or Nm3

/hr), Flue 

gas oxygen content (%, dry), Flue gas carbon dioxide content (%, dry), Flue gas temperature at sampling point (°F), 

Flue gas pressure at sampling point (atm), Standard temperature (°F), Standard pressure (atm). 

54 If emission testing recorded the emissions of filterable and condensable PM, separately, please include those 

separate emission results. Also, please include separate emission results for total PM, PM10, and PM2.5. 55 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, 

nickel and selenium; indicate emission level for all metal HAP for which an emission test has been conducted. 

56 Please provide separate results for total Hg, elemental Hg, oxidized Hg, and particulate Hg, as available. If the 

emissions testing recorded the amount of unburned carbon in fly ash (as reflected by the “Loss on Ignition” [L.O.I.]) 

at the time of any Hg testing, please include these data.
Enclosure 1 Form Approved 12/24/2009 

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PART III: EMISSIONS TESTING 

For units identified in Part B of the Supporting Statement, testing is to be performed for 

the identified HAP on a one-time basis after the last control device (i.e., after the last control 

device or at the stack if the last control device is not shared with one or more other units). 

Facilities are to use the test procedures noted in Enclosure 1 (“Summary of Coal- and Oil-fired 

Electric Utility Steam Generating Unit Test Procedures, Methods, and Reporting Requirements”) 

for both the stack and fuel sampling. Each test is to consist of at least three separate runs for 

each pollutant at the sampling location. 

Companies with multiple units identified on the Attachments to Part B of the Supporting 

Statement will be required to notify EPA within 3 weeks of receipt of the CAA section 114 letter 

which units representing 60 percent of their required data will be submitted within 6 months of 

receipt of the letter and which units representing an additional 20 percent of their required data 

(i.e., a total of 80 percent of their required data) will be submitted within 7 months of receipt of 

the letter. Companies will also be notified of this requirement in the cover letter specifying the 

test requirements. 
Enclosure 1 Form Approved 12/24/2009 

OMB Control No. 2060-0631 

Approval Expires 12/31/2012 

34

Summary of Coal- and Oil-fired Electric Utility Steam Generating 

Unit Test Procedures, Methods, and Reporting Requirements 

This document provides an overview of approved methods, target pollutant units of measure, and 

reporting requirements for the coal- and oil-fired electric utility steam generating unit test plan. 

The document is organized as follows: 

1.0 Stack Testing Procedures and Methods 

2.0 Fuel Analysis Procedures and Methods 

3.0 How to Report Data 

4.0 How to Submit Data 

5.0 Definitions 

6.0 Contact Information for Questions on Test Plan and Reporting 

1.0 Stack Testing Procedures and Methods 

The EPA coal- and oil-fired electric utility steam generating unit test program includes stack test 

data requests for several pollutants, including specific hazardous air pollutants (HAP) and 

potential surrogate groups. If you operate a coal- or oil-fired electric utility steam generating 

unit, you were selected to perform a stack test for some combination of the following pollutants 

or potential surrogate groups (i.e., simultaneous or overlapping measurements per group): 

 Non-dioxin/furan organic HAP: Carbon monoxide (CO), total hydrocarbons (THC), 

methane (CH4), formaldehyde, oxygen (O2), carbon dioxide (CO2), volatile and semivolatile organic HAP 

 Dioxin/furan: dioxins/furans (D/F), O2, CO2

 Acid gas HAP: hydrogen chloride (HCl), hydrogen fluoride (HF), hydrogen cyanide 

(HCN), oxides of nitrogen (NOx), sulfur dioxide (SO2), O2, CO2

 Mercury and non-mercury metallic HAP: mercury (Hg), non-Hg HAP metals (including 

antimony (Sb), arsenic (As), beryllium (Be), cadmium (Cd), chromium (Cr), cobalt (Co), 

lead (Pb), manganese (Mn), nickel (Ni), and selenium (Se)), particulate matter (PM2.5

(filterable and condensable); total solids; O2, CO2

Refer to Table 2 of the section 114 letter you received for the specific combustion unit and 

pollutants on which we are requesting that you perform emission tests. You may have submitted 

test data for some of these pollutants already. 

1.1 How to Select Sample Location and Gas Composition Analysis Methods 

U.S. EPA Method 1 of Appendix A of Part 60 must be used to select the locations and number of 

traverse points for sampling. See http://www.epa.gov/ttn/emc/methods/method1.html for a copy 

of the method and guidance information. 
Enclosure 1 Form Approved 12/24/2009 

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Analysis of flue gas composition, including oxygen concentration, must be performed using U.S. 

EPA Methods 3A or 3B of Appendix A of Part 60. See 

http://www.epa.gov/ttn/emc/methods/method3a.html for Method 3A or 

http://www.epa.gov/ttn/emc/methods/method3b.html for Method 3B information. 

1.2 Coal- and Oil-fired Electric Utility Steam Generating Unit Test Methods and Reporting 

Table 1.2 presents a summary of the recommended test methods for each pollutant and possible 

alternative methods. If you would like to use a method not on this list, and the list does not meet 

the definition of “equivalent” provided in the definitions section of this document, please contact 

EPA for approval of an alternative method. 

For copies of the recommended U.S. EPA methods and additional information, please refer to 

EPA’s Emission Measurement Center website: http://www.epa.gov/ttn/emc/. For copies of the 

US EPA’s SW-846 sampling and analysis methods (such as EPA Method 0010 and EPA Method 

8270D), please refer to EPA’s SW-846 Online website, which is available at the following 

internet address: <http://www.epa.gov/waste/hazard/testmethods/sw846/online/index.htm>. 

Report pollutant emission data as specified in Tables 1.2a through 1.2d below. Each test should 

be comprised of at least three valid test runs. All pollutant concentrations should be corrected to 

7 percent oxygen (or as otherwise directed by a specific method) and should be reported on the 

same moisture basis (dry). Report the results of the stack tests according to the instructions in 

Section 3.0 of this enclosure. During a 30 day period that includes emissions testing and fuel 

analysis reporting, you should collect the following process information: Total heat input; feed 

rate; steam output; gross electric output; net electric output; emissions control devices in use 

during the test; control device operating or monitoring parameters (including, as appropriate to 

the control device, flue gas flow rate, pressure drop, scrubber liquor pH, scrubber liquor flow 

rate, sorbent type and sorbent injection rate), and process parameters (such as oxygen). In 

addition to the emission test data, you should report the above process information as daily 

averages. 

The owner/operator of the EGU must certify that the fuel that was fired during testing is 

representative of the fuel that is burned routinely at the EGU. The owner/operator of the EGU 

must also certify that it operated all of the pollution control equipment in accordance with 

manufacturers’ specifications and requirements for proper operation during the emissions testing. 

Finally, the owner/operator of the EGU must certify that it operated its pollution control 

equipment to optimize reduction of the pollutants for which the equipment is designed. 
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Table 1.2a: Summary of Coal- and Oil-fired Electric Utility Steam Generating Unit Test Methods 

and Alternative Methods for Non-dioxin / furan organic HAP 

Pollutant Recommended Method Alternative Method Target Reported 

Units of Measure 

CO U.S. EPA Method 10, 10A, or 

10B. Collect a minimum volume 

of 1.7 cubic meters and have a 

minimum sample time of 2 hours 

per run. 

None lb/MMBtu and 

ppmvd @ 7% O2

Formaldehyde U.S. EPA Method 320. Use a 

minimum test run time of 2 

hours. 

RCRA Method 0011. Collect a 

minimum volume of 1.7 cubic 

meters and have a minimum 

sample time of 2 hours per run. 

lb/MMBtu and 

ppmvd @ 7% O2

THC U.S. EPA Method 25A. Use a 

minimum sampling time of 2 

hours per run. Calibrate the 

measuring instrument with a 

mixture of the organic 

compounds being emitted or with 

propane, and report as propane. 

None lb/MMBtu and 

ppmvd @ 7% O2 

CH4 U.S. EPA Method 18. Use a 

minimum sample time of 2 hours 

per run. 

U.S. EPA Method 320. lb/MMBtu and 

ppmvd @ 7% O2 

Speciated Volatile 

Organic HAP 

U.S. EPA Method 0031with SW846 Method 8260B. Collect a 

minimum of 4 sets of sorbent 

traps for analysis per each 2 hour 

run. Each set of sorbent traps 

should be run for 20 minutes at 

an approximate flow rate of one 

liter per minute. 

None lb/MMBtu and 

μg/dscm @ 7% O2 

Speciated Semivolatile Organic 

HAP 

U.S. EPA Method 0010 with 

SW-846 Method 8270D. Collect 

a minimum volume of 1.7 cubic 

meters and have a minimum 

sample time of 2 hours per run. 

Use high resolution GCMS for 

the analytical finish. 

None lb/MMBtu and 

μg/dscm @ 7% O2 

SO2

*** U.S. EPA Method 6C U.S. EPA Method 6 lb/MMBtu and 

ppmvd @ 7% O2

O2/CO2

*** U.S. EPA Method 3A U.S. EPA Method 3B % 

Moisture U.S. EPA Method 4 None % 

***If a combustion unit has CEMS installed for CO, NOx and/or SO2, the unit can report daily averages from 

30 days of CEMS data in lieu of conducting a CO, NOx and/or SO2 stack test. In order to correlate these emissions 

with other stack test emissions, a portion of the CEMS data should contain emissions data collected during 

performance of the other requested stack tests. The CEMS must meet the requirements of the applicable 

Performance Specification: CO – Performance Specification 4; NOx and SO2 – Performance Specification 2 and 40 

CFR part 60.13 or the CEMS accuracy and ongoing QA/QC requirements of 40 CFR part 75. 
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Table 1.2b: Summary of Coal- and Oil-fired Electric Utility Steam Generating Unit Test Methods 

and Alternative Methods for Dioxin / furan HAP 

Pollutant Recommended Method Alternative Method Target Reported 

Units of Measure 

D/F, PCB** U.S. EPA Method 23. Collect a 

minimum volume of 8.5 cubic 

meters and have a minimum 

sample time of 8 hours per run. 

Use high resolution GCMS for 

the analytical finish. 

None lb/MMBtu and 

ng/dscm @ 7% O2 

O2/CO2

*** U.S. EPA Method 3A U.S. EPA Method 3B % 

Moisture U.S. EPA Method 4 None % 

**Just the 12 “dioxin-like” PCB congeners (IUPAC Numbers PCB-77, -81, -105, -114, -118, -123, -126, -156, -157, 

-167, -169, and -189) 

***If a combustion unit has CEMS installed for CO, NOx and/or SO2, the unit can report daily averages from 

30 days of CEMS data in lieu of conducting a CO, NOx and/or SO2 stack test. In order to correlate these emissions 

with other stack test emissions, a portion of the CEMS data should contain emissions data collected during 

performance of the other requested stack tests. The CEMS must meet the requirements of the applicable 

Performance Specification: CO – Performance Specification 4; NOx and SO2 – Performance Specification 2 and 40 

CFR part 60.13 or the CEMS accuracy and ongoing QA/QC requirements of 40 CFR part 75. 

Table 1.2c: Summary of Coal- and Oil-fired Electric Utility Steam Generating Unit Test Methods 

and Alternative Methods for Acid gas HAP 

Pollutant Recommended Method Alternative Method Target Reported 

Units of Measure 

HCl and HF U.S. EPA Method 26A. Collect a 

minimum volume of 2.5 cubic 

meters and have a minimum 

sample time of 3 hours per run. 

U.S. EPA Method 26 or U.S . EPA 

Method 320 if there are no entrained 

water droplets in the sample. 

lb/MMBtu 

HCN U.S. EPA Conditional Test 

Method 033 (CTM-033) 

U.S. EPA Method 26A combined with 

the analysis procedures from CTM033, or U.S. EPA Method 26 

combined with the analysis procedures 

from CTM-033 or U.S. EPA Method 

320 if there are no entrained water 

droplets in the sample. 

lb/MMBtu 

NOx

*** U.S. EPA Method 7E U.S. EPA Method 7, 7A, 7B, 7C, or 

7D 

lb/MMBtu and 

ppmvd @ 7% O2

SO2

*** U.S. EPA Method 6C U.S. EPA Method 6 lb/MMBtu and 

ppmvd @ 7% O2

O2/CO2

*** U.S. EPA Method 3A U.S. EPA Method 3B % 

Moisture U.S. EPA Method 4 None % 

***If a combustion unit has CEMS installed for CO, NOx and/or SO2, the unit can report daily averages from 

30 days of CEMS data in lieu of conducting a CO, NOx and/or SO2 stack test. In order to correlate these emissions 

with other stack test emissions, a portion of the CEMS data should contain emissions data collected during 

performance of the other requested stack tests. The CEMS must meet the requirements of the applicable 

Performance Specification: CO – Performance Specification 4; NOx and SO2 – Performance Specification 2 and 40 

CFR part 60.13 or the CEMS accuracy and ongoing QA/QC requirements of 40 CFR part 75. 
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Table 1.2d: Summary of Coal- and Oil-fired Electric Utility Steam Generating Unit Test Methods 

and Alternative Methods for Mercury and Non-mercury metallic HAP 

Pollutant Recommended Method Alternative 

Method 

Target 

Reported 

Units of 

Measure 

Hg U.S. EPA Method 30B. Use a minimum sample 

time of 2 hours per run. 

None lb/MMBtu 

Metals U.S. EPA Method 29. Collect a minimum 

volume of 3.4 cubic meters and have a minimum 

sample time of 4 hours per run. Determine total 

filterable PM emissions according to §8.3.1.1. 

Use ICAP/MS for the analytical finish. 

None lb/MMBtu 

PM2.5 (filterable) from 

stacks without 

entrained water 

droplets (e.g., not from 

units with wet 

scrubbers) 

U.S. EPA Other Test Method 27 (OTM 27). 

Include cyclone catch as filterable PM. Collect a 

minimum volume of 3.4 cubic meters and have a 

minimum sample time of 4 hours per run. 

None lb/MMBtu 

PM2.5 (filterable) from 

stacks with entrained 

water droplets 

AND 

Total Dissolved Solids 

(TDS) and Total 

Suspended Solids 

(TSS) from wet 

scrubber recirculation 

liquid 

U.S. EPA Method 5 with a filter temperature of 

320°F +/- 25°F. Collect a minimum volume of 

3.4 cubic meters and have a minimum sample 

time of 4 hours per run. 

AND 

ASTM D5907 

For TDS and TSS, 

Standard Methods 

of the Examination 

of Water and 

Wastewater Method 

2540B for solids in 

scrubber 

recirculation liquid 

lb/MMBtu for 

PM; 

AND 

mg solids liter 

of scrubber 

recirculation 

liquid*

PM2.5 (condensable) U.S. EPA Other Test Method 28 (OTM 28). 

Collect a minimum volume of 3.4 cubic meters 

and have a minimum sample time of 4 hours per 

run. 

None lb/MMBtu 

O2/CO2

** U.S. EPA Method 3A U.S. EPA Method 

3B 

% 

Moisture U.S. EPA Method 4 None % 

*Also report scrubber recirculation liquid flow rate in liters/min and fuel feed rate in MMBTU/hr. 

**If a combustion unit has CEMS installed for CO, NOx and/or SO2, the unit can report daily averages from 30 days 

of CEMS data in lieu of conducting a CO, NOx and/or SO2 stack test. In order to correlate these emissions with other 

stack test emissions, a portion of the CEMS data should contain emissions data collected during performance of the 

other requested stack tests. The CEMS must meet the requirements of the applicable Performance Specification: 

CO – Performance Specification 4; NOx and SO2 – Performance Specification 2 and 40 CFR part 60.13 or the 

CEMS accuracy and ongoing QA/QC requirements of 40 CFR part 75. 
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2.0 Fuel Analysis Procedures and Methods 

The EPA coal- and oil-fired electric utility steam generating unit test program is requesting fuel 

variability data for fuel-based HAP. The fuel analyses requested include: mercury, chlorine, 

fluorine, and metals (e.g., antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, 

manganese, nickel, and selenium) for any coal- and oil-fired electric utility steam generating unit 

that is selected to conduct a stack test. 

You will need to collect at least three samples of the fuel combusted during each metals, 

mercury, particulate matter, acid gas, and dioxin / furan emissions test run; composite these 

samples; and then analyze and report each composited sample. Only chlorine and fluorine 

analyses are required during acid gas emissions testing. Should you have an oil-fired unit that is 

subject to emissions testing and that is fed from just one fuel tank whose content is uniform and 

is sufficient to complete the emissions testing campaign, you may contact us with a request to 

reduce fuel sampling requirements. Your request should identify the characteristics of your site, 

your proposed alternative fuel sampling procedure, and anticipated impact on emissions of using 

your proposed approach. 

Refer to page 1 of the Section 114 letter you received for the specific types of fuel analyses we 

are requesting from your facility. Directions for collecting, compositing, preparing, and 

analyzing fuel analysis data are outlined in Sections 2.1 through 2.4. 

2.1 How to Collect a Fuel Sample 

Table 2.1 outlines a summary of how samples should be collected. Alternately, you may use the 

procedures in ASTM D2234–00 (for coal) to collect the sample. 
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Table 2.1: Summary of Sample Collection Procedures 

Sampling Location Sampling Procedures Sample Collection Timing 

Solid Fuels 

Belt or Screw Feeder Stop the belt and withdraw a 6- inch wide sample 

from the full cross-section of the stopped belt to 

obtain a minimum two pounds of sample. Collect 

all the material (fines and coarse) in the full crosssection. 

Transfer the sample to a clean plastic bag for 

further processing as specified in Sections 2.2 

through 2.5 of this document. 

Each composite sample will consist 

of a minimum of three samples 

collected at approximately equal 

intervals during the testing period. 

Fuel Pile or Truck For each composite sample, select a minimum of 

five sampling locations uniformly spaced over the 

surface of the pile. 

At each sampling site, dig into the pile to a depth 

of 18 inches. Insert a clean flat square shovel into 

the hole and withdraw a sample, making sure that 

large pieces do not fall off during sampling. 

Transfer all samples to a clean plastic bag for 

further processing as specified in Sections 2.2 

through 2.5 of this document. 

Liquid Fuels 

Manual Sampling Follow collection methods outlined in ASTM D 

4057 

Automatic Sampling Follow collection methods outlined in ASTM 

D4177 

Fuel Supplier Analysis 

Fuel Supplier If you will be using fuel analysis from a fuel 

supplier in lieu of site specific sampling and 

analysis, the fuel supplier must collect the sample 

as specified above and prepare the sample 

according to methods specified in Sections 2.2 

through 2.5 of this document. 

2.2 Create a Composite Sample for Solid Fuels 

Follow the seven steps listed below to composite each sample: 

(1) Thoroughly mix and pour the entire composite sample over a clean plastic sheet. 

(2) Break sample pieces larger than 3 inches into smaller sizes. 

(3) Make a pie shape with the entire composite sample and subdivide it into four equal parts. 

(4) Separate one of the quarter samples as the first subset. 

(5) If this subset is too large for grinding, repeat step 3 with the quarter sample and obtain a 

one-quarter subset from this sample. 

(6) Grind the sample in a mill according to ASTM E829-94, or for selenium sampling 

according to SW-846-7740. 

(7) Use the procedure in step 3 of this section to obtain a one quarter subsample for analysis. If 

the quarter sample is too large, subdivide it further using step 3. 
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2.3 Prepare Sample for Analysis 

Use the methods listed in Table 2.2 to prepare your composite samples for analysis. 

Table 2.2: Methods for Preparing Composite Samples 

Fuel Type Method 

Solid SW-846-3050B or EPA 3050 for total selected metal 

preparation 

Liquid SW-846-3020A or any SW-846 sample digestion procedures 

giving measures of total metal 

Coal ASTM D2013-04 

Biomass ASTM D5198-92 (2003) or equivalent, EPA 3050, or TAPPI 

T266 for total selected metal preparation 

2.4 Analyzing Fuel Sample 

Table 2.3 outlines a list of approved methods for analyzing fuel samplings. If you would like to 

use a method not on this list, and the list does not meet the definition of “equivalent” provided in 

Section 5 of this document, please contact EPA for approval of an alternative method. 

Table 2.3: List of Analytical Methods for Fuel Analysis 

Analyte Fuel Type Method Target Reported 

Units of Measure 

Coal ASTM D5865–04, ASTM D240, ASTM 

E711-87 (1996) 

Biomass ASTM E711–87 (1996) or equivalent, 

ASTM D240, or ASTM D5865-04 

Other Solids ASTM-5865-03a, ASTM D240, ASTM 

E711-87 (1997) 

Higher Heating Value 

Liquid ASTM-5865-03a, ASTM D240, ASTM 

E711-87 (1996) 

Btu/lb 

Moisture Coal, Biomass, Other 

Solids 

ASTM-D3 173-03, ASTM E871-82 

(1998) or equivalent, EPA 160.3 Mod., 

or ASTM D2691-95 for coal. 

% 

Coal 

ASTM D6722-01, EPA Method 1631E, 

SW-846-1631, EPA 821-R-01-013, or 

equivalent 

Biomass 

SW-846-7471A, EPA Method 1631E, 

SW-846-1631, ASTM D6722-01, EPA 

821-R-01-013, or equivalent 

Other Solids 

SW-846-7471A, EPA Method 1631E, 

SW-846-1631, EPA 821-R-01-013, or 

equivalent 

Mercury Concentration 

Liquid 

SW-846-7470A, EPA Method 1631E, 

SW-846-1631E, SW-846-1631, EPA 

821-R-01-013, or equivalent 

ppm 
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Analyte Fuel Type Method Target Reported 

Units of Measure 

Coal 

SW-846-6010B, ASTM D3683-94 

(2000), SW-846-6020, -6020A or ASTM 

D6357-04 (for arsenic, beryllium, 

cadmium, chromium, lead, manganese, 

and nickel in coal) 

ASTM D4606-03 or SW-846-7740 (for 

Se) 

SW-846-7060 or 7060A (for As) 

Biomass 

SW-846-6010B, ASTM D6357-04, SW846-6020, -6020A, EPA 200.8, or ASTM 

E885-88 (1996) or equivalent, SW-846-

7740 (for Se) 

SW-846-7060 or -7060A (for As) 

Other Solids SW-846-6010B, EPA 200.8 

SW-846-7060 or 7060A for As 

Total Selected Metals 

Concentration 

Liquid 

SW-846-6020, -6020A, , SW-846-

6010B, SW-846-7740 for Se, SW-846-

7060 or -7060A for As 

ppm 

Coal 

SW-846-9250 or ASTM D6721-01 or 

equivalent, SW-846-5050, -9056, -9076, 

Chlorine Concentration or -9250, ASTM E776-87 (1996) 

Biomass, Other Solids, 

Liquids 

ASTM E776-87 (1996), SW-846-9250, 

SW-846-5050, -9056, -9076, or -9250 

ppm 

Fluorine Concentration Coal ASTM D3761-96(2002), D5987-96 (2002) ppm 

Report the results of your fuel analysis according to the directions provided in section 3.0 of this 

enclosure. 
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3.0 How to Report Data 

The method for reporting the results of any testing and monitoring requests depend on the type of 

tests and the type of methods used to complete the test requirements. This section discusses the 

requirements for reporting the data. 

3.1 Reporting stack test data 

If you conducted a stack test using one of the methods listed in Table 3.1, shown below, you 

must report your data using the EPA Electronic Reporting Tool (ERT) Version 3. ERT is a 

Microsoft® Access database application. Two versions of the ERT application are available. If 

you are not a registered owner of Microsoft® Access, you can install the runtime version of the 

ERT Application. Both versions of the ERT are available at 

http://www.epa.gov/ttn/chief/ert/ert_tool.html. The ERT supports an Excel spreadsheet 

application (which is included in the files downloaded with the ERT) to document the collection 

of the field sampling data. After completing the ERT, you will also need to attach an electronic 

copy of the emission test report (PDF format preferred) to the Attachments module of the ERT. 

Table 3.1: List of Test Methods Supported by ERT 

Test Methods Supported by ERT 

Methods 1 through 4 

Method 7E 

Method 6C 

Method 5 

Method 3A 

Method 29 

Method 26A 

Method 25A 

Method 23 

Method 202 

Method 201A 

Method 17 

Method 101A 

Method 101 

Method 10 

CT Method 40 

CT Method 39 

OTM 27 

OTM 28 

If you conducted a stack test using a method not currently supported by the ERT, you must 

report the results of this test in a Microsoft® Excel Emission Test Template. The Excel templates 

are specific to each pollutant and type of unit and they can be downloaded from the Electric 

Utility MACT ICR 2009 website (http://utilitymacticr.rti.org). You must report the results of 
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each test on the appropriately labeled worksheet corresponding to the specific tests requested at 

your combustion unit. If more than one unit at your facility conducted a stack test using methods 

not currently supported by the ERT, you must make a copy of the worksheet and update the 

combustor ID in order to distinguish between each separate test. After completing the 

worksheet, you must also submit an electronic copy of the emission test report (PDF format 

preferred). 

If you have CO CEMS that meets performance specification-4 or a SO2 and/or NOx CEMS that 

meets performance specification-2 and 40 CFR part 60.13 or the CEMS accuracy and ongoing 

QA/QC requirements of 40 CFR part 75 installed at your combustion unit, and you used CEMS 

data to meet CO, SO2 and/or NOx test requirements at your facility, you must report daily 

averages from 30 days of CEMS data in a Microsoft® Excel CEMS Template. The Excel 

templates are specific to each pollutant and type of unit and they can be downloaded from the 

Electric Utility MACT ICR 2009 website (http://utilitymacticr.rti.org). 

3.2.1 Reporting measured values below the detection level 

Identify the status of measured values relative to detection levels on the spreadsheet or in the 

ERT using the following descriptions: 

 BDL (below detection level) – all analytical values used to calculate and report an instack emissions value are less than the laboratory’s reported detection level(s); 

 DLL (detection level limited) – at least one but not all values used to calculate and report 

an in-stack emissions value are less than the laboratory’s reported detection level(s); or 

 ADL (above detection level) – all analytical values used to calculate and report an instack emissions value are greater than the laboratory’s reported detection level(s). 

For each reported emissions value, insert the appropriate flag (BDL, DLL, or ADL) in the Note 

line of Excel emission test spreadsheet template or in the Comments line of the Electronic 

Reporting Tool (ERT). 

When reporting and calculating individual test run data: 

 For analytical data reported from the lab as “nondetect” or “below detection level;” 

 Include a brief description of the procedures used to determine the analytical 

detection and in-stack detection levels: 

o In the Note line of Excel emission test spreadsheet template; or 

o In the Comments line of Lab Data tab in the Run Data Details in the ERT. 

 Describe these procedures completely in a separate attachment including the 

measurements made, the standards used, and the statistical procedures applied. 

 Calculate in-stack emissions rate for any analytical measurement below detection 

level using the relevant detection level as the “real” value. 

 Report the calculated emissions concentration or rate result: 
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o As a bracketed “less than” detection level value (e.g., [<0.0105]) in the 

Excel emission test spreadsheet template and include the appropriate flag 

in the Note line; or 

o As a “real” value in the ERT with the appropriate flag in the Comments 

line. 

 Report as “real” values (i.e., no brackets or < symbol) any analytical data 

measured above the detection level including any data between the analytical 

detection level and a laboratory-specific reporting or quantification level (i.e., flag 

as ADL). 

 Apply these reporting and calculation procedures to measurements made with 

Method 23: 

o Report data in the Excel emission test spreadsheet template for each of the 

D/F congeners measured with Method 23 below the detection level as 

[< detection level] 

o Do not report emissions as zero as described in the method 

 For pollutant measurements composed of multiple components or fractions (e.g., Hg and 

other metals sampling trains) when the result for the value for any component is 

measured below the analytical detection level; 

 Calculate in-stack emissions rate or concentrations as outlined above for each 

component or fraction; 

 Sum the measured and detection level values as outlined above using the in-stack 

emissions rate or concentrations for all of the components or fractions; and 

 Report the sum of all components or fractions: 

o As a bracketed “less than” detection level value (e.g., [<0.0105]) in the 

Excel emission test spreadsheet template and include the appropriate flag 

in the Note line; or 

o As a “real” value in the ERT with the appropriate flag in the Comments 

line. 

 Report also the individual component or fraction values for each run if the Excel 

emission test spreadsheet template or ERT format allows; if not (i.e., the format 

allows reporting only a single sum value): 

o For the Excel emission test spreadsheet template, next to the sum reported 

as above report in the Notes line the appropriate flag along with the values 

for the measured or detection level value for each 

component or fraction as used in the calculations (e.g., 0.036, [<0.069], 

1.239, [<0.945] for a four fraction sample) 

o For the ERT, next to the sum reported as above, report on the Comments 

line the appropriate flag and the measured or detection level value for each 

component or fraction as used in the calculations (e.g., 0.036, [<0.069], 

1.239, [<0.945] for a four fraction sample) 

 For measurements conducted using instrumental test methods (e.g., Methods 3A, 6C, 7E, 

10, 25A) 
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 Record gaseous concentration values as measured including negative values and 

flag as ADL; do not report as BDL 

 Calculate and report in-stack emissions rates using these measured values 

 Include relevant information relative to calibration gas values or other technical 

qualifiers for measured values in Comments line in the ERT

 When reporting and calculating average emissions rate or concentration for a test when 

some results are reported as BDL 

 Sum all of the test run values including those indicated as BDL or DLL as “real” 

values 

 Calculate the average emissions rate or concentration (e.g., divide the sum by 3 

for a three-run test) 

 Report the average emissions rate or concentration average: 

o As a bracketed “less than” detection level value (e.g., [<20.06]) in the 

Excel emission test spreadsheet template and include the appropriate flag 

in the Note line 

o As a “real” value in the ERT and include the appropriate flag in the 

Comments line. 

3.2 Reporting Fuel Analysis Data 

If you conducted a fuel analysis, you must report the analysis results separately for each of the 

composited samples in a Microsoft ® Excel Fuel Analysis Template. This Excel template can be 

downloaded from the Electric Utility MACT ICR 2009 website (http://utilitymacticr.rti.org). If 

you conducted fuel analysis on more than one type of fuel used during testing, or for more than 

one combustion unit, you must make a copy of the worksheet and update the combustor ID and 

fuel type in each worksheet order to distinguish between the separate fuel analyses. 

3.3 Required Fields for ERT Reporting 

This section outlines the required data entry fields for the ERT in order to satisfy the 

requirements of this ICR test program. The list of fields within the ERT with the notes whether 

or not the field is required or optional can be found at http://utilitymacticr.rti.org. 
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4.0 How to Submit Data 

You may submit your data by using the Electric Utility MACT ICR 2009 website. To avoid 

duplicate data keep all data for a particular facility together, we request that you submit all of the 

data requested from your facility the same way. To submit your data: 

 Use the Electric Utility MACT ICR 2009 website referenced below and follow the 

directions listed below. 

 If you are submitting Confidential Business Information (CBI), you must mail a separate 

CD or DVD containing only the CBI portion of your data to the EPA address shown in 

your Section 114 letter. 

Instructions for Uploading Part III

1. Open the Web site 

Open the Electrical Utility MACT ICR 2009 Web site, located at the following address: 

http://utilitymacticr.rti.org

2. Log in, or register – It is assumed that the respondent has registered and logged into the 

website previously for entry of Part I and II data.

3. Go to the "Upload Part III" page 

a. Click on the "Upload" menu item within the menu bar at the top of the screen to 

go to the "Upload" page.

b. Click on the "Upload Part III" link.

4. Upload your completed ERT Database and Excel Spreadsheets 

a. Go to the tabbed section of the "Upload Part III" page. 

b. The first tab is the "Upload Checklist" tab. 

Answer all questions, then click on the "Continue" button. Your answers to the 

"Upload Checklist" questions will assist in guiding you correctly through the 

upload process. 

c. The next tab is the "Upload ERT Database" tab. 

i. Enter a description for the upload, or any comments. Note that the 

description and comments entered at this point are primarily for your own 

reference when referring back to the files you have uploaded (refer to 4.e). 
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ii. Select the name(s) of the Facility(s) that the ERT Database applies to. 

iii. Select the name(s) of the Unit(s) that the ERT Database applies to. 

iv. Browse to the ERT Database file that you wish to upload. 

v. After selecting the file, click on the "Upload" link. The file's upload 

progress will be displayed. Uploading may take a few seconds or minutes 

depending on the size of the file you are attempting to upload, and your 

internet connection speed. 

Please be aware that the only file types that will be accepted for the ERT 

Database upload are ".zip" and ".acddr" (the file type of the ERT Database 

originally supplied to you). It is recommended that you zip your 

completed ERT Database prior to uploading it, particularly if it is over 

200MB in size. 

d. After the ERT Database upload has completed, click on the "Continue" button. 

e. If you answered "Yes" to the checklist question regarding Additional Excel 

data(Microsoft® Excel Emission Test Template and/or Microsoft ® Excel Fuel 

Analysis Template), the next tab will be the "Upload Additional Excel Data" tab. 

Follow the same process outlined in 4.c. 

Note that the only file types that will be accepted for the Excel data upload are 

".xls" and ".xlsx". 

f. After the Excel data upload has completed, click on the "Continue" button. 

g. The final tab is the "View uploaded files" tab. This will display a list of the files 

you have uploaded. 

i. Next to each file will be links to "Delete" and "Download" the file. 

1. You can click on the "Delete" link if you wish to remove the file in 

order to upload a new version. 

2. If you would like to check the file that is currently uploaded, click 

on the "Download" link to download a copy of it. 

ii. At the bottom of the "View uploaded files" tab, there is a "Finalize 

uploads" button. 

1. Click on this button when you are sure you have uploaded the final 

copy of your completed ERT Database. 

2. Once you have finalized uploads for Part III you will no longer be 

able to upload further files for that part of the ICR.
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Also at the bottom of the "View uploaded files" tab, there is a button titled "Upload another file". 

Click on this button if you would like to start the upload process again, for another completed 

ERT Database 
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5.0 Definitions 

 

The following definitions apply to the coal- and oil-fired electric utility steam generating unit test 

plan methods: 

Equivalent means: 

(1) An equivalent sample collection procedure means a published voluntary consensus 

standard or practice (VCS) or EPA method that includes collection of a minimum of three 

composite fuel samples, with each composite consisting of a minimum of three increments 

collected at approximately equal intervals over the test period. 

(2) An equivalent sample compositing procedure means a published VCS or EPA method to 

systematically mix and obtain a representative subsample (part) of the composite sample. 

(3) An equivalent sample preparation procedure means a published VCS or EPA method that: 

Clearly states that the standard, practice or method is appropriate for the pollutant and the 

fuel matrix; or is cited as an appropriate sample preparation standard, practice or method 

for the pollutant in the chosen VCS or EPA determinative or analytical method. 

(4) An equivalent procedure for determining heat content means a published VCS or EPA 

method to obtain gross calorific (or higher heating) value. 

(5) An equivalent procedure for determining fuel moisture content means a published VCS or 

EPA method to obtain moisture content. If the sample analysis plan calls for determining 

metals (especially the mercury, selenium, or arsenic) using an aliquot of the dried sample, 

then the drying temperature must be modified to prevent vaporizing these metals. On the 

other hand, if metals analysis is done on an ‘‘as received’’ basis, a separate aliquot can be 

dried to determine moisture content and the metals concentration mathematically adjusted 

to a dry basis. 

(6) An equivalent pollutant (mercury, TSM, or total chlorine) determinative or analytical 

procedure means a published VCS or EPA method that clearly states that the standard, 

practice, or method is appropriate for the pollutant and the fuel matrix and has a published 

detection limit equal to or lower than the methods listed in this test plan. 

Voluntary Consensus Standards or VCS mean technical standards (e.g., materials specifications, 

test methods, sampling procedures, business practices) developed or adopted by one or more 

voluntary consensus bodies. EPA/OAQPS has by precedent only used VCS that are written in 

English. Examples of VCS bodies are: American Society of Testing and Materials (ASTM), 

American Society of Mechanical Engineers (ASME), International Standards Organization 

(ISO), Standards Australia (AS), British Standards (BS), Canadian Standards (CSA), European 

Standard (EN or CEN) and German Engineering Standards (VDI). The types of standards that 

are not considered VCS are standards developed by: the U.S. States, such as California (CARB) 

and Texas (TCEQ); industry groups, such as American Petroleum Institute (API), Gas Processors 

Association (GPA), and Gas Research Institute (GRI); and other branches of the U.S. 

government, such as Department of Defense (DOD) and Department of Transportation (DOT). 
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This does not preclude EPA from using standards developed by groups that are not VCS bodies 

within their rule. When this occurs, EPA has done searches and reviews for VCS equivalent to 

these non-EPA methods. 
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6.0 Contact Information for Questions on Test Plan and Reporting 

For questions on how to report data using the ERT, contact: 

Ron Myers 

U.S. EPA 

(919) 541-5407 

myers.ron@epa.gov

or 

Barrett Parker 

U.S. EPA 

(919) 541-5635 

parker.barrett@epa.gov 

For questions on the test methods contact: 

Peter Westlin 

U.S. EPA 

(919) 541-1058 

westlin.peter@epa.gov

 OR 

Gary McAlister 

U.S. EPA 

(919) 541-1062 

mcalister.gary@epa.gov 

For questions on the coal- and oil-fired electric utility steam generating unit test plan, 

including units selected to test and reporting mechanisms other than the ERT, contact: 

William Maxwell 

U.S. EPA 

(919) 541-5430 

maxwell.bill@epa.gov 

For questions on uploading files to the HTTP site, Please visit http://utilitymacticr.rti.org and 

use the toll free technical support hotline or technical support email address. 
Attachment 4. List of coal-fired electric utility steam generating units requiring Part I and II In

State Plant Name Boiler ID State Plant Name Boiler ID State Plant 

53 

IN A. B. Brown 1 IN A. B. Brown 2 CA ACE Cogeneration Facility CFB PA AES Beaver Valley Partners Beaver Valley 2 PA AES Beaver Valley Partners Beaver Valley 3 PA AES Beaver Valley Partners Beaver Valley 4 PA AES Beaver Valley Partners Beaver Valley 5 NY AES Cayuga 1 NY AES Cayuga 2 NY AES Greenidge LLC 4 NY AES Greenidge LLC 5 NY AES Greenidge LLC 6 HI AES Hawaii BLRA HI AES Hawaii BLRB IN AES Petersburg 1 IN AES Petersburg 2 IN AES Petersburg 3 IN AES Petersburg 4 PR AES Puerto Rico (Aurora) 1 PR AES Puerto Rico (Aurora) 2 OK AES Shady Point 1A OK AES Shady Point 1B OK AES Shady Point 2A OK AES Shady Point 2B NY AES Somerset LLC 1 CT AES Thames A CT AES Thames B MD AES Warrior Run Cogeneration Facility BLR1 NY AES Westover 11 NY AES Westover 12 NY AES Westover 13 WV Albright 1 WV Albright 2 WV Albright 3 MN Allen S. King 1 TN Allen Steam Plant 1 TN Allen Steam Plant 2 TN Allen Steam Plant 3 WI Alma B4 WI Alma B5 VA Altavista Power Station 1 IA Ames Electric Services Power Plant 7 IA Ames Electric Services Power Plant 8 ND Antelope Valley B1 ND Antelope Valley B2 AZ Apache Station 2 AZ Apache Station 3 CO Arapahoe 3 CO Arapahoe 4 PA Armstrong Power Station 1 

PA Armstrong Power Station 2 MO Asbury 1 NC Asheville 1 NC Asheville 2 OH Ashtabula 7 OH Avon Lake 10 OH Avon Lake 12 MI B. C. Cobb 4 MI B. C. Cobb 5 NJ B. L. England 2 IN Bailly 7 IN Bailly 8 IL Baldwin Energy Complex 1 IL Baldwin Energy Complex 2 IL Baldwin Energy Complex 3 AL Barry 1 AL Barry 2 AL Barry 3 AL Barry 4 AL Barry 5 OH Bay Shore 2 OH Bay Shore 3 OH Bay Shore 4 WI Bay Front 5 NC Belews Creek 1 NC Belews Creek 2 MI Belle River 1 MI Belle River 2 FL Big Bend BB01 FL Big Bend BB02 FL Big Bend BB03 FL Big Bend BB04 TX Big Brown 1 TX Big Brown 2 LA Big Cajun 2 2B1 LA Big Cajun 2 2B2 LA Big Cajun 2 2B3 KY Big Sandy BSU1 KY Big Sandy BSU2 SD Big Stone 1 VA Birchwood Power 1A MN Black Dog 3 MN Black Dog 4 NY Black River Generation E0001 NY Black River Generation E0002 NY Black River Generation E0003 WI Blount Street 7 WI Blount Street 8 WI Blount Street 9 MO Blue Valley 1 

MO Blue Valley MO Blue Valley OR Boardman UT Bonanza GA Bowen GA Bowen GA Bowen GA Bowen MD Brandon Shores MD Brandon Shores MA Brayton Point MA Brayton Point MA Brayton Point VA Bremo Bluff VA Bremo Bluff CT Bridgeport Station PA Bruce Mansfield PA Bruce Mansfield PA Bruce Mansfield NC Buck NC Buck NC Buck NC Buck NC Buck TN Bull Run IA Burlington FL C. D. McIntosh Jr MD C. P. Crane MD C. P. Crane NY C. R. Huntley GenNY C. R. Huntley GenNY C. R. Huntley GenPA Cambria Cogen PA Cambria Cogen SC Canadys Steam SC Canadys Steam SC Canadys Steam KY Cane Run KY Cane Run KY Cane Run NC Cape Fear NC Cape Fear UT Carbon UT Carbon OH Cardinal OH Cardinal OH Cardinal IN Cayuga IN Cayuga FL Cedar Bay Gener
State Plant Name Boiler ID State Plant Name Boiler ID State Plant 

54 

FL Cedar Bay Generating LP CBB FL Cedar Bay Generating LP CBC FL Central Power & Lime 1 MD Chalk Point LLC 1 MD Chalk Point LLC 2 NJ Chambers Cogeneration LP BOIL1 NJ Chambers Cogeneration LP BOIL2 MO Chamois 2 AL Charles R Lowman 3 AL Charles R. Lowman 1 AL Charles R. Lowman 2 CO Cherokee 1 CO Cherokee 2 CO Cherokee 3 CO Cherokee 4 VA Chesapeake 1 VA Chesapeake 2 VA Chesapeake 3 VA Chesapeake 4 VA Chesterfield 3 VA Chesterfield 4 VA Chesterfield 5 VA Chesterfield 6 PA Cheswick Power Plant 1 AZ Cholla 1 AZ Cholla 2 AZ Cholla 3 AZ Cholla 4 MN Clay Boswell 1 MN Clay Boswell 2 MN Clay Boswell 3 MN Clay Boswell 4 NC Cliffside 1 NC Cliffside 2 NC Cliffside 3 NC Cliffside 4 NC Cliffside 5 IN Clifty Creek 1 IN Clifty Creek 2 IN Clifty Creek 3 IN Clifty Creek 4 IN Clifty Creek 5 IN Clifty Creek 6 VA Clinch River 1 VA Clinch River 2 VA Clinch River 3 VA Clover 1 VA Clover 2 

ND Coal Creek 1 ND Coal Creek 2 IL Coffeen 01 IL Coffeen 02 NC Cogentrix Dwayne Collier Battle Cogen 1A NC Cogentrix Dwayne Collier Battle Cogen 1B NC Cogentrix Dwayne Collier Battle Cogen 2A NC Cogentrix Dwayne Collier Battle Cogen 2B VA Cogentrix Hopewell 1A VA Cogentrix Hopewell 1B VA Cogentrix Hopewell 1C VA Cogentrix Hopewell 2A VA Cogentrix Hopewell 2B VA Cogentrix Hopewell 2C VA Cogentrix of Richmond 1A VA Cogentrix of Richmond 1B VA Cogentrix of Richmond 2A VA Cogentrix of Richmond 2B VA Cogentrix of Richmond 3A VA Cogentrix of Richmond 3B VA Cogentrix of Richmond 4A VA Cogentrix of Richmond 4B VA Cogentrix Virginia Leasing Corporation 1A VA Cogentrix Virginia Leasing Corporation 1B VA Cogentrix Virginia Leasing Corporation 1C VA Cogentrix Virginia Leasing Corporation 2A VA Cogentrix Virginia Leasing Corporation 2B VA Cogentrix Virginia Leasing Corporation 2C AL Colbert 1 AL Colbert 2 AL Colbert 3 AL Colbert 4 AL Colbert 5 TX Coleto Creek 1 MT Colstrip 1 MT Colstrip 2 MT Colstrip 3 MT Colstrip 4 MT Colstrip Energy LP BLR1 WI Columbia 1 WI Columbia 2 PA Colver Power Project ABB01 CO Comanche 1 CO Comanche 2 CO Comanche 3 PA Conemaugh 1 PA Conemaugh 2 OH Conesville 1 

OH Conesville OH Conesville OH Conesville OH Conesville OH Conesville KY Cooper KY Cooper SC Cope AZ Coronado AZ Coronado IA Council Bluffs IA Council Bluffs IA Council Bluffs IA Council Bluffs ND Coyote CO Craig CO Craig CO Craig IL Crawford IL Crawford FL Crist FL Crist FL Crist FL Crist PA Cromby GeneratinSC Cross SC Cross SC Cross SC Cross FL Crystal River FL Crystal River FL Crystal River FL Crystal River TN Cumberland TN Cumberland KY D. B. Wilson KY Dale KY Dale KY Dale KY Dale IL Dallman IL Dallman IL Dallman IL Dallman MI Dan E. Karn MI Dan E. Karn NC Dan River NC Dan River 
State Plant Name Boiler ID State Plant Name Boiler ID State Plant 

55 

NC Dan River 3 NY Danskammer Generating Station 3 NY Danskammer Generating Station 4 WY Dave Johnston BW41 WY Dave Johnston BW42 WY Dave Johnston BW43 WY Dave Johnston BW44 NJ Deepwater 8 FL Deerhaven Generating Station B2 MD Dickerson 1 MD Dickerson 2 MD Dickerson 3 LA Dolet Hills 1 SC Dolphus M Grainger 1 SC Dolphus M Grainger 2 IA Dubuque 1 IA Dubuque 5 IL Duck Creek 1 NY Dunkirk Generating Station 1 NY Dunkirk Generating Station 2 NY Dunkirk Generating Station 3 NY Dunkirk Generating Station 4 AL E. C. Gaston 1 AL E. C. Gaston 2 AL E. C. Gaston 3 AL E. C. Gaston 4 AL E. C. Gaston 5 IL E. D. Edwards 1 IL E. D. Edwards 2 IL E. D. Edwards 3 KY E. W. Brown 1 KY E. W. Brown 2 KY E. W. Brown 3 IN Eagle Valley 3 IN Eagle Valley 4 IN Eagle Valley 5 IN Eagle Valley 6 IA Earl F. Wisdom 1 KY East Bend 2 OH Eastlake 1 OH Eastlake 2 OH Eastlake 3 OH Eastlake 4 OH Eastlake 5 PA Ebensburg Power 031 MI Eckert Station 1 MI Eckert Station 2 MI Eckert Station 3 

MI Eckert Station 4 MI Eckert Station 5 MI Eckert Station 6 PA Eddystone Generating Station 1 PA Eddystone Generating Station 2 DE Edge Moor 3 DE Edge Moor 4 WI Edgewater 3 WI Edgewater 4 WI Edgewater 5 IN Edwardsport 7-1 IN Edwardsport 7-2 IN Edwardsport 8-1 WI Elm Road Generating Station 1 WI Elm Road Generating Station 2 KY Elmer Smith 1 KY Elmer Smith 2 PA Elrama Power Plant 1 PA Elrama Power Plant 2 PA Elrama Power Plant 3 PA Elrama Power Plant 4 MI Endicott Station 1 MI Erickson Station 1 NM Escalante 1 IN F. B. Culley 1 IN F. B. Culley 2 IN F. B. Culley 3 IA Fair Station 1 IA Fair Station 2 TX Fayette Power Project 1 TX Fayette Power Project 2 TX Fayette Power Project 3 IL Fisk Street 19 AR Flint Creek 1 WV Fort Martin Power Station 1 WV Fort Martin Power Station 2 PA Foster Wheeler Mt Carmel Cogen SG-101 NM Four Corners 1 NM Four Corners 2 NM Four Corners 3 NM Four Corners 4 NM Four Corners 5 IN Frank E. Ratts 1SG1 IN Frank E. Ratts 2SG1 NC G. G. Allen 1 NC G. G. Allen 2 NC G. G. Allen 3 NC G. G. Allen 4 

NC G. G. Allen AL Gadsden AL Gadsden TN Gallatin TN Gallatin TN Gallatin TN Gallatin OH General James M OH General James M WI Genoa IA George Neal NortIA George Neal NortIA George Neal NortIA George Neal SouNE Gerald Gentleman NE Gerald Gentleman KY Ghent KY Ghent KY Ghent KY Ghent TX Gibbons Creek IN Gibson IN Gibson IN Gibson IN Gibson IN Gibson VA Glen Lyn VA Glen Lyn VA Glen Lyn AL Gorgas AL Gorgas AL Gorgas AL Gorgas AL Gorgas WV Grant Town PoweWV Grant Town PoweOK GRDA OK GRDA KY Green River KY Green River AL Greene County AL Greene County SC H. B. Robinson KY H. L. Spurlock KY H. L. Spurlock KY H. L. Spurlock KY H. L. Spurlock OH Hamilton 
State Plant Name Boiler ID State Plant Name Boiler ID State Plant 

56 

OH Hamilton 9 GA Hammond 1 GA Hammond 2 GA Hammond 3 GA Hammond 4 MI Harbor Beach 1 MT Hardin Generator Project PC1 IN Harding Street 50 IN Harding Street 60 IN Harding Street 70 GA Harllee Branch 1 GA Harllee Branch 2 GA Harllee Branch 3 GA Harllee Branch 4 TX Harrington 061B TX Harrington 062B TX Harrington 063B WV Harrison Power Station 1 WV Harrison Power Station 2 WV Harrison Power Station 3 PA Hatfields Ferry Power Station 1 PA Hatfields Ferry Power Station 2 PA Hatfields Ferry Power Station 3 IL Havana 9 MO Hawthorn 5A CO Hayden H1 CO Hayden H2 AK Healy 1 KY Henderson I 6 IL Hennepin Power Station 1 IL Hennepin Power Station 2 MD Herbert A. Wagner 2 MD Herbert A. Wagner 3 KY HMP&L Station Two Henderson H1 KY HMP&L Station Two Henderson H2 KS Holcomb SGU1 PA Homer City Station 1 PA Homer City Station 2 PA Homer City Station 3 MN Hoot Lake 2 MN Hoot Lake 3 OK Hugo 1 UT Hunter 1 UT Hunter 2 UT Hunter 3 UT Huntington 1 UT Huntington 2 IL Hutsonville 05 

IL Hutsonville 06 MO Iatan 1 AR Independence 1 AR Independence 2 DE Indian River Generating Station 2 DE Indian River Generating Station 3 DE Indian River Generating Station 4 FL Indiantown Cogeneration LP AAB01 UT Intermountain Power Project 1SGA UT Intermountain Power Project 2SGA MI J. B. Sims 3 MI J. C. Weadock 7 MI J. C. Weadock 8 MT J. E. Corette Plant 2 MI J. H. Campbell 1 MI J. H. Campbell 2 MI J. H. Campbell 3 KY J. K. Smith 1 TX J. K. Spruce BLR1 TX J. K. Spruce BLR2 OH J. M. Stuart 1 OH J. M. Stuart 2 OH J. M. Stuart 3 OH J. M. Stuart 4 MI J. R. Whiting 1 MI J. R. Whiting 2 MI J. R. Whiting 3 TX J. T. Deely 1 TX J. T. Deely 2 GA Jack McDonough MB1 GA Jack McDonough MB2 MS Jack Watson 4 MS Jack Watson 5 MI James De Young 5 AL James H. Miller Jr. 1 AL James H. Miller Jr. 2 AL James H. Miller Jr. 3 AL James H. Miller Jr. 4 MO James River Power Station 3 MO James River Power Station 4 MO James River Power Station 5 SC Jefferies 3 SC Jefferies 4 KS Jeffrey Energy Center 1 KS Jeffrey Energy Center 2 KS Jeffrey Energy Center 3 WY Jim Bridger BW71 WY Jim Bridger BW72 

WY Jim Bridger WY Jim Bridger PA John B Rich MemPA John B Rich MemWV John E Amos WV John E Amos WV John E. Amos WI John P. Madgett TN John Sevier TN John Sevier TN John Sevier TN John Sevier TN Johnsonville TN Johnsonville TN Johnsonville TN Johnsonville TN Johnsonville TN Johnsonville TN Johnsonville TN Johnsonville TN Johnsonville TN Johnsonville IL Joliet 29 IL Joliet 29 IL Joliet 29 IL Joliet 29 IL Joliet 9 IL Joppa Steam IL Joppa Steam IL Joppa Steam IL Joppa Steam IL Joppa Steam IL Joppa Steam WV Kammer WV Kammer WV Kammer WV Kanawha River WV Kanawha River KY Kenneth C. ColemKY Kenneth C. ColemKY Kenneth C. ColemPA Keystone PA Keystone OH Killen Station IL Kincaid GeneratioIL Kincaid GeneratioTN Kingston TN Kingston 
State Plant Name Boiler ID State Plant Name Boiler ID State Plant 

57 

TN Kingston 3 TN Kingston 4 TN Kingston 5 TN Kingston 6 TN Kingston 7 TN Kingston 8 TN Kingston 9 PA Kline Township Cogen Facility 1 GA Kraft 1 GA Kraft 2 GA Kraft 3 OH Kyger Creek 1 OH Kyger Creek 2 OH Kyger Creek 3 OH Kyger Creek 4 OH Kyger Creek 5 NC L. V. Sutton 1 NC L. V. Sutton 2 NC L. V. Sutton 3 KS La Cygne 1 KS La Cygne 2 MO Labadie 1 MO Labadie 2 MO Labadie 3 MO Labadie 4 MO Lake Road 5 OH Lake Shore 18 IL Lakeside 7 IL Lakeside 8 CO Lamar 4 IA Lansing 3 IA Lansing 4 FL Lansing Smith 1 FL Lansing Smith 2 WY Laramie River Station 1 WY Laramie River Station 2 WY Laramie River Station 3 KS Lawrence Energy Center 3 KS Lawrence Energy Center 4 KS Lawrence Energy Center 5 NC Lee 1 NC Lee 2 NC Lee 3 ND Leland Olds 1 ND Leland Olds 2 MT Lewis & Clark B1 TX Limestone LIM1 TX Limestone LIM2 

NJ Logan Generating Plant B01 NE Lon Wright 8 IA Louisa 101 WI Manitowoc 6 WI Manitowoc 7 WI Manitowoc 8 IL Marion 4 IL Marion 123 NC Marshall 1 NC Marshall 2 NC Marshall 3 NC Marshall 4 CO Martin Drake 5 CO Martin Drake 6 CO Martin Drake 7 TX Martin Lake 1 TX Martin Lake 2 TX Martin Lake 3 NC Mayo 1A NC Mayo 1B GA McIntosh 1 SC McMeekin MCM1 SC McMeekin MCM2 VA Mecklenburg Power Station BLR1 VA Mecklenburg Power Station BLR2 MO Meramec 1 MO Meramec 2 MO Meramec 3 MO Meramec 4 IL Meredosia 01 IL Meredosia 02 IL Meredosia 03 IL Meredosia 04 IL Meredosia 05 IN Merom 1SG1 IN Merom 2SG1 NH Merrimack 1 NH Merrimack 2 OH Miami Fort 6 OH Miami Fort 7 OH Miami Fort 8 OH Miami Fort 5-1 OH Miami Fort 5-2 IN Michigan City 12 KY Mill Creek 1 KY Mill Creek 2 KY Mill Creek 3 KY Mill Creek 4 

IA Milton L. Kapp ND Milton R. Young ND Milton R. Young GA Mitchell WV Mitchell WV Mitchell PA Mitchell Power StMI Monroe MI Monroe MI Monroe MI Monroe TX Monticello TX Monticello TX Monticello MO Montrose MO Montrose MO Montrose WV Morgantown EnerWV Morgantown EnerMD Morgantown GenMD Morgantown GenMA Mount Tom WV Mountaineer WV Mt Storm CA Mt. Poso CogeneWV Mt. Storm WV Mt. Storm IA Muscatine Plant #IA Muscatine Plant #IA Muscatine Plant #OH Muskingum River OH Muskingum River OH Muskingum River OH Muskingum River OH Muskingum River OK Muskogee OK Muskogee OK Muskogee WY Naughton WY Naughton WY Naughton AZ Navajo AZ Navajo AZ Navajo KS Nearman Creek NE Nebraska City NE Nebraska City WY Neil Simpson II 
State Plant Name Boiler ID State Plant Name Boiler ID State Plant 

58 

WI Nelson Dewey 1 WI Nelson Dewey 2 PA New Castle Plant 3 PA New Castle Plant 4 PA New Castle Plant 5 MO New Madrid 1 MO New Madrid 2 IL Newton 1 IL Newton 2 OH Niles 1 OH Niles 2 WV North Branch 1A WV North Branch 1B NE North Omaha 1 NE North Omaha 2 NE North Omaha 3 NE North Omaha 4 NE North Omaha 5 NV North Valmy 1 NV North Valmy 2 PA Northampton Generating Company BLR1 OK Northeastern 3313 OK Northeastern 3314 CO Nucla 1 OH O. H. Hutchings H-1 OH O. H. Hutchings H-2 OH O. H. Hutchings H-3 OH O. H. Hutchings H-4 OH O. H. Hutchings H-5 OH O. H. Hutchings H-6 TX Oak Grove 1 TX Oak Grove 2 TX Oklaunion 1 OH Orrville 10 OH Orrville 11 OH Orrville 12 OH Orrville 13 IA Ottumwa 1 OH Painesville 3 OH Painesville 4 OH Painesville 5 PA Panther Creek Energy Facility BLR1 PA Panther Creek Energy Facility BLR2 KY Paradise 1 KY Paradise 2 KY Paradise 3 CO Pawnee 1 WV Philip Sporn 11 

WV Philip Sporn 21 WV Philip Sporn 31 WV Philip Sporn 41 WV Philip Sporn 51 OH Picway 9 PA Piney Creek Project BRBR1 TX Pirkey 1 WI Pleasant Prairie 1 WI Pleasant Prairie 2 WV Pleasants Power Station 1 WV Pleasants Power Station 2 AR Plum Point Energy STG1 CA Port of Stockton District Energy Facility N64514 CA Port of Stockton District Energy Facility N64516 PA Portland 1 PA Portland 2 VA Potomac River 1 VA Potomac River 2 VA Potomac River 3 VA Potomac River 4 VA Potomac River 5 IL Powerton 51 IL Powerton 52 IL Powerton 61 IL Powerton 62 PA PPL Brunner Island 1 PA PPL Brunner Island 2 PA PPL Brunner Island 3 PA PPL Martins Creek 1 PA PPL Martins Creek 2 PA PPL Montour 1 PA PPL Montour 2 IA Prairie Creek 1 IA Prairie Creek 2 IA Prairie Creek 3 IA Prairie Creek 4 MI Presque Isle 5 MI Presque Isle 6 MI Presque Isle 7 MI Presque Isle 8 MI Presque Isle 9 NC Primary Energy Roxboro 1A NC Primary Energy Roxboro 1B NC Primary Energy Roxboro 1C NC Primary Energy Southport 1A NC Primary Energy Southport 1B NC Primary Energy Southport 1C NC Primary Energy Southport 2A 

NC Primary Energy SNC Primary Energy SNJ PSEG Hudson GeNJ PSEG Mercer GeNJ PSEG Mercer GeWI Pulliam WI Pulliam WI Pulliam WI Pulliam WI Pulliam WI Pulliam KS Quindaro KS Quindaro KY R D Green KY R. D. Green MS R. D. Morrow MS R. D. Morrow OH R. E. Burger OH R. E. Burger OH R. E. Burger OH R. E. Burger IN R. Gallagher IN R. Gallagher IN R. Gallagher IN R. Gallagher ND R. M. Heskett ND R. M. Heskett IN R. M. Schahfer IN R. M. Schahfer IN R. M. Schahfer IN R. M. Schahfer MD R. Paul Smith PowMD R. Paul Smith PowLA R. S. Nelson CO Rawhide CO Ray D. Nixon MS Red Hills GeneratMS Red Hills GeneratNV Reid Gardner NV Reid Gardner NV Reid Gardner NV Reid Gardner OH Richard Gorsuch OH Richard Gorsuch OH Richard Gorsuch OH Richard Gorsuch MI River Rouge MI River Rouge 
State Plant Name Boiler ID State Plant Name Boiler ID State Plant 

59 

NC Riverbend 7 NC Riverbend 8 NC Riverbend 9 NC Riverbend 10 IA Riverside 9 KS Riverton 39 KS Riverton 40 WV Rivesville 7 WV Rivesville 8 NC Roanoke Valley I BLR1 NC Roanoke Valley II BLR2 KY Robert A Reid R1 NY Rochester 7 1 NY Rochester 7 2 NY Rochester 7 3 NY Rochester 7 4 IN Rockport MB1 IN Rockport MB2 LA Rodemacher 2 NC Roxboro 1 NC Roxboro 2 NC Roxboro 3A NC Roxboro 3B NC Roxboro 4A NC Roxboro 4B MO Rush Island 1 MO Rush Island 2 MA Salem Harbor 1 MA Salem Harbor 2 MA Salem Harbor 3 NM San Juan 1 NM San Juan 2 NM San Juan 3 NM San Juan 4 TX San Miguel SM-1 TX Sandow Station 4 TX Sandow Station 5A TX Sandow Station 5B GA Scherer 1 GA Scherer 2 GA Scherer 3 GA Scherer 4 NH Schiller 4 NH Schiller 5 NH Schiller 6 FL Scholz 1 FL Scholz 2 PA Scrubgrass Generating UNIT 1 

PA Scrubgrass Generating UNIT 2 FL Seminole 1 FL Seminole 2 PA Seward 1 PA Seward 2 KY Shawnee 1 KY Shawnee 2 KY Shawnee 3 KY Shawnee 4 KY Shawnee 5 KY Shawnee 6 KY Shawnee 7 KY Shawnee 8 KY Shawnee 9 KY Shawnee 10 PA Shawville 1 PA Shawville 2 PA Shawville 3 PA Shawville 4 NE Sheldon 1 NE Sheldon 2 MN Sherburne County 1 MN Sherburne County 2 MN Sherburne County 3 MI Shiras 3 MO Sibley 1 MO Sibley 2 MO Sibley 3 MO Sikeston Power Station 1 MN Silver Bay Power BLR1 MN Silver Bay Power BLR2 MN Silver Lake 3 MN Silver Lake 4 MO Sioux 1 MO Sioux 2 IA Sixth Street 2 IA Sixth Street 3 IA Sixth Street 4 IA Sixth Street 5 MA Somerset Station 8 OK Sooner 1 OK Sooner 2 WI South Oak Creek 5 WI South Oak Creek 6 WI South Oak Creek 7 WI South Oak Creek 8 VA Southampton Power Station 1 MO Southwest Power Station 1 

AZ Springerville AZ Springerville AZ Springerville AZ Springerville MI St. Clair MI St. Clair MI St. Clair MI St. Clair MI St. Clair MI St. Clair FL St. Johns River PFL St. Johns River PPA St. Nicholas CogeND Stanton ND Stanton FL Stanton Energy CFL Stanton Energy CIN State Line Energy IN State Line Energy IA Streeter Station UT Sunnyside Cogen IA Sutherland IA Sutherland IA Sutherland MN Syl Laskin MN Syl Laskin IN Tanners Creek IN Tanners Creek IN Tanners Creek IN Tanners Creek KS Tecumseh Energy KS Tecumseh Energy MI TES Filer City StaMI TES Filer City StaMO Thomas Hill MO Thomas Hill MO Thomas Hill PA Titus PA Titus PA Titus TX Tolk TX Tolk WA Transalta CentralWA Transalta CentralMI Trenton Channel MI Trenton Channel MI Trenton Channel MI Trenton Channel 
State Plant Name Boiler ID State Plant Name Boiler ID State Plant 

60 

MI Trenton Channel 9A CO Trigen Colorado Energy BLR3 CO Trigen Colorado Energy BLR4 CO Trigen Colorado Energy BLR5 NY Trigen Syracuse Energy 1 NY Trigen Syracuse Energy 2 NY Trigen Syracuse Energy 3 NY Trigen Syracuse Energy 4 NY Trigen Syracuse Energy 5 KY Trimble County 1 NV TS Power Plant BLR100 TX Twin Oaks Power One U1 TX Twin Oaks Power One U2 WY Two Elk Generating Station 1 KY Tyrone 5 SC Urquhart URQ3 WI Valley 1 WI Valley 2 WI Valley 3 WI Valley 4 CO Valmont 5 IL Vermilion 1 IL Vermilion 2 MS Victor J Daniel Jr 1 MS Victor J Daniel Jr. 2 TX W. A. Parish WAP5 TX W. A. Parish WAP6 TX W. A. Parish WAP7 TX W. A. Parish WAP8 OH W. H. Sammis 1 OH W. H. Sammis 2 OH W. H. Sammis 3 OH W. H. Sammis 4 OH W. H. Sammis 5 OH W. H. Sammis 6 OH W. H. Sammis 7 NC W. H. Weatherspoon 1 NC W. H. Weatherspoon 2 NC W. H. Weatherspoon 3 OH W. H. Zimmer 1 SC W. S. Lee 1 SC W. S. Lee 2 SC W. S. Lee 3 IN Wabash River 1 IN Wabash River 2 IN Wabash River 3 IN Wabash River 4 IN Wabash River 5 

IN Wabash River 6 OH Walter C Beckjord 1 OH Walter C Beckjord 2 OH Walter C Beckjord 5 OH Walter C. Beckjord 3 OH Walter C. Beckjord 4 OH Walter C. Beckjord 6 GA Wansley 1 GA Wansley 2 IN Warrick 1 IN Warrick 2 IN Warrick 3 IN Warrick 4 SC Wateree WAT1 SC Wateree WAT2 IL Waukegan 7 IL Waukegan 8 IL Waukegan 17 TX Welsh 1 TX Welsh 2 TX Welsh 3 WI Weston 1 WI Weston 2 WI Weston 3 WI Weston 4 PA Wheelabrator Frackville Energy BLR1 NE Whelan Energy Center 1 AR White Bluff 1 AR White Bluff 2 IN Whitewater Valley 1 IN Whitewater Valley 2 AL Widows Creek 1 AL Widows Creek 2 AL Widows Creek 3 AL Widows Creek 4 AL Widows Creek 5 AL Widows Creek 6 AL Widows Creek 7 AL Widows Creek 8 IL Will County 1 IL Will County 2 IL Will County 3 IL Will County 4 SC Williams WIL1 WV Willow Island 1 WV Willow Island 2 SC Winyah 1 SC Winyah 2 

SC Winyah SC Winyah IL Wood River IL Wood River PA WPS Energy ServPA WPS Energy ServPA WPS Energy ServPA WPS Energy ServPA WPS Energy ServPA WPS Energy ServNY WPS Power NiagPA WPS Westwood GWY Wygen I WY Wygen II WY Wyodak GA Yates GA Yates GA Yates GA Yates GA Yates GA Yates GA Yates VA Yorktown VA Yorktown 
Attachment 5. List of oil-fired electric utility steam generating units requiring Part I and II Inf

State Plant Name Boiler ID State Plant Name Boiler ID State Plant 

61 

PR Aguirre 1 PR Aguirre 2 PR Aguirre 3 PR Aguirre 4 PR Aguirre 5 PR Aguirre 6 PR Aguirre 7 PR Aguirre 8 PR Aguirre 9 PR Aguirre 10 PR Aguirre 11 PR Aguirre 12 FL Anclote 1 FL Anclote 2 PR Arecibo 1 PR Arecibo 2 PR Arecibo 3 NY Astoria Generating Station 30 NY Astoria Generating Station 40 NY Astoria Generating Station 50 NJ B. L. England 3 MS Baxter Wilson 1 MS Baxter Wilson 2 DC Benning 15 DC Benning 16 NY Bowline Point 1 NY Bowline Point 2 MA Brayton Point 4 CT Bridgeport Station BHB2 FL C. D. McIntosh Jr 1 FL C. D. McIntosh Jr 2 GU Cabras 1 GU Cabras 2 MA Canal Station 1 MA Canal Station 2 FL Cape Canaveral PCC1 FL Cape Canaveral PCC2 PR Central Palo Seco 1 PR Central Palo Seco 2 PR Central Palo Seco 3 PR Central Palo Seco 4 PR Central Palo Seco 5 PR Central Palo Seco 6 PR Central Palo Seco 7 PR Central Palo Seco 8 NY Charles Poletti 1 

MA Cleary Flood 8 PR Costa Sur 1 PR Costa Sur 2 PR Costa Sur 3 PR Costa Sur 4 PR Costa Sur 5 PR Costa Sur 6 PR Costa Sur 7 PR Costa Sur 8 PR Costa Sur 9 PR Costa Sur 10 PA Cromby Generating Station 2 MI Dan E. Karn 3 MI Dan E. Karn 4 NY Danskammer Generating Station 1 NY Danskammer Generating Station 2 CT Devon Station 7 CT Devon Station 8 IN Eagle Valley 1 IN Eagle Valley 2 NY East River 5 NY East River 6 PA Eddystone Generating Station 3 PA Eddystone Generating Station 4 DE Edge Moor 5 IN Edwardsport 6-1 MS Gerald Andrus 1 IN Harding Street 9 IN Harding Street 10 IL Havana 1 IL Havana 2 IL Havana 3 IL Havana 4 IL Havana 5 IL Havana 6 IL Havana 7 IL Havana 8 MD Herbert A. Wagner 1 MD Herbert A. Wagner 4 HI Honolulu 16 HI Honolulu 17 FL Indian River 1 FL Indian River 2 FL Indian River 3 SC Jefferies 1 SC Jefferies 2 

HI Kahe HI Kahe HI Kahe HI Kahe HI Kahe HI Kahe FL Manatee FL Manatee FL Martin FL Martin DE McKee Run GA McManus GA McManus IL Meredosia LA Michoud CT Middletown CT Middletown MD Mirant Chalk PoinMD Mirant Chalk PoinPA Mitchell Power StPA Mitchell Power StPA Mitchell Power StCT Montville Station CT Montville Station MA Mystic Generating CT New Haven HarboNH Newington NY Northport NY Northport NY Northport NY Northport FL Northside GeneraCT NRG Norwalk HaCT NRG Norwalk HaNY Oswego Harbor PNY Oswego Harbor PFL P. L. Bartow FL P. L. Bartow FL P. L. Bartow FL Port Everglades FL Port Everglades FL Port Everglades FL Port Everglades NY Port Jefferson NY Port Jefferson VA Possum Point 
State Plant Name Boiler ID State Plant Name Boiler ID State Plant 

62 

PA PPL Martins Creek 3 PA PPL Martins Creek 4 NJ PSEG Sewaren Generating Station 1 NJ PSEG Sewaren Generating Station 2 NJ PSEG Sewaren Generating Station 3 NJ PSEG Sewaren Generating Station 4 VI Randolph E. Harley 1 NY Ravenswood Generating Station 1 NY Ravenswood Generating Station 2 NY Ravenswood Generating Station 3 VI Richmond 1 FL Riviera PRV3 FL Riviera PRV4 NY Roseton Generating Station 1 NY Roseton Generating Station 2 

MA Salem Harbor 4 PR San Juan Plant 1 PR San Juan Plant 2 PR San Juan Plant 3 PR San Juan Plant 4 PR San Juan Plant 5 FL Sanford PSN3 PA Schuylkill Generating Station 1 FL Suwannee River 1 FL Suwannee River 2 FL Suwannee River 3 GU Tanguisson 1 FL Turkey Point PTP1 FL Turkey Point PTP2 MD Vienna Operations 8 

HI Waiau HI Waiau HI Waiau HI Waiau HI Waiau HI Waiau MA West Springfield ME William F. Wyman ME William F. Wyman ME William F. Wyman ME William F. Wyman VA Yorktown 
63 

Attachment 6. List of all IGCC units requiring Part I, II, and III Information and selected for H

acid gas HAP, dioxin/furan organic HAP, non-dioxin/furan organic HAP, and mercury and other 

metallic HAP testing 

State Plant Name Boiler ID FL Polk 1CA FL Polk 1CT IN Wabash River 1a 

Attachment 7. List of all petroleum coke-fired units requiring Part I, II, and III Information an

for HCl/HF/HCN acid gas HAP, dioxin/furan organic HAP, non-dioxin/furan organic HAP, and 

and other non-mercury metallic HAP testing 

State Plant Name Boiler ID NOX Control PM Control TX AES Deepwater AAB001 SCR Electrostatic precipitator, hot side OH Bay Shore 1 Baghouse, pulse PA Chester Operations 10 Baghouse, pulse CA Hanford CB1302 Baghouse, pulse WI Manitowoc 9 SNCR Baghouse, pulse FL Northside Generating Station 1 Baghouse, pulse FL Northside Generating Station 2 Baghouse, pulse LA R S Nelson 1A Baghouse, reverse air LA R S Nelson 2A Baghouse, reverse air CA Rio Bravo Jasmin CFB SNCR Baghouse, pulse CA Rio Bravo Poso CFB SNCR Baghouse, pulse LA Rodemacher 3a SNCR Baghouse, pulse LA Rodemacher 3b SNCR Baghouse, pulse MT Yellowstone Energy LP BLR1 Baghouse, pulse MT Yellowstone Energy LP BLR2 Baghouse, pulse 
64 

Attachment 8. List of coal-fired electric utility steam generating units selected for HCl/HF/HCN acid 

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 

FL Crystal River 5 Bituminous Coal Electrostatic precipitator, cold side TX Oak Grove 1 Lignite Coal SCR Baghouse, pulse AR Plum Point Energy STG1 Subbituminous Coal SCR Baghouse, pulse AZ Springerville 4 Subbituminous Coal Bituminous Coal SCR Baghouse, pulse WY Two Elk Generating Station 1 Subbituminous Coal SCR Baghouse, pulse AZ Cholla 3 Subbituminous Coal Baghouse, pulse AZ Cholla 4 Subbituminous Coal Baghouse, pulse TX Sandow Station 5A Lignite Coal SCR Baghouse, pulse TX Sandow Station 5B Lignite Coal SCR Baghouse, pulse WI Elm Road Generating Station 1 Bituminous Coal SCR Baghouse, pulse NC G. G. Allen 1 Bituminous Coal Electrostatic precipitator, cold side NE Nebraska City 2 Subbituminous Coal Baghouse, pulse GA Wansley 2 Bituminous Coal SCR Electrostatic precipitator, cold side GA Bowen 2BLR Bituminous Coal SCR Electrostatic precipitator, cold side OH Conesville 4 Bituminous Coal Electrostatic precipitator, cold side SC Cross 4 Bituminous Coal SCR Electrostatic precipitator, cold side IL Dallman 34 Bituminous Coal SCR Baghouse, pulse VA Cogentrix Hopewell 1A Bituminous Coal Baghouse, pulse VA Cogentrix Hopewell 1B Bituminous Coal Baghouse, pulse VA Cogentrix Hopewell 1C Bituminous Coal Baghouse, pulse VA Cogentrix Virginia Leasing Corporation 2A Bituminous Coal Baghouse, pulse VA Cogentrix Virginia Leasing Corporation 2B Bituminous Coal Baghouse, pulse VA Cogentrix Virginia Leasing Corporation 2C Bituminous Coal Baghouse, pulse GA Bowen 4BLR Bituminous Coal SCR Electrostatic precipitator, cold side WV John E Amos 1 Bituminous Coal SCR Electrostatic precipitator, cold side WV John E Amos 2 Bituminous Coal SCR Electrostatic precipitator, cold side 
65 

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 

GA Wansley 1 Bituminous Coal SCR Electrostatic precipitator, cold side NV TS Power Plant BLR100 Subbituminous Coal SCR Baghouse, pulse WI Weston 4 Bituminous Coal Subbituminous Coal SCR Baghouse, pulse KY Ghent 4 Bituminous Coal Subbituminous Coal Electrostatic precipitator, hot side GA Bowen 3BLR Bituminous Coal SCR Electrostatic precipitator, cold side KY H. L. Spurlock 4 Bituminous Coal SNCR Baghouse, pulse NC Belews Creek 1 Bituminous Coal Electrostatic precipitator, cold side GA Hammond 1 Bituminous Coal Electrostatic precipitator, cold side GA Hammond 2 Bituminous Coal Electrostatic precipitator, cold side GA Hammond 3 Bituminous Coal Electrostatic precipitator, cold side GA Hammond 4 Bituminous Coal Electrostatic precipitator, cold side VA Cogentrix Hopewell 2A Bituminous Coal Baghouse, pulse VA Cogentrix Hopewell 2B Bituminous Coal Baghouse, pulse VA Cogentrix Hopewell 2C Bituminous Coal Baghouse, pulse VA Cogentrix Virginia Leasing Corporation 1A Bituminous Coal Baghouse, pulse VA Cogentrix Virginia Leasing Corporation 1B Bituminous Coal Baghouse, pulse VA Cogentrix Virginia Leasing Corporation 1C Bituminous Coal Baghouse, pulse WY Wygen II 4 Subbituminous Coal SCR Baghouse, pulse OH Cardinal 2 Bituminous Coal SCR Electrostatic precipitator, cold side WV John E. Amos 3 Bituminous Coal SCR Electrostatic precipitator, cold side IA Louisa 101 Subbituminous Coal Baghouse, pulse Electrostatic precipitator, hot side OH Cardinal 1 Bituminous Coal SCR Electrostatic precipitator, cold side IA Council Bluffs 4 Subbituminous Coal SCR Baghouse, pulse KY Ghent 3 Bituminous Coal Subbituminous Coal Electrostatic precipitator, hot side WV Mitchell 1 Bituminous Coal Electrostatic precipitator, cold side SC Cross 3 Bituminous Coal Coal-based Synfuel SCR Electrostatic precipitator, cold side 
66 

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 

WI Pleasant Prairie 2 Subbituminous Coal SCR Electrostatic precipitator, cold side WV Mountaineer 1 Bituminous Coal SCR Electrostatic precipitator, cold side AZ Springerville 3 Subbituminous Coal SCR Baghouse, pulse WV Mitchell 2 Bituminous Coal Electrostatic precipitator, cold side WI Pleasant Prairie 1 Subbituminous Coal SCR Electrostatic precipitator, cold side NC Marshall 1 Bituminous Coal Multiple cyclone 

Electrostatic precipitator, cold side 

MT Hardin Generator Project PC1 Subbituminous Coal SCR Baghouse, pulse NC Asheville 1 Bituminous Coal Electrostatic precipitator, cold side KY H. L. Spurlock 3 Bituminous Coal SNCR Baghouse, pulse PA Seward 1 Waste Coal Bituminous Coal SNCR Baghouse, pulse PA Seward 2 Waste Coal Bituminous Coal SNCR Baghouse, pulse IL Marion 123 Waste Coal Bituminous Coal Baghouse, pulse WY Wygen I 3 Subbituminous Coal SCR Baghouse, pulse CO Arapahoe 3 Subbituminous Coal Natural Gas Baghouse, reverse air CO Cherokee 2 Bituminous Coal Natural Gas Baghouse, reverse air CO Cherokee 4 Bituminous Coal Natural Gas Baghouse, reverse air PR AES Puerto Rico (Aurora) 1 Bituminous Coal SNCR Baghouse, pulse PR AES Puerto Rico (Aurora) 2 Bituminous Coal SNCR Baghouse, pulse CO Valmont 5 Subbituminous Coal Bituminous Coal Baghouse, reverse air CO Cherokee 3 Bituminous Coal Natural Gas Baghouse, reverse air WA Transalta Centralia Generation BW21 Subbituminous Coal Wet scrubber Electrostatic precipitator, cold side MS Red Hills Generating Facility AA001 Lignite Coal Baghouse, reverse air MS Red Hills Generating Facility AA002 Lignite Coal Baghouse, reverse air WV Mt. Storm 1 Bituminous Coal Electrostatic precipitator, cold side WV Mt. Storm 2 Bituminous Coal Electrostatic precipitator, cold side WA Transalta Centralia Generation BW22 Subbituminous Coal Wet scrubber Electrostatic precipitator, cold side 
67 

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 

PA Homer City Station 3 Bituminous Coal SCR Electrostatic precipitator, cold side IL Dallman 31 Bituminous Coal SCR Electrostatic precipitator, cold side IL Dallman 32 Bituminous Coal SCR Electrostatic precipitator, cold side MO Hawthorn 5A Subbituminous Coal Natural Gas SCR Baghouse, pulse AK Healy 1 Subbituminous Coal Baghouse, reverse air MD AES Warrior Run Cogeneration Facility BLR1 Bituminous Coal SNCR and SCR Baghouse, reverse air FL Big Bend BB01 Bituminous Coal Subbituminous Coal Electrostatic precipitator, cold side FL Big Bend BB02 Bituminous Coal Subbituminous Coal Electrostatic precipitator, cold side AZ Navajo 1 Bituminous Coal Electrostatic precipitator, hot side CO Hayden H2 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air OH Hamilton 9 Bituminous Coal Natural Gas Electrostatic precipitator, hot side Baghouse, pulse CO Hayden H1 Bituminous Coal Natural Gas Baghouse, reverse air AZ Navajo 2 Bituminous Coal Electrostatic precipitator, hot side NM San Juan 1 Subbituminous Coal Electrostatic precipitator, hot side NM San Juan 2 Subbituminous Coal Electrostatic precipitator, hot side NM San Juan 3 Subbituminous Coal Electrostatic precipitator, hot side NM San Juan 4 Subbituminous Coal Electrostatic precipitator, hot side CO Cherokee 1 Bituminous Coal Natural Gas Baghouse, reverse air AZ Navajo 3 Bituminous Coal Electrostatic precipitator, hot side VA Birchwood Power 1A Bituminous Coal SCR Baghouse, reverse air FL Stanton Energy Center 2 Bituminous Coal SCR Electrostatic precipitator, cold side IN AES Petersburg 1 Bituminous Coal Electrostatic precipitator, cold side IN AES Petersburg 2 Bituminous Coal Electrostatic precipitator, cold side VA Clover 2 Bituminous Coal Baghouse, reverse air FL Indiantown Cogeneration LP AAB01 Bituminous Coal SCR Baghouse, reverse air PA Conemaugh 2 Bituminous Coal Electrostatic precipitator, cold side Wet scrubber SC Cope COP1 Bituminous Coal Natural Gas Baghouse, reverse air 
68 

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 

WY Neil Simpson II 2 Subbituminous Coal Electrostatic precipitator, cold side VA Clover 1 Bituminous Coal Baghouse, reverse air PA Northampton Generating Company BLR1 Waste Coal Petroleum Coke SNCR Baghouse, pulse NY AES Cayuga 1 Bituminous Coal SCR Electrostatic precipitator, cold side NY AES Cayuga 2 Bituminous Coal Electrostatic precipitator, cold side KY HMP&L Station Two Henderson H1 Bituminous Coal Electrostatic precipitator, cold side KY HMP&L Station Two Henderson H2 Bituminous Coal Electrostatic precipitator, cold side NC Roanoke Valley II BLR2 Bituminous Coal Baghouse, pulse PA Colver Power Project ABB01 Waste Coal Baghouse, pulse SC Cross 1 Bituminous Coal Coal-based Synfuel SCR Electrostatic precipitator, cold side OH General James M Gavin 2 Bituminous Coal SCR Electrostatic precipitator, cold side NJ B. L. England 2 Bituminous Coal SNCR Electrostatic precipitator, cold side TN Cumberland 1 Bituminous Coal SCR Electrostatic precipitator, cold side TN Cumberland 2 Bituminous Coal Electrostatic precipitator, cold side IN F. B. Culley 2 Bituminous Coal Electrostatic precipitator, cold side IN F. B. Culley 3 Bituminous Coal SCR Electrostatic precipitator, cold side IN Gibson 4 Bituminous Coal Electrostatic precipitator, cold side WV Mt Storm 3 Bituminous Coal Electrostatic precipitator, cold side PA Conemaugh 1 Bituminous Coal Electrostatic precipitator, cold side Wet scrubber OH General James M Gavin 1 Bituminous Coal SCR Electrostatic precipitator, cold side KY Ghent 1 Bituminous Coal Electrostatic precipitator, cold side KY Elmer Smith 1 Bituminous Coal SCR Electrostatic precipitator, cold side KY Elmer Smith 2 Bituminous Coal SNCR Electrostatic precipitator, cold side WV Harrison Power Station 1 Bituminous Coal SCR Electrostatic precipitator, cold side Wet scrubber WV Harrison Power Station 2 Bituminous Coal SCR Electrostatic precipitator, cold side Wet scrubber WV Harrison Power Station 3 Bituminous Coal SCR Electrostatic precipitator, cold side Wet scrubber 
69 

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 

IN Whitewater Valley 2 Bituminous Coal Electrostatic precipitator, cold side NJ Logan Generating Plant B01 Bituminous Coal SCR Baghouse, reverse air NC Roanoke Valley I BLR1 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air NJ Chambers Cogeneration LP BOIL1 Bituminous Coal SCR Baghouse, reverse air NJ Chambers Cogeneration LP BOIL2 Bituminous Coal SCR Baghouse, reverse air FL Cedar Bay Generating LP CBA Bituminous Coal SNCR Baghouse, reverse air FL Cedar Bay Generating LP CBB Bituminous Coal SNCR Baghouse, reverse air FL Cedar Bay Generating LP CBC Bituminous Coal SNCR Baghouse, reverse air CO Arapahoe 4 Subbituminous Coal Natural Gas Baghouse, reverse air PA Scrubgrass Generating UNIT 1 Waste Coal SNCR Baghouse, pulse PA Scrubgrass Generating UNIT 2 Waste Coal SNCR Baghouse, pulse UT Sunnyside Cogen Associates 1 Waste Coal Baghouse, pulse WV North Branch 1A Bituminous Coal Waste Oil Baghouse, pulse WV North Branch 1B Bituminous Coal Waste Oil Baghouse, pulse TX J. K. Spruce BLR1 Subbituminous Coal Baghouse, reverse air VA Mecklenburg Power Station BLR1 Bituminous Coal Baghouse, pulse VA Mecklenburg Power Station BLR2 Bituminous Coal Baghouse, pulse PA Piney Creek Project BRBR1 Waste Coal SNCR Baghouse, pulse GA Yates Y1BR Bituminous Coal Natural Gas Electrostatic precipitator, cold side Wet scrubber HI AES Hawaii BLRA Subbituminous Coal Tire-derived Fuels SNCR Baghouse, reverse air HI AES Hawaii BLRB Subbituminous Coal Waste Oil SNCR Baghouse, reverse air VA Cogentrix of Richmond 3A Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 3B Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 4A Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 4B Bituminous Coal Baghouse, pulse WV Grant Town Power Plant BLR1A Waste Coal Baghouse, pulse WV Grant Town Power Plant BLR1B Waste Coal Baghouse, pulse IN Bailly 7 Bituminous Coal Natural Gas Electrostatic precipitator, cold side 
70 

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 

IN Bailly 8 Bituminous Coal Natural Gas SCR Electrostatic precipitator, cold side PA Panther Creek Energy Facility BLR1 Waste Coal SNCR Baghouse, pulse PA Panther Creek Energy Facility BLR2 Waste Coal SNCR Baghouse, pulse VA Cogentrix of Richmond 1A Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 1B Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 2A Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 2B Bituminous Coal Baghouse, pulse VA Altavista Power Station 1 Bituminous Coal SNCR Baghouse, pulse WV Morgantown Energy Facility CFB1 Waste Coal Baghouse, pulse WV Morgantown Energy Facility CFB2 Waste Coal Baghouse, pulse TX Twin Oaks Power One U2 Lignite Coal Baghouse, shake and deflate VA Southampton Power Station 1 Bituminous Coal Baghouse, pulse PA Ebensburg Power 031 Waste Coal Baghouse, pulse PA Cambria Cogen B1 Waste Coal SNCR Baghouse, shake and deflate PA Cambria Cogen B2 Waste Coal SNCR Baghouse, shake and deflate OH W. H. Zimmer 1 Bituminous Coal Electrostatic precipitator, cold side 
71 

Attachment 9. List of coal-fired electric utility steam generating units selected for dioxin/furan organ

State Plant Name 

Boiler 

ID Primary Fuel 

Secondary 

Fuel 

NOX

Control PM Control 1 PM Control 

CA ACE Cogeneration Facility CFB Bituminous Coal Petroleum Coke Baghouse, reverse air CT AES Thames A Bituminous Coal Baghouse, reverse air CT AES Thames B Bituminous Coal Baghouse, reverse air VA Altavista Power Station 1 Bituminous Coal SNCR Baghouse, pulse NY Black River Generation E0003 Bituminous Coal Baghouse, pulse Multiple cyclone VA Chesterfield 6 Bituminous Coal Electrostatic precipitator, cold side NC 

Cogentrix Dwayne Collier Battle Cogen 

1A Bituminous Coal Baghouse, pulse 

VA Cogentrix of Richmond 4A Bituminous Coal Baghouse, pulse IA Council Bluffs 4 Subbituminous Coal SCR Baghouse, pulse CO Craig C2 Subbituminous Coal Baghouse, pulse TN Cumberland 1 Bituminous Coal SCR Electrostatic precipitator, cold side WY Dave Johnston BW41 Subbituminous Coal Electrostatic precipitator, cold side DE Edge Moor 4 Bituminous Coal Residual Fuel Oil Electrostatic precipitator, cold side KY Green River 5 Bituminous Coal Electrostatic precipitator, hot side KY H. L. Spurlock 2 Bituminous Coal SCR Electrostatic precipitator, hot side IL Havana 9 Subbituminous Coal SCR Electrostatic precipitator, hot side Baghouse, pulse IL Hennepin Power Station 2 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side MN Hoot Lake 3 Subbituminous Coal Electrostatic precipitator, cold side TX J. K. Spruce BLR1 Subbituminous Coal Baghouse, reverse air WV Kammer 1 Bituminous Coal Electrostatic precipitator, cold side WV Kammer 2 Bituminous Coal Electrostatic precipitator, cold side IL Marion 4 Bituminous Coal Waste Coal SCR Electrostatic precipitator, cold side ND Milton R Young B1 Lignite Coal Electrostatic precipitator, cold side MI Monroe 3 Subbituminous Coal Bituminous Coal SCR Electrostatic precipitator, cold side OK Northeastern 3314 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side IA Prairie Creek 4 Subbituminous Coal Landfill Gas Electrostatic precipitator, cold side NC Primary Energy Southport 1C Bituminous Coal Baghouse, pulse 
72 

State Plant Name 

Boiler 

ID Primary Fuel 

Secondary 

Fuel 

NOX

Control PM Control 1 PM Control 

CO Ray D. Nixon 1 Subbituminous Coal Baghouse, reverse air NC Roanoke Valley I BLR1 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air GA Scherer 1 Subbituminous Coal Electrostatic precipitator, hot side GA Scherer 3 Subbituminous Coal Electrostatic precipitator, cold side PA Shawville 3 Bituminous Coal Electrostatic precipitator, cold side MN Silver Bay Power BLR2 Subbituminous Coal Natural Gas Baghouse, reverse air ND Stanton 1 Subbituminous Coal Electrostatic precipitator, cold side IN State Line Energy 3 Subbituminous Coal Baghouse, pulse IA Streeter Station 7 Bituminous Coal Subbituminous Coal Electrostatic precipitator, hot side KS Tecumseh Energy Center 9 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side MI TES Filer City Station 2 Bituminous Coal Baghouse, pulse WA Transalta Centralia Generation BW21 Subbituminous Coal Wet scrubber Electrostatic precip

cold side 

NY Trigen Syracuse Energy 2 Bituminous Coal Baghouse, reverse air TX Twin Oaks Power One U2 Lignite Coal Baghouse, shake and deflate WY Two Elk Generating Station 1 Subbituminous Coal SCR Baghouse, pulse IL Vermilion 1 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side Baghouse, pulse OH Walter C Beckjord 5 Bituminous Coal Electrostatic precipitator, cold side IL Waukegan 8 Subbituminous Coal Electrostatic precipitator, cold side AL Widows Creek 2 Bituminous Coal Electrostatic precipitator, cold side AL Widows Creek 7 Bituminous Coal Electrostatic precipitator, cold side Wet scrubber AL Widows Creek 8 Bituminous Coal Wet scrubber SC Winyah 1 Bituminous Coal Coal-based Synfuel Electrostatic precipitator, cold side Wet scrubber SC Winyah 2 Bituminous Coal Coal-based Synfuel Electrostatic precipitator, cold side 
Shaded units are required to do all organic testing. 

73 

Attachment 10. List of coal-fired electric utility steam generating units selected for non-dioxin/furan or

State Plant Name Boiler ID Primary Fuel Secondary Fuel Boiler Date NOX Control PM Control 1 

TX Oak Grove 1 Lignite Coal 12/31/2009 SCR Baghouse, pulse AR Plum Point Energy STG1 Subbituminous Coal 12/31/2009 SCR Baghouse, pulse AZ Springerville 4 Subbituminous Coal Bituminous Coal 12/31/2009 SCR Baghouse, pulse WY 

Two Elk Generating Station 

1 Subbituminous Coal 12/31/2009 SCR Baghouse, pulse 

TX Sandow Station 5A Lignite Coal 8/31/2009 SCR Baghouse, pulse TX Sandow Station 5B Lignite Coal 8/31/2009 SCR Baghouse, pulse WI 

Elm Road Generating Station 

1 Bituminous Coal 6/1/2009 SCR Baghouse, pulse 

NE Nebraska City 2 Subbituminous Coal 5/1/2009 Baghouse, pulse SC Cross 4 Bituminous Coal 1/1/2009 SCR Electrostatic precipitator, cold side IL Dallman 34 Bituminous Coal 1/1/2009 SCR Baghouse, pulse NV TS Power Plant BLR100 Subbituminous Coal 6/1/2008 SCR Baghouse, pulse WI Weston 4 Bituminous Coal Subbituminous Coal 6/1/2008 SCR Baghouse, pulse KY H. L. Spurlock 4 Bituminous Coal 4/1/2008 SNCR Baghouse, pulse WY Wygen II 4 Subbituminous Coal 12/31/2007 SCR Baghouse, pulse IA Council Bluffs 4 Subbituminous Coal 6/1/2007 SCR Baghouse, pulse SC Cross 3 Bituminous Coal Coal-based Synfuel 1/1/2007 SCR Electrostatic precipitator, cold side AZ Springerville 3 Subbituminous Coal 12/31/2006 SCR Baghouse, pulse MT 

Hardin Generator Project 

PC1 Subbituminous Coal 4/1/2006 SCR Baghouse, pulse 

KY H. L. Spurlock 3 Bituminous Coal 4/1/2005 SNCR Baghouse, pulse PA Seward 1 Waste Coal Bituminous Coal 3/1/2004 SNCR Baghouse, pulse PA Seward 2 Waste Coal Bituminous Coal 3/1/2004 SNCR Baghouse, pulse IL Marion 123 Waste Coal Bituminous Coal 5/1/2003 Baghouse, pulse WY Wygen I 3 Subbituminous Coal 5/1/2003 SCR Baghouse, pulse PR AES Puerto Rico (Aurora) 1 Bituminous Coal 12/31/2002 SNCR Baghouse, pulse PR AES Puerto Rico (Aurora) 2 Bituminous Coal 12/31/2002 SNCR Baghouse, pulse 
Shaded units are required to do all organic testing. 

74 

State Plant Name Boiler ID Primary Fuel Secondary Fuel Boiler Date NOX Control PM Control 1 

MS 

Red Hills Generating Facility 

AA001 Lignite Coal 3/1/2002 Baghouse, reverse air 

MS 

Red Hills Generating Facility 

AA002 Lignite Coal 3/1/2002 Baghouse, reverse air 

MO Hawthorn 5A Subbituminous Coal Natural Gas 6/1/2001 SCR Baghouse, pulse MD 

AES Warrior Run Cogeneration Facility 

BLR1 Bituminous Coal 2/1/2000 SCR and SNCR Baghouse, reverse air 

VA Birchwood Power 1A Bituminous Coal 12/1/1996 SCR Baghouse, reverse air FL Stanton Energy Center 2 Bituminous Coal 6/1/1996 SCR Electrostatic precipitator, cold side VA Clover 2 Bituminous Coal 3/1/1996 Baghouse, reverse air FL 

Indiantown Cogeneration LP 

AAB01 Bituminous Coal 12/1/1995 SCR Baghouse, reverse air 

SC Cope COP1 Bituminous Coal Natural Gas 11/1/1995 Baghouse, reverse air WY Neil Simpson II 2 Subbituminous Coal 11/1/1995 Electrostatic precipitator, cold side VA Clover 1 Bituminous Coal 10/1/1995 Baghouse, reverse air PA 

Northampton Generating Company 

BLR1 Waste Coal Petroleum Coke 8/1/1995 SNCR Baghouse, pulse 

NC Roanoke Valley II BLR2 Bituminous Coal 6/1/1995 Baghouse, pulse PA Colver Power Project ABB01 Waste Coal 5/1/1995 Baghouse, pulse SC Cross 1 Bituminous Coal Coal-based Synfuel 5/1/1995 SCR Electrostatic precipitator, cold side NJ 

Logan Generating Plant 

B01 Bituminous Coal 9/1/1994 SCR Baghouse, reverse air 

NC Roanoke Valley I BLR1 Bituminous Coal Distillate Fuel Oil 5/1/1994 Baghouse, reverse air NJ 

Chambers Cogeneration LP 

BOIL1 Bituminous Coal 3/1/1994 SCR Baghouse, reverse air 

NJ 

Chambers Cogeneration LP 

BOIL2 Bituminous Coal 3/1/1994 SCR Baghouse, reverse air 

FL Cedar Bay Generating LP CBA Bituminous Coal 1/1/1994 SNCR Baghouse, reverse air FL Cedar Bay Generating LP CBB Bituminous Coal 1/1/1994 SNCR Baghouse, reverse air 
Shaded units are required to do all organic testing. 

75 

State Plant Name Boiler ID Primary Fuel Secondary Fuel Boiler Date NOX Control PM Control 1 

FL Cedar Bay Generating LP CBC Bituminous Coal 1/1/1994 SNCR Baghouse, reverse air PA Scrubgrass Generating UNIT 1 Waste Coal 6/1/1993 SNCR Baghouse, pulse PA Scrubgrass Generating UNIT 2 Waste Coal 6/1/1993 SNCR Baghouse, pulse UT 

Sunnyside Cogen Associates 

1 Waste Coal 2/1/1993 Baghouse, pulse 

WV North Branch 1A Bituminous Coal Waste Oil 12/31/1992 Baghouse, pulse WV North Branch 1B Bituminous Coal Waste Oil 12/31/1992 Baghouse, pulse TX J. K. Spruce BLR1 Subbituminous Coal 12/1/1992 Baghouse, reverse air PA Piney Creek Project BRBR1 Waste Coal 12/1/1992 SNCR Baghouse, pulse VA Mecklenburg Power Station BLR1 Bituminous Coal 11/1/1992 Baghouse, pulse VA Mecklenburg Power Station BLR2 Bituminous Coal 11/1/1992 Baghouse, pulse HI AES Hawaii BLRA Subbituminous Coal Tire-derived Fuels 9/1/1992 SNCR Baghouse, reverse air HI AES Hawaii BLRB Subbituminous Coal Waste Oil 9/1/1992 SNCR Baghouse, reverse air VA Cogentrix of Richmond 3A Bituminous Coal 8/1/1992 Baghouse, pulse VA Cogentrix of Richmond 3B Bituminous Coal 8/1/1992 Baghouse, pulse VA Cogentrix of Richmond 4A Bituminous Coal 8/1/1992 Baghouse, pulse VA Cogentrix of Richmond 4B Bituminous Coal 8/1/1992 Baghouse, pulse WV Grant Town Power Plant BLR1A Waste Coal 8/1/1992 Baghouse, pulse WV Grant Town Power Plant BLR1B Waste Coal 8/1/1992 Baghouse, pulse PA Panther Creek Energy Facility BLR1 Waste Coal 6/1/1992 SNCR Baghouse, pulse PA Panther Creek Energy Facility BLR2 Waste Coal 6/1/1992 SNCR Baghouse, pulse VA Cogentrix of Richmond 1A Bituminous Coal 5/1/1992 Baghouse, pulse VA Cogentrix of Richmond 1B Bituminous Coal 5/1/1992 Baghouse, pulse VA Cogentrix of Richmond 2A Bituminous Coal 5/1/1992 Baghouse, pulse VA Cogentrix of Richmond 2B Bituminous Coal 5/1/1992 Baghouse, pulse VA Altavista Power Station 1 Bituminous Coal 2/1/1992 SNCR Baghouse, pulse 
Shaded units are required to do all organic testing. 

76 

State Plant Name Boiler ID Primary Fuel Secondary Fuel Boiler Date NOX Control PM Control 1 

WV Morgantown Energy Facility CFB1 Waste Coal 1/1/1992 Baghouse, pulse WV Morgantown Energy Facility CFB2 Waste Coal 1/1/1992 Baghouse, pulse TX Twin Oaks Power One U2 Lignite Coal 10/1/1991 Baghouse, shake and deflate VA Southampton Power Station 1 Bituminous Coal 6/1/1991 Baghouse, pulse MD Brandon Shores 2 Bituminous Coal 5/1/1991 SCR Electrostatic precipitator, hot side PA Ebensburg Power 031 Waste Coal 5/1/1991 Baghouse, pulse PA Cambria Cogen B1 Waste Coal 3/1/1991 SNCR Baghouse, shake and deflate PA Cambria Cogen B2 Waste Coal 3/1/1991 SNCR Baghouse, shake and deflate AL James H Miller Jr. 4 Subbituminous Coal 3/1/1991 SCR Electrostatic precipitator, cold side OH W. H. Zimmer 1 Bituminous Coal 3/1/1991 Electrostatic precipitator, cold side OK AES Shady Point 1A Bituminous Coal 1/1/1991 Baghouse, pulse OK AES Shady Point 1B Bituminous Coal 1/1/1991 Baghouse, pulse OK AES Shady Point 2A Bituminous Coal 1/1/1991 Baghouse, pulse OK AES Shady Point 2B Bituminous Coal 1/1/1991 Baghouse, pulse CO Nucla 1 Bituminous Coal 1/1/1991 Baghouse, shake and deflate NY 

Trigen Syracuse Energy 

1 Bituminous Coal 1/1/1991 Baghouse, reverse air 

NY 

Trigen Syracuse Energy 

2 Bituminous Coal 1/1/1991 Baghouse, reverse air 

NY 

Trigen Syracuse Energy 

3 Bituminous Coal 1/1/1991 Baghouse, reverse air 

NY 

Trigen Syracuse Energy 

4 Bituminous Coal 1/1/1991 Baghouse, reverse air 

NY 

Trigen Syracuse Energy 

5 Bituminous Coal 1/1/1991 Baghouse, reverse air 

KY Shawnee 10 Bituminous Coal 12/1/1990 Baghouse, reverse air KY Trimble County 1 Bituminous Coal 12/1/1990 SCR Electrostatic precipitator, cold side NC 

Cogentrix Dwayne Collier Battle Cogen 

1A Bituminous Coal 10/1/1990 Baghouse, pulse 
Shaded units are required to do all organic testing. 

77 

State Plant Name Boiler ID Primary Fuel Secondary Fuel Boiler Date NOX Control PM Control 1 

NC 

Cogentrix Dwayne Collier Battle Cogen 

1B Bituminous Coal 10/1/1990 Baghouse, pulse 

NC 

Cogentrix Dwayne Collier Battle Cogen 

2A Bituminous Coal 10/1/1990 Baghouse, pulse 

NC 

Cogentrix Dwayne Collier Battle Cogen 

2B Bituminous Coal 10/1/1990 Baghouse, pulse 

PA 

Foster Wheeler Mt Carmel Cogen 

SG-101 Waste Coal 9/1/1990 Baghouse, pulse 

TX Twin Oaks Power One U1 Lignite Coal 9/1/1990 Baghouse, shake and deflate CA 

ACE Cogeneration Facility 

CFB Bituminous Coal Petroleum Coke 6/1/1990 Baghouse, reverse air 

WI Manitowoc 8 Bituminous Coal Petroleum Coke 6/1/1990 Single cyclone AZ Springerville 2 Subbituminous Coal 6/1/1990 Baghouse, reverse air MI TES Filer City Station 1 Bituminous Coal 6/1/1990 Baghouse, pulse MI TES Filer City Station 2 Bituminous Coal 6/1/1990 Baghouse, pulse NY WPS Power Niagara 1 Bituminous Coal 4/1/1990 SNCR Baghouse, pulse CT AES Thames A Bituminous Coal 3/1/1990 Baghouse, reverse air CT AES Thames B Bituminous Coal 3/1/1990 Baghouse, reverse air MT Colstrip Energy LP BLR1 Waste Coal 2/1/1990 Baghouse, pulse IN Rockport MB2 Subbituminous Coal 12/1/1989 Electrostatic precipitator, cold side PA St. Nicholas Cogen Project 1 Waste Coal 12/1/1989 Baghouse, pulse PA 

Kline Township Cogen Facility 

1 Waste Coal 11/1/1989 Single cyclone 

AL James H Miller Jr. 3 Subbituminous Coal 5/1/1989 SCR Electrostatic precipitator, cold side GA Scherer 4 Subbituminous Coal 2/1/1989 Electrostatic precipitator, cold side PA 

Wheelabrator Frackville Energy 

BLR1 Waste Coal 9/1/1988 Baghouse, pulse 

NY Black River Generation E0001 Bituminous Coal 6/1/1988 Baghouse, pulse NY Black River Generation E0002 Bituminous Coal 6/1/1988 Baghouse, pulse 
Shaded units are required to do all organic testing. 

78 

State Plant Name Boiler ID Primary Fuel Secondary Fuel Boiler Date NOX Control PM Control 1 

NY Black River Generation E0003 Bituminous Coal 6/1/1988 Baghouse, pulse FL Central Power & Lime 1 Bituminous Coal 6/1/1988 Baghouse, reverse air VA 

Cogentrix Virginia Leasing Corporation 

1A Bituminous Coal 6/1/1988 Baghouse, pulse 

VA 

Cogentrix Virginia Leasing Corporation 

1B Bituminous Coal 6/1/1988 Baghouse, pulse 

VA 

Cogentrix Virginia Leasing Corporation 

1C Bituminous Coal 6/1/1988 Baghouse, pulse 

VA 

Cogentrix Virginia Leasing Corporation 

2A Bituminous Coal 6/1/1988 Baghouse, pulse 

VA 

Cogentrix Virginia Leasing Corporation 

2B Bituminous Coal 6/1/1988 Baghouse, pulse 

VA 

Cogentrix Virginia Leasing Corporation 

2C Bituminous Coal 6/1/1988 Baghouse, pulse 

CA Mt. Poso Cogeneration BL01 Bituminous Coal 6/1/1988 SNCR Baghouse, reverse air PA 

WPS Westwood Generation LLC 

031 Waste Coal 6/1/1988 Baghouse, reverse air 

FL St Johns River Power Park 2 Bituminous Coal Coal-based Synfuel 5/1/1988 Electrostatic precipitator, cold side TX Fayette Power Project 3 Subbituminous Coal 4/1/1988 Electrostatic precipitator, cold side PA 

John B Rich Memorial Power Station 

CFB1 Waste Coal 2/1/1988 Baghouse, pulse 

PA 

John B Rich Memorial Power Station 

CFB2 Waste Coal 2/1/1988 Baghouse, pulse 

VA Cogentrix Hopewell 1A Bituminous Coal 12/1/1987 Baghouse, pulse VA Cogentrix Hopewell 1B Bituminous Coal 12/1/1987 Baghouse, pulse VA Cogentrix Hopewell 1C Bituminous Coal 12/1/1987 Baghouse, pulse 
Shaded units are required to do all organic testing. 

79 

State Plant Name Boiler ID Primary Fuel Secondary Fuel Boiler Date NOX Control PM Control 1 

VA Cogentrix Hopewell 2A Bituminous Coal 12/1/1987 Baghouse, pulse VA Cogentrix Hopewell 2B Bituminous Coal 12/1/1987 Baghouse, pulse VA Cogentrix Hopewell 2C Bituminous Coal 12/1/1987 Baghouse, pulse MN Sherburne County 3 Subbituminous Coal 11/1/1987 Baghouse, reverse air NY 

Danskammer Generating Station 

3 Bituminous Coal Natural Gas 9/1/1987 Electrostatic precipitator, cold side 

NC Primary Energy Southport 1A Bituminous Coal 9/1/1987 Baghouse, pulse NC Primary Energy Southport 1B Bituminous Coal 9/1/1987 Baghouse, pulse NC Primary Energy Southport 1C Bituminous Coal 9/1/1987 Baghouse, pulse NC Primary Energy Southport 2A Bituminous Coal 9/1/1987 Baghouse, pulse NC Primary Energy Southport 2B Bituminous Coal 9/1/1987 Baghouse, pulse NC Primary Energy Southport 2C Bituminous Coal 9/1/1987 Baghouse, pulse NC Primary Energy Roxboro 1A Bituminous Coal 8/1/1987 Baghouse, pulse NC Primary Energy Roxboro 1B Bituminous Coal 8/1/1987 Baghouse, pulse NC Primary Energy Roxboro 1C Bituminous Coal 8/1/1987 Baghouse, pulse PA 

AES Beaver Valley Partners Beaver Valley 

2 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side 

PA 

AES Beaver Valley Partners Beaver Valley 

3 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side 

PA 

AES Beaver Valley Partners Beaver Valley 

4 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side 

PA 

AES Beaver Valley Partners Beaver Valley 

5 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side 

FL Stanton Energy Center 1 Bituminous Coal 7/1/1987 Electrostatic precipitator, cold side UT Intermountain Power Project 2SGA Bituminous Coal Subbituminous Coal 5/1/1987 Baghouse, reverse air NY 

Danskammer Generating Station 

4 Bituminous Coal Natural Gas 3/1/1987 Electrostatic precipitator, cold side 

FL St. Johns River Power Park 1 Bituminous Coal Coal-based Synfuel 3/1/1987 Electrostatic precipitator, cold side 
Shaded units are required to do all organic testing. 

80 

State Plant Name Boiler ID Primary Fuel Secondary Fuel Boiler Date NOX Control PM Control 1 

GA Scherer 3 Subbituminous Coal 1/1/1987 Electrostatic precipitator, cold side TX Oklaunion 1 Bituminous Coal 12/1/1986 Electrostatic precipitator, cold side KY D. B. Wilson W1 Bituminous Coal 11/1/1986 Electrostatic precipitator, cold side TX Limestone LIM2 Lignite Coal Subbituminous Coal 10/1/1986 Electrostatic precipitator, cold side ND Antelope Valley B2 Lignite Coal 7/1/1986 Baghouse, reverse air UT Intermountain Power Project 1SGA Bituminous Coal Subbituminous Coal 6/1/1986 Baghouse, reverse air UT Bonanza 1-1 Bituminous Coal 5/1/1986 Baghouse, reverse air IN AES Petersburg 4 Bituminous Coal 4/1/1986 Electrostatic precipitator, cold side MT Colstrip 4 Subbituminous Coal 4/1/1986 Wet scrubber LA Dolet Hills 1 Lignite Coal Natural Gas 4/1/1986 Electrostatic precipitator, cold side OK GRDA 2 Subbituminous Coal 4/1/1986 Electrostatic precipitator, cold side IN A. B. Brown 2 Bituminous Coal 2/1/1986 SCR Electrostatic precipitator, cold side IN R. M. Schahfer 18 Bituminous Coal 2/1/1986 Electrostatic precipitator, cold side TX Limestone LIM1 Lignite Coal Subbituminous Coal 10/1/1985 Electrostatic precipitator, cold side MI Belle River 2 Subbituminous Coal 7/1/1985 Electrostatic precipitator, cold side NV North Valmy 2 Bituminous Coal Subbituminous Coal 7/1/1985 Baghouse, reverse air WI Pleasant Prairie 2 Subbituminous Coal 7/1/1985 Electrostatic precipitator, cold side TX Tolk 172B Subbituminous Coal 7/1/1985 Baghouse, reverse air AZ Springerville 1 Subbituminous Coal 6/1/1985 Baghouse, reverse air AL James H Miller Jr. 2 Subbituminous Coal 5/1/1985 Electrostatic precipitator, cold side 
81 

Attachment 11. List of coal-fired electric utility steam generating units selected for mercury and other non-mer

State Plant Name Boiler ID Primary Fuel Secondary Fuel 

NOX

Control PM Control 1 PM Control 2 PM 

TX Oak Grove 1 Lignite Coal SCR Baghouse, pulse AR Plum Point Energy STG1 Subbituminous Coal SCR Baghouse, pulse AZ Springerville 4 Subbituminous Coal Bituminous Coal SCR Baghouse, pulse WY 

Two Elk Generating Station 

1 Subbituminous Coal 

SCR 

Baghouse, pulse 

AZ Cholla 3 Subbituminous Coal Baghouse, pulse AZ Cholla 4 Subbituminous Coal Baghouse, pulse TX Sandow Station 5A Lignite Coal SCR Baghouse, pulse TX Sandow Station 5B Lignite Coal SCR Baghouse, pulse WI 

Elm Road Generating Station 

1 Bituminous Coal 

SCR 

Baghouse, pulse 

NE Nebraska City 2 Subbituminous Coal Baghouse, pulse SC Cross 4 Bituminous Coal SCR Electrostatic precipitator, cold side IL Dallman 34 Bituminous Coal SCR Baghouse, pulse NM San Juan 1 Subbituminous Coal Baghouse, pulse NM San Juan 2 Subbituminous Coal Baghouse, pulse NM San Juan 3 Subbituminous Coal Baghouse, pulse NM San Juan 4 Subbituminous Coal Baghouse, pulse NV TS Power Plant BLR100 Subbituminous Coal SCR Baghouse, pulse WI Weston 4 Bituminous Coal Subbituminous Coal SCR Baghouse, pulse IL Hennepin Power Station 2 Subbituminous Coal Natural Gas Baghouse, pulse KY H. L. Spurlock 4 Bituminous Coal SNCR Baghouse, pulse WY Wygen II 4 Subbituminous Coal SCR Baghouse, pulse IA Louisa 101 Subbituminous Coal Baghouse, pulse 

Electrostatic precipitator, hot side 

IA Council Bluffs 4 Subbituminous Coal SCR Baghouse, pulse SC Cross 3 Bituminous Coal Coal-based Synfuel SCR Electrostatic precipitator, cold side AZ Springerville 3 Subbituminous Coal SCR Baghouse, pulse 
82 

State Plant Name Boiler ID Primary Fuel Secondary Fuel 

NOX

Control PM Control 1 PM Control 2 PM 

MT 

Hardin Generator Project 

PC1 Subbituminous Coal 

SCR 

Baghouse, pulse 

NC Asheville 1 Bituminous Coal Electrostatic precipitator, cold side IN A. B. Brown 1 Bituminous Coal 

SCR 

Baghouse, pulse 

Electrostatic precipitator, cold side 

KY H. L. Spurlock 3 Bituminous Coal SNCR Baghouse, pulse KY Cane Run 5 Bituminous Coal Coal-based Synfuel Electrostatic precipitator, cold side CO Craig C2 Subbituminous Coal Baghouse, pulse FL Crist 7 Bituminous Coal Natural Gas SCR Electrostatic precipitator, cold side PA Seward 1 Waste Coal Bituminous Coal SNCR Baghouse, pulse PA Seward 2 Waste Coal Bituminous Coal SNCR Baghouse, pulse CO Craig C1 Subbituminous Coal Baghouse, pulse IL Marion 123 Waste Coal Bituminous Coal Baghouse, pulse KY H. L. Spurlock 1 Bituminous Coal SCR Electrostatic precipitator, cold side WY Wygen I 3 Subbituminous Coal SCR Baghouse, pulse PR AES Puerto Rico (Aurora) 1 Bituminous Coal SNCR Baghouse, pulse PR AES Puerto Rico (Aurora) 2 Bituminous Coal SNCR Baghouse, pulse SD Big Stone 1 Subbituminous Coal Baghouse, pulse MD Herbert A Wagner 2 Bituminous Coal Electrostatic precipitator, cold side WA 

Transalta Centralia Generation 

BW21 Subbituminous Coal Wet scrubber 

Electrostatic precipitator, cold side 

MS 

Red Hills Generating Facility 

AA001 Lignite Coal Baghouse, reverse air 

MS 

Red Hills Generating Facility 

AA002 Lignite Coal Baghouse, reverse air 

WA 

Transalta Centralia Generation 

BW22 Subbituminous Coal Wet scrubber 

Electrostatic precipitator, cold side 

MI J. H. Campbell 1 Bituminous Coal Subbituminous Coal Electrostatic precipitator, cold side 
83 

State Plant Name Boiler ID Primary Fuel Secondary Fuel 

NOX

Control PM Control 1 PM Control 2 PM 

NE Gerald Gentleman 2 Subbituminous Coal Baghouse, reverse air MO Hawthorn 5A Subbituminous Coal Natural Gas SCR Baghouse, pulse WI Weston 3 Subbituminous Coal Baghouse, pulse PA PPL Montour 1 Bituminous Coal SCR Electrostatic precipitator, cold side GA Hammond 1 Bituminous Coal Electrostatic precipitator, cold side NE Gerald Gentleman 1 Subbituminous Coal Baghouse, reverse air PA PPL Montour 2 Bituminous Coal SCR Electrostatic precipitator, cold side IL Will County 4 Subbituminous Coal Electrostatic precipitator, cold side MD 

AES Warrior Run Cogeneration Facility 

BLR1 Bituminous Coal SCR and 

SNCR 

Baghouse, reverse air 

PA PPL Brunner Island 2 Bituminous Coal Electrostatic precipitator, cold side NE Sheldon 2 Subbituminous Coal Natural Gas Baghouse, pulse NE Sheldon 1 Subbituminous Coal Natural Gas Baghouse, pulse NC Cape Fear 5 Bituminous Coal Electrostatic precipitator, cold side NH Merrimack 2 Bituminous Coal SCR Electrostatic precipitator, cold side CO Hayden H2 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air SC Canadys Steam CAN3 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air IA Muscatine Plant #1 8 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side IN State Line Energy 3 Subbituminous Coal Baghouse, pulse CO Hayden H1 Bituminous Coal Natural Gas Baghouse, reverse air MI Erickson Station 1 Subbituminous Coal Electrostatic precipitator, cold side NC Asheville 2 Bituminous Coal Electrostatic precipitator, cold side CO Martin Drake 5 Subbituminous Coal Natural Gas Baghouse, reverse air SC H. B. Robinson 1 Bituminous Coal Electrostatic precipitator, cold side GA Hammond 2 Bituminous Coal Electrostatic precipitator, cold side 
84 

State Plant Name Boiler ID Primary Fuel Secondary Fuel 

NOX

Control PM Control 1 PM Control 2 PM 

NC Roxboro 2 Bituminous Coal Electrostatic precipitator, cold side VA Birchwood Power 1A Bituminous Coal SCR Baghouse, reverse air FL Stanton Energy Center 2 Bituminous Coal SCR Electrostatic precipitator, cold side VA Clover 2 Bituminous Coal Baghouse, reverse air IL Waukegan 8 Subbituminous Coal Electrostatic precipitator, cold side FL 

Indiantown Cogeneration LP 

AAB01 Bituminous Coal 

SCR 

Baghouse, reverse air 

SC Cope COP1 Bituminous Coal Natural Gas Baghouse, reverse air WY Neil Simpson II 2 Subbituminous Coal Electrostatic precipitator, cold side PA 

Northampton Generating Company 

BLR1 Waste Coal Petroleum Coke 

SNCR 

Baghouse, pulse 

WI Valley 3 Bituminous Coal Baghouse, pulse WI Valley 4 Bituminous Coal Baghouse, pulse NC Roanoke Valley II BLR2 Bituminous Coal Baghouse, pulse NC Roxboro 1 Bituminous Coal SCR Electrostatic precipitator, cold side PA Colver Power Project ABB01 Waste Coal Baghouse, pulse SC Cross 1 Bituminous Coal Coal-based Synfuel SCR Electrostatic precipitator, cold side IN Eagle Valley 6 Bituminous Coal Electrostatic precipitator, cold side IN Harding Street 60 Bituminous Coal 

SNCR 

Multiple cyclone 

Electrostatic precipitator, cold side 

VA Clover 1 Bituminous Coal Baghouse, reverse air WI Manitowoc 6 Bituminous Coal Multiple cyclone Baghouse, pulse WI Manitowoc 7 Bituminous Coal Multiple cyclone Baghouse, pulse NJ 

Logan Generating Plant 

B01 Bituminous Coal 

SCR 

Baghouse, reverse air 

WI Valley 1 Bituminous Coal Baghouse, pulse WI Valley 2 Bituminous Coal Baghouse, pulse 
85 

State Plant Name Boiler ID Primary Fuel Secondary Fuel 

NOX

Control PM Control 1 PM Control 2 PM 

FL Crist 6 Bituminous Coal Natural Gas Electrostatic precipitator, cold side IN Harding Street 70 Bituminous Coal SCR Electrostatic precipitator, cold side NJ 

PSEG Mercer Generating Station 

1 Bituminous Coal Natural Gas SCR and 

SNCR 

Electrostatic precipitator, cold side 

GA Hammond 4 Bituminous Coal SCR Electrostatic precipitator, cold side NC Roanoke Valley I BLR1 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air MO James River Power Station 5 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side NJ 

Chambers Cogeneration LP 

BOIL1 Bituminous Coal 

SCR 

Baghouse, reverse air 

NJ 

Chambers Cogeneration LP 

BOIL2 Bituminous Coal 

SCR 

Baghouse, reverse air 

FL Cedar Bay Generating LP CBA Bituminous Coal SNCR Baghouse, reverse air FL Cedar Bay Generating LP CBB Bituminous Coal SNCR Baghouse, reverse air FL Cedar Bay Generating LP CBC Bituminous Coal SNCR Baghouse, reverse air KY Elmer Smith 1 Bituminous Coal SCR Electrostatic precipitator, cold side CO Martin Drake 7 Subbituminous Coal Natural Gas Baghouse, reverse air IN Gibson 2 Bituminous Coal Electrostatic precipitator, cold side KY Elmer Smith 2 Bituminous Coal SNCR Electrostatic precipitator, cold side GA Hammond 3 Bituminous Coal Electrostatic precipitator, cold side PA Scrubgrass Generating UNIT 1 Waste Coal SNCR Baghouse, pulse PA Scrubgrass Generating UNIT 2 Waste Coal SNCR Baghouse, pulse SC McMeekin MCM1 Coal-based Synfuel Bituminous Coal Baghouse, reverse air MO Sibley 1 Subbituminous Coal Electrostatic precipitator, cold side MO Sibley 3 Subbituminous Coal Electrostatic precipitator, cold side KY Cane Run 4 Bituminous Coal Coal-based Synfuel Electrostatic precipitator, cold side 
86 

State Plant Name Boiler ID Primary Fuel Secondary Fuel 

NOX

Control PM Control 1 PM Control 2 PM 

UT 

Sunnyside Cogen Associates 

1 Waste Coal Baghouse, pulse 

WV North Branch 1A Bituminous Coal Waste Oil Baghouse, pulse WV North Branch 1B Bituminous Coal Waste Oil Baghouse, pulse TX J. K. Spruce BLR1 Subbituminous Coal Baghouse, reverse air PA Piney Creek Project BRBR1 Waste Coal SNCR Baghouse, pulse VA Mecklenburg Power Station BLR1 Bituminous Coal Baghouse, pulse VA Mecklenburg Power Station BLR2 Bituminous Coal Baghouse, pulse IL Meredosia 05 Subbituminous Coal Bituminous Coal Electrostatic precipitator, cold side HI AES Hawaii BLRA Subbituminous Coal Tire-derived Fuels SNCR Baghouse, reverse air HI AES Hawaii BLRB Subbituminous Coal Waste Oil SNCR Baghouse, reverse air VA Cogentrix of Richmond 3A Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 3B Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 4A Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 4B Bituminous Coal Baghouse, pulse WV Grant Town Power Plant BLR1A Waste Coal Baghouse, pulse WV Grant Town Power Plant BLR1B Waste Coal Baghouse, pulse PA Panther Creek Energy Facility BLR1 Waste Coal SNCR Baghouse, pulse PA Panther Creek Energy Facility BLR2 Waste Coal SNCR Baghouse, pulse WI South Oak Creek 7 Subbituminous Coal Electrostatic precipitator, cold side VA Cogentrix of Richmond 1A Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 1B Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 2A Bituminous Coal Baghouse, pulse VA Cogentrix of Richmond 2B Bituminous Coal Baghouse, pulse IN Michigan City 12 Subbituminous Coal Natural Gas SCR Electrostatic precipitator, cold side 
87 

State Plant Name Boiler ID Primary Fuel Secondary Fuel 

NOX

Control PM Control 1 PM Control 2 PM 

KS Quindaro 2 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side IN Gibson 1 Bituminous Coal Electrostatic precipitator, cold side SC McMeekin MCM2 Coal-based Synfuel Bituminous Coal Baghouse, reverse air WV Morgantown Energy Facility CFB1 Waste Coal Baghouse, pulse WV Morgantown Energy Facility CFB2 Waste Coal Baghouse, pulse NJ 

PSEG Mercer Generating Station 

2 Bituminous Coal Natural Gas SCR and 

SNCR 

Electrostatic precipitator, cold side 

MO Sibley 2 Subbituminous Coal Electrostatic precipitator, cold side TX Twin Oaks Power One U2 Lignite Coal Baghouse, shake and deflate VA Altavista Power Station 1 Bituminous Coal SNCR Baghouse, pulse CO Comanche 2 Subbituminous Coal Natural Gas Baghouse, reverse air WI South Oak Creek 8 Subbituminous Coal Electrostatic precipitator, cold side VA Southampton Power Station 1 Bituminous Coal Baghouse, pulse OH W. H. Zimmer 1 Bituminous Coal Electrostatic precipitator, cold side MD Brandon Shores 2 Bituminous Coal SCR Electrostatic precipitator, hot side PA Ebensburg Power 031 Waste Coal Baghouse, pulse WI Manitowoc 8 Bituminous Coal Petroleum Coke Single cyclone Baghouse, pulse PA Cambria Cogen B1 Waste Coal SNCR Baghouse, shake and deflate PA Cambria Cogen B2 Waste Coal SNCR Baghouse, shake and deflate AL James H Miller Jr. 4 Subbituminous Coal SCR Electrostatic precipitator, cold side OK AES Shady Point 1A Bituminous Coal Baghouse, pulse OK AES Shady Point 1B Bituminous Coal Baghouse, pulse OK AES Shady Point 2A Bituminous Coal Baghouse, pulse OK AES Shady Point 2B Bituminous Coal Baghouse, pulse AL Colbert 4 Bituminous Coal Electrostatic precipitator, cold side 
88 

State Plant Name Boiler ID Primary Fuel Secondary Fuel 

NOX

Control PM Control 1 PM Control 2 PM 

CO Nucla 1 Bituminous Coal Baghouse, shake and deflate NY 

Trigen Syracuse Energy 

1 Bituminous Coal Baghouse, reverse air 

NY 

Trigen Syracuse Energy 

2 Bituminous Coal Baghouse, reverse air 

NY 

Trigen Syracuse Energy 

3 Bituminous Coal Baghouse, reverse air 

NY 

Trigen Syracuse Energy 

4 Bituminous Coal Baghouse, reverse air 

NY 

Trigen Syracuse Energy 

5 Bituminous Coal Baghouse, reverse air 

KY Trimble County 1 Bituminous Coal SCR Electrostatic precipitator, cold side AL Colbert 1 Bituminous Coal Electrostatic precipitator, cold side CO Comanche 1 Subbituminous Coal Natural Gas Baghouse, reverse air NC 

Cogentrix Dwayne Collier Battle Cogen 

1A Bituminous Coal Baghouse, pulse 

NC 

Cogentrix Dwayne Collier Battle Cogen 

1B Bituminous Coal Baghouse, pulse 
89 

Attachment 12. List of all oil-fired electric utility steam generating units selected for HCl/HF/HCN acid gas H

HAP, non-dioxin/furan organic HAP, and mercury and other non-mercury metallic HAP t

State Plant Name Boiler ID NOX Control PM Control 1 

PR Aguirre 3 PR Aguirre 4 PR Aguirre 9 PR Aguirre 10 FL Anclote 1 FL Anclote 2 PR Arecibo 1 NY Astoria Generating Station 40 NJ B L England 3 Multiple cyclone ElectDC Benning 16 MA Brayton Point 4 Electrostatic precipitator, cold side CT Bridgeport Station BHB2 Electrostatic precipitator, cold side FL C. D. McIntosh Jr 2 Electrostatic precipitator, cold side GU Cabras 2 FL Turkey Point PTP1 Multiple cyclone FL Turkey Point PTP2 Multiple cyclone PR Central Palo Seco 2 PR Central Palo Seco 3 PR Central Palo Seco 4 PR Central Palo Seco 5 PR Central Palo Seco 6 PR Central Palo Seco 7 PR Central Palo Seco 8 MA Cleary Flood 8 PR Costa Sur 1 PR Costa Sur 2 PR Costa Sur 6 PR Costa Sur 7 PR Costa Sur 8 
90 

State Plant Name Boiler ID NOX Control PM Control 1 

PR Costa Sur 9 PR Costa Sur 10 CT Devon Station 8 Electrostatic precipitator, cold side IN Eagle Valley 1 Multiple cyclone ElectIN Eagle Valley 2 Multiple cyclone ElectNY East River 6 PA Eddystone Generating Station 4 Multiple cyclone ElectDE Edge Moor 5 Multiple cyclone ElectIN Harding Street 9 Multiple cyclone ElectIN Harding Street 10 Multiple cyclone ElectIL Havana 2 Electrostatic precipitator, hot side IL Havana 4 Electrostatic precipitator, hot side IL Havana 5 Electrostatic precipitator, hot side IL Havana 6 Electrostatic precipitator, hot side IL Havana 7 Electrostatic precipitator, hot side IL Havana 8 Electrostatic precipitator, hot side HI Honolulu 16 FL Indian River 1 FL Indian River 2 FL Indian River 3 SC Jefferies 2 Electrostatic precipitator, cold side HI Kahe 3 HI Kahe 4 FL Manatee PMT1 Multiple cyclone FL Manatee PMT2 Multiple cyclone FL Martin PMR1 Multiple cyclone DE McKee Run 3 Multiple cyclone GA McManus 2 LA Michoud 3 MD Mirant Chalk Point 3 Electrostatic precipitator, cold side PA Mitchell Power Station 1 Electrostatic precipitator, cold side 
91 

State Plant Name Boiler ID NOX Control PM Control 1 

PA Mitchell Power Station 2 Electrostatic precipitator, cold side PA Mitchell Power Station 3 Electrostatic precipitator, cold side CT Montville Station 5 Electrostatic precipitator, cold side CT Montville Station 6 Electrostatic precipitator, cold side MA Mystic Generating Station 7 Electrostatic precipitator, cold side NH Newington 1 Electrostatic precipitator, hot side NY Northport 2 Electrostatic precipitator, cold side NY Northport 4 Electrostatic precipitator, cold side FL Northside Generating Station 3 Baghouse, pulse NY Oswego Harbor Power 5 Electrostatic precipitator, cold side FL Port Everglades PPE3 Multiple cyclone FL Port Everglades PPE4 Multiple cyclone NY Port Jefferson 4 Electrostatic precipitator, cold side VA Possum Point 5 Multiple cyclone ElectPA PPL Martins Creek 3 PA PPL Martins Creek 4 NJ PSEG Sewaren Generating Station 2 NJ PSEG Sewaren Generating Station 4 VI Randolph E. Harley 1 NY Ravenswood Generating Station 1 Electrostatic precipitator, cold side NY Ravenswood Generating Station 2 Electrostatic precipitator, cold side VI Richmond 1 FL Martin PMR2 Multiple cyclone NY Roseton Generating Station 2 Multiple cyclone PR San Juan Plant 1 PR San Juan Plant 2 PR San Juan Plant 4 PA Schuylkill Generating Station 1 Multiple cyclone FL Suwannee River 2 FL Suwannee River 3 MD Vienna Operations 8 Multiple cyclone 
92 

State Plant Name Boiler ID NOX Control PM Control 1 

HI Waiau 3 HI Waiau 4 HI Waiau 5 HI Waiau 6 HI Waiau 7 HI Waiau 8 MA West Springfield 3 Electrostatic precipitator, cold side ME William F Wyman 1 Multiple cyclone ElectME William F Wyman 2 Multiple cyclone Elect
93 

Attachment 13. List of 50 additional coal-fired electric utility steam generating units not chosen in Attachment

HCl/HF/HCN acid gas HAP, non dioxin/furan organic HAP, and mercury and other non-mercury met

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM 

WV Albright 1 Bituminous Coal Electrostatic precipitator, cold side WV Albright 3 Bituminous Coal Electrostatic precipitator, cold side CT Bridgeport Station BHB3 Subbituminous Coal Residual Fuel Oil Electrostatic precipitator, cold side OH Cardinal 3 Bituminous Coal SCR Electrostatic precipitator, hot side VA Clinch River 3 Bituminous Coal Electrostatic precipitator, cold side AL Colbert 3 Bituminous Coal Electrostatic precipitator, cold side MT Colstrip 3 Subbituminous Coal Wet scrubber OH Conesville 3 Bituminous Coal Electrostatic precipitator, cold side FL Crystal River 1 Bituminous Coal Electrostatic precipitator, cold side KY Dale 3 Bituminous Coal Electrostatic precipitator, cold side NY Dunkirk Generating Station 1 Bituminous Coal Subbituminous Coal Electrostatic precipitator, hot side NY Dunkirk Generating Station 4 Bituminous Coal Subbituminous Coal Electrostatic precipitator, hot side PA Eddystone Generating Station 2 Bituminous Coal 

SNCR 

Multiple cyclone Electrost

precipita

PA Elrama Power Plant 2 Bituminous Coal 

SNCR 

Multiple cyclone Electrost

precipita

NC G. G. Allen 3 Bituminous Coal Electrostatic precipitator, cold side TN Gallatin 2 Subbituminous Coal Electrostatic precipitator, cold side 
94 

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM 

PA Hatfields Ferry Power Station 3 Bituminous Coal Electrostatic precipitator, cold side IL Havana 9 Subbituminous Coal SCR Electrostatic precipitator, hot side BaghousMN Hoot Lake 2 Subbituminous Coal Electrostatic precipitator, cold side TX J. T. Deely 1 Subbituminous Coal Electrostatic precipitator, cold side MO James River Power Station 4 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side IL Joliet 9 5 Subbituminous Coal Electrostatic precipitator, cold side KS La Cygne 2 Subbituminous Coal Electrostatic precipitator, cold side KS Lawrence Energy Center 3 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side TX Monticello 1 Lignite Coal Subbituminous Coal Electrostatic precipitator, cold side Baghous

deflate 

IL Newton 2 Subbituminous Coal Electrostatic precipitator, cold side PA PPL Martins Creek 2 Bituminous Coal Electrostatic precipitator, cold side WI Pulliam 8 Subbituminous Coal Electrostatic precipitator, cold side KY R D Green G2 Bituminous Coal Electrostatic precipitator, cold side IN R M Schahfer 14 Bituminous Coal Subbituminous Coal Electrostatic precipitator, cold side LA R. S. Nelson 6 Subbituminous Coal Electrostatic precipitator, hot side CO Rawhide 101 Subbituminous Coal Baghouse, reverse air NV Reid Gardner 1 Bituminous Coal Lignite Coal Multiple cyclone OH Richard Gorsuch 3 Bituminous Coal Natural Gas Electrostatic precipitator, cold side 
95 

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM 

NC Riverbend 7 Bituminous Coal Electrostatic precipitator, hot side NH Schiller 5 Bituminous Coal Residual Fuel Oil SNCR Electrostatic precipitator, cold side FL Scholz 2 Bituminous Coal Electrostatic precipitator, cold side PA Shawville 2 Bituminous Coal Electrostatic precipitator, cold side MN Silver Bay Power BLR1 Subbituminous Coal Natural Gas Baghouse, reverse air MO Sioux 2 Subbituminous Coal Tire-derived Fuels Electrostatic precipitator, cold side IN Tanners Creek U4 Subbituminous Coal Electrostatic precipitator, cold side SC Urquhart URQ3 Bituminous Coal Natural Gas Electrostatic precipitator, cold side IL Vermilion 1 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side BaghousOH W H Sammis 3 Bituminous Coal Subbituminous Coal Baghouse, reverse air OH W H Sammis 4 Bituminous Coal Subbituminous Coal Baghouse, reverse air NC W. H. Weatherspoon 1 Bituminous Coal Electrostatic precipitator, cold side IN Wabash River 2 Bituminous Coal Electrostatic precipitator, cold side TX Welsh 1 Subbituminous Coal Electrostatic precipitator, hot side NE Whelan Energy Center 1 Subbituminous Coal Electrostatic precipitator, cold side PA WPS Energy Servs Sunbury Gen 4 Bituminous Coal Distillate Fuel Oil Electrostatic precipitator, cold side Electrost

precipita