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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 

 

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 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.

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 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.
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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

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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

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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 permitted6to 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 Clean Air Act section 

112(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

Original design gross 

efficiency (%, HHV)

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

Average annual capacity 

factor for the past 3 years

Applicable NSPS

Estimated year of 

retirement18

 

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 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).

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 of operation.

18

 This can be treated as CBI and can be submitted through the proper CBI procedure if desired.
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Emission Control Technology

16. For each boiler noted in Part I, question 15, provide the following information for each current emission control device 

installed and operating and/or planned (please designate the order of the emission controls – 1 for first control following the 

boiler, 2 for second control following the boiler, etc.):

Boiler ID19 Type20 NOx control21 SO2 control22 PM control23 Other control24

 

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 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).

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). Include specific date that 

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

which the catalyst is manufactured and the type of reductant used in with the SCR (e.g., anhydrous ammonia, aqueous ammonia, urea, other). Also, please note 

if 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. Include specific date that 

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 specific date that control 

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 injection (ACI); Powerspan 

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

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

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 contact information for 

each HAP-specific (e.g., mercury, hydrogen chloride) control technology that you have either contracted for, are installing, or have 

installed for the purpose of participating in a control technology demonstration project25 (e.g., U.S. Department of Energy program, 

consent decree, etc.).

Boiler 

ID26

Company (vendor) 

name

Company (vendor) contact information

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 (in whole or in part) 

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 technology’s HAP removal 

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 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).
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18. For the control technologies identified in Part I, question 17, provide the date of actual start-up of the demonstration (if the 

control is currently operating), the date of expected or projected start-up, the date the demonstration was completed, the type of HAP 

control installed (e.g., sorbent and type; pre-combustion boiler chemical additive; combustion boiler chemical additive), the desired 

HAP emission reduction or rate (if any), and the coal rank(s) in use or fuel type upon which the demonstration was conducted. Please 

specify the format of the target HAP emission reduction or rate (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the 

target end-point is percent reduction, provide (1) an estimate of what an equivalent emission rate would be (and specify the format of 

the equivalent emission rate), and (2) the basis for calculating the percent reduction (i.e., where the “inlet” and “outlet” are).

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 reduction 

(%) or emission 

rate

Coal rank(s) in 

use

 

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 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).

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 contact information for 

each HAP (e.g., mercury, hydrogen chloride, etc.) control technology that you have either contracted for, are installing, or have 

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

Boiler 

ID29

Company (vendor) 

name

Company (vendor) contact information

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

operating), the date of expected or projected start-up, the type of HAP control installed (e.g., sorbent and type; pre-combustion boiler 

chemical additive; combustion boiler chemical additive), the guaranteed HAP emission reduction or emission rate, the sorbent feed 

rate upon which the guarantee is based, and the coal rank(s) or fuel type upon which the guarantee is based. Please specify the format 

of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the guarantee is percent reduction, provide (1) an 

estimate of what an equivalent emission rate would be (and specify the format of the equivalent emission rate), and (2) the basis for 

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 rate 

on which 

guarantee is 

based

Coal rank(s) upon 

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 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).

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:

Boiler 

ID32

Permitted emission limit (indicate type of permit and format of emission limit and averaging period)

PM33 PM10

(34)

PM2.5

(35)

SO2

HCl 

and/or 

HF

HCN Metal 

HAP36 Hg CO

Other 

organics 

(specify)

Other 

pollutant 

(specify)

 

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 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).

33

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

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; indicate permit level for 

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:

Boiler 

ID37

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

PM38 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN Metal 

HAP39 Hg CO

Other 

organics 

(specify)

Other 

pollutant 

(specify)

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 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).

38

 If the boiler has separate guaranteed emission rate for filterable and condensable PM, respectively, please include those separate emission rates.

39

 Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for 

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:

Boiler ID40

Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a 

permitted emission limit

PM41 PM10 PM2.5 SO2

HCl 

and/or 

HF

HCN Metal 

HAP42 Hg CO

Other 

organics 

(specify)

 

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 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).

41

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

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; indicate permit level for 

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 requested.43

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

Total Capital Investment: $: ______________

Total Annual Operating and Maintenance Costs: $: ______________ (Include base year for operating costs [e.g., 2006])

26. Are any other means of emission control (for any pollutant) employed on any boiler noted in Part I, question 15 (e.g., low-ash 

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.
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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. 
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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):

Amount 

received, 

dry basis, 

short tons45

ID # of 

boiler(s) 

firing 

fuel46

Fuel source Fuel shipment 

method State/Country County47 Coal seam48

 

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 following 

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

Nickel, 

ppm

Other 

trace 

metal 

HAP, 

ppm50

 

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 constituents (e.g., Cl, F), and 

any metallic HAP (e.g., Hg, Pb, As, Se, etc.), EPA wishes the responding facility to provide those fuel analyses results. Otherwise, this 12-month fuel analysis 

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.
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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:

Boiler 

ID

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

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 Nm

3

/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. 
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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.
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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

Higher Heating Value

Coal ASTM D5865–04, ASTM D240, ASTM 

E711-87 (1996)

Btu/lb

Biomass ASTM E711–87 (1996) or equivalent, 

ASTM D240, or ASTM D5865-04

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

E711-87 (1997)

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

E711-87 (1996)

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.

%

Mercury Concentration

Coal

ASTM D6722-01, EPA Method 1631E, 

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

equivalent

ppm

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

Liquid

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

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

821-R-01-013, or equivalent
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Analyte Fuel Type Method Target Reported 

Units of Measure

Total Selected Metals 

Concentration

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)

ppm

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

Liquid

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

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

7060 or -7060A for As

Chlorine Concentration

Coal

SW-846-9250 or ASTM D6721-01 or 

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

or -9250, ASTM E776-87 (1996) ppm

Biomass, Other Solids, 

Liquids

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

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

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 Information

State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID

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 2

MO Blue Valley 3

OR Boardman 1SG

UT Bonanza 1-1

GA Bowen 1BLR

GA Bowen 2BLR

GA Bowen 3BLR

GA Bowen 4BLR

MD Brandon Shores 1

MD Brandon Shores 2

MA Brayton Point 1

MA Brayton Point 2

MA Brayton Point 3

VA Bremo Bluff 3

VA Bremo Bluff 4

CT Bridgeport Station BHB3

PA Bruce Mansfield 1

PA Bruce Mansfield 2

PA Bruce Mansfield 3

NC Buck 5

NC Buck 6

NC Buck 7

NC Buck 8

NC Buck 9

TN Bull Run 1

IA Burlington 1

FL C. D. McIntosh Jr 3

MD C. P. Crane 1

MD C. P. Crane 2

NY C. R. Huntley Generating Station 65

NY C. R. Huntley Generating Station 67

NY C. R. Huntley Generating Station 68

PA Cambria Cogen B1

PA Cambria Cogen B2

SC Canadys Steam CAN1

SC Canadys Steam CAN2

SC Canadys Steam CAN3

KY Cane Run 4

KY Cane Run 5

KY Cane Run 6

NC Cape Fear 5

NC Cape Fear 6

UT Carbon 1

UT Carbon 2

OH Cardinal 1

OH Cardinal 2

OH Cardinal 3

IN Cayuga 1

IN Cayuga 2

FL Cedar Bay Generating LP CBA
State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID

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 2

OH Conesville 3

OH Conesville 4

OH Conesville 5

OH Conesville 6

KY Cooper 1

KY Cooper 2

SC Cope COP1

AZ Coronado U1B

AZ Coronado U2B

IA Council Bluffs 1

IA Council Bluffs 2

IA Council Bluffs 3

IA Council Bluffs 4

ND Coyote B1

CO Craig C1

CO Craig C2

CO Craig C3

IL Crawford 7

IL Crawford 8

FL Crist 4

FL Crist 5

FL Crist 6

FL Crist 7

PA Cromby Generating Station 1

SC Cross 1

SC Cross 2

SC Cross 3

SC Cross 4

FL Crystal River 1

FL Crystal River 2

FL Crystal River 4

FL Crystal River 5

TN Cumberland 1

TN Cumberland 2

KY D. B. Wilson W1

KY Dale 1

KY Dale 2

KY Dale 3

KY Dale 4

IL Dallman 31

IL Dallman 32

IL Dallman 33

IL Dallman 34

MI Dan E. Karn 1

MI Dan E. Karn 2

NC Dan River 1

NC Dan River 2
State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID

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 5

AL Gadsden 1

AL Gadsden 2

TN Gallatin 1

TN Gallatin 2

TN Gallatin 3

TN Gallatin 4

OH General James M Gavin 1

OH General James M Gavin 2

WI Genoa 1

IA George Neal North 1

IA George Neal North 2

IA George Neal North 3

IA George Neal South 4

NE Gerald Gentleman 1

NE Gerald Gentleman 2

KY Ghent 1

KY Ghent 2

KY Ghent 3

KY Ghent 4

TX Gibbons Creek 1

IN Gibson 1

IN Gibson 2

IN Gibson 3

IN Gibson 4

IN Gibson 5

VA Glen Lyn 6

VA Glen Lyn 51

VA Glen Lyn 52

AL Gorgas 6

AL Gorgas 7

AL Gorgas 8

AL Gorgas 9

AL Gorgas 10

WV Grant Town Power Plant BLR1A

WV Grant Town Power Plant BLR1B

OK GRDA 1

OK GRDA 2

KY Green River 4

KY Green River 5

AL Greene County 1

AL Greene County 2

SC H. B. Robinson 1

KY H. L. Spurlock 1

KY H. L. Spurlock 2

KY H. L. Spurlock 3

KY H. L. Spurlock 4

OH Hamilton 8
State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID

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 BW73

WY Jim Bridger BW74

PA John B Rich Memorial Power Station CFB1

PA John B Rich Memorial Power Station CFB2

WV John E Amos 1

WV John E Amos 2

WV John E. Amos 3

WI John P. Madgett B1

TN John Sevier 1

TN John Sevier 2

TN John Sevier 3

TN John Sevier 4

TN Johnsonville 1

TN Johnsonville 2

TN Johnsonville 3

TN Johnsonville 4

TN Johnsonville 5

TN Johnsonville 6

TN Johnsonville 7

TN Johnsonville 8

TN Johnsonville 9

TN Johnsonville 10

IL Joliet 29 71

IL Joliet 29 72

IL Joliet 29 81

IL Joliet 29 82

IL Joliet 9 5

IL Joppa Steam 1

IL Joppa Steam 2

IL Joppa Steam 3

IL Joppa Steam 4

IL Joppa Steam 5

IL Joppa Steam 6

WV Kammer 1

WV Kammer 2

WV Kammer 3

WV Kanawha River 1

WV Kanawha River 2

KY Kenneth C. Coleman C1

KY Kenneth C. Coleman C2

KY Kenneth C. Coleman C3

PA Keystone 1

PA Keystone 2

OH Killen Station 2

IL Kincaid Generation LLC 1

IL Kincaid Generation LLC 2

TN Kingston 1

TN Kingston 2
State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID

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 2

ND Milton R. Young B1

ND Milton R. Young B2

GA Mitchell 3

WV Mitchell 1

WV Mitchell 2

PA Mitchell Power Station 33

MI Monroe 1

MI Monroe 2

MI Monroe 3

MI Monroe 4

TX Monticello 1

TX Monticello 2

TX Monticello 3

MO Montrose 1

MO Montrose 2

MO Montrose 3

WV Morgantown Energy Facility CFB1

WV Morgantown Energy Facility CFB2

MD Morgantown Generating Plant 1

MD Morgantown Generating Plant 2

MA Mount Tom 1

WV Mountaineer 1

WV Mt Storm 3

CA Mt. Poso Cogeneration BL01

WV Mt. Storm 1

WV Mt. Storm 2

IA Muscatine Plant #1 7

IA Muscatine Plant #1 8

IA Muscatine Plant #1 9

OH Muskingum River 1

OH Muskingum River 2

OH Muskingum River 3

OH Muskingum River 4

OH Muskingum River 5

OK Muskogee 4

OK Muskogee 5

OK Muskogee 6

WY Naughton 1

WY Naughton 2

WY Naughton 3

AZ Navajo 1

AZ Navajo 2

AZ Navajo 3

KS Nearman Creek N1

NE Nebraska City 1

NE Nebraska City 2

WY Neil Simpson II 2
State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID

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 Southport 2B

NC Primary Energy Southport 2C

NJ PSEG Hudson Generating Station 2

NJ PSEG Mercer Generating Station 1

NJ PSEG Mercer Generating Station 2

WI Pulliam 3

WI Pulliam 4

WI Pulliam 5

WI Pulliam 6

WI Pulliam 7

WI Pulliam 8

KS Quindaro 1

KS Quindaro 2

KY R D Green G2

KY R. D. Green G1

MS R. D. Morrow 1

MS R. D. Morrow 2

OH R. E. Burger 5

OH R. E. Burger 6

OH R. E. Burger 7

OH R. E. Burger 8

IN R. Gallagher 1

IN R. Gallagher 2

IN R. Gallagher 3

IN R. Gallagher 4

ND R. M. Heskett B1

ND R. M. Heskett B2

IN R. M. Schahfer 14

IN R. M. Schahfer 15

IN R. M. Schahfer 17

IN R. M. Schahfer 18

MD R. Paul Smith Power Station 9

MD R. Paul Smith Power Station 11

LA R. S. Nelson 6

CO Rawhide 101

CO Ray D. Nixon 1

MS Red Hills Generating Facility AA001

MS Red Hills Generating Facility AA002

NV Reid Gardner 1

NV Reid Gardner 2

NV Reid Gardner 3

NV Reid Gardner 4

OH Richard Gorsuch 1

OH Richard Gorsuch 2

OH Richard Gorsuch 3

OH Richard Gorsuch 4

MI River Rouge 2

MI River Rouge 3
State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID

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 1

AZ Springerville 2

AZ Springerville 3

AZ Springerville 4

MI St. Clair 1

MI St. Clair 2

MI St. Clair 3

MI St. Clair 4

MI St. Clair 6

MI St. Clair 7

FL St. Johns River Power Park 1

FL St. Johns River Power Park 2

PA St. Nicholas Cogen Project 1

ND Stanton 1

ND Stanton 10

FL Stanton Energy Center 1

FL Stanton Energy Center 2

IN State Line Energy 3

IN State Line Energy 4

IA Streeter Station 7

UT Sunnyside Cogen Associates 1

IA Sutherland 1

IA Sutherland 2

IA Sutherland 3

MN Syl Laskin 1

MN Syl Laskin 2

IN Tanners Creek U1

IN Tanners Creek U2

IN Tanners Creek U3

IN Tanners Creek U4

KS Tecumseh Energy Center 9

KS Tecumseh Energy Center 10

MI TES Filer City Station 1

MI TES Filer City Station 2

MO Thomas Hill MB1

MO Thomas Hill MB2

MO Thomas Hill MB3

PA Titus 1

PA Titus 2

PA Titus 3

TX Tolk 171B

TX Tolk 172B

WA Transalta Centralia Generation BW21

WA Transalta Centralia Generation BW22

MI Trenton Channel 16

MI Trenton Channel 17

MI Trenton Channel 18

MI Trenton Channel 19
State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID

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 3

SC Winyah 4

IL Wood River 4

IL Wood River 5

PA WPS Energy Servs Sunbury Gen 3

PA WPS Energy Servs Sunbury Gen 4

PA WPS Energy Servs Sunbury Gen 1A

PA WPS Energy Servs Sunbury Gen 1B

PA WPS Energy Servs Sunbury Gen 2A

PA WPS Energy Servs Sunbury Gen 2B

NY WPS Power Niagara 1

PA WPS Westwood Generation LLC 031

WY Wygen I 3

WY Wygen II 4

WY Wyodak BW91

GA Yates Y1BR

GA Yates Y2BR

GA Yates Y3BR

GA Yates Y4BR

GA Yates Y5BR

GA Yates Y6BR

GA Yates Y7BR

VA Yorktown 1

VA Yorktown 2
Attachment 5. List of oil-fired electric utility steam generating units requiring Part I and II Information

State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID

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 1

HI Kahe 2

HI Kahe 3

HI Kahe 4

HI Kahe 5

HI Kahe 6

FL Manatee PMT1

FL Manatee PMT2

FL Martin PMR1

FL Martin PMR2

DE McKee Run 3

GA McManus 1

GA McManus 2

IL Meredosia 06

LA Michoud 3

CT Middletown 2

CT Middletown 4

MD Mirant Chalk Point 3

MD Mirant Chalk Point 4

PA Mitchell Power Station 1

PA Mitchell Power Station 2

PA Mitchell Power Station 3

CT Montville Station 5

CT Montville Station 6

MA Mystic Generating Station 7

CT New Haven Harbor NHB1

NH Newington 1

NY Northport 1

NY Northport 2

NY Northport 3

NY Northport 4

FL Northside Generating Station 3

CT NRG Norwalk Harbor 1

CT NRG Norwalk Harbor 2

NY Oswego Harbor Power 5

NY Oswego Harbor Power 6

FL P. L. Bartow 1

FL P. L. Bartow 2

FL P. L. Bartow 3

FL Port Everglades PPE1

FL Port Everglades PPE2

FL Port Everglades PPE3

FL Port Everglades PPE4

NY Port Jefferson 3

NY Port Jefferson 4

VA Possum Point 5
State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID

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 3

HI Waiau 4

HI Waiau 5

HI Waiau 6

HI Waiau 7

HI Waiau 8

MA West Springfield 3

ME William F. Wyman 1

ME William F. Wyman 2

ME William F. Wyman 3

ME William F. Wyman 4

VA Yorktown 3
63

Attachment 6. List of all IGCC units requiring Part I, II, and III Information and selected for HCl/HF/HCN 

acid gas HAP, dioxin/furan organic HAP, non-dioxin/furan organic HAP, and mercury and other non-mercury 

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 and selected 

for HCl/HF/HCN acid gas HAP, dioxin/furan organic HAP, non-dioxin/furan organic HAP, and mercury 

and other non-mercury metallic HAP testing

State Plant Name Boiler ID NOX Control PM Control FGD Type

TX AES Deepwater AAB001 SCR Electrostatic precipitator, hot side Spray type

OH Bay Shore 1 Baghouse, pulse

PA Chester Operations 10 Baghouse, pulse

CA Hanford CB1302 Baghouse, pulse Spray type

WI Manitowoc 9 SNCR Baghouse, pulse

FL Northside Generating Station 1 Baghouse, pulse Spray type

FL Northside Generating Station 2 Baghouse, pulse Spray type

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 gas HAP testing

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 FGD Type FGD Date

FL Crystal River 5 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 12/31/2009

TX Oak Grove 1 Lignite Coal SCR Baghouse, pulse Spray dryer type 12/31/2009

AR Plum Point Energy STG1 Subbituminous 

Coal SCR Baghouse, pulse Spray dryer type 12/31/2009

AZ Springerville 4

Subbituminous 

Coal Bituminous Coal SCR Baghouse, pulse Spray dryer type 12/31/2009

WY Two Elk Generating Station 1

Subbituminous 

Coal SCR Baghouse, pulse Spray type 12/31/2009

AZ Cholla 3

Subbituminous 

Coal Baghouse, pulse Spray dryer type 9/1/2008

AZ Cholla 4

Subbituminous 

Coal Baghouse, pulse Spray dryer type 9/1/2008

TX Sandow Station 5A Lignite Coal SCR Baghouse, pulse Spray type 8/31/2009

TX Sandow Station 5B Lignite Coal SCR Baghouse, pulse Spray type 8/31/2009

WI Elm Road Generating Station 1 Bituminous Coal SCR Baghouse, pulse Spray type 6/1/2009

NC G. G. Allen 1 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 5/1/2009

NE Nebraska City 2

Subbituminous 

Coal Baghouse, pulse Spray type 5/1/2009

GA Wansley 2 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Jet Bubbling Reactor 5/1/2009

GA Bowen 2BLR Bituminous Coal SCR

Electrostatic precipitator, 

cold side Jet Bubbling Reactor 4/1/2009

OH Conesville 4 Bituminous Coal Electrostatic precipitator, 

cold side Jet Bubbling Reactor 4/1/2009

SC Cross 4 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Spray type 1/1/2009

IL Dallman 34 Bituminous Coal SCR Baghouse, pulse Packed type 1/1/2009

VA Cogentrix Hopewell 1A Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008

VA Cogentrix Hopewell 1B Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008

VA Cogentrix Hopewell 1C Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008

VA Cogentrix Virginia Leasing 

Corporation 2A Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008

VA Cogentrix Virginia Leasing 

Corporation 2B Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008

VA Cogentrix Virginia Leasing 

Corporation 2C Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008

GA Bowen 4BLR Bituminous Coal SCR

Electrostatic precipitator, 

cold side Jet Bubbling Reactor 12/1/2008

WV John E Amos 1 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Tray type 12/1/2008

WV John E Amos 2 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Tray type 12/1/2008
65

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 FGD Type FGD Date

GA Wansley 1 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Jet Bubbling Reactor 12/1/2008

NV TS Power Plant BLR100 Subbituminous 

Coal SCR Baghouse, pulse Spray dryer type 6/1/2008

WI Weston 4 Bituminous Coal Subbituminous 

Coal SCR Baghouse, pulse Spray dryer type 6/1/2008

KY Ghent 4 Bituminous Coal Subbituminous 

Coal

Electrostatic precipitator, 

hot side Spray type 5/1/2008

GA Bowen 3BLR Bituminous Coal SCR

Electrostatic precipitator, 

cold side Jet Bubbling Reactor 4/1/2008

KY H. L. Spurlock 4 Bituminous Coal SNCR Baghouse, pulse CFB 4/1/2008

NC Belews Creek 1 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 1/1/2008

GA Hammond 1 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 1/1/2008

GA Hammond 2 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 1/1/2008

GA Hammond 3 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 1/1/2008

GA Hammond 4 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 1/1/2008

VA Cogentrix Hopewell 2A Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007

VA Cogentrix Hopewell 2B Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007

VA Cogentrix Hopewell 2C Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007

VA Cogentrix Virginia Leasing 

Corporation 1A Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007

VA Cogentrix Virginia Leasing 

Corporation 1B Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007

VA Cogentrix Virginia Leasing 

Corporation 1C Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007

WY Wygen II 4

Subbituminous 

Coal SCR Baghouse, pulse Spray type 12/31/2007

OH Cardinal 2 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Jet Bubbling Reactor 12/1/2007

WV John E. Amos 3 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Tray type 12/1/2007

IA Louisa 101 Subbituminous 

Coal Baghouse, pulse

Electrostatic 

precipitator, hot 

side

Spray dryer type 12/1/2007

OH Cardinal 1 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Jet Bubbling Reactor 11/1/2007

IA Council Bluffs 4

Subbituminous 

Coal SCR Baghouse, pulse Spray dryer type 6/1/2007

KY Ghent 3 Bituminous Coal Subbituminous 

Coal

Electrostatic precipitator, 

hot side Spray type 5/1/2007

WV Mitchell 1 Bituminous Coal Electrostatic precipitator, 

cold side Tray type 4/1/2007

SC Cross 3 Bituminous Coal Coal-based 

Synfuel SCR

Electrostatic precipitator, 

cold side Spray type 1/1/2007
66

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 FGD Type FGD Date

WI Pleasant Prairie 2

Subbituminous 

Coal SCR

Electrostatic precipitator, 

cold side Spray type 3/31/2007

WV Mountaineer 1 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Spray type 1/1/2007

AZ Springerville 3

Subbituminous 

Coal SCR Baghouse, pulse Spray dryer type 12/31/2006

WV Mitchell 2 Bituminous Coal Electrostatic precipitator, 

cold side Tray type 12/1/2006

WI Pleasant Prairie 1

Subbituminous 

Coal SCR

Electrostatic precipitator, 

cold side Spray type 11/31/2006

NC Marshall 1 Bituminous Coal Multiple cyclone

Electrostatic 

precipitator, cold 

side

Spray type 11/1/2006

MT Hardin Generator Project PC1 Subbituminous 

Coal SCR Baghouse, pulse Spray dryer type 2/1/2006

NC Asheville 1 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 11/1/2005

KY H. L. Spurlock 3 Bituminous Coal SNCR Baghouse, pulse CFB 4/1/2005

PA Seward 1 Waste Coal Bituminous Coal SNCR Baghouse, pulse Spray dryer type 3/1/2004

PA Seward 2 Waste Coal Bituminous Coal SNCR Baghouse, pulse Spray dryer type 3/1/2004

IL Marion 123 Waste Coal Bituminous Coal Baghouse, pulse CFB 5/1/2003

WY Wygen I 3

Subbituminous 

Coal SCR Baghouse, pulse Spray type 5/1/2003

CO Arapahoe 3

Subbituminous 

Coal Natural Gas Baghouse, reverse air Dry Sorbent Injection System 1/1/2003

CO Cherokee 2 Bituminous Coal Natural Gas Baghouse, reverse air Dry sodium injection 1/1/2003

CO Cherokee 4 Bituminous Coal Natural Gas Baghouse, reverse air Spray dryer type 1/1/2003

PR AES Puerto Rico (Aurora) 1 Bituminous Coal SNCR Baghouse, pulse CFB 12/31/2002

PR AES Puerto Rico (Aurora) 2 Bituminous Coal SNCR Baghouse, pulse CFB 12/31/2002

CO Valmont 5

Subbituminous 

Coal Bituminous Coal Baghouse, reverse air Spray dryer type 8/1/2002

CO Cherokee 3 Bituminous Coal Natural Gas Baghouse, reverse air Spray dryer type 7/1/2002

WA Transalta Centralia 

Generation BW21 Subbituminous Coal Wet scrubber

Electrostatic 

precipitator, cold 

side

Spray type 6/1/2002

MS Red Hills Generating Facility AA001 Lignite Coal Baghouse, reverse air CFB 3/1/2002

MS Red Hills Generating Facility AA002 Lignite Coal Baghouse, reverse air CFB 3/1/2002

WV Mt. Storm 1 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 2/1/2002

WV Mt. Storm 2 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 2/1/2002

WA Transalta Centralia 

Generation BW22 Subbituminous Coal Wet scrubber

Electrostatic 

precipitator, cold 

side

Spray type 10/1/2001
67

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 FGD Type FGD Date

PA Homer City Station 3 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Spray type 9/1/2001

IL Dallman 31 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Packed type 6/1/2001

IL Dallman 32 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Packed type 6/1/2001

MO Hawthorn 5A Subbituminous 

Coal Natural Gas SCR Baghouse, pulse Spray dryer type 6/1/2001

AK Healy 1

Subbituminous 

Coal Baghouse, reverse air Spray dryer type 9/1/2000

MD AES Warrior Run 

Cogeneration Facility BLR1 Bituminous Coal SNCR and SCR Baghouse, reverse air CFB 2/1/2000

FL Big Bend BB01 Bituminous Coal Subbituminous 

Coal

Electrostatic precipitator, 

cold side Spray type 12/1/1999

FL Big Bend BB02 Bituminous Coal Subbituminous 

Coal

Electrostatic precipitator, 

cold side Spray type 12/1/1999

AZ Navajo 1 Bituminous Coal Electrostatic precipitator, 

hot side Spray type 8/1/1999

CO Hayden H2 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air Spray dryer type 6/1/1999

OH Hamilton 9 Bituminous Coal Natural Gas Electrostatic precipitator, 

hot side

Baghouse, pulse Dry gas absorption 4/1/1999

CO Hayden H1 Bituminous Coal Natural Gas Baghouse, reverse air Spray dryer type 12/1/1998

AZ Navajo 2 Bituminous Coal Electrostatic precipitator, 

hot side Spray type 11/1/1998

NM San Juan 1

Subbituminous 

Coal

Electrostatic precipitator, 

hot side Spray type 10/1/1998

NM San Juan 2

Subbituminous 

Coal

Electrostatic precipitator, 

hot side Spray type 10/1/1998

NM San Juan 3

Subbituminous 

Coal

Electrostatic precipitator, 

hot side Spray type 10/1/1998

NM San Juan 4

Subbituminous 

Coal

Electrostatic precipitator, 

hot side Spray type 10/1/1998

CO Cherokee 1 Bituminous Coal Natural Gas Baghouse, reverse air Dry sodium injection 2/1/1998

AZ Navajo 3 Bituminous Coal Electrostatic precipitator, 

hot side Spray type 11/1/1997

VA Birchwood Power 1A Bituminous Coal SCR Baghouse, reverse air Spray dryer type 12/1/1996

FL Stanton Energy Center 2 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Spray type 6/1/1996

IN AES Petersburg 1 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 5/1/1996

IN AES Petersburg 2 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 5/1/1996

VA Clover 2 Bituminous Coal Baghouse, reverse air Spray type 3/1/1996

FL Indiantown Cogeneration LP AAB01 Bituminous Coal SCR Baghouse, reverse air Spray dryer type 12/1/1995

PA Conemaugh 2 Bituminous Coal Electrostatic precipitator, 

cold side Wet scrubber Spray type 11/1/1995

SC Cope COP1 Bituminous Coal Natural Gas Baghouse, reverse air Spray dryer type 11/1/1995
68

StatePlant NameBoiler ID Primary Fuel Secondary Fuel NO

X Control PM Control 1 PM Control 2 FGD Type FGD Date

WY Neil Simpson II2

Subbituminous 

Coal

Electrostatic precipitator, 

cold side

Circulating Dry 

Scrubber 11/1/1995

VA Clover1 Bituminous Coal Baghouse, reverse air Spray type 10/1/1995

PA Northampton Generating 

Company BLR1 Waste Coal Petroleum Coke SNCR Baghouse, pulse CFB 8/1/1995

NY AES Cayuga1 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Spray type 6/1/1995

NY AES Cayuga2 Bituminous Coal Electrostatic precipitator, 

cold side Spray typ

e 6/1/1995

KY HMP&L Station Two 

Henderson H1 Bituminous Coal Electrostatic precipitator, cold side Tray type 6/1/1995

KY HMP&L Station Two 

Henderson H2 Bituminous Coal Electrostatic precipitator, cold side Tray type 6/1/1995

NC Roanoke Valley IIBLR2 Bituminous Coal Baghouse, pulse Circulating Dry 

Scrubber 6/1/1995

PA Colver Power Project ABB01 Waste Coal Baghouse, pulse CFB 5/1/1995

SC Cross1 Bituminous Coal Coal

-based 

Synfuel SCR

Electrostatic precipitator, 

cold side Spray type 5/1/1995

OH General James M Gavin2 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Spray type 3/1/1995

NJ B. L. England2 Bituminous Coal SNCR

Electrostatic precipitator, 

cold side Spray type 1/1/1995

TN Cumberland1 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Spray type 1/1/1995

TN Cumberland2 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 1/1/1995

IN F. B. Culley2 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 1/1/1995

IN F. B. Culley3 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Spray type 1/1/1995

IN Gibson4 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 1/1/1995

WV Mt Storm3 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 1/1/1995

PA Conemaugh1 Bituminous Coal Electrostatic precipitator, 

cold side Wet scrubber Spray type 12/1/1994

OH General James M Gavin1 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Spray type 12/1/1994

KY Ghent1 Bituminous Coal

Electrostatic precipitator, 

cold side Spray type 12/1/1994

KY Elmer Smith1 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Spray type 11/1/1994

KY Elmer Smith2 Bituminous Coal SNCR

Electrostatic precipitator, 

cold side Spray type 11/1/199

4

WV Harrison Power Station1 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Wet scrubber Spray type 11/1/1994

WV Harrison Power Station2 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Wet scrubber Spray type 11/1/1994

WV Harrison Power Station3 Bituminous Coal SCR

Electrostatic precipitator, 

cold side Wet scrubber Spray type 11/1/1994
69

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 FGD Type FGD Date

IN Whitewater Valley 2 Bituminous Coal Electrostatic precipitator, 

cold side Spray dryer type 10/1/1994

NJ Logan Generating Plant B01 Bituminous Coal SCR Baghouse, reverse air Spray dryer type 9/1/1994

NC Roanoke Valley I BLR1 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air Circulating Dry 

Scrubber 5/1/1994

NJ Chambers Cogeneration LP BOIL1 Bituminous Coal SCR Baghouse, reverse air Spray dryer type 3/1/1994

NJ Chambers Cogeneration LP BOIL2 Bituminous Coal SCR Baghouse, reverse air Spray dryer type 3/1/1994

FL Cedar Bay Generating LP CBA Bituminous Coal SNCR Baghouse, reverse air Circulating Dry 

Scrubber 2/1/1994

FL Cedar Bay Generating LP CBB Bituminous Coal SNCR Baghouse, reverse air Circulating Dry 

Scrubber 2/1/1994

FL Cedar Bay Generating LP CBC Bituminous Coal SNCR Baghouse, reverse air Circulating Dry 

Scrubber 2/1/1994

CO Arapahoe 4

Subbituminous 

Coal Natural Gas Baghouse, reverse air Dry Sorbent Injection System 6/1/1993

PA Scrubgrass Generating UNIT 1 Waste Coal SNCR Baghouse, pulse CFB 6/1/1993

PA Scrubgrass Generating UNIT 2 Waste Coal SNCR Baghouse, pulse CFB 6/1/1993

UT Sunnyside Cogen Associates 1 Waste Coal Baghouse, pulse CFB 2/1/1993

WV North Branch 1A Bituminous Coal Waste Oil Baghouse, pulse CFB 12/31/1992

WV North Branch 1B Bituminous Coal Waste Oil Baghouse, pulse CFB 12/31/1992

TX J. K. Spruce BLR1 Subbituminous 

Coal Baghouse, reverse air Spray type 12/1/1992

VA Mecklenburg Power Station BLR1 Bituminous Coal Baghouse, pulse Circulating Dry 

Scrubber 11/1/1992

VA Mecklenburg Power Station BLR2 Bituminous Coal Baghouse, pulse Circulating Dry 

Scrubber 11/1/1992

PA Piney Creek Project BRBR1 Waste Coal SNCR Baghouse, pulse Circulating Dry 

Scrubber 11/1/1992

GA Yates Y1BR Bituminous Coal Natural Gas Electrostatic precipitator, 

cold side Wet scrubber Jet Bubbling Reactor 10/1/1992

HI AES Hawaii BLRA Subbituminous 

Coal Tire-derived Fuels SNCR Baghouse, reverse air CFB 9/1/1992

HI AES Hawaii BLRB Subbituminous 

Coal Waste Oil SNCR Baghouse, reverse air CFB 9/1/1992

VA Cogentrix of Richmond 3A Bituminous Coal Baghouse, pulse Spray dryer type 8/1/1992

VA Cogentrix of Richmond 3B Bituminous Coal Baghouse, pulse Spray dryer type 8/1/1992

VA Cogentrix of Richmond 4A Bituminous Coal Baghouse, pulse Spray dryer type 8/1/1992

VA Cogentrix of Richmond 4B Bituminous Coal Baghouse, pulse Spray dryer type 8/1/1992

WV Grant Town Power Plant BLR1A Waste Coal Baghouse, pulse CFB 8/1/1992

WV Grant Town Power Plant BLR1B Waste Coal Baghouse, pulse CFB 8/1/1992

IN Bailly 7 Bituminous Coal Natural Gas Electrostatic precipitator, 

cold side Packed type 6/1/1992
70

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 FGD Type FGD Date

IN Bailly 8 Bituminous Coal Natural Gas SCR

Electrostatic precipitator, 

cold side Packed type 6/1/1992

PA Panther Creek Energy 

Facility BLR1 Waste Coal SNCR Baghouse, pulse Circulating Dry Scrubber 6/1/1992

PA Panther Creek Energy 

Facility BLR2 Waste Coal SNCR Baghouse, pulse Circulating Dry Scrubber 6/1/1992

VA Cogentrix of Richmond 1A Bituminous Coal Baghouse, pulse Spray dryer type 5/1/1992

VA Cogentrix of Richmond 1B Bituminous Coal Baghouse, pulse Spray dryer type 5/1/1992

VA Cogentrix of Richmond 2A Bituminous Coal Baghouse, pulse Spray dryer type 5/1/1992

VA Cogentrix of Richmond 2B Bituminous Coal Baghouse, pulse Spray dryer type 5/1/1992

VA Altavista Power Station 1 Bituminous Coal SNCR Baghouse, pulse Spray dryer type 2/1/1992

WV Morgantown Energy Facility CFB1 Waste Coal Baghouse, pulse CFB 1/1/1992

WV Morgantown Energy Facility CFB2 Waste Coal Baghouse, pulse CFB 1/1/1992

TX Twin Oaks Power One U2 Lignite Coal Baghouse, shake and deflate CFB 10/1/1991

VA Southampton Power Station 1 Bituminous Coal Baghouse, pulse Spray dryer type 6/1/1991

PA Ebensburg Power 031 Waste Coal Baghouse, pulse CFB 5/1/1991

PA Cambria Cogen B1 Waste Coal SNCR Baghouse, shake and deflate CFB 3/1/1991

PA Cambria Cogen B2 Waste Coal SNCR Baghouse, shake and deflate CFB 3/1/1991

OH W. H. Zimmer 1 Bituminous Coal Electrostatic precipitator, 

cold side Spray type 3/1/1991
71

Attachment 9. List of coal-fired electric utility steam generating units selected for dioxin/furan organic HAP testing

State Plant Name

Boiler 

ID Primary Fuel

Secondary 

Fuel

NOX

Control PM Control 1 PM Control 2 FGD_Type01 ACI

CA ACE Cogeneration 

Facility CFB Bituminous Coal Petroleum Coke Baghouse, reverse air CFB

CT AES Thames A Bituminous Coal Baghouse, reverse air Circulating Dry 

Scrubber

CT AES Thames B Bituminous Coal Baghouse, reverse air Circulating Dry 

Scrubber

VA Altavista Power 

Station 1 Bituminous Coal SNCR Baghouse, pulse Spray dryer type

NY Black River 

Generation E0003 Bituminous Coal Baghouse, pulse Multiple cyclone Jet Bubbling Reactor

VA Chesterfield 6 Bituminous Coal Electrostatic precipitator, cold side

NC

Cogentrix Dwayne 

Collier Battle 

Cogen

1A Bituminous Coal Baghouse, pulse Spray dryer type

VA Cogentrix of 

Richmond 4A Bituminous Coal Baghouse, pulse Spray dryer type

IA Council Bluffs 4 Subbituminous Coal SCR Baghouse, pulse Spray dryer type Y

CO Craig C2 Subbituminous Coal Baghouse, pulse Spray type

TN Cumberland 1 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type

WY Dave Johnston BW41 Subbituminous Coal Electrostatic precipitator, cold side

DE Edge Moor 4 Bituminous Coal Residual Fuel 

Oil Electrostatic precipitator, cold side Y

KY Green River 5 Bituminous Coal Electrostatic precipitator, hot side

KY H. L. Spurlock 2 Bituminous Coal SCR Electrostatic precipitator, hot side Spray dryer type

IL Havana 9 Subbituminous Coal SCR Electrostatic precipitator, hot side Baghouse, pulse Y

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 Spray type

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 Venturi type

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 N/A
72

State Plant Name

Boiler 

ID Primary Fuel

Secondary 

Fuel

NOX

Control PM Control 1 PM Control 2 FGD_Type01 ACI

CO Ray D. Nixon 1 Subbituminous Coal Baghouse, reverse air

NC Roanoke Valley I BLR1 Bituminous Coal Distillate Fuel 

Oil Baghouse, reverse air Circulating Dry Scrubber

GA Scherer 1 Subbituminous Coal Electrostatic precipitator, hot side Y

GA Scherer 3 Subbituminous Coal Electrostatic precipitator, cold side Spray type Y

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 Spray dryer type

WA Transalta Centralia 

Generation BW21 Subbituminous Coal Wet scrubber Electrostatic precipitator, cold side Spray type

NY Trigen Syracuse 

Energy 2 Bituminous Coal Baghouse, reverse air N/A

TX Twin Oaks Power 

One U2 Lignite Coal Baghouse, shake and deflate CFB

WY Two Elk 

Generating Station 1 Subbituminous Coal SCR Baghouse, pulse Spray type

IL Vermilion 1 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side Baghouse, pulse Y

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 Spray type

AL Widows Creek 8 Bituminous Coal Wet scrubber Tray type

SC Winyah 1 Bituminous Coal Coal-based 

Synfuel Electrostatic precipitator, cold side Wet scrubber Venturi type

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 organic HAP testing

State Plant Name Boiler ID Primary Fuel Secondary Fuel Boiler Date NOX Control PM Control 1 PM Control 2 FGD Type

TX Oak Grove 1 Lignite Coal 12/31/2009 SCR Baghouse, pulse Spray dryer type

AR Plum Point 

Energy STG1 Subbituminous Coal 12/31/2009 SCR Baghouse, pulse Spray dryer type

AZ Springerville 4 Subbituminous Coal Bituminous Coal 12/31/2009 SCR Baghouse, pulse Spray dryer type

WY

Two Elk 

Generating 

Station

1 Subbituminous Coal 12/31/2009 SCR Baghouse, pulse Spray type

TX Sandow Station 5A Lignite Coal 8/31/2009 SCR Baghouse, pulse Spray type

TX Sandow Station 5B Lignite Coal 8/31/2009 SCR Baghouse, pulse Spray type

WI

Elm Road 

Generating 

Station

1 Bituminous Coal 6/1/2009 SCR Baghouse, pulse Spray type

NE Nebraska City 2 Subbituminous Coal 5/1/2009 Baghouse, pulse Spray type

SC Cross 4 Bituminous Coal 1/1/2009 SCR Electrostatic precipitator, cold side Spray type

IL Dallman 34 Bituminous Coal 1/1/2009 SCR Baghouse, pulse Packed type

NV TS Power Plant BLR100 Subbituminous Coal 6/1/2008 SCR Baghouse, pulse Spray dryer type

WI Weston 4 Bituminous Coal Subbituminous 

Coal 6/1/2008 SCR Baghouse, pulse Spray dryer type

KY H. L. Spurlock 4 Bituminous Coal 4/1/2008 SNCR Baghouse, pulse CFB

WY Wygen II 4 Subbituminous Coal 12/31/2007 SCR Baghouse, pulse Spray type

IA Council Bluffs 4 Subbituminous Coal 6/1/2007 SCR Baghouse, pulse Spray dryer type

SC Cross 3 Bituminous Coal Coal-based 

Synfuel 1/1/2007 SCR Electrostatic precipitator, cold side Spray type

AZ Springerville 3 Subbituminous Coal 12/31/2006 SCR Baghouse, pulse Spray dryer type

MT

Hardin 

Generator 

Project

PC1 Subbituminous Coal 4/1/2006 SCR Baghouse, pulse Spray dryer type

KY H. L. Spurlock 3 Bituminous Coal 4/1/2005 SNCR Baghouse, pulse CFB

PA Seward 1 Waste Coal Bituminous Coal 3/1/2004 SNCR Baghouse, pulse Spray dryer type

PA Seward 2 Waste Coal Bituminous Coal 3/1/2004 SNCR Baghouse, pulse Spray dryer type

IL Marion 123 Waste Coal Bituminous Coal 5/1/2003 Baghouse, pulse CFB

WY Wygen I 3 Subbituminous Coal 5/1/2003 SCR Baghouse, pulse Spray type

PR AES Puerto 

Rico (Aurora) 1 Bituminous Coal 12/31/2002 SNCR Baghouse, pulse CFB

PR AES Puerto 

Rico (Aurora) 2 Bituminous Coal 12/31/2002 SNCR Baghouse, pulse CFB
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 PM Control 2 FGD Type

MS

Red Hills 

Generating 

Facility

AA001 Lignite Coal 3/1/2002 Baghouse, reverse air CFB

MS

Red Hills 

Generating 

Facility

AA002 Lignite Coal 3/1/2002 Baghouse, reverse air CFB

MO Hawthorn 5A Subbituminous Coal Natural Gas 6/1/2001 SCR Baghouse, pulse Spray dryer type

MD

AES Warrior 

Run 

Cogeneration 

Facility

BLR1 Bituminous Coal 2/1/2000 SCR and SNCR Baghouse, reverse air CFB

VA Birchwood 

Power 1A Bituminous Coal 12/1/1996 SCR Baghouse, reverse air Spray dryer type

FL Stanton Energy 

Center 2 Bituminous Coal 6/1/1996 SCR Electrostatic precipitator, cold side Spray type

VA Clover 2 Bituminous Coal 3/1/1996 Baghouse, reverse air Spray type

FL

Indiantown 

Cogeneration 

LP

AAB01 Bituminous Coal 12/1/1995 SCR Baghouse, reverse air Spray dryer type

SC Cope COP1 Bituminous Coal Natural Gas 11/1/1995 Baghouse, reverse air Spray dryer type

WY Neil Simpson II 2 Subbituminous Coal 11/1/1995 Electrostatic precipitator, cold side Circulating Dry 

Scrubber

VA Clover 1 Bituminous Coal 10/1/1995 Baghouse, reverse air Spray type

PA

Northampton 

Generating 

Company

BLR1 Waste Coal Petroleum Coke 8/1/1995 SNCR Baghouse, pulse CFB

NC Roanoke 

Valley II BLR2 Bituminous Coal 6/1/1995 Baghouse, pulse Circulating Dry Scrubber

PA Colver Power 

Project ABB01 Waste Coal 5/1/1995 Baghouse, pulse CFB

SC Cross 1 Bituminous Coal

Coal-based 

Synfuel 5/1/1995 SCR Electrostatic precipitator, cold side Spray type

NJ

Logan 

Generating 

Plant

B01 Bituminous Coal 9/1/1994 SCR Baghouse, reverse air Spray dryer type

NC Roanoke 

Valley I

BLR1 Bituminous Coal Distillate Fuel Oil 5/1/1994 Baghouse, reverse air Circulating Dry 

Scrubber

NJ

Chambers 

Cogeneration 

LP

BOIL1 Bituminous Coal 3/1/1994 SCR Baghouse, reverse air Spray dryer type

NJ

Chambers 

Cogeneration 

LP

BOIL2 Bituminous Coal 3/1/1994 SCR Baghouse, reverse air Spray dryer type

FL Cedar Bay 

Generating LP CBA Bituminous Coal 1/1/1994 SNCR Baghouse, reverse air Circulating Dry Scrubber

FL Cedar Bay 

Generating LP CBB Bituminous Coal 1/1/1994 SNCR Baghouse, reverse air Circulating Dry Scrubber
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 PM Control 2 FGD Type

FL Cedar Bay 

Generating LP CBC Bituminous Coal 1/1/1994 SNCR Baghouse, reverse air Circulating Dry Scrubber

PA Scrubgrass 

Generating UNIT 1 Waste Coal 6/1/1993 SNCR Baghouse, pulse CFB

PA Scrubgrass 

Generating UNIT 2 Waste Coal 6/1/1993 SNCR Baghouse, pulse CFB

UT

Sunnyside 

Cogen 

Associates

1 Waste Coal 2/1/1993 Baghouse, pulse CFB

WV North Branch 1A Bituminous Coal Waste Oil 12/31/1992 Baghouse, pulse CFB

WV North Branch 1B Bituminous Coal Waste Oil 12/31/1992 Baghouse, pulse CFB

TX J. K. Spruce BLR1 Subbituminous Coal 12/1/1992 Baghouse, reverse air Spray type

PA Piney Creek 

Project BRBR1 Waste Coal 12/1/1992 SNCR Baghouse, pulse Circulating Dry Scrubber

VA Mecklenburg 

Power Station BLR1 Bituminous Coal 11/1/1992 Baghouse, pulse Circulating Dry Scrubber

VA Mecklenburg 

Power Station BLR2 Bituminous Coal 11/1/1992 Baghouse, pulse Circulating Dry Scrubber

HI AES Hawaii BLRA Subbituminous Coal Tire-derived Fuels 9/1/1992 SNCR Baghouse, reverse air CFB

HI AES Hawaii BLRB Subbituminous Coal Waste Oil 9/1/1992 SNCR Baghouse, reverse air CFB

VA Cogentrix of 

Richmond 3A Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer type

VA Cogentrix of 

Richmond 3B Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer type

VA Cogentrix of 

Richmond 4A Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer type

VA Cogentrix of 

Richmond 4B Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer type

WV Grant Town 

Power Plant BLR1A Waste Coal 8/1/1992 Baghouse, pulse CFB

WV Grant Town 

Power Plant BLR1B Waste Coal 8/1/1992 Baghouse, pulse CFB

PA Panther Creek 

Energy Facility BLR1 Waste Coal 6/1/1992 SNCR Baghouse, pulse Circulating Dry Scrubber

PA Panther Creek 

Energy Facility BLR2 Waste Coal 6/1/1992 SNCR Baghouse, pulse Circulating Dry Scrubber

VA Cogentrix of 

Richmond 1A Bituminous Coal 5/1/1992 Baghouse, pulse Spray dryer type

VA Cogentrix of 

Richmond 1B Bituminous Coal 5/1/1992 Baghouse, pulse Spray dryer type

VA Cogentrix of 

Richmond 2A Bituminous Coal 5/1/1992 Baghouse, pulse Spray dryer type

VA Cogentrix of 

Richmond 2B Bituminous Coal 5/1/1992 Baghouse, pulse Spray dryer type

VA Altavista Power 

Station 1 Bituminous Coal 2/1/1992 SNCR Baghouse, pulse Spray dryer type
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 PM Control 2 FGD Type

WV Morgantown 

Energy Facility CFB1 Waste Coal 1/1/1992 Baghouse, pulse CFB

WV Morgantown 

Energy Facility CFB2 Waste Coal 1/1/1992 Baghouse, pulse CFB

TX Twin Oaks 

Power One U2 Lignite Coal 10/1/1991 Baghouse, shake and deflate CFB

VA Southampton 

Power Station 1 Bituminous Coal 6/1/1991 Baghouse, pulse Spray dryer type

MD Brandon Shores 2 Bituminous Coal 5/1/1991 SCR Electrostatic precipitator, hot side Spray type

PA Ebensburg 

Power 031 Waste Coal 5/1/1991 Baghouse, pulse CFB

PA Cambria Cogen B1 Waste Coal 3/1/1991 SNCR Baghouse, shake and deflate CFB

PA Cambria Cogen B2 Waste Coal 3/1/1991 SNCR Baghouse, shake and deflate CFB

AL James H Miller 

Jr. 4 Subbituminous Coal 3/1/1991 SCR Electrostatic precipitator, cold side Spray type

OH W. H. Zimmer 1 Bituminous Coal 3/1/1991 Electrostatic precipitator, cold side Spray type

OK AES Shady 

Point 1A Bituminous Coal 1/1/1991 Baghouse, pulse CFB

OK AES Shady 

Point 1B Bituminous Coal 1/1/1991 Baghouse, pulse CFB

OK AES Shady 

Point 2A Bituminous Coal 1/1/1991 Baghouse, pulse CFB

OK AES Shady 

Point 2B Bituminous Coal 1/1/1991 Baghouse, pulse CFB

CO Nucla 1 Bituminous Coal 1/1/1991 Baghouse, shake and deflate CFB

NY

Trigen 

Syracuse 

Energy

1 Bituminous Coal 1/1/1991 Baghouse, reverse air N/A

NY

Trigen 

Syracuse 

Energy

2 Bituminous Coal 1/1/1991 Baghouse, reverse air N/A

NY

Trigen 

Syracuse 

Energy

3 Bituminous Coal 1/1/1991 Baghouse, reverse air N/A

NY

Trigen 

Syracuse 

Energy

4 Bituminous Coal 1/1/1991 Baghouse, reverse air N/A

NY

Trigen 

Syracuse 

Energy

5 Bituminous Coal 1/1/1991 Baghouse, reverse air N/A

KY Shawnee 10 Bituminous Coal 12/1/1990 Baghouse, reverse air CFB

KY Trimble County 1 Bituminous Coal 12/1/1990 SCR Electrostatic precipitator, cold side Spray type

NC

Cogentrix 

Dwayne Collier 

Battle Cogen

1A Bituminous Coal 10/1/1990 Baghouse, pulse Spray dryer type
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 PM Control 2 FGD Type

NC

Cogentrix 

Dwayne Collier 

Battle Cogen

1B Bituminous Coal 10/1/1990 Baghouse, pulse Spray dryer type

NC

Cogentrix 

Dwayne Collier 

Battle Cogen

2A Bituminous Coal 10/1/1990 Baghouse, pulse Spray dryer type

NC

Cogentrix 

Dwayne Collier 

Battle Cogen

2B Bituminous Coal 10/1/1990 Baghouse, pulse Spray dryer type

PA

Foster Wheeler 

Mt Carmel 

Cogen

SG-101 Waste Coal 9/1/1990 Baghouse, pulse Circulating Dry 

Scrubber

TX Twin Oaks 

Power One U1 Lignite Coal 9/1/1990 Baghouse, shake and deflate CFB

CA

ACE 

Cogeneration 

Facility

CFB Bituminous Coal Petroleum Coke 6/1/1990 Baghouse, reverse air CFB

WI Manitowoc 8 Bituminous Coal Petroleum Coke 6/1/1990 Single cyclone Baghouse, pulse CFB

AZ Springerville 2 Subbituminous Coal 6/1/1990 Baghouse, reverse air Spray dryer type

MI TES Filer City 

Station 1 Bituminous Coal 6/1/1990 Baghouse, pulse Spray dryer type

MI TES Filer City 

Station 2 Bituminous Coal 6/1/1990 Baghouse, pulse Spray dryer type

NY WPS Power 

Niagara 1 Bituminous Coal 4/1/1990 SNCR Baghouse, pulse CFB

CT AES Thames A Bituminous Coal 3/1/1990 Baghouse, reverse air Circulating Dry 

Scrubber

CT AES Thames B Bituminous Coal 3/1/1990 Baghouse, reverse air Circulating Dry 

Scrubber

MT Colstrip Energy 

LP BLR1 Waste Coal 2/1/1990 Baghouse, pulse CFB

IN Rockport MB2 Subbituminous Coal 12/1/1989 Electrostatic precipitator, cold side N/A

PA St. Nicholas 

Cogen Project 1 Waste Coal 12/1/1989 Baghouse, pulse CFB

PA

Kline 

Township 

Cogen Facility

1 Waste Coal 11/1/1989 Single cyclone Baghouse, pulse CFB

AL James H Miller 

Jr. 3 Subbituminous Coal 5/1/1989 SCR Electrostatic precipitator, cold side Spray type

GA Scherer 4 Subbituminous Coal 2/1/1989 Electrostatic precipitator, cold side Spray type

PA

Wheelabrator 

Frackville 

Energy

BLR1 Waste Coal 9/1/1988 Baghouse, pulse CFB

NY Black River 

Generation E0001 Bituminous Coal 6/1/1988 Baghouse, pulse Multiple cyclone Jet Bubbling Reactor

NY Black River 

Generation E0002 Bituminous Coal 6/1/1988 Baghouse, pulse Multiple cyclone Jet Bubbling Reactor
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 PM Control 2 FGD Type

NY Black River 

Generation E0003 Bituminous Coal 6/1/1988 Baghouse, pulse Multiple cyclone Jet Bubbling Reactor

FL Central Power 

& Lime

1 Bituminous Coal 6/1/1988 Baghouse, reverse air N/A

VA

Cogentrix 

Virginia 

Leasing 

Corporation

1A Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

VA

Cogentrix 

Virginia 

Leasing 

Corporation

1B Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

VA

Cogentrix 

Virginia 

Leasing 

Corporation

1C Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

VA

Cogentrix 

Virginia 

Leasing 

Corporation

2A Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

VA

Cogentrix 

Virginia 

Leasing 

Corporation

2B Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

VA

Cogentrix 

Virginia 

Leasing 

Corporation

2C Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

CA Mt. Poso 

Cogeneration BL01 Bituminous Coal 6/1/1988 SNCR Baghouse, reverse air CFB

PA

WPS 

Westwood 

Generation 

LLC

031 Waste Coal 6/1/1988 Baghouse, reverse air N/A

FL St Johns River 

Power Park 2 Bituminous Coal Coal-based Synfuel 5/1/1988 Electrostatic precipitator, cold side Spray type

TX Fayette Power 

Project 3 Subbituminous Coal 4/1/1988 Electrostatic precipitator, cold side Spray type

PA

John B Rich 

Memorial 

Power Station

CFB1 Waste Coal 2/1/1988 Baghouse, pulse CFB

PA

John B Rich 

Memorial 

Power Station

CFB2 Waste Coal 2/1/1988 Baghouse, pulse CFB

VA Cogentrix 

Hopewell 1A Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type

VA Cogentrix 

Hopewell 1B Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type

VA Cogentrix 

Hopewell 1C Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type
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 PM Control 2 FGD Type

VA Cogentrix 

Hopewell 2A Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type

VA Cogentrix 

Hopewell 2B Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type

VA Cogentrix 

Hopewell 2C Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type

MN Sherburne 

County 3 Subbituminous Coal 11/1/1987 Baghouse, reverse air Spray dryer type

NY

Danskammer 

Generating 

Station

3 Bituminous Coal Natural Gas 9/1/1987 Electrostatic precipitator, cold side N/A

NC Primary Energy 

Southport 1A Bituminous Coal 9/1/1987 Baghouse, pulse N/A

NC Primary Energy 

Southport 1B Bituminous Coal 9/1/1987 Baghouse, pulse N/A

NC Primary Energy 

Southport 1C Bituminous Coal 9/1/1987 Baghouse, pulse N/A

NC Primary Energy 

Southport 2A Bituminous Coal 9/1/1987 Baghouse, pulse N/A

NC Primary Energy 

Southport 2B Bituminous Coal 9/1/1987 Baghouse, pulse N/A

NC Primary Energy 

Southport 2C Bituminous Coal 9/1/1987 Baghouse, pulse N/A

NC Primary Energy 

Roxboro 1A Bituminous Coal 8/1/1987 Baghouse, pulse N/A

NC Primary Energy 

Roxboro 1B Bituminous Coal 8/1/1987 Baghouse, pulse N/A

NC Primary Energy 

Roxboro 1C Bituminous Coal 8/1/1987 Baghouse, pulse N/A

PA

AES Beaver 

Valley Partners 

Beaver Valley

2 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side Wet scrubber Spray type

PA

AES Beaver 

Valley Partners 

Beaver Valley

3 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side Wet scrubber Spray type

PA

AES Beaver 

Valley Partners 

Beaver Valley

4 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side Wet scrubber Spray type

PA

AES Beaver 

Valley Partners 

Beaver Valley

5 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side Wet scrubber Spray type

FL Stanton Energy 

Center 1 Bituminous Coal 7/1/1987 Electrostatic precipitator, cold side Spray type

UT Intermountain 

Power Project 2SGA Bituminous Coal Subbituminous Coal 5/1/1987 Baghouse, reverse air Spray type

NY

Danskammer 

Generating 

Station

4 Bituminous Coal Natural Gas 3/1/1987 Electrostatic precipitator, cold side N/A

FL St. Johns River 

Power Park 1 Bituminous Coal Coal-based Synfuel 3/1/1987 Electrostatic precipitator, cold side Spray type
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 PM Control 2 FGD Type

GA Scherer 3 Subbituminous Coal 1/1/1987 Electrostatic precipitator, cold side Spray type

TX Oklaunion 1 Bituminous Coal 12/1/1986 Electrostatic precipitator, cold side Spray type

KY D. B. Wilson W1 Bituminous Coal 11/1/1986 Electrostatic precipitator, cold side Spray type

TX Limestone LIM2 Lignite Coal Subbituminous 

Coal 10/1/1986 Electrostatic precipitator, cold side Spray type

ND Antelope 

Valley B2 Lignite Coal 7/1/1986 Baghouse, reverse air Spray dryer type

UT Intermountain 

Power Project 1SGA Bituminous Coal Subbituminous Coal 6/1/1986 Baghouse, reverse air Spray type

UT Bonanza 1-1 Bituminous Coal 5/1/1986 Baghouse, reverse air Spray type

IN AES Petersburg 4 Bituminous Coal 4/1/1986 Electrostatic precipitator, cold side Spray type

MT Colstrip 4 Subbituminous Coal 4/1/1986 Wet scrubber Venturi type

LA Dolet Hills 1 Lignite Coal Natural Gas 4/1/1986 Electrostatic precipitator, cold side Wet scrubber Spray type

OK GRDA 2 Subbituminous Coal 4/1/1986 Electrostatic precipitator, cold side Spray dryer type

IN A. B. Brown 2 Bituminous Coal 2/1/1986 SCR Electrostatic precipitator, cold side Spray type

IN R. M. Schahfer 18 Bituminous Coal 2/1/1986 Electrostatic precipitator, cold side Spray type

TX Limestone LIM1 Lignite Coal Subbituminous 

Coal 10/1/1985 Electrostatic precipitator, cold side Spray type

MI Belle River 2 Subbituminous Coal 7/1/1985 Electrostatic precipitator, cold side N/A

NV North Valmy 2 Bituminous Coal Subbituminous 

Coal 7/1/1985 Baghouse, reverse air Spray dryer type

WI Pleasant Prairie 2 Subbituminous Coal 7/1/1985 Electrostatic precipitator, cold side Spray type

TX Tolk 172B Subbituminous Coal 7/1/1985 Baghouse, reverse air N/A

AZ Springerville 1 Subbituminous Coal 6/1/1985 Baghouse, reverse air Spray dryer type

AL James H Miller 

Jr. 2 Subbituminous Coal 5/1/1985 Electrostatic precipitator, cold side N/A
81

Attachment 11. List of coal-fired electric utility steam generating units selected for mercury and other non-mercury metallic HAP testing

State Plant Name Boiler ID Primary Fuel Secondary Fuel

NOX

Control PM Control 1 PM Control 2 PM Control Date FGD Type

TX Oak Grove 1 Lignite Coal SCR Baghouse, pulse 12/31/2009 Spray dryer type

AR Plum Point 

Energy STG1 Subbituminous Coal SCR Baghouse, pulse 12/31/2009 Spray dryer type

AZ Springerville 4 Subbituminous Coal Bituminous Coal SCR Baghouse, pulse 12/31/2009 Spray dryer type

WY

Two Elk 

Generating 

Station

1 Subbituminous Coal

SCR

Baghouse, pulse 12/31/2009 Spray type

AZ Cholla 3 Subbituminous Coal Baghouse, pulse 9/1/2008 Spray dryer type

AZ Cholla 4 Subbituminous Coal Baghouse, pulse 9/1/2008 Spray dryer type

TX Sandow Station 5A Lignite Coal SCR Baghouse, pulse 8/31/2009 Spray type

TX Sandow Station 5B Lignite Coal SCR Baghouse, pulse 8/31/2009 Spray type

WI

Elm Road 

Generating 

Station

1 Bituminous Coal

SCR

Baghouse, pulse 6/1/2009 Spray type

NE Nebraska City 2 Subbituminous Coal Baghouse, pulse 5/1/2009 Spray type

SC Cross 4 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 1/1/2009 Spray type

IL Dallman 34 Bituminous Coal SCR Baghouse, pulse 1/1/2009 Packed type

NM San Juan 1 Subbituminous Coal Baghouse, pulse 12/1/2008 Spray type

NM San Juan 2 Subbituminous Coal Baghouse, pulse 12/1/2008 Spray type

NM San Juan 3 Subbituminous Coal Baghouse, pulse 12/1/2008 Spray type

NM San Juan 4 Subbituminous Coal Baghouse, pulse 12/1/2008 Spray type

NV TS Power Plant BLR100 Subbituminous Coal SCR Baghouse, pulse 6/1/2008 Spray dryer type

WI Weston 4 Bituminous Coal Subbituminous Coal SCR Baghouse, pulse 6/1/2008 Spray dryer type

IL Hennepin 

Power Station 2 Subbituminous Coal Natural Gas Baghouse, pulse 6/1/2008

KY H. L. Spurlock 4 Bituminous Coal SNCR Baghouse, pulse 4/1/2008 CFB

WY Wygen II 4 Subbituminous Coal SCR Baghouse, pulse 12/31/2007 Spray type

IA Louisa 101 Subbituminous Coal Baghouse, pulse

Electrostatic 

precipitator, hot 

side

12/1/2007 Spray dryer type

IA Council Bluffs 4 Subbituminous Coal SCR Baghouse, pulse 6/1/2007 Spray dryer type

SC Cross 3 Bituminous Coal Coal-based Synfuel SCR

Electrostatic precipitator, cold 

side 1/1/2007 Spray type

AZ Springerville 3 Subbituminous Coal SCR Baghouse, pulse 12/31/2006 Spray dryer type
82

State Plant Name Boiler ID Primary Fuel Secondary Fuel

NOX

Control PM Control 1 PM Control 2 PM Control Date FGD Type

MT

Hardin 

Generator 

Project

PC1 Subbituminous Coal

SCR

Baghouse, pulse 4/1/2006 Spray dryer type

NC Asheville 1 Bituminous Coal Electrostatic precipitator, cold 

side 11/1/2005 Spray type

IN A. B. Brown 1 Bituminous Coal

SCR

Baghouse, pulse

Electrostatic 

precipitator, cold 

side

6/1/2005 Spray type

KY H. L. Spurlock 3 Bituminous Coal SNCR Baghouse, pulse 4/1/2005 CFB

KY Cane Run 5 Bituminous Coal Coal-based Synfuel Electrostatic precipitator, cold 

side 6/1/2004 Spray type

CO Craig C2 Subbituminous Coal Baghouse, pulse 5/1/2004 Spray type

FL Crist 7 Bituminous Coal Natural Gas SCR

Electrostatic precipitator, cold 

side 4/1/2004

PA Seward 1 Waste Coal Bituminous Coal SNCR Baghouse, pulse 3/1/2004 Spray dryer type

PA Seward 2 Waste Coal Bituminous Coal SNCR Baghouse, pulse 3/1/2004 Spray dryer type

CO Craig C1 Subbituminous Coal Baghouse, pulse 11/1/2003 Spray type

IL Marion 123 Waste Coal Bituminous Coal Baghouse, pulse 5/1/2003 CFB

KY H. L. Spurlock 1 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 4/1/2003

WY Wygen I 3 Subbituminous Coal SCR Baghouse, pulse 1/1/2003 Spray type

PR AES Puerto 

Rico (Aurora) 1 Bituminous Coal SNCR Baghouse, pulse 12/31/2002 CFB

PR AES Puerto 

Rico (Aurora) 2 Bituminous Coal SNCR Baghouse, pulse 12/31/2002 CFB

SD Big Stone 1 Subbituminous Coal Baghouse, pulse 10/1/2002

MD Herbert A 

Wagner 2 Bituminous Coal Electrostatic precipitator, cold side 8/1/2002

WA

Transalta 

Centralia 

Generation

BW21 Subbituminous Coal Wet scrubber

Electrostatic 

precipitator, cold 

side

6/1/2002 Spray type

MS

Red Hills 

Generating 

Facility

AA001 Lignite Coal Baghouse, reverse air 3/1/2002 CFB

MS

Red Hills 

Generating 

Facility

AA002 Lignite Coal Baghouse, reverse air 3/1/2002 CFB

WA

Transalta 

Centralia 

Generation

BW22 Subbituminous Coal Wet scrubber

Electrostatic 

precipitator, cold 

side

10/1/2001 Spray type

MI J. H. Campbell 1 Bituminous Coal Subbituminous Coal Electrostatic precipitator, cold 

side 6/1/2001
83

State Plant Name Boiler ID Primary Fuel Secondary Fuel

NOX

Control PM Control 1 PM Control 2 PM Control Date FGD Type

NE Gerald 

Gentleman 2 Subbituminous Coal Baghouse, reverse air 5/1/2001

MO Hawthorn 5A Subbituminous Coal Natural Gas SCR Baghouse, pulse 5/1/2001 Spray dryer type

WI Weston 3 Subbituminous Coal Baghouse, pulse 5/1/2001

PA PPL Montour 1 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 4/1/2001

GA Hammond 1 Bituminous Coal Electrostatic precipitator, cold 

side 1/1/2001

NE Gerald 

Gentleman 1 Subbituminous Coal Baghouse, reverse air 12/1/2000

PA PPL Montour 2 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 6/1/2000

IL Will County 4 Subbituminous Coal Electrostatic precipitator, cold 

side 4/1/2000

MD

AES Warrior 

Run 

Cogeneration 

Facility

BLR1 Bituminous Coal SCR and 

SNCR

Baghouse, reverse air 2/1/2000 CFB

PA PPL Brunner 

Island 2 Bituminous Coal Electrostatic precipitator, cold side 2/1/2000

NE Sheldon 2 Subbituminous Coal Natural Gas Baghouse, pulse 2/1/2000

NE Sheldon 1 Subbituminous Coal Natural Gas Baghouse, pulse 12/1/1999

NC Cape Fear 5 Bituminous Coal Electrostatic precipitator, cold 

side 11/1/1999

NH Merrimack 2 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 10/1/1999

CO Hayden H2 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air 6/1/1999 Spray dryer type

SC Canadys Steam CAN3 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air 5/1/1999

IA Muscatine Plant 

#1 8 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side 4/1/1999

IN State Line 

Energy 3 Subbituminous Coal Baghouse, pulse 1/1/1999

CO Hayden H1 Bituminous Coal Natural Gas Baghouse, reverse air 12/1/1998 Spray dryer type

MI Erickson 

Station 1 Subbituminous Coal Electrostatic precipitator, cold side 11/1/1998

NC Asheville 2 Bituminous Coal Electrostatic precipitator, cold 

side 5/1/1998

CO Martin Drake 5 Subbituminous Coal Natural Gas Baghouse, reverse air 5/1/1998

SC H. B. Robinson 1 Bituminous Coal Electrostatic precipitator, cold 

side 5/1/1997

GA Hammond 2 Bituminous Coal Electrostatic precipitator, cold 

side 5/1/1997
84

State Plant Name Boiler ID Primary Fuel Secondary Fuel

NOX

Control PM Control 1 PM Control 2 PM Control Date FGD Type

NC Roxboro 2 Bituminous Coal Electrostatic precipitator, cold 

side 1/1/1997

VA Birchwood 

Power 1A Bituminous Coal SCR Baghouse, reverse air 12/1/1996 Spray dryer type

FL Stanton Energy 

Center 2 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 6/1/1996 Spray type

VA Clover 2 Bituminous Coal Baghouse, reverse air 3/1/1996 Spray type

IL Waukegan 8 Subbituminous Coal Electrostatic precipitator, cold 

side 1/1/1996

FL

Indiantown 

Cogeneration 

LP

AAB01 Bituminous Coal

SCR

Baghouse, reverse air 12/1/1995 Spray dryer type

SC Cope COP1 Bituminous Coal Natural Gas Baghouse, reverse air 11/1/1995 Spray dryer type

WY Neil Simpson II 2 Subbituminous Coal Electrostatic precipitator, cold 

side 11/1/1995 Circulating Dry Scrubber

PA

Northampton 

Generating 

Company

BLR1 Waste Coal Petroleum Coke

SNCR

Baghouse, pulse 8/1/1995 CFB

WI Valley 3 Bituminous Coal Baghouse, pulse 7/1/1995

WI Valley 4 Bituminous Coal Baghouse, pulse 7/1/1995

NC Roanoke Valley 

II BLR2 Bituminous Coal Baghouse, pulse 6/1/1995 Circulating Dry Scrubber

NC Roxboro 1 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 6/1/1995

PA Colver Power 

Project ABB01 Waste Coal Baghouse, pulse 5/1/1995 CFB

SC Cross 1 Bituminous Coal Coal-based Synfuel SCR

Electrostatic precipitator, cold 

side 5/1/1995 Spray type

IN Eagle Valley 6 Bituminous Coal Electrostatic precipitator, cold 

side 2/1/1995

IN Harding Street 60 Bituminous Coal

SNCR

Multiple cyclone

Electrostatic 

precipitator, cold 

side

2/1/1995

VA Clover 1 Bituminous Coal Baghouse, reverse air 1/1/1995 Spray type

WI Manitowoc 6 Bituminous Coal Multiple cyclone Baghouse, pulse 1/1/1995

WI Manitowoc 7 Bituminous Coal Multiple cyclone Baghouse, pulse 1/1/1995

NJ

Logan 

Generating 

Plant

B01 Bituminous Coal

SCR

Baghouse, reverse air 9/1/1994 Spray dryer type

WI Valley 1 Bituminous Coal Baghouse, pulse 7/1/1994

WI Valley 2 Bituminous Coal Baghouse, pulse 7/1/1994
85

State Plant Name Boiler ID Primary Fuel Secondary Fuel

NOX

Control PM Control 1 PM Control 2 PM Control Date FGD Type

FL Crist 6 Bituminous Coal Natural Gas Electrostatic precipitator, cold 

side 6/1/1994

IN Harding Street 70 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 6/1/1994

NJ

PSEG Mercer 

Generating 

Station

1 Bituminous Coal Natural Gas SCR and 

SNCR

Electrostatic precipitator, cold 

side 6/1/1994

GA Hammond 4 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 5/1/1994

NC Roanoke Valley 

I

BLR1 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air 5/1/1994 Circulating Dry Scrubber

MO James River 

Power Station 5 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side 4/1/1994

NJ

Chambers 

Cogeneration 

LP

BOIL1 Bituminous Coal

SCR

Baghouse, reverse air 3/1/1994 Spray dryer type

NJ

Chambers 

Cogeneration 

LP

BOIL2 Bituminous Coal

SCR

Baghouse, reverse air 3/1/1994 Spray dryer type

FL Cedar Bay 

Generating LP CBA Bituminous Coal SNCR Baghouse, reverse air 2/1/1994 Circulating Dry Scrubber

FL Cedar Bay 

Generating LP CBB Bituminous Coal SNCR Baghouse, reverse air 2/1/1994 Circulating Dry Scrubber

FL Cedar Bay 

Generating LP CBC Bituminous Coal SNCR Baghouse, reverse air 2/1/1994 Circulating Dry Scrubber

KY Elmer Smith 1 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 11/1/1993 Spray type

CO Martin Drake 7 Subbituminous Coal Natural Gas Baghouse, reverse air 11/1/1993

IN Gibson 2 Bituminous Coal Electrostatic precipitator, cold 

side 7/1/1993

KY Elmer Smith 2 Bituminous Coal SNCR

Electrostatic precipitator, cold 

side 6/1/1993 Spray type

GA Hammond 3 Bituminous Coal Electrostatic precipitator, cold 

side 6/1/1993

PA Scrubgrass 

Generating UNIT 1 Waste Coal SNCR Baghouse, pulse 6/1/1993 CFB

PA Scrubgrass 

Generating UNIT 2 Waste Coal SNCR Baghouse, pulse 6/1/1993 CFB

SC McMeekin MCM1 Coal-based Synfuel Bituminous Coal Baghouse, reverse air 5/1/1993

MO Sibley 1 Subbituminous Coal Electrostatic precipitator, cold 

side 4/1/1993

MO Sibley 3 Subbituminous Coal Electrostatic precipitator, cold 

side 4/1/1993

KY Cane Run 4 Bituminous Coal Coal-based Synfuel Electrostatic precipitator, cold 

side 3/1/1993 Spray type
86

State Plant Name Boiler ID Primary Fuel Secondary Fuel

NOX

Control PM Control 1 PM Control 2 PM Control Date FGD Type

UT

Sunnyside 

Cogen 

Associates

1 Waste Coal Baghouse, pulse 2/1/1993 CFB

WV North Branch 1A Bituminous Coal Waste Oil Baghouse, pulse 12/31/1992 CFB

WV North Branch 1B Bituminous Coal Waste Oil Baghouse, pulse 12/31/1992 CFB

TX J. K. Spruce BLR1 Subbituminous Coal Baghouse, reverse air 12/1/1992 Spray type

PA Piney Creek 

Project BRBR1 Waste Coal SNCR Baghouse, pulse 12/1/1992 Circulating Dry Scrubber

VA Mecklenburg 

Power Station BLR1 Bituminous Coal Baghouse, pulse 11/1/1992 Circulating Dry Scrubber

VA Mecklenburg 

Power Station BLR2 Bituminous Coal Baghouse, pulse 11/1/1992 Circulating Dry Scrubber

IL Meredosia 05 Subbituminous Coal Bituminous Coal Electrostatic precipitator, cold 

side 11/1/1992

HI AES Hawaii BLRA Subbituminous Coal Tire-derived Fuels SNCR Baghouse, reverse air 8/1/1992 CFB

HI AES Hawaii BLRB Subbituminous Coal Waste Oil SNCR Baghouse, reverse air 8/1/1992 CFB

VA Cogentrix of 

Richmond 3A Bituminous Coal Baghouse, pulse 8/1/1992 Spray dryer type

VA Cogentrix of 

Richmond 3B Bituminous Coal Baghouse, pulse 8/1/1992 Spray dryer type

VA Cogentrix of 

Richmond 4A Bituminous Coal Baghouse, pulse 8/1/1992 Spray dryer type

VA Cogentrix of 

Richmond 4B Bituminous Coal Baghouse, pulse 8/1/1992 Spray dryer type

WV Grant Town 

Power Plant BLR1A Waste Coal Baghouse, pulse 8/1/1992 CFB

WV Grant Town 

Power Plant BLR1B Waste Coal Baghouse, pulse 8/1/1992 CFB

PA Panther Creek 

Energy Facility BLR1 Waste Coal SNCR Baghouse, pulse 6/1/1992 Circulating Dry Scrubber

PA Panther Creek 

Energy Facility BLR2 Waste Coal SNCR Baghouse, pulse 6/1/1992 Circulating Dry Scrubber

WI South Oak 

Creek 7 Subbituminous Coal Electrostatic precipitator, cold side 6/1/1992

VA Cogentrix of 

Richmond 1A Bituminous Coal Baghouse, pulse 5/1/1992 Spray dryer type

VA Cogentrix of 

Richmond 1B Bituminous Coal Baghouse, pulse 5/1/1992 Spray dryer type

VA Cogentrix of 

Richmond 2A Bituminous Coal Baghouse, pulse 5/1/1992 Spray dryer type

VA Cogentrix of 

Richmond 2B Bituminous Coal Baghouse, pulse 5/1/1992 Spray dryer type

IN Michigan City 12 Subbituminous Coal Natural Gas SCR

Electrostatic precipitator, cold 

side 5/1/1992
87

State Plant Name Boiler ID Primary Fuel Secondary Fuel

NOX

Control PM Control 1 PM Control 2 PM Control Date FGD Type

KS Quindaro 2 Subbituminous Coal Natural Gas Electrostatic precipitator, cold 

side 5/1/1992

IN Gibson 1 Bituminous Coal Electrostatic precipitator, cold 

side

1/1/1992

SC McMeekin MCM2 Coal-based Synfuel Bituminous Coal Baghouse, reverse air 1/1/1992

WV Morgantown 

Energy Facility CFB1 Waste Coal Baghouse, pulse 1/1/1992 CFB

WV Morgantown 

Energy Facility CFB2 Waste Coal Baghouse, pulse 1/1/1992 CFB

NJ

PSEG Mercer 

Generating 

Station

2 Bituminous Coal Natural Gas SCR and 

SNCR

Electrostatic precipitator, cold 

side 1/1/1992

MO Sibley 2 Subbituminous Coal Electrostatic precipitator, cold 

side 1/1/1992

TX Twin Oaks 

Power One U2 Lignite Coal Baghouse, shake and deflate 10/1/1991 CFB

VA Altavista Power 

Station 1 Bituminous Coal SNCR Baghouse, pulse 6/1/1991 Spray dryer type

CO Comanche 2 Subbituminous Coal Natural Gas Baghouse, reverse air 6/1/1991

WI South Oak 

Creek 8 Subbituminous Coal Electrostatic precipitator, cold side 6/1/1991

VA Southampton 

Power Station 1 Bituminous Coal Baghouse, pulse 6/1/1991 Spray dryer type

OH W. H. Zimmer 1 Bituminous Coal Electrostatic precipitator, cold 

side 6/1/1991 Spray type

MD Brandon Shores 2 Bituminous Coal SCR

Electrostatic precipitator, hot 

side 5/1/1991 Spray type

PA Ebensburg 

Power 031 Waste Coal Baghouse, pulse 5/1/1991 CFB

WI Manitowoc 8 Bituminous Coal Petroleum Coke Single cyclone Baghouse, pulse 4/1/1991 CFB

PA Cambria Cogen B1 Waste Coal SNCR Baghouse, shake and deflate 3/1/1991 CFB

PA Cambria Cogen B2 Waste Coal SNCR Baghouse, shake and deflate 3/1/1991 CFB

AL James H Miller 

Jr. 4 Subbituminous Coal SCR

Electrostatic precipitator, cold 

side 3/1/1991 Spray type

OK AES Shady 

Point 1A Bituminous Coal Baghouse, pulse 1/1/1991 CFB

OK AES Shady 

Point 1B Bituminous Coal Baghouse, pulse 1/1/1991 CFB

OK AES Shady 

Point 2A Bituminous Coal Baghouse, pulse 1/1/1991 CFB

OK AES Shady 

Point 2B Bituminous Coal Baghouse, pulse 1/1/1991 CFB

AL Colbert 4 Bituminous Coal Electrostatic precipitator, cold 

side 1/1/1991
88

State Plant Name Boiler ID Primary Fuel Secondary Fuel

NOX

Control PM Control 1 PM Control 2 PM Control Date FGD Type

CO Nucla 1 Bituminous Coal Baghouse, shake and deflate 1/1/1991 CFB

NY

Trigen 

Syracuse 

Energy

1 Bituminous Coal Baghouse, reverse air 1/1/1991 N/A

NY

Trigen 

Syracuse 

Energy

2 Bituminous Coal Baghouse, reverse air 1/1/1991 N/A

NY

Trigen 

Syracuse 

Energy

3 Bituminous Coal Baghouse, reverse air 1/1/1991 N/A

NY

Trigen 

Syracuse 

Energy

4 Bituminous Coal Baghouse, reverse air 1/1/1991 N/A

NY

Trigen 

Syracuse 

Energy

5 Bituminous Coal Baghouse, reverse air 1/1/1991 N/A

KY Trimble County 1 Bituminous Coal SCR

Electrostatic precipitator, cold 

side 12/1/1990 Spray type

AL Colbert 1 Bituminous Coal Electrostatic precipitator, cold 

side 11/1/1990

CO Comanche 1 Subbituminous Coal Natural Gas Baghouse, reverse air 11/1/1990

NC

Cogentrix 

Dwayne Collier 

Battle Cogen

1A Bituminous Coal Baghouse, pulse 10/1/1990 Spray dryer type

NC

Cogentrix 

Dwayne Collier 

Battle Cogen

1B Bituminous Coal Baghouse, pulse 10/1/1990 Spray dryer type
89

Attachment 12. List of all oil-fired electric utility steam generating units selected for HCl/HF/HCN acid gas HAP, dioxin/furan organic 

HAP, non-dioxin/furan organic HAP, and mercury and other non-mercury metallic HAP testing

State Plant Name Boiler ID NOX Control PM Control 1 PM Control 2

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 Electrostatic precipitator, cold side

DC 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 PM Control 2

PR Costa Sur 9

PR Costa Sur 10

CT Devon Station 8 Electrostatic precipitator, cold side

IN Eagle Valley 1 Multiple cyclone Electrostatic precipitator, cold side

IN Eagle Valley 2 Multiple cyclone Electrostatic precipitator, cold side

NY East River 6

PA Eddystone Generating Station 4 Multiple cyclone Electrostatic precipitator, cold side

DE Edge Moor 5 Multiple cyclone Electrostatic precipitator, cold side

IN Harding Street 9 Multiple cyclone Electrostatic precipitator, cold side

IN Harding Street 10 Multiple cyclone Electrostatic precipitator, cold side

IL 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 PM Control 2

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 Electrostatic precipitator, cold side

PA 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 PM Control 2

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 Electrostatic precipitator, cold side

ME William F Wyman 2 Multiple cyclone Electrostatic precipitator, cold side
93

Attachment 13. List of 50 additional coal-fired electric utility steam generating units not chosen in Attachments 8 through 11 selected for 

HCl/HF/HCN acid gas HAP, non dioxin/furan organic HAP, and mercury and other non-mercury metallic HAP testing

State Plant Name Boiler ID Primary Fuel Secondary Fuel NOX Control PM Control 1 PM Control 2 FGD Control ACI

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 Y

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 Venturi type

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 Electrostatic 

precipitator, cold side Spray type

PA Elrama Power Plant 2 Bituminous Coal

SNCR

Multiple cyclone Electrostatic 

precipitator, cold side Venturi type

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 Control 2 FGD Control ACI

PA Hatfields Ferry Power 

Station 3 Bituminous Coal Electrostatic precipitator, cold side

IL Havana 9 Subbituminous Coal SCR Electrostatic precipitator, hot side Baghouse, pulse Y

MN 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 Baghouse, shake and 

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 Spray type

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 Spray dryer 

type

NV Reid Gardner 1 Bituminous Coal Lignite Coal Multiple cyclone Spray type

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 Control 2 FGD Control ACI

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 Baghouse, pulse Y

OH 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 Electrostatic precipitator, cold side