# 1 INFORMATION COLLECTION REQU EST FOR NATIONAL EMISSION

STANDARDS FOR HAZARDOUS AIR PO LLUTANTS (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- a nd oil-fired electric utility steam generating units (EGUs)

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

rural electric cooperatives, and investor-o wned utility generating companies included

approximately 1,332 units (boilers) that generate d 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/EI A 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. Additionall y, 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 thei r electric utility sulfur dioxide (SO 2 

# ) cap-and trade

program) for help with the development of the fina l 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 a ffected sources under this effort.

2. Selection of Units to Provide Source Information

All coal- and oil-fired EGUs identified by EP A 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 pe troleum coke will be required to provide

1 

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

Identification of any un it for receipt of the CAA section 114 letter requ iring 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 dete rmined 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.

# 2 information on the current operational status of th e 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 sele cted to cover four groups of hazardous air

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

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

any surrogate-based standard will be established only if consiste nt 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/fu ran organic HAP, and

mercury and other non-mercury metallic HAP. Ra tionale 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 cont rol device or at the stack if the la st control device is not shared

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

from a separately-controlled unit. Under certai n 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 th e Agency, are the best performing sources for the

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

EPA is proposing to require testing for approximate ly 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 SO 2 

# – instead of only 12 percent of all sources. We will, of

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

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

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

performing 12 percent of the existi ng sources, (for which the Admi nistrator 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

# 3 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 un its, the bases for any surrogacy argument(s) are

less well developed and will requi re 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-sol uble compounds and are more soluble in

water than is SO 2 

# . (Hydrogen cyanide, HCN, represen ting 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 adso rbed 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

SO 2 

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

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

systems, acid gases and SO 2 

# are absorbed by the slurry mixture and react to (usually) form solid

salts. In fluidized bed combustion (F BC) systems, the acid gases and SO 2 

# 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 SO 2 

# , whereas one mole of

Ca(OH) 2 

# will neutralize two moles of HCl. A simila r reaction occurs with the neutralization of

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

more readily than is the SO 2 

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

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

removed more readily than SO 2 

# ). Thus, we are considering emissions of SO 2 

# , a commonly

measured pollutant, as a potenti al 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 SO 2 

# be deemed inappropriate as a potentia l surrogate for emissi ons of the acid-gas

# 4 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 ne west FGD controls installed. EPA believes

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

most stringent, emission limits for SO 2 

# . Even though SO 2 

# may not be an adequate surrogate for

the acid gas HAP, efforts by units to comply with stringent SO 2 

# 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 sele cted from those identified in Attachment 8 and would be required

to test the specified unit for HCl, HF, HCN, SO 2 

# , O 2 

# , CO 2 

# , 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. Howeve r, for units selected for testing in this group

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

not currently listed may be required to test if ne cessary 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 liste d as being below the minimum detection limit for

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

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

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

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



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

formation of dioxins/furans is inhibited. 3,4 

# The vast majority of the coal analyses provided

2 

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

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

3 

# Raghunathan, K., and B,K. Gullett. Role of Su lfur 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.

# 5 through the 1999 ICR indicated S:Cl values greater than 1.0. As a result, EPA expects that

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

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

either to base a surrogate standard or to esta blish 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 ca rbon as a potential control technology for

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

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

dioxins/furans, O 2 

# , CO 2 

# , and moisture from the stack gases, and chlorine and sulfur content,

HHV, and proximate/ultimate analyses of th e coal being utiliz ed 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 le tter, to test similar units at

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

group) as long as the substituted unit was of simila r 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 actua lly test and provide the n eeded 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 co mbustion leads to lower organic emissions. 5 

# However,

although indications are that thes e emissions are low (and perhap s below the minimum detection

level), there are very few emissions data availa ble for these compounds fr om coal-fired utility

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

and, thus, presumed most efficient, units (A ttachment 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 Agen cy. NESHAPS: Final Standards for H azardous Air Pollutants for Hazardous

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

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

(POM), NO X 

# , formaldehyde, methane, O 2 

# , and CO 2 

# , in addition to CO, VOC, and THC. All

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

proximate/ultimate analyses of the co al 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. Compan ies with units sharing an FGD or PM control

system will need to contact EPA with the individu al 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 th e potential surrogat e 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) c ontrol devices. However, mercury (Hg) and other

non-mercury metallic HAP (i.e., arsenic (As), chro mium (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. Als o, 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 thes e metallic HAP from coal-fired utility boilers.

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

coal, the amount of unburned carbon present in the fly ash, the fl ue 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 effectiv ely these ACI-equipped plants reduce their Hg

emissions.

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

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

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

an adequate surrogate for some of the non-me rcury metallic HAP, efforts by units to comply

# 7 with stringent PM limits will likely represent the top performers with regard to non-mercury

metallic HAP emissions. The units selected also in clude 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 af ter 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 liste d for Sb, As, Be, Cd, Cr, Co, Pb, Mn, Hg, Ni, Se,

PM (total filterable, fine [dry], fine [wet]), O 2 

# , CO 2 

# , 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 th e coal being utiliz ed 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, test ing 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 actua lly test and provide the n eeded 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 sele cted at random 50 units (identif ied in Attachment 13) from the

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

SO 2 

# , O 2 

# , CO 2 

# , CO, VOC, THC, POM, NO X 

# , 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 (N EI), Toxics Release Inventory (TRI), data gathered for the

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

this purpose. Utilities are not currently subject to a CAA section 112(d) standard and, therefore,

# 8 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, w ithin 3 weeks of r eceipt of the CAA section 114 letter, to

test sister units at the same f acility. EPA would also entertain re quests, within 3 weeks of receipt

of the CAA section 114 letter, to test similar units at othe r 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 simila r coal, and had similar emission controls. The

subject company would need EPA approval for a ny 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,

SO 2 

# , O 2 

# , CO 2 

# , CO, VOC, THC, POM, NO X 

# , 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 bein g utilized during the test.

Oil-fired units

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

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

technologies, as in the case of the non-mercur y 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 Regul atory Determination do not indicate any

correlation between PM control a nd emissions of non-mercury metall ic HAP from oil-fired units.

# 9 Further, no oil-fired unit has a FGD system inst alled, eliminating the potential basis for the use

of compliance with an SO 2 

# emissions limit that resulted in the installation of an FGD system as a

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

S:Cl value has the same relevance for oil-fired un its as it does for coal-f ired 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, SO 2 

# , dioxins/furans, CO, VOC, THC, POM, NO X 

# ,

formaldehyde, methane, O 2 

# , CO 2 

# , 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 le tter, to test similar units at

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

group) as long as the substituted unit was of simila r 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 actua lly test and provide the n eeded 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 At tachment 7 will be required to test for HCl,

HF, HCN, SO 2 

# , O 2 

# , CO 2 

# , CO, VOC, THC, POM, NO X 

# , formaldehyde, methane, dioxins/furans,

Sb, As, Be, Cd, Cr, Co, Pb, Mn, Hg, Ni, Se, PM (t otal filterable, fine [d ry], fine [wet]), and

moisture from the stack gases. All of these units would also be re quired 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 pur suant 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.

# 10 Attachment 1.

Draft Questionnaire Content

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 11 ELECTRIC UTILITY STEA M GENERATING UNIT

HAZARDOUS AIR POLLUTANT EMISSIONS INFORMATION COLLECTION EFFORT

BURDEN STATEMENT

Preliminary estimates of the public burden a ssociated 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 boile rs, fuel oil types and/or coal rank, 1,332 units

to provide hazardous air pollutant (HAP) emission s 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 disc lose or provide information to or for a Federal Agency. This

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

and systems for the purposes of collecting, valid ating, and verifying information, processing and

maintaining information, and disclosing and providi ng information; adjust the existing ways to

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

to respond to a collection of info rmation; search data sources; co mplete 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 curr ently valid Office of Management and Budget

(OMB) control number.

GENERAL INSTRUCTIONS

[NOTE: It is EPA’s intent for the final vers ion 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 provi de any information you believe may be related.

Use additional copies of the request forms for your response.

If you believe the disclosure of the informa tion requested would compromise confidential

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

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

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

regulations and, for trade secr ets, 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 notwithst anding 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 meeti ng the section 112(a)(8)

definition of an electric utility steam generating unit:

 Part II - Fuel Analyses and Emission Da ta: 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 a ll facilities selected for stack testing:

 Part III – Emissions Test Data: One emi ssions 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 test ed 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 Plan t ID (as reported on U.S. DOE/EIA Form EIA-923 (2008),

schedule 2, page 1, question 2): ____________________________________________________

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

_______________________________________________________________________________

_______________________________________________________________________________

_______________________________________________________________________________

6. Provide mailing address if different: ___________________________________________

_______________________________________________________________________________

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 14 7. Name and title of contact(s) able to answ er 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 permitted 6 

# to be fired in any

steam generating unit at this facility?

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

_____ other (specify in question 14 below)

12. If coal or solid fuel, as described below, derived from a fossil s ource 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 s ubbituminous-derived coal refuse) (% _____)

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

formed by binding materials, or processe s 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 pr evious 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”).

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 15 __ 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, boile r 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 per centage or heat [Btu] basis).

Also indicate (yes/no) whether you are permitted 10 

# 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, boile r 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 subj ect to CAA section 129,

would you continue to utilize (i.e., use as a fu el) 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 permitti ng agency allowed this fuel to be combusted for special

testing and research purposes”).Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/20121615. Identification (or designation) of allcoal- and oil-fired steam generating units(boilers) (as defined by Clean Air Act section112(a)(8)) located atthis facility.



# Boiler ID 11 

# Original design fuel (i.e.

coal rank or type of oil) 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) Operating steam

temperature (°F) Design steam reheat

temperature (°F) 14 

# Operating steam reheat

temperature (°F) 15 

# Fuel 16 

# Hours/year operated 17 

# Average annual capacity

factor for the past 3 years Applicable NSPS Estimated year of

retirement 1811Boiler 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 orgreater 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).12Per fuel burned in the boiler. Reportthis based on higher heating value (HHV).13Per fuel burned in the boiler. Reportthis based on higher heating value (HHV).14Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.15Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both.16Indicate the fuels utilized for the indicated boiler, and percentages, as indicated in questions 11 - 13.17The “ hours/year operated” would be the average of the actualnumber of hours the unit operated in 1 year based on the last 3years of operation.18This can be treated as CBI and can be submitted through the proper CBI procedure if desired.Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/201217Emission Control Technology16. For each boiler noted in Part I, question 15, provide the following information for each current emission control deviceinstalled and operating and/or planned (please designate the order of the emission controls – 1 for first control following theboiler, 2 for second control following the boiler, etc.):Boiler ID19Type20NOxcontrol21SO2control22PM control23Other control2419Boiler 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 orgreater 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).20Examples: tangential-fired; cyclone; wall-fired; circulating fluidized bed (CFB)21Examples: low-NOxburners; selective catalytic reduction (SCR); selective non-catalytic reduction (SNCR); over-fire air (OFA). Include specificdate thatcontrol went online or planned operational date for new installation. If this boiler’s control configuration utilizes a SCR, please include the type of material fromwhich the catalyst is manufactured and the type of reductant used in with the SCR (e.g., anhydrous ammonia, aqueous ammonia, urea, other). Also, please noteif the catalyst is specifically designed to reduce SO3formation?22Examples: wet flue gas desulfurization (FGD; any type); dryscrubbing (any type); specify whether calcium- or sodium-based.Include specific date thatcontrol went online or planned operational date for new installation.23Examples: fabric filter; cold-side electrostatic precipitator (ESP); hot-side ESP; cyclone or multiclone; venturi scrubber.Include specific date that controlwent online or planned operational date for new installation.24Please indicate systems installed specificallyto control any other pollutants (e.g., Hg, SO3,etc.). Examples: activated carbon injection (ACI); PowerspanECO®; dry sorbent injection or wet ESP for SO3control; flue gas conditioning to control opacity (e.g., SO3injection, ammonia, other); additive use for mercurycontrol (e.g., bromine; scrubber additives). Include specific date that control went online or planned operational date for new installation. Also include anypollutants controlled by this other technology (e.g., control technology [pollutant controlled]).Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/20121817. For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information foreach HAP-specific (e.g., mercury, hydrogen chloride) control technology that you have either contracted for, are installing, orhaveinstalled for the purpose of participating in a control technology demonstration project25(e.g., U.S. Department of Energy program,consent decree, etc.).Company (vendor) contact informationBoilerID26Company (vendor)nameName Telephone Address25A 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 aconsent decree) that adds a HAP control technology to a facility’s unit to demonstrate the technology’s HAP removalperformance.26Boiler 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 orgreater 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).Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/20121918. For the control technologies identified inPart I, question 17, provide the date of actual start-up of the demonstration (if thecontrol is currently operating), the date ofexpected or projected start-up, the datethe demonstration was completed, the typeof HAPcontrol installed (e.g., sorbent and type; pre-combustion boiler chemical additive; combustion boiler chemical additive), the desiredHAP emission reduction or rate (if any), and the coal rank(s) in useor fuel type upon which thedemonstration was conducted.Pleasespecify the format of the target HAP emission reduction or rate(e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of thetarget end-point is percent reduction, provide(1) an estimate of what an equivalentemission rate would be (and specify the format ofthe equivalent emission rate), and (2) the basis for calculating the percent reduction(i.e., where the “inlet” and “outlet” are).BoilerID27Demonstrationactivity actualstart-up dateDemonstrationactivity projectedstart-up dateDemonstrationactivity end-dateor projected enddateType of control(e.g., sorbent andtype; chemicaladditive28)Desired HAPemission reduction(%) or emissionrateCoal rank(s) inuse27Boiler 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 orgreater 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).28If additive is used, please indicate injection point.Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/20122019. For each boiler noted in Part I, question 15, provide the company (prime vendor) name and company contact information foreach HAP (e.g., mercury, hydrogen chloride, etc.) control technologythat you have either contracted for, are installing, or haveinstalled for the purpose ofproviding a non-demonstration,full-scale operating system.Company (vendor) contact informationBoilerID29Company (vendor)nameName Telephone Address29Boiler 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 orgreater 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).Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/20122120. For the control technologies identified inPart I, question 19, provide the date of actual start-up (if the control is currentlyoperating), the date of expected or projected start-up, the type ofHAP control installed (e.g., sorbent and type; pre-combustion boilerchemical additive; combustion boiler chemical additive), the guaranteed HAP emission reduction or emission rate, the sorbent feedrate upon which the guarantee is based, and the coal rank(s) orfuel type upon which the guarantee is based. Please specify the formatof the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction, etc.).If the format of the guaranteeis percent reduction, provide (1) anestimate of what an equivalent emission ratewould be (and specify the format of theequivalent emission rate), and (2) the basis forcalculating the percent reduction (i.e., where the “inlet” and “outlet” are).Boiler ID30Actual start-updateExpected orprojected start-updateType of control(e.g., sorbent andtype; chemicaladditive)31Guaranteed HAPemissionreduction (%) oremission rateSorbent oradditive feed rateon whichguarantee isbasedCoal rank(s) uponwhich guaranteeis based30Boiler 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 orgreater 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).31If additive is used, please indicate injection point.Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/20122221. For each boiler noted in Part I, question 15, provide the following information:Permitted emission limit (indicatetype of permit and format of emission limit and averaging period)BoilerID32PM33PM10(34)PM2.5(35)SO2HCland/orHFHCNMetalHAP36Hg COOtherorganics(specify)Otherpollutant(specify)32Boiler 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 orgreater 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).33If the boiler has separate permitted emission limits for filterable and condensable PM, respectively, please include those separate limits. Also include thecompliance test method utilized.34List the compliance test method utilized.35List the compliance test method utilized.36Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium;indicate permit level forall metal HAP for which a permit limit is in place.Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/20122322. For each boiler noted in Part I, question 15, provide the following information:Most recent guaranteed emission rate for each pollutant for which there is a permitted emission limitBoilerID37PM38PM10PM2.5SO2HCland/orHFHCNMetalHAP39Hg COOtherorganics(specify)Otherpollutant(specify)23. Was any other guarantee level soughtor offered? Yes _____ No _____ Please elaborate. ______________________________________________________________________________________________________________________________________________________________________________________________________________________________________________37Boiler 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 orgreater 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).38If the boiler has separate guaranteed emission rate for filterable and condensable PM, respectively, please include those separate emission rates.39Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium;indicate permit level forall metal HAP for which a permit limit is in place.Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/20122424. For each boiler noted in Part I, question 15, provide the following information:Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is apermitted emission limitBoiler ID40PM41PM10PM2.5SO2HCland/orHFHCNMetalHAP42Hg COOtherorganics(specify)40Boiler 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 orgreater 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).41If the boiler’s monitoring, recordkeeping, and reporting requirements require your company to monitoring, keep records, and report filterable and condensablePM separately, please describethe separate actions required.42Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium;indicate permit level forall metal HAP for which a permit limit is in place.Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/20122525. For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested.43Facility 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-ashcoal, coal or oil with low trace constituents, etc.)? Please specify.________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________43This can be treated as CBI and can be submitted through the proper CBI procedure if desired.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 26 PART II: FUEL ANAL YSIS AND EMISSION DATA

Fuel Analysis 44



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

during the preceding 12 calendar months.

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

_______________________________________________________________________________

_______________________________________________________________________________

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

44 

# The respondent should reply to this ICR with separate pages 18 through 24 (Part II) for each of their facilities.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 27 2. For each individual coal and oil shipme nt received during the preceding 12 calendar

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

additional pages, as necessary):

Fuel source Amount

received,

dry basis,

short tons 45 

# ID # of

boiler(s)

firing

fuel 46 

# State/Country County 47 

# Coal seam 48 

# Fuel shipment

method

45 

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

necessarily the same as the amount fired.

46 

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

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

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

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

47 

# If known.

48 

# If known.Enclosure 1Form Approved 12/24/2009OMB Control No. 2060-0631Approval Expires 12/31/2012283. For each individual coal and oil shipment received during the preceding 12 calendar months, provide the followinginformation49, as available (dry basis) (indicate N/A if not available):Sample ID #Totalamount offuelrepresentedby sample,tons orgallonsTotalsulfur, %Ashcontent,%Higherheatingvalue,Btu/lbMercury,ppmChlorine,ppmFluorine,ppmNickel,ppmOthertracemetalHAP,ppm5049To 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), andany metallic HAP (e.g., Hg, Pb, As, Se, etc.), EPA wishes theresponding facility to provide those fuel analyses results. Otherwise, this 12-month fuel analysisrequirement can be bypassed by the respondent.50Metal HAP includes compounds of antimony, arsenic, beryllium,cadmium, chromium, cobalt, lead, manganese, nickel and selenium.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 29 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 meta ls were conducted, please provide copies of any

analyses conducted over the pr eceding 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 Pa rt II, question 2 above. The Agency is requesting

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

to provide these data.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 30 Emission Data

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

are available for the boilers not ed in Part I, question 15, for tests conducted since January 1,

2005. Please consider reports prepared for a ll 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 copi es of the test reports or data at this time;

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

______________________________________________________________________________

______________________________________________________________________________

______________________________________________________________________________

______________________________________________________________________________

8b. Please indicate the date(s) a nd types (e.g., stack, fuel, parametr ic, 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 testi ng at a location upstream of any emission control

devices?

Yes _____ No _____ If yes, please not e which reports and provide a detailed description

of the location of the emi ssions sampling point(s). ____________________________________

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 31 8d. Were any of these test reports conducted wh en 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 te sting during periods of startup, shutdown, and

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

______________________________________________________________________________

______________________________________________________________________________

8f. Did the unit’s contro l configuration differ from that s hown 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 tes ting at a location upstream of a post combustion

SO 2 

# emission control device (e.g., F GD, 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 sampli ng ports were located in relation to the bypass

ductwork. ______________________________________________________________________

_______________________________________________________________________________

9. What type of deviation re porting is required for violati ons of permit requirements?

______________________________________________________________________________

______________________________________________________________________________

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

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

______________________________________________________________________________

______________________________________________________________________________

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 32 11. Are continuous emissions monitoring syst em (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 tes ting? Yes _____ No _____ If yes 51 

# , please

note for which pollutants CEMS data are availabl e 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 da ta are being provided. _____________________________________

_____________________________________________________________________________

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

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



# Boiler

ID Date

of test PM 54 

# SO 2 

# HCl/HF/HCN Metal

HAP 55 

# Hg 56 

# 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 measur ement 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 moistu re 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 filtera ble and condensable PM, separately, please include those

separate emission results. Also, please include separate emission results for total PM, PM 10 

# , and PM 2.5



# . 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 testin g, please include these data.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 33 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 la st 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 Pr ocedures, 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 un its representing an additional 20 percent of their required data

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

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

test requirements.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 34 

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

Unit Test Procedures, Method s, and Reporting Requirements

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

reporting requirements for the coal- and oil-fired electric utility st eam 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 prog ram includes stack test

data requests for several pollutants, including specific hazardous ai r 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 overl apping measurements per group):

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

methane (CH 4 

# ), formaldehyde, oxygen (O 2 

# ), carbon dioxide (CO 2 

# ), volatile and semivolatile organic HAP

 Dioxin/furan: dioxins/furans (D/F), O 2 

# , CO 2



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

(HCN), oxides of nitrogen (NO

x 

# ), sulfur dioxide (SO 2 

# ), O 2 

# , CO 2



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

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

lead (Pb), manganese (Mn), ni ckel (Ni), and selenium (S e)), particulate matter (PM 2.5 

# (filterable and condensable); total solids; O 2 

# , CO 2



# 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 pe rform 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 lo cations and number of

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

of the method and guidance information.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 35 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 Stea m Generating Unit Test Methods and Reporting

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

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

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

EPA for approval of an alternative method.

For copies of the recommended U.S. EPA meth ods 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 meth ods (such as EPA Method 0010 and EPA Method

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

internet address: < http://www.epa.gov/waste/hazard/t estmethods/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 va lid test runs. All pollutant con centrations should be corrected to

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

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

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

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

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

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

the control device, flue gas flow rate, pressu re 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 re port the above process information as daily

averages.

The owner/operator of the EGU must certify th at 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 th e pollution control equipment in accordance with

manufacturers’ specifications and requirements for proper operat ion 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.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 36 Table 1.2a: Summary of Coal- and Oil-fired Elect ric 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% O 2



# 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% O 2



# 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

CH 4 

# 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

μ g/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

μ g/dscm @ 7% O2

SO 2 *** 

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

ppmvd @ 7% O 2



# O 2 

# /CO 2 *** 

# 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, NO

x 

# and/or SO 2 

# , the unit can report daily averages from

30 days of CEMS data in lieu of conducting a CO, NO

x 

# and/or SO 2 

# 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 requir ements of the applicable

Performance Specification: CO – Performance Specification 4; NO

x 

# and SO 2 

# – Performance Specification 2 and 40

CFR part 60.13 or the CEMS accu racy and ongoing QA/QC requir ements of 40 CFR part 75.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 37 Table 1.2b: Summary of Coal- and Oil-fired Elect ric 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

O 2 

# /CO 2 *** 

# 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, NO

x 

# and/or SO 2 

# , the unit can report daily averages from

30 days of CEMS data in lieu of conducting a CO, NO

x 

# and/or SO 2 

# 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 requir ements of the applicable

Performance Specification: CO – Performance Specification 4; NO

x 

# and SO 2 

# – Performance Specification 2 and 40

CFR part 60.13 or the CEMS accu racy and ongoing QA/QC requir ements of 40 CFR part 75.



# Table 1.2c: Summary of Coal- and Oil-fired Elect ric 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 an alysis procedures

from CTM-033 or U.S. EPA Method

320 if there are no entrained water

droplets in the sample. lb/MMBtu

NO

x *** 

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

7D lb/MMBtu and

ppmvd @ 7% O 2



# SO 2 *** 

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

ppmvd @ 7% O 2



# O 2 

# /CO 2 *** 

# 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, NO

x 

# and/or SO 2 

# , the unit can report daily averages from

30 days of CEMS data in lieu of conducting a CO, NO

x 

# and/or SO 2 

# 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 requir ements of the applicable

Performance Specification: CO – Performance Specification 4; NO

x 

# and SO 2 

# – Performance Specification 2 and 40

CFR part 60.13 or the CEMS accu racy and ongoing QA/QC requir ements of 40 CFR part 75.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 38 Table 1.2d: Summary of Coal- and Oil-fired Elect ric Utility Steam Generating Unit Test Methods

and Alternative Methods for Mercu ry 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 an alytical finish. None lb/MMBtu

PM 2.5 

# (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

PM 2.5 

# (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 *



# PM 2.5 

# (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

O 2 

# /CO 2 ** 

# 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, NO

x 

# and/or SO 2 

# , the unit can report daily averages from 30 days

of CEMS data in lieu of conducting a CO, NO

x 

# and/or SO 2 

# stack test. In order to correl ate these emissions with other

stack test emissions, a portion of the CEMS data should contain emissions data collect ed during perfo rmance of the

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

CO – Performance Specification 4; NO

x 

# and SO 2 

# – Performance Specification 2 and 40 CFR part 60.13 or the

CEMS accuracy and ongoing QA/QC re quirements of 40 CFR part 75.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 39 

# 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 dioxi n / furan emissions test run; composite these

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

analyses are required during acid ga s emissions testing. Should you ha ve an oil-fired unit that is

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

is sufficient to complete the emissions testi ng 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 receiv ed for the specific types of fuel analyses we

are requesting from your facility. Directi ons 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.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 40 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 uni formly 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 com posite 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 sa mple 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, re peat 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.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 41 2.3 Prepare Sample for Analysis

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

Table 2.2: Methods for Preparing Composite Samples

Fuel Type Method

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

preparation

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

giving measures of total metal

Coal ASTM D2013-04

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

T266 for total selected metal preparation



# 2.4 Analyzing Fuel Sample

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

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

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

Table 2.3: List of Analytical Methods for Fuel Analysis

Analyte Fuel Type Method Target Reported

Units of Measure



# Coal ASTM D5865–04, ASTM D240, ASTM

E711-87 (1996)

Biomass ASTM E711–87 (1996) or equivalent,

ASTM D240, or ASTM D5865-04

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

E711-87 (1997) Higher Heating Value

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

E711-87 (1996) Btu/lb

Moisture Coal, Biomass, Other

Solids ASTM-D3 173-03, ASTM E871-82

(1998) or equivalent, EPA 160.3 Mod.,

or ASTM D2691-95 for coal. %

Coal ASTM D6722-01, EPA Method 1631E,

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

equivalent

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

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

821-R-01-013, or equivalent

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

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

equivalent Mercury Concentration

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

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

821-R-01-013, or equivalent ppm

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 42 Analyte Fuel Type Method Target Reported

Units of Measure



# Coal SW-846-6010B, ASTM D3683-94

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

D6357-04 (for arsenic, beryllium,

cadmium, chromium, lead, manganese,

and nickel in coal)

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

Se)

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

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

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

7740 (for Se)

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

Other Solids SW-846-6010B, EPA 200.8

SW-846-7060 or 7060A for As Total Selected Metals

Concentration

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

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

7060 or -7060A for As ppm

Coal SW-846-9250 or ASTM D6721-01 or

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

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

Biomass, Other Solids,

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

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

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

# ppm



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

enclosure.

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 43 

# 3.0 How to Report Data

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

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

requirements for reporting the data.

3.1 Reporting stack test data

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

must report your data using the EPA Electroni c 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 th e 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 pref erred) 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 un it and they can be downloaded from the Electric

Utility MACT ICR 2009 website ( http://utilitymacticr.rti.org ). You must report the results of

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 44 each test on the appropriately labe led worksheet corresponding to the specific tests requested at

your combustion unit. If more than one unit at y our facility conducted a st ack 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 emi ssion test report (PDF format

preferred).

If you have CO CEMS that meets performance specification-4 or a SO 2 

# and/or NO

x 

# 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 installe d at your combustion unit, and you used CEMS

data to meet CO, SO 2 

# and/or NO

x 

# test requirements at your f acility, you must report daily

averages from 30 days of CEMS data in a Microsoft ® 

# Excel CEMS Template. The Excel

templates are specific to each pollu tant 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) – a ll analytical values used to calculate and report an instack emissions value are less than the la boratory’s reported de tection 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 va lues 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 calculati ng 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 a ny analytical measurem ent below detection

level using the relevant detec tion level as the “real” value.

 Report the calculated emissions concentration or rate result:

# Enclosure 1 Form Approved 12/24/2009

OMB Control No. 2060-0631

Approval Expires 12/31/2012



# 45 o As a bracketed “less than” detec tion 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 bracket s or < symbol) any analytical data

measured above the detection level incl uding any data between the analytical

detection level and a laboratory-specific re porting or quantifica tion level (i.e., flag

as ADL).

 Apply these reporting and calculation pro cedures 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 Meth od 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 mu ltiple components or fractions (e.g., Hg and

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

measured below the analytical detection level;

 Calculate in-stack emissions rate or c oncentrations 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 co mponents or fractions:

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

Excel emission test spreadsheet templa te 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 fr action 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 measur ed or detection le vel 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)

# Enclosure 1 Form Approved 12/24/2009

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# 46  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 informati on 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” detec tion level value (e.g., [<20.06]) in the

Excel emission test spreadsheet templa te 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 separa tely for each of the

composited samples in a Microsoft ® Excel Fuel An alysis 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 disti nguish 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

.

# Enclosure 1 Form Approved 12/24/2009

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Approval Expires 12/31/2012



# 47 

# 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 facili ty 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 we bsite referenced below and follow the

directions listed below.

 If you are submitting Confidential Business Info rmation (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 entr y 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 assi st 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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# 48 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 f ile that you wish to upload.

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

progress will be displayed. Uploadin g 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 type s 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 recomme nded that you zip your

completed ERT Database prior to upload ing it, particularly if it is over

200MB in size.

d. After the ERT Database upload has co mpleted, 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 comp leted, 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 fo r Part III you will no longer be

able to upload further files for that part of the ICR.

# Enclosure 1 Form Approved 12/24/2009

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Approval Expires 12/31/2012



# 49 Also at the bottom of the "View uploaded files" ta b, there is a button titled "Upload another file".

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

ERT Database

# Enclosure 1 Form Approved 12/24/2009

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# 50 

# 5.0 Definitions

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

plan methods:

Equivalent means:

(1) An equivalent sample collection proc edure 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 proce dure 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 proce dure means a published VCS or EPA method that:

Clearly states that the standa rd, 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 determini ng heat content means a published VCS or EPA

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

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

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

metals (especially the mercury, selenium, or ar senic) 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 recei ved’’ basis, a separate aliquot can be

dried to determine moisture content and the me tals 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 pollu tant 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 prac tices) developed or a dopted 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: Ameri can Society of Testing and Materials (ASTM),

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

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

Standard (EN or CEN) and German Engineering St andards (VDI). The t ypes of standards that

are not considered VCS are standa rds developed by: the U.S. Stat es, such as California (CARB)

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

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

government, such as Department of Defense (DOD) and De partment of Transportation (DOT).

# Enclosure 1 Form Approved 12/24/2009

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# 51 This does not preclude EPA from using standard s 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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# 52 

# 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 electri c utility steam generating unit test plan,

including units selected to test and reporti ng 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 unitsrequiring Part I and II InformationState Plant Name Boiler IDState Plant Name Boiler IDState Plant Name Boiler ID53IN A. B. Brown 1IN A. B. Brown 2CA ACE Cogeneration Facility CFBPA AES Beaver Valley Partners Beaver Valley 2PA AES Beaver Valley Partners Beaver Valley 3PA AES Beaver Valley Partners Beaver Valley 4PA AES Beaver Valley Partners Beaver Valley 5NY AES Cayuga 1NY AES Cayuga 2NY AES Greenidge LLC 4NY AES Greenidge LLC 5NY AES Greenidge LLC 6HI AES Hawaii BLRAHI AES Hawaii BLRBIN AES Petersburg 1IN AES Petersburg 2IN AES Petersburg 3IN AES Petersburg 4PR AES Puerto Rico (Aurora) 1PR AES Puerto Rico (Aurora) 2OK AES Shady Point 1AOK AES Shady Point 1BOK AES Shady Point 2AOK AES Shady Point 2BNY AES Somerset LLC 1CT AES Thames ACT AES Thames BMD AES Warrior Run Cogeneration Facility BLR1NY AES Westover 11NY AES Westover 12NY AES Westover 13WV Albright 1WV Albright 2WV Albright 3MN Allen S. King 1TN Allen Steam Plant 1TN Allen Steam Plant 2TN Allen Steam Plant 3WI Alma B4WI Alma B5VA Altavista Power Station 1IA Ames Electric Services Power Plant 7IA Ames Electric Services Power Plant 8ND Antelope Valley B1ND Antelope Valley B2AZ Apache Station 2AZ Apache Station 3CO Arapahoe 3CO Arapahoe 4PA Armstrong Power Station 1PA Armstrong Power Station 2MO Asbury 1NC Asheville 1NC Asheville 2OH Ashtabula 7OH Avon Lake 10OH Avon Lake 12MI B. C. Cobb 4MI B. C. Cobb 5NJ B. L. England 2IN Bailly 7IN Bailly 8IL Baldwin Energy Complex 1IL Baldwin Energy Complex 2IL Baldwin Energy Complex 3AL Barry 1AL Barry 2AL Barry 3AL Barry 4AL Barry 5OH Bay Shore 2OH Bay Shore 3OH Bay Shore 4WI Bay Front 5NC Belews Creek 1NC Belews Creek 2MI Belle River 1MI Belle River 2FL Big Bend BB01FL Big Bend BB02FL Big Bend BB03FL Big Bend BB04TX Big Brown 1TX Big Brown 2LA Big Cajun 2 2B1LA Big Cajun 2 2B2LA Big Cajun 2 2B3KY Big Sandy BSU1KY Big Sandy BSU2SD Big Stone 1VA Birchwood Power 1AMN Black Dog 3MN Black Dog 4NY Black River Generation E0001NY Black River Generation E0002NY Black River Generation E0003WI Blount Street 7WI Blount Street 8WI Blount Street 9MO Blue Valley 1MO Blue Valley 2MO Blue Valley 3OR Boardman 1SGUT Bonanza 1-1GA Bowen 1BLRGA Bowen 2BLRGA Bowen 3BLRGA Bowen 4BLRMD Brandon Shores 1MD Brandon Shores 2MA Brayton Point 1MA Brayton Point 2MA Brayton Point 3VA Bremo Bluff 3VA Bremo Bluff 4CT Bridgeport Station BHB3PA Bruce Mansfield 1PA Bruce Mansfield 2PA Bruce Mansfield 3NC Buck 5NC Buck 6NC Buck 7NC Buck 8NC Buck 9TN Bull Run 1IA Burlington 1FL C. D. McIntosh Jr 3MD C. P. Crane 1MD C. P. Crane 2NY C. R. Huntley Generating Station 65NY C. R. Huntley Generating Station 67NY C. R. Huntley Generating Station 68PA Cambria Cogen B1PA Cambria Cogen B2SC Canadys Steam CAN1SC Canadys Steam CAN2SC Canadys Steam CAN3KY Cane Run 4KY Cane Run 5KY Cane Run 6NC Cape Fear 5NC Cape Fear 6UT Carbon 1UT Carbon 2OH Cardinal 1OH Cardinal 2OH Cardinal 3IN Cayuga 1IN Cayuga 2FL Cedar Bay Generating LP CBAState Plant Name Boiler IDState Plant Name Boiler IDState Plant Name Boiler ID54FL Cedar Bay Generating LP CBBFL Cedar Bay Generating LP CBCFL Central Power & Lime 1MD Chalk Point LLC 1MD Chalk Point LLC 2NJ Chambers Cogeneration LP BOIL1NJ Chambers Cogeneration LP BOIL2MO Chamois 2AL Charles R Lowman 3AL Charles R. Lowman 1AL Charles R. Lowman 2CO Cherokee 1CO Cherokee 2CO Cherokee 3CO Cherokee 4VA Chesapeake 1VA Chesapeake 2VA Chesapeake 3VA Chesapeake 4VA Chesterfield 3VA Chesterfield 4VA Chesterfield 5VA Chesterfield 6PA Cheswick Power Plant 1AZ Cholla 1AZ Cholla 2AZ Cholla 3AZ Cholla 4MN Clay Boswell 1MN Clay Boswell 2MN Clay Boswell 3MN Clay Boswell 4NC Cliffside 1NC Cliffside 2NC Cliffside 3NC Cliffside 4NC Cliffside 5IN Clifty Creek 1IN Clifty Creek 2IN Clifty Creek 3IN Clifty Creek 4IN Clifty Creek 5IN Clifty Creek 6VA Clinch River 1VA Clinch River 2VA Clinch River 3VA Clover 1VA Clover 2ND Coal Creek 1ND Coal Creek 2IL Coffeen 01IL Coffeen 02NC Cogentrix Dwayne Collier Battle Cogen 1ANC Cogentrix Dwayne Collier Battle Cogen 1BNC Cogentrix Dwayne Collier Battle Cogen 2ANC Cogentrix Dwayne Collier Battle Cogen 2BVA Cogentrix Hopewell 1AVA Cogentrix Hopewell 1BVA Cogentrix Hopewell 1CVA Cogentrix Hopewell 2AVA Cogentrix Hopewell 2BVA Cogentrix Hopewell 2CVA Cogentrix of Richmond 1AVA Cogentrix of Richmond 1BVA Cogentrix of Richmond 2AVA Cogentrix of Richmond 2BVA Cogentrix of Richmond 3AVA Cogentrix of Richmond 3BVA Cogentrix of Richmond 4AVA Cogentrix of Richmond 4BVA Cogentrix Virginia Leasing Corporation 1AVA Cogentrix Virginia Leasing Corporation 1BVA Cogentrix Virginia Leasing Corporation 1CVA Cogentrix Virginia Leasing Corporation 2AVA Cogentrix Virginia Leasing Corporation 2BVA Cogentrix Virginia Leasing Corporation 2CAL Colbert 1AL Colbert 2AL Colbert 3AL Colbert 4AL Colbert 5TX Coleto Creek 1MT Colstrip 1MT Colstrip 2MT Colstrip 3MT Colstrip 4MT Colstrip Energy LP BLR1WI Columbia 1WI Columbia 2PA Colver Power Project ABB01CO Comanche 1CO Comanche 2CO Comanche 3PA Conemaugh 1PA Conemaugh 2OH Conesville 1OH Conesville 2OH Conesville 3OH Conesville 4OH Conesville 5OH Conesville 6KY Cooper 1KY Cooper 2SC Cope COP1AZ Coronado U1BAZ Coronado U2BIA Council Bluffs 1IA Council Bluffs 2IA Council Bluffs 3IA Council Bluffs 4ND Coyote B1CO Craig C1CO Craig C2CO Craig C3IL Crawford 7IL Crawford 8FL Crist 4FL Crist 5FL Crist 6FL Crist 7PA Cromby Generating Station 1SC Cross 1SC Cross 2SC Cross 3SC Cross 4FL Crystal River 1FL Crystal River 2FL Crystal River 4FL Crystal River 5TN Cumberland 1TN Cumberland 2KY D. B. Wilson W1KY Dale 1KY Dale 2KY Dale 3KY Dale 4IL Dallman 31IL Dallman 32IL Dallman 33IL Dallman 34MI Dan E. Karn 1MI Dan E. Karn 2NC Dan River 1NC Dan River 2State Plant Name Boiler IDState Plant Name Boiler IDState Plant Name Boiler ID55NC Dan River 3NY Danskammer Generating Station 3NY Danskammer Generating Station 4WY Dave Johnston BW41WY Dave Johnston BW42WY Dave Johnston BW43WY Dave Johnston BW44NJ Deepwater 8FL Deerhaven Generating Station B2MD Dickerson 1MD Dickerson 2MD Dickerson 3LA Dolet Hills 1SC Dolphus M Grainger 1SC Dolphus M Grainger 2IA Dubuque 1IA Dubuque 5IL Duck Creek 1NY Dunkirk Generating Station 1NY Dunkirk Generating Station 2NY Dunkirk Generating Station 3NY Dunkirk Generating Station 4AL E. C. Gaston 1AL E. C. Gaston 2AL E. C. Gaston 3AL E. C. Gaston 4AL E. C. Gaston 5IL E. D. Edwards 1IL E. D. Edwards 2IL E. D. Edwards 3KY E. W. Brown 1KY E. W. Brown 2KY E. W. Brown 3IN Eagle Valley 3IN Eagle Valley 4IN Eagle Valley 5IN Eagle Valley 6IA Earl F. Wisdom 1KY East Bend 2OH Eastlake 1OH Eastlake 2OH Eastlake 3OH Eastlake 4OH Eastlake 5PA Ebensburg Power 031MI Eckert Station 1MI Eckert Station 2MI Eckert Station 3MI Eckert Station 4MI Eckert Station 5MI Eckert Station 6PA Eddystone Generating Station 1PA Eddystone Generating Station 2DE Edge Moor 3DE Edge Moor 4WI Edgewater 3WI Edgewater 4WI Edgewater 5IN Edwardsport 7-1IN Edwardsport 7-2IN Edwardsport 8-1WI Elm Road Generating Station 1WI Elm Road Generating Station 2KY Elmer Smith 1KY Elmer Smith 2PA Elrama Power Plant 1PA Elrama Power Plant 2PA Elrama Power Plant 3PA Elrama Power Plant 4MI Endicott Station 1MI Erickson Station 1NM Escalante 1IN F. B. Culley 1IN F. B. Culley 2IN F. B. Culley 3IA Fair Station 1IA Fair Station 2TX Fayette Power Project 1TX Fayette Power Project 2TX Fayette Power Project 3IL Fisk Street 19AR Flint Creek 1WV Fort Martin Power Station 1WV Fort Martin Power Station 2PA Foster Wheeler Mt Carmel Cogen SG-101NM Four Corners 1NM Four Corners 2NM Four Corners 3NM Four Corners 4NM Four Corners 5IN Frank E. Ratts 1SG1IN Frank E. Ratts 2SG1NC G. G. Allen 1NC G. G. Allen 2NC G. G. Allen 3NC G. G. Allen 4NC G. G. Allen 5AL Gadsden 1AL Gadsden 2TN Gallatin 1TN Gallatin 2TN Gallatin 3TN Gallatin 4OH General James M Gavin 1OH General James M Gavin 2WI Genoa 1IA George Neal North 1IA George Neal North 2IA George Neal North 3IA George Neal South 4NE Gerald Gentleman 1NE Gerald Gentleman 2KY Ghent 1KY Ghent 2KY Ghent 3KY Ghent 4TX Gibbons Creek 1IN Gibson 1IN Gibson 2IN Gibson 3IN Gibson 4IN Gibson 5VA Glen Lyn 6VA Glen Lyn 51VA Glen Lyn 52AL Gorgas 6AL Gorgas 7AL Gorgas 8AL Gorgas 9AL Gorgas 10WV Grant Town Power Plant BLR1AWV Grant Town Power Plant BLR1BOK GRDA 1OK GRDA 2KY Green River 4KY Green River 5AL Greene County 1AL Greene County 2SC H. B. Robinson 1KY H. L. Spurlock 1KY H. L. Spurlock 2KY H. L. Spurlock 3KY H. L. Spurlock 4OH Hamilton 8State Plant Name Boiler IDState Plant Name Boiler IDState Plant Name Boiler ID56OH Hamilton 9GA Hammond 1GA Hammond 2GA Hammond 3GA Hammond 4MI Harbor Beach 1MT Hardin Generator Project PC1IN Harding Street 50IN Harding Street 60IN Harding Street 70GA Harllee Branch 1GA Harllee Branch 2GA Harllee Branch 3GA Harllee Branch 4TX Harrington 061BTX Harrington 062BTX Harrington 063BWV Harrison Power Station 1WV Harrison Power Station 2WV Harrison Power Station 3PA Hatfields Ferry Power Station 1PA Hatfields Ferry Power Station 2PA Hatfields Ferry Power Station 3IL Havana 9MO Hawthorn 5ACO Hayden H1CO Hayden H2AK Healy 1KY Henderson I 6IL Hennepin Power Station 1IL Hennepin Power Station 2MD Herbert A. Wagner 2MD Herbert A. Wagner 3KY HMP&L Station Two Henderson H1KY HMP&L Station Two Henderson H2KS Holcomb SGU1PA Homer City Station 1PA Homer City Station 2PA Homer City Station 3MN Hoot Lake 2MN Hoot Lake 3OK Hugo 1UT Hunter 1UT Hunter 2UT Hunter 3UT Huntington 1UT Huntington 2IL Hutsonville 05IL Hutsonville 06MO Iatan 1AR Independence 1AR Independence 2DE Indian River Generating Station 2DE Indian River Generating Station 3DE Indian River Generating Station 4FL Indiantown Cogeneration LP AAB01UT Intermountain Power Project 1SGAUT Intermountain Power Project 2SGAMI J. B. Sims 3MI J. C. Weadock 7MI J. C. Weadock 8MT J. E. Corette Plant 2MI J. H. Campbell 1MI J. H. Campbell 2MI J. H. Campbell 3KY J. K. Smith 1TX J. K. Spruce BLR1TX J. K. Spruce BLR2OH J. M. Stuart 1OH J. M. Stuart 2OH J. M. Stuart 3OH J. M. Stuart 4MI J. R. Whiting 1MI J. R. Whiting 2MI J. R. Whiting 3TX J. T. Deely 1TX J. T. Deely 2GA Jack McDonough MB1GA Jack McDonough MB2MS Jack Watson 4MS Jack Watson 5MI James De Young 5AL James H. Miller Jr. 1AL James H. Miller Jr. 2AL James H. Miller Jr. 3AL James H. Miller Jr. 4MO James River Power Station 3MO James River Power Station 4MO James River Power Station 5SC Jefferies 3SC Jefferies 4KS Jeffrey Energy Center 1KS Jeffrey Energy Center 2KS Jeffrey Energy Center 3WY Jim Bridger BW71WY Jim Bridger BW72WY Jim Bridger BW73WY Jim Bridger BW74PA John B Rich Memorial Power Station CFB1PA John B Rich Memorial Power Station CFB2WV John E Amos 1WV John E Amos 2WV John E. Amos 3WI John P. Madgett B1TN John Sevier 1TN John Sevier 2TN John Sevier 3TN John Sevier 4TN Johnsonville 1TN Johnsonville 2TN Johnsonville 3TN Johnsonville 4TN Johnsonville 5TN Johnsonville 6TN Johnsonville 7TN Johnsonville 8TN Johnsonville 9TN Johnsonville 10IL Joliet 29 71IL Joliet 29 72IL Joliet 29 81IL Joliet 29 82IL Joliet 9 5IL Joppa Steam 1IL Joppa Steam 2IL Joppa Steam 3IL Joppa Steam 4IL Joppa Steam 5IL Joppa Steam 6WV Kammer 1WV Kammer 2WV Kammer 3WV Kanawha River 1WV Kanawha River 2KY Kenneth C. Coleman C1KY Kenneth C. Coleman C2KY Kenneth C. Coleman C3PA Keystone 1PA Keystone 2OH Killen Station 2IL Kincaid Generation LLC 1IL Kincaid Generation LLC 2TN Kingston 1TN Kingston 2State Plant Name Boiler IDState Plant Name Boiler IDState Plant Name Boiler ID57TN Kingston 3TN Kingston 4TN Kingston 5TN Kingston 6TN Kingston 7TN Kingston 8TN Kingston 9PA Kline Township Cogen Facility 1GA Kraft 1GA Kraft 2GA Kraft 3OH Kyger Creek 1OH Kyger Creek 2OH Kyger Creek 3OH Kyger Creek 4OH Kyger Creek 5NC L. V. Sutton 1NC L. V. Sutton 2NC L. V. Sutton 3KS La Cygne 1KS La Cygne 2MO Labadie 1MO Labadie 2MO Labadie 3MO Labadie 4MO Lake Road 5OH Lake Shore 18IL Lakeside 7IL Lakeside 8CO Lamar 4IA Lansing 3IA Lansing 4FL Lansing Smith 1FL Lansing Smith 2WY Laramie River Station 1WY Laramie River Station 2WY Laramie River Station 3KS Lawrence Energy Center 3KS Lawrence Energy Center 4KS Lawrence Energy Center 5NC Lee 1NC Lee 2NC Lee 3ND Leland Olds 1ND Leland Olds 2MT Lewis & Clark B1TX Limestone LIM1TX Limestone LIM2NJ Logan Generating Plant B01NE Lon Wright 8IA Louisa 101WI Manitowoc 6WI Manitowoc 7WI Manitowoc 8IL Marion 4IL Marion 123NC Marshall 1NC Marshall 2NC Marshall 3NC Marshall 4CO Martin Drake 5CO Martin Drake 6CO Martin Drake 7TX Martin Lake 1TX Martin Lake 2TX Martin Lake 3NC Mayo 1ANC Mayo 1BGA McIntosh 1SC McMeekin MCM1SC McMeekin MCM2VA Mecklenburg Power Station BLR1VA Mecklenburg Power Station BLR2MO Meramec 1MO Meramec 2MO Meramec 3MO Meramec 4IL Meredosia 01IL Meredosia 02IL Meredosia 03IL Meredosia 04IL Meredosia 05IN Merom 1SG1IN Merom 2SG1NH Merrimack 1NH Merrimack 2OH Miami Fort 6OH Miami Fort 7OH Miami Fort 8OH Miami Fort 5-1OH Miami Fort 5-2IN Michigan City 12KY Mill Creek 1KY Mill Creek 2KY Mill Creek 3KY Mill Creek 4IA Milton L. Kapp 2ND Milton R. Young B1ND Milton R. Young B2GA Mitchell 3WV Mitchell 1WV Mitchell 2PA Mitchell Power Station 33MI Monroe 1MI Monroe 2MI Monroe 3MI Monroe 4TX Monticello 1TX Monticello 2TX Monticello 3MO Montrose 1MO Montrose 2MO Montrose 3WV Morgantown Energy Facility CFB1WV Morgantown Energy Facility CFB2MD Morgantown Generating Plant 1MD Morgantown Generating Plant 2MA Mount Tom 1WV Mountaineer 1WV Mt Storm 3CA Mt. Poso Cogeneration BL01WV Mt. Storm 1WV Mt. Storm 2IA Muscatine Plant #1 7IA Muscatine Plant #1 8IA Muscatine Plant #1 9OH Muskingum River 1OH Muskingum River 2OH Muskingum River 3OH Muskingum River 4OH Muskingum River 5OK Muskogee 4OK Muskogee 5OK Muskogee 6WY Naughton 1WY Naughton 2WY Naughton 3AZ Navajo 1AZ Navajo 2AZ Navajo 3KS Nearman Creek N1NE Nebraska City 1NE Nebraska City 2WY Neil Simpson II 2State Plant Name Boiler IDState Plant Name Boiler IDState Plant Name Boiler ID58WI Nelson Dewey 1WI Nelson Dewey 2PA New Castle Plant 3PA New Castle Plant 4PA New Castle Plant 5MO New Madrid 1MO New Madrid 2IL Newton 1IL Newton 2OH Niles 1OH Niles 2WV North Branch 1AWV North Branch 1BNE North Omaha 1NE North Omaha 2NE North Omaha 3NE North Omaha 4NE North Omaha 5NV North Valmy 1NV North Valmy 2PA Northampton Generating Company BLR1OK Northeastern 3313OK Northeastern 3314CO Nucla 1OH O. H. Hutchings H-1OH O. H. Hutchings H-2OH O. H. Hutchings H-3OH O. H. Hutchings H-4OH O. H. Hutchings H-5OH O. H. Hutchings H-6TX Oak Grove 1TX Oak Grove 2TX Oklaunion 1OH Orrville 10OH Orrville 11OH Orrville 12OH Orrville 13IA Ottumwa 1OH Painesville 3OH Painesville 4OH Painesville 5PA Panther Creek Energy Facility BLR1PA Panther Creek Energy Facility BLR2KY Paradise 1KY Paradise 2KY Paradise 3CO Pawnee 1WV Philip Sporn 11WV Philip Sporn 21WV Philip Sporn 31WV Philip Sporn 41WV Philip Sporn 51OH Picway 9PA Piney Creek Project BRBR1TX Pirkey 1WI Pleasant Prairie 1WI Pleasant Prairie 2WV Pleasants Power Station 1WV Pleasants Power Station 2AR Plum Point Energy STG1CA Port of Stockton District Energy Facility N64514CA Port of Stockton District Energy Facility N64516PA Portland 1PA Portland 2VA Potomac River 1VA Potomac River 2VA Potomac River 3VA Potomac River 4VA Potomac River 5IL Powerton 51IL Powerton 52IL Powerton 61IL Powerton 62PA PPL Brunner Island 1PA PPL Brunner Island 2PA PPL Brunner Island 3PA PPL Martins Creek 1PA PPL Martins Creek 2PA PPL Montour 1PA PPL Montour 2IA Prairie Creek 1IA Prairie Creek 2IA Prairie Creek 3IA Prairie Creek 4MI Presque Isle 5MI Presque Isle 6MI Presque Isle 7MI Presque Isle 8MI Presque Isle 9NC Primary Energy Roxboro 1ANC Primary Energy Roxboro 1BNC Primary Energy Roxboro 1CNC Primary Energy Southport 1ANC Primary Energy Southport 1BNC Primary Energy Southport 1CNC Primary Energy Southport 2ANC Primary Energy Southport 2BNC Primary Energy Southport 2CNJ PSEG Hudson Generating Station 2NJ PSEG Mercer Generating Station 1NJ PSEG Mercer Generating Station 2WI Pulliam 3WI Pulliam 4WI Pulliam 5WI Pulliam 6WI Pulliam 7WI Pulliam 8KS Quindaro 1KS Quindaro 2KY R D Green G2KY R. D. Green G1MS R. D. Morrow 1MS R. D. Morrow 2OH R. E. Burger 5OH R. E. Burger 6OH R. E. Burger 7OH R. E. Burger 8IN R. Gallagher 1IN R. Gallagher 2IN R. Gallagher 3IN R. Gallagher 4ND R. M. Heskett B1ND R. M. Heskett B2IN R. M. Schahfer 14IN R. M. Schahfer 15IN R. M. Schahfer 17IN R. M. Schahfer 18MD R. Paul Smith Power Station 9MD R. Paul Smith Power Station 11LA R. S. Nelson 6CO Rawhide 101CO Ray D. Nixon 1MS Red Hills Generating Facility AA001MS Red Hills Generating Facility AA002NV Reid Gardner 1NV Reid Gardner 2NV Reid Gardner 3NV Reid Gardner 4OH Richard Gorsuch 1OH Richard Gorsuch 2OH Richard Gorsuch 3OH Richard Gorsuch 4MI River Rouge 2MI River Rouge 3State Plant Name Boiler IDState Plant Name Boiler IDState Plant Name Boiler ID59NC Riverbend 7NC Riverbend 8NC Riverbend 9NC Riverbend 10IA Riverside 9KS Riverton 39KS Riverton 40WV Rivesville 7WV Rivesville 8NC Roanoke Valley I BLR1NC Roanoke Valley II BLR2KY Robert A Reid R1NY Rochester 7 1NY Rochester 7 2NY Rochester 7 3NY Rochester 7 4IN Rockport MB1IN Rockport MB2LA Rodemacher 2NC Roxboro 1NC Roxboro 2NC Roxboro 3ANC Roxboro 3BNC Roxboro 4ANC Roxboro 4BMO Rush Island 1MO Rush Island 2MA Salem Harbor 1MA Salem Harbor 2MA Salem Harbor 3NM San Juan 1NM San Juan 2NM San Juan 3NM San Juan 4TX San Miguel SM-1TX Sandow Station 4TX Sandow Station 5ATX Sandow Station 5BGA Scherer 1GA Scherer 2GA Scherer 3GA Scherer 4NH Schiller 4NH Schiller 5NH Schiller 6FL Scholz 1FL Scholz 2PA Scrubgrass Generating UNIT 1PA Scrubgrass Generating UNIT 2FL Seminole 1FL Seminole 2PA Seward 1PA Seward 2KY Shawnee 1KY Shawnee 2KY Shawnee 3KY Shawnee 4KY Shawnee 5KY Shawnee 6KY Shawnee 7KY Shawnee 8KY Shawnee 9KY Shawnee 10PA Shawville 1PA Shawville 2PA Shawville 3PA Shawville 4NE Sheldon 1NE Sheldon 2MN Sherburne County 1MN Sherburne County 2MN Sherburne County 3MI Shiras 3MO Sibley 1MO Sibley 2MO Sibley 3MO Sikeston Power Station 1MN Silver Bay Power BLR1MN Silver Bay Power BLR2MN Silver Lake 3MN Silver Lake 4MO Sioux 1MO Sioux 2IA Sixth Street 2IA Sixth Street 3IA Sixth Street 4IA Sixth Street 5MA Somerset Station 8OK Sooner 1OK Sooner 2WI South Oak Creek 5WI South Oak Creek 6WI South Oak Creek 7WI South Oak Creek 8VA Southampton Power Station 1MO Southwest Power Station 1AZ Springerville 1AZ Springerville 2AZ Springerville 3AZ Springerville 4MI St. Clair 1MI St. Clair 2MI St. Clair 3MI St. Clair 4MI St. Clair 6MI St. Clair 7FL St. Johns River Power Park 1FL St. Johns River Power Park 2PA St. Nicholas Cogen Project 1ND Stanton 1ND Stanton 10FL Stanton Energy Center 1FL Stanton Energy Center 2IN State Line Energy 3IN State Line Energy 4IA Streeter Station 7UT Sunnyside Cogen Associates 1IA Sutherland 1IA Sutherland 2IA Sutherland 3MN Syl Laskin 1MN Syl Laskin 2IN Tanners Creek U1IN Tanners Creek U2IN Tanners Creek U3IN Tanners Creek U4KS Tecumseh Energy Center 9KS Tecumseh Energy Center 10MI TES Filer City Station 1MI TES Filer City Station 2MO Thomas Hill MB1MO Thomas Hill MB2MO Thomas Hill MB3PA Titus 1PA Titus 2PA Titus 3TX Tolk 171BTX Tolk 172BWA Transalta Centralia Generation BW21WA Transalta Centralia Generation BW22MI Trenton Channel 16MI Trenton Channel 17MI Trenton Channel 18MI Trenton Channel 19State Plant Name Boiler IDState Plant Name Boiler IDState Plant Name Boiler ID60MI Trenton Channel 9ACO Trigen Colorado Energy BLR3CO Trigen Colorado Energy BLR4CO Trigen Colorado Energy BLR5NY Trigen Syracuse Energy 1NY Trigen Syracuse Energy 2NY Trigen Syracuse Energy 3NY Trigen Syracuse Energy 4NY Trigen Syracuse Energy 5KY Trimble County 1NV TS Power Plant BLR100TX Twin Oaks Power One U1TX Twin Oaks Power One U2WY Two Elk Generating Station 1KY Tyrone 5SC Urquhart URQ3WI Valley 1WI Valley 2WI Valley 3WI Valley 4CO Valmont 5IL Vermilion 1IL Vermilion 2MS Victor J Daniel Jr 1MS Victor J Daniel Jr. 2TX W. A. Parish WAP5TX W. A. Parish WAP6TX W. A. Parish WAP7TX W. A. Parish WAP8OH W. H. Sammis 1OH W. H. Sammis 2OH W. H. Sammis 3OH W. H. Sammis 4OH W. H. Sammis 5OH W. H. Sammis 6OH W. H. Sammis 7NC W. H. Weatherspoon 1NC W. H. Weatherspoon 2NC W. H. Weatherspoon 3OH W. H. Zimmer 1SC W. S. Lee 1SC W. S. Lee 2SC W. S. Lee 3IN Wabash River 1IN Wabash River 2IN Wabash River 3IN Wabash River 4IN Wabash River 5IN Wabash River 6OH Walter C Beckjord 1OH Walter C Beckjord 2OH Walter C Beckjord 5OH Walter C. Beckjord 3OH Walter C. Beckjord 4OH Walter C. Beckjord 6GA Wansley 1GA Wansley 2IN Warrick 1IN Warrick 2IN Warrick 3IN Warrick 4SC Wateree WAT1SC Wateree WAT2IL Waukegan 7IL Waukegan 8IL Waukegan 17TX Welsh 1TX Welsh 2TX Welsh 3WI Weston 1WI Weston 2WI Weston 3WI Weston 4PA Wheelabrator Frackville Energy BLR1NE Whelan Energy Center 1AR White Bluff 1AR White Bluff 2IN Whitewater Valley 1IN Whitewater Valley 2AL Widows Creek 1AL Widows Creek 2AL Widows Creek 3AL Widows Creek 4AL Widows Creek 5AL Widows Creek 6AL Widows Creek 7AL Widows Creek 8IL Will County 1IL Will County 2IL Will County 3IL Will County 4SC Williams WIL1WV Willow Island 1WV Willow Island 2SC Winyah 1SC Winyah 2SC Winyah 3SC Winyah 4IL Wood River 4IL Wood River 5PA WPS Energy Servs Sunbury Gen 3PA WPS Energy Servs Sunbury Gen 4PA WPS Energy Servs Sunbury Gen 1APA WPS Energy Servs Sunbury Gen 1BPA WPS Energy Servs Sunbury Gen 2APA WPS Energy Servs Sunbury Gen 2BNY WPS Power Niagara 1PA WPS Westwood Generation LLC 031WY Wygen I 3WY Wygen II 4WY Wyodak BW91GA Yates Y1BRGA Yates Y2BRGA Yates Y3BRGA Yates Y4BRGA Yates Y5BRGA Yates Y6BRGA Yates Y7BRVA Yorktown 1VA Yorktown 2Attachment 5. List of oil-fired electric utility steam generating unitsrequiring Part I and II InformationState Plant Name Boiler IDState Plant Name Boiler IDState Plant Name Boiler ID61PR Aguirre 1PR Aguirre 2PR Aguirre 3PR Aguirre 4PR Aguirre 5PR Aguirre 6PR Aguirre 7PR Aguirre 8PR Aguirre 9PR Aguirre 10PR Aguirre 11PR Aguirre 12FL Anclote 1FL Anclote 2PR Arecibo 1PR Arecibo 2PR Arecibo 3NY Astoria Generating Station 30NY Astoria Generating Station 40NY Astoria Generating Station 50NJ B. L. England 3MS Baxter Wilson 1MS Baxter Wilson 2DC Benning 15DC Benning 16NY Bowline Point 1NY Bowline Point 2MA Brayton Point 4CT Bridgeport Station BHB2FL C. D. McIntosh Jr 1FL C. D. McIntosh Jr 2GU Cabras 1GU Cabras 2MA Canal Station 1MA Canal Station 2FL Cape Canaveral PCC1FL Cape Canaveral PCC2PR Central Palo Seco 1PR Central Palo Seco 2PR Central Palo Seco 3PR Central Palo Seco 4PR Central Palo Seco 5PR Central Palo Seco 6PR Central Palo Seco 7PR Central Palo Seco 8NY Charles Poletti 1MA Cleary Flood 8PR Costa Sur 1PR Costa Sur 2PR Costa Sur 3PR Costa Sur 4PR Costa Sur 5PR Costa Sur 6PR Costa Sur 7PR Costa Sur 8PR Costa Sur 9PR Costa Sur 10PA Cromby Generating Station 2MI Dan E. Karn 3MI Dan E. Karn 4NY Danskammer Generating Station 1NY Danskammer Generating Station 2CT Devon Station 7CT Devon Station 8IN Eagle Valley 1IN Eagle Valley 2NY East River 5NY East River 6PA Eddystone Generating Station 3PA Eddystone Generating Station 4DE Edge Moor 5IN Edwardsport 6-1MS Gerald Andrus 1IN Harding Street 9IN Harding Street 10IL Havana 1IL Havana 2IL Havana 3IL Havana 4IL Havana 5IL Havana 6IL Havana 7IL Havana 8MD Herbert A. Wagner 1MD Herbert A. Wagner 4HI Honolulu 16HI Honolulu 17FL Indian River 1FL Indian River 2FL Indian River 3SC Jefferies 1SC Jefferies 2HI Kahe 1HI Kahe 2HI Kahe 3HI Kahe 4HI Kahe 5HI Kahe 6FL Manatee PMT1FL Manatee PMT2FL Martin PMR1FL Martin PMR2DE McKee Run 3GA McManus 1GA McManus 2IL Meredosia 06LA Michoud 3CT Middletown 2CT Middletown 4MD Mirant Chalk Point 3MD Mirant Chalk Point 4PA Mitchell Power Station 1PA Mitchell Power Station 2PA Mitchell Power Station 3CT Montville Station 5CT Montville Station 6MA Mystic Generating Station 7CT New Haven Harbor NHB1NH Newington 1NY Northport 1NY Northport 2NY Northport 3NY Northport 4FL Northside Generating Station 3CT NRG Norwalk Harbor 1CT NRG Norwalk Harbor 2NY Oswego Harbor Power 5NY Oswego Harbor Power 6FL P. L. Bartow 1FL P. L. Bartow 2FL P. L. Bartow 3FL Port Everglades PPE1FL Port Everglades PPE2FL Port Everglades PPE3FL Port Everglades PPE4NY Port Jefferson 3NY Port Jefferson 4VA Possum Point 5State Plant Name Boiler IDState Plant Name Boiler IDState Plant Name Boiler ID62PA PPL Martins Creek 3PA PPL Martins Creek 4NJ PSEG Sewaren Generating Station 1NJ PSEG Sewaren Generating Station 2NJ PSEG Sewaren Generating Station 3NJ PSEG Sewaren Generating Station 4VI Randolph E. Harley 1NY Ravenswood Generating Station 1NY Ravenswood Generating Station 2NY Ravenswood Generating Station 3VI Richmond 1FL Riviera PRV3FL Riviera PRV4NY Roseton Generating Station 1NY Roseton Generating Station 2MA Salem Harbor 4PR San Juan Plant 1PR San Juan Plant 2PR San Juan Plant 3PR San Juan Plant 4PR San Juan Plant 5FL Sanford PSN3PA Schuylkill Generating Station 1FL Suwannee River 1FL Suwannee River 2FL Suwannee River 3GU Tanguisson 1FL Turkey Point PTP1FL Turkey Point PTP2MD Vienna Operations 8HI Waiau 3HI Waiau 4HI Waiau 5HI Waiau 6HI Waiau 7HI Waiau 8MA West Springfield 3ME William F. Wyman 1ME William F. Wyman 2ME William F. Wyman 3ME William F. Wyman 4VA Yorktown 363Attachment 6. List of all IGCC units requiring PartI, II, and III Information and selected for HCl/HF/HCNacid gas HAP, dioxin/furan organic HAP, non-dioxin/furan organic HAP, and mercury and other non-mercurymetallic HAP testingState Plant Name Boiler IDFL Polk 1CAFL Polk 1CTIN Wabash River 1aAttachment 7. List of all petroleum coke-fired unitsrequiring Part I, II, and III Information and selectedfor HCl/HF/HCN acid gas HAP, dioxin/furan organicHAP, non-dioxin/furan organic HAP, and mercuryand other non-mercury metallic HAP testingState Plant Name Boiler ID NOXControl PM Control FGD TypeTX AES Deepwater AAB001 SCR Electrostatic precipitator, hot side Spray typeOH Bay Shore 1 Baghouse, pulsePA Chester Operations 10 Baghouse, pulseCA Hanford CB1302 Baghouse, pulse Spray typeWI Manitowoc 9 SNCR Baghouse, pulseFL Northside Generating Station 1 Baghouse, pulse Spray typeFL Northside Generating Station 2 Baghouse, pulse Spray typeLA R S Nelson 1A Baghouse, reverse airLA R S Nelson 2A Baghouse, reverse airCA Rio Bravo Jasmin CFB SNCR Baghouse, pulseCA Rio Bravo Poso CFB SNCR Baghouse, pulseLA Rodemacher 3a SNCR Baghouse, pulseLA Rodemacher 3b SNCR Baghouse, pulseMT Yellowstone Energy LP BLR1 Baghouse, pulseMT Yellowstone Energy LP BLR2 Baghouse, pulse64Attachment 8. List of coal-fired electric utility steamgenerating units selected for HCl/HF/HCN acid gas HAP testingState Plant Name Boiler ID Primary Fuel Secondary Fuel NOXControl PM Control 1 PM Control 2 FGD Type FGD DateFL Crystal River 5 Bituminous CoalElectrostatic precipitator,cold sideSpray type 12/31/2009TX Oak Grove 1 Lignite CoalSCRBaghouse, pulse Spray dryer type 12/31/2009AR Plum Point Energy STG1SubbituminousCoalSCRBaghouse, pulse Spray dryer type 12/31/2009AZ Springerville 4SubbituminousCoalBituminous CoalSCRBaghouse, pulse Spray dryer type 12/31/2009WY Two Elk Generating Station 1SubbituminousCoalSCRBaghouse, pulse Spray type 12/31/2009AZ Cholla 3SubbituminousCoalBaghouse, pulse Spray dryer type 9/1/2008AZ Cholla 4SubbituminousCoalBaghouse, pulse Spray dryer type 9/1/2008TX Sandow Station 5A Lignite CoalSCRBaghouse, pulse Spray type 8/31/2009TX Sandow Station 5B Lignite CoalSCRBaghouse, pulse Spray type 8/31/2009WI Elm Road Generating Station 1 Bituminous CoalSCRBaghouse, pulse Spray type 6/1/2009NC G. G. Allen 1 Bituminous CoalElectrostatic precipitator,cold sideSpray type 5/1/2009NE Nebraska City 2SubbituminousCoalBaghouse, pulse Spray type 5/1/2009GA Wansley 2 Bituminous CoalSCRElectrostatic precipitator,cold sideJet Bubbling Reactor 5/1/2009GA Bowen 2BLR Bituminous CoalSCRElectrostatic precipitator,cold sideJet Bubbling Reactor 4/1/2009OH Conesville 4 Bituminous CoalElectrostatic precipitator,cold sideJet Bubbling Reactor 4/1/2009SC Cross 4 Bituminous CoalSCRElectrostatic precipitator,cold sideSpray type 1/1/2009IL Dallman 34 Bituminous CoalSCRBaghouse, pulse Packed type 1/1/2009VA Cogentrix Hopewell 1A Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2008VA Cogentrix Hopewell 1B Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2008VA Cogentrix Hopewell 1C Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2008VACogentrix Virginia LeasingCorporation2A Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2008VACogentrix Virginia LeasingCorporation2B Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2008VACogentrix Virginia LeasingCorporation2C Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2008GA Bowen 4BLR Bituminous CoalSCRElectrostatic precipitator,cold sideJet Bubbling Reactor 12/1/2008WV John E Amos 1 Bituminous CoalSCRElectrostatic precipitator,cold sideTray type 12/1/2008WV John E Amos 2 Bituminous CoalSCRElectrostatic precipitator,cold sideTray type 12/1/200865State Plant Name Boiler ID Primary Fuel Secondary Fuel NOXControl PM Control 1 PM Control 2 FGD Type FGD DateGA Wansley 1 Bituminous CoalSCRElectrostatic precipitator,cold sideJet Bubbling Reactor 12/1/2008NV TS Power Plant BLR100SubbituminousCoalSCRBaghouse, pulse Spray dryer type 6/1/2008WI Weston 4 Bituminous CoalSubbituminousCoal SCRBaghouse, pulse Spray dryer type 6/1/2008KY Ghent 4 Bituminous CoalSubbituminousCoalElectrostatic precipitator,hot sideSpray type 5/1/2008GA Bowen 3BLR Bituminous CoalSCRElectrostatic precipitator,cold sideJet Bubbling Reactor 4/1/2008KY H. L. Spurlock 4 Bituminous CoalSNCRBaghouse, pulse CFB 4/1/2008NC Belews Creek 1 Bituminous CoalElectrostatic precipitator,cold sideSpray type 1/1/2008GA Hammond 1 Bituminous CoalElectrostatic precipitator,cold sideSpray type 1/1/2008GA Hammond 2 Bituminous CoalElectrostatic precipitator,cold sideSpray type 1/1/2008GA Hammond 3 Bituminous CoalElectrostatic precipitator,cold sideSpray type 1/1/2008GA Hammond 4 Bituminous CoalElectrostatic precipitator,cold sideSpray type 1/1/2008VA Cogentrix Hopewell 2A Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2007VA Cogentrix Hopewell 2B Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2007VA Cogentrix Hopewell 2C Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2007VACogentrix Virginia LeasingCorporation1A Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2007VACogentrix Virginia LeasingCorporation1B Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2007VACogentrix Virginia LeasingCorporation1C Bituminous CoalBaghouse, pulse Spray dryer type 12/31/2007WY Wygen II 4SubbituminousCoalSCRBaghouse, pulse Spray type 12/31/2007OH Cardinal 2 Bituminous CoalSCRElectrostatic precipitator,cold sideJet Bubbling Reactor 12/1/2007WV John E. Amos 3 Bituminous CoalSCRElectrostatic precipitator,cold sideTray type 12/1/2007IA Louisa 101SubbituminousCoalBaghouse, pulseElectrostaticprecipitator, hotsideSpray dryer type 12/1/2007OH Cardinal 1 Bituminous CoalSCRElectrostatic precipitator,cold sideJet Bubbling Reactor 11/1/2007IA Council Bluffs 4SubbituminousCoalSCRBaghouse, pulse Spray dryer type 6/1/2007KY Ghent 3 Bituminous CoalSubbituminousCoalElectrostatic precipitator,hot sideSpray type 5/1/2007WV Mitchell 1 Bituminous CoalElectrostatic precipitator,cold sideTray type 4/1/2007SC Cross 3 Bituminous CoalCoal-basedSynfuel SCRElectrostatic precipitator,cold sideSpray type 1/1/200766State Plant Name Boiler ID Primary Fuel Secondary Fuel NOXControl PM Control 1 PM Control 2 FGD Type FGD DateWI Pleasant Prairie 2SubbituminousCoalSCRElectrostatic precipitator,cold sideSpray type 3/31/2007WV Mountaineer 1 Bituminous CoalSCRElectrostatic precipitator,cold sideSpray type 1/1/2007AZ Springerville 3SubbituminousCoalSCRBaghouse, pulse Spray dryer type 12/31/2006WV Mitchell 2 Bituminous CoalElectrostatic precipitator,cold sideTray type 12/1/2006WI Pleasant Prairie 1SubbituminousCoalSCRElectrostatic precipitator,cold sideSpray type 11/31/2006NC Marshall 1 Bituminous CoalMultiple cycloneElectrostaticprecipitator, coldsideSpray type 11/1/2006MT Hardin Generator Project PC1SubbituminousCoalSCRBaghouse, pulse Spray dryer type 2/1/2006NC Asheville 1 Bituminous CoalElectrostatic precipitator,cold sideSpray type 11/1/2005KY H. L. Spurlock 3 Bituminous CoalSNCRBaghouse, pulse CFB 4/1/2005PA Seward 1 Waste Coal Bituminous CoalSNCRBaghouse, pulse Spray dryer type 3/1/2004PA Seward 2 Waste Coal Bituminous CoalSNCRBaghouse, pulse Spray dryer type 3/1/2004IL Marion 123 Waste Coal Bituminous CoalBaghouse, pulse CFB 5/1/2003WY Wygen I 3SubbituminousCoalSCRBaghouse, pulse Spray type 5/1/2003CO Arapahoe 3SubbituminousCoalNatural GasBaghouse, reverse airDry Sorbent InjectionSystem1/1/2003CO Cherokee 2 Bituminous Coal Natural GasBaghouse, reverse air Dry sodium injection 1/1/2003CO Cherokee 4 Bituminous Coal Natural GasBaghouse, reverse air Spray dryer type 1/1/2003PR AES Puerto Rico (Aurora) 1 Bituminous CoalSNCRBaghouse, pulse CFB 12/31/2002PR AES Puerto Rico (Aurora) 2 Bituminous CoalSNCRBaghouse, pulse CFB 12/31/2002CO Valmont 5SubbituminousCoalBituminous CoalBaghouse, reverse air Spray dryer type 8/1/2002CO Cherokee 3 Bituminous Coal Natural GasBaghouse, reverse air Spray dryer type 7/1/2002WATransalta CentraliaGenerationBW21SubbituminousCoalWet scrubberElectrostaticprecipitator, coldsideSpray type 6/1/2002MS Red Hills Generating Facility AA001 Lignite CoalBaghouse, reverse air CFB 3/1/2002MS Red Hills Generating Facility AA002 Lignite CoalBaghouse, reverse air CFB 3/1/2002WV Mt. Storm 1 Bituminous CoalElectrostatic precipitator,cold sideSpray type 2/1/2002WV Mt. Storm 2 Bituminous CoalElectrostatic precipitator,cold sideSpray type 2/1/2002WATransalta CentraliaGenerationBW22SubbituminousCoalWet scrubberElectrostaticprecipitator, coldsideSpray type 10/1/200167State Plant Name Boiler ID Primary Fuel Secondary Fuel NOXControl PM Control 1 PM Control 2 FGD Type FGD DatePA Homer City Station 3 Bituminous CoalSCRElectrostatic precipitator,cold sideSpray type 9/1/2001IL Dallman 31 Bituminous CoalSCRElectrostatic precipitator,cold sidePacked type 6/1/2001IL Dallman 32 Bituminous CoalSCRElectrostatic precipitator,cold sidePacked type 6/1/2001MO Hawthorn 5ASubbituminousCoalNatural GasSCRBaghouse, pulse Spray dryer type 6/1/2001AK Healy 1SubbituminousCoalBaghouse, reverse air Spray dryer type 9/1/2000MDAES Warrior RunCogeneration FacilityBLR1 Bituminous CoalSNCR and SCRBaghouse, reverse air CFB 2/1/2000FL Big Bend BB01 Bituminous CoalSubbituminousCoalElectrostatic precipitator,cold sideSpray type 12/1/1999FL Big Bend BB02 Bituminous CoalSubbituminousCoalElectrostatic precipitator,cold sideSpray type 12/1/1999AZ Navajo 1 Bituminous CoalElectrostatic precipitator,hot sideSpray type 8/1/1999CO Hayden H2 Bituminous Coal Distillate Fuel OilBaghouse, reverse air Spray dryer type 6/1/1999OH Hamilton 9 Bituminous Coal Natural GasElectrostatic precipitator,hot sideBaghouse, pulse Dry gas absorption 4/1/1999CO Hayden H1 Bituminous Coal Natural GasBaghouse, reverse air Spray dryer type 12/1/1998AZ Navajo 2 Bituminous CoalElectrostatic precipitator,hot sideSpray type 11/1/1998NM San Juan 1SubbituminousCoalElectrostatic precipitator,hot sideSpray type 10/1/1998NM San Juan 2SubbituminousCoalElectrostatic precipitator,hot sideSpray type 10/1/1998NM San Juan 3SubbituminousCoalElectrostatic precipitator,hot sideSpray type 10/1/1998NM San Juan 4SubbituminousCoalElectrostatic precipitator,hot sideSpray type 10/1/1998CO Cherokee 1 Bituminous Coal Natural GasBaghouse, reverse air Dry sodium injection 2/1/1998AZ Navajo 3 Bituminous CoalElectrostatic precipitator,hot sideSpray type 11/1/1997VA Birchwood Power 1A Bituminous CoalSCRBaghouse, reverse air Spray dryer type 12/1/1996FL Stanton Energy Center 2 Bituminous CoalSCRElectrostatic precipitator,cold sideSpray type 6/1/1996IN AES Petersburg 1 Bituminous CoalElectrostatic precipitator,cold sideSpray type 5/1/1996IN AES Petersburg 2 Bituminous CoalElectrostatic precipitator,cold sideSpray type 5/1/1996VA Clover 2 Bituminous CoalBaghouse, reverse air Spray type 3/1/1996FL Indiantown Cogeneration LP AAB01 Bituminous CoalSCRBaghouse, reverse air Spray dryer type 12/1/1995PA Conemaugh 2 Bituminous CoalElectrostatic precipitator,cold sideWet scrubber Spray type 11/1/1995SC Cope COP1 Bituminous Coal Natural GasBaghouse, reverse air Spray dryer type 11/1/199568State Plant Name Boiler ID Primary Fuel Secondary Fuel NOXControl PM Control 1 PM Control 2 FGD Type FGD DateWY Neil Simpson II 2SubbituminousCoalElectrostatic precipitator,cold sideCirculating DryScrubber11/1/1995VA Clover 1 Bituminous CoalBaghouse, reverse air Spray type 10/1/1995PANorthampton GeneratingCompanyBLR1 Waste Coal Petroleum CokeSNCRBaghouse, pulse CFB 8/1/1995NY AES Cayuga 1 Bituminous CoalSCRElectrostatic precipitator,cold sideSpray type 6/1/1995NY AES Cayuga 2 Bituminous CoalElectrostatic precipitator,cold sideSpray type 6/1/1995KYHMP&L Station TwoHendersonH1 Bituminous CoalElectrostatic precipitator,cold sideTray type 6/1/1995KYHMP&L Station TwoHendersonH2 Bituminous CoalElectrostatic precipitator,cold sideTray type 6/1/1995NC Roanoke Valley II BLR2 Bituminous CoalBaghouse, pulseCirculating DryScrubber6/1/1995PA Colver Power Project ABB01 Waste CoalBaghouse, pulse CFB 5/1/1995SC Cross 1 Bituminous CoalCoal-basedSynfuelSCRElectrostatic precipitator,cold sideSpray type 5/1/1995OH General James M Gavin 2 Bituminous CoalSCRElectrostatic precipitator,cold sideSpray type 3/1/1995NJ B. L. England 2 Bituminous CoalSNCRElectrostatic precipitator,cold sideSpray type 1/1/1995TN Cumberland 1 Bituminous CoalSCRElectrostatic precipitator,cold sideSpray type 1/1/1995TN Cumberland 2 Bituminous CoalElectrostatic precipitator,cold sideSpray type 1/1/1995IN F. B. Culley 2 Bituminous CoalElectrostatic precipitator,cold sideSpray type 1/1/1995IN F. B. Culley 3 Bituminous CoalSCRElectrostatic precipitator,cold sideSpray type 1/1/1995IN Gibson 4 Bituminous CoalElectrostatic precipitator,cold sideSpray type 1/1/1995WV Mt Storm 3 Bituminous CoalElectrostatic precipitator,cold sideSpray type 1/1/1995PA Conemaugh 1 Bituminous CoalElectrostatic precipitator,cold sideWet scrubber Spray type 12/1/1994OH General James M Gavin 1 Bituminous CoalSCRElectrostatic precipitator,cold sideSpray type 12/1/1994KY Ghent 1 Bituminous CoalElectrostatic precipitator,cold sideSpray type 12/1/1994KY Elmer Smith 1 Bituminous CoalSCRElectrostatic precipitator,cold sideSpray type 11/1/1994KY Elmer Smith 2 Bituminous CoalSNCRElectrostatic precipitator,cold sideSpray type 11/1/1994WV Harrison Power Station 1 Bituminous CoalSCRElectrostatic precipitator,cold sideWet scrubber Spray type 11/1/1994WV Harrison Power Station 2 Bituminous CoalSCRElectrostatic precipitator,cold sideWet scrubber Spray type 11/1/1994WV Harrison Power Station 3 Bituminous CoalSCRElectrostatic precipitator,cold sideWet scrubber Spray type 11/1/199469State Plant Name Boiler ID Primary Fuel Secondary Fuel NOXControl PM Control 1 PM Control 2 FGD Type FGD DateIN Whitewater Valley 2 Bituminous CoalElectrostatic precipitator,cold sideSpray dryer type 10/1/1994NJ Logan Generating Plant B01 Bituminous CoalSCRBaghouse, reverse air Spray dryer type 9/1/1994NC Roanoke Valley I BLR1 Bituminous Coal Distillate Fuel OilBaghouse, reverse airCirculating DryScrubber5/1/1994NJ Chambers Cogeneration LP BOIL1 Bituminous CoalSCRBaghouse, reverse air Spray dryer type 3/1/1994NJ Chambers Cogeneration LP BOIL2 Bituminous CoalSCRBaghouse, reverse air Spray dryer type 3/1/1994FL Cedar Bay Generating LP CBA Bituminous CoalSNCRBaghouse, reverse airCirculating DryScrubber2/1/1994FL Cedar Bay Generating LP CBB Bituminous CoalSNCRBaghouse, reverse airCirculating DryScrubber2/1/1994FL Cedar Bay Generating LP CBC Bituminous CoalSNCRBaghouse, reverse airCirculating DryScrubber2/1/1994CO Arapahoe 4SubbituminousCoalNatural GasBaghouse, reverse airDry Sorbent InjectionSystem6/1/1993PA Scrubgrass Generating UNIT 1 Waste CoalSNCRBaghouse, pulse CFB 6/1/1993PA Scrubgrass Generating UNIT 2 Waste CoalSNCRBaghouse, pulse CFB 6/1/1993UT Sunnyside Cogen Associates 1 Waste CoalBaghouse, pulse CFB 2/1/1993WV North Branch 1A Bituminous Coal Waste OilBaghouse, pulse CFB 12/31/1992WV North Branch 1B Bituminous Coal Waste OilBaghouse, pulse CFB 12/31/1992TX J. K. Spruce BLR1SubbituminousCoalBaghouse, reverse air Spray type 12/1/1992VA Mecklenburg Power Station BLR1 Bituminous CoalBaghouse, pulseCirculating DryScrubber11/1/1992VA Mecklenburg Power Station BLR2 Bituminous CoalBaghouse, pulseCirculating DryScrubber11/1/1992PA Piney Creek Project BRBR1 Waste CoalSNCRBaghouse, pulseCirculating DryScrubber11/1/1992GA Yates Y1BR Bituminous Coal Natural GasElectrostatic precipitator,cold sideWet scrubber Jet Bubbling Reactor 10/1/1992HI AES Hawaii BLRASubbituminousCoalTire-derived FuelsSNCRBaghouse, reverse air CFB 9/1/1992HI AES Hawaii BLRBSubbituminousCoalWaste OilSNCRBaghouse, reverse air CFB 9/1/1992VA Cogentrix of Richmond 3A Bituminous CoalBaghouse, pulse Spray dryer type 8/1/1992VA Cogentrix of Richmond 3B Bituminous CoalBaghouse, pulse Spray dryer type 8/1/1992VA Cogentrix of Richmond 4A Bituminous CoalBaghouse, pulse Spray dryer type 8/1/1992VA Cogentrix of Richmond 4B Bituminous CoalBaghouse, pulse Spray dryer type 8/1/1992WV Grant Town Power Plant BLR1A Waste CoalBaghouse, pulse CFB 8/1/1992WV Grant Town Power Plant BLR1B Waste CoalBaghouse, pulse CFB 8/1/1992IN Bailly 7 Bituminous Coal Natural GasElectrostatic precipitator,cold sidePacked type 6/1/199270State Plant Name Boiler ID Primary Fuel Secondary Fuel NOXControl PM Control 1 PM Control 2 FGD Type FGD DateIN Bailly 8 Bituminous Coal Natural GasSCRElectrostatic precipitator,cold sidePacked type 6/1/1992PAPanther Creek EnergyFacilityBLR1 Waste CoalSNCRBaghouse, pulseCirculating DryScrubber6/1/1992PAPanther Creek EnergyFacilityBLR2 Waste CoalSNCRBaghouse, pulseCirculating DryScrubber6/1/1992VA Cogentrix of Richmond 1A Bituminous CoalBaghouse, pulse Spray dryer type 5/1/1992VA Cogentrix of Richmond 1B Bituminous CoalBaghouse, pulse Spray dryer type 5/1/1992VA Cogentrix of Richmond 2A Bituminous CoalBaghouse, pulse Spray dryer type 5/1/1992VA Cogentrix of Richmond 2B Bituminous CoalBaghouse, pulse Spray dryer type 5/1/1992VA Altavista Power Station 1 Bituminous CoalSNCRBaghouse, pulse Spray dryer type 2/1/1992WV Morgantown Energy Facility CFB1 Waste CoalBaghouse, pulse CFB 1/1/1992WV Morgantown Energy Facility CFB2 Waste CoalBaghouse, pulse CFB 1/1/1992TX Twin Oaks Power One U2 Lignite CoalBaghouse, shake and deflate CFB 10/1/1991VA Southampton Power Station 1 Bituminous CoalBaghouse, pulse Spray dryer type 6/1/1991PA Ebensburg Power 031 Waste CoalBaghouse, pulse CFB 5/1/1991PA Cambria Cogen B1 Waste CoalSNCRBaghouse, shake and deflate CFB 3/1/1991PA Cambria Cogen B2 Waste CoalSNCRBaghouse, shake and deflate CFB 3/1/1991OH W. H. Zimmer 1 Bituminous CoalElectrostatic precipitator,cold sideSpray type 3/1/199171Attachment 9. List of coal-fired electric utility steam generating units selected for dioxin/furan organic HAP testingState Plant NameBoilerIDPrimary FuelSecondaryFuelNOXControlPM Control 1 PM Control 2 FGD_Type01 ACICAACE CogenerationFacilityCFB Bituminous Coal Petroleum CokeBaghouse, reverse air CFBCT AES Thames A Bituminous CoalBaghouse, reverse airCirculating DryScrubberCT AES Thames B Bituminous CoalBaghouse, reverse airCirculating DryScrubberVAAltavista PowerStation1 Bituminous CoalSNCRBaghouse, pulse Spray dryer typeNYBlack RiverGenerationE0003 Bituminous CoalBaghouse, pulse Multiple cycloneJet BubblingReactorVA Chesterfield 6 Bituminous CoalElectrostatic precipitator, cold sideNCCogentrix DwayneCollier BattleCogen1A Bituminous CoalBaghouse, pulse Spray dryer typeVACogentrix ofRichmond4A Bituminous CoalBaghouse, pulse Spray dryer typeIA Council Bluffs 4 Subbituminous CoalSCRBaghouse, pulse Spray dryer type YCO Craig C2 Subbituminous CoalBaghouse, pulse Spray typeTN Cumberland 1 Bituminous CoalSCRElectrostatic precipitator,cold side Spray typeWY Dave Johnston BW41 Subbituminous CoalElectrostatic precipitator, cold sideDE Edge Moor 4 Bituminous CoalResidual FuelOilElectrostatic precipitator, cold side YKY Green River 5 Bituminous CoalElectrostatic precipitator, hot sideKY H. L. Spurlock 2 Bituminous CoalSCRElectrostatic precipitator, hot side Spray dryer typeIL Havana 9 Subbituminous CoalSCRElectrostatic precipitator, hot side Baghouse, pulse YILHennepin PowerStation2 Subbituminous Coal Natural GasElectrostatic precipitator, cold sideMN Hoot Lake 3 Subbituminous CoalElectrostatic precipitator, cold sideTX J. K. Spruce BLR1 Subbituminous CoalBaghouse, reverse air Spray typeWV Kammer 1 Bituminous CoalElectrostatic precipitator, cold sideWV Kammer 2 Bituminous CoalElectrostatic precipitator, cold sideIL Marion 4 Bituminous Coal Waste CoalSCRElectrostatic precipitator, cold side Venturi typeND Milton R Young B1 Lignite CoalElectrostatic precipitator, cold sideMI Monroe 3 Subbituminous CoalBituminousCoal SCRElectrostatic precipitator, cold sideOK Northeastern 3314 Subbituminous Coal Natural GasElectrostatic precipitator, cold sideIA Prairie Creek 4 Subbituminous Coal Landfill GasElectrostatic precipitator, cold sideNCPrimary EnergySouthport1C Bituminous CoalBaghouse, pulse N/A72State Plant NameBoilerIDPrimary FuelSecondaryFuelNOXControlPM Control 1 PM Control 2 FGD_Type01 ACICO Ray D. Nixon 1 Subbituminous CoalBaghouse, reverse airNC Roanoke Valley I BLR1 Bituminous CoalDistillate FuelOilBaghouse, reverse airCirculating DryScrubberGA Scherer 1 Subbituminous CoalElectrostatic precipitator, hot side YGA Scherer 3 Subbituminous CoalElectrostatic precipitator,cold side Spray type YPA Shawville 3 Bituminous CoalElectrostatic precipitator, cold sideMN Silver Bay Power BLR2 Subbituminous Coal Natural GasBaghouse, reverse airND Stanton 1 Subbituminous CoalElectrostatic precipitator, cold sideIN State Line Energy 3 Subbituminous CoalBaghouse, pulseIA Streeter Station 7 Bituminous CoalSubbituminousCoalElectrostatic precipitator, hot sideKSTecumseh EnergyCenter9 Subbituminous Coal Natural GasElectrostatic precipitator, cold sideMITES Filer CityStation2 Bituminous CoalBaghouse, pulse Spray dryer typeWATransalta CentraliaGenerationBW21 Subbituminous CoalWet scrubberElectrostatic precipitator,cold sideSpray typeNYTrigen SyracuseEnergy2 Bituminous CoalBaghouse, reverse air N/ATXTwin Oaks PowerOneU2 Lignite CoalBaghouse, shake and deflate CFBWYTwo ElkGenerating Station1 Subbituminous CoalSCRBaghouse, pulse Spray typeIL Vermilion 1 Subbituminous Coal Natural GasElectrostatic precipitator, cold side Baghouse, pulse YOH Walter C Beckjord 5 Bituminous CoalElectrostatic precipitator, cold sideIL Waukegan 8 Subbituminous CoalElectrostatic precipitator, cold sideAL Widows Creek 2 Bituminous CoalElectrostatic precipitator, cold sideAL Widows Creek 7 Bituminous CoalElectrostatic precipitator, cold side Wet scrubber Spray typeAL Widows Creek 8 Bituminous CoalWet scrubber Tray typeSC Winyah 1 Bituminous CoalCoal-basedSynfuelElectrostatic precipitator, cold side Wet scrubber Venturi typeSC Winyah 2 Bituminous CoalCoal-basedSynfuelElectrostatic precipitator, cold sideShaded units are required to do all organic testing.73Attachment 10. List of coal-fired electric utility steam generating units selectedfor non-dioxin/furan organic HAP testingState Plant Name Boiler ID PrimaryFuel Secondary Fuel Boiler Date NOXControl PM Control 1PM Control 2 FGD TypeTXOak Grove1Lignite Coal12/31/2009SCRBaghouse, pulseSpray dryer typeARPlum PointEnergySTG1 Subbituminous Coal 12/31/2009 SCR Baghouse, pulse Spray dryer typeAZ Springerville 4 Subbituminous Coal Bituminous Coal12/31/2009 SCR Baghouse, pulse Spray dryer typeWYTwo ElkGeneratingStation1Subbituminous Coal12/31/2009SCRBaghouse, pulseSpray typeTX Sandow Station 5A Lignite Coal 8/31/2009 SCR Baghouse, pulse Spray typeTX Sandow Station 5B Lignite Coal 8/31/2009 SCR Baghouse, pulse Spray typeWIElm RoadGeneratingStation1 Bituminous Coal 6/1/2009 SCR Baghouse, pulse Spray typeNE Nebraska City 2 Subbituminous Coal5/1/2009 Baghouse, pulse Spray typeSCCross4Bituminous Coal1/1/2009SCRElectrostatic precipitator, cold sideSpray typeIL Dallman 34 Bituminous Coal 1/1/2009 SCR Baghouse, pulse Packed typeNV TS Power Plant BLR100 Subbituminous Coal 6/1/2008 SCR Baghouse, pulse Spray dryer typeWI Weston 4 Bituminous CoalSubbituminousCoal6/1/2008 SCR Baghouse, pulse Spray dryer typeKYH. L. Spurlock4Bituminous Coal4/1/2008SNCRBaghouse, pulseCFBWY Wygen II 4 Subbituminous Coal 12/31/2007 SCR Baghouse, pulse Spray typeIA Council Bluffs 4 Subbituminous Coal 6/1/2007 SCR Baghouse, pulse Spray dryer typeSC Cross 3 Bituminous CoalCoal-basedSynfuel1/1/2007 SCR Electrostatic precipitator, cold side Spray typeAZ Springerville 3 Subbituminous Coal 12/31/2006 SCR Baghouse, pulse Spray dryer typeMTHardinGeneratorProjectPC1 Subbituminous Coal 4/1/2006 SCRBaghouse, pulse Spray dryer typeKYH. L. Spurlock3Bituminous Coal4/1/2005SNCRBaghouse, pulseCFBPA Seward 1 Waste Coal Bituminous Coal 3/1/2004 SNCR Baghouse, pulse Spray dryer typePA Seward 2 Waste Coal Bituminous Coal 3/1/2004 SNCR Baghouse, pulse Spray dryer typeIL Marion 123 Waste Coal Bituminous Coal 5/1/2003 Baghouse, pulse CFBWY Wygen I 3 Subbituminous Coal 5/1/2003 SCR Baghouse, pulse Spray typePRAES PuertoRico (Aurora)1 Bituminous Coal 12/31/2002 SNCR Baghouse, pulse CFBPRAES PuertoRico (Aurora)2 Bituminous Coal 12/31/2002 SNCR Baghouse, pulse CFBShaded units are required to do all organic testing.74State Plant Name Boiler ID PrimaryFuel Secondary Fuel Boiler Date NOXControl PM Control 1PM Control 2 FGD TypeMSRed HillsGeneratingFacilityAA001 Lignite Coal 3/1/2002 Baghouse, reverse air CFBMSRed HillsGeneratingFacilityAA002 Lignite Coal 3/1/2002 Baghouse, reverse air CFBMOHawthorn5ASubbituminous CoalNatural Gas6/1/2001SCRBaghouse, pulseSpray dryer typeMDAES WarriorRunCogenerationFacilityBLR1 Bituminous Coal 2/1/2000 SCR and SNCR Baghouse, reverse air CFBVABirchwoodPower1A Bituminous Coal 12/1/1996 SCR Baghouse, reverse air Spray dryer typeFLStanton EnergyCenter2 Bituminous Coal 6/1/1996 SCR Electrostaticprecipitator, cold side Spray typeVAClover2Bituminous Coal3/1/1996Baghouse, reverse airSpray typeFLIndiantownCogenerationLPAAB01 Bituminous Coal 12/1/1995 SCR Baghouse, reverse air Spray dryer typeSC Cope COP1 Bituminous Coal Natural Gas 11/1/1995 Baghouse, reverse air Spray dryer typeWYNeil Simpson II2Subbituminous Coal11/1/1995Electrostatic precipitator, cold sideCirculating DryScrubberVA Clover 1 Bituminous Coal 10/1/1995 Baghouse, reverse air Spray typePANorthamptonGeneratingCompanyBLR1 Waste Coal Petroleum Coke8/1/1995 SNCR Baghouse, pulse CFBNCRoanokeValley IIBLR2 Bituminous Coal 6/1/1995 Baghouse, pulseCirculating DryScrubberPAColver PowerProjectABB01 Waste Coal 5/1/1995 Baghouse, pulse CFBSC Cross 1 Bituminous CoalCoal-basedSynfuel5/1/1995 SCR Electrostatic precipitator, cold side Spray typeNJLoganGeneratingPlantB01 Bituminous Coal 9/1/1994 SCR Baghouse, reverse air Spray dryer typeNCRoanokeValley IBLR1 Bituminous Coal Distillate Fuel Oil 5/1/1994 Baghouse, reverse airCirculating DryScrubberNJChambersCogenerationLPBOIL1 Bituminous Coal 3/1/1994 SCR Baghouse, reverse air Spray dryer typeNJChambersCogenerationLPBOIL2 Bituminous Coal 3/1/1994 SCR Baghouse, reverse air Spray dryer typeFLCedar BayGenerating LPCBA Bituminous Coal 1/1/1994 SNCR Baghouse, reverse airCirculating DryScrubberFLCedar BayGenerating LPCBB Bituminous Coal 1/1/1994 SNCR Baghouse, reverse airCirculating DryScrubberShaded units are required to do all organic testing.75State Plant Name Boiler ID PrimaryFuel Secondary Fuel Boiler Date NOXControl PM Control 1PM Control 2 FGD TypeFLCedar BayGenerating LPCBCBituminous Coal1/1/1994SNCRBaghouse, reverse airCirculating DryScrubberPAScrubgrassGeneratingUNIT 1 Waste Coal 6/1/1993 SNCR Baghouse, pulse CFBPAScrubgrassGeneratingUNIT 2Waste Coal6/1/1993SNCRBaghouse, pulseCFBUTSunnysideCogenAssociates1 Waste Coal 2/1/1993 Baghouse, pulse CFBWV North Branch 1A Bituminous Coal Waste Oil 12/31/1992 Baghouse, pulse CFBWVNorth Branch1BBituminous CoalWaste Oil12/31/1992Baghouse, pulseCFBTXJ. K. SpruceBLR1Subbituminous Coal12/1/1992Baghouse, reverse airSpray typePAPiney CreekProjectBRBR1 Waste Coal 12/1/1992 SNCR Baghouse, pulseCirculating DryScrubberVAMecklenburgPower StationBLR1 Bituminous Coal 11/1/1992 Baghouse, pulseCirculating DryScrubberVAMecklenburgPower StationBLR2 Bituminous Coal 11/1/1992 Baghouse, pulseCirculating DryScrubberHI AES Hawaii BLRA Subbituminous Coal Tire-derived Fuels 9/1/1992 SNCR Baghouse, reverse air CFBHI AES Hawaii BLRB Subbituminous Coal Waste Oil 9/1/1992 SNCR Baghouse, reverse air CFBVACogentrix ofRichmond3A Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer typeVACogentrix ofRichmond3B Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer typeVACogentrix ofRichmond4A Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer typeVACogentrix ofRichmond4B Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer typeWVGrant TownPower PlantBLR1A Waste Coal 8/1/1992 Baghouse, pulse CFBWVGrant TownPower PlantBLR1B Waste Coal 8/1/1992 Baghouse, pulse CFBPAPanther CreekEnergy FacilityBLR1 Waste Coal 6/1/1992 SNCR Baghouse, pulseCirculating DryScrubberPAPanther CreekEnergy FacilityBLR2 Waste Coal 6/1/1992 SNCR Baghouse, pulseCirculating DryScrubberVACogentrix ofRichmond1A Bituminous Coal 5/1/1992 Baghouse, pulse Spray dryer typeVACogentrix ofRichmond1BBituminous Coal5/1/1992Baghouse, pulseSpray dryer typeVACogentrix ofRichmond2A Bituminous Coal 5/1/1992 Baghouse, pulse Spray dryer typeVACogentrix ofRichmond2BBituminous Coal5/1/1992Baghouse, pulseSpray dryer typeVAAltavista PowerStation1 Bituminous Coal 2/1/1992 SNCR Baghouse, pulse Spray dryer typeShaded units are required to do all organic testing.76State Plant Name Boiler ID PrimaryFuel Secondary Fuel Boiler Date NOXControl PM Control 1PM Control 2 FGD TypeWVMorgantownEnergy FacilityCFB1Waste Coal1/1/1992Baghouse, pulseCFBWVMorgantownEnergy FacilityCFB2 Waste Coal 1/1/1992 Baghouse, pulse CFBTXTwin OaksPower OneU2Lignite Coal10/1/1991Baghouse, shake and deflateCFBVASouthamptonPower Station1Bituminous Coal6/1/1991Baghouse, pulseSpray dryer typeMD Brandon Shores 2 Bituminous Coal 5/1/1991 SCR Electrostatic precipitator, hot side Spray typePAEbensburgPower031Waste Coal5/1/1991Baghouse, pulseCFBPA Cambria Cogen B1 Waste Coal 3/1/1991 SNCR Baghouse, shake and deflate CFBPACambria CogenB2Waste Coal3/1/1991SNCRBaghouse, shake and deflateCFBALJames H MillerJr.4 Subbituminous Coal 3/1/1991 SCR Electrostatic precipitator, cold side Spray typeOHW. H. Zimmer1Bituminous Coal3/1/1991Electrostatic precipitator, cold sideSpray typeOKAES ShadyPoint1A Bituminous Coal 1/1/1991 Baghouse, pulse CFBOKAES ShadyPoint1BBituminous Coal1/1/1991Baghouse, pulseCFBOKAES ShadyPoint2ABituminous Coal1/1/1991Baghouse, pulseCFBOKAES ShadyPoint2B Bituminous Coal 1/1/1991 Baghouse, pulse CFBCONucla1Bituminous Coal1/1/1991Baghouse, shake and deflateCFBNYTrigenSyracuseEnergy1 Bituminous Coal 1/1/1991 Baghouse, reverse air N/ANYTrigenSyracuseEnergy2 Bituminous Coal 1/1/1991 Baghouse, reverse air N/ANYTrigenSyracuseEnergy3 Bituminous Coal 1/1/1991 Baghouse, reverse air N/ANYTrigenSyracuseEnergy4Bituminous Coal1/1/1991Baghouse, reverse airN/ANYTrigenSyracuseEnergy5 Bituminous Coal 1/1/1991 Baghouse, reverse air N/AKYShawnee10Bituminous Coal12/1/1990Baghouse, reverse airCFBKY Trimble County 1 Bituminous Coal 12/1/1990 SCR Electrostatic precipitator, cold side Spray typeNCCogentrixDwayne CollierBattle Cogen1A Bituminous Coal 10/1/1990 Baghouse, pulse Spray dryer typeShaded units are required to do all organic testing.77State Plant Name Boiler ID PrimaryFuel Secondary Fuel Boiler Date NOXControl PM Control 1PM Control 2 FGD TypeNCCogentrixDwayne CollierBattle Cogen1BBituminous Coal10/1/1990Baghouse, pulseSpray dryer typeNCCogentrixDwayne CollierBattle Cogen2A Bituminous Coal 10/1/1990 Baghouse, pulse Spray dryer typeNCCogentrixDwayne CollierBattle Cogen2BBituminous Coal10/1/1990Baghouse, pulseSpray dryer typePAFoster WheelerMt CarmelCogenSG-101Waste Coal9/1/1990Baghouse, pulseCirculating DryScrubberTXTwin OaksPower OneU1 Lignite Coal 9/1/1990 Baghouse, shake and deflate CFBCAACECogenerationFacilityCFB Bituminous Coal Petroleum Coke 6/1/1990 Baghouse, reverse air CFBWIManitowoc8Bituminous CoalPetroleum Coke6/1/1990Single cycloneBaghouse, pulseCFBAZ Springerville 2 Subbituminous Coal 6/1/1990 Baghouse, reverse air Spray dryer typeMITES Filer CityStation1 Bituminous Coal 6/1/1990 Baghouse, pulse Spray dryer typeMITES Filer CityStation2 Bituminous Coal 6/1/1990 Baghouse, pulse Spray dryer typeNYWPS PowerNiagara1 Bituminous Coal 4/1/1990 SNCR Baghouse, pulse CFBCT AES Thames A Bituminous Coal 3/1/1990 Baghouse, reverse airCirculating DryScrubberCTAES ThamesBBituminous Coal3/1/1990Baghouse, reverse airCirculating DryScrubberMTColstrip EnergyLPBLR1Waste Coal2/1/1990Baghouse, pulseCFBIN Rockport MB2 Subbituminous Coal 12/1/1989Electrostatic precipitator, cold side N/APASt. NicholasCogen Project1 Waste Coal 12/1/1989 Baghouse, pulse CFBPAKlineTownshipCogen Facility1Waste Coal11/1/1989Single cycloneBaghouse, pulseCFBALJames H MillerJr.3 Subbituminous Coal 5/1/1989 SCR Electrostatic precipitator, cold side Spray typeGAScherer4Subbituminous Coal2/1/1989Electrostatic precipitator, cold sideSpray typePAWheelabratorFrackvilleEnergyBLR1Waste Coal9/1/1988Baghouse, pulseCFBNYBlack RiverGenerationE0001 Bituminous Coal 6/1/1988Baghouse, pulse Multiple cycloneJet BubblingReactorNYBlack RiverGenerationE0002 Bituminous Coal 6/1/1988Baghouse, pulse Multiple cycloneJet BubblingReactorShaded units are required to do all organic testing.78State Plant Name Boiler ID PrimaryFuel Secondary Fuel Boiler Date NOXControl PM Control 1PM Control 2 FGD TypeNYBlack RiverGenerationE0003 Bituminous Coal 6/1/1988Baghouse, pulse Multiple cycloneJet BubblingReactorFLCentral Power& Lime1 Bituminous Coal 6/1/1988 Baghouse, reverse air N/AVACogentrixVirginiaLeasingCorporation1A Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer typeVACogentrixVirginiaLeasingCorporation1B Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer typeVACogentrixVirginiaLeasingCorporation1C Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer typeVACogentrixVirginiaLeasingCorporation2A Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer typeVACogentrixVirginiaLeasingCorporation2B Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer typeVACogentrixVirginiaLeasingCorporation2CBituminous Coal6/1/1988Baghouse, pulseSpray dryer typeCAMt. PosoCogenerationBL01Bituminous Coal6/1/1988SNCRBaghouse, reverse airCFBPAWPSWestwoodGenerationLLC031 Waste Coal 6/1/1988 Baghouse, reverse air N/AFLSt Johns RiverPower Park2 Bituminous CoalCoal-basedSynfuel5/1/1988 Electrostatic precipitator, cold side Spray typeTXFayette PowerProject3 Subbituminous Coal 4/1/1988 Electrostaticprecipitator, cold side Spray typePAJohn B RichMemorialPower StationCFB1Waste Coal2/1/1988Baghouse, pulseCFBPAJohn B RichMemorialPower StationCFB2 Waste Coal 2/1/1988 Baghouse, pulse CFBVACogentrixHopewell1A Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer typeVACogentrixHopewell1BBituminous Coal12/1/1987Baghouse, pulseSpray dryer typeVACogentrixHopewell1C Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer typeShaded units are required to do all organic testing.79State Plant Name Boiler ID PrimaryFuel Secondary Fuel Boiler Date NOXControl PM Control 1PM Control 2 FGD TypeVACogentrixHopewell2A Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer typeVACogentrixHopewell2B Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer typeVACogentrixHopewell2C Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer typeMNSherburneCounty3Subbituminous Coal11/1/1987Baghouse, reverse airSpray dryer typeNYDanskammerGeneratingStation3Bituminous CoalNatural Gas9/1/1987Electrostatic precipitator, cold sideN/ANCPrimary EnergySouthport1ABituminous Coal9/1/1987Baghouse, pulseN/ANCPrimary EnergySouthport1B Bituminous Coal 9/1/1987 Baghouse, pulse N/ANCPrimary EnergySouthport1C Bituminous Coal 9/1/1987 Baghouse, pulse N/ANCPrimary EnergySouthport2A Bituminous Coal 9/1/1987 Baghouse, pulse N/ANCPrimary EnergySouthport2BBituminous Coal9/1/1987Baghouse, pulseN/ANCPrimary EnergySouthport2CBituminous Coal9/1/1987Baghouse, pulseN/ANCPrimary EnergyRoxboro1ABituminous Coal8/1/1987Baghouse, pulseN/ANCPrimary EnergyRoxboro1B Bituminous Coal 8/1/1987 Baghouse, pulse N/ANCPrimary EnergyRoxboro1CBituminous Coal8/1/1987Baghouse, pulseN/APAAES BeaverValley PartnersBeaver Valley2 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold sideWet scrubber Spray typePAAES BeaverValley PartnersBeaver Valley3 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold sideWet scrubber Spray typePAAES BeaverValley PartnersBeaver Valley4 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold sideWet scrubber Spray typePAAES BeaverValley PartnersBeaver Valley5 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold sideWet scrubber Spray typeFLStanton EnergyCenter1Bituminous Coal7/1/1987Electrostatic precipitator, cold sideSpray typeUTIntermountainPower Project2SGA Bituminous CoalSubbituminousCoal5/1/1987 Baghouse, reverse air Spray typeNYDanskammerGeneratingStation4Bituminous CoalNatural Gas3/1/1987Electrostatic precipitator, cold sideN/AFLSt. Johns RiverPower Park1 Bituminous CoalCoal-basedSynfuel3/1/1987 Electrostatic precipitator, cold side Spray typeShaded units are required to do all organic testing.80State Plant Name Boiler ID PrimaryFuel Secondary Fuel Boiler Date NOXControl PM Control 1PM Control 2 FGD TypeGA Scherer 3 Subbituminous Coal 1/1/1987 Electrostatic precipitator, cold side Spray typeTXOklaunion1Bituminous Coal12/1/1986Electrostatic precipitator, cold sideSpray typeKY D. B. Wilson W1 Bituminous Coal 11/1/1986 Electrostatic precipitator, cold side Spray typeTX Limestone LIM2 Lignite CoalSubbituminousCoal10/1/1986 Electrostatic precipitator, cold side Spray typeNDAntelopeValleyB2 Lignite Coal 7/1/1986 Baghouse, reverse air Spray dryer typeUTIntermountainPower Project1SGA Bituminous CoalSubbituminousCoal6/1/1986 Baghouse, reverse air Spray typeUT Bonanza 1-1 Bituminous Coal 5/1/1986 Baghouse, reverse air Spray typeIN AES Petersburg 4 Bituminous Coal 4/1/1986 Electrostatic precipitator, cold side Spray typeMT Colstrip 4 Subbituminous Coal 4/1/1986 Wet scrubber Venturi typeLA Dolet Hills 1 Lignite Coal Natural Gas 4/1/1986 Electrostatic precipitator, cold side Wet scrubber Spray typeOK GRDA 2 Subbituminous Coal 4/1/1986 Electrostaticprecipitator, cold side Spray dryer typeINA. B. Brown2Bituminous Coal2/1/1986SCRElectrostatic precipitator, cold sideSpray typeIN R. M. Schahfer 18 Bituminous Coal 2/1/1986 Electrostatic precipitator, cold side Spray typeTX Limestone LIM1 Lignite CoalSubbituminousCoal10/1/1985 Electrostatic precipitator, cold side Spray typeMIBelle River2Subbituminous Coal7/1/1985Electrostatic precipitator, cold sideN/ANV North Valmy 2 Bituminous CoalSubbituminousCoal7/1/1985 Baghouse, reverse air Spray dryer typeWI Pleasant Prairie 2 Subbituminous Coal 7/1/1985 Electrostatic precipitator, cold side Spray typeTX Tolk 172B Subbituminous Coal 7/1/1985 Baghouse, reverse air N/AAZSpringerville1Subbituminous Coal6/1/1985Baghouse, reverse airSpray dryer typeALJames H MillerJr.2 Subbituminous Coal 5/1/1985 Electrostatic precipitator,cold side N/A81Attachment 11. List of coal-fired electric utility steam generating units selectedfor mercury and other non-mercury metallicHAP testingState Plant Name Boiler ID Primary Fuel Secondary FuelNOXControlPM Control 1 PM Control 2PM Control Date FGD TypeTX Oak Grove 1 Lignite CoalSCRBaghouse, pulse 12/31/2009 Spray dryer typeARPlum PointEnergySTG1 Subbituminous CoalSCRBaghouse, pulse 12/31/2009 Spray dryer typeAZ Springerville 4 Subbituminous Coal Bituminous CoalSCRBaghouse, pulse 12/31/2009 Spray dryer typeWYTwo ElkGeneratingStation1 Subbituminous CoalSCRBaghouse, pulse 12/31/2009 Spray typeAZ Cholla 3 Subbituminous CoalBaghouse, pulse 9/1/2008 Spray dryer typeAZ Cholla 4 Subbituminous CoalBaghouse, pulse 9/1/2008 Spray dryer typeTX Sandow Station 5A Lignite CoalSCRBaghouse, pulse 8/31/2009 Spray typeTX Sandow Station 5B Lignite CoalSCRBaghouse, pulse 8/31/2009 Spray typeWIElm RoadGeneratingStation1 Bituminous CoalSCRBaghouse, pulse 6/1/2009 Spray typeNE Nebraska City 2 Subbituminous CoalBaghouse, pulse 5/1/2009 Spray typeSC Cross 4 Bituminous CoalSCRElectrostatic precipitator, coldside1/1/2009 Spray typeIL Dallman 34 Bituminous CoalSCRBaghouse, pulse 1/1/2009 Packed typeNM San Juan 1 Subbituminous CoalBaghouse, pulse 12/1/2008 Spray typeNM San Juan 2 Subbituminous CoalBaghouse, pulse 12/1/2008 Spray typeNM San Juan 3 Subbituminous CoalBaghouse, pulse 12/1/2008 Spray typeNM San Juan 4 Subbituminous CoalBaghouse, pulse 12/1/2008 Spray typeNV TS Power Plant BLR100 Subbituminous CoalSCRBaghouse, pulse 6/1/2008 Spray dryer typeWI Weston 4 Bituminous Coal Subbituminous CoalSCRBaghouse, pulse 6/1/2008 Spray dryer typeILHennepinPower Station2 Subbituminous Coal Natural GasBaghouse, pulse 6/1/2008KY H. L. Spurlock 4 Bituminous CoalSNCRBaghouse, pulse 4/1/2008 CFBWY Wygen II 4 Subbituminous CoalSCRBaghouse, pulse 12/31/2007 Spray typeIA Louisa 101 Subbituminous CoalBaghouse, pulseElectrostaticprecipitator, hotside12/1/2007 Spray dryer typeIA Council Bluffs 4 Subbituminous CoalSCRBaghouse, pulse 6/1/2007 Spray dryer typeSC Cross 3 Bituminous Coal Coal-based SynfuelSCRElectrostatic precipitator, coldside1/1/2007 Spray typeAZ Springerville 3 Subbituminous CoalSCRBaghouse, pulse 12/31/2006 Spray dryer type82State Plant Name Boiler ID Primary Fuel Secondary FuelNOXControlPM Control 1 PM Control 2PM Control Date FGD TypeMTHardinGeneratorProjectPC1 Subbituminous CoalSCRBaghouse, pulse 4/1/2006 Spray dryer typeNC Asheville 1 Bituminous CoalElectrostatic precipitator, coldside11/1/2005 Spray typeIN A. B. Brown 1 Bituminous CoalSCRBaghouse, pulseElectrostaticprecipitator, coldside6/1/2005 Spray typeKY H. L. Spurlock 3 Bituminous CoalSNCRBaghouse, pulse 4/1/2005 CFBKY Cane Run 5 Bituminous Coal Coal-based SynfuelElectrostatic precipitator, coldside6/1/2004 Spray typeCO Craig C2 Subbituminous CoalBaghouse, pulse 5/1/2004 Spray typeFL Crist 7 Bituminous Coal Natural GasSCRElectrostatic precipitator, coldside4/1/2004PA Seward 1 Waste Coal Bituminous CoalSNCRBaghouse, pulse 3/1/2004 Spray dryer typePA Seward 2 Waste Coal Bituminous CoalSNCRBaghouse, pulse 3/1/2004 Spray dryer typeCO Craig C1 Subbituminous CoalBaghouse, pulse 11/1/2003 Spray typeIL Marion 123 Waste Coal Bituminous CoalBaghouse, pulse 5/1/2003 CFBKY H. L. Spurlock 1 Bituminous CoalSCRElectrostatic precipitator, coldside4/1/2003WY Wygen I 3 Subbituminous CoalSCRBaghouse, pulse 1/1/2003 Spray typePRAES PuertoRico (Aurora)1 Bituminous CoalSNCRBaghouse, pulse 12/31/2002 CFBPRAES PuertoRico (Aurora)2 Bituminous CoalSNCRBaghouse, pulse 12/31/2002 CFBSD Big Stone 1 Subbituminous CoalBaghouse, pulse 10/1/2002MDHerbert AWagner2 Bituminous CoalElectrostatic precipitator, coldside8/1/2002WATransaltaCentraliaGenerationBW21 Subbituminous CoalWet scrubberElectrostaticprecipitator, coldside6/1/2002 Spray typeMSRed HillsGeneratingFacilityAA001 Lignite CoalBaghouse, reverse air 3/1/2002 CFBMSRed HillsGeneratingFacilityAA002 Lignite CoalBaghouse, reverse air 3/1/2002 CFBWATransaltaCentraliaGenerationBW22 Subbituminous CoalWet scrubberElectrostaticprecipitator, coldside10/1/2001 Spray typeMI J. H. Campbell 1 Bituminous Coal Subbituminous CoalElectrostatic precipitator, coldside6/1/200183State Plant Name Boiler ID Primary Fuel Secondary FuelNOXControlPM Control 1 PM Control 2PM Control Date FGD TypeNEGeraldGentleman2 Subbituminous CoalBaghouse, reverse air 5/1/2001MO Hawthorn 5A Subbituminous Coal Natural GasSCRBaghouse, pulse 5/1/2001 Spray dryer typeWI Weston 3 Subbituminous CoalBaghouse, pulse 5/1/2001PA PPL Montour 1 Bituminous CoalSCRElectrostatic precipitator, coldside4/1/2001GA Hammond 1 Bituminous CoalElectrostatic precipitator, coldside1/1/2001NEGeraldGentleman1 Subbituminous CoalBaghouse, reverse air 12/1/2000PA PPL Montour 2 Bituminous CoalSCRElectrostatic precipitator, coldside6/1/2000IL Will County 4 Subbituminous CoalElectrostatic precipitator, coldside4/1/2000MDAES WarriorRunCogenerationFacilityBLR1 Bituminous CoalSCR andSNCRBaghouse, reverse air 2/1/2000 CFBPAPPL BrunnerIsland2 Bituminous CoalElectrostatic precipitator, coldside2/1/2000NE Sheldon 2 Subbituminous Coal Natural GasBaghouse, pulse 2/1/2000NE Sheldon 1 Subbituminous Coal Natural GasBaghouse, pulse 12/1/1999NC Cape Fear 5 Bituminous CoalElectrostatic precipitator, coldside11/1/1999NH Merrimack 2 Bituminous CoalSCRElectrostatic precipitator, coldside10/1/1999CO Hayden H2 Bituminous Coal Distillate Fuel OilBaghouse, reverse air 6/1/1999 Spray dryer typeSC Canadys Steam CAN3 Bituminous Coal Distillate Fuel OilBaghouse, reverse air 5/1/1999IAMuscatine Plant#18 Subbituminous Coal Natural GasElectrostatic precipitator, coldside4/1/1999INState LineEnergy3 Subbituminous CoalBaghouse, pulse 1/1/1999CO Hayden H1 Bituminous Coal Natural GasBaghouse, reverse air 12/1/1998 Spray dryer typeMIEricksonStation1 Subbituminous CoalElectrostatic precipitator, coldside11/1/1998NC Asheville 2 Bituminous CoalElectrostatic precipitator, coldside5/1/1998CO Martin Drake 5 Subbituminous Coal Natural GasBaghouse, reverse air 5/1/1998SC H. B. Robinson 1 Bituminous CoalElectrostatic precipitator, coldside5/1/1997GA Hammond 2 Bituminous CoalElectrostatic precipitator, coldside5/1/199784State Plant Name Boiler ID Primary Fuel Secondary FuelNOXControlPM Control 1 PM Control 2PM Control Date FGD TypeNC Roxboro 2 Bituminous CoalElectrostatic precipitator, coldside1/1/1997VABirchwoodPower1A Bituminous CoalSCRBaghouse, reverse air 12/1/1996 Spray dryer typeFLStanton EnergyCenter2 Bituminous CoalSCRElectrostatic precipitator, coldside6/1/1996 Spray typeVA Clover 2 Bituminous CoalBaghouse, reverse air 3/1/1996 Spray typeIL Waukegan 8 Subbituminous CoalElectrostatic precipitator, coldside1/1/1996FLIndiantownCogenerationLPAAB01 Bituminous CoalSCRBaghouse, reverse air 12/1/1995 Spray dryer typeSC Cope COP1 Bituminous Coal Natural GasBaghouse, reverse air 11/1/1995 Spray dryer typeWY Neil Simpson II 2 Subbituminous CoalElectrostatic precipitator, coldside11/1/1995 Circulating Dry ScrubberPANorthamptonGeneratingCompanyBLR1 Waste Coal Petroleum CokeSNCRBaghouse, pulse 8/1/1995 CFBWI Valley 3 Bituminous CoalBaghouse, pulse 7/1/1995WI Valley 4 Bituminous CoalBaghouse, pulse 7/1/1995NCRoanoke ValleyIIBLR2 Bituminous CoalBaghouse, pulse 6/1/1995Circulating Dry ScrubberNC Roxboro 1 Bituminous CoalSCRElectrostatic precipitator, coldside6/1/1995PAColver PowerProjectABB01 Waste CoalBaghouse, pulse 5/1/1995 CFBSC Cross 1 Bituminous Coal Coal-based SynfuelSCRElectrostatic precipitator, coldside5/1/1995 Spray typeIN Eagle Valley 6 Bituminous CoalElectrostatic precipitator, coldside2/1/1995IN Harding Street 60 Bituminous CoalSNCRMultiple cycloneElectrostaticprecipitator, coldside2/1/1995VA Clover 1 Bituminous CoalBaghouse, reverse air 1/1/1995 Spray typeWI Manitowoc 6 Bituminous CoalMultiple cyclone Baghouse, pulse 1/1/1995WI Manitowoc 7 Bituminous CoalMultiple cyclone Baghouse, pulse 1/1/1995NJLoganGeneratingPlantB01 Bituminous CoalSCRBaghouse, reverse air 9/1/1994 Spray dryer typeWI Valley 1 Bituminous CoalBaghouse, pulse 7/1/1994WI Valley 2 Bituminous CoalBaghouse, pulse 7/1/199485State Plant Name Boiler ID Primary Fuel Secondary FuelNOXControlPM Control 1 PM Control 2PM Control Date FGD TypeFL Crist 6 Bituminous Coal Natural GasElectrostatic precipitator, coldside6/1/1994IN Harding Street 70 Bituminous CoalSCRElectrostatic precipitator, coldside6/1/1994NJPSEG MercerGeneratingStation1 Bituminous Coal Natural Gas SCR andSNCRElectrostatic precipitator, coldside6/1/1994GA Hammond 4 Bituminous CoalSCRElectrostatic precipitator, coldside5/1/1994NCRoanoke ValleyIBLR1 Bituminous Coal Distillate Fuel OilBaghouse, reverse air 5/1/1994 Circulating Dry ScrubberMOJames RiverPower Station5 Subbituminous Coal Natural GasElectrostatic precipitator, coldside4/1/1994NJChambersCogenerationLPBOIL1 Bituminous CoalSCRBaghouse, reverse air 3/1/1994 Spray dryer typeNJChambersCogenerationLPBOIL2 Bituminous CoalSCRBaghouse, reverse air 3/1/1994 Spray dryer typeFLCedar BayGenerating LPCBA Bituminous CoalSNCRBaghouse, reverse air 2/1/1994 Circulating Dry ScrubberFLCedar BayGenerating LPCBB Bituminous CoalSNCRBaghouse, reverse air 2/1/1994 Circulating Dry ScrubberFLCedar BayGenerating LPCBC Bituminous CoalSNCRBaghouse, reverse air 2/1/1994 Circulating Dry ScrubberKY Elmer Smith 1 Bituminous CoalSCRElectrostatic precipitator, coldside11/1/1993 Spray typeCO Martin Drake 7 Subbituminous Coal Natural GasBaghouse, reverse air 11/1/1993IN Gibson 2 Bituminous CoalElectrostatic precipitator, coldside7/1/1993KY Elmer Smith 2 Bituminous CoalSNCRElectrostatic precipitator, coldside6/1/1993 Spray typeGA Hammond 3 Bituminous CoalElectrostatic precipitator, coldside6/1/1993PAScrubgrassGeneratingUNIT 1 Waste CoalSNCRBaghouse, pulse 6/1/1993 CFBPAScrubgrassGeneratingUNIT 2 Waste CoalSNCRBaghouse, pulse 6/1/1993 CFBSC McMeekin MCM1 Coal-based Synfuel Bituminous CoalBaghouse, reverse air 5/1/1993MO Sibley 1 Subbituminous CoalElectrostatic precipitator, coldside4/1/1993MO Sibley 3 Subbituminous CoalElectrostatic precipitator, coldside4/1/1993KY Cane Run 4 Bituminous Coal Coal-based SynfuelElectrostatic precipitator, coldside3/1/1993 Spray type86State Plant Name Boiler ID Primary Fuel Secondary FuelNOXControlPM Control 1 PM Control 2PM Control Date FGD TypeUTSunnysideCogenAssociates1 Waste CoalBaghouse, pulse 2/1/1993 CFBWV North Branch 1A Bituminous Coal Waste OilBaghouse, pulse 12/31/1992 CFBWV North Branch 1B Bituminous Coal Waste OilBaghouse, pulse 12/31/1992 CFBTX J. K. Spruce BLR1 Subbituminous CoalBaghouse, reverse air 12/1/1992 Spray typePAPiney CreekProjectBRBR1 Waste CoalSNCRBaghouse, pulse 12/1/1992Circulating Dry ScrubberVAMecklenburgPower StationBLR1 Bituminous CoalBaghouse, pulse 11/1/1992Circulating Dry ScrubberVAMecklenburgPower StationBLR2 Bituminous CoalBaghouse, pulse 11/1/1992Circulating Dry ScrubberIL Meredosia 05 Subbituminous Coal Bituminous CoalElectrostatic precipitator, coldside11/1/1992HI AES Hawaii BLRA Subbituminous Coal Tire-derived FuelsSNCRBaghouse, reverse air 8/1/1992 CFBHI AES Hawaii BLRB Subbituminous Coal Waste OilSNCRBaghouse, reverse air 8/1/1992 CFBVACogentrix ofRichmond3A Bituminous CoalBaghouse, pulse 8/1/1992 Spray dryer typeVACogentrix ofRichmond3B Bituminous CoalBaghouse, pulse 8/1/1992 Spray dryer typeVACogentrix ofRichmond4A Bituminous CoalBaghouse, pulse 8/1/1992 Spray dryer typeVACogentrix ofRichmond4B Bituminous CoalBaghouse, pulse 8/1/1992 Spray dryer typeWVGrant TownPower PlantBLR1A Waste CoalBaghouse, pulse 8/1/1992 CFBWVGrant TownPower PlantBLR1B Waste CoalBaghouse, pulse 8/1/1992 CFBPAPanther CreekEnergy FacilityBLR1 Waste CoalSNCRBaghouse, pulse 6/1/1992Circulating Dry ScrubberPAPanther CreekEnergy FacilityBLR2 Waste CoalSNCRBaghouse, pulse 6/1/1992Circulating Dry ScrubberWISouth OakCreek7 Subbituminous CoalElectrostatic precipitator, coldside6/1/1992VACogentrix ofRichmond1A Bituminous CoalBaghouse, pulse 5/1/1992 Spray dryer typeVACogentrix ofRichmond1B Bituminous CoalBaghouse, pulse 5/1/1992 Spray dryer typeVACogentrix ofRichmond2A Bituminous CoalBaghouse, pulse 5/1/1992 Spray dryer typeVACogentrix ofRichmond2B Bituminous CoalBaghouse, pulse 5/1/1992 Spray dryer typeIN Michigan City 12 Subbituminous Coal Natural GasSCRElectrostatic precipitator, coldside5/1/199287State Plant Name Boiler ID Primary Fuel Secondary FuelNOXControlPM Control 1 PM Control 2PM Control Date FGD TypeKS Quindaro 2 Subbituminous Coal Natural GasElectrostatic precipitator, coldside5/1/1992IN Gibson 1 Bituminous CoalElectrostatic precipitator, coldside1/1/1992SC McMeekin MCM2 Coal-based Synfuel Bituminous CoalBaghouse, reverse air 1/1/1992WVMorgantownEnergy FacilityCFB1 Waste CoalBaghouse, pulse 1/1/1992 CFBWVMorgantownEnergy FacilityCFB2 Waste CoalBaghouse, pulse 1/1/1992 CFBNJPSEG MercerGeneratingStation2 Bituminous Coal Natural Gas SCR andSNCRElectrostatic precipitator, coldside1/1/1992MO Sibley 2 Subbituminous CoalElectrostatic precipitator, coldside1/1/1992TXTwin OaksPower OneU2 Lignite CoalBaghouse, shake and deflate 10/1/1991 CFBVAAltavista PowerStation1 Bituminous CoalSNCRBaghouse, pulse 6/1/1991 Spray dryer typeCO Comanche 2 Subbituminous Coal Natural GasBaghouse, reverse air 6/1/1991WISouth OakCreek8 Subbituminous CoalElectrostatic precipitator, coldside6/1/1991VASouthamptonPower Station1 Bituminous CoalBaghouse, pulse 6/1/1991 Spray dryer typeOH W. H. Zimmer 1 Bituminous CoalElectrostatic precipitator, coldside6/1/1991 Spray typeMD Brandon Shores 2 Bituminous CoalSCRElectrostatic precipitator, hotside5/1/1991 Spray typePAEbensburgPower031 Waste CoalBaghouse, pulse 5/1/1991 CFBWI Manitowoc 8 Bituminous Coal Petroleum CokeSingle cyclone Baghouse, pulse 4/1/1991 CFBPA Cambria Cogen B1 Waste CoalSNCRBaghouse, shake and deflate 3/1/1991 CFBPA Cambria Cogen B2 Waste CoalSNCRBaghouse, shake and deflate 3/1/1991 CFBALJames H MillerJr.4 Subbituminous CoalSCRElectrostatic precipitator, coldside3/1/1991 Spray typeOKAES ShadyPoint1A Bituminous CoalBaghouse, pulse 1/1/1991 CFBOKAES ShadyPoint1B Bituminous CoalBaghouse, pulse 1/1/1991 CFBOKAES ShadyPoint2A Bituminous CoalBaghouse, pulse 1/1/1991 CFBOKAES ShadyPoint2B Bituminous CoalBaghouse, pulse 1/1/1991 CFBAL Colbert 4 Bituminous CoalElectrostatic precipitator, coldside1/1/199188State Plant Name Boiler ID Primary Fuel Secondary FuelNOXControlPM Control 1 PM Control 2PM Control Date FGD TypeCO Nucla 1 Bituminous CoalBaghouse, shake and deflate 1/1/1991 CFBNYTrigenSyracuseEnergy1 Bituminous CoalBaghouse, reverse air 1/1/1991 N/ANYTrigenSyracuseEnergy2 Bituminous CoalBaghouse, reverse air 1/1/1991 N/ANYTrigenSyracuseEnergy3 Bituminous CoalBaghouse, reverse air 1/1/1991 N/ANYTrigenSyracuseEnergy4 Bituminous CoalBaghouse, reverse air 1/1/1991 N/ANYTrigenSyracuseEnergy5 Bituminous CoalBaghouse, reverse air 1/1/1991 N/AKY Trimble County 1 Bituminous CoalSCRElectrostatic precipitator, coldside12/1/1990 Spray typeAL Colbert 1 Bituminous CoalElectrostatic precipitator, coldside11/1/1990CO Comanche 1 Subbituminous Coal Natural GasBaghouse, reverse air 11/1/1990NCCogentrixDwayne CollierBattle Cogen1A Bituminous CoalBaghouse, pulse 10/1/1990 Spray dryer typeNCCogentrixDwayne CollierBattle Cogen1B Bituminous CoalBaghouse, pulse 10/1/1990 Spray dryer type89Attachment 12. List of all oil-fired electric utility steam generating units selected for HCl/HF/HCN acid gas HAP, dioxin/furan organicHAP, non-dioxin/furan organic HAP, and mercuryand other non-mercurymetallic HAP testingState Plant Name Boiler ID NOXControl PM Control 1 PM Control 2PR Aguirre 3PR Aguirre 4PR Aguirre 9PR Aguirre 10FL Anclote 1FL Anclote 2PR Arecibo 1NY Astoria Generating Station 40NJ B L England 3 Multiple cyclone Electrostatic precipitator, cold sideDC Benning 16MA Brayton Point 4 Electrostatic precipitator, cold sideCT Bridgeport Station BHB2 Electrostatic precipitator, cold sideFL C. D. McIntosh Jr 2 Electrostatic precipitator, cold sideGU Cabras 2FL Turkey Point PTP1 Multiple cycloneFL Turkey Point PTP2 Multiple cyclonePR Central Palo Seco 2PR Central Palo Seco 3PR Central Palo Seco 4PR Central Palo Seco 5PR Central Palo Seco 6PR Central Palo Seco 7PR Central Palo Seco 8MA Cleary Flood 8PR Costa Sur 1PR Costa Sur 2PR Costa Sur 6PR Costa Sur 7PR Costa Sur 890State Plant Name Boiler ID NOXControl PM Control 1 PM Control 2PR Costa Sur 9PR Costa Sur 10CT Devon Station 8 Electrostatic precipitator, cold sideIN Eagle Valley 1 Multiple cyclone Electrostatic precipitator, cold sideIN Eagle Valley 2 Multiple cyclone Electrostatic precipitator, cold sideNY East River 6PA Eddystone Generating Station 4 Multiple cyclone Electrostatic precipitator, cold sideDE Edge Moor 5 Multiple cyclone Electrostatic precipitator, cold sideIN Harding Street 9 Multiple cyclone Electrostatic precipitator, cold sideIN Harding Street 10 Multiple cyclone Electrostatic precipitator, cold sideIL Havana 2 Electrostatic precipitator, hot sideIL Havana 4 Electrostatic precipitator, hot sideIL Havana 5 Electrostatic precipitator, hot sideIL Havana 6 Electrostatic precipitator, hot sideIL Havana 7 Electrostatic precipitator, hot sideIL Havana 8 Electrostatic precipitator, hot sideHI Honolulu 16FL Indian River 1FL Indian River 2FL Indian River 3SC Jefferies 2 Electrostaticprecipitator, cold sideHI Kahe 3HI Kahe 4FL Manatee PMT1 Multiple cycloneFL Manatee PMT2 Multiple cycloneFL Martin PMR1 Multiple cycloneDE McKee Run 3 Multiple cycloneGA McManus 2LA Michoud 3MD Mirant Chalk Point 3 Electrostatic precipitator, cold sidePA Mitchell Power Station 1 Electrostatic precipitator, cold side91State Plant Name Boiler ID NOXControl PM Control 1 PM Control 2PA Mitchell Power Station 2 Electrostatic precipitator, cold sidePA Mitchell Power Station 3 Electrostatic precipitator, cold sideCT Montville Station 5 Electrostatic precipitator, cold sideCT Montville Station 6 Electrostatic precipitator, cold sideMA Mystic Generating Station 7 Electrostatic precipitator, cold sideNH Newington 1 Electrostatic precipitator, hot sideNY Northport 2 Electrostatic precipitator, cold sideNY Northport 4 Electrostatic precipitator, cold sideFL Northside Generating Station 3 Baghouse, pulseNY Oswego Harbor Power 5 Electrostatic precipitator, cold sideFL Port Everglades PPE3 Multiple cycloneFL Port Everglades PPE4 Multiple cycloneNY Port Jefferson 4 Electrostatic precipitator, cold sideVA Possum Point 5 Multiple cyclone Electrostatic precipitator, cold sidePA PPL Martins Creek 3PA PPL Martins Creek 4NJ PSEG Sewaren Generating Station 2NJ PSEG Sewaren Generating Station 4VI Randolph E. Harley 1NY Ravenswood Generating Station 1 Electrostatic precipitator, cold sideNY Ravenswood Generating Station 2 Electrostatic precipitator, cold sideVI Richmond 1FL Martin PMR2 Multiple cycloneNY Roseton Generating Station 2 Multiple cyclonePR San Juan Plant 1PR San Juan Plant 2PR San Juan Plant 4PA Schuylkill Generating Station 1 Multiple cycloneFL Suwannee River 2FL Suwannee River 3MD Vienna Operations 8 Multiple cyclone92State Plant Name Boiler ID NOXControl PM Control 1 PM Control 2HI Waiau 3HI Waiau 4HI Waiau 5HI Waiau 6HI Waiau 7HI Waiau 8MA West Springfield 3 Electrostatic precipitator, cold sideME William F Wyman 1 Multiple cyclone Electrostatic precipitator, cold sideME William F Wyman 2 Multiple cyclone Electrostatic precipitator, cold side93Attachment 13. List of 50 additional coal-fired electric utilitysteam generating units not chosen in Attachments 8 through 11selected forHCl/HF/HCN acid gas HAP, non dioxin/furan organic HAP,and mercury and other non-mercury metallic HAP testingState Plant Name Boiler ID Primary Fuel Secondary Fuel NOXControl PM Control 1 PMControl 2 FGD Control ACIWV Albright 1 Bituminous CoalElectrostatic precipitator, cold sideWV Albright 3 Bituminous CoalElectrostatic precipitator, cold sideCT Bridgeport Station BHB3 Subbituminous Coal Residual Fuel OilElectrostatic precipitator, cold side YOH Cardinal 3 Bituminous CoalSCRElectrostatic precipitator, hot sideVA Clinch River 3 Bituminous CoalElectrostatic precipitator, cold sideAL Colbert 3 Bituminous CoalElectrostatic precipitator, cold sideMT Colstrip 3 Subbituminous CoalWet scrubber Venturi typeOH Conesville 3 Bituminous CoalElectrostatic precipitator, cold sideFL Crystal River 1 Bituminous CoalElectrostatic precipitator, cold sideKY Dale 3 Bituminous CoalElectrostatic precipitator, cold sideNYDunkirk GeneratingStation1 Bituminous Coal Subbituminous CoalElectrostatic precipitator, hot sideNYDunkirk GeneratingStation4 Bituminous Coal Subbituminous CoalElectrostatic precipitator, hot sidePAEddystone GeneratingStation2 Bituminous CoalSNCRMultiple cycloneElectrostaticprecipitator, cold sideSpray typePA Elrama Power Plant 2 Bituminous CoalSNCRMultiple cycloneElectrostaticprecipitator, cold sideVenturi typeNC G. G. Allen 3 Bituminous CoalElectrostatic precipitator, cold sideTN Gallatin 2 Subbituminous CoalElectrostatic precipitator, cold side94State Plant Name Boiler ID Primary Fuel Secondary Fuel NOXControl PM Control 1 PMControl 2 FGD Control ACIPAHatfields Ferry PowerStation3 Bituminous CoalElectrostatic precipitator, cold sideIL Havana 9 Subbituminous CoalSCRElectrostatic precipitator, hot side Baghouse, pulse YMN Hoot Lake 2 Subbituminous CoalElectrostatic precipitator, cold sideTX J. T. Deely 1 Subbituminous CoalElectrostatic precipitator, cold sideMOJames River PowerStation4 Subbituminous Coal Natural GasElectrostatic precipitator, cold sideIL Joliet 9 5 Subbituminous CoalElectrostatic precipitator, cold sideKS La Cygne 2 Subbituminous CoalElectrostatic precipitator, cold sideKS Lawrence Energy Center 3 Subbituminous Coal Natural GasElectrostatic precipitator, cold sideTX Monticello 1 Lignite Coal Subbituminous CoalElectrostatic precipitator, cold sideBaghouse, shake anddeflateIL Newton 2 Subbituminous CoalElectrostatic precipitator, cold sidePA PPL Martins Creek 2 Bituminous CoalElectrostatic precipitator, cold sideWI Pulliam 8 Subbituminous CoalElectrostatic precipitator, cold sideKY R D Green G2 Bituminous CoalElectrostatic precipitator,cold side Spray typeIN R M Schahfer 14 Bituminous Coal Subbituminous CoalElectrostatic precipitator, cold sideLA R. S. Nelson 6 Subbituminous CoalElectrostatic precipitator, hot sideCO Rawhide 101 Subbituminous CoalBaghouse, reverse airSpray dryertypeNV Reid Gardner 1 Bituminous Coal Lignite CoalMultiple cyclone Spray typeOH Richard Gorsuch 3 Bituminous Coal Natural GasElectrostatic precipitator, cold side95State Plant Name Boiler ID Primary Fuel Secondary Fuel NOXControl PM Control 1 PMControl 2 FGD Control ACINC Riverbend 7 Bituminous CoalElectrostatic precipitator, hot sideNH Schiller 5 Bituminous Coal Residual Fuel OilSNCRElectrostatic precipitator, cold sideFL Scholz 2 Bituminous CoalElectrostatic precipitator, cold sidePA Shawville 2 Bituminous CoalElectrostatic precipitator, cold sideMN Silver Bay Power BLR1 Subbituminous Coal Natural GasBaghouse, reverse airMO Sioux 2 Subbituminous Coal Tire-derived FuelsElectrostatic precipitator, cold sideIN Tanners Creek U4 Subbituminous CoalElectrostatic precipitator, cold sideSC Urquhart URQ3 Bituminous Coal Natural GasElectrostatic precipitator, cold sideIL Vermilion 1 Subbituminous Coal Natural GasElectrostatic precipitator, cold side Baghouse, pulse YOH W H Sammis 3 Bituminous Coal Subbituminous CoalBaghouse, reverse airOH W H Sammis 4 Bituminous Coal Subbituminous CoalBaghouse, reverse airNC W. H. Weatherspoon 1 Bituminous CoalElectrostatic precipitator, cold sideIN Wabash River 2 Bituminous CoalElectrostatic precipitator, cold sideTX Welsh 1 Subbituminous CoalElectrostatic precipitator, hot sideNE Whelan Energy Center 1 Subbituminous CoalElectrostatic precipitator, cold sidePAWPS Energy ServsSunbury Gen4 Bituminous Coal Distillate Fuel OilElectrostatic precipitator, cold sideElectrostaticprecipitator, cold side