## 1

INFORMATION COLLECTION REQUEST FOR NATIONAL EMIS S ION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAP) FOR COAL - AND OIL -FIRED ELECTRIC UTILITY STEAM GENERATING UNITS Part B of the Supporting Statement 1. Respondent Universe In 2005, the number of coal

- and oil

- fired electric utility steam generating units (EGUs) at facilities owned and operated b y publicly- owned utility companies, Federal power agencies, rural electric cooperatives, and investor

- owned utility generating companies included approximately 1 , 3 32 units (boilers) that generated greater than 25 megawatts

- electric (MWe), according to the U.S. Department of Energy /Energy Information Administration (DOE/EIA) Form EIA

- 767 database. 1 

## Currently, this database contains the most recent data available from DOE for coal

- and oil

- fired electric utility steam generating units but DOE/EIA states that (as of the writing of this supporting statement) the 2007 database is soon to be made publically available. The 2006 EIA

- 860 database covers some of the same units covered b y EIA

- 767; however, this database also includes units owned and operated b y non-utilities (including independent power producers and combined heat and power producers). EPA will query this database to determine if it includes any coal

- or oil

- fired EGUs that meet the CAA section 112(a)(8) definition of an EGU. Additionally, EPA/OAR/Office of Air Quality Planning and Standards will coordinate with EPA/OAR/Clean Air Markets Division (to obtain an industry configuration database output from their e lectric utility sulfur dioxide (SO 2 

## ) cap

- and trade program) for help with the development of the final list of EGUs in this survey data collection effort. As facilities respond to Part Iof the ICR data request, the Agency will modify

this base list of units to represent all affected sources under this effort. 2. Selection of Units to Provide Source Information All coal

- and oil

- fired EGUs identified by EPA as being potentially applicable sources under the definition in CAA section 112(a)(8) as well as all integrated gasification combined cycle (IGCC) EGUs and all EGUs fired by petroleum coke will be required to provide

1 

### Note that units have been identified to the best of the Agency’s ability for the purpose of this ICR action only. Identification of any unit for receipt of the CAA section 114 letter requiring information be submitted or testing be conducted does not constitute a final Agency applicability determination related to the rule under development. Similarly, units not receiving a CAA section 114 letter may ultimately be determined to be subject to the final rule. Specific applicability definitions will be developed during the rulemaking process and will be subject to notice and comment.

## 2

information on the current operational status of the unit, including applicable controls installed, along with emissions information. The coal

- fired EGUs identified for this effort are shown in Attachment 4; the oil

- fired EGUs identified are shown in Attachment 5; the IGCC EGUs identified are shown in Attachment 6; and the petroleum coke

- fired EGUs identified are shown in Attachment 7. 3. Selection of Units to Conduct Stack Testing Coal

- fired units to be tested will be selected to cover four groups of hazardous air pollutants (HAP) that may potentially be regulated through the use of surrogate pollutant standards . At this time, we have made no final decision on the use of surrogate pollutants and any surrogate
-based standard will be established only if consistent with the requirements of the CAA and applicable case law. The groups of HAP are acid

- gas HAP (e.g., hydrogen chloride (HCl), hydro gen fluoride (HF)), dioxin/furan organic HAP, non

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

-mercury

metallic HAP. Rationale for the selection of units for each possible surrogate group is discussed below. In the following stack testing, each facility is required to test after the last control device or at the stack if the last control device is not shared with one or more other units. In this way, the facility would test before any “ dilution” by gases from a separately- controlled unit. Under c ertain circumstances, however, testing after a common control device or at the common stack will be allowed. EPA has selected for testing the sources that the Agency believes, based on a variety of factors and information currently available to the Agency, are the best performing sources for the HAP groups for which they will be required to test. Intargeting the best performing sources, EPA is proposing to require testing for approximately 15 percent of all coal

- fired EGUs for 3 of the HAP groups

– metal HAP and PM; non

- dioxin/furan organic HAP, total hydrocarbon, CO, and VOC; and acid gas HAP and SO 2 

## – instead of only 12 percent of all sources. We will, of course, be obtaining emissions information from all sources in Parts I and II of the questionnaire. We are reasonably targeting the best performing coal

- fired sources because the statute requires the Agency

to set the MACT floor at the “ average emission limitation achieved by the best performing 12 percent of the existing sources, (for which the Admini strator 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 units, the bases for any surrogacy

argument(s) are less well developed and will require more extensive testing (EPA is proposing to require 100 of the oil

- fired units to test)

. Coal

- fired units, acid gas HAP The acid

- gas HAP, HCl and HF, are water

- soluble compounds and are more soluble in water than is SO 2 

## . (Hydrogen cyanide, HCN, representing the “ cyanide compounds, ” is also water
- soluble and will be considered an “ acid

- gas HAP ” in this document.) HCl also has a large acid dissociation constant (i.e., HCl is a strong acid) and it , thus, will react easily in an acid

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

. This indicates that both HCl and HF will be more rapidly and readily removed from a flue gas stream than will SO 2 

## , even when only plain water is utilized

. Inthe slurry streams, composed of water and sorbent (e.g., lime , limestone) utilized in both wet and dry flue gas desulfurization (FGD) systems, acid gases and SO 2 

## are absorbed b y the slurry mixture and react to (usually) form solid salts

. Influidized bed combustion (FBC) s ystems, 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 aci d 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 similar reaction occurs with the neutralization of HF . These reactions demonstrate that when using a spray dryer, the HCl and HF are removed more readily

than is the SO 2 

## . Given that even more water is available in a wet

- FGD s ystem, the same condition would also hold in that situation (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 potential surrogate for emissions of the acid

- gas HAP HCl and HF. Although this approach has not been used in any C AA section 112 rules b y 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 potential surrogate for emissions 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 newest FGD controls installed. EPA believes that these units represent those units having to comply with the most recent, and, therefore, likely most stringent, emission limits for 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 selected 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. However, for units selected for testing in this group that share an FGD s ystem with another unit, testing after the FGD s ystem will be allowed. Units not currently listed may

be required to test if necessary to ensure that the approved number of units in the group actually test and provide the needed data to the Agency

. This would yield an additional 170 data sets to be added to the data set we currently have for these pollutants. Coal

- fired units, dioxin/furan organi c HAP Dioxin data were obtained in support of the 1998 Utility Report to Congress. However, approximately

one -half of those data were listed as being below the minimum detection limit for the given test. Dioxin/furan emissions from coal

- fired utility units are generally considered to be low, presumably because of the insufficient amounts of available chlorine. As a result of previous work conducted on municipal waste combustors (MWC), it has also been proposed that the formation of dioxins and furans in exhaust gases is inhibited by the presence of sulfur. 2 

## Further, it has been suggested that if the sulfur

-to
- chlorine ratio (S:Cl) is greater than 1.0, then formation of dioxins/furans is inhibited. 3 , 4 

## The vast majority of the coal analyses provided

2 

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

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

- 290. 2000. 3 

### Raghunathan, K., and B,K. Gullett

. Role of Sulfur in Reducing PCDD and PCDF Formation

. Environmental Science and Technology

. Vol. 30, No. 6:1827

- 1834

. 1996. 4 

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

- derived Fuels and Coals. Journal of Thermal Analysis . Vol. 49:1417

- 1422. 1997.

## 5

through the 1999 IC R indicated S:Cl values greater than 1.0. As a result, EPA expects that additional data gathering efforts will continue the trend of data being at or below the minimum detection limit. However, EPA believes that some additional data are nec essary upon which either to base a surrogate standard or to establish an emission limit for dioxin/furan. Therefore, 50 units have been selected at random from the entire coal

- fired EGU population to conduct emission testing for dioxins/furans (Attachment 9). In addition, as a result of previous work done on MWC units, EPA identified activated carbon as a potential control technology for dioxin/furan control. Therefore, the above data set includes some units with activated carbon injection (ACI) s ystems 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 analys es of the coal b eing utilized during the test. EPA would entertain requests to test sister units at the same facility . EPA would also entertain requests, within 3 weeks of receipt of the CAA section 114 letter, to test similar units at other facilities under the company ’ s ownership or under an organizational umbrella (e. g., trade group) as long as the substituted unit was of similar size and ty pe, utilized a similar coal, and had similar emission controls. The subject company would need EPA approval for any substitution. Units not currently

listed may

be required to test if necessary to ensure that the approved number of units in the group actually test and provide the needed data to the Agency

. This would yield an additional 50 data sets to be added to the data set we currently have for these pollutants. Coal

- fired unit s, non- dioxin/furan organic HAP Emissions of carbon monoxide (CO), volatile organic compounds (VOC), and/or total hydrocarbons (THC) have in the past been used as surrogates for the non

- dioxin/furan organic HAP based on the theory that efficient combustion leads to lower organic emissions. 5 

## However, although indications are that these emissions are low (and perhaps below the minimum detection level), there are very

few emissions data available for these compounds from coal

- fired utility boilers. EPA has i dentified the 175 newest units as being representative of the most modern, and, thus, presumed most efficient, units (Attachment 10). The 170 newest units would be selected from those identified in Attachment 10 and would be required to test for CO, VOC, and

5 

### U.S. Environmental Protection Agency. NESHAPS: Final Standards for Hazardous Air Pollutants for Hazardous Waste Combustors; Final Rule. 64 FR 52828. September 30, 1999.

## 6

THC . From these 170 units, 50 units would be required to test for pol yc yclic organic matter (POM) , NO X 

## , formaldehyde , methane, O 2 

## , and CO 2 

## , in addition to CO, VOC, and THC. All tested units would be required to test for moisture from the stack gases and HHV and proximate/ultimate analyses of the coal being utilized during the test. As units have been identified as meeting the criterion of being a “top performing” unit, substitution of units will not be permitted. Companies with units sharing an FGD or PM control system will need to contact EPA with the individual boiler ’ s specifics. Units not currently listed may be required to test if necessary to ensure that the approved number of units in the group actually test and provide the needed data to the Agency

. This would yield an additional 170 data sets with data on the potential surrogates CO, VOC, and THC as well as 50 data sets on the potential surrogate relationships. Coal

- fired units, mercury and other non-mercury metallic HAP Emissions of certain non -mercury metallic HAP (i.e., antimony (Sb), beryllium (Be), cadmium (Cd), cobalt (Co), lead (Pb), manganese (Mn), and nickel (Ni)) have been assumed to be well controlled b y particulate matter (PM) control devices. However, mercury (Hg) and other
non-mercury

metallic HAP (i.e., arsenic (As), chromium (Cr), and selenium (Se)), because of their presence in both particulate and vapor phases, have been reported, in some instances, to be not well controlled by

PM control devices. Also, it has been shown through recent stack testing that certain of these HAP (i.e., As, Cr, and Se) tend to condense on (or as ) very fine particulate matter in the emissions from coal

- fired units. There are very few recent emissions test data available showing the potential c ontrol of these metallic HAP from coal

- fired utility boilers. The capture of Hg is dependent on several factors including the chloride content of the coal, the amount of unburned carbon present in the fly ash, the flue gas temperature, and the speciation o f the Hg. Based on available data, EPA believes that ACI may be an effective control technology

for controlling Hg emissions in coal

- fired plants. However, EPA has no direct stack test results showing how effectively these ACI

- equipped plants reduce their Hg emissions. EPA has identified the 175 units with the newest PM controls installed. EPA believes that these units represent those units having to comply with the most recent, and, therefore, likely most stringent, emission limits for PM (Attachment 11 ). Even though PM may not ultimately

be an adequate surrogate for some of the non

-mercury metallic HAP, efforts by units to comply

## 7

with stringent PM limits will likely represent the top performers with regard to non

-mercury metallic HAP emissions. The units selected also include a number with ACIinstalled. As units have been identified as meeting the criterion of being a “top performing ” unit, substitution of units will not be permitted. However, units selected for testing in this group that share a PM control system with another unit, testing after the PM control system will be allowed. The 170 units with the newest PM controls installed would be selected from those identified in Attachment 11 and would be required to test after that specific PM contro l (or at the stack if the PM control device is not shared with one or more other units). Each of these 170 units would be required to test the unit listed for Sb, As, Be, Cd, Cr, Co, Pb, Mn, Hg, Ni, Se, PM (total filterable, fine [dry], fine [wet]), O 2 

## , C O 2 

## , and moisture. All units would also be required to anal yz e their coal for the metals above (including Hg), chlorine, and provide the HHV and proximate/ultimate analys es of the coal being utilized during the test. As units have been identified as meeting the criterion of being a “top performing” unit, substitution of units will not be permitted. However, units selected for testing in this group that share a PM control s ystem with another unit, testing after the PM control system will be allowed. Units not currently

listed may

be required to test if necessary to ensure that the approved number of units in the group actually test and provide the needed data to the Agency

. This would yield an additional 170 data sets to be added to the data set we currently have for these pollutants. Coal

- fired units, other To be able to assess the impact of the standards (e.g., reduction in HAP emissions over current conditions), EPA has selected at random 50 units (identified in Attachment 13) from the population of coal

- fired units not selected in any of the above groups to test for HCl, HF, HCN, 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 (NE I), Toxics Release Inventory (TRI), data gathered for the 1998 Utility

Report to Congress) are of sufficient detail or completeness to be appropriate for this purpose. Utilitie s 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, within 3 weeks of receipt of the CAA section 114 letter, to test sister units at the same facility . EPA would also entertain requests, within 3 weeks of receipt o f the CAA section 114 letter, to test similar units at other facilities under the company ’ s ownership or under an organizational umbrella (e.g., trade group) as long as the substituted unit was of similar size and type, utilized a similar coal, and had similar emission controls. The subject company would need EPA approval for any substitution. Units not currently listed may be required to test if necessary to ensure that the approved number of units in the group actually test and provide the needed data to the Agency

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

## , f ormaldehyde , 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 analyz e their coal for the metals above (including Hg), chlorine, fluorine, and sulfur content , HHV, and proximate/ultimate analys es of the coal being utilized during the test. Oil

- fired units The potential surrogacy

arguments for coal

- fired units are primarily based on compliance with recent, stringent emission limits that have generall y resulted in the use of add

- on control technologies, as in the case of the non

-mercury metallic HAP (fabric filter or electrostatic precipitator) and the acid

- gas HAP (FGD). For dioxin/furan organic HAP, the surrogacy argument may

rely on the S:Cl value of the coal. However, the data obtained in support of the 1998 Utility

Report to Congress and the 2000 Regulatory Determination do not indicate any correlation between PM control and emissions of non

-mercury metallic HAP from oil

- fired units.

## 9

Further, no oil

- fired unit has a FGD s ystem installed, eliminating the potential basis for the use of compliance with an SO 2 

## emissions limit that resulted in the installation of an FGD s ystem as a surrogate for emissions of the ac id

- gas HAP from such units. In addition, it is not known if the S:Cl value has the same relevance for oil

- fired units as it does for coal

- fired units. Thus, EPA has no basis for determining which oil

- fired units may be the “best performers

. ” Therefore, EPA is requiring that 100 units selected at random from the 180 known oil

- fired units (Attachment 12) test their stack emissions for Sb, As, Be, Cd, Cr, Co, Pb, Mn, Hg, Ni, Se, PM (total filterable, fine [dry], fine [wet]), HCl, HF, HCN, SO 2 

## , dioxins/furan s, 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 analys e s of the oil being utilized d uring the test

. EPA would entertain requests to test sister units at the same facility . EPA would also entertain requests, within 3 weeks of receipt of the CAA section 114 letter, to test similar units at other facilities under the company ’ s ownership or under an organizational umbrella (e.g., trade group) as long as the substituted unit was of similar size and ty pe, utilized a similar oil , and had similar emission controls. The subject company would need EPA approval for any substitution. Units not currently

listed may

be required to test if necessary to ensure that the approved number of units in the group actually test and provide the needed data to the Agency

. This would yield an additional 100 data sets to be added to the data set we currently have f or this category

of units. Petroleum coke

- fired units All petroleum coke

- fired units identified in Attachment 7 will be required to test for HCl, HF, HCN, 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 analyz e their petroleum coke for the metals above (including Hg), chlorine, fluorine, and sulfur content , HHV, and proximate/ultimate analyses of the petroleum coke being utilized during the test. 4. Response Rates Since the information will be requested pursuant to the authority of CAA section 114, EPA expects that all respondents requested to submit information will do so within the time allotted for the information being requested.

## 10 Attachment 1. Draft Questionnaire Content

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## 11 ELECTRIC UTILITY STEAM GENERATING UNIT HAZARDOUS AIR POLLUTANT EMISSIONS INFORMATION COLLECTION EFFORT
BURDEN STATEMENT Preliminary

estimates of the public burden associated with this information collection effort indicate a total of 125,098 hours and $ 75,972,758 . This is the estimated burden for 537 facilities to provide information on their boilers, fuel oil ty pes and/or coal rank, 1,3 32 units to provide hazardous air pollutant (HAP) emission s data and 12 months of fuel analys es, and 512 units to conduct emissions testing. Burden means the total time, effort, or financial resources expended b y persons to generate, maintain, retain, or disclose or provide information to or for a Federal Agency . This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously

applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information. An Agency may not conduct or sponsor, and a person is not required to respond to, a collection of information that is sent to ten or more persons unless it displays a currentl y valid Office of Management and Budget (OMB) control number.
GENERAL INSTRUCTIONS [NOTE: It is EPA’s intent for the final version of this questionnaire to be in electronic format. The final format will include all questions noted herein.] Please provide the information requested in the following forms. If you are unable to respond to an item as it is stated, please provide any information you believe may be related. Use additional copies of the request forms for your respons e. If you believe the disclosure of the information requested would compromise confidential business information (CBI) or a trade secret, clearly identify such information as discussed in the cover letter. Any information subsequently determined to constitute CBIor a trade secret under EPA’s CBI regulations at 40 CFR part 2, subpart B, will be protected pursuant to those regulations and, for trade secrets, under 18 U.S.C. 1905. If no claim of confidentiality

## Enclosure 1 Form A pproved 12/24/2009 OMB Control No. 2060

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## 12 accompanies the information when it is receive d by EPA, it may

be made available to the public by EPA without further notice pursuant to EPA regulations at 40 CFR 2.203. Because Clean Air Act (CAA) section 114(c) exempts emission data from claims of confidentiality, the emission data you provide will be made available to the public notwithstanding any claims of confidentiality . A definition of what the EPA considers emissions data is provided in 40 CFR 2.301(a)(2)(i). The following section is to be completed b y 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 b y all facilities meeting the section 112(a)(8) definition of an electric utility steam generating unit:

 Part II

- Fuel Analys es and Emission Data: Additional copies of certain pages may be necessary

for a complete response. A copy of Part II responses should be completed and returned to the address noted below within 90 days of receipt. The following section is to be completed b y all facilities selected for stack testing:

 Part III

– Emissions Test Data: One emissions test (consisting of three runs). A copy of the emissions test report should be completed and returned to the address noted below within 6

- 8 months of receipt. Note the discussion in Part III as to when in the 6 to 8 month period the tested facilities results must be submitted. Detailed instructions for each part follow. Questions regarding this information request should be directed to Mr. William Maxwell at (919) 541

- 5430. Return this information request and any additional information to:

U.S. Environmental Protection Agency Office of Air Quality

Planning and Standards Sector Policies and Programs Division U

. S

. EPA Mailroom (D205

- 01) Attention: Peter Tsirigotis, Director 109 T.W. Alexander Drive Research Triangle Park, NC 27711

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## 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, questi on 1) OR Plant Name (as reported on U.S. DOE/EIA Form EIA

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

________________________________ ________________________________ _______________

________________________________ ________________________________ _______________

________________________________ ________________________________ _______________ 4b. EIA Plant Code (as reported on U.S. DOE/EIA Form

- 860 (2007), schedule 2, line 1, page 37, question 2) OR Plant ID (as reported on U.S. DOE/EIA Form EIA

- 923 (2008), schedule 2, page 1, question 2):

________________________________ ____________________ 5. Complete street address of facility (phys ical location):

____________________________

________________________________ ________________________________ _______________

________________________________ ________________________________ _______________

________________________________ ________________________________ _______________ 6. Provide mailing address if different:

________________________________ ___________

________________________________ ________________________________ _______________

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## 14 7. Name and title of contact(s) able to answer te chnical 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 source is fired, indicate which rank of coal or solid fuel was utilized during the previous 12 months prior to the receipt of this IC R : 7 , 8 

## __ lignite (% _____) __ subbituminous (% _____) __ bituminous (% _____) __ anthracite (% _____) __ coal refuse (including gob, culm, and subbituminous

- derived coal refuse) (% _____) __ sy nfuel (including, but not limited to, briquettes, pellets, or extrusions which are forme d by

binding materials, or processes that recycle materials) (% _____) (please specify

the type or form of s ynfuel used ________________________________) __ petroleum coke (% _____) 13. If oil is fired, indicate which ty pe of oil was utilized during the previous 12 months prior to the receipt of this ICR : 9

6 

### “Permitted,” in this context, refers to refers to the fuels that the permit anticipates will be combusted that the facility. 7 

### If the boiler is fired by a blend of coal ranks, please specify percentage (separately, on both a mass and on a Btu basis) of each coal rank (e.g., 85% subbituminous/15% bituminous). 8 

### In reference to footnote 6 , if necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting the reason the fuel type was combusted (e.g., “the permitting agency allowed this fuel to be combusted for special testing and research purposes”).

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## 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, boiler cleaning solutions, animal wastes, etc.) is either utilized or permitted to be used, please indicate below what materials are combusted in the boiler and in what quantities (specify

whether this quantity

is on a weight percentage or heat [Btu] basis). Also indicate (yes/no) whether you are 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

________________ _______________ ______________ ___________

________________ _______________ ______________ ___________

________________ _______________ ______________ _ __________

________________ _______________ ______________ ___________

________________ _______________ ______________ ___________

________________ _______________ ______________ ___________

________________ _______________ ______________ ___________ 1 4b. If “other” was checked in questions 10 or 11 above indicating that any non- fossil fuel or other material (including, but not limited to, plastics, treated wood, rubber belting or gaskets, whole tires, tire

- derived fuel, boiler cleaning solutions, animal wastes, etc.) is either utilized or permitted to be used, were such material to be classified as “solid waste” under the Resource Conservation and Recovery Act and, thus, make the utilizing unit subject to CAA section 129, would you continue to utilize (i.e., use as a fuel) the material? __ Yes __ No Explain: ______________________________________________________________________

9 

### If the boiler is fired by a blend of fuel oil ranks, please specify percentage (separately, on both a volume and on a Btu basis) of each fuel oil rank (e.g., 85% residual oil/15% distillate). 10 

### If necessary, a notation can be added to a utilized fuel type that is not listed in the operating permit noting the reason the fuel type was combusted ( e.g., “the permitting agency allowed this fuel to be combusted for special testing and research purposes”).

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## 16 15. Identification (or designation) of all coal

- and oil

- fired steam generating units (boilers) (as defined by Clean Air Act section 112(a)(8)) located at this facility

.Boiler ID11Original design fuel (i.e.coal rank or type of oil)Designheat input,(MMBtu/hr)12Presentmaximumheatinput,(MMBtu/hr)13MWeGrosscapacitysummerMWeNet capacitysummerOriginal design grossefficiency (%, HHV)Present operating grossefficiency (%, HHV)Design steam pressure(psig)Operating steam pressure(psig)Design steam temperature(°F)Operating steamtemperature (°F)Design steamreheattemperature (°F)14Operating steam reheattemperature (°F)15Fuel16Hours/year operated17Average annual capacityfactor for the past 3yearsApplicable NSPSEstimated year ofretirement18

11 

### Boiler ID (as reported on U.S. DOE/EIA Form EIA

- 860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA

- 923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8)

. 12 

### Per fuel burned in the boiler

. Report this based on higher heating value (HHV). 13 

### Per fuel burned in the boiler

. Report this based on higher heating value (HHV). 14 

### Please indicate if more than one steam reheat cycle is utilized, and, if so, pleas e provide information for both. 15 

### Please indicate if more than one steam reheat cycle is utilized, and, if so, please provide information for both. 16 

### Indicate the fuels utilized for the indicated boiler, and percentages, as indicated in questions 11

- 1 3. 17 

### The “ hours/year operated” would be the average of the actual number of hours the unit operated in 1 year based on the last 3 years of operation. 18 

### This can be treated as CBI and can be submitted through the proper CBI procedure if desired.

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## 17 Emission Control Technology 16. For each boiler note d in Part I , question 15, provide the following information for each current emission control device installed and operating and/or planned (please designate the order of the emission controls

– 1 for first control following the boiler, 2 for second contro l following the boiler, etc.) : Boiler ID 19 

## Type 20 

## NO x 

## control 21 

## SO 2 

## control22 

## PM control 23 

## Other control 24

19 

### Boiler ID (as reported on U.S. DOE/EIA Form EIA

- 860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA

- 923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 20 

### Examples: tangential

- fired; cyclone; wall

- fired; circulating fluidized bed (CFB) 21 

### Examples: low

-NO x 

### burners ; selective catalytic reduction (SCR); selective non

- catalytic reduction (SNCR); over

- fire air (OFA). Include specific date that control went online or planned operational date for new installation. If this boiler’s control configuration utilizes a SCR, please include the type of material from which the catalyst is manufactured and the type of reductant used in with the SCR (e.g., anhydrous ammonia, aqueous ammonia, urea, other). Also, please note if the catalyst is specifically designed to reduce SO 3 

### formation? 22 

### Examples: wet flue gas desulfurization (FGD; any type); dry scrubbing (any type); specify whether calcium

- or sodium

-based. Include specific date that control went online or planned operational date for new installation. 23 

### Examples: fabric filter; cold

- side electrostatic precipitator (ESP); hot

- side ESP; cyclone or multiclone; venturi scrubber. Include specific date that control went online or planned operational date for new installation. 24 

### Please indicate systems installed specifically to control any other pollutants (e.g., Hg, SO 3 

### , etc.). Examples: activated carbon injection (ACI); Powerspan ECO ® 

### ; dry

sorbent injection or wet ESP for SO 3 

### control; flue gas conditioning to control opacity (e.g., SO 3 

### injection, ammonia, other); additive use for mercury control (e.g., bromine; scrubber additives). Include specific date that control went online or planned operational date for new installation. Also include any pollutants controlled by this other technology (e.g., control technology [pollutant controlled]).

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## 18 17. For each boiler noted in Part I , question 15, provide the company (prime vendor) name and company contact information f

or each HAP

- specific (e.g., mercury, hydrogen chloride) control technology that you have either contracted for, are installing, or have installed for the purpose of participating in a control technology demonstration project25 

## (e.g., U.S. Department of Energy program, consent decree, etc.).
Boiler ID 26 

## Company (vendor)

name Company (vendor) contact information Name Telephone Address

25 

### A control technology demonstration project is defined as a U.S. Government (e.g., U.S. Department of Energy program) sponsore d (in whole or in part) project or mandate (e.g., as a result of a consent decree) that adds a HAP control technology to a facility’s unit to demonstrate the technology’s HAP removal performance. 26 

### Boiler ID (as reported on U.S. DOE/EIA Form EIA

- 860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID ( as reported on U.S. DOE/EIA Form EIA

- 923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8).

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## 19 18. For the control technologies identified in Part I, question 17, provide the date o f actual start

-up of the demonstration (if the control is currently operating), the date of expected or projected start

-up, the date the demonstration was completed, the type of HAP control installed (e.g., sorbent and ty pe; pre - combustion boiler chemical additive; combustion boiler chemical additive), the desired HAP emission reduction or rate (if any), and the coal rank(s) in use or fuel ty pe upon which the demonstration was conducted. Please specify the format of the target HAP emission reduction or rate (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the target end

-point is percent reduction, provide (1) an estimate of what an equivalent emission rate would be (and specify the format of the equivalent emission rate), and (2) the basi s for calculating the percent reduction (i.e., where the “inlet” and “outlet” are).

Boiler ID 27 

## Demonstration

activity actual start- up date Demonstration

activity projected start- up date Demonstration

activity end- date or projected enddate Type of control

(e.g., sorbent and type; chemical additive28

## ) Desired HAP

emission reduction (%) or emission rate Coal rank(s) in

use

27 

### Boiler ID (as rep orted on U.S. DOE/EIA Form EIA

- 860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW] ) OR Generator ID (as reported on U.S. DOE/EIA Form EIA

- 923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 28 

### If additive is used, please indicate injection point.

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## 20 19. For each boiler noted in Part I , question 1 5 , provide the company (prime vendor) nam e and company contact information for each HAP (e.g., mercury, hydrogen chloride , etc. ) control technology that you have either contracted for, are installing, or have installed for the purpose of providing a non

- demonstration, full

- scale operating s ystem. Boiler ID 29 

## Company (vendor)

name Company (vendor) contact information Name Telephone Address

29 

### Boiler ID (as reported on U.S. DOE/EIA Form EIA

- 860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA

- 923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8).

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## 21 20. For the control technologies identified in Part I, question 1 9 , provide the date of actual start

-up (if the control is currently operating), the date of expected or projected start

-up, the ty pe of HAP control installed (e.g., sorbent and ty pe; pre - combustion boiler chemical additive; combustion boiler chemical additive), the guaranteed HAP emission reduction or emission rate, the sorbent feed rate upon which the guarantee is based, and the coal rank(s) or fuel type upon which the guarantee is based. Please specify the format of the guarantee (e.g., lb/MWh, lb/TBtu, percent reduction, etc.). If the format of the guarantee is percent reduction, provide (1) an estimate of what an equivalent emission rate would be (and specify the format of the equivalent emission rate), and (2) the b asis for calculating the percent reduction (i.e., where the “inlet” and “outlet” are)

.

Boiler ID 30 

## Actual start- up

date Expected or

projected start- up date Type of control

(e.g., sorbent and type; chemical additive) 31 

## Guaranteed HAP

emission reduction (%) or emission rate Sorbent or

additive feed rate on which guarantee is based Coal rank(s) upon

which guarantee is based

30 

### Boiler ID (as reported on U.S. DOE/EIA Form EIA

- 860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as rep orted on U.S. DOE/EIA Form EIA

- 923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 31 

### If additive is used, p lease indicate injection point.

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

Boiler ID 32 

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

PM 33 

## PM 10 (34 ) 

## PM2.5 (35 ) 

## SO 2 

## HCl and/or HF HCN Metal

HAP 36 

## Hg CO Other organics (specify) Other

pollutant (specify)

32 

### Boiler ID (as reported on U.S. DOE/EIA Form EIA

- 860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA

- 923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 33 

### If the boiler has separate permitted emission limits for filterable and condensable PM, respectively, please include those separate limits. Also include the compliance test method utilized. 34 

### List the compliance test method utilized. 35 

### List the compliance test method utilized. 36 

### Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for all metal HAP for which a permit limit is in place

.

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

Boiler ID 37 

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

PM 38 

## PM 10 

## PM2.5 

## SO 2 

## HCl and/or HF HCN Metal

HAP 39 

## Hg CO Other organics (specify) O ther

pollutant (specify)

23. Was any

other guarantee level sought or offered? Yes _____ No _____ Please elaborate.

________________________

________________________ ___________________________________________________________________________________

___________________________________________________________________________________________________________

37 

### Boiler ID (as reported on U.S. DOE/EIA Form EIA

- 860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA

- 923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 38 

### If the boiler has separate guaranteed emission rate for filterable and condensable PM, respectively, please include those sep arate emission rates. 39 

### Metal HAP include compounds of antimony, arsenic, b eryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for all metal HAP for which a permit limit is in place

.

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## 24 24. For each boiler noted in Part I , question 15, provide the f ollowing information:

Boiler ID 40 

## Required monitoring, recordkeeping, and reporting requirements for each pollutant for which there is a permitted emission limit PM 41 

## PM 10 

## PM2.5 

## SO 2 

## HCl and/or HF HCN Metal

HAP 42 

## Hg CO Other organics (specify)

40 

### Boiler ID (as reported on U.S. DOE/EIA Form EIA

- 860 (2007), “Annual Electric Generator Report,” sche dule 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 Op erations Report,” schedule 5, part A, page 8). 41 

### If the boiler’s monitoring, recordkeeping, and reporting requirements require your company to monitoring, keep records, and report filterable and condensable PM separately, please describe the separate acti ons required. 42 

### Metal HAP include compounds of antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel and selenium; indicate permit level for all metal HAP for which a permit limit is in place

.

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## 25 25. For the control technologies identified in Part I, questions 17 and 19, provide the cost information requested. 43 

## Facility Name / Unit No. : _________ Retrofit to existing boiler? ____ Installation on new boiler? ____ Total Capital Investment: $: ______________ Total Annual Operating and Maintenance Costs: $ :

______________ (Include b ase ye ar for operating costs [e.g., 2006])

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

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

.

________________________________________________________________ _ _________________________________________

______________________________________________________________________________ ____________________________

______________________________________________________________________________ ____________________________

______________________________________________________________________________ ____________________________

43 

### This can be treated as CBI and can be submitted through the proper CBI procedure if desired.

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## 26 PART II: FUEL ANALYSI S AND EMI SSION DATA Fuel Analys is 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.

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## 27 2. For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information, as available (indicate N/A if not available; use additional pages, as necessary): Am ount received, dry basis, short tons 45 

## ID # of

boiler(s) firing fuel46 

## Fuel source Fuel shipment method State/Country County47 

## Co al seam 48

45 

### EPA recognizes that facilities have (sometimes) several months inventory and that the amount received is not necessarily the same as the amount fired. 46 

### Boiler ID (as reported on U.S. DOE/EIA Form EIA

- 860 (2007), “Annual Electric Generator Report,” schedule 6, part A, line 1, page 53, [for plants equal to or greater than 10 MW but less than 100 MW] or on schedule 6, part B, line 1, page 54, [for plants greater than 100 MW]) OR Generator ID (as reported on U.S. DOE/EIA Form EIA

- 923 (2008), “Power Plant Operations Report,” schedule 5, part A, page 8). 47 

### If known. 48 

### If known.

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## 28 3. For each individual coal and oil shipment received during the preceding 12 calendar months, provide the following information49 

## , as available (dry basis) (indicate N/A if not available) :

Sample ID # Total

amount of fuel represented by sample, tons or gallons Total

sulfur, % Ash

content, % Higher

h eating value, Btu/lb Mercury,

ppm Chlorine,

ppm Fluorine,

ppm Nickel,

ppm Other

trace metal HAP, ppm 50

49 

### To the extent that a vendor provides these data or that a facility is required by State or local agency to analyze its fuel for HAP constituents (e.g., Cl, F), and any metallic HAP (e.g., Hg, Pb, As, Se, etc.), EPA wishes the responding facility to provide tho se fuel analyses results. Otherwise, this 12

- mo nth fuel analysis requirement can be bypassed by the respondent. 50 

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

.

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## 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 analys es required in Part II, question 3 above, for samples for which analys es of chlorine and/or any of the HAP metals were conducted, please provide copies of any analys es conducted over the preceding 12 calendar months for (a) complete proximate and ultimate analyses, (b) additional trace metals, and (c) the mineralogy of the ash that are readily available for the oil(s) or coal(s) listed in Part II, question 2 above. The Agency is requesting these data only as they may already be available; no additional sampling or analys es are required to provide these data.

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## 30 Emission Data 8a. What emission test report( s), parametric monitoring data, and other data or monitoring are available for the boilers noted in Part I, question 15, for tests conducted since January 1, 200 5. Please consider reports prepared for all testing and monitoring programs, for all pollutant s, including (but not limited to) those required under Title V, compliance with State or local requirements, fulfillment of contractual obligations, U.S. Department of Energy (DOE) programs, etc. (NOTE: EPA is not requesting copies of the test reports or data at this time; however we may

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

.

______________________________________________________________________________

___________________________________________________________________ ___________

______________________________________________________________________________

______________________________________________________________________________ 8b. Please indicate the date(s) and ty pes (e.g., stack, fuel, parametric, etc.) of the test(s) and the constituents (including criteria and hazardous air pollutants) sampled for. Date: _____ Ty

pe: _____ Constituents: ____________________________________ Date: _____ Ty

pe: _____ Constituents: ____________________________________ Date: _____ Ty

pe: _____ Constituents: ____________________________________ Date: _____ Ty

pe: _____ Constituents: ____________________________________ Date: _____ Ty

pe: _____ Constituents: ____________________________________ Date: _____ Ty

pe : _____ Constituents: ____________________________________ Date: _____ Ty

pe: _____ Constituents: ____________________________________ Date: _____ Ty

pe: _____ Constituents: ____________________________________ Date: _____ Ty

pe: _____ Constituents: ____________________________________ 8c. Do any of these test reports reflect testing at a location upstream of any emission control devices? Yes _____ No _____ If yes, please note which reports and provide a detailed description of the l ocation of the emissions sampling point(s). ____________________________________

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## 31 8d. Were any of these test reports conducted when use of other material(s) or non

- fossil fuels were fired in the boiler? Yes _____ No _____ If yes, please note which reports and identify the other material(s) or non

- fossil fuels used. _________________________________

______________________________________________________________________________

_____________________________________________________________________ _________ 8e. Do any of these test reports reflect testing during periods of startup, shutdown, and malfunction? Yes _____ No _____ If yes, please note which reports. ________________

____________________________________________________________ __________________

______________________________________________________________________________ 8f. Did the unit’s control configuration differ from that shown in Part I, question 1 6 , at the time of these test results? Yes _____ No _____ If ye s, please list the unit’s complete control configuration at time of testing in a similar format to Part I, question 1 6 . _____________

______________________________________________________________________________

__________________________________________ ____________________________________ 8g. Do any of these test reports reflect testing at a location upstream of a post combustion SO 2 

## emission control device (e.g., FGD, SDA, Dry Scrubber)? Yes _____ No _____ If ye s, 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, b ypass of unscrubbed flue gas was utilized at the time of testing (including percentage of total scrubber exhaust gas flow). Note by diagram where sampling ports were located in relation to the by pass ductwork.

________________________________ ________________________________ ______

________________________________ ________________________________ _______________ 9. What ty

pe of deviation reporting is required for violations of permit requirements?

_________________________________________________________________ _____________

______________________________________________________________________________ 10. Are deviation reports available for malfunctions or other periods of noncompliance with permit terms and conditions? Yes _____ No _____ If yes, please note which reports.

______________________________________________________________________________

______________________________________________________________________________

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

monitoring s ystems ) that are not already being provided to the U.S. EPA or permit authority, even if from short

-term testing? Yes _____ No _____ If yes 51 

## , please note for which pollutants CEM S data are available and the period of time (both total period and calendar period) for which data are available. If CEMS data are being provided to EPA, please note to which Office the data are being provided.

_____________________________________

______________________________ _______________________________________________ 12. For each boiler noted in Part I , question 15, provide the following information:
Boiler ID Emissions test results (indicate format of emission data) 52 , 53 

## Date of test PM 54 

## SO 2 

## HCl/HF/HCN Metal HAP 55 

## Hg 56 

## CO Other organics (specify)

51 

### Where unit s are monitored by CEM S (either following CAMR, State, or NIST QA/QC procedures), and w here data are available, EPA requests that these CEM S data b e submitted by the respondent. The respondent should also mark the periods of start up, shut down and malfunction events (SSM) in the data sets. 52 

### Provide emission test data for all tests conducted since January 1, 2005. Please include test data acquired both before and after any control device. Use additional pages as necessary. EPA may, at some future date , request a copy of one or more emission test reports. Data generated to fulfill both Federal and State requirements must be provided. Note that data generated pursuant to CAA Title V must be maintained and available for 5 years. Also include averaging times and measurement units for all pollutants. 53 

### For each emissions test run the respondent should provide the following process information: Unit Load (MW), Net generation during run (MWh net), Flue gas moisture content (%), Flue gas flow rate (dscfm or Nm3 

### /hr), Flue gas oxygen content (%, dry), Flue gas carbon dioxide content (%, dry), Flue gas temperature at sampling point (°F), Flue gas pressure at sampling point (atm), Standard temperature (°F), Standard pressure (atm). 54 

### If emission testing recorded the emissions of filterable and condensable PM, separately, please include those separate emission results. Also, please include separate emission results for total PM, 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 availabl e. If the emissions testing recorded the amount of unburned carbon in fly ash (as reflected by the “Loss o n Ignition” [L.O.I.]) at the time of any Hg testing, please include these data.

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## 33 PART III: EM IS SION S TESTI NG For units identified in Part B of the Supporting Statement, testing is to be performed for the identified HAP on a one

-time basis after the last control device (i.e., after the last control device or at the stack if the last control device is not shared with one or more other units). Facilities are to use the test procedures noted in Enclosure 1 (“Summary of Coal

- and Oil

- fired Electric Utility

Steam Generating Unit Test Procedures, Methods, and Reporting Requirements”) for both the stack and fuel sampling. Each test is to consist of at least three separate runs for each pollutant at the sampling location. Companies with multiple units identi fied on the Attachments to Part B of the Supporting Statement will be required to notify EPA within 3 weeks of receipt of the CAA section 114 letter which units representing 60 percent of their required data will be submitted within 6 months of receipt of the letter and which units representing an additional 20 percent of their required data (i.e., a total of 80 percent of their required data) will be submitted within 7 months of receipt of the letter. Companies will also be notified of this requirement in the cover letter specifying the test requirements.

## Enclosure 1 Form A pproved 12/24/2009 OMB Control No. 20 60

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## 34 

# Summary of Coal- and Oil- fired Electric Utility Steam Generating Unit Test Procedures, Methods, and Reporting Requirements This document provides an overview of approved methods, target pollutant units of measure, and reporting requirements for the coal

- and oil

- fired electric utility steam generating unit test plan. The document is organized as follows: 1.0 Stack Testing Procedures and Methods 2.0 Fuel Analysis Procedures and Methods 3 .0 How to Report Data 4 .0 How to Submit Data 5 .0 Definitions 6 .0 Contact Information for Questions on Test Plan and Reporting 

# 1.0 Stack Testing Procedures and Methods The EPA coal

- and oil

- fired electric utility steam generating unit test program includes stack test data requests for several pollutants, including specific hazardous air pollutants (HAP) and potential surrogate groups. If you operate a coal

- or oil

- fired electric utility steam generating unit, you were selected to perform a stack test for some combination of the following pollutants or potential surrogate groups (i.e., simultaneous or overlapping measurements per group) :

 Non

- dioxin/furan organic HAP: Carbon monoxide (CO), total hydrocarbons (THC), methane (CH4 

## ) , formaldehyde, oxygen (O 2 

## ), carbon dioxide (CO 2 

## ), volatile and semi

volatile 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: mercury

(Hg), non- Hg HAP metals (including antimony (Sb), arsenic (As), beryllium (Be), cadmium (Cd), chromium (Cr), cobalt (Co), lead (Pb), manganese (Mn), nickel (Ni), and selenium (Se)), particulate matter (PM2.5 

## (filterable and condensable); total solids; 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 perform emission tests . You may have submitted test data for some of these p ollutants already. 1.1 How to Select Sample Location and Gas Composition Analysis Methods U.S. EPA Method 1 of Appendix A of Part 60 must be used to select the locations and number of traverse points for sampling. See http://www.epa.gov/ttn/emc/methods/method1.html for a cop y of the method and guidance information.

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## 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 Steam Generating Unit Test Methods and Reporting Table 1.2 presents a summary of the recommended test methods for each pollutant and possible alternative methods. If you would like to use a method not on this list, and the list does not meet the definition of “equivalent” provided in the definitions section of this document, please contact EPA for approval of an alternative method. For copies of the recommended U.S. EPA methods and additional information, please refer to EPA’s Emission Measurement Center website: http://www.epa.gov/ttn/emc/. For copies of the US EPA’s SW

- 846 sampling and analys is methods (such as EPA Method 00 10 and EPA Method 8270D), please refer to EPA’s SW

- 846 Online website, which is available at the following internet address: <http://www.epa.gov/waste/hazard/testmethods/sw8 46/online/index.htm>. Report pollutant emission data as specified in Table s 1.2 a through 1.2d below. Each test should be comprised of at least three valid test runs. All pollutant concentrations should be corrected to 7 percent oxygen (or as otherwise directed by a specific method) and should be reported on the same moisture basis (dry). Report the results of the stack tests according to the instructions in Section 3 .0 of this enclosure. During a 30 day period that includes emissions testing and fuel analys is reporting, you should collect the following process information: Total heat input; feed rate; steam output; gross electric output; net electric output; emissions control devices in use during the test; control device operating or monitoring parameters (including, as appropriate to the control device, flue gas flow rate, pressure drop, scrubber liquor pH, scrubber liquor flow rate, sorbent type and sorbent injection rate), and process parameters (such as oxygen). In addition to the emission test data, you should report the above process information as daily averages. The owner/operator of the EGU must certify that the fuel that was fired during testing is representative of the fuel that is burned routinely at the EGU. The owner/operator of the EGU must also certify

that it operated all of the pollution control equipment in accordance with manufacturers’ specifications and requirements for proper operation during the emissions testing. Finally, the owner/operator of the EGU must certify that it operated its pollution control equipment to optimize reduction of the pollutants for which the equipment is designed.

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

and Alternative Methods for Non - dioxin / fu ran 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 25 A . Use a

minimum sampling time of 2 hours per run. Calibrate the measuring instrument with a mixture of the organic compounds being emitted or with propane , and report as propane

. None lb/MMBtu and ppmvd @ 7% O2

CH4 

### U.S. EPA Method 18. Use a

minimum s ample 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 SW

846 Method 8260B. Collect a minimum of 4 sets of sorbent traps for analysis per each 2 hour run. Each set of sorbent traps should be run for 20 minutes at an approximate flow

rate of one liter per minute. None lb/MMBtu and μg/dscm @ 7% O2

Speciated Semi

volatile Organic HAP U.S. EPA Method 0010 with

SW

- 846 Method 8270D. Collect a minimum volume of 1.7 cubic meters and have a minimum sample time of 2 hours per run. Use high resolution GCMS for the analytical finish. None lb/MMBtu and μg/dscm @ 7% O2

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 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 requirements of 40 CFR part 75

.

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## 37 Table 1.2 b : Summary of Coal- and Oil- fired Electric Utility Steam Generating Unit Test Methods and Alternative Methods for Dioxin / furan HAP Pollutant Recommended Method Alternative Method Target Reported Units of Measure D/F, PCB ** 

### U.S. EPA Method 23. Collect a

minimum volume of 8.5 cubic meters and have a minimum sample time of 8 hours per run. Use high resolution GCMS for the analytical finish. None lb/MMBtu and ng/dscm @ 7% O2

O 2

### /CO 2 *** 

### U.S. EP A 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 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 requirements of 40 CFR part 75

. 

## Table 1.2 c : Summary of Coal- and Oil- fired Electric Utility Steam Generating Unit Test Methods and Alternative Methods for Acid gas HAP Pollutant Recommended Method Alternative Method Targ et 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 sampl e. lb/MMBtu

HCN U.S. EPA Conditional Test

Method 033 (CTM

- 033) U.S. EPA Method 26A combined with the analysis procedures from CTM

033, or U.S. EPA Method 26 combined with the analysis procedures from CTM

- 033 or U.S. EPA Method 320 if there are no entraine d 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 emissi ons with other stack test emissions, a portion of the CEMS data should contain emissions data collected during performance of the other requested stack tests. The CEMS must meet the requirements of the applicable Performance Specification: CO

– Performance Specification 4; NO x 

### and SO 2 

### – Performance Specification 2 and 40 CFR part 60.13 or the CEMS accuracy and ongoing QA/QC requirements of 40 CFR part 75

.

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

and Alternative Methods for Mercury and Non- mercury metallic HAP
Pollutant Recommended Method Alternative Method Target

Reported Units of Measure Hg U.S. EPA Method 30B. Use a minimum sample time of 2 hours per run. None lb/MMBtu Metals U.S. EPA Method 29

. Collect a minimum volume of 3

. 4 cubic meters and have a minimum sample time of 4 hours per run. Determine total filterable PM emissions according to §8.3.1.1. Use ICAP/MS for the analytical finish. None lb/MMBtu

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 fro m 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 requeste d 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 requirements of 40 CF R part 75

.

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## 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 co llect at least three sample s of the fuel combusted during each metals, mercury, particulate matter, acid gas, and dioxin / furan emissions test run; composite these samples; and then analyz e and report each composited sample. Only chlorine and fluorine analys es are required during acid gas emissions testing. Should you have an oil

- fired unit that is subject to emissions testing and that is fed from just one fuel tank whose content is uniform and is sufficient to complete the emissions testing campaign, you may contact us with a request to reduce fuel sampling requirements. Your request should identify the characteristics of your site, your proposed alternative fuel sampling procedure, and anticipated impact on emissions of using your proposed approach. Refer to page 1 of the Section 114 letter you received for the specific types of fuel analyses we are requesting from your facility. Directions for collecting, compositing, preparing, and analyz ing fuel analys is data are outlined in Sections 2.1 through 2.4. 2.1 How to Collect a Fuel Sample Table 2.1 outlines a summary of how samples should be collected. Alternately, you may use the procedures in ASTM D2234

–00 (for coal) to collect the sample.

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## 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 cross

section. 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 c ollected at approximately equal intervals during the testing period.

Fuel Pile or Truck For each composite sample, select a minimum of five sampling locations uniformly spaced over the surface of the pile. At each sampling site, dig into the pile to a depth of 18 inches. Insert a clean flat square shovel into the hole and withdraw a sample, making sure that large pieces do not fall off during sampling. Transfer all samples to a clean plastic bag for further processing as specified in Sections 2.2 through 2.5 of this document. Liquid Fuels Manual Sampling Follow collection methods outlined in ASTM D 4057 Automatic Sampling Follow collection methods outlined in ASTM D4177 Fuel Supplier Analysis Fuel Supplier If you will be using fuel analysis from a fuel supplier in lieu of site specific sampling and analysis, the fuel supplier must collect the sample as specified above and prepare the sample according to methods specified in Sections 2.2 through 2.5 of this document. 

## 2.2 Create a Composite Sample for Solid Fuels Follow the seven steps listed below to composite each sample: (1) Thoroughly mix and pour the entire composite sample over a clean plastic sheet. (2) Break sample pieces larger than 3 inches into smaller sizes. (3) Make a pie shape with the entire composite sample and subdivide it into four equal parts. (4) Separate one of the quarter samples as the first subset. (5) If this subset is too large for grinding, repeat step 3 with the quarter sample and obtain a one - quarter subset from thi s 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 analys is. If the quarter sample is too large, subdivide it further using step 3.

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## 41 2.3 Prepare Sample for Analysis Use the methods listed in Table 2.2 to prepare your composite samples for analys is.

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 sam ple 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 Secti on 5 of this document, please contact EPA for approval of an alternative method.

Table 2. 3 : List of Analytical Methods for Fuel Analysis Analyte Fuel Type Method Target Reported Units of Measure



### Higher Heating Value Coal ASTM D58 65

–04, ASTM D240, ASTM E711

- 87 (1996) Btu/lb Biomass ASTM E711

– 87 (1996) or equivalent, ASTM D240, or ASTM D5865

- 04 Other Solids ASTM

- 5865

- 03a, ASTM D240, ASTM E711

- 87 (1997) Liquid ASTM

- 5865

- 03a, ASTM D240, ASTM E711

- 87 (1996) Moisture Coal, Bio ma ss, Other Solids ASTM

- D3 173

- 03, ASTM E871

- 82 (1998) or equivalent, EPA 160.3 Mod., or ASTM D2691

- 95 for coal. %

Mercury Concentration Coal ASTM D6722

- 01, EPA Method 1631E, SW

- 846

- 1631, EPA 821

- R

- 01

- 013, or equivalent

ppm Biomass SW

- 846

- 7471A, EPA Method 1631E, SW

- 846

- 1631, ASTM D6722

- 01, EPA 821

- R

- 01

- 013, or equivalent Other Solids SW

- 846

- 7471A, EPA Method 1631E, SW

- 846

- 1631, EPA 821

- R

- 01

- 013, or equivalent Liquid SW

- 846

- 7470A, EPA Method 1631E, SW

- 846

- 1631E, SW

- 846

- 1631, EPA 821

- R

- 01

- 013, or equivalent

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## 42 Analyte Fuel Type Method Target Reported Units of Measure



### Total Selected Metals Concentration Coal SW

- 846

- 6010B, ASTM D3683

- 94 (2000), SW

- 846

- 6020,

- 6020A or ASTM D6357

- 04 (for arsenic, beryllium, cadmium, chromium, lead, manganese, and nickel in coal) ASTM D4606

- 03 or SW

- 846

- 7740 (for Se) SW

- 846

- 7060 or 7060A (for As) ppm Biomass SW

- 846

- 6010B, ASTM D6357

- 04, SW

846

- 6020,

- 6020A, EPA 200.8, or ASTM E885

- 88 (1996) or equivalent, SW

- 846

- 7740 (for Se) SW

- 846

- 7060 or

- 7060A (for As) Other Solids SW

- 846

- 6010B, EPA 200.8 SW

- 846

- 7060 or 7060A for As Liquid SW

- 846

- 6020,

- 6020A, , SW

- 846

- 6010B, SW

- 846

- 7740 for Se, SW

- 846

- 7060 or

- 7060A for As
Chlorine Concentration Coal SW

- 846

- 9250 or ASTM D6721

- 01 or equivalent, SW

- 846

- 5050,

- 9056,

- 9076, or - 9250, ASTM E776

- 87 (1996) ppm Biomass, Other Solids, Liquids ASTM E776

- 87 (1996), SW

- 846

- 9250, SW

- 846

- 5050,

- 9056,

- 9076, or

- 9250 Fluorine Concentration Coal ASTM D3761

- 96(2002), D5987

- 96 (2002) 

### ppm 

## Report the results of your fuel analys is according to the directions provided in se ction 3 .0 of this enclosure.

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## 43 

# 3.0 How to Report Data The method for reporting the results of any testing and monitoring requests depend on the type of tests and the ty

pe of methods used to complete the test requirements. This section discusses the requirements for reporting the data. 3.1 Reporting stack test data If you conducted a stack test using one of the methods listed in Table 3 .1, shown below, you must report your data using the EPA Electronic Reporting Tool (ERT) Version 3. ERT is a Microsoft® 

## Access database application. Two versions of the ERT application are available. If you are not a registered owner of Microsoft® 

## Access, you can install the runtime version of the ERT Application. Both versions of the ERT are available at http://www.epa.gov/ttn/chief/ert/ert_tool.html . The ERT supports an Excel spreadsheet application (which is included in the files downloaded with the ERT) to document the collection of the field sampling data. After completing the ERT, you will also need to attach an electronic copy of the emission test report (PDF format preferred) to the Attachments module of the ERT.

Table 3 .1: List of Test Methods Supported by ERT

Test Methods Supported by ERT Methods 1 through 4 Method 7E Method 6C Method 5 Method 3A Method 29 Method 26A Method 25A Method 23 Method 202 Method 201A Method 17 Method 101A Method 101 Method 10 CT Method 40 CT Method 39 OTM 27 OTM 28 

## If you conducted a stack test using a method not currently supported b y 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 ty pe of unit and they

can be downloaded from the Electric Utility MACT ICR 2009 website (http://utility macticr.rti.org) . You must report the results of

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## 44 each test on the appropriately labeled worksheet corresponding to the specific tests requested at your combustion unit. If more than one unit at your facility conducted a stack test using methods not currently supported by the ERT, you must make a cop y of the worksheet and update the combustor ID in order to distinguish between each separate test. After completing the worksheet, you must also submit an electronic copy of the emission test report (PDF format preferred). If you have CO CEMS that meets performance specification

- 4 or a 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 installed at your combustion unit, and you used CEMS data to meet CO, SO 2 

## and/or NO x 

## test requirements at your facility, you must report daily averages from 30 days of CEMS data in a Microsoft® 

## Excel CEMS Template. The Excel templates are specific to each pollutant and type of unit and they can be downloaded from the Electric Utility

MACT ICR 2009 website (http://utility macticr.rti.org)

. 3.2.1 Reporting measured values below the detection level Identify the status of measured values relative to detection levels on the spreadsheet or in the ERT using the following descriptions:

 BDL (below detection level)

– all analytical values used to calculate and report an in

stack emissions value are less than the laboratory ’s reported detection level(s);  DLL (detection level limited)

– at least one but not all values used to calculate and report an in

- stack emissions value are less than the laboratory ’s reported detection level(s); or  ADL ( above detection level)

– all analytical values used to calculate and report an in

stack emissions value are greater than the laboratory ’s reported detection level(s). For each reported emissions value, insert the appropriate flag (BDL, DLL, or ADL) in the Note line of Excel emission test spreadsheet template or in the Comments line of the Electronic Reporting Tool (ERT). When reporting and calculating individual test run data:

 For analy

tical data reported from the lab as “nondetect” or “below detection level;”

 Include a brief description of the procedures used to determine the analy tical detection and in

- stack detection levels: o In the Note line of Excel emission test spreadsheet template; or o In the Comments line of Lab Data tab in the Run Data Details in the ERT

.

 Describe these procedures completely in a separate attachment including the measurements made, the standards used, and the statistical procedures applied.

 Calculate in

- stack emissions rate for any analy tical measurement below detection level using the relevant detection level as the “real” value.

 Report the calculated emissions concentration or rate result:

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## 45 o As a bracketed “less than” detection level value (e.g., [<0.0105]) in the Excel emission test spreadsheet template and include the appropriate flag in the Note line; or o As a “real” value in the ERT with the appropriate flag in the Comments line.

 Report as “real” values (i.e., no brackets or < s ymbol) any anal ytical data measured above the detection level including any data between the analy tical detection level and a laboratory

- specific reporting or quantification level (i.e., flag as ADL).

 Apply these reporting and calculation procedures to measurements made with Method 23 : o Report data in the Excel emission test spreadsheet template for each of the D/F congeners measured with Method 23 below the detection level as [< detection level] o Do not report emissions as zero as described in the method

 For pollutant measurements composed of multiple components or fractions (e.g., Hg and other metals sampling trains) when the result for the value for any component is measured below the analytical detection level;

 Calculate in

- stack emissions rate or concentrations as outlined above for each component or fraction;

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

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

 Report the sum of all components or fractions: o As a bracketed “less than” detection level value (e.g., [<0.0105]) in the Excel emission test spreadsheet template and include the appropriate flag in the Note line; or o As a “real” value in the ERT with the appropriate flag in the Comments line.

 Report also the individual component or fraction values for each run if the Excel emission test spreadshe et template or ERT format allows; if not (i.e., the format allows reporting only

a single sum value): o For the Excel emission test spreadsheet template, next to the sum reported as above report in the Notes line the appropriate flag along with the values for the measured or detection level value for each component or fraction as used in the calculations (e.g., 0.036, [<0.069], 1.239, [<0.945] for a four fraction sample) o For the ERT, next to the sum reported as above, report on the Comments line the appropriate flag and the measured or detection level value for each component or fraction as used in the calculations (e.g., 0.036, [<0.069], 1.239, [<0.945] for a four fraction sample)

 For measurements conducted using instrumental test methods (e.g., Methods 3A, 6C, 7E, 10, 25A)

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## 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 information relative to calibration gas values or other technical qualifiers for measured values in Comments line in the ERT

 When reporting and calculating average emissions rate or concentration for a test when some results are reported as BDL

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

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

-run test)

 Report the average emissions rate or concentration average: o As a bracketed “less than” detection level value (e .g., [<20.06]) in the Excel emission test spreadsheet template and include the appropriate flag in the Note line o As a “real” value in the ERT and include the appropriate flag in the Comments line. 3.2 Reporting Fuel Analysis Data If you conducted a fuel analysis, you must report the analys is results separately for each of the composited samples in a Microsoft ® Excel Fuel Analysis Template. This Excel template can be downloaded from the Electric Utility MACT ICR 2009 website (http://utility macticr.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 ty pe in e ach worksheet order to distinguish between the separate fuel analys es. 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 fi elds within the ERT with the notes whether or not the field is required or optional can be found at http://utility macticr.rti.org

.

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## 47 

# 4 .0 How to Submit Data You may submit your data by

using the Electric Utility MACT ICR 2009 website

. T o avoid duplicate data keep all data for a particular facility together, we request that you submit all of the data requested from your facility the same way . To submit your data:

 Use the Electric Utility MACT ICR 2009 website referenced below and follow the directions listed below.  If you are submitting Confidential Business Information (CBI), you must mail a separate CD or DVD containing only the CBI portion of your data to the EPA address shown in your Section 114 letter. 

# I nstructions for Uploading Part III 1. Open the Web site Open the Electrical Utility MACT ICR 2009 Web site, located at the following address: http://utility

macticr.rti.org 2. Log in, or register

– It is assumed that the respondent has registered and logged into the website previously for entry of Part I and II data. 3. Go to the "Upload Part III" page
a. Click on the "Upload" menu item within the menu bar at the top of the screen to go to the "Upload" page. b. Click on the "Upload Part III" link. 4. Upload your completed ERT Database and Excel Spreadsheets
a. Go to the tabbed section of the "Upload Part III" page. b. The first tab is the "Upload Checklist" tab. Answer all questions, then click on the "Continue" button. Your answers to the "Upload Checklist" questions will assist in guiding you correctly through the upload process.
c. The next tab is the "Upload ERT Database" tab. i. Enter a description for the upload, or any comments. Note that the description and comments entered at this point are primarily for your own reference when referring back to the files you have uploaded (refer to 4.e).

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## 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 file that you wish to upload.
v. After selecting the file, click on the "Upload" link. The file's upload progress will be displayed. Uploading may take a few seconds or minutes depending on the size of the file you are attempting to upload, and your internet connection speed. Please be aware that the only file types that will be accepted for the ERT Database upload are ".zip" and ".acddr" (the file ty pe of the ERT Database originally supplied to you). Itis recommended that you zip your completed ERT Database prior to uploading it, particularly if it is over 200MB in size. d. After the ERT Database upload has completed, click on the "Continue" button.
e. If you answered "Yes" to the checklist question regarding Additional Excel data(Micro soft ® 

## Excel Emission Test Template and/or Microsoft ® Excel Fuel Analysis Template), the next tab will be the "Upload Additional Excel Data" tab. Follow the same process outlined in 4.c. Note that the only

file types that will be accepted for the Excel data upload are ".xls" and ".xlsx". f. After the Excel data upload has completed, click on the "Continue" button. g. The final tab is the "View uploaded files" tab. This will display a list of the files you have uploaded. i. Next to each file will be links to "Del ete" 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 cop y of it. ii. At the bottom of the "View uploaded files" tab, there is a "Finalize uploads" button. 1. Click on this button when you are sure you have uploaded the final copy of your completed ERT Database

. 2. Once you have finalized uploads for Part III you will no longer be able to upload further files for that part of the IC R.

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## 49 Also at the bottom of the "View uploaded files" tab, there is a button titled "Upload another file". Click on this button if you would like to start the upload process again, for another completed ERT Datab ase

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## 50 

# 5.0 Definitions The following definitions apply to the coal

- and oil

- fired electric utility steam generating unit test plan methods: Equivalent means: (1) An equivalent sample collection procedure means a published voluntary consensus standard or practice (VCS) or EPA method that includes collection of a minimum of three composite fuel samples, with each composite consisting of a minimum of three increments collected at approximately equal intervals over the test period. (2) An equivalent sample c ompositing procedure means a published VCS or EPA method to systematically

mix and obtain a representative subsample (part) of the composite sample. (3) An equivalent sample preparation procedure means a published VCS or EPA method that: Clearly states that the standard, practice or method is appropriate for the pollutant and the fuel matrix; or is cited as an appropriate sample preparation standard, practice or method for the pollutant in the chosen VCS or EPA determinative or analytical method. (4) An equivalent procedure for determining heat content means a published VCS or EPA method to obtain gross calorific (or higher heating) value. (5) An equivalent procedure for determining fuel moisture content means a published VCS or EPA method to obtain moisture content. If the sample analys is plan calls for determining metals (especially

the mercury, selenium, or arsenic) using an aliquot of the dried sample, then the drying temperature must be modified to prevent vaporizing these metals. On the other hand, if metals analysis is done on an ‘‘as received’’ basis, a separate aliquot can be dried to determine moisture content and the metals concentration mathematically adjusted to a dry basis. (6) An equivalent pollutant (mercury, TSM, or total chlorine) determinative or anal ytical procedure means a published VCS or EPA method that clearly states that the standard, practice, or method is appropriate for the pollutant and the fuel matrix and has a published detection limit equal to or lower than the methods listed in this test plan. Voluntary Consensus Standards or VCS mean technical standards ( e.g. , materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. EPA/OAQPS has by prece dent only

used VCS that are written in English. Examples of VCS bodies are: American Society of Testing and Materials (ASTM), American Society of Mechanical Engineers (ASME), International Standards Organization (I SO), Standards Australia (AS), British S tandards (BS), Canadian Standards (CSA), European Standard (EN or CEN) and German Engineering Standards (VDI). The types of standards that are not considered VCS are standards developed by: the U.S. States, such as California (CARB) and Texas (TCEQ); industry groups, such as American Petroleum Institute (API), Gas Processors Association (GPA), and Gas Research Institute (GRI); and other branches of the U.S. government, such as Department of Defense (DOD) and Department of Transportation (DOT).

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## 51 This does not preclude EPA from using standards developed b y 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 R eporting 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 te st methods contact: Peter Westlin U.S. EPA (919) 541

- 1058 westlin.peter@epa.gov OR Gary McAlister U.S. EPA (919) 541

- 1062 mcalister.gary@epa.gov For questions on the coal- and oil- fired electric utility ste amgenerating unit test plan, including units selected to test and reporting mechanisms other than the ERT, contact: William Maxwell U.S. EPA (919) 541

- 5430 maxwell.bill@epa.gov For questions on uploading files to the HTTP site, Please visit http://utility macticr.rti.org and use the toll free technical support hotline or technical support email address.

## Attachment 4. List of coal- fired electric utility steam generating units requiring Part I and II Information

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



## 53 IN A. B. Brown 1 IN A. B. Brown 2 CA ACE Cogeneration Facility CFB PA AES Beaver Valley Partners Beaver Valley 2 PA AES Beaver Valley Partners Beaver Valley 3 PA AES Beaver Valley Partners Beaver Valley 4 PA AES Beaver Valley Partners Beaver Valley 5 NY AES Cayuga 1 NY AES Cayuga 2 NY AES Greenidge LLC 4 NY AES Greenidge LLC 5 NY AES Greenidge LLC 6 HI AES H awaii BLRA HI AES Hawaii BLRB IN AES Petersburg 1 IN AES Petersburg 2 IN AES Petersburg 3 IN AES Petersburg 4 PR AES Puerto Rico (Aurora) 1 PR AES Puerto Rico (Aurora) 2 OK AES Shady Point 1A OK AES Shady Point 1B OK AES Shady Point 2A OK AES Shady Point 2 B NY AES Somerset LLC 1 CT AES Thames A CT AES Thames B MD AES W arrior Run Cogeneration Facility BLR1 NY AES W estover 11 NY AES W estover 12 NY AES W estover 13 WV Albright 1 WV Albright 2 WV Albright 3 MN Allen S. King 1 TN Allen Steam Plant 1 TN Allen Stea m Plant 2 TN Allen Steam Plant 3 WI Alma B4 WI Alma B5 VA Altavista Power Station 1 IA Ames Electric Services Power Plant 7 IA Ames Electric Services Power Plant 8 ND Antelope Valley B1 ND Antelope Valley B2 AZ Apache Station 2 AZ Apache Station 3 CO Arapa hoe 3 CO Arapahoe 4 PA Armstrong Power Station 1 PA Armstrong Power Station 2 MO Asbury 1 NC Asheville 1 NC Asheville 2 OH Ashtabula 7 OH Avon Lake 10 OH Avon Lake 12 MI B. C. Cobb 4 MI B. C. Cobb 5 NJ B. L. England 2 IN Bailly 7 IN Bailly 8 IL Baldwin Ene rgy Complex 1 IL Baldwin Energy Complex 2 IL Baldwin Energy Complex 3 AL Barry 1 AL Barry 2 AL Barry 3 AL Barry 4 AL Barry 5 OH Bay Shore 2 OH Bay Shore 3 OH Bay Shore 4 WI Bay Front 5 NC Belews Creek 1 NC Belews Creek 2 MI Belle River 1 MI Belle River 2 F L Big Bend BB01 FL Big Bend BB02 FL Big Bend BB03 FL Big Bend BB04 TX Big Brown 1 TX Big Brown 2 LA Big Cajun 2 2B1 LA Big Cajun 2 2B2 LA Big Cajun 2 2B3 KY Big Sandy BSU1 KY Big Sandy BSU2 SD Big Stone 1 VA Birchwood Power 1A MN Black Dog 3 MN Black Dog 4 NY Black River Generation E0001 NY Black River Generation E0002 NY Black River Generation E0003 WI Blount Street 7 WI Blount Street 8 WI Blount Street 9 MO Blue Valley 1 MO Blue Valley 2 MO Blue Valley 3 OR Boardman 1SG UT Bonanza 1
- 1 GA Bowen 1BLR GA Bowen 2BLR GA Bowen 3BLR GA Bowen 4BLR MD Brandon Shores 1 MD Brandon Shores 2 MA Brayton Point 1 MA Brayton Point 2 MA Brayton Point 3 VA Bremo Bluff 3 VA Bremo Bluff 4 CT Bridgeport Station BHB3 PA Bruce Mansfield 1 PA Bruce Mansfield 2 PA Bruce Mansfield 3 NC Buck 5 NC Buck 6 NC Buck 7 NC Buck 8 NC Buck 9 TN Bull Run 1 IA Burlington 1 FL C. D. McIntosh Jr 3 MD C. P. Crane 1 MD C. P. Crane 2 NY C. R. Huntley Generating Station 65 NY C. R. Huntley Generating Station 67 NY C. R. Huntley Generating Station 68 PA Cambria Cogen B1 PA Cambria Cogen B2 SC Canadys Steam CAN1 SC Canadys Steam CAN2 SC Canadys Steam CAN3 KY Cane Run 4 KY Cane Run 5 KY Cane Run 6 NC Cape Fear 5 NC Cape Fear 6 UT Carbon 1 UT Carbon 2 OH Cardinal 1 OH Cardinal 2 OH Cardinal 3 IN Cayuga 1 I N Cayuga 2 FL Cedar Bay Generating LP CBAState Plant Name Boiler ID State Plant Name Boiler ID S tate Plant Name Boiler ID



## 54 FL Cedar Bay Generating LP CBB FL Cedar Bay Generating LP CBC FL Central Power & Lime 1 MD Chalk Point LLC 1 MD Chalk Point LLC 2 NJ Chambers Cogeneration LP BOIL1 NJ Chambers Cogeneration LP BOIL2 MO Chamois 2 AL Charles R Lowman 3 AL Charles R. Lowman 1 AL Charles R. Lowman 2 CO Cherokee 1 CO Cherokee 2 CO Cherokee 3 CO Cherokee 4 VA Chesapeake 1 VA Chesapeake 2 VA Chesapeake 3 VA Chesapeake 4 VA Chesterfield 3 VA Chesterfield 4 VA Chesterfield 5 VA Chesterfield 6 PA Cheswick Power Plant 1 AZ Cholla 1 AZ Cholla 2 AZ Cholla 3 AZ Cholla 4 MN Clay Boswell 1 MN Clay Boswell 2 MN Clay Boswell 3 MN Clay Boswell 4 NC Cliffside 1 NC Cliffside 2 NC Cliffside 3 NC Cliffside 4 NC Cliffside 5 IN Clifty Creek 1 IN Clifty Creek 2 IN Clifty Creek 3 IN Clifty Creek 4 IN Clifty Creek 5 IN Clifty Creek 6 VA Clinch River 1 VA Clinch River 2 VA Clinch River 3 VA Clover 1 VA Clover 2 ND Coal Creek 1 ND Coal Creek 2 IL Coffeen 01 IL Coffeen 02 NC Cogentrix Dwayne Collier Battle Cogen 1A NC Cogentrix Dwayne Collier Battle Cogen 1B NC Cogentrix Dwayne Collier Battle Cogen 2A NC Cogentrix Dwayne Collier Battle Cogen 2B VA Cogentrix Hopewell 1A VA Cogentrix Hopewell 1B VA Cogentrix Hopewell 1C VA Cogentrix Hopewell 2A VA Cogentrix Hopewell 2B VA Cogentrix Hopewell 2C VA Cogentrix of Richmond 1A VA Cogentrix of Richmond 1B VA Cogentrix of Richmond 2A VA Cogentrix of Richmond 2B VA Cogentrix of Richmond 3A VA Cogentrix of Richmond 3B VA Cogentrix of Richmond 4A VA Cogentrix of Richmond 4B VA Cog entrix Virginia Leasing Corporation 1A VA Cogentrix Virginia Leasing Corporation 1B VA Cogentrix Virginia Leasing Corporation 1C VA Cogentrix Virginia Leasing Corporation 2A VA Cogentrix Virginia Leasing Corporation 2B VA Cogentrix Virginia Leasing Corpora tion 2C AL Colbert 1 AL Colbert 2 AL Colbert 3 AL Colbert 4 AL Colbert 5 TX Coleto Creek 1 MT Colstrip 1 MT Colstrip 2 MT Colstrip 3 MT Colstrip 4 MT Colstrip Energy LP BLR1 WI Columbia 1 WI Columbia 2 PA Colver Power Project ABB01 CO Comanche 1 CO Comanch e 2 CO Comanche 3 PA Conemaugh 1 PA Conemaugh 2 OH Conesville 1 OH Conesville 2 OH Conesville 3 OH Conesville 4 OH Conesville 5 OH Conesville 6 KY Cooper 1 KY Cooper 2 SC Cope COP1 AZ Coronado U1B AZ Coronado U2B IA Council Bluffs 1 IA Council Bluffs 2 IA Council Bluffs 3 IA Council Bluffs 4 ND Coyote B1 CO Craig C1 CO Craig C2 CO Craig C3 IL Crawford 7 IL Crawford 8 FL Crist 4 FL Crist 5 FL Crist 6 FL Crist 7 PA Cromby Generating Station 1 SC Cross 1 SC Cross 2 SC Cross 3 SC Cross 4 FL Crystal River 1 FL C rystal River 2 FL Crystal River 4 FL Crystal River 5 TN Cumberland 1 TN Cumberland 2 KY D. B. W ilson W1 KY Dale 1 KY Dale 2 KY Dale 3 KY Dale 4 IL Dallman 31 IL Dallman 32 IL Dallman 33 IL Dallman 34 MI Dan E. Karn 1 MI Dan E. Karn 2 NC Dan River 1 NC Dan River 2State Plant Name Boiler ID State Plant Name Boiler ID S tate Plant Name Boiler ID



## 55 NC Dan River 3 NY Danskammer Generating Station 3 NY Danskammer Generating Station 4 WY Dave Johnston BW 41 WY Dave Johnston BW 42 WY Dave Johnston BW 43 WY Dave Johnston BW 44 NJ Deepwater 8 FL Deerhaven Generating Station B2 MD Dickerson 1 MD Dickers on 2 MD Dickerson 3 LA Dolet Hills 1 SC Dolphus M Grainger 1 SC Dolphus M Grainger 2 IA Dubuque 1 IA Dubuque 5 IL Duck Creek 1 NY Dunkirk Generating Station 1 NY Dunkirk Generating Station 2 NY Dunkirk Generating Station 3 NY Dunkirk Generating Station 4 A L E. C. Gaston 1 AL E. C. Gaston 2 AL E. C. Gaston 3 AL E. C. Gaston 4 AL E. C. Gaston 5 IL E. D. Edwards 1 IL E. D. Edwards 2 IL E. D. Edwards 3 KY E. W . Brown 1 KY E. W . Brown 2 KY E. W . Brown 3 IN Eagle Valley 3 IN Eagle Valley 4 IN Eagle Valley 5 IN Ea gle Valley 6 IA Earl F. Wisdom 1 KY East Bend 2 OH Eastlake 1 OH Eastlake 2 OH Eastlake 3 OH Eastlake 4 OH Eastlake 5 PA Ebensburg Power 031 MI Eckert Station 1 MI Eckert Station 2 MI Eckert Station 3 MI Eckert Station 4 MI Eckert Station 5 MI Eckert Stati on 6 PA Eddystone Generating Station 1 PA Eddystone Generating Station 2 DE Edge Moor 3 DE Edge Moor 4 WI Edgewater 3 WI Edgewater 4 WI Edgewater 5 IN Edwardsport 7
- 1 IN Edwardsport 7
- 2 IN Edwardsport 8
- 1 WI Elm Road Generating Station 1 WI Elm Road Genera ting Station 2 KY Elmer Smith 1 KY Elmer Smith 2 PA Elrama Power Plant 1 PA Elrama Power Plant 2 PA Elrama Power Plant 3 PA Elrama Power Plant 4 MI Endicott Station 1 MI Erickson Station 1 NM Escalante 1 IN F. B. Culley 1 IN F. B. Culley 2 IN F. B. Culley 3 IA Fair Station 1 IA Fair Station 2 TX Fayette Power Project 1 TX Fayette Power Project 2 TX Fayette Power Project 3 IL Fisk Street 19 AR Flint Creek 1 WV Fort Martin Power Station 1 WV Fort Martin Power Station 2 PA Foster W heeler Mt Carmel Cogen SG
- 101 NM Four Corners 1 NM Four Corners 2 NM Four Corners 3 NM Four Corners 4 NM Four Corners 5 IN Frank E. Ratts 1SG1 IN Frank E. Ratts 2SG1 NC G. G. Allen 1 NC G. G. Allen 2 NC G. G. Allen 3 NC G. G. Allen 4 NC G. G. Allen 5 AL Gadsden 1 AL Gadsden 2 TN Galla tin 1 TN Gallatin 2 TN Gallatin 3 TN Gallatin 4 OH General James M Gavin 1 OH General James M Gavin 2 WI Genoa 1 IA George Neal North 1 IA George Neal North 2 IA George Neal North 3 IA George Neal South 4 NE Gerald Gentleman 1 NE Gerald Gentleman 2 KY Ghen t 1 KY Ghent 2 KY Ghent 3 KY Ghent 4 TX Gibbons Creek 1 IN Gibson 1 IN Gibson 2 IN Gibson 3 IN Gibson 4 IN Gibson 5 VA Glen Lyn 6 VA Glen Lyn 51 VA Glen Lyn 52 AL Gorgas 6 AL Gorgas 7 AL Gorgas 8 AL Gorgas 9 AL Gorgas 10 WV Grant Town Power Plant BLR1A WV Grant Town Power Plant BLR1B OK GRDA 1 OK GRDA 2 KY Green River 4 KY Green River 5 AL Greene County 1 AL Greene County 2 SC H. B. Robinson 1 KY H. L. Spurlock 1 KY H. L. Spurlock 2 KY H. L. Spurlock 3 KY H. L. Spurlock 4 OH Hamilton 8State Plant Name Boiler ID State Plant Name Boiler ID S tate Plant Name Boiler ID



## 56 OH Hamilton 9 GA Hamm ond 1 GA Hammond 2 GA Hammond 3 GA Hammond 4 MI Harbor Beach 1 MT Hardin Generator Project PC1 IN Harding Street 50 IN Harding Street 60 IN Harding Street 70 GA Harllee Branch 1 GA Harllee Branch 2 GA Harllee Branch 3 GA Harllee Branch 4 TX Harrington 061B TX Harrington 062B TX Harrington 063B WV Harrison Power Station 1 WV Harrison Power Station 2 WV Harrison Power Station 3 PA Hatfields Ferry Power Station 1 PA Hatfields Ferry Power Station 2 PA Hatfields Ferry Power Station 3 IL Havana 9 MO Hawthorn 5A C O Hayden H1 CO Hayden H2 AK Healy 1 KY Henderson I 6 IL Hennepin Power Station 1 IL Hennepin Power Station 2 MD Herbert A. W agner 2 MD Herbert A. W agner 3 KY HMP&L Station Two Henderson H1 KY HMP&L Station Two Henderson H2 KS Holcomb SGU1 PA Homer City Sta tion 1 PA Homer City Station 2 PA Homer City Station 3 MN Hoot Lake 2 MN Hoot Lake 3 OK Hugo 1 UT Hunter 1 UT Hunter 2 UT Hunter 3 UT Huntington 1 UT Huntington 2 IL Hutsonville 05 IL Hutsonville 06 MO Iatan 1 AR Independence 1 AR Independence 2 DE Indian River Generating Station 2 DE Indian River Generating Station 3 DE Indian River Generating Station 4 FL Indiantown Cogeneration LP AAB01 UT Intermountain Power Project 1SGA UT Intermountain Power Project 2SGA MI J. B. Sims 3 MI J. C. Weadock 7 MI J. C. Wea dock 8 MT J. E. Corette Plant 2 MI J. H. Campbell 1 MI J. H. Campbell 2 MI J. H. Campbell 3 KY J. K. Smith 1 TX J. K. Spruce BLR1 TX J. K. Spruce BLR2 OH J. M. Stuart 1 OH J. M. Stuart 2 OH J. M. Stuart 3 OH J. M. Stuart 4 MI J. R. Whiting 1 MI J. R. Whiti ng 2 MI J. R. Whiting 3 TX J. T. Deely 1 TX J. T. Deely 2 GA Jack McDonough MB1 GA Jack McDonough MB2 MS Jack W atson 4 MS Jack W atson 5 MI James De Young 5 AL James H. Miller Jr. 1 AL James H. Miller Jr. 2 AL James H. Miller Jr. 3 AL James H. Miller Jr. 4 MO James River Power Station 3 MO James River Power Station 4 MO James River Power Station 5 SC Jefferies 3 SC Jefferies 4 KS Jeffrey Energy Center 1 KS Jeffrey Energy Center 2 KS Jeffrey Energy Center 3 WY Jim Bridger BW 71 WY Jim Bridger BW 72 WY Jim Bridg er BW 73 WY Jim Bridger BW 74 PA John B Rich Memorial Power Station CFB1 PA John B Rich Memorial Power Station CFB2 WV John E Amos 1 WV John E Amos 2 WV John E. Amos 3 WI John P. Madgett B1 TN John Sevier 1 TN John Sevier 2 TN John Sevier 3 TN John Sevier 4 TN Johnsonville 1 TN Johnsonville 2 TN Johnsonville 3 TN Johnsonville 4 TN Johnsonville 5 TN Johnsonville 6 TN Johnsonville 7 TN Johnsonville 8 TN Johnsonville 9 TN Johnsonville 10 IL Joliet 29 71 IL Joliet 29 72 IL Joliet 29 81 IL Joliet 29 82 IL Joliet 9 5 IL Joppa Steam 1 IL Joppa Steam 2 IL Joppa Steam 3 IL Joppa Steam 4 IL Joppa Steam 5 IL Joppa Steam 6 WV Kammer 1 WV Kammer 2 WV Kammer 3 WV Kanawha River 1 WV Kanawha River 2 KY Kenneth C. Coleman C1 KY Kenneth C. Coleman C2 KY Kenneth C. Coleman C3 PA Keystone 1 PA Keystone 2 OH Killen Station 2 IL Kincaid Generation LLC 1 IL Kincaid Generation LLC 2 TN Kingston 1 TN Kingston 2State Plant Name Boiler ID State Plant Name Boiler ID S tate Plant Name Boiler ID



## 57 TN Kingston 3 TN Kingston 4 TN Kingston 5 TN Kingston 6 TN Kingston 7 TN Kingston 8 TN Kingston 9 PA Kline Township Cogen Faci lity 1 GA Kraft 1 GA Kraft 2 GA Kraft 3 OH Kyger Creek 1 OH Kyger Creek 2 OH Kyger Creek 3 OH Kyger Creek 4 OH Kyger Creek 5 NC L. V. Sutton 1 NC L. V. Sutton 2 NC L. V. Sutton 3 KS La Cygne 1 KS La Cygne 2 MO Labadie 1 MO Labadie 2 MO Labadie 3 MO Labadie 4 MO Lake Road 5 OH Lake Shore 18 IL Lakeside 7 IL Lakeside 8 CO Lamar 4 IA Lansing 3 IA Lansing 4 FL Lansing Smith 1 FL Lansing Smith 2 WY Laramie River Station 1 WY Laramie River Station 2 WY Laramie River Station 3 KS Lawrence Energy Center 3 KS Lawren ce Energy Center 4 KS Lawrence Energy Center 5 NC Lee 1 NC Lee 2 NC Lee 3 ND Leland Olds 1 ND Leland Olds 2 MT Lewis & Clark B1 TX Limestone LIM1 TX Limestone LIM2 NJ Logan Generating Plant B01 NE Lon W right 8 IA Louisa 101 WI Manitowoc 6 WI Manitowoc 7 WI Manitowoc 8 IL Marion 4 IL Marion 123 NC Marshall 1 NC Marshall 2 NC Marshall 3 NC Marshall 4 CO Martin Drake 5 CO Martin Drake 6 CO Martin Drake 7 TX Martin Lake 1 TX Martin Lake 2 TX Martin Lake 3 NC Mayo 1A NC Mayo 1B GA McIntosh 1 SC McMeekin MCM1 SC McMeekin MCM2 VA Mecklenburg Power Station BLR1 VA Mecklenburg Power Station BLR2 MO Meramec 1 MO Meramec 2 MO Meramec 3 MO Meramec 4 IL Meredosia 01 IL Meredosia 02 IL Meredosia 03 IL Meredosia 04 IL Meredosia 05 IN Merom 1SG1 IN Merom 2SG1 NH Merrimack 1 NH Merrimack 2 OH Miami Fort 6 OH Miami Fort 7 OH Miami Fort 8 OH Miami Fort 5
- 1 OH Miami Fort 5
- 2 IN Michigan City 12 KY Mill Creek 1 KY Mill Creek 2 KY Mill Creek 3 KY Mill Creek 4 IA Milton L. Kapp 2 ND Milton R. Young B1 ND Milton R. Young B2 GA Mitch ell 3 WV Mitchell 1 WV Mitchell 2 PA Mitchell Power Station 33 MI Monroe 1 MI Monroe 2 MI Monroe 3 MI Monroe 4 TX Monticello 1 TX Monticello 2 TX Monticello 3 MO Montrose 1 MO Montrose 2 MO Montrose 3 WV Morgantown Energy Facility CFB1 WV Morgantown Energy Facility CFB2 MD Morgantown Generating Plant 1 MD Morgantown Generating Plant 2 MA Mount Tom 1 WV Mountaineer 1 WV Mt Storm 3 CA Mt. Poso Cogeneration BL01 WV Mt. Storm 1 WV Mt. Storm 2 IA Muscatine Plant #1 7 IA Muscatine Plant #1 8 IA Muscatine Plant #1 9 OH Muskingum River 1 OH Muskingum River 2 OH Muskingum River 3 OH Muskingum River 4 OH Muskingum River 5 OK Muskogee 4 OK Muskogee 5 OK Muskogee 6 WY Naughton 1 WY Naughton 2 WY Naughton 3 AZ Navajo 1 AZ Navajo 2 AZ Navajo 3 KS Nearman Creek N1 NE Nebra ska City 1 NE Nebraska City 2 WY Neil Simpson II 2State Plant Name Boiler ID State Plant Name Boiler ID S tate Plant Name Boiler ID



## 58 WI Nelson Dewey 1 WI Nelson Dewey 2 PA New Castle Plant 3 PA New Castle Plant 4 PA New Castle Plant 5 MO New Madrid 1 MO New Madrid 2 IL Newton 1 IL Newton 2 OH Niles 1 OH Niles 2 WV North Branch 1A WV Nor

th Branch 1B NE North Omaha 1 NE North Omaha 2 NE North Omaha 3 NE North Omaha 4 NE North Omaha 5 NV North Valmy 1 NV North Valmy 2 PA Northampton Generating Company BLR1 OK Northeastern 3313 OK Northeastern 3314 CO Nucla 1 OH O. H. Hutchings H
- 1 OH O. H. Hutchings H
- 2 OH O. H. Hutchings H
- 3 OH O. H. Hutchings H
-4 OH O. H. Hutchings H
- 5 OH O. H. Hutchings H
- 6 TX Oak Grove 1 TX Oak Grove 2 TX Oklaunion 1 OH Orrville 10 OH Orrville 11 OH Orrville 12 OH Orrville 13 IA Ottumwa 1 OH Painesville 3 OH Painesville 4 OH Painesville 5 PA Panther Creek Energy Facility BLR1 PA Panther Creek Energy Facility BLR2 KY Paradise 1 KY Paradise 2 KY Paradise 3 CO Pawnee 1 WV Philip Sporn 11 WV Philip Sporn 21 WV Philip Sporn 31 WV Philip Sporn 41 WV Philip Sporn 51 OH Picway 9 PA Piney Creek Project BRBR1 TX Pirkey 1 WI Pleasant Prairie 1 WI Pleasant Prairie 2 WV Pleasants Power Station 1 WV Pleasants Power Station 2 AR Plum Point Energy STG1 CA Port of Stockton District Energy Facility N64514 CA Port of Stockton District Energy Facility N64516 PA Portland 1 PA Portland 2 VA Potomac River 1 VA Potomac River 2 VA Potomac River 3 VA Potomac River 4 VA Potomac River 5 IL Powerton 51 IL Powerton 52 IL Powerton 61 IL Powerton 62 PA PPL Brunner Island 1 PA PPL Brunner Island 2 PA PPL B runner Island 3 PA PPL Martins Creek 1 PA PPL Martins Creek 2 PA PPL Montour 1 PA PPL Montour 2 IA Prairie Creek 1 IA Prairie Creek 2 IA Prairie Creek 3 IA Prairie Creek 4 MI Presque Isle 5 MI Presque Isle 6 MI Presque Isle 7 MI Presque Isle 8 MI Presque I sle 9 NC Primary Energy Roxboro 1A NC Primary Energy Roxboro 1B NC Primary Energy Roxboro 1C NC Primary Energy Southport 1A NC Primary Energy Southport 1B NC Primary Energy Southport 1C NC Primary Energy Southport 2A NC Primary Energy Southport 2B NC Prima ry Energy Southport 2C NJ PSEG Hudson Generating Station 2 NJ PSEG Mercer Generating Station 1 NJ PSEG Mercer Generating Station 2 WI Pulliam 3 WI Pulliam 4 WI Pulliam 5 WI Pulliam 6 WI Pulliam 7 WI Pulliam 8 KS Quindaro 1 KS Quindaro 2 KY R D Green G2 KY R. D. Green G1 MS R. D. Morrow 1 MS R. D. Morrow 2 OH R. E. Burger 5 OH R. E. Burger 6 OH R. E. Burger 7 OH R. E. Burger 8 IN R. Gallagher 1 IN R. Gallagher 2 IN R. Gallagher 3 IN R. Gallagher 4 ND R. M. Heskett B1 ND R. M. Heskett B2 IN R. M. Schahfer 14 IN R. M. Schahfer 15 IN R. M. Schahfer 17 IN R. M. Schahfer 18 MD R. Paul Smith Power Station 9 MD R. Paul Smith Power Station 11 LA R. S. Nelson 6 CO Rawhide 101 CO Ray D. Nixon 1 MS Red Hills Generating Facility AA001 MS Red Hills Generating Facility AA0 02 NV Reid Gardner 1 NV Reid Gardner 2 NV Reid Gardner 3 NV Reid Gardner 4 OH Richard Gorsuch 1 OH Richard Gorsuch 2 OH Richard Gorsuch 3 OH Richard Gorsuch 4 MI River Rouge 2 MI River Rouge 3State Plant Name Boiler ID State Plant Name Boiler ID S tate Plant Name Boiler ID



## 59 NC Riverbend 7 NC Riverbend 8 NC Riverbend 9 NC Riverbend 10 IA Riverside 9 KS Riverton 39 KS Riverton 40 WV Rivesville 7 WV Rivesville 8 NC Roanoke Valley I BLR1 NC Roanoke Valley II BLR2 KY Robert A Reid R1 NY Rochester 7 1 NY Rochester 7 2 NY Rochester 7 3 NY Rochester 7 4 IN Rockport MB1 IN Rockport MB2 LA Rodemac her 2 NC Roxboro 1 NC Roxboro 2 NC Roxboro 3A NC Roxboro 3B NC Roxboro 4A NC Roxboro 4B MO Rush Island 1 MO Rush Island 2 MA Salem Harbor 1 MA Salem Harbor 2 MA Salem Harbor 3 NM San Juan 1 NM San Juan 2 NM San Juan 3 NM San Juan 4 TX San Miguel SM
- 1 TX Sa ndow Station 4 TX Sandow Station 5A TX Sandow Station 5 B GA Scherer 1 GA Scherer 2 GA Scherer 3 GA Scherer 4 NH Schiller 4 NH Schiller 5 NH Schiller 6 FL Scholz 1 FL Scholz 2 PA Scrubgrass Generating UNIT 1 PA Scrubgrass Generating UNIT 2 FL Seminole 1 FL Seminole 2 PA Seward 1 PA Seward 2 KY Shawnee 1 KY Shawnee 2 KY Shawnee 3 KY Shawnee 4 KY Shawnee 5 KY Shawnee 6 KY Shawnee 7 KY Shawnee 8 KY Shawnee 9 KY Shawnee 10 PA Shawville 1 PA Shawville 2 PA Shawville 3 PA Shawville 4 NE Sheldon 1 NE Sheldon 2 MN S herburne County 1 MN Sherburne County 2 MN Sherburne County 3 MI Shiras 3 MO Sibley 1 MO Sibley 2 MO Sibley 3 MO Sikeston Power Station 1 MN Silver Bay Power BLR1 MN Silver Bay Power BLR2 MN Silver Lake 3 MN Silver Lake 4 MO Sioux 1 MO Sioux 2 IA Sixth Street 2 IA Sixth Street 3 IA Sixth Street 4 IA Sixth Street 5 MA Somerset Station 8 OK Sooner 1 OK Sooner 2 WI South Oak Creek 5 WI South Oak Creek 6 WI South Oak Creek 7 WI South Oak Creek 8 VA Southampton Power Station 1 MO Southwest Power Station 1 AZ Springerville 1 AZ Springerville 2 AZ Springerville 3 AZ Springerville 4 MI St. Clair 1 MI St. Clair 2 MI St. Clair 3 MI St. Clair 4 MI St. Clair 6 MI St. Clair 7 FL St. Johns River Power Park 1 FL St. Johns River Power Park 2 PA St. Nicholas Cogen Project 1 ND Stanton 1 ND Stanton 10 FL Stanton Energy Center 1 FL Stanton Energy Center 2 IN State Line Energy 3 IN State Line Energy 4 IA Streeter Station 7 UT Sunnyside Cogen Associates 1 IA Sutherland 1 IA Sutherland 2 IA Sutherland 3 MN Syl Laskin 1 MN Syl Lask in 2 IN Tanners Creek U1 IN Tanners Creek U2 IN Tanners Creek U3 IN Tanners Creek U4 KS Tecumseh Energy Center 9 KS Tecumseh Energy Center 10 MI TES Filer City Station 1 MI TES Filer City Station 2 MO Thomas Hill MB1 MO Thomas Hill MB2 MO Thomas Hill MB3 PA Titus 1 PA Titus 2 PA Titus 3 TX Tolk 171B TX Tolk 172B WA Transalta Centralia Generation BW 21 WA Transalta Centralia Generation BW 22 MI Trenton Channel 16 MI Trenton Channel 17 MI Trenton Channel 18 MI Trenton Channel 19State Plant Name Boiler ID State Plant Name Boiler ID S tate Plant Name Boiler ID



## 60 MI Trenton Channel 9A CO Trigen Colorado Energy BLR3 CO Trigen Colorado Energy BLR4 CO Trigen Colorado Energy BLR5 NY Trigen Syracuse Energy 1 NY Trigen Syracuse Energy 2 NY Trigen Syracuse Energy 3 NY Trigen Syracuse Energy 4 NY Trigen Syracuse Energy 5 KY Trimble County 1 NV TS Power P lant BLR100 TX Twin Oaks Power One U1 TX Twin Oaks Power One U2 WY Two Elk Generating Station 1 KY Tyrone 5 SC Urquhart URQ3 WI Valley 1 WI Valley 2 WI Valley 3 WI Valley 4 CO Valmont 5 IL Vermilion 1 IL Vermilion 2 MS Victor J Daniel Jr 1 MS Victor J Dani el Jr. 2 TX W. A. Parish WAP5 TX W. A. Parish WAP6 TX W. A. Parish WAP7 TX W. A. Parish WAP8 OH W. H. Sammis 1 OH W. H. Sammis 2 OH W. H. Sammis 3 OH W. H. Sammis 4 OH W. H. Sammis 5 OH W. H. Sammis 6 OH W. H. Sammis 7 NC W. H. W eatherspoon 1 NC W. H. W eat herspoon 2 NC W. H. W eatherspoon 3 OH W. H. Zimmer 1 SC W. S. Lee 1 SC W. S. Lee 2 SC W. S. Lee 3 IN Wa bash River 1 IN Wa bash River 2 IN Wa bash River 3 IN Wa bash River 4 IN Wa bash River 5 IN Wa bash River 6 OH Wa lter C Beckjord 1 OH Wa lter C Beckjord 2 OH W alter C Beckjord 5 OH Wa lter C. Beckjord 3 OH Wa lter C. Beckjord 4 OH Wa lter C. Beckjord 6 GA Wa nsley 1 GA Wa nsley 2 IN Wa rrick 1 IN Wa rrick 2 IN Wa rrick 3 IN Wa rrick 4 SC Wateree WAT1 SC Wateree WAT2 IL Wa ukegan 7 IL Wa ukegan 8 IL Wa ukegan 17 TX We lsh 1 TX We lsh 2 TX We lsh 3 WI We ston 1 WI We ston 2 WI We ston 3 WI We ston 4 PA Wh eelabrator Frackville Energy BLR1 NE Wh elan Energy Center 1 AR Wh ite Bluff 1 AR Wh ite Bluff 2 IN Wh itewater Valley 1 IN Wh itewater Valley 2 AL Wi dows Creek 1 AL Wi dows Creek 2 AL Wi d ows Creek 3 AL Wi dows Creek 4 AL Wi dows Creek 5 AL Wi dows Creek 6 AL Wi dows Creek 7 AL Wi dows Creek 8 IL Wi ll County 1 IL Wi ll County 2 IL Wi ll County 3 IL Wi ll County 4 SC Wi lliams WIL1 WV Wi llow Island 1 WV Wi llow Island 2 SC Wi nyah 1 SC Wi nyah 2 SC Wi nyah 3 SC Wi nyah 4 IL Wo od River 4 IL Wo od River 5 PA WPS Energy Servs Sunbury Gen 3 PA WPS Energy Servs Sunbury Gen 4 PA WPS Energy Servs Sunbury Gen 1A PA WPS Energy Servs Sunbury Gen 1B PA WPS Energy Servs Sunbury Gen 2A PA WPS Energy Servs Sunbury Gen 2B NY WPS Power Niagara 1 PA WPS W estwood Generation LLC 031 WY Wygen I 3 WY Wygen II 4 WY Wyodak BW 91 GA Yates Y1BR GA Yates Y2BR GA Yates Y3BR GA Yates Y4BR GA Yates Y5BR GA Yates Y6BR GA Yates Y7BR VA Yorktown 1 VA Yorktown 2

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

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



## 61 PR Aguirre 1 PR Aguirre 2 PR Aguirre 3 PR Aguirre 4 PR Aguirre 5 PR Aguirre 6 PR Aguirre 7 PR Aguirre 8 PR Aguirre 9 PR Aguirre 10 PR Aguirre 11 PR Aguirre 12 FL Anclote 1 FL Anclote 2 PR Arecibo 1 PR Arecibo 2 PR Arecibo 3 NY Astoria Generating Station 30 NY Astoria Generating Station 40 NY Astoria Generating Station 50 NJ B. L. England 3 MS Baxter W ilson 1 MS Baxter W ilson 2 DC Benning 15 DC Benning 16 NY Bowline Point 1 NY Bowline Point 2 MA Brayton Point 4 CT Bridgeport Station BHB2 FL C. D. McIntosh Jr 1 FL C. D. McIntosh Jr 2 GU Cabras 1 GU Cabras 2 MA Canal Station 1 MA Canal Station 2 FL Cape Canaveral PCC1 FL Cape Canaveral PCC2 PR Central Palo Seco 1 PR Central Palo Seco 2 PR Central Palo Seco 3 PR Central Palo Seco 4 PR Central Palo Seco 5 PR Central Palo Seco 6 PR Centra l Palo Seco 7 PR Central Palo Seco 8 NY Charles Poletti 1 MA Cleary Flood 8 PR Costa Sur 1 PR Costa Sur 2 PR Costa Sur 3 PR Costa Sur 4 PR Costa Sur 5 PR Costa Sur 6 PR Costa Sur 7 PR Costa Sur 8 PR Costa Sur 9 PR Costa Sur 10 PA Cromby Generating Station 2 MI Dan E. Karn 3 MI Dan E. Karn 4 NY Danskammer Generating Station 1 NY Danskammer Generating Station 2 CT Devon Station 7 CT Devon Station 8 IN Eagle Valley 1 IN Eagle Valley 2 NY East River 5 NY East River 6 PA Eddystone Generating Station 3 PA Eddysto ne Generating Station 4 DE Edge Moor 5 IN Edwardsport 6
- 1 MS Gerald Andrus 1 IN Harding Street 9 IN Harding Street 10 IL Havana 1 IL Havana 2 IL Havana 3 IL Havana 4 IL Havana 5 IL Havana 6 IL Havana 7 IL Havana 8 MD Herbert A. W agner 1 MD Herbert A. W agne r 4 HI Honolulu 16 HI Honolulu 17 FL Indian River 1 FL Indian River 2 FL Indian River 3 SC Jefferies 1 SC Jefferies 2 HI Kahe 1 HI Kahe 2 HI Kahe 3 HI Kahe 4 HI Kahe 5 HI Kahe 6 FL Manatee PMT1 FL Manatee PMT2 FL Martin PMR1 FL Martin PMR2 DE McKee Run 3 G A McManus 1 GA McManus 2 IL Meredosia 06 LA Michoud 3 CT Middletown 2 CT Middletown 4 MD Mirant Chalk Point 3 MD Mirant Chalk Point 4 PA Mitchell Power Station 1 PA Mitchell Power Station 2 PA Mitchell Power Station 3 CT Montville Station 5 CT Montville St ation 6 MA Mystic Generating Station 7 CT New Haven Harbor NHB1 NH Newington 1 NY Northport 1 NY Northport 2 NY Northport 3 NY Northport 4 FL Northside Generating Station 3 CT NRG Norwalk Harbor 1 CT NRG Norwalk Harbor 2 NY Oswego Harbor Power 5 NY Oswego Harbor Power 6 FL P. L. Bartow 1 FL P. L. Bartow 2 FL P. L. Bartow 3 FL Port Everglades PPE1 FL Port Everglades PPE2 FL Port Everglades PPE3 FL Port Everglades PPE4 NY Port Jefferson 3 NY Port Jefferson 4 VA Possum Point 5State Plant Name Boiler ID State Plant Name Boiler ID State Plant Name Boiler ID



## 62 PA PPL Martins Creek 3 PA PPL Mar

tins Creek 4 NJ PSEG Sewaren Generating Station 1 NJ PSEG Sewaren Generating Station 2 NJ PSEG Sewaren Generating Station 3 NJ PSEG Sewaren Generating Station 4 VI Randolph E. Harley 1 NY Ravenswood Generating Station 1 NY Ravenswood Generating Station 2 N Y Ravenswood Generating Station 3 VI Richmond 1 FL Riviera PRV3 FL Riviera PRV4 NY Roseton Generating Station 1 NY Roseton Generating Station 2 MA Salem Harbor 4 PR San Juan Plant 1 PR San Juan Plant 2 PR San Juan Plant 3 PR San Juan Plant 4 PR San Juan Pl ant 5 FL Sanford PSN3 PA Schuylkill Generating Station 1 FL Suwannee River 1 FL Suwannee River 2 FL Suwannee River 3 GU Tanguisson 1 FL Turkey Point PTP1 FL Turkey Point PTP2 MD Vienna Operations 8 HI Wa iau 3 HI Wa iau 4 HI Wa iau 5 HI Wa iau 6 HI Wa iau 7 HI Wa iau 8 MA We st Springfield 3 ME Wi lliam F. W ym an 1 ME Wi lliam F. W ym an 2 ME Wi lliam F. W ym an 3 ME Wi lliam F. W ym an 4 VA Yorktown 3

## 63

Attachment 6. List of all IGCC units requiring Part I, II, and III Information and selected for HCl/HF/HCN acid gas HAP, dioxin/furan organic HAP, non - dioxin/furan organic HAP, and mercury and other non - mercury metallic HAP testing State Plant Name Boiler ID FL Polk 1CA FL Polk 1CT IN Wabash River 1a 

## Attachment 7. List of all petroleum coke- fired units requiring Part I, II, and III Information and selected for HCl/HF/HCN acid gas HAP, dioxin/furan organic HAP, non - dioxin/furan organic HAP, and mercury and other non - mercury metallic HAP testing State Plant Name Boiler ID NO X 

### Control PM Control FGD Type TX AES D eepwater AAB001 SCR Electrostatic precipitator, hot side Spray type OH Bay Shore 1 Baghouse, pulse PA Chester Operations 10 Baghouse, pulse CA Hanford CB1302 Baghouse, pulse Spray type WI Manitowoc 9 SNCR Baghouse, pulse FL Northside Generating Station 1 Baghouse, pulse Spray type FL Northside Generating Station 2 Baghouse, pulse Spray type LA R S Nelson 1A Baghouse, reverse air LA R S Nelson 2A Baghouse, reverse air CA Rio Bravo Jasmin CFB SNCR Baghouse, pulse CA Rio Bravo Poso CFB SNCR Baghouse, pulse LA Rodemacher 3a SNCR Baghouse, pulse LA Rodemacher 3b SNCR Baghouse, pulse MT Yellowstone Energy LP BLR1 Baghouse, pulse MT Yellowstone Energy LP BLR2 Baghouse, pulse

## 64

Attachment 8 . List of coal- fired electric utility ste amgenerating units selected for HCl/HF/HCN acid gas HAP testing
State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X Control PM Control 1 PM Control 2 FGD Type FGD Date FL Crystal River 5 Bituminous Coal Electrostatic precipitator, cold side Spray type 12/31/2009 TX Oak Grove 1 Li gnite Coal SCR Baghouse, pulse Spray dryer type 12/31/2009 AR Plum Point Energy STG1 Subbituminous Coal SCR Baghouse, pulse Spray dryer type 12/31/2009 AZ Springerville 4 Subbituminous Coal Bituminous Coal SCR Baghouse, pulse Spray dryer type 12/31/2009 WY Two Elk Generating Station 1 Subbituminous Coal SCR Baghouse, pulse Spray type 12/31/2009 AZ Cholla 3 Subbituminous Coal Baghouse, pulse Spray dryer type 9/1/2008 AZ Cholla 4 Subbituminous Coal Baghouse, pulse Spray dryer type 9/1/2008 TX Sandow Station 5 A Li gnite Coal SCR Baghouse, pulse Spray type 8/31/2009 TX Sandow Station 5 B Li gnite Coal SCR Baghouse, pulse Spray type 8/31/2009 WI Elm Road Generating Station 1 Bituminous Coal SCR Baghouse, pulse Spray type 6/1/2009 NC G. G. Allen 1 Bituminous Coal Electrostatic precipitator, cold side Spray type 5/1/2009 NE Nebraska City 2 Subbituminous Coal Baghouse, pulse Spray type 5/1/2009 GA Wansley 2 Bituminous Coal SCR Electrostatic precipitator, cold side Jet Bubbling Reactor 5/1/2009 GA Bowen 2BLR Bituminous Coal SCR Electrostatic precipitator, cold side Jet Bubbling Reactor 4/1/2009 OH Conesville 4 Bituminous Coal Electrostatic precipitator, cold side Jet Bubbling Reactor 4/1 /2009 SC Cross 4 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type 1/1/2009 IL Dallman 34 Bituminous Coal SCR Baghouse, pulse Packed type 1/1/2009 VA Cogentrix Hopewell 1A Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008 VA Cogentrix Hopewell 1B Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008 VA Cogentrix Hopewell 1C Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008 VA Cogentrix Virginia Leasing

Corporation 2A Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008 VA Cogentrix Virginia Leasing

Corporation 2B Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008 VA Cogentrix Virginia Leasing

Corporation 2C Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2008 GA Bowen 4BLR Bituminous Coal SCR Electrostatic precipitator, cold side Jet Bubbling Reactor 12/1/2008 WV John E Amos 1 Bituminous Coal SCR Electrostatic precipitator, cold side Tray type 12/1/2008 WV John E Amos 2 Bituminous Coal SCR Electrostatic precipitator, cold side Tray type 12/1/2008

## 65

State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X Control PM Control 1 PM Control 2 FGD Type FGD Date GA Wansley 1 Bituminous Coal SCR Electrostatic precipitator, cold side Jet Bubbling Reactor 12/1/2008 NV TS Power Plant BLR100 Subbituminous Coal SCR Baghouse, pulse Spray dryer type 6/1/2008 WI Weston 4 B ituminous Coal Subbituminous Coal SCR Baghouse, pulse Spray dryer type 6/1/2008 KY Ghent 4 Bituminous Coal Subbituminous Coal Electrostatic precipitator, hot side Spray type 5/1/2008 GA Bowen 3BLR Bituminous Coal SCR Electrostatic precipitator, cold side Jet Bubbling Reactor 4/1/2008 KY H. L. Spurlock 4 Bituminous Coal SNCR Baghouse, pulse CFB 4/1/2008 NC Belews Creek 1 Bituminous Coal Electrostatic precipitator, cold side Spray type 1/1/2008 GA Hammond 1 Bituminous Coal Electrostatic precipitator, cold side Spray type 1/1/2008 GA Hammond 2 Bituminous Coal Electrostatic precipitator, cold side Spray type 1/1/2008 GA Hammond 3 Bituminous Coal Electrostatic precipitator, cold side Spray type 1/1/2008 GA Hammond 4 Bituminous Coal Electrostatic precipitator, cold side Spray type 1/1/2008 VA Cogentrix Hopewell 2A Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007 VA Cogentrix Hopewell 2B Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007 VA Cogentrix Hopewel l 2C Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007 VA Cogentrix Virginia Leasing

Corporation 1A Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007 VA Cogentrix Virginia Leasing

Corporation 1B Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007 VA Cogentrix Virginia Leasing

Corporation 1C Bituminous Coal Baghouse, pulse Spray dryer type 12/31/2007 WY Wygen II 4 Subbituminous Coal SCR Baghouse, pulse Spray type 12/31/2007 OH Cardinal 2 Bituminous Coal SCR Ele ctrostatic precipitator, cold side Jet Bubbling Reactor 12/1/2007 WV John E. Amos 3 Bituminous Coal SCR Electrostatic precipitator, cold side Tray type 12/1/2007
IA Louisa 101 Subbituminous Coal Baghouse, pulse Electrostatic precipitator, hot side Spray dryer type 12/1/2007
OH Cardinal 1 Bituminous Coal SCR Electrostatic precipitator, cold side Jet Bubbling Reactor 11/1/2007 IA Council Bluffs 4 Subbituminous Coal SCR Baghouse, pulse Spray dryer type 6/1/2007 KY Ghent 3 Bituminous Coal Subbituminous Coal Electrostatic precipitator, hot side Spray type 5/1/2007 WV Mitchell 1 Bituminous Coal Electrostatic precipitator, cold side Tray type 4/1/2007 SC Cross 3 Bituminous Coal Coal

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

## 66

State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X Control PM Control 1 PM Control 2 FGD Type FGD Date WI Pleasant Prairie 2 Subbituminous Coal SCR Electrostatic precipitator, cold side Spray type 3 /31/2007 WV Mountaineer 1 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type 1/1/2007 AZ Springerville 3 Subbituminous Co al SCR Baghouse, pulse Spray dryer type 12/31/2006 WV Mitchell 2 Bituminous Coal Electrostatic precipitator, cold side Tray type 12/1/2006 WI Pleasant Prairie 1 Subbituminous Coal SCR Electrostatic precipitator, cold side Spray type 11/31/2006
NC Marshall 1 Bituminous Coal Multiple cyclone Electrostatic precipitator, cold side Spray type 11/1/2006
MT Hardin Generator Project PC1 Subbituminous Coal SCR Baghouse, pulse Spray dryer type 2/1/2006 NC Asheville 1 Bituminous Coal Electrostatic precipitator, cold side Spray type 11/1/2005 KY H. L. Spurlock 3 Bituminous Coal SNCR Baghouse, pulse CFB 4/1/2005 PA Seward 1 Waste Coal Bituminous Coal SNCR Baghouse, pulse Spray dryer type 3/1/2004 PA Seward 2 Waste Coal Bituminous Coal SNCR Baghou se, pulse Spray dryer type 3/1/2004 IL Marion 123 Waste Coal Bituminous Coal Baghouse, pulse CFB 5/1/2003 WY Wygen I 3 Subbituminous Coal SCR Baghouse, pulse Spray type 5/1/2003 CO Arapahoe 3 Subbituminous Coal Natural Gas Baghouse, reverse air Dry Sorbent I njection System 1/1/2003 CO Cherokee 2 Bituminous Coal Natural Gas Baghouse, reverse air Dry sodium injection 1/1/2003 CO Cherokee 4 Bituminous Coal Natural Gas Baghouse, reverse air Spray dryer type 1/1/2003 PR AES Puerto Rico (Aurora) 1 Bituminous Coal SNCR Baghouse, pulse CFB 12/31/2002 PR AES Puerto Rico (Aurora) 2 Bituminous Coal SNCR Baghouse, pulse CFB 12/31/2002 CO Valmont 5 Subbituminous Coal Bituminous Coal Baghouse, reverse air Spray dryer type 8/1/2002 CO Cherokee 3 B ituminous Coal Natural Gas Baghouse, reverse air Spray dryer type 7/1/2002 WA Transalta Centralia

Generation BW21 Subbituminous Coal Wet scrubber Electrostatic precipitator, cold side Spray type 6/1/2002 MS Red Hills Generating Facility AA001 Li gnite Coal Baghouse, reverse air CFB 3/1/2002 MS Red Hills Generating Facility AA002 Li gnite Coal Baghouse, reverse air CFB 3/1/2002 WV Mt. Storm 1 Bituminous Coal Electrostatic precipitator, cold side Spray type 2/1/2002 WV Mt. Storm 2 Bituminous C oal Electrostatic precipitator, cold side Spray type 2/1/2002
WA Transalta Centralia

Generation BW22 Subbituminous Coal Wet scrubber Electrostatic precipitator, cold side Spray type 10/1/2001

## 67

State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X Control PM Control 1 PM Control 2 FGD Type FGD Date PA Homer City Station 3 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type 9/1/2001 IL Dallman 31 Bituminous Coal SCR Electrostatic precipitator, cold side Packed type 6/1/2001 IL Dallman 32 Bituminous Coal SCR Electrostatic precipitator, cold side Packed type 6/1/2001 MO Hawthorn 5A S ubbituminous Coal Natural Gas SCR Baghouse, pulse Spray dryer type 6/1/2001 AK Healy 1 Subbituminous Coal Baghouse, reverse air Spray dryer type 9/1/2000 MD AES Warrior Run

Cogeneration Facility BLR1 Bituminous Coal SNCR and SCR Baghouse, reverse air CFB 2/1/2000 FL Big Bend BB01 Bituminous Coal Subbituminous Coal Electrostatic precipitator, cold side Spray type 12/1/1999 FL Big Bend BB02 Bituminous Coal Subbituminous Coal Electrostatic precipitator, cold side Spray type 12/1/1999 AZ Navajo 1 Bituminous Coal Electrostatic precipitator, hot side Spray type 8/1/1999 CO Hayden H2 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air Spray dryer type 6/1/1999 OH Hamilton 9 Bituminous Coal Natural Gas Electrostatic precipitator, hot side Baghouse, pulse Dry gas absorption 4/1/1999 CO Hayden H1 Bituminous Coal Natural Gas Baghouse, reverse air Spray dryer type 12/1/1998 AZ Navajo 2 Bituminous Coal Electrostatic precipitator, hot side Spray type 11/1/1998 NM San Juan 1 Subbituminou s Coal Electrostatic precipitator, hot side Spray type 10/1/1998 NM San Juan 2 Subbituminous Coal Electrostatic precipitator, hot side Spray type 10/1/1998 NM San Juan 3 Subbituminous Coal Electrostatic precipitator, hot side Spray type 10/1/199 8 NM San Juan 4 Subbituminous Coal Electrostatic precipitator, hot side Spray type 10/1/1998 CO Cherokee 1 Bituminous Coal Natural Gas Baghouse, reverse air Dry sodium injection 2/1/1998 AZ Navajo 3 Bituminous Coal Electrostatic precipitator, hot side Spray type 11/1/1997 VA Birchwood Power 1A Bituminous Coal SCR Baghouse, reverse air Spray dryer type 12/1/1996 FL Stanton Energy Center 2 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type 6/1/1996 IN AES Petersburg 1 Bituminous Coal Electrostatic precipitator, cold side Spray type 5/1/1996 IN AES Petersburg 2 Bituminous Coal Electrostatic precipitator, cold side Spray type 5/1/1996 VA Clover 2 Bituminous Coal Baghouse, reverse air Spray type 3/1/1996 FL Indiantown Cogeneration LP AAB01 Bituminous Coal SCR Baghouse, reverse air Spray dryer type 12/1/1995 PA Conemaugh 2 Bituminous Coal Electrostatic precipitator, cold side Wet scrubber Spray type 11/1/1995 SC Cope COP1 Bituminous Coal Natural Gas Baghouse, reverse air Spray dryer type 11/1/1995

## 68

State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X Control PM Control 1 PM Control 2 FGD Type FGD Date WY Neil Simpson II 2 Subbituminous Coal Electrostatic precipitator, cold side Circulating Dry Scrubber 11/1/1995 VA Clover 1 Bituminous Coal Baghouse, reverse air Spray type 10/1/1995 PA Northampton Generating

Company BLR1 Waste Coal Petroleum Coke SNCR Baghouse, pulse CFB 8/1/1995 NY AES Cayuga 1 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type 6/1/1995 NY AES Cayuga 2 Bituminous Coal Electrostatic precipitator, cold side Spray typ e 6/1/1995 KY HMP&L Station Two

Henderson H1 Bituminous Coal Electrostatic precipitator, cold side Tray type 6/1/1995 KY HMP&L Station Two

Henderson H2 Bituminous Coal Electrostatic precipitator, cold side Tray type 6/1/1995 NC Roanoke Valley II B LR2 Bituminous Coal Baghouse, pulse Circulating Dry Scrubber 6/1/1995 PA Colver Power Project ABB01 Waste Coal Baghouse, pulse CFB 5/1/1995 SC Cross 1 Bituminous Coal Coal

-based Synfuel SCR Electrostatic precipitator, cold side Spray type 5/1/1995 OH General James M Gavin 2 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type 3/1/1995 NJ B. L . England 2 Bituminous Coal SNCR Electrostatic precipitator, cold side Spray type 1/1/1995 TN Cumberland 1 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type 1/1/1995 TN Cumberland 2 Bituminous Coal Electrostatic precipitator, cold side Spray type 1/1/1995 IN F. B. Culley 2 Bituminous Coal Electrostatic precipitator, cold side Spray type 1/1/1995 IN F. B. Culley 3 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type 1/1/1995 IN Gibson 4 Bituminous Coal Electrostatic precipitator, cold side Spray type 1/1/1995 WV Mt Storm 3 Bituminous Coal Electrostatic precipitator, cold side Spray type 1/1/1995 PA Conemaugh 1 Bituminous Coal Electrostatic precipitator, cold side Wet scrubber Spray type 12/1/1994 OH General James M Gavin 1 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type 12/1/1994 KY Ghent 1 Bituminous Coal E lectrostatic precipitator, cold side Spray type 12/1/1994 KY Elmer Smith 1 Bituminous Coal SCR Electrostatic precipitator, cold side Spray type 11/1/1994 KY Elmer Smith 2 Bituminous Coal SNCR Electrostatic precipitator, cold side Spray type 11/1/199 4 WV Harrison Power Station 1 Bituminous Coal SCR Electrostatic precipitator, cold side Wet scrubber Spray type 11/1/1994 WV Harrison Power Station 2 Bituminous Coal SCR Electrostatic precipitator, cold side Wet scrubber Spray type 11/1/1994 WV Harris on Power Station 3 Bituminous Coal SCR Electrostatic precipitator, cold side Wet scrubber Spray type 11/1/1994

## 69

State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X Control PM Control 1 PM Control 2 FGD Type FGD Date IN Whitewater Valley 2 Bituminous Coal Electrostatic precipitator, cold side Spray dryer type 10/1/1994 NJ Logan Generating Plant B01 Bituminous Coal SCR Baghouse, reverse air Spray dryer type 9/1/1994 NC Roanoke Valley I BLR1 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air Circulating Dry Scrubber 5/1/1994 NJ Chambers Cogeneration LP BOIL1 Bituminous Coal SCR Baghouse, reverse air Spray dryer type 3/1/1994 NJ Chambers Cogeneration LP BOIL2 Bituminous Coal SCR Baghouse, reverse air Spray dryer type 3/1/1994 FL Cedar Bay Generating LP CBA Bituminous Coal SNCR Baghouse, reverse air Circulating Dry Scrubber 2/1/1994 FL Ce dar Bay Generating LP CBB Bituminous Coal SNCR Baghouse, reverse air Circulating Dry Scrubber 2/1/1994 FL Cedar Bay Generating LP CBC Bituminous Coal SNCR Baghouse, reverse air Circulating Dry Scrubber 2/1/1994 CO Arapahoe 4 Subbituminous Coal Natural Gas Baghouse, reverse air Dry Sorbent I njection System 6/1/1993 PA Scrubgrass Generating UNIT 1 Waste Coal SNCR Baghouse, pulse CFB 6/1/1993 PA Scrubgrass Generating UNIT 2 Waste Coal SNCR Baghouse, pulse CFB 6/1/1993 UT Sunnyside Cogen Associates 1 Waste Coal Baghouse, pulse CFB 2/1/1993 WV North Branch 1A Bituminous Coal Waste Oil Baghouse, pulse CFB 12/31/1992 WV North Branch 1B Bituminous Coal Waste Oil Baghouse, pulse CFB 12/31/1992 TX J. K. Spruce BLR1 Subbituminous Coal Baghous e, reverse air Spray type 12/1/1992 VA Mecklenburg Power Station BLR1 Bituminous Coal Baghouse, pulse Circulating Dry Scrubber 11/1/1992 VA Mecklenburg Power Station BLR2 Bituminous Coal Baghouse, pulse Circulating Dry Scrubber 11/1/1992 PA Piney Creek Project BRBR1 Waste Coal SNCR Baghouse, pulse Circulating Dry Scrubber 11/1/1992 GA Yates Y1BR Bituminous Coal Natural Gas Electrostatic precipitator, cold side Wet scrubber Jet Bubbling Reactor 10/1/1992 HI AES Hawaii BLRA Subbituminous Coal Tire

- derived Fuels SNCR Baghouse, reverse air CFB 9/1/1992 HI AES Hawaii BLRB Subbituminous Coal Waste Oil SNCR Baghouse, reverse air CFB 9/1/1992 VA Cogentrix of Richmond 3A Bituminous Coal Baghouse, pulse Spray dryer type 8/1/1992 VA Cogentrix of Richmond 3B Bituminous Coal Baghouse, pulse Spray dryer type 8/1/1992 VA Cogentrix of Richmond 4A Bituminous Coal Baghouse, pulse Spray dryer type 8/1/1992 VA Cogentrix of Richmond 4B Bituminous Coal Baghouse, pulse Spray dryer type 8/1/1992 WV Grant Town Power Plant BLR1A Waste Coal Baghouse, pulse CFB 8/1/1992 WV Grant Town Power Plant BLR1B Waste Coal Baghouse, pulse CFB 8/1/1992 IN Bailly 7 Bituminous Coal Natural Gas Electrostatic precipitator, cold side Packed type 6/1/1992

## 70

State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X Control PM Control 1 PM Control 2 FGD Type FGD Date IN B ailly 8 Bituminous Coal Natural Gas SCR Electrostatic precipitator, cold side Packed type 6/1/1992 PA Panther Creek Energy

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

Facility BLR2 Waste Coal SNCR Baghouse, pulse Circulating Dry Scrubber 6/1/1992 VA Cogentrix of Richmond 1A Bituminous Coal Baghouse, pulse Spray dryer type 5/1/1992 VA Cogentrix of Richmond 1B Bituminous Coal Baghouse, pulse Spray dryer type 5/1/1992 VA Cogentrix of Richmond 2A Bituminous Coal Baghouse, pulse Spray dryer type 5/1/1992 VA Cogentrix of Richmond 2B Bituminous Coal Baghouse, pulse Spray dryer type 5/1/1992 VA Altavista Power Station 1 Bituminous Coal SNCR Baghouse, pulse Spray dryer type 2/1/1992 WV Morgantown Energy Facility CFB1 Waste Coal Baghouse, pulse CFB 1/1/1992 WV Morgantown Energy Facility CFB2 Waste Coal Baghouse, pulse CFB 1/1/1992 TX Twin Oaks Power One U2 Li gnite Coal Baghouse, shake and deflate CFB 10/1/1991 VA Southamp ton Power Station 1 Bituminous Coal Baghouse, pulse Spray dryer type 6/1/1991 PA Ebensburg Power 031 Waste Coal Baghouse, pulse CFB 5/1/1991 PA Cambria Cogen B1 Waste Coal SNCR Baghouse, shake and deflate CFB 3/1/1991 PA Cambria Cogen B2 Waste C oal SNCR Baghouse, shake and deflate CFB 3/1/1991 OH W. H. Zimmer 1 Bituminous Coal Electrostatic precipitator, cold side Spray type 3/1/1991

## 71

Attachment 9 . List of coal- fired electric utility steam generating units selected for dioxin/furan organi c HAP testing
State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X

Control PM Control 1 PM Control 2 FGD_Type01 ACI CA ACE Cogeneration Facility CFB Bituminous Coal Petroleum Coke Baghouse, reverse air CFB CT AES Thames A Bituminous Coal Baghouse, reverse air Circulating Dry Scrubber CT AES Thames B Bituminous Coal Baghouse, reverse air Circulating Dry Scrubber VA Altavista Power Station 1 Bituminous Coal SNCR Baghouse, pulse Spray dryer type NY Black River Generation E0003 Bituminous Coal Baghouse, pulse Multiple cyclone Jet Bubbling Reactor VA Chesterfield 6 Bituminous Coal Electrostatic precipitator, cold side NC Cogentrix Dwayne Collier Battle Cogen 1A Bituminous Coal Baghouse, pulse Spray dryer type
VA Cogentrix o f Richmond 4A Bituminous Coal Baghouse, pulse Spray dryer type IA Council Bluffs 4 Subbituminous Coal SCR Baghouse, pulse Spray dryer type Y CO Craig C2 Subbituminous Coal Baghouse, pulse Spray type TN Cumberland 1 Bituminous Coal SCR Electro static precipitator, cold side Spray type WY Dave Johnston BW41 Subbituminous Coal Electrostatic precipitator, cold side DE Edge Moor 4 Bituminous Coal Residual Fuel Oil Electrostatic precipitator, cold side Y KY Green River 5 Bituminous Coal Electrostatic precipitator, hot side KY H. L. Spurlock 2 Bituminous Coal SCR Electrostatic precipitator, hot side Spray dryer type IL Havana 9 Subbituminous Coal SCR Electrostatic precipitator, hot side Baghouse, pulse Y IL Hennepin Power Station 2 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side MN Hoot Lake 3 Subbituminous Coal Electrostatic precipitator, cold side TX J. K. Spruce BLR1 Subbituminous Coal Baghouse, reverse air Spray type WV Kammer 1 Bituminous Coal Electrostatic precipitator, cold side WV Kammer 2 Bituminous Coal Electrostatic precipitator, cold side IL Marion 4 Bituminous Coal Waste Coal SCR Electrostatic precipitator, cold side Venturi type ND Milton R Young B1 Li gnite Coal Electrostatic precipitator, cold side MI Monroe 3 Subbituminous Coal Bituminous Coal SCR Electrostatic precipitator, cold side OK Northeastern 3314 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side IA Prairie Creek 4 Subbit uminous Coal Landfill Gas Electrostatic precipitator, cold side NC Primary Energy Southport 1C Bituminous Coal Baghouse, pulse N/A

## 72

State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X

Control PM Control 1 PM Control 2 FGD_Type01 ACI CO Ray D. Nixon 1 Subbituminous Coal Baghouse, reverse air NC Roanoke Valley I BLR1 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air Circulating Dry Scrubber GA Scherer 1 Subbituminous Coal Electrostatic precipitator, hot side Y GA Scherer 3 Subbituminous Coal Electrostatic precipitator, cold side Spray type Y PA Shawville 3 Bituminous Coal Electrostatic precipitator, cold side MN Silver Bay Power BLR2 Subbituminous Coal Natural Gas Baghouse, reverse air ND Stanton 1 Subbituminous Coal Electrostatic precipitator, cold side IN State Line Energy 3 Subbituminous Coal Baghouse, pulse IA Streeter Station 7 Bituminous Coal Subbituminous Coal Electrostatic precipitator, hot side KS Tecumseh Energy Center 9 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side MI TES Filer City Station 2 Bituminous Coal Baghouse, pulse Spray dryer type WA Transalta Centralia Generation BW21 Subbituminous Coal Wet scrubber Electrostatic precipitator, cold side Spray type NY Trigen Syracuse Energy 2 Bituminous Coal Baghouse, reverse air N/A TX Twin Oaks Power One U2 Li gnite Coal Baghouse, shake and deflate CFB WY Two Elk Generating Station 1 Subbituminous Coal SCR Baghouse, pulse Spray type IL Vermilion 1 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side Baghouse, pulse Y OH Walter C Beckjord 5 Bituminous Coal Electrostatic precipitator, cold side IL Waukegan 8 Subbituminous Coal Electrostatic precipitator, cold side AL Widows Creek 2 Bituminous Coal Electrostatic precipitator, cold side AL Widows Creek 7 Bituminous Coal Electrostatic precipitator, cold side Wet scrubber Spray type AL Widows Creek 8 Bituminous Coal Wet scrubber Tray type SC Winyah 1 Bituminous Coal Coal

-based Synfuel Electrostatic precipitator, cold side Wet scrubber Venturi type SC Winyah 2 Bituminous Coal Coal

-based Synfuel Electrostatic precipitator, cold side

### Shaded unit

s are required to do all organic testing. 

## 73 Attachment 10. List of coal- fired electric utility steam generating units selected for non - dioxin/furan organic HAP testing
State Plant Name B oiler ID Primary Fuel Secon dary Fuel Boiler Date NO X Control PM Control 1 PM Control 2 FGD Type TX Oak Grove 1 Li gnite Coal 12/31/2009 SCR Baghouse, pulse Spray dryer type AR Plum Point Energy STG1 Subbituminous Coal 12/31/2009 SCR Baghouse, pulse Spray dryer type AZ Springer

ville 4 Subbituminous Coal Bituminous Coal 12/31/2009 SCR Baghouse, pulse Spray dryer type WY Two Elk Generating Station 1 Subbituminous Coal 12/31/2009 SCR Baghouse, pulse Spray type TX Sandow Station 5 A Li gnite Coal 8/31/2009 SCR Baghouse, pulse Spray type TX Sandow Station 5 B Li gnite Coal 8/31/2009 SCR Baghouse, pulse Spray type WI Elm Road Generating Station 1 Bituminous Coal 6/1/2009 SCR Baghouse, pulse Spray type NE Nebraska City 2 Subbituminous Coal 5/1/2009 Baghouse, pulse Spray typ e SC Cross 4 Bituminous Coal 1/1/2009 SCR Electrostatic precipitator, cold side Spray type IL Dallman 34 Bituminous Coal 1/1/2009 SCR Baghouse, pulse Packed type NV TS Power Plant BLR100 Subbituminous Coal 6/1/2008 SCR Baghouse, pulse Spray dryer type WI Weston 4 Bituminous Coal Subbituminous Coal 6/1/2008 SCR Baghouse, pulse Spray dryer type KY H. L. Spurlock 4 Bituminous Coal 4/1/2008 SNCR Baghouse, pulse CFB WY Wygen II 4 Subbituminous Coal 12/31/2007 SCR Baghouse, pulse Spray type IA C ouncil Bluffs 4 Subbituminous Coal 6/1/2007 SCR Baghouse, pulse Spray dryer type SC Cross 3 Bituminous Coal Coal

-based Synfuel 1/1/2007 SCR Electrostatic precipitator, cold side Spray type AZ Springerville 3 Subbituminous Coal 12/31/2006 SCR Baghouse , pulse Spray dryer type MT Hardin Generator Project PC1 Subbituminous Coal 4/1/2006 SCR Baghouse, pulse Spray dryer type KY H. L. Spurlock 3 Bituminous Coal 4/1/2005 SNCR Baghouse, pulse CFB PA Seward 1 Waste Coal Bituminous Coal 3/1/2004 SNCR Baghouse, pulse Spray dryer type PA Seward 2 Waste Coal Bituminous Coal 3/1/2004 SNCR Baghouse, pulse Spray dryer type IL Marion 123 Waste Coal Bituminous Coal 5/1/2003 Baghouse, pulse CFB WY Wygen I 3 Subbituminous Coal 5/1/2003 SCR Baghouse, pulse Spray type PR AES Puerto Rico (Aurora) 1 Bituminous Coal 12/31/2002 SNCR Baghouse, pulse CFB PR AES Puerto Rico (Aurora) 2 Bituminous Coal 12/31/2002 SNCR Baghouse, pulse CFB

### Shaded unit

s are required to do all organic testing. 

## 74 State Plant Name B oiler ID Primary Fuel Secon dary Fuel Boiler Date NO X Control PM Control 1 PM Control 2 FGD Type MS Red Hills Generating Facility AA001 Li gnite Coal 3/1/2002 Baghouse, reverse air CFB
MS Red Hills Generating Facility AA002 Li gnite Coal 3/1/2002 Baghouse, reverse air CFB MO Hawthorn 5A Subbituminous Coal Natural Gas 6/1/2001 SCR Baghouse, pulse Spray dryer type
MD AES Warrior Run Cogeneration Facility BLR1 Bituminous Coal 2/1/2000 SCR and SNCR Baghouse, reverse air CFB
VA Birchwood Power 1A Bituminous Coal 12/1/1996 SCR Baghouse, reverse air Spray dryer type FL Stanton Energy Center 2 Bituminous Coal 6/1/1996 SCR Electrostatic precipitator, cold side Spray type VA Clover 2 Bituminous Coal 3/1/1996 Baghouse, reverse air Spray type FL Indiantown Cogeneration LP AAB01 Bituminous Coal 12/1/1995 SCR Baghouse, reverse air Spray dryer type SC Cope COP1 Bituminous Coal Natural Gas 11/1/1995 Baghouse, reverse air Spray dryer type WY Neil Simpson II 2 Subbituminous Coal 11/1/1995 Electrostatic precipitator, cold side Circulating Dry Scrubber VA Clover 1 Bituminous Coal 10/1/1995 Baghouse, reverse air Spray type PA Northampton Generating Company BLR1 Waste Coal Petroleum Coke 8/1/1995 SNCR Baghouse, pulse CFB
NC Roanoke Valley II BLR2 Bituminous Coal 6/1/1995 Baghouse, pulse Circulating Dry Scrubber PA Colver Power Project ABB01 Waste Coal 5/1/1995 Baghouse, pulse CFB SC Cross 1 Bituminous Coal Coal

-based Synfuel 5/1/1995 SCR Electrostatic precipitator, cold side Spray type
NJ Logan Generating Plant B01 Bituminous Coal 9/1/1994 SCR Baghouse, reverse air Spray dryer type
NC Roanoke Valley I BLR1 Bituminous Coal Distillate Fuel Oil 5/1/1994 Baghouse, reverse air Circulating Dry Scrubber NJ Chambers Cogeneration LP BOIL1 Bituminous Coal 3/1/1994 SCR Baghouse, reverse air Spray dryer type
NJ Chambers Cogeneration LP BOIL2 Bituminous Coal 3/1/1994 SCR Baghouse, reverse air Spray dryer ty pe FL Cedar Bay Generating LP CBA Bituminous Coal 1/1/1994 SNCR Baghouse, reverse air Circulating Dry Scrubber FL Cedar Bay Generating LP CBB Bituminous Coal 1/1/1994 SNCR Baghouse, reverse air Circulating Dry Scrubber

### Shaded unit

s are required to do all organic testing. 

## 75 State Plant Name B oiler ID Primary Fuel Secon dary Fuel Boiler Date NO X Control PM Control 1 PM Control 2 FGD Type FL Cedar Bay Generating LP CBC Bituminous Coal 1/1/1994 SNCR Baghouse, reverse air Circulating Dry Scrubber PA Scrubgrass Generating UNIT 1 Waste Coal 6/1/1993 SNCR Baghouse, pulse CFB PA Scrubgrass Generating UNIT 2 Waste Coal 6/1/1993 SNCR Baghouse, pulse CFB
UT Sunnyside Co gen Associates 1 Waste Coal 2/1/1993 Baghouse, pulse CFB WV North Branch 1A Bituminous Coal Waste Oil 12/31/1992 Baghouse, pulse CFB WV North Branch 1B Bituminous Coal Waste Oil 12/31/1992 Baghouse, pulse CFB TX J. K. Spruce BLR1 Subbituminous Co al 12/1/1992 Baghouse, reverse air Spray type PA Piney Creek Project BRBR1 Waste Coal 12/1/1992 SNCR Baghouse, pulse Circulating Dry Scrubber VA Mecklenburg Power Station BLR1 Bituminous Coal 11/1/1992 Baghouse, pulse Circulating Dry Scrubber VA Mecklenburg Power Station BLR2 Bituminous Coal 11/1/1992 Baghouse, pulse Circulating Dry Scrubber HI AES Hawaii BLRA Subbituminous Coal Tire

- derived Fuels 9/1/1992 SNCR Baghouse, reverse air CFB HI AES Hawaii BLRB Subbituminous Coal Waste Oil 9/1/19 92 SNCR Baghouse, reverse air CFB VA Cogentrix of Richmond 3A Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer type VA Cogentrix of Richmond 3B Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer type VA Cogentrix of Richmond 4A Bituminous C oal 8/1/1992 Baghouse, pulse Spray dryer type VA Cogentrix of Richmond 4B Bituminous Coal 8/1/1992 Baghouse, pulse Spray dryer type WV Grant Town Power Plant BLR1A Waste Coal 8/1/1992 Baghouse, pulse CFB WV Grant Town Power Plant BLR1B Waste Co al 8/1/1992 Baghouse, pulse CFB PA Panther Creek Energy Facility BLR1 Waste Coal 6/1/1992 SNCR Baghouse, pulse Circulating Dry Scrubber PA Panther Creek Energy Facility BLR2 Waste Coal 6/1/1992 SNCR Baghouse, pulse Circulating Dry Scrubber VA Cogentrix of Richmond 1A Bituminous Coal 5/1/1992 Baghouse, pulse Spray dryer type VA Cogentrix of Richmond 1B Bituminous Coal 5/1/1992 Baghouse, pulse Spray dryer type VA Cogentrix of Richmond 2A Bituminous Coal 5/1/1992 Baghouse, pulse Spray dryer type VA Cogentrix of Richmond 2B Bituminous Coal 5/1/1992 Baghouse, pulse Spray dryer type VA Altavista Power Station 1 Bituminous Coal 2/1/1992 SNCR Baghouse, pulse Spray dryer type

### Shaded unit

s are required to do all organic testing. 

## 76 State Plant Name B oiler ID Primary Fuel Secon dary Fuel Boiler Date NO X Control PM Control 1 PM Control 2 FGD Type WV Morgantown Energy Facility CFB1 Waste Coal 1/1/1992 Baghou se, pulse CFB WV Morgantown Energy Facility CFB2 Waste Coal 1/1/1992 Baghouse, pulse CFB TX Twin Oaks Power One U2 Li gnite Coal 10/1/1991 Baghouse, shake and deflate CFB VA Southampton Power Station 1 Bituminous Coal 6/1/1991 Baghouse, pulse Spray dryer type MD Brandon Shores 2 Bituminous Coal 5/1/1991 SCR Electrostatic precipitator, hot side Spray type PA Ebensburg Power 031 Waste Coal 5/1/1991 Baghouse, pulse CFB PA Cambria Cogen B1 Waste Coal 3/1/1991 SNCR Baghouse, shake and deflate CFB PA Cambria Cogen B2 Waste Coal 3/1/1991 SNCR Baghouse, shake and deflate CFB AL James H Miller Jr. 4 Subbituminous Coal 3/1/1991 SCR Electrostatic precipitator, cold side Spray type OH W. H. Zimmer 1 Bituminous Coal 3/1/1991 Electrostatic precipitator, cold side Spray type OK AES Shady Point 1A Bituminous Coal 1/1/1991 Baghouse, pulse CFB OK AES Shady Point 1B Bituminous Coal 1/1/1991 Baghouse, pulse CFB OK AES Shady Point 2A Bituminous Coal 1/1/1991 Baghouse, pulse CFB OK AES Shady Point 2B Bituminous Coal 1/1/1991 Baghouse, pulse CFB CO Nucla 1 Bituminous Coal 1/1/1991 Baghouse, shake and deflate CFB NY Trigen Syracuse Energy 1 Bituminous Coal 1/1/1991 Baghouse, reverse air N/A

NY Trigen Syracuse Energy 2 Bituminou s Coal 1/1/1991 Baghouse, reverse air N/A

NY Trigen Syracuse Energy 3 Bituminous Coal 1/1/1991 Baghouse, reverse air N/A

NY Trigen Syracuse Energy 4 Bituminous Coal 1/1/1991 Baghouse, reverse air N/A

NY Trigen Syracuse Energy 5 Bituminous Coal 1/1/1991 Baghouse, reverse air N/A KY Shawnee 10 Bituminous Coal 12/1/1990 Baghouse, reverse air CFB KY Trimble County 1 Bituminous Coal 12/1/1990 SCR Electrostatic precipitator, cold side Spray type NC Cogentrix Dwayne Collier Battle Cogen 1A B ituminous Coal 10/1/1990 Baghouse, pulse Spray dryer type

### Shaded unit

s are required to do all organic testing. 

## 77 State Plant Name B oiler ID Primary Fuel Secon dary Fuel Boiler Date NO X Control PM Control 1 PM Control 2 FGD Type NC Cogentrix Dwayne Collier Battle Cogen 1B Bituminous Coal 10/1/1990 Baghouse, pulse Spray dryer type
NC Cogentrix Dwayne Collier Battle Cogen 2A Bituminous Coal 10/1/1990 Baghouse, pulse Spray dryer type
NC Cogentrix Dwayne Collier Battle Cogen 2B Bituminous Coal 10/1/1990 Baghouse, pulse Spray dryer type
PA Foster Wheeler Mt Carmel Cogen SG

- 101 Waste Coal 9/1/1990 Baghouse, pulse Circulating Dry Scrubber TX Twin Oaks Power One U1 Li gnite Coal 9/1/1990 Baghouse, shake and deflate CFB
CA ACE Cogeneration Facility CFB Bituminous Coal Petroleum Coke 6/1/1990 Baghouse, reverse air CFB WI Manitowoc 8 Bituminous Coal Petroleum Coke 6/1/1990 Single cyclone Baghouse, pulse CFB AZ Springerville 2 Subbituminous Coal 6/1/1990 Baghouse, reverse air Spray dryer type MI TES Filer City Station 1 Bituminous Coal 6/1/1990 Baghouse, pulse Spray dryer type MI TES Filer City Station 2 Bituminous Coal 6/1/1990 Baghouse, pulse Spray dryer type NY WPS Power Niagara 1 Bituminous Coal 4/1/1990 SNCR Baghouse, pulse CFB CT AES Thames A Bituminous Coal 3/1/1990 Baghouse, reverse air Circulating Dry Scrubber CT AES Thames B Bituminous Coal 3/1/1990 Baghouse, reverse air Circulating Dry Scrubber MT Colstrip Energy LP BLR1 Waste Coal 2/1/1990 Baghouse, pulse CFB IN Rockport MB2 Subbituminous Coal 12/1/1989 Electrostatic precipitator, cold side N/A PA St. Nicholas Cogen Project 1 Waste Coal 12/1/1989 Baghouse, pulse CFB
PA Kline Township Cogen Facility 1 Waste Coal 11/1/1989 Single cyclone Baghouse, pulse CFB
AL James H Miller Jr. 3 Subbituminous Coal 5/1/1989 SCR Electrostatic precipitator, cold side Spray type GA Scherer 4 Subbituminous Coal 2/1/1989 Electrostatic precipitator, cold side Spray type PA Wheelabrator Frackville Energy BLR1 Waste Coal 9/1/1988 Baghouse, pulse CFB
NY Black River Generation E0001 Bituminous Coal 6/1/1988 Baghouse, pulse Multiple cyclone Jet Bubbling Reactor NY Black River Generation E0002 Bituminous Coal 6/1/1988 Baghouse, pulse Multiple cyclone Jet Bubbling Reactor

### Shaded unit

s are required to do all organic testing. 

## 78 State Plant Name B oiler ID Primary Fuel Secon dary Fuel Boiler Date NO X Control PM Control 1 PM Control 2 FGD Type NY Black River Generation E0003 Bituminous Coal 6/1/1988 Baghouse, pulse Multiple cyclone Jet Bubbling Reactor FL Central Power & Lime 1 Bituminous Coal 6/1/ 1988 Baghouse, reverse air N/A
VA Cogentrix Virginia Leasing Corporation 1A Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

VA Cogentrix Virginia Leasing Corporation 1B Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

VA Cogentrix Virginia Leasing Corporation 1C Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

VA Cogentrix Virginia Leasing Corporation 2A Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

VA Cogentrix Virginia Leasing Corporation 2B Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type

VA Cogentrix Virginia Leasing Corporation 2C Bituminous Coal 6/1/1988 Baghouse, pulse Spray dryer type
CA Mt. Poso Cogeneration BL01 Bituminous Coal 6/1/1988 SNCR Baghouse, reverse air CFB
PA WPS Westwood Generation LLC 031 Waste Coal 6/1/1988 Baghouse, reverse air N/A

FL St Johns River Power Park 2 Bituminous Coal Coal

-based Synfuel 5/1/1988 Electrostatic precipitator, cold side Spray type TX Fayette Power Project 3 Subbituminous Coal 4/1/1988 Electrostatic precipitator, cold side Spray type
PA John B Rich Memorial Power Station CFB1 Waste Coal 2/1/1988 Baghouse, pulse CFB
PA John B Rich Memorial Power Station CFB2 Waste Coal 2/1/1988 Baghouse, pulse CFB
VA Cogentrix Hopewell 1A Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type VA Cogentrix Hopewell 1B Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type VA Cogentrix Hopewell 1C Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type

### Shaded unit

s are required to do all organic testing. 

## 79 State Plant Name B oiler ID Primary Fuel Secon dary Fuel Boiler Date NO X Control PM Control 1 PM Control 2 FGD Type VA Cogentrix Hopewell 2A Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type VA Cogentrix Hopewell 2B Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type VA Cogentrix Hopewell 2C Bituminous Coal 12/1/1987 Baghouse, pulse Spray dryer type MN Sh erburne County 3 Subbituminous Coal 11/1/1987 Baghouse, reverse air Spray dryer type
NY Danskammer Generating Station 3 Bituminous Coal Natural Gas 9/1/1987 Electrostatic precipitator, cold side N/A
NC Primary Energy Southport 1A Bituminous Coal 9/ 1/1987 Baghouse, pulse N/A NC Primary Energy Southport 1B Bituminous Coal 9/1/1987 Baghouse, pulse N/A NC Primary Energy Southport 1C Bituminous Coal 9/1/1987 Baghouse, pulse N/A NC Primary Energy Southport 2A Bituminous Coal 9/1/1987 Baghouse , pulse N/A NC Primary Energy Southport 2B Bituminous Coal 9/1/1987 Baghouse, pulse N/A NC Primary Energy Southport 2C Bituminous Coal 9/1/1987 Baghouse, pulse N/A NC Primary Energy Roxboro 1A Bituminous Coal 8/1/1987 Baghouse, pulse N/A NC Primary Energy Roxboro 1B Bituminous Coal 8/1/1987 Baghouse, pulse N/A NC Primary Energy Roxboro 1C Bituminous Coal 8/1/1987 Baghouse, pulse N/A
PA AES Beaver Valley Partners Beaver Valley 2 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side Wet scrubber Spray type
PA AES Beaver Valley Partners Beaver Valley 3 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side Wet scrubber Spray type
PA AES Beaver Valley Partners Beaver Valley 4 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side Wet scrubber Spray type
PA AES Beaver Valley Partners Beaver Valley 5 Bituminous Coal Petroleum Coke 7/1/1987 Electrostatic precipitator, cold side Wet scrubber Spray type
FL Stanton Energy Center 1 Bituminous Coal 7/1/1987 Electrostatic precipitator, cold side Spray type UT Intermountain Power Project 2SGA Bituminous Coal Subbituminous Coal 5/1/1987 Baghouse, reverse air Spray type
NY Danskammer Generating Station 4 Bituminous Coal Natural Gas 3/1/1987 Electrostatic precipitator, cold side N/A
FL St. Johns River Power Park 1 Bituminous Coal Coal

-based Synfuel 3/1/1987 Electrostatic precipitator, cold side Spray type

### Shaded unit

s are required to do all organic testing. 

## 80 State Plant Name B oiler ID Primary Fuel Secon dary Fuel Boiler Date NO X Control PM Control 1 PM Control 2 FGD Type GA Scherer 3 Subbituminous Coal 1/1/1987 Electrostatic precipitator, cold side Spray type TX Oklaunion 1 Bituminous Coal 12/1/1986 Electrostatic precipitator, cold side Spray type KY D. B. Wilson W1 Bituminous Coal 11/1/1986 Electrostatic precipitator, cold side Spray type TX Limestone LIM2 Li gnite Coal S ubbituminous Coal 10/1/1986 Electrostatic precipitator, cold side Spray type ND Antelope Valley B2 Li gnite Coal 7/1/1986 Baghouse, reverse air Spray dryer type UT Intermountain Power Project 1SGA Bituminous Coal Subbituminous Coal 6/1/1986 Baghouse , reverse air Spray type UT Bonanza 1

- 1 Bituminous Coal 5/1/1986 Baghouse, reverse air Spray type IN AES Petersburg 4 Bituminous Coal 4/1/1986 Electrostatic precipitator, cold side Spray type MT Colstrip 4 Subbituminous Coal 4/1/1986 Wet scrubb er Venturi type LA Dolet Hills 1 Li gnite Coal Natural Gas 4/1/1986 Electrostatic precipitator, cold side Wet scrubber Spray type OK GRDA 2 Subbituminous Coal 4/1/1986 Electrostatic precipitator, cold side Spray dryer type IN A. B. Brown 2 Bituminou s Coal 2/1/1986 SCR Electrostatic precipitator, cold side Spray type IN R. M. Schahfer 18 Bituminous Coal 2/1/1986 Electrostatic precipitator, cold side Spray type TX Limestone LIM1 Li gnite Coal Subbituminous Coal 10/1/1985 Electrostatic precipitator, cold side Spray type MI Belle River 2 Subbituminous Coal 7/1/1985 Electrostatic precipitator, cold side N/A NV North Valmy 2 Bituminous Coal Subbituminous Coal 7/1/1985 Baghouse, reverse air Spray dryer type WI Pleasant Prairie 2 Subbituminous Coal 7/1/1985 Electrostatic precipitator, cold side Spray type TX Tolk 172B Subbituminous Coal 7/1/1985 Baghouse, reverse air N/A AZ Springerville 1 Subbituminous Coal 6/1/1985 Baghouse, reverse air Spray dryer type AL James H Miller Jr. 2 Subbituminous Coal 5/1/1985 Electrostatic precipitator, cold side N/A

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

S tate P lant Name B oiler ID Primary Fuel Secon dary Fuel NO X Control PM Control 1 PM Control 2 PM Control Date FGD Type TX Oak Grove 1 Li gnite Coal SCR Baghouse, pulse 12/31/2009 Spray dryer type AR Plum Point

Energy STG1 Subbituminous Coal SCR Baghouse, pulse 12/31/2009 Spray dryer type AZ Springerville 4 Subbituminous Coal Bituminous Coal SCR Baghouse, pulse 12/31/2009 Spray dryer type
WY Two Elk

Generating Station 1 Subbituminous Coal SCR Baghouse, pulse 12/31/2009 Spray type
AZ Cholla 3 Subbituminous Coal Baghouse, pulse 9/1/2008 Spray dryer type AZ Cholla 4 Subbituminous Coal Baghouse, pulse 9/1/2008 Spray dryer type TX Sandow Station 5 A Li gnite Coal SCR Baghouse, pulse 8/31/2009 Spray type TX Sandow Station 5 B Li gnite Coal SCR Baghouse, pulse 8/31/2009 Spray type
WI Elm Road

Generating Station 1 Bituminous Coal SCR Baghouse, pulse 6/1/2009 Spray type
NE Nebraska City 2 Subbituminous Coal Baghouse, pulse 5/1/2009 Spray type SC Cross 4 Bituminous Coal SCR Electrostatic precipitator, cold side 1/1/2009 Spray type IL Dallman 34 Bituminous Coal SCR Baghouse, pulse 1/1/2009 Packed type NM San Juan 1 Subbituminous Coal Baghouse, pulse 12/1/2008 Spray type NM San Juan 2 Subbituminous Coal Baghouse, pulse 12/1/2008 Spray type NM San Juan 3 Subbituminous Coal Baghouse, pulse 12/1/2008 Spray type NM San Juan 4 Subbituminous Coal Baghouse, pulse 12/1/2008 Spray type NV TS Power Plant BLR100 Subbituminous Coal SCR Baghouse, pulse 6/1/2008 Spray dryer type WI Weston 4 Bituminous Coal Subbituminous Coal S CR Baghouse, pulse 6/1/2008 Spray dryer type IL Hennepin

Power Station 2 Subb ituminous Coal Natural Gas Baghouse, pulse 6/1/2008 KY H. L. Spurlock 4 Bituminous Coal SNCR Baghouse, pulse 4/1/2008 CFB WY Wygen II 4 Subbituminous Coal SCR Baghouse, pulse 12/31/2007 Spray type
IA Louisa 101 Subbituminous Coal Baghouse, pulse Electrostatic precipitator, hot side 12/1/2007 Spray dryer type
IA Council Bluffs 4 Subbituminous Coal SCR Baghouse, pulse 6/1/2007 Spray dryer type SC Cross 3 Bituminous Coal Coal

-based Synfuel SCR Electrostatic precipitator, cold side 1/1/2007 Spray type AZ Springerville 3 Subbituminous Coal SCR Baghouse, pulse 12/31/2006 Spray dryer type

## 82

S tate P lant Name B oiler ID Primary Fuel Secon dary Fuel NO X Control PM Control 1 PM Control 2 PM Control Date FGD Type MT Hardin

Generator Project PC1 Subbituminous Coal SCR Baghouse, pulse 4/1/20 06 Spray dryer type
NC Asheville 1 Bituminous Coal Electrostatic precipitator, cold side 11/1/2005 Spray type
IN A. B. Brown 1 Bituminous Coal SCR Baghouse, pulse Electrostatic precipitator, cold side 6/1/2005 Spray type
KY H. L. Spurlock 3 Bituminous Coal SNCR Baghouse, pulse 4/1/2005 CFB KY Cane Run 5 Bituminous Coal Coal

-based Synfuel Electrostatic precipitator, cold side 6/1/2004 Spray type CO Craig C2 Subbituminous Coal Baghouse, pulse 5/1/2004 Spray type FL Crist 7 Bituminous Coal Natural Gas SCR Electrostatic precipitator, cold side 4/1/2004 PA Seward 1 Waste Coal Bituminous Coal SNCR Baghouse, pulse 3/1/2004 Spray dryer type PA Seward 2 Waste Coal Bituminous Coal SNCR Baghouse, pulse 3/1/2004 Spray dryer type CO Craig C1 Subbituminous Coal Baghouse, pulse 11/1/2003 Spray type IL Marion 123 Waste Coal Bituminous Coal Baghouse, pulse 5/1/2003 CFB KY H. L. Spurlock 1 Bituminous Coal SCR Electrostatic precipitator, cold side 4/1/2003 WY Wygen I 3 Subbituminous Coal SCR Baghouse, pulse 1/1/2003 Spray type PR AES Puerto

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

Rico (Aurora) 2 Bituminous Coal SNCR Baghouse, pulse 12/31/2002 CFB SD Big Stone 1 Subbituminous Coal Baghouse, pulse 10/1/2002 MD Herbert A

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

Centralia Generation BW21 Subbituminous Coal Wet scrubber Electrostatic precipitator, cold side 6/1/2002 Spray type

MS Red Hills

Generating Facility AA001 Li gnite Coal Baghouse, reverse air 3/1/2002 CFB

MS Red Hills

Generating Facility AA002 Li gnite Coal Baghouse, reverse air 3/1/2002 CFB

WA Transalta

Centralia Generation BW22 Subbituminous Coal Wet scrubber Electrostatic prec ipitator, cold side 10/1/2001 Spray type
MI J. H. Campbell 1 Bituminous Coal Subbituminous Coal Electrostatic precipitator, cold side 6/1/2001

## 83

S tate P lant Name B oiler ID Primary Fuel Secon dary Fuel NO X Control PM Control 1 PM Control 2 PM Control Date FGD Type NE Gerald

Gentleman 2 Subbituminous Coal Baghouse, reverse air 5/1/2001 MO Hawthorn 5A Subbituminous Co al Natural Gas SCR Baghouse, pulse 5/1/2001 Spray dryer type WI Weston 3 Subbituminous Coal Baghouse, pulse 5/1/2001 PA PPL

Montour 1 Bituminous Coal SCR Electrostatic precipitator, cold side 4/1/2001 GA Hammond 1 Bituminous Coal Electrostatic precipitator, cold side 1/1/2001 NE Gerald

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

Montour 2 Bituminous Coal SCR Electrostatic precipitator, cold side 6/1/2000 IL Will County 4 Subbituminous Coal Electrostatic precipitator, cold side 4/1/2000

MD AES Warrior

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

PA PPL

Brunner Is land 2 Bituminous Coal Electrostatic precipitator, cold side 2/1/2000 NE Sheldon 2 Subbituminous Coal Natural Gas Baghouse, pulse 2/1/2000 NE Sheldon 1 Subbituminous Coal Natural Gas Baghouse, pulse 12/1/1999 NC Cape Fear 5 Bituminous Coal Electrostatic precipitator, cold side 11/1/1999 NH Merrimack 2 Bituminous Coal SCR Electrostatic precipitator, cold side 10/1/1999 CO Hayden H2 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air 6/1/1999 Spray dryer type SC Canadys Steam CAN3 Bituminous Coal Distillate Fuel Oil Baghouse, reverse air 5/1/1999 IA Muscatine Plant

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

Energy 3 Subbituminous Coal Baghouse, pulse 1/1/1999 CO Hayden H1 Bituminous Coal Natural Gas Baghouse, reverse air 12/1/1998 Spray dryer type MI Erickson

Station 1 Subbituminous Coal Electrostatic precipitator, cold side 11/1/1998 NC Asheville 2 Bituminous Coal Electrostatic precipitator, cold side 5/1/1998 CO Martin Drake 5 Subbituminous Coal Natural Gas Baghouse, reverse air 5/1/1998 SC H. B. Robinson 1 Bituminous Coal Electrostatic precipitator, cold side 5/1/1997 GA Hammond 2 Bituminous Coal Electrostatic precipitator, cold side 5/1/1997

## 84

S tate P lant Name B oiler ID Primary Fuel Secon dary Fuel NO X Control PM Control 1 PM Control 2 PM Control Date FGD Type NC Roxboro 2 Bituminous Coal Electrostatic precipitator, cold side 1/1/1997 VA Birchwood

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

Center 2 Bituminous Coal SCR Electrostatic precipitator, cold side 6/1/1996 Spray type VA Clover 2 Bituminous Coal Baghouse, reverse air 3/1/ 1996 Spray type IL Waukegan 8 Subbituminous Coal Electrostatic precipitator, cold side 1/1/1996
FL Indiantown

Cogeneration LP AAB01 Bituminous Coal SCR Baghouse, reverse air 12/1/1995 Spray dryer type SC Cope COP1 Bituminous Coal Natural Gas Baghouse, reverse air 11/1/1995 Spray dryer type WY Neil Simpson II 2 Subbituminous Coal Electrostatic precipitator, cold side 11/1/1995 Circulating Dry Scrubber
PA Northampton

Generating Company BLR1 Waste Coal Petroleum Coke SNCR Baghouse, pulse 8/1/1 995 CFB
WI Valley 3 Bituminous Coal Baghouse, pulse 7/1/1995 WI Valley 4 Bituminous Coal Baghouse, pulse 7/1/1995 NC Roanoke Valley

II BLR2 Bituminous Coal Baghouse, pulse 6/1/1995 Circulating Dry Scrubber NC Roxboro 1 Bituminous Coal SCR E lectrostatic precipitator, cold side 6/1/1995 PA Colver Power

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

-based Synfuel SCR Electrostatic precipitator, cold side 5/1/1995 Spray type IN Eagle Valley 6 Bituminous Coal Electrostatic precipitator, cold side 2/1/1995
IN Harding Street 60 Bituminous Coal SNCR Multiple cyclone Electrostatic precipitator, cold side 2/1/1995 VA Clover 1 Bituminous Coal Baghouse, reverse air 1/1/1995 Spray type WI Manitowoc 6 Bituminous Coal Multiple cyclone Baghouse, pulse 1/1/1995 WI Manitowoc 7 Bituminous Coal Multiple cyclone Baghouse, pulse 1/1/1995
NJ Logan

Generating Plant B01 Bituminous Coal SCR Baghouse, reverse air 9/1/1994 Spray dryer type
WI Valley 1 Bituminous Coal Baghouse, pulse 7/1/1994 WI Valley 2 Bituminous Coal Baghouse, pulse 7/1/1994

## 85

S tate P lant Name B oiler ID Primary Fuel Secon dary Fuel NO X Control PM Control 1 PM Control 2 PM Control Date FGD Type FL Crist 6 Bituminous Coal Natural Gas Electrostatic precipitator, cold side 6/1/1994 IN Harding Street 70 Bituminous Coal SCR Electrostatic precipitator, cold side 6/1/1994
NJ PSEG Mercer

Generating Station 1 Bituminous Coal Natural Gas SCR and SNCR Electrostatic precipitator, cold

side 6/1/1994
GA Hammond 4 Bituminous Coal SCR Electrostatic precipitator, cold side 5/1/1994 NC Roanoke Valley

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

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

Cogeneration LP BOIL1 Bit uminous Coal SCR Baghouse, reverse air 3/1/1994 Spray dryer type

NJ Chambers

Cogeneration LP BOIL2 Bituminous Coal SCR Baghouse, reverse air 3/1/1994 Spray dryer type
FL Cedar Bay

Generating LP CBA Bituminous Coal SNCR Baghouse, reverse air 2/1/199 4 Circulating Dry Scrubber FL Cedar Bay

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

Generating LP CBC Bituminous Coal SNCR Baghouse, reverse air 2/1/1994 Circulating Dry Scrubber KY Elmer Smith 1 Bituminous Coal SCR Electrostatic precipitator, cold side 11/1/1993 Spray type CO Martin Drake 7 Subbituminous Coal Natural Gas Baghouse, reverse air 11/1/1993 IN Gibson 2 Bituminous Coal Electrostatic precipitator, cold side 7/1/1993 KY Elmer Smith 2 Bituminous Coal SNCR Electrostatic precipitator, cold side 6/1/1993 Spray type GA Hammond 3 Bituminous Coal Electrostatic precipitator, cold side 6/1/1993 PA Scrubgrass

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

Generating UNIT 2 Waste Coal SNCR Baghouse, pulse 6/1/1993 CFB SC McMeekin MCM1 Coal

-based Synfuel Bituminous Coal Baghouse, reverse air 5/1/1993 MO Sibley 1 Subbituminous Coal Electrostatic precipitator, cold side 4/1/1993 MO Sibley 3 Subbituminous Coal Electrostatic precipitator, cold side 4/1/1993 KY Cane Run 4 Bituminous Coal Coal

-based Synfuel Electrostatic precipitator, cold side 3/1/1993 Spray type

## 86

S tate P lant Name B oiler ID Primary Fuel Secon dary Fuel NO X Control PM Control 1 PM Control 2 PM Control Date FGD Type UT Sunnyside

Cogen Associates 1 Waste Coal Baghouse, pulse 2 /1/1993 CFB
WV North Branch 1A Bituminous Coal Waste Oil Baghouse, pulse 12/31/1992 CFB WV North Branch 1B Bituminous Coal Waste Oil Baghouse, pulse 12/31/1992 CFB TX J. K. Spruce BLR1 Subbituminous Coal Baghouse, reverse air 12/1/1992 Spray type PA Piney Creek

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

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

Power Station BLR2 Bituminous Coal Baghouse, pulse 11/1/1992 Circulating Dry Scrubber IL Meredosia 05 Subbituminous Coal Bituminous Coal Electrostatic precipitator, cold side 11/1/1992 HI AES Hawaii BLRA Subbituminous Coal Tire

- derived Fuels SNCR Baghouse, reverse air 8/1/1992 CFB HI AES Hawaii BLRB Subbituminous Coal Waste Oil SNCR Baghouse, reverse air 8/1/1992 CFB VA Cogentrix of

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

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

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

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

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

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

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

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

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

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

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

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

Richmond 2B Bituminous Coal Baghouse, pulse 5/1/1992 Spray dryer type IN Michigan City 12 Subbituminous Coal Natural Gas SCR Electrostatic precipitator, cold side 5/1/1992

## 87

S tate P lant Name B oiler ID Primary Fuel Secon dary Fuel NO X Control PM Control 1 PM Control 2 PM Control Date FGD Type KS Quindaro 2 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side 5/1/1992 IN Gibson 1 Bituminous Coal Electrostatic precipitator, cold side 1/1/1992 SC McMeekin MCM2 Coal

-based Synfuel Bituminous Coal Baghouse, reverse air 1/1/1992 WV Morgantown

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

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

Generating Station 2 Bituminous Coal Natural Gas SCR and SNCR Electrostatic precipitator, cold

side 1/1/1992
MO Sibley 2 Subbituminous Coal Electrostatic precipitator, cold side 1/1/1992 TX Twin Oaks

Power One U2 Li gnite Coal Baghouse, shake and deflate 10/1/1991 CFB VA Altavista Power

Station 1 Bituminous Coal SNCR Baghouse, pulse 6/1/1991 Spray dryer type CO Comanche 2 Subbituminous Coal Natural Gas Baghouse, reverse air 6/1/1991 WI South Oak

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

Power Station 1 Bituminous Coal Baghouse, pulse 6/1/1991 Spray dryer type OH W. H. Zimmer 1 Bituminous Coal Electrostatic precipitator, cold side 6/1/1991 Spray type MD Brandon Shores 2 Bituminous Coal SCR Electrostatic precipitator, hot side 5/1/1991 Spray type PA Ebensburg

Power 031 Waste Coal Baghouse, pulse 5/1/1991 CFB WI Manitowoc 8 Bituminous Coal Petroleum Coke Single cyclone Baghouse, pulse 4/1/1991 CFB PA Cambria Cogen B1 Waste Coal SNCR Baghouse, shake and deflate 3/1/1991 CFB PA Cambria Cogen B2 Waste Coal SNCR Baghouse, shake and deflate 3/1/1991 CFB AL James H Miller

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

Point 1A Bituminous Coal Baghouse, pulse 1/1/1991 CFB OK AES Shady

Point 1B Bituminous Coal Baghouse, pulse 1/1/1991 CFB OK AES Shady

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

Point 2B Bituminous Coal Baghouse, pulse 1/1/1991 CFB AL Colbert 4 Bituminous Coal Electrostatic precipitator, cold side 1/1/1991

## 88

S tate P lant Name B oiler ID Primary Fuel Secon dary Fuel NO X Control PM Control 1 PM Control 2 PM Control Date FGD Type CO Nucla 1 Bituminous Coal Baghouse, shake and deflate 1/1/1991 CFB
NY Trigen

Syracuse Energy 1 Bituminous Coal Baghouse, reverse air 1/1/1 991 N/A

NY Trigen

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

NY Trigen

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

NY Trigen

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

NY Trigen

Syracuse Energy 5 Bituminous Coal Baghouse, reverse air 1/1/1991 N/A
KY Trimble County 1 Bituminous Coal SCR Electrostatic precipitator, cold side 12/1/1990 Spray type AL Colbert 1 Bituminous Coal Electrostatic precipitator, cold side 11/1/1990 CO Comanche 1 Subbituminous Coal Natural Gas Baghouse, reverse air 11/1/1990 NC Cogentrix

Dwayne Collier Battle Cogen 1A Bituminous Coal Baghouse, pulse 10/1/1990 Spray dryer type

NC Cogentrix

Dwayne Collier Battle Cogen 1B Bituminous Coal Baghouse, pulse 10/1/1990 Spray dryer type

## 89

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

HAP, non - dioxin/furan organic HAP, and mercury and other non - merc ury metallic HAP testing State Plant Name Boiler ID NO X 

### Control PM Control 1 PM Control 2 PR Aguirre 3 PR Aguirre 4 PR Aguirre 9 PR Aguirre 10 FL Anclote 1 FL Anclote 2 PR Arecibo 1 NY Astoria Generating Station 40 NJ B L England 3 Multiple cyclone Electrostatic precipitator, cold side DC Benning 16 MA Brayton Point 4 Electrostatic precipitator, cold side CT Bridgeport Station BHB2 Electrostatic precipitator, cold side FL C. D. McIntosh Jr 2 El ectrostatic precipitator, cold side GU Cabras 2 FL Turkey Point P TP 1 Multiple cyclone FL Turkey Point P TP 2 Multiple cyclone PR Central Palo Seco 2 PR Central Palo Seco 3 PR Central Palo Seco 4 PR Central Palo Seco 5 P R Central Palo Seco 6 PR Central Palo Seco 7 PR Central Palo Seco 8 MA Cleary Flood 8 PR Costa Sur 1 PR Costa Sur 2 PR Costa Sur 6 PR Costa Sur 7 PR Costa Sur 8

## 90

State Plant Name Boiler ID NO X 

### Control PM Control 1 PM Control 2 PR Costa Sur 9 PR Costa Sur 10 CT Devon Station 8 Electrostatic precipitator, cold side IN Eagle Valley 1 Multiple cyclone Electrostatic precipitator, cold side IN Eagle Valley 2 Multiple cyclone Electrostatic precipitator, cold side NY East River 6 PA Eddystone Generating Station 4 Multiple cyclone Electrostatic precipitator, cold side DE Edge Moor 5 Multiple cyclone Electrostatic precipitator, cold side IN Harding Street 9 Multiple cyclone Electrostatic precipitator, cold side IN Harding Street 10 Multiple cyclone Electrostatic precipitator, cold side IL Havana 2 Electrostatic precipitator, hot side IL Havana 4 Electrostatic precipitator, hot side IL Havana 5 Electrostatic precipitator, hot side IL Havana 6 Electrostatic precipitator, hot side IL Havana 7 Electrostatic precipitator, hot side IL Havana 8 Electrostatic precipitator, hot side HI Honolulu 16 FL Indian River 1 FL Indian River 2 FL Indian River 3 SC Jefferies 2 Electrostatic precipitator, cold side HI Kahe 3 HI Kahe 4 FL Manatee PMT1 Multiple cyclone FL Manatee PMT2 Multiple cyclone FL Martin PMR1 Multiple cyclone DE McKee Run 3 Multiple cyclone GA McManus 2 LA Michoud 3 MD Mirant Chalk Point 3 Electrostatic precip itator, cold side PA Mitchell Power Station 1 Electrostatic precipitator, cold side

## 91

State Plant Name Boiler ID NO X 

### Control PM Control 1 PM Control 2 PA Mitchell Power Station 2 Electrostatic precipitator, cold side PA Mitchell Power Station 3 Electrostatic precipitator, cold side CT Montville Station 5 E lectrostatic precipitator, cold side CT Montville Station 6 Electrostatic precipitator, cold side MA Mystic Generating Station 7 Electrostatic precipitator, cold side NH Newington 1 Electrostatic precipitator, hot side NY Northport 2 Electrostatic precipitator, cold side NY Northport 4 Electrostatic precipitator, cold side FL Northside Generating Station 3 Baghouse, pulse NY Oswego Harbor Power 5 Electrostatic precipitator, cold side FL Port Everglades PPE 3 Multiple cyclone FL Port Everglades PPE4 Multiple cyclone NY Port Jefferson 4 Electrostatic precipitator, cold side VA Possum Point 5 Multiple cyclone Electrostatic precipitator, cold side PA PPL Martins Creek 3 PA PPL Martins Creek 4 NJ PSEG Sewaren Generating Station 2 NJ PSEG Sewaren Generating Station 4 VI Randolph E. Harley 1 NY Ravenswood Generating Station 1 Electrostatic precipitator, cold side NY Ravenswood Generating Station 2 Electrostatic precipitator, cold side VI Richmond 1 FL Martin PMR2 Multiple cyclone NY Roseton Generating Station 2 Multiple cyclone PR San Juan Plant 1 PR San Juan Plant 2 PR San Juan Plant 4 PA Schuylkill Generating Station 1 Multiple cyclone FL Suwannee River 2 FL Suwannee River 3 MD Vienna Operations 8 Multiple cyclone

## 92

State Plant Name Boiler ID NO X 

### Control PM Control 1 PM Control 2 HI Waiau 3 HI Waiau 4 HI Waiau 5 HI Waiau 6 HI Waiau 7 HI Waiau 8 MA West Springfield 3 Electrostatic precipitator, cold side ME Will iam F Wyman 1 Multiple cyclone Electrostatic precipitator, cold side ME William F Wyman 2 Multiple cyclone Electrostatic precipitator, cold side

## 93 Attachment 13. List of 50 additional coal-fired electric utility steam generating units not chosen in Attachments 8 through 11 selected for HCl/HF/HCN acid gas HAP, non dioxin/furan organic HAP, and mercury and other non - mercury metallic HAP testing

State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X Control PM Control 1 PM Control 2 FGD Control ACI WV Albright 1 Bituminous Coal Electrostatic precipitator, cold side WV Albright 3 Bituminous Coal Electrostatic precipitator, cold side CT Bridgeport Station BHB3 Subbituminous Coal Residual Fuel Oil Electrostatic precipitator, cold side Y OH Cardinal 3 Bituminous Coal SCR Electrostatic precipitator, hot side VA Clinch River 3 Bituminous Coal Electrostatic precipitator, cold side AL Colbert 3 Bituminous Coal Electrostatic precipitator, cold side MT Colstrip 3 Subbituminous Coal Wet scrubber Venturi type OH Conesville 3 Bituminous Coal Electrostatic precipitator, cold side
FL Crystal River 1 Bituminous Coal Electrostatic precipitator, cold side KY Dale 3 Bituminous Coal Electrostatic precipitator, cold side
NY Dunkirk Generating

Station 1 Bituminous Coal Subbituminous Coal Electrostatic precipitator, hot side

NY Dunkirk Generating

Station 4 Bituminous Coal Subbituminous Coal Electrostatic precipitator, hot side

PA Eddystone Generating

Station 2 Bituminous Coal SNCR Multiple cyclone Electrostatic precipitator, cold side Spray type

PA Elrama Power Plant 2 Bituminous Coal SNCR Multiple cyclone Electrostatic precipitator, cold side Venturi type

NC G. G. Allen 3 Bituminous Coal Electrostatic precipitator, cold side TN Gallatin 2 Subbituminous Coal Electrostatic precipitator, cold side

## 94

State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X Control PM Control 1 PM Control 2 FGD Control ACI

PA Hatfields Ferry Power

Station 3 Bituminous Coal Electrostatic precipitator, cold side

IL Havana 9 Subbituminous Coal SCR Electrostatic precip itator, hot side Baghouse, pulse Y MN Hoot Lake 2 Subbituminous Coal Electrostatic precipitator, cold side
TX J. T. Deely 1 Subbituminous Coal Electrostatic precipitator, cold side

MO James River Power

Station 4 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side

IL Joliet 9 5 Subbituminous Coal Electrostatic precipitator, cold side KS LaCygne 2 Subbituminous Coal Electrostatic precipitator, cold side KS Lawrence Energy Center 3 Subbituminous Coal Natural Ga s Electrostatic precipitator, cold side
TX Monticello 1 Li gnite Coal Subbituminous Coal Electrostatic precipitator, cold side Baghouse, shake and deflate IL Newton 2 Subbituminous Coal Electrostatic precipitator, cold side
PA PPL

Martins Cre ek 2 Bituminous Coal Electrostatic precipitator, cold side
WI Pulliam 8 Subbituminous Coal Electrostatic precipitator, cold side KY R D Green G2 Bituminous Coal Electrostatic precipitator, cold side Spray type
IN R M Schahfer 14 Bituminous Coal Subbituminous Coal Electrostatic precipitator, cold side
LA R. S. Nelson 6 Subbituminous Coal Electrostatic precipitator, hot side CO Rawhide 101 Subbituminous Coal Baghouse, reverse air Spray dryer type NV Reid Gardner 1 Bituminous C oal Li gnite Coal Multiple cyclone Spray type
OH Richard Gorsuch 3 Bituminous Coal Natural Gas Electrostatic precipitator, cold side

## 95

State P lant Name B oiler ID Primary Fuel Secondary Fuel NO X Control PM Control 1 PM Control 2 FGD Control ACI NC Riverbend 7 Bituminous Coal Electrostatic precipitator, hot side NH Schiller 5 Bituminous Coal Residual Fuel Oil SNCR Electrostatic precipitator, cold side FL Scholz 2 Bituminous Coal Electrostatic precipitator, cold side PA Shawville 2 Bituminous Coal Electrostatic precipitator, cold side
MN Silver Bay Power BLR1 Subbituminous Coal Natural Gas Baghouse, reverse air
MO Sioux 2 Subbituminous Coal Tire

- derived Fuels Electrostatic precipitator, cold side IN Tanners Creek U4 Subbituminous Coal Electrostatic precipitator, cold side SC Urquhart URQ3 Bituminous Coal Natural Gas Electro static precipitator, cold side IL Vermilion 1 Subbituminous Coal Natural Gas Electrostatic precipitator, cold side Baghouse, pulse Y OH W H Sammis 3 Bituminous Coal Subbituminous Coal Baghouse, reverse air
OH W H Sammis 4 Bituminous Coal Subbit uminous Coal Baghouse, reverse air

NC W. H. Weatherspoon 1 Bituminous Coal Electrostatic precipitator, cold side

IN Wabash River 2 Bituminous Coal Electrostatic precipitator, cold side TX Welsh 1 Subbituminous Coal Electrostatic precipitator, hot side
NE Whelan Energy Center 1 Subbituminous Coal Electrostatic precipitator, cold side

PA WPS Energy Servs

Sunbury Gen 4 Bituminous Coal Distillate Fuel Oil Electrostatic precipitator, cold side Electrostatic precipitator, cold side