**MA CTEC**  **Federal Programs , Inc.** 

P.O. Box 12077, Research Triangle Park, NC 27709
- 2077 • Phone: 919
- 941
- 0333 • Fax : 919
- 941
- 0234 **DATE:** August 20 , 2008 **TO:** Julie R. McDill

Senior Engineer Mid

- Atlantic Regional Air Management Association , I nc. 8600 L aSalle Road Suite 636 Baltimore, MD 21286 **FROM:** Art hur Werner , MACTEC

William Hodan , MACTEC Scott Justice, MACTEC MACTEC Project 82700 8 G233 **SUBJECT:** Emissions Factors for Condensable Particulate Matter Emissions from Electric

Generating Units
Introduction Accurate emissions factors are needed to model the effect of condensable emissions on regional haze in the MANE VU region. Pa rticulate matter smaller than 2.5 micrometers in diameter (PM 2.5 ) emitted from stationary sources has two components, particles that are solid regardless of stack temperature (filterable) and gases that condense shortly after exiting the stack (condensable ). For electric generating units (EGUs) burning oil or natural gas , condensable particulate matter (CPM) emissions can be gre ater than filterable emissions. However, there is a great deal of uncertaint y about the best way to measure condensable emissions

. Essentially all CPM emissions factors in EPA’s WebFIRE (the database containing AP

- 42 emissions factors) and CPM emissions data collected recentl y were measured using EPA Reference Method 202. In Method 202, an effluent gas stream, after passing throug h a filter to remove solid particulate, is bubbled through a series of impingers to collect CPM. I n measuring CPM from combustion of fuels containing sulfur , it has been shown by EPA that SO 2 collected in the impingers can be oxidized to sulfate and produ ce a variable sulfate artifact that results in overestim ation of condensable emissions. In this example, if impingers are not purged with nitrogen, errors associated with the su lfate artifact may be inflated. T he em issions factors in WebFI RE were develop ed from source test data that are more than 10 ye ars old and may no t represen t newer refinements to Method 202. See the following link for more information on Method 202 and the nitrogen purge: http://www.epa.gov/ttn/emc/methods/method202.html

. Because of th ese and other uncertainties, condensable emissions were not calculated uniformly across all states in the MANE

- VU region in the 2002 emissions inventory

. For the future y ear MANE VU ( 2009, 2012, and 2018) emissions in ventories , MARAMA has requested that MACTEC evaluate available data on condensable emissions from EGUs and recommend emissions factors to be used for the future ye ar inventories.Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 2 Summary of Existing AP

- 42 CPM Emissions Fa ctors To establish a baseline for the condensable emissions factors used in the 2002 MANE VU emissions inventory

and to compare the existing AP

- 42 emissions factors with emissions factors developed from recent source tests, we first review ed EPA’s FI RE (ve rsion 6.25) to identify all EGU source/fuel/control device combinations for which AP

- 42 emissions factors and other factors are provided for CPM and PM 2.5 . These emission s factors are attached in an ACCESS database ( Attachment 1 )

. The attached database c ontains all 121 CPM and 51 PM 2.5 emissions factors that are in the most recent version of FI RE (version 6.25) . FIRE 6.25 contains all emissions factors published in AP

- 42 prior to October 2004. This includes the most recent updates to AP

- 42 Chapters 1 an d 3, which contain all the external and internal combustion emissions factors associated with EGUs and other large combustion sources

. The 121 CPM and 51 PM 2.5 EGU emissions factors in FIRE 6.25 are based on onl y 16 unique emissions factors (14 from AP

- 42 and 2 others). The 172 emissions factors were assigned by assuming that each unique factor can be applied to a large number of source classification codes (SCCs) similar to the one for which th e factor was actually developed

. The 121 CPM EGU emissions f actors represent 14 unique emissions factors from the following AP
- 42 sections (number of unique emission factors in parentheses):

 AP
- 42 Section 1.1: Bituminous and Subbituminous Coal Combustion (3)

 AP
- 42 Section 1.2: Anthracite Coal Combustion ( 1 )

 AP
- 4 2 Section 1.3: Fuel Oil Combustion (2)

 AP
- 42 Section 1.4: Natural Gas Combustion (1)

 AP
- 42 Section 1.6: Wood Residue Combustion in Boilers (1)

 AP
- 42 Section 1.7: L ig nite Combustion (3)

 AP
- 42 Section 3.1: Stationary Gas Turbines (2)

 AP
- 42 Section 3.2: Natural Gas

- fired Reciprocating Engines (1) For those factors for which information was provided, each FIRE 6.25 emissions factor was calculated from data reported in from 2 to 36 test reports. In some cases, no information was provided on the number of tests forming the basis for the CPM factor. In addition to the 14 unique emissions factors from AP

- 42, there are 2 CPM emissions factors in FIRE 6.25 from single independent test reports (not included in AP

- 42). The assigned quality ratings of the facto rs vary

from grade “A” to “E”, with some quality ratings designated as “U” for “Unknown”. The A ratings are likel y due to the large number of tests conducted for some factors. It appears that the data were graded on the number of tests that were conducte d to measure PM or PM 10 , and then the corresponding grade was associated with the CPM emissions factors as well

. The 14 unique emission factors were then assigned to many related SCCs, resulting in the 121 CPM emissions factors in FIRE 6.25. This informa tion is reflected in the attached database , which contains identical emissions factors associated with many SCCs
.Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 3 In addition , f

or each CPM emissions factor, Attachment 1 also contains the following information :
 SCC

 SCC Description

 Control description (if applicable)

 Fuel heat content (assumed value, based on ty pe of fuel and used to convert factors from a mass basis to an energy basis)

 Notes, reference information, formulae, factor identification number, date and description of an y assumptions associat ed with the emissions factor

. The data in Exhibit s 1 and 2 summar ize the FIRE 6.25 info rmation in Attachment 1. The e xhibit s list the emissions factors for coal, natural gas, and oil as they have been assi gned in FIRE 6.25, b y fuel t ype. Because unique emissions factors were assigned multiple times to many SCCs associated with the same fuel, we have only represented each unique emission factor one time per fuel. In this way , we have prevented the average emissions factors from becoming biased due to the number of assignments. W e have indicated the emissions factors that have been calculated from FIRE 6.25 formulae with fuel sulfur content as the variable. Investigation of ty pical sulfur values for the different grades of coal showed that the sulfur con tent is best represented as a range for all the coal t ypes except for lignite coal. We calculated the emissions factors based on established ranges of sulfur content for anthracite, bituminous, and subbituminous coal

. We then averaged the high and low ra nge value to calculate the emissions factor. Please refer to Att achment 1 for additional details on these emissions factors

. Exhibit 1: FI RE 6.25 Unique CPM Emissions Factors by Coal Ty pe Coal Ty pe Anthracite Bituminous Subbituminous Li gnite (units) (l b/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu)

0.0385 ( 1 ) 0.225 ( 1 ) 0.125 ( 1 ) 0.01 ( 2 ) 0.049 ( 1 ) 0.02 (3) 0.02 (3) 0.02 (3)

0.04 (3) 0.04 (3) 0.04 (3)

0.026 AVERAGE 0.044 0.095 0.053 0.023 (1) Em issions factor value was calculated by averaging the low and hi gh range CPM emission estimate that resulted from the assignment of a high and low sulfur value in the emissions factor formula. (2) Em iss ions factor value was calculated by assigning a single value (no range) to the sulfur variable in the em issions fac tor formula. (3) Em issions factors applicable to bituminous, subbituminous, and lignite. Exhibit 2: FI RE 6.25 CPM Emissions Factors for Natural Gas and Fuel Oil Fuel T ype Natural Gas Fuel Oil (units) (lb/MMBtu) (lb/MMBtu)

0.0059 0.01 0.0047 0.0093 0.00991 0.0072 AVERAGE 0.0068 0.0088Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 4 Updated CPM Emissions Factors from Recent Emissions Test Reports To develop CPM emissions factors from recent compliance tests, MACTEC evaluated source test reports beginning in 2002 for PM and CPM emissions from utility boilers and turbines firing coal, oil, or natural gas from six states: Delaware, Minnesota, New Jersey , North Carolina, Pennsy lvania, and Wisconsin. We reviewed 162 test s from 83 test reports to obtain CPM test data

. Additional test reports were reviewed, but did not contain CPM data

. [Note that each FIRE 6.25 emissions factor consists of data from 2 to 36 test reports

. ]
. All tests for CPM were conducted using EPA Method 202 which , as described above, uses water - filled impingers to collect conde nsable gases and aerosols after the filter. A key discriminator of artifact formation in Method 202 is the use of a nitrogen gas purge after sample collection to drive out excess S O 2 before oxidation to sulfate. Thus, in addition to extracting c ondensabl e emissions data and process information from each test report, we collected whatever details were provided on the application of Method 202. MACTEC extracted data from the 162 test s and entered the data in the WebFIRE data template (with emphasis on the use of the nitrogen purge). For each test we calculated the emissions factor from the emissions data and the process information. The condensable emissions fa ctors were sorted b y SCC and compared to the condensable emissions factors in WebFI RE. Exhibit 3 is a breakdown of the number of test reports by state and fuel. Exhibit 4 further breaks down the coal test reports by t yp e of coal. As noted above, a key difference in CPM measured by EPA Method 202 is whether or not the impingers were purged with nitr ogen, Exhibit 5 provides a summary

of the number of tests where impingers were purged, not purged, or not specified. Exhibit 3 : Test s by

State and Fuel Ty

pe State/Fuel Coal Oil Gas Delaware 3 0 0 Minnesota 16 0 1 New Jersey 10 0 0 North Carolina 2 7 1 1 Pennsy lvania 2 3 18 1 9 Wisconsin 32 8 3 Total 11 1 27 2 4Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 5 Exhibit 4: Test s by

State and Ty

pe of Coal State/Fuel Coal* Bituminous Subbituminous Delaware 3 0 0 Minnesota 7 0 9 New Jersey 7 3 0 North Carolina 26 1 0 Pennsy lvania 14 9 0 Wisconsin 32 0 0 Total 89 13 9 (*) Ty

pe of coal unspecified. Exhibit 5: Test s by

State and Nitrogen Purge State/Purge Purged Not purged Not specified Delaware 3 0 0 Minnesota 15 2 0 New Jersey 0 0 1 0 North Carolina 29 0 0 Pennsy lvania 1 25 3 4 Wisconsin 28 6 9 Total 76 33 53 Exhibits 6 through 9 summarize the results of the CPM and FPM data collected from the 162 tests. T he data extracted from the reports and the anal ys es used to generate the graphs in Exhibits 6 through 9 are available in Attachment 2 t o this memorandum. Exhibit 6 shows the average emissions factors for each fuel from all test reports

. The average coal CPM emissions factor is 0.02 3 ± 0.006 lb/MMBtu (95% confidence interval for 111 data points)

. Most of the test reports did not specify the t ype of coal fired, but based on DOE monthly coal

- use data for the United States , the majority of coal burned in the United States is either bituminous or subbituminous

. The average fuel oil CPM emissions factor is 0.01 3 ± 0.006 lb/MMBtu (95% confide nce interval for 27 data points) , and the average natural gas CPM emissions factor is 0.00 5 ± 0.001 lb/MMBtu (95% confidence interval for 2 4 data points)

. The effect of the nitrogen purge can be seen from comparison of the CPM emissions factor results in Exhibits 7 through 9. CPM results from tests for which no nitrogen purge was done are not iceabl y higher than the results from the tests for which the purge was done. A comparison of Exhibits 7 and 8 demonstrates the magnitude of the sulfate artifact . Th e average of the CPM emissions resulting from the non - purged tests are 3 times high er than the results of the purged tests for coal based on the comparison of 11 non
- purged and 66 purged data points. The average of the CPM emissions resulting from the non - purged tests are twice the results of the purged tests for fuel oil based on the comparison of 12 non
- purged and 6 purged data point s . For natural gas, a verage CPM emissions resulting from non - purged tests are 3 times high er than the purged tests based o n comparison of 12 non
- purged and 6 purged data points.Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 6 Exhibit 6: Average Emission Factor s By Fuel

– All Tests **Av er**  **age Emi**  **ssi on**  **Fact or**  **C ompar**  **is on**  **by Fuel**  **- All T est**  **s**

0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16**E m** **i s** **s i** **o n** **F a** **c t** **o r** **s (** **l b** **/ m** **m B** **t u** **)** FPM CPM

**Fuel T**  **ype To**  **tal C oal**  **Sub-bitum inous** 

**Co al**  **Bi tum**  **inous**

**Co al**  **Natural G**  **as Fue**  **l O il** 

Exhibit 7: Emission Factor Comparisons, Purged **Emi ssi**  **on Fact**  **or**

**C ompar**  **is on,**  **P ur**  **ged**

0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16**E m** **i s** **s i** **o n** **F a** **c t** **o r** **s (** **l b** **/ m** **m B** **t u** **)** FPM CPM

**Fuel T**  **ype To**  **tal C oal**  **Sub-bitum in**  **ous Co**  **al Na**  **tural Ga**  **s Fue**  **l O il** Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 7 Exhibit 8: Emission Factor Comparisons, Non

- Purged **Emi ssi**  **on Fact**  **or**

**C ompar**  **is on,**  **N on-**  **Pur ged** 

0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16**A v** **e r** **a g** **e E** **m i** **s s** **i o** **n F** **a c** **t o** **r s** **( l** **b /** **m m** **B t** **u )**  FPM CP M

**Fuel T**  **ype To**  **tal Co**  **al Fue**  **l O il**  **Natu ral**  **G as**  Exhibit 9: Emission Factor Compa risons, Unknown Purge **Emi ssi**  **on Fa**  **ct or** 

**C ompar**  **is on,**  **U nknow**  **n Pur**  **ge**

0 0.0 2 0.0 4 0.0 6 0.0 8 0.1 0.1 2 0.1 4 0.1 6**E m** **i s** **s i** **o n** **s F** **a c** **t o** **r s** **( l** **b /** **m m** **B t** **u )** 

FP M CPM

**Fuel T**  **ype To**  **tal C**  **oal Bi**  **tum inous C**  **oal Na**  **tural G**  **as Fue**  **l O il** Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 8 In addition to categorization by fuel ty pe, we reviewed the available information for each of the 162 tests, and made assignments of the data points to SCCs for direct comparison to existing AP
- 42 emissions factors . Using the avai lable information and considering the limited number of data points (1 62 total), we de cided that the most effective anal ys is would result from assignment of the data points to the 6

- digit SCC level. Assignment at the SCC 8

- digit level was not possible for most test data because the information supplied in most test report s did not indicate the specific boiler/turbine t ype. After the assignments were made, additional calculations wer e completed to calculate the emissions factors b y 6
- digit SCC. Exhibit 10 contains a summary of these data, and the assignments

. C omplete calculations are provided in Attachment 3 to this memorandum. Exhibit 10 : Summary

of CPM Emissions Factors by SCC (6

- digit) SCC (6

- digit) SCC (6

- digit) Description Number of Tests Average CPM

Em issions Factor ( lb/MMBtu ) 95% Confidence

Interval ( lb/MMBtu ) 1
- 01
- 001 Boiler / EGU / Anthracite Coal 1 0.0084 N/A 1
- 01
- 002

– all tests Boiler / EGU /

Bituminous/Subbituminous Coal 10 2 0.02 2 ± 0.006 1
- 01
- 002 (

purged only ) Boiler / EGU /

Bituminous/ Subbituminous Coal 63 0.01 3 ± 0.002 1
- 01
- 003

– all tests Boiler / EGU / Lignite 6 0.039 ± 0.029 1
- 01
- 005

– all tests Boiler / EGU / Fuel Oil 10 0.014 ± 0.007 1
- 01
- 006

– all tests Boiler / EGU / Natural Gas 1 0.00249 N/A 1
- 01
- 008

– all tests Boiler / EG U / Petroleum Coke 2 0.05 ± 0.03 2
- 01
- 001

– all tests Internal Combustion Engine / EGU/

Fuel Oil 17 0.01 3 ± 0.00 5 2
- 01
- 001 (purged only) Internal Combustion Engine / EGU/

Fuel Oil 3 0.010 ± 0.004 2
- 01
- 002

– all tests Internal Combustion Engine / EGU/

Nat ural Gas 23 0.005 ± 0.001 2
- 01
- 002 (

purged only ) Internal Combustion Engine / EGU/

Natural Gas 3 0.0015 ± 0.0002 Summary of Results from Emissions Factors Data Anal ys is In accord ance with EPA guidance that CPM emissions determined from Method 202 tests that apply nitrogen purging are more reliable than results from tests where purging was not used, we will only consider categories where purging was used. Based on the high level of agreement among the 63 test data points for the nitrogen purged tests for SCC “1
- 01
- 002” in Exhibit 10 (third row) , the CPM emissions factor of 0.013 ± 0.002 lb/MMBtu for bituminous and/or subbituminous coal is considered to be a high quality estimate of the CPM emissions factor in EGU boilers and we recommend its use. One shou ld be careful in comparing the emissions factors in Exhibit 10 with those in Exhibit 1 because the emissions factors in Exhibit 1 for coal combustion are averaged over a range of fuel sulfur content and the factors in Exhibit 10 are averaged over tests wit hout regard to fuel sulfur. Nevertheless, it should be noted that the nitrogen purged CPM emissions factor in Exhibit 10 for combustion of bituminous and subbituminous coal are lower than the older emissions factors in FIRE 6.25 by a factor of about 7 and 4 for bituminous and subbituminous coal, respectivel y Additionally , because nearl y all coal fired in the United States is bituminous or subbituminous coal, application of this emissions factor for all combustion of bituminous and/or subbituminous coal sh ould greatl y improve emissions estimates from EGUs.Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 9 Based on the small sample size of nitrogen purged tests for anthracite and lignite coals, natural gas and fuel oil as shown in Exhibit 10 , we do not recommend an y revisions to FI RE 6.25 emissions factors. It should be noted that while these data have been shared with EPA, EPA has not yet added the data to WebFI RE
. Comments from state agency review of this technical memorandum This technical memorandum was circulated to state agency staff for their revie w. A number of technical changes were made as a result of those comments. I n addition, Pennsy lvania provided the following comments:

 Pennsy lvania DEP is requiring EGU owners/operators in Pennsy lvania to conduct source testing b y J une 30, 2009 to determin e actual condensable PM emission.
 T he measurement method for CPM has now been updated . E PA's recentl y developed dry impinger method (OTM

- 028) was not used in the tests used in this study , rather the method that was used (Method 202) produces results that are biased high.
 A follow

- up study

would be desirable to de termine if testing methods affect the CPM/TPM ratio.Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 10

APPENDIX ATechnical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 11 Delaware NRG I ndian River Generating Station, Unit 4, October 31, 2002 NRG I ndian River Generating Station , Unit 2, October 16, 2002 NRG I ndian River Generating Station, Unit 1, October 16, 2002 Minnesota Otter Tail Power Company ’s Hoot Lake Facility , No. 1 Boiler, Fergus Falls, MN, December 19, 2006 Minnesota Power’s Boswell Energy Center, Unit 4, Cohass et, MN, August 26
- 28, 2002 Xcel Energy ’s Riverside Generating Plant, Units 6, 7 and 8, Minneapolis, MN, October 3

- 4, 2006 Xcel Energy

Sherburne County

Generating Plant, Unit 1/2 Common Stack, Becker, MN, June 15
- 16, 2004 Xcel Energy

Sherburne County

Gen erating Plant, Boilers 1 and 2 Common Stack/EP #001, Becker, MN, August 28, 2001 Xcel Energy

Sherburne County

Generating Station, Unit #3 Exhaust Stack, Becker, MN, September 28, 2005 Xcel Energy

Sherburne County

Generating Plant, EU001 & EU002/SV001, Be cker, MN, April 27, 2007 Minnesota Power Laskin Energy Center, Boilers 1 and 2, Hoy t L akes, MN, February

27, 2007 and July 24, 2007 Otter Tail Power Company ’s Hoot Lake Facility , Unit 3 Boiler, Fergus Falls, MN, December 20, 2006 Otter Tail Power Hoot L ake Facility , Unit 3 Boiler, Fergus Falls, MN, August 24, 2006 Xcel Energy

Black Dog Unit #5 Repowering Project, Combustion Turbine #5, Burnsville MN, June 26
- Ju ly

2, 2002Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 12 North Carolina Carolina Power & Light Lee Plant, Unit 1, Goldsboro, NC, May 2, 2 002 Carolina Power & Light Lee Plant, Unit 3, Goldsboro, NC, May 1, 2002 Carolina Power & Light May o Plant, Unit 1, Roxboro, NC, May 9, 2002 Carolina Power & Light L.V. Sutton Steam Electric Plant, Unit No. 1, Wilmington, NC, June 15, 2002 Carolina Pow er & Light L.V. Sutton Steam Electric Plant, Unit No.2, Wilmington, NC, June 16, 2002 Carolina Power & Light L.V. Sutton Steam Electric Plant, Unit No.3, Wilmington, NC, June 13, 2002 Carolina Power & Light Roxboro Plant, Unit 1, Roxboro, NC, July 23, 20 02 Carolina Power & Light Roxboro Plant, Unit 2, Roxboro, NC, May 22, 2002 Carolina Power & Light Roxboro Plant, Unit 3, Roxboro, NC, July 24, 2002 Carolina Power & Light WH Weatherspoon Plant, Units 1 & 2, Lumberton, NC, February 13
- 14, 2002 Carolina Power & Light WH Weatherspoon Plant, Unit3, L umberton, NC, March 6, 2002 Carolina Power & Light WH Weatherspoon Plant, Unit3, L umberton, NC, September 24, 2002 Duke Energy

Allen Steam Station, Unit 1, Gaston County , NC, August 13, 2002 Duke Energy

Allen Steam Station, Unit 3, Gaston County , NC, August 14, 2002 Duke Energy

Allen Steam Station, Unit 4, Gaston County , NC, August 15, 2002 Duke Energy

Riverbend Steam Station, Unit 4 Boiler 7, Gaston County , NC, October 8, 2002 Duke Energy

Riverbend Steam S tation, Unit 5 Stacks A & B, Gaston County , NC, October 9, 2002 Duke Power Compan y, Buck Steam Station, Unit No. 3, Spencer, NC, September 11, 2003 Duke Power Compan y, Buck Steam Station, Unit No. 5, Spencer, NC, September 10, 2003 Duke Power Compan y, Cl iffside Steam Station, Unit No. 5, Rutherford County , NC, August 1, 2002Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 13 Duke Power Compan y Dan River Steam Station, Unit 2, Eden, NC, May 1, 2002 Duke Power Compan y Dan River Steam Station, Unit 1, Eden, NC, April 30, 2002 Progress Energy

Carolina’s Ma yo Plant, Unit 1, Roxboro, NC, June 16, 2004 Progress Energy

Asheville Generating Station, Unit T4, Asheville, NC, May 6

- 9, 2008 Carolina Power and Electric Roxboro Electric Generating Plant, Unit 1, Roxboro, NC, October 16, 2001 Pennsy lvania Alleghen y Energy

Supply Company

Hatfield’s Ferry

Power Station, Stacks 1 & 2, Masontown, PA, March 23 and 26, 2007 Alleghen y Energy Supply Compan y Hatfield’s Ferry Power Station, Stacks 1 & 2, Monongahela Township, PA, June 12, 2007 Reliant Energy

Newcastle Plant, Boilers 3 & 5, Taylor Township, PA, March 22, 2005 Reliant Energy

Newcastle Plant, Boiler 4, Tay lor Township, PA, May 18, 2005 Reliant Energy

Newcastle Plant, Boilers 3, 4 & 5, Tay lor Township, PA, February 27, 2007 Northampton Generating Company , Nort hampton, PA, August 23

- 24, 2005 PPL Brunner Island, Unit 3 ESP, East Manchester Twp., PA, January 10, 2007 PPL Brunner Island S.E.S., Unit 1 Exhaust Stack, York Haven, PA, May 15, 2007 Reliant Energy

Elrama Power Plant, Boilers 1

- 4, Elrama, PA, August 3 , 2005 Reliant Energy

Elrama Power Plant, Baghouse Stack, Elrama, PA, November 18, 2005 Reliant Energy

Elrama Power Plant, Elrama, PA, April 12 & 16, 2007 Reliant Energy

Elrama Power Plant, Boilers 1

- 4, Union Township, PA, December 17, 2007 PPL Martins Creek Station, Northampton County, 2007 PPL Generation Montour Steam Electric Station, Boiler 1, Washingtonville, PA, May 16, 2006 PPL Generation Montour Steam Electric Station, Boiler 2, Washingtonville, PA, April 4, 2007 Reliant Energy

Mid

- Atlantic Po wer Seward Station, Boilers 1 & 2, East Wheatfield Twp., PA, December 5, 2004Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 14 Conectiv Bethlehem, Combined Cy cle Electric Generation Facilit y, Combustion Turbines 1

- 3, Bethlehem and Lower Saucon Twp., PA, January 29
- March 26, 2003 Conectiv Bethlehem, Com bined Cy cle Electric Generation Facilit y, Combustion Turbines 1

- 3, Bethlehem and Lower Saucon Twp., PA, May 20
- June 2, 2003 Conectiv Energy

Bethlehem Power Plant, Units 2 & 3, Bethlehem, PA, February 3,4 7,8 & 10, 2003 Conectiv Energy

Bethlehem Power Plan t, Unit 2, Bethlehem, PA, May 27
- 29, 2003 Conectiv Energy

Bethlehem Power Plant, Unit 3, Bethlehem, PA, May 30,31 & June 2, 2003 Conectiv Energy

Bethlehem Power Plant, Unit 1, Bethlehem, PA, January 28
- 30, 2003 Conectiv Energy

Bethlehem Power Plant, CT 2, Bethlehem & Lower Saucon Twp., PA, December 30, 2003 Conectiv Energy

Bethlehem Power Plant, Unit 5, Bethlehem & Lower Saucon Twp., PA, March 22, 24 2003 Conectiv Energy

Bethlehem Power Plant, CT 3, Bethlehem & Lower Saucon Twp., PA, February 8, 10, 20 03 Conectiv Energy

Bethlehem Power Plant, CT 7, Bethlehem & Lower Saucon Twp., PA, September 25

- 26, 2003 Conectiv Energy

Bethlehem Power Plant, Unit 5, Bethlehem & Lower Saucon Twp., PA, September 15

- 17, 2003 Reliant Energy

Did Atlantic Power Holding Po rtland Station, Combustion Turbine #5, Upper Mt. Bethel Township, PA, September 24, 2002 Conectiv Energy

Bethlehem Power Plant, CT 6, Bethlehem & Lower Saucon Twp., PA, September 22

- 23, 2003 New Jersey Carney ’s Point Generating Plant, Boilers 1 & 2 Carn ey ’s Point, NJ, January 19

- 29, 2004 PSEG Hudson Generating Station, Unit No. 2, Hudson, NJ, June 20 & 23, 2003 Lo gan Generating Station, Swedesboro, NJ, October 27

- 28, 2004 Wisconsin Dairy land Power Cooperative Genoa 3 Station, No. 1 Boiler, Genoa, WI, August 3, 2004Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 15 Dairy land Power Cooperative J.P. Madgett Station, No. 1 Boiler, Alma, WI, April 9, 2002 Dairy land Power Cooperative J.P. Madgett Station, No. 1 Boiler, Alma, WI, May 18, 2006 Dairy land Power Cooperative J.P. Madgett Station, Baghouse Sta ck (Main Boiler B25, S11), Alma, WI , December 18

- 19, 2007 Wisconsin Public Service Corporation J.P. Pulliam Power Plant, Units 3/4 Common Stack, Green Bay , WI, July 7, 2004 Madison Gas and Electric Company Blount Generating Station, Unit 7 Outlet Duct, Ma dison, WI , November 6, 2003 Madison Gas and Electric Company Blount Generating Station, Unit 8 Precipitator Outlet, Madison, WI , April 15, 2004 Manitowoc Public Utilities MPU Power Plant, Boilers B25 and B28, Manitowoc, WI , June 10 and July 9, 2003 Mani towoc Public Utilities MPU Power Plant, Boilers B25 and B28, Manitowoc, WI , March 6

- 9, 2006 Wisconsin Electric Power Company Valley Power Plant, Boilers 1 and 2 Inlet and Outlet Ducts, October 24 and 26, 2001 Wisconsin Public Service Corporation Weston P ower Plant, Unit 1 Stack, Rothschild, WI , December 21, 2005 We Energies Oak Creek Station, Unit 8 Precipitator Outlet, East and West Inlets, Oak Creek, WI , September 4, 2003 We Energies Valley

Power Plant, Boilers 3 and 4 Inlet and Outlet Ducts, Milwauke e, WI, July 28 and 29, 2003 Alliant Energy

Columbia Station, Unit 1 Stack, Pardeeville, WI, September 4, 2003 Dairy land Power Alma Station, No. 105 Boiler Stack, Alma, WI June 1, 2006 Dairy land Power Cooperative Genoa 3 Station, No. 1 Boiler Baghouse St ack, Genoa, WI, July 24
- 25, 2007 We Energies Pleasant Prairie Power Plant, Unit 1 FGD Scrubber Stack, Pleasant Prairie, WI, January 24 and 25, 2007 We Energies Pleasant Prairie Power Plant, Unit 2 FGD Scrubber Stack, Pleasant Prairie, WI, May 23 and 24, 2007Technical Memorandum: Emissions Factors for Condensable Particulate Matter Emissions from EGUs

August 20 , 2008 Page 16 Northern Wisconsin Center, #3 Boiler Exhaust Stack, Chippewa Falls, WI , March 15, 2005 Wisconsin Public Service Corporation Weston Power Plant, Unit 4 Auxiliary Boiler Stack, November 27, 2007 Alliant Energy

Edgewater Generating Station, Unit 4 Out let Duct, Sheboy gan, WI , March 19, 2002 Mendota mental Health heating Plant, #2 Boiler Exhaust, Madison, WI , March 21, 2003 Wisconsin Power and L ig ht Nelson Dewey Generation Station Cassville, Units 1 and 2, Cassville, WI , February

22 and 24, 2005 Manit owoc Public Utilities Custer Plant, Combustion Turbine Stack, Manitowoc, WI , October 2

- 5, 2001 We Energies Port Washington Power Plant, Combustion Turbine 21, Port Washington, WI , October 10

- 11, 2005 Wisconsin Public Service Corporation Weston Power Plan t, Combustion Turbine 32 South Stack, Rothschild, WI , December 29

- 30, 2005 Madison Gas and Electric Company West Campus Cogeneration Facility , Unit 2, Madison, WI , April 11, 12, 15,16, 2005 Madison Gas and Electric Company West Campus Cogeneration Facili ty , Unit 1 and the Diesel Engine Backup Generator, Madison, WI , February 21 and 22, 2006 Wisconsin Public Service Corporation Petenwell Dam Hy dro Site, Simple Cy cle Combustion Turbine, Necedah, WI, September 2

- 5, 2003 Arcadia Municipal Electric Utility , No. 7 Diesel Engine Outlet, Arcadia, WI, July 31, 2002 Wisconsin Public Service Corporation Weston Power Plant, Unit 4 Main Diesel Fire Pump, Rothschild, WI , January

23, 2007 Wisconsin Public Service Corporation Weston Power Plant, Unit 4 Diesel Booster Fire Pump, February 26, 2008