MACTEC, Inc. 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories for VISTAS 

MACTEC, Inc. i 

Table of Contents 

Introduction .................................................................................................................................................................1 

1.0 2012 POINT SOURCE INVENTORY DEVELOPMENT.................................................................................2

1.1 EGU EMISSION PROJECTIONS .....................................................................................................................2

1.1.1 2012 IPM Projections............................................................................................................................3

1.1.2 Adjustments to IPM 2012 Projections ...................................................................................................4

1.1.2.1 Stack Exhaust Gas Temperature Adjustments ............................................................................................. 4

1.1.2.2 PM Emissions Adjustments ......................................................................................................................... 4

1.1.2.3 S/L Agency Adjustments ............................................................................................................................. 5

1.1.3 QA/QC of 2012 EGU Projections..........................................................................................................5

1.1.4 Summary of 2002/2009/2012/2018 EGU Point Source Inventories ......................................................6

1.2 NON-EGU EMISSION PROJECTIONS...........................................................................................................19

1.2.1 Growth assumptions for non-EGU sources .........................................................................................19

1.2.2 Control Programs applied to non-EGU sources .................................................................................21

1.2.3 S/L Adjustments to 2012 Projections ...................................................................................................21

1.2.4 QA/QC of 2012 NonEGU Projections .................................................................................................22

1.2.5 Summary of 2002/2009/2012/2018 nonEGU Point Source Inventories ..............................................22

2.0 2012 PROJECTION INVENTORY FOR NONROAD SOURCES ................................................................34

3.0 2012 AREA SOURCE PROJECTIONS ............................................................................................................39

3.1 VA CHANGES............................................................................................................................................39

3.2 NC CHANGES ............................................................................................................................................42

3.3 AREA SOURCE RESULTS............................................................................................................................42

4.0 2012 ONROAD MOBILE SOURCES ...............................................................................................................48

4.1 DEVELOPMENT OF ON-ROAD MOBILE SOURCE INPUT FILES........................................................................48

4.1.1 Preparation of revised 2012 input data files .......................................................................................48

4.1.2 VMT Data ............................................................................................................................................49

4.2 PROCESSING OF ON-ROAD MOBILE SOURCE EMISSIONS ...........................................................................50

4.3 ON-ROAD EMISSION SUMMARIES ..............................................................................................................52

Appendix A: EGU Controls for Coal and Oil/gas Units 
Documentation of the 2012 Emission Inventory 

MACTEC, Inc. ii 

List of Tables 

Table 1.1-1. Adjustments to IPM Results Specified by S/L Agencies for the 2012 EGU 

Inventory. 

Table 1.1-2. EGU Point Source SO2 Emission Comparison for 2002/2009/2012/2018. 

Table 1.1-3. EGU Point Source NOx Emission Comparison for 2002/2009/2012/2018. 

Table 1.1-4. EGU Point Source VOC Emission Comparison for 2002/2009/2012/2018. 

Table 1.1-5. EGU Point Source CO Emission Comparison for 2002/2009/2012/2018. 

Table 1.1-6. EGU Point Source NH3 Emission Comparison for 2002/2009/2012/2018. 

Table 1.1-7. EGU Point Source PM10-PRI Emission Comparison for 2002/2009/2012/2018. 

Table 1.1-8. EGU Point Source PM2.5 -PRI Emission Comparison for 2002/2009/2012/2018. 

Table 1.2-1. Facility Shutdowns Incorporated in the 2012 Non-EGU Inventory. 

Table 1.2-2. Other S/L Agency Changes Incorporated in the 2012 Non-EGU Inventory. 

Table 1.2-3. Non-EGU Point Source SO2 Emission Comparison for 2002/2009/2012/2018. 

Table 1.2-4. Non-EGU Point Source NOx Emission Comparison for 2002/2009/2012/2018. 

Table 1.2-5. Non-EGU Point Source VOC Emission Comparison for 2002/2009/2012/2018. 

Table 1.2-6. Non-EGU Point Source CO Emission Comparison for 2002/2009/2012/2018. 

Table 1.2-7. Non-EGU Point Source NH3 Emission Comparison for 2002/2009/2012/2018. 

Table 1.2-8. Non-EGU Point Source PM10-PRI Emission Comparison for 2002/2009/2012/2018. 

Table 1.2-9. Non-EGU Point Source PM25-PRI Emission Comparison for 

2002/2009/2012/2018. 

Table 2.0-1. 2012 Emissions Projections for NONROAD Model Sources (tons). 

Table 2.0-2. Estimated Emission Reduction Impacts for 2012 based on T4 Rule. 

Table 2.0-3. 2012 Emissions Projections for Aircraft, Locomotives, and Commercial Marine 

Vessels (tons per year). 

Table 3.1-1. 2012 Control Efficiency (CE), Rule Effectiveness (RE), Rule Penetration (RP) 

and Control Device ID for VA Counties with OTC Controls. 

Table 3.3-2. Comparison of the 2012 ASIP NH3 Emissions with 2002, 2009 and 2018 VISTAS 

B&F Inventory Values. 

Table 3.3-3. Comparison of the 2012 ASIP NOx Emissions with 2002, 2009 and 2018 VISTAS 

B&F Inventory Values. 

Table 3.3-4. Comparison of the 2012 ASIP PM10 Emissions with 2002, 2009 and 2018 VISTAS 

B&F Inventory Values. 

Table 3.3-5. Comparison of the 2012 ASIP PM2.5 Emissions with 2002, 2009 and 2018 VISTAS 

B&F Inventory Values. 

Table 3.3-6. Comparison of the 2012 ASIP SO2 Emissions with 2002, 2009 and 2018 VISTAS 

B&F Inventory Values. 
Documentation of the 2012 Emission Inventory 

MACTEC, Inc. iii 

Table 3.3-7. Comparison of the 2012 ASIP VOC Emissions with 2002, 2009 and 2018 VISTAS 

B&F Inventory Values. 

Table 4.3-1. On-road Mobile Source SO2 Emission Comparison. 

Table 4.3-2. On-road Mobile Source NOx Emission Comparison. 

Table 4.3-3. On-road Mobile Source VOC Emission Comparison. 

Table 4.3-4. On-road Mobile Source CO Emission Comparison. 

Table 4.3-5. On-road Mobile Source NH3 Emission Comparison. 

Table 4.3-6. On-road Mobile Source PM10 Emission Comparison. 

Table 4.3-7. On-road Mobile Source PM2.5 Emission Comparison. 
Documentation of the 2012 Emission Inventory 

MACTEC, Inc. 1

Documentation of the 2012 Projection Emission Inventory 

Introduction

This document provides information related to the development of the 2012 projection 

emission inventory prepared for the Association for Southeastern Integrated Planning 

(ASIP). The emissions developed were prepared using methods similar to those used for 

the Visibility Improvement State and Tribal Association of the Southeast (VISTAS) 2009 

and 2018 emission inventories. MACTEC Engineering and Consulting, Inc (MACTEC) 

prepared estimates for point, area, and nonroad sectors. The details on how each of these 

sectors was projected to 2012 are provided below. This initial 2012 inventory was 

developed by MACTEC and reviewed by the states in June 2008, revised and delivered 

by MACTEC in NIF format to the VISTAS emissions and air quality modeling team in 

July 2008. 
Documentation of the 2012 Emission Inventory 

2

1.0 2012 Point Source Inventory Development 

The starting point for the development of the ASIP 2012 point source emission inventory was the 

2009 VISTAS Best & Final (B&F) inventory. The 2009 B&F inventory has been extensively 

reviewed, updated, and approved by the VISTAS States. Complete documentation of the 2009 

B&F inventory is contained in Documentation of the Base G2 and Best & Final 2002 Base Year, 

2009 and 2018 Emission Inventories for VISTAS (B&F Document), March 14, 2008, prepared by 

MACTEC Engineering and Consulting, Inc.. 

We used different approaches for different sectors of the 2012 point source inventory: 

 For the EGUs, we relied primarily on the Integrated Planning Model® (IPM®) to project 

generation in 2012 as well as to calculate the impact of regulatory control programs on 

emissions in 2012. The IPM results were adjusted based on S/L agency knowledge of 

planned emission controls at specific EGUs that were likely to be in place in 2012. 

 For non-EGUs, we used growth and control data consistent with the data used in EPA’s 

Clean Air Interstate Rule (CAIR) analyses, and supplemented these data with available 

S/L agency knowledge of planned emission controls or other changes at specific nonEGUs. 

For both sectors, we generated the 2012 inventory to account for post-2002 emission reductions 

from promulgated and proposed non-EGU federal control programs as of July 1, 2004; the final 

proposed Clean Air Interstate Rule (CAIR); consent decrees, and other State, local, and sitespecific control programs. Section 1.1 discusses the EGU projection inventory development, 

while Section 1.2 discusses the non-EGU projection inventory development. The inventory was 

completed prior to the DC Circuit Court vacatur of CAIR. Thus the initial 2012 ASIP inventory 

includes EGU controls assumed under CAIR implementation. After the CAIR vacatur, the states 

developed inventories for legally enforceable controls in absence of the CAIR requirements. 

These inventories are documented in a separate report (Documentation of the VISTAS/ASIP “NoCAIR” 2009, 2012, and 2018 Emission Inventory for Electric Generating Units, October, 2008). 

1.1 EGU Emission Projections 

The following subsections discuss the following specific aspects of the development of the EGU 

projections. First, we briefly describe how the IPM was used to develop emission projections for 

2012. Second, we document the changes to the IPM results that S/L agencies specified for 

incorporation in the ASIP 2012 inventory based on new information that was not accounted for 

in the IPM runs. Finally, we present summaries of the base year and projected EGU emissions by 

state and pollutant. 
Documentation of the 2012 Emission Inventory 

3

1.1.1 2012 IPM Projections 

For previous modeling efforts for 2009 and 2018, VISTAS relied primarily on IPM to project 

future generation as well as to calculate the impact of future emission control programs. Section 

2.1.1 of the B&F Document provides a detailed discussion of VISTAS’s use of the IPM to 

project emissions in 2009/2018 from EGUs, including the following topics: 

 A chronology of the evolution of the EGU emission projection methodology, resulting in 

the ultimate use of IPM runs sponsored by VISTAS/CENRAP that are referred to as 

VISTAS/CENRAP Phase II analysis (called IPM VISTAS version 2.1.9); 

 A description of the post-processing of the IPM parsed files to estimate emissions for 

pollutants other than SO2 and NOx; augment the IPM results by adding in control 

efficiencies, stack parameters, latitude-longitude coordinates, and State identifiers (plant 

ID, point ID, stack ID, process ID); site generic units to account for new generation 

capacity; and avoid double counting of EGU emissions. 

 A description of quality assurance steps taken to ensure that the IPM results were 

properly merged with the State’s point source emission inventory. 

The 2012 EGU projections were based primarily on the IPM VISTAS version 2.1.9 results in the 

same manner that the 2009/2018 projections were made. 

MACTEC obtained the 2012 IPM parsed file from the LADCO web site: 

http://www.ladco.org/Regional_Air_Quality.html 

File: VISTASII_PC_1f_All_Units_2012 (To Client) 08-12-05.xls 

LADCO developed 2012 NIF files for EGUs from the IPM parsed files. MACTEC obtained the 

NIF files from the MARAMA ftp site: 

ftp.marama.org

User Name: mane-vu 

Password: exchange 

Folder: 2012 EGU files for GA 

Files: 2012b_ipm.tgz (zip file with NIF tables – TR, SI, ER, EU, EP, PE, CE, and EM) 

MACTEC developed several QA reports to verify that the post-processed NIF files were 

consistent with the results contained in the IPM parsed files. We verified that the emissions in 

the NIF 2012 EM file for SO2 and NOx were the same as those contained in the IPM 2012 parsed 

file. 

MACTEC next developed algorithms to perform a unit-by-unit matching of the 2012 EGU NIF 

files and the 2009 VISTAS B&F NIF files. Various efforts were made to ensure proper 

matching of existing units and the addition of new generic units in 2012 that were not in the 2009 
Documentation of the 2012 Emission Inventory 

4

file. Once the matching of units was accomplished, MACTEC used the projected emissions 

from the 2012 post-processed NIF files as the starting point for the 2012 inventory for EGUs in 

the VISTAS/ASIP states. The VISTAS/ASIP Emission Inventory Technical Advisor used these 

same methods to process MANE-VU and MRPO 2012 EGU files for use in ASIP air quality 

modeling. 

1.1.2 Adjustments to IPM 2012 Projections 

Several adjustments to the information obtained from the post-processed 2012 IPM/NIF files 

were necessary. These adjustments are described in this section. 

1.1.2.1 Stack Exhaust Gas Temperature Adjustments 

Changes to stack parameters were also made in cases where new controls are scheduled to be 

installed. In cases where an emission unit was projected to have a SO2 scrubber in both 2009 and 

2012, some States were able to provide revised stack parameters for some units based on design 

features for the new control system. These stack parameters were used when available. Other 

units projected to install scrubbers by 2012 are not far enough along in the design process to 

have specific design details. For those units, the same process adopted by the VISTAS EGU 

SIWG was used. That process included the following assumptions: 1) the scrubber is a wet 

scrubber; 2) the current stack height was maintained; 3) the current flow rate was maintained, 

and 4) the stack exit temperature was changed to 169 degrees F (this is the virtual temperature 

derived from a wet temperature of 130 degrees F). VISTAS EGU SIWG had determined that an 

exit temperature (wet) of 130 degrees F +/- 5 degrees F is representative of different size units 

and wet scrubber technology. 

1.1.2.2 PM Emissions Adjustments 

As was the case with the 2009/2018 EGU projections, we identified significantly higher PM 

emissions in the 2012 post-processed IPM/NIF files than in the VISTAS B&F 2002 inventory. 

VISTAS had determined that the emission increase from 2002 to 2009/2018 was simply an 

artifact of the change in emission factor, not anything to do with changes in activity or control 

technology application. As a result, for ASIP MACTEC decided to base the 2012 PM emissions 

on the State-supplied 2002 PM emissions and adjust the 2002 emissions based on the ratio of 

forecasted heat input to base year heat input. For the 2009 VISTAS B&F inventory VISTAS had 

used the emission rate (as calculated from 2002 emissions and heat input) in conjunction with the 

IPM forecasted 2009 heat input to generate 2009 PM10/PM2.5 emissions. For 2012, we used the 

2009 B&F emissions and associated IPM heat input to generate a new 2009 emission rate for 

VISTAS units, and then used that same emission rate with IPM forecasted 2012 heat input 

estimates to get the 2012 ASIP emissions. States did not identify any new PM controls that were 

to be applied between 2009 and 2012. 
Documentation of the 2012 Emission Inventory 

5

1.1.2.3 S/L Agency Adjustments 

For the 2012 inventory, adjustments previously made to the 2009/2018 VISTAS B&F 

inventories were reviewed for consistency with the IPM 2012 control assumptions. Consistency 

means that no unit has lower controls in 2012 compared to the VISTAS 2009 B&F controls. 

However, there are instances where there are more controls in 2012 compared to the VISTAS 

2009 B&F controls. For example, when IPM predicts no controls in 2009 but does predict 

controls in 2012, the 2012 controls used were based on the 2012 IPM control assumption. 

For the 2012 inventory, S/L agencies reviewed the 2012 IPM results and specified a number of 

changes to better reflect current information on when/where future controls would occur and 

when/where new generating capacity would come on-line. Specifically, S/L agencies reviewed 

the 2012 IPM results to: 

 Identify any updates needed to better reflect current information on when and where 

future controls would occur based on the best available data from state rules, enforcement 

agreements, compliance plans, permits, and discussions/commitments from individual 

companies; 

 Identify any updates needed to change the IPM determination that most oil/gas steam 

units would either retire early or have no operation in 2009 or 2018; and 

 Identify any updates needed to change the IPM assignment and VISTAS post-processing 

of generic units with specific information on new capacity. 

A comparison of the IPM and ASIP control assumptions for all coal- and oil-fired steam plants in 

the 2012 inventory are summarized in Appendix A. 

1.1.3 QA/QC of 2012 EGU Projections 

We prepared several data files for review by the State and local agencies to confirm the emission 

projections for 2012: 

 We maintained a log of requested changes that identified the name of the person/agency 

requesting the change, the date of the request, the nature of the change, and MACTEC’s 

action to address the change request. This log was circulated among the States to ensure 

that all change requests were addressed and acted upon. 

 We prepared a master spreadsheet that identified all coal- and oil-fired units and included 

both the IPM-generated and VISTAS Best & Final SO2 and NOx emissions for 2002, 

2009, 2012, and 2018; also included in the spreadsheet was an identification of postcombustion controls (i.e., scrubbers, SCRs) as generated by IPM and as assigned in the 

VISTAS Best & Final inventory. 

 We provided NIF files for State and local agency review and comment. 
Documentation of the 2012 Emission Inventory 

6

State and local agency reviewed these files, which resulted in several iterations of changes and 

final confirmation by each State accepting the results of the 2012 EGU inventory. The changes 

to the 2012 IPM results are documented in the Table 1.1-1. 

1.1.4 Summary of 2002/2009/2012/2018 EGU Point Source Inventories 

Tables 1.1-2 through 1.1-8 summarize the B&F 2002/2009/2018 EGU point source inventories 

as well as the initial 2012 ASIP EGU inventory. Some notable changes in emissions by pollutant 

include: 

 SO2 emissions gradually decrease from 2002 to 2018 due to the projected installation of 

scrubbers to meet CAIR or other requirements. 

 NOx emissions generally decrease from 2002 to 2018 due to the projected installation of 

SCRs to meet CAIR or other requirements. For SC, NOx emissions increased from 2009 

to 2012 due to two new Santee Cooper coal units planned for Florence County with NOx

permitted emissions of 3,500 additional tons in 2012. For VA, NOx emissions in 2012 

are lower than in 2009 and 2018 because VA used actual emissions for the Possum Point 

plant in 2012 to better reflect future emission levels; previously for 2009 and 2018, VA 

used the permitted emission rates based on VA’s understanding from EPA Region 3 that 

modeling for the 2009 attainment plan should reflect the permitted NOx levels. For WV, 

NOx emissions in 2012 are higher than in 2009 and 2018 because WV changed the 

control assumptions for the Harrison and Kammer plants based on updated information 

that was not available when the 2009 and 2018 inventories were developed. 

 CO and VOC emissions generally increase from 2002 to 2018 because of increased 

generation capacity, particularly in gas-fired gas turbines and combined cycle units. 

 PM10 and PM2.5 emissions generally increase from 2002 to 2018 in States (NC, SC, and 

VA) where IPM generated coal-fired “Generic Units” - each coal-fired Generic plant 

adds about 1500 – 1800 tons of PM10 and PM2.5. Also, new gas-fired Generic Units are 

adding smaller amounts of PM. Florida showed a large decrease in PM emissions from 

2012 to 2018 due to retirement of several large oil-fired units. 

 NH3 emissions generally increase from 2002 to 2018 due to projected installation of 

SCRs to meet CAIR or other requirements. NH3 emissions in 2012 tend to be higher than 

in 2018 due primarily to a difference in the emission factors used in 2012 versus 2018. 

Other minor inconsistencies between the 2012 inventory and the 2009/2018 inventories result 

from States providing updated information that was not available when the 2009 and 2018 

inventories were developed. 
Documentation of the 2012 Emission Inventory 

7

Table 1.1-1. Adjustments to IPM Results Specified by S/L Agencies 

for the 2012 EGU Inventory. 

State Plant Name and ID Unit Nature of Update/Correction 

AL Alabama Power – 

Green County 

ORIS=10 

1 & 2 IPM assigned scrubbers in 2012; AL does not expect 

scrubbers to be operational in 2012; removed scrubber 

controls (90% for SO2) from these two units. 

 Alabama Power - 

Miller 

ORIS=6002 

1 to 4 IPM did not have scrubbers in 2012, AL expects scrubbers 

to be operational in 2012; added scrubber controls (90% 

reduction) for these four units; reduced NOx emissions to 

account for year round operation compared to IPM 

assumption of ozone season operation only. 

 Alabama Power - 

Barry 

ORIS=3 

1-4 Added SNCR controls (35% reduction in NOx emissions) 

that were not accounted for in IPM. 

 Alabama Power - 

Barry 

ORIS=3 

5 IPM did not have scrubber or SCR in 2012, AL expects both 

scrubber and SCR to be operational in 2012; added scrubber 

and SCR controls (90% reduction in both SO2 and NOx) for 

Unit 5. 

 Alabama Power - 

E C Gaston 

ORIS=26 

1 to 4 IPM had reduced 2012 emissions by about 50% from 2002 

emissions; used 2002 emissions for 2012 since AL could not 

determine the reason for the 50% reduction. 

IPM assigned SCRs in 2012; AL does not expect SCRs to be 

operational in 2012; removed SCR controls (90% for NOx) 

from these four units. 

 Alabama Power - 

E C Gaston 

ORIS=26 

5 IPM did not have scrubber in 2012, AL expects scrubber to 

be operational in 2012; added scrubber controls (90% 

reduction) for Unit 5. 

 Alabama Power - 

Gorgas 

ORIS=8 

8, 9, 10 IPM did not have scrubbers in 2012, AL expects scrubbers 

to be operational in 2008; added scrubber controls (90% 

reduction) for these units. 

 AL Electric Coop - 

Charles R Lowman 

ORIS=56 

1 IPM did not have scrubber in 2012, AL expects scrubber to 

be operational in 2012; added scrubber controls (90% 

reduction) for Unit 1. 

FL Cape Canaveral 

Indian River 

Port Everglades 

Turkey Point 

Manatee 

Martin 

Riviera 

Anclote 

CD McIntosh 

Northside B 

Suwannee River 

1, 2 

1, 2, 3 

1 – 4 

1, 2 

1, 2 

1, 2 

3, 4 

1, 2 

1 

3 

3 

The IPM 2012 solution has either shut-down these oil-fired 

units or converted them to natural gas only. FLDEP has 

reason to believe that these units may continue to operate 

using oil. We assumed that the oil-fired units will operate in 

2012 exactly as they operated in 2002. 
Documentation of the 2012 Emission Inventory 

8

Table 1.1-1 – (continued) 

State Plant Name and ID Unit Nature of Update/Correction 

FL Northside 

ORISID=667 

1A, 1B These units were estimated to be non operational by IPM in 

2012. FLDEP believes these units will continue to operate. 

Emissions were estimated using the 2002 base case 

emissions and growth factors for Northside units 1A and 2A. 

 Cedar Bay Generating 

ORISID=10672 

GEN1 FLDEP disagrees with IPM projections - no knowledge of 

expansion of this facility and the cogeneration facility 

should not grow faster than the underlying industry. Cedar 

Bay is connected to Stone Container (12-031-0310067). 

Replaced IPM emissions with 2002 emissions for Cedar Bay 

(12-031-0310337) times the growth factors for Stone 

Container. 

 Crist 

ORISID=641 

4, 5 

6, 7 

IPM did not assign scrubbers to these units in 2012. 

Scrubbers are currently being installed and should be 

operational in 2009. SO2 emissions reduced by 90% for all 

four units. 

 Indiantown Cogeneration 

ORISID=50976 

GEN1 FLDEP disagrees with IPM projections - no knowledge of 

expansion of this facility and the cogeneration facility 

should not grow faster than the underlying industry. 

Indiantown is connected to Louis Dreyfus Citrus (12-085-

0850002). Replaced IPM emissions with 2002 emissions for 

Indiantown (12-085-0850102) times the growth factors for 

Louis Drefus Citrus. 

 Central Power and Lime 

ORISID= 10333 

GEN1 Central Power and Lime (ORIS10333) is a duplicate entry. 

This is point 18 in Florida Crushed Stone (12-053-0530021). 

Removed IPM emissions for Central Power and Lime. 

GA Georgia Power - 

Bowen 

ORIS=703 

1BLR 

2BLR 

3BLR 

4BLR 

GA EPD updated scrubber efficiency to reflect 95% 

reduction in SO2 compared to IPM reduction of about 90%. 

 Georgia Power - 

McDonough 

ORIS=710 

MB1, 

MB2 

Coal boilers units 1 & 2 are being decommissioned and 

replaced with three (dual unit) gas-fired combustion turbine 

blocks (6 units). These units will contain SCR controls and 

exhaust through separate stacks (6 stacks). IPM projected 

emissions were evenly distributed between the six units and 

the following emission reductions applied: 99.8% SO2

reductions, 85.6% NOx reductions, and 62.3% PM2.5

reductions. 

GA Georgia Power - 

Hammond 

ORIS=708 

1, 2, 3 IPM did not assign reductions from scrubbers to these units 

in 2012; GA EPD expects scrubbers to be operational in 

2012; added scrubber controls (95% reduction in SO2) for 

these units. 

 Georgia Power - 

Hammond 

ORIS=708 

4 IPM assigned scrubber to this unit in 2012; GA EPD 

updated scrubber efficiency to reflect 95% reduction in SO2

compared to IPM reduction of about 90%. 
Documentation of the 2012 Emission Inventory 

9

Table 1.1-1 – (continued) 

State Plant Name and ID Unit Nature of Update/Correction 

GA Georgia Power - 

Wansley 

ORIS=6052 

1, 2 IPM assigned scrubber to these units in 2012; GA EPD 

updated scrubber efficiency to reflect 95% reduction in SO2

compared to IPM reduction of about 90%. 

 Georgia Power - 

Scherer 

ORIS=6257 

3 IPM did not assign scrubber to this unit in 2012; GA EPD 

expects scrubber to be operational in 2012; added scrubber 

controls (95% reduction in SO2) for this unit. 

 Georgia Power - 

Harllee Branch 

ORIS=709 

3 IPM did not assign SCR to this unit in 2012; GA EPD 

expects SCR to be operational in 2012; added SCR controls 

(82.5% reduction in NOx) for this unit. 

 Generic Unit 

ORIS=900113 

1 Set emissions to zero for the IPM assigned coal-fired 

Generic Unit (ORIS900113) in Walton County (13297). 

KY Kentucky Utilities - 

Ghent 

ORIS=1356 

1, 2, 

3, 4 

IPM did not assign scrubbers to units 2, 3, and 4 in 2012; 

KY expects scrubbers to be operational in 2012; added 

scrubber controls (90% reduction in SO2) for these units. 

IPM did not assign SCR to unit 1 in 2012; KY expects SCR 

to be operational in 2012; added SCR controls (90% 

reduction in NOx) for Unit 1. Changed SCR efficiency to 

90% for units 3 and 4. 

 Western KY Energy 

Coleman 

ORIS=1381 

C1, C2, 

C3 

IPM did not assign scrubbers to these units in 2012; KY 

expects scrubbers to be operational in 2012; added scrubber 

controls (90% reduction in SO2) for these units. 

 Kentucky Power - 

Big Sandy 

ORIS=1353 

BSU2 IPM assigned scrubber to this unit in 2012; KY does not 

expect scrubbers to be operational in 2012; removed 

scrubber controls (90% for SO2) from this unit. 

 Kentucky Utilities – 

E W Brown 

ORIS=1355 

1, 2, 3 IPM did not assign scrubbers to these units in 2012; KY 

expects scrubbers to be operational in 2012; added scrubber 

controls (90% reduction in SO2) for these units. 

HMP&L Station 2 

ORIS=1382 

H2 IPM did not assign SCR to this unit in 2012; KY expects 

SCR to be operational in 2012; added SCR controls (90% 

reduction in NOx) for this unit. 

MS Entergy Delta 

Entergy Rex Brown 

Entergy Baxter Wilson 

Entergy Gerald Andrus 

1, 2 

3, 4 

1, 2 

1 

The IPM 2009/2018 solution has either shut-down these oilfired units or converted them to natural gas only. MSDEQ 

has reason to believe that these units may continue to 

operate using oil. To be conservative, MSDEQ assumed that 

the oil-fired units will operate in 2009/2018 exactly as they 

operated in 2002. 

 Jack Watson (2049) 

Victor J Daniel (6073) 

Chevron Oil (2047) 

All MS DEQ specified that the emission projections provided by 

the Southern Company for their units in Mississippi were to 

be used instead of the IPM results. 

 R D Morrow 

ORISID=6061 

1, 2 Revised the 2012 emissions to reflect controls that will be 

coming online 2009 or 2010 per guidance from MS DEQ. 

Table 1.1-1 – (continued) 
Documentation of the 2012 Emission Inventory 

10

State Plant Name and ID Unit Nature of Update/Correction 

NC G G Allen (2718) 

Belews Creek (8042) 

Buck (2720) 

Cliffside (2721) 

Dan River (2723) 

Marshall (2727) 

Riverbend (2732) 

All Replaced all IPM 2012 results with emission projections 

from Duke Power’s NC Clean Air Compliance Plan for 

2008. 

Added Unit 6 to Cliffside which was not in IPM 2012. 

 Asheville (2706) 

Cape Fear (2708) 

Lee (2709) 

Mayo (6250) 

Roxboro (2712) 

Sutton (2713) 

Weatherspoon (2716) 

All Replaced all IPM 2012 results with emission projections 

from Progress Energy’s NC Clean Smokestacks Act 

Calendar Year 2008 compliance plan. 

 Dwayne Collier Battle 

Cogeneration Facility 

ORISID=10384 

GEN1 

GEN2 

Dwayne Collier Battle is a duplicate entry. This is Cogentrix 

of Rocky Mount (37-065-3706500146, stacks G-26 and G27). Duplicate entries were removed from the 2012 

inventory. 

 Kannapolis Energy 

Partners 

ORISID=10626 

GEN2 

GEN3 

Kannapolis Energy emissions are being used as credits for 

another facility. IPM emissions from this facility (37-025-

ORIS10626) were removed from the EGU inventory for 

2012. Emissions from Kannapolis Energy (37-025-

3702500113) were carried forward in the 2012 inventory. 

Generic Unit 

ORIS=900137 

 Set emissions to zero for the coal-fired Generic Unit IPM 

projected for Cleveland County where Cliffside units 6 will 

be 

SC 99 Oil-fired Units The IPM 2012 solution has either shut-down 99 oil-fired 

units or converted them to natural gas only. SCDHEC has 

reason to believe that these units may continue to operate 

using oil. To be conservative, SCDHEC assumed that the 

oil-fired units will operate in 2012 exactly as they operated 

in 2002. 

 Santee Cooper - 

Jefferies 

ORIS=3319 

3 IPM assigned SCR in 2012; SC does not expect SCR to be 

operational in 2012; removed SCR controls (90% for NOx) 

from this unit. 

 SCE&G – Canadys 

ORIS=3280 

CAN3 IPM did not assign scrubbers to this unit in 2012; SC expects 

scrubber to be operational in 2012; added scrubber controls 

(90% reduction in SO2) for this unit. 

 SCE&G – Wateree 

ORIS=3297 

WAT1 IPM did not assign scrubbers to this unit in 2012; SC expects 

scrubber to be operational in 2012; added scrubber controls 

(90% reduction in SO2) for this unit. 
Documentation of the 2012 Emission Inventory 

11

Table 1.1-1 – (continued) 

State Plant Name and ID Unit Nature of Update/Correction 

SC Santee Cooper Cross 

ORISID=130 

1, 2 Unit 1: upgrade scrubber from 82 percent to 95 percent 

removal efficiency by June 30, 2006. Recalculate emissions 

based on upgrade in control efficiency. 

Unit 2: upgrade scrubber from 70 percent to 87 percent 

removal efficiency by June 30, 2006. Recalculate emissions 

based on upgrade in control efficiency. 

 Santee Cooper Cross 

ORISID=130 

4 Added in a new 660 MW Unit 4 (not in IPM) that is 

identical to the new Unit 3 (which was in IPM). NOx

permitted emissions for these two units were 1,750 tpy each, 

for a total of 3,500 additional tons in 2012. 

 Winyah 

ORISID=6249 

1 – 4 Unit 1: Install scrubber that meets 95 percent removal 

efficiency by Dec. 31, 2008; Upgrade ESP from 0.38 to 0.03 

lb/mmBTU by Dec. 31, 2008 

Unit 2: Replace scrubber with one that meets 95 percent 

removal efficiency from 45 percent by Dec. 31, 2008; 

Upgrade ESP from 0.10 to 0.03 lb/mmBTU by Dec. 31, 

2008 

Unit 3: Upgrade scrubber from 70 percent to 90 percent 

removal efficiency by Dec. 31, 2012; Upgrade ESP from 

0.10 to 0.03 lb/mmBTU by Dec. 31, 2012 

Unit 4: Upgrade scrubber from 70 percent to 90 percent 

removal efficiency by Dec. 31, 2007; Upgrade ESP from 

0.10 to 0.03 lb/mmBTU by Dec. 31, 2007 

Recalculated SO2 and PM emissions based on upgrade in 

control efficiencies. 

TN TVA Johnsonville 

ORIS=3406 

1 - 10 IPM assigned SCRs in 2012; TN does not expect SCRs to be 

operational in 2012; removed SCRs controls (90% for NOx) 

from these units. 

 TVA Kingston 

ORIS=3407 

1 - 9 IPM did not assign scrubbers to these units in 2012; TN 

expects scrubbers to be operational in 2012; added scrubber 

controls (90% reduction in SO2) for these units. 

 TVA Kingston 

ORIS=3407 

9 IPM did not assign SCR to this unit in 2012; TN expects 

SCR to be operational in 2012; added SCR controls (90% 

reduction in NOx) for this unit. 

VA Dominion – Altavista 

ORIS=10773 

1, 2 Replaced IPM 2012 SO2 emissions with permit limit for 

facility supplied by VA DEQ. 

 Dominion – Chesterfield 

ORIS=3797 

3, 4 IPM did not assign scrubbers to these units in 2012; VA 

DEQ expects scrubbers to be operational in 2012; added 

scrubber controls and emissions provided by VA DEQ for 

these units. 

IPM did not assign SCR to this Unit 4 in 2012; VA DEQ 

expects SCR to be operational in 2012; added SCR controls 

(80% reduction in NOx) for this unit. 

 Birchwood Power Partners 

ORIS=54304 

1 Replaced IPM 2012 SO2 emissions with permit limit for 

facility supplied by VA DEQ. 
Documentation of the 2012 Emission Inventory 

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Table 1.1-1 – (continued) 

State Plant Name and ID Unit Nature of Update/Correction 

VA Mecklenburg Cogen 

ORIS=52007 

GEN1 

GEN2 

Replaced IPM 2012 SO2 emissions with permit limit for 

facility supplied by VA DEQ. 

 Dominion Possum Point 

ORISID=3804 

5 Unit 5: IPM had zero heat input. Replaced 2012 IPM result 

using VADEQ’s growth and control estimates. 

 3&4 2009/2018 emissions used the permitted level for the 

combined emissions from 3 &4 (3,066 tpy NOx) based on 

VADEQ understanding from EPA Region 3 that the 

modeling for the attainment plan should reflect the permitted 

NOx levels. For 2012, VA decided the permitted levels were 

in no way reflective of how the facility actually operates 

since the units operate very infrequently as they are now gas 

units. To make the 2012 runs truly reflective of future 

emission rates, VA used the IPM generated emission rates 

since IPM does correctly predict the gasification of these 

two units. Emissions for 2009 and 2018 were 3,066 tpy, but 

only 160 tpy in 2012 

 AEP Clinch River 

ORIS=3775 

1, 2, 3 Federal Consent Order caps facility emissions at 21,700 tpy 

SO2 starting 01/01/2010. IPM did not have scrubbers. 

Federal Consent Order requires SNCR on all 3 boilers by 

12/31/2009. IPM did not predict SNCR control on these 

units. A 40% reduction for SNCR was assumed. 

 LG&E Westmoreland 

ORIS=3775 

GEN1 Replaced IPM 2012 SO2 emissions with permit limit for 

facility supplied by VA DEQ. 

 Dominion Yorktown 

ORISID=3809 

1, 2, 3 Unit 3: IPM predicts zero heat input for this 880 MW #6 oil 

fired unit. Dominion plans to continue to operate Unit 3. 

Replaced all 2102 IPM results using VADEQ’s growth and 

control estimates. 

 Potomac River 

ORISID=3788 

1 - 5 No plans to retire #1 or #2. Facility is subject to a facility 

wide permit limitation of 3,813 tpy SO. 

Facility is limited by caps in VA CAIR rule to 1734 tpy NOx

beginning in 2009. 

 Dominion Chesapeake 

ORISID=3803 

1 – 4 Facility expects to continue use of South American coal, 

with 50% less sulfur content. 50% reduction in SO2

emissions assumed. 

SCR on #3 and #4 not included in IPM. Assumed 80% NOx

reduction for the SCR retrofit. 

 James River Cogeneration 

and Cogentrix Hopewell 

ORIS=10377 

1, 2 James River Cogeneration Company (51-670-00055) and 

Cogentrix Hopewell (51-670-ORIS10377) are the same 

facilities. Zeroed out the emission for 51-670-ORIS10377 

and updated emissions for 51-670-00055 per VA DEQ 

estimates. 
Documentation of the 2012 Emission Inventory 

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Table 1.1-1 – (continued) 

State Plant Name and ID Unit Nature of Update/Correction 

VA Dominion Southwest 

Virginia Project 

1 For 2012, replaced the IPM generated Generic Unit located 

in Richmond county (ORISID=900151) with the planned 

Dominion facility going into Wise County. Used the 

potential to emit for the Dominion facility. 

 LF&E Westmoreland 

Hopewell 

ORIS=10771 

GEN1 The facility was mothballed in 2002 and only recently 

started operating. Therefore, it wasn’t in the 2002 inventory. 

The facility was added as 51-670-ORIS10771 and emissions 

were updated per VA DEQ estimates. 

 Bear Garden 

CPV Warren 

 Added these two facilities with combined cycle units 

totaling about 1200 MW. To adjust the generic EGU 

inventory predicted by IPM, delete emissions for generic 

EGU’s firing natural gas and that are combined cycle. These 

units were located in Accomack County (FIPS 001) 

WV Mt. Storm 

ORISID=3954 

1, 2, 3 SO2 Permit Rate was corrected from 2.7 to 0.15 lb/MMBtu. 

Used SO2 Permit Rate of 0.15 lb/MMBtu and IPM predicted 

total fuel used to calculate SO2 emissions in 2012. 

 North Branch 

ORISID=7537 

1A, 1B SO2 Permit Rate was corrected from 2.7 to 0.678 lb/MMBtu. 

Used SO2 Permit Rate and IPM predicted total fuel used to 

calculate SO2 emissions in 2012 

 Monongahela Power – 

Harrison 

ORIS=3944 

1, 2, 3 The predicted 2012 plant total emissions are 18,000 SO2

tons and 9,000 NOx tons. 

This reflects a doubling of 2002 SO2 emissions and a 75% 

reduction of NOx emissions that are not reflected in installed 

or planned controls. 

Review of CAMD data from 2002 through 2007 indicates 

that the 2002 values are more reflective of our expectations 

for emissions from this source than the values provided. 

Please replace the 2012 data with 2002 emissions values for 

all pollutants. 

 Monongahela Power – 

Rivesville 

ORISID=3945 

7, 8 IPM predicted early retirement for these units. AEP 

indicated there are no plans for early retirement. For 2012, 

used 2002 actual emissions as these units are not likely to 

retire by 2012. 

 Morgantown Energy 

ORIS=10743 

1 This source had 2002 SO2 emissions of 850 tons and 2009 

emissions of 777 tons. The 2012 data shows nearly 3,600 

SO2 tons. We can think of no reason for such a large 

increase. NOx emissions do not differ that greatly from our 

expectations. Please replace the 2012 data with 2009 

emissions values for all pollutants. 
Documentation of the 2012 Emission Inventory 

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Table 1.1-1 – (continued) 

State Plant Name and ID Unit Nature of Update/Correction 

WV Generic Unit 

ORIS=900137 

 Set emissions to zero for the coal-fired Generic Unit IPM 

projected for Monongalia County since it is in the same 

county as Longview. 

 Ohio Power - 

Kammer 

ORIS=3947 

1, 2, 3 The predicted 2012 plant total emissions are 2,800 SO2 tons 

and 1,400 NOx tons. 

These values indicate 95% and 90% emission reductions of 

SO2 and NOx respectively from 2002 that are not reflected in 

installed or planned controls. 

Review of the AEP Consent Decree showed that Kammer is 

not required to operate controls until 2018. 

Review of CAMD data from 2002 through 2007 indicates 

that the 2002 values are more reflective of our expectations 

for emissions from this source than the 2012 values 

provided. Therefore, we could find no reason for the large 

emissions reductions seen in the 2012 data. 

Replaced the 2012 data with 2002 emissions values for all 

pollutants. 

 Longview 

Site ID: 54- 061-0134 

1 For 2012 inventory, added Longview which is permitted, 

under construction, and scheduled to be online in 2010. The 

unit is a 600 MW pulverized coal-fired unit with baghouse, 

LNB, SCR, and wet FGD as required controls. Used 

permitted emission rates for 2018. 

 Monongahela Power – 

Willow Island 

ORISID=3946 

1 IPM predicted early retirement for these Unit 1. AEP 

indicated there are no plans for early retirement. For 2012, 

used 2002 emissions as these units are not likely to retire by 

2012. 

 Pleasants Power Station 

ORISID=6004 

1, 2 IPM applied a scrubber with a 79.9% SO2 control efficiency; 

WV indicated that the control efficiency should be 95%. 

 Monongahela Power – 

Albright 

ORISID=3942 

1, 2 IPM predicted early retirement for these units. AEP 

indicated there are no plans for early retirement. For 2012, 

used 2002 actual emissions as these units are not likely to 

retire by 2012. 
Documentation of the 2012 Emission Inventory 

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Table 1.1-2. EGU Point Source SO2 Emission Comparison for 2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 447,828 378,052 255,861 135,851 

FL 453,631 291,831 291,952 194,028 

GA 514,952 408,679 235,377 68,515 

KY 484,057 271,669 250,281 222,102 

MS 67,429 76,646 57,154 15,213 

NC 477,990 242,286 149,977 120,165 

SC 206,399 129,122 101,762 95,377 

TN 334,151 255,410 183,255 112,672 

VA 241,204 174,777 106,519 98,988 

WV 516,084 268,952 213,799 106,199 

Total 3,743,725 2,497,423 1,845,937 1,169,110 

Note: Emission summaries above are based on SCCs 1-01-xxx-xx and 2-01-xxx-xx. 

Table 1.1-3. EGU Point Source NOx Emission Comparison for 

2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 161,038 82,305 75,643 64,358 

FL 257,677 132,535 135,015 87,645 

GA 147,517 98,497 86,250 69,856 

KY 198,817 97,263 90,151 64,378 

MS 43,135 47,276 39,562 21,535 

NC 151,853 66,521 66,924 61,110 

SC 88,241 48,668 53,030 51,751 

TN 157,307 66,405 67,568 31,715 

VA 86,886 64,358 57,621 64,344 

WV 230,977 85,476 103,184 51,474 

Total 1,523,448 789,304 774,948 568,166 

Note 1: Emission summaries above are based on SCCs 1-01-xxx-xx and 2-01-xxx-xx. 

Note 2: After the preparation of the emission files used for ASIP air quality modeling for 2012, 

three errors in NOx EGU emissions were discovered: – CP&L Roxboro Unit 3A was incorrectly 

modeled as 4,046 tpy instead of 1,046 tpy; TVA Kingston Unit 9 was incorrectly modeled as 

2,840 tpy instead of 284 tpy; and Owensboro Utilities Elmer Smith Unit 1 duplicate segment 1 
Documentation of the 2012 Emission Inventory 

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was incorrectly modeled as 433 tpy instead of 176 tpy. The corrected emissions were used in the 

above summary table. 

Table 1.1-4. EGU Point Source VOC Emission Comparison for 

2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 2,295 2,473 2,052 2,952 

FL 2,524 2,730 3,121 3,047 

GA 1,244 2,314 2,486 2,816 

KY 1,487 1,369 1,641 1,426 

MS 648 564 550 1,274 

NC 988 954 1,066 1,302 

SC 470 723 939 931 

TN 926 932 992 976 

VA 754 788 1,033 980 

WV 1,180 1,361 1,393 1,387 

Total 12,516 14,208 15,274 17,091 

Note: Emission summaries above are based on SCCs 1-01-xxx-xx and 2-01-xxx-xx. 

Table 1.1-5. EGU Point Source CO Emission Comparison for 2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 11,279 14,986 21,122 24,342 

FL 57,113 71,072 85,284 85,495 

GA 9,712 23,721 26,271 44,269 

KY 12,619 15,812 17,098 17,144 

MS 5,303 7,116 9,574 17,348 

NC 13,885 14,942 13,212 19,870 

SC 6,990 11,643 15,271 14,975 

TN 7,084 7,214 7,850 7,723 

VA 6,892 12,535 18,322 18,850 

WV 10,341 11,493 12,716 12,397 

Total 141,218 190,535 226,719 262,413 

Note: Emission summaries above are based on SCCs 1-01-xxx-xx and 2-01-xxx-xx. 
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Documentation of the 2012 Emission Inventory 

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Table 1.1-6. EGU Point Source PM10-PRI Emission Comparison for 2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 7,646 6,969 7,210 7,822 

FL 21,387 20,182 20,638 12,791 

GA 11,224 17,891 17,607 20,732 

KY 4,701 6,463 6,658 6,694 

MS 1,633 5,182 5,322 7,412 

NC 22,754 22,152 23,717 35,275 

SC 21,400 20,041 21,042 27,640 

TN 14,640 15,608 15,785 15,941 

VA 3,960 5,606 5,815 12,551 

WV 4,573 5,657 5,679 5,784 

Total 113,918 125,750 129,473 152,642 

Note1: Emission summaries above are based on SCCs 1-01-xxx-xx and 2-01-xxx-xx. 

Note 2: After the preparation of the emission files used for ASIP air quality modeling for 2012, an 

error in PM10 EGU emissions were discovered for Owensboro Utilities Elmer Smith Unit 1. 

Emissions were incorrectly modeled as 560 tons instead of 560 lbs. This correction is accounted 

for in the above summary table. 

Table 1.1-7. EGU Point Source PM2.5 -PRI Emission Comparison for 2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 4,113 3,921 4,518 4,768 

FL 15,643 14,790 15,239 9,417 

GA 4,939 10,907 10,818 13,881 

KY 2,802 4,279 4,404 4,434 

MS 1,138 4,996 5,158 7,252 

NC 16,498 15,949 17,316 28,137 

SC 17,154 16,548 17,548 23,794 

TN 12,166 13,092 13,246 13,387 

VA 2,606 4,165 4,756 10,773 

WV 2,210 2,940 2,995 3,116 

Total 79,269 91,587 95,998 118,959 

Note: Emission summaries above are based on SCCs 1-01-xxx-xx and 2-01-xxx-xx. 

Note 2: After the preparation of the emission files used for ASIP air quality modeling for 2012, an 

error in PM2.5 EGU emissions were discovered for Owensboro Utilities Elmer Smith Unit 1. 

Emissions were incorrectly modeled as 420 tons instead of 420 lbs. This correction is accounted 

for in the above summary table. 
Documentation of the 2012 Emission Inventory 

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Table 1.1-8. EGU Point Source NH3 Emission Comparison for 2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 317 359 1,438 1,072 

FL 234 1,629 3,682 2,976 

GA 83 686 1,500 1,677 

KY 326 400 760 476 

MS 190 334 548 827 

NC 54 445 547 663 

SC 142 370 710 625 

TN 204 227 435 241 

VA 127 694 719 606 

WV 121 330 638 143 

Total 1,798 5,474 10,977 9,306 

Note: Emission summaries above are based on SCCs 1-01-xxx-xx and 2-01-xxx-xx. 

1.2 Non-EGU Emission Projections 

The following subsections discuss the following specific aspects of the development of the nonEGU projections. First, we briefly describe the growth factors used to account for economic 

growth. Second, we document the control programs specified for incorporation in the ASIP 

2012 inventory. Third, we summarize the changes requested by S/L agencies that were primarily 

related to better information on source closures and anticipated controls for specific facilities and 

emission units resulting from BART, consent orders, or permit limits. Finally, we present 

summaries of the base year and projected non-EGU emissions by state and pollutant. 

1.2.1 Growth assumptions for non-EGU sources 

This section summarizes the growth factor data used in developing the 2012 non-EGU ASIP 

inventory. The same sources of data used for the 2009/2018 inventories were used in developing 

the growth factors for the 2012 non-EGU inventory:

 State-specific growth rates from the Regional Economic Model, Inc. (REMI) Policy 

Insight® model, Version 5.5 (being used in the development of the EGAS Version 5.0). 

The REMI socioeconomic data (output by industry sector, population, farm sector value 

added, and gasoline and oil expenditures) are available by 4-digit SIC code at the State 

level. These growth factors are fully documented in the reports entitled Development of 
Documentation of the 2012 Emission Inventory 

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Growth Factors for Future Year Modeling Inventories (dated April 30, 2004) and CAIR 

Emission Inventory Overview (dated July 23, 2004). 

 Energy consumption data from the DOE’s Energy Information Administration’s (EIA) 

Annual Energy Outlook 2006, with Projections through 2025 (released in February 2006) 

for use in generating growth factors for non-EGU fuel combustion sources. These data 

include regional or national fuel-use forecast data that were mapped to specific SCCs for 

the non-EGU fuel use sectors (e.g., commercial coal, industrial natural gas). Growth 

factors for the residential natural gas combustion category, for example, are based on 

residential natural gas consumption forecasts that are reported at the Census division 

level. These Census divisions represent a group of States (e.g., the South Atlantic 

division includes eight southeastern States and the District of Columbia). Although one 

would expect different growth rates in each of these States due to unique demographic 

and socioeconomic trends, EIA’s projects all States within each division using the same 

growth rate. 

 NCDENR supplied recent projections for three key sectors in North Carolina where 

declining production was anticipated – SIC 22xx Textile Mill Products, 23xx Apparel 

and Other Fabrics, and 25xx Furniture and Fixtures. NCDENR decided to use a growth 

factor of 1.0 for these SIC codes for 2009/2012/2018. Although NCDENR has data that 

shows a steady decline in these industries in NC, NCDENR wanted to maintain the 

emission levels at 2002 levels so the future emission reduction credits were available in 

the event that they are needed for nonattainment areas. 

 The American Forest and Paper Association (AF&PA) supplied growth projections for 

the pulp and paper sector, which were applied to SIC 26xx Paper and Allied Products. 

The AF&PA projection factors are for the U.S. industry and apply to all States equally. 

The numbers come from the 15-year forecast for world pulp and recovered paper 

prepared by Resource Information Systems Inc. (RISI). For SIC codes below, we used 

the above AF&PA growth factors by SIC instead of the factors obtained from EPA’s 

CAIR analysis. 

AF&PA Growth Factor 

SIC Sector 

2002 to 2009 2002 to 2012 2002 to 2018 

2611 Pulp Mills 1.067 1.101 1.169 

2621 Paper Mills 1.067 1.101 1.169 

2631 Paperboard Mills 1.067 1.101 1.169 
Documentation of the 2012 Emission Inventory 

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1.2.2 Control Programs applied to non-EGU sources 

The 2012 non-EGU inventory accounts for proposed control programs that are reasonably 

anticipated to result in post-2002 emission reductions. With one exception, we used the same 

control programs for 2012 as for the 2009 and 2018 VISTAS B&F non-EGU point inventories. 

The exception is the anticipated emission reductions from the Industrial Boiler/Process Heater 

MACT standard. On June 8, 2007, the DC Circuit Court of Appeals vacated the MACT 

standard. For the 2009/2018 B&F inventories, VISTAS had assumed that reductions equivalent 

to the MACT standard could be obtained using the 112(j) case-by-case MACT provisions. After 

careful discussion, the ASIP States concluded that States may not have mechanisms in place to 

require controls for boilers equivalent to the MACT by 2012. For this reason, no emission 

reductions due to the boiler MACT (or equivalent case-by-case MACT) were applied for 2012. 

The non-EGU control programs accounted for in the 2012 inventory included: 

 Atlanta / Northern Kentucky / Birmingham 1-hr SIPs 

 NOx RACT in 1-hr ozone nonattainment area SIPs 

 NOx SIP Call (Phase I- except where States have adopted II already e.g. NC) 

 Petroleum Refinery Enforcement Initiative (October 1, 2003 notice; MS & WV) 

 VOC 2-, 4-, 7-, and 10-year maximum achievable control technology (MACT Standards) 

 Combustion Turbine MACT

 NOx SIP Call (Phase II – remaining States & IC engines)

The methodologies used to account for the emission reductions associated with these emission 

control programs are discussed in Section 2.1.2.3 of the B&F Document. 

1.2.3 S/L Adjustments to 2012 Projections 

Several updates and corrections were requested by S/L agencies and incorporated into the 2012 

non-EGU inventories. The updates and corrections included: 

 S/L agencies identified significant source shutdowns that have occurred since 2002 and 

specified that emissions from these sources should not be included in the future year 

inventories. These sources are identified in Table 1.2-1. 

 S/L agencies identified individual unit source shutdowns that have occurred since 2002 

and specified that emissions from these emission units should not be included in the 

future year inventories. S/L agencies identified expansions to existing facilities or new 

facilities and provided estimates of future year emissions. S/L agencies identified other 

changes that were primarily related to better information on anticipated BART controls 
Documentation of the 2012 Emission Inventory 

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for specific facilities and emission units. A summary of these changes are provided in 

Table 1.2-2. 

AL DEM requested that the Birmingham SIP Inventory be used in place of the VISTAS B&F 

2002 inventory for Jefferson County, Alabama, for use in projecting emissions for 2012. 

MACTEC used the SMOKE IDA file (ptinv_baps_2002tpy_jeffco_1feb2008.dbf) provided by 

AL DEM. MACTEC converted the IDA file to NIF tables; ran the tables through EPA QA 

checker to verify the correct NIF format, and projected emissions from 2002 to 2012 using 

existing routines developed to project non-EGU sources for VISTAS B&F inventories. 

1.2.4 QA/QC of 2012 NonEGU Projections 

We prepared several data files for review by the State and local agencies to confirm the emission 

projections for 2012: 

 We maintained a log of requested changes that identified the name of the person/agency 

requesting the change, the date of the request, the nature of the change, and MACTEC’s 

action to address the change request. This log was circulated among the States to ensure 

that all change requests were addressed and acted upon. 

 We prepared a master spreadsheet that compared facility level emissions for 2009 and 

2012 and highlighted were substantial differences occurred for State review. 

 We provided NIF files for State and local agency review and comment. 

State and local agency reviewed these files, which resulted in several iterations of changes and 

final confirmation by each State accepting the results of the 2012 nonEGU inventory. 

1.2.5 Summary of 2002/2009/2012/2018 nonEGU Point Source Inventories 

Tables 1.2-3 through 1.2-9 summarize the B&F 2002/2009/2018 VISTAS non-EGU point source 

inventories as well as the initial 2012 ASIP non-EGU inventory. Some notable changes in 

emissions by pollutant include: 

 SO2 emissions generally increase slightly from 2002 to 2018 due to the projected growth 

in fuel consumption, except in certain State where BART requirements may reduce SO2

emissions. For WV, SO2 emissions are lower in 2012 than in 2009 or 2018 because the 

State identified several source closures for the 2012 inventory that were not identified for 

either the 2009 or 2018 inventories. 

 NOx emissions generally decrease from 2002 to 2009 due to NOx SIP Call, RACT or 

other control requirements, then increase from 2009 to 2018 due to the project growth. 

For WV, NOx emissions are lower in 2012 than in 2009 or 2018 because the State 
Documentation of the 2012 Emission Inventory 

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identified several source closures for the 2012 inventory that were not identified for 

either the 2009 or 2018 inventories. 

 VOC emissions generally decrease from 2002 to 2009 due to MACT control 

requirements and source closures, then generally increase from 2009 to 2018 because of 

projected growth in economic activity. 

 CO emissions generally increase from 2002 to 2018 because of projected growth in 

economic activity. 

 PM10 and PM2.5 emissions generally decrease from 2002 to 2009 due to source closures 

and then increase because of projected growth in fuel consumption and economic 

activity. FL shows a decrease in PM emissions from 2012 to 2018 because no emission 

reductions from the industrial boiler MACT (or equivalent case-by-case MACT) were 

applied for 2012 – in 2009/2018, a 40 percent reduction in PM10/PM2.5 emissions was 

applied to account for expected reduction from the control requirements of the boiler 

MACT. 

 NH3 emissions generally increase from 2002 to 2018 because of projected growth in 

economic activity and fuel use. 

Other minor inconsistencies between the 2012 inventory and the 2009/2018 inventories result 

from States providing updated information that was not available when the 2009 and 2018 

inventories were developed. 
Documentation of the 2012 Emission Inventory 

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Table 1.2-1. Facility Shutdowns Incorporated in the 2012 Non-EGU Inventory. 

Facility ID County Facility Name 

Alabama 

01-001-0013 Autauga BEMIS COMPANY, INC. 

01-023-0003 Choctaw PRUET PRODUCTION COMPANY 

01-031-0014 Coffee DORSEY TRAILER INC 

01-035-S001 Conecuh LOUISIANA PACIFIC CORPORATION 

01-045-0016 Dale TRI-GLASS VMC FIBERGLASS PRODUCTS INC 

01-049-0011 De Kalb EARTH GRAINS BAKING CO 

01-055-0034 Etowah ND DIXIE PACIFIC MANUFACTURING CO INC 

01-077-0016 Lauderdale SUPERIOR PROFILES INC 

01-081-0007 Lee WESTPOINT STEVENS 

01-081-0030 Lee SOUTH EASTERN ELECTRIC DEVELOPMENT CORP 

01-081-0036 Lee GEORGIA POWER COMPANY - FRANKLIN 

01-083-0011 Limestone STEELCASE INC 

01-083-0023 Limestone MONESSEN HEARTH SYSTEMS 

01-091-0015 Marengo MCCLAIN OF ALABAMA INC 

01-091-S003 Marengo MILLER & COMPANY 

01-093-0018 Marion COLBY FURNITURE CO 

01-097-2019 Mobile BROOKLEY FURNITURE 

01-097-8053 Mobile OCAL THOMAS & BETTS INCORPORATED 

01-099-S006 Monroe STALLWORTH TIMBER CO 

01-113-0016 Russell FIELDCREST CANNON 

01-117-0043 Shelby COOK PUBLICATIONS INC 

01-121-0014 Talladega AVONDALE MILLS 

01-125-0006 Tuscaloosa EMPIRE COKE CO 

01-125-0036 Tuscaloosa LAWTER INTERNATIONAL 

01-125-0040 Tuscaloosa JVC MAGNETICS AMERICA 

01-125-0046 Tuscaloosa BLACK WARRIOR TRANSMISSION CORPORATION 

01-125-S011 Tuscaloosa INTERNATIONAL PAPER COMPANY 

01-133-0010 Winston BANKHEAD FURNITURE 

01-133-0014 Winston HOUSTON WOOD PRODUCTS 

01-133-0021 Winston HARDEN MANUFACTURING CORPORATION 

Florida 

12-057-0570075 Hillsborough CORONET INDUSTRIES, INC. 

12-105-1050050 Polk U S AGRI-CHEMICALS CORP. 

12-105-1050051 Polk U.S. AGRI-CHEMICALS CORPORATION 

Georgia 

13-121-12100401 Fulton LAFARGE BUILDING MATERIALS 

Kentucky 

None Specified 

Mississippi 

28-001-2800100010 Adams INTERNATIONAL PAPER, NATCHEZ MILL 

28-023-2802300031 Clarke MAGNOLIA RESOURCES INC, PACHUTA HARMONY 
Documentation of the 2012 Emission Inventory 

25

Table 1.2-1 (continued).

Facility ID County Facility Name 

North Carolina 

37-007-3700700045 Anson HILDRETH SEPTIC TANKS 

37-021-724 Buncombe BASF CORPORATION 

37-031-3703100103 Carteret MOREHEAD CITY TERMINALS 

37-049-3704900069 Craven S & W READY MIX CONCRETE - NEW BERN 

37-051-3705100094 Cumberland PUBLIC WORKS COMMISSION BUTLER-WARNER GE 

37-139-3713900082 Pasquotank ELIZABETH CITY BRICK CO INC 

37-191-3719100239 Wayne S & W READY MIXED CONCRETE CO. - GOLDSBO 

South Carolina 

45-003-0080-0001 Aiken AVONDALE MILLS STEVENS 

45-003-0080-0005 Aiken AVONDALE MILLS SWINT 

45-003-0080-0039 Aiken AVONDALE MILLS WARREN 

45-003-0080-0061 Aiken AVONDALE MILLS GREGG 

45-003-0080-0098 Aiken AVONDALE MILLS HORSE CREEK 

45-007-0200-0014 Anderson SPRINGS INDUSTRIES:WAMSUTTA 

45-007-0200-0047 Anderson CHIQUOLA INDUSTRIAL PROD:CHIQUOLA-CLOSED 

45-007-0200-0050 Anderson VYTECH 

45-007-0200-0058 Anderson ISOLA LAMINATE SYSTEMS PENDLETON-CLOSED 

45-007-9900-0377 Anderson LANE CONSTRUCTION:ANDERSON PLANT2-CLOSED 

45-011-0300-0025 Barnwell EFCO CORP 

45-013-0360-0019 Beaufort CLELAND CONSTRUCTION-CLOSED 

45-015-0420-0083 Berkeley CONCERT ACI INC-CLOSED 

45-019-0560-0036 Charleston CHARLESTON STEEL:BRIGADE STREET-CLOSED 

45-019-0560-0041 Charleston CUMMINS ENGINE:OLD-CLOSED 

45-019-0560-0048 Charleston UNICON:AIRPORT RD 

45-019-0560-0270 Charleston SHEILAS INC 

45-019-0560-0305 Charleston SCE&G:FABER PLACE 

45-019-9900-0384 Charleston CHARLESTON CONCRETE COMPANY 

45-021-0600-0036 Cherokee HAMRICK INDUSTRIES:PLANT 5 

45-021-0600-0055 Cherokee IFCO ICS-SOUTH CAROLINA-CLOSED 

45-023-0640-0011 Chester SPRINGS INDUSTRIES:EUREKA-CLOSED 

45-023-0640-0035 Chester SPRINGS INDUSTRIES:KATHERINE 

45-023-0640-0036 Chester SPRINGS INDUSTRIES:ELLIOTT 

45-023-0640-0037 Chester SPRINGS INDUSTRIES:LEROY 

45-025-0660-0033 Chesterfield TAKATA RESTRAINT SYSTEMS INC 

45-035-0900-0044 Dorchester MIDWEST CONTROL PRODUCTS 

45-035-0900-0052 Dorchester MAXCESS TECHNOLOGIES 

45-041-1040-0089 Florence INTERSTATE BRANDS CORP 

45-041-9900-0389 Florence THE LANE CONSTRUCTION:PLANT #24 

45-045-1200-0009 Greenville US FINISHING-CLOSED 

45-045-1200-0016 Greenville DELTA MILLS:ESTES 

45-045-1200-0033 Greenville SCOTTS SIERRA:TRAVELERS REST 

45-045-1200-0100 Greenville JOHN DEERE GREER-CLOSED 

45-045-1200-0104 Greenville KEMET:MAULDIN 
Documentation of the 2012 Emission Inventory 

26

Table 1.2-1 (continued).

Facility ID County Facility Name 

South Carolina 

45-045-1200-0196 Greenville DAN RIVER:WHITE HORSE-CLOSED 

45-045-1200-0277 Greenville EXCALIBUR TOOL:POINSETT 

45-045-1200-0317 Greenville GATEWAY MFG:PLANT #2 - GREENVILLE 

45-045-1200-0346 Greenville AMERICAN WOODWORKS GREENVILLE 

45-047-1240-0026 Greenwood GREENWOOD MILLS: DURST-CLOSED 

45-047-1240-0034 Greenwood KEMET:GREENWOOD-CLOSED 

45-047-1240-0050 Greenwood FUJI PHOTO FILM:M PLANT 

45-047-1240-0060 Greenwood TRIGEN-BIOPOWER INC 

45-049-1280-0021 Hampton SAFETY DISPOSAL SYSTEM OF SC INC 

45-049-9900-0257 Hampton HAMPTON CONCRETE-CLOSED 

45-051-1340-0013 Horry TEREX PPM CRANES-CLOSED 

45-051-1340-0073 Horry WACCAMAW WHEEL WILLIAMS-CLOSED 

45-051-1340-0084 Horry SOUTHEAST FINISHING HIGHWAY 65 PLANT 

45-051-9900-0310 Horry APAC CAROLINA:PLANT 695 WINYAH CONCRETE 

45-055-1380-0040 Kershaw STANDARD CORPORATION ZYPOLE PLANT-CLOSED 

45-055-1380-0052 Kershaw HOWDEN BUFFALO-CLOSED 

45-057-1460-0041 Lancaster PRESSLEY FARM & GRADING-CLOSED 

45-061-1540-0030 Lee KING COMPANY-CLOSED 

45-063-1560-0054 Lexington BC COMPONENTS-CLOSED 

45-063-1560-0102 Lexington KLINE IRON&STEEL:CAYCE 

45-063-1560-0116 Lexington SMI JOIST:CAYCE 

45-063-1560-0117 Lexington SEA HUNT BOAT 

45-063-1560-0134 Lexington LEADER BOATS-CLOSED 

45-067-1660-0006 Marion INTERNATIONAL PAPER:SELLERS-WPC 

45-069-1680-0008 Marlboro DELTA MILLS:DELTA #2 

45-073-1820-0052 Oconee AEC SENECA-CLOSED 

45-075-1860-0001 Orangeburg VELCOREX INC 

45-077-1880-0018 Pickens ALICE MANUFACTURING ARIAL-CLOSED 

45-077-1880-0043 Pickens MAYFAIR MILLS:GLENWOOD-CLOSED 

45-079-1900-0038 Richland KLINE IRON&STEEL:COLUMBIA-CLOSED 

45-083-2060-0017 Spartanburg INMAN MILLS:RIVERDALE-CLOSED 

45-083-2060-0026 Spartanburg AMERICAN FAST PRINT-CLOSED 

45-083-2060-0079 Spartanburg TNS MILLS:SPARTANBURG-CLOSED 

45-083-2060-0094 Spartanburg CROWN CENTRAL PETROLEUM-CLOSED 

45-083-2060-0094 Spartanburg CROWN CENTRAL PETROLEUM-CLOSED 

45-083-2060-0182 Spartanburg INTELICOAT TECHNOLOGIES-CLOSED 

45-085-2140-0009 Sumter KORN INDUSTRIES SUMTER CABINET 

45-085-2140-0010 Sumter VAUGHAN BASSETT FURNITURE 

45-089-2320-0021 Williamsburg ABBOTT LABORATORIES-CLOSED 

45-091-2440-0010 York CELANESE ACETATE ROCK HILL 

45-091-2440-0044 York CLARIANT LSM (AMERICA):ROCK HILL-CLOSED 

45-091-2440-0080 York TRICO 

45-091-2440-0095 York ADPLEX RHODES 
Documentation of the 2012 Emission Inventory 

27

Table 1.2-1 (continued).

Facility ID County Facility Name 

Tennessee 

47-009-0130 Blount APAC-TN, INC./HARRISON CONSTRUCTION DIVI 

47-009-0136 Blount SKIER'S CHOICE, INC. 

47-011-0004 Bradley CLEVELAND CHAIR COMPANY 

47-011-0012 Bradley ALLIED SIGNAL, INC. 

47-011-0154 Bradley WESTVACO CONSUMER PACKAGING DIVISION 

47-037-4703700100 Davidson IRVING MATERIALS INC. 

47-047-0061 Fayette STABILIT AMERICA, INC. 

47-047-0062 Fayette GLASTEEL INDUSTRIAL LAMINATES, INC. (GIL 

47-053-0012 Gibson FOAMEX INTERNATIONAL, INC. 

47-053-0093 Gibson EMERSON MOTOR COMPANY - COPELAND ELECTRI 

47-053-0143 Gibson A.O. SMITH CORPORATION 

47-053-0162 Gibson ALLSTEEL, INCORPORATED 

47-059-0008 Greene FIVE RIVER MANUFACTURING 

47-059-0116 Greene GREENEVILLE CASTING, INC. 

47-063-0095 Hamblen ARMSTRONG CABINET PRODUCTS 

47-063-0113 Hamblen FOAMEX L.P. - PLANT #1 

47-063-0151 Hamblen SHELBY WILLIAMS 

47-063-0197 Hamblen LIBERTY FIBERS CORPORATION 

47-065-3321 Hamilton U. S. Pipe - Valve Plant 

47-065-3500 Hamilton Velsicol Chemical Corporation 

47-067-0009 Hancock MORRILL MOTORS, INC. 

47-069-0063 Hardeman MOLTAN COMPANY 

47-071-0005 Hardin SAVANNAH - HARDIN COUNTY LANDFILL 

47-073-1029 Hawkins HOLSTON ARMY AMMUNITION PLANT (HSAAP) 

47-075-0068 Haywood BROWNSVILLE POWER, LLC 

47-079-0009 Henry MARK I MOLDED PLASTICS 

47-079-0013 Henry AMERICAN COLLOID COMPANY 

47-091-0029 Johnson FILM PROCESSING CORPORATION 

47-097-0003 Lauderdale A.O. SMITH ELECTRICAL PRODUCTS COMPANY 

47-101-0006 Lewis ESTON CORP 

47-107-0011 McMinn A.O. SMITH - ATHENS PRODUCTS 

47-107-0142 McMinn ADVANCED SPA DESIGN 

47-113-0185 Madison BRUCE HARDWOOD FLOORING 

47-113-0245 Madison SONOCO PRODUCTS COMPANY 

47-117-0003 Marshall INTERNATIONAL COMFORT PRODUCTS CORPORATI 

47-123-0101 Monroe MATSUSHITA REFRIGERATION COMPANY 

47-149-0148 Rutherford MARINE GROUP, LLC 

47-155-0001 Sevier DAN RIVER INCORPORATED 

47-157-00020 Shelby GREAT DANE TRAILERS 

47-157-00524 Shelby MEMPHIS HARDWOOD FLOORING CO. 

47-163-0188 Sullivan FIBERGRATE COMPOSITE STRUCTURES, INC. 

47-179-0052 Washington VAUGHAN FURNITURE COMPANY - EMPIRE DIVIS 

47-179-0248 Washington NICKELSON PLASTICS, INC. 

47-189-0103 Wilson JOHN DEAL COMPANY 
Documentation of the 2012 Emission Inventory 

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Table 1.2-1 (continued).

Facility ID County Facility Name 

Virginia 

51-013-00212 Arlington BERGMANNS INC 

51-027-00046 Buchanan ISLAND CREEK COAL COMPANY/VIRGINIA POCAH 

51-027-00047 Buchanan ISLAND CREEK COAL CO-VIRGINIA POCAHONTAS 

51-047-00008 Culpeper KELLER MANUFACTURING CO INC 

51-089-00012 Henry BASSETT CHAIR CO 

51-089-00073 Henry MARTINSVILLE THERMAL, LLC - FRITH DRIVE 

51-117-00051 Mecklenburg MECKLENBURG COGENERATION FACILITY 

51-137-00001 Orange GENERAL SHALE PRODUCTS LLC-PLANT 37 

51-141-00022 Patrick VAUGHAN FURNITURE CO INC-T GEORGE VAUGHA 

51-155-00038 Pulaski ETHAN ALLEN 

51-165-00073 Rockingham ETHAN ALLEN INC - BRIDGEWATER DIVISION 

51-550-00161 Chesapeake COMMONWEALTH ATLANTIC LIMITED PARTNERSHI 

51-590-00002 Danville DAN RIVER INCORPORATED SCHOOLFIELD 

51-710-00219 Norfolk AMERICAN WASTE INDUSTRIES, INCORPORATED 

51-760-00093 Richmond City FERGUSSON, J W AND SONS, INC. 

51-820-00066 Waynesboro VIRGINIA METALCRAFTERS INC 

West Virginia 

54-009-0015 Brooke UNITED STATES CAN COMPANY 

54-011-0054 Cabell TRANSFAB INC. 

54-033-0025 Harrison CLARKSBURG CASKET COMPANY 

54-039-0002 Kanawha FMC CORPORATION - STEAM PLANT 

54-039-0052 Kanawha FMC CORPORATION - SPRING HILL PLANT 

54-039-0208 Kanawha WV GROUP DBA REPUBLIC CONTAINER 

54-069-0007 Ohio WESCOAT, INC. 

54-073-0006 Pleasants CABOT CORPORATION-OHIO RIVER PLANT 

54-073-0022 Pleasants PLEASANTS ENERGY LLC 

54-079-0001 Putnam FLEXSYS - NITRO PLANT 

54-107-0012 Wood AMES TRUE TEMPER - PLANT #1 

54-107-0016 Wood AMES/TRUE TEMPER-PLANT #2 
Documentation of the 2012 Emission Inventory 

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Table 1.2-2. Other S/L Agency Changes Incorporated in 2012 Non-EGU Inventory. 

State Description of Changes 

FL For 2009/2012/2018, incorporated emission changes due to BART controls at Georgia Pacific (Site 

ID: 12-107-1070005) Unit 15. 

NC There are three Transcontinental Natural Gas Pipeline facilities in NC that are subject to the NOx SIP 

call. We took 2004 emissions and grew them to 2009/2012/2018 and capped those units that are 

subject to the NOx SIP Call Rule. These facility IDs are 37-057-3705700300, 37-097-3709700225, 

and 37-157-3715700131 

 NCDENR applied NOx RACT to a two facilities located in the Charlotte nonattainment area. 

NCDENR provided 2009 & 2018 emissions for Philip Morris USA (37-025-3702500048) and 

Norandal USA (37-159-3715900057). 2012 emissions were grown from 2009 using growth factors. 

SC Specified that the Bowater Inc. facility (45-091-2440-0005) in York County conducted an expansion 

in 2003/2004 and plans a future expansion. SC provided updated emissions for 2009 and 2018 for this 

facility. 2012 emissions were grown from 2009 using growth factors. 

TN Updated 2009/2012/2018 emissions for Eastman Chemical (47-163-0003) based on final (Feb. 2005) 

BART rule. 

 Updated 2009/2012/2018 emission inventory for the Bowater facility (47-107-0012) based on the 

facility’s updated 2002 emission inventory. 

 The 2002 NEI correctly reports the actual emissions for CEMEX (47-093-0008) after the NOx SIP 

call. There is no reason to suspect that that rate would change in 2008, 2009, or 2018. Emissions for 

2009/2012/2018 were set equal to 2002 emissions. 

 There are no plans for NOx controls for two units at Columbia Gulf Transmission (47-111-0004) 

under the NOx SIP Call Phase II rule. No reductions were applied. 

 Identified three emission units that have permanently closed. Emissions from these units were set to 

zero for all pollutants. 47-009-0130-002 (APAC – TN, Inc.-Harrison Construction – Asphalt plant), 

47-009-0130-003 (APAC – TN, Inc.-Harrison Construction – Asphalt crusher), and 47-139-0004-001 

(Intertrade - Number 6 acid plant) 

 A portion of 47-163-0003-020101 (Eastman, B-83-1 Stoker Boilers). This source previously 

consisted of 14 boilers (Boilers 11-24). Boilers 11-17 have been removed from service. Emissions for 

2009/2012/2018 were reduced by 26.64%, based on the portion of the heat input capacity that is being 

removed from service. 

 Coal-fired boilers at DOE Y-12 plant will be replaced with natural gas-fired units by 2012. 

Allowable SO2 emissions will be 39 tons/year and allowable NOx emissions will be 81 tons/year. 

VA VADEQ provided NOx emission estimates for NOx Phase II gas transmission sources at three Transco 

facilities (51-011-00011, 51-137-00027, 51-143-00120) which were used to replace the default NOx

Phase II control assumptions for these facilities. 

 VADEQ provided updated 2009/2018 NOx and SO2 emissions based on new controls required by a 

November 2005 permit modification and netting exercise at the University of Virginia. The entire 

power plant facility is limited to 213 tons of NOx and 107 tons of SO2 per year. The permit also 

allowed the installation of 3 new boilers, also under the 213 tons of NOx /year cap. 2012 emissions 

were grown from 2009 using growth factors. 

 VADEQ indicated that Rock-Tenn received a permit dated 9/13/2003 which required the shutdown of 

units 1 and 2 by 2/27/2004. 
Documentation of the 2012 Emission Inventory 

30

Table 1.2-2 (continued). 

State Description of Changes 

VA Changed SO2 emissions in 2009 and 2018 for thirteen facilities to reflect updated information from 

VADEQ regarding projected SO2 controls. 2012 emissions were grown from 2009 using growth 

factors. 

 The Southside VA Training Center, 730-0001, are shutdowns for three boilers at the site. For those 

unit numbers, all emissions of criteria and non-criteria pollutants may be deleted from the 2012 

inventory. 

WV Weirton Steel (54-029-00001) and Wheeling Pittsburgh Steel (54-009-00002) have undergone 

significant, permanent process changes since 2002. WV DEP staff have consulted with facility staff 

and determined that calendar year 2004 emissions represent a better basis for future year emissions 

estimates. Therefore, WVDEP compiled emissions data from the 2004 inventory for these sources 

and applied the most current VISTAS growth factors to estimate emissions in 2009 and 2018. 2012 

emissions were grown from 2009 using growth factors. 

Table 1.2-3. Non-EGU Point Source SO2 Emission Comparison for 2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 96,481 101,246 102,299 103,303 

FL 65,090 62,651 66,043 71,810 

GA 53,778 53,987 57,176 59,349 

KY 34,029 36,418 38,167 40,682 

MS 35,960 25,564 27,372 25,674 

NC 44,123 42,536 44,050 46,314 

SC 53,518 47,193 49,569 52,410 

TN 79,604 64,964 66,295 56,682 

VA 63,903 58,039 56,247 57,790 

WV 54,070 55,598 46,100 61,702 

Total 580,556 548,196 553,319 575,716 

Note: Emission summaries above include all SCCs except 1-01-xxx-xx and 2-01-xxx-xx. 
Documentation of the 2012 Emission Inventory 

31

Table 1.2-4. Non-EGU Point Source NOx Emission Comparison for 2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 83,310 69,409 71,142 77,960 

FL 45,156 47,125 48,785 52,959 

GA 49,251 50,353 52,197 55,824 

KY 38,392 37,758 39,115 41,034 

MS 61,526 56,398 57,379 61,252 

NC 44,929 34,768 35,846 37,802 

SC 42,153 39,368 40,857 43,331 

TN 64,344 57,514 59,254 62,519 

VA 60,415 51,001 52,297 55,734 

WV 46,612 38,023 37,797 43,280 

Total 536,088 481,715 494,669 531,695 

Note: Emission summaries above include all SCCs except 1-01-xxx-xx and 2-01-xxx-xx. 

Table 1.2-5. Non-EGU Point Source VOC Emission Comparison for 2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 47,037 46,644 46,326 54,290 

FL 38,471 36,882 38,865 42,813 

GA 33,709 34,116 36,179 40,282 

KY 44,834 47,785 50,475 55,861 

MS 43,204 37,747 40,306 45,335 

NC 61,182 61,925 64,922 70,875 

SC 38,458 34,403 36,904 41,987 

TN 84,328 73,498 79,826 92,456 

VA 43,152 43,725 46,115 53,186 

WV 14,595 13,043 13,221 15,582 

Total 448,970 429,768 453,139 512,667 

Note: Emission summaries above include all SCCs except 1-01-xxx-xx and 2-01-xxx-xx. 
Documentation of the 2012 Emission Inventory 

32

Table 1.2-6. Non-EGU Point Source CO Emission Comparison for 2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 174,271 180,369 186,326 201,663 

FL 81,933 87,661 91,042 97,438 

GA 130,850 147,427 154,356 167,904 

KY 109,936 122,024 127,831 139,437 

MS 54,568 57,749 60,809 65,884 

NC 50,576 53,744 56,571 62,197 

SC 56,315 59,934 62,606 68,415 

TN 115,264 119,216 126,415 140,556 

VA 63,796 68,326 70,860 76,846 

WV 89,879 93,839 93,459 111,302 

Total 927,388 990,289 1,030,274 1,131,642 

Note: Emission summaries above include all SCCs except 1-01-xxx-xx and 2-01-xxx-xx. 

Table 1.2-7. Non-EGU Point Source NH3 Emission Comparison for 2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 1,883 2,132 2,298 2,464 

FL 1,423 1,544 1,645 1,829 

GA 3,613 3,963 4,242 4,797 

KY 674 760 808 901 

MS 1,169 668 701 764 

NC 1,180 1,285 1,345 1,466 

SC 1,411 1,578 1,645 1,779 

TN 1,613 1,840 1,965 2,213 

VA 3,104 3,045 3,227 3,604 

WV 332 314 334 378 

Total 16,402 17,129 18,210 20,195 

Note: Emission summaries above include all SCCs except 1-01-xxx-xx and 2-01-xxx-xx. 
Documentation of the 2012 Emission Inventory 

33

Table 1.2-8. Non-EGU Point Source PM10-PRI Emission Comparison for 

2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 25,240 25,421 18,162 29,889 

FL 35,857 39,947 46,845 46,492 

GA 21,610 23,103 25,557 27,273 

KY 16,626 17,174 18,269 20,153 

MS 19,472 19,244 18,854 22,837 

NC 13,838 13,910 15,591 15,737 

SC 14,142 12,959 14,254 14,674 

TN 35,174 34,581 37,552 41,999 

VA 13,252 13,046 14,036 15,111 

WV 17,503 11,882 11,947 14,202 

Total 212,714 211,267 221,067 248,367 

Note: Emission summaries above include all SCCs except 1-01-xxx-xx and 2-01-xxx-xx. 

Table 1.2-9. Non-EGU Point Source PM25-PRI Emission Comparison for 

2002/2009/2012/2018. 

State 

Actual 

2002 B&F 2009 B&F 2012 Initial 2018 B&F 

AL 19,178 19,230 12,148 22,584 

FL 30,504 34,019 40,226 39,486 

GA 17,462 18,982 20,733 22,416 

KY 11,372 11,686 12,435 13,739 

MS 9,906 9,199 8,772 10,719 

NC 10,500 10,458 11,588 11,825 

SC 10,245 9,048 9,967 10,699 

TN 27,807 27,367 29,833 33,293 

VA 10,165 9,988 10,838 11,605 

WV 13,313 7,638 7,578 9,124 

Total 160,452 157,615 164,119 185,490 

Note: Emission summaries above include all SCCs except 1-01-xxx-xx and 2-01-xxx-xx. 
Documentation of the 2012 Emission Inventory 

34

2.0 2012 Projection Inventory for Nonroad Sources 

The starting point for the development of the 2012 nonroad source emission inventory was the 

2009 and 2018 VISTAS Best & Final (B&F) inventory. For nonroad sources the B&F inventory 

was the same as the Base G2 inventory. These inventories has been extensively reviewed, 

updated, and approved by the VISTAS States. Complete documentation of the these inventories 

is contained in Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 

Emission Inventories for VISTAS (B&F Document), March 14, 2008, prepared by MACTEC 

Engineering and Consulting, Inc. 

Subsequent to the development of the Base G2 projection inventories for 2009 and 2018, 

corresponding projection inventories for 2012 were developed. Inventories for both NONROAD 

model sources and aircraft, locomotives, and commercial marine vessels were developed for all 

ASIP (VISTAS)-area counties. The methods used to develop the 2012 inventories were identical 

to those described above for the 2009/2018 VISTAS nonroad inventories. Furthermore, the 

inputs and assumptions used to develop the 2009/2018 inventories were also used without 

change for the development of the 2012 inventories unless specific changes were either dictated 

by the change in the forecast period or were requested by ASIP-area planners. All such changes 

are documented below. 

For NONROAD model sources in all ASIP area counties, NONROAD model inputs for the 2012 

projections were constructed from the final 2009 VISTAS Base G2 NONROAD model input 

files for each county as described in the B&F Document. Prior to executing the NONROAD 

model, the 2009 input files were modified as follows: 

 The model evaluation year was changed to 2012 in all model input files. 

 The sulfur content of land diesel and marine diesel fuel were updated to 31 and 123 ppm 

respectively, based on fuel sulfur recommendations provided by the EPA (see “Diesel 

Fuel Sulfur Inputs for the Draft NONROAD2004 Model used in the 2004 Nonroad 

Diesel Engine Final Rule,” EPA, April 27, 2004). This was the same reference source 

as used for the 2009 and 2018 fuel S content. Gasoline sulfur content was maintained at 

30 ppm for the 2012 inventories as no changes are expected in the national control 

program between 2009 and 2018. Similarly, all other fuel parameters (oxygen content 

and RVP) were maintained at their 2009 Base G2 inventory values as neither national, 

state, or local control program changes are expected. 

The evolution of fuel sulfur content assumptions across projection inventory years is 

summarized as follows: 
Documentation of the 2012 Emission Inventory 

35

Fuel S (ppm) 2002 2009 2012 2018 

 Land-Diesel 2500 348 31 11 

 Marine-Diesel 2638 408 123 56 

 Gasoline varies* 30 30 30 

 * see Table 1.3-2 of the B&F Document 

In response to the Renewable Fuels Standard established under the federal Energy Policy Act of 

2005, some consideration was given to revising the assumed oxygen content of gasoline for the 

2012 NONROAD model projection inventory. Using data presented in the March 2008 version 

of the Energy Information Administration’s 2008 Annual Energy Outlook (Department of 

Energy, Energy Information Administration report DOE/EIA-0383(2008), March 2008 (Revised) 

release), the following average ethanol content estimates for gasoline were developed: 

Ethanol Content (wt. pct.) 2005 2009 2012 2018 

 1.0 2.5 3.2 3.4 

Furthermore, the Annual Energy Outlook forecasts that all gasoline sold in the U.S. will contain 

the legally permissible maximum level of ethanol of 3.5 weight percent sometime between 2019 

and 2020. The Annual Energy Outlook does not include historic estimates for 2002. 

Because all previous (2002, 2009, and 2018) VISTAS area NONROAD model inventories were 

developed under an assumption of zero ethanol content, it was ultimately decided to maintain the 

same zero percent ethanol assumption for the 2012 ASIP projection inventories. However, it is 

important to recognize that according to EPA technical documentation (Exhaust Emission Effects 

of Fuel Sulfur and Oxygen on Gasoline Nonroad Engines, EPA420-R-05-016, December 2005), 

the NONROAD model would respond to increasing gasoline ethanol contents by reducing 

exhaust HC and CO estimates for four-stroke gasoline engines by about 4.5 and 6.2 percent per 

weight percent ethanol respectively and increasing NOx emissions for the same engines by about 

11.5 percent per weight percent ethanol. Emissions for two-stroke gasoline engines would 

decline by about 0.6 and 6.5 percent per weight percent ethanol for exhaust HC and CO 

respectively, while NOx emissions would increase by about 18.6 percent per weight percent 

ethanol. 

Projections for 2012 were developed by running the resulting input files through the 

NONROAD2005 model. Table 2.0-1 summarizes the resulting emission projections. 

Aircraft, locomotive, and commercial marine vessel projections for 2012 in all ASIP area 

counties were developed using the same methodology used to develop the Base G2 2009 and 

2018 VISTAS-area projections for these same sources, as described in the B&F Document. 

Growth and control factors were re-estimated for 2012 using data from the EPA's Clean Air 
Documentation of the 2012 Emission Inventory 

36

Interstate Rule (CAIR) Technical Support Document as described in Section 2.3.4.2 of the B&F 

Document. The only exceptions are for aircraft in Boone County, Kentucky and aircraft in 

Forsyth, Guilford, Mecklenburg, and Wake counties in North Carolina, where growth factors 

provided by state planners were used in place of the CAIR data. 

Kentucky planners did not provide an explicit aircraft growth factor for 2012, but rather factors 

for 2009 and 2018. A corresponding factor for 2012 was derived through linear interpolation of 

the 2009 and 2018 factors. As was the case for the Base G2 2009 and 2018 VISTAS projection 

inventories, the state-provided factors for Kentucky are used for all aircraft. 

Table 2.0-1. 2012 Emissions Projections for NONROAD Model Sources (tons)

State CO NOx PM10 PM2.5 SO2

NonRefueling 

VOC 

Refueling

VOC 

AL 453,492 20,691.2 2,361.6 2,238.6 70.2 42,236.0 1,626.4 

FL 2,133,611 90,768.9 9,740.0 9,255.7 303.4 180,099.9 8,280.0 

GA 899,617 41,002.7 4,530.0 4,309.3 131.3 57,732.1 3,252.8 

KY 347,570 22,466.0 2,358.7 2,250.0 67.8 31,379.8 1,203.4 

MS 251,030 15,768.2 1,727.3 1,641.8 49.9 30,133.9 949.8 

NC 899,019 42,984.5 4,589.9 4,367.4 138.5 63,232.8 3,411.0 

SC 447,416 20,997.5 2,240.0 2,129.2 69.8 36,199.3 1,743.6 

TN 550,214 28,511.5 3,052.7 2,904.3 91.3 46,055.7 2,067.7 

VA 732,105 31,848.9 3,537.0 3,361.6 102.8 47,123.0 2,869.5 

WV 153,912 5,892.2 825.8 779.2 20.0 15,414.7 586.4 

Total 6,867,985 320,931.5 34,963.0 33,236.9 1,044.9 549,607.1 25,990.6

North Carolina provided updated growth factors to be used explicitly for 2012 emissions 

estimation. These latest 2012 factors are not entirely consistent with the corresponding factors 

used for the Base G2 2009 and 2018 VISTAS projection inventories for North Carolina and this 

should be considered in any comparison of North Carolina aircraft emissions projections. 

Moreover, while the state-provided growth factors for the Base G2 2009 and 2018 VISTAS 

projection inventories were applied only to commercial and air taxi aircraft, North Carolina 

planners requested that the 2012 growth factors be applied to all aircraft types in the affected 

counties. The actual aircraft growth factors used in the various projection inventories are as 

follows: 

 2009 2012 2018 

 Boone Co., KY 1.31 1.48 1.81 

 Forsyth Co., NC 0.71 0.992 0.84 

 Guilford Co., NC 0.97 1.066 0.89 
Documentation of the 2012 Emission Inventory 

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 Mecklenburg Co., NC 1.15 1.236 1.01 

 Wake Co., NC 0.88 1.369 0.81 

Finally, the impacts of the EPA’s Tier 4 (T4) diesel fuel sulfur rule on SO2 and PM emissions 

from locomotives and commercial marine vessels were re-estimated for 2012 using data from the 

EPA’s technical support document for the final T4 rule (Final Regulatory Analysis: Control of 

Emissions from Non-road Diesel Engines, EPA420-R-04-007, May 2004), using the same 

procedure described above in Section 2.3.4.2 of the B&F Document. Under the approach, T4 

control factors for 2012 were developed as indicated in Table 2.0-2 (which also shows the 

corresponding control factors for 2009 and 2018). The resulting growth and control factors were 

applied to the final 2002 emission estimates for aircraft, locomotives, and commercial marine 

vessels in all VISTAS-area counties to derive 2012 emissions projections for these sources. 

Table 2.0-3 presents a summary of the resulting emission estimates. 

Table 2.0-2. Estimated Emission Reduction Impacts for 2012 based on T4 Rule 

2009 2012 2018

CMV SO2 = Non-T4 SO2 × 0.1632 0.0490 0.0225 

Locomotive SO2 = Non-T4 SO2 × 0.1632 0.0490 0.0225 

CMV PM = Non-T4 PM × 0.9004 0.8819 0.8685 

Locomotive PM = Non-T4 PM × 0.8187 0.7879 0.7610 
Documentation of the 2012 Emission Inventory 

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Table 2.0-3. 2012 Emissions Projections for Aircraft, Locomotives, and Commercial 

Marine Vessels (tons per year) 

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL 6,552 225 315 124 22 324 

FL 30,898 10,926 2,979 2,919 983 4,482 

GA 8,069 6,602 1,814 1,777 554 542 

KY 7,676 1,240 336 329 119 533 

MS 1,838 172 54 53 16 113 

NC 7,601 1,972 534 523 188 775 

SC 7,744 578 462 453 103 1,023 

TN 8,350 3,237 862 845 281 1,095 

VA 13,684 4,398 2,173 2,130 320 3,293 

WV 1,369 96 30 30 9 78 

Aircraft 

(2275) 

Total 93,781 29,446 9,558 9,183 2,596 12,258 

AL 1,316 8,746 869 799 2,689 782 

FL 6,385 42,505 1,831 1,685 5,875 1,493 

GA 1,123 7,482 315 290 955 260 

KY 7,292 47,084 2,159 1,986 8,238 1,683 

MS 6,240 40,668 1,819 1,674 6,471 1,443 

NC 649 4,317 183 168 576 150 

SC 1,161 7,666 325 299 996 269 

TN 4,000 25,810 1,168 1,075 4,540 923 

VA 1,072 2,614 310 285 19 517 

WV 1,686 10,853 452 416 27 389 

Commercial 

Marine 

(2280) 

Total 30,924 197,744 9,431 8,676 30,386 7,908 

Military Marine VA 121 294 23 21 1 51 

(2283) Total 121 294 23 21 1 51 

AL 3,745 22,566 421 379 73 1,257 

FL 1,071 8,449 176 158 31 372 

GA 2,818 23,397 473 425 82 980 

KY 2,306 18,648 388 349 67 799 

MS 2,451 19,721 411 370 72 828 

NC 1,743 13,987 292 263 51 602 

SC 1,235 9,909 207 186 36 426 

TN 2,795 23,195 451 406 73 959 

VA 1,258 10,814 1,088 979 184 457 

WV 1,394 11,729 234 211 41 477 

Locomotives 

(2285) 

Total 20,816 162,414 4,140 3,726 710 7,156 

Grand Total 145,642 389,898 23,153 21,606 33,693 27,374 
Documentation of the 2012 Emission Inventory 

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3.0 2012 Area Source Projections 

Area sources were projected using techniques developed for the Visibility Improvement State 

and Tribal Association of the Southeast (VISTAS) regional haze emission inventory projections. 

The methods used for VISTAS are documented in the B&F Document. For the ASIP area 

source projections MACTEC used the same methods developed for VISTAS coupled with 

interpolated growth and control factors. The interpolated growth and control factors for 2012 

were based on the values used for the 2009 and 2018 Base G2 projection inventories prepared for 

VISTAS. In all cases, except for those resulting from specific review by State and local air 

pollution agencies (detailed below), the interpolation of growth and control factors was strictly 

based on a linear interpolation of the existing 2009 and 2018 VISTAS growth or control factors. 

The interpolated growth factors developed using the final consolidated list developed for 

VISTAS for 2009 and 2018 and represent a consolidation of both Clean Air Interstate Rule 

(CAIR) and Economic Growth Analysis System (EGAS) version 5 growth factors coupled with 

agricultural livestock growth factors calculated from projected emissions developed by U.S. 

EPA. The controls instituted represent controls used for CAIR along with other controls added 

by the State and local agencies during the inventory review process for VISTAS Base F and Base 

G inventories. For area sources these controls represent “on the books” controls. In addition, in 

several northern Virginia counties the controls represent those imposed by rules adopted by the 

Ozone Transport Commission (OTC). 

In addition to the interpolated growth and control factors, MACTEC received information from 

two States (VA and NC) relative to modifications to either growth or control factors. Details on 

these comments and the changes resulting from them are detailed below by State. 

3.1 VA Changes 

VA DEQ representatives provided comments back to MACTEC related to a list of current 

controls applied to 2009 and 2018. These comments largely addressed the control levels that 

would be utilized for a 2012 inventory for the counties in northern VA that are part of the OTC. 

For the majority of these counties and the area sources that they applied to, the controls were 

utilized as recommended by VA DEQ. In one instance however, VA questioned the value of a 

control applied to the 2009 and 2018 inventory for consumer solvent sources. In the original 

2009/2018 VISTAS inventory, a control value of 25% was applied to all counties in the VISTAS 

(ASIP) region to cover the controls implemented by the national consumer solvent control 

program. However further evaluation coupled with discussion with E.H. Pechan staff (who 

developed the original CAIR control values) indicated that the values for this source should be 

only 20% as that more correctly represented the national control program. Thus for 2012, the 

control was applied as 20% for counties subject only to the national control program for 
Documentation of the 2012 Emission Inventory 

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consumer solvents. For some counties in VA, an additional control was applied due to the OTC 

rule affecting this source category. The controls applied for the OTC counties for this category 

are shown in Table 3.1-1 below. 

Table 3.1-1. 2012 Control Efficiency (CE), Rule Effectiveness (RE), Rule Penetration (RP) 

and Control Device ID for VA Counties with OTC Controls 

State, County 

FIPs 

SCC Pollutant SCC Description CE RE RP Device ID 

51013, 51059, 

51107, 51153, 

51177, 51179, 

51510, 51600, 

51610, 51630, 

51683, 51685 

2401002000 VOC Solvent Utilization, Surface 

Coating, Architectural Coatings - 

Solvent-based, Total: All Solvent 

Types 

31 100 100 102 

51013, 51059, 

51107, 51153, 

51177, 51179, 

51510, 51600, 

51610, 51630, 

51683, 51685 

2401003000 VOC Solvent Utilization, Surface 

Coating, Architectural Coatings - 

Water-based, Total: All Solvent 

Types 

31 100 100 102 

51013, 51059, 

51107, 51153, 

51177, 51179, 

51510, 51600, 

51610, 51630, 

51683, 51685 

2401005000 VOC Solvent Utilization, Surface 

Coating, Auto Refinishing: SIC 

7532, Total: All Solvent Types 

38 100 100 102 

51013, 51059, 

51107, 51153, 

51177, 51179, 

51510, 51600, 

51610, 51630, 

51683, 51685 

2401008000 VOC Solvent Utilization, Surface 

Coating, Traffic Markings, Total: 

All Solvent Types 

31 100 100 102 

51013, 51059, 

51107, 51153, 

51177, 51179, 

51510, 51600, 

51610, 51630, 

51683, 51685 

2401100000 VOC Solvent Utilization, Surface 

Coating, Industrial Maintenance 

Coatings, Total: All Solvent Types 

31 100 100 102 

51013, 51059, 

51107, 51153, 

51177, 51179, 

51510, 51600, 

51610, 51630, 

51683, 51685 

2401200000 VOC Solvent Utilization, Surface 

Coating, Other Special Purpose 

Coatings, Total: All Solvent Types 

31 100 100 102 
Documentation of the 2012 Emission Inventory 

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State, County 

FIPs 

SCC Pollutant SCC Description CE RE RP Device ID 

51013, 51059, 

51107, 51153, 

51177, 51179, 

51510, 51600, 

51610, 51630, 

51683, 51685 

2415300000 VOC Solvent Utilization, Degreasing, All 

Industries: Cold Cleaning, Total: All 

Solvent Types 

66 100 100 046 

51013, 51059, 

51107, 51153, 

51177, 51179, 

51510, 51600, 

51610, 51630, 

51683, 51685 

2415330000 VOC Solvent Utilization, Degreasing, 

Electronic and Other Elec. (SIC 36): 

Cold Cleaning, Total: All Solvent 

Types 

66 100 100 046 

51013, 51059, 

51107, 51153, 

51177, 51179, 

51510, 51600, 

51610, 51630, 

51683, 51685 

2415345000 VOC Solvent Utilization, Degreasing, 

Miscellaneous Manufacturing (SIC 

39): Cold Cleaning, Total: All 

Solvent Types 

66 100 100 046 

51013, 51059, 

51107, 51153, 

51177, 51179, 

51510, 51600, 

51610, 51630, 

51683, 51685 

2415360000 VOC Solvent Utilization, Degreasing, 

Auto Repair Services (SIC 75): Cold 

Cleaning, Total: All Solvent Types 

66 100 100 046 

51013, 51059, 

51107, 51153, 

51510, 51600, 

51610, 51683, 

51685 

2465900000 VOC Solvent Utilization, Miscellaneous 

Non-industrial: Consumer, 

Miscellaneous Products: NEC, 

Total: All Solvent Types 

32.73 100 100 102 

51177, 51179, 

51630 

2465900000 VOC Solvent Utilization, Miscellaneous 

Non-industrial: Consumer, 

Miscellaneous Products: NEC, 

Total: All Solvent Types 

31.36 100 100 102 

51013, 51059, 

51107, 51153, 

51510, 51600, 

51610, 51683, 

51685 

2501060300 VOC Portable Fuel Containers 61.5 099 

51179 2501060300 VOC Portable Fuel Containers 60 099 

51177, 51630 2501060300 VOC Portable Fuel Containers 37.5 099 
Documentation of the 2012 Emission Inventory 

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State, County 

FIPs 

SCC Pollutant SCC Description CE RE RP Device ID 

51013, 51059, 

51107, 51153, 

51510, 51600, 

51610, 51683, 

51685 

2440020000 VOC Industrial Adhesives and Sealants 64.4 100 100 102 

51177, 51630 2501060051 VOC Storage and Transport, Petroleum 

and Petroleum Product Storage, 

Gasoline Service Stations, Stage 1: 

Submerged Filling 

95.89727 91 80 093 

3.2 NC Changes 

In preparing the Base G inventory for VISTAS for NC, NC had prepared estimates of emissions 

for a number of area sources. These estimates were to directly replace the projected emissions 

developed using the standard projection technique used for all other States. However, the 

sources covered in 2009 and 2018 for the data provided by NC for the Base G updates did not 

represent a one-to-one correspondence (e.g., there were some sources in 2009 that were not 

included in 2018 and vice versa). Thus a straight-line interpolation would not work for all 

sources. MACTEC discussed this situation with NC staff and a determination was made to 

develop and apply emissions estimated using a straight-line interpolation for those sources that 

were common between 2009 and 2018. For any remaining sources, their emissions were 

developed using the standard projection technique developed for VISTAS and applied here using 

interpolated growth and control factors as described above. Thus there is a slight disconnect 

between the methods used to prepare the 2009, 2012 and 2018 emission projections for NC. 

3.3 Area Source Results 

Tables 3.3-1 through 3.3-8 show the results by pollutant, State and year for the ASIP 2012 area 

source inventory. The values in each table also include the 2002 VISTAS Base Year inventory 

value, along with the B&F values for 2009 and 2018. During the review process for SIP 

submittals, Jefferson County, KY air quality personnel identified that there were missing area 

source SO2 sources. In evaluating the cause of the missing sources, MACTEC discovered that 

the sources were removed during the CERR update process. MACTEC had received a CERR 

submittal from Jefferson County (via U.S. EPA) that included records for sources with pollutants 

that were not ozone related pollutants. The methodology used by MACTEC to govern whether 

or not a CERR data set represented a complete replacement set was to look for non-ozone 

pollutants. If they were present then the dataset was regarded as complete and a complete 

replacement was performed substituting the CERR data for the previous data. However in this 

case, the pollutants were not complete. MACTEC corrected those records after the preparation 
Documentation of the 2012 Emission Inventory 

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of the B&F inventories for 2009 and 2018. The updated dataset was used as the starting point 

for the 2012 inventory projection. That resulted in increased SO2 emissions relative to 2009 and 

2018 levels and modest increases in some additional pollutants. The additional pollutants were 

also affected because all pollutant records associated with the missing SO2 source categories 

were replaced when the corrected Jefferson County, KY file was developed post-B&F. This 

resulted in moderate increases in NOx, PM2.5 and VOC in 2012 (relative to 2009/2018) in KY. 
Documentation of the 2012 Emission Inventory 

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Table 3.3-1. Comparison of the 2012 ASIP CO Emissions with 2002, 2009 and 2018 

VISTAS B&F Inventory Values 

State Pollutant 2002 2009 2012 2018 

AL CO 83,958 66,654 64,302 59,626 

FL CO 71,079 57,011 55,942 53,903 

GA CO 107,889 93,918 93,763 93,567 

KY CO 66,752 57,887 65,598 54,865 

MS CO 37,905 27,184 25,484 22,099 

NC CO 345,278 301,123 297,671 290,765 

SC CO 113,714 90,390 87,929 83,167 

TN CO 89,246 73,563 71,702 68,005 

VA CO 155,873 128,132 125,917 121,690 

WV CO 39,546 31,640 30,668 28,773 

Total 1,111,240 927,502 918,976 876,460 

Table 3.3-2. Comparison of the 2012 ASIP NH3 Emissions with 2002, 2009 and 2018 

VISTAS B&F Inventory Values 

State Pollutant 2002 2009 2012 2018 

AL NH3 58,318 64,268 66,814 71,915 

FL NH3 37,446 38,616 39,221 40,432 

GA NH3 80,913 89,212 92,768 99,885 

KY NH3 51,135 53,005 53,826 55,211 

MS NH3 58,721 63,708 65,775 69,910 

NC NH3 161,859 170,313 173,830 180,865 

SC NH3 28,166 30,555 31,535 33,496 

TN NH3 34,322 35,176 35,515 36,193 

VA NH3 43,905 46,639 47,818 50,175 

WV NH3 9,963 10,625 10,918 11,504 

Total 564,748 602,117 618,020 649,586 
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Table 3.3-3. Comparison of the 2012 ASIP NOx Emissions with 2002, 2009 and 2018 

VISTAS B&F Inventory Values 

State Pollutant 2002 2009 2012 2018 

AL NOx 23,444 23,930 24,295 25,028 

FL NOx 28,872 28,187 29,027 30,708 

GA NOx 36,105 37,689 38,887 41,282 

KY NOx 39,507 42,088 63,539 44,346 

MS NOx 4,200 4,249 4,327 4,483 

NC NOx 36,512 39,913 41,215 43,820 

SC NOx 19,332 19,360 19,771 20,592 

TN NOx 17,831 18,485 18,850 19,579 

VA NOx 51,418 52,618 53,799 56,158 

WV NOx 12,687 13,439 13,902 14,828 

Total 269,908 279,958 307,612 300,824 

Table 3.3-4. Comparison of the 2012 ASIP PM10 Emissions with 2002, 2009 and 2018 

VISTAS B&F Inventory Values 

State Pollutant 2002 2009 2012 2018 

AL PM10-PRI 393,426 412,815 422,807 444,996 

FL PM10-PRI 443,346 503,230 527,162 578,516 

GA PM10-PRI 695,320 776,305 809,564 880,070 

KY PM10-PRI 233,559 242,177 255,887 256,052 

MS PM10-PRI 343,377 356,324 361,527 375,495 

NC PM10-PRI 280,350 292,412 300,020 315,259 

SC PM10-PRI 260,858 278,299 286,202 304,251 

TN PM10-PRI 211,913 225,409 230,965 245,368 

VA PM10-PRI 237,577 252,488 258,629 275,351 

WV PM10-PRI 115,346 115,089 116,717 121,549 

Total 3,215,072 3,454,548 3,569,480 3,796,907 
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Table 3.3-5. Comparison of the 2012 ASIP PM2.5 Emissions with 2002, 2009 and 2018 

VISTAS B&F Inventory Values 

State Pollutant 2002 2009 2012 2018 

AL PM25-PRI 56,630 58,668 59,138 62,284 

FL PM25-PRI 58,878 64,589 66,047 72,454 

GA PM25-PRI 103,726 111,924 114,491 123,610 

KY PM25-PRI 45,453 46,243 48,819 47,645 

MS PM25-PRI 50,401 51,661 50,994 53,222 

NC PM25-PRI 64,029 69,432 70,008 71,234 

SC PM25-PRI 40,291 41,613 41,767 44,319 

TN PM25-PRI 42,103 43,627 43,338 46,054 

VA PM25-PRI 43,989 44,514 43,762 46,697 

WV PM25-PRI 21,049 20,664 20,414 21,490 

Total 526,549 552,935 558,778 589,009 

Table 3.3-6. Comparison of the 2012 ASIP SO2 Emissions with 2002, 2009 and 2018 

VISTAS B&F Inventory Values 

State Pollutant 2002 2009 2012 2018 

AL SO2 52,253 48,228 48,907 50,264 

FL SO2 40,491 36,699 37,238 38,317 

GA SO2 57,555 57,692 58,368 59,724 

KY SO2 41,805 43,087 58,204 44,186 

MS SO2 771 753 751 746 

NC SO2 5,392 5,730 5,841 6,062 

SC SO2 12,900 13,051 13,186 13,457 

TN SO2 29,897 30,555 31,015 31,935 

VA SO2 105,890 105,984 107,116 109,380 

WV SO2 11,667 12,284 12,473 12,849 

Total 358,621 354,063 373,099 366,920 
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Table 3.3-7. Comparison of the 2012 ASIP VOC Emissions with 2002, 2009 and 2018 

VISTAS B&F Inventory Values 

State Pollutant 2002 2009 2012 2018 

AL VOC 182,674 143,454 144,985 153,577 

FL VOC 404,302 420,172 444,276 489,975 

GA VOC 299,127 271,644 286,523 318,531 

KY VOC 95,375 94,042 112,381 103,490 

MS VOC 131,808 124,977 125,044 140,134 

NC VOC 237,545 187,355 179,248 189,120 

SC VOC 161,000 146,107 151,149 161,228 

TN VOC 146,283 146,826 151,612 172,529 

VA VOC 172,989 145,675 143,031 149,262 

WV VOC 60,443 55,288 54,287 60,747 

Total 1,891,546 1,735,540 1,792,536 1,938,593 
Documentation of the 2012 Emission Inventory 

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4.0 2012 Onroad Mobile Sources 

Our continued approach for assembling data to simulate the 2012 calendar year was to use as 

much existing data from the existing Best and Final 2002, 2009, and 2018 base year and 

projections as possible and to supplement these data with information provided by the States. 

The resulting initial 2012 input data for the MOBILE6 module were delivered to the States for 

review prior to emissions modeling. 

To ensure consistency across evaluation years, the 2012 base case inventory was developed 

using methodologies comparable to those employed in developing the 2009 and 2018 on-road 

portion of the ASIP inventories. All modifications to the 2012 inventory methods were 

developed in consultation with the ASIP State workgroup. Generally, modifications were only 

made to properly account for actual changes expected in the intervening period (i.e., between 

2009 and 2018) reflecting the reduction in NOx and SO2 as anticipated with cleaner fuels and 

cleaner engines. 

4.1 Development of on-road mobile source input files 

As noted in documentation of the 2002, 2009 and 2018 inventory preparation (Documentation of 

the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories for VISTAS

(B&F Document), March 14, 2008), MACTEC prepared versions of the 2009 and 2018 base 

case mobile inventory input data files. 

Because no preliminary 2012 inventory was developed, Alpine Geophysics, LLC (Alpine) 

developed the 2012 initial input files for on-road mobile sources using methods similar to those 

employed for the 2009 and 2018 inventories coupled with changes and revisions provided by the 

States. Therefore, as was the case for 2009 and 2018, Alpine obtained from the States input data 

revisions, methodological revisions, and local control program specifications (to the extent that 

they differed from 2009/2018). These files were used in the MOBILE6 module of the SMOKE 

emissions processor to develop resulting emission estimates for this source category 

4.1.1 Preparation of revised 2012 input data files 

The methodology used to develop the 2012 on-road input files was based on forecasting the 

previously developed revised 2002 base year input files and is identical to that previously 

described for the revised 2009/2018 methodology except as follows: 

1. The evaluation year was updated to 2012. 

2. Diesel fuel sulfur content was revised from 500 ppm to 11 ppm. The 11 ppm value 

was identified from the EPA report entitled "Technical Guidance on the Use of 

MOBILE6.2 for Emission Inventory Preparation" (EPA 420-R-04-013, August 2004), 
Documentation of the 2012 Emission Inventory 

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which stipulated diesel sulfur values from June, 2010 - May 2015 to be modeled as 11 

ppm. 

3. Diesel sales fractions were updated identically as to 2009. 

4. VMT mix fractions were updated to 2012 using an identical method to that described 

for 2009/2018. 

5. All other input data were retained at 2009 values, except as otherwise instructed by 

individual States (see below). This includes all control program descriptions (I/M, 

ATP, Stage II, etc.), all other fuel qualities (RVP, oxy content, etc.), all other vehicle 

descriptive data (registration age distributions, etc.), and all scenario descriptive data. 

In addition to the updates described above that were applied to all ASIP-region inputs, the 

following additional State-specific updates were performed. 

Alabama: 

Alabama provided changes in RVP for all counties. The RVP was set at no lower than 9.0 psi for 

ozone season Statewide and for Jefferson and Shelby, no lower than 7.8 psi. 

Virginia:

Virginia replaced I/M parameter files to incorporate a 4-year grace period for emission testing. 

"VAIM09.IM" was used for Arlington, Fairfax, Prince William, and Alexandria. 

"VAIM09LS.IM" was used for Loudoun and Stafford counties. Modifications to the county cross 

reference files were made to include Falls Church and Fairfax City in Fairfax county and 

Manassas and Manassas Park in Prince William county input file associations. Virginia modified 

the MOBILE6 OXYGENATED FUELS command using 0% and 3.5% respectively for Ether 

and Ethanol Oxygen Content and 0% and 100% respectively for Ether and Ethanol Market Share 

to incorporate the effects of the Energy Policy Act (2005). 

4.1.2 VMT Data 

The basic methodology used to generate the 2012 VMT for use in estimating on-road mobile 

source emissions was a linear interpolation of the 2009 and 2018 VMT at the county-SCC level 

of detail. 

The following States provided some types of forecast data for 2012 VMT. The information 

presented below identifies these submittals as used in the 2012 simulations. 

Kentucky: 

Revised 2012 VMT and VMT mix data were provided by the DEP/DAQ of Kentucky and from 

the Louisville APCD (Bullitt, Jefferson and Oldham counties). 
Documentation of the 2012 Emission Inventory 

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North Carolina: 

North Carolina provided revised VMT estimates for Perquimans Co. to reflect updated 2009 

levels during 2012 interpolation calculation. 

South Carolina: 

South Carolina provided statewide county and roadway type-specific VMT data for 2012. 

Virginia: 

Virginia provided county and roadway type-specific annual VMT for 2012 and these data were 

used directly in the MOBILE6/SMOKE runs consistent with data previously provided for 

2009/2018. 

West Virginia:

West Virginia identified a double counting of VMT in Ohio County, WV for the 2018 calendar 

year which artificially increased the 2012 interpolation using these data. The 2018 VMT were 

corrected per West Virginia’s direction and 2012 VMT estimated from the resulting VMT levels. 

4.2 Processing of On-Road Mobile Source Emissions 

The MOBILE6 module of SMOKE was used to develop the base year on-road mobile source 

emissions estimates for CO, NH3 NOx, PM and VOC emissions. The MOBILE6 parameters, 

vehicle fleet descriptions, and VMT estimates were combined with gridded, episode-specific 

temperature data to calculate the gridded, temporalized emission estimates. Of note, whereas the 

on-network emissions estimates are spatially allocated based on link location and subsequently 

summed to the grid cell level, the off-network emissions estimates are spatially allocated based 

on a combination of the FHWA version 2.0 highway networks and population. For the ASIP 

36/12 km modeling, no link based data was used. The MOBILE6 emissions factors are based on 

episode-specific temperatures predicted by the meteorological model. Further, the MOBILE6 

emissions factors model accounts for the following: 

 Hourly and daily minimum/maximum temperatures; 

 Facility speeds; 

 Locale-specific inspection/maintenance (I/M) control programs, if any; 

 Adjustments for running losses; 

 Splitting of evaporative and exhaust emissions into separate source categories; 

 VMT, fleet turnover, and changes in fuel composition and Reid vapor pressure (RVP). 
Documentation of the 2012 Emission Inventory 

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The primary input to MOBILE6 is the MOBILE shell file. The MOBILE shell contains the 

various options (e.g. type of inspection and maintenance program in effect, type of oxygenated 

fuel program in effect, alternative vehicle mix profiles, RVP of in-use fuel, operating mode) that 

direct the calculation of the MOBILE6 emissions factors. 

For the production of the MOBILE6 emission factors SMOKE was run using the hourly episodespecific meteorological data for temperature and humidity. SMOKE produces emissions factors 

for state and county groups that are selected for regional similarities and consistent MOBILE6 

option requirements (i.e. I/M programs, RVP, fuel programs). The hourly average temperature 

and humidity are calculated from the hourly temperatures in each grid cell in the state/county 

groups. 

SMOKE was run using the daily average speed option for all states except North Carolina. The 

daily average speed was provided based on state, county, and roadway type. North Carolina 

provided hourly average speeds, also based on state, county and roadway type. 

Producing 365 day-specific input files for all source categories places a burden on available 

computing facilities, data management systems, and would have adversely affected the modeling 

schedule. Selecting representative model days for processing on-road source categories reduces 

the processing and file handling requirements to a more manageable level and in most cases does 

not compromise the accuracy of the emissions files. 

Other current or recent projects undertaken by EPA and other RPOs have used a selection 

approach for all of the source categories (except biogenics) that use a representative 

weekday/Saturday/Sunday either for each month or each season to model all of the emissions 

files. In an attempt to better represent the level of temporal and spatial detail available for each 

source category, we have developed and implemented a more detailed strategy. 

Motor vehicle emissions are influenced by meteorological variability, but the processing 

requirements for daily motor vehicle emissions were determined to be prohibitive under the 

current schedule. Rather than utilizing averaged meteorological data or pre-calculated motor 

vehicle emissions, a single week per month was selected for modeling. This week was selected 

from mid-month, to try to best represent the average temperature ranges for the month, and also 

adjusted to exclude holidays that would require atypical processing. The area source modeling 

dates were also selected from these ranges to simplify data handling procedures. 

On-Road Mobile Sources Represented by the Following Weeks

January 13-19 

February 10-16 

March 10-16 
Documentation of the 2012 Emission Inventory 

52

April14-20 

May 12-18 

June 9-15 

July 14-20 

August 11-17 

September 15-21 

October 13-19 

November 10-16 

December 15-21 

4.3 On-road Emission Summaries 

The following tables provide annual emission summaries for the ASIP States using the input files 

described here and in other ASIP inventory preparation documentation and the methods and 

models described above for on-road emissions generation. 

Table 4.3-1. On-road Mobile Source SO2 Emission Comparison. 

Annual On-road Emissions (Tons/Year) 

State 2002 2009 2012 2018 

AL 6,900 810 648 720 

FL 20,915 2,612 2,214 2,533 

GA 12,184 1,585 1,291 1,457 

KY 6,308 759 554 763 

MS 4,614 537 399 440 

NC 12,420 1,503 1,268 1,481 

SC 5,972 721 570 643 

TN 9,226 1,076 847 948 

VA 8,294 1,079 934 1,043 

WV 2,464 279 226 253 

TOTAL 89,296 10,962 8,950 10,281 
Documentation of the 2012 Emission Inventory 

53

Table 4.3-2. On-road Mobile Source NOx Emission Comparison. 

Annual On-road Emissions (Tons/Year) 

State 2002 2009 2012 2018 

AL 158,212 101,831 79,323 47,298 

FL 465,640 315,840 241,360 150,180 

GA 307,732 209,349 168,100 102,179 

KY 156,417 101,182 77,031 52,263 

MS 111,914 70,743 53,746 30,619 

NC 327,329 201,609 156,730 87,791 

SC 140,489 92,499 72,068 43,490 

TN 238,577 151,912 118,850 69,385 

VA 222,374 134,232 105,930 63,342 

WV 58,999 35,635 28,137 17,247 

TOTAL 2,187,683 1,414,834 1,101,275 663,796 

Table 4.3-3. On-road Mobile Source VOC Emission Comparison. 

Annual On-road Emissions (Tons/Year) 

State 2002 2009 2012 2018 

AL 127,295 76,990 65,142 49,175 

FL 527,209 340,947 280,960 222,303 

GA 283,421 195,125 161,520 109,763 

KY 103,503 73,942 47,584 47,066 

MS 87,672 52,107 41,664 31,616 

NC 263,766 168,676 138,836 101,099 

SC 116,163 72,603 59,741 46,301 

TN 179,807 115,181 93,985 67,324 

VA 159,790 96,770 78,761 61,964 

WV 42,174 24,843 20,287 16,121 

TOTAL 1,890,798 1,217,185 988,480 752,732 
Documentation of the 2012 Emission Inventory 

54

Table 4.3-4. On-road Mobile Source CO Emission Comparison. 

Annual On-road Emissions (Tons/Year) 

State 2002 2009 2012 2018 

AL 1,321,528 915,647 746,150 676,210 

FL 4,550,447 3,352,509 2,714,700 2,554,160 

GA 2,735,968 1,983,803 1,635,800 1,476,981 

KY 1,230,148 963,762 707,250 807,536 

MS 864,290 609,972 487,540 445,493 

NC 2,873,992 1,991,708 1,544,500 1,362,214 

SC 1,241,359 889,957 717,230 663,493 

TN 1,917,842 1,338,016 1,086,400 976,634 

VA 2,163,259 1,453,946 1,139,600 1,075,104 

WV 533,471 365,549 296,200 274,804 

TOTAL 19,432,305 13,864,869 11,075,370 10,312,627 

Table 4.3-5. On-road Mobile Source NH3 Emission Comparison. 

Annual On-road Emissions (Tons/Year) 

State 2002 2009 2012 2018 

AL 5,588 6,364 6,687 7,298 

FL 18,114 21,781 23,280 26,163 

GA 10,546 12,687 13,423 14,873 

KY 5,055 5,796 5,695 7,811 

MS 3,585 4,035 4,216 4,566 

NC 9,702 11,825 12,617 14,065 

SC 4,694 5,523 5,849 6,473 

TN 6,625 7,782 8,186 9,021 

VA 7,852 9,086 9,629 10,624 

WV 1,908 2,148 2,250 2,497 

TOTAL 73,670 87,027 91,832 103,394 
Documentation of the 2012 Emission Inventory 

55

Table 4.3-6. On-road Mobile Source PM10 Emission Comparison. 

Annual On-road Emissions (Tons/Year) 

State 2002 2009 2012 2018 

AL 3,903 3,171 2,802 2,410 

FL 11,275 9,911 9,061 8,268 

GA 7,246 6,072 5,417 4,844 

KY 3,723 2,976 2,466 2,580 

MS 2,859 2,275 1,970 1,624 

NC 6,579 5,572 4,926 4,392 

SC 3,452 2,862 2,529 2,184 

TN 5,371 4,206 3,654 3,092 

VA 4,549 3,747 3,429 3,212 

WV 1,381 1,068 937 819 

TOTAL 50,338 41,861 37,190 33,426 

Table 4.3-7. On-road Mobile Source PM2.5 Emission Comparison. 

Annual On-road Emissions (Tons/Year) 

State 2002 2009 2012 2018 

AL 2,799 2,032 1,646 1,192 

FL 7,868 6,173 5,188 4,038 

GA 5,168 3,840 3,127 2,380 

KY 2,697 1,920 1,459 1,272 

MS 2,112 1,508 1,196 819 

NC 4,623 3,493 2,807 2,123 

SC 2,501 1,855 1,502 1,087 

TN 3,949 2,751 2,186 1,544 

VA 3,102 2,241 1,877 1,543 

WV 995 684 549 405 

TOTAL 35,813 26,498 21,535 16,403 
Documentation of the 2012 Emission Inventory 

56

APPENDIX A: 

COMPARISON OF EGU CONTROLS FOR COAL AND OIL/GAS UNITS 

BASED ON IPM MODELING AND STATE-PROVIDED INFORMATION 

FOR THE 2012 INVENTORY
Documentation of the 2012 Emission Inventory 

57

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

01 033 01033 TVA COLBERT 47 1 0010 010 Coal 

Steam 

None None N

01 033 01033 TVA COLBERT 47 2 0010 011 Coal 

Steam 

None None N

01 033 01033 TVA COLBERT 47 3 0010 012 Coal 

Steam 

None None N

01 033 01033 TVA COLBERT 47 4 0010 013 Coal 

Steam 

None None N

01 033 01033 TVA COLBERT 47 5 0010 014 Coal 

Steam 

SCR SCR Scru

01 055 01055 ALABAMA POWER COMPANY 

GADSDEN 

7 1 0002 002 Coal 

Steam 

None None N

01 055 01055 ALABAMA POWER COMPANY 

GADSDEN 

7 2 0002 003 Coal 

Steam 

None None N

01 063 01063 ALABAMA POWER COMPANY 

GREENE COUNTY 

10 1 0001 002 Coal 

Steam 

SCR SCR N

01 063 01063 ALABAMA POWER COMPANY 

GREENE COUNTY 

10 2 0001 003 Coal 

Steam 

SCR SCR N

01 071 01071 TVA - WIDOWS CREEK 50 1 0008 002 Coal 

Steam 

SCR SCR N

01 071 01071 TVA - WIDOWS CREEK 50 2 0008 003 Coal 

Steam 

SCR SCR N

01 071 01071 TVA - WIDOWS CREEK 50 3 0008 004 Coal 

Steam 

SCR SCR N

01 071 01071 TVA - WIDOWS CREEK 50 4 0008 005 Coal 

Steam 

SCR SCR N

01 071 01071 TVA - WIDOWS CREEK 50 5 0008 006 Coal 

Steam 

SCR SCR N

01 071 01071 TVA - WIDOWS CREEK 50 6 0008 007 Coal 

Steam 

SCR SCR N
Documentation of the 2012 Emission Inventory 

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Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

01 071 01071 TVA - WIDOWS CREEK 50 7 0008 008 Coal 

Steam 

SCR SCR Scru

01 071 01071 TVA - WIDOWS CREEK 50 8 0008 009 Coal 

Steam 

SCR SCR Scru

01 073 01073 ALABAMA POWER COMPANY 

(MILLER POWER PLANT) 

6002 4 010730011 001 Coal 

Steam 

SCRAll Year SCRSummer Scru

01 073 01073 ALABAMA POWER COMPANY 

(MILLER POWER PLANT) 

6002 3 010730011 002 Coal 

Steam 

SCR 

All Year 

SCR 

Summer 

Scru

01 073 01073 ALABAMA POWER COMPANY 

(MILLER POWER PLANT) 

6002 2 010730011 004 Coal 

Steam 

SCR 

All Year 

SCR 

Summer 

Scru

01 073 01073 ALABAMA POWER COMPANY 

(MILLER POWER PLANT) 

6002 1 010730011 005 Coal 

Steam 

SCR 

All Year 

SCR 

Summer 

Scru

01 097 01097 ALABAMA POWER COMPANY 

BARRY 

3 1 1001 002 Coal 

Steam 

SNCR None N

01 097 01097 ALABAMA POWER COMPANY 

BARRY 

3 2 1001 003 Coal 

Steam 

SNCR None N

01 097 01097 ALABAMA POWER COMPANY 

BARRY 

3 3 1001 004 Coal 

Steam 

SNCR None N

01 097 01097 ALABAMA POWER COMPANY 

BARRY 

3 4 1001 005 Coal 

Steam 

SNCR None N

01 097 01097 ALABAMA POWER COMPANY 

BARRY 

3 5 1001 006 Coal 

Steam 

SCR None Scru

01 117 01117 ALABAMA POWER COMPANY 

E C GASTON 

26 1 0005 002 Coal 

Steam 

None SCR N

01 117 01117 ALABAMA POWER COMPANY 

E C GASTON 

26 2 0005 003 Coal 

Steam 

None SCR N

01 117 01117 ALABAMA POWER COMPANY 

E C GASTON 

26 3 0005 004 Coal 

Steam 

None SCR N

01 117 01117 ALABAMA POWER COMPANY 

E C GASTON 

26 4 0005 005 Coal 

Steam 

None SCR N
Documentation of the 2012 Emission Inventory 

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Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

01 117 01117 ALABAMA POWER COMPANY 

E C GASTON 

26 5 0005 006 Coal 

Steam 

SCR SCR Scru

01 127 01127 ALABAMA POWER COMPANY 

GORGAS 

8 6 0001 004 Coal 

Steam 

None None N

01 127 01127 ALABAMA POWER COMPANY 

GORGAS 

8 7 0001 005 Coal 

Steam 

None None N

01 127 01127 ALABAMA POWER COMPANY 

GORGAS 

8 8 0001 006 Coal 

Steam 

None None Scru

01 127 01127 ALABAMA POWER 

COMPANYGORGAS 

8 9 0001 007 Coal 

Steam 

None None Scru

01 127 01127 ALABAMA POWER COMPANY 

GORGAS 

8 10 0001 008 Coal 

Steam 

SCR SCR Scru

01 129 01129 ALABAMA ELECTRIC COOP 

CHARLES R LOWMAN 

56 1 0001 002 Coal 

Steam 

None None Scru

01 129 01129 ALABAMA ELECTRIC COOP 

CHARLES R LOWMAN 

56 2 0001 003 Coal 

Steam 

SCR SCR Scru

01 129 01129 ALABAMA ELECTRIC COOP 

CHARLES R LOWMAN 

56 3 0001 004 Coal 

Steam 

SCR SCR Scru

12 001 12001 GAINESVILLE REGIONAL 

UTILITIES JOHN R KELLY 

664 JRK6 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 001 12001 GAINESVILLE REGIONAL 

UTILITIES JOHN R KELLY 

664 JRK7 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 001 12001 GAINESVILLE REGIONAL 

UTILITIES JOHN R KELLY 

664 JRK8 0010005 7 O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 001 12001 CITY OF GAINESVILLE, GRU 

DEERHAVEN 

663 B1 0010006 3 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

12 001 12001 CITY OF GAINESVILLE, GRU 

DEERHAVEN 

663 B2 0010006 5 Coal 

Steam 

None None N

12 005 12005 GULF POWER COMPANY 

LANSING SMITH PLANT 

643 1 0050014 1 Coal 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

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Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

12 005 12005 GULF POWER COMPANY 

LANSING SMITH PLANT 

643 2 0050014 2 Coal 

Steam 

None None N

12 009 12009 FLORIDA POWER & LIGHT 

(PCC) CAPE CANAVERAL 

609 PCC1 0090006 1 O/G 

Steam 

None None N

12 009 12009 FLORIDA POWER & LIGHT 

(PCC) CAPE CANAVERAL 

609 PCC2 0090006 2 O/G 

Steam 

None None N

12 011 12011 FLORIDA POWER & LIGHT 

(PPE) PORT EVERGLADES 

617 PPE1 0110036 1 O/G 

Steam 

None No 

Operation 

N

12 011 12011 FLORIDA POWER & LIGHT 

(PPE) PORT EVERGLADES 

617 PPE2 0110036 2 O/G 

Steam 

None No 

Operation 

N

12 011 12011 FLORIDA POWER & LIGHT 

(PPE) PORT EVERGLADES 

617 PPE3 0110036 3 O/G 

Steam 

None No 

Operation 

N

12 011 12011 FLORIDA POWER & LIGHT 

(PPE) PORT EVERGLADES 

617 PPE4 0110036 4 O/G 

Steam 

None No 

Operation 

N

12 017 12017 PROGRESS ENERGY FLORIDA 

CRYSTAL RIVER 

628 1 0170004 1 Coal 

Steam 

None None N

12 017 12017 PROGRESS ENERGY FLORIDA 

CRYSTAL RIVER 

628 2 0170004 2 Coal 

Steam 

None None N

12 017 12017 PROGRESS ENERGY FLORIDA 

CRYSTAL RIVER 

628 5 0170004 3 Coal 

Steam 

None None N

12 017 12017 PROGRESS ENERGY FLORIDA 

CRYSTAL RIVER 

628 4 0170004 4 Coal 

Steam 

SCR SCR Scru

12 031 12031 SAINT JOHNS RIVER 207 1 0310045-A 16 SCR SCR Scru12 031 12031 SAINT JOHNS RIVER 207 2 0310045-A 17 SCR SCR Scru12 031 12031 NORTHSIDE 667 2A 0310045-B 26 O/G 

Steam 

None No 

Operation 

N

12 031 12031 NORTHSIDE 667 1A 0310045-B 27 O/G 

Steam 

None No 

Operation 

N
Documentation of the 2012 Emission Inventory 

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Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

12 031 12031 NORTHSIDE 667 3 0310045-B 3 O/G 

Steam 

None No 

Operation 

N

12 031 12031 CEDAR BAY COGENERATION 

INC. 

10672 GEN1 0310337 1 Coal 

Steam 

None SNCR Scru

12 033 12033 GULF POWER COMPANY 

CRIST ELECTRIC GENERATION 

641 2 0330045 2 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 033 12033 GULF POWER COMPANY 

CRIST ELECTRIC GENERATION 

641 3 0330045 3 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 033 12033 GULF POWER COMPANY 

CRIST ELECTRIC GENERATION 

641 4 0330045 4 Coal 

Steam 

None None Scru

12 033 12033 GULF POWER COMPANY 

CRIST ELECTRIC GENERATION 

641 5 0330045 5 Coal 

Steam 

None None Scru

12 033 12033 GULF POWER COMPANY 

CRIST ELECTRIC GENERATION 

641 6 0330045 6 Coal 

Steam 

SNCR SNCR Scru

12 033 12033 GULF POWER COMPANY 

CRIST ELECTRIC GENERATION 

641 7 0330045 7 Coal 

Steam 

SCR SCR Scru

12 053 12053 Central Power and Lime 

Incorporated 

10333 GEN1 0530021 18 Coal 

Steam 

None None Scru

12 057 12057 TAMPA ELECTRIC COMPANY 

BIG BEND STATION 

645 BB01 0570039 1 Coal 

Steam 

SCR SCR Scru

12 057 12057 TAMPA ELECTRIC COMPANY 

BIG BEND STATION 

645 BB02 0570039 2 Coal 

Steam 

SCR SCR Scru

12 057 12057 TAMPA ELECTRIC COMPANY 

BIG BEND STATION 

645 BB03 0570039 3 Coal 

Steam 

SCR SCR Scru

12 057 12057 TAMPA ELECTRIC COMPANY 

BIG BEND STATION 

645 BB04 0570039 4 Coal 

Steam 

SCR SCR Scru

12 057 12057 TAMPA ELECTRIC COMPANY 

F.J. GANNON STATION 

646 GB01 0570040 1 No 

Operation 

No 

Operation 

N

Ope

12 057 12057 TAMPA ELECTRIC COMPANY 

F.J. GANNON STATION 

646 GB02 0570040 2 No 

Operation 

No 

Operation 

N

Ope
Documentation of the 2012 Emission Inventory 

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Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

12 057 12057 TAMPA ELECTRIC COMPANY 

F.J. GANNON STATION 

646 GB03 0570040 3 No 

Operation 

No 

Operation 

N

Ope

12 057 12057 TAMPA ELECTRIC COMPANY 

F.J. GANNON STATION 

646 GB04 0570040 4 No 

Operation 

No 

Operation 

N

Ope

12 057 12057 TAMPA ELECTRIC COMPANY 

F.J. GANNON STATION 

646 GB05 0570040 5 No 

Operation 

No 

Operation 

N

Ope

12 057 12057 TAMPA ELECTRIC COMPANY 

F.J. GANNON STATION 

646 GB06 0570040 6 No 

Operation 

No 

Operation 

N

Ope

12 061 12061 CITY OF VERO BEACH 693 0610029 1 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 061 12061 CITY OF VERO BEACH 693 3 0610029 3 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

12 061 12061 CITY OF VERO BEACH 693 4 0610029 4 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

12 063 12063 GULF POWER COMPANY 

SCHOLZ 

642 1 0630014 1 Coal 

Steam 

None None N

12 063 12063 GULF POWER COMPANY 

SCHOLZ 

642 2 0630014 2 Coal 

Steam 

None None N

12 073 12073 CITY OF TALLAHASSEE 

ARVAH B.HOPKINS 

688 1 0730003 1 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

12 073 12073 CITY OF TALLAHASSEE 

ARVAH B.HOPKINS 

688 2 0730003 4 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

12 081 12081 FLORIDA POWER & LIGHT 

(PMT) MANATEE POWER 

6042 PMT1 0810010 1 O/G 

Steam 

None No 

Operation 

N

12 081 12081 FLORIDA POWER & LIGHT 

(PMT) MANATEE POWER 

6042 PMT2 0810010 2 O/G 

Steam 

None No 

Operation 

N

12 085 12085 FLORIDA POWER & LIGHT 

(PMR) FPL / MARTIN 

6043 PMR1 0850001 1 O/G 

Steam 

None No 

Operation 

N

12 085 12085 FLORIDA POWER & LIGHT 

(PMR) FPL / MARTIN 

6043 PMR2 0850001 2 O/G 

Steam 

None No 

Operation 

N
Documentation of the 2012 Emission Inventory 

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Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

12 085 12085 INDIANTOWN 

COGENERATION, L.P. 

50976 GEN1 0850102 1 Coal 

Steam 

SCR SCR Scru

12 086 12086 FLORIDA POWER & LIGHT 

(PCU) CUTLER POWER 

610 PCU5 0250001 3 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

12 086 12086 FLORIDA POWER & LIGHT 

(PCU) CUTLER POWER 

610 PCU6 0250001 4 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

12 086 12086 FLORIDA POWER & LIGHT 

(PTF) TURKEY POINT 

621 PTP1 0250003 1 O/G 

Steam 

None No 

Operation 

N

12 086 12086 FLORIDA POWER & LIGHT 

(PTF) TURKEY POINT 

621 PTP2 0250003 2 O/G 

Steam 

None No 

Operation 

N

12 095 12095 ORLANDO UTILITIES 

COMMISSION STANTON ENERGY 

564 1 0950137 1 Coal 

Steam 

SCR SCR Scru

12 095 12095 ORLANDO UTILITIES 

COMMISSION STANTON ENERGY 

564 2 0950137 2 Coal 

Steam 

SCR SCR Scru

12 099 12099 FLORIDA POWER & LIGHT 

(PRV) RIVIERA POWE 

619 PRV3 0990042 3 O/G 

Steam 

None None N

12 099 12099 FLORIDA POWER & LIGHT 

(PRV) RIVIERA POWE 

619 PRV4 0990042 4 O/G 

Steam 

None None N

12 099 12099 CITY OF LAKE WORTH 

UTILITIES TOM G. SMITH 

673 S-1 0990045 7 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 099 12099 CITY OF LAKE WORTH 

UTILITIES TOM G. SMITH 

673 S-3 0990045 9 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 101 12101 PROGRESS ENERGY FLORIDA 

ANCLOTE 

8048 1 1010017 1 O/G 

Steam 

None No 

Operation 

N

12 101 12101 PROGRESS ENERGY FLORIDA 

ANCLOTE 

8048 2 1010017 2 O/G 

Steam 

None No 

Operation 

N

12 103 12103 PROGRESS ENERGY FLORIDA 

BARTOW 

634 1 1030011 1 O/G 

Steam 

None None N

12 103 12103 PROGRESS ENERGY FLORIDA 

BARTOW 

634 2 1030011 2 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir
Documentation of the 2012 Emission Inventory 

64

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

12 103 12103 PROGRESS ENERGY FLORIDA 

BARTOW 

634 3 1030011 3 O/G 

Steam 

None None N

12 105 12105 LAKELAND ELECTRIC 

CHARLES LARSEN 

675 7 1050003 4 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 105 12105 LAKELAND ELECTRIC C.D. 

MCINTOSH, JR. 

676 3 1050004 1 Coal 

Steam 

None Combined 

Cycle 

N

12 105 12105 LAKELAND ELECTRIC C.D. 

MCINTOSH, JR. 

676 3 1050004 5 Coal 

Steam 

None Combined 

Cycle 

N

12 105 12105 LAKELAND ELECTRIC C.D. 

MCINTOSH, JR. 

676 3 1050004 6 Coal 

Steam 

SCR SCR Scru

12 107 12107 SEMINOLE ELECTRIC 

COOPERATIVE, INC. 

136 1 1070025 1 Coal 

Steam 

SCR SCR Scru

12 107 12107 SEMINOLE ELECTRIC 

COOPERATIVE, INC. 

136 2 1070025 2 Coal 

Steam 

SCR SCR Scru

12 111 12111 FT PIERCE UTILITIES 

AUTHORITY FT PIERCE 

658 7 1110003 7 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

12 111 12111 FT PIERCE UTILITIES 

AUTHORITY FT PIERCE 

658 8 1110003 8 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

12 121 12121 PROGRESS ENERGY FLORIDA 

SUWANNEE RIVER 

638 1 1210003 1 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 121 12121 PROGRESS ENERGY FLORIDA 

SUWANNEE RIVER 

638 2 1210003 2 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 121 12121 PROGRESS ENERGY FLORIDA 

SUWANNEE RIVER 

638 3 1210003 3 O/G 

Steam 

None None N

12 127 12127 FLORIDA POWER & LIGHT 

(PSN) SANFORD POWER 

620 PSN3 1270009 1 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

12 127 12127 FLORIDA POWER & LIGHT 

(PSN) SANFORD POWER 

620 PSN4 1270009 2 No 

Operation 

No 

Operation 

N

Ope

12 129 12129 TALLAHASSEE CITY 

PURDOM GENERATING STATION 

689 7 1290001 7 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope
Documentation of the 2012 Emission Inventory 

65

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

13 015 13015 GEORGIA POWER COMPANY, 

BOWEN STEAM-ELECT 

703 1BLR 01500011 SG01 Coal 

Steam 

SCR SCR Scru

95

13 015 13015 GEORGIA POWER COMPANY, 

BOWEN STEAM-ELECT 

703 2BLR 01500011 SG02 Coal 

Steam 

SCR SCR Scru

95

13 015 13015 GEORGIA POWER COMPANY, 

BOWEN STEAM-ELECT 

703 3BLR 01500011 SG03 Coal 

Steam 

SCR SCR Scru

95

13 015 13015 GEORGIA POWER COMPANY, 

BOWEN STEAM-ELECT 

703 4BLR 01500011 SG04 Coal 

Steam 

SCR SCR Scru

95

13 021 13021 ARKWRIGHT 699 1 0002 1 No 

Operation 

No 

Operation 

N

Ope

13 021 13021 ARKWRIGHT 699 2 0002 2 No 

Operation 

No 

Operation 

N

Ope

13 021 13021 ARKWRIGHT 699 3 0002 3 No 

Operation 

No 

Operation 

N

Ope

13 021 13021 ARKWRIGHT 699 4 0002 4 No 

Operation 

No 

Operation 

N

Ope

13 051 13051 SAVANNAH ELECTRIC: 

KRAFT STEAM 

733 1 05100006 SG01 Coal 

Steam 

None None N

13 051 13051 SAVANNAH ELECTRIC: 

KRAFT STEAM 

733 2 05100006 SG02 Coal 

Steam 

None None N

13 051 13051 SAVANNAH ELECTRIC: 

KRAFT STEAM 

733 3 05100006 SG03 Coal 

Steam 

None None N

13 051 13051 SAVANNAH ELECTRIC: 

KRAFT STEAM 

733 4 05100006 SG04 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

13 051 13051 RIVERSIDE 734 11 05100018 11 O/G 

Steam 

None No 

Operation 

N

13 051 13051 RIVERSIDE 734 12 05100018 12 O/G 

Steam 

None No 

Operation 

N

13 051 13051 RIVERSIDE 734 4 05100018 4 O/G 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

66

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

13 051 13051 RIVERSIDE 734 5 05100018 5 O/G 

Steam 

None No 

Operation 

N

13 051 13051 RIVERSIDE 734 6 05100018 6 O/G 

Steam 

None No 

Operation 

N

13 067 13067 GEORGIA POWER COMPANY, 

MCDONOUGH STEAM 

710 MB1 06700003 SGM1 Coal 

Steam 

Gas Turbine None Gas T

13 067 13067 GEORGIA POWER COMPANY, 

MCDONOUGH STEAM 

710 MB2 06700003 SGM2 Coal 

Steam 

Gas Turbine None Gas T

13 077 13077 GEORGIA POWER COMPANY, 

YATES STEAM-ELECTRIC 

728 Y1BR 07700001 SG01 Coal 

Steam 

None None Scru

13 077 13077 GEORGIA POWER COMPANY, 

YATES STEAM-ELECTRIC 

728 Y2BR 07700001 SG02 Coal 

Steam 

None None N

13 077 13077 GEORGIA POWER COMPANY, 

YATES STEAM-ELECTRIC 

728 Y3BR 07700001 SG03 Coal 

Steam 

None None N

13 077 13077 GEORGIA POWER COMPANY, 

YATES STEAM-ELECTRIC 

728 Y4BR 07700001 SG04 Coal 

Steam 

None None N

13 077 13077 GEORGIA POWER COMPANY, 

YATES STEAM-ELECTRIC 

728 Y5BR 07700001 SG05 Coal 

Steam 

None None N

13 077 13077 GEORGIA POWER COMPANY, 

YATES STEAM-ELECTRIC 

728 Y6BR 07700001 SG06 Coal 

Steam 

None None N

13 077 13077 GEORGIA POWER COMPANY, 

YATES STEAM-ELECTRIC 

728 Y7BR 07700001 SG07 Coal 

Steam 

None None N

13 095 13095 GEORGIA POWER COMPANY, 

MITCHELL STEAM-ELECTRIC 

727 09500002 SG01 No 

Operation 

No 

Operation 

N

Ope

13 095 13095 GEORGIA POWER COMPANY, 

MITCHELL STEAM-ELECTRIC 

727 09500002 SG02 No 

Operation 

No 

Operation 

N

Ope

13 095 13095 GEORGIA POWER COMPANY, 

MITCHELL STEAM-ELECTRIC 

727 3 09500002 SG03 Coal 

Steam 

None None N

13 103 13103 SAVANNAH ELECTRIC: 

MCINTOSH STEAM - ELECTRIC 

6124 1 10300003 SG01 Coal 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

67

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

13 115 13115 GEORGIA POWER COMPANY, 

HAMMOND STEAM-ELECTRIC 

708 1 11500003 SG01 Coal 

Steam 

None None Scrubb

13 115 13115 GEORGIA POWER COMPANY, 

HAMMOND STEAM-ELECTRIC 

708 2 11500003 SG02 Coal 

Steam 

None None Scru

95

13 115 13115 GEORGIA POWER COMPANY, 

HAMMOND STEAM-ELECTRIC 

708 3 11500003 SG03 Coal 

Steam 

None None Scru

95

13 115 13115 GEORGIA POWER COMPANY, 

HAMMOND STEAM-ELECTRIC 

708 4 11500003 SG04 Coal 

Steam 

SCR SCR Scru

95

13 127 13127 GEORGIA POWER COMPANY, 

MCMANUS STEAM-ELECTRIC 

715 1 12700004 SG01 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

13 127 13127 GEORGIA POWER COMPANY, 

MCMANUS STEAM-ELECTRIC 

715 2 12700004 SG02 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

13 149 13149 GEORGIA POWER COMPANY, 

WANSLEY STEAM-ELECTRIC 

6052 1 14900001 SG01 Coal 

Steam 

SCR SCR Scru

95

13 149 13149 GEORGIA POWER COMPANY, 

WANSLEY STEAM-ELECTRIC 

6052 2 14900001 SG02 Coal 

Steam 

SCR SCR Scru

95

13 207 13207 GEORGIA POWER COMPANY, 

SCHERER STEAM-ELECTRIC 

6257 1 20700008 SG01 Coal 

Steam 

None None N

13 207 13207 GEORGIA POWER COMPANY, 

SCHERER STEAM-ELECTRIC 

6257 2 20700008 SG02 Coal 

Steam 

None None N

13 207 13207 GEORGIA POWER COMPANY, 

SCHERER STEAM-ELECTRIC 

6257 3 20700008 SG03 Coal 

Steam 

None None Scru

95

13 207 13207 GEORGIA POWER COMPANY, 

SCHERER STEAM-ELECTRIC 

6257 4 20700008 SG04 Coal 

Steam 

None None N

13 237 13237 GEORGIA POWER COMPANY, 

HARLLEE BRANCH 

709 1 23700008 SG01 Coal 

Steam 

None None N

13 237 13237 GEORGIA POWER COMPANY, 

HARLLEE BRANCH 

709 2 23700008 SG02 Coal 

Steam 

None None N

13 237 13237 GEORGIA POWER COMPANY, 

HARLLEE BRANCH 

709 3 23700008 SG03 Coal 

Steam 

SCR 

82.5% 

None N
Documentation of the 2012 Emission Inventory 

68

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

13 237 13237 GEORGIA POWER COMPANY, 

HARLLEE BRANCH 

709 4 23700008 SG04 Coal 

Steam 

None None N

13 297 13297 GENERIC UNIT 900113 GSC13 ORIS900113 GSC13 Coal 

Steam 

No 

Operation 

None N

Ope

21 015 21015 CINCINNATI GAS & ELECTRIC 

EAST BEND STAT 

6018 2 2101500029 002 Coal 

Steam 

SCR SCR Scru

21 041 21041 KENTUCKY UTILITIES CO 

GHENT GENERATING STATION 

1356 1 2104100010 001 Coal 

Steam 

SCR None Scru

21 041 21041 KENTUCKY UTILITIES CO 

GHENT GENERATING STATION 

1356 2 2104100010 002 Coal 

Steam 

None None Scru

21 041 21041 KENTUCKY UTILITIES CO 

GHENT GENERATING STATION 

1356 3 2104100010 003 Coal 

Steam 

SCR None Scru

21 041 21041 KENTUCKY UTILITIES CO 

GHENT GENERATING STATION 

1356 4 2104100010 004 Coal 

Steam 

SCR None Scru

21 049 21049 EAST KY POWER COOP 

WILLIAM C DALE PLANT 

1385 1 2104900003 001 Coal 

Steam 

None None N

21 049 21049 EAST KY POWER COOP 

WILLIAM C DALE PLANT 

1385 2 2104900003 002 Coal 

Steam 

None None N

21 049 21049 EAST KY POWER COOP 

WILLIAM C DALE PLANT 

1385 3 2104900003 003 Coal 

Steam 

None None N

21 049 21049 EAST KY POWER COOP 

WILLIAM C DALE PLANT 

1385 4 2104900003 004 Coal 

Steam 

None None N

21 059 21059 OWENSBORO MUNICIPAL 

UTIL ELMER SMITH STATION 

1374 1 2105900027 001 Coal 

Steam 

SCR SCR Scru

21 059 21059 OWENSBORO MUNICIPAL 

UTIL ELMER SMITH STATION 

1374 2 2105900027 002 Coal 

Steam 

None None Scru

21 091 21091 WESTERN KY ENERGY CORP 

COLEMAN STATION 

1381 C1 2109100003 001 Coal 

Steam 

None None Scru

21 091 21091 WESTERN KY ENERGY CORP 

COLEMAN STATION 

1381 C2 2109100003 002 Coal 

Steam 

None None Scru
Documentation of the 2012 Emission Inventory 

69

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

21 091 21091 WESTERN KY ENERGY CORP 

COLEMAN STATION 

1381 C3 2109100003 003 Coal 

Steam 

None None Scru

21 091 21091 GENERIC UNIT 900121 GSC21 ORIS900121 GSC21 Coal 

Steam 

SCR SCR Scru

21 101 21101 HENDERSON MUN POW & 

LIGHT 

1372 6 2110100012 002 Coal 

Steam 

None None N

21 101 21101 HENDERSON MUN POW & 

LIGHT 

1372 5 2110100012 5 Coal 

Steam 

None None N

21 111 21111 LOU GAS & ELEC, CANE RUN 1363 4 0126 04 Coal 

Steam 

SCR SCR Scru

21 111 21111 LOU GAS & ELEC, 

CANE RUN 

1363 5 0126 05 Coal 

Steam 

SCR SCR Scru

21 111 21111 LOU GAS & ELEC, 

CANE RUN 

1363 6 0126 06 Coal 

Steam 

SCR SCR Scru

21 111 21111 LOU GAS & ELEC, 

MILL CREEK 

1364 1 0127 01 Coal 

Steam 

None None Scru

21 111 21111 LOU GAS & ELEC, 

MILL CREEK 

1364 2 0127 02 Coal 

Steam 

None None Scru

21 111 21111 LOU GAS & ELEC, 

MILL CREEK 

1364 3 0127 03 Coal 

Steam 

SCR SCR Scru

21 111 21111 LOU GAS & ELEC, 

MILL CREEK 

1364 4 0127 04 Coal 

Steam 

SCR SCR Scru

21 127 21127 KENTUCKY POWER CO 

BIG SANDY PLANT 

1353 BSU1 2112700003 001 Coal 

Steam 

SCR SCR N

21 127 21127 KENTUCKY POWER CO 

BIG SANDY PLANT 

1353 BSU2 2112700003 002 Coal 

Steam 

SCR SCR N

21 145 21145 TVA-ENVIRONMENTAL 

AFFAIRS SHAWNEE PLANT 

1379 1 2114500006 001 Coal 

Steam 

None None N

21 145 21145 TVA-ENVIRONMENTAL 

AFFAIRS SHAWNEE PLANT 

1379 2 2114500006 002 Coal 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

70

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

21 145 21145 TVA-ENVIRONMENTAL 

AFFAIRS SHAWNEE PLANT 

1379 3 2114500006 003 Coal 

Steam 

None None N

21 145 21145 TVA-ENVIRONMENTAL 

AFFAIRS SHAWNEE PLANT 

1379 4 2114500006 004 Coal 

Steam 

None None N

21 145 21145 TVA-ENVIRONMENTAL 

AFFAIRS SHAWNEE PLANT 

1379 5 2114500006 005 Coal 

Steam 

None None N

21 145 21145 TVA-ENVIRONMENTAL 

AFFAIRS SHAWNEE PLANT 

1379 6 2114500006 006 Coal 

Steam 

None None N

21 145 21145 TVA-ENVIRONMENTAL 

AFFAIRS SHAWNEE PLANT 

1379 7 2114500006 007 Coal 

Steam 

None None N

21 145 21145 TVA-ENVIRONMENTAL 

AFFAIRS SHAWNEE PLANT 

1379 8 2114500006 008 Coal 

Steam 

None None N

21 145 21145 TVA-ENVIRONMENTAL 

AFFAIRS SHAWNEE PLANT 

1379 9 2114500006 009 Coal 

Steam 

None None N

21 145 21145 TVA-ENVIRONMENTAL 

AFFAIRS SHAWNEE PLANT 

1379 10 2114500006 016 Coal 

Steam 

None None N

21 161 21161 EAST KY POWER COOP 

SPURLOCK ST. MAYSVILLE 

6041 1 2116100009 001 Coal 

Steam 

SCR SCR Scru

21 161 21161 EAST KY POWER COOP 

SPURLOCK ST. MAYSVILLE 

6041 2 2116100009 002 Coal 

Steam 

SCR SCR Scru

21 167 21167 KENTUCKY UTILITIES CO 

BROWN FACILITY 

1355 1 2116700001 001 Coal 

Steam 

None None Scru

21 167 21167 KENTUCKY UTILITIES CO 

BROWN FACILITY 

1355 2 2116700001 002 Coal 

Steam 

None None Scru

21 167 21167 KENTUCKY UTILITIES CO 

BROWN FACILITY 

1355 3 2116700001 003 Coal 

Steam 

None None Scru

21 177 21177 KENTUCKY UTILITIES CO 

GREEN RIVER STATION 

1357 4 2117700001 003 Coal 

Steam 

None None N

21 177 21177 KENTUCKY UTILITIES CO 

GREEN RIVER STATION 

1357 5 2117700001 004 Coal 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

71

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

21 177 21177 TVA PARADISE STEAM PLANT 1378 1 2117700006 001 Coal 

Steam 

SCR SCR Scru

21 177 21177 TVA PARADISE STEAM PLANT 1378 2 2117700006 002 Coal 

Steam 

SCR SCR Scru

21 177 21177 TVA PARADISE STEAM PLANT 1378 3 2117700006 003 Coal 

Steam 

SCR SCR Scru

21 183 21183 WESTERN KY ENERGY CORP 

WILSON STATION 

6823 W1 2118300069 001 Coal 

Steam 

SCR SCR Scru

21 199 21199 EAST KY POWER COOP 

JOHN SHERMAN COOPER 

1384 1 2119900005 001 Coal 

Steam 

None None N

21 199 21199 EAST KY POWER COOP 

JOHN SHERMAN COOPER 

1384 2 2119900005 002 Coal 

Steam 

SCR SCR Scru

21 223 21223 LOUISVILLE GAS & ELECTRIC 

TRIMBLE CO GEN 

6071 1 2122300002 001 Coal 

Steam 

SCR SCR Scru

21 233 21233 HENDERSON STATION 2 1382 H1 2123300001-

A 

002 Coal 

Steam 

SCR SCR Scru

21 233 21233 HENDERSON STATION 2 1382 H2 2123300001-

A 

003 Coal 

Steam 

SCR None Scru

21 233 21233 WESTERN KY ENERGY CORP 

REID 

1383 R1 2123300001-

B 

001 Coal 

Steam 

None None N

21 233 21233 WESTERN KY ENERGY CORP 

GREEN STATION 

6639 G1 2123300052 001 Coal 

Steam 

None None Scru

21 233 21233 WESTERN KY ENERGY CORP 

GREEN STATION 

6639 G2 2123300052 002 Coal 

Steam 

None None Scru

21 239 21239 KENTUCKY UTILITIES 

TYRONE FACILITY 

1361 5 2123900001 005 Coal 

Steam 

None None N

28 011 28011 ENTERGY MISSISSIPPI INC, 

DELTA PLANT 

2051 1 2801100031 001 O/G 

Steam 

None O/G Early 

Retirement 

N

28 011 28011 ENTERGY MISSISSIPPI INC, 

DELTA PLANT 

2051 2801100031 002 None O/G Early 

Retirement 

N
Documentation of the 2012 Emission Inventory 

72

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

28 011 28011 ENTERGY MISSISSIPPI INC, 

DELTA PLANT 

2051 2 2801100031 003 O/G 

Steam 

None O/G Early 

Retirement 

N

28 011 28011 ENTERGY MISSISSIPPI INC, 

DELTA PLANT 

2051 2801100031 004 None O/G Early 

Retirement 

N

28 019 28019 CHOCTAW GENERATION LLP, 

RED HILLS GENERATING 

55076 AA001 2801900011 001A Coal 

Steam 

SCR SCR Scru

28 035 28035 MISSISSIPPI POWER 

COMPANY, PLANT EATON 

2046 2803500038 001 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 035 28035 MISSISSIPPI POWER 

COMPANY, PLANT EATON 

2046 2803500038 002 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 035 28035 MISSISSIPPI POWER 

COMPANY, PLANT EATON 

2046 2803500038 003 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 047 28047 MISSISSIPPI POWER 

COMPANY, PLANT JACK WATSON 

2049 1 2804700055 001 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 047 28047 MISSISSIPPI POWER 

COMPANY, PLANT JACK WATSON 

2049 2 2804700055 002 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 047 28047 MISSISSIPPI POWER 

COMPANY, PLANT JACK WATSON 

2049 3 2804700055 003 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 047 28047 MISSISSIPPI POWER 

COMPANY, PLANT JACK WATSON 

2049 4 2804700055 004 Coal 

Steam 

None SCR N

28 047 28047 MISSISSIPPI POWER 

COMPANY, PLANT JACK WATSON 

2049 5 2804700055 005 Coal 

Steam 

None SCR N

28 049 28049 ENTERGY MISSISSIPPI INC, 

REX BROWN PLANT 

2053 4 2804900112 001 O/G 

Steam 

None O/G Early 

Retirement 

N

28 049 28049 ENTERGY MISSISSIPPI INC, 

REX BROWN PLANT 

2053 3 2804900112 002 O/G 

Steam 

None O/G Early 

Retirement 

N

28 059 28059 MISSISSIPPI POWER 

COMPANY, PLANT DANIEL 

6073 1 2805900090 001 Coal 

Steam 

None SCR N

28 059 28059 MISSISSIPPI POWER 

COMPANY, 

6073 2 2805900090 002 Coal 

Steam 

None SCR N
Documentation of the 2012 Emission Inventory 

73

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

PLANT DANIEL 

28 067 28067 MOSELLE SOUTH MISSISSIPPI 

ELECTRIC POWER ASSOCIATION 

2070 1 2806700035 001 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 067 28067 MOSELLE SOUTH MISSISSIPPI 

ELECTRIC POWER ASSOCIATION 

2070 2 2806700035 002 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 067 28067 MOSELLE SOUTH MISSISSIPPI 

ELECTRIC POWER ASSOCIATION 

2070 3 2806700035 003 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 073 28073 RD MORROW SOUTH 

MISSISSIPPI ELECTRIC POWER ASSOCIATION 

6061 1 2807300021 001 Coal 

Steam 

None SCR Scru

28 073 28073 RD MORROW SOUTH 

MISSISSIPPI ELECTRIC POWER ASSOCIATION 

6061 2 2807300021 002 Coal 

Steam 

None SCR Scru

28 075 28075 MISSISSIPPI POWER 

COMPANY, PLANT SWEATT 

2048 1 2807500032 001 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 075 28075 MISSISSIPPI POWER 

COMPANY, PLANT SWEATT 

2048 2 2807500032 002 O/G 

Steam 

No 

Operation 

No 

Operation 

N

Ope

28 083 28083 GREENWOOD UTILITIES, 

HENDERSON STATION 

2062 H1 2808300048 001 O/G 

Steam 

None None N

28 083 28083 GREENWOOD UTILITIES, 

HENDERSON STATION 

2062 H3 2808300048 003 O/G 

Steam 

None None N

28 149 28149 ENTERGY MISSISSIPPI INC, 

BAXTER WILSON 

2050 1 2814900027 001 O/G 

Steam 

None O/G Early 

Retirement 

N

28 149 28149 ENTERGY MISSISSIPPI INC, 

BAXTER WILSON 

2050 2 2814900027 002 O/G 

Steam 

None O/G Early 

Retirement 

N

28 151 28151 ENTERGY MISSISSIPPI INC, 

GERALD ANDRUS 

8054 1 2815100048 001 O/G 

Steam 

None No 

Operation 

N

28 163 28163 YAZOO CITY PUBLIC SERVICE 

COMMISSION 

2067 3 2816300005 001 O/G 

Steam 

O/G Early 

Retirement 

O/G Early 

Retirement 

O/G 

Retir

37 017 37017 ELIZABETHTOWN POWER, 

LLC 

10380 UNIT1 3701700043 G-17A Coal 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

74

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

37 017 37017 ELIZABETHTOWN POWER, 

LLC 

10380 UNIT2 3701700043 G-17B None None N

37 019 37019 COGENTRIX OF NORTH 

CAROLINA INC - SOUTHPORT 

10378 GEN1 3701900067 G-29 Coal 

Steam 

None None N

37 019 37019 COGENTRIX OF NORTH 

CAROLINA INC - SOUTHPORT 

10378 GEN2 3701900067 G-30 Coal 

Steam 

None None N

37 021 37021 CAROLINA POWER & LIGHT 

ASHEVILLE STEAM 

2706 1 628 1 Coal 

Steam 

SCR SCR Scru

37 021 37021 CAROLINA POWER & LIGHT 

ASHEVILLE STEAM 

2706 2 628 2 Coal 

Steam 

SCR SCR Scru

37 025 37025 KANNAPOLIS ENERGY 

PARTNERS LLC 

 3702500113 G-2 Coal 

Steam 

None None N

37 025 37025 KANNAPOLIS ENERGY 

PARTNERS LLC 

 3702500113 G-3 Coal 

Steam 

None None N

37 035 37035 DUKE ENERGY 

CORPORATION MARSHALL STEAM 

2727 3 3703500073 G-1 Coal 

Steam 

SNCR SCR Scru

37 035 37035 DUKE ENERGY 

CORPORATION MARSHALL STEAM 

2727 4 3703500073 G-2 Coal 

Steam 

SNCR SCR Scru

37 035 37035 DUKE ENERGY 

CORPORATION MARSHALL STEAM 

2727 1 3703500073 G-4 Coal 

Steam 

SNCR SCR Scru

37 035 37035 DUKE ENERGY 

CORPORATION MARSHALL STEAM 

2727 2 3703500073 G-5 Coal 

Steam 

SNCR SCR Scru

37 037 37037 PROGRESS ENERGY 

CAROLINAS CAPE FEAR 

2708 5 3703700063 G-1 Coal 

Steam 

SNCR SNCR N

37 037 37037 PROGRESS ENERGY 

CAROLINAS CAPE FEAR 

2708 6 3703700063 G-2 Coal 

Steam 

SNCR SNCR N

37 045 37045 GENERIC UNIT 900137 GSC37 ORIS900137 GSC37 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

37 055 37055 GENERIC UNIT 900237 GSC37 ORIS900237 GSC37 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope
Documentation of the 2012 Emission Inventory 

75

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

37 055 37055 GENERIC UNIT 900337 GSC37 ORIS900337 GSC37 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

37 061 37061 GENERIC UNIT 900437 GSC37 ORIS900437 GSC37 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

37 083 37083 GENERIC UNIT 900537 GSC37 ORIS900537 GSC37 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

37 083 37083 GENERIC UNIT 900637 GSC37 ORIS900637 GSC37 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

37 071 37071 DUKE ENERGY 

CORPORATION ALLEN STEAM 

2718 1 3707100039 G-14 Coal 

Steam 

SNCR SNCR Scru

37 071 37071 DUKE ENERGY 

CORPORATION ALLEN STEAM 

2718 2 3707100039 G-15 Coal 

Steam 

SNCR SNCR Scru

37 071 37071 DUKE ENERGY 

CORPORATION ALLEN STEAM 

2718 3 3707100039 G-16 Coal 

Steam 

SNCR SCR Scru

37 071 37071 DUKE ENERGY 

CORPORATION ALLEN STEAM 

2718 4 3707100039 G-17 Coal 

Steam 

SNCR SCR Scru

37 071 37071 DUKE ENERGY 

CORPORATION ALLEN STEAM 

2718 5 3707100039 G-18 Coal 

Steam 

SNCR SCR Scru

37 071 37071 DUKE ENERGY 

CORPORATION RIVERBEND STEAM 

2732 7 3707100040 G-17 Coal 

Steam 

SNCR SNCR N

37 071 37071 DUKE ENERGY 

CORPORATION RIVERBEND STEAM 

2732 8 3707100040 G-18 Coal 

Steam 

SNCR SNCR N

37 071 37071 DUKE ENERGY 

CORPORATION RIVERBEND STEAM 

2732 9 3707100040 G-19 Coal 

Steam 

SNCR SNCR N

37 071 37071 DUKE ENERGY 

CORPORATION RIVERBEND STEAM 

2732 10 3707100040 G-20 Coal 

Steam 

SNCR SNCR N

37 083 37083 ROANOKE VALLEY ENERGY 

FACILITY 

 3708300174 G-27 Coal 

Steam 

None None N

37 083 37083 ROANOKE VALLEY ENERGY 

FACILITY 

 3708300174 G-7 Coal 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

76

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

37 129 37129 L V SUTTON STEAM 

ELECTRIC PLANT 

2713 1 3712900036 G-187 Coal 

Steam 

None SNCR N

37 129 37129 L V SUTTON STEAM 

ELECTRIC PLANT 

2713 2 3712900036 G-188 Coal 

Steam 

None SCR N

37 129 37129 L V SUTTON STEAM 

ELECTRIC PLANT 

2713 3 3712900036 G-189 Coal 

Steam 

None SCR N

37 145 37145 CP&L - ROXBORO STEAM 

ELECTRIC PLANT 

2712 1 3714500029 G-29 Coal 

Steam 

SCR SCR Scru

37 145 37145 CP&L - ROXBORO STEAM 

ELECTRIC PLANT 

2712 2 3714500029 G-30 Coal 

Steam 

SCR SCR Scru

37 145 37145 CP&L - ROXBORO STEAM 

ELECTRIC PLANT 

2712 3A 3714500029 G-35A Coal 

Steam 

SCR SCR Scru

37 145 37145 CP&L - ROXBORO STEAM 

ELECTRIC PLANT 

2712 3B 3714500029 G-35B Coal 

Steam 

SCR SCR Scru

37 145 37145 CP&L - ROXBORO STEAM 

ELECTRIC PLANT 

2712 4A 3714500029 G-36A Coal 

Steam 

SCR SCR Scru

37 145 37145 CP&L - ROXBORO STEAM 

ELECTRIC PLANT 

2712 4B 3714500029 G-36B Coal 

Steam 

SCR SCR Scru

37 145 37145 CP&L - MAYO FACILITY 6250 1A 3714500045 G-46A Coal 

Steam 

SCR SCR Scru

37 145 37145 CP&L - MAYO FACILITY 6250 1B 3714500045 G-46B Coal 

Steam 

SCR SCR Scru

37 155 37155 PROGRESS ENERGY 

CAROLINAS, INC., W.H. WEATHERSPOON 

2716 1 3715500147 G-24 Coal 

Steam 

None SNCR N

37 155 37155 PROGRESS ENERGY 

CAROLINAS, INC., W.H. WEATHERSPOON 

2716 2 3715500147 G-25 Coal 

Steam 

None SNCR N

37 155 37155 PROGRESS ENERGY 

CAROLINAS, INC., W.H. WEATHERSPOON 

2716 3 3715500147 G-26 Coal 

Steam 

None SNCR N

37 155 37155 LUMBERTON POWER, LLC 10382 UNIT1 3715500166 G-17A Coal 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

77

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

37 155 37155 LUMBERTON POWER, LLC 10382 UNIT2 3715500166 G-17B None None N37 157 37157 DUKE ENERGY CORP 

DAN RIVER STEAM 

2723 3 3715700015 G-21 Coal 

Steam 

None SNCR N

37 157 37157 DUKE ENERGY CORP 

DAN RIVER STEAM 

2723 1 3715700015 G-22 Coal 

Steam 

None SNCR N

37 157 37157 DUKE ENERGY CORPDAN 

RIVER STEAM 

2723 2 3715700015 G-23 Coal 

Steam 

None SNCR N

37 159 37159 DUKE ENERGY 

CORPORATION BUCK STEAM 

2720 5 3715900004 G-1 Coal 

Steam 

No 

Operation 

SNCR N

Ope

37 159 37159 DUKE ENERGY 

CORPORATION BUCK STEAM 

2720 6 3715900004 G-2 Coal 

Steam 

No 

Operation 

SNCR N

Ope

37 159 37159 DUKE ENERGY 

CORPORATION BUCK STEAM 

2720 7 3715900004 G-3 Coal 

Steam 

No 

Operation 

SNCR N

Ope

37 159 37159 DUKE ENERGY 

CORPORATION BUCK STEAM 

2720 8 3715900004 G-4 Coal 

Steam 

SNCR SNCR N

37 159 37159 DUKE ENERGY 

CORPORATION BUCK STEAM 

2720 9 3715900004 G-5 Coal 

Steam 

SNCR SNCR N

37 161 37161 DUKE ENERGY 

CORPORATION CLIFFSIDE STEAM 

2721 1 3716100028 G-82 Coal 

Steam 

No 

Operation 

SNCR N

Ope

37 161 37161 DUKE ENERGY 

CORPORATION CLIFFSIDE STEAM 

2721 2 3716100028 G-83 Coal 

Steam 

No 

Operation 

SNCR N

Ope

37 161 37161 DUKE ENERGY 

CORPORATION CLIFFSIDE STEAM 

2721 3 3716100028 G-84 Coal 

Steam 

No 

Operation 

SNCR N

Ope

37 161 37161 DUKE ENERGY 

CORPORATION CLIFFSIDE STEAM 

2721 4 3716100028 G-85 Coal 

Steam 

No 

Operation 

SNCR N

Ope

37 161 37161 DUKE ENERGY 

CORPORATION CLIFFSIDE STEAM 

2721 5 3716100028 G-86 Coal 

Steam 

SCR SCR Scru
Documentation of the 2012 Emission Inventory 

78

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

37 161 37161 DUKE ENERGY 

CORPORATION CLIFFSIDE STEAM 

2721 6 3716100028 G-87 Coal 

Steam 

SCR No 

Operation 

Scru

37 161 37161 DUKE ENERGY 

CORPORATION CLIFFSIDE STEAM 

2721 7 3716100028 G-88 No 

Operation 

No 

Operation 

N

Ope

37 169 37169 DUKE ENERGY CORP 

BELEWS CREEK STEAM 

8042 1 3716900004 G-17 Coal 

Steam 

SCR SCR Scru

37 169 37169 DUKE ENERGY CORP 

BELEWS CREEK STEAM 

8042 2 3716900004 G-18 Coal 

Steam 

SCR SCR Scru

37 191 37191 PROGRESS ENERGY 

F LEE PLANT 

2709 1 3719100017 G-2 Coal 

Steam 

None SNCR N

37 191 37191 PROGRESS ENERGY 

F LEE PLANT 

2709 2 3719100017 G-3 Coal 

Steam 

None SNCR N

37 191 37191 PROGRESS ENERGYF LEE 

PLANT 

2709 3 3719100017 G-4 Coal 

Steam 

None SCR N

45 003 45003 SCE&G:URQUHART 3295 URQ3 0080-0011 003 Coal 

Steam 

None None N

45 003 45003 SCE&G:SRS AREA D 0080-0044 001 Coal 

Steam 

None None N

45 003 45003 SCE&G:SRS AREA D 0080-0044 002 0 0 45 003 45003 SCE&G:SRS AREA D 0080-0044 003 0 0 45 003 45003 SCE&G:SRS AREA D 0080-0044 004 0 0 45 007 45007 DUKE ENERGY:LEE 3264 1 0200-0004 001 Coal 

Steam 

None None N

45 007 45007 DUKE ENERGY:LEE 3264 2 0200-0004 002 Coal 

Steam 

None None N

45 007 45007 DUKE ENERGY:LEE 3264 3 0200-0004 003 Coal 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

79

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

45 015 45015 SANTEE COOPER JEFFERIES 3319 1 0420-0003 001 O/G 

Steam 

None No 

Operation 

N

45 015 45015 SANTEE COOPER JEFFERIES 3319 2 0420-0003 002 O/G 

Steam 

None No 

Operation 

N

45 015 45015 SANTEE COOPER JEFFERIES 3319 3 0420-0003 003 Coal 

Steam 

None SCR N

45 015 45015 SANTEE COOPER JEFFERIES 3319 4 0420-0003 004 Coal 

Steam 

None None N

45 015 45015 SCE&G:WILLIAMS 3298 WIL1 0420-0006 001 Coal 

Steam 

SCR SCR Scru

45 015 45015 SANTEE COOPER CROSS 130 1 0420-0030 001 Coal 

Steam 

SCR SCR Scru

Upg

45 015 45015 SANTEE COOPER CROSS 130 2 0420-0030 002 Coal 

Steam 

SCR SCR Scru

Upg

45 015 45015 SANTEE COOPER CROSS 130 3 0420-0030 3 Coal 

Steam 

SCR SCR Scru

45 015 45015 SANTEE COOPER CROSS 130 4 0420-0030 4 Coal 

Steam 

SCR No 

Operation 

Scru

45 029 45029 SCE&G:CANADYS 3280 CAN1 0740-0002 001 Coal 

Steam 

None None N

45 029 45029 SCE&G:CANADYS 3280 CAN2 0740-0002 002 Coal 

Steam 

None None N

45 029 45029 SCE&G:CANADYS 3280 CAN3 0740-0002 003 Coal 

Steam 

None None Scru

45 031 45031 PROGRESS ENERGY 

ROBINSON STATION 

3251 1 0820-0002 001 Coal 

Steam 

None None N

45 043 45043 SANTEE COOPER WINYAH 6249 1 1140-0005 001 Coal 

Steam 

SCR SCR Scru

45 043 45043 SANTEE COOPER WINYAH 6249 2 1140-0005 002 Coal 

Steam 

SCR SCR Scru
Documentation of the 2012 Emission Inventory 

80

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

45 043 45043 SANTEE COOPER WINYAH 6249 3 1140-0005 003 Coal 

Steam 

SCR SCR Scru

Upg

45 043 45043 SANTEE COOPER WINYAH 6249 4 1140-0005 004 Coal 

Steam 

SCR SCR Scru

Upg

45 051 45051 SANTEE COOPER GRAINGER 3317 1 1340-0003 001 Coal 

Steam 

None None N

45 051 45051 SANTEE COOPER GRAINGER 3317 2 1340-0003 002 Coal 

Steam 

None None N

45 063 45063 SCE&G:MCMEEKIN 3287 MCM1 1560-0003 001 Coal 

Steam 

None None N

45 063 45063 SCE&G:MCMEEKIN 3287 MCM2 1560-0003 002 Coal 

Steam 

None None N

45 075 45075 SCE&G:COPE 7210 COP1 1860-0044 001 Coal 

Steam 

None None Scru

45 079 45079 SCE&G:WATEREE 3297 WAT1 1900-0013 001 Coal 

Steam 

SCR SCR Scru

45 079 45079 SCE&G:WATEREE 3297 WAT2 1900-0013 002 Coal 

Steam 

SCR SCR Scru

45 029 45029 GENERIC UNIT 900145 GSC45 ORIS900145 GSC45 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

45 031 45031 GENERIC UNIT 900245 GSC45 ORIS900245 GSC45 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

45 031 45031 GENERIC UNIT 900345 GSC45 ORIS900345 GSC45 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

45 039 45039 GENERIC UNIT 900445 GSC45 ORIS900445 GSC45 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

45 043 45043 GENERIC UNIT 900545 GSC45 ORIS900545 GSC45 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

47 001 47001 TVA BULL RUN FOSSIL PLANT 3396 1 0009 001 Coal 

Steam 

SCR SCR Scru
Documentation of the 2012 Emission Inventory 

81

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

47 073 47073 TVA JOHN SEVIER FOSSIL 

PLANT 

3405 1 0007 001 Coal 

Steam 

None None N

47 073 47073 TVA JOHN SEVIER FOSSIL 

PLANT 

3405 2 0007 002 Coal 

Steam 

None None N

47 073 47073 TVA JOHN SEVIER FOSSIL 

PLANT 

3405 3 0007 003 Coal 

Steam 

None None N

47 073 47073 TVA JOHN SEVIER FOSSIL 

PLANT 

3405 4 0007 004 Coal 

Steam 

None None N

47 085 47085 TVA JOHNSONVILLE FOSSIL 

PLANT 

3406 1 0011 001 Coal 

Steam 

None SCR N

47 085 47085 TVA JOHNSONVILLE FOSSIL 

PLANT 

3406 2 0011 002 Coal 

Steam 

None SCR N

47 085 47085 TVA JOHNSONVILLE FOSSIL 

PLANT 

3406 3 0011 003 Coal 

Steam 

None SCR N

47 085 47085 TVA JOHNSONVILLE FOSSIL 

PLANT 

3406 4 0011 004 Coal 

Steam 

None SCR N

47 085 47085 TVA JOHNSONVILLE FOSSIL 

PLANT 

3406 5 0011 005 Coal 

Steam 

None SCR N

47 085 47085 TVA JOHNSONVILLE FOSSIL 

PLANT 

3406 6 0011 006 Coal 

Steam 

None SCR N

47 085 47085 TVA JOHNSONVILLE FOSSIL 

PLANT 

3406 7 0011 007 Coal 

Steam 

None SCR N

47 085 47085 TVA JOHNSONVILLE FOSSIL 

PLANT 

3406 8 0011 008 Coal 

Steam 

None SCR N

47 085 47085 TVA JOHNSONVILLE FOSSIL 

PLANT 

3406 9 0011 009 Coal 

Steam 

None SCR N

47 085 47085 TVA JOHNSONVILLE FOSSIL 

PLANT 

3406 10 0011 010 Coal 

Steam 

None SCR N

47 145 47145 TVA KINGSTON FOSSIL 

PLANT 

3407 1 0013 001 Coal 

Steam 

SCR SCR Scru
Documentation of the 2012 Emission Inventory 

82

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

47 145 47145 TVA KINGSTON FOSSIL 

PLANT 

3407 2 0013 002 Coal 

Steam 

SCR SCR Scru

47 145 47145 TVA KINGSTON FOSSIL 

PLANT 

3407 3 0013 003 Coal 

Steam 

SCR SCR Scru

47 145 47145 TVA KINGSTON FOSSIL 

PLANT 

3407 4 0013 004 Coal 

Steam 

SCR SCR Scru

47 145 47145 TVA KINGSTON FOSSIL 

PLANT 

3407 5 0013 005 Coal 

Steam 

SCR SCR Scru

47 145 47145 TVA KINGSTON FOSSIL 

PLANT 

3407 6 0013 006 Coal 

Steam 

SCR SCR Scru

47 145 47145 TVA KINGSTON FOSSIL 

PLANT 

3407 7 0013 007 Coal 

Steam 

SCR SCR Scru

47 145 47145 TVA KINGSTON FOSSIL 

PLANT 

3407 8 0013 008 Coal 

Steam 

SCR SCR Scru

47 145 47145 TVA KINGSTON FOSSIL 

PLANT 

3407 9 0013 009 Coal 

Steam 

SCR None Scru

47 157 47157 ALLEN FOSSIL PLANT 3393 1 00528 Boilr1 Coal 

Steam 

SCR SCR N

47 157 47157 ALLEN FOSSIL PLANT 3393 2 00528 Boilr2 Coal 

Steam 

SCR SCR N

47 157 47157 ALLEN FOSSIL PLANT 3393 3 00528 Boilr3 Coal 

Steam 

SCR SCR N

47 161 47161 TVA CUMBERLAND FOSSIL 

PLANT 

3399 1 0011 001 Coal 

Steam 

SCR SCR Scru

47 161 47161 TVA CUMBERLAND FOSSIL 

PLANT 

3399 2 0011 002 Coal 

Steam 

SCR SCR Scru

47 165 47165 TVA GALLATIN FOSSIL 

PLANT 

3403 1 0025 001 Coal 

Steam 

None None N

47 165 47165 TVA GALLATIN FOSSIL 

PLANT 

3403 2 0025 002 Coal 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

83

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

47 165 47165 TVA GALLATIN FOSSIL 

PLANT 

3403 3 0025 003 Coal 

Steam 

None None N

47 165 47165 TVA GALLATIN FOSSIL 

PLANT 

3403 4 0025 004 Coal 

Steam 

None None N

51 031 51031 DOMINION - ALTAVISTA 

POWER STATION 

10773 1 00156 1 Coal 

Steam 

SNCR SNCR Scru

51 031 51031 DOMINION - ALTAVISTA 

POWER STATION 

10773 2 00156 2 

51 041 51041 DOMINION - CHESTERFIELD 

POWER STATION 

3797 3 00002 3 Coal 

Steam 

None None Scru

51 041 51041 DOMINION - CHESTERFIELD 

POWER STATION 

3797 4 00002 4 Coal 

Steam 

SCR None Scru

51 041 51041 DOMINION - CHESTERFIELD 

POWER STATION 

3797 5 00002 6 Coal 

Steam 

SCR SCR Scru

51 041 51041 DOMINION - CHESTERFIELD 

POWER STATION 

3797 6 00002 8 Coal 

Steam 

SCR SCR Scru

51 065 51065 DOMINION - BREMO POWER 

STATION 

3796 3 00001 1 Coal 

Steam 

None None N

51 065 51065 DOMINION - BREMO POWER 

STATION 

3796 4 00001 2 Coal 

Steam 

SNCR SNCR N

51 071 51071 AMERICAN ELECTRIC POWER 

GLEN LYN 

3776 51 00002 1 Coal 

Steam 

None None N

51 071 51071 AMERICAN ELECTRIC POWER 

GLEN LYN 

3776 52 00002 2 Coal 

Steam 

None None N

51 071 51071 AMERICAN ELECTRIC POWER 

GLEN LYN 

3776 6 00002 3 Coal 

Steam 

None None N

51 083 51083 DOMINION - CLOVER POWER 

STATION 

7213 1 00046 1 Coal 

Steam 

SNCR SNCR Scru

51 083 51083 DOMINION - CLOVER POWER 

STATION 

7213 2 00046 2 Coal 

Steam 

SNCR SNCR Scru
Documentation of the 2012 Emission Inventory 

84

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

51 099 51099 BIRCHWOOD POWER 

PARTNERS, L.P. 

54304 1 00012 1 Coal 

Steam 

SCR SCR Scru

51 117 51117 Mecklenburg Cogeneration Facility 52007 GEN1 00051 1 Coal 

Steam 

None None Scru

51 117 51117 Mecklenburg Cogeneration Facility 52007 GEN2 00051 2 Coal 

Steam 

None None Scru

51 153 51153 DOMINION - POSSUM POINT 3804 3 00002 3 Coal 

Steam 

None Combined 

Cycle 

N

51 153 51153 DOMINION - POSSUM POINT 3804 4 00002 4 Coal 

Steam 

None Combined 

Cycle 

N

51 153 51153 DOMINION - POSSUM POINT 3804 5 00002 5 O/G 

Steam 

None No 

Operation 

N

51 153 51153 DOMINION - POSSUM POINT 3804 6 00002 Combined 

Cycle 

Combined 

Cycle 

Combined 

Cycle 

Com

Cy

51 167 51167 AMERICAN ELECTRIC POWER

CLINCH RIVER PLANT 

3775 1 00003 1 Coal 

Steam 

None None N

51 167 51167 AMERICAN ELECTRIC POWER

CLINCH RIVER PLANT 

3775 2 00003 2 Coal 

Steam 

None None N

51 167 51167 AMERICAN ELECTRIC POWER

CLINCH RIVER PLANT 

3775 3 00003 3 Coal 

Steam 

None None N

51 175 51175 LG&E Westmoreland Southampton 10774 GEN1 00051 1 Coal 

Steam 

None None Scru

51 199 51199 DOMINION - YORKTOWN 

POWER STATION 

3809 3 00001 3 O/G 

Steam 

SNCR No 

Operation 

N

51 199 51199 DOMINION - YORKTOWN 

POWER STATION 

3809 2 00001 5 Coal 

Steam 

SNCR SNCR N

51 199 51199 DOMINION - YORKTOWN 

POWER STATION 

3809 1 00001 6 Coal 

Steam 

SNCR SNCR N

51 510 51510 POTOMAC RIVER 

GENERATING STATION 

3788 1 00003 1 Coal 

Steam 

SNCR Coal Early 

Retirement 

N
Documentation of the 2012 Emission Inventory 

85

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

51 510 51510 POTOMAC RIVER 

GENERATING STATION 

3788 2 00003 2 Coal 

Steam 

SNCR Coal Early 

Retirement 

N

51 510 51510 POTOMAC RIVER 

GENERATING STATION 

3788 3 00003 3 Coal 

Steam 

SNCR None N

51 510 51510 POTOMAC RIVER 

GENERATING STATION 

3788 4 00003 4 Coal 

Steam 

SNCR None N

51 510 51510 POTOMAC RIVER 

GENERATING STATION 

3788 5 00003 5 Coal 

Steam 

SNCR None N

51 550 51550 DOMINION - CHESAPEAKE 3803 1 00026 1 Coal 

Steam 

SNCR SNCR Low 

51 550 51550 DOMINION - CHESAPEAKE 3803 2 00026 2 Coal 

Steam 

SNCR SNCR Low 

51 550 51550 DOMINION - CHESAPEAKE 3803 3 00026 3 Coal 

Steam 

SCR None Low 

51 550 51550 DOMINION - CHESAPEAKE 3803 4 00026 4 Coal 

Steam 

SCR None Low 

51 670 51670 James River Cogen / 

Cogentrix Hopewell 

10377 GEN1 00055/ 

ORIS10377 

1 Coal 

Steam 

None None Scru

51 670 51670 James River Cogen / 

Cogentrix Hopewell 

10377 GEN2 00055/ 

ORIS10377 

2 Coal 

Steam 

None None Scru

51 670 51670 LG&E Westmoreland Hopewell 10771 GEN1 ORIS10771 1 Coal 

Steam 

SNCR SNCR Scru

51 740 51740 Cogentrix Portsmouth 10071 GEN1 00081 / 

ORIS10071 

1 to 3 Coal 

Steam 

None None Scru

51 740 51740 Cogentrix Portsmouth 10071 GEN2 00081 / 

ORIS10071 

4 to 6 Coal 

Steam 

None None Scru

51 760 51740 Cogentrix of Richmond 

Incorporated 

54081 GEN1 00399 / 

ORIS54081 

1 Coal 

Steam 

None None Scru

51 760 51760 Cogentrix of Richmond 

Incorporated 

54081 GEN2 00399 / 

ORIS54081 

2 Coal 

Steam 

None None Scru
Documentation of the 2012 Emission Inventory 

86

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

51 760 51760 Cogentrix of Richmond 

Incorporated 

54081 GEN3 00399 / 

ORIS54081 

3 Coal 

Steam 

None None Scru

51 760 51760 Cogentrix of Richmond 

Incorporated 

54081 GEN4 00399 / 

ORIS54081 

4 Coal 

Steam 

None None Scru

51 159 51159 GENERIC UNIT 900151 GSC51 ORIS900151 GSC51 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

51 167 51167 GENERIC UNIT 900251 GSC51 ORIS900251 GSC51 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

51 195 51195 GENERIC UNIT 900251 GSC51 ORIS900251 GSC51 Coal 

Steam 

SCR No 

Operation 

Scru

51 175 51175 GENERIC UNIT 900351 GSC51 ORIS900351 GSC51 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

51 175 51175 GENERIC UNIT 900451 GSC51 ORIS900451 GSC51 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

51 181 51181 GENERIC UNIT 900551 GSC51 ORIS900551 GSC51 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

54 023 54023 MOUNT STORM POWER 

PLANT 

3954 1 0003 001 Coal 

Steam 

SCR SCR Scru

54 023 54023 MOUNT STORM POWER 

PLANT 

3954 2 0003 002 Coal 

Steam 

SCR SCR Scru

54 023 54023 MOUNT STORM POWER 

PLANT 

3954 3 0003 003 Coal 

Steam 

SCR SCR Scru

54 023 54023 NORTH BRANCH POWER 

STATION 

7537 1A 0014 001 Coal 

Steam 

None None N

54 023 54023 NORTH BRANCH POWER 

STATION 

7537 1B 0014 002 Coal 

Steam 

None None N

54 025 54025 WESTERN GREENBRIER 00066 GEN1 Coal 

Steam 

No 

Operation 

No 

Operation 

N

Ope

54 033 54033 MONONGAHELA POWER CO 

HARRISON 

3944 1 0015 001 Coal 

Steam 

SCR SCR Scru
Documentation of the 2012 Emission Inventory 

87

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

54 033 54033 MONONGAHELA POWER CO 

HARRISON 

3944 2 0015 002 Coal 

Steam 

SCR SCR Scru

54 033 54033 MONONGAHELA POWER CO 

HARRISON 

3944 3 0015 003 Coal 

Steam 

SCR SCR Scru

54 039 54039 APPALACHIAN POWER 

KANAWHA RIVER PLANT 

3936 1 0006 001 Coal 

Steam 

None None N

54 039 54039 APPALACHIAN POWER 

KANAWHA RIVER PLANT 

3936 2 0006 002 Coal 

Steam 

None None N

54 049 54049 MONONGAHELA POWER CO. 

RIVESVILLE POWER 

3945 7 0009 001 Coal 

Steam 

None Coal Early 

Retirement 

N

54 049 54049 MONONGAHELA POWER 

CO.RIVESVILLE POWER 

3945 8 0009 002 Coal 

Steam 

None Coal Early 

Retirement 

N

54 049 54049 AMERICAN BITUMINOUS 

POWER GRANT TOWN PLT 

10151 0026 001 0 0 Scru

54 049 54049 GRANT TOWN POWER PLANT 10151 GEN1 ORIS10151 GEN1 Coal 

Steam 

SNCR None Scru

54 051 54051 OHIO POWER 

MITCHELL PLANT 

3948 1 0005 001 Coal 

Steam 

SCR SCR Scru

54 051 54051 OHIO POWER 

MITCHELL PLANT 

3948 2 0005 002 Coal 

Steam 

SCR SCR Scru

54 051 54051 OHIO POWER 

KAMMER PLANT 

3947 1 0006 001 Coal 

Steam 

None SCR N

54 051 54051 OHIO POWER 

KAMMER PLANT 

3947 2 0006 002 Coal 

Steam 

None SCR N

54 051 54051 OHIO POWER 

KAMMER PLANT 

3947 3 0006 003 Coal 

Steam 

None SCR N

54 053 54053 APPALACHIAN POWER CO. 

PHILIP SPORN PLANT 

3938 11 0001 001 Coal 

Steam 

None None N

54 053 54053 APPALACHIAN POWER CO. 

PHILIP SPORN PLANT 

3938 21 0001 002 Coal 

Steam 

None None N
Documentation of the 2012 Emission Inventory 

88

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

54 053 54053 APPALACHIAN POWER CO. 

PHILIP SPORN PLANT 

3938 31 0001 003 Coal 

Steam 

None None N

54 053 54053 APPALACHIAN POWER CO. 

PHILIP SPORN PLANT 

3938 41 0001 004 Coal 

Steam 

None None N

54 053 54053 APPALACHIAN POWER CO. 

PHILIP SPORN PLANT 

3938 51 0001 005 Coal 

Steam 

None None N

54 053 54053 APPALACHIAN POWER 

MOUNTAINEER PLANT 

6264 1 0009 Coal 

Steam 

SCR SCR Scru

54 061 54061 MONONGAHELA POWER CO. 

FORT MARTIN POWER 

3943 1 0001 001 Coal 

Steam 

SNCR SNCR Scru

54 061 54061 MONONGAHELA POWER CO. 

FORT MARTIN POWER 

3943 2 0001 002 Coal 

Steam 

SNCR SNCR Scru

54 061 54061 MORGANTOWN ENERGY 

ASSOCIATES 

 0027 043 

54 061 54061 MORGANTOWN ENERGY 

FACILITY 

10743 GEN1 ORIS10743 GEN1 Coal 

Steam 

None None N

54 061 54061 LONGVIEW 00134 GEN1 Coal 

Steam 

SCR No 

Operation 

Scru

54 061 54061 GENERIC UNIT 900154 GSC54 ORIS900154 GSC54 Coal 

Steam 

No 

Operation 

SCR N

Ope

54 073 54073 MONONGAHELA POWER CO. 

WILLOW ISLAND 

3946 1 0004 001 Coal 

Steam 

None Coal Early 

Retirement 

N

54 073 54073 MONONGAHELA POWER CO. 

WILLOW ISLAND 

3946 2 0004 002 Coal 

Steam 

None SCR N

54 073 54073 MONONGAHELA POWER CO 

PLEASANTS POWER STATION 

6004 1 0005 001 Coal 

Steam 

SCR SCR Scru

Upg

54 073 54073 MONONGAHELA POWER CO 

PLEASANTS POWER STATION 

6004 2 0005 002 Coal 

Steam 

SCR SCR Scru

Upg

54 077 54077 MONONGAHELA POWER CO 

ALBRIGHT 

3942 1 0001 001 Coal 

Steam 

None Coal Early 

Retirement 

N
Documentation of the 2012 Emission Inventory 

89

Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls

FIPS FIPS Facility Name ORIS ID BLR ID SITE ID UNIT ID Plant Type 

VISTAS 

NOx 2012 

Controls 

IPM 

NOx 2012 

Controls 

VIS

SO2 

Con

54 077 54077 MONONGAHELA POWER CO 

ALBRIGHT 

3942 2 0001 002 Coal 

Steam 

None Coal Early 

Retirement 

N

54 077 54077 MONONGAHELA POWER CO 

ALBRIGHT 

3942 3 0001 003 Coal 

Steam 

None None N

54 079 54079 APPALACHIAN POWER 

JOHN E AMOS PLANT 

3935 1 0006 001 Coal 

Steam 

SCR SCR Scru

54 079 54079 APPALACHIAN POWER 

JOHN E AMOS PLANT 

3935 2 0006 002 Coal 

Steam 

SCR SCR Scru

54 079 54079 APPALACHIAN POWER 

JOHN E AMOS PLANT 

3935 3 0006 003 Coal 

Steam 

SCR SCR Scru