# Documentation of the

2012 Projection Emission Inventory

Prepared for:

Association for Southeastern Integrated Planning (ASIP)

Southeastern States Air Resource Managers, Inc

. (SESARM)

October 21, 2008

Prepared by :

MACTEC Engineering and Consulting, Inc.

William R

. Barnard

Sr. Principal Sci e ntist Edward Sabo

Principal Scient i s t

MACTEC

, 

# i nc.

# 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 E MISSION 

# P ROJECTIONS 

# .....................................................................................................................2

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

1.1.2 Adjustments to IP M 2012 Proj ections ............................................................................................ .......4

1.1.2.1 Stack Exhaust Gas Temp erature 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 N ON 

# -EGU E MISSION 

# P ROJECTIONS 

# ...........................................................................................................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 no nEGU Point Source Inventories ..............................................22

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

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

3.1 VA C HANGES



# ............................................................................................................................... .............39

3.2 NC C HANGES



# ............................................................................................................................... .............42

3.3 A REA 

# S OURCE 

# R ESULTS 

# ............................................................................................................................42

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

4.1 D EVELOPMENT 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 P ROCESSING OF 

# O N 

# -R OAD 

# M OBILE 

# S OURCE 

# E MISSIONS 

# ...........................................................................50

4.3 O N



# - ROAD 

# E MISSION 

# S UMMARIES 

# ..............................................................................................................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 SO 2 

# Emission Comparison for 2002/2009/2012/2018.

Table 1.1-3. EGU Point Source NO x 

# 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 Em ission Comparison for 2002/2009/2012/2018.

Table 1.1-6. EGU Point Source NH 3 

# Emission Comparison for 2002/2009/2012/2018.

Table 1.1-7. EGU Point Source PM 10 

# -PRI Emission Comparison for 2002/2009/2012/2018.

Table 1.1-8. EGU Point Source PM 2.5 

# -PRI Emission Comparison for 2002/2009/2012/2018.

Table 1.2-1. Facility Shutdowns Incor porated in the 2012 Non-EGU Inventory. Table 1.2-2. Other S/L Agency Changes In corporated in the 2012 Non-EGU Inventory.

Table 1.2-3. Non-EGU Point Source SO 2 

# Emission Comparison for 2002/2009/2012/2018.

Table 1.2-4. Non-EGU Point Source NO x 

# 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 NH 3 

# Emission Comparison for 2002/2009/2012/2018.

Table 1.2-8. Non-EGU Point Source PM 10 

# -PRI Emission Compar ison 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 Reducti on Impacts for 2012 based on T4 Rule. Table 2.0-3. 2012 Emissions Projections for Airc raft, Locomotives, and Commercial Marine Vessels (tons per year). Table 3.1-1. 2012 Control Efficiency (CE), Rule Effectiveness (RE), Ru le Penetration (RP) and Control Device ID for VA Counties with OTC Controls. Table 3.3-2. Comparison of the 2012 ASIP NH 3 

# Emissions with 2002, 2009 and 2018 VISTAS B&F Inventory Values. Table 3.3-3. Comparison of the 2012 ASIP NO x 

# Emissions with 2002, 2009 and 2018 VISTAS B&F Inventory Values. Table 3.3-4. Comparison of the 2012 ASIP PM 10 

# Emissions with 2002, 2009 and 2018 VISTAS B&F Inventory Values. Table 3.3-5. Comparison of the 2012 ASIP PM 2.5 

# Emissions with 2002, 2009 and 2018 VISTAS B&F Inventory Values. Table 3.3-6. Comparison of the 2012 ASIP SO 2 

# 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 SO 2 

# Emission Comparison.

Table 4.3-2. On-road Mobile Source NO x 

# Emission Comparison.

Table 4.3-3. On-road Mobile S ource VOC Emission Comparison.

Table 4.3-4. On-road Mobile S ource CO Emission Comparison.

Table 4.3-5. On-road Mobile Source NH 3 

# Emission Comparison.

Table 4.3-6. On-road Mobile Source PM 10 

# Emission Comparison.

Table 4.3-7. On-road Mobile Source PM 2.5 

# 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 Associat ion for Southeastern Integrated Planning (ASIP). The emissions developed were prepar ed 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 st ates in June 2008, revised and delivered by MACTEC in NIF format to the VISTAS em issions 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 emi ssion 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 a nd Consulting, Inc..

We used different approaches for differen t 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 th e impact of regulatory control programs on emissions in 2012. The IPM results were adju sted 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 c ontrols or other changes at specific nonEGUs.

For both sectors, we generated the 2012 invent ory to account for post-2002 emission reductions from promulgated and proposed non-EGU federal c ontrol programs as of July 1, 2004; the final proposed Clean Air Interstate Rule (CAIR); cons ent decrees, and other St ate, local, and sitespecific control programs. Section 1.1 discu sses the EGU projection i nventory development,

while Section 1.2 discusses the non-EGU projection inventory deve lopment. The inventory was completed prior to the DC Circuit Court vacatur of CAIR. Thus the in itial 2012 ASIP inventory includes EGU controls assumed under CAIR implem entation. After the CAIR vacatur, the states developed inventories for legally enforceable cont rols in absence of the CAIR requirements.

These inventories are document ed 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 de scribe how the IPM was used to develop emission projections for 2012. Second, we document the changes to the IP M 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 imp act of future emission c ontrol 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 E GUs, including the following topics:

 A chronology of the evolution of the EGU emission projection met hodology, 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-pro cessing of the IPM parsed file s to estimate emissions for pollutants other than SO 2 

# and NO x 

# ; 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 take n 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/Regi onal_Air_Quality.html File: VISTASII_PC_1f_All_Units_2 012 (To Client) 08-12-05.xls
LADCO developed 2012 NIF files for EGUs from th e 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 ta bles – TR, SI, ER, EU, EP, PE, CE, and EM)
MACTEC developed several QA reports to veri fy that the post-processed NIF files were consistent with the results contained in the IPM pa rsed files. We verified that the emissions in

the NIF 2012 EM file for SO 2 

# and NO x 

# were the same as those contained in the IPM 2012 parsed

file.

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

files and the 2009 VISTAS B&F NIF files. Vari ous 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 accomplis hed, MACTEC used the projected emissions from the 2012 post-processed NIF files as the st arting point for the 2012 inventory for EGUs in

the VISTAS/ASIP states. The VISTAS/ASIP Emi ssion 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 obtai ned from the post-processed 2012 IPM/NIF files were necessary. These adjustment s 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 emissi on unit was projected to have a SO 2 

# 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 ar e 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 he ight was maintained; 3) the curre nt 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 projecti ons, we identified significantly higher PM emissions in the 2012 post-processed IPM/NIF fi les 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 emi ssion 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 adju st 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 emi ssions and heat input) in conjunction with the

IPM forecasted 2009 heat i nput to generate 2009 PM 10 

# /PM 2.5 

# 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 emi ssion 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 previ ously made to the 2009/2018 VISTAS B&F inventories were reviewed for consistency with the IPM 2012 control as sumptions. Consistency

means that no unit has lower c ontrols in 2012 compared to th e VISTAS 2009 B&F controls.
However, there are instances where there are mo re controls in 2012 compared to the VISTAS 2009 B&F controls. For example, when IPM pr edicts no controls in 2009 but does predict
controls in 2012, the 2012 cont rols 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 refl ect 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 specif ic information on new capacity.

A comparison of the IPM and ASIP control assumpti ons 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 th at 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 ch ange request. This log was circul ated among the States to ensure that all change requests we re addressed and acted upon.

 We prepared a master spreadsheet that identif ied all coal- and oil-fi red units and included both the IPM-generated and VISTAS Best & Final SO 2 

# and NO x 

# emissions for 2002, 2009, 2012, and 2018; also included in the spre adsheet was an iden tification 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, whic h resulted in several iterations of changes and final confirmation by each State accepting the re sults 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 ch anges in emissions by pollutant

include:

 SO 2 

# emissions gradually decrease from 2002 to 2018 due to the projected installation of scrubbers to meet CAIR or other requirements.

 NO x 

# emissions generally decrease from 2002 to 2018 due to the projected installation of SCRs to meet CAIR or other requirements. For SC, NO x 

# emissions increased from 2009 to 2012 due to two new Santee Cooper coal units planned for Florence County with NO x 

# permitted emissions of 3,500 additi onal tons in 2012. For VA, NO x 

# 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 NO x 

# levels. For WV,

NO x 

# 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 increas e from 2002 to 2018 because of increased generation capacity, particular ly in gas-fired gas turbines and combined cycle units.

 PM 10 

# and PM 2.5 

# 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 PM 10 

# and PM 2.5 

# . Also, new gas-fire d 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 o il-fired units.

 NH 3 

# emissions generally increase from 2002 to 2018 due to projected installation of SCRs to meet CAIR or other requirements. NH 3 

# 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 i nventory 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 Resu lts 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 SO 2 

# ) 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 NO
x 

# emissions to account for year round oper ation compared to IPM assumption of ozone season operation only.

Alabama Power - Barry

ORIS=3 1-4 Added SNCR controls (35% reduction in NO
x 

# 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 SO 2 

# and NO
x 

# ) 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 NO
x 

# ) 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. SO 2 

# 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 (ORI S10333) 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 e fficiency to reflect 95% reduction in SO 2 

# 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 stack s (6 stacks). IPM projected emissions were evenly distributed between the six units and the following emission reductions applied: 99.8% SO 2 

# reductions, 85.6% NO
x 

# reductions, and 62.3% PM 2.5 

# 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 SO 2 

# ) 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 SO 2 

# 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 SO 2 

# 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 SO 2 

# ) 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 NO
x 

# ) 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 SO 2 

# ) 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 NO
x 

# ) 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 SO 2 

# ) 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 SO 2 

# ) 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 SO 2 

# ) 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 NO
x 

# ) 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 em ission 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 resu lts 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 resu lts 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 Cogentrixof 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 NO
x 

# ) 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 SO 2 

# ) 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 SO 2 

# ) for this unit.

# 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

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). NO
x 

# 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; Up grade 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 SO 2 

# 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 NO
x 

# ) 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 SO 2 

# ) 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 NO
x 

# ) for this unit.

VA Dominion – Altavista

ORIS=10773 1, 2 Replaced IPM 2012 SO 2 

# 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 NO
x 

# ) for this unit.

Birchwood Power Partners

ORIS=54304 1 Replaced IPM 2012 SO 2 

# emissions with permit limit for facility supplied by VA DEQ.

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12 

# 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 SO 2 

# emissions with permit limit for facility supplied by VA DEQ.

Dominion Possum Point

ORISID=3804 5 Unit 5: IPM had zero heat in put. 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 NO
x 

# ) based on VADEQ understanding from EPA Region 3 that the modeling for the attainment plan should reflect the permitted NO
x 

# 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 SO 2 

# 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 SO 2 

# 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 NO
x 

# 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 SO 2 

# emissions assumed.

SCR on #3 and #4 not included in IPM. Assumed 80% NO
x 

# 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.

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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 mothballe d 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 SO 2 

# Permit Rate was corrected from 2.7 to 0.15 lb/MMBtu. Used SO 2 

# Permit Rate of 0.15 lb/MMBtu and IPM predicted total fuel used to calculate SO 2 

# emissions in 2012.

North Branch

ORISID=7537 1A, 1B SO 2 

# Permit Rate was corrected from 2.7 to 0.678 lb/MMBtu. Used SO 2 

# Permit Rate and IPM predicted total fuel used to calculate SO 2 

# emissions in 2012

Monongahela Power – Harrison

ORIS=3944 1, 2, 3 The predicted 2012 plant total emissions are 18,000 SO 2 

# tons and 9,000 NO
x 

# tons. This reflects a doubling of 2002 SO 2 

# emissions and a 75% reduction of NO
x 

# 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 fo r 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 SO 2 

# emissions of 850 tons and 2009 emissions of 777 tons. The 2012 data shows nearly 3,600 SO 2 

# tons. We can think of no reason for such a large increase. NO
x 

# 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 SO 2 

# tons and 1,400 NO
x 

# tons.
These values indicate 95% and 90% emission reductions of SO 2 

# and NO
x 

# respectively from 2002 that are not reflected in installed or planned controls.

Review of the AEP Consent Decr ee 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 2 002 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 fo r 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 scr ubber with a 79.9% SO 2 

# 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 fo r early retirement. For 2012, used 2002 actual emissions as these units are not likely to retire by 2012.

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# Table 1.1-2. EGU Point Source SO 2 

# 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 NO x 

# 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 f iles used for ASIP air quality modeling for 2012, three errors in NO
x 

# 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

16 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 PM 10 

# -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 file s used for ASIP air quality modeling for 2012, an error in PM 10 

# 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 PM 2.5 

# -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 file s used for ASIP air quality modeling for 2012, an error in PM 2.5 

# 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.

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# Table 1.1-8. EGU Point Source NH 3 

# 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 discu ss the following specific aspects of the development of the nonEGU projections. First, we brie fly describe the growth factor s used to account for economic growth. Second, we document the control program s specified for incorporation in the ASIP 2012 inventory. Third, we summarize the changes re quested by S/L agencies that were primarily

related to better information on source closures a nd anticipated controls for specific facilities and emission units resulting from BART, consent orders, or perm it 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 gr owth factor data used in developing the 2012 non-EGU ASIP inventory. The same sources of data used for the 2009/2018 invent ories were used in developing the growth factors for the 2012 non-EGU inventory:

 State-specific growth rates from the Re gional 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 indus try 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 full y 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, w ith 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 da ta 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 co mbustion 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 southeas tern 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 St ates within each division using the same growth rate.

 NCDENR supplied recent projections for th ree key sectors in North Carolina where declining production was anticipated – SI C 22xx Textile Mill Products, 23xx Apparel
and Other Fabrics, and 25xx Furniture and Fi xtures. 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 credit s were available in the event that they are needed for nonattainment areas.

 The American Forest and Paper Associati on (AF&PA) supplied growth projections for the pulp and paper sector, which were a pplied to SIC 26xx Pape r 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 for ecast 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 in stead 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 propos ed control programs that are reasonably anticipated to result in post-2002 emission reduc tions. With one exception, we used the same control programs for 2012 as for the 2009 and 2018 VISTAS B&F non-EGU poi nt inventories. The exception is the anticipated emission reducti ons from the Industrial Boiler/Process Heater
MACT standard. On June 8, 2007, the DC Ci rcuit Court of Appeal s vacated the MACT

standard. For the 2009/2018 B&F i nventories, 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 Stat es 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 equiva lent 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

 NO
x 

# RACT in 1-hr ozone nonattainment area SIPs

 NO
x 

# 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 achieva ble control technology (MACT Standards)

 Combustion Turbine MACT

 NO
x 

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



# The methodologies used to account for the emi ssion 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 update s and correctio ns included:

 S/L agencies identified significant source s hutdowns that have occurred since 2002 and specified that emissions from these sources s hould not be included in the future year

inventories. These sources ar e identified in Table 1.2-1.

 S/L agencies identified individual unit sour ce shutdowns that have occurred since 2002 and specified that emissions from these emi ssion units should not be included in the future year inventories. S/L agencies identi fied expansions to exis ting 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 Birm ingham 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 (p tinv_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, a nd 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 th at 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 ch ange request. This log was circul ated among the States to ensure that all change requests we re addressed and acted upon.

 We prepared a master spreadsheet that compared facility level emissions for 2009 and 2012 and highlighted were substantial di fferences occurred for State review.

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

State and local agency reviewed these files, whic h resulted in several iterations of changes and final confirmation by each Stat e accepting the results of th e 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 in itial 2012 ASIP non-EGU inventor y. Some notable changes in emissions by pollutant include:

 SO 2 

# emissions generally increase slightly fr om 2002 to 2018 due to the projected growth in fuel consumption, except in certain State where BART requirements may reduce SO 2 

# emissions. For WV, SO 2 

# emissions are lower in 2012 th an in 2009 or 2018 because the

State identified several source closures for th e 2012 inventory that were not identified for

either the 2009 or 2018 inventories.

 NO x 

# emissions generally decrea se from 2002 to 2009 due to NO x 

# SIP Call, RACT or other control requirements, then increase fr om 2009 to 2018 due to the project growth.
For WV, NO x 

# emissions are lower in 2012 than in 2009 or 2018 because the State

# Documentation of the 2012 Emission Inventory

23 

# 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 gene rally 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.

 PM 10 

# and PM 2.5 

# emissions generally decrease from 2002 to 2009 due to source closures and then increase because of projected gr owth in fuel consumption and economic activity. FL shows a decrease in PM em issions 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 PM 10 

# /PM 2.5 

# emissions was applied to account for expect ed reduction from the control requirements of the boiler

MACT.

 NH 3 

# emissions generally increase from 2002 to 2018 because of projected growth in economic activity and fuel use.

Other minor inconsistencies between the 2012 i nventory 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

24 

# Table 1.2-1. Facility Shutdowns Incorp orated 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 A VONDALE 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
45-013-0360-00 19 Beaufort CLELAND CONSTRUCTION-CLOSED 45-015-0420-0083 Berkeley CONCERT ACI INC-CLOSED
45-019-0560-00 36 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 SC OTTS 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 DA N RIVER:WHITE HORSE-CLOSED
45-045-1200-02 77 Greenville EXCA LIBUR TOOL:POINSETT
45-045-1200-0317 Gr eenville GATEWAY MFG: PLANT #2 - GREENVILLE
45-045-1200-0346 Gr eenville AMERICAN W OODWORKS 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
45-051-1340-00 73 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 INTE RNATIONAL 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
45-079-1900-00 38 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 LABORA TORIES-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 C LEVELAND 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 INDU STRIAL LAMINATES, INC. (GIL 47-053-0012 Gibson FOAMEX INTERNATIONAL, INC.
47-053-0093 Gibson EM ERSON 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. SM ITH 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

28 

# 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 Culpep er KELLER MANUFACTURING CO INC 51-089-00012 Henry BASSETT CHAIR CO 51-089-00073 Henry MA RTINSVILLE 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 FERG USSON, 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

29 

# 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 Transcontinenta l Natural Gas Pipeline facilities in NC that are subject to the NO
x 

# SIP call. We took 2004 emissions and grew them to 2009/2012/2018 and capped those units that are subject to the NO
x 

# SIP Call Rule. These facility IDs are 37-057-3705700300, 37-097-3709700225, and 37-157-3715700131

NCDENR applied NO
x 

# 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 repor ts the actual emissions for CEMEX (47-093-0008) after the NO
x 

# 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 NO
x 

# controls for two units at Columbia Gulf Transmission (47-111-0004) under the NO
x 

# 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 re placed with natural gas-fired units by 2012. Allowable SO 2 

# emissions will be 39 tons/year and allowable NO
x 

# emissions will be 81 tons/year.

VA VADEQ provided NO
x 

# emission estimates for NO
x 

# Phase II gas transmission sources at three Transco facilities (51-011-0 0011, 51-137-00027 , 51-143-00120) which were us ed to replace the default NO
x 

# Phase II control assumptions for these facilities.

VADEQ provided updated 2009/2018 NO
x 

# and SO 2 

# emissions based on new controls required by a November 2005 permit modification and netting exer cise at the University of Virginia. The entire power plant facility is limited to 213 tons of NO
x 

# and 107 tons of SO 2 

# per year. The permit also allowed the installation of 3 new boilers, also under the 213 tons of NO
x 

# /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 

# SO 2 

# emissions in 2009 and 2018 for thirteen facilities to reflect updated information from VADEQ regarding projected 

# SO 2 

# 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-cr iteria 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 re present a better basis for future year emissions estimates. Therefore, W VDEP 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 SO 2 

# 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 NO x 

# 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 Em ission 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 Em ission 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 NH 3 

# 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 PM 10 

# -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 PM 25-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 th e 2012 nonroad source emission inventory was the 2009 and 2018 VISTAS Best & Final (B&F) inventor y. For nonroad sources the B&F inventory was the same as the Base G2 inventory. Thes e inventories has been extensively reviewed, updated, and approved by the VISTAS States. Complete documenta tion of the these inventories

is contained in Documentation of the Base G2 and Be st & 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 Ba se G2 projection inventories for 2009 and 2018, corresponding projection inventor ies for 2012 were developed. Inventories for both NONROAD
model sources and aircraft, locomotives, and comme rcial marine vessels were developed for all ASIP (VISTAS)-area counties. The methods used to develop th e 2012 inventories were identical

to those described above for the 2009/2018 VIST AS 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 inventorie s unless specific changes were either dictated by the change in the forecast period or were requ ested 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 fina l 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 change d 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 recomm endations provided by the EPA (see “Diesel Fuel Sulfur Inputs for the Draft NON ROAD2004 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 pr ogram changes are expected.

The evolution of fuel sulfur content assu mptions 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 esta blished under the federal Energy Policy Act of 2005, some consideration was give n to revising the assumed oxygen content of gasoline for the 2012 NONROAD model projection inve ntory. Using data presente d in the March 2008 version of the Energy Information Administration’ s 2008 Annual Energy Outlook (Department of Energy, Energy Information Administration re port DOE/EIA-0383(2008), March 2008 (Revised) release), the following average ethanol conten t 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 th at all gasoline sold in the U.S. will contain the legally permissible maximum level of etha nol 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) VI STAS area NONROAD mode l inventories were developed under an assumption of zero ethanol cont ent, it was ultimately decided to maintain the same zero percent ethanol assumption for the 2012 AS IP 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 increasi ng 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 re spectively and increasing NO x 

# emissions for the same engines by about 11.5 percent per weight percent ethanol. Emissions for two-st roke gasoline engines would decline by about 0.6 and 6.5 percent per weight percent ethanol for exhaust HC and CO respectively, while NO x 

# emissions would increase by about 18.6 percent per weight percent

ethanol.

Projections for 2012 were developed by runni ng the resulting input files through the

NONROAD2005 model. Table 2.0-1 summarizes the result ing emission projections.

Aircraft, locomotive, and commercial marine vessel projections for 2012 in all ASIP area counties were developed using the same met hodology used to develop the Base G2 2009 and 2018 VISTAS-area projections for these same s ources, 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 Docu ment 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, a nd Wake counties in North Caro lina, where growth factors provided by state planners were us ed in place of the CAIR data.

Kentucky planners did not provide an explicit airc raft 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 fo r the Base G2 2009 and 2018 VISTAS projection inventories, the state-provid ed factors for Kentucky are used for all aircraft.

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

State CO NO
x 

# PM 10 

# PM 2.5 

# SO 2 

# 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 fact ors are not entirely consistent with the corre sponding factors used for the Base G2 2009 and 2018 VISTAS project ion inventories for North Carolina and this should be considered in any comparison of No rth Carolina aircraft emissions projections. Moreover, while the state-provided growth factors for the Base G2 2009 and 2018 VISTAS projection inventories were appl ied only to commercial and air taxi aircraft, North Carolina planners requested that the 2012 gr owth factors be applied to all aircraft types in the affected counties. The actual aircraft gr owth factors used in the variou s 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 SO 2 

# and PM emissions

from locomotives and commercial marine vessels were re-estimat ed for 2012 using data from the EPA’s technical support documen t 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 indi cated in Table 2.0-2 (which also shows the corresponding control factors for 2009 and 2018). The resulting grow th 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 Reducti on Impacts for 2012 based on T4 Rule

2009 2012 2018

CMV 

# SO 2 

# = Non-T4 

# SO 2 

# × 0.1632 0.0490 0.0225

Locomotive 

# SO 2 

# = Non-T4 

# SO 2 

# × 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

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# Table 2.0-3. 2012 Emissions Projections fo r Aircraft, Locomotives, and Commercial Marine Vessels (tons per year)

Source State CO NO
x 

# PM 10 

# PM 2.5 

# SO 2 

# 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

VA 121 294 23 21 1 51 Military Marine (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

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# 3.0 2012 Area Source Projections

Area sources were projected using techniques de veloped for the Visibility Improvement State and Tribal Association of the Southeast (VISTA S) 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 me thods 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 resul ting from specific review by State and local air pollution agencies (detailed below), the interpolat ion of growth and control factors was strictly based on a linear interpolation of the existing 200 9 and 2018 VISTAS growth or control factors.

The interpolated growth factor s developed using the final cons olidated list developed for VISTAS for 2009 and 2018 and represent a consolid ation 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 invent ory 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 countie s the controls repres ent those imposed by rules adopted by the Ozone Transport Commission (OTC).

In addition to the interpolated growth and cont rol 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 fr om them are detailed below by State.

3.1 VA Changes

VA DEQ representatives provided comments back to MACTEC re lated 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 coun ties in northern VA that are part of the OTC. For the majority of these counties and the area so urces 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 implement ed by the national consumer solvent control program. However further evaluation coupled w ith discussion with E.H. Pechan staff (who developed the original CAIR cont rol values) indicated that the va lues 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 subj ect only to the nationa l 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), Ru le 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, To tal: 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, Tota l: 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

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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

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FIPs SCC Pollutant SCC Description CE RE RP Device ID

51013, 51059,
51107, 51153,
51510, 51600,
51610, 51683,

51685 2440020000 VOC Industrial Adhesive s 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 fo r NC, NC had prepared estimates of emissions

for a number of area sources. These estimates we re to directly replace the projected emissions developed using the standard projection techniqu e 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 straig ht-line interpolation w ould 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 stra ight-line interpolation for those sources that were common between 2009 and 2018. For any re maining sources, their emissions were developed using the standard projection techniqu e 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 po llutant, 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 SO 2 

# sources. In evaluating the cause of th e missing sources, MACTEC discovered that

the sources were removed duri ng the CERR update process. MACTEC had received a CERR submittal from Jefferson County (via U.S. EPA) th at included records for sources with pollutants that were not ozone related pollutants. Th e methodology used by MACTEC to govern whether or not a CERR data set represented a comple te replacement set was to look for non-ozone pollutants. If they were present then the data set 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 record s after the preparation

# Documentation of the 2012 Emission Inventory

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# of the B&F inventories for 2009 and 2018. The upda ted dataset was used as the starting point for the 2012 inventory projection. That resulted in increased SO 2 

# 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 SO 2 

# source categories were replaced when the corrected Jefferson C ounty, KY file was developed post-B&F. This

resulted in moderate increases in NO x 

# , PM 2.5 

# 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 NH 3 

# Emissions with 2002, 2009 and 2018 VISTAS B&F Inventory Values

State Pollutant 2002 2009 2012 2018

AL 

# NH 3 

# 58,318 64,268 66,814 71,915

FL 

# NH 3 

# 37,446 38,616 39,221 40,432

GA 

# NH 3 

# 80,913 89,212 92,768 99,885

KY 

# NH 3 

# 51,135 53,005 53,826 55,211

MS 

# NH 3 

# 58,721 63,708 65,775 69,910

NC 

# NH 3 

# 161,859 170,313 173,830 180,865

SC 

# NH 3 

# 28,166 30,555 31,535 33,496

TN 

# NH 3 

# 34,322 35,176 35,515 36,193

VA 

# NH 3 

# 43,905 46,639 47,818 50,175

WV 

# NH 3 

# 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 NO x 

# Emissions with 2002, 2009 and 2018 VISTAS B&F Inventory Values

State Pollutant 2002 2009 2012 2018

AL 

# NO x 

# 23,444 23,930 24,295 25,028

FL 

# NO x 

# 28,872 28,187 29,027 30,708

GA 

# NO x 

# 36,105 37,689 38,887 41,282

KY 

# NO x 

# 39,507 42,088 63,539 44,346

MS 

# NO x 

# 4,200 4,249 4,327 4,483

NC 

# NO x 

# 36,512 39,913 41,215 43,820

SC 

# NO x 

# 19,332 19,360 19,771 20,592

TN 

# NO x 

# 17,831 18,485 18,850 19,579

VA 

# NO x 

# 51,418 52,618 53,799 56,158

WV 

# NO x 

# 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 PM 10 

# Emissions with 2002, 2009 and 2018 VISTAS B&F Inventory Values

State Pollutant 2002 2009 2012 2018

AL PM 10 

# -PRI 393,426 412,815 422,807 444,996

FL PM 10 

# -PRI 443,346 503,230 527,162 578,516
GA PM 10 

# -PRI 695,320 776,305 809,564 880,070

KY PM 10 

# -PRI 233,559 242,177 255,887 256,052
MS PM 10 

# -PRI 343,377 356,324 361,527 375,495
NC PM 10 

# -PRI 280,350 292,412 300,020 315,259
SC PM 10 

# -PRI 260,858 278,299 286,202 304,251

TN PM 10 

# -PRI 211,913 225,409 230,965 245,368
VA PM 10 

# -PRI 237,577 252,488 258,629 275,351

WV PM 10 

# -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 PM 2.5 

# 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 SO 2 

# Emissions with 2002, 2009 and 2018 VISTAS B&F Inventory Values

State Pollutant 2002 2009 2012 2018

AL 

# SO 2 

# 52,253 48,228 48,907 50,264

FL 

# SO 2 

# 40,491 36,699 37,238 38,317

GA 

# SO 2 

# 57,555 57,692 58,368 59,724

KY 

# SO 2 

# 41,805 43,087 58,204 44,186

MS 

# SO 2 

# 771 753 751 746

NC 

# SO 2 

# 5,392 5,730 5,841 6,062

SC 

# SO 2 

# 12,900 13,051 13,186 13,457

TN 

# SO 2 

# 29,897 30,555 31,015 31,935

VA 

# SO 2 

# 105,890 105,984 107,116 109,380

WV 

# SO 2 

# 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 AS IP 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

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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 da ta for the MOBILE6 module were delivered to the States for review prior to emissions modeling.

To ensure consistency across evaluation year s, the 2012 base case inventory was developed using methodologies comparable to those em ployed in developing the 2009 and 2018 on-road portion of the ASIP inventorie s. All modifications to the 2012 inventory methods were developed in consultation with the ASIP Stat e workgroup. Generally, m odifications were only made to properly account for actual changes exp ected in the intervening period (i.e., between 2009 and 2018) reflecting the reduction in NO x 

# and SO 2 

# 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 (D ocumentation of

the Base G2 and Best & Final 2002 Base Ye ar, 2009 and 2018 Emission Inventories for VISTAS (B&F Document), March 14, 2008), MACTEC prep ared versions of the 2009 and 2018 base case mobile inventory input data files.

Because no preliminary 2012 inventory was de veloped, 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 2 018, Alpine obtained from the States input data revisions, methodological revisions, and local control program speci fications (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 em ission estimates for this source category

4.1.1 Preparation of revised 2012 input data files

The methodology used to develop the 2012 on-ro ad 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 en titled "Technical Guidance on the Use of MOBILE6.2 for Emission Inventory Prep aration" (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 re tained at 2009 values, except as otherwise instructed by individual States (see below). This incl udes all control program descriptions (I/M, ATP, Stage II, etc.), all othe r fuel qualities (RVP, oxy conten t, etc.), all other vehicle descriptive data (registration age distributions, etc.), and a ll scenario descriptive data.

In addition to the updates described above that were applied to all AS IP-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 incor porate a 4-year grace period for emission testing. "VAIM09.IM" was used for Arlington, Fair fax, 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 C hurch 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 us ing 0% and 3.5% respectively for Ether and Ethanol Oxygen Content and 0% and 100% respectively for Et her 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 201 2 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 subm ittals as used in the 2012 simulations.

Kentucky:

Revised 2012 VMT and VMT mix da ta were provided by the DE P/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 statew ide county and roadway type-specific VMT data for 2012.

Virginia:

Virginia provided county and roadway type-spe cific annual VMT for 2012 and these data were used directly in the MOBILE6/SMOKE runs c onsistent with data previously provided for

2009/2018.

West Virginia:

West Virginia identified a doubl e counting of VMT in Ohio County, WV for the 2018 calendar year which artificially increas ed 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 deve lop the base year on-road mobile source
emissions estimates for CO, NH 3 

# NO x 

# , 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, tempor alized emission estimates. Of note, whereas the on-network emissions estimates are spatially a llocated based on link locat ion 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 hi ghway networks and popul ation. 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 emi ssions into separate source categories;

 VMT, fleet turnover, and changes in fuel composition and Reid vapor pressure (RVP).

# Documentation of the 2012 Emission Inventory

51 

# The primary input to MOBILE6 is the MOBILE shell file. The MOBILE shell contains the various options (e.g. type of inspection and main tenance program in effect, type of oxygenated fuel program in effect, alternative vehicle mix pr ofiles, 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 an d humidity. SMOKE pro duces emissions factors for state and county groups that are selected for regional simila rities and consistent MOBILE6 option requirements (i.e. I/M pr ograms, RVP, fuel programs). The hourly average temperature and humidity are calculated from the hourly temper atures in each grid cell in the state/county

groups.

SMOKE was run using the daily average speed opti on 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 base d 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 re quirements 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 (e xcept 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 leve l 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 me teorological variabilit y, but the processing requirements for daily motor vehicle emissions we re determined to be prohibitive under the current schedule. Rather than utilizing averag ed meteorological data or pre-calculated motor vehicle emissions, a single week per month was se lected for modeling. This week was selected from mid-month, to try to best represent the av erage temperature ranges for the month, and also adjusted to exclude holidays that would requir e atypical processing. The area source modeling

dates were also selected from these ra nges to simplify data handling procedures.

On-Road Mobile Sources Represented by the Following Weeks

January 13-19

February 10-16

March 10-16

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# 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 summar ies 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 SO 2 

# 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

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# Table 4.3-2. On-road Mobile Source NO x 

# 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

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# 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 NH 3 

# 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

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# Table 4.3-6. On-road Mobile Source PM 10 

# 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 PM 2.5 

# 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

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# APPENDIX A:

COMPARISON OF EGU CONTROLS FOR COAL AND OIL/GAS UNITS

BASED ON IPM MODELING AND STATE-PROVIDED INFORMATION

FOR THE 2012 INVENTORYDocumentation of the 2012 Emission InventoryMACTEC, Inc.57Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls01 033 01033 TVA COLBERT 47 1 0010 010 CoalSteamNone None None None01 033 01033 TVA COLBERT 47 2 0010 011 CoalSteamNone None None None01 033 01033 TVA COLBERT 47 3 0010 012 CoalSteamNone None None None01 033 01033 TVA COLBERT 47 4 0010 013 CoalSteamNone None None None01 033 01033 TVA COLBERT 47 5 0010 014 CoalSteamSCR SCR Scrubber Scrubber01 055 01055 ALABAMA POWER COMPANYGADSDEN7 1 0002 002 CoalSteamNone None None None01 055 01055 ALABAMA POWER COMPANYGADSDEN7 2 0002 003 CoalSteamNone None None None01 063 01063 ALABAMA POWER COMPANYGREENE COUNTY10 1 0001 002 CoalSteamSCR SCR None Scrubber01 063 01063 ALABAMA POWER COMPANYGREENE COUNTY10 2 0001 003 CoalSteamSCR SCR None Scrubber01 071 01071 TVA - WIDOWS CREEK 50 1 0008 002 CoalSteamSCR SCR None None01 071 01071 TVA - WIDOWS CREEK 50 2 0008 003 CoalSteamSCR SCR None None01 071 01071 TVA - WIDOWS CREEK 50 3 0008 004 CoalSteamSCR SCR None None01 071 01071 TVA - WIDOWS CREEK 50 4 0008 005 CoalSteamSCR SCR None None01 071 01071 TVA - WIDOWS CREEK 50 5 0008 006 CoalSteamSCR SCR None None01 071 01071 TVA - WIDOWS CREEK 50 6 0008 007 CoalSteamSCR SCR None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.58Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls01 071 01071 TVA - WIDOWS CREEK 50 7 0008 008 CoalSteamSCR SCR Scrubber Scrubber01 071 01071 TVA - WIDOWS CREEK 50 8 0008 009 CoalSteamSCR SCR Scrubber Scrubber01 073 01073 ALABAMA POWER COMPANY(MILLER POWER PLANT)6002 4 010730011 001 CoalSteamSCRAll Year SCRSummer Scrubber None01 073 01073 ALABAMA POWER COMPANY(MILLER POWER PLANT)6002 3 010730011 002 CoalSteamSCRAll YearSCRSummerScrubber None01 073 01073 ALABAMA POWER COMPANY(MILLER POWER PLANT)6002 2 010730011 004 CoalSteamSCRAll YearSCRSummerScrubber None01 073 01073 ALABAMA POWER COMPANY(MILLER POWER PLANT)6002 1 010730011 005 CoalSteamSCRAll YearSCRSummerScrubber None01 097 01097 ALABAMA POWER COMPANYBARRY3 1 1001 002 CoalSteamSNCR None None None01 097 01097 ALABAMA POWER COMPANYBARRY3 2 1001 003 CoalSteamSNCR None None None01 097 01097 ALABAMA POWER COMPANYBARRY3 3 1001 004 CoalSteamSNCR None None None01 097 01097 ALABAMA POWER COMPANYBARRY3 4 1001 005 CoalSteamSNCR None None None01 097 01097 ALABAMA POWER COMPANYBARRY3 5 1001 006 CoalSteamSCR None Scrubber None01 117 01117 ALABAMA POWER COMPANYE C GASTON26 1 0005 002 CoalSteamNone SCR None Scrubber01 117 01117 ALABAMA POWER COMPANYE C GASTON26 2 0005 003 CoalSteamNone SCR None Scrubber01 117 01117 ALABAMA POWER COMPANYE C GASTON26 3 0005 004 CoalSteamNone SCR None Scrubber01 117 01117 ALABAMA POWER COMPANYE C GASTON26 4 0005 005 CoalSteamNone SCR None ScrubberDocumentation of the 2012 Emission InventoryMACTEC, Inc.59Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls01 117 01117 ALABAMA POWER COMPANYE C GASTON26 5 0005 006 CoalSteamSCR SCR Scrubber Scrubber01 127 01127 ALABAMA POWER COMPANYGORGAS8 6 0001 004 CoalSteamNone None None None01 127 01127 ALABAMA POWER COMPANYGORGAS8 7 0001 005 CoalSteamNone None None None01 127 01127 ALABAMA POWER COMPANYGORGAS8 8 0001 006 CoalSteamNone None Scrubber None01 127 01127 ALABAMA POWERCOMPANYGORGAS8 9 0001 007 CoalSteamNone None Scrubber None01 127 01127 ALABAMA POWER COMPANYGORGAS8 10 0001 008 CoalSteamSCR SCR Scrubber Scrubber01 129 01129 ALABAMA ELECTRIC COOPCHARLES R LOWMAN56 1 0001 002 CoalSteamNone None Scrubber None01 129 01129 ALABAMA ELECTRIC COOPCHARLES R LOWMAN56 2 0001 003 CoalSteamSCR SCR Scrubber Scrubber01 129 01129 ALABAMA ELECTRIC COOPCHARLES R LOWMAN56 3 0001 004 CoalSteamSCR SCR Scrubber Scrubber12 001 12001 GAINESVILLE REGIONALUTILITIES JOHN R KELLY664 JRK6 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 001 12001 GAINESVILLE REGIONALUTILITIES JOHN R KELLY664 JRK7 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 001 12001 GAINESVILLE REGIONALUTILITIES JOHN R KELLY664 JRK8 0010005 7 O/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 001 12001 CITY OF GAINESVILLE, GRUDEERHAVEN663 B1 0010006 3 O/GSteamNoOperationNoOperationNoOperationNo Operation12 001 12001 CITY OF GAINESVILLE, GRUDEERHAVEN663 B2 0010006 5 CoalSteamNone None None None12 005 12005 GULF POWER COMPANYLANSING SMITH PLANT643 1 0050014 1 CoalSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.60Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls12 005 12005 GULF POWER COMPANYLANSING SMITH PLANT643 2 0050014 2 CoalSteamNone None None None12 009 12009 FLORIDA POWER & LIGHT(PCC) CAPE CANAVERAL609 PCC1 0090006 1 O/GSteamNone None None None12 009 12009 FLORIDA POWER & LIGHT(PCC) CAPE CANAVERAL609 PCC2 0090006 2 O/GSteamNone None None None12 011 12011 FLORIDA POWER & LIGHT(PPE) PORT EVERGLADES617 PPE1 0110036 1 O/GSteamNone NoOperationNone No Operation12 011 12011 FLORIDA POWER & LIGHT(PPE) PORT EVERGLADES617 PPE2 0110036 2 O/GSteamNone NoOperationNone No Operation12 011 12011 FLORIDA POWER & LIGHT(PPE) PORT EVERGLADES617 PPE3 0110036 3 O/GSteamNone NoOperationNone No Operation12 011 12011 FLORIDA POWER & LIGHT(PPE) PORT EVERGLADES617 PPE4 0110036 4 O/GSteamNone NoOperationNone No Operation12 017 12017 PROGRESS ENERGY FLORIDACRYSTAL RIVER628 1 0170004 1 CoalSteamNone None None None12 017 12017 PROGRESS ENERGY FLORIDACRYSTAL RIVER628 2 0170004 2 CoalSteamNone None None None12 017 12017 PROGRESS ENERGY FLORIDACRYSTAL RIVER628 5 0170004 3 CoalSteamNone None None None12 017 12017 PROGRESS ENERGY FLORIDACRYSTAL RIVER628 4 0170004 4 CoalSteamSCR SCR Scrubber Scrubber12 031 12031 SAINT JOHNS RIVER 207 1 0310045-A 16 SCR SCR Scrubber Scrubber12 031 12031 SAINT JOHNS RIVER 207 2 0310045-A 17 SCR SCR Scrubber Scrubber12 031 12031 NORTHSIDE 667 2A 0310045-B 26 O/GSteamNone NoOperationNone No Operation12 031 12031 NORTHSIDE 667 1A 0310045-B 27 O/GSteamNone NoOperationNone No OperationDocumentation of the 2012 Emission InventoryMACTEC, Inc.61Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls12 031 12031 NORTHSIDE 667 3 0310045-B 3 O/GSteamNone NoOperationNone No Operation12 031 12031 CEDAR BAY COGENERATIONINC.10672 GEN1 0310337 1 CoalSteamNone SNCR Scrubber Scrubber12 033 12033 GULF POWER COMPANYCRIST ELECTRICGENERATION641 2 0330045 2 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 033 12033 GULF POWER COMPANYCRIST ELECTRICGENERATION641 3 0330045 3 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 033 12033 GULF POWER COMPANYCRIST ELECTRICGENERATION641 4 0330045 4 CoalSteamNone None Scrubber None12 033 12033 GULF POWER COMPANYCRIST ELECTRICGENERATION641 5 0330045 5 CoalSteamNone None Scrubber None12 033 12033 GULF POWER COMPANYCRIST ELECTRICGENERATION641 6 0330045 6 CoalSteamSNCR SNCR Scrubber None12 033 12033 GULF POWER COMPANYCRIST ELECTRICGENERATION641 7 0330045 7 CoalSteamSCR SCR Scrubber Scrubber12 053 12053 Central Power and LimeIncorporated10333 GEN1 0530021 18 CoalSteamNone None Scrubber Scrubber12 057 12057 TAMPA ELECTRIC COMPANYBIG BEND STATION645 BB01 0570039 1 CoalSteamSCR SCR Scrubber Scrubber12 057 12057 TAMPA ELECTRIC COMPANYBIG BEND STATION645 BB02 0570039 2 CoalSteamSCR SCR Scrubber Scrubber12 057 12057 TAMPA ELECTRIC COMPANYBIG BEND STATION645 BB03 0570039 3 CoalSteamSCR SCR Scrubber Scrubber12 057 12057 TAMPA ELECTRIC COMPANYBIG BEND STATION645 BB04 0570039 4 CoalSteamSCR SCR Scrubber Scrubber12 057 12057 TAMPA ELECTRIC COMPANYF.J. GANNON STATION646 GB01 0570040 1 NoOperationNoOperationNoOperationNo Operation12 057 12057 TAMPA ELECTRIC COMPANYF.J. GANNON STATION646 GB02 0570040 2 NoOperationNoOperationNoOperationNo OperationDocumentation of the 2012 Emission InventoryMACTEC, Inc.62Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls12 057 12057 TAMPA ELECTRIC COMPANYF.J. GANNON STATION646 GB03 0570040 3 NoOperationNoOperationNoOperationNo Operation12 057 12057 TAMPA ELECTRIC COMPANYF.J. GANNON STATION646 GB04 0570040 4 NoOperationNoOperationNoOperationNo Operation12 057 12057 TAMPA ELECTRIC COMPANYF.J. GANNON STATION646 GB05 0570040 5 NoOperationNoOperationNoOperationNo Operation12 057 12057 TAMPA ELECTRIC COMPANYF.J. GANNON STATION646 GB06 0570040 6 NoOperationNoOperationNoOperationNo Operation12 061 12061 CITY OF VERO BEACH 693 0610029 1 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 061 12061 CITY OF VERO BEACH 693 3 0610029 3 O/GSteamNoOperationNoOperationNoOperationNo Operation12 061 12061 CITY OF VERO BEACH 693 4 0610029 4 O/GSteamNoOperationNoOperationNoOperationNo Operation12 063 12063 GULF POWER COMPANYSCHOLZ642 1 0630014 1 CoalSteamNone None None None12 063 12063 GULF POWER COMPANYSCHOLZ642 2 0630014 2 CoalSteamNone None None None12 073 12073 CITY OF TALLAHASSEEARVAH B.HOPKINS688 1 0730003 1 O/GSteamNoOperationNoOperationNoOperationNo Operation12 073 12073 CITY OF TALLAHASSEEARVAH B.HOPKINS688 2 0730003 4 O/GSteamNoOperationNoOperationNoOperationNo Operation12 081 12081 FLORIDA POWER & LIGHT(PMT) MANATEE POWER6042 PMT1 0810010 1 O/GSteamNone NoOperationNone No Operation12 081 12081 FLORIDA POWER & LIGHT(PMT) MANATEE POWER6042 PMT2 0810010 2 O/GSteamNone NoOperationNone No Operation12 085 12085 FLORIDA POWER & LIGHT(PMR) FPL / MARTIN6043 PMR1 0850001 1 O/GSteamNone NoOperationNone No Operation12 085 12085 FLORIDA POWER & LIGHT(PMR) FPL / MARTIN6043 PMR2 0850001 2 O/GSteamNone NoOperationNone No OperationDocumentation of the 2012 Emission InventoryMACTEC, Inc.63Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls12 085 12085 INDIANTOWNCOGENERATION, L.P.50976 GEN1 0850102 1 CoalSteamSCR SCR Scrubber Scrubber12 086 12086 FLORIDA POWER & LIGHT(PCU) CUTLER POWER610 PCU5 0250001 3 O/GSteamNoOperationNoOperationNoOperationNo Operation12 086 12086 FLORIDA POWER & LIGHT(PCU) CUTLER POWER610 PCU6 0250001 4 O/GSteamNoOperationNoOperationNoOperationNo Operation12 086 12086 FLORIDA POWER & LIGHT(PTF) TURKEY POINT621 PTP1 0250003 1 O/GSteamNone NoOperationNone No Operation12 086 12086 FLORIDA POWER & LIGHT(PTF) TURKEY POINT621 PTP2 0250003 2 O/GSteamNone NoOperationNone No Operation12 095 12095 ORLANDO UTILITIESCOMMISSION STANTONENERGY564 1 0950137 1 CoalSteamSCR SCR Scrubber Scrubber12 095 12095 ORLANDO UTILITIESCOMMISSION STANTONENERGY564 2 0950137 2 CoalSteamSCR SCR Scrubber Scrubber12 099 12099 FLORIDA POWER & LIGHT(PRV) RIVIERA POWE619 PRV3 0990042 3 O/GSteamNone None None None12 099 12099 FLORIDA POWER & LIGHT(PRV) RIVIERA POWE619 PRV4 0990042 4 O/GSteamNone None None None12 099 12099 CITY OF LAKE WORTHUTILITIES TOM G. SMITH673 S-1 0990045 7 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 099 12099 CITY OF LAKE WORTHUTILITIESTOM G. SMITH673 S-3 0990045 9 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 101 12101 PROGRESS ENERGY FLORIDAANCLOTE8048 1 1010017 1 O/GSteamNone NoOperationNone No Operation12 101 12101 PROGRESS ENERGY FLORIDAANCLOTE8048 2 1010017 2 O/GSteamNone NoOperationNone No Operation12 103 12103 PROGRESS ENERGY FLORIDABARTOW634 1 1030011 1 O/GSteamNone None None None12 103 12103 PROGRESS ENERGY FLORIDABARTOW634 2 1030011 2 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementDocumentation of the 2012 Emission InventoryMACTEC, Inc.64Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls12 103 12103 PROGRESS ENERGY FLORIDABARTOW634 3 1030011 3 O/GSteamNone None None None12 105 12105 LAKELAND ELECTRICCHARLES LARSEN675 7 1050003 4 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 105 12105 LAKELAND ELECTRIC C.D.MCINTOSH, JR.676 3 1050004 1 CoalSteamNone CombinedCycleNone CombinedCycle12 105 12105 LAKELAND ELECTRIC C.D.MCINTOSH, JR.676 3 1050004 5 CoalSteamNone CombinedCycleNone CombinedCycle12 105 12105 LAKELAND ELECTRIC C.D.MCINTOSH, JR.676 3 1050004 6 CoalSteamSCR SCR Scrubber Scrubber12 107 12107 SEMINOLE ELECTRICCOOPERATIVE, INC.136 1 1070025 1 CoalSteamSCR SCR Scrubber Scrubber12 107 12107 SEMINOLE ELECTRICCOOPERATIVE, INC.136 2 1070025 2 CoalSteamSCR SCR Scrubber Scrubber12 111 12111 FT PIERCE UTILITIESAUTHORITY FT PIERCE658 7 1110003 7 O/GSteamNoOperationNoOperationNoOperationNo Operation12 111 12111 FT PIERCE UTILITIESAUTHORITY FT PIERCE658 8 1110003 8 O/GSteamNoOperationNoOperationNoOperationNo Operation12 121 12121 PROGRESS ENERGY FLORIDASUWANNEE RIVER638 1 1210003 1 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 121 12121 PROGRESS ENERGY FLORIDASUWANNEE RIVER638 2 1210003 2 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 121 12121 PROGRESS ENERGY FLORIDASUWANNEE RIVER638 3 1210003 3 O/GSteamNone None None None12 127 12127 FLORIDA POWER & LIGHT(PSN) SANFORD POWER620 PSN3 1270009 1 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement12 127 12127 FLORIDA POWER & LIGHT(PSN) SANFORD POWER620 PSN4 1270009 2 NoOperationNoOperationNoOperationNo Operation12 129 12129 TALLAHASSEE CITYPURDOM GENERATINGSTATION689 7 1290001 7 O/GSteamNoOperationNoOperationNoOperationNo OperationDocumentation of the 2012 Emission InventoryMACTEC, Inc.65Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls13 015 13015 GEORGIA POWER COMPANY,BOWEN STEAM-ELECT703 1BLR 01500011 SG01 CoalSteamSCR SCR Scrubber95%Scrubber13 015 13015 GEORGIA POWER COMPANY,BOWEN STEAM-ELECT703 2BLR 01500011 SG02 CoalSteamSCR SCR Scrubber95%Scrubber13 015 13015 GEORGIA POWER COMPANY,BOWEN STEAM-ELECT703 3BLR 01500011 SG03 CoalSteamSCR SCR Scrubber95%Scrubber13 015 13015 GEORGIA POWER COMPANY,BOWEN STEAM-ELECT703 4BLR 01500011 SG04 CoalSteamSCR SCR Scrubber95%Scrubber13 021 13021 ARKWRIGHT 699 1 0002 1 NoOperationNoOperationNoOperationNo Operation13 021 13021 ARKWRIGHT 699 2 0002 2 NoOperationNoOperationNoOperationNo Operation13 021 13021 ARKWRIGHT 699 3 0002 3 NoOperationNoOperationNoOperationNo Operation13 021 13021 ARKWRIGHT 699 4 0002 4 NoOperationNoOperationNoOperationNo Operation13 051 13051 SAVANNAH ELECTRIC:KRAFT STEAM733 1 05100006 SG01 CoalSteamNone None None None13 051 13051 SAVANNAH ELECTRIC:KRAFT STEAM733 2 05100006 SG02 CoalSteamNone None None None13 051 13051 SAVANNAH ELECTRIC:KRAFT STEAM733 3 05100006 SG03 CoalSteamNone None None None13 051 13051 SAVANNAH ELECTRIC:KRAFT STEAM733 4 05100006 SG04 O/GSteamNoOperationNoOperationNoOperationNo Operation13 051 13051 RIVERSIDE 734 11 05100018 11 O/GSteamNone NoOperationNone No Operation13 051 13051 RIVERSIDE 734 12 05100018 12 O/GSteamNone NoOperationNone No Operation13 051 13051 RIVERSIDE 734 4 05100018 4 O/GSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.66Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls13 051 13051 RIVERSIDE 734 5 05100018 5 O/GSteamNone NoOperationNone No Operation13 051 13051 RIVERSIDE 734 6 05100018 6 O/GSteamNone NoOperationNone No Operation13 067 13067 GEORGIA POWER COMPANY,MCDONOUGH STEAM710 MB1 06700003 SGM1 CoalSteamGas Turbine None Gas Turbine Scrubber13 067 13067 GEORGIA POWER COMPANY,MCDONOUGH STEAM710 MB2 06700003 SGM2 CoalSteamGas Turbine None Gas Turbine Scrubber13 077 13077 GEORGIA POWER COMPANY,YATES STEAM-ELECTRIC728 Y1BR 07700001 SG01 CoalSteamNone None Scrubber Scrubber13 077 13077 GEORGIA POWER COMPANY,YATES STEAM-ELECTRIC728 Y2BR 07700001 SG02 CoalSteamNone None None None13 077 13077 GEORGIA POWER COMPANY,YATES STEAM-ELECTRIC728 Y3BR 07700001 SG03 CoalSteamNone None None None13 077 13077 GEORGIA POWER COMPANY,YATES STEAM-ELECTRIC728 Y4BR 07700001 SG04 CoalSteamNone None None Scrubber13 077 13077 GEORGIA POWER COMPANY,YATES STEAM-ELECTRIC728 Y5BR 07700001 SG05 CoalSteamNone None None Scrubber13 077 13077 GEORGIA POWER COMPANY,YATES STEAM-ELECTRIC728 Y6BR 07700001 SG06 CoalSteamNone None None Scrubber13 077 13077 GEORGIA POWER COMPANY,YATES STEAM-ELECTRIC728 Y7BR 07700001 SG07 CoalSteamNone None None Scrubber13 095 13095 GEORGIA POWER COMPANY,MITCHELL STEAM-ELECTRIC727 09500002 SG01 NoOperationNoOperationNoOperationNo Operation13 095 13095 GEORGIA POWER COMPANY,MITCHELL STEAM-ELECTRIC727 09500002 SG02 NoOperationNoOperationNoOperationNo Operation13 095 13095 GEORGIA POWER COMPANY,MITCHELL STEAM-ELECTRIC727 3 09500002 SG03 CoalSteamNone None None None13 103 13103 SAVANNAH ELECTRIC:MCINTOSH STEAM -ELECTRIC6124 1 10300003 SG01 CoalSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.67Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls13 115 13115 GEORGIA POWER COMPANY,HAMMOND STEAM-ELECTRIC708 1 11500003 SG01 CoalSteamNone None Scrubber95% Scrubber13 115 13115 GEORGIA POWER COMPANY,HAMMOND STEAM-ELECTRIC708 2 11500003 SG02 CoalSteamNone None Scrubber95%Scrubber13 115 13115 GEORGIA POWER COMPANY,HAMMOND STEAM-ELECTRIC708 3 11500003 SG03 CoalSteamNone None Scrubber95%Scrubber13 115 13115 GEORGIA POWER COMPANY,HAMMOND STEAM-ELECTRIC708 4 11500003 SG04 CoalSteamSCR SCR Scrubber95%Scrubber13 127 13127 GEORGIA POWER COMPANY,MCMANUS STEAM-ELECTRIC715 1 12700004 SG01 O/GSteamNoOperationNoOperationNoOperationNo Operation13 127 13127 GEORGIA POWER COMPANY,MCMANUS STEAM-ELECTRIC715 2 12700004 SG02 O/GSteamNoOperationNoOperationNoOperationNo Operation13 149 13149 GEORGIA POWER COMPANY,WANSLEY STEAM-ELECTRIC6052 1 14900001 SG01 CoalSteamSCR SCR Scrubber95%Scrubber13 149 13149 GEORGIA POWER COMPANY,WANSLEY STEAM-ELECTRIC6052 2 14900001 SG02 CoalSteamSCR SCR Scrubber95%Scrubber13 207 13207 GEORGIA POWER COMPANY,SCHERER STEAM-ELECTRIC6257 1 20700008 SG01 CoalSteamNone None None None13 207 13207 GEORGIA POWER COMPANY,SCHERER STEAM-ELECTRIC6257 2 20700008 SG02 CoalSteamNone None None None13 207 13207 GEORGIA POWER COMPANY,SCHERER STEAM-ELECTRIC6257 3 20700008 SG03 CoalSteamNone None Scrubber95%None13 207 13207 GEORGIA POWER COMPANY,SCHERER STEAM-ELECTRIC6257 4 20700008 SG04 CoalSteamNone None None None13 237 13237 GEORGIA POWER COMPANY,HARLLEE BRANCH709 1 23700008 SG01 CoalSteamNone None None Scrubber13 237 13237 GEORGIA POWER COMPANY,HARLLEE BRANCH709 2 23700008 SG02 CoalSteamNone None None Scrubber13 237 13237 GEORGIA POWER COMPANY,HARLLEE BRANCH709 3 23700008 SG03 CoalSteamSCR82.5%None None ScrubberDocumentation of the 2012 Emission InventoryMACTEC, Inc.68Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls13 237 13237 GEORGIA POWER COMPANY,HARLLEE BRANCH709 4 23700008 SG04 CoalSteamNone None None Scrubber13 297 13297 GENERIC UNIT 900113 GSC13 ORIS900113 GSC13 CoalSteamNoOperationNone NoOperationNone21 015 21015 CINCINNATI GAS & ELECTRICEAST BEND STAT6018 2 2101500029 002 CoalSteamSCR SCR Scrubber Scrubber21 041 21041 KENTUCKY UTILITIES COGHENT GENERATINGSTATION1356 1 2104100010 001 CoalSteamSCR None Scrubber Scrubber21 041 21041 KENTUCKY UTILITIES COGHENT GENERATINGSTATION1356 2 2104100010 002 CoalSteamNone None Scrubber None21 041 21041 KENTUCKY UTILITIES COGHENT GENERATINGSTATION1356 3 2104100010 003 CoalSteamSCR None Scrubber Scrubber21 041 21041 KENTUCKY UTILITIES COGHENT GENERATINGSTATION1356 4 2104100010 004 CoalSteamSCR None Scrubber Scrubber21 049 21049 EAST KY POWER COOPWILLIAM C DALE PLANT1385 1 2104900003 001 CoalSteamNone None None None21 049 21049 EAST KY POWER COOPWILLIAM C DALE PLANT1385 2 2104900003 002 CoalSteamNone None None None21 049 21049 EAST KY POWER COOPWILLIAM C DALE PLANT1385 3 2104900003 003 CoalSteamNone None None None21 049 21049 EAST KY POWER COOPWILLIAM C DALE PLANT1385 4 2104900003 004 CoalSteamNone None None None21 059 21059 OWENSBORO MUNICIPALUTILELMER SMITH STATION1374 1 2105900027 001 CoalSteamSCR SCR Scrubber Scrubber21 059 21059 OWENSBORO MUNICIPALUTILELMER SMITH STATION1374 2 2105900027 002 CoalSteamNone None Scrubber Scrubber21 091 21091 WESTERN KY ENERGY CORPCOLEMAN STATION1381 C1 2109100003 001 CoalSteamNone None Scrubber None21 091 21091 WESTERN KY ENERGY CORPCOLEMAN STATION1381 C2 2109100003 002 CoalSteamNone None Scrubber NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.69Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls21 091 21091 WESTERN KY ENERGY CORPCOLEMAN STATION1381 C3 2109100003 003 CoalSteamNone None Scrubber None21 091 21091 GENERIC UNIT 900121 GSC21 ORIS900121 GSC21 CoalSteamSCR SCR Scrubber Scrubber21 101 21101 HENDERSON MUN POW &LIGHT1372 6 2110100012 002 CoalSteamNone None None None21 101 21101 HENDERSON MUN POW &LIGHT1372 5 2110100012 5 CoalSteamNone None None None21 111 21111 LOU GAS & ELEC, CANE RUN 1363 4 0126 04 CoalSteamSCR SCR Scrubber Scrubber21 111 21111 LOU GAS & ELEC,CANE RUN1363 5 0126 05 CoalSteamSCR SCR Scrubber Scrubber21 111 21111 LOU GAS & ELEC,CANE RUN1363 6 0126 06 CoalSteamSCR SCR Scrubber Scrubber21 111 21111 LOU GAS & ELEC,MILL CREEK1364 1 0127 01 CoalSteamNone None Scrubber Scrubber21 111 21111 LOU GAS & ELEC,MILL CREEK1364 2 0127 02 CoalSteamNone None Scrubber Scrubber21 111 21111 LOU GAS & ELEC,MILL CREEK1364 3 0127 03 CoalSteamSCR SCR Scrubber Scrubber21 111 21111 LOU GAS & ELEC,MILL CREEK1364 4 0127 04 CoalSteamSCR SCR Scrubber Scrubber21 127 21127 KENTUCKY POWER COBIG SANDY PLANT1353 BSU1 2112700003 001 CoalSteamSCR SCR None Scrubber21 127 21127 KENTUCKY POWER COBIG SANDY PLANT1353 BSU2 2112700003 002 CoalSteamSCR SCR None Scrubber21 145 21145 TVA-ENVIRONMENTALAFFAIRSSHAWNEE PLANT1379 1 2114500006 001 CoalSteamNone None None None21 145 21145 TVA-ENVIRONMENTALAFFAIRSSHAWNEE PLANT1379 2 2114500006 002 CoalSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.70Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls21 145 21145 TVA-ENVIRONMENTALAFFAIRSSHAWNEE PLANT1379 3 2114500006 003 CoalSteamNone None None None21 145 21145 TVA-ENVIRONMENTALAFFAIRSSHAWNEE PLANT1379 4 2114500006 004 CoalSteamNone None None None21 145 21145 TVA-ENVIRONMENTALAFFAIRSSHAWNEE PLANT1379 5 2114500006 005 CoalSteamNone None None None21 145 21145 TVA-ENVIRONMENTALAFFAIRSSHAWNEE PLANT1379 6 2114500006 006 CoalSteamNone None None None21 145 21145 TVA-ENVIRONMENTALAFFAIRSSHAWNEE PLANT1379 7 2114500006 007 CoalSteamNone None None None21 145 21145 TVA-ENVIRONMENTALAFFAIRSSHAWNEE PLANT1379 8 2114500006 008 CoalSteamNone None None None21 145 21145 TVA-ENVIRONMENTALAFFAIRS SHAWNEE PLANT1379 9 2114500006 009 CoalSteamNone None None None21 145 21145 TVA-ENVIRONMENTALAFFAIRSSHAWNEE PLANT1379 10 2114500006 016 CoalSteamNone None None None21 161 21161 EAST KY POWER COOPSPURLOCK ST. MAYSVILLE6041 1 2116100009 001 CoalSteamSCR SCR Scrubber Scrubber21 161 21161 EAST KY POWER COOPSPURLOCK ST. MAYSVILLE6041 2 2116100009 002 CoalSteamSCR SCR Scrubber Scrubber21 167 21167 KENTUCKY UTILITIES COBROWN FACILITY1355 1 2116700001 001 CoalSteamNone None Scrubber None21 167 21167 KENTUCKY UTILITIES COBROWN FACILITY1355 2 2116700001 002 CoalSteamNone None Scrubber None21 167 21167 KENTUCKY UTILITIES COBROWN FACILITY1355 3 2116700001 003 CoalSteamNone None Scrubber None21 177 21177 KENTUCKY UTILITIES COGREEN RIVER STATION1357 4 2117700001 003 CoalSteamNone None None None21 177 21177 KENTUCKY UTILITIES COGREEN RIVER STATION1357 5 2117700001 004 CoalSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.71Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls21 177 21177 TVA PARADISE STEAM PLANT 1378 1 2117700006 001 CoalSteamSCR SCR Scrubber Scrubber21 177 21177 TVA PARADISE STEAM PLANT 1378 2 2117700006 002 CoalSteamSCR SCR Scrubber Scrubber21 177 21177 TVA PARADISE STEAM PLANT 1378 3 2117700006 003 CoalSteamSCR SCR Scrubber Scrubber21 183 21183 WESTERN KY ENERGY CORPWILSON STATION6823 W1 2118300069 001 CoalSteamSCR SCR Scrubber Scrubber21 199 21199 EAST KY POWER COOPJOHN SHERMAN COOPER1384 1 2119900005 001 CoalSteamNone None None None21 199 21199 EAST KY POWER COOPJOHN SHERMAN COOPER1384 2 2119900005 002 CoalSteamSCR SCR Scrubber Scrubber21 223 21223 LOUISVILLE GAS & ELECTRICTRIMBLE CO GEN6071 1 2122300002 001 CoalSteamSCR SCR Scrubber Scrubber21 233 21233 HENDERSON STATION 2 1382 H1 2123300001-A002 CoalSteamSCR SCR Scrubber Scrubber21 233 21233 HENDERSON STATION 2 1382 H2 2123300001-A003 CoalSteamSCR None Scrubber Scrubber21 233 21233 WESTERN KY ENERGY CORPREID1383 R1 2123300001-B001 CoalSteamNone None None None21 233 21233 WESTERN KY ENERGY CORPGREEN STATION6639 G1 2123300052 001 CoalSteamNone None Scrubber Scrubber21 233 21233 WESTERN KY ENERGY CORPGREEN STATION6639 G2 2123300052 002 CoalSteamNone None Scrubber Scrubber21 239 21239 KENTUCKY UTILITIESTYRONE FACILITY1361 5 2123900001 005 CoalSteamNone None None None28 011 28011 ENTERGY MISSISSIPPI INC,DELTA PLANT2051 1 2801100031 001 O/GSteamNone O/G EarlyRetirementNone O/G EarlyRetirement28 011 28011 ENTERGY MISSISSIPPI INC,DELTA PLANT2051 2801100031 002 None O/G EarlyRetirementNone O/G EarlyRetirementDocumentation of the 2012 Emission InventoryMACTEC, Inc.72Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls28 011 28011 ENTERGY MISSISSIPPI INC,DELTA PLANT2051 2 2801100031 003 O/GSteamNone O/G EarlyRetirementNone O/G EarlyRetirement28 011 28011 ENTERGY MISSISSIPPI INC,DELTA PLANT2051 2801100031 004 None O/G EarlyRetirementNone O/G EarlyRetirement28 019 28019 CHOCTAW GENERATION LLP,RED HILLS GENERATING55076 AA001 2801900011 001A CoalSteamSCR SCR Scrubber Scrubber28 035 28035 MISSISSIPPI POWERCOMPANY,PLANT EATON2046 2803500038 001 O/GSteamNoOperationNoOperationNoOperationNo Operation28 035 28035 MISSISSIPPI POWERCOMPANY,PLANT EATON2046 2803500038 002 O/GSteamNoOperationNoOperationNoOperationNo Operation28 035 28035 MISSISSIPPI POWERCOMPANY,PLANT EATON2046 2803500038 003 O/GSteamNoOperationNoOperationNoOperationNo Operation28 047 28047 MISSISSIPPI POWERCOMPANY,PLANT JACK WATSON2049 1 2804700055 001 O/GSteamNoOperationNoOperationNoOperationNo Operation28 047 28047 MISSISSIPPI POWERCOMPANY,PLANT JACK WATSON2049 2 2804700055 002 O/GSteamNoOperationNoOperationNoOperationNo Operation28 047 28047 MISSISSIPPI POWERCOMPANY,PLANT JACK WATSON2049 3 2804700055 003 O/GSteamNoOperationNoOperationNoOperationNo Operation28 047 28047 MISSISSIPPI POWERCOMPANY, PLANT JACKWATSON2049 4 2804700055 004 CoalSteamNone SCR None None28 047 28047 MISSISSIPPI POWERCOMPANY,PLANT JACK WATSON2049 5 2804700055 005 CoalSteamNone SCR None None28 049 28049 ENTERGY MISSISSIPPI INC,REX BROWN PLANT2053 4 2804900112 001 O/GSteamNone O/G EarlyRetirementNone O/G EarlyRetirement28 049 28049 ENTERGY MISSISSIPPI INC,REX BROWN PLANT2053 3 2804900112 002 O/GSteamNone O/G EarlyRetirementNone O/G EarlyRetirement28 059 28059 MISSISSIPPI POWERCOMPANY,PLANT DANIEL6073 1 2805900090 001 CoalSteamNone SCR None None28 059 28059 MISSISSIPPI POWERCOMPANY,6073 2 2805900090 002 CoalSteamNone SCR None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.73Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012ControlsPLANT DANIEL28 067 28067 MOSELLE SOUTH MISSISSIPPIELECTRIC POWERASSOCIATION2070 1 2806700035 001 O/GSteamNoOperationNoOperationNoOperationNo Operation28 067 28067 MOSELLE SOUTH MISSISSIPPIELECTRIC POWERASSOCIATION2070 2 2806700035 002 O/GSteamNoOperationNoOperationNoOperationNo Operation28 067 28067 MOSELLE SOUTH MISSISSIPPIELECTRIC POWERASSOCIATION2070 3 2806700035 003 O/GSteamNoOperationNoOperationNoOperationNo Operation28 073 28073 RD MORROW SOUTHMISSISSIPPI ELECTRIC POWERASSOCIATION6061 1 2807300021 001 CoalSteamNone SCR Scrubber Scrubber28 073 28073 RD MORROW SOUTHMISSISSIPPI ELECTRIC POWERASSOCIATION6061 2 2807300021 002 CoalSteamNone SCR Scrubber Scrubber28 075 28075 MISSISSIPPI POWERCOMPANY,PLANT SWEATT2048 1 2807500032 001 O/GSteamNoOperationNoOperationNoOperationNo Operation28 075 28075 MISSISSIPPI POWERCOMPANY,PLANT SWEATT2048 2 2807500032 002 O/GSteamNoOperationNoOperationNoOperationNo Operation28 083 28083 GREENWOOD UTILITIES,HENDERSON STATION2062 H1 2808300048 001 O/GSteamNone None None No Operation28 083 28083 GREENWOOD UTILITIES,HENDERSON STATION2062 H3 2808300048 003 O/GSteamNone None None No Operation28 149 28149 ENTERGY MISSISSIPPI INC,BAXTER WILSON2050 1 2814900027 001 O/GSteamNone O/G EarlyRetirementNone O/G EarlyRetirement28 149 28149 ENTERGY MISSISSIPPI INC,BAXTER WILSON2050 2 2814900027 002 O/GSteamNone O/G EarlyRetirementNone O/G EarlyRetirement28 151 28151 ENTERGY MISSISSIPPI INC,GERALD ANDRUS8054 1 2815100048 001 O/GSteamNone NoOperationNone No Operation28 163 28163 YAZOO CITY PUBLIC SERVICECOMMISSION2067 3 2816300005 001 O/GSteamO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirementO/G EarlyRetirement37 017 37017 ELIZABETHTOWN POWER,LLC10380 UNIT1 3701700043 G-17A CoalSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.74Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls37 017 37017 ELIZABETHTOWN POWER,LLC10380 UNIT2 3701700043 G-17BNone None None None37 019 37019 COGENTRIX OF NORTHCAROLINA INC - SOUTHPORT10378 GEN1 3701900067 G-29 CoalSteamNone None None None37 019 37019 COGENTRIX OF NORTHCAROLINA INC - SOUTHPORT10378 GEN2 3701900067 G-30 CoalSteamNone None None None37 021 37021 CAROLINA POWER & LIGHTASHEVILLE STEAM2706 1 628 1 CoalSteamSCR SCR Scrubber Scrubber37 021 37021 CAROLINA POWER & LIGHTASHEVILLE STEAM2706 2 628 2 CoalSteamSCR SCR Scrubber Scrubber37 025 37025 KANNAPOLIS ENERGYPARTNERS LLC3702500113 G-2 CoalSteamNone None None None37 025 37025 KANNAPOLIS ENERGYPARTNERS LLC3702500113 G-3 CoalSteamNone None None None37 035 37035 DUKE ENERGYCORPORATIONMARSHALL STEAM2727 3 3703500073 G-1 CoalSteamSNCR SCR Scrubber Scrubber37 035 37035 DUKE ENERGYCORPORATIONMARSHALL STEAM2727 4 3703500073 G-2 CoalSteamSNCR SCR Scrubber Scrubber37 035 37035 DUKE ENERGYCORPORATIONMARSHALL STEAM2727 1 3703500073 G-4 CoalSteamSNCR SCR Scrubber Scrubber37 035 37035 DUKE ENERGYCORPORATIONMARSHALL STEAM2727 2 3703500073 G-5 CoalSteamSNCR SCR Scrubber Scrubber37 037 37037 PROGRESS ENERGYCAROLINASCAPE FEAR2708 5 3703700063 G-1 CoalSteamSNCR SNCR None Scrubber37 037 37037 PROGRESS ENERGYCAROLINASCAPE FEAR2708 6 3703700063 G-2 CoalSteamSNCR SNCR None Scrubber37 045 37045 GENERIC UNIT 900137 GSC37 ORIS900137 GSC37 CoalSteamNoOperationNoOperationNoOperationNo Operation37 055 37055 GENERIC UNIT 900237 GSC37 ORIS900237 GSC37 CoalSteamNoOperationNoOperationNoOperationNo OperationDocumentation of the 2012 Emission InventoryMACTEC, Inc.75Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls37 055 37055 GENERIC UNIT 900337 GSC37 ORIS900337 GSC37 CoalSteamNoOperationNoOperationNoOperationNo Operation37 061 37061 GENERIC UNIT 900437 GSC37 ORIS900437 GSC37 CoalSteamNoOperationNoOperationNoOperationNo Operation37 083 37083 GENERIC UNIT 900537 GSC37 ORIS900537 GSC37 CoalSteamNoOperationNoOperationNoOperationNo Operation37 083 37083 GENERIC UNIT 900637 GSC37 ORIS900637 GSC37 CoalSteamNoOperationNoOperationNoOperationNo Operation37 071 37071 DUKE ENERGYCORPORATIONALLEN STEAM2718 1 3707100039 G-14 CoalSteamSNCR SNCR Scrubber Scrubber37 071 37071 DUKE ENERGYCORPORATIONALLEN STEAM2718 2 3707100039 G-15 CoalSteamSNCR SNCR Scrubber Scrubber37 071 37071 DUKE ENERGYCORPORATIONALLEN STEAM2718 3 3707100039 G-16 CoalSteamSNCR SCR Scrubber Scrubber37 071 37071 DUKE ENERGYCORPORATIONALLEN STEAM2718 4 3707100039 G-17 CoalSteamSNCR SCR Scrubber Scrubber37 071 37071 DUKE ENERGYCORPORATIONALLEN STEAM2718 5 3707100039 G-18 CoalSteamSNCR SCR Scrubber Scrubber37 071 37071 DUKE ENERGYCORPORATIONRIVERBEND STEAM2732 7 3707100040 G-17 CoalSteamSNCR SNCR None None37 071 37071 DUKE ENERGYCORPORATIONRIVERBEND STEAM2732 8 3707100040 G-18 CoalSteamSNCR SNCR None None37 071 37071 DUKE ENERGYCORPORATIONRIVERBEND STEAM2732 9 3707100040 G-19 CoalSteamSNCR SNCR None None37 071 37071 DUKE ENERGYCORPORATIONRIVERBEND STEAM2732 10 3707100040 G-20 CoalSteamSNCR SNCR None None37 083 37083 ROANOKE VALLEY ENERGYFACILITY3708300174 G-27 CoalSteamNone None None None37 083 37083 ROANOKE VALLEY ENERGYFACILITY3708300174 G-7 CoalSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.76Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls37 129 37129 L V SUTTON STEAMELECTRIC PLANT2713 1 3712900036 G-187 CoalSteamNone SNCR None None37 129 37129 L V SUTTON STEAMELECTRIC PLANT2713 2 3712900036 G-188 CoalSteamNone SCR None None37 129 37129 L V SUTTON STEAMELECTRIC PLANT2713 3 3712900036 G-189 CoalSteamNone SCR None Scrubber37 145 37145 CP&L - ROXBORO STEAMELECTRIC PLANT2712 1 3714500029 G-29 CoalSteamSCR SCR Scrubber Scrubber37 145 37145 CP&L - ROXBORO STEAMELECTRIC PLANT2712 2 3714500029 G-30 CoalSteamSCR SCR Scrubber Scrubber37 145 37145 CP&L - ROXBORO STEAMELECTRIC PLANT2712 3A 3714500029 G-35A CoalSteamSCR SCR Scrubber Scrubber37 145 37145 CP&L - ROXBORO STEAMELECTRIC PLANT2712 3B 3714500029 G-35B CoalSteamSCR SCR Scrubber Scrubber37 145 37145 CP&L - ROXBORO STEAMELECTRIC PLANT2712 4A 3714500029 G-36A CoalSteamSCR SCR Scrubber Scrubber37 145 37145 CP&L - ROXBORO STEAMELECTRIC PLANT2712 4B 3714500029 G-36B CoalSteamSCR SCR Scrubber Scrubber37 145 37145 CP&L - MAYO FACILITY 6250 1A 3714500045 G-46A CoalSteamSCR SCR Scrubber Scrubber37 145 37145 CP&L - MAYO FACILITY 6250 1B 3714500045 G-46B CoalSteamSCR SCR Scrubber Scrubber37 155 37155 PROGRESS ENERGYCAROLINAS, INC., W.H.WEATHERSPOON2716 1 3715500147 G-24 CoalSteamNone SNCR None None37 155 37155 PROGRESS ENERGYCAROLINAS, INC., W.H.WEATHERSPOON2716 2 3715500147 G-25 CoalSteamNone SNCR None None37 155 37155 PROGRESS ENERGYCAROLINAS, INC., W.H.WEATHERSPOON2716 3 3715500147 G-26 CoalSteamNone SNCR None None37 155 37155 LUMBERTON POWER, LLC 10382 UNIT1 3715500166 G-17A CoalSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.77Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls37 155 37155 LUMBERTON POWER, LLC 10382 UNIT23715500166 G-17B NoneNone None None37 157 37157 DUKE ENERGY CORPDAN RIVER STEAM2723 3 3715700015 G-21 CoalSteamNone SNCR None None37 157 37157 DUKE ENERGY CORPDAN RIVER STEAM2723 1 3715700015 G-22 CoalSteamNone SNCR None None37 157 37157 DUKE ENERGY CORPDANRIVER STEAM2723 2 3715700015 G-23 CoalSteamNone SNCR None None37 159 37159 DUKE ENERGYCORPORATIONBUCK STEAM2720 5 3715900004 G-1 CoalSteamNoOperationSNCR NoOperationNone37 159 37159 DUKE ENERGYCORPORATIONBUCK STEAM2720 6 3715900004 G-2 CoalSteamNoOperationSNCR NoOperationNone37 159 37159 DUKE ENERGYCORPORATIONBUCK STEAM2720 7 3715900004 G-3 CoalSteamNoOperationSNCR NoOperationNone37 159 37159 DUKE ENERGYCORPORATIONBUCK STEAM2720 8 3715900004 G-4 CoalSteamSNCR SNCR None None37 159 37159 DUKE ENERGYCORPORATIONBUCK STEAM2720 9 3715900004 G-5 CoalSteamSNCR SNCR None None37 161 37161 DUKE ENERGYCORPORATIONCLIFFSIDE STEAM2721 1 3716100028 G-82 CoalSteamNoOperationSNCR NoOperationNone37 161 37161 DUKE ENERGYCORPORATIONCLIFFSIDE STEAM2721 2 3716100028 G-83 CoalSteamNoOperationSNCR NoOperationNone37 161 37161 DUKE ENERGYCORPORATIONCLIFFSIDE STEAM2721 3 3716100028 G-84 CoalSteamNoOperationSNCR NoOperationNone37 161 37161 DUKE ENERGYCORPORATIONCLIFFSIDE STEAM2721 4 3716100028 G-85 CoalSteamNoOperationSNCR NoOperationNone37 161 37161 DUKE ENERGYCORPORATIONCLIFFSIDE STEAM2721 5 3716100028 G-86 CoalSteamSCR SCR Scrubber ScrubberDocumentation of the 2012 Emission InventoryMACTEC, Inc.78Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls37 161 37161 DUKE ENERGYCORPORATIONCLIFFSIDE STEAM2721 6 3716100028 G-87 CoalSteamSCR NoOperationScrubber No Operation37 161 37161 DUKE ENERGYCORPORATIONCLIFFSIDE STEAM2721 7 3716100028 G-88 NoOperationNoOperationNoOperationNo Operation37 169 37169 DUKE ENERGY CORPBELEWS CREEK STEAM8042 1 3716900004 G-17 CoalSteamSCR SCR Scrubber Scrubber37 169 37169 DUKE ENERGY CORPBELEWS CREEK STEAM8042 2 3716900004 G-18 CoalSteamSCR SCR Scrubber Scrubber37 191 37191 PROGRESS ENERGYF LEE PLANT2709 1 3719100017 G-2 CoalSteamNone SNCR None None37 191 37191 PROGRESS ENERGYF LEE PLANT2709 2 3719100017 G-3 CoalSteamNone SNCR None None37 191 37191 PROGRESS ENERGYF LEEPLANT2709 3 3719100017 G-4 CoalSteamNone SCR None Scrubber45 003 45003 SCE&G:URQUHART 3295 URQ3 0080-0011 003 CoalSteamNone None None None45 003 45003 SCE&G:SRS AREA D 0080-0044 001 CoalSteamNone None None None45 003 45003 SCE&G:SRS AREA D 0080-0044 002 0 0 0 045 003 45003 SCE&G:SRS AREA D 0080-0044 003 0 0 0 045 003 45003 SCE&G:SRS AREA D 0080-0044 004 0 0 0 045 007 45007 DUKE ENERGY:LEE 3264 1 0200-0004 001 CoalSteamNone None None None45 007 45007 DUKE ENERGY:LEE 3264 2 0200-0004 002 CoalSteamNone None None None45 007 45007 DUKE ENERGY:LEE 3264 3 0200-0004 003 CoalSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.79Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls45 015 45015 SANTEE COOPER JEFFERIES 3319 1 0420-0003 001 O/GSteamNone NoOperationNone No Operation45 015 45015 SANTEE COOPER JEFFERIES 3319 2 0420-0003 002 O/GSteamNone NoOperationNone No Operation45 015 45015 SANTEE COOPER JEFFERIES 3319 3 0420-0003 003 CoalSteamNone SCR None None45 015 45015 SANTEE COOPER JEFFERIES 3319 4 0420-0003 004 CoalSteamNone None None None45 015 45015 SCE&G:WILLIAMS 3298 WIL1 0420-0006 001 CoalSteamSCR SCR Scrubber Scrubber45 015 45015 SANTEE COOPER CROSS 130 1 0420-0030 001 CoalSteamSCR SCR ScrubberUpgradeScrubber45 015 45015 SANTEE COOPER CROSS 130 2 0420-0030 002 CoalSteamSCR SCR ScrubberUpgradeScrubber45 015 45015 SANTEE COOPER CROSS 130 3 0420-0030 3 CoalSteamSCR SCR Scrubber Scrubber45 015 45015 SANTEE COOPER CROSS 130 4 0420-0030 4 CoalSteamSCR NoOperationScrubber No Operation45 029 45029 SCE&G:CANADYS 3280 CAN1 0740-0002 001 CoalSteamNone None None None45 029 45029 SCE&G:CANADYS 3280 CAN2 0740-0002 002 CoalSteamNone None None None45 029 45029 SCE&G:CANADYS 3280 CAN3 0740-0002 003 CoalSteamNone None Scrubber None45 031 45031 PROGRESS ENERGYROBINSON STATION3251 1 0820-0002 001 CoalSteamNone None None None45 043 45043 SANTEE COOPER WINYAH 6249 1 1140-0005 001 CoalSteamSCR SCR Scrubber Scrubber45 043 45043 SANTEE COOPER WINYAH 6249 2 1140-0005 002 CoalSteamSCR SCR Scrubber ScrubberDocumentation of the 2012 Emission InventoryMACTEC, Inc.80Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls45 043 45043 SANTEE COOPER WINYAH 6249 3 1140-0005 003 CoalSteamSCR SCR ScrubberUpgradeScrubber45 043 45043 SANTEE COOPER WINYAH 6249 4 1140-0005 004 CoalSteamSCR SCR ScrubberUpgradeScrubber45 051 45051 SANTEE COOPER GRAINGER 3317 1 1340-0003 001 CoalSteamNone None None None45 051 45051 SANTEE COOPER GRAINGER 3317 2 1340-0003 002 CoalSteamNone None None None45 063 45063 SCE&G:MCMEEKIN 3287 MCM1 1560-0003 001 CoalSteamNone None None None45 063 45063 SCE&G:MCMEEKIN 3287 MCM2 1560-0003 002 CoalSteamNone None None None45 075 45075 SCE&G:COPE 7210 COP1 1860-0044 001 CoalSteamNone None Scrubber Scrubber45 079 45079 SCE&G:WATEREE 3297 WAT1 1900-0013 001 CoalSteamSCR SCR Scrubber None45 079 45079 SCE&G:WATEREE 3297 WAT2 1900-0013 002 CoalSteamSCR SCR Scrubber Scrubber45 029 45029 GENERIC UNIT 900145 GSC45 ORIS900145 GSC45 CoalSteamNoOperationNoOperationNoOperationNo Operation45 031 45031 GENERIC UNIT 900245 GSC45 ORIS900245 GSC45 CoalSteamNoOperationNoOperationNoOperationNo Operation45 031 45031 GENERIC UNIT 900345 GSC45 ORIS900345 GSC45 CoalSteamNoOperationNoOperationNoOperationNo Operation45 039 45039 GENERIC UNIT 900445 GSC45 ORIS900445 GSC45 CoalSteamNoOperationNoOperationNoOperationNo Operation45 043 45043 GENERIC UNIT 900545 GSC45 ORIS900545 GSC45 CoalSteamNoOperationNoOperationNoOperationNo Operation47 001 47001 TVA BULL RUN FOSSIL PLANT 3396 1 0009 001 CoalSteamSCR SCR Scrubber ScrubberDocumentation of the 2012 Emission InventoryMACTEC, Inc.81Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls47 073 47073 TVA JOHN SEVIER FOSSILPLANT3405 1 0007 001 CoalSteamNone None None None47 073 47073 TVA JOHN SEVIER FOSSILPLANT3405 2 0007 002 CoalSteamNone None None None47 073 47073 TVA JOHN SEVIER FOSSILPLANT3405 3 0007 003 CoalSteamNone None None None47 073 47073 TVA JOHN SEVIER FOSSILPLANT3405 4 0007 004 CoalSteamNone None None None47 085 47085 TVA JOHNSONVILLE FOSSILPLANT3406 1 0011 001 CoalSteamNone SCR None None47 085 47085 TVA JOHNSONVILLE FOSSILPLANT3406 2 0011 002 CoalSteamNone SCR None None47 085 47085 TVA JOHNSONVILLE FOSSILPLANT3406 3 0011 003 CoalSteamNone SCR None None47 085 47085 TVA JOHNSONVILLE FOSSILPLANT3406 4 0011 004 CoalSteamNone SCR None None47 085 47085 TVA JOHNSONVILLE FOSSILPLANT3406 5 0011 005 CoalSteamNone SCR None None47 085 47085 TVA JOHNSONVILLE FOSSILPLANT3406 6 0011 006 CoalSteamNone SCR None None47 085 47085 TVA JOHNSONVILLE FOSSILPLANT3406 7 0011 007 CoalSteamNone SCR None None47 085 47085 TVA JOHNSONVILLE FOSSILPLANT3406 8 0011 008 CoalSteamNone SCR None None47 085 47085 TVA JOHNSONVILLE FOSSILPLANT3406 9 0011 009 CoalSteamNone SCR None None47 085 47085 TVA JOHNSONVILLE FOSSILPLANT3406 10 0011 010 CoalSteamNone SCR None None47 145 47145 TVA KINGSTON FOSSILPLANT3407 1 0013 001 CoalSteamSCR SCR Scrubber NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.82Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls47 145 47145 TVA KINGSTON FOSSILPLANT3407 2 0013 002 CoalSteamSCR SCR Scrubber None47 145 47145 TVA KINGSTON FOSSILPLANT3407 3 0013 003 CoalSteamSCR SCR Scrubber None47 145 47145 TVA KINGSTON FOSSILPLANT3407 4 0013 004 CoalSteamSCR SCR Scrubber None47 145 47145 TVA KINGSTON FOSSILPLANT3407 5 0013 005 CoalSteamSCR SCR Scrubber None47 145 47145 TVA KINGSTON FOSSILPLANT3407 6 0013 006 CoalSteamSCR SCR Scrubber None47 145 47145 TVA KINGSTON FOSSILPLANT3407 7 0013 007 CoalSteamSCR SCR Scrubber None47 145 47145 TVA KINGSTON FOSSILPLANT3407 8 0013 008 CoalSteamSCR SCR Scrubber None47 145 47145 TVA KINGSTON FOSSILPLANT3407 9 0013 009 CoalSteamSCR None Scrubber None47 157 47157 ALLEN FOSSIL PLANT 3393 1 00528 Boilr1 CoalSteamSCR SCR None None47 157 47157 ALLEN FOSSIL PLANT 3393 2 00528 Boilr2 CoalSteamSCR SCR None None47 157 47157 ALLEN FOSSIL PLANT 3393 3 00528 Boilr3 CoalSteamSCR SCR None None47 161 47161 TVA CUMBERLAND FOSSILPLANT3399 1 0011 001 CoalSteamSCR SCR Scrubber Scrubber47 161 47161 TVA CUMBERLAND FOSSILPLANT3399 2 0011 002 CoalSteamSCR SCR Scrubber Scrubber47 165 47165 TVA GALLATIN FOSSILPLANT3403 1 0025 001 CoalSteamNone None None None47 165 47165 TVA GALLATIN FOSSILPLANT3403 2 0025 002 CoalSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.83Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls47 165 47165 TVA GALLATIN FOSSILPLANT3403 3 0025 003 CoalSteamNone None None None47 165 47165 TVA GALLATIN FOSSILPLANT3403 4 0025 004 CoalSteamNone None None None51 031 51031 DOMINION - ALTAVISTAPOWER STATION10773 1 00156 1 CoalSteamSNCR SNCR Scrubber Scrubber51 031 51031 DOMINION - ALTAVISTAPOWER STATION10773 2 00156 251 041 51041 DOMINION - CHESTERFIELDPOWER STATION3797 3 00002 3 CoalSteamNone None Scrubber Scrubber51 041 51041 DOMINION - CHESTERFIELDPOWER STATION3797 4 00002 4 CoalSteamSCR None Scrubber Scrubber51 041 51041 DOMINION - CHESTERFIELDPOWER STATION3797 5 00002 6 CoalSteamSCR SCR Scrubber Scrubber51 041 51041 DOMINION - CHESTERFIELDPOWER STATION3797 6 00002 8 CoalSteamSCR SCR Scrubber Scrubber51 065 51065 DOMINION - BREMO POWERSTATION3796 3 00001 1 CoalSteamNone None None None51 065 51065 DOMINION - BREMO POWERSTATION3796 4 00001 2 CoalSteamSNCR SNCR None None51 071 51071 AMERICAN ELECTRIC POWERGLEN LYN3776 51 00002 1 CoalSteamNone None None None51 071 51071 AMERICAN ELECTRIC POWERGLEN LYN3776 52 00002 2 CoalSteamNone None None None51 071 51071 AMERICAN ELECTRIC POWERGLEN LYN3776 6 00002 3 CoalSteamNone None None None51 083 51083 DOMINION - CLOVER POWERSTATION7213 1 00046 1 CoalSteamSNCR SNCR Scrubber Scrubber51 083 51083 DOMINION - CLOVER POWERSTATION7213 2 00046 2 CoalSteamSNCR SNCR Scrubber ScrubberDocumentation of the 2012 Emission InventoryMACTEC, Inc.84Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls51 099 51099 BIRCHWOOD POWERPARTNERS, L.P.54304 1 00012 1 CoalSteamSCR SCR Scrubber Scrubber51 117 51117 Mecklenburg Cogeneration Facility 52007 GEN1 00051 1 CoalSteamNone None Scrubber Scrubber51 117 51117 Mecklenburg Cogeneration Facility 52007 GEN2 00051 2 CoalSteamNone None Scrubber Scrubber51 153 51153 DOMINION - POSSUM POINT 3804 3 00002 3 CoalSteamNone CombinedCycleNone CombinedCycle51 153 51153 DOMINION - POSSUM POINT 3804 4 00002 4 CoalSteamNone CombinedCycleNone CombinedCycle51 153 51153 DOMINION - POSSUM POINT 3804 5 00002 5 O/GSteamNone NoOperationNone No Operation51 153 51153 DOMINION - POSSUM POINT 3804 6 00002 CombinedCycleCombinedCycleCombinedCycleCombinedCycleCombinedCycle51 167 51167 AMERICAN ELECTRIC POWERCLINCH RIVER PLANT3775 1 00003 1 CoalSteamNone None None None51 167 51167 AMERICAN ELECTRIC POWERCLINCH RIVER PLANT3775 2 00003 2 CoalSteamNone None None None51 167 51167 AMERICAN ELECTRIC POWERCLINCH RIVER PLANT3775 3 00003 3 CoalSteamNone None None None51 175 51175 LG&E Westmoreland Southampton 10774 GEN1 00051 1 CoalSteamNone None Scrubber Scrubber51 199 51199 DOMINION - YORKTOWNPOWER STATION3809 3 00001 3 O/GSteamSNCR NoOperationNone No Operation51 199 51199 DOMINION - YORKTOWNPOWER STATION3809 2 00001 5 CoalSteamSNCR SNCR None None51 199 51199 DOMINION - YORKTOWNPOWER STATION3809 1 00001 6 CoalSteamSNCR SNCR None None51 510 51510 POTOMAC RIVERGENERATING STATION3788 1 00003 1 CoalSteamSNCR Coal EarlyRetirementNone Coal EarlyRetirementDocumentation of the 2012 Emission InventoryMACTEC, Inc.85Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls51 510 51510 POTOMAC RIVERGENERATING STATION3788 2 00003 2 CoalSteamSNCR Coal EarlyRetirementNone Coal EarlyRetirement51 510 51510 POTOMAC RIVERGENERATING STATION3788 3 00003 3 CoalSteamSNCR None None None51 510 51510 POTOMAC RIVERGENERATING STATION3788 4 00003 4 CoalSteamSNCR None None None51 510 51510 POTOMAC RIVERGENERATING STATION3788 5 00003 5 CoalSteamSNCR None None None51 550 51550 DOMINION - CHESAPEAKE 3803 1 00026 1 CoalSteamSNCR SNCR Low S Coal None51 550 51550 DOMINION - CHESAPEAKE 3803 2 00026 2 CoalSteamSNCR SNCR Low S Coal None51 550 51550 DOMINION - CHESAPEAKE 3803 3 00026 3 CoalSteamSCR None Low S Coal None51 550 51550 DOMINION - CHESAPEAKE 3803 4 00026 4 CoalSteamSCR None Low S Coal None51 670 51670 James River Cogen /Cogentrix Hopewell10377 GEN1 00055/ORIS103771 CoalSteamNone None Scrubber None51 670 51670 James River Cogen /Cogentrix Hopewell10377 GEN2 00055/ORIS103772 CoalSteamNone None Scrubber None51 670 51670 LG&E Westmoreland Hopewell 10771 GEN1 ORIS10771 1 CoalSteamSNCR SNCR Scrubber Scrubber51 740 51740 Cogentrix Portsmouth 10071 GEN1 00081 /ORIS100711 to 3 CoalSteamNone None Scrubber None51 740 51740 Cogentrix Portsmouth 10071 GEN2 00081 /ORIS100714 to 6 CoalSteamNone None Scrubber None51 760 51740 Cogentrix of RichmondIncorporated54081 GEN1 00399 /ORIS540811 CoalSteamNone None Scrubber Scrubber51 760 51760 Cogentrix of RichmondIncorporated54081 GEN2 00399 /ORIS540812 CoalSteamNone None Scrubber ScrubberDocumentation of the 2012 Emission InventoryMACTEC, Inc.86Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls51 760 51760 Cogentrix of RichmondIncorporated54081 GEN3 00399 /ORIS540813 CoalSteamNone None Scrubber Scrubber51 760 51760 Cogentrix of RichmondIncorporated54081 GEN4 00399 /ORIS540814 CoalSteamNone None Scrubber Scrubber51 159 51159 GENERIC UNIT 900151 GSC51 ORIS900151 GSC51 CoalSteamNoOperationNoOperationNoOperationNo Operation51 167 51167 GENERIC UNIT 900251 GSC51 ORIS900251 GSC51 CoalSteamNoOperationNoOperationNoOperationNo Operation51 195 51195 GENERIC UNIT 900251 GSC51 ORIS900251 GSC51 CoalSteamSCR NoOperationScrubber No Operation51 175 51175 GENERIC UNIT 900351 GSC51 ORIS900351 GSC51 CoalSteamNoOperationNoOperationNoOperationNo Operation51 175 51175 GENERIC UNIT 900451 GSC51 ORIS900451 GSC51 CoalSteamNoOperationNoOperationNoOperationNo Operation51 181 51181 GENERIC UNIT 900551 GSC51 ORIS900551 GSC51 CoalSteamNoOperationNoOperationNoOperationNo Operation54 023 54023 MOUNT STORM POWERPLANT3954 1 0003 001 CoalSteamSCR SCR Scrubber Scrubber54 023 54023 MOUNT STORM POWERPLANT3954 2 0003 002 CoalSteamSCR SCR Scrubber Scrubber54 023 54023 MOUNT STORM POWERPLANT3954 3 0003 003 CoalSteamSCR SCR Scrubber Scrubber54 023 54023 NORTH BRANCH POWERSTATION7537 1A 0014 001 CoalSteamNone None None None54 023 54023 NORTH BRANCH POWERSTATION7537 1B 0014 002 CoalSteamNone None None None54 025 54025 WESTERN GREENBRIER 00066 GEN1 CoalSteamNoOperationNoOperationNoOperationNo Operation54 033 54033 MONONGAHELA POWER COHARRISON3944 1 0015 001 CoalSteamSCR SCR Scrubber ScrubberDocumentation of the 2012 Emission InventoryMACTEC, Inc.87Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls54 033 54033 MONONGAHELA POWER COHARRISON3944 2 0015 002 CoalSteamSCR SCR Scrubber Scrubber54 033 54033 MONONGAHELA POWER COHARRISON3944 3 0015 003 CoalSteamSCR SCR Scrubber Scrubber54 039 54039 APPALACHIAN POWERKANAWHA RIVER PLANT3936 1 0006 001 CoalSteamNone None None None54 039 54039 APPALACHIAN POWERKANAWHA RIVER PLANT3936 2 0006 002 CoalSteamNone None None None54 049 54049 MONONGAHELA POWER CO.RIVESVILLE POWER3945 7 0009 001 CoalSteamNone Coal EarlyRetirementNone Coal EarlyRetirement54 049 54049 MONONGAHELA POWERCO.RIVESVILLE POWER3945 8 0009 002 CoalSteamNone Coal EarlyRetirementNone Coal EarlyRetirement54 049 54049 AMERICAN BITUMINOUSPOWERGRANT TOWN PLT10151 0026 001 0 0 Scrubber Scrubber54 049 54049 GRANT TOWN POWER PLANT 10151 GEN1 ORIS10151 GEN1 CoalSteamSNCR None Scrubber Scrubber54 051 54051 OHIO POWERMITCHELL PLANT3948 1 0005 001 CoalSteamSCR SCR Scrubber Scrubber54 051 54051 OHIO POWERMITCHELL PLANT3948 2 0005 002 CoalSteamSCR SCR Scrubber Scrubber54 051 54051 OHIO POWERKAMMER PLANT3947 1 0006 001 CoalSteamNone SCR None Scrubber54 051 54051 OHIO POWERKAMMER PLANT3947 2 0006 002 CoalSteamNone SCR None Scrubber54 051 54051 OHIO POWERKAMMER PLANT3947 3 0006 003 CoalSteamNone SCR None Scrubber54 053 54053 APPALACHIAN POWER CO.PHILIP SPORN PLANT3938 11 0001 001 CoalSteamNone None None None54 053 54053 APPALACHIAN POWER CO.PHILIP SPORN PLANT3938 21 0001 002 CoalSteamNone None None NoneDocumentation of the 2012 Emission InventoryMACTEC, Inc.88Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls54 053 54053 APPALACHIAN POWER CO.PHILIP SPORN PLANT3938 31 0001 003 CoalSteamNone None None None54 053 54053 APPALACHIAN POWER CO.PHILIP SPORN PLANT3938 41 0001 004 CoalSteamNone None None None54 053 54053 APPALACHIAN POWER CO.PHILIP SPORN PLANT3938 51 0001 005 CoalSteamNone None None None54 053 54053 APPALACHIAN POWERMOUNTAINEER PLANT6264 1 0009 CoalSteamSCR SCR Scrubber Scrubber54 061 54061 MONONGAHELA POWER CO.FORT MARTIN POWER3943 1 0001 001 CoalSteamSNCR SNCR Scrubber Scrubber54 061 54061 MONONGAHELA POWER CO.FORT MARTIN POWER3943 2 0001 002 CoalSteamSNCR SNCR Scrubber Scrubber54 061 54061 MORGANTOWN ENERGYASSOCIATES0027 04354 061 54061 MORGANTOWN ENERGYFACILITY10743 GEN1 ORIS10743 GEN1 CoalSteamNone None None None54 061 54061 LONGVIEW 00134 GEN1 CoalSteamSCR NoOperationScrubber No Operation54 061 54061 GENERIC UNIT 900154 GSC54 ORIS900154 GSC54 CoalSteamNoOperationSCR NoOperationScrubber54 073 54073 MONONGAHELA POWER CO.WILLOW ISLAND3946 1 0004 001 CoalSteamNone Coal EarlyRetirementNone Coal EarlyRetirement54 073 54073 MONONGAHELA POWER CO.WILLOW ISLAND3946 2 0004 002 CoalSteamNone SCR None Scrubber54 073 54073 MONONGAHELA POWER COPLEASANTS POWER STATION6004 1 0005 001 CoalSteamSCR SCR ScrubberUpgradeScrubber54 073 54073 MONONGAHELA POWER COPLEASANTS POWER STATION6004 2 0005 002 CoalSteamSCR SCR ScrubberUpgradeScrubber54 077 54077 MONONGAHELA POWER COALBRIGHT3942 1 0001 001 CoalSteamNone Coal EarlyRetirementNone Coal EarlyRetirementDocumentation of the 2012 Emission InventoryMACTEC, Inc.89Appendix A - Comparison of 2012 EGU Controls for Coal and Oil/Gas Steam Plants (with CAIR Controls)FIPSFIPSFacility NameORISIDBLRIDSITEIDUNITIDPlantTypeVISTASNOx2012ControlsIPMNOx2012ControlsVISTASSO22012ControlsIPMSO22012Controls54 077 54077 MONONGAHELA POWER COALBRIGHT3942 2 0001 002 CoalSteamNone Coal EarlyRetirementNone Coal EarlyRetirement54 077 54077 MONONGAHELA POWER COALBRIGHT3942 3 0001 003 CoalSteamNone None None None54 079 54079 APPALACHIAN POWERJOHN E AMOS PLANT3935 1 0006 001 CoalSteamSCR SCR Scrubber Scrubber54 079 54079 APPALACHIAN POWERJOHN E AMOS PLANT3935 2 0006 002 CoalSteamSCR SCR Scrubber Scrubber54 079 54079 APPALACHIAN POWERJOHN E AMOS PLANT3935 3 0006 003 CoalSteamSCR SCR Scrubber Scrubber