Appendix D.2a 

Point Source Emissions 

Inventory Documentation 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
TABLE OF CONTENTS 

1. INTRODUCTION ...................................................................................................................... 4 

2. 2002 POINT SOURCE INVENTORY DEVELOPMENT ........................................................ 4 

2.1 Development of 2002 Actual Point Source Inventory.................................................... 4 

2.1.1 Consolidated Emissions Reporting Rule .................................................................... 5 

2.1.2 Initial Data Evaluation ................................................................................................ 5 

2.1.3 PM Augmentation....................................................................................................... 7 

2.1.4 EGU Analysis............................................................................................................. 9 

2.1.5 Emission Inventory QA Review............................................................................... 10 

2.1.6 Summary of the 2002 Actual Inventory.................................................................... 11 

2.2 Development of Typical Year EGU Inventory............................................................. 11 

3. 2018 POINT SOURCE EMISSIONS INVENTORY DEVELOPMENT................................ 13 

3.1 EGU Emission Projections ........................................................................................... 13 

3.1.1 Chronology of the Development of EGU Projections.............................................. 14 

3.1.2 VISTAS/MRPO IPM runs for EGU sources............................................................ 16 

3.1.3 Post-Processing of IPM Parsed Files........................................................................ 16 

3.1.4 Eliminating Double Counting of EGU Units............................................................ 18 

3.1.5 Quality Assurance steps............................................................................................ 19 

3.1.6 S/L Adjustments to IPM Modeling Results.............................................................. 20 

3.2 Non-EGU Emission Projections................................................................................... 21 

3.2.1 Growth assumptions for non-EGU sources.............................................................. 22 

3.2.2 Control Programs applied to non-EGU sources........................................................ 24 

3.2.3 Quality Assurance steps............................................................................................ 25 

4. Emission Inventory Summaries................................................................................................ 26 

4.1 Summary of EGU Point Source Inventories................................................................. 27 

4.2 Summary of non-EGU Point Source Inventories.......................................................... 31 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
LIST OF TABLES 

Table 2.1.6-1 2002 Actual Point Source Inventory for Tennessee.............................................. 11 

Table 2.2-1 NOx Emissions Comparison for EGUs..................................................................... 13 

Table 3.1.6-1 TDEC-APC Adjustments to IPM Results for the 2009 and 2018 EGU Inventories

............................................................................................................................................... 21 

Table 4.1-1 EGU Point Source SO2 Emission Comparison ........................................................ 28 

Table 41.7-2 EGU Point Source NOx Emission Comparison...................................................... 28 

Table 4.1-3 EGU Point Source VOC Emission Comparison ...................................................... 29 

Table 4.1-4 EGU Point Source CO Emission Comparison ......................................................... 29 

Table 4.1-5 EGU Point Source PM10-PRI Emission Comparison............................................... 30 

Table 4.1-6 EGU Point Source PM2.5 -PRI Emission Comparison ............................................. 30 

Table 4.1-7 EGU Point Source NH3 Emission Comparison........................................................ 31 

Table 4.2-1 Non-EGU Point Source SO2 Emission Comparison ................................................ 31 

Table 4.2-2 Non-EGU Point Source NOx Emission Comparison................................................ 32 

Table 4.2-3 Non-EGU Point Source VOC Emission Comparison .............................................. 32 

Table 4.2-4 Non-EGU Point Source CO Emission Comparison ................................................. 33 

Table 4.2-5 Non-EGU Point Source PM10-PRI Emission Comparison....................................... 33 

Table 4.2-6 Non-EGU Point Source PM25-PRI Emission Comparison ..................................... 34 

Table 4.2-7 Non-EGU Point Source NH3 Emission Comparison................................................ 34 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
1. INTRODUCTION 

The regional haze modeling was performed by the Southeast Regional Planning Organization, 

Visibility Improvement State and Tribal Association of the Southeast (VISTAS) and is run by 

the ten Southeast states (Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, 

South Carolina, Tennessee, Virginia and West Virginia) and the local programs and tribal 

agencies located within these states. The regional haze modeling uses annual simulations and 

includes an intermediate year. VISTAS developed emission estimates for all pollutants of 

concern for regional haze. 

2. 2002 POINT SOURCE INVENTORY DEVELOPMENT 

This section details the development of the 2002 base year inventory for point sources. There 

were two major components to the development of the point source sector of the inventory. The 

first component was the incorporation of data submitted by State and Local (S/L) agencies to the 

United States Environmental Protection Agency (USEPA) as part of the Consolidated Emissions 

Reporting Rule (CERR) requirements. Work on incorporating the CERR data into the revised 

base year involved: 1) obtaining the data from the USEPA or the S/L agencies, 2) evaluating the 

emissions and pollutants reported in the CERR submittals, 3) augmenting CERR data with 

annual emission estimates for primary coarse particulate matter (PM10-PRI) and primary fine 

particulate matter (PM2.5-PRI); 4) evaluating the emissions from electric generating units, 

5) completing quality assurance reviews for each component of the point source inventory, and 

6) updating the database with corrections or new information from S/L agencies based on their 

review of the 2002 inventory. The processes used to perform the emission inventory 

development are described in the first portion of this section. 

The second component was the development of a “typical” year inventory for electric generating 

units (EGUs). The VISTAS states determined that a typical year EGU inventory was necessary 

to smooth out any anomalies in emissions from the EGU sector due to meteorology, economic, 

and outage factors in 2002. The typical year EGU inventory is intended to represent the five-year 

(2000-2004) period that will be used to determine the regional baseline and to determine the 

regional haze reasonable progress goals. The second part of this section discusses the 

development of the typical year EGU inventory. 

2.1 Development of 2002 Actual Point Source Inventory 

VISTAS/ASIP contracted with MACTEC to develop the 2002 emission inventory. The 

Tennessee Department of Environment and Conservation – Air Pollution Control (TDEC-APC) 

submitted the most updated statewide emission inventory to the contractor with the exception of 

the emissions from the four local programs. For the four local programs, Davidson, Hamilton, 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Knox, and Shelby Counties, the CERR submittal from the USEPA was used. Once all of the 

files were obtained, MACTEC ran the files through the USEPA’s National Emissions Inventory 

(NEI) Input Format (NIF) Basic Format and Content checking tool to ensure that the files were 

submitted in standard NIF format and that there were no referential integrity issues with the files. 

The primary task in preparing the 2002 base year point source inventory was the incorporation of 

corrections and new information as submitted by the S/L agencies based on their review of the 

previous draft versions of the inventory. The following subsections document the data sources 

for the inventory, the checks made on the CERR submittals, the evaluation of EGU emissions, 

and other quality assurance/quality control (QA/QC) checks. The final subsection summarizes 

the 2002 point source inventory by sector (EGU and non-EGU). 

Throughout the development of the point source emissions inventory, the TDEC-APC completed 

detailed reviews of the inventories prepared by the VISTAS contractor and provided comments 

and data corrections when needed. 

2.1.1 Consolidated Emissions Reporting Rule 

The CERR was published in the Federal Register on June 10, 2002 (67 Federal Register 39602). 

This brief summary is provided as a quick introduction to the CERR and covers the major items 

in the rule. 

The purpose of the CERR is to simplify reporting, offer options for data collection and exchange, 

and unify reporting dates for various categories of criteria pollutant emission inventories. The 

rule applies to S/L agencies. Previous reporting requirements have, at times, forced reporting 

agencies into inefficient collecting and reporting activities. This rule consolidates the emission 

inventory reporting requirements found in various parts of the Clean Air Act (CAA). 

Consolidation of reporting requirements will enable S/L agencies to better explain to program 

managers and the public the necessity for a consistent inventory program, increases the 

efficiency of the emission inventory program, and provide more consistent and uniform data. 

States are required to prepare a comprehensive statewide inventory every three years. The first 

inventory was for the year 2002 and was due June 1, 2004. This CERR inventory was used for 

the VISTAS 2002 base year.

2.1.2 Initial Data Evaluation 

MACTEC conducted an initial review of the 2002 point source CERR data. The following 

evaluations were completed to identify potential data quality issues associated with the 

CERR data: 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
• Compared the number of sites in the CERR submittal to the number of sites in the 

VISTAS draft 2002 inventory; the number of sites in the CERR submittal was less than 

in the VISTAS draft 2002 inventory, since the CERR data was limited to major sources, 

while the VISTAS draft 2002 inventory contained data for both major and minor sources; 

verified with S/L contacts that minor sources not included in the CERR point source 

inventory were included in the CERR area source inventory. 

• Checked for correct pollutant codes and corrected to make them NIF-compliant. 

• Checked for types of particulate matter (PM) codes reported (i.e., PM-FIL, PM-CON, 

PM-PRI, PM10-PRI, PM10-FIL, PM25-PRI, PM25-FIL); corrected codes with obvious 

errors (i.e., changed PMPRI to PM-PRI). The PM augmentation process for filling in 

missing PM pollutants is discussed later in Section 2.1.3. 

• Converted all emission values that were not in tons to tons to allow for preparation of 

emission summaries using consistent units. 

• Checked start and end dates in the NIF files to confirm consistency with the 2002 base 

year. 

• Compared annual and daily emissions when daily emissions were reported; in some 

cases, the daily value was non-zero (but very small) but the annual value was zero. This 

was generally the result of rounding in an S/L agency’s submittal. 

• Compared ammonia (NH3) emissions as reported in the CERR submittals and the 2002 

Toxics Release Inventory; worked with S/L agencies to resolve any outstanding 

discrepancies. 

• Compared sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions for EGUs to the 

USEPA’s Clean Air Markets Division (CAMD) continuous emission monitoring (CEM) 

database to identify any outstanding discrepancies. A full discussion of the EGU 

emissions analysis is discussed later in Section 2.1.4. 

• Prepared State-level emission summaries by pollutant for both the EGU and non-EGU 

sectors to allow S/L agencies to compare emissions as reported in the 1999 NEI 

Version 2, the VISTAS draft 2002 inventory, and the CERR submittals. 

• Prepared facility-level emission summaries by pollutant to allow S/L agencies to review 

facility level emissions for reasonableness and accuracy. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
MACTEC communicated the results of these analyses through email/telephone exchanges 

with the S/L point source contacts as well as through Excel summary spreadsheets. The 

VISTAS S/L agencies submitted corrections and updates as necessary to resolve any QA/QC 

issues from these checks. 

2.1.3 PM Augmentation 

Particulate matter emissions can be reported in many different forms, as follows: 

PM Category Description 

PM-PRI Primary PM (includes filterable and condensable) 

PM-CON Primary PM, condensable portion only (all less than 1 micron) 

PM-FIL Primary PM, filterable portion only 

PM10-PRI Primary PM10 (includes filterable and condensable) 

PM10-FIL Primary PM10, filterable portion only 

PM2.5-PRI Primary PM2.5 (includes filterable and condensable) 

PM2.5-FIL Primary PM2.5, filterable portion only 

Tennessee reports PM-PRI, PM10-PRI, and PM2.5–PRI in the CERR. From any one of these 

pollutants, the USEPA has developed augmentation procedures to estimate PM10-PRI, 

PM10-FIL, PM2.5-PRI, PM2.5-FIL, and PM-CON. If not included in a S/L inventory, PM10-PRI 

and PM2.5-PRI were calculated by adding PM10-FIL and PM-CON or PM2.5 -FIL and PM-CON, 

respectively. 

The procedures for augmenting point source PM emissions are documented in detail in the 

USEPA’s document Documentation for the Final 1999 National Emissions Inventory {Version 

3} for Criteria Air Pollutants and Ammonia – Point Sources, January 31, 2004. 

(http://www.epa.gov/ttn/chief/net/1999inventory.html). Briefly, the PM data augmentation 

procedure includes the following five steps: 

• Step 1: Prepare S/L/Tribal PM and PM10 Emissions for Input to the PM Calculator 

• Step 2: Develop and Apply Source-Specific Conversion Factors 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
• Step 3: Prepare Factors from PM Calculator 

• Step 4: Develop and Apply Algorithms to Estimate Emissions from S/L/Tribal Inventory 

Data 

• Step 5: Review Results and Update the NEI with Emission Estimates and Control 

Information. 

Please refer to the USEPA documentation for a complete description of the PM augmentation 

procedures. 

MACTEC took whatever State/Local provided in the way of PM and filled in gaps to add in PMCON where emissions were missing in order to calculate PM10-PRI and PM2.5 -PRI for all 

processes to get a complete set of particulate data. MACTEC did not compare any other 

pollutants besides PM, since for other pollutants CERR emissions equal VISTAS emissions

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
After the PM augmentation process was performed, MACTEC executed a series of checks to 

identify potential inconsistencies in the PM inventory. These checks included: 

• PM-PRI less than PM10-PRI, PM2.5 -PRI, PM10-FIL, PM2.5 -FIL, or PM-CON; 

• PM-FIL less than PM10-FIL or PM2.5 -FIL; 

• PM10-PRI less than PM2.5 -PRI, PM10-FIL, PM2.5 -FIL or PM-CON; 

• PM10-FIL less than PM2.5 -FIL; 

• PM25-PRI less than PM2.5 -FIL or PM-CON; 

• The sum of PM10-FIL and PM-CON not equal to PM10-PRI; and 

• The sum of PM2.5 -FIL and PM-CON not equal to PM2.5 -PRI. 

MACTEC asked S/L agencies to review this information and provide corrections where the 

inconsistencies were significant. 

Note that for the inventory, only the PM10-PRI and PM2.5-PRI emission estimates were retained 

since they are the only two PM species that are included in the air quality modeling. Other PM 

species were removed from the inventory to facilitate emissions modeling. 

2.1.4 EGU Analysis 

MACTEC made a comparison of the annual SO2 and NOx emissions for EGUs as reported in the 

S/L agencies CERR submittals and the data from the USEPA’s CAMD CEM database to identify 

any outstanding discrepancies. Facilities report hourly CEM data to the USEPA for units that are 

subject to CEM reporting requirements of the NOx SIP Call rule and Title IV of the CAA. The 

USEPA sums the hourly CEM emissions to the annual level, and MACTEC compared these 

annual CEM emissions to those in the S/L inventories. The 2002 CEM inventory containing 

NOx and SO2 emissions and heat input data were downloaded from the USEPA CAMD web site 

(www.epa.gov/airmarkets). The data were provided by quarter and emission unit. 

The first step in the EGU analysis involved preparing a crosswalk file to match facilities and 

units in the CAMD inventory to facilities and units in the S/L inventories. In the CAMD 

inventory, the Office of Regulatory Information Systems (ORIS) identification (ID) code 

identifies unique facilities and the unit ID identifies unique boilers and internal combustion 

engines (i.e., turbines and reciprocating engines). In the Tennessee point source emissions 

inventories, the state and county code (FIPS code) and State facility ID together identify unique 

facilities and the emission unit ID identifies unique boilers or internal combustion engines. In 

most cases, there is a one-to-one correspondence between the CAMD identifiers and the S/L 

identifiers. However, in some of the S/L inventories, the emissions for multiple emission units 

are summed and reported under one emission unit ID. MACTEC created an Excel spreadsheet 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
that contained an initial crosswalk with the ORIS ID and unit ID in the CEM inventory matched 

to the State and county FIPS, State facility ID, and emission unit ID in the emissions inventories. 

The initial crosswalk contained both the annual emissions summed from the CAMD database, as 

well as, the S/L emission estimate. The matching at the facility level was nearly complete. In 

some cases, however, S/L agencies or stakeholders’ assistance was needed to match some of the 

CEM units to emission units in the S/L inventories. 

The second step in the EGU analysis was to prepare an Excel spreadsheet that compared the 

annual emissions from the hourly CAMD inventory to the annual emissions reported in the S/L 

inventory. The facility-level comparison of CEM to emission inventory NOx and SO2 emissions 

found that for most facilities, the annual emissions from the S/L inventory equaled the CAMD 

CEM emissions. Minor differences could be explained because the facility in the S/L inventory 

contained additional small or emergency units that were not included in the CAMD database. 

The final step in the EGU analysis was to compare the SO2 and NOx emissions for select 

Southern Company units in the VISTAS region. Southern Company is a super-regional 

company that owns EGUs in four VISTAS States (Alabama, Florida, Georgia, and Mississippi) 

and participates in VISTAS as an industry stakeholder. Southern Company independently 

provided emission estimates for 2002 as part of the development of the preliminary VISTAS 

2002 inventory. Emission estimates were reviewed by the States and incorporated into the States 

CERR submittal. There were no major inconsistencies between the Southern Company data, the 

CAMD data, and the S/L CERR data. 

The minor inconsistencies found included small differences in emission estimates (<2 percent 

difference), exclusion/inclusion of small gas-fired units in the different databases, and grouping 

of emission units in S/L CERR submittals where CAMD listed each unit individually. MACTEC 

compared SO2 and NOx emissions on a unit-by-unit basis and did not find any major 

inconsistencies. 

2.1.5 Emission Inventory QA Review 

Throughout the inventory development process, QA steps were performed to ensure that no 

double counting of emissions occurred, and to ensure that a full and complete inventory was 

developed for VISTAS. QA was an important component to the inventory development process 

and MACTEC performed the following QA steps on the point source component of the VISTAS 

revised 2002 base year inventory: 

1. Facility level emission summaries were prepared and evaluated to ensure that 

emissions were consistent and that there were no missing sources. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
2. State-level EGU and non-EGU comparisons (by pollutant) were developed between 

the 2002 base year inventory, the draft VISTAS 2002 inventory, and the 1999 NEI 

Version 2 inventory. 

3. Data product summaries and raw NIF 3.0 data files were provided to the VISTAS 

Emission Inventory Technical Advisor and to the Point Source, EGU, and non-EGU 

Special Interest Work Group representatives for review and comment. Changes based 

on these comments were reviewed and approved by the S/L point source contact prior 

to implementing the changes in the files. 

Version numbering was used for all inventory files developed. The version numbering process 

used a decimal system to track major and minor changes. 

2.1.6 Summary of the 2002 Actual Inventory 

Tables 2.1.6-1 summarize the final 2002 actual base year inventory for Tennessee. All values 

are in tons per year. The EGU emissions include the emissions from all processes with a Source 

Classification Code (SCC) of either 1-01-xxx-xx (External Combustion Boilers – Electric 

Generation) or 2-01-xxx-xx (Internal Combustion Engines – Electric Generation). Emissions for 

all other SCCs are included in the non-EGU column. 

Table 2.1.6-1 2002 Actual Point Source Inventory for Tennessee 

Pollutant All Point 

Sources EGUs Non-EGUs 

SO2 413,735 334,151 79,584 

NOx 221,638 157,307 64,331 

VOC 78,230 926 77,304 

CO 121,765 7,084 114,681 

PM10-PRI 49,174 14,640 34,534 

PM2.5-PRI 39,511 12,166 27,345 

NH3 1,746 204 1,542 

VOC = Volatile Organic Compounds 

CO = Carbon Monoxide 

2.2 Development of Typical Year EGU Inventory 

VISTAS developed a typical year 2002 emission inventory for EGUs to avoid anomalies in 

emissions due to variability in meteorology, economic, and outage factors in 2002. The typical 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
year inventory represents the five year (2000-2004) period, which are the years used to calculate 

the regional haze baseline. 

Data from the USEPA’s CAMD were used to develop normalization factors for producing a 

2002 typical year inventory for EGUs. The VISTAS contractor used the ratio of the 2000-2004 

average heat input and the 2002 actual heat input to normalize the 2002 actual emissions. 

MACTEC obtained data from the USEPA CAMD for utilities regulated by the Acid Rain 

program. Annual data for the period 2000 to 2004 were obtained from the CAMD web site. The 

parameters available were the SO2 and NOx emission rates, heat input, and operating hours. 

MACTEC used the actual 2002 heat input and the average heat input for the 5-year period from 

2000-2004 as the normalization factor, as follows: 

Normalization Factor: 2000-2004 average heat input 

 2002 actual heat input

If the unit did not operate for all five years, then the 2000-2004 average heat input was calculated 

for the one or two years in which the unit did operate. The annual actual emissions were 

multiplied by the normalization factor to determine the typical emissions for 2002, as follows: 

Typical Emissions = 2002 actual emissions x Normalization Factor 

After applying the normalization factor, some adjustments were needed for special 

circumstances. For example, a unit may not have operated in 2002 and thus have zero emissions. 

If the unit had been permanently retired prior to 2002, then MACTEC used zero emissions for 

the typical year. If the unit had not been permanently retired and would normally operate in a 

typical year, then MACTEC used the 2001 (or 2000) heat input and emission rate to calculate the 

typical year emissions. 

The final step was to replace the 2002 actual emissions with the 2002 typical year data described 

above. MACTEC provided the raw data and results of the typical year calculations in a 

spreadsheet for S/L agency to review and comment. Any comments made were incorporated into 

the typical 2002 inventory. 

Table 2.2-1 summarizes emissions by State and pollutant for the actual 2002 EGU inventory and 

the typical year EGU inventory. For the entire VISTAS region, actual 2002 NOx emissions were 

about 0.1 percent lower than the typical year emissions. Tennessee’s actual 2002 NOx emissions 

were 3.3 percent higher than the typical year emissions. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Table 2.2-1 NOx Emissions Comparison for EGUs 

NOx Emissions (tons/year) 

State 

Actual 2002 Typical 2002 Percentage 

Difference 

AL 161,038 154,704 3.9 

FL 257,677 282,507 -9.6 

GA 147,517 148,126 -0.4 

KY 198,817 201,928 -1.6 

MS 43,135 40,433 6.3 

NC 151,854 148,812 2.0 

SC 88,241 88,528 -0.3 

TN 157,307 152,137 3.3 

VA 86,886 85,081 2.1 

WV 230,977 222,437 3.7 

3. 2018 POINT SOURCE EMISSIONS INVENTORY DEVELOPMENT 

Different approaches were used for different sectors of the point source inventory. For the 

EGUs, VISTAS relied primarily on the Integrated Planning Model® (IPM), version 2.1.9, to 

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

The IPM results were adjusted based on S/L agency knowledge of planned emission controls at 

specific EGUs. For non-EGUs, VISTAS used recently updated growth and control data 

consistent with the data used in the USEPA’s Clean Air Interstate Rule (CAIR) analyses, and 

supplemented these data with available S/L agency input and updated fuel use forecast data for 

the United States Department of Energy. 

For both sectors, VISTAS generated 2018 inventory with control scenarios that account for post2002 emission reductions from promulgated and proposed Federal, State, Local, and site-specific 

control programs as of July 1, 2004. Section 3.1 discusses the EGU projection inventory 

development, while Section 3.2 discusses the non-EGU projection inventory development. 

3.1 EGU Emission Projections 

The following subsections discuss the aspects of the development of the EGU projections. 

• A chronology of the EGU development process used by MACTEC and discuss key 

decisions in selecting the final methods for performing the emissions projections. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
• The development of the final set of IPM runs that are included in the VISTAS 2018 

inventory. 

• The process of transforming the IPM parsed files into NIF format. 

• The process for ensuring that units accounted for in IPM were not double-counted in 

the non-EGU inventory. 

• The QA/QC checks that were made to ensure that the IPM results were properly 

incorporated into the VISTAS inventory. 

• The changes to the IPM results that S/L agencies requested to be included in the 

VISTAS inventory based on new information that was not accounted for in the IPM 

runs. 

• Summary of 2002 and 2018 EGU emissions by state 

3.1.1 Chronology of the Development of EGU Projections 

Initially, VISTAS considered three options for developing the 2009 and 2018 projection 

inventories for EGUs: 

• Option 1 – Use the results of IPM modeling conducted in support of the proposed CAIR 

base and control case analyses as the starting point and refine the projections with readily 

available inputs from stakeholders; these IPM runs were conducted for 2010 and 2015, 

which VISTAS would use to represent projected emissions in 2009 and 2018 

respectively. 

• Option 2 – Use the VISTAS 2002 typical year as the starting point, apply growth factors 

from the Energy Information Administration, and refine future emission rates with 

stakeholder input regarding utilization rates, capacity, retirements, and new unit 

information. 

• Option 3 – Use the results of a new round of IPM modeling sponsored by VISTAS and 

the Midwest Regional Planning Organization (MRPO). These runs incorporated 

VISTAS specific unit and regulation modified parameters, and generate results for 2018 

explicitly. 

An additional consideration for each of the three options was the inclusion of emission 

projections developed by the Southern Company specifically for their units. Southern Company 

used their energy budget forecast to project net generation and heat input for every existing and 

future Southern Company EGU for the year 2018. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Each of these three options and the Southern Company projections were discussed in a series of 

conference calls with the VISTAS EGU Special Interest Work Group (SIWG) during the fall of 

2004. During a conference call on December 6, 2004, the VISTAS EGU SIWG approved the 

use of the latest VISTAS/MRPO sponsored IPM runs (Option 3) to represent 2018 EGU 

forecasts of emissions the future year cases. 

The Option 3 IPM modeling resulted from a joint agreement by VISTAS and MRPO to work 

together to develop future year utility emissions based on IPM modeling. The decision to use 

IPM modeling was based in part on a study of utility forecast methods by E.H. Pechan and 

Associates, Inc. (Pechan) for MRPO, which recommended IPM as a viable methodology. 

Although the USEPA used IPM recently to support their rulemaking for the CAIR, VISTAS 

stakeholders felt that certain model inputs needed to be improved. Thus, VISTAS and MRPO 

decided to hire contractors to conduct new IPM modeling and to post-process the IPM results. 

For 2018, Southern Company projections were generally less than IPM because of assumptions 

made by Southern Company on which units would be economical to control and incorrect data in 

the NEEDS database which feeds IPM. 

In August 2004, VISTAS contracted with ICF to run IPM to provide utility forecasts for 2018 

under two future scenarios – Base Case and CAIR Case. The Base Case represents the current 

operation of the power system under currently known laws and regulations, including those that 

come into force in the study horizon. The CAIR Case is the Base Case with the proposed CAIR 

rule superimposed. The run results were parsed at the unit level for 2018. The IPM output files 

were delivered by ICF in November, and the post-processed data files were delivered by Pechan 

in December 2004. 

On March 10, 2005, the USEPA issued the final CAIR. VISTAS and MRPO, in conjunction 

with other regional planning organizations (RPOs), conducted another round of IPM modeling, 

which reflected changes to control assumptions based on the final CAIR as well as additional 

changes to model inputs based on S/L agency and stakeholder comments. Several conference 

calls were conducted in the spring/summer of 2005 to discuss and provide comments on IPM 

assumptions related to six main topics: power system operation, generating resources, emission 

control technologies, set-up parameters and rule, financial assumptions, and fuel assumptions. 

For the summer 2006 set of IPM runs, ICF generated two different parsed files. One file 

includes all fuel burning units (fossil, biomass, landfill gas), as well as, non-fuel burning units 

(hydro, wind, etc.). The second file contains just the fossil-fuel burning units (e.g., emissions 

from biomass and landfill gas are omitted). The RPOs decided to use the fossil-only file for 

modeling to be consistent with the USEPA, since the USEPA used the fossil only results for 

CAIR analyses. For the 10 VISTAS states, non-fossil fuels accounted for only 0.13 percent of 

the NOx emissions and 0.04 percent of the SO2 emissions in the 2018 IPM runs 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
VISTAS asked S/L agencies to review the results of the summer 2006 set of IPM runs, which 

were incorporated into the VISTAS inventory. The TDEC-APC primarily reviewed and 

commented on the IPM results with respect to IPM decisions on NOx post-combustion controls 

and SO2 scrubbers. The TDEC-APC decided to let the IPM solve the 2018 emissions. 

3.1.2 VISTAS/MRPO IPM runs for EGU sources 

The following summary of the VISTAS/MRPO IPM® modeling is based on ICF’s 

documentation Future Year Electricity Generating Sector Emission Inventory Development 

Using the IPM® in Support of Fine Particulate Mass and Visibility Modeling in the VISTAS and 

Midwest RPO Regions, April 2005. The ICF documentation is to be used as an extension to the 

USEPA's proposed CAIR modeling runs documented in Documentation Supplement for EPA 

Modeling Applications (V.2.1.6) Using the IPM, EPA 430/R-03-007, July 2003. 

IPM provides “forecasts of least-cost capacity expansion, electricity dispatch, and emission 

control strategies for meeting energy demand and environmental, transmission, dispatch, and 

reliability constraints.” The underlying database in this modeling is the USEPA’s National 

Electric Energy Data System (NEEDS) released with the CAIR Notice of Data Availability 

(NODA). The NEEDS database contains the existing and planned/committed unit data in the 

USEPA modeling applications of IPM. NEEDS includes basic geographic, operating, air 

emissions, and other data on these generating units. VISTAS States and stakeholders provided 

changes for: 

• NOx post-combustion control on existing units 

• SO2 scrubbers on existing units 

• SO2 emission limitations 

• PM controls on existing units 

• Summer net dependable capacity 

• Heat rate for existing units 

• SO2 and NOx control plans based on State rules or enforcement settlements 

The years 2009 and 2018 were explicitly modeled in this set of runs. Again, the TDEC-APC 

decided to let the IPM model solve the 2018 emissions. 

3.1.3 Post-Processing of IPM Parsed Files 

The following summary of the VISTAS/MRPO IPM modeling is based on Pechan’s 

documentation LADCO IPM Model Parsed File Post-Processing Methodology and File 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Preparation, February 8, 2005. The essence of the IPM model post-processing methodology is 

to take an initial IPM model output file and transform it into air quality model input files. ICF 

via VISTAS/MRPO provided an initial spreadsheet file containing unit-level records of both 

(1) “existing” units and (2) committed or new generic aggregates. 

All records have unit and fuel type data; existing, retrofit (for SO2 and NOx), and separate NOx

control information; annual SO2 and NOx emissions and heat input; summer season (MaySeptember) NOx and heat input; July day NOx and heat input; coal heat input by coal type; 

nameplate capacity (mega-watts), and State FIPS code. Existing units also have county FIPS 

code, a unique plant identifier (ORISPL) and unit ID (also called boiler ID) (BLRID); generic 

units do not have these data. The processing includes estimating various types of emissions and 

adding in control efficiencies, stack parameters, latitude-longitude coordinates, and State 

identifiers (plant ID, point ID, stack ID, process ID). Additionally, the generic units are sited in 

a county and given appropriate IDs. This processing is described in more detail below. 

The data are prepared by transforming the generic aggregates into units similar to the existing 

units in terms of the available data. The generic aggregates are split into smaller generic units 

based on their unit types and capacity, are provided a dummy ORIS unique plant and boiler ID, 

and are given a county FIPS code based on an algorithm that sites each generic by assigning a 

sister plant that is in a county based on its attainment/nonattainment status. Within a State, 

plants (in county then ORIS plant code order) in attainment counties are used first as sister sites 

to generic units, followed by plants in PM2.5 nonattainment counties, followed by plants in 

8-hour ozone nonattainment counties. Note that no LADCO or VISTAS States provided 

blackout counties that would not be considered when siting generics, so this process is identical 

to the one used for the USEPA IPM post-processing. 

SCCs were assigned for all units; unit/fuel/firing/bottom type data were used for existing units’ 

assignments, while only unit and fuel type were used for generic units’ assignments. Latitudelongitude coordinates were assigned, first using the USEPA-provided data files, secondly using 

the September 17, 2004 Pechan in-house latitude-longitude file, and lastly using county 

centroids. These data were only used when the data were not provided in the 2002 NIF files. 

Stack parameters were attached, first using the USEPA-provided data files, secondly using a 

March 9, 2004 Pechan in-house stack parameter file based on previous Energy Information 

Adminitration form 767 (EIA-767) data, and lastly using an the USEPA June 2003 SCC-based 

default stack parameter file. These data were only used when the data were not provided in the 

2002 NIF files. 

Additional data were required for estimating VOC, CO, filterable primary PM10 and PM2.5, PM 

condensable, and NH3 emissions for all units. Thus, ash and sulfur contents were assigned by 

first using 2002 EIA-767 values for existing units or SCC-based defaults; filterable PM10 and 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
PM2.5 efficiencies were obtained from the 2002 EGU NEI that were based on 2002 EIA-767 

control data and the PM Calculator program (a default of 99.2 percent is used for coal units if 

necessary); fuel use was back calculated from the given heat input and a default SCC-based heat 

content; and emission factors were obtained from an USEPA-approved October 7, 2004 Pechan 

emission factor file based on the USEPA’s AP-42 emission factors. Note that this updated file is 

not the one used for estimating emissions for previous USEPA post-processed IPM files. 

Emissions for 28 temporal-pollutant combinations were estimated since there are seven 

pollutants (VOC, CO, primary PM10 and PM2.5, NH3, SO2 and NOx) and four temporal periods 

(annual, summer season, winter season, July day). 

The next step was to match the IPM unit IDs with the identifiers in VISTAS 2002 inventory. A 

crosswalk file was used to obtain FIPS State and county, plant ID (within State and county), and 

point ID. If the FIPS State and county, plant ID and point ID are in the 2002 VISTAS NIF 

tables, then the process ID and stack ID are obtained from the NIF; otherwise, defaults, described 

above, were used. 

Pechan provided the post-processed files in NIF 3.0 format. Two sets of tables were developed: 

“NIF files” for IPM units that have a crosswalk match and are in the 2002 VISTAS inventory, 

and “NoNIF files” for IPM units that are not in the 2002 VISTAS inventory (which includes 

existing units with or without a crosswalk match as well as generic units). 

3.1.4 Eliminating Double Counting of EGU Units 

The following procedures were used to avoid double counting of EGU emissions in the 2018 

point source inventory. The 2002 VISTAS point source emission inventory contains both EGUs 

and non-EGUs. Since this file contains both EGUs and non-EGU point sources, and EGU 

emissions are projected using the IPM, it was necessary to split the 2002 point source file into 

two components. The first component contains those emission units accounted for in the IPM 

forecasts. The second component contains all other point sources not accounted for in IPM. 

As described in the previous section, Pechan developed 2018 NIF files for EGUs from the IPM 

parsed files. All IPM matched units were initially removed from the 2018 point source inventory 

to create the non-EGU inventory (which was projected to 2018 using the non-EGU growth and 

control factors described in Section 3.2.1). This was done on a unit-by-unit basis based on a 

cross-reference table that matches IPM emission unit identifiers (ORISPL plant code and BLRID 

emission unit code) to VISTAS NIF emission unit identifiers (FIPSST state code, FIPSCNTY 

county code, State Plant ID, State Point ID). When there was a match between the IPM 

ORISPL/BLRID and the VISTAS emission unit ID, the unit was assigned to the EGU inventory; 

all other emission units were assigned to the non-EGU inventory. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
If an emission unit was contained in the NIF files created by Pechan from the IPM output, the 

corresponding unit was removed from the initial 2018 point source inventory. The NIF 2018 

EGU files from the IPM parsed files were then merged with the non-EGU 2018 files to create the 

2018 point source files. 

Next, MACTEC prepared several ad-hoc QA/QC queries to verify that there was no doublecounting of emissions in the EGU and non-EGU inventories: 

• MACTEC reviewed the IPM parsed files to identify EGUs accounted for in IPM. 

MACTEC compared this list of emission units to the non-EGU inventory derived from 

the VISTAS cross-reference table to verify that units accounted for in IPM were not 

double-counted in the non-EGU inventory. As a result of this comparison, MACTEC 

made a few adjustments in the cross-reference table to add emission units for four plants 

to ensure these units accounted for in IPM were moved to the EGU inventory. 

• MACTEC reviewed the non-EGU inventory to identify remaining emission units with a 

Standard Industrial Classification (SIC) code of “4911 Electrical Services” or SCC of “1-

01-xxx-xx External Combustion Boiler, Electric Generation”. 

• MACTEC compared the list of sources meeting these selection criteria to the IPM parsed 

file to ensure that these units were not double-counted. 

MACTEC asked S/L agencies to review the 2018 point source inventory to verify whether there 

was any double counting of EGU emissions. 

3.1.5 Quality Assurance steps 

Quality assurance was an important component to the inventory development process and 

MACTEC performed the following QA steps on the EGU component of the VISTAS revised 

2009 and 2018 EGU inventories: 

1. Provided parsed files (i.e., Excel spreadsheets that provide unit-level results derived from 

the model plant projections obtained by the IPM) to the VISTAS EGU SIWG for review 

and comment. 

2. Provided facility level emission summaries for 2018 for both the base case and CAIR 

case to the VISTAS EGU SIWG to ensure that emissions were consistent and that there 

were no missing sources. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
3. Compared State-level emissions from the IPM parsed files with the post-processed NIF 

files to verify that the post-processed NIF files were consistent with the IPM parsed file 

results. 

VISTAS requested S/L review of these files – the changes specified by Tennessee as a result of 

this review are documented in the following subsection. 

3.1.6 S/L Adjustments to IPM Modeling Results 

After the S/L agency review of the final set of IPM runs, S/L agencies specified a number of 

changes to the IPM results to better reflect current information on when and where future 

controls would occur. These changes to the IPM results primarily involved S/L agency addition 

or subtraction of future emission controls based on the best available data from state rules, 

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

individual companies. 

Some S/L agencies specified changes to the controls assigned by IPM to reflect their best 

estimates of emission controls. The VISTAS contractors used a scrubber control efficiency of 90 

percent when adding or removing SO2 scrubber controls, used a control efficiency of 90 percent 

when adding or removing NOx SCR controls at coal-fired plants, 80 percent when adding or 

removing NOx SCR controls at gas-fired plants, and 35 percent when adding or removing NOx

SNCR controls. The specific changes from the TDEC-APC to the IPM results are also 

summarized in Table 3.1.6-1. 

S/L agencies provided information and/or comment on changes in stack parameters from the 

2002 inventory for the 2009 and 2018 inventories. Changes to stack parameters were also made 

in cases where new controls are scheduled to be installed. In cases where an emission unit 

projected to have a SO2 scrubber in either 2009 or 2018, some states were able to provide revised 

stack parameters for some units based on design features for the new control system. Other units 

projected to install scrubbers by 2009 or 2018 are not far enough along in the design process to 

have specific design details. For those units, the VISTAS EGU SIWG made the following 

assumptions: 1) the scrubber is a wet scrubber; 2) keep the current stack height the same; 3) keep 

the current flow rate the same, and 4) change the stack exit temperature to 169 °F (this is the 

virtual temperature derived from a wet temperature of 130 °F). VISTAS determined that exit 

temperature (wet) of 130 °F +/- 5 °F is representative of different size units and wet scrubber 

technology. A final table of the 2009 and 2018 NOx and SO2 controls that will be or are assumed 

to be applied to specific EGU emission units throughout the VISTAS states is presented in 

Appendix H. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Table 3.1.6-1 Tennessee Adjustments to IPM Results for the 2009 and 2018 EGU 

Inventories 

Plant Name and ID Unit Nature of Update/Correction 

Department of Energy 

(DOE) 

(47001-0020-002) 

Y-12 

Boilers 1-4 will be shut down in 2010. 

Eastman Chemicals 

(47163-0003-021520) 

B-253-1 

This source will install scrubbers as a result of BART. SO2 

emissions will be reduced by 90%. 

Changed 2018 EM emissions for B-253-1: SO2 from 

16,728.78 to 1,672.88 tpy. Added SO2 to CE table with 90 

% efficiency. Changed stack temperature in ER table to 169 

to reflect addition of scrubber per VISTAS Guidance. 

Eastman Chemicals 

(47163-0003-020101) 

B-83-1 

Boilers 11-17 have been removed from service. Emissions 

from this source should be reduced by 26.64%. 

3.2 Non-EGU Emission Projections 

The general approach for assembling future year data was to use recently updated growth and 

control data consistent with the data used in the USEPA’s CAIR analyses, supplement these data 

with available stakeholder input, and provide the results for stakeholder review to ensure 

credibility. The VISTAS contractor used the 2002 VISTAS base year inventory, based on the 

2002 CERR submittals as the starting point for the non-EGU projection inventory. The 2002 

VISTAS/ASIP point source emission inventory contains both EGUs and non-EGUs. Since this 

file contains both EGUs and non-EGU point sources, and EGU emissions are projected using the 

IPM, it was necessary to split the 2002 point source file into two components. The first 

component contains those emission units accounted for in the IPM forecasts. The second 

component contains all other point sources not accounted for in IPM and constitutes the nonEGU emissions inventory. 

MACTEC performed the following activities to apply growth and control factors to the 2002 

non-EGU emissions inventory to generate the 2009 and 2018 projection inventories: 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
• Obtained, reviewed, and applied the most current growth factors developed by the 

USEPA, based on forecasts from an updated Regional Economic Models, Inc. (REMI) 

model (version 5.5) and the latest Annual Energy Outlook published by the Department 

of Energy (DOE); 

• Obtained, reviewed, and applied any State-specific or sector-specific growth factors 

submitted by stakeholders; 

• Obtained and incorporated information regarding sources that have shut down after 2002 

and set the emissions to zero in the projection inventories; 

• Obtained, reviewed, and applied control assumptions; 

• Provided data files in NIF3.0 format and emission summaries in EXCEL format for 

review and comment; and 

• Updated the database with corrections or new information from S/L agencies based on 

their review of the 2009 and 2018 inventories. 

The following sections discuss each of these steps. 

3.2.1 Growth assumptions for non-EGU sources 

The growth factor data used in developing the emission inventory were consistent with the 

USEPA’s analyses for the CAIR rulemaking. These growth factors are fully documented in the 

USEPA’s reports entitled Development of Growth Factors for Future Year Modeling Inventories

(dated April 30, 2004) and CAIR Emission Inventory Overview (dated July 23, 2004). Three 

sources of data were used in developing the growth factors for the 2009 and 2018 emissions 

inventories: 

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

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

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

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

State level. 

• Energy consumption data from the Department of Energy, Energy Information 

Administration’s (EIA) Annual Energy Outlook 2004, with Projections through 2025 for 

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

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

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

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
factors for the residential natural gas combustion category, for example, are based on 

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

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

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

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

and socioeconomic trends, all States within each division received the same growth rate.

• Specific changes for sectors (e.g., plastics, synthetic rubber, carbon black, cement 

manufacturing, primary metals, fabricated metals, motor vehicles and equipment) where 

the REMI-based rates were unrealistic or highly uncertain. Growth projections for these 

sectors were based on industry group forecasts, Bureau of Labor Statistics (BLS) 

projections and Bureau of Economic Analysis (BEA) historical growth from 1987-2002. 

In addition to the growth data described above, VISTAS received two sets of growth projections 

from stakeholders. The American Forest and Paper Association (AF&PA) supplied growth 

projections for the pulp and paper sector, which were applied to SIC 26xx Paper and Allied 

Products, for growth from 2002 to 2009 and 2002 to 2018. The AF&PA projection factors 

(1.067 and 1.169, respectively) are for the United States industry and apply to all States equally. 

The number come from the 15-year forecast for world pulp and recovered paper prepared by 

Resource Information Systems Inc. (RISI). The VISTAS contractor used the above AF&PA 

growth factors by SIC instead of the factors obtained from the USEPA’s CAIR analysis for the 

2009 and 2018 emission inventories. 

For the 2009 and 2018 inventories, the VISTAS/ASIP contractor made one additional change to 

the growth factors. The Annual Energy Outlook (AEO) 2004 data was replaced with the more 

recent AEO2006 forecasts (released in February 2006) to reflect changes in the energy market 

and to improve the emissions growth factors produced. The VISTAS contractor obtained the 

corresponding AEO2006 projection tables from DOE. VISTAS developed tables comparing the 

growth factors based on AEO2004 and AEO2006 and these comparison tables were reviewed by 

the S/L agencies. Based on this review, the VISTAS states decided to use the AEO2006 growth 

factors for fuel burning SCCs. 

VISTAS used the USEPA’s EGAS model and updated the corresponding AEO2006 projection 

tables to create growth factors by SCC. VISTAS applied the updated growth factors to 2002 

actual emissions and replaced the 2009 and 2018 emissions in NIF EM tables for the affected 

SCCs. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
3.2.2 Control Programs applied to non-EGU sources 

The VISTAS’s contractor developed a control scenario to address the CAA requirements. The 

control scenario accounts for post-2002 emission reductions from promulgated Federal, State, 

Local, and site-specific control programs and are listed below. 

• Atlanta / Northern Kentucky / Birmingham 1-hour ozone SIPs 

• Industrial Boiler/Process Heater/RICE MACT 

• NOx RACT in 1-hour NAA SIPs 

• NOx SIP Call (Phase I) 

• NOx SIP Call (Phase II) 

• RFP 3 percent Plans where in place for one hour plans 

• VOC 2-, 4-, 7-, and 10-year MACT Standards 

• Combustion Turbine MACT 

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

control programs are discussed in the following sections. 

NOx SIP Call (Phase I)

Phase I of the NOx SIP call applies to certain large non-EGUs, including large industrial boilers 

and turbines, and cement kilns. States in the VISTAS region affected by the NOx SIP call have 

developed rules for the control of NOx emissions that have been approved by the USEPA. 

VISTAS reviewed the available State rules and guidance documents to determine the affected 

sources and ozone season allowances. VISTAS also obtained and reviewed information in the 

USEPA’s CAMD NOx Allowance Tracking System – Allowances Held Report. Since these 

controls are to be in effect by the year 2007, VISTAS capped the emissions for NOx SIP call 

affected sources at 2007 levels and carried forward the capped levels for the 2009 and 2018 

future year inventories. 

NOx SIP Call (Phase II)

The final Phase II NOx SIP call rule was finalized on April 21, 2004. States had until 

April 21, 2005, to submit SIPs meeting the Phase II NOx budget requirements. The Phase II rule 

applies to large IC engines, which are primarily used in pipeline transmission service at 

compressor stations. VISTAS identified affected units using the same methodology as was used 

by the USEPA in the proposed Phase II rule (i.e., a large IC engine is one that emitted, on 

average, more than 1 ton per day during 2002). The final rule reflects a control level of 82 

percent for natural gas-fired IC engines and 90 percent for diesel or dual fuel categories. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Industrial Boiler/Process Heater MACT

The USEPA anticipates reductions in PM and SO2 as a result of the Industrial Boiler/Process 

Heater MACT standard. The methods used to account for these reductions are the same as those 

used for the CAIR analysis. Reductions were included for existing units firing solid fuel (coal, 

wood, waste, biomass), which had a design capacity greater than 10 mmBtu/hr. The USEPA 

prepared a list of SCCs for solid fuel industrial, commercial/ institutional boilers and process 

heaters. The VISTAS contractor identified boilers greater than 10 mmBtu/hr using either the 

boiler capacity from the VISTAS 2002 inventory, or if the boiler capacity was missing, a default 

capacity based on a methodology developed by the USEPA for assigning default capacities 

based on SCC code. The applied MACT control efficiencies were 4 percent for SO2 and 40 for 

percent for PM10 and PM2.5. 

2, 4, 7, and 10-year MACT Standards

Maximum achievable control technology (MACT) requirements were also applied, as 

documented in the USEPA’s report entitled Control Packet Development and Data Sources, 

dated July 14, 2004. The point source MACTs and associated emission reductions were 

designed from Federal Register notices and discussions with the USEPA’s Emission Standards 

Division staff. VISTAS did not apply reductions for MACT standards with an initial compliance 

date of 2001 or earlier, assuming that the effects of these controls are already accounted for in 

the 2002 inventories supplied by the States. Emission reductions were applied only for MACT 

standards with an initial compliance date of 2002 or greater. 

Combustion Turbine MACT

The projection inventory does not include the NOx co-benefit effects of the MACT regulations 

for Gas Turbines or stationary Reciprocating Internal Combustion Engines, which the USEPA 

estimates to be small compared to the overall inventory. 

Clean Air Interstate Rule

CAIR does not require or assume additional emission reductions from non-EGU boilers and 

turbines. 

3.2.3 Quality Assurance steps 

Final QA checks were run on the revised projection inventory data set to ensure that all 

corrections provided by the S/L agencies and stakeholders were correctly incorporated into the 

S/L inventories and that there were no remaining QA issues that could be addressed during the 

duration of the project. After exporting the inventory to ASCII text files in NIF 3.0, the USEPA 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
QA program was run on the ASCII files and the QA output was reviewed to verify that all QA 

issues that could be addressed were resolved. 

Throughout the inventory development process, quality assurance steps were performed to 

ensure that no double counting of emissions occurred, and to ensure that a full and complete 

inventory was developed for Tennessee. Quality assurance was an important component to the 

inventory development process and MACTEC performed the following QA steps on the point 

source component of the VISTAS inventory: 

1. Facility level emission summaries were prepared and evaluated to ensure that 

emissions were consistent and reasonable. The summaries included base year 2002 

emissions, 2009/2018 projected emissions accounting only for growth, 2009/2018 

projected emissions accounting for both growth and emission reductions from CAA 

controls. 

2. State-level non-EGU comparisons (by pollutant) were developed for the base year 

2002 emissions, 2009/2018 projected emissions accounting only for growth, 

2009/2018 projected emissions accounting for both growth and emission reductions 

from CAA controls. 

3. Data product summaries and raw NIF 3.0 data files were provided to the VISTAS 

Emission Inventory Technical Advisor and to the Point Source, EGU, and non-EGU 

Special Interest Work Group representatives for review and comment. Changes 

based on these comments were reviewed and approved by Tennessee point source 

contact prior to implementing the changes in the files. 

4. Version numbering was used for all inventory files developed. The version 

numbering process used a decimal system to track major and minor changes. 

4. Emission Inventory Summaries 

The following sections include the emissions inventory summaries for the point source for all of 

the states within the VISTAS region. The first section provides the 2002, 2009 and 2018 

emissions for the EGU sources and the second section provides the emissions for the non-EGU 

sources. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
4.1 Summary of EGU Point Source Inventories 

Tables 4.1-1 through 4.1-7 summarize the 2002 base year inventory and 2009 and 2018 

projection inventories for the EGU source sector. The 2009 and 2018 inventories include the 

adjustments to the IPM results specified by the S/L agencies in the previous section. 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Table 4.1-1 EGU Point Source SO2 Emission Comparison 

State 2002 VISTAS 

2009 IPM Based with 

S/L Adjustments 

2018 IPM Based with 

S/L Adjustments 

AL 447,828 378,052 305,262 

FL 453,631 186,055 132,177 

GA 514,952 417,449 230,856 

KY 484,057 290,193 226,062 

MS 67,429 76,579 15,146 

NC 477,990 242,286 108,492 

SC 206,399 124,608 93,274 

TN 334,151 255,410 112,672 

VA 241,204 225,653 140,233 

WV 516,084 277,489 115,324 

Total 3,743,725 2,473,774 1,479,498 

Table 4.1-2 EGU Point Source NOx Emission Comparison 

State 2002 VISTAS 

2009 IPM Based with 

S/L Adjustments 

2018 IPM Based with 

S/L Adjustments 

AL 161,038 82,305 64,358 

FL 257,677 86,165 73,125 

GA 147,517 98,497 75,717 

KY 198,817 92,021 64,378 

MS 43,135 36,011 10,271 

NC 151,854 66,522 62,353 

SC 88,241 46,915 51,456 

TN 157,307 66,405 31,715 

VA 86,886 66,219 75,594 

WV 230,977 86,328 51,241 

Total 1,523,449 727,388 560,208 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Table 4.1-3 EGU Point Source VOC Emission Comparison 

State 2002 VISTAS 

2009 IPM Based with 

S/L Adjustments 

2018IPM Based with 

S/L Adjustments 

AL 2,295 2,473 2,952 

FL 2,524 1,910 2,376 

GA 1,244 2,314 2,841 

KY 1,487 1,369 1,426 

MS 648 404 1,114 

NC 988 954 1,345 

SC 470 660 906 

TN 926 932 976 

VA 754 778 996 

WV 1,180 1,361 1,387 

Total 12,516 13,155 16,319 

Table 4.1-4 EGU Point Source CO Emission Comparison 

State 2002 VISTAS 

2009 IPM Based with 

S/L Adjustments 

2018 IPM Based with 

S/L Adjustments 

AL 11,279 14,986 24,342 

FL 57,113 35,928 53,772 

GA 9,712 23,721 44,476 

KY 12,619 15,812 17,144 

MS 5,303 5,051 15,282 

NC 13,885 14,942 20,223 

SC 6,990 11,135 14,786 

TN 7,084 7,214 7,723 

VA 6,892 12,509 15,420 

WV 10,341 11,493 11,961 

Total 141,218 152,790 225,129 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Table 4.1-5 EGU Point Source PM10-PRI Emission Comparison 

State 2002 VISTAS 

2009 IPM Based with 

S/L Adjustments 

2018 IPM Based with 

S/L Adjustments 

AL 7,646 6,969 7,822 

FL 21,387 9,007 9,953 

GA 11,224 17,891 20,909 

KY 4,701 6,463 6,694 

MS 1,633 4,957 7,187 

NC 22,754 22,152 37,376 

SC 21,400 19,395 28,826 

TN 14,640 15,608 15,941 

VA 3,960 5,508 13,775 

WV 4,573 5,657 6,349 

Total 113,918 113,607 154,832 

Table 4.1-6 EGU Point Source PM2.5 -PRI Emission Comparison 

State 2002 VISTAS 

2009 IPM Based with 

S/L Adjustments 

2018 IPM Based with 

S/L Adjustments 

AL 4,113 3,921 4,768 

FL 15,643 5,910 6,843 

GA 4,939 10,907 13,983 

KY 2,802 4,279 4,434 

MS 1,138 4,777 7,033 

NC 16,498 15,949 29,792 

SC 17,154 16,042 25,032 

TN 12,166 13,092 13,387 

VA 2,606 4,067 11,976 

WV 2,210 2,940 3,648 

Total 79,269 81,884 120,896 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Table 4.1-7 EGU Point Source NH3 Emission Comparison 

State 2002 VISTAS 

2009 IPM Based with 

S/L Adjustments 

2018 IPM Based with 

S/L Adjustments 

AL 317 359 1,072 

FL 234 1,631 2,976 

GA 83 686 1,677 

KY 326 400 476 

MS 190 333 827 

NC 54 445 663 

SC 142 343 617 

TN 204 227 241 

VA 127 694 622 

WV 121 330 180 

Total 1,798 5,448 9,351 

 Note: Emission summaries above are based on SCC’s 1-01-xxx-xx and 2-01-xxx-xx 

4.2 Summary of non-EGU Point Source Inventories 

Tables 4.2-1 through 4.2-7 summarize the 2002 base year inventory and the 2009 and 2018 

projection inventory for the non-EGU point source sector. 

Table 4.2-1 Non-EGU Point Source SO2 Emission Comparison 

State 2002 2009 2018 

AL 96,481 101,246 113,224 

FL 65,090 65,511 75,047 

GA 53,778 53,987 59,349 

KY 34,029 36,418 40,682 

MS 35,960 25,564 39,221 

NC 44,123 42,536 46,314 

SC 53,518 48,324 53,577 

TN 79,584 70,678 77,247 

VA 63,903 62,560 68,909 

WV 54,070 55,973 62,193 

Total 580,536 562,797 635,763 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Table 4.2-2 Non-EGU Point Source NOx Emission Comparison 

State 2002 2009 2018 

AL 83,310 69,409 78,318 

FL 45,156 46,020 51,902 

GA 49,251 50,353 55,824 

KY 38,392 37,758 41,034 

MS 61,526 56,397 61,533 

NC 44,928 34,767 37,801 

SC 42,153 40,019 44,021 

TN 64,331 57,883 63,453 

VA 60,415 51,046 55,945 

WV 46,612 38,031 43,359 

Total 536,074 481,683 533,190 

Table 4.2-3 Non-EGU Point Source VOC Emission Comparison 

State 2002 2009 2018 

AL 47,037 46,644 54,291 

FL 38,471 36,880 42,811 

GA 33,709 34,116 40,282 

KY 44,834 47,785 55,861 

MS 43,204 37,747 45,338 

NC 61,182 61,925 70,875 

SC 38,458 35,665 43,656 

TN 77,304 74,089 93,266 

VA 43,152 43,726 53,186 

WV 14,595 13,810 16,565 

Total 441,946 432,387 516,131 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Table 4.2-4 Non-EGU Point Source CO Emission Comparison 

State 2002 2009 2018 

AL 174,271 180,369 201,794 

FL 81,933 87,037 96,819 

GA 130,850 147,427 167,904 

KY 109,936 122,024 139,437 

MS 54,568 57,748 66,858 

NC 50,576 53,744 62,197 

SC 56,315 60,473 68,988 

TN 114,681 119,039 140,138 

VA 63,796 68,346 76,998 

WV 89,879 100,045 119,332 

 Total 926,805 996,252 1,140,465 

Table 4.2-5 Non-EGU Point Source PM10-PRI Emission Comparison 

State 2002 2009 2018 

AL 25,240 25,421 29,924 

FL 35,857 39,872 46,456 

GA 21,610 23,103 27,273 

KY 16,626 17,174 20,153 

MS 19,472 19,245 22,859 

NC 13,838 13,910 15,737 

SC 14,142 13,370 15,139 

TN 34,534 34,145 41,397 

VA 13,252 13,048 15,112 

WV 17,503 17,090 21,735 

Total 212,074 216,378 255,785 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas 
Table 4.2-6 Non-EGU Point Source PM25-PRI Emission Comparison 

State 2002 2009 2018 

AL 19,178 19,230 22,598 

FL 30,504 33,946 39,430 

GA 17,462 18,982 22,416 

KY 11,372 11,686 13,739 

MS 9,906 9,199 10,739 

NC 10,500 10,458 11,825 

SC 10,245 9,390 11,086 

TN 27,345 27,079 33,893 

VA 10,165 9,988 11,594 

WV 13,313 12,769 16,516 

Total 159,990 162,727 193,836 

Table 4.2-7 Non-EGU Point Source NH3 Emission Comparison 

State 2002 2009 2018 

AL 1,883 2,132 2,464 

FL 1,423 1,544 1,829 

GA 3,613 3,963 4,797 

KY 674 760 901 

MS 1,169 668 764 

NC 1,180 1,285 1,466 

SC 1,411 1,578 1,779 

TN 1,542 1,764 2,115 

VA 3,104 3,049 3,604 

WV 332 341 413 

Total 16,331 17,084 20,132 

Emissions Preparations & Results Appendix D.2a 

Pre-Hearing Draft November 06, 2007 

Regional Haze SIP for TN Class I Areas