Appendix F.1. 

Point Source Emissions Inventory Documentation 
TABLE OF CONTENTS 

I. INTRODUCTION.........................................................................................................1 

II. 2002 POINT SOURCE INVENTORY DEVELOPMENT.......................................................1 

 II.A. Development of 2002 Actual Point Source Inventory.......................................................1 

 II.A.1. Consolidated Emissions Reporting Rule..................................................................2 

 II.A.2. EGU Analysis.................................................................................................2 

 II.A.3. Summary of the 2002 Actual Inventory ......................................................................3 

 II.B. Development of Typical Year EGU Inventory...............................................................4 

III. 2009 POINT SOURCE EMISSIONS INVENTORY DEVELOPMENT....................................5 

 III.A. EGU Emission Projections.......................................................................................5 

 III.A.1. Chronology of the Development of EGU Projections...............................................6 

 III.A.2, VISTAS/MRPO IPM runs for EGU sources.........................................................7 

 III.A.3. Post-Processing of IPM Parsed Files..................................................................7 

 III.A.4. S/L Adjustments to IPM Modeling Results..........................................................9 

 III.A.5. Summary of 2009 EGU Point Source Inventory.....................................................11 

 III.B. Non-EGU Emission Projections..............................................................................12 

 III.B.1. Growth assumptions for non-EGU sources............................................................12 

 III.B.2. Control Programs applied to non-EGU sources....................................................13 

 III.B.2.a. OTB - NOx SIP Call (Phase I)..................................................................14 

 III.B.2.b. OTB - Industrial Boiler/Process Heater MACT..............................................14 

 III.B.2.c. OTB - 2, 4, 7, and 10-year MACT Standards................................................14 

 III.B.2.d. OTB Combustion Turbine MACT.............................................................15 

 III.B.2.e. OTW - NOx SIP Call (Phase II)................................................................15 

 III.B.2.f. Clean Air Interstate Rule.......................................................................15 

 III.B.3. Summary of 2009 non-EGU Point Source Inventory..............................................15 
LIST OF TABLES 

Table F1-1: 2002 Actual Point Source Inventory for South Carolina............................................3 

Table F1-2: NOx Emissions Comparison for EGUs.................................................................4 

Table F1-3: SCDHEC Adjustments to IPM Results for the 2009 EGU Inventory............................10 

Table F1-4: EGU Point Source NOx Emission Comparison for 2002 and 2009.............................11 

Table F1-5: EGU Point Source VOC Emission Comparison for 2002 and 2009.............................11 

Table F1-6: Non-EGU Point Source Control Programs Included in 2009 Inventory........................14 

Table F1-7: Non-EGU Point Source NOx Emission Comparison for 2002 and 2009.......................15 

Table F1-8: Non-EGU Point Source NOx Emission Comparison for 2002 and 2009.......................16 

 
1 

POINT SOURCE EMISSIONS INVENTORY DOCUMENTATION 

I. INTRODUCTION 

 The attainment modeling for the Charlotte-Gastonia-Rock Hill, North Carolina-South Carolina 8-

hour ozone nonattainment area (referred to as the Metrolina area) was performed in conjunction with the 

regional haze modeling being done by the Southeast Regional Planning Organization, Visibility 

Improvement State and Tribal Association of the Southeast (VISTAS) and the fine particulate matter 

(PM2.5) and ozone modeling being done by the Association of Southeastern Integrated Planning (ASIP). 

VISTAS and ASIP are run by the ten Southeast states (Alabama, Florida, Georgia, Kentucky, Mississippi,

North Carolina, South Carolina, Tennessee, Virginia and West Virginia). Since the regional haze and 

PM2.5 modeling uses annual simulations and includes an intermediate year that is the attainment year 

required for the Metrolina nonattainment area, the South Carolina Department of Health and 

Environmental Control (SCDHEC) decided to use this modeling for its attainment demonstration. 

Although the VISTAS/ASIP developed emission estimates for all pollutants of concern for regional haze,

fine particulate matter and ozone, only the emissions inventory discussions relevant to ozone formation, 

i.e., nitrogen oxides (NOx) and volatile organic compounds (VOCs), will be discussed in this document. 

The other pollutants will be discussed in detail in the regional haze and fine particulate matter State 

Implementation Plans (SIPs). 

II. 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 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. This document will not address the augmenting of the particulate 

matter since these pollutants are not considered an ozone precursor. The remaining 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/ASIP 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. This is consistent with the USEPA’s guidance for SIP modeling. The typical year EGU

inventory is intended to represent the five-year (2000 2004) period that will be used for the attainment 

demonstration for the PM2.5 and ozone SIPs, and to determine the regional haze reasonable progress 

goals. The second part of this section discusses the development of the typical year EGU inventory. 

 A. Development of 2002 Actual Point Source Inventory 

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

submitted the most updated statewide emissions inventory to the contractor. 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 
2 

format and that there were no referential integrity issues with those files. 

 The primary task in preparing the 2002 base year 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 NOx and VOC inventory by sector (EGU 

and non-EGU). 

 Throughout the development of the point source emissions inventory, the SCDHEC completed 

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

data corrections when needed. 

 1. Consolidated Emissions Reporting Rule 

 The CERR was published in the Federal Register on Monday, June 10, 2002 (FR Volume 67, 

Number 111, pp 39602 - 39616). 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, increase 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/ASIP 2002 base year. 

 2. EGU Analysis 

 MACTEC made a comparison of the annual sulfur dioxide (SO2) and NOx emissions for EGUs as 

reported in the S/L agencies CERR submittals and the data from the USEPA’s Clean Air Markets 

Division (CAMD) continuous emission monitoring (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 South Carolina 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 
3 

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 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/ASIP region. Southern Company is a super-regional company that owns 

EGUs in four VISTAS/ASIP 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. 

 3. Summary of the 2002 Actual Inventory 

 Table F1-1 summarizes the final 2002 actual base year inventory for South Carolina. 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 F1-1: 

2002 Actual Point Source Inventory for South Carolina 

State All Point Sources EGUs Non-EGUs 

SO2 259,916 206,399 53,518

NOx 130,394 88,241 42,153

VOC 38,927 470 38,458

CO 63,305 6,990 56,315

PM10-PRI 35,542 21,400 14,142

PM2.5-PRI 27,399 17,154 10,245

NH3 1,553 142 1,411
4 

 B. Development of Typical Year EGU Inventory 

 VISTAS/ASIP 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 year 

inventory represents the five year (2000-2004) period, which are the years used to calculate the average 

design value. 

 Data from the USEPA’s CAMD were used to develop normalization factors for producing a 2002 

typical year inventory for EGUs. The VISTAS/ASIP 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 F1-2 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. South Carolina’s actual 2002 NOx emissions were 0.3 

percent lower than the typical year emissions. 

Table F1-2 

NOx Emissions Comparison for EGUs 

 NOx Emissions (tons/year) 

State Actual 2002 Typical 2002 Percentage 

Difference 
5 

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

III. 2009 POINT SOURCE EMISSIONS INVENTORY DEVELOPMENT 

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

VISTAS/ASIP relied primarily on the Integrated Planning Model® (IPM) 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/ASIP 

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/ASIP generated 2009 inventory with control scenarios that account for 

post-2002 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. 

 A. 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 key decisions in 

selecting the final methods for performing the emissions projections. 

 • The development of the final set of IPM runs that are included in the VISTAS/ASIP 2009 

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/ASIP inventory. 

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

based on new information that was not accounted for in the IPM runs. 

 • Summary of 2002 and 2009 EGU emissions by state for NOx and VOC 
6 

 1. Chronology of the Development of EGU Projections 

 Initially, VISTAS/ASIP considered three options for developing the 2009 projection inventory 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, which VISTAS would use to represent 

projected emissions in 2009. 

 • Option 2 – Use the VISTAS/ASIP 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 2009 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 is a super-regional 

company that owns EGUs in Alabama, Florida, Georgia, and Mississippi and participates in VISTAS as 

an industry stakeholder. 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 2009. Further 

documentation of how Southern Company generated the 2009 inventory for their units can be found in 

Developing Southern Company Emissions and Flue Gas Characteristics for VISTAS Regional Haze 

Modeling (April 2005, presented at 14th International Emission Inventory Conference). 

 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 2009 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 (see Electricity Generating Unit 

{EGU} Growth Modeling Method Task 2 Evaluation, February 11, 2004). 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. Southern Company projections in 2009 were roughly 

comparable with IPM. 

 In August 2004, VISTAS/ASIP contracted with ICF to run IPM to provide utility forecasts for 2009 

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 2009. The IPM output files were delivered by ICF in November, 

and the post-processed data files were delivered by Pechan in December 2004. Only the CAIR case was 

used in the final 2009 modeling. 
7 

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

other 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 

2009 IPM runs VISTAS/ASIP asked S/L agencies to review the results of the summer 2006 set of IPM 

runs, which were incorporated into the VISTAS inventory. The SCDHEC primarily reviewed and 

commented on the IPM results with respect to IPM decisions on NOx post-combustion controls and SO2

scrubbers. 

 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 EPA'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 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. 

 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 Preparation, February 8, 2005. 

The essence of the IPM model post-processing methodology is to take an initial IPM model output file 
8 

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 (May-September) 

NOx and heat input; July day NOx and heat input; coal heat input by coal type; nameplate capacity (MW), 

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, latitudelongitude 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. Latitude-longitude 

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 EIA-767 data, and lastly using an 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 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 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/ASIP 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: 
9 

“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). 

 For the 2009 projections, VISTAS/ASIP states reviewed the PM and NH3 emissions from EGUs as 

provided by Pechan and identified significantly higher emissions in 2009 than in 2002. It was determined 

that Pechan used a set of PM and NH3 emission factors that are “the most recent USEPA approved 

uncontrolled emission factors” for estimating 2009 emissions. These factors are most likely not the same 

emission factors used by States for estimating these emissions in 2002 for EGUs in the VISTAS/ASIP 

region. Thus, the emission increase from 2002 to 2009 was simply an artifact of the change in emission 

factor, not anything to do with changes in activity or control technology application. Also, 

VISTAS/ASIP states identified an inconsistent use of SCCs for determining emission factors between the

base and future years. The resolution of the PM and NH3 problem is fully documented in EGU Emission 

Factors and Emission Factor Assignment, memorandum from Greg Stella to VISTAS State Point Source 

Contacts and VISTAS EGU Special Interest Workgroup, June 13, 2005 (attached in Appendix Q). The 

first step was the adjustment of the 2002 base year emissions inventory. Using the latest “USEPAapproved” uncontrolled emission factors by SCC, Alpine Geophysics utilized CERR or VISTAS/ASIP 

reported annual heat input, fuel throughput, heat, ash and sulfur content to estimate annual uncontrolled 

emissions for units identified as output by IPM. This step was conducted for non-CEM pollutants (CO, 

VOC, PM, and NH3) only. For PM emissions, the condensable component of emissions was calculated 

and added to the resulting PM primary estimations. The resulting emissions were then adjusted by any 

control efficiency factors reported in the CERR or VISTAS data collection effort. The second adjustment 

was to the future year inventories. Alpine Geophysics updated the SCCs in the future year inventory to 

assign the same base year SCC. Using the same methods as described for the 2002 revisions, those nonIPM generated pollutants were estimated using IPM predicted fuel characteristics and base year 2002 

SCC assignments. 

 4. 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/ASIP 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 SCDHEC to the IPM results are also summarized in Table F1-3. 

 S/L agencies provided information and/or comment on changes in stack parameters from the 2002 

inventory for the 2009 inventory. 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 2009, 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 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 degrees F (this is the 

virtual temperature derived from a wet temperature of 130 degrees F). VISTAS determined that exit 
10 

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

scrubber technology. 

Table F1-3 

SCDHEC Adjustments to IPM Results for the 2009 EGU Inventory 

State Plant Name and ID Unit Nature of Update/Correction 

SC 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. 

SC Winyah 

ORISID=6249 

1 – 4 

 Unit 1: Install scrubber that meets 95 percent removal 

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

0.03 lb/mmBTU by Dec. 31, 2008 

 Unit 2: Replace scrubber with one that meets 95 

percent removal efficiency from 45 percent by Dec. 31, 

2008; Upgrade ESP from 0.10 to 0.03 lb/mmBTU by Dec. 

31, 2008 

 Unit 3: Upgrade scrubber from 70 percent to 90 

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

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

 Unit 4: Upgrade scrubber from 70 percent to 90 

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

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

 Recalculated SO2 and PM emissions based on upgrade 

in control efficiencies. 

SC Dolphus Grainger 

ORISID=3317 1, 2 

 Unit 1: Upgrade ESP from 0.60 to 0.03 lb/mmBTU by 

Dec. 31, 2012. Reduced PM10 and PM25 emissions in 2018 

by 95 percent based on change in allowable emission rate 

 Unit 2: Install low NOx burners that meet 0.46 

lb/mmBTU from 0.9 by May 1, 2004. Recalculated NOx

emissions using 0.46/lbs/mmBtu and IPM heat input 

 Unit 2: Upgrade ESP from 0.60 to 0.03 lb/mmBTU by 

Dec. 31, 2012. Reduced PM10 and PM25 emissions in 2018 

by 95 percent based on change in allowable emission rate 

SC Jeffries 

ORISID=3319 3, 4 

 Unit 3: Upgrade ESP from 0.54 to 0.03 lb/mmBTU by 

Dec. 31, 2012. Reduced PM10 and PM25 emissions in 2018 

by 94.44 percent based on change in allowable emission 

rate 

 Unit 4: Upgrade ESP from 0.54 to 0.03 lb/mmBTU by 

Dec. 31, 2012. Reduced PM10 and PM25 emissions in 2018 

by 94.44 percent based on change in allowable emission 

rate 
11 

SC W S Lee 

ORISID=3264 1, 2 

 IPM does not indicate that these units are installing 

SOFA NOx control technology by April 30, 2006 to meet 

0.27 lb/mmBTU, down from 0.45 lb/mmBtu. Calculated 

NOx emissions using IPM heat input and 0.27 lbs/mmBtu 

SC Generic Unit 

ORISID=900545 All 

 All predictions for generic units appear reasonable 

with the exception of Plant ID ORIS900545 Point ID 

GSC45 which was modeled in Georgetown County. It will 

be very difficult to add new generation this close to the 

Cape Romain Class I area. Santee Cooper has no plans for 

future generation in Georgetown County, but does have 

plans for new future generation in Florence County. This 

unit was moved to coordinates specified in Florence

County. 

 5. Summary of 2009 EGU Point Source Inventory 

 Tables F1-4 and F1-5 summarize the 2002 base year inventory and 2009 projection inventory for the 

EGU source sector. The 2009 inventory include the adjustments to the IPM results specified by the S/L

agencies in the previous section. 

 

Table F1-4 

EGU Point Source NOx Emission Comparison for 2002 and 2009. 

State 2002 VISTAS 2009 IPM Based with S/L 

Adjustments 

AL 161,038 82,305 

FL 257,677 86,165 

GA 147,517 98,497 

KY 198,817 92,021 

MS 43,135 36,011 

NC 151,854 66,522 

SC 88,241 46,915 

TN 157,307 66,405 

VA 86,886 66,219 

WV 230,977 86,328 

Total 1,523,449 727,388 

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

 

Table F1-5 

EGU Point Source VOC Emission Comparison for 2002 and 2009. 

State 2002 VISTAS 2009 IPM Based with S/L 

Adjustments 

AL 2,295 2,473 

FL 2,524 1,910 

GA 1,244 2,314 
12 

KY 1,487 1,369 

MS 648 404 

NC 988 954 

SC 470 660 

TN 926 932 

VA 754 778 

WV 1,180 1,361 

Total 12,516 13,155 

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

 B. 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/ASIP 

contractor used the 2002 VISTAS/ASIP 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 nonEGU 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 non-EGU emissions inventory. 

 MACTEC performed the following activities to apply growth and control factors to the 2002 nonEGU emissions inventory to generate the 2009 projection inventory: 

 • Obtained, reviewed, and applied the most current growth factors developed by EPA, 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 inventory. 

 The following sections discuss each of these steps. 

 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 reports entitled 
13 

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 emissions inventory: 

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

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

socioeconomic data (output by industry sector, population, farm sector value added, and gasoline and oil 

expenditures) are available by 4-digit SIC code at the State level. 

 • Energy consumption data from the DOE’s 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 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. The AF&PA projection factor (1.067) is for the United States industry and applies to all 

States equally. The number comes from the 15-year forecast for world pulp and recovered paper prepared 

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

growth factors by SIC instead of the factors obtained from the USEPA’s CAIR analysis for the 2009 

emission inventory. 

 For the 2009 inventory, the VISTAS/ASIP contractor made one additional change to the growth 

factors. The AEO2004 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/ASIP contractor obtained the corresponding AEO2006 projection tables from DOE’s web site. 

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/ASIP 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 emissions in NIF EM tables for the affected SCCs. 

 2. Control Programs applied to non-EGU sources 

 VISTAS developed two control scenarios: on-the-books (OTB) controls and on-the-way (OTW) 

controls. The OTB control scenario accounts for post-2002 emission reductions from recently 
14 

promulgated federal, State, local, and site-specific control programs. The OTW control scenario accounts 

for proposed (but not final) control programs that are reasonably anticipated to result in post-2002 

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

emission control programs are discussed in the following sections. 

Table F1-6 

Non-EGU Point Source Control Programs Included in 2009 Inventory. 

On-the-Books (Cut-off of July 1, 2004 for Base 1 adoption) 

 • Atlanta / Northern Kentucky / Birmingham 1-hr SIPs 

 • Industrial Boiler/Process Heater/RICE MACT 

 • NOx RACT in 1-hr NAA SIPs 

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

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

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

 • Combustion Turbine MACT 

On-the-Way 

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

 a. OTB - 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 EPA’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 future year inventory. 

 b. OTB - 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/ASIP 

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. 

 c. OTB - 2, 4, 7, and 10-year MACT Standards 

 Maximum achievable control technology (MACT) requirements were also applied, as documented in 
15 

the 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 (FR) notices and 

discussions with the USEPA’s Emission Standards Division (ESD) 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. 

 d. OTB 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. 

 e. OTW - 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. North Carolina provided more specific information on the anticipated controls at the 

compressor stations. This information was used in the 2009 inventory instead of the default approach 

used by the USEPA in the proposed Phase II rule. 

 f. Clean Air Interstate Rule 

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

 

 3. Summary of 2009 non-EGU Point Source Inventory 

 Tables F1-7 and F1-8 summarize the 2009 non-EGU point source inventory for NOx and VOC 

emissions. 

Table F1-7 

Non-EGU Point Source NOx Emission Comparison for 2002 & 2009. 

State 2002 2009 

AL 83,310 69,409 

FL 45,156 46,020 

GA 49,251 50,353 

KY 38,392 37,758 

MS 61,526 56,397 

NC 44,928 34,767 

SC 42,153 40,019 

TN 64,344 57,883 

VA 60,415 51,046 
16 

WV 46,612 38,031 

Total 536,087 481,683 

 

Table F1-8 

Non-EGU Point Source VOC Emission Comparison for 2002 & 2009. 

State 2002 2009 

AL 47,037 46,644 

FL 38,471 36,880 

GA 33,709 34,116 

KY 44,834 47,785 

MS 43,204 37,747 

NC 61,182 61,925 

SC 38,458 35,665 

TN 84,328 74,089 

VA 43,152 43,726 

WV 14,595 13,810 

Total 448,970 432,387