Appendix F.1. Point Source Emissions Inventory DocumentationTABLE OF CONTENTS

I. INTRODUCTION

**........................................................................... ..............................1** 

II. 2002 POINT SOURCE INVENTORY DEVELOPMENT

**......... ........................**  **......................1**
**II.A. Development of 2002 Actual Point Source Inv entory.......................................................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 DEVELOP MENT

**......... ...........................5** 
**III.A. EGU Emission Projections................................................ .......................................5** 
**III.A.1. Chronology of the Development of EGU Pro jections......................** 

**......................... 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 Invento ry.....................................................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 sour ces..............................** 

**...................... 13** 

**III.B.2.a. OTB - NO**
**x SIP Call (Phase I).........................................................**  **.........14**

**III.B.2.b. OTB - Industrial Boiler/Process Heate r MACT...............**  **...............................14**
**III.B.2.c. OTB - 2, 4, 7, and 10-year MACT Stand ards..................**  **..............................14**

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

**... ........................**  **....15**

**III.B.2.e. OTW - NO**
**x SIP Call (Phase II).................................**  **...............................15**

**III.B.2.f. Clean Air Interstate Rule.................................... ...................................15** 
**III.B.3. Summary of 2009 non-EGU Point Source Inv entory..............................................15** LIST OF TABLES

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

**Table F1-2: NO**
**x**

**Emissions Comparison for EGUs......................................................... ........4** 

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

**Table F1-4: EGU Point Source NO**
**x Emission Comparison for 2002 and 2009.............................**  **11**

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

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

**Table F1-7: Non-EGU Point Source NO**
**x Emission Comparison for 2002 and 2009......................**  **.15**

**Table F1-8: Non-EGU Point Source NO**
**x 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 M etrolina area) was performed in conjunction with th**  **e regional haze modeling being done by the Southeast**  **Regional Planning Organization, Visibility Improvement State and Tribal Association of the Sou**  **theast (VISTAS) and the fine particulate matter (PM2.5) and ozone modeling being done by the Associ**  **ation 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 estimat**  **es for all pollutants of concern for regional haze, fine particulate matter and ozone, only the emissio**  **ns inventory discussions relevant to ozone formatio n,**  **i.e., nitrogen oxides (NO**
**x ) and volatile organic compounds (VOCs), will be di**  **scussed in this document. The other pollutants will be discussed in detail in**  **the regional haze and fine particulate matter Stat e**  **Implementation Plans (SIPs).**

II. 2002 POINT SOURCE INVENTORY DEVELOPMENT

**This section details the development of the 2002 b ase year inventory for point sources. There were**  **two major components to the development of the poin t source sector of the inventory. The first**  **component was the incorporation of data submitted b y State and Local (S/L) agencies to the United Stat**  **es Environmental Protection Agency (USEPA) as part of**  **the Consolidated Emissions Reporting Rule (CERR) requirements. Work on incorporating the CER**  **R data into the revised base year involved: 1) obtaining the data from the USEPA or the S/L agenci**  **es, 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 r**  **eviews for each component of the point source inventory, and 6) updating the database with correc**  **tions 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 desc**  **ribed in the first portion of this section.**

**The second component was the development of a “typ ical” year inventory for electric generating**  **units (EGUs). The VISTAS/ASIP states determined th at 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 (2 000 2004) period that will be used for the attainme**  **nt demonstration for the PM2.5 and ozone SIPs, and to**  **determine the regional haze reasonable progress goals. The second part of this section discusses t**  **he development of the typical year EGU inventory.**

A. Development of 2002 Actual Point Source Invent ory

**VISTAS/ASIP contracted with MACTEC to develop the 2002 emission inventory. SCDHEC**  **submitted the most updated statewide emissions inve ntory to the contractor. Once all of the files wer**  **e obtained, MACTEC ran the files through the USEPA’s**  **National Emissions Inventory (NEI) Input Format (NIF) Basic Format and Content checking tool to ens**  **ure 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 i nventory was the incorporation of corrections and**  **new information as submitted by the S/L agencies ba sed 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 emiss**  **ions, and other quality assurance/quality control (QA/QC) checks. The final subsection summarizes th**  **e 2002 NO**
**x and VOC inventory by sector (EGU**  **and non-EGU).**

**Throughout the development of the point source emi ssions 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 ha**  **ve, at times, forced reporting agencies into ineffi cient**  **collecting and reporting activities. This rule cons olidates the emission inventory reporting requireme**  **nts 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 inven tory**  **program, increase the efficiency of the emission in ventory program, and provide more consistent and**  **uniform data.**

**States are required to prepare a comprehensive sta tewide 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 diox ide (SO**  **2 ) and NO** 
**x emissions for EGUs as**  **reported in the S/L agencies CERR submittals and th e 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 t o the USEPA for units that are subject to CEM**  **reporting requirements of the NO**
**x SIP Call rule and Title IV of the CAA. The USEPA**  **sums the hourly CEM emissions to the annual level, and MACTEC compa**  **red these annual CEM emissions to those in the S/L inventories. The 2002 CEM inventory containing**  **NO**
**x and SO**  **2 emissions and heat input data were**  **downloaded from the USEPA CAMD web site (www.epa.go v/airmarkets). The data were provided by**  **quarter and emission unit.**

**The first step in the EGU analysis involved prepar ing 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) identificatio n (ID) code identifies unique facilities and the un**  **it ID identifies unique boilers and internal combustio**  **n engines (i.e., turbines and reciprocating engines ). In**  **the South Carolina point source emissions inventori es, 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 un it 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 un it ID in the emissions inventories. The initial**  **crosswalk contained both the annual emissions summe d from the CAMD database, as well as the S/L**  **emission estimate. The matching at the facility le vel 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 th e**  **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 ann ual emissions reported in the S/L inventory. The**  **facility-level comparison of CEM to emission invent ory NO** 
**x and SO**  **2 emissions found that for most**  **facilities, the annual emissions from the S/L inven tory 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 SO**  **2 and NO** 
**x emissions for select Southern**  **Company units in the VISTAS/ASIP region. Southern C ompany 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 Compan y 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 St ates 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 dif ferences 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 li sted each unit individually. MACTEC compared**  **SO 2**  **and NO**
**x**

**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 y ear inventory for South Carolina. All values are**  **in tons per year. The EGU emissions include the em issions from all processes with a Source**  **Classification Code (SCC) of either 1-01-xxx-xx (Ex ternal 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 Caroli na

**State All Point Sources EGUs Non-EGUs**
**SO 2**  **259,916 206,399**  **53,518 NO** 
**x 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, econom ic, and outage factors in 2002. The typical year**  **inventory represents the five year (2000-2004) peri od, which are the years used to calculate the avera**  **ge design value.** 

**Data from the USEPA’s CAMD were used to develop no rmalization factors for producing a 2002**  **typical year inventory for EGUs. The VISTAS/ASIP c ontractor used the ratio of the 2000 2004 average**  **heat input and the 2002 actual heat input to normal ize 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 SO**  **2 and**  **NO**
**x emission rates, heat input, and operating hours.** 

**MACTEC used the actual 2002 heat input and the ave rage heat input for the 5-year period from**  **2000-2004 as the normalization factor, as follows:**

**Normalization Factor: 2000-2004 average he at input**  **20 02 actual heat input** 

**If the unit did not operate for all five years, th en 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 th e**  **normalization factor to determine the typical emiss ions for 2002, as follows:** 

**Typical Emissions = 2002 actual emissions x Normalization Factor** 

**After applying the normalization factor, some adju stments were needed for special circumstances.**  **For example, a unit may not have operated in 2002 a nd 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 h**  **ad not been permanently retired and would normally ope**  **rate 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 emis sions 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 pollu tant for the actual 2002 EGU inventory and the**  **typical year EGU inventory. For the entire VISTAS region, actual 2002 NO** 
**x emissions were about 0.1**  **percent lower than the typical year emissions. Sou th Carolina’s actual 2002 NO** 
**x emissions were 0.3**  **percent lower than the typical year emissions.**

Table F1-2 NO
x Emissions Comparison for EGUs

**NO**
**x 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 DEVELOP MENT

**Different approaches were used for different secto rs of the point source inventory. For the EGUs,**  **VISTAS/ASIP relied primarily on the Integrated Plan ning Model® (IPM) to project future generation, as**  **well as to calculate the impact of future emission control programs. The IPM results were adjusted ba**  **sed on S/L agency knowledge of planned emission control**  **s at specific EGUs. For non-EGUs, VISTAS/ASIP used recently updated growth and control data consi**  **stent with the data used in the USEPA’s Clean Air Interstate Rule (CAIR) analyses, and supplemented t**  **hese data with available S/L agency input and updated fuel use forecast data for the United State**  **s Department of Energy.**

**For both sectors, VISTAS/ASIP generated 2009 inven tory 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 d iscusses 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 t he development of the EGU projections.** 

**• A chronology of the EGU development process use d by MACTEC and key decisions in**  **selecting the final methods for performing the emis sions projections.** 

**• The development of the final set of IPM runs th at are included in the VISTAS/ASIP 2009**  **inventory.**

**• The process of transforming the IPM parsed file s into NIF format.** 

**• The process for ensuring that units accounted f or 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 agencie s 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 NO** 
**x and VOC** **6**

1. Chronology of the Development of EGU Projecti ons

**Initially, VISTAS/ASIP considered three options fo r developing the 2009 projection inventory for**  **EGUs:**

**• Option 1 – Use the results of IPM modeling cond ucted in support of the proposed CAIR**  **base and control case analyses as the starting poin t and refine the projections with readily available**  **inputs from stakeholders. These IPM runs were conducted f**  **or 2010, which VISTAS would use to represent projected emissions in 2009.** 

**• Option 2 – Use the VISTAS/ASIP 2002 typical yea r as the starting point, apply growth**  **factors from the Energy Information Administration, and refine future emission rates with stakeholder**  **input regarding utilization rates, capacity, retire ments, and new unit information.** 

**• Option 3 – Use the results of a new round of IP M modeling sponsored by VISTAS and the**  **Midwest Regional Planning Organization (MRPO). The se runs incorporated VISTAS specific unit and**  **regulation modified parameters, and generate result s 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 thei r energy budget forecast to project net generation**  **and heat input for every existing and future Southe rn 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 Internation al Emission Inventory Conference).** 

**Each of these three options and the Southern Compa ny projections were discussed in a series of**  **conference calls with the VISTAS EGU Special Intere st Work Group (SIWG) during the fall of 2004.**  **During a conference call on December 6, 2004, the V ISTAS EGU SIWG approved the use of the latest**  **VISTAS/MRPO sponsored IPM runs (Option 3) to repres ent 2009 EGU forecasts of emissions the future** 

**year cases.**

**The Option 3 IPM modeling resulted from a joint ag reement by VISTAS and MRPO to work**  **together to develop future year utility emissions b ased on IPM modeling. The decision to use IPM**  **modeling was based in part on a study of utility fo recast methods by E.H. Pechan and Associates, Inc.**  **(Pechan) for MRPO, which recommended IPM as a viabl e methodology (see Electricity Generating Unit**  **{EGU} Growth Modeling Method Task 2 Evaluation, Feb ruary 11, 2004). Although the USEPA used**  **IPM recently to support their rulemaking for the CA IR, VISTAS stakeholders felt that certain model**  **inputs needed to be improved. Thus, VISTAS and MRP O 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 Cas e. The Base Case represents the current operation**  **of the power system under currently known laws and regulations, including those that come into force i**  **n 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. Th**  **e IPM output files were delivered by ICF in Novembe r,**  **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 chang es 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, e**  **tc.). The second file contains just the fossil-fuel burni**  **ng units (e.g., emissions from biomass and landfill gas**  **are omitted). The RPOs decided to use the fossil-o nly file for modeling to be consistent with the USE**  **PA, since the USEPA used the fossil only results for CA**  **IR analyses. For the 10 VISTAS states, non-fossil fuels accounted for only 0.13 percent of the NO** 
**x emissions and 0.04 percent of the SO**  **2 emissions in the**  **2009 IPM runs VISTAS/ASIP asked S/L agencies to rev iew the results of the summer 2006 set of IPM**  **runs, which were incorporated into the VISTAS inven tory. The SCDHEC primarily reviewed and**  **commented on the IPM results with respect to IPM de cisions on NO** 
**x post-combustion controls and SO**  **2 scrubbers.** 

2. VISTAS/MRPO IPM runs for EGU sources

**The following summary of the VISTAS/MRPO IPM® mode ling 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 Mode ling Applications (V.2.1.6) Using the IPM,**  **EPA 430/R-03-007, July 2003.**

**IPM provides “forecasts of least-cost capacity exp ansion, electricity dispatch, and emission control**  **strategies for meeting energy demand and environmen tal, transmission, dispatch, and reliability**  **constraints.” The underlying database in this mode ling is USEPA’s National Electric Energy Data**  **System (NEEDS) released with the CAIR Notice of Dat a Availability (NODA). The NEEDS database**  **contains the existing and planned/committed unit da ta in the USEPA modeling applications of IPM.**  **NEEDS includes basic geographic, operating, air emi ssions, and other data on these generating units.**  **VISTAS States and stakeholders provided changes for :** 

**• NO**
**x**

**post-combustion control on existing units • SO**  **2 scrubbers on existing units**  **• SO 2**  **emission limitations • PM controls on existing units**  **• Summer net dependable capacity • Heat rate for existing units**  **• SO 2**  **and NO**
**x 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 model ing is based on Pechan’s documentation**  **LADCO IPM Model Parsed File Post-Processing Methodo logy and File Preparation, February 8, 2005.**  **The essence of the IPM model post-processing method ology 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 b oth (1) “existing” units and (2) committed or new**  **generic aggregates.**

**All records have unit and fuel type data; existing , retrofit (for SO**  **2 and NO** 
**x ), and separate NO** 
**x control information; annual SO**  **2 and NO** 
**x emissions and heat input; summer season (May-Septe**  **mber) NO** 
**x and heat input; July day NO** 
**x and heat input; coal heat input by coal type; name**  **plate capacity (MW), and State FIPS code. Existing units also have count**  **y FIPS code, a unique plant identifier (ORISPL) and unit ID (also called boiler ID) (BLRID); generic un**  **its 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 appro priate IDs. This processing is described in more de**  **tail 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 aggreg ates 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 gen**  **eric by assigning a sister plant that is in a count y**  **based on its attainment/nonattainment status. With in a State, plants (in county then ORIS plant code**  **order) in attainment counties are used first as sis ter sites to generic units, followed by plants in P**  **M2.5 nonattainment counties, followed by plants in 8 hou**  **r ozone nonattainment counties. Note that no LADCO or VISTAS States provided blackout counties t**  **hat would not be considered when siting generics, so this process is identical to the one used for th**  **e 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 use d for generic units’ assignments. Latitude-longitu**  **de coordinates were assigned, first using the USEPA-pr**  **ovided data files, secondly using the September 17, 2004 Pechan in-house latitude-longitude file, and l**  **astly using county centroids. These data were only used when the data were not provided in the 2002 NI**  **F files. Stack parameters were attached, first usin g**  **the USEPA-provided data files, secondly using a Mar ch 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 us**  **ing 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 us**  **ed 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 Pec**  **han emission factor file based on AP-42 emission factors. Note that this updated file is n**  **ot the one used for estimating emissions for previo us**  **USEPA post-processed IPM files. Emissions for 28 t emporal-pollutant combinations were estimated**  **since there are seven pollutants (VOC, CO, primary PM10 and PM2.5, NH3, SO**  **2 and NO** 
**x ) and four**  **temporal periods (annual, summer season, winter sea son, July day).** 

**The next step was to match the IPM unit IDs with t he identifiers in VISTAS/ASIP 2002 inventory.**  **A crosswalk file was used to obtain FIPS State and county, plant ID (within State and county), and poi**  **nt ID. If the FIPS State and county, plant ID and poi**  **nt 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 mat ch and are in the 2002 VISTAS inventory, and**  **“NoNIF files” for IPM units that are not in the 200 2 VISTAS inventory (which includes existing units**  **with or without a crosswalk match as well as generi c units).** 

**For the 2009 projections, VISTAS/ASIP states revie wed the PM and NH3 emissions from EGUs as**  **provided by Pechan and identified significantly hig her emissions in 2009 than in 2002. It was determi**  **ned that Pechan used a set of PM and NH3 emission facto**  **rs that are “the most recent USEPA approved uncontrolled emission factors” for estimating 2009**  **emissions. These factors are most likely not the s ame**  **emission factors used by States for estimating thes e emissions in 2002 for EGUs in the VISTAS/ASIP**  **region. Thus, the emission increase from 2002 to 2 009 was simply an artifact of the change in emissio**  **n factor, not anything to do with changes in activity**  **or control technology application. Also, VISTAS/ASIP states identified an inconsistent use o**  **f SCCs for determining emission factors between the base and future years. The resolution of the PM an**  **d 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 “USEPA approved” uncontrolled emission factors by SCC, Alp**  **ine Geophysics utilized CERR or VISTAS/ASIP reported annual heat input, fuel throughput, heat,**  **ash and sulfur content to estimate annual uncontrol led**  **emissions for units identified as output by IPM. T his step was conducted for non-CEM pollutants (CO,**  **VOC, PM, and NH3) only. For PM emissions, the cond ensable 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 adjustme**  **nt was to the future year inventories. Alpine Geophys**  **ics updated the SCCs in the future year inventory t o**  **assign the same base year SCC. Using the same meth ods as described for the 2002 revisions, those non**  **IPM generated pollutants were estimated using IPM p redicted 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 IP M runs, S/L agencies specified a number of changes**  **to the IPM results to better reflect current inform ation 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, complianc e**  **plans, permits, and discussions/commitments from in dividual companies.** 

**Some S/L agencies specified changes to the control s 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 SO 2**  **scrubber controls, used a control efficiency of 90 percent when adding or**  **removing NO**
**x**

**SCR controls at coal-fired plants, 80 percent when adding or removing NO** 
**x SCR controls**  **at gas-fired plants, and 35 percent when adding or removing NO** 
**x 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 o n 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 w here an emission unit projected to have a SO**  **2 scrubber**  **in 2009, some states were able to provide revised s tack parameters for some units based on design**  **features for the new control system. Other units p rojected to install scrubbers by 2009 are not far e**  **nough 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 sam e; 3)**  **keep the current flow rate the same, and 4) change the stack exit temperature to 169 degrees F (this i**  **s 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/Corre ction** 

**SC Cross**  **ORISID=130 1, 2**  **Unit 1: upgrade scrubber from 82 percent to 95 per cent**  **removal efficiency by June 30, 2006. Recalculate em issions**  **based on upgrade in control efficiency. Unit 2: upgrade scrubber from 70 percent to 87 per**  **cent removal efficiency by June 30, 2006. Recalculate em**  **issions based on upgrade in control efficiency.** 

**SC Winyah**  **ORISID=6249 1 – 4**  **Unit 1: Install scrubber that meets 95 percent rem oval**  **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; Upgra**  **de 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; Upgra**  **de ESP from 0.10 to 0.03 lb/mmBTU by Dec. 31, 2007**  **Recalculated SO 2**  **and PM emissions based on upgrade in control efficiencies.** 

**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 2**  **018 by 95 percent based on change in allowable emission**  **rate Unit 2: Install low NO** 
**x burners that meet 0.46**  **lb/mmBTU from 0.9 by May 1, 2004. Recalculated NO**
**x 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 2**  **018 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 2**  **018 by 94.44 percent based on change in allowable emiss**  **ion**

**rate Unit 4: Upgrade ESP from 0.54 to 0.03 lb/mmBTU by**  **Dec. 31, 2012. Reduced PM10 and PM25 emissions in 2 018**  **by 94.44 percent based on change in allowable emiss ion** 

**rate 11** 

**SC W S Lee**  **ORISID=3264 1, 2**  **IPM does not indicate that these units are install ing**  **SOFA NO**
**x**

**control technology by April 30, 2006 to meet 0.27 lb/mmBTU, down from 0.45 lb/mmBtu. Calculated**  **NO**
**x emissions using IPM heat input and 0.27 lbs/mmBtu** 

**SC Generic Unit**  **ORISID=900545 All**  **All predictions for generic units appear reasonabl e**  **with the exception of Plant ID ORIS900545 Point ID GSC45 which was modeled in Georgetown County. It wi**  **ll be very difficult to add new generation this close**  **to the Cape Romain Class I area. Santee Cooper has no plan**  **s for future generation in Georgetown County, but does ha**  **ve 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 **NO**
**x**

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 a nd 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 da ta was to use recently updated growth and control**  **data consistent with the data used in the USEPA’s C AIR analyses, supplement these data with available**  **stakeholder input, and provide the results for stak eholder review to ensure credibility. The VISTAS/A**  **SIP contractor used the 2002 VISTAS/ASIP base year inve**  **ntory, 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 th**  **is file contains both EGUs and nonEGU point sources, and EGU emissions are projected using the**  **IPM, it was necessary to split the 2002 point sourc e**  **file into two components. The first component cont ains 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 non**  **EGU emissions inventory to generate the 2009 projec tion inventory:** 

**• Obtained, reviewed, and applied the most curren t growth factors developed by EPA, based**  **on forecasts from an updated Regional Economic Mode ls, Inc. (REMI) model (version 5.5) and the latest**  **Annual Energy Outlook published by the Department o f Energy (DOE);** 

**• Obtained, reviewed, and applied any State-speci fic 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 inv entories;** 

**• Obtained, reviewed, and applied control assumpt ions;** 

**• Provided data files in NIF3.0 format and emissi on summaries in EXCEL format for review**  **and comment; and**

**• Updated the database with corrections or new in formation 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 emis sion inventory were consistent with the USEPA’s**  **analyses for the CAIR rulemaking. These growth fac tors are fully documented in the reports entitled** **13**

**Development of Growth Factors for Future Year Model ing 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 E conomic Model, Inc. (REMI) Policy**  **Insight® model, version 5.5 (being used in the deve lopment of the EGAS Version 5.0). The REMI**  **socioeconomic data (output by industry sector, popu lation, farm sector value added, and gasoline and o**  **il expenditures) are available by 4-digit SIC code at**  **the State level.**

**• Energy consumption data from the DOE’s Energy I nformation Administration’s (EIA)**  **Annual Energy Outlook 2004, with Projections throug h 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 u se sectors (e.g., commercial coal, industrial natur**  **al gas). Growth factors for the residential natural ga**  **s combustion category, for example, are based on residential natural gas consumption forecasts that**  **are reported at the Census division level. These Ce nsus**  **divisions represent a group of States (e.g., the So uth Atlantic division includes eight southeastern S**  **tates and the District of Columbia). Although one would e**  **xpect different growth rates in each of these State s**  **due to unique demographic and socioeconomic trends, all States within each division received the same**  **growth rate.**

**• Specific changes for sectors (e.g., plastics, s ynthetic rubber, carbon black, cement**  **manufacturing, primary metals, fabricated metals, m otor vehicles and equipment) where the REMI-based**  **rates were unrealistic or highly uncertain. Growth projections for these sectors were based on industr**  **y group forecasts, Bureau of Labor Statistics (BLS) p**  **rojections and Bureau of Economic Analysis (BEA) historical growth from 1987-2002.** 

**In addition to the growth data described above, VI STAS received two sets of growth projections**  **from stakeholders. The American Forest and Paper A ssociation (AF&PA) supplied growth projections**  **for the pulp and paper sector, which were applied t o SIC 26xx Paper and Allied Products, for growth fr**  **om 2002 to 2009. The AF&PA projection factor (1.067)**  **is for the United States industry and applies to al l**  **States equally. The number comes from the 15-year forecast for world pulp and recovered paper prepare**  **d by Resource Information Systems Inc. (RISI). The V**  **ISTAS/ASIP contractor used the above AF&PA growth factors by SIC instead of the factors obtain**  **ed 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 mo re recent AEO2006 forecasts (released in February**  **2006) to reflect changes in the energy market and t o improve the emissions growth factors produced. T**  **he VISTAS/ASIP contractor obtained the corresponding A**  **EO2006 projection tables from DOE’s web site. VISTAS developed tables comparing the growth factor**  **s 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 th e updated growth factors to 2002 actual emissions**  **and replaced the 2009 emissions in NIF EM tables fo r the affected SCCs.** 

2. Control Programs applied to non-EGU sources

**VISTAS developed two control scenarios: on-the-boo ks (OTB) controls and on-the-way (OTW)**  **controls. The OTB control scenario accounts for pos t-2002 emission reductions from recently** **14**

**promulgated federal, State, local, and site-specifi c control programs. The OTW control scenario accoun**  **ts for proposed (but not final) control programs that**  **are reasonably anticipated to result in post-2002 emission reductions. The methodologies used to acco**  **unt for the emission reductions associated with the se**  **emission control programs are discussed in the foll owing sections.** 

Table F1-6 Non-EGU Point Source Control Programs Included in 2 009 Inventory.

**On-the-Books (Cut-off of July 1, 2004 for Base 1 ad option)** 

**• Atlanta / Northern Kentucky / Birmingham 1-hr SI Ps**  **• Industrial Boiler/Process Heater/RICE MACT**
**• NO**
**x**

**RACT in 1-hr NAA SIPs**
**• NO**
**x**

**SIP Call (Phase I- except where States have adopte d 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**

**• NO**
**x**

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

a. OTB - NO
x SIP Call (Phase I)

**Phase I of the NO**
**x**

**SIP call applies to certain large non-EGUs, includ ing large industrial boilers and**  **turbines, and cement kilns. States in the VISTAS r egion affected by the NO** 
**x SIP call have developed**  **rules for the control of NO**
**x emissions that have been approved by the USEPA. VI**  **STAS reviewed the available State rules and guidance documents to det**  **ermine the affected sources and ozone season allowances. VISTAS also obtained and reviewed info**  **rmation in the EPA’s CAMD NO**
**x Allowance**  **Tracking System - Allowances Held Report. Since the se controls are to be in effect by the year 2007,**  **VISTAS capped the emissions for NO**
**x SIP call affected sources at 2007 levels and carri**  **ed forward the capped levels for the 2009 future year inventory.** 

b. OTB - Industrial Boiler/Process Heater MACT

**The USEPA anticipates reductions in PM and SO 2**  **as a result of the Industrial Boiler/Process Heate r**  **MACT standard. The methods used to account for the se reductions are the same as those used for the**  **CAIR analysis. Reductions were included for existi ng 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/ institutiona l boilers and process heaters. The VISTAS/ASIP**  **contractor identified boilers greater than 10 mmBtu /hr using either the boiler capacity from the VISTA**  **S 2002 inventory or if the boiler capacity was missin**  **g, a default capacity based on a methodology developed by the USEPA for assigning default capaci**  **ties based on SCC code. The applied MACT control efficiencies were 4 percent for SO**  **2 and 40 for percent for PM10 and PM2.5.** 

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

**Maximum achievable control technology (MACT) requi rements were also applied, as documented in** **15**

**the report entitled Control Packet Development and Data Sources, dated July 14, 2004. The point sourc**  **e MACTs and associated emission reductions were desig**  **ned from Federal Register (FR) notices and discussions with the USEPA’s Emission Standards Div**  **ision (ESD) staff. VISTAS did not apply reductions for MACT standards with an initial compl**  **iance 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 stan**  **dards with an initial compliance date of 2002 or greater.** 

d. OTB Combustion Turbine MACT

**The projection inventory does not include the NO**

**x co-benefit effects of the MACT regulations for**  **Gas Turbines or stationary Reciprocating Internal C ombustion Engines, which the USEPA estimates to be**  **small compared to the overall inventory.**

e. OTW - NO
x SIP Call (Phase II)

**The final Phase II NO**
**x SIP call rule was finalized on April 21, 2004. St**  **ates had until April 21, 2005, to submit SIPs meeting the Phase II NO** 
**x budget requirements. The Phase II rule applies to**  **large IC engines, which are primarily used in pipeline trans**  **mission service at compressor stations. VISTAS identified affected units using the same methodolog**  **y 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 f or natural gas-fired IC engines and 90 percent for**  **diesel or dual fuel categories. North Carolina provided more**  **specific information on the anticipated controls a t 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 emissio n reductions from non-EGU boilers and turbines.** 

3. Summary of 2009 non-EGU Point Source Inventor y

**Tables F1-7 and F1-8 summarize the 2009 non-EGU po int source inventory for NO** 
**x and VOC**  **emissions.**

Table F1-7

Non-EGU Point Source NO
x 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 20 02 & 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**