Appendix H 

Reasonable Progress Goals and Long 

Term Strategies 
Appendix H - 1
Table of Contents 

1.0 Base G CAA Controls............................................................................................. 4 

1.1 Point Source Controls............................................................................................... 8 

1.1.1 Electric Generating Units................................................................................... 8 

1.1.2 Non-EGUs........................................................................................................ 14 

1.2 Area Source Controls.............................................................................................. 15 

1.3 Mobile Sources ....................................................................................................... 16 

1.4 Non-Road Sources.................................................................................................. 16 

1.5 Conclusion .............................................................................................................. 17 

2.0 Uniform Rate of Progress..................................................................................... 20 

3.0 Georgia Tech Sensitivities.................................................................................... 22 

3.1 Evaluation of Cape Romain.................................................................................... 22 

4.0 Reasonable Progress Evaluation........................................................................... 24 

4.1 Area of Influence .................................................................................................... 24 

4.2 Source Type Analysis............................................................................................. 25 

4.3 Area of Influence Data and Displays...................................................................... 28 

4.4 Importance of Pollutants other than Sulfate............................................................ 33 

4.5 Summary of Emission Inventories in Cost Curve Analysis.................................... 33 

4.6 Application of AirControlNET Technologies ........................................................ 37 

4.7 Development of AOI-Based Cost Curve ................................................................ 37 

5.0 Reasonable Progress Assessment ......................................................................... 39 

6.0 Four Factor Analysis............................................................................................. 42 

6.1 The Four Statutory Factors..................................................................................... 42 

6.1.1 The Cost of Compliance .................................................................................. 42 

6.1.2 Time Necessary for Compliance...................................................................... 42 

6.1.3 Energy and Non-Air Quality Environmental Impacts of Compliance............. 43 

6.1.4 Remaining Useful Life of the Source .............................................................. 43 

6.2 Evaluating Four Statutory Factors For Specific SO2 Emission Sources in Cape 

Romain’s Area of Influence.......................................................................................... 43 

6.2.1 Cost of Compliance.......................................................................................... 44 

6.2.2 Time Necessary for Compliance...................................................................... 45 

6.2.3 Energy and Non-Air Environmental Impacts.................................................. 45 

6.2.4 Remaining Useful Life..................................................................................... 45 

6.3 Process of Applying Statutory Factors ................................................................... 45 

7.0 Best Available Retrofit Technology (BART)....................................................... 48 

7.1 Background............................................................................................................. 48 

7.2 Approach to Implementation of BART Requirements........................................... 49 

7.3 Identification of BART-Eligible Sources ......................................................... 49 

7.4 Contribution Threshold........................................................................................... 50 

7.5 Exemption of Point Source VOC for BART Purposes........................................... 53 

7.5.1 Method ............................................................................................................. 53 

7.5.2 Conclusions...................................................................................................... 54 

7.6 Treatment of Ammonia........................................................................................... 54 

7.6.1 Method ............................................................................................................. 55 

7.6.2 Conclusions...................................................................................................... 56 

Appendix H - 2
8.0 Explanation of BART Exemption Modeling........................................................ 57 

8.1 Background............................................................................................................. 57 

8.2 South Carolina BART Source Exemption Modeling.............................................. 58 

8.3 Use of the New IMPROVE Algorithm................................................................... 61 

8.4 Conclusions............................................................................................................. 63 

9.0 BART Determinations and Conclusions............................................................... 64 

10.0 Final Long-Term Strategy and Reasonable Progress Goals................................. 65 

10.1 Long-Term Strategy.............................................................................................. 65 

10.2 What Additional Emissions Controls Were Considered as Part of the Long Term 

Strategy for Visibility Improvement by 2018? ............................................................. 66 

10.3 Reasonable Progress Goals................................................................................... 67 

Appendix H - 3
Appendices

Attachment H.1 – Memorandum of Understanding: SC DHEC and SCFC 

Attachment H.2.a - Cost Effectiveness Curve Design 

Attachment H.2.b – VISTAS Class 1 Federal Areas 

Attachment H.2.c – VISTAS Control Options Spreadsheet 

Attachment H.3 – Control Option Costs 

Attachment H.4 – South Carolina’s Evaluation of Source Emissions for BART Eligibility 

Attachment H.5 - BART Analysis Sensitivity Modeling 

Attachment H.6 - BART Modeling Protocols and Demonstrations 

Attachment H.7 – North Carolina’s Clean Smokestacks Act Implementation Plan 

Appendix H - 4
1.0 Base G CAA Controls 

The purpose of this appendix is to outline South Carolina’s strategy for complying with 

the requirement to set and meet Reasonable Progress Goals (RPGs) as part of South 

Carolina’s Regional Haze SIP under 40 CFR 51.308(d)(1), and the requirements for 

establishing best available retrofit (BART) controls under 40 CFR 51.308(e). 

In the 1977 amendments to the Clean Air Act (CAA), Congress set a national goal for 

visibility as “the prevention of any future, and the remedying of any existing, impairment 

of visibility in mandatory Class I Federal areas which impairment results from manmade 

pollution.” The Regional Haze Rule (RHR) at Section 51.308(d) requires states to 

demonstrate reasonable progress towards meeting the goal of a return to natural visibility 

conditions by 2064. As a guide for reasonable progress, the RHR directs states to 

graphically show what would be a “uniform rate of progress” toward natural conditions 

for each Class I area. This is known as the “glidepath.” The RHR then requires states to 

establish RPGs for visibility improvement at each affected Class I area covering each 

approximately ten-year period until 2064. The first set of RPGs will comprise South 

Carolina’s Long Term Strategy (LTS) covering the period from the present until 2018. 

This appendix provides an overview of this first LTS. In addition, a specific component 

of each state’s first LTS is dictated by the specific BART requirements in 40 CFR 

51.308(e). This appendix will also include a discussion of our strategy for developing 

those BART requirements. 

The LTS contains the following components: 

1. Inventory of all controls required or expected under all federal and state 

regulations by 2009 and 2018. 

2. Modeled expected visibility improvement from planned or existing (Base G) 

controls and Comparison of Base G results for 2018 to the uniform rate of 

progress, or “glidepath,” for Cape Romain. 

3. Discussion of emissions sensitivity model runs to help determine which 

pollutants and source categories are contributing the most to visibility 

impairment at Cape Romain (runs conducted by Georgia Institute of 

Technology). 

4. Examination of SO2 Area of Influence (AOI) projections for Cape Romain, 

and also for any surrounding states’ Class I areas whose AOI includes South 

Carolina counties, to determine which specific sources are most likely to be 

impairing visibility at specific Class I areas. 

5. Application of the four “statutory factors,” listed in 40 CFR 

51.308(d)(1)(i)(A) to those sources identified in the previous step. 

6. Identify control determination (based on the results of the four factor 

analyses) for specific sources. 

7. Identify of BART-eligible sources. 

8. Examine BART-exemption modeling for BART-eligible sources to include 

modeling demonstration of visibility improvement after inclusion of BART 

and reasonable progress control determinations. 

Appendix H - 5
9. Determination of RPGs based on the visibility improvement expected by 

2018. 

Base G Planned and Existing Controls 

2009 and 2018 controls include the following planned and existing state and federal 

controls: 

Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR). CAIR will 

permanently cap emissions of sulfur dioxide (SO2) and nitrogen oxides (NOX) in the 

eastern U.S. When fully implemented, CAIR will reduce SO2 emissions in these states 

by over 70 percent and NOX emissions by over 60 percent from 2003 levels. The Clean 

Air Mercury Rule will reduce utility emissions of mercury from 48 tons a year to 15 tons, 

a reduction of nearly 70 percent. While mercury is not a visibility-impairing pollutant, 

CAMR establishes standards of performance that limit mercury emissions from new and 

existing coal-fired power plants and creates a market-based cap-and-trade program that 

will reduce nationwide utility emissions of mercury while simultaneously reducing sulfur 

dioxide SO2 and nitrogen oxides NOX emissions. Appendix M illustrates which sources 

within South Carolina’s AOI are subject to CAIR. 

NOX SIP Call. Phase I of the NOX SIP call applies to certain Electric Generating Units 

(EGUs) and large non-EGUs, including large industrial boilers/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 EPA. This rule results in a 68 

percent reduction in NOX emissions from large stationary combustion sources by 2006. 

For this analysis, we capped the emissions for NOX SIP call-affected sources at 2007 

levels and carried forward the capped levels for the 2009/2018 future year inventories. 

NC Clean Smokestacks Act. Under the act, enacted in 2002, coal-fired power plants in 

North Carolina must achieve a 77 percent cut in nitrogen oxide (NOX) emissions by 2009 

and a 73 percent cut in sulfur dioxide (SO2) emissions by 2013. 

Consent Agreements (Santee Cooper, TECO, VEPCO, Gulf Power Crist 7, and EKPC).

A 2004 EPA consent decree calls for Santee Cooper to: install and commence operation 

of continuous emission control equipment for PM/SO2/NOX emissions; comply with 

system-wide annual PM/SO2/NOX emissions limits; agree not to buy, sell, or trade 

PM/SO2/NOX allowances allocated to Santee Cooper Systems in South Carolina as a 

result of said agreement; and comply with emission unit limits of said agreement. 

Under a 2000 settlement agreement, Tampa Electric (Florida) will: install permanent 

emissions-control equipment to meet stringent pollution limits; implement a series of 

interim pollution-reduction measures to reduce emissions while the permanent controls 

are designed and installed; and retire pollution emission allowances that Tampa Electric 

or others could use/sell to others to emit additional pollution into the environment. 

Appendix H - 6
Virginia Electric and Power Co. (VEPCO) agreed to eliminate 237,000 tons of sulfur 

dioxide (SO2) and nitrogen oxides (NOX) emissions each year from eight coal-fired 

electricity generating plants in Virginia and West Virginia. 

A 2002 agreement calls for Gulf Power to upgrade its operation to cut NOX emission 

rates by 61 percent at its Crist generating plant by 2007, with major reductions beginning 

in early 2005. The Crist plant is a significant source of NOX emissions in the Pensacola, 

Florida area. 

A July 2, 2007 consent agreement between the U.S. EPA and East Kentucky Power 

Cooperative (EKPC) requires the utility to reduce its emissions by 62,000 tpy (including 

54,000 tons of SO2 and 8,000 tons of NOX) located in Indiana, Kentucky, Ohio, Virginia, 

and West Virginia. These reductions will be achieved by installing/operating selective 

catalytic reduction (SCR) technology; low-NOX burners, and PM and mercury 

Continuous Emissions Monitors at the utility’s Spurlock, Dale and Cooper plants. 

According to the EPA, the plants’ total emissions will drop from between 50 and 75 

percent from 2005 levels. As with all federal consent decrees, EKPC is precluded from 

using reductions required under other programs, such as the Clean Air Interstate Rule. 

One-hr ozone SIPs (Atlanta, GA / Birmingham, AL / Northern Kentucky). The purpose 

of these respective SIPs is to grant final approval to the request for redesignation of the 1-

hour ozone NAAQS nonattainment area to attainment. New SIPs have been submitted to 

the EPA for public comment and approval. These SIPs require NOX reductions from 

specific coal-fired power and address transportation plans in these cities. 

NOx RACT in 8-hour Nonattainment Area SIPs. NC DENR applied NOX RACT to two 

facilities located in the Charlotte nonattainment area: Philip Morris USA and Norandal 

USA. 

Heavy Duty Diesel (2007) Engine Standard. A PM emissions standard for new heavyduty engines of 0.01 grams per brake-horsepower-hour (g/bhp-hr) is to take full effect for 

2007 model year diesel engines. This standard also requires reductions in NOX and nonmethane hydrocarbons (NMHC) of 0.20 g/bhp-hr and 0.14 g/ bhp-hr, respectively. These 

NOX and NMHC standards for diesel engines will be phased in together between 2007 

and 2010. Also, sulfur in diesel fuel must be lowered to enable modern pollution-control 

technology to be effective on these diesel-powered trucks and buses. The EPA will 

require a 97 percent reduction in the sulfur content of highway diesel fuel from its current 

level of 500 parts per million (low sulfur diesel, or LSD) to 15 parts per million (ultralow sulfur diesel, or ULSD). 

Tier 2 Tailpipe. Tier 2 is a fleet averaging program, modeled after the California LEV II 

standards. Manufacturers can produce vehicles with emissions ranging from relatively 

dirty to zero, but the mix of vehicles a manufacturer sells each year must have average 

NOX emissions below a specified value. 

Appendix H - 7
Large Spark Ignition and Recreational Vehicle Rule. EPA has adopted new standards for 

emission of oxides of nitrogen (NOX), hydrocarbons (HC), and carbon monoxide (CO) 

from several groups of previously unregulated non-road engines. Included in these 

sources are the Large Industrial Spark-Ignition Engines and Recreational Vehicles. 

Spark-ignition non-road engines are those powered by gasoline, liquid propane gas, or 

compressed natural gas rated over 19 kilowatts (kW) (25 horsepower). These engines are 

used in commercial and industrial applications, including forklifts, electric generators, 

airport baggage transport vehicles, and a variety of farm and construction applications. 

Recreational Vehicles include snowmobiles, off-highway motorcycles, and all-terrainvehicles. Rules were initiated in 2004 and are fully phased in by 2012. 

Non-road Diesel Rule. This rule sets standards that will dramatically reduce emissions 

by over 90 percent from non-road diesel equipment and dramatically reduce sulfur levels 

by 99 percent from current levels in non-road diesel fuel starting in 2007. This rule will 

apply to most non-road diesel fuel in 2010 and to fuel in locomotives and marine vessels 

in 2012. 

Industrial Boiler/Process Heater MACT standards. The applied MACT control 

efficiencies were 4 percent for SO2 and 40 percent for PM10 and PM2.5. However, as of 

June 08, 2007, the Industrial Boiler/Process Heater MACT standard was vacated. A 

mandate without a stay was issued July 30, 2007. SC DHEC is upholding its state 

MACT regulation for industrial boilers, therefore the affected facilities must comply with 

the aforementioned efficiencies. 

Combustion Turbine MACT. The projection inventories do not include the NOX cobenefit effects of the MACT regulations for Gas Turbines or stationary Reciprocating 

Internal Combustion Engines, which the EPA estimates to be small compared to the 

overall inventory. 

VOC 2-, 4-, 7-, and 10-year MACT Standards. Various point source MACTs and 

associated emission reductions were implemented. We did not count reductions 

occurring before 2002. 

Smoke Management Plan (SMP). The GCVTC Report outlined in the RHR notes that 

“emissions from fire (wildfire and prescribed fire) are an important episodic contributor 

to visibility-impairing aerosols.” As such, Section 51.309(d) (6) of the RHR requires that 

each state consider and address the effects of smoke on visibility (especially when 

planning and issuing permits for prescribed fires). The SC Forestry Commission (SCFC) 

has developed (and recently revised as of August 2006) the Smoke Management 

Guideline for Vegetative Debris Burning Operations, which serves to regulate vegetative 

debris burning for forestry, agriculture, and wildlife purposes in the State of South 

Carolina. SC DHEC’s Bureau of Air Quality has developed a state air pollution control 

regulation (R. 61-62.2, Prohibition of Open Burning) that prohibits open burning of 

any/all household garbage, as well as open burning for the purpose of land clearing or 

right of way maintenance in areas other than predominantly residential, as well as open 

Appendix H - 8
burning of residential construction waste from building and construction operations 

unless specific conditions are met. 

When weighed together, these documents address all sources of fire used for land 

management purposes within South Carolina and effectively minimize visibility impacts 

while recognizing the important ecological role that fires can and do play. Appendix H.1 

includes a memorandum of understanding between the SCFC and SC DHEC and 

represents the State’s collective commitment to develop a comprehensive approach to 

establish and maintain a smoke management plan. 

Early Action Compacts (EAC). Forty-five of 46 counties in South Carolina, along with 

the Department and EPA Region 4, signed EACs in December 2002. By signing the 

EAC, EPA agreed to defer the effective date of the nonattainment designation for 

participating areas. The Department has been working with the EPA, state and local 

governments, industry, environmental groups, and other interested parties to develop a 

strategy to reduce the pollution that creates ground-level ozone. In March 2004, 

participating EAC areas in South Carolina, submitted local Early Action Plans to include 

emission reduction strategies. 

The following are source category specific controls used to project future year emissions 

inventories: 

1.1 Point Source Controls 

Different approaches were used for the EGU and the non-EGU sectors of the point source 

inventory: 

• For the EGUs, the State relied primarily on the Integrated Planning Model (IPM) 

to project future generation as well as to calculate the impact of future emission 

control programs, including CAIR and CAMR. The IPM results were adjusted 

based on State and local (S/L) agency knowledge of planned emission controls at 

specific EGUs. 

• For non-EGUs, we used recently updated growth and control data consistent with 

the data used in EPA’s CAIR analyses and supplemented these data with available 

S/L agency input and updated fuel use forecast data for the U.S. Department of 

Energy. 

For both sectors, we generated 2009 and 2018 inventories for a combined planned and 

existing control scenario. The planned and existing control scenarios account for post2002 emission reductions from promulgated and proposed federal, state, local, and sitespecific control programs as of July 1, 2004. 

1.1.1 Electric Generating Units 

Appendix H - 9
State and local (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 state and local 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 adjustments were necessary in the model runs based on additional control 

information. A re-run (Base G2) was performed to account for these differences. 

Table 1-1 lists adjustments to IPM control determinations specified by S/L agencies for 

the Base G 2009/2018 EGU inventories. Table 1-2 lists other adjustments to IPM results 

specified by S/L agencies for Base G 2009/2018 inventories. 

Appendix H - 10
NOx Emission Controls SO2 Emission Controls 

State Plant Name and ID Unit 2009 2018 2009 2018 

IPM State IPM State IPM State IPM 

AL James H. Miller 

ORISID=6002 

1 & 2 3 & 4 

SCR during ozone season SCR during ozone season 

SCR probable yr round due to CAIR SCR yr round from Consent Decree 

SCR during ozone season SCR during ozone season 

SCR probable yr round due to CAIR SCR yr round from Consent Decree 

None None 

None Scrubber 

None None 

Barry ORISID=3 1, 2, 3 

4 5 

None None None 

SNCR SNCR None 

SCR SCR SCR 

SNCR SNCR SCR 

None None None 

None None None 

None Scrubber Scrubber 

E C Gaston ORISID=26 1 - 4 5 SCR SCR None SCR SCR SCR None SCR None Scrubber None None Scrubber Scrubber Gorgas ORISID=8 6 & 7 

8 & 9 10 

None None SCR 

None None SCR 

None None SCR 

None None SCR 

None None None 

None Scrubber Scrubber 

None None Scrubber 

Charles R. Lowman ORISID=56 

1 2 & 3 

None SCR 

None SCR 

None SCR 

None SCR 

None Scrubber 

Scrubber Scrubber 

None Scrubber 

GA Bowen ORISID=703 1BLR 

2BLR 3BLR 4BLR 

SCR SCR SCR SCR 

SCR SCR SCR SCR 

SCR SCR SCR SCR 

SCR SCR SCR SCR 

IPM had retrofit scrubbers but little emission reductions 

None None Scrubber Scrubber 

Scrubber Scrubber Scrubber Scrubber 
GA Wansley ORISID=6052 1 

2 

SCR SCR 

SCR SCR 

SCR SCR 

 SCR SCR 

IPM had retrofit scrubbers but little emission reductions 

Scrubber None 

Scrubber Scrubber 

Kraft ORISID=733 1, 2 3 None None None None None SCR None None None None None None None None  McIntosh ORISID=6124 

1 None None SCR None None None None 

Yates ORISID=728 1 2, 

3 4 – 7 

None None None 

None None None 

None None SCR 

None None None 

Scrubber None None 

Scrubber None None 

Scrubber None Scrubber 

Hammond 

ORISID=708 

1 2 3 4 

None None None SCR 

None None None SCR 

SCR SCR SCR SCR 

SCR SCR SCR SCR 

None None None Scrubber 

Scrubber Scrubber Scrubber Scrubber 

Scrubber Scrubber Scrubber Scrubber 

KY Ghent ORISID=1356 1 

2 3, 4 

None None None 

SCR None SCR 

SCR SCR SCR 

SCR SCR SCR 

Scrubber None None 

Scrubber Scrubber Scrubber 

Scrubber Scrubber Scrubber 

Coleman 

ORISID=1381 

C1 C2 C3 

None None None 

None None None 

SCR SCR SCR 

SCR SCR SCR 

None None None 

Scrubber Scrubber Scrubber 

Scrubber Scrubber Scrubber 
KY E W Brown 

ORISID=1355 

1 2 3 

None None None 

None None None 

None SCR SCR 

None SCR SCR 

None None None 

ScrubberScrubberScrubber 

None Scrubber Scrubber 

SC 

Jefferies ORISID=3319 3 4 SCR None None None SCR None None None None None None None None None Wateree ORISID=3297 WAT1 WAT2 SCR SCR SCR SCR SCR SCR SCR SCR None None Scrubber Scrubber None Scrubber Canadys ORISID=3280 CAN1 

CAN2 CAN3 

None None None 

 None None None 

None None None 

None None None 

None None None 

None None Scrubber 

None None None 

Rainey ORISID=7834 CT1A CT1B None None SCR SCR None None SCR SCR None None None None None None 

TN 

Kingston ORISID=3407 1 – 8 9 SCR None SCR SCR SCR SCR SCR SCR None None None None Scrubber Scrubber Johnsonville ORISID=3406 

1 – 10 SCR None SCR SCR None None None 

WV Willow Island 

ORISID=3946 

2 SCR None SCR SCR Scrubber None Scrubber 

Kammer ORISID=3947 

1 -3 SCR None SCR SCR Scrubber None Scrubber 
Table 1-2. Other Adjustments to IPM Results Specified by S/L Agencies for the Base 

G 2009/2018 EGU Inventories. 

State Plant Name & ID Unit Nature of Update/Correction 

FL Central Power and 

Lime 

ORISID= 10333 

GEN1 Central Power and Lime (ORIS10333) is a duplicate entry. This is point 18 in 

Florida Crushed Stone (12-053-0530021). Removed IPM emissions for Central 

Power and Lime. 

Cedar Bay 

Generating 

ORISID=10672 

GEN1 FLDEP disagrees with IPM projections - no knowledge of expansion of this 

facility and the cogeneration facility should not grow faster than the underlying 

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

Replaced IPM emissions with 2002 emissions for Cedar Bay (12-031-

0310337) times the growth factors for Stone Container. 

 Indiantown 

Cogeneration 

ORISID=50976 

GEN1 FLDEP disagrees with IPM projections - no knowledge of expansion of this 

facility and the cogeneration facility should not grow faster than the underlying 

industry. Indiantown is connected to Louis Dreyfus Citrus (12-0850850002). 

Replaced IPM emissions with 2002 emissions for Indiantown (12-085-

0850102) times the growth factors for Louis Drefus Citrus. 

GA Bowen 

ORISID=703 

1BLR 

2BLR 

3BLR 

4BLR 

IPM indicated retrofit scrubbers on all 4 units in 2009, but the IPM emissions 

showed little reductions from 2002 levels. Changed emissions to reflect 

scrubbers on 1BLR and 2BLR by 2009. 

 Wansley 

ORISID=6052 

1, 2 IPM indicated retrofit scrubbers on both units in 2009, but the IPM emissions 

showed little reductions from 2002 levels. Changed emissions to reflect one 

scrubber on Unit 1 by 2009. 

 Riverside 

ORISID=734 

4 All of plant Riverside was retired from service June 1, 2005; emissions set to 

zero in 2009 and 2018. 

 McIntosh 

ORISID=727 

CT10A CT10B 

CT11A CT11B 

The McIntosh Combined Cycle facility became commercial June 1, 2005. 

Added 346 tons of NOx and 121 tons of SO2 per unit to the 2009 and 2018 

inventories. 

Longleaf Energy 

Station 

1, 2 Longleaf Energy Station is being proposed by LS Power Development, Inc. GA 

specified that the emissions from this proposed plant be included in the 2018 

projections. Boilers 1 and 2 added 1,882 tons of NOx and 3,227 tons of SO2

per unit to the 2018 inventory. 

R D Morrow 

ORISID=6061 

1, 2 Revised the 2018 emissions to reflect controls not indicated by IPM. The SO2

emissions are much lower than IPM, but their expected NOx emissions are 

actually higher than IPM. The controls will be coming online 2009 or 2010, so 

the 2009 inventory did not change. 

MS 

Jack Watson 

(2049) Victor J 

Daniel (6073) 

Chevron Oil (2047) 

All MS DEQ specified that the emission projections provided by the Southern 

Company for their units in Mississippi were to be used instead of the IPM 

results. 

Appendix H - 14
1.1.2 Non-EGUs 

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

and control data consistent with the data used in EPA’s Clean Air Interstate Rule 

analyses, supplement these data with available stakeholder input, and provide the results 

for stakeholder review to ensure credibility. 

MACTEC (MACTEC, 2006) used the same control programs for both the 2009 and 2018 

non-EGU point inventory. Two control scenarios were developed: existing controls and 

planned controls. The existing control scenario accounts for post-2002 emission 

reductions from recently promulgated federal, state, local, and site-specific control 

programs. The planned control scenario accounts for proposed (but not final) control 

programs that are reasonably anticipated to result in post-2002 emission reductions. 

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

documented in 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 EPA’s Emission 

Standards Division (ESD) staff. Reductions for MACT standards with an initial 

compliance date of 2001 or earlier were not included (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. 

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. Affected units were identified using the 

same methodology as was used by EPA in the proposed Phase II rule (e.g., a large IC 

engine is one that emitted, on average, more than one 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. Several state and local agencies provided more specific 

information on the anticipated controls at the compressor stations. This information was 

used instead of the default approach used by EPA in the proposed Phase II rule. 

A summary of non-EGU point source control programs included in 2009/2018 projection 

inventories include: 

• Atlanta / Northern Kentucky / Birmingham 1-hr SIPs 

• Industrial Boiler/Process Heater MACT: The applied MACT control efficiencies 

were 4 percent for SO2 and 40 for percent for PM10 and PM2.5 to account for the 

co-benefit from installation of acid gas scrubbers and other control equipment to 

reduce HAPs. 

Appendix H - 15
• NOX SIP Call (Phase I- except where States have adopted Phase II already e.g. 

NC): Phase I of the NOX SIP call applies to certain large non-EGUs, including 

cement kilns and large industrial boilers and turbines. 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 EPA. 

• Petroleum Refinery Initiative (October 1, 2003 notice; MS & WV): This initiative 

addresses the most significant Clean Air Act compliance concerns affecting the 

petroleum refinery industry. Since December 2000, 17 global refinery settlements 

have been reached with refiners representing nearly 77 percent of domestic 

refining capacity. Three refineries in the VISTAS region are affected by two 

October 2003 Clean Air Act settlements under the EPA Petroleum Refinery 

Initiative. The refineries are: (1) the Chevron refinery in Pascagoula, MS; (2) the 

Ergon refinery in Vicksburg, MS; and (3) the Ergon refinery in Newell, WV. 

• Reasonable Further Progress three percent plans where in place for one-hour 

plans (Metropolitan Washington, DC, and Atlanta, GA). 

• VOC 2-, 4-, 7-, and 10-year MACT Standards: The point source MACTs and 

associated emission reductions were designed from Federal Register (FR) notices 

and discussions with EPA’s Emission Standards Division (ESD) staff. We 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. 

• Combustion Turbine MACT: The projection inventories do not include the NOX

co-benefit effects of the MACT regulations for Gas Turbines or stationary 

Reciprocating Internal Combustion Engines, which EPA estimates to be small 

compared to the overall inventory. 

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

For more information on the development of point source inventories, see Appendix E. 

1.2 Area Source Controls 

Controls (including control efficiency, rule effectiveness and rule penetration) provided 

by the States or originally developed for use in estimating projected emissions for U.S. 

EPA’s Heavy Duty Diesel (HDD) rulemaking emission projections and used in the Clean 

Air Interstate Rule (CAIR) projections were used to calculate controlled emissions. 

The controls obtained by MACTEC (MACTEC, 2006) for the HDD rulemaking were 

controls for the years 2007, 2020, and 2030. Since MACTEC was preparing 2009 and 

2018 projections, control values for intermediate years were prepared using a straight-line 

interpolation of control level between 2007 and 2020. 

State-submitted controls had precedence over the EPA-developed controls. Control 

measures submitted by SC DHEC include Stage I controls for gasoline dispensing 

facilities and open burning controls. 

Appendix H - 16
South Carolina performs inspections on an (approximate) annual basis for facilities with 

regulated underground storage tanks. During such inspections, SC DHEC inspectors 

look for the presence of and test the integrity of any existing Stage I vapor recovery 

technology employed at the facilities. Stage I vapor recovery devices, when installed on 

underground storage tanks, reduce vapor emissions during the tank filling operations. 

Only a small minority of the current South Carolina population of regulated underground 

storage tanks do not have Stage 1 vapor recovery devices. 

In South Carolina, the South Carolina Department of Agriculture is responsible for 

visiting all gasoline dispensing facilities and testing the fuels to ensure they meet the 

quality standards of the State. This includes testing to ensure the ultra-low sulfur diesel 

fuel standards are being met. 

Open burning is treated as a means of waste disposal in rural areas. Materials burned 

generally include household trash, agricultural refuse, landscaping refuse, or scrap wood. 

The open burning emissions inventory includes Source Classification Code (SCC) 

2610030000, residential open burning of household waste and SCC 2610000100, and 

open burning of yard trimmings. Since it is illegal to burn within the corporate limits, the 

rural population in each county is used to estimate emissions. 

For more information on the development of area source inventories, see Appendix E. 

1.3 Mobile Sources 

Local controls included vehicle emissions inspection (i.e., I/M) programs, Stage II vapor 

recovery programs, anti-tampering programs, etc. By nature, the assumptions used for 

the 2002 initial base year inventory vary across the VISTAS region, but the presumption 

is that these data accurately reflected each State’s situation as it existed in 2002. If a 

State had no plans to change program requirements between 2002 and 2018, the 2002 

program descriptions were maintained. However, if a State planned changes, then 

information was requested on those plans. In the final implementation of the inventory, 

where applicable, Stage II controls were exercised in the area source component of the 

inventory, since the units used to develop Stage II refueling estimates are different 

between MOBILE6 and the NONROAD models.

For more information on the development of mobile source inventories, see Appendix D. 

1.4 Non-Road Sources 

Using the 2002 base year emissions inventory for aircraft, locomotives, and commercial 

marine vessels (CMV) prepared as described earlier in this document, corresponding 

emission projections for 2009 and 2018 were developed. Detailed inventory data (both 

before and after controls) for these same emission sources for 1996, 2010, 2015, and 

2020 were obtained from the EPA's Clean Air Interstate Rule (CAIR) Technical Support 

Appendix H - 17
Document. Using these data, combined growth and control factors for the period 2002-

2009 and 2002-2018 were estimated using straight-line interpolation between 1996 and 

2010 (for 2009) and 2015 and 2020 (for 2018). This is done at the State-county-SCCpollutant level of detail. According to EPA documentation, the CAIR baseline emissions 

include the impacts of the Tier 4 (T4) non-road diesel rulemaking, which implements a 

low sulfur fuel requirement that affects both future CMV and locomotive emissions. 

 

For more information on the development of non-road source inventories, see Appendix 

D. 

1.5 Conclusion 

In conclusion of this discussion on source sector controls, Figures 1-1 through 1-4 depict 

pollutant totals for NH3, PM2.5, NOX, and SO2 for the various sectors by state for 2002, 

2009, and 2018 Base G2 modeling. “Miscellaneous” refers to EPA Tier 1 categories and 

include area sources (agriculture, fire, and fugitive dust emissions) not identified in 

previous categories. 

Figure 1 -1 Annual NH3 emissions – Base G2. 

0

20

40

60

80

100

120

140

160

180

200

Alabama

Florida

Georgia

Kentucky

Mississippi

N

Annual NH3 (Thousand Tons)

orth Carolina

South Carolina

Tennessee

Virginia

West Virginia

Miscellaneous

Nonroad

Onroad

Industrial

Other Fuel Combustion

EGU

2002 Typical

2009 OTW

2018 OTW

Appendix H - 18
0

20

40

60

80

100

120

140

160

180

200

Alabama

Florida

Georgia

Kentucky

Mississippi

North Carolina

South Carolina

Tennessee

Virginia

West Virginia

Annual PM-2.5 (Thousand Tons)

Miscellaneous

Nonroad

Onroad

Industrial

Other Fuel Combustion

EGU

2002 Typical

2009 

2018 OTW

Figure 1 – 2 Annual PM2.5 emissions – Base G2 

Figure 1 - 3 Annual NOX emissions – Base G2 

Appendix H - 19
Figure 1 - 4 Annual SO2 emissions – Base G2 

Appendix H - 20
2.0 Uniform Rate of Progress 

The linear rate of improvement sufficient to attain natural conditions by 2064 is referred 

to as the “uniform rate of progress” or “glide path.” The baseline represents the starting 

point from which reasonable progress will be measured. There are two baseline values 

for each Class I area. Using 2000-2004 Interagency Monitoring of Protected Visual 

Environments (IMPROVE) monitoring data, the deciview values for the 20 percent best 

days in each year are averaged together, producing a single average deciview value for 

the best days. Similarly, the deciview values for the 20 percent worst days in each year 

are averaged together, producing a single average deciview value for the worst days. 

Extinction from individual PM components is calculated from the IMPROVE equation 

(EPA, 2003; Hand and Malm, 2006). EPA defined target natural conditions in 2064 for 

each Class I area (EPA, 2003). For each VISTAS Class I area a baseline visibility using 

2000-2004 IMPROVE data and uniform rate of progress was established, using EPA 

default assumptions for calculating visibility and natural background. Most recently, the 

scientific community has reviewed the assumptions used to calculate current and natural 

background visibility and has agreed to revised methods (Hand and Malm, 2006, 

Pitchford, 2006). VISTAS intends to present both the original and revised methods to 

calculate visibility and visibility improvement. Figure 2.1 illustrates the average 20 

percent worst visibility days in the 2000-2004 baseline period for Cape Romain 

(ROMA), the target natural condition in 2064 for the 20 percent worst days, and the 

incremental deciview changes assuming a uniform rate of progress between current and 

natural conditions in 2064, using the original method for calculating visibility. The term 

Method 1prediction in Figure 2.1 refers to EPA’s default assumptions. This is known as 

the “glide path.” 

Appendix H - 21
Uniform Rate of Reasonable Progress Glide Path

Cape Romain - 20% Data Days

New IMPROVE Equation, 12 km grid

26.48 25.53

23.15

20.77

18.39

16.01

13.64

12.21

22.72

0

5

10

15

20

25

30

35

2000 2004 2008 2012 2016 2020 2024 2028 2032 2036 2040 2044 2048 2052 2056 2060 2064

Year

Haziness Index (Deciviews)

Glide Path Natural Condition (Worst Days) Observation Method 1 Prediction

Figure 2-1. CMAQ 2018 Base G2 Results Compared to Uniform Rate of Progress at 

Cape Romain. 

Appendix H - 22
3.0 Georgia Tech Sensitivities 

Georgia Tech performed emission sensitivities to examine the impact of emission 

reductions on regional haze, annual PM2.5, and 8-hour ozone concentrations using 

CMAQv4.4_SOAmods on the VISTAS 12-km modeling domain, using the 2009 OTW 

(on the way) BaseD emissions. Once the key pollutants contributing to visibility 

impairment at each Class I area were identified, the sources or source categories 

responsible for emitting these pollutants or pollutant precursors were determined. 

Emissions sensitivity analyses were conducted using CMAQ with 2009 Base D inventory 

and consider 30 percent reductions from major pollutants and source categories. The 

sensitivity runs were initially designed to consider pollutant contributions in 2009 to 

PM2.5 in urban areas; results were also considered for Class I areas even though the full 

benefit of controls anticipated by 2018 are not included in these sensitivity analyses. 

Results are qualitatively similar to previous sensitivity results using an earlier (Base A) 

2018 inventory. While the 2009 sensitivity analyses cannot be used to judge absolute 

contributions from each state or source sector, the results do indicate relative level of 

response among pollutants, sectors, and geographic areas. 

3.1 Evaluation of Cape Romain 

Figure 3-1 shows the results of emissions sensitivity run for Cape Romain (ROMA) for 

summer. CMAQ was run using 30 percent reductions from the 2009 Base D inventory 

assumptions for implementing existing state and federal regulations for major source 

categories of SO2, NOX, and PM. The results identify geographic origins for visibilityimpairing pollutants and serve as a good starting point when considering potential air 

quality benefits from additional controls for specific source sectors in VISTAS states or 

neighboring RPOs. The greatest benefits at Cape Romain in 2009 are projected to come 

from further reducing SO2 from electric generating utilities (EGUs). Supplementary, 

smaller benefits are projected from additional SO2 emission reductions from non-utility, 

industrial point sources. Reductions of NOX emissions from point sources (EGU and 

non-EGU) or ground-level sources (on-road vehicles, off-road engines, and area sources) 

and reductions of primary carbon from point or ground-level sources are projected to be 

significantly less beneficial than reductions in SO2 emissions. 

Appendix H - 23
Cape_Romain, SC (Summer)

-8.00

-7.00

-6.00

-5.00

-4.00

-3.00

-2.00

-1.00

0.00

1.00

SO2_EGU

SO2_nonEGU

NOx_Ground

NOx_Point

NH3

VOCs

PC_Ground

PC_Point

PC_Fires

Δ

Bext (Mm-1)

Bio.

Antro.

BCs

MRPO

M-VU

CEN

VISTAS

WV

VA

TN

SC

NC

MS

KY

GA

FL

AL

Figure 3-1. Sources of Various Visibility-reducing Pollutants - Cape Romain 

Summer Using 2009 Base D Emissions. 

Reductions in anthropogenic VOC emissions show no response in visibility, while a 30 

percent reduction in biogenic VOC emissions results in a measurable improvement. 

However, controlling the VOCs from vegetation is not possible or appropriate. For this 

sensitivity run, further reducing SO2 emissions from electricity generating utilities in 

South Carolina and Georgia would have the greatest benefit for Cape Romain; reductions 

from electric generating utilities in other VISTAS states would have additional but 

smaller benefits at Cape Romain. Approximately one half of the benefit at Cape Romain 

from further SO2 emission reductions would come from outside VISTAS states, with the 

majority coming from boundary conditions.

Appendix H - 24
4.0 Reasonable Progress Evaluation 

4.1 Area of Influence 

The objective of the VISTAS Area of Influence analysis is to identify the geographic 

source regions that are contributing to visibility impairment at the Class I areas on the 20 

percent worst visibility days. This information will be used by the State as part of the 

evaluation and demonstration of reasonable progress toward visibility improvement at 

Cape Romain. 

VISTAS’ contribution assessment based on IMPROVE monitoring data (Brewer and 

Adlhoch, 2005) demonstrated that ammonium sulfate is the major contributor to PM2.5 

mass and visibility impairment at Class I areas in the VISTAS and neighboring states. As 

illustrated in Figure 4-1, on the 20 percent worst visibility days in 2000-2004, ammonium 

sulfate accounted for greater than 70 percent of the calculated light extinction at Class I 

areas in the Southern Appalachians and greater than 60 percent of the calculated light 

extinction for coastal sites in the VISTAS states (excepting Everglades). In contrast, 

ammonium nitrate contributed less than five percent of the calculated light extinction at 

VISTAS Class I areas on the 20 percent worst visibility days. (Nitrate has a somewhat 

larger contribution on 20 percent worst days at Class I areas in neighboring states to the 

VISTAS region.) Particulate organic matter (organic carbon) accounted for 10-20 

percent of light extinction on 20 percent worst visibility days (except Everglades where 

organic carbon accounted for 40 percent). 

Appendix H - 25
Figure 4 - 1 Average Extinction for 20% Worst Visibility Days in 2000-2004 using 

New IMPROVE Equation (data from VIEWS Sep 2006). 

VISTAS emissions sensitivity analyses using the CMAQ regional air quality model 

project that reductions in SO2 emissions from Electric Generating Utilities (EGU) and 

non-EGU industrial point sources will result in the greatest improvements in visibility at 

VISTAS Class I areas. EGU and non-EGU industrial point sources comprise 95+

 percent 

of the SO2 emissions inventory in the VISTAS states. The emissions sensitivity analyses 

also indicate that improvements in visibility from reductions in NOX or primary carbon 

emissions from ground-level sources or point sources would be small. Based on these 

analyses, VISTAS states chose to focus their reasonable progress evaluation for the first 

regional haze SIP on potential controls of SO2 emissions from EGU and non-EGU point 

sources. To select the specific point sources that would be considered for each Class I 

area, states first identified the geographic areas that most likely influence visibility in 

each Class I area and then identified the major SO2 point sources in that geographic area. 

4.2 Source Type Analysis 

The following analyses are illustrative of an initial approach from September 2005 to 

evaluate potential control strategies. These analyses rely on the 200 km area surrounding 

the Class I area and use the Base F4 model run. 

VISTAS’ emissions inventory for the simplest area of influence, the 200 km concentric 

circle, indicated for Cape Romain in 2018 that fuel combustion from electric utilities and 

industrial processes produces the majority of the remaining SO2 emissions (Table 4-1), 

with 86 percent of 2018 SO2 total coming from fuel combustion. 

Table 4-1. Source types 2018 Base G2 modeling ROMA – Percentage 

Tier VOC NOX CO SO2 PM10 PM2.5 NH3

Fuel Comb. Elec. Util. 0 20 1 46 8 16 1 

Fuel Comb. Industrial 1 17 2 34 3 5 0 

Fuel Comb. Other 4 5 2 6 4 7 1 

Chemical& Allied Product Mfg 1 1 0 4 1 1 1 

Metals Processing 0 0 0 1 0 0 0 

Petroleum & Related Ind. 0 0 0 0 0 0 0 

Other Ind. Processes 6 6 1 6 8 9 2 

Solvent Utilization 40 0 0 0 0 0 0 

Storage & Transport 7 0 0 0 0 1 0 

Waste Disposal & Recycling 4 3 7 1 7 15 0 

Highway Vehicles 19 25 41 1 1 1 11 

Off-highway 14 19 32 1 2 4 0 

Miscellaneous 4 3 14 1 65 40 84 

Appendix H - 26
SC DHEC defined its AOI to identify source regions for which additional controls might 

be considered and that are likely to have the greatest impact on Cape Romain. To better 

understand the sources that should be considered in a four factor analysis for reasonable 

progress, VISTAS contracted ENVIRON to partner with VISTAS’s Data Analysis 

contractor, Air Resource Specialists (ARS), to provide SO2 Areas of Influence for each o 

the VISTAS, and six neighboring, Class I Federal areas. ARS generated meteorological 

back trajectories for IMPROVE sites in VISTAS and neighboring states. Back trajectory 

analyses use interpolated measured or modeled meteorological fields to estimate the most 

likely central path of air masses that arrive at a receptor at a given time. The method 

essentially follows a parcel of air backward in hourly steps for a specified length of time. 

Back trajectories account for the impact of wind direction and wind speed on delivery of 

emissions to the receptor, but do not account for chemical transformation and dispersion 

of emissions. 

Trajectories were generated using the Hybrid-Single Particle Lagrangian Integrated 

Trajectory (HYSPLIT) model developed by the National Oceanic and Atmospheric 

Administration’s (NOAA) Air Resources Laboratory (ARL). HYSPLIT uses archived 

three-dimensional meteorological fields generated from observations and short-term 

forecasts. HYSPLIT can be run to generate forward or backward trajectories using 

several available meteorological archives. 

The data archives used in this analysis were the National Weather Service's National 

Centers for Environmental Prediction Eta Data Assimilation System (EDAS). The EDAS 

fields are archived by the ARL across the continental U.S., including a buffer zone, at a 

horizontal resolution of 80 km before 2004, and at a horizontal resolution of 40 km 

starting in 2004. 

The major model parameters selected for this analysis include those listed in Table 4-2. 

Table 4-2. Back Trajectory Model Parameters Selected for VISTAS AOI Analysis 

The choice of these parameters affects the trajectories generated and the final attribution 

analyses. In particular, trajectories tend to become increasingly uncertain the further 

back in time they are used. Vertical motion in the model is sometimes best represented 

by following actual vertical motion measurements (represented by model data), surfaces 

of constant entropy, or surfaces of constant pressure, depending on the meteorological 

conditions at a given location and time. The impact of receptor height (or end height) on 

an individual trajectory is also important. Low-ending trajectories represent air parcels 

Appendix H - 27
nearer to ground level and high-ending trajectories may represent more accurate 

boundary layer flow above the local terrain. 

For the years 2000-2004, back trajectories were computed for the following IMPROVE 

sampling sites in and around the VISTAS region: 

1. Breton, LA (BRET1) 

2. Brigantine NWR, NJ (BRIG1) 

3. Cadiz, KY (CADI1) 

4. Caney Creek, AR (CACR1) 

5. Cape Romain NWR, SC (ROMA1) 

6. Chassahowitzka NWR, FL (CHAS1) 

7. Cohutta, GA (COHU1) 

8. Dolly Sods Wilderness, WV (DOSO1) 

9. Everglades NP, FL (EVER1) 

10. Great Smoky Mountains NP, TN (GRSM1) 

11. Hercules-Glades, MO (HEGL1) 

12. James River Face Wilderness, VA (JARI1) 

13. Linville Gorge, NC (LIGO1) 

14. Mammoth Cave NP, KY (MACA1) 

15. Mingo, MO (MING1) 

16. Okefenokee NWR, GA (OKEF1) 

17. Shenandoah NP, VA (SHEN1) 

18. Shining Rock Wilderness, NC (SHRO1) 

19. Sipsy Wilderness, AL (SIPS1) 

20. St. Marks, FL (SAMA1) 

21. Swanquarter, NC (SWAN1) 

22. Upper Buffalo Wilderness, AR (UPBU1) 

Based on the five (5) years of individual back trajectories, ARS generated extinctionweighted residence time data for each IMPROVE site. Each hourly trajectory point was 

tagged with its associated sample (or end) date. Back trajectories with end dates 

corresponding to the 20 percent worst visibility days were weighted with calculated 

extinction values and summed into one-degree horizontal grid cells of latitude and 

longitude. 

Extinction data is based on the IMPROVE Regional Haze Rule dataset from November 

2005, and is calculated based on the original IMPROVE algorithm. For sites with less 

than three complete years of data, ARS developed and applied a data substitution 

protocol to fill missing data. Organic carbon and elemental carbon values were filled 

based on correlations to hydrogen and sulfate values for the same site. Other components 

were filled based on data from nearby sites. 

Trajectory data were weighted by total extinction, and by extinction components 

including ammonium sulfate (AmmSO4), ammonium nitrate (AmmNO3), particulate 

organic material (POM), Light Absorbing Carbon (LAC), Soil, and Coarse Mass (CM). 

Appendix H - 28
Weighting trajectories for the 20 percent worst days by sulfate extinction gave greater 

importance to days influenced by SO2 emissions and lesser importance to days influenced 

by organic carbon emissions. This allowed a geographic area of influence to be 

identified based on sulfate contributions and not skewed by contributions from fire. 

These data files were provided to ENVIRON. ENVIRON was charged with developing 

residence time plots to define the geographic area with highest probability of influencing 

the receptor on the 20 percent worst days dominated by sulfate. Residence time over an 

area is indicative of general flow patterns, but since it does not account for emissions and 

removal processes, it does not necessarily imply specific areas contributed significantly 

to haze compounds at a receptor site. 

4.3 Area of Influence Data and Displays 

The primary objective of the Area of Influence (AOI) displays and data sets are to assist 

the State in focusing its reasonable progress analysis on those geographic regions and 

source categories which most impact a particular Class I Area. The sources of data used 

in these analyses include back-trajectory residence time data, provided by ARS and 

described above, and the VISTAS 2002 and 2018 36-km gridded emissions data (Base G, 

Aug 2006 inventory version). 

Extinction weighted back-trajectory residence time plots were provided by ARS for all 

Class I Areas in the VISTAS region as well as for the surrounding neighboring states. 

These trajectories were processed on an un-projected (i.e., geodetic lat/long 1 degree by 1 

degree) grid and transferred to ENVIRON for further GIS processing and analysis. Backtrajectories were run for 100-meter and 500-meter start heights. Because the backtrajectories were to be combined with gridded emissions data, the first step in the analysis 

and GIS processing involved re-projecting these data to the Inter-RPO Unified Lambert 

Conformal Projection domain. Once the data were re-projected, the data were mapped to 

the 36-km grid cells in the RPO projection using an area-weighted mapping routine. The 

re-projected extinction weighted back-trajectory residence times were then plotted on the 

VISTAS 12-km modeling domain. As sulfate is the primary visibility impairing 

component of the total extinction in the Southeast, the SO4-weighted residence time 

trajectories were chosen as the basic data set for display. For clarity, these data are scaled 

by the maximum value of the total extinction-weighted residence time within the 

modeling domain. The 100-km and 200-km distances from the Class I area were labeled. 

Using the trajectories with the 100-m start height, the State has defined the SO2 Areas of 

Influence as the area with grid cells showing 10 percent (area shaded in yellow in 

following plots) or greater residence time (the frequency that winds pass over that area on 

the way to the Class I area on the 20 percent worst days dominated by sulfate) for the 

period 2000-2004. Residence time over an area is indicative of general flow patterns, but 

since it does not account for emissions and removal processes, it does not necessarily 

imply specific areas contributed significantly to haze compounds at a receptor site. 

Appendix H - 29
Figure 4.2 is an extinction-weighted residence time plot for Cape Romain for 100-m and 

500-m trajectory start heights. 

Figure 4-2. Cape Romain SO4 Extinction-Weighted Residence Time Plots for the 

Period 2000-2004. 

As an aid to the analysis, all regions with scaled residence time values greater than five 

percent and greater than ten percent were noted on the display. Finally, county 

boundaries were overlaid to identify those counties and 36-km modeling grid cells for 

which the extinction-weighted residence time back-trajectories exceeded five percent and 

ten percent. These data were then exported as comma-delimited ASCII data files for 

further analyses. These residence time displays are used primarily to determine the 

regions (counties and/or grid cells) impacting each Class I Area. The next step in the 

analysis is to determine the potential impact from emission sources within the regions 

identified from the extinction-weighted back-trajectory residence time displays and 

analyses. 

Previous VISTAS contribution assessment, emissions sensitivity modeling, and inventory 

analyses have indicated that SO4 is the largest contributor to haze on the 20 percent worst 

visibility days and that electric generating utilities and industrial point sources are the 

largest contributors to SO4 levels at the Class I areas. These two source categories make 

up 95 percent of the VISTAS SO2 inventory. Therefore these two source categories were 

identified as the highest priority for evaluation of reasonable progress in 2018 at the Class 

I areas. 

Appendix H - 30
The potential impacts of SO2 point source emissions for each Class I Area are determined 

by combining gridded emissions data and weighted back-trajectory residence times for 

the 36-km grid cells. The analysis was carried out with both the 2002 and 2018 base year 

emission inventories. Figures 4-3 and 4-4 display the gridded point source SO2 emissions 

from the VISTAS modeling databases, for 2002 and 2018, respectively. These data were 

processed by summing all vertical layers for each grid column and then summing across 

all days to obtain annual emission totals for each grid cell. 

Figure 4-3. Annual point source SO2 emissions for the VISTAS region for in 

tons/year. (2002 BaseG) 

Appendix H - 31
Figure 4-4. Annual point source SO2 emissions for the VISTAS region for in 

tons/year (2018 BaseG). 

As a way of incorporating the effects of transport, deposition, and chemical 

transformation of point source emissions along the path of the trajectories, these data 

were weighted by 1/d, where d was calculated as the distance between grid cell centers, 

in kilometers. For the grid cell containing the Class I Area monitor, a weighting of 1/9 

was applied. The distance-weighted point source SO2 emissions are then combined with 

the gridded extinction-weighted back-trajectory residence times at a spatial resolution of 

36-km. 

The final step in the development of the displays and datasets involve the combination of 

the residence times and gridded emission data. The distance weighted (1/d) gridded point 

source SO2 emissions are multiplied by the total extinction-weighted back-trajectory 

residence times (SO2 * Bext-weighted RT * (1/d)) on a grid cell by grid cell basis. These 

results are then normalized by the domain-wide total and displayed as a percentage. The 

analysis is carried out for both the 2002 and 2018 base year inventories. Figure 4-5 

displays the result of this final analysis step. Note that the outlined regions (in red and 

light orange) represent the extent of the >10 percent and >5 percent sulfate extinctionweighted residence times, determined from the first step in the analysis. As with the 

residence time analysis, the results of the combined distance-weighted SO2 emissions and 

extinction-weighted residence times are overlaid with county boundaries and exported to 

comma-delimited ASCII data files for further analyses of emissions and control options 

for specific sources. 

Appendix H - 32
To understand how emissions are predicted to change, the following figure compares 

2002 and 2018 SO2 multiplied by residence time. 

Comparison 2002 vs 2018 SO2 Emissions * Residence 

Time Using 100 m Start Height – Cape Romain, SC

2002 SO2 emissions 2018 SO2 emissions

Green circles indicate 100-km and 200-km radii from Class I area.

Red line perimeter indicate Area of Influence with Residence Time > 10%.

Orange line perimeter indicate Area of Influence with Residence Time > 5%.

Max Value = 56%

Figure 4- 5. Cape Romain 2002 and 2018 SO2 Distance Weighted Emissions * SO4

Extinction Weighted Residence Time Plots. 

VISTAS states evaluated these plots of residence time weighted by sulfate extinction 

plots of gridded SO2 emissions and defined the SO2 Areas of Influence as those areas 

with residence time greater than 10 percent, based on trajectories with start height of 100-

m and four start times per day. 

Extinction-weighted residence plots for Cape Romain indicate that the areas of probable 

influence for sulfate contribution to visibility impairment are similar to those for nitrate 

contribution even though the visibility impact of nitrate is an order of magnitude smaller 

than that of sulfate. From these plots we can initially conclude that it is appropriate to 

focus on sources that contribute to sulfate concentrations and that sources near a Class I 

area are more likely to contribute to visibility impairment than more distant sources. 

Gridded SO2 emissions for the sulfate extinction-weighted residence time plots indicate 

that large emissions sources at great distance from the Class I area can contribute to 

visibility impairment on some 20 percent worst days. 

Appendix H - 33
4.4 Importance of Pollutants other than Sulfate 

For completion, the following is a brief discussion of the importance of other PM 

components and contributing source categories. When NOX controls are considered, 38 

percent of NOX is from point sources, 40 percent is from highway vehicles, and 15 

percent is from nonroad engines. Elevated organic carbon (OC) and elemental carbon 

(EC) are indicators of fire. Some states may need to consider emissions from residential 

wood burning, forest fires (wild and prescribed), land clearing, and agricultural burning. 

Nitrate (NH4NO3) levels in winter can be significant and are dependent on the availability 

of NH3; 80 percent of NH3 is from area sources (e.g. agriculture). Given that sulfates 

contribute the majority of visibility impairment at Cape Romain on the 20 percent worst 

visibility days, SC DHEC believes it is appropriate to focus on SO2 reductions in this first 

Regional Haze SIP. 

4.5 Summary of Emission Inventories in Cost Curve Analysis 

A necessary component of control strategy design is a thorough review of the emission 

inventories that are used in the modeling of the future year base case. These inventories 

can shed light on the residual emissions from sources or source categories defined to be 

within areas of transport or impact of a Class I area. The most current (BaseG fall 2006) 

VISTAS future year (2018) base case and 2002 base year emissions were used to conduct 

this control cost analysis. For purposes of listing sources within the Area of Influence, 

data were provided for all sources with emissions over distance (Q/d) greater than 5 and 

maximum residence time (RTmax) greater than five. States independently defined the 

criteria for selecting which sources from this list would be considered for reasonable 

control measures. 

The NIF-formatted and SMOKE-ready modeling files for both 2002 and 2018 base year 

and base cases were obtained from VISTAS emissions development and modeling 

contractors and converted to annual emissions and summed for the geography and 

domain of interest. 

Tables 4.3 and 4.4 present the State breakdown of these emissions for the entire VISTAS 

domain. Because the SMOKE-ready files were used in this analysis, the particulate 

matter transport factor (0.90 times inventory values) is included in the PM emission 

summaries. This factor is applied to account for the removal of a substantial portion of 

fugitive dust emissions near a source by surrounding vegetation and structures when such 

emissions are used in regional scale modeling analyses. 

Table 4 – 3. VISTAS 2002 Base Year Annual Emissions Summary 

Appendix H - 34
Table 4 - 4. VISTAS 2018 Base Case Annual Emissions Summary 

This review was conducted in a top down fashion starting with an analysis of the major 

source categories in the domains of interest to determine which major categories had the 

highest residual contribution to the area. Once the highest source types were identified, 

subcategories within those source types were reviewed. Again, a ranking of the highest 

residual sub source types was performed and additional analyses on these categories were 

conducted. Using the extinction weighted analysis, these emission reviews and 

summaries like those presented in Figure 4-25, VISTAS made a decision to further 

review only point source controls in increment to the Clean Air Act scenario. 

In addition to reviewing the residual emission categories in the future year base, it was 

important to identify reductions that had already occurred within each category or at 

specific units. This allowed VISTAS States to determine if certain source categories that 

had yet to be controlled under the future year base case had the potential for reduction or 

if source types already reduced had reached the full cost-effective (i.e., did states take 

advantage of this step of the analysis) potential. 

Finally, once each subcategory was identified, unit level tables of emission comparisons 

from 2002 to 2018 were developed, allowing VISTAS States to review existing emission 

reductions and providing the ability to assign new cost-effective controls to units using 

Appendix H - 35
the best control for the scenario. These tables presented comparisons of 2002 and 2018 

emission levels, for SO2, and future year control technology assignment (by IPM 

forecasting and State modification) for point sources. Non-EGU unit-specific technology 

assignments were identified using the control efficiency tables provided by the VISTAS 

emissions inventory contractor, MACTEC. 

Ultimately, the final control strategy decisions will include the application of BARTsubject source reductions in the future year base case. 

Figure 4 – 6. VISTAS Base G2 SO2 Emission Contribution by Major Source Sector. 

The 2018 IPM file used by VISTAS for EGU sources (RPO 2.1.9) was obtained and 

matched to the 2018 base case inventory of EGU sources. This step was conducted to 

ensure that incremental controls assigned to these source types did not duplicate existing 

base case assumptions. Because IPM does not assign a control efficiency with each 

control device applied to any SO2 or NOX SC DHEC made some assumptions (based on 

IPM documentation) as to what pollutant-specific level of reduction was applied in the 

future year base case runs. These assumptions, by primary and secondary control device 

code combinations for SO2, are presented in Table 4-5. 

Table 4 – 5. IPM Post Processing Assigned Device Codes and Applied SO2 Control 

Efficiencies 

Appendix H - 36
Since many of the control technology control cost equations within AirControlNET 

require additional unit-level characteristic data, we also made matches of the SMOKE 

IDA files to VISTAS NIF, EPA NEI, or EPA CAMD CEM data sets to obtain these 

variables when missing. Unit level boiler capacity (MMBtu/hr) or NETDC (MW) values 

are required for capital and operating and maintenance cost calculations for many of the 

SO2 applied technologies. In cases where these nameplate capacity values could not be 

identified, emission weighted capacities (based on the final EPA 2002 NEI) were 

assigned to boilers using a primary (highest emitting) SCC. Table 4-6 presents these 

weighted capacities. Additionally, stack flow, sulfur content, and primary SCC 

assignment were necessary to cross-reference available incremental control technologies 

to the base case emissions inventory data. These variables were obtained where matches 

could be found, in priority order of VISTAS, CAMD, and other EPA datasets, 

respectively. 

Table 4 - 6. Emission Weighted NETDC (MW) Association 

Appendix H - 37
4.6 Application of AirControlNET Technologies 

AirControlNET is a control technology analysis tool developed to support the EPA in its 

analyses of air pollution policies and regulations (Pechan, 2005). The tool provides data 

on emission sources, potential pollution control measures and emission reductions, and 

the costs of implementing those controls. 

The core of AirControlNET is a relational database system in which control technologies 

are linked to sources within EPA emissions inventories. The system contains a database 

of control measure applicability, efficiency, and cost information for reducing the 

emissions contributing to ambient concentrations of ozone, PM10, PM2.5, SO2, and NOX, 

as well as visibility impairment (regional haze) from point, area, and mobile sources. 

PM10 and PM2.5 as included in AirControlNET represent primary emissions of PM. The 

control measure data file in AirControlNET not only includes the technology's control 

efficiency and calculated emission reductions for that source, but also estimates the costs 

(annual and capital) for application of the control measure. 

Since available versions of AirControlNET contain the preprocessed application of 

control technologies to a predetermined set of EPA emission inventories, direct use of the 

model in this analysis was not possible. However, Alpine received approval from EPA’s 

Innovative Strategies and Economics Group (ISEG) to modify the AirControlNET 

version 4.1 source code (Sorrels, 2006) and data tables in order to make it useful to this 

study. The results of the application of this modified version of the code still retain the 

applicability, efficiency, and cost information from the unmodified version of the source 

code, but were thereafter applied to the VISTAS modeling inventories with updated price 

index scalars to reflect control costs in 2005-dollars. 

Using the modified inventories identified above, we ran every available SO2 control 

strategy in AirControlNET against the EGU and non-EGU point source inventories to 

develop a master list of available, incremental control strategies for the entire VISTAS 

36-km domain necessary for VISTAS States to design command-and-control or costeffectiveness based control strategies by source or domain. 

4.7 Development of AOI-Based Cost Curve 

Each Class I area in the VISTAS modeling domain had an associated AOI as identified 

earlier in this document. In order to best determine where emission reduction has the 

greatest benefit, this geography was designed to limit the available source type list from 

including all sources within the entire domain. 

These marginal cost curves include the application of all available control measures to all 

applicable point sources within the AOI. The curves will allow VISTAS States to 

determine if--based on the generic application of SO2 control technologies from the 

associations originally developed in AirControlNET and improved upon with stakeholder 

input will help—attainment of reasonable further progress emission reduction objectives 

Appendix H - 38
can be enhanced while presumably minimizing the number and type of controlled sources 

in each AOI. 

Using a geocoded county list from these AOIs, SC DHEC compared the master list of 

incremental control measures from all point sources located within the boundaries of the 

AOIs. This list was then sorted by incremental cost-effectiveness (marginal cost) basis to 

determine the most cost effective control suite available to attain emission reduction 

targets for SO2 within each AOI. Each individual source had its own corresponding cost 

effectiveness curve. 

In aggregate, the results of these applications are SO2 emission cost curves for all EGU 

and non-EGU point sources within the geographic domain of the AOI. Incremental 

controls on area and mobile sources were not considered in this analysis. An illustrative 

example of the steps involved with the cost effectiveness curve design can be found in 

Attachment H-2.a of this document. 

With each AOI cost curve, additional metrics calculated for the distance from the 

emission release point to the Class I area IMPROVE monitor (in km), the 2018 residual 

emissions and distance (Q/d) or squared distance (Q/d^2), and the normalized 2018 SO2 

point source emissions times distance-weighted residence time (RTMax) values for the 

county in which the emission release point was located were calculated for incremental 

review and consideration. SC DHEC used these values to further determine control 

strategy development for Cape Romain. 

Appendix H - 39
5.0 Reasonable Progress Assessment 

The State concluded that SO2 emissions from EGU and non-EGU point sources in 

geographic Areas of Influence (AOI) are sources to consider for further controls. 

VISTAS developed source matrices for SO2 AOI for Cape Romain, using data delivered 

by ENVIRON for 2002 and 2018 SO2 emissions multiplied by SO4 extinction weighted 

residence time plots. 

Spreadsheets were developed for each Class I area with: 

• Plant name 

• Point ID 

• Tons SO2 projected for 2018 

• Q (tons) 

• Current control efficiency, CE (percent) 

• Stationary source distance to Class I area, d (km) 

• Analysis of emissions per distance from source, Q/d and Q/d2 

• RTMax, the maximum percentage of time that winds pass over that area on the 

way to the Class I area on the 20 worst days 

The ranking refers to the source rank by Q/d when sources from all states are included. 

In an analysis of emissions per distance from source, Q/d2

 is more representative when d 

is less than 20 km because plumes are still dispersing in two dimensions. After about 100 

km, plumes only disperse in one dimension. The distance calculation is based on a single 

stack at a unit (when more than one are represented in the inventory) and is calculated in 

distance in km to the IMPROVE monitor at each Class I area. The residence time for the 

county where the source is located was reviewed. It was generally agreed that states 

would focus on those sources where RT max was equal to or greater than 10 percent. A 

second matrix for sources in the SO2 AOI was developed for sources with a 2018 Q/d > 5 

when d was greater than 100 km, Q/d2

 > 0.03 when d was less than 20 km, and Q/d > 5 or 

Q/d2

 > 0.03 when d was 20-100 km (these values were chosen arbitrarily to limit the 

number of sources on the list and focus on those that are most influential). 

Next, SC DHEC elected to focus on those units that contributed greater than or equal to 

0.01 percent sulfate visibility impairment at Cape Romain for several reasons. 

SC DHEC chose to adopt the one percent threshold based on the precedence established 

by other Federal programs. 

1. The BART rule specifies that a maximum impact of 0.5 dv is an acceptable threshold 

for establishing significance. This threshold equates to roughly a 5 percent change in 

visible perception. This same significance level is used in the Prevention of Significant 

Deterioration/ New Source Review program for the visibility air quality related value. 

 

Appendix H - 40
2. The NOx SIP Call laid out a significance level for Section 126 petitions of 4 parts per 

million (ppm), that being the level to which a State's contribution to another state's ozone 

problem was considered significant. Four ppm represents approximately 3.75 percent of 

the 1-hour ozone standard, which was in place at the time EPA promulgated the NOX SIP 

Call. 

3. For the CAIR rule, a PM contribution of 0.2 μg/m3

 was used to demonstrate a 

significant impact, which is 1.3 percent of the annual PM2.5 standard of 15 μg/m3. 

4. Lastly, when human health standards (NAAQS) are proposed significant impact levels 

are assigned, which allow sources to determine their significance on air quality in the 

area around their facilities. Sources that demonstrate that their "contribution" from the 

new or modified sources is less than these significance levels do not have to complete 

any further modeling. The SILS represent a percentage of the NAAQS. 

After looking at all averaging periods for the criteria pollutants, SC DHEC determined 

that the one percent threshold proposed for reasonable further progress was as protective 

as or more protective than the significant impact levels. The most restrictive threshold 

identified was for NOX, which has a NAAQS of 100 μg/m3 and a significance level of 1 

μg/m3, which represents one percent of the total. 

Finally, SC DHEC considered available resources to evaluate the sources in Cape 

Romain’s sulfate AOI. SC DHEC recognized that there was neither sufficient time nor 

resources available to evaluate all units within a given AOI. Therefore, a threshold 

needed to be established to determine which units would be evaluated. SC DHEC 

believes the one percent threshold is appropriate, given the contribution to the total 

visibility impairment at Cape Romain, and the limited resources available to conduct the 

unit-by-unit evaluation for reasonable progress. 

Table 5-1 shows the analysis for Cape Romain EGU sources that met the above criteria. 

The full spreadsheets containing all VISTAS Class I area results can be found in 

Attachment H-2.b. 

Table 5-2. EGU Sources in South Carolina’s Sulfate AOI. 

State Plant 

Point 

ID 

2018 

Q 

(tons) 

CE 

(%) 

d 

(km) Q/d Q/d^2 RTMax Fraction 

SC 

SANTEE COOPER 

JEFFERIES 3 6,761 0 45.80 147.61 3.22 72.76 0.114308 

SC 

SANTEE COOPER 

JEFFERIES 4 6,609 0 45.80 144.30 3.15 72.76 0.111745 

SC 

SANTEE COOPER 

CROSS 001 719 95 63.26 11.37 0.18 72.76 0.046944 

SC 

SANTEE COOPER 

CROSS 002 3,280 87 63.26 53.43 0.84 72.76 0.046944 

SC 

SANTEE COOPER 

CROSS 3 3,835 0 63.26 60.62 0.96 72.76 0.046944 

SC SCE&G:CANADYS 01 5,203 0 91.25 57.02 0.62 72.55 0.044029 

Appendix H - 41
SC SCE&G:CANADYS 02 5,144 0 91.12 56.45 0.62 72.55 0.043588 

GA 

SAVANNAH 

ELECTRIC: 

MCINTOSH STEAM – 

ELEC SG01 7,015 0 155.93 44.99 0.29 31.04 0.014863 

This spreadsheet was developed to include each area source with Q/d > 5 or Q/d2 > 0.03, 

indicating the plant name, industry description, emissions projections for 2018, current 

control efficiency (CE percent), distance from Class I Federal area, Q/d, Q/d2, RT 

average, RT maximum, Q/d*RT, and the fraction a single source contributes to the total 

Q/d*RT for a Class I Federal area. 

Control efficiency percent is important because it gives a sense of which facilities are 

already controlled and by what percent, and which facilities may be controlled further. 

Next, an analysis of control options, generic costs of controls, and cost per ton for various 

units contributing greater than one percent to any Class I Federal area was developed. 

Spreadsheets containing unit-level emissions and other associated data for the Class I 

Federal areas was matched with data from AirControlNET (Pechan, 2005) to give SO2

control efficiency, annual SO2 emissions reduction from 2018 Base Case, total 

annualized cost (in 2005 dollars), and cost per ton reduced for application of specific 

control measures. 

SC DHEC reviewed the sources, emissions, control options, and costs from the SO2 AOI 

matrices and defined sources for which the Four Factor Analysis was to be conducted. 

The same few categories of point sources contribute to the majority of SO2 emissions, 

(fuel combustion from electric utilities and fuel combustion from industrial sources), with 

little contribution from other sources. Therefore, SC DHEC eliminated other source 

categories from the Four Factor Analysis. SC DHEC next looked at source-specific 

costs, existing controls, remaining useful life, environmental and energy impacts. 

Appendix H - 42
6.0 Four Factor Analysis 

Section 169A(g)(1) of the Clean Air Act (CAA) and 40 CFR 51.308(d)(1)(i)(A) outline 

four statutory factors that have been identified as mandatory for purposes of establishing 

a reasonable progress goal for any mandatory Class I Federal area within a State: cost of 

compliance, time necessary for compliance, energy and non-air quality environmental 

impacts of compliance, and remaining useful life of any existing source subject to such 

requirements. These statutory factors would be specific to the sources being considered 

for additional controls. 

6.1 The Four Statutory Factors 

6.1.1 The Cost of Compliance 

The “cost of compliance” is a factor used to determine whether compliance costs for 

sources are reasonable compared to the emission reduction and visibility improvement 

they will achieve. Note that visibility improvement is not only related to tons of pollutant 

removed, but also involves how the pollutant or chemical compound affects the 

extinction coefficient in each Class I Federal area. For example, on a pound to pound 

comparison, sulfate particulate impairs visibility greater than does coarse particulate. 

Costs should be determined for one-time capital costs, as well as ongoing annual 

operation and maintenance costs. 

6.1.2 Time Necessary for Compliance 

The “time necessary for compliance” factor may be used to adjust the reasonable 

progress goals to reflect the degree of improvement achievable within the long-term 

strategy period (as opposed to the improvement expected at full implementation of a 

control measure) if the time needed for full compliance exceeds the length of the longterm strategy period. For instance, if the implementation of a control measure could not 

be completed within the schedule outlined by the control strategy, the RPG should reflect 

what visibility improvement could be expected within the strategy period. 

For example, if construction labor availability constraints preclude the installation of 

controls at all sources of a particular category within the LTS period, the RPG should 

reflect the visibility improvement anticipated from installation of controls at the 

percentage of sources that could be controlled within the strategy period. (The SIP could 

still include control strategies that extend beyond the 2018 milestone; in the above 

example, the visibility improvement anticipated from installation of controls at the 

percentage of sources that could not be controlled within the first strategy period would 

have to be applied in a later SIP). 

Appendix H - 43
6.1.3 Energy and Non-Air Quality Environmental Impacts of Compliance 

The “energy and non-air quality environmental impacts of compliance” factor is meant to 

consider whether the energy requirements of the control technology result in energy 

penalties or benefits. For example, controls on diesel engines may decrease the overall 

efficiency and require a significant increase in diesel fuel consumption. The State should 

also consider any significant or unusual non-air environmental impacts, such as a waste 

stream that may be generated by a particular control technology. 

6.1.4 Remaining Useful Life of the Source 

The statutory factor of the “remaining useful life of the source” is applicable only to 

those measures that would require retrofitting of control devices (or possibly production 

changes) at existing sources. In such cases, this factor should be treated as one element 

of the overall cost analysis. For purposes of this analysis, the remaining useful life is the 

difference between the year of the reasonable progress analysis and the date the facility 

permanently stops operations. The remaining useful life of a source affects the 

annualized costs of retrofit controls. 

6.2 Evaluating Four Statutory Factors For Specific SO2 Emission Sources in Cape 

Romain’s Area of Influence 

The next step is to identify emission reductions that have already occurred within each 

source category and at specific units. Unit level tables of emission comparisons from 

2002 to 2018 were developed, allowing VISTAS States to review existing emission 

reductions. These tables assigned future year control technology from IPM forecasting 

and State modification for EGU and from control efficiency tables for Non-EGU point 

sources. 

Once emission control profiles for specific units were defined, the next step is to 

determine what, if any, additional control measures would feasibly be available, and to 

assign costs to those control measures. For EGUs, the 2018 IPM file used by VISTAS 

for EGU sources was obtained and matched to the 2018 base case inventory of EGU 

sources. This step was conducted to ensure that incremental controls assigned to these 

source types did not duplicate existing base case assumptions. For non-EGUs, VISTAS 

used EPA’s AirControNET database, modified for the VISTAS emission inventories. 

The core of AirControlNET is a relational database system in which control technologies 

are linked to sources within EPA emissions inventories. The system contains a database 

of control measure applicability, efficiency, and cost information for reducing emissions. 

The control measure data file in AirControlNET includes not only the technology's 

control efficiency, and calculated emission reductions for that source, but also estimates 

the costs (annual and capital) for application of the control measure. 

Using the modified inventories identified above, VISTAS ran every available SO2 control 

strategy in AirControlNET against the EGU and non-EGU point source inventories to 

develop a master list of incremental control strategies for each unit in the VISTAS 36-km 

Appendix H - 44
domain. For the sources within the AOI for Cape Romain, the master list of incremental 

control measures was sorted to determine the costs of incremental control measures. 

These data were combined in a master spreadsheet with the distance from the emission 

release point to the Class I area IMPROVE monitor (in km), the 2018 residual emissions 

and distance (Q/d) or squared distance (Q/d^2), and the normalized 2018 SO2 point 

source emissions times distance-weighted residence time (RTMax) values for the county 

in which the emission release point was located. South Carolina evaluated these control 

measures and costs as part of their review of the statutory factors for reasonable further 

progress. 

The Regional Haze Rule requires that states consider the following factors and 

demonstrate how these factors were taken into consideration in selecting the reasonable 

progress goal: 

• Costs of compliance; 

• Time necessary for compliance; 

• Energy and non-air quality environmental impacts of compliance; and 

• Remaining useful life of any potentially affected sources. 

6.2.1 Cost of Compliance 

As defined in Section 7.5.5, coal-fired electric utilities and coal-fired industrial boilers 

are the largest source categories contributing to SO2 in 2018 in the Areas of Influence 

defined for Cape Romain. Industrial boilers using oil and commercial and institutional 

boilers using coal or oil had small contributions to SO2 in 2018. 

Sulfur dioxide emissions from utility, industrial, commercial, or institutional boilers can 

be controlled either by switching the fuel source to a lower sulfur fuel content or by 

installing post-combustion controls. Costs vary by fuel source and boiler type and 

require source specific analyses for accuracy. 

Bituminous coal is commonly burned in boilers in the eastern U.S. Switching to another 

bituminous coal with lower sulfur content or blending bituminous coals can reduce SO2 

emissions with the least impact to boiler performance. While sub-bituminous coal has a 

lower sulfur content than bituminous coal, it also has a lower heat rate, and therefore, 

more coal has to be burned to generate the same energy output. For boilers that are 

designed for bituminous coal, only a small fraction of the fuel can be switched to low 

sulfur sub-bituminous coal without affecting boiler operations. Costs of boiler 

modifications to accommodate low sulfur sub-bituminous coal may make switching to 

sub-bituminous coal impractical. Contract initiation and termination costs, differential 

fuel prices and heat rates, transportation costs, and modification to boiler operations, fuel 

handling and waste handling systems will have to be considered specific to each source. 

Flue-gas desulfurization (FGD) is the common post-combustion control for coal-fired 

boilers. Flue gas is passed through an absorbent for sulfur dioxide (generally limestone 

or lime) in either a wet scrubber, dry scrubber, or spray dryer. A calcium sulfate 

Appendix H - 45
byproduct is produced that may be further processed to produce gypsum as a commercial 

byproduct. Costs of flue-gas desulfurization include initial construction costs and 

ongoing operational and maintenance costs for the absorber tower, sorbent handling, and 

waste product handling facilities. Costs per ton vary with boiler size, type, and facility 

citing considerations. 

For oil-fired boilers, lower sulfur oil may be an option. Costs need to consider 

differential fuel prices and heat rate, boiler modifications, fuel handling costs, and 

maintenance costs. Conceptually, post-combustion controls can be used for oil boilers, 

but there is little precedence for such installations. 

6.2.2 Time Necessary for Compliance 

For fuel switching, the time necessary to terminate existing fuel contracts and initiate new 

contracts needs to be considered. Generally, two to three years may be required. 

Instillation of post-combustion controls will require three or more years depending on 

market availability of labor and materials and utility system-wide priorities. Time 

necessary for compliance will need to be refined for specific sources. 

6.2.3 Energy and Non-Air Environmental Impacts 

Switching to low sulfur fuel or installing post-combustion controls may reduce boiler 

heat rate and energy output. Scrubbers and spray dryers will require additional safeguard 

for fuel handling and waste handling systems to avoid additional non-air quality 

environmental impacts such as increases effluent in waste water discharges and storm 

water run-off. These factors will need to be considered for specific to individual sources. 

Carbon dioxide is emitted as a byproduct of FGD, therefore impacts of increased carbon 

emissions will need to be considered, particularly if carbon emissions are limited in the 

future under climate change mitigation strategies. 

6.2.4 Remaining Useful Life 

Remaining useful life is specific to the facility for which controls are considered. 

6.3 Process of Applying Statutory Factors 

SC DHEC has just completed the Reasonable Progress Assessment for the first regional 

haze SIP. The following was SC DHEC’s Process on Reasonable Progress Assessment 

for the current time period (from the present to 2018): 

Step 1: Determine Pollutants of Concern

Appendix H - 46
VISTAS evaluated the species contribution on the 20 percent worst visibility days and 

concluded that sulfate accounted for greater than 70 percent of the visibility impairing 

pollution. The VISTAS States concluded that controlling SO2 emissions was the 

appropriate step in addressing the reasonable progress assessment for 2018. VISTAS’ 

findings were consistent with the findings of the Southern Appalachian Mountain 

Initiative (SAMI). SAMI confirmed that sulfate particles account for the greatest portion 

of the haze affecting Class I areas in the Southern Appalachian region and that these 

sulfates were produced in large part from SO2 emissions from coal combustion. 

Step 2: Determine which source sectors should be evaluated for reasonable progress.

Since SO2 point source emissions in 2018 are projected to represent greater than 95 

percent of the total SO2 emissions inventory, the VISTAS States concluded that the focus 

should be on electric generating unit (EGU) and non-EGU point sources of SO2

emissions. 

Step 3: Determine if the Clean Air Interstate Rule (CAIR) is sufficient for reasonable 

progress for subject EGUs.

SC DHEC evaluated the amount of SO2 reduction from the EGU sector resulting from the 

implementation of CAIR. Sulfur dioxide emission reductions that have been predicted by 

IPM to meet the CAIR requirements are not as certain due to the current rule’s reliance 

on unchecked trading and the use of banked Title IV allowances. SC DHEC intends to 

re-evaluate the IPM predictions of SO2 reductions for CAIR at the time of our next 

periodic report in 2012 to ensure that the reductions currently predicted by IPM for CAIR 

are in fact taking place where they are expected and needed. Based on the controls 

predicted by IPM under CAIR, we have concluded that at this time these existing 

regulatory programs constitute reasonable measures for South Carolina EGUs during this 

first assessment period (between baseline and 2018). 

Step 4: Determine which emission units should be evaluated based on impact.

SC DHEC calculated the fractional contribution from all emission units within the SO2

Area of Influence for Cape Romain and identified those emission units with a 

contribution of one percent or more. 

Step 5: Evaluate the four factors.

Each emission unit identified in Step 4 above was evaluated using the statutory and 

regulatory factors of: 1) cost of compliance, 2) time necessary for compliance, 3) the 

energy and non-air quality environmental impacts of compliance, and 4) the remaining 

useful life of the emissions unit. SC DHEC believes that the cost of compliance is 

typically the dominant factor in whether a source will be required to install controls. 

Therefore, more emphasis was placed on cost of control as part of this reasonable 

progress assessment, as compared to the other three statutory factors. In addition, the SC 

DHEC believes that the fifth factor, visibility improvement, is considered by focusing the 

evaluation on those units that contribute at least one percent to visibility impairment at 

Cape Romain. 

Appendix H - 47
For the limited purpose of evaluating the cost for the reasonable progress assessment in 

this first regional haze SIP, SC DHEC believes it is not equitable to require non-EGUs to 

bear a greater economic burden than EGUs for a given control strategy. The facility-byfacility and system-wide costs for implementing the Clean Smoke Stacks Act (included 

as Attachment H.7) were used by SC DHEC as justification of typical costs. The costs 

ranged from $912 to $1,922 dollars per ton of SO2 removed, and the average costs per 

system ranged from $1,231 to $1,375 dollars per ton of SO2 removed. These costs were 

estimated using the capital costs from the CSA 2006 compliance plans, and the projected 

operating costs provided by Duke Energy and Progress Energy. The costs were evaluated 

on the same terms as the AirControlNet cost estimates so that they are directly 

comparable to the cost estimates for the non-EGU units in South Carolina. 

SC DHEC focused the reasonable progress assessments on specific units at the following 

non-EGU facilities in the South Carolina and Georgia: 

• MeadWestvaco, SC 

• International Paper, Georgetown, SC 

• Giant Cement, SC 

• International Paper, Savannah, GA 

• Holcim: Holly Hill, SC 

• DAK Americas, SC 

The following sources were then asked to conduct a four-factor analysis. Each of the 

four factor analyses are discussed in more detail in Appendix N of South Carolina’s 

Regional Haze SIP. 

Appendix H - 48
7.0 Best Available Retrofit Technology (BART) 

7.1 Background 

As required by the CAA, the EPA included in the final regional haze rule a requirement 

for Best Available Retrofit Technology (BART) for certain large stationary sources that 

were placed in operation between 1962 and 1977. The BART-eligible sources are those 

sources that have the potential to emit 250 tons or more of a visibility-impairing air 

pollutant; were placed in operation between August 7, 1962, and August 7, 1977; and 

whose operations fall within one or more of 26 specifically listed source categories. 

Under the CAA, BART is required for any BART-eligible source that a State determines 

‘‘emits any air pollutant which may reasonably be anticipated to cause or contribute to 

any impairment of visibility in any such area.’’ Accordingly, for stationary sources 

meeting these criteria, States must address the BART requirement when they develop 

regional haze SIPs. The EPA has set guidance for identifying BART-eligible sources in 

40 CFR Part 51 Appendix Y. 

A BART-eligible source that is responsible for a 1.0 deciview (dv) change or more is 

considered to “cause” visibility impairment. Although the appropriate threshold may 

vary, the guidelines state that the contribution threshold used for BART applicability 

should not be higher than 0.5 deciviews. Thus a BART-eligible source that is responsible 

for a 0.5 dv change or more is considered to “contribute” to visibility impairment. Any 

source determined to cause or contribute to visibility impairment in any Class I Federal 

area is subject to BART. 

The guidelines direct that States should include SO2, NOX, and direct particulate matter 

(PM) emissions (including both PM10 and PM2.5) in determining whether sources cause or 

contribute to visibility impairment. States may use their best judgment to determine 

whether VOC or ammonia emissions are likely to have an impact on visibility in an area.

To determine which BART-eligible sources are subject to BART, states have several 

options. A state may consider all BART-eligible sources subject to BART; may perform 

analysis showing that the full group of BART-eligible sources in a State cumulatively 

may not be reasonably anticipated to cause or contribute to any visibility impairment in 

any Class I Federal areas; or may consider the individualized contribution of a BARTeligible source to determine whether a specific BART-eligible source is subject to BART. 

Sources that are subject to BART must undergo a BART determination. Section 

169A(g)(7) of the CAA requires that States must consider the following factors in 

making BART determinations: (1) the costs of compliance, (2) the energy and non-air 

quality environmental impacts of compliance, (3) any existing pollution control 

technology in use at the source, (4) the remaining useful life of the source, and (5) the 

degree of improvement in visibility that may reasonably be anticipated to result from the 

use of such technology.

Appendix H - 49
To demonstrate the degree of improvement in visibility from various BART control 

options, the States may run CALPUFF or another appropriate dispersion model to predict 

visibility impacts. Scenarios would be run for the pre-controlled and post-controlled 

emission rates for each of the BART control options under review. The maximum 24-

hour emission rates would be modeled for a period of three or five years of 

meteorological data. States have the flexibility to develop their own methods to evaluate 

model results. 

7.2 Approach to Implementation of BART Requirements 

In order to meet the SIP submittal deadline, South Carolina has used a multifaceted 

approach to implementation of the federal regional haze rule BART requirements. The 

approach consists of source identification efforts; use of a permitting process to establish 

any resulting BART limits for inclusion in the SIP submittal (as well as participation in 

VISTAS BART subgroup to resolve technical issues spanning states in the VISTAS 

region); and ongoing consultation with affected sources, the EPA and FLMs throughout 

the BART process. 

7.3 Identification of BART-Eligible Sources 

EPA provided guidance for identifying BART-eligible sources in 40 CFR Part 51, 

Appendix Y. South Carolina has followed this guidance in identifying its BART-eligible 

sources. The South Carolina 2002 air emissions inventory was reviewed to determine the 

population of potential BART-eligible sources. The data were initially queried for any 

sources emitting SO2, NOX, PM10, VOC, or ammonia. The data set was refined based on 

emission rates, whether emission units fit in any of the twenty-six (26) listed source 

categories for BART, and available information obtained through both review of permit 

and inspection reports and discussion with the Bureau of Air Quality’s permitting and 

regional office staff familiar with the facilities. 

An information packet on BART was sent, and additional information was collected from 

the remaining sources regarding potential emissions and BART eligibility from the 

standpoint of source category and date criteria. Through this iterative review process, the 

list of potential BART-eligible sources was pared down to the twenty-one (21) BARTeligible sources listed below. 

South Carolina BART-Eligible Sources: 

ALBEMARLE CORP. 

BOWATER INC. PAPER/PULP 

BP AMOCO CHEMICAL-COOPER RIVER PLANT 

DAK AMERICAS 

EASTMAN CHEMICAL 

Appendix H - 50
INTERNATIONAL PAPER GEORGETOWN MILL 

INVISTA MAY PLANT 

INVISTA SARL SPARTANBURG (FORMERLY KOSA: ARTEVA) 

ISG GEORGETOWN 

MEADWESTVACO KRAFT MILL 

MILLIKEN CHEMICAL: DEWEY PLANT 

OWENS CORNING: ANDERSON 

RHODIA CHARLESTON 

SANTEE COOPER GRAINGER 

SANTEE COOPER JEFFERIES 

SANTEE COOPER WINYAH 

SCE&G CANADYS 

SCE&G WATEREE 

SCE&G WILLIAMS 

STONE CONTAINER FLORENCE 

WELLMAN INC PALMETTO PLANT 

A spreadsheet of some of the State’s BART-eligible source emissions and distance to 

Class I areas is included as Attachment H.4. 

South Carolina BART-eligible sources were presumed to be subject to BART but were 

provided the opportunity to submit modeling demonstrations showing that they did not 

contribute to visibility impairment, i.e., had less than 0.5 deciviews (dv) impact, on any 

Class I area within 300 km and thus could be exempt. 

7.4 Contribution Threshold 

Determining whether a source causes or contributes to visibility impairment is one step in 

the BART review process. The Guidelines for BART Determinations Under the Regional 

Haze Rule state that, “A single source that is responsible for a 1.0 deciview change or 

more should be considered to ‘cause’ visibility impairment.” The guideline document 

also states that “the appropriate threshold for determining whether a source ‘contributes 

to visibility impairment’ may reasonably differ across states...” but, “As a general matter, 

any threshold that you use for determining whether a source ‘contributes’ to visibility 

impairment should not be higher than 0.5 deciviews.” The rationale for these instructions 

is provided in the preamble to the BART guidance in the statement, “If ‘causing’ 

visibility impairment means causing a humanly perceptible change in visibility in 

virtually all situations (i.e., a 1.0 deciview change), then ‘contributing’ to visibility 

impairment must mean having some lesser impact on the conditions affecting visibility 

that need not rise to the level of human perception.” 

The guidance document itself also 

states that, “States remain free to use a threshold lower than 0.5 deciviews if they 

conclude that the location of a large number of BART-eligible sources within the State 

and in proximity to a Class I area justify this approach.” 

Appendix H - 51
The EPA’s documents strive to set these thresholds in the context of the human 

perception of visibility change. As noted above, the EPA considers a 1.0-deciview 

change in visibility to be humanly perceptible “in virtually all situations.” Also, the 

preamble to the BART guidance cites an analysis in an appendix of a NAPAP (National 

Acid Precipitation Assessment Program) report, which asserts that “changes in light 

extinction of five percent will evoke just noticeable changes in most landscapes” (Malm, 

1990). (A five percent change is approximately 0.5 dv.) But, as noted above, the 

preamble also states that perceptibility is not a prerequisite for choosing a contribution 

threshold. Putting all this together, it appears that “causing” visibility impairment means 

having a humanly perceptible impact (for which EPA considers the practical threshold to 

be 1.0 dv) while “contributing” to visibility impairment means having a smaller impact 

(for which the EPA considers the threshold to be 0.5 dv or some smaller value) that may 

or may not be humanly perceptible. 

The EPA argues that a contribution threshold of less than 0.5 dv impact per source is 

appropriate when multiple sources contribute, in order to limit the combined effect of 

these sources. As an example, EPA asserts that if there were 100 sources, each affecting 

visibility by 0.1 dv (presumably an imperceptible amount), and the total impact would be 

10 dv (which can be expected to be quite perceptible). The point being is that multiple 

sources can cause a larger impact than a single one. For BART purposes, visibility 

impacts are calculated as 24-hour averages of 1-hour plume impacts, so if the plumes 

from the various sources each impact the point of interest at some time during a 24-hour 

period (not necessarily all at the same hour), then the 24-hour average will reflect their 

combined impact. 

The Regional Haze rule gives the states considerable flexibility in determining a BART 

exemption threshold, stating only that a state should not set a threshold higher than 0.5 

dv, while indicating, as mentioned above, that the state should consider the number of 

emission sources affecting the Class I Federal area, the magnitude of the sources’ 

impacts, and the location of the sources. The number of BART sources and the different 

methods available for exemption by a source makes a straightforward, apples-to-apples 

determination of a proper threshold problematic. In fact, given the state’s limited 

resources, it would be impossible to consider every source and every situation in a 

comprehensive manner. SC DHEC decided that a stepwise, common-sense approach 

would satisfy the requirements of the rule while at the same time making the decision 

making process manageable. 

EPA has agreed that CAIR satisfies BART for SO2 and NOX for those EGU facilities 

covered under the CAIR rule even though these EGUs could continue to affect visibility 

at Class I areas. In many cases, modeled impacts for these EGUs will continue to be 

greater than 1.0 dv, or be defined as causing visibility impairment. Thus, for this first 

evaluation period, it appears that the reasonableness of the BART process is a key factor 

in the determination rather than trying to establish a level of controls whereby each 

source will have a visibility impact at the Class I Federal area below the level of 

“causing” visibility impairment, much less contributing to visibility impairment. It 

should be recognized that, at some level, any source will contribute to visibility 

Appendix H - 52
impairment if considered as part of a larger group. Since the BART rule allows for the 

exemption of a source, however, and EPA agrees that CAIR facilities that may impact a 

Class I area above the 1.0 dv level can be exempted, it is clear that the rule intends that a 

source can be exempted even if that source’s impact when considered in aggregate with 

other sources might model above the 1.0 dv level. It seems clear that the total number of 

facilities impacting a Class I Federal area at one time is a key consideration in 

determining the BART exemption threshold. 

For the eight facilities impacting the Wolf Island Class I Federal area, SC DHEC 

concluded that the EPA suggested contribution threshold of 0.5 dv was appropriate in this 

situation based on a qualitative analysis of these facilities and their predicted visibility 

impacts. None of the eight facilities in question are in close proximity to Wolf Island, 

with the closest being just over 200 km away. Considering results of the visibility 

impacts modeling conducted, with four of the facilities reporting a 12 km screening 

(maximum) impact well below 0.5 dv and the other four reporting 4 km refined modeling 

impacts (98th percentile) below 0.3 dv, SC DHEC agrees with the state of Georgia that a 

0.5 dv threshold is appropriate for the Wolf Island Class I Federal area and a lower 

threshold was not warranted. 

For the fourteen facilities impacting the Cape Romain Class I Federal area, a more 

detailed analysis was performed. Of the fourteen facilities, two (SCE&G Williams and 

Wateree) performed a four-factor analysis and did not exempt. Of the remaining twelve 

facilities, only six (MeadWestvaco, DAK Americas, Santee Cooper Jeffries, Santee 

Cooper Winyah, International Paper Georgetown, and ISG Georgetown) were in close 

proximity to Cape Romain. For these six facilities, SC DHEC performed an analysis of 

the overlap in modeling impacts at Cape Romain. For this analysis, SC DHEC compiled 

the 8th highest impacts for each of the modeled years (2001, 2002, and 2003) to see what 

kind of overlap there was predicted on these days. It is important to note that, for this 

modeling, maximum predicted 24-hour emission rates were used. In actual operation, it 

is highly unlikely that each facility would be operating such that the maximum 24-hr 

emissions occurred at the same time. Thus, it is very likely that the actual combined 

impact at the class I area would be less than the sum of combined impacts from these 

facilities. Nevertheless, these 8th highest modeling days resulted in a total of 132 

modeled days. Of the 132 days, there were only a total of 12 days were two or more 

facilities overlapped (five days in 2001, four in 2002, and three in 2003) and only one day 

over the three years where three facilities overlapped. Thus, the overall impact from 

these facilities is relatively spread out, with very little overlap and certainly much fewer 

days of overlap than the 100 days used by EPA in the BART rule. In addition, a 0.5 dv 

threshold is consistent with the 0.5 dv threshold that all of the other VISTAS states intend 

to adopt for the Class I Federal areas in their states. In view of all this, a 0.5 dv threshold 

is appropriate and a lower threshold is not warranted. 

As a result, SC DHEC concluded that the EPA-suggested contribution threshold of 0.5 dv 

was appropriate in this situation since there are a limited number of out of state sources 

that impact Cape Romain. 

Appendix H - 53
7.5 Exemption of Point Source VOC for BART Purposes 

The State of South Carolina has determined through modeling that Volatile Organic 

Compounds (VOC) from point sources are not anticipated to cause or contribute 

significantly to any impairment of visibility at Cape Romain and should be exempt for 

BART purposes. 

 

7.5.1 Method 

The State of South Carolina determined through modeling that VOCs from point sources 

are not anticipated to cause or contribute significantly to any impairment of visibility at 

Cape Romain. 

Modeling was conducted through VISTAS. VISTAS is a collaborative effort of state 

governments, tribal governments, and various federal agencies established to initiate and 

coordinate activities associated with the management of regional haze, visibility and 

other air quality issues in the Southeastern United States. VISTAS contracted with 

Georgia Institute of Technology to perform model sensitivity runs to determine the 

impact of point source VOCs on visibility in Class I areas. 

Georgia Tech performed emission sensitivities to examine the impact of emission 

reductions on regional haze, annual PM2.5, and 8-hour ozone concentrations using 

CMAQv4.4_SOA_mods on the VISTAS 12-km modeling domain, which uses the 2009 

OTW (on the way) BaseD emissions. One such sensitivity run reduced anthropogenic, 

point source VOCs by 100 percent. The purpose was to quantify the impact of VOC 

emissions from VISTAS BART sources on Class I areas. 

The chart below illustrates the VOC contributions for each of the following Class 1 

Federal areas: 

BRET = Breton, LA 

BRIG = Brigantine NWR, NJ 

CACR = Caney Creek, AR 

CHAS = Chassahowitzka, FL 

COHU = Cohutta, GA 

DOSO = Dolly Sods, WV 

EVER = Everglades, FL 

GRSM = Great Smoky Mountains National Park 

HEGL = Hercules Glade, MO 

JARI = James River Face, VA 

LIGO = Linville Gorge, NC 

MACA = Mammoth Cave, KY 

MING = Mingo, MO 

OKEF = Okefenokee, GA 

ROMA = Cape Romain, SC 

Appendix H - 54
SAMA = Saint Marks, FL 

SHEN = Shenandoah, VA 

SHRO = Shining Rock, NC 

SIPS = Sipsey Wilderness, AL 

SWAN = Swanquarter, NC 

UPBU = Upper Buffalo Wilderness, AR 

WOLF = Wolf Island, GA 

Figure 7 - 1. Maximum Point VOC Impact 

7.5.2 Conclusions 

The results show that the maximum impact from eliminating all point source VOC 

emissions in the VISTAS 12-km domain is less than a 0.5 dv for all Class I areas in the 

VISTAS domain. VISTAS and the State of South Carolina conclude that VOCs from 

point sources are not a visibility impairing pollutant for BART purposes and that BARTeligible sources do not need to consider VOC emissions. 

7.6 Treatment of Ammonia 

Similar to its treatment of VOCs, EPA guidance allows States the discretion to decide 

whether or not ammonia emissions are to be considered for BART purposes based on 

evaluations of the contributions of the emissions to haze at Class I areas in their areas of 

influence. One approach a State can use to determine whether applying BART will be 

needed is to evaluate the haze impacts of all current emissions from all BART-eligible 

Appendix H - 55
sources in the State. If the impact from all sources in the state is less than the 

contribution threshold established by the State (0.5 dv for South Carolina), then source by 

source analysis for BART is not needed. 

SC DHEC has determined through modeling that, with one exception, ammonia (NH3) 

emissions from point sources are not anticipated to cause or contribute significantly to 

any impairment of visibility in Cape Romain and should be exempt for BART purposes. 

7.6.1 Method 

The State of South Carolina determined through modeling that ammonia emissions from 

point sources are not anticipated to cause or contribute significantly to any impairment of 

visibility at Cape Romain with the exception of one large point source in close proximity. 

VISTAS contracted with Georgia Institute of Technology to perform model sensitivity 

runs to determine the impact of point source ammonia on visibility in Class I areas. 

Georgia Tech performed emission sensitivities to examine the impact of emission 

reductions on regional haze using CMAQv4.5 with SOA_mods on the VISTAS 12-km 

modeling domain, using the VISTAS 2009 OTW (on the way) Base F4 emissions. One 

such sensitivity run reduced BART-eligible source ammonia by 100 percent. The 

purpose was to quantify the impact of ammonia emissions from VISTAS BART sources 

on Class I areas. Two episodes were examined: June 1 - July 10, 2002 and November 19 

- December 19, 2002. The approach included calculating the extinction coefficient in dv 

(deciviews), then determining the maximum impact of BART-eligible source ammonia. 

The chart below, taken from the VISTAS report BART in the VISTAS Region: Sensitivity 

to VOC, NH3, and Primary PM Emissions (included as Attachment H-5), shows the 

impact on the following twenty-two Class I Federal areas within the VISTAS domain. 

During the periods modeled, the ammonia emissions from all BART-eligible sources 

contributed more than 0.5 dv to haze at Mammoth Cave National Park (MACA), 

Kentucky; Mingo Wilderness (MING), Missouri, Cape Romain National Wildlife Refuge 

Area (ROMA) South Carolina; and Swanquarter National Wildlife Refuge (SWAN), 

North Carolina. 

The majority of ammonia emissions in VISTAS region come from four BART-eligible 

sources as shown in Table 7-1 below. 

Table 7 - 1. Major BART NH3 Sources in the VISTAS Region 

Facility State NH3 Emissions 

(tons/year) 

Distance to Nearest 

Class I Federal Area 

MeadWestvaco SC 130 29 

PCS Phophate NC 206 31 

PCS Nitrogen TN 1252 180 

Appendix H - 56
PCS Nitrogen GA 1765 220 

Analyses of spatial and temporal distributions of ammonia concentrations indicate that 

the primary point source ammonia contributor to Cape Romain haze is the Meadwestvaco 

Plant in North Charleston, South Carolina. Meadwestvaco is located 29 km from Cape 

Romain. 

The Regional Haze Regulations and Guidelines for Best Available Retrofit Technology 

(BART) Determinations final rule states that, “In regard to ammonia, we believe there is 

sufficient uncertainty about emission inventories and about the potential efficacy of 

control measures from location to location such that the most appropriate approach for 

States to take is a case-by-case approach...Thus, while ammonia can contribute to 

visibility impairment, we believe the decision whether to consider ammonia as a 

visibility-impairing pollutant in a specific case where a potential BART source actually 

emits more than 250 tons per year of ammonia is best left to the State” (FR 70 39114). 

As Table 7.1 indicates, Meadwestvaco’s BART-eligible units emit approximately 130 

tons/year of NH3. 

7.6.2 Conclusions 

The BART requirements of the regional haze rule allow states to determine whether or 

not ammonia is to be considered a visibility impairing pollutant to be addressed for 

BART purposes. NH3 emissions from BART sources may impair visibility; however the 

majority of NH3 emissions in the VISTAS region are from a few BART sources. 

Removal of the large NH3 emission sources results in minimal impact on visibility at 

Class I areas in the VISTAS region. At their discretion, states may ask those few large 

sources to evaluate NH3 impacts and potential controls for NH3. Based on annual CMAQ 

sensitivity analyses of the impacts of ammonia emissions as well as current emission 

rates, South Carolina determined that requiring Meadwestvaco to model ammonia 

impacts is not necessary at this time. 

Appendix H - 57
8.0 Explanation of BART Exemption Modeling 

8.1 Background 

SC DHEC opted to consider its BART-eligible sources subject to BART unless the 

source demonstrated exemption via modeling. BART-eligible sources can be excluded 

from BART determinations by demonstrating that the source cannot be reasonably 

expected to cause or contribute to visibility impairment in a Class I area. The threshold 

for determining that a source causes visibility impairment is set at 1.0 dv change from 

natural conditions over a 24-hour averaging period. The BART guidelines also propose 

that the threshold at which a source may “contribute” to visibility impairment should not 

be higher than 0.5 deciviews; however, depending on factors affecting a specific Class I 

area it may be set lower than 0.5 deciviews. 

As stated in the BART regulation the EPA’s preferred approach for determining cause or 

contribution is an assessment with an air quality model such as CALPUFF or other 

appropriate model followed by comparison of the estimated 24-hour visibility impacts 

against a threshold above estimated natural conditions to be determined by the State. The 

EPA recommends that the 98th percentile value from the modeling be compared to the 

State’s chosen contribution threshold to determine if a source does not contribute to 

visibility impairment and thus is not subject to BART. Comparison of the 98th percentile 

value to the threshold must be made for each Class I area. For an annual period, this 

implies the eighth highest 24-hour value at a particular Class I area is compared to the 

contribution threshold. For a three-year modeling period, the 98th percentile value may 

be interpreted as the highest of the three annual 98th percentile values at a particular Class 

I area or the 22nd highest value in the combined three year record, whichever is more 

conservative. 

SC DHEC worked with the regional planning organization (RPO) VISTAS on 

development of the VISTAS Protocol for the Application of the CALPUFF Model for 

Analyses of Best Available Retrofit Technology (BART) (Attachment H-6). The common 

protocol was established to provide the basis for a common understanding among the 

organizations performing BART analyses or reviewing BART modeling results in the 

VISTAS region. 

The VISTAS protocol describes common procedures for carrying out air quality 

modeling to support BART determinations that are consistent with the 40 CFR Part 51, 

Appendix Y guidelines. The protocol provides a consistent model (CALPUFF) and 

modeling guidelines for BART determinations, clearly delineated modeling steps, a 

common CALPUFF configuration, guidance for site-specific modeling, and common 

expectations for reporting model results. Details of the CALPUFF system can be found 

in Chapter 3 of the VISTAS protocol. Specific recommendations for its application for 

BART purposes are found in Chapter 4, and specific information that should be included 

in site-specific protocols is found in Chapter 5. 

Appendix H - 58
VISTAS contracted EarthTech to develop a version of the CALPUFF model appropriate 

for BART purposes. The VISTAS version of the CALPUFF model is CALPUFF 

Version 5.754 and CALMET Version 5.7. 

For BART modeling purposes, VISTAS made publicly available 12-km CALMET output 

files for the entire VISTAS modeling domain (eastern United States) and provided 

CALMET output files for five 4-km grid subdomains covering the VISTAS states and 

VISTAS Class I areas. To generate the CALMET input files, the VISTAS contractor 

used the MM5 databases developed by EPA for 2001, VISTAS for 2002, and Midwest 

RPO for 2003. For the 12-km grid large domain covering the entire VISTAS region, the 

“No-Obs” setting was used. For the 4-km grid available surface and upper air 

observations were used in addition to MM5 meteorological model outputs. Specific 

model settings were provided with the CALMET files and via the CALPUFF website so 

that work could be replicated. 

For CALPUFF modeling, source emissions were to be defined using the maximum 24-

hour actual emission rate during normal operation for the most recent three or five years. 

If maximum 24-hour actual emissions were not available, continuous emission data 

permit allowable emissions, potential emissions, and emission factors from AP-42 source 

profiles could be used as available. 

Key points on specific CALPUFF, CALPOST, and POSTUTIL configuration that were 

to be used for BART modeling are: 

• After running CALPUFF for an individual facility, NO3 should be repartitioned in 

POSTUTIL. 

• Ozone data from non-urban monitors should be used as the background ozone 

input. 

• The Pasquill-Gifford dispersion method should be used. 

• In CALPOST Method 6 with monthly average RH for calculating extinction as 

recommended by EPA should be used. 

• EPA default calculations of light extinction under current and natural background 

conditions should be used. In addition, a source may also calculate visibility 

using the recently revised IMPROVE algorithm. 

Additional discussion of the CALPUFF model and VISTAS recommended settings can 

be found in the VISTAS protocol in Attachment H-6. 

8.2 South Carolina BART Source Exemption Modeling 

SC DHEC requested that sources within South Carolina follow the VISTAS modeling 

protocol in development of their site specific protocols and explain any deviations that 

they proposed to use. In the site-specific modeling demonstrations submitted by South 

Carolina’s BART-eligible sources, the CALPUFF model incorporating three years of preAppendix H - 59
processed MM5 meteorological data was used to evaluate the deciview change compared 

to natural background conditions at each of the Class 1 areas within 300 km of the 

source. The 4-km MM5 dataset prepared by VISTAS was used. The 98th percentile 

delta-deciview (dv) value was determined at each Class 1 area and compared to the 0.5 

dv contribution threshold. 

Fourteen (14) of the twenty-one (21) facilities submitted site-specific modeling protocols 

and subsequent modeling demonstrations based upon the VISTAS modeling protocol. 

The site-specific protocols as well as the demonstrations are found in Attachment H-6. 

The protocols and demonstrations were reviewed by SC DHEC’s Modeling Section 

within the Bureau of Air Quality (BAQ) and also shared with both EPA and FLMs for 

their review and comment. Their comments were shared with the facilities. 

The individual facility modeling demonstrations were also shared with both EPA and 

FLMs for their review and comment. The resulting comments were in turn shared with 

the facilities. SC DHEC worked with EPA and FLMs throughout the process to resolve 

many of the issues and concerns reflected in their comments. SC DHEC BAQ staff 

reviewed the demonstrations to determine whether the sources have less than 0.5 

deciview (dv) impact on any Class I area within 300 km of the source. Sources 

demonstrating less than 0.5 dv impact are considered exempt. Sources contributing 0.5 

dv impact or greater are considered subject to BART and are thus required to proceed 

with an analysis of what control measures, if any, constitute BART for the source. 

Review of the demonstrations submitted led to the determination that the BART-eligible 

sources at nineteen of the twenty-one facilities in Table 8-1 should be exempt from 

BART determination requirements. Based upon these demonstrations, SC DHEC 

initially proposed exemption of sources at nineteen facilities. Table 8-1 below provides a 

summary of the impacts of each facility’s BART-eligible source on the Class I Federal 

areas affected. 

Table 8 - 1. BART Modeling Results 

Facility Class I Area* Impact (Change in dv)

Albemarle VOC Exempt 

BP Amoco Chemical - Cooper 

River Plant 

VOC Exempt 

Rhodia – Charleston VOC Exempt 

Eastman Chemical VOC Exempt 

INVISTA – Spartanburg VOC Exempt 

Stone Container – Florence Cape Romain 0.375** 

ISG Georgetown Cape Romain 0.279 

Owens Corning – Anderson VOC Exempt 

Milliken Chemical – Dewey VOC Exempt 

DAK Americas Cape Romain 

Wolf Island 

0.471 

MeadWestvaco Corp. Cape Romain 0.438 

Appendix H - 60
Okefenokee 

Wolf Island 

SCE&G – Canadys Cape Romain 

Okefenokee 

Wolf Island 

0.341 

International Paper - Georgetown Cape Romain 

Wolf Island 

0.456 

Wellman – Palmetto Cape Romain 

Linville Gorge 

Shining Rock 

0.224 

INVISTA - Camden Plant Cape Romain 

Great Smokies 

Linville Gorge 

Shining Rock 

0.244 

Bowater Cape Romain 

Great Smokies 

Joyce Kilmer 

Linville Gorge 

Shining Rock 

0.381 

Santee Cooper – Jefferies Cape Romain 

Wolf Island 

0.318 

SCE&G – Williams Cape Romain 

Okefenokee 

Wolf Island 

1.83 

Santee Cooper – Winyah Cape Romain 

Wolf Island 

0.476 

Santee Cooper – Grainger Cape Romain 

Swanquarter 

0.235** 

SCE&G – Wateree Cape Romain 

Great Smokies 

Linville Gorge 

Shining Rock 

Wolf Island 

0.72 

* Class I Federal areas within 300 km of the source 

** Screening modeling max impact 

Six of South Carolina’s BART-eligible sources are EGUs. Consistent with BART 

regulation requirements and EPA guidance, BART-eligible sources at electric utilities 

complying with EPA’s Clean Air Interstate Rule (CAIR) that wished to demonstrate 

exemption were allowed to model only direct PM fine emissions. Compliance with 

CAIR constitutes BART for these sources for emissions of NOX and SO2. 

 

On March 8, 2007, South Carolina submitted to EPA a parallel processing request for its 

version of CAIR. South Carolina subsequently received comments from EPA on this rule 

on May 23, 2007. Although the Department intends to accommodate EPA's proposed 

changes, the South Carolina Administrative Procedures Act, which sets forth 

Appendix H - 61
requirements for promulgating new or revised regulations, requires an extensive review 

period. The Department does intend to pursue incorporation of these changes and will 

commence that process as soon as possible. South Carolina's CAIR became stateeffective on June 22, 2007. EPA has indicated it is willing to provide South Carolina 

with abbreviated SIP approval for its version of CAIR (submitted to EPA as a final 

package on August 16, 2007). The proposed revisions, however, do not affect the CAIR 

allocation schedule and do not have a direct impact on existing BART-eligible EGUs; 

therefore, no BART compliance issues are expected for South Carolina EGUs. 

A number of the BART-eligible EGUs in South Carolina have already installed or are 

installing scrubbers to control SO2 and selective catalytic reduction (SCRs) to control 

NOX. Table 8-2 below summarizes the status of controls on these BART-eligible EGUs. 

Table 8-2. South Carolina BART-Eligible EGU Compliance Summary 

Plant Name Units Plant Type Existing NOx Control 

Existing SO2 

Control 

Projected 

Controls 

SANTEE 

COOPER - 

JEFFERIES 3 O/G Steam ESPs (1969/75) N/A N/A 

SANTEE 

COOPER - 

JEFFERIES 4 O/G Steam ESPs (1970/75) N/A N/A 

SCE&G 

WATEREE WAT1 Coal Steam SCR(2002)/Low Nox burners(1997)/FF(1998)/ESP(1982) N/A FGD (2009) 

SCE&G 

WATEREE WAT2 Coal Steam SCR(2002)/Low Nox burners(1998)/FF(1998)/ESP(1986) N/A FGD (2009) 

SCE&G 

WILLIAMS WIL1 Coal Steam SCR(2002)/Low Nox burners(1998)/ESP(1984) N/A FGD (2009) 

SANTEE 

COOPER - 

WINYAH 1 Coal Steam SCR (2003)/ESP(1971) FGD 2007) 

Upgrade FGD 

efficiency to 

95% by 2009 

8.3 Use of the New IMPROVE Algorithm 

During the regional haze SIP development process, the IMPROVE Steering Committee 

made recommendations for a new IMPROVE equation. Among other things, the new 

equation includes components that take into account the effects of sea salt and site 

specific Rayleigh scattering. These are important components to appropriately consider 

for South Carolina’s coastal and several other facilities. Additional discussion of the new 

IMPROVE equation can be found in Appendix O. 

VISTAS contracted Dr. Ivar Tombach to develop a post processor to allow CALPOST 

outputs to be used with the new IMPROVE equation. SC DHEC submitted to U.S. EPA 

Region 4, a request for approval to use the new IMPROVE equation and postprocessor 

developed by Dr. Tombach in BART modeling. A discussion of the rationale for use of 

Appendix H - 62
the new IMPROVE equation follows. The new IMPROVE postprocessor and 

instructions are included in the request to EPA for approval of its use in Attachment O. 

Rationale for Need for Use of New IMPROVE Equation. The new IMPROVE equation is 

a much better representation of the effects of particulate matter on light extinction than 

the old equation and takes into account the latest scientific understanding of several 

parameters. 

1. The new algorithm overcomes biases of the old algorithm on the haziest days and 

the clearest days as demonstrated by comparing the measured light extinction 

from nephelometers at Class I areas to light extinction calculated using each of 

the equations. 

2. The new algorithm recognizes spatial and temporal variation in light extinction as 

size distribution of the aerosol changes by increasing extinction efficiency as 

sulfate, nitrate and organics concentrations increase. 

3. The new algorithm incorporates a term to reflect the contribution of fine sea salt 

and its hygroscopic growth with increasing relative humidity recognizing research 

findings showing that fine sea salt can be an important contributor to light 

extinction in coastal areas. 

4. The new algorithm reflects research finding that the mass concentration of 

particulate organic matter in rural areas is greater than represented by the old 

equation. 

5. The new algorithm includes a NO2 term to represent times when light absorption 

by NO2 is a meaningful contributor to light extinction. 

6. The new algorithm incorporates site-specific Rayleigh scattering values to better 

represent sites close to sea level or with very hot or cold climates. 

With this combination of revisions to the IMPROVE equation, the resulting 

apportionment of extinction to various components is more accurate on the haziest and 

clearest days. This is important for the development of emission control strategies since 

the benefits of control of concentrations of each species will be represented more 

correctly with the new algorithm 

A majority of South Carolina’s BART eligible sources are located in coastal areas. The 

ability to appropriately represent the contribution of sea salt for these sources is important 

in determining their contribution to haze and evaluating the benefit of potential control 

strategies. U.S. EPA Region 4, the National Park Service, and the US Fish & Wildlife 

Service determined that adding site-specific data to account for the impact of sea salt and 

Rayleigh scattering to the old IMPROVE equation is not appropriate, but rather the entire 

new IMPROVE equation should be used. The spreadsheet developed by Dr. Tombach to 

implement the entire new IMPROVE equation for use with CALPUFF contains a 

modification of CALPOST that calculates the light extinction from the CALPUFF output. 

In their review of the spreadsheet and supporting documentation, EPA Region 4 staff 

commented that the VISTAS methodology contained in the spreadsheet developed by Dr. 

Tombach appropriately implements the features of the new IMPROVE equation, with the 

exception of the nitrogen dioxide term. EPA Region 4 further stated that with the 

Appendix H - 63
addition of their recommendation for addressing the NO2 term, the VISTAS methodology 

to incorporate the new IMPROVE equation is acceptable on a case-by-case basis upon 

consultation with the EPA Regional Office. 

South Carolina’s request and approval to use the new IMPROVE equation for BART 

purposes is found in Attachment O. 

8.4 Conclusions 

In total, nineteen of South Carolina’s twenty-one BART-eligible sources were able to 

demonstrate that they did not cause or contribute to visibility impairment in any Class I 

area within 300 km of the source. At least 10 of those sources used the new IMPROVE 

equation in efforts to demonstrate exemption. The two facilities that were not able to 

show they were exempt through modeling were SCE&G Williams and SCE&G Wateree. 

However, these sources are subject to CAIR. SC DHEC has determined that CAIR is 

equivalent to BART level controls. Therefore, no BART determinations are required for 

these facilities.

Appendix H - 64
9.0 BART Determinations and Conclusions 

As stated earlier in the narrative of this appendix, only two of South Carolina’s twentyone BART-eligible sources failed to exempt out of BART through modeling. However, 

as they are subject to CAIR, and South Carolina has determined that implementation of 

CAIR is equivalent to BART for SO2 and NOX. The BART determinations for PM for 

these sources found no reasonable control measures are available. In addition, DAK 

Americas, LLC., has opted to accept emission limitations for its Cooper River Facility in 

its Part 70 Air Quality Operating Permit (Conditions 5.E.34 and 6.B.51) so as to 

demonstrate exemption from further BART analysis. These complete list of BART 

determinations are included as Appendix H-6. 

Appendix H - 65
10.0 Final Long-Term Strategy and Reasonable Progress 

Goals 

As stated in section 2.0 above, the regional haze rule requires States to establish 

reasonable progress goals, expressed in deciviews, for visibility improvement at each 

affected Class I area covering each (approximately) 10-year period until 2064. This first 

set of reasonable progress goals must be met through measures contained in the state’s 

long-term strategy covering the period from the baseline until 2018. This section 

discusses development of South Carolina’s long-term strategy. 

10.1 Long-Term Strategy 

Ammonium sulfate is the most important contributor to visibility impairment and fine 

particle mass on the 20 percent worst and 20 percent best visibility days at Cape Romain. 

Sulfate levels on the 20 percent worst days account for 60-70 percent of the visibility 

impairment. Across the VISTAS region, sulfate levels are higher at the Southern 

Appalachian sites than at the coastal sites. On the 20 percent clearest days, sulfate levels 

are more uniform across the region. Reduction of SO2 emissions would be the most 

effective means of reducing ammonium sulfate. Ninety-five percent of SO2 emissions in 

North Carolina are attributable to electric generating facilities and industrial point 

sources. Thus, the long-term strategy for this first Regional Haze SIP focused on 

reductions in SO2 emissions. There are significant control programs in place in South 

Carolina and the region to reduce SO2 emissions between the baseline period and 2018. 

Most notably, CSA and CAIR are predicted to result in the greatest reduction from EGU 

SO2 emissions in South Carolina. 

Visibility improvements on the 20 percent worst days at Cape Romain are expected to be 

better than the uniform rate of progress glidepath by 2018 based solely on reductions 

from existing and planned emissions controls. The percentage of the target reduction 

achieved for Cape Romain on the 20 percent worst days using the new IMPROVE 

algorithm is approximately 110 percent. This means that the rate of improvement is at 

least 10 percent greater than the uniform rate of progress by 2018. In fact, visibility 

improvements at most of the coastal Class I Federal areas are projected to be better than 

the uniform rate of progress. 

In addition to improving visibility on the 20 percent worst visibility days, states are also 

required to protect visibility on the 20 percent best days at the Class I Federal areas. 

Visibility on the 20 percent best days is projected to improve in 2018 at all VISTAS 

Class I Federal areas as a result of the 2018 Base G2 emissions reductions. The 

percentage of the target achieved for Cape Romain is about -10 percent. Zero percent 

change would mean no change in visibility; while -10 percent means that visibility is 

better than no change or a 10 percent improvement has occurred. 

Appendix H - 66
10.2 What Additional Emissions Controls Were Considered as Part of the Long 

Term Strategy for Visibility Improvement by 2018? 

Section 308(d)(3)(v) of the regional haze rule lists several factors that must be addressed 

in each SIP. These factors include the role of fire at Class I Federal areas and status of 

state planning for smoke management, the role of dust and fine soil at Class I Federal 

areas and status of state plans to mitigate emissions from construction activities, and the 

role of NH3 and potential benefits if emissions from agricultural sources were mitigated. 

Section 51.308(d)(1) of the final RHR requires that a State establish “reasonable progress 

goals” for each Class I Federal area within the state. In establishing reasonable progress 

goals, the CAA provided analytical requirements for setting these goals (know as the four 

factors) which include: the cost of compliance, the time necessary for compliance, the 

energy and non-air quality environmental impacts of compliance, and the remaining 

useful life of any existing source subject to such requirements. 

In developing South Carolina’s reasonable progress goals, VISTAS, in November 2006, 

contracted with Alpine Geophysics to develop a cost control analysis that showed various 

control options for sources within an area of influence for Cape Romain and other Class I 

areas. 

Since sulfate is the predominant cause of visibility impairment in the VISTAS region, 

South Carolina and the other VISTAS states decided to concentrate on reduction of SO2, 

the precursor to sulfate formation, during this first planning period. As such, the cost 

control list was sorted for the SO2 emissions (Q) of each source divided by the distance 

(d) in kilometers to each class one area, or Q/d, and maximum residence time, RTmax. 

All sources with a Q/d greater than or equal to five and an RTmax greater than or equal to 

10 percent were added to the list for further consideration because it has been determined 

that these sources may contribute to visibility impairment on the 20 percent worst days. 

Sources meeting these criteria include: 

• Santee Cooper – Jefferies, South Carolina 

• Santee Cooper – Cross, South Carolina 

• SCE&G – Canadys, South Carolina 

• International Paper – Georgetown, South Carolina 

• Giant Cement, South Carolina 

• Holcim Holly Hill, South Carolina 

• MeadWestvaco, South Carolina 

• DAK Americas, South Carolina 

• International Pa Savannah Electric – McIntosh, Georgia 

• International Paper – Savannah, Georgia 

A cost threshold of $2,000.00 per ton for controls was then applied. Of the remaining 

facilities, all EGUs subject to CAIR were not considered as part of South Carolina’s 

Appendix H - 67
control strategy because CAIR makes substantial SO2 emission reductions and SO2 is the 

leading pollutant that contributes to visibility impairment at Cape Romain. 

SC DHEC multiplied the Q/d factors and the RTmax factors for all sources within a 

sulfate AOI for a given Class I area, then calculated a total and divided each product by 

that total to estimate the fractional contribution of each unit. Only the units with fractions 

of 0.01 or above (or greater than or equal to one percent contribution) were then 

evaluated using the four factor analysis. 

Under South Carolina’s approach, facilities whose costs fall below the $2,000.00 

threshold amount established were asked to conduct a four factor analysis. These 

facilities include: 

• MeadWestvaco, SC 

• International Paper, Georgetown, SC 

• Giant Cement, SC 

• International Paper, Savannah, GA 

• Holcim: Holly Hill, SC 

• DAK Americas, SC 

The final four-factor analysis for the remaining non-EGU sources was performed by the 

facilities and reviewed by the Department. 

The results of the four factor analyses (contained in Appendix N) indicate that no 

additional controls are reasonable at this time. However, further future reductions by 

way of additional controls have been discussed and will be evaluated during the next 

planning stage. 

10.3 Reasonable Progress Goals 

The Regional Haze Rule at 40 CFR section 51.308(d)(1) requires States to establish 

reasonable progress goals for each Class I area within the state (expressed in deciviews) 

that provide for reasonable progress towards achieving natural visibility. In addition, 

EPA released guidance on June 7, 2007 to use in setting reasonable progress goals. The 

goals must provide improvement in visibility for the most impaired days, and ensure no 

degradation in visibility for the least impaired days over the State Implementation Plan 

(SIP) period. The state must also provide an assessment of the number of years it would 

take to attain natural visibility conditions if improvement continues at the rate represented 

by the reasonable progress goal. 

In accordance with the requirements of 40 CFR §51.308(d)(1), this Regional Haze 

Implementation Plan establishes reasonable progress goals for South Carolina’s Class I 

Federal Area, Cape Romain. To calculate the rate of progress represented by each 

reasonable progress goal, SC DHEC compared baseline visibility conditions to natural 

visibility conditions at Cape Romain and determined the uniform rate of visibility 

Appendix H - 68
improvement (in deciviews) that would need to be maintained during each 

implementation period in order to attain natural visibility conditions by 2064. 

These controls were modeled in CMAQ as part of the long-term strategy. The modeling 

results were used to set the final reasonable progress goal. Preliminary results confirm 

what SC DHEC knows, that the final reasonable progress goals are at least as stringent as 

the Base G2a modeling results and are slightly more stringent when other reasonable 

measures are taken into account. 

VISTAS has demonstrated that the 2018 Base G2a control scenario provides for an 

improvement in visibility better than the uniform rate of progress for Cape Romain for 

the most impaired days over the period of the implementation plan and ensures no 

degradation in visibility for the least impaired days over the same period. In addition, SC 

DHEC expects that IMPROVE monitoring results for 2018 will at that time be used to 

establish a new baseline for the next planning period. Table 10-1 lists South Carolina’s 

Reasonable Progress Goals. 

Table 10-1. Reasonable Progress Goals for South Carolina 

Class I Area Baseline 

Visibility 

(20% Worst 

Days) 

Reasonable 

Progress Goal 

(Deciview 

Improvement 

Expected by 

2018, 20% 

Worst Days) 

Baseline 

Visibility 

(20 % Best 

Days) 

Reasonable 

Progress Goal 

(Expected 

Visibility 

Degradation, 20% 

Best Days) 

Cape Romain 26.5 22.7 (3.8) 14.2 12.7 (1.5) 

In conjunction with VISTAS, a final CMAQ modeling run were performed in the 

fall/winter of 2007 to account for the cumulative benefits of the Base G2a emissions 

controls, BART controls, and additional measures to achieve reasonable progress by 

2018. Preliminary results from this analysis show that South Carolina’s aforementioned 

reasonable progress goals for Cape Romain are reasonable and appropriate for this initial 

planning stage. 

Appendix H - 69