Technical Support Document 

for the 

Arkansas Regional Haze State Implementation Plan 

Prepared and Reviewed by: 

Dayana Medina 

Joe Kordzi 

Michael Feldman 

Erik Snyder 

Barbara Nann 

September 2011 
ii 

Table of Contents 

I. Relationship of this TSD to our Proposal .......................................................................................... 5 

II. Background to Regional Haze ......................................................................................................... 8 

III. Evaluation of State Submittal ....................................................................................................... 11 

 A. Identification of Affected Class I Areas : 40 CFR 51.308(d) .................................................... 11 

 B. Reasonable Progress Goals Development ................................................................................ 12 

 B.1. Establishment of Reasonable Progress Goals: 40 CFR 51.308(d)(1) ................................ 12 

 B.2. Reasonable Progress Goals Four Factor Analysis: 40 CFR 51.308(d)(1)(i)(A) ................ 14 

 B.3. Uniform Rate of Progress Determination: 40 CFR 51.308(d)(1)(i)(B) ............................. 16 

 B.4 Analysis of Reasonable Progress Goal: 40 CFR 51.308(d)(1)(ii)-(iii) ............................... 18 

 B.5 Reasonable Progress State Consultation: 40 CFR 51.308(d)(1)(iv) ................................... 18 

B.6 Reasonable Progress Goal To Be Considered by Administrator: 40 CFR 51.308(d)(1)(v)..19 

 B.7 Reasonable Progress Goal Minimum: 40 CFR 51.308(d)(1)(vi) ........................................ 20 

 C. Baseline and Natural Visibility Conditions .............................................................................. 20 

 C.1. Calculation of Baseline Conditions: 40 CFR 51.308(d)(2)(i) ............................................ 20 

 C.2. Calculation of Natural Visibility Conditions: 40 CFR 51.308(d)(2)(iii) ........................... 23 

 C.3. Natural Visibility Impairment: 40 CFR 51.308(d)(2)(iv)(A) ............................................ 24 

 D. Long Term Strategy: 40 CFR 51.308(d)(3) ............................................................. 25 

 D.1 Long Term Strategy State Consultation: 40 CFR 51.308(d)(3)(i) ....................................... 25 

 D.2 Share of Reductions in Other States’ Progress Goals: 40 CFR 51.308(d)(3)(ii) ................ 27 

 D.3 Technical Basis for the Long Term Strategy: 40 CFR 51.308(d)(3)(iii) – (iv) .................. 27 

 D.4 Consideration of Long Term Strategy Factors: 40 CFR 51.308(d)(3)(v) ........................... 34 

 E. Monitoring Strategy/Other SIP Requirements 40 CFR 51.308(d)(4) ....................................... 41 

 F. Best Available Retrofit Technology (BART) Requirements: 40 CFR 51.308(e) ..................... 43 

 F.1. BART Eligible Source Identification: 40 CFR 51.308(e)(1)(i) ......................................... 44 

 F.1.1. BART Sources Exempted Due to Model Waivers....... ... ............................................. 48 

 F.2. BART Five Factor Determination: 40 CFR 51.308(e)(1)(ii)(A) ....................................... 51 

 F.2.1. AECC Bailey Unit 1 and AECC McClellan Unit 1 BART Determinations ................... 54 

 F.2.2. AEP Flint Creek No. 1 Boiler BART Determination ..................................................... 60 

 F.2.3. Entergy Lake Catherine Unit 4 BART Determination ................................................... 62 

 F.2.4. Entergy White Bluff Units 1, 2, and Auxiliary Boiler BART Determinations .............72 

 F.2.5. Domtar Power Boilers No. 1 and 2 BART Determinations .......................................... 80 

F.2.6. ADEQ BART Results and Summary .............................................................89 

F.2.7. Arkansas Regional Haze Rule .......................................................................92 

 F.3. BART for Larger Fossil Fuel Power Plants: 40 CFR 51.308(e)(1)(ii)(B) ........................ 95 

 F.4. De Minimis BART: 40 CFR 51.308(e)(1)(ii)(C) ............................................................... 95 

 F.5. Design, Equipment, or Work Practice BART: 40 CFR 51.308(e)(1)(iii) ......................... 96 

 F.6. Installation of BART: 40 CFR 51.308(e)(1)(iv) – (v) ........................................................ 97 

 F.7. CAIR for BART: 40 CFR 51.308(e)(2-3) ........................................................................ 98 

F.8. CAIR for BART: 40 CFR 51.308(e)(4) ........................................................................... 98 

 F.9. Reasonable Progress and BART: 40 CFR 51.308(e)(5) ................................................... 98 

 F.10. BART Exemptions: 40 CFR 51.308(e)(6) ...................................................................... 99 

 G. 2018 Regional Haze SIP Revision: 40 CFR 51.308(f) ..................................................................... 99 

 H. Five Year Progress Report 40 CFR 51.308(g) ......................................................................... 100 

 I. Existing SIP Adequacy Determination 40 CFR 51.308(h) ..................................................... 101 

 J. Federal Land Manager Coordination 40 CFR 51.308(i) .......................................................... 102 
iii 

Tables

Table 1. Comparison of Reasonable Progress Goals to Uniform Rate of Progress on Most 

 Impaired Days for Arkansas Class I areas ....................................................... 13 

Table 2. Comparison of Reasonable Progress Goals to Baseline Conditions on Least Impaired 

 Days for Arkansas Class I areas...................................................................... 14 

Table 3. Calculation of Uniform Rate of Progress ............................................................ 17 

Table 4. Arkansas’ 2002 Emissions Inventory ............................................................... 30 

Table 5. Arkansas’ 2018 Emissions Inventory.............................................................. 31 

Table 6. Percent Contribution from Arkansas Emissions to Total Visibility Impairment at 

 Class I areas on 20% Worst Days..................................................................... 33 

Table 7. Facilities with BART-eligible units in Arkansas..................................................... 45 

Table 8. BART Eligible Facilities ADEQ Identified as Not Subject to BART............................. 52 

Table 9. Sources in Arkansas required to install BART....................................................... 52 

Table 10. Control Effectiveness of NOx Control Options for Lake Catherine 

 Unit 4- Gas Firing............................................................................................... 64 

Table 11. Control Effectiveness of NOx Control Options for Lake Catherine 

 Unit 4- Fuel Oil Firing................................................................................ 65 

Table 12. Cost-Effectiveness of NOx Control Options for Lake Catherine 

 Unit 4- Gas Firing.................................................................................... 65 

Table 13. Cost-Effectiveness of NOx Control Options for Lake Catherine 

 Unit 4- Fuel Oil Firing............................................................................ 66

Table 14. Visibility Impact of NOx Control Options for Lake Catherine 

 Unit 4- Gas Firing ............................................................................... 66

Table 15. Visibility Impact of NOx Control Options for Lake Catherine 

 Unit 4- Gas Firing .................................................................................. 67

Table 16. Cost-Effectiveness of SO2 Control Options for Lake Catherine 

 Unit 4- Fuel Oil Firing ........................................................................... 70

Table 17. Visibility Impact of SO2 Control Options for Lake Catherine 

 Unit 4- Fuel Oil Firing............................................................................ 70 

Table 18. Cost-Effectiveness of SO2 Control Options for Entergy White Bluff 

 Unit 1............................................................................................... 73 

Table 19. Cost-Effectiveness of SO2 Control Options for Entergy White Bluff 

 Unit 2 ............................................................................................... 74 

Table 20. Cost-Effectiveness of NOx Control Options for Entergy White Bluff 

 Unit 1................................................................................................ 77 

Table 21. Cost-Effectiveness of NOx Control Options for Entergy White Bluff 

 Unit 2 ............................................................................................... 77 

Table 22. Visibility Impact of ADEQ’s SO2, NOx, and PM BART Determinations 

 for Domtar Power Boilers No. 1 and 2......................................................... 85 

Table 23. BART Determinations Satisfying Section 51.308(e)............................................. 90 

Table 24. BART Determinations Not Satisfying Section 51.308(e)........................................ 90 
iv 

Figures 

Figure 1. Map of Class I Areas............................................................................ 8 

Figure 2. Location of the Class I Area in Arkansas...................................................... 9 

Figure 3. Map of Regional Planning Organization Boundaries........................................ 10 

Appendices 

Appendix A. Review of Modeling and Emission Inventory Development for the Regional Haze 

Implementation Plan for the State of Arkansas 
5 

Arkansas Regional Haze Technical Support Document (TSD) 

I. Relationship of this TSD to our Proposal 

 We are proposing to partially approve and partially disapprove a revision to the Arkansas 

State Implementation Plan (SIP) submitted by the State of Arkansas through the Arkansas 

Department of Environmental Quality (ADEQ) on September 23, 2008, August 3, 2010, and 

supplemented on September 27, 2011, that addresses regional haze (RH) for the first 

implementation period. 

 Specifically, we are proposing to approve the following: the State’s identification of 

affected Class I areas; the establishment of baseline and natural visibility conditions; the 

Uniform Rate of Progress (URP); the State’s reasonable progress goal (RPG) consultation and 

the long-term strategy (LTS) consultation; the regional haze monitoring strategy and other SIP 

requirements under section 51.308(d)(4); the State’s commitment to submit periodic regional 

haze SIP revisions and periodic progress reports describing progress towards the RPGs; the 

State’s commitment to make a determination of the adequacy of the existing SIP at the time a 

progress report is submitted; and the State’s consultation and coordination with Federal land 

managers (FLMs). 

 We are proposing to partially approve and partially disapprove those portions addressing 

the State’s identification of BART eligible sources and subject to BART sources; the 

requirements for best available retrofit technology (BART); the State’s RH Rule; and the LTS. 

Specifically, we are proposing to approve the State’s identification of BART eligible sources, 

with the exception of the 6A Boiler at the Georgia-Pacific Crossett Mill, which we find to be 

BART eligible. We are proposing to approve the State’s identification of subject to BART 

sources, with the exception of the 6A and 9A Boilers at the Georgia-Pacific Crossett Mill, which 

we find to be subject to BART. We are proposing to approve the following BART 

determinations made by ADEQ: the PM BART determination for the No. 1 Boiler of the 

American Electric Power (AEP) Flint Creek plant; the SO2 and PM BART determinations for the 

natural gas firing scenario for Unit 4 of the Entergy Lake Catherine plant; the PM BART 

determinations for both the bituminous and sub-bituminous coal firing scenarios for Units 1 and 

2 of the Entergy White Bluff plant; and the PM BART determination for the No. 1 Power Boiler 

of the Domtar Ashdown Mill. We are also proposing to disapprove the following BART 

determinations made by ADEQ: the SO2, NOx, and PM, BART determinations for both Unit 1 

of the Arkansas Electric Cooperative Corporation (AECC) Bailey plant and Unit 1 of the AECC 

McClellan plant; the SO2 and NOx BART determinations for the No. 1 Boiler of the AEP Flint 

Creek plant; the NOx BART determination for the natural gas firing scenario and the SO2, NOx, 

and PM BART determinations for the fuel oil firing scenario for Unit 4 of the Entergy Lake 

Catherine plant; the SO2 and NOx BART determinations for both the bituminous and sub-
6 

bituminous coal firing scenarios for Units 1 and 2 of the Entergy White Bluff plant; the BART 

determination for the Auxiliary Boiler of the Entergy White Bluff Plant; the SO2 and NOx 

BART determinations for the No. 1 Power Boiler of the Domtar Ashdown Mill; and the SO2, 

NOx, and PM BART determinations for the No. 2 Power Boiler of the Domtar Ashdown Mill. 

We are proposing to disapprove these BART determinations because they do not comply with 

our regulations under 40 CFR 51.308(e). The Arkansas Regional Haze Rule, the Arkansas 

Pollution Control and Ecology Commission (APC&E Commission) Regulation 19, Chapter 15, 

was submitted by ADEQ on September 23, 2008, as part of the RH SIP. On August 3, 2010, we 

received a SIP submittal from ADEQ revising several chapters of APC&E Commission 

Regulation 19, including Chapter 15. The revisions to Chapter 15 of APC&E Commission 

Regulation 19 that we received on August 3, 2010, are mostly non-substantive edits to the 

original rule we received on September 23, 2008. Therefore, in this proposed rulemaking we 

propose to take action on Chapter 15 of APC&E Regulation 19 contained in the submittal we 

received on September 23, 2008, and as revised by the submittal we received on August 3, 2010. 

We are proposing to approve the portions of APC&E Commission Regulation 19, Chapter 15, 

that are consistent with the portions of the Arkansas RH SIP we are proposing to approve and we 

are proposing to disapprove the portions that are consistent with other portions of the Arkansas 

RH SIP we are proposing to disapprove. We are proposing to partially approve and partially 

disapprove the State’s LTS because the LTS only partially satisfies the requirements under 

section 51.308(d)(3), and a portion of it relies on portions of the RH SIP we are proposing to 

disapprove. 

 We are also proposing to disapprove the State’s RPGs under section 51.308(d)(1) 

because Arkansas did not consider the factors that states are required to consider in establishing 

RPGs under the CAA and section 51.308(d)(1)(A). 

 This TSD contains one appendix that supports our proposal. Appendix A to this TSD 

contains a report describing our review of the emission inventory development, photochemical 

visibility modeling, and the BART modeling performed by ADEQ. 

 This TSD is not meant to be a complete rationale for our decision. It merely provides 

additional information for some of the technical aspects of the basis for this action when needed. 

In some of the non-technical areas, our Federal Register notice provides more detail than does 

this TSD. Also, this TSD treats the requirements of section 51.308 in the order in which they 

appear in that regulation, whereas our Federal Register notice groups the requirements into 

related areas so the concepts can be understood more easily. In this regard, the TSD can serve as 

a checklist of whether the requirements have been addressed. Lastly, the TSD attempts to refer 

the reader to the specific portions of the Arkansas RH SIP that we relied upon for our analysis of 

particular portions of section 51.308. 
7 

 Throughout this document, we often use language such as, "we find” or other similar 

phrases that on the surface would suggest a final determination has been made. However, all 

aspects of our TSD should be considered to be part of our proposal and are subject to change 

based on comments and other information we may receive during our public comment period. 
8 

II. Background to Regional Haze 

 In Section 169A of the 1977 Amendments to the Clean Air Act (CAA), Congress set 

forth a program for protecting visibility in Federal Class I areas which calls for the “prevention 

of any future, and the remedying of any existing, impairment of visibility in mandatory Federal 

Class I areas which impairment results from manmade air pollution.” Congress adopted the 

visibility provisions to protect visibility in 156 Federal Class I areas, which include certain 

national parks, memorial parks, and wilderness areas over a certain size, and all international 

parks. These areas are defined at 40 CFR 81.400, are listed by State at 40 CFR 81.401-81.437, 

and are depicted in Figure 1. The the two Class I areas within Arkansas, the Caney Creek 

Wilderness Area and the Upper Buffalo Wilderness Area, are depicted in Figure 2. 

Figure 1. Map of Class I Areas 7 
9 

Figure 2. Location of the Class I Areas in Arkansas 

 On December 2, 1980, we promulgated regulations to address visibility impairment that 

is “reasonably attributable” to a single source or small group of sources. (45 FR 80084) These 

regulations represented the first phase in addressing visibility impairment and deferred action on 

regional haze that emanates from a variety of sources until monitoring, modeling and scientific 

knowledge about the relationships between pollutants and visibility impairment improved. 

In the 1990 Amendments to the CAA, Congress added Section 169B and called on us to issue 

Regional Haze rules. The RH rule that we promulgated on July 1, 1999 (64 FR 35713) revised 

the existing visibility regulations to integrate provisions addressing regional haze visibility 

impairment and establish a comprehensive visibility protection program for Federal Class I 

areas. These regulations represented the second phase in addressing visibility impairment. States 

were required to submit state implementation plans (SIPs) to us that set out each state’s plan for 

complying with the RH Rule, including consultation and coordination with other states and with 

Federal Land Managers (FLMs). States were required to submit a Regional Haze SIP to us 

within three years after the date of designation of areas under the National Ambient Air Quality 

Standard (NAAQS) for fine particulate matter (PM2.5). We promulgated PM2.5 designations on 

December 17, 2004, and thus, regional haze SIPs were to be submitted to us by December 17, 

2007, which is also specified at 40 CFR 51.308(b). 
10 

 The RH rule addressed the combined visibility effects of various pollution sources over a 

wide geographic region. Consequently, all 50 states, including those without Class I areas, 

Washington, D.C., and the Virgin Islands, were required to submit Regional Haze SIPs (40 CFR 

51.300(b)(3)). We designated five Regional Planning Organizations (RPOs) to assist with the 

coordination and cooperation needed to address the visibility issue, as shown by Figure 3. 

Figure 3. Map of Regional Planning Organization Boundaries 

 Arkansas, through the ADEQ joined state air agencies from Iowa, Kansas, Louisiana, 

Minnesota, Missouri, Nebraska, Oklahoma, and Texas in forming CENRAP, in 1999. CENRAP 

also includes federally recognized Indian tribes located within the geographic boundaries of its 

member states. The State of Arkansas and its agency, ADEQ, chose to participate in CENRAP to 

develop the technical analyses needed to fulfill the requirements of the RH Rule. 
11 

III. Evaluation of State Submittal 

 In evaluating the Arkansas RH SIP, we reviewed all the parts of the document, including 

the body of the SIP itself, and all appendices. In addition, we drew upon the following additional 

documents that may not have been specifically discussed in our TSD and/or the Federal Register 

publication(s) of our decision: 

1. 40 CFR Part 51. 

2. Appendix V to 40 CFR Part 51. 

3. The “BART Guidelines” in Appendix Y to Part 51—Guidelines for BART Determinations 

 Under the Regional Haze Rule, 70 FR 39104, July 6, 2005. 

4. Guidance for Tracking Progress Under the Regional Haze Rule, EPA-454/B-03-004, 

 September, 2003. 

5. Guidance for Demonstrating Attainment of Air Quality Goals for PM2.5 and Regional Haze, 

 January 2, 2001. 

6. Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule, EPA- 

 454/B-03-005, September 2003. 

7. The “Baseline Memo,” which is entitled, “2002 Base Year Emission Inventory SIP 

 Planning: 8-Hour Ozone, PM2.5 and Regional Haze Programs, dated 11/18/2002, from Lydia 

 Wegman to the Regional Air Directors.” 

8. Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program, dated 

 June 1, 2007. 

9. Visibility Monitoring Guidance, EPA-454/R-99-003, June 1999. 

10. Emissions Inventory Guidance for Implementation of Ozone and Particulate Matter National 

 Ambient Air Quality Standards (NAAQS) and Regional Haze Regulations, EPA-454/R-05- 

 001, dated August, 2005. 

11. Interim Air Quality Policy on Wildland and Prescribed Fires, April 23, 1998. 

A. Identification of Affected Class I Areas : 40 CFR 51.308(d) 

 Arkansas must address regional haze in each mandatory Class I Federal area located 

within it and in each mandatory Class I Federal area located outside it which may be affected by 

emissions from within it. 

State Submittal: Pages 8-9 

The ADEQ is responsible for developing the Regional Haze SIP for Arkansas and 

submitting it to the Arkansas Pollution Control and Ecology Commission for approval. The 

State of Arkansas has two federal Class I areas within its borders. These are the 14,460 acre 
12 

Caney Creek Wilderness in Ouachita National Forest at Polk County and the 11,801 acre Upper 

Buffalo Wilderness in the Ozark National Forest at Newton County, which ADEQ has identified 

in its SIP. The FLM for the two Class I areas in Arkansas is the U.S. Department of Agriculture 

(USDA) Forest Service. 

 ADEQ also determined that Arkansas emissions have a potential to impact visibility at 

Class I areas outside of Arkansas. Potentially affected areas in other states are the two Class I 

areas in Missouri. These are the 12,315 acre Hercules Glades Wilderness (Hercules Glades) in 

the Mark Twain National Forest, located in Taney County Missouri, approximately 25 miles (40 

km) north of Boone County Arkansas; and the 8,000 acre Mingo National Wildlife Refuge 

(Mingo) located in Wayne and Stoddard Counties, approximately 30 miles (48 km) north of Clay 

County, Arkansas. The respective FLMs are the USDA Forest Service and the U.S. Fish and 

Wildlife Service under the U.S. Department of Interior. 

 

EPA Findings: 

 ADEQ has properly identified the Class I areas affected by Arkansas emissions. ADEQ 

consulted with the appropriate state air quality agency in Missouri to reach an agreement on 

whether it is necessary for Arkansas to commit to additional emission reductions that would help 

Missouri achieve its RPGs for Hercules Glades and Mingo. We find that ADEQ has satisfied 

this requirement. . 

B. Reasonable Progress Goals Development 

B.1. Establishment of Reasonable Progress Goals: 40 CFR 51.308(d)(1) 

 For each mandatory Class I Federal area located within the state, Arkansas must establish 

goals (expressed in deciviews) that provide for reasonable progress towards achieving natural 

visibility conditions. The reasonable progress goals must provide for an improvement in 

visibility for the most impaired days over the period of the SIP and ensure no degradation in 

visibility for the least impaired days over the same period. 

State Submittal: Pages 58-66, Appendix 8.1

 ADEQ adopted the CENRAP modeled 2018 visibility conditions as the RPGs for Caney 

Creek and Upper Buffalo Class I areas. ADEQ established a RPG of 22.48 dv for Caney Creek 

for 2018 for the 20% worst days. This represents a 3.88 dv improvement in visibility over a 

baseline of 26.36 dv. For Upper Buffalo, ADEQ established a RPG of 22.52 dv for 2018 for the 

20% worst days, which represents a 3.75 dv improvement in visibility over a baseline of 26.27 
13 

dv. ADEQ calculated that under its RPGs, it would attain natural visibility conditions in 2062 

for Caney Creek and 2063 for Upper Buffalo. ADEQ’s RPGs for the 20% worst days are shown 

on Table 1, which is adapted from Table 10.2 of the Arkansas RH SIP. 

 

Table 1. Comparison of Reasonable Progress Goals to Uniform Rate of Progress on Most 

Impaired Days for Arkansas Class I areas 

Arkansas 

Class I Area 

Visibility Conditions on 20% Worst Days (dv) 

Average for 20% 

Worst Days 

(Baseline 2000-2004) 

2018 URP 

Goal RPG 

Deciview Improvement 

Projected by CY 2018 using 

RPG (dv) 

Caney Creek 26.36 3.45 22.48 3.88 

Upper 

Buffalo 26.27 3.43 22.52 3.75 

The CENRAP’s projections for 2018 for the 20% best days for Caney Creek and Upper 

Buffalo, which represent ADEQ’s RPGs for the 20% best days, are shown in Figures 10.4 and 

10.6 of the RH SIP and in Appendix D to the TSD for CENRAP Emissions and Air Quality 

Modeling to Support RH State Implementation.1 ADEQ’s RPGs for the 20% best days 

(CENRAP projection) are shown on Table 2, which is adapted from Figures 10.4 and 10.6 of the 

RH SIP, and Figures D-1b and D-2b of Appendix D to the TSD for CENRAP Emissions and Air 

Quality Modeling to Support RH State Implementation. 

                                                           

1

 The TSD for CENRAP Emissions and Air Quality Modeling to Support RH State Implementation is found in 

Appendix 8.1 of the Arkansas RH SIP. 
14 

Table 2. Comparison of Reasonable Progress Goals to Baseline Conditions on Least 

Impaired Days for Arkansas Class I areas 

Arkansas 

Class I Area 

Visibility Conditions on 20% Best Days (dv) 

Achieved “No 

Degradation” 

(Y/N) Average for 20% Best Days 

(Baseline 2000-2004) 

RPG 

(CENRAP Projection) 

Caney Creek 11.24 10.35 Y 

Upper Buffalo 11.71 10.80 Y 

EPA Findings: 

The vehicle for ensuring continuing progress towards achieving the natural visibility goal 

is the submission of a series of RH SIPs from the states that establish two RPGs (i.e., two distinct 

goals, one for the “best” and one for the “worst” days) for every Class I area for each 

implementation period. See 70 FR 3915; see also 64 FR 35714. 

 Figures D-1b and D-2b of Appendix D to the TSD for CENRAP Emissions and Air 

Quality Modeling to Support Regional Haze SIPs (and Table 2 above) demonstrate the modeled 

RPGs for the 20% best days show an improvement in visibility of 0.89 dv and 0.91dv for Caney 

Creek and Upper Buffalo, respectively, by 2018. ADEQ also submitted RPGs for Caney Creek 

and Upper Buffalo for the 20% worst days, as shown in Table 1 above. However, for the reasons 

discussed in section III.B.2 of this TSD, we are proposing to disapprove Arkansas’ RPGs for 

Caney Creek and Upper Buffalo.

B.2. Reasonable Progress Goals Four Factor Analysis: 40 CFR 51.308(d)(1)(i)(A) 

 In establishing a reasonable progress goal for any mandatory Class I Federal area within 

Arkansas, ADEQ must consider the costs of compliance, the time necessary for compliance, the 

energy and non-air quality environmental impacts of compliance, and the remaining useful life of 

any potentially affected sources, and include a demonstration showing how these factors were taken 

into consideration in selecting the goal. 
15 

State Submittal: Pages 58-59 and Appendix 10.1 

 In establishing its RPGs for 2018 for the 20% worst days, ADEQ relied on the improvements 

in visibility that are anticipated to result from federal, State, and local control programs that are either 

currently in effect or with mandated future-year emission reduction schedules that predate 2018, 

including BART emission limitations established by ADEQ. Based on the emissions reductions 

from these measures, CENRAP modeled the projected visibility conditions anticipated at each Class 

I area in 2018 and ADEQ used these results to establish RPGs. ADEQ argued that because this rate 

of progress exceeds that representing the Uniform Rate of Progress (URP), and if sustained, will 

result in a return to natural background conditions prior to 2064, no additional analysis was required 

and would be an unnecessary exercise. ADEQ did not conduct a four factor analysis in establishing 

its RPGs. 

EPA Findings: 

 ADEQ has taken the position that because its RPGs provide for a slightly faster rate of 

improvement than the URP, it is not required to consider the reasonable progress factors. We 

disagree that such an approach is acceptable under section 169A of the CAA and our RH Rule. 

 In establishing a RPG for a Class I Federal area located within a state, the State is required by 

CAA §169A(g)(1) and 40 CFR 51.308(d)(1)(i)(A) to “[c]onsider the costs of compliance, the time 

necessary for compliance, the energy and non-air quality environmental impacts of compliance, and 

the remaining useful life of any potentially affected sources, and include a demonstration showing 

how these factors were taken into consideration in selecting the goal.” In addition to this explicit 

statutory requirement, the RH Rule also establishes an analytical requirement to ensure that each 

State considers carefully the suite of emission reduction measures necessary to attain the URP. The 

RH Rule provides that EPA will consider both the State’s consideration of the four factors in section 

51.308(d)(1)(i)(A) and its analysis of the URP “[i]n determining whether the State’s goal for 

visibility improvement provides for reasonable progress.” 40 CFR 51.308(d)(1)(iii). As explained in 

the preamble to the RH Rule, the URP analysis was adopted to ensure that States use a common 

analytical framework and to ensure an informed and equitable decision making process to ensure a 

transparent process that would, among other things, ensure that the public would be provided with 

the information necessary to understand the emission reductions needed, the costs of such measures, 

and other factors associated with improvements in visibility. 64 FR at 35733. The preamble to the 

RH Rule also makes clear that the URP does not establish a “safe harbor” for the state in setting its 

progress goals, providing that after considering the four statutory factors under 40 CFR 

51.308(d)(1)(iii), states may adopt RPGs that provide for greater, equal, or less visibility 

improvement than that represented by the URP (64 FR 35732). 

 States do have discretion in setting RPGs, but are required to go beyond the URP analysis in 

establishing RPGs. ADEQ cannot rely solely on meeting the URP to justify the conclusion that its 
16 

goals provide for reasonable progress. ADEQ made no attempt to determine whether additional 

progress would be reasonable based on the statutory factors. It does not appear that such an analysis 

would have been an unnecessary exercise, as claimed by ADEQ. As discussed in the proposed 

rulemaking and elsewhere in this TSD, there are at least two point sources in Arkansas that are not 

subject to the BART requirements, yet contribute visibility impairment at Arkansas’ Class I areas. 

This conclusion is based on information in the RH SIP indicating that these sources have predicted 

impacts exceeding the 0.5 dv contribution threshold ADEQ used to determine whether BART 

sources contribute to visibility impairment. Given their contribution to visibility impairment, these 

two sources are potential candidates for emissions controls under reasonable progress, as may be 

other Arkansas point sources whose visibility impact was not evaluated by ADEQ. . 

 Further, as discussed in more detail in Appendix A to this TSD, visibility impairment at 

Caney Creek in 2002 on the worst 20% days is largely due to sulfate from point sources that 

contributes over half (75.1 Mm-1) of the total extinction of 133.93 Mm-1. Similarly, visibility 

impairment at Upper Buffalo in 2002 on the worst 20% days is largely due to sulfate from point 

sources that contributes over half (72.17 Mm-1) of the total extinction of 131.79 Mm-1. Arkansas 

sources are projected to remain significant contributors to visibility impairment in 2018 and thus 

providing further support that additional analysis should have be performed according to the statutory 

factors. 

 Given that ADEQ did not provide an analysis that considered the four statutory factors 

under 40 CFR 51.308(d)(1)(i)(A) to evaluate the potential of controlling certain sources or 

source categories for addressing visibility impacts from man-made sources, it is not possible 

assess whether any additional control measures for improving visibility are reasonable. We are 

proposing to find that Arkansas has not satisfied the requirement to establish reasonable progress 

goals under section 51.308(d)(1)(i)(A).

B.3. Uniform Rate of Progress Determination: 40 CFR 51.308(d)(1)(i)(B) 

 In establishing a reasonable progress goal for any mandatory Class I Federal area within the 

State, Arkansas must analyze and determine the rate of progress needed to attain natural visibility 

conditions by the year 2064. To calculate this rate of progress, Arkansas must compare baseline 

visibility conditions to natural visibility conditions in the mandatory Federal Class I area and 

determine the uniform rate of visibility improvement (measured in deciviews) that would need to be 

maintained during each implementation period in order to attain natural visibility conditions by 2064. 

State Submittal: Pages 59-66 and Appendix 10.1 

 See Sections III.C.1 – C.2 of this TSD for a discussion on ADEQ’s calculations of baseline 

and natural visibility conditions. To calculate the rate of progress needed to attain natural visibility 
17 

conditions by the year 2064, also known as the Uniform Rate of Progress (URP), ADEQ compared 

baseline visibility conditions to natural visibility conditions for both the Caney Creek and Upper 

Buffalo Class I areas and determined the linear rate of visibility improvement (in deciviews) that 

would have to be maintained during each implementation period in order to attain natural visibility 

conditions by 2064. Using a baseline of 26.36 dv and a “refined” natural visibility value of 11.58 dv 

for the 20 percent worst days for Caney Creek, ADEQ calculated the URP to be 3.45 dv 

improvement necessary by 2018, as depicted by Table 3. Using a baseline of 26.27 dv and a 

“refined” natural visibility value of 11.57 dv for the 20 percent worst days for Upper Buffalo, ADEQ 

calculated the URP to be 3.43 dv improvement necessary by 2018. Figures 10.3 - 10.6 of the RH SIP 

show comparisons of the URP, RPG, and the anticipated improvement in visibility for each Class I 

area. The RPGs established by ADEQ, if met, will result in Caney Creek attaining the goal of 

background visibility conditions by CY 2062 and Upper Buffalo attaining the goal of background 

visibility conditions by CY 2063. The RPGs established by ADEQ exceed the URPs for these Class 

I areas, and if met will result in a return to natural background conditions prior to CY 2064. 

Table 3. Calculation of Uniform Rate of Progress 

Visibility Metric Caney Creek Upper Buffalo 

Baseline Conditions 26.36 dv 26.27 

Natural Visibility 11.58 dv 11.57 

Total Improvement by 2064 14.78 dv 14.70 

Improvement for this SIP by 2018 3.45 dv 3.43 

Uniform Rate of Progress 0.25 dv/year 0.245 dv/year 

EPA Findings: 

We agree that ADEQ has analyzed and determined the rate of progress needed to attain 

natural visibility conditions by the year 2064. ADEQ constructed the URP consistent with the 

requirements of the RH Rule and our 2003 Tracking Progress Guidance by plotting a straight 

graphical line from the baseline level of visibility impairment for 2000-2004 to the level of 

visibility conditions representing no anthropogenic impairment in 2064 for Caney Creek and for 

Upper Buffalo. ADEQ has calculated this rate of progress, and compared baseline visibility 

conditions to natural visibility conditions for Caney Creek and Upper Buffalo and determined the 

URP needed to be maintained during each implementation period in order to attain natural 

visibility conditions by 2064. We are proposing to find that Arkansas has appropriately 

calculated the URP and has satisfied the requirement in section 51.308(d)(1)(i)(B). 
18 

B.4 Analysis of Reasonable Progress Goal: 40 CFR 51.308(d)(1)(ii)-(iii) 

 For the period of the SIP, if Arkansas establishes a reasonable progress goal that provides for 

a slower rate of improvement in visibility than the rate that would be needed to attain natural 

conditions by 2064, it must demonstrate, based on the factors in section 51.308(d)(1)(i)(A), that the 

rate of progress for the SIP to attain natural conditions by 2064 is not reasonable; and that the 

progress goal adopted by it is reasonable. Arkansas must provide to the public for review as part of 

its SIP an assessment of the number of years it would take to attain natural conditions if visibility 

improvement continues at the rate of progress selected by it as reasonable. 

 

 In determining whether Arkansas’ goal for visibility improvement provides for reasonable 

progress towards natural visibility conditions, the Administrator will evaluate the demonstrations 

developed by it pursuant to Section 51.308(d)(1)(i) and (d)(1)(ii). 

State Submittal: N/A

EPA Findings: 

As the RPGs established by ADEQ provide for a faster rate of improvement in visibility than 

the rate that would be needed to attain natural conditions by 2064, the requirements of section 

51.308(d)(1)(ii) are not applicable to Arkansas. 

B.5 Reasonable Progress State Consultation: 40 CFR 51.308(d)(1)(iv) 

 In developing each reasonable progress goal, Arkansas must consult with those States which 

may reasonably be anticipated to cause or contribute to visibility impairment in the mandatory Class 

I Federal area. In any situation in which Arkansas cannot agree with another such State or group of 

States that a goal provides for reasonable progress, Arkansas must describe in its submittal the 

actions taken to resolve the disagreement. In reviewing Arkansas’ SIP submittal, the Administrator 

will take this information into account in determining whether its goal for visibility improvement 

provides for reasonable progress towards natural visibility conditions. 

State Submittal: Page 67 and Appendix 10.2 

 In establishing RPGs for each Class I area, the State of Arkansas consulted with other states 

and Tribes that are reasonably anticipated to cause or contribute to visibility impairment in each of 

these Class I areas. ADEQ worked with the Missouri Department of Natural Resources (MDNR) 

and CENRAP to develop the consultation plan. Consultations were held jointly by Arkansas and 

Missouri. ADEQ used CENRAP as the main vehicle for facilitating collaboration with FLMs 

and other states in developing its RH SIP. ADEQ was able to use CENRAP generated products, 
19 

such as regional photochemical modeling results and visibility projections, and source 

apportionment modeling to assist in identifying neighboring states’ contributions to the visibility 

impairment at Caney Creek and Upper Buffalo. 

 ADEQ determined that, in addition to Arkansas, the following states have a significant 

contribution to decreased visibility in one or both of Arkansas’ Class I areas: Illinois, Indiana, 

Kentucky, Missouri, Ohio, Oklahoma, Tennessee, and Texas. ADEQ sent a letter dated 

February 26, 2007, to these states, requesting that they participate in the consultation process for 

the Arkansas RH SIP. These States participated in the three consultations hosted jointly by 

ADEQ and MDNR in the form of conference calls on April 3, May 11, and June 7, 2007. 

Participants in these consultations included states and tribes, CENRAP and other Regional 

Planning Organizations (RPOs), EPA, and FLMs. 

 At the three consultations held jointly by ADEQ and MDNR, a URP was developed for 

each Class I area in Arkansas and Missouri (Caney Creek and Upper Buffalo in Arkansas, and 

Hercules Glades and Mingo in Missouri). The participating states also determined that CENRAP 

visibility projection modeling and other findings based on existing and proposed controls arising 

from state and federal requirements indicated that the two Class I areas in Arkansas and the two 

Class I areas in Missouri are on the glidepath to meet the rate of progress goals for the first 

implementation period ending in 2018. Therefore, ADEQ and MDNR determined that projected 

emissions reductions from those states having a significant contribution to decreased visibility at 

the two Class I areas in Arkansas and the two Class I areas in Missouri are adequate to meet each 

state’s apportioned part of emissions reductions necessary for these Class I areas to meet the 

RPGs. ADEQ determined that additional emissions reductions from other States are not 

necessary to address visibility impairment at Caney Creek and Upper Buffalo for the first 

implementation period ending in 2018, and all states participating in its consultations agreed with 

this. 

EPA Findings: 

Although we are proposing to disapprove Arkansas’ RPGs, we propose to find that 

Arkansas has met the state consultation requirements under section 51.308(d)(1)(iv) since ADEQ 

satisfied the minimum requirement of consulting with other states and all states participating in 

the consultation agreed that the goals established by ADEQ provide for reasonable progress. 

B.6 Reasonable Progress Goal To Be Considered by Administrator: 40 CFR 51.308(d)(1)(v) 

 The language under Section 51.308(d)(1)(v), “The reasonable progress goals established 

by the State are not directly enforceable but will be considered by the Administrator in 
20 

evaluating the adequacy of the measures in the SIP to achieve the progress goal adopted by the 

State,” is a statement relating to our review of RH SIPs. Since it does not require a response from 

the state, it is not separately evaluated here.

B.7 Reasonable Progress Goal Minimum: 40 CFR 51.308(d)(1)(vi) 

 Arkansas may not adopt a reasonable progress goal that represents less visibility 

improvement than is expected to result from implementation of other requirements of the CAA 

during the applicable planning period. 

State Submittal: Appendix 10.1 

 The RPGs established by Arkansas are based on CENRAP 2018 modeling projections. The 

modeling projections conducted by CENRAP contain projections of the visibility conditions that are 

anticipated to be realized at each Class I area between the 2002 base year and the 2018 future year. 

These projections are based on an assessment of the visibility improvements associated with local, 

State, and federal control programs that are either currently in effect or with mandated future-year 

emission reduction schedules, as well as on BART emission limitations established to date. 

EPA Findings: 

ADEQ’s RPGs are based on the visibility improvement predicted by CENRAP’s modeling 

projections to take place between the baseline year and 2018. Since CENRAPS’s 2018 modeling 

projections are based on local, State, and federal control programs that are either currently in 

effect or with mandated future-year emission reduction schedules, ADEQ’s RPGs represent at 

least as much visibility improvement as is expected to result from implementation requirements 

of the CAA during the applicable planning period. We propose to find that Arkansas has met 

this requirement. 

C. Baseline and Natural Visibility Conditions 

Note: 40 CFR 51.308(d)(2)(ii) is not applicable since this SIP was submitted after 2003, and 40 CFR 

51.308(d)(2)(iv)(B) is not applicable since this is the first SIP period. 

C.1. Calculation of Baseline Conditions: 40 CFR 51.308(d)(2)(i) 

 For each mandatory Class I Federal area located within Arkansas, the State must determine 

the baseline visibility conditions for the most impaired and least impaired days. The period for 

establishing baseline visibility conditions is 2000 to 2004. Baseline visibility conditions must be 
21 

calculated, using available monitoring data, by establishing the average degree of visibility 

impairment for the most and least impaired days for each calendar year from 2000 to 2004. The 

baseline visibility conditions are the average of these annual values. For mandatory Class I Federal 

areas without onsite monitoring data for 2000–2004, Arkansas must establish baseline values using 

the most representative available monitoring data for 2000–2004, in consultation with the 

Administrator or his or her designee. 

State Submittal: Pages 18-19 and Appendix 5.2 

 Baseline conditions represent visibility for the best and worst days at the time the 

regional haze program is established. Baseline conditions are calculated using multiyear 

averaging of the 20 percent of monitored days with the highest (most impaired, or worst days) 

and the 20 percent of monitored days with the lowest (least impaired, or best days) light 

extinction values, expressed in deciviews (dv), for the years 2000 through 2004. The RHR 

establishes the deciview (dv) as the principal metric for measuring visibility. See 70 FR 39104. 

A deciview is a uniform measure of light extinction caused by regional haze. This visibility 

metric expresses uniform changes in the degree of haze in terms of common increments across 

the entire range of visibility conditions, from pristine to extremely hazy conditions. The 

deciview scale approaches zero for no visibility degradation and increases as visibility is 

degraded. The deciview scale was designed similar to the decibel scale for sound, so that equal 

changes in deciview are equally perceptible. The deciview is a useful measure for tracking 

progress in improving visibility, because each deciview change is an equal incremental change in 

visibility perceived by the human eye. Most people can detect a change in visibility of one 

deciview. Common current values in the west are 15 to 20 dv; common current values in the 

east are 25 to 30 dv. Visibility is also sometimes expressed in terms of the visual range, which is 

the greatest distance, in kilometers or miles, at which a dark object can just be distinguished 

against the sky. 

 The baseline is the starting point for this regional haze submittal, against which progress 

toward the national visibility goal is measured. ADEQ calculated its baseline conditions in 

accordance with our 2003 Natural Visibility Guidance,2

 as required by the RHR. The baseline 

condition calculation begins with the calculation of light extinction, using the IMPROVE 

equation. The IMPROVE equation sums the light extinction resulting from individual pollutants, 

such as sulfates and nitrates. 

 In 2005, the IMPROVE Steering Committee made recommendations for a refined 

equation that modifies the terms of the original equation to account for the most recent data. The 

                                                           

2

 Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Program, EPA-454/B-03-005, 

September 2003. 
22 

purpose of this refinement is to provide more accurate estimates of the various factors that affect 

the calculation of light extinction. The new IMPROVE equation estimates additive extinction 

coefficients for each of several chemical constituents of particulate matter: sulfurous, nitrate, 

organic carbonaceous, elemental “light-absorbing” carbonaceous, fine soil, chlorine or chloride, 

and coarse matter. The equation also accounts for Rayleigh scattering of light and for 

deliquescence on sulfurous, nitrate, and chlorine or chloride particulates with an estimate of 

particle-bound water as a function of relative humidity. It reflects the most recent review of the 

science3

 and it accounts for the effect of particle size distribution on light extinction efficiency of 

sulfate, nitrate, and organic carbon. It also adjusts the mass multiplier for organic carbon 

(particulate organic matter) by increasing it from 1.4 to 1.8. New terms are added to the equation 

to account for light extinction by sea salt and light absorption by gaseous nitrogen dioxide. Sitespecific values are used for Rayleigh scattering (scattering of light due to atmospheric gases) to 

account for the site-specific effects of elevation and temperature. Separate relative humidity 

enhancement factors are used for small and large size distributions of ammonium sulfate and 

ammonium nitrate and for sea salt. The terms for the remaining contributors, elemental carbon 

(light-absorbing carbon), fine soil, and coarse mass terms, do not change between the original 

and new IMPROVE equations. 

 As with the natural visibility conditions calculation, ADEQ chose to use the new 

IMPROVE equation. The choice between use of the old or the new equation for calculating the 

visibility metrics for each Class I area is made by the state in which the Class I area is located. 

ADEQ has chosen to use this new equation, referred to in the SIP as a “refined” approach, for 

calculating both the baseline and natural visibility conditions because it takes into account the 

most recent review of the science and because it is recommended by the IMPROVE Steering 

Committee. 

 The IMPROVE monitor at Upper Buffalo was installed in 1991, and as such, the 

Arkansas RH SIP employs complete visibility data for Upper Buffalo for 2000-2004. The 

IMPROVE monitor at Caney Creek was installed in June 2001, and data fist became available in 

                                                           

3

 An explanation of the revised IMPROVE equation is found in appendix 5.1 of the Arkansas Regional Haze 

submittal and information regarding the science behind it can be found in numerous published papers. See for 

example: Hand, J.L., and Malm, W.C., 2006, Review of the IMPROVE Equation for Estimating Ambient Light 

Extinction Coefficients - Final Report. March 2006. Prepared for Interagency Monitoring of Protected Visual 

Environments (IMPROVE), Colorado State University, Cooperative Institute for Research in the Atmosphere, Fort 

Collins, Colorado. 

http://vista.cira.colostate.edu/improve/publications/GrayLit/016_IMPROVEeqReview/IMPROVEeqReview.htm; and 

Pitchford, Marc., 2006, Natural Haze Levels II: Application of the New IMPROVE Algorithm to Natural Species 

Concentrations Estimates. Final Report of the Natural Haze Levels II Committee to the RPO Monitoring/Data 

Analysis Workgroup. September 2006 

http://vista.cira.colostate.edu/improve/Publications/GrayLit/029_NaturalCondII/naturalhazelevelsIIrenatu.ppt 
23 

2002. ADEQ did not indicate whether any other monitor provided a reasonable substitute that 

met our completeness criteria. As a consequence, the Arkansas RH SIP employs visibility data 

for Caney Creek for 2002-2004. The resulting baseline conditions represent an average for 2002-

2004. ADEQ calculated the baseline by first summing the light extinction (where the extinction 

coefficient is expressed in Mm-1) for sulfate, nitrate, organic carbonaceous, elemental “lightabsorbing” carbonaceous, fine soil, chlorine or chloride, and coarse matter, using the following 

equation: 

βext = βext S + βext NO3 + βext organic+ βext elemental+ βext Soil+ βext coarse+ βext Cl+ βext Rayleigh 

 ADEQ then converted the total light extinction values to deciviews (dv), using the Haze 

Index (HI) equation: 

HI (dv) = 10 ln[βext/(10 Mm -1)] 

 ADEQ calculated the baseline conditions at Caney Creek as 26.36 dv on the 20% worst 

days, and 11.24 dv on the 20% best days. ADEQ calculated the baseline conditions at Upper 

Buffalo as 26.27 dv on the 20% worst days, and 11.71 dv on the 20% best days. 

EPA Findings: 

As stated above, ADEQ did not have access to a complete data set from 2000 – 2004 for 

Caney Creek. The IMPROVE monitor at Hercules Glades is the monitor with closest proximity to 

the monitor at Caney Creek. However, monitoring data from the Hercules Glades monitor first 

became available in 2002 as well. We believe that no adequate substitute for the unavailable 

monitoring data at Caney Creek exists. Therefore, we feel that ADEQ adequately utilized the data 

they did have at their disposal and adequately calculated baseline conditions. We propose to find 

that Arkansas has met this requirement. 

C.2. Calculation of Natural Visibility Conditions: 40 CFR 51.308(d)(2)(iii) 

 For each mandatory Class I Federal area located within the State, the State must determine 

the natural visibility conditions for the most impaired and least impaired days. Natural visibility 

conditions must be calculated by estimating the degree of visibility impairment existing under natural 

conditions for the most impaired and least impaired days, based on available monitoring information 

and appropriate data analysis techniques. 
24 

State Submittal: Page 19 and Appendix 5.3 

 Natural background visibility, as defined in our natural visibility guidance, is based on annual 

average concentrations of fine particle components. Natural background visibility for the 20% worst 

days is estimated by assuming that fine particle concentrations for natural background are normally 

distributed and the 90th percentile of the annual distribution represents natural background visibility 

on the 20% worst days (i.e, Method 1 prediction per our natural visibility guidance). 

 In the natural visibility guidance, we provided default estimates for the natural visibility 

condition at almost all Class I areas. For Caney Creek, the default natural visibility value for the 20% 

worst days is 11.33 dv and for the 20% best days is 3.65 dv. For Upper Buffalo, the default natural 

visibility value for the 20% worst days is 11.28 dv and for the 20% best days is 3.60 dv. 

 The natural visibility guidance also provided that states may use a “refined approach” to 

estimate the values that characterize the natural visibility conditions of the Class I areas. The purpose 

of such a refinement would be to provide more accurate estimates with changes to the extinction 

algorithm that may include the concentration values, factors to calculate extinction from a measured 

particular species and particle size, the extinction coefficients for certain compounds, geographical 

variation (by altitude) of a fixed value, and the addition of visibility pollutants. 

 As with the calculation of baseline conditions, ADEQ chose to use the new IMPROVE 

equation as the basis for its refined estimate because it takes into account the most recent review of 

the science and because it is recommended by the IMPROVE Steering Committee. ADEQ 

calculated the natural conditions at Caney Creek as 11.58 dv on the 20% worst days, and 4.23 dv on 

the 20% best days. ADEQ calculated the natural conditions at Upper Buffalo as 11.57 dv on the 20% 

worst days, and 4.18 dv on the 20% best days. 

EPA Findings: We propose to find that Arkansas has met this requirement. 

C.3. Natural Visibility Impairment: 40 CFR 51.308(d)(2)(iv)(A) 

 For the first SIP addressing the requirements of 51.308(d) and (e) of this section, Arkansas 

must calculate the number of deciviews by which baseline conditions exceed natural visibility 

conditions for the most impaired and least impaired days. 

State Submittal: Pages 18-19, Figures 10.3 and 10.5 

 As discussed in section III.C.1 of this TSD, ADEQ calculated the baseline conditions at 

Caney Creek as 26.36 dv on the 20% worst days, and 11.24 dv on the 20% best days. Also discussed 

in section III.C.2, ADEQ calculated the natural conditions at Caney Creek as 11.58 dv on the 
25 

20%worst days, and 4.23 dv on the 20% best days. ADEQ also calculated the baseline conditions at 

Upper Buffalo as 26.27 dv on the 20% worst days, and 11.71 dv on the 20% best days. ADEQ 

calculated the natural conditions at Upper Buffalo as 11.57 dv on the 20% worst days, and 4.18 dv on 

the 20% best days. The amount of visibility impairment can be calculated by subtracting the natural 

visibility condition values from the baseline values. 

 As displayed in Figure 10.3 of the RH SIP, ADEQ calculated the number of deciviews by 

which baseline conditions exceed natural visibility conditions at Caney Creek for the most impaired 

(20% worst) days to be 14.78 dv (26.36 – 11.58). As displayed in Figure 10.5 of the RH SIP, ADEQ 

calculated the number of deciviews by which baseline conditions exceed natural visibility conditions 

at Upper Buffalo for the most impaired (20% worst) days to be 14.70 dv (26.27 – 11.57). Similarly, 

baseline conditions exceed natural visibility conditions for the least impaired (20% best) days by 7.01 

dv (11.24– 4.23) at Caney Creek and 7.53 dv (11.71– 4.18) at Upper Buffalo. 

EPA Findings: We propose to find that Arkansas has met this requirement. 

D. Long Term Strategy: 40 CFR 51.308(d)(3)

 Arkansas, as with each State listed in section 51. 300(b)(3), must submit a long-term strategy 

that addresses regional haze visibility impairment for each mandatory Class I Federal area within the 

state and for each mandatory Class I Federal area located outside the state which may be affected by 

emissions from within the state. The long-term strategy must include enforceable emissions 

limitations, compliance schedules, and other measures as necessary to achieve the reasonable 

progress goals established by States having mandatory Federal Class I areas. 

State Submittal: Pages 68-75 

 The LTS is a compilation of state-specific control measures relied on by Arkansas for 

achieving its RPGs. Arkansas LTS for the first implementation period addresses the emissions 

reductions from federal, state, and local controls that take effect in the state from the end of the 

baseline period starting in 2004 until 2018. 

EPA Findings: 

Our determination of whether Arkansas has met the long term strategy requirements under 

section 51.308(d)(3) is discussed under section III.D.1-D.4. 
26 

D.1 Long Term Strategy State Consultation: 40 CFR 51.308(d)(3)(i) 

 Where Arkansas has emissions that are reasonably anticipated to contribute to visibility 

impairment in any mandatory Class I Federal area located in another State or States, it must consult 

with the other State(s) in order to develop coordinated emission management strategies. Arkansas 

must consult with any other State having emissions that are reasonably anticipated to contribute to 

visibility impairment in any mandatory Class I Federal area within it. 

State Submittal: Pages 68-69, Appendix 10.2 and Appendix 10.3 

 As in the development of Arkansas’ RPGs for Caney Creek and Upper Buffalo, ADEQ 

used CENRAP as its main vehicle for facilitating collaboration with FLMs and other states in 

satisfying its LTS consultation requirement. This helped ADEQ and other state environmental 

agencies analyze emission apportionments at Class I areas and develop coordinated RH SIP 

strategies. Arkansas’ consultations with other states are discussed in section III.B.6 of this TSD. 

ADEQ consulted with Missouri, as well as with several other states whose emissions have a 

potential visibility impact at Caney Creek and Upper Buffalo. ADEQ also participated in 

consultations for Mingo and the Hercules Glades in Missouri and the Wichita Mountains in 

Oklahoma. The CENRAP visibility modeling demonstrates Arkansas sources are responsible for 

a visibility extinction of approximately 7.1 inverse megameters4 (Mm-1) at Hercules Glades and 

for a visibility extinction of approximately 4.95 Mm-1 at Mingo on the worst 20% days for 2002.5 

As already discussed elsewhere in this proposed notice, ADEQ neither requested additional 

emission reductions from other states, nor made a commitment to other states for additional 

emission reductions beyond those already factored in to the CENRAP’s photochemical modeling 

for the 2018 visibility projections. All states participating in ADEQ’s consultation process 

agreed with this decision. 

EPA Findings: 

 Section 51.308(d)(3)(i) requires that Arkansas consult with other states if its emissions 

are reasonably anticipated to contribute to visibility impairment at that state’s Class I area(s), and 

that Arkansas consult with other states if their emissions are reasonably anticipated to contribute 

to visibility impairment at Caney Creek and Upper Buffalo. In addition to Arkansas, ADEQ 

determined that Illinois, Indiana, Kentucky, Missouri, Ohio, Oklahoma, Tennessee, and Texas 

contribute to visibility impairment at Caney Creek and Upper Buffalo. ADEQ also determined 

                                                           

4

 An inverse megameter is the direct measurement unit for visibility impairment data. It is the amount of light 

scattered and absorbed as it travels over a distance of one million meters. Deciviews (dv) can be calculated from 

extinction data as follows: dv = 10 x ln (bext(Mm-1)/10), where dv stands for “deciviews;” ln stands for “natural 

logarithm;” and bext stands for “extinction value.”. 5

 See Appendix E of the TSD for CENRAP Emissions and Air Quality Modeling to Support Regional Haze State 

Implementation, found in Appendix 8.1 of the Arkansas RH SIP.   
27 

that in addition to impacting visibility at its own two Class I areas, sources in Arkansas also have 

a visibility impact on Missouri’s two Class I areas (Hercules Glade and Mingo). Because ADEQ 

consulted with all states it is required to consult with under section 51.308(d)(3)(i), and because 

all states agreed with the outcome of the consultations, we are proposing to find that ADEQ’s 

consultations satisfy the requirements under section 51.308(d)(3)(i). 

D.2 Share of Reductions in Other States’ Progress Goals: 40 CFR 51.308(d)(3)(ii) 

 Where Arkansas causes or contributes to impairment in a mandatory Class I Federal area, 

it must demonstrate that it has included in its SIP all measures necessary to obtain its share of the 

emission reductions needed to meet the progress goal for the area. If Arkansas has participated 

in a regional planning process, it must ensure it has included all measures needed to achieve its 

apportionment of emission reduction obligations agreed upon through that process. 

State Submittal: Page 69 

 In developing its Regional Haze SIP and RPGs, Arkansas and potentially impacted States 

collaborated through CENRAP. Arkansas developed its RH Plans and RPGs based on CENRAP 

modeling. The CENRAP modeling was based on the reductions Arkansas intends to achieve by 

2018, and included local, State, and federal “on the books” controls, as well as emissions 

reductions resulting from BART controls on Arkansas subject to BART sources. The level of 

Arkansas emissions reductions factored into the CENRAP modeling represents Arkansas’ 

apportionment of emission reduction obligations that were agreed upon through the regional 

planning process. 

EPA Findings: 

Arkansas included in its RH SIP the measures needed to achieve its apportionment of 

emission reduction obligations agreed upon through the CENRAP regional planning process. 

Emissions reductions resulting from BART controls on Arkansas subject to BART sources were 

part of the emission reductions Arkansas committed to and these were factored into the 

CENRAP modeling. Compliance with these BART controls will ensure that Arkansas obtains its 

share of the emission reductions relied upon by other states to meet the RPGs for their Class I 

areas. Since compliance of Arkansas’ subject-to-BART sources with BART requirements is 

dependent upon our approval of the RH SIP, and since we are proposing to disapprove the 

portion of the RH SIP which includes some of Arkansas’ BART determinations, a portion of the 

emission reductions committed to by Arkansas and relied upon by other states will not be 

realized. Therefore, we are proposing to find that Arkansas has not met the requirement of 

section 308(d)(3)(ii). 
28 

D.3 Technical Basis for the Long Term Strategy: 40 CFR 51.308(d)(3)(iii) – (iv) 

 Arkansas must document the technical basis, including modeling, monitoring and 

emissions information, on which the State is relying to determine its apportionment of emission 

reduction obligations necessary for achieving reasonable progress in each mandatory Class I 

Federal area it affects. It may meet this requirement by relying on technical analyses developed 

by the regional planning organization and approved by all State participants. Arkansas must 

identify the baseline emissions inventory on which its strategies are based. The baseline 

emissions inventory year is presumed to be the most recent year of the consolidated periodic 

emissions inventory. 

 Arkansas must also identify all anthropogenic sources of visibility impairment considered 

by the State in developing its long-term strategy. It should consider major and minor stationary 

sources, mobile sources, and area sources. The following discussion of emission inventories for 

the 2002 base and 2018 future year, 2002 and 2018 photochemical modeling results, and our 

review of the results is a brief summary of the work that was done and our conclusions. For a 

more detailed discussion of the technical analyses including the photochemical modeling and our 

review and conclusions concerning what pollutants are causing regional haze in Caney Creek 

and Upper Buffalo, see Appendix A to this TSD. 

State Submittal: 

1. Emissions Inventory 

Pages 24-31, Appendix 7.1A, 7.1B, and 7.1C 

 The 2002 emissions inventory for on-road, nonroad, and nonpoint sources used in the 

regional haze technical analyses was developed by a contractor for ADEQ. ADEQ used EPA’s 

2002 biogenic source emissions inventory and completed the 2002 point source inventory inhouse with Emission Inventory Questionnaire’s (EIQs). The 2018 emissions inventory was 

developed by projecting 2002 emissions using growth and control factors derived from the 

EGAS6, MOBILE6, and NONROAD models and applying reductions expected from federal and 

state regulations affecting the emissions of the visibility-impairing pollutants NOx, PM, SO2,, 

and VOCs. The Integrated Planning Model (IPM) was used to forecast 2018 electric generating 

unit (EGU) emissions. The BART Guidelines direct states to exercise judgment in deciding 

whether VOCs and NH3 impair visibility in their 22 Class I area(s). 70 FR 391160. As 

discussed further in section V.C.3, CENRAP performed modeling sensitivity analyses and/or 

other analyses, which demonstrated that anthropogenic emissions of VOC and NH3 do not 

significantly impair visibility in the CENRAP region. Therefore, Arkansas did not consider 

ammonia among visibility-impairing pollutants and did not further evaluate NH3 and VOC 

emissions sources for potential controls under BART or reasonable progress. 
29 

a. Arkansas 2002 Emission Inventory 

 A contractor developed an emission inventory for three inventory source classifications: 

on-road and non-road mobile sources and nonpoint sources for the baseline year of 2002. ADEQ 

developed the 2002 point source emissions inventory in-house and used the biogenic source 

inventory developed by EPA. 

 The nonpoint, or area source, inventory includes emitters of ozone pollutants (i.e., NOx 

and VOCs) such as devices that combust fuel (e.g., dry cleaners, degreasing, and industrial 

surface coating), gasoline distribution, asphalt paving, and fires and open burning (e.g., 

agricultural burning, structural fires, wildfires, prescribed burning). In addition, area source 

categories contributing to visibility pollutants (i.e., PM10, PM2.5, and NH3) are also included in 

the area source emissions inventory (e.g., fugitive dust, agricultural operations, livestock 

ammonia, etc.). The contractor reviewed all emission factors used in the inventory to ensure they 

were the most appropriate and up-to-date emission factors available and checked all calculations 

for accuracy. 

 The 2002 on-road mobile source emissions included emissions from vehicles certified for 

highway use. Emissions from these sources were estimated by combining EPA emission factors 

from the MOBILE6 model, expressed in grams per mile (g/mile), with vehicle miles traveled 

(VMT) activity data. County-level Highway Performance Monitoring System (HPMS) VMT 

data were used for all Arkansas counties. The Arkansas Highway and Transportation Department 

(AHTD) provided annual average daily HPMS VMT data for 2007 and 2010, and these were 

exponentially extrapolated back to 2002. MOBILE6 emission factors were used in combination 

with the VMT data to estimate emissions by roadway type and vehicle type and vehicle class. 

 The 2002 nonroad mobile source emissions encompassed a wide variety of equipment 

types that moved or were moved within a 12-month period and are covered under the EPA’s 

emissions regulations as nonroad mobile sources. The EPA’s draft NONROAD2002 model (June 

2003) version was used to estimate emissions for most nonroad sources. The NONROAD model 

estimated emissions from non-road equipment in the following categories: agricultural 

equipment, airport ground support, construction equipment, industrial and commercial 

equipment, residential and commercial lawn and garden equipment, logging equipment, 

recreational equipment, and recreational marine vessels. Aircraft, commercial marine, and 

locomotive emissions were estimated separately and were also included in the non-road 

inventory. 

 ADEQ prepared the 2002 point source inventory. Point sources are stationary emissions 

sources that release pollutants into the atmosphere. ADEQ is responsible for identifying point 

sources meeting the threshold criteria, collecting facility emissions data, processing and 
30 

managing data, and compiling and displaying the results. Actual measurement with continuous 

emissions monitoring systems (CEMS) is the desired method of calculating emissions from a 

point source. In lieu of CEMS data, emissions may be calculated using other stack test data, 

material balance, or EPA’s AP-42 emission factors. CENRAP revised and quality assured the 

data point source emissions data compiled by ADEQ, and a contractor quality controlled the data 

and filled in gaps where necessary. 

 ADEQ used the biogenic source inventory developed by EPA. Arkansas 2002 emissions 

inventory is summarized in Table 4: 

Table 4. Arkansas’ 2002 Emissions Inventory 

SO2 NH3 NOx VOCs PM10-

PM2.5

PM2.5

Point 92,205 1 72,419 44,329 12,406 7,837

Nonpoint 29,889 152,436 27,450 93,548 148,433 68,000

Non-road 

mobile

5,490 49 62,472 54,785 5,673 5,220

On-road 

mobile

3,902 2,480 141,894 48,599 3,784 3,021

Biogenic 0 0 18,960 1,385,666 0 0

Total 131,485 154,967 323,195 1,626,927 170,296 84,078

b. Arkansas 2018 Emission Inventory 

 In general, ADEQ used a combination of our Economic Growth Analysis System (EGAS 

6), our mobile emissions model (MOBILE 6), our off-road emissions factor model 

(NONROAD), and the Integrated Planning Model (IPM) for electric generating units. 

 CENRAP developed emissions for five inventory source classifications: point, area, nonroad and on-road mobile sources, and biogenic sources. CENRAP used the 2002 emission 

inventory to estimate emissions in 2018. CENRAP contractors compiled the growth and control 

assumptions and factors used to estimate point-source emissions in 2018 from the inventory for 

2002. This included EGUs, internal combustion engines and other non-EGU point sources. 

CENRAP states provided data for the area source and non-road mobile emissions inventory for 

2018, to which a CENRAP contractor applied area source growth and control factors. These 

control factors accounted for federal standards for commercial marine vessels and locomotives. 

For the remaining non-road mobile categories, the contractor ran our NONROAD2004 model for 
31 

2018. This accounted for estimated growth in equipment populations and incorporated 

anticipated effects of most final federal standards, including the Tier 4 compression-ignition 

engine standards and the exhaust emissions standards for large spark-ignition engines, 

compression-ignition marine engines, and land-based recreational engines. ADEQ and CENRAP 

also developed the on-road mobile source emissions inventory for 2018 with contractor support. 

Biogenic emissions were held constant from the 2002 emission inventory. Arkansas’ 20018 

emissions inventory is summarized in Table 5. 

Table 5. Arkansas’ 2018 Emissions Inventory 

SO2 NH3 NOx VOCs PM10-

PM2.5

PM2.5

Point 106,461 2,575 71,107 55,603 19,799 13,775

Nonpoint 31,169 201,722 31,531 107,387 148,592 69,585

Non-road 

mobile 211 49 34,305 31,475 3,678 3,387

On-road 

mobile 442 3,412 33,640 19,924 949 949

Biogenic 0 0 18,960 1,385,666 0 0

Total 138,283 207,758 189,542 1,600,055 173,019 87,695

 CENRAP used this and other states’ 2018 emission inventories to construct visibility 

projection modeling for 2018. We find ADEQ’s 2018 emission inventory to be acceptable. 

2. Visibility Projection Modeling 

Pages 32-42, Appendix 8.1 

 Chapter 8 of the Arkansas Regional Haze SIP discusses the modeling methods and 

protocol used by CENRAP and ADEQ in developing the assessment. Section 8.1 describes the 

baseline emission inventory used by CENRAP in the Arkansas analysis. A detailed description 

and discussion of the model selection, modeling protocol, quality assurance, performance 

evaluation, emission inventory development and data used in the regional haze analysis can be 

found in Appendix 8.1 of the RH SIP and references therein. A short summary is provided 

below: 
32 

 CENRAP performed modeling for the regional haze LTS for its member states, including 

Arkansas. The modeling analysis is a complex technical evaluation that began with selection of 

the modeling system. CENRAP used the following modeling system: 

• Meteorological Model: The Pennsylvania State University/National Center for 

Atmospheric Research (PSU/NCAR) Mesoscale Meteorological Model (MM5) is a 

nonhydrostatic, prognostic meteorological model routinely used for urban- and regionalscale photochemical, PM2.5, and regional haze regulatory modeling studies. 

• Emissions Model: The Sparse Matrix Operator Kernel Emissions (SMOKE) modeling 

system is an emissions modeling system that generates hourly gridded speciated emission 

inputs of mobile, non-road mobile, area, point, fire and biogenic emission sources for 

photochemical grid models. 

• Air Quality Model: EPA’s Models-3/ Community Multiscale Air Quality (CMAQ) 

modeling system is a photochemical grid model capable of addressing ozone, PM, 

visibility and acid deposition at a regional scale. The photochemical model selected for 

this study was CMAQ version 4.5. It was modified through CENRAP with a module for 

Secondary Organics Aerosols (SOA) in an open and transparent manner that was also 

subjected to outside peer review. The Comprehensive Air Quality Model with extensions 

(CAMx) Version 4.40 model, applied using similar options as used by CMAQ, was used 

as a secondary corroborative model. CAMx was also utilized with its Particulate Source 

Apportionment Technology (PSAT) tool to provide source apportionment of predicted 

nitrate and sulfate aerosol concentrations. 

 CMAQ and CAMx modeling of regional haze in the CENRAP region for 2002 and 2018 

was carried out on a grid of 36x36 kilometer (km) cells that covers the continental United States, 

portions of Canada and Mexico, and portions of the Atlantic and Pacific Oceans along the east 

and west coasts. Selection of a representative period of meteorology is crucial for evaluating 

baseline air quality conditions and projecting future changes in air quality due to changes in 

emissions of visibility-impairing pollutants. CENRAP conducted an in-depth analysis which 

resulted in the selection of the entire year of 2002 (January 1-December 31) as the best period of 

meteorology available for conducting the modeling. The CENRAP modeling was developed 

consistent with our guidance.6

                                                           

6

 “Guidance on the Use of Models and Other Analyses for Demonstrating Attainment of Air Quality Goals for 

Ozone, PM2.5, and Regional Haze,”(EPA-454/B-07-002), April 2007, located at 

http://www.epa.gov/scram001/guidance/guide/final-03-pm-rh-guidance.pdf 

See also “Emissions Inventory Guidance for Implementation of Ozone and Particulate Matter National Ambient Air 

Quality Standards (NAAQS) and Regional Haze Regulations,” August 2005, updated November 2005 (“our 

Modeling Guidance”), located at http://www.epa.gov/ttnchie1/eidocs/eiguid/index.html, EPA-454/R-05-001
33 

 CENRAP examined the model performance of the regional modeling for the areas of 

interest before determining whether the CMAQ model results were suitable for use in the 

regional haze assessment of the LTS and for use in the modeling assessment. The modeling 

assessment predicts future levels of emissions and visibility impairment used to support the LTS 

and to compare predicted, modeled visibility levels with those on the URP. In keeping with the 

objective of the CMAQ modeling platform, the air quality model performance was evaluated 

using graphical and statistical assessments based on ambient measurements of PM species, 

gas-phase species and wet deposition from various monitoring networks and databases for the 

2002 base year. CENRAP used a diverse set of statistical parameters from our Modeling 

Guidance to stress and examine the model and modeling inputs. Once CENRAP determined the 

model performance to be acceptable, CENRAP used the model to assess the 2018 RPGs using 

the current and future year air quality modeling predictions, and compared the RPGs to the URP. 

 The CENRAP modeling shows that Arkansas sources are modeled to have contributions 

to the Class I areas in Missouri (Hercules-Glades and Mingo). Outside of Arkansas and 

Missouri, the largest contribution from Arkansas sources is at the Wichita Mountains Class I area 

in Oklahoma, amounting to 2.0 % of the visibility impairment at Wichita Mountains in 2002 and 

2.3% in 2018. Arkansas is also projected to contribute a small amount of visibility degradation 

at Class I areas in other states listed in Table 6. Table 6 summarizes the projected contribution 

from Arkansas emissions on visibility degradation at 9 Class I areas for the 20 percent worst 

days in 2002 and 2018, as modeled by CENRAP.7

 

Table 6. Percent Contribution from Arkansas Emissions to Total Visibility Impairment at 

Class I areas on 20% Worst Days8

Class I area State 2002 2018

Upper 

Buffalo Arkansas 10.2% 14.0% 

Caney Creek Arkansas 10.1% 13.1%

Hercules 

Glades Missouri 5.9% 7.6%

Mingo Missouri 3.3% 4.4% 

Wichita 

Mountains Oklahoma 2.0% 2.3%

                                                           

7

 See Appendix E of the TSD for CENRAP Emissions and Air Quality Modeling to Support Regional Haze State 

Implementation, found in Appendix 8.1 of the Arkansas RH SIP. 

8

 Contributions less than 1% were excluded from Table 12. 
34 

Mammoth 

Cave Kentucky 1.0% 1.8%

Bondville Illinois 1.2% 1.5%

Breton Island Louisiana 1.1% 1.3% 

Cadiz Kentucky 0.9% 1.2%

EPA Findings: We find ADEQ’s 2002 and 2018 emission inventories and the visibility 

projection modeling to be acceptable. Although we are proposing to find that Arkansas has not 

satisfied the requirements of section 51.308(d)(3)(ii), as discussed in section III.D.2 of this TSD, 

we find that Arkansas has adequately documented the technical basis, including modeling, 

monitoring, and emissions information, on which it relied upon to determine its apportionment of 

emission reduction obligations necessary for achieving reasonable progress in each mandatory 

Class I federal area it affects.9 We also find that Arkansas has adequately identified all 

anthropogenic sources of visibility impairment it considered in developing its LTS. We therefore 

propose to find that Arkansas has satisfied the requirements under section 308(d)(3)(iii) – (iv). 

D.4 Consideration of Long Term Strategy Factors: 40 CFR 51.308(d)(3)(v) 

Arkansas must consider, at a minimum, the following factors in developing its long-term 

strategy: 

(A)Emission reductions due to ongoing air pollution control programs, including measures to 

address reasonably attributable visibility impairment; 

(B) Measures to mitigate the impacts of construction activities; 

(C) Emissions limitations and schedules for compliance to achieve the reasonable progress 

goal; 

(D)Source retirement and replacement schedules; 

                                                           

9

 A detailed evaluation of the 2002 and 2018 Emissions Inventories and the CENRAP visibility projection modeling, 

as well as a discussion of what pollutants are driving regional haze in Caney Creek and Upper Buffalo are found in 

Appendix A to this TSD. 
35 

(E) Smoke management techniques for agricultural and forestry management purposes 

including plans as currently exist within the State for these purposes; 

(F) Enforceability of emissions limitations and control measures; and 

(G)The anticipated net effect on visibility due to projected changes in point, area, and mobile 

source emissions over the period addressed by the long-term strategy. 

State Submittal 

Pages 70-75 

 In addition to its BART determinations, Arkansas’ LTS incorporates emission reductions 

due to a number of ongoing air pollution control programs. This includes enforceable emissions 

limitations, compliance schedules, administrative orders, the issuance and enforcement of 

permits limiting emissions from all known major sources in Arkansas, state rules which 

specifically limit targeted emissions sources and categories, and several other ongoing air 

pollution control programs. ADEQ has promulgated rules in order to administer these programs. 

ADEQ addresses the long term strategy factors in 40 CFR 51.308(d)(3)(v)(A)-(G) as follows: 

1. Emission reductions due to ongoing air pollution control programs, including measures to 

 address reasonably attributable visibility impairment

 In developing its LTS, Arkansas considered a number of pollution control programs 

 required under federal regulations. These include EPA’s Clean Air Interstate Rule 

 (CAIR), which was expected to cap Arkansas’ ozone season trading budget for annual 

 NOx allocations at 9,596 tons by 2015;10 the federal Tier 2 Vehicle Emission Standards 

 for passenger cars and light trucks, which were fully implemented in 2007, and similar 

 rules for heavy trucks that are scheduled to be implemented by 2009; and the Highway 

 Diesel and Nonroad Diesel Rules, which mandate the use of lower sulfur fuels in diesel 

 engines beginning in 2006 for highway diesel fuel, and 2007 for nonroad diesel fuel. 

                                                           

10 CAIR was promulgated on May 12, 2005, and required 29 states to adopt and submit revisions to their SIPs to 

eliminate SO2 and NOx emissions that contribute significantly to downwind nonattainment of the ozone and PM2.5 

NAAQS promulgated in 1997. In July 2008, the Court found CAIR unlawful, and vacated CAIR. However, the 

Court subsequently remanded CAIR to EPA without vacatur. The CAIR requirements remained in place until CAIR 

was replaced by the Cross State Air Pollution Rule (CSAPR), promulgated by EPA on July 6, 2011. Arkansas 

continues to be included in the CSAPR for ozone season NOx. 
36 

2. Measures to mitigate the impacts of construction activities 

 ADEQ notes that since the Arkansas Water and Air Pollution Control Act does not apply 

 to land clearing, land grading, or road construction operations, ADEQ has limited 

 opportunities to mitigate air emissions resulting from construction activities. However, 

 ADEQ notes the federal General Conformity program requires assessment of the potential 

 impacts of any construction-related emissions of criteria pollutants from federal projects in 

 areas that have been designated as not attaining the National Ambient Air Quality 

 Standards (NAAQS) for that pollutant. ADEQ also participates in the Blue Skyways 

 Collaborative, a regional group that works collaboratively on the introduction of 

 innovative, regional-scale, transportation-related programs and projects. ADEQ notes it 

 has undertaken several initiatives to obtain reductions from on-road and non-road engines, 

 including grant funds directed to fleet managers and equipment suppliers as a means of 

 subsidizing diesel retrofits and the biodiesel market. 

3. Emissions limitations and schedules for compliance to achieve the reasonable progress 

 goal 

 ADEQ implements an air permitting program that includes the issuance of permits to all 

 known major point sources in Arkansas. Each permit contains enforceable limitations on 

 emissions of various pollutants, some of which may cause or contribute to regional haze at 

 Caney Creek and Upper Buffalo. ADEQ determined that ongoing State and federal air 

 pollution control programs are sufficient to meet RPGs through 2018, and that emission 

 reductions at non-BART facilities or new control programs for other anthropogenic source 

 categories will not be required at this time. 

4. Source retirement and replacement schedules 

 ADEQ stated retirement and replacement will be 

 managed in conformance with existing SIP requirements pertaining to the Prevention of 

 Significant Deterioration (PSD) and the New Source Review (NSR) programs. ADEQ 

 noted source retirement and replacement will be tracked through on-going point source 

 inventories. 

5. Smoke management techniques for agricultural and forestry management purposes 

 including plans as currently exist within the State for these purposes 

 Regulation 18 of the Arkansas Pollution Control and Ecology Commission contains a 

 general prohibition on “open burning of refuse, garbage, trade waste, or other waste 

 material,” but exempts controlled fires used for forest and wildlife management and 
37 

 certain agricultural activities (ADEQ Reg. 18.602-18.603). In 2007, the Arkansas Forestry 

 Commission approved revisions to the Arkansas Smoke Management Program (SMP). 

 The Arkansas SMP is designed to assure that prescribed fires are planned and executed in 

 a manner designed to minimize impacts associated with the smoke produced by prescribed 

 fires.11 The Arkansas SMP recommends a written fire plan that includes measures that can 

 be taken to reduce residual smoke from burning activities. The Arkansas SMP also 

 includes a process to evaluate potential smoke impacts at sensitive receptors and 

 guidelines for scheduling fires such that exposure of sensitive populations is minimized 

 and visibility impacts in Class I areas are avoided. 

6. Enforceability of emissions limitations and control measures 

 ADEQ has ensured that all emission limitations and control measures used to meet RPGs 

 are enforceable by incorporating these into State regulations.12 Chapter 15 of Regulation 

 No. 19 of the Arkansas Pollution Control and Ecology Commission contains the BART 

 requirements for all subject-to-BART sources in Arkansas. ADEQ has also committed to 

 issuing enforceable Part 70 air quality permits requiring BART-eligible sources subject to 

 BART to install BART and achieve the associated BART emission limits. Subject sources 

 must achieve the BART emission limits referenced above within five years of our 

 approval of the RH SIP, as required by section 51.308(e)(1)(iv). 

7. The anticipated net effect on visibility due to projected changes in point, area, and mobile 

 source emissions over the period addressed by the long-term strategy. 

 In developing its RH SIP, ADEQ relied on the CENRAP’s 2018 modeling projections, 

 which show that net visibility in 2018 is expected to improve by 3.88 dv at Caney Creek 

 and 3.75 dv at Upper Buffalo. CENRAP’s 2018 modeling projections account for changes 

 in point, area, and on-road and non-road mobile emissions. The results of CENRAP’s 

 2018 modeling projections are discussed in Appendix A to this TSD. 

EPA Findings: Our evaluation of whether ADEQ properly considered the factors under section 

51.308(d)(3)(v)(A)-(G) is found below. 

1. Emission reductions due to ongoing air pollution control programs, including measures to 

 address reasonably attributable visibility impairment

 

 Section 51.308(d)(3)(v)(A) requires that Arkansas consider in emission reductions due to 

                                                           

11 Documentation of Arkansas’ Smoke Management Program is found in Appendix 11.1 of the Arkansas RH SIP. 

12 See “Arkansas Pollution Control and Ecology Commission Regulation No. 19- Regulations of the Arkansas Plan 

of Implementation for Air Pollution Control,” found in Appendix 9.3C of the Arkansas RH SIP.
38 

 ongoing air pollution control programs in developing its LTS. Arkansas’ LTS 

 incorporates emission reductions due to EPA’s Clean Air Interstate Rule (CAIR), which 

 was expected to cap Arkansas’ ozone season trading budget for annual NOx allocations at 

 9,596tons by 2015. Consistent with EPA guidance and regulations (see 70 FR 39104, 

 39106 (July 6, 2005)), many states relied on EPA’s Clean Air Interstate Rule (CAIR) to 

 satisfy key elements of Regional Haze SIPs. The D.C. Circuit, however, found CAIR to 

 be inconsistent with the requirements of the Act and remanded the rule to the Agency. 

 North Carolina v. EPA, 531 F.3d 896, 929-30 (D.C. Cir. 2008); modified on rehearing, 

 North Carolina v. EPA, 550 F.3d 1176, 1178 (D.C. Cir. 2008). In response to the remand 

 of the CAIR rule, on July 6, 2011, EPA finalized the Transport Rule, also known as the 

 Cross-State Air Pollution Rule (CSAPR), a rule intended to reduce the interstate transport 

 of fine particulate matter and ozone (see 76 FR 48208). Since Arkansas was subject to 

 CAIR only for ozone season NOx, its Regional Haze SIP did not rely on CAIR to meet the 

 requirements for BART or for attaining the in-state emissions reductions necessary to 

 ensure reasonable progress. Instead, Arkansas evaluated controls for its potential BART 

 sources. Arkansas made BART determinations for its subject to BART sources, including 

 Electric Generating Units (EGUs) that might have been controlled under CAIR. Controls 

 on these sources are an element of Arkansas’ LTS for attaining the RPGs at Caney Creek 

 and Upper Buffalo. In terms of the LTS, EPA anticipates that the Transport Rule will 

 result in similar or better improvements in visibility than those predicted from CAIR at 

 Class I areas in Arkansas. As a result, we do not expect the remand of CAIR to have a 

 significant negative effect on the ability of Arkansas’ LTS to ensure that Caney Creek and 

 Upper Buffalo meet the RPGs in the State’s RH SIP. We note that to assess whether a 

 state’s current strategies will be sufficient to meet its RPGs, the RH Rule requires a 

 midcourse review by each state and, if necessary, a correction of the state’s regional haze 

 plan. See 40 CFR 52.308(g). If for a particular Class I area, the emissions reductions 

 resulting from the Transport Rule do not provide similar or greater benefits than CAIR and 

 if meeting the RPGs at one of its Class I areas is in jeopardy, the State will be required to 

 address this circumstance in its five year review 

 ADEQ also considered the Tier 2 Vehicle Emission Standards in developing its LTS. 

 Federal Tier 2 Vehicle Emission Standards for passenger cars and light trucks were fully 

 implemented in 2007 and similar rules for heavy trucks were scheduled to be implemented 

 by 2009. These federal standards will result in reductions of emissions of PM, ozone 

 precursors, and non-methane organic compounds. In developing its LTS, ADEQ also 

 considered the Highway Diesel and Nonroad Diesel Rules, which mandated the use of 

 lower sulfur fuels in diesel engines beginning in 2006 for highway diesel fuel, and 2007 

 for nonroad diesel fuel. These federal rules have resulted in more effective control of PM 

 emissions from diesel engines by allowing the installation of control devices that were 

 technically infeasible for fuels with higher sulfur content. 
39 

 Section 51.308(d)(3)(v)(A) also requires that Arkansas consider measures to address 

 reasonably attributable visibility impairment (RAVI) in developing its LTS. We approved 

 Arkansas’ Visibility Protection SIP on February 10, 1986 (51 FR 4910). We approved 

 Arkansas’ Part II Visibility Protection SIP, which addresses RAVI at Caney Creek and 

 Upper Buffalo, on July 21, 1988 (53 FR 27514). The FLMs did not identify 

 any integral vistas in Arkansas. In addition, Caney Creek and Upper Buffalo are not 

 experiencing RAVI, nor are any Arkansas sources affected by the RAVI provisions. For 

 this reason, the Arkansas RH SIP does not incorporate any measures to specifically 

 address RAVI. 

 

 We are proposing to find that ADEQ properly addressed the requirements of section 

 51.308(d)(3)(v)(A) in the development of its LTS. 

2. Measures to mitigate the impacts of construction activities 

 Section 51.308(d)(3)(v)(B) requires that in developing its LTS, Arkansas consider 

 measures to mitigate the impacts of construction activities. Construction-related activities 

 are believed to be a small contributor to fine and coarse particulates. ADEQ addressed 

 how it considered measures to mitigate the impacts of construction activities in developing 

 its LTS. We are proposing to find that ADEQ properly addressed the requirements of 

 section 51.308(d)(3)(v)(B) in the development of its LTS. 

3. Emissions limitations and schedules for compliance to achieve the reasonable progress 

 goal 

 Section 51.308(d)(3)(v)(C) requires that in developing its LTS, Arkansas consider 

 emissions limitations and schedules of compliance to achieve the RPGs. The SIP contains 

 emission limits and schedules of compliance for those sources subject to BART: the 

 AECC Bailey Unit 1; the AECC McClellan Unit 1; the AEP Flint Creek Boiler No. 1; the 

 Entergy Lake Catherine Unit 4; the Entergy White Bluff Units 1, 2, and the Auxiliary 

 Boiler; and the Domtar Power Boilers No. 1 and 2. The schedules for implementation of 

 BART for these sources are identified in Section 9.3 of the RH SIP and in the State’s RH 

 Rule included in Appendix 9.3C of the SIP. The BART emission limits established by 

 ADEQ are an element of the LTS, and since we are proposing to disapprove a portion of 

 ADEQ’s BART determinations, we cannot propose to approve this element of the LTS. 

 We are proposing to find that ADEQ has not satisfied the requirement of section 

 51.308(d)(3)(v)(C) in the development of its LTS. 
40 

4. Source retirement and replacement schedules 

 Section 51.308(d)(3)(v)(D) requires that in developing its LTS, Arkansas consider source 

 retirement and replacement schedules. ADEQ addressed how it considered source 

 retirement and replacement schedules in the development of its LTS. We are proposing to 

 find that ADEQ properly addressed the requirements of section 51.308(d)(3)(v)(D) in the 

 development of its LTS. 

5. Smoke management techniques for agricultural and forestry management purposes 

 including plans as currently exist within the State for these purposes 

 Section 51.308(d)(3)(v)(E) requires that in developing its LTS, Arkansas consider smoke 

 management techniques for agricultural and forestry management purposes. ADEQ 

 considered smoke management techniques for the purposes of agricultural and forestry 

 management in its LTS, including a State smoke management program. We are proposing 

 to find that ADEQ properly addressed the requirements of section 51.308(d)(3)(v)(E) in 

 the development of its LTS. 

6. Enforceability of emissions limitations and control measures 

 Section 51.308(d)(3)(v)(F) requires that in developing its LTS, Arkansas consider the 

 enforceability of emissions limitations and control measures. ADEQ has ensured the 

 enforceability of emission limitations and control measures that are being used to meet the 

 State’s RPGs for Caney Creek and Upper Buffalo. We are proposing to find that 

 ADEQ properly addressed the requirements of section 51.308(d)(3)(v)(F) in the 

 development of its LTS. 

7. The anticipated net effect on visibility due to projected changes in point, area, and mobile 

 source emissions over the period addressed by the long-term strategy. 

 Section 51.308(d)(3)(v)(G) requires that in developing its LTS, Arkansas consider the 

 anticipated net effect on visibility due to projected changes in point, area, and mobile 

 source emissions over the period addressed by the LTS. Since ADEQ relied on the 

 CENRAP’s 2018 modeling projections in the development of its RH SIP, which account 

 for changes in point, area, and on-road and non-road mobile emissions, we are proposing 

 to find that ADEQ properly addressed the requirements of section 51.308(d)(3)(v)(G) in 

 the development of its LTS. 

Conclusion: We are proposing to partially approve and partially disapprove Arkansas’ LTS. 

Because we are proposing to disapprove some of ADEQ’s BART determinations, we are also 
41 

proposing to disapprove the corresponding emission limits and schedules of compliance that 

Arkansas relied on as part of its LTS. With the exception of this element, the LTS satisfies the 

requirements of 40 CFR 51.308(d)(3), and we are proposing to approve these remaining 

elements. 

E. Monitoring Strategy/Other SIP Requirements: 40 CFR 51.308(d)(4) 

 Arkansas must submit with the SIP a monitoring strategy for measuring, characterizing, 

and reporting of regional haze visibility impairment that is representative of all mandatory Class 

I Federal areas within it. This monitoring strategy must be coordinated with the monitoring 

strategy required in section 51.305 for reasonably attributable visibility impairment. Compliance 

with this requirement may be met through participation in the Interagency Monitoring of 

Protected Visual Environments (IMPROVE) network. The SIP must also provide for the 

following: 

(i) The establishment of any additional monitoring sites or equipment needed to assess 

whether reasonable progress goals to address regional haze for all mandatory Class I 

Federal areas within Arkansas are being achieved. 

(ii) Procedures by which monitoring data and other information are used in determining the 

contribution of emissions from within Arkansas to regional haze visibility impairment at 

mandatory Class I Federal areas both within and outside the State. 

(iii)For a State with no mandatory Class I Federal areas, procedures by which monitoring 

data and other information are used in determining the contribution of emissions from 

within the State to regional haze visibility impairment at mandatory Class I Federal areas 

in other States. 

(iv)The SIP must provide for the reporting of all visibility monitoring data to the 

Administrator at least annually for each mandatory Class I Federal area in the State. To 

the extent possible, Arkansas should report visibility monitoring data electronically. 

(v) A statewide inventory of emissions of pollutants that are reasonably anticipated to cause 

or contribute to visibility impairment in any mandatory Class I Federal area. The 

inventory must include emissions for a baseline year, emissions for the most recent year 

for which data are available, and estimates of future projected emissions. The State must 

also include a commitment to update the inventory periodically. 
42 

(vi)Other elements, including reporting, recordkeeping, and other measures, necessary to 

assess and report on visibility. 

State Submittal: Pages 8-10, 119 

 Section 51.308(d)(4) requires the SIP contain a monitoring strategy for measuring, 

characterizing, and reporting of regional haze visibility impairment that is representative of all 

mandatory Class I Federal areas within the State. This monitoring strategy must be coordinated 

with the monitoring strategy required in Section 51.305 for reasonably attributable visibility 

impairment. As Section 51.308(d)(4) notes, compliance with this requirement may be met 

through participation in the IMPROVE network, which applies to the monitors at Caney Creek 

and Upper Buffalo. ADEQ stated its intention to rely on the IMPROVE network for complying 

with the regional haze monitoring requirement in our RHR for the current and future regional 

haze implementation periods. The primary monitoring network for regional haze in CENRAP is 

the IMPROVE network. FLMs responsible for Class I areas joined us in 1985 in response to the 

1977 CAA Amendments to form the IMPROVE Program. The IMPROVE Steering Committee 

consists of representatives from the FLMs, us, and regional-state agencies. At the direction of the 

National Park Service, the Cooperative Institute for Research in the Atmosphere, at Colorado 

State University’s Foothills Campus in Fort Collins, Colorado, maintains the network plan on the 

IMPROVE Internet Web site.13 The primary objectives of the IMPROVE Web site are to provide 

federal, state, and air quality regulatory agencies as well as the general public access to 

IMPROVE data, data products, and metadata fully describing the IMPROVE database, including 

characteristics and history of all network sites. The Web site allows users to query data, review 

reports, and communicate with different members of the IMPROVE Program. 

 Section 51.308(d)(4)(i) requires the establishment of any additional monitoring sites or 

equipment needed to assess whether RPGs to address regional haze for all mandatory Class I 

Federal areas within the State are being achieved. The IMPROVE monitor at Upper Buffalo was 

installed in 1991. Shortly after the creation of CENRAP, its monitoring workgroup noted there 

was a visibility void in Southern Arkansas. In 2001, the Caney Creek Wilderness area 

IMPROVE monitor was added to help fill that void. ADEQ also commits in the Arkansas RH 

SIP to evaluate the monitoring network periodically and consider evaluation technology changes 

and the need for new monitors. With the addition of the monitor at Caney Creek, we propose to 

find that ADEQ has satisfied this requirement. 

 Section 51.308(d)(4)(ii) requires that ADEQ establish procedures by which monitoring 

data and other information are used in determining the contribution of emissions from within 

                                                           

13 Please see http://vista.cira.colostate.edu/improve/. 
43 

Arkansas to regional haze visibility impairment at mandatory Class I Federal areas both within 

and outside the State. The monitor at Caney Creek is operated by Caney Creek Wilderness Area 

personnel, while the monitor at Upper Buffalo is operated by Upper Buffalo Wilderness Area 

personnel. The IMPROVE program makes data available on the Internet via the site noted above 

and submits it to our air quality system. This information is used to characterize the visibility at 

Caney Creek and Upper Buffalo and assess Arkansas’ progress toward its RPGs. The IMPROVE 

monitoring program is national in scope, and other states have similar monitoring and data 

reporting procedures, ensuring a consistent and robust monitoring data collection system. 

 Section 51.308(d)(4)(iv) requires that the SIP must provide for the reporting of all 

visibility monitoring data to the Administrator at least annually for each mandatory Class I 

Federal area in the State. To the extent possible, Arkansas should report visibility monitoring 

data electronically. Section 51.308(d)(4)(vi) also requires that ADEQ provide for other elements, 

including reporting, recordkeeping, and other measures, necessary to assess and report on 

visibility. Again, Arkansas’ participation in the IMPROVE network ensures the monitoring data 

is reported at least annually and is available for download from the site referenced above. 

 Section 51.308(d)(4)(iv) requires that ADEQ maintain a statewide inventory of emissions 

of pollutants that are reasonably anticipated to cause or contribute to visibility impairment in any 

mandatory Class I Federal area. The inventory must include emissions for a baseline year, 

emissions for the most recent year for which data are available, and estimates of future projected 

emissions. The State must also include a commitment to update the inventory periodically. 

Please refer to section III.D.3, above, where we discuss how ADEQ has constructed its emission 

inventory. ADEQ has stated on page 29 of its RH SIP that it intends to update the Arkansas 

statewide emissions inventories periodically. 

EPA Findings: We propose to find that Arkansas has satisfied the requirements of section 

51.308(d)(4). 

F. Best Available Retrofit Technology (BART) Requirements: 40 CFR 51.308(e) 

Arkansas must submit a SIP containing emission limitations representing Best Available Retrofit 

Technology (BART) and schedules for compliance with BART for each BART eligible source 

that may reasonably be anticipated to cause or contribute to any impairment of visibility in any 

mandatory Class I Federal area, unless it demonstrates that an emissions trading program or 

other alternative will achieve greater reasonable progress toward natural visibility conditions. 

Note: The evaluation of whether the RH SIP contains “adequate emission limitations 

 representing BART and schedules for compliance with BART for each BART eligible 
44 

 source that may reasonably be anticipated to cause or contribute to any impairment of 

 visibility in any mandatory Class I Federal area” is conducted within each BART 

 evaluation in Sections III.F.2.1 to III.F.2.6. 

Section 40 CFR 51.308(e)(2) – (3) concerning the use of a trading program or other alternative to 

BART are not applicable to this SIP. 

F.1. BART Eligible Source Identification: 40 CFR 51.308(e)(1)(i) 

Arkansas must submit a SIP containing a list of all BART-eligible sources within the State. 

Note: This section is intended to cover the general question of whether the state identified which 

sources were subject to BART. Subsequent sections treat this determination in more detail. 

State Submittal: Pages 43-46 

 ADEQ identified sources as BART eligible if they: 

1. Belonged to one of the twenty-six BART categories listed below; 

2. Did not operate before August 7, 1962, but were in existence on August 7, 1977; and 

3. Had the potential to emit 250 tons per year or more of any visibility-impairing pollutant. 

 ADEQ determined that the visibility-impairing pollutants in Arkansas include sulfur 

dioxide (SO2), nitrogen oxides (NOx), and particulate matter (PM10 and PM2.5). Because of the 

uncertainties in assessing the effect of VOCs and ammonia emissions reductions on visibility, 

Arkansas decided to not consider VOCs and ammonia among visibility-impairing pollutants. 

 ADEQ initially determined which sources were BART eligible by screening its emissions 

inventory and permitting database to identify major facilities with emission units in one or more 

of the 26 BART categories: 

1. Fossil-fuel fired steam electric plants of more than 250 million British thermal units 

(BTU) per hour heat input, 

2. Coal cleaning plants (thermal dryers), 

3. Kraft pulp mills, 

4. Portland cement plants, 

5. Primary zinc smelters, 

6. Iron and steel mill plants, 

7. Primary aluminum ore reduction plants, 
45 

8. Primary copper smelters, 

9. Municipal incinerators capable of charging more than 250 tons of refuse per day, 

10. Hydrofluoric, sulfuric, and nitric acid plants, 

11. Petroleum refineries, 

12. Lime plants, 

13. Phosphate rock processing plants, 

14. Coke oven batteries, 

15. Sulfur recovery plants, 

16. Carbon black plants (furnace process), 

17. Primary lead smelters, 

18. Fuel conversion plants, 

19. Sintering plants, 

20. Secondary metal production facilities, 

21. Chemical process plants, 

22. Fossil-fuel boilers of more than 250 million BTUs per hour heat input, 

23. Petroleum storage and transfer facilities with a capacity exceeding 300,000 barrels, 

24. Taconite ore processing facilities, 

25. Glass fiber processing plants, and 

26. Charcoal production facilities. 

 ADEQ then used its databases and records to identify facilities within these source 

categories with potential emissions of 250 tons per year or more for any visibility-impairing 

pollutant from any unit that was in existence on August 7, 1977 and began operation after 

August 7, 1962. As necessary, ADEQ contacted the sources to obtain or confirm pertinent data 

and information. These emissions units comprise the “BART-eligible sources” listed in Table 7, 

as adapted from Table 9.1 of the Arkansas RH SIP: 

Table 7. Facilities with BART-eligible units in Arkansas 

BART source 

category Facility name County Unit Description 

Fossil fuel-fired 

steam electric 

plants of more 

than 250 

MMBTU/hr heat 

input

AEP Flint Creek Power Plant Benton Boiler 

AECC Carl E. Bailey Generating 

Station Woodruff Boiler 

AECC John L. McClellan Generating 

Station Ouachita Boiler 

Entergy Lake Catherine Plant Hot Spring Unit 4 Boiler 
46 

Entergy Robert E. Ritchie Plant Phillips Unit 2 

Entergy White Bluff Plant Jefferson 

Unit 1 

Unit 2 

Auxiliary Boiler 

Kraft pulp mills 

Domtar Ashdown Mill Little River 

No. 1 Power 

Boiler

No. 2 Power 

Boiler

Delta Natural Kraft Jefferson Recovery Boiler 

Evergreen Packaging/International 

Paper Jefferson No. 4 Recovery Boiler 

Georgia Pacific Crossett Mill Ashley 9A Boiler 

Green Bay Packaging Conway Recovery Boiler 

Potlatch Forest Products/Clearwater 

Paper Corporation Cypress Bend Mill Desha Power Boiler 

Petroleum 

refineries Lion Oil Company Union No. 7 Catalyst Generator 

Sulfur recovery 

plants Albermarle Corporation South Plant Columbia Tail Gas Incinerator 

Sintering plants Big River Industries- Arkalite Crittenden Kiln A 

Chemical 

process plants 

Albermarle Corporation South Plant Columbia 

No. 1 Boiler 

No. 2 Boiler 

Future Fuels/Eastman Chemical 

Company Independence 3 Coal Boilers 

El Dorado Chemical Company Union 

West Nitric Acid 

Plant

East Nitric Acid 

Plant

Nitric Acid 

Concentrator
47 

 We also note that in the State’s RH Rule, Chapter 15 of APC&E Regulation 19, 

contained in the submittal we received on September 23, 2008, and as revised by the submittal 

we received on August 3, 2010, ADEQ identified one more unit (not listed in Table 7 above), the 

6A Boiler at Georgia-Pacific Crossett Mill, as being BART eligible. ADEQ did not identify the 

6A Boiler as BART eligible in the RH SIP narrative. Appendix 9.1A states the 6A Boiler began 

operation prior to August 7, 1962, and that it falls out of the BART eligibility criteria because of 

its start of operations date. On September 27, 2011, ADEQ submitted supplemental information 

clarifying that the Georgia-Pacific Crossett Mill provided ADEQ a copy of a boiler inspection 

report for the 6A Boiler, which states that the inspection of the new boiler took place on August 

6, 1962, to determine if the boiler complied with the State and American Society of Mechanical 

Engineers (ASME) codes.14 However, ADEQ stated it cannot say with certainty whether the 6A 

boiler was in operation as of August 6, 1962, or at a later date.15 

EPA Findings: 

 Since sufficient information was not provided to verify the date of start of operations of 

the 6A Boiler at the Georgia-Pacific Crossett Mill, we cannot make the determination that the 

boiler is not BART eligible. Therefore, we are proposing to find that the 6A Boiler at the 

Georgia-Pacific Crossett Mill is BART eligible. 

 In the RH SIP, ADEQ identified one unit (the No. 4 recovery boiler) at International 

Paper/Evergreen Packaging as BART eligible (shown in Table 7). ADEQ included two other 

units (the No. 1 and 2 Power Boilers) at International Paper/Evergreen Packaging in its 

evaluation to determine what sources are subject to BART. In the State’s September 27, 2011 

supplemental submittal, the State provided an inspection certificate issued on June 26, 1958, by 

the Arkansas Department of Labor to the International Paper Company for the No. 1 and 2 

Boilers.16 The inspection certificate states the Arkansas Department of Labor performed an 

annual inspection of the two boilers on May 27, 1958. Since the No. 1 and 2 Boilers were in 

operation prior to August 7, 1962, they fall out of the startup date criteria for BART eligibility. 

We agree that the No. 1 and 2 Power Boilers at International Paper/Evergreen Packaging are not 

BART-eligible. 

 In the RH SIP, ADEQ did not identify Boilers SN-301A and SN-302A at the Great Lakes 

Chemical Plant as BART-eligible, but since ADEQ at one point believed these units to be BART 

                                                           

14 A copy of the boiler inspection report for the 6A Boiler at the Georgia-Pacific Crossett Mill can be found in the 

docket for this proposed rulemaking. 

15 The BART Guidelines define “in operation” as “engaged in activity related to the primary design function of the 

source.” 

16 A copy of the inspection certificate issued on June 26, 1958, by the Arkansas Department of Labor for the 

Georgia-Pacific Crossett Mill No. 1 and 2 Boilers can be found in the docket for this rulemaking. 
48 

eligible, ADEQ included these units in its evaluation to determine what sources are subject to 

BART. EPA reviewed the federally enforceable operating permit for the Great Lakes Chemical 

Plant and determined that Boilers SN-301A and SN-302A are not BART eligible because they 

are boilers with a heat input rating less than 250 MMBtu/hr and are not integral to the process at 

the plant, as the permit states they are used to supply heat to the process.17 The BART 

Guidelines provide that an individual fossil fuel boiler smaller than 250 MMBtu/hr that does not 

fall into source Category 1 (i.e., Fossil-fuel fired steam electric plants of more than 250 

MMBtu/hr heat input), falls into one of the source categories for BART eligibility only if it is an 

integral part of a process description at a plant. If the boiler is integral to the process description 

at a plant, it falls into the source category of the process which it serves. In general, if the boiler 

serves the process in any way beyond contributing heat, it is integral to the process. Based on 

information in the current operating air permit for the Great Lakes Chemical Plant, we agree that 

Boilers SN-301A and SN-302A are not BART-eligible. 

 We propose to find that ADEQ has adequately identified all BART-eligible sources in 

Arkansas, with the exception of the 6A Boiler at Georgia-Pacific Crossett Mill, which we find to 

be BART eligible. 

F.1.1. BART Sources Exempted Due to Modeling Waivers 

State Submittal: Pages 46-48, Appendix 9.2A 

 Following the identification of those sources which were determined to be BART 

eligible, ADEQ performed visibility modeling of each BART eligible unit to determine whether 

it caused or contributed to visibility impairment at any Class I area. Pursuant to federal 

regulations, states have the option of exempting a BART-eligible source from the BART 

requirements based on dispersion modeling demonstrating that the source cannot reasonably be 

anticipated to cause or contribute to visibility impairment in a Class I area. Please see Appendix 

A to this TSD for more details of how sources were exempt from BART by the ADEQ and our 

analysis of this modeling. 

 ADEQ’s BART Modeling Protocol is found in Appendix 9.2A. ADEQ utilized BART 

modeling that did not include meteorological observations, and therefore used the 1st High (i.e., 

maximum) value from the CALPUFF modeling to determine what sources contribute to visibility 

impairment in Arkansas’ Class I areas, with sources having a visibility impact below 0.5 

deciviews being exempt from BART. Based on these modeling considerations, Arkansas 

                                                           

17 ADEQ Operating Air Permit for the Great Lakes Chemical Corporation- Central Plant (Permit No. 1077-AOPR1). This permit can be viewed at http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/1077-

AOP-R1.pdf. 
49 

determined that the 17 units at the 12 facilities listed in Table 8 are exempt from BART (i.e., not 

subject to BART). 

Table 8. BART Eligible Facilities ADEQ Identified as Not Subject to BART

BART source 

category Facility name County Unit Description 

Fossil fuel-fired 

steam electric 

plants of more 

than 250 

MMBTU/hr heat 

input

Entergy Robert E. Ritchie Plant Phillips Unit 2 

Kraft pulp mills 

Delta Natural Kraft Jefferson Recovery Boiler 

Evergreen Packaging/International 

Paper Jefferson No. 4 Recovery Boiler 

Georgia Pacific Crossett Mill Ashley 9A Boiler 

Green Bay Packaging Conway Recovery Boiler 

Potlatch Forest Products/Clearwater 

Paper Corporation Cypress Bend Mill Desha Power Boiler 

Petroleum 

refineries Lion Oil Company Union No. 7 Catalyst Generator 

Sulfur recovery 

plants Albermarle Corporation South Plant Columbia Tail Gas Incinerator 

Sintering plants Big River Industries- Arkalite Crittenden Kiln A 

Chemical 

process plants 

Albermarle Corporation South Plant Columbia 

No. 1 Boiler 

No. 2 Boiler 

Future Fuels/Eastman Chemical 

Company Independence 3 Coal Boilers 

El Dorado Chemical Company Union 

West Nitric Acid 

Plant

East Nitric Acid 

Plant

Nitric Acid 

Concentrator
50 

EPA Findings: 

ADEQ provided screening modeling results in Appendix 9.2B of the RH SIP for all 

sources identified in the RH SIP as BART-eligible sources, as well as for Boilers SN-301A and 

SN-302A at the Great Lakes Chemical plant (which we find to be not BART eligible), the No. 1 

and No. 2 Power Boilers at International Paper/Evergreen Packaging (which we also find to be 

not BART eligible), and the 6A and 9A Boilers at the Georgia-Pacific Crossett Mill (as discussed 

above). Our evaluation of these results showed that four facilities that ADEQ did not identify as 

subject to BART had modeled visibility impacts that exceed the 0.5 dv contribution threshold 

used by ADEQ to determine what sources are subject to BART. Our evaluation to determine 

whether these sources are subject-to-BART or not is discussed below: 

• The No. 1 and No. 2 Power Boilers at International Paper (Evergreen) and Boilers SN301A and SN-302A at Great Lakes Chemical were determined to be not BART-eligible 

by ADEQ, as discussed above. We propose to approve ADEQ’s identification of these 

two sources as not BART-eligible, since they were in operation prior to 1962, and 

therefore not subject-to-BART. 

• As discussed in section III.F.1. of this TSD, the original meteorological databases 

generated by CENRAP did not include observations as EPA guidance recommends. 

Therefore, in their evaluation to determine if a source exceeds the 0.5 dv contribution 

threshold at nearby Class I areas, states used the 1st high values (i.e., maximum value) of 

modeled visibility impacts instead of the 8th high values (i.e., 98th percentile value). The 

use of the 1st high modeled values was agreed to by EPA, representatives of the Federal 

Land Managers, and CENRAP stakeholders. ADEQ’s modeling shows that Future 

Fuels/Eastman Chemical has a modeled visibility impact of 0.711 dv at Hercules-Glade. 

Further examination of the modeling results reveals that only one day of the three years 

modeled exceeds the 0.5 dv contribution threshold value at any Class I area. Since only 

one day is projected above the threshold, we believe it is very unlikely that a refined 

modeling approach using updated meteorological data, which would allow for the use of 

the 98th percentile modeled visibility impact rather than the maximum impact, would 

show modeled impacts above the threshold. Therefore, we are proposing that this facility 

is not subject-to-BART. 

• The visibility modeling provided in Appendix 9.2B of the Arkansas RH SIP shows that 

the 9A Boiler of the Georgia-Pacific Crossett Mill has visibility impacts exceeding the 

0.5 dv contribution threshold, with a visibility impact above 1 dv at Caney Creek and 

Hercules-Glade. EPA also reviewed ADEQ’s revised modeling for this source, which 

looked at the visibility impacts of both the 6A and 9A Boilers at the Georgia-Pacific 
51 

Crossett Mill. Using updated emission rates, ADEQ’s revised modeling showed 

projected visibility impacts of the two boilers combined below the 0.5 dv threshold. The 

revised emission rates were based on stack test results and assumptions based on worst 

case monthly fuel usage, from the perspective of total emissions. However, from the data 

provided, it is unclear if the modeled emissions are representative of the actual maximum 

24 hour emissions from the highest emitting day over the modeled period. There is no 

supporting technical analysis discussing the assumptions made in the revised emission 

estimates and explaining how stack test data was used to estimate maximum emissions 

nor is fuel usage information provided for the modeled period. We are proposing to 

disapprove ADEQ’s determination that the Georgia Pacific Crossett Mill’s 6A and 9A 

Boilers are not subject-to-BART because ADEQ has not modeled the visibility impact of 

the 6A and 9A Boilers using acceptable estimates of maximum 24 hour emissions, and as 

a result we do not know if the boilers have a combined visibility impact below the 0.5 dv 

contribution threshold or not. Based on the permit allowables and available information, 

the two boilers are subject to BART and require a full BART analysis. 

 We agree that ADEQ’s exemption modeling demonstrates that 11 of the 12 facilities 

identified by ADEQ as exempt from BART each have visibility impacts below the 0.5 dv 

threshold for significant contribution to visibility impairment. We disagree with ADEQ’s 

determination that the Georgia-Pacific Crossett Mill’s 6A and 9A Boilers are not subject to 

BART and find that, based on the available information, these boilers are subject to BART. 

F.2. BART Five Factor Determination: 40 CFR 51.308(e)(1)(ii)(A) 

 For the sources that were not exempt from the BART requirements via dispersion 

modeling analyses, ADEQ must make a determination of BART for each BART-eligible source 

in Arkansas that emits any air pollutant which may reasonably be anticipated to cause or 

contribute to any impairment of visibility in any mandatory Class I Federal area. All such 

sources are subject to BART. The determination of BART must be based on an analysis of the 

best system of continuous emission control technology available and associated emission 

reductions achievable for each BART-eligible source that is subject to BART within the State. In 

this analysis, Arkansas must take into consideration the technology available, the costs of 

compliance, the energy and non-air quality environmental impacts of compliance, any pollution 

control equipment in use at the source, the remaining useful life of the source, and the degree of 

improvement in visibility which may reasonably be anticipated to result from the use of such 

technology. 
52 

State Submittal: 

 Table 9, adapted from Table 9.2 of the Arkansas RH SIP, lists all of the sources 

determined by ADEQ to be subject to BART. The SO2, NOX and PM10 BART determinations 

performed by ADEQ for these facilities are evaluated in Sections III.F.2.1 – 2.6, below. 

Table 9. Sources in Arkansas required to install BART 

Facility Name BART

Emission Units Source Category Pollutants Evaluated

Arkansas Electric Cooperative 

Corporation Carl E. Bailey 

Generating Station 

Unit 1 fossil fuel-fired 

steam electric 

plants 

SO2

NOx 

PM10

Arkansas Electric Cooperative 

Corporation John L. McClellan 

Generating Station 

Unit 1 fossil fuel-fired 

steam electric 

plants 

SO2

NOx 

PM10

American Electric Power Flint Creek 

Power Plant 

Boiler No. 1 fossil fuel-fired 

steam electric 

plants 

SO2

NOx 

PM10

Entergy Lake Catherine Plant Unit 4 fossil fuel-fired 

steam electric 

plants 

SO2

NOx 

PM10

Entergy White Bluff Plant Units 1, 2, and 

Auxiliary Boiler 

fossil fuel-fired 

steam electric 

plants 

SO2

NOx 

PM10

Domtar Ashdown Mill Boilers No. 1 and 

2 

kraft pulp mill SO2

NOx 

PM10

EPA Findings: 

We are proposing to approve ADEQ’s identification of subject to BART sources, with 

the exception of the 6A and 9A Boilers at the Georgia-Pacific Crossett Mill. As discussed 

above, we are proposing to disapprove ADEQ’s determination that the Georgia-Pacific Crossett 
53 

Mill’s 6A and 9A Boilers are not subject to BART and find that, based on the available 

information, these boilers are subject to BART and require a full BART analysis. 

 ADEQ made BART determinations for those sources it identified as subject to BART. 

We have found several problems in ADEQ’s BART determinations, which lead us to propose 

disapproval of some of ADEQ’s BART determinations. We discuss these problems in detail in 

the individual BART determination sections, and we summarize some general issues in the 

paragraphs that follow. 

 For some sources, ADEQ did not adequately consider whether retrofit controls should be 

required based on a flawed analysis of the source’s potential visibility impacts. ADEQ assumed 

that if pre-control modeling18 conducted on the basis of a single pollutant showed that the 

source’s emissions of the pollutant in question did not “contribute” to visibility impairment, then 

further BART analysis for that pollutant was unnecessary. This approach is unacceptable. Due 

to the nonlinear nature and complexity of atmospheric chemistry and chemical transformation 

among pollutants, ideally all relevant pollutants should be modeled together to predict the total 

visibility impact at each Class I area receptor.19 At a minimum, NOx and SO2 emissions should 

be modeled together to determine the visibility impacts attributable to these pollutants when 

evaluating controls and combinations of controls in determining BART for a source. Predicting 

the impacts of PM on visibility is relatively straight-forward, unlike predicting the impacts of 

SO2 and NOx. Using CALPUFF on a pollutant specific basis to model only the impact of PM 

emissions on visibility is an acceptable approach to determine whether a source should be subject 

to review for PM controls, or alternatively, that the source is not subject to BART for PM. 

ADEQ applied a threshold of 0.5 dv for determining whether a source “contributes” to visibility 

impairment on a per-pollutant basis. As discussed above, the State selected a threshold of 0.5 dv 

for the initial screening modeling that included all pollutants. Clearly, a lower threshold value is 

needed in evaluating pollutant-specific modeling for sources that emit more than one visibility 

impairing pollutant. Furthermore, this approach is only acceptable for PM-specific modeling. 

We note that a State may establish de minimis levels of emissions (applicable on a plant-wide 

basis) of visibility impairing pollutants to exclude some sources from further evaluation when 

the emissions are so minimal that they are unlikely to contribute to regional haze.20

                                                           

18 Throughout this document, any reference to “ADEQ modeling” refers to modeling performed or reviewed by 

ADEQ. 

19 Memo from Joseph Paisie (Geographic Strategies Group, OAQPS) to Kay Prince (Branch Chief EPA Region 4) 

on Regional Haze Regulations and Guidelines for Best Available Retrofit Technology (BART) Determinations, July 

19, 2006    20 “...States may choose to identify de minimis levels of pollutants at BART-eligible sources (but are not required to 

do so). De minimis values should be identified with the purpose of excluding only those emissions so minimal that 

they are unlikely to contribute to regional haze. Any de minimis values that you adopt must not be higher than the 

PSD applicability levels: 40 tons/yr for SO2 and NOX and 15 tons/yr for PM10. These de minimis levels may only 

be applied on a plant-wide basis.” 40 CFR Appendix Y to Part 51 
54 

 For some BART determinations, ADEQ did not properly determine BART, but instead 

concluded that the presumptive limits in the BART Guidelines could be adopted in place of a 

careful source-specific analysis of the appropriate level of controls. As noted above, EPA issued 

BART Guidelines in 2005 that address the BART determination process by laying out a step by 

step process for taking into consideration the factors relevant to a BART determination. In that 

rulemaking, EPA also established presumptive BART limits for certain electric generating units 

(EGUs) located at power plants 750 MW or greater in size based variously on the size of the 

unit, the type of unit, the type of fuel used, and the presence or absence of controls.21 Having 

identified controls that the Agency considered to be generally cost-effective across all affected 

units, the EPA took into account the substantial degree of visibility improvement anticipated to 

result from the use of such controls on these EGUs and concluded that such BART-eligible 

sources should at least meet the presumptive limits. The presumptive limits accordingly are the 

starting point in a BART determination for these units -- unless the State determines that the 

general assumptions underlying EPA’s analysis are not applicable in a particular case. EPA did 

not provide that States could avoid a source-specific BART determination by adopting the 

presumptive limits. In fact, nothing on the record would support the conclusion that the 

presumptive limits represent the “best available retrofit controls” for all EGUs at these large 

power plants. EPA did not address the question of whether in specific cases more stringent 

controls would be called for but rather simply concluded that it could not reach a generalized 

conclusion as to the appropriateness of more stringent controls for categories of EGUs. As a 

result, the BART Rule does not establishing a “safe harbor” from more stringent regulation 

under the BART provisions. We have consistently informed ADEQ in comments to its draft SIP 

and in conversations that foregoing a BART analysis is not acceptable. 

 For the BART determinations for which ADEQ did perform a full BART analysis that 

considered the statutory factors under section 51.308(e)(1)(ii)(A), we are proposing to find that 

ADEQ did not adequately consider one or more of the factors it is required to consider in 

determining whether retrofit controls should be required. 

 For more details, please see our evaluation of the BART determination for each subject to 

BART unit, below. 

F.2.1. AECC Bailey Unit 1 and AECC McClellan Unit 1 BART Determinations 

 The AECC Bailey Unit 1 and the AECC McClellan Unit 1 are BART-eligible sources. 

The AECC Bailey Unit 1 is a boiler with a gross output of 122 MW and a maximum heat input 

rate of 1350 MMBtu/hr, and is currently permitted to burn both natural gas and fuel oil. The fuel 

                                                           

21 70 FR at 39131-39136. 
55 

oil burned at the plant is subject to an operating air permit sulfur content limit of 2.3% by weight. 

The AECC McClellan Unit 1 is a boiler with a gross output of 134 MW and a maximum heat 

input rate of 1436 MMBtu/hr, and is currently permitted to burn both natural gas and fuel oil. 

The fuel oil burned at the plant is subject to an operating air permit sulfur content limit of 2.8% 

by weight. 

State Submittal Regarding SO2 BART for both sources: Appendix 9.3A 

AECC performed a BART five factor analysis for SO2. A summary of this analysis is presented 

below: 

Step 1- Identify All Available Retrofit Control Technologies: AECC identified use of fuel oil 

with 1% sulfur content and installation of a scrubber as the only two control options available for 

SO2 BART for AECC Bailey Unit 1 and McClellan Unit 1.

Step 2- Eliminate Technically Infeasible Options: AECC found that neither of the two control 

options is considered technically infeasible for the two units in question. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: AECC determined 

that a scrubber would have a control effectiveness of 95%, whereas use of 1% sulfur fuel oil 

would have 55% control effectiveness at Bailey Unit 1 and 65% control effectiveness at 

McClellan Unit 1. 

Step 4- Evaluate Impacts and Document the Results: AECC considered four factors in this step. 

These factors are the costs of compliance, energy impacts, non-air quality environmental 

impacts, and remaining useful life. 

 

• Costs of Compliance: Using the Integrated Environmental Control (IEC) cost model 

provided by the Electric Power Research Institute (EPRI), AECC determined that 

installation of a scrubber would result in an annualized cost of $8,106,900 and a costeffectiveness of $2,108,25/ ton SO2 removed at Bailey Unit 1, and an annualized cost of 

$8,563,940 and a cost-effectiveness of $1,658.32/ ton SO2 removed at McClellan Unit 1. 

ADEQ also determined that use of 1% sulfur fuel oil would result in an annualized cost 

of $59,524 and a cost-effectiveness of $54.90/ ton SO2 removed at Bailey Unit 1, and an 

annualized cost of $238,095 and a cost-effectiveness of $158.60/ ton SO2 removed at 

McClellan Unit 1. AECC determined that combustion of 1% sulfur fuel oil is much more 

cost-effective than installing and operating scrubbers. 

• Energy Impacts: AECC determined that installation and operation of a scrubber would 

result in an energy consumption of 1.688 MWH at a cost of $55/MWH at Bailey Unit 1, 
56 

and an energy consumption of 1.894 MWH at a cost of $55/MWH at McClellan Unit 1. 

AECC determined there are no energy impacts from using lower-sulfur fuel oil. 

• Non-Air Environmental Impacts: AECC determined SO2 scrubbers would consume 119 

gallons per minute (gpm) of water and result in 12,427 lb/hr of sludge needing proper 

disposal at Bailey Unit 1, and would consume 133 gpm of water and result in 16,750 

lb/hr of sludge at McClellan Unit 1. AECC determined use of 1% sulfur fuel oil has no 

non-air quality environmental impacts. 

• Remaining Useful Life: AECC stated that AECC does not intend to shut down either of 

these plants in the near future. However, any requirement to install and operate a control 

with a high capital cost may cause the retirement of these units. 

 Based on the analysis in Steps 1-4, AECC determined, and ADEQ agreed that SO2 BART 

for the AECC Bailey Unit 1 and McClellan Unit 1 is use of 1% sulfur fuel oil. 

Step 5- Evaluate Visibility Impacts: After making this BART determination, ADEQ evaluated 

the visibility impacts of use of 1% sulfur fuel oil. ADEQ and AECC determined use of 1% 

sulfur fuel oil will result in a maximum impact of 1.042 ∆dv at Hercules Glade, 1.01 ∆dv at 

Caney Creek, and 0.487 ∆dv at Upper Buffalo. This corresponds to an improvement in visibility 

of 34.6% at Hercules Glade, 53.98% at Caney Creek, and 59.28% at Upper Buffalo. 

EPA Findings Regarding SO2 BART Determinations for both sources: Below is our 

evaluation of AECC’s SO2 BART analysis. For the steps that we did not explicitly address in 

our evaluation, we had no particular concerns with how AECC addressed these in the BART 

analysis. 

 We find that AECC did not adequately consider the five statutory factors in determining 

SO2 BART for Bailey Unit 1 and McClellan Unit 1. Specifically, we propose that AECC did not 

properly “take into consideration the technology available” (Step 1) by failing to consider the 

maximum level of control each control option is capable of achieving. In considering use of fuel 

oil with low sulfur content as a control option, ADEQ identified and considered only 1% sulfur 

fuel oil in the BART analysis. The BART Guidelines (Appendix Y to Part 41) provide that in 

identifying all available retrofit control technologies, the most stringent option and a reasonable 

set of options for analysis that reflects a comprehensive list of available technologies must be 

considered. All permutations of available control levels that exist for a given technology need 

not be listed, as the list is complete if it includes the maximum level of control each technology 

is capable of achieving. The requirement to consider the most stringent level of control when 

making BART determinations is also found in the RH Rule (64 FR 35740), which provides that 

in establishing source specific BART emission limits, the State should identify and consider in 
57 

the BART analysis the maximum level of emission reduction that has been achieved in other 

recent retrofits at existing sources in the source category. The visibility regulations define 

BART as “an emission limitation based on the degree of reduction achievable through the 

application of the best system of continuous emission reduction.” Since recent retrofits at 

existing sources provide a good indication of the current “best system” for controlling emissions, 

these controls must be considered in the BART analysis. Furthermore, the BART Rule points 

out that a large portion of BART eligible oil units currently have a 1% or lower sulfur content 

fuel oil restriction and that states should accordingly evaluate a one percent sulfur content 

limitation as a starting point in making BART determinations for oil-fired EGUs subject to 

BART. In considering use of fuel oil with low sulfur content as a control option in the BART 

analysis, AECC did not identify and consider the maximum level of control achievable from the 

use of low sulfur fuel oil, and thus the BART analysis is flawed. 

 Sulfur content in fuel oil currently can be found in industry to be 0.5% by weight or less. 

ADEQ and AECC should have considered the use of fuel oil with 0.5% sulfur content or less in 

the BART analysis for these two sources. We are aware of several fossil-fuel fired steam electric 

plants throughout the country that are currently permitted to burn fuel oil with a sulfur content of 

0.5% or less by weight. Connecticut limits the sulfur content of fuel oil to a maximum 0.3%22

and New York requires facilities to comply with the use of fuel oil with varying sulfur content 

limits, with facilities in New York City being required to use fuel oil with a maximum 0.3% 

sulfur content.23 Lowering the sulfur content in fuel oil is also a part of the long-term strategy 

recommended by the Mid-Atlantic/Northeast Visibility Union (MANE-VU) states to reduce and 

prevent regional haze.24 The MANE-VU states in the inner zone (New Jersey, New York, 

Delaware, and Pennsylvania) plan to reduce the sulfur content of No. 6 residual fuel oil to 0.3-

0.5% sulfur by weight by no later than 2012.25 Therefore, the use of fuel oil with a 0.5% sulfur 

content or lower is technically feasible and either ADEQ or AECC should have evaluated its cost 

effectiveness for the AECC Bailey Unit 1 and the AECC McClellan Unit 1. In addition, an 

operating air permit restriction to use only natural gas as the fuel source for the two units would 

have also been acceptable. As part of the BART analysis, ADEQ and/or AECC must perform a 

cost analysis in which all cost estimates are properly documented and must evaluate the visibility 

                                                           

22 Connecticut Department of Environmental Protection (DEP). “22a-174-19a: Control of Sulfur Dioxide Emissions 

from Power Plants and Other Large Stationary Sources of Air Pollution,” Regulations of Connecticut State 

Agencies, Title 22a: Abatement of Air Pollution, December 28, 2000. 

http://www.dep.state.ct.us/air2/regs/mainregs/sec19a.pdf. 23 New York State Department of Environmental Conservation (DEC). “Subpart 225-1: Fuel Composition and UseSulfur Limitations,” Environmental Conservation Rules and Regulations, May 8, 2005. 

http://www.dec.state.ny.us/website/regs/subpart225_1.html. 24 MANE-VU is an RPO that includes the following states: Maine, New Hampshire, Vermont, Massachusetts, 

Rhode Island, Connecticut, New York, New Jersey, Pennsylvania, Maryland, Delaware, and also the District of 

Columbia. 

25 See 76 FR 27973. 
58 

impacts of all technically feasible control options considered before making a BART 

determination. 

 In Step 4 of the BART analysis, AECC considered the costs of compliance of the two 

control options. AECC found that the annualized cost of installing scrubbers at the AECC 

Bailey Unit 1 and the AECC McClellan Unit 1 is $8,106,900 and $8,563,940, respectively. This 

corresponds to a cost-effectiveness of $2,108/ SO2 ton removed and $1,658/ SO2 ton removed. 

AECC compared these values to the cost-effectiveness of using 1% sulfur content fuel oil at the 

AECC Bailey Unit 1 and the AECC McClellan Unit 1 ($54.90/ SO2 ton removed and $158.60/ 

SO2 ton removed, respectively). In Step 5 of the BART analysis, AECC and ADEQ evaluated 

the visibility impacts of control options. However, AECC stated that since AECC and ADEQ 

agreed that the most cost-effective control would be to use fuel oil with a lower sulfur content, 

ADEQ modeled only the visibility impacts of use of fuel oil with 1% sulfur content. We find 

that based on AECC’s cost analysis, installation and use of scrubbers to control SO2 emissions at 

the Bailey and McClellan units is well within the cost-effectiveness range. Therefore, ADEQ 

and AECC should have modeled the visibility impact of all options considered in the BART 

analysis, and compared the visibility improvements resulting from use of scrubber systems with 

that resulting from use of 1% sulfur content fuel oil. Only after evaluating the visibility impact 

of all available and technically feasible control options can the State properly make a 

determination of which control option is BART. 

 Therefore, for the reasons expressed above, we propose to disapprove the SO2 BART 

determinations for the AECC Bailey Unit 1 and the AECC McClellan Unit 1. 

State Submittal Regarding NOx and PM BART for both sources: Appendix 9.3A 

 Regarding BART for NOx and PM, AECC conducted pollutant specific pre-control 

CALFUFF26 modeling for the AECC Bailey Unit 1 and the AECC McClellan Unit 1. AECC 

stated that the results of the NOx modeling shows that NOx does not cause or contribute to 

visibility impacts.27 Based on this, AECC determined it is not necessary to make a BART 

determination for NOx for the AECC Bailey Unit 1 and AECC McClellan Unit 1. 

                                                           

26 The CALPUFF modeling system consists of a meteorological data pre-processor (CALMET), an air dispersion 

model (CALPUFF), and post-processor programs (POSTUTIL, CALSUM, CALPOST). The CALPUFF modeling 

system is the recommended model for conducting BART visibility analysis. 

27 Arkansas Electric Cooperative Corporation Best Available Retrofit Technology Engineering Analysis prepared by 

Stephen Cain, October 20, 2006. 
59 

EPA Findings Regarding NOx and PM BART Determinations for both sources: 

 Regarding BART for NOx and PM, ADEQ conducted pollutant specific pre-control 

CALFUFF28 modeling for the AECC Bailey Unit 1 and the AECC McClellan Unit 1. AECC 

stated that the results of the NOx modeling show that NOx does not cause or contribute to 

visibility impacts.29 Based on this, AECC determined and ADEQ agreed it was not necessary to 

make a BART determination for NOx for either the AECC Bailey Unit 1 or AECC McClellan 

Unit 1. However, the ADEQ’s modeling results presented indicate that the predicted visibility 

impacts from NOx are as high as 0.347 dv at Mingo due to emissions from the AECC Bailey 

Unit 1, and 0.421 dv at Caney Creek due to emissions from the AECC McClellan Unit 1. As 

stated above, NOx and SO2 emissions should be modeled together due to the nonlinear nature 

and complexity of atmospheric chemistry and chemical transformation among pollutants. 

Evaluation of the screening modeling results for these units reveals that on some of the most 

impacted days, NOx is a significant contributor to the visibility impairment due to these units. 

Post-control modeling performed by ADEQ, applying the use of 1% sulfur fuel, show that these 

units would continue to cause or contribute to visibility impairment at a number of Class I areas, 

with NOx emissions responsible for over 50% of the impairment on some days under this control 

scenario. In light of the relatively high impacts due to NOx, a combination of NOx and SO2

controls may prove to be cost-effective and provide for substantial visibility improvement and 

should therefore be evaluated. 

 For PM BART, AECC decided, and ADEQ agreed, that PM does not cause visibility 

impacts because the PM emissions are less than those of NOx at these units. This conclusion is 

not supported in the record by PM visibility modeling results, additional technical analysis, or 

reference to a permit limit for PM that restricts emissions below a level that will impact 

visibility. Neither ADEQ nor AECC have completed a BART analysis that considers the 

statutory factors under section 51.308(e)(1)(ii)(A) that states are required to consider in 

determining what level of control is BART for a source for NOx and PM, or fully demonstrated 

that these units have sufficient pollution controls in place for these pollutants such that additional 

controls would likely achieve very low emissions reductions, have minimal visibility benefit, and 

not be cost-effective. Therefore, we are proposing to disapprove the NOx and PM BART 

determination for these two units. 

                                                           

28 The CALPUFF modeling system consists of a meteorological data pre-processor (CALMET), an air dispersion 

model (CALPUFF), and post-processor programs (POSTUTIL, CALSUM, CALPOST). The CALPUFF modeling 

system is the recommended model for conducting BART visibility analysis. 

29 Arkansas Electric Cooperative Corporation Best Available Retrofit Technology Engineering Analysis prepared by 

Stephen Cain, October 20, 2006. 
60 

F.2.2. AEP Flint Creek No. 1 Boiler BART Determination 

 The AEP Flint Creek No. 1 Boiler is a BART-eligible source. The unit has a gross output 

of 558 MW and a maximum heat input rate of 6324 MMBtu/hr, and burns primarily low sulfur 

western coal, but can also combust fuel oil and tire derived fuels (TDF). Fuel oil firing is only 

allowed during startup and shutdown of the boiler, startup and shutdown of the pulverizer mills, 

for flame stabilization when the coal is frozen, for fuel oil tank maintenance, to prevent boiler 

tube failure in extreme cold weather, and when the unit is offline for maintenance. 

State Submittal Regarding PM: Appendix 9.3A 

 Regarding BART for PM, AEP conducted pre-control CALFUFF modeling for the AEP 

Flint Creek No. 1 Boiler showing that PM10 and PM2.5 emissions from the source have minimal 

visibility impacts at each Class I area within 300 km. Based on this, AEP decided and ADEQ 

agreed that the existing PM emission limit in the operating air permit, which is achievable 

through the use of the existing electrostatic precipitator (ESP), is BART for PM for AEP Flint 

Creek No. 1 Boiler. 

EPA Findings Regarding PM BART Determination: 

 We reviewed the CALPUFF visibility modeling submitted by ADEQ for AEP Flint 

Creek No. 1 Boiler, and agree that PM10 and PM2.5 emissions from the source have minimal 

visibility impacts at each Class I area within 300 km. As explained in section IV.D.3 of this 

proposed rulemaking, using CALPUFF on a pollutant specific basis to model only the impact of 

PM emissions on visibility is an acceptable approach to determine whether a source should be 

subject to review for PM controls. In the case of the AEP Flint Creek No. 1 Boiler, we have 

found that the visibility impact due to PM emissions alone is so minimal such that the installation 

of any additional PM controls on the unit would likely achieve very low emissions reductions, 

have minimal visibility benefit, and not be cost-effective. Therefore, we are proposing to 

approve ADEQ’s determination that PM BART for AEP Flint Creek No. 1 Boiler is the existing 

PM emission limit. The federally enforceable operating air permit for the source sets the PM 

emission limit for the unit at 0.1 lb/MMBtu.30 

 

State Submittal Regarding SO2 and NOx: Appendix 9.3A 

 Regarding BART for SO2 and NOx, neither AEP nor ADEQ performed a BART analysis 

that considered the statutory factors states are required to consider in determining what retrofit 

                                                           

30 ADEQ Operating Air Permit for AEP- Flint Creek Power Plan (Permit No. 0276-AOP-R5). This permit can be 

viewed at http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/0276-AOP-R5.pdf. 
61 

controls are BART for the AEP Flint Creek No. 1 Boiler. Instead, AEP determined and ADEQ 

agreed that BART for SO2 is the presumptive limit of 0.15 lb/MMBtu and that BART for NOx is 

the presumptive limit of 0.23 lb/MMBtu for AEP Flint Creek No. 1 Boiler.31 

EPA Findings Regarding SO2 and NOx BART Determinations: 

 We are aware that the AEP Flint Creek Power Plant has a 558 MW generating capacity, 

and is therefore not required to follow the BART Guidelines in making BART determinations for 

the No. 1 Boiler. However, AEP and/or the State must still conduct a BART analysis as 

specified in 40 CFR 51.308(e)(1)(ii)(A), which provides that: 

The determination of BART must be based on an analysis of the best system of 

continuous emission control technology available and associated emission 

reductions achievable for each BART-eligible source that is subject to BART 

within the State. In this analysis, the State must take into consideration the 

technology available, the costs of compliance, the energy and nonair quality 

environmental impacts of compliance, any pollution control equipment in use 

at the source, the remaining useful life of the source, and the degree of improvement 

 in visibility which may reasonably be anticipated to result from the use of such 

technology. 

 Therefore, we are proposing to disapprove ADEQ’s BART finding since neither AEP nor 

ADEQ conducted a BART analysis considering the best system of controls for BART for SO2

and NOx for AEP Flint Creek No. 1 Boiler. ADEQ and/or AEP should have performed a BART 

analysis for SO2 and NOx. Controls achieving more than the SO2 and NOx presumptive limits 

are available and should be considered in the BART analysis, especially considering the 

magnitude of the visibility impact of the AEP Flint Creek No. 1 Boiler on the Class I areas 

within 300 km.32 For instance, SCR controls are routinely designed and have routinely achieved 

a NOx control efficiency of 90% and a NOx emission rate as low as 0.04 lb/MMBtu,33 based on 

a 30-day rolling average. Furthermore, SCR system designers analyzed EPA’s Clean Air 

Market’s CEMS data to determine the NOx levels that are currently being achieved by over 100 

                                                           

31 The “presumptive limits” are the rebuttable specific limits established in the BART Rule for SO2 and NOx for 

certain EGUs based on fuel type, unit size, cost effectiveness, and the presence or absence of pre-existing controls. 32 ADEQ’s CALPUFF visibility modeling indicates the highest modeled visibility impact of AEP Flint Creek No. 1 

Boiler on nearby Class I areas is: 3.970 ∆dv at Caney Creek; 3.781 ∆dv at Upper Buffalo; 3.983 ∆dv at Hercules 

Glade; 2.596 ∆dv at Mingo; 1.420 ∆dv at Sipsey. ADEQ’s post-control visibility modeling shows that the State’s 

BART determinations would result in the source still causing visibility impairment at Caney Creek (1.573 ∆dv), 

Upper Buffalo (2.089 ∆dv), and Hercules Glade (1.541 ∆dv), and contributing to visibility impairment at Mingo 

(0.927) (Appendix 9.2B of the Arkansas Regional Haze SIP). 

33 See, e.g., William J. Gretta and others, The SCR Retrofit Design for the Seminole Generating Station, PowerGen, 

2008, Hitachi SCR at Seminole Electric Delivers 0.04 lb/MMBtu NOx (Preliminary Results), FGD and DeNOx 

Newsletter, December 2009, No. 380, and NOx CEMS data reported to Clean Air Markets. 
62 

SCR-equipped coal-fired boilers, and found that 25 of these units are achieving NOx emissions 

less than 0.05 lb/MMBtu on an hourly average basis.34 Flue gas desulfurization (FGD) units 

(i.e., wet and dry scrubbers), are a type of post-combustion control for SO2 emissions. In a 

report for the National Lime Association, Sargent & Lundy stated that vendors guarantee SO2

reduction efficiencies of up to 95%, or as low as 0.06 lb/MMBtu SO2 for dry scrubbers.35 The 

Longleaf Energy Station in Georgia has two 600 MW boilers that burn coal and are equipped 

with a dry scrubber capable of achieving SO2 emissions of 0.065 lb/MMBtu on a 30-day rolling 

average when the uncontrolled SO2 emission rate is less than or equal to 1 lb/MMBtu.36 The 

Desert Rock Energy Company, a 1500 MW coal fired power plant in New Mexico, is equipped 

with a wet scrubber and has an SO2 emission limit of 0.060 lb/MMBtu, averaged over a 24-hour 

period.37 We note that a 24-hour average is much more stringent than a 30-day rolling average. 

 Therefore, for the reasons expressed above, we are proposing to disapprove ADEQ’s 

determination of SO2 and NOx BART for the AEP Flint Creek No. 1 Boiler. 

F.2.3. Entergy Lake Catherine Unit 4 BART Determination 

 The Entergy Lake Catherine Unit 4 is a BART-eligible source. Unit 4 is a combustion 

engineering tilting tangential fired boiler powering a 552 MW generator. The unit has a 

maximum heat input rate of 5850 MMBtu/hr and burns primarily natural gas with No. 6 fuel oil 

as the secondary fuel. There is currently no emission control equipment connected to the boiler. 

Class I areas within 300 km of the facility include Caney Creek, Upper Buffalo, and Hercules 

Glades. 

 Since Unit 4 is permitted to burn both natural gas and No. 6 fuel oil, ADEQ made BART 

determinations for both natural gas firing and fuel oil firing scenarios. The Arkansas RH SIP 

contains the CALPUFF pre-control modeling files for the natural gas firing scenario, and ADEQ 

also provided the modeling files for the fuel oil firing scenario. CALPUFF post-control 

modeling results for both gas and oil firing were also included in the Arkansas RH SIP. In the 

                                                           

34 Clay Erickson, Robert Lisauskas, and Anthony Licata, What New in SCRs, DOE’s Environmental Control 

Conference, May 16, 2006., p. 28. Available here: 

http://www.netl.doe.gov/publications/proceedings/06/ecc/pdfs/Licata.pdf; LG&E Energy, Selective Catalytic 

Reduction: From Planning to Operation, Competitive Power College, December 2005, p. 75-77. 

35 See also Sargent & Lundy, IPM Model - Revisions to Cost and Performance for APC Technologies, SDA FGD 

Cost Development Methodology, Final, August 2010, p. 1 ("It should be noted that the lowest available SO2 

emission guarantees, from the original equipment manufacturers of SDA FGD systems, are 0.06 lb/MMBtu."). 36 Georgia Environmental Protection Division, Longleaf Energy Station, Permit No. 4911-099-0033-P-01-0, April 9, 

2010. Available at: http://airpermit.dnr.state.ga.us/gaairpermits/PermitPDF.aspx?id=PDF-PI-18499. 37 U.S. EPA, Region 9, Prevention of Significant Deterioration Permit, Desert Rock Energy Company, July 31, 

2008. Available at: http://www.regulations.gov/search/Regs/home.html#docketDetail?R=EPA-R09-OAR-2007-

1110. 
63 

State’s September 27, 2011 supplemental submittal, ADEQ brought to our attention that per an 

inspection report dated July 28, 2011, Entergy Lake Catherine Unit 4 is no longer capable of 

burning fuel oil. ADEQ noted that the fuel tanks at the source have been emptied and the 

pipework necessary to burn fuel oil is in the process of being removed. ADEQ stated the source 

does maintain the ability to burn natural gas. We note that since the source has not modified its 

permit and ADEQ has not revised its RH SIP to reflect this change, we are not disregarding the 

source’s BART emission limits for fuel oil firing in this proposed rulemaking. 

State Submittal Regarding SO2 and PM BART Determinations (natural gas): Appendix 

9.3A 

 Regarding BART for SO2 and PM for the natural gas firing scenario, Entergy stated that 

most of the visibility-causing emissions from Unit 4 are due to NOx since SO2 and PM emissions 

from natural gas-fired boilers are generally very low. Therefore, for the natural gas firing 

scenario for Unit 4, Entergy made no BART determination for SO2, and determined that BART 

for PM is the existing PM emission limit in the operating air permit. ADEQ agreed with the 

Entergy’s determination. Revisions to the State’s RH Rule, Chapter 15 of APC&E Commission 

Regulation 19, which were submitted to us on August 3, 2010, state the existing PM emission 

limit as of October 15, 2007 is PM BART for the natural gas firing scenario for Entergy Lake 

Catherine Unit 4. This corresponds to an emission limit of 45 lb/hr PM.38 

EPA Findings Regarding SO2 and PM BART Determinations (natural gas): 

 We agree that SO2 and PM emissions from natural gas-fired boilers are generally very 

low, and therefore we are proposing to approve Entergy and ADEQ’s decision not to make a 

BART determination for SO2 for the natural gas firing scenario for Unit 4. Since we have found 

that the visibility impact of Unit 4 due to PM emissions alone (from natural gas firing) is so 

minimal such that the installation of any additional PM controls on the unit would likely achieve 

very low emissions reductions, have minimal visibility benefits, and not be cost-effective, we are 

also proposing to approve ADEQ’s determination that BART for PM for Unit 4 for the natural 

gas firing scenario is the existing PM emission limit as of October 15, 2007, or 45.0 lb/hr. 

State Submittal Regarding NOx BART Determination (gas & fuel oil): Appendix 9.3A 

 Entergy conducted a BART analysis to determine what retrofit controls are BART for 

Lake Catherine Unit 4. A summary of this analysis is presented below: 

                                                           

38 See ADEQ Operating Air Permit for Entergy Arkansas Inc.- Lake Catherine Plant (Permit No. 1717-AOP-R4). 

This permit can be viewed at http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/1717-AOPR4.pdf. 
64 

Step 1- Identify All Available Retrofit Control Technologies: Entergy considered a combination 

of the following NOx combustion controls for the natural gas firing scenario: boiler tuning, 

burners out of service (BOOS), induced flue gas recirculation (IFGR), overfire air (OFA), and 

low NOx burners (LNB). Entergy considered a combination of the following NOx combustion 

controls for the fuel oil firing scenario: boiler tuning, boiler modifications, BOOS, and forced 

flue gas recirculation (FFGR). Entergy did not consider post-combustion control technology in 

its analysis because it indicated its belief that the BART Guidelines exempt the source from this 

analysis. 

Step 2- Eliminate Technically Infeasible Options: Entergy found that all options identified in 

Step 1 of the analysis are technically feasible. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: Table 10 depicts the 

control effectiveness of the control options for the gas firing scenario (adapted from Table 3-1 of 

Entergy’s BART analysis for Lake Catherine Unit 4, Appendix 9.3A of the Arkansas RH SIP). 

Table 11 depicts the control effectiveness of the control options for the fuel oil firing scenario 

(adapted from Table 3-2 of Entergy’s BART analysis for Lake Catherine Unit 4, Appendix 9.3A 

of the Arkansas RH SIP). 

Table 10. Control Effectiveness of NOx Control Options for Lake Catherine Unit 4- Gas 

Firing 

Control Option Emission Rate 

(lb/MMBtu)

Control Removal 

(%)

Baseline 0.483 0%

Tune 0.386 20.0%

Tune, BOOS 0.280 42.1% 

Tune, BOOS, IFGR 0.147 69.6% 

Tune, BOOS, IFGR, OFA 0.077 84.0% 

Tune, BOOS, IFGR, OFA, LNB 0.055 88.6% 
65 

Table 11. Control Effectiveness of NOx Control Options for Lake Catherine Unit 4- Fuel 

Oil Firing 

Control Option Emission Rate 

(lb/MMBtu)

Control Removal 

(%)

Baseline 0.483 0%

Tune 0.386 20.0%

Tune, boiler mods 0.280 42.1% 

Tune, boiler mods, BOOS 0.253 47.6% 

Tune, boiler mods, BOOS, FFGR 0.219 54.6% 

Step 4- Evaluate Impacts and Document the Results: Entergy considered the costs of compliance 

in this step of the BART analysis. In evaluating the cost-effectiveness of each control scenario 

option for BART for NOx, ADEQ stated it assumed a 10% capacity factor for operation of Unit 

4. Entergy provided no documentation or detailed breakdown of the cost estimates. Table 12 

depicts the cost-effectiveness of the control options for the gas firing scenario (adapted from 

Table 5-1 of ADEQ’s BART analysis for Lake Catherine Unit 4, Appendix 9.3A of the Arkansas 

RH SIP). Table 13 depicts the cost-effectiveness of the control options for the fuel oil firing 

scenario (adapted from Table 5-2 of ADEQ’s BART analysis for Lake Catherine Unit 4, 

Appendix 9.3A of the Arkansas RH SIP). 

Table 12. Cost-Effectiveness of NOx Control Options for Lake Catherine Unit 4- Gas 

Firing 

Control Option Annualized Cost 

($/year)

Annual NOx tons 

removed 

Cost-Effectiveness 

($/ton removed)

Baseline - - -

Tune $17,016 215.2 $79

Tune, BOOS $122,956 452.8 $272 

Tune, BOOS, IFGR $397,923 748.9 $531 

Tune, BOOS, IFGR, OFA $1,537,731 904.3 $1,700 

Tune, BOOS, IFGR, OFA, LNB $3,581,027 953.2 $3,757 
66 

Table 13. Cost-Effectiveness of NOx Control Options for Lake Catherine Unit 4- Fuel Oil 

Firing 

Control Option Annualized Cost 

($/year)

Annual NOx tons 

removed 

Cost-Effectiveness 

($/ton removed)

Baseline - - -

Tune $16,000 220.0 $73

Tune, boiler mods $433,934 462.9 $937 

Tune, boiler mods, BOOS $583,386 523.5 $1,114 

Tune, boiler mods, BOOS, FFGR $1,357,123 600.1 $2,261 

Step 5- Evaluate Visibility Impacts: Entergy and ADEQ conducted post-control CALPUFF 

modeling of the visibility impacts of the NOx control options considered in the BART analysis 

assuming operation of Unit 4 at a 10% capacity factor. A summary of the visibility impact 

analysis is depicted in Table 14 for the gas firing scenario (as adapted from Table 5-1 of the 

Entergy’s BART analysis for Lake Catherine Unit 4, Appendix 9.3A of the Arkansas RH SIP) 

and in Table 15 for the fuel oil firing scenario (as adapted from Table 5-2 of the Entergy BART 

analysis for Lake Catherine Unit 4, Appendix 9.3A of the Arkansas RH SIP). 

Table 14. Visibility Impact of NOx Control Options for Lake Catherine Unit 4- Gas Firing 

Control Option Visibility Impact 

(98th percentile day, ∆dv)

Baseline 1.56

Tune 1.30

Tune, BOOS 0.99 

Tune, BOOS, IFGR 0.56 

Tune, BOOS, IFGR, OFA 0.34 

Tune, BOOS, IFGR, OFA, LNB 0.27 
67 

Table 15. Visibility Impact of NOx Control Options for Lake Catherine Unit 4- Fuel Oil 

Firing 

Control Option Visibility Impact 

(98th percentile day, ∆dv)

Baseline 3.44

Tune 3.31

Tune, boiler mods 3.14 

Tune, boiler mods, BOOS 3.03 

Tune, boiler mods, BOOS, FFGR 2.90 

 Entergy determined, and ADEQ agreed, that for a unit predicted to be dispatched 10% of 

the time, it believed that due to significant cost increases, reduced benefits, and complexities in 

the retrofits beyond BOOS and IFGR, NOx BART for Unit 4 is a combination of boiler tuning, 

BOOS, and IFGR achieving a NOx emission limit of 0.15 lb/MMBtu for the natural gas firing 

scenario and a combination of boiler tuning, boiler modifications, and BOOS, achieving a NOx 

emission limit of 0.25 lb/MMBtu for the fuel oil firing scenario. 

EPA Findings Regarding NOx BART Determination (gas & fuel oil): Below is our 

evaluation of Entergy’s NOx BART analysis. For the steps that we did not explicitly address in 

our evaluation, we had no particular concerns with how ADEQ and Entergy addressed these in 

the BART analysis. 

 Regarding Step 1 of Entergy’s NOx BART analysis for Lake Catherine Unit 4, the BART 

Guidelines and the RH Rule do not limit the consideration of possible BART control technology 

choices to only cost-effective combustion controls for these sources. Post-combustion control 

technologies are technically feasible and should be considered for oil fired and gas fired EGUs as 

part of the BART determination. As discussed above, Entergy did not consider NOx postcombustion controls, such as selective catalytic reduction (SCR) and selective non-catalytic 

reduction (SNCR), in its original BART analysis. We provided comments to ADEQ on the draft 

Arkansas RH SIP to this effect on May 1, 2007.39 In response to our comments, Arkansas 

included in its RH SIP submittal the results of a computerized model it obtained from Entergy, 

which according to the source, evaluated Unit 4’s performance and the capital and operation and 

                                                           

39 Our comments to ADEQ on this matter are documented in Appendix 9.3B of the Arkansas RH SIP. 
68 

maintenance costs associated with each identified control technology. Entergy reported that the 

results of the computerized model showed that post-combustion controls, such as SCR and 

SNCR, had a cost that would be uneconomical to install. Entergy’s results of this computerized 

model are discussed further in the paragraph below. 

 Regarding Step 4 of the BART analysis, in evaluating the costs of compliance, Entergy 

analyzed the cost-effectiveness in annualized dollars per ton of NOx removed ($/ton) of the 

control options identified in Step 1 of the BART analysis for NOx for the natural gas and fuel oil 

firing scenarios. We note there are two flaws in Entergy’s cost-analysis. Entergy provided no 

documentation or detailed breakdown of the cost estimates. The results of the computer model 

the source used to determine the cost-effectiveness of post-combustion controls also did not 

provide documentation or a detailed breakdown of the cost estimates. We have no basis to verify 

the validity of neither the cost estimates nor Entergy’s determination based on the cost estimation 

analysis for BART. The basis for cost estimates should be documented either with data supplied 

by a vendor (i.e., budget estimates or bids) or by a referenced source. This was not done in the 

BART analysis. Furthermore, Unit 4 is a peaking unit,40 and Entergy attempted to account for 

this by assuming a 10% capacity factor41 in the calculation of the metrics for tons removed and 

$/ton removed for all control options considered in Step 1 of the BART analysis. The computer 

model Entergy used to estimate the cost effectiveness of post-combustion controls, likewise 

assumed a 10% capacity factor in the calculation of the metrics for tons removed and $/ton 

removed. Given that there are no permit requirements in place that would limit the operation of 

this unit to 10% capacity, the facility can legally be operated well above the 10% capacity factor 

assumed by Entergy. Thus, any cost effectiveness analysis based on a 10% capacity factor is 

likely to significantly inflate the cost per ton of controlling this unit. In support of the 10% 

capacity utilization factor, Entergy stated that the unit has operated, on average, at a capacity of 

6.9% for the past three years. However, past use of this unit was much higher– approximately 

46% on average –over the 2001-2005 period.42 Given the variability in capacity utilization of 

this unit over the past ten years, the assumed 10% capacity utilization should be supported by an 

enforceable limit. Therefore, we are proposing to disapprove ADEQ’s NOx BART 

determination for both the natural gas and fuel oil firing scenarios for Lake Catherine Unit 4. 

                                                           

40 40 CFR 72.2 defines a peaking unit as “[a] unit that has (i) An average capacity factor of no more than 10.0 

percent during the previous three calendar years and (ii) A capacity factor of no more than 20.0 percent in each of 

those calendar years.” 

41 40 CFR 72.2 defines capacity factor as either “(1) The ratio of a unit's actual annual electric output (expressed in 

MWe/hr) to the unit's nameplate capacity (or maximum observed hourly gross load (in MWe/hr) if greater than the 

nameplate capacity) times 8760 hours; or (2) The ratio of a unit's annual heat input (in million British thermal units 

or equivalent units of measure) to the unit's maximum rated hourly heat input rate (in million British thermal units 

per hour or equivalent units of measure) times 8,760 hours. 

42 Table 2-1 of the “BART Analysis for Lake Catherine Plant- Unit 4,” prepared by Robert Paine, December 2006 

notes that Unit 4 was operated 6,988 hours in 2001 (79.7% utilization); 5,651 hours in 2002 (64.5% utilization); 

3,972 hours in 2003 (45.3% utilization); 1,534 hours in 2004 (17.5% utilization); and 2,059 hours in 2005 (23.5% 

utilization).
69 

 We propose to find that ADEQ and Entergy did not properly follow the requirements of 

section 51.308(e)(1)(ii)(A) in determining NOx BART for the natural gas and fuel oil firing 

scenarios for Entergy Lake Catherine Unit 4. Specifically, we propose that ADEQ and Entergy 

did not properly take into consideration “the technology available” in Step 1 of the BART 

analysis and “the costs of compliance” in Step 4 of the BART analysis. We are proposing to 

disapprove ADEQ’s determination that BART for NOx for Unit 4 is a combination of boiler 

tuning, BOOS, and IFGR achieving a NOx emission limit of 0.15 lb/MMBtu for the natural gas 

firing scenario and a combination of boiler tuning, boiler modifications, and BOOS, achieving a 

NOx emission limit of 0.25 lb/MMBtu for the fuel oil firing scenario. 

State Submittal Regarding SO2 BART Determination (fuel oil): Appendix 9.3A 

 Entergy performed a BART analysis to determine what level of control is BART for SO2

for the fuel oil firing scenario for Entergy Lake Catherine Unit 4. A summary of this analysis is 

presented below: 

Step 1- Identify All Available Retrofit Control Technologies: Entergy identified only one 

available control option in Step 1 of the BART analysis- use of fuel oil with low sulfur content. 

ADEQ agreed with the source’s decision. Entergy only considered the use of fuel oil with 1%, 

0.5%, and 0.2% sulfur content by weight. We note use of fuel oil with 1% sulfur content is the 

base case, as Entergy stated the source’s current Title V permit limits the sulfur content of fuel 

oil used to 1%. Entergy did not consider any post-combustion SO2 controls in the BART 

analysis, even though post-combustion control technologies, such as wet and dry scrubbers, are 

currently being used by comparable facilities to control SO2 emissions. 

Step 2- Eliminate Technically Infeasible Options: Entergy did not indicate any of the control 

options identified under Step 1 of the analysis are technically infeasible. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: Entergy used AP-42 

factors for 1%, 0.5%, and 0.2% sulfur residual oil to determine the amount of sulfur dioxide 

emissions that would be eliminated by use of low sulfur fuel oil. Based on 10% utilization of the 

unit, use of 1% sulfur fuel oil (baseline conditions) results in SO2 emissions of 2,311 tpy; use of 

0.5% sulfur fuel oil would result in 1,059 tpy SO2 removed from the baseline; and use of 0.2% 

sulfur fuel oil would result in 1,802 tpy SO2 removed from the baseline. 

Step 4- Evaluate Impacts and Document the Results: Entergy considered the costs of compliance 

in this step of the BART analysis. In evaluating the cost-effectiveness of each control scenario 

option for BART for SO2, Entergy stated it assumed a 10% capacity factor for operation of Unit 

4. We note Entergy provided no documentation or detailed breakdown of the costs estimates for 
70 

use of low sulfur fuel oil for Unit 4. Table 16 depicts the cost-effectiveness of the control 

options for SO2 BART (adapted from Table 3-3 of Entergy’s BART analysis for Lake Catherine 

Unit 4, Appendix 9.3A of the Arkansas RH SIP). 

Table 16. Cost-Effectiveness of SO2 Control Options for Lake Catherine Unit 4- Fuel Oil 

Firing 

Control Option Annualized 

Cost ($/year)

Annual NOx tons 

removed 

Cost-Effectiveness 

($/ton removed)

Base Case- 1% S No. 6 fuel oil - - -

0.5% S No. 6 fuel oil $8,705,451 1,059 $8,224

0.2% S No. 6 fuel oil $30,355,134 1,802 $16,845 

Step 5- Evaluate Visibility Impacts: ADEQ and Entergy conducted post-control CALPUFF 

modeling of the visibility impacts of the SO2 control options considered in the BART analysis 

for fuel oil firing assuming operation of Unit 4 at a 10% capacity factor. A summary of the 

visibility impact analysis is depicted in Table 17 (as adapted from Table 5-3 of the ADEQ’s 

BART analysis for Lake Catherine Unit 4, Appendix 9.3A of the Arkansas RH SIP). 

Table 17. Visibility Impact of SO2 Control Options for Lake Catherine Unit 4- Fuel Oil 

Firing 

Control Option Visibility Impact 

(98th percentile day, ∆dv)

Base Case- 1% S No. 6 fuel oil 3.03

0.5% S No. 6 fuel oil 2.14

0.2% S No. 6 fuel oil 1.46 

 Entergy determined that for a unit predicted to be dispatched 10% of the time, it believed 

that due to significant cost increases and reduced benefits resulting from more stringent controls, 

BART for SO2 for the fuel oil firing scenario is an SO2 emission limit of 0.562 lb/MMBtu on a 
71 

30 day rolling average. The RH SIP provides conflicting information on whether this emission 

limit corresponds to use of 1% or 0.5% sulfur fuel oil. On September 27, 2011, ADEQ 

submitted a supplemental submittal clarifying that the 0.562 lb/MMBtu emission limit 

corresponds to use of 0.5% sulfur content fuel oil. 

EPA Findings Regarding SO2 BART Determination (fuel oil only): Below is our evaluation 

of Entergy’s SO2 BART analysis. For the steps that we did not explicitly address in our 

evaluation, we had no particular concerns with how ADEQ and Entergy addressed these in the 

BART analysis. 

Regarding Step 1 of Entergy’s SO2 BART analysis, Entergy identified use of low sulfur 

content fuel oil as the only control technology available. Entergy did not consider any postcombustion SO2 controls in the BART analysis, even though post-combustion control 

technologies, such as wet and dry scrubbers, are currently being used by comparable facilities to 

control SO2 emissions. As such, Entergy did not identify and consider control technologies that 

are capable of the maximum level of control that is achievable, as is required by the BART 

guidelines and the RH Rule. Because Entergy did not adequately consider all available control 

options in step 2 of the BART analysis, the subsequent analysis in Steps 3- 5 was incomplete. 

However, for the sake of providing a fuller picture of our evaluation of Entergy’s BART analysis 

for SO2 for Lake Catherine Unit 4, we discuss the remaining steps of Entergy’s BART analysis. 

 Regarding Step 4 of Entergy’s SO2 BART analysis, Entergy provided no documentation 

or detailed breakdown of the cost estimates for low sulfur content fuel oil. Therefore, we have 

no basis to verify the validity of either the cost estimates or Entergy’s BART determination 

based on the cost estimation. The basis for cost estimates should be documented, and should 

clearly indicate the amount of fuel oil that corresponds to the annual cost listed in the costanalysis. The basis for cost estimates should be documented either with data supplied by a 

vendor (i.e., budget estimates or bids) or by a referenced source. This was not done. In addition, 

Entergy did not indicate the amount of fuel oil that corresponds to the annual cost listed in the 

cost-analysis. 

 We propose to find that ADEQ and Entergy did not properly follow the requirements of 

section 51.308(e)(1)(ii)(A) in determining SO2 BART for the fuel oil firing scenario for Lake 

Catherine Unit 4. Specifically, we propose to find that ADEQ and Entergy did not properly take 

into consideration “the technology available” in Step 1 of the BART analysis and the costs of 

compliance” in Step 4 of the BART analysis. Because ADEQ and Entergy did not identify all 

available control technology options with potential application to the emissions unit under 

review and did not document how the cost estimates for low sulfur fuel oil were derived, we are 

proposing to disapprove ADEQ’s determination that BART for SO2 for Unit 4 for the fuel oil 

firing scenario is 0.562 lb/MMBtu on a 30 day rolling average. 
72 

State Submittal Regarding PM BART Determination (fuel oil): Appendix 9.3A 

 Entergy listed the PM10 emission rates associated with use of 1%, 0.5%, and 0.2% sulfur 

fuel oil. ADEQ and Entergy did not consider any post-combustion controls in the BART 

analysis for PM for the fuel oil firing scenario. Entergy determined PM BART for Unit 4 for the 

fuel oil firing scenario is 0.037 lb/MMBtu on a 30 day rolling average. ADEQ’s September 27, 

2011 supplemental submittal clarified that this PM emission limit corresponds to use of 0.5% 

sulfur content fuel oil. 

EPA Findings Regarding PM BART Determination (fuel oil): 

 The use of a wet scrubber system that controls both SO2 and PM emissions may prove to 

be cost-effective and provide for substantial visibility improvement and should therefore be 

considered in Entergy’s analysis for Unit 4. Because ADEQ and Entergy did not postcombustion controls, even though these are an available and technically feasible control option, 

we are proposing to disapprove ADEQ’s determination that BART for PM for Lake Catherine 

Unit 4 is 0.037 lb/MMBtu on a 30 day rolling average for the fuel oil firing scenario. 

F.2.4. Entergy White Bluff Units 1, 2, and Auxiliary Boiler BART Determinations 

 The White Bluff Units 1 and 2 and the Auxiliary Boiler are BART-eligible sources. 

Units 1 and 2 are coal fired boilers with a maximum power rating of 850 MW each and a heat 

input rate of 8700 MMBtu/hr each. Units 1 and 2 are permitted to burn both sub-bituminous and 

bituminous coal as the primary fuel and No. 2 fuel oil or bio-diesel as the start-up fuel. The 

Auxiliary Boiler is a 183 MMBtu/hr boiler that is permitted to burn only No. 2 fuel oil or 

biodiesel. The Class I areas located within 300 km of the facility are Caney Creek, Upper 

Buffalo, and Hercules Glades. Since Units 1 and 2 are permitted to burn both sub-bituminous 

and bituminous coal, Entergy made separate BART determinations for sub-bituminous and 

bituminous coal firing. 

State Submittal Regarding SO2 BART Determination for Units 1 and 2: Appendix 9.3A 

 Regarding BART for SO2 for Units 1 and 2, Entergy decided that since the White Bluff 

plant has a total generating capacity greater than 750 MW, the source is required to evaluate 

presumptive limits as part of the BART analysis. The presumptive SO2 BART limit is 0.15 

lb/MMBtu and was analyzed for BART by Entergy in both the sub-bituminous and bituminous 

coal firing scenarios. Although Entergy performed a BART analysis for BART for SO2, it 
73 

considered only those control options that meet the presumptive limit of 0.15 lb/MMBtu, without 

considering whether a more stringent SO2 emission limit is BART for Units 1 and 2. A summary 

of Entergy’s BART analysis is presented below: 

Step 1- Identify All Available Retrofit Control Technologies: Entergy identified two available 

options to control the units to the presumptive SO2 limit: limestone forced oxidation (i.e., wet 

scrubber) and lime spray dryer (i.e., dry scrubber). 

Step 2- Eliminate Technically Infeasible Options: Entergy did not indicate any of the control 

options identified under Step 1 of the analysis are technically infeasible. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: Entergy determined 

a wet scrubber can achieve up to 95% control efficiency while a dry scrubber can achieve up to 

92% control efficiency. 

Step 4- Evaluate Impacts and Document the Results: Entergy stated that there are no near-term 

limitations on the useful lives of these units and considered the costs of compliance in this step 

of the BART analysis. Assuming 85% utilization of the two units, Entergy determined the 

installation of a wet scrubber would have an annualized cost of $17,023,735 with a cost 

effectiveness of $620/ton SO2 removed at Unit 1 and an annualized cost of $17,159,021 with a 

cost-effectiveness of $620/ton SO2 removed at Unit 2. Entergy also determined the installation 

of a dry scrubber would have an annualized cost of $34,035,909 with a cost effectiveness of 

$1280/ton SO2 removed at Unit 1 and an annualized cost of $34,306,388 with a costeffectiveness of $1280/ton SO2 removed at Unit 2. The results of Entergy’s cost-effectiveness 

analysis are summarized in Tables 18 and 19 below, as adapted from Table A-1 of the BART 

analysis for Entergy White Bluff Units 1 and 2 (found in Appendix 9.3A of the RH SIP). 

Table 18. Cost-Effectiveness of SO2 Control Options for Entergy White Bluff Unit 1 

Control Option Annualized 

Cost ($/year)

Annual SO2

tons removed 

Cost-Effectiveness 

($/ton removed)

Base Case - - -

Limestone forced oxidation (wet scrubber) $17,023,735 27,457.6 $620

Lime Spray Dryer+FF (dry scrubber) $34,035,909 26,590.6 $1280 
74 

Table 19. Cost-Effectiveness of SO2 Control Options for Entergy White Bluff Unit 2 

Control Option Annualized 

Cost ($/year)

Annual SO2

tons removed 

Cost-Effectiveness 

($/ton removed)

Base Case - - -

Limestone forced oxidation (wet scrubber) $17,159,021 27,675.8 $620

Lime Spray Dryer+FF (dry scrubber) $34,306,388 26,801.9 $1280 

Step 5- Evaluate Visibility Impacts: ADEQ and Entergy evaluated the visibility impacts of the 

two control options. However, Entergy modeled both control options at the same SO2 emission 

rate of 0.15 lb/MMBtu, rather than at the achievable control effectiveness of 92% removal for 

dry scrubbing and 95% for wet scrubbing. ADEQ and Entergy determined the post-control 

modeling showed that the visibility benefits for dry scrubbers and wet scrubbers is nearly the 

same (with dry scrubbing being slightly better due to a hotter plume and lower sulfuric acid 

emissions), while the annualized cost of a dry scrubber is nearly twice that of a wet scrubber. 

 Entergy determined and ADEQ agreed that BART for SO2 for Units 1 and 2 is 

installation and operation of a wet scrubber at each unit to achieve the presumptive BART limit 

of 0.15 lb/MMBtu for both the sub-bituminous and the bituminous coal firing scenarios. 

EPA Findings Regarding SO2 BART Determination for Units 1 and 2: Below is our 

evaluation of Entergy’s SO2 BART analysis. For the steps that we did not explicitly address in 

our evaluation, we had no particular concerns with how ADEQ and Entergy addressed these in 

the BART analysis. 

 Regarding Step 1 of Entergy’s SO2 BART analysis, although Entergy performed a BART 

analysis for BART for SO2, it considered only those control options that meet the presumptive 

limit of 0.15 lb/MMBtu, without considering whether a more stringent SO2 emission limit is 

BART for Units 1 and 2. As discussed elsewhere in this TSD, the BART guidelines and the RH 

Rule require consideration of the most stringent control technology in the BART analysis. We 

agree that scrubbers are generally the most stringent controls available for SO2 emissions. 

However, because this control technology option is capable of achieving a lower emission limit 

than the presumptive limit, and similar facilities are capable of achieving an SO2 emission limit 

lower than the presumptive limit using this control technology, ADEQ and/or Entergy must 

consider this control technology and the lowest emission limit achievable in the BART analysis. 

We are proposing to find that ADEQ did not adequately address Step 1 of the BART analysis. 
75 

 Regarding Step 4 of Entergy’s SO2 BART analysis, we note Entergy’s cost analysis of 

the two SO2 control options included no documentation or detailed breakdown of the costs. The 

basis for cost estimates needs to be documented either with data supplied by an equipment 

vendor (i.e., budget estimates or bids) or by a referenced source in order for us to be able to 

determine if the cost was properly evaluated. Entergy must provide a breakdown of costs of 

material, labor, operation and maintenance, etc. Furthermore, the cost-effectiveness analysis is 

problematic because Entergy assumed, and ADEQ agreed with, an 85% utilization of the two 

units when the units are capable of 100% utilization and there is no federally enforceable limit of 

85% utilization in place.43 Since the two units are technically and legally capable of operating at 

100% utilization, a cost estimate assuming 85% utilization may underestimate the amount of 

emission reductions achieved by the controls and therefore under-represent the potential costeffectiveness of such controls. We are proposing to find that ADEQ did not adequately address 

Step 4 of the BART analysis. 

 Furthermore, Entergy considered a wet scrubber achieving 0.15 lb/MMBtu to be the most 

stringent technology available. But as discussed elsewhere, wet scrubbers and dry scrubbers 

have been documented to achieve much lower emissions including emissions as low as .065 

lbs/MMBtu for dry scrubbers. Therefore, the evaluation is not acceptable. In addition, we note 

that the 0.15 lb/MMBtu presumptive BART limit established by ADEQ corresponds to 82% 

control removal of the wet scrubber at Unit 1 and 80% control removal at Unit 2, as indicated by 

ADEQ in the Arkansas RH SIP narrative.44 Table A-1 in Appendix A of the BART analysis 

indicates the cost-effectiveness of installing and operating a wet scrubber is $620/ ton SO2

removed. Although Table A-1 indicates such cost-effectiveness value corresponds to operation 

of the wet scrubber at 95% control efficiency, neither ADEQ nor Entergy provided a breakdown 

of the cost estimates and we were therefore unable to verify whether it in fact corresponds to 

95% control efficiency or if it corresponds to 80% control efficiency at Unit 2 and 82% control 

efficiency at Unit 1. Even if the $620/ ton SO2 removed cost-effectiveness value corresponds to 

only 82% control efficiency for Unit 1 and 80% control efficiency for Unit 2, we believe that the 

incremental cost of operating the wet scrubber at 95% vs. 80% and 82% control efficiency is 

relatively minimal, and is likely cost-effective. Since Entergy and ADEQ considered only the 

0.15 lb/MMBtu SO2 presumptive limit in the BART analysis for Units 1 and 2, even though a 

lower limit is technically achievable and more than likely cost-effective, we are proposing to 

disapprove ADEQ’s determination for SO2 BART for both the sub-bituminous and bituminous 

coal firing scenarios for Units 1 and 2. 

                                                           

43 Based on operating hours provided by Entergy for Units 1 and 2, Unit 1 was operated 92.5% of the time in 2003, 

and Unit 2 was operated 92.7% of the time in 2004. See Table 2-1, under Section 2.2 of the BART analysis for 

Entergy White Bluff Units 1 and 2 (found in Appendix 9.3A of the RH SIP). 

44 See Table 9.3a of the Arkansas RH SIP. 
76 

Conclusion: ADEQ and Entergy did not adequately consider the “technology available” in Step 

1 and the “cost of compliance” in Step 3 of the BART analysis for SO2 for Entergy White Bluff 

Units 1 and 2. Since ADEQ and Entergy considered only the 0.15 lb/MMBtu SO2 presumptive 

limit in its BART analysis for Units 1 and 2 and did not evaluate more stringent emission limits, 

even though a more stringent emission limit is technically achievable and more than likely costeffective, we propose to disapprove ADEQ’s determination that BART for SO2 for Units 1 and 2 

is a wet scrubber with an emissions limit of 0.15 lb/MMBtu on a 30-day rolling average for both 

the sub-bituminous and bituminous coal firing scenarios. 

State Submittal Regarding NOx BART Determination for Units 1 and 2: Appendix 9.3A 

 Entergy performed a BART analysis for NOx for Units 1 and 2, in which available 

combustion control technologies to control NOx to the presumptive limits of 0.15 lb/MMBtu for 

the sub-bituminous coal-firing scenario and 0.28 lb/MMBtu for the bituminous coal-firing 

scenario were considered. As in the SO2 BART analysis for Units 1 and 2, Entergy did not 

consider establishing NOx BART emission limits below the NOx presumptive limits, even 

though it has been demonstrated that there are available control technologies that can meet 

emission limits more stringent than 0.15 lb/MMBtu and 0.28 lb/MMBtu for sub-bituminous coalfiring and bituminous coal-firing, respectively. A summary of Entergy’s analysis is presented 

below: 

Step 1- Identify All Available Retrofit Control Technologies: Entergy identified the following 

control options: boiler tuning, OFA, and LNB. Entergy did not evaluate post-combustion 

controls such as SCR and SNCR or any other NOx control options capable of emission limits 

more stringent than the presumptive limits, when these are technically feasible and available and 

are currently being used by comparable facilities to control NOx emissions at rates more 

stringent than the presumptive limit.

Step 2- Eliminate Technically Infeasible Options: Entergy did not indicate any of the control 

options identified under Step 1 of the analysis are technically infeasible. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: Entergy determined 

boiler tuning will result in 37% control removal; a combination of boiler tuning and OFA will 

result in 53.6% control removal; and a combination of boiler tuning, OFA, and LNB will result 

in 69% control efficiency at each unit. 

Step 4- Evaluate Impacts and Document the Results: Entergy stated there are no near-term 

limitations on the useful lives of these units and considered the costs of compliance in this step 

of the BART analysis. Entergy assumed 85% utilization of each unit (even though the unit can 
77 

technically and legally operate at 100% utilization)45 and determined that a combination of boiler 

tuning, OFA, and LNB has a control effectiveness of $463/ton NOx removed for Unit 1 and 

$437/ton NOx removed for Unit 2. The results of Entergy’s cost-effectiveness analysis are 

summarized in Tables 20 and 21 below, as adapted from Table A-2 of the BART analysis for 

Entergy White Bluff Units 1 and 2 (found in Appendix 9.3A of the RH SIP). 

Table 20. Cost-Effectiveness of NOx Control Options for Entergy White Bluff Unit 1 

Control Option

Annualized 

Cost 

($/year)

Annual SO2

tons 

removed 

Cost-Effectiveness 

($/ton removed)46

Base Case - - -

Tune $128,088 6,022 $21

Tune, OFA $882,767 8,729 $101 

Tune, OFA, LNB $5,201,532 11,238 $463 

Table 21. Cost-Effectiveness of NOx Control Options for Entergy White Bluff Unit 2 

Control Option

Annualized 

Cost 

($/year)

Annual SO2

tons 

removed 

Cost-Effectiveness 

($/ton removed)47

Base Case - - -

Tune $131,509 6,516.8 $20

Tune, OFA $906,741 9,446.2 $96 

Tune, OFA, LNB $5,312,563 12,161.6 $437 

Step 5- Evaluate Visibility Impacts: ADEQ and Entergy conducted post-control CALPUFF 

modeling of the visibility impact of only one NOx control scenario option (a combination of 

                                                           

45 Based on operating hours provided by ADEQ for Units 1 and 2, Unit 1 was operated 92.5% of the time in 2003, 

and Unit 2 was operated 92.7% of the time in 2004. See Table 2-1, under Section 2.2 of the BART analysis for 

Entergy White Bluff Units 1 and 2 (found in Appendix 9,3A of the RH SIP). 

46 Assuming 85% utilization of White Bluff Unit 1. 

47 Assuming 85% utilization of White Bluff Unit 2. 
78 

tuning, OFA, and LNB) coupled with SO2 controls (wet scrubber and dry scrubber). Since 

ADEQ did not conduct post-control CALPUFF modeling for NOx controls alone, we were 

unable to determine the visibility improvement that would result from these NOx controls alone. 

EPA Findings Regarding NOx BART Determination for Units 1 and 2: Below is our 

evaluation of Entergy’s NOx BART analysis. For the steps that we did not explicitly address in 

our evaluation, we had no particular concerns with how ADEQ and Entergy addressed these in 

the BART analysis. 

 Regarding Step 1 of Entergy’s NOx BART analysis, the only control level Entergy 

considered for the two control options corresponds to the NOx presumptive limit (0.15 

lb/MMBtu for sub-bituminous coal firing and 0.28 lb/MMBtu for bituminous coal firing). 

Entergy did not evaluate post-combustion controls such as SCR and SNCR or any other NOx 

control options capable of emission limits more stringent than the presumptive limits, even 

though these controls are technically feasible and available technologies. As already explained 

elsewhere in this TSD and in our proposal, post-combustion controls need to be evaluated as a 

control technology because they are technically feasible and widely used in the industry. 

Adoption of the presumptive emission limits does not preclude analysis of more stringent 

emission limits if such emission limits have been met for the same type of source under review 

under similar conditions. As such, Entergy must consider post combustion controls in its analysis 

as well as emissions limits more stringent than the presumptive limits, including post combustion 

controls. We are proposing to find that ADEQ and Entergy did not adequately consider “the 

technology available” in Step 1 of the BART analysis. 

 Regarding Step 4 of Entergy’s SO2 BART analysis, we note Entergy’s cost analysis of 

the NOx control options included no documentation or detailed breakdown of the costs. We 

have no basis to verify the validity of neither the cost estimates nor ADEQ’s determination based 

on analysis of cost estimation for BART. The basis for cost estimates must be documented 

either with data supplied by an equipment vendor (i.e., budget estimates or bids) or by a 

referenced source. This was not done. Without ADEQ and/or Entergy providing a breakdown 

of costs of material, labor, operation and maintenance, etc, we cannot verify the accuracy of 

Entergy’s cost-effectiveness determination. Furthermore, the cost-effectiveness analysis is 

problematic because Entergy assumed, and ADEQ agreed with, an 85% utilization of the two 

units when the units are capable of 100% utilization and there is no federally enforceable limit of 

85% utilization in place.48 Since the two units are technically and legally capable of operating at 

100% utilization, a cost estimate assuming 85% utilization may underestimate the amount of 

emission reductions achieved by the controls and therefore under-represent the potential cost-

                                                           

48 Based on operating hours provided by Entergy for Units 1 and 2, Unit 1 was operated 92.5% of the time in 2003, 

and Unit 2 was operated 92.7% of the time in 2004. See Table 2-1, under Section 2.2 of the BART analysis for 

Entergy White Bluff Units 1 and 2 (found in Appendix 9.3A of the RH SIP). 
79 

effectiveness of such controls. We propose to find that ADEQ and Entergy did not adequately 

address Step 4 of the BART analysis. 

Conclusion: ADEQ and Entergy did not adequately consider the “technology available” in Step 

1 of the BART analysis and the “cost of compliance” in Step 4 of the NOx BART analysis. 

ADEQ and Entergy should consider post combustion controls for NOx for Units 1 and 2, 

including SCR and SNCR. In addition, when evaluating the 2 units, ADEQ and Entergy need to 

consider all emission limits that can be met by similar types of sources under similar conditions 

in the NOx BART analysis, even if the emission limit is more stringent than the presumptive 

emission limit. Therefore, we propose to disapprove ADEQ’s determination that BART for NOx 

for White Bluff Units 1 and 2 is 0.15 lb/MMBtu for the sub-bituminous coal firing scenario and 

0.28 lb/MMBtu for the bituminous coal firing scenario. 

State Submittal Regarding PM BART Determination for Units 1 and 2: Appendix 9.3A 

 Regarding BART for PM for Units 1 and 2, neither Entergy nor ADEQ performed a 

BART analysis to determine what retrofit controls are BART for Units 1 and 2. The source’s 

rationale for this, which ADEQ agreed with, was its belief that most of the visibility-causing 

emissions from Units 1 and 2 are due to SO2 and NOx, and PM10 emissions are well-controlled 

with existing electrostatic precipitators (ESPs). ADEQ established the existing PM emission 

limit as PM BART for Units 1 and 2. Revisions to the Arkansas RH Rule (APC&E Commission 

Regulation 19, Chapter 15) that were submitted to us by ADEQ on August 3, 2010, state the PM 

BART emission limit for White Bluff Units 1 and 2 is the existing PM emission limit in the air 

permit as of October 15, 2007. The federally enforceable operating air permit states the PM 

emissions from the two units are controlled with ESPs and requires that the two units comply 

with a PM emission standard of 0.10 lb/MMBtu.49 

EPA Findings Regarding PM BART Determination for Units 1 and 2: 

We reviewed the CALPUFF visibility modeling submitted by ADEQ for Entergy White 

Bluff, and agree that PM emissions from the source have minimal visibility impacts at each Class 

I area within 300 km. Because we have found that the visibility impact of the source due to PM 

emissions alone is so minimal such that the installation of any additional PM controls on the 

units would likely achieve very low emissions reductions, have minimal visibility benefits, and 

not be cost-effective, we are proposing to approve ADEQ’s determination that PM BART for 

Units 1 and 2 for both the bituminous and sub-bituminous coal firing scenarios is the existing 

PM emission limit in the air permit as October 15, 2007, or 0.10 lb/MMBtu.. 

                                                           

49 ADEQ Operating Air Permit for Entergy Services Inc.- White Bluff Plant (Permit No. 0263-AOP-R6). This 

permit can be viewed at http://www.adeq.state.ar.us/ftproot/pub/WebDatabases/PermitsOnline/Air/0263-AOPR6.pdf. 
80 

State Submittal Regarding BART Determination for Auxiliary Boiler: Appendix 9.3A 

 With regard to the Auxiliary Boiler, neither ADEQ nor Entergy conducted a BART 

analysis that considered the statutory factors states are required to consider in determining what 

level of control is BART for a source, whether this be an emission limit or a work practice 

standard. The Arkansas RH SIP narrative states ADEQ decided to establish work practice 

standards for this source pursuant to 40 CFR 51.308(e)(1)(iii), rather than establish BART 

emission limits for SO2, NOx, and PM. APC&E Commission Regulation 19, Chapter 15, 

established that BART for the Auxiliary Boiler is a restriction to operate no more than 4360 

hours annually. 

EPA Findings Regarding BART Determination for Auxiliary Boiler: 

 Since ADEQ’s pre and post-control visibility modeling shows the visibility impact on 

surrounding Class I areas of all three units at the facility combined, we are not able to assess the 

visibility impact on Class I areas of the Auxiliary Boiler alone. The operating permit indicates 

the Auxiliary Boiler combusts No. 2 fuel oil or biodiesel to provide steam for Unit 1 and 2 startup activities. The restriction established by ADEQ as BART would allow the Auxiliary Boiler to 

operate 50% of the time on an annual basis. In practice, an auxiliary boiler that is only needed 

for start-up is typically operated much less than that. We are proposing to find that ADEQ did 

not properly follow the requirements of section 51.308(e)(1)(ii)(A) because neither ADEQ nor 

Entergy performed a BART analysis for the Auxiliary Boiler for their chosen work practice 

standard. We are proposing to disapprove ADEQ’s determination that BART for the White 

Bluff Auxiliary Boiler is a restriction to operate no more than 4360 hours annually. 

F.2.5. Domtar Power Boilers No. 1 and 2 BART Determinations 

 The Domtar Power Boilers No. 1 and 2 are BART-eligible sources. The Power Boilers 

generate steam and electricity for the other processes within the Domtar Kraft Pulp Mill. 

 The No. 1 Power Boiler has a heat input rating of 580 MMBtu/hr and is permitted to burn 

bark, wood waste, municipal yard waste, recycled sanitary products composed of cellulose and 

polypropylene, pelletized paper fuel (PPF), No. 6 fuel oil, used oil generated on site, reprocessed 

fuel oil, tire derived fuel (TDF), and natural gas. The No. 1 Power Boiler is equipped with a 

traveling grate, a combustion air system, and a wet ESP for removal of PM emissions. 

According to the operating air permit, the No. 1 Power Boiler’s permitted emission rate for 

PM/PM10 is 0.07 lb/MMBtu. The operating air permit provides that the sulfur content of the fuel 

oil used at the No.1 Power Boiler shall not exceed 3.0% by weight and that the No. 1 Power 
81 

Boiler shall not use more than 2,700,000 gallons of fuel oil for any consecutive 12-month period. 

The permit also limits the total amount of TDF used at the Power Boilers No. 1, 2, and 3 

combined to 220 tons in any 24-hour period. 

 The No. 2 Power Boiler has a heat input rating of 820 MMBtu/hr and burns primarily 

pulverized bituminous coal, but is also permitted to burn non-condensable gases (NCGs), bark 

and wood chips used to absorb oil spills, wood waste, municipal yard waste, natural gas, used oil 

generated on site, recycled sanitary products based on cellulose and polypropylene, No. 6 fuel 

oil, reprocessed fuel oil, TDF, and petroleum coke. The No. 2 Power Boiler is equipped with a 

traveling grate, combustion air system including OFA, multiclones for removal of PM emissions, 

and two venturi scrubbers in parallel for removal of remaining PM emissions and SO2. 

According to the operating air permit, the No. 2 Power Boiler’s permitted emission rate for 

PM/PM10 is 0.1 lb/MMBtu. 

State Submittal Regarding SO2 BART Determination for Power Boiler No. 1: Appendix 

9.3A 

 Regarding BART for SO2 for Power Boiler No. 1, Domtar noted pre-combustion controls 

such as fuel switching/blending and fuel cleaning are ineffective, as wood has low sulfur content. 

Domtar also noted post-combustion controls such as flue gas desulfurization (FGD) and (i.e., wet 

and dry scrubbers) have not been installed on wood-fired boilers because of the relatively low 

SO2 emissions from wood combustion. Domtar determined that due to the low sulfur content of 

wood, SO2 emissions from wood combustion are inherently low and “have a negligible impact 

on visibility impairment.” Domtar determined SO2 BART for Power Boiler No. 1 is no 

additional SO2 controls beyond the existing fuel restrictions (fuel oil with a maximum 3.0% 

sulfur content and a usage limitation of 2,700,000 gallons of fuel oil per consecutive 12-month 

period) are necessary. ADEQ agreed with Domtar’s determination and decided that an emission 

limit of 1.12 lb/MMBtu on a 30-day rolling average is BART for SO2 for Power Boiler No. 1. 

We note that ADEQ’s CALPUFF pre-control modeling demonstrates the No. 1 Power Boiler 

emits more than one-third of the total modeled emissions of SO2 from the two sources. 

EPA Findings Regarding SO2 BART Determination for Power Boiler No. 1: 

 

 We agree that due to the low sulfur content of wood, SO2 emissions from wood-fired 

boilers are generally relatively low. Table 1.6-2 of EPA’s Compilation of Air Pollutant Emission 

Factors indicates the combustion of wood waste has a typical SO2 emission rate of 0.025 

lb/MMBtu.50 In light of this, we question the appropriateness of an SO2 emission limit of 1.12 

                                                           

50 Compilation of Air Pollutant Emission Factors, Volume I: Stationary Point and Area Sources, AP-42, 5th Edition, 

January 1995. 
82 

lb/MMBtu for Power Boiler No. 1. Neither ADEQ nor Domtar provided any support for this 

emission limit. Domtar stated that approximately 75 percent of the heat input for Power Boiler 

No. 1 is supplied by bark. A unit combusting primarily bark should be capable of achieving an 

SO2 emission rate much lower than 1.12 lb/MMBtu. The facility’s current permit for this unit 

limits its annual SO2 emissions to 214 tons per year (tons/year), which is a low figure. 

Therefore, there appears to be a mismatch between ADEQ’s relatively high BART SO2 emission 

limit and what the facility actually needs, based on its current permit. As part of its BART 

analysis, ADEQ and/or Domtar should have conducted a fuel inventory of this boiler in order to 

explore this issue. Other sources of potential sulfur emissions should have been investigated, 

including emissions resulting from burning fuel oil and TDF. ADEQ and Domtar should also 

have considered lowering the sulfur content of fuel oil burned at the source, and/or lowering the 

limit on fuel oil usage. If Power Boiler No. 1 truly needs such a high SO2 emission limit, then 

ADEQ and/or the Domtar should have investigated the feasibility, effectiveness, and cost of SO2

controls. Therefore, we are proposing to find that ADEQ and Domtar did not properly follow the 

requirements of section 51.308(e)(1)(ii)(A) in determining BART. We are proposing to 

disapprove ADEQ’s determination that BART for SO2 for Power Boiler No. 1 is 1.12 lb/MMBtu 

on a 30-day rolling average. 

State Submittal Regarding SO2 BART Determination for Power Boiler No. 2: Appendix 

9.3A 

Regarding BART for SO2 for Power Boiler No. 2, neither ADEQ nor Domtar performed 

a BART analysis that considered the statutory factors under section 51.308(e)(ii)(A). Domtar 

stated the unit is equipped with a wet scrubber for control of SO2 and PM emissions. According 

to Domtar, the existing wet scrubber currently achieves an SO2 control efficiency of 

approximately 90%. Domtar indicated that the BART Guidelines provide an option to skip the 

comprehensive BART analysis for subject-to-BART units already equipped with the most 

stringent controls available, including all possible improvements to control devices, as long as 

these are made federally enforceable for the purpose of implementing BART for the source. 

Domtar stated that since wet scrubbing is the most effective method of controlling SO2 emissions 

and it has not identified any feasible upgrades to the existing wet scrubber, no BART analysis is 

necessary. ADEQ agreed with Domtar, and determined that no additional SO2 removal is needed 

for the No. 2 Power Boiler, and BART for SO2 is 1.20 lb/MMBtu on a 30-day rolling average 

using the existing wet scrubber. 

EPA Findings Regarding SO2 BART Determination for Power Boiler No. 2: 

 We agree that the BART Guidelines allow sources to forego the BART analysis when the 

source already has the most stringent controls available in place and all possible improvements to 

control devices have been made. However, we disagree that a 1.20 lb/MMBtu SO2 emissions 
83 

rate corresponds to the most stringent control available. We note FGD systems are capable of 

SO2 reduction efficiencies up to 98%.51 Therefore, the 90% reduction efficiency claimed by 

Domtar does not correspond to the highest SO2 control efficiency wet scrubbers are capable of 

achieving. The highest SO2 control efficiency issue aside, although Domtar stated it did not 

identify any feasible upgrades to the existing wet scrubber, it provided no documentation of what 

upgrades were considered and why they were found to be technical infeasible. In considering all 

possible improvements to the scrubber, Domtar should have evaluated options that not only 

improve the design removal efficiency of the scrubber vessel itself, but also considered upgrades 

that can improve the overall SO2 removal efficiency of the scrubber system. For example, the 

BART Guidelines state that improving maintenance practices, adjusting scrubber chemistry, and 

increasing auxiliary equipment redundancy are some ways to improve average SO2 removal 

efficiencies. For the reasons discussed above, we are proposing to find that ADEQ and Domtar 

did not properly follow the requirements of section 51.308(e)(1)(ii)(A) in determining BART for 

SO2 for Power Boiler No. 2. We are proposing to disapprove ADEQ’s determination that BART 

for SO2 for the No. 2 Power Boiler is 1.20 lb/MMBtu on a 30-day rolling average using the 

existing wet scrubber. 

State Submittal Regarding NOx BART Determination for Power Boilers No. 1 and No. 2: 

Appendix 9.3A 

 Domtar performed a BART analysis to determine what controls are BART for the two 

boilers. A summary of Domtar’s analysis is presented below: 

Step 1- Identify All Available Retrofit Control Technologies: Domtar identified the following 

NOx control technologies: boiler tuning/optimization, fuel blending, FGR, LNB, OFA, SNCR, 

SCR, and reburning/methane de-NOx. 

 Domtar stated the source has employed and intends to continue to employ the latest boiler 

optimization and tuning techniques, and that such control technologies are considered part of the 

base case for Power Boilers No. 1 and 2. Similarly, Domtar explained that it historically mixes 

10-15% (heat input basis) wood with coal in the No. 2 Power Boiler and therefore fuel blending 

is considered part of the base case for the No. 2 Power Boiler. 

Step 2- Eliminate Technically Infeasible Options: Domtar determined that several of the control 

options identified in Step 1 are technically infeasible for one or both of the power boilers. 

Domtar’s reasoning is summarized here: 

                                                           

51 See EPA’s Air Pollution Control Fact Sheet on FGD control technology, available at 

http://www.epa.gov/ttn/catc/dir1/ffdg.pdf. 
84 

• Domtar explained that since wood is inherently low in nitrogen content, fuel blending is 

not technically feasible for wood-fired boilers, and therefore eliminated this as a control 

option for Power Boiler No. 1. 

• Domtar stated that combustion modification with LNB is used in both gas/oil-fired and 

coal fired units, but is not used for wood-fired boilers. Therefore, Domtar determined use 

of LNB is technically infeasible for Power Boiler No. 1. 

• Regarding FGR, Domtar stated that only thermal NOx can be controlled by FGR. As 

most NOx emissions from the No. 1 and No. 2 Power Boilers are due to fuel NOx rather 

than thermal NOx, Domtar determined FGR is technically infeasible for both power 

boilers. 

• Regarding use of OFA, Domtar stated the source was informed by one OFA vendor that 

while OFA results in decreased NOx emissions, the primary purpose is combustion 

optimization, and implementation of OFA can actually increase NOx emissions in certain 

circumstances. Therefore, Domtar determined an OFA system upgrade at Power Boilers 

No. 1 and 2 is technically infeasible and eliminated this as a control option for both 

power boilers. 

• Domtar determined that SCR and SNCR are technically infeasible control options for No. 

1 and 2 Power Boilers because “they are not suited for power boilers that experience 

wide temperature variances and high load swings.” 

 Domtar determined that methane de-NOx is the only technically feasible NOx control 

option for Power Boiler No. 1 and methane de-NOx and LNB are the only two technically 

feasible NOx control options for Power Boiler No. 2. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: Domtar determined 

that methane de-NOx has a potential control efficiency of 50%, whereas LNB has a potential 

control efficiency of 30%. 

Step 4- Evaluate Impacts and Document the Results: Domtar determined the cost-effectiveness 

of methane de-NOx is $7,262/ton NOx removed at Power Boiler No. 1 and $4,259/ton NOx 

removed at Power Boiler No. 2, while the cost-effectiveness of LNB is $1,465/ton NOx removed 

at Power Boiler No. 1. Domtar eliminated consideration of methane de-NOx at Power Boilers 

No. 1 and 2 due to its high cost. Domtar decided that the only control option it deemed as 

technically feasible (methane de-NOx) is NOx BART for Power Boiler No. 1,and decided there 

are no NOx controls available for Power Boiler No. 2 based on the cost-effectiveness analysis. 
85 

Step 5- Evaluate Visibility Impacts: ADEQ and Domtar did not model the visibility impact of 

the NOx controls it eliminated in Step 4 based on the cost-effectiveness analysis. As far as NOx 

goes, ADEQ modeled the visibility impact only of the NOx control options it selected as BART. 

ADEQ’s post-control visibility modeling shows the visibility impact resulting from its SO2, 

NOx, and PM BART determinations. The results of ADEQ’s post-control visibility modeling are 

summarized in Table 22 (modified from Table 4-7 of the BART analysis for Domtar, see 

Appendix 9.3A of the Arkansas RH SIP): 

Table 22. Visibility Impact of ADEQ’s SO2, NOx, and PM BART Determinations for 

Domtar Power Boilers No. 1 and 2 

Class I area

Pre-control 

Maximum 24-hour 

Impact (∆dv)

Post-control 

Maximum 24-hour 

Impact (∆dv) 

Percent 

Visibility 

Improvment 

(%) 

Caney Creek 2.262 2.039 9.90 

Upper Buffalo 1.181 1.029 12.87 

Mingo 0.923 0.836 9.43 

Hercules Glades 0.701 0.631 9.99 

 

 Domtar determined and ADEQ agreed that there are no NOx controls available for Power 

Boiler No. 1 and established a BART NOx emission limit of 0.46 lb/MMBtu on a 30-day rolling 

average for Power Boiler No. 1. Domtar and ADEQ also determined that BART for Power 

Boiler No. 2 is LNB achieving a NOx emission limit of 0.45 lb/MMBtu on a 30-day rolling 

average. 

EPA Findings Regarding NOx BART Determination for Power Boilers No. 1 and 2: Below 

is our evaluation of Domtar’s NOx BART analysis for Domtar Power Boilers No. 1 and 2. For 

those steps we did not explicitly address in our evaluation, we had no particular concerns with 

how ADEQ and Domtar addressed these in the BART analysis. 

 Regarding Step 2 of Domtar’s NOx BART analysis, we disagree with Domtar’s 

determination that SNCR is a technically infeasible control option for Power Boilers No. 1 and 2 

because SNCR is “not suited for power boilers that experience wide temperature variances and 

high load swings.” We note a review of the RACT/BACT/LAER Clearinghouse (Process types 

11.120 and 11.190) indicates there are several wood-fired utility boilers that employ SNCR. In 
86 

particular, a similar source, the bark boiler at Temple Inland Kraft Linerboard Mill in Orange, 

Texas, employs SNCR, Low Excess Air (LEA), and low NOx gas burners.52 The Temple Inland 

Kraft boiler has a NOx emission limit of 0.166 lb/MMBtu on a 30 day rolling average. Like the 

Domtar Power Boilers No. 1 and 2, the Temple Inland Kraft boiler exhibits load swing. We also 

note there are other similarities in the operating parameters of the bark boiler at Temple Inland 

Kraft and Power Boiler No. 1 (the bark boiler) at Domtar. Like Power Boiler No. 1 at Domtar, 

the bark boiler at Temple Inland Kraft is permitted to burn, among other fuel sources, bark/wood 

biomass, natural gas, and tire-derived fuel. The Temple Inland Kraft bark boiler has a maximum 

heat input rating of 656 MMBtu/hr, while Domtar Power Boiler No. 1 has a maximum heat input 

rating of 580 MMBtu/hr. In conducting its BART analysis, ADEQ and/or Domtar should have 

more carefully considered the use of post combustion control technologies, such as SNCR, for 

both power boilers at Domtar, since SNCR is a control technology that has been used at similar 

facilities to control NOx emissions. Because ADEQ and Domtar eliminated some of the control 

options as being technically infeasible in Step 2 of the BART analysis, the subsequent analysis in 

remaining steps was incomplete. 

Regarding Step 4 of the BART analysis, Domtar eliminated methane de-NOx as a control 

option for Power Boilers No. 1 and 2 due to the high cost of compliance, thereby eliminating the 

one control option identified by Domtar as technically feasible for Power Boiler No.1. Domtar 

determined there are no NOx controls available for Power Boiler No. 1 and that BART for 

Power Boiler No. 2 is LNB. We disagree with ADEQ and Domtar’s approach of eliminating 

control options in Step 4 before the visibility impact of each control option has been modeled. 

Domtar made its NOx BART determinations in Step 4 of the BART analysis, and thereby did not 

evaluate the visibility impact of all technically feasible control options in selecting BART for 

NOx for Power Boilers No. 1 and 2. As Domtar eliminated one of the control options based on 

cost alone in this step of the analysis, we propose to find that ADEQ and Domtar did not 

adequately address Step 4 of the BART analysis. 

 Regarding Step 5 of Domtar’s NOx BART analysis, as explained in our evaluation of 

Step 4 above, ADEQ and Domtar did not evaluate the visibility impact of each technically 

feasible control option as is required under Step 5 of the BART analysis. Domtar eliminated 

control options prematurely in the Step 4 of the BART analysis before evaluating the visibility 

impacts of these NOx controls. Specifically, for Step 5, ADEQ and Domtar did not evaluate the 

visibility impact resulting from use of methane de-NOx at the two power boilers. ADEQ and 

Domtar’s approach for making NOx BART determinations for the No. 1 and 2 Power Boilers is 

flawed, as the RH Rule and the BART Guidelines provide that the visibility impacts of all 

technically feasible control options, which corresponds to Step 5 of the BART analysis, must be 

                                                           

52 See the docket for this rulemaking to view the Title V permit for the Temple Inland Kraft Linerboard Mill. 
87 

considered before a BART determination is made. We propose to find that ADEQ and Domtar 

did not adequately address step 5 of the BART analysis. 

 

 ADEQ stated its post-control visibility modeling demonstrates the BART determinations 

for PM, SO2, and NOx for Power Boilers No. 1 and 2 will result in a combined visibility 

improvement of 9.9% at Caney Creek and 12.9% at Upper Buffalo.53 We note this is very 

minimal visibility improvement and that there is ample room for the additional visibility 

improvement that would result from BART controls more stringent than those selected by 

ADEQ and Domtar. 

Conclusion: We are proposing to find that ADEQ did not properly follow the requirements of 

section 51.308(e)(1)(ii)(A) in determining NOx BART for Power Boilers No.1 and 2. 

Specifically, we are proposing that ADEQ did not properly take into consideration “the 

technology available” and “the degree of improvement in visibility which may reasonably be 

anticipated to result from the use of such technology.” We disagree with Domtar and ADEQ’s 

assessment that use of SNCR at the two power boilers is technically infeasible. In addition, 

ADEQ did not model the visibility impacts of all technically feasible control options before 

making NOx BART determinations. For these reasons, we are proposing to disapprove ADEQ’s 

determination that BART for NOx for Power Boiler No. 1 is a NOx emission limit of 0.46 

lb/MMBtu (which would achieve no NOx emission reductions beyond the baseline) and that 

BART for NOx for Power Boiler No. 2 is a NOx emission limit of 0.45 lb/MMBtu (achieved by 

use of LNB). 

State Submittal Regarding PM BART Determination for Power Boilers No. 1 and No. 2: 

Appendix 9.3A 

 Domtar stated the No. 1 and 2 Power Boilers were at the time the BART analysis was 

prepared subject to the Boiler Maximum Achievable Control Technology (MACT) PM emission 

standard of 0.07 lb/MMBtu. A wet ESP was installed at the No. 1 Power Boiler to meet the 0.07 

lb/MMBtu Boiler MACT PM emission standard. Domtar also stated that the No. 2 Power 

Boiler’s existing wet scrubber is capable of meeting the Boiler MACT PM emission standard. 

Domtar noted that in the BART Guidelines, EPA encourages the use of streamlined approaches 

for BART determinations and elected to forego a BART analysis and to presumptively rely on 

the 0.07 lb/MMBtu Boiler MACT PM emission standard in existence at the time to meet the 

BART PM requirements for both the No. 1 and No. 2 Power Boilers. 

                                                           

53 ADEQ’s post-control modeling, showing the visibility improvement resulting from BART controls, demonstrates 

that the visibility impact of Power Boilers No. 1 and 2 combined will be 2.038 ∆dv at Caney Creek and 1.029 ∆dv at 

Upper Buffalo after ADEQ’s BART controls are put in place. 
88 

 Concerning Power Boiler No. 1, Domtar provided a discussion of other PM control 

technologies available at the time, and determined that a wet ESP with a PM emission limit of 

0.07 lb/MMBtu on a 30-day rolling average is BART for Power Boiler No. 1. ADEQ agreed 

with Domtar’s determination. Concerning Power Boiler No.2, Domtar stated that the unit was 

subject to the Boiler Maximum Achievable Control Technology (MACT)54 PM emission 

standard in existence at the time (0.07 lb/MMBtu), and indicated its intent to presumptively rely 

on such standard to meet BART PM requirements for Power Boiler No. 2. However, instead of 

adopting 0.07 lb/MMBtu as the BART PM emission limit for Power Boiler No. 2, ADEQ 

adopted 0.10 lb/MMBtu as the BART PM emission limit. 

EPA Findings Regarding PM BART Determination for Power Boilers No. 1 and 2: 

 The BART Guidelines (Appendix Y to Part 51) provide that for VOC and PM sources 

subject to MACT standards, states may streamline the BART analysis by including a discussion 

of the MACT controls and whether any major new technologies have been developed subsequent 

to the MACT standards. Many VOC and PM sources that are well controlled because they are 

regulated by the MACT standards, which EPA developed under CAA section 112. This may also 

be true for SO2. Any source subject to MACT standards must meet a level that is as stringent as 

the best-controlled 12 percent of sources in the industry. In many cases, it will be unlikely that 

states will identify emission controls more stringent than the MACT standards without 

identifying control options that would cost many thousands of dollars per ton. The BART 

Guidelines provide that unless there are new technologies subsequent to the MACT standards 

which would lead to cost-effective increases in the level of control, sources may rely on the 

MACT standards for purposes of BART. 

 Concerning Power Boiler No. 1, Domtar provided a discussion of other PM control 

technologies available at the time, and determined that a wet ESP with a PM emission limit of 

0.07 lb/MMBtu on a 30-day rolling average is BART for Power Boiler No. 1. We agree that 

ADEQ’s determination for BART for PM for Power Boiler No. 1 is consistent with the BART 

Guidelines and propose to approve it. 

 Since ADEQ did not select the Boiler MACT PM emission standard current at the time 

the BART determination was made as the BART PM emission limit for Power Boiler No. 2, 

ADEQ cannot elect to take the streamlined approach provided in the BART Guidelines. If 

ADEQ chooses to take the streamlined approach provided in the BART Guidelines, ADEQ must 

select the Boiler MACT PM standard if it determines there are no new and cost-effective 

technologies or available upgrades developed subsequent to the MACT standard. Otherwise, 

                                                           

54 The MACT standards are part of the National Emission Standards for Hazardous Air Pollutants for Source 

Categories (NESHAP), provided under 40 CFR 63. 
89 

ADEQ and/or Domtar must perform a complete BART analysis that considers the statutory 

factors under section 51.308(e)(ii)(A) to determine BART for PM for Power Boiler No. 2. 

Furthermore, ADEQ’s pre-control visibility modeling indicates a considerable portion of the 

combined visibility impact of No. 1 and 2 Power Boilers at Caney Creek is due to PM 

emissions.55

Conclusion: We are proposing to disapprove ADEQ’s determination that BART for PM10 for 

Power Boiler No. 2 is 0.10 lb/MMBtu on a 30-day rolling average, and we are proposing to 

approve ADEQ’s determination that BART for PM10 for Power Boiler No. 1 is 0.07 lb/MMBtu 

on a 30-day rolling average. 

F.2.6 ADEQ BART Results and Summary 

 We have reviewed ADEQ’s BART determinations for the subject to BART sources listed 

in Table 9, above. For the reasons discussed above, we are proposing to find that ADEQ has 

partially satisfied the BART requirement of section 51.308(e). We are proposing to find that the 

BART determinations listed in Table 23 satisfy the BART requirements of section 51.308(e), 

and hereby propose to approve them. We are proposing to find that the BART determinations 

listed in Table 24 do not satisfy the BART requirements of section 51.308(e), and hereby 

propose to disapprove them. We are also proposing to find that the 6A and 9A Boilers at the 

Georgia-Pacific Crossett Mills are subject-to-BART and require a full BART analysis to satisfy 

the BART requirement of section 51.308(e). 

Table 23. BART Determinations Satisfying Section 51.308(e) 

Facility Name BART

Emission Unit

Pollutant BART emission limit56

American Electric 

Power Flint Creek 

Power Plant

Boiler No. 1 PM10

existing PM emission 

limit (0.1 lb/MMBtu) 

Entergy Lake Catherine 

Plant Unit 4 natural gas 

firing SO2

No BART 

Determination 

                                                           

55 ADEQ’s pre-control modeling files are found in Appendix 9.2B of the Arkansas RH SIP. Since ADEQ’s 

visibility modeling shows the visibility impact of No. 1 and 2 Power Boilers combined, we were unable to assess the 

visibility impact of No. 2 Power Boiler individually on surrounding Class I areas. 

56 Emission limits are based on a 30-day rolling average. 
90 

PM10

existing PM emission 

limit (45 lb/hr) 

Entergy White Bluff 

Plant 

Unit 1 

bituminous 

coal firing PM10

existing PM emission 

limit (0.1 lb/MMBtu) 

subbituminous 

coal firing 

PM10

existing PM emission 

limit (0.1 lb/MMBtu) 

Unit 2 

bituminous 

coal firing PM10

existing PM emission 

limit (0.1 lb/MMBtu) 

subbituminous 

coal firing 

PM10

existing PM emission 

limit (0.1 lb/MMBtu) 

Domtar Ashdown Mill No. 1 Power 

Boiler PM10 0.07 lb/MMBtu 

Table 24. BART Determinations Not Satisfying Section 51.308(e) 

Facility Name

BART

Emission 

Unit

Pollutant BART emission limit57

Arkansas Electric 

Cooperative Corporation 

Carl E. Bailey 

Generating Station Unit 1

SO2

Use of fuel oil with 1% 

sulfur content 

NOx No BART 

Determination

PM No BART 

Determination

Arkansas Electric 

Cooperative Corporation 

John L. McClellan 

Generating Station Unit 1

SO2

Use of fuel oil with 1% 

sulfur content 

NOx No BART 

Determination 

PM No BART 

Determination 

                                                           

57 Emission limits are based on a 30-day rolling average. 
91 

American Electric 

Power Flint Creek 

Power Plant Boiler No. 1

SO2 0.15 lb/MMBtu 

NOx 0.23 lb/MMBtu 

Entergy Lake Catherine 

Plant 

Unit 4 

natural gas 

firing NOx 0.15 lb/MMBtu 

fuel oil 

firing 

SO2 0.562 lb/MMBtu 

NOx 0.25 lb/MMBtu 

PM 0.037 lb/MMBtu 

Entergy White Bluff 

Plant 

Unit 1 

bituminous 

coal firing 

SO2 0.15 lb/MMBtu 

NOx 0.28 lb/MMBtu 

subbituminous 

coal firing 

SO2 0.15 lb/MMBtu 

NOx 0.15 lb/MMBtu 

Unit 2 

bituminous 

coal firing 

SO2 0.15 lb/MMBtu 

NOx 0.28 lb/MMBtu 

subbituminous 

coal firing 

SO2 0.15 lb/MMBtu 

NOx 0.15 lb/MMBtu 

Auxiliary 

Boiler All 

Boiler to be operated 

no more than 4360 hrs 

annually 

Domtar Ashdown Mill 

No. 1 Power 

Boiler 

SO2 1.12 lb/MMBtu 

NOx 0.46 lb/MMBtu 

No. 2 Power 

Boiler 

SO2 1.2 lb/MMBtu 

NOx 0.45 lb/MMBtu 

PM10 0.1 lb/MMBtu 
92 

F.2.7 Arkansas Regional Haze Rule 

 

 APC&E Commission Regulation 19, Chapter 15 requires each source subject to BART to 

install and operate BART no later than 6 years after the effective date of ADEQ’s regulation or 5 

years after we approve this RH SIP, whichever comes first.58

 ADEQ originally submitted Arkansas’ RH Rule, the APC&E Commission Regulation 19, 

Chapter 15, along with the Arkansas RH SIP, which we received on September 23, 2008. On 

August 3, 2010, we received a SIP revision submittal from ADEQ revising several chapters of 

APC&E Commission Regulation 19, including Chapter 15. The revisions to Chapter 15 of 

APC&E Commission Regulation 19 that we received on August 3, 2010 are mostly nonsubstantive amendments that revise the original version of the rule we received on September 23, 

2008. Therefore, in this proposed rulemaking we are proposing to take action on the version of 

Chapter 15 of APC&E Regulation 19 contained in the submittal we received on September 23, 

2008, as revised by the submittal received on August 3, 2010. The only portion of the August 3, 

2010 SIP submittal we are proposing to take action on in this rulemaking is that portion revising 

Chapter 15 of APC&E Regulation 19. In this proposed rulemaking, we are not proposing to take 

action on the portions of the August 3, 2010 SIP submittal that revise other chapters of APC&E 

Commission Regulation 19, as those chapters are not related to regional haze. We will take 

action on the revisions to other chapters of APC&E Commission Regulation 19 at a later time. 

 We are proposing to partially approve and partially disapprove Chapter 15 of APC&E 

Commission Regulation 19. We are proposing to approve those portions of Chapter 15 of 

APC&E Commission Regulation 19 that incorporate the BART determinations we are proposing 

to approve and those portions that are consistent with our overall action on the Arkansas RH SIP. 

Specifically, we are proposing to approve the following sections of Chapter 15 of APC&E 

Commission Regulation 19: 

• Reg. 19.1501, which establishes the purpose of the rule; 

• Reg. 19.1502, which incorporates by reference the definitions contained in 40 CFR 

51.301, as in effect on June 22, 2007; 

• Reg. 19.1503, which identifies the State’s BART eligible sources; 

• The portion of Reg. 19.1504(A) that identifies AECC Bailey Generating Station (Unit 1), 

AECC McClellan Generating Station (Unit 1), Domtar Ashdown Mill (Power Boilers No. 

1 and 2), Lake Catherine (Unit 4), White Bluff (Units 1, 2, and the Auxiliary Boiler), and 

AEP Flint Creek (Boiler No. 1) as subject-to-BART sources; 

• Reg. 19.1504(B), which requires each source subject to BART to install and operate 

BART as expeditiously as possible, but no later than 6 years after the effective date of the 

State’s regulation or 5 years after EPA approval of the RH SIP (whichever comes first);59 

                                                           

58 See Arkansas Pollution Control and Ecology Commission Reg. 19.1504(B). 
93 

• Reg. 19.1504(C), which requires each source subject-to-BART to maintain the control 

equipment required by Chapter 15, and establish procedures to ensure such equipment is 

properly operated and maintained; 

• Reg. 19.1505(A)(3), which establishes PM BART for AEP Flint Creek Power Plant, 

Boiler 1; 

• Reg. 19.1505(D)(3), which establishes PM BART for Domtar Ashdown Mill, Power 

Boiler No. 1; 

• Reg. 19.1505(F)(3), which establishes PM BART (bituminous coal) for Entergy White 

Bluff, Unit 1; 

• Reg. 19.1505(G)(3), which establishes PM BART (sub-bituminous coal) for Entergy 

White Bluff, Unit 1; 

• Reg. 19.1505(I)(3), which establishes PM BART (bituminous coal) for Entergy White 

Bluff, Unit 2; 

• Reg. 19.1505(J)(3), which establishes PM BART (sub-bituminous coal) for Entergy 

White Bluff, Unit 2; 

• Reg. 19.1505(M)(2), which establishes PM BART (natural gas) for Entergy Lake 

Catherine Unit 4; 

• Reg. 19.1506, which provides the compliance provisions for the subject to BART 

sources; and 

• Reg. 19.1507, which provides that the Part 70 permit of each facility subject to BART 

shall be subject to re-opening. 

 We are proposing to disapprove the portion of Chapter 15 of APC&E Commission 

Regulation 19 that fails to identify the 6A and 9A Boilers at the Georgia Pacific Mill as subject 

to BART sources, and the portions that incorporate the State’s BART determinations we are 

proposing to disapprove. Specifically, we are proposing to disapprove the following sections of 

Chapter 15 of the Arkansas Pollution Control and Ecology Commission Regulation 19: 

• The portion of Reg. 19.1504(A) that fails to identify the 6A and 9A Boilers at the 

Georgia-Pacific Crossett Mill as subject to BART sources; 

• Reg. 19.1505(A)(1), which establishes SO2 BART for AEP Flint Creek Power Plant, 

Boiler 1; 

• Reg. 19.1505(A)(2), which establishes NOx BART for AEP Flint Creek Power Plant, 

Boiler 1; 

                                                                                                                                                                                                59 On March 26, 2010, the Arkansas Pollution Control & Ecology Commission, Arkansas’ rulemaking body, granted 

all Arkansas subject-to-BART sources a variance from the compliance deadline imposed by the State’s RH Rule, 

such that these sources are now required to comply with BART requirements no later than 5 years after EPA 

approval of the RH SIP. 
94 

• Reg. 19.1505(B), which establishes SO2 BART for AECC Bailey Generating Station, 

Unit 1; 

• Reg. 19.1505(C), which establishes SO2 BART for AECC McClellan Generating Station, 

Unit 1; 

• Reg. 19.1505(D)(1), which establishes SO2 BART for Domtar Ashdown Mill, Power 

Boiler No. 1; 

• Reg. 19.1505(D)(2), which establishes NOx BART for Domtar Ashdown Mill, Power 

Boiler No. 1; 

• Reg. 19.1505(E)(1), which establishes SO2 BART for Domtar Ashdown Mill, Power 

Boiler No. 2; 

• Reg. 19.1505(E)(2), which establishes NOx BART for Domtar Ashdown Mill, Power 

Boiler No. 2; 

• Reg. 19.1505(E)(3), which establishes PM BART for Domtar Ashdown Mill, Power 

Boiler No. 2; 

• Reg. 19.1505(F)(1), which establishes SO2 BART (bituminous coal) for Entergy White 

Bluff, Unit 1; 

• Reg. 19.1505(F)(2), which establishes NOx BART (bituminous coal) for Entergy White 

Bluff, Unit 1; 

• Reg. 19.1505(G)(1), which establishes SO2 BART (sub-bituminous coal) for Entergy 

White Bluff, Unit 1; 

• Reg. 19.1505(G)(2), which establishes NOx BART (sub-bituminous coal) for Entergy 

White Bluff, Unit 1; 

• Reg. 19.1505(H), which provides that when burning a mix of bituminous and subbituminous coal at White Bluff Unit 1, the NOx BART limits shall be prorated using the 

percentage of each coal being used; 

• Reg. 19.1505(I)(1), which establishes SO2 BART (bituminous coal) for Entergy White 

Bluff, Unit 2; 

• Reg. 19.1505(I)(2), which establishes NOx BART (bituminous coal) for Entergy White 

Bluff, Unit 2; 

• Reg. 19.1505(J)(1), which establishes SO2 BART (sub-bituminous coal) for Entergy 

White Bluff, Unit 2; 

• Reg. 19.1505(J)(2), which establishes NOx BART (sub-bituminous coal) for Entergy 

White Bluff, Unit 2; 

• Reg. 19.1505(K), which provides that when burning a mix of bituminous and subbituminous coal at White Bluff Unit 2, the NOx BART limits shall be prorated using the 

percentage of each coal being used; 

• Reg. 19.1505(L), which establishes BART for Entergy White Bluff, Auxiliary Boiler; 

• Reg. 19.1505(M)(1), which establishes NOx BART (natural gas) for Entergy Lake 

Catherine Unit 4; 
95 

• Reg. 19.1505(N)(1), which establishes SO2 BART (fuel oil) for Entergy Lake Catherine 

Unit 4; 

• Reg. 19.1505(N)(2), which establishes NOx BART (fuel oil) for Entergy Lake Catherine 

Unit 4; and 

• Reg. 19.1505(N)(3), which establishes PM BART (fuel oil) for Entergy Lake Catherine 

Unit 4. 

F.3. BART for Larger Fossil Fuel Power Plants: 40 CFR 51.308(e)(1)(ii)(B) 

 A determination of BART is required for each BART-eligible source in Arkansas that 

emits any air pollutant which may reasonably be anticipated to cause or contribute to any 

impairment of visibility in any mandatory Class I Federal area. All such sources are subject to 

BART. The determination of BART for fossil-fuel fired power plants having a total generating 

capacity greater than 750 megawatts must be made pursuant to the guidelines in appendix Y of 

this part (Guidelines for BART Determinations under the Regional Haze Rule). 

State Submittal: Page 48, Appendix 9.3A

 All the facilities required to install BART are fossil-fuel fired steam electric generating 

plants, with the exception of the Domtar Kraft Pulp Mill and the Georgia-Pacific Crosett Mill, 

for which ADEQ did not evaluate BART controls. Each of the fossil-fuel fired steam electric 

generating plants that are required to install BART have a total generating capacity below 750 

MW, with the exception of the Entergy White Bluff plant. ADEQ did not confirm that it satisfied 

the requirements in Section 51.308(e)(1)(ii)(B) in preparing the BART determinations for the 

three subject to BART units at White Bluff. 

EPA Findings: Based on our evaluation of ADEQ’s BART analyses for the Entergy White 

Bluff plant, we found that ADEQ did not follow the BART Guidelines when performing the 

BART five factor analyses for the three subject to BART units at White Bluff. ADEQ’s BART 

determinations for the three White Bluff units subject-to-BART are covered in Appendix 9.3A of 

the Arkansas RH SIP. 

F.4. De Minimis BART: 40 CFR 51.308(e)(1)(ii)(C) 

A determination of BART is required for each BART-eligible source in Arkansas that emits any 

air pollutant which may reasonably be anticipated to cause or contribute to any impairment of 

visibility in any mandatory Class I Federal area. All such sources are subject to BART. Arkansas 
96 

is not required to make a determination of BART for SO2 or for NOx if a BART-eligible source 

has the potential to emit less than 40 tons per year of such pollutant(s), or for PM10 if a BARTeligible source has the potential to emit less than 15 tons per year of such pollutant. 

State Submittal: 

ADEQ did not specifically exclude any BART eligible sources under this provision. 

F.5. Design, Equipment, or Work Practice BART: 40 CFR 51.308(e)(1)(iii) 

 

If Arkansas determines in establishing BART that technological or economic limitations on the 

applicability of measurement methodology to a particular source would make the imposition of 

an emission standard infeasible, it may instead prescribe a design, equipment, work practice, or 

other operational standard, or combination thereof, to require the application of BART. Such 

standard, to the degree possible, is to set forth the emission reduction to be achieved by 

implementation of such design, equipment, work practice or operation, and must provide for 

compliance by means which achieve equivalent results. 

State Submittal: Pages 52-53

 ADEQ prescribed an operational standard as BART for the Auxiliary Boiler at White 

Bluff. ADEQ determined that BART for the Auxiliary Boiler is a restriction to operate no more 

than 4360 hours annually. 

EPA Findings: 

 As discussed in section III.F.2.4 of this TSD, ADEQ did not perform a BART analysis in 

establishing the limit on annual operating hours, as is required under the BART Guidelines and 

the RH Rule. In addition, ADEQ did not provide an explanation of why it decided to establish a 

limit on annual operating hours rather than establish an emission limit for the auxiliary boiler. It 

does not appear that ADEQ’s decision was based on technological or economic limitations on 

the applicability of measurement methodology at the source. Furthermore, ADEQ made no 

attempt to determine the degree of emission reductions that would be achieved by establishing a 

limit to operate the Auxiliary Boiler no more than 4360 hours annually. For the reasons 

described in the section III.F.2.4, we propose to disapprove ADEQ’s BART determination for 

the Auxiliary Boiler. 
97 

F.6. Installation of BART: 40 CFR 51.308(e)(1)(iv) – (v) 

 Each source subject to BART must (1) install and operate BART as expeditiously as 

practicable, but in no event later than 5 years after approval of the SIP revision, and (2) maintain 

the control equipment required by this subpart and establish procedures to ensure such 

equipment is properly operated and maintained. 

State Submittal: Pages 50-51, Appendix 9.3C 

 ADEQ’s RH rule requires each source subject to BART to “install and operate BART as 

expeditiously as practicable, but in no event later than 6 years after the effective date of this 

regulation or 5 years after EPA approval of the Arkansas Regional Haze State Implementation 

Plan, whichever comes first.”60 On March 26, 2010, the Arkansas Pollution Control and Ecology 

Commission, the environmental policy-making body for Arkansas, granted all Arkansas subject 

to BART sources a variance from the compliance deadline imposed by the State’s RH Rule, such 

that these sources are now required to comply with BART requirements no later than 5 years 

after EPA approval of the RH SIP. ADEQ’s RH Rule also provides that each source subject-toBART “shall maintain the control equipment required by this chapter and establish procedures to 

ensure such equipment is properly operated and maintained.”61

EPA Findings: 

 We find that ADEQ has demonstrated it has the authority and enforceable mechanisms in 

place to ensure each source subject to BART will (1) install and operate BART as expeditiously 

as practicable, but in no event later than 5 years after approval of the SIP revision, and (2) 

maintain the control equipment required by this subpart and establish procedures to ensure such 

equipment is properly operated and maintained. We find this satisfies ADEQ’s obligation under 

section 51.308(e)(1)(iv). 

F.7. CAIR for BART: 40 CFR 51.308(e)(2)-(3) 

                                                           

60 See Arkansas Pollution Control and Ecology Commission Reg. 19.1504(B). 

61 See Arkansas Pollution Control and Ecology Commission Reg. 19.1504(C). 
98 

 Arkansas may opt to implement or require participation in an emissions trading program 

or other alternative measure rather than require sources subject to BART to install, operate, and 

maintain BART. Such an emissions trading program or other alternative measure must achieve 

greater reasonable progress than would be achieved through the installation and operation of 

BART. 

Note: This provision of the regional haze rule does not apply to Arkansas since it did not opt to 

implement or require participation in an emissions trading program or other alternative measure 

rather than require sources subject to BART to install, operate, and maintain BART.

F.8. CAIR for BART: 40 CFR 51.308(e)(4) 

 If Arkansas chooses to meet the emission reduction requirements of the Clean Air 

Interstate Rule (CAIR) by participating in one or more of the EPA-administered CAIR trading 

programs for SO2 and NOx, it need not require BART-eligible EGUs subject to such trading 

programs in Arkansas to install, operate, and maintain BART for the pollutants covered by such 

trading programs in it. Arkansas may choose to participate in the EPA-administered CAIR 

trading programs either by submitting a SIP that incorporates the CAIR model trading rules in 

part 96 of this chapter, and is approved, in accordance with section51.123(o)(1) or (2) (for the 

NOx annual program) and (aa)(1) or (2) (for the NOx ozone season program) and section 

51.124(o)(1) or (2) (for the SO2 program) or by remaining subject to the Federal implementation 

plan in part 97 of this chapter (which may be modified by a SIP approved in accordance with 

sections 51.123(p) and (ee) and 51.124(r)). If Arkansas chooses to participate in such trading 

programs, it may also adopt provisions, consistent with such trading programs, for a geographic 

enhancement to the program to address the requirement under section 51.302(c) related to BART 

for reasonably attributable impairment from the pollutants covered by the CAIR cap-and-trade 

programs. 

Note: This provision of the regional haze rule does not apply to Arkansas because Arkansas 

decided to evaluate BART controls for its subject to BART sources instead determining that 

CAIR is better than BART since the State is in CAIR only for NOx during the ozone season. 

F.9. Reasonable Progress and BART: 40 CFR 51.308(e)(5) 

 After a State has met the requirements for BART or implemented emissions trading 

program or other alternative measure that achieves more reasonable progress than the installation 

and operation of BART, BART-eligible sources will be subject to the requirements of paragraph 

(d) of this section in the same manner as other sources. 
99 

Note: There are no BART sources that ADEQ revisited for the purposes of obtaining additional 

reductions under Section 51.308(d). 

F.10. BART Exemptions: 40 CFR 51.308(e)(6) 

 Any BART-eligible facility subject to the requirement under paragraph (e) of this section 

to install, operate, and maintain BART may apply to the Administrator for an exemption from 

that requirement. An application for an exemption will be subject to the requirements of section 

51.303(a)(2)–(h). 

Note: This provision of the regional haze rule was not used by ADEQ in the preparation of its 

RH SIP. 

G. 2018 Regional Haze SIP Revision: 40 CFR 51.308(f) 

 Each State identified in section 51. 300(b)(3),which includes Arkansas, must revise and 

submit its regional haze SIP revision to EPA by July 31, 2018 and every ten years thereafter. In 

each SIP revision, Arkansas must evaluate and reassess all of the elements required in paragraph 

(d) of this section, taking into account improvements in monitoring data collection and analysis 

techniques, control technologies, and other relevant factors. In evaluating and reassessing these 

elements, Arkansas must address the following: 

(1) Current visibility conditions for the most impaired and least impaired days, and actual 

progress made towards natural conditions during the previous implementation period. 

The period for calculating current visibility conditions is the most recent five year period 

preceding the required date of the SIP submittal for which data are available. Current 

visibility conditions must be calculated based on the annual average level of visibility 

impairment for the most and least impaired days for each of these five years. Current 

visibility conditions are the average of these annual values. 

(2) The effectiveness of the long-term strategy for achieving reasonable progress goals over 

the prior implementation period(s); and 

(3) Affirmation of, or revision to, the reasonable progress goal in accordance with the 

procedures set forth in paragraph (d)(1) of this section. If Arkansas established a 

reasonable progress goal for the prior period which provided a slower rate of progress 

than that needed to attain natural conditions by the year 2064, it must evaluate and 
100 

determine the reasonableness, based on the factors in paragraph (d)(1)(i)(A) of this 

section, of additional measures that could be adopted to achieve the degree of visibility 

improvement projected by the analysis contained in the first SIP described in paragraph 

(d)(1)(i)(B) of this section. 

State Submittal: ADEQ acknowledged this requirement on page 76 of its RH SIP.

H. Five Year Progress Report 40 CFR 51.308(g) 

 Each State identified in section 51. 300(b)(3), which includes Arkansas, must submit a 

report to the Administrator every 5 years evaluating progress towards the reasonable progress 

goal for each mandatory Class I Federal area located within it and in each mandatory Class I 

Federal area located outside it which may be affected by emissions from within it. The first 

progress report is due 5 years from submittal of the initial SIP addressing paragraphs (d) and (e) 

of this section. The progress reports must be in the form of SIP revisions that comply with the 

procedural requirements of section 51.102 and section 51.103. Periodic progress reports must 

contain at a minimum the following elements: 

(1) A description of the status of implementation of all measures included in the SIP for 

achieving reasonable progress goals for mandatory Class I Federal areas both within and 

outside Arkansas. 

(2) A summary of the emissions reductions achieved throughout Arkansas through 

implementation of the measures described in paragraph (g)(1) of this section. 

(3) For each mandatory Class I Federal area within Arkansas, it must assess the following 

visibility conditions and changes, with values for most impaired and least impaired days 

expressed in terms of 5-year averages of these annual values. 

(i) The current visibility conditions for the most impaired and least impaired days; 

(ii) The difference between current visibility conditions for the most impaired and 

least impaired days and baseline visibility conditions; 

(iii)The change in visibility impairment for the most impaired and least impaired days 

over the past 5 years; 

(4) An analysis tracking the change over the past 5 years in emissions of pollutants 

contributing to visibility impairment from all sources and activities within Arkansas. 
101 

Emissions changes should be identified by type of source or activity. The analysis must 

be based on the most recent updated emissions inventory, with estimates projected 

forward as necessary and appropriate, to account for emissions changes during the 

applicable 5-year period. 

(5) An assessment of any significant changes in anthropogenic emissions within or outside 

Arkansas that have occurred over the past 5 years that have limited or impeded progress 

in reducing pollutant emissions and improving visibility. 

 

(6) An assessment of whether the current SIP elements and strategies are sufficient to enable 

Arkansas, or other States with mandatory Federal Class I areas affected by emissions 

from it, to meet all established reasonable progress goals. 

(7) A review of Arkansas visibility monitoring strategy and any modifications to the strategy 

as necessary. 

State Submittal: ADEQ acknowledged this requirement on page 76 of its RH SIP. 

I. Existing SIP Adequacy Determination 40 CFR 51.308(h) 

 At the same time Arkansas is required to submit any 5-year progress report to us in 

accordance with paragraph (g) of this section, it must also take one of the following actions 

based upon the information presented in the progress report: 

(1) If Arkansas determines that the existing SIP requires no further substantive revision at 

this time in order to achieve established goals for visibility improvement and emissions 

reductions, it must provide to the Administrator a negative declaration that further 

revision of the existing SIP is not needed at this time. 

(2) If Arkansas determines that the SIP is or may be inadequate to ensure reasonable progress 

due to emissions from sources in another State(s) which participated in a regional 

planning process, it must provide notification to the Administrator and to the other 

State(s) which participated in the regional planning process with the States. Arkansas 

must also collaborate with the other State(s) through the regional planning process for the 

purpose of developing additional strategies to address the plan’s deficiencies. 

(3) Where Arkansas determines that the SIP is or may be inadequate to ensure reasonable 

progress due to emissions from sources in another country, it shall provide notification, 

along with available information, to the Administrator. 
102 

(4) Where Arkansas determines that the SIP is or may be inadequate to ensure reasonable 

progress due to emissions from sources within the State, the State shall revise its SIP to 

address the plan’s deficiencies within one year. 

State Submittal: ADEQ acknowledged this requirement on page 77 of its RH SIP. ADEQ 

stated it intends to use the findings of the five-year progress report required under section 

51.308(g) to make a determination regarding the adequacy of this RH SIP and take an 

appropriate action based upon the requirements of Section 51.308(h). 

J. Federal Land Manager Coordination 40 CFR 51.308(i) 

(1) By November 29, 1999, Arkansas must identify in writing to the Federal Land Managers 

the title of the official to which the Federal Land Manager of any mandatory Class I 

Federal area can submit any recommendations on the implementation of this subpart 

including, but not limited to: 

(i) Identification of impairment of visibility in any mandatory Class I Federal 

area(s); and 

(ii) Identification of elements for inclusion in the visibility monitoring strategy 

required by section 51.305 and this section. 

(2) Arkansas must provide the Federal Land Manager with an opportunity for consultation, 

in person and at least 60 days prior to holding any public hearing on a SIP (or plan 

revision) for regional haze required by this subpart. This consultation must include the 

opportunity for the affected Federal Land Managers to discuss their: 

(i) Assessment of impairment of visibility in any mandatory Class I Federal 

area; and 

(i) Recommendations on the development of the reasonable progress goal and on 

the development and implementation of strategies to address visibility 

impairment. 

(3) In developing any SIP (or plan revision), Arkansas must include a description of how it 

addressed any comments provided by the Federal Land Managers. 
103 

(4) The SIP (or SIP revision) must provide procedures for continuing consultation between 

Arkansas and Federal Land Manager(s) on the implementation of the visibility protection 

program required by this subpart, including development and review of SIP revisions and 

5-year progress reports, and on the implementation of other programs having the 

potential to contribute to impairment of visibility in mandatory Class I Federal areas. 

State Submittal: Page 14 

 Under Section 51.308(i)(2), Arkansas was obligated to provide the USDA Forest Service 

with an opportunity for consultation, in person and at least 60 days prior to holding a public 

hearing on it RH SIP. In practice, state environmental agencies have usually provided all FLMs – 

the Forest Service, the Park Service, and the Fish and Wildlife Service, copies of their RH SIP, 

as the FLMs collectively have reviewed these RH SIPs. ADEQ followed this practice and sent its 

draft of this implementation plan revision to the FLM staff on February 22, 2008 and notified the 

federal land manager staff of the public hearing held on July 7, 2008. 

 Section 51.308(i)(3) requires that ADEQ provide in its RH SIP a description of how it 

addressed any comments provided by the FLMs. ADEQ has provided that information in 

Appendix 2.1 of its RH SIP. 

 Lastly, Section 51.308(i)(4) specifies the RH SIP must provide procedures for continuing 

consultation between the State and FLM on the implementation of the visibility protection 

program required by section 51.308, including development and review of implementation plan 

revisions and 5-year progress reports, and on the implementation of other programs having the 

potential to contribute to impairment of visibility in the mandatory Class I Federal areas. ADEQ 

has stipulated in its RH SIP it will continue to coordinate and consult with the FLMs as required 

by section 51.308(i)(4). ADEQ states it intends to consult the FLMs in the development of 

future progress reports and plan revisions, as well as during the implementation of programs 

having the potential to contribute to visibility impairment at Caney Creek and Upper Buffalo. 

We find that ADEQ has satisfied section 51.308(i). 

EPA Findings: 

 Caney Creek and Upper Buffalo are both managed by the USDA Forest Service, which is 

the Federal Land Manager (FLM) for these two Class I areas. Although the FLMs are very active 

in participating in the RPOs, the RH Rule grants the FLMs a special role in the review of the RH 

SIPs. We view both the FLMs and the state environmental agencies as our partners in the RH 

process. 
104 

 We acknowledge that Section 51.308(i)(1) has been satisfied by all states via 

communication prior to this SIP. We find that ADEQ has satisfied the requirements of Section 

51.308(i)(2)-(3) by providing the FLMs with a with an opportunity for consultation, in person 

and at least 60 days prior to holding any public hearing on its RH SIP, and ADEQ has addressed 

the FLM comments in its SIP. Further, we find that ADEQ has satisfied Section 51.308(i)(4) by 

committing to continuing consultation between the State and the FLMs on the implementation of 

the visibility protection program required by Section 51.308(i), including the development of 

future progress reports and plan revisions, as well as during the implementation of programs 

having the potential to contribute to visibility impairment at Caney Creek and Upper Buffalo.