## 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 2011ii 

### 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 Pr ogress 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 Vi sibility Conditions

.......................................... .................................... 20 C.1. Calculation of Baselin e Conditions: 40 CFR 51.308(d) (2)(i) ............ ................................ 20 C.2. Calculation of Natural Visi bility Conditions: 40 CFR 51.308(d)(2)(iii) ........................... 23 C.3. Natural Visibility Impair ment: 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 Wo rk 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) .......................................................... 102iii 

### 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 Iden tified 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 Contro l Options for Lake Catherine Unit 4- Fuel Oil Firing............................................................................ 66
Table 14. Visibility Impact of NOx Contro l Options for Lake Catherine Unit 4- Gas Firing ............................................................................... 66
Table 15. Visibility Impact of NOx Contro l Options for Lake Catherine Unit 4- Gas Firing .................................................................................. 67
Table 16. Cost-Effectiveness of SO 2 Control Options for Lake Catherine

Unit 4- Fuel Oil Firing ........................................................................... 70
Table 17. Visibility Impact of SO 2 Control Options for Lake Catherine

Unit 4- Fuel Oil Firing

.................. .......................................................... 70
Table 18. Cost-Effectiveness of SO 2 Control Options for Entergy White Bluff Unit 1

................... ............................................................................ 73
Table 19. Cost-Effectiveness of SO 2 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 SO 2 , 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)........................................ 90iv 

### 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 I nventory Development for the Regional Haze Implementation Plan for the State of Arkansas5 Arkansas Regional Haze Technical Support Document (TSD)

I. Relationship of this TSD to our Proposal

We are proposing to partially approve and pa rtially disapprove a re vision 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 addr esses regional haze (RH) for the first implementation period.

Specifically, we are proposing to approve th e following: the Stat e’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) c onsultation; the regional haze m onitoring strategy and other SIP requirements under section 51.308(d)(4); the Stat e’s commitment to submit periodic regional haze SIP revisions and periodic progress repor ts 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 Stat e’s identification of BART eligible sources, with the exception of the 6A Boiler at the Geor gia-Pacific Crossett Mill , which we find to be BART eligible. We are proposing to approve th e State’s identification of subject to BART sources, with the exception of the 6A and 9A Boile rs at the Georgia-Pacific Crossett Mill, which we find to be subject to BART. We ar e 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 SO 2 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-b ituminous 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 SO 2 , NOx, and PM, BART determinations for both Unit 1 of the Arkansas Electric Coope rative Corporation (AECC) Bailey plant and Unit 1 of the AECC McClellan plant; the SO 2 and NOx BART determinations for the No. 1 Boiler of the AEP Flint Creek plant; the NOx BART determination fo r the natural gas firing scenario and the SO 2 , NOx,
and PM BART determinations for the fuel oil firing scenario for Unit 4 of the Entergy Lake Catherine plant; the SO 2 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 SO 2 and NOx
BART determinations for the No. 1 Power Bo iler of the Domtar As hdown Mill; and the SO 2 , NOx, and PM BART determinations for the No. 2 Power Boiler of the Domtar Ashdown Mill. We are proposing to disapprove these BART dete rminations 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 revisi ng several chapters of APC&E Commission Regulation 19, including Chapte r 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 porti ons of the Arkansas RH SIP we are proposing to approve and we are proposing to disapprove the por tions that are consistent with other portions of the Arkansas RH SIP we are proposing to disa pprove. We are proposing to pa rtially approve and partially disapprove the State’s LTS because the LTS onl y 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 RP Gs 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 s upports our proposal. Appendix A to this TSD contains a report describing our review of th e 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 ba sis for this action when needed.
In some of the non-technical area s, our Federal Register notice pr ovides more detail than does this TSD. Also, this TSD treats the requirement s of section 51.308 in the order in which they appear in that regulation, wh ereas our Federal Register notic e groups the requirements into related areas so the concepts can be understood more easily. In th is 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 sp ecific portions of the Arkansas RH SIP th at 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 woul d 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 ma y 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 Fede ral Class I areas which calls for the “prevention of any future, and the remedying of any existing, impairment of vi sibility 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 define d 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 Cl ass I areas within Arkansas, the Caney Creek Wilderness Area and the Upper Buffalo Wild erness Area, are depicted in Figure 2.

Figure 1. Map of Class I Areas 79 Figure 2. Location of the Cl ass I Areas in Arkansas

On December 2, 1980, we promulgated regulati ons 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 addre ssing 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 polluta nts 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 ph ase 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 consultati on 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 (PM 2.5 ). We promulgated PM 2.5 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. Conseque ntly, all 50 states, including those without Class I areas, Washington, D.C., and the Virgin Islands, were required to submit Region al 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, a nd 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 ag ency, ADEQ, chose to par ticipate 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 revi ewed 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 di scussed 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 Atta inment of Air Quality Goals for PM 2.5 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 Emi ssion Inventory SIP Planning: 8-Hour Ozone, PM2.5 and Re gional Haze Programs, da ted 11/18/2002, from Lydia Wegman to the Regional Air Directors. ” 8. Guidance for Setting Reasonable Progress Go als Under the Regional Haze Program, dated June 1, 2007. 9. Visibility Monitoring Guid ance, EPA-454/R-99-003, June 1999. 10. Emissions Inventory Guidance for Implementation of Ozone and Particulate Matter National Ambient Air Quality Standards (NAA QS) 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 Contro l and Ecology Commission for approval. The
State of Arkansas has two federal Class I areas within its borders. These are the 14,460 acre12 Caney Creek Wilderness in Ouachita National Forest at Polk County and the 11,801 acre Upper
Buffalo Wilderness in the Ozar k National Forest at Newton C ounty, 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 W ilderness (Hercules Glades) in the Mark Twain National Forest, located in Ta ney County Missouri, approximately 25 miles (40 km) north of Boone County Arkansas; and the 8,000 acre Mingo Nati onal Wildlife Refuge (Mingo) located in Wayne and Stoddard Counties, approximately 30 miles (48 km) north of Clay County, Arkansas. The respective FLMs are the US DA 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 reduc tions that would help
Missouri achieve its RPGs for Hercules Glades and Mingo. We find th at 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 progr ess towards achieving natural visibility conditions. The reas onable 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 impair ed days over the same period.

State Submittal: Pages 58-66, Appendix 8.1

ADEQ adopted the CENRAP modeled 2018 visib ility 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 represen ts 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 improve ment in visibility over a baseline of 26.2713 dv. ADEQ calculated thatunder its RPGs, it would attain na tural visibility conditions in 2062 for Caney Creek and 2063 for Upper Buffalo. AD EQ’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 G oals 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, whic h is adapted from Figures 10.4 and 10.6 of the RH SIP, and Figures D-1b and D-2b of Appendi x 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 Progre ss 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 towa rds 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 “w orst” 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 improve ment 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 show n 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 fo r any mandatory Class I Federal area within Arkansas, ADEQ must consider the costs of comp liance, the time necessary for compliance, the energy and non-air quality environmental impacts of compliance, and the re maining useful life of any potentially affected sources, and include a dem onstration 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 esta blish 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 aff ected 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 St ate’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 progr ess.” 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 consider ing 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 m eeting the URP to justify the conclusion that its16 goals provide for reasonable progress. ADEQ made no attempt to determine whether additional progress would be reasonable based on the statutory f actors. 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 vi sibility 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 cont ributors to visibility impairment in 2018 and thus providing further support that additional analysis sh ould 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 ev aluate the potential of c ontrolling certain sources or source categories for addressing visibility imp acts from man-made sources, it is not possible assess whether any additional control measures fo r 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 ra te of progress needed to attain natural visibility17 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 antic ipated 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 establ ished 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 determin ed 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 Trac king Progress Guidance by plotting a straight graphical line from the baseline level of vi sibility impairment for 2000-2004 to the level of visibility conditions represen ting 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 impl ementation period in orde r to attain natural visibility conditions by 2064. We are proposing to find that Arkansas has appropriately
calculated the URP and has sa tisfied 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 esta blishes 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 th e 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, Ar kansas 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 re viewing 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. C onsultations were held jointly by Arkansas and Missouri. ADEQ used CENRAP as the main ve hicle 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 resu lts and visibility proj ections, and source apportionment modeling to assist in identifying nei ghboring states’ contributions to the visibility impairment at Caney Creek and Upper Buffalo.

ADEQ determined that, in addition to Arkans as, the following states have a significant contribution to decreased visibility in one or bot h 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 participat ed 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 (RPO s), EPA, and FLMs.

At the three consultations held jointly by ADEQ and MDNR, a URP was developed for
each Class I area in Arkansas a nd Missouri (Caney Creek and U pper Buffalo in Arkansas, and Hercules Glades and Mingo in Missouri). The part icipating states also de termined that CENRAP visibility projection modeling a nd 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 progr ess goals for the first implementation period ending in 2018. Therefore, ADEQ and MDNR determined that projected
emissions reductions from those st ates having a significan t contribution to decr eased visibility at
the two Class I areas in Arkansas and the two Cla ss 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 Ar kansas’ RPGs, we propose to find that
Arkansas has met the state cons ultation requirements under section 51.308(d)(1)(iv) since ADEQ satisfied the minimum requirement of consulting with other states and all st ates participating in the consultation agreed that the goals estab lished 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 progre ss goals established by the State are not directly enforceable but will be considered by the Administrator in20 evaluating the adequacy of the measures in th e SIP to achieve the pr ogress 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 be tween the 2002 base year and the 2018 future year. These projections are based on an assessment of th e 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 im provement 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, St ate, and federal control programs that are either currently in effect or with mandated future-year emission re duction schedules, ADEQ’s RPGs represent at least as much visibility improvement as is expe cted to result from implementation requirements of the CAA during the a pplicable planning period. We propos e 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 be21 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 fo r the best and worst days at the time the regional haze program is established. Ba seline conditions are calculated using multiyear averaging of the 20 percent of monitored days wi th 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 extinct ion 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 visibilitydegradation and increases as visibility is degraded. The deciview scale was designed simila r 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, b ecause 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 e xpressed 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 measur ed. ADEQ calculated its baseline conditions in accordance with our 2003 Natural Visibility Guidance, 2 as required by the RHR. The baseline condition calculation begins w ith the calculation of light extinction, using the IMPROVE equation. The IMPROVE equation sums the light ex tinction 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 Vi sibility Conditions Under the Regiona l Haze Program, EPA-454/B-03-005, September 2003.22 purpose of this refinement is to provide more accura te 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 partic ulate matter: sulfurous, nitrate, organic carbonaceous, elemental “ light-absorbing” carbonaceous, fine soil, chlorine or chloride, and coarse matter. The equation also account s for Rayleigh scattering of light and for deliquescence on sulfurous, nitrate, and chlorine or chloride partic ulates with an estimate of particle-bound water as a function of relative humidity. It reflects the most recent review of the
science 3 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 li ght absorption by gaseous nitrogen dioxide. Sitespecific values are used for Rayleigh scattering (s cattering of light due to atmospheric gases) to account for the site-specific effects of elevati on and temperature. Separate relative humidity enhancement factors are used for small and larg e 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 ma ss terms, do not change between the original and new IMPROVE equations.

As with the natural visi bility conditions calculation, ADEQ chose to use the new IMPROVE equation. The choice between use of th e 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 becau se 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 visibi lity 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 IM PROVE 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), Colo rado State University, Cooperative Institute for Research in the Atmosphere, Fort Collins, Colorado. http://vista.cira.colostate.edu/improve/publicatio ns/GrayLit/016_IMPROVEeqR eview/IMPROVEeqReview.htm ; and Pitchford, Marc., 2006 , Natural Haze Levels II: Application of th e 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_Nat uralCondII/naturalhaz elevelsIIrenatu.ppt23 2002. ADEQ did not indicate whethe r 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 base line 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:

β ext = β ext S + β ext NO3 + β ext organic + β ext elemental + β ext Soil + β ext coars e+ β ext Cl + β ext Rayleigh

ADEQ then converted the tota l light extinction values to deciviews (dv), using the Haze Index (HI) equation:

HI (dv) = 10 ln[ β ext/(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 cal culated 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 vi sibility 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 extinc tion 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 the25 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 fo r 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 reas onably 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 coor dinated 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 facilitatin g collaboration with FLMs and other states in satisfying its LTS consultation requirement. Th is 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 a nd 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 dem onstrates Arkansas sources are responsible for a visibility extinction of appr oximately 7.1 inverse megameters 4 (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 elsewher e in this proposed notice, ADE Q 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 th at Arkansas consult with ot her states if its emissions are reasonably anticipated to contribu te to visibility impairment at that state’s Class I area(s), and
that Arkansas consult with other states if their emissions are reasonably an ticipated to contribute to visibility impairment at Caney Creek and Upper Buffalo. In addi tion to Arkansas, ADEQ determined that Illinois, Indiana, Kentucky, Missouri, Ohio, Oklahoma, Tennessee, and Texas contribute to visibility impair ment 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 (d v) can be calculated from extinction data as follows: dv = 10 x ln (b ext (Mm -1 )/10), where dv stands for “decivi ews;” ln stands for “natural logarithm;” and b ext stands for “extinction value.”.

5 See Appendix E of the TSD for CENRAP Emissions an d 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 visi bility at its own two Class I areas , sources in Arkansas also have a visibility impact on Missouri’s two Class I ar eas (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 outco me of the consultations, we ar e proposing to find that ADEQ’s consultations satisfy the require ments 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 impa irment 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 m eet 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 obliga tions agreed upon th rough that process.

State Submittal: Page 69

In developing its Regional Haze SIP and RPGs , Arkansas and potentially impacted States collaborated through CENRAP. Arkansas develo ped 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 measur es needed to achieve its apportionment of emission reduction obligations agreed upon thro ugh the CENRAP regional planning process. Emissions reductions resulting from BART controls on Arkansas subject to BART sources were part of the emission reductions Arkansas comm itted to and these were factored into the CENRAP modeling. Compliance with these BART c ontrols will ensure that Arkansas obtains its
share of the emission reductions relied upon by other states to m eet 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, an d since we are proposing to disapprove the portion of the RH SIP which includes some of Ar kansas’ BART determina tions, 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 rely ing to determine its a pportionment of emission reduction obligations necessary for achieving r easonable 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 organi zation and approved by all State participants. Arkansas must identify the baseline emissions inventory on which its strategi es 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 visi bility 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 fo llowing 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 th e work that was done and our conclusions. For a
more detailed discussion of th e technical analyses including the photochemical modeling and our review and conclusions concerning what polluta nts 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 contract or 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 gr owth and control factors derived from the EGAS6, MOBILE6, and NONROAD models and appl ying reductions expected from federal and state regulations affecting th e emissions of the visibility -impairing pollutants NOx, PM, SO 2 ,, and VOCs. The Integrated Planning Model (IPM) was used to forecast 2018 electric generating unit (EGU) emissions. The BART Gu idelines direct states to ex ercise 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 demonstr ated that anthropogenic emi ssions of VOC and NH3 do not significantly impair visi bility in the CENRAP region. Theref ore, 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 inventor y 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 em issions inventory in-house a nd 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, degr easing, and industrial surface coating), gasoline distribution, aspha lt paving, and fires and open burning (e.g., agricultural burning, structural fires, wildfires, prescribed burning). In addition, area source categories contributing to visibi lity pollutants (i.e., PM10, PM2.5, and NH3) are also included in the area source emissions inventory (e.g., fugitiv e dust, agricultural operations, livestock ammonia, etc.). The contractor reviewed all emissi on factors used in the i nventory 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 includ ed 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 pe r mile (g/mile), with vehicle miles traveled (VMT) activity data. County-le vel Highway Performance Monitoring System (HPMS) VMT
data were used for all Arkansas counties. The Arkansas Highway and Tr ansportation 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 road way type and vehicle ty pe and vehicle class.

The 2002 nonroad mobile source emissions en compassed 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 so urces. 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, construc tion 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 separate ly 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 re sponsible for identifying point sources meeting the threshold criteria, collecting facility emissions data, processing and30 managing data, and compiling and displaying the re sults. Actual measurement with continuous emissions monitoring systems (CEMS) is the de sired 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 fact ors. 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 de veloped by EPA. Arkansas 2002 emissions inventory is summari zed in Table 4:

Table 4. Arkansas’ 2002 Emissions Inventory

SO 2 NH 3 NOx VOCs PM 10 - PM 2.5 PM 2.5

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 Mode l (IPM) for electric generating units.

CENRAP developed emissions for five invent ory source classifications: point, area, nonroad and on-road mobile sources, and bioge nic 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 combusti on engines and other non-EGU point sources. CENRAP states provided data for the area sour ce 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 for31 2018. This accounted for estimated growth in equipment populations and incorporated anticipated effects of most fi nal federal standards, includi ng 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 engi nes. ADEQ and CENRAP also developed the on-road mobile source emissi ons inventory for 2018 with contractor support. Biogenic emissions were held constant fr om the 2002 emission inventory. Arkansas’ 20018 emissions inventory is summarized in Table 5.

Table 5. Arkansas’ 2018 Emissions Inventory

SO 2 NH 3 NOx VOCs PM 10 - PM 2.5 PM 2.5

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 em ission 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 H aze SIP discusses the modeling methods and protocol used by CENRAP and ADEQ in devel oping the assessment. Section 8.1 describes the baseline emission inventory used by CENRAP in the Arkansas an alysis. A detailed description and discussion of the model selection, modeli ng 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 refere nces 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 tec hnical evaluation that be gan with selection of the modeling system. CENRAP used the following modeling system:

• Meteorological Model: The Pennsylvania St ate University/National Center for Atmospheric Research (PSU/NCAR) Meso scale Meteorological Model (MM5) is a nonhydrostatic, prognostic meteorological model r outinely used for urban- and regionalscale photochemical, PM2.5, and regional haze regulatory modeling studies.

• Emissions Model: The Sparse Matrix Oper ator Kernel Emissions (SMOKE) modeling system is an emissions modeling system that generates hourly gridded speciated emission inputs of mobile, non-road mobile, area, poi nt, fire and biogenic emission sources for photochemical grid models.

• Air Quality Model: EPA’s M odels-3/ Community Multisc ale Air Quality (CMAQ) modeling system is a photochemical grid model capable of addressing ozone, PM, visibility and acid de position at a regional scale. The photochemical model selected for this study was CMAQ version 4.5. It was modi fied through CENRAP with a module for Secondary Organics Aerosols (SOA) in an open and transparent ma nner that was also subjected to outside peer re view. The Comprehensive Air Qu ality Model with extensions (CAMx) Version 4.40 model, applied using si milar 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 pr ovide source apportionment of predicted
nitrate and sulfate aero sol concentrations.

CMAQ and CAMx modeling of regional h aze in the CENRAP region for 2002 and 2018 was carried out on a grid of 36x36 kilometer (km) cel ls that covers the co ntinental United States, portions of Canada and Mexico, and portions of the Atlantic a nd Pacific Oceans along the east and west coasts. Selection of a representative period of meteorology is crucial for evaluating baseline air quality conditions a nd projecting future changes in air quality due to changes in emissions of visibility-impairing pollutants. CE NRAP conducted an in-depth analysis which
resulted in the selection of the entire year of 2002 (January 1-D ecember 31) as the best period of meteorology available for conducting the m odeling. 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/gu ide/final-03-pm-rh-guidance.pdf See also “Emissions Inventory Guidance for Implementa tion of Ozone and Particulate Matter National Ambient Air Quality Standards (NAAQS) and Regional Haze Regulations,” August 2005, updated Nove mber 2005 (“our Modeling Guidance ” ), located at http://www.epa.gov/ttnchie1/eidocs/eiguid/index.html, EPA-454/R-05-00133 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 a nd 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 base d on ambient measurements of PM species, gas-phase species and wet deposition from vari ous 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 us ed the model to assess the 2018 RPGs using the current and future year air quality modeling predicti ons, 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-Gl ades and Mingo). Outside of Arkansas and Missouri, the largest contribution from Arkansas sources is at th e 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 c ontribute a small amount of visibility degradation
at Class I areas in other states listed in Tabl e 6. Table 6 summarizes the projected contribution from Arkansas emissions on visibility degrada tion 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 Emissi ons to Total Visibility Impairment at Class I areas on 20% Worst Days 8

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 an d 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 ar e 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 docum ented the technical basis, including modeling, monitoring, and emissions information, on which it relied upon to determin e 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 developi ng 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 comp liance 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 pollu tants are driving regional haze in Cane y Creek and Upper Buffalo are found in Appendix A to this TSD.35 (E) Smoke management techniques for agricultu ral and forestry management purposes including plans as currently exist wi thin 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 addr essed by the long- term strategy.

State Submittal Pages 70-75

In addition to its BART determinations, Ar kansas’ LTS incorporat es emission reductions due to a number of ongoing air pollution control programs. This includes enforceable emissions limitations, compliance schedules, administrativ e orders, the issuance and enforcement of permits limiting emissions from all known majo r sources in Arkansas, state rules which specifically limit targeted emissions sources and categories, and several other ongoing air pollution control programs. ADEQ ha s promulgated rules in order to administer these programs.

ADEQ addresses the long term strategy factor s 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 attribut able visibility impairment

In developing its LTS, Arkansas consider ed a number of polluti on control programs required under federal re gulations. These include EPA’s Clean Air Interstate Rule (CAIR), which was expected to cap Ar kansas’ ozone season trad ing budget for annual NOx allocations at 9,596 tons by 2015; 10 the federal Tier 2 Vehicl e Emission Standards for passenger cars and light trucks, which were fully implemented in 2007, and similar rules for heavy trucks that are schedul ed to be implemented by 2009; and the Highway Diesel and Nonroad Diesel Rules, which ma ndate 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 unla wful, and vacated CA IR. However, the Court subsequently remanded CAIR to EPA without vacatur. The CAIR requi rements 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 Wate r and Air Pollution Contro l Act does not apply to land clearing, land gr ading, or road construction operations, ADEQ has limited opportunities to mitigate air emissions resu lting from construction activities. However, ADEQ notes the federal General Conformity program requires assessm ent of the potential impacts of any construction -related emissions of criteria pollu tants 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 wo rks 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 dire cted to fleet managers and equipment suppliers as a means of subsidizing diesel retr ofits and the biodiesel market.

3. Emissions limitations and schedules for compliance to achieve the reasonable progress goal

ADEQ implements an air permitting pr ogram that includes the issuance of permits to all known major point sources in Arkans as. Each permit contains enforceable limitations on emissions of various pollutants, some of which may cause or contri bute to regional haze at Caney Creek and Upper Buffalo. ADEQ determined that ongoing State and federal air pollution control programs are suffi cient to meet RPGs thr ough 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 repl acement schedules

ADEQ stated retirement and replacement will be managed in conformance with exis ting SIP requirements pertaini ng to the Prevention of Significant Deterioration (PSD) and the New Source Review (NSR) programs. ADEQ noted source retirement and repl acement will be tracked through on-going point source
inventories.

5. Smoke management techniques for agricultura l and forestry management purposes including plans as currently exi st within the Stat e 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 and37 certain agricultu ral 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 assu re that prescribed fires ar e planned and executed in a manner designed to minimize imp acts associated with the sm oke 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 impa cts in Class I areas are avoided.

6. Enforceability of emissions li mitations and control measures

ADEQ has ensured th at all emission limitations and contro l measures used to meet RPGs are enforceable by in corporating these into State regulations. 12 Chapter 15 of Regulation
No. 19 of the Arkansas Pollution Control and Ecology Commissi on contains the BART requirements for all subject-to-BART sources in Arkansas. ADEQ has also committed to issuing enforceable Part 70 air quali ty 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 lim its referenced above within five years of our approval of the RH SI P, as required by sec tion 51.308(e)(1)(iv).

7. The anticipated net effect on vi sibility due to projected chan ges 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 mo deling 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. CENR AP’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 ar e discussed in Appendix A to this TSD.

EPA Findings: Our evaluation of whether ADEQ properly considered the fact ors 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 attribut able visibility impairment

Section 51.308(d)(3)(v)(A) re quires 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 EP A’s Clean Air Interstate Rule (CAIR), which was expected to cap Arkansas’ ozone seas on trading budget for annua l NOx allocations at 9,596tons by 2015. Consistent with EPA guidance and regula tions (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 requiremen ts 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, EP A finalized the Transport Ru le, 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 BA RT or for attaining the in-state em issions reductions necessary to
ensure reasonable progress. Instead, Arkansas evaluate d controls for its potential BART
sources. Arkansas made BART dete rminations 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 improvement s in visibility than those predicted from CAIR at
Class I areas in Arkansas. As a resu lt, we do not expect the rema nd of CAIR to have a significant negative effect on the ability of Arkansas’ LTS to ensu re that Caney Creek and Upper Buffalo meet the RPGs in the State’s RH SIP. We note th at 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 Cla ss 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 Clas s I areas is in jeopardy, the State will be required to
address this circ umstance in its five year review

ADEQ also considered the Tier 2 Vehicle Emission Standards in developing its LTS.
Federal Tier 2 Vehicle Emission Standa rds for passenger cars and light trucks were fully implemented in 2007 and similar rules for heavy trucks were sche duled to be implemented by 2009. These federal standards will result in reductions of emissions of PM, ozone precursors, and non-methane or ganic compounds. In devel oping its LTS, ADEQ also considered the Highway Diesel a nd Nonroad Diesel Rules, wh ich mandated the use of lower sulfur fuels in diesel engi nes 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 a llowing the installation of c ontrol devices that were technically infeasible for fuels with higher sulfur content.39 Section 51.308(d)(3)(v)(A) also requires that Arkansas co nsider measures to address reasonably attributable visibility impairm ent (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 vist as in Arkansas. In addition, Cane y Creek and Upper Buffalo are not experiencing RAVI, nor are any Arka nsas sources affected by the RAVI provisions. For this reason, the Arkansas RH SIP does not incorporate any meas ures to specifically
address RAVI.

We are proposing to find that ADE Q 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 construc tion activities. Construction-related activities
are believed to be a small contributor to fine and coarse particul ates. ADEQ addressed how it considered measures to mitigate the impacts of construction activities in developing its LTS. We are proposing to find th at ADEQ properly addresse d the requirements of section 51.308(d )(3)(v)(B) in the deve lopment 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 co mpliance for those sources subject to BART: the AECC Bailey Unit 1; the AECC McClel lan 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, a nd since we are proposing to disapprove a portion of ADEQ’s BART determinations, we ca nnot propose to approve this element of the LTS. We are proposing to find that ADE Q has not satisfied the requirement of section 51.308(d)(3)(v)(C) in the development of its LTS.40 4. Source retirement and repl acement schedules

Section 51.308(d)(3)(v)(D) requires that in developing its LTS, Arka nsas consider source retirement and replacement sche dules. 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 th e requirements of section 51.308(d)(3)(v)(D) in the development of its LTS.

5. Smoke management techniques for agricultura l and forestry management purposes including plans as currently exi st within the Stat e for these purposes

Section 51.308(d)(3)(v)(E) requires th at in developing its LTS, Ar kansas consider smoke management techniques for agri cultural and forestry management purposes. ADEQ considered smoke management techni ques for the purposes of ag ricultural and forestry management in its LTS, including a State smoke management program. We are proposing to find that ADEQ properly addre ssed the requirements of s ection 51.308(d)(3)(v)(E) in the development of its LTS.

6. Enforceability of emissions li mitations and control measures

Section 51.308(d)(3)(v)(F) requires th at in developing its LTS, Arkansas consider the enforceability of emissions limita tions and control measures. ADEQ has ensured the enforceability of emission limitations a nd control measures that are being used to meet the State’s RPGs for Caney Creek a nd Upper Buffalo. We are proposing to find that ADEQ properly addressed the re quirements of section 51.308(d)(3)(v)(F) in the development of its LTS.

7. The anticipated net effect on vi sibility due to projected chan ges in point, area, and mobile source emissions over the period addressed by the long-term strategy.

Section 51.308(d)(3)(v)(G) requires th at 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 peri od 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 addre ssed the requirements of s ection 51.308(d)(3)(v)(G) in the development of its LTS.

Conclusion: We are proposing to partially approve and partia lly disapprove Arkansas’ LTS. Because we are proposing to disapprove some of ADEQ’s BART determinations, we are also41 proposing to disapprove the corresponding emissi on limits and schedules of compliance that Arkansas relied on as part of its LTS. With th e exception of this element, the LTS satisfies the requirements of 40 CFR 51.308(d)(3), and we are proposing to appr ove these remaining
elements.

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

Arkansas must submit with the SIP a mon itoring strategy for meas uring, characterizing, and reporting of regional haze visibility impairment that is representative of all mandatory Class I Federal areas within it. This monitoring stra tegy 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 part icipation in the Interagency Monitoring of Protected Visual Environments (IMPROVE) ne twork. The SIP must also provide for the following:

(i) The establishment of any addi tional monitoring sites or equipment needed to assess whether reasonable progress goals to addre ss regional haze for all mandatory Class I
Federal areas within Arkans as are being achieved.

(ii) Procedures by which monitoring data and othe r information are used in determining the
contribution of emissions from within Arkans as 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 dete rmining 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 manda tory 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 pollutant s 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 upda te the inventory periodically.42 (vi) Other elements, including reporting, recordk eeping, and other measures, necessary to assess and report on visibility.

State Submittal: Pages 8-10, 119

Section 51.308(d)(4) requires the SIP c ontain a monitoring strategy for measuring, characterizing, and reporting of regional haze visibil ity 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 Sect ion 51.305 for reasonably attr ibutable visibility impairment. As Section 51.308(d)(4) notes, comp liance with this requirement may be met through participation in the IMPROVE network, wh ich 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 monitori ng 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, a nd regional-state agencies. At the direction of the National Park Service, the Coope rative Institute for Research in the Atmosphere, at Colorado State University’s Foothills Campus in Fort Col lins, Colorado, maintains the network plan on the
IMPROVE Internet Web site. 13 The primary objectives of the IM PROVE Web site are to provide federal, state, and air quality regulatory agen cies 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 user s 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 a ddress 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 m onitoring 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 vo id. ADEQ also commits in the Arkansas RH SIP to evaluate the monitoring network periodic ally 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) requi res that ADEQ establish pro cedures by which monitoring
data and other information are used in determin ing 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 availa ble on the Internet via the site noted above and submits it to our air quality sy stem. This information is used to characterize the visibility at Caney Creek and Upper Buffalo and assess Arka nsas’ progress toward its RPGs. The IMPROVE monitoring program is national in scope, and ot her states have similar monitoring and data reporting procedures, ensuring a consistent a nd robust monitoring data collection system.

Section 51.308(d)(4)(iv) require s that the SIP must provide for the reporting of all visibility monitoring data to the Administrato r at least annually for each mandatory Class I
Federal area in the State. To the extent possible, Arkansas sh ould report visibility monitoring data electronically. Section 51.308(d )(4)(vi) also requires that ADE Q provide for other elements, including reporting, recordkeepi ng, and other measures, necessa ry to assess and report on visibility. Again, Arkansas’ part icipation in the IMPROVE network ensures the monitoring data is reported at least annually a nd is available for download from the site referenced above.

Section 51.308(d)(4)(iv) require s that ADEQ maintain a statew ide inventory of emissions of pollutants that are reasonably an ticipated 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 comm itment 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 in tends 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 lim itations 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 demonstr ates that an emissions trading program or other alternative will achieve gr eater reasonable progress toward natural visibility conditions.

Note: The evaluation of whether the RH SIP contains “adequate emission limitations representing BART and sche dules for compliance with BART for each BART eligible44 source that may reasonably be anticipated to cause or contribute to any impairment of visibility in any mandatory Class I Fe deral 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 So urce Identification: 40 CFR 51.308(e)(1)(i)

Arkansas must submit a SIP containing a list of all BART-eligible source s within the State.

Note: This section is intended to cover the genera l question of whether the state identified which sources were subject to BART. S ubsequent sections tr eat 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 visibili ty-impairing pollutant.

ADEQ determined that the visibility-impai ring pollutants in Arka nsas include sulfur dioxide (SO 2 ), nitrogen oxides (NOx), and particulat e matter (PM10 and PM2.5). Because of the uncertainties in assessing the effect of VOCs and ammonia emissions re ductions on visibility,
Arkansas decided to not consider VOCs and ammonia among visibility-i mpairing 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, a nd 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 exis tence on August 7, 1977 and began operation after August 7, 1962. As necessary, ADEQ contacted the s ources to obtain or confirm pertinent data and information. These emissions units comprise the “BART-eligible sour ces” listed in Table 7, as adapted from Table 9.1 of the Arkansas RH SIP:

Table 7. Facilities with BART-e ligible 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 Boiler46 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 Boile r No. 2 Power Boile r
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 Industr ies- 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 Concentrato r47 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 narra tive. Appendix 9.1A states the 6A Boiler began operation prior to August 7, 1962, and th at it falls out of the BART e ligibility criteria because of its start of operations date. On Septembe r 27, 2011, ADEQ submitted supplemental information clarifying that the Georgia-Pa cific Crossett Mill provided ADE Q 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 Amer ican 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-Pa cific Crossett Mill, we cannot ma ke 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 (t he 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 Inte rnational Paper/Evergreen Packaging in its evaluation to determine what sources are subj ect 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 In ternational Paper Company for the No. 1 and 2
Boilers. 16 The inspection certificate st ates the Arkansas Departme nt 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 fo r BART eligibility. We agree that the No. 1 and 2 Power Boilers at International Paper/Ever green Packaging are not BART-eligible.

In the RH SIP, ADEQ did not identify Boile rs SN-301A and SN-302A at the Great Lakes Chemical Plant as BART-eligible, but since ADEQ at one point believed th ese 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 evalua tion 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 ra ting less than 250 MMBtu/hr and are not integral to the process at the plant, as the permit states they ar e used to supply heat to the process. 17 The BART Guidelines provide that an indi vidual fossil fuel boiler smaller than 250 MMBtu/hr that does not fall into source Category 1 (i.e., Fossil-fuel fi red steam electric plants of more than 250 MMBtu/hr heat input), falls into one of the source categories for BA RT eligibility only if it is an integral part of a process descrip tion at a plant. If th e 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 h eat, 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-e ligible 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 sour ces which were determined to be BART eligible, ADEQ performed visibility modeling of each BART eligible unit to determine whether
it caused or contributed to visi bility impairment at any Class I area. Pursuant to federal regulations, states have the option of exem pting a BART-eligible source from the BART requirements based on dispersion modeling demonstr ating that the source cannot reasonably be anticipated to cause or c ontribute to visibility impairment in a Class I area. Pl ease 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 f ound in Appendix 9.2A. ADEQ utilized BART modeling that did not include meteorological observations , and therefore used the 1 st High ( i.e.

, maximum) value from the CALPUFF modeling to de termine 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 Chemi cal 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 facilitie s 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 Industr ies- 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 Concentrato r50 EPA Findings:

ADEQ provided screening modeling results in Appendix 9.2B of the RH SIP for all
sources identified in the RH SI P as BART-eligible sources, as well as for Boilers SN-301A and
SN-302A at the Great Lakes Chemic al plant (which we find to be not BART eligible), the No. 1 and No. 2 Power Boilers at International Paper/Ev ergreen Packaging (which we also find to be not BART eligible), and the 6A and 9A Boilers at the Georgia-P acific Crossett Mill (as discussed above). Our evaluation of these re sults showed that four facilities that ADEQ did not identify as subject to BART had modeled visibility imp acts that exceed the 0.5 dv contribution threshold used by ADEQ to determine what sources are s ubject 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 Intern ational Paper (Evergreen) and Boilers SN301A and SN-302A at Great Lakes Chemical we re 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-elig ible, since they were in operation prior to 1962, and therefore not subject-to-BART.

• As discussed in section III.F.1. of this TS D, the original meteorological databases generated by CENRAP did not include obs ervations as EPA guidance recommends. Therefore, in their evaluation to determin e 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., 98 th 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 visibil ity impact of 0.711 dv at Hercules-Glade. Further examination of the modeling results re veals that only one da y of the three years
modeled exceeds the 0.5 dv contribution threshol d 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 98 th percentile modeled visibility impact rather than the maximum impact, would show modeled impacts above the threshold. Th erefore, 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 visi bility impacts exceeding the 0.5 dv contribution threshold, w ith 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-Pacific51 Crossett Mill. Using updated emission ra tes, 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 assu mptions 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 da y over the modeled period. There is no supporting technical analysis discussing the a ssumptions 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 Ge orgia 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 estim ates 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 contri bution to visibility impairme nt. We disagree with ADEQ’s determination that the Georgia-Pacific Crossett Mill’s 6A and 9A Boile rs are not subject to BART and find that, based on the available info rmation, 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 determina tion of BART for each BART-eligible source in Arkansas that emits any ai r 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 th at is subject to BART within the State. In this analysis, Arkansas must take into considera tion the technology available, the costs of compliance, the energy and non-air quality enviro nmental impacts of compliance, any pollution control equipment in use at the source, the remaini ng 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 Arka nsas RH SIP, lists all of the sources determined by ADEQ to be subject to BART. The SO 2 , NOX and PM10 BART determinations performed by ADEQ for these facilities are ev aluated 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 SO 2
NOx

PM 10 Arkansas Electric Cooperative Corporation John L. McClellan Generating Station Unit 1 fossil fuel-fired steam electric plants SO 2
NOx

PM 10
American Electric Power Flint Creek Power Plant Boiler No. 1 fossil fuel-fired steam electric plants SO 2
NOx

PM 10 Entergy Lake Catherine Plant Unit 4 fossil fuel-fired steam electric plants SO 2
NOx

PM 10 Entergy White Bluff Plant Units 1, 2, and Auxiliary Boiler fossil fuel-fired steam electric plants SO 2
NOx

PM 10
Domtar Ashdown Mill Boilers No. 1 and
2 kraft pulp mill SO 2
NOx

PM 10

EPA Findings:

We are proposing to approve ADEQ’s identific ation 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 dete rmination that the Georgia-Pacific Crossett53 Mill’s 6A and 9A Boilers ar e 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 so urces 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 BA RT determinations. We discu ss these problems in detail in the individual BART determination sections, a nd we summarize some ge neral issues in the paragraphs that follow.

For some sources, ADEQ did not adequately co nsider whether retrof it controls should be required based on a flawed analysis of the source ’s potential visibility impacts. ADEQ assumed that if pre-control modeling 18 conducted on the basis of a singl e 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 unn ecessary. This approach is unacceptable. Due to the nonlinear nature and comp lexity of atmospheric chemistr y and chemical transformation among pollutants, ideally all relevant pollutants sh ould be modeled together to predict the total visibility impact at each Class I area receptor. 19 At a minimum, NOx and SO 2 emissions should be modeled together to determine the visibility impacts attributable to these pollutants when evaluating controls and combinati ons of controls in determining BART for a source. Predicting the impacts of PM on visibility is relatively st raight-forward, unlike predicting the impacts of

SO 2 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 “contribu tes” to visibility impairment on a per-pollutant basis. As discu ssed above, the State selected a threshold of 0.5 dv for the initial screening modeling that included all pollutants. Clearly, a lo wer threshold value is needed in evaluating pollutant-specific modeling fo r 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 ar e unlikely to contribu te 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 Ava ilable Retrofit Technology (BART) Determinations, July 19, 2006

20 “...States may choose to identify de minimis levels of po llutants 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 5154 For some BART determinations, ADEQ did not properly determine BART, but instead concluded that the presumptive limits in the BA RT 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 consid eration the factors relevant to a BART determination. In that rulemaking, EPA also established presumptive BART limits for certain el ectric generating units (EGUs) located at power plants 750 MW or greate r in size based variou sly on the size of the unit, the type of unit, the type of fuel us ed, 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 th e substantial degree of visibili ty improvement anticipated to
result from the use of such controls on thes e EGUs and concluded that such BART-eligible sources should at least meet the presumptive lim its. 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 coul d avoid a source-specific BART determination by adopting the presumptive limits. In fact, nothing on the re cord 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 appropriatene ss 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 ADE Q did perform a full BA RT 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 c ontrols 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 McClella n Unit 1 are BART-eligible sources. The AECC Bailey Unit 1 is a boiler with a gro ss output of 122 MW and a maximum heat input rate of 1350 MMBtu/hr, and is curr ently permitted to burn both natural gas and fuel oil. The fuel

21 70 FR at 39131-39136.55 oil burned at the plant is subjec t 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 perm itted to burn both natural gas and fuel oil. The fuel oil burned at the plant is subject to an operating air pe rmit sulfur content limit of 2.8% by weight.

State Submittal Regarding SO 2 BART for both sources: Appendix 9.3A

AECC performed a BART five factor analysis for SO 2 . A summary of this analysis is presented
below:

Step 1- Identify All Availabl e Retrofit Control Technologies: AECC identified use of fuel oil
with 1% sulfur content and insta llation of a scrubber as the only two control options available for

SO 2 BART for AECC Bailey Unit 1 and McClellan Unit 1.

Step 2- Eliminate Technically Infeasible Options : AECC found that neith er of the two control options is considered technically infe asible for the two units in question.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies : AECC determined
that a scrubber would have a c ontrol effectiveness of 95%, whereas use of 1% sulfur fuel oil
would have 55% control effectiveness at Bail ey 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, en ergy impacts, non-air quality environmental impacts, and remaining useful life.

• Costs of Compliance: Using the Integrated Environm ental Control (IEC) cost model provided by the Electric Power Research Institute (EPRI), AECC determined that
installation of a scrubber w ould result in an annualizedcost of $8,106,900 and a costeffectiveness of $2,108,25/ ton SO 2 removed at Bailey Unit 1, a nd an annualized cost of $8,563,940 and a cost-effectiveness of $1,658.32/ ton SO 2 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 SO 2 removed at Bailey Unit 1, and an annualized cost of $238,095 and a co st-effectiveness of $158.60/ ton SO 2 removed at
McClellan Unit 1. AECC determined that combus tion of 1% sulfur fuel oil is much more
cost-effective than installi ng and operating scrubbers.

• Energy Impacts : AECC determined that installati on and operation of a scrubber would result in an energy consumption of 1.688 MW H 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 SO 2 scrubbers would consume 119 gallons per minute (gpm) of water and resu lt in 12,427 lb/hr of sl udge 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, a ny requirement to insta ll and operate a control with a high capital cost may cause the retirement of these units.

Based on the analysis in Steps 1-4, AE CC determined, and ADEQ agreed that SO 2 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 fu el 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 Ca ney Creek, and 59.28% at Upper Buffalo.

EPA Findings Regarding SO 2 BART Determinations for both sources: Below is our evaluation of AECC’s SO 2 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

SO 2 BART for Bailey Unit 1 and McClellan Unit 1. Specifically, we propose that AECC did not properly “take into considerati on the technology available” (Step 1) by failing to consider the maximum level of control each control option is capab le of achieving. In considering use of fuel oil with low sulfur content as a control option, ADEQ identified and consid ered only 1% sulfur fuel oil in the BART analysis. The BART Guide lines (Appendix Y to Part 41) provide that in identifying all available retrofit control technolo gies, the most stringen t option and a reasonable set of options for analysis that reflects a comp rehensive list of availabl e technologies must be considered. All permutations of available contro l levels that exist for a given technology need not be listed, as the list is complete if it in cludes the maximum level of control each technology is capable of achieving. The require ment 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 iden tify and consider in57 the BART analysis the maximum level of emissi on 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 ac hievable through the application of the best system of continuous emission reduction.” Since recent retrofits at existing sources provide a good indication of the cu rrent “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 acco rdingly 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 cont rol 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 t hus 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-fu el fired steam electric plants throughout the country that are currently perm itted to burn fuel oil w ith 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 Yo rk City being required to us e fuel oil with a maximum 0.3%
sulfur content. 23 Lowering the sulfur content in fuel oi l is also a part of the long-term strategy recommended by the Mid-Atlantic/Northeast Visib ility 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 resi dual fuel oil to 0.3- 0.5% sulfur by weight by no later than 2012. 25 Therefore, the use of fu el 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 pr operly 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/air 2/regs/mainregs/sec19a.pdf.

23 New York State Department of Environmental Conservation (DEC). “S ubpart 225-1: Fuel Composition and UseSulfur Limitations,” Environmental Conservation Rules and Regulations, May 8, 2005. http://www.dec.state.ny.us/web site/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, Pennsylv ania, Maryland, Delaware, an d also the District of Columbia.

25 See 76 FR 27973.58 impacts of all technically feasible contro l options considered before making a BART
determination.

In Step 4 of the BART analysis, AECC cons idered 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-e ffectiveness of $2,108/ SO 2 ton removed and $1,658/ SO 2 ton removed. AECC compared these values to the cost-effectivene ss of using 1% sulfur c ontent fuel oil at the AECC Bailey Unit 1 and the AECC McClellan Unit 1 ($54.90/ SO 2 ton removed and $158.60/

SO 2 ton removed, respectively). In Step 5 of the BART analysis, AECC and ADEQ evaluated the visibility impacts of control options. Ho wever, AECC stated that since AECC and ADEQ agreed that the most cost-effectiv e control would be to use fuel o il 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, insta llation and use of scr ubbers to control SO 2 emissions at the Bailey and McClellan units is well within the cost-effectiveness range. Therefore, ADEQ and AECC should have modeled the visibility imp act of all options considered in the BART analysis, and compared the visibility improvement s resulting from use of scrubber systems with that resulting from use of 1% sulf ur 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 c ontrol option is BART.

Therefore, for the reasons expresse d above, we propose to disapprove the SO 2 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

CALFUFF 26 modeling for the AECC Bailey Unit 1 a nd the AECC McClellan Unit 1. AECC stated that the results of the NOx modeling s hows 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 Corpora tion 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 c onducted pollutant sp ecific pre-control

CALFUFF 28 modeling for the AECC Bailey Unit 1 a nd the AECC McClellan Unit 1. AECC stated that the results of the NOx modeling s how that NOx does not cau se 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 eith er the AECC Bailey Unit 1 or AECC McClellan Unit 1. However, the ADEQ’s modeling results pres ented 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 emi ssions from the AECC McClellan Unit 1. As stated above, NOx and SO 2 emissions should be modeled toge ther due to the nonlinear nature and complexity of atmospheric chemistry a nd chemical transformation among pollutants. Evaluation of the screening modeling results for th ese units reveals that on some of the most impacted days, NOx is a significan t 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 impairme nt 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 re latively high impacts due to NOx, a combination of NOx and SO 2 controls may prove to be cost-effective and prov ide for substantial visibility improvement and
should therefore be evaluated.

For PM BART, AECC decided, and ADEQ agre ed, that PM does not cause visibility impacts because the PM emissions are less than t hose of NOx at these units. This conclusion is not supported in the record by PM visibility modeling results, a dditional technical analysis, or reference to a permit limit for PM that restrict s emissions below a leve l that will impact visibility. Neither ADEQ nor AECC have comp leted a BART analysis that considers the statutory factors under section 51.308(e)(1)(ii)(A) that states ar e required to consider in determining what level of contro l 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 Corpora tion 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-e ligible 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 tir e 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, fo r fuel oil tank maintenance, to prevent boiler tube failure in extreme cold weather, and wh en 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 PM 10 and PM 2.5 emissions from the source have minimal visibility impacts at each Class I area with in 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 ex isting 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 PM 10 and PM 2.5 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 a pproach to determine wh ether a source should be subject to review for PM contro ls. In the case of the AEP Flin t Creek No. 1 Boiler, we have found that the visibility impact due to PM emissions alone is so minimal su ch that the installation of any additional PM controls on the unit woul d likely achieve very low emissions reductions, have minimal visibility benefit, and not be co st-effective. Therefore, we are proposing to approve ADEQ’s determination that PM BART fo r 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 SO 2 and NOx : Appendix 9.3A

Regarding BART for SO 2 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/Web Databases/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 SO 2 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 SO 2 and NOx BART Determinations:

We are aware that the AEP Flint Creek Po wer 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-eligib le source that is subject to BART within the State. In this analysis, the State must take into consideration the technology available, the costs of comp liance, the energy and nonair quality environmental impacts of compliance, a ny 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 an ticipated to result from the use of such technology.

Therefore, we are proposi ng to disapprove ADEQ’s BART finding since neither AEP nor ADEQ conducted a BART analysis considering the best system of controls for BART for SO 2 and NOx for AEP Flint Creek No. 1 Boiler. ADE Q and/or AEP should have performed a BART analysis for SO 2 and NOx. Controls ach ieving more than the SO 2 and NOx presumptive limits
are available and should be considered in th e BART analysis, especially considering the magnitude of the visibility impact of the AE P Flint Creek No. 1 Boiler on the Class I areas
within 300 km. 32 For instance, SCR controls are routin ely 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 leve ls that are currently being achieved by over 100

31 The “presumptive limits” are the rebuttable specific limits established in the BART Rule for SO 2 and NOx for certain EGUs based on fuel type, unit si ze, cost effectiveness, and the presen ce or absence of pre-existing controls.

32 ADEQ’s CALPUFF visibility modeling indicates the highes t 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 visi bility 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 othe rs, 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 CE MS 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 SO 2 emissions. In a report for the National Lime Association, Sarg ent & Lundy stated that vendors guarantee SO 2 reduction efficiencies of up to 95% , or as low as 0.06 lb/MMBtu SO 2 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 SO 2 emissions of 0.065 lb/MMBtu on a 30-day rolling average when the uncontrolled SO 2 emission rate is less than or equal to 1 lb/MMBtu. 36 The Desert Rock Energy Company, a 1500 MW coal fi red power plant in New Mexico, is equipped
with a wet scrubber and has an SO 2 emission limit of 0.060 lb/MMB tu, averaged over a 24-hour period. 37 We note that a 24-hour average is much mo re stringent than a 30-day rolling average.

Therefore, for the reasons expressed above, we are proposing to disapprove ADEQ’s
determination of SO 2 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 BA RT-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 emi ssion 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-contro l modeling files for the natura l 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 al so 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/Licat a.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 manuf acturers 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 ta nks at the source have been emptied and the pipework necessary to burn fuel oil is in the pr ocess 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 re flect this change, we are not disregarding the
source’s BART emission limits for fuel oil firing in this proposed rulemaking.

State Submittal Regarding SO 2 and PM BART Determinations (natural gas): Appendix

9.3A

Regarding BART for SO 2 and PM for the natural gas firi ng scenario, Entergy stated that most of the visibility-causing emissions from Unit 4 are due to NOx since SO 2 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 SO 2 , 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 St ate’s RH Rule, Chapte r 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 scenar io for Entergy Lake Catherine Unit 4. This corresponds to an emission limit of 45 lb/hr PM. 38

EPA Findings Regarding SO 2 and PM BART Determin ations (natural gas):

We agree that SO 2 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 SO 2 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 natu ral gas firing) is so minimal such that the installation of any addition al 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 De termination (gas & fuel oil): Appendix 9.3A

Entergy conducted a BART analysis to dete rmine what retrofit controls are BART for Lake Catherine Unit 4. A summary of th is 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 Availabl e Retrofit Control Technologies: Entergy considered a combination of the following NOx combustion controls for th e 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: boi ler tuning, boiler modifica tions, BOOS, and forced flue gas recirculation (FFGR). Entergy did not consider post- combustion control technology in its analysis because it indicated its belief that th e BART Guidelines exempt the source from this analysis.

Step 2- Eliminate Technically Infeasible Options : Entergy found that a ll options identified in Step 1 of the analysis ar e technically feasible.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies : Table 10 depicts the
control effectiveness of the contro l options for the gas firing scenario (adapted from Table 3-1 of Entergy’s BART analysis for Lake Catherine Un it 4, Appendix 9.3A of th e Arkansas RH SIP). Table 11 depicts the control effec tiveness of the control options for the fuel oil firing scenario (adapted from Table 3-2 of Entergy’s BART an alysis for Lake Catherine Unit 4, Appendix 9.3A of the Arkansas RH SIP).

Table 10. Control Effectiveness of NOx Contro l 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 anal ysis. In evaluating the cost-effec tiveness of each control scenario option for BART for NOx, ADEQ stated it assume d a 10% capacity factor for operation of Unit 4. Entergy provided no documentation or detaile d 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 Ca therine Unit 4, Appendix 9.3A of the Arkansas RH SIP). Table 13 depicts the co st-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 $3,75766 Table 13. Cost-Effectiveness of NOx Control Opti ons 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 conduc ted post-control CALPUFF modeling of the visibility impacts of the NOx cont rol 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 firi ng scenario (as adapted from Table 5-1 of the Entergy’s BART analysis for Lake Catherine Un it 4, Appendix 9.3A of th e 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, A ppendix 9.3A of the Arkansas RH SIP).

Table 14. Visibility Impact of NOx Control Opti ons for Lake Catherine Unit 4- Gas Firing

Control Option Visibility Impact (98 th 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 0.2767 Table 15. Visibility Impact of NOx Control Op tions for Lake Catherine Unit 4- Fuel Oil Firing

Control Option Visibility Impact (98 th 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 fo r 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 IF GR, 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, boi ler modifications, and BOOS, achieving a NOx emission limit of 0.25 lb/MMBtu for the fuel oil firing scenario.

EPA Findings Regarding NOx BART De termination (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 an alysis for Lake Catherine Unit 4, the BART
Guidelines and the RH Rule do not limit the c onsideration of possible BART control technology choices to only cost-effective combustion contro ls for these sources. Post-combustion control technologies are technically feasib le and should be considered for oil fired and gas fired EGUs as part of the BART determination. As discu ssed above, Entergy did not consider NOx postcombustion controls, such as selective catalyt ic reduction (SCR) and se lective 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 identifi ed control technology. Ente rgy reported that the results of the computerized model showed th at post-combustion controls, such as SCR and SNCR, had a cost that would be une conomical 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 dol lars per ton of NOx re moved ($/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 es timates. The results of the computer model
the source used to determine the cost-effectiv eness 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 sour ce. 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 factor 41 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 effec tiveness of post-combustion controls, likewise assumed a 10% capacity factor in the calculati on of the metrics for tons removed and $/ton removed. Given that there are no permit requireme nts 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 effectivenes s 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 th e unit has operated, on aver age, 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% capac ity 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 fact or of no more than 10.0 percent during the previous three calenda r 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 act ual 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 ra ted 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 Plan t- 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 c onsideration “the technology availa ble” 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 fo r NOx for Unit 4 is a combination of boiler tuning, BOOS, and IFGR achieving a NOx emissi on limit of 0.15 lb/MMBtu for the natural gas firing scenario and a combination of boiler tu ning, boiler modifications, and BOOS, achieving a NOx emission limit of 0.25 lb/MMBtu for the fuel oil firing scenario.

State Submittal Regarding SO 2 BART Determination (fuel oil): Appendix 9.3A

Entergy performed a BART analysis to dete rmine what level of c ontrol is BART for SO 2 for the fuel oil firing scenario for Entergy Lake Ca therine Unit 4. A summary of this analysis is presented below:

Step 1- Identify All Availabl e 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 d ecision. Entergy only considered the use of fuel oil with 1%, 0.5%, and 0.2% sulfur content by weight. We note us e of fuel oil with 1% sulfur content is the base case, as Entergy stated the source’s curren t Title V permit limits the sulfur content of fuel oil used to 1%. Entergy did not consider any post-combustion SO 2 controls in the BART analysis, even though post-combustion control tec hnologies, such as wet and dry scrubbers, are currently being used by comparab le facilities to control SO 2 emissions.

Step 2- Eliminate Technically Infeasible Options : Entergy did not indi cate any of the control options identified unde r Step 1 of the analysis ar e technically infeasible.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies : Entergy used AP-42 factors for 1%, 0.5%, and 0.2% sulfur residual oi l to determine the amount of sulfur dioxide emissions that would be eliminated by use of low su lfur fuel oil. Based on 10% utilization of the unit, use of 1% sulfur fuel oil (baseline conditions) results in SO 2 emissions of 2,311 tpy; use of 0.5% sulfur fuel oil would result in 1,059 tpy SO 2 removed from the baseline; and use of 0.2% sulfur fuel oil would result in 1,802 tpy SO 2 removed from the baseline.

Step 4- Evaluate Impacts and Document the Results : Entergy considered the costs of compliance in this step of the BART anal ysis. In evaluating the cost-effec tiveness of each control scenario option for BART for SO2, Entergy stated it assu med a 10% capacity factor for operation of Unit 4. We note Entergy provided no documentation or detailed breakdown of the costs estimates for70 use of low sulfur fuel oil for Unit 4. Table 16 depicts the cost-effec tiveness of the control options for SO 2 BART (adapted from Table 3-3 of Ente rgy’s BART analysis for Lake Catherine Unit 4, Appendix 9.3A of the Arkansas RH SIP).

Table 16. Cost-Effectiveness of SO 2 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 conduc ted post-control CALPUFF modeling of the visibility impacts of the SO 2 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 Ta ble 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 SO 2 Control Options for Lake Catherine Unit 4- Fuel Oil Firing

Control Option Visibility Impact (98 th 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 mo re stringent controls,
BART for SO 2 for the fuel oil firing scenario is an SO 2 emission limit of 0.562 lb/MMBtu on a71 30 day rolling average. The RH SIP provides c onflicting information on whether this emission limit corresponds to use of 1% or 0.5% sulf ur 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% su lfur content fuel oil.

EPA Findings Regarding SO 2 BART Determination (fuel oil only): Below is our evaluation of Entergy’s SO 2 BART analysis. For the steps that we did not explici tly 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 SO 2 BART analysis, Entergy iden tified use of low sulfur content fuel oil as the only control technology available. En tergy did not consider any postcombustion SO 2 controls in the BART analysis, even though post-combustion control technologies, such as wet and dry scrubbers, are cu rrently being used by comparable facilities to
control SO 2 emissions. As such, Entergy did not identi fy and consider contro l 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 providi ng a fuller picture of our evaluation of Entergy’s BART analysis
for SO 2 for Lake Catherine Unit 4, we discuss the re maining steps of Entergy’s BART analysis.

Regarding Step 4 of Entergy’s SO 2 BART analysis, Enter gy 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 co st estimates should be documented, and should clearly indicate the amount of fuel oil that co rresponds 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 bi ds) 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 SO 2 BART for the fuel oil firing scenario for Lake Catherine Unit 4. Specifically, we propose to fi nd that ADEQ and Entergy did not properly take into consideration “the technology available” in Step 1 of the BA RT analysis and the costs of compliance” in Step 4 of the BART analysis. Because ADEQ and Entergy did not identify all available control technology opti ons 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 de termination that BART for SO 2 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 PM 10 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 scenari o. 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 SO 2 and PM emissions may prove to be cost-effective and provide for substantial vi sibility improvement and should therefore be considered in Entergy’s analysis for Un it 4. Because ADEQ and Entergy did not postcombustion controls, even though these are an ava ilable and technically f easible control option, we are proposing to disapprove ADEQ’s determin ation that BART for PM for Lake Catherine Unit 4 is 0.037 lb/MMBtu on a 30 day rolling av erage 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 Auxi liary Boiler are BART-eligible sources.
Units 1 and 2 are coal fired boilers with a ma ximum 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 SO 2 BART Determination for Units 1 and 2: Appendix 9.3A

Regarding BART for SO 2 for Units 1 and 2, Entergy decided that since the White Bluff plant has a total generating capaci ty greater than 750 MW, the s ource is required to evaluate presumptive limits as part of the BART analysis. The presumptive SO 2 BART limit is 0.15 lb/MMBtu and was analyzed for BART by Ente rgy in both the sub-bituminous and bituminous coal firing scenarios. Although Entergy pe rformed a BART analys is for BART for SO 2 , it73 considered only those control options that meet the presump tive limit of 0.15 lb/MMBtu, without considering whether a more stringent SO 2 emission limit is BART for Units 1 and 2. A summary of Entergy’s BART analysis is presented below:

Step 1- Identify All Availabl e Retrofit Control Technologies: Entergy identified two available options to control the units to the presumptive SO 2 limit: limestone forced oxidation (i.e., wet scrubber) and lime spray dr yer (i.e., dry scrubber).

Step 2- Eliminate Technically Infeasible Options : Entergy did not indi cate any of the control options identified unde r Step 1 of the analysis ar e technically infeasible.

Step 3- Evaluate Control Effectiven ess 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. Assumi ng 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 SO 2 removed at Unit 1 and an annu alized cost of $17,159,021 with a cost-effectiveness of $620/ton SO 2 removed at Unit 2. Entergy al so determined the installation of a dry scrubber would have an annualized cost of $34,035,909 with a co st effectiveness of $1280/ton SO 2 removed at Unit 1 and an annuali zed cost of $34,306,388 with a costeffectiveness of $1280/ton SO 2 removed at Unit 2. The results of Entergy’s cost-effectiveness analysis are summarized in Tables 18 and 19 be low, 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 SO 2 Control Options for Entergy White Bluff Unit 1

Control Option Annualized Cost ($/year) Annual SO 2 tons removed Cost-Effectiveness ($/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 $128074 Table 19. Cost-Effectiveness of SO 2 Control Options for Entergy White Bluff Unit 2

Control Option Annualized Cost ($/year) Annual SO 2 tons removed Cost-Effectiveness ($/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 th e visibility impacts of the two control options. Howeve r, Entergy modeled both control options at the same SO 2 emission rate of 0.15 lb/MMBtu, rather than at the achie vable control effectiven ess of 92% removal for dry scrubbing and 95% for wet scrubbing. ADE Q and Entergy determined the post-control modeling showed that the visibil ity benefits for dry scrubbers a nd 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 sc rubber is nearly twice th at of a wet scrubber.

Entergy determined and ADEQ agreed that BART for SO 2 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 SO 2 BART Determination for Units 1 and 2: Below is our evaluation of Entergy’s SO 2 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 SO 2 BART analysis, although Entergy performed a BART analysis for BART for SO 2 , it considered only thos e control options that meet the presumptive limit of 0.15 lb/MMBtu, without consid ering whether a more stringent SO 2 emission limit is
BART for Units 1 and 2. As discussed elsewher e in this TSD, the BART guidelines and the RH Rule require consideration of the most stringent control technology in th e BART analysis. We agree that scrubbers are ge nerally the most stringent controls available for SO 2 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 a nd the lowest emission limit achievable in the BART analysis. We are proposing to find that ADEQ did not adeq uately address Step 1 of the BART analysis.75 Regarding Step 4 of Entergy’s SO 2 BART analysis, we note En tergy’s cost analysis of
the two SO 2 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 refere nced 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 ag reed 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 th e controls and therefore under-represent the potential costeffectiveness of such controls. We are proposin g to find that ADEQ did not adequately address Step 4 of the BART analysis.

Furthermore, Entergy considered a wet scrubb er achieving 0.15 lb/MMBtu to be the most stringent technology available. But as discusse d elsewhere, wet scrubbe rs and dry scrubbers
have been documented to achieve much lowe r emissions including emissions as low as .065 lbs/MMBtu for dry scrubbers. Therefore, the ev aluation 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 a nd 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-effectivene ss of installing and operating a wet scrubber is $620/ ton SO 2 removed. Although Table A-1 indicates such co st-effectiveness value corresponds to operation
of the wet scrubber at 95% control efficienc y, neither ADEQ nor Ente rgy provided a breakdown
of the cost estimates and we were therefore unabl e to verify whether it in fact corresponds to 95% control efficiency or if it corresponds to 80% cont rol efficiency at Unit 2 and 82% control efficiency at Unit 1. Even if the $620/ ton SO 2 removed cost-effectiven ess value corresponds to only 82% control efficiency for Un it 1 and 80% control efficiency for Unit 2, we believe that the incremental cost of operating th e wet scrubber at 95% vs. 80% a nd 82% control efficiency is relatively minimal, and is likely cost-effective. Since Entergy and ADEQ considered only the
0.15 lb/MMBtu SO 2 presumptive limit in the BART analysis for Units 1 and 2, even though a lower limit is technically achievable and more th an likely cost-effective, we are proposing to disapprove ADEQ’s determination for SO 2 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 c onsider the “technology available” in Step 1 and the “cost of compliance” in Step 3 of the BART analysis for SO 2 for Entergy White Bluff Units 1 and 2. Since ADEQ and Entergy considered only the 0.15 lb/MMBtu SO 2 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 t echnically achievable and more than likely costeffective, we propose to disapprove ADE Q’s determination that BART for SO 2 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 bitumi nous coal firing scenarios.

State Submittal Regarding NOx BART De termination 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 SO 2 BART analysis for Units 1 and 2, Entergy did not consider establishing NOx BART emission limit s below the NOx presumptive limits, even though it has been demonstrated that there are av ailable control technologies that can meet emission limits more stringent than 0.15 lb/MMB tu and 0.28 lb/MMBtu for sub-bituminous coalfiring and bituminous coal-firing, respectively. A summary of Ente rgy’s analysis is presented
below:

Step 1- Identify All Availabl e 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 feas ible and available and are currently being used by comparable faciliti es to control NOx emissions at rates more stringent than the presumptive limit.

Step 2- Eliminate Technically Infeasible Options : Entergy did not indi cate any of the control options identified unde r Step 1 of the analysis ar e technically infeasible.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies : Entergy determined boiler tuning will result in 37% control remova l; a combination of boiler tuning and OFA will result in 53.6% control removal; and a combina tion 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% u tilization of each unit (even though the unit can77 technically and legally oper ate at 100% utilization) 45 and determined that a combination of boiler tuning, OFA, and LNB has a control effectiv eness 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 adap ted 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 ($/year) Annual SO 2 tons removed Cost-Effectiveness ($/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 ($/year) Annual SO 2 tons removed Cost-Effectiveness ($/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 conduc ted 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 SO 2 controls (wet scrubber and dry scrubber). Since ADEQ did not conduct post-contr ol 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 De termination 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 contro l options corresponds to th e 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-co mbustion 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 technical ly feasible and available tec hnologies. 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 doe s not preclude analysis of more stringent
emission limits if such emission limits have b een met for the same type of source under review under similar conditions. As such, Entergy must cons ider post combustion cont rols 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 an d Entergy did not adequately consider “the technology available” in Step 1 of the BART analysis.

Regarding Step 4 of Entergy’s SO 2 BART analysis, we note En tergy’s cost analysis of the NOx control options included no documentati on or detailed breakdown of the costs. We have no basis to verify the valid ity of neither the cost estimate s 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. W ithout ADEQ and/or Ente rgy providing a breakdown of costs of material, labor, operation and mainte nance, etc, we cannot verify the accuracy of Entergy’s cost-effectiven ess determination. Furthermore, th e cost-effectiveness analysis is problematic because Entergy assumed, and ADEQ ag reed 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 th e 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 c onsider the “technology available” in Step 1 of the BART analysis and the “cost of comp liance” in Step 4 of the NOx BART analysis. ADEQ and Entergy should consider post comb ustion controls for NOx for Units 1 and 2, including SCR and SNCR. In addition, when eval uating 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 emissi on limit is more stringent than the presumptive emission limit. Therefore, we propose to disa pprove ADEQ’s determination that BART for NOx
for White Bluff Units 1 and 2 is 0.15 lb/MMBtu fo r the sub-bituminous coal firing scenario and
0.28 lb/MMBtu for the bituminous coal firing scenario.

State Submittal Regarding PM BART De termination 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 cont rols 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 SO 2 and NOx, and PM 10 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 en forceable 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 Det ermination 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 in stallation of any additional PM controls on the units would likely achieve very low emissions re ductions, have minimal visibility benefits, and not be cost-effective, we are proposing to a pprove ADEQ’s determination that PM BART for
Units 1 and 2 for both the bituminous and sub-b ituminous coal firing scen arios 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 stat utory factors states are required to consider in determining what level of control is BART for a source, whethe r this be an emission limit or a work practice
standard. The Arkansas RH SIP narrative st ates 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 SO 2 , NOx, and PM. APC&E Commi ssion 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 Determ ination for Auxiliary Boiler:

Since ADEQ’s pre and post-control visibility modeling shows the visibility impact on surrounding Class I areas of all thr ee units at the facility combine d, 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 ADE Q as BART would allow the Auxiliary Boiler to operate 50% of the time on an annual basis. In pr actice, an auxiliary boile r 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 secti on 51.308(e)(1)(ii)(A) because neither ADEQ nor Entergy performed a BART analysis for the A uxiliary Boiler for their chosen work practice standard. We are proposing to disapprove ADE Q’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 ra ting 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 o il generated on site, reprocessed fuel oil, tire derived fuel (TDF), and natural gas. The No. 1 Power Bo iler is equipped with a traveling grate, a combustion air system, a nd a wet ESP for removal of PM emissions. According to the operating air permit, the N o. 1 Power Boiler’s permitted emission rate for
PM/PM 10 is 0.07 lb/MMBtu. The operating air permit provi des that the sulfur content of the fuel
oil used at the No.1 Power Boiler shall not ex ceed 3.0% by weight and that the No. 1 Power81 Boiler shall not use more than 2,700,000 gallons of fuel oil for a ny consecutive 12-month period. The permit also limits the total amount of TD F 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 wast e, 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 co ke. 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 SO 2

. According to the operating air permit, the N o. 2 Power Boiler’s permitted emission rate for
PM/PM 10 is 0.1 lb/MMBtu.

State Submittal Regarding SO 2 BART Determination for Power Boiler No. 1: Appendix

9.3A

Regarding BART for SO 2 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 su ch as flue gas desulfurization (FGD) and ( i.e. , wet and dry scrubbers) have not been installed on wo od-fired boilers because of the relatively low

SO 2 emissions from wood combustion. Domtar determ ined that due to the low sulfur content of wood, SO 2 emissions from wood combustion are inhere ntly low and “have a negligible impact on visibility impairment.” Domtar determined SO 2 BART for Power Boiler No. 1 is no
additional SO 2 controls beyond the existing fuel restri ctions (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 Domta r’s determination and decided that an emission limit of 1.12 lb/MMBtu on a 30-day ro lling average is BART for SO 2 for Power Boiler No. 1. We note that ADEQ’s CALPUFF pre-control m odeling demonstrates the No. 1 Power Boiler
emits more than one-third of th e total modeled emissions of SO 2 from the two sources.

EPA Findings Regarding SO 2 BART Determination for Power Boiler No. 1:

We agree that due to the low sulfur content of wood, SO 2 emissions from wood-fired boilers are generally relativel y low. Table 1.6-2 of EPA’s Compilation of Air Pollutant Emission

Factors indicates the combustion of wood waste has a typical SO 2 emission rate of 0.025
lb/MMBtu. 50 In light of this, we question the appropriateness of an SO 2 emission limit of 1.12

50 Compilation of Air Pollutant Emission Factors, Volume I: Stationary Point and Area Sources, AP-42, 5 th Edition, January 1995.82 lb/MMBtu for Power Boiler No. 1. Neither ADE Q nor Domtar provided any support for this emission limit. Domtar stated that approximate ly 75 percent of the heat input for Power Boiler No. 1 is supplied by bark. A unit combusting prim arily bark should be capable of achieving an

SO 2 emission rate much lower than 1.12 lb/MMBt u. The facility’s curr ent permit for this unit
limits its annual SO 2 emissions to 214 tons per year (t ons/year), which is a low figure. Therefore, there appears to be a mismat ch between ADEQ’s re latively high BART SO 2 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 conducte d a fuel inventory of th is boiler in order to explore this issue. Other sour ces 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 sulf ur 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 SO 2 emission limit, then ADEQ and/or the Domtar should have investigated the feasibility, effectiveness, and cost of SO 2 controls. Therefore, we are proposing to find that ADEQ and Do mtar 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 SO 2 for Power Boiler No. 1 is 1.12 lb/MMBtu on a 30-day rolling average.

State Submittal Regarding SO 2 BART Determination for Power Boiler No. 2: Appendix

9.3A

Regarding BART for SO 2 for Power Boiler No. 2, neither ADEQ nor Domtar performed a BART analysis that considered the statutor y factors under section 51.308 (e)(ii)(A). Domtar stated the unit is equipped with a wet scrubber for control of SO 2 and PM emissions. According to Domtar, the existing wet scr ubber currently achieves an SO 2 control efficiency of approximately 90%. Domtar indicated that the BA RT Guidelines provide an option to skip the comprehensive BART analysis for subject-to-BA RT units already equipped with the most stringent controls availa ble, including all possible improvement s to control devices, as long as these are made federally enforceable for the pur pose of implementing BART for the source.
Domtar stated that since we t scrubbing is the most effective method of controlling SO 2 emissions
and it has not identified a ny feasible upgrades to the existing wet scrubber, no BART analysis is necessary. ADEQ agreed with Domtar, and determined that no additional SO 2 removal is needed for the No. 2 Power Boiler, and BART for SO 2 is 1.20 lb/MMBtu on a 30-day rolling average using the existing wet scrubber.

EPA Findings Regarding SO 2 BART Determination for Power Boiler No. 2:

We agree that the BART Guidelines allow s ources to forego the BART analysis when the source already has the most stringent controls av ailable in place and all possible improvements to
control devices have been made. Howeve r, we disagree that a 1.20 lb/MMBtu SO 2 emissions83 rate corresponds to the most st ringent control available. We note FGD systems are capable of

SO 2 reduction efficiencies up to 98%. 51 Therefore, the 90% reduc tion efficiency claimed by Domtar does not correspond to the highest SO 2 control efficiency wet sc rubbers are capable of achieving. The highest SO 2 control efficiency issue aside, although Domtar st ated 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 scru bber vessel itself, but also considered upgrades that can improve the overall SO 2 removal efficiency of the scr ubber system. For example, the BART Guidelines state that improving maintena nce practices, adjusting scrubber chemistry, and increasing auxiliary equipment redundancy are some ways to improve average SO 2 removal efficiencies. For the reasons discussed above, we are proposing to find that ADEQ and Domtar did not properly follow the requirements of s ection 51.308(e)(1)(ii)(A) in determining BART for

SO 2 for Power Boiler No. 2. We are proposing to disapprove ADEQ’s determination that BART
for SO 2 for the No. 2 Power Boiler is 1.20 lb/MMB tu on a 30-day rolling average using the existing wet scrubber.

State Submittal Regarding NOx BART Determination for Pow er Boilers No. 1 and No. 2: Appendix 9.3A

Domtar performed a BART analysis to dete rmine what controls are BART for the two boilers. A summary of Domtar’s analysis is presented below:

Step 1- Identify All Availabl e Retrofit Control Technologies: Domtar identified the following NOx control technologies: boi ler tuning/optimization, fuel bl ending, FGR, LNB, OFA, SNCR, SCR, and reburning/methane de-NOx.

Domtar stated the source has employed and in tends to continue to employ the latest boiler optimization and tuning techniques, and that such contro l technologies are cons idered part of the
base case for Power Boilers No. 1 and 2. Similarl y, Domtar explained that it historically mixes 10-15% (heat input basis) wood with coal in th e 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 ar e 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 w ood is inherently low in nitrog en content, fuel blending is not technically feasible for w ood-fired boilers, and therefore e liminated this as a control option for Power Boiler No. 1.

• Domtar stated that combusti on modification with LNB is us ed in both gas/oil-fired and coal fired units, but is not used for wood-fire d boilers. Therefore, Domtar determined use of LNB is technically infeasib le for Power Boiler No. 1.

• Regarding FGR, Domtar stated that only th ermal 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 emi ssions, the primary purpose is combustion optimization, and implementation of OFA can actually increase NOx emissions in certain circumstances. Therefore, Domtar determin ed an OFA system upgrade at Power Boilers No. 1 and 2 is technically infeasible and e liminated this as a control option for both power boilers.

• Domtar determined that SCR and SNCR are tech nically infeasible control options for No. 1 and 2 Power Boilers because “they are not suited for power boile rs 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 Effectiven ess of Remaining Control Technologies : Domtar determined that methane de-NOx has a poten tial 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 remove d 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 cons ideration of methane de-NOx at Power Boilers No. 1 and 2 due to its high cost. Domtar decide d 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 show s the visibility impact resulting from its SO 2 , 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 SO 2 , 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 th ere are no NOx controls available for Power
Boiler No. 1 and established a BART NOx emi ssion limit of 0.46 lb/MMBtu on a 30-day rolling average for Power Boiler No. 1. Domtar and AD EQ 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 Determ ination for Power Boilers No. 1 and 2 : Below is our evaluation of Domtar’s NOx BART analys is 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 infeasib le control option for Power Boilers No. 1 and 2 because SNCR is “not suited for power boilers th at 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-fi red utility boilers that employ SNCR. In86 particular, a similar source, the bark boiler at Temple Inland Kr aft Linerboard Mill in Orange, Texas, employs SNCR, Low Excess Ai r (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 Inla nd Kraft boiler exhibits load swing. We also note there are other similarities in the operating pa rameters 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 pe rmitted to burn, among other fuel sources, bark/wood biomass, natural gas, and tire-derived fuel. Th e 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 com bustion control technologies, such as SNCR, for both power boilers at Domtar, since SNCR is a c ontrol technology that has been used at similar
facilities to control NOx emissions. Because ADE Q 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, Domt ar eliminated methane de-NOx as a control option for Power Boilers No. 1 and 2 due to the hi gh cost of compliance, thereby eliminating the one control option identified by Do mtar as technically feasible for Power Boiler No.1. Domtar
determined there are no NOx controls availabl e for Power Boiler No. 1 and that BART for Power Boiler No. 2 is LNB. We disagree with ADEQ and Domtar’s appr oach 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 St ep 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 ADE Q and Domtar did not adequately address Step 4 of the BART analysis.

Regarding Step 5 of Domtar’s NOx BART an alysis, 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 re quired under Step 5 of the BART analysis. Domtar eliminated control options prematurely in the Step 4 of the BART analysis before ev aluating the visibility impacts of these NOx controls. Specifically, fo r Step 5, ADEQ and Domtar did not evaluate the visibility impact resulting fr om use of methane de-NOx at the two power boilers. ADEQ and Domtar’s approach for making NOx BART determin ations for the No. 1 and 2 Power Boilers is flawed, as the RH Rule and the BART Guidelines provide that the visi bility impacts of all technically feasible control opti ons, 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 st ep 5 of the BART analysis.

ADEQ stated its post-control visibility mode ling demonstrates the BART determinations for PM, SO 2 , and NOx for Power Boilers No. 1 and 2 will result in a combined visibility improvement of 9.9% at Caney Cr eek 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 cont rols 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 degr ee of improvement in visibility which may reasonably be anticipated to result from the use of such t echnology.” We disagree with Domtar and ADEQ’s assessment that use of SNCR at the two power bo ilers is technically in feasible. In addition, ADEQ did not model the visibility impacts of al l technically feasible control options before making NOx BART determinations. For these r easons, we are proposing to disapprove ADEQ’s
determination that BART for NOx for Powe r Boiler No. 1 is a NOx emission limit of 0.46 lb/MMBtu (which would achieve no NOx emi ssion 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 Determin ation 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 Boile r Maximum Achievable Control Technology (MACT) PM emission
standard of 0.07 lb/MMBtu. A wet ESP was instal led 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 m eeting 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 standa rd in existence at the time to meet the BART PM requirements for both th e No. 1 and No. 2 Power Boilers.

53 ADEQ’s post-control modeling, showing the visibility im provement 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 pr ovided a discussion of other PM control technologies available at the ti me, 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 Achi evable Control Technology (MACT) 54 PM emission
standard in existence at the tim e (0.07 lb/MMBtu), and indicated it s 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 Determ ination 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 stream line the BART analysis by including a discussion of the MACT controls and whether any major ne w technologies have been developed subsequent to the MACT standards. Many VOC and PM sour ces 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 SO 2 . 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 th at would cost many thousands of dollars per ton. The BART Guidelines provide that unless there are new t echnologies 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 pr ovided a discussion of other PM control technologies available at the ti me, and determined that a wet ESP with a PM emission limit of 0.07 lb/MMBtu on a 30-day rolling average is BA RT for Power Boiler N o. 1. We agree that ADEQ’s determination for BART for PM for Powe r 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 BA RT 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 Gu idelines, ADEQ must
select the Boiler MACT PM standard if it de termines 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 m odeling indicates a consid erable 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 ADE Q’s determination that BART for PM 10 for
Power Boiler No. 2 is 0.10 lb/MMBtu on a 30-da y rolling average, and we are proposing to approve ADEQ’s determination that BART for PM 10 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 determinatio ns 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 s ection 51.308(e). We are proposing to find that the
BART determinations listed in Table 23 sati sfy the BART requirements of section 51.308(e), and hereby propose to approve them. We are pr oposing 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 proposi ng to find that the 6A and 9A Boilers at the Georgia-Pacific Crossett Mills are subject-to-BART and require a fu ll 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 limit 56

American Electric Power Flint Creek Power Plant Boiler No. 1 PM 10 existing PM emission limit (0.1 lb/MMBtu)

Entergy Lake Catherine Plant Unit 4 natural gas firing SO 2 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 PM 10 existing PM emission limit (45 lb/hr)

Entergy White Bluff Plant

Unit 1 bituminous coal firing PM 10 existing PM emission limit (0.1 lb/MMBtu)

subbituminous coal firing PM 10 existing PM emission limit (0.1 lb/MMBtu)

Unit 2 bituminous coal firing PM 10 existing PM emission limit (0.1 lb/MMBtu)

subbituminous coal firing PM 10 existing PM emission limit (0.1 lb/MMBtu)

Domtar Ashdown Mill No. 1 Power Boiler PM 10 0.07 lb/MMBtu

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

Facility Name BART Emission Unit Pollutant BART emission limit 57

Arkansas Electric Cooperative Corporation Carl E. Bailey Generating Station Unit 1 SO 2 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 SO 2 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 SO 2 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 SO 2 0.562 lb/MMBtu

NOx 0.25 lb/MMBtu

PM 0.037 lb/MMBtu

Entergy White Bluff Plant

Unit 1 bituminous coal firing SO 2 0.15 lb/MMBtu

NOx 0.28 lb/MMBtu

subbituminous coal firing SO 2 0.15 lb/MMBtu

NOx 0.15 lb/MMBtu

Unit 2 bituminous coal firing SO 2 0.15 lb/MMBtu

NOx 0.28 lb/MMBtu

subbituminous coal firing SO 2 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 SO 2 1.12 lb/MMBtu

NOx 0.46 lb/MMBtu

No. 2 Power Boiler SO 2 1.2 lb/MMBtu

NOx 0.45 lb/MMBtu

PM 10 0.1 lb/MMBtu92 F.2.7 Arkansas Regional Haze Rule

APC&E Commission Regulation 19, Chapter 15 re quires 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 Co mmission 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 submitta l from ADEQ revising several chapters of APC&E Commission Regulation 19, including Chapter 15. The re visions 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 act ion on the version of Chapter 15 of APC&E Regulati on 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 subm ittal 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 ch apters of APC&E Commission Regul ation 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 th at incorporate the BART dete rminations we are proposing to approve and those portions that are consistent with our overall act ion on the Arkansas RH SIP. Specifically, we are proposing to approve th e 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 referen ce the definitions c ontained in 40 CFR 51.301, as in effect on June 22, 2007;

• Reg. 19.1503, which identifies the Stat e’s BART eligible sources;

• The portion of Reg. 19.1504(A) th at identifies AECC Bailey Ge nerating Station (Unit 1), AECC McClellan Generating Station (Unit 1), Domtar Ashdown Mill (Power Boilers No. 1 and 2), Lake Catherine (Unit 4), White Blu ff (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 subj ect to BART to install and operate BART as expeditiously as possibl e, but no later than 6 years af ter the effective date of the State’s regulation or 5 years after EPA approva l 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 subj ect-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 BA RT (sub-bituminous coal) for Entergy White Bluff, Unit 1;

• Reg. 19.1505(I)(3), which establishes PM BA RT (bituminous coal) for Entergy White Bluff, Unit 2;

• Reg. 19.1505(J)(3), which establishes PM BA RT (sub-bituminous coal) for Entergy White Bluff, Unit 2;

• Reg. 19.1505(M)(2), which establishes PM BA RT (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 pe rmit of each facility subject to BART shall be subject to re-opening.

We are proposing to disapprove the po rtion 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 pr oposing to disapprove the following sections of Chapter 15 of the Arkansas Pollution Control and Ecology Co mmission Regulation 19:

• The portion of Reg. 19.1504(A) th at 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 SO 2 BART for AEP Flint Creek Power Plant, Boiler 1;

• Reg. 19.1505(A)(2), which establishes NOx BA RT 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 th e compliance deadline imposed by the State’s RH Rule, such that these sources are now required to comply with BART requirements no la ter than 5 years after EPA approval of the RH SIP.94 • Reg. 19.1505(B), which establishes SO 2 BART for AECC Bailey Generating Station, Unit 1;

• Reg. 19.1505(C), which establishes SO 2 BART for AECC McClellan Generating Station, Unit 1;

• Reg. 19.1505(D)(1), which establishes SO 2 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 SO 2 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 SO 2 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 SO 2 BART (sub-bituminous coal) for Entergy White Bluff, Unit 1;

• Reg. 19.1505(G)(2), which establishes NOx BA RT (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 SO 2 BART (bituminous coal) for Entergy White Bluff, Unit 2;

• Reg. 19.1505(I)(2), which establishes NOx BA RT (bituminous coal) for Entergy White Bluff, Unit 2;

• Reg. 19.1505(J)(1), which establishes SO 2 BART (sub-bituminous coal) for Entergy White Bluff, Unit 2;

• Reg. 19.1505(J)(2), which establishes NOx BA RT (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 BA RT (natural gas) for Entergy Lake Catherine Unit 4;95 • Reg. 19.1505(N)(1), which establishes SO 2 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 Foss il 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 a ny 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 th e guidelines in appendix Y of this part (Guidelines for BART Determin ations 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 Pu lp Mill and the Georgi a-Pacific Crosett Mill, for which ADEQ did not evaluate BART controls. Each of the fossil-fuel fired steam electric generating plants that are requi red to install BART have a to tal generating capacity below 750 MW, with the exception of the En tergy White Bluff plant. ADEQ di d not confirm that it satisfied the requirements in Section 51.308( e)(1)(ii)(B) in prep aring the BART determinations for the three subject to BART units at White Bluff.

EPA Findings: Based on our evaluation of ADEQ’s BA RT analyses for the Entergy White Bluff plant, we found that ADEQ did not follo w the BART Guidelines when performing the BART five factor analyses for the three subjec t to BART units at White Bluff. ADEQ’s BART
determinations for the three White Bluff units subject-to-BART are cove red 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 BA RT-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 Cla ss I Federal area. All such sources are subject to BART. Arkansas96 is not required to make a determination of BART for SO 2 or for NOx if a BART-eligible source has the potential to emit less than 40 tons per yearof 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 ec onomic limitations on the applicability of measurement me thodology to a particular sour ce would make the imposition of an emission standard infeasible, it may instead prescribe a design, equipment, work practice, or other operational standard, or combination thereo f, to require the application of BART. Such standard, to the degree possible, is to set forth the emissi on 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 Auxili ary Boiler is a restrict ion 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 ba sed on technological or economic limitations on the applicability of measurem ent methodology at the source. Furthermore, ADEQ made no attempt to determine the degree of emission reduc tions that would be ac hieved by establishing a limit to operate the Auxiliary Boiler no more than 4360 hour s 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) inst all and operate BART as expeditiously as practicable, but in no even t later than 5 years after approval of the SIP revision, and (2) maintain the control equipment required by this subpart and establish procedur es 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 late r than 6 years after the effective date of this regulation or 5 years after EPA approval of th e Arkansas Regional Haze State Implementation Plan, whichever comes first.” 60 On March 26, 2010, the Arkans as Pollution Control and Ecology Commission, the environmental policy-making body fo r 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 Ru le also provides that each source subject-toBART “shall maintain the control equipment require d 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 th e 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 y ears after approval of the SIP revision, and (2) maintain the control equipment required by this s ubpart and establish procedures to ensure such equipment is properly operated and maintaine d. 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 pa rticipation in an emi ssions trading program
or other alternative measur e rather than require sources subject to BART to install, operate, and maintain BART. Such an emissions trading prog ram or other alternativ e 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 participati on in an emissions trading progra m 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 emissi on reduction requirements of the Clean Air Interstate Rule (CAIR) by participating in one or more of the EPA-admi nistered CAIR trading programs for SO 2 and NOx, it need not require BART-elig ible EGUs subject to such trading programs in Arkansas to install, operate, and ma intain 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 SO 2 program) or by remaining subject to the Federal implementation plan in part 97 of this chapte r (which may be modified by a SI P approved in accordance with sections 51.123(p) and (ee) and 51.1 24(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 requi rement 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 subj ect to BART sources instead determining that
CAIR is better than BART si nce 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 fo r BART or implemented emissions trading program or other alternative measure that achiev es 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 sa me manner as other sources.99 Note: There are no BART sources that ADEQ revi sited 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 re quirement under paragraph (e) of this section to install, operate, and maintain BART may a pply to the Administrator for an exemption from that requirement. An application for an exempti on 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 sect ion 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 rea ssess all of the elements required in paragraph (d) of this section, taking into account improvements in monitori ng data collection and analysis techniques, control technologies, an d other relevant factors. In evaluating and reassessing these elements, Arkansas must address the following:

(1) Current visibility conditions for the most im paired and least impaired days, and actual progress made towards natural conditions during the previous implementation period. The period for calculating current visibility cond itions 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 base d 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 aver age 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 reas onable progress goal in accordance with the procedures set forth in paragraph (d)(1) of this section. If Arkansas established a reasonable progress goal for th e prior period which provided a slower rate of progress
than that needed to attain natural conditi ons by the year 2064, it must evaluate and100 determine the reasonableness, based on the factors in para graph (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 contai ned 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 s ection 51. 300(b)(3), which includes Arkansas, must submit a report to the Administrator every 5 years eval uating progress towards the reasonable progress goal for each mandatory Class I Federal area locate d within it and in e ach mandatory Class I Federal area located outside it which may be af fected by emissions from within it. The first progress report is due 5 years from submittal of th e initial SIP addressing paragraphs (d) and (e) of this section. The progr ess 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 implementati on 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 reduction s achieved throughout Arkansas through implementation of the measures described in paragraph (g)(1) of this section.

(3) For each mandatory Class I Federal area with in 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 av erages of these annual values.

(i) The current visibility conditi ons for the most impaired and least impaired days;

(ii) The difference between current visibility conditions for the most impaired and least impaired days and base line 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 activiti es within Arkansas.101 Emissions changes should be identified by type of source or activity. The analysis must be based on the most recent updated emissi ons 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 emissi ons and improving visibility.

(6) An assessment of whether the current SIP elemen ts and strategies are sufficient to enable Arkansas, or other States with mandatory Federal Class I areas affected by emissions from it, to meet all establishe d 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 SI P requires no further substantive revision at this time in order to achieve established goa ls for visibility improvement and emissions reductions, it must provide to the Administ rator a negative declar ation that further revision of the existing SIP is not needed at this time.

(2) If Arkansas determines that the SIP is or ma y be inadequate to ensure reasonable progress
due to emissions from sources in another State(s) which partic ipated in a regional planning process, it must provide notifica tion 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 sha ll 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 deficien cies within one year.

State Submittal: ADEQ acknowledged this requirement on page 77 of its RH SIP. ADEQ
stated it intends to use the fi ndings of the five-year progre ss report required under section 51.308(g) to make a determinati on regarding the adequacy of this RH SIP and take an appropriate action based upon the re quirements 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 Fe deral 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 visib ility 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 Mana ger with an opportunity for consultation, in person and at least 60 da ys prior to holding any public hearing on a SIP (or plan revision) for regional haze required by this s ubpart. This consultation must include the opportunity for the affected Federal Land Managers to discuss their:

(i) Assessment of impairment of visibili ty 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), Ar kansas 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 pro cedures for continuing consultation between Arkansas and Federal Land Manager(s) on the implementation of the visibility protection program required by this subpart, including deve lopment and review of SIP revisions and 5-year progress reports, and on the imple mentation of other programs having the potential to contribute to impa irment of visibility in manda tory Class I Federal areas.

State Submittal: Page 14

Under Section 51.308(i)(2), Arkansas was oblig ated 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 envir onmental agencies have usually provided all FLMs – the Forest Service, the Park Service, and the Fish and Wildlife Service, c opies 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 provi de 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 devel opment and review of implementation plan revisions and 5-year progress reports, and on th e implementation of other programs having the potential to contribute to impair ment of visibility in the manda tory Class I Federal areas. ADEQ has stipulated in its RH SIP it will continue to coordinate and consult wi th the FLMs as required by section 51.308(i)(4). ADEQ st ates it intends to consult th e 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 sa tisfied section 51.308(i).

EPA Findings:

Caney Creek and Upper Buffalo are both mana ged 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 envir onmental 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 co nsultation, 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 fi nd that ADEQ has satisfied Section 51.308(i)(4) by committing to continuing consultation between th e State and the FLMs on the implementation of the visibility protection program required by Se ction 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.