Technical Support Document 

for EPA’s 

Proposed Action on the 

Arkansas Regional Haze Federal Implementation 

Plan 

Prepared and Reviewed by: 

Dayana Medina 

Michael Feldman 

Barbara Nann 

February 2015 
2 

Table of Contents

I. Arkansas Regional Haze 

A. Background on Regional Haze 

B. Regional Haze Requirements 

C. Relationship of this TSD and Our Proposed FIP Action to Our March 12, 2012 Final 

Partial Approval and Partial Disapproval of the Arkansas Regional Haze SIP 

D. Portions of the Arkansas Regional Haze SIP Disapproved by EPA 

II. Best Available Retrofit Technology (BART) 

A. Identification of BART Eligible Sources and Subject to BART Sources 

1. Georgia-Pacific Crossett Mill 6A and 9A Power Boilers 

2. AECC Carl E. Bailey Generating Station Unit 1 

B. BART Requirements 

C. BART Determinations and Federally Enforceable Limits 

1. AECC Carl E. Bailey Generating Station 

2. AECC John L. McClellan Generating Station 

3. AEP Flint Creek Power Plant 

4. Entergy White Bluff Plant 

5. Entergy Lake Catherine Plant 

6. Domtar-Ashdown Paper Mill 

D. Installation of BART 

III. Reasonable Progress Analysis and Determinations 

A. Reasonable Progress Analysis of Point Sources 

B. Reasonable Progress Goals 

IV. Long-term Strategy 

Appendix A. Technical Support Document for the SDA Control Cost Analysis for the Entergy 

White Bluff and Independence Facilities Arkansas Regional Haze Federal Implementation Plan 

(SO2 Cost TSD) 

Appendix B. Technical Support Document for Arkansas Regional Haze Best Available Retrofit 

Technology (BART) Modeling Protocol Review 

Appendix C. Technical Support Document for Visibility Modeling Analysis for Entergy 

Independence Generating Station 
3 

Technical Support Document 

for EPA’s 

Proposed Action on the 

Arkansas Regional Haze Federal Implementation Plan 

I. Arkansas Regional Haze 

A. Background on Regional Haze 

 Regional haze is visibility impairment that is produced by a multitude of sources and 

activities that are located across a broad geographic area and emit fine particulates (PM2.5) (e.g., 

sulfates, nitrates, organic carbon (OC), elemental carbon (EC), and soil dust), and their 

precursors (e.g., sulfur dioxide (SO2), nitrogen oxides (NOx), and in some cases, ammonia (NH3) 

and volatile organic compounds (VOC)). Fine particle precursors react in the atmosphere to form 

PM2.5, which impairs visibility by scattering and absorbing light. Visibility impairment reduces 

the clarity, color, and visible distance that one can see. PM2.5 can also cause serious health effects 

and mortality in humans and contributes to environmental effects such as acid deposition and 

eutrophication. 

 Data from the existing visibility monitoring network, the “Interagency Monitoring of 

Protected Visual Environments” (IMPROVE) monitoring network, show that visibility 

impairment caused by air pollution occurs virtually all the time at most national parks (NPs) and 

wilderness areas (WAs). The average visual range1

 in many Class I areas (i.e., NPs and memorial 

parks, WAs, and international parks meeting certain size criteria) in the western United States is 

100-150 kilometers, or about one-half to two-thirds of the visual range that would exist without 

anthropogenic air pollution. In most of the eastern Class I areas of the United States, the average 

visual range is less than 30 kilometers, or about one-fifth of the visual range that would exist 

under estimated natural conditions. 64 FR 35715 (July 1, 1999). 

B. Regional Haze Requirements 

 The goal of the Regional Haze Rule (RHR) is to restore natural visibility conditions by 

2064 at the 156 Class I areas identified in the 1977 Clean Air Act Amendments.2

 The regional 

haze state implementation plans (SIPs) must contain measures that make “reasonable progress” 

toward this goal by reducing anthropogenic emissions that cause haze. The RHR sets out specific 

requirements for state’s initial regional haze SIPs. In particular, each state’s plan must establish a 

                                                            

1

 Visual range is the greatest distance, in kilometers or miles, at which a dark object can be viewed against the sky. 2

 40 CFR 51.301(q) defines natural conditions: “Natural conditions include naturally occurring phenomena that 

reduce visibility as measured in terms of light extinction, visual range, contrast, or coloration.” 
4 

long-term strategy that ensures reasonable progress toward achieving natural visibility conditions 

in each Class I area affected by the emissions from sources within the state. In addition, for each 

Class I area within the state’s boundaries, the plan must establish a reasonable progress goal 

(RPG) for the first planning period that ends on July 31, 2018. The long-term strategy must 

include enforceable emission limits and other measures as necessary to achieve the RPG. 

Regional haze plans must also give specific attention to certain stationary sources that were in 

existence on August 7, 1977, but were not in operation before August 7, 1962. These sources, 

where appropriate, are required to install Best Available Retrofit Technology (BART) controls to 

eliminate or reduce visibility impairment. More details on regional haze plan requirements are 

summarized in the Federal Register notice for this action. 

C. Relationship of this TSD and Our Proposed FIP Action to Our March 12, 2012 Final 

Partial Approval and Partial Disapproval of the Arkansas Regional Haze SIP 

 The Act requires each state to develop plans to meet various air quality requirements, 

including protection of visibility. (CAA sections 110(a), 169A, and 169B). The plans developed 

by a state are referred to as State Implementation Plans or SIPs. A state must submit its SIPs and 

SIP revisions to EPA for approval. Once approved, a SIP is federally enforceable, that is 

enforceable by EPA and citizens under the Act. If a state fails to make a required SIP submittal 

or if we find that a state’s required submittal is incomplete or unapprovable in whole or in part, 

then we must promulgate a Federal Implementation Plan (FIP) to fill this regulatory gap within 2 

years unless we approve a SIP revision correcting the deficiencies before promulgating a FIP. 

(CAA section 110(c)(1)). 

 To address the first implementation period, the State of Arkansas submitted a RH SIP on 

September 23, 2008, and August 3, 2010, and submitted supplemental information on September 

27, 2011. We are hereafter referring to these regional haze submittals collectively as the “2008 

Arkansas RH SIP”. On March 12, 2012, the EPA partially approved and partially disapproved 

the RH SIP submitted by Arkansas (77 FR 14604). Under section 110(c) of the Act, whenever 

we disapprove a SIP submission in whole or in part, within 2 years of the final disapproval action 

we are required to approve a SIP revision submitted by the State or promulgate a FIP to address 

the disapproved portions of the SIP unless we first approve a SIP revision correcting the 

deficiencies before promulgating a FIP. Specifically, section 110(c) provides: 

(1) The Administrator shall promulgate a Federal implementation plan at any time 

within 2 years after the Administrator— 

(A) finds that a state has failed to make a required submission or finds that the plan or 

plan revision submitted by the state does not satisfy the minimum criteria established 

under [section 110(k)(1)(A)], or 
5 

(B) disapproves a state implementation plan submission in whole or in part, unless the 

state corrects the deficiency, and the Administrator approves the plan or plan revision, 

before the Administrator promulgates such Federal implementation plan. 

 Section 302(y) defines the term “Federal implementation plan” in pertinent part, as: 

[A] plan (or portion thereof) promulgated by the Administrator to fill all or a portion of a 

gap or otherwise correct all or a portion of an inadequacy in a State implementation 

plan, and which includes enforceable emission limitations or other control measures, 

means or techniques (including economic incentives, such as marketable permits or 

auctions or emissions allowances)* * *. 

 Thus, because we partially disapproved the 2008 Arkansas RH SIP and the SIP submittal 

addressing the interstate visibility transport requirement, we are required to promulgate a FIP for 

Arkansas, unless we first approve a SIP revision that corrects the disapproved portions of these 

SIP submittals. Arkansas has not as yet submitted a revised SIP following our partial 

disapproval, and more than two years have passed since EPA partially disapproved Arkansas’ 

RH SIP. Thus, EPA is under an obligation to promulgate a Regional Haze FIP to correct the 

portions of the SIP that we disapproved. We are proposing a FIP to address those portions of the 

SIP that we disapproved. 

D. Portions of the Arkansas Regional Haze SIP Disapproved by EPA 

 In our March 12, 2012, final partial approval and partial disapproval of the 2008 

Arkansas RH SIP, we disapproved the following BART determinations made by Arkansas: 

 SO2, NOX, and PM BART for the Arkansas Electric Cooperative Corporation (AECC) 

Carl E. Bailey Generating Station Unit 1; 

 SO2, NOX, and PM BART for the AECC John L. McClellan Generating Station Unit 1; 

 SO2 and NOX BART for the American Electric Power (AEP) Flint Creek Power Plant 

No. 1 Boiler; 

 SO2 and NOX BART for the bituminous and sub-bituminous coal firing scenarios for the 

Entergy White Bluff Plant Units 1 and 2; 

 SO2, NOX, and PM BART for the Entergy White Bluff Plant Auxiliary Boiler; 

 NOx BART for the natural gas firing scenario for the Entergy Lake Catherine Plant Unit 

4; 

 SO2, NOX, and PM BART for the fuel oil firing scenario for the Entergy Lake Catherine 

Plant Unit 4; 

 SO2 and NOX BART for the Domtar Ashdown Mill No. 1 Power Boiler; and 

 SO2, NOX, and PM BART for the Domtar Ashdown Mill No. 2 Power Boiler. 
6 

 In our final action we also disapproved Arkansas’ determinations that the Georgia-Pacific 

Crossett Mill 6A Boiler is not BART eligible, and that the 6A and 9A Boilers are not subject to 

BART. By partially disapproving Arkansas’ BART determinations, we also partially 

disapproved the corresponding Arkansas Pollution Control and Ecology Commission (APCEC) 

Regulation 19, Chapter 15, which is the State’s BART rulemaking that identifies the BART 

eligible and subject to BART sources in Arkansas and establishes the BART emission limits that 

sources subject to BART are required to comply with. This rulemaking was submitted by the 

State of Arkansas on September 23, 2008 as part of the RH SIP, and non-substantive revisions to 

the rulemaking were submitted as a SIP revision on August 3, 2010. We also disapproved 

Arkansas’ RPGs for its two Class I areas, the Caney Creek Wilderness Area and the Upper 

Buffalo Wilderness Area, because Arkansas did not meet the requirement under section 

169A(g)(1) of the CAA and 40 CFR section 51.308(d)(1)(i)(A) to consider and provide an 

analysis of the four factors that states are required to consider in establishing their RPGs. We 

also partially disapproved the State’s long-term strategy because it relied on other disapproved 

portions of the SIP. 

 The purpose of this TSD and the proposed Federal Register notice associated with this 

TSD is to correct the disapproved portions of the 2008 Arkansas RH SIP and fulfill the 

obligation before us under CAA section 110(c) to implement a FIP within two years of our 

disapproval of the SIP. This TSD contains three appendices that support our proposal: Appendix 

A to this TSD contains a report detailing our cost analysis for SO2 controls at the Entergy White 

Bluff and Entergy Independence facilities; Appendix B to this TSD contains a report describing 

our review of the BART modeling protocol developed by Trinity Consultants on behalf of the 

BART sources; and Appendix C to this TSD contains a report describing the visibility modeling 

analysis performed by EPA for the Entergy Independence facility. 

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

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

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

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

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

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

a checklist of whether the requirements have been addressed. 

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

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

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

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

II. Best Available Retrofit Technology (BART) 
7 

A. Identification of BART Eligible Sources and Subject to BART Sources 

States are required to identify all the BART-eligible sources within their boundaries by 

utilizing the three eligibility criteria in the BART Guidelines (70 FR 39158) and the Regional 

Haze regulations (40 CFR 51.301): (1) One or more emission units at the facility fit within one 

of the 26 categories listed in the BART Guidelines; (2) the emission unit(s) began operation on 

or after August 6, 1962, and the unit was in existence on August 6, 1977; and (3) the potential 

emissions of any visibility-impairing pollutant from subject units are 250 tons or more per year. 

Sources that meet these three criteria are considered BART-eligible. Once a list of the BARTeligible sources within a state has been compiled, states must determine whether to make BART 

determinations for all of them or to consider exempting some of them from BART because they 

may not reasonably be anticipated to cause or contribute to any visibility impairment in a Class I 

area. The BART Guidelines present several options that rely on modeling analyses and/or 

emissions analysis approaches to determine if a source may reasonably be anticipated to cause or 

contribute to visibility impairment in a Class I area. A source that may not be reasonably 

anticipated to cause or contribute to any visibility impairment in a Class I area is not “subject to 

BART,” and for such sources, a state need not apply the five statutory factors to make a BART 

determination. 

1. Georgia-Pacific Crossett Mill 6A and 9A Power Boilers 

In our March 12, 2012 final action, we approved Arkansas’ identification of BARTeligible sources, with the exception of the Georgia-Pacific Crossett Mill 6A Boiler. We also 

approved the State’s determination of which sources are subject to BART, with the exception of 

the State’s determination that the Georgia-Pacific Crossett Mill 6A and 9A Boilers are not 

subject to BART. Our basis and analyses for our disapproval of Arkansas’ determinations that 

the 6A Boiler is not BART-eligible and that the 6A and 9A Boilers are not subject to BART is 

found in our October 17, 2011 proposed rulemaking, March 12, 2012 final rulemaking, and the 

associated TSDs.3

 

 A revised Title V permit for the Georgia-Pacific Crossett Mill was issued on August 4, 

2011, and again on May 23, 2012. Although no actual pollution controls were installed, the 

permitted emission limits for SO2 and PM10 for the 6A Boiler and SO2, NOX, and PM10 for the 

9A Boiler were revised so as to be more stringent. In a letter dated May 18, 2012,4 GeorgiaPacific explained to ADEQ that it had conducted additional dispersion modeling in 2011 based 

on the currently enforceable Title V permit limits for the 6A and 9A Boilers.5 The results of the 

                                                            

3

 76 FR 64186 and 77 FR 14604. 

4

 May 18, 2012 letter from James W. Cutbirth, Environmental Services Superintendent at Georgia-Pacific Crossett 

Paper Operations, to Mary Pettyjohn, ADEQ. A copy of this letter can be found in the docket for this proposed 

rulemaking. 

5

 See ADEQ Operating Air Permit No. 0597-AOP-R14, issued on May 23, 2012. A copy of the air permit can be 

found in the docket for this proposed rulemaking. 
8 

2011 modeling analysis are summarized in the table below. Based on modeling of the current 

permit limits, the boilers’ maximum visibility impact was modeled to be 0.359 ∆dv at Caney 

Creek (2002). In the letter to ADEQ, Georgia-Pacific stated it believes that the 2011 dispersion 

modeling analysis and the current Title V permit that enforces the modeled limits are sufficient 

to demonstrate no cause or contribution to visibility impairment by the 6A and 9A Boilers, and 

that the boilers are therefore not subject to BART. 

Table 1. Maximum Modeled Visibility Impacts from 6A and 9A Boilers 

(Georgia-Pacific’s 2011 Dispersion Modeling Analysis) 

Class I area 

Maximum Visibility Impact (dv) 

2001 meteorology 2002 meteorology 2003 meteorology 

Caney Creek 0.16 0.359 0.296 

Upper Buffalo 0.099 0.074 0.099 

Hercules-Glades 0.08 0.288 0.125 

Mingo 0.123 0.093 0.168 

Sipsey 0.171 0.184 0.119 

 

Following discussions with us and ADEQ, Georgia-Pacific provided additional 

information in support of its contention that the 6A and 9A Boilers are not subject to BART. 

Georgia-Pacific calculated maximum 24-hour emission rates from the 2001-2003 baseline period 

using fuel usage data, and then showed that these estimated maximum 24-hour emission rates are 

below the updated emission rates it modeled in the 2011 BART screening modeling. In a letter 

dated April 1, 2013, Georgia-Pacific provided spreadsheets with fuel usage data for the 6A and 

9A Boilers for each day during the 2001-2003 baseline period.6

 The 6A Boiler burned only 

natural gas during the 2001-2003 baseline period, while the 9A Boiler burned both natural gas 

and bark. Georgia-Pacific used emission factors from AP-42, Compilation of Air Pollutant 

Emission Factors,7 to calculate 24-hour emission rates for SO2, NOX, and PM10 (lb/hr) for the 6A 

and 9A Boilers for each day during the baseline years (see table below). The gas and bark usage 

                                                            

6

 April 1, 2013 letter from James W. Cutbirth, Environmental Services Superintendent at Georgia-Pacific Crossett 

Paper Operations, to Mary Pettyjohn, ADEQ. A copy of this letter and all attachments can be found in the docket 

for this proposed rulemaking. 

7 AP-42, Compilation of Air Pollutant Emission Factors, has been published since 1972 as the primary compilation 

of EPA's emission factor information. It contains emission factors and process information for more than 200 air 

pollution source categories. The emission factors have been developed and compiled from source test data, material 

balance studies, and engineering estimates. The Fifth Edition of AP-42 was published in January 1995. Since then, 

EPA has published supplements and updates to the fifteen chapters available in Volume I, Stationary Point and Area 

Sources. The latest emissions factors are available at http://www.epa.gov/ttnchie1/ap42/. 
9 

value for each day was multiplied by the appropriate AP-42 emission factor to calculate the 24-

hour emission rate for each day during the baseline period. Example calculations for the 6A and 

9A Boilers are shown below. 

Table 2. AP-42 Emission Factors Used to Calculate Pollutant Emission Rates 

Pollutant AP-42 Emission Factor Emission Factor8

(converted to appropriate units) 

Natural Gas Firing (6A and 9A Boilers) 

PM10 7.6 lb/MM ft3 0.0076 lb/M ft3

SO2 0.6 lb/MM ft3 0.0006 lb/M ft3

NOX 280 lb/MM ft3 0.28 lb/M ft3

Bark Firing (9A Boiler) 

PM10 0.066 lb/MMBtu 0.594 lb/ton 

SO2 0.025 lb/MMBtu 0.225 lb/ton 

NOX 0.22 lb/MMBtu 1.98 lb/ton 

Example Calculation of 24-hour Pollutant Emission Rates for 6A Boiler: 

Jan 1, 2001 -- Gas usage for 24-hour period = 459 M ft3 

PM10 (lb/hr) = 459 M ft3 / 24 hr x 0.0076 lb/M ft3 = 0.145 lb/hr 

SO2 (lb/hr) = 459 M ft3 / 24 hr x 0.0006 lb/M ft3 = 0.0115 lb/hr 

NOX (lb/hr) = 459 M ft3 / 24 hr x 0.28 lb/M ft3 = 5.355 lb/hr 

Example Calculation of 24-hour Pollutant Emission Rates for 9A Boiler: 

Jan 1, 2001 -- Bark usage for 24-hour period = 814 tons

PM10 (lb/hr) = 814 tons/ 24 hr x 0.594 lb/ton bark = 20.15 lb/hr 

 SO2 (lb/hr) = 814 tons/ 24 hr x 0.225 lb/ton bark = 7.63 lb/hr 

NOX (lb/hr) = 814 tons/ 24 hr x 1.98 lb/ton bark = 67.15 lb/hr 

                                                            

8

 Georgia-Pacific converted the AP-42 emission factors into units of lb/M ft3 to be consistent with the fuel usage 

units of measure used in the Georgia-Pacific Crossett Mill’s Utility Department electronic recording and 

recordkeeping system. The AP-42 emission factors for bark firing were converted into units of lb/ton by calculating 

the MM/Btu per ton of bark fired (1 ton bark = 2,000 lb; 2,000 lb x 4,500 Btu/lb = 9,000,000 Btu/ton of bark fired). 

The AP-42 emission rates were then multiplied by 9.0 MMBtu/ton of bark to obtain units of lb/ton. 
10 

Jan 1, 2001 -- Gas usage for 24-hour period = 2,513 M ft3 

PM10 (lb/hr) = 2,513 M ft3 / 24 hr x 0.0076 lb/M ft3 = 0.8 lb/hr 

SO2 (lb/hr) = 2,513 M ft3 / 24 hr x 0.0006 lb/M ft3 = 0.063 lb/hr 

NOX (lb/hr) = 2,513 M ft3 / 24 hr x 0.19 lb/M ft3 = 19.9 lb/hr 

Total PM10 = 20.15 + 0.8 = 20.95 lb/hr 

Total SO2 = 7.63 + 0.063 = 7.69 lb/hr 

Total NOX = 67.15 + 19.9 = 87.0 lb/hr 

 After calculating the 24-hour pollutant emission rate for each day of the year, GeorgiaPacific determined the maximum 24-hour emission rate by using the “max” function of Excel.9

For estimating the maximum 24-hour emission rate for PM10 for the 9A Boiler, Georgia-Pacific 

used the results of stack testing it conducted when the boiler was firing bark and gas, since these 

results yielded higher emission rates than those calculated using AP-42 emission factors. The 

table below shows the maximum 24-hour emission rates during the baseline period for the 6A 

and 9A Boilers. 

Table 3. Maximum 24-hour Emission Rates from the 2001 – 2003 Baseline Period 

 Maximum 24-hour Emission Rates (lb/hr) 

Unit SO2 NOX PM10

6A Boiler 0.2 90.7 2.5 

9A Boiler 17.9 174.1 72.0 

 

 Georgia-Pacific then compared the calculated maximum 24-hour emission rates from the 

baseline period with emission rates modeled in the 2011 BART screening modeling and with the 

current Title V permit limits (see table below).10 A comparison of these values shows that the 

calculated maximum 24-hour emission rates for each pollutant are below the emission rates 

Georgia-Pacific modeled in the 2011 BART screening modeling, and that the modeled emission 

rates are approximately equal to the currently enforceable Title V permit limits. 

                                                            

9

 A spreadsheet containing the calculated 24-hour emission rates for each day during the years 2001-2003 for the 6A 

and 9A Boilers can be found in the docket for this proposed rulemaking. 

10 See ADEQ Operating Air Permit No. 0597-AOP-R14, issued on May 23, 2012. A copy of the air permit can be 

found in the docket for this proposed rulemaking. 
11 

Table 4. Comparison of Maximum 24-hour Emission Rates with Modeled Emission Rates 

and Title V Permit Limits 

6A Boiler 

SO2 NOX PM10

Calculated Maximum 24-hr Emission Rate (lb/hr) 0.2 90.7 2.5 

Modeled Emission Rate (lb/hr) 0.3 120.0 3.3 

Title V permit Limit (lb/hr) 0.3 120.0 3.3 

9A Boiler 

SO2 NOX PM10

Calculated Maximum 24-hr Emission Rate (lb/hr) 17.9 174.1 72.0 

Modeled Emission Rate (lb/hr) 200.0 218.0 75.8 

Title V permit Limit (lb/hr) 199.8 196.0 77.4 

 Because the 2011 BART screening modeling showed visibility impacts below 0.5 dv 

from the boilers and the recently estimated maximum 24-hour emission rates from the 2001-

2003 baseline period are below the modeled emission rates, it is reasonable to determine that the 

boilers had visibility impacts below 0.5 dv during the baseline period. Accordingly, we believe 

that Georgia‐Pacific’s newly provided analysis and documentation, as described above, is 

appropriate to demonstrate that the 6A and 9A boilers are not subject to BART. In comparison to 

the information available to us when we issued our March 12, 2012, final action on the 2008 

Arkansas RH SIP, we believe this newly provided analysis allows for a more accurate 

assessment of whether or not the 6A and 9A Boilers are subject to BART. Based on this newly 

provided information, we are proposing to find that while the 6A Boiler is a BART-eligible 

source, it is not subject to BART. The 9A Boiler is also BART-eligible (as the State determined 

in the 2008 Arkansas RH SIP), but we are also proposing to find that the 9A Boiler is not subject 

to BART. Therefore, it is not necessary to perform a BART five factor analysis and make BART 

determinations for the Georgia-Pacific Crossett Mill 6A and 9A Boilers. 

2. AECC Carl E. Bailey Generating Station Unit 1 

In our March 12, 2012, final action on the 2008 Arkansas RH SIP, we noted that the 

original meteorological databases generated by the Central Regional Air Planning Association 

(CENRAP) and used by Arkansas to conduct its modeling analyses did not include surface and 

upper air meteorological observations as EPA guidance recommends. Thus, in its evaluation to 

determine if a source exceeds the 0.5 ∆dv contribution threshold at potentially affected Class I 

areas, Arkansas used the maximum value (i.e. 1st high value) of modeled visibility impacts 
12 

instead of the 98th percentile value (i.e. 8th high value). The use of the maximum modeled values 

in the 2008 Arkansas RH SIP was agreed to by EPA, representatives of the Federal Land 

Managers, and CENRAP stakeholders. In our March 12, 2012 final action, we approved 

Arkansas’ determination that the AECC Carl E. Bailey Generating Station (AECC Bailey) Unit 1 

is subject to BART, based on the maximum value of modeled visibility impacts. 

 Following our March 12, 2012, final action on the Arkansas RH SIP, AECC hired a 

consultant to conduct revised modeling of AECC Bailey Unit 1.11 The revised modeling shows 

visibility impacts from Bailey Unit 1 below 0.5 ∆dv, which is the threshold used by Arkansas to 

determine if a source is subject to BART. However, we already approved the State’s 

determination that the AECC Bailey Unit 1 is subject to BART in our March 12, 2012 final 

action on the 2008 Arkansas RH SIP. We do not have the discretion to reopen the issue of 

whether the source is subject to BART because we already approved the portion of the 2008 

Arkansas RH SIP in which Arkansas determined AECC Bailey Unit 1 is subject to BART and 

Arkansas has not provided us a SIP revision to replace the previous determination.12 We cannot 

re-consider our approval of that portion of the 2008 Arkansas RH SIP to have been in error 

because Arkansas did not submit the revised modeling to us with a request to remove the source 

from BART and the modeling approach used by Arkansas in that SIP is consistent with our 

regional haze regulations and was agreed to by us, representatives of the Federal Land Managers, 

and CENRAP stakeholders prior to submittal of the 2008 Arkansas RH SIP. Therefore, our 

proposed FIP is not reopening the issue of whether the source is subject to BART, and our final 

approval of Arkansas’ determination that the source is subject to BART remains in place and in 

the subsection that follows we evaluate AECC Bailey Unit 1 under BART. 

B. BART Requirements: 40 CFR 51.308(e)

 In determining BART, the state, or EPA if implementing a FIP, must consider the five 

statutory factors in section 169A of the CAA: (1) the costs of compliance; (2) the energy and 

non-air quality environmental impacts of compliance; (3) any existing pollution control 

technology in use at the source; (4) the remaining useful life of the source; and (5) the degree of 

improvement in visibility which may reasonably be anticipated to result from the use of such 

technology. See also 40 CFR 51.308(e)(1)(ii)(A). 

 

                                                            

11 See the following BART analyses: “BART Five Factor Analysis, Arkansas Electric Cooperative Corporation 

Bailey and McClellan Generating Stations,” dated March 2014, Version 4, prepared by Trinity Consultants Inc. in 

conjunction with Arkansas Electric Cooperative Corporation; and “BART Five Factor Analysis- NOX Analysis, 

Addendum to the July 24, 2012 BART Five Factor Analysis, Arkansas Electric Cooperative Corporation Bailey 

and McClellan Generating Stations,” dated December 2013, Version 3. A copy of these two BART analyses can 

be found in the docket for our proposed rulemaking. 

12 77 FR 14604, March 12, 2012. 
13 

 The BART Guidelines (70 FR 39164, July 6, 2005) describe the BART analysis as 

consisting of the following five steps: 

 Step 1: Identify All Available Retrofit Control Technologies; 

 Step 2: Eliminate Technically Infeasible Options; 

 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies; 

 Step 4: Evaluate Impacts and Document the Results; and 

 Step 5: Evaluate Visibility Impacts. 

 

 As mentioned previously, Arkansas submitted the 2008 RH SIP to address the first 

regional haze implementation period on September 23, 2008, and August 3, 2010, and submitted 

supplemental information on September 27, 2011. On March 12, 2012, the EPA partially 

approved and partially disapproved the 2008 Arkansas RH SIP (77 FR 14604). This included a 

disapproval of some of the BART determinations made by Arkansas. Following EPA’s partial 

disapproval action, the Arkansas Department of Environmental Quality (ADEQ) worked closely 

with the BART facilities and with EPA Region 6 to revise the Regional Haze SIP. Each subject 

to BART source, through a consultant, performed a BART five-factor analyses to correct the 

State’s BART decisions that were disapproved by us. As part of our proposed FIP, we have 

reviewed the final version of each BART analysis provided to us by each BART facility and 

other relevant information provided to us by ADEQ and the facilities. Our analysis of the five 

factors presented below is largely based on the technical work performed by the BART facilities 

through their consultant.13 See Appendix B to this TSD for our review of the BART modeling 

protocol developed by the BART facilities through their consultant. 

C. BART Determinations and Federally Enforceable Limits 

 This section addresses the BART requirements for Arkansas sources for which we 

disapproved the State’s BART decision in our March 12, 2012 final rulemaking action.14 

1. AECC Carl E. Bailey Generating Station 

The AECC Bailey Unit 1 is subject to BART. In our March 12, 2012 final action we 

disapproved the State’s BART determinations for SO2, NOX, and PM for Bailey Unit 1 (77 FR 

14604). AECC, through its consultant, performed a BART five factor analysis (AECC BART 

                                                            

13 A copy of the final version of each BART analysis performed by a consultant on behalf of each BART sources, 

upon which our analysis is largely based, can be found in the docket for our proposed rulemaking. 

14 Please see our October 17, 2011 proposed rulemaking (76 FR 64186), March 12, 2012 final rulemaking (77 FR 

14604), and the associated TSDs for a complete discussion of the legal rationale for EPA’s disapproval of the 

State’s BART decisions and for a discussion of the BART determinations that were approved by EPA. 
14 

analysis), and our analysis of the five factors presented below is largely based on the technical 

work performed by AECC.15 

The AECC Bailey Unit 1 is a wall-fired boiler with a gross output of 122 MW and a 

maximum heat input rate of 1350 million British thermal units per hour (MMBtu/hr), and is 

currently permitted to burn natural gas and fuel oil. The fuel oil burned at the plant is subject to 

an operating air permit sulfur content limit of 2.3% by weight. 

 

a. Baseline Emission Rates and Existing Visibility Impairment Attributable to Bailey 

Unit 1 

 AECC estimated SO2, NOX, and PM10 baseline emission rates and then modeled these 

emission rates to determine the existing visibility impairment attributable to the boiler based on 

the default natural conditions. As discussed above, the modeled NOX and PM10 baseline 

emission rates for the fuel oil firing scenario were updated from what was modeled in the 2008 

Arkansas RH SIP. The updated baseline emission rates are shown in the table below. 

Table 5. Baseline Emission Rates for AECC Bailey Unit 1 

Unit/Fuel 

Scenario 

SO2

(lb/hr) 

NOX

(lb/hr) 

Total 

PM1016

(lb/hr) 

Inorganic 

Condensable 

SO4

(lb/hr) 

Coarse 

Soil 

PMc 

(lb/hr) 

Fine Soil 

PMf 

(lb/hr) 

Organic 

Condensable 

PM 

SOA 

(lb/hr) 

Elemental 

Carbon 

EC 

(lb/hr) 

Bailey, Unit 1- 

Natural Gas 

0.5 443.8 10.2 0.3 0.0 0.0 7.4 2.6 

Bailey, Unit 1- 

Fuel Oil 2,375.8 408.8 55.8 4.6 13.7 34.1 0.8 2.7 

 The updated baseline emission rates are based on Continuous Emission Monitoring 

System (CEMS) data, stack testing, and AP-42 emission factors. The SO2 and NOX baseline 

emission rates are the highest actual 24-hour emission rates based on 2001-2003 CEMS data. 

The revised NOX emission rate for the fuel oil firing scenario is higher than what was modeled in 

Arkansas’s 2008 RH SIP. 

                                                            

15 See the following BART analyses: “BART Five Factor Analysis, Arkansas Electric Cooperative Corporation 

Bailey and McClellan Generating Stations,” dated March 2014, Version 4, prepared by Trinity Consultants Inc. in 

conjunction with Arkansas Electric Cooperative Corporation; and “BART Five Factor Analysis- NOX Analysis, 

Addendum to the July 24, 2012 BART Five Factor Analysis, Arkansas Electric Cooperative Corporation Bailey and 

McClellan Generating Stations,” dated December 2013, Version 3. A copy of these two BART analyses can be 

found in the docket for our proposed rulemaking. 

16 The National Park Service PM speciation worksheets are typically used to speciate PM10 into SO4, PMc, PMf, 

SOA, and EC. 
15 

 The PM10 emission rate for natural gas combustion is based on the emission factor for 

total PM10 in Table 1.4-2 of AP-42, which is 7.6 lbs/MMscf, and the unit’s maximum heat input. 

The emission rate for the PM10 species for natural gas combustion reflects the breakdown of the 

filterable and condensable PM10 determined from AP-42 Table 1.4-2 Combustion of Natural 

Gas. All filterable PM was assumed to be elemental carbon and all condensable PM was 

assumed to be SOA, except for a small fraction of the condensable PM that was estimated to be 

sulfate (SO4). 

 The revised PM10 emission rate for fuel oil combustion is lower than what was modeled 

in Arkansas’s 2008 RH SIP. The revised PM10 emission rate for fuel oil combustion was based 

on stack testing of filterable and condensable PM10 emissions conducted by the facility on AECC 

McClellan Unit 1. The results of the stack testing showed that the total PM10 emission rate for 

McClellan Unit 1 was 59.4 lb/hr. The total PM10 emission rate for Bailey Unit 1 was determined 

by scaling the heat input ratio for Bailey vs. McClellan (1350 lb/MMBtu / 1436 lb/MMBtu) to 

get a total PM10 emission rate of 55.8 lb/hr. The emission rate for the PM10 species shown in the 

table above reflects the breakdown of the PM10 emissions as determined using the National Park 

Service (NPS) “speciation spreadsheet” for Uncontrolled Utility Residual Oil Boilers.17 Our 

concern with AECC’s use of the revised PM10 emission rate based on stack testing for the fuel 

oil firing scenario is that there is no discussion provided on how the stack test results are 

representative of the maximum 24-hour emissions. However, since the visibility impacts due to 

PM10 emissions from Bailey Unit 1 are so small, we believe a closer inspection of the revised 

PM10 emission rate for fuel oil combustion and any further revision to it would likely not result 

in significant changes to the modeled visibility impacts and would not affect our proposed BART 

decision. For Bailey Unit 1, the percentage of the visibility impairment at the four Class I areas 

attributable to PM10 ranges from approximately 3 – 11% for the natural gas firing scenario and 

0.5 – 3% for the fuel oil firing scenario. Most of the visibility impairment due to Bailey Unit 1 is 

attributable to NO3 (approximately 83 – 96%) for the natural gas firing scenario and to SO4 (67 – 

99%) for the fuel oil firing scenario (see the table below). Therefore, we did not take further 

steps to adjust the PM10 emission rates or conduct additional modeling. 

 AECC modeled the baseline emission rates using the CALPUFF dispersion model to 

determine the baseline visibility impairment attributable to Bailey Unit 1 at the four Class I areas 

impacted by emissions from BART sources in Arkansas: the Caney Creek Wilderness Area, the 

Upper Buffalo Wilderness Area, the Hercules-Glades Wilderness Area, and the Mingo National 

Wildlife Refuge. The baseline (i.e., existing) visibility impairment attributable to Bailey Unit 1 at 

each Class I area is summarized in the tables below. 

Table 6. Baseline Visibility Impairment Attributable to Bailey Unit 1 (2001-2003)- 

                                                            

17 The NPS Workbook, “Uncontrolled Utility Residual Oil Boiler.xls” updated 03/2006, was obtained from the NPS 

website: http://www.nature.nps.gov/air/Permits/ect/index.cfm. The following parameters were input into the 

workbook for speciation determination for Bailey: No. 6 fuel oil with a sulfur content of 1.81% and a heat input 

of 1,350 MMBtu/hr. 
16 

Natural Gas Firing 

Year Maximum 

(∆dv) 

98th

Percentile 

(∆dv) 

No. of 

Days with 

∆dv ≥ 0.5 

98th

Percentile 

%SO4

98th

Percentile 

%NO3

98th

Percentile 

%PM10

98th

Percentile 

%NO2

Caney Creek Wilderness 

2001 0.137 0.083 0 0.28 93.36 3.35 0.00 

2002 0.219 0.075 0 0.31 95.93 3.22 0.54 

2003 0.067 0.067 0 0.4 91.98 5.51 2.10 

Upper Buffalo Wilderness 

2001 0.089 0.04 0 0.23 95.01 3.05 1.72 

2002 0.160 0.031 0 0.30 86.44 5.48 7.77 

2003 0.170 0.072 0 0.29 95.02 3.43 1.26 

Hercules-Glades Wilderness 

2001 0.238 0.056 0 0.23 96.39 3.08 0.31 

2002 0.067 0.039 0 0.88 87.67 10.78 0.67 

2003 0.175 0.073 0 0.22 92.76 3.67 3.35 

Mingo National Wildlife Refuge 

2001 0.154 0.070 0 0.29 90.58 5.41 3.72 

2002 0.443 0.084 0 0.43 83.07 7.92 8.58 

2003 0.201 0.102 0 0.45 83.34 8.10 8.11 

Table 7. Baseline Visibility Impairment Attributable to Bailey Unit 1 (2001-2003)- 

Fuel Oil Firing 

Year Maximum 

(∆dv) 

98th

Percentile 

(∆dv) 

No. of 

Days with 

∆dv ≥ 0.5 

98th

Percentile 

%SO4

98th

Percentile 

%NO3

98th

Percentile 

%PM10

98th

Percentile 

%NO2

Caney Creek Wilderness 

2001 0.684 0.307 2 75.66 22.47 1.44 0.44 

2002 0.745 0.330 3 87.19 12.11 0.57 0.14 

2003 0.970 0.327 3 98.80 0.81 0.40 0 

Upper Buffalo Wilderness 

2001 0.578 0.282 3 94.29 4.99 0.73 0.00 

2002 0.668 0.305 1 73.65 21.28 3.43 1.64 

2003 0.696 0.348 3 90.73 8.42 0.83 0.02 

Hercules-Glades Wilderness 

2001 0.687 0.327 3 98.40 1.07 0.52 0 

2002 0.635 0.249 2 80.38 18.62 0.87 0.12 

2003 0.648 0.368 1 82.74 14.39 2.08 0.79 
17 

Mingo National Wildlife Refuge 

2001 0.52 0.355 1 89.57 8.35 1.67 0.41 

2002 1.592 0.379 7 93.95 4.68 1.26 0.11 

2003 0.689 0.300 4 66.17 29.13 2.83 1.87 

b. SO2 BART Evaluation 

 AECC Bailey Unit 1 currently combusts natural gas and No. 6 fuel oil. Because the SO2

emissions profile and the 98th percentile visibility impact from natural gas combustion attributed 

to the unit is very small, AECC did not consider additional SO2 controls for combustion of 

natural gas and instead focused the SO2 evaluation on controlling SO2 emissions from 

combustion of No. 6 fuel oil. Because of the low SO2 emissions associated with natural gas 

combustion and the relatively low baseline visibility impacts from AECC Bailey Unit 1 when 

burning natural gas, we concur with AECC’s decision to focus the evaluation on controlling SO2

emissions resulting from the combustion of No. 6 fuel oil. The five factors considered in the 

analysis are discussed below. 

Step 1- Identify All Available Retrofit Control Technologies 

 For SO2 BART, AECC considered flue gas desulfurization (FGD) and fuel switching. 

The type of FGD technologies considered consisted of Dry Sorbent Injection (DSI), Spray Dryer 

Absorber (SDA), wet FGD, and dry FGD. 

Step 2- Eliminate Technically Infeasible Options

 AECC found that FGD applications have not been used historically for SO2 control on 

fuel oil-fired units in the U.S. electric industry and therefore considered it a technically infeasible 

option for control of Bailey Unit 1. Accordingly, AECC did not further consider FGD for SO2

BART. We concur with AECC’s decision to focus the SO2 evaluation on fuel switching. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 

 AECC Bailey Unit 1 currently burns some residual fuel oil. The most recent No. 6 fuel 

oil shipment for Bailey Unit 1 was in December 2006, and had an average sulfur content of 

1.81% by weight. A portion of the fuel oil from this shipment still remains in storage at the 

facility for future use. The baseline fuel used in the BART analysis is based on the average sulfur 

content of the fuel oil from this shipment. Switching to a fuel with a lower sulfur content is 

expected to reduce SO2 emissions in proportion to the reduction in the sulfur content of the fuel, 

assuming similar heat contents of the fuels. The fuel types with lower sulfur content evaluated by 
18 

AECC are lower sulfur No. 6 fuel oil, No. 2 fuel oil (i.e., diesel), and natural gas. These fuel 

types and the estimated control efficiency of each are shown in the table below. 

Table 8. Control Effectiveness of Technically Feasible SO2 Control Technologies for Bailey 

Unit 1 

Fuel Switching to: Estimated Control Efficiency (%) 

No. 6 fuel oil (1% sulfur) 45% 

No. 6 fuel oil (0.5% sulfur) 72% 

Diesel (0.05% sulfur) 97% 

Natural gas (0.04% sulfur) 99.9% 

 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

 Bailey Unit 1 currently burns both No. 6 fuel oil and natural gas. AECC estimated the 

cost of fuel switching by determining the annual cost of the No. 6 fuel oil currently used (i.e., the 

baseline fuel) and determining the cost of switching to the various lower sulfur content fuels. The 

supplier of the existing fuels (i.e., No. 6 fuel oil and natural gas) provided AECC with current 

cost estimates for the existing fuels and for the lower sulfur content No. 6 fuel oil and diesel. As 

shown in the table below, the supplier’s estimate for the cost of No. 6 fuel oil with 0.5% and 1% 

sulfur content is $17.75/MMBtu and $16.50 /MMBtu (respectively), and for diesel is 

$20.95/MMBtu. The cost of the base case No. 6 fuel oil with 1.81% sulfur content was estimated 

to be $16.00/MMBtu. 

 AECC estimated the SO2 annual emissions reductions as a result of fuel switching by 

subtracting the estimated controlled annual emission rates from the baseline annual emission 

rates. AECC estimated the baseline and controlled annual emission rates by conducting a mass 

balance on the sulfur in the various fuels.18 The sulfur content of the baseline fuel is 1.81% by 

weight. The SO2 emissions associated with the base case and the fuel switching scenarios (i.e., 

1% sulfur No. 6 fuel oil, 0.5% sulfur No. 6 fuel oil, diesel, and natural gas) were estimated by 

multiplying the baseline annual fuel usage by the fuel density and by the percent sulfur content 

of the fuel. This yielded the quantity of sulfur in the fuel. The SO2 emissions were then estimated 

                                                            

18 See the following BART analyses: “BART Five Factor Analysis, Arkansas Electric Cooperative Corporation 

Bailey and McClellan Generating Stations,” dated March 2014, Version 4, prepared by Trinity Consultants Inc. in 

conjunction with Arkansas Electric Cooperative Corporation. 
19 

by multiplying the quantity of sulfur available to form SO2 by the ratio of the molecular weight 

for SO2 vs. sulfur. See the table below for the estimated SO2 emissions associated with the base 

case and with each fuel switching scenario. 

 To calculate the average cost-effectiveness of fuel switching, AECC divided the annual 

cost increase of switching to a lower sulfur fuel by the annual SO2 tons reduced as a result of fuel 

switching. The table below shows the average cost-effectiveness and incremental costeffectiveness of fuel switching for Bailey Unit 1. 

Table 9. Summary of Costs Associated with Fuel Switching for Bailey Unit 1 

Fuel 

Switching 

Scenario 

Average 

Sulfur 

Content 

(%) 

Baseline 

Emission 

Rate 

(SO2

tpy) 

Controlled 

Emission 

Rate 

(SO2 tpy) 

Annual 

Emissions 

Reductions 

(SO2 tpy) 

Annual 

Heat Input 

(MMBtu/yr) 

Fuel Heating 

Value 

(MMBtu/Mgal) 

or 

(MMBtu/Mscf) 

Annual 

Fuel 

Usage 

(Mgal/yr) 

Fuel Cost 

($/MMBtu) 

Total 

Annual 

Differential 

Cost of 

Fuel 

Switching 

($/yr) 

Average 

CostEffectiveness 

($/ton) 

Incremental 

Cost 

Effectiveness19

($/ton) 

Base 

Case 1.81 37.03 - - 39,193 155.00 252.86 16.00 - - - 

No. 6 - 

1% 1.00 - 20.67 16.36 39,193 155.00 252.86 16.50 19,596 1,198 - 

No. 6 - 

0.5% 0.50 - 10.23 26.80 39,193 155.00 252.86 17.75 68,587 2,559 4,693 

Diesel 0.05 - 0.99 36.05 39,193 136.15 287.86 20.95 194,003 5,382 13,558 

Natural 

Gas 0.04 - 0.01 37.02 39,193 1,011.00 38.77 6.19 (384,550) -10,387 -596,446 

 AECC’s evaluation did not identify any energy or non-air quality impacts associated with 

switching to 1% sulfur No. 6 fuel oil, 0.5% sulfur No. 6 fuel oil, or diesel. The evaluation 

indicated that switching to natural gas may have an impact during periods of natural gas 

curtailment. During periods of natural gas curtailment, natural gas infrastructure maintenance, 

and other emergencies, the AECC Bailey Generating Station relies on the fuel oil stored at the 

plant to maintain electrical reliability. AECC’s evaluation indicates that because of this, the 

ability to burn fuel oil at AECC Bailey is important even if fuel oil is currently more expensive 

than natural gas. 

 The presence of existing pollution control technology is reflected in the BART analysis 

in two ways: first, in the consideration of available control technologies, and second, in the 

                                                            

19 The incremental cost-effectiveness calculation compares the costs and performance level of a control option to 

those of the next most stringent option, as shown in the following formula (with respect to cost per emissions 

reduction): Incremental Cost Effectiveness (dollars per incremental ton removed) = (Total annualized costs of 

control option) – (Total annualized costs of next control option) / (Control option annual emissions) – Next 

control option annual emissions). See BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4.e. 
20 

development of baseline emission rates for use in cost calculations and visibility modeling. 

Bailey Unit 1 has no existing SO2 pollution control technology. 

 With regard to consideration of the remaining useful life of the unit, this factor does not 

impact the SO2 BART analysis in this case since it is assumed that fuel switching will not require 

any capital cost expenditures. 

Step 5- Evaluate Visibility Impacts 

AECC assessed the visibility improvement associated with fuel switching by comparing 

the visibility impairment from the baseline scenario to the impairment associated with each 

control scenario. The SO2 emission rate in lb/MMBtu associated with the combustion of each 

fuel type was calculated by scaling the existing 30-day rolling average emission rate from 2001-

2003 by the ratio of the sulfur content of the new fuel and the current maximum annual average 

sulfur content from 2009-2011. The controlled 30-day emission rate in lb/MMBtu was converted 

to units of lb/hr by multiplying by the boiler design heat input. The tables below show the 

emission rates modeled and a comparison of the baseline (i.e., existing) visibility impacts and the 

visibility impacts associated with fuel switching, including the maximum modeled visibility 

impact and the 98th percentile modeled visibility impact. The visibility improvement associated 

with fuel switching was calculated as the difference between the existing visibility impairment 

and the visibility impairment for each fuel scenario as measured by the 98th percentile modeled 

visibility impact. 

Table 10. Summary of Emission Rates Modeled for SO2 Control Scenarios at AECC Bailey 

Unit 1

SO2

(lb/hr)

SO4

(lb/hr)

NOX 

(lb/hr)

PMC

(lb/hr)

PMF

(lb/hr)

SOA

(lb/hr)

EC

(lb/hr)

PM10, total

(lb/hr)

1% sulfur fuel 

oil No. 6 1,187.6 2.5 408.8 4.7 11.7 0.4 0.9 20.3 

0.5% sulfur 

fuel oil No. 6 593.8 1.3 408.8 1.5 3.7 0.2 0.3 6.9 

Diesel 59.4 0.1 408.8 0.1 0.2 0.0 0.0 0.4 

Natural gas 0.5 0.3 443.8 0.0 0.0 7.4 2.6 10.3 
21 

Table 11. AECC Bailey Unit 1: Summary of 98th Percentile Visibility Impacts and 

Improvement due to Fuel Switching 

Class I 

area

Baseline 

Visibility 

Impact 

(∆dv)

No. 6 Fuel Oil- 1% 

Sulfur No. 6 Fuel Oil- 0.5% Sulfur Diesel Natural Gas 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

1% Sulfur fuel 

oil 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

0.5% Sulfur 

fuel oil 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

Diesel 

Caney Creek 0.330 0.193 0.137 0.142 0.188 0.051 0.084 0.246 0.058 0.083 0.247 0.001 

Upper 

Buffalo 0.348 0.194 0.154 0.127 0.221 0.067 0.069 0.279 0.058 0.072 0.276 -0.003 

HerculesGlades 0.368 0.206 0.162 0.135 0.233 0.071 0.069 0.299 0.066 0.073 0.295 -0.004 

Mingo 0.379 0.206 0.173 0.170 0.209 0.036 0.095 0.284 0.075 0.102 0.277 -0.007 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.626 -- 0.851 -- -- 1.108 -- -- 1.095 -- 

 The table above shows that switching to No. 6 fuel oil with 1% sulfur content at Bailey 

Unit 1 is projected to result in 0.173 dv visibility improvement at Mingo (based on the 98th

percentile modeled visibility impacts). The visibility improvement at each of the other three 

affected Class I areas is projected to be slightly less than that amount, while the cumulative 

visibility improvement at the four Class I areas is projected to be 0.626 dv. Switching to No. 6 

fuel oil with 0.5% sulfur content is projected to result in meaningful visibility improvement. It is 

projected to result in 0.233 dv visibility improvement at Hercules-Glades. The visibility 

improvement at each of the other three affected Class I areas is projected to be slightly less than 

that amount, while the cumulative visibility improvement at the four Class I areas is projected to 

be 0.851 dv. Switching to diesel or natural gas is also projected to result in meaningful visibility 

improvement. The visibility improvement at Hercules-Glades is projected to be 0.299 dv for 

switching to diesel and 0.295 dv for switching to natural gas. The cumulative visibility 

improvement at the four Class I areas is projected to be 1.108 dv for switching to diesel and 

1.095 dv for switching to natural gas. 
22 

Our Proposed SO2 BART determination: 

Taking into consideration the five factors, we are proposing to determine that BART for 

the AECC Bailey Unit 1 is switching to fuels with 0.5% or lower sulfur content by weight. The 

cost of switching to No. 6 fuel oil with 0.5% sulfur content is within the range of what we 

consider to be cost-effective for BART and it is projected to result in considerable visibility 

improvement compared to the baseline at the affected Class I areas. Switching to No. 6 fuel oil 

with 0.5% sulfur content has an estimated average cost-effectiveness of $2,559/ ton of SO2

removed and is projected to result in visibility improvement ranging from 0.188 to 0.233 dv at 

each modeled Class I area, and a cumulative visibility improvement of 0.851 dv at the four 

modeled Class I areas. Switching to natural gas would currently cost less than the baseline fuel 

oil and is projected to result in even greater visibility improvement than switching to No. 6 fuel 

oil with 0.5% sulfur content. However, the BART Guidelines provide that it is not our intent to 

direct subject-to-BART sources to switch fuel forms, such as from coal or fuel oil to gas (40 

CFR Part 51, Appendix Y, section IV.D.1). Because natural gas has a sulfur content by weight 

that is well below 0.5%, the facility may elect to use this type of fuel to comply with BART, but 

we are not proposing to require a switch to natural gas for Unit 1. Switching to diesel is projected 

to result in an almost identical level of visibility improvement at each Class I area as switching to 

natural gas. The incremental visibility improvement of switching to diesel compared to switching 

to No. 6 fuel oil with a sulfur content of 0.5% is projected to range from 0.058 dv to 0.075 dv at 

each affected Class I area but the average cost-effectiveness is estimated to be $5,382/ ton of SO2

removed and the incremental cost-effectiveness compared to switching to No. 6 fuel oil with a 

sulfur content of 0.5% is estimated to be $13,558/ ton of SO2 removed, which we do not consider 

to be very cost-effective in view of the relatively low incremental visibility improvement. 

Because diesel also has a sulfur content by weight that is well below 0.5%, the facility may elect 

to use this type of fuel to comply with BART, but we are not proposing to require a switch to 

diesel for Unit 1. We are proposing to determine that SO2 BART for Bailey Unit 1 is switching 

to fuels with 0.5% or lower sulfur content by weight. We propose to require that the facility 

purchase no fuel after the effective date of the rule that does not meet the sulfur content 

requirement and that 5 years from the effective date of the rule no fuel be burned that does not 

meet the requirement. We expect this proposed compliance date would allow the facility 

sufficient time to burn its existing supply of No. 6 fuel oil (i.e., the baseline fuel), as the normal 

course of business dictates and in accordance with any operating restrictions enforced by ADEQ. 

We propose that any higher sulfur fuel oil that remains from the facility’s 2006 shipment cannot 

be burned past this point. 

c. NOX BART Evaluation 

Nitrogen oxides, or NOX, are produced during fuel combustion when nitrogen contained 

in both the fuel and the combustion air is exposed to high temperatures. Nitrogen oxide (NO) is 
23 

typically the predominant form of NOX from fossil fuel combustion, with nitrogen dioxide (NO2) 

making up the remainder of the NOX. AECC’s evaluation noted that the formation of NOX

compounds in utility boilers is sensitive to the method of firing and combustion flame 

temperatures. In wall-fired boilers, such as Bailey Unit 1, burners are mounted in the boiler 

walls, producing discrete flames in the furnace. In tangentially-fired boilers, a single rotating 

flame is created in the center of the furnace, rather than the discrete flames produced by burners 

in the wall-fired boilers. Tangentially fired boilers typically have lower uncontrolled NOX

emissions than wall-fired boilers. Therefore, baseline NOX emission rates can vary significantly 

from plant to plant due to method of firing and combustion flame temperatures, among other 

factors. The baseline NOX emission rate for Bailey Unit 1 is discussed under section II.C.1.a. of 

this TSD. The five factors considered in the NOX BART analysis are discussed below. 

Step 1- Identify All Available Retrofit Control Technologies 

 For NOX BART, AECC evaluated both combustion and post-combustion controls. 

Combustion controls involve reducing the peak flame temperature and excess air in the furnace 

to minimize NOX formation, while post-combustion controls involve converting NOX in the flue 

gas to molecular nitrogen and water. The combustion controls evaluated by AECC consisted of 

flue gas recirculation (FGR), overfire air (OFA), and Low NOX Burners (LNB). The postcombustion controls evaluated consisted of Selective Catalytic Reduction (SCR) and Selective 

Non-Catalytic Reduction (SNCR). 

 

Step 2- Eliminate Technically Infeasible Options

 AECC found that some boilers may be restricted from installing OFA retrofits due to 

physical size and space restraints. For purposes of the NOX BART evaluation, AECC assumed 

OFA to be a technically feasible option for Bailey Unit 1, but noted that if the five factor BART 

analysis deemed OFA to be BART, then further analyses would have to be performed to 

determine if (1) the dimensions of the main boiler has sufficient upper furnace volume for OFA 

mixing and complete combustion; and (2) if there are physical space requirements for OFA ports 

and air supply ducts. AECC found the remaining NOX control options to be technically feasible. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 The estimated NOX controlled emission rate of each control option considered by AECC 

is shown in the table below. In its evaluation, AECC considered the following control options: a 

combination of combustion controls (i.e., FGR, OFA, and LNB); a combination of combustion 

controls and SNCR; and SCR. AECC estimated that when FGR is operated alone, the NOX

control range for oil and gas wall-fired boilers is approximately 0.2 – 0.4 lb/MMBtu, and when 

OFA is operated alone it results in an estimated NOX controlled emission rate of 0.2 – 0.3 
24 

lb/MMBtu.20 It also estimated that when LNB is combined with OFA and FGR, a NOX 

controlled emission rate of 0.15 – 0.20 lb/MMBtu is achievable. 

 AECC found that the estimated NOX control efficiency of SCR is 80-90% on gas fired 

boilers and 70-80% for oil fired boilers, and estimated that when SCNR is combined with 

combustion controls, the NOX level of control is estimated to be 10% greater than with 

combustion controls alone.21 

Table 12. Control Effectiveness of Technically Feasible NOX Control Technologies for 

AECC Bailey Unit 1 

Control Technology 

Baseline NOX Emission Rate 

 (lb/MMBtu) 

Estimated NOX Controlled Emission 

Rate (lb/MMBtu) 

Natural Gas Fuel Oil Natural Gas Fuel Oil 

SCR 

0.29 0.30 

0.04 0.08 

Combustion Controls + SNCR 0.12 0.12 

Combustion Controls 0.15 0.15 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, the existing pollution control technology in use at 

the source, and the remaining useful life of the source. 

 AECC’s cost analysis for NOX controls22 was based on “budgetary” cost estimates it 

obtained from the pollution control equipment vendor, Babcock Power Systems. AECC 

estimated the capital and operating costs of controls based on the vendor’s estimates, engineering 

estimates, and published calculation methods using EPA’s Air Pollution Control Cost Manual 

                                                            

20 “Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options,” section II, dated July 1994, State 

and Territorial Air Pollution Program Administrators (STAPPA) and Association of Local Air Pollution Control 

Officials (ALAPCO). 

21 “Preferred and Alternative Methods for Estimating Air Emissions from Boilers” Table 2.2-2. January 2001. See 

http://www.epa.gov/ttn/chief/eiip/techreport/volume02/ii02.pdf. 

22 See “BART Five Factor Analysis- NOX Analysis, Addendum to the July 24, 2012 BART Five Factor Analysis, 

Arkansas Electric Cooperative Corporation Bailey and McClellan Generating Stations,” dated December 2013, 

Version 3. 
25 

(EPA Control Cost Manual).23 We are not aware of any enforceable shutdown date for the AECC 

Bailey Generating Station, nor did AECC’s evaluation indicate any future planned shutdown. 

This means that the anticipated useful life of the boiler is expected to be at least as long as the 

capital cost recovery period of controls. Therefore, a 30-year amortization period was assumed in 

the NOX BART analysis as the remaining useful life of the unit. The table below summarizes the 

estimated cost for installation and operation of NOX controls for Bailey Unit 1. 

 AECC determined the annual emissions reductions associated with each NOX control 

option by subtracting the estimated controlled annual emission rate from the baseline annual 

emission rate. The baseline annual emission rates are the average rates from 2009-2011, while 

the controlled annual emission rates are based on the lb/MMBtu levels believed to be achievable 

from the control technology multiplied by the baseline heat inputs to the boilers in MMBtu/yr. 

The baseline heat inputs for each unit are the sum of the baseline heat inputs for natural gas and 

fuel oil. The baseline heat inputs for natural gas are based on the average natural gas usage for 

each unit from 2007-2011 multiplied by the average heat content of natural gas for the same time 

period. Similarly, the baseline heat inputs for fuel oil are based on the average fuel oil usage for 

each unit from 2007-2011 multiplied by the average heat content of fuel oil for the same time 

period. 

 To calculate the average cost-effectiveness of NOX controls, AECC divided the total 

annual cost of each control option by the estimated annual NOX tons reduced. The table below 

shows the average cost effectiveness of NOX controls for Bailey Unit 1. 

Table 13. Summary of Costs of NOX Controls for AECC Bailey Unit 1 

Control 

Scenario 

Baseline 

Emission 

Rate 

(NOX

tpy) 

Natural 

Gas 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Fuel Oil 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Natural Gas 

Annual 

Heat Input 

(MMBtu/yr) 

Fuel Oil 

Annual 

Heat Input 

(MMBtu/yr) 

Controlled 

Emission 

Rate 

(NOX tpy) 

Annual 

Emissions 

Reductions 

(NOX tpy) 

Capital 

Cost 

($) 

Total 

Annual 

Cost 

($/yr) 

Average 

CostEffectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

Combustion 

Controls 49.81 0.15 0.15 371,866 39,193 30.83 18.98 7,700,000 700,477 36,905 -- 

Combustion 

Controls + 

SNCR 

49.81 0.12 0.12 371,866 39,193 24.79 25.02 11,903,724 1,223,157 48,884 86,536 

SCR 49.81 0.04 0.08 371,866 39,193 9.65 40.16 11,708,183 1,555,718 38,738 21,996 

 AECC estimated the average cost-effectiveness of installing and operating combustion 

controls to be $36,905/ton of NOX removed for Bailey Unit 1. The combination of combustion 

controls and SNCR was estimated to cost $48,884/ton of NOX removed, while SCR was 

                                                            

23 EPA’s “Air Pollution Control Cost Manual,” Sixth edition, January 2002, is located at 

www.epa.gov/ttncatc1/products.html#cccinfo.
26 

estimated to cost $38,738/ton of NOX removed. In its evaluation, AECC also explained that it 

expects NOX controls to be less cost-effective (i.e., greater dollars per ton removed) in future 

years due to projected reduced operation of the unit. Less projected operating time is expected to 

result in lower annual emissions, which would result in lower cost-effectiveness. 

 AECC did not identify any energy or non-air quality environmental impacts associated 

with the use of LNB, OFA, or FGR. As for SCR and SNCR, we are not aware of any unusual 

circumstances at the facility that could create energy or non-air quality environmental impacts 

associated with the operation of these controls greater than experienced elsewhere and that may 

therefore provide a basis for their elimination as BART (40 CFR Part 51, Appendix Y, section 

IV.D.4.i.2.). Therefore, we do not believe there are any energy or non-air quality environmental 

impacts associated with NOX controls at AECC Bailey Unit 1 that would affect our proposed 

BART determination. 

 With regard to consideration of any existing pollution control technology in use at the 

source, Bailey Unit 1 has no existing NOX pollution control technology. The presence of existing 

pollution control technology at the source is reflected in the BART analysis in two ways: first, in 

the consideration of available control technologies, and second, in the development of baseline 

emission rates for use in cost calculations and visibility modeling. 

 With regard to consideration of the remaining useful life of the unit, we are not aware of 

any enforceable shutdown date for the AECC Bailey Generating Station, nor did AECC’s 

evaluation indicate any future planned shutdown. This means that the anticipated useful life of 

the boiler is expected to be at least as long as the capital cost recovery period of controls. 

Therefore, a 30-year amortization period was assumed in the NOX BART analysis as the 

remaining useful life of the unit. 

Step 5- Evaluate Visibility Impacts 

AECC assessed the visibility improvement associated with NOX controls by modeling the 

NOX emission rates associated with each control option using CALPUFF, and then comparing 

the visibility impairment associated with the baseline emission rates to the visibility impairment 

associated with the controlled emission rates. The controlled emission levels associated with 

combustion controls, combustion controls + SNCR, and SCR systems are shown in the table 

above. These levels were multiplied by the unit’s maximum heat input to derive the hourly 

emission rates used in the modeling. The tables below show the emission rates modeled and a 

comparison of the existing (i.e., baseline) visibility impacts and the visibility impacts based on 

NOX controls, including the maximum modeled visibility impact and the 98th percentile modeled 

visibility impact for each Class I area. The visibility improvement associated with NOX controls 

was calculated as the difference between the baseline visibility impairment and the visibility 

impairment for each control scenario as measured by the 98th percentile modeled visibility 

impact. 
27 

Table 14. Summary of Emission Rates Modeled for NOX Control Scenarios at AECC 

Bailey Unit 1

Control 

Scenario 

 Fuel 

Scenario 

SO2

(lb/hr) 

NOX

(lb/hr) 

Total 

PM10

(lb/hr) 

SO4

(lb/hr) 

PMc 

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

Combustion 

Controls 

Natural 

Gas 0.5 202.5 10.2 0.3 0.0 0.0 7.4 2.5 

Fuel Oil 2,375.8 202.5 49.4 4.0 12.1 30.2 0.7 2.4 

SCR 

Natural 

Gas 0.5 59.4 10.2 0.3 0.0 0.0 7.4 2.5 

Fuel Oil 2,375.8 101.5 49.4 4.0 12.1 30.2 0.7 2.4 

Combustion 

Controls + 

SNCR 

Natural 

Gas 0.5 162.9 10.2 0.3 0.0 0.0 7.4 2.5 

Fuel Oil 2,375.8 161.9 49.4 4.0 12.1 30.2 0.7 2.4 

Table 15. AECC Bailey Unit 1: Summary of the 98th Percentile Visibility Impacts and 

Improvement due to NOX Controls- Natural Gas Firing 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

Combustion Controls Combustion 

 Controls + SNCR SCR 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

Combustion 

Controls 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

Combustion 

Controls + 

SNCR 

(∆dv) 

Caney Creek 0.083 0.039 0.044 0.032 0.051 0.007 0.014 0.069 0.018 

Upper 

Buffalo 0.072 0.034 0.038 0.028 0.044 0.006 0.013 0.059 0.015 

HerculesGlades 0.073 0.035 0.038 0.029 0.044 0.006 0.013 0.06 0.016 

Mingo 0.102 0.051 0.051 0.043 0.059 0.008 0.021 0.081 0.022 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.171 -- 0.198 -- -- 0.269 -- 
28 

Table 16. AECC Bailey Unit 1: Summary of the 98th Percentile Visibility Impacts and 

Improvement due to NOX Controls- Fuel Oil Firing 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

Combustion Controls Combustion 

Controls + SNCR SCR 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

Combustion 

Controls 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from 

Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

Combustion 

Controls + 

SNCR 

(∆dv) 

Caney Creek 0.330 0.325 0.005 0.325 0.005 0.000 0.323 0.007 0.002 

Upper 

Buffalo 0.347 0.332 0.015 0.329 0.018 0.003 0.325 0.022 0.004 

HerculesGlades 0.367 0.339 0.028 0.333 0.034 0.006 0.325 0.042 0.008 

Mingo 0.378 0.369 0.009 0.367 0.011 0.002 0.364 0.014 0.003 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.057 -- 0.068 -- -- 0.085 -- 

 The table above shows that the installation and operation of NOX controls is projected to 

result in very modest visibility improvement from the baseline. Combustion controls at Bailey 

Unit 1 are projected to result in visibility improvement ranging from 0.038 – 0.051 dv at each 

Class I area for natural gas firing and 0.005 – 0.028 dv for fuel oil firing (based on the 98th 

percentile modeled visibility impacts). A combination of combustion controls and SNCR is 

projected to result in negligible incremental visibility improvement compared to combustion 

controls alone for both the natural gas and fuel oil firing scenarios. The installation and operation 

of SCR at Bailey Unit 1 is projected to result in visibility improvement ranging from 0.059 – 

0.081 dv at each Class I area for natural gas firing and 0.007 – 0.042 dv for fuel oil firing. SCR is 

projected to result in negligible incremental visibility improvement compared to a combination 

of combustion controls and SNCR. 

Our Proposed NOX BART determination: 

Taking into consideration the five factors, we are proposing to determine that NOX

BART for the AECC Bailey Unit 1 is no additional controls, and are proposing that the existing 

NOX emission limit satisfies BART for NOX. We are proposing the existing emission limit of 
29 

887 lb/hr for NOX BART for Bailey Unit 1.24 As discussed above, the operation of combustion 

controls at Bailey Unit 1 is projected to result in a maximum visibility improvement of 0.051 

∆dv (Mingo), and a smaller amount of visibility improvement at each of the other affected Class 

I areas. The installation and operation of combustion controls at Bailey Unit 1 has an average 

cost-effectiveness of $36,905/ton of NOX removed, which is not cost-effective. We believe the 

relatively small visibility benefit projected from the operation of combustion controls both when 

combusting fuel oil and natural gas does not justify the high estimated cost of those controls. The 

operation of a combination of combustion controls + SNCR is estimated to cost $48,884/ton of 

NOX removed, which is also not cost-effective. A combination of combustion controls + SNCR 

is projected to result in negligible incremental visibility benefit compared to combustion controls 

alone. The operation of SCR is estimated to cost $38,738/ton of NOX removed, which is not 

cost-effective, and is projected to result in negligible incremental visibility benefit compared to a 

combination of combustion controls + SNCR. We are proposing to find that NOX BART for 

Bailey Unit 1 is no additional controls and are proposing the aforementioned existing NOX

emission limit for NOX BART. We are proposing that this already-existing emission limitation 

be complied with for BART purposes as of the effective date of the final action. 

 

d. PM BART Evaluation 

 The five factors considered in the PM BART analysis for Bailey Unit 1 are discussed 

below. 

Step 1- Identify All Available Retrofit Control Technologies 

 For PM BART, AECC considered the following technologies: dry electrostatic 

precipitator (ESP), wet ESP, fabric filter, wet scrubber, cyclone (i.e., mechanical collector), and 

fuel switching. 

 Residual fuel, such as the No. 6 fuel oil burned at Bailey Unit 1, has inherent ash that 

contributes to emissions of filterable PM. Filterable PM emissions could be reduced by switching 

to a lower grade fuel oil or natural gas. For combustion of No. 6 fuel oil, reductions in filterable 

PM are directly related to the sulfur content of the fuel.25 Therefore, switching to No. 6 fuel oil 

with a lower sulfur content is expected to result in lower filterable PM emissions. AECC’s 

evaluation considered switching to No. 6 fuel oil with 1% sulfur content by weight, No. 6 fuel oil 

with 0.5% sulfur content by weight, diesel, and natural gas. These are the same lower sulfur fuel 

types evaluated in the SO2 BART analysis for the unit. 

Step 2- Eliminate Technically Infeasible Options 

                                                            

24 See ADEQ Operating Air Permit No. 0154-AOP-R4, Section IV, Specific Conditions No. 1 and 7. 25 See AP-42, section 1.3-1. 
30 

AECC’s evaluation noted that the particulate matter from oil-fired boilers tends to be 

sticky and small, affecting the collection efficiency of dry ESPs and fabric filters. Dry ESPs 

operate by placing a charge on the particles through a series of electrodes, and then capturing the 

charged particles on collection plates, while fabric filters work by filtering the PM in the flue gas 

through filter bags. The collected particles are periodically removed from the filter bag through a 

pulse jet or reverse flow mechanism. Because of the sticky nature of particles from oil-fired 

boilers, dry ESPs and fabric filters are deemed technically infeasible for use at Bailey Unit 1. 

Wet ESPs, cyclones, wet scrubbers, and fuel switching were identified as technically 

feasible options for Bailey Unit 1. AECC noted that although cyclones and wet scrubbers are 

considered technically feasible for use at these boiler types, they are not very efficient at 

controlling particles in the smaller size fraction, particularly particles smaller than a few microns. 

However, we do not expect this to be an issue for Bailey Unit 1, since the majority of the PM 

emissions from the unit are greater than a few microns in size. 

 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 AECC estimated that switching to a lower sulfur fuel has a PM control efficiency ranging 

from approximately 44% - 99%, depending on the fuel type. The other technically feasible 

control technologies are estimated to have the following PM control efficiency: wet ESP- up to 

90%, cyclone- 85%, and wet scrubber- 55%. 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

 AECC evaluated the capital costs, operating costs, and average cost-effectiveness of wet 

ESPs, cyclones, and wet scrubbers.26 AECC also evaluated the average cost-effectiveness of 

switching to No. 6 fuel oil with 1% sulfur content, No. 6 fuel oil with 0.5% sulfur content, diesel, 

and natural gas. AECC developed the capital and operating costs of a wet ESP and wet scrubber 

using the Electric Power Research Institute’s (EPRI) Integrated Emissions Control Cost 

Estimating Workbook (IECCOST) Software. The capital costs of controls (except for fuel 

switching) were annualized over a 15-year period and then added to the annual operating costs to 

obtain the total annualized costs. The table below summarizes the average cost-effectiveness of 

PM controls. The average cost-effectiveness was determined by dividing the annualized cost of 

controls by the annual PM emissions reductions. The annual emissions reductions were 

                                                            

26 See “BART Five Factor Analysis, Arkansas Electric Cooperative Corporation Bailey and McClellan Generating 

Stations,” dated March 2014, Version 4, prepared by Trinity Consultants Inc. in conjunction with Arkansas Electric 

Cooperative Corporation. 
31 

determined by subtracting the estimated controlled annual emission rates from the baseline 

annual emission rates, which were derived using emission factors from AP-42, section 1.3-1. 

 We disagree with two aspects of AECC’s cost evaluation for PM controls. First, the total 

annual cost numbers associated with fuel switching should be the same as the cost numbers used 

in the SO2 BART cost analysis for Bailey Unit 1 (see Table 9). In earlier draft versions of 

AECC’s analysis, which were provided to us for review, the cost numbers for fuel switching 

used in the PM and SO2 BART analyses were identical. In response to comments provided by us, 

the total annual cost and average cost-effectiveness numbers for fuel switching were revised in 

the final version of AECC’s SO2 BART analysis. However, it appears that AECC overlooked 

updating these cost numbers in the final PM BART analysis.27 In the table below, we have 

revised the total annual cost of fuel switching for the PM BART analysis to be consistent with 

the cost estimates from AECC’s SO2 BART analysis, and we have also updated the PM average 

cost-effectiveness values. The second aspect of AECC’s cost evaluation for PM controls that we 

disagree with is the use of a 15-year capital cost recovery period for calculating the average costeffectiveness of a wet ESP, wet scrubber, and cyclone. As previously discussed, we are not 

aware of any enforceable shutdown date for the AECC Bailey Generating Station, nor AECC’s 

evaluation indicate any future planned shutdown. Therefore, we believe that assuming a 30-year 

equipment life rather than a 15-year equipment life would be more appropriate for these control 

technologies. Extending the amortization period from 15 to 30 years has the effect of decreasing 

the total annual cost of each control option, thereby improving the cost-effectiveness of controls 

(i.e., less dollars per ton removed). However, after considering all five BART factors, we do not 

believe AECC’s assumption of a 15-year amortization period has an impact on our proposed 

BART decision and therefore we did not revise the amortization period or the average costeffectiveness calculations for the PM control equipment options. This is discussed in more detail 

below. The table below summarizes the estimated cost for fuel switching and the installation and 

operation of PM control equipment for Bailey Unit 1. 

Table 17. Summary of Cost of PM Controls for AECC Bailey Unit 1- Baseline is 

No. 6 Fuel Oil with 1.81% Sulfur Content by Weight 

Control 

Scenario 

Baseline 

Emission 

Rate 

(PM tpy) 

Control 

Efficiency 

(%) 

Annual 

Heat Input 

(MMBtu/yr) 

Controlled 

Emission 

Rate 

(PM tpy) 

Annual 

Emissions 

Reductions 

(PM tpy) 

Capital Cost 

($) 

Total Annual 

Cost 

($/yr) 

Average 

CostEffectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

Wet 

Scrubber 25.63 55.0 39,193 11.53 14.09 140,957,713 50,150,862 3,558,286 - 

                                                            

27 The final version of AECC’s BART analysis for SO2 and PM, upon which our analysis is largely based, is titled 

“BART Five Factor Analysis Arkansas Electric Cooperative Corporation Bailey and McClellan Generating 

Stations, March 2014, Version 4.” A copy of AECC’s analysis can be found in the docket for our proposed 

rulemaking. 
32 

No. 6 Fuel 

oil- 1% S 25.63 65.7 39,193 8.80 16.83 -- 19,596 1,164 -18,296,082 

Cyclone 25.63 85.0 39,193 3.84 21.78 989,479 1,188,630 54,570 236,168 

No. 6 Fuel 

oil- 0.5% S 25.63 89.3 39,193 2.75 22.88 -- 68,587 2,997 -1,020,948 

Wet ESP 25.63 90.0 39,193 2.56 23.06 105,141,431 22,638,340 981,583 125,387,517 

Natural 

Gas 25.63 99.0 39,193 0.26 25.37 -- -384,550 -15,157 -9,966,619 

Diesel 25.63 99.5 39,193 0.13 25.50 -- 194,003 7,608 4,450,408 

 

The table above shows that the average cost-effectiveness of all add-on PM control 

technology options evaluated for AECC Bailey Unit 1 ranged from approximately $55,000/ton 

of PM removed to more than $3.5 million/ton of PM removed. Switching to No. 6 fuel oil with 

either a 1% or 0.5% sulfur content was found to be within the range of what we generally 

consider cost-effective for BART. Switching to No. 6 fuel oil with 1% sulfur content is estimated 

to cost $1,164/ton of PM removed, while switching to No. 6 fuel oil with 0.5% sulfur content is 

estimated to cost $2,997/ton of PM removed. As discussed in the SO2 BART analysis, the 

current cost of natural gas is actually lower than the cost of the baseline fuel. Therefore, the 

average cost-effectiveness of switching from the baseline fuel to natural gas is denoted as a 

negative value in the table above. As discussed above, AECC also explained that it expects 

controls to be less cost-effective (i.e., greater dollars per ton removed) in future years due to 

projected reduced operation of the unit. Less projected operating time is expected to result in 

lower annual emissions, which in turn would result in lower cost-effectiveness of controls. 

 AECC did not identify any energy or non-air quality environmental impacts associated 

with fuel switching, but did identify impacts associated with the use of wet ESPs and wet 

scrubbers due to their electricity usage. Energy use in and of itself does not disqualify a 

technology (40 CFR Part 51, Appendix Y, section IV.D.4.h.1.). In addition, the cost of the 

electricity needed to operate this equipment has already been factored into the cost of controls. 

AECC also noted that both wet ESPs and wet scrubbers generate wastewater streams that must 

either be treated on-site or sent to a waste water treatment plant, and the wastewater treatment 

process will generate a filter cake that would likely require landfilling. The BART Guidelines 

provide that the fact that a control device creates liquid and solid waste that must be disposed of 

does not necessarily argue against selection of that technology as BART, particularly if the 

control device has been applied to similar facilities elsewhere and the solid or liquid waste is 

similar to those other applications. (40 CFR Part 51, Appendix Y, section IV.D.4.i.2.). We are 

not aware of any unusual circumstances at the AECC Bailey Generating Station that could 

potentially create greater problems than experienced elsewhere related to the treatment of 

wastewater and any necessary landfilling, nor did AECC’s evaluation discuss or mention any 
33 

such unusual circumstances. Therefore, the need to treat wastewater or landfill any filter cake or 

other waste in and of itself does not provide a basis for disqualification or elimination of a wet 

ESP or wet scrubber. 

With regard to consideration of any existing pollution control technology in use at the 

source, Bailey Unit 1 has no existing PM pollution control technology. The presence of existing 

pollution control technology at the source is reflected in the BART analysis in two ways: first, in 

the consideration of available control technologies, and second, in the development of baseline 

emission rates for use in cost calculations and visibility modeling. 

 With regard to consideration of the remaining useful life of the unit, we are not aware of 

any enforceable shutdown date for the AECC Bailey Generating Station, nor did AECC’s 

evaluation indicate any future planned shutdown. This means that the anticipated useful life of 

the boiler is expected to be at least as long as the capital cost recovery period of controls. 

Therefore, we believe it is appropriate to assume a 30-year amortization period in the PM BART 

analysis as the remaining useful life of the unit. As discussed in more detail below, AECC 

assumed a 15-year amortization period for control equipment in the BART analysis, but we do 

not believe this has an impact on our proposed BART decision and therefore we did not revise 

the amortization period and the average cost-effectiveness calculations for the PM control 

equipment options. This is discussed in more detail below in the subsection titled “Our Proposed 

PM BART Determination.” 

Step 5- Evaluate Visibility Impacts

 As switching to lower sulfur fuels has impacts on both SO2 and PM emissions, AECC’s 

assessment of the visibility improvement associated with fuel switching is addressed in the SO2

BART analysis for Bailey Unit 1, which is discussed under section II.C.1.b. of this TSD. Table 

11 summarizes the visibility improvement associated with controlled emission rates for SO2 and 

PM as a result of fuel switching. 

 AECC assessed the visibility improvement associated with wet ESPs, wet scrubbers, and 

cyclones by modeling the PM emission rates associated with each control option using 

CALPUFF, and then comparing the visibility impairment associated with the baseline emission 

rates to the visibility impairment associated with the controlled emission rates as measured by 

the 98th percentile modeled visibility impact. The controlled PM10 emission rates associated with 

wet ESPs, wet scrubbers, and cyclones were calculated by reducing the uncontrolled annual 

PM10 emission rates by the pollutant removal efficiency of each control technology. The SO2 and 

NOX emission rates modeled in the controlled scenarios are the same as those from the baseline 

scenario, as it is assumed that SO2 and NOX emissions would remain unchanged. The tables 

below show a comparison of the emission rates modeled and the existing (i.e., baseline) visibility 

impacts and the visibility impacts of wet ESPs, wet scrubbers, and cyclones, including the 

maximum modeled visibility impact and the 98th percentile modeled visibility impact. The 

visibility improvement associated with each control scenario was calculated as the difference 
34 

between the existing visibility impairment and the visibility impairment for each control 

scenario, as measured by the 98th percentile modeled visibility impact. 

Table 18. Summary of Emission Rates Modeled for PM Control Scenarios at AECC Bailey 

Unit 1

Control SO2

(lb/hr) 

SO4

(lb/hr) 

NOX

(lb/hr) 

PMC

(lb/hr) 

PMF

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

PM10, 

total 

(lb/hr) 

Wet ESP 2,375.8 0.4 408.8 1.2 3.0 0.1 0.2 4.9 

Wet 

Scrubber 2,375.8 1.8 408.8 5.5 13.6 0.3 1.1 22.2 

Cyclone 2,375.8 4.0 408.8 1.8 4.5 0.7 0.4 7.4 

Table 19. AECC Bailey Unit 1: Summary of the 98th Percentile Visibility Impacts and 

Improvement from PM Controls 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

Wet Scrubber Cyclone Wet ESP 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from 

Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. Wet 

Scrubber 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv)

Incremental 

Visibility 

Improvement 

vs. Cyclone 

(∆dv) 

Caney Creek 0.330 0.328 0.002 0.328 0.002 0.000 0.327 0.003 0.001 

Upper Buffalo 0.347 0.345 0.002 0.345 0.002 0.000 0.343 0.004 0.002 

HerculesGlades 0.367 0.360 0.007 0.361 0.006 -0.001 0.356 0.011 0.005 

Mingo 0.378 0.374 0.004 0.374 0.004 0.001 0.371 0.007 0.003 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.015 -- 0.014 -- -- 0.025 -- 

 The table above shows that the operation of a wet ESP, wet scrubber, and cyclone at 

Bailey Unit 1 is projected to result in minimal visibility improvement at the four affected Class I 

areas. The modeled visibility improvement from switching to No. 6 fuel oil with 1% sulfur 
35 

content, No. 6 fuel oil with 0.5% sulfur content, diesel, and natural gas is summarized in Table 

11. These visibility improvement estimates reflect both SO2 and PM emissions reductions as a 

result of switching to fuels with lower sulfur content. However, the majority of the baseline 

visibility impact at each Class I area when burning the baseline fuel oil at Bailey Unit 1 is due to 

SO2 emissions, while PM10 emissions contribute only a small portion of the baseline visibility 

impacts at each Class I area. Table 7 shows that the percentage of the visibility impairment at the 

four modeled Class I areas attributable to PM10 ranges from approximately 0.5 – 3% for the fuel 

oil firing scenario. Most of the visibility impairment is attributable to SO4 (67 – 99%) for the fuel 

oil firing scenario. Accordingly, the majority of the visibility improvement associated with 

switching to lower sulfur fuels can reasonably be expected to be the result of reduced SO2

emissions. 

Our Proposed PM BART determination: 

 Taking into consideration the five factors, we propose to determine that PM BART for 

the AECC Bailey Unit 1 does not require add-on controls. Consistent with our proposed 

determination for SO2 BART, we are proposing that PM BART is satisfied by Unit 1 switching 

to fuels with 0.5% or lower sulfur content by weight. As discussed above, we disagree with 

AECC’s use of a 15-year amortization period in the cost analysis for a wet ESP, wet scrubber, 

and cyclone. We are not aware of any enforceable shutdown date for the AECC Bailey 

Generating Station, and we believe the expected equipment life of these control technologies, 

which is at least 30 years, should be assumed to be the amortization period. Assuming a 30-year 

amortization period, these controls would have lower estimated total annual costs and would 

therefore have an improved cost-effectiveness (i.e., less dollars per ton removed) than estimated 

in AECC’s evaluation. However, after considering all five BART factors, AECC’s assumption of 

a 15-year amortization period does not have an impact on our proposed BART decision. Even if 

we revised AECC’s cost estimates to reflect a 30-year amortization period, resulting in a lower 

total annual cost and improved cost-effectiveness, we would still not be able to justify the costs 

of add-on controls in light of the minimal visibility benefit of these controls (see the table 

above). 

 We are proposing to determine that PM BART for Bailey Unit 1 is switching to fuels 

with 0.5% or lower sulfur content by weight. We propose to require that the facility purchase no 

fuel after the effective date of the rule that does not meet the sulfur content requirement and that 

5 years from the effective date of the rule no fuel be burned that does not meet the requirement. 

We expect this proposed compliance date would allow the facility sufficient time to burn its 

existing supply of No. 6 fuel oil (i.e., the baseline fuel), as the normal course of business dictates 

and in accordance with any operating restrictions enforced by ADEQ. We propose that any 

higher sulfur fuel oil that remains from the facility’s 2006 shipment cannot be burned past this 

point. 
36 

2. AECC John L. McClellan Generating Station 

 The AECC McClellan Unit 1 is subject to BART. In our March 12, 2012 final action we 

disapproved the State’s BART determinations for SO2, NOX, and PM for McClellan Unit 1 (77 

FR 14604). AECC, through its consultant, performed a BART five factor analysis (AECC BART 

analysis), and our analysis of the five factors presented below is largely based on the technical 

work performed by AECC.28

 The AECC McClellan Unit 1 is a wall-fired boiler with a gross output of 134 MW and a 

maximum heat input rate of 1436 MMBtu/hr, and is currently permitted to burn natural gas and 

fuel oil. The fuel oil burned at the plant is subject to an operating air permit sulfur content limit 

of 2.8% by weight. 

a. Baseline Emission Rates and Existing Visibility Impairment Attributable to 

McClellan Unit 1 

 AECC estimated SO2, NOX, and PM10 baseline emission rates and then modeled these 

emission rates to determine the existing visibility impairment attributable to the boiler based on 

the default natural conditions. The modeled NOX and PM10 baseline emission rates for the fuel 

oil firing scenario were updated from what was modeled in the 2008 Arkansas RH SIP. The 

updated baseline emission rates are shown in the table below. 

Table 20. Baseline Emission Rates for AECC McClellan Unit 1 

Unit/Fuel 

Scenario 

SO2

(lb/hr) 

NOX

(lb/hr) 

Total 

PM10

(lb/hr) 

SO4

(lb/hr) 

PMc 

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

McClellan, Unit 1- 

Natural Gas 0.6 423.9 10.9 0.3 0.0 0.0 7.9 2.7 

McClellan, Unit 1- 

Fuel Oil 2,747.5 579.8 59.4 5.9 14.2 35.4 1.00 2.8 

 

The updated baseline emission rates are based on CEMS data, stack testing, and AP-42 

emission factors. The SO2 and NOX baseline emission rates are the highest actual 24-hour 

emission rates based on 2001-2003 CEMS data. The revised NOX emission rate for the fuel oil 

                                                            

28 See the following BART analyses: “BART Five Factor Analysis, Arkansas Electric Cooperative Corporation 

Bailey and McClellan Generating Stations,” dated March 2014, Version 4, prepared by Trinity Consultants Inc. in 

conjunction with Arkansas Electric Cooperative Corporation; and “BART Five Factor Analysis- NOX Analysis, 

Addendum to the July 24, 2012 BART Five Factor Analysis, Arkansas Electric Cooperative Corporation Bailey 

and McClellan Generating Stations,” dated December 2013, Version 3. A copy of these two BART analyses can 

be found in the docket for our proposed rulemaking. 
37 

firing scenario is higher than what was modeled in Arkansas’s 2008 RH SIP, thereby resulting in 

higher modeled visibility impacts due to NOX. 

 The PM10 emission rate for natural gas combustion is based on the emission factor for 

total PM10 in Table 1.4-2 of AP-42, which is 7.6 lbs/MMscf, and the unit’s maximum heat input. 

The emission rate for the PM10 species for natural gas combustion reflects the breakdown of the 

filterable and condensable PM10 determined from AP-42 Table 1.4-2 Combustion of Natural 

Gas. All filterable PM was assumed to be elemental carbon and all condensable PM was 

assumed to be secondary organic aerosol (SOA), except for a small fraction of the condensable 

PM that was estimated to be sulfate (SO4). 

 The revised PM10 emission rate for fuel oil combustion is lower than what was modeled 

in Arkansas’s 2008 RH SIP. The revised PM10 emission rate for fuel oil combustion was based 

on stack testing of filterable and condensable PM10 emissions conducted by the facility on 

McClellan Unit 1. The results of the stack testing showed that the total PM10 emission rate for 

McClellan Unit 1 was 59.4 lb/hr. The emission rate for the PM10 species shown in the table 

above reflects the breakdown of the PM10 emissions as determined using the National Park 

Service (NPS) “speciation spreadsheet” for Uncontrolled Utility Residual Oil Boilers.29 As with 

Bailey Unit 1, our concern with AECC’s use of the revised PM10 emission rate based on stack 

testing for the fuel oil firing scenario is that there is no discussion provided on how the stack test 

results are representative of the maximum 24-hour emissions. However, since the visibility 

impacts due to PM10 emissions from McClellan Unit 1 are so small, we believe a closer 

inspection of the revised PM10 emission rate and any further revisions to it would likely not 

result in significant changes to the modeled visibility impacts and would not affect our proposed 

BART decision. For McClellan Unit 1, the percentage of the visibility impairment at the four 

Class I areas attributable to PM10 ranges from approximately 4 – 10% for the natural gas firing 

scenario and 0.4 – 2.5% for the fuel oil firing scenario (see table below). Most of the visibility 

impairment due to McClellan Unit 1 is attributable to NO3 (approximately 83 – 95%) for the 

natural gas firing scenario and to SO4 (60 – 98%) for the fuel oil firing scenario. Therefore, we 

did not take further steps to adjust the PM10 emission rates or conduct additional modeling. 

 AECC modeled the baseline emission rates using the CALPUFF dispersion model to 

determine the baseline visibility impairment attributable to McClellan Unit 1 at the four Class I 

areas impacted by emissions from BART sources in Arkansas: the Caney Creek Wilderness 

Area, the Upper Buffalo Wilderness Area, the Hercules-Glades Wilderness Area, and the Mingo 

National Wildlife Refuge. The baseline (i.e., existing) visibility impairment attributable to 

McClellan Unit 1 at each Class I area is summarized in the tables below. 

                                                            

29 The NPS Workbook, “Uncontrolled Utility Residual Oil Boiler.xls” updated 03/2006, was obtained from the NPS 

website: http://www.nature.nps.gov/air/Permits/ect/index.cfm. The following parameters were input into the 

workbook for speciation determination for McClellan Unit 1: No. 6 fuel oil with a sulfur content of 1.38% and a 

heat input of 1,436 MMBtu/hr. 
38 

Table 21. Baseline Visibility Impairment Attributable to McClellan Unit 1 (2001-2003)-

Natural Gas Firing 

Year Maximum 

(∆dv) 

98th

Percentile 

(∆dv) 

No. of 

Days with 

∆dv ≥ 0.5 

98th

Percentile 

%SO4

98th

Percentile 

%NO3

98th

Percentile 

%PM10

98th

Percentile 

%NO2

Caney Creek Wilderness 

2001 0.670 0.116 1 0.31 93.69 4.43 1.57 

2002 0.175 0.092 0 0.55 82.94 8.35 8.15 

2003 0.538 0.125 2 0.39 87.09 6.63 5.89 

Upper Buffalo Wilderness 

2001 0.096 0.048 0 0.38 92.78 5.43 1.41 

2002 0.258 0.031 0 0.32 94.54 4.04 1.10 

2003 0.112 0.052 0 0.34 91.78 4.82 3.05 

Hercules-Glades Wilderness 

2001 0.064 0.034 0 0.29 93.50 4.42 1.79 

2002 0.082 0.022 0 0.74 88.76 10.09 0.41 

2003 0.092 0.04 0 0.74 86.01 10.18 3.07 

Mingo National Wildlife Refuge 

2001 0.091 0.032 0 0.30 92.13 3.91 3.67 

2002 0.132 0.058 0 0.33 91.96 5.13 2.58 

2003 0.107 0.034 0 0.37 90.42 5.85 3.35 

Table 22. Baseline Visibility Impairment Attributable to McClellan Unit 1 (2001-2003)- 

Fuel Oil Firing 

Year Maximum 

(∆dv) 

98th

Percentile 

(∆dv) 

No. of 

Days with 

∆dv ≥ 0.5 

98th

Percentile 

%SO4

98th

Percentile 

%NO3

98th

Percentile 

%PM10

98th

Percentile 

%NO2

Caney Creek Wilderness 

2001 1.685 0.622 10 89.86 9.62 0.53 0.000 

2002 1.021 0.389 4 86.29 11.26 1.72 0.74 

2003 3.007 0.616 9 82.89 15.76 0.36 0.62 

Upper Buffalo Wilderness 

2001 0.604 0.258 2 84.02 14.98 0.99 0.01 

2002 1.323 0.184 1 77.31 20.96 1.43 0.30 

2003 0.599 0.266 2 98.47 0.95 0.58 0.00 

Hercules-Glades Wilderness 

2001 0.512 0.231 1 78.67 20.16 1.17 0.01 

2002 0.463 0.168 0 59.28 37.65 2.31 0.75 

2003 0.662 0.211 1 76.18 20.22 2.51 1.08 
39 

Mingo National Wildlife Refuge 

2001 0.417 0.228 0 80.90 17.89 1.20 0.01 

2002 0.547 0.213 2 59.42 36.88 2.32 1.38 

2003 0.471 0.203 0 87.39 11.23 1.29 0.09 

 

b. SO2 BART Evaluation 

 AECC McClellan Unit 1 currently combusts natural gas and No. 6 fuel oil. Because the 

SO2 emissions profile and the 98th percentile visibility impact from natural gas combustion 

attributed to the unit is very small, AECC did not consider additional SO2 controls for 

combustion of natural gas and instead focused the SO2 evaluation on controlling SO2 emissions 

from combustion of No. 6 fuel oil. Because of the low SO2 emissions associated with natural gas 

combustion and the relatively low baseline visibility impacts from AECC McClellan Unit 1 

when burning natural gas, we concur with AECC’s decision to focus the evaluation on 

controlling SO2 emissions resulting from the combustion of No. 6 fuel oil. The five factors 

considered in the analysis are discussed below. 

Step 1- Identify All Available Retrofit Control Technologies 

 For SO2 BART, AECC’s evaluation considered FGD and fuel switching. The type of 

FGD technologies considered consisted of DSI, SDA, wet FGD, and dry FGD. 

Step 2- Eliminate Technically Infeasible Options

 AECC found that FGD applications have not been used historically for SO2 control on 

fuel oil-fired units in the U.S. electric industry and therefore considered it a technically infeasible 

option for control of McClellan Unit 1. Therefore, AECC’s evaluation did not further consider 

FGD for SO2 BART. We concur with AECC’s decision to focus the SO2 evaluation on fuel 

switching. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 

 AECC McClellan Unit 1 currently burns some residual fuel oil. The most recent No. 6 

fuel oil shipment for McClellan Unit 1 was in April 2009, and had an average sulfur content of 

1.38% by weight. A portion of the fuel oil from this shipment still remains in storage at the 

facility for future use. The baseline fuel used in the BART analysis is based on the average sulfur 

content of the fuel oil from this shipment. Switching to a fuel with a lower sulfur content is 

expected to reduce SO2 emissions in proportion to the reduction in the sulfur content of the fuel, 

assuming similar heat contents of the fuels. The fuel types with lower sulfur content evaluated by 
40 

AECC are lower sulfur No. 6 fuel oil, No. 2 fuel oil (i.e., diesel), and natural gas. These fuel 

types and the estimated control efficiency of each are shown in the table below. 

Table 23. Control Effectiveness of Technically Feasible SO2 Control Technologies for 

AECC McClellan Unit 1 

Fuel Switching to: Estimated Control Efficiency (%) 

No. 6 fuel oil (1% sulfur) 28% 

No. 6 fuel oil (0.5% sulfur) 64% 

Diesel (0.05% sulfur) 96% 

Natural gas (0.04% sulfur) 99.9% 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

 McClellan Unit 1 currently burns both No. 6 fuel oil and natural gas. AECC estimated the 

cost of fuel switching by determining the annual cost of the No. 6 fuel oil currently used (i.e., the 

baseline fuel) and determining the cost of switching to the various lower sulfur content fuels. The 

supplier of the existing fuels (i.e., No. 6 fuel oil and natural gas) provided AECC with current 

cost estimates for the existing fuels and for the lower sulfur content No. 6 fuel oil and diesel. As 

shown in the table below, the supplier’s estimate for the cost of No. 6 fuel oil with 0.5% and 1% 

sulfur content is $17.75/MMBtu and $16.50 /MMBtu (respectively), and for diesel is 

$20.95/MMBtu. The cost of the base case No. 6 fuel oil with 1.38% sulfur content was estimated 

to be $16.00/MMBtu. 

 AECC estimated the SO2 annual emissions reductions as a result of fuel switching by 

subtracting the estimated controlled annual emission rates from the baseline annual emission 

rates. AECC estimated the baseline and controlled annual emission rates by conducting a mass 

balance on the sulfur in the various fuels.30 The sulfur content of the baseline fuel is 1.38% by 

weight. The SO2 emissions associated with the base case and the fuel switching scenarios (i.e., 

1% sulfur No. 6 fuel oil, 0.5% sulfur No. 6 fuel oil, diesel, and natural gas) were estimated by 

multiplying the baseline annual fuel usage by the fuel density and by the percent sulfur content 

of the fuel. This yielded the quantity of sulfur in the fuel. The SO2 emissions were then estimated 

                                                            

30 See the following BART analyses: “BART Five Factor Analysis, Arkansas Electric Cooperative Corporation 

Bailey and McClellan Generating Stations,” dated March 2014, Version 4, prepared by Trinity Consultants Inc. in 

conjunction with Arkansas Electric Cooperative Corporation. 
41 

by multiplying the quantity of sulfur available to form SO2 by the ratio of the molecular weight 

for SO2 vs. sulfur. See the table below for the estimated SO2 emissions associated with the base 

case and with each fuel switching scenario. 

 To calculate the average cost-effectiveness of fuel switching, AECC divided the annual 

cost increase of switching to a lower sulfur fuel by the annual SO2 tons reduced as a result of fuel 

switching. The table below shows the average cost-effectiveness and incremental costeffectiveness of fuel switching for McClellan Unit 1. 

Table 24. Summary of Costs Associated with Fuel Switching for McClellan Unit 1 

Fuel 

Switching 

Scenario

Average 

Sulfur 

Content 

(%) 

Baseline 

Emission 

Rate 

(SO2

tpy) 

Controlled 

Emission 

Rate 

(SO2 tpy) 

Annual 

Emissions 

Reductions 

(tpy) 

Annual 

Heat Input 

(MMBtu/yr) 

Fuel Heating 

Value 

(MMBtu/Mgal) 

or 

(MMBtu/Mscf) 

Annual 

Fuel 

Usage 

(Mgal/yr) 

Fuel Cost 

($/MMBtu) 

Total 

Annual 

Differential 

Cost of 

Fuel 

Switching 

($/yr) 

Average 

Cost 

Effectiveness 

($/ton) 

Incremental 

Cost 

Effectiveness31

($/ton) 

Base 

Case 1.38 209.43 - - 291,733 155.00 1,882.15 16.00 - - - 

No. 6 - 

1% 1.00 - 153.61 55.81 291,733 155.00 1,882.15 16.50 145,866 2,613 - 

No. 6 - 

0.5% 0.50 - 75.88 133.55 291,733 155.00 1,882.15 17.75 510,532 3,823 4,691 

Diesel 0.05 - 7.31 202.11 291,733 136.15 2,142.73 20.95 1,444,077 7,145 13,616 

Natural 

Gas 0.04 - 0.07 209.35 291,733 1,011.00 288.56 5.97 -2,926,874 -13,980 -603,723 

 AECC did not identify any energy or non-air quality impacts associated with switching to 

1% sulfur No. 6 fuel oil, 0.5% sulfur No. 6 fuel oil, or diesel. The evaluation indicated that 

switching to natural gas may have an impact during periods of natural gas curtailment. During 

natural gas curtailments, natural gas infrastructure maintenance, and other emergencies, AECC 

relies on the fuel oil stored at the plant to maintain electrical reliability. The evaluation indicates 

that because of this, the ability to burn fuel oil at AECC McClellan is important even if fuel oil is 

currently more expensive than natural gas. 

 With regard to consideration of any existing pollution control technology in use at the 

source, McClellan Unit 1 has no existing SO2 pollution control technology. The presence of 

existing pollution control technology is reflected in the BART analysis in two ways: first, in the 

                                                            

31 The incremental cost-effectiveness calculation compares the costs and performance level of a control option to 

those of the next most stringent option, as shown in the following formula (with respect to cost per emissions 

reduction): Incremental Cost Effectiveness (dollars per incremental ton removed) = (Total annualized costs of 

control option) – (Total annualized costs of next control option) / (Control option annual emissions) – Next 

control option annual emissions). See BART Guidelines, 40 CFR Part 51, Appendix Y, section IV.D.4.e. 
42 

consideration of available control technologies, and second, in the development of baseline 

emission rates for use in cost calculations and visibility modeling. 

 With regard to consideration of the remaining useful life of the unit, this factor does not 

impact the SO2 BART analysis in this case since it is assumed that fuel switching will not require 

any capital cost expenditures. 

Step 5- Evaluate Visibility Impacts 

 AECC assessed the visibility improvement associated with fuel switching by comparing 

the visibility impairment from the baseline scenario to the impairment associated with each 

control scenario. The SO2 emission rate in lb/MMBtu associated with the combustion of each 

fuel type was calculated by scaling the existing 30-day rolling average emission rate from 2001-

2003 by the ratio of the sulfur content of the new fuel and the current maximum annual average 

sulfur content from 2009-2011. The controlled 30-day emission rate in lb/MMBtu was converted 

to units of lb/hr by multiplying by the boiler design heat input. The tables below show the 

emission rates modeled and a comparison of the baseline (i.e., existing) visibility impacts and the 

visibility impacts associated with fuel switching, including the maximum modeled visibility 

impact and the 98th percentile modeled visibility impact. The visibility improvement associated 

with fuel switching was calculated as the difference between the existing visibility impairment 

and the visibility impairment for each fuel scenario as measured by the 98th percentile modeled 

visibility impact. 

Table 25. Summary of Emission Rates Modeled for SO2 Control Scenarios at McClellan 

Unit 1

SO2

(lb/hr)

SO4

(lb/hr)

NOX

(lb/hr)

PMC

(lb/hr)

PMF

(lb/hr)

SOA

(lb/hr)

EC

(lb/hr)

PM10, total

(lb/hr)

1% sulfur fuel oil 

No. 6 2,317.1 4.3 579.8 8.0 19.9 0.8 1.6 34.6 

0.5% sulfur fuel oil 

No. 6 1,158.5 2.1 579.8 2.5 6.2 0.4 0.5 11.7 

Diesel 115.9 0.2 579.8 0.1 0.3 0.0 0.0 0.7 

Natural gas 0.6 0.3 423.9 0.0 0.0 7.9 2.7 10.9 
43 

Table 26. AECC McClellan Unit 1: Summary of 98th Percentile Visibility Impacts and 

Improvement due to Fuel Switching 

Class I 

area 

Baseline 

Visibility 

Impact 

(∆dv)

No. 6 Fuel Oil1% Sulfur No. 6 Fuel Oil- 0.5% Sulfur Diesel Natural Gas 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 1% Sulfur 

Fuel oil 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 0.5 % 

Sulfur Fuel 

oil 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. Diesel 

Caney Creek 0.622 0.537 0.085 0.322 0.3 0.215 0.174 0.448 0.148 0.125 0.497 0.049 

Upper 

Buffalo 0.266 0.231 0.035 0.146 0.12 0.085 0.073 0.193 0.073 0.052 0.214 0.021 

HerculesGlades 0.231 0.202 0.029 0.115 0.116 0.087 0.062 0.169 0.053 0.040 0.191 0.022 

Mingo 0.228 0.193 0.035 0.136 0.092 0.057 0.080 0.148 0.056 0.058 0.17 0.022 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.184 -- 0.628 - -- 0.958 - -- 1.072 - 

 The table above shows that switching to No. 6 fuel oil with 1% sulfur content at 

McClellan Unit 1 is projected to result in 0.085 dv visibility improvement at Caney Creek (based 

on the 98th percentile modeled visibility impacts). The visibility improvement at each of the other 

three affected Class I is projected to range from 0.029 – 0.035 dv, while the cumulative visibility 

improvement at the four Class I areas is projected to be 0.184 dv. Switching to No. 6 fuel oil 

with 0.5% sulfur content is projected to result in considerable visibility improvement. It is 

projected to result in 0.3 dv visibility improvement at Caney Creek. The visibility improvement 

at each of the other three affected Class I areas is projected to range from 0.092 – 0.12 dv, while 

the cumulative visibility improvement at the four Class I areas is projected to be 0.628 dv. 

Switching to diesel or natural gas is also projected to result in considerable visibility 

improvement. The visibility improvement at Caney Creek is projected to be 0.448 dv for 

switching to diesel and 0.497 dv for switching to natural gas. At each of the three remaining 

Class I areas, the visibility improvement is projected to range from 0.148 – 0.193 dv for 

switching to diesel and 0.17 – 0.214 dv for switching to natural gas. The cumulative visibility 

improvement at the four Class I areas is projected to be 0.958 dv for switching to diesel and 

1.072 dv for switching to natural gas. 

 
44 

Our Proposed SO2 BART determination: 

 Taking into consideration the five factors, we are proposing to determine that BART for 

the AECC McClellan Unit 1 is switching to fuels with 0.5% or lower sulfur content by weight. 

The cost of switching to No. 6 fuel oil with 0.5% sulfur content is within the range of what we 

consider to be cost-effective for BART and it is projected to result in considerable visibility 

improvement compared to the baseline at the affected Class I areas. Switching to No. 6 fuel oil 

with 0.5% sulfur content has an estimated average cost-effectiveness of $3,823/ton of SO2

removed and is projected to result in visibility improvement ranging from 0.092 to 0.3 dv at each 

modeled Class I area, and a cumulative visibility improvement of 0.628 dv at the four modeled 

Class I areas. Switching to natural gas would currently cost less than the baseline fuel oil and is 

projected to result in even greater visibility improvement than switching to No. 6 fuel oil with 

0.5% sulfur content. However, the BART Guidelines provide that it is not our intent to direct 

subject-to-BART sources to switch fuel forms, such as from coal or fuel oil to gas (40 CFR Part 

51, Appendix Y, section IV.D.1). Since natural gas has a sulfur content by weight that is well 

below 0.5%, the facility may elect to use this type of fuel to comply with BART, but we are not 

proposing to require a switch to natural gas for Unit 1. Switching to diesel is projected to result 

in considerable visibility improvement. The visibility improvement of switching to diesel is 

projected to range from 0.148 to 0.448 dv at each modeled Class I area, and the cumulative 

visibility improvement is 0.958 dv at the four affected Class I areas. The incremental visibility 

improvement of switching to diesel compared to switching to No. 6 fuel oil with a sulfur content 

of 0.5% is projected to range from 0.053 dv to 0.148 dv at each affected Class I area. However, 

the average cost-effectiveness of switching to diesel is estimated to be $7,145/ ton of SO2

removed and the incremental cost-effectiveness compared to No. 6 fuel oil with a sulfur content 

of 0.5% is $13,616/ ton of SO2 removed, which we do not consider to be cost-effective in view 

of the incremental visibility improvement. Since diesel also has a sulfur content by weight that is 

well below 0.5, the facility may elect to use this type of fuel to comply with BART, but we are 

not proposing to require a switch to diesel for Unit 1. We are proposing to determine that SO2

BART for McClellan Unit 1 is switching to fuels with 0.5% or lower sulfur content by weight. 

We propose to require that the facility purchase no fuel after the effective date of the rule that 

does not meet the sulfur content requirement and that 5 years from the effective date of the rule 

no fuel be burned that does not meet the requirement We expect this proposed compliance date 

would allow the facility sufficient time to burn its existing supply of No. 6 fuel oil (i.e., the 

baseline fuel), as the normal course of business dictates and in accordance with any operating 

restrictions enforced by ADEQ. We propose that any higher sulfur fuel oil that remains from its 

2009 shipment cannot be burned past this point. 
45 

c. NOX BART Evaluation 

 Nitrogen oxides, or NOX, are produced during fuel combustion when nitrogen contained 

in both the fuel and the combustion air is exposed to high temperatures. Nitrogen oxide (NO) is 

typically the predominant form of NOX from fossil fuel combustion, with nitrogen dioxide (NO2) 

making up the remainder of the NOX. AECC noted that the formation of NOX compounds in 

utility boilers is sensitive to the method of firing and combustion flame temperatures. In wallfired boilers, such as McClellan Unit 1, burners are mounted in the boiler walls, producing 

discrete flames in the furnace. In tangentially-fired boilers, a single rotating flame is created in 

the center of the furnace, rather than the discrete flames produced by burners in the wall-fired 

boilers. Tangentially fired boilers typically have lower uncontrolled NOX emissions than wallfired boilers. Therefore, baseline NOX emission rates can vary significantly from plant to plant 

due to method of firing and combustion flame temperatures, among other factors. The baseline 

NOX emission rate for McClellan Unit 1 is discussed under section II.C.2.a. of this TSD. The 

five factors considered in the NOX BART analysis are discussed below. 

Step 1- Identify All Available Retrofit Control Technologies 

 For NOX BART, AECC evaluated both combustion and post-combustion controls. 

Combustion controls involve reducing the peak flame temperature and excess air in the furnace 

to minimize NOX formation, while post-combustion controls involve converting NOX in the flue 

gas to molecular nitrogen and water. The combustion controls evaluated by AECC consisted of 

FGR, OFA, and LNB. The post-combustion controls evaluated consisted of SCR and SNCR. 

Step 2- Eliminate Technically Infeasible Options

 AECC found that some boilers may be restricted from installing OFA retrofits due to 

physical size and space restraints. For purposes of the NOX BART evaluation, AECC assumed 

OFA to be a technically feasible option for McClellan Unit 1, but noted that if the five factor 

BART analysis deemed OFA to be BART, then further analyses would have to be performed to 

determine if (1) the dimensions of the main boiler has sufficient upper furnace volume for OFA 

mixing and complete combustion; and (2) if there are physical space requirements for OFA ports 

and air supply ducts. AECC found the remaining NOX control options to be technically feasible. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 The estimated NOX controlled emission rate of each control option considered by AECC 

is shown in the table below. In its evaluation, AECC considered the following control options: a 

combination of combustion controls (i.e., FGR, OFA, and LNB); a combination of combustion 

controls and SNCR; and SCR. AECC estimated that when FGR is operated alone, the NOX
46 

control range for oil and gas wall-fired boilers is approximately 0.2 – 0.4 lb/MMBtu, and when 

OFA is operated alone it results in an estimated NOX controlled emission rate of 0.2 – 0.3 

lb/MMBtu.32 It also estimated that when LNB is combined with OFA and FGR, a NOX

controlled emission rate of 0.15 – 0.20 lb/MMBtu is achievable. 

 AECC found that the estimated NOX control efficiency of SCR is 80-90% on gas fired 

boilers and 70-80% for oil fired boilers, and estimated that when SCNR is combined with 

combustion controls, the NOX level of control is estimated to be 10% greater than with 

combustion controls alone.33 

Table 27. Control Effectiveness of Technically Feasible NOX Control Technologies for 

AECC McClellan Unit 1 

Control Technology 

Baseline NOX Emission Rate 

 (lb/MMBtu) 

Estimated NOX Controlled Emission 

Rate (lb/MMBtu) 

Natural Gas Fuel Oil Natural Gas Fuel Oil 

SCR 

0.31 0.5 

0.05 0.12 

Combustion Controls +SNCR 0.12 0.10 

Combustion Controls 0.15 0.15 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, the existing pollution control technology in use at 

the source, and the remaining useful life of the source. 

 AECC’s cost analysis34 for NOX controls was based on “budgetary” cost estimates it 

obtained from the pollution control equipment vendor, Babcock Power Systems. AECC 

estimated the capital and operating costs of controls based on the vendor’s estimates, engineering 

estimates, and published calculation methods using the EPA Control Cost Manual. We are not 

aware of any enforceable shutdown date for the AECC McClellan Generating Station, nor did 

AECC indicate any future planned shutdown. This means that the anticipated useful life of the 

boiler is expected to be at least as long as the capital cost recovery period of controls. Therefore, 

                                                            

32 “Controlling Nitrogen Oxides Under the Clean Air Act: A Menu of Options,” section II, dated July 1994, State 

and Territorial Air Pollution Program Administrators (STAPPA) and Association of Local Air Pollution Control 

Officials (ALAPCO). 

33 “Preferred and Alternative Methods for Estimating Air Emissions from Boilers” Table 2.2-2. January 2001. See 

http://www.epa.gov/ttn/chief/eiip/techreport/volume02/ii02.pdf. 

34 See “BART Five Factor Analysis- NOX Analysis, Addendum to the July 24, 2012 BART Five Factor Analysis, 

Arkansas Electric Cooperative Corporation Bailey and McClellan Generating Stations,” dated December 2013, 

Version 3. 
47 

a 30-year amortization period was assumed in the NOX BART analysis as the remaining useful 

life of the unit. The table below summarizes the estimated cost for installation and operation of 

NOX controls for AECC McClellan Unit 1. 

 AECC determined the annual emissions reductions associated with each NOX control 

option by subtracting the estimated controlled annual emission rate from the baseline annual 

emission rate. The baseline annual emission rates are the average rates from 2009-2011, while 

the controlled annual emission rates are based on the lb/MMBtu levels believed to be achievable 

from the control technology multiplied by the baseline heat inputs to the boilers in MMBtu/yr. 

The baseline heat inputs for each unit are the sum of the baseline heat inputs for natural gas and 

fuel oil. The baseline heat inputs for natural gas are based on the average natural gas usage for 

each unit from 2007-2011 multiplied by the average heat content of natural gas for the same time 

period. Similarly, the baseline heat inputs for fuel oil are based on the average fuel oil usage for 

each unit from 2007-2011 multiplied by the average heat content of fuel oil for the same time 

period. 

 To calculate the average cost-effectiveness of NOX controls, AECC divided the total 

annual cost of each control option by the estimated annual NOX tons reduced. The table below 

shows the average cost effectiveness and incremental cost-effectiveness of NOX controls for 

AECC McClellan Unit 1. 

Table 28. Summary of Costs of NOX Controls for AECC McClellan Unit 1 

Control 

Scenario 

Baseline 

Emission 

Rate 

(NOX

tpy) 

Natural 

Gas 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Fuel Oil 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Natural Gas 

Annual 

Heat Input 

(MMBtu/yr) 

Fuel Oil 

Annual 

Heat Input 

(MMBtu/yr) 

Controlled 

Emission 

Rate 

(NOX tpy) 

Annual 

Emissions 

Reductions 

(NOX tpy) 

Capital 

Cost 

($) 

Total 

Annual 

Cost 

($/yr) 

Average 

CostEffectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

Combustion 

Controls 294.04 0.15 0.15 2,040,117 291,733 174.89 119.15 7,400,000 746,051 6,261 -- 

Combustion 

Controls + 

SNCR 

294.04 0.12 0.10 2,040,117 291,733 136.40 157.64 11,733,253 1,990,988 12,630 32,344 

SCR 294.04 0.05 0.12 2,040,117 291,733 64.98 229.06 12,675,562 1,732,870 7,565 -3,614 

 AECC estimated the average cost-effectiveness of installing and operating combustion 

controls to be $6,261/ton of NOX removed for McClellan Unit 1. The combination of combustion 

controls and SNCR was estimated to cost $12,630/ton of NOX removed, while SCR was 

estimated to cost $7,565/ton of NOX removed. In its evaluation, AECC also explained that it 

expects NOX controls to be less cost-effective (i.e., greater dollars per ton removed) in future 

years due to projected reduced operation of the unit. Less projected operating time is expected to 

result in lower annual emissions, which would result in lower cost-effectiveness of controls. 
48 

 AECC did not identify any energy or non-air quality environmental impacts associated 

with the use of LNB, OFA, or FGR. As for SCR and SNCR, we are not aware of any unusual 

circumstances at the facility that could create energy or non-air quality environmental impacts 

associated with the operation of these controls greater than experienced elsewhere and that may 

therefore provide a basis for their elimination as BART (40 CFR Part 51, Appendix Y, section 

IV.D.4.i.2.). Therefore, we do not believe there are any energy or non-air quality environmental 

impacts associated with NOX controls at AECC McClellan Unit 1 that would affect our proposed 

BART determination. 

With regard to consideration of any existing pollution control technology in use at the 

source, McClellan Unit 1 has no existing NOX pollution control technology. The presence of 

existing pollution control technology at the source is reflected in the BART analysis in two 

ways: first, in the consideration of available control technologies, and second, in the 

development of baseline emission rates for use in cost calculations and visibility modeling. 

 With regard to consideration of the remaining useful life of the unit, we are not aware of 

any enforceable shutdown date for the AECC McClellan Generating Station, nor did AECC’s 

evaluation indicate any future planned shutdown. This means that the anticipated useful life of 

the boiler is expected to be at least as long as the capital cost recovery period of controls. 

Therefore, a 30-year amortization period was assumed in the NOX BART analysis as the 

remaining useful life of Unit 1. 

Step 5- Evaluate Visibility Impacts 

 AECC assessed the visibility improvement associated with NOX controls by modeling the 

NOX emission rates associated with each control option using CALPUFF, and then comparing 

the visibility impairment associated with the baseline emission rates to the visibility impairment 

associated with the controlled emission rates. The controlled emission levels associated with 

combustion controls, combustion controls + SNCR, and SCR systems are shown in the table 

above. These levels were multiplied by each unit’s maximum heat input to derive the hourly 

emission rates used in the modeling. The tables below show a comparison of the emission rates 

modeled and the existing (i.e., baseline) visibility impacts and the visibility impacts based on 

NOX controls, including the maximum modeled visibility impact and the 98th percentile modeled 

visibility impact. The visibility improvement associated with NOX controls was calculated as the 

difference between the baseline visibility impairment and the visibility impairment for each 

control scenario as measured by the 98th percentile modeled visibility impact. 
49 

Table 29. Summary of Emission Rates Modeled for NOX Control Scenarios at AECC 

McClellan Unit 1

Control 

Scenario 

 Fuel 

Scenario 

SO2

(lb/hr) 

NOx 

(lb/hr) 

Total 

PM10

(lb/hr) 

SO4

(lb/hr) 

PMc 

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

Combustion 

Controls 

Natural 

Gas 0.6 215.5 10.9 0.3 0.0 0.0 7.9 2.7 

Fuel Oil 2,747.5 215.5 48.2 4.8 11.5 28.7 0.8 2.3 

SCR 

Natural 

Gas 0.6 66.0 10.9 0.3 0.0 0.0 7.9 2.7 

Fuel Oil 2,747.5 178.7 48.2 4.8 11.5 28.7 0.8 2.3 

Combustion 

Controls + 

SNCR 

Natural 

Gas 0.6 171.5 10.9 0.3 0.0 0.0 7.9 2.7 

Fuel Oil 2,747.5 144.0 48.2 4.8 11.5 28.7 0.8 2.3 

Table 30. Summary of the 98th Percentile Visibility Impacts and Improvement due to NOX

Controls for AECC McClellan Unit 1- Natural Gas Firing (2001-2003) 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

Combustion Controls Combustion 

 Controls + SNCR SCR 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

Combustion 

Controls 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

Combustion 

Controls + 

SNCR 

(∆dv) 

Caney Creek 0.125 0.068 0.057 0.056 0.069 0.012 0.027 0.098 0.029 

Upper 

Buffalo 0.052 0.028 0.024 0.023 0.029 0.005 0.012 0.04 0.011 

HerculesGlades 0.040 0.021 0.019 0.018 0.022 0.003 0.009 0.031 0.009 

Mingo 0.058 0.031 0.027 0.026 0.032 0.005 0.012 0.046 0.014 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.127 -- 0.152 -- -- 0.215 -- 

 
50 

Table 31. Summary of the 98th Percentile Visibility Impacts and Improvement due to NOX

Controls for AECC McClellan Unit 1- Fuel Oil Firing (2001-2003) 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

Combustion Controls Combustion 

 Controls + SNCR SCR 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

Combustion 

Controls 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

Combustion 

Controls + 

SNCR 

(∆dv) 

Caney Creek 0.621 0.554 0.067 0.542 0.079 0.012 0.548 0.073 -0.006 

Upper 

Buffalo 0.266 0.264 0.002 0.264 0.002 0.000 0.264 0.002 0.000 

HerculesGlades 0.230 0.209 0.021 0.203 0.027 0.006 0.207 0.023 -0.004 

Mingo 0.227 0.203 0.024 0.200 0.027 0.003 0.201 0.026 -0.001 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.114 -- 0.135 -- -- 0.124 -- 

As shown in the tables above, the installation and operation of NOX controls is projected 

to result in very modest visibility improvement from the baseline. Combustion controls at 

McClellan Unit 1 are projected to result in visibility improvement ranging from 0.019 – 0.057 dv 

at each Class I area for natural gas firing and 0.002 – 0.067 dv for fuel oil firing (based on the 

98th percentile modeled visibility impacts). A combination of combustion controls + SNCR at 

McClellan Unit 1 is projected to result in only slightly greater visibility improvement than 

combustion controls alone. For example, the combination of combustion controls + SNCR is 

projected to result in visibility improvement ranging from 0.022 – 0.069 dv at each Class I area 

for natural gas firing and 0.002 – 0.079 dv for fuel oil firing. The installation and operation of 

SCR at McClellan Unit 1 is projected to result in only slightly greater visibility improvement 

compared to a combination of combustion controls + SNCR. SCR is projected to result in 

visibility improvement ranging from 0.031 – 0.098 dv at each Class I area for natural gas firing 

and 0.002 – 0.073 dv for fuel oil firing. 

Our NOX BART determination: 

 Taking into consideration the five factors, we are proposing to determine that NOX

BART for the AECC McClellan Unit 1 is no additional controls, and are proposing that the 
51 

existing NOX emission limits satisfy BART for NOX. We are proposing the existing emission 

limit of 869.1 lb/hr for natural gas firing and 705.8 lb/hr for fuel oil firing for NOX BART for 

McClellan Unit 1.35 As discussed above, the operation of combustion controls at McClellan Unit 

1 is projected to result in a maximum visibility improvement of 0.067 dv (Caney Creek), and a 

smaller amount of visibility improvement at each of the other affected Class I areas. The 

installation and operation of combustion controls at McClellan Unit 1 has an average costeffectiveness of $6,261/ton of NOX removed, which is not within the range of what we generally 

consider to be cost-effective. We believe the relatively small visibility benefit projected from the 

operation of combustion controls both when combusting fuel oil and natural gas does not justify 

the high estimated cost of those controls. The operation of a combination of combustion controls 

+ SNCR is estimated to cost $12,630/ton of NOX removed, which is also not cost-effective. A 

combination of combustion controls + SNCR is projected to result in only slight incremental 

visibility benefit compared to combustion controls alone. The operation of SCR is estimated to 

cost $7,565/ton of NOX removed, which is not cost-effective, and is projected to result in only 

slight incremental visibility benefit compared to a combination of combustion controls + SNCR 

for the natural gas firing scenario. For the fuel oil firing scenario, SCR is projected to result in 

slightly lower visibility benefit compared to a combination of combustion controls + SNCR at 

three of the modeled Class I areas. We are proposing to find that NOX BART for McClellan Unit 

1 is no additional controls and are proposing the aforementioned existing NOX emission limits 

for NOX BART. We are proposing that these already-existing emissions limitations be complied 

with for BART purposes from the effective date of the final action. 

d. PM BART Evaluation 

 The five factors considered in the PM BART analysis for McClellan Unit 1 are discussed 

below. 

Step 1- Identify All Available Retrofit Control Technologies 

 For PM BART, AECC considered the following control technologies: dry ESP, wet ESP, 

fabric filter, wet scrubber, cyclone (i.e., mechanical collector), and fuel switching. 

 Residual fuel, such as the No. 6 fuel oil burned at McClellan Unit 1, has inherent ash that 

contributes to emissions of filterable PM. Filterable PM emissions could be reduced by switching 

to a lower grade fuel oil or natural gas. For combustion of No. 6 fuel oil, reductions in filterable 

PM are directly related to the sulfur content of the fuel.36 Therefore, switching to No. 6 fuel oil 

with a lower sulfur content is expected to result in lower filterable PM emissions. AECC’s 

evaluation considered switching to No. 6 fuel oil with 1% sulfur content by weight, No. 6 fuel oil 

                                                            

35 See ADEQ Operating Air Permit No. 0181-AOP-R5, Section IV, Specific Condition No. 1, 3, and 13. 36 See AP-42, section 1.3-1. 
52 

with 0.5% sulfur content by weight, diesel, and natural gas. These are the same lower sulfur fuel 

types evaluated in the SO2 BART analysis for the unit. 

Step 2- Eliminate Technically Infeasible Options 

 AECC’s evaluation noted that the particulate matter from oil-fired boilers tends to be 

sticky and small, affecting the collection efficiency of dry ESPs and fabric filters. Dry ESPs 

operate by placing a charge on the particles through a series of electrodes, and then capturing the 

charged particles on collection plates, while fabric filters work by filtering the PM in the flue gas 

through filter bags. The collected particles are periodically removed from the filter bag through a 

pulse jet or reverse flow mechanism. Because of the sticky nature of particles from oil-fired 

boilers, dry ESPs and fabric filters are deemed technically infeasible for use at McClellan Unit 1. 

Wet ESPs, cyclones, wet scrubbers, and fuel switching were identified as technically feasible 

options for McClellan Unit 1. AECC noted that although cyclones and wet scrubbers are 

considered technically feasible for use at these boiler types, they are not very efficient at 

controlling particles in the smaller size fraction, particularly particles smaller than a few microns. 

However, we do not expect this to be an issue for McClellan Unit 1, since the majority of the PM 

emissions from the unit are greater than a few microns in size. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 AECC estimated that switching to a lower sulfur fuel has a PM control efficiency ranging 

from approximately 44% - 99%, depending on the fuel type. The other technically feasible 

control technologies are estimated to have the following PM control efficiency: wet ESP- up to 

90%, cyclone- 85%, and wet scrubber- 55%. 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

 AECC evaluated the capital costs, operating costs, and average cost-effectiveness of wet 

ESPs, cyclones, and wet scrubbers.37 AECC also evaluated the average cost-effectiveness of 

switching to No. 6 fuel oil with 1% sulfur content, No. 6 fuel oil with 0.5% sulfur content, diesel, 

and natural gas. AECC developed the capital and operating costs of a wet ESP and wet scrubber 

using the Electric Power Research Institute’s (EPRI) Integrated Emissions Control Cost 

                                                            

37 See “BART Five Factor Analysis, Arkansas Electric Cooperative Corporation Bailey and McClellan Generating 

Stations,” dated March 2014, Version 4, prepared by Trinity Consultants Inc. in conjunction with Arkansas Electric 

Cooperative Corporation. 
53 

Estimating Workbook (IECCOST) Software. The capital costs of controls (except for fuel 

switching) were annualized over a 15-year period and then added to the annual operating costs to 

obtain the total annualized costs. The table below summarizes the average cost-effectiveness of 

PM controls. AECC determined the average cost-effectiveness by dividing the annualized cost of 

controls by the annual PM emissions reductions. The annual emissions reductions were 

determined by subtracting the estimated controlled annual emission rates from the baseline 

annual emission rates, which were derived using emission factors from AP-42, section 1.3-1. 

 We disagree with two aspects of AECC’s cost evaluation for PM controls. First, the total 

annual cost numbers associated with fuel switching should be the same as the cost numbers used 

in the SO2 BART cost analysis for McClellan Unit 1 (see Table 24). In earlier draft versions of 

AECC’s analysis, which were provided to us for review, the cost numbers for fuel switching 

used in the PM and SO2 BART analyses were identical. In response to comments we provided, 

the total annual cost and average cost-effectiveness numbers for fuel switching were revised in 

the final version of AECC’s SO2 BART analysis. However, it appears that AECC overlooked 

updating these cost numbers in the final PM BART analysis.38 In the table below, we have 

revised the total annual cost of fuel switching for the PM BART analysis to be consistent with 

the cost estimates from AECC’s SO2 BART analysis, and we have also updated the PM average 

cost-effectiveness values. The second aspect of AECC’s cost evaluation for PM controls that we 

disagree with is the use of a 15-year capital cost recovery period for calculating the average costeffectiveness of a wet ESP, wet scrubber, and cyclone. As previously discussed, we are not 

aware of any enforceable shutdown date for the AECC McClellan Generating Station, nor did 

the AECC’s evaluation indicate any future planned shutdown. Therefore, we believe that 

assuming a 30-year equipment life rather than a 15-year equipment life would be more 

appropriate for these control technologies. Extending the amortization period from 15 to 30 years 

has the effect of decreasing the total annual cost of each control option, thereby improving the 

cost-effectiveness of controls (i.e., less dollars per ton removed). However, after considering all 

five BART factors, we do not believe AECC’s assumption of a 15-year amortization period has 

an impact on our proposed BART decision and therefore we did not revise the amortization 

period or the average cost-effectiveness calculations for the PM control equipment options. This 

is discussed in more detail below. The table below summarizes the estimated cost for fuel 

switching and the installation and operation of PM control equipment for McClellan Unit 1. 

                                                            

38 The final version of AECC’s BART analysis for SO2 and PM, upon which our analysis is largely based, is titled 

“BART Five Factor Analysis Arkansas Electric Cooperative Corporation Bailey and McClellan Generating 

Stations, March 2014, Version 4.” A copy of AECC’s analysis can be found in the docket for our proposed 

rulemaking. 
54 

Table 32. Summary of Cost of PM Controls for AECC McClellan Unit 1- Baseline is 

No. 6 Fuel Oil with 1.38% Sulfur Content by Weight 

Control 

Scenario 

Baseline 

Emission 

Rate 

(PM tpy) 

Control 

Efficiency 

(%) 

Annual Heat 

Input 

(MMBtu/yr) 

Controlled 

Emission 

Rate 

(PM tpy) 

Annual 

Emissions 

Reduction 

(PM tpy) 

Capital Cost 

($) 

Total Annual 

Cost 

($/yr) 

Average PM 

Cost 

Effectiveness 

($/ton) 

Incremental 

Cost 

Effectiveness 

(S/ton) 

No. 6 Fuel 

oil- 1% S 136.08 43.6 291,733 76.70 59.38 -- 145,866 2,456 -- 

Wet 

Scrubber 136.08 55.0 291,733 61.23 74.84 146,303,011 52,056,542 695,549 3,357,741 

No. 6 Fuel 

oil- 0.5% S 136.08 82.4 291,733 23.94 112.14 -- 510,532 4,553 -1,381,931 

Cyclone 136.08 85.0 291,733 20.41 115.67 1,432,971 1,721,384 14,882 343,018 

Wet ESP 136.08 90.0 291,733 13.61 122.47 151,509,333 32,605,907 266,237 4,541,842 

Natural Gas 136.08 99.0 291,733 1.36 134.72 -- -2,926,874 -21,725 -2,900,635 

Diesel 136.08 99.2 291,733 1.10 134.98 -- 1,444,077 10,698 16,811,350 

The table above shows that the average cost-effectiveness values of all add-on PM 

control technology options evaluated for AECC McClellan Unit 1 ranged from approximately 

$15,000/ton of PM removed to more than $266,000/ton of PM removed. Switching to No. 6 fuel 

oil with either a 1% or 0.5% sulfur content was found to be within the range of what we 

generally consider cost-effective for BART. Switching to No. 6 fuel oil with 1% sulfur content is 

estimated to cost $2,456/ton of PM removed, while switching to No. 6 fuel oil with 0.5% sulfur 

content is estimated to cost $4,553/ton of PM removed. As discussed in the SO2 BART analysis, 

the current cost of natural gas is actually lower than the cost of the baseline fuel. Therefore, the 

average cost-effectiveness of switching from the baseline fuel to natural gas is denoted as a 

negative value in the table above. As discussed above, AECC also explained that it expects 

controls to be less cost-effective (i.e., greater dollars per ton removed) in future years due to 

projected reduced operation of the unit. Less projected operating time is expected to result in 

lower annual emissions, which in turn would result in lower cost-effectiveness of controls. 

 AECC did not identify any energy or non-air quality environmental impacts associated 

with fuel switching, but did identify impacts associated with the use of wet ESPs and wet 

scrubbers due to their electricity usage. Energy use in and of itself does not disqualify a 

technology (40 CFR Part 51, Appendix Y, section IV.D.4.h.1.). In addition, the cost of the 

electricity needed to operate this equipment has already been factored into the cost of controls. 

AECC also noted that both wet ESPs and wet scrubbers generate wastewater streams that must 
55 

either be treated on-site or sent to a waste water treatment plant, and the wastewater treatment 

process will generate a filter cake that would likely require landfilling. The BART Guidelines 

provide that the fact that a control device creates liquid and solid waste that must be disposed of 

does not necessarily argue against selection of that technology as BART, particularly if the 

control device has been applied to similar facilities elsewhere and the solid or liquid waste is 

similar to those other applications (40 CFR Part 51, Appendix Y, section IV.D.4.i.2.). We are not 

aware of any unusual circumstances at the AECC McClellan Generating Station that could 

potentially create greater problems than experienced elsewhere related to the treatment of 

wastewater and any necessary landfilling, nor did the AECC BART evaluation discuss or 

mention any such unusual circumstances. Therefore, the need to treat wastewater or landfill any 

filter cake or other waste in and of itself does not provide a basis for disqualification or 

elimination of a wet ESP or wet scrubber. 

With regard to consideration of any existing pollution control technology in use at the 

source, McClellan Unit 1 has no existing PM pollution control technology. The presence of 

existing pollution control technology at the source is reflected in the BART analysis in two 

ways: first, in the consideration of available control technologies, and second, in the 

development of baseline emission rates for use in cost calculations and visibility modeling. 

 With regard to consideration of the remaining useful life of the unit, we are not aware of 

any enforceable shutdown date for the AECC McClellan Generating Station, nor did AECC’s 

evaluation indicate any future planned shutdown. This means that the anticipated useful life of 

the boiler is expected to be at least as long as the capital cost recovery period of controls. 

Therefore, we believe it is appropriate to assume a 30-year amortization period in the PM BART 

analysis as the remaining useful life of the unit. As discussed in more detail below, AECC 

assumed a 15-year amortization period for control equipment in the BART analysis, but we do 

not believe this has an impact on our proposed BART decision and therefore we did not revise 

the amortization period and the average cost-effectiveness calculations for the PM control 

equipment options. This is discussed in more detail below in the subsection titled “Our Proposed 

PM BART Determination.” 

Step 5- Evaluate Visibility Impacts

 As switching to lower sulfur fuels has impacts on both SO2 and PM emissions, AECC’s 

assessment of the visibility improvement associated with fuel switching is addressed in the SO2

BART analysis for McClellan Unit 1, which is discussed under section II.C.1.b. of this TSD. 

Table 18 summarizes the visibility improvement associated with controlled emission rates for 

SO2 and PM as a result of fuel switching. 

 AECC assessed the visibility improvement associated with wet ESPs, wet scrubbers, and 

cyclones by modeling the PM emission rates associated with each control option using 

CALPUFF, and then comparing the visibility impairment associated with the baseline emission 

rates to the visibility impairment associated with the controlled emission rates as measured by 
56 

the 98th percentile modeled visibility impact. The controlled PM10 emission rates associated with 

wet ESPs, wet scrubbers, and cyclones were calculated by reducing the uncontrolled annual 

PM10 emission rates by the pollutant removal efficiency of each control technology. The SO2 and 

NOX emission rates modeled in the controlled scenarios are the same as those from the baseline 

scenario, as it is assumed that SO2 and NOX emissions would remain unchanged. The tables 

below show the emission rates modeled and a comparison of the existing (i.e., baseline) visibility 

impacts and the visibility impacts of wet ESPs, wet scrubbers, and cyclones, including the 

maximum modeled visibility impact and the 98th percentile modeled visibility impact. The 

visibility improvement associated with each control scenario was calculated as the difference 

between the existing visibility impairment and the visibility impairment for each control 

scenario, as measured by the 98th percentile modeled visibility impact. 

Table 33. Summary of Emission Rates Modeled for PM Control Scenarios at McClellan 

Unit 1 

Control SO2

(lb/hr) 

SO4

(lb/hr) 

NOX

(lb/hr) 

PMC

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

PM10, 

total 

(lb/hr) 

Wet ESP 2,747.5 0.5 579.8 1.2 2.9 0.1 0.2 4.8 

Wet 

Scrubber 2,747.5 2.2 579.8 5.2 12.9 0.4 1.0 21.7 

Cyclone 2,747.5 4.8 579.8 1.7 4.3 0.8 0.3 7.2 

Table 34. AECC McClellan Unit 1: Summary of the 98th Percentile Visibility Impacts and 

Improvement from PM Controls 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

Wet Scrubber Cyclone Wet ESP 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from 

Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. Wet 

Scrubber 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from 

Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. Cyclone 

(∆dv) 

Caney Creek 0.621 0.619 0.002 0.619 0.002 0.000 0.617 0.004 0.002 

Upper Buffalo 0.266 0.264 0.002 0.265 0.001 -0.001 0.263 0.003 0.002 

Hercules-Glades 0.230 0.228 0.002 0.229 0.001 -0.001 0.227 0.003 0.002 
57 

Mingo 0.227 0.224 0.003 0.225 0.002 -0.001 0.223 0.004 0.005 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.009 -- 0.006 -- -- 0.014 -- 

 The table above shows that the operation of a wet ESP, wet scrubber, and cyclone at 

McClellan Unit 1 is projected to result in minimal visibility improvement at the four affected 

Class I areas. The modeled visibility improvement from switching to No. 6 fuel oil with 1% 

sulfur content, No. 6 fuel oil with 0.5% sulfur content, diesel, and natural gas is summarized in 

Table 18. These visibility improvement estimates reflect both SO2 and PM emissions reductions 

as a result of switching to fuels with lower sulfur content. However, the majority of the baseline 

visibility impact at each Class I area when burning the baseline fuel oil at McClellan Unit 1 is 

due to SO2 emissions, while PM10 emissions contribute only a small portion of the baseline 

visibility impacts at each Class I area. Table 22 shows that the percentage of the visibility 

impairment at the four modeled Class I areas attributable to PM10 ranges from approximately 0.5 

– 3% for the fuel oil firing scenario. Most of the visibility impairment is attributable to SO4 (67 – 

99%) for the fuel oil firing scenario. Accordingly, the majority of the visibility improvement 

associated with switching to lower sulfur fuels can reasonably be expected to be the result of 

reduced SO2 emissions. 

Our Proposed PM BART determination: 

 Taking into consideration the five factors, we propose to determine that PM BART for 

the AECC McClellan Unit 1 does not require add-on controls. Consistent with our proposed 

determination for SO2 BART, we are proposing that PM BART is satisfied by Unit 1 switching 

to fuels with 0.5% or lower sulfur content by weight. As discussed above, we disagree with 

AECC’s use of a 15-year amortization period in the cost analysis for a wet ESP, wet scrubber, 

and cyclone. EPA is not aware of any enforceable shutdown date for the AECC McClellan 

Generating Station, and we believe the expected equipment life of these control technologies, 

which is at least 30 years, should be assumed to be the amortization period. Assuming a 30-year 

amortization period, these controls would have an improved cost-effectiveness (i.e., less dollars 

per ton removed) than estimated in AECC’s evaluation. However, after considering all five 

BART factors, AECC’s assumption of a 15-year amortization period does not have an impact on 

our proposed BART decision. Even if we revised AECC’s cost estimates to reflect a 30-year 

amortization period, resulting in a lower total annual cost and improved cost-effectiveness, we 

would still not be able to justify the costs of add-on controls in light of the minimal visibility 

benefit of these controls (see table above). 
58 

 We are proposing to determine that PM BART for McClellan Unit 1 is switching to fuels 

with 0.5% or lower sulfur content by weight. We propose to require that the facility purchase no 

fuel after the effective date of the rule that does not meet the sulfur content requirement and that 

5 years from the effective date of the rule no fuel be burned that does not meet the requirement. 

We expect this proposed compliance date would allow the facility sufficient time to burn its 

existing supply of No. 6 fuel oil (i.e., the baseline fuel), as the normal course of business dictates 

and in accordance with any operating restrictions enforced by ADEQ. We propose that any 

higher sulfur fuel oil that remains from its 2009 shipment cannot be burned past this point. 

3. AEP Flint Creek Power Plant 

The AEP Flint Creek Power Plant Unit 1 is subject to BART. In our March 12, 2012 final 

action we disapproved the State’s BART determinations for SO2 and NOX for Flint Creek Unit 1 

(77 FR 14604). AEP, through its consultant, performed a BART five factor analysis (AEP BART 

analysis), and our analysis of the five factors presented below is largely based on the technical 

work performed by AEP.39 

 Flint Creek Unit 1 is a dry bottom wall-fired boiler with a nominal generating capacity 

rating of 558 MW and a nominal design maximum heat input rate of 6,324 MMBtu/hr, and burns 

primarily low sulfur western coal. The unit is currently equipped with an ESP and low NOX

burners. 

a. Baseline Emission Rates and Existing Visibility Impairment Attributable to AEP 

Flint Creek Unit 1 

 AEP estimated SO2, NOX, and PM10 baseline emission rates and then modeled these 

emission rates to determine the existing visibility impairment attributable to Flint Creek Unit 1 

based on the default natural conditions. The baseline emission rates are shown in the table below. 

Table 35. AEP Flint Creek Unit 1: Baseline Maximum 24-Hour Emission Rates 

Source SO2

(lb/hr) 

SO4

(lb/hr) 

NOX

(lb/hr) 

PMc 

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

Unit 1 (SN-01) 4,728.4 3.1 1,945.0 65.1 50.1 15.1 1.9 

                                                            

39 See “BART Five Factor Analysis Flint Creek Power Plant Gentry, Arkansas (AFIN 04-00107),” dated September 

2013, Version 4, prepared by Trinity Consultants Inc. in conjunction with American Electric Power Service 

Corporation for the Southwestern Electric Power Company Flint Creek Power Plant. A copy of this BART 

analysis is found in the docket for our proposed rulemaking. 
59 

 The SO2 and NOX baseline emission rates are the highest actual 24-hour emission rates 

based on 2001-2003 CEMS data. The emission rates for the PM10 species reflect the breakdown 

of the filterable and condensable PM10 determined from the National Park Service (NPS) 

“speciation spreadsheet” for Dry Bottom Boiler Burning Pulverized Coal using only ESP.

40 The 

sulfate (SO4) emission rate was calculated using an EPRI methodology that considers the SO2 to 

SO4 conversion rate and SO4 reduction factors for various downstream equipment. 

 AEP then modeled the baseline emission rates using the CALPUFF dispersion model to 

determine the baseline visibility impairment attributable to AEP Flint Creek Unit 1 at the Caney 

Creek Wilderness Area, Upper Buffalo Wilderness Area, Hercules-Glades Wilderness Area, and 

Mingo National Wildlife Refuge. The existing visibility impairment attributable to Flint Creek 

Unit 1 at each Class I area is summarized in the table below. 

Table 36. Baseline Visibility Impairment Attributable to AEP Flint Creek Unit 1 (2001-

2003) 

Year Maximum 

(∆dv) 

98th

Percentile 

(∆dv) 

No. of Days 

with ∆dv ≥

0.5 

98th

Percentile 

%SO4

98th

Percentile 

%NO3

98th

Percentile 

%PM10

98th

Percentile 

%NO2

Caney Creek Wilderness 

2001 1.318 0.609 19 62.49 34.95 1.00 1.55 

2002 1.165 0.689 10 60.43 35.25 1.72 2.60 

2003 1.298 0.963 19 70.90 27.64 0.62 0.85 

Upper Buffalo Wilderness 

2001 1.732 0.955 22 53.01 45.08 1.16 0.74 

2002 2.426 0.965 18 96.29 2.75 0.96 0.00 

2003 1.394 0.670 23 89.90 5.4 2.74 1.97 

Hercules-Glades Wilderness 

2001 1.418 0.643 19 76.92 22.4 0.69 0.00 

2002 1.364 0.627 15 43.49 51.71 2.08 2.72 

2003 2.103 0.657 13 47.91 49.69 1.19 1.21 

Mingo National Wildlife Refuge 

2001 1.28 0.631 11 90.97 8.59 0.42 0.01 

2002 0.841 0.424 6 93.66 5.94 0.40 0.00 

2003 1.488 0.393 3 38.60 59.69 1.07 0.64 

b. SO2 BART Evaluation 

                                                            

40 The NPS Workbook, “PC Dry Bottom ESP Example.xls” updated 03/2006, was obtained from the NPS website: 

http://www.nature.nps.gov/air/Permits/ect/index.cfm. AEP input the following parameters into the workbook for 

speciation determination: total PM10 emission rate of 192.5 lb/hr, heat value of 8,500 Btu/lb, sulfur content of 

0.31%, ash content of 4.9%. 
60 

 Flint Creek Unit 1 primarily combusts low sulfur western coal, but is also permitted to 

burn fuel oil and tire derived fuels. Fuel oil firing is only allowed during unit startup and 

shutdown, startup and shutdown of pulverizer mills, for flame stabilization when coal is frozen, 

fuel oil tank maintenance, to prevent boiler tube failure in extreme cold weather when the unit is 

offline for maintenance, and malfunction. Sulfur oxides (or SOX) are generated during coal and 

fuel oil combustion from the oxidation of sulfur contained in the fuel. SOX emissions are almost 

entirely dependent on the sulfur content of the fuel and are generally not affected by boiler size 

or burner design. SOX emissions from conventional combustion systems are predominantly in 

the form of SO2. The five factors considered in the SO2 BART analysis are discussed below. 

Step 1- Identify All Available Retrofit Control Technologies 

 The SO2 control technologies considered in AEP’s SO2 BART analysis are Dry Sorbent 

Injection (DSI), a dry scrubber, and a wet scrubber. 

Step 2- Eliminate Technically Infeasible Options

 All SO2 control technology options considered in the analysis were determined to be 

technically feasible options. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 

 DSI involves the injection of a sorbent into the exhaust stream where SO2 reacts with and 

becomes entrained in the sorbent. The stream is then passed through a particulate control device 

to remove the sorbent and entrained SO2. In AEP’s analysis, it was noted that depending on 

residence time, gas stream temperature, and limitations of the particulate control device, DSI 

control efficiency can range between 40 to 60%.41 

 In dry scrubbing systems, an alkaline reagent and water are introduced into the flue gas 

stream, where they react with SO2 to form calcium sulfite and calcium sulfate. The liquid-to-gas 

ratio is such that the heat from the exhaust gas causes the water to evaporate before leaving the 

scrubber outlet, leading to the formation of a dry powder which is carried out with the gas and 

collected with a fabric filter. Dry scrubber control efficiency ranges from 60 to 95%. There are 

various designs of dry scrubbing systems, including Spray Dryer Absorber (SDA), Circulating 

Dry Scrubbing (CDS), and Novel Integrated Desulfurization (NID) technology. According to 

AEP’s evaluation, discussions with vendors indicated that an outlet emission rate of 0.06 

lb/MMBtu at Flint Creek Unit 1 would be achievable with NID technology. In its analysis, AEP 

noted that it has no data to suggest that lower emission levels are sustainably achievable with the 

                                                            

41 “Assessment of Control Technology Options for BART-Eligible Sources: Steam Electric Boilers, Industrial 

Boilers, Cement Plants and Paper and Pulp Facilities” Northeast States for Coordinated Air Use Management 

(NESCAUM), March 2005. 
61 

NID technology in a retrofit application, and that it was not guaranteed a better performance 

level by equipment vendors. An emission rate of 0.06 lb/MMBtu represents 92% control from 

the unit’s baseline 30-day average rate of 0.75 lb/MMBtu. 

 Wet scrubbing involves scrubbing the exhaust gas stream with a slurry comprised of lime 

or limestone in suspension. The process takes place in a wet scrubbing tower located 

downstream of a PM control device such as a fabric filter or an ESP. AEP’s analysis notes that 

wet lime scrubbing is capable of achieving 80 to 95% control when used with lower sulfur coals 

such as those burned at Flint Creek Unit 1. 

 The table below summarizes the controlled emission rates of SO2 control technologies as 

evaluated by AEP. The remainder of AEP’s analysis focused on the two control options with the 

highest control efficiency: wet scrubbing and dry scrubbing (NID). 

Table 37. Control Effectiveness of Technically Feasible SO2 Control Technologies for AEP 

Flint Creek Unit 1 

Control Technology 

SO2 Baseline 

Emission Rate 

 (lb/MMBtu) 

Controlled 

Emission Rate 

(lb/MMBtu) 

Estimated Control 

Efficiency 

Wet Scrubbing 

0.75 

0.04 95% 

Dry Scrubbing (NID) 0.06 92% 

Dry Sorbent Injection 0.30 60% 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

 The capital and operating costs of a wet scrubber and a dry scrubber (NID) estimated in 

AEP’s analysis and used in the calculation of the average cost-effectiveness were based on the 

EPA Control Cost Manual and supplemented, where available, with vendor and site-specific 

information obtained by AEP.42 AEP annualized the capital costs over a 30-year period and then 

                                                            

42 See “BART Five Factor Analysis Flint Creek Power Plant Gentry, Arkansas (AFIN 04-00107),” dated September 

2013, Version 4, prepared by Trinity Consultants Inc. in conjunction with American Electric Power Service 

Corporation for the Southwestern Electric Power Company Flint Creek Power Plant. AEP’s SO2 control cost 

calculations are found in Appendix A of the BART analysis. An Excel file titled “Consolidated Spreadsheet_2013-

09-09” containing spreadsheets with cost information was also provided by AEP Flint Creek in support of the cost 

analysis. A copy of the BART analysis and the Excel file is found in the docket for our proposed rulemaking.
62 

added these to the annual operating costs to obtain the total annualized costs. The annual 

emissions reductions used in the cost-effectiveness calculations were determined by subtracting 

the estimated controlled annual emission rate from the baseline annual emission rate. The 

baseline annual emission rate is the average rate from 2001-2003, and the controlled annual 

emission rates were based on emission rate levels in lb/MMBtu believed to be achievable for the 

control technology multiplied by the baseline heat input to the boiler. AEP calculated the average 

cost-effectiveness in terms of dollars per ton of SO2 reduced by dividing the total annualized cost 

of controls by the annual emissions reductions. AEP estimated the average cost-effectiveness of 

a wet scrubber at an SO2 emission rate of 0.04 lb/MMBtu to be $4,919/ton of SO2 removed, 

while the average cost-effectiveness of NID at an SO2 emission rate of 0.06 lb/MMBtu was 

estimated to be $3,845/ton of SO2 removed (see the table below). 

 We disagree with one aspect of AEP’s cost analysis.43 AEP’s cost estimates are based on 

2016 dollars. AEP escalated costs to a future build date, even though BART should be based on 

present dollars. The approach in the EPA Control Cost Manual explicitly excludes future 

escalation, as cost comparisons should be made on a current real dollar basis. Escalation of costs 

from past to the current year of analysis is permitted, as costs are compared based on the time of 

estimate, but future escalation is not allowed. We expect that de-escalation to 2014 dollars would 

result in lower cost numbers and an improved overall cost-effectiveness (i.e., less dollars per ton 

removed) for all controls evaluated. However, we did not adjust the cost numbers and the costeffectiveness values because we do not expect this to change our proposed BART decision. This 

is discussed in more detail below in the subsection titled “Our Proposed SO2 BART 

Determination.” 

Table 38. Summary of Cost of SO2 Controls for AEP Flint Creek Unit 1 

Control 

Technology 

Baseline 

Emission 

Rate 

(SO2

tpy) 

Controlled 

Emission 

Rate 

(SO2

lb/MMBtu) 

Controlled 

Emission 

Rate 

(SO2 tpy) 

Annual 

Emissions 

Reductions 

(SO2 tpy) 

Capital 

Cost 

($) 

Capital 

Recovery 

& Other 

Indirect 

Annual 

Costs 

($/yr) 

Annual 

Fixed 

O&M 

($/yr) 

Annual 

Variable 

O&M 

($/yr) 

Total 

Annual 

Cost 

($/yr) 

Average 

CostEffectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

NIDS 11,641 0.06 1,120 10,521 281,738,024 30,763,370 205,825 9,478,894 40,448,089 3,845 - 

Wet 

Scrubber 11,641 0.04 747 10,894 374,427,351 40,884,248 205,825 12,502,590 53,592,663 4,919 35,240 

 AEP’s evaluation noted that the potential negative energy and non-air quality 

environmental impacts are greater with wet scrubbing systems than dry scrubbing systems. AEP 

noted that wet scrubbers require increased water use and generate large volumes of wastewater 

                                                            

43 Id. 
63 

and solid waste/sludge that must be treated or stabilized before landfilling, placing additional 

burden on the wastewater treatment and solid waste management capabilities. We do not expect 

that water availability would affect the feasibility of a wet scrubber at Flint Creek Unit 1 because 

the facility is not located in an exceptionally arid region. Additionally, the BART Guidelines 

provide that the fact that a control device creates liquid and solid waste that must be disposed of 

does not necessarily argue against selection of that technology as BART, particularly if the 

control device has been applied to similar facilities elsewhere (40 CFR Part 51, Appendix Y, 

section IV.D.4.i.2.). In cases where the facility can demonstrate that there are unusual 

circumstances that would create greater problems than experienced elsewhere, this may provide 

a basis for the elimination of that control option as BART. But in this case, AEP has not 

indicated that there are any such unusual circumstances. Another potential negative energy and 

non-air quality environmental impact associated with wet scrubbing systems is the potential for 

increased power requirements and greater reagent usage compared to dry scrubbers. The costs 

associated with increased power requirements and greater reagent usage have already been 

factored into the cost analysis for the wet scrubber. 

 The presence of existing pollution control technology at the source is reflected in the 

BART analysis in two ways: first, in the consideration of available control technologies, and 

second, in the development of baseline emission rates for use in cost calculations and visibility 

modeling. AEP Flint Creek Unit 1 has no existing SO2 pollution control technology. 

 With regard to consideration of the remaining useful life of the unit, we are not aware of 

any enforceable shutdown date for AEP Flint Creek Unit 1, nor did AEP’s evaluation indicate 

any future planned shutdown. This means that the anticipated useful life of the boiler is expected 

to be at least as long as the capital cost recovery period of controls. Therefore, we believe it is 

appropriate to assume a 30-year amortization period in the SO2 BART analysis as the remaining 

useful life of the unit. 

Step 5- Evaluate Visibility Impacts

 

 AEP assessed the visibility improvement associated with a wet scrubber and NID 

technology by modeling the SO2 emission rates associated with each control option using 

CALPUFF, and then comparing the visibility impairment associated with the baseline emission 

rates to the visibility impairment associated with the controlled emission rates, as measured by 

the 98th percentile modeled visibility impact. The modeled SO2 emission rates associated with 

wet scrubbing and NID technology were calculated by multiplying the controlled emission level 

(i.e., 0.04 lb/MMBtu for wet scrubbing and 0.06 lb/MMBtu for NID technology) by the boiler 

heat input of 6,324 MMBtu/hr. The NOX emission rate was modeled at the baseline rate for both 

the wet scrubbing and NID technology options. NID technology involves the use of a fabric 

filter, and the change from the existing ESP to a fabric filter will result in changes in PM 

speciation. AEP estimated this and all other rates that changed from the baseline case using the 

NPS speciation spreadsheets for dry bottom boilers burning pulverized coal using only fabric 
64 

filter for emissions control. The tables below show the modeled emission rates and a comparison 

of the baseline (i.e., existing) visibility impacts and the visibility impacts of a wet scrubber and 

NID technology, including the maximum modeled visibility impact and the 98th percentile 

modeled visibility impact for each Class I area. The visibility improvement associated with each 

control scenario was calculated as the difference between the existing visibility impairment and 

the visibility impairment for each control scenario as measured by the 98th percentile modeled 

visibility impact. The table below also shows the incremental visibility improvement of wet 

scrubbers over NID. 

Table 39. Summary of Emission Rates Modeled for SO2 Control Scenarios at AEP Flint 

Creek Unit 1

Control Technology 

SO2

(lb/hr) 

SO4

(lb/hr)

NOX

(lb/hr) 

PMC

(lb/hr) 

PMf

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

NIDS 379.4 0.004 1,945.0 35.2 33.9 24.4 1.3 

Wet Scrubber 253.0 0.11 1,945.0 35.2 33.9 24.4 1.3 

Table 40. AEP Flint Creek Unit 1: Summary of the 98th Percentile Visibility Impacts and 

Improvement Due to SO2 Controls 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

NID Technology Wet Scrubber 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement vs. 

NID 

(∆dv) 

Caney Creek 0.963 0.348 0.615 0.334 0.629 0.014 

Upper Buffalo 0.965 0.501 0.464 0.488 0.477 0.013 

Hercules-Glades 0.657 0.312 0.345 0.305 0.352 0.007 

Mingo 0.631 0.217 0.414 0.208 0.423 0.009 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 1.838 -- 1.881 -- 

 The table above shows that the installation and operation of SO2 controls at Flint Creek 

Unit 1 is expected to result in considerable visibility improvement at the four modeled Class I 

areas. Installation and operation of NID technology is projected to result in visibility 
65 

improvement of up to 0.615 dv at any single Class I area (based on the 98th percentile modeled 

visibility impacts), while a wet scrubber is projected to result in visibility improvement of up to 

0.629 dv. A wet scrubber is projected to result in very minimal incremental visibility benefit over 

NID technology, with the projected incremental visibility improvement over NID ranging from 

0.007 to 0.014 dv at each Class I area. 

Our Proposed SO2 BART Determination: 

Taking into consideration the five factors, we propose to determine that BART for Flint 

Creek Unit 1 is an emission limit of 0.06 lb/MMBtu on a 30 boiler-operating-day rolling average 

based on the installation and operation of NID. The operation of NID is expected to result in 

visibility improvement ranging from 0.352 to 0.629 dv at each affected Class I area (98th

percentile basis), and based on AEP’s evaluation, is estimated to have an average costeffectiveness of $3,845/ton of SO2 removed. By comparison, AEP estimated a wet scrubber to 

have an average cost-effectiveness of $4,919/ton of SO2 removed and the incremental costeffectiveness of wet scrubbers compared to NID is estimated to be $35,240 per ton of SO2

removed. As discussed above, we believe that AEP’s escalation of the cost of controls to 2016 

dollars has likely resulted in the over estimation of the average cost-effectiveness values. 

Therefore, we believe a wet scrubber and NID are more cost-effective (i.e., less dollars per ton of 

SO2 removed) than estimated by AEP (see table above). However, we did not adjust the cost 

numbers and cost-effectiveness values because we do not believe that doing so would change our 

proposed BART determination. We believe that the average cost-effectiveness of both control 

options was likely over-estimated and the costs associated with a wet scrubber would continue to 

be higher than the costs associated with NID if the estimates were adjusted, yet the installation 

and operation of a wet scrubber is projected to result in minimal incremental visibility 

improvement over NID. We are proposing to determine that SO2 BART for Flint Creek Unit 1 is 

an emission limit of 0.06 lb/MMBtu on a 30 boiler-operating-day rolling average based on the 

installation and operation of NID. We believe that the full compliance time44 of 5 years is 

warranted for a new scrubber retrofit and so propose to require compliance with this requirement 

no later than 5 years from the effective date of the final rule. 

c. NOX BART Evaluation 

 Nitrogen oxides, or NOX, are produced during fuel combustion when nitrogen contained 

in both the fuel and the combustion air is exposed to high temperatures. Nitrogen oxide (NO) is 

typically the predominant form of NOX from fossil fuel combustion, with nitrogen dioxide (NO2) 

making up the remainder of the NOX. AEP’s evaluation noted that the formation of NOX

compounds in utility boilers is sensitive to the method of firing and combustion flame 

                                                            

44 Section 51.308(e)(1)(iv), requires, “each source subject to BART be required to install and operate BART as 

expeditiously as practicable, but in no event later than 5 years after approval of the implementation plan revision.” 
66 

temperatures. In a wall-fired boiler, such as Flint Creek Unit 1, burners are mounted in the boiler 

walls, producing discrete flames in the furnace. In tangentially-fired boilers, a single rotating 

flame is created in the center of the furnace, rather than the discrete flames produced by burners 

in the wall-fired boilers. Tangentially fired boilers typically have lower uncontrolled NOX

emissions than wall-fired boilers. Therefore, baseline NOX emission rates can vary significantly 

from plant to plant due to method of firing and combustion flame temperatures, among other 

factors. The baseline NOX emission rate for Flint Creek Unit 1 was discussed under section 

II.C.2.a. of this TSD. The five factors considered in the NOX BART analysis are discussed 

below. 

Step 1- Identify All Available Retrofit Control Technologies 

 The NOx control technologies considered in AEP’s NOX BART report include both 

combustion and post-combustion controls. The combustion controls evaluated consisted of FGR, 

OFA, and LNB. The post-combustion controls evaluated consisted of SCR and SNCR. 

Step 2- Eliminate Technically Infeasible Options

 All evaluated NOX control options were found to be technically feasible. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 The estimated NOX controlled emission rate of each control option considered by AEP is 

shown in the table below. The baseline NOX emission rate for Flint Creek Unit 1 is 

approximately 0.31 lb/MMBtu. AEP’s evaluation stated that based on experience with similar 

boilers and discussions with vendors, it is estimated that the installation and operation of new 

LNB in combination with OFA at Flint Creek Unit 1 would achieve a NOX control level of 

approximately 0.23 lb/MMBtu. It also estimated that new LNB/OFA in combination with SNCR 

would achieve a NOX control level of approximately 0.2 lb/MMBtu, and SCR would achieve a 

NOX control level of approximately 0.067 lb/MMBtu. 

Table 41. Control Effectiveness of Technically Feasible NOX Control Technologies- AEP 

Flint Creek Unit 1 

Control Technology 

Estimated Controlled Level 

for Flint Creek Unit 1 

(lb/MMBtu) 

SCR 0.067 

LNB/OFA + SNCR 0.18 – 0.23 

LNB/OFA 0.18 – 0.24 
67 

SNCR 0.18 – 0.27 

FGR 0.23 – 0.29 

LNB 0.20 – 0.26 

OFA 0.28 – 0.29 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

 AEP estimated the capital costs, operating costs, and average cost-effectiveness of NOX

controls based on vendor estimates and published calculation methods.45 AEP noted that the cost 

analysis followed the EPA Control Cost Manual to the extent possible and estimates were 

supplemented with vendor and site-specific information where available. The cost analysis 

assumed a 30-year amortization period for LNB with OFA and for SCR, and a 20-year 

amortization period for SNCR. The total annual costs were estimated by annualizing the capital 

cost of controls over either a 30-year or 20-year period and then adding to this value the annual 

operating cost of controls. AEP determined the annual emissions reductions associated with each 

NOX control option by subtracting the estimated controlled annual emission rate from the 

baseline annual emission rate. The baseline annual emission rate is the average rate as reported 

by AEP Flint Creek in the 2001-2003 air emission inventories, while the controlled annual 

emission rates are based on the lb/MMBtu levels believed to be achievable from the control 

technology multiplied by the baseline heat inputs to the boilers in MMBtu/yr. The baseline heat 

input is based on the 2001-2003 average daily heat input for Flint Creek Unit 1 as determined 

from the EPA’s Clean Air Markets Database (CAMD). 

 The average cost-effectiveness of NOX controls was calculated by dividing the total 

annual cost of each control option by the estimated annual NOX emissions reductions. The table 

below summarizes the average-cost effectiveness of NOX controls for Flint Creek Unit 1. 

                                                            

45 See “BART Five Factor Analysis Flint Creek Power Plant Gentry, Arkansas (AFIN 04-00107),” dated September 

2013, Version 4, prepared by Trinity Consultants Inc. in conjunction with American Electric Power Service 

Corporation for the Southwestern Electric Power Company Flint Creek Power Plant. AEP’s NOX control cost 

calculations are found in Appendix B of the BART analysis. An Excel file titled “Consolidated Spreadsheet_2013-

09-09” containing spreadsheets with cost information was also provided by AEP Flint Creek in support of the cost 

analysis. A copy of the BART analysis and the Excel file is found in the docket for our proposed rulemaking.
68 

Table 42. Summary of NOX Controls for AEP Flint Creek Unit 1 

Control 

Technology

Baseline 

NOX

Emission 

Rate 

(tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Controlled 

Emission 

Rate 

(NOX tpy) 

Annual 

Emissions 

Reductions 

(NOX tpy) 

Capital 

Cost 

($) 

Annual 

Capital 

Cost 

($.yr) 

Annual 

Fixed 

O&M 

($/yr) 

Annualized 

Variable 

O&M 

($/yr) 

Total 

Annual 

Cost 

($/yr) 

Average 

CostEffectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

LNB/OFA 5,120.27 0.23 4,294.65 825.62 16,000,000 1,289,382 240,000 132,364 1,454,621 1,761 - 

LNB/OFA/SNCR 5,120.27 0.20 3,771.82 1,348.45 23,124,235 1,961,860 240,000 2,183,048 4,177,782 3.098 5,217 

SCR 5,120.27 0.07 1,251.05 3,869.22 121,440,000 9,786,413 1,560,000 3,700,000 13,769,599 3,559 3,805 

 Based on AEP’s cost evaluation for Flint Creek Unit 1, the average cost-effectiveness of 

installing and operating LNB/OFA is $1,761/ton of NOX removed. The average costeffectiveness of LNB/OFA + SNCR is $3,098/ton of NOX removed, while that of SCR is 

$3,559/ton of NOX removed. The incremental cost-effectiveness of LNB/OFA + SNCR 

compared to LNB/OFA is $5,217/ton of NOX removed, while that of SCR compared to 

LNB/OFA + SNCR is $3,805/ton of NOX removed. 

 AEP did not identify any energy or non-air quality environmental impacts associated with 

the use of LNB or OFA. As for SCR and SNCR, we are not aware of any unusual circumstances 

at the facility that could create energy or non-air quality environmental impacts associated with 

the operation of these controls greater than experienced elsewhere and that may therefore 

provide a basis for their elimination as BART (40 CFR Part 51, Appendix Y, section 

IV.D.4.i.2.). Therefore, we do not believe there are any energy or non-air quality environmental 

impacts associated with the operation of NOX controls at AEP Flint Creek Unit 1 that would 

affect our proposed BART determination. 

 AEP Flint Creek Unit 1 is currently equipped with early generation low NOX burners for 

control of NOX emissions. The presence of existing pollution control technology at each source 

is reflected in the BART analysis in two ways: first, in the consideration of available control 

technologies, and second, in the development of baseline emission rates for use in cost 

calculations and visibility modeling. The baseline emission rate used in the cost calculations and 

visibility modeling reflects the operation of these controls. The newer generation low NOX

burners evaluated by AEP are expected to achieve a higher level of NOX control than the 

currently installed early generation low NOX burners. 

 With regard to consideration of the remaining useful life of the unit, we are not aware of 

any enforceable shutdown date for the AEP Flint Creek Unit 1, nor did AEP’s evaluation 

indicate any future planned shutdown. This means that the anticipated useful life of the boiler is 

expected to be at least as long as the capital cost recovery period of controls. AEP assumed a 30-

year amortization period in the evaluation of LNB/OFA and SCR and a 20-year amortization 

period in the evaluation of SNCR. We disagree with AEP’s assumption of a 20-year amortization 
69 

period in the cost analysis of SNCR. Any air pollution controls on the unit are expected to have 

the same life as the boiler. Therefore, we believe it is appropriate to assume a 30-year 

amortization period for SNCR, as was done for SCR and combustion controls. Assuming a 30-

year amortization period, SNCR would have a lower estimated total annual cost and would 

therefore be more cost-effective (i.e., less dollars per ton removed) than estimated in AEP’s 

evaluation. However, we did not adjust the amortization period assumed in AEP’s evaluation 

because we do not believe this has an impact on our proposed BART decision. As discussed in 

the subsection below, the incremental visibility benefit expected from the installation and 

operation of SNCR is too small to justify the cost of these controls compared to combustion 

controls alone. Therefore, we did not revise the amortization period and the average costeffectiveness calculations for SNCR. 

Step 5- Evaluate Visibility Impacts 

AEP assessed the visibility improvement associated with NOX controls by modeling the 

NOX emission rates associated with each control option using CALPUFF, and then comparing 

the visibility impairment associated with the baseline emission rates to the visibility impairment 

associated with the controlled emission rates. The controlled emission levels associated with 

combustion controls, combustion controls + SNCR, and SCR systems are shown in the table 

above (see third column). These levels were multiplied by the unit’s maximum heat input to 

derive the hourly emission rates used in the modeling. The tables below show the modeled 

emission rates and a comparison of the existing (i.e., baseline) visibility impacts and the 

visibility impacts associated with NOX controls, including the maximum modeled visibility 

impact and the 98th percentile modeled visibility impact for each Class I area. The visibility 

improvement over the baseline was calculated as the difference between the baseline visibility 

impairment and the visibility impairment associated with each control scenario. The incremental 

visibility improvement of LNB/OFA + SNCR was calculated as the difference in visibility 

improvement between LNB/OFA + SNCR and LNB/OFA. The incremental visibility 

improvement of SCR was calculated as the difference in visibility improvement between SCR 

and LNB/OFA + SNCR. 

Table 43. Summary of Emission Rates Modeled for NOX Control Scenarios at AEP Flint 

Creek Unit 1

Control 

Technology

SO2

(lb/hr)

SO4

(lb/hr) 

NOX

(lb/hr) 

PM

(lb/hr) 

PMF

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

LNB/OFA 4728.4 3.1 1454.5 65.1 50.1 15.1 1.9 

SCR 4728.4 3.1 423.7 65.1 50.1 15.1 1.9 

LNB/OFA + 

SNCR 4728.4 3.1 1277.74 65.1 50.1 15.1 1.9 
70 

Table 44. AEP Flint Creek Unit 1: Summary of 98th Percentile Visibility Improvement Due 

to NOX Controls 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

LNB/OFA LNB/OFA + SNCR SCR 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

LNB/OFA 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

 LNB/OFA + SNCR 

 (∆dv) 

Caney Creek 0.963 0.882* 0.081* 0.849 0.114 0.033* 0.718 0.245 0.131 

Upper 

Buffalo 0.965 0.939 0.026 0.932 0.033 0.007 0.895 0.070 0.037 

HerculesGlades 0.657 0.633 0.024 0.623 0.034 0.010 0.573 0.084 0.050 

Mingo 0.631 0.617 0.014 0.612 0.019 0.005 0.588 0.043 0.024 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.145 -- 0.2 0.055 -- 0.442 0.242 

*EPA identified a discrepancy in the results presented by AEP and reran the model for the 2003 model year. These 

values have been adjusted to reflect the results of the EPA model run. 

 The table above summarizes the modeled baseline visibility impact and the modeled 

visibility improvement due to the installation and operation of controls at the four Class I areas 

within 300 km of the facility. We note that we identified a discrepancy in the results presented by 

AEP and reran the model for the 2003 model year. The modeled visibility impacts at Caney 

Creek for the LNB/OFA scenario and the incremental visibility improvement between 

LNB/OFA and LNB/OFA + SNCR were adjusted to reflect the results of this model run. The 

table above shows that the installation and operation of LNB/OFA at Flint Creek Unit 1 is 

projected to result in visibility improvement ranging from 0.014 to 0.081 dv at each modeled 

Class I area, based on the 98th percentile visibility impairment. The installation and operation of 

LNB/OFA + SNCR is projected to result in visibility improvement of up to 0.114 dv at each 

modeled Class I area over the baseline. The combination of LNB/OFA + SNCR is projected to 

result in small incremental visibility benefit over LNB/OFA at Caney Creek and negligible 

incremental visibility benefit over LNB/OFA at the other three affected Class I areas. The 

installation and operation of SCR is projected to result in visibility improvement ranging from 

0.043 to 0.245 dv at each modeled Class I area. SCR would result in 0.131 dv incremental 
71 

visibility benefit over LNB /OFA + SNCR at Caney Creek and less than half as much 

incremental visibility benefit at the other three affected Class I areas. 

Our Proposed NOX BART determination: 

Taking into consideration the five factors, we propose to determine that BART for Flint 

Creek Unit 1 is an emission limit of 0.23 lb/MMBtu on a 30 boiler-operating-day rolling average 

based on the installation and operation of new LNB/OFA. The operation of new LNB/OFA is 

projected to result in visibility improvement ranging from 0.014 to 0.081 dv at each affected 

Class I area (98th percentile basis), and a cumulative visibility improvement of 0.145 ∆dv across 

the four affected Class I areas. The installation and operation of LNB/OFA is estimated to have 

an average cost-effectiveness of $1,762/ton of NOX removed, which we consider to be very costeffective. By comparison, the operation of LNB/OFA + SNCR is projected to result in small 

incremental visibility improvement over LNB/OFA, but is estimated to have an average costeffectiveness of $3,098/ton of NOX removed and an incremental cost-effectiveness of $5,217/ton 

of NOX removed. We believe that AEP’s assumption of a 20-year amortization period for SNCR 

has likely resulted in the over-estimation of the average cost-effectiveness value. Therefore, we 

believe LNB/OFA + SNCR is more cost-effective (i.e., less dollars per ton of NOX removed) 

than estimated by AEP (see table above). However, we did not adjust the cost numbers and costeffectiveness values because we do not believe that doing so would change our proposed BART 

determination, as the installation and operation of LNB/OFA with SNCR is projected to result in 

minimal incremental visibility improvement over LNB/OFA alone such that the additional cost 

of SNCR is not justified. 

 The operation of SCR is projected to result in visibility improvement ranging from 

0.043 to 0.245 ∆dv at each Class I area, and has an average cost-effectiveness of $3,559/ton of 

NOX removed. The incremental visibility benefit of SCR compared to LNB/OFA + SNCR is a 

maximum of 0.131 dv at any single Class I area, and the incremental cost-effectiveness is 

estimated to be $3,805/ton of NOX removed. While we believe the average and incremental costeffectiveness of SCR, as estimated by AEP, is within the range of what we consider to be costeffective, we do not believe the 0.131 dv incremental visibility benefit of SCR over LNB/OFA + 

SCNR warrants the higher costs associated with SCR. We are proposing to determine that NOX

BART for Flint Creek Unit 1 is an emission limit of 0.23 lb/MMBtu on a 30 boiler-operating-day 

rolling average based on the installation and operation of new LNB/OFA. We consider 3 years to 

be an adequate time for the installation of NOX combustion controls and thus propose to require 

compliance with this requirement no later than 3 years from the effective date of the final rule. 

4. Entergy White Bluff Power Plant 

 The Entergy White Bluff Power Plant Units 1 and 2, and the Auxiliary Boiler are subject 

to BART. In our March 12, 2012 final action we disapproved the State’s BART determinations 
72 

for SO2 and NOX for Units 1 and 2 and the BART determination for all pollutants for the 

Auxiliary Boiler (77 FR 14604). Entergy, through its consultant, performed a BART five factor 

analysis (Entergy BART analysis), and our analysis of the five factors presented below is largely 

based on the technical work performed by Entergy.46 

 White Bluff Units 1 and 2 are identical tangentially-fired boilers each with a maximum 

net power rating of 850 MW and a nominal heat input capacity of 8,950 MMBtu/hr. The boilers 

burn sub-bituminous coal as the primary fuel and No. 2 fuel oil or biofuel as a start-up fuel. Units 

1 and 2 are currently equipped with ESPs for control of PM emissions. The Auxiliary Boiler is a 

183 MMBtu/hr auxiliary boiler that burns only No. 2 fuel oil or biodiesel, and its purpose is to 

provide steam for the start-up of the two primary boilers, Units 1 and 2. The Auxiliary Boiler is 

typically only used in the rare instance when both of the main boilers are not operating. 

a. Baseline Emission Rates and Existing Visibility Impairment Attributable to White 

Bluff Units 1, 2, and Auxiliary Boiler

 Entergy estimated SO2, NOX, and PM10 baseline emission rates and then modeled these 

emission rates to determine the existing visibility impairment attributable to White Bluff Units 1 

and 2 and the Auxiliary Boiler based on the default natural conditions. The baseline emission 

rates are from actual emissions based on CEMS data, stack testing, and annual emissions 

inventory information. The baseline emission rates are shown in the table below. 

Table 45. Entergy White Bluff: Baseline Maximum 24-Hour Emission Rates 

Subject to BART Unit SO2

(lb/hr) 

NOX

(lb/hr) 

Total 

PM10

(lb/hr) 

SO4

(lb/hr) 

PMc 

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

Unit 1 (SN-01) 7,763.5 3,001.4 118.6 36.8 40.4 31.1 9.2 1.2 

Unit 2 (SN-02) 7,825.1 3,527.4 118.6 36.8 40.4 31.1 9.2 1.2 

Auxiliary Boiler (SN-05) 5.8 31.7 2.8 0.9 0.5 1.2 0.2 0.1 

 The SO2 and NOX baseline emission rates are the highest actual 24-hour emission rates 

based on CAMD data from 2001-2003 for SO2 and from 2009-2011 for NOX. 

The 2001-2003 period was not used as the baseline for NOX because that period no 

longer represents actual operation of the boilers. In 2006, Entergy completed the addition of a 

                                                            

46 See “Revised BART Five Factor Analysis White Bluff Steam Electric Station Redfield, Arkansas (AFIN 35-

00110),” dated October 2013, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc. A 

copy of this BART analysis is found in the docket for our proposed rulemaking. 
73 

neural network system and conducted extensive boiler tuning that substantially reduced NOX

emissions, resulting in an actual change in operations and emissions between the original 

baseline period (2001-2003) and current operations. Neural network systems are online 

enhancements to digital control systems (DCS) and plant information systems that improve 

boiler performance parameters such as heat rate, NOX emissions, and carbon monoxide (CO) 

levels. According to information provided by the facility, the purpose of the neural network 

system was to monitor and control the heat rate at Units 1 and 2.47 The neural network system 

installed at Units 1 and 2 is optimized first for monitoring and controlling the heat rate, and 

second for minimizing NOX emissions. We believe the use of 2009-2011 as the new baseline 

period for NOX is consistent with the BART Guidelines, which provide that “The baseline 

emissions rate should represent a realistic depiction of anticipated annual emissions for the 

source” (40 CFR Part 51, Appendix Y, Section IV.D.4.c). 

The PM10 emission rates are based on emission factors from AP-42 for PM10 filterable 

and PM condensable with a 99% control efficiency for ESP applied to the PM10 filterable in 

conjunction with the average coal heat value and average coal % ash from 2009-2011. The 

emission rates for the PM10 species reflect the breakdown of the PM10 determined from the 

National Park Service (NPS) “speciation spreadsheet” for Dry Bottom Boiler Burning Pulverized 

Coal using only ESP.48 To estimate sulfuric acid emissions to model for the baseline and control 

cases, Entergy assumed all inorganic PM was SO4. We note that this methodology can 

overestimate the amount of sulfuric acid emitted from the facility and we recommend that 

sulfuric acid emissions from power plants be calculated by estimating the amount of H2SO4

produced and the amount of H2SO4 removed by control equipment using information from the 

Electric Power Research Institute (EPRI).49 Rather than assuming that 100% of inorganic 

condensable PM is SO4, the EPRI method estimates the amount of SO2 that is oxidized to SO3, 

assumes that 100% of SO3 is converted to H2SO4, and then accounts for losses due to 

downstream equipment. The sulfuric acid emissions for the base and control scenarios may be 

somewhat overestimated in Entergy’s modeling. However, in this specific situation, we do not 

anticipate that this difference would significantly impact the relative benefits of the SO2 controls 

examined or impact our BART determination since the overall impacts and benefits of control 

are large. 

                                                            

47 See the “S&L NOX Control Technology Study,” which is found in Appendix E to the “Revised BART Five Factor 

Analysis White Bluff Steam Electric Station Redfield, Arkansas (AFIN 35-00110),” dated October 2013, prepared 

by Trinity Consultants Inc. in conjunction with Entergy Services Inc. A copy of this BART analysis and its 

appendices is found in the docket for our proposed rulemaking. 

48 The NPS Workbook, “PC Dry Bottom ESP Example.xls” updated 03/2006, was obtained from the NPS website: 

http://www.nature.nps.gov/air/Permits/ect/index.cfm. Entergy input the following parameters into the workbook 

for speciation determination: total PM10 emission rate of 118.6 lb/hr, heat value of 8,950 Btu/lb, sulfur content of 

0.27%, ash content of 4.87%. 

49 Electric Power Research Institute (EPRI) Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: 

Version 2010a. EPRI, Palo Alto, CA: 2010 
74 

 Entergy then modeled the baseline emission rates using the CALPUFF dispersion model 

to determine the baseline visibility impairment attributable to White Bluff Unit 1, Unit 2, and the 

Auxiliary Boiler at the Caney Creek Wilderness Area, Upper Buffalo Wilderness Area, 

Hercules-Glades Wilderness Area, and Mingo National Wildlife Refuge. The existing visibility 

impairment attributable to White Bluff Units 1 and 2 and the Auxiliary Boiler at each Class I 

area is summarized in the tables below. 

Table 46. Baseline Visibility Impairment Attributable to White Bluff Unit 1 

Year Maximum 

(∆dv) 

98th

Percentile 

(∆dv) 

No. of 

Days with 

∆dv ≥ 0.5 

98th

Percentile 

%SO4

98th

Percentile 

%NO3

98th

Percentile 

%PM10

98th

Percentile 

%NO2

Caney Creek Wilderness 

2001 2.956 1.628 41 1.287 0.336 0.003 0.002 

2002 2.111 1.386 30 0.662 0.659 0.011 0.054 

2003 4.194 1.130 35 0.722 0.385 0.003 0.020 

Upper Buffalo Wilderness 

2001 2.339 1.128 34 0.835 0.290 0.003 0.000 

2002 1.544 0.818 18 0.680 0.133 0.003 0.002 

2003 1.900 1.140 25 1.117 0.021 0.003 0.000 

Hercules-Glades Wilderness 

2001 1.737 1.041 28 0.961 0.078 0.002 0.000 

2002 1.288 0.617 13 0.487 0.128 0.001 0.000 

2003 2.230 0.786 20 0.699 0.085 0.002 0.000 

Mingo National Wildlife Refuge 

2001 1.569 0.887 18 0.828 0.053 0.003 0.002 

2002 1.012 0.750 24 0.427 0.319 0.002 0.002 

2003 1.114 0.702 14 0.448 0.245 0.003 0.007 

Table 47. Baseline Visibility Impairment Attributable to White Bluff Unit 2 

Year Maximum 

(∆dv) 

98th

Percentile 

(∆dv) 

No. of 

Days with 

∆dv ≥ 0.5 

98th

Percentile 

%SO4

98th

Percentile 

%NO3

98th

Percentile 

%PM10

98th

Percentile 

%NO2

Caney Creek Wilderness 

2001 3.199 1.695 41 1.292 0.398 0.003 0.002 

2002 2.270 1.481 33 0.964 0.465 0.011 0.041 

2003 4.437 1.169 38 0.595 0.555 0.004 0.015 

Upper Buffalo Wilderness 

2001 2.385 1.185 35 0.840 0.343 0.003 0.000 

2002 1.618 0.846 20 0.685 0.156 0.003 0.003 

2003 1.998 1.176 25 0.958 0.215 0.003 0.000 

Hercules-Glades Wilderness 
75 

2001 1.838 1.060 30 0.966 0.092 0.002 0.000 

2002 1.340 0.643 14 0.490 0.151 0.001 0.001 

2003 2.263 0.806 21 0.703 0.101 0.002 0.000 

Mingo National Wildlife Refuge 

2001 1.701 0.903 18 0.834 0.063 0.003 0.003 

2002 1.031 0.805 25 0.674 0.129 0.002 0.000 

2003 1.150 0.750 14 0.452 0.288 0.003 0.008 

Table 48. Baseline Visibility Impairment Attributable to White Bluff Auxiliary Boiler 

Year Maximum 

(∆dv) 

98th

Percentile 

(∆dv) 

No. of 

Days with 

∆dv ≥ 0.5 

98th

Percentile 

%SO4

98th

Percentile 

%NO3

98th

Percentile 

%PM10

98th

Percentile 

%NO2

Caney Creek Wilderness 

2001 0.028 0.008 0 0.001 0.007 0.000 0.000 

2002 0.02 0.005 0 0.001 0.004 0.000 0.000 

2003 0.036 0.01 0 0.002 0.008 0.000 0.000 

Upper Buffalo Wilderness 

2001 0.014 0.004 0 0.001 0.003 0.000 0.000 

2002 0.009 0.004 0 0.003 0.000 0.000 0.000 

2003 0.013 0.005 0 0.001 0.004 0.000 0.000 

Hercules-Glades Wilderness 

2001 0.007 0.004 0 0.001 0.003 0.000 0.000 

2002 0.006 0.003 0 0.001 0.002 0.000 0.000 

2003 0.008 0.004 0 0.002 0.001 0.000 0.000 

Mingo National Wildlife Refuge 

2001 0.009 0.003 0 0.000 0.003 0.000 0.000 

2002 0.019 0.008 0 0.001 0.007 0.000 0.000 

2003 0.015 0.003 0 0.001 0.002 0.000 0.000 

b. SO2 BART Evaluation for Units 1 and 2 

 White Bluff Units 1 and 2 burn sub-bituminous coal as the primary fuel and No. 2 fuel oil 

or biofuel as a start-up fuel, while the Auxiliary boiler burns only No. 2 fuel oil or biodiesel. 

Sulfur oxides, or SOX, are generated during fuel combustion from the oxidation of sulfur 

contained in the fuel. SOX emissions are almost entirely dependent on the sulfur content of the 

fuel and are generally not affected by boiler size or burner design. SOX emissions from 

conventional combustion systems are predominantly in the form of SO2. The five factors 

considered in the SO2 BART analysis are discussed below. 

Step 1- Identify All Available Retrofit Control Technologies 
76 

 The SO2 control technologies considered in Entergy’s SO2 BART analysis are DSI, dry 

FGD, and wet FGD. 

Step 2- Eliminate Technically Infeasible Options

 All SO2 control technology options considered in the analysis were determined to be 

technically feasible options. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 

 DSI involves the injection of a sorbent into the exhaust stream where SO2 reacts with and 

becomes entrained in the sorbent. The stream is then passed through a particulate control device 

to remove the sorbet and entrained SO2. Entergy’s evaluation noted that depending on residence 

time, gas stream temperature, and limitations of the particulate control device, the control 

efficiency of dry sorbent injection can range between 40 – 60%.50 

 There are various designs of dry FGD systems, including SDA and CDS designs. Dry 

FGD control efficiencies range from 60 to 95%.51 Wet FGD is generally capable of achieving 

80-95% control, but can achieve up to 98% control efficiency.52 Entergy’s analysis noted that 

engineering evaluations conducted by Sargent & Lundy suggested that a control efficiency of up 

to 97% may be achievable at Units 1 and 2 through the application of wet FGD when burning 

higher-sulfur coals, but that Entergy was not able to obtain vendor guarantees for greater than 

95% control from wet FGD for the two units.53 Despite the lack of vendor assurances, Entergy 

evaluated wet FGD at an outlet SO2 emission rate of 0.04 lb/MMBtu. The remainder of 

Entergy’s analysis focused on the two control options with the highest control efficiency: wet 

FGD and dry FGD. 

Step 4- Evaluate Impacts and Document the Results 

                                                             50 “Assessment of Control Technology Options for BART-Eligible Sources: Steam Electric Boilers, Industrial Boilers, 

Cement Plants and Paper and Pulp Facilities” Northeast States for Coordinated Air Use Management (NESCAUM), 

March 2005. 

51 EPA Basic Concepts in Environmental Sciences, Module 6: Air Pollutants and Control Techniques 

htt://www.epa.gov/eogapti1/module6/sulfur/control/control.htm. 52 Id.

53 See “Revised BART Five Factor Analysis White Bluff Steam Electric Station Redfield, Arkansas (AFIN 35-

00110),” dated October 2013, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc., Page 

5-3. 
77 

 The four factors considered in this step of the analysis are the costs of compliance, energy 

and non-air quality environmental impacts of compliance, the existing pollution control 

technology in use at the source, and the remaining useful life of the source. 

Our Dry Scrubbing Cost Analysis for Entergy White Bluff: 

 Entergy’s estimates of the capital and direct operating and maintenance costs of a dry 

scrubber were based on vendor estimates. Estimates of the indirect operating costs were based on 

calculation methods from our Control Cost Manual. The estimates of the capital and operating 

and maintenance costs of wet FGD were based on vendor estimates obtained by Entergy for a 

system estimated to achieve 97% control and calculation methods from our Control Cost 

Manual. 

 We have reviewed the cost analysis that is part of Entergy’s evaluation and have 

analyzed it for compliance with the Regional Haze Rule, and disagree with several aspects of the 

cost analysis and have made adjustments to it as necessary.54 First, we found that Entergy 

assumed in its dry FGD cost analysis that it will burn a coal corresponding to an uncontrolled 

SO2 emission rate of 2.0 lb/MMBtu – far in excess of the sulfur level of the coals it has 

historically burned, presumably for future fuel flexibility. For the years 2009-2013, the 

maximum monthly SO2 emission rate for Unit 1 is 0.653 lbs/MMBtu and that for Unit 2 is 0.679 

lbs/MMBtu. Thus, Entergy has costed SO2 dry FGD systems for the White Bluff facility that are 

overdesigned compared to its historical needs. Such a system, being capable of a much higher 

level of sulfur removal than is currently required, has a correspondingly higher cost. Entergy 

selected its SO2 emission baseline by using “the average rate from 2001-2003, as reported by 

Entergy in their air emission inventories,”55 while selecting its annualized costs based on a 2.0 

lb/MMBtu coal. In calculating baseline emissions, the BART Guidelines assume the source in 

question is otherwise unchanged in the future, except for the addition of BART controls.56 Thus, 

we believe it is appropriate to adjust the cost analysis presented in Entergy’s report.57

Additionally, the cost estimate for dry FGD presented in Entergy’s report includes line items that 

have not been documented, appear to be already covered in other cost items, or do not appear to 

be valid costs under our Control Cost Manual methodology. This includes line items such as 

                                                            

54 See “Technical Support Document for the SDA Control Cost Analysis for the Entergy White Bluff and 

Independence Facilities Arkansas Regional Haze Federal Implementation Plan (SO2 Cost TSD).” A copy of this 

document is found in the docket for our proposed rulemaking. 

55 Revised Bart Five Factor Analysis, White Bluff Steam Electric Station, Redfield, Arkansas (AFIN 35-00110), 

dated October 2013, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc., Page 5-5. 

56 70 FR 39167. 

57 See “Technical Support Document for the SDA Control Cost Analysis for the Entergy White Bluff and 

Independence Facilities Arkansas Regional Haze Federal Implementation Plan (SO2 Cost TSD),” for a detailed 

discussion of how Entergy’s cost analysis was adjusted. 
78 

capital suspense,58 Entergy internal costs, and certain line items under balance of plant (BOP) 

costs. Please see our SO2 Cost TSD for more details concerning the adjustments we propose to 

make to the White Bluff dry FGD cost analysis. A summary of our adjusted cost analysis, which 

is based on 2013 dollars, is presented in the table below. 

Table 49. Summary of EPA Dry FGD Cost Analysis for White Bluff Units 1 and 2 

Item White Bluff Unit 1 White Bluff Unit 2

Total Annualized Cost $31,981,230 $31,981,230 

Interest Rate (%) 7 7 

Equipment Lifetime (years) 30 30 

Capital Recovery Factor (CRF) 0.0806 0.0806 

SO2 Emission Rate (lbs/MMBtu) 0.65 0.68 

Controlled SO2 Emission Rate (%) 90.81 91.16 

SO2 Emission Baseline (tons) 15,816 16,697 

SO2 Emission Reduction (tons) 14,363 15,221 

Cost Effectiveness ($/ton) $2,227 $2,101 

Our Wet Scrubbing Cost Analysis for Entergy White Bluff: 

Entergy uses a 2012 contractor wet FGD estimate for the White Bluff Units 1 and 2 as 

the starting point for its cost analysis.59 It then used multiplier approximations from our Control 

Cost Manual60 to calculate the Total Capital Investment (TCI). Entergy then calculated the direct 

annual costs, using fixed and variable O&M costs from another 2011 contractor cost summary as 

                                                            

58 Entergy states capital suspense “is a distribution of overhead costs associated with administrators, engineers, and 

supervisors and includes function specific rates and A&G (Corporate Accounting) rates. Function specific capital 

suspense is dependent upon the personal hours allocated to a specific project for a time period. However, the percent 

of a total project that is dedicated to capital suspense is not a constant. Rather, it is dependent upon the yearly total 

capital expense budget and the budgeted capital spending for a specific function.” See Entergy Response to EPA 

Region 6 comments on Entergy White Bluff draft BART Report 06/10/13, Page 9. A copy of this document is found 

in the docket for this proposed rulemaking. 

59 White Bluff Station Unit 1 & 2, Wet FGD - 2.0 lb/MMBtu, Order Of Magnitude Cost Estimate Summary. 

Attached as Attachment C to the 6/10/13 Entergy Response to EPA comments on the White Bluff draft BART 

Report. Pdf page 29. 

60 Section 5.2 Post-Combustion Controls, Chapter 1 – Wet Scrubbers for Acid Gas, Table 1.3. 
79 

a surrogate for the apparently unavailable direct annual costs from the 2012 estimate.61 

Following this, Entergy calculated the indirect annual costs using additional multiplier 

approximations from our Control Cost Manual.62 Lastly, Entergy calculated the annualized 

capital cost in the usual manner by multiplying the TCI by the capital recovery factor. 

As with its dry FGD cost estimates, Entergy designed its wet FGD systems to burn coal 

corresponding to an uncontrolled SO2 emission rate of 2.0 lb/MMBtu, which are overdesigned 

compared to its historical needs. Please see our SO2 Cost TSD for more details concerning the 

adjustments we propose to make to the White Bluff wet FGD cost analysis, which is similar to 

our dry FGD analysis. A summary of our adjusted cost analysis, which is based on 2013 dollars, 

is presented in the table below: 

Table 50. Summary of EPA Wet FGD Cost Analysis for White Bluff Units 1 and 2 

Item White Bluff Unit 1 White Bluff Unit 2

Total Annualized Cost $49,526,167 $49,526,167 

Interest Rate (%) 7 7 

Equipment Lifetime (years) 30 30 

Capital Recovery Factor (CRF) 0.0806 0.0806 

SO2 Emission Rate (lbs/MMBtu) 0.65 0.68 

Controlled SO2 Emission Rate (%) 93.87 94.11 

SO2 Emission Baseline (tons) 15,816 16,697 

SO2 Emission Reduction (tons) 14,847 15,713 

Cost Effectiveness ($/ton) $3,336 $3,152 

 

 Entergy’s evaluation noted that while wet FGD is expected to achieve a slightly higher 

level of control of SO2 emissions compared to dry FGD, the potential negative energy and nonair quality environmental impacts are greater with wet FGD systems. Entergy noted that wet 

FGD systems require increased water use and generate large volumes of wastewater and solid 

waste/sludge that must be treated or stabilized before landfilling, placing additional burden on 

the wastewater treatment and solid waste management capabilities. However, we do not expect 

                                                            

61 6/10/13 Entergy Response to EPA comments on the White Bluff draft BART Report. Pdf page 11. This 

information was supplemented with a cut sheet from the 2011 S&L report via email from David Triplett on 2-10-15. 

Entergy declined to provide the full report, citing confidentiality concerns. 

62 Section 5.2 Post-Combustion Controls, Chapter 1 – Wet Scrubbers for Acid Gas, Table 1.4.
80 

that water availability would affect the feasibility of wet FGD since the facility is not located in 

an exceptionally arid region. Additionally, the BART Guidelines provide that the fact that a 

control device creates liquid and solid waste that must be disposed of does not necessarily argue 

against selection of that technology as BART, particularly if the control device has been applied 

to similar facilities elsewhere (40 CFR Part 51, Appendix Y, section IV.D.4.i.2.). In cases where 

the facility can demonstrate that there are unusual circumstances there that would create greater 

problems than experienced elsewhere, this may provide a basis for the elimination of that control 

option as BART. But in this case, Entergy has not indicated that there are any such unusual 

circumstances. Entergy’s evaluation also pointed out that wet FGD systems have increased 

power requirements and greater reagent usage compared to dry FGD. The costs associated with 

increased power requirements and greater reagent usage have already been factored into the cost 

analysis for wet FGD. 

 Consideration of the presence of existing pollution control technology at the source is 

reflected in the BART analysis in two ways: first, in the consideration of available control 

technologies, and second, in the development of baseline emission rates for use in cost 

calculations and visibility modeling. White Bluff Units 1 and 2 currently do not operate any SO2

control equipment. 

With regard to consideration of the remaining useful life of the units, we are not aware of 

any enforceable shutdown date for the Entergy White Bluff Plant, nor did Entergy’s evaluation 

indicate any future planned shutdown. This means that the anticipated useful life of the boilers is 

expected to be at least as long as the capital cost recovery period of controls. Therefore, a 30-

year amortization period was assumed in the SO2 BART analysis as the remaining useful life of 

the units. 

Step 5- Evaluate Visibility Impacts 

 Entergy assessed the visibility improvement associated with wet FGD and dry FGD by 

modeling the SO2 emission rates associated with each control option using CALPUFF, and then 

comparing the visibility impairment associated with the baseline emission rates to the visibility 

impairment associated with the controlled emission rates as measured by the 98th percentile 

modeled visibility impact. Entergy calculated the modeled SO2 emission rates associated with 

wet FGD and dry FGD were calculated by multiplying the controlled emission level (i.e., 0.04 

lb/MMBtu for wet FGD and 0.06 lb/MMBtu for dry FGD) by the boiler heat input of 8,950 

MMBtu/hr. The NOX emission rate was modeled at the baseline rate for both the wet and dry 

FGD options. For all PM species other than ammonium sulfate, the NPS speciation spreadsheets 

were relied upon to determine emission rates for PM species. A portion of SO2 is further 

oxidized to SO3, which is then converted to sulfuric acid. Sulfuric acid can react with ammonia 

to form ammonium sulfate. The ammonium sulfate emission rates for semi-dry scrubbers were 

estimated by Entergy by assuming the reduction in ammonium sulfate (SO4) is proportional to 

the reduction in SO2 from the baseline to the controlled case (95%), while the ammonium sulfate 
81 

emission rates for wet FGD were estimated by Entergy by assuming 50% reduction in SO4 from 

the baseline case to the controlled case. This is because wet FGD systems generally have less 

affinity for SO3, typically capturing between 25-50% of the SO3. Therefore, the estimated 

ammonium sulfate emission rate for wet FGD is higher than for dry FGD. As discussed above, 

we recommend that sulfuric acid emissions from power plants be calculated by estimating the 

amount of H2SO4 produced and the amount of H2SO4 removed by control equipment using 

information from the Electric Power Research Institute (EPRI).63 However, in this specific 

situation, we do not anticipate that this difference in methodology would significantly impact the 

relative benefits of the SO2 controls examined or impact our BART determination since the 

overall impacts and benefits of control are large. We performed modeling for the sister facility, 

Independence, as described under the reasonable progress analysis section below. In this 

modeling, we utilized the EPRI method to estimate sulfuric acid emissions for the baseline and 

control scenarios. The results of the Independence modeling showed a very small incremental 

visibility benefit between dry FGD and wet FGD and considerable visibility benefit over the 

baseline for both control scenarios. 

 The tables below show the emission rates modeled and a comparison of the baseline (i.e., 

existing) visibility impacts and the visibility impacts of wet FGD and dry FGD, at each Class I 

area. The visibility improvement associated with each control scenario was calculated as the 

difference between the baseline visibility impairment and the visibility impairment for each 

control scenario as measured by the 98th percentile modeled visibility impact at each Class I area. 

Table 51. Summary of Emission Rates Modeled for SO2 Controls for White Bluff Units 1 

and 2

Source 

SO2

(lb/hr)

SO4

(lb/hr)

NOX

(lb/hr) 

PMC

(lb/hr) 

PMF

(lb/hr)

SOA 

(lb/hr) 

EC 

(lb/

hr) 

PM10, 

total 

(lb/hr)

Unit 1 - 

Semi-Dry Scrubbing 

537.0 

2.7 3,001.4 1.0 1.0 0.7 0.0 5.4

Unit 2 – 

Semi-Dry Scrubbing 537.0 2.8 3,527.4 1.0 1.0 0.7 0.0 5.6

Unit 1 – Wet Scrubbing 

358.0 18.4 3,001.4 6.7 6.5 4.6 0.2 36.4

Unit 2 – Wet Scrubbing 

358.0 18.4 3,527.4 6.7 6.5 4.6 0.2 36.4

                                                            

63 Electric Power Research Institute (EPRI) Estimating Total Sulfuric Acid Emissions from Stationary Power Plants: 

Version 2010a. EPRI, Palo Alto, CA: 2010 
82 

Table 52. Entergy White Bluff Unit 1: Summary of the 98th Percentile Visibility Impacts 

and Improvement Due to SO2 Controls 

Class I Area 

Visibility Impact 

(∆dv) 

Visibility Improvement 

Over Baseline 

(dv) Incremental Visibility 

Improvement of Wet 

FGD vs. Dry FGD 

(dv) Baseline Dry 

Scrubber Wet FGD Dry 

Scrubber Wet FGD 

Caney Creek 1.628 0.815 0.794 0.813 0.834 0.021 

Upper Buffalo 1.140 0.378 0.350 0.762 0.790 0.028 

Hercules-Glades 1.041 0.358 0.360 0.683 0.681 -0.002 

Mingo 0.887 0.267 0.271 0.620 0.616 -0.004 

Total 4.696 1.818 1.775 2.878 2.921 0.043 

Table 53. Entergy White Bluff Unit 2: Summary of the 98th Percentile Visibility Impacts 

and Improvement Due to SO2 Controls 

Class I Area 

Visibility Impact 

(∆dv) 

Visibility Improvement 

Over Baseline 

(dv) Incremental Visibility 

Improvement of Wet 

FGD vs. Dry FGD 

Baseline Dry 

Scrubber Wet FGD Dry 

Scrubber Wet FGD 

Caney Creek 1.695 0.941 0.920 0.754 0.775 0.021 

Upper Buffalo 1.185 0.418 0.405 0.767 0.780 0.013 

Hercules-Glades 1.061 0.415 0.416 0.645 0.644 -0.001 

Mingo 0.903 0.310 0.315 0.593 0.588 -0.005 

Total 4.844 2.084 2.056 2.759 2.787 0.028 
83 

 The tables above show that the installation and operation of SO2 controls at White Bluff 

Units 1 and 2 is expected to result in considerable visibility improvement at the four modeled 

Class I areas, measured as the difference between the 98th percentile visibility impairment 

associated with the baseline and the 98th percentile visibility impairment associated with each 

control option. The installation and operation of dry FGD is projected to result in visibility 

improvement of up to 0.813 dv at any single Class I area for Unit 1 and 0.767 dv for Unit 2. The 

installation and operation of wet FGD is projected to result in visibility improvement of up to 

0.834 dv at any single Class I area for Unit 1 and 0.780 dv for Unit 2. The installation and 

operation of wet FGD is projected to result in very minimal incremental visibility benefit over 

dry FGD at Caney Creek and Upper Buffalo, while at Hercules-Glades and Mingo, it is projected 

to result in slight visibility disbenefit. 

Our SO2 BART Determination for Units 1 and 2: 

Taking into consideration the five factors, we propose to determine that BART for White 

Bluff Units 1 and 2 is an emission limit of 0.06 lb/MMBtu on a 30 boiler-operating-day rolling 

average basis based on the installation and operation of dry FGD or another control technology 

that achieves that level of control. The operation of a dry FGD is projected to result in visibility 

improvement ranging from 0.620 to 0.813 dv at each affected Class I areas (98th percentile basis) 

for Unit 1 and ranging from 0.593 to 0.767 dv for Unit 2. Based on our adjustments to Entergy’s 

cost analysis, dry FGD is estimated to have an average cost-effectiveness of $2,227/ton of SO2

removed for Unit 1 and $2,101/ton of SO2 removed for Unit 2. Based on our adjustments to 

Entergy’s cost analysis, wet FGD is estimated to have an average cost-effectiveness of 

$3,336/ton of SO2 removed for Unit 1 and $3,152/ton of SO2 removed for Unit 2. Therefore, 

considering the five BART factors and the slight visibility benefit at Caney Creek and Upper 

Buffalo and slight disbenefit at Hercules-Glades and Mingo of wet FGD over dry FGD, we are 

proposing to determine that SO2 BART for White Bluff Units 1 and 2 is an emission limit of 

0.06 lb/MMBtu on a 30 boiler-operating-day rolling average based on the installation and 

operation of dry FGD or another control technology that achieves that level of control. We are 

proposing to require compliance with this requirement no later than 5 years from the effective 

date of the final rule, consistent with the regional haze regulations.64 Units 1 and 2 each have an 

existing CEMS, and we are proposing to require that compliance be demonstrated using the 

unit’s existing CEMS. We are proposing to require compliance with this requirement no later 

than five years from the effective date of the final rule, consistent with the CAA requirements.65

                                                            

64 40 CFR section 51.308(e)(1)(iv). 

65 Clean Air Act section 169A (g)(4), 42 U.S.C. 7491(g)(4). 
84 

c. NOX BART Evaluation for Units 1 and 2 

 Nitrogen oxides, or NOX, are produced during fuel combustion when nitrogen contained 

in both the fuel and the combustion air is exposed to high temperatures. Entergy’s evaluation 

noted that the formation of NOX compounds in utility boilers is sensitive to the method of firing. 

In tangentially-fired boilers, such as White Bluff Units 1 and 2, a single rotating flame is created 

in the center of the furnace, rather than the discrete flames produced by burners in the wall-fired 

boilers. Tangentially fired boilers typically have lower uncontrolled NOX emissions than wallfired boilers. Therefore, baseline NOX emission rates can vary significantly from plant to plant 

due to method of firing as well as several other factors. The baseline NOX emission rates for 

White Bluff Units 1 and 2 were discussed under section II.C.3.a. of this TSD. The five factors 

considered in the NOX BART analysis are discussed below. 

Step 1- Identify All Available Retrofit Control Technologies 

 The NOX control technologies considered in Entergy’s NOX BART report include both 

combustion and post-combustion controls. The combustion controls evaluated consisted of FGR, 

separated overfire air (SOFA), and LNB. The post-combustion controls evaluated consisted of 

SCR and SNCR. 

Step 2- Eliminate Technically Infeasible Options

 In its evaluation, Entergy noted that the amount of NOX reduction achievable with FGR 

depends primarily on the nitrogen content of the fuel and the amount of FGR used. FGR is more 

effective in controlling thermal NOX than fuel NOX, and therefore is generally more effective 

when used with low nitrogen content fuels such as natural gas and propane. Further, Entergy 

found that FGR technology is not currently offered by vendors for coal-fired units. Therefore, 

FGR is not considered to be a technically feasible control technology for the coal-fired White 

Bluff Units 1 and 2. All other available NOX control options were identified as technically 

feasible. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 Entergy evaluated three control scenarios: LNB/SOFA; the combination of LNB/SOFA 

+ SNCR; and the combination of LNB/SOFA + SCR. Entergy relied on literature control ranges 

and efficiencies and vendor estimates in arriving at the expected controlled emission rates for 

White Bluff Units 1 and 2. The baseline NOX emission rate Entergy assumed in the BART 

analysis is 0.31 lb/MMBtu for Unit 1 and 0.36 lb/MMBtu for Unit 2. 

 OFA diverts a portion of the total combustion air from the burners and injects it through 

separate air ports above the top level of burners. Staging of the combustion air creates an initial 
85 

fuel-rich combustion zone with a lower peak flame temperature, which reduces the formation of 

thermal NOX. SOFA refers to a system where the OFA is injected in a separate wind box 

mounted above the main wind box in order to achieve greater separation from the combustion 

zone. Entergy estimates SOFA would achieve a controlled NOX emission rate of 0.28 – 0.32 

lb/MMBtu for Units 1 and 2. LNB technology uses advanced burner design to reduce NOX

formation through the restriction of oxygen, which lowers flame temperature and/or reduces the 

residence time. When LNB is combined with SOFA, it is expected to achieve a controlled NOx 

emission rate of 0.15 lb/MMBtu for Units 1 and 2. When SNCR is combined with LNB/SOFA it 

is expected to achieve a controlled NOX emission rate of 0.13 lb/MMBtu, and when SCR is 

combined with LNB/SOFA it is expected to achieve a controlled NOX emission rate of 0.055 

lb/MMBtu for Units 1 and 2. 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

 Entergy estimated the capital costs, operating costs, and average cost-effectiveness of 

LNB, SOFA, SNCR, and SCR.66 The capital and operating costs of controls were based on 

vendor estimates specific to Units 1 and 2. The cost analysis assumed a 30-year amortization 

period. The total annual costs were estimated by annualizing the capital cost of controls over a 

30-year period and then adding to this value the annual operating cost of controls. 

 The annual emissions reductions associated with each NOX control option were 

determined by subtracting the estimated controlled annual emission rates from the baseline 

annual emission rate. The baseline annual emission rate is the average rate as reported by 

Entergy in the 2009-2011 air emission inventories, while the controlled annual emission rates are 

based on the lb/MMBtu levels believed to be achievable from the control technology multiplied 

by the baseline heat inputs to the boilers in MMBtu/yr. The average cost-effectiveness of NOX

controls was calculated by dividing the total annual cost of each control option by the estimated 

annual NOX emissions reductions. 

We note that Entergy’s cost estimate for each NOX control option includes capital 

suspense in the total capital costs.67 A capital cost suspense of $955,673 for both units for 

LNB/SOFA; $1,745,429 for both units for LNB/SOFA + SNCR; and $20,552,528 for Unit 1 and 

                                                            

66 See “Revised BART Five Factor Analysis White Bluff Steam Electric Station Redfield, Arkansas (AFIN 35-

00110),” dated October 2013, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc., 

Page Appendix A to the BART analysis contains Entergy’s NOX control cost calculations and Appendix E 

contains the “NOX Control Technology Cost and Performance Study” prepared by Sargent & Lundy on behalf of 

Entergy. A copy of Entergy’s BART analysis and its appendices is found in the docket for our proposed 

rulemaking. 

67 Id. 
86 

$21,332,288 for Unit 2 for LNB/SOFA + SCR is included in the capital costs. As discussed 

above, Entergy described capital suspense as a distribution of overhead costs associated with 

administrators, engineers, and supervisors that includes function specific rates and corporate 

accounting rates. However, we do not believe capital suspense should be included in the cost 

analysis because those costs have not been documented by Entergy and do not appear to be valid 

costs under the Control Cost Manual methodology. We have adjusted the cost estimate of NOX

controls by subtracting the capital suspense line item from the capital costs.68 Based on our 

adjustment to Entergy’s cost estimate, the average cost-effectiveness of LNB/SOFA is estimated 

to be $350/ton of NOX removed for Unit 1 and $340/ton of NOX removed for Unit 2, while the 

average cost-effectiveness of LNB/SOFA + SNCR is estimated to be $1,758/ton of NOX

removed for Unit 1 and $1,449/ton of NOX removed for Unit 2 (see table below). The average 

cost-effectiveness of LNB/SOFA + SCR is estimated to be $3,552/ton of NOX removed for Unit 

1 and $2,749/ton of NOX removed for Unit 2. 

Table 54. Summary of NOX Control Costs for Entergy White Bluff Units 1 and 2 

Control 

Technology 

Baseline 

Emission 

Rate 

(NOX tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Controlled 

Emission 

Rate 

(tpy) 

Annual 

Emissions 

Reduction 

(NOX tpy) 

Capital Cost 

($) 

Annual 

Fixed 

O&M 

($/yr) 

Annualized 

Variable 

O&M 

($/yr) 

Total 

Annual 

Cost 

($/yr) 

Average Cost 

Effectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

Unit 1 (SN-01) 

LNB/SOFA 7,249 0.15 4,145 3,104 9,505,533 142,000 177,887 1,085,904 350 - 

LNB/SOFA/

SNCR 

7,249 0.13 3,593 3,657 19,625,896 311,000 4,538,000 6,430,580 1,758 9,665 

LNB/SOFA/

SCR 7,249 0.055 1,520 5,729 209,776,610 608,000 2,836,000 20,349,142 3,552 6,717 

Unit 2 (SN-02) 

LNB/SOFA 8,185 0.15 4,060 4,125 13,532,533 142,000 170,838 1,403,376 340 - 

LNB/SOFA/

SNCR 

8,185 0.13 3,519 4,666 23,652,896 311,000 4,542,000 6,759,102 1,449 9,900 

LNB/SOFA/

SCR 8,185 0.055 1,489 6,697 185,415,610 608,000 2,858,000 20,127,070 2,749 5,736 

 Entergy did not identify any energy or non-air quality environmental impacts associated 

with the use of LNB/SOFA. As for SCR and SNCR, we are not aware of any unusual 

circumstances at the facility that could create energy or non-air quality environmental impacts 

                                                            

68 See the spreadsheet titled “EPA NOX Control Cost revisions_White Bluff.” A copy of this spreadsheet is found in 

the docket for our proposed rulemaking. 
87 

associated with the operation of these controls greater than experienced elsewhere and that may 

therefore provide a basis for their elimination as BART (40 CFR Part 51, Appendix Y, section 

IV.D.4.i.2.). Therefore, we do not believe there are any energy or non-air quality environmental 

impacts associated with the operation of NOX controls at Entergy White Bluff Units 1 and 2 that 

would affect our proposed BART determination. 

 Consideration of the presence of existing pollution control technology at each unit is 

reflected in the BART analysis in two ways: first, in the consideration of available control 

technologies, and second, in the development of baseline emission rates for use in cost 

calculations and visibility modeling. Other than the installation of a neural net system in 2006 to 

optimize boiler combustion efficiency, which had the co-benefit of decreasing NOX emissions 

compared to the 2001-2003 baseline, White Bluff Units 1 and 2 have no existing NOX pollution 

control technology. The lower NOX emissions achieved as a co-benefit of installing the neural 

net system is reflected in the analysis by the use of 2009-2011 as the baseline for the NOX BART 

analysis. 

 With regard to consideration of the remaining useful life of the units, we are not aware of 

any enforceable shutdown date for White Bluff Units 1 and 2, nor did Entergy’s evaluation 

indicate any future planned shutdown. This means that the anticipated useful life of the boilers is 

expected to be at least as long as the capital cost recovery period of controls. Therefore, a 30-

year amortization period was appropriately assumed in the evaluation of NOX controls as the 

remaining life of Units 1 and 2. 

Step 5- Evaluate Visibility Impacts 

Entergy assessed the visibility improvement associated with NOX controls by modeling 

the NOX emission rates associated with each control option using CALPUFF, and then 

comparing the visibility impairment associated with the baseline emission rate to the visibility 

impairment associated with the controlled emission rates as measured by the 98th percentile 

modeled visibility impact. The controlled emission level associated with LNB/SOFA is 0.15 

lb/MMBtu; the controlled emission level associated with LNB/SOFA + SNCR is 0.13 

lb/MMBtu; and the controlled emission level associated with LNB/SOFA + SCR is 0.055 

lb/MMBtu for each unit. These levels were multiplied by each unit’s maximum heat input to 

derive the hourly emission rates used in the modeling. The tables below show the emission rates 

modeled and a comparison of the existing (i.e., baseline) visibility impacts and the visibility 

impacts based on NOX controls, based on the 98th percentile modeled visibility impacts for each 

Class I area. 
88 

Table 55. Summary of Emission Rates Modeled for NOX Controls for Entergy White 

Bluff Units 1 and 2

SO2

(lb/hr)

SO4

(lb/hr)

NOX

(lb/hr)

PMC

(lb/hr)

PMF

(lb/hr)

SOA

(lb/hr)

EC

(lb/hr)

PM10, 

total

(lb/hr)

Unit 1 – LNB/SOFA 7,763.5 36.8 1342.5 40.4 31.1 9.2 1.2 118.6 

Unit 2 – LNB/SOFA 7,825.1 36.8 1342.5 40.4 31.1 9.2 1.2 118.6 

Unit 1 - LNB/SOFA + 

SNCR 7,763.5 36.8 1163.5 40.4 31.1 9.2 1.2 118.6 

Unit 2 - LNB/SOFA + 

SNCR 7,825.1 36.8 1163.5 40.4 31.1 9.2 1.2 118.6 

Unit 1 – LNB/SOFA + 

SCR 7,763.5 36.8 492.3 40.4 31.1 9.2 1.2 118.6 

Unit 2 - LNB/SOFA + 

SCR 7,825.1 36.8 492.3 40.4 31.1 9.2 1.2 118.6 

Table 56. Entergy White Bluff Unit 1: Summary of the 98th Percentile Visibility Impacts 

and Improvement due to NOX Controls 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

LNB/SOFA LNB/SOFA + SNCR LNB/SOFA + SCR 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

LNB/SOFA 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

LNB/SOFA + 

SNCR 

(∆dv) 

Caney Creek 1.628 1.462 0.166 1.428 0.2 0.034 1.359 0.269 0.069 

Upper Buffalo 1.140 1.039 0.101 1.029 0.111 0.01 0.991 0.149 0.038 

HerculesGlades 1.041 0.865 0.176 0.844 0.197 0.021 0.832 0.209 0.012 

Mingo 0.887 0.849 0.038 0.842 0.045 0.007 0.817 0.07 0.025 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.481 -- 0.553 -- -- 0.697 - 
89 

Table 57. Entergy White Bluff Unit 2: Summary of the 98th Percentile Visibility Impacts 

and Improvement due to NOX Controls 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

LNB/SOFA LNB/SOFA + SNCR LNB/SOFA + SCR 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

LNB/SOFA 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

LNB/SOFA + 

SNCR 

(∆dv) 

Caney Creek 1.695 1.47 0.225 1.437 0.258 0.033 1.368 0.327 0.069 

Upper Buffalo 1.185 1.046 0.139 1.035 0.15 0.011 0.997 0.188 0.038 

HerculesGlades 1.060 0.870 0.190 0.849 0.211 0.021 0.838 0.222 0.011 

Mingo 0.903 0.856 0.047 0.849 0.054 0.007 0.823 0.08 0.026 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.601 -- 0.673 -- -- 0.817 - 

The tables above show that the installation and operation of LNB/SOFA is projected to 

result in visibility improvement of up to 0.176 dv at any single Class I area for Unit 1 and 0.225 

dv for Unit 2, based on the 98th percentile visibility impairment. The installation and operation of 

LNB/SOFA + SNCR is projected to result in visibility improvement of up to 0.2 dv in any single 

Class I area for Unit 1 and 0.258 dv for Unit 2. The installation and operation of LNB/SOFA + 

SCR is projected to result in visibility improvement of up to 0.269 dv in any single Class I area 

for Unit 1 and 0.327 dv for Unit 2. The combination of LNB/SOFA + SNCR would result in 

minimal incremental visibility benefit over LNB/SOFA at all affected Class I areas for both 

units. The combination of LNB/SOFA + SCR at Unit 1 would result in incremental visibility 

benefit over LNB/SOFA + SNCR of 0.069 dv at Caney Creek; 0.038 dv at Upper Buffalo; 0.012 

dv at Hercules-Glades; and 0.025 dv at Mingo. The combination of LNB/SOFA + SCR at Unit 2 

would result in incremental visibility benefit over LNB/SOFA + SNCR of 0.069 dv of at Caney 

Creek; 0.038 dv at Upper Buffalo; 0.011 dv at Hercules-Glades; and 0.026 dv at Mingo. 
90 

Our NOX BART determination for Units 1 and 2: 

Taking into consideration the five factors, we propose to determine that BART for White 

Bluff Units 1 and 2 is an emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling 

average based on the installation and operation of LNB/SOFA. The operation of LNB/SOFA is 

projected to result in visibility improvement ranging from 0.038 to 0.176 dv for Unit 1 and 0.047 

to 0.225 dv for Unit 2 at each of the affected Class I areas (98th percentile basis). Based on our 

adjustments to the cost analysis included in Entergy’s evaluation, the operation of LNB/SOFA is 

estimated to have an average cost-effectiveness of $350/ton of NOX removed for Unit 1 and 

$340/ton of NOX removed for Unit 2, which we consider to be very cost-effective. The operation 

of LNB/SOFA + SNCR is estimated to have an average cost-effectiveness of $1,758/ton of NOX

removed for Unit 1 and $1,449/ton of NOX removed for Unit 2. The incremental costeffectiveness of LNB/SOFA + SNCR compared to LNB/SOFA is $9,665/ton of NOX removed 

for Unit 1 and $9,900/ton of NOX removed for Unit 2.While the average cost-effectiveness of 

LNB/SOFA + SNCR is still very cost effective, the incremental visibility benefit of LNB/SOFA 

+ SNCR compared to LNB/SOFA is estimated to range from 0.007 to 0.034 dv for Unit 1 and 

0.007 to 0.033 dv for Unit 2 at each of the affected Class I areas. We do not believe this small 

amount of incremental visibility benefit justifies the incremental cost of LNB/SOFA + SNCR. 

 The operation of LNB/SOFA + SCR at Unit 1 is projected to result in up to 0.269 dv 

visibility improvement over the baseline at any single Class I area, and based on our adjustments 

to Entergy’s cost analysis, has an average cost-effectiveness of $3,552/ton of NOX removed. 

LNB/SOFA + SCR at Unit 1 is projected to result in up to 0.069 dv of incremental visibility 

improvement over LNB/SOFA + SNCR at any single Class I area, and its incremental costeffectiveness is estimated to be $6,717/ton of NOX removed. The operation of LNB/SOFA + 

SCR at Unit 2 is projected to result in up to 0.327 dv visibility improvement over the baseline at 

any single Class I area, and has an average cost-effectiveness of $2,749/ton of NOX removed. 

LNB/SOFA + SCR at Unit 2 is also projected to result in up to 0.069 dv of incremental visibility 

improvement over LNB/SOFA + SNCR at any single Class I area, and its incremental costeffectiveness is estimated to be $5,736/ton of NOX removed. Although the average and 

incremental cost-effectiveness of LNB/SOFA + SCR at Units 1 and 2 is still within the range of 

what we consider to be cost-effective, we believe the incremental visibility benefit over 

LNB/SOFA + SNCR of up to 0.069 dv at a single Class I area is relatively small considering the 

incremental cost-effectiveness of $6,717/ton of NOX removed for Unit 1 and $5,736/ton of NOX

removed for Unit 2. Therefore, we are proposing to determine that NOX BART for White Bluff 

Units 1 and 2 is an emission limit of 0.15 lb/MMBtu on a 30 boiler-operating-day rolling average 

based on the installation and operation of LNB/SOFA. We are proposing to require compliance 

with this requirement no later than 3 years from the effective date of the final rule, consistent 

with our regional haze regulations.69 We are proposing to require that compliance be 

demonstrated using the unit’s existing CEMS. 

                                                            

69 40 CFR section 51.308(e)(1)(iv). 
91 

d. BART Evaluation for Auxiliary Boiler 

 

 As shown in the table above, the baseline visibility impairment attributable to the 

Auxiliary Boiler is 0.01 dv at Caney Creek and even lower at the other modeled Class I areas 

(98th percentile basis). The BART Rule provides that “Consistent with the CAA and the 

implementing regulations, States can adopt a more streamlined approach to making BART 

determinations where appropriate. Although BART determinations are based on the totality of 

circumstances in a given situation, such as the distance of the source from a Class I area, the type 

and amount of pollutant at issue, and the availability and cost of controls, it is clear that in some 

situations, one or more factors will clearly suggest an outcome. Thus, for example, a State need 

not undertake an exhaustive analysis of a source’s impact on visibility resulting from relatively 

minor emissions of a pollutant where it is clear that controls would be costly and any 

improvements in visibility resulting from reductions in emissions of that pollutant would be 

negligible.” (70 FR 39116). 

 Given the very small baseline visibility impacts from the Auxiliary Boiler, we believe it 

is appropriate to take a streamlined approach for determining BART in this case. Because of the 

very low baseline visibility impacts from the Auxiliary Boiler at each modeled Class I area, we 

believe that the visibility improvement that could be achieved through the installation and 

operation of controls would be negligible, such that the cost of those controls could not be 

justified. Therefore, we are proposing that the existing emission limits satisfy BART for SO2, 

NOX, and PM. We are proposing that the existing emission limit of 105.2 lb/hr is BART for SO2, 

the existing emission limit of 32.2 lb/hr is BART for NOX, and the existing emission limit of 4.5 

lb/hr is BART for PM for the Auxiliary Boiler.70 Because we are proposing a BART emission 

limit that represents current operations and no control equipment installation is necessary, we are 

proposing that these emissions limitations be complied with for BART purposes from the date of 

effectiveness of the finalized action. 

 

5. Entergy Lake Catherine Plant 

 Entergy Lake Catherine Unit 4 is subject to BART. In our March 12, 2012 final action we 

disapproved the State’s BART determinations for NOX for the natural gas firing scenario and for 

SO2, NOX, and PM for the fuel oil firing scenario (77 FR 14604). Entergy hired a consultant to 

conduct a BART five-factor analysis for Lake Catherine Unit 4 (Entergy’s BART analysis).71 

                                                            

70 See ADEQ Operating Air Permit No. 0263-AOP-R7, Section IV, Specific Condition No. 32. 71 See “Revised BART Five Factor Analysis Lake Catherine Steam Electric Station Malvern, Arkansas (AFIN 30-

00011),” dated May 2014, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc. A copy 

of this BART analysis is found in the docket for our proposed rulemaking. 
92 

Lake Catherine Unit 4 is a tangentially-fired boiler with a nominal net power rating of 

558 MW and a nominal heat input capacity of 5,850 MMBtu/hr. The boiler is permitted to burn 

natural gas and No. 6 fuel oil. Entergy’s analysis states that Lake Catherine Unit 4 has not 

burned fuel oil since prior to the 2001-2003 baseline period, currently does not burn fuel oil, and 

that Entergy does not project to burn fuel oil at the unit in the foreseeable future. Therefore, 

Entergy’s analysis72 addresses BART for the natural gas firing scenario and does not consider 

emissions from fuel oil firing. Entergy’s analysis states that if conditions change such that it 

becomes economic to burn fuel oil, the facility will submit a BART five factor analysis for the 

fuel oil firing scenario to the State to be submitted to us as a SIP revision, and that fuel oil 

combustion will not take place until final EPA approval of BART for the fuel oil firing scenario. 

We concur with this commitment.73 Before fuel oil firing is allowed to take place at Lake 

Catherine Unit 4, revised BART determinations must be promulgated for all pollutants for the 

fuel oil firing scenario through a FIP and/or through our action upon and approval of revised 

BART determinations submitted by the State as a SIP revision. 

 We approved the State’s BART determinations for Lake Catherine Unit 4 for SO2 and 

PM for the natural gas firing scenario in our March 12, 2012 final action (77 FR 14604). 

Therefore, the only BART determination that remains to be addressed for the natural gas firing 

scenario is NOX BART. Our analysis presented below focuses on NOX BART for the natural gas 

firing scenario. 

a. Baseline Emission Rates and Existing Visibility Impairment Attributable to Lake 

Catherine Unit 4

 Entergy estimated SO2, NOX, and PM10 baseline emission rates and then modeled these 

emission rates to determine the existing visibility impairment attributable to Lake Catherine Unit 

4 based on the default natural conditions. The baseline emission rates are based on a combination 

of stack testing, CEMS data as reported to EPA’s CAMD, and AP-42 emission factors. The 

baseline emission rates are shown in the table below. 

                                                            

72 See “Revised BART Five Factor Analysis Lake Catherine Steam Electric Station Malvern, Arkansas (AFIN 30-

00011),” dated May 2014, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc. A copy 

of this BART analysis is found in the docket for our proposed rulemaking. 

73 As explained in the regulatory text in the proposed rulemaking associated with this TSD, if Lake Catherine Unit 4 

decides to begin burning fuel oil, we will complete a BART analysis for each pollutant for the fuel oil firing 

scenario after receiving notification that the source will begin burning fuel oil and we will revise the FIP as 

necessary in accordance with Regional Haze Rule requirements, including the BART provisions in 40 CFR 

51.308(e). Alternatively, if the State submits a SIP revision with BART determinations for the fuel oil firing 

scenario, we will take action on the State’s submittal. 
93 

Table 58. Baseline Maximum 24-Hour SO2, NOX, and PM10 Emission Rates 

Source SO2

(lb/hr) 

NOX

(lb/hr) 

Total 

PM10

(lb/hr) 

SO4

(lb/hr) 

PMc 

(lb/hr) 

PMf 

(lb/hr) 

SOA 

(lb/hr) 

EC 

(lb/hr) 

Unit 4 3.1 2,456.4 44.3 1.5 0.0 0.0 31.8 11.0 

 The SO2 and NOX baseline emission rates are the highest actual 24-hour emission rates 

based on 2001-2003 CEMS data from natural gas burning. The PM10 emission rate reflects the 

breakdown of the filterable and condensable PM10 determined from AP-42 Table 1.4-2 

Combustion of Natural Gas. Entergy then modeled the baseline emission rates using the 

CALPUFF dispersion model to determine the baseline visibility impairment attributable to Lake 

Catherine Unit 4 at the Caney Creek Wilderness Area, Upper Buffalo Wilderness Area, 

Hercules-Glades Wilderness Area, and Mingo National Wildlife Refuge. The existing visibility 

impairment attributable to Lake Catherine Unit 4 at each Class I area is summarized in the table 

below. 

Table 59. Baseline Visibility Impairment Attributable to Entergy Lake Catherine Unit 4 

Year Maximum 

(∆dv) 

98th

Percentile 

(∆dv) 

No. of 

Days with 

∆dv ≥ 0.5 

98th

Percentile 

%SO4

98th

Percentile 

%NO3

98th

Percentile 

%PM10

98th

Percentile 

%NO2

Caney Creek Wilderness 

2001 3.480 1.371 31 0.49 85.13 0.00 8.55 

2002 3.318 0.909 21 0.31 92.53 0.00 4.18 

2003 3.276 1.233 28 0.43 85.66 0.00 7.76 

Upper Buffalo Wilderness 

2001 1.478 0.489 7 0.33 89.54 0.00 5.99 

2002 0.916 0.532 9 0.22 96.29 0.00 1.26 

2003 2.044 0.412 5 0.21 97.39 0.00 0.30 

Hercules-Glades Wilderness 

2001 0.760 0.387 4 0.30 91.12 0.00 4.92 

2002 1.016 0.313 2 0.39 88.73 0.00 6.08 

2003 0.881 0.311 2 0.38 93.27 0.00 2.57 

Mingo National Wildlife Refuge 

2001 0.511 0.237 1 0.30 92.55 0.00 3.17 

2002 0.763 0.429 5 0.32 96.25 0.00 0.44 

2003 0.516 0.214 1 0.18 98.08 0.00 0.10 
94 

b. NOX BART Evaluation (Natural Gas Firing) 

 Nitrogen oxides, or NOX, are produced during fuel combustion when nitrogen contained 

in both the fuel and the combustion air is exposed to high temperatures. Entergy’s evaluation 

noted that the formation of NOX compounds in utility boilers is sensitive to the method of firing. 

In tangentially-fired boilers, such as Lake Catherine Unit 4, a single rotating flame is created in 

the center of the furnace, rather than the discrete flames produced by burners in the wall-fired 

boilers. Tangentially fired boilers typically have lower uncontrolled NOX emissions than wallfired boilers. Baseline NOX emission rates can vary significantly from plant to plant due to 

method of firing as well as several other factors. The baseline NOX emission rates for Lake 

Catherine Unit 4 were discussed under section II.C.4.a. of this TSD. The five factors considered 

in the NOX BART analysis are discussed below. 

Step 1- Identify All Available Retrofit Control Technologies 

 

 The NOX control technologies considered in Entergy’s NOX BART analysis include both 

combustion and post-combustion controls. The combustion controls evaluated by consisted of 

Burners out of Service (BOOS), FGR, SOFA, and LNB. The post-combustion controls evaluated 

consisted of SCR and SNCR. 

Step 2- Eliminate Technically Infeasible Options

 Entergy’s evaluation stated that SNCR combined with LNB/SOFA was being evaluated 

as a control option for Lake Catherine Unit 4, but SNCR is not adaptable to all gas-fired boilers. 

All other NOX control options evaluated were identified as technically feasible. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 Entergy relied on literature control ranges and efficiencies and vendor estimates in 

arriving at the expected controlled emission rates for Lake Catherine Unit 4. The baseline NOX

emission rate Entergy used in the analysis is 0.48 lb/MMBtu. 

 BOOS is a staged combustion technique in which fuel is introduced through operational 

burners in the lower furnace zone to create fuel-rich conditions, while not introducing fuel to 

other burners. The removal of fuel from certain zones reduces the temperature and the 

production of thermal NOX. Additional air is then supplied to the non-operational burners to 

complete combustion. Based on a NOX control study developed by Sargent & Lundy on behalf 

of Entergy (Sargent & Lundy NOX Control Study), the estimated controlled NOX level for Unit 4 
95 

while operating BOOS at maximum load is 0.24 lb/MMBtu.74 Based on the level of control 

expected to be achieved by BOOS and the expected utilization levels at Unit 4, Entergy believes 

that an emission rate of 0.22 lb/MMBtu is achievable on a 30 boiler-operating-day rolling 

average basis. 

 FGR uses flue gas as an inert material to reduce the oxygen level in the combustion zone 

and thereby reduce flame temperatures and thermal NOX formation. Entergy estimated the 

controlled NOX level for Unit 4 operating with FGR to be 0.19 lb/MMBtu. SOFA refers to a 

system where the overfire air is injected in a separate wind box mounted above the main wind 

box in order to achieve greater separation from the combustion zone. Entergy estimated that 

when operated without additional controls, SOFA results in NOX emissions for gas fired boilers 

of 0.2 – 0.4 lb/MMBtu. LNB technology uses advanced burner design to reduce NOX formation 

through the restriction of oxygen, which lowers flame temperature and/or reduces the residence 

time. When operated without additional controls, Entergy estimated the controlled NOX emission 

rate for gas fired boilers operating with LNB is approximately 0.25 lb/MMBtu, and when 

combined with SOFA, the estimated controlled NOX emission rate is 0.19 lb/MMBtu. When 

SNCR is combined with LNB/SOFA, Entergy estimated that the controlled NOX emission rate is 

0.14 lb/MMBtu, and when SCR is combined with LNB/OFA it is estimated that the controlled 

NOX emission rate is 0.03 lb/MMBtu. 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

 Entergy’s evaluation noted that the Sargent & Lundy NOX Control Study estimated that 

FGR would result in the same controlled emission level as LNB/SOFA, but at a higher cost.75

Therefore, Entergy’s evaluation did not further consider FGR. Entergy estimated the capital 

costs, operating costs, and cost effectiveness of BOOS, LNB/SOFA, LNB/SOFA/SNCR, and 

LNB/SOFA/SCR.76 Entergy estimated the capital costs, operating costs, and cost-effectiveness 

of these four control scenarios based on cost estimates provided by Sargent & Lundy. The cost 

analysis assumed a 30-year amortization period. The capital cost of each NOX control option was 

                                                            

74 See “NOX Control Technology Cost and Performance Study,” Final Report, Rev. 4, dated May 16, 2013, prepared 

by Sargent & Lundy. A copy of this report is included as Appendix D to Entergy’s BART Five Factor Analysis 

for Lake Catherine Unit 4, which can be found in the docket for this proposed rulemaking. 

75 Id.

76 See “Revised BART Five Factor Analysis Lake Catherine Steam Electric Station Malvern, Arkansas (AFIN 30-

00011),” dated May 2014, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc. 

Appendix A to Entergy’s BART analysis contains the capital and operating cost estimates for each control option 

evaluated. A copy of this BART analysis and its appendices is found in the docket for our proposed rulemaking. 
96 

annualized over a 30-year period and then added to the annual operating costs to obtain the total 

annualized costs.77 

 The annual emissions reductions associated with each NOX control option were 

determined by subtracting the estimated controlled annual emission rate from the baseline annual 

emission rate. The baseline annual emission rate was calculated using the baseline emission level 

of 0.48 lb/MMBtu and an annual heat input reflecting a 10% capacity factor.78 The annual tons 

reduced associated with each NOX control option were determined by subtracting the estimated 

controlled annual emission rate from the baseline annual emission rate. The baseline annual 

emission rate was calculated using the baseline emission level of 0.48 lb/MMBtu and an annual 

heat input reflecting a 10% capacity factor.79 Entergy’s evaluation assumed a 10% capacity 

factor because the annual capacity factor of the unit during each of the years from 2003-2011 

was under 10%, and Entergy anticipates that future annual capacity factors are expected to be 

comparable to those experienced by the unit in 2003-2011. We agree that assuming a 10% 

capacity factor is consistent with the BART Guidelines, which provide that the baseline emission 

rate should represent a realistic depiction of anticipated annual emissions for the source.80 

 The controlled annual emission rates were based on the lb/MMBtu levels believed to be 

achievable from the control technologies multiplied by the annual heat input. Entergy calculated 

the average cost-effectiveness of NOX controls by dividing the total annual cost of each control 

option by the estimated annual NOX emissions reductions. The incremental cost-effectiveness of 

each control option was also calculated. 

 We disagree with two aspects of Entergy’s cost analysis.81 First, Entergy’s cost estimates 

for LNB/SOFA, LNB/SOFA + SNCR, and LNB/SOFA + SCR include capital suspense as a line 

item under the capital costs. However, we do not believe capital suspense should be included in 

the cost analysis because those costs have not been documented by Entergy and do not appear to 

be valid costs under the Control Cost Manual methodology. Second, Entergy’s cost estimates for 

these controls also include Allowance for Funds Used During Construction (AFUDC). AFUDC 

is the cost of capital that is incurred to finance a project during the construction period, and is not 

a valid cost under the methodology in the EPA Control Cost Manual. The exclusion of capital 

                                                            

77 Based on Entergy’s evaluation, it is anticipated that BOOS can be implemented at Unit 4 without any capital 

expenditures, but there are one-time costs associated with BOOS implementation. To provide an “apples-toapples” comparison with the other NOX control options, these one-time additional costs were treated as if they 

were a capital expenditure in calculating the cost effectiveness. 78 The annual heat input reflecting a 10% annual capacity factor is 5,124,600 MMBtu/yr (5,850 MMBtu/hr * 8760 

hrs/yr * 10% = 5,124,600 MMBtu/yr).   79 The annual heat input reflecting a 10% annual capacity factor is 5,124,600 MMBtu/yr (5,850 MMBtu/hr * 8760 

hrs/yr * 10% = 5,124,600 MMBtu/yr).   80 40 CFR Appendix Y to Part 51- Guidelines for BART Determinations Under the Regional Haze Rule, section 

IV.D.4.d. 

81 See “Revised BART Five Factor Analysis Lake Catherine Steam Electric Station Malvern, Arkansas (AFIN 30-

00011),” dated May 2014, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc. 

Entergy’s NOX control cost estimates are found in Appendices A and D of the BART analysis. A copy of the 

BART analysis, including the appendices, is found in the docket for our proposed rulemaking. 
97 

suspense and AFUDC from the capital cost estimates results in lower total annual costs and 

improved average cost-effectiveness (i.e., less dollars per NOX ton removed) for the 

aforementioned NOX control options compared to what is estimated in Entergy’s evaluation. In 

the table below, we have revised the capital costs and cost-effectiveness of NOX controls for Unit 

4 to reflect our adjustments to Entergy’s cost estimates.82 Based on our adjustments to Entergy’s 

cost analysis, the average cost-effectiveness of BOOS at a NOX controlled emission rate of 0.22 

lb/MMBtu is estimated to be $138/ton of NOX removed, while the average cost-effectiveness of 

LNB/SOFA is estimated to be $1,450/ton of NOX removed. The average cost-effectiveness of a 

combination of LNB/SOFA + SNCR is estimated to be $3,523/ton of NOX removed, while the 

average cost-effectiveness of the combination of LNB/SOFA + SCR is estimated to be 

$5,614/ton of NOX removed. 

Table 60. Summary of NOX Control Costs for Lake Catherine Unit 4 

(Natural Gas Firing) 

Baseline 

Emission 

Rate 

(NOX tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Controlled 

Emission 

Rate 

(NOX tpy) 

Annual 

Emissions 

Reduction 

(NOX tpy) 

Capital 

Cost 

($) 

Total 

Annual 

Cost 

($/yr) 

Average 

Cost 

Effectiveness 

($/ton) 

Incremental 

Cost 

effectiveness 

($/ton) 

BOOS 1,236 0.22 564 673 893,000 92,964 138 - 

LNB/SOFA 1,236 0.19 495 742 10,508,863 1,075,905 1,450 14,246 

LNB/SOFA/SNCR 1,236 0.14 371 865 26,015,863 3,047,525 3,523 16,029 

LNB/SOFA/SCR 1,236 0.03 77 1159 70,370,863 6,506,935 5,614 11,767 

 Entergy did not identify any energy or non-air quality environmental impacts 

associated with the use of BOOS, LNB, or SOFA. As for SCR and SNCR, we are not aware of 

any unusual circumstances at the facility that could create energy or non-air quality 

environmental impacts associated with the operation of these controls greater than experienced 

elsewhere and that may therefore provide a basis for their elimination as BART (40 CFR Part 51, 

Appendix Y, section IV.D.4.i.2.). Therefore, we do not believe there are any energy or non-air 

quality environmental impacts associated with the operation of NOX controls at Entergy Lake 

Catherine Unit 4 that would affect our proposed BART determination. 

 The presence of existing pollution control technology at the source is reflected in the 

BART analysis in two ways: first, in the consideration of available control technologies, and 

second, in the development of baseline emission rates for use in cost calculations and visibility 

modeling. Lake Catherine Unit 4 is not currently equipped with any NOX pollution control 

                                                            

82 See the spreadsheet titled “EPA NOX Control Cost revisions_Lake Catherine.xlsx.” A copy of this spreadsheet is 

found in the docket for our proposed rulemaking. 
98 

equipment. The baseline emission rates used in the cost calculations and visibility modeling 

reflects this. 

 With regard to consideration of the remaining useful life of the unit, we are not aware of 

any enforceable shutdown date for Lake Catherine Unit 4, nor did Entergy’s evaluation indicate 

any future planned shutdown. This means that the anticipated useful life of the boiler is expected 

to be at least as long as the capital cost recovery period of controls. Therefore, a 30-year 

amortization period was assumed in the evaluation of NOX controls as the remaining life of Unit 

4. 

Step 5- Evaluate Visibility Impacts 

Entergy assessed the visibility improvement associated with NOX controls by modeling 

the NOX emission rates associated with each control option using CALPUFF, and then 

comparing the visibility impairment associated with the baseline emission rate to the visibility 

impairment associated with the controlled emission rates. The controlled emission level 

associated with BOOS is 0.22 lb/MMBtu; the controlled emission level associated with 

LNB/SOFA is 0.19 lb/MMBtu; the controlled emission level associated with LNB/SOFA + 

SNCR is 0.14 lb/MMBtu; and the controlled emission level associated with LNB/SOFA + SCR 

is 0.03 lb/MMBtu. These levels were multiplied by the maximum heat input (i.e., 5,850 

MMBtu/hr) to derive the hourly emission rates used in the modeling. The tables below show the 

modeled emission rates and a comparison of the existing (i.e., baseline) visibility impacts and the 

visibility impacts based on NOX controls, based on the 98th percentile modeled visibility impact 

for each Class I area. 

Table 61. Summary of Emission Rates Modeled for NOX Controls for Entergy Lake 

Catherine Unit 4

Control SO2

(lb/hr)

SO4

(lb/hr)

NOX

(lb/hr)

PMC

(lb/hr)

PMF

(lb/hr)

SOA

(lb/hr)

EC

(lb/hr)

PM10, 

total

(lb/hr)

BOOS 3.1 1.5 1287.0 0.0 0.0 31.8 11.0 44.3 

LNB/SOFA 3.1 1.5 1111.5 0.0 0.0 31.8 11.0 44.3 

LNB/SOFA + 

SNCR 3.1 1.5 819.0 0.0 0.0 31.8 11.0 44.3 

LNB/SOFA + 

SCR 3.1 1.5 175.5 0.0 0.0 31.8 11.0 44.3 
99 

Table 62. Entergy Lake Catherine Unit 4: Summary of 98th Percentile Visibility 

Impacts and Improvement due to NOX Controls (Natural Gas Firing) 

Class I area 

Baseline 

Visibility 

Impact 

(∆dv)

BOOS LNB/SOFA LNB/SOFA + SNCR LNB/SOFA + SCR 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from 

Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Caney Creek 1.371 0.775 0.596 0.683 0.688 0.529 0.842 0.163 1.208 

Upper 

Buffalo 0.532 0.284 0.248 0.25 0.282 0.193 0.339 0.057 0.475 

HerculesGlades 0.387 0.212 0.175 0.185 0.202 0.141 0.246 0.043 0.344 

Mingo 0.429 0.233 0.196 0.204 0.225 0.154 0.275 0.042 0.387 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 1.215 -- 1.397 -- 1.702 -- 2.414 

 The table above shows that the installation and operation of BOOS is projected to result 

in visibility improvement of up to 0.596 dv at any single Class I area (based on the 98th

percentile modeled visibility impacts), while LNB/SOFA is projected to result in visibility 

improvement of up to 0.688 dv. The installation and operation of the combination of LNB/SOFA 

+ SNCR is projected to result in visibility improvement of up to 0.842 dv at any single Class I 

area, while the combination of LNB/SOFA + SCR is projected to result in visibility 

improvement of up to 1.208 dv. The installation and operation of LNB/SOFA is projected to 

result in 0.092 dv of incremental visibility benefit over BOOS at Caney Creek, and much lower 

incremental visibility benefit over BOOS at the other Class I areas. The combination of 

LNB/SOFA + SNCR is projected to result in 0.154 dv of incremental visibility benefit over 

LNB/SOFA at Caney Creek, and 0.057 dv or less incremental visibility benefit at the other 

affected Class I areas. The combination of LNB/SOFA + SCR is projected to result in 0.366 dv 

of incremental visibility benefit over LNB/SOFA + SNCR at Caney Creek, 0.136 dv at Upper 

Buffalo, 0.098 ∆dv at Hercules-Glades, and 0.112 dv at Mingo. 

EPA’s Proposed NOX BART determination (Natural Gas Firing Scenario): 

 Taking into consideration the five factors, we are proposing to determine that NOX

BART for Lake Catherine Unit 4 for the natural gas firing scenario is an emission limit of 0.22 

lb/MMBtu on a 30 boiler-operating-day rolling average based on the installation and operation of 
100 

BOOS. The operation of BOOS is projected to result in visibility improvement ranging from 

0.175 to 0.596 dv at each affected Class I area (98th percentile basis). The cumulative visibility 

improvement across the four affected Class I areas is projected to be 1.215 dv. The operation of 

BOOS is estimated to have an average cost-effectiveness of $138/ton of NOX removed, which 

we consider to be very cost-effective. By comparison, the installation and operation of 

LNB/SOFA is estimated to have an average cost-effectiveness of $1,450/ton of NOX removed, 

which is still very cost-effective. However, the incremental cost-effectiveness of LNB/SOFA 

over BOOS is $14,246/ton of NOX ton removed, while the incremental visibility benefits are 

only 0.027 to 0.092 dv (depending on the Class I area). As discussed in the preceding paragraph, 

the operation of a combination of LNB/SOFA + SNCR is projected to result in visibility 

improvement over the baseline ranging from 0.246 to 0.842 dv at each affected Class I area and 

an incremental visibility improvement over LNB/SOFA ranging from 0.05 to 0.154 dv at each 

Class I area. However, the combination of LNB/SOFA + SNCR has an average costeffectiveness of $3,523/ton of NOX removed and an incremental cost-effectiveness compared to 

LNB/SOFA of $16,029/ton of NOX removed. We believe that the high incremental costs of the 

combination of LNB/SOFA + SNCR when compared to LNB/SOFA do not justify the amount of 

incremental visibility benefit projected at the affected Class I areas. 

The operation of a combination of LNB/SOFA + SCR is projected to result in 

considerable visibility improvement over the baseline, ranging from 0.344 to 1.208 dv at each 

affected Class I area. The incremental visibility benefit of the combination of LNB/SOFA + SCR 

over LNB/SOFA + SNCR ranges from 0.098 to 0.366 dv at each Class I area. However, the 

combination of LNB/SOFA + SCR has an average cost-effectiveness of $5,614 per ton of NOX

removed and an incremental cost-effectiveness (compared to the combination of LNB/SOFA + 

SNCR) of $11,767 per ton of NOX removed. While the incremental visibility benefit is 

considerable, we do not consider the average and the incremental cost-effectiveness values of the 

combination of LNB/SOFA + SCR to be cost-effective. Therefore, we are proposing to 

determine that NOX BART for Lake Catherine Unit 4 for the natural gas firing scenario is an 

emission limit of 0.22 lb/MMBtu on a 30 boiler-operating-day rolling average based on the 

installation and operation of BOOS. We are proposing to require compliance with this 

requirement no later than 3 years from the effective date of the final rule, consistent with our 

regional haze regulations.83 We are proposing to require that compliance be demonstrated using 

the unit’s existing CEMS. We are inviting public comment specifically on whether this proposed 

NOX emission limit is appropriate or whether an emission limit based on more stringent NOX

controls would be appropriate. 

6. Domtar Ashdown Paper Mill 

 The Domtar Ashdown Paper Mill Power Boilers No. 1 and 2 are subject to BART. We 

disapproved the State’s BART determinations for SO2 and NOX for Power Boiler No. 1 and the 

                                                            

83 40 CFR section 51.308(e)(1)(iv). 
101 

BART determination for SO2, NOX, and PM for the No. 2 Power Boiler in our March 12, 2012 

final action (77 FR 14604). 

 The No. 1 Power Boiler has a heat input rating of 580 MMBtu/hr and an average steam 

generation rate of approximately 120,000 lb/hr. It combusts primarily bark, but is also permitted 

to burn wood waste, tire-derived fuel (TDF), municipal yard waste, pelletized paper fuel (PPF), 

fuel oil, reprocessed fuel oil, and natural gas. It is equipped with a traveling grate, a combustion 

air system, and a wet ESP. 

 The No. 2 Power Boiler has a heat input rating of 820 MMBtu/hr and an average steam 

generation rate of approximately 600,000 lb/hr. It combusts primarily pulverized bituminous 

coal, but is also permitted to burn bark, PPF, TDF, municipal yard waste, fuel oil, used oil, 

natural gas, petroleum coke, and reprocessed oil. It is equipped with a traveling grate, 

combustion air system including OFA, multiclones for particulate removal, and two venturi 

scrubbers in parallel for removal of remaining particulates and SO2. 

 Domtar hired a consultant to perform a BART five-factor analysis for the Domtar 

Ashdown Mill Power Boilers No. 1 and 2 (Domtar’s 2014 BART analysis).84 In this proposal, 

we also refer to certain parts of the Domtar BART evaluation submitted by the State in the 2008 

Arkansas RH SIP, which we are hereafter referring to as the “2006/2007 Domtar BART 

analysis.”85 Although we already took action on that SIP submittal, we reference the 2006/2007 

Domtar BART analysis as it contains the best available information we have related to certain 

NOX controls for Power Boilers No. 1 and 2. 

a. Baseline Emission Rates and Existing Visibility Impairment Attributable to the 

Domtar Ashdown Mill Power Boilers No. 1 and 2

 The table below summarizes the baseline emission rates for Power Boilers No. 1 and 2. 

The SO2 baseline emission rate for Power Boiler No. 1 used in Domtar’s 2014 BART analysis is 

the highest actual 24-hour emission rate estimated using maximum 24-hour fuel usage rates 

during 2009-2011 and sulfur content values for each fuel type.86 The 2009-2011 period was used 

as the baseline in Domtar’s evaluation for Power Boiler No. 1 because a wet ESP was installed 

on Power Boiler No. 1 in 2007 to meet the Maximum Achievable Control Technology (MACT) 

                                                            

84 See “Supplemental BART Determination Information Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),” 

originally dated June 28, 2013 and revised on May 16, 2014, prepared by Trinity Consultants Inc. in conjunction 

with Domtar A.W. LLC. A copy of this BART analysis is found in the docket for our proposed rulemaking. 

85 See “Best Available Retrofit Technology Determination Domtar Industries Inc., Ashdown Mill (AFIN 41-

00002),” originally dated October 31, 2006 and revised on March 26, 2007, prepared by Trinity Consultants Inc. 

This BART analysis is part of the 2008 Arkansas RH SIP, upon which EPA took final action on March 12, 2012 

(77 FR 14604). A copy of this BART analysis is found in the docket for this proposed rulemaking. 

86 In Domtar’s 2014 BART analysis, 2009-2011 was used as the baseline period for Power Boiler No. 1 because a 

wet ESP was installed on Power Boiler No. 1 in 2007. The installation of the wet ESP resulted in a reduction in 

PM and SO2 emissions from Power Boiler No. 1. Therefore, 2009-2011 is more representative of the boiler’s 

emissions than 2001-2003. 
102 

standards under CAA section 112, resulting in a reduction in PM and SO2 emissions from Power 

Boiler No. 1. Therefore, we believe that the 2009-2011 period is more representative of the 

boiler’s current emissions than 2001-2003. We believe the use of 2009-2011 as the new baseline 

period for Power Boiler No. 1 is consistent with the BART Guidelines, which provide that the 

baseline emissions rate should represent a realistic depiction of anticipated annual emissions for 

the source.87 The NOX and PM baseline emission rates used for Power Boiler No. 1 are the 

highest actual 24-hour emission rates estimated using the maximum heat input from 2009-2011 

and emission factors developed from the analysis of stack testing the facility had previously 

conducted. For Power Boiler No. 2, the baseline emission rates are the highest actual 24-hour 

emission rates based on a combination of 2001-2003 CEMS data, source-specific stack testing 

results, and emission factors from AP-42. 

Table 63. Domtar Ashdown Mill: Baseline Maximum 24-Hour Emission Rates 

Subject to BART Unit NOX Emissions 

(lbhr) 

SO2 Emissions 

(lb/hr) 

PM10/PMf Emissions 

(lb/hr) 

Power Boiler No. 1 207.4 21.0 30.4 

Power Boiler No. 2 526.8 788.2 81.6 

 Domtar modeled the baseline emission rates using the CALPUFF dispersion model to 

determine the baseline visibility impairment attributable to the Domtar Ashdown Mill’s Power 

Boilers No. 1 and 2 at the four Class I areas impacted by emissions from BART sources in 

Arkansas. These Class I areas are the Caney Creek Wilderness Area, Upper Buffalo Wilderness 

Area, Hercules-Glades Wilderness Area, and Mingo National Wildlife Refuge. The baseline (i.e., 

existing) visibility impairment attributable to the source at each Class I area is summarized in the 

table below. 

Table 64. Baseline Visibility Impairment Attributable to the Domtar Ashdown Mill 

Emission Unit Caney 

Creek 

Upper 

Buffalo 

HerculesGlades Mingo 

Power Boiler No. 1 

Maximum (∆dv) 0.476 0.090 0.077 0.060 

98th Percentile (∆dv) 0.335 0.038 0.020 0.014 

                                                            

87 40 CFR Part 51, Appendix Y, section IV.D.4.c. 
103 

Power Boiler No. 2 

Maximum (∆dv) 1.603 0.381 0.329 0.246 

98th Percentile (∆dv) 0.844 0.146 0.105 0.065 

b. SO2 BART Evaluation and Proposed BART Determination for Power Boiler No. 1 

 The table above shows that the baseline visibility impairment attributable to Power Boiler 

No. 1 is relatively low based on the 98th percentile visibility impacts, ranging from 0.014 to 

0.335 dv at each Class I area. An examination of the species contribution to the 98th percentile 

visibility impacts shows that SO2 emissions contribute a very small portion of the visibility 

impairment attributable to Power Boiler No. 1 (see the table below). The SO4 species contributes 

only 2.23 – 4.03% of the visibility impairment attributable to Power Boiler No. 1 at the modeled 

Class I areas. We also note that Power Boiler No. 1 combusts primarily bark, which results in 

very low SO2 emissions due to the low sulfur content of bark. 

Table 65. 98th Percentile Baseline Visibility Impairment and Species Contribution for 

Domtar Ashdown Mill- Power Boiler No. 1 

Emissions 

Unit Class I area 

98th 

Percentile 

Visibility 

Impacts 

(dv)88

Species Contribution to 98th Percentile 

Visibility Impacts 

98th

Percentile 

% SO4

98th 

Percentile 

% NO3

98th 

Percentile 

% PM10

98th 

Percentile 

% NO2

Power Boiler 

No. 1 

Caney Creek 0.335 2.23 85.26 6.68 5.83 

Upper Buffalo 0.038 2.75 85.89 8.03 3.32 

Hercules-Glades 0.020 2.70 91.82 3.94 1.55 

Mingo 0.014 4.03 90.06 5.13 0.78 

 

 The BART Rule provides that states, or EPA in this case, can adopt a more streamlined 

approach to making BART determinations where appropriate.89 Considering the very low 

baseline visibility impairment that is due to SO2 emissions from Power Boiler No. 1 and the fact 

                                                            

88 The visibility impact shown represents the highest 98th percentile value among the three modeled years. 89 70 FR 39116. 
104 

that the boiler combusts primarily bark, which has a low sulfur content, we believe that any 

visibility improvement that could be achieved as a result of emissions reductions associated with 

the installation and operation of SO2 controls would be negligible, and that the cost of those 

controls could not be justified. Therefore, we are proposing that the SO2 baseline emission rate 

of 21.0 lb/hr satisfies SO2 BART for Power Boiler No. 1. We are proposing this SO2 emission 

rate on a 30 boiler-operating-day averaging basis, where in this particular case boiler-operatingday is defined as a 24-hour period between 12 midnight and the following midnight during 

which any fuel is fed into and/or combusted at any time in the Power Boiler. Power Boiler No. 1 

is not currently equipped with a CEMS. To demonstrate compliance with this SO2 BART 

emission limit we are proposing to require the facility to use a site-specific curve equation,90

provided to us by the facility, to calculate the SO2 emissions from Power Boiler No. 1 when 

combusting bark, and to confirm the curve equation using stack testing.91 We are also proposing 

that to calculate the SO2 emissions from fuel oil combustion, the facility must assume that the 

SO2 inlet is equal to the SO2 being emitted at the stack. We are inviting public comment on 

whether this method of demonstrating compliance with the proposed BART emission limit is 

appropriate. Since this proposed BART determination does not require the installation of control 

equipment, we are proposing that this SO2 emission limit be complied with by the effective date 

of the final action. 

c. NOX BART Evaluation for Power Boiler No. 1 

Step 1- Identify All Available Retrofit Control Technologies 

 For NOX BART, Domtar’s 2014 BART analysis evaluated SNCR and Methane de-NOX

(MdN). In the 2006/2007 Domtar BART analysis, which was submitted in the 2008 Arkansas 

RH SIP, other NOX controls were also evaluated but found by Arkansas to be either already in 

use or not technically feasible for use at Power Boiler No. 1. Fuel blending, boiler operational 

modifications, and boiler tuning/optimization are already in use at the source, while FGR, LNB, 

Ultra Low NOX Burners (ULNB), OFA, and SCR were determined to be technically infeasible 

for use at Power Boiler No. 1. Domtar did not further evaluate these NOX controls in its 2014 

BART analysis for Power Boiler No. 1, focusing instead on SNCR and MdN. 

Step 2- Eliminate Technically Infeasible Options

                                                            

90 The curve equation is Y= 0.4005 * X – 0.2645, where Y= pounds of sulfur emitted per ton dry fuel feed to the 

boiler and X= pounds of sulfur input per ton of dry bark. The purpose of this equation is to factor in the degree of 

SO2 scrubbing provided by the combustion of bark. 91 Background information and an explanation of the site specific curve equation provided by Domtar can be found 

in the documents titled “Site Specific Curve Equation Background_Domtar PB No1,” and “1PB SO2 Emissions 

from Curve.” Copies of these documents can be found in the docket for this proposed rulemaking. 
105 

 MdN utilizes the injection of natural gas together with recirculated flue gases to create an 

oxygen-rich zone above the combustion grate. Air is then injected at a higher furnace elevation 

to burn the combustibles. In response to comments provided by us regarding Domtar’s 2014 

BART analysis, Domtar stated that discussions regarding the technical infeasibility of MdN in 

the 2006/2007 Domtar BART analysis, submitted as part of the 2008 Arkansas RH SIP, remain 

correct.92 The 2006/2007 Domtar BART analysis submitted in the 2008 Arkansas RH SIP 

discussed that MdN has not been fully demonstrated for this source type and incorporates FGR, 

which is technically infeasible for use at Power Boiler No. 1. Domtar also stated it recently 

completed additional research and found that since the 2006/2007 Domtar BART analysis, MdN 

has not been placed into operation in power boilers at paper mills or any comparable source 

types. We are also not aware of any power boilers at paper mills that operate MdN for NOX

control, and agree that this control can be considered technically infeasible for use at Power 

Boiler No. 1 and do not further consider it in this evaluation. Domtar also questioned the 

technical feasibility of SNCR for bark fired boilers and boilers with high load swings such as 

Power Boiler No. 1, but in response to our comments, SNCR was evaluated for Power Boiler No. 

1 in Domtar’s 2014 BART analysis. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 Domtar’s 2014 BART analysis evaluated SNCR at removal efficiencies of 20%, 32.5%, 

and 45% for Power Boiler No. 1. The estimated 32.5% and 45% removal efficiencies were based 

on equipment vendor estimates that came from the vendor’s proposal,93 which according to the 

facility, is not an appropriations request level quote and therefore needs further refinement.94 For 

example, Domtar’s 2014 BART analysis discusses that for a base loaded pulp mill boiler with 

steady flue gas flow patterns and temperature distribution across the flue gas pathway, SNCR 

can achieve a 45% removal efficiency. However, Power Boiler No. 1 is not a base loaded boiler. 

Domtar’s 2014 BART analysis states that for pulp mill boilers with fluctuating loads (i.e., high 

load swing), such as Power Boiler No. 1, SNCR is used primarily for polishing purposes (i.e., < 

20 to 30% NOX reduction) and it is uncertain whether higher removal efficiencies are achievable 

on a long-term basis. The facility believes that 20% removal efficiency, which has been 

                                                            

92 See the document titled “Domtar Responses to ADEQ Regarding Region 6 Comments on Domtar BART 

Analysis,” p. 10. A copy of this document can be found in the docket for our proposed rulemaking. 

93 Fuel Tech Proposal titled “Domtar Paper Ashdown, Arkansas- NOX Control Options, Power Boilers 1 and 2,” 

dated June 29, 2012. A copy of the vendor proposal is included under Appendix D to the “Supplemental BART 

Determination Information Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),” originally dated June 28, 2013 

and revised on May 16, 2014, prepared by Trinity Consultants Inc. in conjunction with Domtar A.W. LLC. A 

copy of this BART analysis and its appendices is found in the docket for our proposed rulemaking. 

94 See the document titled “Domtar Responses to ADEQ Regarding Region 6 Comments on Domtar BART 

Analysis,” p. 9. A copy of this document can be found in the docket for our proposed rulemaking. 
106 

demonstrated at a similar bark fired power boiler at another paper mill, is the most reasonable 

estimate of the removal efficiency of SNCR for Power Boiler No. 1. 

 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

 In Domtar’s 2014 BART analysis, the capital costs, operating costs, and costeffectiveness of SNCR were calculated based on methods and assumptions found in our Control 

Cost Manual, and supplemented with mill-specific cost information for water, fuels, and ash 

disposal and urea solution usage estimates from the equipment vendor.95 The capital cost was 

annualized over a 30-year period and then added to the annual operating cost to obtain the total 

annualized costs. The annual emissions reductions associated with each NOX control option were 

determined by subtracting the estimated controlled annual emission rate from the baseline annual 

emission rate. The baseline annual emissions used in the calculations are the uncontrolled actual 

emissions from the 2009-2011 baseline period. The average cost-effectiveness was calculated by 

dividing the total annual cost by the estimated annual NOX emissions reductions. The table 

below summarizes the cost of NOX controls for Power Boiler No. 1. 

Table 66. Summary of Cost of NOX Controls for Domtar Ashdown Mill Power Boiler No. 1 

NOX Control 

Scenarios 

Baseline 

Emission 

Rate 

(NOX tpy) 

NOX

Control 

Efficiency 

(%) 

Annual 

Emissions 

Reduction 

(NOX tpy) 

Capital Cost 

($) 

Total Annual 

Cost 

($/yr) 

Average Cost 

Effectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

SNCR- 20% 440 20% 88 2,152,365 1,118,178 12,700 - 

SNCR- 32.5% 440 32.5% 143 2,423,587 1,144,103 7,996 471 

SNCR- 45% 440 45% 198 2,707,431 1,513,602 7,640 6,718 

 Domtar’s 2014 BART analysis did not identify any energy or non-air quality 

environmental impacts associated with the use of SNCR. We are not aware of any unusual 

                                                            

95 See “Supplemental BART Determination Information Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),” 

originally dated June 28, 2013 and revised on May 16, 2014, prepared by Trinity Consultants Inc. in conjunction 

with Domtar A.W. LLC. A copy of this BART analysis is found in the docket for our proposed rulemaking. 
107 

circumstances at the facility that create greater non-air quality environmental impacts than 

experienced elsewhere that may provide a basis for the elimination of these control options as 

BART (40 CFR Part 51, Appendix Y, section IV.D.4.i.2.). Therefore, we do not believe there are 

any energy or non-air quality environmental impacts associated with the operation of NOX

controls at Power Boiler No. 1 that would affect our proposed BART determination. 

 Consideration of the presence of existing pollution control technology at the source is 

reflected in the BART analysis in two ways: first, in the consideration of available control 

technologies, and second, in the development of baseline emission rates for use in cost 

calculations and visibility modeling. Power Boiler No. 1 is currently equipped with a combustion 

air system to optimize boiler combustion efficiency, which has the co-benefit of reducing 

emissions. The baseline emission rate used in the cost calculations and visibility modeling 

reflects the use of the existing combustion air system. 

 We are not aware of any enforceable shutdown date for the Domtar Ashdown Mill Power 

Boiler No. 1, nor did Domtar’s 2014 BART analysis indicate any future planned shutdown. This 

means that the anticipated useful life of the boiler is expected to be at least as long as the capital 

cost recovery period of controls. Therefore, a 30-year amortization period was assumed in the 

evaluation of SNCR as the remaining life of the boiler. 

Step 5- Evaluate Visibility Impacts 

 In the 2014 BART analysis, Domtar assessed the visibility improvement associated with 

SNCR by modeling the NOX emission rates associated with each control option using 

CALPUFF, and then comparing the visibility impairment associated with the baseline emission 

rate to the visibility impairment associated with the controlled emission rates as measured by the 

98th percentile modeled visibility impact. The tables below show the modeled emission rates and 

a comparison of the baseline (i.e., existing) visibility impacts and the visibility impacts 

associated with SNCR for each Class I area. 

Table 67. Summary of Emission Rates Modeled for NOX Controls for Domtar Ashdown 

Mill Power Boiler No.1 

Scenario 

NOX

Emissions

(lb/hr)

SO2

Emissions

(lb/hr)

PM10/PMF 

Emissions

(lb/hr)

Baseline 207.4 21.0 30.4 

SNCR 20.0% 165.9 21.0 30.4 

SNCR 32.5% 140.0 21.0 30.4 

SNCR 45.0% 114.1 21.0 30.4 
108 

MdN 103.7 21.0 30.4 

Table 68. Domtar Ashdown Mill Power Boiler No. 1: Summary of the 98th Percentile 

Visibility Impacts and Improvement due to SNCR 

Class I area 

Baseline 

Visibility 

Impact 

(dv)

SNCR- 20% SNCR- 32.5% SNCR- 45% 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

SNCR 20% 

Visibility 

Impact 

(∆dv) 

Visibility 

Improvement 

from Baseline 

(∆dv) 

Incremental 

Visibility 

Improvement 

vs. 

SNCR 32.5% 

Caney Creek 0.335 0.274 0.061 0.237 0.098 0.037 0.199 0.136 0.038 

Upper Buffalo 0.038 0.031 0.007 0.027 0.011 0.004 0.023 0.015 0.004 

HerculesGlades 0.020 0.017 0.003 0.014 0.006 0.003 0.012 0.008 0.002 

Mingo 0.014 0.011 0.003 0.009 0.005 0.002 0.008 0.006 0.001 

Cumulative 

Visibility 

Improvement 

(∆dv) 

-- -- 0.074 -- 0.12 -- -- 0.165 -- 

 The table above shows that the installation and operation of SNCR is projected to result 

in visibility improvements of up to 0.136 dv at any single Class I area when operated at 45% 

removal efficiency, 0.098 dv when operated at 32.5% removal efficiency, and 0.061 dv when 

operated at 20% removal efficiency (based on the 98th percentile modeled visibility impacts). 

Our Proposed NOX BART determination for Power Boiler No. 1: 

Taking into consideration the five factors, we are proposing to determine that NOX

BART for the Domtar Ashdown Mill Power Boiler No. 1 is an emission limit of 207.4 lb/hr on a 

30 boiler-operating-day rolling average, where boiler-operating-day is defined as a 24-hour 

period between 12 midnight and the following midnight during which any fuel is fed into and/or 

combusted at any time in the Power Boiler. This emission limit is based on the boiler’s NOX

baseline emission rate and therefore represents current operating conditions. 

 MdN was determined to be not technically feasible for use at Power Boiler No. 1 
109 

because it has not been fully demonstrated for this source type and incorporates FGR, which is 

technically infeasible for use at the boiler. The installation and operation of SNCR is projected to 

result in some visibility improvement at the Class I areas. As discussed in more detail above, we 

concur with Domtar’s position that 20% removal efficiency is the most reasonable estimate of 

the level of NOX control SNCR can achieve at Power Boiler No. 1. When operated at 20% 

removal efficiency, SNCR is projected to result in visibility improvement of up to 0.061 dv at 

any single Class I area and is estimated to cost $12,700/ton of NOX removed. We do not believe 

this high cost justifies the modest visibility improvement projected from the installation and 

operation of SNCR at 20% removal efficiency. Although there is uncertainty as to whether 

SNCR can achieve a long term removal efficiency of 45% or even 32.5% at Power Boiler No. 1, 

we believe that the associated costs are also too high and not justified by the projected visibility 

benefits. Installation and operation of SNCR at a 45% removal efficiency is projected to result in 

a visibility improvement of up to 0.136 dv at any single Class I area and is estimated to cost 

$7,640/ton of NOX removed. The operation of SNCR at a 32.5% removal efficiency is projected 

to result in visibility improvement of up to 0.098 dv at any single Class I area and is estimated to 

cost $7,996/ton of NOX removed. Therefore, we are proposing to determine that NOX BART for 

Power Boiler No. 1 is no additional control and are proposing that an emission limit of 207.4 

lb/hr on a 30 boiler-operating-day rolling average satisfies NOX BART. In this particular case, 

we are defining boiler-operating-day as a 24-hour period between 12 midnight and the following 

midnight during which any fuel is fed into and/or combusted at any time in the Power Boiler. 

Power Boiler No. 1 is not currently equipped with a CEMS. To demonstrate compliance with 

this NOX BART emission limit we are proposing to require annual stack testing. We are inviting 

public comment on the appropriateness of this method for demonstrating compliance with the 

NOX BART emission limit for Power Boiler No. 1. Since this proposed BART determination 

does not require the installation of control equipment, we are proposing that this NOX emission 

limit be complied with by the effective date of the final action. 

 

d. SO2 BART Evaluation for Power Boiler No. 2 

Step 1- Identify All Available Retrofit Control Technologies 

 Power Boiler No. 2 is currently equipped with two venturi wet scrubbers in parallel for 

removal of particulates and SO2. Domtar’s 2014 BART analysis evaluated upgrades to the 

existing venturi wet scrubbers and new add-on scrubbers for Power Boiler No. 2.96 Domtar 

contracted with a vendor to evaluate upgrades to the existing venturi scrubbers and to provide a 

quote for a new add-on spray scrubber system that would be installed downstream of the existing 

                                                            

96 See “Supplemental BART Determination Information Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),” 

originally dated June 28, 2013 and revised on May 16, 2014, prepared by Trinity Consultants Inc. in conjunction 

with Domtar A.W. LLC. A copy of this BART analysis is found in the docket for our proposed rulemaking. 
110 

venturi scrubbers.97 Domtar’s analysis states that the existing venturi scrubbers achieve an SO2

control efficiency of approximately 90% and notes that this is within the normal range for the 

highest efficiency achieved by SO2 control technologies. Domtar’s analysis also indicates that 

the upgrades considered for the existing venturi scrubbers include (1) the elimination of bypass 

reheat, (2) the installation of liquid distribution rings, (3) the installation of perforated trays, (4) 

improvements to the auxiliary system requirement, and (5) a redesign of spray header and nozzle 

configuration. 

 Another option not evaluated in Domtar’s 2014 BART analysis is the operation of the 

existing venturi scrubbers to achieve a higher SO2 control efficiency than what is currently being 

achieved through the use of additional scrubbing reagent. Following discussions between us and 

Domtar, the facility provided additional information regarding the existing venturi scrubbers, 

including a description of the internal structure of the scrubbers, whether any scrubber upgrades 

have taken place, the type of reagent used, how the facility determines how much reagent to use, 

and the SO2 control efficiency.98 Domtar confirmed that no upgrades to the scrubbers have ever 

been performed and stated that 100% of the flue gas is treated by the scrubber systems. The 

scrubbing solution used in the venturi scrubbers is made up of three components: 15% caustic 

solution (i.e., NaOH), bleach plant EO filtrate (typical pH above 9.0), and demineralizer anion 

rinse water (approximately 2.5% NaOH). The bleach plant EO filtrate and demineralizer anion 

rinse water are both waste byproducts from the processes at the plant. The 15% caustic solution 

is added to adjust the pH of the scrubbing solution and maintain it within the required range to 

ensure that sufficient SO2 is removed from the flue gas in the scrubber to meet the permitted SO2

emission limit of 1.20 lb/MMBtu on a three hour average. Each venturi scrubber has a 

recirculation tank that is equipped with level control systems to ensure that an adequate supply of 

the scrubbing solution is maintained. There are pH controllers in place that provide signals for 

the 15% caustic flow controllers to adjust the flow of the caustic solution to bring the pH into the 

desired set point range. The pH controllers are overridden in the event that SO2 levels measured 

at the stack by the CEMS are above the operator set point of 0.86 lb/MMBtu on a two hour 

average (the SO2 permit limit is 1.20 lb/MMBtu on a three hour average). This allows additional 

caustic feed to the scrubber solution to increase the pH and reduce the SO2 measured at the stack. 

According to Domtar, the scrubber systems operate in this manner to maintain continuous 

compliance with permitted emission limits. 

Domtar provided monthly average data for 2011, 2012, and 2013 on monitored SO2

emissions from Power Boiler No. 2, mass of the fuel burned for each fuel type, and the percent 

                                                            

97 The information provided by the vendor to Domtar is found in Appendix D to the analysis titled “Supplemental 

BART Determination Information Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),” originally dated June 

28, 2013 and revised on May 16, 2014, prepared by Trinity Consultants Inc. in conjunction with Domtar A.W. 

LLC. 

98 See the following: Letters dated July 9, 2014; July 21, 2014; August 15, 2014; August 29, 2014; and September 

12, 2014, from Annabeth Reitter, Corporate Manager of Environmental Regulation, Domtar, to Dayana Medina, 

U.S. EPA Region 6. Copies of these letters and all attachments are found in the docket for our proposed 

rulemaking. 
111 

sulfur content of each fuel type burned.99 According to the data provided by Domtar, the monthly 

average SO2 control efficiency of the existing scrubbers for the 2011-2013 period ranged from 

57% to 90%. The data indicate that the monthly average control efficiency of the scrubbers is 

usually below 90%. The information provided also indicates that the facility could add more 

scrubbing solution to achieve greater SO2 removal than what is necessary to meet permit limits. 

Based on our discussions with Domtar and the additional information provided to us, we 

believe it is technically feasible to increase the current SO2 control efficiency of the existing 

scrubbers from current levels to 90% on a monthly average basis through the use of additional 

scrubbing reagent. 

Step 2- Eliminate Technically Infeasible Options

 Domtar’s analysis discusses that the vendor determined that any upgrades to the existing 

venturi scrubbers for purposes of achieving additional SO2 control would involve efforts to 

increase pressure drop. Additionally, it determined that any additional control that could 

potentially be achieved from implementation of such upgrades would be marginal, but Domtar 

was unable to quantify the potential additional control. Therefore, Domtar determined that the 

installation of new add-on scrubbers to operate downstream of the existing scrubbers was more 

feasible than any upgrade option. The remainder of Domtar’s analysis focused on the add-on 

scrubber option only. 

 Additionally, as discussed above, based on our discussions with Domtar and the 

additional information Domtar provided to us, we determined it would be technically feasible to 

increase the current control efficiency of the existing scrubbers through the use of additional 

scrubbing reagent. We evaluate this control option in this TSD. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

 Based on the information provided to Domtar by the vendor, new add-on spray scrubbers 

were estimated to achieve 90% control efficiency on top of the SO2 removal currently achieved 

by the existing venturi scrubbers. In Domtar’s analysis, it was estimated that a controlled SO2

emission rate of 78.8 lb/hr would be achieved by the operation of add-on spray scrubbers 

installed downstream of the existing venturi scrubbers. 

 To estimate the current control efficiency of the existing venturi scrubbers, we asked 

Domtar to provide monthly average data for 2011, 2012, and 2013 on monitored SO2 emissions 

from Power Boiler No. 2, mass of the fuel burned for each fuel type, and the percent sulfur 

                                                            

99 August 29, 2014 letter from Annabeth Reitter, Corporate Manager of Environmental Regulation, Domtar, to 

Dayana Medina, U.S. EPA Region 6. A copy of this letter and an Excel file attachment titled “Domtar 2PB 

Monthly SO2 Data,” are found in the docket for our proposed rulemaking. 
112 

content of each fuel type burned.100 Based on the information provided by Domtar, the monthly 

average SO2 control efficiency of the existing scrubbers for the 2011-2013 period ranged from 

57% to 90%. The data indicate that the monthly average control efficiency of the scrubbers is 

usually below 90%. Based on the monthly average SO2 control efficiency data for the 2011-2013 

period, we estimated the annual average SO2 control efficiency for the three-year period to be 

approximately 69%.101 

To determine the controlled emission rate that corresponds to the operation of the 

existing venturi scrubbers at a 90% removal efficiency, we first determined the SO2 emission 

rate that corresponds to the operation of the scrubbers at the current control efficiency of 69%. 

Based on emissions data we obtained from Domtar, we determined that the No. 2 Power Boiler’s 

annual average SO2 emission rate for the years 2009-2011 was 280.9 lb/hr.102 This annual 

average SO2 emission rate corresponds to the operation of the scrubbers at a 69% removal 

efficiency. We also estimated that 100% uncontrolled emissions would correspond to an 

emission rate of approximately 915 lb/hr. Application of 90% control efficiency to this results in 

a controlled emission rate of 91.5 lb/hr, or 0.11 lb/MMBtu based on the boiler’s maximum heat 

input of 820 MMBtu.103

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

 Domtar’s estimates of the capital and operating and maintenance costs of add-on spray 

scrubbers for Power Boiler No. 2 were based on the equipment vendor’s budget proposal and on 

calculation methods from our Control Cost Manual. Domtar annualized the capital cost of the 

add-on spray scrubbers over a 30-year amortization period and then added these to the annual 

                                                            

100 August 29, 2014 letter from Annabeth Reitter, Corporate Manager of Environmental Regulation, Domtar, to 

Dayana Medina, U.S. EPA Region 6. A copy of this letter and an Excel file attachment titled “Domtar 2PB 

Monthly SO2 Data,” are found in the docket for our proposed rulemaking. 

101 See the spreadsheet titled “Domtar 2PB Monthly SO2 Data.” This spreadsheet was included as an attachment to 

the August 29, 2014 letter from Annabeth Reitter, Corporate Manager of Environmental Regulation, Domtar, to 

Dayana Medina, U.S. EPA Region 6. See also the spreadsheet titled “Domtar PB No2- Cost Effectiveness 

calculations.” Copies of these documents can be found in the docket for this proposed rulemaking. 

102 See the spreadsheet titled “Domtar 2PB Monthly SO2 Data.” This spreadsheet was included as an attachment to 

the August 29, 2014 letter from Annabeth Reitter, Corporate Manager of Environmental Regulation, Domtar, to 

Dayana Medina, U.S. EPA Region 6. See also the spreadsheet titled “No2 Boiler_Monthly Avg SO2 emission rate 

and calculations.” Copies of these documents can be found in the docket for this proposed rulemaking. 103 See the spreadsheet titled “No2 Boiler_Monthly Avg SO2 emission rate and calculations.” A copy of this 

spreadsheet can be found in the docket for this proposed rulemaking. 
113 

operating costs to obtain the total annualized cost.104 The average cost-effectiveness in dollars 

per ton removed was calculated by dividing the total annualized cost by the annual SO2

emissions reductions. The average cost-effectiveness of the add-on spray scrubbers for Power 

Boiler No. 2 was estimated to be $5,258/ton of SO2 removed (see table below). Domtar’s 

analysis notes that because of constricted space, there is no existing property or adequate 

structure to support the add-on spray scrubber equipment. In our discussions with Domtar, the 

facility indicated that the installation of add-on spray scrubbers would require construction at the 

facility to accommodate the equipment, but an estimate of these costs was not available and 

therefore not factored into the cost estimates presented in Domtar’s analysis. 

Table 69. Summary of Costs for Add-On Spray Scrubber for Power Boiler No. 2 

Control 

Technology 

Baseline 

Emission 

Rate 

(SO2 tpy) 

Controlled 

Emission 

Level 

(lb/hr) 

Controlled 

Emission 

Rate 

(tpy) 

Annual 

Emissions 

Reductions 

(SO2 tpy) 

Capital 

Cost* 

($) 

Annual 

Direct 

O&M 

Cost 

($/yr) 

Annual 

Indirect 

O&M 

Cost 

($/yr) 

Total 

Annual 

Cost 

($/yr) 

Average 

Cost 

Effectiveness 

($/ton) 

Add-on 

Spray 

Scrubber 

2,078 78.8 208 1,870 7,175,000 8,833,382 421,789 9,833,378 5,258 

* Capital cost does not include new construction to accommodate equipment. 

Based on the cost information provided by the facility, increasing the monthly average 

SO2 control efficiency of the existing venturi scrubbers from current levels to 90% control 

efficiency would require replacing two scrubber pumps, which involves capital costs of 

$200,000.105 It would also require additional scrubbing reagent, treatment of additional 

wastewater, treatment of additional raw water, and additional energy usage, which involves 

annual operation and maintenance costs of approximately $1.96 million. We annualized the 

capital cost of the two scrubber pumps over a 30-year amortization period, assuming a 7% 

interest rate. We calculated the annualized capital cost to be $16,120, and added this to the 

annual operating costs to obtain a total annual costs of $1,976,554.106 

                                                            

104 See Appendices B and D to the “Supplemental BART Determination Information Domtar A.W. LLC, Ashdown 

Mill (AFIN 41-00002),” originally dated June 28, 2013 and revised on May 16, 2014, prepared by Trinity 

Consultants Inc. in conjunction with Domtar A.W. LLC. 105 September 30, 2014 letter from Annabeth Reitter, Corporate Manager of Environmental Regulation, Domtar, to 

Dayana Medina, U.S. EPA Region 6. See also the spreadsheet titled “Domtar PB No2- Cost of Using Additional 

Scrubbing Reagent. Copies of these documents can be found in the docket for this proposed rulemaking. 106 See the Excel spreadsheet titled “Domtar PB No2- Cost of Using Additional Scrubbing Reagent” for line items of 

the capital and operation and maintenance costs associated with the use additional scrubbing reagent, and for 

calculation of the total annual cost. This spreadsheet can be found in the docket for this proposed rulemaking. 
114 

We calculated the average cost-effectiveness in dollars per ton removed by dividing the 

total annual cost by the estimated annual SO2 emissions reductions. To estimate the SO2 annual 

emissions reductions expected from increasing the control efficiency of the scrubbers through the 

use of additional scrubbing solution, we calculated the annual average SO2 control efficiency of 

the existing scrubbers. As discussed above, based on data provided by Domtar for the 2011-2013 

period, we estimated the annual average SO2 control efficiency for the three-year period to be 

approximately 69%.107 Considering the baseline annual emissions for Power Boiler No. 2 are 

2,078 SO2 tpy, and assuming that the scrubbers currently operate at an annual average control 

efficiency of 69%, we have estimated that the uncontrolled annual emissions would be 6,769 SO2

tpy and that operating the scrubbers at 90% control efficiency would result in controlled annual 

emissions of 677 SO2 tpy.108 By subtracting the controlled annual emission rate of 677 SO2 tpy 

from the baseline annual emission rate of 2,078 SO2 tpy, we estimate that increasing the control 

efficiency of the existing venturi scrubbers from the current level of 69% to 90% control 

efficiency would result in annual emissions reductions of 1,401 SO2 tpy.109 We estimate the 

average cost-effectiveness of using additional scrubbing reagent to increase the SO2 control 

efficiency of the existing venturi scrubbers from the current control efficiency (estimated to be 

69%) to 90% is $1,411/ton of SO2 removed. The cost information is presented in the table below. 

Table 70. Summary of Cost of Using Additional Scrubbing Reagent to Increase Control 

Efficiency of Existing Venturi Scrubbers at Domtar Ashdown Mill Power Boiler No. 2 

Control 

Option 

Baseline 

Emission 

Rate 

(SO2 tpy) 

Controlled 

Emission 

Rate 

(tpy) 

Annual 

Emissions 

Reductions 

(SO2 tpy) 

Capital 

Costs110

($) 

Annual 

Operation 

& Maintenance 

Cost111

($/yr) 

Total 

Annual 

Cost 

($/yr) 

Average 

Cost 

Effectiveness 

($/ton) 

Use of 

Additional 

Scrubbing 

Reagent 

2,078 677 1,401 200,000 1,960,434 1,976,554 1,411 

                                                            

107 See the spreadsheet titled “Domtar 2PB Monthly SO2 Data.” This spreadsheet was included as an attachment to 

the August 29, 2014 letter from Annabeth Reitter, Corporate Manager of Environmental Regulation, Domtar, to 

Dayana Medina, U.S. EPA Region 6. See also the spreadsheet titled “Domtar PB No2- Cost Effectiveness 

calculations.” Copies of these documents can be found in the docket for this proposed rulemaking. 

108 See the spreadsheet titled “Domtar PB No2- Cost Effectiveness calculations.” A copy of this spreadsheet can be 

found in the docket for this proposed rulemaking. 

109 Id. 110 The capital costs consist of two new pumps for the existing scrubber system. 

111 The operation and maintenance costs consist of the following costs: additional scrubbing reagent, treatment of 

additional wastewater, treatment of additional raw water, and additional energy usage. 
115 

 Domtar’s 2014 BART analysis did not identify any energy or non-air quality 

environmental impacts associated with the use of add-on spray scrubbers. We are not aware of 

any unusual circumstances at the facility that create energy or non-air quality environmental 

impacts associated with the use of add-on spray scrubbers greater than experienced elsewhere 

that may therefore provide a basis for the elimination of this control option as BART (40 CFR 

Part 51, Appendix Y, section IV.D.4.i.2.). We are also not aware of any unusual circumstances at 

the facility that create energy or non-air quality environmental impacts associated with the use of 

additional scrubbing reagent to increase the control efficiency of the existing venturi scrubbers 

greater than experienced elsewhere that may therefore provide a basis for the elimination of this 

control option as BART. Therefore, we do not believe there are any energy or non-air quality 

environmental impacts associated with these control options at Power Boiler No. 2 that would 

affect our proposed BART determination. 

 Consideration of the presence of existing pollution control technology at the source is 

reflected in the BART analysis in two ways: first, in the consideration of available control 

technologies, and second, in the development of baseline emission rates for use in cost 

calculations and visibility modeling. Power Boiler No. 2 is equipped with multiclones for 

particulate removal and two venturi scrubbers in parallel for control of SO2 emissions. It is also 

equipped with a combustion air system including overfire air to optimize boiler combustion 

efficiency, which also helps control emissions. The baseline emission rate used in the cost 

calculations and visibility modeling reflects the use of these existing controls. As discussed 

above, Domtar’s analysis also evaluated upgrades to the existing venturi scrubbers to potentially 

achieve greater SO2 control efficiency. Another option we have identified and are evaluating in 

this TSD is to use additional scrubbing reagent to achieve greater SO2 control efficiency of the 

existing venturi scrubbers, 

 We are not aware of any enforceable shutdown date for the Domtar Ashdown Mill Power 

Boiler No. 2, nor did Domtar’s 2014 BART analysis indicate any enforceable future planned 

shutdown. This means that the anticipated useful life of the boiler is expected to be at least as 

long as the capital cost recovery period of the add-on spray scrubbers. Therefore, a 30-year 

amortization period was assumed in the evaluation of the add-on spray scrubbers as the 

remaining useful life of the boiler. A 30-year amortization period was also assumed for the 

scrubber pump replacements required for using additional scrubbing reagent. 

Step 5- Evaluate Visibility Impacts 

 In the 2014 BART analysis, Domtar assessed the visibility improvement associated with 

the add-on spray scrubbers by modeling the controlled SO2 emission rate using CALPUFF, and 

then comparing the visibility impairment associated with the controlled emission rate to that of 

the baseline emission rate as measured by the 98th percentile modeled visibility impact. The 

tables below show the emission rates modeled and a comparison of the baseline (i.e., existing) 

visibility impacts and the visibility impacts associated with the add-on spray scrubbers. The 
116 

installation and operation of add-on spray scrubbers is projected to result in visibility 

improvement of 0.146 dv at Caney Creek. The visibility improvement is projected to range from 

0.026 to 0.053 dv at each of the other Class I areas. 

Table 71. Summary of Emission Rates Modeled for SO2 Controls for Domtar Power 

Boiler No.2

Scenario

NOX Emissions 

(lb/hr)

SO2

Emissions

(lb/hr)

PM10/PMF 

Emissions 

(lb/hr)

Baseline 526.8 788.2 81.6

Add-on Spray Scrubber 526.8 78.8 81.6

Table 72. Domtar Ashdown Mill Power Boiler No. 2: Summary of the 98th Percentile 

Visibility Impacts and Improvement due to Add-on Spray Scrubbers 

Class I area 

Baseline 

Visibility 

Impact112 

(dv)

Add-on Spray Scrubbers 

Visibility 

Impact 

(∆dv) 

Visibility Improvement 

from Baseline 

(∆dv) 

Caney Creek 0.844 0.698 0.146 

Upper Buffalo 0.146 0.093 0.053 

Hercules-Glades 0.105 0.054 0.051 

Mingo 0.065 0.039 0.026 

Cumulative Visibility Improvement 

(∆dv) -- -- 0.276 

 

 Using the visibility modeling analysis of the baseline visibility impacts from Power 

Boiler No. 2 and the visibility improvement projected from the installation and operation of new 

add-on spray scrubbers, we have extrapolated the visibility improvement projected as a result of 

using additional scrubbing reagent to increase the SO2 control efficiency of the existing venturi 

                                                            

112 The baseline visibility impacts reflect the operation of the existing venturi scrubbers. 
117 

scrubbers from the current control efficiency (estimated to be 69%) to 90%, or an outlet emission 

rate of 0.11 lb/MMBtu. We have assumed that the maximum 24-hour baseline emission rate used 

in the visibility modeling represents the operation of the existing venturi scrubbers at a 69% 

control efficiency. We estimate that the visibility improvement of using additional scrubbing 

reagent to increase the SO2 control efficiency of the existing venturi scrubbers to 90% control 

efficiency is 0.139 dv at Caney Creek and 0.05 dv or less at each of the other Class I areas (see 

table below). 

Table 73. Domtar Ashdown Mill Power Boiler No. 2: Summary of the 98th Percentile 

Visibility Impacts and Improvement from Use of Additional Scrubbing Reagent 

Class I area 

Baseline 

Visibility 

Impact 

(dv)

Add-on Spray Scrubber Impacts (dv) Estimated Impacts from Use of 

Additional Reagent (dv) 

Visibility Impact 

(dv) 

Visibility 

Improvement from 

Baseline 

(dv) 

Visibility Impact 

(dv) 

Visibility 

Improvement from 

Baseline 

(dv) 

Caney Creek 0.844 0.698 0.146 0.705 0.139

Upper Buffalo 0.146 0.093 0.053 0.096 0.05

Hercules-Glades 0.105 0.054 0.051 0.057 0.048

Mingo 0.065 0.039 0.026 0.04 0.025

Cumulative Visibility 

Improvement 

(dv) 

-- -- 0.276 -- 0.262

Our Proposed SO2 BART determination Power Boiler No. 2: 

 Taking into consideration the five factors, we propose to determine that SO2 BART for 

Power Boiler No. 2 is an emission limit of 0.11 lb/MMBtu on a 30 boiler-operating-day rolling 

average, which we estimate is representative of operating the existing scrubbers at 90% control 

efficiency. In this particular case, we define boiler-operating-day as a 24-hour period between 12 

midnight and the following midnight during which any fuel is fed into and/or combusted at any 

time in the Power Boiler. We are inviting public comment specifically on the appropriateness of 

this proposed SO2 emission limit. We believe that this emission limit can be achieved by using 

additional scrubbing reagent in the operation of the existing venturi scrubbers. We estimate that 

operating the existing scrubbers to achieve this level of control would result in visibility 

improvement of 0.139 dv at Caney Creek and 0.05 dv or lower at each of the other Class I areas. 
118 

We estimate the cumulative visibility improvement at the four Class I areas to be 0.262 dv. 

Based on the cost information provided by the facility, we have estimated that the use of 

additional scrubbing reagent to increase the control efficiency of the existing venturi scrubbers is 

estimated to cost $1,411/ton of SO2 removed. Based on Domtar’s BART analysis, new add-on 

spray scrubbers that would be operated downstream of the existing venturi scrubbers are 

projected to result in visibility improvement of 0.146 dv at Caney Creek and 0.053 dv or lower at 

each of the other Class I areas. The cumulative visibility improvement at the four Class I areas is 

projected to be 0.276 dv. The cost of add-on spray scrubbers is estimated to be $5,258/ton of SO2

removed, not including additional construction costs that would likely be incurred to make space 

to house the new scrubbers. We do not believe that the amount of visibility improvement that is 

projected from the installation and operation of new add-on spray scrubbers would justify their 

high average cost-effectiveness. The incremental visibility improvement of new add-on spray 

scrubbers compared to using additional scrubbing reagent to increase the control efficiency of 

the existing venturi scrubbers ranges from 0.001 to 0.007 dv at each Class I area, yet the 

incremental cost-effectiveness is estimated to be $16,752. We do not believe the incremental 

visibility benefit warrants the higher cost associated with new add-on spray scrubbers. Therefore, 

we are proposing to determine that SO2 BART for Power Boiler No. 2 is an emission limit of 

0.11 lb/MMBtu on a 30 boiler-operating-day rolling averaging basis, and are inviting comment 

on the appropriateness of this emission limit. We propose to require the facility to demonstrate 

compliance with this emission limit using the existing CEMS. Since the SO2 emission limit we 

are proposing can be achieved with the use of the existing venturi scrubbers but will require 

scrubber pump upgrades and the use of additional scrubbing reagent, we propose to require 

compliance with this BART emission limit no later than 3 years from the effective date of the 

final action, but are inviting public comment on the appropriateness of a compliance date 

anywhere from 1 – 5 years. 

 

NOX BART Evaluation for Power Boiler No. 2 

Step 1- Identify All Available Retrofit Control Technologies 

 For NOX BART, Domtar’s 2014 BART analysis evaluated LNB, SNCR, and Methane 

de-NOX (MdN). In the 2006/2007 Domtar BART analysis, which was submitted in the 2008 

Arkansas RH SIP, other NOX controls were also evaluated but found by the State to be either 

already in use or not technically feasible for use at Power Boiler No. 2. Fuel blending, boiler 

operational modifications, and boiler tuning/optimization are already in use at the source, while 

FGR, OFA, and SCR were found to be technically infeasible for use at Power Boiler No. 2. 

Domtar did not further evaluate these NOX controls, and instead focused on LNB, SNCR, and 

MdN in its 2014 BART analysis for Power Boiler No. 2. 
119 

Step 2- Eliminate Technically Infeasible Options

 MdN utilizes the injection of natural gas together with recirculated flue gases to create an 

oxygen-rich zone above the combustion grate. Air is then injected at a higher furnace elevation 

to burn the combustibles. In response to comments provided by us regarding Domtar’s 2014 

BART analysis, Domtar stated that discussions regarding the technical infeasibility of MdN in 

the 2006/2007 Domtar BART analysis, submitted as part of the 2008 Arkansas RH SIP, remain 

correct.113 The 2006/2007 Domtar BART analysis submitted in the 2008 Arkansas RH SIP 

discussed that MdN has not been fully demonstrated for this type of boiler and incorporates 

FGR, which is considered technically infeasible for use at Power Boiler No. 2. Domtar also 

stated it recently completed additional research and found that since the 2006/2007 Domtar 

BART analysis, MdN has not been placed into operation in power boilers at paper mills or any 

comparable source types. We are also not aware of any power boilers at paper mills that operate 

MdN for NOX control, and agree that this control can be considered technically infeasible for use 

at Power Boiler No. 2 and do not further consider it in this evaluation. Domtar also questioned 

the technical feasibility of SNCR for boilers with high load swing such as Power Boiler No. 2, 

but in response to comments from us, SNCR was evaluated in Domtar’s 2014 BART analysis. 

Step 3- Evaluate Control Effectiveness of Remaining Control Technologies: 

Based on vendor estimates, the 2006/2007 Domtar BART analysis estimated the potential 

control efficiency of LNB to be 30%. In Domtar’s 2014 BART analysis, SNCR was evaluated at 

a control efficiency of 27.5% and 35% for Power Boiler No. 2. These values were based on 

SNCR control efficiency estimates that came from the equipment vendor’s proposal,114 which 

according to the facility, is not an appropriations request level quote and therefore requires 

further refinement.115 For example, Domtar’s 2014 BART analysis discusses that for a base 

loaded coal boiler with steady flue gas flow patterns and temperature distribution across the flue 

gas pathway, SNCR is typically capable of achieving 50% NOX reduction. However, Power 

Boiler No. 2 is not a base loaded boiler and does not have steady flue gas flow patterns or steady 

temperature distribution across the flue gas pathway. 

To demonstrate the wide range in temperature at Power Boiler No. 2 and its relationship 

to steam demand, Domtar obtained an analysis of furnace exit gas temperatures for Power Boiler 

                                                            

113 See the document titled “Domtar Responses to ADEQ Regarding Region 6 Comments on Domtar BART 

Analysis,” p. 10. A copy of this document can be found in the docket for our proposed rulemaking. 

114 Fuel Tech Proposal titled “Domtar Paper Ashdown, Arkansas- NOX Control Options, Power Boilers 1 and 2,” 

dated June 29, 2012. A copy of the vendor proposal is included under Appendix D to the “Supplemental BART 

Determination Information Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),” originally dated June 28, 2013 

and revised on May 16, 2014, prepared by Trinity Consultants Inc. in conjunction with Domtar A.W. LLC. A 

copy of this BART analysis and its appendices is found in the docket for our proposed rulemaking. 

115 See the document titled “Domtar Responses to ADEQ Regarding Region 6 Comments on Domtar BART 

Analysis,” p. 9. A copy of this document can be found in the docket for our proposed rulemaking. 
120 

No. 2 from an engineering consultant.116 The furnace exit gas temperatures were analyzed for a 

12-day period that according to Domtar is representative of typical boiler operations. The 

consultant’s report indicated that furnace exit gas temperatures are representative of temperatures 

in the upper portion of the furnace, which is the optimal location for installation of the SNCR 

injection nozzles. The consultant estimated that 1700 – 1800°F represents the temperature range 

at which SNCR can be expected to reach 40% control efficiency at the current boiler operating 

conditions. It was found that there is wide variability in the furnace exit gas temperatures for 

Power Boiler No. 2, with temperatures ranging from 1000 – 2000°F. The data also indicate that 

there is a direct positive relationship between boiler steam demand and furnace exit gas 

temperatures. It was also found that Power Boiler No. 2 operated in the optimal temperature zone 

at which SNCR can be expected to reach 40% control efficiency for only a total of 20 hours over 

the 12-day period analyzed (288 continuous hours), which is approximately 7% of the time. 

According to Domtar, the significant temperature swings, which are due to load 

following and steam demand variability, create a scenario where urea injection will either be too 

high or too low. When not enough urea is injected, NOX removal will be less than projected and 

when too much urea is injected, excess ammonia slip will occur. Domtar stated that the observed 

significant temperature swings demonstrate that it will be difficult to maintain stable, optimal 

furnace temperatures at which urea can be injected to effectively reduce NOX with minimal 

ammonia slip. We agree that because of the wide variability in steam demand and wide range in 

furnace temperature observed at Power Boiler No. 2, the NOX control efficiency of SNCR at the 

boiler would not reach optimal control levels on a long-term basis. We also believe there is 

uncertainty as to the level of control efficiency that SNCR would be able to achieve on a longterm basis for Power Boiler No. 2. However, we further consider SNCR in the remainder of the 

analysis. 

 

Step 4- Evaluate Impacts and Document the Results 

 The four factors considered in this step are the costs of compliance, energy and non-air 

quality environmental impacts of compliance, existing pollution control technology in use at the 

source, and the remaining useful life of the source. 

In the 2006/2007 Domtar BART analysis, the capital cost, operating cost, and costeffectiveness of LNB were estimated based on vendor estimates.117 The analysis was based on a 

10-year amortization period, based on the equipment’s life expectancy. However, since we 

believe a 30-year equipment life is a more appropriate estimate for LNB, we have we have 

                                                            

116 September 12, 2014 letter from Annabeth Reitter, Corporate Manager of Environmental Regulation, Domtar, to 

Dayana Medina, U.S. EPA Region 6. A copy of this letter and its attachments are found in the docket for our 

proposed rulemaking 

117 See “Best Available Retrofit Technology Determination Domtar Industries Inc., Ashdown Mill (AFIN 41-

00002),” originally dated October 31, 2006 and revised on March 26, 2007, prepared by Trinity Consultants Inc. 

This BART analysis is part of the 2008 Arkansas RH SIP, upon which EPA took final action on March 12, 2012 

(77 FR 14604). A copy of this BART analysis is found in the docket for this proposed rulemaking. 
121 

adjusted Domtar’s cost estimate for LNB.118 The annual emissions reductions used in the costeffectiveness calculations were determined by subtracting the estimated controlled annual 

emission rate from the baseline annual emission rate. We have also adjusted the average costeffectiveness calculations presented in the 2006/2007 Domtar BART analysis for LNB by using 

the boiler’s actual annual uncontrolled NOX emissions rather than the maximum 24-hour 

emission rate as the baseline annual emissions. The table below summarizes the estimated cost of 

LNB for Power Boiler No. 2, based on our adjustments to the cost estimates in the 2006/2007 

Domtar BART analysis as discussed above. 

In Domtar’s 2014 BART analysis, the capital costs, operating costs, and costeffectiveness of SNCR were calculated based on methods and assumptions found in our Control 

Cost Manual, and supplemented with mill-specific cost information for water, fuels, and ash 

disposal and urea solution usage estimates from the equipment vendor.119 The two SNCR control 

scenarios evaluated were 27.5% and 35% control efficiencies. Domtar annualized the capital cost 

over a 30-year period and then added to the annual operating cost to obtain the total annualized 

costs. The annual emissions reductions associated with each NOX control option were 

determined by subtracting the estimated controlled annual emission rate from the baseline annual 

emission rate. The baseline annual emissions used in the calculations are the uncontrolled actual 

emissions from the 2001-2003 baseline period. The average cost-effectiveness was calculated by 

dividing the total annual cost by the estimated annual NOX emissions reductions. The table 

below summarizes Domtar’s estimate of the cost of SNCR for Power Boiler No. 2. 

Table 74. Summary of Cost of NOX Controls for Power Boiler No. 2 

NOX Control 

Scenario 

Baseline 

Emission 

Rate 

(NOX tpy) 

NOX

Removal 

Efficiency of 

Controls 

(%) 

Annual 

Emissions 

Reduction 

(NOX tpy) 

Capital Cost 

($) 

Total Annual 

Cost 

($/yr) 

Average Cost 

Effectiveness 

($/ton) 

Incremental 

CostEffectiveness 

($/ton) 

SNCR- 27.5% 1,536 27.5% 422 2,681,678 843,575 1,998 - 

LNB 1,536 30% 461 6,131,745 899,605 1,951 1,437 

SNCR- 35% 1,536 35% 537 2,877,523 1,026,214 1,909 1,666 

 

                                                            

118 See the spreadsheet titled “Domtar PB No2 LNB_cost revisions.” A copy of this spreadsheet is found in the 

docket for this proposed rulemaking. 

119 See “Supplemental BART Determination Information Domtar A.W. LLC, Ashdown Mill (AFIN 41-00002),” 

originally dated June 28, 2013 and revised on May 16, 2014, prepared by Trinity Consultants Inc. in conjunction 

with Domtar A.W. LLC. A copy of this BART analysis is found in the docket for our proposed rulemaking. 
122 

Domtar’s 2014 BART analysis did not identify any energy or non-air quality 

environmental impacts associated with the use of LNB or SNCR. We are not aware of any 

unusual circumstances at the facility that could create energy or non-air quality environmental 

impacts associated with the operation of NOX controls greater than experienced elsewhere and 

that may therefore provide a basis for the elimination of these control options as BART (40 CFR 

Part 51, Appendix Y, section IV.D.4.i.2.). Therefore, we do not believe there are any energy or 

non-air quality environmental impacts associated with NOX controls at Power Boiler No. 2 that 

would affect our proposed BART determination. 

 Consideration of the presence of existing pollution control technology at the source is 

reflected in the BART analysis in two ways: first, in the consideration of available control 

technologies, and second, in the development of baseline emission rates for use in cost 

calculations and visibility modeling. Power Boiler No. 2 is equipped with multiclones for 

particulate removal and two venturi scrubbers in parallel for control of SO2 emissions. It is also 

equipped with a combustion air system including overfire air to optimize boiler combustion 

efficiency, which also helps control emissions. The NOX baseline emission rate used in the cost 

calculations and visibility modeling reflects the use of these existing controls. 

 We are not aware of any enforceable shutdown date for the Domtar Ashdown Mill Power 

Boiler No. 2, nor did Domtar’s 2014 BART analysis indicate any future enforceable planned 

shutdown. This means that the anticipated useful life of the boiler is expected to be at least as 

long as the capital cost recovery period of controls. Therefore, a 30-year amortization period was 

assumed in the evaluation of LNB and SNCR as the remaining life of the boiler. 

Step 5- Evaluate Visibility Impacts 

 In the 2014 BART analysis, Domtar assessed the visibility improvement associated with 

LNB and SNCR by modeling the NOX emission rates associated with each control option using 

CALPUFF, and then comparing the visibility impairment associated with the baseline emission 

rate to the visibility impairment associated with the controlled emission rates as measured by the 

98th percentile modeled visibility impact. The tables below show the modeled emission rates and 

a comparison of the baseline (i.e., existing) visibility impacts and the visibility impacts 

associated with LNB and SNCR for each Class I area. 

Table 75. Summary of Emission Rates Modeled for SO2 Controls for Domtar Power 

Boiler No. 2

Scenario

NOX 

Emissions 

(lb/hr)

SO2

Emissions

(lb/hr)

PM10/PMF 

Emissions 

(lb/hr)

Baseline 526.8 788.2 81.6

Add-on Spray Scrubber 526.8 78.8 81.6
123 

Table 76. Domtar Ashdown Mill Power Boiler No. 2: Summary of the 98th Percentile 

Visibility Impacts and Improvement due to NOX Controls 

Class I area 

Baseline 

Visibility 

Impact (dv)

SNCR27.5% Control 

Efficiency 

LNB 

30% Control Efficiency 

SNCR35% Control Efficiency 

Visibility 

Impact 

(dv) 

Visibility 

Improvement 

from Baseline 

(dv) 

Visibility 

Impact 

(dv) 

Visibility 

Improvement 

from Baseline 

(dv) 

Incremental 

Visibility 

Improvement 

vs. 

SNCR 27.5% 

(dv) 

Visibility 

Impact 

(dv) 

Visibility 

Improvement 

from Baseline 

(dv) 

Incremental 

Visibility 

Improvement 

vs. 

SNCR 35% 

(dv) 

Caney Creek 0.844 0.678 0.166 0.663 0.181 0.015 0.632 0.212 0.031 

Upper Buffalo 0.146 0.134 0.012 0.132 0.014 0.002 0.129 0.017 0.003 

HerculesGlades 0.105 0.095 0.010 0.094 0.011 0.001 0.092 0.013 0.002 

Mingo 0.065 0.060 0.005 0.060 0.005 0.000 0.059 0.006 0.001 

Cumulative 

Visibility 

Improvement 

(dv) 

-- -- 0.193 -- 0.211 -- -- 0.248 -- 

 The table above shows that the installation and operation of SNCR when operated at 35% 

control efficiency, if feasible, is projected to result in visibility improvement of 0.212 dv at 

Caney Creek and 0.017 dv or less at each of the other Class I areas. When operated at 27.5% 

control efficiency, if feasible, SNCR is projected to result in visibility improvement of 0.166 dv 

at Caney Creek and 0.012 dv or less at each of the other Class I areas. The installation and 

operation of LNB is projected to result in visibility improvement of 0.181 dv at Caney Creek and 

0.014 dv or less at each of the other Class I areas. 

EPA’s Proposed NOX BART determination for Power Boiler No. 2: 

 Taking into consideration the five factors, we are proposing to determine that NOX

BART for the Domtar Ashdown Mill Power Boiler No. 2 is an emission limit of 345 lb/hr on a 

30 boiler-operating-day rolling averaging basis, based on the installation and operation of LNB. 

In this particular case, we define boiler-operating-day as a 24-hour period between 12 midnight 

and the following midnight during which any fuel is fed into and/or combusted at any time in the 

Power Boiler. MdN was determined to be not technically feasible for use at Power Boiler No. 2 

because it has not been fully demonstrated for this type of boiler and incorporates FGR, which is 

technically infeasible for use at the boiler. The installation and operation of SNCR is projected to 

result in some visibility improvement at the Class I areas when operated at 27.5% and 35% 
124 

control efficiency. However, based on the information provided by the facility, we believe that 

because of the wide variability in steam demand and wide range in furnace temperature observed 

in Power Boiler No. 2, the NOX control efficiency of SNCR at the boiler would not reach 

optimal control levels on a long-term basis. There is uncertainty as to the level of control 

efficiency that SNCR would be able to achieve on a long-term basis for Power Boiler No. 2. 

The installation and operation of LNB is projected to result in visibility improvement of 

0.181 dv at Caney Creek and 0.005 - 0.014 dv at each of the other Class I areas. The installation 

and operation of LNB is estimated to cost $1,951/ton of NOX removed, which we consider to be 

cost-effective. Therefore, we are proposing to determine that NOX BART for Power Boiler No. 2 

is an emission limit of 345 lb/hr on a 30 boiler-operating-day rolling average basis, based on the 

installation and operation of LNB. We are proposing to require compliance with this emission 

limit no later than 3 years from the effective date of the final rule, and are inviting public 

comment on the appropriateness of this compliance date. We are proposing that the facility 

demonstrate compliance with this emission limit using the existing CEMS. 

e. PM BART Evaluation for Power Boiler No. 2 

 PM BART for Power Boiler No. 2 is addressed in Domtar’s 2014 BART analysis. Power 

Boiler No. 2 is subject to the Boiler MACT standards required under CAA section 112, and 

found at 40 CFR Part 63, Subpart DDDDD – National Emission Standards for Hazardous Air 

Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process 

Heaters. Domtar streamlined the BART analysis for Power Boiler No. 2 by relying on the Boiler 

MACT standards for PM to satisfy the PM BART requirement. Power Boiler No. 2 was 

determined to fall under the “biomass hybrid suspension grate” subcategory for the Boiler 

MACT.120 As such, Power Boiler No. 2 is subject to the Boiler MACT PM emission limit of 0.44 

lb/MMBtu. The BART Guidelines provide that for VOC and PM sources subject to MACT 

standards, the BART analysis may be streamlined by including a discussion of the MACT 

controls and whether any major new technologies have been developed subsequent to the MACT 

standards.121 The BART Guidelines discuss that there are many VOC and PM sources that are 

well controlled because they are regulated by the MACT standards, and in many cases it will be 

unlikely that emission controls more stringent than the MACT standards will be identified 

without identifying control options that would cost many thousands of dollars per ton. Therefore, 

the BART Guidelines provide that unless there are new technologies subsequent to the MACT 

standards which would lead to cost-effective increases in the level of control, the MACT 

standards may be relied on for purposes of BART. 

                                                            

120 See letter dated October 28, 2013, from Thomas Rheaume, Permits Branch Manager, ADEQ, to Ms. Kelly 

Crouch, Manager of Environmental, Energy, and Pulp Tech. at Domtar Ashdown Mill. A copy of this letter is 

found in the docket for this proposed rulemaking. 

121 40 CFR Part 51, Appendix Y, section IV.C. 
125 

Domtar’s 2014 BART analysis does not discuss whether any new technologies 

subsequent to the MACT standards have become available and whether they would lead to costeffective increases in the level of PM control for Power Boiler No. 2. However, Domtar at one 

point estimated the cost of installing both an add-on spray scrubber and wet ESP on Power 

Boiler No. 2. Based on this cost information previously provided by Domtar,122 we have 

estimated that a wet ESP alone would have a purchased equipment cost (PEC) of $3.22 million 

and capital costs of approximately $11.3 million. The total annual cost of a wet ESP alone is 

estimated to be approximately $1.96 million. The average annual PM emissions from Power 

Boiler No. 2 for the 2001-2003 baseline period were 183 tpy. Assuming that the wet ESP has a 

95% control efficiency for PM emissions, we estimate that it would result in PM emissions 

reductions of 174 tpy. Based on this, we estimate that the average cost-effectiveness of installing 

and operating a wet ESP on Power Boiler No. 2 is $11,254/ton PM removed. Additionally, an 

examination of the species contribution to the 98th percentile visibility impacts shows that PM 

emissions contribute a very small portion of the visibility impairment attributable to Power 

Boiler No. 2. As shown in the table below, the baseline visibility impairment attributable to 

Power Boiler No. 2 is 0.844 dv at Caney Creek and 0.146 dv or less at each of the other Class I 

areas, based on the 98th percentile visibility impacts. The PM species contribute only 1.06 – 

4.58% of the baseline visibility impairment attributable to Power Boiler No. 2 at the modeled 

Class I areas. 

Table 77. Baseline Visibility Impairment and Species Contribution for Domtar Ashdown 

Mill- Power Boiler No. 2 

Emissions 

Unit Class I area 

98th 

Percentile 

Visibility 

Impacts 

(dv)123

Species Contribution to 98th Percentile 

Visibility Impacts 

98th

Percentile 

% SO4

98th 

Percentile 

% NO3

98th 

Percentile 

% PM10

98th 

Percentile 

% NO2

Power Boiler 

No. 2 

Caney Creek 0.844 22.04 70.68 4.58 2.69 

Upper Buffalo 0.146 76.99 20.76 2.26 0.00 

Hercules-Glades 0.105 61.17 37.68 1.06 0.09 

                                                            

122 The cost estimate of new add-on spray scrubbers and a wet ESP for Power Boiler No. 2 is found in Appendix B 

to the analysis titled “Supplemental BART Determination Information Domtar A.W. LLC, Ashdown Mill (AFIN 

41-00002),” dated June 28, 2013, prepared by Trinity Consultants Inc. in conjunction with Domtar A.W. LLC. A 

copy of the BART analysis is found in the docket for our proposed rulemaking

123 The visibility impact shown represents the highest 98th percentile value among the three modeled years. 
126 

Mingo 0.065 81.46 15.47 3.07 0.00 

EPA’s Proposed PM BART determination for Power Boiler No. 2: 

 

 Because of the very low baseline visibility impacts that are due to PM emissions from 

Power Boiler No. 2, we believe that there is potential for a very small amount of visibility 

improvement from the installation and operation of a wet ESP. We conclude that cost of 

installing and operating PM controls would not be justified in light of the relatively small amount 

of visibility improvement that could be achieved. Therefore, we are proposing to find that the 

current Boiler MACT PM standard of 0.44 lb/MMBtu satisfies the PM BART requirement for 

Power Boiler No. 2. We are also proposing that the same method for demonstrating compliance 

with the Boiler MACT PM standard is to be used for demonstrating compliance with the PM 

BART emission limit. Because we are proposing a BART emission limit that represents 

current/baseline operations and no control equipment installation is necessary, we are proposing 

that this emission limitation be complied with for BART purposes from the effective date of the 

final action. 

III. Reasonable Progress Goals 

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

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

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

(approximately) 10-year implementation period.124 The RHR does not mandate specific 

milestones or rates of progress, but instead calls for states to establish goals that provide for 

“reasonable progress” toward achieving natural (i.e., “background”) visibility conditions. 

 The RHR and section 169A of the CAA require the State, or EPA in the case of a FIP, to 

set RPGs by considering four factors: the costs of compliance, the time necessary for 

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

remaining useful life of any potentially affected sources (collectively “the RP factors”).125 States, 

or EPA in the case of a FIP, have considerable flexibility in how they take these factors into 

consideration, as noted in EPA’s Reasonable Progress Guidance.126 The RPGs must provide for 

an improvement in visibility on the most impaired days, and ensure no degradation in visibility 

                                                            

124 40 CFR 51.308(d), (f), and 70 FR 3915 125 40 CFR 51.308(d)(1)(i)(A) and CAA section 169A(g)(1). 

126 Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program, June 1, 2007, 

memorandum from William L. Wehrum, Acting Assistant Administrator for Air and Radiation, to EPA Regional 

Administrators, EPA Regions 1-10 (pp. 4-2, 5-1). 
127 

on the least impaired days during the planning period.127 Furthermore, if the projected progress 

for the worst days is less than the Uniform Rate of Progress (URP), then the state or EPA must 

demonstrate, based on the factors above, that it is not reasonable to provide for a rate of progress 

consistent with the URP.128 

A. Arkansas’ Reasonable Progress Goals – 2018 Visibility Projections 

 In the 2008 Arkansas RH SIP, which we partially approved and partially disapproved in 

March 12, 2012, the State adopted the CENRAP modeled 2018 visibility conditions as the RPGs 

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

2018 for the 20% worst days, which represents a 3.88 dv improvement over a baseline of 26.36 

dv. For Upper Buffalo, ADEQ established a RPG of 22.52 dv for 2018 for 20% worst days, 

which represents a 3.75 dv improvement over a baseline of 26.27 dv. 

 In our final action on the Arkansas RH SIP published on March 12, 2012, we 

disapproved the RPGs established by Arkansas for Caney Creek and Upper Buffalo because 

Arkansas did not establish the RPGs in accordance with the requirements of the CAA and the 

RHR.129 Specifically, Arkansas did not take into consideration the four RP factors in establishing 

its RPGs for Caney Creek and Upper Buffalo, stating that it was an unnecessary exercise. 

Arkansas believed, incorrectly, that no additional analysis of potential reasonable progress 

measures was necessary because visibility projections for the Class I areas indicated 

improvements in visibility consistent with the URP. As discussed in our disapproval action, a 

state must determine whether additional control measures are reasonable based on a 

consideration of the four RP factors. Accordingly, in this proposed rule, we are evaluating the 

four RP factors to determine whether additional controls are reasonable and we are establishing 

RPGs for Caney Creek and Upper Buffalo after consideration of the RP factors. 

 

B. Reasonable Progress Analysis 

A discussion of the particular pollutants that contribute to visibility impairment at 

Arkansas’ two Class I areas was provided in our October 17, 2011 proposed action on the 2008 

Arkansas RH SIP (see 76 FR 64186). In that proposed action, we explained that CENRAP used 

CAMx with its Particulate Source Apportionment (PSAT) tool to provide source apportionment 

by geographic region and major source category (i.e., point, natural, on-road, non-road, and area 

sources). 

Sulfate from all the source categories combined contributed 87.05 inverse megameters 

(Mm-1) out of 133.93 Mm-1 of light extinction at Caney Creek and 83.18 Mm-1 out of 131.79 

                                                            

127 Id.

128 40 CFR 51.308(d)(1)(ii). 

129 77 FR 14604, March 12, 2012.
128 

Mm-1 of light extinction at Upper Buffalo on the 20% worst days in 2002, which is 

approximately 65% and 63% of the total light extinction at each Class I area, respectively. 

Nitrate from all source categories combined contributed 13.78 Mm-1 out of 133.93 Mm-1 of light 

extinction at Caney Creek and 13.30 Mm-1 out of 131.79 Mm-1 of light extinction at Upper 

Buffalo, which is approximately 10% of the total light extinction in 2002 on the 20% worst days 

at each Class I area. 

The source category point sources contributed 81.04 Mm-1 out of 133.93 Mm-1 of light 

extinction at Caney Creek and 77.80 Mm-1 out of 131.79 Mm-1 of light extinction at Upper 

Buffalo on the 20% worst days in 2002 (see the tables below). This represents approximately 

60% of the total light extinction at each Class I area. Each of the source categories other than the 

point source category, contribute a much smaller proportion of the total light extinction at each 

Class I area. We are therefore focusing only on the point sources category in our reasonable 

progress analysis for this regional haze planning period. 

Sulfate from point sources contributed 75.1 Mm-1 out of 133.93 Mm-1 of light extinction 

at Caney Creek and 72.17 Mm-1 out of 131.79 Mm-1 of light extinction at Upper Buffalo, which 

is approximately 56% of the total light extinction at Caney Creek and 55% of the total light 

extinction at Upper Buffalo. Nitrate from point sources contributed 4.06 Mm-1 out of 133.93 

Mm-1 of light extinction at Caney Creek and 3.93 Mm-1 out of 131.79 Mm-1 of light extinction at 

Upper Buffalo, which is approximately 3% of the total light extinction at each Class I area. On 

the 20% worst days in 2002, sulfate from Arkansas point sources contributed 2.20% of the total 

light extinction at Caney Creek and 1.99% at Upper Buffalo, and nitrate from Arkansas point 

sources contributed 0.27% of the total light extinction at Caney Creek and 0.14% at Upper 

Buffalo.130 For both Caney Creek and Upper Buffalo, SO2 emissions (sulfate precursor) are the 

principal driver of regional haze on the 20% worst days in Arkansas’ Class I areas, as visibility 

impairment in 2002 on the 20% worst days is largely due to sulfate from point sources. 

 

Table 78. Modeled baseline light extinction for 20% worst days at Caney Creek Wilderness 

Area in 2002 (Mm-1) 

Total1

 Point Natural On-Road Non-Road Area 

SO4 87.05 75.10 0.09 1.19 1.70 5.66 

NO3 13.78 4.06 0.64 4.70 2.45 1.37 

POA 10.50 1.29 1.33 0.46 1.34 5.32 

                                                            

130 See the CENRAP TSD and the August 27, 2007 CENRAP PSAT tool 

(CENRAP_PSAT_Tool_ENVIRON_Aug27_2007.mdb). A copy of the CENRAP TSD and instructions for 

accessing the August 27, 2007 CENRAP PSAT tool can be found in the docket for this proposed rulemaking. 
129 

EC 4.80 0.19 0.33 0.86 1.79 1.40 

SOIL 1.12 0.19 0.01 0.01 0.01 0.87 

CM 3.73 0.21 0.04 0.03 0.02 3.19 

Sum 133.93 81.04 2.45 7.26 7.31 17.81 

1

Totals include contributions from boundary conditions. Sums include secondary organic matter. 

Table 79. Modeled baseline light extinction for 20% worst days at Upper Buffalo 

Wilderness Area in 2002 (Mm-1) 

Total1

 Point Natural On-Road Non-Road Area 

SO4 83.18 72.17 0.08 1.15 1.67 5.24 

NO3 13.30 3.93 0.61 4.14 2.71 1.23 

POA 10.85 1.06 1.33 0.47 1.38 5.75 

EC 4.72 0.16 0.31 0.80 1.93 1.30 

SOIL 1.21 0.20 0.02 0.01 0.01 0.93 

CM 6.85 0.29 0.05 0.05 0.02 6.02 

Sum 131.79 77.80 2.39 6.62 7.72 20.46 

1

Totals include contributions from boundary conditions. Sums include secondary organic matter. 

The CENRAP’s 2018 visibility projections show the total extinction at Caney Creek for 

the 20% worst days is estimated to be 85.84 Mm-1, which is a reduction of approximately 36% 

from 2002 levels (see table and figure below). The total extinction at Upper Buffalo for the 20% 

worst days in 2018 is estimated to be 86.16 Mm-1, which is a reduction of approximately 35% 

from 2002 levels (see the table and figure below). Sulfate from all source categories combined is 

projected to contribute 48.95 Mm-1 out of 85.84 Mm-1 of light extinction at Caney Creek on the 

20% worst days in 2018, or approximately 57% of the total light extinction. Nitrate from all 

source categories combined is projected to contribute 7.57 Mm-1 out of 85.84 Mm-1 of light 

extinction at Caney Creek on the 20% worst days in 2018, or approximately 9% of the total light 

extinction. 
130 

The other source categories are each projected to continue contributing a much smaller 

proportion of the total light extinction at each Class I area. At Upper Buffalo, sulfate from all 

source categories combined is projected to contribute 45.38 Mm-1 out of 86.16 Mm-1 of light 

extinction on the 20% worst days in 2018, which is approximately 53% of the total light 

extinction. Nitrate from all source categories combined is projected to contribute 9.22 Mm-1 out 

of 86.16 Mm-1 of light extinction on the 20% worst days at Upper Buffalo, which is 

approximately 11% of the total light extinction. 

Sulfate from point sources is projected to contribute 39.83 Mm-1 out of 85.84 Mm-1 of 

light extinction at Caney Creek on the 20% worst days in 2018, or approximately 46% of the 

total light extinction. Nitrate from point sources is projected to contribute 2.84 Mm-1 out of 85.84 

Mm-1 of light extinction at Caney Creek on the 20% worst days, which is approximately 3% of 

the total light extinction. At Upper Buffalo, sulfate from point sources is projected to contribute 

37.09 Mm-1 out of 86.16 Mm-1 of light extinction on the 20% worst days in 2018, which is 

approximately 43% of the total light extinction. On the 20% worst days in 2018, sulfate from 

Arkansas point sources is projected to contribute 3.58% of the total light extinction at Caney 

Creek and 3.20% at Upper Buffalo, and nitrate from Arkansas point sources is projected to 

contribute 0.29% of the total light extinction at Caney Creek and 0.25% at Upper Buffalo (see 

Figure 1).131 Based on the 2018 visibility projections, sulfate from point sources is expected to 

continue being the principal driver of regional haze on the 20% worst days at Arkansas Class I 

areas. 

Table 80. Modeled future light extinction for 20% worst days at Caney Creek Wilderness 

Area in 2018 (Mm-1) 

Total1

 Point Natural On-Road Non-Road Area 

SO4 48.95 39.83 0.07 0.12 0.44 5.31 

NO3 7.57 2.84 0.53 0.97 1.33 1.37 

POA 9.93 1.76 1.18 0.14 1.03 5.09 

EC 3.17 0.24 0.30 0.16 0.94 1.31 

SOIL 1.29 0.35 0.01 0.01 0.01 0.87 

CM 3.58 0.24 0.04 0.03 0.01 3.02 

                                                            

131 See the CENRAP TSD and the August 27, 2007 CENRAP PSAT tool 

(CENRAP_PSAT_Tool_ENVIRON_Aug27_2007.mdb). A copy of the CENRAP TSD and instructions for 

accessing the August 27, 2007 CENRAP PSAT tool can be found in the docket for this proposed rulemaking. 
131 

Sum 85.84 45.27 2.12 1.44 3.76 16.96 

1

Totals include contributions from boundary conditions and secondary organic matter. 

Figure 1. Extinction for 20% worst days at Caney Creek Wilderness Area in 2018 (Mm-1) 

CENRAP PSAT Projected W20% 2018 BEXT at Site CACR1 [Total=85.84,Rayleigh=12,SS=0.18]

0.00E+00

5.00E+00

1.00E+01

1.50E+01

2.00E+01

2.50E+01

3.00E+01

3.50E+01

4.00E+01

Elevated_Pt Low Level_Pt Natural OnRoad NonRoad Area EGU NonEGU IC BC SOAA SOAB

Source Category

Extinction (1/Mm)

SO4 NO3 POA EC SOIL CM SOAA SOAB

Table 81. Modeled future light extinction for 20% worst days at Upper Buffalo Wilderness 

Area in 2018 (Mm-1) 

Total1

 Point Natural On-Road Non-Road Area 

SO4 45.38 37.09 0.06 0.12 0.42 4.95 

NO3 9.22 3.48 0.63 1.10 1.81 1.48 

POA 10.17 1.48 1.20 0.14 1.01 5.49 

EC 3.07 0.21 0.28 0.15 0.99 1.21 
132 

SOIL 1.40 0.40 0.01 0.01 0.01 0.93 

CM 6.53 0.36 0.05 0.04 0.02 5.65 

Sum 86.16 43.02 2.24 1.57 4.25 19.71 

1

Totals include contributions from boundary conditions and secondary organic matter. 

Figure 2. Extinction for 20% worst days at Caney Creek Wilderness Area in 2018 (Mm-1) 

CENRAP PSAT Projected W20% 2018 BEXT at Site UPBU1 [Total=86.16,Rayleigh=9,SS=0.16]

0.00E+00

5.00E+00

1.00E+01

1.50E+01

2.00E+01

2.50E+01

3.00E+01

3.50E+01

4.00E+01

4.50E+01

Elevated_Pt Low Level_Pt Natural OnRoad NonRoad Area EGU NonEGU IC BC SOAA SOAB

Source Category

Extinction (1/Mm)

SO4 NO3 POA EC SOIL CM SOAA SOAB
133 

Table 82. Percentage of Total Extinction due to Arkansas Point Sources132

2002 2018 

CACR UPBU CACR UPBU 

Sulfate 2.20 1.99 3.58 3.20 

Nitrate 0.27 0.14 0.29 0.25 

As a starting point in our analysis to determine whether additional controls on Arkansas 

sources are reasonable in the first regional haze planning period, we examined the most recent 

SO2 and NOX emissions inventories for point sources in Arkansas. Based on the 2011 National 

Emissions Inventory (NEI), the Entergy White Bluff Plant, the Entergy Independence Plant, and 

the AEP Flint Creek Power Plant are the three largest point sources of SO2 and NOx emissions in 

Arkansas (see table below).133 The combined annual emissions from these three sources make up 

approximately 84% of the statewide SO2 point-source emissions and 55% of the statewide NOX

point-source emissions. We have evaluated White Bluff Units 1 and 2 and Flint Creek Unit 1 for 

controls under BART and are proposing to require these units to install SO2 and NOX controls to 

meet the BART requirements. We believe that our five-factor BART analysis for these three 

units is adequate for this first planning period to eliminate these sources from further 

consideration of controls under the reasonable progress requirements for this first regional haze 

planning period.. Compliance with the BART requirements is anticipated to result in a 

substantial reduction in SO2 and NOX emissions from these two facilities. The Entergy 

Independence Plant is not subject to BART, but its emissions were 30,398 SO2 tpy and 13,411 

NOX tpy based on the 2011 NEI. The Entergy Independence Plant is the second largest source of 

SO2 and NOX point-source emissions in Arkansas, accounting for approximately 36% of the SO2

point-source emissions and 21% of the NOX point-source emissions in the State. Additionally, as 

we discuss in more detail in the proceeding subsection, the White Bluff and Independence Plants 

are sister facilities with nearly identical units. Based on this, we expect that the cost-effectiveness 

of controls will be very similar for the two facilities. 

Table 83. Ten Largest SO2 and NOX Point Sources in Arkansas (NEI 2011 v1) 

Facility Name County NEI 2011 v1 Emissions 

(tpy) 

                                                            

132 See the CENRAP TSD and the August 27, 2007 CENRAP PSAT tool 

(CENRAP_PSAT_Tool_ENVIRON_Aug27_2007.mdb). A copy of the CENRAP TSD and instructions for 

accessing the August 27, 2007 CENRAP PSAT tool can be found in the docket for this proposed rulemaking. 133 See NEI 2011 v1. A spreadsheet containing the emissions inventory is found in the docket for our proposed 

rulemaking. 
134 

SO2 NOX

Entergy Arkansas- White Bluff Jefferson 31,684* 16,013*

Entergy-Services Inc- Independence Plant Independence 30,398 13,411

Flint Creek Power Plant (SWEPCO) Benton 8,620* 5,326*

FutureFuel Chemical Company Independence 3,421 385

Plum Point Energy Station Unit 1 Mississippi 2,830 1,525

Evergreen Packaging- Pine Bluff Jefferson 1,755 1,010

Domtar A.W. LLC, Ashdown Mill Little River 1,603* 3,152*

Albemarle Corporation- South Plant Columbia 1,279 443

Nucor-Yamato Steel Company Mississippi 607 263

Ash Grove Cement Company Little River 440 1,081

Georgia-Pacific LLC- Crossett Paper Ashley 215 2,402

Marion Intermodal Crittenden 12 1,328

Natural Gas Pipeline Co of America #308 Randolph 0.4 3,194

Natural Gas Pipeline Co of America #307 White 0.4 2,941

Natural Gas Pipeline Co of America #305 Miller 0.3 1,731

*Proposed FIP controls under BART requirements will result in emission reductions 

Because in our March 12, 2012 final partial approval and partial disapproval of the 2008 

Arkansas RH SIP we made a finding that Arkansas did not complete a reasonable progress 

analysis and did not properly demonstrate that additional controls were not reasonable under 40 

CFR 51.308(d)(1)(i)(A) and we disapproved the RPGs it established for Caney Creek and Upper 

Buffalo, we are required to complete the reasonable progress analysis and establish revised 

RPGs, unless we first approve a SIP revision that corrects the disapproved portions of the SIP 

submittal. As Arkansas has not as yet submitted a revised SIP following our partial disapproval, 

we must now complete the reasonable progress analysis and establish revised RPGs for Caney 

Creek and Upper Buffalo. We believe it is appropriate that our evaluation of the reasonable 

progress factors focuses on the Entergy Independence Power Plant because it is a significant 

source of SO2 and NOX, as it is the second largest point source for both NOX and SO2 point 

source emissions in the State. 

We believe it is appropriate to evaluate Entergy Independence even though Arkansas 

Class I areas and those outside of Arkansas most significantly impacted by Arkansas sources are 

projected to meet the URP for the first planning period. This is because we believe that in 
135 

determining whether reasonable progress is being achieved, it would be unreasonable to ignore a 

source representing more than a third of the State’s SO2 emissions and a significant portion of 

NOX point source emissions. The preamble to the Regional Haze Rule also states that the URP 

does not establish a “safe harbor” for the state in setting its progress goals.134 If the state 

determines that the amount of progress identified through the URP analysis is reasonable based 

upon the statutory factors, the state, or us in the case of a FIP, should identify this amount of 

progress as its reasonable progress goal for the first long-term strategy, unless it determines that 

additional progress beyond this amount is also reasonable. If the state or we determine that 

additional progress is reasonable based on the statutory factors, that amount of progress should 

be adopted as the goal for the first long-term strategy. 

In this proposed rulemaking, we are proposing controls for the largest and third largest 

point sources for both NOX and SO2 emissions in Arkansas under the BART requirements. As 

these two BART sources combined with Independence make up a large majority of the SO2 point 

source emissions (84%) and a large proportion of the NOX point source emissions (55%) in 

Arkansas, we believe that a sufficient amount of point source emissions in the State would be 

addressed in this first regional haze planning period by addressing the Independence facility in 

our reasonable progress analysis, which as we note above is the second largest source of both 

SO2 and NOX. We are proposing under Option 1 to control Entergy Independence for the first 

planning period for both SO2 and NOX. Alternatively, under Option 2, for the first planning 

period, we are proposing to control Entergy Independence only for SO2. 

The fourth largest SO2 and NOX point sources in Arkansas are the Future Fuel Chemical 

Company, with emissions of 3,421 SO2 tpy, and the Natural Gas Pipeline Company of America 

#308, with emissions of 3,194 NOX tpy (2011 NEI). In comparison to the emissions of the top 

three sources, emissions from these two facilities are relatively small. Therefore, we are not 

proposing controls in this first planning period for these two facilities because we believe it is 

appropriate to defer the consideration of any additional sources besides Independence to future 

regional haze planning periods. For Independence, however, under Option 1, in combination 

with the BART sources we would be addressing 84% of the SO2 point source emissions in the 

State and over 55% of the NOX point source emissions. Under Option 2, we would be deferring 

the consideration of additional NOX controls to future regional haze planning periods. . In the 

next section, we describe our consideration of the four reasonable progress factors for the 

Entergy Independence Plant as well as the CALPUFF modeling we conducted to assess the 

potential visibility benefits of controls.135

                                                            

134 See 64 FR 35732. 135 While visibility is not an explicitly listed factor to consider when determining whether additional controls are 

reasonable, the purpose of the four-factor analysis is to determine what degree of progress toward natural 

visibility conditions is reasonable. Therefore, it is appropriate to consider the projected visibility benefit of the 

controls when determining if the controls are needed to make reasonable progress. 
136 

1. Entergy Independence Plant Units 1 and 2 

a. Reasonable Progress Analysis for SO2 Controls 

 The Entergy Independence Plant is an electric generating station with two nearly identical 

coal-fired units (Units 1 and 2) with a nameplate capacity of 900 MW each. Units 1 and 2 are 

tangentially-fired boilers that burn sub-bituminous coal as their primary fuel and No. 2 fuel oil or 

Bio-diesel as the start-up fuel. To verify that the White Bluff and Independence Plants are sister 

facilities, we have constructed a master spreadsheet136 that contains information concerning 

ownership, location, boiler type, environmental controls and other pertinent information on these 

facilities. The spreadsheet includes information contained within EIA Forms 860 and 923. 

According to EIA,137 the boilers were manufactured by Combustion Engineering with 

installation dates of 1974 for White Bluff, and 1983 and 1984 for Independence. The two units at 

White Bluff and the two units at Independence are tangentially firing boilers having nameplate 

capacities of 900 MW and similar gross ratings. All four units burn coal from the Powder River 

Basin (PRB) of Wyoming with similar characteristics. All four units employ cold side ESPs for 

particulate collection. Other pertinent characteristics are similar. The layout of the White Bluff 

and Independence facilities are also very similar.138

Costs of Compliance: 

Due to the similarity of these facilities, we applied the total annualized dry FGD and wet 

FGD costs we developed for the White Bluff units to the Independence units. However, we 

adjusted the cost-effectiveness ($/ton) due to the differing baseline SO2 emissions from the units. 

Consistent with the cost estimate we developed for White Bluff, we estimated a total annual cost 

for dry FGD at Independence of approximately $31,981,230 at each unit.139 We expect dry FGD 

to achieve a controlled emission level of 0.06 lb/MMBtu, and estimate that the annual emissions 

reductions at Unit 1 would be 12,912 SO2 tpy, assuming baseline emissions140 of 14,269 SO2 tpy 

(see table below). The average cost-effectiveness of dry FGD at Unit 1 is estimated to be $2,477/ 

ton SO2 removed. For Unit 2, we estimate that the annual emissions reductions would be 13,990 

                                                            

136 This spreadsheet, entitled “EIA Consolidated Data_WB and Ind_Y2012.xlsx,” is located in the docket for our 

proposed rulemaking.

137 See “EIA Consolidated Data_WB and IND_Y2012.xlsx.” 138 See “Technical Support Document for the SDA Control Cost Analysis for the Entergy White Bluff and 

Independence Facilities Arkansas Regional Haze Federal Implementation Plan (SO2 Cost TSD),” Figures 1 and 2. 139 See “Technical Support Document for the SDA Control Cost Analysis for the Entergy White Bluff and 

Independence Facilities Arkansas Regional Haze Federal Implementation Plan (SO2 Cost TSD).” A copy of this 

TSD is found in the docket for our proposed rulemaking. 

140 Baseline emissions were determined by examining annual SO2 emissions for the years 2009-2013, eliminating 

the year with the highest emissions and the year with the lowest emissions, and obtaining the average of the three 

remaining years. 
137 

SO2 tpy, assuming baseline emissions of 15,511 SO2 tpy. The average cost-effectiveness of dry 

FGD at Unit 2 is estimated to be $2,286/ ton SO2 removed. 

Table 84. Summary of Dry FGD Costs for Entergy Independence Units 1 and 2 

Unit 

Baseline 

Emission 

Rate 

(SO2 tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Annual 

Emissions 

Reductions 

(SO2 tpy) 

Total Annual 

Cost 

($/yr) 

Average Cost 

Effectiveness 

($/ton) 

Unit 1 14,269 0.06 12,912 $31,981,230 $2,477

Unit 2 15,511 0.06 13,990 $31,981,230 $2,286

Because our proposed BART determination for the White Bluff facility is that dry FGD is 

more cost-effective (lower $/ton) than wet FGD, and that the additional visibility benefits 

obtained as a result of the greater level of control wet FGD offers over dry FGD are not worth 

the additional cost of wet FGD, we expect that the same would apply to Independence Units 1 

and 2. Therefore, our evaluation of SO2 controls for Independence Units 1 and 2 focuses on dry 

FGD. Nevertheless, we have calculated the cost-effectiveness of wet FGD for Independence 

Units 1 and 2 using the total annualized cost estimate provided by Entergy for White Bluff Units 

1 and 2, with certain adjustments we made to the cost estimate provided by the facility.141

Consistent with our estimate for White Bluff, we estimated a total annual cost for wet FGD at 

Independence of approximately $49,526,167 at each unit.142 We expect wet FGD to achieve a 

controlled emission level of 0.04 lb/MMBtu, and estimate that the annual emissions reductions at 

Unit 1 would be 13,364 SO2 tpy, assuming baseline emissions143 of 14,269 SO2 tpy (see table 

below). The average cost-effectiveness of wet FGD at Unit 1 is estimated to be $3,706/ton SO2

ton. For Unit 2, we estimate that the annual emissions reductions would be 14,497 SO2 tpy, 

assuming baseline emissions of 15,511 SO2 tpy. The average cost-effectiveness of wet FGD at 

Unit 2 is estimated to be $3,416/ton SO2 removed. 

Table 85. Summary of Wet FGD Costs for Entergy Independence Units 1 and 2 

                                                            

141 See our discussion above of the cost analysis for SO2 BART for White Bluff Units 1 and 2. 142 See our Cost Analysis TSD titled “Technical Support Document for the SDA Control Cost Analysis for the 

Entergy White Bluff and Independence Facilities Arkansas Regional Haze Federal Implementation Plan (SO2 Cost 

TSD).” The TSD is found in the docket for our proposed rulemaking. 

143 Baseline emissions were determined by examining annual SO2 emissions for the years 2009-2013, eliminating 

the year with the highest emissions and the year with the lowest emissions, and obtaining the average of the three 

remaining years.   
138 

Unit 

Baseline 

Emission 

Rate 

(SO2 tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Annual 

Emissions 

Reductions 

(SO2 tpy) 

Total Annual 

Cost 

($/yr) 

Average Cost 

Effectiveness 

($/ton) 

Unit 1 14,269 0.04 13,463 $49,526,167 $3,706 

Unit 2 15,511 0.04 14,532 $49,526,167 $3,416 

Time Necessary for Compliance: 

 As is generally the case for installation of scrubber controls on EGUs, we expect that 5 

years from the date of our final action would be sufficient time for Independence to install and 

operate either dry or wet FGD controls at Units 1 and 2 and to comply with the associated 

emission limits. 

 

Energy and Non-Air Quality Environmental Impacts of Compliance: 

 The installation and operation of wet FGD at Independence Units 1 and 2 would require 

greater energy usage and reagent usage compared to dry FGD. The cost of this additional energy 

usage and reagent usage has already been factored into the cost analysis. Non-air quality 

environmental impacts associated with wet FGD systems include increased water usage and the 

generation of large volumes of wastewater and solid waste/sludge that must be treated or 

stabilized before landfilling. Because the facility is not located in an exceptionally arid region, 

we do not anticipate that there would be water-availability issues that would affect the feasibility 

of wet FGD. Lastly, wet FGD systems have the potential for increased particulate and sulfuric 

acid mist releases that contribute to regional haze, which we are taking into consideration 

through an evaluation of the visibility benefits of each control option. 

Remaining Useful Life: 

 Independence Units 1 and 2 were installed in 1983 and 1984. Unit 1 was placed into 

operation in 1983 and Unit 2 was placed into operation in 1985. As there is no enforceable shutdown date for Units 1 and 2, we assume an equipment life of 30 years.144 

                                                            

144 As we note in our Oklahoma FIP, we typically assume a 30 year equipment life for scrubbers, as we do here. 

Please see Response to Technical Comments for Sections E. through H. of the Federal Register Notice for the 

Oklahoma Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA-R06-OAR-2010-

0190. Page 35. 
139 

Degree of Improvement in Visibility: 

 While visibility is not an explicitly listed factor to consider when determining whether 

additional controls are reasonable under the reasonable progress requirements, the purpose of the 

four-factor analysis is to determine what degree of progress toward natural visibility conditions 

is reasonable. Therefore, it is appropriate to consider the projected visibility benefit of the 

controls when determining if the controls are needed to make reasonable progress.145 There are 

four Class I areas within 300 km of the Entergy Independence Plant. We conducted CALPUFF 

modeling to determine the visibility improvement of SO2 controls at these Class I areas, based on 

the 98th percentile visibility impacts. (See Appendix C to this TSD for detailed discussion of the 

modeling protocol, model inputs and visibility modeling results). As shown in the tables below, 

both dry FGD and wet FGD are projected to result in considerable visibility improvement from 

the baseline at each modeled Class I area. For Unit 1, dry FGD is projected to result in almost 0.5 

dv of visibility improvement at each modeled Class I area, and for Unit 2 it is projected to result 

in almost or slightly greater than 0.5 dv of visibility improvement at each Class I area. The 

incremental visibility improvement of wet FGD over dry FGD is projected to be minimal, 

ranging from 0.008 – 0.028 dv at each Class I area for Unit 1 and 0.009 – 0.022 dv for Unit 2.

Dry FGD at both units is projected to result in visibility improvements ranging from 0.87 to 1.06 

dv at each class I area. We also modeled the visibility improvement anticipated from dry FGD at 

both units using an updated baseline emission level for NOX based on lower, more recent 

emissions. This modeled visibility improvement was similar to previous results with visibility 

improvements ranging from 0.97 to 1.08 dv at each class I area. See Appendix C to this TSD for 

detailed discussion of the modeling protocol, model inputs and visibility modeling results for 

each modeled control scenario.  

Table 86. Entergy Independence Unit 1: EPA Modeled Maximum 98th Percentile Visibility 

Impact and Improvement from SO2 Controls 

Class I Area Distance 

(km) 

Visibility Impact 

(∆dv) 

Visibility Improvement 

Over Baseline 

(dv) 

Incremental 

Visibility 

Improvement of 

Wet FGD vs. 

Baseline Dry FGD Dry 

FGD 

Wet 

FGD Dry FGD Wet FGD 

Caney Creek 277 1.133 0.657 0.64 0.476 0.493 0.017 

Upper Buffalo 180 0.845 0.385 0.377 0.460 0.468 0.008 

Hercules-Glades 173 0.793 0.295 0.267 0.498 0.526 0.028 

                                                            

145 See 79 FR at 74838, 74840, and 74874. 
140 

Mingo 174 0.739 0.298 0.284 0.441 0.455 0.014 

Total - 3.51 1.635 1.568 1.875 1.942 0.067 

Table 87. Entergy Independence Unit 2: EPA Modeled Maximum 98th Percentile Visibility 

Impact and Improvement from SO2 Controls 

Class I Area Distance 

(km) 

Visibility Impact 

(∆dv) 

Visibility Improvement 

Over Baseline 

(dv) 

Incremental 

Visibility 

Improvement of 

Wet FGD vs. 

Baseline Dry FGD Dry FGD 

Wet 

FGD Dry FGD Wet FGD 

Caney Creek 277 1.412 0.865 0.843 0.547 0.569 0.022 

Upper Buffalo 180 0.997 0.509 0.499 0.488 0.498 0.01 

Hercules-Glades 173 0.977 0.364 0.355 0.613 0.622 0.009 

Mingo 174 0.883 0.388 0.374 0.495 0.509 0.014 

Total - 4.269 2.126 2.071 2.143 2.198 0.055 

Table 88. Entergy Independence: EPA Modeled Maximum 98th Percentile Visibility Impact 

and Improvement of SO2 Controls (Facility-wide) 

Class I Area Distance 

(km) 

Visibility Impact 

(∆dv) 

Visibility Improvement 

Over Baseline 

(dv) 

Incremental 

Visibility 

Improvement of 

Wet FGD vs. Dry 

Baseline FGD Dry 

FGD 

Wet 

FGD Dry FGD Wet FGD 

Caney Creek 277 2.412 1.474 1.442 0.938 0.97 0.032 
141 

Upper Buffalo 180 1.764 0.876 0.86 0.888 0.904 0.016 

Hercules-Glades 173 1.704 0.648 0.608 1.056 1.096 0.04 

Mingo 174 1.547 0.676 0.649 0.871 0.898 0.027 

Total - 7.427 3.674 3.559 3.753 3.868 0.115 

Proposed Reasonable Progress Determination for SO2 for the Entergy Independence Plant: 

 Based on our analysis of the four RP factors, as well as the considerable projected 

visibility improvement, we propose to require compliance with an SO2 emission limit of 0.06 

lb/MMBtu for Independence Units 1 and 2 based on a 30 boiler-operating-day rolling average 

basis. We propose to find that this emission limit, which is based on the installation and 

operation of dry FGD, is cost-effective at $2,477/ ton SO2 removed for Unit 1 and $2,286/ton 

SO2 removed for Unit 2, and would result in significant visibility benefits at the Caney Creek 

and Upper Buffalo Wilderness Areas and the two Class I areas in Missouri. Under either Option 

1 or 2, we are proposing SO2 controls on Independence Units 1 and 2 for the first planning 

period. We note that more recent emission data show an overall increase in SO2 emissions from 

the facility. Therefore anticipated visibility improvement from controls would be anticipated to 

be larger and the $/SO2 ton reduced would be smaller had we used a more recent time period for 

the baseline emissions modeled. We found that in this instance, the cost of wet FGD on a dollars 

per ton removed basis is higher than that of dry FGD. We found the cost of wet FGD to be 

$3,706 and $3,416 per ton of SO2 removed at Units 1 and 2, respectively. We found the cost of 

dry FGD to be $2,477 and $2,286 per ton of SO2 removed for Units 1 and 2, respectively. We do 

not believe that the minimal amount of incremental visibility improvement projected to result 

from wet FGD justifies the higher cost compared to dry FGD. We are proposing to require 

compliance with an emission limit of 0.06 lb/MMBtu based on a 30 boiler-operating-day rolling 

average basis for Independence Units 1 and 2 no later than 5 years from the effective date of the 

final rule, based on the installation and operation of dry FGD. We are proposing that the facility 

demonstrate compliance with this emission limit using the existing CEMS. 
142 

b. Reasonable Progress Analysis for NOX controls 

As noted previously, monitoring data as well as CENRAP’s CAMx source apportionment 

modeling results for 2002 and 2018 show that visibility impairment is not projected to be 

significantly impacted by nitrate on the 20% worst days at Caney Creek or Upper Buffalo. Point 

source emissions of NOX are projected to contribute to less than 5% of the total impairment on 

the 20% worst days in both 2002 and 2018. The CENRAP CAMx source apportionment 

modeling does not provide visibility impairment estimates for individual facilities. 

As part of our analysis for Independence, we performed modeling using CALPUFF to 

assess the facility’s individual visibility impact and the visibility benefit of controls, as was done 

for the subject-to-BART units discussed above including the sister facility, White Bluff. 

CALPUFF is the recommended model146 for visibility impact analysis for BART determinations 

and other single source visibility modeling where the Class I areas of interest are within 300 km 

of the source. This modeling provided information on the total visibility impairment from 

emissions from the source, including impacts from SO2 and NOX emissions. The primary goal of 

this modeling was to assess the potential visibility benefit of SO2 controls, given the relatively 

large emissions of SO2 from the facility and that SO2 emissions are the primary cause of 

visibility impairment on the 20% worst days at the Class I areas of interest. The results of this 

analysis of SO2 controls are discussed in the section above. These CALPUFF results also 

indicated that impacts from NOX emissions can be significant on some days, and as discussed 

further below, NOX emission controls can be anticipated to result in a sizeable reduction in the 

maximum impacts from the facility. The analysis of the sister facility, Entergy Independence, 

revealed similar results. 

In evaluating CALPUFF modeling results for BART, the 98th percentile ranked impact 

(H8H) was used consistent with our guideline techniques in conducting the CALPUFF modeling. 

CALPUFF modeling provides an assessment of the near maximum (98th percentile) visibility 

impairment on nearby Class I areas from the source of interest based on the facility’s maximum 

short term emissions modeled over a three year period. It is important to note that a specific 

facility’s maximum impact on a Class I area may not correlate with the same meteorological 

conditions or days when visibility is most impaired at a particular Class I area since CALPUFF 

modeling is only for one facility and does not include other facilities and emissions sources. 

Because of the nature of visibility impairment, we consider it appropriate to assess visibility 

impacts from a single source against a natural background. Visibility impairment on the 20% 

worst days may be driven by impacts from other facilities and different meteorological 

conditions. Identification of the 20% worst days is determined by IMPROVE monitor data 

during the baseline period at each Class I area. The source apportionment results for the 20% 

worst days are then based on CAMx modeling using a single year of meteorological data (2002) 

and using estimates of actual emissions from 2002 and projected to 2018 for all emission sources 

in the modeling domain (continental U.S.). Due in large part to the difference in metrics between 

                                                            

146 70 FR 39104. 
143 

the maximum impact as modeled by CALPUFF and the average impact during the 20% worst 

days, the CALPUFF modeling results discussed below indicate a more significant impact than 

suggested by the source apportionment CAMx results. We also note that differences in the 

metrics examined (maximum 98th percentile impact versus average impact during the 20% worst 

days), emissions modeled (single–source maximum 24-hour actual emissions versus actual 

emissions from all emission sources147), and differences in chemistry models result in CAMx 

visibility analysis results for a source or group of sources being much lower in magnitude than 

visibility impacts as modeled by CALPUFF. 

The single source CALPUFF modeling shows that sizeable reductions to the maximum 98th

percentile visibility impact from the Independence facility may be achieved through NOX

controls.148 We recognize, however, that at this time, point source NOX emissions are not the 

main contributors to visibility impairment on the 20% worst days at Arkansas’ Class I areas, as 

projected by CAMx source apportionment modeling. Also, Arkansas Class I areas are projected 

to achieve progress greater than that needed to meet the URP. Because our assessment of the 

Independence facility indicates that it is potentially one of the largest single contributors to 

visibility impairment at Class I areas in Arkansas, we believe that it is appropriate to evaluate the 

appropriateness of NOX controls during this planning period. 

Costs of Compliance: 

As discussed above, due to the similarity of these facilities, we applied the total annualized 

LNB/SOFA cost developed by Entergy for White Bluff Units 1 and 2, with one line item 

revision made by us, to Independence Units 1 and 2.149 However, we adjusted the costeffectiveness ($/ton) due to the differing NOX emissions from the units. Since our proposed 

BART determination for the White Bluff facility is that LNB/SOFA is more cost effective (lower 

$/ton) than SNCR or SCR, and that the additional visibility benefits obtained as a result of the 

greater level of control SNCR and SCR offer over combustion controls are not worth the 

additional cost of SNCR or SCR, we expect that the same would apply to Independence Units 1 

and 2. Therefore, our evaluation of NOX controls for Independence Units 1 and 2 will focus 

solely on LNB/SOFA. 

Consistent with the cost estimate developed for White Bluff, we estimated a total annual 

cost for LNB/SOFA at Independence of approximately $1,085,904 at Unit 1 and $1,403,376 at 

                                                            

147 Emissions used in CALPUFF modeling represented the maximum 24-hour emission rate. Based on evaluation of 

some sources that had both annual and maximum 24-hour actual data, EPA recommended that sources could use an 

emission rate that was double the annual emission rate (used in CAMx) to approximate the maximum 24-hour actual 

emission rates for some sources for CALPUFF modeling when there was not enough data to generate a maximum 

24-hr actual emission rate. 

148 See “Degree of Improvement in Visibility” section below and Appendix C to this TSD for detailed discussion of 

the modeling protocol, model inputs and visibility modeling results. 

149 See our discussion above of the cost analysis for NOX BART for White Bluff Units 1 and 2, under section III.C.4 

of this proposed rulemaking. 
144 

Unit 2.150 We expect LNB/SOFA to achieve a controlled emission level of 0.15 lb/MMBtu, and 

estimate that the annual emissions reductions at Unit 1 would be 2,710 NOX tpy, assuming 

baseline emissions151 of 6,329 NOX tpy (see table below). The average cost-effectiveness of 

LNB/SOFA at Unit 1 is estimated to be $401/ton NOX removed. For Unit 2, we estimate that the 

annual emissions reductions would be 3,217 NOX tpy, assuming baseline emissions of 6,384 

NOX tpy. The average cost-effectiveness of LNB/SOFA at Unit 2 is estimated to be $436/ton 

NOX removed. 

Table 89. Summary of LNB/SOFA Costs for Entergy Independence Units 1 and 2 

Unit 

Baseline 

Emission 

Rate 

(NOX tpy) 

Controlled 

Emission 

Level 

(lb/MMBtu) 

Annual 

Emissions 

Reductions 

(NOX tpy) 

Total Annual 

Cost 

($/yr) 

Average Cost 

Effectiveness 

($/ton) 

Unit 1 6,329 0.15 2,710 $1,085,904 $401

Unit 2 6,384 0.15 3,217 $1,403,376 $436

Time Necessary for Compliance: 

As is generally the case for installation of NOX controls on EGUs, we expect that 3 years 

from the date of our final action would be sufficient time for Independence to install and operate 

LNB/SOFA controls at Units 1 and 2 and to comply with the associated emission limits. 

Energy and Non-Air Quality Environmental Impacts of Compliance: 

We are not aware of any energy or non-air quality environmental impacts that would 

preclude LNB/SOFA from consideration at Independence Units 1 and 2. 

Remaining Useful Life: 

Independence Units 1 and 2 were installed in 1983 and 1984. Unit 1 was placed into 

operation in 1983 and Unit 2 was placed into operation in 1985. As there is no enforceable shut-

                                                            

150 See the spreadsheet titled “Independence Cost Spreadsheet_ LNB-SOFA.” A copy of this spreadsheet is found in 

the docket for our proposed rulemaking. 

151 Baseline emissions were determined by examining annual NOX emissions for the years 2009-2013, eliminating 

the year with the highest emissions and the year with the lowest emissions, and obtaining the average of the three 

remaining years. 
145 

down date for Units 1 and 2, we presume that the units would continue to operate for greater than 

30 years and fully amortize the cost of controls. In our analysis of the cost of controls we have 

assumed an equipment life of 30 years. 

Degree of Improvement in Visibility: 

While visibility is not an explicitly listed factor to consider when determining whether 

additional controls are reasonable under the reasonable progress requirements, the purpose of the 

four-factor analysis is to determine what degree of progress toward natural visibility conditions 

is reasonable. Therefore, it is appropriate to consider the projected visibility benefit of the 

controls when determining if the controls are needed to make reasonable progress.152 There are 

four Class I areas within 300 km of the Entergy Independence Plant. We conducted CALPUFF 

modeling to determine the visibility improvement of NOX controls at these Class I areas, based 

on the 98th percentile visibility impacts.153 As shown in the table below, LNB/SOFA is projected 

to result in a visibility improvement from the baseline at each modeled Class I area.154 On a 

facility-wide basis, the installation and operation of LNB/SOFA on Units 1 and 2 is projected to 

result in 0.461 dv in visibility improvement at Caney Creek, while the projected visibility 

improvement at each of the other modeled Class I areas ranges from 0.213 – 0.264 dv. We also 

conducted a modeling run of both LNB/OFA and dry FGD, which shows projected visibility 

benefits ranging from 1.18 – 1.48 dv at each Class I area.155 As discussed above, more recent 

emission data show an overall increase in SO2 emissions from the facility. Therefore anticipated 

visibility improvement from controls would be anticipated to be larger and there would be an 

improvement in the cost-effectiveness (i.e., lower dollars per ton removed) of controls had we 

used a more recent time period for the baseline emissions modeled. 

                                                            

152 See 79 FR at 74838, 74840, and 74874. 

153 See Appendix C to the TSD, titled “Technical Support Document for Visibility Modeling Analysis for Entergy 

Independence Generating Station,” for a detailed discussion of the visibility modeling protocol and model inputs. 

154 Id. 155 This is discussed in more detail in Appendix C to the TSD, titled “Technical Support Document for Visibility 

Modeling Analysis for Entergy Independence Generating Station,” 
146 

Table 90. Entergy Independence Units 1 and 2 (Facility-Wide): EPA Modeled Maximum 

98th Percentile Visibility Impacts of LNB/SOFA 

Class I Area Distance 

(km) 

Visibility Impact 

(∆dv) 

Visibility Improvement 

of LNB/SOFA Over 

Baseline 

Baseline (dv) 156 LNB/SOFA 

Caney Creek 277 2.054 1.593 0.461 

Upper Buffalo 180 1.724 1.476 0.248 

Hercules-Glades 173 1.482 1.218 0.264 

Mingo 174 1.492 1.279 0.213 

Total - 6.752 5.566 1.186 

Proposed Reasonable Progress Determination for NOX for the Entergy Independence 

Plant: 

 

As discussed above, based on the CENRAP’s CAMx modeling, sulfate from point 

sources is the driver of regional haze at Caney Creek and Upper Buffalo on the 20% worst days 

in both 2002 and 2018. Nitrate from point sources is not considered a driver of regional haze at 

these Class I areas on the 20% worst days, contributing only approximately 3% of the total light 

extinction. The Regional Haze Rule requires that the established RPGs provide for an 

improvement in visibility for the most impaired days (i.e., the 20% worst days) over the period 

of the implementation plan and ensure no degradation in visibility for the least impaired days 

over the same period (40 CFR 51.308(d)(1)). Because of the small contribution of nitrate from 

point sources to the total light extinction at Caney Creek and Upper Buffalo on the most 

impaired days, we do not expect that NOX controls under the reasonable progress requirements 

would offer as much improvement on the most impaired days compared to SO2 controls. 

However, upon evaluation of the four reasonable progress factors, we found that the installation 

and operation of LNB/SOFA at Independence Units 1 and 2 is estimated to cost $401/NOX ton 

removed at Unit 1 and $436/NOX ton removed at Unit 2, which we consider to be very costeffective. These NOX controls are also projected to result in significant visibility improvements at 

                                                            

156 Baseline NOX emissions were updated to the maximum 24-hr emissions from 2011-2013 for the evaluation of the 

anticipated benefit from NOX controls. See Appendix C to the TSD for additional discussion of baseline emission 

rates. 

  
147 

Arkansas and Missouri Class I areas, based on CALPUFF modeling using the 98th percentile 

modeled visibility impacts. 

Therefore, under Option 1, for the first planning period, we are proposing both an SO2

emission limit as described above and a NOX emission limit of 0.15 lb/MMBtu on a 30 boileroperating-day averaging basis based on the installation and operation of LNB/SOFA, in light of 

their cost-effectiveness and visibility benefit based on CALPUFF modeling, even though nitrate 

from point sources is projected to contribute a very small proportion of the total light extinction 

at Caney Creek and Upper Buffalo on the 20% worst days in 2018. Based on our visibility 

modeling of both LNB/OFA and dry FGD, proposed Option 1 is projected to have visibility 

benefits ranging from 1.18 – 1.48 dv at each Class I area.157 Under Option 2, we are proposing 

only SO2 controls for Independence Units 1 and 2 under the reasonable progress requirements. 

Based on our visibility modeling of dry FGD, proposed Option 2 is projected to have visibility 

benefits ranging from 0.87 – 1.06 dv at each Class I area. We specifically solicit public comment 

on this proposed alternative approach. 

In addition to options 1 and 2, we also solicit public comment on any alternative SO2 and 

NOX control measures that would address the regional haze requirements for Entergy White 

Bluff Units 1 and 2 and Entergy Independence Units 1 and 2 for this planning period. This 

includes, but is not limited to, a combination of early unit shutdowns and other emissions control 

measures that would achieve greater reasonable progress than the BART and reasonable progress 

requirements we have proposed for these four units in this rulemaking. 

C. Proposed Reasonable Progress Goals 

We propose RPGs for Caney Creek and Upper Buffalo that are consistent with the 

combination of control measures from the approved portion of the 2008 Arkansas RH SIP and 

our proposed Arkansas RH FIP. In total, these final and proposed controls to meet the BART and 

RP requirements will result in higher emissions reductions and commensurate visibility 

improvements beyond what was in the 2008 Arkansas RH SIP. Development of refined 

numerical RPGs for Arkansas’ Class I areas would require photochemical grid modeling of a 

multistate area, involving thousands of emission sources, unlike the comparatively simple singlesource CALPUFF modeling used for individual BART assessments. In order to accurately reflect 

all emissions reductions expected to occur during this planning period, the new photochemical 

modeling would require an update of the emissions inventory for Arkansas and the surrounding 

states to include not just the actions under this FIP, but all EPA and state regulatory actions on 

point, area, and mobile sources. After the inventory is developed and reviewed by the affected 

                                                            

157 See Appendix C to the TSD, titled “Technical Support Document for Visibility Modeling Analysis for Entergy 

Independence Generating Station,” for a detailed discussion of the visibility modeling protocol and model inputs. 
148 

states for accuracy, it must be converted to a model-ready format before air quality modeling can 

be used to estimate the future visibility levels at the Class I areas. This modeling would require 

specialized and extensive computing hardware and expertise. Developing all of the necessary 

input files, running the photochemical model, and post-processing the model outputs would take 

several months at a minimum. Therefore, we are not conducting new photochemical grid 

modeling to establish revised numeric RPGs for Caney Creek and Upper Buffalo. 

In order to provide RPGs that account for emission reductions from the FIP controls, we 

have used a method similar to the one used in our Regional Haze FIP for Hawaii158 and 

Arizona,159 which is based on a scaling of visibility extinction components in proportion to 

emission changes. To determine the new RPGs for Caney Creek and Upper Buffalo, we started 

with the 2018 projection of extinction components from the CENRAP’s CAMx photochemical 

modeling with source apportionment. The 2018 CAMx emission scenario included some 

assumptions of state BART determinations and other SIP controls, as well as projected emissions 

from other point, area, and mobile sources. We scaled the modeled visibility extinction 

components for sulfate (SO4) and nitrate (NO3) from point sources in Arkansas (Table 92) in 

proportion to the FIP’s emission reductions for SO2 and NOX, respectively. The sulfate scaling 

factor was the 2018 CENRAP emission inventory for Arkansas point source SO2 emissions with 

FIP controls for BART and RP sources in place, divided by the original 2018 CENRAP emission 

inventory for Arkansas point source SO2 emissions (Table 91). We conducted the same scaling 

exercise with nitrate and NOX. The scaled sulfate and nitrate extinctions were added to the 

unscaled extinctions for organic mass and other components to get total extinction, and then this 

was used to calculate post-FIP RPGs in deciviews.160 Although we recognize that this method is 

not refined, it allows us to translate the emission reductions contained in this proposed FIP into 

quantitative RPGs, based on modeling previously performed by the CENRAP. 

Table 91. 2018 CENRAP CAMx modeled extinction due to Arkansas point sources 

(Mm-1)

161

CACR UPBU 

Sulfate 3.0726 2.7601 

Nitrate 0.2498 0.2120 

                                                            

158 See 77 FR 31692, 31708. 

159 See 79 FR 52420, 52468. 

160 See “CACR UPBU RPG analysis.xlsx” in the docket for this proposed rulemaking for additional details on these 

calculations. 

161 See the CENRAP TSD and the August 27, 2007 CENRAP PSAT tool 

(CENRAP_PSAT_Tool_ENVIRON_Aug27_2007.mdb). A copy of the CENRAP TSD and instructions for 

accessing the August 27, 2007 CENRAP PSAT tool can be found in the docket for this proposed rulemaking.
149 

Table 92. Nitrate and Sulfate Scaling Factors for 2018 RPG calculation 

2018 CENRAP Arkansas Point 

Source Emissions 

(tpy) 

FIP Emission 

reductions162 Scaling factor 

Option 1 Option 2 Option 1 Option 2 

NOX 71,107 8,745 1,219 0.8770 0.9829 

SO2 106,461 69,128 69,128 0.3507 0.3507 

These RPGs reflect rates of progress that are faster than the rates projected by Arkansas. 

The revised RPGs for the first planning period for the 20% worst days are 22.27 dv for Caney 

Creek and 22.33 dv for Upper Buffalo. The results of our analysis are shown in the table 

below.163 The RPG calculation was performed for both our proposed Options 1 and 2. Under 

Option 1 we are proposing to control Entergy Independence Units 1 and 2 for the first planning 

period for both SO2 and NOX. Alternatively, under Option 2, we are proposing to control Entergy 

Independence Units 1 and 2 only for SO2 for the first planning period. Due to the small impact 

from all Arkansas point source NOx emissions combined on the 20% worst days and the scaling 

approach utilized to estimate the adjustment to the RPG, the difference between the two 

proposed options results in a very small difference in the calculated 2018 RPGs for the 20% 

worst days for Caney Creek and Upper Buffalo (less than 0.003 dv). We note that some FIP 

controls will not be in place by 2018, however, for the purpose of this calculation, we included 

reductions from all FIP controls. Arkansas will have to re-evaluate during the next regional haze 

planning period what BART and reasonable progress controls are in place and re-calculate the 

RPGs for the next planning period as needed. We also note that RPGs, unlike the emission limits 

that apply to specific RP sources, are not directly enforceable.164 Rather, they are an analytical 

framework considered by us in evaluating whether measures in the implementation plan are 

sufficient to achieve reasonable progress.165 Arkansas may choose to use these RPGs for 

purposes of its progress report, or may develop new RPGs for approval by us along with its 

progress report, based on new modeling or other appropriate techniques, in accordance with the 

requirements of 40 CFR 51.308(d)(1). 

                                                            

162 NOX FIP emission reductions also include adjustments to AECC Bailey and Lake Catherine units 1,2, and 3 to 

recent actual emissions (average from 2009-2013, excluding the maximum and minimum year). These gas units 

were projected for early retirement (see ipmcair2020parsed.xls in the docket for this proposed rulemaking) by 

2018 in the CENRAP 2018 emission inventory. 

163 Please see Appendix C to the TSD, titled “Technical Support Document for Visibility Modeling Analysis for 

Entergy Independence Generating Station,” and the RPG calculation spreadsheet for additional details on 

calculations. These documents are found in the docket for our proposed rulemaking. 164 40 CFR 51.308(d)(1)(v). 

165 64 FR 35733 and 40 CFR 51.308(d)(1)(v). 
150 

Table 93. Proposed Reasonable Progress Goals for 20% Worst Days (In deciviews) 

Class I 

area 

2000-2004 

baseline 

2064 

natural 

conditions 

2018 

URP 

2018 

Projection 

by 

CENRAP 

Estimated 

FIP effect 

Estimated 

FIP 2018 

RPG 

Caney Creek 26.36 11.58 22.91 22.48 -0.21 22.27 

Upper 

Buffalo 26.27 11.57 22.84 22.52 -0.19 22.33 

IV. Our Proposed Long-Term Strategy 

 Section 169A(b) of the CAA and 40 CFR 51.308(d)(3) require that states include in their 

SIP a 10 to 15-year strategy, referred to as the long-term strategy, for making reasonable 

progress for each Class I area within their state. This long-term strategy is the compilation of all 

control measures a state will use during the implementation period of the specific SIP submittal 

to meet any applicable RPGs for a particular Class I area. The long-term strategy must include 

“enforceable emissions limitations, compliance schedules, and other measures as necessary to 

achieve the reasonable progress goals” for all Class I areas within, or affected by emissions from, 

the state.166

 Section 51.308(d)(3)(v) requires that a state consider certain factors (the long-term 

strategy factors) in developing its long-term strategy for each Class I area. These factors are the 

following: (1) emission reductions due to ongoing air pollution control programs, including 

measures to address RAVI; (2) measures to mitigate the impacts of construction activities; (3) 

emissions limitations and schedules for compliance to achieve the reasonable progress goal; (4) 

source retirement and replacement schedules; (5) smoke management techniques for agricultural 

and forestry management purposes including plans as currently exist within the state for these 

purposes; (6) enforceability of emissions limitations and control measures; and (7) the 

anticipated net effect on visibility due to projected changes in point, area, and mobile source 

emissions over the period addressed by the long-term strategy. Since states are required to 

consider emissions limitations and schedules of compliance to achieve the RPGs for each Class I 

area, the BART emission limits that are in the state’s regional haze SIP are an element of the 

state’s long-term strategy (40 CFR 51.308(d)(3)) for each Class I area. In our March 11, 2012 

final action on the 2008 Arkansas RH SIP, since we disapproved a portion of Arkansas’ BART 

determinations and both RPGs for Arkansas’ two Class I areas, we also disapproved these 

                                                            

166 40 CFR 51.308(d)(3). 
151 

elements and approved all other elements of Arkansas’ long-term strategy. The BART limits and 

two RPGs for Arkansas’ Class I areas that are in this proposed FIP address our March 11, 2011 

disapproval of Arkansas’ BART limits and two RPGs. We propose to find that the proposed 

BART limits and two RPGs that are in this proposed FIP also correct the deficiency in Arkansas’ 

long-term strategy for each of its Class I areas.