# 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 20152 

### 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 Disapprova l of the Arkansas Regional Haze SIP D. Portions of the Arkansas Re gional Haze SIP Disapproved by EPA

II. Best Available Retrof it Technology (BART) A. Identification of BART Eligible So urces and Subject to BART Sources 1. Georgia-Pacific Crossett Mill 6A and 9A Power Boilers 2. AECC Carl E. Bailey Gene rating 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 Analys is of Point Sources B. Reasonable Progress Goals

IV. Long-term Strategy

Appendix A. Technical Support Document for th e SDA Control Cost Analysis for the Entergy White Bluff and Independence Facilities Arkans as Regional Haze Federal Implementation Plan (SO 2 Cost TSD)
Appendix B. Technical Support Document for Ar kansas Regional Haze Best Available Retrofit Technology (BART) Modeli ng Protocol Review
Appendix C. Technical Support Document for Visibility Modeling Analysis for Entergy Independence Generating Station3 

### Technical Support Document for EPA’s Proposed Action on the Arkansas Regional Haze Fe deral 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 ge ographic area and emit fine particulates (PM 2.5 ) (e.g., sulfates, nitrates, organic carbon (OC), elem ental carbon (EC), and so il dust), and their precursors (e.g., sulfur dioxide (SO 2 ), nitrogen oxides (NOx), a nd in some cases, ammonia (NH 3 ) and volatile organic compounds (VOC)). Fine particle precursors react in the atmosphere to form PM 2.5 , which impairs visibility by sc attering and absorbing light. Vi sibility impairment reduces the clarity, color, and visible distance that one can see. PM 2.5 can also cause serious health effects and mortality in humans and contributes to envi ronmental effects such as acid deposition and eutrophication. Data from the existing visibility monito ring network, the “Interagency Monitoring of Protected Visual Environments” (IMPROVE) monitoring network, show that visibility impairment caused by air pollution occurs virtuall y all the time at most national parks (NPs) and wilderness areas (WAs). The average visual range 1 in many Class I areas ( i.e. , NPs and memorial parks, WAs, and international park s meeting certain size criteria) in the western United States is 100-150 kilometers, or about one-half to two-thirds of the visu al 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 kilo meters, or about one-fifth of th e 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 cont ain 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 ex tinction, visual range, contrast, or coloration.”4 long-term strategy that ensures reasonable progre ss toward achieving natura l 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 estab lish 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 m easures as necessary to achieve the RPG. Regional haze plans must also give specific attenti on 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 Retrof it 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 visibili ty. (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 approve d, 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 re vision correcting the deficienci es before promulgating a FIP. (CAA section 110(c)(1)). To address the first implementation period, th e 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 re gional 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, with in 2 years of the fi nal disapproval action we are required to approve a SIP revision submit ted by the State or promulgate a FIP to address the disapproved portions of the SIP unless we first approve a SIP re vision correcting the deficiencies before promul gating 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 re quired 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)], or5 (B) disapproves a state implementation plan submission in whole or in part, unless the state corrects the deficiency, and the Administ rator approves the plan or plan revision, before the Administrator promulgates such Federal implementation plan.

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

[A] plan (or portion thereof) pr omulgated 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 emissi on limitations or other control measures, means or techniques (including economic incen tives, such as marketable permits or auctions or emissions allowances)* * *.

Thus, because we partially disapproved th e 2008 Arkansas RH SIP and the SIP submittal addressing the interstate visibili ty 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 s ubmitted a revised SIP following our partial disapproval, and more than two years have pa ssed since EPA partially disapproved Arkansas’ RH SIP. Thus, EPA is under an obligation to pr omulgate a Regional Haze FIP to correct the portions of the SIP that we disa pproved. We are proposing a FIP to address those portions of the SIP that we disapproved.

D. Portions of the Arkansas Region al Haze SIP Disapproved by EPA

In our March 12, 2012, final partial approval and partia l disapproval of the 2008 Arkansas RH SIP, we disapproved the followi ng BART determinations made by Arkansas:

 SO 2 , NO X , and PM BART for the Arkansas Elec tric Cooperative Corporation (AECC) Carl E. Bailey Generating Station Unit 1;

 SO 2 , NO X , and PM BART for the AECC John L. Mc Clellan Generating Station Unit 1;

 SO 2 and NO X BART for the American Electric Po wer (AEP) Flint Creek Power Plant No. 1 Boiler;

 SO 2 and NO X BART for the bituminous and sub-b ituminous coal firing scenarios for the Entergy White Bluff Plant Units 1 and 2;

 SO 2 , NO X , 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;

 SO 2 , NO X , and PM BART for the fuel oil firing s cenario for the Entergy Lake Catherine Plant Unit 4;

 SO 2 and NO X BART for the Domtar Ashdown Mill No. 1 Power Boiler; and

 SO 2 , NO X , and PM BART for the Domtar Ashdown Mill No. 2 Power Boiler.6 In our final action we also disapproved Arka nsas’ determinations that the Georgia-Pacific Crossett Mill 6A Boiler is not BART eligible, and that the 6A and 9A Boile rs are not subject to BART. By partially disapproving Arkansas’ BA RT determinations, we also partially disapproved the corresponding Arkansas Pollu tion 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 Arkans as 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, th e 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 CF R section 51.308(d)(1)(i )(A) to consider and provide an analysis of the four factors that states are re quired to consider in es tablishing 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 Fe deral 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 th ree appendices that suppor t our proposal: Appendix A to this TSD contains a report de tailing our cost analysis for SO 2 controls at the Entergy White Bluff and Entergy Independence facilities; Appendi x B to this TSD contai ns a report describing our review of the BART modeli ng protocol developed by Trinity Consultants on behalf of the BART sources; and Appendix C to this TSD cont ains 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 ba sis for this action when needed. In some of the non-technical area s, our Federal Register notice pr ovides more detail than does this TSD. Also, this TSD treats the requirement s of section 51.308 in the order in which they appear in that regulation, wh ereas our Federal Register notic e groups the requirements into related areas so the concepts can be understood more easily. In th is regard, the TSD can serve as a checklist of whether the requirements have been addressed. Throughout this document, we often use language such as, "we find ” or other similar phrases that on the surface woul d suggest a final determination has been made. However, all aspects of our TSD should be considered to be part of our proposal and are subject to change based on comments and other information we ma y receive during our public comment period.

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 Guidelin es (70 FR 39158) and the Regional Haze regulations (40 CFR 51.301): (1) One or more em ission units at the facility fit within one of the 26 categories listed in the BART Guide lines; (2) the emission uni t(s) began operation on or after August 6, 1962, and the unit was in ex istence on August 6, 1977; and (3) the potential emissions of any visibility-impai ring pollutant from subject units are 250 tons or more per year. Sources that meet these three criteria are cons idered BART-eligible. Once a list of the BARTeligible sources within a state has been compile d, 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 vi sibility impairment in a Class I area. The BART Guidelines present several op tions that rely on mode ling analyses and/or emissions analysis approaches to determine if a source may reasonably be anticipated to cause or contribute to visibility impair ment in a Class I area. A sour ce that may not be reasonably anticipated to cause or c ontribute to any visibility impairment in a Class I area is not “subject to BART,” and for such sources, a state need not a pply 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 appr oved Arkansas’ identification of BARTeligible sources, with the exception of the Geor gia-Pacific Crossett Mill 6A Boiler. We also approved the State’s determination of which sour ces 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 no t subject to BART is found in our October 17, 2011 proposed rulema king, March 12, 2012 final rulemaking, and the associated TSDs. 3 A revised Title V permit for the Georgia-Pa cific Crossett Mill wa s issued on August 4, 2011, and again on May 23, 2012. Although no actual pollution controls we re installed, the permitted emission limits for SO 2 and PM 10 for the 6A Boiler and SO 2 , NO X , and PM 10 for the 9A Boiler were revised so as to be mo re stringent. In a letter dated May 18, 2012, 4 GeorgiaPacific explained to ADEQ that it had conducte d 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, Environmen tal Services Superintendent at Georgia-Pacific Crossett

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

5 See ADEQ Operating Air Permit No. 0597-AOP-R14, issu ed 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 ta ble below. Based on modeling of the current permit limits, the boilers’ maximum visibi lity 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 visib ility impairment by the 6A and 9A Boilers, and that the boilers are therefore not subject to BART.

Table 1. Maximum Modeled Visibility Im pacts from 6A and 9A Boilers (Georgia-Pacific’s 2011 Di spersion 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 th e 6A and 9A Boilers ar e not subject to BART. Georgia-Pacific calculated maximum 24-hour em ission 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 rate s it modeled in the 2011 BART sc reening modeli ng. 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 SO 2 , NO X , and PM 10 (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, Environmen tal Services Superintendent at Georgia-Pacific Crossett

Paper Operations, to Mary Pettyjohn, ADEQ. A copy of th is 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 chap ters available in Volume I, Stationary Point and Area Sources. The latest emissions factors are av ailable 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 baseli ne 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 Factor 8 (converted to appropriate units) Natural Gas Firing (6A and 9A Boilers)

PM 10 7.6 lb/MM ft 3 0.0076 lb/M ft 3 SO 2 0.6 lb/MM ft 3 0.0006 lb/M ft 3 NO X 280 lb/MM ft 3 0.28 lb/M ft 3 Bark Firing (9A Boiler)

PM 10 0.066 lb/MMBtu 0.594 lb/ton SO 2 0.025 lb/MMBtu 0.225 lb/ton NO X 0.22 lb/MMBtu 1.98 lb/ton

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

Jan 1, 2001 -- Gas usage for 24-hour period = 459 M ft 3

PM 10 (lb/hr) = 459 M ft 3 / 24 hr x 0.0076 lb/M ft 3 = 0.145 lb/hr
SO 2 (lb/hr) = 459 M ft 3 / 24 hr x 0.0006 lb/M ft 3 = 0.0115 lb/hr
NO X (lb/hr) = 459 M ft 3 / 24 hr x 0.28 lb/M ft 3 = 5.355 lb/hr

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

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

PM 10 (lb/hr) = 814 tons/ 24 hr x 0.594 lb/ton bark = 20.15 lb/hr
SO 2 (lb/hr) = 814 tons/ 24 hr x 0.225 lb/ton bark = 7.63 lb/hr
NO X (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 ft 3 to be consistent with the fuel usage units of measure used in the Georgia-Pacific Crosse tt 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 ft 3

PM 10 (lb/hr) = 2,513 M ft 3 / 24 hr x 0.0076 lb/M ft 3 = 0.8 lb/hr
SO 2 (lb/hr) = 2,513 M ft 3 / 24 hr x 0.0006 lb/M ft 3 = 0.063 lb/hr
NO X (lb/hr) = 2,513 M ft 3 / 24 hr x 0.19 lb/M ft 3 = 19.9 lb/hr

Total PM 10 = 20.15 + 0.8 = 20.95 lb/hr Total SO 2 = 7.63 + 0.063 = 7.69 lb/hr Total NO X = 67.15 + 19.9 = 87.0 lb/hr

After calculating the 24-hour po llutant emission rate for eachday of the year, GeorgiaPacific determined the maximum 24-hour emissi on rate by using the “max” function of Excel. 9 For estimating the maximum 24-hour emission rate for PM 10 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 thos e calculated using AP-42 emission factors. The table below shows the maximum 24-hour emission rates during the baseli ne period for the 6A and 9A Boilers.

Table 3. Maximum 24-hour Emission Rate s from the 2001 – 2003 Baseline Period
Maximum 24-hour Emission Rates (lb/hr)

Unit SO 2 NO X PM 10
6A Boiler 0.2 90.7 2.5
9A Boiler 17.9 174.1 72.0

Georgia-Pacific then compared the calcula ted 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 scr eening modeling, and that the modeled emission rates are approximately equal to the curre ntly 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, issu ed 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 Emis sion Rates with Modeled Emission Rates and Title V Permit Limits

6A Boiler
SO 2 NO X PM 10 Calculated Maximum 24-hr Em ission 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
SO 2 NO X PM 10 Calculated Maximum 24-hr Em ission 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 re asonable to determine that the boilers had visibility impact s 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 bo ilers 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 pr ovided analysis allows for a more accurate assessment of whether or not the 6A and 9A Bo ilers are subject to BART. Based on this newly provided information, we are pr oposing to find that while the 6A Boiler is a BART-eligible source, it is not subject to BA RT. The 9A Boiler is also BART-e ligible (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 perf orm a BART five factor analysis and make BART determinations for the Georgia-Pacifi c 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 databa ses generated by the Central Re gional Air Planning Association (CENRAP) and used by Arkansas to conduct its modeling analyses did not include surface and upper air meteorological observations as EPA guida nce recommends. Thus, in its evaluation to determine if a source exceeds the 0.5 ∆ dv contribution threshold at po tentially affected Class I areas, Arkansas used the maximum value ( i.e. 1 st high value) of modeled visibility impacts12 instead of the 98 th percentile value ( i.e. 8 th 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 becau se we already approved the portion of the 2008 Arkansas RH SIP in which Arkansas determin ed AECC Bailey Unit 1 is subject to BART and Arkansas has not provided us a SIP revisi on 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 modeli ng to us with a request to remove the source from BART and the modeling approach used by Ar kansas 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 whethe r the source is subject to BART, and our final approval of Arkansas’ determination that the sour ce is subject to BART remains in place and in the subsection that follows we eval uate 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 co mpliance; (3) any existing pollution control technology in use at the source; (4 ) the remaining useful life of th e 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 Electri c Cooperative Corporation

Bailey and McClellan Generating Stations,” dated March 2014 , Version 4, prepared by Tr inity Consultants Inc. in conjunction with Arkansas Electric Cooperative Co rporation; and “BART Fi ve Factor Analysis- NO X Analysis, Addendum to the July 24, 2012 BART Five Factor Analysis, Arkansas Electric Cooperative Corporation Bailey and McClellan Generating Sta tions,” dated December 2013, Ve rsion 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 Technica lly Infeasible Options;

 Step 3: Evaluate Control Effectivene ss of Remaining Control Technologies;

 Step 4: Evaluate Impacts a nd 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 Se ptember 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 Arka nsas RH SIP (77 FR 14604). This included a disapproval of some of the BART determinati ons 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 cons ultant, performed a BART five-f actor analyses to correct the State’s BART decisions that we re disapproved by us. As part of our proposed FIP, we have reviewed the final version of each BART anal ysis 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 te chnical 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 Fe derally 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 SO 2 , NO X , and PM for Bailey Unit 1 (77 FR 14604). AECC, through its consultant, performed a BART five factor an alysis (AECC BART

13 A copy of the final version of each BART analysis perf ormed 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 boile r with a gross output of 122 MW and a maximum heat input rate of 1350 million Britis h 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 c ontent limit of 2.3% by weight.

a. Baseline Emission Rates and Existing Visibi lity Impairment Attributable to Bailey Unit 1

AECC estimated SO 2 , NO X , and PM 10 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 NO X and PM 10 baseline emission rates for the fuel oil firing scenario were updated from what was modeled in the 2008 Arkansas RH SIP. The updated baseline emissi on rates are shown in the table below.

Table 5. Baseline Emission Rates for AECC Bailey Unit 1

Unit/Fuel Scenario SO 2 (lb/hr) NO X (lb/hr) Total PM 10 16 (lb/hr) Inorganic Condensable SO 4 (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 SO 2 and NO X baseline emission rates are the highest actual 24-hour emission rates based on 2001-2003 CEMS data. The revised NO X emission rate for the fuel oil firing scen ario is higher than what was modeled in Arkansas’s 2008 RH SIP.

15 See the following BART analyses: “BART Five Factor Analysis, Arkansas Electri c Cooperative Corporation Bailey and McClellan Generating Stations,” dated March 2014 , Version 4, prepared by Tr inity Consultants Inc. in conjunction with Arkansas Electric Cooperative Co rporation; and “BART Fi ve Factor Analysis- NO X 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 wo rksheets are typically used to speciate PM 10 into SO 4 , PMc, PMf, SOA, and EC.15 The PM 10 emission rate for natural gas combusti on is based on the emission factor for total PM 10 in Table 1.4-2 of AP-42, which is 7.6 lbs/MM scf, and the unit’s maximum heat input. The emission rate for the PM 10 species for natural gas combustion reflects the breakdown of the filterable and condensable PM 10 determined from AP-42 Table 1.4-2 Combustion of Natural Gas . All filterable PM was assumed to be el emental 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 (SO 4 ). The revised PM 10 emission rate for fuel oil combustion is lower than what was modeled in Arkansas’s 2008 RH SIP. The revised PM 10 emission rate for fuel oil combustion was based on stack testing of filterable and condensable PM 10 emissions conducted by the facility on AECC McClellan Unit 1. The results of the st ack testing showed that the total PM 10 emission rate for McClellan Unit 1 was 59.4 lb/hr. The total PM 10 emission rate for Bailey Unit 1 was determined by scaling the heat input rati o for Bailey vs. McClellan ( 1350 lb/MMBtu / 1436 lb/MMBtu) to get a total PM 10 emission rate of 55.8 lb/hr. The emission rate for the PM 10 species shown in the table above reflects the breakdown of the PM 10 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 PM 10 emission rate based on st ack testing for the fuel oil firing scenario is that there is no discus sion provided on how the st ack test results are representative of the maximum 24-hour emissions. However, since the visibility impacts due to PM 10 emissions from Bailey Unit 1 are so small, we believe a closer in spection of the revised PM 10 emission rate for fuel oil combustion and a ny further revision to it would likely not result in significant changes to the mode led 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 PM 10 ranges from approximately 3 – 11% for the natural gas firing scenario and 0.5 – 3% for the fuel oil firing scenario. Most of th e visibility impairment due to Bailey Unit 1 is attributable to NO 3 (approximately 83 – 96%) for the natu ral gas firing scenario and to SO 4 (67 – 99%) for the fuel oil firing scenario (see the ta ble below). Therefore, we did not take further steps to adjust the PM 10 emission rates or conduc t additional modeling. AECC modeled the baseline emission rates using the CALPUFF dispersion model to determine the baseline visibility impairment attrib utable to Bailey Unit 1 at the four Class I areas impacted by emissions from BART sources in Ar kansas: the Caney Creek Wilderness Area, the Upper Buffalo Wilderness Area, the Hercules-G lades 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 A ttributable to Bailey Unit 1 (2001-2003)-

17 The NPS Workbook, “Uncontrolled Utility Residual Oil Boile r.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 fu el oil with a sulfur conten t of 1.81% and a heat input of 1,350 MMBtu/hr.16 Natural Gas Firing

Year Maximum ( ∆ dv) 98 th Percentile ( ∆ dv) No. of Days with ∆ dv ≥ 0.5 98 th Percentile

%SO 4 98 th Percentile

%NO 3 98 th Percentile

%PM 10 98 th Percentile

%NO 2 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 A ttributable to Bailey Unit 1 (2001-2003)- Fuel Oil Firing

Year Maximum ( ∆ dv) 98 th Percentile ( ∆ dv) No. of Days with ∆ dv ≥ 0.5 98 th Percentile

%SO 4 98 th Percentile

%NO 3 98 th Percentile

%PM 10 98 th Percentile

%NO 2 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 0.7917 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. SO 2 BART Evaluation

AECC Bailey Unit 1 currently combusts natura l gas and No. 6 fuel oil. Because the SO 2 emissions profile and the 98 th percentile visibility impact from natural gas combustion attributed to the unit is very small, AECC did not consider additional SO 2 controls for combustion of natural gas and instead focused the SO 2 evaluation on controlling SO 2 emissions from combustion of No. 6 fuel oil. Because of the low SO 2 emissions associated with natural gas combustion and the relatively low baseline visi bility impacts from AECC Bailey Unit 1 when burning natural gas, we concur with AECC’s decision to focus the evaluation on controlling SO 2 emissions resulting from the combustion of No. 6 fu el oil. The five factors considered in the analysis are discussed below.

Step 1- Identify All Availabl e Retrofit Control Technologies

For SO 2 BART, AECC considered flue gas desulf urization (FGD) and fuel switching. The type of FGD technologies cons idered consisted of Dry Sorben t 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 SO 2 control on fuel oil-fired units in the U.S. electric industry and therefore consid ered it a technically infeasible option for control of Bailey Unit 1. Accordingl y, AECC did not further consider FGD for SO 2 BART. We concur with AECC’ s decision to focus the SO 2 evaluation on fuel switching.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies :
AECC Bailey Unit 1 currently burns some resi dual fuel oil. The most recent No. 6 fuel oil shipment for Bailey Unit 1 was in Decembe r 2006, and had an average sulfur content of 1.81% by weight. A portion of the fuel oil from th is 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. Switc hing to a fuel with a lower sulfur content is expected to reduce SO 2 emissions in proportion to the reducti on in the sulfur content of the fuel, assuming similar heat contents of the fuels. The fuel types with lower sulfur content evaluated by18 AECC are lower sulfur No. 6 fuel oil, No. 2 fuel oil ( i.e. , diesel), and natura l gas. These fuel types and the estimated control efficiency of each are shown in the table below.

Table 8. Control Effectiveness of Technically Feasible SO 2 Control Technologies for Bailey Unit 1

Fuel Switching to: Estimate d 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting 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 su lfur content fuels. The supplier of the existing fuels ( i.e. , No. 6 fuel oil and natural ga s) provided AECC with current cost estimates for the existing fuels and for the lo wer sulfur content No. 6 fuel oil and diesel. As shown in the table below, the supplier’s estimate fo r the cost of No. 6 fuel oil with 0.5% and 1% sulfur content is $17.75/MMBtu and $16.50 /MMB tu (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 SO 2 annual emissions reductions as a result of fuel switching by subtracting the estimated controlled annual em ission rates from the baseline annual emission rates. AECC estimated the baseline and cont rolled annual emission ra tes 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 SO 2 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 fu el density and by the percent sulfur content of the fuel. This yielded the quantity of sulfur in the fuel. The SO 2 emissions were then estimated

18 See the following BART analyses: “BART Five Factor Analysis, Arkansas Electri c Cooperative Corporation Bailey and McClellan Generating Stations,” dated March 2014 , Version 4, prepared by Tr inity Consultants Inc. in conjunction with Arkansas Elect ric Cooperative Corporation.19 by multiplying the quantity of su lfur available to form SO 2 by the ratio of the molecular weight for SO 2 vs. sulfur. See the table below for the estimated SO 2 emissions associated with the base case and with each fuel switching scenario. To calculate the average co st-effectiveness of fuel sw itching, AECC divided the annual cost increase of switching to a lower sulfur fuel by the annual SO 2 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 wi th Fuel Switching for Bailey Unit 1

Fuel Switching Scenario Average Sulfur Content

(%) Baseline Emission

Rate (SO 2 tpy) Controlled Emission

Rate (SO 2 tpy) Annual Emissions Reductions (SO 2 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

($/yr) AverageCostEffectiveness ($/ton) Incremental Cost Effectiveness 19 ($/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 impa cts 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 na tural gas may have an impact during periods of natural gas curtailment. During periods of natural gas curtai lment, natural gas infrastructure maintenance, and other emergencies, the AECC Bailey Generating Station relies on the fu el oil stored at the plant to maintain electrical re liability. AECC’s evaluation indicat es 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 t echnology is reflected in the BART analysis in two ways: first, in the c onsideration of available contro l technologies, and second, in the

19 The incremental cost-effectiveness cal culation compares the costs and perfor mance 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 SO 2 pollution control technology. With regard to consideration of the remaini ng useful life of the unit, this factor does not impact the SO 2 BART analysis in this case since it is a ssumed that fuel switching will not require any capital cost expenditures.

Step 5- Evaluate Visibility Impacts

AECC assessed the visibility improvement asso ciated with fuel switching by comparing the visibility impairment from the baseline scenar io to the impairment associated with each control scenario. The SO 2 emission rate in lb/MMBtu associ ated with the combustion of each fuel type was calculated by scal ing the existing 30-day rolli ng average emission rate from 2001- 2003 by the ratio of the sulfur c ontent of the new fuel and the current maximum annual average sulfur content from 2009-2011. The controlled 30-d ay 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 w ith fuel switching, including the maximum modeled visibility impact and the 98 th percentile modeled visibility impact. The visibility improvement associated with fuel switching was calculated as the differe nce between the existing visibility impairment and the visibility impairment for each fuel scenario as measured by the 98 th percentile modeled visibility impact.

Table 10. Summary of Emission Rates Modeled for SO 2 Control Scenarios at AECC Bailey Unit 1

SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10, 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 10.321 Table 11. AECC Bailey Unit 1: Summary of 98 th 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 swit ching to No. 6 fuel oil with 1% sulfur content at Bailey Unit 1 is projected to result in 0.173 dv visibi lity improvement at Mingo (based on the 98 th percentile modeled visibility impacts). The visi bility improvement at each of the other three affected Class I areas is projected to be slig htly less than that amount , while the cumulative visibility improvement at the four Class I ar eas is projected to be 0.626 dv. Switching to No. 6 fuel oil with 0.5% sulfur content is projected to result in meaningf ul visibility improvement. It is projected to result in 0.233 dv visibility im provement 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 vi sibility improvement at the four Class I areas is projected to be 0.851 dv. Switching to diesel or na tural gas is also projected to result in meaningf ul visibility improvement. The visibility improvement at He rcules-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 proj ected to be 1.108 dv for sw itching to diesel and 1.095 dv for switching to natural gas.22 Our Proposed SO 2 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% su lfur 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 aff ected 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 SO 2 removed and is projected to result in visibi lity improvement ranging from 0.188 to 0.233 dv at each modeled Class I area, and a cumulative vi sibility 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 improveme nt than switching to No. 6 fuel oil with 0.5% sulfur content. However, the BART Gu idelines 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 requi re a switch to natural gas for Unit 1. Switching to diesel is projected to result in an almost identical level of visibil ity improvement at each Cl ass I area as switching to natural gas. The incremental visibility improveme nt 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-e ffectiveness is estimated to be $5,382/ ton of SO 2 removed and the incremental cost-effectiveness co mpared to switching to No. 6 fuel oil with a sulfur content of 0.5% is es timated to be $13,558/ ton of SO 2 removed, which we do not consider to be very cost-effective in view of the re latively 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 SO 2 BART for Bailey Unit 1 is switching to fuels with 0.5% or lower sulf ur content by weight. We propose to require that the facility purchase no fuel after the effective date of th e rule that does not m eet the sulfur content requirement and that 5 years from the effective da te of the rule no fuel be burned that does not meet the requirement. We expect this propos ed compliance date would allow the facility sufficient time to burn its existing supply of No. 6 fu el oil (i.e., the baseline fuel), as the normal course of business dictates and in accordance wi th any operating restrictions enforced by ADEQ. We propose that any higher sulfur fuel oil that remains from the facili ty’s 2006 shipment cannot be burned past this point.

c. NO X BART Evaluation

Nitrogen oxides, or NO X , are produced during fuel combustion when nitrogen contained in both the fuel and the combustion air is exposed to high temperatures. Nitrogen oxide (NO) is23 typically the predominant form of NO X from fossil fuel combustion, with nitrogen dioxide (NO 2 ) making up the remainder of the NO X . AECC’s evaluation noted th at the formation of NO X 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 ar e 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 di screte flames produced by burners in the wall-fired boilers. Tangentially fired boilers typically have lower uncontrolled NO X emissions than wall-fired bo ilers. Therefore, baseline NO X emission rates can vary significantly from plant to plant due to method of firing and combustion flame temperatures, among other factors. The baseline NO X emission rate for Bailey Unit 1 is discussed under se ction II.C.1.a. of this TSD. The five factors considered in the NO X BART analysis are discussed below.

Step 1- Identify All Availabl e Retrofit Control Technologies

For NO X BART, AECC evaluated both combus tion and post-combustion controls. Combustion controls involve reducing the peak flame temperature and excess air in the furnace to minimize NO X formation, while post-combustion controls involve converting NO X in the flue gas to molecular nitrogen and water. The comb ustion controls evaluated by AECC consisted of flue gas recirculation (FGR), overfire air (OFA), and Low NO X Burners (LNB). The postcombustion controls evaluated consisted of Se lective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR).

Step 2- Eliminate Technically Infeasible Options

AECC found that some boilers may be restri cted from installing OFA retrofits due to physical size and space restraints. For purposes of the NO X 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 furthe r 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 ther e are physical space requirements for OFA ports and air supply ducts. AECC found the remaining NO X control options to be technically feasible.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies :

The estimated NO X controlled emission rate of each control option considered by AECC is shown in the table below. In its evaluati on, 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 NO X control range for oil and gas wa ll-fired boilers is approximate ly 0.2 – 0.4 lb/MMBtu, and when OFA is operated alone it results in an estimated NO X controlled emission rate of 0.2 – 0.324 lb/MMBtu. 20 It also estimated that when LNB is combined with OFA and FGR, a NO X controlled emission rate of 0.15 – 0.20 lb/MMBtu is achievable. AECC found that the estimated NO X 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 NO X level of control is estimated to be 10% greater than with combustion controls alone. 21

Table 12. Control Effectiveness of Technically Feasible NO X Control Technologies for AECC Bailey Unit 1

Control Technology Baseline NO X Emission Rate (lb/MMBtu) Estimated NO X 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 compli ance, 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 NO X controls 22 was based on “budgetary” cost estimates it obtained from the pollution control equipm ent vendor, Babcock Power Systems. AECC estimated the capital and operating costs of contro ls based on the vendor’s estimates, engineering estimates, and published calculation methods us ing 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 (S TAPPA) 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- NO X Analysis, Addendum to the July 24, 2012 BART Five Factor Analysis, Arkansas Electric Cooperative Corpor ation Bailey and McClellan Generati ng 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 evalua tion indicate any futu re planned shutdown. This means that the anticipated useful life of the bo iler is expected to be at least as long as the capital cost recovery period of controls. Theref ore, a 30-year amortization period was assumed in the NO X BART analysis as the remaining useful life of the unit. The table below summarizes the estimated cost for installation and operation of NO X controls for Bailey Unit 1. AECC determined the annual emissions reductions associated with each NO X control option by subtracting the estimated controlled an nual emission rate from the baseline annual emission rate. The baseline annual emission ra tes 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 aver age 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 NO X controls, AECC divided the total annual cost of each control opt ion by the estimated annual NO X tons reduced. The table below shows the average cost effectiveness of NO X controls for Bailey Unit 1.

Table 13. Summary of Costs of NO X Controls for AECC Bailey Unit 1

Control Scenario Baseline Emission

Rate (NO X 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 (NO X tpy) Annual Emissions Reductions (NO X tpy) Capital Cost ($) Total Annual

Cost ($/yr) AverageCostEffectiveness ($/ton) IncrementalCostEffectiveness ($/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-effectiven ess of installing and operating combustion controls to be $36,905/ton of NO X removed for Bailey Unit 1. The combination of combustion controls and SNCR was estimated to cost $48,884/ton of NO X removed, while SCR was

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

www.epa.gov/ttncatc1/p roducts.html#cccinfo.26 estimated to cost $38,738/ton of NO X removed. In its evaluation, AECC also explained that it expects NO X controls to be less cost-effective ( i.e. , greater dollars per ton removed) in future years due to projected reduced ope ration of the unit. Less projected operating time is expected to result in lower annual emissions, which w ould result in lower co st-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 th at could create energy or non-ai r 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 NO X controls at AECC Bailey Unit 1 that would affect our proposed BART determination. With regard to consideration of any exis ting pollution control t echnology in use at the source, Bailey Unit 1 has no existing NO X 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 c ontrol technologies, and second, in the development of baseline emission rates for use in cost calc ulations and visibility modeling. With regard to consideration of the remaini ng useful life of the unit, we are not aware of any enforceable shutdown date for the AE CC Bailey Generating Sta tion, nor did AECC’s evaluation indicate any future planned shutdown. Th is means that the antic ipated 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 amortizati on period was assumed in the NO X BART analysis as the remaining useful life of the unit.

Step 5- Evaluate Visibility Impacts

AECC assessed the visibility improvement associated with NO X controls by modeling the NO X emission rates associated w ith each control option using CALPUFF, and then comparing the visibility impairment associated with the base line 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 NO X controls, including the maximum m odeled visibility impact and the 98 th percentile modeled visibility impact for each Class I area. Th e visibility improvement associated with NO X controls was calculated as the difference between the base line visibility impairme nt and the visibility impairment for each control scenario as measured by the 98 th percentile modeled visibility impact.27 Table 14. Summary of Emission Rates Modeled for NO X Control Scenarios at AECC Bailey Unit 1

Control Scenario Fuel Scenario SO 2 (lb/hr) NO X (lb/hr) Total PM 10 (lb/hr) SO 4 (lb/hr) PMc (lb/hr) PMf (lb/hr) SOA (lb/hr) EC (lb/hr)CombustionControls 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 2.4SCR 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 2.4CombustionControls +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 98 th Percentile Visibility Impacts and Improvement due to NO X 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 98 th Percentile Visibility Impacts and Improvement due to NO X 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 NO X controls is projected to result in very modest visibility improvement fr om 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 pr ojected to result in visibility improvement ranging from 0.059 – 0.081 dv at each Class I area for natural gas firi ng and 0.007 – 0.042 dv for fuel oil firing. SCR is projected to result in negligible incremental vi sibility improvement compared to a combination of combustion cont rols and SNCR.

Our Proposed NO X BART determination:

Taking into consideration the five factor s, we are proposing to determine that NO X BART for the AECC Bailey Unit 1 is no additional controls, and ar e proposing that the existing NO X emission limit satisfies BART for NO X . We are proposing the existing emission limit of29 887 lb/hr for NO X BART for Bailey Unit 1. 24 As discussed above, the operation of combustion controls at Bailey Unit 1 is projected to re sult in a maximum visibi lity improvement of 0.051 ∆ dv (Mingo), and a smaller amount of visibility imp rovement at each of the other affected Class I areas. The installation and ope ration of combustion controls at Bailey Unit 1 has an average cost-effectiveness of $36,905/ton of NO X 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 justif y the high estimated cost of those controls. The operation of a combination of combustion contro ls + SNCR is estimated to cost $48,884/ton of NO X removed, which is also not cost-effective. A combination of combustion controls + SNCR is projected to result in negligib le incremental visibility benefit compared to combustion controls alone. The operation of SCR is estimated to cost $38,738/ton of NO X 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 NO X BART for Bailey Unit 1 is no additional controls and are proposing the aforementioned existing NO X emission limit for NO X BART. We are proposing that this already-ex isting 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 BA RT analysis for Bailey Unit 1 are discussed below.

Step 1- Identify All Availabl e Retrofit Control Technologies

For PM BART, AECC considered the follo wing 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 bur ned at Bailey Unit 1, has inherent ash that contributes to emissions of filterable PM. Filtera ble PM emissions could be reduced by switching to a lower grade fuel oil or natural gas. For comb ustion 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 SO 2 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 th e particulate matter from oil -fired boilers tends to be sticky and small, affecting the collection efficien cy of dry ESPs and fabric filters. Dry ESPs operate by placing a charge on the pa rticles through a series of elec trodes, 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 periodical ly removed from the filter bag through a pulse jet or reverse flow mechan ism. Because of the sticky nature of particles from oil-fired boilers, dry ESPs and fabric filters are deemed t echnically 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 thes e boiler types, they are not very efficient at controlling particles in the smalle r size fraction, particularly partic les smaller than a few microns. However, we do not expect this to be an issu e 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 Effectiven ess of Remaining Control Technologies :
AECC estimated that switching to a lower sulf ur fuel has a PM cont rol efficiency ranging from approximately 44% - 99%, depending on the fuel type. The other technically feasible control technologies are estimated to have the fo llowing 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting 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 capit al 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 be low 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 reducti ons. 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 contro lled annual emission rates from the baseline annual emission rates, which were derived usi ng emission factors from AP-42, section 1.3-1. We disagree with two aspects of AECC’s cost evaluation for PM cont rols. First, the total annual cost numbers associated with fuel switchi ng should be the same as the cost numbers used in the SO 2 BART cost analysis for Bailey Unit 1 (s ee Table 9). In earlier draft versions of AECC’s analysis, which were provided to us fo r review, the cost numbers for fuel switching used in the PM and SO 2 BART analyses were identical. In response to comments provided by us, the total annual cost and average cost-effectiven ess numbers for fuel switching were revised in the final version of AECC’s SO 2 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 SO 2 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 peri od 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. Th erefore, we believe th at assuming a 30-year equipment life rather than a 15-year equipment li fe 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, ther eby 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 amorti zation 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 equi pment 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) AverageCostEffectiveness ($/ton) IncrementalCostEffectiveness ($/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 SO 2 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 co st-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 SO 2 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 discusse d above, AECC also expl ained that it expects controls to be less cost-effective ( i.e. , greater dollars per ton remove d) in future years due to projected reduced operation of the unit. Less project ed operating time is expected to result in lower annual emissions, which in turn would re sult in lower cost-effect iveness of controls. AECC did not identify any energy or non-air quality environmental impacts associated with fuel switching, but did identify impacts a ssociated with the use of wet ESPs and wet scrubbers due to their electricity usage. Ener gy use in and of itself does not disqualify a technology (40 CFR Part 51, Appendix Y, sectio n IV.D.4.h.1.). In addition, the cost of the electricity needed to operate this equipment has al ready been factored into the cost of controls. AECC also noted that both wet ESPs and wet scr ubbers generate wastewat er 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 cak e that would likely require landfilling. The BART Guidelines provide that the fact that a cont rol device creates liquid and solid wa ste 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 a nd the solid or liquid waste is similar to those other applica tions. (40 CFR Part 51, Appendix Y, section IV.D.4.i.2.). We are not aware of any unusual circumstances at th e AECC Bailey Generating Station that could potentially create greater problems than experi enced elsewhere related to the treatment of wastewater and any necessary landfilling, nor did AECC’s evaluation discuss or mention any33 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 ba sis for disqualification or elimination of a wet ESP or wet scrubber. With regard to consideration of any exis ting pollution control t echnology in use at the source, Bailey Unit 1 has no existing PM polluti on 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 c ontrol technologies, and second, in the development of baseline emission rates for use in cost calc ulations and visibility modeling. With regard to consideration of the remaini ng useful life of the unit, we are not aware of any enforceable shutdown date for the AE CC Bailey Generating Sta tion, nor did AECC’s evaluation indicate any future planned shutdown. Th is means that the antic ipated 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 a ppropriate to assume a 30-year am ortization period in the PM BART analysis as the remaining useful life of the unit. As discusse d in more detail below, AECC assumed a 15-year amortization period for contro l 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-eff ectiveness calculations for the PM control equipment options. This is discussed in more de tail below in the subsect ion titled “Our Proposed PM BART Determination.”

Step 5- Evaluate Visibility Impacts

As switching to lower sulfur fuels has impacts on both SO 2 and PM emissions, AECC’s assessment of the visibility improvement associat ed with fuel switching is addressed in the SO 2 BART analysis for Bailey Unit 1, which is disc ussed under section II.C.1. b. of this TSD. Table 11 summarizes the visibility improvement associ ated with controlled emission rates for SO 2 and PM as a result of fuel switching. AECC assessed the visibility improvement a ssociated with wet ESPs, wet scrubbers, and cyclones by modeling the PM emission rates a ssociated with each control option using CALPUFF, and then comparing th e visibility impairment associ ated with the baseline emission rates to the visibility impairment associated with the controlled emission rates as measured by the 98 th percentile modeled visibil ity impact. The controlled PM 10 emission rates associated with wet ESPs, wet scrubbers, and cyclones were calculated by reducing the uncontrolled annual PM 10 emission rates by the pollutant removal e fficiency of each control technology. The SO 2 and NO X emission rates modeled in the controlled scenar ios are the same as those from the baseline scenario, as it is assumed that SO 2 and NO X emissions would remain unchanged. The tables below show a comparison of the emi ssion 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 98 th percentile modeled vi sibility impact. The visibility improvement associated with each co ntrol scenario was calculated as the difference34 between the existing visibility impairment a nd the visibility impairment for each control scenario, as measured by the 98 th percentile modeled visibility impact.

Table 18. Summary of Emission Rates Modeled fo r PM Control Scenarios at AECC Bailey Unit 1

Control SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10 , 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 98 th 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 visi bility improvement at the four affected Class I areas. The modeled visibility improvement from switching to No. 6 fuel oil with 1% sulfur35 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 SO 2 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 SO 2 emissions, while PM 10 emissions contribute only a small portion of the base line visibility impacts at each Class I area. Table 7 shows that th e percentage of the visib ility impairment at the four modeled Class I areas attributable to PM 10 ranges from approximately 0.5 – 3% for the fuel oil firing scenario. Most of the visibility impairment is attributable to SO 4 (67 – 99%) for the fuel oil firing scenario. Accordingly, the majority of the visibility improve ment associated with switching to lower sulfur fuels can reasonably be expected to be the result of reduced SO 2 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 SO 2 BART, we are proposing that PM BA RT is satisfied by Unit 1 switching to fuels with 0.5% or lower su lfur content by weight. As discussed above, we disagree with AECC’s use of a 15-year amortization period in th e cost analysis for a wet ESP, wet scrubber, and cyclone. We are not aware of any enfo rceable 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 a nnual 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 pr oposed BART decision. Even if we revised AECC’s cost estimate s to reflect a 30-year amortiza tion 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 visib ility benefit of these controls (see the table above). We are proposing to determine that PM BA RT for Bailey Unit 1 is switching to fuels with 0.5% or lower sulfur conten t by weight. We propose to require that the facility purchase no fuel after the effective date of the rule that doe s not meet the sulfur cont ent requirement and that 5 years from the effective date of the rule no fu el be burned that does no t meet the requirement. We expect this proposed compliance date woul d 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 restric tions enforced by ADEQ. We propose that any higher sulfur fuel oil that remains from the f acility’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 SO 2 , NO X , 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 su bject to an operating air permit sulfur content limit of 2.8% by weight.

a. Baseline Emission Rates and Existing Vi sibility Impairment Attributable to McClellan Unit 1

AECC estimated SO 2 , NO X , and PM 10 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 NO X and PM 10 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 SO 2 (lb/hr) NO X (lb/hr) Total PM 10 (lb/hr) SO 4 (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 da ta, stack testing, and AP-42 emission factors. The SO 2 and NO X baseline emission rates ar e the highest actual 24-hour emission rates based on 2001-2003 CEMS data. The revised NO X emission rate for the fuel oil

28 See the following BART analyses: “BART Five Factor Analysis, Arkansas Electri c Cooperative Corporation

Bailey and McClellan Generating Stations,” dated March 2014 , Version 4, prepared by Tr inity Consultants Inc. in conjunction with Arkansas Electric Cooperative Co rporation; and “BART Fi ve Factor Analysis- NO X Analysis, Addendum to the July 24, 2012 BART Five Factor Analysis, Arkansas Electric Cooperative Corporation Bailey and McClellan Generating Sta tions,” dated December 2013, Ve rsion 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 modele d in Arkansas’s 2008 RH SIP, thereby resulting in higher modeled visibility impacts due to NO X

. The PM 10 emission rate for natural gas combusti on is based on the emission factor for total PM 10 in Table 1.4-2 of AP-42, which is 7.6 lbs/MM scf, and the unit’s maximum heat input. The emission rate for the PM 10 species for natural gas combustion reflects the breakdown of the filterable and condensable PM 10 determined from AP-42 Table 1.4-2 Combustion of Natural Gas . All filterable PM was assumed to be el emental 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 (SO 4 ). The revised PM 10 emission rate for fuel oil combustion is lower than what was modeled in Arkansas’s 2008 RH SIP. The revised PM 10 emission rate for fuel oil combustion was based on stack testing of filterable and condensable PM 10 emissions conducted by the facility on McClellan Unit 1. The results of the st ack testing showed that the total PM 10 emission rate for McClellan Unit 1 was 59.4 lb/hr. The emission rate for the PM 10 species shown in the table above reflects the breakdown of the PM 10 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 PM 10 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-ho ur emissions. However, since the visibility impacts due to PM 10 emissions from McClellan Unit 1 ar e so small, we believe a closer inspection of the revised PM 10 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 PM 10 ranges from approximately 4 – 10% for the natural gas firing scenario and 0.4 – 2.5% for the fuel oil firing scen ario (see table below). Mo st of the visibility impairment due to McClellan Un it 1 is attributable to NO 3 (approximately 83 – 95%) for the natural gas firing scenario and to SO 4 (60 – 98%) for the fuel oil fi ring scenario. Therefore, we did not take further steps to adjust the PM 10 emission rates or conduct additional modeling. AECC modeled the baseline emission rates using the CALPUFF dispersion model to determine the baseline visibility impairment attr ibutable to McClellan Un it 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 He rcules-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 Boile r.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 Attr ibutable to McClellan Unit 1 (2001-2003)- Natural Gas Firing

Year Maximum ( ∆ dv) 98 th Percentile ( ∆ dv) No. of Days with ∆ dv ≥ 0.5 98 th Percentile

%SO 4 98 th Percentile

%NO 3 98 th Percentile

%PM 10 98 th Percentile

%NO 2 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 Attri butable to McClellan Unit 1 (2001-2003)- Fuel Oil Firing

Year Maximum ( ∆ dv) 98 th Percentile ( ∆ dv) No. of Days with ∆ dv ≥ 0.5 98 th Percentile

%SO 4 98 th Percentile

%NO 3 98 th Percentile

%PM 10 98 th Percentile

%NO 2 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 1.0839 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. SO 2 BART Evaluation

AECC McClellan Unit 1 currently combusts na tural gas and No. 6 fuel oil. Because the SO 2 emissions profile and the 98 th percentile visibility impact from natural gas combustion attributed to the unit is very sma ll, AECC did not consider additional SO 2 controls for combustion of natural gas and instead focused the SO 2 evaluation on controlling SO 2 emissions from combustion of No. 6 fuel oil. Because of the low SO 2 emissions associated with natural gas combustion and the relatively low baseline visi bility impacts from AECC McClellan Unit 1 when burning natural gas, we concur with AECC’s decision to focus the evaluation on controlling SO 2 emissions resulting from the combustion of No. 6 fuel oil. The five factors considered in the analysis are discussed below.

Step 1- Identify All Availabl e Retrofit Control Technologies

For SO 2 BART, AECC’s evaluation considered F GD 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 SO 2 control on fuel oil-fired units in the U.S. electric industry and therefore consid ered it a technically infeasible option for control of McClellan Unit 1. Therefor e, AECC’s evaluation did not further consider FGD for SO 2 BART. We concur with AECC’ s decision to focus the SO 2 evaluation on fuel switching.

Step 3- Evaluate Control Effectiven ess 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 th is 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. Switc hing to a fuel with a lower sulfur content is expected to reduce SO 2 emissions in proportion to the reducti on in the sulfur content of the fuel, assuming similar heat contents of the fuels. The fuel types with lower sulfur content evaluated by40 AECC are lower sulfur No. 6 fuel oil, No. 2 fuel oil ( i.e. , diesel), and natura l gas. These fuel types and the estimated control efficiency of each are shown in the table below.

Table 23. Control Effectiveness of Technically Feasible SO 2 Control Technologies for AECC McClellan Unit 1

Fuel Switching to: Estimate d 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting 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 su lfur content fuels. The supplier of the existing fuels ( i.e. , No. 6 fuel oil and natural ga s) provided AECC with current cost estimates for the existing fuels and for the lo wer sulfur content No. 6 fuel oil and diesel. As shown in the table below, the supplier’s estimate fo r the cost of No. 6 fuel oil with 0.5% and 1% sulfur content is $17.75/MMBtu and $16.50 /MMB tu (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 SO 2 annual emissions reductions as a result of fuel switching by subtracting the estimated controlled annual em ission rates from the baseline annual emission rates. AECC estimated the baseline and cont rolled annual emission ra tes 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 SO 2 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 fu el density and by the percent sulfur content of the fuel. This yielded the quantity of sulfur in the fuel. The SO 2 emissions were then estimated

30 See the following BART analyses: “BART Five Factor Analysis, Arkansas Electri c Cooperative Corporation Bailey and McClellan Generating Stations,” dated March 2014 , Version 4, prepared by Tr inity Consultants Inc. in conjunction with Arkansas Elect ric Cooperative Corporation.41 by multiplying the quantity of su lfur available to form SO 2 by the ratio of the molecular weight for SO 2 vs. sulfur. See the table below for the estimated SO 2 emissions associated with the base case and with each fuel switching scenario. To calculate the average co st-effectiveness of fuel sw itching, AECC divided the annual cost increase of switching to a lower sulfur fuel by the annual SO 2 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 (SO 2 tpy) Controlled Emission

Rate (SO 2 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 Effectiveness 31 ($/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 ener gy or non-air quality impacts a ssociated with switching to 1% sulfur No. 6 fuel oil, 0.5% sulfur No. 6 fuel oil, or diesel. The ev aluation indicated that switching to natural gas may have an impact during periods of natural gas curtailment. During natural gas curtailments, natural gas infrastruc ture 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 expensiv e than natural gas. With regard to consideration of any exis ting pollution control t echnology in use at the source, McClellan Unit 1 has no existing SO 2 pollution control techno logy. The presence of existing pollution control technology is reflected in the BART analysis in two ways: first, in the

31 The incremental cost-effectiveness cal culation compares the costs and perfor mance 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 c ontrol technologies, and second, in the developmen t of baseline emission rates for use in cost calc ulations and visibility modeling. With regard to consideration of the remaini ng useful life of the unit, this factor does not impact the SO 2 BART analysis in this case since it is a ssumed that fuel switching will not require any capital cost expenditures.

Step 5- Evaluate Visibility Impacts

AECC assessed the visibility improvement a ssociated with fuel switching by comparing the visibility impairment from the baseline scenar io to the impairment associated with each control scenario. The SO 2 emission rate in lb/MMBtu associ ated with the combustion of each fuel type was calculated by scal ing the existing 30-day rolli ng average emission rate from 2001- 2003 by the ratio of the sulfur c ontent of the new fuel and the current maximum annual average sulfur content from 2009-2011. The controlled 30-d ay 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 w ith fuel switching, including the maximum modeled visibility impact and the 98 th percentile modeled visibility impact. The visibility improvement associated with fuel switching was calculated as the differe nce between the existing visibility impairment and the visibility impairment for each fuel scenario as measured by the 98 th percentile modeled visibility impact.

Table 25. Summary of Emission Rates Modeled for SO 2 Control Scenarios at McClellan Unit 1
SO 2 (lb/hr) SO4 (lb/hr) NO X (lb/hr) PMC (lb/hr) PMF (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10, 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 10.943 Table 26. AECC McClellan Unit 1: Summary of 98 th 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% Sul fur 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 98 th percentile modeled visibility impacts). The visibility improvement at each of the other three affected Class I is proj ected to range from 0.029 – 0.035 dv, while the cumulative visibility improvement at the four Class I areas is proj ected to be 0.184 dv. Switchi ng to No. 6 fuel oil with 0.5% sulfur content is proj ected to result in considerable visibility improvement. It is projected to result in 0.3 dv visi bility improvement at Caney Cr eek. The visibility improvement at each of the other three affected Class I ar eas 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 pr ojected 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 fo r 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 proj ected to be 0.958 dv for sw itching to diesel and 1.072 dv for switching to natural gas.44 Our Proposed SO 2 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 aff ected 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 SO 2 removed and is projected to re sult in visibili ty improvement ranging from 0.092 to 0.3 dv at each modeled Class I area, and a cumulative visibil ity 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 great er 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). Si nce natural gas has a sulfur c ontent 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 Un it 1. Switching to diesel is projected to result in considerable visibility improvement. The visi bility 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 aff ected Class I areas. The incremental visibility improvement of switching to diesel compared to switching to No. 6 fuel o il 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 esti mated to be $7,145/ ton of SO 2 removed and the incremental cost-e ffectiveness compared to No. 6 fu el oil with a sulfur content of 0.5% is $13,616/ ton of SO 2 removed, which we do not consider to be cost-effective in view of the incremental visibility improvement. Since dies el also has a sulfur c ontent by weight that is well below 0.5, the facility may elec t 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 SO 2 BART for McClellan Unit 1 is swit ching to fuels with 0.5% or lo wer 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 re quirement and that 5 years from the effective date of the rule no fuel be burned that does not meet the requir ement 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 busin ess dictates and in accordance with any operating restrictions enforced by ADEQ. We propose that any higher sulfur fu el oil that remains from its 2009 shipment cannot be burned past this point.45 c. NO X BART Evaluation

Nitrogen oxides, or NO X , 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 NO X from fossil fuel combustion, with nitrogen dioxide (NO 2 ) making up the remainder of the NO X . AECC noted that the formation of NO X compounds in utility boilers is sensitive to the method of firing and combus tion flame temperatures. In wallfired boilers, such as McClellan Unit 1, burne rs are mounted in the boiler walls, producing discrete flames in the furnace. In tangentially-fired boi lers, a single rotating flame is created in the center of the furnace, rather than the discre te flames produced by burners in the wall-fired boilers. Tangentially fired boilers ty pically have lower uncontrolled NO X emissions than wallfired boilers. Theref ore, baseline NO X emission rates can vary signi ficantly from plant to plant due to method of firing and combustion flame te mperatures, among other f actors. The baseline NO X emission rate for McClellan Unit 1 is discu ssed under section II.C.2.a. of this TSD. The five factors considered in the NO X BART analysis are discussed below.

Step 1- Identify All Availabl e Retrofit Control Technologies

For NO X BART, AECC evaluated both combus tion and post-combustion controls. Combustion controls involve reducing the peak flame temperature and excess air in the furnace to minimize NO X formation, while post-combustion controls involve converting NO X in the flue gas to molecular nitrogen and water. The comb ustion controls evaluated by AECC consisted of FGR, OFA, and LNB. The post-combustion cont rols evaluated consisted of SCR and SNCR.

Step 2- Eliminate Technically Infeasible Options

AECC found that some boilers may be restri cted from installing OFA retrofits due to physical size and space restraints. For purposes of the NO X 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 fu rther 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 ther e are physical space requirements for OFA ports and air supply ducts. AECC found the remaining NO X control options to be technically feasible.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies :

The estimated NO X controlled emission rate of each control option considered by AECC is shown in the table below. In its evaluati on, 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 NO X46 control range for oil and gas wa ll-fired boilers is approximate ly 0.2 – 0.4 lb/MMBtu, and when OFA is operated alone it results in an estimated NO X controlled emission rate of 0.2 – 0.3 lb/MMBtu. 32 It also estimated that when LNB is combined with OFA and FGR, a NO X controlled emission rate of 0.15 – 0.20 lb/MMBtu is achievable. AECC found that the estimated NO X 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 NO X level of control is estimated to be 10% greater than with combustion controls alone. 33

Table 27. Control Effectiveness of Technically Feasible NO X Control Technologies for AECC McClellan Unit 1

Control Technology Baseline NO X Emission Rate (lb/MMBtu) Estimated NO X 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 compli ance, 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 34 for NO X controls was based on “budgetary” cost estimates it obtained from the pollution control equipm ent vendor, Babcock Power Systems. AECC estimated the capital and operating costs of contro ls based on the vendor’s estimates, engineering estimates, and published calculation methods usi ng the EPA Control Cost Manual. We are not aware of any enforceable shutdown date for th e AECC McClellan Generating Station, nor did AECC indicate any future planned shutdown. This m eans that the anticipated useful life of the boiler is expected to be at least as long as the capital cost recovery peri od 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 (S TAPPA) 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- NO X Analysis, Addendum to the July 24, 2012 BART Five Factor Analysis, Arkansas Electric Cooperative Corpor ation Bailey and McClellan Generati ng Stations,” dated December 2013, Version 3.47 a 30-year amortization period was assumed in the NO X BART analysis as the remaining useful life of the unit. The table below summarizes the estimated cost for insta llation and operation of NO X controls for AECC McClellan Unit 1. AECC determined the annual emissions reductions associated with each NO X control option by subtracting the estimated controlled an nual emission rate from the baseline annual emission rate. The baseline annual emission ra tes 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 aver age 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 NO X controls, AECC divided the total annual cost of each control opt ion by the estimated annual NO X tons reduced. The table below shows the average cost effectiveness a nd incremental cost-e ffectiveness of NO X controls for AECC McClellan Unit 1.

Table 28. Summary of Costs of NO X Controls for AECC McClellan Unit 1

Control Scenario Baseline Emission

Rate (NO X 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 (NO X tpy) Annual Emissions Reductions (NO X tpy) Capital Cost ($) Total Annual

Cost ($/yr) AverageCostEffectiveness ($/ton) IncrementalCostEffectiveness ($/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-effectiven ess of installing and operating combustion controls to be $6,261/ton of NO X removed for McClellan Unit 1. The combination of combustion controls and SNCR was estimated to cost $12,630/ton of NO X removed, while SCR was estimated to cost $7,565/ton of NO X removed. In its evaluation, AECC also explained that it expects NO X controls to be less cost-effective ( i.e. , greater dollars per ton removed) in future years due to projected reduced ope ration of the unit. Less projected operating time is expected to result in lower annual emissions, which would re sult 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 th at could create energy or non-ai r 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 NO X controls at AECC McClellan Unit 1 that would affect our proposed BART determination. With regard to consideration of any exis ting pollution control t echnology in use at the source, McClellan Unit 1 has no existing NO X 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 ava ilable 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 remaini ng useful life of the unit, we are not aware of any enforceable shutdown date for the AECC McClellan Generating St ation, nor did AECC’s evaluation indicate any future planned shutdown. Th is means that the antic ipated 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 amortizati on period was assumed in the NO X BART analysis as the remaining useful life of Unit 1.

Step 5- Evaluate Visibility Impacts

AECC assessed the visibility improvement associated with NO X controls by modeling the NO X emission rates associated w ith each control option using CALPUFF, and then comparing the visibility impairment associated with the base line 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 NO X controls, including the maximum m odeled visibility impact and the 98 th percentile modeled visibility impact. The visibility improvement associated with NO X controls was calculated as the difference between the baseline visibility impa irment and the visibility impairment for each control scenario as measured by the 98 th percentile modeled visibility impact.49 Table 29. Summary of Emission Rates Modeled for NO X Control Scenarios at AECC McClellan Unit 1

Control Scenario Fuel Scenario SO 2 (lb/hr) NOx (lb/hr) Total PM 10 (lb/hr) SO 4 (lb/hr) PMc (lb/hr) PMf (lb/hr) SOA (lb/hr) EC (lb/hr)CombustionControls 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 2.3SCR 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 2.3CombustionControls +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 98 th Percentile Visibility Impacts and Improvement due to NO X 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 98 th Percentile Visibility Impacts and Improvement due to NO X 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 NO X controls is projected to result in very modest visibility improveme nt 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 a nd 0.002 – 0.067 dv for fuel oil firing (based on the 98th percentile modeled visibility impacts). A combination of combusti on 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 contro ls + 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 NO X BART determination:

Taking into consideration the five factor s, we are proposing to determine that NO X BART for the AECC McClellan Unit 1 is no addi tional controls, and ar e proposing that the51 existing NO X emission limits satisfy BART for NO X . We are proposing the existing emission limit of 869.1 lb/hr for natural gas firing a nd 705.8 lb/hr for fuel oil firing for NO X BART for McClellan Unit 1. 35 As discussed above, the operation of combustion controls at McClellan Unit 1 is projected to resu lt in a maximum visibility improveme nt 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 McCle llan Unit 1 has an average costeffectiveness of $6,261/ton of NO X removed, which is not within th e 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 combus ting fuel oil and natural gas does not justify the high estimated cost of those controls. The ope ration of a combination of combustion controls + SNCR is estimated to cost $12,630/ton of NO X removed, which is also not cost-effective. A combination of combustion controls + SNCR is pr ojected to result in only slight incremental visibility benefit compared to combustion contro ls alone. The operation of SCR is estimated to cost $7,565/ton of NO X 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 oi l 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 NO X BART for McClellan Unit 1 is no additional controls and are proposing the aforementioned existing NO X emission limits for NO X BART. We are proposing that these already-existing emissi ons limitations be complied with for BART purposes from the eff ective date of the final action.

d. PM BART Evaluation

The five factors considered in the PM BART analysis for McClella n Unit 1 are discussed below.

Step 1- Identify All Availabl e 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 bur ned at McClellan Unit 1, has inherent ash that contributes to emissions of filterable PM. Filtera ble PM emissions could be reduced by switching to a lower grade fuel oil or natural gas. For comb ustion 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 SO 2 BART analysis for the unit.

Step 2- Eliminate Technically Infeasible Options

AECC’s evaluation noted that the particulate matter from o il-fired boilers tends to be sticky and small, affecting the collection efficien cy of dry ESPs and fabric filters. Dry ESPs operate by placing a charge on the pa rticles through a series of elect rodes, 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 periodical ly removed from the filter bag through a pulse jet or reverse flow mechan ism. Because of the sticky nature of particles from oil-fired boilers, dry ESPs and fabric filters are deemed t echnically infeasible for use at McClellan Unit 1. Wet ESPs, cyclones, wet scrubbers, and fuel swit ching were identified as technically feasible options for McClellan Unit 1. AECC noted th at although cyclones and wet scrubbers are considered technically feasible for use at thes e boiler types, they are not very efficient at controlling particles in the smalle r size fraction, particularly partic les 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 Effectiven ess of Remaining Control Technologies :
AECC estimated that switching to a lower sulf ur fuel has a PM cont rol efficiency ranging from approximately 44% - 99%, depending on the fuel type. The other technically feasible control technologies are estimated to have the fo llowing 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting 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 capit al 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 be low summarizes the average cost-effectiveness of PM controls. AECC determined the average cost-e ffectiveness by dividing the annualized cost of controls by the annual PM emissions reducti ons. The annual emissions reductions were determined by subtracting the estimated contro lled annual emission rates from the baseline annual emission rates, which were derived usi ng emission factors from AP-42, section 1.3-1. We disagree with two aspects of AECC’s cost evaluation for PM cont rols. First, the total annual cost numbers associated with fuel switchi ng should be the same as the cost numbers used in the SO 2 BART cost analysis for McClellan Unit 1 (see Table 24). In earlie r draft versions of AECC’s analysis, which were provided to us fo r review, the cost numbers for fuel switching used in the PM and SO 2 BART analyses were identical. In response to comments we provided, the total annual cost and average cost-effectiven ess numbers for fuel switching were revised in the final version of AECC’s SO 2 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 an alysis to be consistent with the cost estimates from AECC’s SO 2 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 peri od 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 th e AECC McClellan Generating Station, nor did the AECC’s evaluation indicate any future plan ned shutdown. Therefore, we believe that assuming a 30-year equipment lif e rather than a 15-year e quipment life would be more appropriate for these control tec hnologies. Extending the amortization period from 15 to 30 years has the effect of decreasing the total annual co st 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 th erefore we did not revise the amortization period or the average cost-effec tiveness 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 a nd operation of PM control equipment for McClellan Unit 1.

38 The final version of AECC’s BART analysis for SO 2 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 co st-effectiveness values of all add-on PM control technology options evalua ted for AECC McClellan Unit 1 ranged from approximately $15,000/ton of PM removed to more than $266,000/t on 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 SO 2 BART analysis, the current cost of natural gas is actually lower th an 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 discusse d above, AECC also expl ained that it expects controls to be less cost-effective ( i.e. , greater dollars per ton remove d) in future years due to projected reduced operation of the unit. Less project ed operating time is expected to result in lower annual emissions, which in turn would re sult in lower cost-effect iveness of controls. AECC did not identify any energy or non-air quality environmental impacts associated with fuel switching, but did identify impacts a ssociated with the use of wet ESPs and wet scrubbers due to their electricity usage. Ener gy use in and of itself does not disqualify a technology (40 CFR Part 51, Appendix Y, sectio n IV.D.4.h.1.). In addition, the cost of the electricity needed to operate this equipment has al ready been factored into the cost of controls. AECC also noted that both wet ESPs and wet scr ubbers generate wastewat er streams that must55 either be treated on-site or sent to a waste water treatment plant, and the wastewater treatment process will generate a filter cak e that would likely require landfilling. The BART Guidelines provide that the fact that a cont rol device creates liquid and solid wa ste 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 a nd the solid or liquid waste is similar to those other applica tions (40 CFR Part 51, Appendix Y, section IV.D.4.i.2.). We are not aware of any unusual circumstances at the AE CC McClellan Generating Station that could potentially create greater problems than experi enced 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 doe s not provide a basis for disqualification or elimination of a wet ESP or wet scrubber. With regard to consideration of any exis ting pollution control t echnology in use at the source, McClellan Unit 1 has no existing PM pol lution control technol ogy. The presence of existing pollution control technology at the source is reflected in the BART analysis in two ways: first, in the consideration of ava ilable 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 remaini ng useful life of the unit, we are not aware of any enforceable shutdown date for the AECC McClellan Generating St ation, nor did AECC’s evaluation indicate any future planned shutdown. Th is means that the antic ipated 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 a ppropriate to assume a 30-year am ortization period in the PM BART analysis as the remaining useful life of the unit. As discusse d in more detail below, AECC assumed a 15-year amortization period for contro l 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-eff ectiveness calculations for the PM control equipment options. This is discussed in more de tail below in the subsect ion titled “Our Proposed PM BART Determination.”

Step 5- Evaluate Visibility Impacts

As switching to lower sulfur fuels has impacts on both SO 2 and PM emissions, AECC’s assessment of the visibility improvement associat ed with fuel switching is addressed in the SO 2 BART analysis for McClellan Unit 1, which is discussed under section II.C.1.b. of this TSD. Table 18 summarizes the visibility improvement a ssociated with controlled emission rates for SO 2 and PM as a result of fuel switching. AECC assessed the visibility improvement a ssociated with wet ESPs, wet scrubbers, and cyclones by modeling the PM emission rates a ssociated with each control option using CALPUFF, and then comparing th e visibility impairment associ ated with the baseline emission rates to the visibility impairment associated with the controlled emission rates as measured by56 the 98 th percentile modeled visibil ity impact. The controlled PM 10 emission rates associated with wet ESPs, wet scrubbers, and cyclones were calculated by reducing the uncontrolled annual PM 10 emission rates by the pollutant removal e fficiency of each control technology. The SO 2 and NO X emission rates modeled in the controlled scenar ios are the same as those from the baseline scenario, as it is assumed that SO 2 and NO X emissions would remain unchanged. The tables below show the emission rates modele d 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 98 th percentile modeled vi sibility impact. The visibility improvement associated with each co ntrol scenario was calculated as the difference between the existing visibility impairment a nd the visibility impairment for each control scenario, as measured by the 98 th percentile modeled visibility impact.

Table 33. Summary of Emission Rates Modeled fo r PM Control Scenarios at McClellan Unit 1

Control SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PMf (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10 , 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 98 th 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 0.00257 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 minima l 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 natu ral gas is summarized in Table 18. These visibility improvement estimates reflect both SO 2 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 burni ng the baseline fuel oil at McClellan Unit 1 is due to SO 2 emissions, while PM 10 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 PM 10 ranges from approximately 0.5 – 3% for the fuel oil firing scenario. Most of the visibility impairment is attributable to SO 4 (67 – 99%) for the fuel oil firing scenario. Accordingl y, the majority of the visibility improvement associated with switching to lower sulfur fuels can reasonably be expected to be the result of reduced SO 2 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. C onsistent with our proposed determination for SO 2 BART, we are proposing that PM BA RT is satisfied by Unit 1 switching to fuels with 0.5% or lower sulf ur content by weight. As discussed above, we disagree with AECC’s use of a 15-year amortization period in th e cost analysis for a wet ESP, wet scrubber, and cyclone. EPA is not aware of any enfor ceable 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 ev aluation. 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 revise d AECC’s cost estimates to reflect a 30-year amortization period, resulting in a lower total an nual cost and improved cost-effectiveness, we would still not be able to justify the costs of a dd-on controls in light of the minimal visibility benefit of these contro ls (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 conten t by weight. We propose to require that the facility purchase no fuel after the effective date of the rule that doe s not meet the sulfur cont ent requirement and that 5 years from the effective date of the rule no fu el be burned that does no t meet the requirement. We expect this proposed compliance date woul d 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 restric tions 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 SO 2 and NO X for Flint Creek Unit 1 (77 FR 14604). AEP, through its consultant, performe d 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 h eat input rate of 6,324 MMBtu/hr, and burns primarily low sulfur western coal. The unit is currently equipped with an ESP and low NO X burners.

a. Baseline Emission Rates and Existing Visi bility Impairment Attributable to AEP Flint Creek Unit 1

AEP estimated SO 2 , NO X , and PM 10 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 baselin e emission rates are shown in the table below.

Table 35. AEP Flint Creek Unit 1: Ba seline Maximum 24-Hour Emission Rates

Source SO 2 (lb/hr) SO 4 (lb/hr) NO X (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 Pl ant 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 El ectric Power Company Flint Creek Powe r Plant. A copy of this BART analysis is found in the docket for our proposed rulemaking.59 The SO 2 and NO X baseline emission rates are the hi ghest actual 24-hour emission rates based on 2001-2003 CEMS data. Th e emission rates for the PM 10 species reflect the breakdown of the filterable and condensable PM 10 determined from the National Park Service (NPS) “speciation spreadsheet” for Dry Bottom Boiler Burning Pulverized Coal using only ESP

. 40 The sulfate (SO 4 ) emission rate was calculated using an EPRI methodology that considers the SO 2 to SO 4 conversion rate and SO 4 reduction factors for various downstream equipment. AEP then modeled the baseline emission ra tes using the CALPUFF dispersion model to determine the baseline visibility impairment attr ibutable 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 visibili ty impairment attributable to Flint Creek Unit 1 at each Class I area is summarized in the table below.

Table 36. Baseline Visibility Impairment Attr ibutable to AEP Flint Creek Unit 1 (2001- 2003)

Year Maximum ( ∆ dv) 98 th Percentile ( ∆ dv) No. of Days with ∆ dv ≥ 0.5 98 th Percentile

%SO 4 98 th Percentile

%NO 3 98 th Percentile

%PM 10 98 th Percentile

%NO 2 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. SO 2 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 PM 10 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 su lfur western coal, but is also permitted to burn fuel oil and tire derived fuels. Fuel oi l firing is only allowe d during unit startup and shutdown, startup and shutdown of pulverizer mills , for flame stabilization when coal is frozen, fuel oil tank maintenance, to prev ent boiler tube failure in extrem e cold weather when the unit is offline for maintenance, and malfunction. Sulfur oxides (or SO X ) are generated during coal and fuel oil combustion from the oxidation of sulfur contained in the fuel. SO X emissions are almost entirely dependent on the sulfur content of the fu el and are generally not affected by boiler size or burner design. SO X emissions from conventional combustion systems are predominantly in the form of SO 2 . The five factors considered in the SO 2 BART analysis are discussed below.

Step 1- Identify All Availabl e Retrofit Control Technologies

The SO 2 control technologies considered in AEP’s SO 2 BART analysis are Dry Sorbent Injection (DSI), a dry scr ubber, and a wet scrubber.

Step 2- Eliminate Technically Infeasible Options

All SO 2 control technology options considered in the analysis were determined to be technically feas ible options.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies :
DSI involves the injectio n of a sorbent into the exhaust stream where SO 2 reacts with and becomes entrained in the sorbent. The stream is then passed through a particulate control device to remove the sorbent and entrained SO 2 . In AEP’s analysis, it wa s noted that depending on residence time, gas stream temperature, and lim itations of the particul ate control device, DSI control efficiency can range between 40 to 60%. 41 In dry scrubbing systems, an alkaline reagen t and water are introduced into the flue gas stream, where they react with SO 2 to form calcium sulfite and calcium sulfate. The liquid-to-gas ratio is such that the heat from the exhaust ga s causes the water to evaporate before leaving the scrubber outlet, leading to the fo rmation of a dry powder which is carried out with the gas and collected with a fabric filter. Dry scrubber cont rol efficiency ranges from 60 to 95%. There are various designs of dry scrubbing systems, incl uding Spray Dryer Absorber (SDA), Circulating Dry Scrubbing (CDS), and Novel Integrated De sulfurization (NID) t echnology. According to AEP’s evaluation, discussions with vendors indi cated that an outlet emission rate of 0.06 lb/MMBtu at Flint Creek Unit 1 would be achieva ble with NID technology. In its analysis, AEP noted that it has no data to sugge st that lower emission levels ar e sustainably achievable with the

41 “Assessment of Control Technology Options for BART-E ligible 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 aver age 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 ta kes place in a wet sc rubbing tower located downstream of a PM control device such as a fabric filter or an ESP. AE P’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 SO 2 control technologies as evaluated by AEP. The remainder of AEP’s analys is focused on the two c ontrol options with the highest control efficiency: wet sc rubbing and dry scrubbing (NID).

Table 37. Control Effectiveness of Technically Feasible SO 2 Control Technologies for AEP Flint Creek Unit 1

Control Technology SO 2 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting pollution control technology in use at the source, and the remaining useful life of the source. The capital and operating cost s of a wet scrubber and a dry scrubber (NID) estimated in AEP’s analysis and used in the calculation of the average cost-effectiv eness were based on the EPA Control Cost Manual and supplemented, wh ere available, with ve ndor and site-specific information obtained by AEP. 42 AEP annualized the capital cost s over a 30-year period and then

42 See “BART Five Factor Analysis Flint Creek Power Pl ant 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 Powe r Company Flint Creek Power Plant. AEP’s SO 2 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 ob tain the total annualized costs. The annual emissions reductions used in th e 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 aver age 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 i nput to the boiler. AEP calculated the average cost-effectiveness in terms of dollars per ton of SO 2 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 SO 2 emission rate of 0.04 lb/MMBtu to be $4,919/ton of SO 2 removed, while the average cost-effec tiveness of NID at an SO 2 emission rate of 0.06 lb/MMBtu was estimated to be $3,845/ton of SO 2 removed (see the table below). We disagree with one asp ect of AEP’s cost analysis. 43 AEP’s cost estimates are based on 2016 dollars. AEP escalated costs to a future bu ild date, even though BART should be based on present dollars. The approach in the EPA Cont rol Cost Manual explicitly excludes future escalation, as cost comparisons should be made on a current real dollar basi s. 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-escala tion 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 evalua ted. However, we did not adjust the cost numbers and the costeffectiveness values because we do not expect th is to change our proposed BART decision. This is discussed in more detail below in the subsection titled “Our Proposed SO 2 BART Determination.”

Table 38. Summary of Cost of SO 2 Controls for AEP Flint Creek Unit 1

Control Technology Baseline Emission

Rate (SO 2 tpy) Controlled Emission

Rate (SO 2 lb/MMBtu) Controlled Emission

Rate (SO 2 tpy) Annual Emissions Reductions (SO 2 tpy) Capital Cost ($) Capital Recovery & Other Indirect Annual Costs ($/yr) Annual Fixed O&M ($/yr) Annual Variable

O&M ($/yr) Total Annual

Cost ($/yr) AverageCostEffectiveness ($/ton) IncrementalCostEffectiveness ($/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 poten tial negative energy and non-air quality environmental impacts are greater with wet scr ubbing 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 befo re landfilling, pl acing additional burden on the wastewater treatment and solid wast e management capabilities. We do not expect that water availability would affect the feasibi lity of a wet scrubber at Flint Creek Unit 1 because the facility is not located in an exceptionall y arid region. Additionall y, the BART Guidelines provide that the fact that a cont rol device creates liquid and solid wa ste 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 facili ty 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 op tion as BART. But in this case, AEP has not indicated that there are any su ch unusual circumstances. Anothe r potential negative energy and non-air quality environmental impact associated with wet scrubbing systems is the potential for increased power requirements and greater reagen t usage compared to dry scrubbers. The costs associated with increased power requirements and greater reagent usage have already been factored into the cost anal ysis for the wet scrubber. The presence of existing pollution control t echnology at the source is reflected in the BART analysis in two ways: first, in the cons ideration of available c ontrol technologies, and second, in the development of baseline emission rate s for use in cost calcul ations and visibility modeling. AEP Flint Creek Unit 1 has no existing SO 2 pollution control technology. With regard to consideration of the remaini ng useful life of the unit, we are not aware of any enforceable shutdown date for AEP Flint Cr eek 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 cap ital cost recovery period of cont rols. Therefore, we believe it is appropriate to assume a 30-year amortization period in the SO 2 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 SO 2 emission rates associated with each control option using CALPUFF, and then comparing th e visibility impairment associ ated with the baseline emission rates to the visibility impairment associated w ith the controlled emission rates, as measured by the 98 th percentile modeled visibi lity impact. The modeled SO 2 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 NO X 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 fabric64 filter for emissions control. The tables below sh ow the modeled emission rates and a comparison of the baseline ( i.e. , existing) visibility impacts and the vi sibility impacts of a wet scrubber and NID technology, including the maximum m odeled visibility impact and the 98 th percentile modeled visibility impact for each Class I area. The visibility improvement associated with each control scenario was calculated as the differen ce between the existing visi bility impairment and the visibility impairment for each control scenario as measured by the 98 th 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 SO 2 Control Scenarios at AEP Flint Creek Unit 1

Control Technology SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM f (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 98 th Percentile Visibility Impacts and Improvement Due to SO 2 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 SO 2 controls at Flint Creek Unit 1 is expected to result in considerable vi sibility improvement at the four modeled Class I areas. Installation and operati on of NID technology is project ed to result in visibility65 improvement of up to 0.615 dv at any single Class I area (based on the 98 th percentile modeled visibility impacts), while a wet scrubber is project ed to result in visibil ity improvement of up to 0.629 dv. A wet scrubber is projected to result in ve ry minimal incremental visibility benefit over NID technology, with the projected incremental vi sibility improvement over NID ranging from 0.007 to 0.014 dv at each Class I area.

Our Proposed SO 2 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/MMB tu on a 30 boiler-operating-day rolling average based on the installation and opera tion of NID. The operation of NI D is expected to result in visibility improvement ranging from 0.352 to 0.629 dv at each affected Class I area (98 th percentile basis), and based on AEP’s evaluation, is estimated to have an average costeffectiveness of $3,845/ton of SO 2 removed. By comparison, AEP estimated a wet scrubber to have an average cost-effectiveness of $4,919/ton of SO 2 removed and the incremental costeffectiveness of wet scrubbers compared to NID is estimated to be $35,240 per ton of SO 2 removed. As discussed above, we believe that AEP’ s escalation of the cost of controls to 2016 dollars has likely resulted in the over estima tion of the average cost-effectiveness values. Therefore, we believe a wet scrubbe r and NID are more cost-effective ( i.e. , less dollars per ton of SO 2 removed) than estimated by AEP (see table a bove). 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-effectiv eness of both control options was likely over-estimated and the costs asso ciated with a wet scru bber 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 SO 2 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 time 44 of 5 years is warranted for a new scrubber retrof it and so propose to require co mpliance with this requirement no later than 5 years from the effective date of the final rule.

c. NO X BART Evaluation

Nitrogen oxides, or NO X , 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 NO X from fossil fuel combustion, with nitrogen dioxide (NO 2 ) making up the remainder of the NO X . AEP’s evaluation noted that the formation of NO X 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 F lint Creek Unit 1, burners ar e 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 di screte flames produced by burners in the wall-fired boilers. Tangentially fired boilers typically have lower uncontrolled NO X emissions than wall-fired bo ilers. Therefore, baseline NO X emission rates can vary significantly from plant to plant due to method of firing and combustion flame temperatures, among other factors. The baseline NO X emission rate for Flint Creek Unit 1 was discussed under section II.C.2.a. of this TSD. The five factors considered in the NO X BART analysis are discussed below.

Step 1- Identify All Availabl e Retrofit Control Technologies

The NOx control technologi es considered in AEP’s NO X BART report include both combustion and post-combustion controls. The com bustion controls evaluate d consisted of FGR, OFA, and LNB. The post-combustion controls evaluated consisted of SCR and SNCR.

Step 2- Eliminate Technically Infeasible Options

All evaluated NO X control options were found to be technically feasible.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies :

The estimated NO X controlled emission rate of each control option considered by AEP is shown in the table below. The baseline NO X emission rate for Flint Creek Unit 1 is approximately 0.31 lb/MMBtu. AEP’s evaluation stat ed that based on experience with similar boilers and discussions with vendors, it is esti mated that the installa tion and operation of new LNB in combination with OFA at Flint Creek Unit 1 would achieve a NO X control level of approximately 0.23 lb/MMBtu. It also estimated that new LNB/OFA in combination with SNCR would achieve a NO X control level of approximately 0.2 lb/MMBtu, and SCR would achieve a NO X control level of approximately 0.067 lb/MMBtu.

Table 41. Control Effectiveness of Technically Feasible NO X 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 – 0.2467 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting 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 NO X controls based on vendor estimates and published calculation methods. 45 AEP noted that the cost analysis followed the EPA Control Cost Manua l to the extent possible and estimates were supplemented with vendor and site-specific info rmation where available. The cost analysis assumed a 30-year amortization period for LN B 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 peri od and then adding to this value the annual operating cost of controls. AEP determined the annual emissions reductions associated with each NO X control option by subtracting the estimate d controlled annual emission rate from the baseline annual emission rate. The baseline annua l emission rate is the av erage 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 NO X controls was calculated by dividing the total annual cost of each control opt ion by the estimated annual NO X emissions reductions. The table below summarizes the average-cost effectiveness of NO X controls for Flint Creek Unit 1.

45 See “BART Five Factor Analysis Flint Creek Power Pl ant 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 Powe r Company Flint Creek Power Plant. AEP’s NO X 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 NO X Controls for AEP F lint Creek Unit 1

Control Technology Baseline NO X Emission

Rate (tpy) Controlled Emission

Level (lb/MMBtu) Controlled Emission

Rate (NO X tpy) Annual Emissions Reductions (NO X tpy) Capital Cost ($) Annual Capital

Cost ($.yr) Annual Fixed O&M ($/yr) Annualized Variable

O&M ($/yr) Total Annual

Cost ($/yr) AverageCostEffectiveness ($/ton) IncrementalCostEffectiveness ($/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 Cr eek Unit 1, the average cost-effectiveness of installing and operating LN B/OFA is $1,761/ton of NO X removed. The average costeffectiveness of LNB/OF A + SNCR is $3,098/ton of NO X removed, while that of SCR is $3,559/ton of NO X removed. The incremental cost-e ffectiveness of LNB/OFA + SNCR compared to LNB/OFA is $5,217/ton of NO X removed, while that of SCR compared to LNB/OFA + SNCR is $3,805/ton of NO X removed. AEP did not identify any energy or non-air qu ality 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 enviro nmental 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 NO X 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 NO X burners for control of NO X emissions. The presence of existing po llution control technology at each source is reflected in the BART analysis in two ways: first, in the co nsideration of av ailable control technologies, and second, in the development of baseline emission rates for use in cost calculations and visibility modeli ng. The baseline emission rate used in the cost calculations and visibility modeling reflects the operation of these contro ls. The newer generation low NO X burners evaluated by AEP are expected to achieve a higher level of NO X control than the currently installed ea rly generation low NO X burners. With regard to consideration of the remaini ng 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 th at the anticipated useful life of the boiler is expected to be at least as long as the capital cost recovery pe riod of controls. AEP assumed a 30- year amortization period in th e evaluation of LNB/OFA and S CR and a 20-year amortization period in the evaluation of SNCR. We disagree with AEP’s assu mption of a 20-year amortization69 period in the cost analysis of SNCR. Any air pollu tion controls on the unit are expected to have the same life as the boiler. Therefore, we be lieve 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 dolla rs per ton removed) than estimated in AEP’s evaluation. However, we did not adjust the am ortization 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 co st 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 NO X controls by modeling the NO X emission rates associated w ith each control option using CALPUFF, and then comparing the visibility impairment associated with the base line 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 th e 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 NO X controls, including the ma ximum modeled visibility impact and the 98 th 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 associat ed with each control scenario. The incremental visibility improvement of LN B/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 diffe rence in visibility improvement between SCR and LNB/OFA + SNCR.

Table 43. Summary of Emission Rates Modeled for NO X Control Scenarios at AEP Flint Creek Unit 1

Control Technology SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM (lb/hr) PM F (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 1.970 Table 44. AEP Flint Creek Unit 1: Summary of 98 th Percentile Visibility Improvement Due to NO X 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 ba seline 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 id entified 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 ope ration of LNB/OFA at Flint Creek Unit 1 is projected to result in visibility improveme nt ranging from 0.014 to 0.081 dv at each modeled Class I area, based on the 98 th percentile visibility impairment. The installation and operation of LNB/OFA + SNCR is projected to result in vi sibility improvement of up to 0.114 dv at each modeled Class I area over the baseline. The comb ination of LNB/OFA + SNCR is projected to result in small incremental visibility benef it 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 opera tion 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 incremental71 visibility benefit over LNB /O FA + SNCR at Caney Creek a nd less than half as much incremental visibility benefit at the other three affected Class I areas.

Our Proposed NO X 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/MMB tu on a 30 boiler-operating-day rolling average based on the installation and ope ration of new LNB/OFA. The operation of new LNB/OFA is projected to result in visibility improveme nt ranging from 0.014 to 0.081 dv at each affected Class I area (98 th percentile basis), and a cumula tive 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 NO X removed, which we consider to be very costeffective. By comparison, the operation of LNB/ OFA + SNCR is projecte d to result in small incremental visibility improvement over LNB/OFA, but is estimated to have an average costeffectiveness of $3,098/ton of NO X removed and an incremental cost-effectiveness of $5,217/ton of NO X removed. We believe that AEP’s assumption of a 20-year amortization period for SNCR has likely resulted in the over-estimation of the av erage cost-effectiveness value. Therefore, we believe LNB/OFA + SNCR is more cost-eff ective (i.e., less do llars per ton of NO X 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 installati on 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 resu lt in visibility improvement ranging from 0.043 to 0.245 ∆ dv at each Class I area, and has an av erage cost-effectiven ess of $3,559/ton of NO X removed. The incremental visibility benefi t of SCR compared to LNB/OFA + SNCR is a maximum of 0.131 dv at any single Class I area, and the incremental co st-effectiveness is estimated to be $3,805/ton of NO X removed. While we believe the average and incremental costeffectiveness of SCR, as estimated by AEP, is w ithin the range of what we consider to be costeffective, we do not believe the 0.131 dv increm ental visibility benefit of SCR over LNB/OFA + SCNR warrants the higher costs associated with SCR. We are proposing to determine that NO X BART for Flint Creek Unit 1 is an emission lim it of 0.23 lb/MMBtu on a 30 boiler-operating-day rolling average based on the installation and opera tion of new LNB/OFA. We consider 3 years to be an adequate time for the installation of NO X combustion controls and thus propose to require compliance with this requirement no later than 3 y ears from the effective da te 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 determinations72 for SO 2 and NO X for Units 1 and 2 and the BART dete rmination 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 tang entially-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 prim ary fuel and No. 2 fuel oil or biofuel as a start-up fuel. Units 1 and 2 are currently equipped with ESPs for cont rol 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 primar y boilers, Units 1 and 2. The Auxiliary Boiler is typically only used in the rare instance when both of the ma in boilers are not operating.

a. Baseline Emission Rates and Existing Visibi lity Impairment Attributable to White Bluff Units 1, 2, and Auxiliary Boiler

Entergy estimated SO 2 , NO X , and PM 10 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 defa ult natural conditions. The baseline emission rates are from actual emissions based on CEMS data, stack testing, and annual emissions inventory information. The ba seline emission rates are shown in the table below.

Table 45. Entergy White Bluff: Baselin e Maximum 24-Hour Emission Rates

Subject to BART Unit SO 2 (lb/hr) NO X (lb/hr) Total PM 10 (lb/hr) SO 4 (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 SO 2 and NO X baseline emission rates are the hi ghest actual 24-hour emission rates based on CAMD data from 2001-2003 for SO 2 and from 2009-2011 for NO X

. The 2001-2003 period was not used as the baseline for NO X because that period no longer represents actual operation of the boile rs. In 2006, Entergy comple ted the addition of a

46 See “Revised BART Five Factor Analysis White Bluf f Steam Electric Station Redfield, Arkansas (AFIN 35- 00110),” dated October 2013, prepared by Trinity Consu ltants 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 NO X emissions, resulting in an actual change in operations and emissions between the original baseline period (2001-2003) a nd 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, NO X emissions, and carbon monoxide (CO) levels. According to information provided by th e 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 fo r monitoring and controlling the heat rate, and second for minimizing NO X emissions. We believe the use of 2009-2011 as the new baseline period for NO X is consistent with the BART Guide lines, which provide that “The baseline emissions rate should represent a realistic depiction of anticip ated annual emissions for the source” (40 CFR Part 51, Appendi x Y, Section IV.D.4.c). The PM 10 emission rates are based on emi ssion factors from AP-42 for PM 10 filterable and PM condensable with a 99% control efficiency for ESP applied to the PM 10 filterable in conjunction with the average coal heat va lue and average coal % ash from 2009-2011. The emission rates for the PM 10 species reflect th e breakdown of the PM 10 determined from the National Park Service (NPS) “speciation spreadsh eet” 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 SO 4 . 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 H 2 SO 4 produced and the amount of H 2 SO 4 removed by control equipment using information from the Electric Power Research Institute (EPRI). 49 Rather than assuming that 100% of inorganic condensable PM is SO 4 , the EPRI method estimates the amount of SO 2 that is oxidized to SO 3 , assumes that 100% of SO 3 is converted to H 2 SO 4 , and then accounts for losses due to downstream equipment. The sulfuric acid emission s for the base and control scenarios may be somewhat overestimated in Entergy’s modeling. Ho wever, in this specific situation, we do not anticipate that this difference would significan tly impact the relative benefits of the SO 2 controls examined or impact our BART determination sin ce the overall impacts an d benefits of control are large.

47 See the “S&L NO X 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 th is 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. Enterg y input the following parameters into the workbook for speciation determination: total PM 10 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: 201074 Entergy then modeled the baseline emissi on rates using the CALP UFF dispersion model to determine the baseline visibility impairment attributable to White Bluff Unit 1, Unit 2, and the Auxiliary Boiler at the Caney Creek Wilder ness Area, Upper Buffalo Wilderness Area, Hercules-Glades Wilderness Area, and Mingo Nationa l 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 At tributable to White Bluff Unit 1

Year Maximum ( ∆ dv) 98 th Percentile ( ∆ dv) No. of Days with ∆ dv ≥ 0.5 98 th Percentile

%SO 4 98 th Percentile

%NO 3 98 th Percentile

%PM 10 98 th Percentile

%NO 2 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 At tributable to White Bluff Unit 2

Year Maximum ( ∆ dv) 98 th Percentile ( ∆ dv) No. of Days with ∆ dv ≥ 0.5 98 th Percentile

%SO 4 98 th Percentile

%NO 3 98 th Percentile

%PM 10 98 th Percentile

%NO 2 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 Wilderness75 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 Attr ibutable to White Bluff Auxiliary Boiler

Year Maximum ( ∆ dv) 98 th Percentile ( ∆ dv) No. of Days with ∆ dv ≥ 0.5 98 th Percentile

%SO 4 98 th Percentile

%NO 3 98 th Percentile

%PM 10 98 th Percentile

%NO 2 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. SO 2 BART Evaluation for Units 1 and 2

White Bluff Units 1 and 2 burn sub-bituminous co al 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 SO X , are generated during fuel combus tion from the oxidation of sulfur contained in the fuel. SO X emissions are almost entirely depe ndent on the sulfur content of the fuel and are generally not affected by boiler size or burner design. SO X emissions from conventional combustion systems are predominantly in the form of SO 2 . The five factors considered in the SO 2 BART analysis are discussed below.

Step 1- Identify All Availabl e Retrofit Control Technologies76 The SO 2 control technologies c onsidered in Entergy’s SO 2 BART analysis are DSI, dry FGD, and wet FGD.

Step 2- Eliminate Technically Infeasible Options

All SO 2 control technology options considered in the analysis were determined to be technically feas ible options.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies :
DSI involves the injectio n of a sorbent into the exhaust stream where SO 2 reacts with and becomes entrained in the sorbent. The stream is then passed through a particulate control device to remove the sorbet and entrained SO 2 . Entergy’s evaluation noted that depending on residence time, gas stream temperature, and limitations of the particulate cont rol device, the control efficiency of dry sorbent inje ction can range between 40 – 60%. 50 There are various designs of dry FGD sy stems, 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 th rough the application of wet FGD when burning higher-sulfur coals, but that En tergy was not able to obtain ve ndor 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 SO 2 emission rate of 0.04 lb/MMBtu. The remainder of Entergy’s analysis focused on the two control opt ions 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-Eligib le 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 Bluf f Steam Electric Station Redfield, Arkansas (AFIN 35- 00110),” dated October 2013, prepared by Trinity Consulta nts Inc. in conjunction with Entergy Services Inc., Page 5-3.77 The four factors considered in this step of the analysis ar e 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 Analys is for Entergy White Bluff:

Entergy’s estimates of the capital and dire ct operating and maintenance costs of a dry scrubber were based on vendor estimates. Estimates of the indirect operati ng costs were based on calculation methods from our Cont rol Cost Manual. The estimate s of the capital and operating and maintenance costs of wet FGD were base d on vendor estimates obtained by Entergy for a system estimated to achieve 97% control a nd 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 Ru le, 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 wi ll burn a coal corresponding to an uncontrolled SO 2 emission rate of 2.0 lb/MMBtu – far in ex cess of the sulfur leve l of the coals it has historically burned, presumably for future fuel flexibi lity. For the years 2009-2013, the maximum monthly SO 2 emission rate for Unit 1 is 0.653 lb s/MMBtu and that for Unit 2 is 0.679 lbs/MMBtu. Thus, Entergy has costed SO 2 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 correspondingl y higher cost. Entergy selected its SO 2 emission baseline by using “the average rate from 2001-2003, as reported by Entergy in their air emission inventories,” 55 while selecting its annua lized costs based on a 2.0 lb/MMBtu coal. In calculating baseline emissi ons, 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 presen ted in Entergy’s report includes line items that have not been documented, appear to be already c overed 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 (SO 2 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 (SO 2 Cost TSD),” for a detailed discussion of how Entergy’s co st analysis was adjusted.78 capital suspense, 58 Entergy internal costs, and certain line items unde r balance of plant (BOP) costs. Please see our SO 2 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 pres ented in the table below.

Table 49. Summary of EPA Dry FGD Cost An alysis for White Bluff Units 1 and 2

Item White Bluff Unit 1 White Bluff Unit 2

Total Annualized Cost $31,981,230 $31,981,230 Interest Rate (%) 7 7 Equipment Lifetime (years) 30 30 Capital Recovery Factor (CRF) 0.0806 0.0806
SO 2 Emission Rate (lbs/MMBtu) 0.65 0.68
Controlled SO 2 Emission Rate (%) 90.81 91.16
SO 2 Emission Baseline (tons) 15,816 16,697
SO 2 Emission Reduction (tons) 14,363 15,221 Cost Effectiveness ($/ton) $2,227 $2,101

Our Wet Scrubbing Cost Analys is 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 Manual 60 to calculate the Total Capital Investment (TCI). Entergy then calculated the direct annual costs, using fixed and variable O&M cost s from another 2011 contractor cost summary as

58 Entergy states capital suspense “is a distribution of overh ead costs associated with ad ministrators, 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 th e budgeted capital spending for a specifi c 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 indir ect 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 SO 2 emission rate of 2.0 lb/MMBtu, which are overdesigned compared to its historical needs. Please see our SO 2 Cost TSD for more details concerning the adjustments we propose to make to the White Blu ff 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 An alysis for White Bluff Units 1 and 2

Item White Bluff Unit 1 White Bluff Unit 2

Total Annualized Cost $49,526,167 $49,526,167 Interest Rate (%) 7 7 Equipment Lifetime (years) 30 30 Capital Recovery Factor (CRF) 0.0806 0.0806
SO 2 Emission Rate (lbs/MMBtu) 0.65 0.68
Controlled SO 2 Emission Rate (%) 93.87 94.11
SO 2 Emission Baseline (tons) 15,816 16,697
SO 2 Emission Reduction (tons) 14,847 15,713 Cost Effectiveness ($/ton) $3,336 $3,152

Entergy’s evaluation noted that while wet FGD is expected to achieve a slightly higher level of control of SO 2 emissions compared to dry FGD, the potential negative energy and nonair quality environmental impacts are greater w ith wet FGD systems. Entergy noted that wet FGD systems require increased water use and gene rate 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 201 1 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 feasibilit y of wet FGD since the facility is not located in an exceptionally arid region. Additionally, the BA RT Guidelines provide that the fact that a control device creates liquid and so lid waste that must be disposed of does not necessarily argue against selection of that technol ogy 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 provi de a basis for the elimination of that control option as BART. But in this case, Entergy has not indicated that ther e are any such unusual circumstances. Entergy’s evaluation also point ed out that wet FGD sy stems have increased power requirements and greater reagent usage comp ared to dry FGD. The costs associated with increased power requirements and greater reagent us age have already been factored into the cost analysis for wet FGD. Consideration of the presen ce of existing pollution contro l technology at the source is reflected in the BART analysis in two ways: fi rst, in the consideration of available control technologies, and second, in the development of baseline emission rates for use in cost calculations and visibility mode ling. White Bluff Units 1 and 2 cu rrently do not operate any SO 2 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 th at the anticipated useful life of the boilers is expected to be at least as long as the capital cost recovery pe riod of controls. Therefore, a 30- year amortization period was assumed in the SO 2 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 SO 2 emission rates associated with each control option using CALPUFF, and then comparing the visibility impairment associated w ith the baseline emission rates to the visibility impairment associated with the contro lled emission rates as measured by the 98 th percentile modeled visibility impact. Ente rgy calculated the modeled SO 2 emission rates associated with wet FGD and dry FGD were calculated by mu ltiplying 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 NO X emission rate was modeled at the ba seline rate for both the wet and dry FGD options. For all PM species other than amm onium sulfate, the NPS speciation spreadsheets were relied upon to determine emission rates for PM species. A portion of SO 2 is further oxidized to SO 3 , which is then converted to sulfuric ac id. Sulfuric acid ca n react with ammonia to form ammonium sulfate. The ammonium sulf ate emission rates for semi-dry scrubbers were estimated by Entergy by assuming the reduction in ammonium sulfate (SO 4 ) is proportional to the reduction in SO 2 from the baseline to the controlled ca se (95%), while the ammonium sulfate81 emission rates for wet FGD were estimated by Entergy by assuming 50% reduction in SO 4 from the baseline case to the controll ed case. This is because wet FGD systems generally have less affinity for SO 3 , typically capturing between 25-50% of the SO 3 . 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 H 2 SO 4 produced and the amount of H 2 SO 4 removed by control equipment using information from the Electric Power Research Institute (EPRI). 63 However, in this specific situation, we do not anticipate th at this difference in methodology would significantly impact the relative benefits of the SO 2 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 show ed 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 F GD and dry FGD, at each Class I area. The visibility improvement associated w ith each control scenario was calculated as the difference between the baseline visibility impa irment and the visibility impairment for each control scenario as measured by the 98 th percentile modeled visibility impact at each Class I area.

Table 51. Summary of Emis sion Rates Modeled for SO 2 Controls for Wh ite Bluff Units 1 and 2

Source SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/ hr) PM 10 , 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: 201082 Table 52. Entergy White Bluff Unit 1: Summary of the 98 th Percentile Visibility Impacts and Improvement Due to SO 2 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 98 th Percentile Visibility Impacts and Improvement Due to SO 2 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 0.02883 The tables above show that th e installation and operation of SO 2 controls at White Bluff Units 1 and 2 is expected to re sult in considerable visibility improvement at the four modeled Class I areas, measured as the difference between the 98 th percentile visibility impairment associated with the baseline and the 98 th percentile visibility impairment associated with each control option. The installation a nd operation of dry FGD is projec ted to result in visibility improvement of up to 0.813 dv at any single Cla ss I area for Unit 1 and 0.767 dv for Unit 2. The installation and opera tion 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 a nd Mingo, it is projected to result in slight vi sibility disbenefit.

Our SO 2 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 opera tion of dry FGD or a nother control technology that achieves that level of cont rol. 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 (98 th percentile basis) for Unit 1 and ranging from 0.593 to 0.767 dv for Un it 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 SO 2 removed for Unit 1 and $2,101/ton of SO 2 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 SO 2 removed for Unit 1 and $3,152/ton of SO 2 removed for Unit 2. Therefore, considering the five BART factor s and the slight visibility be nefit at Caney Creek and Upper Buffalo and slight disbenefit at Hercules-Glade s and Mingo of wet FGD over dry FGD, we are proposing to determine that SO 2 BART for White Bluff Units 1 and 2 is an emission limit of 0.06 lb/MMBtu on a 30 boiler-operating-day rolli ng average based on the installation and operation of dry FGD or another c ontrol technology that achieves th at level of control. We are proposing to require compliance w ith this requirement no later th an 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 requ ire compliance with this requirement no later than five years from the effective date of the final rule, consistent w ith 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. NO X BART Evaluation for Units 1 and 2

Nitrogen oxides, or NO X , are produced during fuel combustion when nitrogen contained in both the fuel and the combustion air is expos ed to high temperatures. Entergy’s evaluation noted that the formation of NO X compounds in utility boilers is sensitive to the method of firing. In tangentially-fired boilers, su ch as White Bluff Units 1 and 2, a single rotating flame is created in the center of the furnace, rather than the di screte flames produced by burners in the wall-fired boilers. Tangentially fired boilers ty pically have lower uncontrolled NO X emissions than wallfired boilers. Theref ore, baseline NO X emission rates can vary signi ficantly from plant to plant due to method of firing as well as se veral other factors. The baseline NO X emission rates for White Bluff Units 1 and 2 were discussed under sec tion II.C.3.a. of this TSD. The five factors considered in the NO X BART analysis are discussed below.

Step 1- Identify All Availabl e Retrofit Control Technologies

The NO X control technologies c onsidered in Entergy’s NO X BART report include both combustion and post-combustion controls. The com bustion controls evaluate d consisted of FGR, separated overfire air (SOFA), and LNB. The po st-combustion controls ev aluated consisted of SCR and SNCR.

Step 2- Eliminate Technically Infeasible Options

In its evaluation, Entergy noted that the amount of NO X 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 NO X than fuel NO X , 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 offe red by vendors for coal-fired units. Therefore, FGR is not considered to be a technically feas ible control technology fo r the coal-fired White Bluff Units 1 and 2. All other available NO X control options were id entified as technically feasible.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies :
Entergy evaluated three control scenarios: LNB/SOFA; the combination of LNB/SOFA + SNCR; and the combination of LNB/SOFA + S CR. Entergy relied on literature control ranges and efficiencies and vendor estimates in arrivi ng at the expected cont rolled emission rates for White Bluff Units 1 and 2. The baseline NO X 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 initial85 fuel-rich combustion zone with a lower peak flam e temperature, which reduces the formation of thermal NO X . SOFA refers to a system where the OFA is inject ed in a separate wind box mounted above the main wind box in order to ac hieve greater separation from the combustion zone. Entergy estimates SOFA would achieve a controlled NO X emission rate of 0.28 – 0.32 lb/MMBtu for Units 1 and 2. LNB technology uses advanced burner design to reduce NO X formation through the restriction of oxygen, which lowers flame temperature and/or reduces the residence time. When LNB is combined with SO FA, 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 NO X emission rate of 0.13 lb/MMBtu, and when SCR is combined with LNB/SOFA it is expected to achieve a controlled NO X 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting pollution control technology in use at the source, and the remaining useful life of the source. Entergy estimated the capital costs, operati ng 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 valu e the annual operating cost of controls. The annual emissions reductions associated with each NO X control option were determined by subtracting the estimated contro lled annual emission rates from the baseline annual emission rate. The baseline annual emissi on rate is the average rate as reported by Entergy in the 2009-2011 air emissi on inventories, while the cont rolled 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 NO X controls was calculated by divi ding the total annual co st of each control opt ion by the estimated annual NO X emissions reductions. We note that Entergy’s cost estimate for each NO X 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 Bluf f Steam Electric Station Redfield, Arkansas (AFIN 35- 00110),” dated October 2013, prepared by Trinity Consu ltants Inc. in conjunction with Entergy Services Inc., Page Appendix A to the BART analysis contains Entergy’s NO X control cost calculations and Appendix E contains the “NO X 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 includ ed 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 specifi c rates and corporate accounting rates. However, we do not believe cap ital suspense should be included in the cost analysis because those costs have not been docum ented by Entergy and do not appear to be valid costs under the Control Cost Manual methodology. We have adjusted the cost estimate of NO X controls by subtrac ting the capital suspense line item from the capital costs. 68 Based on our adjustment to Entergy’s cost estimate, the aver age cost-effectiveness of LNB/SOFA is estimated to be $350/ton of NO X removed for Unit 1 and $340/ton of NO X removed for Unit 2, while the average cost-effectiveness of LNB/SOFA + SNCR is estim ated to be $1,758/ton of NO X removed for Unit 1 and $1,449/ton of NO X removed for Unit 2 (see table below). The average cost-effectiveness of LN B/SOFA + SCR is estimated to be $3,552/ton of NO X removed for Unit 1 and $2,749/ton of NO X removed for Unit 2.

Table 54. Summary of NO X Control Costs for Entergy White Bluff Units 1 and 2

Control Technology Baseline Emission

Rate (NO X tpy) Controlled Emission

Level (lb/MMBtu) Controlled Emission

Rate (tpy) Annual Emissions Reduction (NO X tpy) Capital Cost ($) Annual Fixed O&M ($/yr) Annualized Variable

O&M ($/yr) Total Annual

Cost ($/yr) Average Cost Effectiveness ($/ton) IncrementalCostEffectiveness ($/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-ai r quality environmenta l impacts associated with the use of LNB/SOFA. As for SCR a nd SNCR, we are not aware of any unusual circumstances at the facility th at could create energy or non-ai r quality environmental impacts

68 See the spreadsheet titled “EPA NO X 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 NO X controls at Entergy White Bluff Units 1 and 2 that would affect our proposed BART determination. Consideration of the presen ce of existing pollution contro l technology at each unit is reflected in the BART analysis in two ways: fi rst, in the consideration of available control technologies, and second, in the development of baseline emission rates for use in cost calculations and visibility modeli ng. Other than the installation of a neural net system in 2006 to optimize boiler combustion efficiency, wh ich had the co-benefit of decreasing NO X emissions compared to the 2001-2003 baseline, White Bluff Units 1 and 2 have no existing NO X pollution control technology. The lower NO X emissions achieved as a co-b enefit of installing the neural net system is reflected in the analysis by the use of 2009-2011 as the baseline for the NO X BART analysis. With regard to consideration of the remaini ng useful life of the units , we are not aware of any enforceable shutdown date for White Blu ff Units 1 and 2, nor did Entergy’s evaluation indicate any future planned shutdown. This means th at the anticipated useful life of the boilers is expected to be at least as long as the capital cost recovery pe riod of controls. Therefore, a 30- year amortization period was appropriate ly assumed in the evaluation of NO X controls as the remaining life of Units 1 and 2.

Step 5- Evaluate Visibility Impacts

Entergy assessed the visibility improvement associated with NO X controls by modeling the NO X emission rates associated with each control option using CALPUFF, and then comparing the visibility impairment associated w ith the baseline emission rate to the visibility impairment associated with the contro lled emission rates as measured by the 98 th percentile modeled visibility impact. The controlled emi ssion level associated with LNB/SOFA is 0.15 lb/MMBtu; the controlled emission level a ssociated 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 m odeling. 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 NO X controls, based on the 98 th percentile modeled visi bility impacts for each Class I area.88 Table 55. Summary of Emis sion Rates Modeled for NO X Controls for Entergy White Bluff Units 1 and 2

SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10, 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 98 th Percentile Visibility Impacts and Improvement due to NO X 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 98 th Percentile Visibility Impacts and Improvement due to NO X 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/SO FA 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 98 th percentile visibility impairment . The installation and operation of LNB/SOFA + SNCR is projected to result in visibility improveme nt of up to 0.2 dv in any single Class I area for Unit 1 and 0.258 dv for Unit 2. Th e 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 in cremental visibility benefit over LNB/SOFA + SN CR 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 vi sibility benefit ove r 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 NO X 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 improveme nt 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 (98 th 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 co st-effectiveness of $350/ton of NO X removed for Unit 1 and $340/ton of NO X 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 NO X removed for Unit 1 and $1,449/ton of NO X removed for Unit 2. The incremental costeffectiveness of LNB/SOFA + SNCR compared to LNB/SOFA is $9,665/ton of NO X removed for Unit 1 and $9,900/ton of NO X removed for Unit 2.While the average cost-effectiveness of LNB/SOFA + SNCR is still very co st 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 incrementa l 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 av erage cost-effectiveness of $3,552/ton of NO X removed. LNB/SOFA + SCR at Unit 1 is projected to resu lt in up to 0.069 dv of incremental visibility improvement over LNB/SOFA + SNCR at any singl e Class I area, and its incremental costeffectiveness is estimated to be $6,717/ton of NO X 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 aver age cost-effectivene ss of $2,749/ton of NO X 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 singl e Class I area, and its incremental costeffectiveness is estimated to be $5,736/ton of NO X 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-effectiv eness of $6,717/ton of NO X removed for Unit 1 and $5,736/ton of NO X removed for Unit 2. Therefore, we are proposing to determine that NO X BART for White Bluff Units 1 and 2 is an emission limit of 0.15 lb/M MBtu on a 30 boiler-operating-day rolling average based on the installation and ope ration of LNB/SOFA. We are pr oposing 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 fo r 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 ev en lower at the other modeled Class I areas (98 th percentile basis). The BART Rule provides that “Consis tent 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 di stance 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 sugge st 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 cl ear that controls would be costly and any improvements in visibility resulting from reducti ons in emissions of that pollutant would be negligible.” (70 FR 39116). Given the very small baseline visibility impact s from the Auxiliary Boiler, we believe it is appropriate to take a streamlined approach fo r determining BART in th is 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 ex isting emission limits satisfy BART for SO 2 , NO X , and PM. We are proposing that the existing emission limit of 105.2 lb/hr is BART for SO 2 , the existing emission limit of 32.2 lb/hr is BART for NO X , 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 cont rol equipment installation is necessary, we are proposing that these emissions limitations be comp lied 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 NO X for the natural gas firing scenario and for SO 2 , NO X , and PM for the fuel oil firing scenario (77 FR 14604). Entergy hired a consultant to conduct a BART five-factor anal ysis for Lake Catherine Unit 4 (Entergy’s BART analysis). 71

70 See ADEQ Operating Air Permit No. 0263-AO P-R7, Section IV, Specific Condition No. 32.

71 See “Revised BART Five Factor Analysis Lake Cather ine Steam Electric Station Ma lvern, 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 nomina l 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 analys is states that Lake Catherine Unit 4 has not burned fuel oil since prior to the 2001-2003 baseline peri od, currently does not burn fuel oil, and that Entergy does not project to burn fuel oil at the unit in the foreseeab le future. Therefore, Entergy’s analysis 72 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 approva l of BART for the fuel oil firing scenario. We concur with this commitment. 73 Before fuel oil firing is a llowed to take place at Lake Catherine Unit 4, revised BART determinations mu st be promulgated for all pollutants for the fuel oil firing scenario through a FIP and/or through our action upon a nd approval of revised BART determinations submitted by the State as a SIP revision. We approved the State’s BART determina tions for Lake Catherine Unit 4 for SO 2 and PM for the natural gas firing scenario in our March 12, 2012 final action (77 FR 14604). Therefore, the only BART determination that rema ins to be addressed fo r the natural gas firing scenario is NO X BART. Our analysis presented below focuses on NO X BART for the natural gas firing scenario.

a. Baseline Emission Rates and Existing Visibi lity Impairment Attributable to Lake Catherine Unit 4

Entergy estimated SO 2 , NO X , and PM 10 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 ba seline 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 Cather ine Steam Electric Station Ma lvern, 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 rule making 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, incl uding the BART provisions in 40 CFR 51.308(e). Alternatively, if the State submits a SIP revi sion 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 SO 2 , NO X , and PM 10 Emission Rates

Source SO 2 (lb/hr) NO X (lb/hr) Total PM 10 (lb/hr) SO 4 (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 SO 2 and NO X baseline emission rates are the hi ghest actual 24-hour emission rates based on 2001-2003 CEMS data from natural gas burning. The PM 10 emission rate reflects the breakdown of the filterable and condensable PM 10 determined from AP-42 Table 1.4-2 Combustion of Natural Gas . Entergy then modeled the ba seline emission rates using the CALPUFF dispersion model to determine the baseline visibility impairment attributable to Lake Catherine Unit 4 at the Caney Creek Wilder ness Area, Upper Buffalo Wilderness Area, Hercules-Glades Wilderness Area, and Mingo Nationa l 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 Attribut able to Entergy Lake Catherine Unit 4

Year Maximum ( ∆ dv) 98 th Percentile ( ∆ dv) No. of Days with ∆ dv ≥ 0.5 98 th Percentile

%SO 4 98 th Percentile

%NO 3 98 th Percentile

%PM 10 98 th Percentile

%NO 2 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 0.1094 b. NO X BART Evaluation (N atural Gas Firing)

Nitrogen oxides, or NO X , are produced during fuel combustion when nitrogen contained in both the fuel and the combustion air is expos ed to high temperatures. Entergy’s evaluation noted that the formation of NO X compounds in utility boilers is sensitive to the method of firing. In tangentially-fired boilers, su ch as Lake Catherine Unit 4, a single rotating flame is created in the center of the furnace, rather than the discre te flames produced by burners in the wall-fired boilers. Tangentially fired boilers ty pically have lower uncontrolled NO X emissions than wallfired boilers. Baseline NO X emission rates can vary significan tly from plant to plant due to method of firing as well as severa l other factors. The baseline NO X emission rates for Lake Catherine Unit 4 were discussed und er section II.C.4.a. of this TSD. The five factors considered in the NO X BART analysis are discussed below.

Step 1- Identify All Availabl e Retrofit Control Technologies

The NO X control technologies c onsidered in Entergy’s NO X BART analysis include both combustion and post-combustion controls. The co mbustion controls evaluated by consisted of Burners out of Service (BOOS), FGR, SOFA, a nd LNB. The post-combustion controls evaluated consisted of SCR and SNCR.

Step 2- Eliminate Technically Infeasible Options

Entergy’s evaluation stated that SNCR comb ined with LNB/SOFA was being evaluated as a control option for Lake Cath erine Unit 4, but SNCR is not adapta ble to all gas-fired boilers. All other NO X control options evaluated were identified as technically feasible.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies :
Entergy relied on literature control range s and efficiencies and vendor estimates in arriving at the expected controlled emission ra tes for Lake Catherine Unit 4. The baseline NO X 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 fu el-rich conditions, while not introducing fuel to other burners. The removal of fuel from cer tain zones reduces the temperature and the production of thermal NO X . Additional air is then supplied to the non-operational burners to complete combustion. Based on a NO X control study developed by Sargent & Lundy on behalf of Entergy (Sargent & Lundy NO X Control Study), the estimated controlled NO X level for Unit 495 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 le vels 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 NO X formation. Entergy estimated the controlled NO X 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 NO X emissions for gas fired boilers of 0.2 – 0.4 lb/MMBtu. LNB technology uses advanced burner design to reduce NO X formation through the restriction of oxygen, wh ich lowers flame temperature and/or reduces the residence time. When operated without additional cont rols, Entergy estimated the controlled NO X emission rate for gas fired boilers operating with LN B is approximately 0.25 lb/MMBtu, and when combined with SOFA, the estimated controlled NO X emission rate is 0.19 lb/MMBtu. When SNCR is combined with LNB/SOFA, Entergy estimated that the controlled NO X emission rate is 0.14 lb/MMBtu, and when SCR is combined with LNB/OFA it is estimated that the controlled NO X 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting pollution control technology in use at the source, and the remaining useful life of the source. Entergy’s evaluation noted that the Sargent & Lundy NO X Control Study estimated that FGR would result in the same controlled emissi on level as LNB/SOFA, but at a higher cost. 75 Therefore, Entergy’s evaluation did not furthe r consider FGR. Entergy estimated the capital costs, operating costs, and cost effectiven ess 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 scenario s based on cost estimates provide d by Sargent & Lundy. The cost analysis assumed a 30-year amortizati on period. The capital cost of each NO X control option was

74 See “NO X 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 Cather ine Steam Electric Station Ma lvern, 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 a nd then added to the annual opera ting costs to obtain the total annualized costs. 77 The annual emissions reductions associated with each NO X control option were determined by subtracting the estimated controlle d annual emission rate from the baseline annual emission rate. The baseline annual emission rate wa s calculated using the baseline emission level of 0.48 lb/MMBtu and an annual heat i nput reflecting a 10% capacity factor. 78 The annual tons reduced associated with each NO X control option were determined by subtracting the estimated controlled annual emission rate from the base line 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 factor s are expected to be comparable to those experienced by the uni t in 2003-2011. We agree that assuming a 10% capacity factor is consistent w ith the BART Guidelines, which pr ovide that the baseline emission rate should represent a realis tic depiction of anticipated annual emissions for the source. 80 The controlled annual emission rates were ba sed on the lb/MMBtu le vels believed to be achievable from the control technologies multiplied by the annual heat input. Entergy calculated the average cost-effectiveness of NO X controls by dividing the tota l annual cost of each control option by the estimated annual NO X emissions reductions. The incr emental cost-effectiveness of each control option was also calculated. We disagree with two aspect s 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 F unds Used During Construction (AFUDC). AFUDC is the cost of capital that is incurred to finance a pr oject during the construc tion period, and is not a valid cost under the methodology in the EPA C ontrol 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 implem entation. To provide an “apples-toapples” comparison with the other NO X control options, these one-time additio nal costs were treated as if they were a capital expenditure in calcu lating 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 Cather ine Steam Electric Station Ma lvern, Arkansas (AFIN 30-

00011),” dated May 2014, prepared by Trinity Consultants Inc. in conjunction with Entergy Services Inc. Entergy’s NO X control cost estimates are foun d in Appendices A and D of the BART analysis. A copy of the BART analysis, including the appendices, is foun d in the docket for our proposed rulemaking.97 suspense and AFUDC from the capital cost esti mates results in lower total annual costs and improved average cost-effectiveness ( i.e. , less dollars per NO X ton removed) for the aforementioned NO X control options compared to what is estimated in Entergy’s evaluation. In the table below, we have revised the cap ital costs and cost-effectiveness of NO X 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 NO X controlled emission rate of 0.22 lb/MMBtu is estimated to be $138/ton of NO X removed, while the average cost-effectiveness of LNB/SOFA is estimated to be $1,450/ton of NO X removed. The average cost-effectiveness of a combination of LNB/SOFA + SNCR is estimated to be $3,523/ton of NO X removed, while the average cost-effectiveness of the combination of LNB/SOFA + SCR is estimated to be $5,614/ton of NO X removed.

Table 60. Summary of NO X Control Costs for Lake Catherine Unit 4 (Natural Gas Firing)

Baseline Emission

Rate (NO X tpy) Controlled Emission

Level (lb/MMBtu) Controlled Emission

Rate (NO X tpy) Annual Emissions Reduction (NO X 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 SO FA. As for SCR and SNCR, we are not aware of any unusual circumstances at the facility th at could create ener gy or non-air quality environmental impacts associated with the operati on of these controls gr eater 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 asso ciated with th e operation of NO X controls at Entergy Lake Catherine Unit 4 that would affect our proposed BART determination. The presence of existing pollution control t echnology at the source is reflected in the BART analysis in two ways: first, in the cons ideration of available c ontrol technologies, and second, in the development of baseline emission rate s for use in cost calcul ations and visibility modeling. Lake Catherine Unit 4 is not currently equipped with any NO X pollution control

82 See the spreadsheet titled “EPA NO X 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 remaini ng useful life of the unit, we are not aware of any enforceable shutdown date for Lake Cather ine 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 NO X controls as the remaining life of Unit 4.

Step 5- Evaluate Visibility Impacts

Entergy assessed the visibility improvement associated with NO X controls by modeling the NO X emission rates associated with each control option using CALPUFF, and then comparing the visibility impairment associated w ith 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 a ssociated 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 us ed 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 NO X controls, based on the 98 th percentile modeled visibility impact for each Class I area.

Table 61. Summary of Emis sion Rates Modeled for NO X Controls for Entergy Lake Catherine Unit 4

Control SO 2 (lb/hr) SO 4 (lb/hr) NO X (lb/hr) PM C (lb/hr) PM F (lb/hr) SOA (lb/hr) EC (lb/hr) PM 10, 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 44.399 Table 62. Entergy Lake Catherine Unit 4: Summary of 98 th Percentile Visibility Impacts and Improvement due to NO X 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 th e 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 98 th percentile modeled visibility impacts), while LNB/ SOFA is projected to result in visibility improvement of up to 0.688 dv. The installation a nd operation of the comb ination 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 a nd operation of LNB/SOFA is projected to result in 0.092 dv of incremental visibility be nefit over BOOS at Caney Creek, and much lower incremental visibility benef it over BOOS at the other Cla ss I areas. The combination of LNB/SOFA + SNCR is projected to result in 0.154 dv of increm ental visibility benefit over LNB/SOFA at Caney Creek, and 0.0 57 dv or less incremental visi bility benefit at the other affected Class I areas. The combination of LN B/SOFA + SCR is projec ted to result in 0.366 dv of incremental visibility be nefit 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 NO X BART determination (Natur al Gas Firing Scenario):

Taking into consideration the five factor s, we are proposing to determine that NO X 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 aver age based on the installation and operation of100 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 (98 th percentile basis). The cumulative visibility improvement across the four affected Class I ar eas is projected to be 1.215 dv. The operation of BOOS is estimated to have an average cost-effectiveness of $138/ton of NO X removed, which we consider to be very co st-effective. By comparison, th e installation and operation of LNB/SOFA is estimated to have an av erage cost-effectiveness of $1,450/ton of NO X removed, which is still very cost-effective. However, the incremental cost-eff ectiveness of LNB/SOFA over BOOS is $14,246/ton of NO X ton removed, while the increm ental 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 eachClass I area. However, the combination of LNB/SOFA + SNCR has an average costeffectiveness of $3,523/ton of NO X removed and an incremental cost-effectiveness compared to LNB/SOFA of $16,029/ton of NO X 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 project ed at the affected Class I areas. The operation of a combination of LNB/ SOFA + SCR is projected to result in considerable visibility improvement over th e 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 aver age cost-effectiveness of $5,614 per ton of NO X removed and an incremental cost -effectiveness (compared to the combination of LNB/SOFA + SNCR) of $11,767 per ton of NO X 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 NO X BART for Lake Catherine Unit 4 for th e natural gas firing scenario is an emission limit of 0.22 lb/MMBtu on a 30 boile r-operating-day rolling average based on the installation and operatio n of BOOS. We are proposing to require compliance with this requirement no later than 3 years from the effectiv e 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 specifica lly on whether this proposed NO X emission limit is appropriate or whether an emission limit based on more stringent NO X controls would be appropriate.

6. Domtar Ashdown Paper Mill

The Domtar Ashdown Paper Mill Power Boile rs No. 1 and 2 are subject to BART. We disapproved the State’s BART determinations for SO 2 and NO X for Power Boiler No. 1 and the

83 40 CFR section 51.308(e)(1)(iv).101 BART determination for SO 2 , NO X , 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 a nd 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), muni cipal yard waste, pelletized paper fuel (PPF), fuel oil, reprocessed fuel oil, and natural gas. It is equipped with a trav eling grate, a combustion air system, and a wet ESP. The No. 2 Power Boiler has a heat input rating of 820 MMBtu/hr a nd 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 o il. It is equipped w ith a traveling grate, combustion air system including OFA, multiclone s for particulate removal, and two venturi scrubbers in parallel for removal of remaining particulates and SO 2

. 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 hereafte r 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 av ailable information we have related to certain NO X controls for Power Boilers No. 1 and 2.

a. Baseline Emission Rates and Existing Visi bility 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 SO 2 baseline emission rate for Power Boiler No. 1 used in Domtar’s 2014 BART analysis is the highest actual 24-hour em ission 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 Max imum Achievable Control Technology (MACT)

84 See “Supplemental BART Determination Informati on 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 Determinati on 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 pe riod 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 SO 2 emissions from Power Boiler No. 1. Therefore, 20 09-2011 is more representative of the boiler’s emissions than 2001-2003.102 standards under CAA section 112, resu lting in a reduction in PM and SO 2 emissions from Power Boiler No. 1. Therefore, we believe that the 2009-2011 period is more representative of the boiler’s current emissions th an 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 realis tic depiction of anticipated annual emissions for the source. 87 The NO X and PM baseline emission rates used for Power Boiler No. 1 are the highest actual 24-hour em ission rates estimated using the maximum heat input from 2009-2011 and emission factors developed from the analysis of stack testing the fa cility 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 NO X Emissions (lbhr) SO 2 Emissions (lb/hr) PM 10 /PM f 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 rate s 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 ar e the Caney Creek Wilderness Area, Upper Buffalo Wilderness Area, Hercules-Glades Wilderness Area, and Mi ngo National Wildlife Refuge. The baseline ( i.e. , existing) visibility impairment attributable to th e source at each Class I area is summarized in the table below.

Table 64. Baseline Visibility Impairment At tributable 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. SO 2 BART Evaluation and Proposed BART Determination for Power Boiler No. 1

The table above shows that the baseline visi bility impairment attributable to Power Boiler No. 1 is relatively low based on the 98 th percentile visibility impacts, ranging from 0.014 to 0.335 dv at each Class I area. An examinati on of the species contribution to the 98 th percentile visibility impacts shows that SO 2 emissions contribute a very small portion of the visibility impairment attributable to Power Boile r No. 1 (see the table below). The SO 4 species contributes only 2.23 – 4.03% of the visibility impairment attri butable to Power Boiler No. 1 at the modeled Class I areas. We also note that Power Boiler N o. 1 combusts primarily bark, which results in very low SO 2 emissions due to the low sulfur content of bark.

Table 65. 98 th Percentile Baseline Visibility Impa irment 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 98 th Percentile Visibility Impacts

98 th Percentile

% SO 4 98th Percentile

% NO 3 98th Percentile

% PM 10 98th Percentile

% NO 2

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 dete rminations where appropriate. 89 Considering the very low baseline visibility impairment that is due to SO 2 emissions from Power Boiler No. 1 and the fact

88 The visibility impact shown represents the highest 98 th percentile value among the three modeled years.

89 70 FR 39116.104 that the boiler combusts primarily bark, which ha s a low sulfur content, we believe that any visibility improvement that could be achieved as a result of emi ssions reductions associated with the installation and operation of SO 2 controls would be negligible , and that the cost of those controls could not be justified. Ther efore, we are proposing that the SO 2 baseline emission rate of 21.0 lb/hr satisfies SO 2 BART for Power Boiler No. 1. We are proposing this SO 2 emission rate on a 30 boiler-operating-day av eraging basis, where in this particular case boiler-operatingday is defined as a 24-hour period between 12 midnight and the follo wing 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 SO 2 BART emission limit we are proposing to require the facility to use a site-specific curve equation, 90 provided to us by the fac ility, to calculate the SO 2 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 SO 2 emissions from fuel oil combustion, the facility must assume that the SO 2 inlet is equal to the SO 2 being emitted at the stack. We are inviting public comment on whether this method of demons trating compliance with the proposed BART emission limit is appropriate. Since this proposed BART determina tion does not require the installation of control equipment, we are proposing that this SO 2 emission limit be complied with by the effective date of the final action.

c. NO X BART Evaluation for Power Boiler No. 1

Step 1- Identify All Availabl e Retrofit Control Technologies

For NO X BART, Domtar’s 2014 BART analysis evaluated SNCR and Methane de-NO X (MdN). In the 2006/2007 Domtar BART analys is, which was submitted in the 2008 Arkansas RH SIP, other NO X controls were also evaluated but found by Arkansas to be either already in use or not technically feasible for use at Powe r Boiler No. 1. Fuel bl ending, boiler operational modifications, and boiler tuning/op timization are already in use at the source, while FGR, LNB, Ultra Low NO X Burners (ULNB), OFA, and SCR were determined to be technically infeasible for use at Power Boiler No. 1. Domtar did not further evaluate these NO X 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 SO 2 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 togeth er 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 s ubmitted in the 2008 Arkansas RH SIP discussed that MdN has not been fully demonstrat ed for this source type and incorporates FGR, which is technically infeasible for use at Powe r 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 boile rs at paper mills or any comparable source types. We are also not aware of any power boilers at paper mills that operate MdN for NO X control, and agree that this c ontrol can be considered technica lly 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 boile rs and boilers with high load swings such as Power Boiler No. 1, but in response to our comme nts, SNCR was evaluated for Power Boiler No. 1 in Domtar’s 2014 BART analysis.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies :
Domtar’s 2014 BART analys is evaluated SNCR at remova l 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 appropriati ons request level quote and ther efore 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, Po wer Boiler No. 1 is not a base loaded boiler. Domtar’s 2014 BART analysis states that fo r 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% NO X reduction) and it is uncertain whether higher removal efficiencies are achievable on a long-term basis. The facility believes th at 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- NO X 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting pollution control technology in use at the source, and the remaining useful life of the source. In Domtar’s 2014 BART analysis, the cap ital costs, operating costs, and costeffectiveness of SNCR were cal culated based on methods and a ssumptions 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 ope rating cost to obtain the total annualized costs. The annual emissions reductions associated with each NO X control option were determined by subtracting the estimated controlle d annual emission rate from the baseline annual emission rate. The baseline annual emissions used in the calculations ar e 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 NO X emissions reductions. The table below summarizes the cost of NO X controls for Power Boiler No. 1.

Table 66. Summary of Cost of NO X Controls for Domtar Ashdown Mill Power Boiler No. 1

NO X Control Scenarios Baseline Emission

Rate (NO X tpy) NO X Control Efficiency (%) Annual Emissions Reduction (NO X tpy) Capital Cost ($) Total Annual Cost ($/yr) Average Cost Effectiveness ($/ton) IncrementalCostEffectiveness ($/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 no t identify any energy or non-air quality environmental impacts associated with the us e of SNCR. We are not aware of any unusual

95 See “Supplemental BART Determination Informati on 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 greate r non-air quality environmental impacts than experienced elsewhere that may provide a basis fo r 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 im pacts associated with the operation of NO X controls at Power Boiler No. 1 that would affect our proposed BART determination. Consideration of the presen ce of existing pollution contro l technology at the source is reflected in the BART analysis in two ways: fi rst, in the consideration of available control technologies, and second, in the development of baseline emission rates for use in cost calculations and visibility mode ling. Power Boiler No. 1 is current ly equipped with a combustion air system to optimize boiler combustion effi ciency, 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 exis ting combustion air system. We are not aware of any enforceable shut down 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 lif e 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 rema ining life of the boiler.

Step 5- Evaluate Visibility Impacts

In the 2014 BART analysis, Domtar assessed th e visibility improvement associated with SNCR by modeling the NO X emission rates associated w ith each control option using CALPUFF, and then comparing th e visibility impairment associ ated with the baseline emission rate to the visibility impairment associated wi th the controlled emission rates as measured by the 98 th percentile modeled visibility impact. The ta bles below show the modeled emission rates and a comparison of the baseline (i.e., existing) vi sibility impacts and the visibility impacts associated with SNCR fo r each Class I area.

Table 67. Summary of Emission Rates Modeled for NO X Controls for Domtar Ashdown Mill Power Boiler No.1

Scenario NO X Emissions

(lb/hr) SO 2 Emissions

(lb/hr) PM 10 /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 30.4108 MdN 103.7 21.0 30.4

Table 68. Domtar Ashdown Mill Power Boiler No. 1: Summary of the 98 th Percentile Visibility Impacts and Im provement 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 th e 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 98 th percentile modeled vi sibility impacts).

Our Proposed NO X BART determination for Power Boiler No. 1:

Taking into consideration the five factor s, we are proposing to determine that NO X BART for the Domtar Ashdown Mill Power Boiler N o. 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 th e following midnight during which a ny fuel is fed into and/or combusted at any time in the Power Boiler. This emission limit is based on the boiler’s NO X baseline emission rate and therefore repr esents current oper ating conditions. MdN was determined to be not technically feasible for use at Power Boiler No. 1109 because it has not been fully demonstrated for th is 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 Cla ss 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 NO X 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 es timated to cost $12,700/ton of NO X removed. We do not believe this high cost justifies the mode st 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 co sts are also too high a nd not justified by the projected visibility benefits. Installation and operation of SNCR at a 45% removal efficien cy 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 NO X removed. The operation of SNCR at a 32.5% removal efficiency is projected to result in visibility improveme nt of up to 0.098 dv at any single Class I area and is estimated to cost $7,996/ton of NO X removed. Therefore, we are proposing to determine that NO X 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-da y rolling average satisfies NO X 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 wi th a CEMS. To demonstrate compliance with this NO X BART emission limit we are proposing to re quire annual stack testing. We are inviting public comment on the appropriateness of this method for demonstrating compliance with the NO X BART emission limit for Po wer Boiler No. 1. Since this proposed BART determination does not require the installati on of control equipment, we are proposing that this NO X emission limit be complied with by the effective date of the final action.

d. SO 2 BART Evaluation for Power Boiler No. 2

Step 1- Identify All Availabl e Retrofit Control Technologies

Power Boiler No. 2 is currently equipped with two venturi wet scrubbe rs in parallel for removal of particulates and SO 2 . 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 ev aluate upgrades to the existing ve nturi 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 Informati on 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 SO 2 control efficiency of approximately 90% and notes that this is within the normal range for the highest efficiency achieved by SO 2 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 liqui d distribution rings, (3) the installation of pe rforated 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 SO 2 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 th e facility determines how much reagent to use, and the SO 2 control efficiency. 98 Domtar confirmed that no upgrad es to the scrubbers have ever been performed and stated that 100% of the fl ue gas is treated by the scrubber systems. The scrubbing solution used in the venturi scrubbers is made up of three co mponents: 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 pro cesses at the plant. The 15% caustic solution is added to adjust the pH of the scrubbing soluti on and maintain it within the required range to ensure that sufficient SO 2 is removed from the flue gas in the scrubber to meet the permitted SO 2 emission limit of 1.20 lb/MMBtu on a three ho ur average. Each venturi scrubber has a recirculation tank that is equipped with level control systems to ensu re 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 controller s are overridden in the event that SO 2 levels measured at the stack by the CEMS are above the opera tor set point of 0.86 lb/MMBtu on a two hour average (the SO 2 permit limit is 1.20 lb/MMBtu on a three hour average). This allows additional caustic feed to the scrubber soluti on to increase the pH and reduce the SO 2 measured at the stack. According to Domtar, the scrubber systems opera te in this manner to maintain continuous compliance with permitted emission limits. Domtar provided monthly average da ta for 2011, 2012, and 2013 on monitored SO 2 emissions from Power Boiler No. 2, mass of the fu el 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, As hdown 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 SO 2 control efficiency of th e existing scrubbers for the 2011-2013 period ranged from 57% to 90%. The data indicate that the monthly av erage control efficiency of the scrubbers is usually below 90%. The information provided also indicates that the fa cility could add more scrubbing solution to achieve greater SO 2 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 feasib le to increase the current SO 2 control efficiency of the existing scrubbers from current levels to 90% on a mont hly average basis throug h 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 SO 2 control would involve efforts to increase pressure drop. Additi onally, 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 scrubbe rs to operate downstream of the existing scrubbers was more feasible than any upgrade opti on. 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 provi ded to us, we determined it woul d be technically feasible to increase the current control efficiency of th e existing scrubbers thr ough the use of additional scrubbing reagent. We evaluate th is control option in this TSD.

Step 3- Evaluate Control Effectiven ess of Remaining Control Technologies :
Based on the information provided to Domt ar by the vendor, new add-on spray scrubbers were estimated to achieve 90% control efficiency on top of the SO 2 removal currently achieved by the existing venturi scrubbers. In Domtar’s an alysis, it was estimated that a controlled SO 2 emission rate of 78.8 lb/hr would be achieve d by the operation of a dd-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 SO 2 emissions from Power Boiler No. 2, mass of the fuel burne d 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 le tter 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 pr ovided by Domtar, the monthly average SO 2 control efficiency of th e existing scrubbers for the 2011-2013 period ranged from 57% to 90%. The data indicate that the monthly av erage control efficiency of the scrubbers is usually below 90%. Based on the monthly average SO 2 control efficiency data for the 2011-2013 period, we estimated the annual average SO 2 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 SO 2 emission rate that corresponds to the operation of the scru bbers at the current cont rol efficiency of 69%. Based on emissions data we obtained from Domtar, we determined that the No. 2 Power Boiler’s annual average SO 2 emission rate for the years 2009-2011 was 280.9 lb/hr. 102 This annual average SO 2 emission rate corresponds to the operat ion of the scrubbers at a 69% removal efficiency. We also estimated that 100% unc ontrolled emissions would correspond to an emission rate of approximately 915 lb/hr. Applicati on of 90% control efficien cy 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting pollution control technology in use at the source, and the remaining useful life of the source. Domtar’s estimates of the capital and ope rating 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 th en 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 le tter 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 sp readsheet 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 spre adsheet 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 th e total annualized cost by the annual SO 2 emissions reductions. The averag e cost-effectiveness of the add-on spray scrubbers for Power Boiler No. 2 was estimated to be $5,258/ton of SO 2 removed (see table below). Domtar’s analysis notes that because of constricted sp ace, there is no existing property or adequate structure to support the add-on sp ray 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 estim ates 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 (SO 2 tpy) Controlled Emission

Level (lb/hr) Controlled Emission

Rate (tpy) Annual Emissions Reductions

(SO 2 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 th e facility, increasing the monthly average SO 2 control efficiency of the existing venturi sc rubbers from current le vels to 90% control efficiency would require replacing two scr ubber pumps, which involves capital costs of $200,000. 105 It would also require a dditional scrubbing reagent, treatment of additional wastewater, treatment of additi onal raw water, and additional energy usage, which involves annual operation and maintenance costs of a pproximately $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 th e 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 spre adsheet 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 SO 2 emissions reductions. To estimate the SO 2 annual emissions reductions expected from increasing the control efficien cy of the scrubbers through the use of additional scrubb ing solution, we calculate d the annual average SO 2 control efficiency of the existing scrubbers. As discussed above, ba sed on data provided by Domtar for the 2011-2013 period, we estimated the annual average SO 2 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 SO 2 tpy, and assuming that the scrubbers curren tly operate at an a nnual average control efficiency of 69%, we have estimated that the uncontrolled annual emissions would be 6,769 SO 2 tpy and that operating the scrubbers at 90% control efficiency woul d result in controlled annual emissions of 677 SO 2 tpy. 108 By subtracting the controlled annual emission rate of 677 SO 2 tpy from the baseline annual emission rate of 2,078 SO 2 tpy, we estimate that increasing the control efficiency of the existing venturi scrubbers fr om the current level of 69% to 90% control efficiency would result in annual emissions reductions of 1,401 SO 2 tpy. 109 We estimate the average cost-effectiveness of using additional scrubbing reagent to increase the SO 2 control efficiency of the existing venturi scrubbers from the current control efficiency (estimated to be 69%) to 90% is $1,411/ton of SO 2 removed. The cost information is presented in the table below.

Table 70. Summary of Cost of Using Addition al Scrubbing Reagent to Increase Control Efficiency of Existing Venturi Scrubbers at Domtar Ashdown Mill Power Boiler No. 2

Control Option Baseline Emission

Rate (SO 2 tpy) Controlled Emission

Rate (tpy) Annual Emissions Reductions

(SO 2 tpy) Capital Costs 110 ($) Annual Operation & Maintenance Cost 111 ($/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 sp readsheet 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 Effectiv eness 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 additiona l raw water, and additional energy usage.115 Domtar’s 2014 BART analysis did no t 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 spra y scrubbers greater than experienced elsewhere that may therefore provide a basis for the elimin ation of this control option as BART (40 CFR Part 51, Appendix Y, section IV.D.4.i.2.). We are al so not aware of any unusual circumstances at the facility that create energy or non-air quality e nvironmental impacts associated with the use of additional scrubbing reagent to increase the contro l efficiency of the existing venturi scrubbers greater than experienced elsewhere that may theref ore provide a basis for the elimination of this control option as BART. Therefor e, we do not believe there ar e any energy or non-air quality environmental impacts associated with these cont rol options at Power Boiler No. 2 that would affect our proposed BART determination. Consideration of the presen ce of existing pollution contro l technology at the source is reflected in the BART analysis in two ways: fi rst, 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 Bo iler No. 2 is equipped with multiclones for particulate removal and two venturi scr ubbers in parallel for control of SO 2 emissions. It is also equipped with a combustion air system includi ng overfire air to optimize boiler combustion efficiency, which also helps control emissions. The baseline emission ra te used in the cost calculations and visibility mode ling reflects the use of these ex isting controls. As discussed above, Domtar’s analysis also ev aluated upgrades to the existing ve nturi scrubbers to potentially achieve greater SO 2 control efficiency. Another option we have identified a nd are evaluating in this TSD is to use additional scrubbing reagent to achieve greater SO 2 control efficiency of the existing venturi scrubbers, We are not aware of any enforceable shut down date for the Domtar Ashdown Mill Power Boiler No. 2, nor did Domtar’s 2014 BART analys is indicate any enforceable future planned shutdown. This means that the antici pated 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 evalua tion of the add-on spra y 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 th e visibility improvement associated with the add-on spray scrubbers by modeling the controlled SO 2 emission rate using CALPUFF, and then comparing the visibility impairment associat ed with the controlled em ission rate to that of the baseline emission rate as measured by the 98 th percentile modeled vi sibility impact. The tables below show the emission rates modeled and a comparison of the baseline ( i.e. , existing) visibility impacts and the visi bility impacts associated with the add-on spray scrubbers. The116 installation and operation of add-on spray scrubbers is proj ected to result in visibility improvement of 0.146 dv at Caney Creek. The visibil ity 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 SO 2 Controls for Domtar Power Boiler No.2

Scenario NO X Emissions (lb/hr) SO 2 Emissions

(lb/hr) PM 10 /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 98 th Percentile Visibility Impacts and Improvement due to Add-on Spray Scrubbers

Class I area Baseline Visibility Impact 112 (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 proj ected from the installation and operation of new add-on spray scrubbers, we have extrapolated the vi sibility improvement proj ected as a result of using additional scrubbing r eagent to increase the SO 2 control efficiency of the existing venturi

112 The baseline visibility impacts reflect the op eration of the existing venturi scrubbers.117 scrubbers from the current control efficiency (est imated 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 opera tion of the existing venturi scrubbers at a 69% control efficiency. We estimate that the visi bility improvement of using additional scrubbing reagent to increase the SO 2 control efficiency of the existi ng 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 98 th 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 SO 2 BART determination Power Boiler No. 2:

Taking into consideration the five f actors, we propose to determine that SO 2 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 sc rubbers 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 SO 2 emission limit. We believe that this emission limit can be achieved by using additional scrubbing reagent in the operation of the exis ting venturi scrubbers. We estimate that operating the existing scrubbers to achieve this level of cont rol 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 f acility, we have estimated that the use of additional scrubbing reagent to incr ease the control efficiency of th e existing venturi scrubbers is estimated to cost $1,411/ton of SO 2 removed. Based on Domtar’s BART analysis, new add-on spray scrubbers that would be operated downs tream 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 visibi lity improvement at the four Class I areas is projected to be 0.276 dv. The cost of add-on spra y scrubbers is estimated to be $5,258/ton of SO 2 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 incrementa l visibility improvement of new add-on spray scrubbers compared to using addi tional scrubbing reagen t to increase the c ontrol 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 associat ed with new add-on spray scrubbers. Therefore, we are proposing to determine that SO 2 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 fa cility to demonstrate compliance with this emission limit us ing the existing CEMS. Since the SO 2 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.

NO X BART Evaluation for Power Boiler No. 2

Step 1- Identify All Availabl e Retrofit Control Technologies

For NO X BART, Domtar’s 2014 BART analysis evaluated LNB, SNCR, and Methane de-NO X (MdN). In the 2006/2007 Domtar BART analysis, which was submitted in the 2008 Arkansas RH SIP, other NO X controls were also evaluated bu t found by the State to be either already in use or not t echnically feasible for use at Powe r Boiler No. 2. Fuel blending, boiler operational modifications, and boile r 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 furthe r evaluate these NO X 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 togeth er 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 s ubmitted in the 2008 Arkansas RH SIP discussed that MdN has not been fully demonstrat ed for this type of boiler and incorporates FGR, which is considered technically infeasible for use at Power Boile r No. 2. Domtar also stated it recently completed additional rese arch and found that si nce 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 NO X control, and agree that this control can be considered te chnically 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 w ith 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 Effectiven ess 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 Domt ar’s 2014 BART analysis, SNCR was evaluated at a control efficiency of 27.5% and 35% for Po wer 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 leve l 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 pa tterns and temperature distribution across the flue gas pathway, SNCR is typically capable of achieving 50% NO X reduction. However, Power Boiler No. 2 is not a base loaded boiler and does not have steady flue ga s flow patterns or steady temperature distribution acro ss 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- NO X 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 temperat ures were analyzed for a 12-day period that according to Domtar is re presentative 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 th e optimal location for installation of the SNCR injection nozzles. The consultant estimated that 1700 – 1800°F repr esents the temperature range at which SNCR can be expected to reach 40% cont rol efficiency at the current boiler operating conditions. It was found that ther e 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 betw een 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% co ntrol 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 temp erature swings, which are due to load following and steam demand variability, create a scen ario where urea injection will either be too high or too low. When not enough urea is injected, NO X removal will be less than projected and when too much urea is injected, excess ammonia s lip will occur. Domtar stated that the observed significant temperature swings dem onstrate that it will be difficult to maintain stable, optimal furnace temperatures at which urea can be injected to effectively reduce NO X with minimal ammonia slip. We agree that becau se of the wide variability in steam demand and wide range in furnace temperature observed at Power Boiler No. 2, the NO X 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 compli ance, energy and non-air quality environmental impacts of compliance, ex isting 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 equi pment’s life expectancy. However, since we believe a 30-year equipment life is a more appr opriate 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 Determinati on 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 pres ented in the 2006/2007 Domtar BART analysis for LNB by using the boiler’s actual a nnual uncontrolled NO X emissions rather than the maximum 24-hour emission rate as the baseline annual emissions. Th e table below summarizes the estimated cost of LNB for Power Boiler No. 2, based on our adjust ments to the cost es timates in the 2006/2007 Domtar BART analysis as discussed above. In Domtar’s 2014 BART analysis, the capit al costs, operating costs, and costeffectiveness of SNCR were cal culated based on methods and a ssumptions 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% a nd 35% control efficien cies. Domtar annualized the capital cost over a 30-year period and then added to the annual operating cost to obta in the total annualized costs. The annual emissions reductions associated with each NO X control option were determined by subtracting the estimated controlle d annual emission rate from the baseline annual emission rate. The baseline annual emissions used in the calculations ar e 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 NO X emissions reductions. The table below summarizes Domtar’s estimate of the cost of SNCR fo r Power Boiler No. 2.

Table 74. Summary of Cost of NO X Controls for Power Boiler No. 2

NO X Control Scenario Baseline Emission

Rate (NO X tpy) NO X Removal Efficiency of

Controls (%) Annual Emissions Reduction (NO X tpy) Capital Cost ($) Total Annual Cost ($/yr) Average Cost Effectiveness ($/ton) IncrementalCostEffectiveness ($/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 revi sions.” 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 us e of LNB or SNCR. We are not aware of any unusual circumstances at the facility that coul d create energy or non-air quality environmental impacts associated with the operation of NO X controls greater than experienced elsewhere and that may therefore provide a basis for the elimin ation of these control options as BART (40 CFR Part 51, Appendix Y, section IV.D.4.i.2.). Therefor e, we do not believe there are any energy or non-air quality environmental impacts associated with NO X controls at Power Boiler No. 2 that would affect our proposed BART determination. Consideration of the presen ce of existing pollution contro l technology at the source is reflected in the BART analysis in two ways: fi rst, 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 Bo iler No. 2 is equipped with multiclones for particulate removal and two venturi scr ubbers in parallel for control of SO 2 emissions. It is also equipped with a combustion air system includi ng overfire air to optimize boiler combustion efficiency, which also helps control emissions. The NO X 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 shut down 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 antici pated useful life of the boiler is expected to be at least as long as the capital cost recovery period of cont rols. 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 th e visibility improvement associated with LNB and SNCR by modeling the NO X emission rates associated w ith each control option using CALPUFF, and then comparing th e visibility impairment associ ated with the baseline emission rate to the visibility impairment associated wi th the controlled emission rates as measured by the 98 th percentile modeled visibility impact. The ta bles 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 SO 2 Controls for Domtar Power Boiler No. 2

Scenario NO X Emissions

(lb/hr) SO 2 Emissions

(lb/hr) PM 10 /PMF Emissions

(lb/hr)

Baseline 526.8 788.2 81.6 Add-on Spray Scrubber 526.8 78.8 81.6123 Table 76. Domtar Ashdown Mill Power Boiler No. 2: Summary of the 98 th Percentile Visibility Impacts and Improvement due to NO X 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 visi bility 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 visibili ty 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 visi bility 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 NO X BART determination for Power Boiler No. 2:

Taking into consideration the five factor s, we are proposing to determine that NO X 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 aver aging basis, based on the instal lation and operation of LNB. In this particular case, we define boiler-opera ting-day as a 24-hour pe riod between 12 midnight and the following midnight during whic h any fuel is fed into and/or combusted at any time in the Power Boiler. MdN was determined to be not tec hnically feasible for us e 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 th e Class I areas when operated at 27.5% and 35%124 control efficiency. However, based on the inform ation provided by the faci lity, we believe that because of the wide variability in steam demand and wide range in furnace temperature observed in Power Boiler No. 2, the NO X control efficiency of SNCR at the boiler would not reach optimal control levels on a long-term basis. Th ere 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 projec ted to result in visibi lity 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 estim ated to cost $1,951/ton of NO X removed, which we consider to be cost-effective. Therefore, we ar e proposing to determine that NO X BART for Power Boiler No. 2 is an emission limit of 345 lb/hr on a 30 boiler-operating-day rolli ng average basis, based on the installation and operation of LNB. We are proposing to requ ire compliance with this emission limit no later than 3 years from the effective da te of the final rule, and are inviting public comment on the appropriateness of this complia nce date. We are proposing that the facility demonstrate compliance with this em ission limit using the existing CEMS.

e. PM BART Evaluation for Power Boiler No. 2

PM BART for Power Boiler No. 2 is addre ssed in Domtar’s 2014 BART analysis. Power Boiler No. 2 is subject to th e Boiler MACT standards requir ed under CAA section 112, and found at 40 CFR Part 63, Subpart DDDDD – Nati onal Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Comm ercial, 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 stream lined by including a disc ussion of the MACT controls and whether any major new technologies have been deve loped subsequent to the MACT standards. 121 The BART Guidelines discuss that ther e 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 stringen t than the MACT standards will be identified without identifying control options that would cost many thousa nds of dollars per ton. Therefore, the BART Guidelines provide that unless there are new technologies su bsequent to the MACT standards which would lead to cost-effective in creases 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 no t 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 inform ation 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 th at 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 98 th 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 a nd 0.146 dv or less at each of the other Class I areas, based on the 98 th percentile visibility impacts. Th e PM species contribute only 1.06 – 4.58% of the baseline visibility impairment attr ibutable to Power Boile r No. 2 at the modeled Class I areas.

Table 77. Baseline Visibility Impairment a nd Species Contribution for Domtar Ashdown Mill- Power Boiler No. 2

Emissions Unit Class I area 98th Percentile Visibility Impacts

(dv) 123 Species Contribution to 98 th Percentile Visibility Impacts

98 th Percentile

% SO 4 98th Percentile

% NO 3 98th Percentile

% PM 10 98th Percentile

% NO 2

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 Determinati on 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 98 th percentile value among the three modeled years.126 Mingo 0.065 81.46 15.47 3.07 0.00

EPA’s Proposed PM BART determ ination 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 pot ential 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 c ould 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 proposi ng 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 fo r BART purposes from the effective date of the final action.

III. Reasonable Progress Goals

The vehicle for ensuring continuing progress to wards achieving the natural visibility goal is the submission of a series of regional haze SI Ps from the states that establish two RPGs ( i.e. , two distinct goals, one for the “b est” 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” to ward achieving natural ( i.e. , “background”) visibility conditions. The RHR and section 169A of the CAA require th e 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 envi ronmental impacts of compliance, and the remaining useful life of any potentially affect ed sources (collectivel y “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 EP A’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 Admi nistrator for Air and Radi ation, 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 th e 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 G oals – 2018 Visibility Projections

In the 2008 Arkansas RH SIP, which we pa rtially approved and pa rtially disapproved in March 12, 2012, the State adopted the CENRAP m odeled 2018 visibility conditions as the RPGs for Caney Creek and Upper Buffalo. ADEQ estab lished 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 f our RP factors in establishing its RPGs for Caney Creek and Upper Buffalo, st ating that it was an unnecessary exercise. Arkansas believed, incorrectly, that no additi onal analysis of potenti al reasonable progress measures was necessary because visibility projections for the Class I areas indicated improvements in visibility consistent with th e URP. As discussed in our disapproval action, a state must determine whether additional c ontrol measures are r easonable 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 afte r consideration of th e RP factors.

B. Reasonable Progress Analysis

A discussion of the particular pollutants that contribute to visibi lity impairment at Arkansas’ two Class I areas was provided in our October 17, 2011 propos ed action on the 2008 Arkansas RH SIP (see 76 FR 64186). In that pro posed 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 categorie s 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 tota l light extinction in 2002 on the 20% worst days at each Class I area. The source category point s ources 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 ta bles below). This represents approximately 60% of the total light extinction at each Class I area. Each of th e 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 Cane y 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 approximate ly 3% of the total light extin ction 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, a nd nitrate from Arkansas point sources contributed 0.27% of the total light extinction at Caney Cr eek and 0.14% at Upper Buffalo. 130 For both Caney Creek and Upper Buffalo, SO 2 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 la rgely due to sulfate from point sources.

Table 78. Modeled baseline light extinction fo r 20% worst days at Caney Creek Wilderness Area in 2002 (Mm -1 )

Total 1 Point Natural On-Road Non-Road Area

SO 4 87.05 75.10 0.09 1.19 1.70 5.66

NO 3 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 do cket for this pr oposed 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 co nditions. Sums include secondary organic matter.

Table 79. Modeled baseline light extinction for 20% worst days at Upper Buffalo Wilderness Area in 2002 (Mm -1 )

Total 1 Point Natural On-Road Non-Road Area

SO 4 83.18 72.17 0.08 1.15 1.67 5.24

NO 3 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 co nditions. 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 a nd figure below). Sulfate from a ll 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 extincti on. 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 Cl ass 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, whic h is approximately 53 % of the total light extinction. Nitrate from all source categories co mbined is projected to contribute 9.22 Mm -1 out of 86.16 Mm -1 of light extinction on the 20% wors t 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 projecte d 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 Uppe r Buffalo, sulfate from point sour ces 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% wo rst days in 2018, sulfate from Arkansas point sources is proj ected to contribute 3.58% of the total light extinction at Caney Creek and 3.20% at Upper Buffalo, and nitrate from Arkansas point sour ces is projected to contribute 0.29% of the total li ght extinction at Caney Creek a nd 0.25% at Upper Buffalo (see Figure 1). 131 Based on the 2018 visibility pr ojections, 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 fo r 20% worst days at Caney Creek Wilderness Area in 2018 (Mm -1 )

Total 1 Point Natural On-Road Non-Road Area

SO 4 48.95 39.83 0.07 0.12 0.44 5.31

NO 3 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 do cket for this pr oposed 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 CategoryExtinction (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 )

Total 1 Point Natural On-Road Non-Road Area

SO 4 45.38 37.09 0.06 0.12 0.42 4.95

NO 3 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 1.21132 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 CategoryExtinction (1/Mm) SO4 NO3 POA EC SOIL CM SOAA SOAB133 Table 82. Percentage of Total Extinction due to Arkansas Point Sources 132

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 dete rmine whether additional controls on Arkansas sources are reasonable in the fi rst regional haze planning period, we examined the most recent SO 2 and NO X emissions inventories for point sources in Arkansas. Based on the 2011 National Emissions Inventory (NEI), the Entergy White Bl uff Plant, the Entergy Independence Plant, and the AEP Flint Creek Power Plant are th e three largest point sources of SO 2 and NOx emissions in Arkansas (see table below). 133 The combined annual emissions from these three sources make up approximately 84% of the statewide SO 2 point-source emissions and 55% of the statewide NO X 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 SO 2 and NO X controls to meet the BART requirements. We believe that our five-factor BART analysis for these three units is adequate for this first planning pe riod to eliminate these sources from further consideration of controls under the reasonable progress requirement s for this first regional haze planning period.. Compliance with the BART requirements is an ticipated to result in a substantial reduction in SO 2 and NO X emissions from these two facilities. The Entergy Independence Plant is not subject to BART, but its emissions were 30,398 SO 2 tpy and 13,411 NO X tpy based on the 2011 NEI. The Entergy Indepe ndence Plant is the sec ond largest source of SO 2 and NO X point-source emissions in Arkansas, acc ounting for approximately 36% of the SO 2 point-source emissions and 21% of the NO X point-source emissions in the State. Additionally, as we discuss in more detail in the proceeding s ubsection, 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 sim ilar for the two facilities.

Table 83. Ten Largest SO 2 and NO X 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 do cket for this pr oposed rulemaking.

133 See NEI 2011 v1. A spreadsheet containing the emissions inventory is found in the docket for our proposed rulemaking.134 SO 2 NO X Entergy Arkansas- White Bl uff 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 M ill 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 require ments will result in emission reductions

Because in our March 12, 2012 final partial ap proval and partial disapproval of the 2008 Arkansas RH SIP we made a fi nding 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 disa pproved the RPGs it establishe d for Caney Creek and Upper Buffalo, we are required to complete the reas onable progress analysis and establish revised RPGs, unless we first approve a SIP revision th at 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 reas onable progress analysis and esta blish revised RPGs for Caney Creek and Upper Buffalo. We believe it is appr opriate that our evalua tion of the reasonable progress factors focuses on the Entergy Indepe ndence Power Plant because it is a significant source of SO 2 and NO X , as it is the second larges t point source for both NO X and SO 2 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 planni ng period. This is because we believe that in135 determining whether reasonable progress is being achieved, it w ould be unreasonable to ignore a source representing more than a third of the State’s SO 2 emissions and a significant portion of NO X point source emissions. The preamble to the Re gional Haze Rule also states that the URP does not establish a “safe harbor” for th e state in setting its progress goals. 134 If the state determines that the amount of progress identified thr ough the URP analysis is reasonable based upon the statutory factors, the state, or us in th e case of a FIP, should identify this amount of progress as its reasonable progress goal for the fi rst long-term strategy, unle ss it determines that additional progress beyond this amount is also re asonable. If the state or we determine that additional progress is reasonable based on the stat utory factors, that amount of progress should be adopted as the goal for th e first long-term strategy. In this proposed rulemaking, we are proposing controls for the larg est and third largest point sources for both NO X and SO 2 emissions in Arkansas unde r the BART requirements. As these two BART sources combined with Inde pendence make up a large majority of the SO 2 point source emissions (84%) and a large proportion of the NO X 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 regiona l haze planning period by addressi ng the Independence facility in our reasonable progress analysis, which as we no te above is the second largest source of both SO 2 and NO X . We are proposing under Option 1 to cont rol Entergy Independence for the first planning period for both SO 2 and NO X . Alternatively, under Option 2, for the first planning period, we are proposing to control Entergy Independence only for SO 2

. The fourth largest SO 2 and NO X point sources in Arkansas ar e the Future Fuel Chemical Company, with emissions of 3,421 SO 2 tpy, and the Natural Gas Pipeline Company of America #308, with emissions of 3,194 NO X 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 facili ties because we believe it is appropriate to defer the consideration of any a dditional sources besides Independence to future regional haze planning periods. For Independe nce, however, under Option 1, in combination with the BART sources we woul d be addressing 84% of the SO 2 point source emissions in the State and over 55% of the NO X point source emissions. Under Option 2, we would be deferring the consideration of additional NO X controls to future regional haze planning periods. . In the next section, we describe our consideration of the four reasonable pr ogress factors for the Entergy Independence Plant as well as the CA LPUFF 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 th e four-factor analysis is to determine wh at degree of progress toward natural visibility conditions is reasonable. Therefore, it is approp riate 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 SO 2 Controls
The Entergy Independence Plant is an electric generating station with two nearly identical coal-fired units (Units 1 and 2) with a name plate capacity of 900 MW each. Units 1 and 2 are tangentially-fired boilers that burn sub-bituminous co al 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 spreadsheet 136 that contains information concerning ownership, location, boiler type, environmental c ontrols and other pertinent information on these facilities. The spread sheet includes information contai ned 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. A ll four units burn coal from the Powder River Basin (PRB) of Wyoming with similar characteristic s. All four units employ cold side ESPs for particulate collection. Other pertin ent 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 annua lized dry FGD and wet FGD costs we developed for the White Bluff units to the Independence units. However, we adjusted the cost-effectiveness ($/to n) due to the differing baseline SO 2 emissions from the units. Consistent with the cost estimate we developed fo r 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 SO 2 tpy, assuming baseline emissions 140 of 14,269 SO 2 tpy (see table below). The average co st-effectiveness of dry FGD at Unit 1 is estimated to be $2,477/ ton SO 2 removed. For Unit 2, we estimate that th e 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 (SO 2 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 (SO 2 Cost TSD).” A copy of this TSD is found in the docket for our proposed rulemaking.

140 Baseline emissions were determined by examining annual SO 2 emissions for the years 2009-2013, eliminating

the year with the highest emissions a nd the year with the lowest emissions, and obtaining the average of the three remaining years.137 SO 2 tpy, assuming baseline emissions of 15,511 SO 2 tpy. The average cost-e ffectiveness of dry FGD at Unit 2 is estimated to be $2,286/ ton SO 2 removed.

Table 84. Summary of Dry FGD Costs for Entergy Independence Units 1 and 2

Unit Baseline Emission Rate (SO 2 tpy) Controlled Emission

Level (lb/MMBtu) Annual Emissions Reductions

(SO 2 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 th e White Bluff facility is that dry FGD is more cost-effective (lower $/ton) than wet FGD, and that the additiona l visibility benefits obtained as a result of the grea ter level of control wet FGD of fers 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 SO 2 controls for Independence Units 1 and 2 focuses on dry FGD. Nevertheless, we have calculated the co st-effectiveness of wet FGD for Independence Units 1 and 2 using the total annualized cost estimate provided by Enterg y 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 fo r White Bluff, we estimated a to tal 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 SO 2 tpy, assuming baseline emissions 143 of 14,269 SO 2 tpy (see table below). The average cost-effec tiveness of wet FGD at Unit 1 is estimated to be $3,706/ton SO 2 ton. For Unit 2, we estimate that the annual emissions reductions would be 14,497 SO 2 tpy, assuming baseline emissions of 15,511 SO 2 tpy. The average cost-effectiveness of wet FGD at Unit 2 is estimated to be $3,416/ton SO 2 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 SO 2 BART for White Bluff Units 1 and 2.

142 See our Cost Analysis TSD titled “Technical Support Do cument for the SDA Control Cost Analysis for the Entergy White Bluff and Independence Facilities Arkans as Regional Haze Federa l Implementation Plan (SO 2 Cost TSD).” The TSD is found in the docket for our proposed rulemaking.

143 Baseline emissions were determined by examining annual SO 2 emissions for the years 2009-2013, eliminating the year with the highest emissions a nd the year with the lowest emissions, and obtaining the average of the three remaining years.138 Unit Baseline Emission Rate (SO 2 tpy) Controlled Emission

Level (lb/MMBtu) Annual Emissions Reductions

(SO 2 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 Unit s 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 alr eady been factored into the co st 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. Becau se the facility is not located in an exceptionally arid region, we do not anticipate that there would be water-availa bility issues that would affect the feasibility of wet FGD. Lastly, wet FGD systems have the po tential for increased particulate and sulfuric acid mist releases that contri bute 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 operat ion 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 Comme nts for Sections E. through H. of the Federal Register Notice for the Oklahoma Regional Haze and Visibility Transport Federal Implementation Plan, Docket No. EPA-R 06-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 reasonabl e under the reasonable progress re quirements, 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 co nsider 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 Ente rgy Independence Plant. We conducted CALPUFF modeling to determine the visibility improvement of SO 2 controls at these Class I areas, based on the 98 th percentile visibility impact s. (See Appendix C to this TSD for detailed discussion of the modeling protocol, model inputs and visibility m odeling results). As shown in the tables below, both dry FGD and wet FGD are projected to result in considerable visibi lity 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 improveme nt 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 visi bility improvement anticipated from dry FGD at both units using an updated ba seline emission level for NO X based on lower, more recent emissions. This modeled visibility improvement wa s similar to previous results with visibility improvements ranging from 0.97 to 1.08 dv at each cl ass I area. See Appendix C to this TSD for detailed discussion of the modeling protocol, m odel inputs and visibili ty modeling results for each modeled control scenario.

Table 86. Entergy Independence Unit 1: EPA Modeled Maximum 98 th Percentile Visibility Impact and Improvement from SO 2 Controls

Class I Area Distance (km) Visibility Impact ( ∆ dv) Visibility Improvement Over Baseline (dv) Incremental Visibility Improvement of

Wet FGD vs.

Dry FGD Baseline 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 98 th Percentile Visibility Impact and Improvement from SO 2 Controls

Class I Area Distance (km) Visibility Impact ( ∆ dv) Visibility Improvement Over Baseline (dv) Incremental Visibility Improvement of

Wet FGD vs.

Dry FGD Baseline 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 98 th Percentile Visibility Impact and Improvement of SO 2 Controls (Facility-wide)

Class I Area Distance (km) Visibility Impact ( ∆ dv) Visibility Improvement Over Baseline (dv) Incremental Visibility Improvement of Wet FGD vs. Dry FGD Baseline Dry FGD Wet FGD Dry FGD Wet FGD

Caney Creek 277 2.412 1.474 1.442 0.938 0.97 0.032141 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 SO 2 for the Entergy Independence Plant:

Based on our analysis of the four RP fact ors, as well as the considerable projected visibility improvement, we propose to require compliance with an SO 2 emission limit of 0.06 lb/MMBtu for Independence Units 1 and 2 base d on a 30 boiler-operating-day rolling average basis. We propose to find that this emissi on limit, which is based on the installation and operation of dry FGD, is co st-effective at $2,477/ ton SO 2 removed for Unit 1 and $2,286/ton SO 2 removed for Unit 2, and would result in signifi cant visibility benefits at the Caney Creek and Upper Buffalo Wilderness Areas and the two Cl ass I areas in Missouri. Under either Option 1 or 2, we are proposing SO 2 controls on Independence Units 1 and 2 for the first planning period. We note that more recent emission data show an overall increase in SO 2 emissions from the facility. Therefore anticipated visibility improvement from c ontrols would be anticipated to be larger and the $/SO 2 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 th an that of dry FGD. We fou nd the cost of wet FGD to be $3,706 and $3,416 per ton of SO 2 removed at Units 1 and 2, resp ectively. We found the cost of dry FGD to be $2,477 and $2,286 per ton of SO 2 removed for Units 1 and 2, respectively. We do not believe that the minimal amount of incremen tal visibility improvement projected to result from wet FGD justifies the higher cost compar ed to dry FGD. We are proposing to require compliance with an emission limit of 0.06 lb/MMB tu based on a 30 boiler-operating-day rolling average basis for Independence Units 1 and 2 no late r than 5 years from the effective date of the final rule, based on the installati on and operation of dry FGD. We ar e proposing that the facility demonstrate compliance with this em ission limit using the existing CEMS.142 b. Reasonable Progress Analysis for NO X controls

As noted previously, monitoring data as we ll as CENRAP’s CAMx source apportionment modeling results for 2002 and 2018 show that visi bility 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 NO X 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 visi bility impairment estimates for individual facilities. As part of our analysis for Independence, we performed modeling using CALPUFF to assess the facility’s individual visi bility impact and the visibility benefit of controls, as was done for the subject-to-BART units discussed above including the sister fa cility, White Bluff. CALPUFF is the recommended model 146 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 SO 2 and NO X emissions. The primary goal of this modeling was to assess the po tential visibility benefit of SO 2 controls, given the relatively large emissions of SO 2 from the facility and that SO 2 emissions are the primary cause of visibility impairment on the 20% worst days at th e Class I areas of interest. The results of this analysis of SO 2 controls are discussed in the sec tion above. These CALPUFF results also indicated that impacts from NO X emissions can be significant on some days, and as discussed further below, NO X 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 w ith our guideline techniques in conducting the CALPUFF modeling. CALPUFF modeling provides an asse ssment of the near maximum (98 th 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 ma y not correlate with th e same meteorological conditions or days when visibili ty is most impaired at a par ticular Class I area since CALPUFF modeling is only for one facility and does not in clude 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 natura l background. Visibility impairment on the 20% worst days may be driven by impacts from ot her facilities and di fferent meteorological conditions. Identification of the 20% worst da ys is determined by IMPROVE monitor data during the baseline period at each Class I ar ea. The source apportionment results for the 20% worst days are then based on CAMx modeling usi ng a single year of me teorological data (2002) and using estimates of actual emissions from 200 2 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 a nd the average impact during the 20% worst days, the CALPUFF modeling results discussed be low indicate a more significant impact than suggested by the source apportionment CAMx re sults. We also note that differences in the metrics examined (maximum 98 th percentile impact versus aver age impact during the 20% worst days), emissions modeled (single–source ma ximum 24-hour actual emissions versus actual emissions from all emission sources 147 ), and differences in chemistry models result in CAMx visibility analysis resu lts 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 th at sizeable reductions to the maximum 98 th percentile visibility impact from the Inde pendence facility may be achieved through NO X controls. 148 We recognize, however, that at this time, point source NO X emissions are not the main contributors to visibility impairment on th e 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 poten tially one of the largest single contributors to visibility impairment at Class I ar eas in Arkansas, we believe that it is appropriate to evaluate the appropriateness of NO X controls during th is planning period.

Costs of Compliance:

As discussed above, due to the similarity of thes e facilities, we applied the total annualized LNB/SOFA cost developed by En tergy 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 NO X 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 additiona l 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 woul d apply to Independence Units 1 and 2. Therefore, our evaluation of NO X controls for Independence Units 1 and 2 will focus solely on LNB/SOFA. Consistent with the cost estim ate 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 NO X 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 cont rolled emission level of 0.15 lb/MMBtu, and estimate that the annual emissions reductions at Unit 1 would be 2,710 NO X tpy, assuming baseline emissions 151 of 6,329 NO X tpy (see table below). The average cost-effectiveness of LNB/SOFA at Unit 1 is es timated to be $401/ton NO X removed. For Unit 2, we estimate that the annual emissions reductions would be 3,217 NO X tpy, assuming baseline emissions of 6,384 NO X tpy. The average cost-effectiven ess of LNB/SOFA at Unit 2 is estimated to be $436/ton NO X removed.

Table 89. Summary of LNB/SOFA Costs fo r Entergy Independence Units 1 and 2

Unit Baseline Emission Rate (NO X tpy) Controlled Emission

Level (lb/MMBtu) Annual Emissions Reductions (NO X 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 NO X controls on EGUs, we expect that 3 years from the date of our final action would be suffici ent 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 installe d in 1983 and 1984. Unit 1 was placed into operation in 1983 and Unit 2 was placed into operat ion 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 NO X emissions for the years 2009-2013, eliminating the year with the highest emissions a nd 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 un its would continue to ope rate 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 reasonabl e under the reasonable progress re quirements, 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 co nsider 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 Ente rgy Independence Plant. We conducted CALPUFF modeling to determine the visibility improvement of NO X controls at these Class I areas, based on the 98 th percentile visibility impacts. 153 As shown in the table belo w, 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 installa tion 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 Cl ass I areas ranges from 0.213 – 0.264 dv. We also conducted a modeling run of both LNB/OFA and dr y 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 SO 2 emissions from the facility. Therefore anticipated visibility improvement from controls would be an ticipated to be larger and there would be an improvement in the cost-effectiven ess (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 98 th Percentile Visibility Impacts of LNB/SOFA

Class I Area Distance (km) Visibility Impact ( ∆ dv) Visibility Improvement of LNB/SOFA Over Baseline (dv) Baseline 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 NO X for the Entergy Independence Plant:

As discussed above, based on the CENRAP ’s CAMx modeling, sulfate from point sources is the driver of regiona l 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% wo rst days, contributing only approxi mately 3% of the total light extinction. The Regional Haze Rule requires th at 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 degrada tion 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 li ght extinction at Caney Creek and Upper Buffalo on the most impaired days, we do not expect that NO X controls under the reasonable progress requirements would offer as much improvement on the most impaired days compared to SO 2 controls. However, upon evaluation of the four reasonable progress factors, we f ound that the installation and operation of LNB/SOFA at Independence Un its 1 and 2 is estimated to cost $401/NO X ton removed at Unit 1 and $436/NO X ton removed at Unit 2, which we consider to be very costeffective. These NO X controls are also projected to result in significant visibility improvements at

156 Baseline NO X emissions were updated to the maximum 24-hr emissions from 2011-2013 for the evaluation of the anticipated benefit from NO X 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 98 th percentile modeled visibility impacts. Therefore, under Option 1, for the first planning period, we ar e proposing both an SO 2 emission limit as described above and a NO X emission limit of 0.15 lb/MMBtu on a 30 boileroperating-day averaging basis base d on the installation and operati on of LNB/SOFA, in light of their cost-effectiveness and visibility benef it 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 SO 2 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 Clas s 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 SO 2 and NO X control measures that woul d address the regional haze re quirements for Entergy White Bluff Units 1 and 2 and Entergy Independence Un its 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 thes e 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 a pproved 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 emissi ons reductions and commensurate visibility improvements beyond what was in the 2008 Arka nsas RH SIP. Development of refined numerical RPGs for Arkansas’ Class I areas w ould 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 dur ing this planning period, the new photochemical modeling would require an update of the emissi ons 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 invent ory 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 compu ting hardware and expertise. De veloping all of the necessary input files, running the photochemical model, a nd post-processing the mode l outputs would take several months at a minimum. Therefore, we are not conducting new photochemical grid modeling to establish revised numeric RP Gs for Caney Creek and Upper Buffalo. In order to provide RPGs that account for em ission reductions from the FIP controls, we have used a method similar to the one used in our Regional Haze FIP for Hawaii 158 and Arizona, 159 which is based on a scali ng 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 ex tinction components from the CENRAP’s CAMx photochemical modeling with source apportionment. The 2018 CAMx emission scenario included some assumptions of state BART determinations and ot her SIP controls, as well as projected emissions from other point, area, and mobile sources. We scaled the modeled visibility extinction components for sulfate (SO 4 ) and nitrate (NO 3 ) from point sources in Arkansas (Table 92) in proportion to the FIP’s emission reductions for SO 2 and NO X , respectively. The sulfate scaling factor was the 2018 CENRAP emission i nventory for Arkans as point source SO 2 emissions with FIP controls for BART and RP sources in place, divided by the original 2018 CENRAP emission inventory for Arkansas point source SO 2 emissions (Table 91). We conducted the same scaling exercise with nitrate and NO X . 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 emissi on reductions contained in this proposed FIP into quantitative RPGs, based on modeling pr eviously performe d by the CENRAP.

Table 91. 2018 CENRAP CAMx modeled extincti on 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 do cket for this pr oposed rulemaking.149 Table 92. Nitrate and Sulfate Scaling Factors for 2018 RPG calculation

2018 CENRAP Arkansas Point Source Emissions (tpy) FIP Emission reductions 162 Scaling factor

Option 1 Option 2 Option 1 Option 2

NO X 71,107 8,745 1,219 0.8770 0.9829

SO 2 106,461 69,128 69,128 0.3507 0.3507

These RPGs reflect rates of pr ogress that are faster than th e rates projected by Arkansas. The revised RPGs for the first planning peri od for the 20% worst days are 22.27 dv for Caney Creek and 22.33 dv for Upper Buffalo. The result s 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 In dependence Units 1 and 2 for the first planning period for both SO 2 and NO X . Alternatively, under Option 2, we are proposing to control Entergy Independence Units 1 and 2 only for SO 2 for the first planning period. Due to the small impact from all Arkansas point source NOx emissions co mbined 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 diffe rence 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. Ar kansas will have to re-evaluat e during the next regional haze planning period what BART and reasonable progre ss 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 whet her 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 devel op new RPGs for approval by us along with its progress report, based on new mode ling or other appropriate techni ques, in accordance with the requirements of 40 CFR 51.308(d)(1).

162 NO X 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, exclud ing the maximum and minimum year). These gas units were projected for early retirement (s ee 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 Goal s 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 stat es include in their SIP a 10 to 15-year strategy, referred to as the long-term strate gy, 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 im plementation 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 sc hedules, 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 Cla ss I area. These factors are the following: (1) emission reductions due to ongoi ng air pollution control programs, including measures to address RAVI; (2) measures to mitigate the impacts of construction activities; (3) emissions limitations and schedules for complian ce 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 visibi lity 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 a nd schedules of compliance to ach ieve the RPGs for each Class I area, the BART emission limits th at 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 Ar kansas’ long-term strate gy. The BART limits and two RPGs for Arkansas’ Class I areas that ar e 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 propos ed FIP also correct the deficiency in Arkansas’ long-term strategy for each of its Class I areas.