Vol. 81 Tuesday, 

No. 187 September 27, 2016 

Part II 

Environmental Protection Agency 

40 CFR Part 52 

Promulgation of Air Quality Implementation Plans; State of Arkansas; 

Regional Haze and Interstate Visibility Transport Federal Implementation 

Plan; Final Rule 


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66332 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

1 76 FR 64186, October 17, 2011 (proposed 

action); and 77 FR 14604, March 12, 2012 (final 

action). 

2 77 FR 14604. 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R06–OAR–2015–0189; FRL–9952–03- 

Region 6] 

Promulgation of Air Quality 

Implementation Plans; State of 

Arkansas; Regional Haze and 

Interstate Visibility Transport Federal 

Implementation Plan 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is promulgating a final 

Federal Implementation Plan (FIP) 

addressing the requirements of the 

Regional Haze Rule and interstate 

visibility transport for the portions of 

Arkansas’ Regional Haze State 

Implementation Plan (SIP) that EPA 

disapproved in a final rule published in 

the Federal Register on March 12, 2012. 

In that action, we partially approved 

and partially disapproved the State’s 

plan to implement the regional haze 

program for the first planning period. 

This final rule addresses the Regional 

Haze Rule’s requirements for Best 

Available Retrofit Technology (BART), 

reasonable progress, and a long-term 

strategy (LTS), as well as the 

requirements of the Clean Air Act (CAA 

or Act) regarding interference with other 

states’ programs for visibility protection 

(interstate visibility transport) triggered 

by the issuance of the 1997 ozone 

National Ambient Air Quality Standards 

(NAAQS) and the 1997 fine particulate 

matter (PM2.5) NAAQS. The FIP 

includes sulfur dioxide (SO2), nitrogen 

oxide (NOX), and particulate matter 

(PM) emission limits for nine units 

located at six facilities to address BART 

requirements (these limits also satisfy 

reasonable progress requirements for 

these sources); and SO2 and NOX

emission limits for two units located at 

one power plant to address the 

reasonable progress requirements. We 

also provide reasonable progress goals 

(RPGs) for Arkansas’ Class I areas. We 

are prepared to work with the State on 

a SIP revision that would replace some 

or all elements of the FIP. 

DATES: This final rule is effective on 

October 27, 2017. 

ADDRESSES: The EPA has established a 

docket for this action under Docket ID 

No. EPA–R06–OAR–2015–0189. All 

documents in the docket are listed on 

the http://www.regulations.gov Web 

site. Publicly available docket materials 

are available either electronically 

through http://www.regulations.gov or 

in hard copy at EPA Region 6, 1445 Ross 

Avenue, Suite 700, Dallas, Texas 75202– 

2733. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Dayana Medina at 214–665–7241; or 

Medina.dayana@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document wherever 

‘‘we,’’ ‘‘us,’’ or ‘‘our’’ is used, we mean 

the EPA. Also throughout this 

document, when we refer to the 

Arkansas Department of Environmental 

Quality (ADEQ), we mean Arkansas. 

Table of Contents 

I. Introduction 

II. History of State Submittals and Our 

Actions 

A. State Submittals and EPA Actions 

B. EPA’s Authority To Promulgate a FIP 

III. Summary of Our Proposed Rule 

A. Regional Haze 

B. Interstate Visibility Transport 

IV. Summary of Our Final FIP 

A. Regional Haze 

1. Identification of BART-Eligible and 

Subject-to-BART Sources 

2. BART Determinations 

3. Reasonable Progress Analysis 

4. Long Term Strategy 

B. Interstate Visibility Transport 

V. Summary and Analysis of Major Issues 

Raised by Commenters 

A. General Comments 

B. Entergy’s Alternative Strategy for White 

Bluff and Independence 

C. Reasonable Progress Goals and 

Reasonable Progress Analysis 

D. Control Levels and Emission Limits 

E. Domtar Ashdown Mill Repurposing 

Project 

F. Other Compliance Dates 

G. Compliance Demonstration 

Requirements 

H. Reliance on CSAPR Better than BART 

I. Cost 

J. Modeling 

K. Legal 

L. Interstate Visibility Transport 

VI. Final Action 

A. Regional Haze 

B. Interstate Visibility Transport 

VII. Statutory and Executive Order Reviews 

I. Introduction 

The purpose of Federal and state 

regional haze plans is to achieve a 

national goal, declared by Congress, of 

restoring and protecting visibility at 156 

Federal Class I areas across the United 

States, most of which are national parks 

and wilderness areas with scenic vistas 

enjoyed by the American public. The 

national goal, as described in CAA 

Section 169A, is ‘‘the prevention of any 

future, and the remedying of any 

existing, impairment of visibility in 

mandatory Class I Federal areas which 

impairment results from man-made air 

pollution.’’ States are required to submit 

SIPs that ensure reasonable progress 

toward the national goal of remedying 

anthropogenic visibility impairment in 

Federal Class I areas. Arkansas has two 

Federal Class I areas, the Caney Creek 

Wilderness Area (Caney Creek) and 

Upper Buffalo Wilderness Area (Upper 

Buffalo). Please refer to our previous 

rulemaking on the Arkansas Regional 

Haze SIP for additional background 

information regarding the CAA, regional 

haze, and the Regional Haze Rule.1

In our previous action on the 

Arkansas Regional Haze SIP, we 

approved a number of elements but 

disapproved others.2 In this final action, 

we are addressing these disapproved 

elements. We are establishing BART 

emission limits for nine units at six 

facilities that contribute to visibility 

impairment at Caney Creek and Upper 

Buffalo in Arkansas, as well as the 

Hercules-Glades Wilderness Area 

(Hercules-Glades) and the Mingo 

National Wildlife Refuge (Mingo) in 

Missouri. These facilities are subject to 

BART controls for emissions of SO2, 

NOX, and PM. The BART sources are 

the Arkansas Electric Cooperative 

Corporation Carl E. Bailey Generating 

Station (AECC Bailey) Unit 1; Arkansas 

Electric Cooperative Corporation John L. 

McClellan Generating Station (AECC 

McClellan) Unit 1; American Electric 

Power (AEP) Flint Creek Power Plant 

Unit 1; Entergy White Bluff Plant Units 

1, 2, and Auxiliary Boiler; Entergy Lake 

Catherine Plant Unit 4; and Domtar 

Ashdown Mill Power Boilers Nos. 1 and 

2. In addition, we are establishing SO2

and NOX emission limits for the Entergy 

Independence Plant Units 1 and 2 

pursuant to the reasonable progress and 

long-term strategy provisions of the 

Regional Haze Rule. We have calculated 

numerical RPGs for Caney Creek and 

Upper Buffalo that reflect the visibility 

improvement anticipated by 2018 from 

the combination of control measures 

from the approved portion of the 

Arkansas Regional Haze SIP and this 

FIP. 

We are also making a finding that the 

combination of the approved portion of 

the Arkansas Regional Haze SIP and this 

FIP satisfy the requirements of CAA 

section 110(a)(2)(D)(i)(II) with respect to 

visibility (interstate visibility transport 

requirement) for the 1997 8-hour ozone 

and 1997 PM2.5 NAAQS. This provision 

of the CAA requires that each state’s SIP 

have adequate provisions to prohibit instate emissions from interfering with 

measures required to protect visibility 

in any other state. To address this 

requirement, the SIP must address the 


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3These deficiencies are discussed in our March 

12, 2012 final action on the Arkansas Regional Haze 

SIP and SIP revision to address the interstate 

visibility transport requirements. See 77 FR 14604. 

4 76 FR 64186. 

5 77 FR 14604. 

6See 76 FR 64186, 64188 (proposed action) and 

77 FR 14604, 14672 (final action). 

7 80 FR 18944. 

8 80 FR 24872. 

9 80 FR 43661. 

10 81 FR 19097. 

11See the spreadsheet titled ‘‘Caney Creek and 

Upper Buffalo Wilderness Areas Reasonable 

Progress Goals (CACR UPBU RPG analysis.xlsx),’’ 

which is available in the docket for our rulemaking. 

potential for interference with visibility 

protection caused by the pollutant 

(including precursors) to which the new 

or revised NAAQS applies. In our 

March 12, 2012 final action on the 

Arkansas Regional Haze SIP, we also 

partially approved and partially 

disapproved the SIP submittal with 

respect to the interstate transport 

visibility requirement under CAA 

section 110(a)(2)(D)(i)(II). This FIP fully 

addresses the deficiencies we identified 

in our final action on the Arkansas 

Regional Haze SIP with respect to the 

interstate visibility transport 

requirement under CAA section 

110(a)(2)(D)(i)(II) for the 1997 8-hour 

ozone and 1997 PM2.5 NAAQS. 

In this document, we summarize our 

responses to comments received during 

our comment period on our proposed 

rule and indicate where we have made 

adjustments based on the comments and 

additional information we received. In 

some cases, we have adjusted the 

emission limits, compliance deadlines, 

and requirements for testing and 

demonstration of compliance in 

response to information received during 

the comment period. We also received 

several comments, from Entergy and 

Sierra Club, after the close of the 

comment period, which included new 

information on an alternative approach 

for White Bluff. We do not address these 

late comments in our rulemaking and 

they are not a basis for our decision in 

this action. We do note that the new 

information regarding an alternative 

approach may have promise with 

respect to addressing the BART 

requirements for White Bluff, and we 

encourage the State to consider it as it 

develops a SIP revision to replace our 

FIP. 

EPA is promulgating this partial FIP 

to address the deficiencies in the 

Arkansas Regional Haze SIP and the SIP 

revision submitted by the State to 

address the interstate visibility transport 

requirements.3 The State retains its 

authority to submit a revised state plan 

consistent with CAA and Regional Haze 

Rule requirements. EPA stands ready to 

work with the State on a SIP revision 

that would replace some or all elements 

of the FIP. 

II. History of State Submittals and Our 

Actions 

A. State Submittals and EPA Actions 

Arkansas submitted a SIP to address 

the regional haze requirements for the 

first planning period on September 23, 

2008. On August 3, 2010, Arkansas 

submitted a SIP revision that addressed 

the Arkansas Pollution Control and 

Ecology Commission (APCEC) 

Regulation 19, Chapter 15, which is the 

State rule that identifies the BARTeligible and subject-to-BART sources in 

Arkansas and establishes the BART 

emission limits that subject-to-BART 

sources are required to comply with. On 

September 27, 2011, the State submitted 

supplemental information related to 

regional haze. We are hereafter referring 

to these regional haze submittals 

collectively as the ‘‘Arkansas Regional 

Haze SIP.’’ On April 2, 2008, Arkansas 

submitted a SIP revision to address the 

interstate visibility transport 

requirement of CAA section 

110(a)(2)(D)(i)(II) for the 1997 8-hour 

ozone and 1997 PM2.5 NAAQS. On 

October 17, 2011, we published our 

proposed partial approval and partial 

disapproval of the Arkansas Regional 

Haze SIP and the interstate visibility 

transport SIP.4 Our final rule partially 

approving and partially disapproving 

the Arkansas Regional Haze SIP and 

interstate visibility transport SIP was 

published on March 12, 2012.5 We 

explained in our proposed and final 

actions on the Arkansas Regional Haze 

SIP that we elected not to promulgate a 

FIP concurrently with our partial 

disapproval action because ADEQ 

expressed its intent to revise the 

disapproved portions of the SIP and we 

therefore wanted to provide the state 

time to submit a SIP revision.6

Our final partial disapproval of the 

Arkansas RH SIP and interstate 

visibility transport SIP started a 2-year 

FIP clock such that we have an 

obligation to approve a SIP revision 

and/or promulgate a FIP to address the 

disapproved portions of the SIP within 

2 years of our final partial disapproval 

action. We began working in 2012 with 

ADEQ and the affected facilities to 

revise the disapproved portions of the 

SIP. However, a SIP revision was not 

submitted and the FIP clock expired in 

April 2014. On April 8, 2015, we 

proposed a FIP to address the 

disapproved portions of the Arkansas 

Regional Haze SIP and interstate 

visibility transport SIP.7 On May 1, 

2015, we published a notice extending 

the public comment period for our FIP 

proposal and announcing the 

availability in the docket of 

supplemental modeling we performed 

for the Entergy Independence Plant 

following the April 8, 2015 publication 

of our FIP proposal.8 On July 23, 2015, 

we published a notice reopening the 

public comment period for our FIP 

proposal by 15 days in response to a 

request we received from the Domtar 

Ashdown Mill so that the facility would 

be able to complete modeling work and 

submit to us information it deemed to 

be essential and related to a significant 

aspect of the proposed FIP requirements 

for the Domtar Ashdown Mill.9 The 

reopening of the comment period also 

allowed other interested persons 

additional time to submit comments to 

us on our FIP proposal. On April 4, 

2016, we published a notice and 

welcomed comment on supplemental 

information added to the docket which 

we relied on in our FIP proposal 

published on April 8, 2015, but which 

was inadvertently omitted from the 

docket at the time we proposed our 

FIP.10 Our notice published on April 4, 

2016, also reopened the public comment 

period for our FIP proposal until May 4, 

2016, but strictly limited the reopening 

of the comment period to our 

calculations of the revised RPGs, as 

presented in the spreadsheet we made 

available at that time in the docket.11 In 

this action, we are finalizing our FIP 

proposal published on April 8, 2015, 

and the associated aforementioned 

supplemental notices. 

B. EPA’s Authority To Promulgate a FIP 

Under CAA section 110(c), EPA is 

required to promulgate a FIP at any time 

within 2 years of the effective date of a 

finding that a state has failed to make a 

required SIP submission or has made an 

incomplete submission, or of the date 

that EPA disapproves a SIP in whole or 

in part. The FIP requirement is 

terminated only if a state submits a SIP, 

and EPA approves that SIP as meeting 

applicable CAA requirements before 

promulgating a FIP. CAA section 302(y) 

defines the term ‘‘Federal 

implementation plan’’ in pertinent part, 

as a plan (or portion thereof) 

promulgated by EPA ‘‘to fill all or a 

portion of a gap or otherwise correct all 

or a portion of an inadequacy’’ in a SIP, 

and which includes enforceable 

emission limitations or other control 

measures, means or techniques 

(including economic incentives, such as 

marketable permits or auctions or 

emissions allowances). 


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12 77 FR 14604. 

13 80 FR 18944. 

14 80 FR 24872. 

15 81 FR 19097. 

16See file titled ‘‘Region 6 feedback on Georgia 

Pacific 6A and 9A Boilers_3–4–2013,’’ which is 

found in the docket associated with this 

rulemaking. 

17As discussed in our proposal, Georgia Pacific 

estimated the maximum 24-hour emission rates 

using daily fuel usage data and emission factors 

from AP–42, Compilation of Air Pollutant Emission 

Factors. See 80 FR 18944, 18948. 

As discussed above, in a final action 

published on March 12, 2012, we 

disapproved in part the Arkansas 

Regional Haze SIP and the SIP 

submitted by the state to address the 

interstate visibility transport 

requirement of CAA section 

110(a)(2)(D)(i)(II) for the 1997 8-hour 

ozone and 1997 PM2.5 NAAQS.12 That 

final action became effective on April 

11, 2012. Therefore, EPA is required 

under CAA section 110(c) to promulgate 

a FIP for the portions of the Arkansas 

Regional Haze SIP and the SIP submittal 

to address the interstate visibility 

transport requirement of CAA section 

110(a)(2)(D)(i)(II) for the 1997 8-hour 

ozone and 1997 PM2.5 NAAQS that we 

disapproved on March 12, 2012. 

III. Summary of Our Proposed Rule 

In this section, we provide a summary 

of our proposed rule that was published 

in the Federal Register on April 8, 

2015,13 and the associated supplemental 

notices published on May 1, 2015,14 and 

April 4, 2016,15 as background for 

understanding this final action. Our 

electronic docket at 

www.regulations.gov contains Technical 

Support Documents (TSDs) and other 

materials that supported our proposal 

and supplemental notices. 

A. Regional Haze 

Our FIP proposal addressed the 

disapproved portions of the Arkansas 

Regional Haze SIP and interstate 

visibility transport SIP. In our March 12, 

2012 final action on the Arkansas 

Regional Haze SIP, we disapproved 

some of the state’s BART determinations 

and we also determined that the SIP did 

not include the required analysis of the 

four reasonable progress factors. 

Therefore, we partially disapproved the 

state’s LTS for Caney Creek and Upper 

Buffalo and also disapproved the RPGs 

established by the state. 

CAA section 169A(b)(2)(A) requires 

states to revise their SIPs to contain 

such measures as may be necessary to 

make reasonable progress towards the 

natural visibility goal, including a 

requirement that certain categories of 

existing major stationary sources built 

between 1962 and 1977 procure, install, 

and operate the ‘‘best available retrofit 

technology,’’ as determined by the state 

or EPA in the case of a plan 

promulgated under section 110(c) of the 

CAA. Under the Regional Haze Rule, 

states are directed to conduct BART 

determinations for such ‘‘BARTeligible’’ sources that may be 

anticipated to cause or contribute to any 

visibility impairment in a Class I area. 

Rather than requiring source-specific 

BART controls, states or EPA in a FIP 

also have the flexibility to adopt an 

emissions trading program or other 

alternative program as long as the 

alternative provides greater reasonable 

progress towards improving visibility 

than BART. CAA section 169(g)(2) and 

the Regional Haze Rule at 40 Code of 

Federal Regulations (CFR) 

§ 51.308(e)(1)(A) provide that in 

determining BART, the state or EPA in 

a FIP shall take into consideration the 

following factors: Costs of compliance, 

the energy and nonair quality 

environmental impacts of compliance, 

any existing pollution control 

technology in use at the source, the 

remaining useful life of the source, and 

the degree of improvement in visibility 

which may reasonably be anticipated to 

result from the use of such technology. 

We commonly refer to these as the 

BART factors, or the five statutory 

factors. CAA section 169(g)(1) and 

§ 51.308(d)(1) also require that in 

determining reasonable progress, there 

shall be taken into consideration the 

costs of compliance, the time necessary 

for compliance, the energy and nonair 

quality environmental impacts of 

compliance, and the remaining useful 

life of any existing source subject to 

such requirements. We commonly refer 

to these as the reasonable progress 

factors, or the four statutory factors. 

Consistent with the requirement in CAA 

section 169A(b) that states include in 

their regional haze SIP a 10—15 year 

strategy for making reasonable progress, 

§ 51.308(d)(3) requires that states 

include a LTS in their regional haze 

SIPs. The LTS is the compilation of all 

control measures a state will use during 

the implementation period of the 

specific SIP submittal to meet any 

applicable RPGs. The LTS must include 

enforceable emissions limitations, 

compliance schedules, monitoring and 

recordkeeping requirements, and 

various supporting documentation and 

analyses to ensure that the SIP or FIP 

will provide reasonable progress toward 

the national goal of natural visibility 

conditions. 

Our FIP proposal included proposed 

BART determinations for nine units at 

six facilities and proposed reasonable 

progress determinations for two units at 

one facility in Arkansas. These 

determinations resulted in proposed 

emission limits, compliance schedules, 

and other requirements for these 

sources. The proposed regulatory 

language was included under Part 52 at 

the end of that document. We also 

addressed the RPGs, as well as the LTS 

requirements. Lastly, we proposed that 

the approved measures in the Arkansas 

Regional Haze SIP and measures in our 

proposed FIP would adequately address 

the interstate transport of pollutants that 

affect visibility requirement for the 1997 

8-hour ozone and 1997 PM2.5 NAAQS. 

Georgia Pacific-Crossett Mill 6A and 

9A Power Boilers: In our FIP proposal, 

we proposed to find that the Georgia 

Pacific-Crossett Mill 6A Boiler is a 

BART-eligible source, but not subject to 

BART. We also proposed to find that the 

9A Boiler, which the State had 

previously determined was BARTeligible, is not subject to BART. Our 

proposed determinations were based on 

the company’s newly provided analysis 

and documentation, including BART 

screening modeling conducted in 2011 

by Georgia Pacific based on revised 

emission limits from a permit issued on 

May 23, 2012, and using 2001, 2002, 

and 2003 meteorology. The modeling 

showed the maximum visibility impact 

from the boilers was 0.359 deciviews 

(dv) at Caney Creek, which is below the 

0.5 dv threshold the state used in the 

Arkansas Regional Haze SIP to identify 

subject-to-BART sources. Prior to 

issuing our FIP proposal, we had 

communicated to ADEQ our concern 

with relying on the company’s BART 

screening modeling that was based on 

revised emission limits from a permit 

issued in 2012, without documentation 

that these emission limits were 

representative of the baseline period 

emissions.16 To address our concern, 

the company provided estimates of 

maximum 24-hour emission rates for the 

6A and 9A Boilers from the 2001–2003 

baseline period to demonstrate that 

these emission rates were lower than the 

revised emission limits that it modeled 

in its 2011 BART screening modeling.17

This indicated that the 2011 BART 

screening modeling that was based on 

allowable emissions was conservative in 

terms of representing the impact that the 

source had on visibility in the 2001– 

2003 period, the period that matters for 

the subject-to-BART determination, and 

we proposed to find that it is reasonable 

to conclude based on the modeling 

analysis and documentation provided 

by Georgia Pacific that the 6A and 9A 

Boilers had visibility impacts below 0.5 


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18The curve equation is Y = 0.4005 * X¥0.2645, 

where Y = pounds of sulfur emitted per ton dry fuel 

feed to the boiler and X = pounds of sulfur input 

per ton of dry bark. The purpose of this equation 

is to factor in the degree of SO2 scrubbing provided 

by the combustion of bark. 

19We define SO2 inlet to be the SO2 content of 

the fuel delivered to the fuel inlet of the combustion 

chamber. 

dv during the 2001–2003 baseline 

period and are therefore not subject to 

BART. 

AECC Bailey Unit 1: We proposed that 

BART for SO2 and PM is the use of fuels 

with 0.5% or lower sulfur content by 

weight. We also proposed to require 

that, after the effective date of the final 

rule, the facility shall not purchase fuel 

that does not meet the sulfur content 

requirement, but to allow the facility 5 

years to burn its existing supply of No. 

6 fuel oil, in accordance with any 

operating restrictions enforced by 

ADEQ. We proposed to require the 

facility to comply with the requirement 

to use fuels with 0.5% or lower sulfur 

content by weight no later than 5 years 

from the effective date of the final rule. 

We proposed that BART for NOX is the 

existing emission limit in the permit of 

887 lb/hr, which would not necessitate 

the installation of additional controls. 

We proposed to require the source to 

comply with this emission limit for 

BART purposes as of the effective date 

of the final rule. 

AECC McClellan Unit 1: We proposed 

that BART for SO2 and PM is the use of 

fuels with 0.5% or lower sulfur content 

by weight. We also proposed to require 

that, after the effective date of the final 

rule, the facility shall not purchase fuel 

that does not meet the sulfur content 

requirement, but to allow the facility 5 

years to burn its existing supply of No. 

6 fuel oil, in accordance with any 

operating restrictions enforced by 

ADEQ. We proposed to require the 

source to comply with the requirement 

to use fuels with 0.5% or lower sulfur 

content by weight no later than 5 years 

from the effective date of the final rule. 

We proposed that BART for NOX are the 

existing emission limits in the permit of 

869.1 lb/hr for natural gas firing and 

705.8 lb/hr for fuel oil firing, which 

would not necessitate the installation of 

additional controls. We proposed to 

require the source to comply with these 

emission limits for BART purposes as of 

the effective date of the final rule. 

AEP Flint Creek Unit 1: We proposed 

that BART for SO2 is an emission limit 

of 0.06 lb/MMBtu on a 30 boileroperating-day rolling average, which is 

consistent with the installation and 

operation of a type of dry flue gas 

desulfurization (FGD or ‘‘scrubbers’’) 

system called Novel Integrated 

Desulfurization (NID) technology. We 

stated that the full compliance time of 

5 years allowed under the CAA and 

Regional Haze Rule is appropriate for a 

new scrubber retrofit, and proposed to 

require the source to comply with this 

emission limit no later than 5 years from 

the effective date of the final rule. We 

proposed that BART for NOX is an 

emission limit of 0.23 lb/MMBtu on a 30 

boiler-operating-day rolling average, 

which is consistent with the installation 

and operation of new low NOX burners 

(LNB) with overfire air (OFA). We 

proposed to require the source to 

comply with this emission limit no later 

than 3 years from the effective date of 

the final rule. 

Entergy White Bluff Units 1 and 2: We 

proposed that BART for SO2 for Units 1 

and 2 is an emission limit of 0.06 lb/

MMBtu on a 30 boiler-operating-day 

rolling average, consistent with the 

installation and operation of dry FGD or 

another control technology that achieves 

that level of control. We proposed to 

require the source to comply with this 

emission limit no later than 5 years from 

the effective date of the final rule. We 

proposed that BART for NOX for Units 

1 and 2 is an emission limit of 0.15 lb/ 

MMBtu on a 30 boiler-operating-day 

rolling average, consistent with the 

installation and operation of LNB with 

separated overfire air (SOFA). We 

proposed to require the source to 

comply with this emission limit no later 

than 3 years from the effective date of 

the final rule. 

Entergy White Bluff Auxiliary Boiler: 

We proposed that the existing emission 

limit in the permit of 105.2 lb/hr is 

BART for SO2, the existing emission 

limit of 32.2 lb/hr is BART for NOX, and 

the existing emission limit of 4.5 lb/hr 

is BART for PM for the Auxiliary Boiler. 

These emission limits would not 

necessitate the installation of additional 

controls. We proposed to require the 

source to comply with these emission 

limits for BART purposes as of the 

effective date of the final rule. 

Entergy Lake Catherine Unit 4: We 

proposed that BART for NOX for the 

natural gas-firing scenario is an 

emission limit of 0.22 lb/MMBtu on a 30 

boiler-operating-day rolling average, 

consistent with the installation and 

operation of burners out of service 

(BOOS). We proposed to require the 

source to comply with this emission 

limit no later than 3 years from the 

effective date of the final rule. We 

invited public comment specifically on 

whether this proposed NOX emission 

limit is appropriate or whether an 

emission limit based on more stringent 

NOX controls would be appropriate. We 

did not propose BART determinations 

for the fuel oil-firing scenario for Lake 

Catherine Unit 4 in light of the source’s 

commitment to submit to Arkansas a 

five-factor BART analysis for the fuel 

oil-firing scenario, to then be submitted 

to us as a SIP revision for approval, 

before any fuel oil combustion takes 

place at Unit 4. We proposed that fuel 

oil-firing is not allowed to take place at 

Lake Catherine Unit 4 until BART 

determinations are promulgated for SO2, 

NOX, and PM for the fuel oil-firing 

scenario through our approval of a SIP 

revision and/or promulgation of a FIP. 

Domtar Ashdown Mill Power Boiler 

No. 1: We proposed that BART for SO2

is an emission limit of 21.0 lb/hr on a 

30 boiler-operating-day averaging basis, 

where boiler-operating-day is defined as 

a 24-hour period between 12 midnight 

and the following midnight during 

which any fuel is fed into and/or 

combusted at any time in the Power 

Boiler. This emission limit is consistent 

with the Power Boiler’s baseline 

emissions and would not necessitate 

additional controls. We proposed to 

require the source to comply with this 

emission limit as of the effective date of 

the final rule. We proposed to require 

the source to use a site-specific curve 

equation,18 provided to us by the 

facility, to calculate the SO2 emissions 

from Power Boiler No. 1 when 

combusting bark for purposes of 

demonstrating compliance with the 

BART requirement, and to confirm the 

curve equation using stack testing no 

later than 1 year from the effective date 

of the final rule. We also proposed that 

to calculate the SO2 emissions from fuel 

oil combustion for purposes of 

demonstrating compliance with the 

BART requirement, the facility must 

assume that the SO2 inlet 19 is equal to 

the SO2 being emitted at the stack. We 

invited public comment on whether this 

method of demonstrating compliance 

with the proposed SO2 BART emission 

limit for Power Boiler No. 1 is 

appropriate. 

We proposed that BART for NOX is an 

emission limit of 207.4 lb/hr on a 30 

boiler-operating-day rolling average, 

where boiler-operating-day is defined as 

a 24-hour period between 12 midnight 

and the following midnight during 

which any fuel is fed into and/or 

combusted at any time in the Power 

Boiler. This emission limit is consistent 

with the Power Boiler’s baseline 

emissions and would not necessitate 

additional controls. We proposed to 

require the source to comply with this 

emission limit as of the effective date of 

the final rule. To demonstrate 

compliance with this NOX BART 

emission limit, we proposed to require 

the source to conduct annual stack 


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66336 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

20See NEI 2011 v1. A spreadsheet containing the 

emissions inventory is found in the docket for our 

proposed rulemaking. 

testing. We invited public comment on 

the appropriateness of this method for 

demonstrating compliance with the 

proposed NOX BART emission limit for 

Power Boiler No. 1. 

Domtar Ashdown Mill Power Boiler 

No. 2: We proposed that BART for SO2

is an emission limit of 0.11 lb/MMBtu 

on a 30 boiler-operating-day rolling 

average, which we estimated is 

representative of operating the existing 

venturi scrubbers at 90% control 

efficiency and can be achieved through 

the installation of scrubber pump 

upgrades and use of additional 

scrubbing reagent. We indicated that 

boiler-operating-day is defined as a 24- 

hour period between 12 midnight and 

the following midnight during which 

any fuel is fed into and/or combusted at 

any time in the Power Boiler. We 

invited public comment specifically on 

the appropriateness of our proposed SO2

emission limit. We proposed to require 

compliance with this BART emission 

limit no later than 3 years from the 

effective date of the final action, but 

invited public comment on the 

appropriateness of a compliance date 

anywhere from 1–5 years. We also 

proposed to require the source to 

demonstrate compliance with this 

emission limit using the existing 

continuous emissions monitoring 

system (CEMS). 

We proposed that BART for NOX is an 

emission limit of 345 lb/hr on a 30 

boiler-operating-day rolling averaging 

basis, consistent with the installation 

and operation of LNB. We indicated that 

boiler-operating-day is defined as a 24- 

hour period between 12 midnight and 

the following midnight during which 

any fuel is fed into and/or combusted at 

any time in the Power Boiler. We 

proposed to require compliance with 

this emission limit no later than 3 years 

from the effective date of the final rule, 

and invited public comment on the 

appropriateness of this compliance date. 

We also proposed to require the source 

to demonstrate compliance with this 

emission limit using the existing CEMS. 

Power Boiler No. 2 is subject to the 

Boiler Maximum Achievable Control 

Technology (MACT) standards for PM 

required under CAA section 112, and 

found at 40 CFR part 63, subpart 

DDDDD—National Emission Standards 

for Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and 

Institutional Boilers and Process 

Heaters. We proposed to find that the 

current Boiler MACT PM standard 

satisfies the PM BART requirement for 

Power Boiler No. 2. We also proposed 

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. We proposed to require 

the source to comply with this emission 

limit for BART purposes as of the 

effective date of the final rule. 

Proposed Reasonable Progress 

Determinations: In our proposed rule, 

we explained that the Central Regional 

Air Planning Association (CENRAP) 

CAMx modeling with Particulate Source 

Apportionment Tool (PSAT) showed 

that point sources are responsible for a 

majority of the light extinction at 

Arkansas Class I areas, contributing 

approximately 60% of the total light 

extinction at each Class I area on the 

20% worst days in 2002. Point sources 

contributed 81.04 Mm¥1 out of 133.93 

Mm¥1 of light extinction at Caney Creek 

and 77.80 Mm¥1 out of 131.79 Mm¥1

of light extinction at Upper Buffalo on 

the average across the 20% worst days 

in 2002. Since other source types (i.e., 

natural, on-road, non-road, and area) 

each contributed a much smaller 

proportion of the total light extinction at 

each Class I area, we decided to focus 

only on point sources in our reasonable 

progress analysis for this planning 

period. 

As a starting point in our analysis to 

determine whether additional controls 

on Arkansas sources are necessary to 

make reasonable progress in the first 

regional haze planning period, we 

examined the most recent SO2 and NOX

emissions inventories for point sources 

in Arkansas. Based on the 2011 National 

Emissions Inventory (NEI), the Entergy 

White Bluff Plant, the Entergy 

Independence Plant, and the AEP Flint 

Creek Power Plant are the three largest 

point sources of SO2 and NOX emissions 

in Arkansas.20 The combined annual 

emissions from these three sources 

make up approximately 84% of the 

statewide SO2 point-source emissions 

and 55% of the statewide NOX pointsource emissions. As our proposed rule 

included SO2 and NOX emission limits 

under BART for White Bluff Units 1 and 

2 and Flint Creek Unit 1 that are 

anticipated to result in a substantial 

reduction in SO2 and NOX emissions 

from these facilities, we proposed to 

determine that it is appropriate to 

eliminate these three units from further 

consideration of additional controls 

under the reasonable progress 

requirements for the first planning 

period. The Entergy Independence Plant 

is not subject to BART, and its 

emissions were 30,398 SO2 tons per year 

(tpy) and 13,411 NOX tpy based on the 

2011 NEI. The Entergy Independence 

Plant is the second largest source of SO2

and NOX point-source emissions in 

Arkansas, accounting for approximately 

36% of the SO2 point-source emissions 

and 21% of the NOX point-source 

emissions in the State. In our proposal, 

we explained that it is appropriate to 

focus our reasonable progress analysis 

on the Entergy Independence Power 

Plant because it is a significant source 

of SO2 and NOX, as it is the second 

largest point source for both NOX and 

SO2 emissions in the State. We 

explained that our proposed SO2 and 

NOX controls under BART for White 

Bluff Units 1 and 2 and Flint Creek Unit 

1 and our evaluation of controls under 

reasonable progress for the 

Independence facility would address a 

sufficient amount of SO2 and NOX point 

source emissions in the State in this first 

planning period. The fourth largest SO2

and NOX point sources in Arkansas are 

the Future Fuel Chemical Company, 

with emissions of 3,421 SO2 tpy, and 

the Natural Gas Pipeline Company of 

America #308, with emissions of 3,194 

NOX tpy (2011 NEI). In comparison to 

the SO2 and NOX emissions from the top 

three point sources (i.e., White Bluff, 

Independence, and Flint Creek), 

emissions from these two facilities and 

remaining point sources in the state are 

relatively small. Therefore, we did not 

evaluate other Arkansas point sources in 

our reasonable progress analysis. We 

explained that it is therefore appropriate 

to defer the consideration and 

evaluation of any additional sources 

under reasonable progress to future 

regional haze planning periods. 

We conducted source-specific 

reasonable progress analyses of 

potential SO2 and NOX controls for 

Independence Units 1 and 2 and 

conducted CALPUFF modeling to assess 

the baseline visibility impacts from the 

facility and potential visibility benefits 

of controls. Based on these analyses, we 

proposed two options in the alternative 

for satisfying the reasonable progress 

requirements for Independence Units 1 

and 2. Under Option 1, we proposed to 

establish both SO2 and NOX emission 

limits. We proposed to require 

compliance with an SO2 emission limit 

of 0.06 lb/MMBtu for Independence 

Units 1 and 2 based on a 30 boileroperating-day rolling average basis, 

consistent with the installation and 

operation of dry FGD. We proposed to 

require Independence Units 1 and 2 to 

comply with this emission limit no later 

than 5 years from the effective date of 

the final rule. We proposed to require 

compliance with a NOX emission limit 

of 0.15 lb/MMBtu on a 30 boileroperating-day averaging basis, 


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Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66337 

21See Arkansas Regional Haze SIP, Appendix 

8.1—‘‘Technical Support Document for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze State Implementation Plans,’’ 

sections 3.7.1 and 3.7.2. See the docket for this 

rulemaking for a copy of the Arkansas Regional 

Haze SIP. 

22See Arkansas Regional Haze SIP, Appendix 

8.1—‘‘Technical Support Document for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze State Implementation Plans,’’ section 

3.7.1 and 3.7.2. See the docket for this rulemaking 

for a copy of the Arkansas Regional Haze SIP. 

23 80 FR 24872. 24April 13, 2015 letter from Mr. Bill Bumpers to 

Mr. Guy Donaldson, Chief, Air Planning Section, 

EPA Region 6, ‘‘Entergy Arkansas Inc. (EAI) request 

for extension of comment period on EPA–R06– 

OAR–2015–0189–0001.’’ This document is found in 

the docket for this rulemaking. 25See document titled ‘‘Summary of Additional 

Modeling for Entergy Independence,’’ dated April 

20, 2015. This document is found in the docket for 

this rulemaking. 

26See ‘‘Technical Support Document for EPA’s 

Proposed Action on the Arkansas Regional Haze 

Federal Implementation Plan’’ at page 147. 

consistent with the installation and 

operation of LNB/SOFA. We proposed 

to require Independence Units 1 and 2 

to comply with this emission limit no 

later than 3 years from the effective date 

of the final rule. 

We proposed to require SO2 controls 

based on our evaluation of the four 

reasonable progress factors, our 

CALPUFF modeling of the anticipated 

benefits of controls, and the existing 

CENRAP CAMx modeling. Specifically, 

we proposed that dry FGD was costeffective and would provide 

considerable visibility improvement on 

the days where Independence has the 

largest impacts at nearby Class I areas. 

Additionally, the CENRAP CAMx 

modeling showed that on most of the 

20% worst days in 2002, total extinction 

is dominated by sulfate at both Caney 

Creek and Upper Buffalo.21 Therefore, 

we concluded that the substantial SO2

emissions reductions that would be 

achieved by our proposed SO2 controls 

for Independence Units 1 and 2 would 

accordingly reduce visibility extinction 

at Arkansas’ Class I areas on the 20% 

worst days. 

We also proposed to require NOX

controls under Option 1 based on our 

evaluation of the four reasonable 

progress factors, our CALPUFF 

modeling of the anticipated benefits of 

controls, and the existing CENRAP 

CAMx modeling. Specifically, we 

proposed that LNB/SOFA was very costeffective and would provide 

considerable visibility improvement on 

the days where Independence has the 

largest impacts at nearby Class I areas. 

In addition, the CENRAP CAMx 

modeling showed that total extinction at 

Caney Creek was dominated by nitrate 

on 4 of the days that comprise the 20% 

worst days in 2002, while a significant 

portion of the total extinction at Upper 

Buffalo was due to nitrate on 2 of the 

days that comprise the 20% worst days 

in 2002.22 Therefore, we concluded that 

our proposed NOX controls on 

Independence Units 1 and 2 would 

improve visibility on some of the 20% 

worst days. In the alternative, we 

proposed under Option 2 to require only 

SO2 controls for Independence Units 1 

and 2 under the CAA’s reasonable 

progress requirements. Our reasoning 

for proposing to require only SO2

controls under Option 2 was that nitrate 

from point sources is not a primary 

contributor to the total light extinction 

at Arkansas Class I areas on most of the 

20% worst days, so NOX controls would 

not offer as much visibility 

improvement on the most impaired days 

as SO2 controls. In our proposed rule, 

we specifically solicited public 

comment on Options 1 and 2. 

In addition to Options 1 and 2, we 

also solicited public comment on any 

alternative SO2 and NOX control 

measures that would address the 

regional haze requirements for Entergy 

White Bluff Units 1 and 2 and Entergy 

Independence Units 1 and 2 for this 

planning period. We noted that this 

could include, but was 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 proposed for 

these four units in our proposed rule. 

On May 1, 2015, we published a 

notice in the Federal Register 

announcing supplemental modeling that 

we conducted for Independence Units 1 

and 2, and extending the comment 

period to allow interested persons 

additional time to provide comments on 

the supplemental modeling.23 We 

performed the supplemental modeling 

after receiving a letter dated April 13, 

2015, that revealed that we made an 

error in the modeled location of the 

Entergy Independence facility.24 The 

supplemental modeling included the 

corrected facility location. We provided 

a summary of our supplemental 

modeling for Independence Units 1 and 

2 in the docket for our proposed 

rulemaking.25 In the summary, we 

provided a comparison of our previous 

CALPUFF modeling for Independence 

Units 1 and 2 (i.e., the modeling that 

was presented in our proposed rule 

published on April 8, 2015) and our 

supplemental modeling. We noted that 

the modeled visibility benefits from our 

proposed SO2 controls (dry FGD) for 

Independence were the same or larger in 

the supplemental modeling. The largest 

difference was an increase of 0.29 dv in 

the modeled visibility benefit from SO2

controls at Upper Buffalo. The largest 

modeled benefit from NOX controls was 

at Caney Creek and was approximately 

the same in the supplemental modeling. 

Modeled visibility benefits from NOX

controls at the three other Class I areas 

were slightly smaller in the 

supplemental modeling. The change in 

location of the modeled facility resulted 

in different transport patterns from the 

facility to the Class I areas, which 

resulted in the modeled 98th percentile 

visibility impacts being more driven by 

sulfate impacts. Therefore, the benefits 

from NOX controls on the 98th 

percentile days were slightly reduced. 

In addition, whereas our previous 

modeling of the control scenario that 

included both dry FGD and LNB/SOFA 

controls showed visibility benefits 

ranging from 1.18 to 1.48 dv at each 

Class I area, the supplemental modeling 

showed larger visibility benefits ranging 

from 1.40 to 1.52 dv at each Class I area. 

After reviewing the supplemental 

modeling, we did not change our 

proposed reasonable progress controls 

for Independence Units 1 and 2. 

Proposed Reasonable Progress Goals: 

We proposed RPGs for Caney Creek and 

Upper Buffalo that reflected the 

anticipated visibility conditions 

resulting from the combination of 

control measures from the approved 

portion of the 2008 Arkansas Regional 

Haze SIP and our FIP proposal. As 

explained more fully in our proposal, 

we adjusted the 2018 RPGs modeled by 

CENRAP using a scaling methodology 

that adjusted visibility extinction 

components in proportion to emission 

changes. We recognized that this 

method was not refined, but explained 

that it allowed us to incorporate the 

additional emission reductions achieved 

through the FIP into the states’ RPGs. 

Based on this methodology, we 

proposed revised RPGs for the first 

planning period for the 20% worst days 

of 22.27 dv for Caney Creek and 22.33 

dv for Upper Buffalo. 

Our proposed revised RPGs and our 

methodology for calculating the revised 

RPGs were discussed in detail in our 

FIP proposal and in our technical 

support documentation,26 which was 

made available in the docket when the 

proposed rule was published on April 8, 

2015. However, a spreadsheet 

containing the actual calculations of our 

proposed revised RPGs for the 20% 

worst days for the Caney Creek and 

Upper Buffalo Wilderness Areas was 

inadvertently omitted from the docket. 

On April 4, 2016, we published a notice 

in the Federal Register announcing the 


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66338 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

27 81 FR 19097. 28See the document titled ‘‘Caney Creek and 

Upper Buffalo Wilderness Areas Reasonable 

Progress Goals (CACR UPBU RPG analysis.xlsx),’’ 

which is available in the docket for our rulemaking. 

availability in the docket of the 

spreadsheet containing the actual 

calculations of our proposed revised 

RPGs for the 20% worst days for the 

Caney Creek and Upper Buffalo 

Wilderness Areas.27 The notice also 

reopened the comment period for our 

FIP proposal until May 4, 2016, but 

strictly limited the reopening of the 

comment period to our calculations of 

the revised RPGs, as presented in the 

spreadsheet we made available at that 

time in the docket.28

Long-Term Strategy: We proposed to 

find that provisions in the approved 

portion of the Arkansas Regional Haze 

SIP and our FIP proposal fulfilled the 

requirements of 40 CFR 51.308(d)(3), 

which requires emission limitations, 

compliance schedules, monitoring and 

recordkeeping requirements, and 

various supporting documentation and 

analyses to ensure that the SIP or FIP 

will provide reasonable progress toward 

the national goal. Specifically, we 

proposed to promulgate emission limits, 

compliance schedules, and other 

requirements for Arkansas’ BART 

sources and the two units at the 

Independence facility to address the 

long-term strategy requirement. 

B. Interstate Visibility Transport 

Among other things, CAA section 

110(a)(2)(D)(i)(II) requires that all SIPs 

contain adequate provisions to prohibit 

emissions that will interfere with 

measures required to protect visibility 

in other states. We refer to this as the 

interstate transport visibility 

requirement. Our proposed FIP 

included emission limits for Arkansas 

sources under the BART and reasonable 

progress requirements that would 

ensure a level of emissions reductions at 

least as great as what surrounding states 

relied on in developing their regional 

haze SIPs. We proposed that the 

combination of the measures in the 

approved portions of the Arkansas 

Regional Haze SIP and our FIP proposal 

would satisfy the visibility requirement 

of CAA section 110(a)(2)(D)(i)(II) for the 

1997 8-hour ozone and 1997 PM2.5

NAAQS. 

IV. Summary of Our Final FIP 

Below, we present a summary of our 

final Arkansas Regional Haze FIP. In 

this section, we provide a summary of 

our final BART determinations, 

reasonable progress determinations, 

revised RPGs, LTS provisions, and 

interstate transport provisions. This 

final FIP includes emission limits, 

compliance schedules, and 

requirements for equipment 

maintenance, monitoring, testing, 

recordkeeping, and reporting for all 

affected sources and units. 

We note that we are finalizing our FIP 

with certain changes to our proposal in 

response to comments we received 

during the public comment period. In 

particular, we are finalizing a bifurcated 

NOX BART emission limit for White 

Bluff Units 1 and 2; we are finalizing an 

SO2 BART emission limit for the Domtar 

Ashdown Mill Power Boiler No. 1 in the 

form of lb/day based on a 30 boileroperating-day average instead of lb/hr 

based on a 30 boiler-operating-day 

average; and we are finalizing an SO2

BART emission limit for the Domtar 

Ashdown Mill Power Boiler No. 2 in the 

form of lb/hr based on a 30 boileroperating-day average instead of lb/

MMBtu based on a 30 boiler-operatingday average. In light of information we 

received during the public comment 

period, we are also adjusting the 

compliance dates for some of our BART 

determinations. We are requiring AEP 

Flint Creek Unit 1 to comply with the 

SO2 BART emission limit within 18 

months of the effective date of this final 

action, instead of the 5-year compliance 

date we proposed. We are requiring AEP 

Flint Creek Unit 1 and White Bluff Units 

1 and 2 to comply with the NOX BART 

emission limit within 18 months of the 

effective date of this final action, instead 

of the 3-year compliance date we 

proposed. We are requiring the Domtar 

Ashdown Mill to comply with the SO2

and NOX BART emission limits for 

Power Boiler No. 1 and the PM BART 

emission limit for Power Boiler No. 2 

within 30 days from the effective date 

of this final action instead of on the date 

of the final action. We are requiring the 

Domtar Ashdown Mill to comply with 

the SO2 and NOX BART emission limits 

for Power Boiler No. 2 within 5 years of 

the effective date of this final action, 

instead of the 3-year compliance date 

we proposed. We are making some 

adjustments to the requirements for 

demonstrating compliance, testing, 

reporting, and recordkeeping for SO2

and NOX BART for the Domtar 

Ashdown Mill Power Boiler No. 1 and 

for SO2, NOX, and PM BART for Power 

Boiler No. 2. We are also revising the 

definition of boiler-operating-day as it 

applies to Power Boilers No. 1 and 2 

under this FIP. 

We are finalizing SO2 and NOX

controls under reasonable progress for 

Independence Units 1 and 2 (our 

proposed Option 1). In response to 

comments we received during the 

public comment period, we are 

finalizing a bifurcated NOX emission 

limit for Independence Units 1 and 2 

and are requiring the source to comply 

with the NOX emission limit within 18 

months of the effective date of this final 

action instead of the 3-year compliance 

date we proposed. We are also 

providing revised RPGs for Arkansas’ 

Class I areas that reflect anticipated 

visibility conditions at the end of the 

implementation period in 2018 rather 

than the anticipated visibility 

conditions once the FIP has been fully 

implemented. 

These changes to our proposal are 

discussed in more detail in the 

subsections that follow and in our 

separate Response to Comment (RTC) 

document, which can be found in the 

docket for this final rulemaking. The 

final regulatory language for the FIP is 

under Part 52 at the end of this notice. 

The final FIP requires that subject-toBART sources comply with the 

emission limits contained in Table 1 

below and that the Independence Plant 

comply with the emission limits 

contained in Table 2 below. We are 

determining that the BART emission 

limits for the sources listed in Table 1 

are also sufficient for reasonable 

progress. Throughout this section of the 

final rule, we specify the averaging basis 

of each emission limit and associated 

compliance dates. 

TABLE 1—FINAL BART EMISSION LIMITS

Unit Final SO2 emission limit Final NOX emission limit Final PM emission limit 

Bailey Unit 1 ........................ 0.5% limit on sulfur content of fuel combusted.887 lb/hr a .......................... 0.5% limit on sulfur content of fuel combusted. 

McClellan Unit 1 .................. 0.5% limit on sulfur content of fuel combusted.869.1 lb/hr b/705.8 lb/hr b ... 0.5% limit on sulfur content of fuel combusted. 


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Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66339 

29See also 80 FR 18944, 18951, and 18955. 

30 80 FR 18944, 18952, 18956. 

TABLE 1—FINAL BART EMISSION LIMITS—Continued 

Unit Final SO2 emission limit Final NOX emission limit Final PM emission limit 

Flint Creek Unit 1 ................ 0.06 lb/MMBtu ......................................... 0.23 lb/MMBtu ................... EPA approved the state’s BART determination in March 12, 2012 final action (77 FR 14604). 

White Bluff Unit 1 ................ 0.06 lb/MMBtu ......................................... 0.15 lb/MMBtu c/671 lb/hr d EPA approved the state’s BART determination in March 12, 2012 final action (77 FR 14604). 

White Bluff Unit 2 ................ 0.06 lb/MMBtu ......................................... 0.15 lb/MMBtu c/671 lb/hr d EPA approved the state’s BART determination in March 12, 2012 final action (77 FR 14604). 

White Bluff Auxiliary Boiler .. 105.2 lb/hr a ............................................. 32.2 lb/hr a ......................... 4.5 lb/hr a. 

Lake Catherine Unit 4 e ....... EPA approved the state’s BART determination in March 12, 2012 final action (77 FR 14604).0.22 lb/MMBtu ................... EPA approved the state’s BART determination in March 12, 2012 final action (77 FR 14604). 

Domtar Ashdown Mill Power 

Boiler No. 1.

504 lb/day f .............................................. 207.4 lb/hr f ........................ EPA approved the state’s BART determination in March 12, 2012 final action (77 FR 14604). 

Domtar Ashdown Mill Power 

Boiler No. 2.

91.5 lb/hr ................................................. 345 lb/hr ............................ PM BART shall be satisfied by relying on 

the applicable PM standard under 40 

CFR part 63, subpart DDDDD g. 

aExisting emission limit; we do not anticipate that the facility will have to install any additional control to comply with this emission limit. 

bExisting emission limit; we do not anticipate that the facility will have to install any additional control to comply with this emission limit. Emission limit of 869.1 lb/hr applies to the natural gas-firing scenario; emission limit of 705.8 lb/hr applies to the fuel oil-firing scenario. cEmission limit of 0.15 lb/MMBtu applies when unit is operated at 50% or greater of the unit’s maximum heat input rating. 

dEmission limit of 671 lb/hr applies when the unit is operated at less than 50% of the unit’s maximum heat input rating. 

eEmission limit for NOX applies to the natural gas-firing scenario. The unit shall not burn fuel oil until BART determinations for SO2, NOX, and 

PM are promulgated for the unit for the fuel oil-firing scenario through EPA approval of a SIP revision or a FIP. fEmission limit is representative of baseline emissions; we do not anticipate that the facility will have to install any additional control to comply 

with this emission limit. gThe facility shall rely on the applicable PM standard under 40 CFR part 63, subpart DDDDD—National Emission Standards for Hazardous Air 

Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters, as revised, to satisfy the PM BART 

requirement. 

TABLE 2—FINAL REASONABLE PROGRESS EMISSION LIMITS FOR SOURCES NOT SUBJECT TO BART 

Unit Final SO2 emission limit Final NOX emission limit 

Independence Unit 1 ................................................... 0.06 lb/MMBtu ............................... 0.15 lb/MMBtu a/671 lb/hr b. 

Independence Unit 2 ................................................... 0.06 lb/MMBtu ............................... 0.15 lb/MMBtu a/671 lb/hr b. 

aEmission limit of 0.15 lb/MMBtu applies when unit is operated at 50% or greater of the unit’s maximum heat input rating. 

bEmission limit of 671 lb/hr applies when the unit is operated at less than 50% of the unit’s maximum heat input rating. 

A. Regional Haze 

1. Identification of BART-Eligible and 

Subject-to-BART Sources 

We are finalizing our determination 

that the Georgia-Pacific Crossett Mill 6A 

Boiler is a BART-eligible source, but is 

not subject to BART. We are also 

finalizing our determination that the 9A 

Boiler, which the State had previously 

determined is BART-eligible, is not 

subject to BART. These determinations 

are based on the company’s newly 

provided analysis and documentation, 

as described above and in our proposal. 

Therefore, the CAA and Regional Haze 

Rule do not require BART 

determinations for the 6A and 9A 

Boilers. 

2. BART Determinations 

a. AECC Bailey Unit 1 

Bailey Unit 1 burns primarily natural 

gas, but is also permitted to burn fuel 

oil. Our proposal explains why the 

source needs to retain the flexibility to 

use fuel oil. Taking into consideration 

the BART factors, we are finalizing 

BART determinations and emission 

limits for SO2, NOX, and PM as 

proposed. Our final BART 

determination for SO2 and PM is the use 

of fuels with 0.5% or lower sulfur 

content by weight. After the effective 

date of this final rule, the facility shall 

not purchase fuel for use in Unit 1 that 

does not meet this sulfur-content 

requirement. We are allowing the 

facility 5 years to burn its existing 

supply of No. 6 fuel oil in accordance 

with any operating restrictions enforced 

by ADEQ. Providing this time period 

will avoid creating an incentive for the 

source to burn large amounts of this fuel 

during a short period, which could 

affect visibility on individual days more 

adversely. We are requiring the facility 

to comply with the requirement to use 

only fuels with 0.5% or lower sulfur 

content by weight no later than 5 years 

from the effective date of this final rule. 

We discussed in detail in our proposal 

the cost effectiveness and projected 

visibility improvement of switching 

from the baseline fuel to fuels with a 

sulfur content by weight of 0.5% or 

lower, and also present this information 

in Tables 3 and 4.29 We are not making 

changes to the analysis we presented in 

our proposal of the cost and visibility 

improvement of this control measure. 

As discussed in our proposal, the cost 

of switching from the baseline fuel to 

fuels with a sulfur content by weight of 

0.5% or lower is within the range of 

what we consider to be cost effective for 

BART and it is projected to result in 

considerable visibility improvement at 

the affected Class I areas.30 We are 

finalizing this BART determination for 

SO2 and PM as proposed. 


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66340 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

31See also 80 FR 18944, 18958, 18959, and 

18962. 32 80 FR 18944, 18959, 18962. 

TABLE 3—AECC BAILEY UNIT 1— 

COST EFFECTIVENESS OF SWITCHING TO FUEL WITH SULFUR CONTENT OF 0.5% OR LOWER

Pollutant 

No. 6 Fuel 

oil—0.5% sulfur 

content 

($/ton) 

SO2 ....................................... 2,559 

TABLE 3—AECC BAILEY UNIT 1— 

COST EFFECTIVENESS OF SWITCHING TO FUEL WITH SULFUR CONTENT OF 0.5% OR LOWER—Continued 

Pollutant 

No. 6 Fuel 

oil—0.5% sulfur 

content 

($/ton) 

PM ........................................ 2,997 

TABLE 4—AECC BAILEY UNIT 1—SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT OF

SWITCHING TO FUEL WITH SULFUR CONTENT OF 0.5% OR LOWER

Class I area 

Baseline 

visibility impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv)—reflects 

improvement 

from SO2 and 

PM reductions 

No. 6 Fuel 

oil—0.5% sulfur content 

Caney Creek ............................................................................................................................................................ 0.330 0.188 

Upper Buffalo ........................................................................................................................................................... 0.348 0.221 

Hercules-Glades ...................................................................................................................................................... 0.368 0.233 

Mingo ....................................................................................................................................................................... 0.379 0.209 

Cumulative Visibility Improvement (Ddv) ................................................................................................................. ........................ 0.851 

Our final BART determination for 

NOX is an emission limit of 887 lb/hr, 

which is the existing emission limit and 

does not necessitate the installation of 

additional controls. The source must 

comply with the NOX emission limit for 

BART purposes as of the effective date 

of this final rule. 

b. AECC McClellan Unit 1 

AECC McClellan Unit 1 burns 

primarily natural gas, but is also 

permitted to burn fuel oil. Our proposal 

explains why the source needs to retain 

the flexibility to use fuel oil. Taking into 

consideration the BART factors, we are 

finalizing BART determinations and 

emission limits for SO2, NOX, and PM 

as proposed. Our final BART 

determination for SO2 and PM is the use 

of fuels with 0.5% or lower sulfur 

content by weight. After the effective 

date of this final rule, the facility shall 

not purchase fuel for use in Unit 1 that 

does not meet this sulfur content 

requirement. We are allowing the 

facility 5 years to burn its existing 

supply of No. 6 fuel oil, in accordance 

with any operating restrictions enforced 

by ADEQ. We are requiring the facility 

to comply with the requirement to use 

only fuels with 0.5% or lower sulfur 

content by weight no later than 5 years 

from the effective date of this final rule. 

Providing this time period will avoid 

creating an incentive for the source to 

burn large amounts of this fuel during 

a short period, which could affect 

visibility on individual days more 

adversely. We discussed in detail in our 

proposal the cost effectiveness and 

projected visibility improvement of 

switching from the baseline fuel to fuels 

with a sulfur content by weight of 0.5% 

or lower, and also present this 

information in Tables 5 and 6.31 We are 

not making changes to the analysis we 

presented in our proposal of the cost 

and visibility improvement of this 

control measure. As discussed in our 

proposal, the cost of switching from the 

baseline fuel to fuels with a sulfur 

content by weight of 0.5% or lower is 

within the range of what we consider to 

be cost effective for BART and it is 

projected to result in considerable 

visibility improvement at the affected 

Class I areas.32 We are finalizing this 

BART determination for SO2 and PM as 

proposed. 

TABLE 5—AECC MCCLELLAN UNIT

1—COST EFFECTIVENESS OF

SWITCHING TO FUEL WITH SULFUR

CONTENT OF 0.5% OR LOWER

Pollutant 

No. 6 Fuel 

oil—0.5% sulfur 

content 

($/ton) 

SO2 ....................................... 3,823 

PM ........................................ 4,553 


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33 80 FR 18944, 18966. 

34 80 FR 18944, 18967. 

35See the Arkansas PSC Web site at http://

www.apscservices.info/efilings/docket_search.asp. 

The quarterly reports the company is required to 

submit to the Arkansas PSC are available by 

searching for docket No. 12–008–U. 

36See file titled ‘‘Record of Call—Flint Creek_

August 10 2016,’’ which is found in the docket for 

this rulemaking. 

TABLE 6—AECC MCCLELLAN UNIT 1—SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT OF

SWITCHING TO FUEL WITH SULFUR CONTENT OF 0.5% OR LOWER

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

Visibility improvement 

from baseline 

(Ddv)—reflects 

improvement 

from SO2 and 

PM reductions 

No. 6 Fuel 

oil—0.5% 

sulfur content 

Caney Creek ............................................................................................................................................................ 0.622 0.3 

Upper Buffalo ........................................................................................................................................................... 0.266 0.12 

Hercules-Glades ...................................................................................................................................................... 0.231 0.116 

Mingo ....................................................................................................................................................................... 0.228 0.092 

Cumulative Visibility Improvement (Ddv) ................................................................................................................. ........................ 0.628 

Our final BART determination for 

NOX is an emission limit of 869.1 lb/hr 

for natural gas firing and 705.8 lb/hr for 

fuel oil firing, which are the existing 

emission limits and do not necessitate 

the installation of additional controls. 

The source must comply with the NOX

emission limits for BART purposes as of 

the effective date of the final rule. 

c. AEP Flint Creek Unit 1 

Taking into consideration the BART 

factors, we are finalizing our 

determination that BART for SO2 is an 

emission limit of 0.06 lb/MMBtu on a 30 

boiler-operating-day rolling average, 

which is consistent with the installation 

and operation of NID technology (a type 

of dry scrubbing system). As discussed 

in detail in our RTC document, we are 

not making changes to the analysis we 

presented in our proposal of the cost 

and visibility improvement of this 

control measure. We discussed in our 

proposal that the cost of NID on Flint 

Creek Unit 1 is estimated to be $3,845/ 

SO2 ton removed, which is within the 

range of what we consider to be cost 

effective for BART, and it is projected to 

result in considerable visibility 

improvement at the affected Class I 

areas (see Table 7).33 Therefore, we are 

finalizing this SO2 BART emission limit 

as proposed. 

TABLE 7—AEP FLINT CREEK UNIT 1—SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT OF

NID TECHNOLOGY

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ............................................................................................................................................................ 0.963 0.615 

Upper Buffalo ........................................................................................................................................................... 0.965 0.464 

Hercules-Glades ...................................................................................................................................................... 0.657 0.345 

Mingo ....................................................................................................................................................................... 0.631 0.414 

Cumulative Visibility Improvement (Ddv) ................................................................................................................. ........................ 1.838 

In our proposal, we stated that we 

believed that the maximum compliance 

time of 5 years allowed under the CAA 

and Regional Haze Rule was appropriate 

for a new scrubber retrofit and proposed 

to require the source to comply with 

this emission limit no later than 5 years 

from the effective date of the final 

rule.34 We received comments during 

the public comment period that brought 

to our attention that the Arkansas Public 

Service Commission (PSC) has 

determined that dry scrubber 

installation at Flint Creek is in the 

public interest and that the installation 

of NID controls is already underway and 

anticipated by the company to be 

completed by May 29, 2016. The 

Arkansas PSC requires Flint Creek to 

provide quarterly reports on the 

progress of the installation of these 

controls, which are publicly available 

online on the Arkansas PSC Web site.35

The first quarterly report submitted by 

the company to the Arkansas PSC is 

dated March 26, 2014, and stated that 

the FGD project includes the installation 

of an Alstom NID system to comply 

with the Mercury and Air Toxics 

Standards (MATS) Rule and in 

anticipation of the BART requirements. 

The report also stated that the company 

established design, procurement, and 

construction schedules to bring the 

upgraded plant fully on line by May 29, 

2016. The most recent quarterly report 

available on the Arkansas PSC Web site 

is dated March 10, 2016, and covers the 

fourth quarter in 2015. This report 

indicated that the company still 

expected that the upgraded plant would 

be fully on line by May 29, 2016. We 

verified the status of the installation of 

the controls with the company, who 

confirmed that installation of the NID 

controls was completed in June 2016, 

and that the plant is now operating with 

those controls.36 We proposed a 5-year 

compliance date without knowing that 

installation of these controls was well 

underway. After carefully considering 


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66342 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

37CAA section 169A(b)(2)(A). 

38The shorter compliance timeframe we are 

finalizing is a logical outgrowth of our proposal 

based on the comments received, which are 

discussed in more detail elsewhere in the final rule 

and our RTC document. See Int’l Union, UMW, 407 

F.3d at 1259; Fertilizer Inst., 935 F.2d at 1311; 

Chocolate Mfrs. Ass’n, 755 F.2d 1098. 

39These five EGUs are White Bluff Units 1 and 

2, Independence Units 1 and 2, and Flint Creek 

Unit 1. 

the comments we received, we have 

determined that a 5-year compliance 

date is not appropriate because the CAA 

requires that sources comply with BART 

as expeditiously as practicable.37

Therefore, we are finalizing a shorter 

compliance date.38 The information that 

has been made available to us during 

the comment period indicates that Flint 

Creek intends to operate the NID system 

to comply with the alternative SO2

emission limit under the Utility MATS 

rule. The applicable MATS SO2

emission limit is 0.2 lb/MMBtu. The 

SO2 emission limit we are requiring in 

our FIP to satisfy the SO2 BART 

requirement is 0.06 lb/MMBtu. The 

comments and documentation 

submitted to us indicate that the 

company intends to use the same NID 

system to comply with MATS and the 

SO2 BART requirement. We expect that 

in order to achieve an emission rate of 

0.06 lb/MMBtu, additional scrubbing 

reagent would be needed beyond that 

required to meet the 0.2 lb/MMBtu 

emission limit the company was 

required to meet by April 2016 under 

MATS. We also recognize that it is 

possible that the reagent handling 

system installed to meet the 0.2 lb/

MMBtu emission limit would need 

some upgrades in order to accommodate 

the additional scrubbing reagent that 

would be needed to achieve the more 

stringent 0.06 lb/MMBtu emission limit 

we are requiring in this FIP. Therefore, 

to allow the facility sufficient time to 

secure the additional scrubbing reagent 

that would be needed to comply with 

the SO2 BART emission limit and to 

make any necessary upgrades to the 

reagent handling system, we are 

finalizing an 18-month compliance date 

for Flint Creek Unit 1 to comply with 

the SO2 BART requirement. We believe 

that this will provide sufficient time for 

the facility to be able to achieve the SO2

BART requirement while still meeting 

the statutory mandate that BART 

controls be installed and operated as 

expeditiously as practicable. 

Taking into consideration the BART 

factors, we are finalizing our 

determination that BART for NOX is an 

emission limit of 0.23 lb/MMBtu on a 30 

boiler-operating-day rolling average, 

which is consistent with the installation 

and operation of new LNB/OFA. In 

response to comments we received on 

our initial cost analysis presented in our 

proposal, we have revised our cost 

estimate for LNB/OFA for AEP Flint 

Creek Unit 1. Based on this revision to 

our cost analysis, we find that LNB/OFA 

is estimated to cost $1,258/NOX ton 

removed, which is even more cost 

effective (lower $/ton) than we 

estimated in our proposal. LNB/OFA is 

also projected to result in considerable 

visibility improvement at the affected 

Class I areas (see Table 8). As we 

discuss in our RTC document, after 

revising our cost analysis of NOX

controls for AEP Flint Creek, we find 

that the additional cost of more 

stringent controls such as SNCR and 

SCR is not justified by the incremental 

visibility benefits of the more stringent 

controls. Therefore, we are finalizing the 

NOX BART emission limit as proposed, 

consistent with installation of LNB/OFA 

controls. 

TABLE 8—AEP FLINT CREEK UNIT 1—SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT OF

LNB/OFA 

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ............................................................................................................................................................ 0.963 0.081 

Upper Buffalo ........................................................................................................................................................... 0.965 0.026 

Hercules-Glades ...................................................................................................................................................... 0.657 0.024 

Mingo ....................................................................................................................................................................... 0.631 0.014 

Cumulative Visibility Improvement (Ddv) ................................................................................................................. ........................ 0.145 

We received comments from the 

company requesting that we extend our 

proposed 3-year compliance date for the 

NOX BART requirement to 5 years to 

allow sufficient time for planning, 

selection of engineering and design 

professionals, vendors, contractors, 

permitting, start up and commissioning, 

and coordinating and scheduling unit 

outages. We also received comments 

from an environmental group stating 

that we should shorten the compliance 

date because the typical installation 

timeframe for low NOX burners is 6–8 

months from bid evaluation through 

startup of the technology. The 

environmental group also indicated that 

the company may have already started 

the process of installing LNB/OFA 

controls in anticipation of the BART 

requirement. We do not have 

information corroborating that the 

installation of these controls is already 

underway, but we agree with the 

environmental group that LNB/OFA can 

be installed within a 6–8 month 

timeframe. The company did not 

provide specific information to support 

its contention that a longer compliance 

date that extends beyond the 6–8 month 

typical installation timeframe for LNB/ 

OFA, measured from bid evaluation, is 

needed for AEP Flint Creek. Although 

we agree that 6–8 months is the typical 

installation timeframe for LNB/OFA 

controls, in determining the appropriate 

compliance date we have also taken into 

consideration that we are finalizing NOX

emission limits that are based on LNB/ 

OFA or LNB/SOFA controls for a total 

of five EGUs in this FIP and that the 

installation of these controls will 

require outage time. These five EGUs 

combined accounted for approximately 

45% of the state’s 2015 heat input.39

Because of the heavy reliance on these 

EGUs for electricity generation in the 

state, we recognize that it may be 

difficult to schedule outage time to 

install LNB/OFA or LNB/SOFA on all 

five of these units within the typical 

installation timeframe of 6–8 months 

and at the same time supply adequate 

electricity to meet demand in the state. 

As we discuss in section V.F. of this 

final rule, in light of these unique 

circumstances, we believe that it is 

appropriate to finalize an 18-month 

compliance date for these EGUs to 

comply with the NOX emission limits 

required by this FIP. This compliance 

date provides the affected utilities 

considerable time beyond typical LNB/ 


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40https://www3.epa.gov/airtransport/CSAPR/

pdfs/CSAPR_SO2_Remand_Memo.pdf. 

41See also 80 FR 18944, 18972. 

OFA installation timeframes to install 

these controls and comply with their 

NOX emission limits. 

Several commenters submitted 

comments stating that Arkansas is 

subject to the Cross State Air Pollution 

Rule (CSAPR) for ozone season NOX, so 

we should rely on CSAPR to satisfy the 

NOX BART requirement instead of 

promulgating source-specific NOX

BART determinations. In the same way 

that a state subject to CSAPR for ozone 

season NOX has the discretion to decide 

whether to conduct source-specific 

BART determinations for NOX or to rely 

on EPA’s 2012 finding that CSAPR is 

better than BART, EPA has the same 

discretion in promulgating a FIP. Our 

decision to propose source-specific NOX

BART determinations for Arkansas was 

reasonable for multiple reasons: It is the 

approach Congress chose in the statute 

itself; it is consistent with Arkansas’ 

earlier decision to conduct sourcespecific BART determinations in lieu of 

relying on the Clean Air Interstate Rule 

(CAIR) to meet the BART requirements; 

and at the time of our proposed action, 

it properly accounted for uncertainty in 

the CSAPR better-than-BART regulation 

created by ongoing litigation regarding 

the CSAPR program. Further, 

subsequent to our proposal, the D.C 

Circuit Court issued a July 2015 

decision upholding CSAPR but 

remanding without vacatur a number of 

the Rule’s state NOX and SO2 emissions 

budgets. Arkansas’ ozone season NOX

budget is not itself affected by the 

remand. However, the Court’s remand of 

the affected states’ emissions budgets 

has implications for CSAPR better-than 

BART, since the demonstration 

underlying that rulemaking relied on 

the emission budgets of all states subject 

to CSAPR, including those that the D.C. 

Circuit remanded, to establish that 

CSAPR provides for greater reasonable 

progress than BART. As of the time EPA 

is taking this action to finalize Arkansas’ 

Regional Haze FIP, we are in the process 

of acting on the Court’s remand 

consistent with the planned response 

we outlined in a June 2016 

memorandum.40 For these reasons, 

which we discuss in more detail in our 

RTC document, we are finalizing 

source-specific NOX BART 

determinations for AEP Flint Creek Unit 

1 and other Arkansas EGUs subject to 

BART. As we have noted throughout 

this document, we are willing to work 

with ADEQ to develop a SIP revision 

that could replace our FIP. Such a SIP 

revision will need to meet the CAA and 

EPA’s Regional Haze regulations. In its 

SIP revision, ADEQ may elect to rely on 

CSAPR to satisfy the NOX BART 

requirements for Arkansas’ EGUs 

instead of doing source-specific NOX

BART determinations. Such an 

approach could be appropriate if, as we 

expect, the uncertainty created by the 

D.C. Circuit’s remand of the affected 

states’ emission budgets will shortly be 

resolved. 

d. White Bluff Units 1 and 2 

Taking into consideration the BART 

factors, we are finalizing our 

determination that BART for SO2 for 

White Bluff Units 1 and 2 is an emission 

limit of 0.06 lb/MMBtu on a 30 boileroperating-day rolling average, consistent 

with the installation and operation of 

dry FGD or another control technology 

that achieves that level of control. We 

are requiring the source to comply with 

this emission limit no later than 5 years 

from the effective date of the final rule. 

In response to comments we received on 

our initial cost analysis presented in our 

proposal, we have revised our cost 

estimate for dry FGD for White Bluff 

Units 1 and 2. Based on this revision to 

our cost analysis, we find that dry FGD 

is estimated to cost $2,565/SO2 ton 

removed at Unit 1 and $2,421/SO2 ton 

removed at Unit 2. Although these cost 

estimates are slightly higher than we 

estimated in our proposal, we continue 

to find these controls to be cost effective 

and would result in considerable 

visibility improvement (see Table 9).41

Therefore, we are finalizing the SO2

BART emission limit as proposed. 

TABLE 9—ENTERGY WHITE BLUFF UNITS 1 AND 2—SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND

IMPROVEMENT OF DRY FGD 

Class I area 

White Bluff Unit 1 White Bluff Unit 2 

Baseline 

visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Baseline 

visibility impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek .................................................................................................... 1.628 0.813 1.695 0.754 

Upper Buffalo ................................................................................................... 1.140 0.762 1.185 0.767 

Hercules-Glades .............................................................................................. 1.041 0.683 1.061 0.645 

Mingo ............................................................................................................... 0.887 0.620 0.903 0.593 

Cumulative Visibility Improvement (Ddv) ......................................................... ........................ 2.878 ........................ 2.759 

Several commenters requested that we 

rely on CSAPR to satisfy the NOX BART 

requirement for Arkansas EGUs in our 

final FIP. We discuss in section V.H. of 

this final rule that we have concluded 

for a number of reasons that it would 

not be appropriate to rely on CSAPR as 

an alternative to NOX BART for EGUs in 

Arkansas at this time. Therefore, we are 

finalizing source-specific NOX BART 

determinations for all Arkansas EGUs, 

including White Bluff Units 1 and 2. We 

proposed that BART for NOX for Units 

1 and 2 is an emission limit of 0.15 lb/ 

MMBtu on a 30 boiler-operating-day 

rolling average, consistent with the 

installation and operation of LNB/

SOFA. We received comments from the 

company stating that White Bluff Units 

1 and 2 are no longer expected to be 

able to consistently meet our proposed 

NOX emission limit of 0.15 lb/MMBtu 

over a 30-boiler-operating-day period 

based on LNB/SOFA controls. We have 

determined that the company has 

provided sufficient information to 

substantiate that the units are not 

expected to be able to meet our 

proposed NOX emission limit of 0.15 lb/ 

MMBtu when the units are primarily 

operated at less than 50% of their 

operating capacity. In particular, LNB/

SOFA is expected to achieve optimal 

NOX control when the boiler is operated 

from 50–100% steam flow because the 

heat input across this range is sufficient 

to safely redirect a substantial portion of 

combustion air through the overfire air 

registers. This allows the combustion 


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42A final rule is a logical outgrowth of the 

proposed rule ‘‘if interested parties should have 

anticipated that the change was possible, and thus 

reasonably should have filed their comments on the 

subject during the notice-and-comment period.’’ 

Int’l Union,UMW v. MSHA, 407 F.3d 1250, 1259 

(D.C. Cir. 2005) (internal quotations omitted); see 

also, Fertilizer Inst. v. EPA, 935 F.2d 1303, 1311 

(D.C. Cir. 1991). No additional notice or 

opportunity to comment is necessary where, as 

here, the final rule is ‘‘in character with the original 

scheme,’’ and does not ‘‘substantially depart [] from 

the terms or substance’’ of the proposal. Chocolate 

Mfrs. Ass’n v. Block, 755 F.2d 1098 (4th Cir. 1985). 

43Our cost analysis and visibility modeling 

analysis for LNB/SOFA for White Bluff Units 1 and 

2, as presented in our proposal, is based on an 

emission limit of 0.15 lb/MMBtu on a 30 boileroperating-day rolling average. As discussed in this 

final action, we received new information from 

Entergy that indicates that the source expects to be 

operating at less than 50% load more frequently 

and therefore no longer expects to be able to meet 

our proposed NOX emission limit. We are therefore 

finalizing the bifurcated NOX emission limit 

described in this final action. We recognize that the 

comments submitted by Entergy indicate that some 

of the assumptions used to calculate the cost 

effectiveness of NOX controls for White Bluff may 

not exactly apply to future operations. However, 

because we found LNB/SOFA controls to be very 

cost effective, we expect that even if the change in 

operation of the source were known more precisely 

and were taken into account in our calculation of 

the cost ($/ton), these controls would continue to 

be cost effective. Therefore, we are not revising our 

cost effectiveness calculations or visibility 

improvement modeling of LNB/SOFA for White 

Bluff Units 1 and 2. 

44 80 FR at 18972. 

zone airflow to be sub-stoichiometric 

and oxygen to be reduced to the point 

where much of the elemental nitrogen 

in the fuel and combustion air can pass 

through the boiler without converting to 

NOX. When a boiler is operated below 

the 50–100% capacity range, NOX

concentrations on a lb/MMBtu basis can 

be elevated due to the lower heat input 

rating, even though the pounds of NOX

emitted per hour are less due to the 

reduced amount of fuel and air. In light 

of the information provided by the 

company, we are finalizing a bifurcated 

NOX emission limit for each unit, where 

our proposed 0.15 lb/MMBtu emission 

limit will address emissions when the 

unit is operated at high capacities and 

a mass-based emission limit will 

address emissions when the unit is 

operated at low capacities. The 

bifurcated emission limits we are 

finalizing are a logical outgrowth of our 

proposal based on the company’s 

comments, which are discussed in more 

detail elsewhere in the final rule and 

our RTC document.42

We are requiring White Bluff Units 1 

and 2 to each meet a NOX emission limit 

of 0.15 lb/MMBtu on a 30 boileroperating-day rolling average, where the 

average is to be calculated by including 

only the hours during which the unit 

was dispatched at 50% or greater of 

maximum capacity. In this particular 

case, the 30 boiler-operating-day rolling 

average is to be calculated for each unit 

by the following procedure: (1) 

Summing the total pounds of NOX

emitted during the current boileroperating day and the preceding 29 

boiler-operating days, including only 

emissions during hours when the unit 

was dispatched at 50% or greater of 

maximum capacity; (2) summing the 

total heat input in MMBtu to the unit 

during the current boiler-operating day 

and the preceding 29 boiler-operating 

days, including only the heat input 

during hours when the unit was 

dispatched at 50% or greater of 

maximum capacity; and (3) dividing the 

total pounds of NOX emitted as 

calculated in step 1 by the total heat 

input to the unit as calculated in step 2. 

In addition to the 0.15 lb/MMBtu 

emission limit that is intended to 

control NOX emissions when the units 

are operated at 50% or greater of 

maximum capacity, we are establishing 

a limit in lb/hr that applies when the 

units are operated at lower capacity. 

The company suggested an emission 

limit of 1,342.5 lb/hr on a 30 boileroperating-day rolling average applicable 

at all times regardless of the capacity at 

which the unit is operated. Based on the 

information available to us, we find that 

an emission limit of 1,342.5 lb/hr is too 

high to appropriately control NOX

emissions when the units are operated 

at low capacities. It appears that the 

company calculated the emission limit 

by multiplying the 0.15 lb/MMBtu limit 

by the maximum heat input rating for 

each unit (8,950 MMBtu/hr), which 

yielded 1,342.5 lb/hr. We find that an 

emission limit of 1,342.5 lb/hr would be 

appropriate when the unit is operated at 

high capacities considering that the 

limit was calculated based on the unit’s 

maximum heat input rating. However, 

such an emission limit would not be 

sufficiently protective or appropriate 

when the unit is operated at lower 

capacities since the mass of NOX

emitted is expected to be lower 

compared to operation at high capacity. 

To address this concern, we calculated 

a new emission limit of 671 lb/hr that 

is based on 50% of the unit’s maximum 

heat input rating, and is applicable only 

when the unit is being operated at less 

than 50% of maximum heat input 

rating. We calculated this limit by 

multiplying 0.15 lb/MMBtu by 50% of 

the maximum heat input rating for each 

unit (i.e., 50% of 8,950 MMBtu/hr, or 

4,475 MMBtu/hr). This emission limit is 

on a rolling 3-hour average, where the 

average is to be calculated by including 

emissions only for the hours during 

which the unit was dispatched at less 

than 50% of maximum capacity (i.e., 

hours when the heat input to the unit 

is less than 4,475 MMBtu). We are not 

establishing a lb/hr emission limit that 

applies when the units are operated at 

50% or greater of maximum heat input 

rating because the 0.15 lb/MMBtu 

emission limit will address NOX

emission during those operating 

conditions. We discussed in our 

proposal that the cost of LNB/SOFA on 

White Bluff Units 1 and 2 is estimated 

to be $350/NOX ton removed for Unit 1 

and $340/NOX ton removed for Unit 2,43

which we consider to be very cost 

effective, and it would also result in 

considerable visibility improvement at 

the affected Class I areas (see Table 

10).44 Therefore, we are finalizing the 

NOX BART emission limits as described 

above. 

As discussed in section V.F. of this 

final rule, in response to comments we 

received, we are shortening the 

compliance date for the NOX BART 

requirement for White Bluff Units 1 and 

2 from our proposed 3 years to 18 

months. 

TABLE 10—ENTERGY WHITE BLUFF UNITS 1 AND 2—SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND

IMPROVEMENT OF LNB/SOFA 

Class I area 

White Bluff Unit 1 White Bluff Unit 2 

Baseline 

visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Baseline 

visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek .................................................................................................... 1.628 0.166 1.695 0.225 

Upper Buffalo ................................................................................................... 1.140 0.101 1.185 0.139 


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45As described in section I. of this notice, Entergy 

also submitted a comment after the close of the 

comment period, indicating that Entergy intends 

that a second alternative described in the late 

comment, involving only White Bluff, is a 

replacement for the multi-unit alternative 

previously described in its timely comments. 

Because the late comment is not a basis for our 

decision making in this final rule, we are 

responding in this final rule and in our RTC 

document to the alternative proposal described in 

the comments that Entergy filed during the 

comment period. 

46 80 FR 18944, 18978. 

TABLE 10—ENTERGY WHITE BLUFF UNITS 1 AND 2—SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND

IMPROVEMENT OF LNB/SOFA—Continued 

Class I area 

White Bluff Unit 1 White Bluff Unit 2 

Baseline 

visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Baseline 

visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Hercules-Glades .............................................................................................. 1.041 0.176 1.060 0.190 

Mingo ............................................................................................................... 0.887 0.038 0.903 0.047 

Cumulative Visibility Improvement (Ddv) ......................................................... ........................ 0.481 ........................ 0.601 

In our proposal, we also solicited 

public comment on any alternative SO2

and NOX control measures that could 

address the regional haze requirements 

for Entergy White Bluff Units 1 and 2 

and Entergy Independence Units 1 and 

2 for this planning period. We received 

comments from the company during the 

public comment period that proposed 

one alternative strategy,45 but we 

determined that this alternative strategy 

would not adequately address the BART 

and reasonable progress requirements 

for the affected units. We discuss this 

issue in more detail elsewhere in this 

final rule and in our RTC document. 

e. White Bluff Auxiliary Boiler 

We are finalizing our determination 

that the existing emission limit of 105.2 

lb/hr is BART for SO2, the existing 

emission limit of 32.2 lb/hr is BART for 

NOX, and the existing emission limit of 

4.5 lb/hr is BART for PM for the 

Auxiliary Boiler. We do not expect these 

emission limits to require the 

installation of additional controls. We 

are requiring the White Bluff Auxiliary 

Boiler to comply with these emission 

limits as of the effective date of this 

final rule. 

f. Entergy Lake Catherine Unit 4 

Taking into consideration the BART 

factors, we are finalizing our 

determination that BART for NOX for 

the natural gas-firing scenario is an 

emission limit of 0.22 lb/MMBtu on a 30 

boiler-operating-day rolling average, 

consistent with the installation and 

operation of BOOS. As discussed in 

more detail in our RTC document, we 

are not making changes to the analysis 

presented in our proposal of the cost 

and visibility improvement of this 

control measure. We discussed in our 

proposal that the cost of BOOS on Lake 

Catherine Unit 4 is estimated to be 

$138/NOX ton removed, which we 

consider to be very cost effective, and it 

is also projected to result in 

considerable visibility improvement at 

the affected Class I areas (see Table 

11).46 Therefore, we are finalizing the 

NOX BART emission limit as proposed. 

We are requiring the source to comply 

with this emission limit no later than 3 

years from the effective date of this final 

rule. 

TABLE 11—ENTERGY LAKE CATHERINE UNIT 4—SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND

IMPROVEMENT OF BOOS 

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ............................................................................................................................................................ 1.371 0.596 

Upper Buffalo ........................................................................................................................................................... 0.532 0.248 

Hercules-Glades ...................................................................................................................................................... 0.387 0.175 

Mingo ....................................................................................................................................................................... 0.429 0.196 

Cumulative Visibility Improvement (Ddv) ................................................................................................................. ........................ 1.215 

We are also finalizing our 

determination that Lake Catherine Unit 

4 shall not burn any fuel oil unless or 

until Arkansas submits a SIP revision 

that contains BART determinations for 

SO2, NOX, and PM for the fuel oil-firing 

scenario for Unit 4 and we approve 

these BART determinations into the SIP 

or we promulgate such BART 

determinations in a FIP. We are 

finalizing this determination in light of 

the fact that Unit 4 has not combusted 

any fuel oil in over 10 years and the 

company’s commitment to not burn any 

fuel oil at Unit 4 until Arkansas submits 

the SIP revision described above. 

g. Domtar Ashdown Mill Power Boiler 

No. 1 

In response to comments received 

from the company, we are finalizing an 

SO2 BART emission limit in the form of 

lb/day instead of lb/hr for Power Boiler 

No. 1. Specifically, we are finalizing an 

SO2 BART emission limit of 504 lb/day 

averaged over a rolling 30 boileroperating-day period instead of the 

proposed emission limit of 21.0 lb/hr 

averaged over a rolling 30 boileroperating-day period. According to the 

company, the calculation of hourly SO2

emissions using hourly fuel throughput 

information is not a workable approach 

for Power Boiler No. 1, where the 

practice is to use monthly fuel 

throughput information that is 

reconciled at the end of each month to 

determine monthly fuel usage. The 

company believes an emission limit in 

terms of lb/day is better suited to the 

mill’s methodology for determining fuel 

usage at Power Boiler No. 1. We agree 


asabaliauskas on DSK3SPTVN1PROD with RULES
66346 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

47The lb/day emission limit we are finalizing is 

a logical outgrowth of our proposal based on the 

company’s comments, which are discussed in more 

detail elsewhere in the final rule and our RTC 

document. See Int’l Union, UMW, 407 F.3d at 1259; 

Fertilizer Inst., 935 F.2d at 1311; Chocolate Mfrs. 

Ass’n, 755 F.2d 1098. 

48The curve equation is Y = 0.4005 * X¥0.2645, 

where Y = pounds of sulfur emitted per ton dry fuel 

feed to the boiler and X = pounds of sulfur input 

per ton of dry bark. The purpose of this equation 

is to factor in the degree of SO2 scrubbing provided 

by the combustion of bark. 

49The alternative methods for demonstrating 

compliance we are finalizing for Power Boiler No. 

1 are a logical outgrowth of our proposal based on 

the company’s comments, which are discussed in 

more detail elsewhere in the final rule and our RTC 

document. See Int’l Union,UMW, 407 F.3d at 1259; 

Fertilizer Inst., 935 F.2d at 1311; Chocolate Mfrs. 

Ass’n, 755 F.2d 1098. 

50The revised definition of ‘‘boiler operating 

day’’ as it applies to these two units is a logical 

outgrowth of our proposal based on the company’s 

comments, which are discussed in more detail 

elsewhere in the final rule and our RTC document. 

See Int’l Union,UMW, 407 F.3d at 1259; Fertilizer 

Inst. v. EPA, 935 F.2d at 1311; and Chocolate Mfrs. 

Ass’n, 755 F.2d 1098. 

with the company and are finalizing an 

SO2 BART emission limit of 504 lb/day 

averaged over a rolling 30 boileroperating-day period. This emission 

limit is consistent with the Power 

Boiler’s baseline emissions and would 

not necessitate additional controls.47

We are also finalizing our determination 

that the mill must demonstrate 

compliance with the SO2 BART 

emission limit by using a site-specific 

curve equation (provided to us by the 

facility) to calculate SO2 emissions from 

Power Boiler No. 1 when combusting 

bark, and that the mill must confirm the 

accuracy of the site-specific curve 

equation using stack testing.48 Further, 

we are finalizing our determination that 

for purposes of demonstrating 

compliance with the emission limit for 

BART for SO2 when combusting fuel oil, 

the mill shall assume that the SO2 inlet 

is equal to the SO2 being emitted at the 

stack, where SO2 inlet is defined to be 

the SO2 content of the fuel delivered to 

the fuel inlet of the combustion 

chamber. 

We are finalizing a NOX BART 

emission limit of 207.4 lb/hr for Power 

Boiler No. 1 as proposed. This emission 

limit is consistent with the Power 

Boiler’s baseline emissions, and we 

expect that compliance with this 

emission limit will not necessitate the 

installation of additional controls. In 

response to comments we received from 

the company, we are revising our 

proposed method for demonstrating 

compliance with the NOX BART 

emission limit. We proposed that, to 

demonstrate compliance with the NOX

BART emission limit, the facility must 

conduct annual stack testing. The 

company submitted comments stating 

that it generally agreed that stack testing 

was an appropriate method for 

demonstrating compliance, but it 

disagreed that our proposed frequency 

of an annual stack testing was 

appropriate. The company noted that 

historical NOX stack test data from 

2001–2005 and 2010 for Power Boiler 1 

showed the NOX emissions were fairly 

consistent. After carefully considering 

the company’s comments, we agree that 

the results of these previous stack tests 

demonstrate that an annual stack test is 

not warranted. Therefore, we are 

finalizing a requirement that the facility 

demonstrate compliance with the NOX

BART emission limit for Power Boiler 

No. 1 by conducting stack testing once 

every 5 years, beginning no later than 1 

year from the effective date of our final 

action. 

In response to comments we received 

from the company, we are finalizing one 

alternative method for demonstrating 

compliance with the SO2 and NOX

BART emission limits for Power Boiler 

No. 1. The company submitted 

comments stating that it may decide in 

the near future to convert Power Boiler 

No. 1 to burn only natural gas. After 

carefully considering the company’s 

comments, we are making the 

determination that if the company 

makes the decision to convert Power 

Boiler No. 1 to burn only pipeline 

quality natural gas and its 

preconstruction air permit is revised to 

reflect that Power Boiler No. 1 is 

permitted to burn only pipeline quality 

natural gas, the company will have 

demonstrated that the boiler is 

complying with the SO2 BART emission 

limit. Once the air permit is revised to 

reflect that Power Boiler No. 1 is 

allowed to burn only pipeline quality 

natural gas, the reporting and 

recordkeeping requirements associated 

with our SO2 BART emission limit 

would no longer be applicable. We find 

this alternative method for 

demonstrating compliance with the SO2

BART emission limit to be appropriate 

given that SO2 emissions due to natural 

gas combustion are negligible. This 

alternative method for compliance 

demonstration will ensure that the 

facility is not unnecessarily burdened 

with calculating SO2 emissions and 

with recordkeeping and reporting 

requirements when SO2 emissions from 

Power Boiler No. 1 are anticipated to be 

negligible. We are also making the 

determination that if the 

preconstruction air permit is revised to 

reflect that Power Boiler No. 1 is 

permitted to burn only pipeline quality 

natural gas, the facility may demonstrate 

compliance with the NOX emission 

limit by calculating NOX emissions 

using AP–42 emission factors and fuel 

usage records. Under this scenario, the 

facility would not be required to 

demonstrate compliance with the NOX

BART emission limit for Power Boiler 

No. 1 through stack testing. We also 

note that after the close of the comment 

period for our proposal, we became 

aware that Power Boiler No. 1 has 

already switched to burn only natural 

gas and that the facility submitted a 

permit renewal application to ADEQ 

that will reflect that the power boiler is 

permitted to burn only natural gas. We 

believe that the alternative methods for 

compliance demonstration we are 

finalizing are appropriate and addresses 

the mill’s concerns.49

In response to comments we received 

from the company, we are revising our 

definition of ‘‘boiler-operating-day’’ as it 

applies to Power Boilers Nos. 1 and 2 

under this FIP. The company 

commented that for mill operation 

purposes, it defines boiler-operating-day 

as ‘‘a 24-hr period between 6 a.m. and 

6 a.m. the following day during which 

any fuel is fed into and/or combusted at 

any time in the power boiler.’’ After 

carefully considering the comment, we 

agree with the company that it is 

reasonable and appropriate to 

harmonize our definition of a boileroperating day with that of the mill to 

avoid any unnecessary modification or 

reprogramming of Power Boilers 1 and 

2. Therefore, for purposes of BART for 

Power Boilers No. 1 and 2, we are 

defining a boiler-operating-day as a 24- 

hour period between 6 a.m. and 6 a.m. 

the following day during which any fuel 

is fed into and/or combusted at any time 

in the power boiler. The 30-day rolling 

average for Power Boiler No. 1 shall be 

determined by adding together the 

pounds of SO2 from that boileroperating-day and the preceding 29 

boiler-operating-days and dividing the 

total pounds of SO2 by the sum of the 

total number of boiler operating days 

(i.e., 30). The result will be the 30 

boiler-operating-day rolling average in 

terms of lb/day emissions of SO2.50

In response to comments we received 

from the company, we are also revising 

our proposed compliance dates for SO2

and NOX BART for Power Boiler No. 1. 

The company submitted comments 

requesting that we finalize a compliance 

date of 30 days after the effective date 

of the final rule instead of requiring the 

source to comply with BART as of the 

effective date of the final rule. The 

company noted this would provide 

additional time for it to prepare 

compliance records. We determined that 

the company’s request is reasonable and 


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51The revised compliance date is a logical 

outgrowth of our proposal based on the company’s 

comments. See Int’l Union,UMW, 407 F.3d at 1259; 

Fertilizer Inst, 935 F.2d at 1311; and Chocolate 

Mfrs. Ass’n, 755 F.2d 1098. 

52 80 FR 18944, 18984. 53 80 FR at 18984. 54The lb/hr emission limits we are finalizing is 

a logical outgrowth of our proposal based on the 

company’s comments, which are discussed in more 

detail elsewhere in the final rule and our RTC 

document. See Int’l Union,UMW, 407 F.3d at 1259; 

Fertilizer Inst, 935 F.2d at 1311; and Chocolate 

Mfrs. Ass’n, 755 F.2d 1098. 

55 80 FR at 18984, 18985. 

would allow the mill to prepare 

applicable compliance records and 

adjust recordkeeping systems without 

unduly delaying compliance with the 

BART emission limits. Therefore, we are 

requiring Power Boiler No. 1 to comply 

with the SO2 and NOX BART emission 

limits no later than 30 days from the 

effective date of this final rule.51

h. Domtar Ashdown Mill Power Boiler 

No. 2 

In response to comments we received 

from the company, we are finalizing an 

emission limit of 91.5 lb/hr based on a 

30 boiler-operating-day rolling average 

instead of 0.11 lb/MMBtu. As discussed 

in our proposal, Domtar provided 

monthly average data for 2011, 2012, 

and 2013 on monitored SO2 emissions 

from Power Boiler No. 2, mass of the 

fuel burned for each fuel type, and the 

percent sulfur content of each fuel type 

burned.52 Based on the information 

provided by Domtar, we found that the 

monthly average SO2 control efficiency 

of the existing venturi scrubbers for the 

2011–2013 period ranged from 57% to 

90%. The information provided also 

indicated that the facility could add 

more scrubbing solution to achieve 

greater SO2 removal than what is 

currently being achieved. We proposed 

that it is feasible for the facility to use 

additional scrubbing solution to 

consistently achieve at least a 90% SO2

removal on a monthly average basis. To 

determine the controlled emission rate 

that corresponds to the operation of the 

existing venturi scrubbers at a 90% 

removal efficiency, we first determined 

the SO2 emission rate that corresponds 

to the operation of the scrubbers at the 

current average control efficiency (i.e., 

baseline control efficiency) of 

approximately 69%. Based on the 

emissions data provided by Domtar, we 

determined that Power Boiler No. 2’s 

annual average SO2 emission rate for the 

years 2011–2013 was 280.9 lb/hr. This 

annual average SO2 emission rate 

corresponds to the operation of the 

scrubbers at a 69% removal efficiency. 

We also estimated that 100% 

uncontrolled emissions would 

correspond to an emission rate of 

approximately 915 lb/hr. Application of 

a 90% control efficiency to the 

uncontrolled rate 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.53 We thus 

proposed that BART for SO2 for Power 

Boiler No. 2 is an emission limit of 0.11 

lb/MMBtu on a 30 boiler-operating-day 

rolling average. 

During the public comment period, 

the company submitted comments 

requesting that we finalize an SO2 BART 

emission limit that is on a lb/hr basis 

instead of lb/MMBtu. The company 

correctly noted that we used the boiler’s 

maximum heat input rating of 820 

MMBtu/hr to determine the proposed 

emission limit in terms of lb/MMBtu. 

The company brought to our attention 

that the use of the maximum heat input 

rating is not representative of typical 

boiler operating conditions, which are 

lower than the maximum heat input 

capability. We have determined that 

finalizing an emission limit in terms of 

lb/hr is appropriate and will address the 

company’s concern.54 Therefore, we are 

finalizing an SO2 emission limit of 91.5 

lb/hr on a 30 boiler-operating-day 

rolling average for Power Boiler No. 2. 

Because the SO2 emission limit we are 

finalizing is based on converting our 

proposed emission limit of 0.11 lb/

MMBtu to an emission limit in the form 

of lb/hr, we find that our final emission 

limit is expected to achieve the same 

level of SO2 reduction as 0.11 lb/

MMBtu, which is what we assumed in 

our analysis of cost and visibility 

improvement. Therefore, we are not 

making changes to the analysis we 

presented in our proposal of the cost 

and visibility improvement of this 

control measure.55 The use of additional 

scrubbing reagent with scrubber pump 

upgrades on the existing venturi 

scrubbers to meet an emission limit of 

91.5 lb/hr is estimated to cost $1,411/

SO2 ton removed, and it is projected to 

result in considerable visibility 

improvement at the affected Class I 

areas (see Table 12). Taking into 

consideration the BART factors, we are 

finalizing this SO2 emission limit. In 

response to comments we received from 

the company, we are also revising our 

definition of ‘‘boiler-operating-day’’ as it 

applies to Power Boilers No. 1 and 2 for 

BART purposes. 

TABLE 12—DOMTAR POWER BOILER NO. 2—SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT

OF USING ADDITIONAL SCRUBBING REAGENT/SCRUBBER PUMP UPGRADES

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

Estimated 

visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ............................................................................................................................................................ 0.844 0.139 

Upper Buffalo ........................................................................................................................................................... 0.146 0.05 

Hercules-Glades ...................................................................................................................................................... 0.105 0.048 

Mingo ....................................................................................................................................................................... 0.065 0.025 

Cumulative Visibility Improvement (Ddv) ................................................................................................................. ........................ 0.262 

We also received comments from 

Domtar expressing uncertainty as to 

whether our proposed SO2 emission 

limit for Power Boiler No. 2 can be met 

by upgrading the scrubber pumps and 

using additional scrubbing solution to 

consistently achieve our proposed SO2

emission limit. However, we have 

determined that aside from expressing 

general uncertainty, Domtar did not 

provide any information that 

demonstrates that it is not technically 

feasible to meet our proposed SO2

emission limit, which is based on a 30 

boiler-operating-day rolling average. We 

also received comments from Domtar 

disagreeing with our use of 2011–2013 

as the baseline years for calculating our 

proposed SO2 emission limit for Power 

Boiler No. 2. Domtar asked that we 

instead use 2001–2003 as the baseline 

period for calculating the SO2 emission 

limit, which would result in an 

emission limit of 155 lb/hr instead of 


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66348 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

56The alternative method to demonstrate 

compliance with the SO2 emission limit is a logical 

outgrowth of our proposal based on the company’s 

comments, which are discussed in more detail 

elsewhere in the final rule and our RTC document. 

See Int’l Union, UMW, 407 F.3d at 1259; Fertilizer 

Inst, 935 F.2d at 1311; and Chocolate Mfrs. Ass’n, 

755 F.2d 1098. 

57 80 FR 18944, 18987. 

91.5 lb/hr. Domtar pointed out that in 

more recent years (after the 2001–2003 

period), the mill voluntarily reduced its 

SO2 emissions and that using a more 

recent period to calculate the BART 

emission limit results in a more 

stringent emission limit. 

As discussed in more detail elsewhere 

in this final rule and in our RTC 

document, we disagree that it is 

appropriate to use 2001–2003 as the 

baseline period for purposes of 

calculating the SO2 BART emission 

limit for Power Boiler No. 2. One of the 

factors we are required to take into 

consideration in making a BART 

determination is whether there is any 

existing pollution control equipment in 

use at the source. Power Boiler No. 2 is 

currently equipped with venturi 

scrubbers for control of SO2 emissions, 

and in our BART analysis, we evaluated 

upgrades to the existing scrubbers. As 

we discussed in our proposal, in 

determining whether upgrades to the 

existing scrubbers are technically 

feasible and whether additional SO2

control could be achieved, it was 

necessary for us to first determine the 

current control efficiency of the 

scrubbers. For purposes of determining 

the current control efficiency of the 

scrubbers, we believe the most 

reasonable and appropriate approach is 

to rely on recent data instead of older 

data from the 2001–2003 period. 

Therefore, we relied on 2011–2013 

monthly average data on monitored SO2

emissions, records of mass of fuel 

burned for each fuel type, and the 

percent sulfur content of each fuel type 

burned to estimate the current average 

control efficiency (i.e., baseline control 

efficiency) of the scrubbers, which we 

found to be approximately 69%. We 

find that because the baseline control 

efficiency of the existing scrubbers (i.e., 

69%) corresponds to emissions data 

from 2011–2013, it is reasonable and 

appropriate to rely on emissions data 

from the same period to calculate the 

emission limit that corresponds to 

increasing the control efficiency from 

the baseline level of approximately 69% 

up to 90%. Therefore, we are not using 

2001–2003 as the baseline period for 

purposes of calculating the SO2

emission limit for Power Boiler No. 2. 

We proposed to require the facility to 

demonstrate compliance with the SO2

emission limit for Power Boiler No. 2 

using the existing CEMS. We are 

finalizing this method for demonstrating 

compliance with the SO2 BART 

emission limit for Power Boiler No. 2. 

During the public comment period for 

our proposal, Domtar submitted 

comments stating that due to a 

repurposing project the mill is currently 

undergoing, the mill’s steam demands 

may change and Power Boiler No. 2 may 

be converted to burn only natural gas, 

mothballed, or shut down in the near 

future. After carefully considering the 

comments submitted to us, we have 

determined that in light of the 

repurposing project the mill is currently 

undergoing and the possibility of Power 

Boiler No. 2 being converted to burn 

only natural gas, it is appropriate to 

provide the facility with flexibility in 

how it must demonstrate compliance 

with the SO2 emission limit for Power 

Boiler No. 2. Therefore, we are 

providing one alternative method for 

demonstrating compliance with the SO2

BART emission limit: The owner or 

operator may demonstrate compliance 

with this emission limit by switching 

Power Boiler No. 2 to burn only 

pipeline quality natural gas provided 

that the preconstruction air permit is 

revised so as to permit combustion of 

only pipeline quality natural gas at 

Power Boiler No. 2. Therefore, if Power 

Boiler No. 2 is switched to burn only 

pipeline quality natural gas and the 

company’s air permit is revised to 

reflect this, it would satisfy the 

requirement for demonstrating 

compliance with the boiler’s SO2 BART 

emission limit, and the related reporting 

and recordkeeping requirements would 

not be applicable.56

Taking into consideration the BART 

factors, we are finalizing our 

determination that BART for NOX for 

Power Boiler No. 2 is an emission limit 

of 345 lb/hr on a 30 boiler-operating-day 

rolling average basis, which is 

consistent with the installation and 

operation of LNB. We are not making 

changes to the analysis we presented in 

our proposal of the cost and visibility 

improvement of this control measure.57

As discussed in our proposal, the cost 

of LNB on Power Boiler No. 2 is 

estimated to cost $1,951/NOX ton 

removed, and it is projected to result in 

considerable visibility improvement at 

the most impacted Class I area (see 

Table 13). We are finalizing this NOX

emission limit as proposed. 

TABLE 13—DOMTAR POWER BOILER NO. 2—SUMMARY OF THE 98TH PERCENTILE VISIBILITY IMPACTS AND IMPROVEMENT

OF LNB 

Class I area 

Baseline 

visibility 

impact 

(Ddv) 

Estimated 

visibility 

improvement 

from 

baseline 

(Ddv) 

Caney Creek ............................................................................................................................................................ 0.844 0.181 

Upper Buffalo ........................................................................................................................................................... 0.146 0.014 

Hercules-Glades ...................................................................................................................................................... 0.105 0.011 

Mingo ....................................................................................................................................................................... 0.065 0.005 

Cumulative Visibility Improvement (Ddv) ................................................................................................................. ........................ 0.211 

We proposed to require the facility to 

demonstrate compliance with this NOX

emission limit using the existing CEMS. 

We are finalizing this method for 

demonstrating compliance. As 

discussed above, during the public 

comment period for our proposal, 

Domtar submitted comments stating that 

due to a repurposing project the mill is 

currently undergoing, the mill’s steam 

demands may change and Power Boiler 

No. 2 may be converted to burn only 

natural gas, mothballed, or shut down in 

the near future. After carefully 

considering the comments submitted to 

us, we have determined that it is 

appropriate to provide the facility with 

flexibility in how it must demonstrate 

compliance with the NOX emission 

limit for Power Boiler No. 2. Therefore, 

we are providing one alternative method 


asabaliauskas on DSK3SPTVN1PROD with RULES
Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66349 

58The alternative method to demonstrate 

compliance with the NOX emission limit is a logical 

outgrowth of our proposal based on the company’s 

comments, which are discussed in more detail 

elsewhere in the final rule and our RTC document. 

See Int’l Union, UMW, 407 F.3d at 1259; Fertilizer 

Inst, 935 F.2d at 1311; and Chocolate Mfrs. Ass’n, 

755 F.2d 1098. 

59Boiler MACT standards are required under 

CAA section 112, and are found at 40 CFR part 63, 

subpart DDDDD—National Emission Standards for 

Hazardous Air Pollutants for Major Sources: 

Industrial, Commercial, and Institutional Boilers 

and Process Heaters. 

60The revised compliance date is a logical 

outgrowth of our proposal based on the company’s 

comments, which are discussed in more detail 

elsewhere in the final rule and our RTC document. 

for demonstrating compliance with the 

NOX BART emission limit: If Power 

Boiler No. 2 is switched to burn only 

natural gas and the facility’s 

preconstruction air permit is revised 

such that Power Boiler No. 2 is 

permitted to burn only natural gas, the 

facility may demonstrate compliance 

with the NOX emission limit by 

calculating emissions using AP–42 

emission factors and fuel usage records 

provided that the operation of the CEMS 

is no longer required by any other 

applicable requirements. Under these 

circumstances, the facility would not be 

required to use the existing CEMS to 

demonstrate compliance with the NOX

BART emission limit.58

As discussed above, in response to 

comments we received from Domtar, we 

are also revising our definition of 

‘‘boiler-operating-day’’ as it applies to 

Power Boilers No. 1 and 2 for BART 

purposes. For purposes of SO2 and NOX

BART for Power Boilers No. 1 and 2, we 

are defining a boiler-operating-day as a 

24-hour period between 6 a.m. and 6 

a.m. the following day during which 

any fuel is fed into and/or combusted at 

any time in the power boiler. 

We proposed to require the Domtar 

Ashdown Mill to comply with the SO2

and NOX BART emission limits no later 

than 3 years from the effective date of 

our final action, but invited public 

comment on this issue in our proposal. 

We received comments from Domtar 

requesting that we finalize a 5-year 

compliance date in light of the 

repurposing project the mill is currently 

undergoing. The repurposing project 

involves converting a non-BART paper 

machine at the mill into a fluff pulp line 

and may significantly affect the mill’s 

steam demands and ultimately 

determine the future operating scenario 

for Power Boiler No. 2. The comments 

submitted by Domtar indicate that after 

the repurposing and reconfiguration of 

the mill systems is complete and fully 

operational and the mill has learned 

how to operate and optimize in its 

newly configured state, it will be able to 

determine steam demands and will then 

decide the future operating scenario for 

Power Boiler No. 2. Our understanding 

from the comments submitted is that 

this decision is expected to be made in 

late 2018, but that additional time will 

be needed after this to implement the 

future operating scenario selected by the 

mill for Power Boiler No. 2, which 

could include switching fuels, 

mothballing or retiring the boilers, or 

continued operation under current 

operating conditions. It is not EPA’s 

intention to place an undue burden on 

the Domtar Ashdown Mill by requiring 

a compliance date that may not provide 

sufficient time for the mill to install 

controls or otherwise make the 

necessary operating changes to meet the 

boiler’s BART emission limits after it 

has made a final decision on the future 

operating scenario for Power Boiler No. 

2. We believe that a 3-year compliance 

date is generally sufficient for 

installation of the controls that the SO2

and NOX BART emission limits we are 

requiring can be achieved with. 

However, due to the special 

circumstances in this case, which we 

discuss in section V.E of this final rule, 

we believe it is reasonable and 

appropriate to establish a longer 

compliance date. Therefore, we are 

requiring the mill to comply with the 

SO2 and NOX BART emission limits no 

later than 5 years from the effective date 

of this final rule. We believe that this 

adequately addresses the commenter’s 

concerns while complying with the 

CAA mandate that compliance with 

BART requirements must be as 

expeditiously as practicable, but in no 

event later than 5 years after 

promulgation of this FIP. 

We are finalizing our determination 

that Domtar must satisfy the PM BART 

requirement by relying on the 

applicable Boiler MACT PM standard as 

revised.59 We proposed that the same 

method for demonstrating compliance 

with the Boiler MACT PM standard 

must be used for demonstrating 

compliance with the PM BART 

emission limit. We proposed to require 

the source to comply with this emission 

limit for BART purposes as of the 

effective date of the final rule. During 

the public comment period, we received 

comments from Domtar seeking 

clarification regarding the requirements 

for compliance demonstration, 

reporting, and recordkeeping for our 

proposed PM BART determination for 

Power Boiler No. 2. Domtar requested 

that we ensure that the requirements for 

compliance demonstration, testing, 

reporting, and recordkeeping under the 

Boiler MACT standard for PM are 

consistent with those associated with 

the PM BART emission limit for Power 

Boiler No. 2. As the Domtar Ashdown 

Mill will be relying on compliance with 

the Boiler MACT PM standard to satisfy 

the PM BART requirement for Power 

Boiler No. 2, we believe that there is no 

need for a separate set of requirements 

for compliance demonstration, testing, 

monitoring, recordkeeping, and 

reporting to satisfy the PM BART 

requirement. This was our position at 

proposal, but we recognize that the 

regulatory text in our proposal may not 

have conveyed this clearly. Therefore, to 

provide clarification, we are revising the 

regulatory requirements of our FIP 

found under 40 CFR 52.173(c) that 

apply to Power Boiler No. 2 for PM 

BART to state that the mill shall rely on 

compliance with the Boiler MACT PM 

standard under 40 CFR part 63 Subpart 

DDDDD to satisfy the PM BART 

requirement for Power Boiler No. 2. In 

other words, compliance with the Boiler 

MACT PM standard applicable to Power 

Boiler No. 2 is sufficient to demonstrate 

compliance with the PM BART 

requirement. Additionally, we are also 

clarifying that Power Boiler No. 2 must 

satisfy the PM BART requirement by 

relying on the Boiler MACT PM 

standard that it is subject to at any given 

time, such that if the MACT PM 

standard and/or the compliance 

demonstration and recordkeeping 

requirements are revised in the future, 

the boiler must rely on those revised 

requirements to satisfy the PM BART 

requirement. 

In response to comments we received 

from the company, we are revising our 

proposed compliance date for PM BART 

for Power Boiler No. 2. The company 

submitted comments requesting that we 

finalize a compliance date of 30 days 

after the effective date of the final rule 

instead of requiring the source to 

comply with BART as of the effective 

date of the final rule. The company 

noted that this would provide 

additional time for it to prepare 

compliance records. We determined that 

the company’s request is reasonable and 

would provide the mill with additional 

time to understand the applicable BART 

requirements and to prepare compliance 

records and adjust recordkeeping 

systems without unduly delaying 

compliance with the BART emission 

limit. Therefore, we are requiring Power 

Boiler No. 2 to comply with the PM 

BART emission limit no later than 30 

days from the effective date of this final 

rule.60


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61See Arkansas Regional Haze SIP, Appendix 

8.1—‘‘Technical Support Document for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze State Implementation Plans,’’ 

sections 3.7.1 and 3.7.2. See the docket for this 

rulemaking for a copy of the Arkansas Regional 

Haze SIP. 

62See Arkansas Regional Haze SIP, Appendix 

8.1—‘‘Technical Support Document for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze State Implementation Plans,’’ section 

3.7.1 and 3.7.2. See the docket for this rulemaking 

for a copy of the Arkansas Regional Haze SIP. 63 80 FR 18944, 18991. 

3. Reasonable Progress Analysis 

a. Four-Factor Analysis 

In our proposed rule, we explained 

that the CENRAP CAMx modeling with 

PSAT showed that sulfate from all 

source categories combined contributed 

87.05 inverse megameters (Mm¥1) out 

of 133.93 Mm¥1 of light extinction at 

Caney Creek on the average across the 

20% worst days in 2002, which is 

approximately 65% of the total light 

extinction. At Upper Buffalo, sulfate 

from all source categories combined 

contributed 83.18 Mm¥1 out of 131.79 

Mm¥1 of light extinction at Upper 

Buffalo on the average across the 20% 

worst days in 2002, which is 

approximately 63% of the total light 

extinction. Nitrate from all source 

categories combined contributed 13.78 

Mm¥1 out of 133.93 Mm¥1 of light 

extinction at Caney Creek and 13.30 

Mm¥1 out of 131.79 Mm¥1 of light 

extinction at Upper Buffalo, which is 

approximately 10% of the total light 

extinction at each Class I area on the 

average across the 20% worst days in 

2002. The CENRAP CAMx modeling 

showed that on most of the 20% worst 

days in 2002, total extinction was 

dominated by sulfate at both Caney 

Creek and Upper Buffalo.61

Additionally, total extinction at Caney 

Creek was dominated by nitrate on 4 of 

the days that comprise the 20% worst 

days in 2002, while a significant portion 

of the total extinction at Upper Buffalo 

on 2 of the days that comprise the 20% 

worst days in 2002 was due to nitrate.62

Given their contribution to visibility 

impairment on the 20% worst days, we 

consider both SO2 and NOX to be key 

pollutants contributing to visibility 

impairment at Arkansas Class I areas, so 

it is appropriate to consider both SO2

and NOX controls in our reasonable 

progress analysis. 

In our proposal, we explained that 

point sources are responsible for a 

majority of the total light extinction at 

each Class I area, contributing 

approximately 60% of the total light 

extinction. Point sources contributed 

81.04 Mm¥1 out of 133.93 Mm¥1 of 

light extinction at Caney Creek and 

77.80 Mm¥1 out of 131.79 Mm¥1 of 

light extinction at Upper Buffalo on the 

average across the 20% worst days in 

2002. Because other source types (i.e., 

natural, on-road, non-road, and area) 

each contributed a much smaller 

proportion of the total light extinction at 

each Class I area, we decided to focus 

only on point sources in our reasonable 

progress analysis for this 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 on 

the average across the 20% worst days 

in 2002, which is approximately 56% of 

the total light extinction at Caney Creek 

and 55% of the total light extinction at 

Upper Buffalo. Nitrate from point 

sources contributed 4.06 Mm¥1 out of 

133.93 Mm¥1 of light extinction at 

Caney Creek and 3.93 Mm¥1 out of 

131.79 Mm¥1 of light extinction at 

Upper Buffalo, which is approximately 

3% of the total light extinction at each 

Class I area. Sulfate from Arkansas point 

sources contributed 2.20% of the total 

light extinction at Caney Creek and 

1.99% at Upper Buffalo, and nitrate 

from Arkansas point sources 

contributed 0.27% of the total light 

extinction at Caney Creek and 0.14% at 

Upper Buffalo. We explained in our 

proposal that SO2 emissions (a 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 was largely due to sulfate from 

point sources. We also explained that on 

the 20% worst days in 2018, sulfate 

from Arkansas’ point sources is 

projected to contribute 3.58% of the 

total light extinction at Caney Creek and 

3.20% at Upper Buffalo, while nitrate 

from Arkansas’ point sources is 

projected to contribute 0.29% of the 

total light extinction at Caney Creek and 

0.25% at Upper Buffalo. Based on the 

CENRAP 2018 visibility projections, 

sulfate from point sources is expected to 

continue being the principal driver of 

regional haze on the 20% worst days at 

Arkansas’ Class I areas. 

As a starting point in our analysis to 

determine whether additional controls 

on Arkansas sources are necessary to 

make reasonable progress in the first 

regional haze planning period, we 

examined the most recent SO2 and NOX

emissions inventories for point sources 

in Arkansas. In our examination of the 

SO2 and NOX emissions inventories for 

Arkansas’ point sources, we found that 

the number of point sources in Arkansas 

that emit SO2 and NOX emissions is 

relatively small. Furthermore, a very 

small portion of the point sources in the 

state are responsible for a large portion 

of the statewide SO2 and NOX pointsource emissions. Specifically, White 

Bluff, Independence, and Flint Creek are 

the three largest emitters of SO2 and 

NOX point-source emissions in the state 

and are collectively responsible for 

approximately 84% of the SO2 point 

source emissions and 55% of the NOX

point-source emissions in the state.63 As 

our proposed rule included SO2 and 

NOX emission limits under BART for 

White Bluff Units 1 and 2 and Flint 

Creek Unit 1 that are anticipated to 

result in a substantial reduction in SO2

and NOX emissions from these facilities, 

we proposed to determine that it is 

appropriate to eliminate these two 

facilities from further consideration of 

additional controls under the reasonable 

progress requirements for the first 

planning period. The Entergy 

Independence Plant is not subject to 

BART, and its emissions were 30,398 

SO2 tpy and 13,411 NOX tpy based on 

the 2011 NEI. The Entergy 

Independence Plant is the second 

largest source of SO2 and NOX pointsource emissions in Arkansas, 

accounting for approximately 36% of 

the SO2 point-source emissions and 

21% of the NOX point-source emissions 

in the state. In our proposal, we 

explained that it was appropriate to 

focus our reasonable progress analysis 

on the Entergy Independence Power 

Plant because it is a significant source 

of SO2 and NOX as the second largest 

emitter of NOX and SO2 point-source 

emissions in the State. Consequently, 

addressing White Bluff and AEP Flint 

Creek under the BART requirements 

and Independence under the reasonable 

progress requirements will address a 

large proportion of the visibility impacts 

due to Arkansas point sources at Caney 

Creek and Upper Buffalo. 

We also found that the remaining 

point sources in the state had much 

lower SO2 and NOX emissions than 

these facilities. For example, the point 

source with the fourth highest SO2

emissions is Future Fuel Chemical 

Company, which contributes 

approximately 4.1% of the total SO2

point-source emissions in the state (i.e., 

3,420 SO2 tons out of statewide SO2

point source emissions of 83,883 SO2

tons). The point source with the fourth 

highest NOX emissions is the Natural 

Gas Pipeline Company of America #308, 

which contributes approximately 5.1% 

of the total NOX point source emissions 

in the state (i.e., 3,194 NOX tons out of 

statewide NOX point source emissions 

of 62,984 NOX tons). Based on the much 

smaller magnitude of these sources’ 


asabaliauskas on DSK3SPTVN1PROD with RULES
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64 81 FR 296 (January 5, 2016). 

65 80 FR 24872. 

66North Dakota v. EPA, 730 F.3d 750, 764–66 

(8th Cir. 2013) (discussing reasonable progress 

determination for the Antelope Valley station). 

67The Independence Plant accounts for 

approximately 36% of the SO2 point-source 

emissions and 21% of the NOX point-source 

emissions in Arkansas (2011 NEI). 

emissions, we determined that the 

remaining point sources in the state are 

less likely to be significant contributors 

to regional haze (both on an actual and 

percentage basis) and thus did not 

warrant closer evaluation during this 

planning period. Because such a small 

number of point sources in Arkansas are 

responsible for a such large portion of 

the statewide SO2 and NOX point-source 

emissions in the state, we concluded 

that photochemical modeling or other 

more exhaustive analyses that we have 

performed in other regional haze actions 

were unnecessary to identify sources in 

Arkansas to evaluate under reasonable 

progress. In contrast, in states such as 

Texas where the universe of point 

sources is much larger and the 

distribution of SO2 and NOX emissions 

is very widespread, an evaluation of the 

state’s emissions inventory alone was 

not sufficient to reveal the best potential 

candidates for evaluation under 

reasonable progress. For this reason, we 

explained in our Texas Regional Haze 

FIP that, due to the challenges presented 

by the geographic distribution and 

number of sources in Texas, the CAMx 

photochemical model was best suited 

for identifying sources to evaluate for 

reasonable progress controls.64 We did 

not encounter these challenges in our 

Arkansas Regional Haze FIP and 

therefore did not conduct 

photochemical modeling. 

In our reasonable progress analysis for 

Independence, we considered the four 

statutory factors under CAA section 

169A(g)(1) and 40 CFR 

51.308(d)(1)(i)(A): The costs of 

compliance, the time necessary for 

compliance, the energy and nonair 

quality environmental impacts of 

compliance, and the remaining useful 

life of any existing source subject to 

such requirements. Alongside the four 

statutory factors, we also considered the 

visibility improvement of controls. 

Although visibility is not one of the four 

mandatory factors explicitly listed for 

consideration under CAA section 

169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), 

states or EPA have the option of 

considering the projected visibility 

benefits of controls in determining if the 

controls are necessary to make 

reasonable progress. In our proposal, we 

explained that SO2 emissions are the 

principal driver of regional haze on the 

20% worst days in Arkansas’ Class I 

areas. While point source NOX

emissions are not the principal 

contributor to visibility extinction on 

the 20% worst days at Arkansas’ Class 

I areas, NOX is nevertheless a key 

pollutant since NOX emissions 

contributed considerably to visibility 

impairment on a portion of the 20% 

worst days in 2002 based on CENRAP’s 

CAMx source apportionment modeling. 

Further, our assessment of the 

Independence facility using CALPUFF 

dispersion modeling, which assesses the 

98th percentile visibility impairment 

caused by the facility, indicated that 

Independence is potentially one of the 

largest single contributors to visibility 

impairment at Class I areas in 

Arkansas.65 Therefore, we determined 

that it was appropriate to evaluate the 

Independence facility for both SO2 and 

NOX controls under reasonable progress. 

Based on our reasonable progress 

analysis under 40 CFR 51.308(d)(1), we 

discussed in our proposal that SO2 and 

NOX controls at Independence would be 

cost-effective and would result in 

meaningful visibility benefits at 

Arkansas’ Class I areas based on the 

maximum (98th percentile) facility 

impacts using CALPUFF dispersion 

modeling. Although the reasonable 

progress provisions of the Regional Haze 

Rule place emphasis on the 20% worst 

days, the CAA goal of remedying 

visibility impairment due to 

anthropogenic emissions encompasses 

all days. Thus, states and EPA have the 

discretion to consider the visibility 

impacts of sources and the visibility 

benefit of controls on days other than 

the 20% worst days in making their 

decisions, such as the days on which a 

given facility has its own largest 

impacts. Even if the days on which a 

given facility has its largest impacts are 

not the same as the 20% of days with 

the worst visibility overall, the facility’s 

impacts will still need to be addressed 

for Arkansas’ Class I areas to achieve the 

goal of natural visibility conditions. The 

Eighth Circuit previously addressed 

state and EPA use of CALPUFF for 

reasonable progress purposes.66

Based on our consideration of the four 

reasonable progress factors and the 

visibility impacts from Independence 

and the visibility improvement of 

controls, we proposed two alternative 

options for reducing emissions at 

Independence Units 1 and 2. Under 

Option 1, we proposed to require both 

SO2 and NOX controls. Under Option 2, 

we proposed to require only SO2

controls. We solicited public comment 

on our two proposed options. In 

addition to Options 1 and 2, we also 

solicited public comment on any 

alternative SO2 and NOX control 

measures that could address the 

regional haze requirements for White 

Bluff Units 1 and 2 and Independence 

Units 1 and 2 for this planning period. 

We received many comments opposed 

to our proposal to establish any controls 

on Independence to achieve reasonable 

progress. Many of these comments 

stated that it was not necessary to 

control or even evaluate Arkansas’ 

sources under the CAA and Regional 

Haze Rule’s reasonable progress 

requirements because Arkansas’ Class I 

areas are projected to be below the 

uniform rate of progress (URP) in 2018 

and because Arkansas’ Class I areas are 

on track to meet the RPGs established by 

the state in the Arkansas Regional Haze 

SIP. As discussed in section V.C. of this 

final rule and in our RTC document, we 

have an obligation under the CAA and 

the Regional Haze Rule to conduct an 

analysis of the four reasonable progress 

factors. This obligation applies even 

when a Class I area is below the URP 

and even when monitoring data show 

that a Class I area is meeting or is 

projected to meet the RPG previously 

established by the state. The CAA and 

Regional Haze Rule are clear that the 

determination of what controls are 

necessary to make reasonable progress 

(and whose emission reductions dictate 

the RPGs) must be determined based on 

the four-factor analysis. See CAA 

section 169A(b)(2) & (g)(1); 40 CFR 

51.308(d)(1)(i). Neither the CAA nor the 

Regional Haze Rule divest states or EPA 

of the authority and obligation to 

conduct a four-factor analysis for 

sources contributing significantly to 

visibility impairment based on existing 

or projected future visibility conditions 

at affected Class I areas. We discussed 

above and also in section V of this final 

rule that our four factor analysis focused 

on the Independence Plant because it is 

a significant source of visibility 

impairing pollutants, as it is the second 

largest source of SO2 and NOX pointsource emissions in Arkansas.67 The 

largest and third largest sources of SO2

and NOX point-source emissions in 

Arkansas are White Bluff and Flint 

Creek, for which we are requiring 

controls under the BART requirements 

in this final rule. In comparison to the 

SO2 and NOX emissions from the three 

largest point sources (i.e., White Bluff, 

Independence, and Flint Creek), 

emissions from the remaining point 

sources in the state are relatively small 

and are less likely to be significant 

contributors to regional haze, both on an 

actual and percentage basis. Therefore, 


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66352 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

68Entergy Arkansas Inc. is one of the owners of 

White Bluff Units 1 and 2 and Independence Units 

1 and 2. The company submitted CAMx 

photochemical modeling as part of its comments 

submitted during the public comment period. These 

and all other comments we received are found in 

the docket associated with this rulemaking. 

69 80 FR 24872. 

70As discussed in our proposal, dry FGD controls 

on Independence Units 1 and 2 are expected to 

reduce facility-wide SO2 emissions by 26,902 tpy 

from a baseline emission rate of 29,780 tpy (i.e., 

Units 1 and 2 combined). See 80 FR 18944, 18993. 

our reasonable progress analysis focused 

on the Independence Plant. As 

discussed in our proposal and 

throughout this final notice, based on 

our analysis of the four reasonable 

progress factors and our consideration 

of the baseline visibility impacts from 

Independence and the visibility 

improvement of potential controls, we 

determined that SO2 and NOX controls 

at Independence would be cost-effective 

and would result in meaningful 

visibility benefits at Arkansas’ Class I 

areas, and therefore find that they are 

reasonable controls and are necessary to 

make reasonable progress. 

Other comments we received stated 

that Arkansas’ point sources have a very 

small impact on visibility impairment at 

Arkansas’ Class I areas on the 20% 

worst days and that we should therefore 

not require any controls at 

Independence under the reasonable 

progress requirements. At a minimum, 

these commenters argued, the 

contribution to visibility impairment at 

Arkansas’ Class I areas on the 20% 

worst days from point-source nitrate 

emissions was insignificant, so NOX

controls for Independence were 

unnecessary. After carefully considering 

these comments, we continue to believe 

that Arkansas’ point sources have a 

significant contribution to visibility 

impairment at Arkansas Class I areas on 

the 20% worst days. As we discuss in 

section V.J. of this final rule, CAMx 

source apportionment modeling 

conducted by Entergy Arkansas Inc.68

(Entergy) and submitted to us during the 

public comment period showed that the 

contribution to visibility impairment 

due to emissions from the Independence 

facility alone are projected to be 

approximately 1.3% of the total 

visibility impairment during the 20% 

worst days in 2018 at each Arkansas 

Class I area. Considering that the CAMx 

photochemical modeling takes into 

account the emissions of thousands of 

sources, both in Arkansas and outside of 

the state, we consider this to be a 

significant contribution to visibility 

impairment at each Class I area and a 

large portion (approximately one-third) 

of the total contribution from all 

Arkansas point sources that can be 

addressed through installation of 

controls on two units at a single facility. 

The CAMx modeling also showed that 

at Upper Buffalo, the Independence 

facility’s contribution to visibility 

impairment is greater than the 

contribution from all of the subject-toBART sources addressed in this final 

action combined. In terms of deciviews, 

the average impact from Independence 

over the 20% worst days, based on 

Entergy’s CAMx modeling and adjusted 

to natural background conditions, is 

over 0.5 dv at each of the Arkansas Class 

I areas. Together, the modeling results 

from Entergy’s CAMx modeling and the 

CALPUFF modeling demonstrate that 

controls will provide meaningful 

visibility benefits toward the goal of 

natural visibility conditions. 

While the majority of the visibility 

impacts due to Independence on the 

20% worst days are due to SO2, we note 

that NOX emissions from the facility 

also have impacts on the 20% worst 

days. The CAMx source apportionment 

modeling submitted by Entergy showed 

that NOX emissions from Independence 

are responsible for 30–40% of the 

visibility impairment in Arkansas’ Class 

I areas on 2 of the 20% worst days (i.e., 

2 out of the 21 days that are the 20% 

worst of the days with Interagency 

Monitoring of Protected Visual 

Environments (IMPROVE) monitoring 

data). We expect that installation of 

NOX controls on Independence will 

provide visibility improvement on this 

portion of the 20% worst days and will 

also provide meaningful visibility 

improvement on the 98th percentile 

day, as shown by the CALPUFF 

dispersion modeling. After carefully 

considering all comments submitted to 

us during the comment period, we are 

finalizing both SO2 and NOX controls 

for Independence Units 1 and 2 to make 

reasonable progress at Arkansas’ Class I 

areas (i.e., proposed Option 1), because 

both SO2 and NOX are key pollutants 

contributing to visibility impairment, 

and because we have determined that 

these controls are cost effective and will 

provide for significant visibility benefits 

towards the goal of natural visibility 

conditions at Arkansas’ Class I areas. 

In response to comments we received 

on our initial cost analysis presented in 

our proposal, we have revised our cost 

estimate for dry FGD for Independence 

Units 1 and 2. Based on this revision to 

our cost analysis, we find that dry FGD 

is estimated to cost $2,853/SO2 ton 

removed at Unit 1 and $2,634/SO2 ton 

removed. Although these cost estimates 

are slightly higher than we estimated in 

our proposal, we continue to find these 

controls to be cost effective and well 

within the range of cost of controls 

found to be reasonable by EPA and the 

States in other regional haze actions. 

Dry FGD controls on Independence are 

also expected to result in considerable 

visibility improvement at Arkansas’ 

Class I areas based on CALPUFF 

modeling of the maximum (98th 

percentile) visibility impacts from the 

facility (see Table 14).69 As dry FGD 

will eliminate a majority of the SO2

emissions from Independence,70 we 

anticipate that on the 20% worst days 

these controls will also accordingly 

eliminate a majority of the visibility 

impairment due to SO2 emissions from 

Independence. Taking into 

consideration the four reasonable 

progress factors and the visibility 

benefit of dry FGD controls, we 

conclude that these are reasonable 

controls and are therefore necessary to 

make reasonable progress. We are 

finalizing an SO2 emission limit of 0.06 

lb/MMBtu for Independence Units 1 

and 2 based on a 30 boiler-operating-day 

rolling average basis, which is 

consistent with the installation and 

operation of dry FGD. We are requiring 

the facility to comply with this emission 

limit no later than 5 years from the 

effective date of this final rule. 


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71Our cost analysis and visibility modeling 

analysis for LNB/SOFA for Independence Units 1 

and 2, as presented in our proposal, is based on an 

emission limit of 0.15 lb/MMBtu on a 30 boileroperating-day rolling average. As discussed in this 

final action, we received new information from 

Entergy that indicates that the source expects to be 

operating at less than 50% load more frequently 

and therefore no longer expects to be able to meet 

our proposed NOX emission limit. We are therefore 

finalizing the bifurcated NOX emission limit 

described in this final action. We recognize that the 

comments submitted by Entergy indicate that some 

of the assumptions used to calculate the cost 

effectiveness of NOX controls for Independence may 

not exactly apply to future operations. However, 

because we found LNB/SOFA controls to be very 

cost effective, we expect that even if the change in 

operation of the source were known more precisely 

and were taken into account in our calculation of 

the cost ($/ton), these controls would continue to 

be cost effective. Therefore, we are not revising our 

cost effectiveness calculations or visibility 

improvement modeling of LNB/SOFA for 

Independence Units 1 and 2. 

72 80 FR 24872. 

73As discussed in our proposal, LNB/SOFA 

controls on Independence Units 1 and 2 are 

expected to reduce facility-wide NOX emissions by 

5,927 tpy from a baseline emission rate of 12,713 

tpy (i.e., Units 1 and 2 combined). See 80 FR 18944, 

18996. 

74Entergy submitted comments on this issue that 

are applicable to both White Bluff and 

Independence. We discuss and address these 

comments in more detail elsewhere in this final 

rule. 

75The bifurcated emission limit is a logical 

outgrowth of our proposal based on the company’s 

comments, which are discussed in more detail 

elsewhere in the final rule and our RTC document. 

See Int’l Union, UMW, 407 F.3d at 1259; Fertilizer 

Inst, 935 F.2d at 1311; and Chocolate Mfrs. Ass’n, 

755 F.2d 1098. 

TABLE 14—ENTERGY INDEPENDENCE PLANT—SUMMARY OF THE 98TH PERCENTILE BASELINE VISIBILITY IMPACTS AND

IMPROVEMENT DUE TO DRY FGD 

[Facility-wide] 

Class I area 

Facility-wide 

baseline 

visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ............................................................................................................................................................ 2.512 1.096 

Upper Buffalo ........................................................................................................................................................... 2.264 1.178 

Cumulative Visibility Improvement at Arkansas’ Class I areas (Ddv) ..................................................................... ........................ 2.274 

As discussed in our proposal, LNB/

SOFA controls on Independence are 

estimated to cost $401/NOX ton 

removed at Unit 1 and $436/NOX ton 

removed at Unit 2,71 which we consider 

to be very cost effective and well within 

the range of cost of controls found to be 

reasonable by EPA and the States in 

other regional haze actions. LNB/SOFA 

controls on Independence are also 

expected to provide considerable 

visibility benefits based on CALPUFF 

modeling of the maximum (98th 

percentile) visibility impacts from the 

facility (see Table 15).72 As LNB 

controls will eliminate a large portion of 

the NOX emissions from 

Independence,73 we anticipate that 

these controls will also accordingly 

eliminate a large portion of the visibility 

impairment due to NOX emissions from 

Independence on a portion of the 20% 

worst days. Taking into consideration 

the four reasonable progress factors and 

the visibility benefit of LNB/SOFA 

controls, we conclude that these are 

reasonable controls and are therefore 

necessary to make reasonable progress. 

As such, we are requiring NOX controls 

for Independence Units 1 and 2 under 

the reasonable progress requirements. 

TABLE 15—ENTERGY INDEPENDENCE PLANT—SUMMARY OF THE 98TH PERCENTILE BASELINE VISIBILITY IMPACTS AND

IMPROVEMENT DUE TO LNB/SOFA 

[Facility-wide] 

Class I area 

Facility-wide 

baseline 

visibility 

impact 

(Ddv) 

Visibility 

improvement 

from baseline 

(Ddv) 

Caney Creek ............................................................................................................................................................ 2.028 0.459 

Upper Buffalo ........................................................................................................................................................... 2.003 0.198 

Cumulative Visibility Improvement at Arkansas’ Class I areas (Ddv) ..................................................................... ........................ 0.657 

We received comments from the 

company stating that Independence 

Units 1 and 2 are no longer expected to 

be able to consistently meet our 

proposed NOX emission limit of 0.15 lb/ 

MMBtu over a 30-boiler-operating-day 

period based on LNB/SOFA controls.74

We have determined that the company 

has provided sufficient information to 

substantiate that the units are not 

expected to be able to meet our 

proposed NOX emission limit of 0.15 lb/ 

MMBtu when the units are primarily 

operated at less than 50% of their 

operating capacity. Therefore, we are 

finalizing a ‘‘bifurcated’’ NOX emission 

limit for each unit.75 We are requiring 

Independence Units 1 and 2 to meet a 

NOX emission limit of 0.15 lb/MMBtu 

on a 30 boiler-operating-day rolling 

average, where the average is to be 

calculated by including only the hours 

during which the unit was dispatched at 

50% or greater of maximum capacity. In 

this particular case, the 30 boileroperating-day rolling average is to be 

calculated for each unit by the following 

procedure: (1) Summing the total 

pounds of NOX emitted during the 

current boiler operating day and the 

preceding 29 boiler operating days, 

including only emissions during hours 

when the unit was dispatched at 50% or 

greater of maximum capacity; (2) 

summing the total heat input in MMBtu 

to the unit during the current boiler 

operating day and the preceding 29 

boiler operating days, including only 

the heat input during hours when the 

unit was dispatched at 50% or greater 

of maximum capacity; and (3) dividing 

the total pounds of NOX emitted as 


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76As described in section I. of this notice, Entergy 

also submitted a comment after the close of the 

comment period, indicating that Entergy intends 

that a second alternative described in the late 

comment, involving only White Bluff, is a 

replacement for the multi-unit alternative 

previously described in its timely comments. 

Because the late comment is not a basis for our 

decision making in this final rule, we are 

responding in this final rule and in our RTC 

document to the alternative proposal described in 

the comments that Entergy filed during the 

comment period. 

77 ‘‘Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program,’’ dated 

June 1, 2007. We refer to this guidance as the ‘‘2007 

Reasonable Progress Guidance’’ throughout this 

final notice. 

78 40 CFR 51.308(d)(1). 

79 40 CFR 51.308(d)(1)(iv). 

80 40 CFR 51.308(d)(1)(ii). 

81 40 CFR 51.308(g)–(h). 

82 ‘‘Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program,’’ at 5–2. 

83We discuss in section II.A of this final rule the 

history of the state’s submittals and our actions. 

84These RPGs are calculated using the same 

methodology described in our proposal and TSD. 

See ‘‘CACR UPBU RPG analysis 2018.xlsx’’ for 

additional information on the calculation of the 

RPGs. 

85The RPGs we are finalizing in this rulemaking 

for Caney Creek and Upper Buffalo are a logical 

outgrowth of our proposed RPGs based on 

comments we received, which are discussed in 

more detail elsewhere in the final rule and our RTC 

document. See Int’l Union, UMW, 407 F.3d at 1259; 

Fertilizer Inst., 935 F.2d at 1311; and Chocolate 

Mfrs. Ass’n v. Block, 755 F.2d 1098. 

calculated in step 1 by the total heat 

input to the unit as calculated in step 2. 

In addition to this limit that is intended 

to control NOX emissions when the 

units are operated at 50% or greater of 

maximum capacity, we are also 

establishing a limit in lb/hr that applies 

only when the units are operated at 

lower capacity. We are requiring 

Independence Units 1 and 2 to meet an 

emission limit of 671 lb/hr on a rolling 

3-hour average, where the average is to 

be calculated by including emissions 

only for the hours during which the unit 

was dispatched at less than 50% of the 

unit’s maximum heat input rating (i.e., 

hours when the heat input to the unit 

is less than 4,475 MMBtu). We 

calculated this emission limit by 

multiplying 0.15 lb/MMBtu by 50% of 

the maximum heat input rating for each 

unit (i.e., 50% of 8,950 MMBtu/hr, or 

4,475 MMBtu/hr). As discussed in 

section V.F. in this final rule, in 

response to comments we received, we 

are shortening the compliance date for 

the NOX emission limit for 

Independence Units 1 and 2 from our 

proposed 3 years to 18 months. 

We also received comments during 

the public comment period from 

Entergy that presented an alternative 

multi-unit approach to address the 

regional haze requirements for White 

Bluff Units 1 and 2 and Independence 

Units 1 and 2.76 The company’s 

alternative approach consisted of the 

following: Requiring White Bluff Units 

1 and 2 and Independence Units 1 and 

2 to comply with an SO2 emission limit 

of 0.60 lb/MMBtu on a 30 boileroperating-day rolling average beginning 

in 2018; requiring White Bluff Units 1 

and 2 and Independence Units 1 and 2 

to comply with a NOX emission limit of 

1,342.5 lb/hr on a 30 boiler-operatingday rolling average based on the 

installation of LNB/SOFA within 3 

years; and ceasing coal combustion at 

White Bluff Units 1 and 2 in 2027 and 

2028. We note that we do not interpret 

Entergy’s comments as suggesting that 

we adopt the elements in its alternative 

that are unique to White Bluff as an 

alternative to our proposed BART 

emission limits at the facility unless we 

also conclude that the remaining 

elements address any reasonable 

progress requirements for 

Independence. After carefully 

considering the comments we received 

specifically on this issue, we do not 

believe the comprehensive multi-unit 

strategy as presented by the company 

has potential to satisfy the BART 

requirements for White Bluff Units 1 

and 2 and the reasonable progress 

requirements for Independence Units 1 

and 2. We address this in more detail 

elsewhere in this final rule. 

b. RPGs for Caney Creek and Upper 

Buffalo 

We proposed RPGs for the 20% worst 

days for Caney Creek and Upper Buffalo 

of 22.27 dv and 22.33 dv, respectively 

that reflected the anticipated visibility 

conditions resulting from the 

combination of control measures from 

the approved portion of the 2008 

Arkansas Regional Haze SIP and our FIP 

proposal. We received comments on our 

proposal indicating that our proposed 

RPGs for the 20% worst days for Caney 

Creek and Upper Buffalo improperly 

incorporated visibility improvements 

that would not occur until after 2018. 

After considering these comments, we 

agree that the RPGs should reflect 

anticipated visibility conditions at the 

end of the implementation period in 

2018 rather than the anticipated 

visibility conditions once the FIP has 

been fully implemented. This approach 

is consistent with the purpose of RPGs 

and the direction provided in our 2007 

Reasonable Progress Guidance.77

Section 169B(e)(1) of the CAA 

directed the Administrator to 

promulgate regulations that ‘‘include[e] 

criteria for measuring ‘reasonable 

progress’ toward the national goal.’’ 

Consequently, we promulgated 40 CFR 

51.308(d)(1) as part of the Regional Haze 

Rule. This provision directs states to 

develop RPGs for the most and least 

impaired days to ‘‘measure’’ the 

progress that will be achieved by the 

control measures in the state’s long-term 

strategy ‘‘over the period of the 

implementation plan.’’ 78 The current 

implementation period ends in 2018. 

RPGs ‘‘are not directly enforceable’’ like 

the emission limitations in the longterm strategy.79 Rather, they fulfill two 

key purposes: (1) Allowing for 

comparisons between the progress that 

will be achieved by the state’s long-term 

strategy and the URP,80 and (2) 

providing a benchmark for assessing the 

adequacy of a state’s SIP in 5-year 

periodic reports.81 Consequently, in our 

2007 Reasonable Progress Guidance, we 

indicated that states could consider the 

‘‘time necessary for compliance’’ factor 

by ‘‘adjust[ing] the RPG to reflect the 

degree of improvement in visibility 

achievable within the period of the first 

SIP if the time needed for full 

implementation of a control measure (or 

measures) will extend beyond 2018.’’ 82

In other words, RPGs need not reflect 

the visibility improvement anticipated 

from all of the control measures deemed 

necessary to make reasonable progress 

(as a result of the four-factor analysis) 

and included in the long-term strategy. 

In this instance, we are taking final 

action on the Arkansas Regional Haze 

FIP 9 years after the state’s initial SIP 

submission was due.83 As a result, only 

some of the control measures that we 

have determined are necessary to satisfy 

the BART and reasonable progress 

requirements will be installed by the 

end of 2018. Some controls will not be 

installed until 2021. Because RPGs are 

only unenforceable analytical 

benchmarks, we think that it is 

appropriate to follow the 

recommendation in our 2007 

Reasonable Progress Guidance and 

finalize RPGs that represent the 

visibility conditions anticipated on the 

20% worst days at Caney Creek and 

Upper Buffalo by 2018. These RPGs are 

listed in the table below: 84 85

TABLE 16—REASONABLE PROGRESS

GOALS FOR 2018 FOR CANEY

CREEK AND UPPER BUFFALO

Class I area 

2018 RPG 

20% Worst 

days 

(dv) 

Caney Creek ......................... 22.47 

Upper Buffalo ........................ 22.51 


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86 64 FR 35714, 35755 (July 1, 1999). 

4. Long-Term Strategy 

We are finalizing our determination 

that the provisions in this final rule, in 

combination with provisions in the 

approved portion of the Arkansas 

Regional Haze SIP, fulfill the Regional 

Haze Rule’s long-term strategy 

requirements. The long-term strategy 

must include enforceable emissions 

limitations, compliance schedules, and 

other measures as necessary to achieve 

reasonable progress at Class I areas 

impacted by emissions from Arkansas. 

In this final rule, we are promulgating 

emission limits, compliance schedules, 

and other requirements for nine units 

subject to BART and for two reasonable 

progress units. 

B. Interstate Visibility Transport 

We are finalizing our determination 

that the control measures in the 

approved portion of the Arkansas 

Regional Haze SIP and our final FIP are 

adequate to prevent Arkansas’ emissions 

from interfering with other states’ 

required measures to protect visibility. 

Thus, the combined measures from both 

plans satisfy the interstate transport 

visibility requirement of CAA section 

110(a)(2)(D)(i)(II) for the 1997 8-hour 

ozone and the 1997 PM2.5 NAAQS. 

V. Summary and Analysis of Major 

Issues Raised by Commenters 

We received comments at the public 

hearing held in Little Rock, as well as 

comments submitted electronically on 

www.regulations.gov and through the 

mail. The full text of comments we 

received from commenters is included 

in the publicly posted docket associated 

with this action at www.regulations.gov. 

Our RTC document, which is also 

included in the docket associated with 

this action, provides detailed responses 

to all significant comments received, 

and is a part of the administrative 

record for this action. Below we provide 

summaries of the more significant 

comments received and our responses to 

them. Our RTC document is organized 

similarly to the structure of this section 

(e.g., Cost, Modeling, etc.). Therefore, if 

additional information is desired 

concerning how we addressed a 

particular comment, the reader should 

refer to the appropriate section in the 

RTC document. 

A. General Comments 

Comment: We received 238 comments 

in support of our rulemaking, 

specifically regarding the requirements 

to control SO2, NOX, and PM emissions 

from Arkansas’ subject-to-BART 

sources, and to control emissions from 

the Independence facility pursuant to 

the Regional Haze Rule’s reasonable 

progress requirements. Most of these 

commenters also expressed support for 

our proposed Option 1, which consists 

of both SO2 and NOX controls for 

Independence Units 1 and 2. These 

comments were from members 

representing various organizations and 

members of the general public. At the 

public hearing in Little Rock, Arkansas, 

40 people expressed general support for 

the plan. The speakers at the public 

hearings included members of various 

organizations and members of the 

general public. Some of these 

commenters also stated that we should 

transition away from coal-fired power 

and that retrofitting these plants and 

allowing them to continue operating is 

not a sound long-term solution, but does 

signal progress in Arkansas towards 

cleaner energy sources. 

Response: We thank the commenters 

for participating in the rulemaking and 

acknowledge their support of this 

action. As discussed in section IV. of 

this final rule, we are finalizing SO2,

NOX, and PM controls for six facilities 

under the BART requirements and we 

are finalizing both SO2 and NOX

controls for Independence under the 

reasonable progress requirements 

(proposed Option 1). Under the 

Regional Haze Rule, we are authorized 

to require affected sources to meet 

emission limits for visibility impairing 

pollutants (i.e., SO2, NOX, and PM), but 

we are not authorized to dictate what 

type of technology the source must 

employ to meet those emission limits 

and we are not authorized to force 

sources to retire or to stop burning fossil 

fuels. However, sources may choose to 

voluntarily retire or switch fuels in 

order to comply with our emission 

limits. 

Comment: We received one email 

from a citizen that opposed our 

proposal. The commenter expressed that 

it is not fair that we are requiring 

sources in Arkansas to spend a large 

amount of money in retrofits when other 

countries are not held to the same 

standards. The commenter questioned 

why other countries are given additional 

time to meet requirements. The 

commenter also expressed concern that 

our proposed controls would result in a 

higher electric bill that could mean no 

electricity for some people. 

Response: We acknowledge the 

commenter’s concerns. Consistent with 

the CAA, the regional haze program is 

concerned with remedying existing and 

preventing future impairment of 

visibility caused by manmade air 

pollution in mandatory Class I Federal 

areas (located in this country). Our 

action requires particular Arkansas 

sources to control emissions that impact 

visibility at Arkansas and Missouri 

Class I areas. Our action does not in any 

way expect Arkansas to make up for 

emissions from international sources. 

On the other hand, as we discussed in 

the preamble to the Regional Haze Rule, 

‘‘the States should not consider the 

presence of emissions from foreign 

sources as a reason not to strive to 

ensure reasonable progress in reducing 

any visibility impairment caused by 

sources located within their 

jurisdiction.’’ 86 While the goal of the 

regional haze program is to restore 

natural visibility conditions at Class I 

areas by 2064, the rule requires only 

that reasonable progress be made 

towards the goal during each planning 

period. In cases where it is not 

reasonable to meet the rate of progress 

needed to attain the goal by 2064, the 

Regional Haze Rule requires a state to 

demonstrate that this rate of progress is 

not reasonable, and that the state’s 

selected rate of progress is reasonable 

for that planning period. While there is 

no indication at this time that emissions 

from international sources are 

anticipated to prevent Arkansas from 

attaining the goal of natural visibility 

conditions at its Class I areas, we 

recognize that in some cases it may not 

be possible to attain the goal by 2064 

because of impacts from new or 

persistent international emissions 

sources or impacts from sources where 

reasonable controls are not available. 

However, states are still required to 

demonstrate that they are establishing a 

reasonable rate of progress that includes 

implementation of reasonable measures 

within the state to address visibility 

impairment in an effort to make 

progress towards the natural visibility 

goal during each planning period. We 

acknowledge the commenter’s concern 

regarding potential increases in 

electricity rates. While our 

consideration of cost under the Regional 

Haze Rule is limited to the direct costs 

incurred by sources, consistent with the 

CAA’s and Rule’s source-specific focus, 

we are very sensitive to the 

ramifications of our actions and we seek 

to select the most cost-effective options 

when we propose and finalize these 

controls. 

Comment: ADEQ submitted 

comments stating that it concurs with 

our proposed determination that the 

Georgia Pacific-Crossett Mill 6A and 9A 

Boilers are not subject to BART. 

Response: We appreciate ADEQ’s 

support of our proposed determination. 

As discussed in section IV. of this final 

action, we are finalizing our 

determination that the Georgia PacificVerDate Sep<11>2014 17:39 Sep 26, 2016 Jkt 238001 PO 00000 Frm 00025 Fmt 4701 Sfmt 4700 E:\FR\FM\27SER2.SGM 27SER2

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87Although not specified in Entergy’s written 

comments, the company met with us and confirmed 

that the interim emission limit would be met by 

combusting lower sulfur coal. See file titled 

‘‘Record of Meeting October 27 2015,’’ which is 

found in the docket for this rulemaking. 

88 80 FR 18944, 18970; see also the spreadsheet 

titled ‘‘White Bluff R6 cost revisions2,’’ which is 

found in the docket for this rulemaking.’’ 

89For example, Florida evaluated a shutdown 

option by December 31, 2020 for two BART units. 

After reviewing the Florida Regional Haze SIP, we 

concluded that the State should have evaluated DSI 

as a as a possible interim BART control option 

during the interim before the units shut down. We 

ultimately approved Florida’s determination after 

evaluating the cost-effectiveness of DSI and 

concluding that such controls were not costeffective in light of the remaining useful life of the 

units. See 78 FR 53250, 53261 (August 29, 2013). 

90See ‘‘Regional Haze Modeling Assessment 

Report,’’ dated August 4, 2015, submitted as Exhibit 

C to Entergy Arkansas Inc.’s comments. 

Crossett Mill 6A and 9A Power Boilers 

are not subject to BART. 

B. Entergy’s Alternative Strategy for 

White Bluff and Independence 

Comment: Entergy proposes an 

alternative multi-unit strategy to address 

the regional haze requirements for four 

units that it states EPA should adopt 

instead of finalizing the proposed 

controls for the four units. The 

alternative multi-unit strategy involves 

meeting an emission limit of 0.60 lb/

MMBtu on a 30-day rolling average at 

White Bluff Units 1 and 2 and 

Independence Units 1 and 2 by 2018; 

ceasing coal combustion at White Bluff 

Units 1 and 2 by 2027 and 2028; and 

installing LNB/SOFA at White Bluff 

Units 1 and 2 and Independence Units 

1 and 2 within 3 years. Based on 

Entergy’s modeling, the company says it 

believes its alternative multi-unit 

proposal achieves virtually the same 

visibility benefit as the FIP proposal and 

that the alternative proposal would 

ensure that Arkansas’ Class I areas 

remain below the URP glidepath. 

Entergy argues that the difference in the 

haze index between the proposed FIP 

controls and Entergy’s alternative multiunit strategy is too trivial to justify a $2 

billion investment at White Bluff and 

Independence for the installation of dry 

FGD. 

Response: After carefully considering 

the comments we received, we have 

determined that we cannot approve 

Entergy’s alternative proposal consistent 

with the Clean Air Act and Regional 

Haze rule. This determination is based 

on our conclusion that the alternative is 

not a better than BART alternative, does 

not meet the BART requirement for 

White Bluff Units 1 and 2, does not 

meet the reasonable progress 

requirements, and does not provide for 

the same visibility benefits as the FIP 

while delaying a majority of the 

visibility benefits until several years 

later than the FIP. Below, we discuss 

our assessment of the merits of Entergy’s 

alternative proposal as an alternative 

approach for both meeting the BART 

requirements of section 308(e) for White 

Bluff and meeting the requirements of 

sections 308(d)(1) and 308(d)(3) 

regarding reasonable progress. 

As an initial matter, we note that 

Entergy does not appear to be proposing 

that we apply the provisions of sections 

308(e)(2) and 308(e)(3) to determine that 

its multi-unit strategy is an alternative 

program that provides more reasonable 

progress than BART. To the extent that 

this is Entergy’s proposal, we cannot 

approve Entergy’s multi-unit plan as an 

alternative to BART because it does not 

meet the requirements of section 

308(e)(2)(iii) that ‘‘all necessary 

emission reductions take place during 

the first planning period,’’ i.e., by 

December 31, 2018. Moreover, Entergy 

does not argue that its alternative would 

provide for ‘‘greater’’ reasonable 

progress towards achieving natural 

visibility conditions, only that its 

proposal would result in ‘‘virtually the 

same’’ visibility benefits. Thus, our 

assessment discussed below considers 

only the requirements of section 

308(e)(1), which contains the sourcespecific BART requirements, in 

considering the provisions of Entergy’s 

alternative proposal applicable to White 

Bluff. 

Entergy proposes that White Bluff 

Units 1 and 2 would meet an SO2

interim emission limit of 0.6 lb/MMBtu 

on a rolling 30-day average from 2018 

through 2027/2028, when coal 

combustion at the two units would 

cease.87 We note that the 0.6 lb/MMBtu 

interim emission limit is only slightly 

lower than the units’ current SO2

emission rates. The maximum monthly 

SO2 emission rates for White Bluff Units 

1 and 2 in 2009–2013 were 0.653 lb/

MMBtu and 0.679 lb/MMBtu, 

respectively.88 Thus, under Entergy’s 

alternative proposal, White Bluff Units 

1 and 2 would continue to operate for 

the remainder of the first planning 

period and throughout most of the 

second planning period at near the 

current emission rate, with only a slight 

actual reduction in SO2 emissions. 

Because section 308(e)(1) and the BART 

guidelines require that a subject-toBART source install and operate the 

best available emission reduction 

technology based on the five statutory 

factors, it is necessary to consider 

whether there are any additional SO2

control measures, such as dry sorbent 

injection (DSI), that constitute BART 

during this interim period. Entergy has 

argued that with this limited remaining 

period of coal combustion, the cost per 

ton of SO2 emissions reduction for dry 

scrubbers would be too high for it to be 

selected as BART for White Bluff. While 

we agree that a shorter remaining useful 

life might result in a conclusion that dry 

scrubbers are not cost effective, as part 

of the BART analysis, technically 

feasible control technologies beyond the 

interim SO2 emission limit the company 

has proposed must be evaluated to 

determine if they are cost effective for 

use in the period before coal 

combustion ceases. In particular, DSI 

has a relatively low capital cost and may 

be cost effective even if operated for a 

short period of time.89 Under Entergy’s 

proposed strategy, White Bluff Units 1 

and 2 would cease coal combustion 

towards the end of the second planning 

period. Therefore, it would be necessary 

to consider and evaluate DSI as a 

possible interim BART control option 

for White Bluff Units 1 and 2. Because 

Entergy has provided no analysis to 

demonstrate that there is no more 

effective interim SO2 control that would 

constitute BART, the company’s 

proposed strategy is not adequate to 

ensure that the BART requirements for 

White Bluff Units 1 and 2 will be met. 

Even if it were not necessary to 

evaluate DSI or if we found it to not be 

cost effective for use at White Bluff in 

the interim period before coal 

combustion ceases, Entergy’s alternative 

proposal would still not satisfy the 

BART requirements for White Bluff 

because it does not propose SO2 and 

NOX emission limits after coal 

combustion ceases or otherwise propose 

adopting a binding requirement to burn 

only natural gas or completely shut 

down the units. Entergy proposes to 

cease coal combustion at White Bluff 

Units 1 and 2 in 2027/2028, but its 

comments do not specify the operating 

conditions of White Bluff Units 1 and 2 

after coal combustion ceases. The type 

of fuel White Bluff is permitted to burn 

after ceasing coal combustion will 

impact the emissions reductions 

actually achieved under Entergy’s 

alternative proposal. Exhibit C to 

Entergy’s comments indicates that the 

company assumes in its visibility 

modeling that SO2 and NOX emissions 

from White Bluff Units 1 and 2 will be 

zero under the company’s alternative 

proposal (i.e., ‘‘Entergy’s proposed 

controls’’ scenario).90 If Entergy’s 

alternative proposal had included 

accepting a binding requirement to burn 

only natural gas at White Bluff Units 1 

and 2 after coal combustion ceases, or 

a binding requirement to completely 

shut down the units, then we would 


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91The SO2 emissions reductions expected to 

result from our FIP will take place several years 

earlier than any significant SO2 reductions under 

Entergy’s alternative proposal. However, for 

purposes of comparing the long-term emissions 

reductions under the FIP and under the Entergy 

alternative, we are assessing the annual emissions 

reductions that will take place beginning in 2028, 

when the Entergy alternative would be fully 

implemented. 

92 In our proposal, for purposes of estimating the 

annual SO2 emissions reductions due to controls on 

White Bluff Units 1 and 2 and Independence Units 

1 and 2, we assumed an SO2 emissions baseline that 

was determined by examining annual SO2

emissions for the years 2009–2013, eliminating the 

year with the highest emissions and the year with 

the lowest emissions, and obtaining the average of 

the three remaining years. See 80 FR 18944, 18971, 

and 18992. 

93Although not specified in Entergy’s written 

comments, the company met with us and confirmed 

that this emission limit would be met by 

combusting lower sulfur coal. See file titled 

‘‘Record of Meeting October 27 2015,’’ which is 

found in the docket for this rulemaking. 

94See the spreadsheet titled ‘‘White Bluff R6 cost 

revisions2,’’ which is found in the docket for this 

rulemaking. 

agree that it would be appropriate to 

assume that SO2 emissions from White 

Bluff will be zero beginning in 2027/

2028. Similarly, if Entergy’s alternative 

proposal had included accepting a 

binding requirement to completely shut 

down White Bluff, then we would agree 

that it would be appropriate to assume 

that NOX emissions from White Bluff 

will be zero beginning in 2027/2028. 

Although, as we have already 

established, Entergy’s alternative 

proposal cannot constitute a BART 

alternative because all necessary 

emission reductions will not take place 

during the first implementation period 

and the alternative proposal also does 

not satisfy the source-specific BART 

requirements of section 308(e)(1) for 

White Bluff, in response to Entergy’s 

comment that its alternative proposal 

would achieve almost the same level of 

visibility benefit as the FIP, we 

compared the potential impacts of 

Entergy’s proposal to our FIP. Despite 

the ambiguity in the comments 

submitted by Entergy regarding its 

alternative proposal, for purposes of 

assessing the visibility impacts of the 

company’s proposed approach we have 

assumed that post-2028 SO2 and NOX

emissions from White Bluff Units 1 and 

2 will be zero under Entergy’s 

alternative proposal. In Table 17, we 

compare the total annual SO2 emissions 

reductions that would result under our 

FIP and under Entergy’s alternative 

proposal when the alternative proposal 

is fully implemented in 2028 (i.e., when 

coal combustion has ceased at White 

Bluff).91 For consistency and to allow 

for direct comparison to our FIP 

proposal, in estimating the SO2

emissions reductions anticipated to 

result from Entergy’s alternative 

proposal we have assumed the same 

SO2 baseline emissions we used for 

White Bluff and Independence in our 

proposal.92 As shown in Table 17, 

although Entergy’s alternative proposal 

would, after 2027/2028, achieve slightly 

greater SO2 reductions at White Bluff 

Units 1 and 2 than our FIP proposal, it 

would achieve substantially lower SO2

reductions at Independence Units 1 and 

2. Under Entergy’s proposed approach, 

Independence Units 1 and 2 would be 

subject to an SO2 emission limit of 0.6 

lb/MMBtu on a rolling 30-day average 

beginning in 2018.93 This emission limit 

is only slightly lower than the current 

SO2 emission rates from Independence 

Units 1 and 2. The maximum monthly 

SO2 emission rates for Independence 

Units 1 and 2 in 2009–2013 were 0.631 

lb/MMBtu and 0.612 lb/MMBtu, 

respectively.94 We have no basis to 

assume that future emissions would be 

different from current rates in the 

absence of new SIP or FIP requirements, 

and so these current emission rates are 

the appropriate baseline for comparing 

strategies, rather than the currently 

permitted emission rates, which are 

higher. As such, under Entergy’s 

proposal these units would continue to 

operate with minimal SO2 emissions 

reductions. Unlike Entergy’s proposed 

approach with respect to White Bluff, 

the proposed limits for Independence 

would not be interim emission limits. 

The company’s alternative proposal 

does not include any further SO2

controls for Independence Units 1 and 

2, such as DSI or the eventual cessation 

of coal combustion. In contrast, we 

expect our proposed SO2 emission limit 

of 0.06 lb/MMBtu would significantly 

and permanently reduce SO2 emissions 

from Independence Units 1 and 2. As 

shown in Table 17, our FIP proposal 

would achieve substantially greater SO2

emissions reductions at Independence 

than Entergy’s alternative proposal. We 

estimate that the additional SO2

emissions reductions that our FIP 

proposal would achieve at 

Independence compared to Entergy’s 

alternative strategy are 11,621 SO2 tpy at 

Unit 1 and 12,591 SO2 tpy at Unit 2. In 

light of the minimal SO2 emissions 

reductions that would be achieved at 

Independence under the company’s 

proposed strategy, we expect that there 

would be correspondingly minimal 

visibility improvement with respect to 

the SO2 controls it proposes for 

Independence. 

TABLE 17—COMPARISON OF ANNUAL SO2 EMISSIONS REDUCTIONS FROM WHITE BLUFF UNITS 1 AND 2 AND

INDEPENDENCE UNITS 1 AND 2 

[Post-2028] 

Unit 

SO2

Baseline 

emissions 

(tpy) 

FIP Proposal— 

annual SO2

reductions 1

Entergy 

alternative 

proposal— 

annual SO2

reductions 2

Additional SO2

emissions 

reductions 

achieved by 

FIP proposal 

White Bluff Unit 1 ............................................................................................. 15,816 14,363 15,816 (1,453) 

White Bluff Unit 2 ............................................................................................. 16,697 15,221 16,697 (1,476) 

Independence Unit 1 ....................................................................................... 14,269 12,912 1,291 11,621 

Independence Unit 2 ....................................................................................... 15,511 13,990 1,399 12,591 

Total—All four units combined (SO2 tpy) ................................................. 62,293 56,486 35,203 21,283 

1These SO2 reductions will begin taking place no later than 5 years from the effective date of this final FIP. 2This takes into account the full SO2 reductions that would take place under Entergy’s alternative proposal; a small amount of SO2 reductions 

would begin taking place in 2018, but the majority of these SO2 reductions would begin taking place in 2027/2028. 

As shown in Table 17, considering the 

four units combined, we estimate that 

our FIP proposal would achieve annual 

emissions reductions of 21,283 SO2 tpy 

more than Entergy’s alternative 

proposal. With regard to visibility 

benefits, Entergy does not assert that its 

alternative proposal would provide 

equal or greater visibility benefits 


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95We discuss this, as well as Entergy’s ranked 

statistical analysis and its photochemical modeling, 

in more detail elsewhere in this final rule and in 

our RTC document. 

96We explain in an earlier part of our response 

why Entergy’s alternative proposal does not satisfy 

the source-specific BART requirements of section 

308(e)(1) for White Bluff. 

97CENRAP CAMx modeling shows that on most 

of the 20% worst days in 2002, total extinction is 

dominated by sulfate at both Caney Creek and 

Upper Buffalo. Therefore, SO2 emissions are 

considered the primary driver of haze in Arkansas’ 

Class I areas. However, as discussed elsewhere in 

this final rule and in our RTC document, we 

consider both SO2 and NOX to be key visibility 

impairing pollutants in Arkansas’ Class I areas. See 

Arkansas Regional Haze SIP, Appendix 8.1— 

‘‘Technical Support Document for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze State Implementation Plans,’’ 

sections 3.7.1 and 3.7.2. See the docket for this 

rulemaking for a copy of the Arkansas Regional 

Haze SIP. 

relative to our proposed FIP once the 

alternative is fully realized in the period 

after 2027/2028. Entergy states only that 

its alternative proposal would provide 

almost the same visibility benefit as our 

proposed FIP post-2027/2028. However, 

as illustrated in Table 17, it is clear that 

annual emissions would be significantly 

higher under the Entergy alternative and 

that the long-term visibility benefits of 

the Entergy alternative proposal would 

be significantly smaller than those of the 

proposed and final FIP. As we 

explained above, Entergy assumes in its 

visibility improvement projections that 

SO2 and NOX emissions from White 

Bluff Units 1 and 2 will be zero under 

the company’s alternative proposal. The 

assumption of zero SO2 emissions from 

White Bluff after coal combustion ceases 

would be appropriate only if Entergy’s 

alternative proposal involves accepting 

a binding requirement to burn only 

natural gas or permanently shut down 

after coal combustion ceases. With 

respect to NOX emissions from all four 

units of White Bluff and Independence, 

Entergy’s multi-unit strategy includes 

the same level of NOX control as our FIP 

proposal prior to the cessation of coal 

combustion at White Bluff in 2027/

2028. Since Entergy’s explanation of its 

alternative proposal does not specify the 

operating conditions of White Bluff 

Units 1 and 2 when coal combustion 

ceases in 2027/2028, we find that the 

assumption of zero NOX emissions is 

also not adequately supported. 

However, even if we accept Entergy’s 

assumption that NOX emissions from 

White Bluff will be zero after coal 

combustion ceases and that its 

alternative proposal would thus achieve 

greater NOX reductions compared to our 

FIP proposal, given the dominance of 

visibility impact from sulfate compared 

to nitrate at the affected Class I areas in 

Arkansas, the higher visibility impacts 

due to sulfate under the Entergy 

alternative proposal would more than 

outweigh any extra nitrate-related 

visibility benefit. Entergy’s own CAMx 

modeling shows that even assuming 

zero SO2 and NOX emissions from 

White Bluff once it ceases coal 

combustion, its multi-unit alternative 

proposal would achieve less visibility 

benefit than the FIP controls at 

Arkansas’ Class I areas, most 

significantly at Upper Buffalo where the 

benefit from Entergy’s proposal is 

approximately only 66% of the benefit 

from the FIP (i.e., 1.54 dv visibility 

benefit from the FIP compared to 0.97 

dv from Entergy’s alternative 

proposal).95

We also note that Entergy does not 

appear to be requesting in the comments 

submitted during the comment period 

that we adopt the elements in its 

alternative proposal that are unique to 

White Bluff as an alternative to our 

proposed BART emission limits at the 

facility unless we also conclude that the 

remaining elements address any 

reasonable progress requirements for 

Independence. In other words, Entergy’s 

comments provide no indication that it 

is willing to accept a binding 

requirement to cease coal combustion at 

White Bluff by 2027/2028, unless we 

also accept the elements of its 

alternative proposal that are applicable 

to Independence as satisfying the 

reasonable progress requirements. Even 

if we had interpreted Entergy’s 

comments as requesting that we adopt 

the elements in its alternative proposal 

that are unique to White Bluff as an 

alternative to our proposed BART 

emission limits at the facility without 

these elements being linked to the 

remaining elements addressing the 

reasonable progress requirements for 

Independence, we conclude that we 

would not be able to incorporate the 

Entergy alternative proposal into the 

final FIP as a way of meeting the BART 

requirement for White Bluff for the 

reasons already discussed above.96

Similarly, we also conclude that we 

cannot consider Entergy’s proposal to 

meet the reasonable progress 

requirements with respect to 

Independence if Independence is 

considered in isolation. SO2 emissions 

are the primary driver of regional haze 

in Arkansas’ Class I areas on the 20% 

worst days and Independence is the 

second largest source of SO2 emissions 

in Arkansas.97 As explained in our 

proposal, our consideration of the four 

reasonable progress factors and 

consideration of visibility impacts and 

visibility improvement of controls for 

Independence revealed that dry 

scrubbers on Independence Units 1 and 

2 are cost effective. These controls 

would provide significant visibility 

improvement as projected by our 

CALPUFF modeling focusing on the 

98th percentile impacts from the source. 

We also discuss in section V.J. of this 

final rule and in our RTC document that 

the results of Entergy’s CAMx 

photochemical modeling, which 

estimates the visibility impacts from 

Independence during the average of the 

20% worst days, confirm and provide 

additional support to our determination 

that Independence significantly impacts 

visibility at Arkansas’ Class I areas. 

Since Entergy’s alternative proposal 

includes minimal SO2 control for 

Independence, thus omitting controls 

that we found to be cost effective and 

that are anticipated to result in 

considerable visibility benefits at 

Arkansas’ Class I areas, we conclude 

that the elements of Entergy’s 

alternative proposal that are specific to 

Independence do not satisfy the 

reasonable progress requirements. 

We recognize that ceasing coal 

combustion at White Bluff Units 1 and 

2 could result in greater nonair 

environmental benefits and in more 

emission reductions of mercury and 

other hazardous air pollutants and CO2/ 

CO2e than our proposed FIP. However, 

in assessing Entergy’s alternative 

proposal, we do not find it necessary to 

weigh the nonair quality environmental 

benefits with the other statutory factors 

since we ultimately find that we cannot 

accept Entergy’s alternative proposal 

because it does not satisfy the 

requirements of the Regional Haze Rule. 

As discussed earlier in our response, we 

conclude that Entergy’s proposal does 

not satisfy the requirements to be 

considered a better-than-BART 

alternative under sections 308(e)(2) and 

308(e)(3); does not satisfy the sourcespecific BART requirements under 

section 308(e)(1) for White Bluff; does 

not satisfy the reasonable progress 

requirements under section 308(d)(1); 

and does not provide for the same 

visibility benefits as the FIP, while 

delaying a majority of the visibility 

benefits until several years later than the 

FIP. For these reasons, we cannot adopt 

Entergy’s alternative approach in lieu of 

our FIP. 

In response to Entergy’s comment 

regarding the cost to install dry FGD and 

as discussed in more detail in our RTC 

document, we have revised our cost 

calculations of SO2 controls for White 

Bluff Units 1 and 2 in response to the 

comments received on our initial cost 


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98Based on our revised cost analysis, we have 

found that dry scrubbers on White Bluff are 

estimated to cost $2,565/SO2 ton removed at Unit 

1 and $2,421/SO2 ton removed at Unit 2. 

99See 80 FR at 18972, 18974. Our FIP proposal 

provides a detailed discussion of the visibility 

improvement of these controls based on our 

CALPUFF modeling. 

100Based on our revised cost analysis, we have 

found that dry scrubbers on Independence are 

estimated to cost $2,853/SO2 ton removed at Unit 

1 and $2,634/SO2 ton removed at Unit 2. After 

revising our cost estimates, we continue to believe 

that these controls are cost effective. 

101 80 FR 24872. 

102This means 2 out of the 21 days that are the 

20% worst of the days with IMPROVE monitoring 

data. 

analysis.98 As we discuss in more detail 

elsewhere in this final rule, based on 

our consideration of the five BART 

factors, we have determined that 

controls consistent with dry scrubber 

and LNB/SOFA installation are BART 

for White Bluff Units 1 and 2. After 

revising our cost estimates, we continue 

to believe that dry scrubber controls and 

LNB/SOFA controls are cost effective at 

White Bluff Units 1 and 2 and would 

result in significant visibility 

improvement at Arkansas’ Class I areas 

based on our CALPUFF modeling of the 

98th percentile visibility impacts from 

the facility.99

As we discuss in more detail 

elsewhere in this final rule, based on 

our consideration of the four reasonable 

progress factors and of the visibility 

impacts and visibility improvement of 

controls on Independence, we have 

determined that dry scrubbers and LNB/ 

SOFA controls on Independence Units 1 

and 2 are necessary to make reasonable 

progress at Arkansas’ Class I areas. We 

have also revised our cost calculations 

of SO2 controls for these units in 

response to the comments received on 

our initial cost analysis, and we 

continue to believe that both dry 

scrubber and LNB/SOFA controls are 

cost effective.100 We also find that these 

controls on Independence would 

provide significant visibility 

improvement as projected by our 

CALPUFF modeling that focuses on the 

98th percentile impacts from the 

facility.101 Additionally, the CAMx 

photochemical modeling submitted by 

Entergy shows that the contribution to 

visibility impairment due to baseline 

emissions from the Independence 

facility alone are projected to be 

approximately 1.3% of the total 

visibility impairment during the average 

20% worst days in 2018 at each 

Arkansas Class I area. We consider this 

to be a significant contribution to 

visibility impairment at each Class I 

area and a large portion (approximately 

one-third) of the total contribution from 

all Arkansas point sources. The results 

of Entergy’s CAMx modeling confirm 

and provide additional support to our 

determination that Independence 

significantly impacts visibility at 

Arkansas’ Class I areas. While the 

majority of the visibility impacts due to 

Independence on the 20% worst days 

are due to SO2, we note that NOX

emissions from the facility also have 

impacts on the 20% worst days. 

Entergy’s CAMx modeling shows that 

nitrate from Independence is 

responsible for 30–40% of the visibility 

impairment in Arkansas’ Class I areas 

on 2 of the 20% worst days.102 We 

expect that installation of cost-effective 

NOX controls on Independence would 

provide visibility improvement on this 

portion of the 20% worst days, and as 

such, are requiring both SO2 and NOX

controls under the reasonable progress 

requirements. 

We are requiring White Bluff Units 1 

and 2 under BART and Independence 

Units 1 and 2 under reasonable progress 

to each meet an SO2 emission limit of 

0.06 lb/MMBtu on a 30 boiler-operatingday rolling average. We are requiring 

White Bluff Units 1 and 2 under BART 

and Independence Units 1 and 2 under 

reasonable progress to each meet a NOX

emission limit of 0.15 lb/MMBtu on a 30 

boiler-operating-day rolling average, 

where the average is to be calculated by 

including only the hours during which 

the unit is dispatched at 50% or greater 

of maximum capacity. In addition, we 

are requiring White Bluff Units 1 and 2 

under BART and Independence Units 1 

and 2 under reasonable progress to each 

meet a NOX emission limit of 671 lb/hr 

on a rolling 3-hour average, where the 

average is to be calculated by including 

emissions only for the hours during 

which the unit was dispatched at less 

than 50% of the unit’s maximum heat 

input rating (i.e., hours when the heat 

input to the unit is less than 4,475 

MMBtu). 

We do note that if Arkansas submits 

a regional haze SIP revision to replace 

our FIP, the state has the discretion to 

consider an approach to address the 

BART requirements for White Bluff that 

involves ceasing coal combustion at 

Units 1 and 2 by 2027/2028, but an 

approvable SIP revision must also 

include consideration and evaluation of 

DSI as a possible interim BART control 

option. With respect to Independence, a 

strategy that includes controls for 

Independence similar to the elements of 

Entergy’s alternative proposal that are 

specific to White Bluff (i.e., interim SO2

controls, ceasing coal combustion in the 

near future, and NOX controls) would 

also have potential merit with respect to 

addressing the reasonable progress 

requirements for Independence Units 1 

and 2. The state may consider 

submitting a SIP revision that includes 

such a strategy for Independence to 

replace our FIP. 

With regard to the comment that 

Entergy’s alternative multi-unit strategy 

would ensure that Arkansas’ Class I 

areas remain below the URP glidepath, 

we discuss in section V.C. of this final 

rule and in our RTC document that 

being on or below the URP glidepath 

does not mean that the BART 

requirements for White Bluff Units 1 

and 2 and the reasonable progress 

requirements for Independence Units 1 

and 2 are automatically satisfied. 

Comment: Several commenters noted 

that as part of a multi-unit plan to 

improve visibility and to better manage 

its generation assets for reliability and 

costs, Entergy proposed in comments 

submitted to EPA to cease burning coal 

at White Bluff Units 1 and 2 by 2027 

and 2028, one unit per year, and is 

prepared to take an enforceable 

commitment to that effect. The 

commenters stated that the CAA and the 

Regional Haze Rule require EPA and 

states to consider the remaining useful 

life of a source in BART determinations, 

which factors into the cost of 

compliance in the BART analysis. The 

commenters argue that as a result of 

Entergy’s alternative proposal, EPA’s 

proposed BART determination for 

White Bluff Units 1 and 2 has been 

rendered inapplicable, requiring EPA to 

undertake a new BART analysis to 

address the now reduced remaining 

useful coal-fired life of the units. The 

commenters noted that comments 

submitted by Entergy contain a revised 

dry FGD cost analysis from Sargent & 

Lundy (S&L) that takes into account 

current costs for dry FGD installation 

and argue that when the appropriate dry 

scrubber costs from the S&L analysis are 

considered, operating the dry FGD 

systems at White Bluff for only 6 or 7 

years would result in a cost 

effectiveness of over $7,500 to $8,500 

per ton at the White Bluff units, which 

is several times higher than EPA 

estimates and not cost effective. 

Response: Entergy’s comments 

propose a multi-unit strategy as an 

alternative to the proposed FIP. As 

discussed above, we do not interpret 

Entergy’s comments submitted during 

the comment period as requesting that 

we adopt the elements in its alternative 

that are unique to White Bluff as an 

alternative to our proposed BART 

emission limits for the facility unless we 

also conclude that the remaining 

elements address any reasonable 

progress requirements for 


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103See Appendix Y to 40 CFR part 51— 

Guidelines for BART Determinations Under the 

Regional Haze Rule, section IV.D.4.k. 

104Additionally, as discussed above, Entergy did 

not submit sufficient information to demonstrate 

that there are no additional SO2 control measures, 

such as DSI, that constitute BART even in light of 

a limited remaining useful life for White Bluff. 

105Available at http://www.adeq.state.ar.us/air/

planning/pdfs/ar_5yr_prog_rep_review-final-6-2- 

2015.pdf. 106 77 FR 14604, 14629. 

Independence. As we discuss in a 

previous response, we do not find that 

the comprehensive multi-unit 

alternative proposal as presented by the 

company satisfies the BART 

requirements for White Bluff Units 1 

and 2 and the reasonable progress 

requirements for Independence Units 1 

and 2. A chief element of Entergy’s 

alternative is its proposal to cease coal 

combustion at White Bluff Units 1 and 

2. It is unclear whether this would mean 

the shutdown or the repowering of 

White Bluff Units 1 and 2. Regardless of 

this ambiguity, a number of commenters 

have argued that because of Entergy’s 

proposal, we should use a shorter 

remaining life in assessing the costs of 

controls at White Bluff. If we were to 

assume that Entergy were proposing 

changes at White Bluff regardless of our 

action regarding Independence, we 

could include in our final FIP an 

enforceable requirement for the 

shutdown (or repowering) and take that 

change into consideration as part of a 

BART determination. The BART 

Guidelines state that where unit 

shutdown affects the BART 

determination, the shutdown date 

should be assured by a federally or 

state-enforceable restriction preventing 

further operation.103 Although we could 

include such a requirement in our FIP, 

the comments we received from Entergy 

during the public comment period do 

not indicate that it intends to cease coal 

combustion at White Bluff Units 1 and 

2 at this time absent a broader 

agreement on appropriate controls for 

both White Bluff and Independence. As 

such, we do not consider it appropriate 

to include a requirement in our FIP to 

cease coal combustion at White Bluff 

Units 1 and 2 in our rule unless we were 

to also accept the Entergy proposal as 

meeting all requirements with respect to 

Independence.104 Therefore, we 

consider it appropriate to assume a 

remaining useful life of 30 years for 

White Bluff Units 1 and 2 when 

determining BART for these units. We 

address specific comments regarding the 

White Bluff cost analysis in the section 

of this final rule where we discuss cost 

issues. 

C. Reasonable Progress Goals and 

Reasonable Progress Analysis 

Comment: Several commenters stated 

that EPA lacks evidence of a sufficient 

need to evaluate additional controls 

under reasonable progress for Arkansas 

point sources. These commenters 

argued that before evaluating controls 

under reasonable progress, EPA must 

first determine that further actions are 

necessary in Arkansas beyond BART to 

ensure that visibility improvement is 

continuing on or below the glide path 

for each affected Class I area. These 

commenters cited to the CAA and EPA 

guidance which they believe support 

their position that reductions beyond 

BART should not be required because 

the impacted Class I areas are at or 

below their glide paths. The 

commenters also pointed to ADEQ’s 

‘‘State Implementation Plan Review for 

the Five-Year Regional Haze Progress 

Report’’ 105 as evidence that Caney 

Creek and Upper Buffalo will be below 

the glide path in 2018. They claimed 

that EPA ignores ADEQ’s Five-Year 

Progress SIP revision, which they 

argued demonstrates that Arkansas has 

achieved 73% of the 2018 RPG it 

established for Caney Creek (3.88 dv of 

improvement) and 66% of the 2018 RPG 

it established for Upper Buffalo (3.75 dv 

of improvement). The commenters 

argued that as a result of emission 

reductions achieved through regional 

and national programs, including 

MATS, CAIR, and CSAPR, future Clean 

Air Act programs such as 

implementation of the 1-hour SO2

NAAQS, the revised ozone NAAQS and 

the Clean Power Plan, as well as the 

reductions for White Bluff and 

Independence that Entergy is proposing 

and the BART controls that EPA has 

proposed for the other sources in 

Arkansas, there is every reason to 

project continued improvement in 

visibility in Caney Creek and Upper 

Buffalo well beyond 2018. 

Response: EPA disagrees with the 

comment that we can only evaluate 

controls under reasonable progress if 

further controls beyond BART are 

needed to be on or below the URP 

glidepath for a Class I area. Specifically, 

commenters cited section 169A(b)(2) of 

the Act, which requires regional haze 

regulations to ‘‘contain such emission 

limits, schedules of compliance and 

other measures as may be necessary to 

make reasonable progress toward 

meeting the national goal.’’ These 

commenters interpret the term 

‘‘reasonable progress’’ to be defined as 

being on or below the URP glidepath, 

and that as long as a Class I area is on 

or below the URP glidepath, additional 

controls are not necessary under the 

reasonable progress requirements. This 

interpretation is incorrect and does not 

take into account other, more explicit, 

statutory and regulatory language. The 

CAA requires reasonable progress 

determinations to be based on 

consideration of ‘‘the costs of 

compliance, the time necessary for 

compliance, the energy and nonair 

quality environmental impacts of 

compliance, and the remaining useful 

life of any existing source subject to 

such requirements.’’ CAA section 

169A(g)(1). The regional haze 

regulations under 40 CFR 

51.308(d)(1)(i)(A) also require 

consideration of these four statutory 

factors in establishing the RPGs and a 

demonstration showing how these 

factors were taken into account. 

We commonly refer to the evaluation 

of these four statutory factors as the 

‘‘four-factor analysis’’ or ‘‘reasonable 

progress analysis.’’ The statute and 

regulations are both clear that the states 

or EPA in a FIP have the authority and 

obligation to evaluate the four 

reasonable progress factors and that the 

decision regarding the controls required 

to make reasonable progress and the 

establishment of the RPG must be based 

on these factors identified in the CAA 

section 169A(g)(1) and the Regional 

Haze regulations under 

§ 51.308(d)(1)(i)(A). While the 

regulations require that a state must also 

consider the URP glidepath in 

establishing the RPGs, this should not 

be interpreted to mean that the URP can 

or should be automatically adopted as 

the RPG without completing the 

requisite analysis of the four statutory 

factors. It also should not be interpreted 

to mean that a set of controls sufficient 

to achieve the URP is automatically 

sufficient for an approvable long-term 

strategy. Clearly, a state’s obligation to 

set reasonable progress goals based on 

CAA section 169A(g)(1) and 

§ 51.308(d)(1) applies in all cases, 

without regard to the Class I area’s 

position on the URP. Since an 

evaluation of the factors is required 

regardless of the Class I area’s position 

on the glidepath, this necessarily means 

that the CAA and the Regional Haze 

regulations envisioned that controls 

could be required under reasonable 

progress even when a Class I area is on 

or below the URP glidepath. There is 

nothing in the CAA or Regional Haze 

regulations that suggests that a State’s 

obligation, or EPA’s in a FIP, to ensure 

reasonable progress can be met by just 

meeting the URP.106

Some commenters also argue that the 

EPA’s 2007 Reasonable Progress 


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107 ‘‘Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program,’’ at 4–1. 

108 80 FR at 18992. 

109 64 FR 35714, 35732. 

110 77 FR at 14629. 

111We anticipate taking action on ADEQ’s Five 

Year Progress Report SIP revision in a separate, 

future action. 

Guidance suggests that controls under 

reasonable progress are not necessary if 

a Class I area is on or below the URP 

glidepath. The specific part of the 

Reasonable Progress Guidance that some 

of the commenters point to states that: 

Given the significant emissions reductions 

that we anticipate to result from BART, the 

CAIR, and the implementation of other CAA 

programs, including the ozone and PM2.5

NAAQS, for many States [determining the 

amount of emission reductions that can be 

expected from identified sources or source 

categories as a result of requirements at the 

local, State, and federal levels during the 

planning period of the SIP and the resulting 

improvements in visibility at Class I areas] 

will be an important step in determining 

your RPG, and it may be all that is necessary 

to achieve reasonable progress in the first 

planning period for some States.107

We see nothing in the Reasonable 

Progress Guidance indicating that 

additional controls can only be required 

if further action beyond BART is needed 

to remain on or below the URP 

glidepath. Nor do we see anything in the 

Reasonable Progress Guidance 

indicating that a state (or EPA) is 

exempt from completing the four factor 

analysis if a Class I area is on or below 

the URP glidepath. As discussed above, 

the CAA and Regional Haze regulations 

are clear that an evaluation of the four 

statutory factors is required, and this 

requirement applies regardless of the 

Class I area’s position on the glidepath. 

We noted in our FIP proposal that the 

preamble to the Regional Haze Rule 

states that the URP does not establish a 

‘‘safe harbor’’ for the state in setting its 

progress goals: 

If the State determines that the amount of 

progress identified through the [URP] 

analysis is reasonable based upon the 

statutory factors, the State should identify 

this amount of progress as its reasonable 

progress goal for the first long-term strategy, 

unless it determines that additional progress 

beyond this amount is also reasonable. If the 

State determines that additional progress is 

reasonable based on the statutory factors, the 

State should adopt that amount of progress 

as its goal for the first long-term strategy.108

Being projected to meet the URP for 

2018 does not justify dismissing the 

analysis required under CAA section 

169A(g)(1) and § 51.308(d)(1) in 

determining reasonable progress and 

establishing the RPGs, nor does it 

automatically mean that no additional 

controls beyond BART are required 

under reasonable progress. The URP is 

an analytical requirement created by 

regulation to ensure that states consider 

the possibility of setting an ambitious 

reasonable progress goal. Its purpose is 

to complement, not usurp, the 

reasonable progress analysis. Based on 

the analysis of the four statutory factors 

required under the CAA and Regional 

Haze regulations, a state (or EPA in a 

FIP) may determine that a greater or 

lesser amount of visibility improvement 

than what is reflected in the URP is 

necessary to demonstrate reasonable 

progress.109 Based on our analysis of the 

factors under CAA section 169A(g)(1) 

and § 51.308(d)(1), along with 

consideration of the visibility 

improvement of controls, we 

determined that there are reasonable 

controls available for Independence that 

would be cost-effective and would 

result in meaningful visibility benefit at 

Arkansas’ Class I areas. Because we 

have identified that additional progress 

(beyond the amount reflected in the 

URP) is reasonable based on the 

statutory factors and our consideration 

of the visibility impacts, we are required 

to adopt that amount of progress under 

the reasonable progress requirements. It 

is for this reason, we are requiring 

controls on Independence. It is not, as 

some commenters contend, ‘‘for the sole 

purpose of achieving emissions 

reductions.’’ 

We note that our conclusion here is 

consistent with our final action on the 

Arkansas Regional Haze SIP, where we 

disapproved Arkansas’ RPGs 

specifically because the state 

established its RPGs without conducting 

an evaluation of the four statutory 

factors and did so based on the fact that 

its Class I areas are below the URP 

glidepath. In the preamble to our final 

action on the Arkansas Regional Haze 

SIP, we were clear that an evaluation of 

the four statutory factors is required 

regardless of the Class I area’s position 

on the URP glidepath: 

[B]eing on the ‘‘glidepath’’ does not mean 

a state is allowed to forego an evaluation of 

the four statutory factors when establishing 

its RPGs. Based on an evaluation of the four 

statutory factors, states may determine that 

RPGs that provide for a greater rate of 

visibility improvement than would be 

achieved with the URP for the first 

implementation period are reasonable.110

Our final action on the Arkansas 

Regional Haze SIP was published in the 

Federal Register on March 12, 2012, 

and became effective on April 11, 2012. 

We reiterate in this final action that the 

CAA and Regional Haze regulations 

require an analysis of the four 

reasonable progress factors regardless of 

a Class I area’s position on the URP and 

that being below the glide path does not 

automatically mean that no controls are 

necessary under reasonable progress. 

With regard to the comment 

contending that we are ignoring data 

from ADEQ’s Five-Year Progress Report 

SIP revision, we note that Arkansas 

submitted the first 5-year report to EPA 

in June 2015, and that we are not 

addressing that SIP revision within this 

action.111 The 5-year progress report is 

a separate requirement from the regional 

haze SIP required for the first and 

subsequent planning periods, and it has 

separate content and criteria for review. 

We are therefore not obligated to 

consider or take action on the 5-year 

progress report at the same time we 

promulgate our FIP. 

We acknowledge that recent 

IMPROVE monitoring data indicate 

there has been visibility improvement in 

Arkansas’ Class I areas. But even 

assuming that the current trend in 

visibility improvement will continue, as 

the commenter argues, this does not 

divest us from our authority and 

obligation to conduct a reasonable 

progress analysis, nor does it justify the 

dismissal of controls for Independence 

that we have determined, pursuant to 

that analysis, are cost-effective and 

would result in meaningful visibility 

benefit at Arkansas’ Class I areas. The 

commenters point out that even without 

the BART and reasonable progress 

controls required by our FIP, Caney 

Creek has achieved 73% and Upper 

Buffalo has achieved 66% of their 

respective 2018 RPGs established by 

Arkansas based on 5-year average data 

from IMPROVE monitors as of 2011. 

However, even if we had approved these 

RPGs (which we did not), achieving or 

being projected to achieve the RPG does 

not necessarily demonstrate that a state 

has satisfied its requirements under 

BART and reasonable progress. The 

state or EPA must complete the requisite 

analyses to determine appropriate 

controls and emission limits under the 

BART and reasonable progress 

requirements, and must adopt and 

enforce these controls and emission 

limits. The numeric RPGs are calculated 

by taking into account the visibility 

improvement anticipated from these 

enforceable emission limitations and 

other control measures (including 

BART, reasonable progress, and other 

‘‘on the books’’ controls). The Regional 

Haze Rule provides that these emission 

limitations and control measures are 

what is enforceable, not the RPGs 


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112 64 FR 35714, 35733. 

113The RPGs are intended to provide the state or 

EPA’s best estimate of the amount of visibility 

improvement in deciviews anticipated for each 

Class I area over the planning period of the SIP or 

FIP. 

114 77 FR 14604. 

115 64 FR at 35733. 

116See 51.308(d)(1)(v). 

themselves.112 Thus, the RPGs are 

intended to provide a degree of 

transparency regarding the rate of 

improvement in visibility anticipated 

for each Class I area over the planning 

period of the SIP.113

As noted above, we disapproved 

Arkansas’ RPGs in our March 12, 2012 

final action on the Arkansas Regional 

Haze SIP 114 because the state did not 

complete the required four-factor 

analysis in establishing the RPGs. 

Further, the state’s RPGs were based on 

BART determinations that were not in 

accordance with the CAA and Regional 

Haze regulations. As such, the State’s 

RPGs are not a reflection of the controls 

necessary to make reasonable progress, 

and any arguments upholding or 

suggesting that the state’s RPGs are 

appropriate or adequate are outside the 

scope of this action. That Arkansas’ 

Class I areas are on track to achieve the 

disapproved RPGs by 2018 does not 

mean that the reasonable progress 

requirements have been satisfied, nor 

does it justify no additional controls 

under reasonable progress. 

Comment: Some commenters argued 

that our FIP proposal was improper 

because it adopted an individual sourcebased approach to setting RPGs, and 

that this is inconsistent with the CAA. 

Another commenter claimed that EPA 

failed to explain how factors required to 

be considered in setting the RPGs, 

which are themselves not enforceable, 

could somehow be used to require 

specific enforceable limits for a single 

plant. 

Response: While our FIP does 

consider and ultimately apply controls 

on an individual source basis to assure 

reasonable progress, this is consistent 

with the CAA, our regulations, and past 

EPA guidance. The four statutory factors 

under CAA Section 169A(g) and 40 CFR 

51.308(d)(1)(i)(A) are directed to the 

listed possible features or consequences 

of potential emission control measures 

for sources, including individual 

stationary sources. The CAA and the 

Regional Haze regulations expressly set 

forth that the reasonable progress 

analysis must consider the 

‘‘compliance’’ time and costs for 

‘‘potentially affected sources.’’ A state 

determines the rate of progress that is 

reasonable for a Class I area after taking 

into account the four statutory factors— 

as applied to specific sources or groups 

of sources—to determine what 

additional controls should be required 

in its regional haze SIP. Thus, 

individual stationary sources may be 

subject to emission limits and source 

specific analysis when determining 

whether additional controls are 

necessary to make reasonable progress. 

The commenter’s suggestion that 

because the RPGs are not themselves 

enforceable we cannot require specific 

enforceable limits for a single plant is 

not consistent with the requirement that 

each regional haze SIP or FIP include 

enforceable emissions limitations as 

necessary to ensure that the SIP or FIP 

will provide reasonable progress toward 

the national goal of natural visibility 

conditions. The numeric RPGs 

established by the state or EPA 

represent the best estimate of the degree 

of visibility improvement that will 

result in 2018 from changes in 

emissions inventories, changes driven 

by the particular set of control measures 

the state has adopted in its regional haze 

SIP or EPA in a regional haze FIP to 

address visibility, as well as all other 

enforceable measures expected to 

reduce emissions over the period of the 

SIP from 2002 to 2018.115 Thus, the 

RPGs are intended to provide a degree 

of transparency regarding the rate of 

improvement in visibility anticipated 

for each Class I area over the planning 

period of the SIP. But the RPGs 

themselves are not enforceable.116 EPA 

cannot enforce an RPG in the sense of 

seeking to apply penalties on a state for 

failing to meet the RPG or obtaining 

injunctive relief to require a state to 

achieve its RPG. However, the long-term 

strategy can and must contain emission 

limits and other control measures that 

apply to specific sources under the 

reasonable progress requirements, and 

that are themselves enforceable. The fact 

that the RPGs are not enforceable does 

not mean that we cannot conduct a 

source-specific evaluation of the 

reasonable progress factors or require 

source-specific emission limits under 

the reasonable progress requirements. 

Comment: EPA treated Independence 

Units 1 and 2 as if they were subject-toBART units by ignoring whether 

controls at the units are needed to 

improve visibility and looking only at 

whether controls are cost effective. 

EPA’s failure to assess and document 

the contribution to visibility impairment 

at any relevant Class I area from any 

Arkansas point source, including 

Independence, is contrary to past 

rulemakings and is inconsistent with 

the detailed approach taken by EPA 

Region 6 in its promulgation of the 

Texas Regional Haze FIP. The 

Independence plant was apparently 

singled out by EPA for additional 

pollution controls under reasonable 

progress, while other non-BART 

emission sources were not. EPA does 

not provide any explanation for its 

selective treatment in this case other 

than noting that the Independence is 

among the top three largest point 

sources in the state. EPA’s justification 

for imposing SO2 and NOX emission 

limits on Independence is not based on 

rational policy, legal, or environmental 

grounds and, as a result, it is arbitrary 

and capricious. EPA’s primary 

justification for proposing reasonable 

progress limits at Independence is that 

‘‘it would be unreasonable to ignore a 

source representing more than a third of 

the State’s SO2 emissions and a 

significant portion of NOX point source 

emissions.’’ EPA further supports its 

conclusion that emission limits based 

on the installation of major control 

technology are justified based on a 

finding that the proposed controls at 

Independence are cost effective. 

However, the fact that a source, which 

is not subject to BART, may have 

significant SO2 or NOX emissions, or 

that it would be cost effective to control 

such emissions, is irrelevant for 

reasonable progress purposes. This is an 

inapplicable and inadequate 

justification to identify sources for 

control under a reasonable progress 

analysis. EPA did not appropriately 

analyze which sources, if any, should be 

controlled for reasonable progress and 

did not follow the procedures it has 

regularly used in other regional haze 

FIPs. 

Response: We did not treat 

Independence as if it were a subject-toBART source, nor did we ignore 

whether controls at the facility are 

needed to improve visibility, or only 

look at whether controls are cost 

effective. Under the CAA and 40 CFR 

51.308(d)(1), we must consider the 

following four factors in our reasonable 

progress analysis: (1) The costs of 

compliance; (2) the time necessary for 

compliance; (3) the energy and nonair 

quality environmental impacts of 

compliance; and (4) the remaining 

useful life of any potentially affected 

sources. These are the factors we took 

into consideration in our proposal. As 

we discuss in our proposal and 

elsewhere in this final rule, although 

visibility is not one of the four 

mandatory factors explicitly listed for 

consideration under CAA section 

169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), 

states or EPA have the option of 

considering the projected visibility 


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117CAMx source apportionment modeling was 

submitted to us by Entergy Arkansas Inc. during the 

comment period. This modeling shows that 

Independence has significant visibility impacts in 

Arkansas Class I areas on the 20% worst days, and 

further supports our decision to require controls for 

Independence under reasonable progress. We 

discuss Entergy Arkansas Inc.’s photochemical 

modeling and the visibility impacts due to SO2 and 

NOX from Independence on the 20% worst days 

elsewhere in this final rule. 118 80 FR at 18992. 

119 ‘‘Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program,’’ at 4–2. 

120See 80 FR 18944, 18989. 

benefits of controls in determining if the 

controls are necessary to make 

reasonable progress. We modeled both 

the baseline visibility impacts from the 

Independence facility and the visibility 

benefit of controls using CALPUFF 

dispersion modeling. Based on our 

consideration of the four reasonable 

progress factors as well as the baseline 

visibility impacts from Independence 

and the visibility improvement of 

potential controls, we determined that 

reasonable controls for SO2 and NOX are 

available for Independence Units 1 and 

2 that are cost effective and would result 

in a large amount of visibility 

improvement in Arkansas’ Class I areas 

in terms of the 98th percentile impacts 

from the source.117 Therefore, the claim 

that we ignored whether controls at the 

units are needed to improve visibility is 

incorrect. 

We also disagree that the fact that a 

non-BART source has significant SO2 or 

NOX emissions, or that it would be costeffective to control such emissions, is 

irrelevant in determining what sources 

to take a closer look at and evaluate 

under reasonable progress. As noted 

above, the cost of compliance is one of 

the statutory factors that EPA is required 

to consider in a reasonable progress 

analysis, meaning that the cost 

effectiveness of potential controls is not 

irrelevant for reasonable progress 

purposes. Significant SO2 or NOX

emissions from a source is generally an 

indication that there may be significant 

visibility impacts at nearby Class I areas 

and that installation of more effective 

controls, if any are available, may result 

in substantial emissions reductions and 

meaningful visibility improvement. As 

noted above, states and EPA have the 

option of considering the projected 

visibility benefits of controls in 

determining if the controls are necessary 

to make reasonable progress. Therefore, 

we find that consideration of a source’s 

emissions and whether it would be costeffective to control such emissions is 

appropriate and relevant for reasonable 

progress purposes. 

The commenter makes the incorrect 

claim that our primary justification for 

imposing emission limits under 

reasonable progress for Independence 

Units 1 and 2 is that it would be 

unreasonable to ignore a source 

representing more than a third of the 

state’s SO2 emissions and a significant 

portion of NOX point source emissions. 

While we did state in our FIP proposal 

that it would be unreasonable to ignore 

a source representing more than a third 

of the state’s SO2 emissions and a 

significant portion of NOX point source 

emissions, the commenters took this 

statement out of context. The full 

citation from our FIP proposal 

referenced by the commenters is the 

following: 

We believe it is appropriate to evaluate 

Entergy Independence even though Arkansas 

Class I areas and those outside of Arkansas 

most significantly impacted by Arkansas 

sources are projected to meet the URP for the 

first planning period. This is because we 

believe that in determining whether 

reasonable progress is being achieved, it 

would be unreasonable to ignore a source 

representing more than a third of the State’s 

SO2 emissions and a significant portion of 

NOX point source emissions.118

As evidenced by the full citation from 

our FIP proposal, the fact that we 

considered it unreasonable to ignore a 

source representing more than a third of 

the State’s SO2 emissions and a 

significant portion of NOX point source 

emissions was our primary justification 

for looking more closely and evaluating 

the Independence plant in our 

reasonable progress analysis. It was not, 

as the commenter contends, our 

justification for imposing controls on 

Independence. As we discuss in our FIP 

proposal and elsewhere in this final 

action, our decision to require controls 

on Independence is based on our 

analysis under § 51.308(d)(1), as 

required by the CAA and Regional Haze 

Rule. 

We do not agree with the commenter’s 

allegation that we did not appropriately 

analyze what sources, if any, should be 

controlled under reasonable progress. 

To the extent that the commenter 

contends that our process for 

determining which sources should be 

evaluated under reasonable progress 

was incorrect because we did not 

conduct photochemical modeling, such 

argument is incorrect. To the extent that 

the commenter contends that we treated 

the Independence facility like a BART 

source because we evaluated it under 

the reasonable progress requirements 

without conducting photochemical 

modeling to identify potential sources to 

evaluate under reasonable progress, this 

is also incorrect. We are not required to 

conduct photochemical modeling in a 

reasonable progress analysis. Our 2007 

Reasonable Progress Guidance states 

that ‘‘The RHR gives States wide 

latitude to determine additional control 

requirements, and there are many ways 

to approach identifying additional 

reasonable measures; however, you 

must at a minimum, consider the four 

statutory factors.’’ 119 The states or EPA 

in the context of a FIP have wide 

discretion in deciding what approaches, 

methods, and tools to use in identifying 

source categories, specific point sources, 

or pollutants to evaluate for additional 

controls under the reasonable progress 

requirements, provided that a 

reasonable rationale for the approach 

used is provided. There are a number of 

different approaches states or EPA in 

the context of a FIP have used in 

identifying sources for reasonable 

progress evaluation, but they usually 

center around the general premise of 

evaluating the biggest sources and/or 

the biggest impactors on visibility. 

While the states or EPA have the 

discretion to consider visibility in a 

reasonable progress analysis, 

photochemical modeling is not required 

for purposes of conducting a reasonable 

progress analysis. 

Our FIP proposal provided a detailed 

explanation of how we determined what 

sources to evaluate for controls under 

reasonable progress, and we provided a 

reasonable rationale for the approach we 

used. The first step in our analysis 

involved determining what source 

categories or specific point sources it 

would be appropriate to look at more 

closely and evaluate under the 

reasonable progress requirements in 

§ 51.308(d)(1) to determine if additional 

controls are necessary. We explained in 

our proposal that it was appropriate to 

focus our analysis on point sources 

since the other source categories (i.e., 

natural, on-road, non-road, and area) 

each contribute a much smaller 

proportion of the total light extinction at 

each Class I area in Arkansas based on 

the CENRAP CAMx modeling.120 At 

Caney Creek, point sources contribute 

81.04 Mm¥1 out of a total light 

extinction of 133.93 Mm¥1 on the 

average across the 20% worst days in 

2002, or approximately 60.5% of the 

total light extinction. At Upper Buffalo, 

point sources contribute 77.80 Mm¥1

out of a total light extinction of 131.79 

Mm¥1 on the average across the 20% 

worst days in 2002, or approximately 

59% of the total light extinction. In 

comparison, area sources, which are the 

source category with the next highest 

contribution to the total light extinction 

at each Class I area, contribute 

approximately 13.3% of the total light 


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121See Arkansas Regional Haze SIP, Appendix 

8.1—‘‘Technical Support Document for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze State Implementation Plans,’’ 

sections 3.7.1 and 3.7.2. See the docket for this 

rulemaking for a copy of the Arkansas Regional 

Haze SIP. 

122See Arkansas Regional Haze SIP, Appendix 

8.1—‘‘Technical Support Document for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze State Implementation Plans,’’ section 

3.7.1 and 3.7.2. See the docket for this rulemaking 

for a copy of the Arkansas Regional Haze SIP. 

123 ‘‘Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program,’’ at 2–3 

and 3–1. 

124 80 FR at 18991. 

125See NEI 2011 v1. A spreadsheet containing the 

emissions inventory is found in the docket for our 

proposed rulemaking. 126 80 FR at 18992. 

extinction at Caney Creek and 15.5% at 

Upper Buffalo. The remaining source 

categories each contribute less than 6% 

of the total light extinction at each Class 

I area. Therefore, we concluded that it 

was appropriate to focus our analysis on 

point sources. 

The CENRAP CAMx modeling shows 

that on most of the 20% worst days in 

2002, total extinction was dominated by 

sulfate at both Caney Creek and Upper 

Buffalo.121 Additionally, total extinction 

at Caney Creek was dominated by 

nitrate on 4 of the days that comprise 

the 20% worst days in 2002 and a 

significant portion of the total extinction 

at Upper Buffalo on 2 of the days that 

comprise the 20% worst days in 2002 

was due to nitrate.122 The CENRAP 

CAMx modeling also shows that sulfate 

from point sources was responsible for 

approximately 54.8% of the total 

visibility impairment at Upper Buffalo 

and 56.1% at Caney Creek on the 20% 

worst days in 2002. Nitrate from point 

sources was responsible for 

approximately 3% of the total visibility 

impairment at each Class I area on the 

20% worst days in 2002. As such, 

although SO2 emissions are the primary 

contributor to regional haze in 

Arkansas’ Class I areas on the 20% 

worst days, NOX emissions are also a 

key contributor. Thus, consistent with 

our Guidance for Setting Reasonable 

Progress Goals Under the Regional Haze 

Program,123 we found it appropriate to 

evaluate both SO2 and NOX controls 

under reasonable progress. 

We explained in our FIP proposal that 

as a starting point in our analysis to 

determine whether additional controls 

on Arkansas point sources are 

reasonable in the first regional haze 

planning period, we examined the most 

recent SO2 and NOX emissions 

inventories for point sources in 

Arkansas (NEI 2011 v1).124 We reasoned 

that examination of the emissions 

inventories is appropriate because 

significant SO2 or NOX emissions from 

a source are generally an indication that 

it may be having significant visibility 

impacts at nearby Class I areas and that 

installation of controls may result in 

substantial emissions reductions and 

meaningful visibility improvement. We 

did not conduct photochemical 

modeling or other more exhaustive 

analyses to identify potential candidates 

to evaluate under reasonable progress, 

and while we recognize that this 

approach is different from the 

approaches and methods that we have 

used or approved in other regional haze 

actions, we find that the approach we 

are taking in this action is appropriate 

given the specific circumstances. In 

particular, our examination of the SO2

and NOX emissions inventories for 

Arkansas’ point sources revealed that 

the number of point sources that emit 

SO2 and NOX emissions is relatively 

small. Furthermore, a very small portion 

of the point sources in the state is 

responsible for a large portion of the 

statewide SO2 and NOX point source 

emissions. Specifically, White Bluff, 

Independence, and Flint Creek are 

collectively responsible for 

approximately 84% of the SO2 point 

source emissions and 55% of the NOX

point source emissions in the state. 

Consequently, addressing these sources 

under the regional haze program will 

address a large proportion of the 

visibility impacts due to Arkansas point 

sources. We are requiring SO2 and NOX

controls for White Bluff and Flint Creek 

under the BART requirements in this 

final action, which will substantially 

reduce emissions from these two 

facilities. The Independence Plant, 

which is not a subject-to-BART source, 

contributes approximately 36.2% of the 

total SO2 point source emissions in the 

state (30,398 SO2 tons out of total SO2

point source emissions of 83,883 SO2

tons, based on the 2011 NEI).125 This 

source also contributes approximately 

21.3% of the total NOX point source 

emission in the state (13,411 NOX tons 

out of total NOX point source emissions 

of 62,984 NOX tons). Based on this 

examination, we determined that the 

magnitude of emissions from the 

Independence Plant warranted further 

evaluation of the source to determine if 

it is a significant contributor to regional 

haze in Arkansas’ Class I areas and 

whether controls at the facility are 

needed based on an analysis under 

§ 51.308(d)(1). 

After White Bluff, Independence, and 

Flint Creek, the remaining point sources 

in the state have much lower SO2 and 

NOX emissions than these facilities. In 

other words, the magnitude of SO2 and 

NOX emissions from point sources in 

Arkansas drops off considerably after 

the top 3 emitters. We stated the 

following in our proposal: 

The fourth largest SO2 and NOX point 

sources in Arkansas are the Future Fuel 

Chemical Company, with emissions of 3,421 

SO2 tpy, and the Natural Gas Pipeline 

Company of America #308, with emissions of 

3,194 NOX tpy (2011 NEI). In comparison to 

the emissions of the top three sources, 

emissions from these two facilities are 

relatively small. Therefore, we are not 

proposing controls in this first planning 

period for these two facilities because we 

believe it is appropriate to defer the 

consideration of any additional sources 

besides Independence to future regional haze 

planning periods.126

Future Fuel Chemical Company, the 

point source with the fourth highest SO2

emissions (after White Buff, 

Independence, and Flint Creek), 

contributes approximately 4.1% of the 

total SO2 point source emissions in the 

state (3,420 SO2 tons out of total SO2

point source emissions of 83,883 SO2

tons, based on the 2011 NEI). The 

Natural Gas Pipeline Company of 

America #308, the point source with the 

fourth highest NOX emissions, 

contributes approximately 5.1% of the 

total NOX point source emission in the 

state 3,194 NOX tons out of total NOX

point source emissions of 62,984 NOX

tons, based on the 2011 NEI). Based on 

the much smaller magnitude of these 

sources’ emissions, we determined that 

the remaining point sources in the state 

are less likely to be significant 

contributors to regional haze, and thus 

did not warrant closer evaluation under 

reasonable progress in this planning 

period. As such, we found that it is 

appropriate to evaluate Independence 

for controls under reasonable progress. 

The claim that we arbitrarily singled out 

Independence and that we provided no 

explanation as to why we did not 

evaluate other point sources under 

reasonable progress is not supported by 

the record in this action. 

Because our examination of the 

Arkansas emissions inventory revealed 

that the number of point sources that 

emit SO2 and NOX emissions is 

relatively small and that a very small 

portion of the point sources in the state 

are responsible for a large portion of the 

statewide SO2 and NOX point source 

emissions, we concluded that 

photochemical modeling or other more 

exhaustive analyses that we have 

performed in other regional haze actions 

were unnecessary to identify point 

sources to evaluate under reasonable 

progress. In contrast, in states such as 

Texas, where the universe of point 


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127 81 FR 296. 128See 77 FR at 14629. 

129This means 2 out of the 21 days that are the 

20% worst of the days with IMPROVE monitoring 

data. 

sources is much larger and the 

distribution of SO2 and NOX emissions 

is very widespread, an evaluation of the 

state’s emissions inventory alone was 

not sufficient to reveal the best potential 

candidates for evaluation under 

reasonable progress. For this reason, we 

explained in our Texas Regional Haze 

FIP that due to the challenges presented 

by the geographic distribution and 

number of sources in Texas, the CAMx 

photochemical model was best suited 

for identifying sources to evaluate for 

reasonable progress controls.127 We did 

not encounter these challenges in the 

development of our reasonable progress 

analysis for Arkansas and therefore did 

not conduct photochemical modeling. 

We do note that while we did not 

conduct photochemical modeling to 

identify Arkansas point sources to 

evaluate under reasonable progress, 

Entergy conducted CAMx sourceapportionment modeling and submitted 

it during the comment period. Entergy’s 

CAMx source apportionment modeling 

showed that emissions from the 

Independence facility alone are 

projected to contribute approximately 

1.3% of the total visibility impairment 

in 2018 on the 20% worst days at each 

Arkansas Class I area. This is a large 

portion (approximately one-third) of the 

total contribution from all Arkansas 

point sources, and we consider it to be 

a significant contribution to visibility 

impairment Arkansas’ Class I areas on 

the 20% worst days. The CAMx 

modeling also showed that at Upper 

Buffalo, the Independence facility’s 

contribution to visibility impairment is 

greater than the contribution from all of 

the subject-to-BART sources addressed 

in this final action combined. In terms 

of deciviews, the average impact from 

Independence over the 20% worst days, 

based on Entergy’s CAMx modeling and 

adjusted to natural background 

conditions, is over 0.5 dv at the 

Arkansas Class I areas. The results of 

Entergy’s CAMx modeling confirm and 

provide additional support to our 

determination that Independence 

significantly impacts visibility at 

Arkansas’ Class I areas. 

Additionally, we note that because of 

the controls required during this 

planning period, we expect that the 

impact from the facilities in Arkansas 

that were not controlled and not 

specifically evaluated in the first 

planning period will become larger on 

a percentage basis. These sources will 

become the largest impacting sources 

and should be considered for analysis 

under reasonable progress in future 

planning periods. The methodology we 

used here thus allows a consistent 

procedure to identify facilities for 

additional control analysis in this and 

future planning periods and ensures 

continuing progress towards the goal of 

natural visibility conditions. 

To the extent the commenter contends 

that additional controls under 

reasonable progress cannot or should 

not be evaluated or required unless 

controls beyond BART are needed for 

Arkansas to be on or below the URP 

glidepath or to meet the RPGs 

established by the state (which, in the 

case of Arkansas, we disapproved in a 

previous final action), this is incorrect. 

As we discuss elsewhere in this section 

of the final rule and in our RTC 

document, there is nothing in the CAA 

or Regional Haze regulations that 

suggests that a State’s obligations to 

ensure reasonable progress can be met 

simply by being on or below the URP 

glidepath or meeting the state’s RPGs.128

Comment: EPA’s own analysis 

counsels against imposing additional 

controls on the Independence Plant. 

EPA asserts that CENRAP modeling 

shows that sulfate from all point sources 

is projected to contribute to 57% of the 

total light extinction at Caney Creek on 

the worst 20% days in 2018 and 43% of 

the total light extinction at Upper 

Buffalo. Nitrate from all point sources is 

projected to account for only 3% of the 

total light extinction at the Class I areas. 

However, the CENRAP modeling also 

projects that sulfate from Arkansas point 

sources will be responsible for only 

3.58% of the total light extinction at 

Caney Creek and 3.20% at Upper 

Buffalo. The contribution of nitrate from 

Arkansas point sources to visibility 

impairment is even more insignificant, 

accounting for only 0.29% of the total 

light extinction at Caney Creek and 

0.25% at Upper Buffalo. The 

Independence Plant’s share of emissions 

to this minimal contribution from 

Arkansas point sources is even smaller. 

Despite these very small contributions, 

EPA’s proposal concludes that SO2 and 

NOX controls at the Independence Plant 

are warranted and reasonable. EPA lacks 

evidence of a sufficient need to evaluate 

additional controls for Arkansas point 

sources and lacks a sufficient basis to 

justify additional controls. 

Response: The commenter appears to 

believe that the CENRAP modeling 

shows that the visibility impacts on the 

20% worst days from Arkansas point 

sources, and from Independence in 

particular, are very small. We disagree 

that these visibility impacts are 

insignificant. As we discuss above, 

Entergy’s CAMx source apportionment 

modeling showed that the contribution 

to visibility impairment due to 

emissions from the Independence 

facility alone are projected to be 

approximately 1.3% of the total 

visibility impairment during the 20% 

worst days in 2018 at each Arkansas 

Class I area. This is a large portion 

(approximately one-third) of the total 

contribution from all Arkansas point 

sources, and we consider this to be a 

significant contribution to visibility 

impairment. Entergy’s CAMx modeling 

also showed that at Upper Buffalo, the 

Independence facility’s contribution to 

visibility impairment is greater than the 

contribution from all of the subject-toBART sources addressed in this final 

action combined. In terms of deciviews, 

the average impact from Independence 

over the 20% worst days, based on 

Entergy’s CAMx modeling and adjusted 

to natural background conditions, is 

over 0.5 dv at the Arkansas Class I areas. 

The results from Entergy’s CAMx 

modeling confirm and provide 

additional support to our determination 

that the source significantly impacts 

visibility at Arkansas’ Class I areas and 

should be evaluated for controls under 

reasonable progress. 

As discussed in our proposal and 

elsewhere in this final rule, we have 

found that dry scrubbers for SO2 control 

are cost effective and are expected to 

provide significant visibility 

improvements to the facility’s 98th 

percentile visibility impacts as shown 

by our CALPUFF modeling. We have 

also found that NOX controls in the form 

of LNB/SOFA on Independence are very 

cost effective and are expected to 

provide considerable visibility 

improvements to the 98th percentile 

visibility impacts. 

Based on Entergy’s CAMx modeling, 

SO2 emissions are responsible for a 

majority of the visibility impacts from 

Independence on the 20% worst days 

and NOX emissions are responsible for 

30–40% of the visibility impairment on 

2 of the 20% worst days.129 The controls 

we are requiring will significantly 

reduce SO2 and NOX emissions from 

Independence, and accordingly, we 

expect that they will also significantly 

reduce the significant visibility impacts 

from the facility on the 20% worst days. 

Therefore, we disagree that these 

controls are not necessary and/or that 

they would not improve visibility in 

Arkansas Class I areas. Based on our 

consideration of the four reasonable 

progress factors and of the visibility 

improvement of controls, we are 


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130 77 FR 14604. 

131CAA section 169A(b)(2). 

132CAA section 169A(g)(1). 

requiring both SO2 and NOX controls for 

Independence Units 1 and 2 under the 

reasonable progress requirements. 

Comment: The RPG and URP in the 

Arkansas Regional Haze SIP should be 

accepted as presented by the State since 

ADEQ’s Five Year Progress Report SIP 

revision demonstrates that Arkansas is 

on track to achieve its RPGs and is 

below the URP glidepath. EPA’s 

disapproval of the Arkansas Regional 

Haze SIP submitted to EPA in 2008 was 

not due to lack of reasonable progress to 

achieve visibility improvement or for 

missing the URP. It was disapproved 

primarily because the underlying 

emissions were based on presumptive 

limits and no BART evaluations had 

been conducted. EPA’s proposed FIP 

and the controls for Independence only 

serve to achieve greater emissions 

reductions than in the Arkansas 

Regional Haze SIP. Therefore, EPA 

should not look beyond BART eligible 

units to achieve greater visibility 

improvements. EPA should not simply 

use the regional haze program as 

leverage to impose emissions reductions 

that have little benefit to the purpose of 

the rule to improve visibility. 

Response: We disagree that we should 

accept Arkansas’ RPGs as presented in 

the Arkansas Regional Haze SIP 

submitted to us in 2008. We partially 

approved and partially disapproved the 

Arkansas Regional Haze SIP in our final 

action published on March 12, 2012.130

In that final action, we disapproved a 

large portion of the state’s BART 

determinations, as well as the state 

established RPGs. We disapproved the 

state’s RPGs because they were based on 

BART determinations that were not 

made in accordance with the CAA and 

Regional Haze regulations and also 

because in establishing the RPGs, the 

state did not conduct the reasonable 

progress analysis required under the 

CAA and § 51.308(d)(1). As discussed in 

a separate response, the state decided to 

forego an evaluation of the four 

statutory factors, stating that there was 

no need for such an evaluation since 

Arkansas’ Class I areas are below the 

URP glidepath. In foregoing the 

reasonable progress analysis, the state 

did not demonstrate that the RPGs it 

established were a reflection of the 

amount of visibility improvement 

necessary to make reasonable progress. 

Our final action disapproving Arkansas’ 

RPGs for Caney Creek and Upper 

Buffalo became effective on April 11, 

2012. Any arguments upholding or 

suggesting that the state’s RPGs are 

appropriate or adequate are outside the 

scope of this action. 

Under section 110(c) of the Act, 

whenever we disapprove a mandatory 

SIP submission in whole or in part, we 

are required to promulgate a FIP within 

two years unless we approve a SIP 

revision correcting the deficiencies 

before promulgating a FIP. To date, 

Arkansas has not submitted a SIP 

revision following our partial 

disapproval, and EPA is already pastdue on its action per the statutory 

deadlines. In addition, EPA is under an 

August 31, 2016 court ordered deadline 

to either finalize a FIP or approve a SIP 

to address the regional haze 

requirements and the interstate 

visibility transport requirements. 

Therefore, the purpose of our FIP is to 

correct the deficiencies in the SIP and 

conduct the required analyses and 

establish emission limits in accordance 

with the CAA and the Regional Haze 

Rule. One of the required analyses we 

must conduct in this FIP is the 

consideration of the four statutory 

factors to determine if additional 

controls are needed to make reasonable 

progress. We discuss in a separate 

response that the reasonable progress 

requirements under CAA section 

169A(g)(1) and our Regional Haze 

regulations at § 51.308(d)(1) cannot be 

satisfied by merely being below the URP 

glidepath and/or meeting the RPGs 

previously established by the state. The 

states or EPA in a FIP must conduct an 

analysis of the four statutory factors 

regardless of the Class I area’s position 

on the URP glidepath. Based on our 

consideration of the four statutory 

factors and of the baseline visibility 

impacts from Independence and the 

visibility improvement of potential 

controls, we determined that reasonable 

controls for SO2 and NOX are available 

for Independence Units 1 and 2 that are 

cost effective and would result in a large 

amount of visibility improvement in 

Arkansas’ Class I areas in terms of the 

98th percentile impacts from the source. 

Additionally, as we discuss in section 

V.J of this final rule, CAMx source 

apportionment modeling submitted to 

us by Entergy during the comment 

period shows that Independence has 

significant visibility impacts in 

Arkansas’ Class I areas on the 20% 

worst days, and further supports our 

decision to require controls for 

Independence under reasonable 

progress. Therefore, the claim that the 

SO2 and NOX controls we are requiring 

for Independence Units 1 and 2 only 

serve to achieve greater emissions 

reductions that have little benefit to the 

purpose of the Regional Haze Rule to 

improve visibility are incorrect. Because 

we have identified through our 

reasonable progress analysis that 

additional controls are reasonable, we 

are requiring these controls for 

Independence Units 1 and 2. We 

address elsewhere in this final rule and 

in the RTC document comments related 

to ADEQ’s 5-year Progress Report SIP 

revision. 

Comment: EPA’s imposition of costly 

controls on BART-ineligible sources like 

the Independence plant, based only on 

what it claims is ‘‘reasonable,’’ is 

economically wasteful and effectively 

re-writes the definition of what sources 

are BART eligible. Under the regional 

haze program, BART controls may be 

imposed on (1) major stationary sources 

in 26 listed categories, (2) that existed 

on August 7, 1977, (3) but were not in 

operation prior to August 7, 1962, and 

(4) emit air pollutants ‘‘which may 

reasonably be anticipated to cause or 

contribute to any impairment of 

visibility’’ at Class I areas. Under the 

proposed rule, the first three of these 

statutory and regulatory criteria would 

be rendered a nullity. According to EPA, 

it may impose BART controls on any 

facility, regardless of when it was built 

or when it began operating, so long as 

EPA determines it to be ‘‘reasonable.’’ 

EPA has effectively adopted a 

presumption that at least some BARTineligible sources should be subject to 

BART unless those pollution controls 

are cost prohibitive. Such a 

presumption ignores the statute and rewrites EPA’s own regulations. 

Response: We are requiring controls 

on Independence under the reasonable 

progress requirements, not under the 

BART requirements. Clean Air Act 

section 169A required us to promulgate 

regulations directing the States to revise 

their SIPs to include emission limits 

and other measures as necessary to 

make ‘‘reasonable progress.’’ 131

Congress defined reasonable progress 

based on the consideration of four 

statutory factors: The costs of 

compliance, the time necessary for 

compliance, the energy and nonair 

quality environmental impacts of 

compliance, and the remaining useful 

life of any existing source subject to 

such requirements.132 We commonly 

refer to our analysis of these four 

statutory factors as a reasonable progress 

analysis. Congress also directed EPA to 

promulgate regulations requiring BART 

for a specific universe of older sources, 

and again provided a set of statutory 

factors States must consider: The costs 

of compliance, the energy and nonair 


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133CAA section 169A(b)(2)(A), (g)(2). 

134 80 FR at 18992. 

135 80 FR at 18996. 

136Entergy Arkansas Inc. submitted CAMx source 

apportionment modeling during the comment 

period. This modeling shows that Independence 

has significant visibility impacts in Arkansas Class 

I areas on the 20% worst days, and further supports 

our decision to require controls for Independence 

under reasonable progress. We discuss Entergy 

Arkansas Inc.’s photochemical modeling and the 

visibility impacts due to SO2 and NOX from 

Independence on the 20% worst days elsewhere in 

this final rule and in our RTC document. 

quality environmental impacts of 

compliance, any existing pollution 

control technology in use at the source, 

the remaining useful life of the source, 

and the degree of improvement in 

visibility which may reasonably be 

anticipated to result from the use of 

such technology.133 We note that many 

of the factors that must be considered in 

a BART analysis must also be 

considered in the reasonable progress 

analysis. Therefore, some commenters 

may mistakenly believe that we are 

somehow stretching the BART analysis 

to impose BART controls on 

Independence Units 1 and 2. This is not 

the case. As discussed in our proposal 

and elsewhere in this final rule, in our 

reasonable progress analysis, we 

considered the reasonable progress 

statutory factors as well as the visibility 

improvement of potential controls. 

Although visibility is not one of the four 

mandatory factors explicitly listed for 

consideration under CAA section 

169A(g)(1) or 40 CFR 51.308(d)(1)(i)(A), 

states and EPA have the option of 

considering the projected visibility 

benefits of controls in determining if the 

controls are necessary to make 

reasonable progress. We discuss this in 

more detail in our proposal and in our 

RTC document. Based on our analysis of 

the four statutory factors and 

consideration of the visibility 

improvement of controls, we have 

determined that there are SO2 and NOX

controls available for Independence 

Units 1 and 2 that are cost-effective and 

would result in considerable visibility 

benefit at Arkansas’ Class I areas, and 

are therefore requiring these controls 

under reasonable progress. 

To the extent the commenter believes 

that we treated the Independence Plant 

as if it were subject to BART in 

performing a source-specific reasonable 

progress analysis, this is incorrect. As 

we discuss elsewhere in this section of 

the final rule, individual stationary 

sources may be subject to sourcespecific analysis when determining 

whether additional controls are 

necessary to make reasonable progress. 

To the extent the commenter believes 

that only sources subject to BART can 

be looked to for emission reductions to 

promote reasonable progress, this is 

incorrect. If that were the case, then 

States, or EPA acting as necessary in the 

place of a State, would have little to no 

room for additional progress and even 

less need for sequential planning 

periods to build on past progress. 

Comment: Some commenters claim 

that we inappropriately took a ‘‘cut and 

paste’’ approach in estimating the cost 

of controls for Independence in our 

reasonable progress analysis. 

Response: We explained in our FIP 

proposal that White Bluff and 

Independence are sister facilities with 

nearly identical units. We explained 

that we verified that the two plants are 

sister facilities by constructing a master 

spreadsheet that contains information 

concerning ownership, location, boiler 

type, environmental controls, and other 

pertinent information.134 The cost of 

compliance is a factor that is required 

for consideration under both a BART 

and a reasonable progress analysis. Due 

to the similarities in the facilities and 

the identical requirement for 

consideration of the cost of controls 

under reasonable progress and BART, 

our use of the total annualized costs of 

controls on White Bluff Units 1 and 2 

in our cost analysis for Independence 

Units 1 and 2 was a reasonable 

approach. We do note that we used 

actual emissions data from 

Independence Units 1 and 2 to estimate 

the emission reductions expected to 

take place from the controls we 

evaluated and to calculate the cost 

effectiveness ($/ton removed) of 

controls for Independence Units 1 and 

2. Thus, the total annual cost of controls 

on Independence was the only aspect of 

our reasonable progress analysis where 

we relied on our cost analysis for White 

Bluff. Our consideration of the 

remaining reasonable progress factors 

(time necessary for compliance, energy 

and nonair quality environmental 

impacts of compliance, and the 

remaining useful life of any potentially 

affected sources), as well as the 

visibility impacts of Independence and 

improvement due to controls on the 

facility, was specific to the 

Independence facility.135 We modeled 

both the baseline visibility impacts from 

the Independence facility and the 

visibility benefit of controls using 

CALPUFF dispersion modeling. Based 

on our consideration of the four 

reasonable progress factors and the 

modeled visibility improvement of 

controls, we determined that reasonable 

controls for SO2 and NOX are available 

for Independence Units 1 and 2 that are 

cost effective and would result in a large 

amount of visibility improvement in 

Arkansas’ Class I areas in terms of the 

98th percentile impacts from the 

source.136

Comment: The CAA’s regional haze 

program tasks states with making 

reasonable progress toward the 

elimination of man-made visibility 

impairment, for which EPA has set a 

goal of 2064 with required progress 

milestones. Accordingly, the CAA’s 

regional haze program contemplates 

gradual visibility improvements along a 

‘‘glide path’’ toward the 2064 goal. This 

program does not require immediate 

and costly reductions in the first 

planning period or any subsequent 

planning period that go beyond what is 

needed to make ‘‘reasonable progress,’’ 

as determined by a state based on its 

assessment of the four statutory factors. 

Thus, it neither requires nor authorizes 

the front-loading of extensive control 

requirements. Delaying consideration of 

controls on Independence until the next 

planning period is a more reasonable 

approach that would allow for the 

consideration of updated information, 

such as control equipment 

characteristics and costs, emissions 

reductions attributable to other 

regulatory and market drivers, and 

contemporaneous monitoring and 

meteorological conditions, which would 

allow the coordination of these 

important investment and regulatory 

decisions with the implementation of 

other pending regulations. This 

approach would also give states and 

regulated entities the opportunity to 

conduct integrated compliance planning 

in ways that are consistent with 

provision of reliable and affordable 

electric power. EPA should withdraw its 

proposed controls for Independence 

Units 1 and 2. 

Response: We agree that the regional 

haze program contemplates gradual 

visibility improvements over several 

planning periods. Those gradual 

improvements are guided by the 

principle that controls found to be 

reasonable in a given planning period 

should be required now, rather than in 

some unspecified future planning 

period. That is the very nature of 

‘‘reasonable progress.’’ For that reason, 

we do not consider the controls we 

proposed and those we finalize in this 

action as being frontloading. As we 

discuss in several sections throughout 

this final rule, our cost analysis 

indicates that the SO2 and NOX controls 

we are requiring for Independence Units 

1 and 2 are cost effective and well 

within the range of cost of controls 

found to be reasonable by EPA and the 


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66368 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

137 77 FR 14604. 

138 76 FR 78194, 78206 (December 16, 2011). 

139 77 FR 11858, 11870 (February 28, 2012). 140 76 FR at 78206. 

states in other regional haze actions for 

this first planning period. Arkansas did 

not comply with certain aspects of the 

Regional Haze Rule and thus portions of 

its Regional Haze SIP submitted to us in 

2008 were not approvable, including the 

state’s reasonable progress 

determinations and RPGs.137 We 

therefore have an obligation to 

promulgate this FIP to address the 

disapproved portions of the State’s SIP 

submission. Pursuant to CAA section 

169A(g)(1) and our Regional Haze 

regulations at § 51.308(d)(i)(A), we 

conducted an evaluation of additional 

controls under a reasonable progress 

analysis that considered the four 

statutory factors. As discussed in our 

proposal and throughout this final rule, 

based on the demonstrations we 

developed pursuant to the CAA and 

§ 51.308(d)(1) and our consideration of 

the visibility impacts from 

Independence and the visibility 

improvement of potential controls, we 

determined that there are reasonable 

and cost-effective SO2 and NOX controls 

available for Independence that would 

result in considerable visibility benefit 

at Arkansas’ Class I areas. Under the 

CAA and the Regional Haze regulations, 

if we determine that additional controls 

are reasonable based on the 

consideration of the four statutory 

factors, we must require those controls. 

Therefore, we are requiring SO2 and 

NOX controls for Independence Units 1 

and 2 under reasonable progress. 

Comment: EPA applied dollar per ton 

cost-effectiveness estimates and 

visibility improvement rates for the 

proposed controls on Independence that 

are out of line with the standards 

applied in other regional haze actions. 

Specifically, EPA’s proposal attempts to 

justify a cost-effectiveness of dry FGD at 

Independence Plant totaling $2,477/SO2

ton removed for Unit 1 and $2,686/SO2

ton removed for Unit 2. This far exceeds 

the cost-effectiveness standards 

reviewed and approved by EPA for the 

Kentucky138 and North Carolina 

Regional Haze SIPs.139 In its approval of 

the Kentucky Regional Haze SIP, EPA 

approved the use of a $2,000 per ton 

SO2 screening threshold. In its approval 

of the North Carolina Regional Haze SIP, 

EPA approved the state’s decision not to 

implement additional controls under 

reasonable progress despite the finding 

that there are potential controls with 

cost effectiveness ranging from $912 to 

$1,922 per ton of SO2 removed. EPA’s 

proposed controls for Independence are 

inconsistent with these other regional 

haze actions. 

Response: In response to comments 

we received during the comment period, 

we have revised our cost analysis for 

SO2 controls for Independence and 

estimate that these controls cost $2,853/ 

SO2 ton removed for Unit 1 and $2,634/ 

SO2 ton removed for Unit 2. Although 

slightly higher than the cost 

effectiveness estimates we presented in 

our proposal, we continue to consider 

these controls to be cost effective and 

well within the range of cost of controls 

found to be reasonable by EPA and the 

states in other regional haze actions. We 

disagree with the statement that our 

proposal to require SO2 controls for 

Independence is inconsistent with our 

approvals of the Kentucky and North 

Carolina Regional Haze SIPs. 

Additionally, the factual contexts of 

both of these actions are easily 

distinguished from context in which we 

assessed potential reasonable progress 

controls for Independence. 

The commenter contends that in our 

proposed approval of the Kentucky 

Regional Haze SIP, we approved the 

state’s use of a $2,000/SO2 ton 

threshold. This is incorrect. In the 

preamble of our proposed approval of 

the Kentucky Regional Haze SIP, we 

discussed that the state identified 10 

units for evaluation under reasonable 

progress, and that 9 of these were EGUs 

subject to CAIR. The remaining facility, 

Century Aluminum, is not an EGU. We 

further discussed that for the limited 

purpose of evaluating the cost of 

compliance for the reasonable progress 

assessment in this first regional haze SIP 

for the non-EGU Century Aluminum, 

Kentucky concluded that it was not 

equitable to require non-EGUs to bear a 

greater economic burden than EGUs for 

a given control strategy. As a result, 

Kentucky decided to use CAIR as a 

guide, using a cost of $2,000/ton of SO2

reduced as a threshold for costeffectiveness for that particular nonEGU source. Kentucky found that the 

cost effectiveness of the SO2 control as 

suggested by the VISTAS control cost 

spreadsheet for potlines 1–4 at Century 

Aluminum is $14,207/ton of SO2

removed. The State thus concluded that, 

based on the high cost on a $/ton basis, 

there are no cost-effective SO2

reasonable progress controls available 

for the Century Aluminum units for the 

first implementation period. We 

proposed to approve Kentucky’s 

determination, but we also stated the 

following concerning our position on 

Kentucky’s use of a $2,000/SO2 ton 

threshold: 

Although the use of a specific threshold for 

assessing costs means that a state may not 

fully consider available emissions reduction 

measures above its threshold that would 

result in meaningful visibility improvement, 

EPA believes that the Kentucky SIP still 

ensures reasonable progress. In proposing to 

approve Kentucky’s reasonable progress 

analysis, EPA is placing great weight on the 

fact that there is no indication in the SIP 

submittal that Kentucky, as a result of using 

a specific cost effectiveness threshold, 

rejected potential reasonable progress 

measures that would have had a meaningful 

impact on visibility in its Class I area.140

It is clear in our proposed approval 

that we were not approving or otherwise 

advocating Kentucky’s use of a $2,000/ 

SO2 ton threshold in the reasonable 

progress analysis. On the contrary, we 

expressed concern that the use of a 

specific threshold for assessing cost may 

result in a state not fully considering 

potential reasonable control measures 

above that threshold that would have 

meaningful visibility improvement on 

its Class I areas. Furthermore, our 

statements in the proposal indicate that 

had there been evidence of more 

affordable controls available above the 

$2,000/SO2 ton threshold used by the 

state that provide meaningful visibility 

improvement at the Class I areas, we 

might have arrived at a different 

decision concerning the approvability of 

Kentucky’s reasonable progress analysis 

for SO2. 

North Carolina took a similar 

approach to that of Kentucky in its SO2

reasonable progress analysis by relying 

on a cost threshold when deciding on 

measures for its non-EGUs. North 

Carolina set this threshold based on the 

estimated cost of compliance with its 

Clean Smokestacks Act, a law 

establishing a state-wide cap on SO2 and 

NOX emissions from the State’s two 

major utilities. In our proposed approval 

of the North Carolina Regional Haze SIP, 

we discussed that the state identified 11 

units (non-EGU) for evaluation. We 

noted that North Carolina decided that 

for the limited purpose of evaluating the 

cost of compliance for non-EGUs in the 

SO2 reasonable progress assessment for 

the first implementation period, it was 

not equitable to require non-EGUs to 

bear a greater economic burden than 

EGUs for a given control strategy and 

therefore also used a cost-effectiveness 

threshold for its non-EGUs. North 

Carolina’s threshold was based on ‘‘[t]he 

facility-by-facility cost for EGUs under 

[the Clean Smokestacks Act which] 

ranged from 912 to 1,922 dollars per ton 

of SO2 removed,’’ a statement which the 

commenters appear to have 

misinterpreted to mean that North 


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141 77 FR at 11870. 

142 77 FR 11858, 11872. 

143 79 FR 74818, 74873 (December 16, 2014). 

144 80 FR at 18966. 

145See Arkansas Regional Haze SIP, Appendix 

8.1— ‘‘Technical Support Document for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze State Implementation Plans,’’ section 

3.7.1 and 3.7.2. See the docket for this rulemaking 

for a copy of the Arkansas Regional Haze SIP. 

146See NEI 2011 v1. A spreadsheet containing the 

emissions inventory is found in the docket for our 

proposed rulemaking. 

147Although the reasonable progress provisions 

of the Regional Haze Rule place emphasis on the 

20% worst days, the CAA goal of remedying 

visibility impairment due to anthropogenic 

emissions encompasses all days. Thus, states and 

EPA have the discretion to consider the visibility 

impacts of sources and the visibility benefit of 

controls on days other than the 20% worst days in 

making their decisions, such as the days on which 

a given facility has its own largest (98th percentile) 

impacts. Because Independence has significant 98th 

percentile visibility impacts, these impacts will 

need to be addressed to achieve the CAA goal of 

remedying visibility impairment due to 

anthropogenic emissions. 

Carolina rejected potential reasonable 

progress measures with costs falling 

within this range.141 Rather, upon 

conducting cost evaluations for the nonEGUs and determining that the costs of 

controls exceeded its threshold, North 

Carolina concluded that there were no 

cost-effective reasonable progress SO2

controls available for the first 

implementation period. We proposed to 

approve North Carolina’s determination, 

but we also stated the following 

concerning our position on North 

Carolina’s use of a specific costeffectiveness threshold: 

Although the use of a specific threshold for 

assessing costs means that a state may not 

fully consider available emissions reduction 

measures above its threshold that would 

result in meaningful visibility improvement, 

EPA believes that the North Carolina SIP still 

ensures reasonable progress. In proposing to 

approve North Carolina’s reasonable progress 

analysis, EPA is placing great weight on the 

fact that there is no indication in the SIP 

submittal that North Carolina, as a result of 

using a specific cost effectiveness threshold, 

rejected potential reasonable progress 

measures that would have had a meaningful 

impact on visibility in its Class I areas.142

As in the case of Kentucky, it is clear 

that in our proposed approval of North 

Carolina’s reasonable progress 

determination, we were not approving 

or otherwise advocating North 

Carolina’s use of that specific costeffectiveness threshold in the reasonable 

progress analysis. Therefore, we 

disagree that our requirement of SO2

controls for Independence Units 1 and 

2 under reasonable progress is 

inconsistent with our actions on the 

Kentucky and North Carolina Regional 

Haze SIPs. 

Comment: EPA’s decision to evaluate 

and propose NOX controls at the 

Independence Plant stands completely 

opposite its decision not to even 

evaluate similar controls for Texas’ 

point sources despite similar visibility 

conditions. EPA elected not to evaluate 

Texas point sources for NOX controls 

because modeling suggested that 

impacts from the sources on the 20% 

worst days were ‘‘primarily due to 

sulfate emissions.’’ 143 In Arkansas, EPA 

was even more explicit in stating that 

‘‘visibility impairment is not projected 

to be significantly impacted by nitrate 

on the 20% worst days at Caney Creek 

or Upper Buffalo.’’ 144 However, the 

agency nevertheless evaluated and 

proposed NOX controls for the 

Independence Plant Units 1 and 2. The 

arbitrary nature of this aspect of EPA’s 

proposal is further evidenced by the low 

projection for anticipated visibility 

improvement due to the NOX controls. 

For instance, EPA rejected installation 

of SCR controls under reasonable 

progress where it was projected to result 

in 0.41 dv improvement at affected 

Class I areas in the Arizona Regional 

Haze FIP proposal, whereas it is 

proposing to require NOX controls on 

Independence that are projected to 

result in visibility improvement of 0.461 

dv in the Arkansas Regional Haze FIP 

proposal. 

Response: This comment, and our 

response to it, illustrate the very factspecific nature of individual evaluations 

and decisions under the regional haze 

program. It is critical to understand the 

full context of each decision. In each 

one, the EPA applies the requirements 

of the statute and regulations in a 

consistent manner, but the different 

facts—unique to each state and 

facility—inevitably lead to different 

outcomes. We agree that in our Texas 

FIP action we noted that on the 20% 

worst days, the impacts from the EGUs 

we evaluated under reasonable progress 

were primarily due to sulfate emissions. 

We also agree that in our Arkansas FIP 

proposal we acknowledged that the 

CENRAP modeling demonstrates that 

sulfate is the primary driver of regional 

haze in Arkansas’ Class I areas on the 

20% worst days. This does not mean 

that NOX is not a key pollutant 

contributing to regional haze 

impairment in both states. For instance, 

the CENRAP CAMx modeling shows 

that total extinction at Caney Creek is 

dominated by nitrate on 4 of the days 

that comprise the 20% worst days in 

2002, and a significant portion of the 

total extinction at Upper Buffalo on 2 of 

the days that comprise the 20% worst 

days in 2002 is due to nitrate.145

As a key pollutant, we considered 

NOX controls under reasonable progress 

in both Texas and Arkansas. In our 

Texas FIP, we considered NOX controls 

under reasonable progress for the Works 

No. 4 Glass Plant but ultimately did not 

require those controls based on the 

emission reductions already occurring 

at the facility, the anticipated lifetime of 

the furnaces, and the fact that Furnace 

No. 2 had undergone rebricking within 

the past few years. Although we 

determined it was reasonable to not 

require additional controls for Works 

No. 4 Glass Plant at this time, we 

encouraged Texas to consider additional 

controls when Furnace No. 2 is 

scheduled for its next rebricking. We 

also found that in Texas all the EGUs 

that we evaluated for controls under 

reasonable progress had existing LNB 

for control of NOX emissions. This is in 

contrast to Independence, which is the 

second largest source of NOX point 

source emissions in Arkansas and is not 

currently equipped with any NOX

controls. As such, Independence was a 

more compelling candidate for 

evaluation of NOX controls than were 

the EGUs in Texas that we evaluated for 

controls under reasonable progress. 

As NOX is a visibility impairing 

pollutant and Independence is 

responsible for a very large portion of 

the point source NOX emissions in the 

state (approximately 21.3%),146 we 

determined that it was reasonable to 

evaluate NOX controls under reasonable 

progress in our Arkansas FIP proposal. 

We conducted CALPUFF modeling and 

found that the Independence Plant has 

significant visibility impacts in 

Arkansas’ Class I areas due to NOX

emissions based on the 98th percentile 

visibility impacts from the facility, and 

also found that LNB/SOFA would 

improve these visibility impacts.147 We 

also found that LNB/SOFA is very cost 

effective ($401/ton removed for Unit 1 

and $436/ton removed for Unit 2). For 

these reasons, we proposed LNB/SOFA 

for Independence Units 1 and 2 under 

Option 1. In addition, we discuss in 

more detail elsewhere in this final rule 

and in our RTC document that Entergy 

submitted CAMx photochemical 

modeling during the public comment 

period showing that nitrate from 

Independence is responsible for 30– 

40% of the visibility impairment in 

Arkansas’ Class I areas on 2 out of the 

20% worst days in 2018. We expect that 

the installation of NOX controls at 

Independence, which we found to be 

very cost effective, would provide 

visibility improvement on this portion 

of the 20% worst days, thereby assuring 

reasonable progress toward the goal of 

natural visibility conditions. Based on 


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66370 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

148 79 FR 9318, 9360 (February 18, 2014). 

149 79 FR 9318, 9359. 

150 79 FR 74818, 74834. 

151 64 FR at 35714, 35732. 

our consideration of the four statutory 

factors and the visibility improvement 

available from controls, we have 

determined that there are reasonable 

NOX controls available for 

Independence that are cost effective and 

would result in considerable visibility 

improvement. Therefore, we are 

requiring these controls. 

We disagree that our decision to 

require NOX controls for Independence 

is inconsistent with our Arizona FIP 

proposal. In that action, we proposed 

that neither SCR nor SNCR was required 

to achieve reasonable progress for 

Springerville Units 1 and 2 in this 

regional haze planning period because: 

[w]hile the cost per ton for SNCR may be 

reasonable, the projected visibility benefits 

are relatively small (0.18 dv at the most 

affected area). The projected visibility 

benefits of SCR are larger (0.41 dv at the most 

affected area), but we do not consider them 

sufficient to warrant the relatively high cost 

of controls for purposes of RP in this 

planning period. However, these units 

should be considered for additional NOX

controls in future planning periods.148

The ‘‘relatively high cost’’ of SCR 

controls we refer to in that statement is 

$6,829/ton NOX removed for 

Springerville Unit 1 and $6,085/ton 

NOX removed for Springerville Units 

2.149 Thus, our decision to not propose 

SCR at Springerville Units 1 and 2 was 

not because we considered the visibility 

benefits to be too small, as the 

commenter appears to believe. Instead, 

it was because we determined that, 

under these circumstances, this level of 

visibility improvement was not 

sufficient to warrant the cost per ton of 

emissions reduced. In contrast, we 

found that the cost of LNB/SOFA at 

Independence Units 1 and 2 is 

significantly lower ($401/ton removed 

for Unit 1 and $436/ton removed for 

Unit 2), and we determined that 0.459 

dv visibility improvement on a facility 

wide basis warranted the cost of these 

controls. Therefore, we disagree that the 

NOX controls we proposed and are 

finalizing in this action for 

Independence Units 1 and 2 in any way 

contradict our proposed Arizona 

Regional Haze FIP. 

Comment: The overarching 

requirement of the CAA’s haze 

provisions is for each state’s plan to 

include ‘‘emission limits, schedules of 

compliance and other measures as may 

be necessary to make reasonable 

progress.’’ CAA section 169A(b)(2). The 

statute defines reasonable progress to 

account for four factors: The cost of 

controls, the time needed to install 

controls, energy and nonair quality 

environmental impacts of controls, and 

the remaining useful life of the source. 

CAA section 169A(g)(1) and 40 CFR 

51.308(d)(1)(i)(A). EPA’s implementing 

regulations require each state with a 

Class I area to set an RPG for each area 

within its borders based on considering 

the four statutory factors for reasonable 

progress. Each state must also determine 

the uniform rate of progress. If a state 

sets a reasonable progress goal that 

provides for less progress than the URP, 

the state must demonstrate that 

achieving the URP is unreasonable and 

that its alternative goal is reasonable. 

Moreover, each state must consult with 

other states that contribute to haze in 

the host state’s Class I areas. Neither the 

statute nor the regulations exempts 

states from the required reasonable 

progress analysis merely because a Class 

I area is on the glidepath to achieving 

the URP. To the contrary, EPA’s longstanding interpretation of the regional 

haze rule is that ‘‘the URP does not 

establish a ‘safe harbor’ for the state in 

setting its progress goals.’’ 150 If it is 

reasonable to make more progress than 

the URP, a state must do so, as EPA 

explained in the 1999 Regional Haze 

Rule.151 Having disapproved Arkansas’ 

regional haze plan, EPA has an 

obligation to conduct a reasonable 

progress analysis for Caney Creek and 

Upper Buffalo based on a consideration 

of the four statutory factors for 

reasonable progress. 40 CFR 

51.308(d)(1). 

Response: We agree with this 

comment with regard to our obligation 

to conduct a reasonable progress 

analysis for sources in Arkansas 

regardless of the Class I areas’ position 

on the URP glidepath. 

D. Control Levels and Emission Limits 

Comment: Assuming EPA proceeds 

with BART for the Ashdown Mill, EPA 

should revise the proposed SO2 limit for 

Power Boiler 2 from 0.11 lb/MMBTU to 

155 lb/hr on a 30-day boiler operating 

day. There are a number of concerns 

with EPA’s proposed limit of 0.11 lb/

MMBTU: It is too stringent, it is based 

on the use of an inappropriate baseline 

(2011–2013), and assumes the existing 

control equipment can continuously 

operate at the upper range of its 

capability (90% efficiency) over long 

periods of time, without supporting data 

or other documentation. First, in the 

methodology to calculate the proposed 

BART limit, EPA used data from 2011– 

2013 for determining the proposed 

BART limit, instead of using 2001–2003 

as the baseline. No justification is given 

for not using 2001–2003 as the baseline, 

or why the particular years EPA selected 

are better than the BART baseline years 

or legally appropriate. Deviating from 

the 2001–2003 BART baseline is 

appropriate if significant changes were 

made to the emission units or permit 

conditions were imposed that prevent a 

unit from operating at the BART 

baseline emission value. However, this 

is not the case for Power Boiler 2. The 

BART 2001–2003 baseline information 

is representative of Power Boiler 2’s 

potential operations. The fact that the 

Ashdown Mill voluntarily elected to 

operate at a lower SO2 level subsequent 

to the 2001–2003 baseline period is not 

relevant. Moreover, by not utilizing the 

BART 2001–2003 baseline actual 

emissions in establishing the proposed 

BART SO2 limit, EPA penalizes the 

Ashdown Mill for its voluntary SO2

emission reductions undertaken on its 

own initiative since the BART baseline 

period. Here, the mill voluntarily 

reduced SO2 emissions by over 40% 

since the BART baseline years prior to 

the proposed BART requirements. Using 

the actual emission data from the BART 

baseline period of 2001–2003, gives the 

mill credit for its early voluntary action. 

Second, EPA wrongly applied the 

maximum rated heat input capacity of 

820 MMBTU/hr when it converted from 

a lb/hr limit to a lb/MMBTU limit. The 

use of the maximum heat input rating is 

not representative of average (typical) 

boiler operating conditions, which are 

lower than the maximum heat input 

capability. The actual average heat input 

during the 2001–2003 baseline period is 

586 MMBTU/hr. In this situation, the 

use of actual emission data and 

maximum rated heat input to calculate 

the proposed SO2 BART limit is 

inappropriate and an inaccurate 

methodology which creates significant 

concerns. EPA should instead establish 

an SO2 emission limit in terms of lb/hr. 

Third, based on monthly SO2

information for the 2011–2013 period, 

EPA estimated that the SO2 control 

efficiency for the existing scrubber on 

Power Boiler 2 to be approximately 69% 

and that the existing scrubber may 

achieve on a short-term basis an SO2

control efficiency of 90%. However, 

there is no documentation showing that 

the scrubber can sustain this maximum 

performance level on a long term basis. 

EPA should revise the methodology for 

calculating the SO2 BART emission 

limit for Power Boiler No. 2 by using 

2001–2003 actual emissions as the 

baseline; assuming the existing 

scrubbers operated at a 69% control 

efficiency during the 2001–2003 


asabaliauskas on DSK3SPTVN1PROD with RULES
Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66371 

152See 80 FR at 18984. See also August 29, 2014 

letter from Annabeth Reitter, Corporate Manager of 

Environmental Regulation, Domtar, to Dayana 

Medina, U.S. EPA Region 6. A copy of this letter 

and an Excel file attachment titled ‘‘Domtar 2PB 

Monthly SO2 Data,’’ are found in the docket for our 

proposed rulemaking. 

153See 80 FR at 18984. See also the spreadsheet 

titled ‘‘Domtar 2PB Monthly SO2 Data.’’ This 

spreadsheet was included as an attachment to the 

August 29, 2014 letter from Annabeth Reitter, 

Corporate Manager of Environmental Regulation, 

Domtar, to Dayana Medina, U.S. EPA Region 6. See 

also the spreadsheet titled ‘‘Domtar PB No2—Cost 

Effectiveness calculations.’’ Copies of these 

documents can be found in the docket for this 

proposed rulemaking. 

154 80 FR at 18983, 18984. 

155 80 FR at 18984. 

156See 80 FR at 18984. See also the spreadsheet 

titled ‘‘Domtar 2PB Monthly SO2 Data.’’ This 

spreadsheet was included as an attachment to the 

August 29, 2014 letter from Annabeth Reitter, 

Corporate Manager of Environmental Regulation, 

Domtar, to Dayana Medina, U.S. EPA Region 6. See 

also the spreadsheet titled ‘‘No2 Boiler_Monthly 

Avg SO2 emission rate and calculations.’’ Copies of 

these documents can be found in the docket for our 

rulemaking. 

157See 80 FR at 18984. See also the spreadsheet 

titled ‘‘No2 Boiler Monthly Avg SO2 emission rate 

and calculations.’’ A copy of this spreadsheet can 

be found in the docket for our rulemaking. 

baseline period; calculating an SO2

emission limit in lb/hr based on 2001– 

2003 baseline actual emissions and a 

90% control efficiency. Based on this 

approach, EPA should revise the 

proposed SO2 limit for Power Boiler 2 

from 0.11 lb/MMBTU to 155 lb/hr on a 

30-day boiler operating day. 

Response: We disagree that an 

emission limit of in an emission limit of 

155 lb/hr on a 30 boiler-operating-day 

satisfies the SO2 BART requirement for 

Power Boiler No. 2. As discussed in our 

proposal, we requested information 

from the facility to determine if 

upgrades to the existing scrubbers are 

technically feasible and if they would be 

cost effective and provide meaningful 

visibility benefit. This assessment first 

required us to determine the current 

control efficiency of the scrubbers. 

Because our BART analysis involved 

determining the current control 

efficiency of the existing scrubbers, we 

found that the most reasonable 

approach was to use data that reflect the 

current control efficiency of the existing 

scrubbers, as opposed to 2001–2003 

data. In order to conduct our BART 

analysis, we requested monthly average 

data for 2011, 2012, and 2013 on 

monitored SO2 emissions from Power 

Boiler No. 2, mass of the fuel burned for 

each fuel type, and the percent sulfur 

content of each fuel type burned.152

These were the three most recent full 

calendar years of data available at the 

time we conducted our BART analysis. 

For these reasons, our use of 2011–2013 

as the baseline for calculating the 

current control efficiency of the existing 

scrubbers and our proposed SO2 BART 

limit for Power Boiler No. 2 was 

appropriate and justified. As discussed 

in detail in our proposal, based on the 

emissions data and fuel usage data 

Domtar provided to us, we estimated 

that the current control efficiency of the 

existing scrubbers is approximately 69% 

based on 2011–2013 data.153 The data 

also indicated that the existing 

scrubbers could achieve up to 90% 

removal efficiency. As discussed in our 

proposal, Domtar indicated that the 

scrubbers are currently operated in a 

manner that allows for compliance with 

permitted emission limits.154 In other 

words, the facility generally uses only 

the amount of scrubbing solution 

needed to comply with permitted 

emission limits. The information the 

facility provided indicated that it would 

be possible to add more scrubbing 

solution to achieve greater SO2 removal 

than required to meet the boiler’s 

existing SO2 permit limit; specifically, 

the information indicated that 

additional scrubbing reagent can be 

added to increase the control efficiency 

of the existing scrubbers to 90%.155

We agree that we applied the boiler’s 

maximum heat input rating of 820 

MMBtu/hr when we calculated our 

proposed limit of 0.11 lb/MMBtu, and 

based on information provided by the 

commenter, we acknowledge that use of 

the maximum heat input rating is not 

representative of average (typical) boiler 

operating conditions. To address the 

commenter’s concern, we are finalizing 

an SO2 BART limit for Power Boiler No. 

2 in terms of lb/hr. As we discussed in 

our proposal, based on the emissions 

data we obtained from Domtar, we 

determined that the No. 2 Power 

Boiler’s annual average SO2 emission 

rate for the years 2011–2013 was 280.9 

lb/hr.156 This annual average SO2

emission rate corresponds to the 

operation of the scrubbers at a 69% 

removal efficiency. We also estimated 

that 100% uncontrolled emissions 

would correspond to an emission rate of 

approximately 915 lb/hr. Application of 

90% control to this emission rate results 

in a controlled emission rate of 91.5 lb/ 

hr.157 We recognize that the boiler’s SO2

emissions are currently lower than they 

were in the 2001–2003 period, and that 

had we used 2001–2003 data to 

calculate the current control efficiency 

and SO2 BART emission limit, as the 

commenter requests, this would have 

resulted in a less stringent emission 

limit. However, as discussed above, the 

most reasonable approach is to use 

recent data in our calculation of an 

appropriate SO2 BART emission limit. 

As Domtar is requesting an emission 

limit in terms of lb/hr, we are finalizing 

for SO2 BART for Power Boiler No. 2 an 

emission limit of 91.5 lb/hr on a 30 

boiler operating day. We believe this 

emission limit reflects operation of the 

scrubbers at 90% control efficiency and 

addresses the SO2 BART requirement 

for Power Boiler No. 2. 

We believe it reasonable to set the 

emission limit using baseline emissions 

resulting from recent/current fuels. 

Given that we don’t find it appropriate 

to use emissions from the 2001–2003 

period to calculate the SO2 emission 

limit, the control efficiency from that 

period is irrelevant. What is relevant are 

the current uncontrolled SO2 emissions 

and the possible control efficiency of 

the existing scrubbers, which is what we 

considered in our BART analysis. We 

found in our analysis that during the 

2011–2013 period, the company was 

able to achieve an average monthly 

control efficiency of 90% and find that 

this level of control is reasonable, and 

can be achieved by the use of sufficient 

reagent to achieve the lower level. We 

also note that the commenter did not 

provide additional information to 

support the claim that the existing 

scrubbers cannot consistently achieve 

the level of control efficiency necessary 

to meet an emission limit of 91.5 lb/hr. 

Comment: The NOX emission limits 

proposed for the units at White Bluff 

and Independence are based on the 

emission rate for LNB/SOFA of 0.15 lb/ 

MMBtu that Entergy proposed in the 

Revised White Bluff BART Analysis. At 

the time Entergy submitted the Revised 

White Bluff BART Analysis in October 

2013, which EPA relied on in 

developing its FIP proposal, all four of 

the coal-fired units at White Bluff and 

Independence were operated as base 

load units and spent the overwhelming 

majority of their operating time at loads 

of greater than 50% of unit capacity. 

Since submitting the Revised White 

Bluff BART Analysis, Entergy 

transitioned to MISO in December 2013. 

MISO utilizes an economic dispatch 

model to determine which EGUs within 

its service territory are dispatched to 

operate and the operating load (MW) for 

each unit. Beginning in December 2014, 

the units at both White Bluff and 

Independence began to be dispatched 

primarily as load-following units. Since 

December 2014, the White Bluff and 

Independence units have been 

dispatched less frequently and, when 

dispatched, have spent significantly 

more time at low operating rates of less 

than 50% of unit capacity. The data for 

2015 (through June 30) reflects a 

significant increase in the percentage of 

time that each unit is dispatched at less 


asabaliauskas on DSK3SPTVN1PROD with RULES
66372 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

158See comments submitted during the comment 

period by Entergy Arkansas Inc., including Exhibit 

G to Entergy’s comments. These and all other 

comments and associated attachments submitted 

during the public comment period are found in the 

docket associated with this rulemaking. 

than 50% of operating capacity. Three 

of the four units have spent greater than 

40% of their 2015 operating hours at 

less than 50% of capacity, and the two 

Independence units have spent nearly 

half of their operating time at less than 

50% of capacity. This change in 

dispatch coincided with a sharp drop in 

natural gas prices. This drop in gas 

prices to near $3 per MMBtu has been 

sustained since December 2014, and 

Entergy has no reason to expect any 

significant increase in gas pricing in the 

near future. This change in dispatch for 

the units at both White Bluff and 

Independence is significant with regard 

to NOX emissions as the LNB/SOFA 

system is designed to operate primarily 

in the range of 50–100% of unit load. 

Entergy has selected Foster Wheeler as 

the LNB/SOFA vendor for White Bluff 

and has only been able to obtain a 

guarantee of less than 0.15 lb/MMBtu 

for operating loads in the range of 50– 

100% of unit capacity. Since the 

available emission guarantee does not 

cover unit operation at less than 50% of 

capacity, Entergy requested a 

memorandum from Foster Wheeler 

regarding the impact of unit operation at 

less than 50% capacity on NOX

emission rates. Based on input from the 

LNB/SOFA vendor, Entergy does not 

believe that the proposed emission rate 

of 0.15 lb/MMBtu is consistently 

achievable under all operating 

conditions. Even with a 30-day 

averaging period for the proposed limit, 

a unit which is frequently dispatched at 

less than 50% of capacity may not be 

able to achieve compliance. This was 

not perceived as an issue at the time 

that the Revised White Bluff BART 

Analysis was prepared and submitted to 

ADEQ by Entergy as, historically and at 

that time, the units were operated 

almost exclusively as base-load units 

and spent less than 10% of their 

operating time at less than 50% of unit 

capacity. In the current dispatch 

environment, with some units spending 

nearly 50% of their operating time 

outside of the control range for LNB/

SOFA, Entergy can no longer be 

confident that the units will be able to 

achieve compliance with a limit of 0.15 

lb/MMBtu on a 30-day rolling average 

basis. The concern arises from low-load 

operation during which periods of 

higher NOX emissions, on a lb/MMBtu 

basis, would not be expected to 

correspond to an increase in the 

maximum mass emission rate (lb/hr) 

from the units as any increase in the 

emission rate on a lb/MMBtu basis 

would be expected to be more than 

offset by the lower unit operating rate in 

MMBtu/hr to arrive at a mass emission 

rate (lb/hr). 

To address the potential for a higher 

NOX emission rate (lb/MMBtu basis) at 

operating rates of less than 50% of unit 

capacity, Entergy proposes a rolling 30- 

boiler operating day average emission 

rate of 1,342.5 lb NOX/hr at each coalfired unit at White Bluff and 

Independence. In the alternative, if EPA 

believes that a lb/MMBtu limit is 

necessary for the units, Entergy 

proposes a bifurcated NOX emission 

limit for each unit at both White Bluff 

and Independence as follows: (1) For all 

unit operation (0–100% of capacity) 

require an emission limit of 1,342.5 lb 

NOX/hr, based on a rolling 30-boiler 

operating day average; and (2) for unit 

operation at 50–100% of capacity, 

require an emission limit of 0.15 lb 

NOX/MMBtu, based on a rolling 30- 

boiler operating day average, to include 

only those hours for which the unit was 

dispatched at 50% or greater of 

maximum capacity. This alternative 

approach would ensure that the units 

are operated in compliance with the 

LNB/SOFA design within the control 

range of 50–100% of capacity while 

providing Entergy with flexibility in 

demonstrating compliance. The lb/hr 

limit, which would apply to all 

operating hours, will ensure that the 30- 

day average emission rates remain 

below those on which both EPA and 

Entergy relied to project visibility 

improvements from the proposed NOX

emission reductions. 

Response: We acknowledge the 

information provided by the 

commenter. We understand the 

commenter’s concerns that because of 

recent changes in dispatch of the units, 

White Bluff Units 1 and 2 and 

Independence Units 1 and 2 are no 

longer expected to be able to 

consistently meet our proposed NOX

emission limit of 0.15 lb/MMBtu over a 

30-boiler-operating-day period based on 

LNB/SOFA controls. We believe the 

commenter has provided sufficient 

information to substantiate that the 

units are not expected to be able to meet 

our proposed NOX emission limit of 

0.15 lb/MMBtu when the units are 

primarily operated at less than 50% of 

their operating capacity. In particular, 

the information provided by the 

commenter indicates that LNB/SOFA 

achieves optimal NOX control when the 

boiler is operated from 50 to 100% 

steam flow because the heat input 

across this range is sufficient to safely 

redirect a substantial portion of 

combustion air through the overfire air 

registers.158 This allows the combustion 

zone airflow to be sub-stoichiometric 

and oxygen to be reduced to the point 

where much of the elemental nitrogen 

in the fuel and combustion air can pass 

through the boiler without oxidizing 

(i.e., converting to NOX). When a boiler 

is operated below the 50 to 100% 

capacity range, NOX concentrations on a 

lb/MMBtu basis can be elevated due to 

the lower heat input rating, even though 

the pounds of NOX emitted (i.e., on a 

mass basis) is less due to the reduced 

amount of fuel and air. In light of the 

information provided by the 

commenter, we believe it is appropriate 

to promulgate a bifurcated NOX

emission limit for each unit, as 

suggested by the commenter. 

Therefore, in this FIP we are requiring 

White Bluff Units 1 and 2 and 

Independence Units 1 and 2 to each 

meet a NOX emission limit of 0.15 lb/ 

MMBtu on a 30 boiler-operating-day 

rolling average, where the average is to 

be calculated by including only the 

hours during which the unit was 

dispatched at 50% or greater of 

maximum capacity, as requested by the 

commenter. Specifically, the 30 boileroperating-day rolling average is to be 

calculated for each unit by the following 

procedure: (1) Summing the total 

pounds of NOX emitted during the 

current boiler-operating-day and the 

preceding 29 boiler-operating-days, 

including only emissions during hours 

when the unit was dispatched at 50% or 

greater of maximum capacity; (2) 

summing the total heat input in MMBtu 

to the unit during the current boileroperating-day and the preceding 29 

boiler-operating-days, including only 

the heat input during hours when the 

unit was dispatched at 50% or greater 

of maximum capacity; and (3) dividing 

the total pounds of NOX emitted as 

calculated in step 1 by the total heat 

input to the unit as calculated in step 2. 

In addition to this limit that is intended 

to control NOX emissions when the 

units are operated at 50% or greater of 

maximum capacity, we are establishing 

a limit in lb/hr for periods in which the 

units are operated at less than 50% 

capacity. However, the 1,342.5 lb/hr 

emission limit suggested by the 

commenter is too high to appropriately 

control NOX emissions when the units 

are operated at low capacities. There is 

no indication in the comments 

submitted that the 1,342.5 lb/hr 

emission limit suggested by the 


asabaliauskas on DSK3SPTVN1PROD with RULES
Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66373 

159 80 FR 18944, 18980. 

160 80 FR at 18980. 

161See file ‘‘Record of Meeting_March 10 2016,’’ 

which can be found in the docket for this 

rulemaking. 

162 40 CFR 51.301. 

commenter was based on a vendor 

guarantee. The commenter did not 

explain how the 1,342.5 lb/hr limit was 

calculated, but it appears that it was 

calculated by multiplying the 0.15 lb/

MMBtu limit by the maximum heat 

input rating for each unit (8,950 

MMBtu/hr), which yielded 1,342.5 lb/

hr. An emission limit of 1,342.5 lb/hr 

would be appropriate when the unit is 

operated at high capacities considering 

that the limit was calculated based on 

the unit’s maximum heat input rating. 

However, such an emission limit would 

not be sufficiently protective or 

appropriate when the unit is operated at 

lower capacities when it is expected 

that NOX emissions on a mass basis 

would be lower compared to operation 

at high capacity. To address this 

concern, we have calculated a new 

emission limit of 671 lb/hr that is based 

on 50% of the unit’s maximum heat 

input rating, and is applicable only 

when the unit is being operated at less 

than 50% of the unit’s maximum heat 

input rating. We calculated this limit by 

multiplying 0.15 lb/MMBtu by 50% of 

the maximum heat input rating for each 

unit (i.e., 50% of 8,950 MMBtu/hr, or 

4,475 MMBtu/hr). This limit is on a 

rolling 3-hour average, where the 

average is to be calculated by including 

emissions only from the hours during 

which the unit was operated at less than 

50% of the unit’s maximum heat input 

rating (i.e., hours when the heat input to 

the unit is less than 4,475 MMBtu). We 

are not establishing a lb/hr emission 

limit that applies when the units are 

operated at 50% or greater of the unit’s 

maximum heat input rating because 

there is no need for it since the 0.15 lb/ 

MMBtu limit will address NOX emission 

during those operating conditions. 

As such, we are requiring White Bluff 

Units 1 and 2 and Independence Units 

1 and 2 to each meet a NOX emission 

limit of 0.15 lb/MMBtu on a 30 boileroperating-day rolling average, where the 

average is to be calculated by including 

only the hours during which the unit 

was dispatched at 50% or greater of 

maximum capacity, as requested by the 

commenter. In addition, we are 

requiring White Bluff Units 1 and 2 and 

Independence Units 1 and 2 to each 

meet a NOX emission limit of 671 lb/hr 

on a rolling 3-hour average that applies 

only to the hours when the unit is 

operated at less than 50% of the unit’s 

maximum heat input rating. We believe 

that these limits address the 

commenter’s concern of not being able 

to meet the lb/MMBtu emission limit 

when the unit is being operated at lower 

capacities, and will also ensure that 

NOX emissions are appropriately 

controlled when the units are operated 

at higher capacities, as well as when 

they are operated at lower capacities. 

Comment: Assuming EPA proceeds 

with BART for the Domtar Ashdown 

Mill, the mill conceptually agrees with 

the proposed BART SO2 limit for Power 

Boiler 1 of 21.0 lb/hr on a 30-day 

averaging basis with no add-on control. 

However, based on the methodology the 

mill uses to determine fuel usage, the 

emission limit needs to be expressed in 

an alternative form to better match with 

the compliance averaging time of 30 

days. Calculation of hourly SO2

emissions using hourly fuel usage 

information is not a workable approach 

for Power Boiler 1, where the facility’s 

practice is to use monthly fuel usage 

information that is reconciled at the end 

of each month based on fuel inventory 

records. Records of daily fuel usage may 

be adjusted at the end of the month as 

part of the reconciliation process. 

Therefore, Domtar requests the BART 

limit of 21.0 lb/hr be expressed as 504 

lb/day. 

Response: After carefully considering 

this comment we have determined that 

Domtar’s request for an SO2 BART 

emission limit in terms of lb/day is 

reasonable. An emission limit in terms 

of lb/day will be better suited for the 

mill’s methodology of using monthly 

fuel throughput information. Therefore, 

as requested by the facility, we are 

finalizing an SO2 BART emission limit 

of 504 lb/day for Power Boiler No. 1. 

E. Domtar Ashdown Mill Repurposing 

Project 

Comment: The Domtar Ashdown Mill 

is in the process of re-purposing and is 

in a state of transition. Once the repurposing and re-configuration is 

complete and the mill is fully 

operational, the mill will need to decide 

if Power Boiler 1 will continue with full 

or intermittent operation, and if so what 

fuels will be used, or will be retired. If 

the boiler is fuel switched to natural gas 

or the boiler retired, the SO2 BART limit 

will be unnecessary along with the 

associated monitoring, recordkeeping 

and reporting requirements for the SO2

BART limit. The Ashdown Mill is 

requesting EPA include in the FIP final 

rule an alternate compliance option that 

removes all of SO2 BART related 

requirements for Power Boiler 1 if this 

boiler is switched to burn only natural 

gas. If Power Boiler 1 is switched to 

burn only natural gas, requirements for 

NOx testing also need to be removed 

and an alternate NOX BART compliance 

option needs to be developed to allow 

compliance to be based on the use of 

AP–42 emission factors and fuel use 

records. If Power Boiler 1 is retired, 

there is no need to retain the SO2 and 

NOX BART limits and associated 

requirements, and an alternate BART 

compliance option should address this 

retirement scenario as well. 

Response: We proposed an SO2 BART 

emission limit of 21.0 lb/hr for Power 

Boiler No. 1. As discussed in section IV. 

of this final rule, we are finalizing an 

emission limit in terms of lb/day, as 

requested by Domtar. We proposed to 

find that to demonstrate compliance 

with this SO2 BART emission limit, the 

facility was required to use a sitespecific curve equation (provided to us 

by the facility) to calculate the SO2

emissions from Power Boiler No. 1 

when combusting bark, and to confirm 

the curve equation using stack 

testing.159 We also proposed to find that 

to calculate the SO2 emissions from 

Power Boiler No. 1 when combusting 

fuel oil, the facility must assume that 

the SO2 inlet is equal to the SO2 being 

emitted at the stack.160 In our proposal 

we invited public comment specifically 

on the issue of whether our proposed 

method of demonstrating compliance is 

appropriate. 

We note that we became aware that 

Power Boiler No. 1 wished to burn only 

natural gas after the end of the comment 

period for our proposal, and that the 

facility has submitted a permit renewal 

application to ADEQ that will reflect 

this enforceable change.161 We do not 

agree that the SO2 BART emission limit 

becomes ‘‘unnecessary’’ when a unit is 

switched to burn only natural gas. The 

Regional Haze regulations define BART 

as an emission limitation based on the 

degree of reduction achievable through 

the application of the best system of 

continuous emission reduction for each 

pollutant which is emitted by an 

existing stationary facility.162 Therefore, 

a BART emission limit is still applicable 

and is required regardless if the unit 

switches to natural gas. However, the 

repurposing project the mill is currently 

undergoing and the fact that the 

facility’s air permit will be revised such 

that Power Boiler No. 1 will be 

permitted to burn only natural gas 

render it appropriate to provide the 

facility with flexibility in demonstrating 

compliance with the SO2 emission limit. 

Therefore, in addition to the method we 

proposed for demonstrating compliance 

with the SO2 BART emission limit for 

Power Boiler No. 1, we are also 

finalizing one alternative method for 


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163 40 CFR 51.301. 

demonstrating compliance: The owner 

or operator may demonstrate 

compliance with the SO2 emission limit 

by switching Power Boiler No. 1 to burn 

only pipeline quality natural gas. 

Therefore, if the facility’s air permit is 

revised to reflect that Power Boiler No. 

1 is permitted to burn only pipeline 

quality natural gas, this would satisfy 

the requirement for demonstrating 

compliance with the boiler’s SO2 BART 

emission limit, and the reporting and 

recordkeeping requirements would be 

waived. We are revising proposed 

§ 52.173 to reflect this. 

We are finalizing our determination 

that NOX BART for Power Boiler No. 1 

is an emission limit of 207.4 lb/hr. We 

proposed that to demonstrate 

compliance with this NOX BART 

emission limit, the facility was required 

to conduct annual stack testing. In 

response to a separate comment 

provided by Domtar, in our final FIP we 

are requiring stack testing every five 

years instead of annually to demonstrate 

compliance with the NOX BART 

emission limit. The repurposing project 

the mill is currently undergoing and the 

fact that the facility’s air permit will be 

revised such that Power Boiler No. 1 

will be permitted to burn only natural 

gas render it appropriate to provide the 

facility with flexibility in demonstrating 

compliance with the NOX emission 

limit. Therefore, we are also providing 

one alternative method for 

demonstrating compliance with the 

NOX emission limit: If the facility’s air 

permit is revised to reflect that Power 

Boiler No. 1 is permitted to burn only 

pipeline quality natural gas, the facility 

may demonstrate compliance with the 

NOX emission limit by calculating 

emissions using AP–42 emission factors 

and fuel usage records. Under these 

circumstances, the facility would not be 

required to demonstrate compliance 

with the NOX BART emission limit for 

Power Boiler No. 1 through stack 

testing. We are revising proposed 

§ 52.173 to reflect this. 

With regard to the request that we 

include a provision in our FIP that 

removes all SO2 and NOX BART related 

requirements for Power Boiler 1 if this 

boiler is permanently retired in the 

future, we noted above that the Regional 

Haze regulations define BART as an 

emission limitation based on the degree 

of reduction achievable through the 

application of the best system of 

continuous emission reduction for each 

pollutant which is emitted by an 

existing stationary facility. The BART 

emission limits and applicable 

requirements continue to apply 

regardless if a BART source is 

mothballed or retired/shut down 

without being dismantled, 

decommissioned, and having the air 

permit revoked. In the event that the 

BART source is permanently shut down, 

dismantled, decommissioned, and the 

permit revoked in the future, the 

process for removing the BART 

emission limits and applicable 

requirements would necessarily involve 

a request by the company for partial FIP 

withdrawal or a SIP revision from the 

State in the event that we have 

approved a SIP revision that replaces 

our FIP. We are committed to work with 

ADEQ and the facility to partially 

withdraw our FIP with respect to the 

emission limits for the BART unit or 

revise the SIP if at some point in the 

future the company decides to 

permanently shut down, dismantle, and 

decommission the boiler and surrender 

the air permit. 

Further, we consider the conditions 

under which a unit is permanently 

retired and the mechanism by which 

this is made enforceable to be critical. 

Because the company has not decided if 

and when Power Boiler No. 1 will be 

permanently retired or decided what the 

conditions of the retirement will be, we 

believe that it is reasonable and 

appropriate to wait until the company 

makes these decisions instead of 

including a provision in our FIP that 

waives the BART recordkeeping 

requirements in anticipation that the 

unit’s permanent retirement will take 

place under certain conditions and 

made enforceable through a particular 

mechanism that may be different from 

what ultimately takes place. 

Comment: If Power Boiler 2 is fuel 

switched to natural gas or retired as part 

of the Domtar Ashdown Mill’s 

repurposing project, there is no need to 

retain the SO2 and PM BART limits and 

the associated monitoring, 

recordkeeping and reporting 

requirements for the SO2 and PM BART 

limits. The Ashdown Mill requests that 

EPA include in the FIP final rule an 

alternative compliance option which 

removes the SO2 and PM BART limits 

and the associated requirements if the 

boiler is fuel switched to natural gas or 

permanently retired. Additionally, if 

Power Boiler 2 is fuel switched to 

natural gas as part of the Domtar 

Ashdown Mill’s repurposing project, the 

NOX BART requirements need to be 

modified to require compliance based 

on the use of AP–42 emission factors 

and fuel use records. The requirement to 

operate and maintain a NOX CEM needs 

to be removed. If Power Boiler 2 is 

retired, all the BART requirements are 

unnecessary. The Ashdown Mill 

requests that EPA include alternate 

compliance options in the FIP final rule 

provisions to address these potential 

scenarios. 

Response: We are finalizing an SO2

BART emission limit of 91.5 lb/hr and 

we are finalizing our determination that 

compliance with the Boiler MACT PM 

standard as revised satisfies the PM 

BART requirement for Power Boiler No. 

2. We proposed to require the facility to 

demonstrate compliance with the SO2

emission limit for Power Boiler No. 2 

using the existing CEMS, and to 

demonstrate compliance with the PM 

emission limit using the same method 

that is used for demonstrating 

compliance with the Boiler MACT PM 

standard. We are finalizing these 

methods for demonstrating compliance 

with the SO2 and PM emission limits for 

Power Boiler No. 2. With regard to the 

commenter’s request that we include an 

alternate compliance option in our FIP 

that removes the SO2 and PM BART 

limits if the boiler is switched to natural 

gas, we do not have the authority to do 

this. The Regional Haze regulations 

define BART as an emission limitation 

based on the degree of reduction 

achievable through the application of 

the best system of continuous emission 

reduction for each pollutant which is 

emitted by an existing stationary 

facility.163 The BART emission limits 

are still applicable and are required 

regardless if the unit is switched to 

natural gas. However, the repurposing 

project the mill is currently undergoing 

and the possibility of Power Boiler No. 

2 being converted to burn only natural 

gas render it appropriate to provide the 

facility with flexibility in demonstrating 

compliance with the SO2 and PM 

emission limits for Power Boiler No. 2. 

Therefore, we are providing one 

alternative method for demonstrating 

compliance with the SO2 and PM 

emission limits: The owner or operator 

may demonstrate compliance with these 

emission limits by switching Power 

Boiler No. 2 to burn only natural gas. 

Therefore, if Power Boiler No. 2 is 

switched to burn only pipeline quality 

natural gas, and the air permit is revised 

to reflect this change, this would satisfy 

the requirement for demonstrating 

compliance with the boiler’s SO2 and 

PM BART emission limits, and the 

related reporting and recordkeeping 

requirements would be waived. Under 

these circumstances, the SO2 and PM 

BART determinations for Power Boiler 

No. 2 would continue to apply but the 

facility would be able to demonstrate 

compliance with these emission limits 

by virtue of switching to natural gas and 

it would not be required to use the 

existing CEMS to demonstrate 


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compliance with the SO2 BART 

emission limit. We are revising 

proposed § 52.173 to reflect this. 

We are requiring Power Boiler No. 2 

to meet an emission limit of 345 lb/hr 

to satisfy the NOX BART requirement. 

We proposed to require the facility to 

demonstrate compliance with this NOX

emission limit using the existing CEMS, 

and we are finalizing this method for 

demonstrating compliance. However, 

the repurposing project the mill is 

currently undergoing and the possibility 

of Power Boiler No. 2 being converted 

to burn natural gas only render it 

appropriate to provide the facility with 

flexibility in demonstrating compliance 

with the NOX emission limit. Therefore, 

we are providing one alternative method 

for demonstrating compliance with the 

NOX emission limit: If Power Boiler No. 

2 is switched to burn only pipeline 

quality natural gas, and the air permit is 

revised to reflect this, the facility may 

demonstrate compliance with the NOX

emission limit by calculating emissions 

using AP–42 emission factors and fuel 

usage records. Under these 

circumstances, the facility would not be 

required to use the existing CEMS to 

demonstrate compliance with the NOX

BART emission limit. We are revising 

proposed § 52.173 to reflect this. 

We do not have the authority to 

include in our FIP a provision that 

removes all SO2, NOX, and PM BART 

requirements for Power Boiler No. 2 if 

it is permanently retired in the future. 

As noted above, the Regional Haze 

regulations define BART as an emission 

limitation based on the degree of 

reduction achievable through the 

application of the best system of 

continuous emission reduction for each 

pollutant which is emitted by an 

existing stationary facility. The BART 

emission limits and applicable 

requirements continue to apply 

regardless if a BART source is 

mothballed or retired/shut down 

without being dismantled, 

decommissioned, and having the air 

permit revoked. In the event that the 

BART source is permanently shut down, 

dismantled, decommissioned, and the 

permit revoked in the future, the 

process for removing the BART 

emission limits and applicable 

requirements would necessarily involve 

a request for a partial FIP withdrawal or 

a SIP revision in the event that we have 

approved a SIP revision that replaces 

our FIP. We are committed to work with 

ADEQ and the facility to partially 

withdraw our FIP with respect to the 

emission limits for the BART unit or 

revise the SIP if at some point in the 

future the company decides to 

permanently shut down, dismantle, and 

decommission the boiler and surrender 

the air permit. 

Further, we consider the conditions 

under which a unit is permanently 

retired and the mechanism by which 

this is made enforceable to be critical. 

Because the company has not decided if 

and when Power Boiler No. 2 will be 

permanently retired or decided what the 

conditions of the retirement will be, we 

believe that it is reasonable and 

appropriate to wait until the company 

makes these decisions instead of 

including a provision in our FIP that 

waives the BART recordkeeping 

requirements in anticipation that the 

unit’s permanent retirement will take 

place under certain conditions and 

made enforceable through a particular 

mechanism that may be different from 

what ultimately takes place. 

Comment: EPA proposes to require 

compliance with the SO2 BART 

emission limit for Power Boiler 2 within 

3 years of the effective date of the final 

rule. EPA also proposes compliance 

with the NOX BART emission limit 

within 3 years of the effective date of 

the final rule. With the mill 

transformation and re-purposing project 

and all of the work associated with this 

huge undertaking, the Ashdown Mill 

needs a 5-year compliance window from 

the effective date of the final rule for the 

SO2 and NOX BART requirements for 

Power Boiler 2 (assuming EPA decides 

to proceed with BART for the mill). As 

announced in late 2014, the mill is 

converting a paper machine to produce 

fluff pulp. This transformation project is 

being driven by the continued decline 

in the demand for paper products. 

Power 1 and Power Boiler 2 are part of 

the mill’s steam generating components, 

and are operated to produce steam that 

is needed for the manufacturing of pulp 

and paper products. It is anticipated 

that this mill transformation project may 

significantly affect mill steam demands 

reducing the amount of steam needed 

from Power Boiler 1 and 2. Ultimately, 

this transformation project may 

determine future use of Power Boiler 2. 

Once the re-purposing and reconfiguration of the mill systems is 

complete and fully operational, the mill 

will decide whether Power Boiler 2 will 

continue with full or intermittent 

operation, if so, using what fuels, or will 

it be permanently retired. In order to 

make this decision, the mill will need 

to go through the startup, initial 

operation and a shakedown period with 

the new fluff pulp process. Since this is 

a significant change for the mill it is 

uncertain how long it will take to learn 

how to operate and to optimize in this 

newly configured state. The mill will 

then need at least 2 winter cycles to 

understand what the maximum steam 

demand requirements will be for the 

newly configured mill. The repurposing project is scheduled to be 

completed and the newly configured 

mill is anticipated to start-up in late 

2016. The mill will operate through the 

winter of 2016–2017 and will be 

learning how to operate and optimize 

the new process. The winter of 2017– 

2018 will be the first real indicator of 

what winter steam demands will be in 

the re-purposed state. For the purposes 

of selecting an appropriate BART 

compliance schedule and future mill 

operations, the understanding of how 

the Power Boilers will operate and on 

what fuels is essential. The project 

schedule will set these key decision 

points in late 2018. Once the decision 

on mill steam needs and boiler 

utilization is made, additional time is 

required to implement the boiler 

scenario selected by the mill. These 

scenarios could range from the 

mothballing or retiring Power Boilers 1 

or 2 to shifting fuels. In addition, 

changes involving the combustion of the 

NCG gases and the shared biomass feed 

system also need to be determined and 

new systems engineered and permitted, 

as needed. Another factor to be 

considered is determining the ability of 

the existing SO2 scrubber to 

continuously operate at 90% removal on 

a long-term basis. If Power Boiler 2 

continues to use solid fuels, additional 

time is needed to optimize the existing 

scrubber to consistently perform at this 

higher level of control efficiency on a 

long-term basis. Given the mill’s 

interconnected nature as well as the 

complex aspects of the re-purposing 

project, a 5-year compliance schedule 

for achieving the SO2 BART and NOX

BART requirements for Power Boiler 2 

is essential. 

Response: We have reconsidered the 

SO2 and NOX BART compliance dates 

for Power Boiler No. 2 in response to 

this comment. We understand the 

commenter’s concerns with respect to 

how the transformation and repurposing 

project the mill is currently undertaking 

may significantly affect mill steam 

demands and may ultimately determine 

future use of Power Boiler No. 2. We 

understand that the mill will decide the 

future use of Power Boiler No. 2, 

including whether it will be converted 

to other fuels or permanently retired, 

after the repurposing and 

reconfiguration of the mill systems is 

complete and fully operational and after 

the mill has learned how to operate and 

to optimize in its newly configured 

state. Our understanding from the 

comments is that Ashdown Mill expects 


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164CAA section 169A(b)(2)(A) and (g)(4). 

to make this decision in late 2018, but 

that additional time will be needed to 

implement the boiler scenario selected 

by the mill, which could include 

switching fuels, mothballing or retiring 

the boilers, or continued operation and 

combustion of solid fuels and 

installation of air pollution controls to 

meet the BART emission limits. It is not 

EPA’s intention to place an undue 

burden on the Domtar Ashdown Mill by 

requiring a compliance date that may 

not provide sufficient time for the mill 

to install controls or otherwise make the 

necessary operating changes to meet the 

boiler’s BART emission limits. While 

we believe that a 3-year compliance date 

is generally sufficient for installation of 

the controls on which the BART 

emission limits are based, due to the 

special circumstances in this case we 

believe that it is reasonable and 

appropriate to establish a longer 

compliance date particularly since it 

could avoid unnecessary investment in 

a scrubber that may be no longer needed 

due shutdown or fuel switch. Therefore, 

we are requiring that the mill comply 

with the SO2 and NOX BART emission 

limits no later than 5 years from the 

effective date of this final rule and have 

amended the proposed regulatory text to 

reflect this change. We believe that this 

adequately addresses the commenter’s 

concerns while in keeping with the 

CAA mandate that compliance with 

BART requirements must be as 

expeditiously as practicable but in no 

event later than 5 years after 

promulgation of this FIP. 

F. Other Compliance Dates 

Comment: EPA proposed compliance 

with the SO2 and NOX BART limits for 

Power Boiler 1 and for the PM BART 

limit for Power Boiler No. 2 to be on the 

effective date of the final rule. Should 

EPA proceed with imposing these BART 

limits, the Ashdown Mill requests the 

compliance date be changed to 30 

calendar days after effective date of the 

final rule. That will give the mill 

additional time to prepare the 

compliance records if there is a short 

period between when the rule is 

promulgated and the effective date, 

especially if the effective date of the 

final rule falls on a weekend or a 

holiday. In addition, if any confusion 

exists regarding exactly when the 

effective date is, the cushion of 30 days 

helps to provide more certainty. This 

extra time will be needed if EPA 

finalizes any changes to definitions or 

other requirements that require the 

Ashdown to adjust recordkeeping 

systems. 

Response: We are finalizing a NOX

BART emission limit of 207.4 lb/hr for 

Power Boiler No. 1, which is what we 

proposed. We proposed an SO2 BART 

emission limit of 21.0 lb/hr for Power 

Boiler No. 1, and as discussed in section 

IV. of this final rule, we are finalizing 

an emission limit of 504 lb/day. We are 

finalizing our determination that 

compliance with the Boiler MACT PM 

standard satisfies the PM BART 

requirement for Power Boiler No. 2. As 

discussed elsewhere in this section of 

the final rule, we are finalizing some 

changes to the definitions and BART 

requirements for Power Boiler No. 1. 

After carefully considering this 

comment, we have determined that 

extending the compliance dates 

associated with the aforementioned 

BART emission limits for Power Boiler 

No. 1 is appropriate because it is a 

reasonable request that will allow the 

owner or operator of the affected facility 

to prepare applicable compliance 

records and adjust recordkeeping 

systems without unduly delaying 

compliance with the BART requirement. 

Therefore, we are revising the 

compliance dates we proposed for the 

SO2 and NOX BART emission limits for 

Power Boiler No. 1 and the PM BART 

requirement for Power Boiler No. 2 such 

that the owner or operator must comply 

with these emission limits no later than 

30 calendar days from the effective date 

of the final rule. 

Comment: EPA’s proposed BART 

requirements will require installation of 

new emission controls on utility electric 

generation resources at a significant 

cost. The utilities will pass these costs 

on to Arkansas ratepayers. The 

Ashdown Mill, like other energy 

intensive manufacturers, will be 

affected by the increasing cost of electric 

power needed to operate our processes. 

EPA should also consider other 

emerging regulatory initiatives that will 

be driving substantial changes to major 

coal burning facilities. Manufacturing 

facilities, such as the Ashdown Mill, are 

undertaking major transformation 

projects that potentially may result in a 

move away from coal and other 

emerging regulations targeting utilities 

are likely to further reduce coal burning 

and further remove visibility concerns. 

A practical alternative to EPA’s 

proposed compliance dates is for EPA to 

use its discretion under the Regional 

Haze Rule and delay the Arkansas 

BART requirements for all sources for 

five years. This will align compliance 

timelines so that the full effects of all of 

these regulatory changes will be known. 

Facilities affected by these other 

requirements can plan holistic 

compliance strategies rather than being 

compelled to follow an expensive and 

potentially wasteful piecemeal 

approach. Using the maximum 5-year 

window allowed under BART will 

provide the Ashdown Mill the time to 

determine if coal will continue as a fuel 

for the facility. It will also provide the 

other affected sources in Arkansas with 

time to address the Clean Power Plan 

strategies and other significant 

regulatory programs that may also 

remove coal as a fuel. The effect of 

allowing a full 5-year compliance 

program will thereby minimize the 

potential for stranded assets and 

minimize the cost increases on 

companies and on ratepayers. This 

approach is further compelled by the 

fact that Arkansas is more than meeting 

its ‘‘glide path’’ as discussed above. 

Response: We acknowledge the 

commenter’s concerns related to the 

potential increase in utility rates for 

Arkansas ratepayers as well as to 

potential requirements related to other 

CAA and EPA regulatory actions. We 

agree that multiple regulatory actions 

are pending that will affect the power 

sector and that regulatory development 

should be coordinated when possible 

while still meeting the statutory and 

regulatory requirements for compliance. 

We also recognize the importance of 

long-term and coordinated planning on 

the parts of owners of industrial sources 

that are subject to BART. However, we 

disagree that our FIP presents a tight or 

unreasonable regulatory timeline. It is 

an appropriate timeline for costeffective control measures needed to 

meet the regional haze requirements. 

The CAA and Regional Haze Rule 

require the installation and operation of 

BART, in particular, to be carried out 

expeditiously. The CAA defines the 

term ‘‘as expeditiously as practicable’’ 

to mean ‘‘as expeditiously as practicable 

but in no event later than five years after 

the date of approval of a [Regional Haze] 

plan revision. . . .’’ 164 Therefore, we 

do not have the authority to delay 

compliance dates across the board for 

all subject-to-BART sources in Arkansas 

to allow time for greater certainty 

regarding requirements associated with 

other CAA and regulatory requirements. 

We also disagree that ADEQ’s finding 

that Arkansas Class I areas are projected 

to be below the URP glidepath in 2018 

is sufficient justification for delaying the 

compliance dates for all subject-toBART sources in Arkansas. We address 

other more specific comments related to 

this issue in a separate response. 

In determining what is ‘‘as 

expeditiously as practicable’’ for 

installation and operation of a particular 

control technology, the states and EPA 


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165 40 CFR 51.308(e)(1)(iv). 

166See 7/10/2013 SWEPCO News Release, 

SWEPCO Receives Arkansas Commission Approval 

for Flint Creek Plant Project, at https://

www.swepco.com/info/news/

viewRelease.aspx?releaseID=1424. 

167See Stamper Report at 14 (citing October 25, 

2013 Permit No. 0276–AOP–R6 at 5 (Ex. 29 to 

Stamper Report)). 

168Stamper Report at 14 (citing Flint Creek 

Retrofit Project, SWEPCO News & Info Site at 

https://swepco.com/info/projects/FlintCreek/; 

March 26, 2014 Independent Monitor Report for 

AEP Flint Creek Plant Unit 1, submitted to the 

Arkansas Public Service Commission under Docket 

No. 12–008–U, at (Ex. 30 to Stamper Report)). 

169CAA section 169A(b)(2)(A). 

170https://www.swepco.com/info/projects/

FlintCreek/. 

171See the Arkansas PSC Web site at http://

www.apscservices.info/efilings/docket_search.asp. 

The quarterly reports the company is required to 

submit to the Arkansas PSC are available by 

searching for docket No. 12–008–U. 

172See file titled ‘‘Record of Call- Flint Creek_

August 10 2016,’’ which is found in the docket for 

this rulemaking. 

usually consider the amount of time it 

generally takes to install and operate 

that type of technology at similar 

sources and the compliance dates that 

have been required for the installation 

and operation of the same type of 

control technology at similar sources in 

other regional haze actions, especially if 

there are no source-specific 

considerations or other special 

circumstances that would prevent the 

source from installing and operating the 

control technology within the same 

amount of time. For example, where a 

particular control technology can 

generally be installed and operated in 3 

years, and where there are no sourcespecific considerations or other special 

circumstances that would affect the 

facility’s ability to install and operate 

the control technology within that time 

frame, it would not be in accordance 

with the CAA and the Regional Haze 

Rule to allow a 5-year compliance 

period because that would not be as 

expeditiously as practicable. 

Additionally, considering that most 

other states already have plans in place 

that fully address the regional haze 

requirements, it would be inequitable 

and contrary to the intent of the CAA 

and the Regional Haze Rule to further 

delay implementation of regional haze 

requirements in Arkansas by allowing a 

5-year compliance date across the board 

for all of Arkansas’ subject-to-BART 

sources. Therefore, we disagree that it is 

appropriate for us to allow a 5-year 

compliance date for all subject-to-BART 

sources in Arkansas, rather than 

establishing deadlines consistent with 

the facts and regulatory requirements in 

each instance. 

We do note that we are revising some 

of the compliance dates we proposed in 

response to source-specific 

considerations raised in other 

comments. We address these comments 

in separate responses. 

Comment: If EPA’s final SO2 BART 

determination for Flint Creek Unit 1 is 

based on installation of a NID dry 

scrubber, EPA should impose a shorter 

compliance deadline, as required by the 

Act. EPA’s proposed FIP requires Flint 

Creek Unit 1 to comply with the SO2

BART determination within five years 

from the effective date of the final rule. 

Yet the statute requires a source to 

comply with BART as expeditiously as 

possible, but no later than five years 

from the effective date of EPA’s action 

on the regional haze plan.165 AEP could 

install a NID scrubber at Flint Creek 

much more expeditiously than five 

years from the effective date of the rule. 

The utility has already obtained an 

Arkansas PSC order finding that NID 

dry scrubber installation is in the public 

interest.166 ADEQ has already issued a 

Title V air permit for scrubber 

construction and operation at Flint 

Creek.167 Further, it appears that on-site 

construction of the NID scrubber has 

begun, and that the Flint Creek owners 

intend to operate it by May 29, 2016, in 

order to comply with EPA’s MATS 

rule.168 Thus, given that AEP is 

currently installing the NID scrubber 

with a May 2016 planned operation 

date, EPA’s five-year SO2 BART 

compliance deadline does not comply 

with the statutory requirement that 

BART controls be installed ‘‘as 

expeditiously as practicable,’’ 169 Since 

AEP is installing the NID scrubber for 

MATS as well as BART compliance, 

EPA should require SO2 BART 

compliance at Flint Creek by no later 

than May 29, 2016. 

Response: We acknowledge the 

information provided by the commenter 

regarding AEP Flint Creek’s plans to 

complete installation of the NID system 

in 2016 in order to comply with 40 CFR 

part 63, subpart UUUUU—National 

Emission Standards for Hazardous Air 

Pollutants: Coal- and Oil-Fired Electric 

Utility Steam Generating Units, 

otherwise known as the Utility MATS 

Rule. MATS establishes emission limits 

for three categories of pollutants: 

Mercury, acid gases (HCl and SO2), and 

non-mercury hazardous air pollutant 

(HAP) metals. To address acid gases, an 

EGU must comply with an HCl emission 

limit unless it is equipped with a wet or 

dry FGD or DSI and an SO2 CEMS, in 

which case it has the option of 

complying with an alternative SO2

emission limit. The applicable 

alternative SO2 emission limit is 0.2 lb/ 

MMBtu. 

The commenter has made us aware 

that the Arkansas PSC has determined 

that dry scrubber installation at Flint 

Creek is in the public interest and that 

the installation of those controls is 

already underway and anticipated by 

the company to be complete by May 29, 

2016. The commenter also points to the 

air permit issued to Flint Creek by 

ADEQ on October 25, 2013, which 

allows for the installation and operation 

of new control equipment and 

associated material handling systems to 

comply with the requirements of the 

Utility MATS Rule. These controls 

include a NID system on Unit 1. The 

AEP–SWEPCO Web site also indicates 

that the installation of these scrubber 

controls is driven by MATS and future 

Regional Haze rules.170 A timeline 

provided on the Web site states that 

construction of these controls began in 

October 2013 and that installation will 

be complete and the facility will be 

operating with these controls by the end 

of May 2016. In addition, the 

commenter has made us aware that the 

Arkansas PSC requires Flint Creek to 

provide quarterly reports on the 

progress of the installation of these 

controls. The first report the company 

submitted to the Arkansas PSC is dated 

March 26, 2014, and stated that the FGD 

project includes the installation of an 

Alstom NID system to comply with 

MATS and in anticipation of the BART 

requirements. The report also stated that 

the NID system and associated 

equipment are to be constructed at Flint 

Creek Unit 1, and that the company 

established design, procurement, and 

construction schedules to bring the 

upgraded plant fully on line by May 29, 

2016. The commenter provided the 

report as an attachment to the comments 

submitted, but this and all other 

quarterly reports the company 

submitted to the Arkansas PSC are 

available online.171 The most recent 

quarterly report available on the 

Arkansas PSC Web site is dated March 

10, 2016, and covers the fourth quarter 

in 2015. This report indicated that the 

company still expected the upgraded 

plant to be fully on line by May 29, 

2016. We verified the status of the 

installation of the controls with the 

company, who confirmed that 

installation of the NID controls was 

completed in June 2016, and that the 

plant is now operating with those 

controls.172

After carefully considering the 

information the commenter has brought 

to our attention, we no longer believe 

that a 5-year compliance date is 

appropriate for the SO2 BART controls 


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66378 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

173See comments and exhibits submitted by 

Earthjustice, the National Parks Conservation 

Association, and Sierra Club, dated August 7, 2015. 

These and all other comments submitted during the 

public comment period are found in the docket 

associated with this rulemaking. 174 40 CFR 51.308(e)(1)(iv). 

we are requiring for Flint Creek. We 

agree with the commenter that BART 

controls must be installed as 

expeditiously as practicable. CAA 

section 169A(b)(2)(A). Therefore, we are 

finalizing a shorter compliance date. 

The information made available to us 

during the comment period, as 

discussed above, indicates that Flint 

Creek intends to operate the NID system 

to comply with the alternative SO2

emission limit under the Utility MATS 

rule. The applicable SO2 emission limit 

is 0.2 lb/MMBtu. The SO2 emission 

limit we are requiring in our FIP to 

satisfy the BART requirement is 0.06 lb/ 

MMBtu. As indicated in the information 

and other documentation the 

commenter provided, the company 

plans to use the same NID system to 

comply with MATS and to comply with 

the facility’s SO2 BART requirement. 

We expect that to achieve an emission 

rate of 0.06 lb/MMBtu, additional 

scrubbing reagent would be needed 

beyond that required to meet the 0.2 lb/ 

MMBtu emission limit the company is 

required to meet by April 2016 under 

MATS. We also recognize that it is 

possible that the reagent handling 

system installed to meet the 0.2 lb/

MMBtu emission limit would need 

some upgrades in order to accommodate 

the additional scrubbing reagent that 

would be needed to achieve the more 

stringent 0.06 lb/MMBtu emission limit 

we are requiring in this FIP. Therefore, 

to allow the facility sufficient time to 

secure the additional scrubbing reagent 

that would be needed to comply with 

the SO2 BART emission limit and to 

make any necessary upgrades to the 

reagent handling system, we are 

finalizing an 18-month compliance date 

for Flint Creek Unit 1 to comply with 

the SO2 BART requirement. We believe 

this is will provide sufficient time for 

the facility to be able to achieve the SO2

BART requirement while still meeting 

the statutory mandate that BART 

controls be installed as expeditiously as 

practicable. 

Comment: If EPA’s final NOX BART 

determination for White Bluff is based 

on installation of a SCR with LNB/

SOFA, EPA should require a NOX BART 

compliance date for SCR at White Bluff 

of no later than within 3 years of the 

final rule’s effective date, which would 

represent the expeditious 

implementation required by CAA 

section 169A(b)(2)(A). The NOX BART 

compliance date for LNB/SOFA should 

be 8 months from the final rule’s 

effective date. If EPA finalizes its 

proposal to require LNB/SOFA only as 

NOX BART for White Bluff, EPA should 

require compliance within 8 months of 

the final rule’s effective date. Eight 

months is sufficient time for installation 

of these controls. These same comments 

apply and should be extended to EPA’s 

reasonable progress determination for 

NOX for Independence Units 1 and 2. 

Response: We are requiring White 

Bluff Units 1 and 2 and Independence 

Units 1 and 2 to each meet a NOX

emission limit of 0.15 lb/MMBtu on a 30 

boiler-operating-day rolling average, 

where the average is to be calculated by 

including only the hours during which 

the unit was dispatched at 50% or 

greater of maximum capacity. In 

addition, we are requiring each unit to 

meet a NOX emission limit of 671 lb/hr 

on a rolling 3-hour average that is 

applicable only when the unit is being 

operated at less than 50% of the unit’s 

maximum heat input rating. These 

emission limits are consistent with the 

installation and operation of LNB/SOFA 

controls. In light of the comment, we 

have reconsidered the compliance date 

for the NOX BART requirements for 

White Bluff Units 1 and 2 and for the 

NOX controls under reasonable progress 

for Independence Units 1 and 2. Based 

on the supporting information provided 

by the commenter, we agree with the 

commenter that 6–8 months is the 

typical installation timeframe for LNB/ 

OFA controls.173 However, in 

determining the appropriate compliance 

date for these NOX controls, we have 

also taken into consideration that we are 

finalizing NOX emission limits that are 

based on LNB/OFA or LNB/SOFA 

controls for a total of five EGUs in this 

FIP and that the installation of these 

controls will require outage time. These 

five EGUs are Flint Creek Unit 1, White 

Bluff Units 1 and 2, and Independence 

Units 1 and 2, and combined they 

accounted for approximately 45% of the 

state’s 2015 heat input. Because of the 

heavy reliance on these EGUs for 

electricity generation in the state, we 

recognize that it may be difficult to 

schedule outage time to install LNB/ 

OFA or LNB/SOFA on all five of these 

Arkansas units within the typical 

installation timeframe of 6–8 months 

and at the same time supply adequate 

electricity to meet demand in the state. 

In light of these unique circumstances, 

we find that it is appropriate to finalize 

an 18-month compliance date for White 

Bluff Units 1 and 2, Independence Units 

1 and 2, and Flint Creek Unit 1 to 

comply with the NOX emission limits 

required by this FIP. This compliance 

date provides the affected utilities 

sufficient time beyond typical LNB/OFA 

installation timeframes to install these 

controls and comply with their NOX

emission limits, while safeguarding the 

continuity of Arkansas’ electricity 

supply. 

We address comments contending 

that we should require SCR controls on 

White Bluff and Independence 

elsewhere in this final rule and in our 

RTC document. 

Comment: One commenter noted that 

the proposed FIP would require Flint 

Creek Unit 1 to comply with the NOX

BART requirement within 3 years of the 

effective date of the rule. The 

commenter argued that if EPA’s final 

NOX BART determination for Flint 

Creek is based on installation of LNB/ 

OFA, EPA should establish a shorter 

compliance deadline since compliance 

with BART is required as expeditiously 

as practicable.174 The commenter 

contends that AEP has been planning 

for the installation of LNB/OFA and that 

construction has already begun. The 

commenter argues that since the utility 

is currently installing LNB/OFA with a 

May 2016 planned operation date, EPA 

should require a NOX BART compliance 

date of no later than May 2016 in order 

to ensure the expeditious 

implementation required by law. 

AEP/SWEPCO, which is one of the 

owners of Flint Creek, also commented 

on our proposed NOX BART compliance 

date for Flint Creek Unit 1. The 

company stated that if EPA does not 

rely on CSAPR to satisfy the NOX BART 

requirement for EGUs in Arkansas, it 

supports EPA’s determination of LNB/ 

OFA controls as BART and the 

associated limits proposed by EPA. But 

the company stated that the proposed 3- 

year compliance timeframe is 

unreasonable. The company stated that 

the compliance time frame must allow 

for planning, selection of engineering 

and design professionals, vendors, 

contractors, permitting, start up and 

commissioning, and coordinating and 

scheduling unit outages. The company 

also argued that since EPA has allowed 

installation schedules up to 5 years in 

other states, we should allow such a 

time frame here. 

Response: We are finalizing our 

determination that NOX BART for AEP 

Flint Creek Unit 1 is an emission limit 

of 0.23 lb/MMBtu on a 30 boileroperating-day rolling average, which is 

consistent with the installation and 

operation of LNB/OFA. The commenter 

has not provided sufficient information 

to corroborate the claim that installation 

of LNB/OFA at Flint Creek Unit 1 is 


asabaliauskas on DSK3SPTVN1PROD with RULES
Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66379 

175See Arkansas Public Service Commission, 

Docket No. 12–008–U, Order No. 14, dated July 10, 

2013. A copy of the order can be found at http:// 

www.apscservices.info/pdf/12/12-008-u_227_1.pdf. 

176See the document titled ‘‘Technical Support 

Document to Comments of Conservation 

Organizations,’’ which is an attachment to the 

comments submitted by Earthjustice, the National 

Parks Conservation Association, and Sierra Club. 

These and all other comments submitted during the 

public comment period are found in the docket 

associated with this rulemaking. 

177http://www.apscservices.info/pdf/12/12-008- 

u_238_1.pdf. 

178See the comments submitted by AEP– 

SWEPCO, dated July 15, 2015 and August 7, 2015. 

These and all other comments submitted during the 

public comment period are found in the docket 

associated with this rulemaking. 

179See Excel file titled ‘‘Email from Domtar 

Regarding NOx Stack Test for PB1,’’ found in the 

docket for this final rule. The data provided by 

Domtar indicate that out of the stack testing 

conducted in 2001, 2002, 2003, 2004, 2005, and 

2010, the highest NOX emission rate from Power 

Boiler No. 1 was 171.3 lb/hr, compared to the 207.4 

lb/hr NOX emission limit we are finalizing. 

expected to be completed by May 2016. 

We acknowledge that on July 10, 2013, 

the Arkansas PSC filed an order 

agreeing that the installation of 

additional environmental controls at 

Flint Creek Unit 1, including LNB/OFA 

to meet the NOX BART requirement, is 

in the public interest.175 In the 

attachments to the comment, the 

commenter points to a news article that 

references a January 21, 2014 report 

submitted by AEP/SWEPCO to the 

Arkansas PSC.176 In that January 21, 

2014 report, AEP/SWEPCO announces 

that construction of environmental 

controls at Flint Creek commenced on 

January 20, 2014.177 However, the 

January 21, 2014 report does not specify 

if this includes construction of LNB/ 

OFA. While we acknowledge that there 

is publicly available information 

indicating that the company planned to 

complete installation of a NID system 

and activated carbon injection by May 

2016 to comply with the Utility MATS 

rule, there is no information available to 

us corroborating that the expected date 

of LNB/OFA installation was also May 

2016. In fact, the comments submitted 

by AEP/SWEPCO indicate that the 

company has not begun installation of 

these controls.178 With regard to AEP/ 

SWEPCO’s request that we extend the 

compliance date to 5 years, we have 

determined that the company has not 

provided any information regarding any 

special circumstances specific to the 

facility that sets it apart from other 

facilities and that would prevent it from 

completing installation of controls 

within typical 3-year LNB/OFA 

installation timeframes. 

Additionally, as discussed in a 

previous response, we agree that LNB/ 

OFA can typically be installed within a 

6–8 month timeframe. However, in 

determining the appropriate compliance 

date for these NOX controls, we have 

also taken into consideration that we are 

finalizing NOX emission limits that can 

be achieved by the installation of LNB/ 

OFA or LNB/SOFA controls for a total 

of 5 EGUs in this FIP. Because of the 

heavy reliance on these EGUs for 

electricity generation in the state and 

because it may be difficult to schedule 

outage time to install these controls on 

all five of these units within the typical 

installation timeframe of 6–8 months 

without disrupting the supply of 

electricity in the state, we are finalizing 

an 18-month compliance date for Flint 

Creek Unit 1 and the other EGUs to 

comply with the NOX emission limits 

required by this FIP. 

G. Compliance Demonstration 

Requirements 

Comment: For purposes of BART for 

the Domtar Ashdown Mill Power Boiler 

No. 1 and Power Boiler No. 2, EPA is 

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, consistent 

with the guidelines for utility boilers. 

However, the Ashdown Mill boilers are 

industrial boilers, not utility boilers. 

The Ashdown Mill defines a mill 

operating day to be a 24-hour period 

between 6 a.m. and 6 a.m. the following 

day. All of the mill’s systems for Power 

Boilers No. 1 and 2 are programmed 

around this definition of a mill 

operating day and modification of these 

systems would require a significant 

amount of effort and would require the 

gathering and maintaining of multiple 

sets of records. Assuming EPA proceeds 

with BART for the Ashdown Mill, the 

mill requests that for Power Boiler No. 

1 and Power Boiler No. 2 a boiler 

operating day be defined as ‘‘a 24-hr 

period between 6 a.m. and 6 a.m. the 

following day during which any fuel is 

fed into and/or combusted at any time 

in the power boiler.’’ Harmonizing the 

definitions of a boiler operating day and 

a mill operating day does not increase 

costs for the mill, reduces confusion for 

the mill operators, eliminates the need 

for maintaining multiple sets of records, 

and eliminates the need for changes to 

existing monitoring systems. We believe 

EPA is authorized or can use its 

discretion to define a boiler operating 

day for the Ashdown Mill to be 

consistent with the mill’s boiler 

operating day definition. 

Response: After carefully considering 

the comment, we agree that Domtar’s 

request is reasonable and that it is 

appropriate to harmonize the definitions 

of a boiler operating day and a mill 

operating day to avoid any unnecessary 

modification or reprogramming of 

Power Boilers 1 and 2. To accommodate 

Domtar’s request, for purposes of Power 

Boiler 1 and Power Boiler 2, in this final 

action we are defining a boiler operating 

day as ‘‘a 24-hr period between 6 a.m. 

and 6 a.m. the following day during 

which any fuel is fed into and/or 

combusted at any time in the power 

boiler.’’ We are revising proposed 

§ 52.173 to reflect this. 

Comment: EPA proposed to require 

compliance with the BART NOX limit 

for the Domtar Ashdown mill Power 

Boiler No. 1 be demonstrated with an 

annual stack test. Domtar agrees in 

general that stack testing is an 

appropriate method for demonstrating 

compliance. However, EPA’s proposal 

to require stack testing annually is not 

appropriate. Historical NOX stack test 

data from 2001, 2002, 2003, 2004, 2005, 

and 2010 for Power Boiler 1 show NOX

emissions to be fairly consistent. Based 

on the numerous previous stack tests, 

conducting stack tests annually is not 

warranted. Should EPA proceed with 

BART for the Ashdown Mill, the facility 

is requesting that stack testing to 

demonstrate compliance with the BART 

NOX limit be required every 5 years 

instead of annually, which is consistent 

with the Ashdown Mill’s Title V permit 

requirements. 

Response: After carefully considering 

the comment, we have reconsidered our 

proposed requirement of annual stack 

testing. We agree that the results of the 

NOX stack testing conducted by Domtar 

for Power Boiler No. 1 demonstrate that 

NOX emissions have historically 

remained well below the NOX emission 

limit we are finalizing for the boiler.179

Therefore, we agree with the company 

that it is appropriate to require stack 

testing every 5 years instead of 

annually. In our final action we are 

requiring that the facility demonstrate 

compliance with the NOX BART 

emission limit for Power Boiler No. 1 by 

conducting stack testing every five 

years, beginning no later than 1 year 

from the effective date of our final 

action. As discussed in a separate 

response, we are also providing one 

alternative method for demonstrating 

compliance with the NOX BART 

emission limit for Power Boiler No. 1. 

Specifically, if the facility’s air permit is 

revised to reflect that Power Boiler No. 

1 is permitted to burn only natural gas, 

the facility may demonstrate 

compliance with the NOX emission 

limit by calculating emissions using 

AP–42 emission factors and fuel usage 

records. Under these circumstances, the 


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66380 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

180 40 CFR 51.308(e); 77 FR 33642. 

181 76 FR 48208. 

182 77 FR 33642 (June 7, 2012). 

183Approval and Promulgation of 

Implementation Plans; Texas and Oklahoma; 

Regional Haze State Implementation Plans; 

Interstate Transport State Implementation Plan To 

Address Pollution Affecting Visibility and Regional 

Haze; Federal Implementation Plan for Regional 

Haze and Interstate Transport of Pollution Affecting 

Visibility, 79 FR 74818. 

184 79 FR 74818, 74851. 

185 79 FR 74818, 74853. 

186See CAA section 169A(g)(2) in which Congress 

defined the five factor analysis for determining 

BART but did not expressly provide for an 

alternative to source by source BART. 

facility would not be required to 

demonstrate compliance with the NOX

BART emission limit for Power Boiler 

No. 1 through stack testing. We are 

revising proposed § 52.173 to reflect 

this. 

Comment: Assuming EPA proceeds 

with BART for the Domtar Ashdown 

Mill, the mill agrees with the proposed 

BART PM limit of 0.44 lb/MMBTU for 

Power Boiler No. 2 based on the MACT 

standard for the ‘‘biomass hybrid 

suspension grate’’ sub-category 

contained in the 2013 Boiler MACT 

final rule. The Ashdown Mill agrees 

with EPA’s approach of relying on the 

Boiler MACT standards for PM to satisfy 

the PM BART requirement. However, 

for this streamlined BART approach, 

EPA must also ensure that the 

monitoring, recordkeeping, reporting 

requirements for PM BART are 

consistent with the monitoring, 

recordkeeping and reporting 

requirements under Boiler MACT. 

Deviating from the MACT requirements 

will result in additional administrative 

burden for the facility in maintaining 

‘‘multiple sets of compliance books.’’ It 

also will create confusion for external 

stakeholders if different values and 

information are being reported. 

Response: We generally agree with the 

comment. We proposed to find that the 

Domtar Ashdown Mill may rely on 

compliance with the Boiler MACT PM 

standard to satisfy the PM BART 

requirement for Power Boiler No. 2, and 

we did not intend for our FIP to 

establish requirements for compliance 

demonstration, monitoring, 

recordkeeping, and reporting different 

from those the mill is already required 

to comply with under the Boiler MACT 

PM standard. In our proposal, our intent 

was to propose requirements for 

compliance demonstration, monitoring, 

recordkeeping, and reporting for the PM 

BART limit for Power Boiler No. 2 that 

are consistent with those under the 

Boiler MACT PM standard. However, 

the commenter has brought to our 

attention that only some of the 

compliance demonstration, monitoring, 

recordkeeping, and reporting 

requirements associated with the Boiler 

MACT PM standard were included 

under our proposed § 52.173(c)(21) and 

(22) and that it appeared that we were 

proposing a separate and distinct set of 

requirements associated with our PM 

BART determination for Power Boiler 

No.2. Therefore, to ensure clarity and 

consistency, we are revising the 

regulatory text found under 40 CFR 

52.173(c) that applies to Power Boiler 

No. 2 for PM BART to state that the mill 

shall rely on compliance with the Boiler 

MACT PM standard under 40 CFR part 

63 Subpart DDDDD as revised to satisfy 

the PM BART requirement for Power 

Boiler No. 2. We interpret this to mean 

that compliance with the applicable 

Boiler MACT PM standard as revised is 

sufficient to demonstrate compliance 

with the PM BART requirement. We are 

not establishing a separate set of 

requirements for compliance 

demonstration, monitoring, 

recordkeeping, and reporting (i.e., in 

addition to those already required under 

the Boiler MACT PM standard, as 

revised), that Power Boiler No. 2 is 

required to comply with to satisfy the 

PM BART requirement. 

H. Reliance on CSAPR Better Than 

BART 

Comment: Arkansas is subject to a 

Cross-State Air Pollution Rule (CSAPR, 

also referred to as the Transport Rule) 

FIP for ozone-season NOX. EPA should 

not require sources that are subject to 

the CSAPR FIP to also install BART or 

additional emissions controls based on 

a reasonable progress analysis. The 

Regional Haze Rule allows states to 

implement an alternative program in 

lieu of BART so long as the alternative 

program has been demonstrated to 

achieve greater reasonable progress 

toward the national visibility goal than 

would BART.180 EPA published CSAPR 

as a replacement to CAIR on August 8, 

2011.181 In the final Transport rule, EPA 

demonstrated that CSAPR would make 

greater reasonable progress toward 

national visibility goals than would 

BART.182 EPA concluded in the final 

Transport rule that a state in the CSAPR 

region whose EGUs are subject to the 

requirements of the CSAPR trading 

program for ozone season NOX may rely 

on EPA’s finding that CSAPR makes 

greater reasonable progress than sourcespecific NOX BART. Despite EPA’s 

demonstration that CSAPR makes 

greater reasonable progress than sourcespecific BART, EPA makes no mention 

of CSAPR emissions controls in the FIP 

proposal and requires source specific 

NOX BART for Arkansas EGUs that are 

covered by CSAPR. The approach that 

EPA has proposed for Arkansas is 

inconsistent with that taken for other 

states. EPA promulgated FIPs to replace 

reliance on CAIR with reliance on 

CSAPR for the following states: Georgia, 

Indiana, Iowa, Kentucky, Michigan, 

Missouri, Ohio, Pennsylvania, South 

Carolina, Tennessee, Virginia and West 

Virginia. Similarly, Virginia is revising 

the Virginia Regional Haze SIP to rely 

on the Virginia CSAPR FIP to meet 

BART and reasonable progress 

requirements for SO2 and NOX. Perhaps 

most noteworthy, EPA has proposed 

reliance on CSAPR in states that border 

Arkansas. The Texas-Oklahoma 

Regional Haze FIP proposal does not 

require BART for sources that are 

subject to CSAPR.183 In that FIP 

proposal, EPA reiterates its position that 

‘‘CSAPR, like CAIR, provides for greater 

reasonable progress towards the 

national goal than would BART,’’ 184

and proposes replacing reliance on 

CAIR with reliance on the trading 

programs of CSAPR as an alternative to 

SO2 and NOX BART for Texas EGUs.185

Not only is EPA requiring Arkansas 

EGUs covered by CSAPR to control 

emissions under BART in the FIP 

proposal, but EPA has not even 

considered CSAPR as an option for 

making reasonable progress. Even if 

EPA ultimately rejected CSAPR as a 

means to meet the reasonable progress 

requirements under the Regional Haze 

Rule, EPA is required to cogently 

explain why it has exercised its 

discretion in a given manner. EPA’s 

failure to consider CSAPR is arbitrary 

and capricious in light of its treatment 

of other states. EPA should withdraw 

the FIP proposal and remove the sourcespecific NOX BART requirements for 

Arkansas EGUs that are covered by 

CSAPR in any subsequently proposed 

plan. 

Response: Arkansas EGUs are subject 

to CSAPR for ozone season NOX, and we 

acknowledge that a state in the CSAPR 

region whose EGUs are subject to the 

requirements of the CSAPR trading 

program for ozone season NOX may rely 

on CSAPR to satisfy the NOX BART 

requirement for its EGUs. However, 

when standing in the shoes of a state 

and promulgating a FIP, EPA has the 

same discretion as the state to choose to 

either conduct source-specific BART 

determinations or to rely on EPA’s 2012 

finding that CSAPR is better than BART. 

Our decision to make source-specific 

NOX BART determinations for Arkansas 

is reasonable for multiple reasons: It is 

the approach Congress chose in the 

statute itself; 186 it is consistent with 

Arkansas’ earlier decision to conduct 


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Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66381 

187 40 CFR 51.308(e)(2). 

188 70 FR 39104, 39156 (July 6, 2005). 

189North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 

2008). 

190 77 FR 33642. 

191As Arkansas did not rely on CAIR to satisfy 

requirements in the regional haze SIP, Arkansas is 

not included in the EPA’s limited disapproval of 

regional haze SIPs that relied on CAIR to satisfy 

certain regional haze requirements. See 77 FR 

33642, at 33654. In that same rulemaking, the EPA 

promulgated FIPs to replace reliance on CAIR with 

reliance on CSAPR in many of those regional haze 

SIPs; however, Arkansas was likewise not included 

in that FIP action. 

192 795 F.3d 118 (DC Cir 2015). 

193https://www3.epa.gov/airtransport/CSAPR/

pdfs/CSAPR_SO2_Remand_Memo.pdf. 

194 81 FR 296, 302. 

195 70 FR 39104, 39143; see also 77 FR 33642, 

33653. 

196See discussion beginning on pages 9 and 20 

of our TSD Appendix A. 

197We believe that the IPM cost algorithms 

provide study level accuracy. See pdf page 17 of our 

Control Cost Manual: ‘‘[a]‘‘study’’ level estimate 

[has] a nominal accuracy of ± 30% percent. 

According to Perry’s Chemical Engineer’s 

Handbook, a study estimate is ‘. . . used to estimate 

the economic feasibility of a project before 

expending significant funds for piloting, marketing, 

land surveys, and acquisition . . . [However] it can 

be prepared at relatively low cost with minimum 

data.’’’ 

source-specific NOX BART 

determinations in lieu of relying on 

CAIR to meet the BART requirements; 

and at the time of our proposed action, 

it properly accounted for uncertainty in 

the CSAPR better-than-BART regulation 

created by ongoing litigation regarding 

the CSAPR program. Further 

explanation of these reasons is given 

below. 

The Regional Haze regulations 

provide generally that ‘‘[a] State may 

opt’’ to rely on an emissions trading 

program rather than to require sourcespecific BART controls.187 More 

specifically, in 2005 EPA revised the 

Regional Haze regulations to provide 

that a state subject to CAIR ‘‘need not 

require affected BART-eligible EGUs to 

install, operate, and maintain 

BART.’’ 188 Following the D.C. Circuit’s 

vacatur and remand of CAIR,189 EPA 

issued CSAPR as a replacement rule. 

EPA revised its regulations in 2012 to 

allow states to rely on CSAPR in lieu of 

source-specific BART.190

In its 2008 regional haze SIP 

submittal, Arkansas decided to not rely 

on CAIR to satisfy the NOX BART 

requirement for its EGUs.191 In our 

Regional Haze FIP proposal for 

Arkansas, we did not rely on CSAPR 

(the follow up rule to CAIR) to satisfy 

the NOX BART requirement for EGUs 

because we chose to follow the same 

source-specific approach to NOX BART 

that Arkansas selected in its Regional 

Haze SIP submittal. In addition, 

litigation surrounding CSAPR was 

ongoing at the time that we issued our 

proposed Arkansas Regional Haze FIP. 

CSAPR was issued in 2011, but on 

December 30, 2011, the D.C. Circuit 

stayed the rule prior to implementation. 

The D.C. Circuit subsequently vacated 

CSAPR, an action later reversed by the 

Supreme Court in 2014. The case was 

then remanded to the D.C. Circuit. 

Then, after our April 2015 Regional 

Haze FIP proposal, the D.C. Circuit 

issued a July 2015 decision in EME 

Homer City Generation v. EPA 192

upholding CSAPR but remanding 

without vacatur a number of the Rule’s 

state NOX and SO2 emissions budgets. 

Arkansas’ ozone season NOX budget is 

not itself affected by the remand. 

However, the Court’s remand of the 

affected states’ emissions budgets has 

implications for CSAPR better-than 

BART, since the demonstration 

underlying that rulemaking relied on 

the emission budgets of all states subject 

to CSAPR, including those that the D.C. 

Circuit remanded, to establish that 

CSAPR provides for greater reasonable 

progress than BART. As of the time EPA 

is taking this action to finalize Arkansas’ 

Regional Haze FIP, we are in the process 

of acting on the Court’s remand 

consistent with the planned response 

we outlined in a June 2016 

memorandum.193

Our final action on the Arkansas 

Regional Haze FIP is consistent with our 

final action on the Texas Regional Haze 

FIP. Although we proposed to rely on 

CSAPR to address the NOX BART 

requirements for EGUs in Texas, we did 

not finalize that portion of our proposed 

Texas FIP given the uncertainty arising 

from the remand of the CSAPR budgets 

for Texas and other states.194 In light of 

the above, the comments that we are 

treating Arkansas differently than other 

states where EPA relied on CSAPR to 

meet the BART requirements are no 

longer applicable. 

As we have noted throughout this 

document, we are willing to work with 

ADEQ to develop a SIP revision that 

could replace our FIP. Such a SIP 

revision will need to meet the CAA and 

EPA’s Regional Haze regulations. In its 

SIP revision, ADEQ may elect to rely on 

CSAPR to satisfy the NOX BART 

requirements for Arkansas’ EGUs 

instead of doing source-specific NOX

BART determinations. Such an 

approach could be appropriate if, as we 

expect, the uncertainty created by the 

D.C. Circuit’s remand of the affected 

states’ emission budgets will shortly be 

resolved. 

With regard to the comment that we 

should not require EGUs that are 

covered under CSAPR to also install 

additional emissions controls under 

reasonable progress analysis, we 

disagree. In our 2012 finding that 

CSAPR is better than BART, we stated 

that states with EGUs covered under 

CSAPR may rely on CSAPR to satisfy 

the BART requirement. However, 

controls under reasonable progress are a 

separate requirement from BART, and 

we disagree that states can rely on 

CSAPR to satisfy the reasonable 

progress requirements under 

§ 51.308(d)(1). As explained in the 2005 

rulemaking addressing reliance on 

CAIR, our determination that a trading 

program provides for greater reasonable 

progress than BART is not a 

determination that the trading program 

satisfies all reasonable progress 

requirements.195

I. Cost 

We received numerous comments 

related to the cost analyses we 

proposed. These comments were 

received from both industry and 

environmental groups, and covered all 

aspects of our cost analyses. 

We received comments from industry 

concerning our proposed scrubber cost 

analyses that objected to our use of the 

IPM cost algorithms that Sargent and 

Lundy (S&L) developed under contract 

to us. As we discuss in our TSD, we 

programmed the Spray Dryer Absorber 

(SDA—a type of dry scrubber), and wet 

FGD cost algorithms, as employed in 

version 5.13 of our IPM model, into 

spreadsheets in our analysis of various 

aspects of the Entergy White Bluff and 

Independence scrubber cost analyses.196

Industry stated these cost algorithms 

were not accurate enough to warrant 

their use in individual unit-by-unit cost 

analyses, do not consider site-specific 

costs, and that our use of them violated 

our Control Cost Manual. 

Environmental groups supported our 

use of the IPM cost algorithms, and 

employed them as well in costing 

scrubber and SCR control costs to 

support their own comments. In 

response, we conclude that the IPM cost 

algorithms provide reliable, study-level, 

unit-specific costs for regulatory cost 

analysis such as required for BART and 

reasonable progress.197

We received comments relating to our 

critique of Entergy’s White Bluff dry 

scrubber cost analysis. These primarily 

involved claims that we (1) improperly 

escalated Entergy’s own cost analyses, 

(2) improperly excluded costs, (3) 

under-estimated O&M costs, (4) 

improperly calculated the SO2 baseline, 

(5) improperly excluded ‘‘Allowance for 

Funds Used During Construction’’ 


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198See Section 3.1 in Appendix A of our TSD. 

199See Section 2.7 in Appendix A of our TSD. 

200Our AirControlNET tool is out of date and no 

longer supported. 

201 77 FR 42852 (July 20, 2012). 

202Memorandum from Jim Staudt to Doug Grano, 

EPA, Re: Review of Estimated Compliance Costs for 

Wyoming Electricity Generating Units (EGUs)— 

Revision of Previous Memo, February 7, 2013, EPA– 

R08–OAR–2012–0026–0086_Feb 7, 2013. 

203 76 FR 81728 (December 28, 2011). 

204https://www3.epa.gov/ttn/ecas/ 

cost_manual.html. 

205See discussion beginning on page 19 of 

Appendix A to our TSD. 

206See section 2.1 of Appendix A to our TSD. 

(AFUDC) and owner’s costs, and (6) 

improperly extended our White Bluff 

scrubber cost analyses to the 

Independence facility. In response to 

these comments, we have made some 

minor adjustments to our White Bluff 

scrubber cost analyses, but those 

changes do not change our proposal that 

scrubbers remain cost-effective for the 

White Bluff facility, and by extension to 

the Independence facility. 

We received comments from 

environmental groups concerning the 

White Bluff, Independence, and Flint 

Creek facilities that (1) generally 

supported our proposed control suite, 

(2) criticized us in some cases for not 

proposing stricter control levels, (3) 

criticized our control cost analyses for 

being too conservative in some cases 

and/or containing errors, and (4) 

criticized us in some cases for not 

requiring earlier compliance. These 

groups also generally opposed our 

BART determination for Lake Catherine 

Unit 4. 

Below we present a summary of our 

responses to the more significant 

comments we received that relate to our 

proposed cost analyses. 

Comment: S&L states we significantly 

under-estimated the direct Operating 

and Maintenance (‘‘O&M’’) costs 

projected for the scrubbers by using its 

Integrated Planning Model (‘‘IPM’’) 

Spray Dryer Absorber (‘‘SDA’’) cost 

model to scale the O&M costs rather 

than estimating these costs using 

current utility pricing information. S&L 

stated that our use of the IPM cost 

algorithms was not in keeping with our 

Control Cost Manual and because of the 

limited number of site-specific inputs, 

the IPM cost algorithms provide orderof-magnitude control system cost 

estimates, but do not provide case-bycase project-specific cost estimates 

meeting the requirements of the BART 

Guidelines, nor do the IPM equations 

incorporate the cost estimating 

methodology described in the Control 

Cost Manual. 

Response: We disagree with S&L. As 

we discuss in our TSD,198 we needed to 

adjust Entergy’s O&M costs for its White 

Bluff SDA model because of a mismatch 

between Entergy’s SO2 emission 

baseline and the SO2 inlet it assumed in 

the design of its scrubber (discussed in 

our response to another comment). 

Entergy costed a scrubber capable of 

treating a SO2 level of 2.0 lbs/MMBtu, 

when it historically burned coal that 

averaged less than 0.6 lbs/MMBtu from 

2009–2013. This had the effect of 

worsening the cost effectiveness 

(increasing the $/ton) over what it 

would have been had Entergy designed 

it to treat the coal it historically burned. 

We could not directly adjust Entergy’s 

O&M costs because Entergy’s O&M cost 

estimates were based on an S&L 

economic model from May 2008, which 

it did not supply.199 These issues, 

which we discuss in our responses to 

comments elsewhere, dictated a revision 

to Entergy’s cost estimate. We were left 

with no choice but to seek an alternative 

means of estimating Entergy’s O&M 

costs, in order to address the mismatch 

described above. We utilized the IPM 

SDA cost model that Entergy’s own 

contractor designed for us. 

We disagree that our cost estimates 

were not in keeping with the Control 

Cost Manual. As we stated in our TSD 

Appendix A, we relied on the methods 

and principles contained within the 

Control Cost Manual, namely the use of 

the overnight costing method. In fact, 

the Control Cost Manual does not 

include any method for estimating the 

costs specific to any of the SO2 control 

equipment evaluated in this action. We 

note our technique of relying on a 

publicly available control cost tool is 

similar to the strategy the states 

themselves employed in the 

development of their SIPs. For instance, 

as explained in the Texas SIP, the ADEQ 

used the control strategy analysis 

completed by the CENRAP, which 

depended on the EPA AirControlNET 

tool 200 to develop cost per ton 

estimates. We have used IPM cost 

models to estimate BART costs in other 

similar rulemakings including our 

Arizona Regional Haze FIPs,201 the 

Wyoming Regional Haze FIP,202 and to 

supplement our analysis in the 

Oklahoma FIP.203 S&L used real world 

cost data to construct its cost algorithms 

and confirm their validity. These cost 

models have been updated and 

maintained since their introduction in 

2010 and we have been continuously 

using them since that time. These 

control costs are based on databases of 

actual control project costs and account 

for project specifics such as unit size, 

coal type, gross heat rate, and retrofit 

factor. The costs further require unit 

specific inputs such as reagent cost, 

waste disposal cost, auxiliary power 

cost, labor cost, gross load, and emission 

information. We believe that the IPM 

cost models provide reliable study-level, 

unit-specific costs for regulatory cost 

analysis such as required for BART and 

reasonable progress. We are confident 

enough in the basic methodology 

behind the S&L cost algorithms that in 

our recent update of the SCR chapter of 

the Control Cost Manual 204 we 

presented an example costing 

methodology that is based on the IPM 

S&L SCR algorithms, which were 

developed using a similar methodology 

to the wet FGD, SDA, and DSI cost 

algorithms discussed herein. Lastly, we 

note that Entergy used a number of 

general approximations when 

estimating the wet scrubbing costs for 

White Bluff, as we describe in our 

TSD.205 We conclude that our approach 

is in keeping with the Control Cost 

Manual and is sufficiently accurate for 

its intended purpose. 

Comment: Entergy disagreed with our 

approach for escalating a 2013 scrubber 

cost analysis for its White Bluff facility 

to 2015, rather than obtaining a revised 

cost estimate. Entergy claims this 

caused us to underestimate our scrubber 

cost estimate by $36,322,881 (total for 

both units). Entergy also disagreed with 

our application of the Chemical 

Engineering Plant Cost Index (CEPCI) 

indices in several instances from 2008 

that de-escalated costs, resulting in 

lower costs in 2013 as compared to 

2008. Entergy states that our cost 

calculations ignored the updated 2012 

direct annual costs it provided, and 

instead included the 2008 costs. In a 

subsequent comment, Entergy calculates 

an escalation rate of 4.7%, based on a 

comparison of a revised 2013 quote to 

a 2009 quote, and applies that escalation 

rate along with other corrections to 

various cost line items in concluding 

that we underestimated the cost of 

installing scrubbers at the White Bluff 

facility by $42,607,547 per unit. 

Response: For our proposal, we used 

Entergy’s revised BART analysis for the 

White Bluff facility, as submitted by it 

on October 14, 2013, because at the time 

it was the latest information available to 

us.206 In our proposal, our control cost 

analysis used the same basic 

information that Entergy previously 

presented to us in 2013. As we describe 

in Appendix A of our TSD, Entergy 

stated that it received two different SDA 

cost estimates for White Bluff: An early 

2009 Sargent and Lundy (S&L) estimate 

with a total contractor cost of 

$291,930,000, and a December 2009 


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207See section 2.1 of Appendix A to our TSD. 

208Note that escalation during the construction 

period is disallowed, however, because that is not 

a part of the overnight method. 

209 Vatavuk, William, M., ‘‘Updating the CE Plant 

Cost Index,’’ Chemical Engineering, January 2002. 

210See section 2.6 of Appendix A to our TSD. 

211Entergy’s reference to de-escalated costs. 

212See section 2.7 of Appendix A to our TSD. 213Revised Bart Five Factor Analysis, White Bluff 

Steam Electric Station, Redfield, Arkansas (AFIN 

35–00110). Appendix A, SDA cost analysis, June 

2013, Appendix A. 214See, e.g., ‘‘Response to Technical Comments 

for Sections E through H of the Federal Register 

Notice for the Oklahoma Regional Haze and 

Visibility Transport Federal Implementation Plan,’’ 

Docket No. EPA–R06–OAR–2010–0190, 12/13/ 

2011. 

estimate from Alstom of $247,856,184. 

Entergy stated that unlike the S&L 

quote, the Alstom estimate was not 

itemized and only included a total 

price. Entergy used the 2009 Alstom 

price quote as the basis for its BART 

cost analysis for White Bluff by 

increasing it by 10%, and scaling the 

S&L itemized cost to match the 110% 

adjusted Alstom total price. As we 

describe in our RTC, we critiqued 

certain aspects of Entergy’s use of this 

information. For example, Entergy 

mistakenly included certain NOX

controls in its 2013 cost analysis. It also 

failed to document certain BOP costs 

that we had no choice but to exclude. 

However, between the 2009 S&L and the 

2009 Alstom quotes, and with these 

corrections, we were able to construct a 

reasonable control cost estimate. In so 

doing, we used the same 2009 Alstom 

total, and the Alstom payment schedule 

for its quote, as the actual Alstom quote 

was not supplied and no better 

information was presented by Entergy. 

Because Entergy’s 2013 cost estimate 

used 2009 Alstom pricing, we had no 

choice but to escalate it to 2013—more 

recent information was not available. 

Entergy did not provide its updated 

2015 cost estimate, which it references 

in its comment, until after our proposal. 

Entergy’s 2015 report uses updated 2013 

pricing from Alstom as its basis. As we 

discuss in our RTC, we reviewed this 

2015 cost analysis and found that it 

presents problems that prevent us from 

using it, primarily because it is 

undocumented. 

In this comment, Entergy attempts to 

use its newly submitted 2015 cost 

analysis to discredit the escalation 

technique we employed to adjust its 

previous 2013 cost analysis. It does so 

without even presenting the 2013 

Alstom quote on which it states the 

2015 cost estimate relies. Thus, we have 

no basis to conclude that the costs 

Entergy presents in its first table above 

even cover the same scope of work. This 

is an important consideration and a 

different scope can cause a significant 

difference in cost. Entergy itself noted 

this when it used a revised BOP 

estimate to adjust its 2009 Alstom quote 

because the scope had changed. Even 

different cost estimates received in the 

same year can result in significantly 

different totals. For instance, as we also 

note in our TSD, Entergy stated that it 

received two different SDA cost 

estimates for White Bluff: An early 2009 

S&L estimate with a total contractor cost 

of $291,930,000, and a December 2009 

estimate from Alstom of 

$247,856,184.207 We note that the 

difference between these two quotes is 

$44,073,816, which is more than 

Entergy calculates in its first table above 

is the difference between our escalated 

2013 quote ($261,581,119) and its 

revised 2015 cost estimate, based on the 

its 2013 Alstom quote ($297,904,000). 

Escalation from one year’s cost basis 

to another 208 is not only allowed by the 

Control Cost Manual, it is a required 

procedure in order to allow an applesto-apples comparison between control 

cost analyses. Our use of the Chemical 

Engineering Plant Cost Index (CEPCI) is 

a standard method of escalating costs,209

and one that power companies have also 

used on numerous occasions. Entergy 

itself has used the CEPCI in an attempt 

to escalate its costs. Unfortunately, as 

we explain in our TSD, Entergy did so 

incorrectly and we corrected that 

error.210 We certainly prefer revised 

vendor quotations to escalating older 

cost estimates. However, when revised 

vendor quotes are not available as in 

this case, we have no choice but to 

escalate older cost estimates in order to 

bring the cost basis to the present. 

Entergy also apparently objects to any 

escalation technique that results in a 

reduction in a future year’s cost basis, 

holding it up as evidence of our error.211

This is a fundamental misunderstanding 

of escalation. For instance, although the 

Composite CE index usually increases 

from year to year, it does occasionally 

decrease, due to various broad economic 

factors, such as it did from 2008 to 2009, 

and again from 2011 to 2013. This is 

mainly due to broad economic factors 

that influence the cost of raw materials, 

supply and demand, vendor profit, etc. 

Thus, Entergy’s objection over the ‘‘deescalation’’ of cost from 2008 to 2013 is 

entirely misplaced. In other words, 

escalation is escalation: Most of the time 

it is positive but sometimes it is 

negative. We therefore do not agree with 

Entergy’s objections to our escalation 

technique. We take up the issue of 

Entergy’s 2015 cost estimate in our 

response to another comment. 

Entergy states that our cost 

calculations ignored the updated 2012 

direct annual costs provided by Entergy, 

and instead included the 2008 costs. As 

noted in the first sentence of our 

response to this comment, we were 

constrained to use Entergy’s revised 

BART analysis for the White Bluff 

facility, as submitted by Entergy on 

October 14, 2013 (hereafter referred to 

as the ‘‘2013 SDA Cost Analysis’’). 

These costs employed a 2008 vintage 

total direct annual cost, as we indicate 

in Appendix A of our TSD.212 Regarding 

its direct annual costs, Entergy further 

states, ‘‘The cost estimates were scaled 

to reflect 2012 dollars.’’ 213 We therefore 

agree that Entergy did provide what it 

stated was 2012 vintage direct annual 

costs. We did not use those costs 

because Entergy incorrectly escalated 

them from 2008, as we discuss above. 

For instance, Entergy presented its 2008 

direct annual cost as $7,901,369. It then 

‘‘scaled’’ them to 2012 using a 2008 

CEPCI index of 530.7 and a 2012 CEPCI 

index of 593.6, resulting in a 2012 value 

of $8,837,861. As we discuss in 

Appendix A of our TSD, Entergy 

appears to have incorrectly used the 

January monthly CEPCI value for each 

year instead of the annual CEPCI value. 

Entergy should have used a 2008 CEPCI 

index of 575.4 and a 2012 CEPCI index 

of 584.6, resulting in a 2012 escalated 

direct annual cost of $8,027,703 

($7,901,369 × 584.6/575.4). As we also 

discuss in our TSD, because we were 

conducting our analysis later, we 

escalated Entergy’s 2008 direct annual 

cost to 2013, resulting in a value of 

$7,790,140 ($7,901,369 × 567.3/575.4). 

These facts appear to have been ignored 

by Entergy in its comment. We therefore 

have no choice but to disagree with 

Entergy’s comment concerning our not 

using its 2012 direct annual cost. 

Comment: Entergy and Nucor stated 

that we improperly excluded AFUDC 

and owner’s costs from our White Bluff 

control cost analysis. Entergy also 

objects to our disallowance of certain 

BOP costs. 

Response: As we have noted in a 

number of our FIPs, AFUDC and 

Owner’s Costs are not valid costs under 

our Control Cost Manual methodology. 

We invite the commenters to examine 

our response to similar comments we 

received in response to those actions.214

In Appendix A to our TSD, we noted 

that Entergy used BOP costs from a 2008 

S&L quote to supplement its adjusted 

2009 Alstom quote in its 2013 SDA cost 

analysis for the White Bluff BART 

determination. However, due to a lack 

of documentation, it appeared that a 

number of items were either not 

appropriate for a SO2 scrubber, or were 


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215See the file, ‘‘White Bluff_R6 cost revisions2- 

revised.xlsx’’ in our docket. 

216http://ampd.epa.gov/ampd/ 

217 70 FR 39104, 39167. 

218 ‘‘Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program,’’ at 5–1. 

219See ‘‘EIA Consolidated Data_WB and 

IND_Y2012.xlsx.’’ 

220See document titled ‘‘AR RH FIP TSD 

Appendix A—White Bluff and Independence SO2

Cost Analysis,’’ found in the docket for this 

rulemaking. 

already covered as part of the Alstom 

quote. As discussed in detail in our RTC 

document, we removed those items 

from our proposed SDA cost analysis 

and invited Entergy to supply additional 

documentation to verify these costs. 

S&L now points to an S&L Report 

#012831, which contains a 2015 White 

Bluff SDA cost estimate, for that 

documentation. First, Entergy states that 

its 2015 SDA cost estimate is based on 

a 2013 Alstom quote. As with the 2009 

Alstom quote it used to support its 2013 

SDA cost analysis, Entergy did not 

provide this Alstom quote. 

Consequently, we have no way of 

verifying Entergy’s 2015 cost 

calculations or to conclude that their 

scopes are the same. Therefore, we have 

no choice but to conclude that Entergy 

has not demonstrated that our removal 

of costs associated with the reagent 

preparation enclosure and reagent 

handling system and ductwork was 

incorrect. Similarly, we continue to find 

that Entergy has not documented certain 

BOP indirect costs, miscellaneous 

contract labor, Entergy internal costs, 

and capital suspense. 

We do agree that Entergy has 

provided documentation for other costs, 

including demonstrating that 

recalibration of the CEMS and painting 

of the chimney are justified, and we 

have adjusted our White Bluff scrubber 

cost analysis accordingly. Other costs 

that were calculated as percentages of 

the equipment, material, and labor costs 

were similarly adjusted. We have 

revised our cost analysis to include 

these adjustments, and have determined 

that dry scrubbers are estimated to cost 

$2,565/SO2 ton removed at Unit 1 and 

$2,421/SO2 ton removed at Unit 2.215

Revising these costs did not change our 

final determination that dry scrubbers 

are cost-effective for the White Bluff 

facility. 

Comment: S&L objects to our 

approach of calculating an SO2 baseline 

for the White Bluff and Independence 

facilities, in which we eliminated the 

high and low annual emission values 

from 2009 to 2013, and averaged the 

remaining values. S&L presents four 

alternative approaches in which a 

straight five year average from 2009 to 

2013, and different three year averages 

from 2009 to 2013 are examined for 

White Bluff Units 1 and 2 and 

Independence Units 1 and 2, and 

concludes that in all cases, at least one 

of the alternative approaches would 

have resulted in lower baseline SO2

emissions for one of the units. 

Response: We disagree with S&L that 

we erred in the procedure we used in 

estimating baseline emissions for our 

BART and reasonable progress scrubber 

upgrade cost analyses. We calculated 

our baseline SO2 emissions by first 

acquiring the 2009 to 2013 emissions as 

reported to us by the facilities in 

question.216 We reasonably eliminated 

the high and low values from the 2009– 

2013 emissions to better address 

potential yearly variations in in coal 

sulfur data, capacity usage, etc., and to 

make the baseline more representative 

of plant operations and thereby provide 

the basis for a more accurate estimate of 

the cost effectiveness of controls. The 

fact that S&L can construct alternative 

approaches to our baseline calculation 

that result in lower emissions estimates 

does not invalidate our BART and 

reasonable progress approaches. As can 

be seen from an examination of S&L’s 

own data, regardless of whether a 3-year 

average or a 5-year average of a 

particular set of years is employed, the 

resulting emissions baselines are all 

similar. In fact, for three out of four 

units, one of S&L’s alternative 

approaches would have produced 

higher SO2 emissions baselines, which 

if used would have resulted in the cost 

analyses we performed being even more 

cost-effective. We believe that the 

procedure we used is in compliance 

with the BART Guidelines, which 

states: 

How do I calculate baseline emissions? 

1. The baseline emissions rate should 

represent a realistic depiction of anticipated 

annual emissions for the source. In general, 

for the existing sources subject to BART, you 

will estimate the anticipated annual 

emissions based upon actual emissions from 

a baseline period. 

2. When you project that future operating 

parameters (e.g., limited hours of operation 

or capacity utilization, type of fuel, raw 

materials or product mix or type) will differ 

from past practice, and if this projection has 

a deciding effect in the BART determination, 

then you must make these parameters or 

assumptions into enforceable limitations. In 

the absence of enforceable limitations, you 

calculate baseline emissions based upon 

continuation of past practice.217

Regarding the baseline used in our 

Independence reasonable progress 

analysis, our 2007 Reasonable Progress 

Guidance notes the similarity between 

some of the reasonable progress factors 

and the BART factors contained in 

§ 51.308(e)(1)((ii)(A), and suggests that 

the BART Guidelines be consulted 

regarding cost, energy and nonair 

quality environmental impacts, and 

remaining useful life.218 We are 

therefore relying on our BART 

Guidelines for assistance in interpreting 

those reasonable progress factors, as 

applicable. One of these areas is in the 

calculation of the baseline emissions in 

determining cost effectiveness. 

The difference between our baseline 

calculations and any of the alternative 

procedures S&L outlines is small and 

would not change our conclusions for 

the White Bluff BART determinations 

and the Independence reasonable 

progress determinations. 

Comment: S&L objects to our 

extending our White Bluff scrubber cost 

analysis to the Independence facility on 

the basis of the similarity of the two 

facilities. S&L states that our use of EIA 

information, satellite photographs and 

other points of comparison are 

inadequate to account for potential sitespecific differences between the two 

facilities, such as operating data, O&M 

practices, underground utility 

interferences, geotechnical differences, 

and seismic differences. 

Response: While there are likely 

differences between the two facilities 

that would have some minor impact on 

the scrubber cost analyses, we 

reasonably concluded based on the 

information available to us that there 

were enough similarities between the 

facilities to make our approach 

appropriate. As we discuss in our TSD: 

The White Bluff and Independence 

facilities are sister facilities. According to 

EIA,219 the boilers were manufactured by 

Combustion Engineering with in-service 

dates of 1980 and 1981 for White Bluff, and 

1983 and 1985 for Independence. All four 

units are tangentially firing boilers having 

nameplate capacities of 900 MW and similar 

gross ratings. As we indicate above, all four 

units burn coal from the Powder River Basin 

of Wyoming with similar characteristics. All 

four units employ cold side electrostatic 

precipitators for particulate collection. Other 

pertinent characteristics are similar.220

We further presented satellite 

photographs to demonstrate that the 

layout of these facilities are extremely 

similar. We consequently expect that 

the differences Entergy describes in its 

comments result in minor differences in 

the cost to install and operate scrubbers. 

As we have discussed in our response 

to another comment, the Control Cost 

Manual explains that the sole input 

required for making an ‘‘order of 

magnitude’’ estimate is the control 


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system’s capacity (often measured by 

the maximum volumetric flow rate of 

the gas passing through the system). 

Such an estimate, for example, could be 

obtained from the cost reported in 

dollars per megawatt ($/MW) or dollars 

per million BTUs fired ($/MMBtu), 

metrics that are widely reported in the 

literature. The Control Cost Manual 

indicates that ‘‘the costs and estimating 

methodology in this Manual are 

directed toward the ‘study’ estimate 

with a nominal accuracy of +/¥30% 

percent.’’ This is the long-standing rule 

of thumb for cost estimate accuracy 

used by the EPA for regulatory cost 

effectiveness analyses. We see nothing 

in Entergy’s comments that would 

suggest that the differences between 

these two facilities are so significant 

they would impact this required level of 

accuracy. Indeed, Entergy does not 

attempt to estimate the capital costs of 

these differences or otherwise provide a 

cost estimate specific to the 

Independence facility in support of its 

argument that it was inappropriate for 

us to extend our White Bluff scrubber 

cost analysis to the Independence 

facility. 

Comment: Entergy objects to our 

correction to its White Bluff scrubber 

control cost analysis to adjust the cost 

for a scrubber designed to treat a 2.0 lb/ 

MMBtu coal to 0.68 lbs/MMBtu to 

account for the lower sulfur coal it has 

historically burned. Entergy states that 

we correctly assumed that the 2.0 lb/ 

MMBtu design basis for the White Bluff 

scrubber was to preserve fuel flexibility, 

but our conclusions that, ‘‘either (1) this 

higher cost be balanced against its 

greater SO2 reduction potential, or (2) 

that the scrubber system’s capability 

and cost be adjusted down to match the 

facility’s historical emissions’’ are 

without basis and inconsistent with the 

BART guidelines. Entergy also 

concludes that its assumption that a 2.0 

lb/MMBtu scrubber inlet was in error 

and a 1.2 lb/MMBtu inlet assumption is 

now appropriate. Entergy presents SO2

emission data in support of its position 

that our 0.68 lbs/MMBtu coal 

assumption was incorrect and 

recalculates its O&M and capital costs. 

Lastly, Entergy states that in correcting 

its scrubber control cost analysis to 

account for a 0.68 lbs/MMBtu coal, we 

misapplied a correction factor to our 

total direct and indirect costs. 

Response: As we noted in our TSD, 

‘‘either (1) this higher cost be balanced 

against its greater SO2 reduction 

potential, or (2) that the scrubber 

system’s capability and cost be adjusted 

down to match the facility’s historical 

emissions.’’ Entergy chose to do neither 

and costed a scrubber capable of treating 

a coal far in excess of what it 

historically burned, but continued to 

base the capabilities of the scrubber on 

its historical SO2 baseline. Thus, either 

Entergy’s annualized cost (the ‘‘$’’) or its 

tons reduced (the ‘‘tons’’) in the $/ton 

cost effectiveness calculation are 

misrepresented. Our approach was to 

recalculate Entergy’s scrubber cost to 

bring its scrubber design in line with the 

coal it has historically burned. Entergy 

could have taken the alternative 

approach of calculating a new baseline 

on the basis of its higher sulfur design 

coal, but it chose not to do so. We see 

nothing in Entergy’s comments that 

would cause us to conclude our 

reasoning was in error. With regard to 

Entergy’s concerns with the 0.68 lbs/ 

MMBtu baseline that we use, it appears 

the SO2 emission data Entergy presented 

was hourly data, which should not be 

used to design a scrubber that would 

have to meet a 30–BOD average. Our 

analysis indicates the individual hourly 

data fluctuations Entergy presents are 

inconsequential. Further, an 

examination of the running 30–BOD 

average indicates that our decision to fix 

the mismatch between Entergy’s 

scrubber costs and its historical SO2

baseline on the basis of a SO2 inlet of 

0.68 lbs/MMBtu is reasonable. 

In apparent agreement with our basic 

approach, Entergy recalculates its 

variable and fixed O&M costs on the 

basis of 0.68 lb/MMBtu fuel sulfur 

levels. We note that our own variable 

and fixed O&M costs are actually 

greater, adding to the conservativeness 

of our calculation. To illustrate the 

small difference in capital costs 

associated with the revised design basis 

(1.2 lb/MMBtu versus 0.68 lb/MMBtu), 

Entergy then performs a sensitivity 

analysis and concedes there is a ‘‘small 

difference in capital costs associated 

with the revised design basis (1.2 lb/ 

MMBtu versus 0.68 lb/MMBtu). . . .’’ 

This conclusion is borne out by our own 

figures, which indicate there is a small 

difference in capital costs to even the 

2.0 lbs/MMBtu case; the capital, 

engineering and construction costs, 

which cover the fundamental design 

parameter of a scrubber—gas flow rate— 

were only changed by less than 5%. In 

sum, Entergy’s assertion that our cost 

analysis improperly designed the White 

Bluff scrubber system is without merit 

and would make an insignificant 

difference in the final outcome. 

Lastly, we agree with Entergy that we 

misapplied a correction factor to our 

total direct and indirect costs. We 

incorporate that correction in our final 

SDA cost analysis for the White Bluff 

and Independence facilities, which we 

discuss in more detail in our response 

to other comments. This correction has 

a relatively minor impact on the overall 

cost analysis. 

Comment: The Sierra Club supported 

our proposal regarding SO2 for the 

White Bluff and Independence facilities, 

but concluded that our proposed SO2

emission rate of 0.06 lbs/MMBtu on a 

30–BOD average should have been 

stricter at 0.04 lbs/MMBtu, based on wet 

scrubbing. The Sierra Club also agrees 

with our assessment that Entergy 

included undocumented costs in its 

White Bluff scrubber cost estimate. 

The Sierra Club’s consultant 

performed a cost analysis of dry and wet 

scrubber systems, including Alstom’s 

NID circulating dry scrubber, and 

concluded that our White Bluff scrubber 

cost analysis was conservative, that 

scrubbers are cost effective compared to 

controls required pursuant to other 

BART determinations, and that we 

should have required compliance in 3 

years instead of 5 years. 

Response: We confirm that we 

intended to construct conservative cost 

estimates. With some minor 

disagreements with the Sierra Club, we 

generally agree that an independent cost 

analysis such as it presents does support 

our basic position that scrubbers are 

cost effective at both the White Bluff 

and Independence facilities. However, 

as we discuss in our RTC document, we 

disagree that in this specific instance 

wet scrubbers are more cost effective 

than dry scrubbers. Our scrubber cost 

analyses was built off of the analyses 

supplied by Entergy, and we determined 

that wet scrubbers were significantly 

less cost effective—again, in the specific 

cases of the White Bluff and 

Independence facilities for BART and 

reasonable progress respectively. We 

disagree with the SO2 baseline Sierra 

Club uses in its cost analysis, rendering 

its scrubber cost analysis and ours not 

directly comparable. Consequently, we 

disagree that an SO2 emission rate of 

0.04 lbs/MMBtu averaged over a 30- 

boiler-operating-day period, based on a 

wet scrubber cost analysis, is 

appropriate for either the White Bluff or 

Independence facilities. We agree that 

in some cases scrubbers can be installed 

in less than the 5 years that we 

proposed. However, this is site-specific 

and, in this case, we have found that 

installation within 5 years is as 

expeditious as practicably possible. 

We agree that the Alstom NID 

circulating dry scrubber is a promising 

SO2 control option. We reviewed NID in 

our preliminary work but ultimately 

decided not to evaluate it as a control 

because we had no relevant operating 

data and no method to estimate costs. 


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221Those corrections are contained in the file, 

‘‘White Bluff_R6 cost revisions2-revised.xlsx,’’ 

which appears in our docket. 

222See our supplemental NOX modeling results 

for the Independence facility in 80 FR 24872 vs. our 

NOX modeling results for the White Bluff facility in 

80 FR at 18974. 

After addressing all comments from 

Entergy and the Sierra Club concerning 

our White Bluff and Independence 

scrubber cost analyses, we made several 

minor corrections.221 Below we 

summarize those corrections: 

TABLE 18—CORRECTIONS TO OUR COST-EFFECTIVENESS CALCULATIONS FOR DRY FGD FOR WHITE BLUFF AND

INDEPENDENCE

Unit 

Proposed 

cost-effectiveness 

($/ton) 

Final cost-effectiveness 

($/ton) 

White Bluff Unit 1 ..................................................................................................................................................... $2,227 $2,565 

White Bluff Unit 2 ..................................................................................................................................................... 2,101 2,421 

Independence Unit 1 ............................................................................................................................................... 2,477 2,853 

Independence Unit 2 ............................................................................................................................................... 2,286 2,634 

We find that these revised costeffectiveness calculations do not change 

our proposed findings for BART and 

reasonable progress for these units. 

In addition, we have examined the 

effect of adding back in a number of the 

BOP and other costs we excluded (based 

on these costs being either disallowed 

by the Control Cost Manual, or having 

lacked documentation from Entergy). 

This exercise also appears in the file 

‘‘White Bluff_R6 cost revisions2- 

revised.xlsx.’’ These costs include: 

• BOP Costs associated with the 

reagent prep enclosure and the reagent 

handling system, totaling $21,229,000. 

• BOP Costs associated with the flue 

gas system ductwork, totaling 

$1,754,000. 

• BOP indirect costs of $8,474,666 

(escalated to 2013). 

• Miscellaneous contract labor costs 

of $4,448,074 (escalated to 2013). 

• Entergy internal costs of 

$19,482,518 (escalated to 2013). 

• Capital suspense costs of 

$8,101,226 (escalated to 2013). 

TABLE 19—ALTERNATE COST-EFFECTIVE CALCULATIONS FOR DRY FGD 

ON WHITE BLUFF AND INDEPENDENCE

[Include disallowed costs] 

Unit 

Alternate costeffectiveness 

($/ton) 

White Bluff Unit 1 ................. $3,013 

White Bluff Unit 2 ................. 2,843 

Independence Unit 1 ............ 3,351 

Independence Unit 2 ............ 3,093 

We continue to believe that these 

costs are either disallowed by the 

Control Cost Manual, or are properly 

disallowed because they lack 

documentation from Entergy. We have 

presented this information to indicate 

that these disallowed costs have a 

relatively minor effect on the final cost 

effectiveness. Although our final 

decision regarding BART and 

reasonable progress for the White Bluff 

and Independence units does not rest 

upon these cost-effectiveness 

calculations that include the disallowed 

costs, had our final decision rested on 

these cost-effectiveness calculations, we 

would have reached the same 

conclusions regarding BART and 

reasonable progress for these units. 

Comment: The Sierra Club stated that 

the NOX emission limit of 0.15 lbs/ 

MMBtu based on LNB/SOFA we 

proposed for White Bluff Units 1 and 2 

does not satisfy BART. The Sierra Club 

asserted that NOX BART for these units 

should have been based on SCR. The 

Sierra Club’s consultant concluded that 

we overestimated the costs of SCR and 

underestimated the visibility benefits of 

SNCR and SCR. The consultant’s 

conclusions are based on costeffectiveness calculations developed by 

the consultant, which rely on the S&L 

IPM SCR Cost Module and assume an 

achievable NOX emission rate of 0.04 lb/ 

MMBtu for LNB/SOFA plus SCR. The 

Sierra Club stated that LNB/SOFA can 

be installed in much shorter timeframe 

than the 3 years we proposed. The 

Sierra Club also stated that we should 

have evaluated SNCR and SCR for the 

Independence facility. 

Response: We have a number of 

disagreements with the Sierra Club’s 

consultant concerning the SCR cost 

analysis provided, including the NOX

baseline and the emission limit, which 

are outlined in detail in our RTC 

document. After addressing those 

issues, we do not believe that the cost 

effectiveness of SCR or SNCR fall within 

a range that justifies the relatively small 

incremental visibility improvement 

(over our NOX BART determination 

based on LNB/SOFA) that would result 

from the installation of SNCR or SCR at 

the White Bluff facility. As we 

discussed in our proposal,222 our 

modeling indicated that the visibility 

improvement at several Class I areas 

from the installation of LNB/SOFA at 

the Independence facility was of a 

similar magnitude as the same controls 

at the White Bluff facility, and 

cumulatively (i.e., at all Class I areas 

combined) the visibility improvement of 

the controls at Independence was lower 

than at White Bluff. Therefore, we 

reasoned that since White Bluff and 

Independence are sister facilities with 

near identical units, the cost 

effectiveness of SCR or SNCR at 

Independence would likely not fall 

within a range that justifies the 

relatively small incremental visibility 

improvement (over LNB/SOFA) that 

would result from installation of these 

controls. Therefore, we did not evaluate 

SCR or SNCR controls for 

Independence. As we discuss in a 

separate response, after carefully 

considering the comments we have 

received, we are finalizing an 18-month 

compliance date for the NOX emission 

limits we are establishing for White 

Bluff Units 1 sand 2 under BART and 

Independence Units 1 and 2 under 

reasonable progress. 

Comment: The Sierra Club and others 

stated that the costs of both a wet and 

a dry scrubber are reasonable at the two 

Independence units. The Sierra noted 

our proposed costs are reasonable in 

other reasonable progress 

determinations that it summarizes. The 

Sierra Club’s consultant independently 

calculated the costs of scrubbers at 

Independence Units 1 and 2 and 

concluded that those calculations 

confirm that a scrubber is cost-effective. 

The consultant also noted that the 

significant visibility improvement from 

a scrubber at Independence Units 1 and 

2 would equal or exceed the visibility 

improvement from other reasonable 


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223See page 65 of our TSD: ‘‘[W]e believe that 

AEP’s escalation of the cost of controls to 2016 

dollars has likely resulted in the over estimation of 

the average cost-effectiveness values. Therefore, we 

believe a wet scrubber and NID are more costeffective (i.e., less dollars per ton of SO2 removed) 

than estimated by AEP (see table above). However, 

we did not adjust the cost numbers and costeffectiveness values because we do not believe that 

doing so would change our proposed BART 

determination. We believe that the average costeffectiveness of both control options was likely 

over-estimated and the costs associated with a wet 

scrubber would continue to be higher than the costs 

associated with NID if the estimates were adjusted, 

yet the installation and operation of a wet scrubber 

is projected to result in minimal incremental 

visibility improvement over NID. 

224See response to comment beginning on page 

310 of our Response to Comments for the Federal 

Register Notice for the Texas and Oklahoma 

Regional Haze State Implementation Plans; 

Interstate Visibility Transport State Implementation 

Plan to Address Pollution Affecting Visibility and 

Regional Haze; and Federal Implementation Plan 

for Regional Haze, Docket No. EPA–R06–OAR– 

2014–0754, 12/9/2015. 

225See email from Dayana Medina to Mary 

Pettyjohn on 8/21/13. 

226Modeled emission rates were based on a 

maximum heat input of 6,324 MMBtu/hr multiplied 

by the anticipated control rate (e.g. 0.067 lb/ 

MMBtu) Baseline emissions determined from 2001– 

2003 CAMD data were 1,945 lb/hr, approximately 

0.308 lb/MMbtu. 

progress controls we have previously 

approved. The Sierra Club’s consultant 

also incorporated comments for the 

White Bluff facility regarding time for 

installation and control level. 

Response: We take no position on the 

separate cost analysis that the Sierra 

Club’s consultant has conducted for dry 

and wet scrubbers and that uses to 

conclude that our cost analyses are 

reasonable. We agree that our finding 

that the control costs are reasonable, 

given the visibility improvements 

achieved, is consistent with other EPA 

actions. We refer the Sierra Club’s 

consultant to our responses to other 

similar comments regarding the White 

Bluff facility scrubber concerning 

control level and installation time. 

Comment: The Sierra Club and others 

stated that our proposal that SO2 BART 

for AEP Flint Creek is a NID dry 

scrubber is appropriate, but argued that 

a NID dry scrubber is even more costeffective than what AEP and EPA have 

estimated. The Sierra Club’s consultant 

presented cost analyses for wet and NID 

scrubbing for Flint Creek, based on the 

IPM cost algorithms we used in our 

recent Texas-Oklahoma FIP. In so doing, 

the consultant applied the SDA cost 

algorithm to NID, citing to 

documentation that indicates that NID 

may be 1–2% lower in cost to an SDA 

system. The Sierra Club’s consultant 

argues that both wet and dry scrubbers 

are capable of even greater levels of 

control than what we assumed. 

Response: As we discuss in our 

TSD,223 we noted a number of issues 

with AEP’s NID and wet scrubber cost 

analyses that if corrected would have 

resulted in more favorable (lower $/ton) 

cost-effectiveness values. Nevertheless, 

even disregarding those errors, we 

concluded that NID was cost-effective 

and worth the visibility benefit that will 

result from its installation. We also 

determined that wet scrubbing would 

remain less cost-effective than NID, and 

was not worth the small additional 

visibility that would result from its 

installation in this particular instance. 

We extensively analyzed the 

performance potential of wet scrubbers 

in our recent Texas-Oklahoma FIP.224

We concluded that a control level of 

98%, not to go below an emission rate 

of 0.04 lbs/MMBtu on a 30–BOD 

average, was a reasonable lower level of 

control. We applied the same reasoning 

to our Arkansas proposal. As we discuss 

in our response to another comment, 

although we regard NID as a promising 

technology that may in fact be capable 

of greater levels of control than what we 

have assumed, there is no real long-term 

monitoring data to substantiate such a 

conclusion. Therefore, because we have 

concluded that in this instance the costeffectiveness of wet scrubbers is not 

justified by their relatively small 

additional visibility benefit, we disagree 

that SO2 BART for Flint Creek Unit 1 

should be 0.04, based on the 

performance of a wet scrubber. 

Comment: The Sierra Club and others 

stated that the LNB/OFA proposal for 

Flint Creek does not satisfy NOX BART, 

which should have been based on SCR. 

The Sierra Club stated that we and AEP 

used very conservative assumptions that 

inflated the cost of the SCRs and SNCRs 

as NOX BART options for Flint Creek. 

The Sierra Club’s consultant stated that 

the 20-year life assumed in AEP’s SCR 

cost analysis should have been 30 years, 

and that the assumed level of control 

should have been 0.04 lbs/MMBtu. The 

consultant then performed an SCR 

control cost analysis and concluded that 

the cost effectiveness was within a range 

we have previously found to be 

acceptable in other BART 

determinations. The Sierra Club’s 

consultant also stated that AEP 

overestimated the cost of SNCR because 

it based it on a reduction of from 0.31 

lbs/MMBtu to 0.2 lbs/MMBtu, when in 

fact, the first-in-line LNB/OFA controls 

would have already reduced the NOX to 

0.23 lbs/MMBtu, resulting in a lesser 

loading to the SNCR system and 

reducing its operating costs. 

Response: We note that we provided 

comments to ADEQ,225 which included 

a recommendation that 30 years should 

be used as an equipment life for SNCR. 

AEP did not adopt this recommendation 

in its September 2013 BART analysis for 

the Flint Creek facility. We agree with 

the Sierra Club’s consultant that AEP 

overestimated the cost of SNCR because 

its calculation based it on a reduction of 

from 0.31 lbs/MMBtu to 0.2 lbs/MMBtu. 

We have corrected this error, and the 

error in AEP SWEPCO’s assumed 20- 

year equipment life, and recalculated 

the SNCR cost effectiveness for Flint 

Creek. We calculated that SNCR + LNB/ 

OFA has a revised cost-effectiveness of 

$1,346/ton, as opposed to cost 

effectiveness of $1,258/ton for LNB/ 

OFA alone. Also, we calculated that the 

incremental cost effectiveness of SNCR 

+ LNB/OFA over LNB/OFA alone is 

$1,581/ton. We then re-applied the 

BART five factors, with emphasis on 

cost and visibility improvement. The 

incremental visibility improvement of 

SNCR + LNB/OFA over LNB/OFA alone 

is 0.033 dv at Caney Creek and ranges 

from 0.005 to 0.01 dv at each of the 

other affected Class I areas. As 

discussed in our proposal, we consider 

the incremental visibility improvement 

of SNCR + LNB/OFA to be relatively 

small at Caney Creek and to be very 

small in the remaining three affected 

Class I areas. We conclude that despite 

the improvement in the costeffectiveness of SNCR + LNB/OFA over 

LNB/OFA alone, under these 

circumstances the resulting relatively 

small incremental visibility 

improvement is still not worth the 

additional cost of the more stringent 

controls. 

Regarding the Sierra Club’s 

consultant’s SCR control cost analysis, 

we do not believe that a NOX emission 

limit of 0.04 lbs/MMBtu has been 

maintained on a 30 boiler-operating-day 

average at other similar facilities. We 

conclude that, as we did in our New 

Mexico FIP, a 30 boiler-operating-day 

NOX average of 0.05 lbs/MMBtu is an 

appropriate assumption for SCR 

installation at the Flint Creek facility. 

We also note that the maximum 

visibility improvement due to SCR at 

Flint Creek based on the modeled rate 

of 0.067 lb/MMBtu was 0.245 dv, which 

occurred at Caney Creek. If we make 

reasonable, conservative adjustments to 

the anticipated visibility benefit, based 

on a control level of 0.055 lbs/MMBtu 

rather than the modeled rate of 0.067 

lbs/MMBtu,226 we estimate that the 

resulting visibility improvement at 

Caney Creek would be no higher than 


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227Modeled visibility benefit at CACR over 

baseline from SCR at 0.067lb/MMbtu was 0.245 dv. 

SCR at 0.055 lb/MMBtu would result in an 

additional reduction in emissions from baseline of 

only 4%. Assuming a linear relationship between 

emission and visibility impacts, this would also 

result in an increase in visibility benefit of only 4%. 

228This was our approach in calculating the SO2

baselines used in our recent TX–OK FIP. 

229 70 FR at 39167. 

230Response to Technical Comments for Sections 

E. through H. of the Federal Register Notice for the 

Oklahoma Regional Haze and Visibility Transport 

Federal Implementation Plan, Docket No. EPA– 

R06–OAR–2010–0190, 12/13/2011, pdf 116. 

231We note, however, that in both its final rule 

and in its brief the EPA asserts that the guidelines 

0.26 dv.227 Based on this adjustment, 

the incremental visibility improvement 

of SCR + LNB/OFA over SNCR + LNB/ 

OFA is 0.146 dv. Even accepting the 

Sierra Club’s consultant’s SCR cost 

analysis of $3,511/ton (which would be 

higher were it revised using a controlled 

NOX rate of 0.05 lbs/MMBtu) and taking 

into consideration the adjustments we 

have made to the cost analysis for SNCR 

+ LNB/OFA, the incremental cost 

effectiveness of SCR + LNB/OFA over 

SNCR + LNB/OFA is $4,969/ton. In the 

context of this BART determination, we 

do not consider the relatively small 

incremental visibility improvement to 

be worth the incremental cost of the 

SCR installation. 

Comment: The Sierra Club and others 

stated that the Lake Catherine Unit 4 

BART analysis failed to accurately 

consider compliance costs, nonenvironmental impacts, and the degree 

of visibility improvement. The Sierra 

Club further stated we underestimated 

the cost of BOOS and overestimated the 

costs of low NOX burners, over-fired air, 

SNCR, and SCR. The Sierra Club’s 

consultant also alleges that the 

documentation to support the Lake 

Catherine NOX BART analysis is 

incomplete. Lastly, the Sierra Club 

stated that our cost-effectiveness 

analysis should be based on a capacity 

calculation that depends on time of 

operation, and our proposal to use a 

10% capacity is unenforceable. Had we 

used a higher capacity factor, the Sierra 

Club reasons that the increase in NOX

emissions removed by the various 

pollution control equipment would 

have improved their cost-effectiveness 

(lower $/ton), making them more 

attractive. 

Response: The Sierra Club’s 

consultant raises a number of issues 

pertaining to missing documentation or 

errors in Entergy’s NOX BART analysis 

for Lake Catherine Unit 4, on which we 

relied on in making our BART decision. 

We reviewed the issues raised by the 

Sierra Club’s consultant in detail in our 

RTC document and conclude they are 

unfounded or lack documentation. We 

conducted an analysis of Lake 

Catherine’s data on heat input, 

operational time, and NOX emissions to 

investigate the correlation between heat 

input and operational time to NOX

emissions, and further conclude that 

capacity calculations for the Lake 

Catherine Unit 4 should be based on 

heat input and not operational time. 

Lastly, we calculate the historical 

capacity for the Lake Catherine Unit 4 

as follows: 

TABLE 20—LAKE CATHERINE UNIT 4 

HISTORICAL CAPACITY

Year Capacity factor 

(%) 

2001 ...................................... 28.2 

2002 ...................................... 24.2 

2003 ...................................... 11.3 

2004 ...................................... 3.7 

2005 ...................................... 4.7 

2006 ...................................... 0.6 

2007 ...................................... 0.8 

2008 ...................................... 2.3 

2009 ...................................... 2.8 

2010 ...................................... 3.5 

2011 ...................................... 2.9 

2012 ...................................... 14.3 

2013 ...................................... 11.1 

2014 ...................................... 2.0 

2015 ...................................... 3.9 

We agree that the Lake Catherine Unit 

4 historical capacity has sometimes 

exceeded the 10% capacity Entergy has 

assumed in its control cost analyses. 

However, the average from the last ten 

years of data (2006 to 2015) has been 

4.4%. Typically, we place the most 

emphasis on the last five years of data, 

and our recent practice has been to 

discard the high and low values and 

average the remaining three years.228

Applying that procedure to the Lake 

Catherine Unit 4 capacity factor results 

in a value of 6.0%. Alternatively, 

calculating a straight average of the last 

five years results in a value of 6.8%. 

Thus, we disagree that we erred in 

accepting Entergy’s assumption of a 

10% capacity factor in its control cost 

analysis. We note that in its response to 

us, Entergy stated, ‘‘If future capacity 

factors change, ADEQ and EPA may 

impose further NOX emission 

reductions on Unit 4, if necessary, in 

later planning periods to show 

reasonable progress.’’ We believe that is 

an appropriate strategy and we will reexamine Lake Catherine’s historical 

capacity in our review of Arkansas’ next 

regional haze SIP. 

Comment: We received comments 

from Nucor, Entergy and Conway 

Corporation stating that we should have 

used the dollar per deciview ($/dv) 

metric to weigh the cost versus the 

visibility benefit of controls for the 

White Bluff and Independence facilities. 

The Sierra Club supported our position 

that we are not required to use this 

metric. 

Response: The BART Guidelines 

require that cost effectiveness be 

calculated in terms of annualized 

dollars per ton of pollutant removed, or 

$/ton.229 The BART Guidelines list the 

$/deciview metric as an optional cost 

effectiveness measure that can be 

employed along with the required $/ton 

metric for use in a BART evaluation. 

The metric can be useful in comparing 

control strategies or as additional 

information in the BART determination 

process; however, due to the complexity 

of the technical issues surrounding 

regional haze, we have never 

recommended the use of this metric as 

a cutpoint or threshold in making BART 

determinations or reasonable progress 

determinations. We note that to use the 

$/deciview metric as the main 

determining factor would most likely 

require the development of thresholds 

of acceptable costs per deciview of 

improvement for BART and reasonable 

progress determinations for both single 

and multiple Class I analyses. We have 

not developed such thresholds for use 

in BART or reasonable progress 

determinations. Generally speaking, 

while the $/deciview metric can be 

useful if thoughtfully applied, we view 

the use of this metric as suggesting a 

level of precision in the calculation of 

visibility impacts that is not justified in 

many cases. While we did not use a $/ 

deciview metric in the BART and 

reasonable progress determinations we 

make in this FIP, we did, however, 

consider the visibility benefits and costs 

of control together, as noted above by 

weighing the costs in light of the 

predicted visibility improvement. We 

have addressed this issue in a number 

of our previous actions since we first 

discussed this issue in our Oklahoma 

FIP,230 and our position with regard to 

the $/deciview metric was reviewed and 

upheld in Oklahoma v. EPA, 723 F.3d 

1201 by the Tenth Circuit which ruled: 

Oklahoma first suggests EPA should not 

have rejected the visibility analysis it 

conducted in the SIP, which used the dollarper-deciview method. This argument is 

misguided. The EPA rejected the SIP because 

of the flawed cost estimates. When 

promulgating its own implementation plan, it 

did not need to use the same metric as 

Oklahoma. The guidelines merely permit the 

BART-determining authority to use dollar per 

deciview as an optional method of evaluating 

cost effectiveness. See 40 CFR pt. 51 app. 

Y(IV)(E)(1).231 And in the final rule, the EPA 


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require the use of the dollar-per-ton metric in 

evaluating cost effectiveness. The guidelines 

themselves are a bit unclear. In the section on cost 

effectiveness, the guidelines mention only the 

dollar-per-ton metric. 40 CFR pt. 51 app. 

Y(IV)(D)(4)(c). However, the guidelines later state 

that in evaluating alternatives, ‘‘we recommend you 

develop a chart (or charts) displaying for each of the 

alternatives’’ that includes, among other factors, the 

cost of compliance defined as ‘‘compliance—total 

annualized costs ($), cost effectiveness ($/ton), and 

incremental cost effectiveness ($/ton), and/or any 

other cost-effectiveness measures (such as $/ 

deciview).’’ Id. app.Y(IV)(E)(1) (emphasis added). 

232For example, see 76 FR 52388, 52429 (August 

22, 2011). 

233 40 CFR 51 Appendix Y, IV.D.5. 

234 ‘‘Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program,’’ June 1, 

2007. 

explained why it did not use the dollar-perdeciview metric used by Oklahoma. 

‘‘Generally speaking, while the metric can be 

useful if thoughtfully applied, we view the 

use of the $/deciview metric as suggesting a 

level of precision in the calculation of 

visibility impacts that is not justified in many 

cases.’’ 76 Fed. Reg. at 81,747. The EPA has 

never mandated the use of this metric, and 

has not developed ‘‘thresholds of acceptable 

costs per deciview improvement.’’ Id. While 

the federal land managers have developed 

thresholds, these thresholds were apparently 

developed without input from the EPA and 

without notice-and-comment review. EPA Br. 

at 54 n. 13. In light of this, we do not find 

it arbitrary or capricious that the EPA chose 

not to use the dollar-per-deciview metric in 

evaluating BART options in creating the FIP. 

We therefore also conclude that any 

argument by the petitioners that the dollarper-deciview measurement proves the 

scrubbers are not cost effective lacks merit. 

See Pet. Reply Br. at 16. 

We see no reason to deviate from our 

view of the $/deciview metric here. 

J. Modeling 

1. Cumulative Visibility Impairment 

Comment: Several commenters 

opposed the use of a ‘‘cumulative 

deciviews’’ or ‘‘total’’ visibility 

improvement metric and claim the 

‘‘cumulative deciviews’’ metric has no 

basis in the CAA and EPA’s regulations. 

It also allegedly mischaracterizes 

visibility improvements in Class I areas. 

Determinations instead should be based 

on the predicted visibility 

improvements at individual Class I 

areas. Furthermore, the cumulative 

metric is deceptive and provides no 

information that could be used to assess 

whether any single Class I area would 

experience perceivable visibility 

improvements as a result of BART or 

reasonable progress controls, and may 

mask the fact that no individual Class I 

area would experience any discernible 

visibility improvement from control of 

emissions at any particular source. The 

cumulative metric represents an illusory 

visibility benefit; it is an improvement 

that cannot be perceived and therefore 

provides no indication of whether the 

proposed controls will contribute to the 

goal of the regional haze program: To 

reduce human perception of visibility 

impairment in Class I areas. The only 

purpose of the cumulative visibility 

improvement indicator is to imply that 

facilities are having a large impact 

across numerous Class I areas, but this 

indicator can be deceptive if it includes 

imperceptible visibility improvements 

for some Class I areas. 

The commenters also suggest that the 

use of a ‘‘total dv’’ metric is inconsistent 

with BART guidelines (40 CFR part 51 

Appendix Y, IV.D.5) that state it is 

appropriate to model impacts at the 

nearest Class I area as well as other 

nearby Class I areas to determine where 

the impacts are greatest. Modeling at 

other Class I areas may be unwarranted 

if the highest modeled effects are 

observed at the nearest Class I area. The 

commenters claim the analysis should 

be focused on the visibility impacts at 

the most impacted area, not all areas. 

Other commenters supported the use of 

the cumulative visibility metric, stating 

that it is appropriate and lawful, and 

within the spirit of the statutory 

mandate and expressly permissible 

within the regulation to consider 

cumulative impacts. 

Response: We agree with the 

comments supporting the consideration 

of cumulative visibility impacts and 

benefits. We disagree with the other 

commenters that cumulative 

improvement over multiple areas is an 

inappropriate metric, or that examining 

a single Class I area is sufficient. The 

cumulative improvement metric (i.e., 

the simple sum of impacts or 

improvements over all the affected Class 

I areas) is not intended to correspond to 

a single human’s perception at a given 

time and place. The approach is simply 

one way of assessing improvements at 

multiple areas, for consideration along 

with other visibility metrics. Another 

approach would be to simply list 

visibility improvements at the various 

areas, and qualitatively weigh the 

number of areas and the magnitudes of 

the improvements. The cumulative sum 

is simply an easily understood and 

objective way of weighing cumulative 

visibility improvement, as part of the 

overall control evaluation along with 

the visibility improvement at each 

impacted Class I area. As noted by some 

comments, we have calculated 

cumulative visibility in a number of 

Regional Haze actions evaluating the 

benefits of controls under BART and 

when visibility is considered in the 

reasonable progress analysis. 

Furthermore, the FLMs have provided 

comments in support of the use of this 

metric in past actions.232

The comment opposing cumulative 

modeling does not provide the full 

context when citing to the BART 

guidelines. The portion referred to by 

the commenter discusses the 

development of a modeling protocol and 

establishing the receptors to model. The 

full portion of the BART Guidelines that 

the commenter referenced states: 

The receptors that you use should be 

located in the nearest Class I area with 

sufficient density to identify the likely 

visibility effects of the source. For other Class 

I areas in relatively close proximity to a 

BART-eligible source, you may model a few 

strategic receptors to determine whether 

effects at those areas may be greater than at 

the nearest Class I area. For example, you 

might chose to locate receptors at these areas 

at the closest point to the source, at the 

highest and lowest elevation in the Class I 

area, at the IMPROVE monitor, and at the 

approximate expected plume release height. 

If the highest modeled effects are observed at 

the nearest Class I area, you may choose not 

to analyze the other Class I areas any further 

as additional analyses might be 

unwarranted.233

This section of the BART Guidelines 

addresses how to determine visibility 

impacts as part of the BART 

determination. Several paragraphs later 

in the BART Guidelines it states: ‘‘You 

have flexibility to assess visibility 

improvements due to BART controls by 

one or more methods. You may consider 

the frequency, magnitude, and duration 

components of impairment,’’ 

emphasizing the flexibility in method 

and metrics that exists in assessing the 

net visibility improvement. 

In fully considering the visibility 

benefits anticipated from the use of an 

available control technology as one of 

the factors in selection of BART, it is 

appropriate to account for visibility 

benefits across all affected Class I areas 

and the BART guidelines provide the 

flexibility to do so. One approach as 

noted above is to qualitatively consider, 

for example, the frequency, magnitude, 

and duration of impairment at each and 

all affected Class I areas. Where a source 

significantly impacts more than one 

Class I areas, the cumulative visibility 

metric is one way to take magnitude of 

the impacts of the source into account. 

With respect to our analysis of 

controls under reasonable progress, we 

rely on our Reasonable Progress 

Guidance.234 Our Reasonable Progress 

Guidance notes the similarity between 

some of the reasonable progress factors 

and the BART factors contained in 

§ 51.308(e)(1)((ii)(A), and suggests that 


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235As we explain in our proposed action (80 FR 

at 18993): ‘‘While visibility is not an explicitly 

listed factor to consider when determining whether 

additional controls are reasonable under the 

reasonable progress requirements, the purpose of 

the four-factor analysis is to determine what degree 

of progress toward natural visibility conditions is 

reasonable. Therefore, it is appropriate to consider 

the projected visibility benefit of the controls when 

determining if the controls are needed to make 

reasonable progress’’. See 79 FR at 74838, 74840, 

and 74874. 

236CAA section 169A (‘‘Congress hereby declares 

as a national goal the prevention of any future, and 

the remedying of any existing, impairment of 

visibility in mandatory class I Federal areas which 

impairment results from manmade air pollution.) 

(emphasis added). 

237E.g. Webster’s Third New International 

Dictionary 2557 (1981) (‘‘visible’’ means ‘‘capable of 

being seen’’; ‘‘visibility’’ means ‘‘the degree or 

extent to which something is visible . . . [by] the 

observer’s eye unaided by special optical devices’’). 

238Am. Corn Growers Ass’n v. EPA, 291 F.3d 1, 

7 (D.C. Cir. 2002). 

239 It is generally recognized that a change in 

visibility of 1.0 deciview is humanly perceptible. 

240 70 FR 39104, 39129. 

241CAA section 169A(g)(2). 

the BART Guidelines be consulted 

regarding cost, energy and nonair 

quality environmental impacts, and 

remaining useful life. We are therefore 

relying on our BART Guidelines for 

assistance in interpreting those 

reasonable progress factors, as 

applicable. 

Also, similar to a BART analysis, we 

are also considering the projected 

visibility benefit in our analysis 

following the BART guidelines and the 

use of CALPUFF.235 We rely on the 

BART Guidelines here and in other 

actions evaluating reasonable progress 

controls because they provide a 

reasonable and consistent approach 

regarding visibility modeling. This 

includes the flexibility in metrics that 

exists in assessing the net visibility 

improvement, and the use of cumulative 

visibility, along with visibility impacts 

at individual Class I areas, as one way 

to take magnitude of the impacts of the 

source into account where a source 

evaluated under reasonable progress 

significantly impacts more than one 

Class I area. 

For each subject-to-BART source and 

the source evaluated for reasonable 

progress controls, we evaluated the 

visibility impacts from the source and 

benefits of controls at four separate 

Class I areas. In addition to providing 

the visibility impacts and potential 

benefits at each Class I area in the 

proposal, we also summed the impact 

and improvement across the four Class 

I areas. The results show that some 

sources significantly impact visibility at 

more than one Class I area, emission 

reductions result in visibility benefits at 

all impacted class I areas, and in some 

situations, the largest visibility benefits 

from controls can occur at Class I areas 

other than the most impacted. 

Therefore, consistent with the BART 

Guidelines, and based upon these facts, 

we determined additional analyses were 

not only warranted but necessary. The 

BART Guidelines only indicate that 

additional analyses may be unwarranted 

at other Class I areas, and in no way 

exclude such analyses, as the 

commenter suggests. We concluded that 

a quantitative analysis of visibility 

impacts and benefits at only the most 

impacted area would not be sufficient to 

fully assess the impacts and benefits of 

controlling emissions from the sources 

evaluated for BART and reasonable 

progress. 

Nothing in the Regional Haze Rule 

suggests that a state (or EPA in issuing 

a FIP) should ignore the full extent of 

the visibility impacts and improvements 

from controls at multiple Class I areas. 

Given that the national goal of the 

program is to improve visibility at all 

Class I areas, it would be short-sighted 

to limit the evaluation of the visibility 

benefits of a control to only the most 

impacted Class I area. We believe such 

information is useful in quantifying the 

overall benefit of controls. As discussed 

in our proposal, we evaluated the 

statutory factor, visibility benefits 

anticipated due to controls, at each 

Class I area in making BART 

determinations and considered the 

visibility benefits in consideration of 

controls for reasonable progress. 

2. Imperceptible Visibility Improvement 

Comment: EPA must withdraw the 

proposed FIP because the FIP would 

only achieve visibility improvements 

below one deciview, which is not 

discernible to the naked eye. 

Commenters state that the CAA only 

provides EPA with the authority to 

regulate the ‘‘impairment of 

visibility.’’ 236 Visibility extends only to 

things that humans can see with their 

naked eyes.237 By extension, EPA only 

has authority to regulate the 

impairments of visibility that are 

perceptible to the human eye. Under 

both the plain language and dictionary 

definitions of ‘‘visibility,’’ the statute 

does not provide EPA with the authority 

to regulate haze below a single 

deciview, which would be invisible to 

the naked eye. Since the Proposed FIP 

will only achieve visibility 

improvements smaller than one 

deciview, the EPA lacks authority to 

revise the RPGs suggested by Arkansas, 

and it should withdraw the Proposed 

FIP. 

Commenters also state that the EPA 

may not require a source ‘‘to spend 

millions of dollars for new technology 

that will have no appreciable effect on 

haze in any Class I area.’’ Am. Corn 

Growers Ass’n. v. EPA 238 (vacating 

EPA’s BART determinations because 

EPA left open the possibility that it 

could require a source to install 

technologies even when those 

technologies had no appreciable effect 

on visibility). Yet the EPA requires 

certain stationary sources of immense 

value to the State of Arkansas and its 

citizens to install controls that will cost 

billions of dollars in order to achieve 

imperceptible visibility improvements. 

Response: We disagree with 

commenters that the Regional Haze Rule 

requires that controls on a source or 

group of sources result in perceptible 

visibility improvement.239 We believe, 

for reasons we have outlined in our 

proposal and elsewhere in our response 

to comments, that the controls we 

proposed under our FIP will result in 

significant improvements in visibility at 

a number of Class I areas. In a situation 

where the installation of BART may not 

result in a perceptible improvement in 

visibility, the visibility benefit may still 

be significant, as explained by the 

Regional Haze Rule: 

Even though the visibility improvement 

from an individual source may not be 

perceptible, it should still be considered in 

setting BART because the contribution to 

haze may be significant relative to other 

source contributions in the Class I area. Thus, 

we disagree that the degree of improvement 

should be contingent upon perceptibility. 

Failing to consider less-than-perceptible 

contributions to visibility impairment would 

ignore the CAA’s intent to have BART 

requirements apply to sources that contribute 

to, as well as cause, such impairment.240

Section 169A of the CAA requires that 

certain major sources that emit any 

pollutant which may reasonably be 

anticipated to cause or contribute to 

visibility impairment in Class I Areas 

install BART. The following factors 

must be taken into account in 

determining BART: The costs of 

compliance, the energy and nonair 

quality environmental impacts of 

compliance, any existing pollution 

control technology in use at the source, 

the remaining useful life of the source, 

and the degree of improvement in 

visibility which may reasonably be 

anticipated to result from the use of 

such technology.241

The CAA also requires that in 

determining reasonable progress there 

shall be taken into consideration the 

costs of compliance, the time necessary 

for compliance, the energy and nonair 


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242 ‘‘Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program,’’ June 1, 

2007. 

243As we explain in our proposed action (80 FR 

at 18993): ‘‘While visibility is not an explicitly 

listed factor to consider when determining whether 

additional controls are reasonable under the 

reasonable progress requirements, the purpose of 

the four-factor analysis is to determine what degree 

of progress toward natural visibility conditions is 

reasonable. Therefore, it is appropriate to consider 

the projected visibility benefit of the controls when 

determining if the controls are needed to make 

reasonable progress’’. See also 79 FR at 74838, 

74840, and 74874. 

244 76 FR 81728, 81739. 

245Am. Corn Growers Ass’n v. EPA, 291 F.3d 1, 

7 (D.C. Cir. 2002). 

246 Id. 

247 Id. at 7–8. 

248 40 CFR 51.308(e)(1)(ii)(B). 

249 Id. 

250 291 F.3d at 6. 

251 70 FR 39104. 

quality environmental impacts of 

compliance, and the remaining useful 

life of any existing source subject to 

such requirements. Our 2007 

Reasonable Progress Guidance 242 notes 

the similarity between some of the 

reasonable progress factors and the 

BART factors contained in 

§ 51.308(e)(1)(ii)(A), and suggests that 

the BART Guidelines be consulted 

regarding cost, energy and nonair 

quality environmental impacts, and 

remaining useful life. We are therefore 

relying on our BART Guidelines for 

assistance in interpreting those 

reasonable progress factors, as 

applicable, including visibility 

improvement even though it may not be 

perceptible from an individual source. 

Also, similar to a BART analysis, we are 

also considering the projected visibility 

benefit in our analysis of reasonable 

progress controls following the BART 

guidelines.243 We rely on the BART 

Guidelines here and in other actions 

evaluating reasonable progress controls 

because they provide a reasonable and 

consistent approach regarding visibility 

modeling. 

We accordingly disagree that selection 

of control measures under BART or for 

reasonable progress should be 

contingent upon perceptible visibility 

improvement. As we stated in our 

previous rulemaking addressing the 

BART determinations in Oklahoma: 

Given that sources are subject to BART 

based on a contribution threshold of no 

greater than 0.5 deciviews, it would be 

inconsistent to automatically rule out 

additional controls where the improvement 

in visibility may be less than 1.0 deciview or 

even 0.5 deciviews. A perceptible visibility 

improvement is not a requirement of the 

BART determination because visibility 

improvements that are not perceptible may 

still be determined to be significant.244

The Regional Haze Rule provides that 

BART–eligible sources with a 0.5 dv 

impact at a Class I area ‘‘contribute’’ to 

visibility impairment and must be 

analyzed for BART controls. BART 

determining authorities, however, are 

free to establish thresholds less than 0.5 

dv. Consequently, even though the 

visibility improvement from controlling 

an individual source may not be 

perceptible, it should still be considered 

because the contribution to haze may be 

significant when the aggregate 

contribution of other sources in the 

Class I area is taken into account and 

because the contribution to haze from 

the source may be significant relative to 

other source contributions in the Class 

I area. Thus, in our visibility 

improvement analysis for BART sources 

and in consideration of visibility 

benefits from controls under our 

reasonable progress analysis, we have 

not considered perceptibility as a 

threshold criterion for considering 

improvements in visibility to be 

meaningful. 

We have considered visibility 

improvement in a holistic manner, 

taking into account all reasonably 

anticipated improvements in visibility, 

and the fact that, in the aggregate, 

improvements from controls on 

multiple sources (either under BART or 

reasonable progress) will contribute to 

visibility progress towards the goal of 

natural visibility conditions. Visibility 

impacts below the thresholds of 

perceptibility cannot be ignored because 

regional haze is produced by a 

multitude of sources and activities 

which are located across a broad 

geographic area. In this action, we found 

that the required cost-effective controls 

reduce visibility impairment from those 

BART sources that contribute or cause 

visibility impairment at nearby Class I 

areas and result in meaningful visibility 

benefits towards the goal of natural 

visibility conditions. Similarly, we also 

found that the required cost-effective 

controls at the Entergy Independence 

facility reduce visibility impairment 

from the source with the largest 

potential visibility impacts (among all 

Non-BART sources) and result in 

meaningful visibility benefits towards 

the goal of natural visibility conditions. 

The commenter mischaracterizes a 

statement made by the D.C. Circuit 

Court of Appeals in Am. Corn Growers 

Ass’n. v. EPA. The statement made by 

the Court is as follows: ‘‘[U]nder EPA’s 

take on the statute, it is therefore 

entirely possible that a source may be 

forced to spend millions of dollars for 

new technology that will have no 

appreciable effect on the haze in any 

Class I area.’’ 245 The Court made this 

statement in reviewing EPA’s approach 

to the BART requirements in the 

Regional Haze Rule promulgated in 

1999 which did not require the sourcespecific assessment of a BART eligible 

source’s visibility impacts at any step of 

the BART process.246

The Court disagreed with the 

approach used by EPA to determine 

what BART eligible sources are 

reasonably anticipated to cause or 

contribute to regional haze and therefore 

subject to BART.247 The approach in the 

Regional Haze Rule required a State to 

analyze ‘‘the degree of visibility 

improvement that would be achieved in 

each mandatory Class I Federal area as 

a result of the emission reductions 

achievable from all sources subject to 

BART located within the region that 

contributes to visibility impairment in 

the Class I area.’’ 248 The Court held that 

the Rule’s treatment of ‘‘the degree of 

improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology’’ factor 

infringed on states’ authority with 

respect to BART determinations under 

the Act.249 The Court noted that the Act 

does not assign a specific weight with 

which to consider each factor, it solely 

mandates that all the factors be 

considered in making a BART 

determination.250 The Court’s issue was 

not with the weight, or lack thereof, 

placed on this factor by EPA. It found 

issue with what it considered to be 

‘‘dramatically’’ different treatment of the 

visibility factor by EPA. Id. While the 

court in American Corn Growers Ass’n. 

v. EPA found that we had impermissibly 

constrained State authority, it did so 

because it found that we forced States 

to require BART controls without first 

assessing a source’s particular 

contribution to visibility impairment. 

This is not the case with our action in 

Arkansas. In response to this court 

decision and to address these concerns 

we finalized revised Regional Haze 

Regulations and Guidelines for Best 

Available Retrofit Technology (BART) 

Determinations.251

Our analysis does not give greater 

weight to one factor over another; 

rather, we considered all five BART 

factors fully, revealing that the cost and 

visibility factors were the two most 

important factors in our decisions. In 

American Corn Growers Ass’n. v. EPA, 

the D.C. Circuit Court faulted how EPA 

assessed the statutory fifth factor of 

visibility improvement in a BART 

determination by using a regional, 

multi-source, group approach to 

assessing the visibility improvement 

factor, while assessing the other four 


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252 291 F. 3d at 8–9. 

253 79 FR 5032, 5120 (January 30, 2014). 

254BART Guidelines, 70 FR 39104, 39121 (‘‘there 

are other features of our recommended modeling 

approach that are likely to overstate the actual 

visibility effects of an individual source. Most 

important, the simplified chemistry in the model 

tends to magnify the actual visibility effects of that 

source.’’) 

255Proposed Texas Regional Haze FIP, 79 FR 

74818, 74877, 74878. 

256 Id. at 74878. 

257 Draft Modeling Guidance at 22. The Draft 

Modeling Guidance is available at http://

www.epa.gov/scram001/guidance/guide/Draft_O3- 

PMRH_Modeling_Guidance-2014.pdf. 

258Appendix W to 40 CFR part 51. 

259 Docket ID EPA–HQ–OAR–2015–0310–0004. 

statutory BART factors on a sourcespecific basis. Here, we did not give 

greater weight to our consideration of 

visibility improvement or consider the 

visibility in a different fashion from the 

other factors. All BART factors were 

evaluated on a source-specific basis. 

The Court also noted that it is the 

State’s and not EPA’s duty to determine 

what BART is (provided that the State’s 

determination complies with the Act 

and EPA guidelines.252). When EPA 

promulgates a FIP, it is acting in the 

place of the State, and thus has the same 

authority a state has when the state 

promulgates a SIP. It is therefore our 

duty to determine what BART is since 

we are proposing a FIP for Arkansas. We 

must also consider the same factors that 

the State is mandated to consider by the 

CAA. The ‘‘degree of improvement in 

visibility which may reasonably be 

anticipated to result from the use of 

such [best available retrofit] technology’’ 

is just one of several factors the State, 

or EPA in the case of a FIP, must 

consider in determining what BART is 

for a specific source. 

We also disagree with commenter’s 

statement that we required emissions 

reductions just for the sake of doing so 

under the guise of imperceptible 

visibility improvements or solely for the 

sake of reducing emissions. As 

discussed above, we considered all the 

statutory factors, including the ‘‘degree 

of improvement in visibility which may 

reasonably be anticipated to result from 

the use of such [best available retrofit] 

technology’’ in our BART 

determinations. We do not consider 

perceptibility as a threshold criterion for 

considering improvements in visibility 

to be meaningful. Failing to consider 

less-than-perceptible contributions to 

visibility impairment would ignore the 

CAA’s intent to have BART 

requirements apply to sources that 

contribute to, as well as cause, such 

impairment. 

Comment: One commenter stated that 

the visibility benefits of some of the 

required controls either individually or 

in combination will result in perceptible 

visibility benefits. They also comment 

that the regional haze regulations reflect 

EPA’s finding that the Congressional 

goal of eliminating haze can be achieved 

only by tackling the multitude of 

sources that contribute to haze in 

national parks and wilderness areas. For 

this reason, EPA has stated that 

‘‘visibility improvement does not need 

to be perceptible to be deemed 

significant for BART purposes.’’ 253

Response: We agree with the 

commenter. As we discuss in response 

to comments above, the Regional Haze 

Rule does not require that controls on a 

source or group of sources result in 

perceptible visibility improvement. We 

also agree that in some cases required 

controls either individually or in 

combination with other required 

controls will result in perceptible 

visibility improvements at impacted 

Class I areas on some days. 

3. Model Selection 

Comment: CALPUFF modeling cannot 

be used to justify controls at 

Independence under the reasonable 

progress requirements. Using CALPUFF, 

a single source model, for evaluating the 

reasonable progress benefits of installing 

controls at Independence is misplaced 

and clearly in error. EPA must 

demonstrate that additional controls are 

rational and economically justifiable 

and that the amount of progress that 

would result will be ‘‘reasonable based 

upon the statutory factors.’’ CALPUFF is 

overly simplistic and greatly overstates 

the effect of single source emissions.254

CALPUFF also fails to show the effects 

of multiple sources, and is much less 

sophisticated in its treatment of the 

chemical interactions of the different 

pollutants in the atmosphere than 

CAMx. The commenters also state that 

the use of CALPUFF does not reflect the 

interaction of pollutants in the 

atmosphere as accurately as CAMx does. 

EPA used CALPUFF and did not 

perform refined, multi-state modeling to 

determine the amount of visibility 

improvements that would be achieved 

through the installation of controls 

because it would be difficult, timeconsuming, and expensive. Instead, the 

Agency took a ‘‘thumbnail’’ approach in 

an attempt to justify the proposed 

controls based on how long it would 

take to achieve background levels. 

EPA recognized in their action on 

Texas regional haze that CAMx, a 

photochemical transport 3-dimensional 

grid model, is a more appropriate 

modeling tool for reasonable progress 

purposes.255 BART analyses assess the 

impact of a single facility based on the 

maximum or 98th percentile impacts, 

regardless of whether the Class I area 

was actually experiencing high visibility 

impairment on any given day. Since 

CALPUFF does not conduct an analysis 

considering all the emissions from all 

potential sources, some of the days with 

the worst model-predicted 

concentrations could be days that are 

not significantly impaired. Reasonable 

progress modeling using a 

photochemical model, such as CAMx, 

allows EPA to evaluate impacts from a 

source (with all other sources included 

in the modeling) on a Class I area’s best 

and worst days.256

The draft EPA Modeling Guidance for 

Demonstrating Attainment of Air 

Quality Goals for Ozone, PM2.5, and 

Regional Haze (Dec. 2014) (‘‘Draft 

Modeling Guidance’’) discusses the use 

of photochemical grid models. The Draft 

Modeling Guidance specifically notes 

that ‘‘a modeling based demonstration 

of the impacts of an emissions control 

scenario . . . as part of a regional haze 

assessment usually necessitates the 

application of a chemical transport grid 

model.’’ 257 Throughout the Draft 

Modeling Guidance, the discussion is 

focused on items specific to 

photochemical grid models such as 

CAMx, including emissions inventories, 

supporting models, pre-processors, and 

applying a model to changes in 

visibility. 

Notably, EPA recently issued a 

proposal, which would remove 

CALPUFF from EPA’s preferred list of 

air dispersion models in its Guideline 

on Air Quality Models 258 (‘‘Guideline’’). 

Although EPA states that the proposed 

changes to the Guideline would not 

affect its recommendation that 

CALPUFF be used in the BART 

determination process, EPA made no 

such assurances regarding the use of 

CALPUFF for a reasonable progress 

analysis. EPA’s proposal emphasizes the 

use of chemical transport models for 

assessing visibility impacts from a 

single source or small group of sources. 

EPA’s Interagency Workgroup on Air 

Quality Modeling Phase 3 Summary 

Report: Long Range Transport and Air 

Quality Related Values 259 makes clear 

that CALPUFF should not be used for a 

reasonable progress analysis. 

Another commenter, EarthJustice, 

states that the other commenter’s 

assessment of the methodology used for 

Texas sources is incorrect. In fact, EPA 

also used an emission ‘‘scaling’’ 

approach to determine the effects of 

various control scenarios for their 

evaluation of Texas sources that is 


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260 70 FR 39104, 39123, 39124. ‘‘We understand 

the concerns of commenters that the chemistry 

modules of the CALPUFF model are less advanced 

than some of the more recent atmospheric 

chemistry simulations. To date, no other modeling 

applications with updated chemistry have been 

approved by EPA to estimate single source 

pollutant concentrations from long range 

transport.’’ and in discussion of using other models 

with more advanced chemistry it continues, ‘‘A 

discussion of the use of alternative models is given 

in the Guideline on Air Quality in appendix W, 

section 3.2.’’ 

261 70 FR at 39123, 39124. ‘‘The use of other 

models and techniques to estimate if a source 

causes or contributes to visibility impairment may 

be considered by the State, and the BART 

guidelines preserve a State’s ability to use other 

models. Regional scale photochemical grid models 

may have merit, but such models have been 

designed to assess cumulative impacts, not impacts 

from individual sources. Such models are very 

resource intensive and time consuming relative to 

CALPUFF, but States may consider their use for SIP 

development in the future as they are adapted and 

demonstrated to be appropriate for single source 

applications.’’ 

262See Appendix 9–4: CAMx Modeling Protocol, 

Screening Analysis of Potentially BART-Eligible 

Sources in Texas of the Texas regional haze SIP. 

263 40 CFR part 51 Appendix W, Guideline on Air 

Quality Models, 70 FR 68218 (November 9, 2005). 

264For example see summary of the reasonable 

progress analyses for specific sources in Arizona (79 

FR 9353), North Dakota (76 FR 58631), Montana (77 

FR 24065), and Wyoming (78 FR 34785). 

similar to that currently being applied 

for the evaluation of the sources in 

Arkansas. EPA Region 6 did not run the 

CAMx model repeatedly to determine 

the overall visibility effects of 

controlling individual sources. 

Response: The commenters confuse 

the single source analysis for evaluating 

the visibility impact and benefits of 

controls on units at the Independence 

facility and the analysis to estimate the 

visibility benefits of all controls on the 

20% worst days in establishing a new 

reasonable progress goal for 2018. We 

utilized CALPUFF modeling following 

the same modeling protocol relied on 

for the BART analyses to assess the 

visibility impacts and potential benefits 

of controls for the units at the 

Independence facility. For estimating 

the total visibility benefit from all 

controls and estimating a new 

reasonable progress goal that reflects 

those controls, we relied on the 

CENRAP’s 2018 CAMx modeling 

results, including source apportionment 

results, and the projected emission 

inventories, and scaled the results as 

described in the TSD. While we 

acknowledge that this approach is not as 

refined an estimate as would be attained 

in performing a new photochemical 

modeling run, it is based on scaling of 

earlier photochemical modeling results 

and not on CALPUFF modeling, as the 

commenter suggests. We disagree with 

the commenter’s characterization of our 

analysis as a ‘‘thumbnail’’ approach and 

noted in our proposal that similar 

approaches have been used in other 

actions in Hawaii and Arizona. As 

discussed in the proposed action, our 

determination that controls were 

reasonable for the Independence units 

was based on our evaluation of the four 

factors and including consideration of 

the visibility benefit of controls. For 

consideration of the visibility benefits, 

we relied on the results of our 

CALPUFF modeling, the CENRAP 

CAMx source apportionment results, 

and point source emission inventory 

data that initially identified the 

Independence facility as having the 

greatest potential to impact visibility at 

nearby Class I areas among all sources 

not already controlled under the BART 

requirements. 

The 2005 BART Guidelines 

recommended the use of CALPUFF for 

assessing visibility (secondary chemical 

impacts) but noted that CALPUFF’s 

chemistry was fairly simple. The 

visibility results from CALPUFF could 

be used as one of the five factors in a 

BART evaluation and the impacts 

should be utilized in a somewhat 

relative sense because CALPUFF was 

not explicitly approved for full 

chemistry calculations.260 The BART 

guidelines also provided the option to 

potentially use photochemical grid 

models (such as CAMx) in the future if 

modeling tools available were 

appropriate and EPA approved of the 

technical approaches and how the 

model would be utilized.261 Appendix 

W gives us discretionary authority in 

the selection of what models to use for 

visibility assessments with modeling 

systems, and models such as CALPUFF, 

CMAQ, REMSAD, and CAMx have all 

been used for that purpose. Specifically 

for single-source reasonable progress 

assessments similar to that done here for 

Independence, CALPUFF has been used 

for the majority of sources, while CAMx 

has been used in some situations, most 

notably and as noted by the commenter, 

in evaluating specific Texas sources for 

reasonable progress. In 2006/7, EPA 

OAQPS and EPA Region 6 consulted 

with FLM representatives and approved 

Texas’ BART screening modeling 

protocol using source apportionment 

tools in CAMx.262

Under the BART guidelines, 

CALPUFF should be used as a screening 

tool and appropriate consultation with 

the reviewing authority is required to 

use CALPUFF in a BART determination 

as part of a SIP or FIP. The BART 

Guideline cited and referred to EPA’s 

Guideline on Air Quality Models 

(Appendix W) 263 which includes 

provisions to obtain approval through 

consultation with the reviewing 

authority. Moreover, we also note that 

in EPA’s document entitled Guidance 

on the Use of Models and Other 

Analyses for Demonstrating Attainment 

of Air Quality Goals for Ozone, PM2.5, 

and Regional Haze (EPA–454/B–07– 

002), that Appendix W does not identify 

a particular modeling system as 

‘preferred’ for modeling conducted in 

support of state implementation plans 

under 40 CFR 51.308(b). A model 

should meet several general criteria for 

it to be a candidate for consideration. 

These general criteria are consistent 

with the requirements of 40 CFR 51.112 

and 40 CFR 51, Appendix W. Therefore, 

it is correct to interpret that no model 

system is considered ‘preferred’ under 

40 CFR 51, Appendix W, Section 3.1.1 

(b) for either secondary particulate 

matter or for visibility assessments. 

Under this general framework, we 

followed the general recommendation in 

Appendix Y to use CALPUFF as a 

screening technique since the modeling 

system has not been specifically 

approved for chemistry. The use of 

CALPUFF is subject to Appendix W 

requirements in section 3.0(b), 4, and 

6.2.1(e) which includes an approved 

protocol to use the current version. 

We and some states have used 

CALPUFF to model visibility benefits as 

part of the reasonable progress analysis, 

and have used largely the same 

methodology as in BART modeling (i.e. 

use of 24 hour or hourly maximum 

emissions, a ‘‘clean’’ background 

condition, and a maximum or 98th 

percentile metric).264 This approach 

provides information on the relative 

visibility benefits of controls to inform 

the evaluation of cost-effectiveness as 

part of the four factor analysis and has 

the benefit that it is immediately 

comparable to modeling used for BART 

determinations. Compared to a CAMx 

modeling exercise, CALPUFF modeling 

of one or more sources requires much 

less resources and time. However, the 

CALPUFF approach models the impacts 

from the single facility with limited 

chemistry and focuses on the maximum 

impacts from the source rather than the 

visibility impairment on the 20% worst 

days. We agree with the commenter that 

the CAMx model may be better suited 

for evaluating the average visibility 

impairment due to individual sources 

during the 20% worst days as part of 

reasonable progress analysis. 

Photochemical models, like the CAMx 

model, provide a complete 

representation of emissions, chemistry, 

transport, and deposition, while 

CALPUFF treats a single source with 

simplified chemistry and parameterized 

physical processes. Furthermore, the 


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265Texas Regional Haze FIP, EPA Response to 

Comments Document, available at 

www.regulations.gov, Document ID: EPA–R06– 

OAR–2014–0754–0087. 

266For example see summary of the reasonable 

progress analyses for specific sources in Arizona (79 

FR 9321, 9353), North Dakota (76 FR 58570, 58631 

(September 21, 2011)), Montana (77 FR 23988, 

24065 (April 20, 2012)), and Wyoming (78 FR 

34738, 34785 (June 10, 2013)). 

267See Summary of Additional Modeling for 

Entergy Independence and Appendix C to the TSD. 

268 ‘‘Most important, the simplified chemistry in 

the model tends to magnify the actual visibility 

effects of that source. Because of these features and 

the uncertainties associated with the model, we 

believe it is appropriate to use the 98th percentile— 

a more robust approach that does not give undue 

weight to the extreme tail of the distribution.’’ 

269 70 FR at 39123. 

CAMx model can be used to evaluate a 

large number of individual sources, and 

there are concerns in using CALPUFF 

for modeling impacts at distances much 

greater than 300 km from the source. In 

our analysis of source-specific impacts 

of Texas sources, we determined that 

CAMx was best suited for the complex 

analysis that we needed to perform in 

evaluating a large number of sources (38 

separate facilities for our initial 

analysis) at distances from impacted 

Class I areas much larger than 300km, 

and in focusing on the 20% worst days. 

We discuss our selection of CAMx 

modeling in our Texas analysis in depth 

in the RTC document that accompanies 

that action.265 As noted by EarthJustice, 

we did not perform a final CAMx model 

scenario to obtain the new RPGs in our 

Texas action, and instead relied on a 

scaling analysis similar to the 

methodology used in this action to 

adjust the CENRAP modeled RPG values 

based on the source apportionment data 

and emissions data available. As 

discussed above, RPGs were adjusted in 

actions in Arizona, Hawaii, Texas/

Oklahoma and in this action by 

estimating the visibility improvement 

due to required controls based on 

scaling the anticipated emission 

reductions and the source 

apportionment modeling. In Texas/

Oklahoma, source-specific source 

apportionment data and emissions were 

utilized. In the other states, emissions 

and source-apportionment data on a 

state and source category level were 

utilized. 

Consistent with the examples 

discussed above,266 in evaluating the 

sources in Arkansas, we determined that 

CALPUFF was adequate since we 

determined that only one source needed 

to be assessed for a reasonable progress 

evaluation, and that source was well 

within the recommended range for 

CALPUFF modeling of under 300km 

from the Class I areas of interest. In fact, 

three of the four impacted Class I areas 

lie within 200km of the source. We 

discuss comments concerning why our 

reasonable progress screening analysis 

focused on NOX and SO2 emissions 

from Arkansas point sources and our 

determination that additional analysis 

was necessary for the Independence 

facility in response to comments 

elsewhere in this document. In 

evaluating visibility impacts and 

benefits for those sources subject to 

BART, we relied on CALPUFF modeling 

prepared by the facilities. Utilizing 

CALPUFF for the reasonable progress 

analysis on Independence provided for 

a consistent approach for all facilities 

and allowed for direct comparison of 

the visibility impacts and benefits 

across all facilities impacted by the 

proposed rulemaking. In some 

situations, the CALPUFF modeled 

maximum or 98th percentile impacts of 

the facility may not coincide with the 

days that make up the worst 20% 

monitored days at the Class I area. 

Therefore, the visibility benefits 

modeled by CALPUFF are not directly 

comparable to the visibility benefits that 

would be anticipated on the 20% worst 

days from those specific controls. 

However, our analysis of the CENRAP 

2018 CAMx photochemical modeling 

showed that: On the 20% worst days, 

Arkansas point sources contribute 

significantly to visibility impairment at 

Arkansas’ Class I areas (greater than 4% 

of total visibility impairment at each 

Arkansas Class I area); review of the 

emission inventory revealed that a very 

small number of point sources are 

responsible for the majority of the point 

source emissions of NOX and SO2 and 

therefore a very small number of point 

sources are responsible for the portion 

of visibility impairment due to Arkansas 

point sources on the 20% worst days; 

and the Independence facility is one of 

the very largest emission sources and it 

is located relatively close (under 200 

km) to three Class I areas. Therefore, we 

identified Independence as having the 

greatest potential to impact visibility on 

the 20% worst days based on emissions 

and location and should be evaluated 

for reasonable progress controls. We 

determined that CALPUFF modeling 

was appropriate and sufficient to 

provide information on the degree of 

visibility benefits of controls on 

Independence to inform the reasonable 

progress assessment. Through our 

evaluation of the four statutory factors, 

we identified cost-effective controls. We 

then considered visibility benefits of the 

cost-effective controls. We conducted 

CALPUFF modeling to determine the 

level of visibility impacts and benefits 

anticipated by SO2 and NOX controls at 

nearby impacted Class I areas, 

evaluating the 98th percentile visibility 

impacts.267

As we discuss elsewhere in this final 

rule, Entergy submitted CAMx model 

results as part of their comments. The 

modeled contribution to visibility 

impairment due to baseline emissions 

from the Independence facility alone 

were approximately 1.3% of the total 

visibility impairment at each Arkansas 

Class I area. In terms of deciviews, the 

average impact over the 20% worst days 

based on Entergy’s CAMx modeling 

(adjusting to natural background 

conditions) is over 0.5 dv at the 

Arkansas Class I areas and even larger 

at the Class I areas in Missouri. These 

results estimate the visibility impacts 

from the source on the 20% worst days 

and confirm and provide additional 

support to our determination that 

Independence significantly impacts 

visibility, both in terms of maximum 

visibility impairment and visibility 

impairment on the 20% worst days, and 

that emissions controls provide for 

meaningful visibility benefits towards 

the goal of natural visibility conditions. 

In conclusion, both approaches, 

CALPUFF and CAMx, support the 

determination that the required controls 

are reasonable. 

The commenter cites the BART 

guidelines and asserts that EPA 

recognizes that the CALPUFF model is 

overly simplistic and overstates the 

effect of single-source emissions. This is 

not an accurate characterization. EPA 

recognized the uncertainty in the 

CALPUFF modeling results when EPA 

made the decision, in the final BART 

Guidelines, to recommend that the 

model be used to estimate the 98th 

percentile visibility impairment rather 

than the highest daily impact value. We 

made the decision to consider the less 

conservative 98th percentile primarily 

because the chemistry modules in the 

CALPUFF model are simplified and 

likely to provide conservative (higher) 

results for peak impacts. Since 

CALPUFF’s simplified chemistry could 

lead to model over predictions and thus 

be conservative, EPA decided to use the 

less conservative 98th percentile.268

While recognizing the limitations of the 

CALPUFF model in the preamble, EPA 

concluded that, for the specific 

purposes of the Regional Haze Rule’s 

BART provisions, CALPUFF is 

sufficiently reliable to inform the 

decision making process.269 More recent 

evaluations demonstrate that the 

CALPUFF model can both under-predict 

and over-predict visibility impacts. For 

example, the 2012 ENVIRON report on 


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270Comparison of Single-Source Air Quality 

Assessment Techniques for Ozone, PM2.5, other 

Criteria Pollutants and AQRVs, ENVIRON, 

September 2012. 

271Anderson, B., K. Baker, R. Morris, C. Emery, 

A. Hawkins, E. Snyder ‘‘Proof-of-Concept 

Evaluation of Use of Photochemical Grid Model 

Source Apportionment Techniques for Prevention 

of Significant Deterioration of Air Quality Analysis 

Requirements’’ Presentation for Community 

Modeling and Analysis System (CMAS) 2010 

Annual Conference, (October 11–15, 2010) can be 

found at http://www.cmascenter.org/conference/

2010/agenda.cfm. 

272 70 FR 39104, 39122. 

273 2007 EPA modeling Guidance for 

Demonstrating Attainment of Air Quality Goals for 

Ozone, PM2.5, and Regional Haze. 

274 Draft EPA modeling Guidance for 

Demonstrating Attainment of Air Quality Goals for 

Ozone, PM2.5, and Regional Haze (December 2014) 

Section 4.8 ‘‘What Is The Recommended Modeling 

Analysis for Regional Haze?’’ 

275 Draft EPA modeling Guidance for 

Demonstrating Attainment of Air Quality Goals for 

Ozone, PM2.5, and Regional Haze (December 2014) 

at 173: ‘‘The modeling can be used to determine the 

predicted improvement in visibility and whether 

the visibility levels are on, above, or below the 

glidepath. It cannot by itself determine the 

reasonable progress goals or determine whether the 

reasonable progress goal is met, and it does not 

satisfy the requirements for the statutory four factor 

analysis. See the Regional Haze Rule and related 

guidance documents for more information on the 

four factor analysis, including control strategy 

analysis for single sources.’’ 

276 80 FR 45340 (July 29, 2015). 

277 Interagency Workgroup on Air Quality 

Modeling Phase 3 Summary Report: Long Range 

Transport and Air Quality Related Values. 

278 80 CFR 45340, 45349: ‘‘In order to provide the 

user community flexibility in estimating singlesource secondary pollutant impacts and given the 

availability of more appropriate modeling 

techniques, such as photochemical transport 

models (which address limitations of models like 

CALPUFF [37]), the EPA is proposing that the 

Guideline no longer contain language that requires 

the use of CALPUFF or another Lagrangian puff 

model for long-range transport assessments. 

Additionally, the EPA is proposing to remove the 

CALPUFF modeling system as an EPA-preferred 

model for long-range transport due to concerns 

about the management and maintenance of the 

model code given the frequent change in ownership 

of the model code since promulgation in the 

previous version of the Guideline. [38] The EPA 

recognizes that long-range transport assessments 

may be necessary in certain limited situations for 

PSD increment. For these situations, the EPA is 

proposing a screening approach where CALPUFF 

along with other appropriate screening tools and 

methods may be used to support long-range 

transport PSD increment assessments’’ 

279 80 FR at 45349. 

280 Interagency Workgroup on Air Quality 

Modeling Phase 3 Summary Report: Long Range 

Transport and Air Quality Related Values (July 

2015). 

281 IWAQM Phase 3 Report (July 2015) at 9: ‘‘In 

sum, the differences in the types of models, the 

inputs to the models, and how the models and 

model results are used means that the results from 

a BART determination or similar modeling using 

CALPUFF cannot be directly compared to estimated 

impacts of emissions controls from a single source 

on a reasonable progress goal. If recommended 

Continued 

Comparison of Single-Source Air 

Quality Assessment Techniques for 

Ozone, PM2.5, other criteria pollutants 

and AQRVs found that CALPUFF 

predicted highest 24-hr nitrate and 

sulfate concentrations lower than those 

predicted by the CAMx photochemical 

grid model in some areas within the 

modeling domain.270 In a presentation 

for the 2010 annual Community 

Modeling and Analysis System 

conference, Anderson et al. (2010) 271

found that the CALPUFF model 

frequently predicted lower nitrate 

concentrations compared to the CAMx 

photochemical grid model which has a 

much more rigorous treatment of 

photochemical reactions. As we stated 

in promulgating the BART Guidelines, 

we are confident that CALPUFF 

distinguishes, comparatively, the 

relative contributions from sources such 

that the differences in source 

configurations, sizes, emission rates, 

and visibility impacts are well-reflected 

in the model results.272

With regard to comments concerning 

the draft EPA modeling Guidance for 

Demonstrating Attainment of Air 

Quality Goals for Ozone, PM2.5, and 

Regional Haze (Dec. 2014), the 

commenter confuses the single-source 

analysis to evaluate visibility impacts 

and benefits of controls on an 

individual source with the analysis of 

overall visibility conditions at a Class I 

area due to the complete emission 

control strategy for all sources 

developed under the reasonable 

progress and long-term strategy 

requirements. The draft modeling 

guidance (as does the current 

guidance 273) discusses the projection of 

overall visibility conditions and the 

need for photochemical grid modeling 

to account for all emission sources to 

model current visibility conditions and 

project future visibility conditions in 

response to the overall emission control 

scenarios. The section of the modeling 

guidance on regional haze 274 describes 

the recommended modeling analysis to 

assess overall future visibility 

improvement relative to the uniform 

rate of progress or ‘‘glidepath’’ (for each 

Class I area) as part of a reasonable 

progress analysis, and does not discuss 

source-specific analyses that may be 

completed to inform a reasonable 

progress assessment.275 Because the 

CALPUFF model only evaluates 

visibility impacts from a single-source 

or a limited group of sources, it is not 

capable of projecting overall visibility 

conditions due to all sources and 

controls. Consistent with this draft 

guidance and the current guidance, 

CENRAP and Arkansas utilized CAMx 

and CMAQ modeling to project future 

visibility conditions for 2018 for 

establishment of the RPGs and 

comparison with the URP. Similarly, we 

utilized the CENRAP CAMx model 

results and adjusted them based on 

source apportionment and emissions 

data, to estimate the new RPGs for the 

Arkansas Class I areas considering the 

anticipated changes in emissions due to 

all required controls. We discuss the 

selection of models for assessing 

individual visibility impacts and 

benefits of controls above. 

The commenters cite to the proposed 

revisions to the Guideline on Air 

Quality Models (Appendix W) 276 and 

the IWAQM Phase 3 modeling report 277

and assert that they support the 

conclusion that the use of CALPUFF for 

Independence was inappropriate. We 

disagree with the commenter. As we 

discuss above, we agree with the 

commenter that the CAMx model, may 

be better suited for a reasonable progress 

analysis in certain situations. Proposed 

revisions to Appendix W discuss 

removing the requirement to use 

CALPUFF for long-range transport 

assessments and as a preferred model 

due to the need to provide flexibility in 

estimating single-source secondary 

pollutant impacts and concerns about 

management and maintenance of the 

CALPUFF modeling code.278 These 

proposed changes do not affect EPA’s 

recommendation that States use 

CALPUFF to determine the applicability 

and level of BART in regional haze 

implementation plans. The proposed 

changes also do not preclude the use of 

CALPUFF for any other non-BART 

analysis, such as long-range transport 

PSD increment assessment, but 

recognize that modern chemical 

transport models have evolved 

sufficiently and provide a credible 

platform for estimating potential 

visibility impacts from a single or small 

group of emission sources.279 The 

proposed Appendix W rule simply 

proposes to remove CALPUFF as a 

preferred model. If the proposed 

changes are finalized, CALPUFF or any 

other model can still be used for nonBART analyses with the appropriate 

justification as an ‘‘alternative model’’. 

The IWAQM Phase 3 modeling 

report 280 discusses in detail the 

difference between the CALPUFF 

analysis typically followed under BART 

and the use of photochemical grid 

models for assessing reasonable progress 

and overall visibility conditions. The 

report does not identify a preferred 

model for single-source analysis but 

rather identifies the difference between 

the modeling approaches and cautions 

that the model results are not directly 

comparable.281 The report also states 


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procedures change for either BART determination 

impact assessments or reasonable progress goal 

impact assessments the comparability between 

approaches would also change. Photochemical grid 

models could be applied to estimate single source 

impacts and post-processed in a manner consistent 

with requirements for a BART-like assessment but 

Lagrangian puff models are not ideal for reasonable 

progress demonstrations since they typically 

characterize one or a small group of sources’’ 

282Coincidentally, the EPA Administrator on July 

14, 2015, signed a proposed notice to remove 

CALPUFF as a model for long-range transport in 

EPA’s Guideline on Air Quality Models in Docket 

No. EPA–HQ–OAR–2015–0310. 

283See Exhibit 19 to Nucor’s comments, 

Hoffnagle, G., ‘‘Accuracy of Visibility Protocol 

Modeling in BART Evaluations’’ (June 15, 2012); 

EPA Docket EPA–R08–OAR–2011–0851. 

284See, McNider, R. ‘‘Inadequacy of CALPUFF 

and CALMET Protocols for Visibility Impact 

Analysis in the Arkansas RHR FIP,’’ July 13, 2015, 

attached hereto as Exhibit 20 to Nucor’s comments. 

285Hoffnagle, Exhibit 19 at p. 4. 

286Hoffnagle, Exhibit 19 at p. 23. 

287 70 FR 39104, 39123. 

288As well as the other sources that were 

modeled using CALPUFF. 

289 70 FR at 39123, 39124. ‘‘We understand the 

concerns of commenters that the chemistry modules 

of the CALPUFF model are less advanced than 

some of the more recent atmospheric chemistry 

simulations. To date, no other modeling 

applications with updated chemistry have been 

approved by EPA to estimate single source 

pollutant concentrations from long range 

that puff-models, such as CALPUFF, are 

not suited for reasonable progress 

demonstrations assessing overall 

visibility conditions and improvement 

because they are only able to model a 

single or small group of sources. 

Accordingly, we utilized CAMx model 

results to project overall future visibility 

conditions and establish the new RPGs 

in our reasonable progress 

demonstration. We used CALPUFF 

visibility modeling along with our 

evaluation of the costs of controls to 

inform our decision on the 

reasonableness of controls at the 

Independence facility. We also used 

CALPUFF visibility modeling as only 

one factor to inform our decisions on 

BART for subject-to-BART facilities. We 

also note that both the proposed 

revisions and the IWAQM report were 

published after the proposed rule for 

Arkansas regional haze was published 

and well before the technical analysis 

and modeling were completed. 

We address comments concerning the 

contribution to visibility impairment 

from Arkansas point sources and the 

benefit of controls on Independence on 

Arkansas Class I areas elsewhere. We 

find that the contribution to visibility 

impairment from Arkansas point 

sources to be significant and that 

controls on Independence will result in 

meaningful visibility improvements 

towards the goal of natural visibility 

conditions and addresses a significant 

portion of the visibility impairment due 

to Arkansas sources. 

Comment: Use of CALPUFF modeling 

does not support EPA’s determination to 

require controls at the three coal-fired 

power plants. EPA’s reliance on 

CALPUFF modeling results to make 

regulatory decisions in this case is not 

justified due to CALPUFF’s well-known 

overestimation of visibility impacts.282

Under the circumstances here, it is 

highly likely that CALPUFF 

overestimated the visibility impacts of 

White Bluff, Flint Creek and 

Independence by at least five (5) times. 

One component of this overestimation is 

the failure to incorporate the puff 

splitting option within the CALPUFF 

model into the development of visibility 

results. CALPUFF’s overestimation of 

visibility impacts by a factor of 2–10 

times under similar circumstances has 

been previously identified 283 and is 

described with specific reference to 

EPA’s Proposed FIP for Arkansas in a 

report by Dr. Richard T. McNider.284 Dr. 

McNider’s report explains that the 

CALPUFF protocols used in the 

Proposed FIP fail to account for several 

well-known meteorological phenomena 

and processes, and causes it to 

overestimate visibility impacts. The 

Hoffnagle report demonstrates that 

CALPUFF modeling has not been 

validated by real world observations 

and that the current regulatory version 

of CALPUFF used by EPA is 

outdated.285 Consequently, CALPUFF is 

not ‘‘sufficiently accurate to make 

determinations of deciview differences 

of 1 deciview.’’ 286

It is inappropriate to utilize CALPUFF 

as a screening tool to qualify a source 

as subject to BART and subsequently 

use it to determine a facility’s required 

implementation of a control technology 

at a significant financial cost. EPA in its 

final regional haze rules stated that 

‘‘because of the scale of the predicted 

impacts from these sources, CALPUFF 

is an appropriate or a reasonable 

application to determine whether such 

a facility can reasonably be anticipated 

to cause or contribute to any 

impairment of visibility. In other words, 

to find that a source with a predicted 

maximum impact greater than 2 to 3 

deciviews meets the contribution 

threshold adopted by the States does not 

require the degree of certainty in the 

results of the model that might be 

required for other regulatory 

purposes.’’ 287

EPA’s visibility analysis in the 

Proposed FIP systematically overstates 

both the baseline visibility impacts of 

White Bluff, Flint Creek and 

Independence, and the visibility 

benefits that would result from 

installation of EPA’s required 

controls.288 EPA’s Proposed FIP 

presumes greater accuracy and precision 

than is reasonable or that may be 

expected from CALPUFF under the 

circumstances here. EPA has failed to 

update its model or to address any of 

these deficiencies considering currently 

available state-of-the-art modeling 

science. EPA’s consideration of 

visibility impacts is fundamentally 

flawed and should be withdrawn and 

corrected. 

EPA’s admission that CALPUFF is a 

reasonable tool to evaluate a facility’s 

visibility impacts only if those impacts 

exceed 2 to 3 deciviews, combined with 

the inability of the model to make 

accurate determinations below the 1 

deciview threshold of perceptibility, 

discredits the results of the visibility 

analyses in the Proposed FIP. For these 

reasons, EPA has not adequately 

explained how the baseline and 

subsequent controlled visibility 

analyses in the Proposed FIP justify the 

selected control technologies. 

Response: In promulgating the 2005 

BART guidelines, we responded to 

comments concerning the limitations 

and appropriateness of using CALPUFF. 

There we respond: 

CALPUFF is the best modeling application 

available for predicting a single source’s 

contribution to visibility impairment. It is the 

only EPA-approved model for use in 

estimating single source pollutant 

concentrations resulting from the long range 

transport of primary pollutants. In addition, 

it can also be used for some purposes, such 

as the visibility assessments addressed in 

today’s rule, to account for the chemical 

transformation of SO2 and NOX. As explained 

above, simulating the effect of precursor 

pollutant emissions on PM2.5 concentrations 

requires air quality modeling that not only 

addresses transport and diffusion, but also 

chemical transformations. CALPUFF 

incorporates algorithms for predicting both. 

At a minimum, CALPUFF can be used to 

estimate the relative impacts of BARTeligible sources. We are confident that 

CALPUFF distinguishes, comparatively, the 

relative contributions from sources such that 

the differences in source configurations, 

sizes, emission rates, and visibility impacts 

are well-reflected in the model results. 

The use of CALPUFF in the context of 

the Regional Haze rule provides results 

that can be used in a relative manner 

and are only one factor in the overall 

BART determination. We determined 

the visibility results from CALPUFF 

could be used as one of the five factors 

in a BART evaluation and the impacts 

should be utilized somewhat in a 

relative sense because CALPUFF was 

not explicitly approved for full 

chemistry calculations.289


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transport.’’ and in discussion of using other models 

with more advanced chemistry it continues, ‘‘A 

discussion of the use of alternative models is given 

in the Guideline on Air Quality in appendix W, 

section 3.2.’’ 

290 70 FR at 39123. 

291 70 FR at 39123. 

292 70 FR at 39123. 

293 ‘‘Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program,’’ June 1, 

2007. 

294As we explain in our proposed action (80 FR 

at 18993): ‘‘While visibility is not an explicitly 

listed factor to consider when determining whether 

additional controls are reasonable under the 

reasonable progress requirements, the purpose of 

the four-factor analysis is to determine what degree 

of progress toward natural visibility conditions is 

reasonable. Therefore, it is appropriate to consider 

the projected visibility benefit of the controls when 

determining if the controls are needed to make 

reasonable progress’’. See 79 FR at 74838, 74840, 

and 74874. 

295App. W, Section 7.2.9(a) ‘‘. . . Therefore, 

model calibration is unacceptable.’’ 

296 70 FR at 39123. 

297CALPUFF contains an optional puff splitting 

algorithm that can further account for vertical wind 

shear effects across individual puffs when this is of 

specific concern. Dispersion and transport can act 

on separate puffs generated from the original puff. 

This option is not part of the regulatory default setup. 

298See CALPUFF_SJGS_SPLIT_summary.xls. 

299On December 4, 2013, EPA approved an 

update to v5.8.4 that contains bug fixes to the 

previous version. See December 3, 2013 CALPUFF 

Update Memo for a discussion of model changes. 

300 80 CFR at 45349: ‘‘In order to provide the user 

community flexibility in estimating single-source 

secondary pollutant impacts and given the 

availability of more appropriate modeling 

Continued 

EPA’s modeling in this action was 

consistent with the BART Guidelines 

and Appendix W. In recommending the 

use of CALPUFF for assessing source 

specific visibility impacts, EPA 

recognized that the model had certain 

limitations but concluded that ‘‘[f]or 

purposes of the regional haze rule’s 

BART provisions . . . CALPUFF is 

sufficiently reliable to inform the 

decision-making process.’’ 290 To the 

extent that the comment takes issue 

with the provisions in the BART 

Guidelines for use of CALPUFF, the 

legal deadline for challenging the use of 

CALPUFF has passed. 

The commenters also refer to the 2005 

Rule where we discuss the use of 

CALPUFF as a screening tool to qualify 

a source as subject to BART291 and 

claim that we state that CALPUFF is 

only a reasonable tool when impacts 

exceed 2 to 3 deciviews. This is 

incorrect. The commenters fail to note 

that later in that same section we also 

discuss the recommended use of 

CALPUFF to evaluate visibility benefits 

of controls. There we state: 

‘‘. . . we also recommend that the States use 

CALPUFF as a screening application in 

estimating the degree of visibility 

improvement that may reasonably be 

expected from controlling a single source in 

order to inform the BART determination. As 

we noted in 2004, this estimate of visibility 

improvement does not by itself dictate the 

level of control a State would impose on a 

source; ‘‘the degree of improvement in 

visibility which may reasonably be 

anticipated to result from the use of [BART]’’ 

is only one of five criteria that the State must 

consider together in making a BART 

determination.’’ 292

With respect to our analysis of 

controls under reasonable progress, we 

rely on our Reasonable Progress 

Guidance.293 Our Reasonable Progress 

Guidance notes the similarity between 

some of the reasonable progress 4 

statutory factors and the BART 5 

statutory factors contained in the Act 

and repeated in the Guidance, and 

suggests that the BART Guidelines be 

consulted regarding cost, energy and 

nonair quality environmental impacts, 

and remaining useful life. We are 

therefore relying on our BART 

Guidelines for assistance in interpreting 

those reasonable progress factors, as 

applicable. 

Also, similar to a BART analysis, we 

are considering the projected visibility 

benefit in our reasonable progress 

analysis following the BART guidelines 

and the use of CALPUFF.294 We rely on 

the BART Guidelines here and in other 

actions evaluating reasonable progress 

controls because they provide a 

reasonable and consistent approach 

regarding visibility modeling. 

We also disagree with the commenters 

conclusions concerning CALPUFF 

model performance and assertions that 

model predictions are overestimated by 

a factor of 5. We note that our 

regulations do not allow for the 

calibration of model results to try to 

adjust for potential biases as suggested 

by the commenter.295

As discussed more fully in the RTC 

document, the CALPUFF model can 

both under-predict and over-predict 

visibility impacts. While recognizing the 

limitations of the CALPUFF model in 

the Preamble of the Regional Haze Rule 

EPA concluded that, for the specific 

purposes of the Regional Haze Rule’s 

BART provisions, CALPUFF is 

sufficiently reliable to inform the 

decision making process.296

We disagree with the commenter’s 

assertion that we were incorrect in not 

utilizing the puff-splitting option 297 and 

that this resulted in an overestimation of 

model results. Tests conducted by the 

EPA and the FLM’s have shown that the 

CALPUFF puff-splitting algorithm does 

not behave in the manner posited in Dr. 

McNider’s document.298 As discussed 

in detail in the RTC document, multiple 

evaluations of puff-splitting show that 

visibility impacts (and thus 

concentrations) both increased and 

decreased across various Class I areas 

impacted by the source. These results 

are contrary to the claims of the 

commenter that CALPUFF overpredicts 

downwind concentrations at distances 

beyond 100 km and that the use of puffsplitting would result in lower 

concentrations. Furthermore, 

commenters have not provided any 

additional CALPUFF modeling to 

support their claims concerning model 

performance using the non-default puff 

splitting option. 

The commenter refers to the Hoffnagle 

report (Ex. 19 of Nucor comments) to 

support claims that the CALPUFF 

model overpredicts concentrations, that 

the model is unreliable beyond 200km, 

and that the modeling is not sufficiently 

accurate to make determinations of 

deciview differences of 1 dv. We 

disagree with the conclusions of the 

Hoffnagle report and note significant 

flaws in that analysis. We also note that 

all the large EGU sources modeled in 

this action are less than 200 km for at 

least one Class I area. We specifically 

address Hoffnagle’s analysis of modeled 

to measured results in response to 

comments elsewhere where we address 

comments concerning the ‘‘margin of 

error’’ of the model and case study 

comparisons of CALPUFF modeled 

values to measured values. 

We disagree with the commenter that 

the model we utilized is outdated. We 

used the regulatory version of the 

CALPUFF model.299 We disagree that 

the newer versions of CALPUFF should 

be used in this action to determine 

potential visibility impacts. The newer 

version(s) of CALPUFF have not 

received the level of review required for 

use in regulatory actions subject to EPA 

approval and consideration in a BART 

decision making process. Based on our 

review of the available evidence we do 

not consider these newer versions of 

CALPUFF to have been shown to be 

sufficiently documented, technically 

valid, and reliable for use in a BART 

decision making process. 

The commenters also refer to the 

proposed revisions to the Guideline on 

Air Quality Models (Appendix W). 

Proposed revisions to Appendix W 

discuss removing the requirement to use 

CALPUFF for long-range transport 

assessments and as a preferred model 

due to the need to provide flexibility in 

estimating single-source secondary 

pollutant impacts and concerns about 

management and maintenance of the 

CALPUFF modeling code.300 These 


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techniques, such as photochemical transport 

models (which address limitations of models like 

CALPUFF [37]), the EPA is proposing that the 

Guideline no longer contain language that requires 

the use of CALPUFF or another Lagrangian puff 

model for long-range transport assessments. 

Additionally, the EPA is proposing to remove the 

CALPUFF modeling system as an EPA-preferred 

model for long-range transport due to concerns 

about the management and maintenance of the 

model code given the frequent change in ownership 

of the model code since promulgation in the 

previous version of the Guideline. [38] The EPA 

recognizes that long-range transport assessments 

may be necessary in certain limited situations for 

PSD increment. For these situations, the EPA is 

proposing a screening approach where CALPUFF 

along with other appropriate screening tools and 

methods may be used to support long-range 

transport PSD increment assessments.’’ 

301CAA section 169A(g)(2). 

302 80 FR at 18968. 

303 ‘‘Concurring, Judge Berzon wrote separately to 

emphasize her understanding that the lead opinion 

is not impugning the EPA’s use of the CALPUFF 

model generally, but only requiring a sufficiently 

reasoned response to a particular comment 

regarding CALPUFF’s usefulness in these specific 

circumstances.’’ Nat’l Parks Conservation Ass’n vs. 

EPA. 

304Am. Corn Growers Ass’n v. EPA, 291 F.3d 1 

(D.C. Cir. 2002). 

305 70 FR at 39121. 

306See ‘‘more recent series of comparisons has 

been completed for a new model, CALPUFF 

(Section A.3). Several of these field studies 

involved three-to-four hour releases of tracer gas 

sampled along arcs of receptors at distances greater 

than 50km downwind. In some cases, short-term 

concentration sampling was available, such that the 

transport of the tracer puff as it passed the arc could 

be monitored. Differences on the order of 10 to 20 

degrees were found between the location of the 

simulated and observed center of mass of the tracer 

puff. Most of the simulated centerline concentration 

maxima along each arc were within a factor of two 

of those observed.’’ 68 FR 18440, 18458 (April 15, 

2003), 2003 Revisions to Appendix W, Guideline on 

Air Quality Models 

307 Interagency Workgroup on Air Quality 

Modeling (IWAQM) Phase 2 Summary Report and 

Recommendations for Modeling Long-Range 

Transport Impacts. Publication No. EPA–454/R–98– 

019. Office of Air Quality Planning & Standards, 

Research Triangle Park, NC. 1998. 

308 68 FR 18440, 18458, 2003 Revisions to 

Appendix W, Guideline on Air Quality Models. 

proposed changes do not affect EPA’s 

recommendation that States use 

CALPUFF to determine the applicability 

and level of BART in regional haze 

implementation plans. The proposed 

changes also do not preclude the use of 

CALPUFF for any other non-BART 

analysis. The proposed changes to the 

Appendix W rule simply propose to 

remove CALPUFF as a preferred model 

for long-range transport assessments. If 

the proposed changes are finalized, 

CALPUFF or any other model can still 

be used with the appropriate 

justification as an ‘‘alternative model’’ 

for long-range transport assessments. 

Finally, the CAMx modeling provided 

by Entergy Arkansas provides additional 

information that directly contradicts the 

commenter’s assertion that CALPUFF 

greatly overestimates visibility impacts 

by at least a factor of 5. As we discuss 

elsewhere in this final rule, the CAMx 

visibility modeling estimates a 

maximum visibility impact (limited to 

only the days comprising the 20% worst 

days and based on annual emissions) of 

over 1.5 dv from the Independence 

facility at both Caney Creek and Upper 

Buffalo. For the White Bluff facility, the 

CAMx maximum visibility impact is 

approximately 3.5 dv at Caney Creek 

and 0.8 dv at Upper Buffalo. In some 

situations, the CALPUFF modeled 

maximum or 98th percentile impacts of 

the facility may not coincide with the 

days that make up the worst 20% 

monitored days at the Class I area, 

therefore the true maximum impact 

considering all days based on CAMx 

modeling could be even higher. This 

compares to a CALPUFF modeled 

visibility 98th percentile impact (based 

on maximum emissions) due to the 

Independence facility of 2.5 dv at Caney 

Creek and 2.3 at Upper Buffalo. For 

White Bluff, the CALPUFF modeled 

impact (98th percentile) is 

approximately 3.3 dv at Caney Creek 

and 2.3 dv at Upper Buffalo. 

We address more general comments 

concerning the use of CALPUFF 

modeling and model uncertainty in 

separate response to comments. 

4. Margin of Error in CALPUFF 

Modeling 

Comment: Commenters stated that 

BART requires that states (or EPA in the 

case of a federal implementation plan) 

consider ‘‘the degree of improvement in 

visibility which may reasonably be 

anticipated to result from the use of 

such technology.’’ 301 The Ninth Circuit, 

in National Parks Conservation 

Association v. EPA, Case No. 12–73710, 

2015 WL 3559149 at 8 (9th Cir. June 9, 

2015), held that the estimated visibility 

improvement was less than CALPUFF’s 

margin of error, and thus, EPA had no 

basis to believe that BART controls in 

that case could ‘‘reasonably be 

anticipated’’ to improve visibility. The 

Clean Air Act does not require visibility 

improvements that cannot be reasonable 

anticipated. Visibility improvements 

that are less than the margin of error are 

not ‘‘reasonably anticipated’’ and found 

to be invalid by the Ninth Circuit in 

National Parks Conservation 

Association.302 In the proposal, EPA 

dictates the imposition of control 

equipment for emissions reduction 

under BART in instances where 

CALPUFF predicted minor visibility 

improvements. EPA did so without first 

undertaking any site specific analytical 

analysis to determine if the visibility 

improvements were in fact within the 

CALPUFF margin of error. 

The CAA does not require visibility 

improvements that cannot be reasonably 

anticipated. Conversely, visibility 

improvements that are less than the 

margin of error were expressly found to 

be invalid. Until such time as EPA can 

provide assurance that the CALPUFF 

model is a reliable indicator of visibility 

projections, many of the numerical 

projections contained in the Proposed 

FIP are themselves, unreliable. For this 

reason, the Proposed FIP is flawed and 

is overly expansive and should be 

withdrawn. 

Response: We disagree with the 

commenter’s characterization of the 

Ninth Circuit decision regarding the 

‘‘margin of error’’ of the CALPUFF 

model. The Ninth Circuit decision cited 

did not rule on any specific issue 

related to CALPUFF or the ‘‘margin of 

error.’’ Rather, the court ruled on a 

procedural error that EPA did not 

respond to the comment received 

regarding the CALPUFF margin of error 

in its rulemaking as required under the 

law.303

In response to the court’s finding in 

American Corn Growers Ass’n. v. EPA 304 that we failed to provide an option 

for BART evaluations on an individual 

source-by-source basis, we had to 

identify the appropriate analytical tools 

to estimate single-source visibility 

impacts. The 2005 BART Guidelines 

recommended the use of CALPUFF for 

assessing visibility (secondary chemical 

impacts) but noted that CALPUFF’s 

chemistry was fairly simple and the 

model has not been fully tested for 

secondary formation and thus is not 

fully approved for secondary-formed 

particulate. In the preamble of the final 

2005 BART guidelines we identify 

CALPUFF as the best available tool for 

analyzing the visibility effects of 

individual sources, but we also 

recognized that it is a model that 

includes certain assumptions and 

uncertainties.305 Evaluation of 

CALPUFF model performance for 

dispersion (no chemistry) to case 

studies using inert tracers has been 

performed.306 It was concluded from 

these case studies the CALPUFF 

dispersion model had performed in a 

reasonable manner, and had no 

apparent bias toward over or under 

prediction, so long as the transport 

distance was limited to less than 

300km.307 308

In promulgating the 2005 BART 

guidelines, we responded to comments 

concerning the limitations and 


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309 68 FR 18440. 

310 70 FR at 39123, 39124. ‘‘We understand the 

concerns of commenters that the chemistry modules 

of the CALPUFF model are less advanced than 

some of the more recent atmospheric chemistry 

simulations. To date, no other modeling 

applications with updated chemistry have been 

approved by EPA to estimate single source 

pollutant concentrations from long range 

transport,’’ and in discussion of using other models 

with more advanced chemistry it continues, ‘‘A 

discussion of the use of alternative models is given 

in the Guideline on Air Quality in appendix W, 

section 3.2.’’ 

311 ‘‘Most important, the simplified chemistry in 

the model tends to magnify the actual visibility 

effects of that source. Because of these features and 

the uncertainties associated with the model, we 

believe it is appropriate to use the 98th percentile— 

a more robust approach that does not give undue 

weight to the extreme tail of the distribution.’’ 70 

FR 39104, 39121. 

312See figures for Lake Catherine and Domtar in 

our response to comments on the ‘‘Margin of Error’’ 

analysis in the RTC document 

313Comparison of Single-Source Air Quality 

Assessment Techniques for Ozone, PM2.5, other 

Criteria Pollutants and AQRVs, ENVIRON, 

September 2012. 

314Anderson, B., K. Baker, R. Morris, C. Emery, 

A. Hawkins, E. Snyder ‘‘Proof-of-Concept 

Evaluation of Use of Photochemical Grid Model 

Source Apportionment Techniques for Prevention 

of Significant Deterioration of Air Quality Analysis 

Requirements’’ Presentation for Community 

Modeling and Analysis System (CMAS) 2010 

Annual Conference, (October 11–15, 2010) can be 

found at http://www.cmascenter.org/conference/

2010/agenda.cfm. 

315 68 FR at 18458, 2003 Revisions to Appendix 

W, Guideline on Air Quality Models. 

316 70 FR at 39129, ‘‘We believe the maximum 

24hour modeled impact can be an appropriate 

measure in determining the degree of visibility 

improvement expected from BART reductions (or 

for BART applicability)’’ 

317 70 FR 39104, 39107–3918 of BART Rule. For 

assessing the fifth factor, the degree of improvement 

in visibility from various BART control options, the 

States may run CALPUFF or another appropriate 

dispersion model to predict visibility impacts. 

Scenarios would be run for the pre-controlled and 

post-controlled emission rates for each of the BART 

control options under review. The maximum 24- 

hour emission rates would be modeled for a period 

of three or five years of meteorological data. 

appropriateness of using CALPUFF. 

There we respond: 

CALPUFF is the best modeling application 

available for predicting a single source’s 

contribution to visibility impairment. It is the 

only EPA-approved model for use in 

estimating single source pollutant 

concentrations resulting from the long range 

transport of primary pollutants. In addition, 

it can also be used for some purposes, such 

as the visibility assessments addressed in 

today’s rule, to account for the chemical 

transformation of SO2 and NOX. As explained 

above, simulating the effect of precursor 

pollutant emissions on PM2.5 concentrations 

requires air quality modeling that not only 

addresses transport and diffusion, but also 

chemical transformations. CALPUFF 

incorporates algorithms for predicting both. 

At a minimum, CALPUFF can be used to 

estimate the relative impacts of BARTeligible sources. We are confident that 

CALPUFF distinguishes, comparatively, the 

relative contributions from sources such that 

the differences in source configurations, 

sizes, emission rates, and visibility impacts 

are well-reflected in the model results. 

In the 2003 revisions to the Guideline 

on Air Quality Models, CALPUFF was 

added as an approved model for longrange transport of primary pollutants. At 

that time, we considered approving 

CALPUFF for assessing the impact from 

secondary pollutants but determined 

that it was not appropriate in the 

context of a PSD review because the 

impact results could be used as the sole 

determinant in denying a permit.309

However, the use of CALPUFF in the 

context of the Regional Haze rule 

provides results that can be used in a 

relative manner and are only one factor 

in the overall BART determination. We 

determined the visibility results from 

CALPUFF could be used as one of the 

five factors in a BART evaluation and 

the impacts should be utilized 

somewhat in a relative sense because 

CALPUFF was not explicitly approved 

for full chemistry calculations.310

We also recognized the uncertainty in 

the CALPUFF modeling results when 

we made the decision, in the final BART 

Guidelines, to recommend that the 

model be used to estimate the 98th 

percentile visibility impairment rather 

than the highest daily impact value. We 

made the decision to consider the less 

conservative 98th percentile primarily 

because the chemistry modules in the 

CALPUFF model are simplified and 

likely to provide conservative (higher) 

results for peak impacts. Since 

CALPUFF’s simplified chemistry could 

lead to model over predictions and thus 

be conservative, EPA decided to use the 

less conservative 98th percentile.311

Examining the distribution of CALPUFF 

modeled visibility impacts, it can be 

seen that the few values at the extreme 

of the distribution are much higher than 

the rest of the values.312 Therefore, in 

recognizing some of the limitations of 

the CALPUFF model, we determined 

that use of the maximum modeled 

impact may be overly conservative and 

recommended the use of the 98th 

percentile value. 

We disagree with the commenter’s 

general statement that there is an 

acknowledged over-prediction of the 

CALPUFF model or an acknowledged 

inaccuracy at low levels, and that the 

actual visibility impacts from the BART 

sources are lower. The CALPUFF model 

can both under-predict and over-predict 

visibility impacts when compared to 

photochemical grid model. For example, 

the 2012 ENVIRON report on 

Comparison of Single-Source Air 

Quality Assessment Techniques for 

Ozone, PM2.5, other criteria pollutants 

and AQRVs found that CALPUFF 

predicted highest 24-hr nitrate and 

sulfate concentrations lower than those 

predicted by the CAMx photochemical 

grid model in some areas within the 

modeling domain.313 In a presentation 

for the 2010 annual Community 

Modeling and Analysis System 

conference, Anderson et al. (2010) 314

found that the CALPUFF model 

frequently predicted lower nitrate 

concentrations compared to the CAMx 

photochemical grid model, which has a 

much more rigorous treatment of 

photochemical reactions. As discussed 

above, model evaluations examining 

how the model captures the transport 

and diffusion of pollutants showed that 

the model performed in a reasonable 

manner for modelled distances less than 

300 km.315 The selection of the 98th 

percentile value rather than the 

maximum value was made to address 

concerns that the maximum may be 

overly conservative. 

The CALPUFF modeling following 

the BART guidelines and using the 98th 

percentile value does not lend itself to 

model performance evaluations of the 

type suggested by the commenters (see 

comments below concerning the 

‘‘Margin of error’’ analysis), comparing 

measured visibility impairment at a 

specific time and place to modeled 

impairment at that same time and place 

to derive some ‘‘margin of error’’ in the 

modeled estimates. The BART modeling 

is a worst case assessment, utilizing 

maximum emissions,316 assumptions of 

background ammonia and ozone, and 

simplified chemistry, modeled over a 

period of three years.317 The modeling 

also does not capture the effect of 

competition with other emission 

sources for the available ammonia. The 

goal of this modeling is to estimate the 

maximum anticipated impact from the 

source in the vicinity of a Class I area 

(typically an area on the order of several 

hundred square miles or more), and not 

to provide an estimate of downwind 

concentrations or visibility conditions 

for a specific place at a specific time. 

CALPUFF uses a pseudo-first-order 

chemical reaction mechanism to model 

the conversion of SO2 to SO4 and NOX

(NO + NO2) to NO3. We find the 

representation of key chemical 

conversions of precursors to PM2.5 in 

CALPUFF are appropriate for estimating 

a worst-case scenario for this particular 

source and region. We note that small 

changes in emission levels will not 

significantly perturb the available 

ammonia. Therefore, the relative 

difference between two scenarios with 

similar emissions will not be overly 


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318 ‘‘Evaluation of the CALPUFF Modeling 

System Margin of Error Report for BART Analysis, 

Domtar A. W. LLC, Ashdown Mill’’ Prepared by 

Trinity Consultants, August 2015 and ‘‘Evaluation 

of the CALPUFF Modeling System Margin of Error 

Report for BART Analysis, Entergy Arkansas, Inc., 

Lake Catherine Plant’’ Prepared by Trinity 

Consultants, August 2015. 

319CAA section 169A(g)(2); see NPCA, 788 F.3d 

1134, 1146–47. 

320 Gale F. Hoffnagle, Accuracy of Visibility 

Protocol Modeling in BART Evaluations, TRC 

Environmental Corporation, June 15, 2012. 

321National Parks Conservation Ass’n v. EPA, 

788 F.3d 1134, 1146–47 (9th Cir. 2015). 

322 ‘‘Concurring, Judge Berzon wrote separately to 

emphasize her understanding that the lead opinion 

is not impugning the EPA’s use of the CALPUFF 

model generally, but only requiring a sufficiently 

reasoned response to a particular comment 

regarding CALPUFF’s usefulness in these specific 

circumstances.’’ Nat’l Parks Conservation Ass’n vs. 

EPA. 

influenced by assumptions of 

background concentrations of ammonia. 

The utility of the model used must be 

judged based on the available data, the 

known limitations or simplifications 

inherent to the model, and the purpose 

of the modeling or manner in which the 

model results are used in informing 

decisions. The use of the 98th percentile 

value and considering a minimum of 

three years of meteorological data 

within CALPUFF provides a snapshot of 

the worst case visibility impacts, 

simulating impacts (based on maximum 

emissions and assumed ammonia 

concentrations) on a day when modeled 

meteorological conditions are most 

conducive to formation and transport of 

visibility impairing pollutants to a 

receptor within a Class I area. While 

there is some uncertainty in the absolute 

visibility impacts and benefits due to 

the model and some of the 

simplifications and assumptions used in 

the BART guideline modeling approach, 

the relative level of impact is a reliable 

assessment of the degree of visibility 

impacts and benefit from controls. Any 

uncertainties in meteorological 

conditions that govern the transport and 

diffusion of pollutants are less 

important in comparing impacts 

between two control scenarios, since the 

same effects will be included in both the 

base and the control scenario model 

simulations. CALPUFF modeling will be 

better at predicting changes in visibility 

impairment due to the application of 

controls than at predicting the absolute 

visibility impacts. BART determinations 

are only made for sources that have 

already been shown to reasonably be 

anticipated to cause or contribute to any 

visibility impairment in a Class I area. 

Modeling of control scenarios is used to 

estimate the amount that this visibility 

impact can be reduced due to a 

reduction in emissions. The modeling of 

these control scenarios is done in a 

manner that holds all variables constant 

except for the emissions of the pollutant 

of interest. A relative reduction in 

visibility impact due to a change in 

emissions is an indication that visibility 

benefits are reasonably anticipated to 

occur. The modeled magnitude of the 

visibility improvement is not a 

determinative factor in the BART 

determination, but only one factor and 

is considered on a relative basis to the 

baseline impact and the benefits of other 

controls. The relative visibility benefit 

of all controls is weighed along with the 

absolute and relative costs of controls, 

energy and nonair environmental 

impacts, any existing controls, and the 

remaining useful life of the source. As 

stated above, we are confident that 

CALPUFF distinguishes, comparatively, 

the relative contributions from sources 

such that the differences in source 

configurations, sizes, emission rates, 

and visibility impacts are well-reflected 

in the model results. 

CALPUFF visibility modeling, 

performed using the regulatory 

CALPUFF model version and following 

all applicable guidance and EPA/FLM 

recommendations, provides a consistent 

tool for comparison with the 0.5 dv 

subject-to-BART threshold. The 

CALPUFF model, as recommended in 

the BART guidelines, has been used for 

almost every single-source BART 

analysis in the country and has 

provided a consistent basis for assessing 

the degree of visibility benefit 

anticipated from controls as one of the 

factors under consideration in a fivefactor BART analysis. Since almost all 

states have completed their BART 

analyses and have either approved SIPs 

or FIPs in place, there is a large set of 

available data on modeled visibility 

impacts and benefits, and how those 

model results were utilized to screen 

out sources and as part of the five-factor 

analysis in making BART control 

determinations for comparison with. 

Comment: Trinity Consultants 

completed a quantitative analysis to 

evaluate the margin of error in the 

CALPUFF model for Lake Catherine 

Unit 4 and Domtar Ashdown Mill.318

Trinity calculated the average difference 

between modeled values obtained using 

CALPUFF (including the CENRAP 

background) and IMPROVE monitored 

values for Caney Creek and Upper 

Buffalo. Trinity compared the regional 

haze design value format of average 

W20 days visibility for this analysis. 

In its analysis, the pre-BART impact 

from Lake Catherine Unit 4 at Caney 

Creek and Upper Buffalo is 

inconsequential when compared with 

the IMPROVE measurements, which 

capture the impact of all other sources, 

including Lake Catherine, on the Class 

I areas. 

The proposed NOX BART controls for 

Lake Catherine Unit 4 will result in 

visibility improvements that are even 

more inconsequential and cannot 

accurately be predicted by CALPUFF. 

Based on Trinity’s analysis, the 

minimum calculated margin of error for 

CALPUFF for Lake Catherine Unit 4 is 

0.93 dv. The CALPUFF modeling 

predicted visibility improvement 

associated with EPA’s proposed BART 

controls for Lake Catherine Unit 4 at 

Caney Creek and Upper Buffalo falls 

within the minimum calculated margin 

of error for CALPUFF for Lake Catherine 

Unit 4. Similarly, the predicted 

visibility improvements associated with 

the imposition of the proposed BART 

requirements for Power Boiler 2 at the 

Domtar Ashdown Mill fall within the 

CALPUFF model’s margin of error. As 

such, the visibility improvements at 

each of these Class I areas associated 

with the proposed BART controls 

cannot ‘‘reasonably be anticipated.’’ 319

Accordingly, EPA has not adequately 

demonstrated that it is appropriate to 

require controls on Lake Catherine Unit 

4 or Power Boiler 2 at the Domtar 

Ashdown Mill. 

These analyses include a discussion 

of work performed by TRC 

Environmental Corporation, including a 

June 2012 paper prepared by Gale 

Hoffnagle that discusses several case 

studies that compared CALPUFF 

modeled values to measured values 

from the IMPROVE monitoring 

network.320 The commenters state that 

PPL Montana relied on this study in its 

successful challenge to the Montana FIP 

for its argument that EPA failed to 

explain why it could reasonably 

anticipate a visibility improvement 

when the improvement was within 

CALPUFF’s margin of error.321

Response: The commenters 

mischaracterize the Ninth Circuit 

decision regarding the ‘‘margin of error’’ 

of the model. The commenter suggests 

that the Court agreed that the 

anticipated visibility benefits in that 

case were within the margin of error of 

the model. This is incorrect. The Ninth 

Circuit decision cited did not rule on 

any specific issue related to CALPUFF. 

Rather, the court ruled on a procedural 

error that EPA did not respond to the 

comment received regarding the 

CALPUFF margin of error in its 

rulemaking as required under the 

law.322 Here and elsewhere in our 

response to comments we address a very 

similar comment with respect to 


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Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66401 

323Evaluation of the CALPUFF Modeling System 

Margin of Error for a BART Analysis, Entergy 

Services, Inc.—Lake Catherine Plant, available as 

Exhibit H to comments submitted by Entergy 

Arkansas, Inc. 

324 80 FR 18944, 18990. 

325 Id. 

326 Id. 

327See Figures 9 and 10 of Entergy Arkansas Inc. 

Comments On the Proposed Regional Haze and 

Interstate Visibility Transport Federal 

Implementation Plan for Arkansas available in the 

docket for this action. 

328 80 FR at 18991. 

CALPUFF modeling for Arkansas 

sources, as well as the commenter’s 

analysis claiming to estimate the 

‘‘margin of error’’. 

The Trinity analysis 323 purports to 

calculate a ‘‘margin of error’’ of the 

CALPUFF modeling for Lake Catherine. 

In general, the commenter’s analysis 

adds CALPUFF model results for a 

specific source or sources with CAMx 

model results and compares this value 

to visibility conditions derived from 

monitored data at each Class I area. This 

analysis is flawed for many reasons as 

discussed in detail in our RTC 

document and fails to provide any 

assessment of the ability of the 

CALPUFF model to evaluate the degree 

of visibility improvement that may be 

expected from available control 

technology to inform BART and 

reasonable progress evaluations. 

Whether or not the modeled visibility 

impacts or benefits lie below this 

calculated ‘‘margin of error’’ is 

immaterial to any assessment of 

whether or not the visibility impairment 

or benefits from controls can reasonably 

be anticipated to occur. BART 

determinations are only made for 

sources that have already been shown to 

reasonably be anticipated to cause or 

contribute to any visibility impairment 

in a Class I area. Modeling of control 

scenarios is used to estimate the amount 

that this visibility impact can be 

reduced due to a reduction in 

emissions. The modeling of these 

control scenarios is done in a manner 

that holds all variables constant except 

for the emissions of the pollutant of 

interest. A relative reduction in 

visibility impact due to a change in 

emissions is an indication that visibility 

benefits are reasonably anticipated to 

occur. The modeled magnitude of the 

visibility improvement is not the 

determinative factor in the BART 

determination, but only one factor and 

is considered on a relative basis to the 

baseline impact and the benefits of other 

controls. The relative visibility benefit 

of all controls is weighed along with the 

absolute and relative costs of controls, 

energy and nonair environmental 

impacts, any existing controls, and the 

remaining useful life of the source. As 

discussed elsewhere in this section of 

the final rule, we are confident that 

CALPUFF distinguishes, comparatively, 

the relative contributions from sources 

such that the differences in source 

configurations, sizes, emission rates, 

and visibility impacts are well-reflected 

in the model results. 

We respond to specific comments 

concerning each separate case study in 

our RTC document. 

5. Reasonable Progress Analysis for 

Entergy Independence 

Comment: Entergy contracted with 

Trinity to perform regional haze 

modeling using CAMx and PSAT based 

on the modeling originally developed 

for CENRAP. This modeling was 

performed to assess the proposed 

control options for Independence units 

1 and 2, as well as White Bluff units 1 

and 2. In addition to the baseline 

scenario modeling, the FIP scenario 

(proposed controls in EPA’s FIP) and 

Entergy’s proposed control approach 

consisting of installed LNB/SOFA on 

Independence, and the cessation of coal 

combustion at White Bluff were 

modeled. 

Entergy stated that EPA’s own 

analysis counsels against imposing 

emission limits on Independence. EPA 

asserts that CENRAP modeling shows 

that sulfate from all point sources 

included in the regional modeling is 

projected to contribute to 57% of the 

total light extinction at Caney Creek on 

the W20 days in 2018 and 43% of the 

total light extinction at Upper 

Buffalo.324 However, EPA recognizes 

that the CENRAP modeling also 

demonstrates that sulfate from all 

(elevated and low level) Arkansas point 

sources is projected to be responsible for 

only 3.58% of the total light extinction 

at Caney Creek and 3.20% at Upper 

Buffalo.325 The contribution of Arkansas 

point sources’ nitrate emissions to 

visibility impairment at Arkansas’ Class 

I areas is even more insignificant. 

According to EPA’s analysis, nitrate 

from all point sources included in the 

regional modeling is projected to 

account for only 3% of the total light 

extinction at the Caney Creek and Upper 

Buffalo Class I areas, with nitrate from 

Arkansas point sources being 

responsible for only 0.29% of the total 

light extinction at Caney Creek and 

0.25% at Upper Buffalo.326 The 

Independence units’ share of emissions 

to this minimal contribution from 

Arkansas point sources to visibility 

impairment at Caney Creek and Upper 

Buffalo is even less. 

Entergy’s CAMx modeling confirms 

that Independence’s contribution to 

visibility impairment is insignificant in 

both Class I areas. Independence is 

projected to contribute to only 0.119 dv 

of visibility impairment at Caney Creek 

and Upper Buffalo on W20 days in 

2018.327 This reflects only one half of 

one percent of the visibility impairment, 

based on modeling, on the W20 days in 

either Caney Creek or Upper Buffalo. 

Yet, based on such a miniscule 

contribution and with no credible 

explanation, EPA arbitrarily concludes 

that SO2 and NOX controls at 

Independence are warranted. 

Response: We disagree with the 

commenter’s assertion that the 

contribution to visibility impairment 

from Entergy Independence is 

‘‘insignificant’’ or ‘‘minimal.’’ For 

example, as the commenter states, the 

CENRAP source apportionment data 

show that sulfate from Arkansas point 

sources are projected to be responsible 

for 3.58% of the total light extinction at 

Caney Creek and 3.20% at Upper 

Buffalo in 2018. As we discuss in our 

proposal, based on 2011 NEI data, the 

Entergy Independence Plant is the 

second largest source of both SO2 and 

NOX point source emissions in 

Arkansas, accounting for approximately 

36% of the SO2 point-source emissions 

and 21% of the point source NOX

emissions in the State.328 Therefore, a 

significant portion of the total visibility 

impairment on the 20% worst days, on 

the order of 1% or more, can be 

expected to be attributable to SO2

emissions from a single facility, the 

Independence facility. As we discuss in 

more detail elsewhere, given their 

contribution to visibility impairment on 

the 20% worst days, we consider both 

SO2 and NOX to be key pollutants 

contributing to visibility impairment at 

Arkansas’ Class I areas. Our CALPUFF 

modeling evaluating the baseline 98th 

percentile impacts confirmed that the 

Independence facility was estimated to 

impact visibility at levels much larger 

than the level considered to ‘‘cause’’ 

visibility impairment (greater than 1 dv) 

at nearby Class I areas, ranging from 

2.512 dv at Caney Creek, to 1.859 dv at 

Mingo. CALPUFF modeling also 

showed that anticipated visibility 

benefits from SO2 and NOX controls at 

the facility exceeded 1 dv at each of the 

four impacted Class I areas. Although 

we recognize that Independence is not 

a subject to BART source, for 

comparison purposes we note that the 

threshold used for visibility impacts to 


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66402 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

329 ‘‘As a general matter, any threshold that you 

use for determining whether a source ‘‘contributes’’ 

to visibility impairment should not be higher than 

0.5 deciviews.’’ BART Guidelines, App. Y to 40 

CFR 51. 

330See ‘‘Entergy Scenario 01 Contribution 2015– 

1124_FINAL.xlsx,’’ ‘‘Avg_Impacts’’ tab, column 

‘‘AA’’ for Caney Creek and Upper Buffalo Class I 

areas. We summarize these results in the RTC 

document. 

331This recommended approach to the treatment 

of background air quality when quantifying source 

impacts and potential benefits from additional 

measures is different than the approach to 

background air quality when projecting how all 

emission reductions measures combined will 

determine visibility conditions at the end of the 

implementation period, i.e., how background 

assumptions relate to the RPGs. It is not appropriate 

to consider only the amount by which a potential 

measure or combination of measures would change 

the projected overall deciview index value as of the 

end of the implementation period, i.e., the degree 

by which the RPGs would differ with and without 

the control being included in the LTS. The RPGs 

are values that will be compared in a progress 

report to actual visibility conditions, and 

accordingly must represent the expected actual 

overall visibility conditions. Estimates of source 

impacts and measure benefits have a different 

purpose, which is to help guide decisions on the 

control of individual sources. 

332 70 FR at 39124. 

333The EPA has followed this logic in the North 

Dakota (77 FR 20894, April 6, 2012), Montana (77 

FR 57864, September 18, 2012), Arizona (79 FR 

52420, September 3, 2014), and Texas (81 FR 296, 

January 5, 2016) FIPs and partial disapprovals of 

North Dakota (77 FR 20894, April 6, 2012) and 

Texas (81 FR 296, January 5, 2016). 

334North Dakota v. EPA, 730 F.3d 750, 764–766 

(8th Cir. 2013). ‘‘Although the State was free to 

employ its own visibility model and to consider 

visibility improvement in its reasonable progress 

determinations, it was not free to do so in a manner 

that was inconsistent with the CAA. Because the 

goal of § 169A is to attain natural visibility 

conditions in mandatory Class I Federal areas, see 

CAA section 169A(a)(1), and EPA has demonstrated 

that the visibility model used by the State would 

serve instead to maintain current degraded 

conditions, we cannot say that EPA acted in a 

manner that was arbitrary, capricious, or an abuse 

of discretion by disapproving the State’s reasonable 

progress determination based upon its cumulative 

source visibility modeling.’’ 

335Some of the major differences are: (1) 

CALPUFF uses maximum 24-hour emission rates, 

while CAMx uses annual average emission rates; (2) 

CALPUFF focuses on the day with the 98th 

percentile highest visibility impact from the source 

being evaluated, whereas CAMx focuses on the 

average visibility impacts across the 20% worst 

days regardless of whether the impacts from a 

specific facility are large or small; and (3) CAMx 

models all sources of emissions in the modeling 

domain, which includes all of the continental U.S., 

whereas CALPUFF only models the impact of 

emissions from one facility without explicit 

chemical interaction with other sources’ emissions. 

336 Deciview impacts are calculated using the 

following equation: Ddv = 10 ln((bbackground+ bsource)/ 

bbackground), where b is extinction (Mm¥1) and Ddv 

is the delta-deciview visibility impact. 

determine whether facilities are subject 

to BART is 0.5 dv.329

We disagree with the commenter that 

the CAMx modeling submitted by the 

commenter confirms that contributions 

to visibility impairment from the 

Independence facility are insignificant. 

When properly assessed, as detailed in 

the RTC document, the commenter’s 

CAMx modeling supports and reinforces 

our finding that visibility impairment 

from Entergy Independence is 

significant and emission reductions will 

result in meaningful visibility benefits 

towards the goal of natural visibility 

conditions. Entergy’s CAMx modeling 

shows a visibility impact of 0.12 dv at 

both Caney Creek and Upper Buffalo 

when compared to 2018 ‘‘dirty’’ or 

‘‘degraded’’ background conditions. The 

commenter then calculates that this 0.12 

dv impact is 0.5% of the total 23 dv 

visibility impairment. As discussed in 

the RTC document, the deciview scale 

is a logarithmic function of extinction, 

and therefore the calculations by the 

commenter are incorrect because they 

are based on deciview values and must 

be performed based on light extinction 

to properly calculate the percent 

contribution to visibility impairment. 

Spreadsheets submitted by the 

commenter present the light extinction 

attributable to each source (in inverse 

megameters) based on the results of 

their CAMx source apportionment 

modeling and calculate the percent 

contribution to total visibility 

impairment at each Class I area.330 The 

commenter is incorrect in its statement 

that the impact from the Independence 

facility is one half of one percent; it is 

in fact, based on their own modeling 

and calculation, approximately 1.3% of 

the total visibility impairment at each 

Arkansas Class I area. Considering that 

the CAMx photochemical modeling 

takes into account the emissions of 

thousands of sources, both in Arkansas 

and outside of the state, we consider 

this to be a significant contribution to 

visibility impairment at each Class I 

area and a large portion (approximately 

one-third) of the total contribution from 

all Arkansas point sources that can be 

addressed through installation of 

controls on two units at a single facility. 

The CAMx modeling also showed that 

at Upper Buffalo, the Independence 

facility’s contribution to visibility 

impairment is greater than the 

contribution from all of the subject-toBART sources addressed in this final 

action combined. 

Furthermore, the deciview visibility 

impacts for individual sources should 

be assessed based on natural ‘‘clean’’ 

background visibility conditions. The 

deciview improvement based on the 

2018 background conditions provides 

an estimate of the amount of benefit that 

can be anticipated in 2018 and the 

impact a control/emission reduction 

may have on the established RPG for 

2018. However, this estimate based on 

degraded or ‘‘dirty’’ background 

conditions underestimates the visibility 

improvement that would be realized for 

the control options under consideration. 

The source impacts and the potential 

benefits of controls must be considered 

relative to a light extinction level that 

represents a clean/natural background, 

rather than the current visibility 

conditions or projected visibility 

conditions at the end of the planning 

period.331 The need for consideration of 

visibility impacts and benefits relative 

to clean/natural conditions was 

explained in the preamble to the final 

BART Guidelines: 

Using existing conditions as the baseline 

for single source visibility impact 

determinations would create the following 

paradox: The dirtier the existing air, the less 

likely it would be that any control is 

required. This is true because of the 

nonlinear nature of visibility impairment. In 

other words, as a Class I area becomes more 

polluted, any individual source’s 

contribution to changes in impairment 

becomes geometrically less. Therefore the 

more polluted the Class I area would become, 

the less control would seem to be needed 

from an individual source. . . . Such a 

reading would render the visibility 

provisions meaningless, as EPA and the 

States would be prevented from assuring 

‘‘reasonable progress’’ and fulfilling the 

statutorily-defined goals of the visibility 

program. Conversely, measuring 

improvement against clean conditions would 

ensure reasonable progress toward those 

clean conditions.332

The same logic applies to the 

evaluation of visibility impacts and 

benefits for sources examined for 

controls for reasonable progress. 

Accordingly, the EPA has used clean 

background conditions in evaluating the 

benefits of controls on individual 

reasonable progress sources and has 

disapproved reasonable progress 

decisions by states that relied on 

modeling employing dirty background 

conditions.333 This approach has been 

upheld by the Eighth Circuit.334

We note that while CALPUFF results 

are not directly comparable to CAMx 

model results due to differences in 

metrics, models and model inputs,335

CALPUFF visibility impacts are also 

calculated based on natural or ‘‘clean’’ 

background conditions. 

We recalculated the average modeled 

visibility impact for the 20% worst days 

based on the commenter’s CAMx 

modeled average visibility impact for 

the 20% worst days using a clean 

background approach (using annual 

average natural conditions 

background).336 The Independence 

facility (units 1 and 2 combined) has 

impacts greater than 0.5 dv at both 


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Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66403 

337See ‘‘Entergy Arkansas CAMx—EPA calcs max 

and clean background.xlsx,’’ available in the docket 

for this action. 

338 80 FR at 18995. 

339See Arkansas Regional Haze SIP, Appendix 

8.1— ‘‘Technical Support Document for CENRAP 

Emissions and Air Quality Modeling to Support 

Regional Haze State Implementation Plans,’’ section 

3.7.1 and 3.7.2. See the docket for this rulemaking 

for a copy of the Arkansas Regional Haze SIP. 

340See 80 FR at 18991, Table 59. 

341 80 FR at 18995. 

Caney Creek and Upper Buffalo on 

average across the 20% worst days on a 

‘‘clean’’ background basis based on 

CAMx modeling submitted by the 

commenter.337 These CAMx model 

results for the average across the 20% 

worst days show that the Independence 

facility contributes significantly to 

visibility impairment on the 20% worst 

days and controls will result in 

meaningful visibility benefit towards 

the goal of natural visibility conditions. 

Furthermore, the maximum visibility 

impact on an individual day within the 

subset of days that make up the 20% 

worst days are much larger. Facilitywide visibility impacts from 

Independence exceed 1 dv at each 

Arkansas Class I area. We note that in 

some situations, the days that CALPUFF 

model maximum or 98th percentile 

value impacts of the facility occur may 

not coincide with any of the days that 

make up the days in the worst 20% days 

at the Class I area and the visibility 

impacts modeled by CALPUFF are not 

directly comparable to the visibility 

benefits that would be anticipated on 

the 20% worst days. See our complete 

RTC document for additional 

information on calculated visibility 

impacts from the Entergy facilities based 

on the commenter’s CAMx modeling 

results. 

Comment: The level of improvement 

expected from EPA’s proposed controls 

for Independence is virtually 

insignificant and does not justify the 

costs of controls. The BART-type 

evaluation for NOX for the 

Independence Power Plant Units 1 and 

2 would result in visibility 

improvements ranging from 0.148 to 

0.459 dv with a cumulative 

improvement of 0.978 dv. EPA 

recognized that these improvements 

were relatively small and proposed an 

option (Option 2) that did not include 

the LNB/SOFA NOX controls for Units 

1 and 2. EPA, however, did not 

recognize that the Independence facility 

is subject to CSAPR and that NOX

reductions ‘‘better than BART’’ would 

already be achieved by participation in 

that program without specifically 

requiring the LNB/SOFA in the FIP. 

For SO2 emissions for Independence 

Units 1 and 2, EPA estimated 

improvements with dry FGD ranging 

from 1.045 to 1.178 dv with a 

cumulative benefit of 4.375 dv. Three of 

the four class I areas would realize 

visibility improvements barely 

discernible to the human eye (<1.1 dv). 

The best improvement is for Upper 

Buffalo and is only 1.178 dv. It is not 

appropriate to use the cumulative 

values as a representation of the 

visibility benefit of adding controls 

since only the improvement at each 

particular Class I area could actually be 

recognized. This level of visibility 

improvement is virtually insignificant 

and does not justify the costs associated 

with adding a dry FGD and, therefore, 

does not meet the statutory RPG 

requirement for proper consideration of 

the cost of controls and so is not 

‘‘reasonable.’’ 

Response: We disagree with the 

commenter and do not believe that 

visibility improvements from NOX

controls ranging from 0.128 to 0.459 dv 

are relatively small. Given that sources 

are subject to BART based on a 

contribution threshold of no greater 

than 0.5 deciviews, it would be 

inconsistent to consider an 

improvement in visibility of nearly 0.5 

dv to be insignificant or small for 

reasonable progress. In our proposed 

action, we noted that ‘‘The single source 

CALPUFF modeling shows that sizeable 

reductions to the maximum 98th 

percentile visibility impact from the 

Independence facility may be achieved 

through NOX controls.’’ 338 Furthermore, 

total modeled extinction at Caney Creek 

is dominated by nitrate on 4 of the days 

that comprise the 20% worst days in 

2002, and a significant portion of the 

total extinction at Upper Buffalo on 2 of 

the days that comprise the 20% worst 

days in 2002 is due to nitrate.339 Both 

NOX and SO2 are key pollutants that 

contribute to visibility impairment at 

the Arkansas Class I areas. Because we 

have identified these two pollutants as 

key, we are obligated to determine 

which sources or source categories are 

responsible for emitting these pollutants 

and evaluate them for reasonable 

progress. Independence is the second 

largest point source of both SO2 and 

NOX in the State.340 Therefore, we 

evaluated it for reasonable progress 

controls for both pollutants. We 

recognized, however, that at this time, 

even though NOX emissions are a key 

pollutant, point source NOX emissions 

are not the main contributors to 

visibility impairment on the average of 

the 20% worst days at Arkansas’ Class 

I areas in 2018, as projected by CAMx 

source apportionment modeling.’’ 341

Even though we recognized that NOX

emissions are a key pollutant to 

reaching the regional haze goals, and 

that the visibility benefits from NOX

controls were sizeable, we took 

comment on two options because the 

visibility impairment due to Arkansas 

point source emissions on the average of 

the 20% worst days were primarily due 

to sulfate emissions. We also found that 

significant reductions could be achieved 

very cost effectively through the 

implementation of low NOX burners. In 

our final action, we have determined 

that it is appropriate to require the NOX

controls as proposed under Option 1 

because the goal of the long-term 

strategy and reasonable progress 

requirements is to improve visibility 

and make progress towards natural 

conditions and NOX is a key pollutant 

impacting visibility at the Arkansas 

Class I areas. We used a shorthand term, 

‘‘driver,’’ in our proposal discussing 

SO2, and did not mean to imply that 

NOX was not also a key pollutant. While 

point source NOX emissions are not the 

primary contributor to impairment on 

most of the 20% worst days, NOX is a 

key contributor to visibility on other 

days of the year and on some days that 

make up the 20% worst days (in 2002, 

IMPROVE monitor data shows that two 

days that make up the 20% worst days 

at Upper Buffalo and three days at 

Caney Creek are more significantly 

impacted by nitrate than sulfate). So in 

considering reasonable progress factors, 

we have determined that because NOX

and SO2 are both key visibility 

impairing pollutants, for Independence 

there are technically feasible and cost 

effective controls available for both SO2

and NOX and those controls will 

provide significant visibility 

improvement. Therefore, both SO2 and 

NOX controls are reasonable and 

necessary to eventually achieve the 

national goal. We have determined that 

it is appropriate to reduce NOX

emissions and finalize Option 1. As to 

the comment that we did not recognize 

‘‘better than BART’’ coverage due to 

CSAPR, we address this comment 

elsewhere in a separate response to 

comment. 

With respect to the anticipated 

visibility improvement due to SO2

controls, we consider visibility benefits 

ranging from 1.045 to 1.178 dv at each 

Class I area to be significant. We note 

that the Regional Haze Rule provides 

that sources with a 0.5 dv impact at a 

Class I area ‘‘contribute’’ to visibility 

impairment and must be analyzed for 

BART controls, and that source with a 

1.0 dv impact at a Class I area to 

‘‘cause’’ visibility impairment. Given 


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342 80 FR at 18990. 

343The projected haze index at Upper Buffalo of 

18.05 dv would keep Upper Buffalo below the glide 

path until approximately 2038—the end of the third 

planning period. 

that sources are subject to BART based 

on a contribution threshold of no greater 

than 0.5 deciviews and visibility 

impacts greater than 1.0 deciview are 

considered a level to be ‘‘causing’’ 

visibility impairment, it would be 

inconsistent to consider a potential 

improvement in visibility of greater than 

twice the BART threshold to be 

insignificant. 

Furthermore, as discussed elsewhere 

throughout this final rule, results of 

Entergy Arkansas’ CAMx modeling with 

source apportionment provide 

additional support that the 

Independence facility has significant 

impacts on visibility at nearby Class I 

areas on the 20% worst days and that 

controlling these units would result in 

significant visibility benefits towards 

the goal of natural visibility conditions. 

We address comments concerning the 

consideration of cumulative visibility 

benefits and imperceptible visibility 

benefits elsewhere. 

Comment: EPA’s CALPUFF modeling 

indicates that the SO2 and NOX

emission limits proposed for 

Independence will result in a 1.952 dv 

improvement in Caney Creek and a 

1.782 dv improvement in Upper Buffalo. 

However, this range is vastly overstated. 

Based on the current monitored 

visibility levels in Caney Creek and 

Upper Buffalo, the W20 days show that 

the visibility impairment in 2018 will be 

approximately 23 to 24 dv. EPA 

recognizes that sulfate from all of 

Arkansas’ point sources are projected to 

be responsible for only about 3.6% of 

total light extinction at Arkansas’ Class 

I areas based on CENRAP modeling.342

This means that sulfate from all 

Arkansas point sources are projected to 

be responsible for only about 0.81–0.86 

dv of impairment (23–24 dv × 3.6%). 

For nitrates, EPA projects that Arkansas 

point source emissions will account for, 

at most, 0.29% of the total light 

extinction at Arkansas’ Class I areas. 

Independence’s SO2 and NOX emissions 

contribute only a portion to the sulfate 

and nitrate percentages estimated from 

Arkansas point sources. It would, 

therefore, be impossible for the SO2 and 

NOX limits proposed for Independence 

to result in deciview improvements at 

Caney Creek and Upper Buffalo of 1.952 

dv and 1.782 dv, respectively. This 

simple example demonstrates the 

obvious flaw in EPA’s use of CALPUFF 

for its reasonable progress analysis and, 

thus, its justification for imposing 

emission limits on Independence 

despite the fact that the Class I areas are 

below the URP. 

Based on CALPUFF modeling, EPA’s 

proposed BART limits will result in 

projected combined visibility benefits of 

approximately 4.3 dv at Caney Creek. 

Based on Entergy’s statistical projection 

of the haze index in Caney Creek, that 

would result in a haze index of 15.76 

dv, which would put Caney Creek closer 

to natural background levels than the 

glide path. The URP would not reach 

that haze level until approximately 

2048.343 Indeed, even if you ascribed 

the CALPUFF-projected benefits to 

Caney Creek based on the recent 

IMPROVE levels (approximately 22 dv 

between 2009 and 2012), the projected 

haze index would drop to 17.7 dv, 

which indicates no further action 

should be needed to remain below the 

URP until approximately 2038. 

If EPA insists on relying on CALPUFF 

to evaluate the projected visibility 

benefits of requiring controls on 

Independence, it must be consistent and 

use CALPUFF to evaluate the need for 

such controls for purposes of 

demonstrating reasonable progress. As 

demonstrated in Figures 11 and 12, 

controls at Independence cannot be 

justified for reasonable progress based 

on the CALPUFF results, which predict 

an improvement of several deciviews 

solely from BART controls. 

Response: As more fully explained 

above and in the RTC Document, the 

commenter’s analysis fails to account 

for the fact that deciviews are a 

logarithmic function of extinction, that 

CALPUFF results are for the maximum 

impact (98th percentile impact from 

each source) in contrast to the CENRAP 

projected visibility conditions that are 

for the average visibility over the 20% 

worst days, and also fails to differentiate 

between deciview values calculated 

based on natural background conditions 

(as the CALPUFF results are) and the 

deciview values relative to a degraded 

or dirty background. 

First, the commenter incorrectly 

estimates that the impact from sulfate 

point source emissions in Arkansas is 

0.81–0.86 dv. Because the deciview 

metric is a logarithmic function of 

extinction, the percent extinction 

cannot be directly applied to the total 

deciview impairment. Recalculating the 

impact from sulfate point sources to 

correct for this error yields 

approximately a 0.32 dv impact based 

on a ‘‘dirty’’ background 2018 projected 

visibility conditions and 0.92 dv based 

on a natural background approach. 

Second, 0.92 dv represents the 

estimated deciview improvement from 

eliminating sulfate emissions at all 

point sources in Arkansas (based on 

typical or average emissions) on average 

across the 20% worst days, as defined 

by the 20% worst days of monitored 

visibility at Caney Creek. This CAMx 

derived value is not directly comparable 

to the CALPUFF modeled 1.952 dv 

improvement from controls on both 

units at Independence, due to 

differences in models, model inputs and 

metrics. CALPUFF modeling following 

the BART guidelines and recommended 

protocol provides an estimate of the 

maximum (98th percentile) visibility 

benefit based on 24-hr maximum actual 

emissions modeled over a period of 

three years. The CAMx modeling results 

presented by the commenter represent 

the average visibility impacts over the 

20% worst days (as defined by 

monitored data) based on modeling 

actual emissions levels. In addition, 

CALPUFF uses an estimated constant 

background ammonia level and does not 

account for the competition for 

ammonia due to emissions from other 

sources. A maximum value of 1.952 dv 

for visibility benefits of controlling 

Independence based on CALPUFF 

modeling is not inconsistent with an 

estimated 0.92 dv impact from all 

sulfate point source emissions averaged 

over the 20% worst days. In general, the 

maximum value could be several times 

larger than the average over the 20% 

worst days (representing the average 

visibility over the 73 days, or 24 

monitored days with the worst 

visibility). Furthermore, the maximum 

value as modeled by CALPUFF is based 

on maximum 24-hr emissions, which 

may be much higher than the average 

emissions. As discussed in a separate 

response to comment above, CAMx 

modeling using source apportionment 

provided by the commenter (Entergy) 

modeled a facility-wide impact from 

Entergy Independence of 1.64 dv on the 

maximum day within the subset of days 

that make up the 20% worst days. The 

maximum modeled impact across the 

full 365 days modeled could be much 

larger. Furthermore, this modeling is 

based on actual emissions and not 

maximum 24-hr emissions as modeled 

by CALPUFF. Therefore, the 1.952 dv 

visibility benefit estimated by CALPUFF 

is not ‘‘impossible’’ and is in fact in line 

with the visibility impacts estimated 

using the CAMx model as supplied by 

the commenter. 

Third, the commenter is incorrect in 

estimating a 4.3 dv improvement from 

all BART controls and using this value 

to adjust projected visibility conditions 


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344Commenter states: ‘‘Trinity derived the 4.3 dv 

improvement from the CALPUFF modeling by 

determining the total extinction (in inverse 

megameters) from each proposed BART source, 

adding them together, and then calculating the 

deciview improvement. The resulting 4.3 dv 

improvement is over five times the total visibility 

impact attributed to all point sources in Arkansas 

based on CENRAP’s CAMx modeling and 14 times 

the impact attributed to point sources based on 

Entergy’s current CAMx modeling.’’ 

345These values are the calculated improvement 

based on EPA’s ‘‘scaling methodology.’’ See 80 FR 

at 18997. 

346North Dakota v. EPA, 730 F.3d 750, 767 (8th 

Cir. 2013). 

347The commenter states that requiring 

imperceptible visibility improvements is simply 

unreasonable and refers to the 8th circuit decision 

that the CAA requires only ‘‘reasonable progress, 

not the most reasonable progress.’’ North Dakota v. 

EPA, 730 F.3d 750, 767 (8th Cir. 2013). 

in 2018 on the 20% worst days in the 

above figures. The cumulative visibility 

impacts cited to by the commenter (e.g., 

4.3 dv improvement at Caney Creek due 

to all BART controls) combines the 

maximum visibility improvements from 

each facility that would result from 

required NOX or SO2 controls without 

any consideration of the location of the 

source or if the impacts and benefits 

would occur on the same day. The 

commenter’s approach overstates the 

combined impact at a given Class I area 

and does not contemplate if sources are 

located near each other and would 

likely impact a Class I area at the same 

time. Contrary to the commenter’s 

description of the methodology used to 

estimate the total visibility benefits of 

BART controls,344 the commenter 

simply added the CALPUFF modeled 

deciview visibility benefits for each 

control. These benefits represent the 

maximum (98th percentile) visibility 

benefits at each source based on 

reductions to the maximum 24-hr 

emissions modeled over a period of 

three years. The maximum benefits from 

controlling one source cannot be added 

to the maximum benefits of controlling 

another source as these benefits are not 

likely to occur on the same day since 

the sources are not collocated. In 

addition, the maximum benefits from 

NOX controls and SO2 controls at the 

same facility cannot be added as they 

may not occur on the same day. 

Furthermore, these values represent the 

benefit on an individual day and not the 

average visibility benefit on the 20% 

worst days so it is not appropriate to 

adjust the visibility conditions on the 

20% worst days by this amount as the 

commenter does in the above figures. In 

some situations, the days that CALPUFF 

model maximum or 98th percentile 

value impacts of the facility occur may 

not coincide with any of the days that 

make up the days in the worst 20% days 

at the Class I area and the visibility 

benefits modeled by CALPUFF are not 

directly comparable to the visibility 

benefits that would be anticipated on 

the 20% worst days from those specific 

controls. Furthermore, as discussed 

elsewhere in this section of the final 

rule, because deciviews are a 

logarithmic function of extinction, they 

cannot be added as the commenter does 

here. The CALPUFF modeled visibility 

benefits represent the visibility benefits 

of controls based on a clean background 

approach, and not the amount of benefit 

that would occur from degraded 

conditions, which would be needed to 

estimate the improvement in overall 

visibility conditions in 2018. We 

estimated the amount of visibility 

benefit anticipated from all controls 

against 2018 visibility conditions in 

estimating the proposed RPGs for 2018. 

In this calculation we estimated the 

benefit from all required controls to be 

0.21 dv at Caney Creek and 0.19 dv at 

Upper Buffalo. 

Comment: CALPUFF overstates the 

visibility improvement expected from 

EPA’s proposed controls on 

Independence, EPA concluded that the 

cumulative benefit of installing all of 

the controls in the Proposed FIP—all 

BART controls plus controls at 

Independence—would result in 

visibility benefits at Caney Creek of only 

0.21 dv and at Upper Buffalo of only 

0.19 dv. Since Independence represents 

only approximately 36% of the SO2

point source emissions and 21% of the 

point source NOX emissions in 

Arkansas, one can ascribe only a minor 

portion of this projected insignificant 

deciview improvement to controls on 

Independence (approximately 0.08 dv at 

Caney Creek and 0.07 dv at Upper 

Buffalo).345 Based on this, installation of 

controls on Independence will yield no 

discernible visibility improvements. 

This demonstrates the illogic of 

relying on CALPUFF for reasonable 

progress. Independence’s contribution 

to the deciview improvements EPA 

projects based on the CENRAP modeling 

would be much less than the total 

deciview improvement at Caney Creek 

of 0.21 dv from the installation of 

controls at all of the proposed FIP 

sources and 0.19 dv at Upper Buffalo 

would not be perceptible to the human 

eye; nowhere close to the 1.95 dv and 

1.78 dv improvement that EPA is 

claiming based on CALPUFF. Requiring 

imperceptible visibility improvements 

is simply unreasonable. The CAA 

requires only ‘‘reasonable progress, not 

the most reasonable progress.’’ 346

Response: As we discuss in depth 

elsewhere, visibility improvements from 

controls must be evaluated on a ‘‘clean’’ 

background basis to fully assess the 

benefits from controls. It is not 

appropriate to consider only the amount 

by which a potential measure or 

combination of measures would change 

the projected overall deciview index 

value as of the end of the 

implementation period, i.e., the degree 

by which the RPGs would differ with 

and without the control being included 

in the LTS, as the commenter does here. 

We also discuss elsewhere in this 

section of the final rule that the 

deciview scale is a logarithmic function 

of extinction and calculations to 

determine benefits or amount of 

contribution to visibility impairment 

must be based on extinction and then 

converted into deciviews. Nevertheless, 

the commenter’s estimated visibility 

benefits of 0.08 dv at Caney Creek and 

0.07 dv at Upper Buffalo on average 

across the 20% worst days are 

approximately a reduction in extinction 

of 0.8 Mm¥1 at Caney Creek and 0.7 

Mm¥1 at Upper Buffalo, which is 0.37 

dv and 0.32 dv based on a clean 

background approach for the 20% worst 

days. In our response to a separate 

comment above, we discuss that due to 

the differences in models, model inputs, 

and metrics, the estimated visibility 

benefits estimated from CAMx modeling 

cannot be directly compared to 

CALPUFF modeled visibility benefits. 

For one, CALPUFF modeling is used to 

estimate the maximum visibility benefit 

based on maximum emissions whereas 

the CAMx modeling estimates the 

average visibility benefit over the 20% 

worst days (as defined by the monitored 

data) using actual or typical emission 

levels. As we also discuss above in a 

separate response to comment, CAMx 

visibility modeling with source 

apportionment submitted by Entergy 

estimates a maximum visibility impact 

(limited to only the days comprising the 

20% worst days) of over 1.5 dv from the 

Independence facility at both Caney 

Creek and Upper Buffalo. In some 

situations, the CALPUFF modeled 

maximum or 98th percentile impacts of 

the facility may not coincide with the 

days that make up the worst 20% 

monitored days at the Class I area, 

therefore the maximum impact based on 

CAMx modeling could be even higher. 

With regard to the quote the 

commenter reproduced from the Eighth 

Circuit Court’s decision in North Dakota 

v. EPA,347 several environmental groups 

challenged a portion of our final action 

on North Dakota’s regional haze SIP that 

ultimately approved North Dakota’s 

reasonable progress determination for 


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348See EPA’s final rule at 77 FR 20894, 20945 

(April 6, 2012). 

349 64 FR at 35732. 

350 80 FR at 18991. 

351Entergy Arkansas Inc. stated that it is 

proposing near-term interim controls and the 

cessation of coal combustion at White Bluff by 

2028. Entergy is proposing to meet lower SO2

emission rates at White Bluff Units 1 and 2 and 

Independence Units 1 and 2 by 2018, and is willing 

to install LNB/SOFA at all four units and meet a 

30-day rolling average NOX emission rate of 1,342.5 

lb NOX/hr, within three years after the effective date 

of the final FIP as part of its multi-unit approach. 

Entergy’s comments with regard to the proposed 

NOX rate are discussed elsewhere in this final rule. 

NOX controls for the Coyote Station.348

The environmental groups objected to 

North Dakota’s decision to reject a 

control it had evaluated, after having 

applied the four reasonable progress 

factors, and subsequently approving 

another NOX control as reasonable 

progress. 

We interpret the Court’s statement as 

meaning broadly that just because a 

more stringent level of control could be 

technically feasible in a particular 

instance, it does not mean it necessarily 

must be required under reasonable 

progress. We see no conflict with this 

determination and our proposed 

Arkansas FIP and requiring controls that 

may not result in perceptible visibility 

improvements. In North Dakota’s case, 

we noted technical flaws in North 

Dakota’s analysis, and we noted that we 

could have reached a different 

conclusion had we conducted the 

analysis ourselves, but we ultimately 

determined these issues did not prevent 

us from accepting North Dakota’s 

reasonable progress determination. The 

Court did not find that our conclusions 

on the issue were arbitrary, stating in 

part that, ‘‘[e]ven if [the control in 

question] were perhaps the most 

reasonable technology available, the 

CAA requires only that a state establish 

reasonable progress, not the most 

reasonable progress. In contrast, and as 

explained in greater detail elsewhere, in 

our 2012 rulemaking,349 we made a 

finding that Arkansas did not complete 

a reasonable progress analysis and 

therefore did not properly demonstrate 

that additional controls were not 

reasonable under 40 CFR 

51.308(d)(1)(i)(A). Thus we disapproved 

the RPGs Arkansas established for 

Caney Creek and Upper Buffalo. Our 

proposed rulemaking completed the 

reasonable progress analysis and 

established revised RPGs, since we have 

not received a revised SIP to correct the 

portions of the SIP submittal we 

disapproved. We determined that cost 

effective controls were in fact available 

that would have very significant 

visibility benefits. 

Comment: EPA’s assessment 

demonstrates that the Independence 

Power Plant’s emissions have, and will 

continue to have, very little effect on 

visibility in any Class I area. EPA’s 

reasonable progress analysis shows that 

‘‘[o]n the 20% worst days in 2002, 

sulfate from Arkansas point sources 

contributed 2.20% of the total light 

extinction at Caney Creek and 1.99% at 

Upper Buffalo, and nitrate from 

Arkansas point sources contributed 

0.27% of the total light extinction at 

Caney Creek and 0.14% at Upper 

Buffalo.’’ 80 FR at 18989 (footnote 

omitted). According to EPA, these very 

small percentages reflect contributions 

from all ‘‘Arkansas point sources,’’ not 

from the Independence Power Plant 

alone, whose emissions of course 

contribute only a fraction of these small 

amounts. 

Response: We disagree with the 

commenter’s assertion that the 

contribution to visibility impairment 

from Independence is ‘‘insignificant’’ or 

‘‘minimal.’’ We agree with the 

commenter’s description of the 2002 

CENRAP source apportionment data. 

The CENRAP modeling also projects 

that Arkansas point sources will be 

responsible for 3.58% of the total light 

extinction at Caney Creek and 3.20% at 

Upper Buffalo in 2018. As we discuss in 

our proposal, based on 2011 NEI data 

the Entergy Independence Plant is the 

second largest source of SO2 and NOX

point source emissions in Arkansas, 

accounting for approximately 36% of 

the SO2 point-source emissions and 

21% of point-source NOX emissions in 

the State.350 Therefore, a significant 

portion of the total projected visibility 

impairment on the 20% worst days, on 

the order of 1% or more, can be 

expected to be attributable to SO2

emissions from a single facility, the 

Independence facility, based on the 

CERNAP modeling. We discuss in a 

separate response to comment that 

results of our CALPUFF modeling, as 

well as the results of additional CAMx 

modeling submitted by Entergy, confirm 

and support that the visibility 

impairment due to the Independence 

facility is significant and that emission 

reductions will result in meaningful 

visibility benefits towards natural 

visibility conditions. 

6. Visibility Benefit of Entergy Arkansas 

Proposal 

Comment: Entergy’s proposed 

combination of controls and lower SO2

emission rates will ensure that the Class 

I areas achieve virtually the same 

reasonable progress as EPA’s proposal 

but at a cost of over $2 billion less than 

the proposal.351 Based on Entergy’s 

CAMx modeling and Ranked Statistical 

Analysis, the difference in the haze 

index between the proposed FIP 

controls and Entergy’s proposal is 0.05 

dv at Caney Creek and 0.07 dv at Upper 

Buffalo. 

Response: We discuss the ‘‘ranked 

statistical analysis’’ submitted by the 

commenter in the response to comments 

elsewhere. We disagree with the 

commenter that the Entergy proposed 

control scenario achieves ‘‘virtually’’ the 

same visibility benefits as the controls 

required in this FIP. We examined the 

estimated visibility benefits of the FIP 

and Entergy’s proposal from the 

commenter’s CAMx photochemical 

modeling. We note that both scenarios 

include benefits from all required BART 

controls at all subject-to-BART facilities 

with the exception of White Bluff. The 

modeled FIP scenario also includes SO2

and NOX controls at both Independence 

and White Bluff. The modeled Entergy 

proposal scenario includes the 

elimination of emissions from White 

Bluff, an approximate 15% reduction in 

SO2 emissions from Independence and 

roughly similar NOX reductions at 

Independence as required in the FIP. 

Entergy’s proposal achieves less 

visibility benefit than the FIP controls at 

Arkansas’ Class I areas, most 

significantly at Upper Buffalo where the 

benefit from Entergy’s proposal is 

approximately only 63% of the benefit 

from the FIP (1.54 Mm¥1 from the FIP 

compared to 0.97 Mm¥1 from Entergy’s 

Proposal, see the RTC document for 

additional information). As discussed 

above, CAMx source apportionment 

modeling submitted by Entergy shows 

that Entergy Independence has 

significant visibility impacts at both 

Arkansas Class I areas. At Upper 

Buffalo, the Independence facility 

contributes more to visibility 

impairment than all the subject-toBART sources addressed in this action 

combined. Additional reductions from 

the elimination of emissions from the 

White Bluff facility under Entergy’s 

proposal are much too small to 

compensate for the lack of significant 

SO2 reductions at Independence. 

Furthermore, Entergy’s proposal does 

not achieve these benefits until 2028, 

seven years after the full benefits from 

the FIP would be realized. We discuss 

other aspects of Entergy’s proposal, 

including uncertainty in emissions at 

White Bluff after the cessation of coalburning, and issues concerning the 

BART requirements for White Bluff in 

separate responses to comment 

elsewhere in this document. 


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352Trinity’s report is included as Exhibit D 

IMPROVE Data Statistical Analysis, Trinity 

Consultants (July 2015) to Entergy Arkansas, Inc.’s 

comments. 

353See Figure 2–3 of Exhibit D to Entergy 

Arkansas, Inc.’s comments. 

354See RTC document for additional information 

on Arkansas source category SO2 emissions from 

2004 to 2014. 

We also disagree with the 

commenter’s use of the results of their 

ranked statistical analysis (the 

‘‘projected haze index’’ shown in the 

Entergy Arkansas Inc.’s submitted 

comments in figures 13 and 14) as the 

starting point for calculating the overall 

visibility benefits from the FIP or the 

commenter’s proposed alternative. As 

discussed elsewhere in this section of 

the final rule, the ranked statistical 

analysis is simply a projection of future 

visibility conditions based on past 

improvement and is not directly tied to 

any additional required emission 

reductions in the next few years that 

would result in this future visibility 

improvement from current conditions to 

this projected value in 2018. 

7. Observed Visibility Improvements 

Comment: Trinity was tasked by 

Entergy Arkansas with conducting a 

statistical analysis of observed visibility 

data gathered through the IMPROVE 

program to statistically determine the 

future trends in the regional haze index 

values. Trinity conducted a simple 

Trend Statistical Analysis and more 

robust Ranked Statistical Analysis to 

determine the projected haze index in 

2018.352

For Caney Creek and Upper Buffalo, 

respectively, the observed values are 

well below the glide path with a 

consistent downward trend in the 

observations. This downward trend is 

consistent with the historical (2002– 

2011) trend in decreasing sulfur dioxide 

(SO2) emissions from tier 1 sources 

located in the states contributing 

significantly to the Caney Creek and 

Upper Buffalo Class I Areas.353 Pursuant 

to the NEI emissions data, the SO2

emissions have significantly decreased 

since 2005 to 2011 in all source 

categories, including especially a more 

than 50% drop due to fuel combustion 

from electric utilities and a 67% drop in 

the fuel combustion from industrial 

sources. Based on the significant 

downward trend in the observed data 

and the actual SO2 emissions data, the 

future haze index value in 2018 is 

expected to be lower than the currently 

predicted glide path. The lower haze 

index value in 2018 will be additionally 

supported by the anticipated 

implementation of regulations further 

curbing emissions. 

In order to statistically calculate the 

future deciview haze index values using 

observed data instead of relying on the 

CENRAP modeling, two statistical 

analyses were performed and evaluated 

to determine the most appropriate 

analysis for predicting the haze index 

values based on observed data: Trend 

Analysis, and Ranked Statistical 

Analysis. The 2018 average of the 20% 

worst days for visibility was calculated 

to be 20.07 dv for Caney Creek and 

20.91 dv for Upper Buffalo. These 

numbers are far below the URP for the 

first planning period and demonstrate 

that no source in Arkansas, including 

Independence, needs to install controls 

for Arkansas to remain below the glide 

path. 

Response: As we discuss in section 

V.C of this final rule, being projected to 

be on or below the URP glidepath in 

2018 (or even beyond) does not 

automatically mean that no controls or 

evaluation under reasonable progress is 

needed in this planning period. The 

commenter presents SO2 emissions data 

from 2002, 2005, 2008, and 2011 for 

states identified by the commenter as 

impacting visibility at the Arkansas 

Class I areas. These data show 

significant emissions reductions over 

this time period and are consistent with 

observed visibility improvement at the 

Arkansas Class I areas. However, most 

of the visibility improvement currently 

observed in Arkansas appears to be due 

to emissions reductions that have taken 

place outside the state. Arkansas 

emissions do not exhibit the same 

downward trend as presented for the 

other states that impact visibility at the 

Arkansas Class I areas.354 More recent 

annual emissions from 2012–2014 are 

actually higher than emissions from the 

2008–2011 period and there is no 

downward trend in emissions from 

those point sources with the largest 

visibility impacts, those from fuel 

combustion at electric utilities. To the 

extent that the commenters are 

suggesting that Arkansas should be 

relieved of its regional haze obligations 

because other states’ emission reduction 

efforts have already resulted in 

significant visibility improvement at 

Arkansas’ Class I areas, this is incorrect. 

Rather Arkansas, and EPA in standing 

in Arkansas’ shoes, must consider the 

statutory factors in addressing the long 

term strategy and reasonable progress 

requirements. 

We disagree with the commenter that 

the CENRAP CAMx predicted 2018 haze 

index is overly conservative. The 

comments indicate a lack of 

understanding of how reasonable 

progress goals are established, as well as 

the imports of the goals as opposed to 

the measures adopted to ensure 

reasonable progress. As we state in the 

Regional Haze Rule, the reasonable 

progress goal(s) set by the state, or EPA 

when promulgating a FIP, are not 

enforceable. The reasonable progress 

goals are an analytical tool used by EPA 

and the states to estimate future 

visibility conditions and track progress 

towards the goal of natural visibility 

conditions. Accordingly, the RPGs must 

represent an estimate of the degree of 

visibility improvement that will result 

in a future year from changes in 

emissions inventories, changes driven 

by the particular set of control measures 

adopted in the regional haze SIP or FIP 

to address visibility, as well as all other 

enforceable measures expected to 

reduce emissions. Given the forwardlooking nature of reasonable progress 

goals and the range of assumptions that 

must be made as to emissions in the 

future, we expect there to be some 

uncertainty in the estimates of future 

visibility. 

The statistical analyses provided by 

the commenter are simply 

extrapolations of future visibility 

conditions based on observed 

reductions in visibility impairment in 

the past. Future visibility projections 

must be directly tied to projections of 

future emissions, and anticipated 

reductions due to federal and state 

requirements. Current 5-yr average 

(2010–2014) observed visibility 

conditions are 21.8 dv at Caney Creek 

and 21.6 dv at Upper Buffalo. Any 

future improvements in overall 

visibility conditions at the Arkansas 

Class I areas between now and 2018 will 

be due to future emission reductions 

during that time period. Commenters 

have not provided any specific 

information suggesting anticipated 

enforceable emission reductions from 

those Arkansas point sources with 

significant visibility impacts or other 

sources that would result in the almost 

2 dv visibility improvement by 2018 

projected by the commenter at Caney 

Creek in their statistical analysis. 

Furthermore, as discussed above, any 

anticipated emission reductions from 

sources in other states do not relieve 

Arkansas of its regional haze 

obligations. The BART requirements 

under § 51.308(e) must be met for those 

specific sources that meet the BART 

criteria and contribute to visibility 

impairment. The determination of 

whether an RPG and the emission 

limitations and other control measures 

upon which it is based constitute 

reasonable progress is made by 

conducting certain analyses and 


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355 64 FR at 35732. 

356 2002 CENRAP modeled SO2 emissions for 

Flint Creek were 11,165 tpy and 2018 CENRAP 

modeled SO2 emissions were 2,896 tpy, an assumed 

75% reduction in emissions. 

meeting the requirements under 

§ 51.308(d)(1). 

The RPGs are an analytical tool the 

state and we use to evaluate whether the 

measures in the implementation plan 

are sufficient to achieve reasonable 

progress. What is enforceable under the 

RH rule are the emission limitations and 

other control measures that apply to 

specific sources, and upon which the 

RPGs are based. Since the emission 

limitations we are requiring in our FIP 

for specific Arkansas sources (which is 

what our revised RPGs are based upon) 

are not currently being achieved, we 

disagree that visibility at the Class I 

areas has already improved beyond 

what we would require in our FIP and 

that our FIP is therefore unjustified and 

unwarranted. The emission reductions 

required in this action will result in 

significant visibility improvements at 

the Class I areas beyond what is 

currently being achieved or observed. 

As discussed elsewhere throughout this 

final rule, the commenter’s 

photochemical modeling analysis 

provides an additional demonstration 

that the controls required in this action 

result in visibility benefits beyond 

current observed visibility conditions 

and serve to accelerate progress towards 

natural visibility conditions. 

8. Reasonable Progress Goals 

Comment: EPA’s proposed RPGs are 

more stringent than Arkansas’ proposed 

RPGs in its 2008 Regional Haze SIP, 

which would have ensured that 

Arkansas is on track to achieve natural 

visibility conditions by 2064. Arkansas 

is reducing regional haze in its Class I 

areas at a higher rate than both the URP, 

which was approved by EPA, and 

Arkansas’ initial proposed RPGs. As 

indicated by the URP, Arkansas is well 

on track to reaching natural visibility 

conditions by 2064 and more stringent 

RPGs than those in Arkansas’ 2008 

Regional Haze SIP are not necessary. 

EPA should withdraw the Proposed FIP 

and ensure that revised RPGs in any 

subsequent plan are within the scope of 

EPA’s authority to address impairment 

of visibility. 

The differences in projected 2018 

visibility conditions at Caney Creek and 

Upper Buffalo that are attributable to all 

of the proposed FIP controls—including 

both FIP BART and FIP reasonable 

progress requirements—will be 

imperceptibly small (i.e., improvements 

of, at most, 0.21 dv and 0.19 dv, 

respectively, at Caney Creek and Upper 

Buffalo). The minimal visibility 

improvements that EPA’s proposed 

reasonable progress emission control 

requirements would produce would 

come at exorbitant costs. Additionally, 

even the negligible changes in visibility 

represented by EPA’s proposed revised 

RPGs are greatly overstated because 

some controls will not be in place until 

after 2018. 

Commenters also state that the 

methodology utilized by EPA in 

estimating the RPGs is oversimplified 

and inaccurate. EPA chose a method of 

determining RPGs that is admittedly 

inferior and less sophisticated than the 

alternative approach, which EPA 

rejected in Arkansas but used in Texas: 

CAMx photochemical modeling. EPA 

admits that it has not performed its own 

modeling in a manner adequate to 

develop ‘‘refined numerical RPGs.’’ 

Some commenters stated that EPA used 

CALPUFF, which is not a 

photochemical grid model, to develop a 

‘‘quick-and-dirty’’ RPG analysis in the 

proposed Rule. 

Response: As we discuss in more 

detail elsewhere in our response to 

comments, we agree that Arkansas 

proposed RPGs in its 2008 regional haze 

SIP that fell below the URP. However, 

in our 2012 rulemaking,355 we made a 

finding that Arkansas did not complete 

a reasonable progress analysis and 

therefore did not properly demonstrate 

that additional controls were not 

reasonable under 40 CFR 

51.308(d)(1)(i)(A). Thus we disapproved 

the RPGs Arkansas established for 

Caney Creek and Upper Buffalo. In our 

proposed rulemaking, we completed the 

reasonable progress analysis and 

established revised RPGs, since we have 

not received a revised SIP to correct the 

portions of the SIP submittal we 

disapproved. As discussed in our 

proposal and in our RTC document, we 

focused our reasonable progress analysis 

on the Entergy Independence facility 

because of its significant emissions of 

NOX and SO2 and its large potential to 

impact visibility at nearby Class I areas. 

We determined that cost-effective 

controls were available for units at this 

facility and that they would result in 

significant visibility benefits. We 

respond to specific comments 

concerning the visibility benefits from 

controls on the Independence facility in 

separate responses to comments. We 

also completed five-factor BART 

analyses and determinations for subjectto-BART facilities where we had 

previously disapproved the BART 

determination in the 2008 Arkansas 

regional haze SIP. Our proposed RPGs 

reflected the visibility benefits 

anticipated from the implementation of 

controls across the subject-to-BART 

facilities and the Independence facility 

required in this action. As we discuss in 

our proposal and in response to 

comments, we have determined that 

these controls are cost-effective and 

result in significant visibility benefits 

that provide for progress towards the 

goal of natural visibility conditions. As 

we discuss below in a separate response 

to comment, after considering 

comments received, we agree that the 

RPGs should reflect anticipated 

visibility conditions at the end of the 

implementation period in 2018 rather 

than the anticipated visibility 

conditions once the FIP has been fully 

implemented. We are finalizing RPGs 

that represent the visibility conditions 

anticipated on the 20% worst days at 

Caney Creek and Upper Buffalo by 2018. 

We disagree with the commenter that 

the amount of visibility improvement 

due to our proposed FIP is 

‘‘insignificant.’’ We address comments 

concerning the perceptibility of 

visibility improvements in response to 

comments elsewhere. The required 

controls are estimated to improve 

overall visibility benefits compared to 

the CENRAP projected visibility 

conditions for 2018 by approximately 

0.2 deciviews, a reduction in light 

extinction of about 2 Mm¥1 at Caney 

Creek and 1.8 Mm¥1 at Upper Buffalo. 

Once fully implemented, the required 

controls to meet the BART 

requirements, as well as required 

controls on the Independence facility 

result in an approximate 2% 

improvement in overall visibility 

conditions projected by CENRAP at both 

Caney Creek and Upper Buffalo on the 

20% worst days. Our technical record 

demonstrates that the required controls 

reduce impacts from these sources and 

result in meaningful visibility benefits 

towards the goal of natural visibility 

conditions. The required controls 

reduce the projected visibility 

impairment due to all Arkansas point 

sources by 50% at Caney Creek and 

50% at Upper Buffalo. We note that the 

required controls actually result in 

larger visibility improvements than 

calculated here because the CENRAP 

projections already included an 

assumption of large emission reductions 

due to SO2 BART at Flint Creek, as well 

as NOX controls at White Bluff and Flint 

Creek.356

We disagree with the commenter that 

our proposed RPGs overstated the 

visibility benefit of controls or that they 

are inaccurate. In our proposal, we 

acknowledged that the methodology we 

utilized to estimate the revised RPGs is 


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not as refined as developing an updated 

model projection. However, it allows us 

to translate the emission reductions 

contained in the proposed FIP into 

quantitative RPGs, based on modeling 

previously performed by the CENRAP. 

These proposed RPGs provided an 

estimate of the visibility benefit of all 

the required controls compared to the 

2018 visibility conditions projected by 

the state and established in their SIP 

that would result without the required 

controls. After considering comments 

received, we agree that the RPGs should 

reflect anticipated visibility conditions 

at the end of the implementation period 

in 2018 rather than the anticipated 

visibility conditions once the FIP has 

been fully implemented, and have 

accordingly revised the 2018 RPGs. 

RPGs, unlike the emission limits that 

apply to specific reasonable progress 

and BART sources, are not directly 

enforceable. Rather, the RPGs are an 

analytical framework considered by us 

in evaluating whether measures in the 

implementation plan are sufficient to 

achieve reasonable progress. Our FIP 

imposes emissions limitations that we 

conclude to be necessary under the CAA 

for the first planning period. Ideally, 

these controls would be installed and 

the emission limitations achieved, so 

the visibility improvements can be 

realized and built on in a subsequent 

comprehensive periodic SIP revision 

(see 40 CFR 51.308(f)). Arkansas may 

choose to use these RPGs for purposes 

of its progress report (along with a 

consideration for what controls had 

already been implemented and what 

controls would be implemented in the 

near future), or may develop new RPGs 

for approval by us along with its 

progress report, based on new modeling 

or other appropriate techniques, in 

accordance with the requirements of 40 

CFR 51.308(d)(1) in evaluating the 

adequacy of their SIP (or this FIP) to 

meet the established RPGs. 

We discuss our selection of the 

CALPUFF model for evaluating singlesource visibility impacts in a separate 

response to comment above. In the 

response, we also explain the model 

selection for our Texas action and refer 

the reader to our detailed explanation in 

the RTC that accompanies that action. 

Commenters are incorrect and confuse 

the single-source visibility analysis used 

to evaluate the visibility benefit of 

controls on a specific source with the 

assessment of overall visibility 

conditions. We did not use the 

CALPUFF modeling to develop the new 

reasonable progress goals we establish 

in this rulemaking. The RPGs are based 

on adjusting the CENRAP 2018 CAMx 

photochemical modeling based on 

source apportionment modeling results 

and emission inventory data. As we 

stated in the proposed rulemaking, we 

did not perform additional 

photochemical modeling to directly 

model the new projected visibility goals 

due to the time and resource demands 

associated with photochemical 

modeling. The commenters are also 

incorrect in their comparison of 

approaches for establishing new RPGs 

between this action for Arkansas and 

our previous action in Texas. For both 

Texas and Arkansas, we utilized the 

CENRAP 2018 CAMx modeling that 

estimated the 2018 RPGs and then 

adjusted those RPGs to account for 

estimated visibility improvement due to 

required controls. In neither case did we 

perform a full photochemical modeling 

analysis to model all the required 

controls and project the future visibility 

conditions. In both cases, the 2018 RPGs 

were adjusted based on a scaling of the 

source apportionment model results and 

emission inventory changes. 

Comment: The demonstration 

methodology used by EPA is 

unscientific. EPA used a ratio of 

emission rates from BART sources to 

Arkansas point sources to scale the 

modeled predicted haze index. First, 

there is no evidence to prove that the 

CAMx predicted modeling results are 

linearly correlated with emission rates. 

In fact, the CAMx modeling 

fundamentally is based on 

photochemical reactions. Therefore, the 

relationship between variation in the 

emission rates and predicted 

concentration is complicated. Second, a 

deciview is a logarithmic scale based on 

the concept that one deciview is the 

minimum change in the visibility 

perceptible to a human observer. As 

such, deciviews cannot be added or 

subtracted directly. Therefore, 

fractioning or scaling deciviews based 

on emission rates is illogical. 

Another commenter was supportive of 

our approach, stating that in Texas, the 

model results were used to demonstrate 

that the overall change in species 

concentrations was very nearly linearly 

proportional to the change in emission 

levels for an individual source (with 

very high linear correlation coefficients 

near 1.0). This strongly supports the use 

of the emission scaling approach for 

Arkansas. If the CAMx model were used 

to determine the impact of emission 

controls on a single source in Arkansas 

(such as Independence), it is therefore 

expected that the modeled reductions in 

sulfate and nitrate concentrations at 

each of the Class I areas will be very 

nearly proportional to the SO2 and NOX

concentration reductions. In other 

words, the emission scaling approach 

has been shown to be mathematically 

sound and quite appropriate, especially 

considering the resources that would be 

required to exercise CAMx separately 

for each control measure at each 

evaluated source. 

Response: We disagree with the 

comments that the methodology used to 

estimate overall visibility benefits from 

all required controls control level 

emissions was unreasonable or 

unscientific. We agree with comments 

that the approach we followed is 

reasonable and based on a scaling of 

visibility extinction components due to 

Arkansas point sources in proportion to 

emission changes from the required 

controls at Arkansas point sources. The 

commenter is incorrect in suggesting 

that we developed a linear relationship 

between emissions and deciviews and 

then commenting that this ‘‘fractioning 

or scaling of deciviews’’ is flawed 

because the relationship between light 

extinction and deciviews is exponential. 

We properly developed a linear 

relationship between emissions and 

light extinction (inverse Megameters), 

not deciviews. 

We agree with the commenters, that 

in general, the relationship between 

downwind concentrations and 

emissions can be complicated and nonlinear due to complex chemistry, 

including the fact that reductions in 

sulfur emissions can result in an 

increase in ammonium nitrate. For 

estimating the total visibility benefit 

from all controls and estimating a new 

reasonable progress goal that reflects 

those controls, we relied on the 

CENRAP’s 2018 CAMx modeling 

results, including source apportionment 

results, and the projected emission 

inventories, and scaled the results as 

described in the TSD, similar to what 

was done in our previous action in 

Arizona and Texas. While we 

acknowledge that this approach is not as 

refined an estimate as would be attained 

in performing a new photochemical 

modeling run, it is based on scaling to 

adjust earlier photochemical modeling 

results that took into account the 

complex chemistry that impacts the 

overall visibility. The uncertainty in the 

visibility benefit from these controls 

introduced by the linear extrapolation 

does not impact the overall conclusions. 

Furthermore, in our technical analysis 

developed to support our action on 

Texas regional haze, we observed that 

for each facility and Class I area, the 

available modeled visibility impact was 

linear with respect to emissions with 


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66410 Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 

357See 81 FR 296, 335 and the FIP TSD 

(document ID: EPA–R06–OAR–2014–0754–0007). 

358See Entergy CAMx Results 2015–1124_

FINAL.xls. 

359 40 CFR 51.308(d)(1). 360 40 CFR 51.308(d)(1)(iv). 361 40 CFR 51.308(d)(1)(ii). 362 40 CFR 51.308(g)–(h). 363 ‘‘Guidance for Setting Reasonable Progress 

Goals Under the Regional Haze Program,’’ at 5–2. 

364We discuss in section II.A of this final rule the 

history of the state’s submittals and our actions. 

365These RPGs are calculated using the same 

methodology described in our proposal and TSD. 

See ‘‘CACR UPBU RPG analysis 2018.xlsx’’ for 

additional information on the calculation of the 

RPGs. 

366 80 FR 18944, 18998. 

367 40 CFR 51.308(d)(1)(v). 

368 64 FR at 35733 and 40 CFR 51.308(d)(1)(v). 

high correlation.357 Following this 

approach we estimated that when fully 

implemented, the required controls 

would result in a reduction in light 

extinction of about 2 Mm¥1 at Caney 

Creek and 1.8 Mm¥1 at Upper Buffalo 

on the 20% worst days. As discussed 

elsewhere, Entergy Arkansas submitted 

additional CAMx modeling with their 

comments. This photochemical 

modeling projects a 2.95 Mm¥1

reduction at Caney Creek and 1.54 

Mm¥1 reduction at Upper Buffalo when 

compared to the Entergy’s base case 

modeling for 2018 for the 20% worst 

days.358

Comment: Even the negligible 

changes in visibility represented by 

EPA’s proposed revised RPGs are greatly 

overstated because the bulk of the EPAprojected visibility improvements are 

due to proposed SO2 emission limits for 

BART and reasonable progress that have 

a five-year compliance deadline and 

thus will not become operative until at 

least 2020. No sound basis exists for the 

projections of visibility improvements 

by 2018 that EPA sets out in the 

proposed rule. Those EPA projections 

are inaccurate and unsupportable. 

In this regard, EPA fails to explain 

why (a) the Agency may permissibly use 

a concededly oversimplified and 

inaccurate shortcut methodology for 

calculating RPGs in its FIP, on the 

grounds that EPA otherwise would have 

to conduct time-consuming and 

complicated modeling, see id., but (b) 

Arkansas and other states apparently are 

held to a much higher standard for their 

RPG analyses, see id. In proposing and 

promulgating a FIP for Arkansas, EPA 

merely stands in the state’s shoes. 

Accordingly, if EPA may lawfully 

comply with the CAA and the regional 

haze rules by conducting and relying on 

this sort of analysis that is ‘‘not refined’’ 

but (purportedly) sufficient to support 

its FIP’s RPGs, then states also may do 

so to support their SIPs’ RPGs. On the 

other hand, to the extent EPA does not 

believe that RPGs based on such an 

abbreviated analysis would be 

approvable if submitted by a state in a 

SIP, EPA cannot lawfully promulgate 

the RPGs that it proposes based on the 

analysis presented in its proposed rule. 

Response: We proposed RPGs for the 

20% worst days for Caney Creek and 

Upper Buffalo of 22.27 dv and 22.33 dv, 

respectively that reflected the 

anticipated visibility conditions 

resulting from the combination of 

control measures from the approved 

portion of the 2008 Arkansas Regional 

Haze SIP and our FIP proposal. After 

considering these comments, we agree 

that the RPGs should reflect anticipated 

visibility conditions at the end of the 

implementation period in 2018 rather 

than the anticipated visibility 

conditions once the FIP has been fully 

implemented. This approach is 

consistent with the purpose of RPGs and 

the direction provided in our 2007 

Reasonable Progress Guidance. 

Section 169B(e)(1) of the CAA 

directed the Administrator to 

promulgate regulations that ‘‘include[e] 

criteria for measuring ‘reasonable 

progress’ toward the national goal.’’ 

Consequently, we promulgated 40 CFR 

51.308(d)(1) as part of the Regional Haze 

Rule. This provision directs states to 

develop RPGs for the most and least 

impaired days to ‘‘measure’’ the 

progress that will be achieved by the 

control measures in the state’s long-term 

strategy ‘‘over the period of the 

implementation plan.’’ 359 The current 

implementation period ends in 2018. 

RPGs ‘‘are not directly enforceable’’ like 

the emission limitations in the longterm strategy.360 Rather, they fulfill two 

key purposes: (1) Allowing for 

comparisons between the progress that 

will be achieved by the state’s long-term 

strategy and the URP,361 and (2) 

providing a benchmark for assessing the 

adequacy of a state’s SIP in 5-year 

periodic reports.362 Consequently, in 

our 2007 Reasonable Progress Guidance, 

we indicated that states could consider 

the ‘‘time necessary for compliance’’ 

factor by ‘‘adjust[ing] the RPG to reflect 

the degree of improvement in visibility 

achievable within the period of the first 

SIP if the time needed for full 

implementation of a control measure (or 

measures) will extend beyond 2018.’’ 363

In other words, RPGs need not reflect 

the visibility improvement anticipated 

from all of the control measures deemed 

necessary to make reasonable progress 

(as a result of the four-factor analysis) 

and included in the long-term strategy. 

In this instance, we are taking final 

action on the Arkansas Regional Haze 

FIP 9 years after the state’s initial SIP 

submission was due.364 As a result, only 

some of the control measures that we 

have determined are necessary to satisfy 

the BART and reasonable progress 

requirements will be installed by the 

end of 2018. Some controls will not be 

installed until 2021. Because RPGs are 

unenforceable analytical benchmarks, 

we think that it is appropriate to follow 

the recommendation in our 2007 

Reasonable Progress Guidance and 

finalize RPGs that represent the 

visibility conditions anticipated on the 

20% worst days at Caney Creek and 

Upper Buffalo by 2018. These RPGs are 

listed in the table below: 365

TABLE 21—REASONABLE PROGRESS

GOALS FOR 2018 FOR CANEY

CREEK AND UPPER BUFFALO

Class I area 

2018 RPG 

20% Worst 

days (dv) 

Caney Creek ......................... 22.47 

Upper Buffalo ........................ 22.51 

We disagree with the commenter that 

the proposed RPGs overstated the 

visibility benefit of controls or that they 

are inaccurate. In our proposal, we 

acknowledged that the methodology we 

utilized to estimate the RPGs is not as 

refined as developing an updated model 

projection. However, it allows us to 

translate the emission reductions 

contained in the proposed FIP into 

quantitative RPGs, based on modeling 

previously performed by the 

CENRAP.366 The proposed RPGs 

provided an estimate of the visibility 

benefit of all the required controls 

compared to the 2018 visibility 

conditions projected by the state and 

established in their SIP that would 

result without the required controls. 

Our final RPGs, calculated using the 

same methodology, reflect the 

anticipated visibility conditions at the 

end of the implementation period in 

2018 and the visibility benefit from 

those controls required to be 

implemented by the end of 2018. RPGs, 

unlike the emission limits that apply to 

specific reasonable progress and BART 

sources, are not directly enforceable.367

Rather, the RPGs are an analytical 

framework considered by us in 

evaluating whether measures in the 

implementation plan are sufficient to 

achieve reasonable progress.368 Our FIP 

imposes emissions limitations that we 

conclude to be necessary under the CAA 

for the first planning period. Ideally, 

these controls would be installed and 

the emission limitations achieved, so 


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369 77 FR 14604. 

the visibility improvements can be 

realized and built on in a subsequent 

comprehensive periodic SIP revision 

(see 40 CFR 51.308(f)). Arkansas may 

choose to use these RPGs for purposes 

of its progress report (along with a 

consideration for what controls had 

already been implemented and what 

controls would be implemented in the 

near future), or may develop new RPGs 

for approval by us along with its 

progress report, based on new modeling 

or other appropriate techniques, in 

accordance with the requirements of 40 

CFR 51.308(d)(1) in evaluating the 

adequacy of their SIP (or this FIP) to 

meet the established RPGs. 

We disagree that Arkansas would be 

held to a higher standard or that the 

methodology utilized by EPA to adjust 

the RPGs would not be approvable if 

submitted by a state. The approach 

followed by EPA in this action, using 

scaling to adjust the modeled RPGs 

based on photochemical source 

apportionment model results is 

reasonable and meets the requirements 

of the Regional Haze Rule. In our 2012 

rulemaking,369 we made a finding that 

Arkansas did not complete a reasonable 

progress analysis and therefore did not 

properly demonstrate that additional 

controls were not reasonable under 40 

CFR 51.308(d)(1)(i)(A). Thus we 

disapproved the RPGs Arkansas 

established for Caney Creek and Upper 

Buffalo. In our proposed rulemaking, we 

completed the reasonable progress 

analysis and established revised RPGs 

using the methodology described above, 

since we have not received a revised SIP 

to correct the portions of the SIP 

submittal we disapproved. 

9. Additional Modeling Comments 

Comment: We received additional 

specific modeling comments concerning 

emission rates modeled to assess 

baseline visibility impacts for 

Independence, White Bluff and Flint 

Creek. We also received separate 

comments concerning our modeling 

analysis and assessment of NOX controls 

on Lake Catherine, White Bluff and 

Independence. 

Response: We address these 

comments in our RTC document. 

K. Legal 

We received several comments on 

EPA’s legal authority to promulgate a 

FIP under the Regional Haze Rule, and, 

more specifically, to address the Rule’s 

reasonable progress requirements. 

Below is a summary of some of the more 

significant comments. For a more 

detailed explanation, please refer to the 

RTC document that is a part of the 

docket for this rulemaking. 

We received comments that EPA is 

prohibited from requiring controls for 

this planning period if they cannot be 

installed during this planning period. 

We disagree with these comments. The 

CAA establishes our authority and 

responsibility to promulgate a FIP that 

addresses the requirements of the 

regional haze program where a State’s 

SIP submission fails to meet the 

program requirements. Although the 

first planning period, ending in 2018, 

includes RPGs specific to that planning 

period, there is no limitation in the CAA 

or the Regional Haze Rule that controls 

contained in a SIP (or a FIP) must be 

fully implemented by the end of the 

planning period. As both the long-term 

strategy and BART requirements may 

extend beyond the first planning period, 

it follows that EPA has FIP authority to 

fill in ‘‘gaps’’ or ‘‘inadequacies’’ related 

to those components irrespective of 

whether controls can be put into place 

by 2018. In addition, any emission 

limitations that prove to be required by 

the CAA for the first planning period 

need to be achieved at their soonest 

opportunity, not delayed, deferred, or 

avoided for later planning periods when 

even further progress may be required in 

order to achieve the national visibility 

goal. 

We also received comments that we 

had no legal basis for requiring 

alternative proposals for SO2 and NOX

control measures that would address the 

regional haze requirements for White 

Bluff Units 1 and 2 and Independence 

Units 1 and 2 for this planning period 

to achieve greater reasonable progress 

than the BART and reasonable progress 

requirements that EPA has proposed for 

the first planning period. Our response 

explains our analysis of Entergy’s fourunit approach and clarifies how our 

evaluation of that approach was 

consistent with the Regional Haze 

Rule’s BART alternative and reasonable 

progress requirements. 

In addition, we received several 

comments that our proposed FIP was 

not in keeping with the legal 

requirements for reasonable progress 

and long term strategy as spelled out in 

the Regional Haze Rule and EPA 

Guidance. We disagree and explain in 

more detail in the RTC document that 

we disapproved the reasonable progress 

determination Arkansas submitted in 

2012 because the State did not conduct 

the required four-factor analysis. The 

CAA requires us to stand in the State’s 

shoes and promulgate a FIP that 

addresses the requirements of the 

Regional Haze Rule that we 

disapproved, including reasonable 

progress and the long term strategy for 

Arkansas’ Class I areas. 

We also received comments that our 

proposed FIP did not take into account 

the leading role of the state in 

developing a plan that addresses the 

regional haze program and thus is not in 

keeping with cooperative federalism. 

We disagree that EPA ignored the 

principles of cooperative federalism. 

Arkansas did develop a regional haze 

plan. We reviewed it and partially 

approved and disapproved the plan in 

2012. The CAA creates a mandatory 

duty for EPA to either approve a state 

SIP revision submittal that corrects the 

deficiency or promulgate a FIP within 

two years of the effective date of the 

disapproval of a state plan. 

We received comments that EPA does 

not have authority to finalize a FIP after 

two years have elapsed from our initial 

disapproval of the Arkansas Regional 

Haze SIP. We describe in more detail in 

the RTC document our disagreement 

with this interpretation of what is 

required under the Clean Air Act. The 

Tenth Circuit has upheld EPA’s 

authority to finalize a Regional Haze FIP 

after the two years have passed for EPA 

to act on Oklahoma’s Regional Haze SIP. 

We also received comments that our 

proposed FIP was not in keeping with 

Executive Orders 12866 and 13211. Our 

response is that our proposed action is 

not subject to Executive Order 13211 

because it is not a ‘‘significant 

regulatory action’’ under Executive 

Order 12866; therefore, the proposed 

FIP is not a rule of general applicability 

because its requirements apply and are 

tailored to only seven individually 

identified facilities. Thus, it is not a 

‘‘rule’’ or ‘‘regulation’’ within the 

meaning of E.O. 12866 and this action 

is not a ‘‘regulatory action’’ subject to 

12866. Since E.O. 13211 applies only to 

‘‘significant regulatory actions’’ under 

E.O. 12866, this action is not subject to 

review under E.O. 13211.28 Evaluation 

of the proposal under E.O. 13211’s 

criteria is therefore not required. 

We respond in greater detail in the 

RTC document to comments that EPA 

did not adequately consider costs to 

ratepayers as is required under Arkansas 

law in developing air regulations. States 

are under an obligation to submit a 

Regional Haze SIP to EPA which 

complies with federal requirements. 

While states enjoy flexibility in 

developing a SIP and can meet 

additional state requirements as long as 

the federal requirements are satisfied, in 

the event that EPA must step in and 

create a Federal Implementation Plan, 

we must meet all federal requirements. 

We are not subject to state law 

requirements related to how the cost 


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370 80 FR at 18998. 

371See ‘‘2006 Guidance for SIP Submissions to 

Meet Current Outstanding Obligations Under 

Section 110(a)(2)(D)(i) for the 8-Hour Ozone and 

PM2.5 NAAQS’’ at pages 9–10. 

372 77 FR 14604. 373 40 CFR 51.308(d)(3)(i). 

analyses must be conducted or what 

specific factors need to be considered. 

We did consider costs in great detail to 

ensure that the controls required by the 

FIP are cost-effective, appropriate in 

light of the visibility reductions 

achieved, and consistent with 

expectations in other SIPs and FIPs. 

We received several general 

comments including a claim that 

documents that EPA relied for its 

rulemaking were not in the docket. As 

explained more fully in our RTC 

document, the documents referred to are 

briefing sheets and did not serve as the 

basis for EPA’s decision making. The 

docket contains all of the documents 

that serve as our basis for our 

rulemaking for Arkansas Regional Haze. 

L. Interstate Visibility Transport 

Comment: The good neighbor 

visibility provision in 42 U.S.C. 

7410(a)(2)(D)(i)(II) prohibits interference 

with ‘‘measures’’ required to be 

included in another State’s 

implementation plan to protect 

visibility. EPA has not demonstrated 

that any of these sources in its FIP 

proposal are interfering with any 

visibility control measure in any other 

state’s SIP. In its FIP proposal, EPA 

states that the Arkansas SIP did not 

ensure that emissions from Arkansas 

sources ‘‘do not interfere with other 

states’ visibility programs as required by 

section 110(a)(2)(D)(i)(II) of the 

CAA.’’ 370 The visibility protection 

requirement of section 110(a)(2)(D)(i)(II) 

does not protect against interference 

with either other states ‘‘efforts’’ or 

other states ‘‘programs.’’ Unlike the 

language in section 110(a)(2)(D)(i)(I), 

which prohibits emissions that 

contribute significantly to 

nonattainment or maintenance of a 

NAAQS in another state, the visibility 

protection requirement is narrower and 

only protects against interference with 

specific measures, that is, actions 

included in another state’s plan to 

achieve a visibility goal. Reasonable 

progress goals, projected deciview 

improvements from regional efforts, and 

the like are goals or standards; they are 

not ‘‘measures’’ taken by or enforced by 

a state. There is nothing in the record 

demonstrating that any of the sources in 

the FIP proposal interfere with any 

measure included in any other state’s 

SIP for the purpose of protecting or 

improving visibility. To the extent that 

EPA’s proposed interstate visibility 

transport FIP is not based on direct 

interference with a control measure in 

another state’s regional haze SIP (in 

contrast to interference with a regional 

haze related visibility goal), EPA’s 

interpretation is contrary to the clear 

and express language of Section 110. 

EPA’s interpretation also is contrary to 

the CAA’s clear direction that each state 

is to determine its own emission limits, 

schedules of compliance and other 

measures for sources in that state for 

purposes of visibility protection under 

section 169A. EPA’s interpretation 

would impermissibly give one state the 

power to control another state’s regional 

haze SIP decisions, including its BART 

and reasonable progress determinations. 

Finally, even if the CAA’s good 

neighbor visibility provision required a 

SIP to contain emission limits for 

sources that contribute to visibility 

impairment at a Class I area in another 

state, EPA has not demonstrated that 

any of the controls in its FIP proposal 

are ‘‘necessary’’ for that purpose, 

considering based on the uncertainty in 

the modeling that these controls will 

result in actual visibility improvements. 

Response: Section 110(a)(2)(D)(i)(II) 

does not explicitly define what is 

required in SIPs to prevent the 

prohibited impact on visibility in other 

states nor does it explicitly define how 

to determine if a state’s emissions are 

interfering with another state’s measures 

to protect visibility. We have interpreted 

this statutory requirement as providing 

that a Regional Haze SIP that requires 

emission reductions consistent with the 

assumptions the relevant RPO used to 

model the RPGs for Class I areas in other 

states satisfies a state’s obligation to 

ensure that its own emissions do not 

interfere with another state’s visibility 

measures. States may rely on a fully 

approved Regional Haze SIP to 

demonstrate that a SIP for 8-hour ozone 

or PM2.5 contains adequate provisions to 

prohibit emissions that interfere with 

visibility measures in other states.371

Arkansas chose to address the 

interstate visibility transport 

requirement under section 

110(a)(2)(D)(i)(II) by relying on its 2008 

Regional Haze SIP submittal to achieve 

the emissions reductions necessary to 

meet this requirement. However, due to 

our previous partial disapproval of this 

submittal,372 the Arkansas SIP does not 

currently include all of the emission 

reductions Arkansas agreed to achieve 

in its RPO process. Arkansas is a 

member state of CENRAP, the regional 

planning committee on regional haze. 

Each CENRAP state based its regional 

haze plan and RPGs on the CENRAP 

modeling, which was based in part on 

the emissions reductions each state 

intended to achieve by 2018. Within the 

CENRAP process, Arkansas promised to 

achieve emission reductions 

corresponding to BART, and these 

emissions reductions were included in 

the CENRAP modeling used by the 

participating states to develop their 

RPGs and Regional Haze SIPs. However, 

EPA previously disapproved some of 

Arkansas’ BART determinations; 

therefore, the State’s SIP does not 

currently provide for all the emissions 

reductions that Arkansas itself 

determined to be necessary to meet the 

interstate visibility transport 

requirement. Because Arkansas has not 

provided any other analysis or 

explanation of how the Arkansas SIP 

fulfills the requirement of 

110(a)(2)(D)(i)(II), it follows that the 

Arkansas SIP does not contain adequate 

provisions to prohibit emissions that 

would interfere with other states’ 

visibility protection measures. 

We disagree with the commenter’s 

contention that our interpretation is 

contrary to the CAA because the Act 

gives clear direction that each state is to 

determine its own emission limits, 

schedules of compliance and other 

measures for sources in that state for 

purposes of visibility protection under 

section 169A. The commenter states that 

our interpretation would impermissibly 

give one state the power to control 

another state’s regional haze SIP 

decisions. However, the commenter’s 

interpretation is inconsistent with 

section 110(a)(2)(D)(i)(II)’s ‘‘good 

neighbor’’ provision, which requires 

states to prohibit emissions that 

interfere with other states’ measures to 

protect visibility. This statutory 

requirement anticipates that a state may 

be required to adjust its own emissions 

based on the impacts of those emissions 

on other states. Our Regional Haze Rule, 

which was promulgated through noticeand-comment rulemaking in 1999, also 

requires that states develop 

‘‘coordinated emission management 

strategies’’ when necessary to prevent 

interstate visibility impairment.373

Thus, while the CAA and our 

regulations do not allow one state to 

‘‘control’’ another’s regional haze 

planning, they do contemplate that a 

state may be required to prohibit 

emissions that interfere with visibility 

in another state’s Class I areas. 

As stated above, Arkansas elected to 

address the interstate visibility transport 

requirement under section 

110(a)(2)(D)(i)(II) by relying on the 

BART determinations that are part of its 


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374See, e.g., Colorado (76 FR 22036 (April 20, 

2011)), Idaho (76 FR 36329 (June 22, 2011)), and 

New Mexico (76 FR 52388 (August, 22, 2011)). 

375We’ve allowed states to rely on their approved 

regional haze plan to meet the requirements of the 

visibility component of 110(a)(2)(D)(i)(II) because 

the regional haze plan achieved at least as much 

emissions reductions as projected by the RPO 

modeling. See 76 FR 34608, June 14, 2011 

(California); 79 FR 60985, October 9, 2014 (New 

Mexico); 76 FR 36329, June 22, 2011 (Idaho); and 

76 FR 38997, July 5, 2011 (Oregon). 

Regional Haze SIP submittal. Arkansas 

could have elected to address the 

interstate visibility transport 

requirement under section 

110(a)(2)(D)(i)(II) by other means; we 

have elsewhere determined that states 

may also be able to satisfy the 

requirements of CAA section 

110(a)(2)(D)(i)(II) with something less 

than an approved Regional Haze SIP.374

In other words, an approved Regional 

Haze SIP is not the only possible means 

to satisfy the requirements of CAA 

section 110(a)(2)(D)(i)(II) with respect to 

visibility; however such a SIP could be 

sufficient.375 The approved portion of 

the Arkansas Regional Haze SIP and our 

Regional Haze FIP together will ensure 

emissions reductions from Arkansas 

sources consistent with the assumptions 

used in the CENRAP modeling and 

meets Arkansas’ obligations to address 

the interstate visibility transport 

requirement under section 

110(a)(2)(D)(i)(II). 

We address elsewhere in this 

document comments contending that 

there is uncertainty in the CALPUFF 

modeling and uncertainty that our 

proposed controls will result in actual 

visibility improvements. 

VI. Final Action 

We are finalizing a FIP to remedy the 

deficiencies in the Arkansas Regional 

Haze SIP and Interstate Visibility 

Transport SIP to address the visibility 

transport requirement under section 

110(a)(2)(D)(i)(II) for the 1997 8-hour 

ozone and PM2.5 NAAQS. 

A. Regional Haze 

Our final FIP includes SO2, NOX, and 

PM emission limits for specific emission 

units in Arkansas to address the BART 

requirements. The affected emission 

units are the AECC Bailey Unit 1; AECC 

McClellan Unit 1; AEP Flint Creek Unit 

1; Entergy White Bluff Units 1, 2, and 

Auxiliary Boiler; Entergy Lake Catherine 

Unit 4; and Domtar Ashdown Mill 

Power Boilers No. 1 and 2. In addition, 

we are requiring SO2 and NOX controls 

under reasonable progress for Entergy 

Independence Units 1 and 2. We are 

also finalizing compliance schedules 

and testing, reporting and recordkeeping 

requirements for these emission units. 

Our final FIP requires the following 

emission limits for these emission units: 

TABLE 22—FINAL BART EMISSION LIMITS

Unit Final SO2 emission limit Final NOX emission limit Final PM emission limit 

Bailey Unit 1 .................................. 0.5% limit on sulfur content of fuel 

combusted.

887 lb/hr ........................................ 0.5% limit on sulfur content of fuel 

combusted. 

McClellan Unit 1 ............................. 0.5% limit on sulfur content of fuel 

combusted.

869.1 lb/hr a/705.8 lb/hr a .............. 0.5% limit on sulfur content of fuel 

combusted. 

Flint Creek Unit 1 ........................... 0.06 lb/MMBtu .............................. 0.23 lb/MMBtu .............................. EPA approved the state’s BART 

determination in March 12, 

2012 final action (77 FR 

14604). 

White Bluff Unit 1 ........................... 0.06 lb/MMBtu .............................. 0.15 lb/MMBtu b/671 lb/hr c ........... EPA approved the state’s BART 

determination in March 12, 

2012 final action (77 FR 

14604). 

White Bluff Unit 2 ........................... 0.06 lb/MMBtu .............................. 0.15 lb/MMBtu b/671 lb/hr c ........... EPA approved the state’s BART 

determination in March 12, 

2012 final action (77 FR 

14604). 

White Bluff Auxiliary Boiler ............ 105.2 lb/hr ..................................... 32.2 lb/hr ....................................... 4.5 lb/hr. 

Lake Catherine Unit 4 d .................. EPA approved the state’s BART 

determination in March 12, 

2012 final action (77 FR 14604).

0.22 lb/MMBtu .............................. EPA approved the state’s BART 

determination in March 12, 

2012 final action (77 FR 

14604). 

Domtar Ashdown Mill Power Boiler 

No. 1.

504 lb/day ..................................... 207.4 lb/hr ..................................... EPA approved the state’s BART 

determination in March 12, 

2012 final action (77 FR 

14604). 

Domtar Ashdown Mill Power Boiler 

No. 2.

91.5 lb/hr ....................................... 345 lb/hr ........................................ PM BART shall be satisfied by relying on the applicable PM 

standard under 40 CFR part 63, 

subpart DDDDD e

aEmission limit of 869.1 lb/hr applies to the natural gas-firing scenario; emission limit of 705.8 lb/hr applies to the fuel oil-firing scenario. 

bEmission limit of 0.15 lb/MMBtu applies when unit is operated at 50% or greater of the unit’s maximum heat input rating. 

cEmission limit of 671 lb/hr applies when the unit is operated at less than 50% of the unit’s maximum heat input rating. 

dEmission limit for NOX applies to the natural gas-firing scenario. The unit shall not burn fuel oil until BART determinations for SO2, NOX, and 

PM are promulgated for the unit for the fuel oil-firing scenario through EPA approval of a SIP revision or a FIP. eThe facility shall rely on the applicable PM standard under 40 CFR part 63, subpart DDDDD—National Emission Standards for Hazardous Air 

Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters, as revised, to satisfy the PM BART 

requirement. 

TABLE 23—FINAL REASONABLE PROGRESS EMISSION LIMITS FOR SOURCES NOT SUBJECT TO BART 

Unit Final SO2 emission limit Final NOX emission limit 

Independence Unit 1 ......................................... 0.06 lb/MMBtu .................................................. 0.15 lb/MMBtu a/671 lb/hr b


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TABLE 23—FINAL REASONABLE PROGRESS EMISSION LIMITS FOR SOURCES NOT SUBJECT TO BART—Continued 

Unit Final SO2 emission limit Final NOX emission limit 

Independence Unit 2 ......................................... 0.06 lb/MMBtu .................................................. 0.15 lb/MMBtu a/671 lb/hr b

aEmission limit of 0.15 lb/MMBtu applies when unit is operated at 50% or greater of the unit’s maximum heat input rating. 

bEmission limit of 671 lb/hr applies when the unit is operated at less than 50% of the unit’s maximum heat input rating. 

Based on our technical analysis, we 

have calculated the following RPGs for 

the 20% worst days for Arkansas’ Class 

I areas: 

TABLE 24—REASONABLE PROGRESS

GOALS FOR 2018 FOR CANEY

CREEK AND UPPER BUFFALO

Class I area 

2018 RPG 

20% Worst 

days (dv) 

Caney Creek ......................... 22.47 

Upper Buffalo ........................ 22.51 

B. Interstate Visibility Transport 

We are finalizing our determination 

that the control measures in the 

approved portion of the Arkansas 

Regional Haze SIP and our final FIP are 

sufficient to prevent Arkansas’ 

emissions from interfering with other 

states’ required measures to protect 

visibility. Thus, the combined measures 

from both plans satisfy the interstate 

transport visibility requirement of CAA 

section 110(a)(2)(D)(i)(II) for the 1997 8- 

hour ozone and the 1997 PM2.5 NAAQS. 

VII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is exempt from review by 

the Office of Management and Budget 

(OMB) because it imposes requirements 

that apply and are tailored to only six 

individual power plants (AECC Bailey; 

AECC McClellan; AEP Flint Creek; 

Entergy White Bluff; Entergy Lake 

Catherine; and Entergy Independence) 

and one paper mill in Arkansas (Domtar 

Ashdown Paper Mill). This FIP is not a 

rule of general applicability. Thus, it is 

not a ‘‘rule’’ or ‘‘regulation’’ within the 

meaning of E.O. 12866, and this action 

is not a ‘‘regulatory action’’ subject to 

12866. 

B. Paperwork Reduction Act (PRA) 

This action does not impose an 

information collection burden under the 

provisions of the PRA, 44 U.S.C. 3501 

et seq. Under the PRA, a ‘‘collection of 

information’’ is defined as a 

requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

persons * * *’’ 44 U.S.C. 3502(3)(A). 

Because the FIP applies to only seven 

facilities, the Paperwork Reduction Act 

does not apply. See 5 CFR 1320.3(c). 

C. Regulatory Flexibility Act (RFA) 

I certify that this action will not have 

a significant economic impact on a 

substantial number of small entities 

under the RFA. This action will not 

impose any requirements on small 

entities. This FIP will apply to seven 

facilities, none of which fall under the 

definition of small entities. 

D. Unfunded Mandates Reform Act 

(UMRA) 

EPA has determined that Title II of 

the UMRA does not apply to this rule. 

In 2 U.S.C. 1502(1) all terms in Title II 

of UMRA have the meanings set forth in 

2 U.S.C. 658, which further provides 

that the terms ‘‘regulation’’ and ‘‘rule’’ 

have the meanings set forth in 5 U.S.C. 

601(2). Under 5 U.S.C. 601(2), ‘‘the term 

‘rule’ does not include a rule of 

particular applicability relating to . . . 

facilities.’’ Because this rule is a rule of 

particular applicability relating to seven 

named facilities, EPA has determined 

that it is not a ‘‘rule’’ for the purposes 

of Title II of the UMRA. 

E. Executive Order 13132: Federalism 

This action does not have Federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. The final rule 

does not impose significant economic 

costs on state or local governments. 

Thus, Executive Order 13132 does not 

apply to the final rule. 

F. Executive Order 13175: Coordination 

With Indian Tribal Governments 

This action does not have tribal 

implications as specified in Executive 

Order 13175. This action applies to 

seven facilities in Arkansas and to 

Federal Class I areas in Arkansas. This 

action does not apply on any Indian 

reservation land, any other area where 

EPA or an Indian tribe has demonstrated 

that a tribe has jurisdiction, or nonreservation areas of Indian country. 

Thus, Executive Order 13175 does not 

apply to this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets Executive Order 

13045 as applying only to those 

regulatory actions that concern 

environmental health or safety risks that 

the EPA has reason to believe may 

disproportionately affect children, per 

the definition of ‘‘covered regulatory 

action’’ in section 2–202 of the 

Executive Order. This action is not 

subject to Executive Order 13045 

because it implements specific 

standards established by Congress in 

statutes. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution or Use 

This action is not subject to Executive 

Order 13211 because it is not a 

significant regulatory action under 

Executive Order 12866. 

I. National Technology Transfer and 

Advancement Act 

This action involves technical 

standards. Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. This rule would 

require the seven affected facilities to 

meet the applicable monitoring 

requirements of 40 CFR part 75. Part 75 

already incorporates a number of 

voluntary consensus standards. 

Consistent with the Agency’s 

Performance Based Measurement 

System (PBMS), part 75 sets forth 

performance criteria that allow the use 

of alternative methods to the ones set 


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Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66415 

forth in part 75. The PBMS approach is 

intended to be more flexible and costeffective for the regulated community; it 

is also intended to encourage innovation 

in analytical technology and improved 

data quality. At this time, EPA is not 

recommending any revisions to part 75; 

however, EPA periodically revises the 

test procedures set forth in part 75. 

When EPA revises the test procedures 

set forth in part 75 in the future, EPA 

will address the use of any new 

voluntary consensus standards that are 

equivalent. Currently, even if a test 

procedure is not set forth in part 75, 

EPA is not precluding the use of any 

method, whether it constitutes a 

voluntary consensus standard or not, as 

long as it meets the performance criteria 

specified; however, any alternative 

methods must be approved through the 

petition process under 40 CFR 75.66 

before they are used. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

The EPA believes the human health or 

environmental risk addressed by this 

action will not have potential 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income, or indigenous 

populations because it increases the 

level of environmental protection for all 

affected populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low-income population. 

This FIP limits emissions of SO2, NOX, 

and PM from seven facilities in 

Arkansas. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this action and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

This action is not a ‘‘major rule’’ as 

defined by 5 U.S.C. 804(2). This rule 

will be effective on October 27, 2016. 

L. Judicial Review 

Under section 307(b)(1) of the Clean 

Air Act, petitions for judicial review of 

this action must be filed in the United 

States Court of Appeals for the 

appropriate circuit by November 28, 

2016. Filing a petition for 

reconsideration by the Administrator of 

this final rule does not affect the finality 

of this action for the purposes of judicial 

review nor does it extend the time 

within which a petition for judicial 

review may be filed, and shall not 

postpone the effectiveness of such rule 

or action. This action may not be 

challenged later in proceedings to 

enforce its requirements. (See CAA 

section 307(b)(2).) 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Nitrogen dioxide, Ozone, 

Particulate matter, Reporting and 

recordkeeping requirements, Sulfur 

dioxides, Visibility, Interstate transport 

of pollution, regional haze, Best 

available retrofit technology. 

Dated: August 31, 2016. 

Gina McCarthy, 

Administrator. 

Title 40, chapter I, of the Code of 

Federal Regulations is amended as 

follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

Subpart E—Arkansas 

■ 2. Section 52.173 is amended by 

adding paragraphs (c) and (d) to read as 

follows: 

§ 52.173 Visibility protection. 

* * * * * 

(c) Federal implementation plan for 

regional haze. Requirements for AECC 

Carl E. Bailey Unit 1; AECC John L. 

McClellan Unit 1; AEP Flint Creek Unit 

1; Entergy White Bluff Units 1, 2, and 

Auxiliary Boiler; Entergy Lake Catherine 

Unit 4; Domtar Ashdown Paper Mill 

Power Boilers No. 1 and 2; and Entergy 

Independence Units 1 and 2 affecting 

visibility. 

(1) Applicability. The provisions of 

this section shall apply to each owner 

or operator, or successive owners or 

operators, of the sources designated as: 

AECC Carl E. Bailey Unit 1; AECC John 

L. McClellan Unit 1; AEP Flint Creek 

Unit 1; Entergy White Bluff Units 1, 2, 

and Auxiliary Boiler; Entergy Lake 

Catherine Unit 4; Domtar Ashdown 

Paper Mill Power Boilers No. 1 and 2; 

and Entergy Independence Units 1 and 

2. 

(2) Definitions. All terms used in this 

part but not defined herein shall have 

the meaning given them in the Clean Air 

Act and in parts 51 and 60 of this title. 

For the purposes of this section: 

24-hour period means the period of 

time between 12:01 a.m. and 12 

midnight. 

Air pollution control equipment 

includes selective catalytic control 

units, baghouses, particulate or gaseous 

scrubbers, and any other apparatus 

utilized to control emissions of 

regulated air contaminants which would 

be emitted to the atmosphere. 

Boiler-operating-day for electric 

generating units listed under paragraph 

(c)(1) of this section means any 24-hour 

period between 12 midnight and the 

following midnight during which any 

fuel is combusted at any time at the 

steam generating unit, unless otherwise 

specified. For power boilers listed under 

paragraph (c)(1) of this section, we 

define boiler-operating-day as a 24-hr 

period between 6 a.m. and 6 a.m. the 

following day during which any fuel is 

fed into and/or combusted at any time 

in the power boiler. 

Daily average means the arithmetic 

average of the hourly values measured 

in a 24-hour period. 

Heat input means heat derived from 

combustion of fuel in a unit and does 

not include the heat input from 

preheated combustion air, recirculated 

flue gases, or exhaust gases from other 

sources. Heat input shall be calculated 

in accordance with 40 CFR part 75. 

Owner or Operator means any person 

who owns, leases, operates, controls, or 

supervises any of the units or power 

boilers listed under paragraph (c)(1) of 

this section. 

Regional Administrator means the 

Regional Administrator of EPA Region 6 

or his/her authorized representative. 

Unit means one of the natural gas, fuel 

oil, or coal fired boilers covered under 

paragraph (c) of this section. 

(3) Emissions limitations for AECC 

Bailey Unit 1 and AECC McClellan Unit 

1. The individual SO2, NOX, and PM 

emission limits for each unit are as 

listed in the following table. 


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Unit SO2 Emission limit NOX Emission limit PM Emission limit 

AECC Bailey Unit 1 ....................... Use of fuel with a sulfur content 

limit of 0.5% by weight..

887 lb/hr ........................................ Use of fuel with a sulfur content 

limit of 0.5% by weight. 

AECC McClellan Unit 1 ................. Use of fuel with a sulfur content 

limit of 0.5% by weight..

869.1 lb/hr .....................................

(Natural Gas firing) .......................

705.8 lb/hr .....................................

(Fuel Oil firing) ..............................

Use of fuel with a sulfur content 

limit of 0.5% by weight. 

(4) Compliance dates for AECC Bailey 

Unit 1 and AECC McClellan Unit. The 

owner or operator of each unit must 

comply with the SO2 and PM 

requirements listed in paragraph (c)(3) 

of this section by October 27, 2021. As 

of October 27, 2016, the owner or 

operator of each unit shall not purchase 

fuel for combustion at the unit that does 

not meet the sulfur content limit in 

paragraph (c)(3) of this section. The 

owner or operator of each unit must 

comply with the requirement in 

paragraph (c)(3) of this section to burn 

only fuel with a sulfur content limit of 

0.5% by weight by October 27, 2021. 

The owner or operator of each unit must 

comply with the NOX emission limits in 

paragraph (c)(3) of this section by 

October 27, 2016. 

(5) Compliance determination and 

reporting and recordkeeping 

requirements for AECC Bailey Unit 1 

and AECC McClellan Unit—(i) SO2 and 

PM. To determine compliance with the 

SO2 and PM requirements listed in 

paragraph (c)(3) of this section, the 

owner or operator shall sample and 

analyze each shipment of fuel to 

determine the sulfur content by weight, 

except for natural gas shipments. A 

‘‘shipment’’ is considered delivery of 

the entire amount of each order of fuel 

purchased. Fuel sampling and analysis 

may be performed by the owner or 

operator of an affected unit, an outside 

laboratory, or a fuel supplier. All 

records pertaining to the sampling of 

each shipment of fuel as described 

above, including the results of the sulfur 

content analysis, must be maintained by 

the owner or operator and made 

available upon request to EPA and 

ADEQ representatives. 

(ii) NOX. To determine compliance 

with the NOX emission limits of 

paragraph (c)(3) of this section, the 

owner or operator shall determine the 

average concentration (arithmetic 

average of three contiguous one hour 

periods) of NOX as measured by the 

CEMS and converted to pounds per 

hour using corresponding average 

(arithmetic average of three contiguous 

one hour periods) stack gas flow rates. 

Records of the NOX emissions rates 

must be maintained by the owner or 

operator and made available upon 

request to EPA and ADEQ 

representatives. 

(iii) The owner or operator shall 

continue to maintain and operate a 

CEMS for NOX on the units listed in 

paragraph (c)(3) of this section in 

accordance with 40 CFR 60.8 and 

60.13(e), (f), and (h), and appendix B of 

part 60. The owner or operator shall 

comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. Compliance with the emission 

limits for NOX shall be determined by 

using data from a CEMS. 

(iv) Continuous emissions monitoring 

shall apply during all periods of 

operation of the units listed in 

paragraph (c)(3) of this section, 

including periods of startup, shutdown, 

and malfunction, except for CEMS 

breakdowns, repairs, calibration checks, 

and zero and span adjustments. 

Continuous monitoring systems for 

measuring NOX and diluent gas shall 

complete a minimum of one cycle of 

operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Hourly averages shall be 

computed using at least one data point 

in each fifteen minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid NOX pounds per 

hour emission data are not obtained 

because of continuous monitoring 

system breakdowns, repairs, calibration 

checks, or zero and span adjustments, 

emission data must be obtained by using 

other monitoring systems approved by 

the EPA to provide emission data for a 

minimum of 18 hours in each 24-hour 

period and at least 22 out of 30 

successive boiler operating days. 

(6) Emissions limitations for AEP Flint 

Creek Unit 1 and Entergy White Bluff 

Units 1 and 2. The individual SO2 and 

NOX emission limits for each unit are as 

listed in the following table, as specified 

in pounds per million British thermal 

units (lb/MMBtu) or pounds per hour 

(lb/hr). The SO2 emission limits of 0.06 

lb/MMBtu and the NOX emission limits 

of 0.23 lb/MMBtu and 0.15 lb/MMBtu 

are on a rolling 30 boiler-operating-day 

averaging period. The NOX emission 

limit of 671 lb/hr is on a rolling 3-hour 

average. 

Unit 

SO2 Emission 

limit 

(lb/MMBtu) 

NOX Emission 

limit 

(lb/MMBtu) 

NOX Emission 

limit 

(lb/hr) 

AEP Flint Creek Unit 1 ................................................................................................................ 0.06 0.23 ........................

Entergy White Bluff Unit 1 ........................................................................................................... 0.06 0.15 671 

Entergy White Bluff Unit 2 ........................................................................................................... 0.06 0.15 671 

(7) Compliance dates for AEP Flint 

Creek Unit 1 and Entergy White Bluff 

Units 1 and 2. The owner or operator of 

AEP Flint Creek Unit 1 must comply 

with the SO2 and NOX emission limits 

listed in paragraph (c)(6) of this section 

by April 27, 2018. The owner or 

operator of White Bluff Units 1 and 2 

must comply with the SO2 emission 

limit listed in paragraph (c)(6) of this 

section by October 27, 2021, and must 

comply with the NOX emission limits 

listed in paragraph (c) (6) of this section 

by April 27, 2018. 

(8) Compliance determination and 

reporting and recordkeeping 

requirements for AEP Flint Creek Unit 1 

and Entergy White Bluff Units 1 and 2. 

(i) For purposes of determining 

compliance with the SO2 and NOX

emissions limits listed in paragraph 


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Federal Register / Vol. 81, No. 187 / Tuesday, September 27, 2016 / Rules and Regulations 66417 

(c)(6) of this section for AEP Flint Creek 

Unit 1 and with the SO2 emissions limit 

listed in paragraph (c)(6) of this section 

for White Bluff Units 1 and 2, the 

emissions for each boiler-operating-day 

for each unit shall be determined by 

summing the hourly emissions 

measured in pounds of SO2 or pounds 

of NOX. For each unit, heat input for 

each boiler-operating-day shall be 

determined by adding together all 

hourly heat inputs, in millions of BTU. 

Each boiler-operating-day of the 30-day 

rolling average for a unit shall be 

determined by adding together the 

pounds of SO2 or NOX from that day 

and the preceding 29 boiler-operatingdays and dividing the total pounds of 

SO2 or NOX by the sum of the heat input 

during the same 30 boiler-operating-day 

period. The result shall be the 30 boileroperating-day rolling average in terms of 

lb/MMBtu emissions of SO2 or NOX. If 

a valid SO2 or NOX pounds per hour or 

heat input is not available for any hour 

for a unit, that heat input and SO2 or 

NOX pounds per hour shall not be used 

in the calculation of the 30 boileroperating-day rolling average for SO2 or 

NOX. For each day, records of the total 

SO2 and NOX emitted that day by each 

emission unit and the sum of the hourly 

heat inputs for that day must be 

maintained by the owner or operator 

and made available upon request to EPA 

and ADEQ representatives. Records of 

the 30 boiler-operating-day rolling 

average for SO2 and NOX for each unit 

as described above must be maintained 

by the owner or operator for each boileroperating-day and made available upon 

request to EPA and ADEQ 

representatives. 

(ii) For purposes of determining 

compliance with the 0.15 lb/MMBtu 

NOX emissions limit listed in paragraph 

(c)(6) of this section for White Bluff 

Units 1 and 2, the NOX emissions for 

each unit shall be determined by the 

following procedure: 

(A) Summing the total pounds of NOX

emitted during the current boileroperating-day and the preceding 29 

boiler-operating-days while including 

only emissions during hours when the 

unit was dispatched at 50% or greater 

of the unit’s maximum heat input rating; 

(B) Summing the total heat input in 

MMBtu to the unit during the current 

boiler-operating-day and the preceding 

29 boiler-operating-days while 

including only the heat input during 

hours when the unit was dispatched at 

50% or greater of the unit’s maximum 

heat input rating; and 

(C) Dividing the total pounds of NOX

emitted as calculated in step 1 by the 

total heat input to the unit as calculated 

in step 2. The result shall be the 30 

boiler-operating-day rolling average in 

terms of lb/MMBtu emissions of NOX. If 

a valid NOX pounds per hour or heat 

input is not available for any hour for 

a unit, that heat input and NOX pounds 

per hour shall not be used in the 

calculation of the 30 boiler-operatingday rolling average for NOX. For each 

day, records for each unit of the hours 

during which the unit was dispatched at 

50% or greater of the unit’s maximum 

heat input rating, as well as NOX

emissions and hourly heat input for 

each of those hours must be maintained 

by the owner or operator and made 

available upon request to EPA and 

ADEQ representatives. Records of the 30 

boiler-operating-day rolling average for 

NOX for each unit as described above 

must be maintained by the owner or 

operator for each boiler-operating-day 

and made available upon request to EPA 

and ADEQ representatives. 

(iii) For purposes of determining 

compliance with the 671 lb/hr NOX

emissions limit listed in paragraph (c)(6) 

of this section for White Bluff Units 1 

and 2, the NOX emissions for each unit 

shall be determined by the following 

procedure: 

(A) Summing the total pounds of NOX

emitted during the current hour and the 

preceding 2 hours during which the unit 

was dispatched at less than 50% of the 

unit’s maximum heat input rating; and 

(B) Dividing the total pounds of NOX

emitted as calculated in step 1 by 3. The 

result shall be the rolling 3-hour average 

in terms of lb/hr emissions of NOX. If a 

valid NOX pounds per hour is not 

available for any hour for a unit, that 

NOX pounds per hour shall not be used 

in the calculation of the rolling 3-hour 

average for NOX. For each day, records 

for each unit of the hours during which 

the unit was dispatched at less than 

50% of each unit’s maximum heat input 

rating, as well as NOX emissions and 

hourly heat input for each of those 

hours must be maintained by the owner 

or operator and made available upon 

request to EPA and ADEQ 

representatives. Records of the rolling 3- 

hour averages for NOX for each unit as 

described above must be maintained for 

each day by the owner or operator and 

made available upon request to EPA and 

ADEQ representatives. 

(iv) The owner or operator shall 

continue to maintain and operate a 

CEMS for SO2 and NOX on the units 

listed in paragraph (c)(6) of this section 

in accordance with 40 CFR 60.8 and 

60.13(e), (f), and (h), and appendix B of 

part 60. The owner or operator shall 

comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 75. Compliance with the emission 

limits for SO2 and NOX shall be 

determined by using data from a CEMS. 

(v) Continuous emissions monitoring 

shall apply during all periods of 

operation of the units listed in 

paragraph (c)(6) of this section, 

including periods of startup, shutdown, 

and malfunction, except for CEMS 

breakdowns, repairs, calibration checks, 

and zero and span adjustments. 

Continuous monitoring systems for 

measuring SO2 and NOX and diluent gas 

shall complete a minimum of one cycle 

of operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Hourly averages shall be 

computed using at least one data point 

in each fifteen minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid SO2 or NOX pounds 

per hour emission data are not obtained 

because of continuous monitoring 

system breakdowns, repairs, calibration 

checks, or zero and span adjustments, 

emission data must be obtained by using 

other monitoring systems approved by 

the EPA to provide emission data for a 

minimum of 18 hours in each 24 hour 

period and at least 22 out of 30 

successive boiler operating days. 

(9) Emissions limitations for Entergy 

White Bluff Auxiliary Boiler. The 

individual SO2, NOX, and PM emission 

limits for the unit are as listed in the 

following table in pounds per hour (lb/ 

hr). 

Unit 

SO2 Emission 

limit 

(lb/hr) 

NOX Emission 

limit 

(lb/hr) 

PM Emission 

limit 

(lb/hr) 

Entergy White Bluff Auxiliary Boiler ............................................................................................. 105.2 32.2 4.5 


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(10) Compliance dates for Entergy 

White Bluff Auxiliary Boiler. The owner 

or operator of the unit must comply 

with the SO2, NOX, and PM emission 

limits listed in paragraph (c)(9) of this 

section by October 27, 2016. 

(11) Compliance determination and 

reporting and recordkeeping 

requirements for Entergy White Bluff 

Auxiliary Boiler. For purposes of 

demonstrating compliance with the 

emission limits listed in paragraph (c)(9) 

of this section, records of fuel oil 

analysis must be maintained by the 

owner or operator and made available 

upon request to EPA and ADEQ 

representatives. 

(12) Emissions limitations for Entergy 

Lake Catherine Unit 4. The individual 

NOX emission limit for the unit for 

natural gas firing is as listed in the 

following table in pounds per million 

British thermal units (lb/MMBtu) as 

averaged over a rolling 30 boileroperating-day period. The unit must not 

burn fuel oil until BART determinations 

are promulgated for the unit for SO2,

NOX, and PM for the fuel oil firing 

scenario through a FIP and/or through 

EPA action upon and approval of 

revised BART determinations submitted 

by the State as a SIP revision. 

Unit 

NOX Emission 

limit—natural 

gas firing 

(lb/MMBtu) 

Entergy Lake Catherine Unit 

4 ........................................ 0.22 

(13) Compliance dates for Entergy 

Lake Catherine Unit 4. The owner or 

operator of the unit must comply with 

the NOX emission limit listed in 

paragraph (c)(12) of this section by 

October 27, 2019. 

(14) Compliance determination and 

reporting and recordkeeping 

requirements for Entergy Lake Catherine 

Unit 4. (i) NOX emissions for each day 

shall be determined by summing the 

hourly emissions measured in pounds 

of NOX. The heat input for each boileroperating-day shall be determined by 

adding together all hourly heat inputs, 

in millions of BTU. Each boileroperating-day of the thirty-day rolling 

average for the unit shall be determined 

by adding together the pounds of NOX

from that day and the preceding 29 

boiler-operating-days and dividing the 

total pounds of NOX by the sum of the 

heat input during the same 30 boileroperating-day period. The result shall be 

the 30 boiler-operating-day rolling 

average in terms of lb/MMBtu emissions 

of NOX. If a valid NOX pounds per hour 

or heat input is not available for any 

hour for the unit, that heat input and 

NOX pounds per hour shall not be used 

in the calculation of the 30 boileroperating-day rolling average for NOX. 

For each day, records of the total NOX

emitted that day by the unit and the 

sum of the hourly heat inputs for that 

day must be maintained by the owner or 

operator and made available upon 

request to EPA and ADEQ 

representatives. Records of the 30 

boiler-operating-day rolling average for 

NOX for the unit as described above 

must be maintained by the owner or 

operator for each boiler-operating-day 

and made available upon request to EPA 

and ADEQ representatives. 

(ii) The owner or operator shall 

continue to maintain and operate a 

CEMS on the unit listed in paragraph 

(c)(12) of this section in accordance 

with 40 CFR part 75, Appendix E as 

long as the unit meets the definition of 

a peaking unit under 40 CFR part 75. 

The owner or operator shall comply 

with the quality assurance procedures 

for CEMS found in 40 CFR part 75. 

(iii) Continuous emissions monitoring 

shall apply during all periods of 

operation of the unit listed in paragraph 

(c)(12) of this section, including periods 

of startup, shutdown, and malfunction, 

except for CEMS breakdowns, repairs, 

calibration checks, and zero and span 

adjustments. 

(15) Emissions Limitations for Domtar 

Ashdown Paper Mill Power Boiler No. 1. 

The SO2 emission limit for the boiler is 

as listed in the following table in 

pounds per day (lb/day) as averaged 

over a rolling 30 boiler-operating-day 

period. The NOX emission limit for the 

boiler is as listed in the following table 

in pounds per hour (lb/hr). 

Unit 

SO2 Emission 

limit 

(lb/day) 

NOX Emission 

limit 

(lb/hr) 

Domtar Ashdown Paper Mill Power Boiler No. 1 .................................................................................................... 504 207.4 

(16) Compliance dates for Domtar 

Ashdown Mill Power Boiler No. 1. The 

owner or operator of the boiler must 

comply with the SO2 and NOX emission 

limits listed in paragraph (c)(15) of this 

section by November 28, 2016. 

(17) Compliance determination and 

reporting and recordkeeping 

requirements for Domtar Ashdown 

Paper Mill Power Boiler No. 1. (i)(A) SO2

emissions resulting from combustion of 

fuel oil shall be determined by assuming 

that the SO2 content of the fuel 

delivered to the fuel inlet of the 

combustion chamber is equal to the SO2

being emitted at the stack. The owner or 

operator must maintain records of the 

sulfur content by weight of each fuel oil 

shipment, where a ‘‘shipment’’ is 

considered delivery of the entire 

amount of each order of fuel purchased. 

Fuel sampling and analysis may be 

performed by the owner or operator, an 

outside laboratory, or a fuel supplier. 

All records pertaining to the sampling of 

each shipment of fuel oil, including the 

results of the sulfur content analysis, 

must be maintained by the owner or 

operator and made available upon 

request to EPA and ADEQ 

representatives. SO2 emissions resulting 

from combustion of bark shall be 

determined by using the following sitespecific curve equation, which accounts 

for the SO2 scrubbing capabilities of 

bark combustion: 

Y= 0.4005 * X¥0.2645 

Where: 

Y= pounds of sulfur emitted per ton of dry 

fuel feed to the boiler 

X= pounds of sulfur input per ton of dry bark 

(B) The owner or operator must 

confirm the site-specific curve equation 

through stack testing. By October 27, 

2017, the owner or operator must 

provide a report to EPA showing 

confirmation of the site specific-curve 

equation accuracy. Records of the 

quantity of fuel input to the boiler for 

each fuel type for each day must be 

compiled no later than 15 days after the 

end of the month and must be 

maintained by the owner or operator 

and made available upon request to EPA 

and ADEQ representatives. Each boileroperating-day of the 30-day rolling 

average for the boiler must be 

determined by adding together the 

pounds of SO2 from that boileroperating-day and the preceding 29 

boiler-operating-days and dividing the 

total pounds of SO2 by the sum of the 


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total number of boiler operating days 

(i.e., 30). The result shall be the 30 

boiler-operating-day rolling average in 

terms of lb/day emissions of SO2. 

Records of the total SO2 emitted for each 

day must be compiled no later than 15 

days after the end of the month and 

must be maintained by the owner or 

operator and made available upon 

request to EPA and ADEQ 

representatives. Records of the 30 

boiler-operating-day rolling averages for 

SO2 as described in this paragraph 

(c)(17)(i) must be maintained by the 

owner or operator for each boileroperating-day and made available upon 

request to EPA and ADEQ 

representatives. 

(ii) If the air permit is revised such 

that Power Boiler No. 1 is permitted to 

burn only pipeline quality natural gas, 

this is sufficient to demonstrate that the 

boiler is complying with the SO2

emission limit under paragraph (c)(15) 

of this section. The compliance 

determination requirements and the 

reporting and recordkeeping 

requirements under paragraph (c)(17)(i) 

of this section would not apply and 

confirmation of the accuracy of the sitespecific curve equation under paragraph 

(c)(17)(i)(B) of this section through stack 

testing would not be required so long as 

Power Boiler No. 1 is only permitted to 

burn pipeline quality natural gas. 

(iii) To demonstrate compliance with 

the NOX emission limit under paragraph 

(c)(15) of this section, the owner or 

operator shall conduct stack testing 

using EPA Reference Method 7E once 

every 5 years, beginning 1 year from the 

effective date of our final rule. Records 

and reports pertaining to the stack 

testing must be maintained by the 

owner or operator and made available 

upon request to EPA and ADEQ 

representatives. 

(iv) If the air permit is revised such 

that Power Boiler No. 1 is permitted to 

burn only pipeline quality natural gas, 

the owner or operator may demonstrate 

compliance with the NOX emission 

limit under paragraph (c)(15) of this 

section by calculating NOX emissions 

using fuel usage records and the 

applicable NOX emission factor under 

AP–42, Compilation of Air Pollutant 

Emission Factors, section 1.4, Table 1.4– 

1. Records of the quantity of natural gas 

input to the boiler for each day must be 

compiled no later than 15 days after the 

end of the month and must be 

maintained by the owner or operator 

and made available upon request to EPA 

and ADEQ representatives. Records of 

the calculation of NOX emissions for 

each day must be compiled no later than 

15 days after the end of the month and 

must be maintained by the owner or 

operator and made available upon 

request to EPA and ADEQ 

representatives. Each boiler-operatingday of the 30-day rolling average for the 

boiler must be determined by adding 

together the pounds of NOX from that 

day and the preceding 29 boileroperating-days and dividing the total 

pounds of NOX by the sum of the total 

number of hours during the same 30 

boiler-operating-day period. The result 

shall be the 30 boiler-operating-day 

rolling average in terms of lb/hr 

emissions of NOX. Records of the 30 

boiler-operating-day rolling average for 

NOX must be maintained by the owner 

or operator for each boiler-operating-day 

and made available upon request to EPA 

and ADEQ representatives. Under these 

circumstances, the compliance 

determination requirements and the 

reporting and recordkeeping 

requirements under paragraph 

(c)(17)(iii) of this section would not 

apply. 

(18) SO2 and NOX Emissions 

Limitations for Domtar Ashdown Paper 

Mill Power Boiler No.2. The individual 

SO2 and NOX emission limits for the 

boiler are as listed in the following table 

in pounds per hour (lb/hr) as averaged 

over a rolling 30 boiler-operating-day 

period. 

Unit SO2 Emission 

Limit (lb/hr) 

NOX Emission 

Limit (lb/hr) 

Domtar Ashdown Paper Mill Power Boiler No. 2 .................................................................................................... 91.5 345 

(19) SO2 and NOX Compliance dates 

for Domtar Ashdown Mill Power Boiler 

No. 2. The owner or operator of the 

boiler must comply with the SO2 and 

NOX emission limits listed in paragraph 

(c)(18) of this section by October 27, 

2021. 

(20) SO2 and NOX Compliance 

determination and reporting and 

recordkeeping requirements for Domtar 

Ashdown Mill Power Boiler No. 2. (i) 

NOX and SO2 emissions for each day 

shall be determined by summing the 

hourly emissions measured in pounds 

of NOX or pounds of SO2. Each boileroperating-day of the 30-day rolling 

average for the boiler shall be 

determined by adding together the 

pounds of NOX or SO2 from that day 

and the preceding 29 boiler-operatingdays and dividing the total pounds of 

NOX or SO2 by the sum of the total 

number of hours during the same 30 

boiler-operating-day period. The result 

shall be the 30 boiler-operating-day 

rolling average in terms of lb/hr 

emissions of NOX or SO2. If a valid NOX

pounds per hour or SO2 pounds per 

hour is not available for any hour for the 

boiler, that NOX pounds per hour shall 

not be used in the calculation of the 30 

boiler-operating-day rolling average for 

NOX. For each day, records of the total 

SO2 and NOX emitted for that day by the 

boiler must be maintained by the owner 

or operator and made available upon 

request to EPA and ADEQ 

representatives. Records of the 30 

boiler-operating-day rolling average for 

SO2 and NOX for the boiler as described 

above must be maintained by the owner 

or operator for each boiler-operating-day 

and made available upon request to EPA 

and ADEQ representatives. 

(ii) The owner or operator shall 

continue to maintain and operate a 

CEMS for SO2 and NOX on the boiler 

listed in paragraph (c)(18) of this section 

in accordance with 40 CFR 60.8 and 

60.13(e), (f), and (h), and appendix B of 

part 60. The owner or operator shall 

comply with the quality assurance 

procedures for CEMS found in 40 CFR 

part 60. Compliance with the emission 

limits for SO2 and NOX shall be 

determined by using data from a CEMS. 

(iii) Continuous emissions monitoring 

shall apply during all periods of 

operation of the boiler listed in 

paragraph (c)(18) of this section, 

including periods of startup, shutdown, 

and malfunction, except for CEMS 

breakdowns, repairs, calibration checks, 

and zero and span adjustments. 

Continuous monitoring systems for 

measuring SO2 and NOX and diluent gas 

shall complete a minimum of one cycle 

of operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Hourly averages shall be 

computed using at least one data point 

in each fifteen minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 


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backups of data from data acquisition 

and handling system, and recertification 

events. When valid SO2 or NOX pounds 

per hour emission data are not obtained 

because of continuous monitoring 

system breakdowns, repairs, calibration 

checks, or zero and span adjustments, 

emission data must be obtained by using 

other monitoring systems approved by 

the EPA to provide emission data for a 

minimum of 18 hours in each 24 hour 

period and at least 22 out of 30 

successive boiler operating days. 

(iv) If the air permit is revised such 

that Power Boiler No. 2 is permitted to 

burn only pipeline quality natural gas, 

this is sufficient to demonstrate that the 

boiler is complying with the SO2

emission limit under paragraph (c)(18) 

of this section. Under these 

circumstances, the compliance 

determination requirements under 

paragraphs (c)(20)(i) through (iii) of this 

section would not apply to the SO2

emission limit listed in paragraph 

(c)(18) of this section. 

(v) If the air permit is revised such 

that Power Boiler No. 2 is permitted to 

burn only pipeline quality natural gas 

and the operation of the CEMS is not 

required under other applicable 

requirements, the owner or operator 

may demonstrate compliance with the 

NOX emission limit under paragraph 

(c)(18) of this section by calculating 

NOX emissions using fuel usage records 

and the applicable NOX emission factor 

under AP–42, Compilation of Air 

Pollutant Emission Factors, section 1.4, 

Table 1.4–1. Records of the quantity of 

natural gas input to the boiler for each 

day must be compiled no later than 15 

days after the end of the month and 

must be maintained by the owner or 

operator and made available upon 

request to EPA and ADEQ 

representatives. Records of the 

calculation of NOX emissions for each 

day must be compiled no later than 15 

days after the end of the month and 

must be maintained and made available 

upon request to EPA and ADEQ 

representatives. Each boiler-operatingday of the 30-day rolling average for the 

boiler must be determined by adding 

together the pounds of NOX from that 

day and the preceding 29 boileroperating-days and dividing the total 

pounds of NOX by the sum of the total 

number of hours during the same 30 

boiler-operating-day period. The result 

shall be the 30 boiler-operating-day 

rolling average in terms of lb/hr 

emissions of NOX. Records of the 30 

boiler-operating-day rolling average for 

NOX must be maintained by the owner 

or operator for each boiler-operating-day 

and made available upon request to EPA 

and ADEQ representatives. Under these 

circumstances, the compliance 

determination requirements under 

paragraphs (c)(20)(i) through (iii) of this 

section would not apply to the NOX

emission limit. 

(21) PM BART Requirements for 

Domtar Ashdown Paper Mill Power 

Boiler No.2. The owner or operator must 

rely on the applicable PM standard 

required under 40 CFR part 63, subpart 

DDDDD—National Emission Standards 

for Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and 

Institutional Boilers and Process 

Heaters, as revised, to satisfy the PM 

BART requirement. Compliance with 

the applicable PM standard under 40 

CFR part 63 subpart DDDDD, as revised, 

shall demonstrate compliance with the 

PM BART requirement. 

(22) PM compliance dates for Domtar 

Ashdown Mill Power Boiler No. 2. The 

owner or operator of the boiler must 

comply with the PM BART requirement 

listed in paragraph (c)(21) of this section 

by November 28, 2016. 

(23) Alternative PM Compliance 

Determination for Domtar Ashdown 

Paper Mill Power Boiler No.2. If the air 

permit is revised such that Power Boiler 

No. 2 is permitted to burn only pipeline 

quality natural gas, this is sufficient to 

demonstrate that the boiler is complying 

with the PM BART requirement under 

paragraph (c)(21) of this section. 

(24) Emissions limitations for Entergy 

Independence Units 1 and 2. The 

individual emission limits for each unit 

are as listed in the following table in 

pounds per million British thermal 

units (lb/MMBtu) or pounds per hour 

(lb/hr). The SO2 emission limit and the 

NOX emission limits listed in the table 

as lb/MMBtu are on a rolling 30 boileroperating-day averaging period. The 

NOX emission limit of 671 lb/hr is on 

a rolling 3-hour average. 

Unit 

SO2 Emission 

limit (lb/

MMBtu) 

NOX Emission 

limit (lb/

MMBtu) 

NOX Emission 

Limit (lb/hr) 

Entergy Independence Unit 1 ...................................................................................................... 0.06 0.15 671 

Entergy Independence Unit 2 ...................................................................................................... 0.06 0.15 671 

(25) Compliance dates for Entergy 

Independence Units 1 and 2. The owner 

or operator of each unit must comply 

with the SO2 emission limit in 

paragraph (c)(24) of this section by 

October 27, 2021 and with the NOX

emission limits by April 27, 2018. 

(26) Compliance determination and 

reporting and recordkeeping 

requirements for Entergy Independence 

Units 1 and 2. (i) For purposes of 

determining compliance with the SO2

emissions limit listed in paragraph 

(c)(24) of this section for each unit, the 

SO2 emissions for each boiler-operatingday shall be determined by summing 

the hourly emissions measured in 

pounds of SO2. For each unit, heat input 

for each boiler-operating-day shall be 

determined by adding together all 

hourly heat inputs, in millions of BTU. 

Each boiler-operating-day of the thirtyday rolling average for a unit shall be 

determined by adding together the 

pounds of SO2 from that day and the 

preceding 29 boiler-operating-days and 

dividing the total pounds of SO2 by the 

sum of the heat input during the same 

30 boiler-operating-day period. The 

result shall be the 30 boiler-operatingday rolling average in terms of lb/

MMBtu emissions of SO2. If a valid SO2

pounds per hour or heat input is not 

available for any hour for a unit, that 

heat input and SO2 pounds per hour 

shall not be used in the calculation of 

the applicable 30 boiler-operating-days 

rolling average. For each day, records of 

the total SO2 emitted that day by each 

emission unit and the sum of the hourly 

heat inputs for that day must be 

maintained by the owner or operator 

and made available upon request to EPA 

and ADEQ representatives. . Records of 

the 30 boiler-operating-day rolling 

average for each unit as described above 

must be maintained by the owner or 

operator for each boiler-operating-day 

and made available upon request to EPA 

and ADEQ representatives. 

(ii) For purposes of determining 

compliance with the 0.15 lb/MMBtu 

NOX emissions limit listed in paragraph 

(c)(24), the NOX emissions for each unit 

shall be determined by the following 

procedure: 

(A) Summing the total pounds of NOX

emitted during the current boileroperating-day and the preceding 29 

boiler-operating-days while including 

only emissions during hours when the 

unit was dispatched at 50% or greater 

of the unit’s maximum heat input rating; 


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(B) Summing the total heat input in 

MMBtu to the unit during the current 

boiler-operating-day and the preceding 

29 boiler operating days while including 

only the heat input during hours when 

the unit was dispatched at 50% or 

greater of the unit’s maximum heat 

input rating; and 

(C) Dividing the total pounds of NOX

emitted as calculated in step 1 by the 

total heat input to the unit as calculated 

in step 2. The result shall be the 30 

boiler-operating-day rolling average in 

terms of lb/MMBtu emissions of NOX. If 

a valid NOX pounds per hour or heat 

input is not available for any hour for 

a unit, that heat input and NOX pounds 

per hour shall not be used in the 

calculation of the 30 boiler-operatingday rolling average for NOX. For each 

day, records for each unit of the hours 

during which the unit was dispatched at 

50% or greater of the unit’s maximum 

heat input rating, as well as NOX

emissions and hourly heat input for 

each of those hours must be maintained 

by the owner or operator and made 

available upon request to EPA and 

ADEQ representatives. Records of the 30 

boiler-operating-day rolling average for 

NOX for each unit as described above 

must be maintained by the owner or 

operator for each boiler-operating-day 

and made available upon request to EPA 

and ADEQ representatives. 

(iii) For purposes of determining 

compliance with the 671 lb/hr NOX

emissions limit listed in paragraph 

(c)(24), the NOX emissions for each unit 

shall be determined by the following 

procedure: 

(A) Summing the total pounds of NOX

emitted during the current hour and the 

preceding 2 hours during which the unit 

was dispatched at less than 50% of the 

unit’s maximum heat input rating; and 

(B) Dividing the total pounds of NOX

emitted as calculated in step 1 by 3. The 

result shall be the rolling 3-hour average 

in terms of lb/hr emissions of NOX. If a 

valid NOX pounds per hour is not 

available for any hour for a unit, that 

NOX pounds per hour shall not be used 

in the calculation of the rolling 3-hour 

average for NOX. For each day, records 

for each unit of the hours during which 

the unit was dispatched at less than 

50% of each unit’s maximum heat input 

rating, as well as NOX emissions and 

hourly heat input for each of those 

hours must be maintained by the owner 

or operator and made available upon 

request to EPA and ADEQ 

representatives. Records of the rolling 3- 

hour averages for NOX for each unit as 

described above must be maintained for 

each day by the owner or operator and 

made available upon request to EPA and 

ADEQ representatives. 

(iv) The owner or operator shall 

continue to maintain and operate a 

CEMS for SO2 and NOX on the units 

listed in paragraph (c)(24) in accordance 

with 40 CFR 60.8 and 60.13(e), (f), and 

(h), and appendix B of part 60. The 

owner or operator shall comply with the 

quality assurance procedures for CEMS 

found in 40 CFR part 75. Compliance 

with the emission limits for SO2 and 

NOX shall be determined by using data 

from a CEMS. 

(v) Continuous emissions monitoring 

shall apply during all periods of 

operation of the units listed in 

paragraph (c)(24) of this section, 

including periods of startup, shutdown, 

and malfunction, except for CEMS 

breakdowns, repairs, calibration checks, 

and zero and span adjustments. 

Continuous monitoring systems for 

measuring SO2 and NOX and diluent gas 

shall complete a minimum of one cycle 

of operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute period. Hourly averages shall be 

computed using at least one data point 

in each fifteen minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. When valid SO2 or NOX pounds 

per hour emission data are not obtained 

because of continuous monitoring 

system breakdowns, repairs, calibration 

checks, or zero and span adjustments, 

emission data must be obtained by using 

other monitoring systems approved by 

the EPA to provide emission data for a 

minimum of 18 hours in each 24 hour 

period and at least 22 out of 30 

successive boiler operating days. 

(27) Reporting and recordkeeping 

requirements. Unless otherwise stated 

all requests, reports, submittals, 

notifications, and other communications 

to the Regional Administrator required 

under paragraph (c) of this section shall 

be submitted, unless instructed 

otherwise, to the Director, Multimedia 

Planning and Permitting Division, U.S. 

Environmental Protection Agency, 

Region 6, to the attention of Mail Code: 

6PD, at 1445 Ross Avenue, Suite 1200, 

Dallas, Texas 75202–2733. For each unit 

subject to the emissions limitation 

under paragraph (c) of this section, the 

owner or operator shall comply with the 

following requirements, unless 

otherwise specified: 

(i) For each emissions limit under 

paragraph (c) of this section where 

compliance shall be determined by 

using data from a CEMS, comply with 

the notification, reporting, and 

recordkeeping requirements for CEMS 

compliance monitoring in 40 CFR 

60.7(c) and (d). 

(ii) [Reserved] 

(28) Equipment operations. At all 

times, including periods of startup, 

shutdown, and malfunction, the owner 

or operator shall, to the extent 

practicable, maintain and operate the 

unit including associated air pollution 

control equipment in a manner 

consistent with good air pollution 

control practices for minimizing 

emissions. Determination of whether 

acceptable operating and maintenance 

procedures are being used will be based 

on information available to the Regional 

Administrator which may include, but 

is not limited to, monitoring results, 

review of operating and maintenance 

procedures, and inspection of the unit. 

(29) Enforcement. (i) Notwithstanding 

any other provision in this 

implementation plan, any credible 

evidence or information relevant as to 

whether the unit would have been in 

compliance with applicable 

requirements if the appropriate 

performance or compliance test had 

been performed, can be used to establish 

whether or not the owner or operator 

has violated or is in violation of any 

standard or applicable emission limit in 

the plan. 

(ii) Emissions in excess of the level of 

the applicable emission limit or 

requirement that occur due to a 

malfunction shall constitute a violation 

of the applicable emission limit. 

(d) Measures Addressing Partial 

Disapproval of Portion of Interstate 

Visibility Transport SIP for the 1997 8- 

hour ozone and PM2.5 NAAQS. The 

deficiencies identified in EPA’s partial 

disapproval of the portion of the SIP 

pertaining to adequate provisions to 

prohibit emissions in Arkansas from 

interfering with measures required in 

another state to protect visibility, 

submitted on March 28, 2008, and 

supplemented on September 27, 2011 

are satisfied by § 52.173. 

[FR Doc. 2016–22508 Filed 9–26–16; 8:45 am] 

BILLING CODE 6560–50–P 


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