Federal Register / Vol. 82, No. 174 / Monday, September 11, 2017 / Proposed Rules 42627 

(Federalism) it is determined that this 

action does not have sufficient 

federalism implications to warrant the 

preparation of a Federalism Assessment. 

List of Subjects in 21 CFR Part 1308 

Administrative practice and 

procedure, Drug traffic control, 

Reporting and recordkeeping 

requirements. 

For the reasons set out above, the DEA 

proposes to amend 21 CFR part 1308 as 

follows: 

PART 1308—SCHEDULES OF 

CONTROLLED SUBSTANCES 

■ 1. The authority citation for part 1308 

continues to read as follows: 

Authority: 21 U.S.C. 811, 812, 871(b), 

unless otherwise noted. 

■ 2. In § 1308.11, add paragraph (h)(18) 

to read as follows: 

§ 1308.11 Schedule I. 

* * * * * 

(h) * * * 

(18) methyl 2-(1-(4-fluorobenzyl)- 

1H-indazole-3-carboxamido)-3- 

methylbutanoate, its optical, 

positional, and geometric isomers, salts and salts of isomers 

(Other names: FUB-AMB, 

MMB-FUBINACA, AMBFUBINACA) ................................ (7021) 

Dated: August 14, 2017. 

Chuck Rosenberg, 

Acting Administrator. 

[FR Doc. 2017–17639 Filed 9–8–17; 8:45 am] 

BILLING CODE 4410–09–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R06–OAR–2015–0189; FRL–9966–97– 

Region 6] 

Approval and Promulgation of 

Implementation Plans; Arkansas; 

Approval of Regional Haze State 

Implementation Plan Revision and 

Withdrawal of Federal Implementation 

Plan for NOX for Electric Generating 

Units in Arkansas 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: Pursuant to the Federal Clean 

Air Act (CAA or the Act), the 

Environmental Protection Agency (EPA) 

is proposing to approve a proposed 

revision to the Arkansas Regional Haze 

State Implementation Plan (SIP) 

submitted for parallel processing on July 

12, 2017, by the State of Arkansas 

through the Arkansas Department of 

Environmental Quality (ADEQ). 

Specifically, the EPA is proposing to 

approve the State’s proposed SIP 

revision, which addresses nitrogen 

oxide (NOX) requirements for the 

Arkansas Electric Cooperative 

Corporation (AECC) Bailey Plant Unit 1; 

AECC McClellan Plant Unit 1; the 

American Electric Power/Southwestern 

Electric Power Company (AEP/ 

SWEPCO) Flint Creek Plant Boiler No. 

1; Entergy Arkansas, Inc. (Entergy) Lake 

Catherine Plant Unit 4; Entergy White 

Bluff Plant Units 1 and 2 and the 

Auxiliary Boiler; and Entergy 

Independence Plant Units 1 and 2. In 

conjunction with this proposed 

approval, we are proposing to withdraw 

federal implementation plan (FIP) 

emission limits for NOX that would 

otherwise apply to the nine 

aforementioned units. 

DATES: Written comments must be 

received on or before October 11, 2017. 

ADDRESSES: Submit your comments, 

identified by Docket No. EPA–R06– 

OAR–2015–0189, at http://

www.regulations.gov or via email to 

R6AIR_ARHaze@epa.gov. Follow the 

online instructions for submitting 

comments. Once submitted, comments 

cannot be edited or removed from 

Regulations.gov. The EPA may publish 

any comment received to its public 

docket. Do not submit electronically any 

information you consider to be 

Confidential Business Information (CBI) 

or other information whose disclosure is 

restricted by statute. Multimedia 

submissions (audio, video, etc.) must be 

accompanied by a written comment. 

The written comment is considered the 

official comment and should include 

discussion of all points you wish to 

make. The EPA will generally not 

consider comments or comment 

contents located outside of the primary 

submission (i.e. on the web, cloud, or 

other file sharing system). For 

additional submission methods, please 

contact Dayana Medina, 

medina.dayana@epa.gov. For the full 

EPA public comment policy, 

information about CBI or multimedia 

submissions, and general guidance on 

making effective comments, please visit 

http://www2.epa.gov/dockets/ 

commenting-epa-dockets. 

Docket: The index to the docket for 

this action is available electronically at 

www.regulations.gov and in hard copy 

at the EPA Region 6, 1445 Ross Avenue, 

Suite 700, Dallas, Texas. While all 

documents in the docket are listed in 

the index, some information may be 

publicly available only at the hard copy 

location (e.g., copyrighted material), and 

some may not be publicly available at 

either location (e.g., CBI). 

FOR FURTHER INFORMATION CONTACT: 

Dayana Medina, 214–665–7241, 

medina.dayana@epa.gov. To inspect the 

hard copy materials, please schedule an 

appointment with Dayana Medina or 

Mr. Bill Deese at 214–665–7253. 

SUPPLEMENTARY INFORMATION: 

Throughout this document wherever 

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

the EPA. 

Table of Contents 

I. Background 

A. The Regional Haze Program 

B. Our Previous Actions on Arkansas 

Regional Haze 

C. CSAPR as an Alternative to SourceSpecific NOX BART 

II. Our Evaluation of Arkansas’ Proposed 

Regional Haze SIP Revision 

A. Reliance on CSAPR To Satisfy NOX

BART 

B. Reasonable Progress Analysis for NOX

1. Regional Particulate Source 

Apportionment Tool (PSAT) Data for 

Caney Creek and Upper Buffalo 

2. Arkansas Source PSAT Data for Caney 

Creek and Upper Buffalo 

3. Arkansas’ Conclusions Regarding Key 

Pollutants and Source Category 

Contributions 

4. Our Evaluation of Arkansas’ Analysis 

C. Required Consultation 

III. Proposed Action 

A. Arkansas’ Proposed Regional Haze SIP 

Revision 

B. Partial FIP Withdrawal 

C. Clean Air Act Section 110(l) 

IV. Statutory and Executive Order Reviews 

I. Background 

A. The Regional Haze Program 

Regional haze is visibility impairment 

that is produced by a multitude of 

sources and activities that are located 

across a broad geographic area and emit 

fine particulates (PM2.5) (e.g., sulfates, 

nitrates, organic carbon (OC), elemental 

carbon (EC), and soil dust), and their 

precursors (e.g., sulfur dioxide (SO2), 

NOX, and in some cases, ammonia (NH3) 

and volatile organic compounds 

(VOCs)). Fine particle precursors react 

in the atmosphere to form PM2.5, which 

impairs visibility by scattering and 

absorbing light. Visibility impairment 

reduces the clarity, color, and visible 

distance that can be seen. PM2.5 can also 

cause serious adverse health effects and 

mortality in humans; it also contributes 

to environmental effects such as acid 

deposition and eutrophication. 

Section 169A of the CAA directs 

states to evaluate the use of retrofit 

controls at certain larger, often undercontrolled, older stationary sources in 

order to address visibility impacts from 


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1 Guidance for Setting Reasonable Progress Goals 

under the Regional Haze Program, June 1, 2007, 

memorandum from William L. Wehrum, Acting 

Assistant Administrator for Air and Radiation, to 

EPA Regional Administrators, EPA Regions 1–10 

(pp. 4–2, 5–1). 

2See 76 FR 64186 and 80 FR 18944. 

3 77 FR 14604. 

4 81 FR 66332; see also 81 FR 68319 (October 4, 

2016) (correction). 

5See the docket associated with this proposed 

rulemaking for a copy of the petitions for 

reconsideration and administrative stay submitted 

by the State of Arkansas; Entergy Arkansas Inc., 

Entergy Mississippi Inc., and Entergy Power LLC 

(collectively ‘‘Entergy’’); AECC; and the Energy and 

Environmental Alliance of Arkansas (EEAA). 

6See letter dated April 14, 2017, regarding 

‘‘Convening a Proceeding for Reconsideration of 

Final Rule, ‘Promulgation of Air Quality 

Implementation Plans; State of Arkansas; Regional 

Haze and Interstate Visibility Transport Federal 

Implementation Plan,’ published September 7, 

2016. 81 FR 66332.’’ A copy of this letter is 

included in the docket, Docket No. EPA–R06–OAR– 

2015–0189. 

7 82 FR 18994. 

8 82 FR 32284. 

9 70 FR 25161 (May 12, 2005). 

10 70 FR 39104, 39139 (July 6, 2005). 

these sources. Specifically, section 

169A(b)(2)(A) of the CAA requires states 

to revise their SIPs to contain such 

measures as may be necessary to make 

reasonable progress toward 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’’ (BART). Larger ‘‘fossil-fuel 

fired steam electric plants’’ are one of 

these source categories. Under the 

Regional Haze Rule, states are directed 

to conduct BART determinations for 

‘‘BART-eligible’’ sources that may be 

anticipated to cause or contribute to any 

visibility impairment in a Class I area. 

Section 169A(g)(2) of the CAA 

establishes that in determining BART, 

states must take into consideration the 

following five factors: (1) Costs of 

compliance, (2) the energy and nonair 

quality environmental impacts of 

compliance, (3) any existing pollution 

control technology in use at the source, 

(4) the remaining useful life of the 

source, and (5) the degree of 

improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology. The 

evaluation of BART for electric 

generating units (EGUs) that are located 

at fossil-fuel fired power plants having 

a generating capacity in excess of 750 

megawatts must follow the ‘‘Guidelines 

for BART Determinations Under the 

Regional Haze Rule’’ at appendix Y to 

40 CFR part 51 (hereinafter referred to 

as the ‘‘BART Guidelines’’). Rather than 

requiring source-specific BART 

controls, states also have the flexibility 

to adopt an emissions trading program 

or other alternative program as long as 

the alternative provides for greater 

progress towards improving visibility 

than BART. 

The vehicle for ensuring continuing 

progress towards achieving the natural 

visibility goal is the submission of a 

series of regional haze SIPs that contain 

long-term strategies to make reasonable 

progress towards natural visibility 

conditions and establish reasonable 

progress goals (RPGs) for every Class I 

area within the state. States have 

significant discretion in establishing 

RPGs,1 but are required to consider the 

following factors established in section 

169A of the CAA: (1) The costs of 

compliance; (2) the time necessary for 

compliance; (3) the energy and non-air 

quality environmental impacts of 

compliance; and (4) the remaining 

useful life of any potentially affected 

sources. States must determine whether 

additional control measures beyond 

BART and other ‘‘on the books’’ controls 

are reasonable based on a consideration 

of the four reasonable progress factors. 

States must demonstrate in their SIPs 

how these factors are considered when 

selecting the RPGs for each applicable 

Class I area. We commonly refer to this 

as the ‘‘reasonable progress analysis’’ or 

‘‘four factor analysis.’’ 

Additional information about the 

Regional Haze program can be found in 

the background sections of our previous 

proposed rulemakings on Arkansas 

regional haze.2

B. Our Previous Actions on Arkansas 

Regional Haze 

Arkansas submitted a SIP on 

September 9, 2008, to address the first 

regional haze implementation period. 

On August 3, 2010, Arkansas submitted 

a SIP revision with non-substantive 

revisions to the APCEC Regulation 19, 

Chapter 15; this Chapter identified the 

BART-eligible and subject-to-BART 

sources in Arkansas and established the 

BART emission limits for subject-toBART sources. On September 27, 2011, 

the State submitted supplemental 

information to address the regional haze 

requirements. We are hereafter referring 

to these regional haze submittals 

collectively as the ‘‘2008 Arkansas 

Regional Haze SIP.’’ On March 12, 2012, 

we partially approved and partially 

disapproved the 2008 Arkansas 

Regional Haze SIP.3 On September 27, 

2016, we published a FIP addressing the 

deficiencies identified in the 

disapproved portions of the 2008 

Arkansas Regional Haze SIP (the 

Arkansas Regional Haze FIP).4 Among 

other things, the FIP established NOX

emission limits under the BART 

requirements for Bailey Unit 1; 

McClellan Unit 1; Flint Creek Boiler No. 

1; Lake Catherine Unit 4; and White 

Bluff Units 1 and 2 and the Auxiliary 

Boiler. The FIP also established NOX

emission limits under the reasonable 

progress requirements for Independence 

Units 1 and 2. 

In response to petitions submitted by 

the State of Arkansas and industry 

parties seeking reconsideration and an 

administrative stay of the final Arkansas 

Regional Haze FIP,5 in a letter dated 

April 14, 2017, we announced the 

convening of a proceeding to reconsider 

several elements of the FIP, including 

the appropriate compliance dates for the 

NOX emission limits for Flint Creek 

Unit 1, White Bluff Units 1 and 2, and 

Independence Units 1 and 2.6 EPA also 

published a notice in the Federal 

Register on April 25, 2017, 

administratively staying the 

effectiveness of the 18-month NOX

compliance dates in the FIP for these 

units for a period of 90 days.7 On July 

13, 2017, the EPA published a proposed 

rule that would extend the NOX

compliance dates for Flint Creek Unit 1, 

White Bluff Units 1 and 2, and 

Independence Units 1 and 2, by 21 

months to January 27, 2020.8

C. CSAPR as an Alternative to SourceSpecific NOX BART 

In 2005, the EPA published the Clean 

Air Interstate Rule (CAIR), which 

required 27 states and the District of 

Columbia to reduce emissions of SO2

and NOX that significantly contribute to 

or interfere with maintenance of the 

1997 national ambient air quality 

standards (NAAQS) for fine particulates 

and/or 8-hour ozone in any downwind 

state.9 EPA demonstrated that CAIR 

would achieve greater reasonable 

progress toward the national visibility 

goal than would BART; therefore, states 

could rely on CAIR as an alternative to 

EGU BART for SO2 and NOX.10

Although Arkansas was subject to 

certain of the NOX requirements of 

CAIR, including the state-wide ozone 

season NOX budget but not the annual 

NOX budget, and although this would 

have been sufficient for Arkansas to rely 

on CAIR to satisfy NOX BART, it elected 

not to rely on CAIR in its 2008 Regional 

Haze SIP to satisfy the NOX BART 

requirement for its EGUs. 

On July 11, 2008, the D.C. Circuit 

found CAIR was fatally flawed and on 

December 23, 2008, the Court remanded 

CAIR to EPA without vacatur to 

‘‘preserve the environmental benefits 


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11North Carolina v. EPA, 531 F.3d 896, 901 (D.C. 

Cir. 2008), modified, 550 F.3d 1176, 1178 (D.C. Cir. 

2008). 

12 76 FR 48207 (August 8, 2011). 

13 76 FR 82219 (December 30, 2011). 

14The limited disapproval triggered the EPA’s 

obligation to issue a FIP or approve a SIP revision 

to correct the relevant deficiencies within 2 years 

of the final limited disapproval action. CAA section 

110(c)(1); 77 FR 33642, at 33654 (June 7, 2012). 

15See 40 CFR 51.308(e)(4). 

16See 77 FR 33642, at 33654. 

17Arkansas’ ozone season NOX budget was not 

included in the remand. EME Homer City 

Generation v. EPA, 795 F.3d 118, 138 (D.C. Cir. 

2015). 

18 81 FR74504 (October 26, 2016). 

19 81 FR 78954 (November 10, 2016). 

20 77 FR 14604. 

provided by CAIR’’.11 In 2011, acting on 

the D.C. Circuit’s remand, we 

promulgated the Cross-State Air 

Pollution Rule (CSAPR) to replace CAIR 

and issued FIPs to implement the rule 

in CSAPR-subject states.12 Arkansas 

EGUs are covered under CSAPR for 

ozone season NOX.13

In 2012, we issued a limited 

disapproval of several states’ regional 

haze SIPs because of reliance on CAIR 

as an alternative to EGU BART for SO2

and/or NOX.14 We also determined that 

CSAPR would provide for greater 

reasonable progress than BART and 

amended the Regional Haze Rule to 

allow for CSAPR participation as an 

alternative to source-specific SO2 and/or 

NOX BART for EGUs, on a pollutantspecific basis.15 As Arkansas did not 

rely on CAIR to satisfy the NOX BART 

requirements in the 2008 Regional Haze 

SIP, Arkansas was not included in the 

EPA’s limited disapproval of regional 

haze SIPs that relied on CAIR to satisfy 

certain regional haze requirements.16 As 

noted above, in the 2012 rulemaking in 

which we promulgated those limited 

disapprovals, the EPA also 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. 

CSAPR has been subject to extensive 

litigation, and on July 28, 2015, the D.C. 

Circuit issued a decision generally 

upholding CSAPR but remanding 

without vacating the CSAPR emissions 

budgets for a number of states.17 We are 

in the process of responding to the 

remand of these CSAPR budgets. On 

October 26, 2016, we finalized an 

update to the CSAPR rule that addresses 

the 1997 ozone NAAQS portion of the 

remand and also addresses the CAA 

requirements regarding interstate 

transport for the 2008 ozone NAAQS.18

Additionally, three states, Alabama, 

Georgia, and South Carolina, have 

adopted or committed to adopt SIPs to 

replace the remanded FIPs and will 

continue the states’ participation in the 

CSAPR program with the same budgets. 

On November 10, 2016, we proposed a 

rule intended to address the remainder 

of the Court’s remand.19 This separate 

proposed rule includes a sensitivity 

analysis showing that the set of actions 

EPA has taken or expects to take in 

response to the D.C. Circuit’s decision 

would not adversely impact the analytic 

demonstration for our 2012 

determination that CSAPR participation 

meets the criteria to qualify as an 

alternative to BART. Based on that 

assessment, the EPA proposed that 

states may continue to rely on CSAPR 

as being better than BART on a 

pollutant-specific basis. As of the date 

of this proposed action, EPA has not yet 

finalized that proposed rulemaking. 

EPA can approve regional haze SIP 

submissions that rely on participation in 

CSAPR as an alternative to BART only 

after finalizing the November 2016 

proposed rule or otherwise determining 

that participation in CSAPR remains a 

viable BART alternative. 

II. Our Evaluation of Arkansas’ 

Proposed Regional Haze SIP Revision 

On July 12, 2017, Arkansas submitted 

a proposed SIP revision with a request 

for parallel processing, addressing the 

NOX requirements for Bailey Unit 1, 

McClellan Unit 1, Flint Creek Boiler No. 

1, Lake Catherine Unit 4, White Bluff 

Units 1 and 2 and the Auxiliary Boiler, 

and Independence Units 1 and 2 (July 

2017 Arkansas Regional Haze SIP). This 

proposed SIP revision is the subject of 

this proposed action, in conjunction 

with our proposed withdrawal of the 

emission limits for NOX that we 

promulgated in our September 27, 2016 

FIP for the same EGUs addressed in the 

proposed SIP revision. The EPA is 

proposing action on the SIP revision at 

the same time that ADEQ is completing 

the corresponding public comment and 

rulemaking process at the state level. 

The July 2017 SIP revision request will 

not be complete and will not meet all 

the SIP approvability criteria until the 

state completes the public process and 

submits the final, adopted SIP revision 

with a letter from the Governor or 

Governor’s designee to EPA. The EPA is 

proposing to approve the SIP revision 

request after completion of the state 

public process and final submittal. 

Arkansas’ July 2017 Regional Haze 

SIP revision proposal addresses certain 

portions of the 2008 Regional Haze SIP 

that were partially disapproved by EPA 

on March 12, 2012.20 The 2008 Regional 

Haze SIP included source-by-source 

NOX BART determinations for subjectto-BART EGUs in Arkansas. EPA’s 

March 12, 2012 final action on the 2008 

Regional Haze SIP included disapproval 

of the State’s source-by-source NOX

BART determinations for these EGUs. 

These EGUs are Bailey Unit 1; 

McClellan Unit 1; Flint Creek Boiler No. 

1; Lake Catherine Unit 4; White Bluff 

Units 1 and 2 and its auxiliary boiler. 

EPA’s March 12, 2012 final action on 

the 2008 Regional Haze SIP also 

included a determination that the State 

did not satisfy the statutory and 

associated regulatory requirements for 

the reasonable progress analysis. We 

promulgated a FIP on September 27, 

2016, that established source specific 

NOX BART emission limits for these 

seven EGUs and NOX emission limits 

under reasonable progress for 

Independence Units 1 and 2 to address 

the disapproved portions of the 2008 

Regional Haze SIP submittal. 

Arkansas’ July 2017 Regional Haze 

SIP revision addresses the NOX BART 

requirements for Arkansas’ EGUs by 

relying on CSAPR as an alternative to 

BART. The July 2017 Regional Haze SIP 

revision proposal also makes the 

determination that no additional NOX

emission controls for Arkansas sources, 

beyond participation in CSAPR’s ozone 

season NOX trading program, are 

required for achieving reasonable 

progress in Arkansas. As noted above, 

the July 2017 Regional Haze SIP 

revision addresses NOX requirements 

for the same EGUs for which we 

established source-specific NOX

emission limits in our September 27, 

2016 FIP. 

A. Reliance on CSAPR To Satisfy NOX

BART 

Arkansas’ 2017 Regional Haze SIP 

revision proposal relies on EPA’s 

determination that CSAPR provides for 

greater reasonable progress than BART 

to address the NOX BART requirements 

for its EGUs. Consistent with 40 CFR 

51.308(e)(4), Arkansas makes the 

determination that since the Arkansas 

EGUs are currently subject to the 

CSAPR requirements for ozone-season 

NOX, the State need not require subjectto-BART EGUs to install, operate, and 

maintain BART for NOX. We are 

proposing to find that it is appropriate 

for Arkansas to rely on participation in 

the CSAPR ozone season NOX trading 

program to satisfy the NOX BART 

requirements for Arkansas EGUs. EPA’s 

2012 determination and our November 

2016 proposed determination that 

implementation of CSAPR meets the 

criteria for a BART alternative are based 

on an analytic demonstration that 

implementation of CSAPR across all 

states subject to CSAPR would result in 


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21 77 FR 33642. 

22 81 FR 78954. 

23 77 FR 33642. 

24 81 FR 78954. 

25The central states region includes Texas, 

Oklahoma, Louisiana, Arkansas, Kansas, Missouri, 

Nebraska, Iowa, Minnesota, and the tribal 

governments within these states. 

26Point sources (considering sources both in and 

outside Arkansas) are responsible for approximately 

81.04 Mm¥1 out of a total light extinction of 115.87 

Mm¥1 at Caney Creek and 77.8 Mm¥1 out of a total 

light extinction of 115 Mm¥1 at Upper Buffalo on 

the 20% worst days in 2002. See Table 1 of the 2017 

Arkansas Regional Haze SIP revision, page 10. 

27Area sources (considering sources both in and 

outside Arkansas) are responsible for approximately 

17.81 Mm¥1 out of a total light extinction of 115.87 

Mm¥1 at Caney Creek and 20.46 Mm¥1 out of a 

total light extinction of 115 Mm¥1 at Upper Buffalo 

on the 20% worst days in 2002. See Table 1 of the 

2017 Arkansas Regional Haze SIP revision, page 10. 

greater reasonable progress than BART 

toward restoring natural visibility 

conditions in relevant locations.21 Our 

proposed approval of Arkansas’ 2017 

Regional Haze SIP revision is dependent 

upon our November 10, 2016 proposed 

determination,22 which is based in part 

on the analysis we conducted for our 

2012 determination that CSAPR is better 

than BART,23 but with updates to reflect 

the changes to CSAPR to address the 

Court’s remand. 

We are proposing to find that the NOX

BART requirements for EGUs in 

Arkansas will be satisfied by 

participation in CSAPR’s ozone season 

NOX program. Finalization of today’s 

proposed SIP approval is dependent 

upon finalization of the November 10, 

2016 proposed finding that CSAPR 

continues to be better than BART or 

EPA otherwise determining that 

participation in CSAPR remains a viable 

alternative to source-specific BART.24

B. Reasonable Progress Analysis for NOX

In determining whether additional 

controls are necessary under the 

reasonable progress requirements and in 

establishing RPGs, a state must consider 

four statutory factors in section 

169A(g)(1) of the CAA: (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 existing source subject 

to such requirements. 

Arkansas’ 2017 Regional Haze SIP 

revision includes a discussion of the key 

pollutants and source categories that 

contribute to visibility impairment in 

Arkansas Class I areas. In this SIP 

revision, Arkansas refers back to the 

2008 Arkansas Regional Haze SIP, 

which included air quality modeling 

performed by the Central Regional Air 

Planning Association (CENRAP) in 

support of SIP development in the 

central states region.25 The CENRAP 

modeling included PSAT with CAMx 

version 4.4, which was used to provide 

source apportionment by geographic 

regions and major source categories for 

pollutants that contribute to visibility 

impairment at each of the Class I areas 

in the central states region. Arkansas’ 

2017 Regional Haze SIP revision 

provides a discussion of region-wide 

PSAT results and also provides a 

discussion of Arkansas PSAT data. The 

conclusion that Arkansas’ 2017 Regional 

Haze SIP revision draws from this representation of the CENRAP modeling 

results is that sulfate (SO4) from point 

sources is the primary contributor to 

total light extinction at Arkansas Class 

I areas on the 20% worst days, whether 

looking at all regional sources or only 

Arkansas sources. In contrast, nitrate 

(NO3) is responsible for a much smaller 

proportion of total light extinction at 

Arkansas Class I areas. With regard to 

light extinction due to NO3, the PSAT 

results show that when looking at only 

Arkansas sources, the majority of the 

light extinction due to NO3 is clearly 

attributed to on-road mobile sources 

whereas looking at all region-wide 

sources the light extinction due to NO3

is nearly equally attributed to on-road 

mobile and point sources on the 20% 

worst days in 2002. In particular, NO3

from Arkansas point sources contribute 

0.36 inverse megameters (Mm¥1) out of 

a total light extinction of approximately 

115.87 Mm¥1 at Caney Creek on the 

20% worst days in 2002. NO3 from 

Arkansas point sources also contribute 

0.18 Mm¥1 out of a total light extinction 

of approximately 115 Mm¥1 at Upper 

Buffalo on the 20% worst days in 2002. 

In terms of percent contribution, NO3

from Arkansas point sources contribute 

approximately 0.31% of the total light 

extinction at Caney Creek and 0.16% of 

the total light extinction at Upper 

Buffalo on the 20% worst days in 2002. 

NO3 from Arkansas area sources had an 

even smaller contribution to light 

extinction on the 20% worst days in 

2002, contributing approximately 0.18 

Mm¥1 out of a total light extinction of 

approximately 115.87 Mm¥1 at Caney 

Creek and 0.11 Mm¥1 out of a total light 

extinction of approximately 115 Mm¥1

at Upper Buffalo. In terms of percent 

contribution, NO3 from Arkansas area 

sources contribute approximately 0.16% 

of the total light extinction at Caney 

Creek and 0.1% of the total light 

extinction at Upper Buffalo on the 20% 

worst days in 2002. Based on its 

evaluation of the CENRAP modeling 

results, Arkansas concludes that given 

the small amount of visibility 

impairment due to NO3 from Arkansas 

point sources, it does not expect that 

additional NOX controls on Arkansas 

point sources would yield meaningful 

visibility improvements at Arkansas 

Class I areas. Taking this into 

consideration and given that Arkansas 

EGUs are required to participate in the 

CSAPR ozone season NOX trading 

program, the state determines it is 

appropriate to screen out point sources 

in Arkansas from further evaluation of 

NOX controls under reasonable progress. 

1. Regional Particulate Source 

Apportionment Tool (PSAT) Data for 

Caney Creek and Upper Buffalo 

Arkansas’ 2017 Regional Haze SIP 

revision explains that the region-wide 

PSAT results show that on the 20% 

worst days in 2002, point sources are 

the primary contributor to total light 

extinction at Arkansas’ Class I areas. 

Arkansas explains that point sources are 

responsible for approximately 60% of 

the total light extinction at each 

Arkansas Class I area on the 20% worst 

days in 2002.26 Area sources are the 

next largest contributor to total light 

extinction at Arkansas Class I areas, 

contributing approximately 13% and 

16% of light extinction at Caney Creek 

and Upper Buffalo, respectively.27 The 

remaining source categories each 

contribute between 2% and 6% of total 

light extinction at Arkansas’ Class I 

areas. 

Looking at the modeled relative 

contribution to light extinction from 

each species on the 20% worst days in 

2002, the PSAT results show that SO4

contributes approximately 87.05 Mm¥1

to the total light extinction at Caney 

Creek and 83.18 Mm¥1 to the total light 

extinction at Upper Buffalo, or 

approximately 72% and 69% of the total 

modeled light extinction at each Class I 

area, respectively. SO4 due to point 

sources (including point sources both in 

and outside Arkansas) contributes 75.1 

Mm¥1 to the total light extinction at 

Caney Creek and 72.17 Mm¥1 at Upper 

Buffalo, or approximately 62% and 60% 

of the total light extinction at each Class 

I area on the 20% worst days in 2002, 

respectively. SO4 due to point sources is 

responsible for approximately 86% and 

87% of the light extinction due to SO4

at Caney Creek and Upper Buffalo, 

respectively. The other source categories 

(i.e., natural, on-road, non-road, and 

area sources) each contribute much 

smaller proportions of light extinction 

due to SO4. By comparison, NO3

contributes approximately 13.78 Mm¥1

to the total light extinction at Caney 

Creek and 13.3 Mm¥1 at Upper Buffalo, 

or approximately 11% of the total light 

extinction at each Class I area, 

respectively. Primary organic aerosols 


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Federal Register / Vol. 82, No. 174 / Monday, September 11, 2017 / Proposed Rules 42631 

28Arkansas sources contribute approximately 

13.58 Mm¥1 out of a total light extinction of 115.87 

Mm¥1 at Caney Creek on the 20% worst days in 

2002, and 13.46 Mm¥1 out of a total light extinction 

of 115 Mm¥1 at Upper Buffalo. See Tables 1 and 

3 of the 2017 Arkansas Regional Haze SIP revision, 

pages 10 and 16. 

29Arkansas sources contribute approximately 

11.24 Mm¥1 out of a total light extinction of 69.55 

Mm¥1 at Caney Creek on the 20% worst days in 

2018, and 12.02 Mm¥1 out of a total light extinction 

of 70.79 Mm¥1 at Upper Buffalo. See Tables 2 and 

4 of the 2017 Arkansas Regional Haze SIP revision, 

pages 13 and 19. 

(POA) contribute approximately 8%, 

elemental carbon (EC) contributes 

approximately 4%, soil contributes 

approximately 1%, and crustal material 

(CM) contributes approximately 3 to 5% 

of the total modeled visibility extinction 

at each Arkansas Class I area on the 

20% worst days in 2002. NO3 due to onroad sources contributes 4.7 Mm¥1 and 

NO3 due to point sources contributes 

4.06 Mm¥1 at Caney Creek, or 

approximately one-third of the light 

extinction due to NO3 at the Class I area. 

NO3 due to point sources contributes 

3.93 Mm¥1 and NO3 due to on-road 

sources contributes 4.14 Mm¥1 at 

Upper Buffalo, or approximately 30% to 

31% of the light extinction due to NO3

at the Class I area. Area sources are the 

primary driver of light extinction 

attributed to POA, soil, and CM. Nonroad and area sources are the primary 

drivers of light extinction attributed to 

EC. 

The PSAT results also show that point 

sources are projected to remain the 

primary contributor to light extinction 

at Arkansas’ Class I areas on the 20% 

worst days in 2018, contributing 

approximately 45.27 Mm¥1 at Caney 

Creek and 43.02 Mm¥1 at Upper 

Buffalo, or approximately 65% of total 

light extinction at Caney Creek and 61% 

of total light extinction at Upper 

Buffalo. Area sources are projected to 

continue being the second largest 

contributor to light extinction on the 

20% worst days in 2018, contributing 

approximately 16.96 Mm¥1 at Caney 

Creek and 19.71 Mm¥1 at Upper 

Buffalo, or approximately 24% of total 

light extinction at Caney Creek and 28% 

of total light extinction at Upper 

Buffalo. The PSAT results show that 

natural, on-road, and non-road sources 

are projected to continue to contribute 

a very small portion of total light 

extinction at Arkansas’ Class I areas on 

the 20% worst days in 2018. 

Arkansas explains that the PSAT 

results show that the light extinction 

attributed to SO4 is projected to 

decrease by approximately 44% at 

Caney Creek and 45% at Upper Buffalo 

on the 20% worst days in 2018. 

However, SO4 is projected to continue 

being the primary driver of total light 

extinction at Arkansas Class I areas on 

the 20% worst days in 2018, and point 

sources are projected to continue being 

the primary source of light extinction 

due to SO4. SO4 due to point sources is 

projected to contribute approximately 

39.83 Mm¥1 at Caney Creek and 37.09 

Mm¥1 at Upper Buffalo, or 

approximately 53% and 49% of total 

light extinction on the 20% worst days 

in 2018 at each Class I area, 

respectively. The other species (i.e., 

NO3, POA, EC, soil, and CM) are also 

projected to have reductions in their 

contribution to total light extinction at 

Caney Creek and Upper Buffalo in 2018. 

These species’ relative contributions to 

total light extinction in 2018 are 

projected to remain much smaller than 

that of SO4. For example, NO3 is 

projected to contribute approximately 

7.57 Mm¥1 at Caney Creek and 9.22 

Mm¥1 at Upper Buffalo on the 20% 

worst days in 2018, or approximately 10 

to 12% of the total light extinction at 

each Class I area. 

2. Arkansas Source PSAT Data for 

Caney Creek and Upper Buffalo 

In its 2017 Regional Haze SIP 

submittal, Arkansas explains that 

species attributed to Arkansas sources 

in particular contribute approximately 

10% of total light extinction on the 20% 

worst days in 2002 at Arkansas Class I 

areas,28 and are projected to contribute 

approximately 13% to 14% of total light 

extinction on the 20% worst days in 

2018.29

When considering only Arkansas 

sources, area sources are responsible for 

a greater portion of the visibility 

extinction than point sources on the 

20% worst days in 2002 at Arkansas 

Class I areas. For example, Arkansas 

area sources contribute 5.03 Mm¥1, or 

approximately 37% of the light 

extinction attributed to Arkansas 

sources at Caney Creek, and 

approximately 4% of total light 

extinction at the Class I area on the 20% 

worst days in 2002. Arkansas area 

sources also contribute 6.72 Mm¥1, or 

approximately 50% of light extinction 

attributed to Arkansas sources at Upper 

Buffalo, and approximately 6% of the 

total light extinction at the Class I area 

on the 20% worst days in 2002. By 

comparison, Arkansas point sources 

contribute 3.85 Mm¥1, or 

approximately 28% of the light 

extinction attributed to Arkansas 

sources at Caney Creek, and 

approximately 3% of the total light 

extinction at the Class I area on the 20% 

worst days in 2002. Arkansas point 

sources also contribute 3.25 Mm¥1, or 

approximately 24% of light extinction 

attributed to Arkansas sources at Upper 

Buffalo, and approximately 3% of the 

total light extinction at the Class I area 

on the 20% worst days in 2002. The 

other source categories in Arkansas each 

contribute between 7% and 14% to light 

extinction attributed to Arkansas 

sources at Caney Creek and Upper 

Buffalo. 

Looking at each species and their 

modeled relative contributions to light 

extinction at Arkansas Class I areas, SO4

from all Arkansas sources contributes 

4.14 Mm¥1 at Caney Creek and 3.97 

Mm¥1 at Upper Buffalo, or 

approximately 3% of the total modeled 

light extinction at each Class I area on 

the 20% worst days in 2002. SO4 due to 

Arkansas point sources contributes 2.94 

Mm¥1 at Caney Creek and 2.62 Mm¥1

at Upper Buffalo, or approximately twothirds of the light extinction attributed 

to SO4 from all Arkansas sources at each 

Class I area. POA from Arkansas sources 

contributes approximately 3% and 2% 

of the total light extinction on the 20% 

worst days in 2002 at Caney Creek and 

Upper Buffalo, respectively. NO3 from 

all Arkansas sources contributes 2.11 

Mm¥1 at Caney Creek and 1.07 Mm¥1

at Upper Buffalo, or approximately 2% 

and 1% of the total light extinction on 

the 20% worst days in 2002 at each 

Class I area, respectively. NO3 due to 

Arkansas on-road sources contributes 

1.09 Mm¥1 at Caney Creek and 0.54 

Mm¥1 at Upper Buffalo, or 

approximately 50% of the light 

extinction attributed to NO3 from 

Arkansas sources at Arkansas Class I 

areas on the 20% worst days in 2002. 

NO3 due to Arkansas point sources 

contributes 0.36 Mm¥1 at Caney Creek 

and 0.18 Mm¥1 at Upper Buffalo, or 

approximately 17% of the light 

extinction attributed to NO3 from all 

Arkansas sources at each Class I area. 

EC from Arkansas sources contributes 

approximately 1% and soil from 

Arkansas sources contributes 

approximately 0.2% to the total light 

extinction at Caney Creek and Upper 

Buffalo on the 20% worst days in 2002. 

CM from Arkansas sources, primarily 

area sources, contribute approximately 1 

and 2% of total light extinction at Caney 

Creek and Upper Buffalo, respectively. 

The PSAT results show that area 

sources are projected to continue having 

a larger impact on visibility extinction 

than point sources at Caney Creek and 

Upper Buffalo when only considering 

sources located in Arkansas on the 20% 

worst days in 2018. For example, 

Arkansas area sources are projected to 

contribute 4.84 Mm¥1 at Caney Creek, 

or approximately 43% of the light 

extinction attributed to Arkansas 

sources at Caney Creek, and 


asabaliauskas on DSKBBXCHB2PROD with PROPOSALS
42632 Federal Register / Vol. 82, No. 174 / Monday, September 11, 2017 / Proposed Rules 

30See Appendix A of Arkansas’ 2017 Regional 

Haze SIP submittal, which can be found in the 

docket associated with this proposed rulemaking. 

31 In the FIP we explained that the CENRAP 

CAMx modeling with PSAT showed that point 

sources are responsible for a majority of the light 

extinction at Arkansas Class I areas on the 20% 

worst days in 2002 (this is taking into account all 

pollutant species and sources both in and outside 

Arkansas). We reasoned that since other source 

types (i.e., natural, on-road, non-road, and area) 

approximately 6% of the total light 

extinction at that Class I area on the 

20% worst days in 2018. Arkansas area 

sources are also projected to contribute 

6.52 Mm¥1 at Upper Buffalo, or 

approximately 54% of the light 

extinction attributed to Arkansas 

sources at Upper Buffalo, and 

approximately 8% of the total light 

extinction at that Class I area on the 

20% worst days in 2018. By 

comparison, Arkansas point sources are 

projected to contribute 4.05 Mm¥1 at 

Caney Creek and 3.63 Mm¥1 at Upper 

Buffalo, or approximately 36% of the 

light extinction attributed to Arkansas 

sources at Caney Creek and 

approximately 30% of the light 

extinction attributed to Arkansas 

sources at Upper Buffalo. Other source 

categories in Arkansas are projected to 

contribute between 2% and 9% each to 

light extinction from Arkansas sources 

at Arkansas Class I areas on the 20% 

worst days in 2018. 

The PSAT results also show that light 

extinction attributed to Arkansas NO3

sources is projected to decrease by 62% 

at Caney Creek and 41% at Upper 

Buffalo on the 20% worst days in 2018, 

largely due to a decrease in light 

extinction attributed to NO3 from 

Arkansas on-road sources. Overall light 

extinction due to SO4 from Arkansas 

sources (all source categories combined) 

is projected to decrease at Arkansas 

Class I areas. However, light extinction 

due to SO4 from point sources located 

in Arkansas is projected to increase by 

4% at Caney Creek and 5% at Upper 

Buffalo on the 20% worst days in 2018. 

Arkansas’ 2017 Regional Haze SIP 

revision states that even so, the 

contribution to total light extinction of 

SO4 from Arkansas point sources 

remains relatively small—3% of total 

light extinction at each Arkansas Class 

I area. 

3. Arkansas’ Conclusions Regarding Key 

Pollutants and Source Category 

Contributions 

Arkansas asserts that when only 

sources located in Arkansas are 

considered, light extinction due to area 

sources (all pollutant species 

considered) is greater compared to point 

sources for both Caney Creek and Upper 

Buffalo on the 20% worst days both in 

2002 and in 2018. Even though area 

sources contribute a larger proportion of 

the total light extinction compared to 

other source categories when only 

Arkansas sources are considered, 

Arkansas asserts that the costeffectiveness of controlling many 

individual small area sources is difficult 

to quantify. Therefore, Arkansas did not 

evaluate area sources for controls under 

reasonable progress. 

Arkansas also asserts that the regionwide PSAT data indicate that the 

relative regional contribution of SO4 to 

light extinction at Arkansas Class I areas 

is much higher than that of other 

pollutants on the 20% worst days. 

However, the PSAT results for Arkansas 

sources show that the relative 

contribution to light extinction of the 

various species due to Arkansas sources 

is not as weighted toward SO4 compared 

to the region-wide contribution results. 

Nevertheless, SO4 is still the species 

with the largest contribution to light 

extinction at Caney Creek and Upper 

Buffalo on the 20% worst days in both 

the regional contribution results and the 

Arkansas source contribution results. 

After examination of both region-wide 

PSAT data and data for Arkansas 

sources, Arkansas identifies SO4 as the 

key species contributing to light 

extinction at Caney Creek and Upper 

Buffalo. Since the primary driver of SO4

formation is emissions of SO2 from 

point sources when looking at both the 

regional PSAT data and the data for 

Arkansas sources, Arkansas states it will 

evaluate in a subsequent SIP revision 

large sources of SO2 to determine 

whether their emissions and proximity 

to Arkansas Class I areas warrant further 

analysis using the four statutory factors. 

Arkansas also asserts that only a very 

small proportion of total light extinction 

is due to NO3 from Arkansas sources 

and that this proportion has historically 

been driven by on-road sources, which 

are regulated by national vehicle 

emission standards. Arkansas points out 

that the PSAT data show that NO3 from 

Arkansas point sources contributes less 

than 0.5% of the total light extinction at 

Caney Creek and Upper Buffalo on the 

20% worst days in 2002, and that this 

contribution is expected to decrease on 

the 20% worst days in 2018. Arkansas 

asserts that the level of visibility 

impairment due to NO3 from Arkansas 

point sources is miniscule, and that the 

state therefore does not anticipate that 

additional NOX controls on Arkansas 

point sources would yield meaningful 

visibility improvements at Arkansas 

Class I areas. Additionally, Arkansas 

points out that Arkansas EGUs with a 

nameplate capacity of 25 megawatts 

(MW) or greater participate in the 

CSAPR ozone season NOX emissions 

trading program. Arkansas notes that the 

Independence facility’s EGUs 

participate in CSAPR for ozone season 

NOX and also that the EPA promulgated 

NOX controls for this facility in the 

Arkansas Regional Haze FIP to ensure 

reasonable progress toward improving 

visibility. Arkansas makes the 

determination that because of the small 

impact at Arkansas Class I areas due to 

NO3 from Arkansas sources, 

participation of Arkansas EGUs in 

CSAPR for ozone season NOX satisfies 

the reasonable progress requirements for 

NOX for sources in Arkansas. 

Further, Arkansas states that the 2018 

CSAPR trading program ozone season 

allocations for Arkansas EGUs add up to 

3,708 NOX tons less than the 2016 ozone 

season NOX emissions from Arkansas 

EGUs.30 Arkansas also states that it 

anticipates that some EGUs will choose 

to install combustion controls to comply 

with CSAPR that would achieve 

emissions reductions year-round, not 

just in the ozone season. Therefore, 

Arkansas anticipates that the total 

annual NOX reductions associated with 

compliance with the 2018 CSAPR ozone 

season trading program would be greater 

than 3,708 NOX tons. 

4. Our Evaluation of Arkansas’ Analysis 

We agree with Arkansas’ assertion 

that when only sources located in 

Arkansas are considered, light 

extinction due to area sources (all 

pollutant species considered) is greater 

compared to that of point sources for 

both Caney Creek and Upper Buffalo on 

the 20% worst days in 2002. In 

particular, light extinction due to 

Arkansas areas sources (all pollutant 

species considered) was 5.03 Mm¥1 out 

of total light extinction of 115.87 Mm¥1

at Caney Creek and 6.72 Mm¥1 out of 

total light extinction of 115 Mm¥1 at 

Upper Buffalo. By comparison, light 

extinction due to Arkansas point 

sources (all pollutant species 

considered) was 3.85 Mm¥1 out of total 

light extinction of 115.87 Mm¥1 at 

Caney Creek and 3.25 Mm¥1 out of total 

light extinction of 115 Mm¥1 at Upper 

Buffalo. We also agree that the cost of 

controlling many individual small area 

sources may be difficult to quantify, and 

we are therefore proposing to find that 

it is acceptable for Arkansas to choose 

not to evaluate area sources for controls 

under reasonable progress in this 

implementation period. This is 

consistent with EPA’s decision not to 

conduct a four factor analysis of area 

sources under reasonable progress in 

this implementation period in the 

Arkansas Regional Haze FIP.31


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Federal Register / Vol. 82, No. 174 / Monday, September 11, 2017 / Proposed Rules 42633 

each contributed a much smaller proportion of the 

total light extinction at each Class I area, it was 

appropriate to focus only on point sources in our 

reasonable progress analysis for this 

implementation period. See 80 FR 18944 and 81 FR 

66332 at 66336. See also the ‘‘Arkansas Regional 

Haze FIP Response to Comments (RTC) Document,’’ 

pages 71–99. 

32 80 FR 18996. 

33See 80 FR 18944 and 81 FR 66332 at 66336. 

See also the ‘‘Arkansas Regional Haze FIP RTC 

Document,’’ pages 71–99. 

34See Excel spreadsheet titled ‘‘Nitrate_

percentage_extinction_CACR_UPBU.xlsx.’’ This 

spreadsheet is found in the docket associated with 

this proposed rulemaking. 

35 81 FR 66332; see also 81 FR 68319 (October 4, 

2016) (correction). 

36 80 FR 18996. 

37 80 FR 18996. 

38 80 FR 18995. 

39 81 FR 66332. 

We agree with Arkansas that the 

PSAT results for Arkansas sources show 

that the relative contribution to light 

extinction of SO4 on the 20% worst days 

at Arkansas Class I areas is not as great 

compared to the regional contribution 

results. However, SO4 is still the species 

with the largest contribution to light 

extinction at Caney Creek and Upper 

Buffalo on the 20% worst days in both 

the regional data and the Arkansas 

source data. Therefore, we agree with 

Arkansas’ identification of SO4 as the 

key species contributing to light 

extinction at Caney Creek and Upper 

Buffalo on the 20% worst days. This is 

consistent with our finding in the 

Arkansas Regional Haze FIP that the 

CENRAP’s CAMx modeling shows that 

SO4 from point sources is the driver of 

regional haze at Caney Creek and Upper 

Buffalo on the 20% worst days in both 

2002 and 2018.32

With regard to NOX, we also accept 

Arkansas’ assertion that a very small 

proportion of total light extinction is 

due to NO3 from Arkansas sources and 

that this is driven by on-road sources. 

Because on-road sources are primarily 

regulated by national vehicle emission 

standards. we are proposing to find that 

it is reasonable for Arkansas to choose 

not to evaluate on-road sources for 

additional NOX control measures to 

address visibility impairment in this 

implementation period. This is 

consistent with EPA’s decision not to 

conduct a four factor analysis of on-road 

mobile sources under reasonable 

progress in this implementation period 

in the Arkansas Regional Haze FIP.33

Arkansas points out that the PSAT 

data show that NO3 from Arkansas point 

sources contributes less than 0.5% of 

the total light extinction at Caney Creek 

and Upper Buffalo on the 20% worst 

days in 2002, and that this contribution 

is expected to decrease on the 20% 

worst days in 2018. NO3 from Arkansas 

point sources contributes 0.36 Mm¥1

out of a total light extinction of 115.87 

Mm¥1 at Caney Creek and 0.18 Mm¥1

out of a total light extinction of 115 

Mm¥1 at Upper Buffalo on the 20% 

worst days in 2002. Arkansas considers 

this level of visibility impairment due to 

NO3 from Arkansas point sources to be 

miniscule. Although the 2017 Regional 

Haze SIP revision does not provide a 

discussion of data from the existing 

visibility monitoring network, the 

Interagency Monitoring of Protected 

Visual Environments (IMPROVE) 

monitoring network, we looked at recent 

IMPROVE monitor data to determine the 

level of contribution from NO3 to the 

monitored light extinction at Caney 

Creek and Upper Buffalo. The monitor 

data show that for the 20% most 

impaired days in 2013–2015, the 

average contribution of NO3 to total 

extinction (including Rayleigh) was 

approximately 9.43 Mm¥1 out of a total 

average light extinction of 69.13 Mm¥1

at Caney Creek and 15.25 Mm¥1 out of 

a total average light extinction of 66.37 

Mm¥1 at Upper Buffalo. In terms of 

percent contribution, the average 

contribution of NO3 to total light 

extinction was approximately 14% at 

Caney Creek and 23% at Upper 

Buffalo.34 This consists of NO3 from all 

source categories (i.e., point, area, onroad, non-road, and natural) and from 

all sources, rather than just Arkansas 

sources. By comparison, the monitor 

data show that the average contribution 

of SO4 to total extinction was 

approximately 34.21 Mm¥1 out of a 

total average light extinction of 69.13 

Mm¥1 at Caney Creek and 28.19 Mm¥1

out of a total average light extinction of 

66.37 Mm¥1 at Upper Buffalo. In terms 

of percent contribution, the average 

contribution of SO4 to total light 

extinction was approximately 50% at 

Caney Creek and 43% at Upper Buffalo 

on the 20% most impaired days in 

2013–2015. Based on the CENRAP 

PSAT data discussed above, we expect 

that a large proportion of NO3 from 

Arkansas sources is likely due to onroad sources and that the average 

percentage contribution of NO3 from 

Arkansas point sources at Arkansas 

Class I areas is considerably smaller 

than 14% at Caney Creek and 23% at 

Upper Buffalo. Taking into 

consideration that states have 

significant discretion in determining 

what sources to analyze for controls 

under reasonable progress, we are 

proposing to find that it is reasonable 

for Arkansas to reach the conclusion 

that, for the first implementation period, 

additional NOX controls for Arkansas 

point sources are not anticipated to 

yield meaningful visibility 

improvements at Arkansas Class I areas 

in view of the amount of visibility 

impairment attributed to these sources. 

Arkansas’ conclusions with regard to 

the percentage contribution to light 

extinction from NO3 on the 20% worst 

days is generally consistent with the 

findings we made in the Arkansas 

Regional Haze FIP.35 In the FIP, we 

made the finding that NO3 from point 

sources is not considered a driver of 

regional haze at Caney Creek and Upper 

Buffalo on the 20% worst days, 

contributing only approximately 3% of 

the total light extinction, as projected by 

CENRAP’s CAMx source apportionment 

modeling.36 We also stated in the FIP 

proposal that because of the small 

contribution of NO3 from point sources 

to the total light extinction at Caney 

Creek and Upper Buffalo on the most 

impaired days, we did not expect that 

NOX controls under the reasonable 

progress requirements would offer as 

much improvement on the most 

impaired days compared to SO2

controls.37 However, in the FIP, we 

decided to look at 2011 National 

Emissions Inventory (NEI) data for NOX

for Arkansas point sources to determine 

if there are any large point sources that 

are reasonable candidates for evaluation 

under the four reasonable progress 

factors. Based on this assessment, we 

proceeded with an analysis of the four 

reasonable progress factors for NOX

controls for the Independence facility as 

we reasoned that it is the second largest 

point source of NOX emissions in the 

state and potentially one of the largest 

single contributors to visibility 

impairment at Class I areas in 

Arkansas.38 We also conducted 

CALPUFF modeling to determine the 

maximum 98th percentile visibility 

impacts from the Independence facility 

and the predicted visibility 

improvement due to NOX controls at the 

facility. That analysis revealed that low 

NOX burner controls would be very 

cost-effective and would result in an 

improvement of the 98th percentile 

visibility impacts from the 

Independence facility at Caney Creek 

and Upper Buffalo, and we finalized 

NOX controls for the Independence 

facility under the reasonable progress 

requirements.39

In the July 2017 Regional Haze SIP 

revision, Arkansas takes a different, but 

nonetheless equally reasonable, 

approach to determine whether 

additional controls are necessary under 

reasonable progress. In its evaluation, 

Arkansas places greater emphasis on the 


asabaliauskas on DSKBBXCHB2PROD with PROPOSALS
42634 Federal Register / Vol. 82, No. 174 / Monday, September 11, 2017 / Proposed Rules 

40 81 FR 74504. 

41 77 FR 14604. 

42On January 10, 2017, the EPA revised the 

Regional Haze Rule, including the FLM 

consultation requirements at 40 CFR 51.308(i)(2). 

See 82 FR 3078. However, these revisions to the 

Regional Haze Rule are intended to address 

requirements for the second implementation period 

rather than the first implementation period; 

Arkansas’ 2017 Regional Haze SIP revision 

addresses regional haze requirements for the first 

implementation period. For the first 

implementation period, the Regional Haze Rule 

required states to provide the FLMs with an 

opportunity for consultation, in person and at least 

60 days prior to holding any public hearing on an 

implementation plan (or plan revision) for regional 

haze. See 64 FR 35714, at 35769. 

43See Tab D of the 2017 Arkansas Regional Haze 

SIP revision, which can be found in the docket 

associated with this rulemaking. 

44See Tab D of the 2017 Arkansas Regional Haze 

SIP revision, which can be found in the docket 

associated with this rulemaking. 45 81 FR 78954. 

relative contributions of sources within 

Arkansas to light extinction at Caney 

Creek and Upper Buffalo rather than the 

relative contributions of all sources both 

in and outside Arkansas. Arkansas also 

focuses its assessment on the CENRAP’s 

CAMx source apportionment modeling 

rather than conducting or relying on 

CALPUFF modeling, and reaches the 

conclusion that, for the first 

implementation period, additional NOX

controls for Arkansas point sources are 

not anticipated to yield meaningful 

visibility improvements at Arkansas 

Class I areas on the 20% worst days in 

view of the amount of visibility 

impairment attributed to these sources. 

Additionally, Arkansas points out that 

the Independence facility and other 

EGUs in Arkansas with a nameplate 

capacity of 25 MW or greater are 

participating in CSAPR for ozone season 

NOX.40 Thus, NOX emissions from 

Independence and other Arkansas 

sources will be addressed under 

reasonable progress through EGU 

participation in the CSAPR ozone 

season NOX trading program. We 

believe that Arkansas is within its 

discretion to take the approach of 

focusing on the CENRAP’s CAMx source 

apportionment modeling to help inform 

its decision regarding whether NOX

controls under reasonable progress are 

warranted. Given the relatively small 

level of visibility impairment due to 

NOX3 from Arkansas point sources at 

Caney Creek and Upper Buffalo on the 

20% worst days and considering that 

Arkansas EGUs are participating in 

CSAPR for ozone season NOX, we are 

proposing to find that Arkansas’ 

decision to screen out Arkansas point 

sources from further evaluation of 

additional NOX controls is reasonable 

and we are proposing to approve 

Arkansas’ determination that Arkansas 

EGU participation in CSAPR for ozone 

season NOX is sufficient to satisfy the 

reasonable progress requirements for 

NOX in Arkansas for the first 

implementation period. We find that 

Arkansas has addressed our concerns 

presented in our final partial 

disapproval 41 of the 2008 Regional 

Haze SIP revision with respect to 

reasonable progress for NOX by 

providing additional analysis that 

shows that NOX emissions are not the 

driver of regional haze on the 20% 

worst days in Arkansas Class I areas and 

that further analysis of additional NOX

controls for Arkansas sources under 

reasonable progress is therefore not 

warranted for the first implementation 

period considering that NOX emissions 

from Arkansas EGUs are addressed 

through participation in the CSAPR 

ozone season NOX trading program. 

C. Required Consultation 

The Regional Haze Rule requires 

states to provide the designated Federal 

Land Managers (FLMs) with an 

opportunity for consultation at least 60 

days prior to holding any public hearing 

on a SIP revision for regional haze for 

the first implementation period.42

Arkansas sent letters to the FLMs on 

June 14, 2017, providing notification of 

the proposed SIP revision and providing 

electronic access to the draft SIP 

revision and related documents.43 The 

Regional Haze Rule at section 

51.308(d)(3)(i) also provides that if a 

state has emissions that are reasonably 

anticipated to contribute to visibility 

impairment in a Class I area located in 

another state, the state must consult 

with the other state(s) in order to 

develop coordinated emission 

management strategies. Since Missouri 

has two Class I areas impacted by 

Arkansas sources, Arkansas sent a letter 

to the Missouri Department of Natural 

Resources (MDNR) on June 14, 2017, 

providing notification of the proposed 

SIP revision and providing electronic 

access to the draft SIP revision and 

related documents.44 Arkansas stated it 

will consider and respond to any 

comments received from the FLMs and 

from the MDNR on the proposed SIP 

revision before finalizing and 

submitting the final SIP revision to EPA. 

We are proposing to find that 

Arkansas has provided an opportunity 

for consultation to the FLMs and to the 

MDNR on the proposed SIP revision, as 

required under section 51.308(i)(2) and 

51.308(d)(3)(i). Our final determination 

with respect to Arkansas’ satisfaction of 

the consultation requirements under the 

Regional Haze Rule will be contingent 

upon Arkansas’ appropriate 

consideration and responses to 

comments from the FLMs and the 

MDNR in the final SIP submission. 

III. Proposed Action 

A. Arkansas’ Proposed Regional Haze 

SIP Revision 

The EPA has made the preliminary 

determination that the July 12, 2017 

proposed revisions to the Arkansas 

Regional Haze SIP and the request by 

the State for parallel processing are in 

accordance with the CAA and 

consistent with the CAA and the EPA’s 

rule on regional haze. Therefore, the 

EPA proposes to approve the following 

revisions to the Arkansas Regional Haze 

SIP that were proposed for adoption on 

July 8, 2017 and submitted for parallel 

processing on July 12, 2017: the NOX

BART requirements for Bailey Unit 1; 

McClellan Unit 1; Flint Creek Boiler No. 

1; Lake Catherine Unit 4; and White 

Bluff Units 1 and 2 and the Auxiliary 

Boiler, will be satisfied by participation 

in CSAPR. We cannot finalize today’s 

proposed SIP approval until we finalize 

the November 10, 2016 proposed 

finding that CSAPR continues to be 

better than BART45 or otherwise 

determine that participation in CSAPR 

remains a viable BART alternative 

because such a determination provides 

the basis for Arkansas to rely on CSAPR 

participation as an alternative to source 

specific EGU BART for NOX. Given the 

relatively small level of visibility 

impairment due to NO3 from Arkansas 

point sources at Caney Creek and Upper 

Buffalo and considering that Arkansas 

EGUs are participating in CSAPR for 

ozone season NOX, we are proposing to 

find that Arkansas’ decision not to 

conduct further analysis of additional 

NOX controls for Arkansas sources is 

reasonable and we are proposing to 

approve Arkansas’ determination that 

Arkansas EGU participation in CSAPR 

for ozone season NOX is sufficient to 

satisfy the reasonable progress 

requirements for NOX in Arkansas for 

the first implementation period. 

The EPA is proposing this action in 

parallel with the state’s rulemaking 

process. We cannot take a final action 

until the state completes its rulemaking 

process, adopts its final regulations, and 

submits these final adopted regulations 

as a revision to the Arkansas SIP. If 

during the response to comments 

process, the final SIP revision is 

changed significantly from the proposed 

SIP revision upon which the EPA 

proposed, the EPA may have to 

withdraw our initial proposed rule and 

re-propose based on the final SIP 

submittal. 


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46The proposed amendatory language for this 

proposed revision of the earlier promulgated FIP is 

set forth at the end of this proposal. If the action 

is finalized as proposed, the final action will also 

present additional amendatory language reflecting 

our approval of the submitted SIP revision. 

47 42 U.S.C. 7410(l). 

48 81 FR74504. 

49 81 FR 78954. 

50 81 FR 78954. 

B. Partial FIP Withdrawal 

We are proposing to withdraw those 

portions of the Arkansas Regional Haze 

FIP at 40 CFR 52.173 that impose NOX

requirements on Bailey Unit 1; 

McClellan Unit 1; Flint Creek Boiler No. 

1; Lake Catherine Unit 4; White Bluff 

Units 1 and 2 and the Auxiliary Boiler; 

and Independence Units 1 and 2.46 We 

are proposing that these portions of the 

FIP will be replaced by the July 2017 

Regional Haze SIP revision that we are 

proposing to approve in this action. 

C. Clean Air Act Section 110(l) 

Section 110(l) of the CAA states that 

‘‘[t]he Administrator shall not approve a 

revision of a plan if the revision would 

interfere with any applicable 

requirement concerning attainment and 

reasonable further progress or any other 

applicable requirement of this 

chapter.’’ 47 EPA does not interpret 

section 110(l) to require a full 

attainment or maintenance 

demonstration before any changes to a 

SIP may be approved. Generally, a SIP 

revision may be approved under section 

110(l) if EPA finds that it will at least 

preserve status quo air quality, 

particularly where the pollutants at 

issue are those for which an area has not 

been designated nonattainment. 

We do not believe an approval of the 

2017 Regional Haze SIP revision, as 

proposed, will interfere with CAA 

requirements for BART or reasonable 

progress because all areas in the state 

are designated as attainment for all 

NAAQS, and our proposal is supported 

by an evaluation that those CAA 

requirements are met. The SIP replaces 

federal determinations for source 

specific NOX emission limits for BART 

EGUs in Arkansas. Following 

promulgation of the FIP, EPA finalized 

an update to the CSAPR rule on October 

26, 2016, that addresses the 1997 ozone 

NAAQS portion of the remand and the 

CAA requirements addressing interstate 

transport for the 2008 ozone NAAQS.48

On November 10, 2016, EPA proposed 

a rule intended to address the remainder 

of the court’s remand, which also 

included an assessment of the impacts 

of the set of actions that the EPA has 

taken or expects to take in response to 

the D.C. Circuit’s remand on our 2012 

demonstration that participation in 

CSAPR provides for greater reasonable 

progress than BART.49 Based on that 

assessment, the EPA proposed in the 

November 10, 2016 action that states 

may continue to rely on CSAPR as being 

better than BART on a pollutant-specific 

basis. As such, Arkansas now has the 

option to propose to rely on compliance 

with CSAPR to satisfy the NOX BART 

requirement for EGUs. Finalization of 

EPA’s November 10, 2016, proposed 

finding that CSAPR continues to be 

better than BART50 or EPA otherwise 

determining that CSAPR remains a 

viable BART alternative will provide the 

basis for Arkansas to rely on CSAPR 

participation as an alternative to source 

specific EGU BART for NOX. 

With regard to reasonable progress, 

Arkansas has provided an analysis of 

anthropogenic sources of visibility 

impairment and arrived at the 

determination that Arkansas EGU 

participation in CSAPR for ozone season 

NOX is sufficient to satisfy the 

reasonable progress requirements for 

NOX in Arkansas for the first 

implementation period. The 

Independence facility, on which the FIP 

imposed NOX controls under the 

reasonable progress requirements, is 

subject to CSAPR for ozone season NOX. 

Even though we are withdrawing the 

source-specific NOX controls in the FIP 

for the Independence facility, its NOX

emissions will still be addressed under 

the reasonable progress requirements 

through participation in the CSAPR 

ozone season NOX emissions trading 

program. 

We also believe that approval of the 

submitted SIP revision will not interfere 

with attainment and maintenance of the 

NAAQS within the state of Arkansas. 

No areas in Arkansas are currently 

designated nonattainment for any 

NAAQS pollutants. The SIP revision we 

are proposing to approve would allow 

Arkansas to rely on compliance with 

CSAPR to satisfy the NOX BART 

requirement for Arkansas EGUs as well 

as the reasonable progress requirements 

for NOX. Additionally, the CSAPR 2018 

NOX ozone season allocations for 

Arkansas sources are more stringent 

than the 2017 allocations. As all areas 

are attaining the NAAQS even with 

current emissions levels, reductions in 

those levels as a result of compliance 

with the 2018 NOX ozone season 

allocations will not interfere with 

attainment. Therefore, we do not deem 

this to be an instance where a full 

attainment or maintenance 

demonstration is needed to bolster our 

determination that approval of the 

submitted SIP revision would not 

interfere with attainment and 

maintenance of the NAAQS. We are not 

aware of any basis for concluding or 

demonstrating that Arkansas’ July 2017 

Regional Haze SIP revision, when 

implemented, would interfere with the 

maintenance of the NAAQS in 

Arkansas. 

IV. Statutory and Executive Order 

Reviews 

Under the CAA, the Administrator is 

required to approve a SIP submission 

that complies with the provisions of the 

Act and applicable Federal regulations. 

42 U.S.C. 7410(k); 40 CFR 52.02(a). 

Thus, in reviewing SIP submissions, the 

EPA’s role is to approve state choices, 

provided that they meet the criteria of 

the CAA. Accordingly, this action 

merely proposes to approve state law as 

meeting Federal requirements and does 

not impose additional requirements 

beyond those imposed by state law. For 

that reason, this action: 

• Is not a ‘‘significant regulatory 

action’’ subject to review by the Office 

of Management and Budget under 

Executive Orders 12866 (58 FR 51735, 

October 4, 1993) and 13563 (76 FR 3821, 

January 21, 2011); 

• Does not impose an information 

collection burden under the provisions 

of the Paperwork Reduction Act (44 

U.S.C. 3501 et seq.); 

• Is certified as not having a 

significant economic impact on a 

substantial number of small entities 

under the Regulatory Flexibility Act (5 

U.S.C. 601 et seq.); 

• Does not contain any unfunded 

mandate or significantly or uniquely 

affect small governments, as described 

in the Unfunded Mandates Reform Act 

of 1995 (Pub. L. 104–4); 

• Does not have Federalism 

implications as specified in Executive 

Order 13132 (64 FR 43255, August 10, 

1999); 

• Is not an economically significant 

regulatory action based on health or 

safety risks subject to Executive Order 

13045 (62 FR 19885, April 23, 1997); 

• Is not a significant regulatory action 

subject to Executive Order 13211 (66 FR 

28355, May 22, 2001); 

• Is not subject to requirements of 

section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (15 U.S.C. 272 note) because 

this action does not involve technical 

standards; and 

• Does not provide EPA with the 

discretionary authority to address, as 

appropriate, disproportionate human 

health or environmental effects, using 

practicable and legally permissible 

methods, under Executive Order 12898 

(59 FR 7629, February 16, 1994). 


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In addition, the SIP is not approved 

to apply on any Indian reservation land 

or in any other area where EPA or an 

Indian tribe has demonstrated that a 

tribe has jurisdiction. In those areas of 

Indian country, the proposed rule does 

not have tribal implications and will not 

impose substantial direct costs on tribal 

governments or preempt tribal law as 

specified by Executive Order 13175 (65 

FR 67249, November 9, 2000). 

List of Subjects in 40 CFR Part 52 

Air pollution control, Best available 

retrofit technology, Environmental 

protection, Incorporation by reference, 

Intergovernmental relations, Nitrogen 

dioxide, Ozone, Regional haze, 

Reporting and recordkeeping 

requirements, Visibility. 

Dated: August 29, 2017. 

Samuel Coleman, 

Acting Regional Administrator, Region 6. 

Title 40, chapter I, of the Code of 

Federal Regulations is proposed to be 

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: 

■ a. Revising paragraphs (c)(3) through 

(10) and (c)(12) 

■ b. Removing paragraphs (c)(13) and 

(14) 

■ c. Redesignating paragraphs (c)(15) 

through (29) as paragraphs (c)(13) 

through (27) and 

■ d. Revising redesignated paragraphs 

(c)(14), (15), (17), (18), (20), (21), (22), 

(23) and (24) 

Revisions to read as follows: 

§ 52.173 Visibility protection. 

* * * * * 

(c) * * * 

(3) Emissions limitations for AECC 

Bailey Unit 1 and AECC McClellan Unit 

1. The individual SO2 and PM emission 

limits for each unit are as listed in the 

following table. 

Unit SO2 emission limit PM emission limit 

AECC Bailey Unit 1 ............. Use of fuel with a sulfur content limit of 0.5% by weight 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 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. 

(5) Compliance determination and 

reporting and recordkeeping 

requirements for AECC Bailey Unit 1 

and AECC McClellan Unit for 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. 

(6) Emissions limitations for AEP Flint 

Creek Unit 1 and Entergy White Bluff 

Units 1 and 2. The individual SO2

emission limits for each unit are as 

listed in the following table, as specified 

in pounds per million British thermal 

units (lb/MMBtu). The SO2 emission 

limits of 0.06 lb/MMBtu are on a rolling 

30 boiler-operating-day averaging 

period. 

Unit 

SO2 emission 

limit 

(lb/MMBtu) 

AEP Flint Creek Unit 1 ......... 0.06 

Entergy White Bluff Unit 1 .... 0.06 

Entergy White Bluff Unit 2 .... 0.06 

(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 emission limit 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. 

(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 emission limit 

listed in paragraph (c)(6) of this section 

for AEP Flint Creek Unit 1 and with the 

SO2 emission limits 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.

For each unit, 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 30-day 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 boileroperating-day period. The result shall be 

the 30 boiler-operating-day 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 30 boiler-operatingday rolling average for SO2. 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 

SO2 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) The owner or operator shall 

continue to maintain and operate a 

CEMS for SO2 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 


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Federal Register / Vol. 82, No. 174 / Monday, September 11, 2017 / Proposed Rules 42637 

limits for SO2 shall be determined by 

using data from a CEMS. 

(iii) 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 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 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 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) 

PM emission 

limit 

(lb/hr) 

Entergy White Bluff Auxiliary Boiler ......................................................................................................................... 105.2 4.5 

(10) Compliance dates for Entergy 

White Bluff Auxiliary Boiler. The owner 

or operator of the unit must comply 

with the SO2 and PM emission limits 

listed in paragraph (c)(9) of this section 

by October 27, 2016. 

* * * * * 

(12) Emissions limitations for Entergy 

Lake Catherine Unit 4. The unit must 

not burn fuel oil until BART 

determinations are promulgated for the 

unit for SO2 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. 

* * * * * 

(14) 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)(13) of this 

section by November 28, 2016. 

(15) 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 

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)(15)(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)(13) 

of this section. The compliance 

determination requirements and the 

reporting and recordkeeping 

requirements under paragraph (c)(15)(i) 

of this section would not apply and 

confirmation of the accuracy of the sitespecific curve equation under paragraph 

(c)(15)(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)(13) 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)(13) of this 

section by calculating NOX emissions 

using fuel usage records and the 

applicable NOX emission factor under 


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42638 Federal Register / Vol. 82, No. 174 / Monday, September 11, 2017 / Proposed Rules 

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)(15)(iii) of this section would not 

apply. 

* * * * * 

(17) 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)(16) of this section by October 27, 

2021. 

(18) 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)(16) 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)(16) 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. 

(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)(16) 

of this section. Under these 

circumstances, the compliance 

determination requirements under 

paragraphs (c)(18)(i) through (iii) of this 

section would not apply to the SO2

emission limit listed in paragraph 

(c)(16) 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)(16) 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)(18)(i) through (iii) of this 

section would not apply to the NOX

emission limit. 

* * * * * 

(20) 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)(19) of this section 

by November 28, 2016. 

(21) Alternative PM Compliance 

Determination for Domtar Ashdown 

Paper Mill Power Boiler No. 2. If the air 

permit is revised such that Power Boiler 


asabaliauskas on DSKBBXCHB2PROD with PROPOSALS
Federal Register / Vol. 82, No. 174 / Monday, September 11, 2017 / Proposed Rules 42639 

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)(19) of this section. 

(22) 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). The SO2 emission 

limits listed in the table as lb/MMBtu 

are on a rolling 30 boiler-operating-day 

averaging period. 

Unit 

SO2 emission 

limit 

(lb/MMBtu) 

Entergy Independence Unit 1 0.06 

Entergy Independence Unit 2 0.06 

(23) Compliance dates for Entergy 

Independence Units 1 and 2. The owner 

or operator of each unit must comply 

with the SO2 emission limits in 

paragraph (c)(22) of this section by 

October 27, 2021. 

(24) 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)(22) 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) The owner or operator shall 

continue to maintain and operate a 

CEMS for SO2 on the units listed in 

paragraph (c)(22) 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 shall be 

determined by using data from a CEMS. 

(iii) Continuous emissions monitoring 

shall apply during all periods of 

operation of the units listed in 

paragraph (c)(22) 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 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 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. 

* * * * * 

[FR Doc. 2017–18661 Filed 9–8–17; 8:45 am] 

BILLING CODE 6560–50–P 


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