[Federal Register Volume 82, Number 133 (Thursday, July 13, 2017)]
[Proposed Rules]
[Pages 32294-32301]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2017-14693]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2017-0129; FRL-9964-20-Region 6]


Approval and Promulgation of Implementation Plans; Louisiana; 
Regional Haze State Implementation Plan

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: Pursuant to the Federal Clean Air Act (CAA or the Act), the 
Environmental Protection Agency (EPA) is proposing to approve for the 
Entergy R. S. Nelson facility (Nelson) (1) a portion of a revision to 
the Louisiana Regional Haze State Implementation Plan (SIP) submitted 
on February 20, 2017; and (2) a revision submitted for parallel 
processing on June 20, 2017, by the State of Louisiana through the 
Louisiana Department of Environmental Quality (LDEQ). Specifically, the 
EPA is proposing to approve these two revisions, which address the Best 
Available Retrofit Technology requirement of Regional Haze for Nelson 
for sulfur-dioxide (SO2) and particulate-matter (PM).

DATES: Written comments must be received on or before August 14, 2017.

ADDRESSES: Submit your comments, identified by Docket No. EPA-R06-OAR-
2017-0129, at http://www.regulations.gov or via email to 
[email protected]. 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 Jennifer Huser, 
[email protected]. 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: Jennifer Huser, 214-665-7347, 
[email protected]. To inspect the hard copy materials, please 
schedule an appointment with Jennifer Huser 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 and Our Proposed Action on Louisiana 
Regional Haze
II. Our Evaluation of Louisiana's BART Analysis for Nelson
    A. Identification of Nelson as a BART-Eligible Source
    B. Evaluation of Whether Nelson Is Subject to BART
    1. Visibility Impairment Threshold
    2. CALPUFF Modeling to Screen Sources
    3. Nelson is Subject to BART
    C. Reliance on CSAPR To Satisfy NOX BART
    D. Louisiana's Five-Factor Analyses for SO2 and PM 
BART for Nelson
III. Proposed Action
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), nitrogen oxides (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.
    Data from the existing visibility monitoring network, ``Interagency 
Monitoring of Protected Visual Environments'' (IMPROVE), shows that 
visibility impairment caused by air pollution occurs virtually all the 
time at most national parks and wilderness areas. In 1999, the average 
visual range in many Class I areas (i.e., national parks and memorial 
parks, wilderness areas, and international parks meeting certain size 
criteria) in the western United States was 100-150 kilometers, or about 
one-half to two-thirds of the visual range that would exist without 
anthropogenic air pollution. In most of the eastern Class I areas of 
the United States, the average visual range was less than 30 
kilometers, or about one-fifth of the visual range that would exist 
under estimated natural conditions. CAA programs have reduced some 
haze-causing pollution, lessening some visibility impairment and 
resulting in partially improved average visual ranges.
    CAA requirements to address the problem of visibility impairment 
continue to be implemented. In Section 169A of the 1977 Amendments to 
the CAA, Congress created a program for protecting visibility in the 
nation's national parks and wilderness areas. This section of the CAA 
establishes as a national goal the prevention of any future, and the 
remedying of any existing, man-made impairment of visibility in 156 
national parks and wilderness areas designated as mandatory Class I 
Federal areas. On December 2, 1980, the EPA promulgated

[[Page 32295]]

regulations to address visibility impairment in Class I areas that is 
``reasonably attributable'' to a single source or small group of 
sources, i.e., ``reasonably attributable visibility impairment.'' These 
regulations represented the first phase in addressing visibility 
impairment. The EPA deferred action on regional haze that emanates from 
a variety of sources until monitoring, modeling, and scientific 
knowledge about the relationships between pollutants and visibility 
impairment were improved.
    Congress added section 169B to the CAA in 1990 to address regional 
haze issues, and the EPA promulgated regulations addressing regional 
haze in 1999. The Regional Haze Rule revised the existing visibility 
regulations to add provisions addressing regional haze impairment and 
established a comprehensive visibility protection program for Class I 
areas. The requirements for regional haze, found at 40 CFR 51.308 and 
51.309, are included in our visibility protection regulations at 40 CFR 
51.300-309. The requirement to submit a regional haze SIP applies to 
all 50 states, the District of Columbia, and the Virgin Islands. States 
were required to submit the first implementation plan addressing 
regional haze visibility impairment no later than December 17, 2007.
    Section 169A of the CAA directs states to evaluate the use of 
retrofit controls at certain larger, often under-controlled, older 
stationary sources in order to address visibility impacts from 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. 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.

B. Our Previous Actions and Our Proposed Action on Louisiana Regional 
Haze

    On June 13, 2008, Louisiana submitted a SIP to address regional 
haze (2008 Louisiana Regional Haze SIP or 2008 SIP revision). We acted 
on that submittal in two separate actions. Our first action was a 
limited disapproval \1\ because of deficiencies in the State's regional 
haze SIP submittal arising from the remand by the U.S. Court of Appeals 
for the District of Columbia of the Clean Air Interstate Rule (CAIR). 
Our second action was a partial limited approval/partial disapproval 
\2\ because the 2008 SIP revision met some but not all of the 
applicable requirements of the CAA and our regulations as set forth in 
sections 169A and 169B of the CAA and 40 CFR 51.300-308, but as a 
whole, the 2008 SIP revision strengthened the SIP. On August 11, 2016, 
Louisiana submitted a SIP revision to address the deficiencies related 
to BART for four non-EGU facilities. We proposed to approve that 
revision on October 27, 2016.\3\
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    \1\ 77 FR 33642 (June 7, 2012).
    \2\ 77 FR 39425 (July 3, 2012).
    \3\ 81 FR 74750 (October 27, 2016).
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    On February 10, 2017, Louisiana submitted a SIP revision intended 
to address the deficiencies related to BART for EGU sources (February 
2017 Louisiana Regional Haze SIP or February 2017 SIP revision). We 
proposed approval of that SIP revision as it pertains to all of the 
BART-eligible EGUs in the State on May 19, 2017, except for Nelson, 
which we address herein.\4\
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    \4\ 82 FR 22936 (May 19, 2017).
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    On June 20, 2017, Louisiana submitted a SIP revision with a request 
for parallel processing, specifically addressing the BART requirements 
for Nelson. (June 2017 Louisiana Regional Haze SIP or June 2017 SIP 
revision). This revision, along with the Nelson portion of the February 
20, 2017 SIP revision, are the subject of this proposed action. 
Parallel processing of the June 2017 SIP revision means that, at the 
same time Louisiana is completing the corresponding public comment and 
rulemaking process at the state level, we are proposing action on it. 
Because Louisiana has not yet finalized the June 2017 SIP revision that 
we are parallel processing, we are proposing to approve this SIP 
revision in parallel with Louisiana's rulemaking activities. If changes 
are made to the State's proposed rule after the EPA's notice of 
proposed rulemaking, such changes must be acknowledged in the EPA's 
final rulemaking action. If the changes are significant, then the EPA 
may be obligated to withdraw our initial proposed action and re-
propose. If there are no changes to the parallel-processed version, EPA 
would proceed with final rulemaking on the version finally adopted by 
Louisiana and submitted to EPA, as appropriate after consideration of 
public comments.

II. Our Evaluation of Louisiana's BART Analysis for Nelson

    Nelson is located in Westlake, Calcasieu Parish, Louisiana. The 
nearest Class I areas are Breton National Wilderness Area in Louisiana, 
located 264 miles east of the facility and Caney Creek Wilderness Area 
in Arkansas, located 286 miles north of the facility.

A. Identification of Nelson as a BART-Eligible Source

    In our partial disapproval and partial limited approval of the 2008 
Louisiana Regional Haze SIP, we approved the LDEQ's identification of 
76 BART-eligible sources, which included Nelson.\5\ Nelson is a fossil-
fuel steam electric power generating facility and operates three BART-
eligible steam generating units: Unit 4, Unit 4 Auxiliary Boiler, and 
Unit 6.
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    \5\ See 77 FR 11839 at 11848 (February 28, 2012).
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B. Evaluation of Whether Nelson Is Subject to BART

    Because Louisiana's 2008 Regional Haze SIP relied on CAIR as a BART 
alternative for EGUs, the submittal did not include a determination of 
which BART-eligible EGUs were subject to BART. On May 19, 2015, we sent 
a CAA Section 114 letter to the Nelson BART-eligible source in 
Louisiana. In that letter, we noted our understanding that the source 
was actively working with the LDEQ to develop a SIP. However, in order 
to be in a position to develop a FIP should that be necessary, we 
requested information regarding the BART-eligible sources, including 
Nelson. The Section 114 letter required the source to conduct modeling 
to determine if the source was subject to BART, and included a modeling 
protocol. The letter also requested that a BART analysis be performed 
in accordance with the BART Guidelines for Nelson if determined to be 
subject to BART. We worked closely with the BART-eligible facility and 
with the LDEQ to this end, and all the information we received from the

[[Page 32296]]

facility was also sent to the LDEQ. As a result, the LDEQ submitted the 
February and June SIP revisions addressing BART for Nelson. The LDEQ 
provides a BART determination for each of the three units at the source 
for all visibility impairing pollutants except NOX.\6\ Once 
a list of BART-eligible sources still in operation within a state has 
been compiled, the state must determine whether to make BART 
determinations for all of them or to consider exempting some of them 
from BART because they are not reasonably anticipated to cause or 
contribute to any visibility impairment in a Class I area. The BART 
Guidelines present several options that rely on modeling analyses and/
or emissions analyses to determine if a source is not reasonably 
anticipated to cause or contribute to visibility impairment in a Class 
I area. A source that is not reasonably anticipated to cause or 
contribute to any visibility impairment in a Class I area is not 
``subject to BART,'' and for such sources, a state need not apply the 
five statutory factors to make a BART determination.\7\ Sources that 
are reasonably anticipated to cause or contribute to any visibility 
impairment in a Class I area are subject to BART.\8\ For each source 
subject to BART, 40 CFR 51.308(e)(1)(ii)(A) requires that the LDEQ 
identify the level of control representing BART after considering the 
factors set out in CAA section 169A(g)(2). To determine which sources 
are anticipated to contribute to visibility impairment, the BART 
Guidelines state ``you can use CALPUFF or other appropriate model to 
estimate the visibility impacts from a single source at a Class I 
area.''\9\
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    \6\ We have previously proposed approval of the portion of 
LDEQ's February 2017 revision that relies on CSAPR participation as 
an alternative to source-specific EGU BART for NOX, 
therefore, a source by source analysis for NOX is 
unnecessary. 82 FR 22936, at 22943.
    \7\ See 40 CFR part 51, Appendix Y, III, How to Identify Sources 
``Subject to BART''.
    \8\ Id.
    \9\ See 40 CFR part 51, Appendix Y, III, How to Identify Sources 
``Subject to BART''.
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1. Visibility Impairment Threshold
    The preamble to the BART Guidelines advise that, ``for purposes of 
determining which sources are subject to BART, States should consider a 
1.0 deciview \10\ change or more from an individual source to `cause' 
visibility impairment, and a change of 0.5 deciviews to `contribute' to 
impairment.'' \11\ They further advise that ``States should have 
discretion to set an appropriate threshold depending on the facts of 
the situation,'' and describes situations in which states may wish to 
exercise that discretion, mainly in situations in which a number of 
sources in an area are all contributing fairly equally to the 
visibility impairment of a Class I area. In Louisiana's 2008 Regional 
Haze SIP submittal, the LDEQ used a contribution threshold of 0.5 dv 
for determining which sources are subject to BART, and we approved this 
threshold in our previous action.\12\
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    \10\ As we note in the Regional Haze Rule (64 FR 35725, July 1, 
1999), the ``deciview'' or ``dv'' is an atmospheric haze index that 
expresses changes in visibility. This visibility metric expresses 
uniform changes in haziness in terms of common increments across the 
entire range of visibility conditions, from pristine to extremely 
hazy conditions.
    \11\ 70 FR 39104, 39120 (July 6, 2005), [40 CFR part 51, 
Appendix Y].
    \12\ See, 77 FR 11839, 11849 (February 28, 2012).
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2. CALPUFF Modeling to Screen Sources
    The BART Guidelines recommend that the 24-hour average actual 
emission rate from the highest emitting day of the meteorological 
period be modeled, unless this rate reflects periods of start-up, 
shutdown, or malfunction. The maximum 24-hour emission rate (lb/hr) for 
NOX and SO2 from the baseline period (2000-2004) 
for the source is identified through a review of the daily emission 
data for each BART-eligible unit from the EPA's Air Markets Program 
Data.\13\ Because daily emissions are not available for PM, maximum 24-
hr PM emissions are estimated based on permit limits, maximum heat 
input, and AP-42 factors, and/or stack testing. EPA conducted CALPUFF 
modeling and provided it to LDEQ to determine whether Nelson causes or 
contributes to visibility impairment in nearby Class I areas (see 
Appendix F of the June 2017 SIP revision). See the CALPUFF Modeling TSD 
for additional discussion on modeling protocol, model inputs, and model 
results for this portion of the screening analysis. The CALPUFF 
modeling establishes that Nelson's visibility impacts are above LDEQ's 
chosen threshold of 0.5 dv.
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    \13\ http://ampd.epa.gov/ampd/.
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3. Nelson Is Subject to BART
    The BART-eligible units at the Nelson facility have visibility 
impacts greater than 0.5 dv. Therefore, Nelson is subject to BART and 
must undergo a five-factor analysis. See our CALPUFF Modeling TSD for 
further information.
    We note that, in addition to CALPUFF modeling, Appendix D of the 
February 2017 SIP revision includes the results of CAMx modeling \14\ 
performed by Trinity consultants for Entergy. This modeling purports to 
demonstrate that the baseline visibility impacts from Nelson \15\ are 
significantly less than the 0.5 dv threshold. However, this modeling 
was not conducted in accordance with the BART Guidelines or a previous 
modeling protocol we developed for the use of CAMx modeling for BART 
screening,\16\ and does not properly assess maximum baseline impacts. 
Therefore, we agree with LDEQ's decision in the February 2017 SIP 
revision to not rely on this CAMx modeling.\17\ See the CAMx Modeling 
TSD for a detailed discussion. We also note that, for the largest 
emission sources in Louisiana, such as the Nelson facility, we 
performed our own CAMx modeling while following the BART Guidelines and 
the modeling protocol to provide additional information on visibility 
impacts and impairment and address possible concerns with utilizing 
CALPUFF to assess visibility impacts at Class I areas located at large 
distances from the emission sources. Our CAMx modeling indicates that 
Nelson has a maximum impact \18\ of 2.22 dv at Caney Creek, with 31 
days out of the 365 days modeled exceeding 0.5 dv, and 9 days exceeding 
1.0 dv. See the CAMx Modeling TSD for additional information on the 
EPA's CAMx modeling protocol, inputs, and model results.
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    \14\ CAMx Modeling Report, prepared for Entergy Services by 
Trinity Consultants, Inc. and All 4 Inc, October 14, 2016, included 
in Appendix D of the February 2017 Louisiana Regional Haze SIP 
submittal.
    \15\ Entergy's CAMx modeling included model results for Michoud, 
Little Gypsy, R.S. Nelson, Ninemile Point, Willow Glen, and 
Waterford.
    \16\ Texas was the only state that developed a modeling 
protocol, which EPA approved, to screen sources using CAMx. Texas 
had over 120 BART-eligible facilities located at a wide range of 
distances to the nearest class I areas in their original Regional 
Haze SIP. CAMx modeling was appropriate in that instance due to the 
distances between sources and Class I areas and the number of 
sources. Texas worked with EPA and FLM representatives to develop 
this modeling protocol, which proscribed how the modeling was to be 
performed and what metrics had to be evaluated for determining if a 
source screened out. See Guidance for the Application of the CAMx 
Hybrid Photochemical Grid Model to Assess Visibility Impacts of 
Texas BART Sources at Class I Areas, ENVIRON International, December 
13, 2007, available in the docket for this action. EPA, the Texas 
Commission on Environmental Quality (TCEQ), and FLM representatives 
verbally approved the approach in 2006 and in email exchange with 
TCEQ representatives in February 2007 (see email from Erik Snyder 
(EPA) to Greg Nudd of TCEQ Feb. 13, 2007 and response email from 
Greg Nudd to Erik Snyder Feb. 15, 2007, available in the docket for 
this action).
    \17\ See Response to Comments in Appendix A of the 2017 
Louisiana Regional Haze SIP submittal.
    \18\ Maximum impact is defined as the maximum or1st high out of 
all modeled days (365 days in 2002).

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[[Page 32297]]

C. Reliance on CSAPR To Satisfy NOX BART

    Louisiana's February 2017 SIP revision relies on CSAPR as a BART 
alternative for NOX for EGUs. In our previous proposed 
approval of this February 2017 SIP revision,\19\ we proposed to find 
that the NOX BART requirements for all EGUs in Louisiana, 
including Nelson, will be satisfied by our determination and proposed 
for separate finalization that Louisiana's participation in CSAPR's 
ozone-season NOX program is a permissible alternative to 
source-specific NOX BART.\20\ We cannot finalize this 
portion of that proposed SIP approval action unless and until we 
finalize our separate proposed finding that CSAPR continues to provide 
for greater reasonable progress than BART \21\ because finalization of 
that proposal provides the basis for Louisiana to rely on CSAPR 
participation as an alternative to source-specific EGU BART for 
NOX. If for some reason our proposed approval of LDEQ's 
reliance on CSAPR as a BART alternative cannot be finalized, source-by-
source BART analyses for NOX will be required for all 
subject-to-BART EGUs in Louisiana, including Nelson.
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    \19\ 82 FR 22936.
    \20\ Id, at 22943.
    \21\ 81 FR 78954.
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D. Louisiana's Five-Factor Analyses for SO2 and PM BART for 
Nelson

    In determining BART, the state must consider the five statutory 
factors in section 169A of the CAA: (1) The costs of compliance; (2) 
the energy and non-air quality environmental impacts of compliance; (3) 
any existing pollution control technology in use at the source; (4) the 
remaining useful life of the source; and (5) the degree of improvement 
in visibility which may reasonably be anticipated to result from the 
use of such technology. See also 40 CFR 51.308(e)(1)(ii)(A). All units 
that are subject to BART must undergo a BART analysis. The BART 
Guidelines break the analysis down into five steps: \22\
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    \22\ 70 FR 39103, 39164 (July 6, 2005) [40 CFR 51, App. Y].
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    STEP 1--Identify All Available Retrofit Control Technologies,
    STEP 2--Eliminate Technically Infeasible Options,
    STEP 3--Evaluate Control Effectiveness of Remaining Control 
Technologies,
    STEP 4--Evaluate Impacts and Document the Results, and
    STEP 5--Evaluate Visibility Impacts.
    As mentioned previously, we disapproved portions of Louisiana's 
2008 Regional Haze SIP due to the State's reliance on CAIR as an 
alternative to source-by-source BART for EGUs.\23\ Following our 
limited disapproval, LDEQ worked closely with Louisiana's BART eligible 
EGUs, including Nelson, and with us to revise its Regional Haze SIP, 
which resulted in the submittal of its February and June 2017 SIP 
revisions addressing BART for Nelson. Although the February 2017 SIP 
revision addressed Nelson, we did not propose to take action on the 
SO2 and PM BART for Nelson in our May 19, 2017 proposed 
approval.\24\ Louisiana's February 2017 SIP revision relies on CSAPR 
participation as an alternative to source-specific EGU BART for 
NOX. The June 2017 SIP revision includes additional 
information that the State used to evaluate BART for the Nelson 
facility. Nelson has three BART-eligible steam generating units: Unit 
4, Unit 4 Auxiliary Boiler, and Unit 6.
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    \23\ 77 FR 33642.
    \24\ 82 FR 22936.
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    Unit 4 is permitted to combust natural gas, No. 2, No. 4 and No. 6 
fuel oils, and refinery fuel gas. Unit 4 has a maximum heat-rated 
capacity of 5,400 MMBtu/hour and exhausts out of one stack. It has flue 
gas recirculation equipment installed for control of NOX 
emissions. The Unit 4 Auxiliary Boiler is permitted to burn natural gas 
and fuel oil.
    Unit 6 burns coal as its primary fuel and No. 2 and No. 4 fuel oils 
as secondary fuels. Unit 6 has a maximum heat-rated capacity of 6,216 
MMBtu/hour and exhausts out of one stack. It has an electrostatic 
precipitator (ESP) with flue gas conditioning for control of PM 
emissions. Unit 6 has installed Separated Overfire Air Technology 
(SOFA) and a Low NOX Concentric Firing System (LNCFS) for 
NOX control. Entergy submitted a BART screening analysis to 
us and the LDEQ on August 31, 2015, and a BART five-factor analysis 
dated November 9, 2015, revised April 15, 2016, in response to an 
information request.\25\ These analyses were adopted and incorporated 
into Louisiana's February 2017 SIP revision (Appendix D). As part of 
our effort to assist the State, we submitted a draft analysis of 
Entergy's CALPUFF and CAMx modeling, our own draft CAMx and CALPUFF 
modeling, and our own draft cost analysis for Nelson to LDEQ. These 
analyses were adopted and incorporated into Louisiana's June 2017 SIP 
revision (Appendix F).
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    \25\ Letter from Wren Stenger, Director, Multimedia Planning and 
Permitting Division, EPA Region 6, to Renee Masinter, Entergy 
Louisiana (May 19, 2015); letter from Wren Stenger to Paul Castanon, 
Entergy Gulf States (May 19, 2015; and letter from Wren Stenger to 
Marcus Brown, Entergy New Orleans (May 19, 2015).
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Unit 4 and Unit 4 Auxiliary Boiler
    These units are currently permitted to burn natural gas and fuel 
oil. However, Entergy has not burned fuel oil at either unit in several 
years. Further, Entergy has no current operational plans to burn fuel 
oil. The LDEQ did not conduct a five-factor BART analysis for these 
units. The preamble to the BART Guidelines states: \26\
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    \26\ 70 FR 39116.

    Consistent with the CAA and the implementing regulations, States 
can adopt a more streamlined approach to making BART determinations 
where appropriate. Although BART determinations are based on the 
totality of circumstances in a given situation, such as the distance 
of the source from a Class I area, the type and amount of pollutant 
at issue, and the availability and cost of controls, it is clear 
that in some situations, one or more factors will clearly suggest an 
outcome. Thus, for example, a State need not undertake an exhaustive 
analysis of a source's impact on visibility resulting from 
relatively minor emissions of a pollutant where it is clear that 
controls would be costly and any improvements in visibility 
resulting from reductions in emissions of that pollutant would be 
negligible. In a scenario, for example, where a source emits 
thousands of tons of SO2 but less than one hundred tons 
of NOX, the State could easily conclude that requiring 
expensive controls to reduce NOX would not be 
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appropriate.

    The SO2 and PM emissions from gas-fired units are 
inherently low,\27\ so the installation of any additional PM or 
SO2 controls on this unit would likely achieve very small 
emissions reductions and have minimal visibility benefits.
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    \27\ AP 42, Fifth Edition, Volume 1, Chapter 1: External 
Sources, Section 1.4, Natural Gas Combustion, available here: 
https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s04.pdf.
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    To address SO2 and PM BART for Unit 4 and the Unit 4 
Auxiliary boiler, the June 2017 SIP revision precludes fuel-oil 
combustion at these units. To make the prohibition on fuel-oil usage 
enforceable, Entergy and the LDEQ intend to enter an Administrative 
Order on Consent (AOC), included in the June 2017 SIP revision, that 
establishes the following requirement:

    Before fuel oil firing is allowed to take place at Unit 4, and 
the auxiliary boiler at the Facility, a revised BART determination 
must be promulgated for SO2 and PM for the fuel oil 
firing scenario through a FIP or an action by the LDEQ as a SIP 
revision and approved by the EPA such that the action will become 
federally enforceable.

    We propose to approve the AOC as sufficient to meet the 
SO2 and PM BART requirements for Unit 4 and the Unit 4 
Auxiliary Boiler. If we finalize our

[[Page 32298]]

approval of the AOC, it will become federally enforceable for purposes 
of regional haze.
Unit 6
Identification of Controls
    In assessing SO2 BART in the February 2017 SIP revision 
(Appendix D), Entergy considered the five BART factors. In assessing 
feasible control technologies and their effectiveness, Entergy 
considered low-sulfur coal, Dry Sorbent Injection (DSI), an enhanced 
DSI system, dry scrubbing (spray dry absorption, or SDA), and wet 
scrubbing (wet flue gas desulfurization, or wet FGD).
    DSI is performed by injecting a dry reagent into the hot flue gas, 
which chemically reacts with SO2 and other gases to form a 
solid product that is subsequently captured by the particulate control 
device. We agree with the LDEQ that no technical feasibility concerns 
warrant removing these controls from consideration as potential BART 
options for Unit 6.
    SO2 scrubbing techniques utilize a large dedicated 
vessel in which the chemical reaction between the sorbent \28\ and 
SO2 takes place either completely or in large part. In 
contrast to DSI systems, SO2 scrubbers add water to the 
sorbent when introduced to the flue gas. The two predominant types of 
SO2 scrubbing employed at coal-fired EGUs are limestone wet 
FGD and lime SDA. These controls are in wide use and have been 
retrofitted to a variety of boiler types and plant configurations. We 
agree with the LDEQ that no technical feasibility concerns warrant 
removing these controls from consideration as potential BART options 
for Unit 6.
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    \28\ Limestone is the most common sorbent used in wet scrubbing, 
while lime is the most common sorbent used in dry scrubbing.
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    Utilization of coal with a lower sulfur content will also result in 
a reduction in SO2 emissions. Thus, Entergy identified 
switching to a lower sulfur coal in order to meet an emission limit of 
0.6 lb/MMBtu as a potential BART control option. We note that the BART 
Guidelines do not require states to consider fuel supply changes as a 
potential control option,\29\ but states are free to do so at their 
discretion.
---------------------------------------------------------------------------

    \29\ 40 CFR part 51, Appendix Y, Section IV.D.1.5, ``STEP 1: How 
do I identify all available retrofit emission control techniques?''
---------------------------------------------------------------------------

Control-Effectiveness
    Entergy assessed SDA and wet FGD as being capable of achieving 
SO2 emission rates of 0.06 lb/MMBtu and 0.04 lb/MMBtu, 
respectively. As we discuss in the TSD, based on review of IPM 
documentation, industry publications, and real-world monitoring data, 
we agree with the LDEQ that 98% control efficiency for wet FGD and 95% 
control efficiency for SDA are reasonable assumptions and consistent 
with the emission rates identified by Entergy.
    Entergy determined that DSI could achieve an SO2 
emission rate of 0.47 lb/MMBtu when coupled with the existing Unit 6 
ESP and that enhanced DSI could achieve an SO2 emission rate 
of 0.19 lb/MMBtu when coupled with a new fabric filter. Finally, 
Entergy determined that switching to a lower sulfur coal could reduce 
the SO2 emission rate at Unit 6 to approximately 0.6 lb/
MMBtu.
Impact Analysis
    Entergy presented cost-effectiveness figures for each control they 
evaluated. Entergy estimated that the cost-effectiveness of switching 
to lower sulfur coal (LSC) would be $597/ton of emissions removed, the 
cost-effectiveness of DSI would be $5,590/ton, the cost-effectiveness 
of enhanced DSI would be $5,611/ton, the cost-effectiveness of SDA 
would be $4,536/ton, and the cost-effectiveness of wet FGD would be 
$4,413/ton. See Appendix D of the February 2017 Louisiana Regional Haze 
SIP. In general, Entergy's DSI and scrubber cost calculations were 
based on a propriety database, so we were unable to verify any of the 
company's costs. We solicit comment with respect to any information 
that would support or refute the undocumented costs in Entergy's 
evaluation. We also note that Entergy's control cost estimates included 
costs not allowed under our Control Cost Manual (e.g., escalation 
during construction and owner's costs).\30\ Entergy also assumed a 
contingency of 25%, which we note is unusually high. The lack of 
documentation aside, removing the disallowed costs and adjusting the 
contingency to a more reasonable value of 10% significantly improves 
(lower $/ton) Entergy's cost-effectiveness estimates. For instance, 
assuming the same SO2 baseline as we used in our 
analyses,\31\ Entergy's SDA cost-effectiveness would improve from a 
value of $5,094/ton to $4,154/ton.
---------------------------------------------------------------------------

    \30\ As noted in our letter to Kelly McQueen of Entergy on March 
16, 2016, we requested documentation for the Nelson Unit 6 cost 
analyses. Entergy replied on April 15, 2016, but did not supply any 
additional site specific documentation.
    \31\ Our SO2 baseline, used in all of our cost-
effectiveness calculations (including our adjustment of Entergy's 
cost analyses), was obtained from eliminating the max and min of the 
Nelson Unit 6 annual SO2 emissions from 2012-2016, and 
averaging the SO2 emissions from the remaining years.
---------------------------------------------------------------------------

    Regarding the cost to switch to lower sulfur coal, Entergy states 
that its $597/ton cost-effectiveness value is based on a lower sulfur 
coal premium of $0.50/ton, but Entergy does not provide any 
documentation to support this figure. We examined information regarding 
Entergy's coal purchases for Nelson Unit 6 from the Energy Information 
Administration. This information indicated that, although there is some 
variability in the data, the premium Entergy has historically paid for 
lower sulfur coal has averaged higher than $0.50/ton.\32\ We solicit 
comments on Entergy's $0.50/ton figure.
---------------------------------------------------------------------------

    \32\ We calculated a premium of $2.48 based on a review of coal 
purchase data for 2016 from EIA. See the TSD for additional 
information.
---------------------------------------------------------------------------

    Because of these issues, we developed our own control cost 
analyses, which we present in our TSD. Table 1 summarizes the results 
of our analyses. For our cost-effectiveness calculations, we used a 
SO2 baseline constructed from annual SO2 
emissions from the 2012-2016 period.\33\ LDEQ incorporated our cost 
analysis into Appendix F of its June 2017 SIP revision along with 
Entergy's cost analysis.
---------------------------------------------------------------------------

    \33\ Our SO2 baseline, used in all of our cost-
effectiveness calculations (including our adjustment of Entergy's 
cost analyses), was obtained from eliminating the max and min of the 
Nelson Unit 6 annual SO2 emissions from 2012-2016, and 
averaging the SO2 emissions from the remaining years.

                                                         Table 1--Summary of EPA's Cost Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                               2016
                                                                                           SO2 reduction    2016 Total      2016 Cost-      Incremental
                   Unit                                Control             Control level       (tpy)        annualized     effectiveness       cost-
                                                                                (%)                            cost           ($/ton)      effectiveness
                                                                                                                                             ($/ton) *
--------------------------------------------------------------------------------------------------------------------------------------------------------
Nelson Unit 6.............................  Low-Sulfur Coal.............            11.3           1,149      $3,397,281          $2,957          $2,957
                                            DSI.........................              50           5,082      18,180,195           3,578           3,759

[[Page 32299]]

 
                                            SDA.........................           92.11           9,361      25,332,736           2,706           1,671
                                            Wet FGD.....................           94.74           9,628      26,409,798           2,743           4,027
--------------------------------------------------------------------------------------------------------------------------------------------------------
* For low-sulfur coal, the incremental $/ton is relative to use of coal typically used by the source in the past. For each remaining control,
  incremental $/ton is relative to the control in the row above.

    In assessing energy impacts, Entergy identified additional power 
requirements associated with operating DSI, SDA, and wet FGD. 
Documentation issues aside, these auxiliary-power costs were accounted 
for in the variable operating costs in the cost evaluation. Entergy did 
not identify any energy impacts associated with switching to a lower 
sulfur coal. We agree with LDEQ's identification of the energy impacts 
associated with each of the control options.
    In assessing non-air quality environmental impacts, Entergy noted 
that DSI, SDA, and wet FGD would add spent reagent to the waste stream 
generated by the facility. Entergy accounted for these waste-disposal 
costs in the variable operating costs in the cost evaluation. See our 
TSD for further information. Entergy did not identify any non-air 
quality environmental impacts associated with switching to a lower 
sulfur coal. We agree with LDEQ's identification of the non-air quality 
environmental impacts associated with each of the control options.
    In assessing remaining useful life, Entergy indicated this factor 
did not impact the evaluation of controls as there is no enforceable 
commitment in place to retire Unit 6. We agree with LDEQ that Entergy's 
use of a 30-year equipment life for the DSI, SDA, and wet FGD cost 
evaluations, which is consistent with the Control Cost Manual, was 
therefore appropriate.
    In assessing visibility impacts, Entergy evaluated the visibility 
impacts and potential benefits of each control option (See Appendix D 
for Entergy's visibility BART analysis for Nelson Unit 6). However, 
Entergy's CALPUFF modeling included errors in its estimates of sulfuric 
acid and PM emissions.\34\ EPA performed CALPUFF modeling to correct 
for these errors (See CALPUFF Modeling TSD). The LDEQ incorporated our 
modeling, among other things, into the June 2017 SIP revision (Appendix 
F) and considered it along with the visibility analysis developed by 
Entergy. As we discuss above and in the CAMx Modeling TSD, Entergy also 
provided additional screening modeling results using CAMx to support 
its conclusion that visibility impacts from Unit 6 are minimal. 
However, this modeling was not conducted in accordance with the BART 
Guidelines and does not properly assess maximum baseline impacts, so we 
consider this CAMx modeling provided by Entergy to be invalid for 
supporting a determination of minimal visibility impacts. We performed 
our own CAMx modeling that follows the BART Guidelines and uses 
appropriate techniques and metrics to provide additional information on 
visibility impacts and benefits and to address possible concerns with 
utilizing CALPUFF to assess visibility impacts at Class I areas located 
farther from the emission sources. The LDEQ also incorporated this 
information into the June 2017 SIP revision (Appendix F) and considered 
it along with the visibility analysis developed by Entergy.
---------------------------------------------------------------------------

    \34\ See the CALPUFF Modeling TSD for discussion of these errors 
and corrected values.
---------------------------------------------------------------------------

    EPA's CAMx modeling for Unit 6 directly evaluated the maximum 
baseline visibility impacts and potential benefits from DSI. In 
addition to the DSI modeled benefits, visibility benefits for SDA, wet 
FGD, and low-sulfur coal were estimated based on linear extrapolation 
for the average across the top ten impacted days using the modeled 
baseline and DSI visibility impacts, and estimated emission reductions. 
We note that the baseline emission rate modeled is based on 24-hr 
actual emissions during the baseline period (2000-2004), while the 
control scenario emission rates are based on anticipated 30-day 
emission rates, as noted in the table below. At a maximum heat input of 
6,126 MMBtu/hr for the boiler, the baseline short-term emission rate is 
approximately 1.2 lb/MMBtu for the 2000-2004 baseline. The results of 
this modeling for the maximum-impact day and the average across the top 
ten most impacted baseline days are summarized in Table 2. We note that 
wet FGD is estimated to provide a very small visibility benefit over 
SDA on average across the top ten most impacted baseline days, so we do 
not show the results for wet FGD in this table. See the CAMx Modeling 
TSD for a full description of the modeling and model results.

                                                  Table 2--Summary of EPA's Visibility Analysis (CAMx)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                            Visibility     Visibility benefit of controls over baseline
                                                                             Baseline       benefit of        (dv) average for top ten impacted days
                                                             Baseline       Impact (dv)    controls over -----------------------------------------------
                      Class I area                          impact \a\     (average for    baseline (dv)
                                                               (dv)           top ten     maximum impact    Low-sulfur
                                                             (maximum)    impacted days) ----------------    coal \c\         DSI \d\         SDA \e\
                                                                                              DSI \b\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Breton..................................................           0.599           0.314           0.250           0.133           0.165           0.266
Caney Creek.............................................           2.179           1.302           1.187           0.411           0.511           0.831
Mingo...................................................           1.468           0.785           0.370           0.215           0.265           0.430
Upper Buffalo...........................................           1.219           0.934           0.374           0.330           0.408           0.663
Hercules-Glade..........................................           1.287           0.777           0.473           0.273           0.338           0.548

[[Page 32300]]

 
Wichita Mountains.......................................           0.575           0.412           0.287           0.180           0.223           0.360
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ 2000-2004 baseline.
\b\ DSI at 0.47 lb/MMBtu.
\c\ Low-Sulfur Coal benefit (at 0.6 lb/MMBtu, estimated based on linear extrapolation of baseline and DSI visibility impacts at each Class I area.
\d\ DSI at 0.47 lb/MMBtu.
\e\ SDA at 0.06 lb/MMBtu, estimated based on linear extrapolation of baseline and DSI visibility impacts at each Class I area.

Louisiana's SO2 BART Determination for Nelson Unit 6
    The LDEQ weighed the statutory factors, reviewed Entergy's and 
EPA's information, and concluded that SO2 BART is an 
emission limit of 0.6 lbs/MMBtu based on a 30-day rolling average, 
consistent with the use of lower-sulfur coal. The LDEQ acknowledged 
that the visibility benefits of SDA and wet FGD are larger than those 
associated with lower-sulfur coal, but explained that lower-sulfur coal 
still achieves some visibility benefits and at a lower annual cost. The 
LDEQ also noted that SDA and wet FGD create additional waste due to 
spent reagent and have additional power demands to run the equipment.
Louisiana's PM BART Determination for Nelson Unit 6
    The LDEQ noted that Nelson Unit 6 is currently equipped with an ESP 
to control PM emissions, the visibility impacts from PM emissions are 
small, and that any additional controls beyond the ESP would have 
minimal visibility benefits and would not be cost-effective. Therefore, 
the LDEQ determined that PM BART is an emission limit of 317.61 lb/hr, 
consistent with the use of the existing ESP.
Our Review of Louisiana's BART Determination for Nelson Unit 6
    We propose to approve LDEQ's proposed finding in the June 2017 SIP 
revision that the visibility impacts from Unit 6's PM emissions are so 
minimal that any additional PM controls would result in very minimal 
visibility benefits that would not justify the cost of any upgrades 
and/or operational changes needed to achieve a more stringent emission 
limit. Unit 6 is currently equipped with an ESP for controlling PM 
emissions. The PM control efficiency of ESPs varies somewhat with the 
design of the ESP, the resistivity of the PM, and the maintenance of 
the ESP. We do not have information on the control efficiency of the 
ESP in use at Unit 6. However, reported control efficiencies for well-
maintained ESPs typically range from greater than 99% to 99.9%.\35\ We 
consider this pertinent in concluding that the potential additional PM 
control that a baghouse could offer over an ESP would be very minimal 
and come at a very high cost.\36\ Also, our visibility modeling 
indicates that the impact from Unit 6's baseline PM emissions is very 
small, so the visibility improvement from replacing the ESP with a 
baghouse would be only a fraction of that small impact.\37\ As 
discussed above, states can adopt a more streamlined approach to making 
BART determinations where appropriate. We therefore propose to agree 
with Louisiana that no additional controls are required to satisfy PM 
BART. In the June 2017 SIP revision, the LDEQ and Entergy have proposed 
to enter into an AOC establishing an enforceable limit on 
PM10 consistent with current controls at 317.61 lb/hr on a 
30-day rolling basis. We are proposing to approve this AOC if it is 
finalized without significant changes and included in the final 
submittal.
---------------------------------------------------------------------------

    \35\ EPA, ``Air Pollution Control Technology Fact Sheet: Dry 
Electrostatic Precipitator (ESP)--Wire Plate Type,'' EPA-452/F-03-
028. Grieco, G., ``Particulate Matter Control for Coal-fired 
Generating Units: Separating Perception from Fact,'' apcmag.net, 
February, 2012. Moretti, A. L.; Jones, C. S., ``Advanced Emissions 
Control Technologies for Coal-Fired Power Plants, Babcox and Wilcox 
Technical Paper BR-1886, Presented at Power-Gen Asia, Bangkok, 
Thailand, October 3-5, 2012.
    \36\ We do not discount the potential health benefits this 
additional control can have for ambient PM. However, the regional 
haze program is only concerned with improving the visibility at 
Class I areas.
    \37\ See the TSD for additional information.
---------------------------------------------------------------------------

    We are also proposing to approve the LDEQ's February 2017 SIP 
revision as revised by the LDEQ's June 2017 SIP revision that addresses 
BART for the Nelson facility, including the State's proposed finding 
that lower sulfur coal is the appropriate SO2 BART control 
for Unit 6. LDEQ has weighed the statutory factors and after a review 
of both Entergy's and EPA's information has concluded that BART is the 
emission limit of 0.6 lbs/MMBtu based on a 30-day rolling average as 
defined in the AOC. The LDEQ and Entergy have proposed to enter into an 
AOC establishing an enforceable limit of SO2 at 0.6 lbs/
MMBtu on a 30-day rolling basis. The emission limit will become 
enforceable upon EPA's final approval of the SIP. We are proposing to 
approve this AOC if finalized without significant changes and if it is 
included in the final submittal.
    As the energy industry evolves, the LDEQ has committed to continue 
to work with EGUs throughout Louisiana to evaluate the operation of 
utilities. As such, the LDEQ will engage in discussions with Entergy 
about any potential changes in usage or emission rates at the Nelson 
facility. Any such changes will be considered for reasonable progress 
for future planning periods as appropriate.

III. Proposed Action

    We are proposing to approve the remaining portion of the 
Louisiana's Regional Haze SIP revision submitted on February 10, 2017, 
related to the Entergy Nelson facility and the SIP revision submitted 
to the EPA for parallel processing on June 20, 2017 that establishes 
BART for the Nelson facility. We propose to approve the BART 
determination for Nelson Units 6 and 4 and Unit 4 auxiliary boiler, and 
the AOC that makes emission limits that represent BART permanent and 
enforceable for the purposes of regional haze. We solicit comment with 
respect to any information that would support or refute the 
undocumented costs in Entergy's evaluation for SO2 controls 
on Unit 6. Once we take final action on our proposed approval of 
Louisiana's 2016 SIP revision addressing non-EGU

[[Page 32301]]

BART,\38\ our proposed approval addressing BART for all other BART-
eligible EGUs \39\ and this proposal to address SO2 and PM 
BART for the Nelson facility, we will have fulfilled all outstanding 
obligations with respect to the Louisiana regional haze program for the 
first planning period.
---------------------------------------------------------------------------

    \38\ 81 FR 74750 (October 27, 2016).
    \39\ 82 FR 22936 (May 19, 2017).
---------------------------------------------------------------------------

    The EPA has made the preliminary determination that the June 2017 
SIP revision requested by the State to be parallel processed is in 
accordance with the CAA and consistent with the CAA and the EPA's 
policy and guidance. Therefore, the EPA is proposing action on the June 
2017 SIP revision in parallel with the State's rulemaking process. 
After the State completes its rulemaking process, adopts its final 
regulations, and submits these final adopted regulations as a revision 
to the Louisiana SIP, the EPA will prepare a final action. If changes 
are made to the State's proposed rule after the EPA's notice of 
proposed rulemaking, such changes must be acknowledged in the EPA's 
final rulemaking action. If the changes are significant, then the EPA 
may be obligated to withdraw our initial proposed action and re-
propose.

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).
    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

    Environmental protection, Air pollution control, Incorporation by 
reference, Intergovernmental relations, Nitrogen dioxide, Ozone, 
Particulate matter, Reporting and recordkeeping requirements, Sulfur 
dioxides, Visibility, Interstate transport of pollution, Regional haze, 
Best available control technology.

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

    Dated: June 23, 2017.
Samuel Coleman,
Acting Regional Administrator, Region 6.
[FR Doc. 2017-14693 Filed 7-12-17; 8:45 am]
 BILLING CODE 6560-50-P