Approval and Promulgation of Implementation Plans; Louisiana; Regional Haze State Implementation Plan, 32294-32301 [2017-14693]
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In addition, the SIP is not approved
to apply on any Indian reservation land
or in any other area where the 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, Ammonia,
Incorporation by reference,
Intergovernmental relations, Nitrogen
dioxide, Particulate matter, Reporting
and recordkeeping requirements, Sulfur
dioxide, Volatile organic compounds.
Authority: 42 U.S.C. 7401 et seq.
Dated: June 30, 2017.
Debra H. Thomas,
Acting Regional Administrator, Region 8.
[FR Doc. 2017–14748 Filed 7–12–17; 8:45 am]
BILLING CODE 6560–50–P
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
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
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 particulatematter (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 https://
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SUMMARY:
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www.regulations.gov or via email to R6_
LA_BART@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 Jennifer Huser, huser.jennifer@
epa.gov. For the full EPA public
comment policy, information about CBI
or multimedia submissions, and general
guidance on making effective
comments, please visit https://
www2.epa.gov/dockets/commentingepa-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,
huser.jennifer@epa.gov. 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 BARTEligible 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
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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 hazecausing 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
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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 undercontrolled, 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
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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
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
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
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1 77
FR 33642 (June 7, 2012).
FR 39425 (July 3, 2012).
3 81 FR 74750 (October 27, 2016).
4 82 FR 22936 (May 19, 2017).
2 77
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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 BARTEligible Source
In our partial disapproval and partial
limited approval of the 2008 Louisiana
Regional Haze SIP, we approved the
LDEQ’s identification of 76 BARTeligible 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.
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 BARTeligible 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
5 See
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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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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
6 We have previously proposed approval of the
portion of LDEQ’s February 2017 revision that relies
on CSAPR participation as an alternative to sourcespecific 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’’.
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.
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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
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 startup, 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.
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
11 70 FR 39104, 39120 (July 6, 2005), [40 CFR part
51, Appendix Y].
12 See, 77 FR 11839, 11849 (February 28, 2012).
13 https://ampd.epa.gov/ampd/.
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
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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.
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 BARTeligible 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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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 sourcespecific EGU BART for NOX. If for some
reason our proposed approval of LDEQ’s
reliance on CSAPR as a BART
alternative cannot be finalized, sourceby-source BART analyses for NOX will
be required for all subject-to-BART
EGUs in Louisiana, including Nelson.
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 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. 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
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
19 82
FR 22936.
at 22943.
21 81 FR 78954.
22 70 FR 39103, 39164 (July 6, 2005) [40 CFR 51,
App. Y].
20 Id,
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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.
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
FR 33642.
FR 22936.
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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24 82
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incorporated into Louisiana’s June 2017
SIP revision (Appendix F).
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
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 appropriate.
The SO2 and PM emissions from gasfired 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.
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
26 70
FR 39116.
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.
27 AP
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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.
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.
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 costeffectiveness of switching to lower
sulfur coal (LSC) would be $597/ton of
emissions removed, the costeffectiveness of DSI would be $5,590/
ton, the cost-effectiveness of enhanced
DSI would be $5,611/ton, the costeffectiveness 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 costeffectiveness would improve from a
value of $5,094/ton to $4,154/ton.
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.
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.
TABLE 1—SUMMARY OF EPA’S COST ANALYSIS
Control level
(%)
Control
Nelson Unit 6 ......................
sradovich on DSK3GMQ082PROD with PROPOSALS2
Unit
Low-Sulfur Coal ..................
DSI ......................................
28 Limestone is the most common sorbent used in
wet scrubbing, while lime is the most common
sorbent used in dry scrubbing.
29 40 CFR part 51, Appendix Y, Section IV.D.1.5,
‘‘STEP 1: How do I identify all available retrofit
emission control techniques?’’
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.
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SO2 reduction
(tpy)
11.3
50
1,149
5,082
Entergy replied on April 15, 2016, but did not
supply any additional site specific documentation.
31 Our SO baseline, used in all of our cost2
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.
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Fmt 4702
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2016 Total
annualized
cost
$3,397,281
18,180,195
2016 Costeffectiveness
($/ton)
$2,957
3,578
2016
Incremental
costeffectiveness
($/ton) *
$2,957
3,759
32 We calculated a premium of $2.48 based on a
review of coal purchase data for 2016 from EIA. See
the TSD for additional information.
33 Our SO baseline, used in all of our cost2
effectiveness calculations (including our adjustment
of Entergy’s cost analyses), was obtained from
eliminating the max and min of the Nelson Unit 6
annual SO2 emissions from 2012–2016, and
averaging the SO2 emissions from the remaining
years.
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32299
TABLE 1—SUMMARY OF EPA’S COST ANALYSIS—Continued
Unit
Control level
(%)
Control
SDA ....................................
Wet FGD .............................
SO2 reduction
(tpy)
92.11
94.74
9,361
9,628
2016 Total
annualized
cost
25,332,736
26,409,798
2016 Costeffectiveness
($/ton)
2,706
2,743
2016
Incremental
costeffectiveness
($/ton) *
1,671
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.
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)
Baseline
impact a (dv)
(maximum)
sradovich on DSK3GMQ082PROD with PROPOSALS2
Class I area
Baseline
Impact (dv)
(average for
top ten impacted days)
Visibility
benefit of
controls over
baseline (dv)
maximum
impact
Visibility benefit of controls over baseline (dv)
average for top ten
impacted days
Low-sulfur
coal c
DSI d
SDA e
DSI b
Breton .......................................................
Caney Creek ............................................
Mingo .......................................................
Upper Buffalo ...........................................
Hercules-Glade ........................................
0.599
2.179
1.468
1.219
1.287
0.314
1.302
0.785
0.934
0.777
0.250
1.187
0.370
0.374
0.473
0.133
0.411
0.215
0.330
0.273
34 See the CALPUFF Modeling TSD for discussion
of these errors and corrected values.
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E:\FR\FM\13JYP1.SGM
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0.165
0.511
0.265
0.408
0.338
0.266
0.831
0.430
0.663
0.548
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TABLE 2—SUMMARY OF EPA’S VISIBILITY ANALYSIS (CAMX)—Continued
Baseline
impact a (dv)
(maximum)
Class I area
Baseline
Impact (dv)
(average for
top ten impacted days)
Visibility
benefit of
controls over
baseline (dv)
maximum
impact
Visibility benefit of controls over baseline (dv)
average for top ten
impacted days
Low-sulfur
coal c
DSI d
SDA e
DSI b
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.
sradovich on DSK3GMQ082PROD with PROPOSALS2
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
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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.
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
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.
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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 30day 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
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Federal Register / Vol. 82, No. 133 / Thursday, July 13, 2017 / Proposed Rules
BART,38 our proposed approval
addressing BART for all other BARTeligible 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.
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.
sradovich on DSK3GMQ082PROD with PROPOSALS2
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
38 81
FR 74750 (October 27, 2016).
39 82 FR 22936 (May 19, 2017).
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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
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 62
[EPA–R02–OAR–2017–0132, FRL–9962–42–
Region 2]
Approval and Promulgation of Plans
for Designated Facilities; New Jersey;
Delegation of Authority
AGENCY:
Environmental Protection
Agency.
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ACTION:
32301
Proposed rule.
The Environmental Protection
Agency (EPA) is proposing to approve a
request from the New Jersey Department
of Environmental Protection (NJDEP) for
delegation of authority to implement
and enforce the Federal plan for Sewage
Sludge Incineration (SSI) units. On
April 29, 2016 the EPA promulgated the
Federal plan for SSI units to fulfill the
requirements of sections 111(d)/129 of
the Clean Air Act. The Federal plan
addresses the implementation and
enforcement of the emission guidelines
applicable to existing SSI units located
in areas not covered by an approved and
currently effective state plan. The
Federal plan imposes emission limits
and other control requirements for
existing affected SSI facilities which
will reduce designated pollutants.
On January 24, 2017, the NJDEP
signed a Memorandum of Agreement
which is intended to be the mechanism
for the transfer of authority between the
EPA and the NJDEP and defines the
policies, responsibilities and procedures
pursuant to the Federal plan for existing
SSI units.
SUMMARY:
Written comments must be
received on or before August 14, 2017.
DATES:
Submit your comments,
identified by Docket ID Number EPA–
R02–OAR–2017–0132 at https://
www.regulations.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, the full
EPA public comment policy,
information about CBI or multimedia
submissions, and general guidance on
making effective comments, please visit
https://www2.epa.gov/dockets/
commenting-epa-dockets.
ADDRESSES:
FOR FURTHER INFORMATION CONTACT:
Anthony (Ted) Gardella, Environmental
Protection Agency, 290 Broadway, New
York, New York 10007–1866, at (212)
E:\FR\FM\13JYP1.SGM
13JYP1
]]>Agencies
[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 https://www.regulations.gov or via email to
R6_LA_BART@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 Jennifer Huser,
huser.jennifer@epa.gov. For the full EPA public comment policy,
information about CBI or multimedia submissions, and general guidance
on making effective comments, please visit https://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,
huser.jennifer@epa.gov. 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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\13\ https://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].
---------------------------------------------------------------------------
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).
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
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\29\ 40 CFR part 51, Appendix Y, Section IV.D.1.5, ``STEP 1: How
do I identify all available retrofit emission control techniques?''
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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.
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\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.
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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.
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\32\ We calculated a premium of $2.48 based on a review of coal
purchase data for 2016 from EIA. See the TSD for additional
information.
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Because of these issues, we developed our own control cost
analyses, which we present in our TSD. Table 1 summarizes the results
of our analyses. For our cost-effectiveness calculations, we used a
SO2 baseline constructed from annual SO2
emissions from the 2012-2016 period.\33\ LDEQ incorporated our cost
analysis into Appendix F of its June 2017 SIP revision along with
Entergy's cost analysis.
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\33\ Our SO2 baseline, used in all of our cost-
effectiveness calculations (including our adjustment of Entergy's
cost analyses), was obtained from eliminating the max and min of the
Nelson Unit 6 annual SO2 emissions from 2012-2016, and
averaging the SO2 emissions from the remaining years.
Table 1--Summary of EPA's Cost Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
2016
SO2 reduction 2016 Total 2016 Cost- Incremental
Unit Control Control level (tpy) annualized effectiveness cost-
(%) cost ($/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.
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\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.
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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.
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\38\ 81 FR 74750 (October 27, 2016).
\39\ 82 FR 22936 (May 19, 2017).
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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
