[Federal Register Volume 82, Number 244 (Thursday, December 21, 2017)]
[Rules and Regulations]
[Pages 60520-60543]
[FR Doc No: 2017-27452]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2016-0520; EPA-R06-OAR-2017-0129; FRL-9971-85-Region 6]

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: Pursuant to the Federal Clean Air Act (CAA or the Act), the
Environmental Protection Agency (EPA) is finalizing an approval of
revisions to the Louisiana State Implementation Plan (SIP) submitted by
the State of Louisiana through the Louisiana Department of
Environmental Quality (LDEQ) that address regional haze for the first
planning period. LDEQ submitted these revisions to address the
requirements of the Clean Air Act (CAA) and the EPA's rules that
require states to prevent any future and remedy any existing
anthropogenic impairment of visibility in mandatory Class I areas
(national parks and wilderness areas) caused by emissions of air
pollutants from numerous sources located over a wide geographic area
(also referred to as the ``regional haze program''). To address the
Best Available Retrofit Technology (BART) requirement for sulfur
dioxide (SO2), oxides of nitrogen (NOX) and
particulate matter (PM), the EPA is finalizing approval of source-by-
source BART determinations for certain electric generating and non-
electric generating units. To address the BART requirement for
NOX for electric generating units, we are finalizing our
proposed determination that Louisiana's participation in the Cross-
State Air Pollution Rule's (CSAPR) trading program for ozone-season
NOX qualifies as an alternative to BART.

DATES: This rule is effective on January 22, 2018.

ADDRESSES: The EPA has established dockets for this action under Docket
ID No. EPA-R06-OAR-2016-0520 for non-electric generating units and
Docket ID No. EPA-R06-OAR-2017-0129 for electric generating units
(EGUs). All documents in the dockets are listed on the http://www.regulations.gov website. Although listed in the index, some
information is not publicly available, e.g., Confidential Business
Information or other information whose disclosure is restricted by
statute. Certain other material, such as copyrighted material, is not
placed on the internet and will be publicly available only in hard copy
form. Publicly available docket materials are available either
electronically through http://www.regulations.gov or in hard copy at
the EPA Region 6, 1445 Ross Avenue, Suite 700, Dallas, Texas 75202-
2733.

FOR FURTHER INFORMATION CONTACT: Jennifer Huser,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION: Throughout this document ``we,'' ``us,'' and
``our'' means the EPA.

I. Background
    A. The Regional Haze Program
    B. Our Previous Actions
    C. CSAPR as an Alternative to Source-Specific NOX
BART
II. Summary of Final Action
III. Response to Comments
    A. Modeling
    B. NRG Big Cajun II
    C. Cleco Brame Energy Center
    D. Entergy Nelson
    E. Legal
    F. CSAPR-Better-Than-BART
    H. Long-Term Strategy and Reasonable Progress
    I. Compliance Date for Nelson
IV. Final Action
V. Incorporation by Reference
VI. 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 of
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 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 \1\ 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 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.
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    \1\ Here and elsewhere in this document, the term ``Regional
Haze Rule,'' refers to the 1999 final rule (64 FR 35714), as amended
in 2005 (70 FR 39156, July 6, 2005), 2006 (71 FR 60631, October 13,
2006), 2012 (77 FR 33656, June 7, 2012), and January 10, 2017 (82 FR
3078).
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    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

    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 \2\ 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 \3\ 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 existing SIP. In that
action we disapproved Louisiana's long-term strategy, finding that it
was deficient given our finding that certain of Louisiana's BART
determinations were not fully approvable.\4\ We found that Louisiana
followed the requirements with regards to reasonable progress goals,
but that the goals did not reflect appropriate emissions reductions for
BART. We found that the long term strategy satisfied most requirements
of 40 CFR 51.308(d)(3), but was deficient since it relied on BART
determinations which we disapproved.
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    \2\ 77 FR 33642 (June 7, 2012).
    \3\ 77 FR 39425 (July 3, 2012).
    \4\ 77 FR 39426 (July 3, 2012).
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    On August 11, 2016, Louisiana submitted a SIP revision to address
the deficiencies related to BART for four non-EGU facilities: Sid
Richardson, Phillips 66 Company--Alliance Refinery, Mosaic, and
EcoServices, LLC. Based on the BART analysis and modeling provided by
Sid Richardson, LDEQ concluded that the facility is not subject to BART
because its model visibility impact was less than 0.5 deciviews (dv).
We proposed to approve this determination. We also proposed approval of
LDEQ's determination that the current controls installed and operating
conditions at the Phillips 66 Company--Alliance Refinery subject to
BART units constitute BART. The emission limits which reflect current
controls and operating conditions at the facility for all subject to
BART units are included in Administrative Order on Consent (AOC) No.
AE-AOC-14-00211A between LDEQ and Phillips 66 in accordance with 40 CFR
51.308(e), and were provided in the August 11, 2016 SIP revision. We
further proposed approval of LDEQ's determination that the current
controls and operating conditions at the Mosaic facility constitute
BART. The emission limits for Mosaic under current controls and
operating conditions are included in AOC No. AE-AOC-14-00274A which was
included in the August 11, 2016 SIP revision. Finally, we proposed
approval

of LDEQ's determination that the current controls and operating
conditions at the EcoServices LLC facility constitute BART. The
emission limits for EcoServices are included in AOC No. AE-AOC-14-00957
between LDEQ and EcoServices. We proposed to approve that August 11,
2016 revision in its entirety on October 27, 2016.\5\ We received no
comments on our October 27, 2016 proposal and we are finalizing that
approval here.
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    \5\ 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. On May 19,
2017, we proposed to approve that revision, with the exception of the
portion related to Entergy's Nelson facility. We proposed to approve
the LDEQ determination that the BART-eligible units at the following
facilities do not cause or contribute to visibility impairment and are
not subject to BART: Terrebonne Parish Consolidated Government Houma
Generating Station (Houma), Louisiana Energy and Power Authority
Plaquemine Steam Plant (Plaquemine), Lafayette Utilities System Louis
``Doc'' Bonin Generating Station, Cleco Teche, Entergy Sterlington, NRG
Big Cajun I, and NRG Big Cajun II. We also proposed to approve the LDEQ
BART determinations for subject to BART units at the following
facilities: Cleco's Brame Energy Center, and Entergy's Willow Glen,
Little Gypsy, Ninemile Point, Waterford and Michoud facilities. We
proposed to approve the AOCs for Brame, Willow Glen, Little Gypsy, and
Ninemile Point. We are now finalizing our approval that BART has been
addressed for these units.
    We note that Entergy applied for a permit for Michoud, which
included the decommissioning of the subject to BART Units 2 and 3, and
the construction of new units. We proposed to approve the BART
determination for Units 2 and 3 based on the draft permit indicating
the units would no longer be operational. We expected the permit would
be finalized before we took final action but it has not yet been
finalized. We addressed this possibility by also proposing that LDEQ
could submit another enforceable document to ensure that Units 2 and 3
cannot restart without a BART determination and emission limits, or
otherwise demonstrate that the units have been decommissioned to the
point that they cannot restart without obtaining a new NSR permit. LDEQ
provided additional information from Entergy indicating that the units
are in the process of being decommissioned, and are non-operational, as
reflected in an email dated October 9, 2017, submitted by LDEQ to
supplement its February 2017 SIP revision. We received no comments on
our proposed approach for the Michoud BART units. As a result, we
approving the SIP's finding that BART is addressed because the units
are no longer in operation and are in the process of being
decommissioned.
    On June 20, 2017, LDEQ submitted a SIP revision for parallel
processing related to Entergy's Nelson facility. On July 13, 2017, we
proposed to approve this SIP revision along with the remaining portion
of the February 2017 SIP revision that addressed BART for the Nelson
facility. Specifically, we proposed to approve the LDEQ BART
determinations for Nelson Units 6 and 4, and the Unit 4 auxiliary
boiler, and the AOC that makes the emission limits that represent BART
permanent and enforceable for the purposes of regional haze. We also
solicited comment with respect to any information that would support or
refute the costs in Entergy's evaluation of SO2 controls for
Unit 6. On June 21, 2017, Entergy submitted a comment to LDEQ on its
proposed SIP revision requesting a three-year compliance deadline to
achieve the proposed SO2 BART limit for Nelson Unit 6.
Entergy's letter explained that the company has coal contracts in place
for the next three years, so the revised compliance date would provide
the company sufficient time to transition to new mines with lower
sulfur coal. Additionally, Entergy stated that it did not have the
necessary equipment to blend varying fuel supplies. On August 24, 2017,
we received a letter from LDEQ explaining their intent to revise the
compliance date in the SIP revision for Nelson Unit 6 based on
Entergy's comment letter. On September 26, 2017, we supplemented our
proposed approval of the SO2 BART determination for Nelson
by proposing to approve the three-year compliance date. On October 26,
2017, we received LDEQ's final SIP revision addressing Nelson,
including a final AOC with emission limits and a SO2
compliance date three years from the effective date of the EPA's final
approval of the SIP revision.

C. CSAPR as an Alternative to Source-Specific NOX BART

    In 2005, the EPA promulgated CAIR, which required 28 states and the
District of Columbia to reduce emissions of SO2 and
NOX that significantly contribute to non-attainment or
interfere with maintenance of the 1997 national ambient air quality
standards (NAAQS) for fine particulates and/or 8-hour ozone in any
downwind state.\6\ EPA demonstrated that CAIR would achieve greater
reasonable progress toward the national visibility goal than would BART
and determined that states participating in CAIR could rely on CAIR as
an alternative to EGU BART for SO2 and NOX.\7\
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    \6\ 70 FR 25161 (May 12, 2005).
    \7\ 70 FR 39104, 39139 (July 6, 2005).
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    Louisiana's 2008 Regional Haze SIP relied on participation in CAIR
as an alternative to meeting the source-specific EGU BART requirements
for SO2 and NOX.\8\ Shortly after Louisiana
submitted its SIP to us, however, the D. C. Circuit remanded CAIR
(without vacatur).\9\ The court thereby left CAIR and CAIR Federal
Implementation Plans (FIPs) in place in order to ``temporarily preserve
the environmental values covered by CAIR'' until we could, by
rulemaking, replace CAIR consistent with the court's opinion.\10\ In
2011, we promulgated the Cross-State Air Pollution Rule (CSAPR) to
replace CAIR.\11\ While EGUs in Louisiana were required to participate
in CAIR for both SO2 and NOX, Louisiana EGUs are
only included in CSAPR for ozone-season NOX.\12\
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    \8\ See 40 CFR 51.308(e)(4) (2006).
    \9\ The court decided to vacate CAIR on July 11, 2008, and
revised its decision, so as to remand the rule without vacatur, on
December 23, 2008. North Carolina v. EPA, 531 F. 3d 896, 901 (D.C.
Cir. 2008), modified, 550 F. 3d 1176 (D.C. Cir. 2008). Louisiana's
initial Regional Haze SIP was submitted on June 13, 2008. 77 FR
39425.
    \10\ 550 F. 3d at 1178.
    \11\ 76 FR 48207 (August 8, 2011).
    \12\ 76 FR 82219, at 82226 (December 30, 2011).
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    In 2012, we issued a limited disapproval of Louisiana's and several
other states' regional haze SIPs because of reliance on CAIR as an
alternative to EGU BART for SO2 and/or NOX.\13\
We also determined that CSAPR would provide for greater reasonable
progress than BART and amended the Regional Haze Rule to allow CSAPR
participation as an alternative to source-specific SO2 and/
or NOX BART for EGUs, on a pollutant-specific basis.\14\
Because Louisiana EGUs are included in CSAPR for NOX,
Louisiana can rely on CSAPR to satisfy the EGU BART requirement for
NOX.
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    \13\ The limited disapproval triggered the EPA's obligation to
issue a FIP or approve a SIP revision to correct the relevant
deficiencies within 2 years of the final limited disapproval action.
CAA section 110(c)(1); 77 FR 33642, at 33654 (August 6, 2012).
    \14\ While that rulemaking also promulgated FIPs for several
states to replace reliance on CAIR with reliance on CSAPR as an
alternative to BART, it did not include a FIP for Louisiana. 77 FR
33642, 33654.
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    CSAPR has been subject to extensive litigation, and on July 28,
2015, the D. C. Circuit issued a decision generally

upholding CSAPR but remanding without vacating the CSAPR emissions
budgets for a number of states.\15\ On October 26, 2016, we finalized
an update to CSAPR that addresses the 1997 ozone NAAQS portion of the
remand as well as the CAA requirements addressing interstate transport
for the 2008 ozone NAAQS.\16\ Additionally, three states, Alabama,
Georgia, and South Carolina, have adopted or committed to adopt SIPs to
replace the remanded FIPs and will continue their participation in the
CSAPR program on a voluntary basis with the same budgets. On November
10, 2016, we proposed a rule intended to address the remainder of the
court's remand as it relates to Texas.\17\ This separate proposed rule
included an assessment of the impacts of the set of actions that the
EPA had taken or expected to take in response to the D. C. Circuit's
remand on our 2012 demonstration that participation in CSAPR provides
for greater reasonable progress than BART. Based on that assessment,
the EPA proposed that states may continue to rely on CSAPR as an
alternative to BART on a pollutant-specific basis. On September 29,
2017, we finalized our proposed finding that the EPA's 2012 analytical
demonstration remains valid and that participation in CSAPR, as it now
exists, meets the Regional Haze Rule's criteria for an alternative to
BART.\18\ LDEQ's February 2017 SIP revision relies on CSAPR as an
alternative to BART for control of NOX from EGUs.
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    \15\ Louisiana's ozone season NOX budgets were not
included in the remand. EME Homer City Generation v. EPA, 795 F.3d
118, 138 (D.C. Cir. 2015).
    \16\ 81 FR74504 (October 26, 2016).
    \17\ 81 FR 78954 (November 10, 2016).
    \18\ 82 FR 45481 (September 29, 2017).
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II. Summary of Final Action

    This action finalizes our proposed approval of the BART
determinations for non-EGU facilities,\19\ our proposed approval of the
BART determinations for EGU facilities,\20\ our proposed approval of
the BART determination for Nelson Unit 6,\21\ our proposed approval of
the reliance on CSAPR by EGUs for NOX BART requirements, and
our proposed approval that the BART eligible sources \22\ at the
following facilities do not cause or contribute to visibility
impairment and are not subject to BART: Terrebonne Parish Consolidated
Government Houma Generating Station (Houma), Louisiana Energy and Power
Authority Plaquemine Steam Plant (Plaquemine), Lafayette Utilities
System Louis ``Doc'' Bonin Generating Station, Cleco Teche, Entergy
Sterlington, NRG Big Cajun I, and NRG Big Cajun II. With the exception
of the change in compliance date for Nelson Unit 6, we note that we are
finalizing the proposed rules referenced above as proposed.\23\ A brief
summary of the SIP submittal provisions being finalized is included
below.
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    \19\ 81 FR 74750 (August 16, 2016).
    \20\ 82 FR 22936 (May 19, 2017).
    \21\ 82 FR 32294 (July 13, 2017).
    \22\ The BART-eligible source is the collection of BART-eligible
units at a stationary source. 40 CFR Appendix Y, II.A.4
    \23\ On September 26, 2017, we published a proposed rule
amending our July 13, 2017 proposal. This amended proposed rule
proposed a new compliance date of three years from the date the rule
becomes final. See, 82 FR 32294 (July 13, 2017) and 82 FR 44753
(September 26, 2017).
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    We are finalizing our approval of the Louisiana Regional Haze SIP
as we have found it to meet the applicable provisions of the Act and
EPA regulations and it is consistent with EPA guidance. We find that
the core requirements for regional haze SIPs found in 40 CFR 51.308(d)
such as: The requirement to establish reasonable progress goals, the
requirement to determine the baseline and natural visibility
conditions, and the requirement to submit a long-term strategy; the
BART requirements for regional haze visibility impairment with respect
to emissions of visibility impairing pollutants from non-EGUs and EGUs
in 40 CFR 51.308(e); and the requirement for coordination with state
and Federal Land Managers in 51.308(i) are met. This final action
includes, among other things, the approval of the following: The
determination that the emission limits reflected in the AOC between
LDEQ and Phillips 66 meet the BART requirements, the determination that
the sources listed in Tables 1, 2, and 3 below are not subject to BART,
the determination that the sources listed in Table 4 below are subject
to BART, the determination that the emission limits and operating
conditions reflected in the AOC for Mosaic Fertilizer, LLC meet the
BART requirements, the determination that the emission limits and
operating conditions reflected in the AOC for EcoServices, LLC meet the
BART requirements, the determination that emission limits and operating
conditions listed in the AOC for Louisiana Generating, LLC meet the
applicable BART requirements for Big Cajun II, the determination that
the emission limits and operating conditions listed in the AOC for
Cleco meet BART requirements for Cleco Brame Energy Center, and the
determination that the emission limits and operating conditions in the
AOCs for Entergy meet the applicable BART requirements for Waterford,
Willow Glen, Ninemile, Little Gypsy, and Nelson. This final rule
renders the limits and conditions included in the AOCs mentioned above
federally enforceable. We are also finalizing approval of the three-
year compliance date for Nelson Unit 6 in this final rule.\24\
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    \24\ Id.
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    Additionally, this final action fully approves the 2008, 2016, and
the two 2017 SIP revisions as supplemented with respect to Sec.
51.308(e), and addresses all deficiencies identified in our previous
partial disapproval and partial limited approval of the 2008 SIP
submission.\25\
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    \25\ 77 FR 39425 (July 3, 2012).

                                            Table 1--Retired Sources
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              Facility name                          Units                               Parish
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Louisiana Energy and Power Authority      Units 1, 2, 3, and 4         St. Mary/St. Martin.
 Morgan City Steam Plant.                  boilers.
City of Ruston Ruston Electric            Boilers 1, 2, and 3........  Lincoln.
 Generating Plant.
City of Natchitoches Utility Department.  3 boilers..................  Natchitoches.
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                     Table 2--BART-Eligible Sources Screened Out Using Model Plant Analysis
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              Facility name                          Units                               Parish
----------------------------------------------------------------------------------------------------------------
Louisiana Energy and Power Authority      Boilers 1 and 2............  Iberville.
 Plaquemine Steam Plant.

Lafayette Utilities System Louis ``Doc''  Units 1, 2, and 3..........  Lafayette.
 Bonin Electric Generating Station.
Terrebonne Parish Consolidated            Units 15 and 16............  Terrebonne.
 Government Houma Generating Station.
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             Table 3--BART-Eligible Sources Screened Out With Visibility Impact of Less Than 0.5 dv
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              Facility name                          Units                               Parish
----------------------------------------------------------------------------------------------------------------
Cleco Teche.............................  Unit 3.....................  St. Mary.
Entergy Sterlington.....................  Unit 7.....................  Ouachita.
Louisiana Generating (NRG) Big Cajun I..  Units 1 and 2..............  Point Coupee.
Louisiana Generating (NRG) Big Cajun II.  Units 1 and 2..............  Pointe Coupee.
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                                      Table 4--Subject to BART EGU Sources
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                                                           BART determination \1\
         Facility name                 Units       --------------------------------------         Parish
                                                           SO2                 PM
----------------------------------------------------------------------------------------------------------------
Cleco Brame Entergy Center.....  Nesbitt I (Unit    3.0 lb/hr........  37.3 lb/hr.......  Rapides.
                                  1).               0.30 lb/MMBtu....  545 lb/hr........
                                 Rodemacher II
                                  (Unit 2).
Entergy Waterford..............  Units 1, 2, and    Fuel oil with a    Fuel oil with a    St. Charles.
                                  auxiliary boiler.  sulfur content     sulfur content
                                                     of 1% or less.     of 1% or less.
                                                    No additional      No additional
                                                     control.           control.
Entergy Willow Glen............  Units 2, 3, 4, 5,  No additional      No additional      Iberville.
                                  and auxiliary      controls when      controls when
                                  boiler.            burning natural    burning natural
                                                     gas \2\.           gas \2\.
Entergy Ninemile Point.........  Units 4 and 5....  Fuel oil with a    Fuel oil with a    Jefferson.
                                                     sulfur content     sulfur content
                                                     of 0. 0015%.       of 0. 0015%.
Entergy Little Gypsy...........  Units 2, 3, and    Fuel oil with a    Fuel oil with a    St. Charles.
                                  auxiliary boiler.  sulfur content     sulfur content
                                                     of 0.0015%.        of 0. 0015%.
                                                    No additional      No additional
                                                     control.           control.
Entergy Nelson.................  Unit 4 and         No additional      No additional      Calcasieu.
                                  auxiliary boiler.  controls when      controls when
                                 Unit 6...........   burning natural    burning natural
                                                     gas \2\.           gas \2\.
                                                    0.6 lb/MMBtu.....  317.61 lb/hr.....
----------------------------------------------------------------------------------------------------------------
\1\ Numeric BART limits are on a 30-day rolling basis.
\2\ Before fuel oil firing is allowed to take place at the Willow Glen BART units, Nelson Unit 4 or the
  auxiliary boiler, a revised BART determination for that unit 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 received comments from several commenters on our proposed
approval of the BART determinations for EGU facilities,\26\ our
proposed approval of the BART determination for Nelson Unit 6,\27\ and
our proposed approval of LDEQ's revised SIP, which changed the
effective date of the emission limits for Nelson Unit 6.\28\ We did not
receive comments on our proposed approval of the BART determinations
for the four subject to BART non-EGU facilities.\29\ Our response to
the substantive comments are summarized in Section III. We note that we
received a comment letter from Cleco Brame Energy Center on August 2,
2017. This comment letter was received outside of the applicable
comment period.\30\ Additionally, the comments contained in the letter
did not raise any issues with our proposal. They were submitted in
response to issues raised by another commenter in a separate comment
letter.\31\
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    \26\ 82 FR 22936 (May 19, 2017).
    \27\ 82 FR 32294 (July 13, 2017).
    \28\ 82 FR 44753 (September 26, 2017).
    \29\ 81 FR 74750 (October 27, 2016).
    \30\ The comment period closed on June 19, 2017.
    \31\ See August 2, 2017 letter from William Matthews (Cleco
Corporation) to Jennifer Huser (EPA), Document ID EPA-R06-OAR-2017-
0129-003. Cleco submitted its comment letter on August 2, 2017 in
response to a comment letter previously submitted by Earthjustice,
National Parks Conservation Association, and Sierra Club (the
Conservation Organizations) on June 19, 2017. In its letter, Cleco
addressed the concerns raised by the Conservation Organizations in
their letter.
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    We are approving the 2008, 2016, February 2017, and the October
2017 LA RH SIPs (as supplemented by the October 9, 2017 email \32\)
submitted by Louisiana as we have determined that they meet all of the
regional haze SIP requirements, including the BART requirements in
Sec.  51.308(e). We have fully considered all significant comments on
our proposed actions on the four RH SIP revision submittals as
supplemented by the October 9, 2017 email, and have concluded that no
changes are warranted.
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    \32\ Email from Vivian Aucoin (LDEQ) forwarding email from
Richie Corvers (Entergy) detailing the current status of
decommissioning Entergy Michoud Units 2 and 3.
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III. Response to Comments

    We received written comments by the internet and the mail. The full
text of comments received from these commenters is included in the
publicly posted docket associated with this action at
www.regulations.gov. We reviewed all public comments that we received
on the proposed actions. Below, we provide a summary of certain
comments and our responses. First, we provide a summary of the more
significant/relevant modeling related comments with a summary of our
responses. The entirety of the modeling comments and our responses
thereto are contained in a separate document titled the Modeling RTC
document. Second, we provide a summary of all of the relevant technical
comments we received and our responses to these comments. Third, we
provide a

summary below of all of the relevant legal comments and our responses.

A. Modeling

    Comment: Cleco and Entergy assert that their BART-eligible sources
were shown through their initial Comprehensive Air Quality Model with
Extensions (CAMx) modeling analysis not to have significant impacts
above the 0.5 dv threshold and are therefore, not subject to BART.
After EPA's initial review of Entergy and Cleco's CAMx modeling \33\
provided to EPA and LDEQ before LDEQ proposed its SIP, EPA provided
additional guidance to LDEQ and Entergy/Cleco/Trinity. Even though the
commenters disagreed with the technical basis of EPA's requests for
revised modeling, in response to this guidance, revised modeling
analyses \34\ were completed for these sources and the commenters
maintain that based on their revised modeling analyses, these units are
not subject to BART. The commenters state that EPA's CAMx and CALPUFF
modeling, which show that these sources are subject to BART, contain
significant defects, making the modeling far less reliable than the
initial CAMx modeling analyses submitted by Cleco and Entergy. They
assert that CAMx modeling is clearly superior to CALPUFF modeling when
there are relatively long distances between the modeled source and the
Class I areas. The commenters state that the CAMx modeling protocol
followed in their initial modeling analysis was proper, minimizes
potential bias and shows that the BART-eligible units at Cleco Brame
Energy Center and the Entergy Nelson, Waterford, Willow Glen, Ninemile
Point, and Little Gypsy facilities have insignificant impacts at all
Class I areas. Therefore, the commenters believe that all of these
units should have been characterized as not subject to BART by LDEQ and
EPA.
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    \33\ See Updated BART Applicability Screening Analysis Prepared
by Trinity Consultants, November 9, 2015. Available in Appendix D of
the 2017 Louisiana Regional Haze SIP.
    \34\ See October 10, 2016 Letter from Cleco Corporation to
Vivian Aucoin and Vennetta Hayes, LDEQ, RE: Cleco Corporation
Louisiana BART CAMx Modeling, included in Appendix B of the 2017
Louisiana Regional Haze SIP submittal; CAMx Modeling Report,
prepared for Entergy Services by Trinity Consultants, Inc. and All 4
Inc, October 14, 2016, included in Appendix D of the 2017 Louisiana
Regional Haze SIP submittal.
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    The commenters state that EPA should reconsider its evaluation of
the submitted CAMx modeling, as the EPA's concerns about the accuracy
of these modeling results are unfounded. Commenters provide additional
specific comments addressing technical issues related to EPA's
assessment of Cleco and Entergy's CAMx modeling analyses, refutes EPA's
criticism in the proposed rule and TSD of this modeling, as well as
comments concerning problems with EPA's own CAMx modeling methodology
and performance evaluation. These specific comments also address
deficiencies with the CALPUFF modeling system, including limitations on
modeling at distances greater than 300km and the ability of the CALPUFF
model to assess visibility impacts.
    Response: We disagree with the comments, and we agree with LDEQ
that the CALPUFF modeling following the reviewed protocol is an
appropriate tool for evaluating visibility impacts and benefits to
inform a BART determination. Relying on the CALPUFF modeling results
submitted by Cleco \35\ and Entergy,\36\ as well as EPA's review and
additional CALPUFF modeling,\37\ included in the February 2017 and
October 2017 SIP revisions, LDEQ concluded that the BART-eligible
sources at Cleco Brame Energy Center and the Entergy Nelson, Waterford,
Willow Glen, Ninemile Point, and Little Gypsy facilities have
visibility impacts greater than 0.5 dv and are therefore subject to
BART. We are finalizing our approval of LDEQ's subject to BART
determinations for these EGU sources. Accordingly, LDEQ performed the
required five-factor analyses and made BART determinations for these
subject to BART sources. We agree with the commenters that CAMx
provides a scientifically defendable platform for assessing visibility
impacts over a wide range of source-to-receptor distances and is also
more suited than some other modeling approaches for evaluating the
impacts of SO2, NOX, VOC, and PM emissions, as it
has a more robust chemistry mechanism. As we discuss below, we utilized
CAMx to provide additional data and analysis for some large emission
sources. However, CALPUFF is an appropriate tool for BART evaluations
and remains the recommended model for BART.\38\ We are confident that
CALPUFF distinguishes the relative contributions from sources such that
the differences in source configurations, sizes, emission rates, and
visibility impacts are well-reflected in the model results. We address
specific comments concerning limitations on modeling distance and the
ability of CALPUFF to assess visibility impacts from these sources in
detail in the Modeling RTC. As discussed in the Modeling RTC document,
EPA and FLM representatives have utilized CALPUFF results in a number
of different situations when the range was between 300-450 km or
more.\39\ We note that the Entergy Waterford, Willow Glen, Ninemile
Point, and Little Gypsy facilities are located 217 km or less from the
nearest Class I area. Therefore, the commenters concern regarding the
use of CALPUFF modeling for distances greater than 300km is not
relevant to the subject-to-BART determinations for these sources.
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    \35\ CALPUFF Modeling Report BART Applicability Screening
Analysis: Cleco Corporation, Brame Energy Center, Teche Power
Station, Prepared by Trinity Consultants, July 30, 2015. Available
in Appendix B of the 2017 Louisiana Regional Haze SIP submittal.
    \36\ Updated BART Applicability Screening Analysis Prepared by
Trinity Consultants, November 9, 2015. Available in Appendix D of
the 2017 Louisiana Regional Haze SIP submittal.
    \37\ DRAFT Technical Support Document for Louisiana Regional
Haze: CALPUFF Best Available Retrofit Technology Modeling Review,
April 2017 (revised May 2017 to include Entergy Nelson). Available
in Appendix F of the 2017 Louisiana Regional Haze SIP submittal. EPA
performed additional modeling for Entergy Nelson to address
identified errors in some emission estimates.
    \38\ 82 FR 5182, 5196 (Jan. 17, 2017). ``As detailed in the
preamble of the proposed rule, it is important to note that the
EPA's final action to remove CALPUFF as a preferred appendix A model
in this Guideline does not affect its use under the FLM's guidance
regarding AQRV assessments (FLAG 2010) nor any previous use of this
model as part of regulatory modeling applications required under the
CAA. Similarly, this final action does not affect the EPA's
recommendation [See 70 FR 39104, 39122-23 (July 6, 2005)] that
states use CALPUFF to determine the applicability and level of best
available retrofit technology in regional haze implementation
plans.''
    \39\ For example, South Dakota used CALPUFF for Big Stone's BART
determination, including its impact on multiple Class I areas
further than 400 km away, including Isle Royale, which is more than
600 km away. See 76 FR 76656. Nebraska relied on CALPUFF modeling to
evaluate whether numerous power plants were subject to BART where
the ``Class I areas [were] located at distances of 300 to 600
kilometers or more from'' the sources. See Best Available Retrofit
Technology Dispersion Modeling Protocol for Selected Nebraska
Utilities, p. 3. EPA Docket ID No. EPA-R07-OAR-2012-0158-0008. In
our 2014 proposed action and the 2016 final action on Texas regional
haze we approved the use of CALPUFF to screen BART-eligible non-EGU
sources at distances of 400 to 614 km for some sources. 79 FR 74818
(Dec. 16, 2014), 81 FR 296 (Jan. 5, 2016).
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    As we noted in our May 19, 2017 proposed action and CALPUFF
Modeling TSD,\40\ the CALPUFF model is typically used for distances
less than 300-400 km. Some of the BART-eligible sources in Louisiana
are far away from Class I areas, yet have high enough emissions that
they may significantly impact visibility at Class I areas in Louisiana
and surrounding states. We performed additional modeling using CAMx to
evaluate the visibility impacts and benefits of controls for the
Entergy Nelson, Cleco Brame, and Big Cajun II

sources to address possible concerns with utilizing CALPUFF to assess
visibility impacts at Class I areas located far from these large
emission sources. LDEQ included this modeling in Appendix F of the
October 26, 2017 SIP revision.\41\ Our CAMx modeling supports the
determination made by LDEQ that Entergy Nelson and Cleco Brame cause or
contribute to visibility impairment at nearby Class I areas and are
therefore subject to BART. Entergy Nelson has a maximum modeled
impact[thinsp]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. Similarly,
Cleco Brame has a maximum modeled impact of 2.833 dv at Caney Creek,
with 30 days out of a maximum 365 days modeled exceeding 0.5 dv and 10
days exceeding 1.0 dv. We disagree with the commenters and find that
our CAMx modeling is consistent with the BART Guidelines and a previous
modeling protocol we developed for the use of CAMx modeling for BART
screening for sources in Texas. 42 43 We respond to specific
comments concerning our CAMx modeling, including model inputs, model
performance, our modeling protocol and the use of direct model results
in detail in the Modeling RTC document.
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    \40\ 82 FR 32294 (May 19, 2017).
    \41\ DRAFT Technical Support Document for Louisiana Regional
Haze: CAMx Best Available Retrofit Technology Modeling April 2017
(Revised May 2017 to include Entergy Nelson). Available in Appendix
F of the 2017 Louisiana Regional Haze SIP submittal.
    \42\ 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. Due to the distances between sources and
Class I areas and the number of sources, Texas worked with EPA and
FLM representatives to develop a modeling protocol to conduct BART
screening of sources using CAMx photochemical modeling. Texas was
the only state that screened sources using CAMx and had a protocol
developed for 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.
    \43\ 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).
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    As we discuss in detail in our May 19, 2017 proposed action and
CAMx Modeling TSD,\44\ the initial CAMx modeling, as well as the
revised modeling submitted by Cleco and Entergy \45\ was not conducted
in accordance with the BART Guidelines and the previous modeling
protocol developed for the use of CAMx modeling for BART screening for
sources in Texas and does not properly assess the maximum baseline
impacts. We disagree with the commenters and consider this CAMx
modeling in the February 2017 LA RH SIP, Appendices B and D, to be
invalid for supporting any determination of visibility impacts below
0.5 dv. As discussed in the CAMx Modeling TSD and in our Preliminary
Review Response letter to Entergy and Cleco,\46\ the initial modeling
deviated from the BART guidelines because it did not utilize emissions
representative of maximum 24-hr actual emissions from the baseline
period, did not evaluate the maximum modeled impact for all days, and
did not calculate the deciview visibility impact based on a natural
visibility background approach. We also review the revised modeling in
detail in the CAMx Modeling TSD, identify a number of short comings in
the revised approach, and conclude that it does not properly assess the
maximum baseline impacts and is inconsistent with the BART Guidelines.
We respond to specific comments concerning the CAMx modeling analyses
developed by Trinity Consultants for Cleco and Entergy included in the
February 2017 LA RH SIP at Appendices B and D in detail in the Modeling
RTC.
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    \44\ 82 FR 32294, (May 19, 2017).
    \45\ February 10, 2017 LA RH SIP, Appendices B (Cleco) and D
(Entergy).
    \46\ Technical Support Document for EPA's Proposed Action on the
Louisiana Regional Haze State Implementation Plan, April 2017.
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B. NRG Big Cajun II

    Comment: NRG stated that it supports EPA's proposed approval of
Louisiana's SIP revision, which determined that the Big Cajun II units
are not subject to BART. NRG stated that Big Cajun II is not subject to
BART, but even if it were, no further controls would be needed because
the compliance actions NRG has taken for Mercury and Air Toxics
Standards (MATS) and a consent decree,\47\ including installation of
the existing dry sorbent injection (DSI) system, would be sufficient to
meet BART. NRG asserted that, if the requirements set forth in the
Consent Decree between Louisiana Generating \48\ and EPA do not satisfy
BART, Louisiana Generating's five-factor analysis, which used a
baseline based on operation of the existing DSI and represents a
realistic depiction of anticipated annual emissions, indicates that no
further controls are cost-effective and Big Cajun II's current
configuration and emission controls satisfies BART.
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    \47\ The Consent Decree was agreed to and entered in U.S. of
America and Louisiana Department of Environmental Quality vs.
Louisiana Generating LLC, Civil Action No. 09-100-JJB-DLD (M. D.
La.). Among other things, the CD requires Louisiana Generating to
refuel Big Cajun II Unit 2 to natural gas, and install and
continuously operate dry sorbent injection (DSI) at Big Cajun II
Unit 1 while maintaining a 30-day rolling average SO2
emission rate of no greater than 0.380 lb/MMBtu by no later than
April 15, 2015. The CD also requires Louisiana Generating to retire,
refuel, repower, or retrofit Big Cajun II Unit 1 by no later than
April 1, 2025.
    \48\ NRG is the corporate entity that owns Louisiana Generating
(LA Gen), which operates two plants in Louisiana, Big Cajun I and
Big Cajun II.
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    Response: We agree that Big Cajun II is not subject to BART. Prior
to the submittal of the February 2017 Regional Haze SIP, the LDEQ and
Louisiana Generating entered into an AOC that made the existing control
requirements and maximum daily emission limits permanent and
enforceable for BART. The AOC is included in Louisiana's February 2017
SIP revision. The modeling included in the February 10, 2017 SIP
submittal (Appendix C) demonstrates that, with these existing controls
and enforceable emission limits, Big Cajun II has modeled visibility
impacts less than 0.5 dv at all impacted Class I areas, and therefore
the facility is not subject to BART. We are finalizing our approval of
Louisiana's determination in the SIP that the source is not subject to
BART. Because the source was determined to not be subject to BART, LDEQ
and EPA have made no determination of what controls, if any, would be
necessary to satisfy BART had the source not screened out.

C. Cleco Brame Energy Center

    Comment: Cleco stated that it disagrees with the EPA that there is
uncertainty in the cost-effectiveness of the enhanced DSI system for
the Rodemacher 2 unit. Cleco stated that cost-effectiveness is
calculated by adding annual operation and maintenance costs to the
annualized capital cost of an option and then dividing by the reduction
in annual emissions from a baseline period. Cleco asserted that, as the
EPA acknowledged in its proposal, there are no capital costs associated
with upgrading to an enhanced DSI system at Rodemacher 2. Rather, the
only costs that Cleco will incur relate to additional reagent and
associated waste disposal. Cleco stated that the cost of reagent that
the company used in its five-factor analysis was based on actual
contracts (currently in place) between the reagent supplier and Cleco.
In addition, Cleco determined the reduction in emissions from the
baseline period during actual unit testing. Therefore, Cleco believes
that there is a high degree of certainty that

the cost-effectiveness value for an enhanced DSI system is $967/ton.
    Cleco also disagrees with the EPA that there is ``uncertainty''
with respect to the cost-effectiveness estimates for the dry scrubbing
(Spray Dry Absorption or SDA) and wet scrubbing (wet Flue Gas
Desulfurization, or wet FGD) options. The estimates were prepared for
Cleco by the engineering firm Sargent & Lundy (S&L). S&L is a full-
service engineering consulting firm providing expertise in all areas of
power plant engineering and design. S&L has considerable experience
with the federal and state environmental regulations affecting power
plant operations, as well as the specification, evaluation selection,
and implementation of emission control technologies for both gas and
coal-fueled utility power facilities, including extensive experience
with various FGD technologies. For example, since 2000, S&L has
provided, or is currently providing, engineering services for the
implementation of over 40 wet FGD projects, 30 dry FGD projects, and 25
DSI projects, all of which are technologies that were analyzed as part
of the Five-Factor Analysis. As such, S&L is qualified to develop
capital and O&M cost estimates for these control analyses.
    Cost estimates for the Rodemacher 2 unit were prepared in
accordance with the BART Guidelines and the methodology described in
EPA's Control Cost Manual and represent study-level cost estimates.
Capital costs for major equipment were developed using equipment costs
for similarly sized units (adjusted for actual equipment sizing), site-
specific balance-of plant (BOP) project-specific indirect cost factors.
Where possible, default factors from EPA's Control Cost Manual were
used to calculate indirect costs.
    The capital cost estimates were provided to LDEQ and EPA for both
the wet FGD and SDA options identifying the major cost categories,
including civil work, concrete, steel, mechanical equipment, material
handling, electrical, piping, controls and instrumentation. In
addition, detailed cost effectiveness worksheets were provided to LDEQ
and EPA identifying the variable O&M costs (e.g., reagent, waste
disposal, auxiliary power and water), indirect operating costs (e.g.,
property taxes, insurance, and administrative services) and fixed O&M
costs (e.g., operating personnel, maintenance material and labor) for
both the SDA and wet FGD options. The indirect and fixed operating
costs were based on factors provided in EPA's Control Cost Manual.
    Cleco, however, agrees with EPA that the Total Capital Cost figure
for the SDA option should be $378,318,000. The capital cost for the
fabric filter and associated auxiliaries were inadvertently included
twice in the Total Capital Cost figure line item. As such, the cost
effectiveness for the SDA option should be $6,893/ton, not $8,589/ton.
See attachment Cleco RPS2 S02 Worksheets_2010-2014 Baseline--Rev I.
Regardless, the cost-effectiveness of the SDA and wet FGD options are
significantly higher in comparison to the enhanced DSI option with
minimal incremental visibility improvement. Cleco nevertheless agrees
with LDEQ and EPA that an enhanced DSI system meets BART for the
Rodemacher 2 unit.
    Response: We agree that the cost effectiveness figures presented in
Cleco's Five Factor Analysis included in the February 2017 LA RH SIP,
Appendix B, are reasonable, as we stated in our April 2017 Technical
Support Document (April 2017 TSD).\49\ ``However, because DSI and a
fabric filter baghouse are already installed and operational, the cost-
effectiveness of Cleco's enhanced DSI is based only on the cost of the
additional reagent and no additional capital costs are involved.
Consequently, we believe that the uncertainty of Cleco's enhanced DSI
cost-effectiveness figures is low and that Cleco's estimated cost-
effectiveness of $967/ton is reasonable.'' \50\
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    \49\ Technical Support Document for EPA's Proposed Action on the
Louisiana Regional Haze State Implementation Plan, April 2017.
    \50\ Id. at 19.
---------------------------------------------------------------------------

    We agree with Cleco's correction to the capital costs provided for
SDA, and that the total capital cost figure based on Cleco's cost
estimate should have been $378,318,000. The estimated cost
effectiveness for SDA in their analysis is $6,893/ton, rather than
$8,589/ton as stated in the Cleco cost analysis.\51\
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    \51\ See Appendix B of the February 2017 LA RH SIP.
---------------------------------------------------------------------------

    As discussed in the April 2017 TSD, Cleco did not supply complete
documentation for its cost analysis for SDA and wet FGD for Rodemacher
2, including details to support total direct cost and total capital
cost figures. Based on our experience reviewing and conducting control
cost analyses for many other similar types of facilities, Cleco's
estimates appear high and without complete documentation, some
uncertainty exists with respect to Cleco's cost-effectiveness estimates
for SDA and wet FGD--$6,893/ton and $5,580/ton, respectively. For
example, our estimated cost-effectiveness for similar equipment at
Nelson Unit 6 is approximately $3000/ton.
    We noted, however, that because DSI and a fabric filter baghouse
are already installed and operational, the cost-effectiveness of
Cleco's enhanced DSI is based only on the cost of the additional
reagent and no additional capital costs are involved. In contrast to
enhanced DSI, SDA and wet FGD, require the installation of controls and
significant capital costs. We recognize the low cost effectiveness
value of enhanced DSI. We also recognize the potentially high
incremental costs of obtaining 0.1-0.2 dv of visibility improvement
through SDA or wet FGD. Therefore, we are finalizing our approval of
LDEQ's conclusion that enhanced DSI is SO2 BART for the
Rodemacher 2, with a SO2 emission limit of 0.30 lbs/MMBtu on
a 30 day rolling basis.
    Comment: EPA's proposed determination [for Cleco's Brame Unit 2
(Rodemacher 2)] that enhanced DSI constitutes BART due to it being more
cost-effective than FGD or scrubber given the small amount of
additional visibility improvement that would be achieved with FGD or
SDA is incorrect. EPA admitted it did not know the cost of scrubbers
and therefore could not make the determination that scrubbers were not
cost effective. Additionally, EPA recognized in its proposal that the
costs submitted by Cleco were likely too high. EPA provided no
discussion concerning the range of cost-effectiveness values for wet
FGD that the agency would deem sufficient to justify the incremental
visibility improvement relative to enhanced DSI. Nothing in the
guidance, statute, or federal rules indicates that incremental costs
should be dispositive in a BART determination. EPA must correct the
State's mistakes and provide an accurate estimate of the costs and
cost-effectiveness of controls, including enhanced DSI, dry FGD, and
wet FGD.
    Had EPA or Louisiana developed an accurate cost analysis, it is
clear that either a wet or dry FGD at Rodemacher 2 would be well within
the range of controls that EPA has previously determined are cost
effective. First, with respect to dry FGD systems, it does not appear
that Louisiana or EPA evaluated accurate removal efficiencies of
various dry FGD systems, especially with the low sulfur coal that is
used. SDAs can achieve emission rates lower than 0.06 lb/MMBtu and
SO2 removal efficiencies greater than 95% control.\52\
Indeed,

Louisiana failed entirely to evaluate dry FGD systems, such as
circulating dry scrubbers (CDS) that are commonly used in the industry
and vastly understated the removal efficiencies associated with those
controls. The Alstom Novel Integrated Desulfurization system
(NIDTM), has been selected as the most cost effective
scrubber option when compared to other technologies in several recent
evaluations. Second, with respect to the dry FGD systems that the State
did evaluate, it significantly overstated the costs of such control
technologies. Together, these errors significantly overstated the cost-
effectiveness of dry FGD systems. When those errors are corrected the
cost-effectiveness of dry FGD control technology is well within the
range of costs that EPA has previously found reasonable.\53\ SDA at a
controlled emission rate of 0.06 lb/MMBtu is estimated to be $2,908/
ton. SDA or NIDTM CDS is estimated to be $2,808/ton with a
controlled emission rate of 0.04 lb/MMBtu.
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    \52\ For example, the Newmont Nevada power plant (aka TS Power
Plant), equipped with a dry lime FGD system, has achieved an annual
average SO2 rate of 0.034 lb/MMBtu over 2009 to 2016. The
Wygen II power plant is also equipped with a dry lime scrubber and
burns low sulfur coal, and is achieving annual average
SO2 rates of 0.048 lb/MMBtu. The Dry Fork Station which
began operation in 2011 and is equipped with a dry lime scrubber is
achieving an annual average SO2 rate of 0.050 lb/MMBtu.
See Technical Support Document to Comments of Conservation
Organizations, Prepared by Victoria R. Stamper, June 18, 2017.
    \53\ BART controls have been approved that have an average cost-
effectiveness of more than $5,500 per ton. See 77 FR 31,692, 31,711
(May 29, 2012) and 77 FR 61478, 61506 (Oct. 9, 2012) (requiring
SO2 BART controls with an average cost-effectiveness of
$5,587, $5,583, and $5,583 for the Kanoelehua, Puna, and Shipman
power plants). Other final BART determinations have been only
slightly less expensive than the costs here. See, e.g., 77 FR 18052,
18082, 18084, 18087 (Mar. 26, 2012) (approval of Colorado's SIP) and
77 FR 76871 (Dec. 31, 2012) (requiring NOX BART controls
with an average cost-effectiveness of $4,887 for Craig Unit 3).
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    These supplemental cost analyses, using the same IPM cost
spreadsheets used by EPA in its proposed Texas BART analysis,\54\
demonstrate that Louisiana's cost analyses for a dry FGD system are
greatly overstated.
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    \54\ 82 FR 912 (January 4, 2017).
---------------------------------------------------------------------------

    Louisiana's cost calculations for wet FGD controls at Rodemacher 2
are also erroneous. Contrary to Louisiana's evaluation, wet FGDs can
achieve much lower SO2 emission rates than the 0.04 lb/MMBtu
assumed by the State. Indeed, coupled with low sulfur Powder River
Basin coal, new wet FGD scrubbers can achieve emission reductions
greater than 95%, and are capable of achieving SO2 emission
rates of 0.02 lb/MMBtu. Even assuming a 0.04 lb/MMBtu emission rate, an
accurate cost effectiveness evaluation demonstrates that a wet FGD
system could be installed for $2,947/ton of SO2 removed,
which is well within the range of costs that EPA has found reasonable--
most recently in the agency's proposed BART determinations for Texas.
Moreover, BART controls have been approved that would lead to equal, or
less, visibility improvement than achievable with wet or dry scrubbers
at Rodemacher 2.
    The commenter states that their supplemental cost analyses of
either wet FGD or dry FGD at Brame Unit 2 (Rodemacher 2) show that the
costs of either a wet or a dry FGD system are very reasonable, in that
other similar sources have had to bear similar costs for pollution
control to address BART and regional haze requirements. The incremental
costs of installing a dry FGD or a wet FGD system at Brame Unit 2
compared to DSI plus a baghouse are very reasonable and thus should not
be the basis for rejecting a dry or wet FGD system at Brame Unit 2.
Considering the additional SO2 reductions and improved
visibility benefits of installing the more effective controls of a dry
or wet scrubber compared to DSI, EPA should have based its
SO2 BART determination on either wet or dry FGD for Brame
Unit 2.
    Response: We agree with the comment that in some cases SDA and wet
FGD may achieve lower emission rates than those evaluated. We evaluated
the control capabilities of SDA and wet FGD in our action on Oklahoma
BART.\55\ There we determined that reduction efficiencies of up to 95%
or as low as 0.06 lb/MMBtu SO2 for dry scrubbers and 97%-98%
removal efficiency or an outlet SO2 of 0.04 lb/MMBtu for wet
scrubbers are appropriate levels for the BART evaluation for units when
burning low sulfur coals.\56\ These limits are a reasonable estimate of
potential control and we have consistently used these emission limits
in our evaluation of controls for similar units in Texas and
Arkansas.\57\ We disagree with the comment that the analysis in the
February 2017 SIP is deficient because CDS was not evaluated. CDS is a
variation on SDA with similar costs and reduction efficiency as the
more widely used SDA design. As the commenters note, CDS annual costs
are estimated to only be about 1-2% lower than the annual costs of an
SDA.
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    \55\ 76 FR 16168 (March 22, 2011); 76 FR 81728 (Dec. 28, 2011).
    \56\ See Appendix C to the Oklahoma TSD, available at
regulations.gov, Document ID: EPA-R06-OAR-2010-0190-0018.
    \57\ 82 FR 912 (January 4, 2017), 80 FR 18943 (April 8, 2015).
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    We disagree with the comment concerning consideration of
incremental costs. The BART Guidelines state that while the average
costs (total annual cost/total annual emission reductions) for two
control options each may be deemed to be reasonable, the incremental
cost of the additional emission reductions to be achieved by option 2
may be very great. In such an instance, it may be inappropriate to
choose option 2, based on its high incremental costs, even though its
average cost may be considered reasonable.\58\ LDEQ reviewed all the
available information and determined that the amount of visibility
benefit achieved from SDA or wet FGD over enhanced DSI was not large
enough to justify the additional cost of these controls at Rodemacher
2. EPA's regulations under the CAA ``do not require uniformity between
. . . actions in all circumstances and instead `allow for some
variation' in actions taken in different regions.'' 81 FR at 326
(quoting Amendments to Regional Consistency Requirements, 80 FR 50250,
at 50258 (Aug. 19, 2015)). Some variation is to be expected because SIP
actions are highly fact-dependent. The state weighed the factors
considering all available information, in the February 10, 2017 SIP,
and concluded that enhanced DSI is BART for this unit. The CAA allows
EPA to review all the information in the SIP submittal and any other
publicly available information to make its decision whether it agrees
the state's determination meets the applicable requirements. After
reviewing the relevant information, we determined that the State's SIP
meets the requirements of the Act and the applicable regulations and
guidance.
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    \58\ 40 CFR part 51, Appendix Y, IV(D)(e)(5).
---------------------------------------------------------------------------

    In our review of the cost estimates, we noted a lack of
documentation and uncertainty in the Cleco cost-estimates for SDA and
wet FGD. We noted, however, that because DSI and a fabric filter
baghouse are already installed and operational, the cost-effectiveness
of Cleco's enhanced DSI is based only on the cost of the additional
reagent and no additional capital costs are involved. The cost-
effectiveness of enhanced DSI was estimated to be $967/ton.\59\ In
contrast to enhanced DSI, SDA and wet FGD require the installation of
controls and significant capital costs. Cleco's cost-effectiveness
estimates for SDA and wet FGD are $6,893/ton and $5,580/ton,
respectively, while the commenter's estimate the costs of SDA,
NIDTM CDS and wet FGD to be approximately $2,800/ton or
greater.\60\ When the

already sunk capital costs of the existing DSI system are removed, the
incremental annual cost of enhanced DSI is estimated to be only
$1,695,300/yr. Even accounting for the potential issues in Cleco's SDA
and wet FGD cost analyses and considering the commenter's cost
estimates, we are cognizant of the enhanced DSI's low cost-
effectiveness, and the incremental costs of obtaining the additional
0.1-0.2 dv of visibility improvement that can be achieved by SDA, CDS
or wet FGD over enhanced DSI are high. Therefore, we are finalizing our
approval of LDEQ's conclusion that the amount of visibility benefit
achieved from SDA or wet FGD over enhanced DSI was not large enough to
justify the additional cost of these controls and enhanced DSI is
SO2 BART for the Rodemacher 2, with a SO2
emission limit of 0.30 lbs/MMBtu on a 30 day rolling basis.
---------------------------------------------------------------------------

    \59\ LA RH SIP (February 2017), Appendix B.
    \60\ Technical Support Document to Comments of Conservation
Organizations (Stamper Report), Prepared By: Vivian R Stamper (June
18, 2017).
---------------------------------------------------------------------------

    Comment: With respect to the analysis for the Rodemacher 2 unit,
EPA stated the following concerning enhanced DSI:

    In considering enhanced DSI, Cleco relied upon on-site testing
it had conducted to determine the performance potential of an
enhanced DSI system. The testing was conducted to evaluate the
effectiveness of the DSI system to control hydrochloric acid for
compliance with the Mercury and Air Toxics Standards (MATS), but the
continuous emissions monitor system (CEMS) was operating and
capturing SO2 emissions data during the test, which
provided the necessary information to determine the control
efficiency of DSI and enhanced DSI for SO2.

    82 FR 22936. On page 19 of the related TSD, EPA further stated:

    Cleco also did not provide the DSI testing information, which
creates a degree of uncertainty concerning the potential control
level of its current DSI system and the enhanced DSI system it
reviews. Another concern was that the DSI testing that Cleco relied
on was not intended to evaluate DSI for SO2 control
efficiency, which caused some uncertainty concerning the potential
control level of DSI and enhanced DSI.

    Cleco disagrees that there is a ``degree of uncertainty''
concerning the potential SO2 control level of the current
DSI system or the enhanced DSI system. Although the testing conducted
was based on operating the system to determine removal of hydrogen
chloride (HCl), the Rodemacher 2 unit operated a SO2
continuous emission monitoring system (CEMS) that gathered valid, real-
time SO2 emissions data that demonstrated the achievable
reductions. The data gathered by the SO2 CEMS is the same
data submitted to EPA's Air Markets Program Data on a quarterly basis.
Cleco, therefore, does not believe that a degree of uncertainty exists
with respect to the SO2 control level.
    As stated in the BART Five-Factor Analysis submitted to LDEQ,\61\
two performance tests were conducted at very high injection rates to
determine the removal that could be achieved while operating the DSI
system at close to the maximum design injection rate. The first test
was performed at 12,000 lb/hr, which showed an average removal of 66%
SO2 and the second test was conducted at 4,000 lb/hr, which
showed an average removal of 63% SO2. Both tests were
conducted at injection rates significantly higher than the current DSI
rate of 1,500 lb/hr. Although the system is designed to inject up to
17,800 lb/hr of Trona, there would be close to no benefit in additional
SO2 reduction since increasing the injection rate by 300%
(from 4,000 lb/hr to 12,000 lb/hr) only provided an additional 3%
SO2 reduction on average. Based on the foregoing, Cleco
believes there is a high degree of certainty regarding the control
levels achievable for the current DSI and enhanced DSI systems.
---------------------------------------------------------------------------

    \61\ LA RH SIP (February 2017), Appendix B.
---------------------------------------------------------------------------

    We also received comments from environmental groups \62\ stating
that Cleco evaluated two levels of control with DSI: DSI to meet an
SO2 limit of 0.41 lb/MMBtu and ``enhanced DSI'' to meet an
SO2 limit of 0.30 lb/MMBtu. These proposed limits were based
on testing done on-site that Cleco conducted to determine the
performance potential of enhanced DSI. However, Cleco did not submit
the testing as part of the record for the BART determination. Further,
the testing was not done to evaluate SO2 removal efficiency
and was instead done to optimize hydrogen chloride control efficiency.
Presumably, Cleco did not concurrently evaluate uncontrolled
SO2 emissions, and thus the accuracy of the assumed
SO2 removal efficiencies with DSI and enhanced DSI of 39%
and 63% is questionable.
---------------------------------------------------------------------------

    \62\ See Stamper Report (attached as Technical Support Document
to Conservation Organizations June 18, 2017 comment letter).
---------------------------------------------------------------------------

    Further, Brame Unit 2 (Rodemacher 2) is already achieving the
assumed ``enhanced DSI'' level of control of 0.30 lb/MMBtu
SO2 rate with the current DSI operations which are being
implemented to meet the MATS hydrogen chloride limit. Based on data in
EPA's Air Markets Program Database, the average monthly SO2
emission rate at Brame Unit 2 was 0.26 lb/MMBtu from June 2015 through
the first quarter of 2017. While there have been a few months with
monthly SO2 emission rates in excess of 0.30 lb/MMBtu, the
large majority of monthly SO2 emission rates at Brame Unit 2
have been at or well below 0.30 lb/MMBtu. Thus, there does not seem to
be much if any enhancement needed to achieve 0.30 lb/MMBtu with DSI and
a baghouse. Cleco should therefore have assumed a 0.30 lb/MMBtu
SO2 limit, or even lower, as achievable with the currently
operated DSI and baghouse. Given that the unit is already achieving a
0.30 lb/MMBtu level, it does appear likely any lower SO2
emission rates could be achieved with DSI ``enhancements.''
    Response: We agree with the commenter that the available testing
data demonstrates that increasing the injection rate beyond 4,000 lb/hr
(63% removal) results in minimal increased removal efficiency. As we
discussed in our TSD and identified by the commenter above, because the
DSI testing was not performed to examine optimization of SO2
removal and Cleco did not provide sufficient detail with regard to how
the testing was conducted, we noted ``some uncertainty'' in the
potential control levels for DSI and enhanced DSI. For example, it is
unclear if the testing evaluated a range of fuel sulfur content or heat
input rates. We therefore reviewed available emissions data from the
unit from when the DSI became operational in March 2015 through the end
of 2016 and found that based on that information \63\ covering a range
of actual operations, as well as the provided testing data, Louisiana's
selection of 0.30 lbs/MMBtu on a rolling 30-day basis for
SO2 is reasonable for an enhanced DSI system on the
Rodemacher 2 unit.
---------------------------------------------------------------------------

    \63\ See Figure 1 and accompanying discussion on page 18 of the
TSD associated with our May 2017 proposed approval.
---------------------------------------------------------------------------

    We agree with the comment that recent emission data from June 2015
through the first quarter of 2017 demonstrates the ability to emit at
or below 0.3 lb/MMBtu on a monthly basis. However, as also noted by the
commenter, monthly emission rates with the current operation of the
existing DSI system have also exceeded 0.3 lb/MMBtu at times during
that same period. For example, the average monthly emission rate in
December 2016 was 0.39 lb/MMBtu. The available testing data
demonstrates that the unit is already equipped to operate the existing
DSI and fabric filter at a range of injection rates, including the
higher injection rates evaluated in the BART analysis, as ``enhanced
DSI.'' In order to achieve the emission rate specified in Louisiana's
BART determination of 0.30 lbs/MMBtu for SO2, made permanent
and enforceable in the AOC, Cleco will

have to operate the existing DSI system at higher injection rates to
maintain future emissions below 0.3 lb/MMBtu on a rolling 30-day basis.

D. Entergy Nelson

    Comment: LDEQ commented that EPA's cost analysis did not alter its
initial conclusion presented in its February 2017 RH SIP submittal that
BART was ``no further control.''
    Response: In its October 2017 Regional Haze SIP submittal, LDEQ
stated that, after a weighing of the five factors and after a review of
both Entergy's and EPA's information, ``BART is the emission limit of
0.6 lbs/MMBtu based on a 30 day rolling average as defined in the AOC .
. . LDEQ believes, at present, that the use of lower sulfur coal
presents the appropriate SO2 control based on consideration
of economics, energy impacts, non-air quality environmental impacts,
and impacts to visibility.'' \64\
---------------------------------------------------------------------------

    \64\ Louisiana Regional Haze SIP, October 2017.
---------------------------------------------------------------------------

    Comment: Entergy supports the proposed limit for Nelson Unit 6 but
disagrees that the Control Cost Manual disallows certain costs such as
escalation during construction and owner's costs.\65\ These are actual
costs that will be incurred during construction and that should have
been included in the costs for each add-on control technology
evaluated. Entergy also disagrees with EPA's reduction in the
contingency factor from 25% to 10%. EPA has provided no justification
for its use of 10% for the contingency factor, over than that it is
``in the middle of the range employed in the Control Cost Manual.''
\66\ The costs that Entergy submitted in its BART Five-Factor Analysis
for Nelson \67\ are a more accurate estimate of the actual costs for
controls at Nelson Unit 6 than the more generic costs that EPA assumed.
However, even accepting EPA's cost calculations, the costs of
installing SO2 controls are too high to constitute BART in
light of the distance of Nelson from the nearest Class I areas and the
minor visibility benefit expected to be achieved by such controls.
Based on an evaluation of the five statutory factors required for a
BART analysis, LDEQ appropriately concluded that low sulfur coal
constitutes SO2 BART for Nelson 6. As Entergy concluded in
the Nelson Five-Factor analysis, ``no visibility improvement can
reasonably be anticipated to result from the installation of
[SO2] controls. Furthermore, the cost of each of the add-on
[SO2] control options for Unit 6 is estimated as $3 billion
or more per dv improvement.'' \68\
---------------------------------------------------------------------------

    \65\ 82 FR at 32298.
    \66\ TSD for EPA's Proposed Action on the Louisiana State
Implementation Plan for the Entergy Nelson Facility, at page 18
(June 2017), Docket No. EPA-R06-OAR-2017-0129-0025.
    \67\ Nelson Five-Factor Analysis.
    \68\ Nelson Five-Factor Analysis, at 4-6.
---------------------------------------------------------------------------

    Response: We disagree with commenters' assertions that Allowance
for Funds Used During Construction (AFUDC) should be incorporated into
our cost analysis, as the practice of incorporating AFUDC is
contradictory to the Cost Control Manual (CCM) methodology.\69\ The
utility industry uses a method known as ``levelized costing'' to
conduct its internal comparisons, which is different from the methods
specified by the CCM. Utilities use ``levelized costing'' to allow them
to recover project costs over a period of several years and, as a
result, realize a reasonable return on their investment. The CCM uses
an approach sometimes referred to as overnight costing, which treats
the costs of a project as if the project were completed ``overnight,''
with no construction period and no interest accrual. Since assets under
construction do not provide service to current customers, utilities
cannot charge the interest and allowed return on equity associated with
these assets to customers while under construction. Under the
``levelized costing'' methodology, AFUDC capitalizes the interest and
return on equity that would accrue over the construction period and
adds them to the rate base when construction is completed and the
assets are used. Although it is included in capital costs, AFUDC
primarily represents a tool for utilities to capture their cost of
borrowing and return on equity during construction periods. AFUDC is
not allowed as a capitalized cost associated with a pollution control
device under CCM's overnight costing methodology and is specifically
disallowed for SCRs (ie., set to zero) in the CCM.\70\ Therefore, in
reviewing other BART determinations, EPA has consistently excluded
AFUDC.\71\ EPA's position regarding exclusion of AFUDC has been upheld
in the United States Ninth Circuit Court of Appeals.\72\
---------------------------------------------------------------------------

    \69\ EPA Air Pollution Control Cost Manual, Sixth Edition, EPA/
452/B-02-001, January 2002 available at http://www.epa.gov/ttncatc1/dir1/c_allchs.pdf.
    \70\ CCM (Tables 1.4 and 2.5 show AFUDC value as zero).
    \71\ See, e.g., 77 FR 20894, 20916-17 (Apr. 6, 2012) (explaining
in support of the North Dakota Regional Haze FIP, ``we maintain that
following the overnight method ensures equitable BART determinations
* * *. ''); 76 FR 52388, 52399-400 (August 22, 2011) (explaining in
the New Mexico Regional Haze FIP that the Manual does not allow
AFUDC)
    \72\ Ariz. ex. rel. Darwin v. U.S. EPA, 815 F,3d 519 (9th Cir.
2016).
---------------------------------------------------------------------------

    In the TSD we discuss Entergy's selection of contingency factor.
There, we state that we are not aware of any characteristics of Nelson
Unit 6 that would present any unusual difficulty distinguishing it from
any other scrubber retrofit, and thus justifying a high estimate for
contingency. The CCM uses contingency values ranging from 5 to 15%,
depending upon the control device in question and the precise nature of
the factors requiring contingency. Entergy has not provided any
additional information to support the use of a contingency factor
outside of this range. The CCM clarifies that a contingency factor
should be reserved (and applied to) only those items that could incur a
reasonable but unanticipated increase but are not directly related to
the demolition, fabrication, and installation of the system. We used a
contingency value of 10% for our analysis and adjustment of Entergy's
costs, which lies in the middle of the range employed in the CCM. We
believe this value is appropriate for mature technologies such as SDA
and wet FGD.\73\
---------------------------------------------------------------------------

    \73\ ``EIA lists 748 SO2 scrubber installations in
operation in 2015. Of these, 296 are listed as being spray type wet
scrubbers, with an additional 42 listed as being tray type wet
scrubbers. An additional 269 are listed as being spray dry absorber
types.'' See pg 8 of Technical Support Document for EPA's Proposed
Action on the Louisiana State Implementation Plan for the Entergy
Nelson Facility, June 2017.
---------------------------------------------------------------------------

    We disagree with the commenter's conclusion that no visibility
improvement can reasonably be anticipated to result from the
installation of SO2 controls and that visibility benefits of
scrubbers cost $3 billion/dv or more. This conclusion and estimate in
Entergy's Nelson Five-Factor analysis, is based on its CAMx modeling
analysis. As we discuss in detail in the CAMx Modeling TSD and in our
Modeling RTC document, we consider this submitted CAMx modeling to be
invalid for supporting any determination of visibility impacts. The
results of Entergy's CALPUFF modeling and EPA's CALPUFF and CAMx
modeling assessing the visibility benefits of controls on this unit are
included in Appendix D and F of the October 2017 LA RH SIP.
    LDEQ reviewed all the available information including the modeling
provided by EPA and determined ``that additional visibility benefits
may be available through the use of FGD.'' The state, however, weighed
the factors considering all available information

contained in the SIP submittal, and concluded that ``the use of lower
sulfur coal presents the appropriate SO2 control based on
consideration of economics, energy impacts, non-air quality
environmental impacts, and impacts to visibility.''
    We also note that we disagree with the use of the dollar per
deciview metric as the only cost effectiveness metric in BART
determinations. We discuss this in detail in our Response to Comments
on our final action on Oklahoma Regional Haze.\74\ Our decision to not
rely on a $/dv metric was reviewed and upheld in by the Tenth
Circuit.\75\
---------------------------------------------------------------------------

    \74\ Response to Technical Comments for Sections E. through H.
of the Federal Register Notice for the Oklahoma Regional Haze and
Visibility Transport Federal Implementation Plan, Docket No. EPA-
R06-OAR-2010-0190, 12/13/2011, pdf 116.
    \75\ Oklahoma v. EPA, 723 F.3d 1201 (10th Cir. 2013).
---------------------------------------------------------------------------

    Comment: The State makes the claim that a scrubber should be
rejected because of the environmental impacts of waste generated by a
scrubber. EPA reached the opposite conclusion, stating that FGD and DSI
``do not present any significant or unusual environmental impacts.''
Moreover, the State ignores that the cost to dispose of scrubber wastes
is included in the cost model for a scrubber, as EPA points out.
Allowing Nelson to emit 0.6 lb/MMBtu of SO2 is a ten-fold
increase in the SO2 emissions rate relative to the 0.06 lb/
MMBtu which a scrubber can achieve.\76\ In the name of considering
environmental impacts, the State chose the option that will lead to the
greatest amount of air pollution. This is not rational decision making,
it runs counter to the statutory mandate for the haze program, and it
is not approvable. We are unaware of any similar state or EPA decision
for a haze SIP. EPA has cited no precedent for approving a State's
selection of the least-effective pollution control on the basis that
more effective pollution controls allegedly are worse for the
environment.
---------------------------------------------------------------------------

    \76\ See Stamper Report at 6-7, 9-10 (attached as Technical
Support Document to Conservation Organizations June 18, 2017 comment
letter).
---------------------------------------------------------------------------

    In addition, the State fails to consider that a dry scrubber
generates far less waste than a wet scrubber. And scrubber wastewater
can be treated with available technologies to dramatically reduce
environmental impacts. See 80 FR 67838 (Nov. 3, 2015). The State's
rejection of a scrubber because of the auxiliary power needed to run a
scrubber is without merit. All of the cost calculations for a scrubber
reviewed by the State--both EPA's and Entergy's--included the energy
cost to run the scrubber. Thus, the energy cost is not a separate
consideration, and is not a separate basis for rejecting a scrubber.
Just as we are aware of no example of EPA approving the rejection of a
scrubber on the basis of scrubber wastes, we are not aware of any EPA
decision approving the rejection of a scrubber because of the auxiliary
power costs.
    Response: We disagree with the commenter's characterization of the
State's consideration of the energy and non-air quality environmental
impacts. The consideration of these impacts is required as part of the
BART determination. LDEQ stated in the October 2017 SIP:

    While additional visibility benefits may be available through
the use of FGD, the lower sulfur coal option results in visibility
benefits at a lower annual cost. In addition, FGD use results in
additional waste due to spent reagent and has some power demands to
run the equipment. LDEQ believes, at present, that the use of lower
sulfur coal presents the appropriate S02 control based on
consideration of economics, energy impacts, non-air quality
environmental impacts, and impacts to visibility.\77\
---------------------------------------------------------------------------

    \77\ October 2017 LA RH SIP submission.

    LDEQ did not reject additional controls solely on the basis of the
non-air quality environmental impacts or energy impacts associated with
those controls. LDEQ identified the impacts associated with each
control level as required, noting the difference between the lower
sulfur coal option and additional add-on controls. LDEQ considered all
of the available information, including EPA's analysis of the
associated impacts and costs, and weighed all the factors in making the
BART determination for Nelson Unit 6.
    Comment: EPA cannot possibly have discharged its obligation to
ensure that the State's BART determination is ``reasonably moored to
the Act's provisions,'' Alaska Dep't of Envtl. Conservation, 540 U.S.
at 485, because EPA claims it was ``unable to verify any of the
company's costs,'' 82 FR at 32298, and could review only the ``general
description of the modeling protocol'' that Entergy used. See Appendix
F, CAMx Modeling TSD at 30. It is axiomatic that EPA cannot approve a
plan where the agency is unable to review and verify the accuracy of
the analysis on which the plan is based. See Motor Vehicle Mfrs. Ass'n
of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)
(``[T]he agency must examine the relevant data and articulate a
satisfactory explanation for its action including a `rational
connection between the facts found and the choice made.' '') (emphasis
added) (quoting Burlington Truck Lines v. United States, 371 U.S. 156,
168 (1962)).
    Response: We disagree with the comment. While we noted in our
proposal that we were unable to verify the company's costs and that we
reviewed a general description of Entergy's modeling protocol, we also
noted that we conducted our own independent cost analysis and CAMx
modeling.\78\ EPA's cost and visibility analyses were included by LDEQ
as a part of its October 2017 SIP submission (Appendix F) and were
included in the information considered by the State in making its BART
determination. LDEQ considered all the information contained in the SIP
submittal, including information submitted by Entergy, EPA's review of
that information, and EPA's additional analyses. As a result, LDEQ had
adequate information upon which to base its determination.\79\
---------------------------------------------------------------------------

    \78\ 82 FR 32294 (August 14, 2017).
    \79\ In response to comments from the Conservation Groups and
inquiries from EPA regarding its cost analysis, Entergy submitted a
Technical Memorandum clarifying the approach used in its cost
analysis. See, Technical Memorandum from Ken Snell, Dated December
6, 2017, Subject: Nelson Unit 6 BART Cost Estimates. Entergy stated
although the specific details in the cost estimate are generated
from proprietary databases, EPA could do a meaningful review of the
cost estimates based on the information included in the submitted
analysis.
---------------------------------------------------------------------------

    Comment: Neither the State nor EPA offered a rational basis for
rejecting a scrubber and EPA did not offer a rational basis for
approving the State's decision. The State did not explain why it
rejected a control with cost-effectiveness and visibility improvement
values which so many other states, and EPA, have found reasonable for
BART determinations. And EPA has not explained how it can approve the
rejection of a scrubber when the cost-effectiveness and visibility
improvement values are within the range that EPA has found reasonable
in so many other haze rulemakings. See generally 42 U.S.C. 7410(k)(3)
(requiring EPA to review each SIP submission to ensure compliance with
the Act), id. sec. 7410(l) (barring EPA approval of a SIP submission
that interferes with any applicable requirement of the Act); Oklahoma
v. EPA, 723 F.3d at 1208-09 (holding that ``the statute mandates that
the EPA must ensure SIPs comply with the statute'' and upholding EPA's
disapproval of the Oklahoma regional haze plan because Oklahoma
``failed to follow the [BART] guidelines'').
    EPA cannot approve the State's plan because EPA concluded that the
analysis the State relied on is riddled with errors; approving such a
plan is

arbitrary and capricious. EPA identified multiple errors in Entergy's
cost and visibility analyses--errors which Entergy and the State
refused to correct, e.g., escalation during construction and owner's
costs, a contingency of 25%, and the inability to verify any of the
company's costs. EPA's submission of its own analyses to the State does
not cure this defect since EPA's analysis is limited by the same lack
of access to data from which the State's analysis suffers.
    Response: As explained in previous responses, EPA reviewed the
State's entire submission, including any attached appendices and
supporting documentation, and any publicly available information as a
whole in determining whether the State's submission is approvable.
Though we identified errors in Entergy's cost and visibility analyses,
EPA conducted its own cost and visibility analyses in accordance with
the applicable regulations and guidelines. EPA's cost and visibility
analyses are part of the SIP submission (Appendix F) and were included
in the information considered by the State in making its BART
determination. We do not believe that our modeling or cost analysis
were limited by the lack of access to data. Our cost estimates rely on
algorithms designed to use readily available data \80\ that provide
reasonable estimates of costs. Furthermore, we had all the data
necessary to make estimates of visibility impairment. We only noted
that there was limited access to documentation to explain the
difference between our cost estimates and those provided by Entergy. As
stated previously, LDEQ considered all the information contained in the
SIP submittal. LDEQ reviewed this information as is evidenced by its
SIP submission. LDEQ states, ``LDEQ has weighed the five factors and
after a review of both Entergy's and EPA's information. . .'' \81\ This
indicates that the State reviewed the information it received from both
Entergy and the EPA, and thus had adequate information upon which to
base its determination. After reviewing the relevant information
contained in LDEQ's SIP, we determined that the State's SIP meets the
requirements of the Act and the applicable regulations and guidance.
---------------------------------------------------------------------------

    \80\ See Cost Analysis in LA RH SIP, October 2017, Appendix F.
    \81\ LA RH SIP Revision Addendum, June 19, 2017, p. 6.
---------------------------------------------------------------------------

    Comment: Though EPA stated that the State ``weighed the statutory
factors,'' \82\ there is no evidence that the State weighed two of the
statutory factors, the remaining useful life of the source and the
existing controls in use at the source. BART must be based on a
consideration of the five factors. The State's BART analysis appears in
a single paragraph, which does not mention two of the five factors: The
``remaining useful life of the source'' and ``existing pollution
controls in use at the source,'' 42 U.S.C. 7491(g)(2). The State's
failure to consider existing pollution controls for SO2
emissions is significant, given that the State treats its BART
determination of low-sulfur coal as requiring Nelson to do something
new, despite evidence that Nelson is already using low-sulfur coal. As
EPA acknowledged, the RS Nelson Plant has already been burning low
sulfur Powder River Basin coal for many years.\83\
---------------------------------------------------------------------------

    \82\ 82 FR at 32300 (July 13, 2017).
    \83\ See EPA Technical Assistance Document at 6-7. See also EPA
TSD at 9.
---------------------------------------------------------------------------

    Similarly, it is important that states consider the ``remaining
useful life'' factor. Cost calculations typically assume that costs
will be recovered over the remaining useful life of a source. As a
result, the remaining useful life is a key variable in cost analyses.
    Whether Entergy or EPA considered these two factors is irrelevant
legally, because the statute requires the State, not the plant owner,
to determine BART. There is no evidence in the SIP that the State
actually considered and relied on any analysis which Entergy or EPA may
have conducted of the remaining useful life and existing pollution
controls in use at the source. In particular, there is no passage in
the State's SIP narrative in which the State discusses how it
considered and weighed the remaining useful life and existing pollution
controls in use at Nelson.\84\ EPA cannot approve a BART determination
which fails to consider two factors, the remaining useful life and the
existing controls in use at the source, which the statute requires
states to consider.
---------------------------------------------------------------------------

    \84\ By contrast, the State expressly considers and weighs
annual costs, visibility improvement, and environmental impacts of
controls. See LA RH SIP, October 2017, p. 6.
---------------------------------------------------------------------------

    Response: As explained in previous responses above, EPA reviews the
final SIP document and any accompanying supplementary information or
appendices that have been submitted by the State. In the October 2017
LA RH SIP at Appendix D, Entergy's BART analysis for Nelson unit 6
includes a description of existing control equipment at the unit \85\
and a statement that remaining useful life does not impact the cost
analysis.\86\ In our analysis, we conducted a five-factor analysis and
addressed both remaining useful life and the existing controls in use
at the source. As discussed in our draft Technical Support Document
provided to LDEQ and included in its October 2017 LA RH SIP, Appendix
F, in evaluating the cost of switching to lower sulfur coal to meet an
emission limit of 0.6 lb/MMBtu, we began by noting that Entergy has
purchased both higher and lower sulfur coals. To account for the
existing use of low sulfur coal, we applied the premium \87\ associated
with purchasing only low sulfur coal to the fraction of higher sulfur
coal purchased. In making their decision, the State evaluated all
available information regarding the remaining useful life of the source
and the existing controls in use at the source. LDEQ submitted the
analyses conducted by EPA and Entergy as appendices to the LA RH SIP.
As such, we took all the information contained in the LA RH SIP into
account in making our determination to approve the State's SIP
submittal.
---------------------------------------------------------------------------

    \85\ See Page 1-1 of Entergy Nelson five-factor BART analysis,
November 9, 2015, revised April 15, 2016. Available in Appendix D of
the LA RH SIP.
    \86\ See Page 4-4 of Entergy Nelson five-factor BART analysis,
November 9, 2015, revised April 15, 2016. Available in Appendix D of
the LA RH SIP.
    \87\ We estimate the low sulfur coal premium based on 2016 coal
purchases for coals above and below 0.6 lb/MMBtu. See Nelson TAD in
Appendix F of the LA RH SIP, October 2016, Section 3.2.9.
---------------------------------------------------------------------------

    Comment: The State unreasonably and unlawfully failed to consider
the cost-effectiveness of controls in violation of the BART Guidelines.
The State stated it selected low-sulfur coal over a scrubber even
though additional visibility benefits may be achievable with the use of
FGD because the lower sulfur coal option results in visibility benefits
at a lower annual cost. The State's BART analysis violates the BART
Guidelines by focusing the cost analysis solely on annual costs and by
failing to consider cost-effectiveness at all. EPA's proposed approval
fails to mention the applicable portions of EPA's own BART Guidelines
and to discuss how the State's analysis is inconsistent with the
Guidelines. In keeping with the statute, the regulations indicate that
it is the total generating capacity of the plant--not any particular
unit--that determines whether the BART Guidelines are mandatory.
    Nelson began operation in 1960.\88\ Nelson Units 1 and 2 each have
a

nameplate capacity of approximately 114 MW, Unit 3 is 163 MW, Unit 4 is
592 MW, and Unit 6 is 615 MW. Although Units 1 and 2 have been spun off
into a separate permit, the current Title V permit provides that the
``facility capacity'' is 1,204 MW.\89\ Given that Nelson's total
capacity exceeds 750 MW, BART for Nelson must be determined in
accordance with the BART Guidelines.\90\
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    \88\ Louisiana Department of Environmental Quality, Statement of
Basis, Proposed Part 70 Operating Permit 0520-00014-V2, Roy S.
Nelson Electric Generating Plant, Entergy Gulf States Louisiana,
L.L.C. Westlake, Calcasieu Parish, Louisiana, Agency Interest (AI)
No. 19588, Activity No. PER20100003 (Oct. 17, 2012), Attached as
Exhibit 7 to Sierra Club's August 14, 2017 comment letter.
    \89\ Louisiana Department of Environmental Quality, Part 70
Operating Permit 0520-00014-V2, Roy S. Nelson Electric Generating
Plant, Entergy Gulf States Louisiana, L.L.C. Westlake, Calcasieu
Parish, Louisiana, Agency Interest (AI) No. 19588, Activity No.
PER20100003 (issued Oct. 4, 2013). By letters dated May 1, 2015, and
August 24, 2015, Entergy confirmed that Units 4 and 6 are BART
eligible. LA059-006-_4_4_Entergy Nelson_6_BART_Survey.pdf; LA059-
006-_4_7Ltr_2015-08-24_from_FHyman_to_VAucoin_re_N4-WG3-
LG3_Aux_Boilers_BART_eligibility.pdf. Attached as Exhibit 8 to
Sierra Club's August 14, 2017 comment letter.
    \90\ To determine whether the total capacity exceeds 750 MW,
EPA's policy is to add the generating capacity of all the units at a
power plant, so long as one of the units is subject to BART. See,
e.g., 77 FR 12770, 12778 (Mar. 2, 2012) (``[I]t is reasonable to
interpret the RHR to mean that if the plant capacity is greater than
750 MW at the time the BART determination is made by the State . . .
then the power plant is a facility `having a total generating
capacity in excess of 750 [MW]' and any unit at the plant greater
than 200 MW is subject to presumptive BART.''); 76 FR 58570, 58596
(Sept. 21, 2011) (concluding that the BART Guidelines are mandatory
for Milton R. Young Station because Unit 1 is 277 MW and Unit 2 is
517 MW, which sums to 794 MW).
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    The BART Guidelines recommend the use of cost-effectiveness ``to
assess the potential for achieving an objective in the most economical
way.'' The BART Guidelines specifically caution states not to consider
annual costs without also considering cost-effectiveness. The
SO2 BART determination violates the requirements in the BART
Guidelines to consider cost-effectiveness of controls. Given that
Nelson Unit 6 is located at a plant with a total generating capacity
greater than 750 MW, the State is required to determine BART pursuant
to the BART Guidelines--which the State failed to do, by failing to
consider the cost-effectiveness of controls. The State should have
followed the BART Guidelines and considered the cost-effectiveness of
controls, which weigh in favor of selecting a scrubber as BART.
    It is both irrational and contrary to the purpose of the haze
provisions for the State to reject a very cost-effective control, a
scrubber, on the ground that the annual cost is higher than the least-
effective control, low-sulfur coal. If a state were permitted to reject
more effective controls solely on the basis that annual costs are
higher, then more effective controls would rarely, if ever, be
required. If the State's rationale were approved by EPA, it would be
difficult, if not impossible, to require the very pollution controls
necessary to achieve the statutory mandate to eliminate haze pollution.
The State's rationale must be rejected because it is incompatible with
achieving the goal of the Clean Air Act to ultimately eliminate all
human-caused haze pollution.
    Response: We agree with the comment that the total capacity of the
Nelson facility exceeds 750 MW and that the State was therefore
required to determine BART pursuant to the BART Guidelines for this
source. However, we disagree that LDEQ failed to consider cost-
effectiveness. LDEQ included estimates of annual costs, cost-
effectiveness, and incremental costs for the control options for Nelson
Unit 6 in Appendices D and F of its SIP revision. LDEQ considered all
information in the record, including all cost information provided by
the EPA and Entergy. LDEQ weighed the five factors and concluded that
``the use of lower sulfur coal presents the appropriate SO2
control based on consideration of economics, energy impacts, non-air
quality environmental impacts, and impacts to visibility.'' EPA has
reviewed all the information in the SIP submittal and finds that the
state's determination is approvable.
    Comment: EPA's proposed approval of Entergy's 2012-2016 emissions
baseline for the purposes of evaluating costs is arbitrary and contrary
to law. As an initial matter, the cost analyses for other Louisiana
BART sources, including Little Gypsy Unit 2, the Waterford units, and
the Ninemile units, relied on a 2000-2004 emission baseline for the
purposes of determining the cost effectiveness of controls. Neither
Entergy nor EPA provide any reasoned explanation for treating Nelson
differently. Instead, Entergy relied on an unenforceable, more recent
operational profile in its BART analysis. Indeed, Entergy's BART
analysis (and its conclusion that no additional controls are cost-
effective) is based on baseline emissions from 2012-2014, during which
Nelson 6 happened to be operating far less frequently than in earlier
years.\91\ This is important because using a 2000-2004 baseline, a
scrubber is even more cost-effective. The commenter estimates that a
dry scrubber would cost $1,712 to $1,750 per ton and a wet scrubber
would cost $1,728 to $1,748 using a 2000-2004 baseline. EPA's proposed
approval of Entergy's emission baseline skews the cost analysis.
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    \91\ See Dec. 30 Comments, Ex. C, Entergy Nelson Emissions and
Hours of Operation from 2000 through 2016, available at https://ampd.epa.gov/ampd/, attached as Exhibit 9.
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    EPA has repeatedly concluded that states should determine BART
using emissions data from 2000-2004. If projected operations will
differ from past practice, and the state's BART determination is based
on that emission baseline, the state ``must make these parameters or
assumptions into enforceable limitations'' in the SIP itself. See 40
CFR part 51, App'x. Y Sec.  (IV)(D)(4)(d) LDEQ's proposed SIP contains
no such enforceable limitation requiring Entergy to comply with 2012-
2014 emissions, and is therefore unapprovable.
    Response: We disagree with the comment regarding the use of
baseline emissions in estimating annual costs and cost-effectiveness.
Annual emissions used in evaluating cost effectiveness of controls are
based on annual emissions representative of future anticipated annual
emissions.\92\ The BART guidelines state that in the absence of
enforceable limitations, baseline emissions should be based upon
continuation of past practice.\93\ In many cases, in order to represent
future anticipated annual emissions from the source EPA has used actual
annual emissions from the most recent five-year period as being
consistent with past practice for the purposes of the cost evaluation.
EPA typically uses the most recent five years of annual emissions,
eliminating the maximum and minimum annual emissions when evaluating
cost impacts. For Nelson Unit 6, the cost analysis \94\ developed by
EPA and included in the October 2017 SIP submittal in appendix F,
utilized a baseline based on average emissions from 2011 through 2015,
excluding the maximum and minimum values. This analysis was later
updated to using 2012-2016, excluding the maximum and minimum values.
As stated in the Nelson Technical Assistance Document (Nelson TAD),\95\
EPA concluded that using the average annual emissions over the most
recent five years, excluding the maximum and minimum years, was a
reasonable compromise between simply selecting the maximum value from

2011-2015, or using the average of the values from 2011-2015. We
discuss our review of the Entergy cost analysis for Nelson Unit 6
elsewhere in the response to comment section. The commenter is
incorrect concerning the baseline used for cost analysis for Little
Gypsy Unit 2, the Waterford units, and the Ninemile units. For the
Waterford units, we utilized 2015 fuel oil prices and determined cost-
effectiveness based on costs and tons reduced per 1,000 barrels of fuel
burned. We also identified the highest annual emissions during the
2011-2015 period as part of our review of the BART determination for
this source. For Little Gypsy and Ninemile, consideration of cost-
effectiveness of controls was not necessary as the sources adopted the
most stringent control level available. In addition, we note there are
additional differences besides the choice of baseline emissions that we
disagree with that resulted in lower estimated costs by the commenter
than those estimated by EPA.\96\ We discuss the inputs we selected in
our cost evaluation in the Nelson TSD.
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    \92\ 40 CFR part 51 app. Y Sec.  IV.D.4.d. ``The baseline
emissions rate should represent a realistic depiction of anticipated
annual emissions for the source.''
    \93\ 40 CFR part 51 app. Y Sec.  IV.D.4.d.
    \94\ ``Nelson Technical Assistance Document'' (Nelson TAD) in
the Louisiana State Implementation Plan for the Entergy Nelson
Facility, June 2017, Available in Appendix F of the October 2017 LA
RH SIP submittal.
    \95\ See Technical Assistance Document for the Louisiana State
Implementation Plan for the Entergy Nelson Facility, June 2017,
Available in Appendix F of the October 2017 LA RH SIP submittal.
    \96\ For example, gross heat rate and SO2 rate.
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    Comment: The SIP is not approvable because it unlawfully fails to
require at least presumptive BART for SO2 emissions as
required by the BART Guidelines. For SO2, presumptive BART
is an emission limit of 0.15 lb/MMBtu. 40 CFR part 51, App. Y Sec.
(IV)(E)(4) (``You must require 750 MW power plants to meet specific
control levels for SO2 of either 95 percent control or 0.15
lbs/MMBtu, for each EGU greater than 200 MW that is currently
uncontrolled unless you determine that an alternative control level is
justified based on a careful consideration of the statutory
factors.''). The State's BART determination for SO2 is an
emission limit of 0.6 lb/MMBtu, which achieves nowhere near a 95%
reduction in SO2 emissions and is four times higher than the
presumptive BART rate of 0.15 lb/MMBtu. The State's failure to require
at least the minimum emissions reductions mandated by the BART
Guidelines violates the Clean Air Act requirement that BART be
determined ``pursuant to'' the BART Guidelines for plants larger than
750 MW, 42 U.S.C. 7491(b)(2). EPA cannot approve a SIP which violates
the Clean Air Act, and thus EPA must disapprove the SO2 BART
determination Nelson Unit 6.
    Response: We disagree with the comment that the State must require
at least a level of control consistent with the presumptive limit for
SO2 of either 95 percent control or 0.15 lbs/MMBtu. As
identified by the commenter, the BART Guidelines state that the
presumptive limit applies ``unless you determine that an alternative
control level is justified based on a careful consideration of the
statutory factors.'' LDEQ considered all information in the record,
including all estimates of visibility benefits, annual costs, cost-
effectiveness, and incremental cost provided by EPA and Entergy. The
state weighed the factors and concluded that ``the use of lower sulfur
coal presents the appropriate SO2 control based on
consideration of economics, energy impacts, non-air quality
environmental impacts, and impacts to visibility.'' EPA has reviewed
all the information in the SIP submittal and finds that the state's
determination meets the applicable requirements and therefore is
approvable.
    Comment: EPA's CALPUFF modeling shows that a scrubber would improve
visibility by more than 1 deciview at Caney Creek, and slightly less
than 1 deciview at Breton. Draft SIP, Appendix F at 41, Table 4-8.
EPA's CAMx modeling indicated that a scrubber would improve visibility
by 0.831 deciviews at Caney Creek and 0.663 deciviews at Upper Buffalo.
82 FR at 32299-300. These are significant amounts of visibility
improvement, as indicated by the BART Guidelines instructions on
determining which sources are subject to BART; the Guidelines state
that a source which causes 1 deciview of impairment ``causes''
visibility impairment, and a source which leads to 0.5 deciviews of
impairment ``contributes'' to impairment, 40 CFR part 51, App. Y Sec.
(III)(A)(1). This visibility improvement is well within the range of
values for previous final BART determinations. In addition to being
comparable to other BART determinations, the visibility improvement
from a new scrubber is necessary as BART to move both affected Class I
areas closer to natural visibility conditions.\97\
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    \97\ The Cost Effectiveness spreadsheet and related documents
used to develop the following charts are attached as Exhibit 5. ``At
a single Class I area'' refers to either the benefit at the most
impacted Class I area or the highest benefit at any single Class I
area (these are often but not always the same Class I area).
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    EPA's cost and visibility analyses only undermine the State's
proposed BART determination, by demonstrating that the cost and
visibility improvement from a scrubber are within the range of values
which states and EPA routinely find to be reasonable, and on a case-
specific basis, warranted as BART based on a five-factor analysis.
EPA's own analysis concluded that the average cost-effectiveness is
$2,706 per ton for SDA and $2,743 per ton for wet FGD. 82 FR at 32299.
As the chart below indicates, these values are well within the range of
average cost-effectiveness values for final BART determinations.\98\
EPA has not explained how it can approve the rejection of a scrubber
when the cost-effectiveness and visibility improvement values are
within the range that EPA has found reasonable in so many other haze
rulemakings.
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    \98\ See also Dec. 30 Comments, Ex. D Letter from Guy Donaldson
to Entergy Services (May 20, 2015) (describing deficiencies in
modeling); Letter from Kelly McQueen to Guy Donaldson (Apr. 15,
2016), EPA Doc. No. LA059-006-
_4_11_Reply_to_EPA_on_LA_BART_Issues_Final_4-15-16.pdf (purporting
to address EPA concerns about modeling and cost methodology, but
declining to correct errors and deficiencies).
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    The commenter estimates the costs of a dry scrubber would cost
$2,272 to $2,335 per ton and a wet scrubber would cost $2,328 to $2,361
per ton.\99\ And while the commenter states that it does not believe
that incremental cost-effectiveness \100\ should be a determining
factor, it notes that EPA found that the incremental cost-effectiveness
of a dry scrubber relative to DSI is $1,671. Both the average and
incremental cost-effectiveness of a scrubber are well-within the range
of cost-effectiveness values that states and EPA have found reasonable.
See ``Cost Effectiveness and Visibility in BART Determinations''
spreadsheet (showing that many final BART determinations have an
average cost-effectiveness exceeding $2,700 per ton of SO2
removed), Attached as Exhibit 5 (``Cost Effectiveness Spreadsheet'').
Given the degree to which Nelson contributes to impairment at Class I
areas, and the statutory mandate to restore natural conditions to these
skies, the cost of a scrubber is justified as BART for this facility.
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    \99\ See Stamper Report (attached as Technical Support Document
to Conservation Organizations June 18, 2017 comment letter).
    \100\ EPA defines ``incremental cost-effectiveness'' as the
difference between the cost-effectiveness of one pollution control
and the cost-effectiveness of the next-most-effective pollution
control. See 40 CFR part 51, App. Y Sec.  (IV)(D)(4)(E).
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    Response: The charts provided by the commenter give the ranges of
cost-effectiveness and visibility benefits of controls identified by
EPA and states in previous BART determinations for both NOX
and SO2. However, these charts do not provide information on
the visibility benefits, costs of controls, or incremental costs and
benefits for technologies that were rejected in each of these
determinations or in other situations where no additional controls were
required to meet BART. Each BART determination is dependent on the
specific situation and requires

consideration of a number of factors including, the characteristics of
the fuel burned at the source, the existing controls, the control
efficiency of available control technologies, the remaining useful
life, the costs and incremental costs of controls and the anticipated
visibility benefit of each potential control. The Regional Haze Rule
and BART Guidelines do not require the state to select as BART a more
effective technology merely because it has visibility benefits or cost-
effectiveness that fall within the range of previous cases, nor do they
prohibit the state from choosing as BART a less effective technology
measure that falls outside the range of previous cases. The state must
consider all 5 statutory factors.
    The Clean Air Act gave EPA the power to identify pollutants and set
air quality standards. Congress gave states ``the primary
responsibility for implementing those standards.'' Luminant Generation
Co. v. EPA, 675 F.3d 917, 921 (5th Cir. 2012). (internal quotation
marks omitted); see 42 U.S.C. 7407(a) (``Each State shall have the
primary responsibility for assuring air quality within [its] entire
geographic area.''); id. sec. 7401(a)(3) (``[A]ir pollution prevention
. . . is the primary responsibility of States and local governments.'')
The states have ``wide discretion'' in formulating SIPs. Union Elec.
Co. v. EPA, 427 U.S. 246, 250 (1976). The Clean Air Act provides that
EPA ``shall approve'' a SIP ``if it meets the applicable requirements
of this chapter.'' 42 U.S.C. 7410(k)(3). EPA's regulations under the
CAA ``do not require uniformity between . . . actions in all
circumstances and instead `allow for some variation' in actions taken
in different regions.'' 81 FR at 326 (quoting Amendments to Regional
Consistency Requirements, 80 FR 50250, at 50258 (Aug. 19, 2015)). Some
variation is to be expected because SIP actions are highly fact-
dependent. Though we identified errors in Entergy's cost and visibility
analyses, EPA conducted its own cost and visibility analyses in
accordance with the applicable regulations and guidelines. EPA's cost
and visibility analyses are part of the SIP submission (Appendix F) and
were included in the information considered by the State in making
their BART determination. LDEQ considered all information in the
record, including all estimates of visibility benefits, annual costs,
cost-effectiveness, and incremental cost provided by EPA and Entergy.
The state weighed the factors considering all available information
included in the SIP, and concluded that ``the use of lower sulfur coal
presents the appropriate SO2 control based on consideration
of economics, energy impacts, non-air quality environmental impacts,
and impacts to visibility.'' EPA has reviewed all the information in
the SIP submittal and finds that the state's determination is
approvable.
    Comment: EPA arbitrarily ignores the impact that errors in the cost
and modeling analyses relied on by the State had on the State's BART
determination. The State rejected a scrubber in favor of low-sulfur
cost based on comparing the relative costs and visibility benefits of
the two controls. Yet EPA found that the factors on which the State
based its decision, cost and visibility benefits, are thoroughly
inaccurate. EPA failed to explain how the Entergy analyses the State
relied on can be incorrect, but the State's ultimate BART determination
can be approvable.
    Response: As explained in previous responses, EPA reviewed the
State's entire submission, including any attached appendices and
supporting documentation in determining whether the State's submission
is approvable. EPA conducted its own cost and visibility analyses and
submitted these analyses to the State for review in its determination.
LDEQ reviewed this information as is evidenced by its SIP submission.
LDEQ states, ``LDEQ has weighed the five factors and after a review of
both Entergy's and EPA's information . . .'' This indicates that the
State reviewed the information it received from both Entergy and the
EPA in making its determination. After reviewing the relevant
information contained in the State's SIP, we determined that the
State's SIP is approvable.
    Comment: The record indicates that EPA Region 6 has, on multiple
occasions, expressed concerns with Entergy's modeling and cost
analyses, as well as the Company's proposed baseline emission
rates.\101\ Those documents--including Entergy's October 14, 2016
analysis, EPA's underlying March 16, 2016 Preliminary Review Response
letter explaining its concerns with Entergy's modeling methodology, and
any EPA response to Entergy's letter--do not appear to be included in
the administrative record. Moreover, Louisiana's final BART analysis
for Nelson does not address, let alone correct, many of the flaws EPA
identified. As a result, the public has been deprived of information
relevant to the legal and factual basis for Entergy's BART analysis,
and is therefore unable to comment meaningfully on EPA's proposed
approval of the BART analysis.
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    \101\ See, e.g., Trinity Consultants, Inc., CAMx Modeling Report
Prepared for Entergy Services (Oct. 14, 2016), available at http://edms.deq.louisiana.gov, LDEQ AI No. 174156, Doc. Nos.
10369532_6of7.pdf and 10369532_7of7.pdf (describing EPA critique of
CAMx modeling platform, but excluding underlying letter), attached
as Exhibit 4; see also Dec. 30 Comments, Ex. D, Letter from EPA Air
Planning Chief Guy Donaldson to Firdina Hyman, Response to
Deviations Request for Best Available Retrofit Applicability
Screening Modeling (May 20, 2015); Letter from Kelly
---------------------------------------------------------------------------

    Response: The letters referenced by the commenter were made
available by LDEQ on its website during its comment period. The final
February 2017 SIP EPA received from LDEQ did not contain these letters
as attachments, so they were inadvertently left out of the EPA docket,
but they have since been placed in the docket. We note that the
commenter cited to these letters in its comment, indicating that the
commenter had the opportunity to review them. We also note that
Entergy's response letter was included in the docket. This response
letter included the questions raised by EPA in its initial letter
verbatim.\102\ EPA did not rely on the Entergy's CAMx analysis in the
October 2017 LA RH SIP, Appendix D, which is referred to by the