[Federal Register Volume 82, Number 2 (Wednesday, January 4, 2017)]
[Proposed Rules]
[Pages 912-950]
[FR Doc No: 2016-30713]

Vol. 82

Wednesday,

No. 2

January 4, 2017

Part II

Environmental Protection Agency

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40 CFR Part 52

Promulgation of Air Quality Implementation Plans; State of Texas;
Regional Haze and Interstate Visibility Transport Federal
Implementation Plan; Proposed Rule

Federal Register / Vol. 82 , No. 2 / Wednesday, January 4, 2017 /
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R06-OAR-2016-0611; FRL-9955-77-Region 6]

Promulgation of Air Quality Implementation Plans; State of Texas;
Regional Haze and Interstate Visibility Transport Federal
Implementation Plan

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: Pursuant to the Federal Clean Air Act (CAA or Act), the
Environmental Protection Agency (EPA) is proposing to promulgate a
Federal Implementation Plan (FIP) in Texas to address the remaining
outstanding requirements that are not satisfied by the Texas Regional
Haze State Implementation Plan (SIP) submission. Specifically, the EPA
proposes SO2 limits on 29 Electric Generating Units (EGUs)
located at 14 Texas facilities to fulfill requirements for the
installation and operation of the Best Available Retrofit Technology
(BART) for SO2. To address the requirement for
NOX BART for Texas EGU sources, we are proposing a FIP that
relies upon two other EPA rulemakings, one already final and one
proposed, which together will establish that participation in the
Cross-State Air Pollution Rule (CSAPR) continues to qualify as an
alternative to NOX BART for EGUs in Texas. We also are
proposing to disapprove the portion of the Texas Regional Haze SIP that
addresses the BART requirement for EGUs for Particulate Matter (PM) and
proposing a FIP with PM BART limits for EGUs at 29 EGUs located at 14
Texas facilities, based on existing practices and control capabilities.
In addition, we propose to reconsider and re-propose disapproval of
portions of several SIP revisions submitted to satisfy the requirement
to address interstate visibility transport for six NAAQS and that the
FIP emission limits we are proposing meet the interstate visibility
transport requirements for these NAAQS.

DATES: Comments: Comments must be received on or before March 6, 2017.
A public hearing will be held January 10, 2017. For additional
logistical information regarding the public hearing please see the
SUPPLEMENTARY INFORMATION section of this action.

ADDRESSES: Submit your comments, identified by Docket No. EPA-R06-OAR-
2016-0611, at http://www.regulations.gov or via email to<EMAIL_ADDRESS>Follow the online instructions for submitting comments.
Once submitted, comments cannot be edited or removed from
Regulations.gov. The EPA may publish any comment received to its public
docket. Do not submit electronically any information you consider to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Multimedia submissions (audio,
video, etc.) must be accompanied by a written comment. The written
comment is considered the official comment and should include
discussion of all points you wish to make. The EPA will generally not
consider comments or comment contents located outside of the primary
submission (i.e. on the web, cloud, or other file sharing system). For
additional submission methods, please contact Joe Kordzi,<PHONE_NUMBER>,
<EMAIL_ADDRESS>For the full EPA public comment policy, information
about CBI or multimedia submissions, and general guidance on making
effective comments, please visit http://www2.epa.gov/dockets/commenting-epa-dockets.
    Docket: The index to the docket for this action is available
electronically at http://www.regulations.gov and in hard copy at the
EPA Region 6, 1445 Ross Avenue, Suite 700, Dallas, Texas. While all
documents in the docket are listed in the index, some information may
be publicly available only at the hard copy location (e.g., copyrighted
material), and some may not be publicly available at either location
(e.g., CBI).
    The Texas regional haze SIP is available online at: https://www.tceq.texas.gov/airquality/sip/bart/haze_sip.html. It is also
available for public inspection during official business hours, by
appointment, at the Texas Commission on Environmental Quality, Office
of Air Quality, 12124 Park 35 Circle, Austin, Texas 78753.

FOR FURTHER INFORMATION CONTACT: Joe Kordzi, Air Planning Section (6PD-
L), Environmental Protection Agency, Region 6, 1445 Ross Avenue, Suite
700, Dallas, Texas 75202-2733, telephone<PHONE_NUMBER>; fax number 214-
665-7263; email address<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Throughout this document wherever ``we,''
``us,'' or ``our'' is used, we mean the EPA.
    Public Hearing: We are holding an information session, for the
purpose of providing additional information and informal discussion for
our proposal. We are also holding a public hearing to accept oral
comments into the record:

Date: Tuesday, January 10, 2017
Time: Open House: 1:30 p.m.-3:30 p.m.
Public hearing: 4:00 p.m.-8:00 p.m. (including short break)
Location: Joe C. Thompson Conference Center (on the University of
Texas (UT) Campus), Room 3.102, 2405 Robert Dedman Drive, Austin,
Texas 78712

    Joe C. Thompson Conference Center parking is adjacent to the
building in Lot 40, located at the intersection of East Dean Keeton
Street and Red River Street. Additional parking is available at the
Manor Garage, located at the intersection of Clyde Littlefield Drive
and Robert Dedman Drive. If arranged in advance, the UT Parking Office
will allow buses to park along Dedman Drive near the Manor Garage for a
fee.
    The public hearing will provide interested parties the opportunity
to present information and opinions to us concerning our proposal.
Interested parties may also submit written comments, as discussed in
the proposal. Written statements and supporting information submitted
during the comment period will be considered with the same weight as
any oral comments and supporting information presented at the public
hearing. We will not respond to comments during the public hearing.
When we publish our final action, we will provide written responses to
all significant oral and written comments received on our proposal. To
provide opportunities for questions and discussion, we will hold an
information session prior to the public hearing. During the information
session, EPA staff will be available to informally answer questions on
our proposed action. Any comments made to EPA staff during an
information session must still be provided orally during the public
hearing, or formally in writing within 30 days after completion of the
hearings, in order to be considered in the record.
    At the public hearings, the hearing officer may limit the time
available for each commenter to address the proposal to three minutes
or less if the hearing officer determines it to be appropriate. We will
not be providing equipment for commenters to show overhead slides or
make computerized slide presentations. Any person may provide written
or oral comments and data pertaining to our proposal at the public
hearings. Verbatim English language transcripts of the hearing and
written statements will be included in the rulemaking docket.

Table of Contents

I. Background
II. Overview of Proposed Actions
    A. Regional Haze
    B. Interstate Transport of Pollutants That Affect Visibility

    C. Our Authority To Promulgate a FIP
III. Our Proposed BART Analyses for SO2 and PM
    A. Identification of BART-Eligible Sources
    B. Identification of Sources That are Subject to BART
    1. Our use of the Standard BART Model Plant Exemption
    2. Our Extension of the BART Model Plant Exemption
    3. Our use of CALPUFF Modeling to Exempt Sources From Being
Subject to BART
    4. Our use of CAMx Modeling to Exempt Sources From Being Subject
to BART
    5. Summary of Sources That are Subject to BART
    C. Our BART Five Factor Analyses
    1. Steps 1 and 2: Technically Feasible SO2 Retrofit
Controls
    a. Identification of Technically Feasible SO2
Retrofit Control Technologies for Coal Fired Units
    b. Identification of Technically Feasible SO2
Retrofit Control Technologies for Gas-Fired Units That Burn Oil
    c. Identification of Technically Feasible SO2 Control
Technologies for Scrubber Upgrades
    2. Step 3: Evaluation of Control Effectiveness
    a. Evaluation of SO2 Control Effectiveness for Coal
Fired Units
    b. Evaluation of SO2 Control Effectiveness for Gas
Fired Units
    3. Step 4: Evaluate Impacts and Document the Results for
SO2
    a. Impact Analysis Part 1: Cost of Compliance for DSI, SDA, and
Wet FGD
    b. Impact Analysis Part 1: Cost of Compliance for Scrubber
Upgrades
    c. Impact Analysis Part 1: Cost of Compliance for Gas Units That
Burn Oil
    4. Impact Analysis Parts 2, 3, and 4: Energy and Non-air Quality
Environmental Impacts, and Remaining Useful Life
    5. Step 5: Evaluate Visibility Impacts
    a. Visibility Benefits of DSI, SDA, and Wet FGD for Coal-fired
Units
    b. Visibility Benefits of Scrubber Upgrades for Coal-fired Units
    c. Visibility Benefits of Fuel Oil Switching for Gas/Fuel Oil-
Fired Units
    6. BART Five Factor Analysis for PM
    D. How, if at all, Do Issues of ``Grid Reliability'' Relate to
the Proposed BART Determinations?
IV. Our Weighing of the Five BART Factors
    A. SO2 BART for Coal-fired Units With no
SO2 Controls
    1. Big Brown 1 & 2
    2. Monticello 1 & 2
    3. Coleto Creek 1
    4. Welsh 1
    5. Harrington 061B & 062B
    6. W A Parish WAP 5 & 6
    7. J T Deely 1 & 2
    B. SO2 BART for Coal-fired Units With Underperforming
Scrubbers
    C. SO2 BART for Gas-fired Units That Burn Oil
    D. PM BART
V. Proposed Actions
    A. Regional Haze
    1. NOX BART
    2. SO2 BART for Coal-fired Units
    3. Potential Process for Alternative Scrubber Upgrade Emission
Limits
    4. SO2 BART for Gas-fired Units That Burn Oil
5. PM BART
B. Interstate Visibility Transport
VI. Statutory and Executive Order Reviews

I. Background

    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 health effects and
mortality in humans and contributes to environmental effects such as
acid deposition and eutrophication.
    Data from the existing visibility monitoring network, the
``Interagency Monitoring of Protected Visual Environments'' (IMPROVE)
monitoring network, show that visibility impairment caused by air
pollution occurs virtually all the time at most national parks and
wilderness areas. In 1999, the average visual range \1\ 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.\2\ CAA programs have reduced some haze-causing pollution,
lessening some visibility impairment and resulting in partially
improved average visual ranges.\3\
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    \1\ Visual range is the greatest distance, in kilometers or
miles, at which a dark object can be viewed against the sky.
    \2\ 64 FR 35715 (July 1, 1999).
    \3\ An interactive ``story map'' depicting efforts and recent
progress by EPA and states to improve visibility at national parks
and wilderness areas may be visited at: http://arcg.is/29tAbS3.
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    CAA requirements to address the problem of visibility impairment
are continuing to be addressed and 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.\4\ On December 2, 1980, 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.'' \5\ These regulations represented the first phase in
addressing visibility impairment. 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.
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    \4\ Areas designated as mandatory Class I Federal areas consist
of National Parks exceeding 6000 acres, wilderness areas and
national memorial parks exceeding 5000 acres, and all international
parks that were in existence on August 7, 1977. 42 U.S.C. 7472(a).
In accordance with section 169A of the CAA, EPA, in consultation
with the Department of Interior, promulgated a list of 156 areas
where visibility is identified as an important value. 44 FR 69122
(November 30, 1979). The extent of a mandatory Class I area includes
subsequent changes in boundaries, such as park expansions. 42 U.S.C.
7472(a). Although states and tribes may designate as Class I
additional areas which they consider to have visibility as an
important value, the requirements of the visibility program set
forth in section 169A of the CAA apply only to ``mandatory Class I
Federal areas.'' Each mandatory Class I Federal area is the
responsibility of a ``Federal Land Manager.'' 42 U.S.C. 7602(i).
When we use the term ``Class I area'' in this action, we mean a
``mandatory Class I Federal area.''
    \5\ 45 FR 80084 (December 2, 1980).
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    Congress added section 169B to the CAA in 1990 to address regional
haze issues, and we promulgated regulations addressing regional haze in
1999.\6\ The Regional Haze Rule revised the existing visibility
regulations to integrate into the regulations provisions addressing
regional haze impairment and established a comprehensive visibility
protection program for Class I areas. The requirements for regional
haze, found at 40 CFR 51.308 and 51.309, are included in our visibility
protection regulations at 40 CFR 51.300-309. The requirement to submit
a regional haze SIP applies to all 50 states, the District of Columbia,
and the Virgin Islands. States were required to submit the first
implementation plan addressing regional haze visibility

impairment no later than December 17, 2007.\7\
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    \6\ 64 FR 35714 (July 1, 1999), codified at 40 CFR part 51,
subpart P (Regional Haze Rule).
    \7\ See 40 CFR 51.308(b). EPA's regional haze regulations
require subsequent updates to the regional haze SIPs. 40 CFR
51.308(g)-(i).
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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 \8\ built between 1962 and 1977 procure, install and operate
the ``Best Available Retrofit Technology'' (BART). Larger ``fossil-fuel
fired steam electric plants'' are included among the BART 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 alternative program as long as the alternative provides greater
reasonable progress towards improving visibility than BART. To the
extent a Regional Haze SIP does not meet CAA requirements to address
BART, the CAA requires EPA to promulgate a FIP that makes the requisite
determinations to ensure the BART requirement is satisfied, as
applicable, for sources in the state.\9\
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    \8\ See 42 U.S.C. 7491(g)(7) (listing the set of ``major
stationary sources'' potentially subject-to-BART).
    \9\ See, 42 U.S.C. 7491(b)(2)(A)(citing the potential need for
BART as determined by ``the Administrator in the case of a plan
promulgated under section 7410(c) of this title'').
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II. Overview of Proposed Actions

A. Regional Haze

    On January 5, 2016, we took final action on nearly all portions of
a Regional Haze SIP submittal submitted by the State of Texas on March
31, 2009.\10\ In that final rule, we did not take action on the portion
of the submittal that was intended to satisfy BART requirements for
EGUs as mandated by 40 CFR 51.308(e). In an earlier, separate action,
we issued a limited disapproval of the Texas Regional Haze SIP
concerning EGU BART due to Texas' reliance on the Clean Air Interstate
Rule (CAIR).\11\ The EGU BART requirements for NOX and
SO2 remain unmet following the limited disapproval, and
Texas has not submitted a revised SIP to address the deficiencies.
While we previously proposed to approve the portion of the Regional
Haze SIP that was intended to address whether EGUs in Texas must
install and operate BART for PM,\12\ that part of the proposed action
was not finalized.\13\ In connection with changed circumstances on how
Texas EGUs are able to satisfy NOX and SO2 BART,
we are now proposing to disapprove the portion of the Texas Regional
Haze SIP that evaluated the PM BART requirement for EGUs. The FIP we
are proposing today addresses the EGU BART requirement and addresses
these deficiencies in the Texas Regional Haze SIP.
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    \10\ 81 FR 296 (January 5, 2016). A preliminary order of the
Fifth Circuit Court of Appeals in Case No. 16-60118 was issued on
July 15, 2016, and stayed the rule ``in its entirety.'' On December
2, 2016, the U.S. Department of Justice filed a motion for voluntary
remand of the parts of the rule under challenge and consenting to
continuation of the judicial stay for remanded parts of the rule.
The motion also requested affirmance of the partial approvals of the
Texas and Oklahoma SIPs and lifting of the stay as to those
approvals. This motion is currently pending disposition.
    \11\ The limited disapproval triggered the EPA's obligation to
issue a FIP for Texas unless the State submitted an approvable SIP
revision to correct the relevant deficiencies within 2 years of the
final limited disapproval action. CAA section 110(c)(1); 77 FR
33641, 33654 (August 6, 2012).
    \12\ 79 FR 74817, 74851 (proposing to concur with screening
analyses conducted by TCEQ including findings that no Texas EGUs are
subject to BART for PM).
    \13\ 81 FR at 302 (January 5, 2016): ``[W]e proposed to approve
Texas' determination that for its EGUs no PM BART controls were
appropriate, based on a screening analysis of the visibility impacts
of from just PM emissions. . . ..we have. . . .decided not to
finalize our proposed approval of Texas' PM BART determination [for
EGUs].''
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    Texas' regional haze SIP relied on participation in CAIR as an
alternative to meeting the source-specific BART requirements for
SO2 and NOX. See 40 CFR 51.308(e)(4) (2006). At
the time that Texas submitted its SIP to EPA, however, the D.C. Circuit
had remanded CAIR (without vacatur). See North Carolina v. EPA, 531
F.3d 896 (D.C. Cir.), modified, 550 F.3d 1176 (D.C. Cir. 2008). The
court thereby left CAIR and CAIR 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.\14\
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    \14\ 550 F.3d at 1178.
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    On August 8, 2011, we promulgated the Cross-State Air Pollution
Rule (CSAPR), to replace CAIR.\15\ In 2012, we issued a limited
disapproval of the Texas regional haze SIP because of Texas' reliance
on CAIR as an alternative to EGU BART for SO2 and
NOX.\16\ 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 NOX BART for EGUs.\17\ 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 in EME
Homer City Generation v. EPA, 795 F.3d 118 (D.C. Cir.). Specifically,
the court invalidated a number of the Phase 2 ozone-season
NOX budgets and found that the SO2 budgets for
four states resulted in over-control for purposes of CAA section
110(a)(2)(D)(i)(I). The remand included Texas' ozone-season
NOX budget and annual SO2 budget.
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    \15\ 76 FR 48208.
    \16\ 77 FR 33641.
    \17\ 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 Texas. 77 FR
33641, 33654.
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    We had earlier proposed to rely on CSAPR participation to address
these BART-related deficiencies in Texas' SIP submittals.\18\ Because
of the uncertainty caused by the D.C. Circuit Court's partial remand,
however, we determined that it was not appropriate to finalize our
action. We are in the process of responding to the remand of these
CSAPR budgets. On October 26, 2016, we finalized an update to the CSAPR
rule that addresses the 1997 ozone NAAQS portion of the remand and the
requirements of CAA section 110(a)(2)(D)(i)(I) for the 2008 ozone
NAAQS.\19\ This rule promulgated a new

FIP for Texas that replaced the CSAPR ozone season NOX
emission budget designed to address the 1997 ozone NAAQS for the State
with a revised budget designed to address the requirements of CAA
section 110(a)(2)(D)(i)(I) for the 2008 ozone NAAQS. Then, on November
10, 2016, we proposed to withdraw the FIP provisions that require
affected EGUs in Texas to participate in CSAPR for annual emissions of
SO2 and NOX with regard to emissions after
2016.\20\ Withdrawal of these FIP requirements will address the D.C.
Circuit's remand of the CSAPR Phase 2 SO2 budget for Texas.
This recently published proposed rule includes an assessment of the
impacts of the set of actions that the EPA has taken or expects to take
in response to the D.C. Circuit's remand on our 2012 demonstration that
participation in CSAPR would provide for greater reasonable progress
than BART.
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    \18\ 79 FR 74817, 74823 (December 16, 2014).
    \19\ ``Cross-State Air Pollution Rule Update for the 2008 Ozone
NAAQS.'' 81 FR74504. The relevant portion of the remand pertained to
the Phase 2 ozone season NOX emission budget designed to
address the 1997 ozone NAAQS. In response to the remand, in this
final rule the EPA removed the regulatory requirement for sources in
Texas to comply with the phase 2 ozone season NOX budget
calculated to address the 1997 ozone standard because we determined
that no additional emission reductions from sources in Texas are
necessary to address the State's obligation under 110(a)(2)(D)(i)(I)
for the 1997 ozone NAAQS. However, because Texas is linked to
downwind air quality problems with respect to the 2008 ozone NAAQS,
we promulgated a new ozone season NOX emission budget to
address that standard. 81 FR 74504, 74600-74601.
    \20\ ``Interstate Transport of Fine Particulate Matter: Revision
of Federal Implementation Plan Requirements for Texas,'' 81 FR 78954
(November 10, 2016). Although the court's decision specifically
remanded only Texas' SO2 budget, the court's rationale
for remanding that budget also implicates Texas' annual
NOX budget because the SO2 and annual
NOX budgets were developed through an integrated analysis
and were promulgated to meet a common PM2.5 transport
obligation under CAA section 110(a)(2)(D)(i)(I).
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    In 2012, we determined that CSAPR is ``better-than-BART'' based on
a comparison of projected visibility in scenarios representing CSAPR
implementation and BART implementation, as well as a base case without
CSAPR or BART, in relevant locations throughout the country. In the
case of the remanded Phase 2 ozone-season NOX budgets, eight
of the states with remanded budgets (including Texas) will continue to
be subject to CSAPR to address ozone transport obligations with regard
to the more stringent 2008 ozone NAAQS, and North Carolina and South
Carolina, although no longer covered by CSAPR to address ozone
transport obligations, will continue to be subject to CSAPR annual
NOX requirements in order to address their PM2.5
transport obligations. In considering the potential impact of the
remand of Phase 2 budgets on the 2012 CSAPR-Better-than-BART analytic
demonstration, we therefore believe that only two changes have
potential relevance: The withdrawal of the FIP provisions subjecting
Florida EGUs to CSAPR ozone-season NOX requirements that has
already been finalized, and the withdrawal of FIP provisions subjecting
Texas EGUs to CSAPR SO2 and annual NOX
requirements that is proposed separately. That proposed analysis
supports the continued conclusion that CSAPR participation would
achieve greater reasonable progress than BART for NOX
despite the change in the treatment of Texas and Florida EGUs.
Consequently, we have proposed that the Regional Haze Rule continues to
authorize the use of CSAPR participation as a BART alternative for
EGUs.\21\ Finalization of that proposal would allow for Texas' regional
haze program to rely on CSAPR ozone season control program
participation as an alternative to source-specific EGU BART for
NOX.\22\ Based on that national proposal, we are now
proposing a FIP to replace Texas' reliance on CAIR with reliance on
CSAPR to address the NOX BART requirements for EGUs.
Finalization of this portion of the FIP is contingent on our taking
final action to find that CSAPR continues to be an appropriate
alternative to source specific BART. However, finalization of the
portion of our national proposal that would withdraw the FIP provisions
for Texas for annual emissions of SO2 and NOX
described above would mean that Texas will no longer be eligible to
rely on CSAPR participation as an alternative to source-specific EGU
BART for SO2. As a result, we are proposing to promulgate a
FIP that includes BART screening of sources and a source-by-source
analysis for SO2 BART and controls for this pollutant as
appropriate. We are also unable to propose approval of the Texas
Regional Haze SIP's PM BART evaluation, as previously proposed, as that
demonstration made underlying assumptions that are no longer valid.\23\
We instead propose to disapprove that portion of the SIP and, in place
of it, promulgate source-specific PM BART requirements for EGUs that we
have evaluated to be subject to BART in this proposed FIP.
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    \21\ 81 FR at 78962-78964.
    \22\ While we have proposed to remove Texas from CSAPR's annual
NOX program, CSAPR is still an appropriate alternative to
BART for NOX purposes because EGUs in Texas continue to
be required to participate in CSAPR's ozone season NOX
program.
    \23\ We previously proposed approval of Texas' SIP for EGU PM
BART on the premise that EGU BART for both SO2 and
NOX were covered by participation in CSAPR, which allowed
Texas to conduct a screening analysis of the visibility impacts from
PM emissions in isolation. However, modeling on a pollutant-specific
basis for PM is appropriate only in the narrow circumstance where a
state relies on a BART alternative to satisfy NOX and
SO2 BART. Due to the complexity and nonlinear nature of
atmospheric chemistry and chemical transformation among pollutants,
EPA has not recommended performing modeling on a pollutant-specific
basis to determine whether a source is subject to BART, except in
the unique situation described above. See discussion in Memorandum
from Joseph Paisie to Kay Prince, ``Regional Haze Regulations and
Guidelines for Best Available Retrofit Technology (BART)
Determinations,'' July 19, 2006. More recently, the Ninth Circuit
upheld EPA's disapproval of the Arizona regional haze SIP for
including a pollutant-specific screening analysis for
NOX. Phoenix Cement Co. v. EPA, 647 F. App'x 702, 705-06
(9th Cir. Mar. 31, 2016) (upholding EPA's interpretation that the
``Regional Haze Rule [] require[s] a BART determination for any
pollutant at a source that exceeds the de minimis threshold, once
that source has been determined subject to BART.''). We did not
finalize our proposed approval of Texas' EGU PM BART determination
because of the uncertainty at that time concerning the CSAPR remand
and whether Texas would continue to have CSAPR coverage for both
NOX and SO2, 81 FR 296, 302, but that
uncertainty has now been resolved.
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    We believe, however, it is preferable for states to assume primary
responsibility for implementing the Regional Haze requirements as
envisioned by the CAA. We will work with the State of Texas if it
chooses to develop a SIP to meet these overdue Regional Haze
requirements and replace or avoid a finalized FIP.
    The FIP we are proposing includes BART control determinations for
EGUs in Texas without previously approved BART determinations and
associated compliance schedules and requirements for equipment
maintenance, monitoring, testing, recordkeeping, and reporting for all
affected sources and units. The EGU BART sources addressed in this FIP
cause or contribute to visibility impairment at one or more Class I
areas in Texas, Oklahoma, Arkansas, and New Mexico. The two Class I
areas in Texas are Big Bend National Park and the Guadalupe Mountains
National Park. The Class I area in Oklahoma is the Wichita Mountains
National Wildlife Refuge. The two Class I areas in Arkansas are the
Caney Creek Wilderness Area and the Upper Buffalo Wilderness Area. The
closest impacted Class I areas in New Mexico are the Carlsbad Caverns
National Park, Salt Creek Wilderness Area, and White Mountains
Wilderness Area.
    In order to remedy these deficiencies in the Texas SIP, we are
proposing this FIP to establish the means by which the regional haze
program for Texas will meet the BART requirements for SO2,
NOX, and PM. We are proposing source-specific BART
determinations for EGUs subject to BART for SO2 and PM. We
are proposing that NOX BART requirements for EGUs in Texas
will be satisfied by a determination, proposed for separate
finalization, that Texas' participation in CSAPR's ozone season control
program is a permissible alternative to source-specific NOX
BART.
    Addressing the BART requirement for Texas EGUs, as proposed today,
with cost-effective and readily available controls, will help ensure
that progress

is made toward natural visibility conditions at Class I areas affected
by Texas' sources. Please refer to our previous rulemaking on the Texas
regional haze SIP for additional background regarding the CAA, regional
haze, and our Regional Haze Rule.\24\
---------------------------------------------------------------------------

    \24\ 81 FR 296. The public docket for this past rulemaking
remains accessible under EPA Docket ID: EPA-R06-OAR-2014-0754 at
https://www.regulations.gov. This proposed rulemaking has a
separately established docket (EPA-R06-OAR-2016-0611). Our TSD
contains a list of materials from EPA Docket ID: EPA-R06-OAR-2014-
0754 that we incorporate by reference and consider to be part of
this rulemaking record even as they are not necessarily re-uploaded
to the newer docket.
---------------------------------------------------------------------------

B. Interstate Transport of Pollutants That Affect Visibility

    Section 110(a) of the CAA directs states to submit a SIP that
provides for the implementation, maintenance, and enforcement of each
NAAQS, which is commonly referred to as an infrastructure SIP. Among
other things, CAA 110(a)(2)(D)(i)(II) requires that SIPs contain
adequate provisions to prohibit interference with measures required to
protect visibility in other states. This requirement is referred to as
``interstate visibility transport.'' SIPs addressing interstate
visibility transport are due to EPA within three years after the
promulgation of a new or revised NAAQS (or within such shorter period
as we may prescribe). A state's failure to submit a complete,
approvable SIP for interstate visibility transport creates an
obligation for EPA to promulgate a FIP to address this requirement.\25\
---------------------------------------------------------------------------

    \25\ CAA Sec.  110(c)(1). Mandatory sanctions under CAA section
179 do not apply because the deficiencies are not with respect to a
submission that is required under CAA title I part D. ``Guidance on
Infrastructure State Implementation Plan (SIP) Elements under Clean
Air Act Sections 110(a)(1) and (2)'' at pages 34-35 (September 13,
2013) [hereinafter 2013 i-SIP Guidance].
---------------------------------------------------------------------------

    Previously, we issued a finding that Texas failed to submit a SIP
revision to satisfy all four requirements of interstate transport under
section 110(a)(2)(D)(i) of the CAA for the 1997 8-hour ozone and 1997
PM2.5 NAAQS.\26\ Texas later submitted a SIP revision to
address interstate transport for these NAAQS. However, in our January
5, 2016 final action we disapproved the portion of Texas' SIP revisions
intended to address interstate visibility transport for six NAAQS,
including the 1997 8-hour ozone and 1997 PM2.5.\27\ We
concluded that to meet the requirements of interstate visibility
transport: (1) Texas could not rely on its Regional Haze SIP, which
relied heavily upon the remanded CAIR, to ensure that emissions from
Texas do not interfere with measures to protect visibility in nearby
states; and (2) additional control of SO2 emissions in Texas
were needed to prevent interference with measures required to be
included in the Oklahoma SIP to protect visibility. However, in that
action we did not finalize the portion of our proposed FIP addressing
Texas' interstate visibility transport obligations because that portion
of the proposed FIP would have partially relied on CSAPR to ensure the
emissions from Texas' sources do not interfere with other states'
visibility programs. Given the uncertainty that existed at the time
arising from the D.C. Circuit's remand of Texas' CSAPR budgets (EME
Homer City Generation v. EPA, 79 F.3d 118 (D.C. Cir.)), we concluded
that it was not appropriate to finalize our proposed determination to
rely on CSAPR as an alternative to SO2 and NOX
BART for EGUs in Texas in that action.\28\
---------------------------------------------------------------------------

    \26\ 70 FR 21147 (April 25, 2005). The four components of
interstate transport in Section 110(a)(2)(D)(i) are contained in two
subsections. Section 110(a)(2)(D)(i)(I) addresses any emissions
activity in one state that contributes significantly to
nonattainment, or interferes with maintenance, of the NAAQS in
another state. Section 110(a)(2)(D)(i)(II) requires SIPs to include
provisions prohibiting any source or other type of emissions
activity in one state from interfering with measures required of any
other state to prevent significant deterioration of air quality or
from interfering with measures required of any other state to
protect visibility (referring to visibility in Class I areas). This
proposal only addresses the fourth requirement concerning
visibility.
    \27\ Specifically, we previously disapproved the relevant
portion of these Texas' SIP submittals: April 4, 2008: 1997 8-hour
Ozone, 1997 PM2.5 (24-hour and annual); May 1, 2008: 1997
8-hour Ozone, 1997 PM2.5 (24-hour and annual); November
23, 2009: 2006 24-hour PM2.5; December 7, 2012: 2010
NO2; December 13, 2012: 2008 8-hour Ozone; May 6, 2013:
2010 1-hour SO2 (Primary NAAQS). 79 FR 74818, 74821; 81
FR 296, at 302.
    \28\ 81 FR 296, 301-2.
---------------------------------------------------------------------------

    Our prior disapproval of interstate visibility transport for the
six NAAQS is currently stayed by the Fifth Circuit.\29\ We recognize
that because our prior disapproval of the Texas SIP submittals
addressing interstate visibility transport relied in part on our
determinations of the measures needed in Texas to ensure reasonable
progress in Oklahoma, the Fifth Circuit's stay of our previous action
complicates next steps to ensure that the visibility requirements of
CAA 110(a)(2)(D)(i)(II) are met. The Court's stay accordingly calls
into question whether our past disapprovals for interstate visibility
transport would stand. At the same time, we also note that we continue
to have an obligation to issue a FIP for the 1997 8-hour ozone and 1997
PM2.5 NAAQS as a result of our 2005 finding that Texas
failed to timely submit SIPs to address the interstate transport
visibility requirements. Given the uncertainties arising from the Fifth
Circuit's stay of our prior disapproval, we are now proposing to
reconsider the basis of our prior disapproval of Texas' SIP submittals
addressing the interstate visibility transport requirement for all six
NAAQS. We are now proposing to determine that Texas' SIP submittals
addressing interstate visibility transport for the six NAAQS are not
approvable because these submittals relied solely on Texas' Regional
Haze SIP to ensure that emissions from Texas did not interfere with
required measures in other states. Texas' Regional Haze SIP, in turn,
relied on the implementation of CAIR as an alternative to EGU BART for
SO2 and NOX. Specifically, we are proposing
disapproval of the following Texas SIP submittals insofar as they
address the interstate visibility transport requirement: April 4, 2008:
1997 8-hour Ozone, 1997 PM2.5 (24-hour and annual); May 1,
2008: 1997 8-hour Ozone, 1997 PM2.5 (24-hour and annual);
November 23, 2009: 2006 24-hour PM2.5; December 7, 2012:
2010 NO2; December 13, 2012: 2008 8-hour Ozone; May 6, 2013:
2010 1-hour SO2 (Primary NAAQS). Texas has not submitted a
SIP revision to remove reliance on CAIR for Regional Haze or interstate
visibility transport. As CAIR is no longer in effect and has been
replaced by CSAPR, we are proposing to find that Texas' Regional Haze
SIP does meet its interstate visibility transport obligations. As a
result, the Texas SIPs to address interstate visibility transport for
these six NAAQS continue to be unapprovable.
---------------------------------------------------------------------------

    \29\ July 15, 2016 Order in Texas v. EPA (Fifth Cir. Case No.
16-160118). The EPA's filed motion requesting voluntary partial
remand and continuation of the judicial stay for remanded parts of
the rule includes our prior disapproval of Texas' SIPs concerning
interstate visibility transport. This motion is currently pending
disposition.
---------------------------------------------------------------------------

    We are proposing a FIP to cure the deficiencies in Texas' Regional
Haze Program concerning EGU BART. This FIP will replace reliance on
CAIR with reliance on CSAPR to meet the requirements for EGU BART for
NOX in Texas. The FIP will also address Texas EGU BART for
SO2 and PM on a source-specific basis. With the absence of
CSAPR coverage for SO2, we must reevaluate what is needed in
Texas to address interstate visibility transport. Our proposed FIP to
address Texas EGU BART achieves significant reductions of
SO2, which exceed the reductions initially assumed for Texas
under either CAIR or CSAPR. In addition, our proposed FIP achieves
reductions at large sources of SO2 emissions (e.g.,
Monticello, Martin Lake and Big Brown), that have significant impacts
on

Class I areas in nearby states. The BART FIP requires controls on many
but not all of the sources that were controlled in our previous partial
FIP for Texas Regional Haze. The EGU BART FIP also includes control
requirements at some additional sources not controlled in our previous
action on Texas Regional Haze.
    We are proposing to find that our proposed EGU BART FIP is adequate
to prevent interference with measures required to protect visibility in
other states for the first planning period.\30\ We, therefore, propose
that the measures in our proposed FIP to address Texas EGU BART will
fully address Texas' interstate visibility transport obligations for
the six NAAQS (1997 8-hour ozone, 1997 PM2.5, 2006
PM2.5, 2008 8-hour ozone, 2010 1-hour NO2, and
2010 1-hour SO2). We also propose that reliance on CSAPR for
EGU NOX BART is appropriate to ensure NOX
emissions from Texas EGUs do not interfere with other states' measures
to protect visibility. We are proposing this action based on the
reasoning that our BART FIP will achieve more emission reductions than
projected under CAIR or CSAPR and the reductions are occurring at
sources that have particularly large impacts on Class I areas outside
of Texas. To the extent our previous final action concerning Texas
Regional Haze is remanded by a Court or otherwise reconsidered in the
future, we may revisit whether controls in the EGU BART FIP are
adequate to address interstate visibility transport requirements.
Nonetheless, we are here proposing that the proposed EGU BART FIP
measures will be adequate to address interstate visibility transport
based on current information. This proposal concerning the adequacy of
the proposed FIP remedy does not depend on our earlier action on the
Texas Regional Haze SIP or hinge on its disposition, nor does it
foreclose that we may reexamine visibility transport concerns under
potential scenarios where we have a responsibility to take new
action.\31\
---------------------------------------------------------------------------

    \30\ This proposed FIP for interstate visibility transport is
premised on the interpretation that this requirement can be
addressed even when a Regional Haze SIP is not fully approved and
the FIP does not purport to correct all Regional Haze SIP
deficiencies. See e.g. 76 FR 52388 (August 22, 2011); 76 FR 22036
(April 20, 2011); and 78 FR 14681 (March 7, 2013); see also, 2013 i-
SIP Guidance, at page 34 (stating that EPA may find it appropriate
to supplement the i-SIP Guidance regarding the relationship between
Regional Haze SIPs and interstate visibility transport for future
planning periods).
    \31\ See e.g. 78 FR 14681, 14685.
---------------------------------------------------------------------------

    We encourage Texas to consider adopting additional SIP provisions
that would allow the EPA to fully approve the Regional Haze SIP and
thus to withdraw the FIP and approve Texas' SIP with respect to
interstate visibility transport. Texas may also elect to satisfy
interstate visibility transport by providing, as an alternative to
relying on its Regional Haze SIP alone, a demonstration that emissions
within its jurisdiction do not interfere with other states' plans to
protect visibility.\32\
---------------------------------------------------------------------------

    \32\ 2013 i-SIP Guidance, at pages 34-35.
---------------------------------------------------------------------------

C. Our Obligation To Promulgate a FIP

    Under section 110(c) of the CAA, whenever we disapprove a mandatory
SIP submission in whole or in part, we are required to promulgate a FIP
within 2 years unless we approve a SIP revision correcting the
deficiencies before promulgating a FIP. Specifically, CAA section
110(c) provides that the Administrator shall promulgate a FIP within 2
years after the Administrator disapproves a state implementation plan
submission ``unless the State corrects the deficiency, and the
Administrator approves the plan or plan revision, before the
Administrator promulgates such Federal implementation plan.'' \33\ The
term ``Federal implementation plan'' is defined in Section 302(y) of
the CAA in pertinent part as a plan promulgated by the Administrator to
correct an inadequacy in a SIP.
---------------------------------------------------------------------------

    \33\ EPA additionally has the authority to promulgate a FIP any
time after finding that ``a State has failed to make a required
submission'' of a SIP. CAA section 110(c)(1)(A); 42 U.S.C.
7410(c)(1)(a).
---------------------------------------------------------------------------

    Beginning in 2012, following the limited disapproval of the Texas
Regional Haze SIP, EPA had the authority and obligation to promulgate a
FIP to address BART for Texas EGUs for NOX and
SO2. In proposing to disapprove the Regional Haze SIP
component that sought to address the PM BART requirement for Texas
EGUs, we also have the obligation to promulgate a PM BART FIP to
address the deficiency. Texas has not addressed the EGU BART
disapproval, and that requirement is now significantly overdue.\34\ We
are accordingly empowered and required by the CAA to make
determinations and promulgate a FIP to ensure the BART requirement for
Texas EGUs is satisfied.
---------------------------------------------------------------------------

    \34\ The Texas Regional Haze SIP stated, ``The TCEQ will take
appropriate action if CAIR is not replaced with a system that the US
EPA considers to be equivalent to BART.'' BART determinations were
due in SIP submissions on December 17, 2007, 40 CFR 51.308(b),
putting them on a timeline for controls by 2014 (considering the
deadline for SIP action at CAA section 110(k)(2) and allowing five
years for installation of BART controls). Additional delay of any
amount is not appropriate and not consistent with the law.
---------------------------------------------------------------------------

    Adding to this background, beginning with our January 5, 2016
disapproval of Texas SIP provisions regarding interstate visibility
transport, we obtained the authority and obligation to promulgate a FIP
to correct the deficiencies relating to that CAA requirement.\35\ As
with the BART requirement, we lack a SIP revision that would have any
potential to correct the deficiency, necessitating that we now take
action under FIP authority.
---------------------------------------------------------------------------

    \35\ Additionally, we continue to have authority to issue a FIP
to address interstate visibility transport for 1997 8-hour ozone and
1997 PM2.5 due to our 2005 finding that Texas failed to
submit SIPs to address interstate transport for these NAAQS under
CAA section 110(a)(2)(D)(i). 70 FR 21147.
---------------------------------------------------------------------------

III. Our Proposed BART Analyses for SO2 and PM

    In our previous action,\36\ we determined that due to the CSAPR
remand, it was not appropriate at that time to rely on CSAPR as an
alternative to SO2 and NOX BART for EGUs in
Texas. As a consequence, action to satisfy the overdue requirement to
address BART for EGUs in the state of Texas was further delayed.\37\ In
this proposal, we are proposing that CSAPR, once fully revised to
address the D.C. Circuit's remand, provides a basis for satisfying EGU
BART obligations for NOX alone. It remains the case that we
cannot rely on CSAPR as an alternative to SO2 BART for Texas
EGUs as further confirmed by our proposed action to remove Texas from
the annual NOX and SO2 control programs. Thus, we
have the obligation to consider source-specific requirements for Texas
EGUs consistent with the BART Guidelines for SO2 BART.
---------------------------------------------------------------------------

    \36\ See the discussion beginning on 81 FR 301 (January 5,
2016).
    \37\ Id. at 346.
---------------------------------------------------------------------------

    Because the component of the Texas Regional Haze SIP regarding the
PM BART requirement for EGUs has not been acted on, we have the
responsibility under CAA section 110(k) to evaluate the submission and
take action to approve or disapprove it. The SIP determinations for PM
were based on modeling that was conducted by examining visibility
impairment due to PM emissions alone, based on the assumption that the
state would be participating in CAIR for SO2 and
NOX and thereby having BART coverage for those pollutants.
The Texas Regional Haze SIP had concluded that no PM BART controls for
EGUs were appropriate, because modeling assessment of PM impacts alone
showed their impacts to be too small to warrant control consideration.
But Texas' screening analysis is no longer reliable or accurate because
of the invalid assumption that source-by-source BART for either
SO2 or NOX would not be

required. In order to appropriately evaluate the BART requirements for
EGUs, the visibility impacts from all pollutants must be studied,
including PM emissions. Texas' PM BART analysis for EGUs does not do
this.\38\
---------------------------------------------------------------------------

    \38\ Texas' Regional Haze SIP determined whether its sources
should be subject to review for PM controls by only looking at the
impact of PM emissions on visibility. This approach is only
appropriate when a state satisfies the requirements for BART for
SO2 and NOX with an alternative measure.
Additionally, as reflected in our TSD on the identification of BART-
Eligible Sources, the Texas SIP neglected to identify several BART-
eligible sources; this also shows error in the state's PM BART
demonstration and conclusions, and it constitutes grounds for the
proposed partial SIP disapproval for PM BART.
---------------------------------------------------------------------------

    Accordingly, we are proposing to disapprove the portion of the
Texas Regional Haze SIP that determined that all Texas EGUs screen out
of the BART requirement for PM. The basis for the proposed disapproval
is the SIP determination's assumption that EGUs would have coverage for
SO2 and NOX BART under an alternative
measure.\39\ Since that assumption is not valid, the technical
determinations regarding PM BART cannot be approved. Following the
directions of the BART Guidelines on how to identify sources ``subject
to BART,'' we have looked at all visibility impairing pollutants from
EGUs that are BART-eligible. Our proposed FIP therefore seeks to fill
that regulatory gap by assessing BART for Texas EGUs for visibility
impairing pollutants other than NOX, i.e., SO2
and PM.
---------------------------------------------------------------------------

    \39\ The requirements for ``emissions trading programs or other
alternative measures'' that may be implemented rather than requiring
BART are provided at 40 CFR 51.308(e)(2).
---------------------------------------------------------------------------

A. Identification of BART-Eligible Sources

    The BART Guidelines set forth the steps for identifying whether the
source is a BART-eligible source: \40\
---------------------------------------------------------------------------

    \40\ 70 FR 39158 (July 6, 2005).

    Step 1: Identify the emission units in the BART categories,
    Step 2: Identify the start-up dates of those emission units, and
    Step 3: Compare the potential emissions to the 250 ton/yr
cutoff.

    Following our 2016 final action on the March 31, 2009 Texas RH SIP,
we began the process of generating additional technical information and
analysis in order to address the above three steps in our BART-
eligibility proposal. We started with Texas' facility-specific listing
of BART-eligible EGU sources and removed sources we verified had
retired. We then gathered additional information from (1) our authority
under Section 114(a) of the CAA to request information from potential
BART-eligible sources, and (2) the U.S. Energy Information
Administration (EIA). We then converted Texas' facility-specific BART-
eligible list to a unit-specific BART-eligible list and verified the
BART-eligibility of each unit. The following is a list of units we
propose have satisfied the above three steps and are BART-eligible:
\41\
---------------------------------------------------------------------------

    \41\ See our BART FIP TSD for more information concerning how we
selected the units we are proposing are BART-eligible and other
details concerning our proposed BART determinations.

              Table 1--Summary of BART-Eligibility Analysis
------------------------------------------------------------------------
                   Facility                               Unit
------------------------------------------------------------------------
Barney M. Davis (Talen/Topaz)................  1.
Big Brown (Luminant).........................  1.
Big Brown (Luminant).........................  2.
Cedar Bayou (NRG)............................  CBY1.
Cedar Bayou (NRG)............................  CBY2.
Coleto Creek (Engie).........................  1.
Dansby (City of Bryan).......................  1.
Decker Creek (Austin Energy).................  1.
Decker Creek (Austin Energy).................  2.
Fayette (LCRA)...............................  1.
Fayette (LCRA)...............................  2.
Graham (Luminant)............................  2.
Greens Bayou (NRG)...........................  5.
Handley (Exelon).............................  3.
Handley (Exelon).............................  4.
Handley (Exelon).............................  5.
Harrington Station (Xcel)....................  061B.
Harrington Station (Xcel)....................  062B.
J T Deely (CPS Energy).......................  1.
J T Deely (CPS Energy).......................  2.
Jones Station (Xcel).........................  151B.
Jones Station (Xcel).........................  152B.
Knox Lee Power Plant (AEP)...................  5.
Lake Hubbard (Luminant)......................  1.
Lake Hubbard (Luminant)......................  2.
Lewis Creek (Entergy)........................  1.
Lewis Creek (Entergy)........................  2.
Martin Lake (Luminant).......................  1.
Martin Lake (Luminant).......................  2.
Martin Lake (Luminant).......................  3.
Monticello (Luminant)........................  1.
Monticello (Luminant)........................  2.
Monticello (Luminant)........................  3.
Newman (El Paso Electric)....................  2.
Newman (El Paso Electric)....................  3.
Newman (El Paso Electric)....................  4.
Nichols Station (Xcel).......................  143B.
O W Sommers (CPS Energy).....................  1.
O W Sommers (CPS Energy).....................  2.
Plant X (Xcel)...............................  4.
Powerlane (City of Greenville)...............  ST1.
Powerlane (City of Greenville)...............  ST2.
Powerlane (City of Greenville)...............  ST3.
R W Miller (Brazos Elec. Coop)...............  1.
R W Miller (Brazos Elec. Coop)...............  2.
R W Miller (Brazos Elec. Coop)...............  3.
Sabine (Entergy).............................  2.
Sabine (Entergy).............................  3.
Sabine (Entergy).............................  4.
Sabine (Entergy).............................  5.
Sim Gideon (LCRA)............................  1.
Sim Gideon (LCRA)............................  2.
Sim Gideon (LCRA)............................  3.
Spencer (City of Garland)....................  4.
Spencer (City of Garland)....................  5.
Stryker Creek (Luminant).....................  ST2.
Trinidad (Luminant)..........................  6.
Ty Cooke (City of Lubbock)...................  1.
Ty Cooke (City of Lubbock)...................  2.
V H Braunig (CPS Energy).....................  1.
V H Braunig (CPS Energy).....................  2.
V H Braunig (CPS Energy).....................  3.
W A Parish (NRG).............................  WAP4.
W A Parish (NRG).............................  WAP5.
W A Parish (NRG).............................  WAP6.
Welsh Power Plant (AEP)......................  1.
Welsh Power Plant (AEP)......................  2.
Wilkes Power Plant (AEP).....................  1.
Wilkes Power Plant (AEP).....................  2.
Wilkes Power Plant (AEP).....................  3.
------------------------------------------------------------------------

    The final step in identifying a ``BART-eligible source'' is to use
the information from the previous three steps to identify the
collection of emissions units that comprise the BART-eligible source.

B. Identification of Sources That Are Subject to BART

    Following our compilation of the BART-eligible sources in Texas, we
examined whether these sources cause or contribute to visibility
impairment in nearby Class I areas.\42\ For those sources that are not
reasonably anticipated to cause or contribute to any visibility
impairment in a Class I area, a BART determination is not required.
Those sources are determined to be not subject-to-BART. Sources that
are reasonably anticipated to cause or contribute to any visibility
impairment in a Class I area are determined to be subject-to-BART. For
each source subject to BART, 40 CFR 51.308(e)(1)(ii)(A) requires that
states (or EPA, in the case of a FIP) identify the level of control
representing BART after considering the factors set out in CAA section
169A(g). The BART guidelines discuss several approaches available to
exempt sources from the BART determination process, including modeling
individual sources and the use of model plants. To determine which
sources are anticipated to contribute to visibility impairment the BART
guidelines state that CALPUFF or another appropriate model can be used
to predict the visibility impacts from a single source at a Class I
area. We employed a four-fold strategy in determining which units
should or should not be subject to BART. A flowchart of the analysis
along with a detailed discussion of the subject-to-BART screening
analysis is provided in

the BART Screening TSD.\43\ We summarize the methodology and results of
this analysis here.
---------------------------------------------------------------------------

    \42\ See 40 CFR part 51, Appendix Y, III, How to Identify
Sources ``Subject to BART''.
    \43\ See our TSD, ``Our Strategy for Assessing which Units are
Subject to BART for the Texas Regional Haze BART Federal
Implementation Plan (BART Screening TSD)'' in our docket.
---------------------------------------------------------------------------

    First, we examined whether any of the BART-eligible units should be
eliminated from consideration based on the standard model plant
exemptions described in the BART Guidelines.\44\ Second, we created
specific model plants between sources and nearby Class I areas and
conducted CALPUFF modeling to evaluate a number of sources for
exemption. Third, we performed stand-alone, source specific CALPUFF
modeling on a number of units to determine if their visibility impacts
were large enough to identify them as being subject to BART. Fourth,
for those remaining units outside of the CALPUFF model's range, we
contracted to have CAMx modeling performed to determine if their
visibility impacts were large enough to merit their being subject to
BART. These steps are further described below.
---------------------------------------------------------------------------

    \44\ See the discussion beginning on 70 FR 39104, 39162 (July 6,
2005) [40 CFR part 51, App. Y].
---------------------------------------------------------------------------

    For states using modeling to determine the applicability of BART to
single sources, the BART Guidelines note that the first step is to set
a contribution threshold to assess whether the impact of a single
source is sufficient to cause or contribute to visibility impairment at
a Class I area. The BART Guidelines preamble advises that, ``for
purposes of determining which sources are subject to BART, States
should consider a 1.0 deciview change or more from an individual source
to ``cause'' visibility impairment, and a change of 0.5 deciviews to
``contribute'' to impairment.'' \45\ It further advises that ``States
should have discretion to set an appropriate threshold depending on the
facts of the situation,'' but ``[a]s a general matter, any threshold
that you use for determining whether a source `contributes' to
visibility impairment should not be higher than 0.5 dv,'' and describes
situations in which states may wish to exercise their discretion to set
lower thresholds, mainly in situations in which a large number of BART-
eligible sources within the State and in proximity to a Class I area
justify this approach. We do not believe that the sources under
consideration in this rule, most of which are not in close proximity to
a Class I area, merit the consideration of a lesser contribution
threshold. Therefore, our analysis employs a contribution threshold of
0.5 deciviews.
---------------------------------------------------------------------------

    \45\ 70 FR at 39118.
---------------------------------------------------------------------------

1. Our Use of the Standard BART Model Plant Exemption
    As the BART Guidelines note:

    [W]e believe that a State that has established 0.5 deciviews as
a contribution threshold could reasonably exempt from the BART
review process sources that emit less than 500 tons per year of
NOX or SO2 (or combined NOX and
SO2), as long as these sources are located more than 50
kilometers from any Class I area; and sources that emit less than
1000 tons per year of NOX or SO2 (or combined
NOX and SO2) that are located more than 100
kilometers from any Class I area. You do, however, have the option
of showing other thresholds might also be appropriate given your
specific circumstances.\46\
---------------------------------------------------------------------------

    \46\ 70 FR at 39163 [40 CFR part 51, App. Y].

    We applied the standard BART model plant exemption described above
to the following facilities, exempting them from further analysis:

            Table 2--Standard BART Model Plant Exempt Sources
------------------------------------------------------------------------
                Facility                              Units
------------------------------------------------------------------------
Dansby (City of Bryan).................  1.
Greens Bayou (NRG).....................  5.
Nichols Station (Xcel).................  143B.
Plant X (Xcel).........................  4.
Powerlane (City of Greenville).........  ST1, ST2 & ST3.
Spencer (City of Garland)..............  4 & 5.
Trinidad (Luminant)....................  6.
Ty Cooke (City of Lubbock).............  1 & 2.
------------------------------------------------------------------------

2. Our Extension of the BART Model Plant Exemption
    As the BART Guidelines note, the standard BART model plant
exemption can be extended to values other than the 500 tons/50 km and
1,000 tons/100 km scenarios discussed in the previous section. The BART
Guidelines explain that: ``you may find based on representative plant
analyses that certain types of sources are not reasonably anticipated
to cause or contribute to visibility impairment. To do this, you may
conduct your own modeling to establish emission levels and distances
from Class I areas on which you can rely to exempt sources with those
characteristics.'' \47\
---------------------------------------------------------------------------

    \47\ 70 FR at 39163 [40 CFR part 51, App. Y].
---------------------------------------------------------------------------

    Modeling analyses of representative plants are used to reflect
groupings of specific sources with important common characteristics. We
conducted CALPUFF modeling to establish emission levels and distances
from Class I areas on which we could rely to exempt sources with those
characteristics. In this approach, a hypothetical facility (``model
plant'') is located between a group of BART-eligible sources and a
Class I area. Predominant wind patterns and elevation are considered in
locating the model plant such that conditions that would be anticipated
to transport pollution from the group of BART-eligible sources to the
Class I area are consistent with conditions anticipated to transport
pollution from the model plant to the Class I area. The visibility
impacts from this model plant are modeled utilizing CALPUFF following
the protocol described in the BART Screening TSD. Model plant emissions
are adjusted such that the modeled visibility impact (maximum of 98th
percentile values for 2001, 2002, and 2003) is below the screening
threshold of 0.5 dv. For each model plant, the Q/d value is calculated
as the annual emissions (combined NOX and SO2
emissions) divided by distance to the Class I area (km) resulting in a
critical Q/d value. The Q/d value for each BART-eligible source is
calculated based on annual emissions based on the maximum actual 24-hr
emission rate and distance to the Class I area and is then compared to
the critical Q/d value. For a BART-eligible source with a lower Q/d
value than the critical Q/d, it is reasonably anticipated that the
visibility impact from the BART-eligible source is lower than the model
plant and therefore below the screening threshold and not subject to
BART. See the BART Screening TSD for additional discussion and source-
specific information used in this model plant screening analysis. By
this extension of the BART model plant exemption, we identified the
following additional facilities that can be exempted from further
analysis:

            Table 3--Extended BART Model Plant Exempt Sources
------------------------------------------------------------------------
                Facility                              Units
------------------------------------------------------------------------
Barney M. Davis (Talen/Topaz)..........  1.
Cedar Bayou (NRG)......................  CBY1 & CBY2.
Decker Creek (Austin...................  1 & 2.
Energy)................................
Lewis Creek (Entergy)..................  1 & 2.
Sabine (Entergy).......................  2, 3, 4 & 5.
Sim Gideon (LCRA)......................  1, 2 & 3.
V H Braunig (CPS Energy)...............  1, 2 & 3.
------------------------------------------------------------------------

3. Our Use of CALPUFF Modeling To Exempt Sources From Being Subject to
BART
    Those sources that did not screen out using the model plant
approach were modeled directly with CALPUFF if they were in a range of
when CALPUFF has

been previously used. Historically CALPUFF has been used at distances
up to approximately 400 km. The maximum 98th percentile impact from the
modeled years (calculated based on annual average natural background
conditions) was compared with the 0.5 dv screening threshold following
the modeling protocol described in the BART screening TSD. The BART
Guidelines recommend that states use the 24-hour average actual
emission rate from the highest emitting day of the meteorological
period modeled, unless this rate reflects periods of start-up,
shutdown, or malfunction. The maximum 24-hour emission rate (lb/hr) for
NOX and SO2 from the 2000-2004 baseline period
for each source was identified through a review of the daily emission
data for each BART-eligible unit from EPA's Air Markets Program
Data.\48\ For some BART-eligible sources, evaluation of baseline
emissions revealed evidence of the installation of NOX
control technology during the baseline period. For those sources, the
maximum emission rate was updated to reflect the identified maximum
emission rate from the post-control portion of the baseline period.
Because daily emissions are not available for PM, the annual average
emission rate was doubled to approximate the 24-hr maximum emission
rate for PM. See the BART Screening TSD for additional discussion and
source-specific information used in the CALPUFF modeling for this
portion of the screening analysis. With the use of CALPUFF modeling
results, we identified the following additional facilities that can be
exempted from further analysis:
---------------------------------------------------------------------------

    \48\ http://ampd.epa.gov/ampd/.

                  Table 4--CALPUFF BART Exempt Sources
------------------------------------------------------------------------
                Facility                              Units
------------------------------------------------------------------------
Handley (Exelon).......................  3, 4 & 5.
Jones (Xcel)...........................  151B & 152B.
Lake Hubbard (Luminant)................  1 & 2.
Knox Lee (AEP).........................  5.
R W Miller (Brazos Elec. Coop).........  1, 2 & 3.
------------------------------------------------------------------------

    Based on these CALPUFF screening analyses using model plant
approaches and direct modeling, the following gas \49\/fuel oil fired
facilities did not screen out from being subject to BART: Newman,
Stryker, Graham, and Wilkes. None of the coal fired facilities screened
out in our CALPUFF modeling for the facilities within CALPUFF range.
---------------------------------------------------------------------------

    \49\ When we use the term ``gas,'' we mean ``pipeline quality
natural gas.''
---------------------------------------------------------------------------

    4. Our Use of CAMx Modeling To Exempt Sources From Being Subject to
BART
    Some of the BART-eligible sources in Texas are geographically
distant from a Class I area, yet have high enough emissions that they
may significantly impact visibility at Class I areas in Texas and
surrounding states. However, the use of CALPUFF is not recommended for
distances much greater than 300 km, and has typically not been used at
distances more than approximately 400 km. To determine which sources
are anticipated to contribute to visibility impairment the BART
guidelines state that CALPUFF or another appropriate model can be used
to predict the visibility impacts from a single source at a Class I
area. CAMx provides a scientifically defensible platform for assessment
of visibility impacts over a wide range of source-to-receptor
distances. CAMx 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. The CAMx PM
Source Apportionment Technology (PSAT) modeling was conducted for those
BART-eligible sources that have large SO2 emissions.\50\ In
2006/2007, the TCEQ developed a modeling protocol and analysis using
CAMx with the same Plume in Grid and PSAT techniques to evaluate
visibility impacts from non-EGU BART sources, as well as to evaluate
VOC and PM impacts from all BART-eligible sources to inform the 2009
Texas Regional Haze SIP.51 52 This modeling protocol was
reviewed by the TCEQ, EPA and FLM representatives specialized in air
quality analyses and BART prior to performing the analysis and
submission of their regional haze SIP. Our subject-to-BART screening
modeling for EGU-sources using CAMx is consistent with the protocol
developed and utilized by Texas in their regional haze SIP. We are
using more recent model versions with updated science in our analysis.
---------------------------------------------------------------------------

    \50\ CAMx results were also obtained and add to our basis of
information for coal-fired facilities that have CALPUFF results.
    \51\ See TX RH SIP Appendix 9-5, ``Screening Analysis of
Potential BART-Eligible Sources in Texas''; Revised Draft Final
Modeling Protocol Screening Analysis of Potentially BART-Eligible
Sources in Texas, Environ Sept. 27, 2006; and Guidance for the
Application of the CAMx Hybrid Photochemical Grid Model to Assess
Visibility Impacts of Texas BART Sources at Class I Areas, Environ
December 13, 2007 all available in the docket for this action.
    \52\ We approved Texas' subject-to-BART analysis for non-EGU
sources which relied on this CAMx modeling in our January 5, 2016
rulemaking (81 FR 296).
---------------------------------------------------------------------------

    Consistent with the BART guidelines and our CALPUFF modeling, for
the selected BART-eligible sources we used the maximum actual 24-hr
emission rates for NOX and SO2 from the 2000-2004
baseline period from EPA's Air Markets Program Data \53\ and modeled
these emission rates as constant emission rates for the entire modeled
year. For some of the modeled BART-eligible sources, evaluation of
baseline emissions revealed evidence of installation of NOX
control technology during the baseline period. For those sources the
maximum emission rate was identified from the post-control portion of
the baseline period. Because daily emissions are not available for PM,
the annual average emission rate was doubled to approximate the 24-hr
maximum emission rate for PM. A BART-eligible source that is shown not
to contribute significantly to visibility impairment at any of the
Class I areas using CAMx modeling may be excluded from further steps in
the BART process. The maximum modeled impact for each source
(calculated based on annual average natural background conditions) was
compared to the 0.5 dv contribution threshold. See the BART Screening
TSD for additional details on the CAMx modeling performed and the model
inputs used. The table below summarizes the results of the CAMx
screening analysis. As shown in the table below, all sources analyzed
with CAMx modeling had impacts greater than 0.5 dv at one or more Class
I areas. The most impacted Class I areas based on these results are
Wichita Mountains National Wildlife Refuge in Oklahoma (WIMO), Caney
Creek Wilderness Area in Arkansas (CACR), and Salt Creek Wilderness
Area in New Mexico (SACR). CAMx modeled impacts at single locations for
these sources (maximum impact day) ranged from 0.845 dv to 10.498 dv.
---------------------------------------------------------------------------

    \53\ http://ampd.epa.gov/ampd/.

                                                  Table 5--CAMx BART Screening Source Analysis Results
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Number of       Number of
                                                          Most impacted Class I   Maximum  delta-                          modeled days    modeled days
       BART-eligible source                Units                   area                 dv          Less than  0.5 dv?      over 0.5 dv     over 1.0 dv
                                                                                \2\             \2\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Big Brown........................  1 & 2...............  WIMO...................           4.017  No....................              65              33
Coleto Creek.....................  1...................  WIMO...................           0.845  No....................               9               0
Fayette Power....................  1 & 2...............  CACR...................           1.894  No....................              26               9
Harrington.......................  061B & 062B.........  SACR...................           5.288  No....................              13               5
Martin Lake......................  1, 2, & 3...........  CACR...................           6.651  No....................             141              99
Monticello.......................  1, 2, & 3...........  CACR...................          10.498  No....................             152             111
Calaveras........................  J T Deely 1 & 2, OW   WIMO...................           1.513  No....................              47               6
                                    Sommers 1 & 2.
W A Parish.......................  WAP4, WAP5 & WAP6...  CACR...................           3.177  No....................              54              22
Welsh \1\........................  1 & 2...............  CACR...................           4.576  No....................              92              39
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Welsh unit 2 has recently shutdown. We note that baseline impacts from unit 1 alone are 2.343 dv at Caney Creek.
\2\ Number of days over 0.5 or 1.0 dv at the most impacted Class I area.

5. Summary of Sources that are Subject to BART
    Based on the four methodologies described above, the BART-eligible
sources in the table below have been determined to cause or contribute
to visibility impairment at a nearby Class I area, and we therefore
propose to find the sources are subject-to-BART. They are subject to
review for visibility impairing pollutants other than
NOX.\54\ Foremost, they are subject to SO2 BART,
the visibility impairing pollutant that is the main contributor to the
regional haze problem at Class I areas in Texas and neighboring states.
The sources are also subject to review for source-specific BART
requirements for PM.
---------------------------------------------------------------------------

    \54\ The NOX BART requirement for these EGU sources
is not addressed by source-specific limits in this proposal.
According to our proposal, participation in CSAPR, in its updated
form, would serve as a BART alternative, dispensing with the need
for source-specific BART determinations and requirements for
NOX.

           Table 6--Summary: Sources That are Subject-to-BART
------------------------------------------------------------------------
             Facility                              Units
------------------------------------------------------------------------
Big Brown........................  1 & 2.
Coleto Creek.....................  1.
Fayette Power....................  1 & 2.
Harrington.......................  061B & 062B.
Martin Lake......................  1, 2 & 3.
Monticello.......................  1, 2 & 3.
Calaveras........................  J T Deely 1 & 2, O W Sommers 1 & 2.
W A Parish.......................  WAP4, WAP5 & WAP6.
Welsh............................  1 & 2*.
Stryker..........................  ST2.
Graham...........................  2.
Wilkes...........................  1, 2 & 3.
Newman...........................  2, 3 & 4.
------------------------------------------------------------------------
* Welsh Unit 2 retired in April, 2016.

C. Our BART Five Factor Analyses

    The purpose of the BART analysis is to identify and evaluate the
best system of continuous emission reduction based on the BART
Guidelines.\55\ In determining BART, a state, or EPA when promulgating
a FIP, must consider the five statutory factors in section 169A of the
CAA: (1) The costs of compliance; (2) the energy and nonair quality
environmental impacts of compliance; (3) any existing pollution control
technology in use at the source; (4) the remaining useful life of the
source; and (5) the degree of improvement in visibility which may
reasonably be anticipated to result from the use of such technology.
See also 40 CFR 51.308(e)(1)(ii)(A). This is commonly referred to as
the ``BART five factor analysis.'' The BART Guidelines break the
analyses of these requirements down into five steps: \56\
---------------------------------------------------------------------------

    \55\ See July 6, 2005 BART Guidelines, 40 CFR part 51, Regional
Haze Regulations and Guidelines for Best Available Retrofit
Technology Determinations.

    \56\ 70 FR 39104, 39164 (July 6, 2005) [40 CFR part 51, App. Y].
---------------------------------------------------------------------------

    STEP 1--Identify All Available Retrofit Control Technologies,
    STEP 2--Eliminate Technically Infeasible Options,
    STEP 3--Evaluate Control Effectiveness of Remaining Control
Technologies,
    STEP 4--Evaluate Impacts and Document the Results, and
    STEP 5--Evaluate Visibility Impacts.

    The following sections treat these steps individually for
SO2. We are combining these steps into one section in our
assessment of PM BART that follows the SO2 sections.
1. Steps 1 and 2: Technically Feasible SO2 Retrofit Controls
    The BART Guidelines state that in identifying all available
retrofit control options,

    [Y]ou must identify the most stringent option and a reasonable
set of options for analysis that reflects a comprehensive list of
available technologies. It is not necessary to list all permutations
of available control levels that exist for a given technology--the
list is complete if it includes the maximum level of control each
technology is capable of achieving.\57\
---------------------------------------------------------------------------

    \57\ 70 FR at 39164, fn 12 [40 CFR part 51, App. Y]

    Adhering to this, we will identify a reasonable set of
SO2 control options, including those that cover the maximum
level of control each technology is capable of achieving. In the course
of that task, we will note whether any of these technologies are
technically infeasible.
    The subject-to-BART units identified in Table 6 can be organized
into four broad categories, based on their fuel type and the potential
types of SO2 controls that could be retrofitted: (1) Coal-
fired EGUs with no SO2 scrubber, (2) coal-fired EGUs with
underperforming SO2 scrubbers, (3) gas-fired EGUs that do
not burn oil, and (4) gas-fired EGUs that occasionally burn fuel oil.
This classification is represented below:

                                           Table 7--Subject to BART Fuel Types and Potential SO2 BART Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Coal  underperforming
            Facility                       Unit              Coal no scrubber             scrubber                Gas no oil           Gas burns oil
--------------------------------------------------------------------------------------------------------------------------------------------------------
Big Brown (Luminant)............  1.....................  X.....................  ........................  .....................  .....................
Big Brown (Luminant)............  2.....................  X.....................  ........................  .....................  .....................
Coleto Creek (Engie)............  1.....................  X.....................  ........................  .....................  .....................
Fayette (LCRA) *................  1.....................  ......................  ........................  .....................  .....................
Fayette (LCRA) *................  2.....................  ......................  ........................  .....................  .....................
Graham (Luminant)...............  2.....................  ......................  ........................  .....................  X
Harrington Station (Xcel).......  061B..................  X.....................  ........................  .....................  .....................
Harrington Station (Xcel).......  062B..................  X.....................  ........................  .....................  .....................
J T Deely (CPS Energy)..........  1.....................  X.....................  ........................  .....................  .....................
J T Deely (CPS Energy)..........  2.....................  X.....................  ........................  .....................  .....................
Martin Lake (Luminant)..........  1.....................  ......................  X.......................  .....................  .....................
Martin Lake (Luminant)..........  2.....................  ......................  X.......................  .....................  .....................
Martin Lake (Luminant)..........  3.....................  ......................  X.......................  .....................  .....................
Monticello (Luminant)...........  1.....................  X.....................  ........................  .....................  .....................
Monticello (Luminant)...........  2.....................  X.....................  ........................  .....................  .....................
Monticello (Luminant)...........  3.....................  ......................  X.......................  .....................  .....................
Newman (El Paso Electric).......  2.....................  ......................  ........................  .....................  X
Newman (El Paso Electric).......  3.....................  ......................  ........................  .....................  X
Newman (El Paso Electric).......  4.....................  ......................  ........................  X....................  .....................
O W Sommers (CPS Energy)........  1.....................  ......................  ........................  .....................  X
O W Sommers (CPS Energy)........  2.....................  ......................  ........................  .....................  X
Stryker Creek (Luminant)........  ST2...................  ......................  ........................  .....................  X
W A Parish (NRG)................  WAP4..................  ......................  ........................  X....................  .....................
W A Parish (NRG)................  WAP5..................  X.....................  ........................  .....................  .....................
W A Parish (NRG)................  WAP6..................  X.....................  ........................  .....................  .....................
Welsh Power Plant (AEP).........  1.....................  X.....................  ........................  .....................  .....................
Wilkes Power Plant (AEP)........  1.....................  ......................  ........................  .....................  X
Wilkes Power Plant (AEP)........  2.....................  ......................  ........................  X....................  .....................
Wilkes Power Plant (AEP)........  3.....................  ......................  ........................  X....................  .....................
--------------------------------------------------------------------------------------------------------------------------------------------------------
* The Fayette units have high performing wet Flue Gas Desulfurization scrubbers in place.

    For the coal-fired EGUs without an existing scrubber, we have
identified four potential control technologies: (1) Coal pretreatment,
(2) Dry Sorbent Injection (DSI), (3) Spray Dryer Absorber (SDA), and
(4) wet Flue Gas Desulfurization (FGD.) For the coal-fired EGUs with an
existing underperforming scrubber we will examine whether that scrubber
can be upgraded.
    Gas-fired EGUs that do not burn oil have inherently very low
SO2 emissions and there are no known SO2 controls
that can be evaluated.
    For gas-fired units that occasionally burn fuel oil, we will follow
the BART Guidelines recommendations for oil-fired units: ``For oil-
fired units, regardless of size, you should evaluate limiting the
sulfur content of the fuel oil burned to 1 percent or less by weight.''
\58\ In addition, we will also evaluate the potential for post
combustion SO2 controls for these units.
---------------------------------------------------------------------------

    \58\ 70 FR 39171 (July 6, 2005) [40 CFR 51, App. Y].
---------------------------------------------------------------------------

a. Identification of Technically Feasible SO2 Retrofit
Control Technologies for Coal-Fired Units
    Available SO2 control technologies for coal-fired EGUs
consist of either pretreating the coal in order to improve its
qualities, or treating the flue gas through the installation of either
DSI or some type of scrubbing technology.
Coal Pretreatment
    Coal pretreatment, or coal upgrading, has the potential to reduce
emissions by reducing the amount of coal that must be burned in order
to result in the same heat input to the boiler. Coal pretreatment
broadly falls into two categories: coal washing and coal drying.
    Coal washing is often described as preparation (for particular
markets) or cleaning (by reducing the amount of mineral matter and/or
sulphur in the product coal).\59\ Washing operations are carried out
mainly on bituminous and anthracitic coals, as the characteristics of
subbituminous coals and lignite (brown coals) do not lend themselves to
separation of mineral matter by this means, except in a few cases.\60\
Coal is mechanically sized, then various washing techniques are
employed, depending on the particle size, type of coal, and the desired
level of preparation.\61\ Following the coal washing, the coal is
dewatered, and the waste streams are disposed.
---------------------------------------------------------------------------

    \59\ Couch, G.R., ``Coal Upgrading to Reduce CO2
emissions,'' CCC/67, October 2002, IEA Clean Coal Centre.
    \60\ Ibid.
    \61\ Various coal washing techniques are treated in detail in
Chapter 4 of Meeting Projected Coal Production Demands In The USA,
Upstream Issues, Challenges, and Strategies, The Virginia Center for
Coal and Energy Research, Virginia Polytechnic Institute and State
University, contracted for by the National Commission on Energy
Policy, 2008.
---------------------------------------------------------------------------

    Coal washing takes place offsite at large dedicated coal washing
facilities, typically located near where the coal is mined. In
addition, coal washing carries with it a number of problems:
     Coal washing is not typically performed on the types of
coals used in the power plants under consideration, Powder River Basin
(PRB) subbituminous and Texas lignites.

     Because coal washing is not typically conducted onsite of
the power plant, it is viewed as a consideration in the selection of
the coal, and not as an air pollution control.
     Coal washing poses significant energy and non-air quality
considerations under section 51.308(e)(1)(ii)(A). For instance, it
results in the use of large quantities of water,\62\ and coal washing
slurries are typically stored in impoundments, which can, and have,
leaked.\63\
---------------------------------------------------------------------------

    \62\ ``Water requirements for coal washing are quite variable,
with estimates of roughly 20 to 40 gallons per ton of coal washed (1
to 2 gal per MMBtu) (Gleick, 1994; Lancet, 1993).'' Energy Demands
on Water Resources, Report to Congress on the Interdependency of
Energy and Water, U.S. Department Of Energy, December 2006.
    \63\ Committee on Coal Waste Impoundments, Committee on Earth
Resources, Board on Earth Sciences and Resources, Division on Earth
and Life Studies; Coal Waste Impoundments, Risks, Responses, and
Alternatives; National Research Council; National Academy Press,
2002.
---------------------------------------------------------------------------

    Because of these issues, we do not consider coal washing as a part
of our reasonable set of options for analysis as BART SO2
control technology.
    In general, coal drying consists of reducing the moisture content
of lower rank coals, thereby improving the heating value of the coal
and so reducing the amount of coal that has to be combusted to achieve
the same power, thus improving the efficiency of the boiler. In the
process, certain pollutants are reduced as a result of (1) mechanical
separation of mineralized sulfur (e.g., and iron pyrite) and rocks, and
(2) the unit burning less coal to make the same amount of power.
    Coal drying can be performed onsite and so can be considered a
potential BART control. Great River Energy has developed a patented
process which is being successfully utilized at the Coal Creek facility
and is potentially available for installation at other facilities.\64\
This process utilizes excess waste heat to run trains of moving
fluidized bed dryers. The process offers a number of co-benefits, such
as general savings due to lower coal usage (e.g., coal cost, ash
disposal), less power required to run mills and ID fans, and lower
maintenance on coal handling equipment air preheaters, etc.
---------------------------------------------------------------------------

    \64\ DryFining\TM\ is the company's name for the process. It is
described here: http://www.powermag.com/improve-plant-efficiency-and-reduce-co2-emissions-when-firing-high-moisture-coals/.
---------------------------------------------------------------------------

    Although we view this new patented technology for coal drying
onsite as a promising path in the near future for generally improving
boiler efficiency and obtaining some reduction in SO2, its
analysis presents a number of difficulties. For instance, the degree of
reduction in SO2 is dependent on a number of factors. These
include (1) the quality and quantity of the waste heat available at the
unit, (2) the type of coal being dried (amount of bound sulfur, i.e.,
pyrites, moisture content), and (3) the design of the boiler (e.g.,
limits to steam temperatures, which can decrease due to the reduced
flue gas flow through the convective pass of the boiler). We cannot
assess many of these site-specific issues and we believe that
requesting that the facilities in question do so would require detailed
engineering analysis and extend our review time greatly. As a result of
these issues, we do not further assess coal drying as part of our
reasonable set of options for BART analysis. We expect that this
technology may have matured enough such that it can be better assessed
for the second planning period.
DSI
    DSI is performed by injecting a dry reagent into the hot flue gas,
which chemically reacts with SO2 and other gases to form a
solid product that is subsequently captured by the particulate control
device. A blower delivers the sorbent from its storage silos through
piping directly to the flue gas ducting via injection lances. The most
commonly used sorbent is trona, a naturally occurring mineral primarily
mined from the Green River Formation in Wyoming. Trona can also be
processed into sodium bicarbonate, which is more reactive with
SO2 than trona, but more expensive. Hydrated lime is another
potential sorbent but it is less frequently used and little data are
available regarding its potential performance and cost. In general,
trona is considered the most cost-effective of the sorbents for
SO2 removal. There are many examples of DSI being used on
coal-fired EGUs to control SO2. However, DSI may not be
technically feasible at every coal-fired EGU. For instance, Luminant
states in its response to one of our Section 114(a) letters regarding
its Big Brown and Monticello units: \65\
---------------------------------------------------------------------------

    \65\ Luminant's 6/17/14 response to EPA's 5/20/14 Section 114(a)
request for information relating to the Big Brown, Martin Lake,
Monticello, and Sandow generating stations.

    Luminant commissioned the study of dry sorbent injection
(``DSI'') at these units in 2011. These studies determined that a
very high feed rate (in the range of 20-30%) was required to achieve
modest SO2 removal. Further, it was determined that other
economic and operational factors make the use of DSI infeasible. For
example, sorbent build-up was determined to cause degraded
performance of the control equipment over time, as well as
significant, repeat down time on a regular basis (i.e., every few
days) to remove the buildup. In addition to the high cost of the
sorbent required, the disposal and transport of the used sorbent (a
Texas Class 1 waste) would result in significant additional cost.
Thus, the use of DSI was determined infeasible from both an
operational and economic point of view, and further evaluation has
---------------------------------------------------------------------------
been discontinued.

    As a consequence of this statement, which is discussed more fully
in the CBI material Luminant has submitted and in our TSD, we have
concluded that DSI is not a feasible alternative for the Big Brown and
Monticello facilities. For all unscrubbed, coal-fired BART-subject
units other than the Big Brown and Monticello facilities, although
individual installations may present technical difficulties or poor
performance due to the suboptimization of one or more of the above
factors, we believe that DSI is technically feasible and should be
considered as a potential BART control.
SO2 Scrubbing Systems
    In contrast to DSI, SO2 scrubbing techniques utilize a
large dedicated vessel in which the chemical reaction between the
sorbent and SO2 takes place either completely or in large
part. Also in contrast to DSI systems, SO2 scrubbers add
water to the sorbent when introduced to the flue gas. The two
predominant types of SO2 scrubbing employed at coal-fired
EGUs are wet FGD, and Spray Dry Absorber (SDA). More recently,
Circulating Dry Scrubbers (CDS) have been introduced. The EIA reports
the following types of flue gas desulfurization systems as being
operational in the U.S. for 2015:

          Table 8--EIA Reported Desulfurization Systems in 2015
------------------------------------------------------------------------
                                                             Number of
                          Type                             installations
------------------------------------------------------------------------
Wet spray tower scrubber................................             296
Spray dryer absorber....................................             269
Circulating dry scrubber................................              50
Packed tower wet scrubber...............................               6
Venturi wet scrubber....................................              48
Jet bubbling reactor....................................              31
Tray tower wet scrubber.................................              42
Mechanically aided wet scrubber.                                       4
DSI.....................................................             106
Other...................................................               1
Unspecified.............................................               1
                                                         ---------------
    Total...............................................             854
------------------------------------------------------------------------

    Excluding the DSI installations, 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.\66\ An additional 269 are listed as being
spray dry absorber types. Consequently, spray type or tray type wet
scrubbers (wet FGD) account for approximately 45% of all scrubber
systems, and spray dry scrubbers (SDA) account for approximately 36% of
all scrubber systems that were operational in the U.S. in 2015.
---------------------------------------------------------------------------

    \66\ Trays are often employed in spray type wet scrubbers and
EIA lists some of the wet spray tower systems as secondarily
including trays.
---------------------------------------------------------------------------

    We consider some of the other scrubber system types (e.g., venturi
and packed wet scrubber types) to be older, outdated technologies (that
are not existing controls or factor into considerations regarding
existing controls) and therefore will not be considered in our BART
analysis. Jet bubbling reactors and circulating dry scrubbers are
relatively new technologies, with limited installations, and little
information is available with which to characterize them or their
suitability as a retrofit control option. Therefore, they too will not
be further considered as part of our reasonable set of options for
analysis for BART controls.
    In summary, wet FGD and SDA installations account for approximately
81% of all scrubber installations in the U.S. and as such constitute a
reasonable set of SO2 scrubber control options. The vast
majority of the wet FGD and SDA installations utilize limestone and
lime, respectively as reagents. In addition, these technologies cover
the maximum level of SO2 control available. As described
above, these controls are in wide use and have been retrofitted to a
variety of boiler types and plant configurations. We therefore see no
technical infeasibility issues and believe that limestone wet FGD and
lime SDA should be considered as potential BART controls for all of the
unscrubbed coal-fired BART-eligible units.
b. Identification of Technically Feasible SO2 Retrofit
Control Technologies for Gas-Fired Units that Burn Oil
Reduction in Fuel Oil Sulfur
    A number of the units we proposed in Table 6 as being subject to
BART primarily fire gas, but have occasionally fired fuel oil in the
past as reported by the EIA databases: EIA-767, EIA-906/920, and EIA-
923,\67\ which indicate the historic quantities of fuel oil burned and
the type and sulfur content of that fuel oil. These units are
identified below in Table 9:
---------------------------------------------------------------------------

    \67\ EIA-767: http://www.eia.gov/electricity/data/eia767/. EIA-
906/920 and EIA-923: http://www.eia.gov/electricity/data/eia923/.

                      Table 9--Gas Units that Occasionally Burn Oil and are Subject to BART
----------------------------------------------------------------------------------------------------------------
              Facility                       Unit(s)                Gas turbine               Steam turbine
----------------------------------------------------------------------------------------------------------------
Graham (Luminant)..................  2.....................  .........................  X
Newman (El Paso Electric)..........  2, 3..................  .........................  X
O W Sommers (CPS Energy)...........  1, 2..................  .........................  X
Stryker Creek (Luminant)...........  ST2...................  .........................  X
Wilkes Power Plant (AEP)...........  1.....................  .........................  X
----------------------------------------------------------------------------------------------------------------

    The BART Guidelines advise that for oil-fired units, regardless of
size, limits on fuel oil sulfur content should be considered in the
BART evaluation.\68\ All of the subject units are limited by permit to
burning oil with a sulfur content of no more than 0.7% sulfur by
weight.\69\ In analyzing the technical feasibility under BART of these
facilities burning fuel oils of sulfur contents lower than historically
burned, we investigated two issues: (1) Is lower sulfur fuel oil
available and what is its cost, and (2) are there any technical issues
in burning a lower sulfur fuel oil that could add to the cost of that
oil? All of the units have either burned Distillate Fuel Oil (DFO) or
have switched between DFO and Residual Fuel Oil (RFO), thus
demonstrating the ability to burn DFOs of the type under consideration
for SO2 BART. We therefore conclude that lower sulfur DFOs
are a technically feasible retrofit control option under BART. Lower
sulfur DFOs carry no capital costs. Any cost increases relate to
purchase price differences.
---------------------------------------------------------------------------

    \68\ 70 FR at 39171.
    \69\ In addition, the Newman units 2 and 3 are restricted to
burning fuel oil for no more than 10% of their annual operating
time.
---------------------------------------------------------------------------

SO2 Scrubber Feasibility for Gas/Oil-Fired Boilers
    We are aware of instances in which FGDs of various types have been
installed or otherwise deemed feasible on a boiler that burns oil.\70\
Consequently, we will consider the installation of various types of
scrubbers to be technically feasible.
---------------------------------------------------------------------------

    \70\ Crespi, M. ``Design of the FLOWPAC WFGD System for the
Amager Power Plant.'' Power-Gen FGD Operating Experience, November
29, 2006, Orlando, FL.
    Babcock and Wilcox. ``Wet Flue Gas Desulfurization (FGD) Systems
Advanced Multi-Pollutant Control Technology.'' See Page 4: ``We have
also provided systems for heavy oil and Orimulsion fuels.''
    DePriest, W; Gaikwad, R. ``Economics of Lime and Limestone for
Control of Sulfur Dioxide.'' See page 7: ``A CFB unit, in Austria,
is on a 275 MW size oil-fired boiler burning 1.0-2.0% sulfur oil.''
---------------------------------------------------------------------------

c. Identification of Technically Feasible SO2 Control
Technologies for Scrubber Upgrades
    In our recent Texas-Oklahoma FIP,\71\ we presented a great deal of
information that concluded that the existing scrubbers for a number of
facilities could be very cost-effectively upgraded.\72\ That
information is included in this proposal.\73\ It contains a
comprehensive survey of available literature concerning the kinds of
upgrades that have been performed by industry on scrubber systems
similar to the ones installed on the units included in this proposal.
We then reviewed all of the information we had at our disposal
regarding the status of the existing scrubbers for each unit, including
any upgrades the facility may have already installed. We finished by
calculating the cost-effectiveness of scrubber upgrades, using the
facility's own information, obtained as a result of our Section 114
collection efforts. The companies that supplied this information have
asserted a Confidential Business Information (CBI) claim for much of
it, as provided in 40 CFR 2.203(b). We therefore redacted any CBI
information we utilize in our analyses, or otherwise disguised it so
that it cannot be traced back to its specific source. Of the facilities
we evaluated for scrubber upgrades in that action, Martin Lake Units 1,
2, and 3; and Monticello Unit 3 are subject to BART and are thus a part
of this proposal.
---------------------------------------------------------------------------

    \71\ 81 FR 321.
    \72\ See information presented in Sections 6 and 7 of the Cost
TSD.
    \73\ That information is included in our BART FIP TSD, Appendix
B.

---------------------------------------------------------------------------

2. Step 3: Evaluation of SO2 Control Effectiveness
    In the following subsections, we evaluate the control levels each
technically feasible technology is capable of achieving for the coal
and gas units. In so doing, we consider the maximum level of control
each technology is capable of delivering based on a 30 Boiler Operating
Day (BOD) period. As the BART Guidelines direct, ``[y]ou should
consider a boiler operating day to be any 24-hour period between 12:00
midnight and the following midnight during which any fuel is combusted
at any time at the steam generating unit.'' \74\ To calculate a 30-day
rolling average based on BOD, the average of the last 30 ``boiler
operating days'' is used. In other words, days are skipped when the
unit is down, as for maintenance. In effect, this provides a margin of
safety by eliminating spikes that occur at the beginning and end of
outages.
---------------------------------------------------------------------------

    \74\ 70 FR 39103, 39172 (July 6, 2005), [40 CFR part 51, App.
Y].
---------------------------------------------------------------------------

a. Evaluation of SO2 Control Effectiveness for Coal Fired
Units
Control Effectiveness of DSI
    We lack the site-specific information, which we believe requires an
individual performance test, in order to be able to accurately
determine the maximum DSI SO2 removal efficiency for the
individual units listed in Table 7. We are aware that a number of the
subject-to-BART coal-fired units have conducted such testing. However,
although we have examined that testing, most of the facilities have
claimed it as CBI and requested protection from public disclosure as
provided by 40 CFR part 2.
    However, we nevertheless must evaluate DSI as a viable, proven
method of SO2 control. We must do the same for
SO2 scrubbing, and in so doing, compare the visibility
benefits and costs of each technology in order to inform our proposed
BART determinations. We therefore propose the following methodology:
     We will evaluate each unit at its maximum recommended DSI
performance level, according to the IPM DSI documentation,\75\ assuming
milled trona: 80% SO2 removal for an ESP installation and
90% SO2 removal for a baghouse installation. This level of
control is within the range that can be achieved by SO2
scrubbers, and thus allows a better comparison of the costs of DSI and
scrubbers.
---------------------------------------------------------------------------

    \75\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2 Control Cost
Development Methodology, Final March 2013, Project 12847-002,
Systems Research and Applications Corporation, Prepared by Sargent &
Lundy, p. 7.
---------------------------------------------------------------------------

     However, (1) we do not know whether a given unit is
actually capable of achieving these control levels and (2) we believe
it is useful to evaluate lesser levels of DSI control (and
correspondingly lower costs). We therefore also evaluate all the units
at a DSI SO2 control level of 50%, which we believe is
likely achievable for most units.
     We invite comments on whether particular units have
performed DSI testing and have concluded they cannot achieve a
SO2 reduction between 50% and 80/90%. Any data to support
such a conclusion should be submitted along with those comments.
Control Effectiveness of Wet FGD and SDA
    We have assumed a wet FGD level of control to be a maximum of 98%
not to go below 0.04 lbs/MMBtu, in which case, we assume the percentage
of control equal to 0.04 lbs/MMBtu. As we discuss later in this
proposal, we will conduct our wet FGD control cost analysis using the
wet FGD cost algorithms, as employed in version 5.13 of our IPM
model.\76\ The IPM wet FGD Documentation states: ``The least squares
curve fit of the data was defined as a ``typical'' wet FGD retrofit for
removal of 98% of the inlet sulfur. It should be noted that the lowest
available SO2 emission guarantees, from the original
equipment manufacturers of wet FGD systems, are 0.04 lb/MMBtu.'' As we
established in our Oklahoma FIP,\77\ this level of control is
achievable with wet FGD. This level of control was also employed in our
recent Texas-Oklahoma FIP.\78\ We received a comment challenging this
level of control and we responded to that comment in our final action
on our Texas-Oklahoma FIP and incorporate that response in this
proposed action.\79\ We continue to conclude that our proposed level of
control for wet FGD is reasonable.
---------------------------------------------------------------------------

    \76\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2 Control Cost
Development Methodology, Final March 2013, Project 12847-002,
Systems Research and Applications Corporation, Prepared by Sargent &
Lundy. Documentation for v.5.13: Chapter 5: Emission Control
Technologies, Attachment 5-5: DSI Cost Methodology, downloaded
https://www.epa.gov/sites/production/files/2015-08/documents/attachment_5-5_dsi_cost_methodology.pdf.
    IPM Model--Updates to Cost and Performance for APC Technologies,
SDA FGD Cost Development Methodology, Final March 2013, Project
12847-002, Systems Research and Applications Corporation, Prepared
by Sargent & Lundy. Documentation for v. 5.13: Chapter 5: Emission
Control Technologies, Attachment 5-2: SDA FGD Cost Methodology,
downloaded from https://www.epa.gov/sites/production/files/2015-08/documents/attachment_5-2_sda_fgd_cost_methodology_3.pdf.
    IPM Model--Updates to Cost and Performance for APC Technologies,
wet FGD Cost Development Methodology, Final March 2013, Project
12847-002, Systems Research and Applications Corporation, Prepared
by Sargent & Lundy. Documentation for v.5.13: Chapter 5: Emission
Control Technologies, Attachment 5-1: Wet FGD Cost Methodology,
downloaded from https://www.epa.gov/sites/production/files/2015-08/documents/attachment_5-1_wet_fgd_cost_methodology.pdf.
    \77\ As discussed previously in our TSD for that action, control
efficiencies reasonably achievable by dry scrubbing and wet
scrubbing were determined to be 95% and 98% respectively. 76 FR
81742); Oklahoma v. EPA, 723 F.3d 1201 (July 19, 2013), cert. denied
(U.S. May 27, 2014).
    \78\ 81 FR 321.
    \79\ That information is included in our BART FIP TSD, Appendix
A.
---------------------------------------------------------------------------

    As with our Oklahoma FIP, we have assumed a SDA level of control
equal to 95%, unless that level of control would fall below an outlet
SO2 level of 0.06 lb/MMBtu, in which case, we assume the
percentage of control equal to 0.06 lbs/MMBtu. See our response to
comments in our previous Oklahoma FIP.\80\ In that FIP, we finalized
the same emission limit of 0.06 lbs/MMBtu on a 30 BOD average for 6
coal-fired EGUs. We justified those limits based on the same SDA
technology, using a combination of industry publications and real world
monitoring data. Much of that information is summarized in our response
to a comment to that action \81\ and in our TSD. We continue to
conclude that our proposed level of control for SDA is reasonable.
---------------------------------------------------------------------------

    \80\ 76 FR 81728.
    \81\ 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. See comment and response beginning on
page 91.
---------------------------------------------------------------------------

b. Evaluation of SO2 Control Effectiveness for Gas Fired
Units
    The control effectiveness of switching from a higher sulfur fuel
oil to a lower sulfur fuel oil lies in the reduction in sulfur
emissions. The emissions reduction depends on the percentage reduction
from the sulfur contents of the fuel oil that forms the SO2
baseline to the replacement fuel oil. Ultimately, the highest level of
control would result from a switch from the highest percentage sulfur
the units are permitted to burn, 0.7% to the lowest DFO available,
ultra-low sulfur diesel, which has a sulfur content of 0.0015%. This
would equate to a control effectiveness of 99.8%. Lesser levels of
controls are also possible. We will evaluate a range of control
effectiveness in switching to lower sulfur fuel oils in the next
section.

    Because we are unaware of any scrubber installations on oil fired
units in the U.S., we have no information on their control
effectiveness. However, we see no technical reason why the control
effectiveness of FGDs installed on gas-fired units that occasionally
burn fuel oil should not be equal to that of FGDs installed on coal-
fired units.
3. Step 4: Evaluate Impacts and Document the Results for SO2
    The BART Guidelines offers the following with regard to how Step 4
should be conducted: \82\
---------------------------------------------------------------------------

    \82\ 70 FR 39166.
---------------------------------------------------------------------------

    After you identify the available and technically feasible control
technology options, you are expected to conduct the following analyses
when you make a BART determination:

    Impact analysis part 1: Costs of compliance,
    Impact analysis part 2: Energy impacts, and
    Impact analysis part 3: Non-air quality environmental impacts.
    Impact analysis part 4: Remaining useful life.

    We evaluate the cost of compliance on a unit-by unit basis, because
control cost analysis depends on specific factors that can vary from
unit to unit. However, we generally evaluate the energy impacts, non-
air quality impacts, and the remaining useful life for all the units in
question together because in this instance there are no appreciable
differences in these factors from unit to unit.\83\
---------------------------------------------------------------------------

    \83\ To the extent these factors inform the cost of controls,
consistent with the BART Guidelines, they do inform our
considerations on a unit-by-unit basis.
---------------------------------------------------------------------------

    In developing our cost estimates for the units in Table 7, we rely
on the methods and principles contained within the EPA Air Pollution
Control Cost Manual (the Control Cost Manual, or Manual).\84\ We
proceed in our SO2 costing analyses by examining the current
SO2 emissions and the level of SO2 control, if
any, for each of the units listed in Table 7. For the coal units
without any SO2 control, we calculate the cost of installing
DSI, a SDA scrubber, and a wet FGD scrubber. For the gas units that
burn oil, we evaluate the cost of switching to lower sulfur fuel oils
and installing scrubbers.
---------------------------------------------------------------------------

    \84\ 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.
---------------------------------------------------------------------------

    In order to estimate the costs for DSI, SDA scrubbers, and wet FGD
scrubbers, we programmed the DSI, SDA and wet FGD cost algorithms, as
employed in version 5.13 of our IPM model, referenced above, into three
spreadsheets. These cost algorithms calculate the Total Project Cost
(TPC), Fixed Operating and Maintenance (Fixed O&M) costs, and Variable
Operating and Maintenance (Variable O&M) costs. We then performed DSI,
SDA and wet FGD cost calculations for each unit listed in Table 7 that
did not already have SO2 control.\85\ These cost models were
based on costs escalated to 2012 dollars.\86\ Because the IPM 5-13 cost
algorithms were calculated in 2012 dollars, we have escalated them to
2016, using the annual Chemical Engineering Plant Cost Indices (CEPCI).
---------------------------------------------------------------------------

    \85\ These spreadsheets are entitled, ``DSI Cost IPM 5-13 TX
BART.xlsx,'' ``SDA Cost IPM 5-13 TX BART.xlsx,'' and ``Wet FGD Cost
IPM 5-13 TX BART.xlsx,'' and are located in our Docket.
    \86\ Ibid., p.1: ``The data was converted to 2012 dollars based
on the Chemical Engineering Plant Index (CEPI) data.''
---------------------------------------------------------------------------

a. Impact Analysis Part 1: Cost of Compliance for DSI, SDA, and Wet FGD
    As we discuss above and in our Cost TSD, we evaluated each unit at
its maximum recommended level of control, considering the type of
SO2 control device. Below, we present a summary of our DSI,
SDA, and wet FGD cost analysis: \87\
---------------------------------------------------------------------------

    \87\ In this table, the capital cost is the total cost of
constructing the facility. The annualized cost is the sum of the
annualized capital cost and the annualized operational cost. See our
Cost TSD for more information on how these costs were calculated.

                                                Table 10--Summary of DSI, SDA, and Wet FGD Cost Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                2016
                                                                                SO2 reduction       2016          2016 Cost      Incremental
            Facility                     Unit               Control        Control level       (tpy)        Annualized     effectiveness       cost-
                                                                                (%)                            cost           ($/ton)      effectiveness
                                                                                ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Big Brown.......................  1.................  DSI...............              50          14,448     $29,468,587          $2,040
                                                      DSI...............              90          26,006      72,131,749           2,774          $3,691
                                                      SDA...............              95          27,453      35,297,532           1,286         -25,456
                                                      Wet FGD...........              98          28,320      33,673,102           1,189          -1,874
                                  2.................  DSI...............              50          15,320      29,342,350           1,915
                                                      DSI...............              90          27,576      71,322,593           2,586           3,425
                                                      SDA...............              95          29,108      35,359,239           1,215         -23,475
                                                      Wet FGD...........            97.9          29,998      33,817,952           1,127          -1,732
Monticello......................  1.................  DSI...............              50           4,787      11,408,872           2,383
                                                      DSI...............              90           8,617      25,409,128           2,949           3,655
                                                      SDA...............              95           9,095      24,294,319           2,671          -2,332
                                                      Wet FGD...........              97           9,286      25,236,699           2,718           4,934
                                  2.................  DSI...............              50           4,129       9,742,648           2,360
                                                      DSI...............              90           7,431      21,418,734           2,882           3,536
                                                      SDA...............              95           7,844      23,126,113           2,948           4,134
                                                      Wet FGD...........            96.8           7,995      24,233,133           3,031           7,331
Coleto Creek....................  1.................  DSI...............              50           7,376      16,246,169           2,203