[Federal Register Volume 88, Number 86 (Thursday, May 4, 2023)]
[Proposed Rules]
[Pages 28918-28984]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2023-08732]
[[Page 28917]]
Vol. 88
Thursday,
No. 86
May 4, 2023
Part V
Environmental Protection Agency
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40 CFR Parts 52, 78, and 97
Revision and Promulgation of Air Quality Implementation Plans; Texas;
Regional Haze Federal Implementation Plan; Disapproval and Need for
Error Correction; Denial of Reconsideration of Provisions Governing
Alternative to Source-Specific Best Available Retrofit Technology
(BART) Determinations; Proposed Rule
Federal Register / Vol. 88, No. 86 / Thursday, May 4, 2023 / Proposed
Rules
[[Page 28918]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 52, 78, and 97
[EPA-R06-OAR-2016-0611; EPA-HQ-OAR-2016-0598; FRL-9771-01-R6]
Revision and Promulgation of Air Quality Implementation Plans;
Texas; Regional Haze Federal Implementation Plan; Disapproval and Need
for Error Correction; Denial of Reconsideration of Provisions Governing
Alternative to Source-Specific Best Available Retrofit Technology
(BART) Determinations
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 withdraw the
existing Texas Sulfur Dioxide (SO2) Trading Program
provisions, which constitute the Federal implementation plan (FIP) the
EPA previously promulgated to address SO2 Best Available
Retrofit Technology (BART) requirements for EGUs in Texas that are not
adequately satisfied by the Texas Regional Haze State implementation
plan (SIP). In its place, the EPA proposes a FIP that establishes
SO2 limits on 12 Electric Generating Units (EGUs) located at
six Texas facilities to fulfill requirements of the Regional Haze Rule
for the installation and operation of BART for SO2. Based on
these proposed changes, we also propose to affirm the continued
validity of participation in the Cross-State Air Pollution Rule (CSAPR)
trading programs as a BART alternative. Therefore, the EPA is proposing
to deny a petition for reconsideration of our 2017 determination that
States that are participating in CSAPR can continue to rely on CSAPR
participation as a BART alternative. Finally, we are proposing to find
that our prior approval of the portion of the Texas Regional Haze SIP
that addresses the BART requirement for EGUs for Particulate Matter
(PM) was made in error and are proposing to correct that error by
proposing to disapprove that portion of the Texas Regional Haze SIP
through our authority under the CAA section 110(k)(6), and, as part of
a FIP, we are proposing PM BART limits for 12 EGUs located at six Texas
facilities.
DATES:
Comments: Comments must be received on or before July 3, 2023.
Virtual Public Hearing: The EPA will hold a virtual public hearing
to solicit comments on May 19, 2023. The last day to pre-register to
speak at the hearing will be on May 17, 2023. On May 18, 2023, the EPA
will post a general agenda for the hearing that will list pre-
registered speakers in approximate order at https://www.epa.gov/tx/texas-regional-haze-best-available-retrofit-technology-federal-implementation-plan-and-cross. If you require the services of a
translator or a special accommodation such as audio description/closed
captioning, please pre-register for the hearing and describe your needs
by May 11, 2023.
For more information on the virtual public hearing, see
SUPPLEMENTARY INFORMATION.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R06-
OAR-2016-0611 to the Federal eRulemaking Portal: https://www.regulations.gov/ (our preferred method). For additional submission
methods, please contact the person identified in the FOR FURTHER
INFORMATION CONTACT section.
Instructions: All submissions received must include the Docket ID
No. for this rulemaking. Comments received may be posted without change
to https://www.regulations.gov/, including any personal information
provided.
Docket: The docket for this action is available electronically at
https://www.regulations.gov. Some information in the docket may not be
publicly available via the online docket due to docket file size
restrictions, such as certain modeling files, or content (e.g., CBI).
To request a copy of the modeling files, please send a request via
email to [email protected]">R6[email protected]. For questions about a
document in the docket please contact individual listed in the FOR
FURTHER INFORMATION CONTACT section.
CBI: Do not submit information containing CBI to the EPA through
https://www.regulations.gov. To submit information claimed as CBI,
please contact the individual listed in the FOR FURTHER INFORMATION
CONTACT section. Clearly mark the part or all of the information that
you claim to be CBI. In addition to one complete version of the
comments that includes information claimed as CBI, you must submit a
copy of the comments that does not contain the information claimed as
CBI directly to the public docket through the procedures outlined in
Instructions earlier. Information not marked as CBI will be included in
the public docket and the EPA's electronic public docket without prior
notice. Information marked as CBI will not be disclosed except in
accordance with procedures set forth in 40 Code of Federal Regulations
(CFR) part 2. For the full EPA public comment policy, information about
CBI or multimedia submissions, and general guidance on making effective
comments, please visit https://www2.epa.gov/dockets/commenting-epa-dockets.
To pre-register to attend or speak at the virtual public hearing,
please use the online registration form available at https://www.epa.gov/tx/texas-regional-haze-best-available-retrofit-technology-federal-implementation-plan-and-cross or contact us via email at
[email protected]. For more information on the virtual
public hearing, see SUPPLEMENTARY INFORMATION.
FOR FURTHER INFORMATION CONTACT: Michael Feldman, Air and Radiation
Division, SO2 and Regional Haze Section (ARSH),
Environmental Protection Agency, 1201 Elm St., Suite 500 Dallas, TX
75270; telephone number: 214-665-9793; or via email:
[email protected].
SUPPLEMENTARY INFORMATION: Throughout this document wherever ``we,''
``us,'' or ``our'' is used, we mean the EPA.
There are two dockets supporting this action, EPA-R06-OAR-2016-0611
and EPA-HQ-OAR- EPA-HQ-OAR-2016-0598. Docket No. EPA-R06-OAR-2016-0611
contains information specific to BART requirements for Texas, including
this notice of proposed rulemaking and prior rulemakings related to
Texas BART, previous submittals from the State, and the Technical
Support Documents for this action. Docket No. EPA-HQ-OAR-2016-0598
contains previous actions and information related to CSAPR as a BART
alternative. All comments regarding this proposed action should be made
in Docket No. EPA-R06-OAR-2016-0611. For additional submission methods,
please email [email protected].
Virtual Public Hearing
The EPA is holding a virtual public hearing to provide interested
parties the opportunity to present data, views, or arguments concerning
the proposal. The EPA will hold a virtual public hearing to solicit
comments on May 19, 2023. The hearing will convene in two sessions.
Session 1 will convene at 1 p.m. Central Time (CT) and will conclude at
3 p.m. CT, or 15 minutes after the last pre-registered presenter in
attendance has presented if there are no additional presenters. Session
2 will convene at 4 p.m. Central Time (CT) and will conclude at 7 p.m.
CT, or 15 minutes after the last pre-registered presenter in attendance
has presented if
[[Page 28919]]
there are no additional presenters. The EPA will announce further
details, including information on how to register for the virtual
public hearing, on the virtual public hearing website at https://www.epa.gov/tx/texas-regional-haze-best-available-retrofit-technology-federal-implementation-plan-and-cross. The EPA will begin pre-
registering speakers and attendees for the hearing upon publication of
this document in the Federal Register. To pre-register to attend or
speak at the virtual public hearing, please use the online registration
form available at https://www.epa.gov/tx/texas-regional-haze-best-available-retrofit-technology-federal-implementation-plan-and-cross or
contact us via email at [email protected]. The last day to
pre-register to speak at the hearing will be on May 17, 2023. On May
18, 2023, the EPA will post a general agenda for the hearing that will
list pre-registered speakers in approximate order at https://www.epa.gov/tx/texas-regional-haze-best-available-retrofit-technology-federal-implementation-plan-and-cross. Additionally, requests to speak
will be taken on the day of the hearing as time allows.
The EPA will make every effort to follow the schedule as closely as
possible on the day of the hearing; however, please plan for the
hearing to run either ahead of schedule or behind schedule. Each
commenter will have approximately 3 to 5 minutes to provide oral
testimony. The EPA encourages commenters to provide the EPA with a copy
of their oral testimony electronically by including it in the
registration form or emailing it to [email protected]. The
EPA may ask clarifying questions during the oral presentations but will
not respond to the presentations at that time. Written statements and
supporting information submitted during the comment period will be
considered with the same weight as oral comments and supporting
information presented at the virtual public hearing. A transcript of
the virtual public hearing, as well as copies of oral presentations
submitted to the EPA, will be included in the docket for this action.
The EPA is asking all hearing attendees to pre-register, even those
who do not intend to speak. The EPA will send information on how to
join the public hearing to pre-registered attendees and speakers.
Please note that any updates made to any aspect of the hearing will
be posted online at https://www.epa.gov/tx/texas-regional-haze-best-available-retrofit-technology-federal-implementation-plan-and-cross.
While the EPA expects the hearing to go forward as set forth above,
please monitor our website or contact us via email at
[email protected] to determine if there are any updates.
The EPA does not intend to publish a document in the Federal Register
announcing updates.
If you require the services of a translator or a special
accommodation such as audio description/closed captioning, please pre-
register for the hearing and describe your needs by May 11, 2023. The
EPA may not be able to arrange accommodations without advance notice.
Table of Contents
I. Executive Summary
II. Background
A. Regional Haze
B. BART
C. Previous Actions Related to Texas BART and ``CSAPR Better-
Than-BART''
D. Consultation With Federal Land Managers (FLMs)
III. Overview of Proposed Action
IV. Withdrawal of the Texas SO2 Trading Program as a BART
Alternative for SO2
A. Legal Authority To Withdraw the Texas SO2 Trading
Program
B. Basis for Withdrawing the Texas SO2 Trading
Program
V. CSAPR Participation as a BART Alternative
A. Introduction
B. Background
C. Summary of the 2020 Petition for Reconsideration and
Associated Litigation
D. Criteria for Granting a Mandatory Petition for
Reconsideration
E. The EPA's Evaluation of the Petition for Reconsideration
VI. The EPA's Authority To Promulgate a FIP Addressing
SO2 and PM BART
A. CAA Authority To Promulgate a FIP for SO2 BART
B. Error Correction and CAA Authority To Promulgate a FIP--PM
BART
VII. BART Analysis for SO2 and PM
A. Identification of Sources Subject to BART
B. BART Five Factor Analysis
VIII. Weighing of the Five BART Factors and Proposed BART
Determinations
A. SO2 BART for Coal-Fired Units With no
SO2 Controls
B. SO2 BART for Coal-Fired Units With Existing
Scrubbers
C. PM BART
IX. Proposed Action
A. Regional Haze
B. CSAPR Better-Than-BART
X. Environmental Justice Considerations
XI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Overview
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Determinations Under CAA Section 307(b)(1) and (d)
I. Executive Summary
The CAA's visibility protection program was created in response to
a national goal set by Congress in 1977 to remedy and prevent
visibility impairment in certain national parks, such as Grand Canyon
National Park, and national wilderness areas, such as the Okefenokee
National Wildlife Refuge. Vistas in these areas are often obscured by
visibility impairment such as regional haze, which is caused by
emissions from numerous sources located over a wide geographic area.
In response to this Congressional directive, the EPA promulgated
regulations to address visibility impairment in 1999. These
regulations, which are commonly referred to as the Regional Haze Rule,
established an iterative process for achieving Congress's national goal
by providing for multiple, approximately 10-year ``planning periods''
in which State air agencies must submit to EPA plans that address
sources of visibility-impairing pollution in their States. The first
State plans were due in 2007 for the planning period that ended in
2018. The second State plans were due in 2021 for the period that ends
in 2028. This proposal focuses on obligations from the first planning
period of the regional haze program.
A central element of these first planning period State plans was
the requirement for certain older stationary sources to install the
Best Available Retrofit Technology (BART) for the purpose of making
reasonable progress towards Congress's national goal of eliminating
visibility impairment within our nation's most treasured lands. The
Regional Haze Rule provided two approaches a State could take to
fulfill its BART obligations: (1) conduct source-by-source evaluations
for covered sources, or (2) implement an alternative program, such as
an emissions trading program, that achieves greater reasonable progress
than source-by-source BART.
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One such BART alternative that 19 States have relied on for over a
decade to fulfill some or all of their BART obligations with respect to
visibility-impairing pollution from power plants is participation in
the EPA's Cross-State Air Pollution Rule (CSAPR), an emissions trading
program that was promulgated in 2011. Changes to the CSAPR program over
the years, particularly with respect to the status of the State of
Texas, have required the EPA to reexamine on several occasions whether
the program continues to achieve greater reasonable progress than
source-by-source BART for participating States. Most recently, after
removing Texas from certain aspects of the CSAPR program, the EPA
reaffirmed the viability of the CSAPR program as a BART alternative in
2017 and then again in 2020 when the EPA denied a petition for
reconsideration of the 2017 reaffirmation.
Texas submitted its first State plan to address regional haze in
2009, relying at that time on the now-defunct predecessor program to
CSAPR to satisfy the BART requirement for its power plants.\1\ The EPA
disapproved this portion of Texas's plan in 2012. Texas is home to
numerous power plants, many of which operate without modern pollution
controls. As a result, several of these plants are among the highest
emitters of visibility-impairing pollutants, such as sulfur dioxide
(SO2), in the nation. These emissions cause or contribute to
visibility impairment in such iconic places as Big Bend National Park
and Guadalupe Mountains National Park in Texas, Salt Creek Wilderness
Area in New Mexico, Caney Creek Wilderness Area in Arkansas, and
Wichita Mountains Wilderness Area in Oklahoma. In 2017, the EPA
proposed to address the gap in Texas's plan by, among other things,
requiring source-by-source BART controls for SO2 emissions
from covered sources that would have significantly reduced these
emissions. The EPA never finalized this proposal, however. Instead, in
2017 (and again in 2020), the EPA promulgated an intrastate trading
program to govern SO2 emissions from Texas power plants,
based on a finding that the program would achieve greater reasonable
progress than source-by-source BART even though the program would allow
for increases in SO2 emissions (and thus increased
visibility impairment) instead of emission reductions.
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\1\ https://www.tceq.texas.gov/airquality/sip/bart/haze_sip.html.
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This proposal seeks to address both the BART requirements for
Texas's power plants and an outstanding petition that once again calls
into question the continued viability of the CSAPAR program as a BART
alternative for participating States due to the status of Texas, and
the complicated interactions between these two regulatory regimes.
Specifically, the EPA is proposing to withdraw the intrastate trading
program on the basis that it does not achieve greater reasonable
progress than source-by-source BART. In its place, the EPA is proposing
to promulgate source-by-source BART emission limits for covered sources
in Texas. If finalized, these emission limits would reduce emissions
from these sources by more than 80,000 tons of SO2
emissions, improving visibility across a wide range of the nation's
most scenic vistas. In addition, the EPA is proposing that these
changes to the Texas plan, if finalized, would allow the EPA to once
again reaffirm that the CSAPR program remains a viable BART alternative
for the 19 participating States. On that basis, the EPA is proposing to
deny the outstanding petition seeking to end these States' longstanding
reliance on the CSAPR program to satisfy their BART obligations for
power plants.
II. Background
A. Regional Haze
Regional haze is visibility impairment that is produced by a
multitude of sources and activities which are located across a broad
geographic area. These sources and activities emit fine particulate
matter (PM2.5) (e.g., sulfates, nitrates, organic carbon,
elemental carbon, and soil dust) and its 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, in addition to direct sources of PM
2.5, impairs visibility by scattering and absorbing light.
Visibility impairment (i.e., light scattering) reduces the clarity,
color, and visible distance that one can see. PM2.5 can also
cause serious health effects (including premature death, heart attacks,
irregular heartbeat, aggravated asthma, decreased lung function, and
increased respiratory symptoms) and mortality in humans, and
contributes to environmental effects such as acid deposition and
eutrophication.
In section 169A of the 1977 Amendments to the Clean Air Act (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, anthropogenic impairment of visibility in
156 national parks and wilderness areas designated as mandatory Class I
areas.\2\ Congress added section 169B to the CAA in 1990 to address
regional haze issues, and the EPA promulgated the Regional Haze Rule
(RHR), codified at 40 CFR 51.308,\3\ on July 1, 1999.\4\ The RHR
established a requirement to submit a regional haze SIP, which applies
to all 50 States, the District of Columbia, and the Virgin Islands.\5\
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\2\ Areas designated as mandatory Class I areas consist of
National Parks exceeding 6,000 acres, wilderness areas and national
memorial parks exceeding 5,000 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, the 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.''
\3\ In addition to the generally applicable regional haze
provisions at 40 CFR 51.308, the EPA also promulgated regulations
specific to addressing regional haze visibility impairment in Class
I areas on the Colorado Plateau at 40 CFR 51.309. The latter
regulations are not relevant here.
\4\ See 64 FR 35714 (July 1, 1999). On January 10, 2017, the EPA
promulgated revisions to the RHR that apply for the second and
subsequent implementation periods. See 82 FR 3078 (Jan. 10, 2017).
\5\ 40 CFR 51.300(b).
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To address regional haze visibility impairment, the RHR established
an iterative planning process that requires States in which Class I
areas are located and States from which emissions may reasonably be
anticipated to cause or contribute to any impairment of visibility in a
Class I area to periodically submit SIP revisions to address regional
haze visibility impairment.\6\ Under the CAA, each SIP submission must
contain ``a long-term (ten to fifteen years) strategy for making
reasonable progress toward meeting the national goal,'' and the initial
round of SIP submissions also had to address the statutory requirement
[[Page 28921]]
that certain older, larger sources of visibility-impairing pollutants
install and operate the Best Available Retrofit Technology (BART), as
discussed further in Section II.B.\7\ States' first regional haze SIPs
were due by December 17, 2007, with subsequent SIP submissions
containing revised long-term strategies originally due July 31, 2018,
and every ten years thereafter.\8\
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\6\ See 42 U.S.C. 7491(b)(2); 40 CFR 51.308(b) and (f); see also
64 FR 35768 (July 1, 1999). The EPA established in the RHR that all
States either have Class I areas within their borders or ``contain
sources whose emissions are reasonably anticipated to contribute to
regional haze in a Class I area;'' therefore, all States must submit
regional haze SIPs. See 64 FR 35721. In addition to each of the 50
States, the EPA also concluded that the Virgin Islands and District
of Columbia contain a Class I area and/or contain sources whose
emissions are reasonably anticipated to contribute regional haze in
a Class I area. See 40 CFR 51.300(b) and (d)(3).
\7\ See 42 U.S.C. 7491(b)(2)(A); 40 CFR 51.308(d) and (e).
\8\ See 40 CFR 51.308(b). The 2017 RHR revisions changed the
second period SIP due date from July 31, 2018, to July 31, 2021, and
maintained the existing schedules for the subsequent implementation
periods. See 40 CFR 51.308(f).
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B. BART
Section 169A of the CAA directs States to evaluate the use of
retrofit controls at certain larger, older stationary sources to
address visibility impacts from these sources, whose emissions are
often uncontrolled or poorly controlled. Specifically, section
169A(b)(2) of the CAA requires States to revise their SIPs to contain
such measures as may be necessary to make reasonable progress towards
the national visibility goal, including a requirement that certain
categories of existing major stationary sources built between 1962 and
1977 procure, install, and operate BART as determined by the State
applying five statutory factors. On July 6, 2005, the EPA published the
Guidelines for BART Determinations Under the Regional Haze Rule at
Appendix Y to 40 CFR part 51 (BART Guidelines) to assist States in the
BART evaluation process. Under the RHR and the BART Guidelines, the
BART evaluation process consists of three steps: (1) An identification
of all BART-eligible sources in the State, (2) an assessment of whether
the BART-eligible sources are subject to BART (based on a determination
that each source or sources may reasonably be anticipated to cause or
contribute to any visibility impairment in a Class I area), and (3) a
determination of an emission limit reflecting BART after applying the
five statutory BART factors.\9\ In applying the BART factors for a
fossil fuel-fired electric generating plant with a total generating
capacity in excess of 750 megawatts, a State must use the approach set
forth in the BART Guidelines.\10\ A State is generally encouraged, but
not required, to follow the BART Guidelines for other types of
sources.\11\
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\9\ See generally 40 CFR 51.308(e)(1); 40 CFR part 51, Appendix
Y.
\10\ 42 U.S.C. 7491(b); 40 CFR 51.308(e)(1)(ii)(B).
\11\ See 40 CFR part 51, Appendix Y. For additional details
regarding the three steps of the BART evaluation process, see, e.g.,
85 FR 47134, 47136-37 (August 4, 2020).
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States must make source-specific BART determinations for all
``BART-eligible'' sources determined to be subject to BART. However, as
an alternative to making these ``source-specific'' BART determinations,
States may adopt an emissions trading program or other alternative
program for all or a portion of their BART-eligible sources, so long as
the alternative achieves greater reasonable progress towards improving
visibility than BART would for those sources, and the alternative meets
certain other requirements. Several options are available for making
BART-alternative demonstrations, and these are discussed in greater
detail in Section IV.B and Section V.\12\
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\12\ See generally 40 CFR 51.308(e)(2)-(4).
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States generally undertook the BART determination process during
the regional haze program's first implementation period. While the BART
requirement is considered a one-time requirement, BART-eligible
sources, including sources found subject to BART and for which a BART
emission limit was established, may need to be re-assessed for
additional controls in future implementation periods under the CAA's
reasonable progress provisions. Thus, the EPA has stated that States
should treat BART-eligible sources the same as other reasonable
progress sources going forward.\13\
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\13\ See 81 FR 26942, 26947 (May 4, 2016).
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C. Previous Actions Related to Texas BART and ``CSAPR Better-Than-
BART''
The procedural history leading up to this proposed action is set
forth in detail in this section. On March 31, 2009, Texas submitted a
regional haze SIP (the 2009 Regional Haze SIP) to the EPA that included
reliance on Texas's participation in trading programs under the Clean
Air Interstate Rule (CAIR) as an alternative to BART for SO2
and NOX emissions from Electric Generating Units (EGUs).\14\
This reliance was consistent with the EPA's regulations at the time
that Texas developed its 2009 Regional Haze SIP.\15\ However, at the
time Texas submitted its SIP to the EPA, the D.C. Circuit had remanded
CAIR (without vacatur).\16\ The court left CAIR and our 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. The EPA promulgated the Cross-
State Air Pollution Rule (CSAPR) to replace CAIR in 2011 \17\ (and
revised it in 2012).\18\ CSAPR established FIP requirements for sources
in a number of States, including Texas, to address the States'
interstate transport obligation under CAA section 110(a)(2)(D)(i)(I).
CSAPR addresses interstate transport of PM2.5 and ozone by
requiring affected EGUs in these States to participate in one or more
of the CSAPR trading programs, which establish emissions budgets that
apply to the EGUs' collective annual emissions of SO2 and
NOX, as well as emissions of NOX during ozone
season.\19\
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\14\ CAIR required certain States, including Texas, to reduce
emissions of SO2 and NOX that contribute
significantly to downwind nonattainment of the 1997 NAAQS for fine
particulate matter and ozone. See 70 FR 25152 (May 12, 2005).
\15\ See 70 FR 39104 (July 6, 2005).
\16\ See North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008),
as modified, 550 F.3d 1176 (D.C. Cir. 2008).
\17\ Federal Implementation Plans; Interstate Transport of Fine
Particulate Matter and Ozone and Correction of SIP Approvals, 76 FR
48208 (Aug. 8, 2011).
\18\ CSAPR was amended three times in 2011 and 2012 to add five
States to the seasonal NOX program and to increase
certain State budgets. 76 FR 80760 (December 27, 2011); 77 FR 10324
(February 21, 2012); 77 FR 34830 (June 12, 2012).
\19\ Ozone season for CSAPR purposes is May 1 through September
30.
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Following the issuance of CSAPR, the EPA determined that CSAPR
would achieve greater reasonable progress towards improving visibility
than would source-specific BART in CSAPR States (a determination often
referred to as ``CSAPR Better-than-BART'').\20\ In the EPA's 2012
action promulgating CSAPR-Better-than-BART, the EPA used air quality
modeling to show that CSAPR met the two-pronged numerical test for a
BART alternative under 40 CFR 51.308(e)(3).\21\ In the same action, we
revised the Regional Haze Rule to allow States whose sources
participate in the CSAPR trading programs to rely on such participation
in lieu of requiring BART-eligible EGUs in the State to meet source-
specific emission limits reflective of BART controls as to the relevant
pollutant. In addition to allowing States to rely on CSAPR to address
BART requirements, the EPA issued limited disapprovals of a number of
States' regional haze SIPs, including the 2009 Regional Haze SIP
submittal from Texas, due to the States' reliance on CAIR, which had
been replaced by CSAPR.\22\ The EPA did not immediately promulgate a
FIP to address those aspects of the 2009 Regional Haze SIP submittal
from Texas subject to the
[[Page 28922]]
limited disapproval in order to allow more time for the EPA to assess
the remaining elements of the SIP.
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\20\ 77 FR 33642 (June 7, 2012). This determination was upheld
by the D.C. Circuit. See Util. Air Regulatory Grp. v. EPA, 885 F.3d
714 (D.C. Cir. 2018).
\21\ See generally 77 FR 33642 (June 7, 2012).
\22\ Id.
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In December 2014, we proposed an action to address the remaining
regional haze obligations for Texas.\23\ In that action, we proposed,
among other things, to rely on our CSAPR FIP requiring Texas sources'
participation in the CSAPR trading programs to satisfy the
NOX and SO2 BART requirements for Texas's BART-
eligible EGUs consistent with the 2012 revisions to the Regional Haze
Rule. We also proposed to approve the portions of the 2009 Texas
Regional Haze SIP addressing PM BART requirements for the State's BART-
eligible EGUs. Before that proposed rule was finalized, however, the
D.C. Circuit issued a decision on a number of challenges to CSAPR,
denying most claims, but remanding the CSAPR SO2 and/or
seasonal NOX emissions budgets of several States to the EPA
for reconsideration, including the Phase 2 SO2 and seasonal
NOX budgets for Texas.\24\ Due to the uncertainty arising
from the remand of Texas's CSAPR budgets, we did not finalize our
December 2014 proposal to rely on CSAPR to satisfy the SO2
and NOX BART requirements for Texas EGUs.\25\ Additionally,
because our proposed action on the PM BART provisions for EGUs was
dependent on how SO2 and NOX BART were satisfied,
we did not take final action on the PM BART elements of the 2009 Texas
Regional Haze SIP.\26\
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\23\ 79 FR 74818 (Dec. 16, 2014).
\24\ EME Homer City Generation, L.P. v. EPA (EME Homer City II),
795 F.3d 118, 132 (D.C. Cir. 2015). In 2012, several State,
industry, and other petitioners challenged CSAPR in the D.C.
Circuit, which stayed and then vacated the rule, ruling on only a
subset of petitioners' claims. See EME Homer City Generation, L.P.
v. EPA, 696 F.3d 7 (D.C. Cir. 2012). However, in April 2014 the
Supreme Court reversed the vacatur and remanded to the D.C. Circuit
for resolution of petitioners' remaining claims. See EPA v. EME
Homer City Generation, L.P., 572 U.S. 489 (2014). Following the
Supreme Court remand, the D.C. Circuit conducted further proceedings
to address petitioners' remaining claims. In July 2015, the court
issued a decision denying most of the claims but remanding the Phase
2 SO2 emissions budgets for Alabama, Georgia, South
Carolina, and Texas and the Phase 2 ozone-season NOX
budgets for eleven States to the EPA for reconsideration.
\25\ 81 FR 296 (Jan. 5, 2016).
\26\ In January 2016, we finalized action on the remaining
aspects of the December 2014 proposal. This final action
disapproved, among other things Texas's reasonable progress analysis
and Texas's long-term strategy. The EPA promulgated a FIP
establishing a new long-term strategy that consisted of
SO2 emission limits for 15 coal-fired EGUs at eight power
plants. 81 FR 296, 302 (Jan. 5, 2016). That rulemaking was
judicially challenged, however, and in July 2016, the Fifth Circuit
granted the petitioners' motion to stay the rule pending review.
Texas v. EPA, 829 F.3d 405 (5th Cir. 2016). On March 22, 2017,
following the submittal of a request by the EPA for a voluntary
remand of the parts of the rule under challenge, the Fifth Circuit
Court of Appeals remanded the rule in its entirety. (In this
rulemaking, we are not addressing those remanded requirements.)
March 22, 2017, Order, Texas v. EPA, 829 F.3d 405 (5th Cir. 2016)
(No. 16-60118).
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On October 26, 2016, the EPA finalized an update to CSAPR to
address the interstate transport requirements of CAA section
110(a)(2)(D)(i)(I) with respect to the 2008 ozone NAAQS (CSAPR
Update).\27\ The EPA also responded to the D.C. Circuit's remand in EME
Homer City II of certain CSAPR seasonal NOX budgets in that
action.\28\ As to Texas, the EPA withdrew Texas's seasonal
NOX budget finalized in CSAPR to address the 1997 ozone
NAAQS. However, in that same action, the EPA promulgated a FIP with a
revised seasonal NOX budget for Texas to address the 2008
ozone NAAQS.\29\ Accordingly, Texas sources remain subject to CSAPR
seasonal NOX requirements.
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\27\ 81 FR 74504 (Oct. 26, 2016).
\28\ See generally EME Homer City II, 795 F.3d 118, (D.C. Cir.
2015).
\29\ 81 FR 74504, 74524-25.
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On November 10, 2016, in response to the D.C. Circuit's remand in
EME Homer II of Texas's CSAPR SO2 budget, we proposed to
withdraw the FIP provisions that required EGUs in Texas to participate
in the CSAPR trading programs for annual emissions of SO2
and NOX.\30\ The EPA indicated that if the withdrawal was
finalized, Texas would no longer be eligible under 40 CFR 51.308(e)(4)
to rely on participation of its EGUs in a CSAPR trading program as an
alternative to source-specific SO2 BART determinations.\31\
We also proposed to reaffirm the EPA's 2012 analytical demonstration
that CSAPR provides greater reasonable progress than BART despite the
changes in CSAPR's geographic scope to address the EME Homer City II
remand, including removal of Texas's EGUs from the CSAPR trading
program for SO2 emissions.\32\ On September 29, 2017, we
finalized the withdrawal of the FIP provisions for annual emissions of
SO2 and NOX for EGUs in Texas \33\ and affirmed
our proposed finding that the EPA's 2012 analytical demonstration
remains valid and that participation in the CSAPR trading programs as
amended continues to meet the Regional Haze Rule's criteria for an
alternative to BART.\34\ (We refer to this as the ``2017 Affirmation of
CSAPR Better-than-BART'' throughout this notice.) In the September 29,
2017, final rule we evaluated the potential emissions shifting that
could occur due to the withdrawal of Texas from the CSAPR trading
program for SO2 emissions. Based on this evaluation, we
determined that an increase in emissions in the remaining CSAPR States
participating in the SO2 trading program would be more than
offset by the favorable visibility impacts brought about by the reduced
emissions in Texas under presumptive source-specific SO2
BART for the State's BART-eligible EGUs.\35\ As discussed later in this
section, certain environmental organizations filed a petition for
reconsideration of this affirmation in November 2017.
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\30\ 81 FR 78954 (Nov. 10, 2016).
\31\ Id. at 78956. The EPA also noted that because Texas EGUs
would continue to participate in a CSAPR trading program for ozone-
season NOX emissions, Texas would still be eligible under
40 CFR 51.308(e)(4) to rely on CSAPR participation as an alternative
to source-specific NOX BART determinations for the
covered sources. 81 FR at 78962.
\32\ Id.
\33\ Texas continues to participate in CSAPR for ozone season
NOX. See final action signed September 21, 2017,
available at regulations.gov in Docket No. EPA-HQ-OAR-2016-0598.
\34\ 82 FR 45481 (September 29, 2017).
\35\ Id. at 45493-94.
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On January 4, 2017, we proposed a FIP to address the BART
requirements for Texas's BART-eligible EGUs. With respect to
NOX, we proposed to replace the 2009 Regional Haze SIP's
reliance on CAIR with reliance on our CSAPR FIP to address the
NOX BART requirements for EGUs.\36\ This portion of our
proposal was based on the CSAPR Update and our separate November 10,
2016, proposed finding that the EPA's actions in response to the D.C.
Circuit's remand would not adversely impact our 2012 demonstration that
participation in the CSAPR trading programs meets the Regional Haze
Rule's criteria for alternatives to BART.\37\ We noted that we could
not finalize this portion of our proposed FIP to address the
NOX BART requirements for EGUs unless and until we finalized
our proposed finding that CSAPR was still better than BART.\38\ (This
predicate finding was finalized on September 29, 2017.)
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\36\ 82 FR 912, 914-15 (Jan. 4, 2017).
\37\ 81 FR 74504 (Nov. 10, 2016).
\38\ 82 FR 912, 915 (Jan. 4, 2017).
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The January 4, 2017, proposed action addressing the SO2
BART requirements for Texas EGUs acknowledged that Texas sources would
no longer be participating in the CSAPR program for SO2, and
therefore, the remaining unfulfilled BART requirements for Texas's
BART-eligible EGUs would need to be fulfilled by either an approved SIP
or an EPA-issued FIP. The EPA proposed to satisfy these requirements
through a BART FIP,
[[Page 28923]]
which addressed the identification of BART-eligible EGU sources,
screening to identify which BART-eligible sources are ``subject-to-
BART'' (i.e., may reasonably be anticipated to cause or contribute to
any impairment of visibility in any Class I area), and source-by-source
determinations of SO2 BART controls as appropriate. We
proposed SO2 emission limits on 29 EGUs located at 14
facilities.
In the January 2017 proposal, we also proposed to disapprove the
portion of the 2009 Texas Regional Haze SIP that made BART
determinations for PM from EGUs, on the grounds that the demonstration
in the 2009 Texas Regional Haze SIP relied on underlying assumptions as
to how the SO2 and NOX BART requirements for EGUs
were being met that were no longer valid with the proposed source-
specific SO2 requirements.\39\ The 2009 Texas Regional Haze
SIP included a pollutant-specific screening analysis for PM to
demonstrate that Texas EGUs were not subject to BART for PM. In a 2006
guidance document,\40\ the EPA stated that pollutant-specific screening
can be appropriate where a State is relying on a BART alternative to
address both NOX and SO2 BART. While we
previously proposed to approve the EGU BART determinations for PM in
the 2009 Texas Regional Haze SIP back in 2014, at that time, CSAPR was
an appropriate alternative for SO2 and NOX BART
requirements for EGUs. With the proposal to promulgate source-specific
SO2 BART requirements, however, SO2 BART would no
longer be addressed by a BART alternative. Thus, pollutant-specific
screening for PM was no longer appropriate. To address PM BART
requirements, we proposed to promulgate source-specific PM BART
requirements, which generally were based on existing practices and
control capabilities for those EGUs that we proposed to find subject to
BART. For coal-fired units, we proposed PM BART limits consistent with
PM emission limits in the Mercury and Air Toxics Standards (MATS) rule;
for gas-fired units, we proposed PM BART would be satisfied by making
the burning of pipeline-quality gas federally enforceable; and for oil-
fired units, we proposed that fuel-content requirements for
SO2 BART would also satisfy PM BART.\41\
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\39\ In the 2009 Regional Haze Texas SIP, emissions of both
SO2 and NOX from Texas's BART-eligible EGUs
were covered by participation in trading programs, which allowed
Texas to conduct a screening analysis of the visibility impacts from
PM emissions from such units in isolation. However, modeling on a
pollutant specific basis for PM is appropriate only in the narrow
circumstance of reliance on BART alternatives to satisfy both
NOX and SO2 BART. Due to the complexity and
nonlinear nature of atmospheric chemistry and chemical
transformation among pollutants, the 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.
\40\ 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.
\41\ 82 FR at 936.
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The EPA received public comments on this 2017 proposal encouraging
the agency to consider other potentially viable methods of implementing
a BART alternative for SO2 in Texas, rather than finalizing
source-specific BART limits. Specifically, some commenters suggested to
the EPA the concept of a trading program as a BART alternative to
satisfy SO2 BART requirements. After considering these and
other public comments, rather than finalizing source-specific BART
limits for subject-to-BART EGUs in Texas, we issued a final action on
October 17, 2017, that addressed SO2 BART requirements for
all BART-eligible coal-fired units and a number of BART-eligible gas-
or gas/fuel oil-fired units through a BART alternative for
SO2--specifically, a new intrastate trading program (Texas
SO2 Trading Program). The remaining BART-eligible EGUs not
covered by the Texas SO2 Trading Program were determined to
be not subject to BART based on screening methods as described in our
January 2017 proposed rule and the associated BART Screening technical
support document (BART Screening TSD) for that action.\42\
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\42\ See document in regulations.gov at docket identification
number EPA-R06-OAR-2016-0611-0005.
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At the time, the EPA modeled the Texas SO2 Trading
Program after the CSAPR SO2 trading program. We determined
that the Texas SO2 Trading Program would achieve similar
emission reductions to CSAPR had the State continued to be subject to
the CSAPR trading program through a FIP or SIP. As such, we concluded
that the Texas program satisfied the clear-weight-of-evidence test
requirements for a BART alternative under 40 CFR 51.308(e)(2).\43\ As
finalized in October 2017, the Texas SO2 Trading Program
established an annual trading program budget of 238,393 tons allocated
to the covered units, as well as a Supplemental Allowance Pool budget
of 10,000 tons, for a total of up to 248,393 allowances potentially
available in each year on average.\44\ The Texas SO2 Trading
Program allowed ``banking'' of allowances for use in future years,
similar to the CSAPR trading programs, but unlike the CSAPR programs,
did not impose an ``assurance level'' above which annual emissions
would be penalized via a higher allowance-surrender ratio. The Texas
SO2 Trading Program did not include all EGUs that would have
been subject to CSAPR, but the EPA concluded that potential annual
emissions from the excluded units were relatively small (i.e., less
than 27,500 tons) and would not undermine its overall conclusion that
the Texas SO2 Trading Program was essentially equivalent in
design and stringency to the CSAPR program.\45\ In reaching that
conclusion, the EPA compared the annual average emission limit of
248,393 tons under the Texas SO2 Trading Program (combined
with estimated emissions for the non-covered EGUs) to a benchmark
figure of 317,100 tons of annual SO2 emissions evaluated for
EGUs in Texas in the 2012 CSAPR Better-Than-BART analysis.\46\
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\43\ 82 FR 48324, 48329-30, 48357 (Oct. 17, 2017). The EPA
initially determined that the Texas SO2 Trading Program
achieved greater reasonable progress than source-specific BART under
the clear-weight-of-evidence test in 40 CFR 51.308(e)(2), relying on
the EPA's national finding that CSAPR provides for greater
reasonable progress than BART and the fact that the Texas
SO2 Trading Program would achieve similar emission
reductions to CSAPR in Texas. See 82 FR at 48329-30.
\44\ Id. at 48358.
\45\ Id.
\46\ Id. at 48359-60.
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In our final action on October 17, 2017, we also finalized our
January 2017 proposed determination that Texas's participation in
CSAPR's trading program for ozone-season NOX qualifies as an
alternative to source-specific NOX BART. Because Texas
continues to participate in CSAPR's trading program for ozone-season
NOX, we are not reopening this determination in this action.
Finally, because both NOX and SO2 were now once
again addressed by a BART alternative, we approved Texas's 2009
Regional Haze SIP's determination, based on a pollutant-specific
screening analysis, that Texas's EGUs are not subject to BART for PM.
On November 28, 2017, Sierra Club and the National Parks
Conservation Association (NPCA) submitted a petition for partial
reconsideration of our September 2017 finding affirming that CSAPR
continues to satisfy requirements as a BART alternative.\47\
[[Page 28924]]
Among other things, the petitioners alleged that it was impracticable,
and indeed impossible, to comment on the relationship between the Texas
SO2 Trading Program and the CSAPR Better-than-BART analysis
in the final rule because the EPA did not finalize the Texas
SO2 Trading Program until after the final rule was signed
and the EPA had assumed presumptive source-specific SO2 BART
controls in the rulemaking record for the final rule.\48\ Petitioners
alleged, in particular, that the EPA's emissions shifting analysis
accounted for potential increases in emissions in remaining CSAPR
States of between 22,300 to 53,000 tons by assuming these emissions
would be offset by an estimated 127,300 tons of SO2 emission
reductions in Texas due to presumptive source-specific BART
controls.\49\ However, these petitioners alleged that this assumption
was proven false when the EPA promulgated the Texas SO2
Trading Program rather than source-specific BART.\50\ On this basis,
among other things, petitioners sought mandatory reconsideration of the
September 29, 2017 action under CAA section 307(d)(7)(B).
---------------------------------------------------------------------------
\47\ Sierra Club and National Parks Conservation Association,
Petition for Partial Reconsideration of Interstate Transport of Fine
Particulate Matter: Revision of Federal Implementation Plan
Requirements for Texas; Final Rule; 82 FR 45481 (Sept. 29, 2017);
EPA-HQ-OAR-2016-0598; FRL-9968-46-OAR (submitted Nov. 28, 2017).
\48\ Id. at 8-9.
\49\ Id. at 13-14.
\50\ Id.
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On December 15, 2017, the EPA received a separate petition from
Sierra Club, NPCA, and the Environmental Defense Fund (EDF) requesting
reconsideration of certain aspects of the October 2017 final rule
focused mainly on issues related to the Texas SO2 Trading
Program promulgated to address the SO2 BART requirement for
Texas EGUs.\51\ In response to the December 15, 2017, petition for
reconsideration and in light of the change in direction between the
EPA's proposed and final actions for SO2 BART in Texas, we
stated that we believed that certain aspects of the October 2017 final
rule could benefit from further public comment. Accordingly, on August
27, 2018, the EPA proposed to affirm in most respects the October 2017
final rule, including the Texas SO2 Trading Program, but
solicited public comment on certain issues including whether the Texas
SO2 Trading Program for certain EGUs in Texas met the
requirements for an alternative to BART for SO2 and our
approval of Texas's SIP determination that no sources are subject to
BART for PM.\52\
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\51\ Sierra Club, National Parks Conservation Association, and
Environmental Defense Fund Petition for Reconsideration of
Promulgation of Air Quality Implementation Plans; State of Texas;
Regional Haze and Interstate Visibility Transport Federal
Implementation Plan (Oct. 17, 2017) EPA-R06-OAR-2016-0611; FRL-9969-
07-Region 6 (submitted Dec. 15, 2017).
\52\ 83 FR 43586, 43587.
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On November 14, 2019, partly in response to comments received on
its 2018 proposed affirmation, the EPA issued a supplemental proposal
to amend certain parts of the Texas SO2 Trading Program.\53\
The supplemental proposal included additional measures such as an
assurance level and penalty provisions. Specifically, these provisions
imposed a penalty surrender ratio of three-to-one on SO2
emissions exceeding a specified ``assurance level.'' \54\ The notice
also proposed a variability limit set at 7 percent of the trading
program budget (or 16,668 tons) and a resulting assurance level of 107
percent of the trading program budget (or 255,081 tons \55\) based on
the CSAPR methodology establishing such amounts for CSAPR States but
applied to Texas-specific data.\56\ The supplemental proposal also
included other minor changes with the goal of strengthening the overall
stringency of the program.\57\
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\53\ 84 FR 61850 (Nov. 14, 2019).
\54\ Id. at 61853.
\55\ In the final rule signed on June 29, 2020, we adjusted the
assurance level to 255,083 tons rather than the 255,081-ton
assurance level we proposed in the November 2019 supplemental
proposal. 85 FR 49170, 49183 (Aug. 12, 2020).
\56\ The increment between a State's emissions budget and its
corresponding assurance level is referred to as a ``variability
limit,'' because the increment is designed to account for year-to-
year variability in electricity generation and associated emissions.
\57\ 84 FR at 61855-56.
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On June 29, 2020, in two separate but concurrent actions, former
EPA Administrator Andrew Wheeler signed a final rule affirming, with
the proposed modifications from the supplemental proposal described
above, the Texas SO2 Trading Program as an alternative to
BART for SO2 for certain sources in Texas and signed a
letter denying the petition for reconsideration of the 2017 affirmation
of CSAPR Better-than-BART.\58\ Along with the denial of the petition,
the EPA also published in the docket the ``Cross-State Air Pollution
Rule (CSAPR) Better Than Best Available Retrofit Technology (BART)
Petition for Reconsideration Sensitivity Calculations'' \59\ to
demonstrate that, even accounting for the reduced stringency of the
Texas SO2 Trading Program as compared to source-specific
BART in Texas, and assuming a concomitant shift in SO2
emissions to remaining CSAPR States in the southeastern United States,
CSAPR remained a valid BART alternative.
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\58\ See 85 FR 49170 (Aug. 12, 2020) (affirming the Texas
SO2 Trading Program as an alternative to BART for certain
EGU sources in Texas). 85 FR 40286 (July 6, 2020) (providing notice
that the agency responded to a petition for partial reconsideration
of the 2017 affirmation of CSAPR better than BART).
\59\ Docket document ID EPA-HQ-OAR-2016-0598-0034 available at
https://www.regulations.gov/docket/EPA-HQ-OAR-2016-0598.
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On August 28, 2020, the Sierra Club, NPCA, and Earthjustice
submitted a petition for partial reconsideration under CAA section
307(d)(7)(B) of the EPA's 2020 Denial of their November 2017 petition
for reconsideration (August 2020 petition).\60\ The petitioners alleged
that because the EPA presented the updated CSAPR Better-than-BART
sensitivity calculations for the first time in its 2020 denial of the
2017 Petition (and thus they were not afforded an opportunity to
comment), and because that updated analysis is of central relevance to
the September 2017 Final Rule, the EPA must reconsider both actions
under CAA section 307(d)(7)(B).\61\ The petitioners alleged that,
contrary to the EPA's conclusions in its 2020 Denial, the updated CSAPR
Better-than-BART analysis demonstrates that visibility improvement
under CSAPR is not equal to or greater than visibility improvement
under source-specific BART averaged over all 140 Class I areas, or the
60 eastern Class I areas covered by CSAPR.\62\ The August 2020 petition
will be discussed in further detail in Section V.
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\60\ Petition for Partial Reconsideration of Denial of Petition
for Reconsideration and Petition for Reconsideration of the
Interstate Transport of Fine Particulate Matter: Revision of Federal
Implementation Plan Requirements for Texas (Aug. 28, 2020), Docket
document ID EPA-HQ-OAR-2016-0598-0041, available in
www.regulations.gov.
\61\ 2020 Pet. at 8.
\62\ 2020 Pet. at 9.
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On October 13, 2020, we received a separate petition for partial
reconsideration from NPCA, Sierra Club, and Earthjustice, on our 2020
final rule affirming that the Texas SO2 Trading Program is a
valid alternative to SO2 BART requirements for Texas
EGUs.\63\ In the petition, Petitioner's allege that the EPA presented a
corrected sensitivity analysis for the first time on July 6, 2020, the
day the EPA published notice of its denial of the 2017 administrative
petition for reconsideration of the CSAPR Better-than-BART affirmation
and after the EPA signed the final rule affirming the Texas Regional
Haze BART FIP.
[[Page 28925]]
Specifically, the Petitioners alleged that the corrected sensitivity
analysis is the ``primary evidence'' for the EPA's conclusion that the
Texas SO2 Trading Program is a lawful and valid BART
alternative for SO2 under the Regional Haze Rule, and that
contrary to the EPA's assertions, the ``corrected'' analysis reveals
that the Texas SO2 Trading Program does not achieve greater
reasonable progress than source-specific BART, and therefore, is
arbitrary and contrary to the Clean Air Act and Regional Haze Rule.
Moreover, Petitioners contended that the corrected sensitivity analysis
demonstrates that visibility improvement under CSAPR, including the
Texas SO2 Trading Program, is not equal to or greater than
visibility improvement under source-specific BART averaged over all 140
Class I areas or the 60 eastern Class I areas generally within the
States covered under CSAPR. Because the EPA disclosed the updated
analysis for the first time on July 6, 2020, the Petitioners argued
that the grounds for the objections raised in this petition arose after
the period for public comment, which ended on January 13, 2020, for the
EPA's supplemental notice of proposed rulemaking (84 FR 61,850 (Nov.
14, 2019)). Thus, Petitioners alleged the petition met the requirements
for mandatory reconsideration under CAA section 307(d)(7)(B).
---------------------------------------------------------------------------
\63\ Sierra Club, National Parks Conservation Association, and
Earthjustice Petition for Partial Reconsideration of Promulgation of
Air Quality Implementation Plans; State of Texas; Regional Haze and
Interstate Visibility Transport Federal Implementation Plan EPA-R06-
OAR-2016-0611 (dated Oct. 13, 2020).
---------------------------------------------------------------------------
By letter dated June 22, 2021, the EPA acknowledged receipt of the
petition for partial reconsideration and, without conceding that the
conditions for mandatory reconsideration were necessarily met pursuant
to CAA section 307(d)(7)(B), the agency recognized that aspects of this
action warrant careful review, and potential modification, to ensure
our actions are fully consistent with the requirements of the Clean Air
Act and the Regional Haze Rule.\64\ The letter stated the EPA's intent
to reconsider certain aspects of the Texas Regional Haze BART action,
which we are proposing in this action.
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\64\ Letter from Joseph Goffman, Acting Assistant Administrator
Office of Air and Radiation, Re: Sierra Club and National Parks
Conservation Association, Petition for Partial Reconsideration of
Promulgation of Air Quality Implementation Plans; State of Texas;
Regional Haze and Interstate Visibility Transport Federal
Implementation Plan EPA-R06-OAR-2016-0611 (June 22, 2021) available
in Docket ID No. EPA-R06-OAR-2016-0611 or at https://www.epa.gov/system/files/documents/2021-07/tx-rh-bart-fip-response-signed_1.pdf.
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D. Consultation With Federal Land Managers (FLMs)
The Regional Haze Rule requires that a State, or the EPA if
promulgating a FIP, consult with FLMs before adopting and submitting a
required SIP or SIP revision or a required FIP or FIP revision. Under
40 CFR 51.308(i)(2), a State, or the EPA if promulgating a FIP, must
provide an opportunity for consultation no less than 60 days prior to
holding any public hearing or other public comment opportunity on a SIP
or SIP revision, or FIP or FIP revision, for regional haze. The EPA
must include a description of how it addressed comments provided by the
FLMs when considering a FIP or FIP revision. We consulted with the FLMs
(specifically, U.S. Fish and Wildlife Service, U.S. Forest Service, and
the National Park Service) on December 6, 2022. During the consultation
we provided an overview of our proposed actions. The FLMs signaled
support for our proposed action.\65\
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\65\ See ``Texas Regional Haze FLM Consultation 12-6-2022.xls''
in the docket for this action.
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III. Overview of Proposed Action
In this notice of proposed rulemaking, the EPA proposes an action
with several interrelated components. As more fully explained in the
following sections, on reconsideration, and due to concerns that our
justification for the Texas SO2 Trading Program rested on an
erroneous interpretation of our BART alternative regulations, we are
proposing to withdraw the Texas SO2 Trading Program and
instead propose source-specific BART limits for certain EGUs in Texas.
We are proposing to satisfy the Regional Haze Rule's SO2
BART requirements through conducting a source-specific BART analysis
for certain BART-eligible EGU sources identified in this action.
Additionally, based on our assessment of the effect of this proposed
action with regard to Texas BART (if finalized), we are proposing to
re-affirm our 2017 analytical demonstration that CSAPR remains a valid
BART alternative. Thus, in this action we propose to deny the 2020
petition for partial reconsideration of our 2020 denial of a petition
for reconsideration of that 2017 determination. Finally, we are
proposing to make an error correction under CAA section 110(k)(6) with
respect to our prior approval of the portion of the 2009 Texas Regional
Haze SIP that found that Texas's EGUs are not subject to BART for PM on
the grounds that our approval relied on underlying assumptions as to
how the SO2 and NOX BART requirements for EGUs
were being met that are no longer valid with the proposed withdrawal of
the Texas SO2 Trading Program. As such, we propose to
correct the error by disapproving Texas's 2009 Regional Haze SIP
submission related to PM BART and propose to satisfy PM BART by also
conducting a source-specific BART analysis for certain BART-eligible
EGU sources identified in this action. Unless expressly reopened in
this notice, the EPA is not reopening any other prior determinations
related to regional haze requirements in the State of Texas.
IV. Withdrawal of the Texas SO2 Trading Program as a BART Alternative
for SO2
As previously stated, on August 12, 2020, the EPA published a final
rule affirming our 2017 final rule that the Texas SO2
Trading Program, with amendments, satisfied the requirements for a BART
alternative for SO2 under 40 CFR 51.308(e)(2).\66\ In this
action, we are proposing to find that the basis for the Texas
SO2 Trading Program as a BART alternative rested on an
erroneous interpretation of our BART alternative regulations. That
interpretation in turn produced an analytical basis for the BART
alternative that we now propose to find insufficient and in error. We
are proposing to withdraw the Texas SO2 Trading Program
under CAA section 110(k)(6) and our inherent authority to reconsider
prior actions.
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\66\ See generally 85 FR 49170.
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A. Legal Authority To Withdraw the Texas SO2 Trading Program
1. The EPA's Error Correction Authority Under CAA 110(k)(6)
The EPA proposes to correct its Texas Regional Haze BART FIP by
proposing to withdraw the Texas SO2 Trading Program and
proposing to instead conduct a source-specific BART analysis for the
BART-eligible EGUs included in the Texas SO2 Trading
Program. In this action, we are proposing to find that the Texas
SO2 Trading Program was promulgated on an erroneous basis,
constituting an error under CAA section 110(k)(6).
Section 110(k)(6) of the CAA provides the EPA with the authority to
make corrections to actions on CAA implementation plans that are
subsequently found to be in error. Ass'n of Irritated Residents v. EPA,
790 F.3d 934, 948 (9th Cir. 2015) (110(k)(6) is a ``broad provision''
enacted to provide the EPA with an avenue to correct errors). The key
provisions of section 110(k)(6) are that the Administrator has the
authority to ``determine'' that the promulgation of a plan was ``in
error,'' and when the Administrator does so, may then revise the action
``as
[[Page 28926]]
appropriate,'' in the same manner as the prior action.\67\ Moreover,
CAA section 110(k)(6) ``confers discretion on the EPA to decide if and
when it will invoke the statute to revise a prior action.'' 790 F.3d at
948 (section 110(k)(6) grants the ``EPA the discretion to decide when
to act pursuant to that provision'').
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\67\ See 85 FR 73636, 73637 (Nov. 19, 2020).
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While CAA section 110(k)(6) provides the EPA with the authority to
correct its own ``error,'' nowhere does this provision or any other
provision in the CAA define what qualifies as ``error.'' Thus, the EPA
believes that the term should be given its plain language, everyday
meaning, which includes all unintentional, incorrect, or wrong actions
or mistakes.\68\ Under CAA section 110(k)(6), the EPA must make an
error determination and provide the ``the basis thereof.'' There is no
indication that this is a substantial burden for the Agency to meet. To
the contrary, the requirement is met if the EPA clearly articulates the
error and basis thereof. Ass'n of Irritated Residents v. EPA, 790 F.3d
at 948; see also 85 FR 73636, 73638.
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\68\ See 85 FR at 73637-38.
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2. The EPA's Inherent Authority To Reconsider Its Prior Action
In addition to the error correction provision of CAA section
110(k)(6), the EPA also has the inherent administrative authority to
withdraw the Texas SO2 Trading Program and propose in its
place to conduct a source-specific BART analysis for the BART-eligible
EGUs included in the Texas SO2 Trading Program. This
authority lies in CAA section 301(a), read in conjunction with CAA
section 110 and case law holding that an agency has inherent authority
to reconsider its prior actions.\69\ Section 301(a) authorizes the EPA
``to prescribe such regulations as are necessary to carry out the
[EPA's] functions'' under the CAA. Reconsidering prior rulemakings,
when necessary, is part of the ``[EPA's] functions'' under the CAA--
considering the EPA's inherent authority as recognized under the case
law to do so--and as a result, CAA section 301(a) confers authority
upon the EPA to undertake this rulemaking. Moreover, CAA section
110(c)(1) provides the EPA with the authority to promulgate a FIP where
``the Administrator . . . disapproves a State implementation plan
submission in whole or in part.'' As such, the EPA's authority to
promulgate FIPs under the CAA necessarily provides it the inherent
authority to amend/withdraw FIPs.\70\
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\69\ Trujillo v. General Electric Co., 621 F.2d 1084, 1086 (10th
Cir. 1980) (``Administrative agencies have an inherent authority to
reconsider their own decisions, since the power to decide in the
first instance carries with it the power to reconsider.'')
\70\ See 76 FR 25177, 25181 (May 2011).
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Additionally, it is well-established that the EPA has discretion to
revisit existing regulations. Specifically, agencies have inherent
authority to reconsider past decisions and to revise, replace, or
repeal a decision to the extent permitted by law and supported by a
reasoned explanation. FCC v. Fox Television Stations, Inc., 556 U.S.
502, 515 (2009) (``Fox''); Motor Vehicle Manufacturers Ass'n of the
United States, Inc. v. State Farm Mutual Automobile Insurance Co., 463
U.S. 29, 42 (1983) (``State Farm''); see also Encino Motorcars, LLC v.
Navarro, 579 U.S. 211, 221-22 (2016).
As such, we find that our inherent ability to reconsider past
actions also provides us the authority to withdraw the Texas
SO2 Trading Program for the same reasons as under CAA
section 110(k)(6), as described in Section IV.B. That is, because the
Texas SO2 Trading Program rested on what we find to be an
improper interpretation of our BART alternative regulations, we are
proposing to withdraw the program and to conduct a source-specific BART
analysis for those EGUs currently participating in the program.
The EPA acknowledges the potential for reliance interests to be
affected by our reconsideration of a prior rule. However, the EPA is
not aware of any substantial commitment of resources or capital, or
that the EGUs covered by the Texas SO2 Trading Program
undertook any significant decisions in reliance on participation in the
trading program. The Texas SO2 Trading Program established
an emissions budget that the covered sources were already operating
well below. Therefore, the requirements of the Texas SO2
Trading Program did not cause any sources to invest in new pollution
control technology or to undertake any other significant investments.
Further, because the Texas SO2 Trading Program rested on an
improper interpretation of our BART alternative regulations, we do not
think a reliance interest alone (even if there were such interests)
would be sufficient to overcome the need to return to a proper
interpretation of our BART regulations and proper implementation of the
BART program.
B. Basis for Withdrawing the Texas SO2 Trading Program
We propose that, in attempting to demonstrate that the Texas
SO2 Trading Program satisfied the BART alternative
requirements in 40 CFR 51.308(e)(2), the EPA erroneously relied on its
previous determination that the CSAPR trading program is better-than-
BART nationwide, when in fact the Texas SO2 Trading Program
was a separate BART alternative program that was not a part of the
CSAPR program.\71\ Because the Texas SO2 Trading Program was
and is separate and distinct from CSAPR and functioned as an
independent BART alternative disconnected from any other BART
alternative, we propose that in conducting the comparative analysis
required by 51.308(e)(2)(i), the EPA should have compared the
visibility benefits of the Texas SO2 Trading Program in
isolation with the visibility benefits of source-specific BART controls
for the particular subject-to-BART sources that would have been
required in the absence of the BART alternative. We conducted no such
comparison in either the 2017 rule originally promulgating the Texas
SO2 Trading Program, nor in the 2020 action affirming the
Texas SO2 Trading Program with certain, minor amendments.
For purposes of determining whether it is appropriate to now withdraw
the Texas SO2 Trading Program as a BART alternative, we have
conducted an analysis comparing the Texas SO2 Trading
Program to source-specific BART for the relevant EGU BART sources. We
propose to find that source-specific BART controls substantially
outperform the Texas SO2 Trading Program in terms of
emission reductions and visibility improvement at the Class I areas
that are affected by the sources in Texas. As a result of this finding
of error, we are proposing to withdraw the Texas SO2 Trading
Program as a BART alternative for SO2 and propose in its
place to conduct a source-specific BART analysis for those BART-
eligible EGUs included in the Texas SO2 Trading Program.
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\71\ See 82 FR 48324, 48330 (Oct. 17, 2017).
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1. BART Alternative Requirements
The Regional Haze Rule's BART provisions generally direct States to
identify all BART-eligible sources; determine which of those BART-
eligible sources are subject to BART requirements based on whether the
sources emit air pollutants that may reasonably be anticipated to cause
or contribute to visibility impairment in a Class I area; determine
source-specific BART for each source that is subject to BART
requirements, based on an analysis taking specified factors into
consideration; and include emission limitations reflecting those BART
determinations in their SIPs. However, the Regional Haze Rule also
provides
[[Page 28927]]
each State with the flexibility to adopt an allowance trading program
or other alternative measure instead of requiring source-specific BART
controls, so long as the alternative measure is demonstrated to achieve
greater reasonable progress than BART toward the national goal of
achieving natural visibility conditions in Class I areas.
States, or the EPA if promulgating a FIP, that opt to rely on an
alternative program in lieu of source-specific BART, must meet the
requirements under 40 CFR 51.308(e)(2) and, if applicable, (e)(3).
These requirements for alternative programs establish the criteria for
demonstrating that the alternative program will achieve greater
reasonable progress than would be achieved through the installation and
operation of BART (i.e., they establish the ``better-than-BART'' tests)
and are fundamental elements of any alternative program. To demonstrate
that the alternative program achieves greater reasonable progress than
source-specific BART, States, or the EPA if developing a FIP, must
demonstrate that the alternative meets the requirements, as applicable,
in 40 CFR 51.308(e)(2)(i) through (vi). Separately, under 40 CFR
51.308(e)(4), States whose sources participate in the CSAPR trading
program(s) may rely on such programs to satisfy BART as to the relevant
pollutants and sources without the need for any additional analysis
(discussed in more detail in Section V).
Under 40 CFR 51.308(e)(2), the State, or the EPA, must conduct an
analysis of the best system of continuous emission control technology
available and the associated emission reductions achievable for each
source subject to BART covered by the alternative program, termed a
``BART benchmark.'' \72\ Where the alternative program has been
designed to meet requirements other than BART, simplifying assumptions
may be used to establish a BART benchmark.\73\ The BART benchmark is
the basis for comparison in the better-than-BART test for BART
alternatives. Under 40 CFR 51.308(e)(2)(i)(E), the State or the EPA
must provide a determination that the alternative program achieves
greater reasonable progress than BART under 40 CFR 51.308(e)(3). 40 CFR
51.308(e)(3), in turn, provides two different avenues, applicable under
specific circumstances, for determining whether the BART alternative
achieves greater reasonable progress than BART. If the distribution of
emissions under the alternative program is not substantially different
than under BART, and the alternative program results in greater
emissions reductions of each relevant pollutant than BART, then the
alternative program may be deemed to achieve greater reasonable
progress. On the other hand, if the distribution of emissions is
significantly different, the differences in visibility improvement
between BART and the alternative program must be determined by
conducting dispersion modeling for each impacted Class I area for the
best and worst 20 percent of days. This modeling demonstrates ``greater
reasonable progress'' if both of the following criteria are met: (1)
Visibility does not decline in any Class I area; and (2) there is
overall improvement in visibility when comparing the average
differences in visibility conditions between BART and the alternative
program across all the affected Class I areas.\74\
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\72\ 40 CFR 51.308(e)(2)(i)(C).
\73\ 40 CFR 51.308(e)(2)(i)(C).
\74\ 40 CFR 51.308(e)(3).
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Alternatively, pursuant to 40 CFR 51.308(e)(2)(i)(E), a third test
is available under which States may show that the BART alternative
achieves greater reasonable progress than BART ``based on the clear
weight of evidence.'' As stated in the EPA's revisions to the Regional
Haze Rule governing alternatives to source-specific BART
determinations, such demonstrations attempt to make use of all
available information and data which can inform a decision while
recognizing the relative strengths and weaknesses of that information
in arriving at the soundest decision possible.\75\ Factors which can be
used in a weight of evidence determination in this context may include,
but are not limited to, future projected emissions levels under the
program as compared to under BART, future projected visibility
conditions under the two scenarios, the geographic distribution of
sources likely to reduce or increase emissions under the program as
compared to BART sources, monitoring data and emissions inventories,
and sensitivity analyses of any models used. This array of information
and other relevant data may be of sufficient quality to inform the
comparison of visibility impacts between BART and the alternative
program. In showing that an alternative program is better than BART and
when there is confidence that the difference in visibility impacts
between BART and the alternative scenarios are expected to be large
enough, a weight of evidence comparison may be warranted in making the
comparison.
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\75\ 71 FR 60612, 60622 (Oct. 13, 2006).
---------------------------------------------------------------------------
Under 40 CFR 51.308(e)(2)(iii) and (iv), all emission reductions
for the alternative program must take place during the period of the
first long-term strategy (i.e., the first planning period) for regional
haze and all the emission reductions resulting from the alternative
program must be surplus to those reductions resulting from measures
adopted to meet requirements of the CAA as of the baseline date of the
SIP.
2. The EPA Inappropriately Relied on CSAPR When Promulgating and
Affirming the Texas SO2 Trading Program in 2017 and 2020
The EPA has long maintained that the CSAPR trading programs can
function as a BART alternative for the relevant covered visibility
pollutants for the EGU BART sources that are covered by the relevant
CSAPR trading program. The EPA promulgated CSAPR, a revised multistate
trading program to replace CAIR, in 2011 (and revised it in 2012).\76\
CSAPR established FIP requirements for several States, including Texas,
to address the States' interstate transport obligation under CAA
section 110(a)(2)(D)(i)(I). The EPA made the original CSAPR better-
than-BART determination in a 2012 rulemaking, codified at 40 CFR
51.308(e)(4), and subsequently reaffirmed that determination in a 2017
rulemaking.\77\ At the time of the 2012 rulemaking, Texas was part of
the CSAPR annual NOX and SO2 trading programs to
address interstate transport of PM2.5. Therefore, Texas was
among the States who could choose to meet BART obligations for their
EGUs through participation in the relevant CSAPR trading program. The
EPA subsequently withdrew Texas from CSAPR for purposes of addressing
interstate transport requirements for the PM2.5 NAAQS (i.e.,
Texas was withdrawn from the annual NOX and SO2
trading programs) in response to the D.C. Circuit Court's decision in
EME Homer City Generation, L.P. v. EPA.\78\ However, when the EPA
promulgated the Texas SO2 Trading Program, the Agency
reasoned that it could nonetheless
[[Page 28928]]
satisfy the Regional Haze Rule's BART alternative requirements by
demonstrating that SO2 emissions under the Texas
SO2 Trading Program were comparable to SO2
emissions anticipated from Texas had Texas remained in CSAPR.\79\
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\76\ Federal Implementation Plans; Interstate Transport of Fine
Particulate Matter and Ozone and Correction of SIP Approvals, 76 FR
48208 (Aug. 8, 2011).
\77\ 77 FR 33642 (June 7, 2012) (codified at 40 CFR
51.308(e)(4)). The final rule amended the Regional Haze Rule to
allow States whose EGUs participate in one of the CSAPR trading
programs for a given pollutant to rely on that participation as an
alternative to source-specific BART requirements); see also 82 FR
45481 (Sep 29, 2017) (affirming that CSAPR remained better than BART
nationwide after Texas and other States were removed from CSAPR for
PM).
\78\ EME Homer City Generation, L.P. v. EPA, 795 F. 3d 118, 138
(D.C. Cir. 2015).
\79\ 82 FR 48324, 48336 (Oct. 17, 2017).
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As we explained in our June 2020 affirmation of the Texas
SO2 Trading Program, annual SO2 emissions for
sources covered by the Texas SO2 Trading Program are
constrained by the annual budgets and an assurance level of 255,083
tons. The EPA then added to this amount an estimated 35,000 tons per
year of emissions from units not covered by the Texas SO2
Trading Program, but which would have been covered by the CSAPR
program. This yielded 290,083 tons of SO2, which was below
the 317,100-tons per year emissions level assumed for Texas sources
under CSAPR.\80\ Thus, rather than considering the Texas SO2
Trading Program in isolation as a BART alternative and comparing the
effects of that program to the effects of source-specific BART for the
relevant EGUs in Texas to determine whether it made ``greater
reasonable progress,'' the EPA instead relied on the CSAPR Better-than-
BART analysis as the basis for concluding that the Texas SO2
Trading Program provided greater reasonable progress than BART--even
though the Texas SO2 Trading Program was not connected in
any way to CSAPR and functioned as its own, independent BART
alternative.
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\80\ Promulgation of Air Quality Implementation Plans; State of
Texas; Regional Haze and Interstate Visibility Transport Federal
Implementation Plan 85 FR 49170, 49183 (Aug. 12, 2020).
---------------------------------------------------------------------------
Such reliance is inconsistent with the requirements of the Regional
Haze Rule's requirements for a BART alternative in 40 CFR 51.308(e)(2),
which requires a comparison between the BART alternative and the BART
benchmark for the relevant sources.\81\ Because the Texas
SO2 Trading Program is an intrastate program, the effects of
that program should have been considered independently of CSAPR.
Indeed, participation in the CSAPR program in lieu of implementing BART
requirements is provided for under a separate provision of the Regional
Haze Rule, 40 CFR 51.308(e)(4). Thus, the EPA could only rely on the
analytical demonstrations made in the CSAPR better-than-BART
rulemakings had Texas remained in CSAPR.\82\ Once Texas was withdrawn
from CSAPR, the EPA could not rely on that provision as justification
that the Texas SO2 Trading Program made ``greater reasonable
progress'' than BART at Texas EGUs. Thus, whether the Texas
SO2 Trading Program provided similar or more reductions than
anticipated had Texas remained in CSAPR is irrelevant and fails to
demonstrate that it achieves greater reasonable progress than BART as
required by 40 CFR 51.308(e)(2).
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\81\ 40 CFR 51.308(e)(2).
\82\ Even after the removal of Texas (and other States) from
CSAPR following the remand of certain CSAPR budgets in EME Homer
City Generation, Texas (and other States) had the option to
voluntarily participate in CSAPR to gain the benefit of addressing
BART obligations. Texas declined to adopt this approach.
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Furthermore, although the Texas SO2 Trading Program was
modeled after CSAPR in its design and operation, the two programs are
distinct. First, the sources covered under the Texas SO2
Trading Program do not include all the sources in Texas that were part
of the CSAPR trading program.\83\ Thus, the EPA had to rely on an
unenforceable emissions assumption of 35,000 tons per year from the
non-covered sources to allow for an apples-to-apples comparison between
the Texas program and the CSAPR program in terms of the universe of
sources analyzed.\84\ However, there was no obligation that the non-
covered sources would emit below that assumed level in perpetuity.
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\83\ See 85 FR 49170, 49184.
\84\ 85 FR 49170, 49184.
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Second, CSAPR was designed as a regional trading program that
involved the participation of sources from many States over a wide
geographic area, as compared to the Texas SO2 Trading
Program, which is an intrastate trading program. As such, the Texas
SO2 Trading Program is limited to sources in Texas which
cannot trade allowances with sources in other States as is permitted
under CSAPR. Because of the scope of participation in CSAPR, in
demonstrating that CSAPR was Better-than-BART, the EPA was not required
by the rule to demonstrate that CSAPR achieves greater reasonable
progress than BART at every Class I area or in every State.\85\ Rather,
the EPA demonstrated that CSAPR achieved greater visibility improvement
than BART when visibility was averaged across all Class I areas.\86\ In
averaging visibility improvement from CSAPR across all the affected
Class I areas, the 2012 demonstration properly relied on the
substantial emission reductions anticipated to occur in the eastern
half of the country for which other States, which included Texas at the
time, could take advantage of without having to apply source-specific
BART.\87\ For example, SO2 emissions in Tennessee were
anticipated to be approximately 321,300 in a nationwide BART
scenario,\88\ but only approximately 66,700 under CSAPR.\89\ Similar
situations were also anticipated in several other States including Ohio
(546,700 tons of SO2 under a nationwide BART scenario
compared to only 190,000 tons under CSAPR); Indiana (454,500 tons of
SO2 under a nationwide BART scenario compared to only
202,900 tons under CSAPR); and Pennsylvania (222,600 tons of
SO2 under a BART scenario compared to only 134,500 tons
under CSAPR).\90\
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\85\ See 77 FR at 33650.
\86\ See e.g., 77 FR at 33650.
\87\ Specifically, in the 2017 affirmation that CSAPR remains
better than BART after withdrawal of multiple States from CSAPR,
including Texas, we stated that the 2012 analytic demonstration
showed that the difference in emissions between the CSAPR scenario
plus BART elsewhere would lead to an overall reduction in
SO2 emission reductions for the overall modeled region of
773,000 tons as compared to application of source specific BART
nationwide. See memo entitled ``Sensitivity Analysis Accounting for
Increases in Texas and Georgia Transport Rule State Emissions
Budgets,'' Docket document ID No. EPA-HQ-OAR-2011-0729-0323 (May 29,
2012) (2012 CSAPR/BART sensitivity analysis memo), at 1-2, available
in the docket for this proposed action.
\88\ For all BART-eligible EGUs in the Nationwide BART scenario
and for BART-eligible EGUs not subject to CSAPR for a particular
pollutant in the CSAPR + BART-elsewhere scenario, the modeled
emission rates were the presumptive EGU BART limits for
SO2 and NOX as specified in the BART
Guidelines (Appendix Y to 40 CFR part 51--Guidelines for BART
Determinations under the Regional Haze Rule), unless an actual
emission rate at a given unit with existing controls was lower, in
which case the lower emission rate was modeled. (For additional
details see Technical Support Document for Demonstration of the
Transport Rule as a BART Alternative, Docket document ID No. EPA-HQ-
OAR-2011-0729-0014 (December 2011) (2011 CSAPR/BART Technical
Support Document EPA-HQ-OAR-2011-0729-0014) in www.regulations.gov.
\89\ See Technical Support Document for Demonstration of the
Transport Rule as a BART Alternative, Docket document ID No. EPA-HQ-
OAR-2011-0729-0014 (December 2011) (2011 CSAPR/BART Technical
Support Document EPA-HQ-OAR-2011-0729-0014), at table 2-4, also
available in the docket for this action at document ID EPA-R06-OAR-
2016-0611-0119.
\90\ See Technical Support Document for Demonstration of the
Transport Rule as a BART Alternative, Docket ID No. EPA-HQ-OAR-2011-
0729-0014 (December 2011) (2011 CSAPR/BART Technical Support
Document), at table 2-4, available in www.regulations.gov, document
ID EPA-R06-OAR-2016-0611-0119.
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However, while CSAPR leads to greater emissions reductions overall
over the modeled region, we explained that for certain CSAPR States,
application of source-specific BART was projected to lead to greater
emission reductions than through participation in CSAPR. We explained
that this could occur in CSAPR States that have numerous BART-eligible
EGUs.\91\ One
[[Page 28929]]
such State where this was anticipated to occur was Texas. In the case
of Texas, the projected SO2 emissions from affected EGUs in
the modeled nationwide-BART scenario (139,300 tons per year) are
considerably lower than the projected SO2 emissions from the
affected EGUs in the CSAPR scenario (266,600 tons per year as modeled,
and up to approximately 317,100 tons, as addressed in the 2012 CSAPR/
BART sensitivity analysis memo).\92\ Thus, the application of
presumptive source-specific BART, instead of participation in the CSAPR
SO2 trading program, would have resulted in projected
emissions of 139,300 tons per year, a reduction in projected
SO2 emissions by between approximately 127,300 tons and
177,800 tons from the CSAPR SO2 trading program
emissions.\93\ As a result, a demonstration that the Texas
SO2 Trading Program achieves equivalent emissions reductions
as anticipated had Texas remained in CSAPR fails to demonstrate that
the Texas SO2 Trading Program achieves greater reasonable
progress than BART for the BART sources in Texas participating in the
Texas SO2 Trading Program. The comparison in estimated
emissions above strongly indicates this not to be the case.
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\91\ 81 FR 78954, 78962-63 (Nov. 10, 2016).
\92\ 81 FR 78954, 78962-63 (Nov. 10, 2016).
\93\ 81 FR 78954, 78962-63 (Nov. 10, 2016). As stated in both
the proposal and final rule withdrawing Texas from CSAPR
SO2 trading program, the 127,300-ton amount was described
as the minimum reduction in projected Texas SO2 emissions
because it did not reflect a 50,500-ton increase in the Texas
SO2 budget that occurred after the original CSAPR
scenario was modeled. If that budget increase had been reflected in
the original CSAPR scenario, modeled Texas EGU SO2
emissions in that scenario would likely have been higher,
potentially by the full 50,500-ton amount. The CSAPR budget increase
would have had no effect on Texas EGUs' modeled SO2
emissions under BART. Therefore, the 127,300-ton minimum estimate of
the reduction in projected Texas SO2 emissions caused by
removing Texas EGUs from CSAPR for SO2, which are
computed as the difference between Texas EGUs' collective emissions
in the original CSAPR scenario and the BART scenario, may be
understated by as much as 50,500 tons. See 82 FR at 45492; 81 FR at
78962-63.
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Thus, we propose that it was an error to allow the Texas
SO2 Trading Program to rely on a demonstration made for a
different and unconnected BART alternative (i.e., CSAPR) because it
failed to comport with the requirements in 40 CFR 51.308(e)(2).
Instead, the EPA should have assessed whether the Texas SO2
Trading Program provides for greater reasonable progress than BART for
those BART sources in Texas covered by the Texas SO2 Trading
Program.\94\
---------------------------------------------------------------------------
\94\ See 40 CFR 51.308(e)(2), (e)(3).
---------------------------------------------------------------------------
3. The Texas SO2 Trading Program Does Not Achieve Greater
Reasonable Progress Than BART
Because the 2017 Texas BART FIP and subsequent affirmation
improperly relied on CSAPR to support the validity of the Texas
SO2 Trading Program, there is no evidence in the record to
support a finding that the Texas SO2 Trading Program
provides for greater reasonable progress than BART when compared to the
proper BART benchmark (i.e., source specific BART for the sources in
Texas covered by the Texas SO2 Trading Program). Rather, the
relevant information indicates that had the Texas SO2
Trading Program been compared to the appropriate Texas-specific BART
benchmark, the analysis would have found that the Texas SO2
Trading Program does not provide for greater reasonable progress than
BART at the Class I areas affected by those sources.
For purposes of determining whether it is appropriate to now
withdraw the Texas SO2 Trading Program as a BART
alternative, we have conducted an analysis comparing the effects of the
Texas SO2 Trading Program to source-specific BART for the
relevant EGU BART sources. The purpose of this analysis is not to
conduct a full re-evaluation of the Texas SO2 Trading
Program under each of the requirements of the BART-alternative
regulations of 40 CFR 51.308(e)(2). Rather, this analysis evaluates the
question of whether, even under conservative assumptions, the Texas
SO2 Trading Program, when compared to the proper BART
benchmark (source-specific BART for the relevant sources in Texas),
could possibly achieve greater reasonable progress. The analysis
confirms a stark disparity in outcomes, with the Texas SO2
Trading Program not securing any additional emission reductions and
even allowing for substantial SO2 emissions increases from
baseline levels while source-specific BART would achieve substantial
SO2 emissions decreases. We propose to find that the
installation and operation of source-specific BART controls
substantially outperform the Texas SO2 Trading Program in
terms of emission reductions and resulting visibility improvement at
the Class I areas that are affected by the sources in Texas, and that
the Texas SO2 Trading Program does not achieves greater
reasonable progress than BART as required by 40 CFR 51.308(e)(2).
As we explained earlier in Section II and in our June 2020
affirmation of the Texas SO2 Trading Program as an
alternative to BART for SO2, annual SO2 emissions
for sources covered by the Texas SO2 Trading Program are
constrained by the annual budgets and an assurance level of 255,083
tons.\95\ The Texas SO2 Trading Program imposes a penalty
surrender ratio of three allowances for each ton of emissions in any
year in excess of the assurance level, which provides a disincentive
against emissions exceeding the assurance level. Added to this amount
is an estimated 35,000 tons per year of emissions from units not
covered by the Texas SO2 Trading Program, but which would
have been covered by the CSAPR program. This yields an estimated
290,083 tons of SO2 from all Texas EGUs. This is
significantly higher than the 139,300 tons per year estimated in the
nationwide BART only scenario for Texas EGUs in the 2012 CSAPR better
than BART demonstration. In other words, the presumptive BART scenario
developed for the 2012 demonstration would result in approximately
150,000 tons per year less SO2 emissions than the Texas
SO2 Trading Program scenario.
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\95\ 85 FR 49170, 49183 (Aug. 12, 2020).
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We note, however, that this comparison of emissions of the Texas
SO2 Trading Program and presumptive BART from the 2012 CSAPR
analysis does not account for recent facility shutdowns. Sandow,\96\
Big Brown,\97\ and Monticello \98\ retired in 2018. Welsh Unit 2
retired in 2016,\99\ and the J. T. Deely units retired at the end of
2018.\100\ While these retirements have resulted in overall emission
reductions, they have also resulted in a surplus of allowances that
serve to decrease or eliminate any
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\96\ See letter dated February 14, 2018, from Kim Mireles of
Luminant to the TCEQ requesting to cancel certain air permits and
registrations for Sandow Steam Electric Station available in the
docket for this action at document ID EPA-R06-OAR-2016-0611-0143 for
Sandow Unit 4 and document ID EPA-R06-OAR-2016-0611-0134 for Sandow
Unit 5.
\97\ See letter dated March 27, 2018, from Kim Mireles of
Luminant to the TCEQ requesting to cancel certain air permits and
registrations for Big Brown available in the docket for this action
at document ID EPA-R06-OAR-2016-0611-0130.
\98\ See letter dated February 8, 2018, from Kim Mireles of
Luminant to the TCEQ requesting to cancel certain air permits and
registrations for Monticello available in the docket for this action
at document ID EPA-R06-OAR-2016-0611-0132.
\99\ Welsh Unit 2 was retired on April 16, 2016, pursuant to a
Consent Decree (No. 4:10-cv-04017-RGK) and subsequently removed from
the Title V permit (permit no. O26). See ``TX197.183 Turk (Welsh)
Consent Decree 12.22.11'' (document ID EPA-R06-OAR-2016-0611-0138)
and ``TX187.129 AIR OP_O26-13404_Permits_Public_20160919_Project
File Folder_1410429 (document ID EPA-R06-OAR-2016-0611-0129) in the
docket for this action.
\100\ See letters dated December 2021 from the TCEQ to Danielle
Frerich regarding the cancellation of air quality permits for the J.
T. Deely Units available in the docket for this action.
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[[Page 28930]]
regulatory pressure from the Texas SO2 Trading Program to
further decrease emissions from current levels. Under the Texas
SO2 Trading Program, retired units continue to be allocated
allowances for a period of five years.\101\ After that period, those
allowances are still allocated but to the supplemental allowance
pool.\102\ Sources participating in the Texas SO2 Trading
Program have flexibility to transfer allowances among multiple
participating units under the same owner/operator when planning
operations, and unused allowances can be banked for use in future
years.\103\ Furthermore, allowances are allocated from the supplemental
allowance pool each year if the reported emissions for an ownership
group exceeds the amount of allowances allocated to that group, with a
limit on these allocations in any year of 16,688 tons plus any
allowances added to the pool in that year from retired units. The
combination of allocations to retired units, banking of allowances, and
allocations from the supplemental allowance pool results in an excess
availability in allowances to cover the sources' emissions with the
only limitation being the assurance level.
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\101\ 40 CFR 97.911(a)(2).
\102\ 40 CFR 97.911(a)(2).
\103\ See 45 FR at 49208.
---------------------------------------------------------------------------
Because the Texas SO2 Trading Program contains both BART
and non-BART EGUs, we must establish emission estimates for both types
of units to compare the installation and operation of source-specific
BART for SO2 to the Texas SO2 Trading Program.
For the purposes of comparing the Texas SO2 Trading Program
to source-specific BART, we assume that all BART-eligible coal-fired
sources are subject to BART \104\ and that source-specific BART results
in emission reductions greater than or equal to those reductions
estimated based on a presumptive BART level of 0.15 lb/MMBtu.\105\
\106\ For the gas fired sources included in the Texas SO2
Trading Program, we assume that they are not subject to BART for
purposes of this analysis and thus treat them as non-BART sources.\107\
We note that an assumption of 95 percent control would result in lower
emissions than the 0.15 lb/MMBtu rate for all BART units, however, for
the purpose of this comparison, we are selecting a conservative (high)
estimate for presumptive BART limits to illustrate the large emission
reductions available through the installation and operation of BART
even at this conservatively high emission rate. We also note that the
assumption of 0.15 lb/MMBtu is more conservative than what was used for
these units in the 2012 CSAPR Better-than-BART analysis.
---------------------------------------------------------------------------
\104\ This is consistent with our subject to BART screening
analysis below in Section VII.
\105\ BART Guidelines, 70 FR 39104, 39131 (July 6, 2005). ``. .
., we are establishing a BART presumptive emission limit for coal-
fired EGUs greater than 200 MW in size without existing
SO2 control. These EGUs should achieve either 95 percent
SO2 removal, or an emission rate of 0.15 lb
SO2/MMBtu, unless a State determines that an alternative
control level is justified based on a careful consideration of the
statutory factors.''
\106\ In Section VII of this proposed action, we evaluate and
identify which of the BART-eligible EGUs currently in the Texas
SO2 Trading Program are subject to BART sources as well
as the analysis of the five factors that inform the BART
determination for subject to BART sources. In Section VIII, we
provide our weighing of the factors and proposed determination on
source-specific BART requirements for these sources.
\107\ We note that in Section VII we determined that W. A.
Parish Unit WAP4, which is gas fired, is subject to BART because it
is co-located with two other coal-fired BART units (Units WAP5 &
WAP6). Thus, in evaluating whether the BART-eligible units at W. A.
Parish were subject to BART we evaluated emissions from Units WAP4
with WAP5 & WAP6, which is consistent with the subject to BART
evaluation process as explained in Section VII. For Unit WAP4, we
are not assuming any further reductions due to application of BART
because of the inherently low levels of SO2 from firing
natural gas.
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To estimate emissions for BART sources, we multiplied the average
heat input from 2016-2020 by a presumptive BART emission rate of 0.15
lb/MMBtu.\108\ To obtain a conservative estimate for non-BART units, we
used the maximum annual emissions from the 2016-2020 period for each
unit. The use of the maximum annual emissions from the 2016-2020 period
for each non-BART unit provides a conservative assumption of emissions
anticipated from these units to represent a scenario in which they are
not participating in the Texas SO2 Trading Program. We then
added the estimated emissions from the BART units together with the
estimated emissions from the non-BART units to compare emissions
between the Texas SO2 Trading Program and BART. Sources that
have recently shutdown were not included in the analysis. In addition
to comparing emission levels under source-specific BART to the
assurance level of the Texas SO2 Trading Program, we also
consider the impact of source-specific BART on current emissions levels
under the program.
---------------------------------------------------------------------------
\108\ The Fayette BART units (Units 1 and 2) are currently
operating well below 0.15 lb/MMBtu. For these units, the maximum
annual emissions from 2016-2020 were used in this comparison.
---------------------------------------------------------------------------
Table 1 shows 2021 annual emissions in one column, and the other
column shows estimated emissions under the presumptive BART assumptions
plus the maximum annual emissions from the 2016-2020 period for those
non-BART units as described in the paragraph above. The 2021 emissions
are the most recent annual emissions available at the time of this
action and represent emissions under the Texas SO2 Trading
Program regulations, including the amended provisions in the 2020 final
action. Under these conservative assumptions, presumptive BART for
those BART-eligible units plus the maximum annual emissions from the
2016-2020 period for those non-BART units still results in an
approximately 32 percent reduction in total estimated emissions as
compared to actual emissions for these same sources as provided for
under the Texas SO2 Trading Program. This is a significant
reduction compared to actual emissions and far below the assurance
level of 255,083 tons per year. Additionally, in looking at only
subject-to-BART units, presumptive BART reduces emissions by more than
70,000 tons as compared to what those units are emitting under the
Texas SO2 Trading Program. The estimated emissions for the
BART sources under presumptive BART of 24,108 tons is also far below
the allowance allocations to these units of 96,487 tons of allowances
per year. As detailed in Section VIII, our determinations of source-
specific BART result in even larger emission reductions than what was
calculated here under these presumptive BART assumptions.
[[Page 28931]]
Table 1--Comparison of Actual Emissions Under the Texas SO2 Trading
Program and Presumptive BART \109\
------------------------------------------------------------------------
Presumptive BART
emissions plus
2021 Actual max. emissions
emissions (tons) for non-BART
(tons)
------------------------------------------------------------------------
Total (SO2 Trading Program Units). 129,790 88,023
Total (Subject-to-BART units only) 96,601 24,108
------------------------------------------------------------------------
Because the alternative program under review, the Texas
SO2 Trading Program, results in much higher emissions than
source-specific BART, we are proposing to find that the Texas
SO2 Trading Program does not meet the requirements of a BART
alternative under 40 CFR 51.308(e)(2). As discussed earlier, if the
distribution of emissions under the alternative program is not
substantially different than under BART, and the alternative program
results in greater emissions reductions of each relevant pollutant than
under BART, then the alternative program may be deemed to achieve
greater reasonable progress.\110\ The Texas SO2 Trading
Program under review does not result in greater emission reductions
than under BART. Rather, compared to the presumptive BART scenario,
emissions from sources covered by the Texas SO2 Trading
Program are similar or higher. Furthermore, the Texas SO2
Trading Program does not secure emission reductions at non-BART sources
in Texas to compensate for the higher than BART emissions at the Texas
BART sources. In these situations, a BART alternative program can only
achieve greater reasonable progress than BART when emission reductions
from non-BART sources are large enough (or the resulting visibility
benefits from those reductions are large enough) to compensate for
smaller emission reductions at BART sources than would be achieved
under source-specific BART.
---------------------------------------------------------------------------
\109\ See ``Annual EI Texas thru 2021.xlsx'' available in the
docket for this action.
\110\ 40 CFR 51.308(e)(2)(E), (e)(3).
---------------------------------------------------------------------------
This finding that the Texas SO2 Trading Program, which
was designed to achieve a stringency level on par with CSAPR, does not
achieve greater reasonable progress than BART, when isolated to the
units in Texas, is not surprising, and it does not undermine the
continued validity of CSAPR as a BART-alternative in other States. As
discussed earlier in Section IV.B.2, the CSAPR program resulted in
large emission reductions anticipated to occur in the eastern half of
the country due to its coverage of both many BART sources and many non-
BART sources. However, this was not true for every State. Texas, for
instance, generally had higher emissions under the CSAPR BART
alternative compared to source-specific BART, since it had relatively
more BART-eligible sources compared to many other States in the eastern
United States. As discussed, Texas was removed from the CSAPR
SO2 trading program in September 2017, and therefore, cannot
rely on the reductions in the eastern half of the country brought about
by CSAPR because the Texas SO2 Trading Program is
independent of CSAPR. As an independent BART alternative, the Texas
SO2 Trading Program is deficient because it secures no
additional emission reductions from any non-BART sources and, as
demonstrated, the BART emission reductions that would need to be offset
are very large. Because the Texas SO2 Trading Program
secures no reductions (and in fact would have permitted significant
growth in emissions from current levels), the establishment of source-
specific BART emission limits would result in large additional emission
reductions by comparison that would result in comparatively greater
visibility benefits. Accordingly, the Texas SO2 Trading
Program does not provide for greater reasonable progress than the
installation and operation of BART, and therefore, fails to meet the
requirements for a BART alternative under the Regional Haze Rule. Thus,
we are proposing to withdraw the Texas SO2 Trading Program
and instead propose to satisfy the Regional Haze Rule's SO2
BART requirements through conducting a source-specific BART analysis
for certain BART-eligible EGU sources identified in Sections VII and
VIII of this action.
V. CSAPR Participation as a BART Alternative
A. Introduction
If the proposed source-specific BART requirements in Texas are
finalized, the analytical basis within the EPA's withdrawal of Texas
from the CSAPR trading programs for annual NOX and
SO2 in September of 2017 will be restored (82 FR 45481).
Therefore, the EPA is proposing to find that, if this proposal to
implement source-specific BART requirements at certain EGUs in Texas is
finalized, the analytical basis for concluding that the implementation
of CSAPR in the remaining covered States will continue to meet the
criteria for a BART alternative for those States remains valid. Related
to this finding, the EPA is also proposing to deny a 2020
administrative petition for partial reconsideration brought by Sierra
Club, National Parks Conservation Association (NPCA), and Earthjustice
of the EPA's June 2020 denial of a 2017 petition to reconsider the
EPA's original September 2017 finding, the details of which are
provided in the next sections. Based on this analysis, the EPA is
affirming the current Regional Haze Rule provision allowing States
whose EGUs continue to participate in a CSAPR trading program for a
given pollutant to continue to rely on CSAPR participation as a BART
alternative for its BART-eligible EGUs for that pollutant. The public
is invited to comment on this proposed basis for denying the 2020
petition for partial reconsideration.
B. Background
1. CSAPR Better-Than-BART
a. General Background
CSAPR (76 FR 48208; Aug. 8, 2011) implements a series of emissions
trading programs for sulfur dioxide (SO2) and nitrogen
oxides (NOX) across the eastern United States to address
interstate ozone and fine particulate (PM2.5) pollution
under CAA section 110(a)(2)(D)(i)(I) (the ``good neighbor
provision'').\111\ The EPA has issued regulations allowing the CSAPR
States to rely on participation in these trading programs in lieu of
requiring source-specific BART controls at their BART-eligible EGUs
covered by one or more of the CSAPR trading programs with respect to
the visibility pollutant at issue (i.e., NOX or
SO2). See
[[Page 28932]]
40 CFR 51.308(e)(4).\112\ This determination authorizing reliance on
CSAPR participation as a BART alternative is often referred to as
``CSAPR Better-Than-BART.'' \113\
---------------------------------------------------------------------------
\111\ 42 U.S.C. 7410(a)(2)(D)(i)(I).
\112\ The EPA had previously made a similar finding for the
predecessor to CSAPR, the Clean Air Interstate Rule (CAIR), and this
determination was upheld in UARG v. EPA, 471 F.3d 1333 (D.C. Cir.
2006) (UARG I).
\113\ 77 FR 33642 (June 7, 2012).
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In the EPA's 2012 action promulgating CSAPR Better-Than-BART, the
EPA used air quality modeling to show CSAPR met the two-pronged
numerical test for a BART alternative.\114\ To account for certain
CSAPR State-budget increases that were made after the initial modeling
was conducted, the 2012 CSAPR Better-Than-BART determination also
included a sensitivity analysis (2012 sensitivity analysis) that
examined the effect of those budget increases on the modeled visibility
impacts for the CSAPR scenario.\115\ In the 2012 action, the EPA found
that under a scenario analyzing the visibility benefits of CSAPR
(referred to as the ``CSAPR + BART-Elsewhere'' scenario), visibility
would not decline in any Class I area compared to a baseline scenario,
satisfying the first prong of the two-pronged BART-alternative test.
The EPA also found that the CSAPR + BART-Elsewhere scenario would
result in an overall improvement in visibility on average across
affected Class I areas, as compared to a scenario analyzing visibility
benefits resulting from ``presumptive'' BART limits at all BART-
eligible sources (referred to as the ``nationwide BART'' scenario),
satisfying the second prong of the two-pronged BART-alternative test.
The EPA's findings held true whether looking at the 60 Class I areas in
the eastern U.S. most heavily impacted by the sources subject to CSAPR
or looking at all 140 Class I areas in the continental United States.
The United States Court of Appeals for the D.C. Circuit (D.C. Circuit)
upheld this action in UARG v. EPA, 885 F.3d 714 (D.C. Cir. 2018) (UARG
II).
---------------------------------------------------------------------------
\114\ 40 CFR 51.308(e)(3); See generally 77 FR 33642 (June 7,
2012).
\115\ See 77 FR 33642, 33651-52; This sensitivity analysis was
included in a technical memo accompanying the 2012 action. See
``Sensitivity Analysis Accounting for Increases in Texas and Georgia
Transport Rule State Budgets,'' Docket ID No. EPA-HQ-OAR-2011-0729
and in the docket for this action at document ID EPA-R06-OAR-2016-
0611-0113.
---------------------------------------------------------------------------
To account for certain CSAPR State-budget increases that were made
after the initial modeling was conducted, the 2012 CSAPR Better-Than-
BART determination also included a sensitivity analysis (2012
sensitivity analysis) that examined the effect of those budget
increases on the modeled visibility impacts for the CSAPR + BART-
Elsewhere scenario.\116\ The EPA determined that the increases in
SO2 and NOX budgets were small enough that they
did not require a comprehensive set of new power sector and air quality
modeling. Instead, the 2012 sensitivity analysis applied a simple, but
very conservative adjustment factor to the existing quantitative air
quality modeling results to show that, even with the higher emissions
budgets, the CSAPR + BART-Elsewhere scenario was still projected to
show greater reasonable progress toward natural visibility than the
Nationwide BART scenario. Specifically, the 2012 sensitivity analysis
applied adjustments to visibility impacts in the CSAPR + BART-Elsewhere
scenario to account for increases in the SO2 budgets for
Texas and Georgia, since SO2-driven impacts were the most
important impacts in the analysis and Texas and Georgia had the largest
SO2 budget increases.
---------------------------------------------------------------------------
\116\ See 77 FR 33642, 33651-52; This sensitivity analysis was
included in a technical memo accompanying the 2012 action. See
``Sensitivity Analysis Accounting for Increases in Texas and Georgia
Transport Rule State Budgets,'' Docket ID No. EPA-HQ-OAR-2011-0729
and in the docket for this action at document ID EPA-R06-OAR-2016-
0611-0113.
---------------------------------------------------------------------------
The 2012 sensitivity analysis identified sets of Class I areas that
are most impacted by emissions in Texas (9 areas) and Georgia (7 areas)
and assumed that all of the modeled visibility improvement in those
sets of Class I areas is due to SO2 emissions reductions
from either Texas or Georgia, respectively. This methodology is highly
conservative because the projected SO2 emissions reductions
in Texas and Georgia represented only 4.4 percent and 1.8 percent,
respectively, of the total projected regional emissions reductions in
the CSAPR + BART-Elsewhere scenario, and the Class I areas most
impacted by Texas and Georgia emissions are also affected by the very
large emissions reductions projected from other States in the regional
CSAPR + BART-Elsewhere scenario. By assuming a linear relationship
between emissions increases in Texas and Georgia and visibility
degradation in those Class I areas, the EPA very conservatively
determined that even with the budget increases, the CSAPR + BART-
Elsewhere scenario was projected to achieve greater visibility
improvement than the Nationwide BART scenario on average across all 60
eastern Class I areas and all 140 nationwide Class I areas, thereby
satisfying the second prong of the two-pronged test under 40 CFR
51.308(e)(3). The sensitivity analysis also showed no visibility
degradation in the CSAPR + BART-Elsewhere scenario relative to the
baseline scenario at any Class I area, thereby satisfying the first
prong of the test.
b. The CSAPR Remand and the EPA's 2017 Affirmation of CSAPR Better-
Than-BART
The original 2011 CSAPR action was largely upheld by the Supreme
Court in 2014.\117\ However, the case was remanded to the D.C. Circuit
to assess whether the EPA may have ``over-controlled'' certain States
for purposes of implementing the good neighbor provision. In EME Homer
City Generation, L.P. v. EPA, 795 F.3d 118 (D.C. Cir. 2015), based on
this potential for overcontrol, the court remanded certain State
budgets to the EPA, including Texas' SO2 budget, which the
EPA had established to address PM2.5 transport.
---------------------------------------------------------------------------
\117\ EPA v. EME Homer City Generation, L.P., 572 U.S. 489
(2014).
---------------------------------------------------------------------------
To address the remand, in November 2016, the EPA proposed to remove
Texas EGUs from the CSAPR SO2 Group 2 Trading Program as
well as the CSAPR NOX Annual Trading Program, which
similarly addressed PM2.5 transport.\118\ The EPA indicated
that if the withdrawal was finalized, Texas would no longer be eligible
under 40 CFR 51.308(e)(4) to rely on participation of its EGUs in a
CSAPR trading program as an alternative to source-specific
SO2 BART determinations.\119\ The EPA also provided a
proposed analysis (2016 proposed analysis) showing that the changes in
the geographic scope of CSAPR coverage since the EPA's original 2012
CSAPR Better-Than-BART determination, including the proposed withdrawal
of Texas EGUs from the CSAPR SO2 and annual NOX
trading programs, would not have altered the 2012 determination because
the changes would not have altered the EPA's analytical findings that
both prongs of the two-pronged test for a BART alternative under 40 CFR
51.308(e)(3) were satisfied.\120\
---------------------------------------------------------------------------
\118\ See 81 FR 78954 (Nov. 10, 2016).
\119\ Id. at 78956; the EPA also noted that because Texas EGUs
would continue to participate in a CSAPR trading program for ozone-
season NOX emissions, Texas would still be eligible under
40 CFR 51.308(e)(4) to rely on CSAPR participation as an alternative
to source-specific NOX BART determinations for the
covered sources. 81 FR at 78962.
\120\ See id. at 78961-64.
---------------------------------------------------------------------------
In September 2017, the EPA finalized the withdrawal of Texas EGUs
from the
[[Page 28933]]
CSAPR SO2 and annual NOX programs.\121\ In the
same action, the EPA also issued its final analysis (2017 final
analysis) showing that, even with Texas EGUs no longer participating in
these programs (and other changes in the geographic coverage of CSAPR),
the EPA's original 2012 analytical finding that CSAPR is better than
BART remained valid.\122\ In response to comments received on the 2016
proposed analysis, the EPA's 2017 final analysis included an evaluation
of the potential impact of emissions shifting under both prongs of the
two-pronged test for a BART alternative under 40 CFR 51.308(e)(3). This
analysis focused on the fact that if Texas sources were withdrawn from
the CSAPR SO2 Group 2 Trading Program, they would no longer
purchase up to 22,300 SO2 allowances from sources in other
Group 2 States, as had been projected in the CSAPR + BART-Elsewhere
scenario used in the 2012 CSAPR Better-Than-BART determination. As to
the first prong, the EPA explained that, relative to a baseline
scenario without CSAPR or BART, a revised CSAPR + BART-Elsewhere
scenario with an increased quantity of SO2 allowances
available for use by units in other Group 2 States would still show no
visibility degradation at any Class I area because, absent unusual
circumstances that the EPA showed were not expected to occur in this
case, all units in the remaining Group 2 States would still have
stronger incentives to control their SO2 emissions in the
revised CSAPR + BART-Elsewhere scenario (with some positive allowance
price) than in the baseline scenario (without any allowance
price).\123\
---------------------------------------------------------------------------
\121\ See 82 FR 45481 (September 29, 2017).
\122\ See id. at 45490-94.
\123\ Id. at 45493.
---------------------------------------------------------------------------
As to the second prong, the EPA assumed that the availability of
22,300 additional allowances would result in a 22,300-ton increase in
emissions in the remaining Group 2 States, but observed that the
potential adverse visibility impacts of those emissions would be more
than offset by the favorable visibility impacts of at least 127,300
tons of reduced emissions in Texas under presumptive source-specific
SO2 BART for the State's BART-eligible EGUs.\124\ In other
words, under the methodological framework the EPA devised in 2012 to
compare CSAPR with BART, see 77 FR 33648-49, the EPA concluded that the
``Transport Rule [CSAPR] + BART Elsewhere'' scenario would still
outperform the ``Nationwide BART'' scenario, even if Texas's EGU BART
sources fell under the ``BART Elsewhere'' category rather than the
CSAPR category. Thus, the EPA's conclusion that CSAPR satisfied the
second prong of the two-pronged test rested in part on assuming net
SO2 reductions of approximately 105,000 tons from
presumptive source-specific BART in Texas, after accounting for the
potential for shifting of 22,300 tons of emissions from Texas to the
remaining Group 2 States.\125\
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\124\ Id. at 45493-94.
\125\ 82 FR 45493-94.
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2. Promulgation and Affirmation of the Texas SO2 Trading
Program as a BART Alternative
As explained in Section II.C, rather than finalize source-specific
BART SO2 emission limits for subject-to-BART EGUs in Texas
(as had been assumed in the September 2017 finding affirming CSAPR as
better than BART), the EPA took final action in October 2017
establishing an intrastate trading program for SO2 for
certain Texas EGUs as an alternative to BART.\126\ On June 29, 2020,
after completing rulemaking proceedings on reconsideration, the EPA
affirmed the Texas SO2 Trading program as a BART
alternative, with certain amendments as proposed in November 2019.\127\
This rulemaking, its rationale, and subsequent reconsideration and
affirmation in June 2020 are summarized in Section II.C and are not
repeated here.
---------------------------------------------------------------------------
\126\ See 82 FR 48324 (October 17, 2017); In the same January
2017 and October 2017 notices, the EPA also proposed and finalized
action to rely on CSAPR participation as a NOX BART
alternative for Texas EGUs, see 82 FR at 946; 82 FR at 48361.
\127\ 85 FR 49170 (Aug. 12, 2020).
---------------------------------------------------------------------------
3. The EPA's Denial of Petition for Reconsideration of the 2017
Affirmation of CSAPR As a BART Alternative
On November 28, 2017, the Sierra Club and NPCA submitted a petition
for partial reconsideration (2017 petition) under CAA section
307(d)(7)(B) of our September 29, 2017 action withdrawing Texas from
the CSAPR trading programs for SO2 and annual NOX
and affirming that CSAPR participation continues to satisfy
requirements as a BART alternative (September 2017 Final Rule).\128\
The petitioners alleged that it was impracticable, and indeed
impossible, to comment on the relationship between the Texas
SO2 Trading Program and the CSAPR Better-Than-BART analysis
in the final rule because the EPA did not finalize the Texas
SO2 Trading Program until after the final rule was signed
and the EPA had assumed presumptive source-specific SO2 BART
controls in the rulemaking record for the final rule.\129\ The
petitioners also alleged it was impracticable to comment on other
aspects of the EPA's geographic emissions shifting analysis, which was
not presented until the final rule.\130\ The petitioners argued that
both sets of issues are of central relevance to the September 2017
Final Rule.
---------------------------------------------------------------------------
\128\ The Sierra Club and National Parks Conservation
Association, Petition for Partial Reconsideration of Interstate
Transport of Fine Particulate Matter: Revision of Federal
Implementation Plan Requirements for Texas; Final Rule; 82 FR 45,481
(September 29, 2017); EPA-HQ-OAR-2016-0598; FRL-9968-46-OAR
(November 28, 2017).
\129\ Id. at 8-9.
\130\ Id. at 9.
---------------------------------------------------------------------------
With respect to the BART requirements in Texas, the petitioners
argued that the final rule was ``impermissibly based upon a factual
predicate that no longer exists--namely, that sulfur dioxide emission
reductions associated with the installation of presumptive source-
specific BART would be install [sic] at Texas EGUs.'' \131\ The
petitioners went on to purportedly demonstrate, using the 2012
sensitivity analysis methodology developed by the EPA, that source-
specific BART in Texas would improve visibility in Class I areas in or
affected by Texas more than CSAPR or the Texas SO2 Trading
Program.\132\
---------------------------------------------------------------------------
\131\ Id. at 10.
\132\ Id. at 11-13.
---------------------------------------------------------------------------
Concurrently with the affirmation of the Texas SO2
Trading Program on June 29, 2020, the EPA issued a denial of the 2017
petition (2020 Denial).\133\ In addition to addressing the other
objections raised in the 2017 petition,\134\
[[Page 28934]]
the EPA included an updated sensitivity analysis (2020 sensitivity
analysis) assessing whether CSAPR would remain a valid BART alternative
based on assumptions regarding emissions performance under the Texas
SO2 Trading Program rather than source-specific BART.\135\
The EPA used the same methodology it had used in its 2012 CSAPR Better-
Than-BART determination and applied an emissions assumption for the
Texas SO2 Trading Program used by Petitioners in their 2017
petition of 320,600 tons of SO2 per year. The EPA also used
an assumption that there would be a 22,300-ton increase in emissions in
a single State in the Group 2 trading program, Georgia.\136\ The EPA
presented the results of this analysis in Table 3 of the 2020 Denial,
and we asserted that for purposes of the ``prong 2'' portion of the
BART analysis, that CSAPR continued to perform equal to or better than
BART.\137\ Based on this analysis, the EPA reaffirmed the 2012 CSAPR
Better-Than-BART determination, albeit now on the assumption of the
Texas SO2 Trading Program operating in Texas rather than
CSAPR or presumptive source-specific BART.\138\
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\133\ 85 FR 40286 (July 6, 2020) (``2020 Denial''); See, e.g.,
Letter from U.S. EPA Administrator Andrew Wheeler to Joshua Smith,
Sierra Club, denying petition for reconsideration (June 29, 2020),
Docket ID EPA-HQ-OAR-2016-0598-0036. The EPA concurrently sent
identical letters to other petitioners. This letter, rather than the
Federal Register notice, is what we refer to when citing specific
pages in the ``2020 Denial.''
\134\ In their 2020 petition for partial reconsideration
summarized below, Petitioners did not renew their objections as to
other aspects of the EPA's analysis in the 2020 Denial and therefore
these issues will not be summarized here. As to the issues not
raised in their 2020 petition, but addressed in denying their 2017
petition, the EPA is not reopening the bases for denial of these
objections set forth in its 2020 Denial letter. We note that in
their 2020 petition for partial reconsideration, Petitioners noted
that they ``continue to object'' to the EPA's use of ``presumptive''
BART limits in its CSAPR better than BART analysis. See 2020
Petition at 5 n.10. The EPA is not revisiting this issue here. The
EPA explained in its 2020 Denial why this objection did not meet
either prong of the CAA section 307(d)(7)(B) test for mandatory
reconsideration, including that petitioners could have, but did not,
comment on this issue in the original 2017 affirmation rulemaking
proceeding. See 2020 Denial at 19-20.
\135\ 2020 Denial at 13-16.
\136\ Id. at 14-15.
\137\ Id. at 16.
\138\ Note that neither in the 2020 Denial or in this present
proposal are we reopening our determination in the September 2017
Final Rule that withdrawal of Texas from the annual NOX
trading program would have caused sufficient changes in modeled
NOX emissions in a revised CSAPR scenario to materially
alter the visibility impacts comparison. See 82 FR 45492 n.82. As
detailed in the November 2016 proposal, projected annual
NOX emissions from Texas EGUs were only 2,600 tons higher
than the annual NOX emissions projected for the CSAPR +
BART-Elsewhere case, in which it was assumed that the EGUs were
subject to CSAPR requirements for both ozone-season and annual
NOX emissions. The EPA determined that this relatively
small increase in NOX emissions in the CSAPR + BART-
Elsewhere case would have been too small to cause any change in the
results of either prong of the two-pronged CSAPR-Better-Than-BART
test.
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C. Summary of the 2020 Petition for Reconsideration and Associated
Litigation
On August 28, 2020, the Sierra Club, NPCA, and Earthjustice
submitted a petition for partial reconsideration under CAA section
307(d)(7)(B) of the EPA's 2020 Denial of their November 2017 petition
for reconsideration (2020 petition).\139\ The petitioners alleged that
because the EPA presented the updated CSAPR Better-than-BART
sensitivity calculations for the first time in its 2020 Denial of the
2017 Petition (and thus they were not afforded an opportunity to
comment), and because that updated analysis is of central relevance to
the September 2017 Final Rule, the EPA must reconsider both actions
under CAA section 307(d)(7)(B). The petitioners alleged that, contrary
to the EPA's conclusions in its 2020 Denial, the updated CSAPR Better-
Than-BART analysis demonstrates that visibility improvement under CSAPR
is not equal to or greater than visibility improvement under source-
specific BART averaged over all 140 Class I areas, or the 60 eastern
Class I areas covered by CSAPR.\140\
---------------------------------------------------------------------------
\139\ Petition for Partial Reconsideration of Denial of Petition
for Reconsideration and Petition for Reconsideration of the
Interstate Transport of Fine Particulate Matter: Revision of Federal
Implementation Plan Requirements for Texas (Aug. 28, 2020), Docket
ID EPA-HQ-OAR-2016-0598-0041.
\140\ Id. at 9.
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Specifically, Petitioners note that had the EPA's results been
reformatted to display two decimal places instead of one, the average
visibility improvement for the CSAPR + BART-Elsewhere scenario would
have been less than that of the Nationwide BART scenario on two of the
four metrics used.\141\ Thus, Petitioners concluded that the EPA's 2020
sensitivity analysis proves that the visibility improvement in the
CSAPR + BART-Elsewhere scenario, with the adjustments made to Texas's
and Georgia's emissions, is not equal to or greater than the visibility
improvement in the Nationwide BART scenario. Moreover, Petitioners also
argue that it was impracticable for them to raise these issues
concerning the sensitivity analysis during the comment period for the
September 2017 Final Rule because the sensitivity calculations were
presented for the first time in the 2020 Denial.\142\ The Petitioners
claim that the data within the 2020 sensitivity analysis addresses an
issue of central relevance to the September 2017 Final Rule, i.e.,
whether CSAPR results in an overall improvement in visibility compared
to source-specific BART. Moreover, because Petitioners claim that the
EPA's sensitivity analysis showed that source-specific BART would
result in greater visibility improvement than CSAPR, they argue that
the EPA's continued reliance on CSAPR as a BART alternative is
arbitrary, capricious, and contrary to law.\143\
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\141\ Id. at 11.
\142\ Id. at 12.
\143\ Id. at 13.
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Sierra Club, NPCA, and Earthjustice also filed a petition for
judicial review of the 2020 Denial in the U.S. Court of Appeals for the
District of Columbia.\144\ On November 3, 2020, this challenge and the
Petitioners' preexisting challenge to the September 2017 final analysis
(No. 17-1253 (D.C. Cir.)) were consolidated. On January 13, 2021, the
court placed the petitions for review in abeyance pending further order
of the court, and the court directed the parties to file motions to
govern following the EPA's action on the 2020 petition.
---------------------------------------------------------------------------
\144\ National Parks Conservation Association et al. v. EPA, No.
20-1341 (D.C. Cir. filed Sept. 4, 2020).
---------------------------------------------------------------------------
The EPA is now proposing to deny the 2020 petition in this action.
D. Criteria for Granting a Mandatory Petition for Reconsideration
Under section 307(d)(7)(B) of the Act, ``[o]nly an objection to a
rule or procedure which was raised with reasonable specificity during
the period for public comment . . . may be raised during judicial
review.'' \145\ However, ``[i]f a person raising an objection can
demonstrate . . . that it was impracticable to raise such objection
within such time or if the grounds for such objection arose after the
period for public comment . . . and if such objection is of central
relevance to the outcome of the rule, the Administrator shall convene a
proceeding for reconsideration of the rule.'' \146\ The EPA considers
an objection to be of ``central relevance'' to the outcome of a rule
``if it provides substantial support for the argument that the
regulation should be revised.'' \147\
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\145\ 42 U.S.C. 7607(d)(7)(B).
\146\ Id.
\147\ See Coal. For Responsible Regulation, Inc. v. EPA, 684
F.3d 102, 125 (D.C. Cir. 2012) (internal citation and quotation
omitted).
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E. The EPA's Evaluation of the Petition for Reconsideration
The EPA proposes to deny the 2020 petition because the objections
raised to the 2020 Denial are not ``centrally relevant'' under a
scenario in which the EPA finalizes the proposal to withdraw the
present BART-alternative intrastate trading FIP for Texas EGUs and
replaces those requirements with source-specific SO2 BART
requirements. Under this scenario, the findings made in the September
2017 Final Rule (i.e., the EPA's finding that CSAPR remains better than
BART) can be affirmed. The Agency acknowledges that the petitioners
raised legitimate questions in the 2020 petition concerning the 2020
sensitivity analysis and the conclusion that CSAPR remains better than
BART in a scenario in which the Texas SO2 Trading Program is
implemented. However, with this proposal and the return to source-
specific BART requirements in Texas, this issue is effectively
resolved. The 2020 petition can therefore be denied since the
[[Page 28935]]
objection raised is no longer centrally relevant.
For purposes of the 2012 analytic demonstration that CSAPR provides
for greater reasonable progress than BART, the EPA treated Texas EGUs
as subject to CSAPR for SO2 and annual NOX (as
well as ozone-season NOX). In the September 2017 Final Rule,
the EPA recognized that the treatment of Texas EGUs in the 2012
analysis would have been different if those sources were not in the
CSAPR SO2 and annual NOX programs. To address
potential concerns about continuing to rely on CSAPR participation as a
BART alternative for EGUs in the remaining CSAPR States, the EPA
provided an analysis explicitly addressing the potential effect on the
2012 analytic demonstration if the treatment of Texas (and several
other States') EGUs had been consistent with the updated scope of CSAPR
coverage following the D.C. Circuit's remand of CSAPR in EME Homer
City. In particular, in its September 2017 Final Rule, the EPA assumed
that, as for all other non-CSAPR States, Texas EGUs would be subject to
presumptive, source-specific SO2 BART limits.
As discussed below, if the EPA's proposal in this action to
implement source-specific BART requirements at certain EGUs in Texas is
finalized, the analytical basis for the EPA's September 2017
conclusions will be restored, and that analysis will continue to
support the conclusion that CSAPR participation would achieve greater
reasonable progress than BART, despite the change in the treatment of
Texas EGUs. Consequently, by virtue of this proposed action that
relates to Texas, the EPA is also able to propose to reaffirm the
continued validity of the CSAPR better-than-BART provision, 40 CFR
51.308(e)(4), which authorizes the use of CSAPR participation as a BART
alternative for BART-eligible EGUs for a given pollutant in States
whose EGUs continue to participate in a CSAPR trading program for that
pollutant. In the September 2017 Final Rule, the EPA evaluated whether
a revised CSAPR scenario reflecting the removal of Texas EGUs from the
CSAPR SO2 program (and other changes in CSAPR's geographic
scope) would continue to satisfy the two-pronged test under 40 CFR
51.308(e)(3). Regarding the changes in CSAPR requirements for Texas
EGUs, the EPA determined that the changes would have no adverse impact
on the 2012 analytic demonstration. Finalization of this proposal would
restore the analytical bases for the EPA's conclusions in the September
2017 Final Rule. We discuss that analysis in the following paragraphs
and explain how it would be restored if this action is finalized as
proposed.
As the EPA concluded in the September 2017 Final Rule, Texas EGUs
are ineligible to rely on CSAPR as an SO2 BART alternative.
In this proposal, we are affirming this position and rejecting the
contrary arguments that the Agency previously put forward in support of
the Texas BART-alternative FIP, as explained above in Section IV. As
explained in the November 2016 proposal,\148\ if this information had
been available at the time of the 2012 CSAPR Better-than-BART
demonstration, the treatment of Texas EGUs in the baseline case and in
the Nationwide BART case would not have changed, but in the CSAPR +
BART-Elsewhere case, Texas EGUs would have been treated as subject to
source-specific SO2 BART instead of being treated as subject
to CSAPR SO2 requirements. In the case of Texas, the
projected SO2 emissions from affected EGUs in the modeled
Nationwide BART scenario (139,300 tons per year) are considerably lower
than the projected SO2 emissions from the affected EGUs in
the CSAPR + BART-Elsewhere scenario (266,600 tons per year as modeled,
and up to approximately 317,100 tons, as addressed in the 2012
sensitivity analysis).
---------------------------------------------------------------------------
\148\ See 81 FR 78954 (Nov. 10, 2016).
---------------------------------------------------------------------------
As modeled, treating Texas EGUs in the CSAPR + BART-Elsewhere
scenario as subject to source-specific SO2 BART instead of
CSAPR SO2 requirements would therefore have reduced
projected SO2 emissions by between 127,300 tons and
approximately 177,800 tons in this scenario, thereby improving
projected air quality in this scenario relative to projected air
quality in both the Nationwide BART scenario and the baseline
scenario.\149\ At the lower end of this range, a reduction in
SO2 emissions of 127,300 tons would represent a reduction of
over four percent of the total SO2 emissions from EGUs in
all modeled States in the CSAPR + BART-elsewhere scenario. The EPA has
previously observed that the visibility improvements from CSAPR
relative to BART are primarily attributable to the greater reductions
in SO2 emissions from CSAPR across the overall modeled
region in the CSAPR + BART-Elsewhere scenario relative to the
Nationwide BART scenario.
---------------------------------------------------------------------------
\149\ As explained in greater detail in Section IV, while many
States participating in CSAPR were projected to have substantially
lower SO2 emissions under CSAPR as compared to
implementing BART requirements, this was not the case for Texas's
EGUs.
---------------------------------------------------------------------------
With a return to source-specific SO2 BART requirements
at the relevant Texas EGUs, this analysis will continue to (or, once
again will) be valid. Further, we propose to find that the conclusions
reached in the September 2017 Final Rule regarding ``emissions
shifting'' from Texas back into the remaining CSAPR region would remain
valid if source-specific BART requirements are implemented at the
relevant Texas EGUs. The September 2017 Final Rule responded to a
comment regarding potential ``emissions shifting'' when Texas was
removed from the CSAPR SO2 trading program. For purposes of
the second prong, to account for the effect of potential emissions
shifting caused by the fact that Texas sources would no longer purchase
SO2 allowances from sources in other CSAPR Group 2 States,
the EPA assumed that SO2 emissions in Georgia could increase
by up to 22,300 tons, the quantity of allowances that Texas had been
projected to purchase from the other Group 2 States in the original
CSAPR scenario. However, as detailed above, the EPA showed in 2017 that
a potential shift of up to 22,300 SO2 tons to Georgia (or
other CSAPR States) would be dwarfed by the lower SO2 tons
emitted in Texas under a source-specific BART scenario (127,300 tons or
more). Therefore, the EPA proposes that the September 2017 Final Rule's
conclusion that CSAPR would continue to pass both prongs of the better-
than-BART test, even accounting for emissions shifting, remains valid
(or will once again be valid) if this proposal is finalized and source-
specific BART is implemented in Texas.
In summary, the EPA proposes to affirm that if the information
regarding the proposed withdrawal of CSAPR FIP requirements for
SO2 for Texas EGUs had been available at the time of the
2012 CSAPR Better-than-BART analytic demonstration, the CSAPR + BART-
Elsewhere scenario would have reflected SO2 emissions from
Texas EGUs under presumptive source-specific BART. This would have been
127,300 or more tons per year lower than the emissions projections
under CSAPR and remains a valid assumption so long as the presumed
source-specific SO2 BART reductions are in fact required in
Texas. Under this assumption--which is, again, made possible by
withdrawing the current BART-alternative FIP and implementing source-
specific BART in Texas as outlined in this proposal--emissions would
not have changed in the Nationwide BART or baseline scenarios. Instead,
modeled visibility improvement in the CSAPR + BART-Elsewhere scenario
would have been
[[Page 28936]]
even larger relative to the other scenarios than what was modeled in
the 2012 analytic demonstration.
Lower SO2 emissions in Texas (after implementation of
source-specific BART) would clearly lead to more visibility improvement
on the best and worst visibility days in the nearby Class I areas.
Since the ``original'' CSAPR + BART-Elsewhere scenario passed both
prongs of the better-than-BART test (compared to the Nationwide BART
scenario and the baseline scenario), a modified CSAPR + BART-Elsewhere
scenario without Texas in the CSAPR region would without question also
have passed both prongs of the better-than-BART test. The EPA therefore
further proposes that there is no need to do any new modeling or more
complicated sensitivity analysis to affirm the findings of the
September 2017 Final Rule. And for the same reason, there is no need to
do any additional modeling or analysis to support this finding under
the current Texas BART proposal in this action (i.e., to withdraw the
Texas SO2 Trading Program and replace the FIP with source-
specific BART for Texas EGUs), assuming this proposal is finalized.
Therefore, the EPA proposes to deny the 2020 petition for partial
reconsideration and proposes to again affirm the use of CSAPR as a BART
alternative for all States whose EGUs continue to participate in the
CSAPR trading programs as to the relevant pollutants. Specifically, the
EPA proposes to conclude that, if the present proposal and the
restoration of the analytical premise for the findings of the September
2017 Final Rule are finalized, the objections that the 2020 petition
for partial reconsideration raised as to the analysis the EPA presented
in the 2020 Denial will be resolved and are therefore not of ``central
relevance'' to the September 2017 Final Rule. We are providing the
opportunity for, and invite, public comment on this proposed denial of
the petition for partial reconsideration.
VI. The EPA's Authority To Promulgate a FIP Addressing SO2
and PM BART
A. CAA Authority To Promulgate a FIP for SO2 BART
Under section 110(c) of the CAA, whenever the EPA disapproves a
mandatory SIP submission in whole or in part, the EPA is required to
promulgate a FIP within 2 years unless we approve a SIP revision
correcting the deficiencies before promulgating a FIP. 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.
Beginning in 2012, following the limited disapproval of the Texas
Regional Haze SIP, the EPA has had the authority and obligation to
promulgate a FIP to address BART for Texas EGUs for SO2. As
discussed in Section II, we exercised this FIP authority in October
2017 to promulgate a BART alternative (the Texas SO2 Trading
Program) to address the inadequacy of Texas's SIP as it pertained to
BART requirements for Texas EGUs for SO2. Because we are now
proposing that the basis for the Texas SO2 Trading Program
as a BART alternative rested on an erroneous interpretation of our BART
alternative regulations, and thus proposing to withdraw the program for
the reasons explained throughout Section IV, we have an obligation
under the CAA to promulgate a FIP in its place. We propose to exercise
this FIP authority through conducting a source-specific BART analysis
for those BART-eligible EGU sources participating in the Texas
SO2 Trading Program and, as appropriate, establish source-
specific BART emission limits and associated compliance requirements,
as identified in Sections VII and VIII of this action.
B. Error Correction and CAA Authority To Promulgate a FIP--PM BART
The EPA proposes that its prior approval of a portion of Texas's
2009 Regional Haze SIP related to its finding that no EGUs were subject
to BART requirements for PM (PM BART) was in error under CAA section
110(k)(6). Section 110(k)(6) of the CAA provides the EPA with the
authority to make corrections to actions that are subsequently found to
be in error. Ass'n of Irritated Residents v. EPA, 790 F.3d 934, 948
(9th Cir. 2015) (explaining that 110(k)(6) is a ``broad provision''
enacted to provide the EPA with an avenue to correct errors). The EPA
proposes that its approval of the portion of Texas's Regional Haze SIP
addressing PM BART for EGUs was in error, as the approval was based on
the Texas SO2 Trading Program that was promulgated in error.
Under CAA section 110(k)(6), once the EPA determines that its previous
action approving a SIP revision was in error, the EPA may revise such
action as appropriate without requiring any further submission from the
State. To correct the error here, the EPA proposes to revise its
previous approval of the portion of Texas's 2009 Regional Haze SIP
addressing PM BART for EGUs and proposes to instead disapprove this
portion of Texas's SIP.
In the 2009 Texas Regional Haze SIP, Texas conducted a screening
analysis of the visibility impacts from PM emissions in isolation and
determined that no EGUs were subject to BART for PM based on an
assumption that BART requirements for EGUs for both SO2 and
NOX were covered by participation in an earlier trading
program (CAIR). This decision was consistent with a 2006 EPA memorandum
titled ``Regional Haze Regulations and Guidelines for Best Available
Retrofit Technology (BART) Determinations''; however, that memorandum
stated that pollutant-specific screening is only appropriate in the
limited situation where a State is relying on a BART alternative, such
as a trading program, to address both NOX and SO2
BART.\150\
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\150\ Memorandum from Joseph Paisie to Kay Prince, ``Regional
Haze Regulations and Guidelines for Best Available Retrofit
Technology (BART) Determinations,'' July 19, 2006, available in the
docket for this action.
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In our 2017 Texas BART FIP, we created the Texas SO2
Trading Program as a BART alternative to satisfy SO2 BART
requirements for EGUs. As a result, the Texas BART FIP created a
scenario in which Texas EGUs were again subject to trading programs to
address both NOX and SO2 BART, and therefore, the
EPA approved the pollutant-specific screening for PM as performed by
Texas in its 2009 Regional Haze SIP submittal. Upon further
consideration, and as described in more detail above in Section IV, we
have determined that the Texas SO2 Trading Program as
promulgated in 2017, and affirmed in 2020, was based on an erroneous
interpretation of our BART alternative regulations. As such, it failed
to meet the requirements for a valid BART alternative and thus we are
proposing to withdraw the Texas SO2 Trading Program and to
satisfy SO2 BART requirements through conducting a source-
specific BART analysis. The basis for approval of Texas's SIP related
to the BART requirements for PM for EGUs rested on our creation of a
BART alternative for SO2, and we are proposing in this
action to determine that the Texas SO2 Trading Program is
not a valid BART alternative. Consistent with our proposal regarding
the Texas SO2 Trading Program, we are also proposing that
our approval of the portion of the 2009 Texas Regional Haze SIP related
to PM BART requirements for EGUs was in error.
Accordingly, the EPA is proposing to correct its previous approval
of the Texas 2009 Regional Haze SIP submittal related to PM BART for
EGUs by proposing to disapprove Texas's pollutant-specific PM screening
analysis and determination that PM BART emission limits are not
required for any
[[Page 28937]]
Texas EGUs. The EPA is proposing this action through an error
correction under CAA section 110(k)(6). If the EPA finalizes this
disapproval, the EPA will have the authority and obligation under CAA
section 110(c)(1)(B), to promulgate a FIP within 2 years. As part of
this rulemaking, the EPA proposes to promulgate a FIP addressing PM
BART requirements and satisfying that FIP obligation. As discussed
further in Section VII and Section VIII, the EPA is proposing source-
specific PM BART requirements for those EGUs that we propose to find
subject to BART.
VII. BART Analysis for SO2 and PM
As discussed in Section IV of this action, we are proposing to
withdraw the Texas SO2 Trading Program previously
established as an alternative to SO2 BART for Texas EGUs.
Thus, to satisfy SO2 BART requirements for Texas, we are
proposing to conduct a source-specific BART evaluation consistent with
the BART Guidelines for appropriate EGU sources. Specifically, we must
evaluate EGUs that were previously identified as BART-eligible, but for
which no subject-to-BART determinations were made because they were
included in the Texas SO2 Trading Program. Additionally,
because our approval of the portion of the Texas Regional Haze SIP
related to PM BART for EGUs was in error, we are now proposing an error
correction to disapprove that portion of the Texas SIP. We propose to
address the deficiency through a source-specific BART evaluation
consistent with the BART Guidelines for PM BART for the EGU sources
that were previously identified as BART-eligible, but for which no
subject-to-BART determinations were made because they were included in
the Texas SO2 Trading Program.
A. Identification of Sources Subject to BART
In January 2016, we approved Texas's determination of which non-EGU
sources in the State are BART-eligible and the determination that none
of the State's BART-eligible non-EGU sources are subject to BART
because they are not reasonably anticipated to cause or contribute to
visibility impairment at any Class I areas.\151\ In our October 2017
Texas BART FIP,\152\ and subsequent affirmation in 2020, addressing
BART requirements for Texas EGUs, we noted that all BART-eligible EGUs
in Texas are either covered by a BART alternative or have screened out
of being subject to BART. Our October 2017 FIP lists the units covered
by the BART alternative for SO2 (i.e., the Texas
SO2 Trading Program) and identifies which of those units are
BART-eligible.\153\ For those BART-eligible EGUs that were not covered
by the Texas SO2 Trading Program, we finalized
determinations that those EGUs are not subject-to-BART for
NOX, SO2, and PM based on screening methods as
described in our 2017 proposed rule and BART Screening TSD.\154\
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\151\ See 81 FR 296, 301 (Jan. 5, 2016).
\152\ See 82 FR at 48328 (Oct. 17, 2017).
\153\ 82 FR at 48329 (Oct.17, 2017).
\154\ See 82 FR at 48328-29 (Oct.17, 2017). Table 2 in the
October 2017 notice lists the EGUs that we finalized as being BART-
eligible, but for which we determined were not be subject-to-BART
based on various screening analysis as more fully described in the
2017 proposal (82 FR at 918-21). We are not reopening that
determination in this action.
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Because we are now proposing to withdraw the Texas SO2
Trading Program, we must evaluate the EGU sources that were previously
identified as BART-eligible, but for which no subject-to-BART
determinations were made because they were included in the Texas
SO2 Trading Program. The sources included in the Texas
SO2 Trading Program are identified in Table 2.
Table 2--Sources Included in the Texas SO2 Trading Program
----------------------------------------------------------------------------------------------------------------
Owner/operator Units BART-eligible
----------------------------------------------------------------------------------------------------------------
AEP...................................... Welsh Power Plant Unit 1........ Yes.
Welsh Power Plant Unit 2........ Yes.
Welsh Power Plant Unit 3........ No.
H W Pirkey Power Plant Unit 1... No.
Wilkes Unit 1 [dagger].......... Yes.
Wilkes Unit 2 [dagger].......... Yes.
Wilkes Unit 3 [dagger].......... Yes.
CPS Energy............................... J. T. Deely Unit 1.............. Yes.
J. T. Deely Unit 2.............. Yes.
O. W. Sommers Unit 1 [dagger]... Yes.
O. W. Sommers Unit 2 [dagger]... Yes.
LCRA..................................... Fayette/Sam Seymour Unit 1...... Yes.
Fayette/Sam Seymour Unit 2...... Yes.
Luminant................................. Big Brown Unit 1................ Yes.
Big Brown Unit 2................ Yes.
Martin Lake Unit 1.............. Yes.
Martin Lake Unit 2.............. Yes.
Martin Lake Unit 3.............. Yes.
Monticello Unit 1............... Yes.
Monticello Unit 2............... Yes.
Monticello Unit 3............... Yes.
Sandow Unit 4................... No.
Stryker ST2 [dagger]............ Yes.
Graham Unit 2 [dagger].......... Yes.
Coleto Creek Unit 1............. Yes.
NRG...................................... Limestone Unit 1................ No.
Limestone Unit 2................ No.
W. A. Parish Unit WAP4 [dagger]. Yes.
W. A. Parish Unit WAP5.......... Yes.
W. A. Parish Unit WAP6.......... Yes.
W. A. Parish Unit WAP7.......... No.
Xcel..................................... Tolk Station Unit 171B.......... No.
Tolk Station Unit 172B.......... No.
[[Page 28938]]
Harrington Unit 061B............ Yes.
Harrington Unit 062B............ Yes.
Harrington Unit 063B............ No.
El Paso Electric......................... Newman Unit 2 [dagger].......... Yes.
Newman Unit 3 [dagger].......... Yes.
Newman Unit **4 [dagger]........ Yes.
Newman Unit **5[dagger]......... Yes.
----------------------------------------------------------------------------------------------------------------
[dagger] Gas-fired or gas/fuel oil-fired units.
Some of the BART-eligible sources that were included in the Texas
SO2 Trading Program have retired. Welsh Unit 2 retired in
2016 \155\ and Big Brown,\156\ Monticello,\157\ and the J.T. Deely
units retired at the end of 2018.\158\ These shutdowns are permanent
and enforceable because the CAA permits for these units have been
cancelled or the units have been withdrawn from the facilities' Title V
operating permits. These units may not return to operation without
going through CAA new source permitting and Title V operating
permitting requirements. Therefore, because the units are permanently
retired, it is not necessary to include these units in our screening
analysis to determine whether these sources are subject to BART.
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\155\ Welsh Unit 2 was retired on April 16, 2016, pursuant to a
Consent Decree (No. 4:10-cv-04017-RGK) and subsequently removed from
the Title V permit (permit no. O26). We have included the Consent
Decree, permitting notes, and new Title V permit showing that the
Unit is removed in the docket for this action.
\156\ See letter dated March 27, 2018, from Kim Mireles of
Luminant to the TCEQ requesting to cancel certain air permits and
registrations for Big Brown available in the docket (EPA-R06-OAR-
2016-0611-0132) for this action.
\157\ See letter dated February 8, 2018, from Kim Mireles of
Luminant to the TCEQ requesting to cancel certain air permits and
registrations for Monticello available in the docket (EPA-R06-OAR-
2016-0611-0130) for this action.
\158\ See letter dated December 15, 2021, from Johnny Bowers,
Team Leader Air Permits Division at TCEQ to Danielle Frerich
regarding the cancellation of air quality permits for the J.T. Deely
units available in the docket for this action.
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To determine which of those remaining BART-eligible sources listed
in Table 2 are anticipated to cause or contribute to visibility
impairment in any Class I area (subject-to-BART),\159\ 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. The BART source is the collection of BART-eligible emission units
at a facility. A detailed discussion of the subject-to-BART screening
analysis is provided in the 2023 BART Modeling TSD.\160\ We summarize
the methodology and results of this analysis here.
---------------------------------------------------------------------------
\159\ See 40 CFR part 51, Appendix Y, III, How to Identify
Sources ``Subject to BART.''
\160\ See our 2023 BART Modeling TSD in our docket.
---------------------------------------------------------------------------
1. Modeling Approach
For States (or the EPA in the case of a FIP) using modeling to
determine the applicability of BART to single sources, the first step
in the BART Guidelines is to set a contribution threshold to assess
whether the impact of a single source (collectively the BART-eligible
units at a specific facility) 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 (dv) change or more from
an individual source to `cause' visibility impairment, and a change of
0.5 dv to `contribute' to impairment.'' \161\ The BART Guidelines
further advise 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 describe 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.\162\ 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 lower contribution threshold. Therefore, our
analysis employs a contribution threshold of 0.5 dv.
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\161\ 70 FR at 39118.
\162\ 70 FR at 39118.
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In this action we conducted modeling using both CALPUFF \163\ and
CAMx.\164\ In the 2005 BART Guidelines, CALPUFF was in part chosen
because it is much less resource intensive with respect to required
computing power, run time, and development of model inputs than
chemical transport models such as CAMx. Additionally, CAMx tools for
assessing single source impacts were still undergoing development at
that time. CAMx tools have advanced since 2005, and while still
resource intensive, for this action we were able to conduct CAMx
modeling using TCEQ's modeling platform as a starting point for this
assessment. We discuss details of the CALPUFF and CAMx modeling systems
throughout this section and in the 2023 BART Modeling TSD.
---------------------------------------------------------------------------
\163\ EPA used the version of CALPUFF approved previously for
regulatory modeling (CALPUFF version 5.8.5, level 15214) as
discussed on EPA's website (https://www.epa.gov/scram/air-quality-dispersion-modeling-alternative-models) and this CALPUFF version is
available for download from Exponent at https://www.src.com/.
\164\ CAMx is available for download at https://www.camx.com/.
---------------------------------------------------------------------------
As recommended in the BART Guidelines, we performed stand-alone,
source-specific CALPUFF modeling on several of the remaining BART-
eligible sources included in Table 2 to determine which of the BART-
eligible sources in Table 2 cause or contribute to visibility
impairment in nearby Class I areas. CALPUFF is a multi-species non-
steady-state puff dispersion model that simulates the effects of
pollution transport, dispersion, transformation, and removal of
emissions from modeled sources for transport distances beyond 50 km
using general background concentrations to represent air pollution
levels that the modeled sources emissions interact. Relevant guidance
\165\ States that the CALPUFF
[[Page 28939]]
model is generally applicable at distances from 50 km to at least 300
km downwind of a source. However, previous Regional Haze BART SIP
modeling conducted by consultants and the States extended beyond 300km
for numerous BART analyses.\166\ In fact, in evaluating the Texas 2009
Regional Haze SIP, the EPA, FLM representatives, and TCEQ agreed with
using CALPUFF for Texas sources for distances out to 614 km.\167\
Initially, CALPUFF results beyond 300 km were thought to be potentially
conservative (overestimate impacts); however subsequent analysis of
CALPUFF indicates that it can also underpredict impacts at ranges
greater than 300km.\168\ For this particular BART analysis, we chose to
evaluate CALPUFF results out to approximately 450 km due to these
potential uncertainties that seem to be larger at ranges greater than
450 km.\169\ All BART-eligible sources that we modeled with CALPUFF in
this action have at least one Class I area within the more typical
CALPUFF range of 300km (see Table 3 for distance to most impacted Class
I areas for each modeled source). This use of CALPUFF is consistent
with the EPA's recommendation in the 2005 BART Guidelines \170\ to
determine whether a source is subject to BART and in conducting the
BART analysis for those sources determined to be subject to BART.\171\
We also have CAMx modeling results for all coal-fired BART-eligible
sources and as such we have both CALPUFF and CAMx modeling results for
the coal-fired sources within 450 km of Class I area(s). For those
sources beyond 450 km, we only used CAMx modeling results as discussed
in more detail later in this section.
---------------------------------------------------------------------------
\165\ Interagency Workgroup on Air Quality Modeling (IWAQM)
Phase 2 Summary Report and Recommendations for Modeling Long-Range
Transport and Impacts on Regional Visibility, EPA- 454/R-98-019,
IWAQM, 1998; ``Federal Land Managers' Air Quality Related Values
Workgroup (FLAG)'': Phase I Report, FLAG, USDI--National Park
Service, Air Resources Division, Denver, CO., 2000. https://www.nature.nps.gov/air/Pubs/pdf/flag/FlagFinal.pdf; Revisions to the
Guideline on Air Quality Models: Adoption of a Preferred Long Range
Transport Model and Other Resources, 72 FR 18440 (Apr. 15, 2003).
\166\ Historically, the EPA has indicated that use of CALPUFF
was generally acceptable at 300 km and for larger emissions sources
with elevated stacks, such as coal-fired power plants, we and FLM
representatives have also allowed or supported the use of CALPUFF
results at larger distances, beyond 400 km in some cases. For
example, South Dakota used CALPUFF for Big Stone's BART
determination, including its impact on multiple Class I areas
further than 400 km away. See 76 FR 76646, 76654 (Dec. 8, 2011), 77
FR 24845 (Apr.26, 2012). Nebraska relied on CALPUFF modeling to
evaluate whether numerous power plants were subject to BART where
the ``Class I areas [were] located at distances of 300 to 600
kilometers or more from'' the sources. See Best Available Retrofit
Technology Dispersion Modeling Protocol for Selected Nebraska
Utilities, p. 3, EPA Docket ID No. EPA-R07-OAR-2012-0158-0008.
\167\ In our 2014 proposed action and the 2016 final action on
the 2009 Texas Regional Haze SIP, we approved the use of CALPUFF to
screen BART-eligible non-EGU sources at distances of 400 to 614 km
for some sources. 79 FR 74818 (Dec. 16, 2014), 81 FR 296 (Jan. 5,
2016).
\168\ ``Documentation of the Evaluation of CALPUFF and Other
Long Range Transport Models using Tracer Field Experiment Data''
(PDF)(247 pp, 8 MB, 05-01-2012, 454-R-12-003). Prepared for the U.S.
Environmental Protection Agency by the ENVIRON International
Corporation. (EPA Contract No: EP-D-07-102, Work Assignment No: 4-
06); ``Evaluation of Chemical Dispersion Models using Atmospheric
Plume Measurements from Field Experiments'' (PDF)(127 pp, 3 MB, 09-
01-2012). Prepared for the U.S. Environmental Protection Agency by
the ENVIRON International Corporation. (EPA Contract No: EP-D-07-
102, Work Assignment No: 4-06 and 5-08); and ``Comparison of Single-
Source Air Quality Assessment Techniques for Ozone,
PM2.5, other Criteria Pollutants and AQRVs'' (PDF)(143
pp, 19 MB, 09-01-2012). Prepared for the U.S. Environmental
Protection Agency by the ENVIRON International Corporation. (EPA
Contract No: EP-D-07-102, Work Assignment No: 4-06 and 5-08);
https://www.epa.gov/scram/air-modeling-reports-and-journal-articles.
See 2023 BART Modeling TSD for further discussion on this topic.
\169\ We discuss the choice of using CALPUFF model results in
the 300-450 km range in more detail in the 2023 BART Modeling TSD.
\170\ See 70 FR 39104, 39122-23 (July 6, 2005).
\171\ 70 FR at 39122.
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Consistent with the BART Guidelines, for those sources modeled with
CALPUFF, we compared the 98th percentile (equivalent to the 8th highest
daily value in each year modeled) impact from the three modeled years
to the 0.5 dv screening threshold following the modeling protocol
described in the 2023 BART Modeling TSD.\172\ The BART Guidelines
recommend that States (or the EPA in the case of a FIP) 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. Consistent with this
recommendation, in this action, we used the 24-hour average actual
emission rate from the highest emitting day during the baseline period.
---------------------------------------------------------------------------
\172\ In the 2005 BART Guidelines the selection of the 98th
percentile value rather than the maximum value was made to address
concerns with CALPUFF's limitations that could result in the maximum
from CALPUFF modeling being overly conservative. We state that,
``Most important, the simplified chemistry in the model tends to
magnify the actual visibility effects of that source. Because of
these features and the uncertainties associated with the model, we
believe it is appropriate to use the 98th percentile--a more robust
approach that does not give undue weight to the extreme tail of the
distribution.'' 70 FR at 39121.
---------------------------------------------------------------------------
For this proposed action, we conducted modeling using a baseline
period of emissions data of 2016-2020 and used meteorological data for
2016-2018 to evaluate source visibility impacts to Class I areas. Our
selection of this baseline period for subject-to-BART screening
modeling was made based on consideration of a number of factors. We
note that most BART screening analyses, including the BART screening in
the 2009 Texas Regional Haze SIP, were based on a 2000-2004 baseline
period, used 2001-2003 meteorological data, and used 2002 in the
baseline modeling to project 2018 visibility conditions for the first
planning period SIPs. Our 2017 proposed rule also used this
period.\173\
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\173\ See generally 82 FR 912 (January 4, 2017).
---------------------------------------------------------------------------
We selected the 2016-2020 emissions baseline period for subject-to-
BART screening in this instance because recent actual emissions more
accurately reflect future anticipated emissions which is required in
evaluating controls. In addition, this emissions baseline period is
consistent with the 2016-2018 meteorological period modeled. In this
manner, the screening, visibility benefit analysis, cost analysis, and
consideration of existing controls are all based on consideration of
the same baseline meteorological time period, operating conditions, and
emissions. The 2000-2004 baseline period is no longer representative of
anticipated future emissions or current operations because more recent
regulatory actions, such as the MATS rule, and market pressures have
impacted how these units now operate. We also note that our previous
use of baseline emissions data from 2000-2004 reflected steady-state
operating conditions during periods of high-capacity utilization and
was appropriate for the screening nature of the analysis rather than
any specific federally enforceable limit in effect at that time. We
believe this same approach, updated for 2016-2020, continues to serve
the same function and provides a suitable estimate of emissions during
high utilization for each of these sources. Additionally, it also
allows the screening, visibility benefit analysis, cost analysis, and
consideration of existing controls to all be based on the same baseline
period for meteorological data, operating conditions, and emissions.
Using an appropriate, updated baseline is also the foundation for
evaluating control costs once a source is determined to be subject to
BART. The BART determination includes consideration of past practices,
existing controls, and anticipated future operation. The BART
Guidelines state that in evaluating the costs of controls as part of
the five-factor analysis for sources determined to be subject to BART,
baseline annual emissions utilized for control cost analyses should be
a realistic depiction of anticipated annual emissions for the source
and calculated based upon continuation of past practice \174\ in the
absence of enforceable limitations.
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\174\ Past practices can include a broad consideration of
operations, changes in market conditions, and unique situations that
can impact emissions.
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[[Page 28940]]
For both the CALPUFF and CAMx modeling, the maximum 24-hour
emission rate (lb/hr) for NOX and SO2 from the
2016-2020 baseline period for each source was identified through a
review of the daily emission data obtained from the EPA's Clean Air
Markets Program Data \175\ for each of the BART-eligible units included
in Table 2. Because daily emissions are not available for PM, we used
data from EPA's Air Markets Program Data and TCEQ's Central Registry EI
information to obtain PM10 and PM2.5 tpy emission
rates for each year (2016-2020) on a unit basis. We used the annual
average lb/MMBtu and the maximum daily heat input to calculate the
maximum daily PM10 and PM2.5 emissions rates that
were used in the subject to BART modeling and were also used in the
control cases. For the gas and gas/fuel oil facilities,\176\ we
utilized the heat input data from the EPA Clean Air Markets Division
(CAMD) coupled with the EPA's AP-42 emission factors to estimate
maximum PM10 and PM2.5 emissions. The 2023 BART
Modeling TSD includes additional discussion and source-specific
information used in the CALPUFF modeling for this portion of the
screening analysis.
---------------------------------------------------------------------------
\175\ https://campd.epa.gov/. See ``2016-2020 CAMD Data
Evaluation.xlsx'' in the docket for this action.
\176\ When we use the term ``gas,'' we mean ``pipeline natural
gas.''
---------------------------------------------------------------------------
As previously discussed, while the BART Guidelines recommend the
use of CALPUFF to determine which sources are anticipated to contribute
to visibility impairment, the Guidelines also allow the use of another
``appropriate model'' to predict the visibility impacts from a single
source at a Class I area. Because some of these BART-eligible sources
(included in Table 2) are beyond the distance to Class I areas for
which CALPUFF modeling is typically used, we used photochemical grid
modeling (CAMx) to evaluate the visibility impacts of those sources. In
addition, we also used CAMx to evaluate the other BART-eligible coal-
fired EGUs with SO2 emissions located within the typical
CALPUFF modeling range. The CAMx modeling includes all of these
emission sources to provide a consistent approach to compare the
modeling results across all these sources. CAMx is a photochemical grid
model that is formulated to assess the long-range transport of
emissions from sources up to distances of several thousand miles
including emissions from sources outside the range that CALPUFF is
typically utilized. CAMx allows modeling of impacts from individual
sources and assessment of their impacts on Class I areas at distances
much greater than the limited CALPUFF model system and accounts for all
the other known emissions sources in the modeling domain that results
in varying background pollution levels temporally and spatially that
individual source emissions interact. Furthermore, CAMx is also more
suited than other possible modeling approaches for evaluating the
visibility impacts of SO2, NOX, VOC, and PM
emissions, as it has a more robust chemistry mechanism that is
continually updated as the scientific community of peers agree on
chemistry, physics, and structural upgrades. As such, CAMx provides a
scientifically defensible platform for the assessment of visibility
impacts over a wide range of source-to-receptor distances that has been
used by a number of States in development of their Regional Haze SIPs,
including Texas.
Since CAMx modeling differs in several ways from CALPUFF modeling,
we are using different metrics to evaluate BART visibility impacts from
CAMx. For CAMx modeling, we utilize the maximum daily impact as the
primary metric for BART screening and assessment of visibility impacts
as compared to the use of the 98th percentile metric with CALPUFF. As
explained in the 2023 BART Modeling TSD, this approach recognizes
differences in the models and model inputs and their application in
determining whether the source is anticipated to cause or contribute to
visibility impairment. For example, one difference is that compared to
CALPUFF, CAMx utilizes a more robust chemistry mechanism, thus the
primary concern that drove the selection of the 98th percentile value
for CALPUFF based modeling are not applicable. Furthermore, because the
CAMx modeling uses a more limited meteorological data period (one year
of meteorology instead of three years used for CALPUFF modeling), and
CAMx modeling also uses only one receptor for the Class I area \177\
versus the many receptors covering the entire area of the Class I area
that are used in CALPUFF modeling, the maximum of the daily impacts at
a Class I area is appropriate for determining if a source is subject to
BART. The use of the maximum value from CAMx also comports with TCEQ's
use of the maximum value from CAMx modeling for BART screening that
TCEQ included in the 2009 Texas Regional Haze SIP.178 179
See the 2023 BART Modeling TSD for further discussion of the CALPUFF
and CAMx modeling systems, the metrics evaluated, and the limitations
and strengths of each modeling system.
---------------------------------------------------------------------------
\177\ For CAMx, we used the location coordinates of the 13
IMPROVE monitors that represent the 15 Class I areas, as was done in
previous modeling. IMPROVE monitor GUMO1 represents both the
Guadalupe Mountains NP and the Carlsbad Caverns NP Class I areas,
and IMPROVE monitor WHPE1 represents both Wheeler Peak and Pecos
Wilderness Areas Class I areas. IMPROVE monitors are part of a
nationwide visibility monitoring network. The IMPROVE program
establishes current visibility and aerosol conditions in mandatory
Class I areas; identifies chemical species and emission sources
responsible for existing man-made visibility impairment; documents
long-term trends in visibility; and provides regional haze
monitoring representing all visibility-protected Federal Class I
areas, where practical.
\178\ See 2009 Texas Regional Haze 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. The EPA, the Texas Commission on Environmental Quality
(TCEQ), and FLM representatives verbally approved the approach in
2006 and in email exchange with TCEQ representatives in February
2007 (see email from Erik Snyder (EPA) to Greg Nudd of TCEQ Feb. 13,
2007 and response email from Greg Nudd to Erik Snyder Feb. 15, 2007,
available in the docket for this action).
\179\ We approved Texas's subject-to-BART analysis for non-EGU
sources which relied on this CAMx modeling in our January 5, 2016,
rulemaking (81 FR 296).
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For this proposed action, our CAMx modeling platform began with
TCEQ's 2016 Modeling Platform,\180\ namely TCEQ's 2016 emissions data,
2016 meteorological data, and other modeling files utilized in their
CAMx modeling for TCEQ's Second Planning Period Texas Regional Haze
SIP. We are using this updated modeling platform to reflect more recent
meteorology and emissions inventories and have identified it to be the
best available platform for modeling these sources in Texas.\181\ We
upgraded this modeling platform to the newest version of the CAMx
model, adjusted emissions for BART-eligible units, and utilized
[[Page 28941]]
different/new Particulate Matter Source Apportionment Technology (PSAT)
\182\ categories (individual EGU units and facilities) to track source
contributions for BART-eligible units. These adjustments are explained
in more detail in the 2023 BART Modeling TSD.
---------------------------------------------------------------------------
\180\ For this action, we used TCEQ's 2016 modeling platform
from its Second Planning Period Regional Haze SIP revision. TCEQ
submitted this Second Planning Period Regional Haze SIP revision to
the EPA on July 20, 2021. The EPA has not reviewed this SIP nor
proposed action on this SIP, but we are utilizing the modeling
platform developed by TCEQ for this SIP to perform our modeling
analyses to determine whether a source is subject to BART and in
conducting the BART analysis for those sources determined to be
subject to BART. The EPA will evaluate the Second Planning Period
Regional Haze SIP submitted by TCEQ in a separate action. The SIP is
available at https://www.tceq.texas.gov/airquality/sip/bart/haze_sip.html and in the docket for this action.
\181\ Consequently, a 2016-2018 period for CALPUFF modeling and
2016-2020 emissions would be consistent with this choice.
\182\ CAMx includes an advanced mechanism that allows tracking
the contributions of individual sources and pollutants within the
grid model. For purposes of tracking particulate matter formation,
we employed the CAMx PSAT for the BART-eligible sources included in
the Texas SO2 Trading Program, including the three coal-
fired EGU sources that did not screen out with the CALPUFF modeling
(Harrington, Martin Lake, and Welsh).
---------------------------------------------------------------------------
Using the BART Guidelines recommended maximum daily emissions and
post-processing approach, if the source (which is the aggregate of all
BART-eligible units at a specific facility) is shown to contribute less
than 0.5 dv to visibility impairment at all modeled Class I areas on
all modeled days, then it is said to be ``not subject to BART'' and may
be excluded from further steps in the BART process. The maximum modeled
impact for each source, taking into account the annual average natural
background conditions at the Class I areas, was compared to the 0.5 dv
contribution threshold. See the 2023 BART Modeling TSD for additional
details on the CAMx modeling.
2. Subject to BART Determinations Based on CALPUFF and CAMx Modeling
Results
Table 3 shows the CALPUFF modeling results for the screening
analysis. The Graham, Newman, Stryker Creek, and Wilkes BART-eligible
units (all gas-fired or gas/fuel oil-fired BART-eligible units) that
were included in the Texas SO2 Trading Program can be
exempted from further analysis because they all have modeled maximum
98th percentile annual impacts at all Class I areas of less than the
0.5 dv threshold. When considering impacts modeled using CALPUFF, a
source is considered subject to BART if any of the three annual 98th
percentile values are 0.5 dv or greater. As Table 3 shows, the coal-
fired BART-eligible units at Martin Lake, Harrington, and Welsh did not
screen out based on the CALPUFF modeling and thus are considered to
cause or contribute to visibility impairment at Class I areas. See the
2023 BART Modeling TSD for this action for more details on the CALPUFF
modeling and the modeling results.
Table 3--CALPUFF BART Screening Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
Maximum delta deciviews
Plant name Operator name Boiler ID(s) Most impacted class ------------------------------------------------ Less than 0.5 dv
I area (distance) 2016 2017 2018
--------------------------------------------------------------------------------------------------------------------------------------------------------
Graham....................... Luminant........ 2.............. Wichita Mountains 0.297 0.203 0.423 Yes.
(174 km).
Newman....................... El Paso Electric 2, 3, **4, **5. Guadalupe Mountain 0.342 0.368 0.354 Yes.
(133 km).
Stryker Creek................ Luminant........ ST2............ Caney Creek (283 km) 0.054 0.059 0.064 Yes.
Wilkes Power Plant........... AEP............. 1, 2, 3........ Caney Creek (174 km) 0.380 0.373 0.442 Yes.
Martin Lake.................. Luminant........ 1,2,3.......... Caney Creek (238 km) 3.28 3.60 3.35 No.
Harrington................... Xcel............ 061B, 062B..... Salt Creek (305 km). 0.49 0.59 0.54 No.
Harrington................... Xcel............ 061B, 062B..... Wichita Mountains 0.54 0.45 0.58 No.
(278 km).
Welsh........................ AEP............. 1.............. Caney Creek (161 km) 0.7 0.94 0.96 No.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table 4 summarizes the results of the CAMx screening analysis.
These results also establish the baseline impacts for further modeling
analyses of potential visibility benefits of controls. We note that all
six sources analyzed with CAMx PSAT modeling had impacts greater than
0.5 dv at one or more Class I areas. Table 4 also shows that the CAMx-
predicted visibility impacts range from 0.52 dv to 6.69 dv for these
six sources at individual Class I areas on their maximum impact day.
Additionally, Table 4 shows the number of days impacted over 0.5 dv and
1.0 dv at the maximum impacted Class I areas for each source. We note
that maximum impacts from Fayette \183\ are just above the 0.5 dv
threshold and only exceed the threshold on one day. However, because
the intent of the screening analysis is to be inclusive, we therefore
consider Fayette subject to BART. The relatively lower visibility
impacts and potential benefits from controls will be considered as part
of the five-factor analysis when determining the potential availability
of cost-effective emission reductions. With the exception of Fayette,
the BART-eligible sources modeled using CAMx had maximum impacts well
over the 0.5 dv threshold on multiple modeled days (ranging from 8 to
150 days).
---------------------------------------------------------------------------
\183\ Fayette Power Project is also known as Sam Seymour. We
refer to it as Fayette throughout this document.
Table 4--CAMx BART Screening Source Analysis Summary
--------------------------------------------------------------------------------------------------------------------------------------------------------
Number of Number of
BART-eligible source Units Most impacted class Maximum delta- Less than 0.5 dv? modeled days modeled days
I area dv >=0.5 dv \1\ >=1.0 dv \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coleto Creek...................... 1.................... Caney Creek......... 1.55 No..................... 18 2
Fayette Power..................... 1 & 2................ Caney Creek......... 0.52 No..................... 1 0
Harrington........................ 061B & 062B.......... White Mountain...... 2.64 No..................... 8 3
Martin Lake....................... 1, 2, & 3............ Caney Creek......... 6.69 No..................... 150 101
W. A. Parish...................... WAP4, WAP5, & WAP6... Wichita Mountains... 3.97 No..................... 35 12
Welsh............................. 1.................... Caney Creek......... 1.58 No..................... 27 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Number of days over 0.5 or 1.0 dv at the most impacted Class I area. See Table 12 for cumulative results at the 15 Class I areas analyzed.
[[Page 28942]]
Based on the modeling analysis, the BART-eligible sources in Table
5 have been determined to cause or contribute to visibility impairment
at a nearby Class I area; therefore, we propose to find the six sources
are subject to BART. We must establish emission limits for visibility
impairing pollutants SO2 and PM through further evaluation
using the BART five factor analysis.\184\
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\184\ The NOX BART requirement for these EGU sources
is not addressed by source-specific limits in this proposal. The
EPA's determination that Texas' participation in CSAPR for ozone-
season NOX satisfies NOX BART for EGUs was
finalized in our October 17, 2017 final rule (82 FR 48324), thus
dispensing with the need for source-specific BART determinations and
requirements for NOX. We did not reopen that
determination in our August 2018 proposal, November 2019
supplemental proposal, or August 2020 final rule, and are not
reopening it in this proposal.
Table 5--Sources That Are Subject-to-BART
------------------------------------------------------------------------
Facility Units
------------------------------------------------------------------------
Coleto Creek.............................. 1.
Fayette Power............................. 1 & 2.
Harrington................................ 061B & 062B.
Martin Lake............................... 1, 2 & 3.
W. A. Parish.............................. WAP4, WAP5 & WAP6.
Welsh..................................... 1.
------------------------------------------------------------------------
3. Subject to BART Determination for O.W. Sommers Units 1 and 2
CPS Energy operates the Calaveras Power Station which is comprised
of O. W. Sommers Units 1 and 2, J. T. Deely Units 1 and 2,\185\ and J.
K. Spruce Units 1 and 2. In our 2017 Texas BART proposal, we identified
O. W. Sommers Units 1 and 2 and J. T. Deely Units 1 and 2 as BART-
eligible and conducted CAMx modeling to determine their visibility
impacts. Because J. T. Deely Units 1 and 2 subsequently ceased
operation and shut down, our analysis in this action is limited to the
two gas-fired units at O. W. Sommers. Given the retirement of the two
coal-fired units at J. T. Deely and the low SO2 emissions
from the O. W. Sommers gas-fired EGUs, rather than conducting new CAMx
modeling, we updated our analysis of O. W. Sommers Units 1 and 2
relying on the CAMx modeling from our 2017 Texas BART proposal (further
referred to as 2017 Proposal). In that analysis, we conducted CAMx
modeling using the combined maximum 24-hour emissions from both J. T.
Deely Units 1 and 2 and O. W. Sommers Units 1 and 2 to determine if the
aggregate BART-eligible source (all four BART-eligible units at
Calaveras Power Station) was subject to BART. The maximum modeled
impact from the Calaveras Power Station was 1.513 dv. As documented in
the BART Screening TSD and associated supporting documents for the 2017
BART FIP,\186\ the impacts of the two O. W. Sommers BART-eligible units
were previously estimated to have a maximum visibility impact of 0.286
dv at the Caney Creek Class I area, which is below the 0.5 dv
threshold.\187\
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\185\ Acosta, Sarah (January 3, 2019). ``CPS Energy closes coal-
fired Deely plant in operation since `70s to focus on cleaner energy
sources''. KSAT-TV. Retrieved January 4, 2019.
\186\ ``Technical Support Document Our Strategy for Assessing
which Units are Subject to BART for the Texas Regional Haze BART
Federal Implementation Plan (BART Screening TSD), pdf page 72 and
Appendix E, available in the docket EPA-R06-OAR-2016-0611 (at EPA-
R06-OAR-2016-0611-0005).
\187\ Id. pdf page 72 and Appendix E. CAMx Maximum Impact at
each Class Area; The O. W. Sommers BART-eligible units were modeled
individually, the sum (maximum dv impacts) of which is 0.286 dv.
Adding the maximum impacts of each unit results in a slight
overestimation of the visibility impacts, since we did not first
calculate total extinction and then dv, which is a natural
logarithmic function. Therefore 0.286 dv is conservative (higher
than if modeled).
---------------------------------------------------------------------------
To bolster our current analysis, we also compared the modeled
SO2 and NOx emission rates from the O. W. Sommers
units with the recent maximum daily emissions from 2016-2020. Sulfate
and nitrate made up almost all of the extinction value on the maximum
impact day at Caney Creek Class I area, with approximately 89 percent
of the total extinction from nitrates and 9 percent from sulfates on
the maximum impact day due to emissions from O. W. Sommers. Because the
two O. W. Sommers BART-eligible units are located near each other and
have similar stack parameters, we used a linear adjustment comparing
emissions modeled previously to more recent emissions (2016-2020) to
provide an estimate of current visibility impact. While linear scaling
does not result in the same values as modeling, it is a reasonable
methodology to conservatively approximate the visibility impact from a
source.
Table 6 compares the NOX and SO2 emission
rates modeled in the 2017 Proposal to the maximum daily emission rates
of NOX and SO2 from the 2016-2020
period.188 189 We did not compare PM10 or
PM2.5 as they were less than 3 percent of the total light
extinction on the maximum impact day. SO2 emissions from the
2016-2020 period were less than 3 percent of what was previously
modeled, and NOX emissions were 13.71 percent higher than
what was modeled for our 2017 Proposal for these two units.
Acknowledging that the reduction in SO2 emissions will
result in lower visibility impact, we choose to not adjust for the
lower SO2 emissions in an effort to be conservative in our
analysis. Scaling the 2017 visibility impact (0.286 dv at Caney Creek
Class I area) linearly to account for the 13.71 percent total increase
in NOX emissions, we estimate a maximum visibility impact of
0.325 dv at the Caney Creek Class I area, which is well below the 0.5
dv threshold. Based on this analysis, it is reasonable to conclude that
if emissions from the two O. W. Sommers BART-eligible units were
remodeled using recent emissions, it would result in a maximum
visibility impact less than 0.5 dv and would screen out of further
analysis. Therefore, the EPA proposes that O. W. Sommers Units 1 and 2
are not subject to BART.
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\188\ Id. Appendix A. Modeled parameters: Stack and emissions
for CAMx modeled sources for modeled emissions in 2017 proposal.
\189\ https://campd.epa.gov/.
Table 6--O. W. Sommers BART-Eligible Units Emissions Modeled in 2017 vs. Recent 2016-2020 Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
O. W. Sommers modeled in 2017 proposal (TPD) O. W. Sommers max daily emissions 2016-2020
------------------------------------------------ (TPD) 2016-2020 Total
------------------------------------------------ as percentage of
Unit 1 Unit 2 Total Unit 1 Unit 2 Total 2017 modeled (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2................................... 2.01 10.92 12.93 0.167 0.147 0.31 2.43
NOX................................... 5.96 8.04 14.00 9.32 6.6 15.92 113.71
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 28943]]
B. BART Five Factor Analysis
The purpose of the BART analysis is to identify and evaluate the
best system of continuous emission reduction based on the BART
Guidelines.\190\ In determining BART, a State, or the 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 non-
air quality environmental impacts of compliance; (3) any existing
pollution control technology in use at the source; (4) the remaining
useful life of the source; and (5) the degree of improvement in
visibility which may reasonably be anticipated to result from the use
of such technology. See also 40 CFR 51.308(e)(1)(ii)(A). This is
commonly referred to as the ``BART five factor analysis.'' The BART
Guidelines break the analyses of these requirements into five steps:
\191\
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\190\ See July 6, 2005 BART Guidelines, 40 CFR part 51, Regional
Haze Regulations and Guidelines for Best Available Retrofit
Technology Determinations.
\191\ 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. Step 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.\192\
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\192\ 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. We will also
note whether any of these technologies are technically infeasible.
The subject-to-BART units identified in Table 5 can be organized
into three broad categories, based on their fuel type and the potential
types of SO2 control options that could be available: (1)
coal-fired EGUs with no SO2 scrubber, (2) coal-fired EGUs
with existing SO2 scrubbers, and (3) gas-fired EGUs that do
not burn oil. This classification is represented in Table 7.
Table 7--Fuel/Control Types for Subject-to-BART Sources
----------------------------------------------------------------------------------------------------------------
Coal (existing
Facility Unit Coal (no scrubber) scrubber) Gas
----------------------------------------------------------------------------------------------------------------
Coleto Creek (Dynegy)............... 1 X
Fayette (LCRA)...................... 1 X
Fayette (LCRA)...................... 2 X
Harrington Station (Xcel)........... 061B X
Harrington Station (Xcel)........... 062B X
Martin Lake (Luminant).............. 1 X
Martin Lake (Luminant).............. 2 X
Martin Lake (Luminant).............. 3 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
----------------------------------------------------------------------------------------------------------------
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) dry Flue Gas Desulfurization
(FGD), and (4) wet FGD. For the coal-fired EGUs with existing
scrubbers, we will examine whether those scrubbers can be upgraded.
Gas-fired EGUs that do not burn oil (W. A. Parish Unit WAP4) have
inherently very low SO2 emissions and there are no known
SO2 controls that can be evaluated.
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 by 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
sulfur in the product coal).\193\ 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.\194\
Coal is mechanically sized, then various washing techniques are
employed, depending on the particle size, type of coal, and the desired
level of preparation.\195\ Following the coal washing, the coal is
dewatered, and the waste streams are disposed.
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\193\ Couch, G. R., ``Coal Upgrading to Reduce CO2
emissions,'' CCC/67, October 2002, IEA Clean Coal Centre.
\194\ Id.
\195\ 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. Coal
washing carries with it a number of problems:
Coal washing is not typically performed on the types of
coals used in
[[Page 28944]]
the power plants under consideration, Powder River Basin (PRB)
subbituminous and Texas lignites.
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,\196\ and coal washing
slurries are typically stored in impoundments, which can, and have,
leaked.\197\
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\196\ ``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.
\197\ 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.
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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., iron pyrite) and rocks, and (2)
the unit burning less coal to make the same amount of power.
Coal drying could be considered a potential BART control. Great
River Energy has developed a patented process which is being
successfully utilized at the Coal Creek facility in North Dakota and is
potentially available for installation at other facilities.\198\ 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. Coal Creek units also utilize
wet FGD to reduce SO2 emissions. Therefore, the observed
additional SO2 emission reductions are due to the
combination of a higher percentage of flue gas being scrubbed
(decreased bypass of the wet FGD) in combination with a decrease in
coal usage and any removal of sulfur in the drying process. We are not
aware of any other EGUs in the United States that utilize coal drying
for the purpose of reducing SO2 emissions. Therefore, we
believe coal drying has limited application at EGUs in the United
States.
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\198\ DryFining\TM\ is the company's name for the process. It is
described here: https://www.powermag.com/improve-plant-efficiency-and-reduce-co2-emissions-when-firing-high-moisture-coals/.
---------------------------------------------------------------------------
Although coal drying may be a potential option 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
several 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). As a result of these issues, we do not further assess
coal drying as part of our reasonable set of options for BART analysis.
DSI
DSI is not a stand-alone, add-on air pollution control system but a
modification to the combustion unit or ductwork. 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. In general, there are many
types of sorbent materials, but their efficacy is variable and
dependent on operating conditions. Trona is currently the most commonly
used sorbent for SO2 removal and is 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 that is more frequently used for acid
gas control.199 200
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\199\ See Documentation for the EPA's Power Sector Modeling
Platform v6 Using the Integrated Planning Model, dated September
2021, page 5-19. Documentation for v.6 downloaded from https://www.epa.gov/power-sector-modeling/documentation-epas-power-sector-modeling-platform-v6-summer-2021-reference.
\200\ ``Dry Sorbent Injection of Sodium Sorbents,'' presented at
the LADCO Lake Michigan Air Directors Consortium, Emission Control
and Measurement Technology for Industrial Sources Workshop, March
24, 2010. A copy of the presentation is located in the docket at
EPA-R06-OAR-2016-0611-0043.
---------------------------------------------------------------------------
There are many examples of DSI being used on coal-fired EGUs.
However, DSI may not be technically feasible at every coal-fired EGU.
For example, DSI technology is not a technically feasible control
option for boilers that burn fuels with sulfur content greater than 2
lb SO2/MMBtu.\201\ Although individual installations may
present technical difficulties or poor performance due to the
suboptimization of operational factors, we believe that DSI may be a
particularly appropriate SO2 control option for boilers that
burn low-sulfur coal or lignite, as such boilers typically do not need
SO2 controls with very high control efficiencies (i.e.,
greater than 95 percent) to achieve low emission rates. Because the
Texas coal-fired EGUs we are evaluating in this proposal burn low-
sulfur coal, we find that they are well suited for consideration of DSI
for SO2 control. Additionally, boilers that operate DSI and
burn low-sulfur coal require much less sorbent than boilers burning
high-sulfur coal to achieve similar control efficiencies. We also note
that DSI is a common control technology that has been widely installed
for compliance with the acid gas control requirements in the Mercury
and Air Toxics Standards (MATS).\202\ For these reasons, we find that
DSI is technically feasible and should be considered as a potential
BART control.
---------------------------------------------------------------------------
\201\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2/HCl Control
Cost Development Methodology, Final April 2017, Project 13527-001,
Eastern Research Group, Inc., Prepared by Sargent & Lundy, page 3.
Documentation for v.6: Chapter 5: Emission Control Technologies,
Attachment 5-5: DSI Cost Methodology, downloaded from https://www.epa.gov/sites/default/files/2018-05/documents/attachment_5-5_dsi_cost_development_methodology.pdf.
\202\ The MATS rule was finalized by the EPA in December 2011,
and compliance with the standard was required by 2015. The MATS rule
requires that plants greater than 25 megawatts meet the maximum
achievable control technology for mercury, hydrochloric acid, and
filterable particulate matter (note the MATS rule does not require
controls for SO2). See https://www.epa.gov/mats/regulatory-actions-final-mercury-and-air-toxics-standards-mats-power-plants.
---------------------------------------------------------------------------
SO2 Scrubbing Systems
In contrast to DSI, SO2 scrubbing techniques utilize a
large, dedicated vessel in which the chemical reaction between the
sorbent (typically lime or limestone) 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 dry FGD. The U.S. Energy
Information Administration (EIA) reports \203\ the following types of
flue
[[Page 28945]]
gas desulfurization systems as being operational in the U.S. for 2020:
---------------------------------------------------------------------------
\203\ See EIA-860 data available here: https://www.eia.gov/electricity/data/eia860/.
Table 8--EIA Reported Desulfurization Systems in 2020
------------------------------------------------------------------------
Number of
Type installations
------------------------------------------------------------------------
Wet spray tower scrubber................................ 288
Spray dryer absorber.................................... 256
Circulating dry scrubber................................ 41
Packed tower wet scrubber............................... 4
Venturi wet scrubber.................................... 58
Jet bubbling reactor.................................... 23
Tray tower wet scrubber................................. 63
Mechanically aided wet scrubber......................... 4
DSI..................................................... 149
Other................................................... 36
Unspecified............................................. 0
---------------
Total................................................. 922
------------------------------------------------------------------------
Excluding the DSI installations,\204\ EIA lists 773 SO2
scrubber installations in operation in 2020. Of these, 288 are listed
as being spray type wet scrubbers, with an additional 63 listed as
being tray type wet scrubbers.\205\ An additional 256 are listed as
being spray dry absorber (SDA) scrubbers, which are a type of dry FGD.
Consequently, spray type or tray type wet scrubbers (wet FGD) account
for approximately 45 percent of all scrubber systems, and SDA accounts
for approximately 33 percent of all scrubber systems that were
operational in the U.S. in 2020.
---------------------------------------------------------------------------
\204\ As discussed in this section, DSI is more commonly
installed for compliance with the acid gas control requirements for
MATS, not for meeting SO reduction requirements.
\205\ 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. Circulating dry scrubbers (CDS) is another type of dry
scrubbing system that can achieve high removal efficiencies but has
seen more limited use in the United States compared to SDA.\206\ Based
on available data, CDS systems have installed costs that are comparable
to SDA systems even though there are differences in design.\207\ CDS
systems may be capable of achieving a slightly higher control
efficiency than SDA, but based on 2019 data for coal-fired units at
power plants, the 12-month average emission rate for the top performing
50 percent FGD systems is 0.06 lb/MMBtu for SDA systems and 0.12 lb/
MMBtu for CDS systems.\208\
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\206\ See the EPA Air Pollution Control Cost Manual, Seventh
Edition (April 2021), Section 5, Chapter 1, page 1-44. The EPA Air
Pollution Control Cost Manual is available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution#cost%20manual. The EPA is currently in
the process of updating the Control Cost Manual and this update will
be the Seventh Edition. Although updates are not yet complete for
all sections the EPA intends to update in the Seventh Edition,
updated Section 5, Chapter 1, which is titled ``Wet and Dry
Scrubbers for Acid Gas Control,'' is now available and is part of
the Seventh Edition of the Control Cost Manual.
\207\ See Control Cost Manual, Wet and Dry Scrubbers for Acid
Gas Control Response to Comment Document, pg 32. Available at
chrome-extension://efaidnbmnnnibpcajpcglclefindmkaj/https://www.epa.gov/sites/default/files/2021-05/documents/rtcdocument_wet_and_dry_scrubbers_controlcostmanual_7thedition.pdf
and in the docket for this action.
\208\ The EPA Air Pollution Control Cost Manual (the Control
Cost Manual, or Manual), Seventh Edition (April 2021), Section 5,
Chapter 1 titled ``Wet and Dry Scrubbers for Acid Gas Control,''
page 1-12. The Control Cost Manual can be found at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution#cost%20manual.
---------------------------------------------------------------------------
The BART Guidelines explain that:
A possible outcome of the BART procedures discussed in these
guidelines is the evaluation of multiple control technology
alternatives which result in essentially equivalent emissions. It is
not our intent to encourage evaluation of unnecessarily large numbers
of control alternatives for every emissions unit. Consequently, you
should use judgment in deciding on those alternatives for which you
will conduct the detailed impacts analysis (Step 4 below).\209\
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\209\ See 40 CFR part 51, Appendix Y--Guidelines For BART
Determinations Under the Regional Haze Rule, Section IV.D.2.
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We believe that evaluation of SDA and wet FGD covers a reasonable
range of control efficiencies offered by available SO2
scrubbing technologies and includes the most stringent control option
available.\210\ CDS will not be further considered as part of our
reasonable set of options for analysis for BART controls given the
similarity in cost and removal efficiencies with SDA. However, CDS
could potentially be considered as an alternative dry scrubber control
to SDA. We therefore solicit comment regarding costs and control
efficiency of CDS, including comments from the facilities we evaluated
for SO2 scrubbers on whether they have conducted analysis of
CDS, the level of SO2 control efficiency that could be
achieved with installation of CDS at the unit, and the estimated cost
of that control technology at the unit.
---------------------------------------------------------------------------
\210\ The EPA Air Pollution Control Cost Manual (the Control
Cost Manual, or Manual), Seventh Edition (April 2021), Section 5,
Chapter 1 titled ``Wet and Dry Scrubbers for Acid Gas Control''
provides data summarizing the efficiency and SO2 emission
rates for SO2 scrubbers based on 2019 data for coal-fired
units at power plants. The 12-month average emission rate for the
top performing 50 percent FGD systems is 0.04 lb/MMBtu for limestone
wet FGD systems, 0.06 lb/MMBtu for SDA systems, and 0.12 lb/MMBtu
for CDS systems. (See page 1-12). The Control Cost Manual can be
found at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution#cost%20manual.
---------------------------------------------------------------------------
Wet FGD and SDA installations account for approximately 79 percent
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. Based on typical SDA
performance, SDA scrubbers should not be applied to boilers that burn
fuels with more than 3 lb SO2/MMBtu.\211\ Typically, SDA
technology has been applied to boilers that burn fuels with less than 2
lb/MMBtu. The Texas coal-fired EGUs we are evaluating in our BART
analyses burn low sulfur coal and are suitable for evaluation of both
SDA and wet FGD. We see no technical infeasibility issues and believe
that limestone wet FGD and lime SDA should be considered as potential
BART controls for all unscrubbed coal-fired subject to BART units.
However, due to potential non-air quality concerns associated with
water availability, we limit our SO2 control analysis for
Harrington Units 061B and 062B to DSI and SDA. This is discussed in
more detail in Section VII.B.3.
---------------------------------------------------------------------------
\211\ IPM Model--Updates to Cost and Performance for APC
Technologies, SDA FGD Cost Development Methodology, Final January
2017, Project 13527-001, Eastern Research Group, Inc., Prepared by
Sargent & Lundy, p. 2.
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b. Identification of Technically Feasible SO2 Control
Technologies for Scrubber Upgrades
In our 2016 Texas-Oklahoma FIP,\212\ we presented a great deal of
information on which we reached a conclusion that the existing
scrubbers for a number of facilities could be very cost-effectively
upgraded.\213\ While that action was stayed by the Fifth Circuit, the
basis for the stay was not related to that technical analysis. This
information remains valid and can be used to inform our BART analysis
in this proposal. Therefore, we have included this information in the
record for this proposal in Appendix A
[[Page 28946]]
of the 2023 BART FIP TSD in the docket.\214\ Appendix A also contains a
comprehensive survey we prepared as part of our 2016 Texas-Oklahoma FIP
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
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 previous CAA 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 utilized in our
analyses, or otherwise disguised it so that it cannot be traced back to
its specific source. Based on our review of this information, we find
that upgrades to the existing scrubbers should be considered as
potential BART controls for the three subject-to-BART units at the
Martin Lake facility.
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\212\ 81 FR 296, 321 (Jan. 5, 2016).
\213\ See information presented in Sections 6 and 7 of the 2016
Texas-Oklahoma FIP Cost TSD, Document No. EPA-R06-OAR-2014-0754-
0008, available at www.regulations.gov.
\214\ See our 2023 BART FIP TSD, Appendix A, ``Wet FGD Scrubber
Upgrade Control Analysis as used in the Texas-Oklahoma FIP.''
---------------------------------------------------------------------------
The Fayette Units 1 and 2 are currently equipped with high
performing wet FGDs. Both units have demonstrated the ability to
maintain a SO2 30 Boiler Operating Day (BOD) average below
0.04 lb/MMBtu for years at a time.\215\ As we discuss in Section
VII.B.2.a, we state that retrofit wet FGDs should be evaluated at 98
percent control not to go below 0.04 lb/MMBtu. Because the Fayette
units are already performing at this level, we do not evaluate any
additional scrubber upgrades for these two units. Thus, our
SO2 BART analysis in this proposed rulemaking evaluates
scrubber upgrades as potential BART controls only for Martin Lake Units
1, 2, and 3.
---------------------------------------------------------------------------
\215\ See our 2023 BART FIP TSD for additional information and
graphs of this data.
---------------------------------------------------------------------------
c. Identification of Technically Feasible SO2 Control
Technologies for Gas Fired Units
Based on our subject to BART screening analysis, W. A. Parish Unit
WAP4 is the only gas-fired unit we determined to be subject to BART.
Because the BART screening analysis is done on a facility-wide basis,
Unit WAP4 is only subject to BART because it is collocated with two
BART-eligible coal-fired units. Gas-fired EGUs have inherently low
SO2 emissions \216\ and there are no known SO2
controls that can be evaluated. While we must assign SO2
BART determinations to the gas-fired unit, there are no practical add-
on controls to consider for setting a more stringent BART emission
limit. The Guidelines state that if the most stringent controls are
made federally enforceable for BART, then the otherwise required
analyses leading up to the BART determination can be skipped.\217\ As
there are no appropriate add-on controls and the status quo reflects
the most stringent control level, we are proposing that SO2
BART for W. A. Parish Unit WAP4 is to limit fuel to pipeline natural
gas, as defined at 40 CFR 72.2.\218\
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\216\ AP 42, Fifth Edition, Volume 1, Chapter 1: External
Sources, Section 1.4, Natural Gas Combustion, available here:
https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s04.pdf.
\217\ 70 FR at 39165 (``. . . you may skip the remaining
analyses in this section, including the visibility analysis . .
.'').
\218\ As provided for in 40 CFR 72.2, pipeline natural gas
contains 0.5 grains or less of total sulfur per 100 standard cubic
feet. This is equivalent to an SO2 emission rate of
0.0006 lb/MMBtu.
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2. Step 3: Evaluation of Control Effectiveness
In the following subsections, we evaluate the control levels each
technically feasible technology can achieve for the coal units. In so
doing, we consider the maximum level of control each technology is
capable of delivering based on a 30 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.''
\219\ 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.
---------------------------------------------------------------------------
\219\ 70 FR 39103, 39172 (July 6, 2005), [40 CFR part 51, App.
Y].
---------------------------------------------------------------------------
a. Evaluation of SO2 Control Effectiveness for Coal-Fired
Units Without an Existing Scrubber
Control Effectiveness of DSI
DSI involves pneumatically injecting a sorbent either directly into
a coal-fired boiler or into ducting downstream of where the coal is
combusted. The sorbent interacts with various pollutants in the flue
gas, including SO2 and acid gases such as hydrochloric acid
(HCl), such that a fraction of these pollutants are removed from the
gas stream. After the appropriate chemical interactions between the
sorbent and the pollutants in the flue gas, the dry waste product of
the reaction is removed using a particulate control device, typically a
fabric filter baghouse or electrostatic precipitator (ESP). The
SO2 removal efficiency of DSI varies greatly but is highly
dependent on the following factors: the type of sorbent used; the
careful balancing of the stoichiometry of the molecules in the sorbent
(sodium in the case of trona or sodium bicarbonate, or calcium in the
case of hydrated lime) and SO2 molecules in the flue gas;
and the type of particulate capture device used in conjunction with the
sorbent injection. Removal efficiency can also be improved by
increasing the surface area of the sorbent to increase reactivity with
the SO2 gas. This can be achieved by crushing or ``milling''
the sorbent and also by applying heat. Both the application of heat and
milling the sorbent increase the efficiency of the DSI system, but also
increase the cost.\220\
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\220\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2/HCl Control
Cost Development Methodology, Final April 2017, Project 13527-001,
Eastern Research Group, Inc., Prepared by Sargent & Lundy.
---------------------------------------------------------------------------
The most common sodium-based sorbents used in DSI systems are trona
and sodium bicarbonate. Sodium bicarbonate is more effective in
removing SO2 emissions than trona,\221\ and therefore, less
sodium bicarbonate is needed for an equivalent amount of SO2
removal compared to trona. However, sodium bicarbonate is more
expensive than trona on a per ton basis. Hydrated lime is a calcium-
based sorbent that is also used in DSI systems. DSI using hydrated lime
typically achieves a lower SO2 removal efficiency compared
to DSI using trona. Aside from the lower SO2 removal
efficiency typically seen with hydrated lime, we also note that DSI
using hydrated lime as the sorbent may necessitate the use of a
baghouse rather than an ESP as the particulate capture device, which
would increase costs if a unit does not already have an existing
baghouse. Because trona is generally considered the most cost-effective
of the DSI sorbents for SO2 removal and considering the
limitations associated with hydrated lime for SO2 removal,
our DSI analysis is based on using milled trona as the sorbent.\222\
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\221\ Sodium bicarbonate may be able to achieve even higher
SO2 removal efficiencies compared to trona. However, the
April 2017 IPM DSI documentation and associated 2019 Retrofit Cost
Analyzer (RCA) tool cost spreadsheet do not include information on
sodium bicarbonate costs and removal efficiencies.
\222\ As discussed in the preceding paragraph, the removal
efficiency of trona can be improved by crushing or ``milling'' the
sorbent, which increases the reactivity with the SO2 gas.
The control efficiencies we evaluate for DSI and our cost analysis
is based on the use of milled trona.
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[[Page 28947]]
In developing our BART analysis for DSI, we relied on the EPA's
April 2017 version of the Integrated Planning Model (IPM) DSI
documentation 223 224 and the 2019 version of the EPA's
Retrofit Cost Analyzer (RCA), which is an Excel-based tool that can be
used to estimate the cost of building and operating air pollution
controls and also employs version 6 of our IPM model.\225\ We expect
that by the time this proposal is published in the Federal Register, or
shortly thereafter, the EPA will have issued an updated version of the
IPM DSI documentation and an accompanying updated version of the RCA
tool for calculating the cost of DSI. The updated IPM DSI documentation
and updated RCA tool for DSI include a number of updates to the cost
algorithms and updated estimates for sorbent costs. Initial review of
the updated DSI documentation indicates the maximum potential
SO2 control efficiencies of DSI may be higher than indicated
in the April 2017 version of the IPM DSI documentation. The updated DSI
documentation and RCA tool also include updated cost algorithms
predicting the amount of sorbent required to achieve certain control
efficiencies that generally result in similar cost effectiveness values
($/ton) for DSI using milled trona compared to the cost algorithms used
in the April 2017 version of the IPM DSI documentation and the 2019
version of the RCA tool. This is the result of the updated efficiency
curves estimating lower sorbent use and updated higher costs for milled
trona. The updated RCA tool contains cost information for sodium
bicarbonate and the capability to estimate the cost of DSI using sodium
bicarbonate as the sorbent. In general, the cost-effectiveness values
for DSI using milled trona and sodium bicarbonate appear to be very
similar. Less sodium bicarbonate is needed than milled trona to achieve
a given control efficiency but the cost per ton of sodium bicarbonate
is higher compared to milled trona, thereby resulting in similar cost-
effectiveness values. However, the updated IPM DSI documentation
indicates that sodium bicarbonate may be able to achieve higher control
efficiencies compared to milled trona. We will include these documents
in the docket once they are finalized and made publicly available. As
these updated documents were not available at the time we developed our
cost analysis, we did not rely on this updated information in our DSI
cost analysis presented in this proposal. In general, the updated IPM
DSI documentation and updated RCA tool for DSI suggest that DSI could
potentially achieve higher SO2 control efficiencies at a
similar cost per SO2 tons removed. However, as described in
further detail below, absent site-specific information from the
facilities that we evaluated for DSI, we believe there is uncertainty
whether these units are capable of achieving the assumed maximum DSI
performance levels specified in either the April 2017 IPM DSI
documentation or the updated version of the IPM DSI documentation.
Similarly, we believe that our concern regarding the uncertainty in the
cost estimates for DSI at high SO2 removal levels would
still exist even if we were to rely on the updated versions of the IPM
DSI documentation and the RCA tool.\226\ However, as we discuss later
in this subsection, we solicit comment on the range and maximum control
efficiency that can be achieved with DSI at the evaluated units and
estimates of the range of associated costs. We are especially
interested in any site-specific analysis of DSI for the units we
evaluated, the level of SO2 control efficiency that could be
achieved with installation of DSI at these units, and the estimated
cost of that control technology at these units.
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\223\ See Documentation for the EPA's Power Sector Modeling
Platform v6 Using the Integrated Planning Model, dated September
2021. Documentation for v.6 downloaded from https://www.epa.gov/power-sector-modeling/documentation-epas-power-sector-modeling-platform-v6-summer-2021-reference.
\224\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2/HCl Control
Cost Development Methodology, Final April 2017, Project 13527-001,
Eastern Research Group, Inc., Prepared by Sargent &Lundy.
Documentation for v.6: Chapter 5: Emission Control Technologies,
Attachment 5-5: DSI Cost Methodology, downloaded from https://www.epa.gov/sites/default/files/2018-05/documents/attachment_5-5_dsi_cost_development_methodology.pdf.
\225\ Retrofit Cost Analyzer, rev: 06-04-2019, downloaded from
https://www.epa.gov/power-sector-modeling/retrofit-cost-analyzer.
\226\ We discuss these issues in more detail in Sections
VII.B.3.a and VIII.A.
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According to the April 2017 IPM DSI documentation, the assumed
maximum DSI performance level using milled trona is 80 percent
SO2 removal for an Electrostatic Precipitator (ESP)
installation and 90 percent SO2 removal for a baghouse
installation.\227\ The BART Guidelines state the following regarding
selection of an emissions performance level or levels to evaluate in a
BART analysis for a control option with a wide range of emission
performance levels:
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\227\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2/HCl Control
Cost Development Methodology, Final April 2017, Project 13527-001,
Eastern Research Group, Inc., Prepared by Sargent & Lundy.
Documentation for v.6: Chapter 5: Emission Control Technologies,
Attachment 5-5: DSI Cost Methodology, downloaded from https://www.epa.gov/sites/default/files/2018-05/documents/attachment_5-5_dsi_cost_development_methodology.pdf.
It is not our intent to require analysis of each possible level
of efficiency for a control technique as such an analysis would
result in a large number of options. It is important, however, that
in analyzing the technology you take into account the most stringent
emission control level that the technology is capable of achieving.
You should consider recent regulatory decisions and performance data
(e.g., manufacturer's data, engineering estimates and the experience
of other sources) when identifying an emissions performance level or
levels to evaluate.\228\
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\228\ See 40 CFR Part 51, Appendix Y--Guidelines For BART
Determinations Under the Regional Haze Rule, Section IV.D.3.
Adhering to this, we are evaluating each unit at its assumed
maximum achievable DSI performance level according to the April 2017
IPM DSI documentation. All the units we are evaluating for DSI controls
have existing baghouses with the exception of Harrington Unit 061B,
which has an ESP. For Coleto Creek Unit 1 and W. A. Parish Units WAP5
and WAP6, we are evaluating DSI at 90 percent SO2 removal.
For Welsh Unit 1 and Harrington Unit 062B, we are limiting the upper
DSI control to their equivalent SDA control efficiencies of 87 percent
and 89 percent, respectively. For Harrington Unit 061B, the only unit
with an existing ESP, we are evaluating DSI at 80 percent
SO2 removal.
We recognize that there is some variation based on facility-
specific circumstances which could affect whether a given unit is
actually capable of achieving these assumed maximum performance levels.
There is typically a direct correlation with DSI between the targeted
SO2 removal efficiency and the amount of sorbent needed;
therefore, more sorbent is needed to reach higher SO2
removal efficiencies. However, the reaction between the sorbent and the
various pollutants in the flue gas results in a dry waste product that
must be removed using a particulate control device. As additional
sorbent is added to achieve higher SO2 removal efficiencies,
the increased dry waste product can impact the performance of the
particulate control device. For instance, DSI using trona and an ESP
for capture of the dry waste product typically can achieve 40-50
percent SO2 removal efficiency without an increase in
particulate emissions.\229\ At higher
[[Page 28948]]
SO2 removal efficiencies, however, depending on the
throughput capacity, an ESP may not be able to handle the increased dry
waste product. Similar issues exist where DSI is used with a fabric
filter for capture of the dry waste product. The increased dry waste
product produced in trying to achieve high SO2 removal
efficiencies would result in the more rapid formation of baghouse
filter cake, which is the mixture of fly ash and sorbent-SO2
reaction product. This would result in the need for more frequent
cleaning, more rapid filter bag wear, and more frequent replacement of
filter bags. The frequent need to clean and replace the filter bags may
become impractical and additional fabric filter compartments may need
to be added to handle the high loading that occurs at high
SO2 removal efficiencies. The exact SO2 removal
efficiency at which these secondary impacts would become significant is
typically site-specific. As we discuss in Section VII.B.3.a, these
secondary impacts associated with trying to achieve higher
SO2 removal efficiencies also lead to some uncertainty in
our cost estimates for DSI at high SO2 removal efficiencies.
---------------------------------------------------------------------------
\229\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2/HCl Control
Cost Development Methodology, Final April 2017, Project 13527-001,
Eastern Research Group, Inc., Prepared by Sargent & Lundy.
Documentation for v.6: Chapter 5: Emission Control Technologies,
Attachment 5-5: DSI Cost Methodology, p. 3; downloaded from https://www.epa.gov/sites/default/files/2018-05/documents/attachment_5-5_dsi_cost_development_methodology.pdf.
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Site-specific information based on individual performance testing
is typically needed to be able to accurately determine the maximum DSI
SO2 removal efficiency for a particular unit. We do not have
this site-specific information and testing for the individual units
that we are evaluating for DSI. Instead, we analyzed publicly available
2017-2021 data for coal-fired EGUs with existing DSI systems and
estimated the monthly average SO2 removal efficiency of
existing DSI systems by utilizing the reported sulfur content and
tonnages of the fuels burned and reported to EIA \230\ and the
monitored SO2 outlet emissions reported to the EPA.\231\
Based on our analysis, we found that there is a large range of
SO2 removal efficiency at the coal-fired EGUs with existing
DSI for which there is publicly available data. However, unless there
is a specific regulatory requirement to meet a low SO2
emissions rate, DSI installations are often not optimized to achieve
the highest possible SO2 control efficiency. Of particular
interest for this BART analysis, there are existing coal-fired DSI
units that are consistently achieving high monthly average
SO2 removal efficiencies in the 70-90 percent range. We
discuss this analysis in further detail in our 2023 BART FIP TSD in the
docket. However, because we could only identify a few cases where units
are consistently achieving greater than 70 percent SO2
control efficiency and, most importantly, because we do not have the
site-specific information and individual performance testing needed to
accurately determine the maximum DSI SO2 removal efficiency
for a particular unit, we do not know whether the EGUs we are
evaluating in this proposal are capable of achieving the assumed
maximum DSI performance levels specified in the April 2017 IPM DSI
documentation or what level of control should be considered the maximum
achievable level for these units.
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\230\ EIA Form 923. Available at https://www.eia.gov/electricity/data/eia923/.
\231\ EPA Air Markets and Programs Data. Available at https://campd.epa.gov/.
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Recognizing that DSI has a wide range of SO2 removal
efficiencies, that there is some variation based on facility-specific
circumstances which could affect whether a given unit is actually
capable of achieving the assumed maximum achievable control levels
outlined in the April 2017 IPM DSI documentation, and because we
believe it is useful to evaluate lesser levels of DSI control to
provide a range of costs, we will also evaluate these units at a DSI
SO2 control level that can likely be achieved by most coal-
fired units. DSI using trona and an ESP for particulate capture can
typically remove 40-50 percent of SO2 without affecting the
performance of the particulate control device.\232\ Therefore, we
believe 50 percent SO2 removal is a conservatively low DSI
control efficiency that any given coal-fired EGU is likely capable of
achieving without requiring high sorbent injection rates that may
negatively impact the particulate control. This approach is consistent
with the BART Guidelines, which state the following:
---------------------------------------------------------------------------
\232\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2/HCl Control
Cost Development Methodology, Final April 2017, Project 13527-001,
Eastern Research Group, Inc., Prepared by Sargent & Lundy.
Documentation for v.6: Chapter 5: Emission Control Technologies,
Attachment 5-5: DSI Cost Methodology, p. 3; downloaded from https://www.epa.gov/sites/default/files/2018-05/documents/attachment_5-5_dsi_cost_development_methodology.pdf.
You may encounter cases where you may wish to evaluate other
levels of control in addition to the most stringent level for a
given device. While you must consider the most stringent level as
one of the control options, you may consider less stringent levels
of control as additional options. This would be useful, particularly
in cases where the selection of additional options would have widely
varying costs and other impacts.\233\
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\233\ See 40 CFR part 51, appendix Y--Guidelines For BART
Determinations Under the Regional Haze Rule, Section IV.D.3.
We invite comments on the range and maximum control efficiency that
can be achieved with DSI at the evaluated units. We are especially
interested in any site-specific DSI testing for the units we evaluated
to determine the range and maximum control efficiency that can be
achieved at those units. Any data to support the range and maximum
control efficiency for a particular unit should be submitted along with
those comments. We will further consider DSI site-specific information
provided to us during the public comment period in making our final
decision and potentially re-evaluate DSI and the control efficiency for
one or more particular units.
Control Effectiveness of Wet FGD and SDA
We have assumed a wet FGD level of control to be a maximum of 98
percent not to go below 0.04 lb/MMBtu, in which case, we assume the
percentage of control equal to 0.04 lb/MMBtu. As we discuss later in
this proposal, we conducted our wet FGD control cost analysis using the
EPA's ``Air Pollution Control Cost Estimation Spreadsheet For Wet and
Dry Scrubbers for Acid Gas Control,'' \234\ which employs version 6 of
our IPM model.\235\ The IPM wet FGD
[[Page 28949]]
Documentation states: ``The least-squares curve fit of the data was
defined as a ``typical'' wet FGD retrofit for removal of 98 percent 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.'' \236\ The most
recent version of the EPA Air Pollution Control Cost Manual (the
Control Cost Manual, or Manual) section on Wet and Dry Scrubbers for
Acid Gas Control \237\ provides data summarizing the efficiency and
SO2 emission rates for SO2 scrubbers based on
2019 data for coal-fired units at power plants. The 12-month average
emission rate for the top performing 50 percent of wet limestone FGD
systems is 0.04 lb/MMBtu.\238\
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\234\ Air Pollution Control Cost Estimation Spreadsheet For Wet
and Dry Scrubbers for Acid Gas Control, U.S. Environmental
Protection Agency, Air Economics Group, Health and Environmental
Impacts Division, Office of Air Quality Planning and Standards
(January 2023), downloaded from https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
\235\ See Documentation for the EPA's Power Sector Modeling
Platform v6 Using the Integrated Planning Model, dated September
2021. Documentation for v.6 downloaded from https://www.epa.gov/power-sector-modeling/documentation-epas-power-sector-modeling-platform-v6-summer-2021-reference.
IPM Model--Updates to Cost and Performance for APC Technologies,
Dry Sorbent Injection for SO2/HCl Control Cost
Development Methodology, Final April 2017, Project 13527-001,
Eastern Research Group, Inc., Prepared by Sargent & Lundy.
Documentation for v.6: Chapter 5: Emission Control Technologies,
Attachment 5-5: DSI Cost Methodology, downloaded from https://www.epa.gov/sites/default/files/2018-05/documents/attachment_5-5_dsi_cost_development_methodology.pdf.
IPM Model--Updates to Cost and Performance for APC Technologies,
SDA FGD Cost Development Methodology, Final January 2017, Project
13527-001, Eastern Research Group, Inc., Prepared by Sargent &
Lundy. Documentation for v.6: Chapter 5: Emission Control
Technologies, Attachment 5-2: SDA FGD Cost Methodology, downloaded
from https://www.epa.gov/sites/default/files/2018-05/documents/attachment_5-2_sda_fgd_cost_development_methodology.pdf.
IPM Model--Updates to Cost and Performance for APC Technologies,
Wet FGD Cost Development Methodology, Final January 2017, Project
13527-001, Eastern Research Group, Inc., Prepared by Sargent &
Lundy. Documentation for v.6: Chapter 5: Emission Control
Technologies, Attachment 5-1: Wet FGD Cost Methodology, downloaded
from https://www.epa.gov/sites/default/files/2018-05/documents/attachment_5-1_wet_fgd_cost_development_methodology.pdf.
\236\ IPM Model--Updates to Cost and Performance for APC
Technologies, Wet FGD Cost Development Methodology, Final January
2017, Project 13527-001, Eastern Research Group, Inc., Prepared by
Sargent & Lundy, p. 2.
\237\ EPA Air Pollution Control Cost Manual, Seventh Edition,
April 2021 available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution#cost%20manual. The EPA is currently in the process of
updating the Control Cost Manual and this update will be the Seventh
Edition. Although updates are not yet complete for all sections the
EPA intends to update in the Seventh Edition, updated Section 5,
Chapter 1, which is titled ``Wet and Dry Scrubbers for Acid Gas
Control,'' is now available and is part of the Seventh Edition of
the Control Cost Manual.
\238\ These observed overall SO2 emission rates are
likely attributable to a variety of factors including improvements
in the design and operation of FGD systems and operational changes
at some utilities from switching to lower sulfur coal and operating
at less than full capacity. EPA Air Pollution Control Cost Manual,
Seventh Edition, April 2021, Section 5, Chapter 1, p 1-12.
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Assuming a wet FGD level of control to be a maximum of 98 percent
not to go below 0.04 lb/MMBtu is also consistent with our determination
in the 2011 Oklahoma FIP.\239\ Issues that have been raised in the past
concerning these conclusions are discussed further in Appendix A of the
2023 BART FIP TSD in the docket. Elsewhere in this notice and in the
2023 BART FIP TSD, we discuss the performance of the wet FGD on Fayette
Units 1 and 2 as an example of units with emission rates consistent
with our assumption of 0.04 lb/MMBtu with this control technology. We
propose that this level of control for wet FGD is reasonable.
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\239\ As discussed previously in our TSD for that action,
control efficiencies reasonably achievable by dry scrubbing and wet
scrubbing were determined to be 95 percent and 98 percent
respectively. 76 FR 81728, 81742 (2011); Oklahoma v. EPA, 723 F.3d
1201 (July 19, 2013), cert. denied (U.S. May 27, 2014). This level
of control was also employed in our Texas-Oklahoma FIP. See 81 FR at
321.
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In evaluating the control effectiveness for SDA, the Control Cost
Manual identifies the 12-month average emission rate for the top
performing 50 percent of SDA systems as 0.06 lb/MMBtu.\240\ As with our
Oklahoma FIP, we have assumed an SDA level of control equal to 95
percent, 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 lb/MMBtu.\241\ In that Oklahoma
FIP, we finalized the same emission limit of 0.06 lb/MMBtu on a 30 BOD
average for six coal-fired EGUs in Oklahoma. We justified those limits
based on the same SDA technology, using a combination of industry
publications and real-world monitoring data. Much of the information in
support of our position that an emission limit of 0.06 lb/MMBtu on a 30
BOD average is within the demonstrated capabilities of SDA retrofits is
summarized in our response to comments document for the Oklahoma FIP
\242\ and in our 2023 BART FIP TSD. We propose that this level of
control for SDA is reasonable.
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\240\ These observed overall SO2 emission rates are
likely attributable to a variety of factors including improvements
in the design and operation of FGD systems and operational changes
at some utilities from switching to lower sulfur coal and operating
at less than full capacity. EPA Air Pollution Control Cost Manual,
Seventh Edition, April 2021, Section 5, Chapter 1, p 1-12.
\241\ See 76 FR 81728 (December 28, 2011).
\242\ 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.
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b. Evaluation of SO2 Control Effectiveness for Coal-fired
Units With Existing Scrubbers
Control Effectiveness of Upgrades to Existing Scrubbers
Of the units we are proposing to determine are subject to BART,
Martin Lake Units 1, 2, and 3 are currently equipped with wet FGDs that
are not high-performing. Based on information we received from the
facility, which we obtained in response to our previous CAA Section
114(a) information collection request, we find that upgrades to the
existing scrubbers should be considered as potential BART controls for
these Martin Lake units. Because the company asserted a CBI claim for
much of the information supplied to us, as provided in 40 CFR 2.203(b),
we are limited in what information we can include in this section. The
following summary is based on information not claimed as CBI.
The absorber system could be upgraded to perform at an
SO2 removal efficiency of at least 95 percent using proven
equipment and techniques.
The SO2 scrubber bypass could be eliminated,
and the additional flue gas could be treated by the absorber system
with at least a 95 percent removal efficiency.
Additional modifications necessary to eliminate the bypass
could be performed using proven equipment and techniques.
The additional SO2 emission reductions
resulting from the scrubber upgrade would be substantial.
Given that we lack Continuous Emissions Monitoring Systems (CEMS)
data for the inlet of the scrubbers and only have CEMS data for the
outlet of the scrubbers, we calculated the current removal efficiency
of each scrubber by utilizing the reported sulfur content and tonnages
of the fuels burned and reported to EIA \243\ and the monitored
SO2 scrubber outlet emissions reported to the EPA.\244\ Our
approach for estimating the current removal efficiency of the existing
scrubbers is discussed in greater detail in our 2023 BART FIP TSD in
the docket. Based on emissions rate data and reported sulfur content
and tonnages of the fuels burned in 2016--2020, we have estimated that
the current removal efficiency of the existing scrubbers at the Martin
Lake units is approximately 64 percent at Unit 1, 66 percent at Unit 2,
and 64 percent at Unit 3.\245\ We find that an assumption that upgrades
to the existing scrubbers can increase their control efficiency to 95
percent at Martin Lake Units 1, 2, and 3 is reasonable. This is below
the upper end of what an upgraded wet SO2 scrubber can
achieve, which is 98-99 percent, as we have noted in the 2023 BART FIP
TSD in the docket. We believe that a 95 percent control assumption
provides an adequate margin of error, such that the Martin Lake units
would be able to comfortably achieve this removal efficiency. Based on
the reported sulfur content and tonnages of the fuels
[[Page 28950]]
burned in 2016-2020, 95 percent control would equate to an emission
rate of 0.08 lb/MMBtu for each unit.
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\243\ EIA Form 923. Available at https://www.eia.gov/electricity/data/eia923/.
\244\ EPA Air Markets and Programs Data. Available at https://campd.epa.gov/.
\245\ See ``Coal vs CEM data 2016-2020_ML.xlsx,'' tab
``charts,'' cell H12. This Excel spreadsheet is located in the
docket associated with this proposed rule.
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3. Step 4: Evaluate Impacts and Document the Results for SO2
The BART Guidelines offer the following with regard to how Step 4
should be conducted: \246\
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\246\ 70 FR at 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 there are usually no appreciable differences
in these factors from unit to unit.\247\ 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).\248\ We proceed in our
SO2 cost analyses by examining the current SO2
emissions and the level of SO2 control, if any, for each of
the coal-fired units listed in Table 7.\249\
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\247\ 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.
\248\ EPA Air Pollution Control Cost Manual, Seventh Edition,
April 2021 available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution#cost%20manual. The EPA is currently in the process of
updating the Control Cost Manual and this update will be the Seventh
Edition. Although updates are not yet complete for all sections the
EPA intends to update in the Seventh Edition, updated Section 5,
Chapter 1, which is titled ``Wet and Dry Scrubbers for Acid Gas
Control,'' is now available and is part of the Seventh Edition of
the Control Cost Manual.
\249\ W.A. Parish WAP4 is the only gas-fired unit we determined
to be subject to BART. As we discussed in Section VII.B.1.c, gas-
fired EGUs have inherently low SO2 emissions and there
are no known SO2 controls that can be evaluated.
Therefore, our cost analysis does not include WAP4.
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a. Impact Analysis Part 1: Cost of Compliance for DSI, SDA, and Wet FGD
As we discuss in Section VII.B.2. and in our 2023 BART FIP TSD
associated with this notice, we evaluated each unit at the assumed
maximum SO2 performance levels, considering the type of
SO2 control device. For DSI, in addition to evaluating each
unit at the assumed maximum achievable level of SO2 control,
we also evaluated each unit at 50 percent control efficiency. In Table
9 we present a summary of our DSI, SDA, and wet FGD cost analysis.\250\
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\250\ In this table, the annualized cost is the sum of the
annualized capital cost and the annualized operational cost. See our
TSD for more information on how these costs were calculated.
Table 9--Summary of DSI, SDA, and Wet FGD Cost Analysis
--------------------------------------------------------------------------------------------------------------------------------------------------------
SO2 reduction Cost Incremental Cost-
Facility Unit Control Control level (tpy) Annualized effectiveness (/ effectiveness(/
(%) cost ton) \1\ ton) \2\ \3\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coleto Creek................. 1............. DSI.................. 50 6,680 $15,016,712 $2,249 ................
DSI.................. 90 12,024 29,320,229 2,439 2,677
SDA.................. 91 12,035 32,400,831 2,692 3,246
Wet FGD.............. 94 12,448 36,238,608 2,911 9,292
Harrington................... 061B.......... DSI.................. 50 1,892 7,075,817 3,740 ................
DSI.................. 80 3,027 11,596,018 3,830 3,983
SDA.................. 89 3,327 21,967,236 6,603 10,377
062B.......... DSI.................. 50 2,703 7,408,200 2,742 ................
DSI.................. 89 4,794 13,104,954 2,734 2,724
SDA.................. 89 4,812 23,369,564 4,857 7,568
Welsh........................ 1............. DSI.................. 50 3,959 10,952,162 2,766 ................
DSI.................. 87 6,885 18,562,875 2,696 2,601
SDA.................. 87 6,878 30,056,814 4,370 6,545
Wet FGD.............. 91 7,219 32,464,043 4,497 7,059
W.A. Parish.................. WAP5.......... DSI.................. 50 6,689 15,125,672 2,262 ................
DSI.................. 90 12,039 29,457,805 2,447 2,679
SDA.................. 91 12,139 36,957,568 3,044 4,006
Wet FGD.............. 94 12,560 38,607,330 3,074 3,919
WAP6.......... DSI.................. 50 6,902 15,489,974 2,244 ................
DSI.................. 90 12,423 30,246,942 2,435 2,673
SDA.................. 91 12,475 33,070,310 2,651 3,155
Wet FGD.............. 94 12,908 35,073,781 2,717 4,627
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ We evaluated DSI both at the assumed maximum DSI performance levels of 80/90 percent specified in the April 2017 IPM DSI documentation and at 50
percent control efficiency. However, we note there is uncertainty that the units we are evaluating for DSI are actually capable of achieving the
assumed maximum DSI performance levels specified in the April 2017 IPM DSI documentation and there is also potential uncertainty in the DSI cost
estimates at these high DSI performance levels.
\2\ The incremental cost effectiveness calculation compares the costs and performance level of a control option to those of the next most stringent
option, as shown in the following formula (with respect to cost per emissions reduction): Incremental Cost Effectiveness (dollars per incremental ton
removed) = (Total annualized costs of control option)-(Total annualized costs of next control option) / (Control option annual emissions)-(Next
control option annual emissions). See Section IV.D.4.e of Appendix Y to Part 51--Guidelines for BART Determinations Under the Regional Haze Rule.
\3\ We calculated the incremental cost-effectiveness of SDA by comparing it to DSI at 50 percent control efficiency rather than to DSI at 80/87/89/90
percent control efficiency. We took this approach given the following considerations: (1) the control efficiencies of SDA and DSI at the assumed
maximum DSI performance level for units with fabric filters specified in the April 2017 IPM DSI documentation are assumed to be identical; (2) there
is uncertainty that the units we are evaluating for DSI are actually capable of achieving the assumed maximum DSI performance levels specified in the
April 2017 IPM DSI documentation; and (3) there is potential uncertainty in the cost estimates for DSI at these high DSI performance levels, as
discussed later in this subsection.
[[Page 28951]]
For the coal units without any SO2 control, we
calculated the cost of installing DSI, an SDA scrubber, and a wet FGD
scrubber. In order to estimate the costs for SDA scrubbers and wet FGD
scrubbers, we used the ``Air Pollution Control Cost Estimation
Spreadsheet For Wet and Dry Scrubbers for Acid Gas Control,'' which is
an Excel-based tool that can be used to estimate the costs for
installing and operating scrubbers for reducing sulfur dioxide and
acidic gas emissions from fossil fuel-fired combustion units and other
industrial sources of acid gases.\251\ The methodologies for wet FGD
scrubbers and SDA scrubbers are based on those from version 6 of our
IPM model.\252\ The size and costs of a wet FGD scrubber and SDA
scrubber are based primarily on the size of the combustion unit and the
sulfur content of the coal burned. The wet FGD scrubber methodology
includes cost algorithms for capital and operating cost for wastewater
treatment consisting of chemical pretreatment, low hydraulic residence
time biological reduction, and ultrafiltration to treat wastewater
generated by the wet FGD system. The calculation methodologies used in
the ``Air Pollution Control Cost Estimation Spreadsheet For Wet and Dry
Scrubbers for Acid Gas Control,'' are those presented in the U.S. EPA's
Air Pollution Control Cost Manual.
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\251\ Air Pollution Control Cost Estimation Spreadsheet For Wet
and Dry Scrubbers for Acid Gas Control, U.S. Environmental
Protection Agency, Air Economics Group, Health and Environmental
Impacts Division, Office of Air Quality Planning and Standards
(January 2023), downloaded from https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
\252\ See Documentation for EPA's Power Sector Modeling Platform
v6 Using the Integrated Planning Model, dated September 2021.
Documentation for v.6 downloaded from https://www.epa.gov/power-sector-modeling/documentation-epas-power-sector-modeling-platform-v6-summer-2021-reference.
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The cost algorithm used in the ``Air Pollution Control Cost
Estimation Spreadsheet For Wet and Dry Scrubbers for Acid Gas Control''
calculates the Total Capital Investment, Direct Annual Cost, and
Indirect Annual Cost. The Total Capital Investment for wet FGD is a
function of the absorber island capital costs, reagent preparation
equipment costs, waste handling equipment costs, balance of plant
costs, and wastewater treatment facility costs. For SDA, the Total
Capital Investment is a function of the absorber island capital costs
that include both an absorber and a baghouse, reagent preparation and
waste recycling/handling costs, and balance of plant costs. The Direct
Annual Costs consist of annual maintenance cost, annual operator cost,
annual reagent cost, annual make-up water cost, annual waste disposal
cost, and annual auxiliary power cost. Additionally, the Direct Annual
Costs for wet FGD also include annual wastewater treatment cost and the
replacement cost of a mercury monitor (replaced once every 6 years).
The Indirect Annual Cost consists of administrative charges and capital
recovery costs.
To estimate the costs for DSI, we relied on the EPA's April 2017
IPM DSI documentation \253\ and the 2019 version of the EPA's RCA tool,
which employs version 6 of our IPM model.\254\ The cost algorithm used
in the RCA tool calculates the Total Project Cost (TPC), Fixed
Operating and Maintenance (Fixed O&M) costs, and Variable Operating and
Maintenance (Variable O&M) costs. As we discuss in Section VII.B.2.a.,
for DSI systems using a fabric filter for particulate control and
operating at high SO2 removal efficiency, it is expected
that filter bag wear would occur more rapidly and that filter bags
would need to be replaced more frequently due to the increased dry
waste product. The frequent need to clean and replace the filter bags
may become impractical and additional fabric filter compartments may
need to be added to handle the high loading that occurs at high
SO2 removal efficiencies. This impacts the cost and leads to
some uncertainty in our cost estimates for DSI at high SO2
removal efficiencies given that we do not have site-specific
information and performance testing to determine how frequently filter
bags would need to be replaced or whether additional fabric filter
compartments are necessary. Similarly, DSI systems with an ESP for
particulate control may not be capable of handling the higher loadings
at high SO2 removal efficiencies and would require
consideration of additional costs for a new ESP or fabric filter to
handle the load at these high sorbent injection rates. This impacts the
cost and leads to some uncertainty in our cost estimates for DSI with
an existing ESP (for Harrington Unit 061B) given that our cost
estimates do not reflect the cost of a new ESP or fabric filter even
though we do not know with certainty whether the existing ESP can
handle the high sorbent injection rates needed at high SO2
removal efficiency.
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\253\ See Documentation for EPA's Power Sector Modeling Platform
v6 Using the Integrated Planning Model, dated September 2021.
Documentation for v.6 downloaded from https://www.epa.gov/power-sector-modeling/documentation-epas-power-sector-modeling-platform-v6-summer-2021-reference.
IPM Model--Updates to Cost and Performance for APC Technologies,
Dry Sorbent Injection for SO2/HCl Control Cost
Development Methodology, Final April 2017, Project 13527-001,
Eastern Research Group, Inc., Prepared by Sargent & Lundy.
Documentation for v.6: Chapter 5: Emission Control Technologies,
Attachment 5-5: DSI Cost Methodology, downloaded from https://www.epa.gov/sites/default/files/2018-05/documents/attachment_5-5_dsi_cost_development_methodology.pdf.
\254\ Retrofit Cost Analyzer, rev: 06-04-2019, downloaded from
https://www.epa.gov/power-sector-modeling/retrofit-cost-analyzer.
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As we discuss in Section VII.B.2.a, we expect that by the time this
proposal is published in the Federal Register, or shortly thereafter,
the EPA will have issued an updated version of the IPM DSI
documentation and an updated version of the RCA tool for calculating
the cost of DSI. We will include these documents in the docket once
they are finalized and made publicly available. As these updated
documents were not available at the time we developed our cost
analysis, we did not rely on this information in our DSI cost analysis
presented in this proposal. In general, the updated IPM DSI
documentation and updated RCA tool for DSI suggest that DSI could
potentially achieve higher SO2 control efficiencies and at a
similar cost per SO2 tons removed. Absent site-specific
information from the facilities that we evaluated for DSI, we believe
that our concerns regarding the uncertainty of whether these units are
actually capable of achieving the assumed maximum DSI performance
levels and the uncertainty in the cost estimates for DSI at high
SO2 removal efficiencies would still exist even if we were
to rely on the updated versions of the IPM DSI documentation and the
RCA tool. However, we invite comments on the range and maximum control
efficiency that can be achieved with DSI at the evaluated units and
estimates of the range of associated costs. We are especially
interested in any site-specific DSI testing for the units we evaluated
to determine the range and maximum control efficiency that can be
achieved at those units and any other unit-specific information that
would help provide better insight into the unit-specific DSI costs. Any
data to support the control efficiency range, maximum control
efficiency, and cost of DSI for a particular unit should be submitted
along with those comments. We will further consider DSI site-specific
information provided to us during the public comment period in our
final decision and potentially re-evaluate DSI for those particular
units.
The cost models used in IPM version 6 were based on 2016 dollars.
Thus, in
[[Page 28952]]
performing the cost calculations \255\ for each unit listed in Table 9
we have escalated the costs to 2020 dollars. For DSI, we accomplished
this escalation using the annual Chemical Engineering Plant Cost
Indices (CEPCI). For the SDA and wet FGD scrubbers, the ``Air Pollution
Control Cost Estimation Spreadsheet For Wet and Dry Scrubbers for Acid
Gas Control'' allows the user to enter a different dollar-year for
costs and the corresponding cost index if a different dollar-year is
desired. Using this capability, we entered the 2020 CEPCI index into
the spreadsheet to estimate the cost of wet FGD scrubbers and SDA
scrubbers in 2020 dollars. For a more detailed discussion of the inputs
and cost calculations, see our 2023 BART FIP TSD in the docket.
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\255\ The cost calculation spreadsheets can be found in the
docket for this action under the heading ``Cost Calculations''.
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b. Impact Analysis Part 1: Cost of Compliance for Scrubber Upgrades
In our 2023 BART FIP TSD associated with this proposed rulemaking,
we analyze those units listed in Table 7 of this notice that have an
existing SO2 scrubber in order to determine if cost-
effective scrubber upgrades are available. Of our subject-to-BART
units, Martin Lake Units 1, 2, 3; and Fayette Units 1 and 2 are
currently equipped with wet FGDs. As discussed in Section VII.B.1.b,
because the Fayette units are already performing at the maximum level
of control we considered for wet FGD, we will not evaluate any
additional scrubber upgrades for these two units.
Martin Lake was the highest emitting EGU facility for
SO2 in the United States for the past four years (2018-
2021). On an individual unit basis, Martin Lake Units 1, 2, and 3 were
the top three emitting units in the country in 2018 and among the top
four emitting units in 2019 and 2021.\256\ In general, given the very
large emissions, potential for large emission reductions, and the lower
costs associated with upgrading existing controls compared to a new
scrubber retrofit, it is reasonable to expect scrubber upgrades at
Martin Lake to be very cost-effective in terms of cost per ton removed.
A review of emissions data for these units shows significant
variability and demonstrates the ability of these units to be operated
with higher removal efficiency to maintain lower emission levels for
periods of time depending on the mixture of coals, the operation of the
scrubbers, and the amount of scrubber bypass. For example, in 2016, the
annual average emission rate for the three units ranged from 0.3 to
0.43 lb/MMBtu, but in 2020, the annual average emission rate ranged
from 0.55 to 0.73 lb/MMBtu.\257\ At the same time, the amount of higher
sulfur lignite burned in 2016 was higher than in 2020 \258\ (61 to 71
percent of heat input came from lignite in 2016 for the three units
compared to 14 to 32 percent in 2020), meaning that the scrubbers and
amount bypassed were operated in a manner that achieved a significantly
higher overall removal efficiency in 2016 than in 2020. Table 10
summarizes the annual emission rate and the estimated annual scrubber
removal efficiency. Given the variability in demonstrated scrubber
efficiency, higher removal efficiency can be and has been achieved with
optimized operation, reduced bypass, and increased reagent use with the
current configuration of the scrubbers. As discussed earlier in this
section, additional remaining cost-effective physical modifications to
the scrubbers can further improve scrubber removal efficiency. This
further supports our assessment that increased scrubber efficiency is
cost-effective.
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\256\ In 2019 and 2021, a unit at the Gavin Facility in Ohio was
the third highest emitting unit in the country. In 2020, the three
Martin Lake units fell within the top 6 units. See
``Largest_units_SO2_annual emissions 2016-2021.xlsx''
available in the docket for this action.
\257\ See ``Largest_units_SO2_annual emissions 2016-
2021.xlsx'' available in the docket for this action.
\258\ See ``Coal vs CEM data 2016-2020_ML.xlsx'' available in
the docket for this action.
Table 10--Martin Lake Annual Emission Rate and Estimated Annual Scrubber Removal Efficiency
----------------------------------------------------------------------------------------------------------------
Annual emission rate (lb/MMBtu) Estimated overall removal efficiency
-------------------------------------- (%)
Martin Lake -------------------------------------
2016 2020 2016 2020
----------------------------------------------------------------------------------------------------------------
Unit 1.............................. 0.42 0.73 78.2 52.8
Unit 2.............................. 0.30 0.60 84.5 62.8
Unit 3.............................. 0.43 0.55 78.0 62.8
----------------------------------------------------------------------------------------------------------------
The cost of scrubber upgrades at coal-fired power plants has been
evaluated in many other instances in both the context of BART and
reasonable progress for both the first and second planning periods for
regional haze. Based on what we have seen in other regional haze
actions, upgrading an underperforming SO2 scrubber is
generally very cost-effective.\259\ In our TSD, we provide further
discussion of other regional haze actions where scrubber upgrades have
been found to be very cost-effective.
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\259\ See for instance, the North Dakota Regional Haze SIP:
scrubber upgrades for the Milton R. Young Station Unit 2 were
evaluated under BART and were found to cost $522/ton and scrubber
upgrades with coal drying for the Coal Creek Station Units 1 and 2
were evaluated under BART and found to cost $555/ton at each unit.
See the EPA's final action approving the SO2 BART
determinations for the Coal Creek Station Units 1 and 2 and for the
Milton R. Young Station Unit 2 at 77 FR 20894 (April 6, 2012). See
also the Wyoming Regional Haze SIP: scrubber upgrades for Wyodak
Unit 1 were evaluated to address the regional haze rule requirements
under 40 CFR 51.309 and found to cost $1,167/ton. The EPA approved
this portion of the Wyoming Regional Haze SIP at 77 FR 73926
(December 12, 2012).
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In the Texas Regional Haze SIP for the Second Planning Period
recently submitted to us by TCEQ, the State evaluated Martin Lake Units
1, 2, and 3 for controls under the reasonable progress requirements for
the regional haze second planning period.\260\ Specifically, TCEQ
evaluated scrubber upgrades for the Martin Lake units, the same
SO2 control type we have evaluated for those units in this
proposal. In that SIP submittal, TCEQ took an approach in its cost
analysis of scrubber upgrades different from ours in this proposal and
they did not rely on cost information from the facility. As they did
not rely on cost information claimed to be CBI by the facility, TCEQ
was able to present estimated cost-effectiveness numbers for scrubber
upgrades for the Martin Lake units in their SIP submittal. TCEQ
estimated the cost-effectiveness of scrubber upgrades at Martin Lake to
be $907/ton for Unit
[[Page 28953]]
1; $1,040/ton for Unit 2; and $891/ton for Unit 3. Since we have not
completed our review of the Texas Regional Haze SIP for the Second
Planning Period and have not yet proposed action on it, we are not at
this time taking a position on the approvability or appropriateness of
TCEQ's cost analyses and determinations in the Texas Regional Haze SIP
for the Second Planning Period. We merely present TCEQ's cost-
effectiveness estimates here to illustrate that they are comparable to
our own cost-effectiveness estimates in this notice.
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\260\ The Texas Regional Haze SIP for the Second Planning Period
was submitted to the EPA by TCEQ on July 20, 2021. A copy of this
submission is available at https://www.tceq.texas.gov/airquality/sip/bart/haze_sip.html and in the docket for this action.
---------------------------------------------------------------------------
In our cost analysis of scrubber upgrades for the Martin Lake
units, we are using information we received from the facility in
response to our previous CAA Section 114(a) information collection
request. We are limited in what information we can include in this
section because the facility claimed this information as CBI. We can
disclose that we previously used this information claimed as CBI by the
facility to calculate the total annualized costs for the Martin Lake
units in our 2016 Texas-Oklahoma FIP.\261\ We have escalated those
total annualized costs to 2020 dollars and are using this to estimate
the cost-effectiveness of scrubber upgrades at these units. As we
discuss in Section VII.B.2.b, we believe that modifications necessary
to eliminate the bypass could be performed using proven equipment and
techniques to increase the control efficiency of the scrubbers to 95
percent and substantially reduce SO2 emissions at these
units. Our estimates of the baseline emissions and the annual
SO2 emissions reductions anticipated from upgrading the
scrubbers at Martin Lake Units 1, 2, and 3 are presented in Table 11.
Using the anticipated annual SO2 emissions reductions
presented in Table 11, we have estimated the cost-effectiveness of
scrubber upgrades at these units. Because those calculations depended
on cost information claimed by the facility as CBI, we cannot present
them here except to note that for each unit, the cost-effectiveness was
less than $1,200/ton.
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\261\ See generally, 81 FR 296 (Jan 5, 2016).
Table 11--Martin Lake Updated Baseline Emissions and SO2 Emissions Reductions Due to Scrubber Upgrades
----------------------------------------------------------------------------------------------------------------
Annual SO2
2016-2020 avg SO2 emissions at emissions SO2 emission rate
Unit annual emissions 95% control reduction due to at 95% control
(tons) (tons) crubber upgrade (lb/MMBtu)
(tons)
----------------------------------------------------------------------------------------------------------------
Martin Lake 1....................... 14,885 2,047 12,838 0.08
Martin Lake 2....................... 11,909 1,769 10,140 0.08
Martin Lake 3....................... 14,121 1,941 12,180 0.08
---------------------------------------------------------------------------
Total SO2 Removed............... ................. ................. 35,158 .................
----------------------------------------------------------------------------------------------------------------
We recognize that the information we used in our cost analysis on
scrubber upgrades was provided by the facility several years ago and
that our escalation of the total annualized costs from 2013 to 2020
dollars introduces some level of uncertainty in our cost estimates. We
acknowledge that it is reasonable to assume that the cost information
we received from the facility may have changed in the interim, due to
changes in the costs of various materials and services, as well as
possible recent upgrades to the scrubbers that may have already been
implemented at these units that would no longer need to be considered
in our cost analysis. However, based on the information presented in
this subsection, we find that the cost of scrubber upgrades at the
Martin Lake units is so low in terms of dollars per ton reduced such
that even if we had updated cost information, we expect that scrubber
upgrades would continue to be very cost-effective. Accordingly, we
would still propose to require upgrades to these SO2
scrubbers in light of the significant visibility benefits, as discussed
later in our weighing of the factors in Section VIII. Nevertheless, we
invite comment on any additional analysis on the cost of scrubber
upgrades at the Martin Lake units that may have been conducted in the
interim period following Luminant's response to our request for cost
information. We also invite comments regarding documentation on any
upgrades or optimization that may have been made to the scrubbers at
the Martin Lake units in the interim period. Finally, we invite comment
on whether a lower emission limit of 0.04 lb/MMBtu should be required
that would be consistent with 95 percent control efficiency and the
burning of only subbituminous coal.\262\
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\262\ In the Matter of an Agreed order Concerning Luminant
Generation Company, LLC, Martin Lake Steam Electric Station, Docket
No. 2021-0508-MIS includes a requirement to burn only subbituminous
coal.
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The Fayette Units 1 and 2 are currently equipped with high
performing wet FGDs. Both units have demonstrated the ability to
maintain a SO2 30 BOD average below 0.04 lb/MMBtu for years
at a time.\263\ As we discuss in Section VII.B.2, we evaluate BART
demonstrating that retrofit wet FGDs should be evaluated at 98 percent
control not to go below 0.04 lb/MMBtu. Because the Fayette units are
already performing below this level, we propose that no scrubber
upgrades are necessary and there are no additional costs associated
with maintaining the current levels of operation.
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\263\ See our 2023 BART FIP TSD for graphs of this data.
---------------------------------------------------------------------------
c. Impact Analysis Parts 2, 3, and 4: Energy and Non-Air Quality
Environmental Impacts, and Remaining Useful Life
i. Energy and Non-Air Quality Environmental Impacts
Regarding the analysis of energy impacts, the BART Guidelines
advise, ``You should examine the energy requirements of the control
technology and determine whether the use of that technology results in
energy penalties or benefits.'' \264\ The key part of this analysis is
the energy requirements of the ``control technology.'' As such, this
part of the analysis is focused on considering the various energy
impacts of the control technologies identified earlier in the BART
analysis as technologically feasible and determining whether there are
energy penalties or benefits associated that may factor into the
overall decision to select
[[Page 28954]]
a certain control technology over another. Such considerations would
include extra fuel or electricity to power a control device or the
availability of potentially scarce fuels.\265\ As discussed in our 2023
BART FIP TSD, in our cost analyses for DSI, SDA, and wet FGD, our cost
model allows for the inclusion or exclusion of the cost of the
additional auxiliary power required for the pollution controls we
considered to be included in the variable operating costs. We chose to
include this additional auxiliary power in all cases. Consequently, we
believe that any energy impacts of compliance have been adequately
considered in our analyses through the inclusion of related costs of
electricity to operate the controls.
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\264\ 70 FR 39103, 39168 (July 6, 2005), [40 CFR part 51, App.
Y.].
\265\ 70 FR at 39168-69.
---------------------------------------------------------------------------
Neither the CAA nor the BART Guidelines specifically require the
examination of grid reliability considerations because utilities may
shut down or retire a unit rather than comply with a more stringent
emission limit or limits. However, the Guidelines recognize there may
be cases where the installation of controls, even when cost-effective,
would ``affect the viability of continued plant operations.'' \266\
Under the Guidelines, where there are ``unusual circumstances,'' we are
permitted to take into consideration ``the conditions of the plant and
the economic effects of requiring the use of a control technology.''
\267\ If the effects are judged to have a ``severe impact,'' those
effects can be considered in the selection process. In such cases, the
Guidelines counsel that any determinations be made with an economic
analysis with sufficient detail for public review on the ``specific
economic effects, parameters, and reasoning.'' \268\ It is recognized,
by the language of the Guidelines, that any such review process may
entail the use of sensitive business information that may be
confidential.\269\ As suggested by the Guidelines, the information
necessary to inform our judgment with respect to the viability of
continued operations for a source would likely entail source-specific
information on ``product prices, the market share, and the
profitability of the source.'' All of that said, the Guidelines also
advise that we may ``consider whether other competing plants in the
same industry have been required to install BART controls if this
information is available.'' \270\ Because Texas EGUs are among the last
to have SO2 BART determinations, this information is
available. It is indeed the case that other similar EGUs have been
required to install the same types of SO2 BART controls that
we are proposing as cost effective. The emission limits that we propose
for these sources are based on conventional, proven, at-the-source
pollution control technology that is in place across a vast portion of
the existing EGU fleet in the United States.\271\ In general these
pollution controls are cost-effective and can be implemented while the
EGU continues in large part to operate as it had before.
---------------------------------------------------------------------------
\266\ 70 FR 39103, 39171 (July 6, 2005), [40 CFR part 51, App.
Y].
\267\ Id.
\268\ 70 FR at 39171.
\269\ The FOR FURTHER INFORMATION section of this proposal
explains how to submit confidential information with comments, and
when claims of confidential business information, or CBI, are
asserted with respect to any information that is submitted, the EPA
regulations at 40 CFR part 2, subpart B-Confidentiality Business
Information apply to protect it.
\270\ 70 FR at 39171.
\271\ See EIA Reported Desulfurization Systems in 2020 data in
Table 8 of this notice showing the hundreds of scrubber
installations that have been performed on similar EGUs.
---------------------------------------------------------------------------
Should any of the units faced with a final BART emission limit
choose instead to explore retirement, such a decision would presumably
be made on the basis of a determination that the retirement of the unit
would be the more economical choice, taking into account any and all
regulatory requirements impacting the source and market conditions.
Further, the relevant grid operator would follow their planning
requirements to ensure that sufficient reserve capacity is available.
We have also reviewed available information regarding the grids
operating in Texas to provide data on these generation units and
reserve capacity. The Welsh and Harrington facilities operate as part
of the Southwest Power Pool (SPP).\272\ The owners of these facilities
have announced plans to convert to natural gas in the near future so it
is unlikely that these sources would now choose to shut down as a
result of the proposed BART requirements, which could be met by burning
natural gas instead of coal.\273\ The Electric Reliability Council of
Texas (ERCOT) operates Texas's electrical grid which represents 90
percent of the State's electric load. Coleto Creek, Fayette, Martin
Lake, and W. A. Parish facilities produce power for the ERCOT grid. As
discussed elsewhere, we are not proposing to require additional
reductions from the Fayette units due to their high efficiency
scrubbers. For that reason, we do not anticipate any impact to
operations of this source. Further, the owners of Coleto Creek already
have announced their intentions to shut down the unit in 2027,\274\
citing costs imposed by Federal regulations for coal ash disposal and
wastewater treatment, and market pressures. Therefore, we focus the
remainder of this section on the Martin Lake and W. A. Parish BART
units.
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\272\ SPP oversees the bulk electric grid and wholesale power
market in the central United States for utilities and transmission
companies in 17 States.
\273\ See Section VII.B.3.c.ii for more information regarding
Harrington's conversion to natural gas.
\274\ Rosenberg, Mike. ``Coleto Creek Power Plant shutting down
by 2027.'' Victoria Advocate, December 1, 2020, https://www.victoriaadvocate.com/counties/goliad/coleto-creek-power-plant-shutting-down-by-2027/article_261596c8-342b-11eb-92e8-0f9c2d927a2b.html. Last Accessed February 1, 2023.
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One way to evaluate potential changes to the grid is to examine
forecasted peak demand and generation capacity for summer and winter.
These five coal-fired units represent 3,737 MW of summer capacity.\275\
ERCOT's November 2022 Report on the Capacity, Demand and Reserves \276\
estimates that 2023 operational generation capacity for summer peak
demand will be 92,792 MW with additional planned resource capacity
expected for the 2023 summer peak demand of 4,400 MW. This includes
1,254 MW of summer-rated gas-fired resources, and the remainder in
additional wind and solar resources becoming available by next summer.
Summer peak demand is estimated to be 80,218 MW for 2023, resulting in
an estimated reserve margin of 22.2 percent for 2023, with capacity
outpacing demand by approximately 18,000 MW. That reserve margin is
projected to increase to 39.9 percent for summer 2024, as planned
generation increases to almost 21,400 MW, largely reflecting solar
capacity additions for 2024 and increasing total estimated capacity to
115,000 MW. The current minimum target reserve margin established by
ERCOT is 13.75 percent. Projections through 2027 include additional
planned generation for a total estimated capacity of 121,000 MW and an
estimated reserve margin of 40.1 percent in 2027. Projections for 2028
through 2032 hold generation capacity at 2027 levels (no additional
planned capacity) but continue to project increased demand each year
resulting in a
[[Page 28955]]
decreasing reserve margin each year with 2032 estimated at 36.3
percent.
---------------------------------------------------------------------------
\275\ Report on the Capacity, Demand, and Reserves (CDR) in the
ERCOT Region, 2023-2032. November 29, 2022. Available at https://www.ercot.com/files/docs/2022/11/29/CapacityDemandandReservesReport_Nov2022.pdf and in the docket for
this action.
\276\ Report on the Capacity, Demand, and Reserves (CDR) in the
ERCOT Region, 2023-2032. November 29, 2022. Available at https://www.ercot.com/files/docs/2022/11/29/CapacityDemandandReservesReport_Nov2022.pdf and in the docket for
this action.
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ERCOT's November 2022 Report on the Capacity, Demand and Reserves
\277\ estimates that 2023/2024 operational generation capacity for
winter peak demand will be 90,599 MW with additional planned resource
capacity expected for the 2023 summer peak demand of 2,893 MW. This
includes 1,323 MW of winter-rated gas-fired resources, and the
remainder in additional wind and solar resources becoming available by
next winter. Winter peak demand is estimated to be 66,645 MW for 2023/
2024, resulting in an estimated reserve margin of 35.9 percent for
Winter 2023/2024. That reserve margin is projected to increase to 36.2
percent for winter 2024/2025, and then decrease to 28.7 percent for
winter 2027/2028 as projected peak demand increases.
---------------------------------------------------------------------------
\277\ Report on the Capacity, Demand, and Reserves (CDR) in the
ERCOT Region, 2023-2032. November 29, 2022. Available at https://www.ercot.com/files/docs/2022/11/29/CapacityDemandandReservesReport_Nov2022.pdf and in the docket for
this action.
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The SO2 BART emission limits for these EGUs are proposed
to take effect no later than five years from the effective date of a
final rule (Martin Lake's scrubber upgrades would be required within
three years).\278\ Thus, even if all five of these units chose to
retire instead of complying with the BART emission limits, the removal
of 3,737 MW of summer capacity (3,782 MW winter capacity) would
decrease the estimated summer reserve margin to 35.8 percent in 2027
(estimated winter 2027/2028 reserve margin decreases to 23.6 percent).
Even if we also account for the additional 655 MW loss of generation
from Coleto Creek in 2027, the summer reserve margin would be estimated
to be 35.1 percent with estimated summer generating capacity of 116,706
MW, about 30,000 MW more than the projected summer peak demand. The
winter 2027/2028 reserve margin would be 22.7 percent, with generating
capacity about 16,500 MW higher than peak demand when including the
loss of Coleto Creek generation. Further, this level of reserve
generating capacity is already projected to be available without
considering whether the owners or operators of the affected EGUs would
continue to invest and pursue additional replacement generation
projects. Based on this analysis, there will be more than sufficient
existing and planned capacity in the ERCOT grid to provide for
substitute generation and reserve capacity by the time the BART
emission limits would take effect to meet the projected demand.
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\278\ See 76 FR 81729, 81758 (December 28, 2011) and 81 FR
66332, 66416 (September 27, 2016), where we promulgated regional
haze FIPs for Oklahoma and Arkansas, respectively. These FIPs
required BART SO2 emission limits on coal-fired EGUs
based on new scrubber retrofits with a compliance date of no later
than five years from the effective date of the final rule.
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To further evaluate the potential changes to the grid due to
retirements, we also examined ERCOT's December 2017 Report on the
Capacity, Demand and Reserves,\279\ the first report issued after the
announced retirement of 4,273 MW of generating capacity from the
Luminant facilities (Monticello, Big Brown, and Sandow) in early 2018.
Due to the retirements, the reserve margin was projected to decrease to
9.3 percent for summer 2018 and 9.0 percent in summer 2022. In response
to requests from Luminant to retire these units, ERCOT issued
determinations that these resources were not required to support ERCOT
transmission system reliability in early 2018 and allowed to
permanently retire. Additional gas, solar and wind resources have come
online since that time to increase the generation capacity and provide
for a much larger reserve margin. And again, this rule, if finalized,
only establishes an emission limit for each EGU that could be met with
proven, conventional, at the source control technologies already in use
across a broad swath of the U.S. EGU fleet; thus retirements, if they
should occur, are at the discretion of the sources and subject to the
reliability authority and planning requirements that would be overseen
by the grid operator, ERCOT.
---------------------------------------------------------------------------
\279\ Report on the Capacity, Demand, and Reserves (CDR) in the
ERCOT Region, 2018-2027. December 18, 2017. Available at https://www.ercot.com/files/docs/2018/01/03/CapacityDemandandReserveReport-Dec2017.pdf and in the docket for this action.
---------------------------------------------------------------------------
Regarding the analysis of non-air quality environmental impacts,
the BART Guidelines advise: \280\
---------------------------------------------------------------------------
\280\ 70 FR at 39169 (July 6, 2005), [40 CFR part 51, App. Y.].
Such environmental impacts include solid or hazardous waste
generation and discharges of polluted water from a control device.
You should identify any significant or unusual environmental impacts
associated with a control alternative that have the potential to
affect the selection or elimination of a control alternative. Some
control technologies may have potentially significant secondary
environmental impacts. Scrubber effluent, for example, may affect
water quality and land use. Alternatively, water availability may
affect the feasibility and costs of wet scrubbers. Other examples of
secondary environmental impacts could include hazardous waste
discharges, such as spent catalysts or contaminated carbon.
Generally, these types of environmental concerns become important
when sensitive site-specific receptors exist or when the incremental
emissions reductions potential of the more stringent control is only
marginally greater than the next most-effective option. However, the
fact that a control device creates liquid and solid waste that must
be disposed of does not necessarily argue against selection of that
technology as BART, particularly if the control device has been
applied to similar facilities elsewhere and the solid or liquid
waste is similar to those other applications. On the other hand,
where you or the source owner can show that unusual circumstances at
the proposed facility create greater problems than experienced
elsewhere, this may provide a basis for the elimination of that
---------------------------------------------------------------------------
control alternative as BART.
The SO2 control technologies we considered in our
analysis--DSI and scrubbers--are in wide use in the coal-fired
electricity generation industry. Both technologies add spent reagent to
the waste stream already generated by the facilities we analyzed. As
discussed in our cost analyses for DSI and scrubbers, our cost model
includes estimated waste disposal costs in the variable operating
costs. With DSI, when sodium-based sorbents such as trona are captured
in the same particulate control device as the fly ash, the resulting
waste must be landfilled.\281\ We are aware that some facilities may
sell their fly ash, and that the addition of trona may render that fly
ash unsellable. We included the fly ash disposal costs in the variable
operation and maintenance costs for DSI in all cases, but our cost
analysis did not account for any potential lost revenue resulting from
being unable to sell the fly ash. We invite comments on the assumptions
we have made regarding fly ash disposal costs and on any unforeseen
waste disposal costs associated with DSI when using trona or sodium
bicarbonate.
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\281\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2/HCl Control
Cost Development Methodology, Final April 2017, Project 13527-001,
Eastern Research Group, Inc., Prepared by Sargent & Lundy, p.6.
---------------------------------------------------------------------------
Regarding water related impacts, we recognize that wet FGD requires
additional amounts of water as compared to SDA and DSI. Furthermore,
based on recent Effluent Limitation Guidelines (ELG), it is expected
that all future wet FGD installations will require the facility to
incorporate a wastewater treatment facility.\282\ While this cost is
factored into our cost analysis, it also
[[Page 28956]]
highlights water quality concerns associated with the waste stream for
wet FGD as compared to the installation of dry scrubbers and DSI.
Additionally, we are aware of water availability concerns in the area
surrounding the Harrington facility. As such, the Harrington facility
has instituted a water recycling program and obtains some of its water
from the City of Amarillo.\283\ Because of the increased water required
for wet FGD as compared to dry scrubbers and DSI, we limit our
SO2 control analysis for Harrington to DSI and dry
scrubbers. For the other facilities where we consider wet FGD as a
potential control option, we weigh the additional water usage and
wastewater treatment requirements associated with wet FGD in comparison
to other control options.
---------------------------------------------------------------------------
\282\ IPM Model--Updates to Cost and Performance for APC
Technologies, Wet FGD Cost Development Methodology, Final January
2017, Project 13527-001, Eastern Research Group, Inc., Prepared by
Sargent & Lundy, p. 1.
\283\ https://www.powermag.com/xcel-energys-harrington-generating-station-earns-powder-river-basin-coal-users-group-award/.
---------------------------------------------------------------------------
ii. Remaining Useful Life
Regarding the remaining useful life, the BART Guidelines advise:
\284\
---------------------------------------------------------------------------
\284\ 70 FR 39103, 39169, [40 CFR part 51, App. Y].
You may decide to treat the requirement to consider the source's
``remaining useful life'' of the source for BART determinations as
one element of the overall cost analysis. The ``remaining useful
life'' of a source, if it represents a relatively short time period,
may affect the annualized costs of retrofit controls. For example,
the methods for calculating annualized costs in EPA's OAQPS Control
Cost Manual require the use of a specified time period for
amortization that varies based upon the type of control. If the
remaining useful life will clearly exceed this time period, the
remaining useful life has essentially no effect on control costs and
on the BART determination process. Where the remaining useful life
is less than the time period for amortizing costs, you should use
---------------------------------------------------------------------------
this shorter time period in your cost calculations.
We have no reason to conclude that the remaining useful life of any
SO2 control options we are evaluating would be any less than
the thirty years recommended by the Control Cost Manual.\285\ As we
stated in our Oklahoma FIP,\286\ the scrubber vendors indicated that
the lifetime of a scrubber is equal to the lifetime of the boiler,
which might easily be well over 60 years. We identified specific
scrubbers installed between 1975 and 1985 that are still in operation,
such as the scrubbers at Martin Lake. These scrubbers were installed in
the early 1970s, and, while they may be inefficient for a modern
scrubber, they are still operational.
---------------------------------------------------------------------------
\285\ EPA Air Pollution Control Cost Manual, Seventh Edition,
April 2021, Section 5 ``SO2 and Acid Gas Controls,''
Chapter 1 ``Wet and Dry Scrubbers for Acid Gas Control,'' see
Section 1.1.6, p. 1-8, available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution#cost%20manual.
\286\ 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 discussion beginning on page 36.
---------------------------------------------------------------------------
Some of the facilities we have analyzed for BART in this action
have announced plans to retire or refuel to natural gas within the next
several years.\287\ For example, we are aware that Xcel Energy has
signed an Administrative Order with TCEQ to refuel Harrington Units
061B and 062B to natural gas by January 1, 2025.\288\ We discuss this
change in future operating conditions in our weighing of the factors.
However, the BART Guidelines state that in situations where a future
operating parameter will differ from past or current practices, and if
such future operating parameters will have a deciding effect in the
BART determination, then the future operating parameters need to be
made federally enforceable and permanent to consider them in the BART
determination.\289\
---------------------------------------------------------------------------
\287\ We received a November 21, 2016, letter from the source
owner regarding W.A. Parish Units WAP5 & WAP6. The letter available
in the docket, explains the units have natural gas firing
capabilities and expresses interest in obtaining flexibility to
avoid BART or obtaining multiple options for complying with BART. We
are not aware of any more recent commitments to change operations at
these units that would impact our BART analysis at this time.
Rosenberg, Mike. ``Coleto Creek Power Plant shutting down by 2027.''
Victoria Advocate, December 1, 2020, https://www.victoriaadvocate.com/counties/goliad/coleto-creek-power-plant-shutting-down-by-2027/article_261596c8-342b-11eb-92e8-0f9c2d927a2b.html. Last Accessed February 1, 2023. ``SWEPCO to End
Coal Operations at Two Plants, Upgrade a Third''.'' Southwestern
Electric Power Co.'s News Release, November 5, 2020, https://www.swepco.com/company/news/view?releaseID=5847. Last Accessed
February 2, 2023.
\288\ In the Matter of an Agreed Order Concerning Southwestern
Public Service Company, dba Xcel Energy, Harrington Station Power
Plant, TCEQ Docket No. 2020-0982-MIS (Adopted Oct. 21, 2020). A copy
of the Order is available in the docket for this action.
\289\ 70 FR at 39167.
---------------------------------------------------------------------------
If a facility owner were to enter into a federally enforceable
commitment to shut down or refuel by a date certain, that date would be
used to revise the remaining useful life and the annualized costs
weighed in making the BART determination. Whether that adjustment in
analysis would ultimately alter our final BART determinations from this
proposal would depend on the outcome of an updated BART analysis with
the inclusion of the shutdown or refuel date. Should an owner decide to
shut down or refuel a unit before the compliance date set out for the
proposed BART controls, the shutdown or refueling to natural gas would
also achieve the required SO2 emission limits.
4. Step 5: Evaluate Visibility Impacts
The 2023 BART Modeling TSD describes in detail the modeling runs we
conducted, our methodology and selection of emission rates, modeling
results, and final modeling analyses that we used to evaluate the
benefits of the proposed controls and their associated emission
decreases on visibility impairment values. In this section, we present
a summary of our analyses and our proposed findings regarding the
estimated visibility benefits of emission reductions based on the
CALPUFF and/or CAMx modeling results. For those sources that are within
450 km of a Class I area (Martin Lake, Harrington, and Welsh), we
utilized both CALPUFF and CAMx modeling results to assess the
visibility benefits of potential controls. For the remaining coal-fired
sources (Coleto Creek, Fayette, and W. A. Parish), only CAMx modeling
was utilized, as these sources are located at greater distances from
the nearest Class I areas than typically modeled with the CALPUFF model
for BART analyses. The CAMx modeling provides unit specific impacts and
also total facility impacts where the CALPUFF modeling was performed
such that only total facility impacts were generated. Therefore, we do
not have unit specific CALPUFF results. Additional details regarding
our approach to using CAMx and CALPUFF modeling are within Section
VII.A.1 and the 2023 BART Modeling TSD.
To assess the visibility benefits of controls, we modeled the
sources with emissions reflecting a low control level and a high
control level.290 291 For the low control level, we
evaluated the visibility benefits of DSI for all the subject to BART
units at each facility identified in Tables 12 and 13 that currently
have no SO2 control. For these low control levels, we
modeled these units at a DSI SO2 control level of 50
percent, which we believe is achievable for any unit. At this assumed
control
[[Page 28957]]
level, we expect that the corresponding visibility benefits from DSI in
most cases would be close to half of the benefits from scrubbers, which
are generally at a control level of 90 percent or greater from the
baseline. For the high control level, we evaluated the visibility
benefits for scrubber retrofits (wet FGD or SDA) for these same units,
assuming the same control levels corresponding to SDA (for Harrington
BART units) and wet FGD (for all other unscrubbed BART units) that we
used in our control cost analyses. NOX and PM10
and PM2.5 emissions were held constant for the control case.
---------------------------------------------------------------------------
\290\ As discussed in Section VIII.A and in the 2023 BART
Modeling TSD, we completed some additional CALPUFF modeling for
Welsh and Harrington units in addition to the low and high control
scenarios. We also extrapolated CAMx results to estimate visibility
benefits for SDA for units at Coleto Creek, W.A. Parish, and Welsh,
and extrapolated CAMx results for Harrington Unit 61B for additional
levels of control. See the 2023 BART Modeling TSD for discussion of
all modeled and extrapolated visibility modeling.
\291\ NOX and PM10/PM2.5
emissions were held constant at baseline emission levels for all
emission units in order to isolate visibility improvements due to
SO2 reductions from any visibility benefits that would
result from reductions in NOX emissions.
---------------------------------------------------------------------------
We also modeled the visibility benefits of improved efficiency on
the existing scrubbers at Martin Lake. We assumed the same 95 percent
control level represented by an emission limit of 0.08 lb/MMBtu used in
our control cost analyses for the high control level. We also modeled a
lower control level based on an emission rate of 0.32 lb/MMBtu. This
emission rate is consistent with the limit included in an Agreed Order
\292\ between TCEQ and Luminant for purposes of addressing
SO2 NAAQS nonattainment requirements.\293\
---------------------------------------------------------------------------
\292\ Agreed Order 2021-0508-MIS, signed February 22, 2022,
available in the docket for this action.
\293\ The agreed order and accompanying SIP submittal remain
before the EPA for review. In this action we are not taking a
position on the approvability or appropriateness of the limits in
the agreed order for purposes of addressing SO2 NAAQS
nonattainment requirements.
---------------------------------------------------------------------------
As discussed in Section VII.B.1.b, Fayette Units 1 and 2 have
scrubbers that are operating consistently at a high control level.
Accordingly, we modeled both units at an emission rate of 0.04 lb/MMBtu
for the high control level, which is consistent with emission rates
from the past several years. For the low control scenario, we evaluated
the visibility impacts at the current permitted emission rates, which
is higher than the current actual emissions. These model runs do not
correspond to ``low control'' and ``high control'' specifically. We
discuss the model results for Fayette further in Section VIII.B. As
discussed elsewhere, we found that for these units no additional
controls or upgrades were necessary.
Tables 12 and 13 present a summary of the modeled visibility
impacts for the baseline at the Class I areas most impacted by each
source, and the visibility benefits from the low and high control
scenarios, as predicted by CAMx \294\ and CALPUFF. In evaluating the
impacts and benefits of control options, we utilized a number of
metrics, including change in deciviews on the maximum impacted day for
CAMx results and annual 98th percentile for CALPUFF results, and also
number of days impacted over 0.5 dv and 1.0 dv. In Section VIII, we
provide some additional discussion of model results and additional
metrics in weighing the visibility benefits of controls. Consistent
with the BART Guidelines, the visibility impacts and benefits modeled
in CALPUFF and CAMx are calculated as the change in deciviews compared
against natural visibility conditions.\295\ For a more detailed
discussion of our review of all the modeling results and factors that
we considered in evaluating and weighing results, including scrubber
upgrades, see our 2023 BART FIP TSD and 2023 BART Modeling TSD.
---------------------------------------------------------------------------
\294\ For the CAMx modeling, visibility was assessed using the
grid cell containing the monitor representative of the Class I area.
In 2016, Carlsbad Caverns shared a monitor with the Guadalupe
Mountains and Pecos Wilderness shared a monitor with Wheeler Peak.
Therefore, the modeled impacts and benefits at these receptors/
monitors were applied to both Class I areas represented by that
monitor site.
\295\ 40 CFR 51 Appendix Y, IV.D.5: ``Calculate the model
results for each receptor as the change in deciviews compared
against natural visibility conditions.'' For the specific
calculations, see 2023 BART Modeling TSD for this action.
[[Page 28958]]
Table 12--CAMx Modeling of Baseline Impacts and Visibility Benefits of Controls for Subject-to-BART Sources
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2016 Baseline impacts Low control scenario High control scenario
-----------------------------------------------------------------------------------------------------------------------------------------------
BART source & top 3 Class I areas Impact at Benefit at Number of days Number of days Benefit at Number of days Number of days
class I area Number of days Number of days class I area impacted >=0.5 impacted >=1.0 class I area impacted >=0.5 impacted>=1.0
(dv) >=0.5 dv >=1.0 dv (dv) dv dv (dv) dv dv
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Martin Lake, Units 1, 2, and 3 (0.32 lb/MMBtu)
(0.08 lb/MMBtu)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek................................. 6.69 150 101 3.28 97 46 5.00 32 7
Wichita Mountains........................... 5.49 51 27 2.87 21 7 4.57 3 0
Upper Buffalo............................... 5.16 111 70 2.78 61 25 4.39 7 0
Cumulative (all 15 Class I areas)........... 33.79 521 301 18.29 259 91 27.91 47 7
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
W.A. Parish, Units WAP4, WAP5, and WAP6 (DSI @50%)
(wet FGD @0.04 lb/MMBtu)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Wichita Mountains........................... 3.97 35 12 1.73 15 1 3.61 0 0
Caney Creek................................. 3.13 86 38 1.31 48 11 2.59 1 0
Breton...................................... 2.21 12 4 0.85 4 2 1.89 0 0
Cumulative (all 15 Class I areas)........... 17.96 269 91 7.76 119 18 15.66 1 0
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington Station, Units 061B and 062B (DSI @50%)
(SDA @0.06 lb/MMBtu)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
White Mountain.............................. 2.64 8 3 0.96 4 1 1.78 1 0
Bandelier................................... 1.60 4 1 0.65 1 0 1.23 0 0
Salt Creek.................................. 1.52 13 6 0.49 7 1 0.97 1 0
Cumulative (all 15 Class I areas)........... 12.77 44 10 5.01 13 2 9.08 2 0
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Coleto Creek, Unit 1 (DSI @50%)
(wet FGD @0.04 lb/MMBtu)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek................................. 1.55 18 2 0.67 2 0 1.38 0 0
Breton...................................... 1.19 4 1 0.50 1 0 1.08 0 0
Wichita Mountains........................... 1.13 23 3 0.54 4 0 1.00 0 0
Cumulative (all 15 Class I areas)........... 8.54 69 6 3.92 9 0 7.75 0 0
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Welsh, Unit 1 (DSI @50%)
(wet FGD @0.04 lb/MMBtu)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek................................. 1.58 27 6 0.48 8 1 1.08 0 0
Wichita Mountains........................... 1.54 6 2 0.69 2 0 1.34 0 0
Upper Buffalo............................... 1.12 8 1 0.40 2 0 0.83 0 0
Cumulative (all 15 Class I areas)........... 6.67 46 9 2.60 13 1 5.27 0 0
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 28959]]
To further illustrate the CAMx modeled visibility benefits provided
by both the low and high control levels, we compared the visibility
benefits of the low and high control levels to the baseline impacts in
terms of percent reduction in visibility impacts. To make this
comparison, we used the maximum impact for each Class I area and
compared these values for the low control and high control with the
baseline impacts, looking at the values for the highest impacted Class
I area and the average of the 15 Class I areas from the baseline
modeling to show the benefit for the control levels. For Martin Lake,
low and high control resulted in a reduction of visibility impacts at
Caney Creek by 49 percent and 75 percent, respectively, and an average
reduction of visibility impacts at the 15 Class I areas of 54 percent
and 83 percent, respectively. For W.A. Parish, low and high control
resulted in a reduction of visibility impacts at Wichita Mountains by
44 percent and 91 percent, respectively, and an average reduction of
visibility impacts at the 15 Class I areas of 43 percent and 87
percent, respectively. For Harrington, low and high control resulted in
a reduction of visibility impacts by 36 percent and 67 percent,
respectively, and an average reduction of visibility impacts at the 15
Class I areas of 39 percent and 71 percent, respectively. For Coleto
Creek, low and high control resulted in a reduction of visibility
impacts by at Caney Creek 43 percent and 89 percent, respectively, and
an average reduction of visibility impacts at the 15 Class I areas of
46 percent and 91 percent, respectively. For Welsh, low and high
control resulted in a reduction of visibility impacts at Caney Creek by
30 percent and 68 percent, respectively, and an average reduction of
visibility impacts at the 15 Class I areas of 39 percent and 79
percent, respectively. For Fayette, high control resulted in a
reduction of visibility impacts at Caney Creek by 0 percent and an
average reduction of visibility impacts at the 15 Class I areas of 5
percent. We provide additional analysis of the visibility benefits of
the different control levels in Section VIII and in the 2023 BART FIP
TSD and 2023 BART Modeling TSD.
For each of the facilities, CAMx predicted a large decrease in the
number of days with visibility impacts greater than 0.5 dv with the
high level of controls. Aside from impacts on the Caney Creek Class I
area, CAMx predicted zero days over 1.0 dv with the high level of
controls on the Martin Lake facility. Additional unit-specific
information for these sources can be found in the 2023 BART Modeling
TSD.
[[Page 28960]]
Table 13--CALPUFF Modeling Baseline Impact and Visibility Benefit of Controls for Subject-to-BART Sources *
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
2016-18 Baseline Low control scenario High control scenario
-----------------------------------------------------------------------------------------------------------------------------------------------------------
Cumulative Benefit at class I area (dv) Cumulative Benefit at class I area (dv) Cumulative
2016-18 # --------------------------------------- 2016-18 # --------------------------------------- 2016-18 #
BART source & class I area of days of days of days
2016 dv 2017 dv 2018 dv with with with
impacts 2016 dv 2017 dv 2018 dv impacts 2016 dv 2017 dv 2018 dv impacts
>=0.5 dv/ >=0.5 dv/ >=0.5 dv/
>=1.0 dv >=1.0 dv >=1.0 dv
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Martin Lake, Units 1, 2, and 3 (0.32 lb/MMBtu)
(0.08 lb/MMBtu)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..................... 3.28 3.60 3.35 338/215 1.62 1.78 1.75 222/95 2.12 2.36 2.16 133/44
Upper Buffalo................... 2.12 2.54 2.27 212/115 1.12 1.39 1.10 100/29 1.58 1.90 1.72 33/8
Wichita Mountains............... 1.45 1.07 1.15 79/36 0.80 0.58 0.65 25/4 1.21 0.89 0.91 5/2
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Welsh, Unit 1 (DSI @50%)
(wet FGD @0.04 lb/MMBtu)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek..................... 0.70 0.94 0.96 77/13 0.17 0.30 0.32 41/3 0.28 0.37 0.53 18/1
Upper Buffalo................... 0.36 0.49 0.60 16/0 0.14 0.17 0.22 3/0 0.25 0.33 0.42 0/0
Wichita Mountains............... 0.25 0.35 0.24 3/0 0.09 0.17 0.08 1/0 0.17 0.28 0.16 0/0
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington Station, Units 061B and 062B (DSI @50%)
(SDA @0.06 lb/MMBtu)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Carlsbad Caverns................ 0.39 0.41 0.56 16/5 0.12 0.16 0.15 7/1 0.24 0.27 0.31 1/1
Bandelier....................... 0.17 0.12 0.14 2/0 0.06 0.04 0.05 0/0 0.12 0.09 0.11 0/0
Pecos........................... 0.22 0.28 0.24 9/0 0.08 0.09 0.09 3/0 0.15 0.17 0.16 0/0
Salt Creek...................... 0.49 0.59 0.54 27/3 0.13 0.22 0.19 14/1 0.23 0.39 0.32 2/0
Wheeler Peak.................... 0.12 0.15 0.16 2/0 0.03 0.05 0.06 0/0 0.07 0.10 0.11 0/0
White Mountain.................. 0.26 0.43 0.33 7/0 0.09 0.15 0.13 1/0 0.17 0.26 0.24 0/0
Wichita Mountains............... 0.54 0.45 0.58 24/8 0.19 0.16 0.18 12/0 0.35 0.23 0.33 3/0
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
* Benefit of control values are the decrease in deciview between baseline and the control scenario. Number of days is the number of days that are equal or greater than 0.5 and 1.0 dv after
controls.
[[Page 28961]]
As discussed in prior sections, when using CALPUFF, the visibility
benefit (dv) is derived from the 98th percentile (eighth highest day
for each year) for each Class I area. We provide additional analysis of
the benefits of the different control levels in Section VIII and in the
2023 BART FIP TSD and 2023 BART Modeling TSD. As shown in Table 13,
CALPUFF predicted large reductions in the number of days over the 1.0
dv threshold under the high control level for all three facilities. For
Harrington, CALPUFF results predicted one day with visibility impacts
over 1.0 dv compared to baseline impacts of 16 days. For Welsh, CALPUFF
results predicted only one day over 1.0 dv compared to baseline impacts
of 16 days. For Martin Lake, CALPUFF results predicted 54 days over 1.0
dv compared to baseline impacts of 366 days.
To further illustrate the CALPUFF modeled visibility benefits
provided by both the low and high control levels, we also compared the
visibility benefits of the low and high control levels to the baseline
impacts in terms of percent reduction in visibility impacts as we did
in analyzing CAMx benefits. To make this comparison, we first
calculated the average of the 98th percentile for the three years
modeled for each Class I area. We then compared these values for the
low control and high control with the baseline impacts, looking at the
values for the highest impacted Class I area and the average of the
Class I areas from the baseline modeling to show the benefit for the
control levels. For Harrington, Salt Creek was the highest impacted of
the seven Class I areas and low and high control resulted in a
reduction of visibility impacts by 33 percent and 58 percent,
respectively, and an average reduction of visibility impacts at the
seven Class I areas of 34 percent and 61 percent, respectively. For
Martin Lake, Caney Creek was the highest impacted of the three Class I
areas and low and high control resulted in a reduction of visibility
impacts by 50 percent and 65 percent, respectively, and an average
reduction of visibility impacts at the three Class I areas of 52
percent and 71 percent, respectively. For Welsh, Caney Creek was the
highest impacted of the three Class I areas and low and high control
resulted in a reduction of visibility impacts by 30 percent and 45
percent, respectively and an average reduction of visibility impacts at
the three Class I areas of 34 percent and 57 percent, respectively. As
further discussed in the 2023 BART Modeling TSD, CALPUFF model results
are not directly comparable to CAMx results due to difference in the
modeling analysis as discussed elsewhere (years modeled, receptor(s)
modeled, etc.) and difference in the model including the simplified
chemistry in CALPUFF. The potential to overestimate nitrate impacts in
the CALPUFF model may limit (resulting in an underestimation) the
amount of modeled visibility benefits (improvement) on both the 98th
percentile days and the number of days above a threshold that result
from decreases in SO2 emissions.
5. BART Five Factor Analysis for PM
In our 2017 Texas BART FIP, we approved Texas's determination in
its 2009 Regional Haze SIP that no PM BART controls were appropriate
for its EGUs, based on a screening analysis of the visibility impacts
from just PM emissions and the premise that EGU SO2
emissions were covered by the Texas SO2 Trading Program and
NOX emissions were covered by participation in CSAPR
(allowing consideration of PM emissions in isolation). For reasons
provided for in Section VI, we are now proposing that our approval was
in error and are correcting that error by disapproving the portion of
the SIP regarding PM BART for EGUs. Based on this proposed disapproval,
the FIP we are proposing to address BART requirements for those Texas
EGUs that are subject to BART will cover PM BART.
The BART Guidelines permit us to conduct a streamlined analysis of
PM BART for PM sources subject to MACT standards. Unless there are new
technologies subsequent to the MACT standards which would lead to cost-
effective increases in the level of control, the Guidelines state it is
permissible to rely on MACT standards for purposes of BART.\296\ With
this background, we are providing our evaluation, along with some
supplementary information, on the BART sources as divided into two
categories: coal-fired EGUs and gas-fired EGUs.
---------------------------------------------------------------------------
\296\ 70 FR at 39163-64.
---------------------------------------------------------------------------
BART Analysis for PM for Coal-Fired Units
All coal-fired EGUs that are subject to BART are currently equipped
with either Electrostatic Precipitators (ESPs) or baghouses, or both,
as illustrated in Table 14:
Table 14--Current PM Controls for Coal-Fired Units Subject to BART \297\
----------------------------------------------------------------------------------------------------------------
Facility name Unit ID Fuel type (primary) SO2 control(s) PM control(s)
----------------------------------------------------------------------------------------------------------------
Coleto Creek..................... 1 Coal............... ................... Baghouse.
Harrington Station............... 061B Coal............... ................... Electrostatic
Precipitator.
Harrington Station............... 062B Coal............... ................... Baghouse.
Martin Lake...................... 1 Coal............... Wet Limestone...... Electrostatic
Precipitator.
Martin Lake...................... 2 Coal............... Wet Limestone...... Electrostatic
Precipitator.
Martin Lake...................... 3 Coal............... Wet Limestone...... Electrostatic
Precipitator.
Fayette.......................... 1 Coal............... Wet Limestone...... Electrostatic
Precipitator.
Fayette.......................... 2 Coal............... Wet Limestone...... Electrostatic
Precipitator.
W. A. Parish..................... WAP5 Coal............... ................... Baghouse.
W. A. Parish..................... WAP6 Coal............... ................... Baghouse.
Welsh Power Plant................ 1 Coal............... ................... Baghouse (Began Nov 15,
2015) + Electrostatic
Precipitator.
----------------------------------------------------------------------------------------------------------------
We began our analysis by examining the control efficiencies of both
baghouses and ESPs. When considering the units controlled by a
baghouse, they were widely reported to be capable of achieving 99.9
percent control of PM, which is the maximum level of control for PM.
Therefore, the units equipped with a baghouse will not be further
analyzed for PM BART. The remaining units are fitted with ESPs.
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\297\ www.eia.gov/electricity/data/eia860/.
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The particulate matter control efficiency of ESPs varies somewhat
with design, resistivity of the particulate
[[Page 28962]]
matter, and maintenance of the ESP. We do not have information
specifically on the control level efficiency of any of the ESPs for the
units in question. However, reported control efficiencies for well-
maintained ESPs typically range from greater than 99 percent to 99.9
percent.\298\ We therefore consider this pertinent when concluding that
the potential additional particulate control that a baghouse can offer
over an ESP is relatively minimal.\299\ Accordingly, even if we did
obtain additional control information specific to the ESP units in
question, we do not expect the additional information would result in a
different conclusion.
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\298\ EPA, ``Air Pollution Control Technology Fact Sheet: Dry
Electrostatic Precipitator (ESP)--Wire Plate Type,'' EPA-452/F-03-
028. Grieco, G., ``Particulate Matter Control for Coal-fired
Generating Units: Separating Perception from Fact,'' apcmag.net,
February, 2012. Moretti, A.L.; Jones, C.S., ``Advanced Emissions
Control Technologies for Coal-Fired Power Plants, Babcox and Wilcox
Technical Paper BR-1886, Presented at Power-Gen Asia, Bangkok,
Thailand, October 3-5, 2012.
\299\ We do not discount the potential health benefits this
additional control can have for ambient PM. However, the regional
haze program is only concerned with improving the visibility at
Class I areas.
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Nevertheless, we will examine the potential cost of retrofitting a
typical 500 MW coal- fired unit with a baghouse. Using our baghouse
cost algorithms as employed in version 6 of our IPM model,\300\ and
assuming a conservative air to cloth ratio of 6.0, the results for
capital engineering and construction costs are $84,770,000.\301\ For
the purposes of analyzing the subject units, this cost assumes a
retrofit factor of 1.0, and does not consider the demolition of the
existing ESP, should it be required in order to make space for the
baghouse.
---------------------------------------------------------------------------
\300\ IPM Model--Updates to Cost and Performance for APC
Technologies, Particulate Control Cost Development Methodology,
Final April 2017, Project 13527-001, Eastern Research Group, Inc.,
Prepared by Sargent & Lundy. Documentation for v.6: Chapter 5:
Emission Control Technologies, Attachment 5-7: PM Cost Methodology,
downloaded from: https://www.epa.gov/sites/default/files/2018-05/documents/attachment_5-7_pm_control_cost_development_methodology.pdf.
\301\ Id. See page 11.
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We did not calculate the cost-effectiveness resulting from
replacing an ESP with a baghouse because we expect that the tons of
additional PM removed by a baghouse over an ESP to be very small, which
would result in a very high cost-effectiveness figure. For this reason,
we did not model the visibility benefit of replacing an ESP with a
baghouse. As noted previously, our visibility impact modeling indicates
that the contributions to visibility impairment from the baseline PM
emissions of these units are very small, and thus we expect the
visibility improvement from replacing an ESP with a baghouse to be
minimal. For instance, our CAMx baseline modeling shows that on a
source-wide level, impacts from PM emissions on the maximum impacted
days was at most 7 percent in the case of Fayette, a few were near 1
percent, and others were less than 1 percent of the total visibility
impairment, as calculated as the percent of total extinction due to the
source(s) at each subject to BART facility. Similarly, our CALPUFF
modeling indicates that visibility impairment from PM is also a small
fraction (at most 3 percent for Harrington) of the total visibility
impairment due to each source. Therefore, additional PM controls are
anticipated to result in very little visibility benefit on the maximum
impacted days.
Accordingly, we believe an appropriately stringent PM BART control
level that would be met with existing, or otherwise-required, controls
is a filterable PM limit of 0.030 lb/MMBtu for each of the coal-fired
units subject to BART. This limit is consistent with the Mercury and
Air Toxics (MATS) Rule, which establishes an emission standard of 0.030
lb/MMBtu filterable PM (as a surrogate for toxic non-mercury metals) as
representing Maximum Achievable Control Technology (MACT) for coal-
fired EGUs.\302\ This standard derives from the average emission
limitation achieved by the best performing 12 percent of existing coal-
fired EGUs, as based upon test data used in developing the MATS Rule.
Thus, consistent with the BART Guidelines, we are proposing to rely on
this limit for purposes of PM BART for all of the coal-fired units as
part of our FIP.\303\ We understand the coal-fired units covered by
this proposal to be subject to MATS, but to the extent the units may be
following alternate limits that differ from the surrogate PM limits
found in MATS, we welcome comments on different, appropriately
stringent limits reflective of current control capabilities.\304\
Because we anticipate any limit we assign should be achieved by current
control capabilities, we propose that compliance can be met at the
effective date of the rule. To address periods of startups and
shutdowns, we are further proposing that PM BART for these units will
additionally be met by following the work practice standards specified
in 40 CFR part 63, subpart UUUUU, Table 3, and using the relevant
definitions in 63.10042. We are proposing that the demonstration of
compliance can be satisfied by the methods for demonstrating compliance
with filterable PM limits that are specified in 40 CFR part 63, subpart
UUUUU, Table 7. However, we invite comment on alternate or additional
methods of demonstrating compliance.
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\302\ 77 FR 9304, 9450, 9458 (February 16, 2012) (codified at 40
CFR 60.42 Da(a), 60.50 Da(b)(1)); 40 CFR part 63 Subpart UUUUU--
National Emission Standards for Hazardous Air Pollutants: Coal- and
Oil-Fired Electric Utility Steam Generating Units.
\303\ 70 FR at 39163-64.
\304\ The various limits are provided at 40 CFR part 63, subpart
UUUUU, Table 2 (``Emission Limits for Existing EGUs'').
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BART Analysis for PM for Gas-Fired Units
As explained in Section VII.A, W. A. Parish Unit WAP4 is the only
gas fired unit that we are proposing to find subject to BART. With
respect to gas-fired units, which have inherently low emissions of PM
(as well as SO2),\305\ the RHR did not specifically envision
new or additional controls or emissions reductions from the PM BART
requirement.\306\ The BART Guidelines preclude us from stating that PM
emissions are de minimis when plant-wide emissions exceed 15 tons per
years.\307\ In assigning a PM BART determination to the W. A. Parish
Unit WAP4, there are no practical add-on controls to consider for
setting a more stringent PM BART emission limit than what is already
required of the unit, and therefore, the status quo reflects the most
stringent controls. The Guidelines state that if the most stringent
controls are made federally enforceable for BART, then the otherwise
required analyses leading up to the BART determination can be
skipped.\308\ Thus, we are proposing that PM BART for W. A. Parish Unit
WAP4 is to limit fuel to pipeline natural gas, as defined at 40 CFR
72.2.
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\305\ AP 42, Fifth Edition, Volume 1, Chapter 1: External
Sources, Section 1.4, Natural Gas Combustion, available here:
https://www3.epa.gov/ttn/chief/ap42/ch01/final/c01s04.pdf.
\306\ See 70 FR at 39165.
\307\ 70 FR at 39116-17.
\308\ 70 FR at 39165 (``. . . you may skip the remaining
analyses in this section, including the visibility analysis . .
.'').
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VIII. Weighing of the Five BART Factors and Proposed BART
Determinations
In this section, we present our reasoning for our proposed BART
determinations for 12 EGUs in Texas, based on our analysis and weighing
of the five statutory BART factors for the following unit types: (1)
proposed SO2 and PM BART determinations for 6 coal-fired
units with no SO2 controls, and (2) proposed SO2
and PM BART determinations for 5 coal-fired units
[[Page 28963]]
with existing scrubbers, and (3) proposed SO2 and PM BART
determination for the gas-fired unit (W. A. Parish Unit WAP4).
In previous sections of this proposal, we have described how we
assessed the five BART factors. We will now discuss how we weigh these
factors in our BART determinations. As a general matter, cost
effectiveness and visibility benefits are the driving factors for most
of our BART determinations. However, site specific considerations can
impact the evaluation of control options and establishing an
appropriate BART limit. As defined in the BART Guidelines, ``BART means
an emission limitation based on the degree of reduction achievable
through the application of the best system of continuous emission
reduction for each pollutant which is emitted by . . . [a BART-eligible
source].'' Through this process, we will establish emission limits that
represent a system of continuous emission reduction for specific
pollutants based on consideration of the technology available, the
costs of compliance, the energy and non-air quality environmental
impacts of compliance, any pollution control equipment in use or in
existence at the source, the remaining useful life of the source, and
the degree of improvement in visibility which may reasonably be
anticipated to result from the use of such technology.
In considering cost-effectiveness and visibility benefit, we do not
eliminate any controls based solely on the magnitude of the cost-
effectiveness value, nor do we use cost-effectiveness as the primary
determining factor. Rather, we compare the cost-effectiveness to the
anticipated visibility benefit, and we take note of any additional
considerations. Also, in judging the visibility benefit we do not
simply examine the highest value for a given Class I area, or a group
of Class I areas, but we also consider the cumulative visibility
benefit for all affected Class I areas, the number of days in a
calendar year in which we see significant improvements, and other
factors.\309\ We consider visibility improvement in a holistic manner,
taking into account all reasonably anticipated improvements in
visibility expected to result at all impacted Class I areas. As
explained in Section VII.A, and in accordance with the BART Guidelines,
a source with a modeled 0.5 dv impact at a single Class I area
``contributes'' to visibility impairment and must be analyzed for BART
controls. Controlling individual units to reduce emissions of a
visibility impairing pollutant, such as SO2, at such a
source will address only a fraction of the total visibility impairment
and will not result in perceptible improvements (~1 dv improvement) or
visibility improvements greater than 0.5 dv. However, when considered
in the aggregate, small improvements from controls on multiple sources
will lead to visibility progress.
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\309\ See 70 FR at 39130: ``comparison thresholds can be used in
a number of ways in evaluating visibility improvement (e.g., the
number of days or hours that the threshold was exceeded, a single
threshold for determining whether a change in impacts is
significant, a threshold representing an x percent change in
improvement, etc.).''
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The visibility benefits and cost-effectiveness of all of the
controls that form the basis of our proposed BART determinations are
within a range found to be acceptable in other BART actions nationwide,
with the exception of SDA on Harrington Unit 061B which is discussed in
further detail in Section VIII.A.2.a.\310\ As we stated in the BART
Rule, a reasonable range would be a range that is consistent with cost
effectiveness values used in other similar decisions over a period of
time.\311\ We looked at past BART actions to assess the upper range of
cost effectiveness values that have previously been found to be
acceptable. In past BART decisions, several controls were required by
either EPA or States as BART with average cost-effectiveness values in
the $4,200 to $5,100/ton range (escalated to 2020 dollars) and
visibility benefits of 0.26 to 0.83 dv. For instance, the EPA
promulgated a FIP for Arkansas where we made the determination that
SO2 BART for Flint Creek Unit 1 is an SO2
emission limit based on dry scrubbers at a cost of $3,845/ton, which is
$4,232/ton escalated to 2020 dollars using the CEPCI, and estimated to
result in visibility benefit of 0.615 dv at the Class I area with the
greatest visibility benefit.312 313 The EPA also promulgated
a FIP for Wyoming where we made the determination that NOX
BART for Laramie River Units 1, 2, and 3 is a NOX emission
limit based on LNB with SOFA and Selective Catalytic Reduction (SCR) at
a cost per unit ranging from $4,375 to $4,461/ton, which is $4,599 to
$4,689/ton escalated to 2020 dollars, and estimated to result in
visibility benefit ranging from 0.52 to 0.57 dv per unit at the Class I
area with the greatest visibility benefit.314 315 In that
Wyoming Regional Haze FIP, we explained the following:
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\310\ See for instance 77 FR 18070 (March 26, 2012): the EPA
proposed approval of Colorado's NOX BART determination of
SCR for Hayden Unit 2, later finalized at 77 FR 76871 (December 31,
2012). The estimated cost of SCR at Hayden Unit 2 is $4,064/ton
($4,211/ton when escalated from 2008 dollars to 2020 dollars) and
anticipated to result in visibility benefit of 0.85 dv at the Class
I area with greatest visibility benefit. We escalated this cost-
effectiveness value using the following equation: Cost-effectiveness
escalated to 2020 dollars = Cost-effectiveness in 2008 dollars x
(2020 CEPCI/2008 CEPCI).
\311\ 70 FR at 39168 (July 6, 2005).
\312\ See the EPA's proposed Arkansas Regional Haze FIP at 80 FR
18944 (April 8, 2015), later finalized at 81 FR 66332 (September 27,
2016). The Arkansas Regional Haze FIP was later replaced with a SIP
revision submitted by Arkansas that included the same SO2
BART determination for Flint Creek Unit 1. See the EPA's approval of
Arkansas Regional Haze SIP Revision at 84 FR 51033 (September 27,
2019).
\313\ The year basis for the EPA's cost-effectiveness
calculation is 2016. We escalated the cost-effectiveness value from
2016 dollars to 2020 dollars using CEPCI and the following equation:
Cost-effectiveness escalated to 2020 dollars = Cost-effectiveness in
2016 dollars x (2020 CEPCI/2016 CEPCI); 2016 CEPCI = 541.7, 2020
CEPCI = 596.2.
\314\ See the EPA's Wyoming Regional Haze FIP at 79 FR 5032
(January 30, 2014).
\315\ The year basis for the EPA's cost-effectiveness
calculations is 2013. We escalated the cost-effectiveness value from
2013 dollars to 2020 dollars using the CEPCI and the following
equation: Cost-effectiveness escalated to 2020 dollars = Cost-
effectiveness in 2013 dollars x (2020 CEPCI/2013 CEPCI); 2013 CEPCI
= 567.2, 2020 CEPCI = 596.2.
In regards to the costs of compliance, we found that the revised
average and incremental cost-effectiveness of LNB/SOFA + SCR is in
line with what we have found to be acceptable in our other FIPs. The
average cost-effectiveness per unit ranges from $4,375 to $4,461/
ton, while the incremental cost-effectiveness ranges from $5,449 to
$5,871/ton. We believe that these costs are reasonable, especially
in light of the significant visibility improvement associated with
LNB/SOFA + SCR. As a result, we are finalizing our proposed
disapproval of the State's NOX BART determination for
Laramie River Station and finalizing our proposed FIP that includes
a NOX BART determination of LNB/SOFA + SCR, with an
emission limit of 0.07 lb/MMBtu (30-day rolling average).\316\
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\316\ See 79 FR at 5047-48.
In addition, the EPA approved several BART SIP decisions that
required controls with similar cost-effectiveness values. For example,
the EPA approved Colorado's determination that NOX BART for
the Colorado Energy Nations Company Unit 5 is a NOX emission
limit based on Low NOX burners (LNB) with Separated Overfire
Air (SOFA) and Selective Non-Catalytic Reduction (SNCR) at a cost of
$4,918/ton, which is $5,096/ton escalated to 2020 dollars, and
estimated to result in visibility benefit of 0.26 dv at the Class I
area with the greatest visibility benefit.317 318 The
[[Page 28964]]
EPA also approved Colorado's determination that NOX BART for
Tri-State Craig Unit 1 is a NOX emission limit based on SNCR
at a cost of $4,877/ton, which is $5,053/ton escalated to 2020 dollars,
and estimated to result in visibility benefit of 0.31 dv at the Class I
area with the greatest visibility benefit.319 320 The EPA
approved Kentucky's determination that PM BART for Mill Creek Station
Units 3 and 4 is an emission limit based on sorbent injection at a cost
of $4,293/ton for Unit 3 and $4,443/ton for Unit 4, which is $4,872/ton
and $5,042/ton escalated to 2020 dollars (respectively), and estimated
to result in visibility benefit of 0.83 dv for both units combined at
the Class I area with the greatest visibility
benefit.321 322 In these BART determinations, the EPA and
States found that the evaluated controls were reasonable based on the
weighing of the five factors (including cost-effectiveness and
visibility benefits).
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\317\ See the EPA's proposed approval of Colorado Regional Haze
SIP at 77 FR 18052, later finalized at 77 FR 76871.
\318\ The year basis for Colorado's cost-effectiveness
calculation is 2008. We escalated the cost-effectiveness value from
2008 dollars to 2020 dollars using the CEPCI and the following
equation: Cost-effectiveness escalated to 2020 dollars = Cost-
effectiveness in 2008 dollars x (2020 CEPCI/2008 CEPCI); 2008 CEPCI
= 575.4, 2020 CEPCI = 596.2.
\319\ See the EPA's proposed approval of Colorado Regional Haze
SIP at 77 FR 18052, later finalized at 77 FR 76871.
\320\ The year basis for Colorado's cost-effectiveness
calculation is 2008. We escalated the cost-effectiveness value from
2008 dollars to 2020 dollars using the CEPCI and the following
equation: Cost-effectiveness escalated to 2020 dollars = Cost-
effectiveness in 2008 dollars x (2020 CEPCI/2008 CEPCI); 2008 CEPCI
= 575.4, 2020 CEPCI = 596.2.
\321\ See the EPA's proposed approval of Kentucky Regional Haze
SIP at 76 FR 78194 (December 16, 2011), later finalized at 77 FR
19098 (March 30, 2012).
\322\ The year basis for Kentucky's cost-effectiveness
calculations is 2007. We escalated the cost-effectiveness value from
2007 dollars to 2020 dollars using the CEPCI and the following
equation: Cost-effectiveness escalated to 2020 dollars = Cost-
effectiveness in 2007 dollars x (2020 CEPCI/2007 CEPCI); 2007 CEPCI
= 525.4, 2020 CEPCI = 596.2.
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A. SO2 BART for Coal-Fired Units With No SO2 Controls
In this section, we compare DSI, SDA, and wet FGD using the five
BART factors for the six coal-fired units with no SO2
controls. As discussed in Section VII.B.2 and in our TSD, we evaluated
each unit at its assumed maximum achievable DSI performance level using
milled trona according to the April 2017 IPM DSI documentation, which
corresponds to 90 percent for units with an existing fabric filter
baghouse and 80 percent for units with an ESP.323 324 All
units we evaluated for DSI have an existing baghouse, with the
exception of Harrington Unit 061B, which has an ESP. Since we do not
have site-specific information and individual DSI performance testing,
we do not know with certainty whether the EGUs we are evaluating in
this proposal are capable of achieving the assumed maximum DSI
performance levels specified in the April 2017 IPM DSI documentation.
Taking this into account, and recognizing that DSI has a wide range of
SO2 removal efficiencies, we also evaluated all units at a
DSI SO2 control level of 50 percent, which we believe is a
conservatively low DSI control efficiency that any given coal-fired EGU
is likely capable of achieving without requiring high sorbent injection
rates that may negatively impact the performance of the particulate
control device. Evaluating a range of control levels better informs our
analysis of control options by providing a range of costs.
Additionally, this approach addresses the BART Guidelines directive
that in evaluating technically feasible alternatives we ``(1) [ensure
we] express the degree of control using a metric that ensures an
`apples to apples' comparison of emissions performance levels among
options, and (2) [give] appropriate treatment and consideration of
control techniques that can operate over a wide range of emission
performance levels.'' \325\
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\323\ IPM Model--Updates to Cost and Performance for APC
Technologies, Dry Sorbent Injection for SO2/HCl Control
Cost Development Methodology, Final April 2017, Project 13527-001,
Eastern Research Group, Inc., Prepared by Sargent & Lundy.
\324\ Note for Harrington Unit 062B and Welsh Unit 1, we further
limited the maximum DSI control level to that of our calculated SDA
control level of 89 percent and 87 percent, respectively.
\325\ 70 FR 39166 (July 6, 2005).
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For the units with existing baghouses where we evaluated DSI at 50
percent and 90 percent control, in comparing the 50 percent control
level to the higher control level, we found DSI to have similar or
slightly higher (up to around 10 percent higher) $/ton average cost-
effectiveness at 90 percent control compared to 50 percent
control.\326\ This is due to higher annual operation and maintenance
costs associated with increased sorbent usage, as well as higher
capital costs. Similarly, for Harrington Unit 061B, which is the only
unit we evaluated that has an existing ESP rather than a baghouse, we
found DSI to have a slightly higher $/ton on average at 80 percent
control compared to 50 percent control. While the cost-effectiveness of
DSI in certain cases had a slightly higher $/ton, when going from 50
percent to 80/90 percent control efficiency, DSI at 80/90 percent
control efficiency offered much greater SO2 reductions and
higher resulting visibility benefits compared to 50 percent control
efficiency. For all units evaluated, DSI at both 50 percent and 80/90
percent control efficiency has a lower cost-effectiveness ($/ton) than
SDA and wet FGD. However, because of the lack of site-specific
information and related uncertainty over whether the specific units we
are evaluating can achieve these assumed maximum achievable DSI
performance levels, which we discuss in Section VII.B.2.a, we place
much greater weight on our evaluation of DSI at 50 percent control
efficiency compared to 80/90 percent control efficiency. There is also
additional potential uncertainty in our cost estimates for DSI at these
high performance levels. For the units with existing fabric filters, we
do not know how frequently fabric filter bags would need to be cleaned
and replaced or whether additional fabric filter compartments are
necessary at these high DSI performance levels and so our cost
estimates do not include these potential additional costs. For
Harrington Unit 061B (the only unit with an existing ESP), our cost
estimate for DSI at 80 percent control efficiency does not include the
cost of a new ESP or fabric filter even though we do not know with
certainty whether the existing ESP would be able to handle the high
sorbent injection rates needed at high SO2 removal
efficiency. Therefore, without additional site-specific information
regarding the range of maximum control efficiency achievable and
associated costs needed to consider DSI at higher control levels, we
are not further considering DSI at 80/90 percent control efficiency in
our weighing of the factors. We welcome site-specific information and
comments on the potential for these units to consistently achieve DSI
SO2 control efficiencies much higher than 50 percent (which
may be as high as 80 to 90 percent).
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\326\ Harrington Unit 062B and Welsh Unit 1 show small
improvement in cost effectiveness at the higher level of DSI
control.
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In comparing DSI at 50 percent control level with SDA and wet FGD,
we found that DSI at the 50 percent control level was more cost-
effective than either SDA or wet FGD. In general, DSI systems have low
capital costs in comparison to SDA or wet FGD. At 50 percent control
level, the ongoing annual operation and maintenance costs of DSI are
comparable to those of SDA and wet FGD. Given the relatively low
initial capital costs of DSI as compared to the installation of SDA or
wet FGD, DSI may be a more favorable control option from a cost
perspective for a coal-fired EGU that may have plans to retire in the
next several years. However, we are not aware of any federally
enforceable and permanent commitment to cease operations for these
sources that would impact the remaining useful life of controls.
[[Page 28965]]
Therefore, we do not place extra weight on the capital cost benefit of
DSI at 50 percent control over the visibility benefit gained by SDA. In
considering CAMx modeled visibility benefits, wet FGD and SDA provide
approximately twice the amount of visibility benefits as DSI at 50
percent control level. Additionally, for all units, with the exception
of Harrington Unit 061B, we conclude that scrubbers are approximately
$4,900/ton or less, and thus within the range we regularly find to be
cost-effective. We are proposing to find that, with the possible
exception of Harrington Unit 061B, the resulting visibility benefit
offered by scrubbers outweighs any possible advantage DSI at 50 percent
control may hold in terms of cost-effectiveness. At higher control
efficiencies, DSI may become more favorable as the difference in
visibility benefits between DSI and SDA or wet FGD decreases and
estimated cost-effectiveness for DSI even at higher control is
estimated to be less than that for SDA or wet FGD, resulting in
increasing incremental costs between DSI and scrubbers. However, as
noted elsewhere, there is uncertainty as to what DSI control
efficiencies are achievable for these particular units and the
associated costs at these higher control efficiencies. We will further
consider site-specific information provided to us during the public
comment period in making our final decision on SO2 BART and
potentially re-evaluate DSI for one or more particular units.
As we indicate elsewhere in our proposal, both SDA and wet FGD are
mature technologies that are in wide use throughout the United States.
In comparing wet FGD versus SDA, wet FGD is slightly less cost-
effective than SDA in all cases evaluated for this proposed action. Wet
FGD has slightly higher SO2 removal efficiency than SDA and
generally requires lower reagent usage and has lower associated reagent
costs than a comparable dry scrubber. However, as the Control Cost
Manual explains, ``In general, dry scrubbers have lower capital and
operating costs than wet scrubbers because dry scrubbers are generally
simpler, consume less water and require less waste processing.'' \327\
The Control Cost Manual also notes that SDA has lower auxiliary power
usage and lower water usage than wet FGD and does not require any
wastewater treatment, unlike a wet FGD.\328\ These factors all
contribute to the generally lower capital and operating costs of SDA
compared to wet FGD. Further, the wet FGD cost algorithms were updated
in version 6 of our IPM model to incorporate the capital and operating
costs of a wastewater treatment facility for all wet FGDs. The IPM wet
FGD Documentation states:
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\327\ EPA Air Pollution Control Cost Manual, Seventh Edition,
April 2021, Section 5, Chapter 1, titled ``Wet and Dry Scrubbers for
Acid Gas Control,'' page 1-11. The EPA Air Pollution Control Cost
Manual is available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution#cost%20manual.
\328\ Id. At 1-3 and 1-4.
Industry data from ``Current Capital Cost and Cost-effectiveness
of Power Plant Emissions Control Technologies'' prepared by J. E.
Cichanowicz for the Utility Air Regulatory Group (UARG) in 2012 to
2014 were used by Sargent & Lundy LLC (S&L) to update the wet FGD
cost algorithms from 2013. The published data were significantly
augmented by the S&L in-house database of recent wet FGD and wet FGD
wastewater treatment system projects. Due to recently published
Effluent Limitation Guidelines (ELG), it is expected that all future
wet FGDs will have to incorporate a wastewater treatment
facility.\329\
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\329\ IPM Model--Updates to Cost and Performance for APC
Technologies, Wet FGD Cost Development Methodology, Final January
2017, Project 13527-001, Eastern Research Group, Inc., Prepared by
Sargent & Lundy, p. 1.
The anticipated need for a wastewater treatment facility for all
future wet FGDs also contributes to the higher capital and operating
costs of wet FGD compared to SDA. We discuss the cost differences and
the factors that result in wet FGD being slightly less cost-effective
than SDA for the evaluated units in greater detail in our 2023 BART FIP
TSD. We solicit comment on any additional factors or information that
may affect the costs of wet FGD and/or SDA for the evaluated units and
weigh in favor of one control option or the other. Although wet FGD
would offer slightly greater SO2 emission reductions
compared to SDA, that the estimated visibility benefits of the two
control options are very similar in all cases. In consideration of the
additional costs and non-air environmental impacts associated with wet
FGD, we propose to conclude that, based on a weighing of these factors,
the selection of SDA is appropriate for Coleto Creek Unit 1, W. A.
Parish Units WAP5 and WAP6, Welsh Unit 1, and Harrington Unit 062B. We
propose that SO2 BART should be based on the emission limit
associated with SDA control levels. For those units with existing
fabric filters, DSI could potentially meet the same emission
limitations as SDA but this would need to be confirmed with site-
specific performance testing. For Harrington Unit 061B, as discussed in
Section VIII.A.2., there are unique circumstances that impact the
evaluation of controls. For this unit, we propose that SO2
BART should be an emission limit based on SDA and we propose in the
alternative an emission limit based on DSI at 50 percent control level.
We discuss in further detail our consideration of the cost-
effectiveness and anticipated visibility benefits of controls for each
of the facilities. Tables 15 thru 17 and 19 thru 26 provide summary
CAMx and CALPUFF model results of the benefits from the recommended
BART controls. The CAMx model results shown in the following tables for
each evaluated BART source summarize the benefits from the recommended
controls at the three Class I areas most impacted by the source or unit
in the baseline modeling. The benefit is calculated as the difference
between the maximum impact modeled for the baseline and the maximum
impact level modeled under the control scenario. Also summarized are
the cumulative benefit and the number of days impacted over 0.5 and 1.0
dv. Cumulative benefit is calculated as the difference in the maximum
visibility impacts from the baseline and control scenario summed across
the 15 Class I areas included in the CAMx modeling. The baseline total
cumulative number of days over 0.5 (1.0) dv is calculated as the sum of
the number of modeled days at each of the 15 Class I area impacted over
the threshold in the baseline modeling. The reduction in number of days
is calculated as the sum of the number of days over the chosen
threshold across the 15 Class I areas included in the CAMx modeling for
the baseline scenario subtracted by the number of days over the
threshold for the control scenario.
In addition to these metrics, to further inform the impacts and
potential benefits of emission reductions, we also provide the average
of modeled potential impacts from CAMx on a broader set of high impact
days. The CAMx model results tables include the average impact across
the top ten highest impacted days at the most impacted class I areas
(and cumulative across all Class I areas) for the baseline and the
recommended control scenario, as well as the calculated visibility
benefits, to assess the potential visibility benefits that could be
anticipated due to
[[Page 28966]]
controls during the ten days with meteorological/transport conditions
that result in the largest visibility impacts. These varying conditions
affect the reaction rates and transport of pollutants which can be
simulated within the photochemical grid model. While the BART analysis
is focused on examination of the maximum potential visibility
impairment and benefits, these additional metrics provide a sense for
the potential benefit across days other than just the maximum impact
day.
For Coleto Creek, Parish and Welsh units, we also present the
benefits of SDA control levels for comparison with wet FGD, though
these SDA control levels were not directly modeled in CAMx. To evaluate
SDA control levels using the available CAMx model results, we
calculated an estimate of the visibility benefits using a mathematical
extrapolation method, which is further discussed in the 2023 BART
Modeling TSD.
The CALPUFF model results in the following tables for the evaluated
BART sources include the 98th percentile modeled impact and the number
of days impacted over 0.5 and 1.0 dv for those Class I areas within the
range of CALPUFF typically used for BART. See the 2023 BART Modeling
TSD for a complete summary of our visibility benefit analysis of
controls, including modeled benefits and impacts at all Class I areas
included in the modeling analyses, plus additional metrics considered
in the assessment of visibility benefits.
1. Coleto Creek Unit 1
In reviewing Coleto Creek Unit 1, we conclude that the installation
of SDA or wet FGD results in significant visibility benefits. We
summarize some of these visibility benefits in Table 15 and discuss
them after the table.
Table 15--CAMx-Predicted Wet FGD (SDA) Visibility Benefits at Coleto Creek Unit 1
----------------------------------------------------------------------------------------------------------------
Coleto Creek Unit 1 Baseline Controlled
----------------------------------------------------------------------------------------------------------------
Visibility
Impact (dv) Avg impact Number of improvement Avg visibility Impacted
Class I area on the (dv) for days >=0.5/ (dv) on the improvement number of
maximum the top 10 >=1.0 dv maximum (dv) for the days >=0.5/
impact day days impact day * top 10 days * >=1.0 dv
----------------------------------------------------------------------------------------------------------------
Caney Creek................. 1.55 0.89 18/2 1.38 (1.34) 0.80 (0.78) 0/0
Breton...................... 1.19 0.47 4/1 1.08 (1.05) 0.43 (0.42) 0/0
Wichita Mountains........... 1.13 0.86 23/3 1.00 (0.98) 0.79 (0.76) 0/0
Cumulative (all Class I 8.54 5.14 69/6 7.75 4.71 0/0
areas).....................
----------------------------------------------------------------------------------------------------------------
* Secondary values in parentheses indicate estimated visibility benefits for SDA.
The visibility benefits predicted by CAMx with wet FGD control
levels applied to Coleto Creek Unit 1 are summarized in Table 15. We
also present the estimated benefits of SDA (shown in parentheses) for
the visibility improvement at the top three impacted Class I areas. The
small difference in visibility benefits between SDA and wet FGD is
consistent with the relatively small difference in control efficacy,
with an estimated difference between wet FGD and SDA on the maximum
impacted day of 0.04 dv at Caney Creek and an average top 10 days
difference of 0.02 dv at Caney Creek and Wichita Mountains.
CAMx modeling results indicate that wet FGD will
eliminate all 69 days impacted over 0.5 dv across all Class I areas. At
each of the three most impacted Class I areas (Caney Creek, Breton, and
Wichita Mountains), wet FGD will result in visibility improvements of
more than 1.0 dv on the maximum impacted days at each Class I area, and
for the average of the top 10 most impacted days, CAMx
predicts an average improvement of 0.43 to 0.80 dv at those same three
Class I areas. Overall, there is a cumulative improvement to the
average of the top 10 impacted days of approximately 4.7 dv with wet
FGD across all impacted Class I areas and 7.7 dv cumulative improvement
on the maximum impacted day. When compared to wet FGD, we estimate that
SDA will result in very similar visibility benefits, ranging from 0.98
to 1.34 dv at the three most impacted Class I areas on the maximum
impacted days and an average improvement of 0.42 to 0.78 dv at those
same three Class I areas for the average of the top 10 most impacted
days. See the 2023 BART Modeling TSD for more information on our
estimation of the visibility benefits of SDA. Additional evaluation of
the visibility benefits of DSI are presented in the 2023 BART Modeling
TSD, but in summary, we find that DSI averaged 46 percent reduction in
cumulative visibility impacts at the Class I areas, while wet FGD
averaged 91 percent reduction in cumulative visibility impacts overall
on the most impacted days. At Caney Creek (highest baseline maximum
impact of 1.55 dv), DSI results in improvement on the maximum impacted
day of 0.66 dv compared to 1.38 dv for wet FGD and 1.34 dv for SDA.
Thus, we conclude that the resulting visibility benefit offered by
scrubbers outweighs the possible advantage DSI at 50 percent control
may hold in cost-effectiveness.
We also conclude that both SDA and wet FGD are cost-effective at
$2,692/ton and $2,911/ton (respectively) and, as discussed in Section
VIII, well within a range that we have previously found to be
acceptable. Wet FGD is less cost-effective than SDA and we estimate
that it would have only a slight additional visibility benefit over
SDA. As discussed earlier, in weighing the factors between SDA and wet
FGD, we determined the additional visibility benefits did not outweigh
the additional cost, water requirements, and wastewater treatment
requirements associated with wet FGD. We consider the significant
visibility benefits that will result as justification for the cost of
SDA at the Coleto Creek Unit 1. We therefore propose that
SO2 BART for Coleto Creek Unit 1 is an emission limit of
0.06 lbs/MMBtu on a 30 BOD rolling average based on the installation of
SDA.
2. Harrington Units 061B & 062B
From our identification of available controls, we conclude that
both DSI and SDA are technically feasible on both Harrington units.
Harrington Unit 061B is distinct from the other coal-fired units we
evaluated in that it has an existing ESP rather than a fabric filter.
Additionally, this unit had relatively low utilization at times during
the 2016-2020 baseline we used in our BART analysis, which has resulted
in a cost per SO2 tons removed for SDA that is relatively
high compared to the other units evaluated for SDA. Based on these
facts, we are proposing and taking comment on two alternative BART
[[Page 28967]]
determinations. We are proposing BART is an emission limit reflective
of the installation and operation of SDA on both Unit 061B and 062B. In
the alternative, we are proposing BART to be an emission limit
reflective of the installation and operation of DSI at 50 percent
control for Unit 061B and SDA on 062B. We provide the reasoning for
each determination in detail in the following paragraphs and solicit
comment on both approaches.
In order to evaluate visibility benefits of control options for the
Harrington units, we performed modeling using both CALPUFF and
CAMx. As discussed in Section VII, and in more detail in our
2023 BART Modeling TSD, there are a number of differences between CAMx
and CALPUFF with one of the concerns being CALPUFF's simpler chemistry
mechanism that may underestimate the benefit of SO2
reductions versus CAMx generated values using more state of
the science chemistry.
a. Control Scenario 1: SDA on Unit 061B and Unit 062B
Table 16--CALPUFF Predicted Visibility Benefits of SDA on Both Harrington Units.*
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington 2016-2018 baseline impact Modeled Benefit of SDA on both
-------------------------------------------------------------------------------------------------------- units Cumulative
Cumulative --------------------------------- 2016-2018 # of
2016-2018 # of days with
Class I Area 2016 dv 2017 dv 2018 dv days with impacts >=0.5
impacts >=0.5 2016 dv 2017 dv 2018 dv dv/>=1.0 dv
dv/>=1.0 dv
--------------------------------------------------------------------------------------------------------------------------------------------------------
Carlsbad Caverns...................................... 0.39 0.41 0.56 16/5 0.24 0.27 0.31 1/1
Bandelier............................................. 0.17 0.12 0.14 2/0 0.12 0.09 0.11 0/0
Pecos................................................. 0.22 0.28 0.24 9/0 0.15 0.17 0.16 0/0
Salt Creek............................................ 0.49 0.59 0.54 27/3 0.23 0.39 0.32 2/0
Wheeler Peak.......................................... 0.12 0.15 0.16 2/0 0.07 0.10 0.11 0/0
White Mountain........................................ 0.26 0.43 0.33 7/0 0.17 0.26 0.24 0/0
Wichita Mountains..................................... 0.54 0.45 0.58 24/8 0.35 0.23 0.33 3/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Benefit of control values are the decrease in deciview between baseline and the control scenario. Number of days is the number of days that are equal
or greater than 0.5 and 1.0 dv after controls.
As in Section VII, we compared the visibility benefits (as
predicted by CALPUFF) of the SDA control levels on both units to the
baseline impacts in terms of percent reduction in visibility impacts.
To make this comparison, we first calculated the average of the 98th
percentile (8th highest value) for the three years modeled for each
Class I area and the average for the seven Class I areas. For
Harrington, Salt Creek was the highest impacted of the seven Class I
areas and SDA control on both units compared to baseline resulted in a
reduction of visibility impacts by 58 percent, from 0.54 dv to 0.23 dv.
At the second highest impacted Class I area, Wichita Mountains, SDA on
both units result in a reduction of visibility impacts by 58 percent,
from 0.52 dv to 0.22 dv. SDA on both units also resulted in an average
reduction of visibility impacts across the seven Class I areas combined
of 61 percent. Using the CALPUFF modeling results from the baseline, we
determined the total number of days when facility impacts were greater
than 0.5 dv and 1.0 dv. Harrington had a total of 87 days with
visibility impacts above 0.5 dv and 16 days above 1.0 dv at the seven
Class I areas modeled with CALPUFF. In comparison, SDA on both units
results in a large reduction in impacted days with only six days still
above 0.5 dv and one day above 1.0 dv at the same seven Class I areas.
In conclusion, the CALPUFF modeling results show that SDA on both units
would provide notable visibility improvements.
Table 17--CAMx-Predicted Visibility Impact and Benefit of Controls for SDA
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington Baseline Controlled
--------------------------------------------------------------------------------------------------------------------------------------------------------
Visibility
Impact (dv) on Avg impact Number of days improvement Avg visibility Impacted
Class I area the maximum (dv) for the >=0.5/ >=1.0 (dv) on the improvement number of days
impact day top 10 days dv maximum impact (dv) for the >=0.5/>=1.0 dv
day top 10 days
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington Unit 061B
--------------------------------------------------------------------------------------------------------------------------------------------------------
White Mountain.......................................... 1.43 0.48 3/1 0.96 0.35 0/0
Bandelier............................................... 0.83 0.28 1/0 0.64 0.23 0/0
Salt Creek.............................................. 0.79 0.55 6/0 0.50 0.43 0/0
Cumulative (all Class I areas).......................... 6.59 3.15 10/1 4.61 2.48 0/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington Unit 062B
--------------------------------------------------------------------------------------------------------------------------------------------------------
White Mountain.......................................... 1.36 0.48 3/1 0.95 0.36 0/0
Bandelier............................................... 0.82 0.29 1/0 0.65 0.23 0/0
Salt Creek.............................................. 0.79 0.56 6/0 0.52 0.45 0/0
Cumulative (all Class I areas).......................... 6.55 3.17 10/1 4.79 2.56 0/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington Units 061B and 062B
--------------------------------------------------------------------------------------------------------------------------------------------------------
White Mountain.......................................... 2.64 0.93 8/3 1.78 0.70 1/0
Bandelier............................................... 1.60 0.56 4/1 1.24 0.45 0/0
Salt Creek.............................................. 1.52 1.08 13/6 0.97 0.86 1/0
[[Page 28968]]
Cumulative (all Class I areas).......................... 12.77 6.23 44/10 9.08 5.00 2/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
The CAMx results reinforce that installation of SDA at the
Harrington units would provide significant visibility benefits. CAMx
modeling results indicate SDA on the individual Harrington units will
eliminate all days impacted over 0.5 dv at all Class I areas. When
considering the combined impacts of the two units, visibility benefits
from SDA installed on both units predicts only one day to exceed the
0.5 dv threshold at each of the White Mountain and Salt Creek Class I
areas. This is an overall (cumulative Class I areas) reduction from 44
days over 0.5 dv in the baseline to a total of only two days with SDA.
The overall cumulative visibility improvement is 9.08 dv on the maximum
impacted days and 5.0 dv improvement when considering the average of
the top ten days across all 15 Class I areas.
For Harrington Unit 061B, the CAMx results show that SDA would
eliminate all days impacted over 0.5 dv for that unit. On the maximum
impacted day at White Mountain, SDA results in 0.96 dv improvement over
baseline (1.43 dv), an additional 0.44 dv improvement over DSI at 50
percent control (from Table 12). On the maximum impacted day at
Bandelier, SDA results in 0.64 dv improvement over the baseline (0.83
dv), an additional 0.3 dv improvement over DSI at 50 percent control.
Furthermore, the CAMx results predict that the cumulative visibility
benefit provided by SDA on just Unit 061B is 4.6 dv, with eight Class I
areas seeing improvements of 0.25 dv or more.\330\ SDA control on both
units resulted in a reduction of maximum visibility impacts by 67
percent at White Mountain and an average reduction of maximum
visibility impacts across all 15 Class I areas of 71 percent. This
highlights that emissions and reductions from Harrington impact
visibility conditions at several Class I areas. Visibility benefits for
SDA on Unit 062B are very similar to Unit 061B.
---------------------------------------------------------------------------
\330\ Bandelier, Guadalupe Mountains, Carlsbad Caverns, Salt
Creek, Upper Buffalo, White Mountain, Wheeler Peak, and Pecos
visibility improvements with SDA on Harrington Unit 061B ranging
from 0.25 dv to 0.96 dv.
Table 18--Cost Analysis Summary for Units 061B and 062B
--------------------------------------------------------------------------------------------------------------------------------------------------------
2020
SO2 reduction 2020 Cost- Incremental
Facility Control (tpy) 2020 Annualized effectiveness cost-
cost ($/ton) effectiveness
($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington 061B............................... DSI w/ESP--50% control efficiency.... 1,892 $7,075,817 $3,740 ..............
Harrington 061B............................... SDA.................................. 3,327 $21,967,236 $6,603 $10,377
Harrington 062B............................... DSI w/BGH--50% control efficiency.... 2,703 $7,408,200 $2,742 ..............
Harrington 062B............................... SDA.................................. 4,812 $23,369,564 $4,857 $7,568
--------------------------------------------------------------------------------------------------------------------------------------------------------
A summary of our cost analyses from Section VII.B.3. are presented
in Table 18. In our analysis, we find SDA to have a cost of $6,603/ton
for Harrington Unit 061B, which is above the range for controls that we
have previously found to be cost-effective. It is reasonable to expect
that similar controls installed on units that are designed for similar
capacity would result in similar tons reduced and cost effectiveness.
Units 061B and 062B are designed to produce 360 MW of electricity but
based on a review of heat input data from 2010 to 2021, differences in
utilization or heat input have resulted in different estimates of tons
reduced and cost effectiveness.\331\ The resulting control cost
effectiveness for Harrington Unit 061B ($6,603/ton) is higher than at
the similarly designed and sized Unit 062B ($4,857/ton) because of a
lower utilization rate.
---------------------------------------------------------------------------
\331\ See ``CAMD Heat Input Data for Harrington Station.xlsx''
available in the docket for this action.
---------------------------------------------------------------------------
[[Page 28969]]
[GRAPHIC] [TIFF OMITTED] TP04MY23.115
As shown in Figure 1, the utilization rate of Unit 061B was much
lower than Unit 062B during the 2016-2020 baseline period we evaluated
for this proposed action. However, utilization rates both before and
after the baseline period have been more consistent between the two
units, and the utilization rate at Unit 061B has at times exceeded the
annual utilization at Unit 062B. The difference in utilization during
the baseline period used for the BART analysis results in a relatively
smaller estimated reduction of SO2 emissions (3,327 tons per
year with SDA for Unit 061B compared to 4,812 tons per year reduced
with SDA for Unit 062B) used to calculate the cost-effectiveness in $/
ton removed.
Further examination of the historical heat input for these units
shows that Unit 061B annual heat input for 2015 and for 2021 are higher
than during the 2016-2020 period, and for both 2015 and 2021, heat
input for Units 061B and 062B are similar. During Fall of 2016 through
spring of 2017, Unit 061B was utilized less than the other two units at
the facility.\332\ This pattern continued for 2017/2018 and 2018/2019,
resulting in lower overall heat input for the unit during those years.
Starting in Fall of 2019, utilization of the BART units at the facility
became roughly similar again, except during periods where a unit at the
facility was down. We also note that July 2022 heat input for Unit 061B
is higher than in any other single month from 2015-2022. These changes
in utilization in the more recent period may suggest that the
historical pattern of lower utilization of Unit 061B compared to Unit
062B that was observed in the majority of the 2016-2020 period may not
continue in the future, which could result in more favorable (lower $/
ton) cost-effectiveness for SDA and other controls at Harrington Unit
061B. Furthermore, because there are no enforceable limitations on
utilization for these units, there is no assurance that Unit 061B will
operate in the future at the lower utilization rates seen between 2016
and 2020.
---------------------------------------------------------------------------
\332\ The Harrington facility has three EGUs. The third unit,
Unit 063B, is not BART-eligible.
---------------------------------------------------------------------------
We find that SDA on Units 061B and 062B provides significant
visibility benefits. For Unit 062B we find SDA at $4,857/ton within the
range we have previously found to be cost effective for BART. While
above the range we have previously found to be cost effective, we still
find SDA at $6,603/ton for Unit 061B to be reasonable based on the
visibility benefits. Additionally, the estimated higher cost-
effectiveness associated with SDA is driven by past lower utilization
of Unit 061B during the baseline period. We propose and are taking
comment on our determination that BART for Units 061B and 062B is an
emission limit of 0.06 lb/MMBtu consistent with the installation and
operation of SDA.
b. Control Scenario 2: DSI on Unit 061B and SDA on Unit 062B
Because we recognize the cost effectiveness of SDA at Harrington
Unit 061B is above a range of costs we have previously required for
BART, we are proposing in the alternative to determine that BART is DSI
at a control level of 50 percent, with a requirement to conduct a DSI
performance evaluation.
[[Page 28970]]
Table 19--CALPUFF Predicted Visibility Benefit of DSI (50 Percent) on Harrington Unit 061B and SDA on Unit 062B
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington 2016-2018 Baseline Benefit of DSI--50% at Unit 061B and
----------------------------------------------------------------------------------------------------- SDA at Unit 062B Cumulative
Cumulative --------------------------------------- 2016-2018 #
# of days of days
with with
Class I area 2016 dv 2017 dv 2018 dv impacts 2016 dv 2017 dv 2018 dv impacts
>=0.5 dv/ >=0.5 dv/
>=1.0 dv >=1.0 dv
--------------------------------------------------------------------------------------------------------------------------------------------------------
Carlsbad Caverns................................ 0.39 0.41 0.56 16/5 0.18 0.21 0.23 5/1
Bandelier....................................... 0.17 0.12 0.14 2/0 0.09 0.06 0.08 0/0
Pecos........................................... 0.22 0.28 0.24 9/0 0.11 0.13 0.12 0/0
Salt Creek...................................... 0.49 0.59 0.54 27/3 0.16 0.30 0.25 11/1
Wheeler Peak.................................... 0.12 0.15 0.16 2/0 0.05 0.08 0.08 0/0
White Mountain.................................. 0.26 0.43 0.33 7/0 0.14 0.20 0.19 0/0
Wichita Mountains............................... 0.54 0.45 0.58 24/8 0.27 0.20 0.25 8/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Benefit of control values are the decrease in deciview between baseline and the control scenario. Number of days is the number of days that are equal
or greater than 0.5 and 1.0 dv after controls.
For Harrington, CALPUFF results show installation of DSI at a 50
percent control level on Unit 061B and SDA on Unit 062B resulted in a
reduction of visibility impacts by 44 percent from the baseline at the
highest impacted Class I area (Salt Creek) from 0.54 dv to 0.31 dv, and
an average reduction of visibility impacts across seven Class I areas
of 47 percent. For the 2016-2018 modeled years (baseline period),
Harrington baseline had a total of 87 days with visibility impacts
above 0.5 dv and 16 days above 1.0 dv at the seven Class I areas
modeled with CALPUFF. DSI at 50 percent on Unit 061B and SDA on Unit
062B resulted in 24 days above 0.5 dv and two days above 1.0 dv. The
incremental visibility benefit between DSI and SDA is larger with the
CAMx modeling than with the CALPUFF modeling.\333\
---------------------------------------------------------------------------
\333\ See the 2023 BART Modeling TSD for detailed discussion of
differences between CAMx and CALPUFF models and modeling results.
Table 20--CAMx Predicted Visibility Benefit of DSI (50 Percent) on Unit 061B and SDA on Unit 062B
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington Baseline Controlled
--------------------------------------------------------------------------------------------------------------------------------------------------------
Visibility
Impact (dv) on Avg impact Number of days improvement Avg visibility Impacted
Class I area the maximum (dv) for the >=0.5/ >=1.0 (dv) on the improvement number of days
impact day top 10 days dv maximum impact (dv) for the >=0.5/ >=1.0
day top 10 days dv
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington Unit 061B with DSI (50 percent) control
--------------------------------------------------------------------------------------------------------------------------------------------------------
White Mountain.......................................... 1.43 0.48 3/1 0.52 0.19 1/0
Bandelier............................................... 0.83 0.28 1/0 0.34 0.12 0/0
Salt Creek.............................................. 0.79 0.55 6/0 0.26 0.23 1/0
Cumulative (all Class I areas).......................... 6.59 3.15 10/1 2.56 1.34 2/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington Unit 062B with SDA control
--------------------------------------------------------------------------------------------------------------------------------------------------------
White Mountain.......................................... 1.36 0.48 3/1 0.95 0.36 0/0
Bandelier............................................... 0.82 0.29 1/0 0.65 0.23 0/0
Salt Creek.............................................. 0.79 0.56 6/0 0.52 0.45 0/0
Cumulative (all Class I areas).......................... 6.55 3.17 10/1 4.79 2.56 0/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Harrington Unit 061B with DSI (50 percent) and 062B with SDA controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
White Mountain.......................................... 2.64 0.93 8/3 * 1.34 * 0.54 ** 1/1
Bandelier............................................... 1.60 0.56 4/1 * 0.94 * 0.34 ** 1/0
Salt Creek.............................................. 1.52 1.08 13/6 * 0.73 * 0.66 ** 3/0
Cumulative (all Class I areas).......................... 12.77 6.23 44/10 * 7.03 * 3.86 ** 5/1
--------------------------------------------------------------------------------------------------------------------------------------------------------
* We did not model this combination (50 percent DSI on 061B and SDA on 062B) directly, so we estimated these values by subtracting the difference
between the 50 percent DSI (Low Control) and SDA for 061B improvement values from the combined units SDA-only values in the previous table.
** Again, we did not model this combination directly, so we estimated the number of days based on the High (SDA) and Low (50 percent DSI) control number
of days.
The CAMx results for Harrington for this second control scenario
show that White Mountain was the most impacted of the 15 Class I areas,
the same as in the first control scenario, which had SDA on both units.
From Table 17 of the first control scenario, we calculate that SDA
control on both units compared to baseline resulted in a reduction of
visibility impacts at White Mountain by 67 percent and an average
reduction of visibility impacts across the 15 Class I areas of 71
percent; whereas, from Table 20 we calculate that the 50% DSI on Unit
061B and SDA on Unit 062B
[[Page 28971]]
compared to the baseline resulted in a reduction of visibility impacts
at White Mountain by 51 percent and an average reduction of visibility
impacts across the 15 Class I areas of 55 percent.
For Unit 061B, by itself, DSI at 50 percent control results in
visibility benefits approximately one half of those achieved through
SDA. On the maximum impacted day at White Mountain, DSI at 50 percent
on Unit 061B results in 0.52 dv improvement compared to 0.96 dv with
SDA on that unit; at Bandelier, DSI at 50 percent results in 0.34 dv
improvement compared to 0.64 dv with SDA on that unit. The cumulative
visibility benefit across all Class I areas on the maximum impacted
days for Unit 61B with DSI at 50 percent is 2.56 dv compared to 4.61 dv
with SDA. For the average of the top 10 most impacted days, SDA
provides for a 0.43 dv benefit at Salt Creek compared to 0.23 dv for
DSI at 50 percent control, and SDA provides for 0.35 dv benefit at
White Mountain compared to 0.19 dv for DSI at 50 percent control--
almost twice the improvement with SDA over DSI at 50% on Unit 061B.
When considering the combined benefits of DSI for Unit 061B and SDA
for Unit 062B, the visibility improvement at White Mountain Class I
area is estimated to be more than 1.3 (1.78 minus 0.44) dv on the
highest impact day, while the average of the top 10 most impacted days
visibility improvement is approximately 0.6 (0.86 minus 0.20) dv at
Salt Creek. Overall, for the visibility improvement at the cumulative
Class I areas from the Harrington facility, CAMx predicts an average
improvement of almost 4.0 (5.00 minus 1.14) dv across all the Class I
areas evaluated on the top 10 days and an improvement on the maximum
impacted days of approximately 7.0 (9.08 minus 2.05) dv with SDA
controls on Unit 062B and DSI at 50 percent on Unit 061B. Thus, we find
that SDA on Unit 062B and DSI at 50 percent control on Unit 061B
results in a significant reduction in visibility impacts from these
units and that the benefits are spread across a number of Class I areas
in New Mexico, Texas, and Oklahoma. As previously discussed, SDA on
both units provides an additional cumulative visibility benefit (the
difference between DSI at 50 percent control and SDA on Unit 061B) on
the average of the top 10 days from the Harrington facility of 1.14 dv
across all the Class I areas evaluated and an additional improvement on
the maximum impacted days of 2.05 dv. However, DSI at 50 percent
control for Harrington is more cost-effective ($2,742/ton for Unit 062B
and $3,740/ton for Unit 061B) than SDA ($4,857/ton for Unit 062B and
$6,603/ton for Unit 061B) and is well within the range of what we have
previously found to be acceptable in other BART actions. For Harrington
Unit 062B, we consider SDA to also be cost-effective and within the
range of what we have previously found to be acceptable in other BART
actions. As discussed earlier, the cost of SDA at Unit 061B is above
the range we have previously found to be cost-effective, and the
incremental cost-effectiveness of SDA (going from DSI at 50 percent
control efficiency to SDA) is $10,377, which we consider to be
relatively high. The cost of SDA at Unit 061B is relatively high, but
we still find SDA to be reasonable based on the important visibility
benefits of SDA on this unit. However, given the relatively high cost
of SDA at Unit 061B, we propose in the alternative that BART for this
unit is based on DSI. While the visibility benefits of DSI are
approximately half those from SDA on Unit 061B using the CAMx results,
installation of DSI is significantly less costly than SDA. Therefore,
we are proposing in the alternative that BART for Unit 061B is 0.27 lb/
MMBtu based on DSI at 50 percent, with a compliance period of no later
than two (2) years from the effective date of the final rule.\334\
---------------------------------------------------------------------------
\334\ The proposed regulatory language for this rulemaking only
covers our first proposed approach (SDA on Harrington Units 061B and
062B). If the EPA finalizes an action consistent with our
alternative proposed approach (DSI at 50% control on Unit 061B and
SDA on Unit 062B), we will revise the regulatory language
accordingly.
---------------------------------------------------------------------------
We believe Unit 061B is likely capable of achieving an
SO2 emission limit of 0.27 lb/MMBtu with DSI but are not
certain whether the unit could achieve a lower emission limit on a 30
BOD or what the potential impacts to PM emissions could be at higher
injections rates necessary for higher control efficiencies using the
existing ESP. We evaluated DSI at a 50 percent control level as a
conservative representative of what DSI can achieve on average. Because
the control efficiency of DSI is dependent on several operational
variables, we also propose to require a performance evaluation (as
provided for in Section IX.A.3) to determine the maximum control
efficiency of DSI for Harrington Unit 061B specifically along with an
estimate of the cost to operate DSI at this control level.\335\ Based
on available information, on a unit-specific basis, using sodium-based
sorbents, we believe DSI could potentially achieve up to 80 percent or
higher SO2 control, even with an ESP. However, as noted
earlier, because of unit-specific uncertainty we are proposing an
emissions limit of 0.27 lb/MMBtu based on DSI at 50 percent. If a DSI
performance evaluation finds that Unit 061B can meet a lower rate, we
will propose to adjust this limit in a future notice to reflect the
maximum control efficiency that the unit can consistently meet. As
discussed in Sections VII.B.2.a and VII.B.3.a, we are also soliciting
comments on the range and maximum control efficiency that can be
achieved with DSI at the evaluated units, including Harrington Unit
061B, and estimates of the range of associated costs. We are especially
interested in comments on any site-specific DSI testing for Unit 061B
to determine the range and maximum control efficiency that can be
achieved with DSI at the unit. Any data to support the control
efficiency range, maximum control efficiency, and cost of DSI for the
unit should be submitted along with those comments. We will further
consider DSI site-specific information provided to us during the public
comment period in our final decision and potentially re-evaluate DSI
for this particular unit.
---------------------------------------------------------------------------
\335\ The purpose of the DSI performance evaluation is to
determine the lowest SO2 emission rate Unit 061B would be
able to sustainably achieve on a 30 BOD with DSI under three
different scenarios for particulate removal ((1) using the existing
ESP; (2) with a new ESP installation; and (3) with a new fabric
filter installation) and to determine how compliance with such an
emission rate would impact our cost estimates for DSI. The proposed
DSI performance evaluation requirements are discussed in greater
detail in Section IX.A.3.
---------------------------------------------------------------------------
c. Option To Convert to Natural Gas
Additionally, we recognize that Xcel Energy has announced its
intent to convert Harrington Station to natural gas by January 1, 2025.
We understand this has been formalized further in an Agreed Order with
TCEQ,\336\ a PSD permit revision,\337\ and approval from the Texas
Public Utility Commission (PUC).\338\ The BART Guidelines state in
situations where a future operating parameter will differ from past or
current practices, and if such future operating parameters will have a
deciding effect in the BART determination, then the future operating
parameters need to be made federally enforceable and permanent in order
to consider them in the BART
[[Page 28972]]
determination.\339\ Thus, we are providing Xcel Energy the option to
make this conversion to natural gas a permanent and federally
enforceable commitment by incorporating it into this FIP. We are
proposing that should Xcel Energy agree to these future operating
parameters (i.e., operating as a natural gas source no later than
January 1, 2025), then for purposes of this analysis we will consider
Harrington to be a natural gas source. We noted earlier that for
natural gas units, there are no practical add-on controls to consider
for setting a more stringent SO2 BART emission limit.
Therefore, under this option, we propose that BART for both Harrington
units is the burning of pipeline natural gas, as defined at 40 CFR
72.2.\340\ Because the conversion to natural gas no later than January
1, 2025, would occur before the deadline to comply with a BART emission
limit reflective of the installation of DSI or scrubbers, there is no
need to evaluate whether an interim SO2 emission limit is
necessary prior to the conversion to natural gas. Additionally, the
visibility benefits of a conversion to natural gas would be greater
than with the limits we are proposing based on either SDA or DSI. We
are interested in comments on this option and specifically invite
Harrington to provide comments as to their interest in this option.
---------------------------------------------------------------------------
\336\ In the Matter of an Agreed Order Concerning Southwestern
Public Service Company, dba cel Energy, Harrington Station Power
Plant, TCEQ Docket No. 2020-0982-MIS (Adopted Oct. 21, 2020). A copy
of the Order is available in the docket for this action.
\337\ See Harrington's revised PSD permits (NSR1529 and NSR1388)
located in the docket for this action.
\338\ See the Texas PUC Order, Docket No. 52485-201, located in
the docket for this action.
\339\ 70 FR at 39167.
\340\ ``Pipeline natural gas'' means a naturally occurring fluid
mixture of hydrocarbons (e.g., methane, ethane, or propane) produced
in geological formations beneath the Earth's surface that maintains
a gaseous state at standard atmospheric temperature and pressure
under ordinary conditions, and which is provided by a supplier
through a pipeline. Pipeline natural gas contains 0.5 grains or less
of total sulfur per 100 standard cubic feet. This is equivalent to
an SO2 emission rate of 0.0006 lb/MMBtu. Additionally,
pipeline natural gas must either be composed of at least 70 percent
methane by volume or have a gross calorific value between 950 and
1100 Btu per standard cubic foot. 40 CFR 72.2.
---------------------------------------------------------------------------
3. Welsh Unit 1
In reviewing the modeling results for Welsh Unit 1, we conclude
that the installation of a wet FGD or SDA will provide significant
visibility benefits. As discussed in Section VII.A.1, we modeled Welsh
Unit 1 with both CALPUFF and CAMx. The visibility benefits for Welsh
are summarized in Tables 21 and 22.
Table 21--CALPUFF-Predicted Wet FGD and SDA Visibility Benefits at Welsh Unit 1 *
--------------------------------------------------------------------------------------------------------------------------------------------------------
2016-18 baseline High control scenarios (WFGD/SDA)
-----------------------------------------------------------------------------------------------------------------
Cumulative Visibility benefit at Class I area Cumulative 2016-2018 #
Class I area 2016-18 # of (dv) from baseline (WFGD/SDA) of days with impacts
2016 dv 2017 dv 2018 dv days with --------------------------------------- >=0.5 />=1.0 dv
impacts >=0.5 -------------------------
dv/>=1.0 dv 2016 dv 2017 dv 2018 dv WFGD SDA
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek........................... 0.70 0.94 0.96 77/13 0.28/0.27 0.37/0.35 0.53/0.53 18/1 18/1
Upper Buffalo......................... 0.36 0.49 0.60 16/0 0.25/0.24 0.33/0.32 0.42/0.40 0/0 1/0
Wichita Mountains..................... 0.25 0.35 0.24 3/0 0.17/0.16 0.28/0.26 0.16/0.16 0/0 1/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Benefit of control values are the decrease in deciview between baseline and the control scenario. Number of days is the number of days that are equal
or greater than 0.5 and 1.0 dv after controls.
The Welsh facility is within 450 km of three Class I areas (Caney
Creek, Wichita Mountains, and Upper Buffalo), and therefore, within the
range that the CALPUFF model has been used for assessing visibility
impacts in BART analyses. CALPUFF results for Welsh indicate that
installation of wet FGD or SDA resulted in a reduction of visibility
impacts by 45 percent (0.39 dv average visibility benefit) and 44
percent (0.38 dv average visibility benefit), respectively from the
baseline (0.86 dv) at the highest impacted Class I area (Caney Creek),
and an average reduction of visibility impacts across the three Class I
areas of 57 percent and 55 percent respectively.
Using three years (2016-2018) CALPUFF modeling results, we assessed
the annual number of days when the facility impacts were greater than
the 0.5 dv and 1.0 dv threshold at each of the Class I areas and then
summed this value for all Class I areas to determine the total number
of days in the 2016-2018 modeled period where visibility impacts were
above 0.5 dv and 1.0 dv. These results indicate that the installation
of wet FGD or SDA will eliminate 78 days (81 percent decrease) and 76
days (79 percent decrease) respectively where visibility is greater
than 0.5 dv and 12 days (92 percent decrease) where visibility is
greater than 1.0 dv over the three modeled years for these three Class
I areas. Comparing the CALPUFF modeled improvement with the
installation of wet FGD versus SDA on Unit 1 indicates the visibility
benefits are very similar (within 1.3-5.4 percent of each other).
Table 22--CAMx-Predicted Wet FGD (SDA) Visibility Benefits at Welsh Unit 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Welsh Unit 1 Baseline Controlled
--------------------------------------------------------------------------------------------------------------------------------------------------------
Visibility
Impact (dv) on Avg impact Number of days improvement Avg visibility Impacted
Class I area the maximum (dv) for the >=0.5/ >=1.0 (dv) on the improvement number of days
impact day top 10 days dv maximum impact (dv) for the >=0.5/>=1.0 dv
day * top 10 days *
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek............................................. 1.58 1.11 27/6 1.08 (1.02) 0.83 (0.79) 0/0
Wichita Mountains....................................... 1.54 0.71 6/2 1.34 (1.29) 0.60 (0.57) 0/0
Upper Buffalo........................................... 1.12 0.68 8/1 0.83 (0.79) 0.53 (0.50) 0/0
Cumulative (all Class I areas).......................... 6.67 3.97 46/9 5.27 3.21 0/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Secondary values in parentheses indicate estimated visibility benefits for SDA.
[[Page 28973]]
Table 22 displays the visibility benefits predicted by CAMx with
wet FGD control levels applied to Welsh Unit 1. We also present the
estimated benefits of SDA (shown in parentheses). Since SDA is slightly
less effective at reducing SO2 emissions than wet FGD, the
comparative results between SDA and wet FGD are consistent with the
difference in control efficacy, with a difference between wet FGD and
SDA on the maximum impacted day of 0.06 dv at Caney Creek and 0.05 dv
at Wichita Mountains and an average top 10 days difference of 0.03-0.04
dv at each of the top three Class I areas.
CAMx modeling results indicate that wet FGD on Welsh Unit 1 will
eliminate all days impacted by the unit over 0.5 dv at all Class I
areas, from 46 days in the baseline to zero with wet FGD, and SDA
controls eliminate all but one day with impacts over 0.5 dv. At the
most impacted Class I areas, wet FGD control results in visibility
improvements of up to 1.35 dv on the maximum impacted day at Wichita
Mountains and 1.29 dv with SDA control compared to the baseline maximum
impact of 1.54 dv. Similarly, wet FGD control results in visibility
improvements of up to 1.08 dv on the maximum impacted day at Caney
Creek and 1.02 dv with SDA control compared to the baseline maximum
impact of 1.58 dv. For the average of the top 10 most impacted days,
wet FGD control results in 0.82 dv, while SDA results in 0.79 dv
visibility improvements at Caney Creek (baseline impact 1.11 dv). For
the average of the top 10 most impacted days, wet FGD control results
in 0.60 dv, while SDA results in 0.57 dv visibility improvements at
Wichita Mountains (baseline impact 0.71 dv).
Overall, there is a cumulative improvement to the average of the
top 10 days of approximately 3.2 dv with wet FGD across all impacted
Class I areas and approximately 5.3 dv cumulative improvement on the
maximum impacted day. The 2023 BART Modeling TSD shows that DSI control
achieved approximately 39 percent average improvement in visibility,
while wet FGD averaged 79 percent overall visibility improvement. At
Caney Creek, DSI results in improvement on the maximum impacted day of
0.48 dv compared to 1.08 dv for wet FGD and 1.02 dv for SDA. At Wichita
Mountains, DSI results in improvement on the maximum impacted day of
0.69 dv compared to 1.35 dv for wet FGD and 1.29 dv for SDA. At Caney
Creek, the baseline had 27 days over 0.5 dv and 6 days over 1.0 dv, but
with DSI these number of days were reduced to 8 and 1, respectively,
and further reduced with wet FGD to zero days over 0.5 dv and zero days
over 1.0 dv. At Wichita Mountains, the baseline had 6 days over 0.5 dv
and 2 days over 1.0 dv, but with DSI these number of days were reduced
to 2 and zero, respectively, and further reduced with wet FGD to zero
days over 0.5 dv and zero days over 1.0 dv.
We conclude that both SDA and wet FGD are cost-effective at $4,370/
ton and $4,497/ton (respectively) and remain within a range that we
have previously found to be acceptable. Wet FGD is less cost-effective
than SDA and as discussed in the preceding paragraphs, it would have
only a slight additional visibility benefit over SDA. As discussed
earlier, in weighing the factors between SDA and wet FGD, we determined
the additional visibility benefits did not outweigh the additional
cost, water requirements, and wastewater treatment requirements
associated with wet FGD. DSI at 50 percent control is more cost-
effective but results in much less visibility benefit. We consider the
significant visibility benefits that will result from the installation
of SDA at Welsh Unit 1 to justify the cost, and therefore, we propose
that SO2 BART for Welsh Unit 1 should be based on the
installation of SDA at an emission limit of 0.06 lb/MMBtu based on a 30
BOD.
We recognize that at $4,370/ton, the cost of SDA for Welsh Unit 1
is in the upper range of cost-effectiveness of controls found to be
acceptable in other BART actions nationwide. Nevertheless, we consider
it to be cost-effective and provides for significant visibility
benefit. Since BART is defined as an emission limitation,\341\ sources
have the flexibility to decide what controls to install and implement
so long as they comply with the BART emission limitations and
associated requirements that are promulgated. As discussed in Section
VIII.A, based on available DSI cost information, some EGUs with an
installed baghouse may be able to achieve 90+ percent SO2
control efficiency using DSI with sodium-based sorbents. Therefore,
Welsh Unit 1 could potentially comply with our proposed SO2
emission limit of 0.06 lb/MMBtu with DSI operated at a high
SO2 control level, but this would need to be confirmed with
site-specific performance testing. If the unit is capable of meeting
this SO2 emission limit with DSI, this control technology is
likely to be even more cost-effective than SDA.
---------------------------------------------------------------------------
\341\ See 40 CFR part 51, Appendix Y--Guidelines For BART
Determinations Under the Regional Haze Rule, section IV.A.
---------------------------------------------------------------------------
As discussed in Sections VII.B.2.a and VII.B.3.a, we also invite
comments on the range and maximum control efficiency that can be
achieved with DSI at Welsh Unit 1 and estimates of the range of
associated costs. We are especially interested in any site-specific DSI
testing for Welsh Unit 1 to determine the range and maximum control
efficiency that can be achieved with DSI at this unit. Any data to
support the control efficiency range, maximum control efficiency, and
cost of DSI for the unit should be submitted along with those comments.
We will further consider site-specific information provided to us
during the public comment period in making our final decision on
SO2 BART and potentially re-evaluate DSI for this particular
unit.
4. W. A. Parish Units WAP4, WAP5 & WAP6
W. A. Parish Unit WAP4 is the only gas-fired unit we determined to
be subject to BART. Gas-fired EGUs have inherently low SO2
emissions and there are no known SO2 controls that can be
evaluated. While we must assign SO2 BART determinations to
the gas-fired unit, there are no practical add-on controls to consider
for setting a more stringent BART emission limit. As explained earlier
in Section VII.B.1.c, the BART Guidelines state that if the most
stringent controls are made federally enforceable for BART, then the
otherwise required analyses leading up to the BART determination can be
skipped. As there are no appropriate add-on controls and the status quo
reflects the most stringent control level, we are proposing that
SO2 BART for W. A. Parish Unit WAP4 is to limit fuel to
pipeline natural gas, as defined at 40 CFR 72.2.\342\
---------------------------------------------------------------------------
\342\ As provided for in 40 CFR 72.2, pipeline natural gas
contains 0.5 grains or less of total sulfur per 100 standard cubic
feet. This is equivalent to an SO2 emission rate of
0.0006 lb/MMBtu.
---------------------------------------------------------------------------
In evaluating W. A. Parish Units WAP5 and WAP6, we conclude that
the installation of wet FGD or SDA will result in significant
visibility benefits. We summarize some of these visibility benefits in
Table 23.
[[Page 28974]]
Table 23--CAMx Predicted Visibility Benefit of Wet FGD (SDA) at W. A. Parish
--------------------------------------------------------------------------------------------------------------------------------------------------------
W. A. Parish Baseline Controlled
--------------------------------------------------------------------------------------------------------------------------------------------------------
Visibility
Impact (dv) on Avg impact improvement Avg visibility Impacted
Class I area the maximum (dv) for the Number of days (dv) on the improvement number of days
impact day top 10 days >=0.5/>=1.0 dv maximum impact (dv) for the >=0.5/>=1.0 dv
day * top 10 days *
--------------------------------------------------------------------------------------------------------------------------------------------------------
W. A. Parish WAP5
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wichita Mountains....................................... 2.01 0.83 12/1 1.86 (1.80) 0.77 (0.75) 0/0
Caney Creek............................................. 1.57 1.09 36/6 1.38 (1.36) 0.97 (0.94) 0/0
Breton.................................................. 1.08 0.52 4/1 0.94 (0.92) 0.47 (0.45) 0/0
Cumulative (all Class I areas).......................... 8.82 5.18 86/10 7.93 4.71 0/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
W. A. Parish WAP6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wichita Mountains....................................... 2.24 0.93 15/1 2.07 (2.01) 0.86 (0.84) 0/0
Caney Creek............................................. 1.75 1.22 47/9 1.52 (1.50) 1.08 (1.05) 0/0
Breton.................................................. 1.21 0.58 4/2 1.05 (1.02) 0.52 (0.50) 0/0
Cumulative (all Class I areas).......................... 9.86 5.80 119/15 8.81 5.27 0/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
W. A. Parish WAP5 and WAP6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Wichita Mountains....................................... 3.97 1.71 35/12 3.61 1.56 0/0
Caney Creek............................................. 3.13 2.22 86/38 2.59 1.91 1/0
Breton.................................................. 2.21 1.08 12/4 1.89 0.96 0/0
Cumulative (all Class I areas).......................... 17.96 10.72 269/91 15.66 9.56 1/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Secondary values in parentheses indicate estimated visibility benefits for SDA
Table 23 displays the visibility benefits predicted by CAMx
modeling with wet FGD control levels applied to Units WAP5 and WAP6. We
also present the estimated benefits of SDA (shown in parentheses) for
each unit individually. Since SDA is slightly less effective at
reducing SO2 emissions than wet FGD, the comparative results
between SDA and wet FGD are consistent with the difference in control
efficacy, with a maximum difference between wet FGD and SDA on the
maximum impacted day of 0.06 dv at Wichita Mountains for each unit
(0.02-0.03 dv for Caney Creek and Breton) and an average top 10 days
difference of 0.03 dv at Caney Creek (0.02 dv at Wichita Mountains and
Breton) for each unit, with SDA always showing marginally less
improvement from the baseline. These values indicate that SDA per unit
results in approximately 2-4 percent less benefit than wet FGD on a per
unit basis.
CAMx modeling results indicate that wet FGD installed on each of
Units WAP5 and WAP6 will eliminate all days impacted by each unit over
0.5 dv at all Class I areas, and our estimates for SDA control also
show no days over 0.5 dv at any Class I areas. When considering the
combined impacts from all three units taken together with wet FGD on
WAP5 and WAP6, the CAMx results predict one day to exceed the 0.5 dv
threshold (at Caney Creek).\343\ We would expect similar results in
looking at SDA for Units WAP5 and WAP6 as the visibility differences
for SDA and wet FGD are small. Overall, there is a cumulative reduction
from 269 days over 0.5 dv in the baseline to a total of just one day
over the threshold with wet FGD across all impacted Class I areas.
---------------------------------------------------------------------------
\343\ W. A. Parish Unit WAP4 is a gas-fired unit for which we
are locking in the requirement to burn pipeline quality natural gas.
---------------------------------------------------------------------------
Installation of wet FGD on both units results in 3.61 dv
improvement (91 percent reduction of 3.97 dv baseline) on the maximum
impact day at Wichita Mountains and a 1.56 dv improvement (91 percent
reduction of 1.71 dv baseline) on the top 10 average days at Wichita
Mountains. Installation of wet FGD on both units results in 2.59 dv
improvement (83 percent reduction of 3.13 dv baseline) on the maximum
impact day at Caney Creek and a 1.91 dv improvement (86 percent
reduction of 2.22 dv baseline) on the top 10 average days at Caney
Creek. SDA visibility benefits on a unit basis result in 95 percent or
more of the visibility benefit of wet FGD on a unit basis. At the most
impacted Class I areas, either wet FGD or SDA on each unit will each
result in visibility improvements of more than 1.8 dv per unit at
Wichita Mountains, and the top 10 days average visibility improvement
for the individual units are more than 0.9 dv at Caney Creek for each
unit with wet FGD or SDA. Across all impacted Class I areas, the top 10
days average improvement from all three units combined is predicted to
be approximately 9.5 dv, or approximately 89 percent reduction in
visibility impairment due to wet FGD controls or SDA. As provided in
Section VII.B.4, DSI operated at 50 percent control (``low control
scenario'') results in 43 percent visibility improvement for the
overall three units, whereas wet FGD visibility benefits result in 87
percent improvement at the most impacted Class I areas for the three
units and the cumulative 15 Class I areas included in the modeling.
We conclude that both SDA and wet FGD are cost-effective at $3,044/
ton and $3,074/ton (respectively) for Unit WAP5 and $2,651/ton and
$2,717/ton (respectively) for Unit WAP6 and remain well within a range
that we have previously found to be acceptable. While DSI at 50 percent
control is more cost-effective at $2,262/ton for Unit WAP5 and $2,244/
ton for Unit WAP6, it results in less visibility benefit. The
incremental cost-effectiveness of SDA (going from DSI at 50 percent
control efficiency to SDA) is $4,006/ton for Unit WAP5 and $3,155/ton
for Unit WAP6, which we consider to be reasonable. Thus, we conclude
that the resulting visibility benefit offered by scrubbers outweighs
the possible advantage DSI at 50 percent control may hold in cost-
effectiveness.
[[Page 28975]]
Wet FGD is slightly less cost-effective than SDA and we estimate
based on scaling of our CAMx modeling results that it would have only a
slight additional visibility benefit over SDA. As discussed earlier, in
weighing the factors between SDA and wet FGD, we determined the
additional visibility benefits did not outweigh the additional cost,
water requirements and wastewater treatment requirements associated
with wet FGD. We consider the cost of SDA at the two W. A. Parish units
to be justified by the significant visibility benefits that will
result. We therefore propose that SO2 BART for W. A. Parish
Units WAP5 and WAP6 should be based on the installation of SDA at an
emission limit of 0.06 lb/MMBtu based on a 30 BOD.
B. SO2 BART for Coal-Fired Units With Existing Scrubbers
1. Martin Lake Units 1, 2, and 3
The BART Guidelines state that underperforming scrubber systems
should be evaluated for upgrades.\344\ Other than upgrading the
existing scrubbers, all of which are wet FGDs, there are no competing
control technologies that could be considered for these units at Martin
Lake. These units were modeled with both CALPUFF and CAMx. We summarize
some of these visibility benefits from upgrading Martin Lake's existing
scrubbers in Tables 24 and 25.
---------------------------------------------------------------------------
\344\ 70 FR 39171 (July 6, 2005).
Table 24--CALPUFF-Predicted Scrubber Upgrade Visibility Benefits at Martin Lake
--------------------------------------------------------------------------------------------------------------------------------------------------------
2016-18 Baseline impacts Scrubber upgrades
-------------------------------------------------------------------------------------------
Cumulative Visibility benefit at class I Cumulative
2016-2018 # area (dv) from baseline 2016-2018 #
Class I area of days --------------------------------- of days
2016 dv 2017 dv 2018 dv with with
impacts impacts
>=0.5 dv/ 2016 dv 2017 dv 2018 dv >=0.5 dv/
>=1.0 dv >=1.0 dv
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek................................................. 3.28 3.60 3.35 338/215 2.12 2.36 2.16 133/44
Upper Buffalo............................................... 2.12 2.54 2.27 212/115 1.58 1.90 1.72 33/8
Wichita Mountains........................................... 1.45 1.07 1.15 79/36 1.21 0.89 0.91 5/2
Cumulative.................................................. 6.84 7.21 6.78 629/366 4.90 5.15 4.79 171/54
--------------------------------------------------------------------------------------------------------------------------------------------------------
In evaluating Martin Lake, there are three Class I areas (Caney
Creek, Upper Buffalo, and Wichita Mountains) within the typical 450 km
range that CALPUFF has been used for assessing visibility impacts. The
modeled scrubber upgrades result in large visibility improvements of
over 2.2 dv at Caney Creek and 1.7 dv at Upper Buffalo. Visibility
benefits at Wichita Mountains also exceed 1.0 dv. CALPUFF results for
Martin Lake indicate that upgrading the scrubbers resulted in a
reduction of visibility impacts by 65 percent from the baseline at the
highest impacted Class I area (Caney Creek), and an average reduction
of visibility impacts at the three Class I areas of 71 percent. Using
the three years (2016-2018) of CALPUFF modeling results, we assessed
the annual average number of days, averaged across the three years,
when the facility impacts were greater than 0.5 dv at each Class I
area; we also looked at the cumulative number of days summed across the
three years at all the Class I areas (three in this case). The
reduction in the number of days (annual average) was calculated using
the cumulative value of the number of days (three-year total) over the
0.5 dv threshold across the three Class I areas for the baseline
scenario minus the cumulative number of days (three-year total) over
the threshold for the control scenario. For the three Class I areas,
2016-2018 CALPUFF modeling results indicate that upgraded scrubbers on
the three units will eliminate 152 days annually (3-year average), or
458 days cumulatively across the 3 years, when the facility has impacts
greater than 0.5 dv in the baseline. The same analysis for the 1.0 dv
threshold, as reported in Table 24, has 104 days (312 days total)
reduced on annual average. CALPUFF modeling results indicate large
improvements at the individual Class I areas and the cumulative
improvement of almost 5 dv; these scrubber upgrades markedly improve
the overall cumulative predicted visibility by approximately 71 percent
from the baseline.
Table 25 includes each affected Martin Lake unit and the combined
facility along with the resulting CAMx-modeled visibility benefits from
upgrading Martin Lake's existing scrubbers.
Table 25--CAMx Predicted Visibility Benefit of Scrubber Upgrades for Martin Lake
--------------------------------------------------------------------------------------------------------------------------------------------------------
Martin Lake Baseline Controlled
--------------------------------------------------------------------------------------------------------------------------------------------------------
Visibility
Impact (dv) on Avg impact improvement Avg visibility Impacted
Class I area the maximum (dv) for the Number of days (dv) on the improvement number of days
impact day top 10 days >=0.5/>=1.0 dv maximum (dv) for the >=0.5/>=1.0 dv
impact day top 10 days
--------------------------------------------------------------------------------------------------------------------------------------------------------
Martin Lake Unit 1
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek............................................. 2.60 1.98 74/22 2.00 1.56 2/0
Wichita Mountains....................................... 2.08 1.01 17/3 1.76 0.85 0/0
Upper Buffalo........................................... 1.93 1.39 48/8 1.66 1.18 0/0
Cumulative (all Class I areas).......................... 12.39 7.90 197/38 10.36 6.64 2/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Martin Lake Unit 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek............................................. 2.54 1.94 72/22 1.94 1.52 2/0
[[Page 28976]]
Wichita Mountains....................................... 2.03 0.99 17/3 1.71 0.82 0/0
Upper Buffalo........................................... 1.89 1.36 44/8 1.62 1.14 0/0
Cumulative (all Class I areas).......................... 12.09 7.71 188/38 10.06 6.44 2/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Martin Lake Unit 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek............................................. 2.81 2.14 85/24 2.23 1.73 2/0
Wichita Mountains....................................... 2.24 1.09 18/3 1.93 0.93 0/0
Upper Buffalo........................................... 2.09 1.51 51/12 1.84 1.30 0/0
Cumulative (all Class I areas).......................... 13.44 8.59 223/48 11.45 7.34 2/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Martin Lake Units 1, 2, and 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek............................................. 6.69 5.27 150/101 5.00 4.07 32/7
Wichita Mountains....................................... 5.49 2.83 51/27 4.57 2.35 3/0
Upper Buffalo........................................... 5.16 3.83 111/70 4.39 3.21 7/0
Cumulative (all Class I areas).......................... 33.79 22.16 521/301 27.91 18.44 47/7
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table 25 shows that the Martin Lake units individually cause or
contribute to visibility impairment at Wichita Mountains, Caney Creek,
and Upper Buffalo on a large number of days. CAMx predicts baseline
impacts for these combined three units to be more than the 0.5 dv
visibility threshold 150 days of the year at Caney Creek, 111 days of
the year at Upper Buffalo, 51 days of the year at Wichita Mountains,
and in total for 209 days per year for the other 12 Class I areas
modeled. The average visibility impact across the top 10 days for the
combined units is more than 5.2 dv at Caney Creek and more than 3.8 dv
at Upper Buffalo. CAMx modeling results indicate that upgrades to
Martin Lake's wet FGD scrubbers to 95 percent control efficiency
installed on each of the units will eliminate all but two days impacted
by each individual unit over 0.5 dv at all Class I areas. When
considering the combined impacts from all three units, the modeling
results show an overall (across all impacted Class I areas) reduction
from 521 days over 0.5 dv in the baseline to a total of 47 days over
the threshold after the scrubber upgrades are installed, for an overall
reduction of more than 90 percent in the number of days over the
threshold. With the modeled scrubber upgrades, the number of days
impacted over 1.0 dv are reduced from 101 days to 7 days at Caney
Creek. Days over the 1.0 dv threshold at all other Class I areas are
eliminated, decreasing from 200 in the baseline to zero with the
scrubber upgrades. At the most impacted Class I Areas, the scrubber
upgrades on each unit will each result in visibility improvements of
approximately 2.0 dv on the most impacted days at Caney Creek, and the
top 10 days average visibility improvement for the individual units is
more than 1.5 dv at Caney Creek. Across all 15 Class I areas, the top
10 days average impact from all three units combined dropped from
baseline of 22.2 dv to 3.7 dv after control upgrades, for an overall
cumulative improvement of approximately 83 percent reduction due to
improved scrubber efficiency. Similarly, across all 15 Class I areas,
the maximum daily impact from scrubber upgrades results in a visibility
improvement of 27.91 dv compared to the 33.79 dv baseline total, which
is a reduction of 83 percent.
As we state elsewhere in this proposal, we estimate scrubber
upgrades at the Martin Lake units to be very cost-effective and less
than $1,200/ton. We conclude that these scrubber upgrades are very
cost-effective and result in very significant visibility benefits,
significantly reducing the impacts from these units and reducing the
number of days that Class I areas are impacted over 1.0 dv and 0.5 dv.
We propose SO2 BART for each Martin Lake unit should be to
upgrade the wet FGD scrubbers to a control efficiency of 95 percent,
with an emission limit of 0.08 lb/MMBtu on a 30 BOD basis. This cost
analysis, the reasons set forth in previous sections regarding the
overall SO2 emissions impact of these units, and the modeled
benefits, support this proposed BART determination.
2. Fayette Units 1 and 2
Fayette Units 1 and 2 are currently equipped with high performing
wet FGDs. Both units have demonstrated the ability to maintain a
SO2 30 Boiler Operating Day (BOD) average below 0.04 lb/
MMBtu for years at a time.\345\ As discussed in Section VII.B.2.a,
retrofit wet FGDs should be evaluated at 98 percent control or no less
than 0.04 lb/MMBtu. Table 26 shows the visibility impacts for the
baseline emissions, the current permitted emission limit (which is
greater than the baseline emission rate), and an emission limit of 0.04
lb/MMBtu (which is representative of controlled emissions with wet
FGD).
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\345\ See our 2023 BART FIP TSD for additional information and
graphs of this data.
[[Page 28977]]
Table 26--CAMx-Predicted Visibility Impacts of Baseline, Permit Limits, and Wet FGD Limit of 0.04 lb/MMBtu for Fayette Units 1 and 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Fayette Units 1 and 2 2016 Baseline impacts Permitted limit (0.2 lb/MMBtu) Wet FGD (0.04 lb/MMBtu)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Number of days
Impact at Number of days Impact at >0.5 dv/number Impact at Number of days
Class I area Class I area >=0.5 dv/>=1.0 Class I area of days >1.0 Class I area >=0.5 dv/>=1.0
(dv) dv (dv) dv (dv) dv
--------------------------------------------------------------------------------------------------------------------------------------------------------
Caney Creek............................................. 0.52 1/0 1.04 11/1 0.52 1/0
Wichita Mountains....................................... 0.34 0/0 1.02 3/1 0.31 0/0
Upper Buffalo........................................... 0.33 0/0 0.73 5/0 0.34 0/0
Cumulative (all 15 Class I areas)....................... 2.24 1/0 5.31 21/2 2.12 1/0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Fayette modeling shows increased visibility impacts when modeling
the existing permit limit (Title V permit level of 0.2 lb/MMBtu to meet
NSPS UUUUU). At this higher permitted rate, the Fayette source would
have visibility impacts greater than 1 dv at Caney Creek and Wichita
Mountains. However, Fayette routinely emits at rates less than this
permit limit. We also modeled wet FGD at 0.04 lb/MMBtu, which these
units already consistently meet on a 30-day BOD basis. The results are
very similar to baseline modeling results reflecting the maximum 24-hr
emissions from 2016-2020, but did result in a slight overall benefit
from baseline conditions. Therefore, we propose that additional
scrubber upgrades for Fayette are not necessary and that Fayette Units
1 and 2 maintain a 30 BOD rolling average SO2 emission rate
of 0.04 lb/MMBtu. We believe that based on their demonstrated ability
to maintain an emission rate below this value on a 30 BOD basis, these
units can consistently achieve this emission level.
C. PM BART
As discussed in Section VI.B, we propose to disapprove the portion
of the Texas Regional Haze SIP that sought to address the BART
requirement for EGUs for PM. We present our analysis of the BART
factors and the potential costs and visibility benefits of PM controls
in Section VII.B.5. All the coal-fired units are either currently
fitted with a baghouse, an ESP and a polishing baghouse, or an ESP. As
part of our BART determination, we propose to conclude that the cost of
retrofitting the subject units (Harrington Unit 061B, Martin Lake
Units, and Fayette Units) with a baghouse would be extremely high
compared to the visibility benefit for any of the units currently
fitted with an ESP. The BART Guidelines state it is permissible to rely
on MACT standards for purposes of BART unless there are new
technologies subsequent to the MACT standards which would lead to cost-
effective increases in the level of control. Because the costs of
installing a baghouse would be extremely high, we propose that PM BART
for the coal-fired units is an emission limit of 0.030 lb/MMBtu along
with work practice standards. This limit is consistent with the MATS
Rule, which establishes an emission standard of 0.030 lb/MMBtu
filterable PM (as a surrogate for toxic non-mercury metals) as
representing MACT for coal-fired EGUs.
For the gas-fired BART unit, W. A. Parish Unit WAP4, there are no
appropriate add-on controls and the status quo reflects the most
stringent controls. We are proposing to make the requirement to burn
pipeline natural gas federally enforceable. We are proposing that PM
BART for W. A. Parish Unit WAP4 is to limit fuel to pipeline natural
gas, as defined at 40 CFR 72.2.
IX. Proposed Action
A. Regional Haze
We are proposing to withdraw the Texas SO2 Trading
Program set forth in 40 CFR part 97 Subpart FFFFF, which constitutes
the FIP provisions the EPA previously promulgated to address
SO2 BART obligations for EGUs in Texas. In its place, we are
proposing to promulgate a FIP as described in this notice and
summarized in this section to address the SO2 BART
requirements for those BART-eligible sources participating in the Texas
SO2 Trading Program. Additionally, as described in Section
VI, we are proposing that our prior approval of the portion of the
Texas Regional Haze SIP related to PM BART for EGUs was in error and
are correcting that through disapproving that portion of the SIP and
promulgating source specific BART requirements to address the
deficiency. Our proposed FIP includes SO2 and PM BART
emission limits for 12 EGUs located at 6 different facilities.
1. SO2 BART
We propose that SO2 BART for the subject-to-BART units
is the following SO2 emission limits to be met on a 30 BOD
period:
Table 27--Proposed SO2 BART Emission Limits
------------------------------------------------------------------------
Proposed SO2
Unit emission limit
(lb/MMBtu)
------------------------------------------------------------------------
Scrubber Upgrades
Martin Lake Unit 1...................................... 0.08
Martin Lake Unit 2...................................... 0.08
Martin Lake Unit 3...................................... 0.08
Emission Limit as BART
Fayette Unit 1.......................................... 0.04
Fayette Unit 2.......................................... 0.04
W A. Parish Unit WAP4 *................................. ..............
Scrubber Retrofits
Harrington 061B......................................... 0.06
Harrington 062B......................................... 0.06
Coleto Creek Unit 1..................................... 0.06
W. A. Parish WAP5....................................... 0.06
W. A. Parish WAP6....................................... 0.06
Welsh Unit 1............................................ 0.06
DSI
Harrington 061B......................................... 0.27 (in the
alternative)
------------------------------------------------------------------------
* For Unit WAP4, BART is to limit fuel use to pipeline natural gas, as
defined at 40 CFR 72.2. As provided for in 40 CFR 72.2, pipeline
natural gas contains 0.5 grains or less of total sulfur per 100
standard cubic feet. This is equivalent to an SO2 emission rate of
0.0006 lb/MMBtu.
We propose that the following sources comply with these limits
within five years of the effective date of our final rule: Coleto Creek
Unit 1; Harrington Units 061B (for a limit consistent with scrubber
retrofit) and 062B; W. A. Parish Units WAP5 and WAP6; and Welsh Unit 1.
This is the maximum amount of time allowed under the Regional Haze Rule
for BART compliance. We based our cost analysis on the installation of
wet FGD and SDA scrubbers for these units, and in past actions we have
typically required that scrubber retrofits under BART be operational
within five years.\346\
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\346\ See 76 FR 81729, 81758 (December 28, 2011) and 81 FR
66332, 66416 (September 27, 2016), where we promulgated regional
haze FIPs for Oklahoma and Arkansas, respectively. These FIPs
required BART SO2 emission limits on coal-fired EGUs
based on new scrubber retrofits with a compliance date of no later
than five years from the effective date of the final rule.
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[[Page 28978]]
We are proposing an alternative BART limit based on DSI at 50
percent for Harrington Unit 061B with a proposed compliance date within
two years of the effective date of our final rule. We believe that two
years is appropriate as the installation of DSI systems is less complex
and time consuming than the construction of a scrubber. We also propose
to require a DSI performance evaluation, as more fully described in
Section IX.A.3, within one year of the effective date of our final
rule. In Section VIII.A.2 we also provide an option for Harrington to
agree as part of this FIP to convert to natural gas by no later than
January 1, 2025.
For Martin Lake Units 1, 2, and 3, we propose that compliance with
these limits be within three years of the effective date of our final
rule. We believe that three years is appropriate for these units, as we
based our cost analysis on upgrading the existing wet FGD scrubbers of
these units, which we believe to be less complex and time consuming
than the construction of a new scrubber.
For Fayette Units 1 and 2, we propose that compliance with these
limits be within one year. We believe that one year is appropriate for
these units because the Fayette units have already demonstrated their
ability to meet these emission limits.
2. Potential Process for Alternative Scrubber Upgrade Emission Limits
In our 2023 BART FIP TSD, we discuss how we calculated the
SO2 removal efficiency of the units we analyzed for scrubber
upgrades. Since we do not have CEMS data for the inlet of the scrubbers
(we only have CEMS data for the outlet of the scrubbers) and we do not
have recent site-specific testing from the facility to more accurately
determine the current control efficiency of the scrubbers, we estimated
the current removal efficiency of each scrubber using formulas. These
formulas utilize the reported sulfur content and tonnages of the fuels
burned at each unit to calculate the theoretical uncontrolled
SO2 emissions. The calculated theoretical uncontrolled
SO2 emissions and CEMS data for the scrubber outlet
SO2 emissions are then used to calculate scrubber
efficiency. Given a lack of updated source-specific information
resulting in an estimated control efficiency based on available fuel
usage and SO2 emissions data, we cannot assure accuracy in
our quantification of scrubber efficiency. However, despite the
potential for inaccurate information regarding scrubber efficiency,
based on the results of our scrubber upgrade cost analysis, we do not
believe that any such error in calculating the true tons of
SO2 removed affects our proposed determination that scrubber
upgrades are cost-effective. Even if we were to make reasonable
adjustments in the tons removed to account for any potential error in
our scrubber efficiency calculation, we would still propose to upgrade
these SO2 scrubbers. We believe we have demonstrated that
upgrading an underperforming SO2 scrubber is one of the most
cost-effective pollution control upgrades a coal-fired power plant can
implement to improve the visibility at Class I areas. However, our
proposed FIP does specify an SO2 emission limit that is
based on 95 percent removal. This is below the upper end of what an
upgraded wet SO2 scrubber can achieve, which is 98-99
percent, as we have noted in our 2023 BART FIP TSD. We believe that a
95 percent control assumption provides an adequate margin of error for
the units for which we have proposed scrubber upgrades, such that they
should be able to comfortably attain the emission limits we have
proposed. However, for the owner of any unit that disagrees with us on
this point, we propose the following:
(1) The affected unit should comment why it believes it cannot
attain the SO2 emission limit we have proposed, based on
a scrubber upgrade that includes the kinds of improvements (e.g.,
elimination of bypass, wet stack conversion, installation of trays
or rings, upgraded spray headers, upgraded ID fans, using all
recycle pumps, etc.) typically included in a scrubber upgrade.
(2) After considering those comments, and responding to all
relevant comments in a final rulemaking action, should we still
require a scrubber upgrade in our final FIP we will provide the
company the following option in the FIP to seek a revised emission
limit after taking the following steps:
(a) Install a CEMS at the inlet to the scrubber.
(b) Pre-approval of a scrubber upgrade plan conducted by a third
party engineering firm that considers the kinds of improvements
(e.g., elimination of bypass, wet stack conversion, installation of
trays or rings, upgraded spray headers, upgraded ID fans, using all
recycle pumps, etc.) typically performed during a scrubber upgrade.
The goal of this plan will be to maximize the unit's overall
SO2 removal efficiency.
(c) Installation of the scrubber upgrades.
(d) Pre-approval of a performance testing plan, followed by the
performance testing itself.
(e) A pre-approved schedule for 2.a through 2.d.
(f) Should we determine that a revision of the SO2
emission limit is appropriate, we will have to propose a
modification to the BART FIP after it has been promulgated. It
should be noted that any proposal to modify the SO2
emission limit will be based largely on the performance testing and
may result in a proposed increase or decrease of that value.
3. DSI Performance Evaluation for Harrington Unit 061B
We are proposing that SO2 BART for Harrington Unit 061B
should be based on the installation of SDA at an emission limit of 0.06
lb/MMBtu based on a 30 BOD and in the alternative, we are proposing
that SO2 BART should be based on DSI at 50 percent control
efficiency at an emission limit of 0.27 lb/MMBtu based on a 30 BOD with
the requirement to conduct a DSI performance evaluation and submit to
the EPA no later than one (1) year from the effective date of our final
rule. We believe Unit 061B is likely capable of achieving an
SO2 emission limit of 0.27 lb/MMBtu with DSI, but are not
certain whether the unit could achieve a lower emission limit on a 30
BOD or what the potential impacts to PM emissions could be at higher
injections rates necessary for higher control efficiencies using the
existing ESP. The purpose of the DSI performance evaluation is to
determine the lowest SO2 emission rate Unit 061B would be
able to sustainably achieve on a 30 BOD with DSI as well as the
potential control efficiencies achievable with upgraded particulate
removal and to determine how compliance with such an emission rate
would impact our cost estimates for DSI. Therefore, as part of the
performance evaluation, we are also proposing to require an estimate of
the costs of DSI for each of the three control scenarios specified in
1.a through 1.c.
Should we require an SO2 emission limit based on DSI for
Harrington Unit 061B in our final FIP, we are proposing the following
requirements for a DSI performance evaluation:
(1) The performance evaluation must be conducted by a third-party
engineering firm and must determine the potential lowest sustainable
SO2 emission rate on a 30 BOD with DSI for each of the
following control scenarios:
(a) DSI with the existing ESP for particulate removal;
(b) DSI with a new ESP installation for particulate removal;
(c) DSI with a new fabric filter installation for particulate
removal.
(2) The performance evaluation must include an estimate of the
costs for each of the three control scenarios specified in 1.a through
1.c. The cost estimates must include a detailed breakdown of the
capital costs and annual operation and maintenance costs for each
control scenario as well as an estimate of the annual SO2
emissions reductions under each control scenario. The cost estimates
should adhere to the costing methodologies recommended in the
[[Page 28979]]
EPA Air Pollution Control Cost Manual.\347\
---------------------------------------------------------------------------
\347\ EPA Air Pollution Control Cost Manual, Seventh Edition,
April 2021 available at https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution#cost%20manual.
---------------------------------------------------------------------------
(3) The facility must submit a detailed report of the performance
evaluation and all supporting documentation to the EPA no later than
one year from the effective date of our final BART FIP.
Based on the DSI performance evaluation, we will determine whether
a revision of the SO2 emission limit for Harrington Unit
061B is appropriate. Should we determine that a revision of the
SO2 emission limit is appropriate, we will propose a
modification to the BART FIP after it has been promulgated.
4. PM BART
We propose that PM BART limits for the coal-fired units, Martin
Lake Units 1, 2, and 3; Coleto Creek Unit 1; W. A. Parish Units WAP5
and WAP6; Welsh Unit 1; Harrington Units 061B and 062B; and Fayette
Units 1 and 2 are 0.030 lb/MMBtu and work practice standards, shown in
Table 28.
Table 28--PM BART Emissions Standards and Work Practice Standards
------------------------------------------------------------------------
Unit type PM BART proposal
------------------------------------------------------------------------
Coal-Fired BART Units..................... 0.030 lb/MMBtu filterable PM
Table 3 to Subpart UUUUU
Gas-Fired Only BART Units................. Pipeline quality natural gas
------------------------------------------------------------------------
We propose that compliance with these emissions standards and work
practice standards be the effective date of our final rule, as the
affected facilities should already be meeting them.
We propose that PM BART for W. A. Parish WAP4 is to limit fuel to
pipeline natural gas, as defined at 40 CFR 72.2.
B. CSAPR Better-Than-BART
We propose that, if this proposal to implement source-specific BART
requirements at certain EGUs in Texas is finalized, the EPA's
analytical basis for our 2017 CSAPR Better-than-BART determination will
be restored,\348\ which concluded that implementation of CSAPR in the
remaining covered States will continue to meet the criteria for a BART
alternative. This will also resolve the claims in the 2017 and 2020
petitions for consideration. We are therefore proposing to deny the
2020 petition for partial reconsideration of our September 2017 Final
Rule affirming 40 CFR 51.308(e)(4) and our subsequent 2020 denial of a
2017 petition for reconsideration of that rule. This proposed
reaffirmation will allow the continued reliance on CSAPR participation
as a BART alternative for BART-eligible EGUs for a given pollutant in
States whose EGUs continue to participate in a CSAPR trading program
for that pollutant.
---------------------------------------------------------------------------
\348\ 82 FR 45481.
---------------------------------------------------------------------------
X. Environmental Justice Considerations
The EPA defines environmental justice (EJ) as ``the fair treatment
and meaningful involvement of all people regardless of race, color,
national origin, or income with respect to the development,
implementation, and enforcement of environmental laws, regulations, and
policies.'' The EPA further defines the term fair treatment to mean
that ``no group of people should bear a disproportionate burden of
environmental harms and risks, including those resulting from the
negative environmental consequences of industrial, governmental, and
commercial operations or programs and policies.'' \349\ Recognizing the
importance of these considerations to local communities, the EPA
conducted an environmental justice screening analysis around the
location of the facilities associated with this action to identify
potential environmental stressors on these communities and the
potential impacts of this action. However, the EPA is providing the
information associated with this analysis for informational purposes
only. The information provided herein is not a basis of the proposed
action.
---------------------------------------------------------------------------
\349\ See https://www.epa.gov/environmentaljustice/learn-about-environmental-justice.
---------------------------------------------------------------------------
The EPA conducted the screening analyses using EJScreen, an EJ
mapping and screening tool that provides the EPA with a nationally
consistent dataset and approach for combining various environmental and
demographic indicators.\350\ The EJScreen tool presents these
indicators at a Census block group (CBG) level or a larger user-
specified ``buffer'' area that covers multiple CBGs.\351\ An individual
CBG is a cluster of contiguous blocks within the same census tract and
generally contains between 600 and 3,000 people. EJScreen is not a tool
for performing in-depth risk analysis, but is instead a screening tool
that provides an initial representation of indicators related to EJ and
is subject to uncertainty in some underlying data (e.g., some
environmental indicators are based on monitoring data which are not
uniformly available; others are based on self-reported data).\352\ For
informational purposes, we have summarized EJScreen data within larger
``buffer'' areas covering multiple block groups and representing the
average resident within the buffer areas surrounding the BART
facilities. EJScreen environmental indicators help screen for locations
where residents may experience a higher overall pollution burden than
would be expected for a block group with the same total population in
the U.S. These indicators of overall pollution burden include estimates
of ambient particulate matter (PM2.5) and ozone
concentration, a score for traffic proximity and volume, percentage of
pre-1960 housing units (lead paint indicator), and scores for proximity
to Superfund sites, risk management plan (RMP) sites, and hazardous
waste facilities.\353\ EJScreen also provides information on
demographic indicators, including percent low-income, communities of
color, linguistic isolation, and less than high school education.
---------------------------------------------------------------------------
\350\ The EJSCREEN tool is available at https://www.epa.gov/ejscreen.
\351\ See https://www.census.gov/programs-surveys/geography/about/glossary.html.
\352\ In addition, EJSCREEN relies on the five-year block group
estimates from the U.S. Census American Community Survey. The
advantage of using five-year over single-year estimates is increased
statistical reliability of the data (i.e., lower sampling error),
particularly for small geographic areas and population groups. For
more information, see https://www.census.gov/content/dam/Census/library/publications/2020/acs/acs_general_handbook_2020.pdf.
\353\ For additional information on environmental indicators and
proximity scores in EJSCREEN, see ``EJSCREEN Environmental Justice
Mapping and Screening Tool: EJSCREEN Technical Documentation,''
Chapter 3 and Appendix C (September 2019) at https://www.epa.gov/sites/default/files/2021-04/documents/ejscreen_technical_document.pdf.
---------------------------------------------------------------------------
The EPA prepared EJScreen reports covering buffer areas of
approximately 6-mile radii around the BART facilities. From those
reports, one BART facility, Harrington Station, showed EJ indices
greater than the 80th national percentiles,\354\ which were for ozone,
lead paint, and RMP facility proximity, none of which are regulated by
this proposed action. No BART facility showed an EJ index greater than
80th national percentile for PM2.5, diesel particulate
matter, air toxics cancer risk, air toxics respiratory hazard index,
traffic proximity, hazardous waste site proximity, underground storage
tanks,
[[Page 28980]]
or wastewater discharge. The full, detailed EJScreen reports are
provided in the docket for this rulemaking.
---------------------------------------------------------------------------
\354\ For a place at the 80th percentile nationwide, that means
20% of the U.S. population has a higher value. EPA identified the
80th percentile filter as an initial starting point for interpreting
EJScreen results. The use of an initial filter promotes consistency
for EPA programs and regions when interpreting screening results.
---------------------------------------------------------------------------
This action is proposing to promulgate a FIP to address BART
requirements that are not adequately satisfied by the Texas Regional
Haze SIP. The proposed rule is proposing SO2 and PM BART
limits on EGUs in Texas to fulfill regional haze program requirements
and additionally disapproving portions of the Texas Regional Haze SIP
related to PM BART. Exposure to PM and SO2 is associated
with significant public health effects. Short-term exposures to
SO2 can harm the human respiratory system and make breathing
difficult. People with asthma, particularly children, are sensitive to
these effects of SO2.\355\ Exposure to PM can affect both
the lungs and heart and is associated with: premature death in people
with heart or lung disease, nonfatal heart attacks, irregular
heartbeat, aggravated asthma, decreased lung function, and increased
respiratory symptoms, such as irritation of the airways, coughing or
difficulty breathing. People with heart or lung diseases or conditions,
children, and older adults are the most likely to be affected by PM
exposure.\356\ Therefore, we expect that these requirements for EGUs in
Texas, if finalized, and resulting emissions reductions will contribute
to reduced environmental and health impacts on all populations impacted
by emissions from these sources, including populations experiencing a
higher overall pollution burden, people of color and low-income
populations. There is nothing in the record which indicates that this
proposed action, if finalized, would have disproportionately high or
adverse human health or environmental effects on communities with
environmental justice concerns.
---------------------------------------------------------------------------
\355\ See https://www.epa.gov/so2-pollution/sulfur-dioxide-basics#effects.
\356\ See https://www.epa.gov/pm-pollution/health-and-environmental-effects-particulate-matter-pm.
---------------------------------------------------------------------------
XI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Overview
This action is exempt from review by the Office of Management and
Budget (OMB) because the proposed FIP, if finalized, would not
constitute a rule of general applicability, as it proposes source
specific requirements for electric generating units at six different
facilities located in Texas.
B. Paperwork Reduction Act
This action does not impose any new information collection burden
under the PRA. OMB has previously approved the information collection
activities contained in the existing regulations and has assigned OMB
control number 2060-0667. Because the proposed source specific BART
emission limits apply to only six different facilities, the Paperwork
Reduction Act does not apply. See 5 CFR 1320.3(c).
Additionally, the proposed withdrawal of the Texas SO2
Trading Program does not impose any new or revised information
collection burden under the provisions of the Paperwork Reduction Act
(PRA), 44 U.S.C. 3501 et seq. OMB has previously approved the
information collection activities for the Texas SO2 Trading
Program as part of the most recent information collection request
renewal for the CSAPR trading programs, which was assigned OMB control
number 2060-0667. The withdrawal of the Texas SO2 Trading
Program does not change any collection requests required as part of the
CSAPR trading programs. Furthermore, the withdrawal of the Texas
SO2 Trading Program will cause no change in information
collection burden related to SO2 requirements because the
sources that are currently participating in the Texas SO2
Trading Program have the same SO2 monitoring and reporting
requirements under the Acid Rain Program. Thus, the withdrawal of the
Texas SO2 Trading Program proposed in this action will not
change any collection burden that these sources are subject to under
either the CSAPR trading programs or the Acid Rain Program.
C. Regulatory Flexibility Act
I certify that this action will not have a significant impact on a
substantial number of small entities under the RFA. This action will
not impose any requirements on small entities. The proposed FIP action,
if finalized, will apply to EGUs at six facilities, none of which are
small entities as defined by the RFA.
D. Unfunded Mandates Reform Act
The EPA has determined that Title II of UMRA does not apply to this
proposed rule. In 2 U.S.C. 1502(1) all terms in Title II of UMRA have
the meanings set forth in 2 U.S.C. 658, which further provides that the
terms ``regulation'' and ``rule'' have the meanings set forth in 5
U.S.C. 601(2). Under 5 U.S.C. 601(2), ``the term `rule' does not
include a rule of particular applicability relating to . . .
facilities.'' Because this proposed rule is a rule of particular
applicability relating to specific EGUs located at six named
facilities, the EPA has determined that it is not a ``rule'' for the
purposes of Title II of UMRA.
E. Executive Order 13132: Federalism
This proposed action does not have federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This proposed rule does not have tribal implications, as specified
in Executive Order 13175. It will not have substantial direct effects
on tribal governments. Thus, Executive Order 13175 does not apply to
this rule.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks
that EPA has reason to believe may disproportionately affect children,
per the definition of ``covered regulatory action'' in section 2-202 of
the Executive Order. Therefore, this action is not subject to Executive
Order 13045 because it does not concern an environmental health risk or
safety risk. Since this action does not concern human health, EPA's
Policy on Children's Health also does not apply.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This proposed action is not subject to Executive Order 13211 (66 FR
28355 (May 22, 2001)), because it is not a significant regulatory
action under Executive Order 12866.
I. National Technology Transfer and Advancement Act
Section 12 of the National Technology Transfer and Advancement Act
(NTTAA) of 1995 requires Federal agencies to evaluate existing
technical standards when developing a new regulation. To comply with
NTTAA, the EPA must consider and use ``voluntary consensus standards''
(VCS) if available and applicable when developing programs and policies
unless doing so would be inconsistent with applicable law or otherwise
impractical. The EPA
[[Page 28981]]
believes that VCS are inapplicable to this action. This action does not
require the public to perform activities conducive to the use of VCS.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) directs
Federal agencies, to the greatest extent practicable and permitted by
law, to make environmental justice part of their mission by identifying
and addressing, as appropriate, disproportionately high and adverse
human health or environmental effects of their programs, policies, and
activities on minority populations (people of color and/or Indigenous
peoples) and low-income populations.
The EPA believes that the human health or environmental conditions
that exist prior to this action have the potential to result in
disproportionate and adverse human health or environmental effects on
people of color, low-income populations and/or Indigenous peoples. As
explained further in Section X, the EPA's screening analysis provides
an assessment of indicators related to environmental justice and
overall pollution burden and demonstrates the potential for
disproportionate and adverse effects on the areas located near at least
one of the facilities subject to this action.
The EPA believes that this action, if finalized, is not likely to
change the human health or environmental conditions, unrelated to
SO2 emissions, that exist prior to this action and that have
the potential to result in disproportionate and adverse human health or
environmental effects on people of color, low-income populations and/or
Indigenous peoples. For example, this action is not expected to reduce
potential community impacts associated with ozone, lead paint, or RMP
facility status. However, the action, if finalized, is expected to
reduce any potential existing disproportionate and adverse effects
associated with SO2 emissions from the sources covered by
this action. This action, if finalized, will significantly reduce
SO2 emissions in the State of Texas, which is anticipated to
improve air quality. The analyses and proposed requirements included in
this proposed rulemaking are consistent with and commensurate with the
Regional Haze Rule and how that rule functions. As discussed in Section
X, exposure to SO2 is associated with significant public
health effects.
For informational purposes in a manner consistent with both the CAA
and E.O. 12898, the EPA conducted an EJScreen analysis, considered a
large radius around the BART facilities as well as environmental
indicators beyond the scope of this action, as discussed in Section X.
The EPA intends to promote fair treatment and provide meaningful
involvement in developing the final action through the public notice
and comment process. This will include a virtual public hearing and
public comment period, as well as additional outreach to promote public
engagement. Information related to this action will be available on the
EPA's website as well as in the docket for this action.
The information supporting this Executive Order review is contained
in Section X of this Preamble as well as throughout the Preamble, and
all supporting documents have been placed in the public docket for this
action.
K. Determinations Under CAA Section 307(b)(1) and (d)
Section 307(b)(1) of the CAA governs judicial review of final
actions by the EPA. This section provides, in part, that petitions for
review must be filed in the U.S. Court of Appeals for the D.C. Circuit:
(i) when the agency action consists of ``nationally applicable
regulations promulgated, or final actions taken, by the
Administrator,'' or (ii) when such action is locally or regionally
applicable, but ``such action is based on a determination of nationwide
scope or effect and if in taking such action the Administrator finds
and publishes that such action is based on such a determination.'' For
locally or regionally applicable final actions, the CAA reserves to the
Administrator complete discretion whether to invoke the exception in
(ii).
This proposed action, if finalized, will be ``nationally
applicable'' within the meaning of CAA section 307(b)(1). As set forth
in Section V, the EPA proposes to deny the 2020 petition for partial
reconsideration of our September 2017 Final Rule affirming 40 CFR
51.308(e)(4) and our subsequent 2020 denial of a 2017 petition for
reconsideration of that rule. This denial, if finalized, will once
again reaffirm the continued validity of the CSAPR better-than-BART
provision at 40 CFR 51.308(e)(4), which is a nationally applicable
regulation. The EPA's proposed denial of the 2020 petition for partial
reconsideration is dependent on the EPA's promulgation of source-
specific BART emissions limits in Texas. As explained in Section IV,
the proposed withdrawal of the Texas SO2 Trading Program and
proposed adoption of source-specific BART limits for EGUs in Texas
allows the EPA to restore the analytical basis for 40 CFR 51.308(e)(4),
as set forth in our September 2017 Final Rule affirming the 2012 CSAPR
better-than-BART determination. The CSAPR better-than-BART provision at
40 CFR 51.308(e)(4) allows States covered by a CSAPR trading program in
40 CFR 52.38 or 52.39 (or a SIP-approved trading program meeting these
requirements) to implement those trading programs in lieu of source-
specific BART limits for BART-eligible EGU sources. Currently, 19
States located across five of the ten EPA regions and in seven judicial
circuits are included in at least one of the CSAPR trading programs and
rely on these programs in lieu of source-specific BART, pursuant to 40
CFR 51.308(e)(4). The EPA's restoration of the analytical basis for 40
CFR 51.308(e)(4) would thus affect all of these States and BART-
eligible EGU sources located in these States.
In the alternative, to the extent a court finds this proposal, if
finalized, to be locally or regionally applicable, the Administrator
intends to exercise the complete discretion afforded to him under the
CAA to make and publish a finding that this action is based on a
determination of ``nationwide scope or effect'' within the meaning of
CAA section 307(b)(1).\357\ First, this proposed action, if finalized,
would be based on a determination of nationwide scope or effect for the
same reasons identified above with respect to this action being
``nationally applicable''--namely, because it would reaffirm the
validity of 40 CFR 51.308(e)(4). Currently, 19 States would be directly
affected by our decision to reaffirm the continued validity of the
CSAPR better-than-BART provision at 40 CFR 51.308(e)(4), and these
States represent a wide geographic area falling within nine different
judicial circuits.\358\ Second, underlying the EPA's decision to
reaffirm the validity of 40 CFR 51.308(e)(4) is our proposed action to
withdraw the Texas SO2 Trading Program and instead to
[[Page 28982]]
adopt source-specific BART limits for SO2 at the relevant
Texas EGU sources, together with PM BART limits as part of a complete
BART analysis that is required by the withdrawal of the Texas
SO2 Trading Program as a BART alternative, as explained in
Section IV. Thus, the source-specific BART control program for Texas is
a necessary component of the proposed action because it provides the
basis for the reaffirmation of our conclusion that CSAPR serves as an
alternative to BART for EGU sources located in over half the States in
the country. As explained in Section V, our proposed reaffirmation of
the CSAPR better-than-BART provision depends on our finalization and
implementation of source-specific BART emissions limits for BART-
eligible EGUs in Texas, thus achieving (among other things)
SO2 emissions reductions comparable to the assumptions used
in the September 2017 Final Rule affirming the 2012 CSAPR better-than-
BART determination.
---------------------------------------------------------------------------
\357\ In deciding whether to invoke the exception by making and
publishing a finding that an action is based on a determination of
nationwide scope or effect, the Administrator takes into account a
number of policy considerations, including his judgment balancing
the benefit of obtaining the D.C. Circuit's authoritative
centralized review versus allowing development of the issue in other
contexts and the best use of agency resources.
\358\ In the report on the 1977 Amendments that revised CAA
section 307(b)(1), Congress noted that the Administrator's
determination that the ``nationwide scope or effect'' exception
applies would be appropriate for any action that has a scope or
effect beyond a single judicial circuit. See H.R. Rep. No. 95-294 at
323-24, reprinted in 1977 U.S.C.C.A.N. 1402-03.
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The Administrator intends to find that this is a matter on which
national uniformity is desirable, to take advantage of the D.C.
Circuit's administrative law expertise, and to facilitate the orderly
development of the basic law under the Act. The Administrator also
intends to find that consolidated review of this action in the D.C.
Circuit will avoid piecemeal litigation in the regional circuits,
further judicial economy, and eliminate the risk of inconsistent
results for different States, and that a nationally consistent approach
to implementation of CSAPR trading programs at EGUs nationwide to
satisfy BART requirements constitutes the best use of agency resources.
For these reasons, this action, if finalized, will be nationally
applicable or, alternatively, the Administrator intends to exercise the
complete discretion afforded to him under the CAA to make and publish a
finding that this action is based on a determination of nationwide
scope or effect for purposes of CAA section 307(b)(1).
This proposed action is subject to the provisions of section
307(d). CAA section 307(d)(1)(B) provides that section 307(d) applies
to, among other things, ``the promulgation or revision of an
implementation plan by the Administrator under [CAA section 110(c)].''
42 U.S.C. 7407(d)(1)(B). This action, if finalized, among other things,
promulgates a Federal implementation plan pursuant to the authority of
section 110(c). To the extent any portion of this proposed action is
not expressly identified under section 307(d)(1)(B), the Administrator
determines that the provisions of section 307(d) apply to this proposed
action. See CAA section 307(d)(1)(V) (the provisions of section 307(d)
apply to ``such other actions as the Administrator may determine'').
List of Subjects
40 CFR Part 52
Environmental protection, Air pollution control, Incorporation by
reference, Intergovernmental relations, Nitrogen dioxide, Particulate
matter, Reporting and recordkeeping requirements, Sulfur dioxides,
Visibility, Interstate transport of pollution, Regional haze, Best
available retrofit technology.
40 CFR Part 78
Environmental protection, Administrative practice and procedure,
Air pollution control, Reporting and recordkeeping requirements, Sulfur
dioxides.
40 CFR Part 97
Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Nitrogen dioxide,
Reporting and recordkeeping requirements, Sulfur dioxides.
Michael S. Regan,
Administrator.
For the reasons stated in the preamble, the EPA proposes to amend
40 CFR parts 52, 78 and 97 as follows:
PART 52--APPROVAL AND PROMULGATION OF IMPLEMENTATION PLANS
0
1. The authority citation for part 52 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart SS--Texas
Sec. 52.2270 [Amended]
0
2. Section 52.2270 is amended in the second table in paragraph (e),
titled ``EPA Approved Nonregulatory Provisions and Quasi-Regulatory
Measures in the Texas SIP,'' by removing the entry ``Texas Regional
Haze BART Requirement for EGUs for PM''.
0
3. Section 52.2287 is added to subpart SS to read as follows:
Sec. 52.2287 Best Available Retrofit Requirements (BART) for
SO2 and Particulate Matter; What are the FIP requirements
for visibility protection?
(a) Applicability. The provisions of this section shall apply to
each owner or operator, or successive owners or operators, of the coal
or natural gas burning equipment designated below.
(b) Definitions. All terms used in this part but not defined herein
shall have the meaning given them in the CAA and in parts 51 and 60 of
this subchapter. For the purposes of this section:24-hour period means
the period of time between 12:01 a.m. and 12 midnight.
Air pollution control equipment includes selective catalytic
control units, baghouses, particulate or gaseous scrubbers, and any
other apparatus utilized to control emissions of regulated air
contaminants that would be emitted to the atmosphere.
Boiler-operating-day means any 24-hour period between 12 midnight
and the following midnight during which any fuel is combusted at any
time at the steam generating unit.
Daily average means the arithmetic average of the hourly values
measured in a 24-hour period.
Heat input means heat derived from combustion of fuel in a unit and
does not include the heat input from preheated combustion air,
recirculated flue gases, or exhaust gases from other sources. Heat
input shall be calculated in accordance with 40 CFR part 75.
Owner or Operator means any person who owns, leases, operates,
controls, or supervises any of the coal or natural gas burning
equipment designated below.
PM means particulate matter.
Regional Administrator means the Regional Administrator of EPA
Region 6 or his/her authorized representative.
Unit means one of the natural gas or coal-fired units covered in
this section.
(c) Emissions Limitations and Compliance Dates for SO2.
The owner/operator of the units listed in table 1 to paragraph (c)(1)
of this section shall not emit or cause to be emitted pollutants in
excess of the following limitations from the subject unit. Compliance
with the requirements of this section is required as listed below
unless otherwise indicated by compliance dates contained in specific
provisions.
(1) Coal-Fired Units:
Table 1 to Paragraph (c)(1)
------------------------------------------------------------------------
Proposed
SO2 Compliance date (from
Unit emission the effective date of
limit (lb/ the final rule)
MMBtu)
------------------------------------------------------------------------
Martin Lake 1...................... 0.08 3 years.
Martin Lake 2...................... 0.08 3 years.
Martin Lake 3...................... 0.08 3 years.
Coleto Creek 1..................... 0.06 5 years.
Fayette 1.......................... 0.04 1 year.
Fayette 2.......................... 0.04 1 year.
Harrington 061B.................... 0.06 5 years.
Harrington 062B.................... 0.06 5 years.
W. A. Parish WAP5.................. 0.06 5 years.
W. A. Parish WAP6.................. 0.06 5 years.
Welsh 1............................ 0.06 5 years.
------------------------------------------------------------------------
[[Page 28983]]
(2) W. A. Parish WAP4 shall burn only pipeline natural gas, as
defined in 40 CFR 72.2. Compliance for this unit shall be as of
[EFFECTIVE DATE OF FINAL RULE].
(d) Emissions Limitations and Compliance Dates for PM. The owner/
operator of the units listed below shall not emit or cause to be
emitted pollutants in excess of the following limitations from the
subject unit. Compliance with the requirements of this section is
required as listed below unless otherwise indicated by compliance dates
contained in specific provisions.
(1) Coal-Fired Units at Martin Lake Units 1, 2, and 3; Coleto Creek
Unit 1; W. A. Parish WAP5 and WAP6; Welsh Unit 1; Harrington Units 061B
and 062B; and Fayette Units 1 and 2.
(i) Normal operations: Filterable PM limit of 0.030 lb/MMBtu.
(ii) Work practice standards specified in 40 CFR part 63, subpart
UUUUU, Table 3, and using the relevant definitions in 63.10042.
(2) W. A. Parish WAP4 shall burn only pipeline natural gas, as
defined in 40 CFR 72.2.
(3) Compliance for the units included in paragraph (d) of this
section shall be as of [EFFECTIVE DATE OF FINAL RULE].
(e) Testing and monitoring. (1) No later than the compliance date
of this regulation, the owner or operator shall install, calibrate,
maintain and operate Continuous Emissions Monitoring Systems (CEMS) for
SO2 on the units covered under paragraph (c)(1) of this
section. Compliance with the emission limits for SO2 for
those units covered under paragraph (c)(1) shall be determined by using
data from a CEMS.
(2) Continuous emissions monitoring shall apply during all periods
of operation of the units covered under paragraph (c)(1) of this
section, including periods of startup, shutdown, and malfunction,
except for CEMS breakdowns, repairs, calibration checks, and zero and
span adjustments. Continuous monitoring systems for measuring
SO2 and diluent gas shall complete a minimum of one cycle of
operation (sampling, analyzing, and data recording) for each successive
15-minute period. Hourly averages shall be computed using at least one
data point in each fifteen minute quadrant of an hour. Notwithstanding
this requirement, an hourly average may be computed from at least two
data points separated by a minimum of 15 minutes (where the unit
operates for more than one quadrant in an hour) if data are unavailable
as a result of performance of calibration, quality assurance,
preventive maintenance activities, or backups of data from data
acquisition and handling system, and recertification events. When valid
SO2 pounds per hour, or SO2 pounds per million
Btu emission data are not obtained because of continuous monitoring
system breakdowns, repairs, calibration checks, or zero and span
adjustments, emission data must be obtained by using other monitoring
systems approved by the EPA to provide emission data for a minimum of
18 hours in each 24-hour period and at least 22 out of 30 successive
boiler operating days.
(3) Compliance with the requirement for the unit covered under
paragraphs (c)(2) and (d)(2) of this section shall be determined from
documentation demonstrating the use of pipeline natural gas as defined
in 40 CFR 72.2.
(4) Compliance with the PM emission limits for units in paragraph
(d)(1) of this section shall be demonstrated by the filterable PM
methods specified in 40 CFR part 63, subpart UUUUU, table 7.
(f) Reporting and Recordkeeping Requirements. Unless otherwise
stated all requests, reports, submittals, notifications, and other
communications to the Regional Administrator required by this section
shall be submitted, unless instructed otherwise, to the Director, Air
and Radiation Division, U.S. Environmental Protection Agency, Region 6,
to the attention of Mail Code: ARD, at 1201 Elm Street, Suite 500,
Dallas, Texas 75270. For each unit subject to the emissions limitation
in this section and upon completion of the installation of CEMS as
required in this section, the owner or operator shall comply with the
following requirements:
(1) For each SO2 emission limit in paragraph (c)(1) of
this section, comply with the notification, reporting, and
recordkeeping requirements for CEMS compliance monitoring in 40 CFR
60.7(c) and (d).
(2) For each day, provide the total SO2 emitted that day
by each emission unit covered under paragraph (c)(1) of this section.
For any hours on any unit where data for hourly pounds or heat input is
missing, identify the unit number and monitoring device that did not
produce valid data that caused the missing hour.
(3) For the unit covered under paragraphs (c)(2) and (d)(2) of this
section, records sufficient to demonstrate that the fuel for the unit
is pipeline natural gas.
(4) Records for demonstrating compliance with the SO2
and PM emission limitations in this section shall be maintained for at
least five years.
(g) Equipment operations. At all times, including periods of
startup, shutdown, and malfunction, the owner or operator shall, to the
extent practicable, maintain and operate the unit including associated
air pollution control equipment in a manner consistent with good air
pollution control practices for minimizing emissions. Determination of
whether acceptable operating and maintenance procedures are being used
will be based on information available to the Regional Administrator
which may include, but is not limited to, monitoring results, review of
operating and maintenance procedures, and inspection of the unit.
(h) Enforcement. (1) Notwithstanding any other provision in this
implementation plan, any credible evidence or information relevant as
to whether the unit would have been in compliance with applicable
requirements if the appropriate performance or compliance test had been
performed, can be used to establish whether or not the owner or
operator has violated or is in violation of any standard or applicable
emission limit in the plan.
(2) Emissions in excess of the level of the applicable emission
limit or requirement that occur due to a malfunction shall constitute a
violation of the applicable emission limit.
0
4. Section 52.2304 is amended by revising the paragraph (f) heading and
adding paragraph (f)(3) to read as follows:
Sec. 52.2304 Visibility protection.
* * * * *
(f) Measures Addressing Disapproval Associated with NOX, SO2, and
PM. * * *
(3) The deficiencies associated with PM with respect to best
available retrofit technology under section 169A of the Clean Air Act,
as identified in EPA's disapproval of the regional haze plan submitted
by Texas on March 31, 2009, are satisfied by Sec. 52.2287.
0
5. Section 52.2312 is amended by revising paragraph (a) and removing
and reserving paragraph (b).
The revision reads as follows:
Sec. 52.2312 Requirements for the control of SO2 emissions to address
in full or in part requirements related to BART, reasonable progress,
and interstate visibility transport.
(a) The Texas source-specific BART limits set forth in Sec.
52.2287 constitute the Federal Implementation Plan provisions fully
addressing Texas' obligations with respect to best available retrofit
technology under section 169A of the Act and the deficiencies
associated with EPA's disapprovals in
[[Page 28984]]
Sec. 52.2304(d) and partially addressing Texas' obligations with
respect to reasonable progress under section 169A of the Act, as those
obligations relate to emissions of sulfur dioxide (SO2) from
electric generating units (EGUs).
* * * * *
PART 78--APPEAL PROCEDURES
0
6. The authority citation for part 78 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Sec. 78.1 [Amended]
0
7. Section 78.1 is amended in paragraph (a)(1)(i)(D) by removing
``FFFFF,'' and by removing and reserving paragraph (b)(18).
Sec. 78.3 [Amended]
0
8. Section 78.3 is amended in paragraphs (a)(4), (c)(7)(iv), and
(d)(2)(iv) by removing ``FFFFF,'' and in paragraph (d)(6) by removing
``FFFFF,'' and ``Sec. 97.906,''.
Sec. 78.4 [Amended]
0
9. Section 78.4 is amended:
0
a. In paragraph (a)(1)(iv)(A), by removing ``CSAPR SO2 Group
2 unit or CSAPR SO2 Group 2 source, or Texas SO2
Trading Program unit or Texas SO2 Trading Program source''
and adding in its place ``or CSAPR SO2 Group 2 unit or CSAPR
SO2 Group 2 source''; and
0
b. In paragraph (a)(1)(iv)(B), by removing ``CSAPR SO2 Group
2 allowances, or Texas SO2 Trading Program allowances'' and
adding in its place ``or CSAPR SO2 Group 2 allowances''.
PART 97--FEDERAL NOX BUDGET TRADING PROGRAM, CAIR NOX AND SO2
TRADING PROGRAMS, AND CSAPR NOX AND SO2 TRADING PROGRAMS
0
10. The authority citation for part 97 is revised to read as follows:
Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et
seq.
0
11. Revise the heading for part 97 to read as set forth above.
Subpart FFFFF--[Removed and Reserved]
0
12. Remove and reserve subpart FFFFF, consisting of Sec. Sec. 97.901
through 97.935.
[FR Doc. 2023-08732 Filed 5-2-23; 8:45 am]
BILLING CODE 6560-50-P