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

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

burned in 2016-2020, 95 percent control would equate to an emission
rate of 0.08 lb/MMBtu for each unit.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

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.
---------------------------------------------------------------------------

    \255\ The cost calculation spreadsheets can be found in the
docket for this action under the heading ``Cost Calculations''.
---------------------------------------------------------------------------

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

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.
---------------------------------------------------------------------------

    \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

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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

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

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.

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

    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.

                                           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.

    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.
---------------------------------------------------------------------------

    \297\ www.eia.gov/electricity/data/eia860/.
---------------------------------------------------------------------------

    The particulate matter control efficiency of ESPs varies somewhat
with design, resistivity of the particulate

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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

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

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