technology review); Chromium Electroplating, 77 FR 58225, 58226
(Sept. 19, 2012) (considered total annual costs and capital costs in
technology review); Oil and Natural Gas, 77 FR 49490, 49523 (Aug.
16, 2012) (considered total capital costs and annualized costs and
capital costs in technology review). C.f. NRDC v. EPA, 749 F.3d
1055, 1060 (D.C. Cir. 2014 . . .
---------------------------------------------------------------------------

    For this proposal, the costs--either the annual control cost
estimates presented above in Table 3 or the projected total annual
system-wide compliance costs presented in Table 3-4 in the RIA--
represent a very small fraction of typical capital and total
expenditures for the power sector. In the 2022 Proposal (reaffirming
the appropriate and necessary finding), the EPA evaluated the
compliance costs that were projected in the 2012 MATS rule relative to
the typical annual revenues, capital expenditures, and total (capital
and production) expenditures.\26\ (January 11, 2022); 80 FR 37381 (June
30, 2015). Using electricity sales data from the U.S. EIA, the analysis
in the 2022 Proposal demonstrated that revenues from retail electricity
sales increased from $276.2 billion in 2000 to a peak of $356.6 billion
in 2008 (an increase of about 29 percent during this period) and have
slowly declined since to a post-2011 low of $331.0 billion in 2019 (a
decrease of about 7 percent from its peak during this period) in 2007
dollars. The annual control cost estimates for this proposal based on
the cost-effectiveness analysis in Table 3 constitute at most about 0.2
percent of sector sales at their lowest over the 2000 to 2019 period.
Making similar comparisons of the estimated capital and total
compliance costs to historical trends in sector-level capital and
production costs, respectively, would yield similarly small values.
Because this cost-effectiveness evaluation only considers improved fPM
control needed at a few units and not the entire fleet, we also
evaluated an alternative cost-effectiveness approach that considers
allowable emissions, assuming emission reductions achieved if all
evaluated EGUs emit the maximum allowable amount of fPM (i.e., at the
current standard of 3.0E-02 lb/MMBtu), and the associated costs for
EGUs to comply with the three potential fPM standards. Using this
approach, the EPA estimates the cost-effectiveness (based on allowable
rather than actual emissions) of control of non-Hg HAP metals to range
from $35,400/ton to $49,100/ton for a 1.5E-02 lb/MMBtu emission limit,
from $197,000/ton to $238,000/ton for a 1.0E-02 lb/MMBtu emission
limit, and $1,610,000/ton for a 6.0E-03 lb/MMBtu emission limit.
---------------------------------------------------------------------------

    \26\ See Cost TSD for 2022 Proposal at Docket ID No. EPA-HQ-OAR-
2018-0794-4620 at regulations.gov.
---------------------------------------------------------------------------

    The EPA strives to minimize the uncertainty and the costs
associated with the measurements used to demonstrate compliance with
emission limits. For fPM measurements, the EPA believes that
appropriate approaches to minimizing both uncertainty and costs would
include limiting sampling times to 3 hours per run and maintaining the
random error contribution to the tolerance given to PM CEMS--which is
one component of uncertainty--consistent with that of existing fPM
emission limits. The impact of sampling times and random errors on
measurable emission limits is described in the ``PM CEMS Random Error
Contribution by Emission Limit'' memorandum, available in the
rulemaking docket. The

EPA believes that available PM CEMS will be able to accurately measure
the proposed fPM emission limit of 1.0E-02 lb/MMBtu, as the average
random error contribution is under that of existing emission limits.
Although sources have reported fPM values as low as 2.0E-04 lb/MMBtu,
given the 3-hour sampling duration and the current fPM detection limit,
the EPA currently believes, as described in the memorandum, that some
PM CEMS may struggle to meet the EPA's guideline for average random
error contribution to the PM CEMS tolerance to demonstrate compliance
with a fPM emission limit of 6.0E-03 lb/MMBtu or lower. The EPA
solicits comment on the implications for the costs of measuring
emissions to demonstrate compliance--whether through stack testing or
PM CEMS--of alternate emission limits set at or below 6.0E-03 lb/MMBtu
as compared to the proposed fPM emission limit of 1.0E-02 lb/MMBtu,
including run durations, fPM detection levels, and random error
calculations.
    The EPA seeks comment broadly on how we should consider costs in
the context of this rule. Taking all of the foregoing discussion into
account, the EPA believes that the middle option, a limit of 1.0E-02
lb/MMBtu best balances the critical importance of reducing hazardous
emissions pursuant to the EPA's statutory obligations under CAA section
112(d)(6) and ensuring that the worst performers are required to
perform at the level of the remainder of the fleet with the costs of
doing so in the context of this industry. Considering all the cost
metrics, the EPA believes that the cost of the proposed standards is
reasonable, and modest in the context of this industry. Based on the
foregoing discussion and these analyses, the EPA is proposing to revise
the fPM emission limit, as a surrogate for the total non-Hg metal HAP,
to 1.0E-02 lb/MMBtu as supported by our analyses of technical
feasibility, control costs, cost-effectiveness, and economics. The EPA
believes this standard appropriately balances CAA section 112's
direction to achieve the maximum degree of emissions reductions while
taking into account the statutory factors, including cost. The EPA is
further seeking comment on whether a standard of 6.0E-03 lb/MMBtu or
lower (for example 2.4E-03 lb/MMBtu, which is the average emission of
the best performing 50 percent of units evaluated) would represent a
better balancing of the statutory factors.
    Indeed, Congress designed CAA section 112 to achieve significant
reductions in HAP emissions, which it recognized are particularly
harmful pollutants. This proposal is consistent with the EPA's
authority pursuant to CAA section 112(d)(6) to take developments in
practices, processes, and control technologies into account to
determine if more stringent standards are achievable than those
initially set by the EPA in establishing MACT floors, based on
developments that occurred in the interim. See LEAN v. EPA, 955 F.3d
1088, 1097-98 (D.C. Cir. 2020). As discussed above in this section, the
EPA finds that the vast majority of existing coal-fired EGUs are
performing well below the 2012 MATS fPM emission requirements, and that
they are achieving these levels at lower costs than the EPA assumed in
the 2012 rulemaking. While this proposal in no way refutes that the
EPA's initial MACT standards were set at correct levels based on the
available information at the time, consistent with CAA section 112's
statutory scheme requiring the EPA to regularly revisit those
standards, the EPA now proposes to find that more stringent standards
are achievable, as chiefly evidenced by the large majority of
facilities that are reporting fPM at emission rates well below the
current standard.
    This proposed emission limit is comparable to the new source
standard for fPM in MATS. This proposed emission limit is estimated to
reduce non-Hg metal HAP by 6.34 tons per year (and fPM emissions by
2,074 tons/year) at annual costs between $77.3 and $93.2 million. While
the 2020 Residual Risk Review concluded that the residual risks are at
an acceptable level, Congress required the EPA to conduct technology
reviews on an ongoing basis, at least every 8 years, independent of the
residual risk review.\27\ Moreover, Congress required the EPA to set
the standards at the maximum degree of emissions reductions (including
prohibition on emissions) that is achievable taking into account the
statutory factors. The technological standard approach of CAA section
112 is based on the premise that, to the extent there are controls
available to reduce HAP emissions, sources should be required to use
them. Since 91 percent of the anticipated capacity of the fleet is
already achieving a limit below 1.0E-02 lb/MMBtu, the EPA proposes that
this emissions limit level is technologically feasible and demonstrated
for a range of control configurations. Additionally, this revised limit
would result in significantly lower allowable fPM emissions from the
source category compared to the level of emissions allowed by the 2012
MATS Final Rule and help prevent any emissions increases. The EPA does
not anticipate any significant non-air health, environmental, or energy
impacts as a result of these proposed amendments. Our assessment of
control options, costs, and emission reductions is summarized in the
memorandum ``2023 Technology Review for the Coal- and Oil-Fired EGU
Source Category'' in Docket ID No. EPA-HQ-OAR-2018-0794.
---------------------------------------------------------------------------

    \27\ See discussion in section V.A, above.
---------------------------------------------------------------------------

    The EPA is not proposing the highest limit examined (1.5E-02 lb/
MMBtu) because it would largely leave in place the status quo, in
which, despite the proven feasibility and effectiveness of control
technologies, a number of sources are lagging far behind. The EPA does
not consider a proposed revision to this standard to be consistent with
its statutory charge.
    While the EPA is not proposing the most stringent limit examined
(6.0E-03 lb/MMBtu) or an even more stringent limit, the EPA is taking
comment on whether it should consider finalizing such a standard. Such
a standard would achieve far more emissions reductions than the
emission standards that the EPA is proposing in this action. It would
also ensure that the bottom lowest performing quarter of the fleet
would have to improve their performance to the level already
demonstrated by the remaining three-quarters of the fleet. The EPA
declines to propose 6.0E-03 lb/MMBtu as the primary policy option here
in light of the above presentation of potential costs, including the
EPA's current assessment of measurement uncertainty, when considering
the current fleet. These cost estimates are based on the assumption
that existing ESP-controlled units would need to install a new FF in
order to meet the lower limit, or if existing FF-controlled units do
not meet the more stringent limit, those units would need to upgrade
their FF bags. If these assumptions are unnecessarily conservative, the
total costs and associated cost-effectiveness values may be
considerably lower than estimated. The EPA seeks comment on whether
there are lower cost compliance options for units with existing ESPs.
    An additional factor affecting the total estimated compliance cost
is the size and composition of the generating fleet. As noted above,
the cost estimates in Table 3 do not account for market and policy
developments that are likely to further change the universe of
regulated sources and reduce the expected costs of meeting more
protective fPM standards. In the likely case that the power sector's
transition to lower-emitting generation

is accelerated by the IRA, for example, the total costs and emissions
reductions achieved by each of the three alternative fPM standards
shown in Table 3 would also be an overestimate, and the EPA's judgment
could change about which standard most appropriately balances CAA
section 112's direction to achieve the maximum degree of emissions
reductions while taking into account cost and other the statutory
factors. The EPA seeks comment on how the IRA and other market and
policy developments should inform the Agency's determination.
    Additionally, the EPA notes that other future state and federal
policies could affect the size, composition, and fPM emissions rate of
the future coal-fired EGU fleet. The EPA seeks comment on the extent to
which, and how, to take these future policies into account when
considering the total cost and cost effectiveness of a more stringent
fPM emission limit.
    The EPA requests public comment on all aspects of this proposed
rule, including our evaluation of the costs and efficacy of control
option assumptions. Among other issues, the EPA requests comment on
whether we have accurately assessed the variability of fPM emissions
and requests information on the costs, pollution reduction benefits,
and cost-effectiveness of applying lower emission limits to sources
subject to MATS; and whether there are other factors the EPA should
consider that would support a lower emission limit, including the
contribution that HAP from these sources make to the overall pollution
burden. The EPA seeks comment on requiring existing coal-fired EGUs to
meet a fPM standard of 6.0E-03 lb/MMBtu or a more stringent standard
considering the higher emission reductions as well as the larger total
costs such a standard would entail to inform our consideration of
whether the more stringent standard would reduce the overall pollution
burden in these communities. The EPA also seeks comment on whether
there are any areas where EPA has overestimated costs, including some
of the generation and storage technologies discussed above as well as
the cost of PM controls themselves.
2. PM Emission Monitoring
    Under the current rule, EGU owners or operators may choose among
quarterly testing, PM CEMS, and PM CPMS to demonstrate compliance with
the alternate fPM emission limit in MATS. The initial MATS ICR,
available at www.reginfo.gov,\28\ anticipated that all EGU owners or
operators would use PM CEMS for compliance purposes and estimated
Equivalent Uniform Annual Cost (EUAC) for the beta gauge PM CEMS to be
$65,388. As mentioned in the 2012 proposed Portland Cement NESHAP,\29\
beta gauge technology, also referred to as beta attenuation, allows PM
CEMS to be much less sensitive to changes in particle characteristics
than light-based PM CEMS technologies such as light-scatter or
scintillation. Beta attenuation PM CEMS extracts a sample from the
stack gas and collects the fPM on filter tape. The device periodically
advances the tape from the sampling mode to an area where the sample is
exposed to beta radiation. The detector measures the amount of beta
radiation emitted by the sample and that amount can be directly related
to the mass of the filter. The unannualized purchase cost for a beta
gauge PM CEMS and its installation were estimated to be $115,267 in the
initial MATS ICR; and the EUAC for beta gauge PM CEMS was estimated to
be less expensive than quarterly EPA Method 5 (M5) testing for fPM.
Even so, not all EGU owners or operators chose the most cost-effective
means of demonstrating compliance with the fPM emission limits. Review
of reports submitted to WebFIRE and ongoing ICR renewals shows PM CEMS
are used for compliance purposes by about one-third of EGU owners or
operators. In addition to being more cost-effective for compliance
purposes, PM CEMS provide regulators and the public, as well as the EGU
owners or operators, direct and continuous measurement of the pollutant
of concern. Such data supply real-time, quality-assured feedback that
can lead to improved control device and power plant operation, which,
in turn, can lead to fPM emission reductions. Moreover, quick detection
of potential problems with PM emissions as provided by PM CEMS, coupled
with appropriate corrective measures, can prevent instances of non-
compliance, which otherwise could go undetected and uncorrected until
the next quarterly PM test. This quicker identification and correction
of high emitting EGUs will lead to less pollution emitted and lower
pollutant exposure for local communities. In addition to significant
value of more efficient pollution abatement, transparency of EGU
emissions as provided by PM CEMS, along with real-time assurance of
compliance has intrinsic value to the public and communities as well as
instrumental value in holding sources accountable.
---------------------------------------------------------------------------

    \28\ See the supporting statement 2137ss06.docx in ICR reference
number<PHONE_NUMBER>-005 at OMB Control Number 2060-0567.
    \29\ See 77 FR 42375, July 18, 2012.
---------------------------------------------------------------------------

    Since promulgation of MATS, two important developments in the PM
CEMS industry have occurred, which the EPA identified as part of this
technology review: cessation of beta gauge PM CEMS manufacturing and
reduced overall costs for non-beta gauge PM CEMS instruments and
installation. These two occurrences have reduced the current one-time
costs for PM CEMS, making their use even more cost-effective. As shown
in Table 4 below, average non-beta gauge instrument and installation
costs obtained from representatives of the Institute of Clean Air
Companies (ICAC), a trade association consisting of air pollution
control and measurement and monitoring system manufacturers and of
environmental equipment and service providers, and from Envea/Altech, a
PM CEMS manufacturer and vendor, show about a 48 percent reduction
(from $109,420 to $57,095) from average comparable costs determined
from the EPA's CEMS Cost Model and Monitoring Cost/Benefit Analysis
Tool (MCAT).

                                           Table 4--Non-Beta Gauge PM CEMS Cost Estimates Using M5I for PS 11
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          One time costs, $                            Annual costs,  $
                                                  ------------------------------------------------------------------------------------------
          Data source              PM CEMS type    Instrument and   Other initial    Capital     Operation and                Other annual     EUAC,  $
                                                    installation        costs        recovery     maintenance      Audits         costs
--------------------------------------------------------------------------------------------------------------------------------------------------------
EPA MCAT......................  In situ..........         119,295          81,220       22,016           1,558       54,877          11,219       89,670
                                Extractive.......         152,850          81,220       25,700           2,579       54,877          12,241       95,397
EPA CEMS Cost Model...........  In situ..........          65,107          79,813       15,912           2,689       54,392           6,525       79,518

                                Extractive.......         100,427          84,458       20,300           3,689       54,392           7,525       85,906
                                                  ------------------------------------------------------------------------------------------------------
    Average...................  .................         109,420          81,678       20,982           2,629       54,635           9,378       87,623
--------------------------------------------------------------------------------------------------------------------------------------------------------
ICAC..........................  Low..............          35,000  ..............        3,843          12,000       14,290  ..............       30,133
                                High.............          40,000  ..............        4,392          12,000       14,290  ..............       30,682
Envea/Altech..................  Dry..............          34,743  ..............        3,821  ..............       14,290  ..............       18,111
                                Wet..............         118,585  ..............       13,020  ..............       14,290  ..............       27,310
                                                  ------------------------------------------------------------------------------------------------------
    Average...................  .................          57,095  ..............        6,269          12,000       14,290  ..............       32,559
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Generally, EPA models include other initial costs associated with
PM CEMS installation, including those associated with planning,
selecting equipment, and conducting correlation testing, in its models;
such one-time costs are annualized along with instrument and
installation costs. The proposed lower fPM emission limit will require
longer duration runs for M5 testing and may require the use of M5I,
which was designed for PM CEMS correlation testing at low fPM levels.
Initial costs in Table 4 for M5I emission testing are $58,000; such
testing includes 18 runs of 3-hour duration spread over 9 total days.
PM CEMS correlation testing for the proposed lower fPM levels using M5
is estimated to be $41,000. Of course, the quarterly testing run
durations would need to increase if PM CEMS were not used; annual cost
for M5 testing with 3 hour run duration is estimated to be $85,127
($82,000 for testing, and $3,127 for 24 hours of site technical
support); quarterly testing using M5I with runs of similar duration is
estimated to be $107,127. However, neither ICAC nor Envea/Altech
explicitly included those costs as line items in their estimates. This
does not necessarily mean that such costs have been excluded; if such
costs have been included, then the estimates do not change, but if such
costs have not been included, the estimates may increase. Their average
capital recovery cost, determined from the sum of the instrument,
installation, and other initial costs amortized over 15 years at a 7
percent interest rate, is about 70 percent lower than that obtained
from the average capital recovery cost obtained from the EPA models. As
shown in the table, EPA models also include annual costs for operation
and maintenance, relative response and correlation audits, and other
items such as reporting and recordkeeping. The sum of those items plus
the capital recovery cost yields EUAC of PM CEMS. ICAC includes
operation and maintenance as a line item in its annual costs, but
neither ICAC nor Envea/Altech include audits or other items in their
annual costs estimates. Because EPA believes some EGUs may require PM
spiking--an approach that involves introducing known amounts of fPM to
increase fPM concentration without altering control device equipment--
the EPA added $14,290 (the annualized cost of conducting $35,000 p.m.
spiking every 3 years at an interest rate of 7 percent) to the audit
portion of all entries. As mentioned earlier, omission of specifically
named costs does not necessarily mean that those costs have been
excluded; rather these costs may be included in other listed costs.
Using the data provided and explained above, the average EUAC for PM
CEMS that rely on M5I correlation testing is about 63 percent lower
than the average EUAC from EPA models (from $87,623 to $32,559). Given
that the annual cost of quarterly M5 testing for fPM is now estimated
to be $85,127, annualized other one-time costs and operation and
maintenance, audits, and other annualized costs--if omitted by the
manufacturers--would have to be more than $52,568 for PM CEMS to be
less cost-effective than quarterly testing.
    As mentioned in the proposed Portland Cement NESHAP from 10 years
ago (see 77 FR 42374, July 18, 2012), the EPA was aware of the
potential difficulty use of PM CEMS might have created in determining
compliance for that rulemaking due to the low end of emission limits
(0.04 lb/ton clinker, which translates to a range of about 5 to 8 mg/
dscm, depending on particle characteristics) and to the short duration
of emission test runs. The EPA addressed those concerns for that
rulemaking by proposing to raise the emission limit to 0.07 lb/ton
clinker, which translated to a range of about 7 to 14 mg/dscm, and to
no longer require PM CEMS use; instead, owners or operators would use
their PM CEMS as PM CPMS. Even so, the durations of test runs used to
develop the correlation of the instrument with the emissions limit
remained unchanged, at about 1 hour per run. Such short run durations
led to inherent measurement uncertainty accounting for more than half
the emission limit at the expected portland cement plant operating
condition, leading some to question whether values provided by
instrumentation were appropriately related to emissions.
    The conditions experienced by portland cement facilities that
required revisions to emission limits and compliance determination
method are not similar to those expected to be faced by EGU owners or
operators subject to MATS. First, the fuel used by coal-fired EGUs is
more uniform and its characteristics are more consistent than those of
the fuel and additive mixtures used by portland cement kilns. Such fuel
combustion particle consistency allows technologies such as light
scattering and scintillation, in addition to beta gauges, to be used by
PM CEMS for compliance determination purposes. Moreover, consistent fPM
particle characteristics for EGUs provide stable correlations for those
EGUs with existing PM CEMS; while the fPM particle characteristics
provide correlations that remain within specifications, as evidenced by
ongoing relative correlation audits, the existing correlations do not
change and can continue to be used now and in the future without having
to develop a new correlation. Second, the proposed MATS emission limit
of 1.0E-02 lb/MMBtu, which translates to about 7.3 mg/dscm, coupled
with a minimum sampling collection time of 3 hours per run, based on a
typical sampling rate of \3/4\ cubic feet per minute, avoids the
measurement problems described by the Portland Cement NESHAP by
reducing the average inherent measurement uncertainty for half of the
proposed emission limit (where the EGU is expected to operate) from
more than 50 to 80 percent. In addition, use of 3 hour

run durations would allow for a 6.0E-03 lb/MMBtu (or about 4.4 mg/dscm)
MATS emission limit, which the EPA is seeking comment on, to have an
average inherent measurement uncertainty due to random error of 14
percent at the target PM CEMS operational limit of 3.0E-03 lb/MMBtu. As
shown, inherent measurement uncertainty does not appear to be
problematic for the primary proposed emission limit, but, as mentioned
earlier, some PM CEMS may have difficulty meeting the inherent
measurement uncertainty--specifically, the average random error
component--of the alternative proposed emission limit. Note that the
primary proposed MATS emission limit is just above the fPM limit for
new EGUs, as 9.0E-02 lb/MWh on an electrical output basis translates to
about 9.0E-03 lb/MMBtu on a heat input basis. MATS requires use of PM
CEMS for new EGUs, along with minimum sampling collection time of 3
hours per run.\30\ Proposed use of runs of at least 3 hour durations
and emission limits of 1.0E-02 lb/MMBtu would be consistent with run
durations and limits already in MATS. Third, Performance Specification
11 (PS 11), which provides procedures and acceptance criteria for
validating PM CEMS technologies, already anticipates and includes
approaches for developing low-level emission correlations for PM CEMS.
Those techniques include varying process operations; varying fPM
control device conditions; PM spiking zero point methods when the
previous techniques are not able to provide the 3 distinct fPM
concentration levels. As mentioned earlier, average costs for fPM
spiking are about $35,000 every 3 years, or $14,290 annually at an
interest rate of 7 percent, and not every EGU will need to adjust its
existing correlation in order to continue to use its existing PM CEMS
to demonstrate compliance with the proposed limits; however, for
purposes of this proposal, costs for spiking will be included in annual
PM CEMS cost estimates. In addition to these techniques to aid PM CEMS
use for rules with low level emissions, the EPA is aware that the
Electric Power Research Institute (EPRI) began working with an
instrument manufacturer in 2009, prior to MATS promulgation, to develop
a National Institute of Standards and Technology (NIST) traceable
aerosol generator that injects known particle size distribution and
mass into PM CEMS. Such an instrument, known as a Quantitative Aerosol
Generator (QAG), would allow direct PM CEMS calibration, as opposed to
the development of a curve that provides a correlation for the PM
CEMS.\31\ That study relied on six emission rates, four of which were
at or under 5 mg/dscm, and reported successful sample collection and
transport. EPRI continued this work and provided a technical update in
2014,\32\ but the EPA is unaware of specific recommendations or
suggestions regarding QAG application to PM CEMS. While we believe the
use of the QAG could lower fPM monitoring costs for PM CEMS use, we
seek more information on its application for lower fPM limits as
measured by PM CEMS; specifically, we solicit comment on whether
implementation of the QAG is another reason that PM CEMS costs have
decreased.
---------------------------------------------------------------------------

    \30\ See Table 1 to subpart UUUUU of 40 CFR part 63. At a
typical sampling rate of \3/4\ cubic foot per minute, a run would
require 3 hours to collect at least 4 cubic meters of sample.
    \31\ See A Qualitative Aerosol Generator Designed for
Particulate Matter (PM) Continuous Emissions Monitoring Systems
(CEMS) Calibration, available at www.epri.com/research/products/1017574.
    \32\ See Quantitative Aerosol Generator (QAG) for Calibration of
Particulate Monitors: 2014 Technical Update, available at
www.epri.com/research/products/3002003343.
---------------------------------------------------------------------------

    For these reasons, we propose to require the use of PM CEMS as the
method to demonstrate compliance with the fPM emissions limit for coal-
fired and IGCC EGUs pursuant to the EPA's authority under CAA section
112(d)(6). If our proposal is finalized, EGU owners or operators
currently relying on quarterly PM emissions testing would need to
install, operate, and maintain PM CEMS. Such a switch is projected to
be more cost-effective, more informative, and more effective in
assuring compliance than use of quarterly testing. Those EGU owners or
operators already using PM CEMS as their means of compliance
determination would maintain their current approach; while some may
have no need for additional expenditures, the proposal includes the
costs associated with revised and ongoing correlation testing and
spiking for all EGUs. Since a proposed requirement for use of PM CEMS
renders the current compliance option for the LEE program superfluous,
the EPA proposes to remove the individual and total non-Hg metal HAP
and the surrogate fPM from the LEE program for all MATS-affected EGUs
and solicits comments on removing these limits.
    The EPA seeks comment on distinctions between portland cement
plants and EGUs that would facilitate PM CEMS use at EGUs.
Specifically, the EPA seeks comment on the ability, type, and
capabilities of PM CEMS to accurately measure fPM emissions at the
levels proposed in this rule. Moreover, the EPA seeks comment on
additional or other approaches that could be employed to facilitate PM
CEMS use for the proposed emission levels. Specific comments on direct
PM CEMS calibration methods, such as the QAG, as well as limitations,
are welcome.
    The EPA solicits comment on the availability of beta gauge
instruments, on the current average costs of non-beta gauge PM CEMS
instruments and installation, on ICAC's annual costs, and on Envea/
Altech's annual costs. When commenting on EPA model estimates or ICAC's
or Envea/Altech's estimates, please provide specific PM CEMS instrument
type, manufacturer, and model; cost information broken down by initial
cost including instrument type and installation cost, and annual cost,
including operation and maintenance, audit, and other costs in your
comments. Moreover, please identify in your comments specific items
included in your cost information, such as installation, operation, and
maintenance provisions. The EPA also solicits comment on the cost-
effectiveness of PM CEMS as compared to quarterly PM emissions testing.
Also, the EPA solicits comment on the availability of PM CEMS and their
use for compliance purposes, especially when compared to less frequent,
more expensive measures.
    The EPA is aware that some EGUs may be on enforceable schedules to
cease operations, which may be just beyond the three-year compliance
date the EPA proposes for PM CEMS monitoring requirements in section
V.E, below, and that owners or operators of EGUs may be unable to
recoup investments in PM CEMS if the instruments are not in operation
for at least a certain period of time beyond their installation date.
Therefore, the EPA seeks comment on whether EGUs should be able to
continue to use quarterly emissions testing past the proposed
compliance date for a certain period of time or until EGU retirement,
whichever occurs first, provided the EGU is on an enforceable schedule
for ceasing coal- or oil-fired operation. In addition, the EPA seeks
comment on what would qualify as an enforceable schedule, such as that
contained in the Agency's ``EGUs Permanently Ceasing Coal Combustion by
2028'' included in the 2020 Steam Electric ELG Reconsideration Rule (85
FR 64640, 64679, and 64710; 10/13/2020), as well as what the maximum
duration of operation using quarterly emissions testing for compliance
purposes should be.

3. Review of the Hg Emission Standards
a. Overview of Hg Emissions From Combustion of Coal
    Mercury is a naturally occurring element found in small and varying
quantities in coal. During combustion of coal, Hg is volatilized and
converted to elemental Hg vapor (Hg\0\) in the high temperature regions
of the boiler. Hg\0\ vapor is difficult to capture because it is
typically nonreactive and insoluble in aqueous solutions. However,
under certain conditions, the Hg\0\ vapor in the flue gas can be
oxidized to divalent Hg (Hg\2+\). The Hg\2+\ can bind to the surface of
solid particles (e.g., fly ash) in the flue gas stream, often referred
to as ``particulate bound Hg'' (Hgp), and be removed in a
downstream PM control device. Oxidized Hg compounds can also be soluble
and can be removed in a wet scrubber. The presence of chlorine in gas-
phase equilibrium favors the formation of mercuric chloride
(HgCl2) at flue gas cleaning temperatures. However, Hg\0\
oxidation reactions are kinetically limited as the flue gas cools and,
as a result, Hg often enters the flue gas cleaning device(s) as a
mixture of Hg\0\, Hg\2+\ compounds, and Hgp. This
partitioning into various species of Hg has considerable influence on
selection of Hg control approaches. In general, because of the presence
of higher amounts of halogen (especially chlorine) in bituminous coals,
most of the Hg in the flue gas from bituminous coal-fired boilers is in
the form of Hg\2+\ compounds, typically HgCl2 and is more
easily captured in downstream control equipment. Conversely, both
subbituminous coal and lignite have lower halogen content, compared to
that of bituminous coals, and the Hg in the flue gas from boilers
firing those fuels tends to be in the form of Hg\0\ and is more
challenging to control in downstream control equipment.
    Fly ash is typically classified as acidic (pH less than 7.0),
mildly alkaline (pH greater than 7.0 to 9.0), or strongly alkaline (pH
greater than 9.0). The pH of the fly ash is usually determined by the
calcium/sulfur ratio and the amount of halogen. The ash from bituminous
coals tends to be acidic due to the relatively higher sulfur and
halogen content and the glassy (nonreactive) nature of the calcium
present in the ash. Conversely, the ash from subbituminous and lignite
coals tends to be more alkaline due to the lower amounts of sulfur and
halogen and a more alkaline and reactive (non-glassy) form of calcium
in the ash. The natural alkalinity of the subbituminous and lignite fly
ash can effectively neutralize the limited free halogen in the flue gas
and prevent oxidation of the Hg\0\.
    Some coal-fired power plants--especially those firing bituminous
coal--achieve some level of Hg emissions control using existing
equipment that was installed to remove other pollutants, including PM,
SO2, and nitrogen oxides (NOX). Particulate-bound
Hg (Hgp) is effectively removed along with PM in PM control
equipment such as FFs and ESPs. Soluble Hg\2+\ compounds (such as
HgCl2) can be effectively captured in wet FGD systems. And,
while a selective catalytic reduction (SCR) system that has been
installed for NOX control does not itself capture Hg, it can
under the right conditions enhance the oxidation of Hg\0\ in the flue
gas for increased Hg removal in a downstream PM control device or in a
wet FGD scrubber.
    However, because the Hg in their flue gas tends to be present in
the non-reactive Hg\0\ phase, EGUs firing subbituminous coal or lignite
often get little to no control from equipment designed and installed
for other pollutants. While some bituminous coal-fired EGUs require use
of additional Hg-specific control technology, such as injection of a
sorbent or chemical additive, to supplement the control that these
units already achieve from criteria pollutant control equipment, these
Hg-specific control technologies are often required as part of the Hg
emission reduction strategy at EGUs that are firing subbituminous coal
or lignite. As mentioned, the Hg in the flue gas for those EGUs tends
to be in the non-reactive Hg\0\ phase due to lack of free halogen to
promote the oxidation reaction. To alleviate this challenge, activated
carbon and other sorbent providers and control technology vendors
developed methods to introduce halogen into the flue gas to improve the
control of Hg emissions from EGUs firing subbituminous coal and
lignite. This was primarily through the injection of pre-halogenated
(often pre-brominated) activated carbon sorbents or through the
injections of halogen-containing chemical additives along with
conventional sorbents. This challenge to controlling Hg emissions was a
challenge for EGUs firing subbituminous coal and for EGUs firing
lignite.
b. Hg Emission Standards in the 2012 MATS Final Rule
    In the 2012 MATS Final Rule, the EPA promulgated a beyond-the-floor
standard for Hg for the subcategory of existing coal-fired units
designed for low rank virgin coal (i.e., lignite) based on the use of
ACI for Hg control. See 77 FR 9304, February 16, 2012. The EPA
established a final Hg emission standard of 4.0 pounds of Hg per
trillion British thermal units of heat input (lb Hg/TBtu) for lignite-
fired utility boilers. The EPA promulgated a final Hg emission standard
for EGUs firing non-lignite coals, including bituminous and
subbituminous coal, of 1.2 lb Hg/TBtu.
    Under CAA section 112(d)(1), the Administrator has the discretion
to ``distinguish among classes, types, and sizes of sources within a
category or subcategory'' in establishing standards. Any basis for
subcategorization must be related to an effect on HAP emissions that is
due to the difference in class, type, or size of the units. See 76 FR
25036-25037.
    When developing the MATS rule, the EPA examined available Hg
emissions data from coal-fired EGUs and found that there were no
lignite-fired EGUs among the top performing 12 percent. The EPA then
determined that the difference in the emissions from the lignite-fired
EGUs was due to a difference in the class, type, or size of those units
and finalized two subcategories of coal-fired EGUs for Hg emissions.
See 76 FR 25036-67. The EPA considered basing the subcategory
definition solely on an EGU (1) being designed to burn lignite and (2)
burning lignite. However, the EPA decided not to do so because of the
concern that such a definition would allow sources to potentially meet
the definition by combusting very small amounts of low rank virgin
lignite. In the preamble of the 2012 MATS Final Rule, the EPA suggested
a scenario where an EGU that was not designed to burn lignite and did
not routinely burn lignite could import one truck full of low rank
virgin coal and burn a very small quantity of it periodically to meet
the subcategory definition. To avoid creating this potential loophole,
the EPA also finalized a requirement that the unit be constructed and
operated at or near a mine containing the low rank virgin coal it
burns. The EPA indicated that the final definition would prevent other
EGUs that are not firing lignite from complying with the less stringent
Hg emission standard. The final definition, as specified in the 2012
MATS Final Rule (77 FR 9369, February 16, 2012), was: ``Unit designed
for low rank virgin coal subcategory means any coal-fired EGU that is
designed to burn and that is burning non-agglomerating virgin coal
having a calorific value (moist, mineral matter-free basis) of less
than 19,305 kJ/kg (8,300 Btu/lb) that is constructed and operates at or
near the mine that produces such coal.''

c. Beyond-the-Floor Analysis for the 2012 MATS Final Rule
    For the 2012 MATS Final Rule, the EPA calculated beyond-the-floor
costs for Hg controls by assuming injection of brominated activated
carbon at a rate of 3.0 pounds of sorbent per million actual cubic feet
of flue gas (lb/MMacf) for lignite-fired EGUs with an ESP for PM
control and at an injection rate of 2.0 lb/MMacf for lignite-fired
units with a baghouse (also known as a fabric filter, FF). The sorbent
injection rate of 2.0 lb/MMacf for lignite-fire units with FFs is
consistent with the rate assumed for all other coal types. The EPA
assumed a sorbent injection rate of 3.0 lb/MMacf for lignite-fired
units with ESPs, which is lower than the sorbent injection rate of 5.0
lb/MMacf that the EPA assumed for EGUs firing using other (non-lignite)
coal types. In the Beyond-the-Floor Memo (see Docket ID No. EPA-HQ-OAR-
2009-0234-20130), the EPA indicated that this lower sorbent injection
rate was appropriate, because a higher rate would likely result in Hg
emission reductions greater than those needed to meet the beyond-the-
floor standard of 4.0 lb/TBtu noting that greater than 90 percent
control can be achieved at lignite-fired units at a 2.0 lb/MMacf
injection rate for units with installed FF and using treated (i.e.,
brominated) activated carbon or at an injection rate of 3.0 lb/MMacf
for units using treated activated carbon with installed ESPs.
    Petitioners challenged the beyond-the-floor standard for lignite-
fired EGUs, claiming that the final standard is not achievable because
they asserted that the standard would require unrealistically high
levels of Hg reduction. In White Stallion v. EPA, the Court of Appeals
of the District of Columbia Circuit rejected petitioners' challenge to
the final beyond-the-floor standard on the basis that the EPA had
adequately concluded during the rulemaking process that the standard
for lignite units were achievable if sources increased their use of a
particular control technology, ACI. See White Stallion Energy Center,
LLC v. EPA, 748 F.3d 1222, 1251 (D.C. Cir. 2014).
d. Hg Emission Reductions Since Promulgation of the 2012 MATS Final
Rule
    The EPA estimated annual Hg emissions from coal-fired power plants
in 2010 (pre-MATS) to be 29 tons.\33\ In 2017, after full
implementation of the MATS rule, the EPA estimated Hg emissions had
been reduced to 4 tons, an 86 percent decrease.\34\ This decline was
due to the installation and use of Hg controls as well as other
significant changes in the power sector (e.g., coal plant retirements,
increase use of natural gas and renewable energy, etc.) in the same
time period.
---------------------------------------------------------------------------

    \33\ Memorandum: Emissions Overview: Hazardous Air Pollutants in
Support of the Final Mercury and Air Toxics Standard. EPA-454/R-11-
014. November 2011; Docket ID No. EPA-HQ-OAR-2009-0234-19914.
    \34\ 2017 Power Sector Programs Progress Report; available at
https://www.epa.gov/sites/default/files/2019-12/documents/2017_full_report.pdf and in the rulemaking docket.
---------------------------------------------------------------------------

i. Hg Emissions From Coal-Fired EGUs in 2021
    Hg emission reductions have continued to decline since 2017 as more
coal-fired EGUs have retired or reduced utilization. The EPA estimated
that 2021 Hg emissions from coal-fired EGUs were 3 tons (a 90 percent
decrease compared to pre-MATS levels).\35\ However, units burning
lignite coal (or permitted to burn lignite) accounted for a
disproportionate amount of the total Hg emissions in 2021. As shown in
Table 5 below, 16 of the top 20 Hg-emitting EGUs were lignite-fired
EGUs. Overall, lignite-fired EGUs were responsible for almost 30
percent of all Hg emitted from coal-fired EGUs in 2021, while
generating about 7 percent of total 2021 megawatt-hours. Lignite
accounted for 8 percent of total U.S. coal production in 2021.
---------------------------------------------------------------------------

    \35\ 2021 Power Sector Programs Progress Report; available at
https://www3.epa.gov/airmarkets/progress/reports/pdfs/2021_full_report.pdf and in the rulemaking docket.

                                      Table 5--Top Hg-Emitting EGUs in 2021
----------------------------------------------------------------------------------------------------------------
                                                                                2021 Hg
              Rank                         EGU                     Fuel           emissions (lb)       State
----------------------------------------------------------------------------------------------------------------
1..............................  Coal Creek 2...........  Lignite...............           181.8  ND
2..............................  Coal Creek 1...........  Lignite...............           175.6  ND
3..............................  Oak Grove 2............  Lignite...............           149.8  TX
4..............................  Martin Lake 3..........  Lignite/Subbituminous.           134.4  TX
5..............................  Oak Grove 1............  Lignite...............           112.7  TX
6..............................  Martin Lake 2..........  Lignite/Subbituminous.           111.0  TX
7..............................  Milton R Young B2......  Lignite...............           103.1  ND
8..............................  Martin Lake 1..........  Lignite/Subbituminous.           100.7  TX
9..............................  Antelope Valley B2.....  Lignite...............            89.8  ND
10.............................  Coyote B1..............  Lignite...............            79.9  ND
11.............................  H W Pirkey Power Plant   Lignite/Subbituminous.            71.1  TX
                                  1 *.
12.............................  Antelope Valley B1.....  Lignite...............            69.6  ND
13.............................  San Miguel SM-1........  Lignite...............            64.6  TX
14.............................  Sandy Creek Energy       Subbituminous.........            53.5  TX
                                  Station S01.
15.............................  Limestone LIM2.........  Lignite/Subbituminous.            52.5  TX
16.............................  Milton R Young B1......  Lignite...............            52.4  ND
17.............................  Comanche 3.............  Subbituminous.........            50.3  CO
18.............................  Leland Olds 2..........  Lignite...............            50.1  ND
19.............................  James H Miller Jr 3....  Subbituminous.........            42.9  AL
20.............................  Labadie 2..............  Subbituminous.........            42.5  MO
----------------------------------------------------------------------------------------------------------------
* This unit has announced its intention to retire in 2023.

ii. Limited CAA Section 114 Request
    In May 2021, pursuant to authority in section 114 of the CAA, 42
U.S.C. 7414(a), the EPA solicited information related to Hg emissions
and Hg control technologies from certain lignite-fired EGUs to inform
this CAA section 112(d)(6) technology review. The selected lignite-
fired EGUs were asked

to provide information on their control configuration for Hg and for
other air pollutants (e.g., criteria pollutants such as PM,
NOX, SO2). Selected information on lignite-fired
EGU control configurations that was obtained from the CAA section 114
information request is shown below in Table 6. Additional information
on the location, size (capacity), firing configuration, and control
configuration of lignite-fired EGUs (including those few that were not
included in the CAA section 114 information request) is also included.
The additional information was obtained from the EPA's NEEDS
database.\36\
---------------------------------------------------------------------------

    \36\ National Electric Energy Data System (NEEDS) v621 rev: 10-
14-22, available at: https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs-v6.

                             Table 6--Control Configurations for Lignite-Fired EGUs
----------------------------------------------------------------------------------------------------------------
                                     Capacity                      Control         Hg control
        Plant name          State      (MW)        Firing       configuration     description       Hg control
----------------------------------------------------------------------------------------------------------------
Antelope Valley #1.......  ND             450  tangent......  ACI + SDA + FF..  Does not use     Nalco non-
Antelope Valley #2.......  ND             450  tangent......  ACI + SDA + FF..   activated        carbon, non-
                                                                                carbon as its    halogenated
                                                                                sorbent,         liquid sorbent
                                                                                instead          added to dry
                                                                                injects a        scrubber; M-
                                                                                liquid sorbent   Sorb additive
                                                                                to the           (bromide).
                                                                                scrubber. The
                                                                                facility
                                                                                stopped using
                                                                                refined coal
                                                                                in December
                                                                                2021.
----------------------------------------------------------------------------------------------------------------
Coal Creek #1............  ND             574  tangent......  ACI + ESPC +      Information not collected in the
Coal Creek #2............  ND             573  tangent......   WFGD.             CAA 114 request.
                                                              ACI + ESPC +
                                                               WFGD..
----------------------------------------------------------------------------------------------------------------
Coyote...................  ND             429  cyclone......  ACI + SDA + FF..  Information not collected in the
                                                                                CAA 114 request.
----------------------------------------------------------------------------------------------------------------
Leland Olds #1...........  ND             222  wall.........  SNCR + ACI +      Activated        ME2C SEA SF10
                                                               ESPC + WFGD.      carbon and       Oxidizer and
                                                                                oxidizer         SB24 Activated
                                                                                injections for   Carbon.
                                                                                Hg control.
Leland Olds #2...........  ND             445  cyclone......  SNCR + ACI +
                                                               ESPC + WFGD.
----------------------------------------------------------------------------------------------------------------
Milton R Young #1........  ND             237  cyclone......  SNCR + ACI +      Hg controlled    DARCO Hg-H non-
Milton R Young #2........  ND             447  cyclone......   ESPC + WFGD.      by Powdered      halogenated
                                                              SNCR + ACI +       Activated        Powdered
                                                               ESPC + WFGD..     Carbon           Activated
                                                                                Injection plus   Carbon + ADA M-
                                                                                Oxidizing        Prove
                                                                                Agent/Halogen    additive.
                                                                                Injection
                                                                                System.
----------------------------------------------------------------------------------------------------------------
Spiritwood Station.......  ND              92  FBC..........  SNCR + ACI + SDA  Hg emissions     Activated
                                                               + FF.             are controlled   Carbon sorbent
                                                                                by activated     (not
                                                                                carbon           specified).
                                                                                injection
                                                                                system and a
                                                                                CEMS. The
                                                                                activated
                                                                                carbon
                                                                                injection feed
                                                                                rate is
                                                                                adjusted to
                                                                                maintain
                                                                                emissions
                                                                                below the 4.0
                                                                                lb/TBtu
                                                                                standard.
----------------------------------------------------------------------------------------------------------------
Limestone #1.............  TX             831  tangent......  SNCR + ACI +      Information not collected in the
                           .......  .........  .............   ESPC + WFGD.      CAA 114 request.
Limestone #2.............  TX             858  tangent......  SNCR + ACI +
                                                               ESPC + WFGD.
----------------------------------------------------------------------------------------------------------------
Major Oak #1.............  TX             152  FBC..........  Reagent           Hg is            Cabot DARCO Hg-
Major Oak #2.............  TX             153  FBC..........   Injection +       controlled by    H non-
                                                               SNCR + ACI + FF.  the              Brominated AC
                                                              Reagent            introduction     + ADA-ES M-
                                                               Injection +       of activated     Prove
                                                               SNCR + ACI +      carbon into      additive.
                                                               FF..              each boiler
                                                                                duct directly
                                                                                in front of
                                                                                the baghouse.
                                                                                A halogen fuel
                                                                                additive is
                                                                                also applied
                                                                                to the lignite
                                                                                before it
                                                                                enters the day
                                                                                silos.
----------------------------------------------------------------------------------------------------------------
Martin Lake #1...........  TX             800  tangent......  ACI + ESPC +      Brominated       ME2C SEA
Martin Lake #2...........  TX             805  tangent......   WFGD.             additive         process (non-
Martin Lake #3...........  TX             805  tangent......  ACI + ESPC +       injected into    Brominated AC
                                                               WFGD..            the furnace      + chemical
                                                              ACI + ESPC +       and activated    additive).
                                                               WFGD..            carbon
                                                                                injected
                                                                                upstream of
                                                                                the air
                                                                                heater. In
                                                                                2020 and 2021
                                                                                Refined Coal
                                                                                System applied
                                                                                an aqueous
                                                                                bromine salt
                                                                                solution to
                                                                                the coal.
                          --------------------------------------------------------------------------------------
Oak Grove #1.............  TX             855  tangent......  SCR + ACI + FF +  Brominated       ADA-CS Br-AC.
Oak Grove #2.............  TX             855  wall.........   WFGD.             activated
                                                              SCR + ACI + FF +   carbon
                                                               WFGD..            injected
                                                                                downstream of
                                                                                the air
                                                                                heater. From
                                                                                2018 to 2021,
                                                                                the unit was
                                                                                equipped with
                                                                                a Refined Coal
                                                                                System for Hg
                                                                                control. This
                                                                                system applied
                                                                                an aqueous
                                                                                bromine salt
                                                                                solution to
                                                                                the coal
                                                                                downstream of
                                                                                the crusher.
                                                                                The refined
                                                                                coal system is
                                                                                no longer in
                                                                                service.
----------------------------------------------------------------------------------------------------------------
Red Hills #1.............  MS             220  FBC..........  Reagent           Hg is            ADA-CS non-Br
Red Hills #2.............  MS             220  FBC..........   Injection + ACI   controlled by    AC + ADA-ES
                                                               + FF.             injection of     M45 liquid
                                                              Reagent            activated        additive.
                                                               Injection + ACI   carbon into
                                                               + FF..            each boiler
                                                                                duct directly
                                                                                in front of
                                                                                the baghouse.
                                                                                A fuel
                                                                                additive is
                                                                                also applied
                                                                                to the lignite
                                                                                before it
                                                                                enters the day
                                                                                silos. The
                                                                                application of
                                                                                fuel additives
                                                                                ended in
                                                                                December 2021.
----------------------------------------------------------------------------------------------------------------

San Miguel...............  TX             391  wall.........  SNCR + ACI +      Hg is captured   ME2C SEA
                                                               ESPC + WFGD.      using a          process (non-
                                                                                sorbent          Br AC + powder-
                                                                                enhanced         based chemical
                                                                                additive (SEA)   additive).
                                                                                injected onto
                                                                                the lignite at
                                                                                the pulverizer
                                                                                feeders or
                                                                                directly into
                                                                                the furnace to
                                                                                promote the
                                                                                oxidation and
                                                                                capture of Hg.
                                                                                This is
                                                                                followed by an
                                                                                ACI system
                                                                                located in the
                                                                                boiler exit
                                                                                duct work
                                                                                upstream of
                                                                                the air
                                                                                heaters. The
                                                                                scrubber
                                                                                system also
                                                                                reduces Hg
                                                                                emissions.
----------------------------------------------------------------------------------------------------------------
Note: ACI = activated carbon injection; SDA = spray dryer absorber (dry scrubber); FF = fabric filter; ESPC =
  cold side electrostatic precipitator; WFGD = wet flue gas desulfurization scrubber; SNCR = selective non-
  catalytic reduction (NOX control); reagent injection = sorbent injection into fluidized bed combustor.

    Most, but not all, of the EGUs utilized a combination of the use of
a chemical additive and injection of a sorbent as their Hg control
strategy. One facility in North Dakota (Antelope Valley) uses a liquid
sorbent that is injected to the SO2 scrubber (spray dryer
absorber, SDA). Many of the EGUs used ``refined coal.'' Refined coal is
typically produced by mixing proprietary additives to feedstock coal to
help capture emissions when the coal is burned. For example, these
additives may promote the oxidation of Hg to Hg\2+\ compounds for
capture in downstream control equipment (e.g., FGD scrubbers, PM
control devices). Several of the facilities noted that use of refined
coal as a part of their Hg control strategy was discontinued at the end
of 2021 when the refined coal production tax credit (created by the
American Jobs Creation Act of 2004) expired. According to a U.S.
Government Accountability Office audit report, refined coal producers
claimed approximately $8.9 billion in tax credits between 2010 and
2020.
    According to fuel use information supplied to EIA (on form 923), 13
of 22 EGUs that were designed to burn lignite utilized refined coal to
some extent in 2021, as summarized in Table 7. EIA form 923 does not
specify the type of coal that is ``refined'' when reporting boiler or
generator fuel use. For this technology review, the EPA has assumed
that the facilities have utilized ``refined lignite,'' as reported in
fuel receipts on EIA form 923. However, several ``lignite-fired EGUs''
located in Texas reported very high use of subbituminous coal in 2021
(ranging from 76 percent up to > 99 percent).

                                  Table 7--2021 Fuel Use At Lignite-Fired EGUs
----------------------------------------------------------------------------------------------------------------
                                    Distillate      Natural gas    Lignite coal    Refined coal    Subbituminous
           Plant name              fuel oil  (%)        (%)             (%)             (%)          coal  (%)
----------------------------------------------------------------------------------------------------------------
Antelope Valley 1...............             0.0             0.6             5.8            93.5             0.0
Antelope Valley 2...............             0.0             0.6             5.8            93.5             0.0
Coal Creek 1....................             0.1             0.0             0.0            99.9             0.0
Coal Creek 2....................             0.1             0.0             0.0            99.9             0.0
Coyote 1........................             0.3             0.0            99.7             0.0             0.0
Leland Olds 1...................             0.3             0.0            37.6            62.1             0.0
Leland Olds 2...................             0.3             0.0             6.2            93.6             0.0
Milton R Young 1................             0.4             0.0            17.0            82.6             0.0
Milton R Young 2................             0.2             0.0            12.1            87.6             0.0
Spiritwood Station 1............             0.0            35.6             0.0            64.4             0.0
Limestone 1.....................             0.0             0.2             0.0             0.0            99.8
Limestone 2.....................             0.0             0.8             0.0             0.0            99.2
Major Oak Power 1...............             0.0             0.2            99.8             0.0             0.0
Major Oak Power 2...............             0.0             0.0           100.0             0.0             0.0
Martin Lake 1...................             0.1             0.0            23.5             0.0            76.4
Martin Lake 2...................             0.1             0.0            22.4             0.0            77.5
Martin Lake 3...................             0.1             0.0            19.2             0.0            80.6
Oak Grove 1.....................             0.0             1.9             3.4            94.7             0.0
Oak Grove 2.....................             0.0             0.0             3.7            96.3             0.0
Red Hills Generating Facility 1.             0.0             0.3             0.0            99.7             0.0
Red Hills Generating Facility 2.             0.0             0.3             0.0            99.7             0.0
San Miguel 1....................             0.2             0.0            99.8             0.0             0.0
----------------------------------------------------------------------------------------------------------------

e. CAA Section 112(d)(6) Technology Review of the Hg Standards
i. Review of the Hg Emission Standard for Non-Lignite-Fired EGUs
    The final MATS Hg emission limit for EGUs firing non-lignite coals
(i.e., bituminous and subbituminous coals) is 1.2 lb Hg/TBtu. To review
that emission standard, the EPA evaluated the 2021 performance of EGUs
firing non-lignite coals and found that EGUs firing primarily
bituminous coal emitted Hg at an average annual rate of 0.4 lb Hg/TBtu
(with a range of roughly 0.2 to 1.2 lb Hg/TBtu). EGUs firing primarily
subbituminous coal in 2021 (not including those EGUs that are permitted
to burn lignite but burned a significant amount of subbituminous coal)
emitted Hg at an average annual rate of 0.6 lb Hg/TBtu (with a range of
0.1 to 1.2 lb/TBtu). This represents a control range of 98 to 77
percent (assuming an average inlet concentration of 5.5 lb/TBtu). The
EPA has information on the control configurations of these non-lignite

EGUs. However, because the non-lignite-fired EGUs were not included in
the limited CAA section 114 information collection, the EPA does not
have detailed information on the type of sorbent injected (e.g.,
activated carbon or non-carbonaceous; pre-halogenated, etc.). The EPA
also does not have detailed information on the injection rate of
sorbents used for Hg control (if any). Similarly, the EPA does not have
information on the type of quantity of chemical additives used (if
any). However, the bituminous coal-fired EGUs are already achieving an
average annual rate of 0.4 lb/TBtu and the subbituminous coal-fired
EGUs are already achieving an average annual rate of 0.6 lb/TBtu. The
typical Hg control performance curves for sorbent injection show a
leveling off such that increasing the amount of sorbent results in
diminishing improvement in Hg control. Based on full-scale
demonstration testing of Hg sorbents, this leveling off typically takes
place somewhere greater than 90 percent capture. Without knowing the
type of sorbent being injected or the rate of the sorbent injection, it
is difficult to determine whether additional emission reductions could
be achieved in a cost-effective manner. For bituminous coal-fired EGUs
that do not utilize sorbent injection but rely on co-benefit control
from equipment installed for criteria pollutants, it is difficult to
determine whether additional Hg emission reduction could be obtained in
a cost-effective manner with knowledge of the levels of Hg control
achieved in each of the installed controls and, if chemical additives
are injected, the type and rate of chemical additive injection. For
those reasons, the EPA is not proposing to adjust the Hg emission
standard for non-lignite-fired EGUs at this time. However, the EPA
solicits comment on the performance of Hg controls for non-lignite-
fired EGUs, including information on the type and injection rate of
sorbents used for Hg control, as well as the possibility of additional
cost-effective measures to further reduce Hg from equipment installed
for criteria pollutants. The EPA also seeks comment on whether there
would be a reasonably efficient way to more thoroughly survey the types
of controls--including the types of sorbents used and their injection
rates--used to limit Hg emissions at non-lignite-fired EGUs, and
whether conducting such additional information collection would be
worthwhile.
    In addition, the EPA notes that several states have adopted Hg
reduction standards that go beyond the 2012 MATS Final Rule in their
reduction target. For instance, Connecticut, Minnesota, Montana, New
York, Oregon, and Utah all established input-based Hg limits below 1.2
lb/TBtu. For further detail on all 18 states with existing Hg emissions
limits, see Chapter 3 of EPA's IPM documentation, available in the
docket. The EPA solicits information about the cost and effectiveness
of control strategies that EGUs in these states utilize to meet more
stringent Hg emission standards than those promulgated in the 2012 MATS
Final Rule, as well as any other available control strategies that the
EPA should consider and their costs.
ii. Review of the Hg Emission Standard for Lignite-Fired EGUs
    The final MATS Hg emission limit for EGUs firing lignite coal is
4.0 lb Hg/TBtu--more than three times the standard for non-lignite
coal. To review that emission standard, the EPA evaluated the data
obtained in the 2022 CAA section 114 data survey along with the
emissions data reported to the EPA and the fuel use data submitted to
EIA. The 2021 performance of lignite-fired EGUs (including those
permitted to burn lignite but that utilized significant amounts of
subbituminous coal in 2021) is shown in Table 8 below. The table shows
a ``Hg Inlet'' level which reflects the maximum Hg content of the range
of feedstock coals that the EPA assumes is available to each of the
plants in the Integrated Planning Model, IPM,\37\ the estimated control
(percentage) needed to meet an emission standard of 4.0 lb Hg/TBtu (the
current standard for lignite-fired EGUs) and the estimated control
(percentage) to meet an emission standard of 1.2 lb Hg/TBtu (the
current standard for non-lignite-fired EGUs). The table also shows the
estimated 2021 Hg inlet concentration from actual 2021 fuel usage (as
mentioned earlier, some units utilized significant quantities of non-
lignite fuel, e.g., subbituminous coal, natural gas, etc.) and the 2021
Hg emissions reported to the EPA. The EPA then estimated the apparent
level of Hg control for 2021 and the level of control that would been
needed to achieve the emission standard applicable to the non-lignite-
firing EGUs (1.2 lb Hg/TBtu).
---------------------------------------------------------------------------

    \37\ Discussion of how these assumptions were developed for use
in the EPA's IPM modeling is available in Chapter 7 of the IPM
Documentation.

                                       Table 8--Hg Emissions and Control Performance of Lignite-Fired EGUs in 2021
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Est Hg control  Est Hg control    Est 2021 Hg                                     Est 2021 Hg
               Plant name                 Hg inlet  (lb/  at 4.0 lb/TBtu  at 1.2 lb/TBtu    inlet  (lb/   2021 Hg outlet    Est 2021 Hg   control at 1.2
                                               TBtu)            (%)             (%)            TBtu)         (lb/TBtu)     control  (%)    lb/TBtu  (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Antelope Valley #1......................            7.81            48.8            84.6            7.76            2.87            63.0            84.5
Antelope Valley #2......................            7.81            48.8            84.6            7.76            2.74            64.6            84.5
Coal Creek #1...........................            7.81            48.8            84.6            7.80            3.62            53.6            84.6
Coal Creek #2...........................            7.81            48.8            84.6            7.80            3.89            50.2            84.6
Coyote..................................            7.81            48.8            84.6            7.79            3.17            59.2            84.6
Leland Olds #1..........................            7.81            48.8            84.6            7.79            2.51            67.8            84.6
Leland Olds #2..........................            7.81            48.8            84.6            7.79            3.02            61.3            84.6
Milton R Young #1.......................            7.81            48.8            84.6            7.78            3.23            58.4            84.6
Milton R Young #2.......................            7.81            48.8            84.6            7.79            3.20            58.9            84.6
Spiritwood Station......................            7.81            48.8            84.6            5.03            1.86            63.1            76.1
Limestone #1............................           14.88            73.1            91.9            6.24            0.94            84.9            80.8
Limestone #2............................           14.88            73.1            91.9            6.20            1.59            74.4            80.7
Major Oak #1............................           14.65            72.7            91.8           14.62            1.24            91.5            91.8
Major Oak #2............................           14.65            72.7            91.8           14.65            1.31            91.1            91.8
Martin Lake #1..........................           14.65            72.7            91.8            8.22            2.32            71.8            85.4
Martin Lake #2..........................           14.65            72.7            91.8            8.13            2.99            63.2            85.2
Martin Lake #3..........................           14.65            72.7            91.8            7.85            3.04            61.3            84.7

Oak Grove #1............................           14.88            73.1            91.9           14.60            2.01            86.2            91.8
Oak Grove #2............................           14.88            73.1            91.9           14.88            2.59            82.6            91.9
Red Hills #1............................           12.44            67.8            90.4           12.40            1.33            89.3            90.3
Red Hills #2............................           12.44            67.8            90.4           12.40            1.35            89.1            90.3
San Miguel..............................           14.65            72.7            91.8           14.62            2.81            80.8            91.8
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As can be seen in the table, all lignite-fired EGUs are estimated
to meet the current standard by achieving a level of control of less
than 75 percent. The average reported 2021 Hg emission rate for
lignite-fired EGUs located in North Dakota was 3.0 lb Hg/TBtu with an
average control of 83.7 percent. The average reported 2021 Hg emission
rate for lignite-fired EGUs located in Texas and Mississippi was 2.0 lb
Hg/TBtu (with an average control of 88.2 percent).
f. Proposed Revision of the Hg Emission Standard for Lignite-Fired EGUs
    Several commenters have provided information on new developments in
Hg control technology. One commenter \38\ indicated that improvements
in halogen and ACI technologies have significantly lowered the costs of
those pollution control systems. The use of computational fluid
dynamics and physical modeling has also improved pollutant capture and
reduced sorbent consumption. The commenter further noted that ACI
systems operate more reliably, and many users utilize technology to
improve the dispersion of sorbents in flue gas for better performance.
After reviewing the available literature and other studies and
available information, the assumptions made regarding Hg control in the
2012 MATS Final Rule, and the information obtained from compliance
reports and the 2022 CAA section 114 information collection, the EPA
has determined that there are developments in practices, processes, and
control technologies since 2012 that warrant consideration of revising
the Hg standards for lignite-fired EGUs. As explained below, the EPA
has further determined that available controls and methods of operation
that will allow lignite-fired EGUs to meet the same Hg emission
standard that is being met by EGUs firing on non-lignite coals, and
that the costs of doing so are reasonable.\39\ Therefore, the EPA is
proposing to revise the Hg emission standard for lignite-fired EGUs to
1.2E-06 lb/MMBtu.
---------------------------------------------------------------------------

    \38\ See EPA-HQ-OAR-2018-0794-1171.
    \39\ As discussed in section V.B above, prior CAA section
112(d)(2) technology reviews conducted by the EPA establish that
obtaining better information on performance of controls can provide
the basis for updates to standards under a technology review.
---------------------------------------------------------------------------

i. Both Lignite and Subbituminous Coal Are Low Rank Coals With Low
Halogen Content
    Coal is classified into four main types, or ranks: \40\ anthracite,
bituminous, subbituminous, and lignite. The ranking depends on heating
value of the coal. Anthracite has the highest heating value of all
ranks of coal and is mostly used by the metals industry (it is rarely
using for power production). Anthracite accounted for less than 1
percent of the coal mined in the U.S. in 2021. Bituminous coal is also
considered a ``high rank coal'' because of its higher heating value. It
is the most abundant rank of domestic coal and accounted for about 45
percent of total U.S. coal production in 2021. Bituminous coal is used
to generate electricity and in other industries.
---------------------------------------------------------------------------

    \40\ ``Coal Explained, Types of Coal'' Energy Information
Administration, available at www.eia.gov/energyexplained/coal and in
the rulemaking docket.
---------------------------------------------------------------------------

    Subbituminous coal and lignite are referred to as ``low rank
coals.'' They both have lower heating values than bituminous coal.
Subbituminous coal accounted for about 46 percent of total U.S. coal
production in 2021, with the vast majority produced in the Powder River
Basin (PRB) of Wyoming and Montana. Lignite has the lowest energy
content of all coal ranks. Lignite accounted for about 8 percent of
total U.S. coal production in 2021.\41\ About 56 percent was mined in
North Dakota (Fort Union lignite) and about 36 percent was mined in
Texas (Gulf Coast lignite).
---------------------------------------------------------------------------

    \41\ EIA Annual Coal Report 2021, October 2022, https://www.eia.gov/coal/annual/pdf/acr.pdf.
---------------------------------------------------------------------------

    Chlorine is the most abundant halogen in coal. Bromine may also be
present in coal but is typically in much lower concentrations than
chlorine.\42\ Low-rank coals such as lignite and subbituminous
generally have lower chlorine contents than higher rank coals such as
bituminous coal.\43\
---------------------------------------------------------------------------

    \42\ See Figure 5 in the U.S. Geological Survey publication
``Mercury and Halogens in Coal--Their Role in Determining Mercury
Emissions From Coal Combustion'' available at https://pubs.usgs.gov/fs/2012/3122/pdf/FS2012-3122_Web.pdf.
    \43\ Id.
---------------------------------------------------------------------------

    As mentioned earlier, the halogen content of the coal--especially
chlorine--largely influences the oxidation state of Hg in the flue gas
stream. As a result, the halogen content of the coal directly
influences the ability to capture and contain the Hg before it is
emitted into the atmosphere. As explained earlier, ash from lignite and
subbituminous coals tends to be more alkaline (relative to that from
bituminous coal) due to the lower amounts of sulfur and halogen and the
presence of a more alkaline and reactive (non-glassy) form of calcium
in the ash. The natural alkalinity of the subbituminous and lignite fly
ash can effectively neutralize the limited free halogen in the flue gas
and prevent oxidation of the Hg\0\. This makes control of Hg from both
subbituminous coal-fired EGUs and lignite-fired EGUs more challenging
than the control of Hg from bituminous coal-fired EGUs. However,
because control strategies and technologies were developed to introduce
halogens to the flue gas stream, EGUs firing subbituminous coals have
been able to meet the 1.2 lb/TBtu emission standard in the 2012 MATS
Final Rule. As mentioned earlier, EGUs firing subbituminous coal in
2021 emitted Hg at an average annual rate of 0.6 lb Hg/TBtu with
measured values as low as 0.1 lb/TBtu. Clearly EGUs firing
subbituminous coal have found control options to meet--and exceed--the
1.2 lb/TBtu emission standard despite the challenges presented by the
low natural halogen content of the coal and production of difficult-to-
control elemental Hg vapor in the flue gas stream.

ii. The Hg Content of Fort Union Lignite and PRB Subbituminous Coal Are
Similar
    As can be seen in Table 8 above, for the 2012 MATS Final Rule, the
EPA estimated the Fort Union lignite-fired EGUs inlet Hg concentration
at up to 7.8 lb/TBtu and estimated the inlet Hg concentration of
subbituminous coal-fired EGUs at up to 8.65 lb/TBtu. These values are
very similar to results from a published study that found the average
Hg concentration of Fort Union lignite and PRB subbituminous coals to
be very similar. The study found that the Fort Union lignite samples
contained an average of 8.5 lb/TBtu and the PRB subbituminous coal
samples contained an average of 7.5 lb/TBtu.\44\ Despite the
similarities in Hg content, halogen content, and alkalinity between
Fort Union lignite and PRB subbituminous coal, EGUs firing
subbituminous coal in 2021 emitted Hg at an average annual rate of 0.6
lb Hg/TBtu while those firing on Fort Union lignite emitted Hg at an
average annual rate of 3.0 lb Hg/TBtu. While the EGUs firing Fort Union
lignite at an average emission rate of 3.0 lb Hg/TBtu are complying
with the 2012 MATS Final Rule emission standard of 4.0 lb Hg/TBtu, it
is difficult to justify why those units should not meet a similar level
of Hg control as that of the EGUs firing PRB subbituminous coal given
the similarities between the two fuels--especially the similarities in
Hg content, halogen content, and alkalinity.
---------------------------------------------------------------------------

    \44\ ``Mercury in North Dakota lignite'', Katrinak, K.A.;
Benson, S.A.; Henke, K.R.; Hassett, D.J.; Fuel Processing
Technology, 39, 35, 1994.
---------------------------------------------------------------------------

iii. The Hg Content of Gulf Coast Lignite Is Greater Than That of Fort
Union Lignite; and Several Lignite-Fired EGUs in Texas Have Co-Fired
Significant Quantities of Subbituminous Coal
    The Hg content of Gulf Coast lignite tends to be higher than that
of the Fort Union lignite. As can be seen in Table 8 above, for the
2012 MATS Final Rule, the EPA estimated the inlet Hg concentration for
Gulf Coast lignite-fired EGUs at an average inlet Hg concentration of
up to 14.9 lb/TBtu (as compared to average inlet Hg concentrations of
up to 7.8 lb/TBtu for Fort Union lignite). Despite the higher Hg
content in Gulf Coast lignite, EGUs permitted as lignite-fired had, in
2021, an average Hg emission rate of 2.0 lb/TBtu--which was lower than
the 2021 average emission rate of EGUs firing Fort Union lignite (at
3.0 lb/TBtu). This is due, in part, because some EGUs in Texas that are
permitted as lignite-fired units (and thus subject to the Hg emission
standard of 4.0 lb/TBtu) were, in 2021, firing significant amounts of
subbituminous coal. Firing high levels of non-lignite coal (in some
cases greater than 99 percent non-lignite coal), while remaining
subject to the less stringent Hg emission standard for the subcategory
of lignite-fired EGUs seems to fit the scenario that the EPA expressed
concern about in the 2012 MATS Final Rule preamble--that ``sources to
potentially meet the definition by combusting very small amounts of low
rank virgin coal [lignite].'' See 77 FR 9379.
iv. The Proposed More Stringent Hg Emission Standard Can Be Achieved,
Cost-Effectively, Using Available Control Technology
    For the 2012 MATS Final Rule, the EPA calculated beyond-the-floor
costs for Hg controls by assuming injection of brominated activated
carbon at a rate of 3.0 lb/MMacf for units with ESPs and injection
rates of 2.0 lb/MMacf for units with baghouses (also known as FF). Yet,
in responses to the CAA section 114 information survey, only one
facility (Oak Grove) explicitly indicated use of brominated activated
carbon. Oak Grove units #1 and #2 (both using FF for PM control)
reported use of brominated activated carbon at an average injection
rate of less than 0.5 lb/MMacf for operation at capacity factor greater
than 70 percent. The Oak Grove units fired, in 2021, using mostly
refined coal.\45\ That injection rate is considerably less than the 2.0
lb/MMacf assumed.
---------------------------------------------------------------------------

    \45\ EIA form 923 does not specify the rank of coal that is
``refined'' in boiler or generator fuel data. For this technology
review, the EPA has assumed that facilities reporting the use of
refined coal have utilized ``refined lignite,'' which was confirmed
in EIA form 923 fuel receipts and costs.
---------------------------------------------------------------------------

    From the CAA 114 information survey, the average injection rate
reported for non-halogenated sorbents was 2.5 lb/MMacf. The average
sorbent injection rate ranged from 10-65 percent of the maximum design
sorbent injection rate (the average was 36 percent of the maximum
design rate). As mentioned earlier, most sources utilized a control
strategy of sorbent injection coupled with chemical (usually
halogenated) additives. In the beyond-the-floor analysis in the 2012
MATS Final Rule, we noted that the results from various demonstration
projects suggests that greater than 90 percent Hg control can be
achieved at lignite-fired units using brominated activated carbon
sorbent at an injection rate of 2.0 lb/MMacf for units with installed
FFs for PM control and at an injection rate of 3.0 lb/MMacf for units
with installed ESPs for PM control. As shown in Table 8 above, all
units (in 2021) would have needed to control their Hg emissions to less
than 92 percent to meet an emission standard of 1.2 lb/TBtu. Based on
this, we expect that the units could meet the proposed, more stringent,
emission standard of 1.2 lb/TBtu by utilizing brominated activated
carbon at the injection rates suggested in the beyond-the-floor memo
\46\ from the 2012 MATS Final Rule.
---------------------------------------------------------------------------

    \46\ See Docket ID No. EPA-HQ-OAR-2009-0234-20130 at
regulations.gov.
---------------------------------------------------------------------------

    To determine the cost-effectiveness of that strategy, we calculated
the incremental cost-effectiveness (cost per lb of Hg controlled) for a
model 800 MW lignite-fired EGU. We calculated the incremental cost of
injecting non-brominated activated carbon sorbent at a sufficiently
large injection rate of 5.0 lb/MMacf to achieve an emission rate of 1.2
lb/TBtu versus the cost to meet an emission rate of 4.0 lb/TBtu using
non-brominated activated carbon sorbent at an emission rate of 2.5 lb/
MMacf. For an 800 MW lignite-fired EGU, the incremental cost
effectiveness was $8,703 per incremental lb of Hg removed. The actual
cost-effectiveness is likely lower than this value as it is unlikely
that sources will need to inject brominated activated carbon sorbent at
rates as high as 5.0 lb/MMacf (the Oak Grove units were injecting less
than 0.5 lb/MMacf) and is well below the cost that the EPA has found to
be acceptable in previous rulemakings (e.g., $27,500/lb Hg was proposed
to be cost-effective for the Primary Copper RTR (87 FR 1616);
approximately $27,000/lb Hg was found to be cost-effective in the
beyond-the-floor analysis supporting the 2012 MATS Final Rule \47\).
---------------------------------------------------------------------------

    \47\ Ibid.
---------------------------------------------------------------------------

    In summary, the EPA is proposing to revise the Hg emission standard
for lignite-fired EGUs from 4.0E-06 lb/MMBtu to 1.2E-06 lb/MMBtu, which
is the same Hg emission limit that non-lignite-fired EGUs must meet. We
are proposing to revise this emission standard while recognizing that
Hg from the combustion of lignite is challenging to capture because of
the lack of naturally occurring halogen in the fuel and because of the
natural alkalinity of the resulting fly ash. However, Hg from the
combustion of subbituminous coal is similarly challenging to capture
for the same reasons. Yet, EGUs firing subbituminous coal in 2021
emitted Hg at an average rate of 0.6 lb/TBtu and some as low as 0.1 lb/
TBtu. From the CAA section 114 information survey, very few lignite-
fired EGUs are using the control technology that the EPA identified as
the most effective for Hg control in the 2012 MATS Final Rule,

brominated ACI, which many demonstration projects have shown can
achieve Hg control of greater than 90 percent. Although we are not
proposing to mandate the use of any particular control technology, we
have shown that use of brominated activated carbon sorbent injection
can be used to cost-effectively meet the more stringent emission.
    We also considered the energy implications and non-air
environmental impacts of this proposed revision of the Hg emission
standard for lignite-fired EGUs. We do not anticipate any energy
implications from this proposed revision as most units are already
using sorbent injection technology as part of the Hg control strategy
and we do not project significant changes in unit operations as a
result of the proposed revision. Regarding the non-air environmental
impact, we anticipate that there may be positive non-air environmental
impacts. The current strategies employed by most lignite-fired EGUs
involve the injection of oxidizing halogen additives and, separately,
injection of sorbent (typically non-brominated activated carbon).
Because homogeneous (gas-phase) oxidation of Hg\0\ is kinetically
limited, most of the Hg\0\ oxidation is thought to occur as
heterogeneous (solid-phase) reactions resulting from halogens or other
oxidants attached to flue gas solids (e.g., unburned carbon, other).
This is essentially a two-step process where the injected (or natural)
halogen (chloride or bromide) must first attach to a flue gas solid and
then contact and react with gas-phase Hg\0\. The addition of sorbent
that has already been pre-halogenated (most often brominated) is more
efficient as the first step occurs prior to injection. This means that
less bromine will be unutilized and captured in a downstream control
device or potentially included in the plant water effluent discharge.
The EPA requests comment on its expectation that most EGUs (including
lignite-fired EGUs) will no longer use ``refined coal'' due to the
expiration of the refined coal tax credit. The amount of Br on
brominated activated carbon is much less than that used to produce
refine coal, and Br is retained on the activated carbon sorbent where
it reacts with gas phase Hg and is captured by downstream control
devices. Thus, the EPA believes that cross-media transfers of bromine
to receiving waterbodies and emitted to the atmosphere, especially when
wet FGD is not employed, are not expected (or would certainly be lower)
with the use of brominated sorbents as compared to use of refined coal
and that any negative health, ecological, and productivity effects
associated with bromine transfer to water effluent will be minimized or
avoided, especially given the EPA's proposed zero-discharge
requirements under the Clean Water Act (88 FR 18824; March 29, 2023).
4. No Revisions to Work Practice Standards for Organic HAP
    Following promulgation of the 2020 Final Action, in which the EPA
found no developments in new technology or methods of operation that
would result in cost-effective emission reductions of organic HAP and
thus did not revise the work practice standards for organic HAP, the
EPA received a petition for reconsideration that, in relevant part,
requested the EPA to reconsider work practice standards for organic
HAP.\48\ Our review of new technology and of methods of operation
conducted as part of this technology review proposal also found no
developments that would result in cost-effective emission reductions of
organic HAP. Likewise, we are not proposing revisions to the organic
HAP work practice standards finalized in the 2012 MATS Final Rule.\49\
The EPA acknowledges that it received a petition for reconsideration
from environmental organizations that, in relevant part, sought the
EPA's reconsideration of organic HAP work practice standards, which the
EPA continues to review and will respond to in a separate action.\50\
---------------------------------------------------------------------------

    \48\ See Docket ID No. EPA-HQ-OAR-2018-0794-4565 at
www.regulations.gov.
    \49\ See 40 CFR 63.9991, Table 3.
    \50\ See Docket ID No. EPA-HQ-OAR-2018-0794-4565 at
www.regulations.gov.
---------------------------------------------------------------------------

5. No Proposed Revisions to the Acid Gas Standards for Coal-Fired EGUs
    The EPA evaluated the use of control technologies and strategies
that are commonly used for control of acid gas HAP (e.g., HCl, HF).
These control technologies and strategies include the use of wet FGD
scrubbers, spray drier absorber (SDA) scrubbers, reagent injection (for
fluidized combustors), dry sorbent injection (DSI), and use of low
sulfur or low halogen fuels. As described in section III of this
preamble, EGUs in six subcategories are subject to numeric emission
limits for acid gas HAP (e.g., HCl, HF). Emission standards for HCl
serve as a surrogate for all acid gas HAP, with an alternate standard
for SO2 that may be used as a surrogate for the acid gas HAP
at coal-fired EGUs with operational FGD systems and SO2
CEMS.
    When the EPA finalized the 2012 MATS Final Rule, the primary air
pollution control devices installed at EGUs for the control of acid
gases were wet scrubbers (wet FGD), dry scrubbers (dry FGD or spray
dryer absorber, SDA), and reagent injection (at fluidized bed
combustors). These technologies are still in wide use for acid gas HAP
control. An additional acid gas control technology--dry sorbent
injection (DSI)--was in limited use in the power sector at the time the
MATS rule was finalized but has seen increased use since (approximately
20 percent of EGUs operating in 2021 utilized DSI for acid gas control
for one reason or another).
    A wet FGD scrubber uses an alkaline liquid slurry (usually a
limestone or lime slurry) to remove acidic gases from an exhaust
stream. The acid gases react with the alkaline compounds in the slurry
and are removed as scrubber solids (e.g., CaSO3 or
CaSO4) or may be captured due to their solubility in the
scrubber slurry. Most wet FGD scrubbers have SO2 removal
efficiencies exceeding 90 percent and perform even better for HCl and
HF. Dry FGD scrubbers (SDA) are an acid gas pollution control system
where an alkaline sorbent slurry is injected into the flue gas stream
to react with and neutralize acid gases in the exhaust stream forming a
dry powder material which is then captured in a downstream PM control
device (usually an FF). Alkaline sorbent injection systems (reagent
injection) are also used in fluidized bed combustors (FBC) and
circulating fluidized bed (CFB) boilers for control of acid gases. In
that use, the alkaline sorbent (usually powdered limestone) is injected
into the combustion chamber with the primary fuel. Dry sorbent
injection (DSI) is an add-on air pollution control system in which a
dry alkaline powdered sorbent (typically sodium- or calcium-based) is
injected into the flue gas steam upstream of a PM control device to
react with and neutralize acid gases in the exhaust stream forming a
dry powder material that may be removed in a primary or secondary PM
control device. The EPA evaluated the use of these control technologies
(wet FGD scrubbers, SDA, reagent injection, and DSI), and the strategic
use of low sulfur or low halogen fuels.
    The EPA reviewed compliance data for SO2 and/or HCl, as
shown in Figure 3 of the Technical Memo, showing EGUs with highest
SO2 emissions in 2021 to those with the lowest
SO2 emissions in 2021. Approximately two-thirds of coal-
fired EGUs have demonstrated compliance with the

alternative SO2 emission standard rather than the HCl
emission limit. About one-third of EGUs have demonstrated compliance
with the primary acid gas emission limit for HCl. And some sources have
reported emissions data that demonstrates compliance with either of the
standards. The emission rates for HCl that are shown in Figure 3 of the
Technical Memo distinguish between EGUs that utilize some sort of acid
gas control system--which would be a wet FGD scrubber, a dry scrubber
(an SDA), reagent injection or DSI--and EGUs that do not have a wet FGD
scrubber or an SDA and do not utilize either reagent injection or DSI.
All of the EGUs with no acid gas controls are units that were firing
subbituminous coal and were likely able to demonstrate compliance with
the HCl emission standard due to the low natural chlorine content and
high alkalinity of most subbituminous coals.
    All sources submit SO2 emissions data to comply with
other CAA requirements (e.g., the Acid Rain Program). As mentioned
earlier, some sources submitted emissions data that demonstrates
compliance with either the HCl standard or the alternative
SO2 standard. The average SO2 emission rate for
units at or below the alternative SO2 emission limit was
9.0E-02 lb SO2/MMBtu, which is approximately 55 percent
below the SO2 emission limit of 2.0E-01 lb SO2/
MMBtu. The average HCl emission rate for units demonstrating compliance
with the SO2 standard but also reporting HCl emissions was
4.0E-04 lb HCl/MMBtu, which is approximately 80 percent below the HCl
emission limit of 2.0E-03 lb HCl/MMBtu. This result is consistent with
the EPA's rationale for establishing the alternative SO2
emission limit--because HCl emissions are much more easily controlled
than SO2 emissions (HCl and HF are much more reactive and
much more water soluble than SO2), controlling emissions of
SO2 using FGD controls very effectively controls emissions
of HCl. Note that an EGU may demonstrate compliance with the acid gas
surrogate SO2 standard only if the unit has some type of
installed acid gas control and an operational SO2 CEMS.
    The EPA looked further at the HCl emissions of the EGUs operating
in 2021 with and without acid gas controls. The average emission rate
of EGUs with no add-on acid gas control was 8.0E-04 lb HCl/MMBtu, which
is 60 percent below the SO2 emission limit.
    The EPA looked closer at the relative performance of acid gas
controls for HCl emissions. The best performing EGUs tend to be those
that utilize either wet or dry FGD scrubbers, with units utilizing
sorbent injection emitting at slightly higher rates. The units that
utilize DSI with an FF tend to have lower HCl emissions than those that
utilize DSI with an ESP. This is an expected outcome as the filter cake
on the FF provides great opportunity for contact with the gas phase
acid gases.
    Overall, the EPA has evaluated acid gas emissions data from MATS-
affected EGUs and have determined that some units have demonstrated
compliance with the primary HCl emission standard using acid gas
control technologies (wet FGD scrubbers, SDA, reagent injection, and
DSI) and through the strategic use of low-halogen, high-alkalinity
fuels. Other units have demonstrated compliance with acid gas emission
limits by meeting or exceeding the alternative surrogate SO2
emission standard. The average HCl emission rates for units with add-on
acid gas controls was 4.0E-04 lb HCl/MMBtu which is approximately 80
percent below the MATS HCl emission limit. The average HCl emission
rates for units with no add-on acid gas controls was 8.0E-04 lb HCl/
MMBtu (approximately 60 percent below the MATS HCl emission limit). It
is not clear that improvements in a wet or dry FGD scrubber would
result in additional HCl emission reductions since HCl emissions are
already much easier to control than SO2 emissions. The EPA
does not have information on the sorbent injection rates for DSI
systems; so, we cannot assess whether increased sorbent injection would
result in additional HCl emission reductions. Units using DSI in
combination with an ESP would almost certainly see improved performance
if they were to replace the ESP with a FF. However, that small
incremental reduction in HCl emissions would come at a high cost and
would certainly not be a cost-effective option.
    In the 2020 Technology Review, the EPA concluded that ``the
existing acid gas pollution control technologies that are currently in
use are well-established and provide the capture efficiencies necessary
for compliance with the promulgated MATS rule limits.'' Comments
received during the 2020 Proposal did not provide any new practices,
processes, or control technologies for acid gas control. One commenter
noted that ``in the short time since the RTR was finalized, there have
been no developments in practices, processes, or control technologies,
nor any new technologies or practices for the control of . . . acid gas
HAP'' (Docket ID No. EPA-HQ-OAR-2018-5121). Another commenter pointed
to an independent comprehensive report to show acid gas emission
controls had better performance and lower capital costs than the EPA
assumed in the 2011 modeling (Docket ID No. EPA-HQ-OAR-2018-0794-4962).
That report suggested control technology improvements to acid gas
controls to achieve revised HCl emission standards of 1.0E-03 lb HCl/
MMBtu, 6.0E-04 lb HCl/MMBtu, and 1.0E-05 lb HCl/MMBtu through addition
of new DSI systems, upgrades to existing DSI systems, upgrades to
existing wet and dry scrubbers, and, for the most stringent options,
installation of new FFs. However, as mentioned earlier--and as detailed
further in the Technical Memo--it is not clear that such improvements
targeting acid gases would result in corresponding reductions in HCl or
HF emissions, as emissions of HCl and HF are already much easier to
control than emissions of SO2.
    In summary, the EPA has not identified any new control technologies
or any improvements to existing acid gas controls that would result in
additional cost-effective acid gas HAP emission reductions from coal-
fired EGUs and is, therefore, not proposing revisions to the acid gas
emission standards or for the surrogate SO2 emission
standard. However, the EPA solicits comment on any new practices,
processes, or technologies for control of acid gas HAP emissions,
including any information on whether increased sorbent injection rates
(for sources using DSI or SDA controls) would result in additional HCl
emission reductions, that could inform the potential for additional
cost-effective acid gas HAP emission reductions from coal-fired EGUs.
6. No Proposed Revisions to Standards for Continental Liquid Oil-Fired
EGUs
    The annual capacity factors of most continental liquid oil-fired
units are low. Based on available data reported to the EIA and the
EPA's Clean Air Markets Program Data (CAMPD), in 2021 the average
annual capacity factor for liquid oil-fired units was 3 percent.
Additionally, there were only two continental liquid oil-fired units
identified with 2-year capacity factors greater than 8 percent. Those
two units primarily fire natural gas but had heat input-based
percentages of fuel oil firing that were about 16 percent in at least
one of the years from 2019 through 2021 (i.e., slightly above the 15
percent that would qualify them as oil-fired units). Therefore, it is
likely that there are very few continental liquid oil-fired units that
would be outside of the definition

of the limited-use liquid oil-fired subcategory.
    Furthermore, for the continental liquid oil-fired units with
available data that are likely limited-use units, the cumulative
percentage of heat input from residual fuel oil in 2021 was 32 percent,
the heat input of distillate fuel oil was 4 percent, and the heat input
from natural gas was 64 percent. Because the capacity factors of most
continental liquid oil-fired units are low, and most combustion by
those units is using fuel (i.e., natural gas) with low metallic HAP
emission rates, the EPA is not proposing changes to the total HAP
metals (which includes Hg), nor to the standards for the individual HAP
metals, nor to the HAP metal surrogate fPM emission standard for
continental liquid oil-fired electricity generating units.
    However, given there have been several recent temporary and
localized increases in oil combustion at continental liquid oil-fired
EGUs during periods of extreme weather conditions, such as the 2023
polar vortex in New England, the EPA seeks comment on whether the
current definition of the limited-use liquid oil-fired subcategory
remains appropriate or if, given the increased reliance on oil-fired
generation during periods of extreme weather, a period other than the
current 24-month period or a different threshold would be more
appropriate for the current definition. The EPA also seeks comment on
the appropriateness of including new HAP standards for EGUs subject to
the limited use liquid oil-fired subcategory, as well as on the means
of demonstrating compliance with the new HAP standards. For example, in
order to reduce HAP emissions during periods of extreme weather
conditions, it may be appropriate for limited-use liquid oil-fired EGUs
to use distillate fuel oil instead of residual oil, or to switch from
residual oil to cleaner fuels after a certain number of hours of
operation, or to be subject to an annual or seasonal limit of residual
oil firing. The EPA solicits comment on each of these options.
    The EPA also solicits comment on establishing a HAP emission limit
on liquid oil-fired EGUs (including those in the limited-use
subcategory and those located in non-continental areas) where
compliance would be demonstrated through fuel sampling and analysis.
The EPA seeks comment from the regulated community, citizens, and
regulatory authorities on the need for a revision to the limited-use
oil-fired subcategory definition and on additional, cost-effective
methods to minimize HAP emissions during periods of limited operation.
7. No Proposed Revisions to Standards for Non-Continental Liquid Oil-
Fired EGUs
    Hawaiian Electric Company (HECO) operates 12 liquid oil-fired
boilers at its Waiau Generating Station (Pearl City, HI) and at its
Kahe Generating Station (Kapolei, HI). Their average capacity factor in
2021 was 29.6 percent (on a net basis) and they fire on residual fuel
oil. HECO has, in compliance reports, reported fPM emission rates to
the EPA that are below the fPM emission rate of 3.0E-02 lb/MMBtu.
    In Puerto Rico, there are 14 liquid oil-fired MATS-affected EGUs
(3,552 MW total capacity) at four separate facilities operated by the
Puerto Rico Electric Power Authority (PREPA). The EGUs operate using
residual fuel oil and do not currently have any emission controls for
NOX, PM or SO2. At least two of the units have
dual fuel capabilities and have operated on high levels of natural gas.
There is limited stack testing data available, but testing done in 2021
and 2022 indicated fPM emission rates ranging from 2.6E-02 lb/MMBtu to
2.9E-02 lb/MMBtu, a range that is just below the fPM emission rate of
3.0E-02 lb/MMBtu.
    As mentioned earlier in section IV.A of this preamble summarizing
the 2020 Residual Risk Review, the results of the chronic inhalation
cancer risk assessment based on actual emissions indicated that the
estimated maximum individual lifetime cancer risk (cancer MIR) was 9-
in-1 million, with nickel emissions from oil-fired EGUs at these four
facilities in Puerto Rico as the major contributor to the risk. The
total estimated cancer incidence from this source category was 0.04
excess cancer cases per year, or one excess case in every 25 years.
Approximately 193,000 people were estimated to have cancer risks at or
above 1-in-1 million from HAP emitted from the facilities in this
source category. The estimated maximum chronic noncancer TOSHI for the
source category was 0.2 (respiratory), which was driven by emissions of
nickel and cobalt from the oil-fired EGUs.
    Since these oil-fired EGUs do not have installed control devices
for HAP metals (PM controls), there is no opportunity to improve their
performance in the same ways the EPA found available to some coal-fired
EGUs. PREPA has recently proposed near-term retirement dates (by 2026)
for 10 of the 14 oil-fired EGUs with two of the other four remaining
boilers burning mostly natural gas.
    Because of the low capacity factors of the Hawaii oil-fired EGUs
and the near-term retirement dates of most of the Puerto Rico liquid
oil-fired EGUs and plans for a transition to greater use of natural gas
for the remaining boilers, the EPA is not proposing to revise emission
standards for non-continental oil-fired EGUs.
    However, the EPA seeks comment on whether the fPM surrogate
emission standard is appropriate for these non-continental liquid oil-
fired EGUs. As mentioned, the largest risks identified in the 2020 RTR
were associated with nickel emissions from residual oil-fired EGUs
located in Puerto Rico. The EPA solicits comment on eliminating or
revising the fPM standard for existing non-continental sources, and,
instead, requiring these EGUs to comply with the existing emission
limits for the individual metals, including nickel. In addition, the
EPA also seeks comment on the appropriateness of including new HAP
standards for EGUs in Puerto Rico and Hawaii, as well as other non-
continental U.S. areas, such as Guam and the Virgin Islands, and the
means of demonstrating compliance with the new HAP standards. For
example, the EPA seeks input on whether, in order to reduce HAP
emissions and associated risks in these places, oil-fired EGUs should
be required to switch from residual oil to cleaner fuels, or to switch
to cleaner fuels after a certain number of hours of operation, or
should be subject to an annual limit of residual oil firing. The EPA
solicits comment on whether compliance with a HAP metal emission limit
could be demonstrated by fuel sampling and analysis. The EPA solicits
comment on the need for additional, cost-effective methods to minimize
HAP emissions in non-continental states and territories--including
Hawaii, Puerto Rico, the U.S. Virgin Islands, and Guam. We solicit
comment on any special considerations--including the availability of
clean fuels such as distillate fuel oil and natural gas--in non-
continental areas.
8. No Proposed Revisions to Standards for IGCC EGUs
    The EPA is aware of two existing IGCC facilities that meet the
definition of an IGCC EGU. The Edwardsport Power Station, located in
Knox County, Indiana, includes two IGCC EGUs that had 2021 average
capacity factors of approximately 85 percent and 67 percent. The Polk
Power Station, located in Polk County, Florida, had a 2021 average
capacity factor of approximately 70 percent, but burned only natural
gas in 2021.

    While this subcategory has a less stringent fPM standard of 4.0E-02
lb/MMBtu (as compared to that of coal-fired EGUs), recent compliance
data indicates fPM emissions well below the most stringent standard
option of 6.0E-03 lb/MMBtu that was evaluated for coal-fired EGUs.
Since there are only two IGCC EGU facilities, and the EPA is unaware of
any developments in the HAP emission controls used at IGCC units, the
EPA is not proposing to revise any of the emission standards for this
subcategory. However, the EPA is proposing that the affected facilities
must install a PM CEMS to demonstrate compliance with the existing fPM
limit. Further, the EPA solicits comment on cost-effective methods to
achieve additional HAP emission reductions from this subcategory.

D. What other actions are we proposing, and what is the rationale for
those actions?

    In addition to the proposed actions described above, we are
proposing additional revisions to the NESHAP.
1. Startup Requirements
    In the Reconsideration of Certain Startup/Shutdown Issues: National
Emission Standards for Hazardous Air Pollutants From Coal- and Oil-
Fired Electric Utility Steam Generating Units and Standards of
Performance for Fossil-Fuel-Fired Electric Utility, Industrial-
Commercial-Institutional and Small Industrial-Commercial-Institutional
Steam Generating Units (79 FR 68777; November 19, 2014), the EPA took
final action on its reconsideration of the startup and shutdown
provisions by adding an alternative work practice standard for startup
periods. That alternative work practice standard, referred to as
paragraph (2) of the definition of ``startup'', required clean fuel use
to the maximum extent possible, operation of PM control devices within
1 hour of introduction of primary fuel (i.e., coal, residual oil, or
solid oil-derived fuel) to the EGU, collection and submission of
records of clean fuel use and emissions control device capabilities and
operation, as well as adherence to applicable numerical standards
within 4 hours of the generation of electricity or thermal energy for
use either on site or for sale over the grid (i.e., the end of startup)
and to continue to maximize clean fuel use throughout that period. The
EPA provided this alternative work practice because many commenters
asserted it would be difficult, if not impossible, for their EGUs to
meet the already-promulgated startup work practices.\51\ In Chesapeake
Climate Action Network v. EPA, the D.C. Circuit remanded the
alternative work practice standard for startup and shutdown to the EPA
for reconsideration based on a petition for reconsideration from
environmental groups. 952 F.3d 310 (D.C. Cir. 2020). In this action,
and in conjunction with the EPA's authority pursuant to CAA section
112(d)(6), the EPA is granting in part petitions for reconsideration
which sought the EPA's review of startup and shutdown provisions.\52\
As part of our obligation to address the remand on this issue, we
reviewed the information available to us. As discussed below, that
information shows that the conditions contained in the alternative work
practice standard do not represent what the best performers are able to
do; moreover, as a practical matter, few EGUs have chosen to use the
alternative work practice standard.
---------------------------------------------------------------------------

    \51\ See Assessment of Startup Period at Coal-Fired Electric
Generating Units, available at Docket ID No. EPA-HQ-OAR-2009-0234-
20378.
    \52\ See Docket ID No. EPA-HQ-OAR-2018-0794-4565 at
www.regulations.gov; see also Chesapeake Climate Action Network v.
EPA, 952 F.3d 310 (D.C. Cir. 2020).
---------------------------------------------------------------------------

    The EPA was able to identify 14 EGUs with the ability to generate
up to 8.4 GW that chose to use the alternative work practice for
startup periods. As shown in Table 9 below, six of those EGUs with the
ability to generate up to 3.2 GW have retired and one of those EGUs
with the ability to generate up to 0.7 GW will retire by 2025.

                     Table 9--EGUs Relying on Paragraph (2) of the Definition of ``Startup''
----------------------------------------------------------------------------------------------------------------
           EGU name                  Unit          ORIS code          MW             Notes             Fuel
----------------------------------------------------------------------------------------------------------------
Prairie State Generating.....  1..............           55856             877  ...............  Bituminous.
Prairie State Generating.....  2..............           55856             877  ...............  Bituminous.
Brame Energy Center..........  Rodemacher 2...            6190             552  ...............  Subbituminous.
Brame Energy Center..........  Madison 3-1....            6190             600  ...............  Petroleum coke,
                                                                                coal.
Brame Energy Center..........  Madison 3-2....            6190             600  ...............  Petroleum coke,
                                                                                coal.
Dolet Hills..................  1..............              51             720  Retired 2021...  Lignite.
Sherburne....................  3..............            6090           938.7  Retires 2034...  Subbituminous.
Westwood.....................  1..............           50611              36  ...............  Waste coal.
Centralia....................  BW21...........            3845           729.9  Retired 2020...  Subbituminous.
Centralia....................  BW22...........            3845           729.9  Retires 2025...  Subbituminous.
St Johns River...............  1..............             207             679  Retired 2018...  Bituminous.
St Johns River...............  2..............             207             679  Retired 2018...  Bituminous.
HMP&L Station 2..............  H1.............            1382             200  Retired 2019...  Bituminous.
HMP&L Station 2..............  H2.............            1382             200  Retired 2019...  Bituminous.
----------------------------------------------------------------------------------------------------------------

    After the planned retirements in 2025, just seven EGUs with the
ability to generate up to 4.5 GW will remain; this represents less than
0.4 percent of electrical generation from all affected sources and less
than 1.7 percent of the 278 GW of coal-fired and other, non-natural gas