by the best performing 12 percent of existing sources (for which the
Administrator has emissions information) for categories and
subcategories with 30 or more sources or the best performing 5 sources
for subcategories with less than 30 sources. This requirement
determines the MACT floor for existing EGUs. However, EPA may not
consider costs or other impacts in determining the MACT floor. EPA must
consider cost, nonair quality health and environmental impacts, and
energy requirements in connection with any standards that are more
stringent than the MACT floor (beyond-the-floor controls).

D. How did EPA determine the MACT floors for existing EGUs?

    EPA must consider available emissions information to determine the
MACT floors. For each pollutant, we calculated the MACT floor for a
subcategory of sources by ranking all the available emissions data
obtained through the 2010 ICR\158\ from units within the subcategory
from lowest emissions to highest emissions (on a lb/MMBtu basis), and
then taking the numerical average of the test results from the best
performing (lowest emitting) 12 percent of sources.
---------------------------------------------------------------------------

    \158\ Earlier data were not used due to concerns related to
changes in test and analytical methods.
---------------------------------------------------------------------------

    Therefore, the MACT floor limits for each of the HAP and HAP
surrogates are calculated based on the performance of the lowest
emitting (best performing) sources in each of the subcategories.
    As discussed above, for coal-fired EGUs, EPA established the MACT
floors for non-Hg metallic HAP and non-metallic inorganic (acid gas)
HAP based on sources representing 12 percent of the number of sources
in the subcategory. For Hg from coal-fired units and all HAP from oil-
fired units, EPA established the MACT floors based on sources
representing 12 percent of the sources for which the Agency had
emissions information. The IGCC and solid oil-fired EGU subcategories
each have less than 30 units so the MACT floors were determined using
the 5 best performing sources (or 2 sources for IGCC because there are
only 2 such sources in the subcategory). The MACT floor limitations for
each of the HAP and HAP surrogates (PM, Hg, and HCl) are calculated
based on the performance of the lowest emitting (best performing)
sources in each of the subcategories. The initial sort of the
respective data to determine the MACT floor pool for analysis was made
on the ``lb/MMBtu'' formatted data; this same pool of EGUs was then
used for the ``lb/MWh'' analysis and all analyses were based on the
data provided through the 2010 ICR.
    We used the emissions data for those best performing affected
sources to determine the emission limitations to be proposed, with an
accounting for variability. EPA must exercise its judgment, based on an
evaluation of the available data, to determine the level of emissions
control that has been achieved by the best performing sources under
variable conditions. The DC Circuit Court has recognized that EPA may
consider variability in estimating the degree of emission reduction
achieved by best-performing sources in setting MACT floors. See
Mossville Envt'l Action Now v. EPA, 370 F.3d 1232, 1241-42 (DC Cir
2004) (holding EPA may consider emission variability in estimating
performance achieved by best-performing sources and may set the floor
at a level that best-performing source can expect to meet ``every day
and under all operating conditions'').
    In determining the MACT floor limitations, we first determine the
floor, which is the level achieved in practice by the average of the
top 12 percent of similar sources for subcategories with more than 30
sources. We then assess variability of the best performers by using a
statistical formula designed to estimate a MACT floor level that is
achieved by the average of the best performing sources with some
confidence (e.g., 99 percent confidence) if the best performing sources
were able to replicate the compliance tests in our data base.
Specifically, the MACT floor limit is an upper prediction limit (UPL)
calculated with the Student's t-test using the TINV function in
Microsoft Excel. The Student's t-test has also been used in other EPA
rulemakings (e.g., NSPS for Hospital/Medical/Infectious Waste
Incinerators; NESHAP for IB and Portland Cement) in accounting for
variability. A prediction interval for a future observation, or an
average of future observations, is an interval that will, with a
specified degree of confidence, contain the next (or the average of
some other pre-specified number of) randomly selected observation(s)
from a population. In other words, the prediction interval estimates
what the range of future values, or average of future values, will be,
based upon present or past background samples taken. Given this
definition, the UPL represents the value which we can expect the mean
of three future observations (3-run average) to fall below, based upon
the results of an independent sample from the same population. In other
words, if we were to randomly select a future test condition from any
of these sources (i.e., average of 3 runs), we can be 99 percent
confident that the reported level will fall at or below the UPL value.
To calculate the UPL, we used the average (or sample mean) and an
estimate of the standard deviation, which are two statistical measures
calculated from the available data. The average is a measure of
centrality of the distribution. Symmetric distributions such as the
normal are centered around the average. The standard deviation is a
common measure of the dispersion of the data set around the average.
    We first determined the distribution of the emissions data for the
best-performing 12 percent of units within each subcategory prior to
calculating UPL values. When the sample size is 15 or larger, one can
assume based on the Central Limit theorem, that the sampling
distribution of the average or sampling mean of emission data is
approximately normal, regardless of the parent distribution of the
data. This assumption justifies selecting the normal-distribution based
UPL equation for calculating the floor.
    When the sample size is smaller than 15 and the distribution of the
data is unknown, the Central Limit Theorem can't be used to support the
normality assumption. Statistical tests of the kurtosis, skewness, and
goodness of fit are then used to evaluate the normality assumption. To
determine the distribution of the best performing dataset, we first
computed the skewness and kurtosis statistics and then conducted the
appropriate small-sample hypothesis tests. The skewness statistic (S)
characterizes the degree of asymmetry of a given data distribution.
Normally distributed data have a skewness of zero (0). A skewness
statistic that is greater (less) than 0 indicates that the data are
asymmetrically distributed with a right (left) tail extending towards
positive (negative) values. Further, the standard error of the skewness
statistic (SES) can be approximated by SES = SQRT(6/N) where N is the
sample size. According to the small sample skewness hypothesis test, if
S is greater than two times the SES, the data distribution can be
considered non-normal. The kurtosis statistic (K) characterizes the
degree of peakedness or flatness of a given data distribution in
comparison to a normal distribution. Normally distributed data have a
kurtosis of 0. A kurtosis statistic that is greater (less) than 0
indicates a

relatively peaked (flat) distribution. Further, the standard error of
the kurtosis statistic (SEK) can be approximated by SEK = SQRT(24/N)
where N is the sample size. According to the small sample kurtosis
hypothesis test, if K is greater than two times the SEK, the data
distribution is typically considered to be non-normal.
    The skewness and kurtosis hypothesis tests were applied to both the
reported test values and the lognormal values (using the LN() function
in Excel) of the reported test values. If S and K of the reported data
set were both less than twice the SES and SEK, respectively, the
dataset was classified as normally distributed. If neither S nor K, or
only one of these statistics, were less than twice the SES or SEK,
respectively, then we looked at the skewness and kurtosis hypothesis
test results conducted for the natural log-transformed data. Then, the
distribution most similar to a normal distribution was selected as the
basis for calculating the UPL. If the results of the skewness and
kurtosis hypothesis tests were mixed for the reported values and the
natural log-transformed reported values, we chose the normal
distribution to be conservative. We believe this approach is more
accurate and obtained more representative results than a more
simplistic normal distribution assumption.
    Because some of the MACT floor emission limitations are based on
the average of a 3-run test, and compliance with these limitations will
be based on the same, the UPL for data considered to be normally
distributed is calculated by:
[GRAPHIC] [TIFF OMITTED] TP03MY11.000

Where:
n = the number of test runs
m = the number of test runs in the compliance average
[ballot] = mean of the data from top performing sources calculated
as
[GRAPHIC] [TIFF OMITTED] TP03MY11.001

t(0.99, n-1) is the 99th percentile of the T-Student distribution
with n-1 degrees of freedom
s2 = variance of the data from top performing sources
calculated as
[GRAPHIC] [TIFF OMITTED] TP03MY11.002

    This calculation was performed using the following Excel function:
    Normal distribution: 99% UPL = AVERAGE(Test Runs in Top 12%) +
[STDEV(Test Runs in Top 12%) x TINV(2 x probability, n-1 degrees of
freedom)*SQRT((1/n)+(1/3))], for a one-tailed t-value (with 2 x
probability), probability of 0.01, and sample size of n.
    Data from only a single unit was used in establishing the new-
source floor. Analysis based solely in these single-data-point-per-unit
observations does not capture any within source variability. When
additional information (e.g., stack averages) from the past 5 years
(from the 2010 ICR) was available, we combined the current and past
data and calculated an estimate of the variance term, s\2\, that
intends to include the within and between source variability. The most
recent data (e.g., single floor average) were used to calculate the
average in the UPL equation. The UPL equation for this case was
calculated as:
[GRAPHIC] [TIFF OMITTED] TP03MY11.003

UPL =
Where:
m = the number of test runs in the compliance average
N = the number of units involved in calculating the average (a
single measurement (e.g., floor average) per unit)
ni = number of data points (e.g., stack averages) collected in the
past for the i\th\ source
[GRAPHIC] [TIFF OMITTED] TP03MY11.004

number of data points (floor average plus stack averages) available
to calculate the variance
df = n-1
xi = current information (e.g., single floor average) for the i\th\
source
yi = past information (e.g., stack average) for the i\th\ source
m = the number of future test runs in the compliance average
[ballot] = mean of the data from top performing sources calculated
as
[GRAPHIC] [TIFF OMITTED] TP03MY11.005

[GRAPHIC] [TIFF OMITTED] TP03MY11.006

s\2\ = variance calculated as
[GRAPHIC] [TIFF OMITTED] TP03MY11.007

\t\df,.99 = quantile t-distribution with df degrees of
freedom at 99 percent confidence level df = degrees of freedom = n - 1
    The calculation of this UPL was performed using the following Excel
function:
    Normal distribution: 99% UPL = AVERAGE(Test Runs in Top 12%) +
[STDEV(Test Runs in Top 12%, stack averages) x TINV(2 x probability,
(n-1) degrees of freedom)*SQRT((1/N)+(\1/3\))], for a one-tailed t-
value (with 2 x probability), probability of 0.01, and sample size of
n.
    The UPL, to test compliance based on a 3-run average and assuming
log-normal data, is calculated by (Bhaumik and Gibbons, 2004):
[GRAPHIC] [TIFF OMITTED] TP03MY11.008

[GRAPHIC] [TIFF OMITTED] TP03MY11.009

[sgr] = the variance estimate of the log transformed data from the top
performing sources calculated as:
[GRAPHIC] [TIFF OMITTED] TP03MY11.010

z99 = the 99\th\-percentile of the log-normal
distribution estimated using the trapezoidal rule approach from the
following equation
[GRAPHIC] [TIFF OMITTED] TP03MY11.011

    The calculation of the log-normal based UPL was performed using the
following Excel function:
    Normal distribution: 99% UPL = EXP(AVERAGE(LN(Test Runs in Top
12%)) + VAR(LN(Test Runs in Top 12%))/2) + (99\TH\-PERCENTILE LOGNORMAL
DISTRIBUTION/m)*
    SQRT(m*EXP(2* AVERAGE(LN(Test Runs in Top 12%))+ VAR(LN(Test Runs
in Top 12%)))*(EXP(VAR(LN(Test Runs in Top 12%)))-1)+m[caret]2* EXP(2*
AVERAGE(LN(Test Runs in Top 12%))+ VAR(LN(Test Runs in Top
12%)))*(VAR(LN(Test Runs in Top 12%))/n+ VAR(LN(Test Runs in Top
12%))[caret]2/(2*(n-1)))).
    The 99\th\ percentile of the log-normal distribution,
z.99, was calculated following Bhaumik and Gibbons (2004).
    Test method measurement imprecision can also be a component of data
variability. At very low emissions levels, as encountered in some of
the data used to support this proposed rule, the inherent imprecision
in the pollutant measurement method has a large influence on the
reliability of the data underlying the regulatory floor or beyond-the-
floor emissions limit. Of particular concern are those data that are
reported near or below a test method's pollutant detection capability.
In our guidance for reporting pollutant emissions used to support this
proposed rule, we specified the criteria for determining test-specific
MDL. Those criteria ensure that there is about a 1 percent probability
of an error in deciding that the pollutant measured at the MDL is
present when in fact it was absent. Such a probability is also called a
false positive or the alpha, Type I, error. Another view of this
probability is that one is 99 percent certain of the presence of the
pollutant measured at the MDL. Because of matrix effects, laboratory
techniques, sample size, and other factors, MDLs normally vary from
test to test. We requested sources to identify (i.e., flag) data which
were measured below the MDL and to report those values as equal to the
test-specific MDL.
    Variability of data due to measurement imprecision is inherently
and reasonably addressed in calculating the floor emissions limit when
the data distribution, which would include the results of all tests, is
significantly above the MDL. Should the data distribution shift such
that some or many test results are below the MDL but are reported as
MDL values, as is the case for some of our database, then other
techniques need to be used to account for data variability. Indeed,
under such a shift, the distribution becomes truncated on the lower
end, leading to an artificial overabundance of values occurring at the
MDL. Such an artificial overabundance of values could, if not adjusted,
lead to erroneous floor calculations; those unadjusted floor
calculations may be higher than otherwise expected, because no values
reported below the MDL are included in the calculation. There is a
concern that a floor emissions limit based on a truncated data base may
not account adequately for data measurement variability and that a
floor emissions limit calculated using values at or near the MDL may
not account adequately for data measurement variability, because the
measurement error associated with those values provides a large degree
of uncertainty--up to 100 percent.
    Despite our concern that accounting for measurement imprecision
should be an important consideration in calculating the floor emissions
limit, we did not adjust the calculated floor for the data used for
this proposed rule because we do not know how to develop such an
adjustment. We remain open to considering approaches for making such an
adjustment, particularly when those approaches acknowledge our
inability to detect with certainty those values below the MDL. We
request comment on approaches suitable to account for measurement
variability in establishing the floor emissions limit when based on
measurements at or near the MDL.
    As noted above, the confidence level that a value measured at the
detection level is greater than 0 is about 99 percent. The expected
measurement imprecision for an emissions value occurring at or near the
MDL is about 40 to 50 percent. Pollutant measurement imprecision
decreases to a consistent relative 10 to 15 percent for values measured
at a level about three times the MDL.\159\ One approach that we believe
could be applied to account for measurement variability would require
defining a MDL that is representative of the data used in establishing
the floor emissions limitations and also minimizes the influence of an
outlier test-specific MDL value. The first step in this approach would
be to identify the highest test-specific MDL reported in a data set
that is also equal to or less than the floor emissions limit calculated
for the data set. This approach has the advantage of relying on the
data collected to develop the floor emissions limit while to some
degree minimizing the effect of a test(s) with an inordinately high MDL
(e.g., the sample volume was too small, the laboratory technique was
insufficiently sensitive, or the procedure for determining the
detection level was other than that specified).
---------------------------------------------------------------------------

    \159\ American Society of Mechanical Engineers, Reference Method
Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack
Emission Measurements, CRTD Vol. 60, February 2001.
---------------------------------------------------------------------------

    The second step would be to determine the value equal to three
times the representative MDL and compare it to the calculated floor
emissions limit. If three times the representative MDL were less than
the calculated floor emissions limit, we would conclude that
measurement variability is adequately addressed and we would not adjust
the calculated floor emissions limit. If, on the other hand, the value
equal to three times the representative MDL were greater than the
calculated floor emissions limit, we would conclude that the calculated
floor emissions limit does not account entirely for measurement
variability. We then would use the value equal to three times the MDL
in place of the calculated floor emissions limit to ensure that the
floor emissions limit accounts for measurement variability. This
adjusted value would ensure measurement variability is adequately
addressed in the floor or the emissions limit. This check was part of
the variability analysis for all new MACT floors that had below
detection level (BDL) or detection level limited (DLL) run data present
in the best controlled data set and resulted in the MACT floors being
three times the MDL rather than the UPL in a limited number of
instances (see ``MACT Floor Analysis (2011) for the Subpart UUUUU--
National Emission Standards for Hazardous Air Pollutants: Coal- and
Oil-fired Electric Utility Steam Generating Units'' (MACT Floor Memo)
in the docket). We request comment on this approach.
    As previously discussed, we account for variability in setting
floors, not only because variability is an element of performance, but
because it is reasonable to assess best performance over time. For
example, we know that the HAP emission data from the best performing
units are, for the most part, short-term averages, and that the actual
HAP emissions from those sources will vary over time. If we do not
account for this variability, we would expect that even the units that
perform better than the floor on average could potentially exceed the
floor emission levels a part of the time which would mean that
variability was not properly taken into account. This variability may
include the day-to-day variability in the total fuel-borne HAP input to
each unit; variability of the sampling and analysis methods; and
variability resulting from site-to-site differences for the best

performing units. EPA's consideration of variability accounted for that
variability exhibited by the data representing multiple units and
multiple data values for a given unit (where available). We calculated
the MACT floor based on the UPL (upper 99th percentile) as described
earlier from the average performance of the best performing units,
Student's t-factor, and the variability of the best performing units.
    We believe this approach reasonably ensures that the emission
limits selected as the MACT floors adequately represent the level of
emissions actually achieved by the average of the units in the top 12
percent, considering operational variability of those units. Both the
analysis of the measured emissions from units representative of the top
12 percent, and the variability analysis, are reasonably designed to
provide a meaningful estimate of the average performance, or central
tendency, of the best controlled 12 percent of units in a given
subcategory.
    A detailed discussion of the MACT floor methodology is presented in
the MACT Floor Memo in the docket.
1. Determination of MACT for the Fuel-borne HAP for Existing Sources
    In developing the proposed MACT floor for the fuel-borne HAP (non-
Hg metals, acid gases, and Hg), as described earlier, we are using PM
as a surrogate for non-Hg metallic HAP (except for the liquid oil-fired
subcategory) and HCl as a surrogate for the acid gases (except for the
liquid oil-fired subcategory). Table 12 of this preamble presents the
number of units in each of the subcategories, along with the number of
units comprising the best performing units (top 12 percent). Table 12
of this preamble also shows the average emission level of the top 12
percent, and the MACT floor including consideration of variability (99
percent UPL of top 12 percent).

                          Table 12--Summary of MACT Floor Results for Existing Sources
----------------------------------------------------------------------------------------------------------------
          Subcategory                   Parameter                PM                HCl              Mercury
----------------------------------------------------------------------------------------------------------------
Coal-fired unit designed for     No. of sources in       1,091............  1,091............  1,061.
 coal >= 8,300 Btu/lb.            subcategory.
                                 No. in MACT floor.....  131..............  131..............  40.
                                 Avg. of top 12%.......  0.02 lb/MMBtu....  0.0003 lb/MMBtu..  0.01 lb/TBtu.
                                 99% UPL of top 12%....  0.030 lb/MMBtu...  0.0020 lb/MMBtu..  1.0 lb/TBtu.
Coal-fired unit designed for     No. of sources in       1,091............  1,091............  30.
 coal < 8,300 Btu/lb.             subcategory.
                                 No. in MACT floor.....  131..............  131..............  2.
                                                                                1.*
                                 Avg. of top 12%.......  0.02 lb/MMBtu....  0.0003 lb/MMBtu..  1 lb/TBtu.
                                                                                (1 lb/TBtu *).
                                 99% UPL of top 12%....  0.030 lb/MMBtu...  0.0020 lb/MMBtu..  11.0 lb/TBtu.
                                                                                (4.0 lb/TBtu *).
IGCC...........................  No. of sources in       2................  2................  2.
                                  subcategory.
                                 No. in MACT floor.....  2................  2................  2.
                                 Avg...................  0.03 lb/MMBtu....  0.0002 lb/MMBtu..  0.9 lb/TBtu.
                                 99% UPL...............  0.050 lb/MMBtu...  0.00050 lb/MMBtu.  3.0 lb/TBtu.
Solid oil-derived..............  No. of sources in       10...............  10...............  10.
                                  subcategory.
                                 No. in MACT floor.....  5................  5................  5.
                                 Avg. of top 5.........  0.04 lb/MMBtu....  0.002 lb/MMBtu...  0.09 lb/TBtu.
                                 99% UPL of top 5......  0.20 lb/MMBtu....  0.0050 lb/MMBtu..  0.20 lb/TBtu.
                                                         Total metals **..  HCl..............  Mercury.
Liquid oil.....................  No. of sources in       154..............  154..............  154.
                                  subcategory.
                                 No. in MACT floor.....  7................  7................  7.
                                 Avg. of top 12%.......  0.00002 lb/MMBtu.  0.0001 lb/MMBtu..  NA.
                                 99% UPL of top 12%....  0.000030 lb/MMBtu  0.00030 lb/MMBtu.  NA.
----------------------------------------------------------------------------------------------------------------
* Beyond-the-floor limit as discussed elsewhere.
** Includes Hg.
NA = Not applicable.

    For the ``Coal-fired unit designed for coal < 8,300 Btu/lb''
subcategory, we used 12 percent of the available data (11 data points),
or 2 units, in setting the existing source floor for Hg. For the IGCC
subcategory, we used data from both units in setting the existing
source floor. For the oil-fired subcategory, we did not include data
obtained from EGUs co-firing natural gas in the existing-source MACT
floor analysis because those emissions are not representative of EGUs
firing 100 percent fuel oil.
    We believe that chlorine may not be a compound generally expected
to be present in oil. The ICR data that we have received suggests that
in at least some oil, it is in fact present. EPA requests comment on
whether chlorine would be expected to be a contaminant in oil and if
not, why it is appearing in the ICR data. To the extent it would not be
expected, we are taking comment on the appropriateness of an HCl limit.
Further, we are proposing a total metals limit for oil-fired EGUs that
includes Hg, in lieu of a PM limit, based on compliance through fuel
analysis. We solicit comment on whether a PM limit or a total metals
limit based on stack testing is an appropriate alternative. We
recognize that PM is not an appropriate surrogate for Hg because Hg is
not controlled to the same extent by the technologies which control
emissions of other HAP metals, but we are soliciting comment as to
whether there is anything unique as to oil-fired EGUs that would allow
us to conclude that PM is an appropriate surrogate for all HAP metal
emissions from such units. We further solicit comment on whether we
should be setting a separate standard for Hg if we require end-of-stack
testing for a total metals limit. Based on the data we have, that Hg
limit would be 0.050 lb/MMBtu (0.000070 lb/GWh) for existing oil-fired
units and 0.00010 lb/GWh for new oil-fired units. In this regard, we
request additional Hg emissions data from oil-fired EGUs. Although we
have some data, additional

data would aid in our development of the standards for such units.
2. Determination of the Work Practice Standard
    CAA section 112(h)(1) states that the Administrator may prescribe a
work practice standard or other requirements, consistent with the
provisions of CAA sections 112(d) or (f), in those cases where, in the
judgment of the Administrator, it is not feasible to enforce an
emission standard. CAA section 112(h)(2)(B) further defines the term
``not feasible'' in this context to apply when ``the application of
measurement technology to a particular class of sources is not
practicable due to technological and economic limitations.''
    As noted earlier, the significant majority of the measured
emissions from EGUs of dioxin/furan and non-dioxin/furan organic HAP
are at or below the MDL of the EPA test methods even though we required
8 hour test runs. As such, EPA considers it impracticable to reliably
measure emissions from these units. As mentioned earlier, because the
expected measurement imprecision for an emissions value occurring at or
near the MDL is about 40 to 50 percent, we are uncertain of the true
levels of organic HAP emissions that would be obtained during any test
program. Overall, the fact that the organic HAP emission levels found
at EGUs are so near the MDL achievable by the available test methods
indicates that the results obtained are questionable for all of the
organic HAP.
    Because the levels of organic HAP emissions from EGUs are so low
(at or below the MDL of the available test methods), there is no
indication that expending additional cost (i.e., extending the sampling
time) would provide the regulated community the ability to test for
these HAP that would provide reliable, technically viable results. In
fact, the 2010 ICR testing required a longer testing period than
normally used and the results were still predominantly below the MDL.
Because of the technical infeasibility, the economic infeasibility is
that sources do not have a way to demonstrate compliance that is
legitimate and we conclude no additional cost will improve the results.
    Based on this analysis, and considering the fact that regardless of
the cost, the resulting emissions data would be suspect due to the
detection level issues, the Administrator is proposing under CAA
section 112(h) that it is not feasible to enforce emission standards
for dioxin/furan and non-dioxin/furan organic HAP because of the
technological and economic infeasibility described above. Thus, a work
practice, as discussed below, is being proposed to limit the emission
of these HAP for existing EGUs.
    For existing units, the only work practice we identified that would
potentially control these HAP emissions is an annual performance test.
Organic HAP are formed from incomplete combustion of the fuel. The
objective of good combustion is to release all the energy in the fuel
while minimizing losses from combustion imperfections and excess air.
The combination of the fuel with the O2 requires temperature
(high enough to ignite the fuel constituents), mixing or turbulence (to
provide intimate O2-fuel contact), and sufficient time (to
complete the process), sometimes referred to the three Ts of
combustion. Good combustion practice (GCP), in terms of combustion
units, could be defined as the system design and work practices
expected to minimize the formation and maximize the destruction of
organic HAP emissions. We maintain that the proposed work practice
standards will promote good combustion and thereby minimize the organic
HAP emissions we are proposing to regulate in this manner.

E. How did EPA consider beyond-the-floor options for existing EGUs?

    Once the MACT floors were established for each subcategory, we
considered various regulatory options more stringent than the MACT
floor level of control (i.e., technologies or other work practices that
could result in lower emissions) for the different subcategories.
    Except for one subcategory, we could not identify better HAP
emissions reduction approaches that could achieve greater emissions
reductions of HAP than the control technology combination(s) (e.g., FF,
carbon injection, scrubber, and GCP) that we expect will be used to
meet the MACT floor levels of control (and that are already in use on
EGUs comprising the top performing 12 percent of sources), though we
did consider duplicate controls (e.g., multiple scrubbers) in series
and found the cost of that option unreasonable.
    Fuel switching to natural gas is an option that would reduce HAP
emissions. We determined that fuel switching was not an appropriate
beyond-the-floor option. First, natural gas supplies are not available
in some areas. Natural gas pipelines are not available in all regions
of the U.S., and natural gas may not be available as a fuel for many
EGUs. Moreover, even where pipelines provide access to natural gas,
supplies of natural gas may not be adequate, especially during peak
demand (e.g., the heating season). Under such circumstances, there
would be some units that could not comply with a requirement to switch
to natural gas. While the combined capital cost and O&M costs for a
coal-to-gas retrofit could be less than that of a combined retrofit
with ACI and either DSI or FGD, the increased fuel costs of coal-to-gas
cause its total incremental COE at a typical EGU is likely to be
significantly larger than the incremental COE of the other retrofit
options available. For example, an EPA analysis detailed in an
accompanying TSD found that the incremental COE of coal-to-gas was 4 to
22 times the cost of alternatives, although the magnitude of the
difference would change with alternative fuel price assumptions. EPA,
therefore, concludes that the coal-to-gas option is not a cost-
effective means of achieving HAP reductions for the purposes of this
proposed rule.
    Additional detail on the economics of coal-to-gas conversion and
illustrative calculations of additional emission reductions versus cost
impacts are provided in the ``Coal-to-Gas Conversion'' TSD in the
docket.
    As noted earlier, no EGU designed to burn a nonagglomerating virgin
coal having a calorific value (moist, mineral matter-free basis) of
19,305 kJ/kg (8,300 Btu/lb) or less in a EGU with a height-to-depth
ratio of 3.82 or greater was found among the top performing 12 percent
of sources for Hg emissions, even though some of these units employed
ACI. EPA has learned that the units of this design that were using ACI
during the testing were using ACI to meet their permitted Hg emission
levels. However, EPA believes that the control level being achieved is
still not that which could be achieved if ACI were used to its fullest
extent. Therefore, EPA is proposing to establish a beyond-the-floor
emission limit for existing EGUs designed to burn a nonagglomerating
virgin coal having a calorific value (moist, mineral matter-free basis)
of 19,305 kJ/kg (8,300 Btu/lb) or less in a EGU with a height-to-depth
ratio of 3.82 or greater. The proposed emission limit is 4 lb/TBtu for
existing EGUs in this class. This proposed emission limit is based on
use of the data from the top performing unit in the subcategory made
available to the Agency through the 2010 ICR; the same statistical
analyses were conducted as were done to establish the MACT floor values
for the other HAP. EPA notes that our analysis shows that the
technology installed to achieve the MACT floor

limit would be the same technology used to achieve the beyond-the-floor
MACT limit and, thus, proposing to go beyond-the-floor is reasonable.
EPA solicits comment on whether it is appropriate to propose a beyond-
the-floor limit for existing EGUs in this subcategory.
    To assess the impacts on the existing EGUs in this subcategory to
implement the proposed beyond-the-floor limit, EPA conducted analyses
using approaches as discussed in the memoranda ``Beyond-the-Floor
Analysis (2011) for the Subpart UUUUU--National Emission Standards for
Hazardous Air Pollutants: Coal- and Oil-fired Electric Utility Steam
Generating Units'' and ``Emission Reduction Costs for the Beyond-the-
Floor Mercury Rate in the Toxics Rule'' in the docket. The cost
effectiveness of the beyond-the-floor option ranged from $17,375 to
$21,393/lb Hg removed in the two approaches. The total costs of the
non-air environmental impacts for the proposed beyond-the-floor limit
for this subcategory are estimated as $12,310. Non-air quality health
impacts were evaluated, but no incremental health impacts were
attributable to installation of FF and ACI, because these technologies
do not expose electric utility employees or the public to any
additional health risks above the risks attributable to current utility
operations involving compressed air systems, confined spaces, and
exposure to fly ash.
    EPA is aware that there may be other means of enhancing the removal
of Hg from the flue gas stream (e.g., spraying a halogen such as
chlorine or bromine on the coal as it is fed to the EGU). EPA has
information that indicates that such means were employed by an unknown
number of EGUs during the period of time they were testing to provide
data in compliance with the 2010 ICR (see McMeekin memo in the docket).
Thus, we believe that the performance of such means is reflected in the
MACT floor analysis. However, EPA has no data upon which to assess
whether any other technology would provide additional control to that
already shown by the use of ACI and, thus, we are not proposing to use
such technologies as the basis for a beyond-the-floor analysis. EPA
solicits comment on this approach.
    EPA believes the best potential way of reducing Hg emissions from
existing IGCC units is to remove Hg from the syngas before combustion.
For example, an existing industrial coal gasification unit has
demonstrated a process, using a sulfur-impregnated AC bed, which has
proven to yield over 90 percent Hg removal from the coal syngas.
(Rutkowski 2002.) We considered using carbon bed technology as beyond-
the-floor for existing IGCC units. However, we have no detailed data to
support this position at this time and, thus, are not proposing a
beyond-the-floor limit for existing IGCC units. EPA requests comments
on whether the use of this or other control techniques have been
demonstrated to consistently achieve emission levels that are lower
than levels from similar sources achieving the proposed existing MACT
floor level of control. Comments should include information on
emissions, control efficiencies, reliability, current demonstrated
applications, and costs, including retrofit costs.
    We considered proposing beyond-the-floor requirements for Hg in the
other subcategories and for the other HAP in all of the subcategories.
Activated carbon injection is used on EGUs designed for coal greater
than or equal to 8,300 Btu/lb and, therefore, its effect on Hg removal
has already been accounted for in the MACT floor. Further, EPA has no
information that would indicate that ACI would provide significantly
lower emission levels given the MACT floor Hg standard, and it is also
possible that existing sources in this subcategory will utilize ACI to
comply with the MACT floor limit. Activated carbon injection has not
been demonstrated on liquid oil-fired EGUs. Similarly, ACI has not been
demonstrated on solid oil-derived fuel-fired EGUs. EPA has no
information that would indicate that ACI would provide significantly
lower Hg emission levels on units operating at the level of the MACT
floor. For the non-Hg metallic and acid gas HAP, there is no technology
that would achieve additional control over that being shown by units
making up the floor. Additional combinations of controls (e.g., dual
FGD systems in series) could be used but at a significant additional
cost and, given the MACT floor level of control, a minimal additional
reduction in HAP emissions. For the organic HAP, EPA is not aware of
any measures beyond those proposed here that would result in lower
emissions. Therefore, EPA is not proposing beyond-the-floor limitations
other than as noted above.

F. Should EPA consider different subcategories?

    EPA has attempted to identify subcategories that provide the most
reasonable basis for grouping and estimating the performance of
generally similar units using the available data. We believe that the
subcategories we selected are appropriate.
    EPA requests comments on whether additional or different
subcategories should be considered. Comments should include detailed
information regarding why a new or different subcategory is appropriate
(based on the available data and on the statutory constraint of
``class, type or size''), how EPA should define any additional and/or
different subcategories, how EPA should account for varied or changing
fuel mixtures, and how EPA should use the available data to determine
the MACT floor for any new or different subcategories.

G. How did EPA determine the proposed emission limitations for new
EGUs?

    All standards established pursuant to CAA section 112 must reflect
MACT, the maximum degree of reduction in emissions of air pollutants
that the Administrator, taking into consideration the cost of achieving
such emissions reductions, and any nonair quality health and
environmental impacts and energy requirements, determines is achievable
for each category. The CAA specifies that MACT for new EGUs shall not
be less stringent than the emission control that is achieved in
practice by the best-controlled similar source. This minimum level of
stringency is the MACT floor for new units. However, EPA may not
consider costs or other impacts in determining the MACT floor. EPA must
consider cost, nonair quality health and environmental impacts, and
energy requirements in connection with any standards that are more
stringent than the MACT floor (beyond-the-floor controls).

H. How did EPA determine the MACT floor for new EGUs?

    Similar to the MACT floor process used for existing EGUs, the
approach for determining the MACT floor must be based on available
emissions test data. Using such an approach, we calculated the MACT
floor for a subcategory of sources by ranking the 2010 ICR emissions
data from EGUs within the subcategory from lowest to highest (on a lb/
MMBtu basis) to identify the best controlled similar source. The MACT
floor limitations for each of the HAP and HAP surrogates (PM, Hg, and
HCl) are calculated based on the performance (numerical average) of the
lowest emitting (best controlled) source for each pollutant in each of
the subcategories.
    The MACT floor limitations for new sources were calculated using
the same formula as was used for existing sources with one exception.
For the new source calculations, the results of the three individual
emission test runs were used

instead of the 3-run average that was used in determining the existing-
source MACT floor. This was done to be able to provide some measure of
variability. As previously discussed, we account for variability of the
best-controlled source in setting floors, not only because variability
is an element of performance, but because it is reasonable to assess
best performance over time. We calculated the MACT floor based on the
UPL (upper 99th percentile) as described earlier from the average
performance of the best controlled similar source, Student's t-factor,
and the total variability of the best-controlled source.
    This approach reasonably ensures that the emission limit selected
as the MACT floor adequately represents the average level of control
actually achieved by the best controlled similar source, considering
ordinary operational variability.
    A detailed discussion of the MACT floor methodology is presented in
the MACT Floor Memo in the docket.
    The approach that we use to calculate the MACT floors for new
sources is somewhat different from the approach that we use to
calculate the MACT floors for existing sources. Although the MACT
floors for existing units are intended to reflect the performance
achieved by the average of the best performing 12 percent of sources,
the MACT floors for new units are meant to reflect the emission control
that is achieved in practice by the best controlled similar source.
Thus, for existing units, we are concerned about estimating the central
tendency of a set of multiple units, whereas for new units, we are
concerned about estimating the level of control that is representative
of that achieved by a single best controlled source. As with the
analysis for existing sources, the new EGU analysis must account for
variability.
1. Determination of MACT for the Fuel-Borne HAP for New Sources
    In developing the MACT floor for the fuel-borne HAP (PM, HCl, and
Hg), as described earlier, we are using PM as a surrogate for non-Hg
metallic HAP and HCl as a surrogate for the acid gases (except for the
liquid oil-fired subcategory). Table 13 of this preamble presents for
each subcategory and fuel-borne HAP the average emission level of the
best controlled similar source and the MACT floor which accounts for
variability (99 percent UPL).

                                                 TAble 13--Summary of MACT Floor Results for New Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
             Subcategory                     Parameter                       PM                            HCl                         Mercury
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coal-fired unit designed for coal     Avg. of top performer..  0.03 lb/MWh..................  0.2 lb/GWh..................  0.00001 lb/GWh.
 [gteqt] 8,300 Btu/lb.
                                      99% UPL of top           0.050 lb/MWh.................  0.30 lb/GWh.................  0.000010 lb/GWh.
                                       performer (test runs).
Coal-fired unit designed for coal <   Avg. of top performer..  0.03 lb/MWh..................  0.2 lb/GWh..................  0.02 lb/GWh.
 8,300 Btu/lb.
                                      99% UPL of top           0.050 lb/MWh.................  0.30 lb/GWh.................  0.040 lb/GWh.
                                       performer (test runs).
IGCC................................  Avg. of top performer..  N/A..........................  N/A.........................  N/A.
                                      99% UPL of top           0.050 lb/MWh *...............  0.30 lb/GWh *...............  0.000010 lb/GWh.*
                                       performer (test runs).
Solid oil-derived...................  Avg. of top performer..  0.04 lb/MWh..................  0.0003 lb/MWh...............  0.0007 lb/GWh.
                                      99% UPL of top           0.050 lb/MWh.................  0.00030 lb/MWh..............  0.0020 lb/GWh.
                                       performer (test runs).
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                      Total metals **                      HCl                         Mercury
                                     -------------------------------------------------------------------------------------------------------------------
Liquid oil..........................  Avg. of top performer..  0.00009 lb/MMBtu.............  0.0002 lb/MWh...............  NA.
                                      99% UPL of top           0.00040 lb/MMBtu.............  0.00050 lb/MWh..............  NA.
                                       performer (test runs).
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Beyond-the-floor as discussed elsewhere.
** Includes Hg.
NA = Not applicable.

2. Determination of the Work Practice Standard
    We are proposing a work practice standards for non-dioxin/furan
organic and dioxin/furan organic HAP under CAA section 112(h) that
would require the implementation of an annual performance test program
for new EGUs. This proposal for new EGUs is based on the same reasons
discussed previously for existing EGUs. That is, the measured emissions
from EGUs of these HAP are routinely below the detection limits of the
EPA test methods, and, as such, EPA considers it impracticable to
reliably measure emissions from these units.
    Thus, the work practice discussed above for existing EGUs is being
proposed to limit the emissions of non-dioxin/furan organic and dioxin/
furan organic HAP for new EGUs.
    We request comments on this approach.

I. How did EPA consider beyond-the-floor for new units?

    The MACT floor level of control for new EGUs is based on the
emission control that is achieved in practice by the best controlled
similar source within each of the subcategories. No technologies were
identified that would achieve HAP reduction greater than the new source
floors for the subcategories, except for multiple controls in series
(e.g., multiple FFs) which we consider to be unreasonable from a cost
perspective.
    Fuel switching to natural gas is a potential regulatory option
beyond the new source floor level of control that would reduce HAP
emissions. However, natural gas supplies are not available in some
areas. Thus, this potential control option may be unavailable to many
sources in practice. Limited emissions reductions in combination with
the high cost of fuel switching and considerations about the
availability and technical feasibility of fuel switching makes this an
unreasonable regulatory option that was not considered further. As
discussed above, the uncertainties associated with nonair quality
health and environmental impacts also argue against determining that
fuel switching is reasonable beyond-the-floor option. In addition,

even if we determined that natural gas supplies were available in all
regions, we would still not adopt this fuel switching option because it
would effectively prohibit new construction of coal-fired EGUs and we
do not think that is a reasonable approach to regulating HAP emissions
from EGUs.
    Although, as discussed earlier for existing EGUs, EPA is proposing
to establish a beyond-the-floor emission limit for Hg for existing EGUs
designed to burn a nonagglomerating fuel having a calorific value
(moist, mineral matter-free basis) of 19,305 kJ/kg (8,300 Btu/lb) or
less in a EGU with a height-to-depth ratio of 3.82 or greater, EPA is
not proposing to go beyond-the-floor for new EGUs in this subcategory.
The proposed emission limit of 0.04 lb/GWh for new EGUs in this
subcategory is based on use of ACI on a new unit and, we believe,
reflects a level of performance achievable and, as noted above, no
technologies were identified that would achieve HAP reduction greater
than the new source floors for the subcategories, except for multiple
controls in series (e.g., multiple FFs) which we consider to be
unreasonable from a cost perspective.
    As discussed earlier, because of a lack of data, EPA is not
proposing beyond-the-floor emission limits for existing IGCC units.
However, EPA believes that the new-source limits derived from the data
obtained from the two operating IGCC units are not representative of
what a new IGCC unit could achieve. Therefore, EPA looked to the permit
issued for the Duke Energy Edwardsport IGCC facility currently under
construction.\160\ The permitted limits for this unit are similar to
the limits derived from the existing units. Because of advances in
technology, EPA does not believe that even these permitted levels are
representative of what a modern IGCC unit could achieve. The emissions
from IGCC units are normally predicted to be similar to or lower than
those from traditional pulverized coal (PC) boilers. For example, DOE
projects that future IGCC units will be able to meet a PM (filterable)
emissions limit of 0.0071 lb/MMBtu, a SO2 emissions limit of
0.0127 lb/MMBtu, and a Hg emissions limit of 0.571 lb/TBtu.\161\
Therefore, we are proposing that the new-source limits for new IGCC
units be identical to those of new coal-fired units designed for coal
greater than or equal to 8,300 Btu/lb. However, EPA has no information
upon which to base the costs and non-air quality health, environmental,
and energy impacts of this proposed approach. EPA solicits comment on
this approach. Commenters should provide data that support their
comment, including costs, emissions data, or engineering analyses.
---------------------------------------------------------------------------

    \160\ Letter from Matthew Stuckey, State of Indiana, to Mack
Sims, Duke Energy Indiana. Operating permit fo Edwardsport
Generating Station IGCC. Undated.
    \161\ DOE. Overview--Bituminous & Natural Gas to Electricity;
Overview of Bituminous Baseline Study. From: Cost and Performance
Baseline for Fossil Energy Plants, Vol. 1, DOE/NETL-2007/1281, May
2007.
---------------------------------------------------------------------------

    Similarly, for the reasons discussed earlier for existing EGUs, EPA
is not proposing any other beyond-the-floor emission limitations. EPA
requests comments on whether the use of any control techniques have
been demonstrated to consistently achieve emission levels that are
lower than levels from similar sources achieving the proposed new-
source MACT floor levels of control. Comments should include
information on emissions, control efficiencies, reliability, current
demonstrated applications, and costs, including retrofit costs.

J. Consideration of Whether To Set Standards for HCl and Other Acid Gas
HAP Under CAA Section 112(d)(4)

    We are proposing to set a conventional MACT standard for HCl and,
for the reasons explained elsewhere, are proposing that the HCl limit
also serve as a surrogate for other acid gas HAP. We also considered
whether it was appropriate to exercise our discretionary authority to
establish health-based emission standards under CAA section 112(d)(4)
for HCl and each of the other relevant HAP acid gases: Cl2,
HF, SeO2, and HCN \162\ (because if it were regulated under
CAA section 112(d)(4), HCl may no longer be the appropriate surrogate
for these other HAP).\163\ This section sets forth the requirements of
CAA section 112(d)(4); our analysis of the information available to us
that informed the decision on whether to exercise discretion; questions
regarding the application of CAA section 112(d)(4); and our explanation
of how this case relates to prior decisions EPA has made under CAA
section 112(d)(4) with respect to HCl.
---------------------------------------------------------------------------

    \162\ Before considering whether to exercise her discretion
under CAA section 112(d)(4) for a particular pollutant, the
Administrator must first conclude that a health threshold has been
established for the pollutant.
    \163\ Hydrogen chloride can serve as a surrogate for the other
acid gases in a technology-based MACT standard, because the control
technology that would be used to control HCl would also reduce the
other acid gases. By contrast, HCl would not be an appropriate
surrogate for a health-based emission standard that is protective
against the potential adverse health effects from the other acid
gases, because these gases (e.g., HF) can act on biological
organisms in a different manner than HCl, and each of the acid gases
affects human health with a different dose-response relationship.
---------------------------------------------------------------------------

    As a general matter, CAA section 112(d) requires MACT standards at
least as stringent as the MACT floor to be set for all HAP emitted from
major sources. However, CAA section 112(d)(4) provides that for HAP
with established health thresholds, the Administrator has the
discretionary authority to consider such health thresholds when
establishing emission standards under CAA section 112(d). This
provision is intended to allow EPA to establish emission standards
other than conventional MACT standards, in cases where a less stringent
emission standard will still ensure that the health threshold will not
be exceeded, with an ample margin of safety. In order to exercise this
discretion, EPA must first conclude that the HAP at issue has an
established health threshold and must then provide for an ample margin
of safety when considering the health threshold to set an emission
standard.
    It is clear the Administrator may exercise her discretionary
authority under CAA section 112(d)(4) only with respect to pollutants
with a health threshold. Where there is an established threshold, the
Administrator interprets CAA section 112(d)(4) to allow her to weigh
additional factors, beyond any established health threshold, in making
a judgment whether to set a standard for a specific pollutant based on
the threshold, or instead follow the traditional path of developing a
MACT standard after determining a MACT floor. In deciding whether to
exercise her discretion for a threshold pollutant for a given source
category, the Administrator interprets CAA section 112(d)(4) to allow
her to take into account factors such as the following: the potential
for cumulative adverse health effects due to concurrent exposure to
other HAP with similar biological endpoints, from either the same or
other source categories, where the concentration of the threshold
pollutant emitted from the given source category is below the
threshold; the potential impacts on ecosystems of releases of the
pollutant; and reductions in criteria pollutant emissions and other co-
benefits that would be achieved by a MACT standard. Each of these
factors is directly relevant to the health and environmental outcomes
at which CAA section 112 is fundamentally aimed. If the Administrator
does determine that it is appropriate to set a standard based on a
health threshold, she must develop emission standards that will ensure
the public will not be exposed to levels of the pertinent HAP in excess
of the

health threshold, with an ample margin of safety.
    EPA has exercised its discretionary authority under CAA section
112(d)(4) in a handful of prior rules setting emissions standards for
other major source categories, including the Boiler NESHAP issued in
2004, which was vacated on other grounds by the DC Circuit Court. In
the Pulp and Paper NESHAP (63 FR 18765; April 15, 1998), and Lime
Manufacturing NESHAP (67 FR 78054; December 20, 2002), EPA invoked CAA
section 112(d)(4) for HCl emissions for discrete units within the
facility. In those rules, EPA concluded that HCl had an established
health threshold (in those cases it was interpreted as the RfC for
chronic effects) and HCl was not classified as a human carcinogen. In
light of the absence of evidence of carcinogenic risk, the availability
of information on non-carcinogenic effects, and the limited potential
health risk associated with the discrete units being regulated, EPA
concluded that it was appropriate to exercise its discretion under CAA
section 112(d)(4) for HCl under the circumstances of those rules. EPA
did not set an emission standard based on the health threshold; rather,
the exercise of EPA's discretion in those cases in effect exempted HCl
from the MACT requirement. In more recent rules, EPA decided not to
propose a health-based emission standard for HCl emissions under CAA
section 112(d)(4) for Portland Cement facilities (75 FR 54970
(September 9, 2010), and for Industrial, Commercial, and Institutional
Boilers, (75 FR 32005; June 4, 2010 proposal(major); the final major
source rule was signed on February 21, 2011 but has not yet been
published). EPA has never implemented a NESHAP that used CAA section
112(d)(4) with respect to HF, Cl2, SeO2, or
HCN.\164\
---------------------------------------------------------------------------

    \164\ EPA has not classified HF, Cl2,
SeO2, or HCN with respect to carcinogenicity. However, at
this time the Agency is not aware of any data that would suggest any
of these HAP are carcinogens.
---------------------------------------------------------------------------

    Because any emission standard under CAA section 112(d)(4) must
consider the established health threshold level, with an ample margin
of safety, in this rulemaking EPA has considered the adverse health
effects of the HAP acid gases, beginning with HCl and including HF,
Cl2, SeO2, and HCN. Research indicates that HCl
is associated with chronic respiratory toxicity. In the case of HCl,
this means that chronic inhalation of HCl can cause tissue damage in
humans. Among other things, it is corrosive to mucous membranes and can
cause damage to eyes, nose, throat, and the upper respiratory tract as
well as pulmonary edema, bronchitis, gastritis, and dermatitis.
Considering this respiratory toxicity, EPA has established a chronic
RfC for the inhalation of HCl of 20 micrograms per cubic meter ([mu]g/
m\3\). An RfC is defined as an estimate (with uncertainty spanning
perhaps an order of magnitude) of a continuous inhalation exposure to
the human population (including sensitive subgroups \165\) that is
likely to be without an appreciable risk of deleterious effects during
a lifetime. The development of the RfC for HCl reflected data only on
its chronic respiratory toxicity. It did not take into account effects
associated with acute exposure,\166\ and, in this situation, the IRIS
health assessment did not evaluate the potential carcinogenicity of HCl
(on which there are very limited studies). As a reference value for a
single pollutant, the RfC also did not reflect any potential cumulative
or synergistic effects of an individual's exposure to multiple HAP or
to a combination of HAP and criteria pollutants. As the RfC calculation
focused on health effects, it did not take into account the potential
environmental impacts of HCl.
---------------------------------------------------------------------------

    \165\ ``Sensitive subgroups'' may refer to particular life
stages, such as children or the elderly, or to those with particular
medical conditions, such as asthmatics.
    \166\ California EPA considered acute toxicity and established a
1-hour reference exposure level (REL) of 2.1 milligrams per cubic
meter (mg/m\3\). An REL is the concentration level at or below which
no adverse health effects are anticipated for a specified exposure
duration. RELs are designed to protect the most sensitive
individuals in the population by the inclusion of margins of safety.
---------------------------------------------------------------------------

    With respect to the potential health effects of HCl, we note the
following:
    (1) Chronic exposure to concentrations at or below the RfC is not
expected to cause chronic respiratory effects;
    (2) Little research has been conducted on its carcinogenicity. The
one occupational study of which we are aware found no evidence of
carcinogenicity;
    (3) There is a significant body of scientific literature addressing
the health effects of acute exposure to HCl (for a summary, see
California Office of Health Hazard Assessment, 2008. Acute Toxicity
Summary for Hydrogen Chloride, http://www.oehha.ca.gov/air/hot_spots/2008/AppendixD2_final.pdf#page=112 EPA, 2001). In addition, we note
that several researchers have shown associations between acid gases and
reduced lung function and asthma in North American children.\167\
However, we currently lack information on the peak short-term emissions
of HCl from EGUs, which might allow us to determine whether a chronic
health-based emission standard for HCl would ensure that acute
exposures will not pose any health concerns, and;
---------------------------------------------------------------------------

    \167\ Dockery DW, Cunningham J, Damokosh AI, Neas LM, Spengler
JD, Koutrakis P, Ware JH, Raizenne M, Speizer FE. 1996. Health
Effects of Acid Aerosols on North American Children: Respiratory
Symptoms. Environmental Health Perspectives 104(5):500-504; Raizenne
M, Neas LM, Damokosh AI, Dockery DW, Spengler JD, Koutrakis P, Ware
JH, Speizer FE. 1996. Health Effects of Acid Aerosols on North
American Children: Pulmonary Function. Environmental Health
Perspectives 104(5):506-514.
---------------------------------------------------------------------------

    (4) We are aware of no studies explicitly addressing the toxicity
of mixtures of HCl with other respiratory irritants. However, many of
the other HAP (and criteria pollutants) emitted by EGUs also are
respiratory irritants, and in the absence of information on
interactions, EPA assumes an additive cumulative effect (Supplementary
Guidance for Conducting Health Risk Assessment of Chemical Mixtures.
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=20533). The fact
that EGUs can be located in close proximity to a wide variety of
industrial facilities makes predicting and assessing all possible
mixtures of HCl and other emitted air pollutants difficult, if not
impossible.
    In addition to potential health impacts, the Administrator also has
evaluated the potential for environmental impacts when considering
whether to exercise her discretion under CAA section 112(d)(4). When
HCl gas encounters water in the atmosphere, it forms an acidic solution
of hydrochloric acid. In areas where the deposition of acids derived
from emissions of sulfur and NOX are causing aquatic and/or
terrestrial acidification, with accompanying ecological impacts, the
deposition of hydrochloric acid could exacerbate these impacts. Recent
research \168\ has suggested that deposition of airborne HCl has had a
greater impact on ecosystem acidification than previously thought,
although direct quantification of these impacts remains an uncertain
process. We maintain it is appropriate to consider potential adverse
environmental effects in addition to adverse health effects when
setting an emission standard for HCl under CAA section 112(d)(4).
---------------------------------------------------------------------------

    \168\ Evans, CD, Monteith, DT, Fowler, D, Cape, JN, and
Brayshaw, S. Hydrochloric Acid: an Overlooked Driver of
Environmental Change, Env. Sci. Technol., DOI: 10.1021/es10357u.
---------------------------------------------------------------------------

    Because the statute requires an ample margin of safety, it would be
reasonable to set any CAA section 112(d)(4) emission standard for a
pollutant with a health threshold at a level that at least

assures that persons exposed to emissions of the pollutant would not
experience the adverse health effects on which the threshold is based
due to sources in the controlled category or subcategory. In the case
of this proposed rulemaking, we have concluded that we do not have
sufficient information at this time to establish what the health-based
emission standards would be for HCl or the other acid gases from EGUs
alone, much less for EGUs and other sources of acid gas HAP located at
or near facilities with EGUs.
    Finally, we considered the fact that setting conventional MACT
standards for HCl as well as PM (as a surrogate for HAP metals) would
result in significant reductions in emissions of other pollutants, most
notably SO2, PM, and other non-HAP acid gases (e.g.,
hydrogen bromide) and would likely also result in additional reductions
in emissions of Hg and other HAP metals (e.g., Se). The additional
reductions of SO2 alone attributable to the proposed limit
for HCl are estimated to be 2.1 million tons in the third year
following promulgation of the proposed HCl standard. These are
substantial reductions with substantial public health benefits.
Although NESHAP may directly address only HAP, not criteria pollutants,
Congress did recognize, in the legislative history to CAA section
112(d)(4), that NESHAP would have the collateral benefit of controlling
criteria pollutants as well and viewed this as an important benefit of
the air toxics program.\169\ Therefore, even where EPA concludes a HAP
has a health threshold, the Agency may consider the collateral benefits
of controlling criteria pollutants as a factor in determining whether
to exercise its discretion under CAA section 112(d)(4).
---------------------------------------------------------------------------

    \169\ See S. Rep. No. 101-228, 101st Cong. 1st sess. At 172.
---------------------------------------------------------------------------

    Given the limitations of the currently available information (e.g.,
the HAP mix where EGUs are located, and the cumulative impacts of
respiratory irritants from nearby sources), the environmental effects
of HCl and the other acid gas HAP, and the significant co-benefits of
setting a conventional MACT standard for HCl and the other acid gas
HAP, the Administrator is proposing not to exercise her discretion to
use CAA section 112(d)(4).
    This conclusion is not contrary to EPA's prior decisions noted
earlier where we found it appropriate to exercise the discretion to
invoke the authority in CAA section 112(d)(4) for HCl, because the
circumstances in this case differ from previous considerations. EGUs
differ from the other source categories for which EPA has exercised its
authority under CAA section 112(d)(4) in ways that affect consideration
of any health threshold for HCl. EGUs are much more likely to be
significant emitters of acid gas HAP and non-HAP than are other source
categories. In fact, they are the largest anthropogenic emitter of HCl
and HF in the U.S, emitting roughly half of the estimated nationwide
total HCl and HF emissions in 2010. Our case study analyses of the
chronic impacts of EGUs did not indicate any significant potential for
them to cause any exceedances of the chronic RfC for HCl due to their
emissions alone.\170\ However, we do not have adequate information on
the other acid gas HAP to include them in our analysis, and did not
consider their impacts in concert with other emitters of HCl (such as
IB units) to develop estimates of cumulative exposures to HCl and other
acid gas HAP in the vicinity of EGUs. In addition, EGUs may be located
at facilities in heavily populated urban areas where many other sources
of HAP exist. These factors make an analysis of the health impact of
emissions from these sources on the exposed population significantly
more complex than for many other source categories, and, therefore,
make it more difficult to establish an ample margin of safety without
significantly more information. Absent the information necessary to
provide a credible basis for developing alternative health-based
emission standards for all acid gases, and for all the other reasons
discussed above, EPA is choosing not to exercise its discretion under
CAA section 112(d)(4) for these pollutants from EGUs.
---------------------------------------------------------------------------

    \170\ For those facilities modeled, the hazard index for HCl
ranged from 0.05 to 0.005 (see Non-Hg Case Study Chronic Inhalation
Risk Assessment for the Utility MACT ``Appropriate and Necessary''
Analysis in the docket).
---------------------------------------------------------------------------

K. How did we select the compliance requirements?

    We are proposing testing, monitoring, notification, and
recordkeeping requirements that are adequate to assure continuous
compliance with the requirements of this proposed rule. These
requirements are described elsewhere in this preamble. We selected
these requirements based upon our determination of the information
necessary to ensure that the emission standards and work practices are
being followed and that emission control devices and equipment are
maintained and operated properly. These proposed requirements ensure
compliance with this proposed rule without imposing a significant
additional burden for units that must implement them.
    We are proposing that units using continuous monitoring systems for
PM, HCl, and Hg demonstrate initial compliance by performance testing
for non-Hg HAP metals and the surrogate PM, for HCl and its surrogate
SO2, and for Hg, and then to perform subsequent performance
testing every 5 years for non-Hg HAP metals and PM and for HCl and
SO2. To ensure continuous compliance with the proposed Hg
emission limits in-between the performance tests, this proposed rule
would require coal-fired units to use either CEMS or sorbent trap
monitoring systems, with an option for very low emitters to use a less
rigorous method based on periodic stack testing. These requirements are
found in proposed Appendix A to 40 CFR part 63, subpart UUUUU. For PM
and HCl, affected units that elect to install CEMS would use the CEMS
to demonstrate continuous compliance. However, units equipped with
devices that control PM and HCl emissions but do not elect to use CEMS,
would determine suitable parameter operating limits, to monitor those
parameters on a continuous basis, and to conduct emissions testing
every other month. Units combusting liquid oil on a limited basis
would, upon request and approval, be allowed to determine limits for
metals, chlorine, and Hg concentrations in fuel and to measure
subsequent fuel metals, chlorine, and Hg concentrations monthly; and
low emitting units would be allowed to determine limits for metals,
chlorine, and Hg concentrations in fuel and to measure subsequent fuel
metals, chlorine, and Hg concentrations monthly.
    Additionally, this proposed rule would require annual maintenance
be performed so that good combustion continues. Such an annual check
will serve to ensure that dioxins, furans, and other organic HAP
emissions continue to be at or below MDLs.
    We evaluated the feasibility and cost of applying PM CEMS to EGUs.
Several electric utility companies in the U.S. have now installed or
are planning to install PM CEMS. In recognition of the fact that PM
CEMS are commercially available, EPA developed and promulgated PSs for
PM CEMS (69 FR 1786, January 12, 2004). Performance Specifications for
PM CEMS are established under PS 11 in appendix B to 40 CFR part 60 for
evaluating the acceptability of a PM CEMS used for determining
compliance with the emission standards on a continuous basis. For PM
CEMS monitoring, initial costs were estimated to be $261,000 per

unit and annualized costs were estimated to be $91,000 per unit. We
determined that requiring PM CEMS for EGUs combusting coal or oil is a
reasonable monitoring option. We are requesting comment on the
application of PM CEMS to EGUs, and the use of data from such systems
for compliance determinations under this proposed rule.
    Table 14 holds preliminary cost information. Note that these costs
are based on 2010 ICR emissions test estimates and on values in EPA's
monitoring costs assessment tool. Particulate matter and metals and
SO2 and HCl testing includes surrogacy testing initially and
every 5 years, parameter monitoring includes testing every two months,
and fuel content monitoring includes annual testing.

                                           Table 14--Cost Information
----------------------------------------------------------------------------------------------------------------
                                               Initial costs,     Annual costs,
                                                     $K                $K
----------------------------------------------------------------------------------------------------------------
                                                     Metals
----------------------------------------------------------------------------------------------------------------
PM CEMS.....................................               261                91
Fabric filter...............................                61               109
ESP.........................................                59               114
----------------------------------------------------------------------------------------------------------------
                                                   Acid Gases
----------------------------------------------------------------------------------------------------------------
SO2 CEMS....................................               232                66  None if existing CEMS used.
HCl CEMS....................................               233                57
Dry sorbent injection.......................                10               144  Plus material costs.
Wet scrubber................................                 9               143
----------------------------------------------------------------------------------------------------------------
                                                     Mercury
----------------------------------------------------------------------------------------------------------------
Hg CEMS.....................................               271               110
Sorbent traps...............................                23               128  Minimum of 52 traps and
                                                                                analysis per year.
Fuel analysis...............................                10                49
----------------------------------------------------------------------------------------------------------------
                                  Dioxin/furan and non-dioxin/furan organic HAP
----------------------------------------------------------------------------------------------------------------
Tune up.....................................                17                 3
----------------------------------------------------------------------------------------------------------------

    The Agency is seeking comment on the cost information presented
above. The commenters are encouraged to provide detailed information
and data that will help the Agency refine its cost estimates for this
rulemaking.
    The majority of test methods that this proposed rule would require
for the performance stack tests have been required under many other EPA
standards. Three applicable voluntary consensus standards were
identified: American Society of Mechanical Engineers (ASME) Performance
Test Code (PTC) 19-10-1981-Part 10, ``Flue and Exhaust Gas Analyses,''
a manual method for measuring the oxygen, CO2, and CO
content of exhaust gas; ASTM Z65907, ``Standard Method for Both
Speciated and Elemental Mercury Determination,'' a method for Hg
measurement; and ASTM Method D6784-02 (Ontario Hydro), a method for
measuring Hg. The majority of emissions tests upon which the proposed
emission limitations are based were conducted using these test methods.
    When a performance test is conducted, we are proposing that
parameter operating limitations be determined during the tests.
Performance tests to demonstrate compliance with any applicable
emission limitations are either stack tests or fuel analysis or a
combination of both.
    To ensure continuous compliance with the proposed emission
limitations and/or operating limits, this proposed rule would require
continuous parameter monitoring of control devices and recordkeeping.
We selected the following requirements based on reasonable cost, ease
of execution, and usefulness of the resulting data to both the owners
or operators and EPA for ensuring continuous compliance with the
emission limitations and/or operating limits.
    We are proposing that certain parameters be continuously monitored
for the types of control devices commonly used in the industry. These
parameters include pH, pressure drop and liquid flow rate for wet
scrubbers; and sorbent injection rate for dry scrubbers and DSI
systems. You must also install a BLDS for FFs. These monitoring
parameters have been used in other standards for similar industries.
The values of these parameters are established during the initial or
most recent performance test that demonstrates compliance. These values
are your operating limits for the control device.
    You would be required to set parameters based on 4-hour block
averages during the compliance test, and demonstrate continuous
compliance by monitoring 12-hour block average values for most
parameters. We selected this averaging period to reflect operating
conditions during the performance test to ensure the control system is
continuously operating at the same or better level as during a
performance test demonstrating compliance with the emission limits.
    To demonstrate continuous compliance with the emission and
operating limits, you would also need daily records of the quantity,
type, and origin of each fuel burned and hours of operation of the
affected source. If you are complying with the chlorine fuel input
option, you must keep records of the calculations supporting your
determination of the chlorine content in the fuel.
    If a liquid oil-fired EGU elected to demonstrate compliance with
the HCl or individual or total HAP metal limit by using fuel which has
a statistically lower pollutant content than the emission limit, we are
proposing that the source's operating limit is the emission limit of
the applicable pollutant. Under this option, a source is not required
to conduct performance

stack tests. If a source demonstrates compliance with the HCl,
individual or total PM, or Hg limit by using fuel with a statistically
higher pollutant content than the applicable emission limit, but
performance tests demonstrate that the source can meet the emission
limitations, then the source's operating limits are the operating
limits of the control device (if used) and the fuel pollutant content
of the fuel type/mixture burned.
    This proposed rule would specify the testing methodology and
procedures and the initial and continuous compliance requirements to be
used when complying with the fuel analysis options. Fuel analysis tests
for total chloride, gross calorific value, Hg, individual and total HAP
metal, sample collection, and sample preparation are included in this
proposed rule.
    If you are a liquid oil-fired EGU and elect to comply based on fuel
analysis, you will be required to statistically analyze, using the z-
test, the data to determine the 90th percentile confidence level. It is
the 90th percentile confidence level that is required to be used to
determine compliance with the applicable emission limit. The
statistical approach is required to assist in ensuring continuous
compliance by statistically accounting for the inherent variability in
the fuel type.
    We are proposing that a source be required to recalculate the fuel
pollutant content only if it burns a new fuel type or fuel mixture and
conduct another performance test if the results of recalculating the
fuel pollutant content are higher than the level established during the
initial performance test.

L. What alternative compliance provisions are being proposed?

    We are proposing that owners and operators of existing affected
sources may demonstrate compliance by emissions averaging for units at
the affected source that are within a single subcategory.
    As part of EPA's general policy of encouraging the use of flexible
compliance approaches where they can be properly monitored and
enforced, we are including emissions averaging in this proposed rule.
Emissions averaging can provide sources the flexibility to comply in
the least costly manner while still maintaining regulation that is
workable and enforceable. Emissions averaging would not be applicable
to new affected sources and could only be used between EGUs in the same
subcategory at a particular affected source. Also, owners or operators
of existing sources subject to the EGU NSPS (40 CFR part 60, subparts D
and Da) would be required to continue to meet the PM emission standard
of that NSPS regardless of whether or not they are using emissions
averaging.
    Emissions averaging would allow owners and operators of an affected
source to demonstrate that the source complies with the proposed
emission limits by averaging the emissions from an individual affected
unit that is emitting above the proposed emission limits with other
affected units at the same facility that are emitting below the
proposed emission limits and that are within the same subcategory.
    This proposed rule includes an emissions averaging compliance
alternative because emissions averaging represents an equivalent, more
flexible, and less costly alternative to controlling certain emission
points to MACT levels. We have concluded that a limited form of
averaging could be implemented that would not lessen the stringency of
the MACT floor limits and would provide flexibility in compliance, cost
and energy savings to owners and operators. We also recognize that we
must ensure that any emissions averaging option can be implemented and
enforced, will be clear to sources, and most importantly, will be no
less stringent than unit by unit implementation of the MACT floor
limits.
    EPA has concluded that it is permissible to establish within a
NESHAP a unified compliance regimen that permits averaging within an
affected source across individual affected units subject to the
standard under certain conditions. Averaging across affected units is
permitted only if it can be demonstrated that the total quantity of any
particular HAP that may be emitted by that portion of a contiguous
major source that is subject to the NESHAP will not be greater under
the averaging mechanism than it could be if each individual affected
unit complied separately with the applicable standard. Under this test,
the practical outcome of averaging is equivalent to compliance with the
MACT floor limits by each discrete unit, and the statutory requirement
that the MACT standard reflect the maximum achievable emissions
reductions is, therefore, fully effectuated.
    In past rulemakings, EPA has generally imposed certain limits on
the scope and nature of emissions averaging programs. These limits
include: (1) No averaging between different types of pollutants; (2) no
averaging between sources that are not part of the same affected
source; (3) no averaging between individual sources within a single
major source if the individual sources are not subject to the same
NESHAP; and (4) no averaging between existing sources and new sources.
    This proposed rule would fully satisfy each of these criteria.
First, emissions averaging would only be permitted between individual
sources at a single existing affected source, and would only be
permitted between individual sources subject to the proposed EGU
NESHAP. Further, emissions averaging would not be permitted between two
or more different affected sources. Finally, new affected sources could
not use emissions averaging. Accordingly, we have concluded that the
averaging of emissions across affected units is consistent with the
CAA. In addition, this proposed rule would require each facility that
intends to utilize emission averaging to submit an emission averaging
plan, which provides additional assurance that the necessary criteria
will be followed. In this emission averaging plan, the facility must
include the identification of: (1) All units in the averaging group;
(2) the control technology installed; (3) the process parameter that
will be monitored; (4) the specific control technology or pollution
prevention measure to be used; (5) the test plan for the measurement of
the HAP being averaged; and (6) the operating parameters to be
monitored for each control device. Upon receipt, the regulatory
authority would not be able to approve an emission averaging plan
containing averaging between emissions of different types of pollutants
or between sources in different subcategories.
    This proposed rule would also exclude new affected sources from the
emissions averaging provision. EPA believes emissions averaging is not
appropriate for new affected sources because it is most cost effective
to integrate state-of-the-art controls into equipment design and to
install the technology during construction of new sources. One reason
we allow emissions averaging is to give existing sources flexibility to
achieve compliance at diverse points with varying degrees of add-on
control already in place in the most cost-effective and technically
reasonable fashion. This flexibility is not needed for new affected
sources because they can be designed and constructed with compliance in
mind.
    In addition, we seek comment on use of a discount factor when
emissions averaging is used and on the appropriate value of a discount
factor, if used. Such discount factors (e.g., 10 percent) have been
used in previous NESHAP, particularly where there was variation in the
types of units within a common

source category to ensure that the environmental benefit was being
achieved. In this situation, however, the affected sources are more
homogeneous, making emissions averaging a more straight-forward
analysis. Further, with the monitoring and compliance provisions that
are being proposed, there is additional assurance that the
environmental benefit will be realized. Further, the emissions
averaging provision would not apply to individual units if the unit
shares a common stack with units in other subcategories, because in
that circumstance it is not possible to distinguish the emissions from
each individual unit.
    The emissions averaging provisions in this proposed rule are based
in part on the emissions averaging provisions in the Hazardous Organic
NESHAP (HON). The legal basis and rationale for the HON emissions
averaging provisions were provided in the preamble to the final
HON.\171\
---------------------------------------------------------------------------

    \171\ Hazardous Organic NESHAP (59 FR 19425; April 22, 1994).
---------------------------------------------------------------------------

M. How did EPA determine compliance times for this proposed rule?

    CAA section 112 specifies the dates by which affected sources must
comply with the emission standards. New or reconstructed units must be
in compliance with this proposed rule immediately upon startup or [DATE
THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER], whichever is
later. Existing sources may be provided up to 3 years to comply with
the final rule; if an existing source is unable to comply within 3
years, a permitting authority has the discretion to grant such a source
up to a 1-year extension, on a case-by-case basis, if such additional
time is necessary for the installation of controls. See section
112(i)(3). We believe that 3 years for compliance is necessary to allow
adequate time to design, install and test control systems that will be
retrofitted onto existing EGUs, as well as obtain permits for the use
of add-on controls.
    We believe that the requirements of the proposed rule can be met
without adversely impacting electric reliability. Our analysis shows
that the expected number of retirements is less than many have
predicted and that these can be managed effectively with existing tools
and processes for ensuring continued grid reliability. Further, the
industry has adequate resources to install the necessary controls and
develop the modest new capacity required within the compliance schedule
provided for in the CAA. Although there are a significant number of
controls that need to be installed, with proper planning, we believe
that the compliance schedule established by the CAA can be met. There
are already tools in place (such as integrated resource planning, and
in some cases, advanced auctions for capacity) that ensure that
companies adequately plan for, and markets are responsive to, future
requirements such as the proposed rule. In addition, EPA itself has
already begun reaching out to key stakeholders including not only
sources with direct compliance obligations, but also groups with
responsibility to assure an affordable and reliable supply of
electricity including state Public Utility Commissions (PUC), Regional
Transmission Organizations (RTOs), the National Electric Reliability
Council (NERC), the Federal Energy Regulatory Commission (FERC), and
DOE. EPA intends to continue these efforts during both the development
and implementation of this proposed rule. It is EPA's understanding
that FERC and DOE will work with entities whose responsibility is to
ensure an affordable, reliable supply of electricity, including state
PUCs, RTOs, the NERC to share information and encourage them to begin
planning for compliance and reliability as early as possible. This
effort to identify and respond to any projected local and regional
reliability concerns will inform decisions about the timing of
retirements and other compliance strategies to ensure energy
reliability. EPA believes that the ability of permitting authorities to
provide an additional 1 year beyond the 3-year compliance time-frame as
specified in CAA section 112, along with other compliance tools,
ensures that the emission reductions and health benefits required by
the CAA can be achieved while safeguarding completely against any risk
of adverse impacts on electricity system reliability. Between proposal
and final, EPA will work with DOE and FERC to identify any
opportunities offered by the authorities and policy tools at the
disposal of DOE and/or FERC that can be pursued to further ensure that
the dual goals of substantially reducing the adverse public health
impacts of power generation, as required by the CAA, while continuing
to assure electric reliability is maintained. EPA also intends to
continue to work with DOE, FERC, state PUCs, RTOs and power companies
as this rule is implemented to identify and address any challenges to
ensuring that both the requirements of the CAA and the need for a
reliable electric system are met.
    In developing this proposed rule, EPA has performed specific
analysis to assess the feasibility (e.g., ability of companies to
install the required controls within the compliance time-frame) and
potential impact of the proposed rule on reliability.
    With regards to feasibility, EPA used IPM to project what types of
controls would need to be installed to meet the requirements of this
proposed rule. This includes technologies to control acid gases (wet
and dry scrubber technology and the use of sorbent injection), the Hg
requirements (co-benefits from other controls such as scrubbers and FFs
and Hg-specific controls such as ACI), the non-Hg metal requirements
(upgrades and or replacements of existing particulate control devices),
and other HAP emissions (GCP).
    Much of the power sector already has controls in place that remove
significant amounts of acid gases. Today over 50 percent of the power
generation fleet has scrubbing technology installed and the industry is
already working on installations to bring that number to nearly two-
thirds of the fleet by 2015. Many of the remaining coal-fired units are
smaller, burn lower sulfur coals, and/or do not operate in a base-load
mode. Units with these types of characteristics are candidates to use
DSI technology which takes significantly less time to install. Units
that choose to install dry or wet scrubbing technology should be able
to do so within the compliance schedule required by the CAA as this
technology can be installed within the 3-year window.\172\ Notably, EPA
does not project use of wet scrubbing technology to meet the
requirements of this proposed rule and that is the technology that
typically takes a longer time to install.
---------------------------------------------------------------------------

    \172\ In a letter to Senator Carper dated November 3, 2010
(http://www.icac.com/files/public/ICAC_Carper_Response_110310.pdf) David Foerter, the executive director of the Institute
of Clean Air Companies (ICAC) explained that wet scrubber technology
could be installed in 36 months, dry scrubber technology could be
installed in 24 months and dry sorbent injection could be installed
in 12 months. Page 3.
---------------------------------------------------------------------------

    For Hg control, those units that do not meet the requirements with
existing controls have several options. Companies with installed
scrubbers may be able to make modifications (such as the use of
scrubber additives to enhance Hg control). Other companies may use
supplemental controls such as ACI. These types of options all take
significantly less than 3 years to install.
    Units that do not meet the non-Hg metal HAP requirements have
several options such as upgrading existing particulate controls,
installing

supplemental particulate controls, or replacing existing particulate
controls. These options can also be implemented in significantly less
than 3 years.
    EPA projects that for acid gas control, companies will likely use
dry scrubbing and sorbent injection technologies rather than wet
scrubbing. For non-Hg metal HAP controls, EPA has assumed that
companies with ESPs will likely upgrade them to FFs. As a number of
units that were in the MACT floor for non-Hg HAP metals only had ESPs
installed, this is likely a conservative assumption. For Hg, EPA
projects that companies will comply through either the collateral
reductions created by other controls (e.g., scrubber/SCR combination)
or ACI. EPA has assessed the feasibility of installing these controls
within the compliance window (see TSD) and believes that the controls
can be reasonably installed within that time. Although EPA assessed the
ability to install the controls in 3 years (and determined that the
controls could be installed in that time-frame), this would require the
control technology industry to ramp up quickly. Therefore, EPA also
assessed a time-frame that would allow some installations to take up to
4 years. This time-frame is consistent with the CAA which allows
permitting authorities the discretion to grant extensions to the
compliance time-line of up to 1 year. This time-frame also allows for
staggered installation of controls at facilities that need to install
technologies on multiple units. Staggered installation allows companies
to address such issues as scheduling outages at different units so that
reliable power can be provided during these outage periods or
particularly complex retrofits (e.g., when controls for one unit need
to be located in an open area needed to construct controls on another
unit). In other words, the additional 1-year extension would provide an
additional two shoulder periods to schedule outages. It also provides
additional opportunity to spread complex outages over multiple outage
periods. EPA believes that while many units will be able to fully
comply within 3 years, the 4th year that permitting authorities are
allowed to grant for installation of controls is an important
flexibility that will address situations where an extra year is
necessary.
    Permitting authorities are familiar with the operation of this
provision because they have used it in implementing previous NESHAP.
This extension can be used to address a range of reasons that
installation schedules may take more than 3 years including: staggering
installations for reliability or constructability purposes, or other
site-specific challenges that may arise related to source-specific
construction issues, permitting, or local manpower or resource
challenges. EPA is proposing that States consider applying this
extension both to the installation of add on controls (e.g., a FF, or a
dry scrubber) and the construction of on-site replacement power (e.g.,
a case when a coal unit is being shut down and the capacity is being
replaced on-site by another cleaner unit such as a combined cycle or
simple cycle gas turbine and the replacement process requires more than
3 years to accomplish). EPA believes that it is reasonable to allow the
extension to apply to the replacement because EPA believes that
building of replacement power could be considered ``installation of
controls'' at the facility. Because the phrase ``installation of
controls'' could also be interpreted to apply only to changes made to
an existing unit rather than the replacement of that existing unit with
a new cleaner one, EPA takes comment on its proposal to allow the
extension to apply to replacement power.
    EPA has also considered the impact that potential retirements under
this proposed rule will have on reliability. When considering the
impact that one specific action has on power plant retirements, it is
important to understand that the economics that drive retirements are
based on multiple factors including: Expected electric demand, cost of
alternative generation, and cost of continuing to generate using an
existing unit. EPA's analysis shows that the lower cost of alternative
generating sources (particularly the cost of natural gas), as well as
reductions in demand, have a greater impact on the number of projected
retirements than does the impact of the proposed rule. EPA's assessment
looked at the reserve margins in each of 32 subregions in the
continental U.S. It shows that with the addition of very little new
capacity, average reserve margins are significantly higher than
required (NERC assumes a default reserve margin of 15 percent while the
average capacity margin seen after implementation of the policy is
nearly 25 percent). Although such an analysis does not address the
potential for more localized transmission constraints, the number of
retirements projected suggests that the magnitude of any local
retirements should be manageable with existing tools and processes.
Demand forecasts used were based on EIA projected demand growth.
    Reliability concerns caused by local transmission constraints can
be addressed through a range of solutions including the development of
new generation and/or demand side resources, and/or enhancements to the
transmission system. On the supply side, there are a range of options
including the development of more centralized power resources (either
base-load or peaking), and/or the development of cogeneration, or
distributed generation. Even with the large reserve margins, there are
companies ready to implement supply side projects quickly. For
instance, in the PJM Interconnection (an RTO) region, there are over
11,600 MW of capacity that have completed feasibility and impact
studies and could be on-line by the third quarter of 2014.\173\ Demand
side options include energy efficiency as well as demand response
programs. These types of resources can also be developed very quickly.
In 2006, PJM Interconnection had less than 2,000 MWs of capacity in
demand side resources. Within 4 years this capacity nearly quadrupled
to almost 8,000 MW of capacity.\174\ Recent experience also shows that
transmission upgrades to address reliability issues from plant closures
can also occur in less than 3 years. In addition to helping address
reliability concerns, reducing demand through mechanisms such as energy
efficiency and demand side management practices has many other
benefits. It can reduce the cost of compliance and has collateral air
quality benefits by reducing emissions in periods where there are peak
air quality concerns.
---------------------------------------------------------------------------

    \173\ Paul M Sotkiewicz, PJM Interconnection, Presentation at
the Bipartisan Policy Commission Workshop Series on Environmental
Regulation and Electric System Reliability, Workshop 3: Local,
State, Regional and Federal Solutions, January 19, 2011, Washington
DC, http://www.bipartisanpolicy.org/sites/default/files/Paul%20Sotkiewicz-%20Panel%202_0.pdf, slide 6.
    \174\ Ibid--slide 5.
---------------------------------------------------------------------------

    EPA also examined the impact on reliability of unit outages to
install control equipment. Because these outages usually occur in the
shoulder months (outside summer or winter peaking periods) when demand
is lower (and, thus, reserve margins are higher), the analysis showed
that even with conservative estimates regarding the length of the
outages and conservative estimates about how many outages occurred
within a 1-year time-frame, reserve margins were maintained. With the
potential for a 1-year compliance extension, outages can be further
staggered, providing additional flexibility, even if some units require
longer outages.
    Although EPA's analysis shows that there is sufficient time and
grid capacity to allow for compliance with the rule within the 3-year
compliance window

(with the possibility of a 1-year extension), to achieve compliance in
a timely fashion, EPA expects that sources will begin promptly, based
upon this proposed rule, to evaluate, select, and plan to implement,
source-specific compliance options. In doing so, we would expect
sources to consider the following factors: if retirement is the
selected compliance option, notifying any relevant RTO/ISO in advance
in order to develop an appropriate shutdown plan that identifies any
necessary replacement power transmission upgrades or other actions
necessary to ensure consistent electric supply to the grid; if
installation of control technologies is necessary, any source-specific
space limitations, such that installation can be staggered in a timely
fashion; and source-specific electric supply requirements, such that
outages can be appropriately scheduled. Starting assessments early and
considering the full range of options is prudent because it will help
ensure that the requirements of this proposed rule are met as
economically as possible and that power companies are able to provide
reliable electric power.
    There is significant evidence that companies do in fact engage in
such forward planning. For instance, in September of 2004
(approximately 6 months before the CAIR and CAMR requirements were
finalized); Cinergy announced that it had already begun a construction
program to comply. This program involved not only preliminary
engineering, but actual construction of scrubbers.\175\ Southern
Company also began its engineering process well before those rules were
finalized.\176\ Although EPA understands that not every generating
company may commit to actual capital projects in advance of
finalization of the rule, the CAIR experience shows that some companies
do. Even if companies do not take the step of committing to the capital
projects, there are actions that companies can take that are much less
costly. Companies can analyze their unit-by-unit compliance options
based on the proposed rule. This will put them in a position to begin
construction of projects with the longest lead times quickly and will
ensure that the 3-year compliance window (or 4 with extension from the
permitting authority) can be met.
---------------------------------------------------------------------------

    \175\ Cinergy Press Release, September 2nd, 2004, ``Cinergy
Operating Companies to Reduce Power Plant Emissions, Improve Air
Quality.''
    \176\ ICAC.
---------------------------------------------------------------------------

    It will also ensure that sufficient notification can be provided to
RTOs/ISOs so that the full range of options for addressing any
reliability concerns can be considered. Although most RTOs/ISOs only
require 90-day notifications for retirements, construction schedules
for all but the simplest retrofits will be longer, so sources should be
able to notify their RTOs of their retirements earlier. This will also
help as multiple sources work with their RTO/ISO to determine outage
schedules. The RTOs/ISOs also have a very important role to play and it
appears that a number of them are already engaged in preparing for
these rules. For instance, PJM Interconnection considered the impact of
these anticipated rules at its January 14, 2011, Regional Planning
Process Task Force Meeting,\177\ and Midwest Independent Transmission
System Operator, Inc. (MISO) has also begun a planning process to
consider the impact of EPA rules.\178\
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    \177\ Paul M Sotkiewicz, PJM Interconnection, ``Consideration of
Forthcoming Environmental Regulations in the Planning Process,''
January 14, 2011.
    \178\ MISO Planning Advisory Committee, ``Proposed EPA
Regulatory Impact Analysis,'' November 23, 2010.
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    As discussed above, given the large reserve margins that exist,
even after consideration of requirements of the proposed rule, EPA
believes that any reliability issues are likely to be primarily local
in nature and be due to the retirement of a unit in a load constrained
area. As demonstrated by the work that PJM Interconnection and MISO are
doing, RTOs/ISOs are required to do long range (at least 10 years)
capacity planning that includes consideration of future requirements
such as EPA regulations. Furthermore, if companies within an RTO/ISO
wish to retire a unit, they must first notify the RTO/ISO in advance so
that any reliability concerns can be addressed. The RTOs/ISOs, have
well established procedures to address such retirements.
    Starting assessments early and considering the full range of
options will help ensure that the requirements of this rule are met as
economically as possible and that power companies are able to provide
reliable electric power while significantly reducing their impact on
public health. For power companies this includes considering the range
of pollution control options available for their existing fleet as well
as considering the range of options for replacement power, in the cases
where shutting down a unit is the more economic choice. The RTOs/ISOs
should consider the full range of options to provide any necessary
replacement power including the development of both supply and demand
side resources. Environmental regulators should work with their
affected sources early to understand their compliance choices. In this
way, those regulators will be able to accurately access when use of the
1-year compliance extension is appropriate. By working with regulators
early, affected sources will be in a position to have assurance that
the 1-year extension will be granted in those situations where it is
appropriate.
    Section X.c. describes the sensitivity analysis performed by EPA
for an Energy Efficiency case, in which a combination of DOE appliance
standards and State investments in demand-side efficiency come into
place at the same time as compliance with the requirements of this
rule. That analysis shows that even in the absence of this rule,
moderate actions to promote energy efficiency would lead to retirement
of an additional 11 GW in 2015, of 27 GW in 2020, and of 26 GW in 2030,
beyond the capacity already projected to retire in the base case. In
effect, the timely adoption and implementation of energy efficiency
policies would augment currently projected reserve capacities that are
instrumental to assuring system reliability.
    As noted, instrumental to undertaking such actions are other
Federal agencies such as DOE, ISOs and RTOs, and state agencies such as
PUCs. Fortunately, in addition to helping to assure system reliability,
timely implementation of energy efficiency policies offer these key
decision-makers an additional incentive to take action. As the analysis
shows, energy efficiency can reduce costs for ratepayers and customers.
    First, with or without the proposed Toxic Rule, energy efficiency
policies are shown by the analysis to reduce the overall costs of
generating electricity, with the cost reductions increasing over time.
See Table 22. Second, when comparing the Toxics Rule Case without
energy efficiency to the Toxics Rule Case with energy efficiency, the
analysis suggests that if these energy efficiency policies were to be
put into place and maintained over time by system operators, states and
DOE, the costs of the proposed Toxics Rule are mitigated by these cost
reductions such that the overall system costs are reduced by $2 billion
in 2015, $6 billion in 2020, and $11 billion in 2030.
    The energy savings driven by these energy efficiency policies mean
that consumers will pay less for electricity as well. EPA has modeled
national average retail electricity prices, including the energy
efficiency costs that are paid by the ratepayer. The Toxics Rule
increases retail prices by 3.7 percent, 2.6 percent and 1.9 percent in
2015, 2020 and 2030

respectively relative to the base case. If energy efficiency policies
are implemented along with the Toxics Rule, the average retail price of
electricity increases by 3.3 percent in 2015 relative to the base case,
but falls relative to the base case by about 1.6 percent in 2020 and
about 2.3 percent in 2030. The effect on electricity bills however may
fall more than these percentages suggest as energy efficiency means
that less electricity will be used by consumers of electricity.
    EPA believes that as it shares these results with PUCs, the
commissions will respond in accordance with their ongoing imperative to
ensure that electricity costs for ratepayers and consumers remains
stable. Specifically, the opportunity created through the deployment of
energy efficiency-promoting strategies and initiatives to safeguard
system reliability and, especially, to curb cost increases that might
otherwise result from implementation of the Toxics Rule should provide
PUCs with both the motivation and the justification for providing
utilities with the financial and regulatory support they need to begin
planning as early as possible for compliance and to incorporate in
their plans the kinds of energy efficiency investments needed to
achieve both compliance and cost-minimization.
    EPA recognizes that both utilities and their regulators often are
hesitant to take early action to comply with environmental standards
because they avoid incurring costs that they fear may not be required
once the final regulation is promulgated. EPA urges utilities and
regulators to begin planning and preparations for timely compliance.
The same concerns about consumer cost in some cases also dissuade
utilities from incurring, and commissions from authorizing, the upfront
costs associated with energy efficiency programs. However, EPA also
believes that if it takes steps to actively disseminate the results of
the energy efficiency analysis, then utilities will be that much more
likely to begin, and regulators that much more likely to support,
comprehensive assessment and planning as early as possible since
compliance approaches that encompass energy efficiency integrated with
other actions needed to meet the Toxics Rule's requirements will result
in lower costs for ratepayers and consumers. EPA encourages State
environmental regulators to consider the extent to which a utility
engages in early planning when making a decision regarding granting a
4th year for compliance with the Toxics Rule.
    In summary, EPA believes that the large reserve margins, the range
of control options, the range of flexibilities to address unit
shutdowns, existing processes to assure that sufficient generation
exists when and where it is needed, and the flexibilities within the
CAA, provide sufficient assurance that the CAA section 112 requirements
for the power sector can be met without adversely impacting electric
reliability.
    EGUs are the subject of several rulemaking efforts that either are
or will soon be underway. In addition to this rulemaking proposal,
concerning both hazardous air pollutants under section 112 and criteria
pollutant NSPS standards under section 111, EGUs are the subject of
other rulemakings, including ones under section 110(a)(2)(D) addressing
the interstate transport of emissions contributing to ozone and PM air
quality problems, coal combustion wastes, and the implementation of
section 316(b) of the Clean Water Act (CWA). They will also soon be the
subject of a rulemaking under CAA section 111 concerning emissions of
greenhouse gases.
    EPA recognizes that it is important that each and all of these
efforts achieve their intended environmental objectives in a common-
sense manner that allows the industry to comply with its obligations
under these rules as efficiently as possible and to do so by making
coordinated investment decisions and, to the greatest extent possible,
by adopting integrated compliance strategies. In addition, EO 13563
states that ``[i]n developing regulatory actions and identifying
appropriate approaches, each agency shall attempt to promote such
coordination, simplification, and harmonization. Each agency shall also
seek to identify, as appropriate, means to achieve regulatory goals
that are designed to promote innovation.'' Thus, EPA recognizes that it
needs to approach these rulemakings, to the extent that its legal
obligations permit, in ways that allow the industry to make practical
investment decisions that minimize costs in complying with all of the
final rules, while still achieving the fundamentally important
environmental and public health benefits that the rulemakings must
achieve.
    The upcoming rulemaking under section 111 regarding GHG emissions
from EGUs may provide an opportunity to facilitate the industry's
undertaking integrated compliance strategies in meeting the
requirements of these rulemakings. First, since that rulemaking will be
finalized after a number of the other rulemakings that are currently
underway are, the Agency will have an opportunity to take into account
the effects of the earlier rulemakings in making decisions regarding
potential GHG standards for EGUs.
    Second, in that rulemaking, EPA will be addressing both CAA section
111(b) standards for emissions from new and modified EGUs and CAA
section 111(d) emission guidelines for states to follow in establishing
their plans regarding GHG emissions from existing EGUs. In evaluating
potential emission standards and guidelines, EPA may consider the
impacts of other rulemakings on both emissions of GHGs from EGUs and
the costs borne by EGUs. The Agency expects to have ample latitude to
set requirements and guidelines in ways that can support the states'
and industry's efforts in pursuing practical, cost-effective and
coordinated compliance strategies encompassing a broad suite of its
pollution-control obligations. EPA will be taking public comment on
such flexibilities in the context of that rulemaking.
    As discussed elsewhere in this preamble, we invite comment on this
proposed rule. EPA solicits comment on the ability of sources subject
to this proposed rule to comply within the statutorily mandated 3-year
compliance window and/or the 1-year discretionary extension, as well as
comment on specific factors that could prevent a source from achieving,
or could enable a source to achieve, compliance. In addition, EPA
requests comment on the impact of this proposed rule on electric
reliability, and ways to ensure compliance while maintaining the
reliability of the grid.
    A number of states (or localities) have proactively developed plans
to address a suite of environmental issues, an aging generation fleet,
and electric reliability (e.g., plans requiring retirement of coal and
pollution control devices such as the Colorado ``Clean Air-Clean Jobs
Act'' or renewable portfolio standards that because of the states'
current generation mix could result in significant changes to the
composition of the fossil-fuel-fired portion of the fleet such as
Hawaii's renewable portfolio standard (HB-1464)). In most cases, these
plans were developed solely under State law with no underlying Federal
requirement. Furthermore, as explained above, many of the technologies
that were installed or that are planned to be installed in response to
these state plans are likely to result in collateral reductions of many
HAP required to be reduced in today's proposed rule. Although some of
these state programs may have obtained some important emission
reductions to date, they may also allow compliance time-frames for

some units that extend beyond those authorized under CAA section
112(i)(3).
    The Agency has a program pursuant to 40 CFR subpart E, whereby
states can take delegation of section 112 emission standards. Among
other things, states can seek approval of state rules to the extent
they can demonstrate that those rules are no less stringent that the
applicable section 112(d) rule. Because overall, some of these state
programs may result in greater emission reductions, EPA is taking
comment on whether (and if so how) such state plans could be integrated
with the proposed rule requirements consistent with the statute. EPA
also intends to engage with states who believe that they have such
plans to understand whether they believe that there are opportunities
to integrate the two sets of requirements in a manner consistent with
the requirements of the CAA.
    EGUs are the subject of several rulemaking efforts that either are
or will soon be underway. In addition to this rulemaking proposal,
concerning both HAP under section 112 and criteria pollutant NSPS
standards under section 111, EGUs are the subject of other rulemakings,
including ones under section 110(a)(2)(D) addressing the interstate
transport of emissions contributing to ozone and PM air quality
problems, coal combustion wastes, and the implementation of section
316(b) of the CWA. They will also soon be the subject of a rulemaking
under CAA section 111 concerning emissions of greenhouse gases (GHG).
    EPA recognizes that it is important that each and all of these
efforts achieve their intended environmental objectives in a common-
sense manner that allows the industry to comply with its obligations
under these rules as efficiently as possible and to do so by making
coordinated investment decisions and, to the greatest extent possible,
by adopting integrated compliance strategies. Thus, EPA recognizes that
it needs to approach these rulemakings, to the extent that its legal
obligations permit, in ways that allow the industry to make practical
investment decisions that minimize costs in complying with all of the
final rules, while still achieving the fundamentally important
environmental and public health benefits that the rulemakings must
achieve.
    The upcoming rulemaking under section 111 regarding GHG emissions
from EGUs may provide an opportunity to facilitate the industry's
undertaking integrated compliance strategies in meeting the
requirements of these rulemakings. First, since that rulemaking will be
finalized after a number of the other rulemakings that are currently
underway are, the agency will have an opportunity to take into account
the effects of the earlier rulemakings in making decisions regarding
potential GHG standards for EGUs.
    Second, in that rulemaking, EPA will be addressing both CAA section
111(b) standards for emissions from new and modified EGUs and CAA
section 111(d) emission guidelines for states to follow in establishing
their plans regarding GHG emissions from existing EGUs. In evaluating
potential emission standards and guidelines, EPA may consider the
impacts of other rulemakings on both emissions of GHGs from EGUs and
the costs borne by EGUs. The Agency expects to have ample latitude to
set requirements and guidelines in ways that can support the states'
and industry's efforts in pursuing practical, cost-effective and
coordinated compliance strategies encompassing a broad suite of its
pollution-control obligations. EPA will be taking public comment on
such flexibilities in the context of that rulemaking.

N. How did EPA determine the required records and reports for this
proposed rule?

    You would be required to comply with the applicable requirements in
the NESHAP General Provisions, subpart A of 40 CFR part 63, as
described in Table 10 of the proposed 40 CFR part 63, subpart UUUUU. We
evaluated the General Provisions requirements and included those we
determined to be the minimum notification, recordkeeping, and reporting
requirements necessary to ensure compliance with, and effective
enforcement of, this proposed rule.
    We would require additional recordkeeping if you chose to comply
with the chlorine or Hg fuel input option. You would need to keep
records of the calculations and supporting information used to develop
the chlorine or Hg fuel input operating limit.

O. How does this proposed rule affect permits?

    The CAA requires that sources subject to this proposed rule be
operated pursuant to a permit issued under EPA-approved state operating
permit program. The operating permit programs are developed under Title
V of the CAA and the implementing regulations under 40 CFR parts 70 and
71. If you are operating in the first 2 years of the current term of
your operating permit, you will need to obtain a revised permit to
incorporate this proposed rule. If you are in the last 3 years of the
current term of your operating permit, you will need to incorporate
this proposed rule into the next renewal of your permit.

P. Alternative Standard for Consideration

    As discussed above, we are proposing alternate equivalent emission
standards (for certain subcategories) to the proposed surrogate
standards in three areas: SO2 (in addition to HCl),
individual non-Hg metals (for PM), and total non-Hg metals (for PM).
The proposed emission limitations are provided in Tables 16 and 17 of
this preamble.

                                     Table 15--Alternate Emission Limitations for Existing Coal- and Oil-Fired EGUs
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                                         Coal-fired unit
                                     designed for coal  = 8,300 Btu/lb   designed for coal  <            GWh)                 (lb/GWh)          Solid oil-derived
                                                                  8,300 Btu/lb
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SO2................................  0.20 lb/MMBtu (2.0 lb/  0.20 lb/MMBtu (2.0 lb/  NA...................  NA...................  0.40 lb/MMBtu (5.0 lb/
                                      MWh).                   MWh).                                                                 MWh).
Total non-Hg metals................  0.000040 lb/MMBtu       0.000040 lb/MMBtu       5.0 (0.050)..........  NA...................  0.000050 lb/MMBtu