located in the Docket.
---------------------------------------------------------------------------

2. Determination of MACT for Organic HAP
    In developing the MACT floor for organic HAP, as described earlier,
we are using CO as a surrogate for non-dioxin organic HAP. Table 3 of
this preamble presents the number of units in each of the 11
subcategories, along with the number of units from which we have
collected emission data. Table 3 also presents for each subcategory
(for CO and D/F) the number of units comprising the best performing
units (top 12 percent), the average emission level of the top 12
percent, and the MACT floor (99 percent UPL of top 12 percent) which
includes the variability across the best performing units and the long
term variability.
    We calculated the MACT floors based on the upper 99th percentile
UPL from the average performance of the best performing units and their
variances as described earlier for the fuel-related HAP.

                    Table 3--Summary of MACT Floor Results for the Organic HAP Subcategories
----------------------------------------------------------------------------------------------------------------
            Subcategory                       Parameter                     CO              Dioxin/Furan (TEQ)
----------------------------------------------------------------------------------------------------------------
Stoker--Coal.......................  No. of sources in            361...................  361.
                                      subcategory.
                                     No. of sources with data...  61....................  14.
                                     No. in MACT floor..........  8.....................  2.
                                     Avg of top 12%.............  21.4 ppm @ 3% O2......  0.00182 ng/dscm @ 7%
                                                                                O2.
                                     99% UPL of top % (test       48.8 ppm @ 3% O2......  0.00274 ng/dscm @ 7%
                                      runs).                                               O2.
Fluidized Bed--Coal................  No. of sources in            31....................  31.
                                      subcategory.
                                     No. of sources with data...  17....................  12.
                                     No. in MACT floor..........  3.....................  2.
                                     Avg of top 12%.............  12.5 ppm @ 3% O2......  0.000471 ng/dscm @ 7%
                                                                                O2.
                                     99% UPL of top % (test       21.4 ppm @ 3% O2......  0.00168 ng/dscm @ 7%
                                      runs).                                               O2.
PC--Coal...........................  No. of sources in            186...................  186.
                                      subcategory.
                                     No. of sources with data...  41....................  10.
                                     No. in MACT floor..........  5.....................  2.
                                     Avg of top 12%.............  19.2 ppm @ 3% O2......  0.00158 ng/dscm @ 7%
                                                                                O2.
                                     99% UPL of top % (test       82.8 ppm @ 3% O2......  0.00307 ng/dscm @ 7%
                                      runs).                                               O2.
Stoker--Biomass....................  No. of sources in            320...................  320.
                                      subcategory.
                                     No. of sources with data...  119...................  16.
                                     No. in MACT floor..........  15....................  2.
                                     Avg of top 12%.............  203 ppm @ 3% O2.......  0.000819 ng/dscm @ 7%
                                                                                O2.
                                     99% UPL of top % (test       551 ppm @ 3% O2.......  0.00339 ng/dscm @ 7%
                                      runs).                                               O2.
Fluidized Bed--Biomass.............  No. of sources in            12....................  12.
                                      subcategory.
                                     No. of sources with data...  7.....................  6.
                                     No. in MACT floor..........  5.....................  5.
                                     Avg of top 12%.............  97.1 ppm @ 3% O2......  0.00507 ng/dscm @ 7%
                                                                                O2.
                                     99% UPL of top 12% (test     245 ppm @ 3% O2.......  0.0127 ng/dscm @ 7%
                                      runs).                                               O2.
Suspension Burner/Dutch Oven.......  No. of sources in            62....................  62.
                                      subcategory.
                                     No. of sources with data...  17....................  3.
                                     No. in MACT floor..........  3.....................  1.
                                     Avg of top 12%.............  362 ppm @ 3% O2.......  0.00952 ng/dscm @ 7%
                                                                                O2.
                                     99% UPL of top 12% (test     1010 ppm @ 3% O2......  0.0279 ng/dscm @ 7%
                                      runs).                                               O2.
Fuel Cell--Biomass.................  No. of sources in            26....................  26.
                                      subcategory.
                                     No. of sources with data...  16....................  7.
                                     No. in MACT floor..........  5.....................  5.
                                     Avg of top 12%.............  130 ppm @ 3% O2.......  0.00552 ng/dscm @ 7%
                                                                                O2.
                                     99% UPL of top 12% (test     262 ppm @ 3% O2.......  0.0148 ng/dscm @ 7%
                                      runs).                                               O2.
Units designed for Liquid fuel       No. of sources in            826...................  826.
 firing.                              subcategory.
                                     No. of sources with data...  116...................  17.
                                     No. in MACT floor..........  14....................  3.
                                     Avg of top 12%.............  0.443 ppm @ 3% O2.....  0.000733 ng/dscm @ 7%
                                                                                O2.
                                     99% UPL of top 12% (test     0.911 ppm @ 3% O2.....  0.00182 ng/dscm @ 7%
                                      runs).                                               O2.
Units designed for other gases       No. of sources in            199...................  199.
 firing.                              subcategory.
                                     No. of sources with data...  75....................  5.
                                     No. in MACT floor..........  9.....................  1.
                                     Avg of top 12%.............  0.0737 ppm @ 3% O2....  0.00267 ng/dscm @ 7%
                                                                                O2.
                                     99% UPL of top 12% (test     0.134 ppm @ 3% O2.....  0.00828 ng/dscm @ 7%
                                      runs).                                               O2.
----------------------------------------------------------------------------------------------------------------

    For organic HAP, as previously discussed above for fuel-related
HAP, 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. Here, however, we know that the
organic HAP emissions will also vary over the operating range of the
unit, unlike fuel-related HAP emissions. Organic HAP are combustion-
related pollutants. That is, their levels of emissions are a function
of the combustion process. Combustion units operate most efficiently
when operated

at or near their design capacity. The combustion efficiency tends to
decrease as the unit's load (steam production) decreases. Most
industrial or commercial/institutional units do not continuously
operate at or near their design capacity but operate according to the
facility's demand for steam. Thus, operation at lower capacity rates
must be accounted for in determining operational variability.
    As part of EPA's information collection effort, we obtained data on
organic HAP (THC and CO) from six units (two coal-fired, two biomass-
fired, and two gas-fired) that were collected using CEM over a 30-day
period. All of these units were selected to test using CEM to provide
variability information because their stack test results indicated that
they were among the best performing units.
    The CEMS data shows that CO (as a surrogate for non-dioxin organic
HAP) from best performing units did not vary much when such unit is
operated at below design capacity. Therefore, even though ICI units,
due to steam demand, may operate at these low load conditions, no
additional variability due to operating load needs to be accounted for
since the average CO emission levels that include these low load
conditions are within the variability range determined by the
statistical analyses of CO emissions from the best performing units.
Thus, we are proposing to add no additional variability factor to
account for load variability to the MACT floor 99 percent UPL values
determined from the stack test data for CO emissions.
    This approach reasonably ensures that the emission limit selected
as the MACT floor adequately represents the average level of control
actually achieved by units in the top 12 percent in each subcategory,
considering ordinary operational variability of those units. Both the
analysis of the measured emissions from units representative of the top
12 percent, and the variability analysis of those units, 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.
    As was the case for the three fuel-dependent MACT floors, the
proposed new and existing source MACT floors for eight combustion-
dependent subcategories are almost identical because the best
performing 12 percent of units (for which we have emissions
information) is only one or two sources. Again, the reason we look to
the best performing 12 percent of sources is that these subcategories
consist of 30 or more units. In contrast, if these subcategories had
less than 30 sources, we would be required to use the top five best
performing sources, rather than the one or two that comprise the top 12
percent. As stated previously, we are seeking comment on whether, with
the facts of this rulemaking, we should consider reading the intent of
Congress to allow us to consider five sources rather than just one,
two, or three. We are specifically requesting comment on this
interpretation relating to the proposed MACT floors.
3. 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.''
    The standard reference methods for measuring emissions of mercury,
CO (as a surrogate for organic HAP), D/F, HCl (as a surrogate for acid
gases) and PM (as a surrogate for non-mercury metals) are EPA Methods
29, 10, 23, 26A and 5. These methods are reliable but relatively
expensive as a group. However, the methods are generally not able to
accurately sample small diameter (less than 12 inches) stacks. For
example, in these small diameter stacks, the conventional EPA Method 5
stack assembly blocks a significant portion of the cross-section of the
duct and, if unaccounted for, could cause inaccurate measurements. Many
existing small boilers and process heaters have stacks with diameters
less than 12 inches. The stack diameter is generally related to the
size of the unit. Units that have capacity below 10 million Btu per
hour generally have stacks with diameters less than 12 inches. Also,
many existing small units do not currently have sampling ports or a
platform for accessing the exhaust stack which would require an
expensive modification to install sampling ports and a platform.
    We conducted a cost analysis \10\ to evaluate the economic impact
of the testing and monitoring costs that facilities with small units
would incur to demonstrate compliance with the proposed emission
limits. The compliance costs imposed on each facility would not only
include the costs of the stack tests and monitoring equipment but would
also include the capital costs of any installed control equipment. We
estimate that the total capital costs of installing control equipment
on the over 7,400 small boilers and process heaters to achieve the
proposed emission limits would be $6.3 billion. In addition to these
costs, additional costs would be incurred because many of these small
units do not have test ports or testing platforms installed in order to
conduct performance testing. Prior to conducting a stack test each unit
would need to construct or rent scaffolding and install test ports. EPA
estimates that these small sources would incur an additional $185
million to install test ports and rent temporary scaffolding. Many
establishments in each industry, commercial, or institutional sector
are associated with multiple (as many as a 700) small units.
---------------------------------------------------------------------------

    \10\ Memorandum: Methodology for Estimating Impacts from
Industrial, Commercial, and Institutional Boilers and Process
Heaters at Major Sources of Hazardous Air Pollutant Emissions, March
23, 2010.
---------------------------------------------------------------------------

    The results of the analysis indicate that the annual costs for
testing and monitoring costs alone would have a significant adverse
economic impact on these facilities. The severity of the economic
impact would depend on the size of the facility.
    Based on this analysis, the Administrator has determined under CAA
section 112(h) that it is not feasible to enforce emission standards
for a particular class of existing boilers and process heaters because
of the technological and economic limitations described above. Thus, a
work practice, as discussed below, is being proposed to limit the
emission of HAP for existing boilers and process heaters having a heat
input capacity of less than 10 million Btu per hour. We are
specifically requesting comment on whether a threshold higher than 10
million Btu per hour meets the technical and economic limitations as
specified in CAA section 112(h).
    For existing units, the only work practice being used that
potentially controls HAP emissions is a tune-up. Fuel dependent HAP are
typically controlled by removing them from the flue gas after
combustion. The only work practices expected to minimize fuel dependent
HAP emissions are reducing the fuel usage or fuel switching to a fuel
type with a lower HAP content. Fuel usage can be reduced by improving
the combustion efficiency of the unit, such as, by a tune-up. As
combustion efficiency decreases, fuel usage must increase to maintain

constant energy output. This increased fuel use results in increased
emissions.
    On the other hand, 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
oxygen requires temperature (high enough to ignite the fuel
constituents), mixing or turbulence (to provide intimate oxygen-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 organic HAP emissions.
    We have obtained information on units that reported using GCP, as
part of the information collection effort for the NESHAP. The data that
we have suggests that units typically conduct tune-ups. We also
reviewed State regulations and permits. The work practices listed in
State regulations includes tune-ups (10 States), operator training (1
State), periodic inspections (2 States), and operation in accordance
with manufacturer specifications (1 State). Of the units with a
capacity of less than 10 MMBtu/h that responded to EPA's information
collection effort for the NESHAP, 80 percent reported conducting a
tune-up program. Ultimately, we determine that at least 6 percent of
the units in each of the subcategories are subject to a tune-up
requirement. Therefore, the proposed work practice of a tune-up \11\
program does establish the MACT floor for HAP emissions from existing
units with a heat input capacity of less than 10 MMBtu/h.
---------------------------------------------------------------------------

    \11\ Tune-up procedure is specified in section 63.7540 of this
proposed rule and includes making adjustments to the burner to
optimize the flame to minimize CO emissions consistent with the
manufacturer's specifications.
---------------------------------------------------------------------------

    We are also proposing a work practice standard under section 112(h)
that would require an annual tune-up for existing boilers and process
heaters combusting natural gas or refinery gas. These boilers and
process heaters are units included in the Gas 1 and metal processing
furnace subcategories. We are specifically seeking comment on whether
the application of measurement methodology to sources in this
subcategory is impracticable due to technological or economic
limitations, as specified in section 112(h)(2)(B).
    This work practice standard is being proposed for several reasons.
First, the capital costs estimated for installing controls on these
boilers and process heaters to comply with MACT limits for the five HAP
groups is over $14 billion. This cost includes installation of a
combination system of a fabric filter (for PM, mercury, and D/F
control) and a wet scrubber (for HCl control). This capital cost is
higher than the estimated combined capital cost for boilers and process
heaters in all of the other subcategories. The projected control system
needed for boilers and process heaters in the other subcategories is
also a combined fabric filter/wet scrubber system.
    Second, we believe that proposing emission standards for gas-fired
boilers and process heaters that result in the need to employ the same
emission control system as needed for the other fuel types would have
the negative benefit of providing a disincentive for switching to gas
as a control technique (and a pollution prevention technique) for
boilers and process heaters in the other fuel subcategories. In
addition, emission limits on gas-fired boilers and process heaters may
have the negative benefit of providing an incentive for a facility to
switch from gas (considered a ``clean'' fuel) to a ``dirtier'' but
cheaper fuel (i.e., coal). It would be inconsistent with the emissions
reductions goals of the CAA, and of section 112 in particular, to adopt
requirements that would result in an overall increase in HAP emissions.
We are soliciting comment on the extent to which natural gas facilities
would be expected to switch to a ``dirtier'' fuel if emissions limits
for such facilities are adopted.
    Thus, a work practice, as discussed above for small boilers and
process heaters, is being proposed to limit the emission of HAP for
existing natural gas-fired and refinery gas-fired boilers and process
heaters.
    We request comments on whether the emission limits listed in Table
4 of this preamble for the Gas 1 and Metal Process Furnace
subcategories should be promulgated. Comments should include detailed
information regarding why emission limits for these gas-fired boilers
and process heaters are appropriate.

                              Table 4--Summary of MACT Floor Results for the Gas 1 and Metal Process Furnace Subcategories
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Dioxin/furan
           Subcategory                 Parameter              PM                Mercury               HCl                 CO              (total TEQ)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Units designed for NG/RG firing.  No. of sources in   10,783............  10,783............  10,783............  10,783............  10,783.
                                   subcategory.
                                  No. of sources      144...............  14................  11................  754...............  8.
                                   with data.
                                  No. in MACT floor.  18................  2.................  2.................  91................  1.
                                  Avg of top 12%....  0.00388 lb/MMBtu..  1.1E-07 lb/MMBtu..  1.01E-04 lb/MMBtu.  1.45 ppm @ 3%       0.0026 ng/dscm @
                                                                                oxygen.             7% oxygen.
                                  99% UPL of top 12%  0.03 lb/MMBtu.....  2.0E-07 lb/MMBtu..  0.0002 lb/MMBtu...  20 ppm @ 3% oxygen  0.01 ng/dscm @ 7%
                                   (test runs).                                                                                oxygen.
Metal Process Furnaces..........  No. of sources in   749...............  749...............  749...............  749...............  749.
                                   subcategory.
                                  No. of sources      9.................  7.................  9.................  15................  7.
                                   with data.
                                  No. in MACT floor.  2.................  1.................  2.................  2.................  1.
                                  Avg of top 12%....  0.0047 lb/MMBtu...  3.3E-08 lb/MMBtu..  1.92E-04 lb/MMBtu.  0.38 ppm @ 3%       0.0026 ng/dscm @
                                                                                oxygen.             7% oxygen.
                                  99% UPL of top 12%  0.02 lb/MMBtu.....  2.0E-07 lb/MMBtu..  0.0004 lb/MMBtu...  2 ppm @ 3% oxygen.  0.004 ng/dscm @ 7%
                                   (test runs).                                                                                oxygen.
--------------------------------------------------------------------------------------------------------------------------------------------------------

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

    Once the MACT floor determinations were done 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. A
detailed description of the beyond-the-floor consideration is in the
memorandum ``Methodology for Estimating Cost and Emissions Impacts for
Industrial, Commercial, Institutional Boilers and Process Heaters
National Emission Standards for Hazardous Air Pollutants'' in the
docket.
    We could not identify better HAP emissions reduction approaches
that could achieve greater emissions reductions of HAP than the control
technology combination (fabric filter, carbon injection, scrubber, and
GCP) that we expect will be used to meet the MACT floor level of
control.
    For each subcategory, 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, and supplies to industrial customers
can be limited during periods when natural gas demand exceeds supply.
Additionally, the estimated emissions reductions that would be achieved
if solid and liquid fuel units switched to natural gas were compared
with the estimated cost of converting existing solid fuel and liquid
fuel units to fire natural gas. The annualized cost of fuel switching
was estimated to be $13.5 billion compared with $3.5 billion under the
floor approach. The emission reduction associated with fuel switching
was estimated to be 4,296 tons per year for metallic HAP, 8 tons per
year for mercury, and 50,332 tons per year for inorganic HAP (HCl and
HF). The cost for fuel switching is over double the cost of the floor
approach while the emission reductions associated with fuel switching
are approximately the same. Additional detail on the calculation
procedures is provided in the memorandum ``Development (2010) of Fuel
Switching Costs and Emissions Reductions for Industrial, Commercial,
and Institutional Boilers and Process Heaters National Emission
Standards for Hazardous Air Pollutants'' in the docket.
    We also considered the pollution prevention and energy conservation
measure of an energy assessment/audit as a beyond-the-floor option for
HAP emissions. An energy assessment provides valuable information on
improving energy efficiency. An energy assessment, or audit, is an in-
depth energy study identifying all energy conservation measures
appropriate for a facility given its operating parameters. An energy
assessment refers to a process which involves a thorough examination of
potential savings from energy efficiency improvements, pollution
prevention, and productivity improvement. It leads to the reduction of
emissions of pollutants through process changes and other efficiency
modifications. Besides reducing operating and maintenance costs,
improving energy efficiency reduces negative impacts on the environment
and results in reduced emissions and improved public health.
Improvement in energy efficiency results in decreased fuel use which
results in a corresponding decrease in emissions (both HAP and non-HAP)
from the combustion unit, but not necessarily a decrease in emissions
of all HAP emitted. The Department of Energy has conducted energy
assessments at selected manufacturing facilities and reports that
facilities can reduce fuel/energy use by 10 to 15 percent by using best
practices to increase their energy efficiency. Many best practices are
considered pollution prevention because they reduce the amount of fuel
combusted which results in a corresponding reduction in emissions from
the fuel combustion. The most common best practice is simply tuning the
boiler to the manufacturer's specification.
    The one-time cost of an energy assessment ranges from $2500 to
$55,000 depending on the size of the facility. The total annualized
cost if each major source facility conducted an energy assessment is
estimated at $26 million. If a facility implemented the cost-effective
energy conservation measures identified in the energy assessment, it
would potentially result in greater HAP reduction than achieved by a
boiler tune-up alone and potentially reducing HAP emissions (HCl,
mercury, non-mercury metals, and VOC) by an additional 820 to 1,640
tons per year. In addition, the costs of any energy conservation
improvement will be offset by the cost savings in lower fuel costs.
Therefore, we decided to go beyond the MACT floor for this proposed
rule for the existing units. These proposed standards for existing
units include the requirement of a performance of an energy assessment
to identify cost-effective energy conservation measures. Since there
was insufficient information to determine if requiring implementation
of cost-effective measures were economically feasible, we are seeking
comment on this point.
    In this proposed rule, we are defining a cost-effective energy
conservation measure to be any measure that has a payback (return of
investment) period of 2 years or less. This payback period was selected
based on section 325(o)(2)(B)(iii) of the Energy Policy and
Conservation Act which states that there is a presumption that an
energy conservation standard is economically justified if the increased
installed cost for a measure is less than three times the value of the
first-year energy savings resulting from the measure.
    We believe that an energy assessment is an appropriate beyond-the-
floor control technology because it is one of the measures identified
in CAA section 112(d)(2). CAA section 112(d)(2) states that ``Emission
standards promulgated * * * and applicable to new or existing sources *
* * is achievable * * * through application of measures, processes,
methods, systems or techniques including, but not limited to measures
which * * * reduce the volume of, or eliminate emissions of, such
pollutants through process changes, substitution of materials or other
modifications * * *''
    The purpose of an energy assessment is to identify energy
conservation measures (such as, process changes or other modifications
to the facility) that can be implemented to reduce the facility energy
demand which would result in reduced fuel use. Reduced fuel use will
result in a corresponding reduction in HAP, and non-HAP, emissions.
Thus, an energy assessment, in combination with the MACT emission
limits will result in the maximum degree of reduction in emissions as
required by 112(d)(2). Therefore, we are proposing to require all
existing sources to conduct a one-time energy assessment to identify
cost-effective energy conservation measures.
    We are proposing that the energy assessment be conducted by energy
professionals and/or engineers that have expertise that cover all
energy using systems, processes, and equipment. We are aware of, at
least, two organizations that provide certification of specialists in
evaluating energy systems. We are proposing that a qualified
specialized is someone who has successfully completed the Department of
Energy's Qualified Specialist Program for all systems or a professional
engineer certified as a Certified Energy Manager by the Association of
Energy Engineers.
    As part of the energy assessment, we are proposing that the
facility assess its energy management program and

practices using EPA's ENERGY STAR Facility Energy Management Assessment
Matrix. ENERGY STAR has a simple facility energy management assessment
tool that can be used as part of the assessment process. This tool
identifies gaps in current practices. Facilities, as part of the
requirement, would identify steps to close the management gaps. We are
also proposing that the facility develop an energy management program
according to the ENERGY STAR Guidelines for Energy Management (see
www.energystar.gov/guidelines).\12\
---------------------------------------------------------------------------

    \12\ The location of the guidance is: http://www.energystar.gov/
index.cfm?c=guidelines.assess_facility_energy.
---------------------------------------------------------------------------

    We are specifically requesting comment on: (1) Whether our
estimates of the assessment costs are correct; (2) is there adequate
access to certified assessors; (3) are there other organizations for
certifying energy engineers; (4) are online tools adequate to inform
the facility's decision to make efficiency upgrades; (5) is the
definition of ``cost-effective'' appropriate in this context since it
refers to payback of energy saving investments without regard to the
impact on HAP reduction; (6) what rate of return should be used; and
(7) are there other guidelines for energy management beside ENERGY
STAR's that would be appropriate.
    We considered proposing a beyond-the-floor requirement for certain
sources in the natural gas and refinery gas subcategory (i.e., the Gas
1 subcategory). Specifically, we considered proposing that facilities
with boilers or process heaters combusting refinery gas install and
maintain a carbon adsorber bed system \13\ to remove mercury from the
refinery gas before combustion in a boiler or process heater. Based on
data from the information collection effort, refinery gas contains
mercury and additional mercury reductions can be achieved from units
combusting refinery gas. Consequently, we analyzed the mercury
emissions reductions and additional cost of adopting this work
practice. The annualized cost of the carbon adsorber bed system to
treat the refinery gas prior to combustion is estimated to be about 1.6
billion dollars with a mercury emission reduction of 0.8 tons. The
results indicated that while additional mercury emissions reductions
would be realized, the costs would be too high to consider it a
feasible beyond-the-floor option. Nonair quality health, environmental
impacts, and energy effects were not significant factors, because there
would be little difference in the nonair quality health and
environmental impacts of requiring the installation of carbon bed
adsorbers. Therefore, we are not proposing installation of a carbon
adsorber bed system as a beyond-the-floor requirement.
---------------------------------------------------------------------------

    \13\ Carbon adsorption of mercury can be accomplished by (a)
injecting dry carbon with or without other dry sorbents into the
offgas upstream of a PM control device (typically a baghouse), or
(b) using a fixed or moving bed of granular carbon through which the
offgas flows. In a typical fixed bed carbon adsorption system, the
flue gas flows through a vessel packed with a specified depth of the
carbon granules. The bed and packing are designed to limit the
linear velocity of the offgas in the bed to increase the contact
time with the carbon. Due to the increased contact times and
typically lower operating temperatures, better removal efficiencies
can be achieved than for carbon injection. At a residence time of 10
seconds in the carbon bed, virtually all of the mercury can be
removed. (Ref. NUCON INTERNATIONAL, Inc., ``Design & Performance
Characteristics of MERSORBB Mercury Adsorbents in Liquids and
Gases,'' NUCON 11B28, August 1995.)
---------------------------------------------------------------------------

F. Should EPA consider different subcategories for solid fuel boilers
and process heaters?

    The boilers and process heaters source category is tremendously
heterogeneous. 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 or adequate data submitted with the
comment), how EPA should define any additional/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 categories.

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

    All standards established pursuant to section 112 of the CAA 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
boilers and process heaters 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 units?

    Similar to the MACT floor process used for existing units, 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 emission test results
from units within the subcategory from lowest to highest to identify
the best controlled similar source. The MACT floor limits for each of
the HAP and HAP surrogates (PM, mercury, CO, HCl, and D/F) 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 limits for new sources were calculated using the
same formula as was used for existing sources. However, as was the case
for the existing MACT floor analysis, we determined that it was
inappropriate to use only this MACT floor approach to determine
variability and to establish emission limits for new boilers and
process heaters. The main problem with using only the HAP emissions
test data is that the data may not reflect the variability of fuel-
related HAP from the best controlled similar source over the long term.
Based on our current information, fuel-related HAP levels in the
various fuels can vary significantly over time. The variations in fuel-
related HAP inputs directly translate to a variability of fuel-related
HAP stack emissions.
    As previously discussed above, 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. If we do not account for this variability,
we would expect that even the best controlled similar source would
potentially exceed the floor emission levels a significant part of the
time which would mean that their variability was not properly accounted
for when setting the floor. 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, Students 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 memorandum ``MACT Floor Analysis for the Industrial, Commercial,
and Institutional Boilers and Process Heaters National Emission
Standards for Hazardous Air Pollutants'' 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. While 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 source. Thus, for existing
units, we are concerned about estimating the central tendency of a set
of multiple units, while 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 unit analysis must account for variability. To
accomplish this for new sources, for the fuel dependent HAP emissions,
we determined what the best controlled source has achieved in light of
the inherent and unavoidable variations in the HAP content of the fuel
that such unit might potentially use. For non-fuel dependent HAP
emissions, on the other hand, we look at the inherent variability of
the control technology used by the best-controlled source in the
subcategory. These approaches, respectively, represent the most
reasonable way to estimate performance for purposes of establishing
MACT floors for new units, given the data available.
    For fuel dependent HAP emissions (mercury and HCl), we calculated
the variability factor by looking at data on HAP variability in fuel
obtained through our information collection request. We derived the
fuel dependent variability factor by dividing the highest observed HAP
concentration by the lowest observed HAP concentration from the fuel
analyses from the best-controlled source. Once we calculated the fuel
dependent variability factors, we applied these factors to the average
measured emissions performance of the best controlled similar source to
derive the MACT floor level of control. This approach reasonably
estimates the best source's level of emissions, adjusted for
unavoidable variation in fuel characteristics which have a direct
impact on emissions.
1. Determination of MACT for the Fuel-Related HAP
    In developing the MACT floor for the fuel-related HAP (PM, HCl, and
mercury), as described earlier, we are using PM as a surrogate for non-
mercury metallic HAP and HCl as a surrogate for the acid gases. Table 5
presents for each subcategory and fuel-related HAP the average emission
level of the best controlled similar source and the MACT floor (99
percent UPL) which includes the variability across the best controlled
similar source and the long term variability of that source.

                 Table 5--Summary of MACT Floor Results for the Fuel-Related HAP for New Sources
----------------------------------------------------------------------------------------------------------------
                                                                                Mercury Lb/    HCl Lb/
                Subcategory                           Parameter            PM Lb/MMBtu     MMBtu        MMBtu
----------------------------------------------------------------------------------------------------------------
Units designed for Coal firing............  Avg of top performer.........     0.000396     1.18E-07     3.85E-05
                                            99% UPL of top performer          0.000928     3.89E-07     5.21E-05
                                             (test runs).
Units designed for Biomass firing.........  Avg of top performer.........      0.00216     9.73E-08     7.85E-04
                                            99% UPL of top performer           0.00711     1.86E-07     3.07E-03
                                             (test runs).
Units designed for Liquid Fuel firing.....  Avg of top performer.........     0.000511     5.87E-08     3.99E-04
                                            99% UPL of top performer           0.00154     2.47E-07     9.80E-04
                                             (test runs).
Units designed for other gas firing.......  Avg of top performer.........      0.00042     8.25E-08     1.70E-06
                                            99% UPL of top performer            0.0024     1.86E-07     2.50E-06
                                             (test runs).
----------------------------------------------------------------------------------------------------------------

2. Determination of MACT for Organic HAP
    In developing the MACT floor for organic HAP, as described earlier,
we are using CO as a surrogate for non-dioxin organic HAP. Table 6
presents for each subcategory and CO and D/F the average emission level
of the best controlled similar source and the MACT floor (99 percent
UPL) which includes the variability across the best controlled similar
source and the long term variability of that source.

                   Table 6--Summary of MACT Floor Results for the Organic HAP for New Sources
----------------------------------------------------------------------------------------------------------------
                                                                                Dioxin/Furan
                                                                                CO (ppm @ 3    (TEQ) (ng/dscm @
                 Subcategory                             Parameter             percent oxygen)      7 percent
                                                                                oxygen)
----------------------------------------------------------------------------------------------------------------
Stoker--Coal................................  Avg of top performer..........              4.29          1.52E-03
                                              99% UPL of top performer (test              6.53          2.82E-03
                                               runs).
Fluidized Bed--Coal.........................  Avg of top performer..........              8.26          9.05E-06
                                              99% UPL of top performer (test             *39.9          2.54E-05
                                               runs).
PC--Coal....................................  Avg of top performer..........              25.0          1.04E-03
                                              99% UPL of top performer (test             *97.5          1.47E-03
                                               runs).
Stoker--Biomass.............................  Avg of top performer..........               920          1.52E-05
                                              99% UPL of top performer (test             *3730          4.86E-05
                                               runs).
Fluidized Bed--Biomass......................  Avg of top performer..........              25.8          2.27E-03
                                              99% UPL of top performer (test              34.2          6.48E-03
                                               runs).
Suspension Burner/Dutch Oven................  Avg of top performer..........               352          9.52E-03
                                              99% UPL of top performer (test             *1050          2.79E-02
                                               runs).
Fuel Cell--Biomass..........................  Avg of top performer..........               110          2.42E-04

                                              99% UPL of top performer (test              *264          4.17E-04
                                               runs).
Units designed for Liquid fuel firing.......  Avg of top performer..........             0.125          1.09E-03
                                              99% UPL of top performer (test             0.125          1.52E-03
                                               runs).
Units designed for other gases firing.......  Avg of top performer..........            0.0129          2.67E-03
                                              99% UPL of top performer (test            0.0129          8.28E-03
                                               runs).
----------------------------------------------------------------------------------------------------------------
* Value is higher than existing floor limit in the same subcategory. Therefore defaulted to existing floor limit
  for the same subcategory.

    For organic HAP, as previously discussed above for the fuel-
related, 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. Here, we know that CO (as a
surrogate for non-dioxin organic HAP) emissions does not vary
significantly over the operating range of the unit. Thus, we have not
added any additional operational variability to account for operation
at lower capacity rates.
    We are proposing a work practice standard under section 112(h) that
would require an annual tune-up for new boilers and process heaters
combusting natural gas or refinery gas. These boilers and process
heaters are units included in the Gas 1 and metal processing furnace
subcategories. We are specifically seeking comment on whether the
application of measurement methodology to sources in this subcategory
is impracticable due to technological or economic limitations, as
specified in section 112(h)(2)(B).
    This proposal for new boilers and process heaters combusting
natural gas or refinery gas is based on the same reasons discussed
previously for existing boilers and process heaters combusting natural
gas or refinery gas. That is, we believe that proposing emission
standards for new gas-fired boilers and process heaters that result in
the need to employ the same emission control system as needed for the
other fuel types would have the negative benefit of providing a
disincentive for switching to gas as a control technique (and a
pollution prevention technique) for boilers and process heaters in the
other fuel subcategories. In addition, emission limits on gas-fired
boilers and process heaters may have the negative benefit of providing
an incentive for a facility to switch from gas (considered a ``clean''
fuel) to a ``dirtier'' but cheaper fuel (i.e., coal). It would be
inconsistent with the emissions reductions goals of the CAA, and of
section 112 in particular, to adopt requirements that would result in
an overall increase in HAP emissions. We are soliciting comment on the
extent to which new facilities would be expected to switch away from
natural gas to a ``dirtier'' fuel if emissions limits for new such
facilities are adopted.
    Thus, a work practice, as discussed above for existing boilers and
process heaters combusting natural gas or refinery gas, is being
proposed to limit the emission of HAP for new natural gas-fired and
refinery gas-fired boilers and process heaters.
    We request comments on whether the emission limits listed in Table
7 of this preamble for new units in the Gas 1 and Metal Process Furnace
subcategories should be promulgated. Comments should include detailed
information regarding why emission limits for these gas-fired boilers
and process heaters are appropriate.

                        Table 7--Summary of MACT Floor Results for New Units in the Gas 1 and Metal Process Furnace Subcategories
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Dioxin/Furan
                                                                                CO (ppm @ 3     (Total TEQ)
                Subcategory                           Parameter             PM Lb/MMBtu     Mercury Lb/    HCl LB/MMBtu       percent      (ng/dscm @ 7
                                                                                MMBtu                          oxygen)         percent
                                                                                oxygen)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Units designed for NG/RG firing...........  Avg of top performer........         0.00013         9.4E-08         7.3E-05               5          0.0026
                                            99% UPL of top (test runs) =          0.0005         2.0E-07          0.0002              20            0.01
Metal Process Furnaces....................  Avg of top performer........          0.0065         3.3E-08         8.6E-05             0.5          0.0026
                                            99% UPL of top (test runs) =            0.02         2.0E-07          0.0002               2           0.004
--------------------------------------------------------------------------------------------------------------------------------------------------------

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

    The MACT floor level of control for new units 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.
    Fuel switching to natural gas is a potential regulatory option
beyond the new source floor level of control that would reduce HAP
emissions from non-gas-fired units. However, based on current trends
within the industry, EPA projects that the majority of new boilers and
process heaters will be built to fire natural gas as opposed to solid
and liquid fuels such that the overall emissions reductions associated
with this option would be minimal. In addition, natural gas supplies
are not available in some areas, and supplies to industrial customers
can be limited during periods when natural gas demand exceeds supply.
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.\14\
Nonair quality health, environmental impacts, and energy effects were
not significant factors. No beyond-the-floor options for gas-fired
boilers were identified.
---------------------------------------------------------------------------

    \14\ Memorandum ``Development (2010) of Fuel Switching Costs and
Emission Reductions for Industrial, Commercial, and Institutional
Boilers and Process Heaters National Emission Standards for
Hazardous Air Pollutants,'' April 2010.
---------------------------------------------------------------------------

    An energy assessment is a beyond-the-floor standard being proposed
for existing facilities. However, we are not proposing it as a beyond-
the-floor option for new major source facilities since we believe it
would not be cost effective because most projected new boilers or
process heaters will be installed at existing major source facility
which would have already conducted an energy assessment as required by
this proposed rule. We also believe that any new greenfield major
source facility having boilers or process heaters will be designed to
operate with energy efficiency.
    Based on the analysis discussed above, EPA decided to not go beyond
the MACT floor level of control for new sources in this proposed rule.
A detailed description of the beyond-the-floor consideration is in the
memorandum ``Methodology for Estimating Cost and Emissions Impacts for
Industrial, Commercial, Institutional Boilers and Process Heaters
National Emission Standards for Hazardous Air Pollutants'' in the
docket.

J. Consideration of whether to set standards for HCl and other acid
gases under section 112(d)(4)

    We are proposing to set a conventional MACT standard for HCl and,
for the reasons explained elsewhere in today's notice, 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 section 112(d)(4) for HCl and each of the other relevant HAP acid
gases: Chlorine (Cl2), hydrogen fluoride (HF), and hydrogen
cyanide (HCN) \15\ (since if it were regulated under section 112(d)(4),
HCl may no longer be the appropriate surrogate for these other
HAPs).\16\ This section sets forth the requirements of 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 112(d)(4) and solicitation of comments,
and explains how this case relates to prior decisions EPA has made
under section 112(d)(4) with respect to HCl.
---------------------------------------------------------------------------

    \15\ Before considering whether to exercise her discretion under
section 112(d)(4) for a particular pollutant, the Administrator must
first conclude that a health threshold has been established for the
pollutant.
    \16\ HCl 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., HCN) 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, 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, 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 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.
    The legislative history of section 112(d)(4) indicates that
Congress did not intend for this provision to provide a mechanism for
EPA to delay issuance of emission standards for sources of HAPs.
Finally, the legislative history also indicates that a health-based
emission limit under section 112(d)(4) should be set at the level at
which no observable effects occur, with an ample margin of safety. S.
Rep. 101-228 at 171-72.
    It is clear the Administrator may exercise her discretionary
authority under 112(d)(4) only with respect to pollutants with an
health threshold. Where there is an established threshold, the
Administrator interprets 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 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
HAPs 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 via the MACT standard. Each of these factors is
directly relevant to the health and environmental outcomes at which
section 112 of the Clean Air Act 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 section
112(d)(4) in a handful of prior actions setting emissions standards for
other major source categories, including the emissions standards issued
in 2004 for commercial and industrial boilers and process heaters,
which were vacated on other grounds by the U.S. Court of Appeals for
the D.C. Circuit. In both the Pulp and Paper MACT, 63 FR at 18765
(April 15, 1998), and Lime Manufacturing MACT, 67 FR at 78054 (December
20, 2002), EPA invoked 112(d)(4) for HCl emissions for discrete units
within the facility. In those actions, EPA concluded that HCl had an
established health threshold (in those cases it was interpreted as the
reference concentration for chronic effects, or RfC) and 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 section 112(d)(4) for HCl
under the circumstances of those actions. 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 a more recent action, EPA decided not to propose a
health-based emission standard for HCl

emissions under section 112(d)(4) for Portland Cement facilities, 74 FR
at 21154 (May 6, 2009). EPA has never implemented a NESHAP that used
section 112(d)(4) with respect to HF, Cl2 or HCN.\17\
---------------------------------------------------------------------------

    \17\ EPA has not classified HF, chlorine gas, or HCN with
respect to carcinogenicity. However, at this time the Agency is not
aware of any data that would suggest any of these HAPs are
carcinogens.
---------------------------------------------------------------------------

    Since any emission standard under 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. 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 reference
concentration (RfC) for the inhalation of HCl of 20 [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 \18\) 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,\19\ 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 HAPs or
to a combination of HAPs and criteria pollutants. As the RfC
calculation focused on health effects, it did not take into account the
potential environmental impacts of HCl.
---------------------------------------------------------------------------

    \18\ ``Sensitive subgroups'' may refer to particular life
stages, such as children or the elderly, or to those with particular
medical conditions, such as asthmatics.
    \19\ California EPA considered acute toxicity and established a
1-hour reference exposure level (REL) of 2.1 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 know 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 (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). However, we currently lack information
on the peak short-term emissions of HCl from boilers, 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;
    4. We are aware of no studies explicitly addressing the toxicity of
mixtures of HCl with other respiratory irritants. However, many of the
other HAPs (and criteria pollutants) emitted by boilers 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 boilers can be located among 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 section 112(d)(4). The
legislative history states that employing a section 112(d)(4) standard
rather than a conventional MACT standard ``shall not result in adverse
environmental effects which would otherwise be reduced or eliminated.''
S. Rep. 101-228 at 171. 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
nitrogen oxides are causing aquatic and/or terrestrial acidification,
with accompanying ecological impacts, the deposition of hydrochloric
acid could exacerbate these impacts. Being mindful of the legislative
history, it is appropriate to consider potential adverse environmental
effects in addition to adverse health effects when setting an emission
standard for HCl under section 112(d)(4).
    Because the statute requires an ample margin of safety, it would be
reasonable to set any section 112(d)(4) emission standard for a
pollutant with a health threshold at a level that at least assures
that, for the sources in the controlled category or subcategory,
persons exposed to emissions of the pollutant would not experience the
adverse health effects on which the threshold is based. 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. Public
comments are invited on our information and conclusion.
    When Congress established the technology-based MACT program in the
1990 Clean Air Act Amendments, it recognized the challenges involved in
evaluating health risk. Determining an emission standard that will
protect the public health with an ample margin of safety is complex, in
part because of the limited data available on cumulative impacts. In
order to assess the feasibility of health-based standards in this rule,
the agency believes it would need additional facility-specific
emissions information. Such information would enable us to develop
model plants for the eleven subcategories considered in the proposed
rule and allow us to conduct the dispersion modeling necessary to
establish health-based emission limits. These limits would need to be
established to ensure that exposure is below the health threshold for
sources in the subcategory, and account for the possibility of multiple
exposures from co-located sources as well as potential short-term
increases in emissions for these sources and their short-term impacts.
Currently, the Agency has very limited information on facility-specific
emissions, plant configurations, and overall fence-line characteristics
for this large and diverse source category. This information is a
precondition to establishing health-based emission standards that
provide an ample margin of safety. To this end, the Agency is
requesting information on these factors from the regulated community
and others to allow us to evaluate the appropriateness and viability of
health-based emission limits.
    EPA specifically requests comment on the following issues.
Additional information on these issues is important to implement
section 112(d)(4) in a reasonable and appropriate manner, if we were to
establish emissions standards under that provision. First,

EPA requests comment on whether it would be appropriate to establish
section 112(d)(4) standards for each acid gas described above, or
whether EPA could set a single 112(d)(4) standard for one of the acid
gases as a surrogate for the other acid gases. Commenters who believe a
surrogate would be appropriate should also address the mechanism that
should be used to determine the appropriate surrogate. In order to set
individual standards under section 112(d)(4) for each acid gas, we
would need to be able to conclude that each has an appropriate health
threshold, that there is no scientific evidence that they are
carcinogenic, and that the emission standard for each uses the best
available science to consider the possibility of toxicologic
interactions with the other emitted gases. Alternatively, if we were to
establish a health-based emission standard for one of the acid gases as
a surrogate for the others, in addition to the above considerations, we
would need to demonstrate, based on a knowledge of the effectiveness of
scrubbers for controlling each of the acid gases, that the surrogate
emission standard effectively ensures that ambient levels of each of
the other acid gases do not exceed their respective chronic health
thresholds.
    EPA also solicits comments on whether there would be an additive
effect if individual section 112(d)(4) standards are established for
each acid gas, and if so, how we would simulate that effect. Individual
acid gas standards under section 112(d)(4) would likely be established
using the hazard quotient (HQ) approach, under which we would develop
the ratio of the maximum ambient level to the chronic threshold.
However, this approach would not by itself account for potential
toxicologic interactions. Since all of the acid gases are respiratory
irritants, one way to account for potential toxicologic interactions of
these pollutants would be the use of the hazard index (HI) approach, as
described in EPA's ``Guideline for the Health Risk Assessment of
Chemical Mixtures.'' EPA requests comment on that approach, and on
whether there are any other approaches to address such additive
effects.
    Additionally, EPA requests comment on whether we should consider
the affected sources (boilers) by themselves, or whether we should
consider all HAP emissions at the facility when developing a 112(d)(4)
standard. Given that section 112(d)(4) requires an ``ample margin of
safety,'' EPA believes it should consider all reasonable circumstances
in order to ensure such a margin. Since boilers are, in many cases,
located at industrial sites with significant additional sources of HAP
(e.g., petroleum refineries, furniture manufacturers, etc.), EPA
requests comment on how we should consider the potential interactions
of acid gases with other emitted respiratory irritants at these
locations if we were to develop emission limits under section
112(d)(4). Commenters are requested to provide any actual data that is
available to make this type of demonstration. If no data are available,
we request comment on whether such a demonstration could be made using
a bounding calculation.
    EPA also requests comment on whether we should consider HAP
emissions from neighboring facilities, and, if so, what the geographic
scope of such consideration should be (e.g., 1 km, 3 km, etc.). We note
that consideration of emissions from nearby facilities is a more
difficult task than consideration of facility-wide emissions, since it
requires information on all potential HAP emissions near all of the
locations with boilers. Therefore, we request comment on whether such
emissions should be considered in setting section 112(d)(4) emissions
standards, and if so, how they should be considered. For example, the
consideration could be limited in geographic scope (e.g., a radius of 3
km), or could be based on ``average'' or ``high-end'' ambient levels of
respiratory irritants seen in recent monitoring data or modeled
estimates, since site-specific data might not be available on all
respiratory irritants.
    Further, EPA requests comment on how to appropriately simulate all
reasonable facility/exposure situations (e.g., using worst-case
facility emissions coupled with worst-case population proximity,
average emissions and population, or 90th percentile emissions and
population). Such a simulation could be based on a sequential
examination of the facilities with the highest-emitting boilers on-site
using site-specific data, or it could use screening or bounding
methodologies with high-end or worst-case exposure assumptions to
remove facilities from a more site-specific examination. We request
comment on these and other approaches.
    Finally, we considered the fact that setting conventional MACT
standards for HCl as well as PM (as a surrogate for metals including
manganese) would result in significant reductions in emissions of other
pollutants, most notably SO2, non-condensable PM, and other
non-HAP acid gases (e.g., hydrogen bromide) and would likely also
result in additional reductions in emissions of mercury and other HAP
metals (e.g., selenium). The additional reductions of SO2
alone attributable to the proposed MACT standard for HCl are estimated
to be 340,000 tons per year in the third year following promulgation of
the proposed HCl standard. These are substantial reductions with
substantial public health benefits. Although MACT standards may
directly address only HAPs, not criteria pollutants, Congress did
recognize, in the legislative history to section 112(d)(4), that MACT
standards would have the collateral benefit of controlling criteria
pollutants as well and viewed this as an important benefit of the air
toxics program.\20\ Therefore, even where EPA concludes a HAP has a
health threshold, the Agency may consider such benefits as a factor in
determining whether to exercise its discretion under section 112(d)(4).
---------------------------------------------------------------------------

    \20\ See S. Rep. No. 101-228, 101st Cong. 1st sess. At 172
---------------------------------------------------------------------------

    Given the limitations of the currently available information (i.e.,
the HAP mix where boilers are located, and the cumulative health
impacts from co-located sources), the environmental effects of HCl, and
the significant co-benefits of setting a conventional MACT standard for
HCl, the Administrator is proposing not to exercise her discretion to
use section 112(d)(4).
    This conclusion is not contrary to EPA's prior decisions where we
found it appropriate to exercise the discretion to invoke the authority
in section 112(d)(4) for HCl, since the circumstances in this case
differ from previous considerations. Boilers and process heaters differ
from the other source categories for which EPA has exercised its
authority under section 112(d)(4) in ways that affect consideration of
any health threshold for HCl. Commercial and industrial boilers and
process heaters are much more likely to be co-located with multiple
other sources of HAPs than are pulp and paper mills and lime
manufacturing facilities. In addition, boilers and process heaters are
often located at facilities in heavily populated urban areas where many
other sources of HAPs 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.
    Given the particular complexities of this source category (the
location of boilers and process heaters near other significant sources
of HAP emissions

and the use of HCl as a surrogate for other HAPs), we solicit comment
on all of the conclusions in this section, including the way the agency
has used 112(d)(4) previously, and in particular whether it would be
feasible and appropriate to establish such a standard and, if so, the
methodology by which it could be established.

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 requirement of this proposed rule. These
requirements are described in detail in sections IV.K to IV.N. 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 facilities that must implement
them.
    We are proposing that compliance with the emission limits for PM,
HCl, mercury, CO, and D/F be demonstrated by an initial performance
test. To ensure continuous compliance with the proposed PM, HCl, and
mercury emission limits, this proposed rule would require continuous
parameter monitoring of control devices and recordkeeping.
Additionally, this proposed rule would require annual performance tests
to ensure, on an ongoing basis, that the air pollution control device
is operating properly and its performance has not deteriorated. If
initial compliance with the mercury and/or HCl emission limits are
demonstrated by a fuel analysis performance test, this proposed rule
would require fuel analyses monthly, with compliance determined based
on an annual average.
    We evaluated the feasibility and cost of applying PM CEMS to
boilers and process heaters. CEMS have been used in Europe to monitor
PM emissions from a variety of industrial sources. Several electric
utility companies in the United States 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 Performance
Specifications (PS) for PM CEMS (69 FR 1786, January 12, 2004). PS for
PM CEMS are established under PS-11 in appendix B to 40 CFR part 60 for
evaluating the acceptability of a PM CEM used for determining
compliance with the emission standards on a continuous basis. For PM
CEM monitoring, capital costs were estimated to be $88,000 per unit and
annualized costs were estimated to be $33,000 per unit. We determined
that requiring PM CEMS for units with heat input capacity greater or
equal to 250 MMBtu/hr and combusting either coal, biomass, or oil is a
reasonable monitoring option. We are requesting comment on the
application of PM CEMS to boilers and process heaters, and the use of
data from such systems for compliance determinations under this
proposed rule.
    We reviewed cost information for CO CEMS to make the determination
on whether to require CO CEMS or conducting annual CO testing to
demonstrate continuous compliance with the CO emission limit. In
evaluating the available cost information, we determined that requiring
CO CEMS for units with heat input capacities greater or equal to 100
MMBtu/hr is reasonable. This proposed rule would require units with
heat input capacities less than 100 MMBtu/hr to conduct initial and
annual performance (stack) tests.
    The majority of test methods that this proposed rule would require
for the performance stack tests have been required under many other EPA
standards. The only applicable voluntary consensus standard identified
is ASTM Method D6784-02 (Ontario Hydro). The majority of emissions
tests upon which the proposed emission limits are based were conducted
using these test methods.
    When a performance test is conducted, we are proposing that
parameter operating limits be determined during the tests. Performance
tests to demonstrate compliance with any applicable emission limits are
either stack tests or fuel analysis or a combination of both.
    To ensure continuous compliance with the proposed emission limits
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 limits
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 opacity monitoring except for wet scrubbers; pH,
pressure drop and liquid flowrate for wet scrubbers; and sorbent
injection rate for dry scrubbers. You must also install a bag leak
detection system for fabric filters. If you cannot monitor opacity for
control systems with an ESP then you must monitor the secondary current
and voltage or total power input for the ESP. 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 source elected to demonstrate compliance with the HCl or
mercury 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 or
mercury 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 limits, 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, mercury, sample collection,
and sample

preparation are included in this proposed rule.
    If you 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.
    For boilers and process heaters with heat input capacities greater
or equal to 100 MMBtu/hr, we are proposing that CO be continuously
monitored to demonstrate that average CO emissions, on a 30-day rolling
average, are at or below the proposed CO limit.
    For boilers and process heaters with heat input capacities between
10 and 100 MMBtu/hr, we are proposing that a performance stack test of
CO emissions be conducted to demonstrate compliance with the CO
emission limit.

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 the 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 sources and could only be used between boilers and process
heaters in the same subcategory at a particular affected source. Also,
owners or operators of existing sources subject to the Industrial
Boiler NSPS (40 CFR part 60, subparts Db and Dc) 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.
    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 boiler and process
heater NESHAP. Further, emissions averaging would not be permitted
between two or more different affected sources. Finally, new 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, the 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 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 sources
because they can be designed and constructed with compliance in mind.
    With concern about the equivalency of emissions reductions from
averaging and non-averaging in mind, we are also proposing under the
emission averaging provision caps on the current emissions from each of
the sources in the averaging group. The emissions for each unit in the
averaging group would be capped at the emission level being achieved on
the effective date of the final rule. These caps would ensure that
emissions do not increase above the emission levels that sources
currently are designed, operated, and maintained to achieve. In the
absence of performance tests, in documenting these

caps, these sources will document the type, design, and operating
specification of control devices installed on the effective date of the
final rule to ensure that existing controls are not removed or operated
less efficiently. By including this provision in this proposed rule, we
would further ensure that emission averaging results in environmental
benefits equivalent to or better than without emission averaging.
    In addition, we are proposing that a discount factor of ten percent
would be applied when emissions averaging is used. This discount factor
will further ensure that averaging will be at least as stringent as the
MACT floor limits in the absence of averaging. The EPA is soliciting
comment on use of a discount factor and whether ten percent is the
appropriate discount factor. 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 rational for the HON emissions
averaging provisions were provided in the preamble to the final HON (59
FR 19425, April 22, 1994).

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

    Section 112 of the CAA 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 are allowed 3 years to comply with
the final rule. This is the maximum period allowed by the CAA. 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 boilers, as well as obtain permits for the use of add-on
controls.

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 subpart DDDDD. We evaluated the
General Provisions requirements and included those we determined to be
the minimum notification, recordkeeping, and reporting necessary to
ensure compliance with, and effective enforcement of, this proposed
rule.
    We are also requiring that you keep daily records of the total fuel
use by each affected source, subject to an emission limit or work
practice standard, along with a description of the fuel, the total fuel
usage amounts and units of measure, and information on the supplier and
original source of the fuel. This information is necessary to ensure
that the affected source is complying with the emission limits from the
correct subcategory.
    We would require additional recordkeeping if you chose to comply
with the chlorine or mercury fuel input option. You would need to keep
records of the calculations and supporting information used to develop
the chlorine or mercury 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 3 years of your operating permit,
you will need to obtain a revised permit to incorporate this proposed
rule. If you are in the last 2 years of your operating permit, you will
need to incorporate this proposed rule into the next renewal of your
permit.

P. Alternate Standard for Consideration

    As discussed above, EPA is proposing a definition of non-hazardous
solid waste under RCRA in a concurrent notice. The proposed CAA section
112(d) standards for boilers and process heaters were developed
considering that proposed definition of solid waste. Therefore, the
emission limits presented in Tables 1 through 5 above are based on
subcategories established considering sources that are ICI boilers and
process heaters under the proposed definition of solid waste under
RCRA. However, the RCRA proposal also identifies and solicits comment
on an alternative approach for defining solid waste, under which more
units would be considered solid waste incineration units than under the
proposed definition. As such, the alternative approach for defining
solid waste under RCRA would result in a different, smaller population
of units being covered by Boiler MACT. Consistent with EPA's
solicitation of comment on an alternative proposed definition of solid
waste under RCRA, we calculated MACT floors using emission rates for
units that would be ICI boilers and process heaters under that
alternative definition, using the same statistical procedures that were
used to calculate the standards that are being proposed. Table 6
reflects that calculation of MACT floor limits for the existing source
subcategories that would be changed by the alternative definition of
solid waste identified in the concurrent RCRA proposal, compared to the
proposed definition of solid waste in that proposal. The MACT floor
limits for the remaining existing source subcategories (Gas 1, Gas 2,
and Liquid) would not change under the alternative definition of solid
waste on which EPA is soliciting comment in the concurrent RCRA
proposal, and are therefore not included in Table 8 because the MACT
floor limits for those subcategories would be the same under the
alternative definition of solid waste as under the proposed definition.

  Table 8--Existing MACT Floor Limits Using The ``Alternative Approach'' Under Consideration and Comment in the
                                         Concurrently Proposed RCRA Rule
                                   [Pounds per million British thermal units]
----------------------------------------------------------------------------------------------------------------
                                                                                Dioxins/
                                   Particulate      Hydrogen                     Carbon monoxide   Furans (total
          Subcategory              matter (PM)   chloride (HCl)   Mercury (Hg)    (CO) (ppm @ 3%  TEQ) (ng/dscm)
                                                                                oxygen)          @ 7% O2
----------------------------------------------------------------------------------------------------------------
Existing--Coal Stoker..........            0.03            0.02         4.0E-06               40         0.003
Existing--Coal Fluidized Bed...            0.03            0.02         4.0E-06               50         0.008
Existing--Pulverized Coal......            0.03            0.02         4.0E-06               90         0.004

Existing--Biomass Stoker.......            0.02            0.03         5.0E-07              180         0.00005
Existing--Biomass Fluidized Bed            0.02            0.03         5.0E-07           10,650         0.1
Existing--Biomass Suspension               0.02            0.03         5.0E-07            1,060         0.3
 Burner/Dutch Oven.............
Existing--Biomass Fuel Cells...            0.02            0.03         5.0E-07              460         0.02
----------------------------------------------------------------------------------------------------------------

    Comparing the emissions limits in Table 1 (based on the proposed
definition of solid waste) with those in Table 8 (based on the
alternative definition of solid waste), the MACT emission limits for PM
and mercury for the biomass subcategories would be less stringent if
they are based on the alternative definition of solid waste while the
HCl emission limits for the coal and biomass subcategories would be
more stringent if they are based on the alternative definition.
    The potential emissions reductions if the MACT floor limits are
calculated based on the alternative definition of solid waste would be
generally lower than the potential emissions reductions for MACT floors
based on the proposed definition of solid waste, because 280 fewer
boilers and process heaters would be subject to the boiler and process
heater MACT standards under the alternative definition. These units
would instead be considered CISWI units under the alternative
definition of solid waste. For example, mercury emissions reduction
would be 7 tons per year based on the alternative definition of solid
waste (compared to 8 tons per year based on the proposed definition)
and HCl emissions reduction would be 5,100 tons per year based on the
alternative definition (compared to 37,000 tons per year based on the
proposed definition). Most (181) of the 280 units that would be
considered CISWI units under the alternative definition of solid waste
proposed under RCRA are biomass-fired boilers or process heaters, with
the others being in the coal and liquid fuel subcategories.
    The resulting total national cost impact for existing boilers and
process heaters of the proposed emission limits based on the
alternative definition of solid waste would be 8.0 billion dollars in
capital expenditures and 2.4 billion dollars per year in total annual
costs. This compares to $9.5 billion in capital costs and $2.9 billion
in annual costs under the proposed definition of solid waste in the
RCRA proposed rule. Table 9 of this preamble shows the capital and
annual cost impacts for each subcategory under the alternative
definition of solid waste. Costs include testing and monitoring costs,
but not recordkeeping and reporting costs.

 Table 9--Summary of Capital and Annual Costs for Existing Sources Under the Alternative Solid Waste Definition
----------------------------------------------------------------------------------------------------------------
                                                                 Estimated/ projected     Capital     Annualized
               Source                       Subcategory           number of affected       costs         cost
                                                                        units             (10\6\$)   (10\6\$/yr)
----------------------------------------------------------------------------------------------------------------
Existing Units......................  Coal units.............  525....................        3,861        1,508
                                      Biomass units..........  239....................        1,250          317
                                      Liquid units...........  791....................        1,352          417
                                      Gas (NG/RG) units......  11,524.................           75          259
                                      Gas (other) units......  196....................        1,476          434
Energy Assessment...................  ALL....................  1,551 facilities.......  ...........         24.9
----------------------------------------------------------------------------------------------------------------

    A discussion of the methodology used to estimate cost impacts is
presented in ``Methodology and Results of Estimating the Cost of
Complying with the Industrial, Commercial, and Institutional Boiler and
Process Heater NESHAP (2010)'' in the Docket.
    We are soliciting public comments on the emission limits listed in
Table 6 of this preamble, consistent with EPA's solicitation of
comments on the alternative definition of solid waste concurrently
proposed under RCRA. As explained above, the MACT floor limits proposed
today are based on the proposed definition of solid waste under RCRA.
However, because EPA is seeking comment on an alternative definition of
solid waste under RCRA, the Agency believes it is necessary to also
solicit comment on what the MACT floor limits would be based on the
universe of sources that would be subject to the boiler and process
heater MACT under that alternative definition.

V. Impacts of the Proposed Rule

A. What are the air impacts?

    Table 10 of this preamble illustrates, for each basic fuel
subcategory, the emissions reductions achieved by the proposed rule
(i.e., the difference in emissions between a boiler or process heater
controlled to the floor level of control and boilers or process heaters
at the current baseline) for new and existing sources. Nationwide
emissions of selected HAP (i.e., HCl, HF, mercury, metals, and VOC)
will be reduced by 43,000 tons per year for existing units and 15 tons
per year for new units. Emissions of HCl will be reduced by 37,000 tons
per year for existing units and 9 tons per year for new units.
Emissions of mercury will be reduced by 8 tons per year for existing
units and 2.6 pounds per year for new units. Emissions of filterable PM
will be reduced by 50,100 tons per year for existing units and 130 tons
per year for new units. Emissions of non-mercury

metals (i.e., antimony, arsenic, beryllium, cadmium, chromium, cobalt,
lead, manganese, nickel, and selenium) will be reduced by 3,200 tons
per year for existing units and will be reduced by 0.6 ton per year for
new units. In addition, emissions of SO2 are estimated to be
reduced by 340,000 tons per year for existing sources and 500 tons per
year for new sources. Emissions of dioxin/furans, on a total mass
basis, will be reduced by 722 grams per year for existing units and 1
gram per year for new units. A discussion of the methodology used to
estimate emissions and emissions reductions is presented in
``Estimation of Baseline Emissions and Emissions Reductions for
Industrial, Commercial, and Institutional Boilers and Process Heaters
(2010)'' in the docket.

                     Table 10--Summary of Emissions Reductions for Existing and New Sources
                                                    [Tons/yr]
----------------------------------------------------------------------------------------------------------------
                                                                               Non
            Source                Subcategory        HCl           PM        mercury      Mercury        VOC
                                                                            metals \a\
----------------------------------------------------------------------------------------------------------------
Existing Units...............  Coal units......       35,450       17,000          770          7.1          490
                               Biomass units...          520       22,500          230          0.2          760
                               Liquid units....          840       10,400        2,200      0.00005          290
                               Gas 1 (NG/RG)               9          130          1.2         0.01           72
                                units.
                               Gas 2 (other)             220            0            0          0.2          170
                                units.
New Units....................  Coal units......            0            0            0            0            0
                               Biomass units...            0            0            0            0            0
                               Liquid units....            9          130          0.6       0.0007            3
                               Gas 1 units.....         0.01          0.1        0.001     0.000008         0.01
                               Gas 2 units.....            1            4         0.01       0.0006            1
----------------------------------------------------------------------------------------------------------------
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.

B. What are the water and solid waste impacts?

    The EPA estimated the additional water usage that would result from
installing wet scrubbers to meet the emission limits for HCl would be
2,400 million gallons per year for existing sources and 200,000 gallons
per year for new sources. In addition to the increased water usage, an
additional 730 million gallons per year of wastewater would be produced
for existing sources and 140,000 gallons per year for new sources. The
annual costs of treating the additional wastewater are $4.0 million for
existing sources and $774 for new sources. These costs are accounted
for in the control costs estimates.
    The EPA estimated the additional solid waste that would result from
the MACT floor level of control to be 81,000 tons per year for existing
sources and 149,800 tons per year for new sources. Solid waste is
generated from flyash and dust captured in PM and mercury controls as
well as from spent carbon that is injected into exhaust streams or used
to filter gas streams. The costs of handling the additional solid waste
generated are $3.4 million for existing sources and $6.3 million for
new sources. These costs are also accounted for in the control costs
estimates.
    A discussion of the methodology used to estimate impacts is
presented in ``Estimation of Impacts for Industrial, Commercial, and
Institutional Boilers and Process Heaters NESHAP (2010)'' in the
Docket.

C. What are the energy impacts?

    The EPA expects an increase of approximately 2.995 million kilowatt
hours (kWh) in national annual energy usage as a result of the proposed
rule. Of this amount, 2,944 million kWh would be from existing sources
and 11 million kWh are estimated from new sources. The increase results
from the electricity required to operate control devices, such as wet
scrubbers, electrostatic precipitators, and fabric filters which are
expected to be installed to meet the proposed rule. Additionally, the
EPA expects work practice standards such as boilers tune-ups and
combustion controls will improve the efficiency of boilers, resulting
in an estimated fuel savings of 42 trillion BTU each year from existing
sources and an additional 100,000 million BTU each year. This fuel
savings estimate includes only those fuel savings resulting from gas,
liquid, and coal fuels and it is based on the assumption that the work
practice standards will achieve 1 percent improvement in efficiency.

D. What are the control costs?

    To estimate the national cost impacts of the proposed rule for
existing sources, we developed average baseline emission factors for
each fuel type/control device combination based on the emission data
obtained and contained in the Boiler MACT emission database. If a unit
reported emission data, we assigned its unit-specific emission data as
its baseline emissions. For units that did not report emission data, we
assigned the appropriate emission factors to each existing unit in the
inventory database, based on the average emission factors for boilers
with similar fuel, design, and control devices. We then compared each
unit's baseline emission factors to the proposed MACT floor emission
limit to determine if control devices were needed to meet the emission
limits. The control analysis considered fabric filters, carbon bed
adsorbers, and activated carbon injection to be the primary control
devices for mercury control, electrostatic precipitators for units
meeting mercury limits but requiring additional control to meet the PM
limits, wet scrubbers to meet the HCl limits, tune-ups, replacement
burners, and combustion controls for CO and organic HAP control, and
carbon injection for dioxin/furan control. We identified where one
control device could achieve reductions in multiple pollutants, for
example a fabric filter was expected to achieve both PM and mercury
control in order to avoid overestimating the costs. We also included
costs for testing and monitoring requirements contained in the proposed
rule. The resulting total national cost impact of the proposed rule is
9.5 billion dollars in capital expenditures and 3.2 billion dollars per
year in total annual costs. Considering estimated fuel savings
resulting from work practice standards and combustion controls, the
total annualized costs are reduced to 2.9 billion dollars. The total
capital and annual costs include costs for control devices, work
practices, testing and monitoring. Table 11 of this preamble shows the
capital and annual

cost impacts for each subcategory. Costs include testing and monitoring
costs, but not recordkeeping and reporting costs.

                   Table 11--Summary of Capital and Annual Costs for New and Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                                                Annualized
                                                             Estimated/                Testing and  cost (10\6\$/
                                                             projected     Capital     monitoring        yr)
               Source                     Subcategory        number of      costs      annualized   (considering
                                                              affected     (10\6\$)       costs         fuel
                                                               units                   (10\6\$/yr)    savings)
----------------------------------------------------------------------------------------------------------------
Existing Units.....................  Coal units...........          578        4,468         62.4         1,619
                                     Biomass units........          420        2,003         35.5           609
                                     Liquid units.........          826        1,389         27.4           419
                                     Gas (NG/RG) units....       11,532           75          0            (260)
                                     Gas (other) units....          199        1,554         10.4           459
Energy Assessment..................  ALL..................  ...........  ...........  ............           26
New Units..........................  Coal units...........            0            0          0               0
                                     Biomass units........            0            0          0               0
                                     Liquid units.........           11           12          0.5           6.1
                                     Gas (NG/RG) units....           33          0.2          0            0.01
                                     Gas (other) units....            2          5.5          0.14          1.7
----------------------------------------------------------------------------------------------------------------

    Using Department of Energy projections on fuel expenditures, the
number of additional boilers that could be potentially constructed was
estimated. The resulting total national cost impact of the proposed
rule in the 3rd year is 17 million dollars in capital expenditures and
6.2 million dollars per year in total annual costs, when considering a
1 percent fuel savings.
    Potential control device cost savings and increased recordkeeping
and reporting costs associated with the emissions averaging provisions
in the proposed rule are not accounted for in either the capital or
annualized cost estimates.
    A discussion of the methodology used to estimate cost impacts is
presented in ``Methodology and Results of Estimating the Cost of
Complying with the Industrial, Commercial, and Institutional Boiler and
Process Heater NESHAP (2010)'' in the Docket.

E. What are the economic impacts?

    The economic impact analysis (EIA) that is included in the RIA
shows that the expected prices for industrial sectors could be 0.01
percent higher and domestic production may fall by about 0.01 percent.
Because of higher domestic prices imports may rise by 0.01 percent. In
addition, impacts to affected energy markets show that prices may rise
by 0.04 percent.
    Social costs are estimated to also be $2.9 billion in 2008 dollars.
This is estimated to be made up of a $0.8 billion loss in domestic
consumer surplus, a $2.5 billion loss in domestic producer surplus, a
$0.1 billion increase in rest of the world surplus, and a $0.4 billion
in net fuel savings not modeled in a way that can be used to attribute
it to consumers and producers.
    EPA performed a screening analysis for impacts on small entities by
comparing compliance costs to sales/revenues (e.g., sales and revenue
tests). EPA's analysis found the tests were typically higher than 3
percent for small entities included in the screening analysis. EPA has
prepared an Initial Regulatory Flexibility Analysis (IRFA) that
discusses alternative regulatory or policy options that minimize the
rule's small entity impacts. It includes key information about key
results from the Small Business Advocacy Review (SBAR) panel.
    Precise job effect estimates cannot be estimated with certainty.
Morgenstern et al. (2002) identify three economic mechanisms by which
pollution abatement activities can indirectly influence jobs:
     Higher production costs raise market prices, higher prices
reduce consumption, and employment within an industry falls (``demand
effect'');
     Pollution abatement activities require additional labor
services to produce the same level of output (``cost effect''); and
     Post regulation production technologies may be more or
less labor intensive (i.e., more/less labor is required per dollar of
output) (``factor-shift effect'').
    Several empirical studies, including Morgenstern et al. (2002),
suggest the net employment decline is zero or economically small (e.g.,
Cole and Elliot, 2007; Berman and Bui, 2001). However, others show the
question has not been resolved in the literature (Henderson, 1996;
Greenstone, 2002). Morgenstern's paper uses a six-year panel (U.S.
Census data for plant-level prices, inputs (including labor), outputs,
and environmental expenditures) to econometrically estimate the
production technologies and industry-level demand elasticities. Their
identification strategy leverages repeat plant-level observations over
time and uses plant-level and year fixed effects (e.g., plant and time
dummy variables). After estimating their model, Morgenstern show and
compute the change in employment associated with an additional $1
million ($1987) in environmental spending. Their estimates covers four
manufacturing industries (pulp and paper, plastics, petroleum, and
steel) and Morgenstern, et al. present results separately for the cost,
factor shift, and demand effects, as well as the net effect. They also
estimate and report an industry-wide average parameter that combines
the four industry-wide estimates and weighting them by each industry's
share of environmental expenditures.
    EPA has most often estimated employment changes associated with
plant closures due to environmental regulation or changes in output for
the regulated industry (EPA, 1999a; EPA, 2000). This analysis goes
beyond what EPA has typically done in two ways. First, because the
multimarket model provides estimates for changes in output for sectors
not directly regulated, we were able to estimate a more comprehensive
``demand effect.'' Secondly, parameters estimated in the Morgenstern
paper were used to estimate all three effects (``demand,'' ``cost,''
and ``factor shift''). This transfer of results from the Morgenstern
study is uncertain but avoids ignoring the ``cost effect'' and the
``factor-shift effect.''
    We calculated ``demand effect'' employment changes by assuming that
the number of jobs changes proportionally with multi-market model's
simulated output changes. These results were calculated for all

sectors in the EPA model that show a change in output. The total job
losses are estimated to be approximately 6,000.
    We also calculated a similar ``demand effect'' estimate that used
the Morgenstern paper. To do this, we multiplied the point estimate for
the total demand effect (-3.56 jobs per million ($1987) of
environmental compliance expenditure) by the total environmental
compliance expenditures used in the partial equilibrium model. For
example, the job loss estimate is approximately 7,000 jobs (-3.56 x
$3.5 billion x 0.60).\21\
---------------------------------------------------------------------------

    \21\ Since Morgenstern's analysis reports environmental
expenditures in $1987, we make an inflation adjustment the
engineering cost analysis using GDP implicit price deflator (64.76/
108.48) = 0.60).
---------------------------------------------------------------------------

    We also present the results of using the Morgenstern paper to
estimate employment ``cost'' and ``factor-shift'' effects (Table 1).
Although using the Morgenstern parameters to estimate these ``cost''
and ``factor-shift'' employment changes is uncertain, it is helpful to
compare the potential job gains from these effects to the job losses
associated with the ``demand'' effect. Table 1 shows that using the
Morgenstern point estimates of parameters to estimate the ``cost'' and
``factor shift'' employment gains may be greater than the employment
losses using either of the two ways of estimating ``demand'' employment
losses. The 95 percent confidence intervals are shown for all of the
estimates based on the Morgenstern parameters. As shown, at the 95%
confidence level, we cannot be certain if net employment changes are
positive or negative.
    Although the Morgenstern paper provides additional information
about the potential job effects of environmental protection programs,
there are several qualifications EPA considered as part of the
analysis. First, EPA has used the weighted average parameter estimates
for a narrow set of manufacturing industries (pulp and paper, plastics,
petroleum, and steel). Absent other data and estimates, this approach
seems reasonable and the estimates come from a respected peer-reviewed
source. However, EPA acknowledges the proposed rule covers a broader
set of industries not considered in original empirical study. By
transferring the estimates to other industrial sectors, we make the
assumption that estimates are similar in size. In addition, EPA assumes
also that Morgenstern et al.'s estimates derived from the 1979-1991
still applicable for policy taking place in 2013, almost 20 years
later. Second, the multi-market model only considers near term
employment effects in a U.S. economy where production technologies are
fixed. As a result, the modeling system places more emphasis on the
short term ``demand effect'' whereas the Morgenstern paper emphasizes
other important long term responses. For example, positive job gains
associated with ``factor shift effects'' are more plausible when
production choices become more flexible over time and industries can
substitute labor for other production inputs. Third, the Morgenstern
paper estimates rely on sector demand elasticities that are different
from the demand elasticity parameters used in the multi-market model.
As a result, the demand effects are not directly comparable with the
demand effects estimated by the multi-market model. Fourth, Morgenstern
identifies the industry average as economically and statistically
insignificant effect (i.e., the point estimates are small, measured
imprecisely, and not distinguishable from zero.) EPA acknowledges this
fact and has reported the 95 percent confidence intervals in Table 1.
Fifth, Morgenstern's methodology assumes large plants bear most of the
regulatory costs. By transferring the estimates, EPA assumes a similar
distribution of regulatory costs by plant size and that the regulatory
burden does not disproportionately fall on smaller plants.

                   Table 12--Employment Changes: 2013
------------------------------------------------------------------------
                     Estimation method                       1,000 Jobs
------------------------------------------------------------------------
Partial equilibrium model (multiple markets) (demand                 -5
 effect only).............................................
Literature-based estimate (net effect [A + B + C below])..           +3
                                                             (-6 to +12)
    A. Literature-based estimate: Demand effect...........           -7
                                                             (-15 to +1)
    B. Literature-based estimate: Cost effect.............           +5
                                                              (+2 to +8)
    C. Literature-based estimate: Factor shift effect.....           +5
                                                              (0 to +10)
------------------------------------------------------------------------