emissions from coal-fired units. There are very few recent emissions
test data available showing the potential control of these metallic HAP
from coal-fired EGUs.
    EPA identified the units with the newest PM controls installed as
the units to test for non-Hg metal HAP. EPA believed that these units
represent those units having to comply with the most recent, and,
therefore, likely most stringent, emission limits for PM. EPA believes
units complying with stringent PM limits represent the top performers
with regard to non-Hg metallic HAP emissions, even for those HAP that
may at times form in other than the particulate phase. The units
selected also included a number with ACI installed. The 170 units with
the newest PM controls installed were selected and were required to
test after that specific PM control (or at the stack if the PM control
device is not shared with one or more other units); specifics of the
required testing may be found in Docket entry EPA-HQ-OAR-2009-0234-
0062.
    The capture of Hg is dependent on several factors including the
chloride content of the coal, the sulfur content of the coal, the
amount of unburned carbon present in the fly ash, and the flue gas
temperature profile. All of these factors affect the chemical form (the
speciation) of Hg in the flue gas. Mercury may exist as Hg\0\, as
Hg\+2\ (or reactive gaseous Hg, RGM) or as Hgp. Based on
available data, EPA believes that sorbent injection (including ACI) has
the potential to be a very effective technology for controlling Hg
emissions in coal-fired plants, and some units using ACI for Hg control
were among those selected for testing. EPA had no direct stack test
results showing how effectively these ACI-equipped plants reduce their
Hg emissions. The effectiveness of ACI is highly dependent upon the
type of sorbent used (i.e., chemically treated versus conventional AC)
and on the amount injected. Further, previous data-gathering efforts
had shown that FFs are capable of providing highly effective control of
certain species of Hg and, in some cases, as high or higher than that
achieved by ACI (ACI is not always used to achieve maximum reductions
in Hg but, rather, to achieve permit requirements). Thus, testing for
Hg was included with the testing for the non-Hg metallic HAP.
    To be able to assess the impact of the standards (e.g., reduction
in HAP emissions over current conditions), EPA selected at random 50
units from the population of coal-fired units not selected in any of
the above groups to test; specifics of the required testing may be
found in Docket entry EPA-HQ-OAR-2009-0234-0062. We did not use the
data gathered for the Utility Study because those data are outdated and
lack sufficient detail. Thus, EPA believed that gathering these data
was necessary to assess the emissions of this important source
category.
    All IGCC units were also required to test; specifics of the
required testing may be found in Docket entry EPA-HQ-OAR-2009-0234-
0062.
    EPA was able to identify the best performing coal-fired units for
the three HAP surrogate groups but the data obtained in support of the
Utility Study and the December 2000 Finding do not indicate that any
oil-fired units control beyond some ESP use and the data do not show
any correlation between the PM control at oil-fired units and emissions
of non-Hg metallic HAP from those units. Further, no oil-fired EGU has
been constructed in decades and no oil-fired EGU has a FGD system
installed, eliminating the potential basis for the use of compliance
with an SO 2 emissions limit that resulted in the
installation of an FGD system as a basis for selecting best performers
for the acid-gas HAP from such units. Thus, EPA had no basis for
determining which oil-fired units may be the ``best performers.''
Therefore, EPA required that 66 units selected at random from the
population of known oil-fired units test their stack emissions;
specifics of the required testing may be found in Docket entry EPA-HQ-
OAR-2009-0234-0062.
    All petroleum coke-fired units identified were required to test;
specifics of the required testing may be found in Docket entry EPA-HQ-
OAR-2009-0234-0062.
    Pursuant to CAA section 112(q)(3), CAA section 112 as in effect
prior to the 1990 CAA amendments remains in effect for radionuclide
emissions from coal-fired EGUs at the Administrator's discretion. For
this reason, we did not require testing for radionuclides. We are also
not proposing standards for radionuclides in this action.

F. What is the relationship between this proposed rule and other
combustion rules?

1. CAA Section 111
    Revised NSPS for SO2, NOX, and PM were
promulgated under CAA section 111 for EGUs (40 CFR part 60, subpart Da)
and industrial boilers (IB) (40 CFR part 60, subparts Db and Dc) on
February 27, 2006 (71 FR 9866). As noted elsewhere, we are proposing
certain amendments to 40 CFR part 60, subpart Da. In developing this
proposed rule, we considered the monitoring requirements, testing
requirements, and recordkeeping requirements of the existing NSPS to
avoid duplicating requirements to the extent possible.
2. CAA Section 112
    EPA has previously developed other non-EGU combustion-related
NESHAP under CAA section 112(d) in addition to today's proposed rule
for coal- and oil-fired EGUs. EPA signed final NESHAP for major and
area source Boiler NESHAP on February 21, 2011 (to be

codified at 40 CFR part 63, subpart DDDDD and subpart JJJJJJ,
respectively) and promulgated standards for stationary combustion
turbines (CT) on March 5, 2004 (69 FR 10512; 40 CFR part 63 subpart
YYYY). In addition to these two NESHAP, on February 21, 2011, EPA also
signed final CAA section 129 standards for commercial and institutional
solid waste incinerator (CISWI) units, including energy recovery units
(to be codified at 40 CFR part 60, subparts CCCC (NSPS) and DDDD
(emission guidelines) and a definition of non-hazardous secondary
materials that are solid waste (Non-hazardous Solid Waste Definition
Rule, to be codified at 40 CFR part 241, subpart B). EGUs and IB that
combust fossil fuel and solid waste, as that term is defined by the
Administrator pursuant to the Resource Conservation and Recovery Act
(RCRA), will be subject to section 129 (e.g., CISWI energy recovery
units), unless they meet one of the exemptions in CAA section 129(g).
CAA section 129 standards are discussed in more detail below.
    The two IB NESHAP, CT NESHAP, and this proposed rule will regulate
HAP emissions from sources that combust fossil fuels for electrical
power, process operations, or heating. The differences among these
rules are due to the size of the units (MWe or Btu/hr), the boiler/
furnace technology, or the portion of their electrical output (if any)
for sale to any utility power distribution systems. See CAA section
112(a)(8) (defining EGU) earlier.
    All of the MWe ratings quoted in the proposed rule are considered
to be the original nameplate rated capacity of the unit. Cogeneration
is defined as the simultaneous production of power (electricity) and
another form of useful thermal energy (usually steam or hot water) from
a single fuel-consuming process.
    The CT rule regulates HAP emissions from all simple-cycle and
combined-cycle stationary CTs producing electricity or steam for any
purpose. Because of their combustion technology, simple-cycle and
combined-cycle stationary CTs (with the exception of IGCC units that
burn gasified coal or petroleum coke syngas) are not considered EGUs
for purposes of this proposed rule.
    Any combustion unit, regardless of size, that produces steam to
serve a generator that produces electricity exclusively for industrial,
commercial, or institutional purposes (i.e., no sales are made to the
national electrical distribution grid) is considered an IB unit. A
fossil fuel-fired combustion unit that serves a generator that produces
electricity for sale is not considered to be an EGU under the proposed
rule if the size of the combustion unit is less than or equal to 25
MWe. Units under that size would be subject to one of appropriate
Boiler NESHAP. Further, EPA interprets the CAA section 112(a)(8)
definition such that a non-cogeneration unit must both have a
combustion unit of more than 25 MWe and supply more than 25 MWe to any
utility power distribution system for sale to be considered an EGU
pursuant to this proposed rule so as to be consistent with the
cogeneration definition in CAA section 112(a)(8). Such units that sell
less than 25 MWe of their power generation to the grid would be subject
to the appropriate Boiler NESHAP.
    As noted earlier, natural gas-fired EGU's were not included in the
December 2000 listing. Thus, this proposed rule would not regulate a
unit that otherwise meets the CAA section 112(a)(8) definition of an
EGU but combusts natural gas exclusively or natural gas in combination
with another fuel where the natural gas constitutes 90 percent or more
of the average annual heat input during the previous 3 calendar years
or 85.0 percent or more of the annual heat input during any one of
those calendar years. Such units are considered to be natural gas-fired
EGUs and would not be subject to this proposed rule.
    The CAA does not define the terms ``fossil fuel'' and ``fossil fuel
fired;'' therefore, we are proposing definitions for both terms. The
definition of ``fossil fuel fired'' will determine the applicability of
the proposed rule to combustion units that sell electricity to the
utility power distribution system. A number of units that may otherwise
meet the CAA section 112(a)(8) EGU definition fire primarily non-fossil
fuels (e.g., biomass). However, these units generally startup using
either natural gas or oil and may use these fuels (or coal) during
normal operation for flame stabilization. We have included a definition
that will establish the scope of applicability based in part on the
amount of fossil fuel combustion necessary to make a unit become
``fossil fuel fired,'' and the units that combust primarily non-fossil
fuel will be subject to this proposed rule should they fire more than
that amount of coal or oil. Specifically, EPA is proposing that an EGU
must be capable of combusting more than 73 MWe (250 MMBtu/hr) heat
input \156\ (equivalent to 25 MWe output) of coal or oil to be
considered an EGU subject to this proposed rule. To be ``capable of
combusting'' coal or oil, a unit would need to have fossil fuels
allowed in their permits and have the appropriate fuel handling
facilities on-site (e.g., coal handling equipment, including for
purposes of example, but not limited to, coal storage area, belts and
conveyers, pulverizers, etc.; oil storage facilities). In addition, EPA
is proposing that an EGU must have fired coal or oil for more than 10.0
percent of the average annual heat input during the previous 3 calendar
years or for more than 15.0 percent of the annual heat input during any
one of those calendar years to be considered a fossil fuel-fired EGU
subject to this proposed rule. Units that do not meet these definitions
would, in most cases, be considered IB units subject to one of the
Boiler NESHAP. Thus, for example, a biomass-fired EGU, regardless of
size, that utilizes fossil fuels for startup and flame stabilization
purposes only (i.e., less than or equal to 250 MMBtu/hr and used less
than 10.0 percent of the average annual heat input during the previous
3 calendar years or less than 15.0 percent of the annual heat input
during any one of those calendar years) is not considered to be a
fossil fuel-fired EGU under this proposed rule. EPA has based its
threshold value on the definition of ``oil-fired'' in the ARP found at
40 CFR 72.2. As EPA has no data on such use for (e.g.) biomass co-fired
EGUs because their use has not yet become commonplace, we believe this
definition also accounts for the use of fossil fuels for flame
stabilization use without inappropriately subjecting such units to this
proposed rule. EPA solicits comment on the use of these definitions.
Commenters suggesting alternate definitions (including thresholds)
should provide detailed information in support of their comment (e.g.,
3- to 5-year average fossil fuel use under conditions of startup and
flame stabilization).
---------------------------------------------------------------------------

    \156\ Heat input means heat derived from combustion of fuel in
an EGU and does not include the heat derived from preheated
combustion air, recirculated flue gases or exhaust gases from other
sources (such as stationary gas turbines, internal combustion
engines, and IB).
---------------------------------------------------------------------------

    Also, a cogeneration facility that sells electricity to any utility
power distribution system equal to more than one-third of their
potential electric output capacity and more than 25 MWe is considered
to be an EGU if it is fossil fuel fired as that term is defined above.
For such units, EPA is proposing that the unit must be capable of
combusting sufficient coal or oil to generate 25 MWe from the fossil
fuel alone, and must provide for sale to any utility power distribution
system electricity equal to

more than one-third of their potential electric output capacity and
greater than 25 MWe electrical output. However, a cogeneration facility
that meets the above definition of an EGU during any portion of a month
would be subject to the proposed EGU rule for the succeeding 6 calendar
months (combustion units that begin combusting solid waste must
immediately comply with an applicable CAA section 129 standard (e.g.,
CISWI standards applicable to energy recovery units)).
    We recognize that different section 112 rules may impact a
particular unit at different times. For example there will likely be
some cogeneration units that are determined to be covered under the
Boiler NESHAP. Such unit may make a decision to increase/decrease the
proportion of production output being supplied to the electric utility
grid, thus causing the unit to meet the EGU cogeneration criteria
(i.e., greater than one-third of its potential output capacity and
greater than 25 MWe). A unit subject to one of the Boiler NESHAP that
increases its electricity output and meets the definition of an EGU
would be subject to the proposed EGU NESHAP for the 6-month period
after the unit meets the EGU definition. Assuming the unit did not meet
the definition of an EGU following that initial occurrence, at the end
of the 6-month period it would revert back to being subject to the
Boiler NESHAP. This approach is consistent with that taken on the CISWI
rulemaking.
    EPA solicits comment on the extent to which this situation might
occur and whether the 6-month period is appropriate. Given the
differences between the rules, should EPA address reclassification of
the sources between the rules, particularly with regard to initial and
ongoing compliance requirements and schedules? (As noted above, EPA is
proposing to consider as an EGU any cogeneration unit that meets the
definition noted earlier during any month in a year.) We specifically
solicit comments as to how to address sources that may meet the
definition of an EGU for only parts of a year. We also solicit comment
on whether we should include provisions similar to those included in
the final CISWI rule to address units that combust different fuels at
different times. See Final CISWI Rule, 40 CFR 60.2145, http://www.epa.gov/airquality/combustion/docs/20110221ciswi.pdf.
    Another situation may occur where one or more coal- or oil-fired
EGU(s) share an air pollution control device (APCD) and/or an exhaust
stack with one or more similarly-fueled IB unit(s). To demonstrate
compliance with two different rules, the emissions have to either be
apportioned to the appropriate source or the more stringent emission
limit must be met. Data needed to apportion emissions are not currently
required by this proposed rule or the final Boiler NESHAP. Therefore,
EPA is proposing that compliance with the more stringent emission limit
be demonstrated.
    EPA solicits comment on the extent to which this situation might
occur. Given potential differences between the rules, how should EPA
address apportionment of the emissions to the individual sources with
regard to initial and ongoing compliance requirements? EPA specifically
requests comment on the appropriateness of a mass balance-type
methodology to determine pollutant apportionment between sources both
pre-APCD and post-APCD.
3. CAA Section 129
    Units that combust ``non-hazardous solid waste'' as defined by the
Administrator under RCRA are regulated under the provisions of CAA
section 129. On February 21, 2011, EPA signed the final Non-Hazardous
Solid Waste Definition Rule. Any EGU that combusts any solid waste as
defined in that final rule is a solid waste incineration unit subject
to CAA section 129.
    In the Non-Hazardous Solid Waste Definition Rule, EPA determined
that coal refuse from current mining operations is not considered to be
a ``solid waste'' if it is not discarded. Coal refuse that is in legacy
coal refuse piles is considered a ``solid waste'' because it has been
discarded. However, if the discarded coal refuse is processed in the
same manner as currently mined coal refuse, the coal refuse would not
be a solid waste and, therefore, the combustion of such material would
not subject the unit to regulation under CAA section 129. By contrast,
the unit would be subject to this rule if it meets the definition of
EGU. If the unit combusts solid waste, it would be subject to emission
standards under CAA section 129. See, e.g., CISWI rule. Coal refuse
properly processed is a product fossil fuel (i.e., not a solid waste)
if it is not a solid waste; thus, combustion units that otherwise meet
the CAA section 112(a)(8) EGU definition that combust coal refuse that
is product fuel not a solid waste are EGUs subject to this proposed
rule. For this proposed rule, we assumed that all units that combust
coal refuse and otherwise meet the definition of a coal-fired EGU
combust newly mined coal refuse or coal refuse from legacy piles that
has been processed such that it is not a solid waste. We request
comment on this assumption and whether there are any units combusting
coal refuse that is a solid waste such that the units would be solid
waste incineration units instead of EGUs.
    Further, CAA section 129(g)(1)(B) exempts from regulation under CAA
section 129

    ``* * * qualifying small power production facilities, as defined
in section 796(17)(C) of Title 16, or qualifying cogeneration
facilities, as defined in section 796(18)(B) of Title 16, which burn
homogeneous waste * * * for the production of electric energy or in
the case of qualifying cogeneration facilities which burn
homogeneous waste for the production of electric energy and steam or
other forms of useful energy (such as heat) which are used for
industrial, commercial, heating or cooling purposes * * *''

    Thus, qualifying small power production facilities and cogeneration
facilities that burn a homogeneous waste would be exempt from
regulation under CAA section 129. If the ``homogeneous waste'' material
combusted is a fossil fuel, then the units that are exempt from
regulation under CAA section 129 and that otherwise meet the definition
of an EGU under CAA section 112(a)(8) would be covered under this
proposed rule. For example, a unit that combusts only coal refuse that
is a solid waste would be subject to this proposed rule if the unit met
the definition of EGU and the coal refuse was determined to be a
``homogenous waste'' as that term is defined in the final CAA section
129 CISWI standards (the final rule was signed on February 21, 2011,
but has not yet been published in the Federal Register).

G. What emission limitations and work practice standards must I meet?

    We are proposing the emission limitations presented in Tables 10
and 11 of this preamble. Within the two major subcategories of ``coal''
and ``oil,'' emission limitations were developed for new and existing
sources for five subcategories, two for coal-fired EGUs, one for coal-
and solid oil-derived IGCC EGUs, and two for oil-fired EGUs, which we
developed based on unit type.
    We are proposing that new or existing EGUs are ``coal-fired'' if
they combust coal and meet the proposed definition of ``fossil fuel
fired.'' We are proposing that an EGU is considered to be a ``coal-
fired unit designed for coal greater than or equal to 8,300 Btu/lb'' if
the EGU: (1) Combusts coal; (2) meets the proposed definition of
``fossil fuel fired;'' and (3) burns any coal in an EGU designed to
burn a coal having a calorific value (moist, mineral matter-free basis)
of

greater than or equal to 19,305 kilojoules per kilogram (kJ/kg) (8,300
British thermal units per pound (Btu/lb)) in an EGU with a height-to-
depth ratio of less than 3.82. We are proposing that the EGU is
considered to be a ``coal-fired unit designed for coal less than 8,300
Btu/lb'' if the EGU: (1) Combusts coal; (2) meets the proposed
definition of ``fossil fuel fired;'' and (3) burns any virgin coal in
an EGU designed to burn a nonagglomerating fuel having a calorific
value (moist, mineral matter-free basis) of less than 19,305 kJ/kg
(8,300 Btu/lb) in an EGU with a height-to-depth ratio of 3.82 or
greater.
    We are proposing that the EGU is considered to be an IGCC unit if
the EGU: (1) Combusts gasified coal or solid oil-derived (e.g.,
petroleum coke); (2) meets the proposed definition of ``fossil fuel
fired;'' and (3) is classified as an IGCC unit. We are not proposing to
subcategorize IGCC EGUs based on the source of the syngas used (i.e.,
coal, petroleum coke). Based on information available to the Agency,
although the fuel characteristics of coal and petcoke are quite
different, the syngas products are very similar from both
feedstocks.\157\
---------------------------------------------------------------------------

    \157\ U.S. Department of Energy, Wabash River Coal Gasification
Repowering Project. Project Performance Summary; Clean Coal
Technology Demonstration Program. DOE/FE-0448. July 2002.
---------------------------------------------------------------------------

    We are proposing that the EGU is considered to be ``liquid oil''
fired if the EGU burns liquid oil and meets the proposed definition of
``fossil fuel fired.'' We are proposing that the EGU is considered to
be ``solid oil-derived fuel-fired'' if the EGU burns any solid oil-
derived fuel (e.g., petroleum coke) and meets the proposed definition
of ``fossil fuel fired.'' EPA is also considering a limited-use
subcategory to account for liquid oil-fired units that only operate a
limited amount of time per year on oil and are inoperative the
remainder of the year. Such units could have specific emission
limitations, reduced monitoring requirements (limited operation may
preclude the ability to conduct stack testing), or be held to the same
emission limitations (which could be met through fuel sampling) as
other liquid oil-fired units. EPA solicits comment on all of these
proposed subcategorization approaches.

               Table 10--Emission Limitations for Coal-Fired and Solid Oil-Derived Fuel-Fired EGUS
----------------------------------------------------------------------------------------------------------------
             Subcategory              Total particulate matter     Hydrogen chloride             Mercury
----------------------------------------------------------------------------------------------------------------
Existing coal-fired unit designed     0.030 lb/MMBtu (0.30 lb/  0.0020 lb/MMBtu (0.020   1.0 lb/TBtu (0.0.008 lb/
 for coal [gteqt] 8,300 Btu/lb.        MWh).                     lb/MWh).                 GWh).
Existing coal-fired unit designed     0.030 lb/MMBtu (0.30 lb/  0.0020 lb/MMBtu (0.020   11.0 lb/TBtu (0.20 lb/
 for coal < 8,300 Btu/lb.              MWh).                     lb/MWh).                 GWh) 4.0 lb/TBtu *
                                                                                (0.040 lb/GWh *).
Existing--IGCC......................  0.050 lb/MMBtu (0.30 lb/  0.00050 lb/MMBtu         3.0 lb/TBtu (0.020 lb/
                                       MWh).                     (0.0030 lb/MWh).         GWh).
Existing--Solid oil-derived.........  0.20 lb/MMBtu (2.0 lb/    0.0050 lb/MMBtu (0.080   0.20 lb/TBtu (0.0020 lb/
                                       MWh).                     lb/MWh).                 GWh).
New coal-fired unit designed for      0.050 lb/MWh............  0.30 lb/GWh............  0.000010 lb/GWh.
 coal [gteqt] 8,300 Btu/lb.
New coal-fired unit designed for      0.050 lb/MWh............  0.30 lb/GWh............  0.040 lb/GWh.
 coal < 8,300 Btu/lb.
New--IGCC...........................  0.050 lb/MWh *..........  0.30 lb/GWh *..........  0.000010 lb/GWh *.
New--Solid oil-derived..............  0.050 lb/MWh............  0.00030 lb/MWh.........  0.0020 lb/GWh.
----------------------------------------------------------------------------------------------------------------
Note: lb/MMBtu = pounds pollutant per million British thermal units fuel input.
lb/TBtu = pounds pollutant per trillion British thermal units fuel input.
lb/MWh = pounds pollutant per megawatt-electric output (gross).
lb/GWh = pounds pollutant per gigawatt-electric output (gross).
* Beyond-the-floor limit as discussed elsewhere.

                            Table 11--Emission Limitations for Liquid Oil-Fired EGUS
----------------------------------------------------------------------------------------------------------------
             Subcategory                 Total HAP metals *        Hydrogen chloride        Hydrogen fluoride
----------------------------------------------------------------------------------------------------------------
Existing--Liquid oil................  0.000030 lb/MMBtu.......  0.00030 lb/MMBtu.......  0.00020 lb/MMBtu.
                                      (0.00030 lb/MWh)........  (0.0030 lb/MWh)........  (0.0020 lb/MWh).
New--Liquid oil.....................  0.00040 lb/MWh..........  0.00050 lb/MWh.........  0.00050 lb/MWh.
----------------------------------------------------------------------------------------------------------------
* Includes Hg.

    Pursuant to CAA section 112(h), we are proposing a work practice
standard for organic HAP, including emissions of dioxins and furans,
from all subcategories of EGU. The work practice standard being
proposed for these EGUs would require the implementation of an annual
performance (compliance) test program as described elsewhere in this
preamble. We are proposing work practice standards because the data
confirm that the significant majority of the measured organic HAP
emissions from EGUs are below the detection levels of the EPA test
methods, and, as such, EPA considers it impracticable to reliably
measure emissions from these units. As discussed later in this
preamble, EPA believes the inaccuracy of a majority of measurements
coupled with the extended sampling times used, fulfill the criteria for
these HAP to be subject to a work practice standard under CAA section
112(h).
    We are proposing a beyond-the-floor standard for Hg only for all
existing coal-fired units designed for coal less than 8,300 Btu/lb
based on the use of ACI for Hg control, as described elsewhere in this
preamble. We are proposing a beyond-the-floor standard for all
pollutants for new IGCC units based on the new-source limits for coal-
fired units designed for coal greater than or equal to 8,300 Btu/lb as
described elsewhere in this preamble.
    As noted elsewhere in this preamble, we are proposing to use total
PM as a surrogate for the non-Hg metallic HAP and HCl as a surrogate
for the acid gas HAP for all subcategories of coal-fired EGUs and for
the solid oil derived fuel-fired EGUs. For liquid oil-fired EGUs, we
are proposing total HAP metal, HCl, and HF emission limitations.

    In addition, we are proposing three alternative standards for
certain subcategories: (1) SO2 (as an alternative equivalent
to HCl for all subcategories with add-on FGD systems); (2) individual
non-Hg metallic HAP (as an alternate to PM for all subcategories except
liquid oil-fired); (3) total non-Hg metallic HAP (as an alternate to PM
for all subcategories except liquid oil-fired); and (4) individual
metallic HAP (as an alternate to total metal HAP) for the liquid oil-
fired subcategory. These alternative proposed standards are discussed
elsewhere in this preamble.

H. What are the startup, shutdown, and malfunction (SSM) requirements?

    The DC Circuit Court vacated portions of two provisions in EPA's
CAA section 112 regulations governing the emissions of HAP during
periods of SSM. Sierra Club v. EPA, 551 F.3d 1019 (DC Cir. 2008), cert.
denied, 130 S. Ct. 1735 (U.S. 2010). Specifically, the DC Circuit Court
vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR
63.6(h)(1), that are part of a regulation, commonly referred to as the
``General Provisions Rule,'' that EPA promulgated under CAA section
112. When incorporated into CAA section 112(d) regulations for specific
source categories, these two provisions exempt sources from the
requirement to comply with the otherwise applicable CAA section 112(d)
emission standard during periods of SSM.
    Consistent with Sierra Club, EPA is proposing standards in this
rule that apply at all times. In proposing the standards in this rule,
EPA has taken into account startup and shutdown periods and, for the
reasons explained below, has not proposed different standards for those
periods. The standards that we are proposing are 30 boiler operating
day averages. EGUs, especially solid fuel-fired EGUs, do not normally
startup and shutdown frequently and typically use cleaner fuels (e.g.,
natural gas or oil) during the startup period. Based on the data before
the Agency, we are not establishing different emissions standards for
startup and shutdown.
    To appropriately determine emissions during startup and shutdown
and account for those emissions in assessing compliance with the
proposed emission standards, we propose use of a default diluent value
of 10.0 percent O2 or the corresponding fuel specific
CO2 concentration for calculating emissions in units of lb/
MMBtu or lb/TBtu during startup or shutdown periods. For calculating
emissions in units of lb/MWh or lb/GWh, we propose source owners use an
electrical production rate of 5 percent of rated capacity during
periods of startup or shutdown. We recognize that there are other
approaches for determining emissions during periods of startup and
shutdown, and we request comment on those approaches. We further
solicit comment on the proposed approach described above and whether
the values we are proposing are appropriate.
    Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. However, by
contrast, malfunction is defined as a ``sudden, infrequent, and not
reasonably preventable failure of air pollution control and monitoring
equipment, process equipment or a process to operate in a normal or
usual manner * * *.'' 40 CFR 63.2. EPA has determined that malfunctions
should not be viewed as a distinct operating mode and, therefore, any
emissions that occur at such times do not need to be factored into
development of CAA section 112(d) standards, which, once promulgated,
apply at all times. In Mossville Environmental Action Now v. EPA, 370
F.3d 1232, 1242 (DC Cir. 2004), the DC Circuit Court upheld as
reasonable standards that had factored in variability of emissions
under all operating conditions. However, nothing in CAA section 112(d)
or in case law requires that EPA anticipate and account for the
innumerable types of potential malfunction events in setting emission
standards. See, Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (DC Cir.
1978) (``In the nature of things, no general limit, individual permit,
or even any upset provision can anticipate all upset situations. After
a certain point, the transgression of regulatory limits caused by
`uncontrollable acts of third parties,' such as strikes, sabotage,
operator intoxication or insanity, and a variety of other
eventualities, must be a matter for the administrative exercise of
case-by-case enforcement discretion, not for specification in advance
by regulation.'')
    Further, it is reasonable to interpret CAA section 112(d) as not
requiring EPA to account for malfunctions in setting emissions
standards. For example, we note that CAA section 112 uses the concept
of ``best performing'' sources in defining MACT, the level of
stringency that major source standards must meet. Applying the concept
of ``best performing'' to a source that is malfunctioning presents
significant difficulties. The goal of best performing sources is to
operate in such a way as to avoid malfunctions of their units.
    Moreover, even if malfunctions were considered a distinct operating
mode, we believe it would be impracticable to take malfunctions into
account in setting CAA section 112(d) standards for EGUs. As noted
above, by definition, malfunctions are sudden and unexpected events and
it would be difficult to set a standard that takes into account the
myriad different types of malfunctions that can occur across all
sources in the category. Moreover, malfunctions can vary in frequency,
degree, and duration, further complicating standard setting.
    In the unlikely event that a source fails to comply with the
applicable CAA section 112(d) standards as a result of a malfunction
event, EPA would determine an appropriate response based on, among
other things, the good faith efforts of the source to reduce the
likelihood that malfunctions would occur, minimize emissions during
malfunction periods, including preventative and corrective actions, as
well as root cause analyses to ascertain and rectify excess emissions.
EPA would also consider whether the source's failure to comply with the
CAA section 112(d) standard was, in fact, ``sudden, infrequent, not
reasonably preventable'' and was not instead ``caused in part by poor
maintenance or careless operation.'' See 40 CFR 63.2 (definition of
malfunction).
    Finally, EPA recognizes that even equipment that is properly
designed and maintained can sometimes fail and that such failure can
sometimes cause an exceedance of the relevant emission standard. (See,
e.g., State Implementation Plans: Policy Regarding Excessive Emissions
During Malfunctions, Startup, and Shutdown (September 20, 1999); Policy
on Excess Emissions During Startup, Shutdown, Maintenance, and
Malfunctions (February 15, 1983)). EPA is, therefore, proposing an
affirmative defense to civil penalties for exceedances of emission
limits that are caused by malfunctions. See 40 CFR 63.10042 (defining
``affirmative defense'' to mean, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which
are independently and objectively evaluated in a judicial or
administrative proceeding). We also are proposing other regulatory
provisions to specify the elements that are necessary to establish this
affirmative defense; the source must prove by a preponderance of the
evidence that it has met all of the elements set forth in section
63.10001. See 40 CFR 22.24. The criteria ensure that the affirmative
defense is available only where the event that causes an exceedance of
the emission limit meets

the narrow definition of malfunction in 40 CFR 63.2 (sudden,
infrequent, not reasonably preventable and not caused by poor
maintenance and/or careless operation). For example, to successfully
assert the affirmative defense, the source must prove by a
preponderance of the evidence that excess emissions ``[w]ere caused by
a sudden, infrequent, and unavoidable failure of air pollution control
and monitoring equipment, process equipment, or a process to operate in
a normal or usual manner * * *.'' The criteria also are designed to
ensure that steps are taken to correct the malfunction, to minimize
emissions in accordance with 40 CFR 63.10000(b) and to prevent future
malfunctions. For example, the source must prove by a preponderance of
the evidence that ``[r]epairs were made as expeditiously as possible
when the applicable emission limitations were being exceeded * * *''
and that ``[a]ll possible steps were taken to minimize the impact of
the excess emissions on ambient air quality, the environment and human
health * * *'' In any judicial or administrative proceeding, the
Administrator may challenge the assertion of the affirmative defense
and, if the respondent has not met its burden of proving all of the
requirements in the affirmative defense, appropriate penalties may be
assessed in accordance with CAA section 113. See also 40 CFR part
22.77.

I. What are the testing requirements?

    We are proposing that the owner or operator of a new or existing
coal- or oil-fired EGU must conduct performance tests to demonstrate
compliance with all applicable emission limits. For units using
certified continuous emissions monitoring systems (CEMS) that directly
measure the concentration of a regulated pollutant under proposed 40
CFR part 63, subpart UUUUU (e.g., Hg CEMS, SO2 CEMS, or HCl
CEMS) or sorbent trap monitoring systems, the initial performance test
would consist of all valid data recorded with the certified monitoring
system in the first 30 operating days after the compliance date. For
units using CEMS to measure a surrogate for a regulated pollutant
(i.e., PM CEMS), initial stack testing of the surrogate and the
regulated pollutant conducted during the same compliance test period
and under the same process (e.g., fuel) and control device operating
conditions would be required, and an operating limit would be
established. Affected units would be required to conduct the following
compliance tests where applicable:
    (1) For coal-fired units, IGCC units, and solid oil-derived fuel-
fired units, if you elect to comply with the total PM emission limit,
then you would conduct HAP metals and PM emissions testing during the
same compliance test period and under the same process (e.g., fuel) and
control device operating conditions initially and every 5 years using
EPA Methods 29, 5, and 202. Continuous compliance would be determined
using a PM CEMS with an operating limit established based on the
filterable PM values measured using Method 5. If you elect to comply
with the total HAP metals emission limit or the individual HAP metals
emissions limits, then you would conduct total PM and HAP metals
testing during the same compliance test period and under the same
process (e.g., fuel) and control device operating conditions at least
once every 5 years and, to demonstrate continuous compliance, you would
conduct total or individual HAP metals emissions testing every 2 months
(or every month if you have no PM control device) using EPA Method 29.
Note that the filter temperature for each Method 29 or 5 emissions test
is to be maintained at 160  14 [deg]C (320  25
[deg]F) and that the material in Method 29 impingers is to be analyzed
for metals content.
    (2) Coal-fired, IGCC, and solid oil-derived fuel-fired units would
be required to use a Hg CEMS or sorbent trap monitoring system for
continuous compliance using the continuous Hg monitoring provisions of
proposed Appendix A to proposed 40 CFR part 63, subpart UUUUU. The
initial performance test would consist of all valid data recorded with
the certified Hg monitoring system in the first 30 boiler operating
days after the compliance date.
    (3) For coal-fired and solid oil-derived fuel-fired units and new
or reconstructed IGCC units that have SO2 emission controls
and elect to use SO2 CEMS for continuous compliance, an
initial stack test for SO2 would not be required. Instead
the first 30 days of SO2 CEMS data would be used to
determine initial compliance. For units with or without SO2
or HCl emission controls that elect to use HCl CEMS, an initial stack
test for HCl would not be required. Instead the first 30 days of HCl
CEMS data would be used to determine initial compliance. For units
without HCl CEMS and without SO2 or HCl emissions control
devices, you would be required to conduct HCl emissions testing every
month using EPA Method 26 if no entrained water droplets exist in the
exhaust gas or Method 26A if entrained water droplets exist in the
exhaust gas. For units without SO2 or HCl CEMS but with
SO2 emissions control devices, you would conduct HCl testing
at least every 2 months using EPA Method 26 or 26A. For units without
SO2 or HCl CEMS and without SO2 emissions control
devices, you would conduct HCl emissions testing every month using EPA
Method 26A if entrained water droplets exist in the exhaust gas or
Method 26A or 26 if no entrained water droplets exist in the exhaust
gas.
    (4) For all required performance stack tests, you would conduct
concurrent oxygen (O2) or carbon dioxide (CO2)
emission testing using EPA Method 3A and then, use an appropriate
equation, selected from among Equations 19-1 through 19-9 in EPA Method
19 to convert measured pollutant concentrations to lb/MMBtu values.
Multiply the lb/MMBtu value by one million to get the lb/TBtu value (if
applicable).
    (5) For liquid oil-fired units, initial performance testing would
be conducted as follows. For non-Hg HAP metals, use EPA Method 29. For
Hg, conduct emissions testing using EPA Method 29 or Method 30B. For
acid gases, conduct HCl and HF testing using EPA Methods 26A or 26.
Conduct additional performance testing for Hg at least annually;
conduct additional performance tests for HAP metals and acid gases
every 2 months if the EGU has emission controls for metals or acid
gases, and every month if the EGU does not have these controls.
    (6) For existing units that qualify as low emitting EGUs (LEEs),
conduct subsequent performance tests for the LEE qualified pollutants
every 5 years and perform fuel analysis monthly.
    Except for liquid oil-fired units, those EGUs with PM emissions
control devices, without HCl CEMS but with HCl control devices, or for
LEE, we are proposing that you monitor during initial performance
testing specified operating parameters that you would use to
demonstrate ongoing compliance. You would calculate the minimum (or
maximum, depending on the parameter measured) hourly parameter values
measured during each run of a 3-run performance test. The average of
the three minimum (or maximum) values from the three runs for each
applicable parameter would establish a site-specific operating limit.
The applicable operating parameters for which operating limits would be
required to be established are based on the emissions limits applicable
to your unit as well as the types of add-on controls on the unit. The
following is a summary of the operating limits that we are proposing to
be established for the various types of the following units:

    (1) For units without wet or dry FGD scrubbers that must comply
with an HCl emission limit, you must measure the average chlorine
content level in the input fuel(s) during the HCl performance test.
This is your maximum chlorine input operating limit.
    (2) For units with wet FGD scrubbers, you must measure pressure
drop and liquid flow rate of the scrubber during the performance test,
and determine the maximum value for each test run. The average of the
minimum hourly value for the three test runs establishes your minimum
site-specific pressure drop and liquid flow rate operating levels. If
different average parameter levels are measured during the Hg and HCl
tests, the highest of the average values becomes your site-specific
operating limit. If you are complying with an HCl emission limit, you
must measure pH of the scrubber effluent during the performance test
for HCl and determine the minimum hourly value for each test run. The
average of the three minimum hourly values from the three test runs
establishes your minimum pH operating limit.
    (3) For units with dry scrubbers or DSI (including ACI), you would
be required to measure the sorbent injection rate for each sorbent used
during the performance tests for HCl and Hg and determine the minimum
hourly rate of injected sorbent for each test run. The average of the
three test run minimum values established during the performance tests
would be your site-specific minimum sorbent injection rate operating
limit. If different sorbents and/or injection rates are used during the
Hg and HCl performance testing, the highest value for each sorbent
becomes your site-specific operating limit for the respective HAP. If
the same sorbent is used during the Hg and HCl performance testing, but
at different injection rates, the highest average value for each
sorbent becomes your site-specific operating limit. The type of sorbent
used (e.g., conventional AC, brominated AC, trona, hydrated lime,
sodium carbonate, etc.) must be specified.
    (4) For units with FFs in combination with wet scrubbers, you must
measure the pH, pressure drop, and liquid flow rate of the wet scrubber
during the performance test and calculate the minimum hourly value for
each test run. The average of the minimum hourly values from the three
test runs establishes your site-specific pH, pressure drop, and liquid
flow rate operating limits for the wet scrubber.
    (5) For units with an ESP in combination with wet scrubbers, you
must measure the pH, pressure drop, and liquid flow rate of the wet
scrubber during the HCl performance test and you must measure the
voltage and current of each ESP collection field during the Hg and PM
performance test. You would then be required to calculate the minimum
hourly value of these parameters for each of the three test runs. The
average of the three minimum hourly values would establish your site-
specific minimum pH, pressure drop, and liquid flow rate operating
limit for the wet scrubber and the minimum voltage and current
operating limits for the ESP.
    (6) For liquid oil-fired or LEEs, you would be required to measure
the Hg, Cl, and HAP metal content of the inlet fuel that was burned
during the Hg, HCl and HF, and HAP metal emissions performance testing.
The fuel content value for each of these compounds is your maximum fuel
inlet operating limit for each of these compounds.
    (7) For units with FFs, you must measure the output of the bag leak
detection system (BLDS) sensor (whether in terms of relative or
absolute PM loading) during each Hg, PM, and metals performance test.
You would then be required to calculate the minimum hourly value of
this output for each test run. The average of the minimum hourly BLDS
values would establish your site-specific maximum BLDS sensor output
and current operating limit for the BLDS.
    (8) For units with an ESP, you must measure the voltage and current
of each ESP collection field during each Hg, PM, and metals performance
test. You would then be required to calculate the minimum hourly value
of these parameters for each test run. The average of the three minimum
hourly values would establish your site-specific minimum voltage and
current operating limits for the ESP.
    (9) Note that you establish the minimum (or maximum) hourly average
operating limits based on measurements done during performance testing;
should you desire to have differing operating limits which correspond
to other loads, you should conduct testing at those other loads to
determine those other operating limits.
    Instead of operating limits for dioxins and furans and non-dioxin/
furan organic HAP, we are proposing that owners or operators of units
submit documentation that a ``tune up'' meeting the requirements of the
proposed rule was conducted. Such a ``tune-up'' would require the owner
or operator of a unit to:
    (1) As applicable, inspect the burner, and clean or replace any
components of the burner as necessary (you may delay the burner
inspection until the next scheduled unit shutdown, but you must inspect
each burner at least once every 18 months);
    (2) Inspect the flame pattern, as applicable, and make any
adjustments to the burner necessary to optimize the flame pattern. The
adjustment should be consistent with the manufacturer's specifications,
if available;
    (3) Inspect the system controlling the air-to-fuel ratio, as
applicable, and ensure that it is correctly calibrated and functioning
properly;
    (4) Optimize total emissions of CO and NOX. This
optimization should be consistent with the manufacturer's
specifications, if available;
    (5) Measure the concentration in the effluent stream of CO and
NOX in ppm, by volume, and oxygen in volume percent, before
and after the adjustments are made (measurements may be either on a dry
or wet basis, as long as it is the same basis before and after the
adjustments are made); and
    (6) Maintain on-site and submit, if requested by the Administrator,
an annual report containing:
    (i) The concentrations of CO and NOX in the effluent
stream in ppm by volume, and oxygen in volume percent, measured before
and after the adjustments of the EGU;
    (ii) A description of any corrective actions taken as a part of the
combustion adjustment; and
    (iii) The type and amount of fuel used over the 12 months prior to
the adjustment, but only if the unit was physically and legally capable
of using more than one type of fuel during that period.
    Many, if not most, EGUs have planned annual outages, and the
inspection and tune up procedure was designed to occur during this
normal occurrence. Nonetheless, we are proposing a maximum period of up
to 18 months between inspections and tune ups to account for those EGUs
with unusual planned outage schedules. We seek comment on the
appropriateness of this period.

J. What are the continuous compliance requirements?

1. Continuous Compliance Requirements
    To demonstrate continuous compliance with the emission limitations,
we are proposing the following requirements:
    (1) For IGCC units or units combusting coal or solid oil-derived
fuel and electing to use PM as a surrogate for non-Hg HAP metals, you
would install, certify, and operate PM CEMS in

accordance with Performance Specification (PS) 11 in Appendix B to 40
CFR part 60, and to perform periodic, on-going quality assurance (QA)
testing of the CEMS according to QA Procedure 2 in Appendix F to 40 CFR
part 60. An operating limit (PM concentration) would be set during
performance testing for initial compliance; the hourly average PM
concentrations would be averaged on a rolling 30 boiler operating day
basis. Each 30 boiler operating day average would have to meet the PM
operating limit.
    IGCC units or units combusting coal or solid oil-derived fuel and
electing to comply with the total non-Hg HAP metals emissions limit,
would demonstrate continuous compliance by conducting Method 29 testing
every two months if PM controls are installed or every month if no PM
controls are installed. As an option, PM CEMS could be used to
demonstrate continuous compliance as described above. IGCC units or
units combusting coal or solid oil-derived fuel and electing to comply
with the individual non-Hg HAP metals emissions limits, would have the
option to demonstrate continuous compliance only by conducting Method
29; again, testing would be conducted every two months if PM controls
are installed or every month if no PM controls are installed. IGCC
units or units combusting coal or solid oil-derived fuel with PM
controls but not using PM CEMS to demonstrate continuous compliance
would also be required to conduct parameter monitoring and meet
operating limits established during performance testing. Units using
FFs would be required to install and operate BLDS. As mentioned
earlier, the BLDS output would be required to be less than or
equivalent with the average BLDS output determined during performance
testing. Moreover, a source owner or operator would be required to
operate the FFs such that the sum duration of alarms from the BLDS
would not exceed 5 percent of the process operating time during any 6-
month period. Units using an ESP would be required to install and
operate sensors to detect and measure current and voltage for each
field in the ESP. As mentioned earlier, the current and voltage values
for each field in the ESP would need to be greater than or equivalent
with the maximum test run averages determined during performance
testing.
    (2) For IGCC units or units combusting coal or solid oil-derived
fuel, we are proposing that Hg CEMS or sorbent trap monitoring systems
be installed, certified, maintained, operated, and quality-assured in
accordance with proposed Appendix A to 40 CFR part 63, subpart UUUUU,
and that Hg levels (averaged on a rolling 30 boiler operating day
basis) be maintained at or below the applicable Hg emissions limit.
Given that the proposed Appendix A QA procedures for Hg CEMS are based
on a Hg emissions trading rule (CAMR), and this proposal is for a not-
to-exceed NESHAP, EPA solicits comments on whether these Hg CEMS QA
procedures should be adjusted. Further, we are proposing that each pair
of sorbent traps be used to collect Hg samples for no more than 14
operating days, and that the traps be replaced in a timely manner to
ensure that Hg emissions are sampled continuously. In requiring
continuous Hg monitoring, we assumed that most, if not all, of the
units that were subject to CAMR purchased Hg CEMS and/or sorbent trap
systems prior to the rule vacatur, and that many of these monitoring
systems are currently installed and in operation. The Agency's
conclusion regarding Hg CEMS purchases and installation is based in
part on the significant number of units (over 100) that voluntarily
opted to submit Hg CEMS data for the 2010 ICR. We also considered the
steps taken by the industry to prepare for CAMR, and the fact that many
state regulations currently require the installation and operation of
Hg CEMS in order to demonstrate compliance with various SIP and consent
decrees.
    (3) For new or reconstructed IGCC units or coal-fired or solid oil-
derived fuel-fired units with SO2 emissions control devices,
we are proposing two compliance options for acid gases. First, an
SO2 or an HCl CEMS could be installed and certified. We are
proposing that the SO2 monitor be certified and quality-
assured according to 40 CFR part 75 or PS 2 or 6 and Procedure 1 in
Appendices B and F, respectively, of 40 CFR part 60. We believe this is
reasonable, because nearly all utility units are subject to the ARP,
and coal-fired ARP units already have certified SO2 monitors
in place that meet Part 75 requirements. For HCl monitors, PS 15 or 6
in Appendix B to 40 CFR part 60 would be used for certification and,
tentatively, Procedure 1 of Appendix F to 40 CFR part 60 would be
followed for on-going QA.
    Note that a PS specific to HCl CEMS has not been promulgated yet,
but we expect to publish one prior to the compliance date of this
proposed rule and to make it available to source owners and operators.
In the meantime, the FTIR CEMS (PS 15) may be an appropriate choice for
measuring continuous HCl concentrations. Hourly data from the
SO2 or HCl monitor would be converted to the units of the
emission standard and averaged on a rolling 30 boiler operating day
basis. Each 30 boiler operating day average would have to meet the
applicable SO2 or HCl limit.
    The second option that we are proposing would be for units without
SO2 or HCl CEMS but with SO2 emissions control
devices. For these units, parameter operating limits, established
during performance testing, would be monitored continuously, along with
the already-mentioned frequent (every 2 months) HCl emissions testing.
For units with wet FGD scrubbers, we are proposing that you monitor
pressure drop and liquid flow rate of the scrubber continuously and
maintain 12-hour block averages at or above the operating limits
established during the performance test. You must monitor the pH of the
scrubber and maintain the 12-hour block average at or above the
operating limit established during the performance test to demonstrate
continuous compliance with the HCl emission limits.
    For units with dry scrubbers or DSI systems, we are proposing that
you continuously monitor the sorbent injection rate and maintain it at
or above the operating limits established during the performance tests.
    (4) For liquid oil-fired units, we are proposing to require testing
as follows. HAP metals testing would be performed every other month if
a unit has a non-Hg HAP metals control device, and every month if the
unit does not have a non-Hg metals control device. We propose to
require HCl and HF testing every other month if a unit has HCl and HF
control devices, and monthly if the unit does not have these emissions
controls.
    (5) For each unit using PM, HCl, SO2, or Hg CEMS for
continuous compliance, we are proposing that you install, certify,
maintain, operate and quality-assure the additional CEMS (e.g., CEMS
that measure oxygen or CO2 concentration, stack gas flow
rate, and moisture content) needed to convert pollutant concentrations
to units of the emission standards or operating limits. Where
appropriate, we have proposed that these additional CEMS may be
certified and quality-assured according to 40 CFR part 75. Once again,
we believe this is reasonable because almost all coal-fired utility
units already have these monitors in place, under the ARP.
    (6) For limited-use liquid oil combustion units, we are proposing
that those units be allowed to demonstrate compliance with the Hg
emission limit, the HAP metals, or the HCl and HF emissions limits
separately or in

combination based on fuel analysis rather than performance stack
testing, upon request by you and approval by the Administrator. Such a
request would require the owner/operator to follow the requirements in
40 CFR 63.8(f), which presents the procedure for submitting a request
to the Administrator to use alternative monitoring, and, among other
things, explain why a unit should be considered for eligibility,
including, but not limited to, use over the previous 5 years and
projected use over the next 5 years. Approval from the Administrator
would be required before you could use this alternative monitoring
procedure. If approval were granted by the Administrator, we are
proposing that you would maintain fuel records that demonstrate that
you burned no new fuels or fuels from a new supplier such that the Hg,
the non-Hg HAP metal, the fluorine, or the chlorine content of the
inlet fuel was maintained at or below your maximum fuel Hg, non-Hg HAP
metal, fluorine, or chlorine content operating limit set during the
performance stack tests. If you plan to burn a new fuel, a fuel from a
new mixture, or a new supplier's fuel that differs from what was burned
during the initial performance tests, then you must recalculate the
maximum Hg, HAP metal, fluorine, and/or chlorine input anticipated from
the new fuels based on supplier data or own fuel analysis, using the
methodology specified in Table 6 of this proposed rule. If the results
of recalculating the inputs exceed the average content levels
established during the initial test then, you must conduct a new
performance test(s) to demonstrate continuous compliance with the
applicable emission limit.
    (7) For existing LEEs, we are proposing that those units that
qualify be allowed to demonstrate continuous compliance with the Hg
emission limit, the non-Hg HAP metals, or the HCl emissions limits
separately or in combination based on fuel analysis rather than
performance stack testing. LEE would be those units where performance
testing demonstrates that emissions are less than 50 percent of the PM
or HCl emissions limits, less than 10 percent of the Hg emissions
limits, or less than 22.0 pounds per year (lb/yr) of Hg. Note that for
LEE emissions testing for total PM, total HAP metals, individual HAP
metals, HCl, and HF, the required minimum sampling volumes shown in
Table 2 or this proposed rule must be increased nominally by a factor
of two. The LEE cutoff of 22.0 lb/yr represents about 5 percent of the
nationwide Hg mass emissions from the coal-fired units represented in
the 2010 ICR. Most of the units that emit less than 22.0 lb/yr would be
smaller units with relatively low heat input capacities. The 22.0 lb/yr
threshold was determined by summing the total Hg emissions from the
1,091 units in operation and determining the 5th percentile of the
total mass. The units were then ranked by their annual Hg mass
emissions. At the point in the rankings where the cumulative mass was
equivalent to the 5th percentile value calculated, the annual mass
emissions of that unit (22.0 lb/yr) was selected as the threshold. Five
percent of the total mass was chosen as a cut point because comments
received on CAMR indicated that 5 percent of the total mass was a
reasonable cut point. At this 5th percentile threshold, approximately
394 smaller units out of the 1,091 total units would have the option of
using this Hg monitoring methodology.
    Under the proposed alternative compliance option, you would
maintain fuel records that demonstrate that you burned no new fuels or
fuels from a new supplier such that the Hg, non-Hg HAP metal, or the
chlorine content of the inlet fuel was maintained at or below your
maximum fuel Hg, non-Hg HAP metal, fluorine, or chlorine content
operating limit set during the performance stack tests. If you plan to
burn a new fuel, a fuel from a new mixture, or a new supplier's fuel
that differs from what was burned during the initial performance tests,
then you must recalculate the maximum Hg, non-Hg HAP metal, and/or the
maximum chlorine input anticipated from the new fuels based on supplier
data or own fuel analysis, using the methodology specified in Table 6
of this proposed rule. If the results of recalculating the inputs
exceed the average content levels established during the initial test
then, you must conduct a new performance test(s) to demonstrate
continuous compliance with the applicable emission limit.
    (8) For all EGUs, we are proposing that you maintain daily records
of fuel use that demonstrate that you have burned no materials that are
considered solid waste.
    If an owner or operator would like to use a control device other
than the ones specified in this section to comply with this proposed
rule, the owner/operator should follow the requirements in 40 CFR
63.8(f), which establishes the procedure for submitting a request to
the Administrator to use alternative monitoring.
2. Streamlined Approach to Continuous Compliance
    EPA is proposing to simplify compliance with the proposed rule by
harmonizing its monitoring and reporting requirements, to the extent
possible, with those of 40 CFR part 75. With a few exceptions, the
utility industry is already required to monitor and report hourly
emissions data according to Part 75 under the Title IV ARP and other
emissions trading programs. The Agency is, therefore, proposing Hg
monitoring requirements that are consistent with Part 75 and similar to
those that had been promulgated for the vacated CAMR regulation. We are
proposing that hourly Hg emission data be reported to EPA
electronically, on a quarterly basis. At this time, we are proposing
not to apply the same electronic reporting for certification and QA
test data from HCl or PM CEMS but are instead relying on the existing
provisions in Parts 60 and 63.
    Our rationale for this is as follows. We considered two possible Hg
monitoring and reporting options to demonstrate continuous compliance.
The first option would be for Hg CEMS and sorbent trap systems to be
certified and quality-assured according to PS 12A and 12B in Appendix B
to 40 CFR part 60. Procedure 5 in Appendix F to Part 60 would be
followed for on-going QA. Semiannual hard copy reporting of
``deviations'' would be required, along with data assessment reports
(DARs). Even though this option would not require electronic reporting
of either hourly Hg emissions data or QA test results, it still would
require affected sources to have a data handling system (DAHS) that:
(1) Is programmed to capture data from the Hg CEMS; (2) uses the
criteria in Appendix F to Part 60 to validate or invalidate the Hg
data; (3) calculates hourly averages for Hg concentration and for the
auxiliary parameters (e.g., flow rate, O2 or CO2
concentration) that are needed to convert Hg concentrations to the
units of the emission standard; (4) calculates 30 boiler operating day
rolling average Hg emission rates; and (5) identifies any deviations
that must be reported to the Agency.
    The second option would simply integrate Hg emissions data and QA
test results into the existing Part 75-compliant DAHS that is installed
at the vast majority of the coal-fired EGUs. We obtained feedback from
several DAHS vendors indicating that the cost of modifying the existing
Part 75 DAHS systems to accommodate hourly reporting of Hg CEMS and
sorbent trap

data would be similar, and in some cases, less than the cost of the
first option. Also, there would be little or no cost to industry for
the flow rate, CO2, or O2, and moisture monitors
needed to convert Hg concentration to the units of the standard,
because, as previously noted, almost all of the EGUs already have these
monitors in place. In view of these considerations, we have decided in
favor of this second option for Hg.
    Requiring the reporting of hourly Hg emissions data from EGUs would
be advantageous, both to EPA and industry. The DAHS could be automated
to demonstrate compliance with the standard on a continuous basis. The
data could then be submitted to the Agency electronically, thereby
eliminating the need for the Agency to request additional information
for compliance determinations and program implementation.
    Today's proposed rule would also require quarterly electronic
reporting of hourly SO2 CEMS data, PM CEMS data, and HCl
CEMS data (for sources electing to demonstrate continuous compliance
using certified CEMS), as well as electronic summaries of emission test
results (for sources demonstrating continuous compliance by periodic
stack testing), and semiannual electronic ``deviation'' reports (for
sources that monitor parameters or assess compliance in other ways). As
discussed in detail in the paragraphs below, requiring electronic
reporting in lieu of traditional hard copy reports would enable utility
sources to demonstrate continuous compliance with the applicable
emissions limitations of this proposed rule, using a process that is
familiar to them and consistent with the procedures that they currently
follow to comply with ARP and other mass-based emissions trading
programs.
    Currently, utility sources that are subject to the ARP and other
EPA emissions trading programs use the Emissions Collection and
Monitoring Plan System (ECMPS) to process and evaluate continuous
monitoring data and other information in an electronic format for
submittal to the Agency. In addition to receiving hourly emissions
data, this system supports the maintenance of an electronic
``monitoring plan'' and is designed to receive the results of
monitoring system certification test data and ongoing QA test data.
Emissions data are submitted quarterly through ECMPS, and users are
given feedback on the quality of their reports before the data are
submitted. This allows them to make corrections or otherwise address
issues with the reports prior to making their official submittals.
Despite the stringency and thoroughness of the data validation checks
performed by the ECMPS software, the implementation of this process has
resulted in very few errant reports being submitted each quarter. This
has saved both industry and the Agency countless hours of valuable
time, which in years past, was spent troubleshooting errors in the
quarterly reports. EPA is proposing to apply the same basic quarterly
data collection process to Hg, HCl, and PM CEMS data, and to modify
ECMPS to be able to accommodate summarized stack test data and
semiannual deviation reports.
    The ECMPS process divides electronic data into three categories,
the first of which is monitoring plan data. The electronic monitoring
plan is maintained as a separate entity, and can be updated at any
time, if necessary. The monitoring plan documents the characteristics
of the affected units (e.g., unit type, rated heat input capacity,
etc.) and the monitoring methodology that is used for each parameter
(e.g., CEMS). The monitoring plan also describes the type of monitoring
equipment used (hardware and software components), includes analyzer
span and range settings, and provides other useful information. Nearly
all coal-fired EGUs are subject to the ARP and have established
electronic monitoring plans that describe their required
SO2, flow rate, CO2 or O2, and, in
some cases, moisture monitoring systems. The ECMPS monitoring plan
format could easily accommodate this same type of information for Hg,
HCl, and PM CEMS, with the addition of a few codes for the new
parameters.
    The second type of data collected through ECMPS is certification
and QA test data. This includes data from linearity checks, relative
accuracy test audits (RATAs), cycle time tests, 7-day calibration error
tests, and a number of other QA tests that are required to validate the
emissions data. The results of these tests can be submitted to EPA as
soon as the results are received, with one notable exception. Daily
calibration error tests are not treated as individual QA tests, due to
the large number of records generated each quarter. Rather, these tests
are included in the quarterly electronic reports, along with the hourly
emissions data.
    The ECMPS system is already set up to receive and process
certification and QA data from SO2, CO2,
O2, flow rate, and moisture monitoring systems that are
installed, certified, maintained, operated, and quality-assured
according to Part 75. EGUs routinely submit these data to EPA under the
ARP and other emissions trading programs.
    To accommodate the certification and QA tests for Hg CEMS and
sorbent trap monitoring systems, relatively few changes would have to
be made to the structure and functionality of ECMPS, because most of
the tests are the same ones that are required for other gas monitors.
More substantive changes to the system would be required to receive and
process the certification and QA tests required for HCl and PM CEMS,
and to receive summarized stack test results, and the types of data
provided in semiannual compliance reports; however, we believe these
changes are implementable. Another modification that could be made to
ECMPS would be to disable the Part 75 bias test (which is required for
certain types of monitors under EPA's emissions trading programs) for
Hg, HCl, and PM CEMS, if bias adjustment of the data from these
monitors is believed to be unnecessary or inappropriate for compliance
with the proposed rule. We are proposing to make this modification and
solicit comment on it.
    The third type of data collected through ECMPS is the emissions
data, which, as previously noted, is reported on a quarterly schedule.
The reports must be submitted within 30 days after the end of each
calendar quarter. The emissions data format requires hourly reporting
of all measured and calculated emissions values, in a standardized
electronic format. Direct measurements made with CEMS, such as gas
concentrations, are reported in a Monitor Hourly Value (MHV) record. A
typical MHV record for gas concentration includes data fields for: (1)
The parameter monitored (e.g., SO2); (2) the unadjusted and
bias-adjusted hourly concentration values (note that if bias adjustment
is not required, only the unadjusted hourly value is reported); (3) the
source of the data, i.e., a code indicating either that each reported
hourly concentration is a quality-assured value from a primary or
backup monitor, or that quality-assured data were not obtained for the
hour; and (4) the percent monitor availability (PMA), which is updated
hour-by-hour. This generic record structure could easily accommodate
hourly average measurements from Hg, HCl, and PM CEMS.
    The ECMPS reporting structure is quite flexible, which makes it
useful for assessing compliance with various emission limits. The
Derived Hourly Value (DHV) record provides the means whereby a wide
variety of quantities that can be calculated from the hourly emissions
data can be reported. For instance, if an emission limit is expressed
in units of lb/MMBtu, the

DHV record can be used to report hourly pollutant concentration values
in these units of measure, since the lb/MMBtu values can be derived
from the hourly pollutant and diluent gas (CO2 or
O2) concentrations reported in the MHV records. ECMPS can
also accommodate multiple DHV records for a given hour in which more
than one derived value is required to be reported. Therefore, if hourly
Hg, HCl, and PM concentration data are reported through ECMPS, the DHV
record, in conjunction with the appropriate equations and auxiliary
information such as heat input and electrical load (all of which are
reported hourly in the emissions reports), could be used to report
hourly data in the units of the emission standards (e.g., lb/MMBtu, lb/
TBtu, lb/GWh, etc.).
    The ARP and other emissions trading programs that report emissions
data to EPA using Part 75 are required to provide a complete data
record. Emissions data are required to be reported for every unit
operating hour. When CEMS are out of service, substitute data must be
reported to fill in the gaps. However, for the purposes of compliance
with a NESHAP, reporting substitute data during monitor outages may not
be appropriate. Today's proposed rule would not require the use of
missing data substitution for Hg monitoring systems. We intend to
extend this concept to HCl and PM CEMS, if we receive data from those
types of monitors. Hours when a monitoring system is out of service
would simply be counted as hours of monitor down time, to be counted
against the percent monitor availability. We solicit comment on this
proposed approach.
    As previously stated, EPA is proposing to add Hg monitoring
provisions as Appendix A to 40 CFR part 63, subpart UUUUU, and to
require these provisions to be used to document continuous compliance
with the proposed rule, for units that cannot qualify as LEEs. Proposed
Appendix A would consolidate all of the Hg monitoring provisions in one
place. Today's proposed rule would provide two basic Hg continuous
monitoring options: Hg CEMS and sorbent trap monitoring systems.
    Proposed Appendix A would require the Hg CEMS and sorbent trap
monitoring systems to be initially certified and then to undergo
periodic QA testing. The certification tests required for the Hg CEMS
would be a 7-day calibration error test, a linearity check, using NIST-
traceable elemental Hg standards, a 3-level system integrity check
(similar to a linearity check), using NIST-traceable oxidized Hg
standards, a cycle time test, and a RATA. A bias test would not be
required. The performance specifications for the required certification
tests, which are summarized in Table A-1 of proposed Appendix A, would
be the same as those that were published in support of CAMR. For
ongoing QA of the Hg CEMS, proposed Appendix A would require daily
calibrations, weekly single-point system integrity checks, quarterly
linearity checks (or 3-level system integrity checks) and annual RATAs.
These QA test requirements and the applicable performance criteria,
which, once again, are the same as the ones we had published in support
of CAMR, are summarized in Table A-3 in proposed Appendix A. For
sorbent trap monitoring systems, a RATA would be required for initial
certification, and annual RATAs would be required for ongoing QA. The
performance specification for these RATAs would be the same as for the
RATAs of the Hg CEMS. Bias adjustment of the measured Hg concentration
data would not be required. However, for routine, day-to-day operation
of the sorbent trap system, proposed Appendix A provides the owner or
operator the option to follow the procedures and QA/QC criteria in PS
12B in Appendix B to 40 CFR part 60. Performance Specification 12B is
nearly identical to the vacated Appendix K to Part 75. The Part 75
concepts of: (1) Determining the due dates for certain QA tests on the
basis of ``QA operating quarters''; and (2) grace periods for certain
QA tests, would apply to both Hg CEMS and sorbent trap monitoring
systems.
    Mercury concentrations measured by Hg CEMS or sorbent trap systems
would be used together with hourly flow rate, diluent gas, moisture,
and electrical load data, to express the Hg emissions in units of the
proposed rule, on an hourly basis (i.e., lb/TBtu or lb/GWh). Proposed
section 6 of Appendix A provides the necessary equations for these unit
conversions. These hourly values could then be ``rolled up'' within the
DAHS into the proper 30 boiler operating day averaging period, to
assess compliance. A report function could be added to ECMPS to show
the results of these calculations, and to highlight any values in
excess of the standard.
    The proposed rule would specify record keeping and reporting
requirements for the two Hg monitoring methodologies. Essential
information pertaining to each methodology would be represented in the
electronic monitoring plan. Hourly Hg concentration data would be
reported in all cases. However, for the sorbent trap option, a single
Hg concentration value would be reported for extended periods of time,
since a sorbent trap monitoring system does not provide hour-by-hour
measurements of Hg concentration. The results of all required
certification and QA tests would also be reported. Missing data
substitution for Hg concentration would not be required for hours in
which quality-assured data are not obtained. Special codes would be
reported to identify these hours.
    Of all the types of NESHAP compliance data that could be brought
into ECMPS (i.e., CEMS data, stack test summaries, and semiannual
compliance reports), the easiest to implement would be the Hg
monitoring data, because, as noted above, we had published specific Hg
monitoring and reporting provisions in Part 75 prior to the vacatur of
CAMR, and had made considerable progress in modifying ECMPS to receive
these data. Today's proposed rule provides detailed regulatory language
in proposed Appendix A to 40 CFR part 63, subpart UUUUU, pertaining to
the monitoring of Hg emissions and reporting the data electronically.
    We are requesting comment on these proposed compliance approaches
and on whether our proposed ``one stop shopping'' approach to reporting
MACT compliance information electronically is desirable. In your
comments, we ask you to consider the merits of requiring reporting of
results from PM CEMS and HCl CEMS to ECMPS and consequent development
of a monitoring and reporting scheme for these CEMS that is compatible
with ECMPS. If you favor our proposed streamlined continuous compliance
approach, we request input on how to make the reporting process user-
friendly and efficient. EPA believes that if the essential data that
are reported under the Agency's emissions trading programs and the
proposed rule are all sent to the same place, this could significantly
reduce the burden on industry and bring about national consistency in
assessing compliance.

K. What are the notification, recordkeeping, and reporting
requirements?

    All new and existing sources would be required to comply with
certain requirements of the General Provisions (40 CFR part 63, subpart
A), which are identified in Table 10 of this proposed rule. The General
Provisions include specific requirements for notifications,
recordkeeping, and reporting.
    Each owner or operator would be required to submit a notification
of compliance status report, as required by Sec.  63.9(h) of the
General Provisions. This

proposed rule would require the owner or operator to include in the
notification of compliance status report certifications of compliance
with rule requirements.
    Except for units that use CEMS for continuous compliance,
semiannual compliance reports, as required by Sec.  63.10(e)(3) of
subpart A, would be required for semiannual reporting periods,
indicating whether or not a deviation from any of the requirements in
the rule occurred, and whether or not any process changes occurred and
compliance certifications were reevaluated. As previously discussed, we
are proposing to use the ECMPS system to receive the essential
information contained in these semiannual compliance reports
electronically. For units using CEMS, quarterly electronic reporting of
hourly Hg and associated (O2, CO2, flow rate,
and/or moisture) monitoring data, as well as electronic reporting of
monitoring plan data and certification and QA test results, would be
required, also through ECMPS.
    This proposed rule would require records to demonstrate compliance
with each emission limit and work practice standard. These
recordkeeping requirements are specified directly in the General
Provisions to 40 CFR part 63, and are identified in Table 9 of this
proposed rule.
    Records of continuously monitored parameter data for a control
device if a device is used to control the emissions or CEMS data would
be required.
    We are proposing that you must keep the following records:
    (1) All reports and notifications submitted to comply with this
proposed rule.
    (2) Continuous monitoring data as required in this proposed rule.
    (3) Each instance in which you did not meet each emission limit and
each operating limit (i.e., deviations from this proposed rule).
    (4) Daily hours of operation by each source.
    (5) Total fuel use by each affected liquid oil-fired source
electing to comply with an emission limit based on fuel analysis for
each 30 boiler operating day period 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.
    (6) Calculations and supporting information of chlorine fuel input,
as required in this proposed rule, for each affected liquid oil-fired
source with an applicable HCl emission limit.
    (7) Calculations and supporting information of Hg and HAP metal
fuel input, as required in this proposed rule, for each affected source
with an applicable Hg and HAP metal (or PM) emission limit.
    (8) A signed statement, as required in this proposed rule,
indicating that you burned no new fuel type and no new fuel mixture or
that the recalculation of chlorine input demonstrated that the new fuel
or new mixture still meets chlorine fuel input levels, for each
affected source with an applicable HCl emission limit.
    (9) A signed statement, as required in this proposed rule,
indicating that you burned no new fuels and no new fuel mixture or that
the recalculation of Hg and/or HAP metal fuel input demonstrated that
the new fuel or new fuel mixture still meets the Hg and/or HAP metal
fuel input levels, for each affected source with an applicable Hg and/
or HAP metal emission limit.
    (10) A copy of the results of all performance tests, fuel analyses,
performance evaluations, or other compliance demonstrations conducted
to demonstrate initial or continuous compliance with this proposed
rule.
    (11) A copy of your site-specific monitoring plan developed for
this proposed rule as specified in 63 CFR 63.8(e), if applicable.
    We are also proposing to require that you submit the following
additional notifications:
    (1) Notifications required by the General Provisions.
    (2) Initial Notification no later than 120 calendar days after you
become subject to this subpart.
    (3) Notification of Intent to conduct performance tests and/or
compliance demonstration at least 60 calendar days before the
performance test and/or compliance demonstration is scheduled.
    (4) Notification of Compliance Status 60 calendar days following
completion of the performance test and/or compliance demonstration.

L. Submission of Emissions Test Results to EPA

    EPA must have performance test data to conduct effective reviews of
CAA sections 112 and 129 standards, as well as for many other purposes
including compliance determinations, emission factor development, and
annual emission rate determinations. In conducting these required
reviews, EPA has found it ineffective and time consuming, not only for
us, but also for regulatory agencies and source owners and operators,
to locate, collect, and submit performance test data because of varied
locations for data storage and varied data storage methods. In recent
years, though, stack testing firms have typically collected performance
test data in electronic format, making it possible to move to an
electronic data submittal system that would increase the ease and
efficiency of data submittal and improve data accessibility.
    Through this proposal, EPA is presenting a step to increase the
ease and efficiency of data submittal and improve data accessibility.
Specifically, EPA is proposing that owners and operators of EGUs submit
electronic copies of required performance test reports to EPA's WebFIRE
database. The WebFIRE database was constructed to store performance
test data for use in developing emission factors. A description of the
WebFIRE database is available at http://cfpub. epa. gov/oarweb/
index.cfm?action=fire. main.
    As proposed above, data entry would be through an electronic
emissions test report structure called the Electronic Reporting Tool
(ERT). The ERT would be able to transmit the electronic report through
EPA's Central Data Exchange (CDX) network for storage in the WebFIRE
database making submittal of data very straightforward and easy. A
description of the ERT can be found at http://www.epa.gov/ttn/chief/ert/ert gov/ttn/chief/
ert/ert--tool. html.
    The proposal to submit performance test data electronically to EPA
would apply only to those performance tests conducted using test
methods that will be supported by the ERT. The ERT contains a specific
electronic data entry form for most of the commonly used EPA reference
methods. A listing of the pollutants and test methods supported by the
ERT is available at http://www.epa.gov/ttn/chief/ert/ert gov/ttn/chief/ert/ert--tool. html.
We believe that industry would benefit from this proposed approach to
electronic data submittal. Having these data, EPA would be able to
develop improved emission factors, make fewer information requests, and
promulgate better regulations.
    One major advantage of the proposed submittal of performance test
data through the ERT is a standardized method to compile and store much
of the documentation required to be reported by this rule. Another
advantage is that the ERT clearly states what testing information would
be required. Another important proposed benefit of submitting these
data to EPA at the time the source test is conducted is that it should
substantially reduce the effort involved in data collection activities
in the future. When EPA has performance test data in hand, there will
likely be fewer or less substantial data collection requests in
conjunction with prospective required residual risk assessments or
technology reviews. This

would result in a reduced burden on both affected facilities (in terms
of reduced manpower to respond to data collection requests) and EPA (in
terms of preparing and distributing data collection requests and
assessing the results).
    State, local, and tribal agencies could also benefit from more
streamlined and accurate review of electronic data submitted to them.
The ERT would allow for an electronic review process rather than a
manual data assessment making review and evaluation of the source
provided data and calculations easier and more efficient. Finally,
another benefit of the proposed data submittal to WebFIRE
electronically is that these data would greatly improve the overall
quality of existing and new emissions factors by supplementing the pool
of emissions test data for establishing emissions factors and by
ensuring that the factors are more representative of current industry
operational procedures. A common complaint heard from industry and
regulators is that emission factors are outdated or not representative
of a particular source category. With timely receipt and incorporation
of data from most performance tests, EPA would be able to ensure that
emission factors, when updated, represent the most current range of
operational practices. In summary, in addition to supporting regulation
development, control strategy development, and other air pollution
control activities, having an electronic database populated with
performance test data would save industry, state, local, tribal
agencies, and EPA significant time, money, and effort while also
improving the quality of emission inventories and, as a result, air
quality regulations. In this action, as previously stated, EPA is
proposing a step to improve data accessibility. Specifically, we are
proposing that you submit, to an EPA database, electronic copies of
reports of certain performance tests required under the proposed rule
through our ERT; however, we request comment on the feasibility of
using a modified version of ECMPS, which the utility industry already
is familiar with and uses for reporting under the Title IV ARP and
other emissions trading programs, to provide this information.
    ECPMS could be modified to allow electronic submission of periodic
data, including, but not limited to, 30 day averages of parametric
data, 30 day average fuel content data, stack test results, and
performance of tune up records. These data will need to be submitted
and reviewed, and we believe electronic submission via a specific
format already in use for other submissions eases understanding,
affords transparency, ensures consistency, and saves time and money.
    We seek comment on alternatives to the use of a modified ECMPS for
electronic data submission. Commenters should describe alternate means
for supplying these data and information on associated reliability, the
cost, the ease of implementation, and the transparency to the public of
the information.

V. Rationale for This Proposed NESHAP

A. How did EPA determine which subcategories and sources would be
regulated under this proposed NESHAP?

    As stated above, EPA added coal- and oil-fired EGUs to the CAA
section 112(c) list on December 20, 2000. This proposed rule proposes
standards for the subcategories of coal- and oil-fired EGUs as defined
in this preamble. Sources in these subcategories may potentially
include combustion units that are at times IB units or solid waste
incineration units subject to other standards under CAA section 112 or
to standards under CAA section 129. We request comment on whether the
proposed rule should address how sources that change fuel input (e.g.,
burn solid waste or biomass), or otherwise take action that would
change the source's applicability (e.g., stop or start selling
electricity to the utility power distribution system), must demonstrate
continuous compliance with all applicable standards. Note that units
subject to another CAA section 112 standard or to solid waste
incineration unit standards established under CAA section 129 are not
subject to this proposed rule during the period of time they are
subject to the other CAA section 112 or 129 standards.
    The scope of the EGU source category is limited to coal- and oil-
fired units meeting the CAA section 112(a)(8) definition and the
proposed definition of ``fossil fuel fired'' discussed above.
    Under CAA section 112(d)(1), the Administrator has the discretion
to ``* * * distinguish among classes, types, and sizes of sources
within a category or subcategory in establishing * * *'' standards. For
example, differences between given types of units can lead to
corresponding differences in the nature of emissions and the technical
feasibility of applying emission control techniques. In the December
2000 listing, EPA initially established and listed two subcategories of
fossil fuel-fired EGUs: Coal-fired and oil-fired. The design,
operating, and emissions information that EPA has reviewed indicates
that there are significant design and operational differences in unit
design that distinguish different types of EGUs within these two
subcategories, and, because of these differences, we have proposed to
establish two subcategories for coal-fired EGUs, two subcategories for
oil-fired EGUs, and an IGCC subcategory for gasified coal and solid
oil-derived fuel (e.g., petroleum coke), as stated above and discussed
further below.
    EGU systems are designed for specific fuel types and will encounter
problems if a fuel with characteristics other than those originally
specified is fired. Changes to the fuel type would generally require
extensive changes to the fuel handling and feeding system (e.g., liquid
oil-fired EGUs cannot fire solid fuel without extensive modification).
Additionally, the burners and combustion chamber would need to be
redesigned and modified to handle different fuel types and account for
increases or decreases in the fuel volume. In some cases, the changes
may reduce the capacity and efficiency of the EGU. An additional effect
of these changes would be extensive retrofitting needed to operate
using a different fuel. These effects must be considered whether one is
discussing two fuel types (e.g., coal vs. oil) or two ranks or forms of
fuel within a given fuel type (e.g., gasified vs. solid coal or solid
oil-derived fuel).
    The design of the EGU, which is dependent in part on the type of
fuel being burned, impacts the degree of combustion, and may impact the
level and kind of HAP emissions. EGUs emit a number of different types
of HAP emissions. Organic HAP are formed from incomplete combustion and
are primarily influenced by the design and operation of the unit. The
degree of combustion may be greatly influenced by three general
factors: Time, turbulence, and temperature. On the other hand, the
amount of fuel-borne HAP (non-Hg metals, Hg, and acid gases) is
primarily dependent upon the composition of the fuel. These fuel-borne
HAP emissions generally can be controlled by either changing the fuel
property before combustion or by removing the HAP from the flue gas
after combustion.
    We first examined the HAP emissions results to determine if
subcategorization by unit design type was warranted. Normally, any
basis for subcategorizing (e.g., type of unit) must be related to an
effect on emissions, rather than some difference which does not affect
emissions performance. We concluded that the data were sufficient for
one or

more HAP for determining that a distinguishable difference in
performance exists based on the following five unit design types: coal-
fired units designed to burn coal with greater than or equal to 8,300
Btu/lb (for Hg emissions only); coal-fired units designed to burn coal
with less than 8,300 Btu/lb (for Hg emissions only); IGCC units; liquid
oil units; and solid oil-derived units. For other types of units noted
above (e.g., FBC, stoker, wall-fired, tangential (T)-fired), there was
no significant difference in emissions that would justify
subcategorization. Because in the five cases different types of units
have different emission characteristics for one or more HAP, we have
determined that these types of units should be subcategorized.
Accordingly, we propose to subcategorize EGUs based on the five unit
types.
    For Hg emissions from coal-fired units, we have determined that
different emission limits for the two subcategories are warranted.
There were no EGUs designed to burn a nonagglomerating virgin coal
having a calorific value (moist, mineral matter-free basis) of 19,305
kJ/kg (8,300 Btu/lb) or less in an EGU with a height-to-depth ratio of
3.82 or greater among the top performing 12 percent of sources for Hg
emissions, indicating a difference in the emissions for this HAP from
these types of units. The boiler of a coal-fired EGU designed to burn
coal with that heat value is bigger than a boiler designed to burn
coals with higher heat values to account for the larger volume of coal
that must be combusted to generate the desired level of electricity.
Because the emissions of Hg are different between these two
subcategories, we are proposing to establish different Hg emission
limits for the two coal-fired subcategories. For all other HAP from
these two subcategories of coal-fired units, the data did not show any
difference in the level of the HAP emissions and, therefore, we have
determined that it is not reasonable to establish separate emissions
limits for the other HAP.
    For all HAP emissions from oil-fired units, we have determined that
two subcategories are warranted. EGUs designed to burn a solid fuel
(e.g., petroleum coke) derived from the refining of petroleum (oil) are
of a different design, and have different emissions, than those
designed to burn liquid oil. In addition, EGUs designed to burn liquid
oil cannot, in fact, accommodate the solid fuel derived from the
refining of oil. Thus, we are proposing to subcategorize oil-fired EGUs
into two subcategories based on the type of units designed to burn oil
in its different physical states.
    EGUs employing IGCC technology combust a synthetic gas derived from
solid coal or solid oil-derived fuel. No solid fuel is directly
combusted in the unit during operation (although a coal- or solid oil-
derived fuel is fired), and both the process and the emissions from
IGCC units are different from units that combust solid coal or
petroleum coke. Thus, we are proposing to subcategorize IGCC units as a
distinct type of EGU for this proposed rule. EPA solicits comment on
these subcategorization approaches.
    Additional subcategories have been evaluated, including those
suggested by the SERs serving on the SBAR established under the SBREFA.
These suggestions include subcategorization of lignite coal vs. other
coal ranks; subcategorization of Fort Union lignite coal vs. Gulf Coast
lignite coal vs. other coal ranks; subcategorization by EGU size (i.e.,
MWe); subcategorization of base load vs. peaking units (e.g., low
capacity utilization units); subcategorization of wall-fired vs. T-
fired units; and subcategorization of small, non-profit-owned units vs.
other units.
    EPA has reviewed the available data and does not believe that these
suggested approaches merit subcategorization. For example, there are
both large and small units among the EGUs comprising the top performing
12 percent of sources and small entities may own minor portions of
large EGUs and/or individual EGUs themselves. In addition, because the
proposed format of the standards is lb/MMBtu (or TBtu for Hg), the size
should only affect the rate at which a unit generates electricity and,
with a lower electricity generation rate, there is less fuel
consumption and, therefore, less emissions of fuel-borne HAP (i.e.,
acid gas and metal HAP). Further, with the exception of IGCC and as
noted elsewhere regarding boiler height-to-depth ratio, there is no
indication that EGU type (e.g., wall-fired, T-fired, FBC, stoker-
fired), has any impact on HAP emission levels as all of these types are
within the top performing 12 percent of sources. There is also little
indication that operating load has any significant impact on HAP
emissions or on the type of control demonstrated on the unit.
    EPA solicits comment on whether we should further subcategorize the
source category. In commenting, commenters should provide a definition
or threshold that would distinguish the proposed subcategory from the
remainder of the EGU population and, to support this distinction, an
estimate of how many EGUs would be impacted by the subcategorization
approach, the amount of time such impacted units operate, the extent to
which such impacted units would move out of and back into the
subcategory in a given year (or other period of time), and any other
information the commenter believes is pertinent. For example, if a
commenter were to suggest subcategorizing low capacity factor or
peaking units from the remainder of the EGU population, in addition to
the suggested threshold capacity factor, information on the number of
such units that would be impacted, the amount of time such units are
running (capacity utilization), the extent to which such units are low
capacity factor units in a given year vs. operating at a higher
capacity factor, and data from the units when operating both as peaking
units and as baseload units (among other information) would need to be
provided to support the comment. Commenters should further explain how
their suggested subcategorizations constitute a ``size,'' ``type,'' or
``class,'' as those terms are used in CAA section 112(d)(1).

B. How did EPA select the format for this proposed rule?

    This proposed rule includes numerical emission limitations for PM,
Hg, and HCl (as well as for other alternate constituents or groups).
Numerical emission limitations provide flexibility for the regulated
community, because they allow a regulated source to choose any control
technology, approach, or technique to meet the emission limitations,
rather than requiring each unit to use a prescribed control method that
may not be appropriate in each case.
    We are proposing numerical emission rate limitations as a mass of
pollutant emitted per heat energy input to the EGU for the fuel-borne
HAP for existing sources. The most typical units for the limitations
are lb/MMBtu of heat input (or, in the case of Hg, lb/TBtu). The mass
per heat input units are consistent with other Federal and many state
EGU regulations and allows easy comparison between such requirements.
Additionally, this proposed rule contains an option to monitor inlet
chlorine, fluorine, non-Hg metal, and Hg content in the liquid oil to
meet outlet emission rate limitations. This is reasonable because oil-
fired units may choose to remove these fuel-borne HAP from the oil
before combustion in lieu of installing air pollution control devices.
This option can only be done on a mass basis by liquid oil-fired EGUs.
We request comment on the viability of this approach for IGCC units.

    We are proposing numerical emission rate limitations as a mass of
pollutant emitted per megawatt- or gigawatt-hour (MWh or GWh) gross
output from the EGU for the fuel-borne HAP for new sources and as an
alternate format for existing sources. An outlet numerical emission
limit is also consistent with the format of other regulations (e.g.,
the EGU NSPS, 40 CFR part 60, subpart Da).
    EGUs can emit a wide variety of compounds, depending on the fuel
burned. Because of the large number of HAP potentially present and the
disparity in the quantity and quality of the emissions information
available, EPA grouped the HAP into five categories based on available
information about the pollutants and on experiences gained on other
NESHAP: Hg, non-Hg metallic HAP, inorganic (i.e., acid gas) HAP, non-
dioxin/furan organic HAP, and dioxin/furan organic HAP. The pollutants
within each group have similar characteristics and can be controlled
with the same techniques. For example, non-Hg metallic HAP can be
controlled with PM controls. We chose to look at Hg separately from
other metallic HAP due to its different chemical characteristics and
its different control technology feasibility.
    Next, EPA identified compounds that could be used as surrogates for
all the compounds in each pollutant category. Existing technologies
that have been installed to control emissions of other (e.g., criteria)
pollutants are expected to provide coincidental or ``co-benefit''
control of some of the HAP. For example, technologies for PM control
(e.g., ESP, FF) can effectively remove Hg that is bound to particulate
such as injected sorbents, unburned carbon, or other fly ash particles.
Similarly, PM control technologies are effective at reducing emissions
of the non-Hg metal HAP that are present in the fly ash as solid
particulate. Flue gas desulfurization technologies typically remove
SO2 using acid-base neutralization reactions (usually via
contact with alkaline solids or slurries). This approach is also
effective for other acid gases as well, including the acid gas HAP
(HCl, HF, Cl2, and HCN).
    EGUs routinely measure operating parameters (flow rates,
temperatures, pH, pressure drop, etc.) and flue gas composition for
process control and monitoring and for emission compliance and
verification. Some of these routinely or more easily-measured
parameters or components may serve as surrogates or indicators of the
level of control of one or more of the HAP that may not be easily or
routinely measured or monitored. The use of more easily-measured
components or process conditions as surrogates or predictors of HAP
emissions can greatly simplify monitoring requirements under this
proposed rule and, in some cases, provide more reliable results.
    In order to evaluate potential surrogacy relationships, the EPA
Office of Research and Development (ORD), in collaboration with OAR,
conducted a series of tests in the Agency's Multipollutant Control
Research Facility (MPCRF), a pilot-scale combustion and control
technology research facility located at EPA's Research Triangle Park
campus in North Carolina. The combustor is rated at 4 MMBtu/hr
(approximately 1.2 megawatt-thermal (MWt)). It is capable of
firing all ranks of pulverized coal, natural gas, and fuel oil. The
facility is equipped with low NOX burners and an SCR unit
for NOX control. The system can be configured to allow the
flue gas to flow through either an ESP or a FF for PM control. The
facility also uses a wet lime-based FGD scrubber for control of
SO2 emissions. The system is well equipped with CEMS for on-
line measurement of O2, CO2, NOX
(nitrogen oxide, NO, and nitrogen dioxide, NO2),
SO2, CO, Hg, and THC. There are multiple sampling ports
throughout the flue gas flow path. The facility is designed for ease of
modification so that various control technologies and configurations
can be tested. The facility has a series of heat exchangers to remove
heat such that the flow path of the flue gas has a similar time-
temperature profile to that seen in a typical full-scale coal-fired
EGU.
    Eleven independent tests were performed in the MPCRF in order to
examine potential surrogacy relationships. Three types of coal (eastern
bituminous, subbituminous, and Gulf Coast lignite) were tested. The PM
control was also varied; in some tests, the ESP was used whereas the FF
was used in others. Three potential surrogacy relationships were
examined during the testing program. The potential for use of PM
control as a surrogate for the control of the non-Hg metal HAP (Be, As,
Cd, Co, Cr, Mn, Ni, Pb, Sb, and Se) was examined. The potential for use
of HCl or SO2 control as a surrogate for other acid gases
(HCl, HF, Cl2) was studied. In addition, several potential
surrogate relationships were examined for the non-dioxin/furan organic
HAP. No surrogate studies were conducted for Hg; we have not identified
any surrogates for Hg and, thus, are regulating Hg directly. No
surrogacy studies were conducted for dioxin/furan organic HAP because
we believed the S:Cl ratio in the flue gas would be greater than 1.0,
meaning that the formation of dioxins/furans would be inhibited.
Moreover, it was anticipated that levels of these compounds would be
very low, and, as mentioned earlier in the preamble, the approved 2010
ICR sampling methods for dioxin/furan organic HAP required 8-hour
sampling periods; such a long sampling period was not practical in our
pilot system and would not be practical on a continuous basis.
    The results of the program indicated that the control of all non-Hg
metal HAP (except Se) was consistently similar to the control of the
bulk total PM (PMtotal). The average PMtotal
control during the tests was 99.5 percent. All of the non-Hg metal HAP
were controlled along with the PMtotal at levels greater
than 95 percent for measurements taken for particulate control using
both the ESP and the FF. Average control for the test series for each
of the metals was (for all coals and all configurations): Sb--95.3
percent; As--98.0 percent; Be--98.5 percent; Cd--98.7 percent; Cr--98.0
percent; Co--99.3 percent; Pb--99.2 percent; Mn--99.5 percent; and Ni--
97.6 percent.
    The results for Se control were less consistent. When subbituminous
coal was fired, the control of Se was consistently very good (average
98.9 percent), regardless of the PM control device being used. When
using the FF as the primary PM control device, the Se control was
consistently very good (average 99.2 percent) regardless of the coal
being fired. Control of Se when the ESP was the primary PM control
device was variable. When subbituminous coal was fired, the control of
Se through the ESP was greater than 99 percent. When lignite was fired,
the control through the ESP was about 80 percent. However, when the
eastern bituminous coal was fired, the Se control through the ESP
ranged from zero to 73 percent.
    The variability in the performance of Se control with coal rank and
PM control device can be explained by the known behavior and chemistry
of Se in the combustion and flue gas environments. Selenium is a
metalloid that sits just below sulfur on the periodic table and is,
chemically, very similar to sulfur. In the high temperature combustion
environment, Se is likely to be present as gas phase SeO2
(as, similarly, sulfur is likely to be present as gaseous
SO2). Much like SO2, SeO2 is a weak
acid gas. The testing in the pilot-scale combustion facility showed
that Se in the flue gas entering the PM control device tended to be
predominantly in the gas phase (55 to 90 percent) when firing eastern
bituminous coal and predominantly in the solid phase when firing
subbituminous coal (greater than 95

percent) and Gulf Coast lignite (80 percent). This is explained by the
large difference in calcium (Ca) content of those fuels. The ash from
the bituminous coal contained 1.4 weight percent Ca, whereas the ashes
from the subbituminous coal and Gulf Coast lignite contained Ca at 10.0
weight percent and 9.0 weight percent, respectively. The alkaline Ca in
the fly ash effectively neutralized the SeO2 acid gas,
forming a particulate that is easily removed in the PM control device.
The bituminous fuel contained insufficient free Ca to completely
neutralize the SeO2 and the much increased levels of
SO2 in that flue gas. The good performance through the FF
(regardless of the fuel being fired) can be attributed to the increased
contact between the gas stream and the filter cake on the FF. This
allows more of the SeO2 to adsorb or condense on fly ash
particles--either alkaline particles or unburned carbon. Because
SeO2 behaves very similarly to its sulfur analog,
SO2, it can be expected to also be removed effectively in
standard FGD technologies (wet scrubbers, dry scrubbers, DSI, etc.).
Therefore, Se will either fall in to the category of ``non-Hg metal
HAP'' and be effectively removed in a PM control device, or it will
fall into the category of ``acid gas HAP'' as gaseous SeO2
and be effectively removed using FGD technologies.
    Two of the 11 tests were specifically designated for testing of
surrogacy relationships relating to the acid gas HAP. Eastern
bituminous coal was fired and duct samples were taken upstream and
downstream of the lime-based wet FGD scrubber. Those tests showed, as
expected, very high levels of control for HCl (greater than 99.9
percent control). The control of HF was greater than 92 percent for the
first run and greater than 76 percent for the second run. The control
of Cl2 was greater than 76 percent for the first run and
greater than 92 percent for the second run. (Note that both of these
control efficiencies were likely much higher than the reported values
because the outlet measurements were below the MDL for both HF and
Cl2. The control efficiencies were calculated using the MDL
value.) The control efficiency for SO2 for the runs was
greater than 98 percent.
    Tests were also conducted to examine potential surrogacy
relationships for the non-dioxin/furan organic HAP. The amounts of Hg,
non-Hg metals, HCl, HF, and Cl2 in the flue gas are directly
related to the amounts of Hg, non-Hg metals, chlorine, and fluorine in
the coal. Control of these components generally requires downstream
control technology. However, the presence of the organics in the flue
gas is not related to the composition of the fuel but rather they are a
result of incomplete or poor combustion. Control of the organics is
often achieved by improving combustion conditions to minimize formation
or to maximize destruction of the organics in the combustion
environment.
    During the pilot-scale tests, sampling was conducted for semi-
volatile and volatile organic HAP and aldehydes. On-line monitors also
collected data on THC, CO, O2, and other processing
conditions. Total hydrocarbons and CO have been used previously as
surrogates for the presence of non-dioxin/furan organics. Carbon
monoxide has often been used as an indicator of combustion conditions.
Under conditions of ideal combustion, a carbon-based or hydrocarbon
fuel will completely oxidize to produce only CO2 and water.
Under conditions of incomplete or non-ideal combustion, a greater
amount of CO will be formed.
    With complex carbon-based fuels, combustion is rarely ideal and
some CO and concomitant organic compounds are expected to be formed.
Because CO and organics are both products of poor combustion, it is
logical to expect that limiting the concentration of CO would also
limit the production of organics. However, it is very difficult to
develop direct correlations between the average concentration of CO and
the amount of organics produced during the prescribed sampling period
in the MPCRF (which was 4 hours for the pilot-scale tests described
here). This is especially true for low values of CO as one would expect
corresponding low quantities of organics to be produced. Samples of
coal combustion flue gas have mostly shown very low quantities of the
organic compounds of interest. Some of the flue gas organics may also
be destroyed in the high temperature post combustion zone (whereas the
CO would remain stable). Semi-volatile organics may also condense on PM
and be removed in the PM control device.
    The average CO from the pilot-scale tests ranged from 23 to 137 ppm
for the bituminous coals tests, from 43 to 48 ppm for the subbituminous
coal tests and from 93 to 129 ppm for the Gulf Coast lignite tests.
However, it was difficult to correlate that concentration to the
quantity of organics produced for several reasons. The most difficult
problems are associated with the large number of potential organics
that can be produced (both those on the HAP list and those that are not
on the HAP list). This is further complicated by the organic compounds
tending to be at or below the MDL in coal combustion flue gas samples.
Further, there are complications associated with the CO concentration
values. Some of the runs with very similar average concentrations of CO
had very different maximum concentrations of CO (i.e., some of the runs
had much more stable emissions of CO whereas others had some
excursions, or ``spikes,'' in CO concentration). For example, one of
the bituminous runs had an average CO concentration of 69 ppm but a
maximum concentration of 1,260 ppm (due to a single ``spike'' of CO
during a short upset). Comparatively, another bituminous run had a
higher average CO concentration at 137 ppm but a much lower maximum CO
value at 360 ppm.
    In the pilot tests, the THC measurement was inadequate as the
detection limit of the instrument was much too high to detect changes
in the very low concentrations of hydrocarbons in the flue gas.
    Based on the testing described above and the emissions data
received under the 2010 ICR, we are proposing surrogate standards for
the non-Hg metallic HAP and the non-metallic inorganic (acid gas) HAP.
For the non-Hg metallic HAP, we chose to use PM as a surrogate. Most,
if not all, non-Hg metallic HAP emitted from combustion sources will
appear on the flue gas fly-ash. Therefore, the same control techniques
that would be used to control the fly-ash PM will control non-Hg
metallic HAP. PM was also chosen instead of specific metallic HAP
because all fuels do not emit the same type and amount of metallic HAP
but most generally emit PM that includes some amount and combination of
all the metallic HAP. The use of PM as a surrogate will also eliminate
the cost of performance testing to comply with numerous standards for
individual non-Hg metals. Because non-Hg metallic HAP may
preferentially partition to the small size particles (i.e., fine
particle enrichment), we considered using PM2.5 as the
surrogate, but we determined that total PM (filterable (i.e.,
PM2.5) plus condensable) was the more appropriate surrogate
for two reasons. The test method (201A) for measuring PM2.5
is only applicable for use in exhaust stacks without entrained water
droplets. Therefore, the test method for measuring PM2.5 is
not applicable for units equipped with wet scrubbers which are in use
at many EGUs today and may be necessary at some additional units to
achieve the proposed HCl emission limitations. Thus, we are proposing
to use total PM, instead of PM2.5, as the surrogate for non-
Hg metals. However, as discussed elsewhere, we are also proposing

alternative individual non-Hg metallic HAP emission limitations as well
as total non-Hg metallic HAP emission limitations for all subcategories
(total metal HAP emission limitation for the liquid oil-fired
subcategory).
    For non-metallic inorganic (acid gas) HAP, EPA is proposing setting
an HCl standard and using HCl as a surrogate for the other non-metallic
inorganic HAP for all subcategories except the liquid oil-fired
subcategory. The emissions test information available to EPA indicate
that the primary non-metallic inorganic HAP emitted from EGUs are acid
gases, with HCl present in the largest amounts. Other inorganic
compounds emitted are found in smaller quantities. As discussed
earlier, control technologies that reduce HCl indiscriminately control
other inorganic compounds such as Cl2 and other acid gases
(e.g., HF, HCN, SeO2). Thus, the best controls for HCl are
also the best controls for other inorganic acid gas HAP. Therefore, HCl
is a good surrogate for inorganic HAP because controlling HCl will
result in control of other inorganic HAP emissions (as no liquid oil-
fired EGU has an FGD system installed, there is no effective control in
use and the surrogacy argument is invalid). As discussed elsewhere, EPA
is also proposing to set an alternative equivalent SO2
emission limit for coal-fired EGUs with some form of FGD system
installed as: (1) The controls for SO2 are also effective
controls for HCl and the other acid gas-HAP; and (2) most, if not all,
EGUs already have SO2 CEMS in-place. Thus, SO2
CEMS could serve as the compliance monitoring mechanism for such units.
EGUs without an FGD system installed would not be able to use the
alternate SO2 emission limit, and EGUs must operate their
FGD at all times to use the alternate SO2 emission limit.
    EPA is proposing work practice standards for non-dioxin/furan
organic and dioxin/furan organic HAP. The significant majority of
measured emissions from EGUs of these HAP were below the detection
levels of the EPA test methods, and, as such, EPA considers it
impracticable to reliably measure emissions from these units. As the
majority of measurements are so low, doubt is cast on the true levels
of emissions that were measured during the tests. Overall, 1,552 out of
2,334, total test runs for dioxin/furan organic HAP contained data
below the detection level for one or more congeners, or 67 percent of
the entire data set. In several cases, all of the data for a given run
were below the detection level; in few cases were the data for a given
run all above the detection level. For the non-dioxin/furan organic
HAP, for the individual HAP or constituent, between 57 and 89 percent
of the run data were comprised of values below the detection level.
Overall, the available test methods are technically challenged, to the
point of providing results that are questionable for all of the organic
HAP. For example, for the 2010 ICR testing, EPA extended the sampling
time to 8 hours in an attempt to obtain data above the MDL. However,
even with this extended sampling time, such data were not obtained
making it questionable that any amount of effort, and, thus, expense,
would make the tests viable. Based on the difficulties with accurate
measurements at the levels of organic HAP encountered from EGUs and the
economics associated with units trying to apply measurement methodology
to test for compliance with numerical limits, we are proposing a work
practice standard under CAA section 112(h).
    We do not believe that this approach is inconsistent with that
taken on other NESHAP where we also had issues with data at or below
the MDL (e.g., Portland Cement NESHAP; Boiler NESHAP). In the case of
the Portland Cement NESHAP, the MDL issue was with HCl (a single
compound HAP as opposed to the oftentimes multi-congener organic HAP),
and in data from only 3 of 21 facilities. As noted elsewhere in this
preamble, we dealt with similar MDL issues with HCl in establishing the
limits in this proposed rule. In the case of the Boiler NESHAP, the MDL
issue was with the organic HAP. For that rulemaking, the required
sampling time during conducting of the associated ICR was 4 hours, as
opposed to the 8 hours required in the 2010 ICR. Further, a review of
the data indicates that the dioxin/furan HAP levels (a component of the
organic HAP) were at least 7 times greater, on average, for coal-fired
IB units and 3 times greater, on average, for oil-fired IB units than
from similar EGUs. We think this difference is significant from a
testing feasibility perspective.
    For all the other HAP, as stated above, we are proposing to
establish numerical emission rate limitations; however, we did consider
using a percent reduction format for Hg (e.g., the percent efficiency
of the control device, the percent reduction over some input amount,
etc.). We determined not to propose a percent reduction standard for
several reasons. The percent reduction format for Hg and other HAP
emissions would not have addressed EPA's desire to promote, and give
credit for, coal preparation practices that remove Hg and other HAP
before firing (i.e., coal washing or beneficiation, actions that may be
taken at the mine site rather than at the site of the EGU). Also, to
account for the coal preparation practices, sources would be required
to track the HAP concentrations in coal from the mine to the stack, and
not just before and after the control device(s), and such an approach
would be difficult to implement and enforce. In addition, we do not
have the data necessary to establish percent reduction standards for
HAP at this time. Depending on what was considered to be the ``inlet''
and the degree to which precombustion removal of HAP was desired to be
included in the calculation, EPA would need (e.g.) the HAP content of
the coal as it left the mine face, as it entered the coal preparation
facility, as it left the coal preparation facility, as it entered the
EGU, as it entered the control devices, and as it left the stack to be
able to establish percent reduction standards. EPA believes, however,
that an emission rate format allows for, and promotes, the use of
precombustion HAP removal processes because such practices will help
sources assure they will comply with the proposed standard.
Furthermore, a percent reduction requirement would limit the
flexibility of the regulated community by requiring the use of a
control device. In addition, as discussed in the Portland Cement NESHAP
(75 FR 55,002; September 9, 2010), EPA believes that a percent
reduction format negates the contribution of HAP inputs to EGU
performance and, thus, may be inconsistent with the DC Circuit Court's
rulings as restated in Brick MACT (479 F.3d at 880) that say, in
effect, that it is the emissions achieved in practice (i.e., emissions
to the atmosphere) that matter, not how one achieves those emissions.
The 2010 ICR data confirm the point relating to plant inputs likely
playing a role in emissions in that they indicate that some EGUs are
achieving lower Hg emissions to the atmosphere at a lower Hg percent
reduction (e.g., 75 to 85 percent) than are other EGUs with higher
percent reductions (e.g., 90 percent or greater). For all of these
reasons, we are proposing to establish numerical emission standards for
HAP emissions from EGUs with the exception of the organic HAP standard
which is in the form of work practices.

C. How did EPA determine the proposed emission limitations for existing
EGUs?

    All standards established pursuant to CAA section 112(d)(2) 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. For existing sources, MACT
cannot be less stringent than the average emission limitation achieved