desulfurization technology,'' ``emission rate period,'' and
``responsible official'' to read as follows:

Sec.  61.41Da  Definitions.

* * * * *
    Affirmative defense means, 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.
* * * * *
    Gaseous fuel means any fuel that is present as a gas at standard
conditions and includes, but is not limited to, natural gas, refinery
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
* * * * *
    Integrated gasification combined cycle electric utility steam
generating unit or IGCC electric utility steam generating unit means an
electric utility combined cycle gas turbine that is designed to burn
fuels containing 50 percent (by heat input) or more solid-derived fuel
not meeting the definition of natural gas. The Administrator may waive
the 50 percent solid-derived fuel requirement during periods of the
gasification system construction or repair. No solid fuel is directly
burned in the unit during operation.
* * * * *

    Petroleum for facilities constructed, reconstructed, or modified
before May 4, 2011, means crude oil or a fuel derived from crude oil,
including, but not limited to, distillate oil, and residual oil. For
units constructed, reconstructed, or modified after May 3, 2011,
Petroleum means crude oil or a fuel derived from crude oil, including,
but not limited to, distillate oil, residual oil, and petroleum coke.
* * * * *
    Petroleum Coke, also known as petcoke, means a carbonization
product of high-boiling hydrocarbon fractions obtained in petroleum
processing (heavy residues). Petroleum coke is typically derived from
oil refinery coker units or other cracking processes.
* * * * *
    Steam generating unit for facilities constructed, reconstructed, or
modified before May 4, 2011, means any furnace, boiler, or other device
used for combusting fuel for the purpose of producing steam (including
fossil-fuel-fired steam generators associated with combined cycle gas
turbines; nuclear steam generators are not included). For units
constructed, reconstructed, or modified after May 3, 2011, Steam
generating unit means any furnace, boiler, or other device used for
combusting fuel for the purpose of producing steam (including fossil-
fuel-fired steam generators associated with combined cycle gas
turbines; nuclear steam generators are not included) plus any
integrated combustion turbines and fuel cells.
* * * * *
    11. Revise Sec.  60.42Da to read as follows:

Sec.  60.42Da  Standard for particulate matter (PM).

    (a) Except as provided in paragraph (a)(4) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec.  60.8, whichever date comes first,
an owner or operator of an affected facility shall not cause to be
discharged into the atmosphere from any affected facility for which
construction, reconstruction, or modification commenced before March 1,
2005, any gases that contain filterable PM in excess of:
    (1) 13 ng/J (0.03 lb/MMBtu) heat input;
    (2) 1 percent of the potential combustion concentration (99 percent
reduction) when combusting solid fuel; and
    (3) 30 percent of potential combustion concentration (70 percent
reduction) when combusting liquid fuel.
    (4) An owner or operator of an affected facility that combusts only
gaseous or liquid fuels (excluding residual oil) with potential
SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and
does not use a post-combustion technology to reduce emissions of
SO2 or PM is exempt from the PM standard specified in
paragraphs (a)(1), (a)(2), and (a)(3) of this section:
    (b) Except as provided in paragraphs (b)(1) and (b)(2) of this
section, on and after the date the initial PM performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, an owner or operator of an affected facility shall not
cause to be discharged into the atmosphere any gases which exhibit
greater than 20 percent opacity (6-minute average), except for one 6-
minute period per hour of not more than 27 percent opacity.
    (1) Owners and operators of an affected facility that elect to
install, calibrate, maintain, and operate a continuous emissions
monitoring system (CEMS) for measuring PM emissions according to the
requirements of this subpart are exempt from the opacity standard
specified in this paragraph (b) of this section.
    (2) An owner or operator of an affected facility that combusts only
natural gas is exempt from the opacity standard specified in paragraph
(b) of this section.
    (c) Except as provided in paragraphs (d) and (e) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification after February
28, 2005, but before May 4, 2011, shall cause to be discharged into the
atmosphere from that affected facility any gases that contain
filterable PM in excess of either:
    (1) 18 ng/J (0.14 lb/MWh) gross energy output; or
    (2) 6.4 ng/J (0.015 lb/MMBtu) heat input.
    (d) As an alternative to meeting the requirements of paragraph (c)
of this section, the owner or operator of an affected facility for
which construction, reconstruction, or modification commenced after
February 28, 2005, but before May 4, 2011, may elect to meet the
requirements of this paragraph. For an affected facility that commenced
construction, reconstruction, or modification, on and after the date on
which the initial performance test is completed or required to be
completed under Sec.  60.8, whichever date comes first, no owner or
operator shall cause to be discharged into the atmosphere from that
affected facility any gases that contain filterable PM in excess of:
    (1) 13 ng/J (0.030 lb/MMBtu) heat input, and
    (2) For an affected facility that commenced construction or
reconstruction, 0.1 percent of the combustion concentration determined
according to the procedure in Sec.  60.48Da(o)(5) (99.9 percent
reduction) when combusting solid, liquid, or gaseous fuel, or
    (3) For an affected facility that commenced modification, 0.2
percent of the combustion concentration determined according to the
procedure in Sec.  60.48Da(o)(5) (99.8 percent reduction) when
combusting solid, liquid, or gaseous fuel.
    (e) An owner or operator of an affected facility than combusts only
gaseous or liquid fuels (excluding residual oil) with potential
SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and
that does not use a post-combustion technology to reduce emissions of
SO2 or PM is exempt from the PM standard specified in
paragraphs (c) of this section.
    (f) Except as provided in paragraph (g) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec.  60.8, whichever date comes first,
no owner or operator of an affected facility that commenced
construction, modification, or reconstruction after May 3, 2011, shall
cause to be discharged into the atmosphere from that affected facility
any gases that contain total PM in excess of either:
    (1) For an affected facility that commenced construction or
reconstruction 7.0 ng/J (0.055 lb/MWh) gross energy output; or
    (2) For an affected facility that commenced modification, 15 ng/J
(0.034 lb/MMBtu) heat input.
    (g) An owner or operator of an affected facility that combusts only
natural gas is exempt from the total PM standard specified in paragraph
(f) of this section.
    (h) The PM emission standards under this section do not apply to an
owner or operator of any affected facility that is operated under a PM
commercial demonstration permit issued by the Administrator in
accordance with the provisions of Sec.  60.47Da.
    12. Section 60.43Da is amended as follows:
    a. By revising paragraphs (a)(1) through (a)(3).
    b. By revising paragraph (f).
    c. By revising paragraph (i).
    d. By revising paragraph (j).
    e. By revising paragraph (k).

    f. By adding paragraph (a)(4).
    g. By adding paragraph (l).
    h. By adding paragraph (m).
    i. By adding paragraph (n).

Sec.  60.43Da  Standard for sulfur dioxide (SO2).

    (a) * * *
    (1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the
potential combustion concentration (90 percent reduction);
    (2) 30 percent of the potential combustion concentration (70
percent reduction), when emissions are less than 260 ng/J (0.60 lb/
MMBtu) heat input;
    (3) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (4) 65 ng/J (0.15 lb/MMBtu) heat input.
* * * * *
    (f) The SO2 standards under this section do not apply to
an owner or operator of an affected facility that is operated under an
SO2 commercial demonstration permit issued by the
Administrator in accordance with the provisions of Sec.  60.47Da.
* * * * *
    (i) Except as provided in paragraphs (j) and (k) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification commenced after
February 28, 2005, but before May 4, 2011, shall cause to be discharged
into the atmosphere from that affected facility, any gases that contain
SO2 in excess of the applicable emission limitation
specified in paragraphs (i)(1) through (3) of this section.
    (1) For an affected facility which commenced construction, any
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 5 percent of the potential combustion concentration (95
percent reduction).
    (2) For an affected facility which commenced reconstruction, any
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
    (iii) 5 percent of the potential combustion concentration (95
percent reduction).
    (3) For an affected facility which commenced modification, any
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
    (iii) 10 percent of the potential combustion concentration (90
percent reduction).
    (j) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification commenced after
February 28, 2005, but before May 4, 2011, and that burns 75 percent or
more (by heat input) coal refuse on a 12-month rolling average basis,
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of the
applicable emission limitation specified in paragraphs (j)(1) through
(3) of this section.
    (1) For an affected facility which commenced construction, any
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 6 percent of the potential combustion concentration (94
percent reduction).
    (2) For an affected facility which commenced reconstruction, any
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
    (iii) 6 percent of the potential combustion concentration (94
percent reduction).
    (3) For an affected facility which commenced modification, any
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output;
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or
    (iii) 10 percent of the potential combustion concentration (90
percent reduction).
    (k) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility located in a
noncontinental area that commenced construction, reconstruction, or
modification commenced after February 28, 2005, but before May 4, 2011,
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of the
applicable emission limitation specified in paragraphs (k)(1) and (2)
of this section.
    (1) For an affected facility that burns solid or solid-derived
fuel, the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 520 ng/J
(1.2 lb/MMBtu) heat input.
    (2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged
into the atmosphere any gases that contain SO2 in excess of
230 ng/J (0.54 lb/MMBtu) heat input.
    (l) Except as provided in paragraphs (m) and (n) of this section,
on and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification commenced after
May 3, 2011, shall cause to be discharged into the atmosphere from that
affected facility, any gases that contain SO2 in excess of
the applicable emission limitation specified in paragraphs (l)(1) or
(2) of this section.
    (1) For an affected facility which commenced construction or
reconstruction, any gases that contain SO2 in excess of
either:
    (i) 130 ng/J (1.0 lb/MWh) gross energy output; or
    (ii) 3 percent of the potential combustion concentration (97
percent reduction).
    (2) For an affected facility which commenced modification, any
gases that contain SO2 in excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 10 percent of the potential combustion concentration (90
percent reduction).
    (m) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification commenced after
May 3, 2011, and that burns 75 percent or more (by heat input) coal
refuse on a 12-month rolling average basis, shall caused to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the applicable emission
limitation specified in paragraphs (m)(1) or (2) of this section.
    (1) For an affected facility which commenced construction or
reconstruction, any gases that contain SO2 in excess of
either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 6 percent of the potential combustion concentration (94
percent reduction).
    (2) For an affected facility which commenced modification, any
gases that contain SO2 in excess of either:

    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 10 percent of the potential combustion concentration (90
percent reduction).
    (n) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility located in a
noncontinental area that commenced construction, reconstruction, or
modification commenced after May 3, 2011, shall cause to be discharged
into the atmosphere from that affected facility any gases that contain
SO2 in excess of the applicable emission limitation
specified in paragraphs (n)(1) and (2) of this section.
    (1) For an affected facility that burns solid or solid-derived
fuel, the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain SO2 in excess of 520 ng/J
(1.2 lb/MMBtu) heat input.
    (2) For an affected facility that burns other than solid or solid-
derived fuel, the owner or operator shall not cause to be discharged
into the atmosphere any gases that contain SO2 in excess of
230 ng/J (0.54 lb/MMBtu) heat input.
    13. Section 60.44Da is amended:
    a. By revising paragraph (a) introductory text.
    b. By revising paragraph (b).
    c. By revising paragraph (d).
    d. By revising paragraph (e).
    e. By revising paragraph (f).
    f. By adding paragraph (g).
    g. By adding paragraph (h).

Sec.  60.44Da  Standard for nitrogen oxides (NO).

    (a) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator subject to the provisions of this
subpart shall cause to be discharged into the atmosphere from any
affected facility, except as provided under paragraphs (b), (d), (e),
and (f) of this section, any gases that contain NOX
(expressed as NO2) in excess of the following emission
limits:
* * * * *
    (b) The NOX emission limitations under this section do
not apply to an owner or operator of an affected facility which is
operating under a commercial demonstration permit issued by the
Administrator in accordance with the provisions of Sec.  60.47Da.
    (d)(1) On and after the date on which the initial performance test
is completed or required to be completed under Sec.  60.8, whichever
date comes first, no owner or operator of an affected facility that
commenced construction after July 9, 1997, but before March 1, 2005
shall cause to be discharged into the atmosphere any gases that contain
NOX (expressed as NO2) in excess of 200 ng/J (1.6
lb/MWh) gross energy output, except as provided under Sec.  60.48Da(k).
    (2) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of affected facility for which
reconstruction commenced after July 9, 1997, but before March 1, 2005
shall cause to be discharged into the atmosphere any gases that contain
NOX (expressed as NO2) in excess of 65 ng/J (0.15
lb/MMBtu) heat input.
    (e) Except as provided in paragraph (f) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec.  60.8, whichever date comes first,
no owner or operator of an affected facility that commenced
construction, reconstruction, or modification after February 28, 2005
but before May 4, 2011, shall cause to be discharged into the
atmosphere from that affected facility any gases that contain
NOX (expressed as NO2) in excess of the
applicable emission limitation specified in paragraphs (e)(1) through
(3) of this section.
    (1) For an affected facility which commenced construction, any
gases that contain NOX (expressed as NO2) in
excess of 130 ng/J (1.0 lb/MWh) gross energy output, except as provided
under Sec.  60.48Da(k).
    (2) For an affected facility which commenced reconstruction, any
gases that contain NOX (expressed as NO2) in
excess of either:
    (i) 130 ng/J (1.0 lb/MWh) gross energy output; or
    (ii) 47 ng/J (0.11 lb/MMBtu) heat input.
    (3) For an affected facility which commenced modification, any
gases that contain NOX (expressed as NO2) in
excess of either:
    (i) 180 ng/J (1.4 lb/MWh) gross energy output; or
    (ii) 65 ng/J (0.15 lb/MMBtu) heat input.
    (f) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, the owner or operator of an IGCC electric utility steam
generating unit subject to the provisions of this subpart and for which
construction, reconstruction, or modification commenced after February
28, 2005 but before May 4, 2011, shall meet the requirements specified
in paragraphs (f)(1) through (3) of this section.
    (1) Except as provided for in paragraphs (f)(2) and (3) of this
section, the owner or operator shall not cause to be discharged into
the atmosphere any gases that contain NOX (expressed as
NO2) in excess of 130 ng/J (1.0 lb/MWh) gross energy output.
    (2) When burning liquid fuel exclusively or in combination with
solid-derived fuel such that the liquid fuel contributes 50 percent or
more of the total heat input to the combined cycle combustion turbine,
the owner or operator shall not cause to be discharged into the
atmosphere any gases that contain NOX (expressed as
NO2) in excess of 190 ng/J (1.5 lb/MWh) gross energy output.
    (3) In cases when during a 30 boiler operating day rolling average
compliance period liquid fuel is burned in such a manner to meet the
conditions in paragraph (f)(2) of this section for only a portion of
the clock hours in the 30-day period, the owner or operator shall not
cause to be discharged into the atmosphere any gases that contain
NOX (expressed as NO2) in excess of the computed
weighted-average emissions limit based on the proportion of gross
energy output (in MWh) generated during the compliance period for each
of emissions limits in paragraphs (f)(1) and (2) of this section.
    (g) Compliance with the emission limitations under this section are
determined on a 30-boiler operating day rolling average basis, except
as provided under Sec.  60.48Da(j)(1).
    (h) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification after May 3,
2011, shall cause to be discharged into the atmosphere from that
affected facility any gases that contain NOX (expressed as
NO2) in excess of 88 ng/J (0.70 lb/MWh) gross energy output.

Sec.  60.45Da  [Removed and Reserved]

    14. Remove and reserve Sec.  60.45Da.
    15. Section 60.47Da is amended as follows:
    a. By adding paragraph (f).
    b. By adding paragraph (g).
    c. By adding paragraph (h).
    d. By adding paragraph (i).
Section 60.47Da Commercial demonstration permit.
* * * * *
    (f) An owner or operator of an affected facility that uses a
pressurized fluidized bed or a multi-pollutant emissions controls
system who is issued a

commercial demonstration permit by the Administrator is not subject to
the total PM emission reduction requirements under Sec.  60.42Da but
must, as a minimum, reduce PM emissions to less than 15 ng/J (0.034 lb/
MMBtu) heat input.
    (g) An owner or operator of an affected facility that uses a
pressurized fluidized bed or a multi-pollutant emissions controls
system who is issued a commercial demonstration permit by the
Administrator is not subject to the SO2 standards or
emission reduction requirements under Sec.  60.43Da but must, as a
minimum, reduce SO2 emissions to 5 percent of the potential
combustion concentration (95 percent reduction) or to less than 180 ng/
J (1.4 lb/MWh) gross output on a 30 boiler operating day rolling
average basis.
    (h) An owner or operator of an affected facility that uses a
pressurized fluidized bed or a multi-pollutant emissions controls
system or advanced combustion controls who is issued a commercial
demonstration permit by the Administrator is not subject to the
NOX standards or emission reduction requirements under Sec.
60.44Da but must, as a minimum, reduce NOX emissions to less
than 130 ng/J (1.0 lb/MWh) gross output on a 30 boiler operating day
rolling average basis.
    (i) Commercial demonstration permits may not exceed the following
equivalent MW electrical generation capacity for any one technology
category.

------------------------------------------------------------------------
                                                           Equivalent
                                                           electrical
          Technology                  Pollutant           capacity (MW
                                                           electrical
                                                             output)
------------------------------------------------------------------------
Multi-pollutant Emission       SO2....................             1,000
 Control.
Multi-pollutant Emission       NOX....................             1,000
 Control.
Multi-pollutant Emission       PM.....................             1,000
 Control.
Pressurized Fluidized Bed      SO2....................             1,000
 Combustion.
Pressurized Fluidized Bed      NOX....................             1,000
 Combustion.
Pressurized Fluidized Bed      PM.....................             1,000
 Combustion.
Advanced Combustion Controls.  NOX....................             1,000
------------------------------------------------------------------------

    16. Section 60.48Da is amended as follows:
    a. By revising paragraph (c).
    b. By revising paragraph (g).
    c. By revising paragraph (k)(1)(i).
    d. By revising paragraph (k)(1)(ii).
    e. By revising paragraph (k)(2)(i).
    f. By revising paragraph (k)(2)(iv).
    g. By removing and reserving paragraph (l).
    h. By revising paragraph (n).
    i. By revising paragraphs (p)(5), (p)(7), and (p)(8).
    j. By adding paragraph (r).
Section 60.48a Compliance provisions.
* * * * *
    (c) For affected facilities that commenced construction,
modification, or reconstruction before May 4, 2011, the PM emission
standards under Sec.  60.42Da, and the NOX emission
standards under Sec.  60.44Da apply at all times except during periods
of startup, shutdown, or malfunction. The sulfur dioxide emission
standards under Sec.  60.43Da apply at all times except during periods
of startup, shutdown, or when both emergency conditions exist and the
procedures under paragraph (d) of this section are implemented. For
affected facilities that commence construction, modification, or
reconstruction after May 3, 2011, the PM emission standards under Sec.
60.42Da, the NOX emission standards under Sec.  60.44Da, and
the sulfur dioxide emission standards under Sec.  60.43Da apply at all
times.
* * * * *
    (g) The owner or operator of an affected facility subject to
emission limitations in this subpart shall determine compliance as
follows:
    (1) For affected facilities that commenced construction,
modification, or reconstruction before May 4, 2011, compliance with
applicable 30 boiler operating day rolling average SO2 and
NOX emission limitations is determined by calculating the
arithmetic average of all hourly emission rates for SO2 and
NOX for the 30 successive boiler operating days, except for
data obtained during startup, shutdown, malfunction (NOX
only), or emergency conditions (SO2 only). For affected
facilities that commence construction, modification, or reconstruction
after May 3, 2011, compliance with applicable 30 boiler operating day
rolling average SO2 and NOX emission limitations
is determined by dividing the sum of all the SO2 and
NOX emissions for the 30 successive boiler operating days
divided by the sum of all the gross useful output for the 30 successive
boiler operating days.
    (2) For affected facilities that commenced construction,
modification, or reconstruction before May 4, 2011, compliance with
applicable SO2 percentage reduction requirements is
determined based on the average inlet and outlet SO2
emission rates for the 30 successive boiler operating days. For
affected facilities that commence construction, modification, or
reconstruction after May 3, 2011, compliance with applicable
SO2 percentage reduction requirements is determined based on
the ``as fired'' total potential emissions and the total outlet
SO2 emissions for the 30 successive boiler operating days.
    (3) For affected facilities that commenced construction,
modification, or reconstruction before May 4, 2011 compliance with
applicable daily average PM emission limitations is determined by
calculating the arithmetic average of all hourly emission rates for PM
each boiler operating day, except for data obtained during startup,
shutdown, and malfunction. For affected facilities that commence
construction, modification, or reconstruction after May 3, 2011,
compliance with applicable daily average PM emission limitations is
determined by calculating the sum of all PM emissions for PM each
boiler operating day divided by the sum of all the gross useful output
for PM each boiler operating day, except for data obtained during
malfunction. Averages are only calculated for boiler operating days
that have non-out-of-control data for at least 18 hours of unit
operation during which the standard applies. Instead, all of the non-
out-of-control hourly emission rates of the operating day(s) not
meeting the minimum 18 hours non-out-of-control data daily average
requirement are averaged with all of the non-out-of-control hourly
emission rates of the next boiler operating day with 18 hours or more
of non-out-of-control PM CEMS data to determine compliance.
* * * * *
    (k) * * *
    (1) * * *
    (i) The emission rate (E) of NOX shall be computed using
Equation 2 in this section:

[GRAPHIC] [TIFF OMITTED] TP03MY11.012

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross output;
Csg = Average hourly concentration of NOX
exiting the steam generating unit, ng/dscm (lb/dscf);
Cte = Average hourly concentration of NOX in
the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas
from steam generating unit, dscm/hr (dscf/hr);
Qte = Average hourly volumetric flow rate of exhaust gas
from combustion turbine, dscm/hr (dscf/hr);
Osg = Average hourly gross energy output from steam
generating unit, J/h (MW); and
h = Average hourly fraction of the total heat input to the steam
generating unit derived from the combustion of fuel in the affected
duct burner.
* * * * *
    (2) * * *
    (i) The emission rate (E) of NOX shall be computed using
Equation 3 in this section:
[GRAPHIC] [TIFF OMITTED] TP03MY11.013

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross output;
Csg = Average hourly concentration of NOX
exiting the steam generating unit, ng/dscm (lb/dscf);
Qsg = Average hourly volumetric flow rate of exhaust gas
from steam generating unit, dscm/hr (dscf/hr); and
Occ = Average hourly gross energy output from entire
combined cycle unit, J/h (MW).
* * * * *
    (iv) The owner or operator may, in lieu of installing, operating,
and recording data from the continuous flow monitoring system specified
in Sec.  60.49Da(l), determine the mass rate (lb/hr) of NOX
emissions by installing, operating, and maintaining continuous fuel
flowmeters following the appropriate measurements procedures specified
in appendix D of part 75 of this chapter. If this compliance option is
selected, the emission rate (E) of NOX shall be computed
using Equation 4 in this section:
[GRAPHIC] [TIFF OMITTED] TP03MY11.014

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross output;
ERsg = Average hourly emission rate of NOX
exiting the steam generating unit heat input calculated using
appropriate F factor as described in Method 19 of appendix A of this
part, ng/J (lb/MMBtu);
Hcc = Average hourly heat input rate of entire combined
cycle unit, J/hr (MMBtu/hr); and
Occ = Average hourly gross energy output from entire
combined cycle unit, J/h (MW).
* * * * *
    (n) Compliance provisions for sources subject to Sec.
60.42Da(c)(1). The owner or operator of an affected facility subject to
Sec.  60.42Da(c)(1) shall calculate PM emissions by multiplying the
average hourly PM output concentration (measured according to the
provisions of Sec.  60.49Da(t)), by the average hourly flow rate
(measured according to the provisions of Sec.  60.49Da(l) or Sec.
60.49Da(m)), and divided by the average hourly gross energy output
(measured according to the provisions of Sec.  60.49Da(k)).
* * * * *
    (p) * * *
    (5) At a minimum, non-out-of-control valid CEMS hourly averages
shall be obtained for 75 percent of all operating hours on a 30 boiler
operating day rolling average basis. Beginning on January 1, 2012, non-
out-of-control CEMS hourly averages shall be obtained for 90 percent of
all operating hours on a 30 boiler operating day rolling average basis.
    (i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
    (ii) [Reserved]
* * * * *
    (7) All non-out-of-control CEMS data shall be used in calculating
average emission concentrations even if the minimum CEMS data
requirements of paragraph (j)(5) of this section are not met.
    (8) When PM emissions data are not obtained because of CEMS
breakdowns, repairs, calibration checks, and zero and span adjustments,
emissions data shall be obtained by using other monitoring systems as
approved by the Administrator to provide, as necessary, non-out-of-
control emissions data for a minimum of 90 percent (only 75 percent is
required prior to January 1, 2012) of all operating hours per 30 boiler
operating day rolling average.
* * * * *
    (r) Affirmative Defense for Exceedance of Emission Limit During
Malfunction. In response to an action to enforce the standards set
forth in paragraph Sec. Sec.  60.42Da, 60.43Da, and 60.44Da, you may
assert an affirmative defense to a claim for civil penalties for
exceedances of such standards that are caused by malfunction, as
defined at 40 CFR 60.2. Appropriate penalties may be assessed, however,
if you fail to meet your burden of proving all of the requirements in
the affirmative defense. The affirmative defense shall not be available
for claims for injunctive relief.
    (1) To establish the affirmative defense in any action to enforce
such a limit, you must timely meet the notification requirements in
paragraph (b) of this section, and must prove by a preponderance of
evidence that:
    (i) The excess emissions:
    (A) Were 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, and
    (B) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
    (C) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
    (D) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
    (ii) Repairs were made as expeditiously as possible when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable to make these
repairs; and
    (iii) The frequency, amount and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions; and
    (iv) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage; and
    (v) All possible steps were taken to minimize the impact of the
excess emissions on ambient air quality, the environment and human
health; and
    (vi) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
    (vii) All of the actions in response to the excess emissions were
documented by properly signed, contemporaneous operating logs; and
    (viii) At all times, the facility was operated in a manner
consistent with good practices for minimizing emissions; and
    (ix) A written root cause analysis has been prepared, the purpose
of which is to determine, correct, and eliminate the primary causes of
the malfunction and the excess emissions resulting from the malfunction
event at issue. The analysis shall also specify, using best monitoring

methods and engineering judgment, the amount of excess emissions that
were the result of the malfunction.
    (2) The owner or operator of the facility experiencing an
exceedance of its emission limit(s) during a malfunction shall notify
the Administrator by telephone or facsimile (FAX) transmission as soon
as possible, but no later than two business days after the initial
occurrence of the malfunction, if it wishes to avail itself of an
affirmative defense to civil penalties for that malfunction. The owner
or operator seeking to assert an affirmative defense shall also submit
a written report to the Administrator within 45 days of the initial
occurrence of the exceedance of the standards in Sec. Sec.  60.42Da,
60.43Da, and 60.44Da to demonstrate, with all necessary supporting
documentation, that it has met the requirements set forth in paragraph
(a) of this section. The owner or operator may seek an extension of
this deadline for up to 30 additional days by submitting a written
request to the Administrator before the expiration of the 45 day
period. Until a request for an extension has been approved by the
Administrator, the owner or operator is subject to the requirement to
submit such report within 45 days of the initial occurrence of the
exceedance.
    17. Section 60.49Da is amended as follows:
    a. By revising paragraphs (a)(1), (a)(2), and (a)(3) introductory
text.
    b. By revising paragraphs (b) introductory text and (b)(2).
    c. By revising paragraph (e).
    d. By revising paragraph (k) introductory text.
    e. By revising paragraph (l).
    f. By removing and reserving paragraph (p).
    g. By removing and reserving paragraph (q).
    h. By removing and reserving paragraph (r).
    i. By revising paragraph (t).
    j. By revising paragraphs (u)(1)(iii) and (u)(4).

Sec.  60.49Da  Emission monitoring.

    (a) * * *
    (1) Except as provided for in paragraph (a)(2) of this section, the
owner or operator of an affected facility subject to an opacity
standard, shall install, calibrate, maintain, and operate a COMS, and
record the output of the system, for measuring the opacity of emissions
discharged to the atmosphere. If opacity interference due to water
droplets exists in the stack (for example, from the use of an FGD
system), the opacity is monitored upstream of the interference (at the
inlet to the FGD system). If opacity interference is experienced at all
locations (both at the inlet and outlet of the SO2 control
system), alternate parameters indicative of the PM control system's
performance and/or good combustion are monitored (subject to the
approval of the Administrator).
    (2) As an alternative to the monitoring requirements in paragraph
(a)(1) of this section, an owner or operator of an affected facility
that meets the conditions in either paragraph (a)(2)(i), (ii), (iii),
or (iv) of this section may elect to monitor opacity as specified in
paragraph (a)(3) of this section.
    (i) The affected facility uses a fabric filter (baghouse) to meet
the standards in Sec.  60.42Da and a bag leak detection system is
installed and operated according to the requirements in paragraphs
Sec.  60.48Da(o)(4)(i) through (v);
    (ii) The affected facility burns only gaseous or liquid fuels
(excluding residual oil) with potential SO2 emissions rates
of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion
technology to reduce emissions of SO2 or PM;
    (iii) The affected facility meets all of the conditions specified
in paragraphs (a)(2)(iii)(A) through (C) of this section; or
    (A) No post-combustion technology (except a wet scrubber) is used
for reducing PM, SO2, or carbon monoxide (CO) emissions;
    (B) Only natural gas, gaseous fuels, or fuel oils that contain less
than or equal to 0.30 weight percent sulfur are burned; and
    (C) Emissions of CO discharged to the atmosphere are maintained at
levels less than or equal to 1.4 lb/MWh on a boiler operating day
average basis as demonstrated by the use of a CEMS measuring CO
emissions according to the procedures specified in paragraph (u) of
this section.
    (iv) The affected facility uses an ESP and uses an ESP predictive
model to monitor the performance of the ESP developed in accordance and
operated according to the most current requirements in section Sec.
60.48Da of this part.
    (3) The owner or operators of an affected facility that meets the
conditions in paragraph (a)(2) of this section may, as an alternative
to using a COMS, elect to monitor visible emissions using the
applicable procedures specified in paragraphs (a)(3)(i) through (iv) of
this section. The opacity performance test requirement in paragraph
(a)(3)(i) must be conducted by April 29, 2011, within 45 days after
stopping use of an existing COMS, or within 180 days after initial
startup of the facility, whichever is later.
* * * * *
    (b) The owner or operator of an affected facility shall install,
calibrate, maintain, and operate a CEMS, and record the output of the
system, for measuring SO2 emissions, except where natural
gas and/or liquid fuels (excluding residual oil) with potential
SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less are
the only fuels combusted, as follows:
* * * * *
    (2) For a facility that qualifies under the numerical limit
provisions of Sec.  60.43Da SO2 emissions are only monitored
as discharged to the atmosphere.
* * * * *
    (e) The CEMS under paragraphs (b), (c), and (d) of this section are
operated and data recorded during all periods of operation of the
affected facility including periods of startup, shutdown, malfunction,
and emergency conditions, except for CEMS breakdowns, repairs,
calibration checks, and zero and span adjustments.
* * * * *
    (k) The procedures specified in paragraphs (k)(1) through (3) of
this section shall be used to determine gross output for sources
demonstrating compliance with an output-based standard.
* * * * *
    (l) The owner or operator of an affected facility demonstrating
compliance with an output-based standard shall install, certify,
operate, and maintain a continuous flow monitoring system meeting the
requirements of Performance Specification 6 of appendix B of this part
and the CD assessment, RATA and reporting provisions of procedure 1 of
appendix F of this part, and record the output of the system, for
measuring the volumetric flow rate of exhaust gases discharged to the
atmosphere; or
* * * * *
    (t) The owner or operator of an affected facility demonstrating
compliance with the output-based emissions limitation under Sec.
60.42Da shall install, certify, operate, and maintain a CEMS for
measuring PM emissions according to the requirements of paragraph (v)
of this section. An owner or operator of an affected facility
demonstrating compliance with the input-based emission limitation in
Sec.  60.42Da may install, certify, operate, and maintain a CEMS for
measuring PM emissions according to the requirements of paragraph (v)
of this section.

    (u) * * *
    (1) * * *
    (iii) At a minimum, non-out-of-control 1-hour CO emissions averages
must be obtained for at least 90 percent of the operating hours on a 30
boiler operating day rolling average basis. The 1-hour averages are
calculated using the data points required in Sec.  60.13(h)(2).
* * * * *
    (4) As of January 1, 2012 and within 60 days after the date of
completing each performance test, as defined in Sec.  63.2, conducted
to demonstrate compliance with this subpart, you must submit relative
accuracy test audit (i.e., reference method) data and performance test
(i.e., compliance test) data, except opacity data, electronically to
EPA's Central Data Exchange (CDX) by using the Electronic Reporting
Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or
other compatible electronic spreadsheet. Only data collected using test
methods compatible with ERT are subject to this requirement to be
submitted electronically into EPA's WebFire database.
    18. Section 60.50Da is amended as follows:
    a. By revising paragraphs (b)(2) and (b)(4).
    b. By removing paragraph (g).
    c. By removing paragraph (h).
    d. By removing paragraph (i).

Sec.  60.50Da  Compliance determination procedures and methods.

* * * * *
    (b) * * *
    (2) For the filterable particular matter concentration, Method 5 of
appendix A of this part shall be used at affected facilities without
wet FGD systems and Method 5B of appendix A of this part shall be used
after wet FGD systems.
* * * * *
    (4) Total particular matter concentration consists of the sum of
the filterable and condensable fractions. The condensable fraction
shall be measured using Method 202 of appendix M of part 51, and the
filterable fraction shall be measured using Method 5 of appendix A of
this part.
* * * * *
    19. Section 60.51Da is amended as follows:
    a. By revising paragraph (a).
    b. By removing and reserving paragraph (g).
    c. By revising paragraph (k).

Sec.  60.51  Da Reporting requirements.

    (a) For SO2, NOX, and PM emissions, the
performance test data from the initial and subsequent performance test
and from the performance evaluation of the continuous monitors
(including the transmissometer) are submitted to the Administrator.
* * * * *
    (k) The owner or operator of an affected facility may submit
electronic quarterly reports for SO2 and/or NOX
and/or opacity in lieu of submitting the written reports required under
paragraphs (b), (g), and (i) of this section. The format of each
quarterly electronic report shall be coordinated with the permitting
authority. The electronic report(s) shall be submitted no later than 30
days after the end of the calendar quarter and shall be accompanied by
a certification statement from the owner or operator, indicating
whether compliance with the applicable emission standards and minimum
data requirements of this subpart was achieved during the reporting
period.

Sec.  60.52Da(a)  [Removed and reserved]

    20. Section 60.52Da is amended by removing and reserving paragraph
(a).

Subpart Db--[Amended]

    21. Section 60.40b is amended as follows:
    a. By revising paragraph (c).
    b. By revising paragraph (h).
    c. By revising paragraph (i).
    d. By adding paragraph (1).

Sec.  60.40b  Applicability and delegation of affected facility.

* * * * *
    (c) Affected facilities that also meet the applicability
requirements under subpart J or subpart Ja (Standards of performance
for petroleum refineries) are subject to the PM and NOX
standards under this subpart and the SO2 standards under
subpart J or subpart Ja.
* * * * *
    (h) Any affected facility that meets the applicability requirements
and is subject to subpart Ea, subpart Eb, subpart AAAA, or subpart CCCC
of this part is not subject to this subpart.
    (i) Affected facilities (i.e. heat recovery steam generators) that
are associated with stationary combustion turbines and that meet the
applicability requirements of subpart KKKK of this part are not subject
to this subpart. This subpart will continue to apply to all other
affected facilities (i.e. heat recovery steam generators with duct
burners) that are capable of combusting more than 29 MW (100 MMBtu/hr)
heat input of fossil fuel. If the affected facility (i.e. heat recovery
steam generator) is subject to this subpart, only emissions resulting
from combustion of fuels in the steam generating unit are subject to
this subpart. (The stationary combustion turbine emissions are subject
to subpart GG or KKKK, as applicable, of this part.)
* * * * *
    (l) Affected facilities that also meet the applicability
requirements under subpart BB (Standards of Performance for Kraft Pulp
Mills) are subject to the SO2 and NOX standards
under this subpart and the PM standards under subpart BB.
* * * * *
    22. Section 60.41b is amended by revising the definition of
``distillate oil'' to read as follows:

Sec.  60.41b  Definitions.

* * * * *
    Distillate oil means fuel oils that contain 0.05 weight percent
nitrogen or less and comply with the specifications for fuel oil
numbers 1 and 2, as defined by the American Society of Testing and
Materials in ASTM D396 (incorporated by reference, see Sec.  60.17),
diesel fuel oil numbers 1 and 2, as defined by the American Society for
Testing and Materials in ASTM D975 (incorporated by reference, see
Sec.  60.17), kerosene, as defined by the American Society of Testing
and Materials in ASTM D3699 (incorporated by reference, see Sec.
60.17), biodiesel as defined by the American Society of Testing and
Materials in ASTM D6751 (incorporated by reference, see Sec.  60.17),
or biodiesel blends as defined by the American Society of Testing and
Materials in ASTM D7467 (incorporated by reference, see Sec.  60.17).
* * * * *
    23. Section 60.44b is amended by revising paragraphs (c) and (d) to
read as follows:

Sec.  60.44b  Standard for nitrogen oxides (NO).

* * * * *
    (c) Except as provided under paragraph (d) and (l) of this section,
on and after the date on which the initial performance test is
completed or is required to be completed under Sec.  60.8, whichever
date comes first, no owner or operator of an affected facility that
simultaneously combusts coal or oil, or a mixture of these fuels with
natural gas, and wood, municipal-type solid waste, or any other fuel
shall cause to be discharged into the atmosphere any gases that contain
NOX in excess of the emission limit for the coal or oil, or
mixtures of these fuels with natural gas combusted in the affected
facility, as determined pursuant to paragraph (a) or (b) of this
section, unless the affected facility has an annual capacity factor for
coal or oil, or mixture of these fuels

with natural gas of 10 percent (0.10) or less and is subject to a
federally enforceable requirement that limits operation of the affected
facility to an annual capacity factor of 10 percent (0.10) or less for
coal, oil, or a mixture of these fuels with natural gas.
    (d) On and after the date on which the initial performance test is
completed or is required to be completed under Sec.  60.8, whichever
date comes first, no owner or operator of an affected facility that
simultaneously combusts natural gas or distillate oil with a potential
SO2 emissions rate of 26 ng/J (0.060 lb/MMBtu) or less with
wood, municipal-type solid waste, or other solid fuel, except coal,
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain NOX in excess of 130 ng/J
(0.30 lb/MMBtu) heat input unless the affected facility has an annual
capacity factor for natural gas, distillate oil, or a mixture of these
fuels of 10 percent (0.10) or less and is subject to a federally
enforceable requirement that limits operation of the affected facility
to an annual capacity factor of 10 percent (0.10) or less for natural
gas, distillate oil, or a mixture of these fuels.
* * * * *
    24. Section 60.46b is amended by revising paragraph (j)(14) to read
as follows:

Sec.  60.46b  Compliance and performance test methods and procedures
for particulate matter and nitrogen oxides.

* * * * *
    (j) * * *
    (14) As of January 1, 2012, and within 60 days after the date of
completing each performance test, as defined in Sec.  63.2, conducted
to demonstrate compliance with this subpart, you must submit relative
accuracy test audit (i.e., reference method) data and performance test
(i.e., compliance test) data, except opacity data, electronically to
EPA's Central Data Exchange (CDX) by using the Electronic Reporting
Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or
other compatible electronic spreadsheet. Only data collected using test
methods compatible with ERT are subject to this requirement to be
submitted electronically into EPA's WebFIRE database.
    25. Section 60.48b is amended as follows:
    a. By revising paragraphs (a) introductory text and (a)(1)(i).
    b. By revising paragraph (j) introductory text.
    c. By revising paragraph (j)(5).
    d. By revising paragraph (j)(6).
    e. By adding paragraph (j)(7).

Sec.  60.48b  Emission monitoring for particulate matter and nitrogen
oxides.

    (a) Except as provided in paragraph (j) of this section, the owner
or operator of an affected facility subject to the opacity standard
under Sec.  60.43b shall install, calibrate, maintain, and operate a
continuous opacity monitoring systems (COMS) for measuring the opacity
of emissions discharged to the atmosphere and record the output of the
system. The owner or operator of an affected facility subject to an
opacity standard under Sec.  60.43b and meeting the conditions under
paragraphs (j)(1), (2), (3), (4), (5), or (6) of this section who
elects not to use a COMS shall conduct a performance test using Method
9 of appendix A-4 of this part and the procedures in Sec.  60.11 to
demonstrate compliance with the applicable limit in Sec.  60.43b by
April 29, 2011, within 45 days of stopping use of an existing COMS, or
within 180 days after initial startup of the facility, whichever is
later, and shall comply with either paragraphs (a)(1), (a)(2), or
(a)(3) of this section. The observation period for Method 9 of appendix
A-4 of this part performance tests may be reduced from 3 hours to 60
minutes if all 6-minute averages are less than 10 percent and all
individual 15-second observations are less than or equal to 20 percent
during the initial 60 minutes of observation.
    (1) * * *
    (i) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later;
* * * * *
    (j) The owner or operator of an affected facility that meets the
conditions in either paragraph (j)(1), (2), (3), (4), (5), (6), or (7)
of this section is not required to install or operate a COMS if:
* * * * *
    (5) The affected facility uses a bag leak detection system to
monitor the performance of a fabric filter (baghouse) according to the
most current requirements in section Sec.  60.48Da of this part; or
    (6) The affected facility uses an ESP as the primary PM control
device and uses an ESP predictive model to monitor the performance of
the ESP developed in accordance and operated according to the most
current requirements in section Sec.  60.48Da of this part; or
    (7) The affected facility burns only gaseous fuels or fuel oils
that contain less than or equal to 0.30 weight percent sulfur and
operates according to a written site-specific monitoring plan approved
by the permitting authority. This monitoring plan must include
procedures and criteria for establishing and monitoring specific
parameters for the affected facility indicative of compliance with the
opacity standard.
* * * * *

Subpart Dc--[Amended]

    26. Section 60.40c is amended as follows:
    a. By revising paragraph (e).
    b. By revising paragraph (f).
    c. By revising paragraph (g).

Sec.  60.40c  Applicability and delegation of authority.

* * * * *
    (e) Affected facilities (i.e. heat recovery steam generators and
fuel heaters) that are associated with stationary combustion turbines
and meet the applicability requirements of subpart KKKK of this part
are not subject to this subpart. This subpart will continue to apply to
all other heat recovery steam generators, fuel heaters, and other
affected facilities that are capable of combusting more than or equal
to 2.9 MW (10 MMBtu/hr) heat input of fossil fuel but less than or
equal to 29 MW (100 MMBtu/hr) heat input of fossil fuel. If the heat
recovery steam generator, fuel heater, or other affected facility is
subject to this subpart, only emissions resulting from combustion of
fuels in the steam generating unit are subject to this subpart. (The
stationary combustion turbine emissions are subject to subpart GG or
KKKK, as applicable, of this part).
    (f) Any facility that meets the applicability requirements of and
is subject to subpart AAAA or subpart CCCC of this part is not subject
to this subpart.
    (g) Any facility that meets the applicability requirements of and
is subject to an EPA approved State or Federal section 111(d)/129 plan
implementing subpart BBBB of this part is not subject to this subpart.
    27. Section 60.41c is amended by removing the definition of
``Cogeneration'' and revising the definition of ``Distillate oil'' to
read as follows:

Sec.  60.41c  Definitions.

* * * * *
    Distillate oil means fuel oil that complies with the specifications
for fuel oil numbers 1 or 2, as defined by the American Society for
Testing and

Materials in ASTM D396 (incorporated by reference, see Sec.  60.17),
diesel fuel oil numbers 1 or 2, as defined by the American Society for
Testing and Materials in ASTM D975 (incorporated by reference, see
Sec.  60.17), kerosene, as defined by the American Society of Testing
and Materials in ASTM D3699 (incorporated by reference, see Sec.
60.17), biodiesel as defined by the American Society of Testing and
Materials in ASTM D6751 (incorporated by reference, see Sec.  60.17),
or biodiesel blends as defined by the American Society of Testing and
Materials in ASTM D7467 (incorporated by reference, see Sec.  60.17).
* * * * *
    28. Section 60.42c is amended as follows:
    a. By revising paragraph (d).
    b. By revising paragraph (h) introductory text.
    c. By revising paragraph (h)(3).
    d. By adding paragraph (h)(4).

Sec.  60.42c  Standard for sulfur dioxide (SO2).

* * * * *
    (d) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, no owner or operator of an affected facility that combusts
oil shall cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 215 ng/J
(0.50 lb/MMBtu) heat input from oil; or, as an alternative, no owner or
operator of an affected facility that combusts oil shall combust oil in
the affected facility that contains greater than 0.5 weight percent
sulfur. The percent reduction requirements are not applicable to
affected facilities under this paragraph.
* * * * *
    (h) For affected facilities listed under paragraphs (h)(1), (2),
(3), or (4) of this section, compliance with the emission limits or
fuel oil sulfur limits under this section may be determined based on a
certification from the fuel supplier, as described under Sec.
60.48c(f), as applicable.
* * * * *
    (3) Coal-fired affected facilities with heat input capacities
between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
    (4) Other fuels-fired affected facilities with heat input
capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
* * * * *
    29. Section 60.45c is amended by revising paragraph (c)(14) to read
as follows:

Sec.  60.45c  Compliance and performance test methods and procedures
for particulate matter.

* * * * *
    (c)(14) As of January 1, 2012, and within 60 days after the date of
completing each performance test, as defined in Sec.  63.2, conducted
to demonstrate compliance with this subpart, you must submit relative
accuracy test audit (i.e., reference method) data and performance test
(i.e., compliance test) data, except opacity data, electronically to
EPA's Central Data Exchange (CDX) by using the Electronic Reporting
Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or
other compatible electronic spreadsheet. Only data collected using test
methods compatible with ERT are subject to this requirement to be
submitted electronically into EPA's WebFIRE database.
* * * * *
    30. Section 60.47c is amended as follows:
    a. By revising paragraphs (a) introductory text and (a)(1)(i).
    b. By revising paragraph (f).
    c. By revising paragraph (g).
    d. By adding paragraph (h).

Sec.  60.47c  Emission monitoring for particulate matter.

    (a) Except as provided in paragraphs (c), (d), (e), (f), (g), and
(h) of this section, the owner or operator of an affected facility
combusting coal, oil, or wood that is subject to the opacity standards
under Sec.  60.43c shall install, calibrate, maintain, and operate a
continuous opacity monitoring system (COMS) for measuring the opacity
of the emissions discharged to the atmosphere and record the output of
the system. The owner or operator of an affected facility subject to an
opacity standard in Sec.  60.43c(c) that is not required to use a COMS
due to paragraphs (c), (d), (e), (f), or (g) of this section that
elects not to use a COMS shall conduct a performance test using Method
9 of appendix A-4 of this part and the procedures in Sec.  60.11 to
demonstrate compliance with the applicable limit in Sec.  60.43c by
April 29, 2011, within 45 days of stopping use of an existing COMS, or
within 180 days after initial startup of the facility, whichever is
later, and shall comply with either paragraphs (a)(1), (a)(2), or
(a)(3) of this section. The observation period for Method 9 of appendix
A-4 of this part performance tests may be reduced from 3 hours to 60
minutes if all 6-minute averages are less than 10 percent and all
individual 15-second observations are less than or equal to 20 percent
during the initial 60 minutes of observation.
    (1) * * *
    (i) If no visible emissions are observed, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 12
calendar months from the date that the most recent performance test was
conducted or within 45 days of the next day that fuel with an opacity
standard is combusted, whichever is later;
* * * * *
    (f) Owners and operators of an affected facility that is subject to
an opacity standard in Sec.  60.43c(c) and that uses a bag leak
detection system to monitor the performance of a fabric filter
(baghouse) according to the most current requirements in section Sec.
60.48Da of this part is not required to operate a COMS.
    (g) The affected facility uses an ESP as the primary PM control
device and uses an ESP predictive model to monitor the performance of
the ESP developed in accordance and operated according to the most
current requirements in section Sec.  60.48Da of this part.
    (h) Owners and operators of an affected facility that is subject to
an opacity standard in Sec.  60.43c(c) and that burns only gaseous
fuels and/or fuel oils that contain less than or equal to 0.5 weight
percent sulfur and operates according to a written site-specific
monitoring plan approved by the permitting authority is not required to
operate a COMS. This monitoring plan must include procedures and
criteria for establishing and monitoring specific parameters for the
affected facility indicative of compliance with the opacity standard.

Subpart HHHH--[Removed and Reserved]

    31. Subpart HHHH is removed and reserved.

PART 63--[AMENDED]

    32. The authority citation for part 63 continues to read as
follows:

    Authority:  42 U.S.C. 7401, et seq.

    33. Part 63 is amended by adding subpart UUUUU to read as follows:

Subpart UUUUU--National Emission Standards for Hazardous Air
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating
Units

Sec.

What This Subpart Covers

63.9980 What is the purpose of this subpart?
63.9981 Am I subject to this subpart?
63.9982 What is the affected source of this subpart?

63.9983 Are any EGUs not subject to this subpart?
63.9984 When do I have to comply with this subpart?

Emission Limitations and Work Practice Standards

63.9990 What are the subcategories of EGUs?
63.9991 What emission limitations, work practice standards, and
operating limits must I meet?

General Compliance Requirements

63.10000 What are my general requirements for complying with this
subpart?
63.10001 Affirmative Defense for Exceedence of Emission Limit During
Malfunction.

Testing, Fuel Analyses, and Initial Compliance Requirements

63.10005 What are my initial compliance requirements and by what
date must I conduct them?
63.10006 When must I conduct subsequent performance tests, fuel
analyses, or tune-ups?
63.10007 What methods and other procedures must I use for the
performance tests?
63.10008 What fuel analyses and procedures must I use for the
performance tests?
63.10009 May I use emission averaging to comply with this subpart?
63.10010 What are my monitoring, installation, operation, and
maintenance requirements?
63.10011 How do I demonstrate initial compliance with the emission
limitations and work practice standards?

Continuous Compliance Requirements

63.10020 How do I monitor and collect data to demonstrate continuous
compliance?
63.10021 How do I demonstrate continuous compliance with the
emission limitations and work practice standards?
63.10022 How do I demonstrate continuous compliance under the
emission averaging provision?

Notifications, Reports, and Records

63.10030 What notifications must I submit and when?
63.10031 What reports must I submit and when?
63.10032 What records must I keep?
63.10033 In what form and how long must I keep my records?

Other Requirements and Information

63.10040 What parts of the General Provisions apply to me?
63.10041 Who implements and enforces this subpart?
63.10042 What definitions apply to this subpart?

Tables to Subpart UUUUU of Part 63

Table 1 to Subpart UUUUU of Part 63--Emission Limits for New or
Reconstructed EGUs
Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing
EGUs
Table 3 to Subpart UUUUU of Part 63--Work Practice Standards
Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs
Table 5 to Subpart UUUUU of Part 63--Performance Testing
Requirements
Table 6 to Subpart UUUUU of Part 63--Fuel Analysis Requirements
Table 7 to Subpart UUUUU of Part 63--Establishing Operating Limits
Table 8 to Subpart UUUUU of Part 63--Demonstrating Continuous
Compliance
Table 9 to Subpart UUUUU of Part 63--Reporting Requirements
Table 10 to Subpart UUUUU of Part 63--Applicability of General
Provisions to Subpart UUUUU
Appendix A to Subpart UUUUU--Hg Monitoring Provisions

Subpart UUUUU--National Emission Standards for Hazardous Air
Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating
Units

What This Subpart Covers

Sec.  63.9980  What is the purpose of this subpart?

    This subpart establishes national emission limitations and work
practice standards for hazardous air pollutants (HAP) emitted from
coal- and oil-fired electric utility steam generating units (EGUs).
This subpart also establishes requirements to demonstrate initial and
continuous compliance with the emission limitations.

Sec.  63.9981  Am I subject to this subpart?

    You are subject to this subpart if you own or operate a coal-fired
EGU or an oil-fired EGU.

Sec.  63.9982  What is the affected source of this subpart?

    (a) This subpart applies to each individual or group of one or more
new, reconstructed, and existing affected source(s) as described in
paragraphs (a)(1) and (2) of this section within a contiguous area and
under common control.
    (1) The affected source of this subpart is the collection of all
existing coal- or oil-fired EGUs as defined in Sec.  63.10042.
    (2) The affected source of this subpart is each new or
reconstructed coal- or oil-fired EGU as defined in Sec.  63.10042.
    (b) An EGU is new if you commence construction of the coal- or oil-
fired EGU after May 3, 2011, and you meet the applicability criteria at
the time you commence construction.
    (c) An EGU is reconstructed if you meet the reconstruction criteria
as defined in Sec.  63.2, you commence reconstruction after May 3,
2011, and you meet the applicability criteria at the time you commence
reconstruction.
    (d) An EGU is existing if it is not new or reconstructed. An
existing electric utility steam generating unit that has switched
completely to burning a different coal rank or fuel type is considered
to be an existing affected source under this subpart.

Sec.  63.9983  Are any EGUs not subject to this subpart?

    The types of EGUs listed in paragraphs (a) through (c) of this
section are not subject to this subpart.
    (a) Any unit designated as a stationary combustion turbine, other
than an integrated gasification combined cycle (IGCC), covered by 40
CFR part 63, subpart YYYY.
    (b) Any EGU that is not a coal- or oil-fired EGU and combusts
natural gas 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.
    (c) Any EGU that has the capability of combusting more than 73 MWe
(250 million Btu/hr, MMBtu/hr) heat input (equivalent to 25 MWe output)
of coal or oil but did not fire 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. 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 industrial boilers).

Sec.  63.9984  When do I have to comply with this subpart?

    (a) If you have a new or reconstructed EGU, you must comply with
this subpart by [DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL
REGISTER] or upon startup of your EGU, whichever is later.
    (b) If you have an existing EGU, you must comply with this subpart
no later than [3 YEARS AFTER DATE THE FINAL RULE IS PUBLISHED IN THE
FEDERAL REGISTER].
    (c) You must meet the notification requirements in Sec.  63.10030
according to the schedule in Sec.  63.10030 and in subpart A of this
part. Some of the notifications must be submitted before you are
required to comply with the emission limits and work practice standards
in this subpart.

Emission Limitations and Work Practice Standards

Sec.  63.9990  What are the subcategories of EGUs?

    (a) Coal-fired EGUs are subcategorized as defined in paragraphs
(a)(1) through

(a)(2) of this section and as defined in Sec.  63.10042.
    (1) EGUs designed for coal = 8,300 Btu/lb, and
    (2) EGUs designed for coal < 8,300 Btu/lb. (b) Oil-fired EGUs are
subcategorized as noted in paragraphs (b)(1) through (b)(2) of this
section and as defined in Sec.  63.10042.
    (1) EGUs designed to burn liquid oil, and
    (2) EGUs designed to burn solid oil-derived fuel.
    (c) IGCC units combusting either gasified coal or gasified solid
oil-derived fuel. For purposes of compliance, monitoring,
recordkeeping, and reporting requirements in this subpart, IGCC units
are subject in the same manner as coal-fired units and solid oil-
derived fuel-fired units, unless otherwise indicated.

Sec.  63.9991  What emission limitations, work practice standards, and
operating limits must I meet?

    (a) You must meet the requirements in paragraphs (a)(1) and (2) of
this section. You must meet these requirements at all times.
    (1) You must meet each emission limit and work practice standard in
Table 1 through 3 to this subpart that applies to your EGU, for each
EGU at your source, except as provided under paragraph (a)(1)(i) and
(ii) or under Sec.  63.10009.
    (i) You may not use the alternate SO2 limit if your
coal-fired EGU does not have a system using wet or dry flue gas
desulfurization technology installed on the unit.
    (ii) You may not use the alternate SO2 limit if your
oil-fired EGU does not have a system using wet or dry flue gas
desulfurization technology installed on the unit.
    (iii) You must operate the wet or dry flue gas desulfurization
technology installed on the unit at all times in order to qualify to
use the alternate SO2 limit.
    (2) You must meet each operating limit in Table 4 to this subpart
that applies to your EGU. If you use a control device or combination of
control devices not covered in Table 4 to this subpart, or you wish to
establish and monitor an alternative operating limit and alternative
monitoring parameters, you must apply to the EPA Administrator for
approval of alternative monitoring under Sec.  63.8(f).
    (b) As provided in Sec.  63.6(g), EPA may approve use of an
alternative to the work practice standards in this section.

General Compliance Requirements

Sec.  63.10000  What are my general requirements for complying with
this subpart?

    (a) You must be in compliance with the emission limits and
operating limits in this subpart. These limits apply to you at all
times.
    (b) At all times you must operate and maintain any affected source,
including associated air pollution control equipment and monitoring
equipment, in a manner consistent with safety and good air pollution
control practices for minimizing emissions. Determination of whether
such operation and maintenance procedures are being used will be based
on information available to the EPA Administrator which may include,
but is not limited to, monitoring results, review of operation and
maintenance procedures, review of operation and maintenance records,
and inspection of the source.
    (c)(1) For coal-fired units and solid oil-derived fuel-fired units,
initial performance testing is required for all pollutants. For non-
mercury HAP metals, you demonstrate continuous compliance through use
of a particulate matter (PM) CEMS; initial compliance is determined by
establishing an operational limit for filterable PM obtained during
total PM emissions testing. As an alternative to using a PM CEMS, you
may demonstrate initial and continuous compliance by conducting total
HAP metals testing or individual non-mercury (Hg) metals testing. For
acid gases, you demonstrate initial and continuous compliance through
use of a continuous hydrogen chloride (HCl) CEMS. As an alternative to
HCl CEMS, you may demonstrate initial and continuous compliance by
conducting performance testing. As another alternative to HCl CEMS, you
may demonstrate initial and continuous compliance through use of a
certified sulfur dioxide (SO2) CEMS, provided the unit has a
system using wet or dry flue gas desulfurization technology. For
mercury (Hg), if your unit does not qualify as a low emitting EGU
(LEE), you must demonstrate initial and continuous compliance through
use of a Hg CEMS or a sorbent trap monitoring system.
    (2) For liquid oil-fired units, you must demonstrate initial and
continuous compliance for HCl, hydrogen fluoride (HF), and individual
or total HAP metals by conducting performance testing. As an
alternative to conducting performance testing, you may demonstrate
compliance with the applicable emissions limit for HCl, HF, and
individual or total HAP metals using fuel analysis provided the
emission rate calculated according to Sec.  63.10011(c) is less than
the applicable emission limit.
    (d) If you demonstrate compliance with any applicable emissions
limit through use of a continuous monitoring system (CMS), where a CMS
includes a continuous parameter monitoring system (CPMS) as well as a
continuous emissions monitoring system (CEMS), or through the use of a
sorbent trap monitoring system for Hg, you must develop a site-specific
monitoring plan and submit this site-specific monitoring plan, if
requested, at least 60 days before your initial performance evaluation
(where applicable) of your CMS or sorbent trap monitoring system. This
requirement also applies to you if you petition the EPA Administrator
for alternative monitoring parameters under Sec.  63.8(f). This
requirement to develop and submit a site-specific monitoring plan does
not apply to affected sources with existing monitoring plans that apply
to CEMS and CPMS prepared under Appendix B to part 60 or Part 75 of
this chapter, and that meet the requirements of Sec.  63.10010. The
monitoring plan must address the provisions in paragraphs (d)(1)
through (7) of this section.
    (1) Installation of the CMS or sorbent trap monitoring system
sampling probe or other interface at a measurement location relative to
each affected process unit such that the measurement is representative
of control of the exhaust emissions (e.g., on or downstream of the last
control device).
    (2) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems.
    (3) Schedule for conducting initial and periodic performance
evaluations.
    (4) Performance evaluation procedures and acceptance criteria
(e.g., calibrations), including ongoing data quality assurance
procedures in accordance with the general requirements of Sec.  63.8(d)
or Appendix A to this subpart, as applicable.
    (5) Ongoing operation and maintenance procedures in accordance with
the general requirements of Sec.  63.8(c)(1)(ii), (c)(3), and
(c)(4)(ii) or Appendix A to this subpart, as applicable.
    (6) Conditions that define a continuous monitoring system that is
out of control consistent with Sec.  63.8(c)(7)(i) and for responding
to out of control periods consistent with Sec. Sec.  63.8(c)(7)(ii) and
(c)(8) or Appendix A to this subpart, as applicable.

    (7) Ongoing recordkeeping and reporting procedures in accordance
with the general requirements of Sec.  63.10(c), (e)(1), and (e)(2)(i)
and Appendix A to this subpart, as applicable.
    (e) You must operate and maintain the CMS or sorbent trap
monitoring system according to the site-specific monitoring plan.

Sec.  63.10001  Affirmative Defense for Exceedence of Emission Limit
During Malfunction.

    In response to an action to enforce the standards set forth in
paragraph Sec.  63.9991 you may assert an affirmative defense to a
claim for civil penalties for exceedances of such standards that are
caused by malfunction, as defined at 40 CFR 63.2. Appropriate penalties
may be assessed, however, if the respondent fails to meet its burden of
proving all of the requirements in the affirmative defense. The
affirmative defense shall not be available for claims for injunctive
relief.
    (a) To establish the affirmative defense in any action to enforce
such a limit, the owners or operators of facilities must timely meet
the notification requirements in paragraph (b) of this section, and
must prove by a preponderance of evidence that:
    (1) The excess emissions:
    (i) Were 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; and
    (ii) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
    (iii) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
    (iv) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
    (2) Repairs were made as expeditiously as possible when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable to make these
repairs; and
    (3) The frequency, amount and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions; and
    (4) If the excess emissions resulted from a bypass of control
equipment or a process, then the bypass was unavoidable to prevent loss
of life, personal injury, or severe property damage; and
    (5) All possible steps were taken to minimize the impact of the
excess emissions on ambient air quality, the environment and human
health; and
    (6) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
    (7) All of the actions in response to the excess emissions were
documented by properly signed, contemporaneous operating logs; and
    (8) At all times, the facility was operated in a manner consistent
with good practices for minimizing emissions; and
    (9) A written root cause analysis has been prepared, the purpose of
which is to determine, correct, and eliminate the primary causes of the
malfunction and the excess emissions resulting from the malfunction
event at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of excess emissions that
were the result of the malfunction.
    (b) The owner or operator of the facility experiencing an
exceedence of its emission limit(s) during a malfunction shall notify
the EPA Administrator by telephone or facsimile (FAX) transmission as
soon as possible, but no later than two (2) business days after the
initial occurrence of the malfunction, if it wishes to avail itself of
an affirmative defense to civil penalties for that malfunction. The
owner or operator seeking to assert an affirmative defense shall also
submit a written report to the EPA Administrator within 45 days of the
initial occurrence of the exceedence of the standard in Sec.  63.9991
to demonstrate, with all necessary supporting documentation, that it
has met the requirements set forth in paragraph (a) of this section.
The owner or operator may seek an extension of this deadline for up to
30 additional days by submitting a written request to the Administrator
before the expiration of the 45 day period. Until a request for an
extension has been approved by the Administrator, the owner or operator
is subject to the requirement to submit such report within 45 days of
the initial occurrence of the exceedances.

Testing, Fuel Analyses, and Initial Compliance Requirements

Sec.  63.10005  What are my initial compliance requirements and by what
date must I conduct them?

    (a) General requirements. Affected EGUs must demonstrate initial
compliance with each of the applicable emissions limits in Tables 1 or
2 of this subpart through performance testing, along with one or more
of the following activities: conducting a fuel analysis for each type
of fuel combusted, establishing operating limits where applicable
according to Sec.  63.10011 and Table 7 to this subpart; conducting CMS
performance evaluations where applicable; and conducting sorbent trap
monitoring system performance evaluations, where applicable, in
conjunction with performance testing. If you use a CMS that measures
pollutant concentrations directly (i.e., a CEMS or a sorbent trap
monitoring system), the performance test consists of the first 30
operating days of data collected with the certified monitoring system,
after the applicable compliance date. If you use a continuous
monitoring system that measures a surrogate for a pollutant (e.g., an
SO2 monitor), you must perform initial emission testing
during the same compliance test period and under the same process
(e.g., fuel) and control device operating conditions of the pollutant
and surrogate, in addition to conducting the initial 30-day performance
test. If you wish to demonstrate that a unit qualifies as a low
emitting EGU (LEE), you must conduct performance testing in accordance
with paragraphs (k) and (l) of this section.
    (b) Performance Testing Requirements. Affected EGUs must
demonstrate initial compliance with each of the applicable emissions
limits in Tables 1 or 2 of this subpart by conducting performance tests
according to Sec.  63.10007 and Table 5 to this subpart.
    (1) For affected EGUs that do not rely on CMS, sorbent trap
monitoring systems, or 28 to 30 day Method 30B testing to demonstrate
initial compliance, performance test data and results from a prior
performance test may be used to demonstrate initial compliance,
provided the performance tests meet the following conditions:
    (i) The performance test was conducted within the last twelve
months;
    (ii) The performance test was conducted in accordance with all
requirements contained in Sec.  63.10007 and Table 5 of this subpart;
and
    (iii) You certify, and have and keep documentation demonstrating,
that the EGU configuration, control devices, and materials/fuel have
remained constant since the prior performance test was conducted.
    (2) [Reserved]
    (c) Fuel Analysis Requirements. Affected liquid oil-fired EGUs may
choose to demonstrate initial compliance with each of the applicable
emissions limits in Tables 1 or 2 of this subpart by conducting a fuel
analysis for each type of fuel combusted, except

those affected EGUs that meet the exemptions identified in paragraphs
(c)(4) and (5) of this section and those affected EGUs that opt to
comply with the individual or total HAP metals limits in Tables 1 or 2
of this subpart which must comply by conducting a fuel analysis as
described in paragraph (c)(1) of this section.
    (1) For affected liquid oil-fired EGUs demonstrating compliance
with the applicable emissions limits in Tables 1 or 2 of this subpart
for HCl or individual or total HAP metals through fuel analysis, your
initial compliance requirement is to conduct a fuel analysis for each
type of fuel burned in your EGU according to Sec.  63.10008 and Table 6
to this subpart and establish operating limits according to Sec.
63.10011 and Table 8 to this subpart.
    (2) For affected liquid oil-fired EGUs that elect to demonstrate
compliance with the applicable emissions limits in Tables 1 or 2 of
this subpart for HF, your initial compliance requirement is to conduct
a fuel analysis for each type of fuel burned in your EGU according to
Sec.  63.10008 and Table 6 to this subpart and establish operating
limits according to Sec.  63.10011 and Table 8 to this subpart.
    (3) Fuel analysis data and results from a prior fuel analysis may
be used to demonstrate initial compliance, provided the fuel analysis
meets the following conditions:
    (i) The fuel analysis was conducted within the last twelve months;
    (ii) The fuel analysis was conducted in accordance with all
requirements contained in Sec.  63.10008 and Table 6 of this subpart;
and
    (iii) You certify, and have and keep documentation demonstrating,
that the EGU configuration, control devices, and materials/fuel have
remained constant since the prior fuel analysis was conducted.
    (4) For affected EGUs that combust a single type of fuel, you are
exempted from the initial compliance requirements of conducting a fuel
analysis for each type of fuel burned in your EGU according to Sec.
63.10008 and Table 6 to this subpart.
    (5) For purposes of this subpart, EGUs that use a supplemental fuel
only for startup, unit shutdown, or transient flame stability purposes
qualify as affected EGUs that combust a single type of fuel, the
supplemental fuel is not subject to the fuel analysis requirements
under Sec.  63.10008 and Table 6 to this subpart, and you are exempted
from the initial compliance requirements of conducting a fuel analysis
for each type of fuel burned in your EGU according to Sec.  63.10008
and Table 6 to this subpart.
    (d) CMS Requirements. (1) For affected liquid oil-fired EGUs that
elect to demonstrate initial compliance with the applicable emissions
limits in Tables 1 or 2 of this subpart for HCl through use of HCl
CEMS, initial compliance is determined using the average hourly HCl
concentrations obtained during the first 30 day operating period after
the monitoring system is certified.
    (2) For affected liquid oil-fired EGUs that elect to demonstrate
initial compliance with the applicable emissions limits in Tables 1 or
2 of this subpart for HF through use of HF CEMS, initial compliance is
determined using the average hourly HF concentrations obtained during
the first 30 day operating period after the monitoring system is
certified.
    (3) For affected solid oil-derived fuel- or coal-fired EGUs that
demonstrate initial compliance with the applicable emissions limits in
Tables 1 or 2 of this subpart for HCl through use of HCl CEMS, initial
compliance is determined using the average hourly HCl concentrations
obtained during the first 30 day operating period after the monitoring
system is certified.
    (4) For affected solid oil-derived fuel- or coal-fired EGUs with
installed systems that use wet or dry flue gas desulfurization
technology to demonstrate initial compliance with the applicable
emissions limits in Tables 1 or 2 of this subpart for SO2
through use of SO2 CEMS, initial compliance is determined
using the average hourly SO2 concentrations obtained during
the first 30 day operating period after the monitoring system is
certified.
    (5) For affected solid oil-derived fuel- or coal-fired EGUs that
demonstrate initial compliance with the applicable emissions limits in
Tables 1 or 2 of this subpart for PM through use of PM CEMS, initial
compliance is determined using the average hourly PM concentrations
obtained during the first 30 day operating period after the monitoring
system is certified.
    (6) For affected EGUs that demonstrate initial compliance with the
applicable emissions limits in Tables 1 or 2 of this subpart for Hg
through use of Hg CEMS, initial compliance is determined using the
average hourly Hg concentrations obtained during the first 30 day
operating period after the monitoring system is certified.
    (7) For affected EGUs that elect to demonstrate initial compliance
with the applicable emissions limits in Tables 1 or 2 of this subpart
for PM, non-Hg HAP metals, HCl, HF, or Hg through use of CPMS, initial
compliance is determined using the average hourly PM, non-Hg HAP
metals, HCl, HF, or Hg concentrations obtained during the first 30 day
operating period.
    (e) Sorbent Trap Monitoring System Requirements. For affected EGUs
that demonstrate initial compliance with the applicable emissions
limits in Tables 1 or 2 of this subpart for Hg through use of Hg
sorbent trap monitoring system, initial compliance is determined using
the average hourly Hg concentrations obtained during the first 30 day
operating period.
    (f) Tune-ups. For affected EGUs subject to work practice standards
in Table 3 of this subpart, your initial compliance requirement is to
conduct a tune-up of your EGU according to Sec.  63.10021(a)(16)(i)
through (vi).
    (g) For existing affected sources, you must demonstrate initial
compliance no later than 180 days after the compliance date that is
specified for your source in Sec.  63.9984 and according to the
applicable provisions in Sec.  63.7(a)(2) as cited in Table 10 to this
subpart.
    (h) If your new or reconstructed affected source commenced
construction or reconstruction between May 3, 2011 and [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must
demonstrate initial compliance with either the proposed emission limits
or the promulgated emission limits no later than 180 days after [DATE
60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or
within 180 days after startup of the source, whichever is later,
according to Sec.  63.7(a)(2)(ix).
    (i) If your new or reconstructed affected source commenced
construction or reconstruction between May 3, 2011, and [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], and you
chose to comply with the proposed emission limits when demonstrating
initial compliance, you must conduct a second compliance demonstration
for the promulgated emission limits within 3 years after [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or within
3 years after startup of the affected source, whichever is later.
    (j) If your new or reconstructed affected source commences
construction or reconstruction after [DATE 60 DAYS AFTER PUBLICATION OF
THE FINAL RULE IN THE FEDERAL REGISTER], you must demonstrate initial
compliance with the promulgated emission limits no later than 180 days
after startup of the source.

    (k) Low emitting EGU. Your existing EGU may qualify for low
emitting EGU (LEE) status provided that initial performance test data
that meet the requirements of Sec.  63.10005(b) and paragraph (l) of
this section demonstrate:
    (1) With the exception of mercury, emissions less than 50 percent
of the appropriate emissions limitation, or
    (2) For mercury, emissions less than 10 percent of the mercury
emissions limitation or less than 22.0 pounds per year. Only existing
affected units may qualify for LEE status for Hg. When qualifying for
LEE status for Hg emissions less than 22.0 pounds per year, the
affected unit must also demonstrate compliance with the applicable
emission limitation.
    (3) The following provisions apply in demonstrating that a unit
qualifies as a LEE. For all pollutants or surrogates except for Hg,
conduct the initial performance tests as described in Sec.  63.10007
but note that the required minimum sampling volume must be increased
nominally by a factor of two; follow the instructions in Table 5 to
this subpart to convert the test data to the units of the applicable
standard. For Hg, you must conduct a 28 to 30 operating day performance
test, using Method 30B in appendix A-8 to part 60 of this chapter, to
determine Hg concentration. Locate the Method 30B sampling probe tip at
a point within the 10 percent centroidal area of the duct at a location
that meets Method 1 in appendix A-8 to part 60 of this chapter and
conduct at least three nominally equal length test runs over the 28 to
30 day test period. You may not use a pair of sorbent traps to sample
the stack gas for more than 10 days. Collect diluent gas data over the
corresponding time period, and if preferred for calculation of pounds
per year of Hg, stack flow rate data using Method 2 in appendix A-1 to
part 60 of this chapter or a certified flow rate monitor and moisture
data using Method 4 in appendix A-1 to part 60 of this chapter or a
moisture monitor. Record parametric data during each performance test,
to establish operating limits, in accordance with the applicable
provisions of Sec.  63.10010(k)(3). Calculate the average Hg
concentration, in [mu]g/m\3\, for the 28 to 30 day performance test, as
the arithmetic average of all sorbent trap results. Calculate the
average CO2 or O2 concentration for the test
period. Use the average Hg concentration and diluent gas values to
express the performance test results in units of lb of Hg/TBtu, as
described in section 6.2.1 of appendix A to this subpart, and, if
elected, pounds of Hg per year, using the expected fuel input over a
year period. You may also opt to calculate pounds of Hg per year using
the average Hg concentration, average stack gas flow rate, average
stack gas moisture, and maximum operating hours per year.
    (1) Startup and Shutdown default values for calculations. For the
purposes of this rule and only during periods of startup or shutdown,
use a default diluent gas concentration value of 10.0 percent
O2 or the corresponding fuel-specific CO2
concentration in calculating emissions in units of lb/MMBtu or lb/TBtu.
For calculating emissions in units of lb/MWh or lb/GWh only during
startup or shutdown periods, use a nominal electrical production rate
equal to 5 percent of rated capacity.

Sec.  63.10006  When must I conduct subsequent performance tests, fuel
analyses, or tune-ups?

    (a) For solid oil-derived fuel- and coal-fired EGUs using total PM
emissions as a surrogate for non-Hg HAP metals emissions and using PM
CEMS to measure filterable PM emissions as a surrogate for total PM
emissions, you must conduct all applicable performance tests for PM and
non-Hg HAP metals emissions during the same compliance test period and
under the same process (e.g., fuel) and control device operating
conditions according to Table 5 and Sec.  63.10007 at least every 5
years.
    (b) For solid oil-derived fuel- and coal-fired EGUs with installed
systems that use wet or dry flue gas desulfurization technology using
sulfur dioxide (SO2) emissions as a surrogate for HCl
emissions and using SO2 CEMS to measure SO2
emissions, you must conduct all applicable performance tests for
SO2 and HCl emissions during the same compliance test period
and under the same process (e.g., fuel) and control device operating
conditions according to Table 5 and Sec.  63.10007 at least every 5
years.
    (c) For affected units meeting the LEE requirements of Sec.
63.1005(k), provided that the unit operates within the operating limits
established during the initial performance test, you need only repeat
the performance test once every 5 years according to Table 5 and Sec.
63.10007 and conduct fuel sampling and analysis according to Table 6
and Sec.  63.10008 at least every month. However, if the unit fails to
operate within the operating limits during any 5 year compliance
period, LEE status is lost. If this should occur:
    (1) For all pollutants or surrogates except for Hg, you must
initiate periodic emission testing, as required in the applicable
paragraph(s) of this section, within a six month period.
    (2) For Hg, you must install, certify, maintain, and operate a Hg
CEMS or a sorbent trap monitoring system in accordance with appendix A
to this subpart, within a one year period.
    (d) For solid oil-derived fuel- and coal-fired EGUs without PM CEMS
but with PM emissions control devices, you must conduct all applicable
performance tests for PM and non-Hg HAP metals emissions during the
same compliance test period and under the same process (e.g., fuel) and
control device operating conditions according to Table 5 and Sec.
63.10007 at least every year and you must conduct non-Hg HAP metals
emissions testing according to Table 5 and Sec.  63.10007 at least
every other month.
    (e) For solid oil-derived fuel- and coal-fired EGUs without PM CEMS
and without PM emissions control devices, you must conduct all
applicable performance tests for non-Hg HAP metals emissions according
to Table 5 and Sec.  63.10007 at least every month.
    (f) For liquid oil-fired EGUs with non-Hg HAP metals control
devices, you must conduct all applicable performance tests for
individual or total HAP metals emissions according to Table 5 and Sec.
63.10007 at least every other month.
    (g) For liquid oil-fired EGUs without non-Hg HAP metals control
devices, you must conduct all applicable performance tests for
individual or total HAP metals emissions according to Table 5 and Sec.
63.10007 at least every month.
    (h) For solid oil-derived fuel- and coal-fired EGUs without
SO2 CEMS but with installed systems that use wet or dry flue
gas desulfurization technology, you must conduct all applicable
performance tests for SO2 and HCl emissions during the same
compliance test period and under the same process (e.g., fuel) and
control device operating conditions according to Table 5 and Sec.
63.10007 at least every year and you must conduct SO2
emissions testing according to Sec.  63.10007 at least every other
month.
    (i) For solid oil-derived fuel- and coal-fired EGUs without
SO2 CEMS and without installed systems that use wet or dry
flue gas desulfurization technology, you must conduct all applicable
performance tests for SO2 and HCl emissions during the same
compliance test period and under the same process (e.g., fuel) and
control device operating conditions according to Table 5 and Sec.
63.10007 at least every year and you must conduct HCl

emissions testing according to Table 5 and Sec.  63.10007 at least
every month.
    (j) For solid oil-derived fuel- and coal-fired EGUs without HCl
CEMS but with HCl emissions control devices, you must conduct all
applicable performance tests for HCl emissions according to Table 5 and
Sec.  63.10007 at least every other month.
    (k) For solid oil-derived fuel- and coal-fired EGUs without HCl
CEMS and without HCl emissions control devices, you must conduct all
applicable performance tests for HCl emissions according to Table 5 and
Sec.  63.10007 at least every month.
    (l) For liquid oil-fired EGUs without HCl and HF CEMS but with HCl
and HF emissions control devices, you must conduct all applicable
performance tests for HCl and HF emissions according to Table 5 and
Sec.  63.10007 at least every other month.
    (m) For liquid oil-fired EGUs without HCl and HF CEMS and without
HCl and HF emissions control devices, you must conduct all applicable
performance tests for HCl and HF emissions according to Table 5 and
Sec.  63.10007 at least every month.
    (n) Unless you follow the requirements listed in paragraphs (o)
through (q) of this section, performance tests required at least every
5 years must be completed within 58 to 62 months after the previous
performance test; performance tests required at least every year must
be completed no more than 13 months after the previous performance
test; performance tests required at least every 2 months must be
completed between 52 and 69 days after the previous performance test;
and performance tests required at least every month must be completed
between 21 and 38 days after the previous performance test.
    (o) For EGUs with annual or more frequent performance testing
requirements, you can conduct performance stack tests less often for a
given pollutant if your performance stack tests for the pollutant for
at least 3 consecutive years show that your emissions are at or below
50 percent of the emissions limit, and if there are no changes in the
operation of the affected source or air pollution control equipment
that could increase emissions. In this case, you do not have to conduct
a performance test for that pollutant for the next 2 years. You must
conduct a performance test during the third year and no more than 37
months after the previous performance test. If you elect to demonstrate
compliance using emission averaging under Sec.  63.10009, you must
continue to conduct performance stack tests at the appropriate
frequency given in section (c) through (m) of this paragraph.
    (p) If your EGU continues to meet the emissions limit for the
pollutant, you may choose to conduct performance stack tests for the
pollutant every third year if your emissions are at or below the
emission limit, and if there are no changes in the operation of the
affected source or air pollution control equipment that could increase
emissions, but each such performance test must be conducted no more
than 37 months after the previous performance test. If you elect to
demonstrate compliance using emission averaging under Sec.  63.10009,
you must continue to conduct performance stack tests at the appropriate
frequency given in section (c) through (m) of this paragraph.
    (q) If a performance test shows emissions in excess of 50 percent
of the emission limit, you must conduct performance tests at the
appropriate frequency given in section (c) through (m) of this
paragraph for that pollutant until all performance tests over a
consecutive 3-year period show compliance.
    (r) If you are required to meet an applicable tune-up work practice
standard, you must conduct a performance tune-up according to Sec.
63.10007. Each performance tune-up specified in Sec.  63.10007 must be
no more than 18 months after the previous performance tune-up.
    (s) If you demonstrate compliance with the Hg, individual or total
non-Hg HAP metals, HCl, or HF emissions limit based on fuel analysis,
you must conduct a monthly fuel analysis according to Sec.  63.10008
for each type of fuel burned. If you burn a new type of fuel, you must
conduct a fuel analysis before burning the new type of fuel in your
EGU. You must still meet all applicable continuous compliance
requirements in Sec.  63.10021.
    (t) You must report the results of performance tests, performance
tune-ups, and fuel analyses within 60 days after the completion of the
performance tests, performance tune-ups, and fuel analyses. This report
must also verify that the operating limits for your affected EGU have
not changed or provide documentation of revised operating parameters
established according to Sec.  63.10011 and Table 7 to this subpart, as
applicable. The reports for all subsequent performance tests must
include all applicable information required in Sec.  63.10031.

Sec.  63.10007  What methods and other procedures must I use for the
performance tests?

    (a) You must conduct all performance tests according to Sec.
63.7(c), (d), (f), and (h). You must also develop a site-specific test
plan according to the requirements in Sec.  63.7(c).
    (b) You must conduct each performance test according to the
requirements in Table 5 to this subpart.
    (c) You must conduct each performance test under the specific
conditions listed in Tables 5 and 7 to this subpart. You must conduct
performance tests at the maximum normal operating load while burning
the type of fuel or mixture of fuels that has the highest content of
chlorine, fluorine, non-Hg HAP metals, and Hg, and you must demonstrate
initial compliance and establish your operating limits based on these
tests. These requirements could result in the need to conduct more than
one performance test. Moreover, should you desire to have differing
operating limits which correspond to loads other than maximum normal
operating load, you should conduct testing at those other loads to
determine those other operating limits. Following each performance test
and until the next performance test, you must comply with the operating
limit for operating load conditions specified in Table 4 of this
subpart.
    (d) For performance testing that does not involve CMS or a sorbent
trap monitoring system, you must conduct three separate test runs for
each performance test required, as specified in Sec.  63.7(e)(3). Each
test run must comply with the minimum applicable sampling times or
volumes specified in Tables 1 and 2 to this subpart. For performance
testing that involves CMS or a sorbent trap monitoring system,
compliance shall be determined as described in Sec.  63.10005(d) and
(e).
    (e) To determine compliance with the emission limits, you must use
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA
Method 19 at 40 CFR part 60, Appendix A-7 of this chapter to convert
the measured PM concentrations, the measured HCl and HF concentrations,
the measured SO2 concentrations, the measured individual and
total non-Hg HAP metals concentrations, and the measured Hg
concentrations that result from the initial performance test to pounds
per million Btu (lb/MMBtu) (pounds per trillion Btu, lb/TBtu, for Hg)
heat input emission rates using F-factors.
    (f) Performance tests shall be conducted under such conditions as
the EPA Administrator specifies to the owner or operator based on

representative performance of the affected source for the period being
tested. Upon request, the owner or operator shall make available to the
EPA Administrator such records as may be necessary to determine the
conditions of performance tests.

Sec.  63.10008  What fuel analyses and procedures must I use for the
performance tests?

    (a) You must conduct performance fuel analysis tests according to
the procedures in paragraphs (b) through (e) of this section and Table
6 to this subpart, as applicable. You are not required to conduct fuel
analyses for fuels used only for startup, unit shutdown, or transient
flame stability purposes.
    (b) You must develop and submit a site-specific fuel analysis plan
to the EPA Administrator for review and approval according to the
following procedures and requirements in paragraphs (b)(1) and (2) of
this section.
    (1) You must submit the fuel analysis plan no later than 60 days
before the date that you intend to demonstrate compliance.
    (2) You must include the information contained in paragraphs
(b)(2)(i) through (vi) of this section in your fuel analysis plan.
    (i) The identification of all fuel types anticipated to be burned
in each EGU.
    (ii) For each fuel type, the notification of whether you or a fuel
supplier will be conducting the fuel analysis.
    (iii) For each fuel type, a detailed description of the sample
location and specific procedures to be used for collecting and
preparing the composite samples if your procedures are different from
paragraph (c) or (d) of this section. Samples should be collected at a
location that most accurately represents the fuel type, where possible,
at a point prior to mixing with other dissimilar fuel types.
    (iv) For each fuel type, the analytical methods from Table 6, with
the expected minimum detection levels, to be used for the measurement
of chlorine, fluorine, non-Hg HAP metals, or Hg.
    (v) If you request to use an alternative analytical method other
than those required by Table 6 to this subpart, you must also include a
detailed description of the methods and procedures that you are
proposing to use. Methods in Table 6 shall be used until the requested
alternative is approved.
    (vi) If you will be using fuel analysis from a fuel supplier in
lieu of site-specific sampling and analysis, the fuel supplier must use
the analytical methods required by Table 6 to this subpart.
    (c) At a minimum, you must obtain three composite fuel samples for
each fuel type according to the procedures in paragraph (c)(1) or (2)
of this section.
    (1) If sampling from a belt (or screw) feeder, collect fuel samples
according to paragraphs (c)(1)(i) and (ii) of this section.
    (i) Stop the belt and withdraw a 6-inch wide sample from the full
cross-section of the stopped belt to obtain a minimum two pounds of
sample. You must collect all the material (fines and coarse) in the
full cross-section. You must transfer the sample to a clean plastic
bag.
    (ii) Each composite sample will consist of a minimum of three
samples collected at approximately equal 1-hour intervals during the
testing period.
    (2) If sampling from a fuel pile or truck, you must collect fuel
samples according to paragraphs (c)(2)(i) through (iii) of this
section.
    (i) For each composite sample, you must select a minimum of five
sampling locations uniformly spaced over the surface of the pile.
    (ii) At each sampling site, you must dig into the pile to a depth
of 18 inches. You must insert a clean flat square shovel into the hole
and withdraw a sample, making sure that large pieces do not fall off
during sampling.
    (iii) You must transfer all samples to a clean plastic bag for
further processing.
    (d) You must prepare each composite sample according to the
procedures in paragraphs (d)(1) through (7) of this section.
    (1) You must thoroughly mix and pour the entire composite sample
over a clean plastic sheet.
    (2) You must break sample pieces larger than 3 inches into smaller
sizes.
    (3) You must make a pie shape with the entire composite sample and
subdivide it into four equal parts.
    (4) You must separate one of the quarter samples as the first
subset.
    (5) If this subset is too large for grinding, you must repeat the
procedure in paragraph (d)(3) of this section with the quarter sample
and obtain a one-quarter subset from this sample.
    (6) You must grind the sample in a mill.
    (7) You must use the procedure in paragraph (d)(3) of this section
to obtain a one-quarter subsample for analysis. If the quarter sample
is too large, subdivide it further using the same procedure.
    (e) You must determine the concentration of pollutants in the fuel
(Hg, HAP metals, and/or chlorine) in units of lb/MMBtu of each
composite sample for each fuel type according to the procedures in
Table 6 to this subpart.

Sec.  63.10009  May I use emission averaging to comply with this
subpart?

    (a) As an alternative to meeting the requirements of Sec.  63.9991
for PM, HF, HCl, non-Hg HAP metals, or Hg on an EGU-specific basis, if
you have more than one existing EGU in the same subcategory located at
one or more contiguous properties, belonging to a single major
industrial grouping, which are under common control of the same person
(or persons under common control), you may demonstrate compliance by
emission averaging among the existing EGUs in the same subcategory, if
your averaged emissions for such EGUs are equal to or less than the
applicable emission limit, according to the procedures in this section.
    (b) Separate stack requirements. For a group of two or more
existing EGUs in the same subcategory that each vent to a separate
stack, you may average PM, HF, HCl, non-Hg HAP metals, or Hg emissions
to demonstrate compliance with the limits in Table 2 to this subpart if
you satisfy the requirements in paragraphs (c), (d), (e), (f), and (g)
of this section.
    (c) For each existing EGU in the averaging group, the emission rate
achieved during the initial compliance test for the HAP being averaged
must not exceed the emission level that was being achieved on [THE DATE
30 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] or
the control technology employed during the initial compliance test must
not be less effective for the HAP being averaged than the control
technology employed on [THE DATE 30 DAYS AFTER PUBLICATION OF THE FINAL
RULE IN THE FEDERAL REGISTER].
    (d) The averaged emissions rate from the existing EGUs
participating in the emissions averaging option must be in compliance
with the limits in Table 2 to this subpart at all times following the
compliance date specified in Sec.  63.9984.
    (e) You must demonstrate initial compliance according to paragraph
(e)(1) or (2) of this section using the maximum normal operating load
of each EGU and the results of the initial performance tests or fuel
analysis.
    (1) You must use Equation 1 of this section to demonstrate that the
PM, HF, SO2, HCl, non-Hg HAP metals, or Hg emissions from
all existing units participating in the emissions averaging option do
not exceed the emission limits in Table 2 to this subpart.

[GRAPHIC] [TIFF OMITTED] TP03MY11.015

Where:

Ave Weighted Emissions = Average weighted emissions for PM, HF,
SO2, HCl, non-Hg HAP metals, or Hg, in units of lb/MMBtu
(lb/TBtu for Hg) of heat input.
Er = Emissions rate (as determined during the most recent
performance test, according to Table 5 to this subpart) for PM, HF,
HCl, non-Hg HAP metals, or Hg or by fuel analysis for Cl, F, non-Hg
HAP metals, or Hg as calculated by the applicable equation in Sec.
63.10011(c) for unit, i, for PM, HF, SO2, HCl, non-Hg HAP
metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Hm = Maximum rated heat input capacity of unit, i, in units of
million Btu per hour.
n = Number of units participating in the emissions averaging option.

    (2) If you are not capable of monitoring heat input, and the EGU
generates steam for purposes other than generating electricity, you may
use Equation 2 of this section as an alternative to using Equation 1 of
this section to demonstrate that the PM, HF, HCl, non-Hg HAP metals,
and Hg emissions from all existing units participating in the emissions
averaging option do not exceed the emission limits in Table 2 to this
subpart.
[GRAPHIC] [TIFF OMITTED] TP03MY11.016

Where:

Ave Weighted Emissions = Average weighted emission level for PM, HF,
HCl, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg)
of heat input.
Er = Emissions rate (as determined during the most recent
performance test, according to Table 5 to this subpart) for PM, HF,
HCl, non-Hg HAP metals, or Hg or by fuel analysis for Cl, F, non-Hg
HAP metals, or Hg as calculated by the applicable equation in Sec.
63.10011(c)) for unit, i, for PM, HCl, HF, HAP metals, or Hg, in
units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Sm = Maximum steam generation by unit, i, in units of pounds.
Cf = Conversion factor, calculated from the most recent compliance
test, in units of million Btu of heat input per pounds of steam
generated for unit, i.
n = Number of units participating in the emissions averaging option.

    (f) You must demonstrate compliance on a monthly basis determined
at the end of every month (12 times per year) according to paragraphs
(f)(1) through (3) of this section. The first monthly period begins on
the compliance date specified in Sec.  63.9984.
    (1) For each calendar month, you must use Equation 3 of this
section to calculate the monthly average weighted emission rate using
the actual heat capacity for each existing unit participating in the
emissions averaging option.
[GRAPHIC] [TIFF OMITTED] TP03MY11.017

Where:

Ave Weighted Emissions = Monthly average weighted emission level for
PM, HCl, HF, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu
for Hg) of heat input.
Er = Emissions rate, (as determined during the most recent
performance test, according to Table 5 to this subpart) for PM, HCl,
HF, non-Hg HAP metals, or Hg or by fuel analysis for Cl, F, non-Hg
HAP metals, or Hg as calculated by the applicable equation in Sec.
63.10011(c)) for unit, i, for PM, HCl, HF, non-Hg HAP metals, or Hg,
in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Hb = The average heat input for each calendar month of EGU, i, in
units of million Btu.
n = Number of units participating in the emissions averaging option.
    (2) If you are not capable of monitoring heat input, you may use
Equation 4 of this section as an alternative to using Equation 3 of
this section to calculate the monthly weighted emission rate using the
actual steam generation from the units participating in the emissions
averaging option.
[GRAPHIC] [TIFF OMITTED] TP03MY11.018

Where:

Ave Weighted Emissions = Monthly average weighted emission level for
PM, HCl, HF, HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for
Hg) of heat input.
Er = Emissions rate, (as determined during the most recent
performance test, as calculated according to Table 5 to this
subpart) for PM, HCl, HF, non-Hg HAP metals, or Hg or by fuel
analysis for Cl, F, and non-Hg HAP metals, or Hg as calculated by
the applicable equation in Sec.  63.10011(c)) for unit, i, for PM,
HCl, HF, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for
Hg) of heat input.
Sa = Actual steam generation for each calendar month by EGU, i, in
units of pounds.
Cf = Conversion factor, as calculated during the most recent
compliance test, in units of million Btu of heat input per pounds of
steam generated for unit, i.
n = Number of units participating in the emissions averaging option.

    (3) Until 12 monthly weighted average emission rates have been
accumulated, calculate and report only the monthly

average weighted emission rate determined under paragraph (f)(1) or (2)
of this section. After 12 monthly weighted average emission rates have
been accumulated, for each subsequent calendar month, use Equation 5 of
this section to calculate the 12-month rolling average of the monthly
weighted average emission rates for the current month and the previous
11 months.
[GRAPHIC] [TIFF OMITTED] TP03MY11.019

Where:

Eavg = 12-month rolling average emissions rate, (lb/MMBtu heat
input; lb/TBtu for Hg).
ERi = Monthly weighted average, for month ``i'' (lb/MMBtu (lb/TBtu
for Hg) heat input)(as calculated by (f)(1) or (2)).

    (g) You must develop, and submit to the applicable regulatory
authority for review and approval upon request, an implementation plan
for emission averaging according to the following procedures and
requirements in paragraphs (g)(1) through (4) of this section.
    (1) You must submit the implementation plan no later than 180 days
before the date that the facility intends to demonstrate compliance
using the emission averaging option.
    (2) You must include the information contained in paragraphs
(g)(2)(i) through (vii) of this section in your implementation plan for
all emission sources included in an emissions average:
    (i) The identification of all existing EGUs in the averaging group,
including for each either the applicable HAP emission level or the
control technology installed as of [DATE 60 DAYS AFTER PUBLICATION OF
THE FINAL RULE IN THE FEDERAL REGISTER] and the date on which you are
requesting emission averaging to commence;
    (ii) The process parameter (heat input or steam generated) that
will be monitored for each averaging group;
    (iii) The specific control technology or pollution prevention
measure to be used for each emission EGU in the averaging group and the
date of its installation or application. If the pollution prevention
measure reduces or eliminates emissions from multiple EGUs, the owner
or operator must identify each EGU;
    (iv) The test plan for the measurement of PM, HF, HCl, individual
or total non-Hg HAP metals, or Hg emissions in accordance with the
requirements in Sec.  63.10007;
    (v) The operating parameters to be monitored for each control
system or device consistent with Sec.  63.9991 and Table 4, and a
description of how the operating limits will be determined;
    (vi) If you request to monitor an alternative operating parameter
pursuant to Sec.  63.10010, you must also include:
    (A) A description of the parameter(s) to be monitored and an
explanation of the criteria used to select the parameter(s); and
    (B) A description of the methods and procedures that will be used
to demonstrate that the parameter indicates proper operation of the
control device; the frequency and content of monitoring, reporting, and
recordkeeping requirements; and a demonstration, to the satisfaction of
the applicable regulatory authority, that the proposed monitoring
frequency is sufficient to represent control device operating
conditions; and
    (vii) A demonstration that compliance with each of the applicable
emission limit(s) will be achieved under representative operating
conditions.
    (3) The regulatory authority shall review and approve or disapprove
the plan according to the following criteria:
    (i) Whether the content of the plan includes all of the information
specified in paragraph (g)(2) of this section; and
    (ii) Whether the plan presents sufficient information to determine
that compliance will be achieved and maintained.
    (4) The applicable regulatory authority shall not approve an
emission averaging implementation plan containing any of the following
provisions:
    (i) Any averaging between emissions of differing pollutants or
between differing sources; or
    (ii) The inclusion of any emission source other than an existing
unit in the same subcategory.
    (h) Common stack requirements. For a group of two or more existing
affected units, each of which vents through a single common stack, you
may average PM, HF, HCl, individual or total non-Hg HAP metals, or Hg
emissions to demonstrate compliance with the limits in Table 2 to this
subpart if you satisfy the requirements in paragraph (i) or (j) of this
section.
    (i) For a group of two or more existing units in the same
subcategory, each of which vents through a common emissions control
system to a common stack, that does not receive emissions from units in
other subcategories or categories, you may treat such averaging group
as a single existing unit for purposes of this subpart and comply with
the requirements of this subpart as if the group were a single unit.
    (j) For all other groups of units subject to paragraph (h) of this
section, the owner or operator may elect to:
    (1) Conduct performance tests according to procedures specified in
Sec.  63.10007 in the common stack if affected units from other
subcategories vent to the common stack. The emission limits that the
group must comply with are determined by the use of equation 6.
[GRAPHIC] [TIFF OMITTED] TP03MY11.020

Where:

En = HAP emissions limit, lb/MMBtu (lb/TBtu for Hg), ppm, or ng/
dscm.
ELi = Appropriate emissions limit from Table 2 to this subpart for
unit i, in units of lb/MMBtu (lb/TBtu for Hg), ppm, or ng/dscm.
Hi = Heat input from unit i, MMBtu.
n = Number of units.

    (2) Conduct performance tests according to procedures specified in
Sec.  63.10007 in the common stack. If affected units from nonaffected
units vent to the common stack,the units from nonaffected units must be
shut down or vented to a different stack during the performance test or
each affected and each nonaffected unit must meet the most stringent
emissions limit; and
    (3) Meet the applicable operating limit specified in Sec.  63.10021
and Table 8 to this subpart for each emissions control system (except
that, if each unit venting to the common stack has an applicable
opacity operating limit, then a single continuous opacity monitoring
system may be located in the common stack instead of in each duct to
the common stack).
    (k) Combination requirements. The common stack of a group of two or
more existing EGUs in the same subcategory subject to paragraph (h) of
this section may be treated as a single stack for purposes of paragraph
(b) of this section and included in an emissions averaging group
subject to paragraph (b) of this section.

Sec.  63.10010  What are my monitoring, installation, operation, and
maintenance requirements?

    (a) In some cases, existing affected units may exhaust through a
common stack configuration or may include a bypass stack. Emission
monitoring system installation provisions for possible stack
configurations are as follows.
    (1) Single Unit-Single Stack Configuration. For an affected unit
that exhausts to the atmosphere through a single, dedicated stack, the
owner or operator shall install CEMS and sorbent trap monitoring
systems in accordance

with the applicable performance specification or Appendix A to this
subpart.
    (2) Unit Utilizing Common Stack with Other Affected Unit(s). When
an affected unit utilizes a common stack with one or more other
affected units, but no non-affected units, the owner or operator shall
either:
    (i) Install CEMS and sorbent trap monitoring systems described in
this section in the duct to the common stack from each unit; or
    (ii) Install CEMS and sorbent trap monitoring systems described in
this section in the common stack.
    (3) Unit Utilizing Common Stack with Non-affected Units. When one
or more affected units shares a common stack with one or more non-
affected units, the owner or operator shall either:
    (i) Install CEMS and sorbent trap monitoring systems described in
this section in the duct to the common stack from each affected unit;
or