comes first, no owner or operator of an affected facility located in a
noncontinental area for which 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 emissions limit 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 (j) and (m) 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 for which
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 emissions limit specified in paragraphs (l)(1) and (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) 140 ng/J (1.2 lb/MWh) net energy output; or
    (iii) 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 located in a
noncontinental area for which 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 emissions limit specified in
paragraphs (m)(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.
0
15. Section 60.44Da is revised to read as follows:

Sec.  60.44Da  Standards for nitrogen oxides (NOX).

    (a) Except as provided in paragraph (h) 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 subject to the provisions of this subpart shall
cause to be discharged into the atmosphere from any affected facility
for which construction, reconstruction, or modification commenced
before July 10, 1997 any gases that contain NOX (expressed
as NO2) in excess of the applicable emissions limit in
paragraphs (a)(1) and (2) of this section.
    (1) The owner or operator shall not cause to be discharged into the
atmosphere any gases that contain NOX in excess of the
emissions limit listed in the following table as applicable to the fuel
type combusted and as determined on a 30-boiler operating day rolling
average basis.

------------------------------------------------------------------------
                                                 Emission limit for heat
                                                          input
                   Fuel type                   -------------------------
                                                    ng/J       lb/MMBtu
------------------------------------------------------------------------
Gaseous fuels:
    Coal-derived fuels........................          210         0.50
    All other fuels...........................           86         0.20
Liquid fuels:

    Coal-derived fuels........................          210         0.50
    Shale oil.................................          210         0.50
    All other fuels...........................          130         0.30
Solid fuels:
    Coal-derived fuels........................          210         0.50
    Any fuel containing more than 25%, by               (1)          (1)
     weight, coal refuse......................
Any fuel containing more than 25%, by weight,           340         0.80
 lignite if the lignite is mined in North
 Dakota, South Dakota, or Montana, and is
 combusted in a slag tap furnace \2\..........
Any fuel containing more than 25%, by weight,           260         0.60
 lignite not subject to the 340 ng/J heat
 input emission limit \2\.....................
Subbituminous coal............................          210         0.50
Bituminous coal...............................          260         0.60
Anthracite coal...............................          260         0.60
All other fuels...............................          260         0.60
------------------------------------------------------------------------
\1\ Exempt from NOX standards and NOX monitoring requirements.
\2\ Any fuel containing less than 25%, by weight, lignite is not
  prorated but its percentage is added to the percentage of the
  predominant fuel.

    (2) When two or more fuels are combusted simultaneously in an
affected facility, the applicable emissions limit (En) is
determined by proration using the following formula:
[GRAPHIC] [TIFF OMITTED] TR16FE12.019

Where:

En = Applicable NOX emissions limit when multiple fuels
are combusted simultaneously (ng/J heat input);
w = Percentage of total heat input derived from the combustion of
fuels subject to the 86 ng/J heat input standard;
x = Percentage of total heat input derived from the combustion of
fuels subject to the 130 ng/J heat input standard;
y = Percentage of total heat input derived from the combustion of
fuels subject to the 210 ng/J heat input standard;
z = Percentage of total heat input derived from the combustion of
fuels subject to the 260 ng/J heat input standard; and
v = Percentage of total heat input delivered from the combustion of
fuels subject to the 340 ng/J heat input standard.

    (b) [Reserved]
    (c) [Reserved]
    (d) Except as provided in paragraph (h) 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 July 9, 1997, but
before March 1, 2005, 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 emissions
limit specified in paragraphs (d)(1) and (2) of this section as
determined on a 30-boiler operating day rolling average basis.
    (1) For an affected facility which commenced construction, any
gases that contain NOX in excess of 200 ng/J (1.6 lb/MWh)
gross energy output.
    (2) For an affected facility which commenced reconstruction, any
gases that contain NOX in excess of 65 ng/J (0.15 lb/MMBtu)
heat input.
    (e) Except as provided in paragraphs (f) and (h) 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 emissions limit specified in paragraphs (e)(1) through (3)
of this section as determined on a 30-boiler operating day rolling
average basis.
    (1) For an affected facility which commenced construction, any
gases that contain NOX in excess of 130 ng/J (1.0 lb/MWh)
gross energy output.
    (2) For an affected facility which commenced reconstruction, any
gases that contain NOX 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 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 compliance 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) Except as provided in paragraphs (h) of this section and Sec.
60.45Da, 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 the applicable emissions limit specified
in paragraphs (g)(1) through (3) of this section.
    (1) For an affected facility which commenced construction or
reconstruction, any gases that contain NOX in excess of
either:
    (i) 88 ng/J (0.70 lb/MWh) gross energy output; or
    (ii) 95 ng/J (0.76 lb/MWh) net energy output.
    (2) For an affected facility which commenced construction or
reconstruction and that burns 75 percent or more coal refuse (by heat
input) on a 12-month rolling average basis, any gases that contain
NOX in excess of either:
    (i) 110 ng/J (0.85 lb/MWh) gross energy output; or
    (ii) 120 ng/J (0.92 lb/MWh) net energy output.
    (3) For an affected facility which commenced modification, any
gases that contain NOX in excess of 140 ng/J (1.1 lb/MWh)
gross energy output.
    (h) The NOX emissions limits 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.
0
16. Section 60.45Da is revised to read as follows:

Sec.  60.45Da  Alternative standards for combined nitrogen oxides (NOX)
and carbon monoxide (CO).

    (a) The owner or operator of an affected facility that commenced
construction, reconstruction, or modification after May 3, 2011 as
alternate to meeting the applicable NOX emissions limits
specified in Sec.  60.44Da may elect to meet the applicable standards
for combined NOX and CO specified in paragraph (b) of this
section.
    (b) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8 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) plus CO in
excess of the applicable emissions limit specified in paragraphs (b)(1)
through (3) of this section as determined on a 30-boiler operating day
rolling average basis.
    (1) For an affected facility which commenced construction or
reconstruction, any gases that contain NOX plus CO in excess
of either:
    (i) 140 ng/J (1.1 lb/MWh) gross energy output; or
    (ii) 150 ng/J (1.2 lb/MWh) net energy output.
    (2) For an affected facility which commenced construction or
reconstruction and that burns 75 percent or more coal refuse (by heat
input) on a 12-month rolling average basis, any gases that contain
NOX plus CO in excess of either:
    (i) 160 ng/J (1.3 lb/MWh) gross energy output; or
    (ii) 170 ng/J (1.4 lb/MWh) net energy output.
    (3) For an affected facility which commenced modification, any
gases that contain NOX plus CO in excess of 190 ng/J (1.5
lb/MWh) gross energy output.

0
17. Section 60.47Da is amended as follows:
0
a. By revising paragraph (c).
0
b. By adding paragraph (f).
0
c. By adding paragraph (g).
0
d. By adding paragraph (h).
0
e. By adding paragraph (i).

Sec.  60.47Da  Commercial demonstration permit.

* * * * *
    (c) An owner or operator of an affected facility that uses
fluidized bed combustion (atmospheric or pressurized) and who is issued
a commercial demonstration permit by the Administrator is not subject
to the SO2 emission reduction requirements under Sec.
60.43Da(a) but must, as a minimum, reduce SO2 emissions to
15 percent of the potential combustion concentration (85 percent
reduction) on a 30-day rolling average basis and to less than 520 ng/J
(1.20 lb/MMBtu) heat input on a 30-day rolling average basis.
* * * * *
    (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 6.4 ng/J (0.015 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 energy 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 control 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) or the combined NOX plus CO
emissions to less than 180 ng/J (1.4 lb/MWh) gross energy 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 listed in the following table.

------------------------------------------------------------------------
                                                              Equivalent
                                                              electrical
                                                               capacity
             Technology                     Pollutant            (MW
                                                              electrical
                                                               output)
------------------------------------------------------------------------
Multi-pollutant Emission Control....  SO2..................        1,000

Multi-pollutant Emission Control....  NOX..................        1,000
Multi-pollutant Emission Control....  PM...................        1,000
Pressurized Fluidized Bed Combustion  SO2..................        1,000
Pressurized Fluidized Bed Combustion  NOX..................        1,000
Pressurized Fluidized Bed Combustion  PM...................        1,000
Advanced Combustion Controls........  NOX..................        1,000
------------------------------------------------------------------------

0
18. Section 60.48Da is amended as follows:
0
a. By revising paragraphs (a) through (g).
0
b. By revising paragraph (i).
0
c. By revising paragraph (k)(1)(i).
0
d. By revising paragraph (k)(2)(i).
0
e. By revising paragraph (k)(2)(iv).
0
f. By removing and reserving paragraph (l).
0
g. By revising paragraph (m).
0
h. By revising paragraph (n).
0
i. By revising paragraphs (p)(5), (7), and (8).
0
j. By adding paragraph (r).
0
k. By adding paragraph (s).

Sec.  60.48Da  Compliance provisions.

    (a) For affected facilities for which construction, modification,
or reconstruction commenced before May 4, 2011, the applicable PM
emissions limit and opacity standard under Sec.  60.42Da,
SO2 emissions limit under Sec.  60.43Da, and NOX
emissions limit under Sec.  60.44Da apply at all times except during
periods of startup, shutdown, or malfunction. For affected facilities
for which construction, modification, or reconstruction commenced after
May 3, 2011, the applicable SO2 emissions limit under Sec.
60.43Da, NOX emissions limit under Sec.  60.44Da, and
NOX plus CO emissions limit under Sec.  60.45Da apply at all
times. The applicable PM emissions limit and opacity standard under
Sec.  60.42Da apply at all times except during periods of startup and
shutdown.
    (b) After the initial performance test required under Sec.  60.8,
compliance with the applicable SO2 emissions limit and
percentage reduction requirements under Sec.  60.43Da, NOX
emissions limit under Sec.  60.44Da, and NOX plus CO
emissions limit under Sec.  60.45Da is based on the average emission
rate for 30 successive boiler operating days. A separate performance
test is completed at the end of each boiler operating day after the
initial performance test, and a new 30-boiler operating day rolling
average emission rate for both SO2, NOX or
NOX plus CO as applicable, and a new percent reduction for
SO2 are calculated to demonstrate compliance with the
standards.
    (c) For the initial performance test required under Sec.  60.8,
compliance with the applicable SO2 emissions limits and
percentage reduction requirements under Sec.  60.43Da, the
NOX emissions limits under Sec.  60.44Da, and the
NOX plus CO emissions limits under Sec.  60.45Da is based on
the average emission rates for SO2, NOX, CO, and
percent reduction for SO2 for the first 30 successive boiler
operating days. The initial performance test is the only test in which
at least 30 days prior notice is required unless otherwise specified by
the Administrator. The initial performance test is to be scheduled so
that the first boiler operating day of the 30 successive boiler
operating days is completed within 60 days after achieving the maximum
production rate at which the affected facility will be operated, but
not later than 180 days after initial startup of the facility.
    (d) For affected facilities for which construction, modification,
or reconstruction commenced before May 4, 2011, compliance with
applicable 30-boiler operating day rolling average SO2 and
NOX emissions limits 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, or malfunction. For affected
facilities for which construction, modification, or reconstruction
commenced after May 3, 2011, compliance with applicable 30-boiler
operating day rolling average SO2 and NOX
emissions limits is determined by dividing the sum of the
SO2 and NOX emissions for the 30 successive
boiler operating days by the sum of the gross energy output or net
energy output, as applicable, for the 30 successive boiler operating
days.
    (e) For affected facilities for which construction, modification,
or reconstruction commenced 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 for which construction, modification, or
reconstruction commenced 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.
    (f) For affected facilities for which construction, modification,
or reconstruction commenced before May 4, 2011, compliance with
applicable daily average PM emissions limits 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. Daily 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. For
affected facilities for which construction, modification, or
reconstruction commenced after May 3, 2011, compliance with applicable
daily average PM emissions limits is determined by dividing the sum of
the PM emissions for the 30 successive boiler operating days by the sum
of the gross useful output or net energy output, as applicable, for the
30 successive boiler operating days.
    (g) For affected facilities for which construction, modification,
or reconstruction commenced after May 3, 2011, compliance with
applicable 30-boiler operating day rolling average NOX plus
CO emissions limit is determined by dividing the sum of the
NOX plus CO emissions for the 30 successive boiler operating
days by the sum of the gross energy output or net energy output, as

applicable, for the 30 successive boiler operating days.
* * * * *
    (i) Compliance provisions for sources subject to Sec.
60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), (f), or (g). The owner or
operator shall calculate NOX emissions as 1.194 x
10-7 lb/scf-ppm times the average hourly NOX
output concentration in ppm (measured according to the provisions of
Sec.  60.49Da(c)), times the average hourly flow rate (measured in
scfh, according to the provisions of Sec.  60.49Da(l) or Sec.
60.49Da(m)), divided by the average hourly gross energy output
(measured according to the provisions of Sec.  60.49Da(k)) or the
average hourly net energy output, as applicable. Alternatively, for
oil-fired and gas-fired units, NOX emissions may be
calculated by multiplying the hourly NOX emission rate in
lb/MMBtu (measured by the CEMS required under Sec.  60.49Da(c) and
(d)), by the hourly heat input rate (measured according to the
provisions of Sec.  60.49Da(n)), and dividing the result by the average
gross energy output (measured according to the provisions of Sec.
60.49Da(k)) or the average hourly net energy output, as applicable.
    (k) * * *
    (1) * * *
    (i) The emission rate (E) of NOX shall be computed using
Equation 2 in this section:
[GRAPHIC] [TIFF OMITTED] TR16FE12.000

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross energy 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/h (dscf/h);
Qte = Average hourly volumetric flow rate of exhaust gas
from combustion turbine, dscm/h (dscf/h);
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] TR16FE12.001

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross energy 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/h (dscf/h); 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/h) 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] TR16FE12.002

Where:

E = Emission rate of NOX from the duct burner, ng/J (lb/
MWh) gross energy 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/h (MMBtu/h); and
Occ = Average hourly gross energy output from entire
combined cycle unit, J/h (MW).

* * * * *
    (m) Compliance provisions for sources subject to Sec.
60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i),
(j)(3)(i), (l)(1)(i), (l)(1)(ii), or (l)(2). The owner or operator
shall calculate SO2 emissions as 1.660 x 10-7 lb/
scf-ppm times the average hourly SO2 output concentration in
ppm (measured according to the provisions of Sec.  60.49Da(b)), times
the average hourly flow rate (measured according to the provisions of
Sec.  60.49Da(l) or Sec.  60.49Da(m)), divided by the average hourly
gross energy output (measured according to the provisions of Sec.
60.49Da(k)) or the average hourly net energy output, as applicable.
Alternatively, for oil-fired and gas-fired units, SO2
emissions may be calculated by multiplying the hourly SO2
emission rate (in lb/MMBtu), measured by the CEMS required under Sec.
60.49Da, by the hourly heat input rate (measured according to the
provisions of Sec.  60.49Da(n)), and dividing the result by the average
gross energy output (measured according to the provisions of Sec.
60.49Da(k)) or the average hourly net energy output, as applicable.
    (n) Compliance provisions for sources subject to Sec.
60.42Da(c)(1) or (e)(1)(i). The owner or operator 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 dividing by the average hourly
gross energy output (measured according to the provisions

of Sec.  60.49Da(k)) or the average hourly net energy output, as
applicable.
* * * * *
    (p) * * *
    (5) At a minimum, non-out-of-control 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 or EPA Reference Method 19 of appendix A
of this part 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) Compliance provisions for sources subject to Sec.  60.45Da. To
determine compliance with the NOX plus CO emissions limit,
the owner or operator shall use the procedures specified in paragraphs
(r)(1) through (3) of this section.
    (1) Calculate NOX emissions as 1.194 x 10-7
lb/scf-ppm times the average hourly NOX output concentration
in ppm (measured according to the provisions of Sec.  60.49Da(c)),
times the average hourly flow rate (measured in scfh, according to the
provisions of Sec.  60.49Da(l) or Sec.  60.49Da(m)), divided by the
average hourly gross energy output (measured according to the
provisions of Sec.  60.49Da(k)) or the average hourly net energy
output, as applicable.
    (2) Calculate CO emissions by multiplying the average hourly CO
output concentration (measured according to the provisions of Sec.
60.49Da(u), by the average hourly flow rate (measured according to the
provisions of Sec.  60.49Da(l) or Sec.  60.49Da(m)), and dividing by
the average hourly gross energy output (measured according to the
provisions of Sec.  60.49Da(k)) or the average hourly net energy
output, as applicable.
    (3) Calculate NOX plus CO emissions by summing the
NOX emissions results from paragraph (r)(1) of this section
plus the CO emissions results from paragraph (r)(2) of this section.
    (s) Affirmative defense for exceedance of emissions limit during
malfunction. In response to an action to enforce the standards set
forth in paragraph Sec. Sec.  60.42Da, 60.43Da, 60.44Da, and 60.45Da,
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 as specified in paragraphs (s)(1) and (2) of
this section. 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 (s)(2) 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 emissions limits 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) Notification. The owner or operator of the affected source
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 or, if it is not
possible to determine within two business days whether the malfunction
caused or contributed to an exceedance, no later than two business days
after the owner or operator knew or should have known that the
malfunction caused or contributed to an exceedance, but, in no event
later than two business days after the end of the averaging period, 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 standard in Sec.  63.9991 to demonstrate, with all
necessary supporting documentation, that it has met the requirements
set forth in paragraph (s)(1) 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.

0
19. Section 60.49Da is amended as follows:
0
a. By revising paragraphs (a)(1) and (2).

0
b. By revising paragraph (a)(3) introductory text.
0
c. By revising paragraph (a)(3)(ii).
0
d. By revising paragraph (a)(3)(iii)(B).
0
e. By adding paragraph (a)(4).
0
f. By revising paragraph (b) introductory text.
0
g. By revising paragraph (b)(2).
0
h. By revising paragraph (e).
0
i. By revising paragraph (k) introductory text.
0
j. By revising paragraph (k)(3).
0
k. By revising paragraph (l).
0
l. By removing and reserving paragraph (p).
0
m. By removing and reserving paragraph (q).
0
n. By removing and reserving paragraph (r).
0
o. By revising paragraph (t).
0
p. By revising paragraph (u)(1)(iii).
0
q. By revising paragraph (v)(4).

Sec.  60.49Da  Emission monitoring.

    (a) * * *
    (1) Except as provided for in paragraphs (a)(2) and (4) 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.
    (A) No post-combustion technology (except a wet scrubber) is used
for reducing PM, SO2, or 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; or
    (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 operator 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.
* * * * *
    (ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this
section, the owner or operator shall conduct subsequent Method 9 of
appendix A-4 of this part performance tests using the procedures in
paragraph (a)(3)(i) of this section according to the applicable
schedule in paragraphs (a)(3)(ii)(A) through (a)(3)(ii)(C) of this
section, as determined by the most recent Method 9 of appendix A-4 of
this part performance test results.
    (A) If the maximum 6-minute average opacity is less than or equal
to 5 percent, 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;
    (B) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
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; or
    (C) If the maximum 6-minute average opacity is greater than 10
percent, a subsequent Method 9 of appendix A-4 of this part performance
test must be completed within 45 calendar days from the date that the
most recent performance test was conducted.
    (iii) * * *
    (B) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily
observations shall be resumed.
* * * * *
    (4) An owner or operator of an affected facility that is subject to
an opacity standard under Sec.  60.42a(b) is not required to operate a
COMS provided that affected facility meets the conditions in either
paragraph (a)(4)(i) or (ii) of this section.
    (i) The affected facility combusts only gaseous fuels and/or liquid
fuels (excluding residue oil) with a potential SO2 emissions
rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit 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.
For testing performed as part of this site-specific monitoring plan,
the permitting authority may require as an alternative to the
notification and reporting requirements specified in Sec. Sec.  60.8
and 60.11 that the owner or operator submit any deviations with the
excess emissions report required under Sec.  60.51a(d).
    (ii) The owner or operator of the affected facility installs,
calibrates, operates, and maintains a particulate matter continuous
parametric monitoring system (PM CPMS) according to the requirements
specified in subpart UUUUU of part 63.
    (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, and
malfunction, 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 energy output for sources
demonstrating compliance with an output-based standard.
* * * * *
    (3) For an affected facility generating process steam in
combination with electrical generation, the gross energy output is
determined according to the definition of ``gross energy output''
specified in Sec.  60.41Da that is applicable to the affected facility.
    (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 calibration drift (CD) assessment, relative accuracy test audit
(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 emissions limit 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).
* * * * *
    (v) * * *
    (4) As of January 1, 2012, and within 90 days after the date of
completing each performance test, as defined in Sec.  60.8, 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.
* * * * *

0
20. Section 60.50Da is amended as follows:
0
a. By revising paragraph (b).
0
b. By removing paragraph (g).
0
c. By removing paragraph (h).
0
d. By removing paragraph (i).

Sec.  60.50Da  Compliance determination procedures and methods.

* * * * *
    (b) In conducting the performance tests to determine compliance
with the PM emissions limits in Sec.  60.42Da, the owner or operator
shall meet the requirements specified in paragraphs (b)(1) through (3)
of this section.
    (1) The owner or operator shall measure filterable PM to determine
compliance with the applicable PM emissions limit in Sec.  60.42Da as
specified in paragraphs (b)(1)(i) through (ii) of this section.
    (i) The dry basis F factor (O2) procedures in Method 19
of appendix A of this part shall be used to compute the emission rate
of PM.
    (ii) For the PM concentration, Method 5 of appendix A of this part
shall be used for an affected facility that does not use a wet FGD. For
an affected facility that uses a wet FGD, Method 5B of appendix A of
this part shall be used downstream of the wet FGD.
    (A) The sampling time and sample volume for each run shall be at
least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder
heating system in the sampling train may be set to provide an average
gas temperature of no greater than 160  14 [deg]C (320
 25[emsp14][deg]F).
    (B) For each particulate run, the emission rate correction factor,
integrated or grab sampling and analysis procedures of Method 3B of
appendix A of this part shall be used to determine the O2
concentration. The O2 sample shall be obtained
simultaneously with, and at the same traverse points as, the
particulate run. If the particulate run has more than 12 traverse
points, the O2 traverse points may be reduced to 12 provided
that Method 1 of appendix A of this part is used to locate the 12
O2 traverse points. If the grab sampling procedure is used,
the O2 concentration for the run shall be the arithmetic
mean of the sample O2 concentrations at all traverse points.
    (2) In conjunction with a performance test performed according to
the requirements in paragraph (b)(1) of this section, the owner or
operator of an affected facility for which construction,
reconstruction, or modification commenced after May 3, 2011, shall
measure condensable PM using Method 202 of appendix M of part 51.
    (3) Method 9 of appendix A of this part and the procedures in Sec.
60.11 shall be used to determine opacity.
* * * * *
0
21. Section 60.51Da is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (b)(5).
0
c. By revising paragraph (d).
0
d. By removing and reserving paragraph (g).
0
e. By revising paragraph (k).

Sec.  60.51Da  Reporting requirements.

    (a) For SO2, NOX, PM, and NOX plus
CO emissions, the performance test data from the initial and subsequent
performance test and from the performance evaluation of the continuous
monitors (including the transmissometer) must be reported to the
Administrator.
    (b) * * *
    (5) Identification of the times when emissions data have been
excluded from the calculation of average emission rates because of
startup, shutdown, or malfunction.
* * * * *
    (d) In addition to the applicable requirements in Sec.  60.7, the
owner or operator of an affected facility subject to the opacity limits
in Sec.  60.43c(c) and conducting performance tests using Method 9 of
appendix A-4 of this part shall submit excess emission reports for any
excess emissions from the affected facility that occur during the
reporting period and maintain records according to the requirements
specified in paragraph (d)(1) of this section.
    (1) For each performance test conducted using Method 9 of appendix

A-4 of this part, the owner or operator shall keep the records
including the information specified in paragraphs (d)(1)(i) through
(iii) of this section.
    (i) Dates and time intervals of all opacity observation periods;
    (ii) Name, affiliation, and copy of current visible emission
reading certification for each visible emission observer participating
in the performance test; and
    (iii) Copies of all visible emission observer opacity field data
sheets.
    (2) [Reserved]
* * * * *
    (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) 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  [Amended]

0
22. Section 60.52Da is amended by removing and reserving paragraph (a).

Subpart Db--[Amended]

0
23. Section 60.40b is amended as follows:
0
a. By revising paragraph (c).
0
b. By revising paragraph (h).
0
c. By revising paragraph (i).
0
d. By adding paragraph (1).
0
e. By adding paragraph (m).

Sec.  60.40b  Applicability and delegation of authority.

* * * * *
    (c) Affected facilities that also meet the applicability
requirements under subpart J or subpart Ja of this part are subject to
the PM and NOX standards under this subpart and the
SO2 standards under subpart J or subpart Ja of this part, as
applicable.
* * * * *
    (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/h)
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 of this part (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.
    (m) Temporary boilers are not subject to this subpart.
    24. Section 60.41b is amended by revising the definition of
``distillate oil'', and adding the definition of ``temporary boiler''
in alphabetical order 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), kerosine, 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).
* * * * *
    Temporary boiler means any gaseous or liquid fuel-fired steam
generating unit that is designed to, and is capable of, being carried
or moved from one location to another by means of, for example, wheels,
skids, carrying handles, dollies, trailers, or platforms. A steam
generating unit is not a temporary boiler if any one of the following
conditions exists:
    (1) The equipment is attached to a foundation.
    (2) The steam generating unit or a replacement remains at a
location for more than 180 consecutive days. Any temporary boiler that
replaces a temporary boiler at a location and performs the same or
similar function will be included in calculating the consecutive time
period.
    (3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
    (4) The equipment is moved from one location to another in an
attempt to circumvent the residence time requirements of this
definition.
* * * * *
0
25. Section 60.43b is amended by revising paragraph (f) to read as
follows:

Sec.  60.43b  Standard for particulate matter (PM).

* * * * *
    (f) 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
combusts coal, oil, wood, or mixtures of these fuels with any other
fuels shall cause to be discharged into the atmosphere any gases that
exhibit greater than 20 percent opacity (6-minute average), except for
one 6-minute period per hour of not more than 27 percent opacity. An
owner or operator of an affected facility that elects to install,
calibrate, maintain, and operate a continuous emissions monitoring
system (CEMS) for measuring PM emissions according to the requirements
of this subpart and is subject to a federally enforceable PM limit of
0.030 lb/MMBtu or less is exempt from the opacity standard specified in
this paragraph.
* * * * *
0
26. Section 60.44b is amended as follows:
0
a. The section heading is revised.
0
b. By revising paragraph (b) introductory text.
0
c. By revising paragraph (c).
0
d. By revising paragraph (d).
0
e. By revising paragraph (e).
0
f. By revising paragraph (l)(1).

Sec.  60.44b  Standard for nitrogen oxides (NOX).

* * * * *
    (b) Except as provided under paragraphs (k) 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 mixtures of only coal, oil, or natural gas
shall cause to be discharged into the atmosphere from that affected
facility any gases that contain NOX in excess of a limit
determined by the use of the following formula:
* * * * *
    (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, natural gas (or any combination of
the three), and wood, 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, oil, natural gas (or any combination
of the three), combusted in the affected facility, as determined
pursuant to paragraph (a) or (b) of this section. This standard does
not apply to an affected facility that is subject to and in compliance
with 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, natural gas (or any combination of the three).
    (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 and/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.
    (e) Except as provided under paragraph (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 only coal, oil, or natural gas with byproduct/waste shall
cause to be discharged into the atmosphere any gases that contain
NOX in excess of the emission limit determined by the
following formula unless the affected facility has an annual capacity
factor for coal, oil, and 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:
* * * * *
    (l) * * *
    (1) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility
combusts coal, oil, or natural gas (or any combination of the three),
alone or with any other fuels. The affected facility is not subject to
this limit if it is subject to and in compliance with a federally
enforceable requirement that limits operation of the facility to an
annual capacity factor of 10 percent (0.10) or less for coal, oil, and
natural gas (or any combination of the three); or
* * * * *
0
27. 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 90 days after the date of
completing each performance test, as defined in Sec.  60.8, 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.
0
28. Section 60.48b is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By revising paragraphs (a)(1)(i) through (iii) .
0
c. By revising paragraph (a)(2)(ii).
0
d. By revising paragraph (j) introductory text.
0
e. By revising paragraph (j)(5).
0
f. By revising paragraph (j)(6).
0
g. By adding paragraph (j)(7).
0
h. By adding paragraph (l).

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;
    (ii) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed
within 6 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;
    (iii) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
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; or
* * * * *
    (2) * * *
    (ii) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an

opacity standard is applicable. If any visible emissions are observed,
daily observations shall be resumed.
* * * * *
    (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.
* * * * *
    (l) An owner or operator of an affected facility that is subject to
an opacity standard under Sec.  60.43b(f) is not required to operate a
COMS provided that the unit burns only gaseous fuels and/or liquid
fuels (excluding residue oil) with a potential SO2 emissions
rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit 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. For testing performed as part of
this site-specific monitoring plan, the permitting authority may
require as an alternative to the notification and reporting
requirements specified in Sec. Sec.  60.8 and 60.11 that the owner or
operator submit any deviations with the excess emissions report
required under Sec.  60.49b(h).
0
29. Section 60.49b is amended by revising paragraph (r)(1) to read as
follows.

Sec.  60.49b  Reporting and recordkeeping requirements.

* * * * *
    (r) * * *
    (1) The owner or operator of an affected facility who elects to
demonstrate that the affected facility combusts only very low sulfur
oil, natural gas, wood, a mixture of these fuels, or any of these fuels
(or a mixture of these fuels) in combination with other fuels that are
known to contain an insignificant amount of sulfur in Sec.  60.42b(j)
or Sec.  60.42b(k) shall obtain and maintain at the affected facility
fuel receipts (such as a current, valid purchase contract, tariff
sheet, or transportation contract) from the fuel supplier that certify
that the oil meets the definition of distillate oil and gaseous fuel
meets the definition of natural gas as defined in Sec.  60.41b and the
applicable sulfur limit. For the purposes of this section, the
distillate oil need not meet the fuel nitrogen content specification in
the definition of distillate oil. Reports shall be submitted to the
Administrator certifying that only very low sulfur oil meeting this
definition, natural gas, wood, and/or other fuels that are known to
contain insignificant amounts of sulfur were combusted in the affected
facility during the reporting period; or
* * * * *

Subpart Dc--[Amended]

0
30. Section 60.40c is amended as follows:
0
a. By revising paragraph (a).
0
b. By revising paragraph (e).
0
c. By revising paragraph (f).
0
d. By revising paragraph (g).
0
e. By adding paragraph (h).
0
f. By adding paragraph (i).

Sec.  60.40c  Applicability and delegation of authority.

    (a) Except as provided in paragraphs (d), (e), (f), and (g) of this
section, the affected facility to which this subpart applies is each
steam generating unit for which construction, modification, or
reconstruction is commenced after June 9, 1989 and that has a maximum
design heat input capacity of 29 megawatts (MW) (100 million British
thermal units per hour (MMBtu/h)) or less, but greater than or equal to
2.9 MW (10 MMBtu/h).
* * * * *
    (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/h) heat input of fossil fuel but less than or equal
to 29 MW (100 MMBtu/h) 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 affected 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 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.
    (h) Affected facilities that also meet the applicability
requirements under subpart J or subpart Ja of this part are subject to
the PM and NOX standards under this subpart and the
SO2 standards under subpart J or subpart Ja of this part, as
applicable.
    (i) Temporary boilers are not subject to this subpart.
0
31. Section 60.41c is amended as follows:
0
a. By removing the definition of ``Cogeneration.''
0
b. By revising the definition of ``Distillate oil.''
0
c. By adding a definition of ``Temporary boiler'' in alphabetical
order.

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), kerosine, 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).
* * * * *

    Temporary boiler means a steam generating unit that combusts
natural gas or distillate oil with a potential SO2 emissions
rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit is designed
to, and is capable of, being carried or moved from one location to
another by means of, for example, wheels, skids, carrying handles,
dollies, trailers, or platforms. A steam generating unit is not a
temporary boiler if any one of the following conditions exists:
    (1) The equipment is attached to a foundation.
    (2) The steam generating unit or a replacement remains at a
location for more than 180 consecutive days. Any temporary boiler that
replaces a temporary boiler at a location and performs the same or
similar function will be included in calculating the consecutive time
period.
    (3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
    (4) The equipment is moved from one location to another in an
attempt to circumvent the residence time requirements of this
definition.
* * * * *
0
32. Section 60.42c is amended as follows:
0
a. By revising paragraph (c)(1) and (3).
0
b. By revising paragraph (d).
0
c. By revising paragraph (e)(1)(ii).
0
d. By revising paragraph (h) introductory text.
0
e. By revising paragraph (h)(3).
0
f. By adding paragraph (h)(4).

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

* * * * *
    (c) * * *
    (1) Affected facilities that have a heat input capacity of 22 MW
(75 MMBtu/h) or less;
* * * * *
    (3) Affected facilities located in a noncontinental area; or
* * * * *
    (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.
    (e) * * *
    (1) * * *
    (ii) Has a heat input capacity greater than 22 MW (75 MMBtu/h); and
* * * * *
    (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/h).
    (4) Other fuels-fired affected facilities with heat input
capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/h).
* * * * *

0
33. Section 60.43c is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By revising paragraph (b) introductory text.
0
c. By revising paragraph (c).
0
d. By revising paragraphs (e)(1), (3), and (4).

Sec.  60.43c  Standard for particulate matter (PM).

    (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 of an affected facility that
commenced construction, reconstruction, or modification on or before
February 28, 2005, that combusts coal or combusts mixtures of coal with
other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/h) or
greater, shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of the following
emission limits:
* * * * *
    (b) 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 on or before
February 28, 2005, that combusts wood or combusts mixtures of wood with
other fuels (except coal) and has a heat input capacity of 8.7 MW (30
MMBtu/h) or greater, shall cause to be discharged into the atmosphere
from that affected facility any gases that contain PM in excess of the
following emissions limits:
* * * * *
    (c) 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
coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/h)
or greater shall cause to be discharged into the atmosphere from that
affected facility any gases that exhibit greater than 20 percent
opacity (6-minute average), except for one 6-minute period per hour of
not more than 27 percent opacity. 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 and are subject
to a federally enforceable PM limit of 0.030 lb/MMBtu or less are
exempt from the opacity standard specified in this paragraph (c).
* * * * *
    (e)(1) 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
commences construction, reconstruction, or modification after February
28, 2005, and that combusts coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any other fuels and has a heat input
capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged
into the atmosphere from that affected facility any gases that contain
PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, except as provided
in paragraphs (e)(2), (e)(3), and (e)(4) of this section.
* * * * *
    (3) 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
commences modification after February 28, 2005, and that combusts over
30 percent wood (by heat input) on an annual basis and has a heat input
capacity of 8.7 MW (30 MMBtu/h) or greater shall cause to be discharged
into the atmosphere from that affected facility any gases that contain
PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.
    (4) An owner or operator of an affected facility that commences
construction, reconstruction, or modification after February 28, 2005,
and that combusts only oil that contains no more than 0.50 weight
percent sulfur

or a mixture of 0.50 weight percent sulfur oil with other fuels not
subject to a PM standard under Sec.  60.43c and not using a post-
combustion technology (except a wet scrubber) to reduce PM or
SO2 emissions is not subject to the PM limit in this
section.

0
34. Section 60.45c is amended as follows:
0
a. By revising paragraph (c)(14).
0
b. By revising paragraph (d).

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

* * * * *
    (c) * * *
    (14) As of January 1, 2012, and within 90 days after the date of
completing each performance test, as defined in Sec.  60.8, 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.
    (d) The owner or operator of an affected facility seeking to
demonstrate compliance under Sec.  60.43c(e)(4) shall follow the
applicable procedures under Sec.  60.48c(f). For residual oil-fired
affected facilities, fuel supplier certifications are only allowed for
facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30
MMBtu/h).

0
35. Section 60.47c is amended as follows:
0
a. By revising paragraph (a) introductory text.
0
b. By revising paragraphs (a)(1)(i) through (iii).
0
c. By revising paragraph (a)(2)(ii).
0
d. By revising paragraph (f).
0
e. By removing paragraph (g).

Sec.  60.47c  Emission monitoring for particulate matter.

    (a) Except as provided in paragraphs (c), (d), (e), and (f) 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), or (f) 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;
    (ii) If visible emissions are observed but the maximum 6-minute
average opacity is less than or equal to 5 percent, a subsequent Method
9 of appendix A-4 of this part performance test must be completed
within 6 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;
    (iii) If the maximum 6-minute average opacity is greater than 5
percent but less than or equal to 10 percent, a subsequent Method 9 of
appendix A-4 of this part performance test must be completed within 3
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; or
* * * * *
    (2) * * *
    (ii) If no visible emissions are observed for 10 operating days
during which an opacity standard is applicable, observations can be
reduced to once every 7 operating days during which an opacity standard
is applicable. If any visible emissions are observed, daily
observations shall be resumed.
* * * * *
    (f) An owner or operator of an affected facility that is subject to
an opacity standard in Sec.  60.43c(c) is not required to operate a
COMS provided that the affected facility meets the conditions in either
paragraphs (f)(1), (2), or (3) of this section.
    (1) The affected facility uses a fabric filter (baghouse) as the
primary PM control device and, the owner or operator operates a bag
leak detection system to monitor the performance of the fabric filter
according to the requirements in section Sec.  60.48Da of this part.
    (2) The affected facility uses an ESP as the primary PM control
device, and the owner or operator uses an ESP predictive model to
monitor the performance of the ESP developed in accordance and operated
according to the requirements in section Sec.  60.48Da of this part.
    (3) The affected facility burns only gaseous fuels and/or fuel oils
that contain no greater than 0.5 weight percent sulfur, and the owner
or operator operates the unit 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. For testing performed as part of
this site-specific monitoring plan, the permitting authority may
require as an alternative to the notification and reporting
requirements specified in Sec. Sec.  60.8 and 60.11 that the owner or
operator submit any deviations with the excess emissions report
required under Sec.  60.48c(c).

Subpart HHHH--[Removed and Reserved]

0
36. Subpart HHHH is removed and reserved.

PART 63--[AMENDED]

0
37. The authority citation for 40 CFR Part 63 continues to read as
follows:

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

Subpart A--[Amended]

0
38. Section 63.14 is amended as follows:
0
a. By adding paragraphs (b)(19) and (20).
0
b. By adding paragraphs (b)(22) and (23).
0
c. By adding paragraphs (b)(69) through (72).
0
d. By revising paragraph (i)(1).

Sec.  63.14  Incorporation by reference.

* * * * *
    (b) * * *

    (19) ASTM D95-05 (Reapproved 2010), Standard Test Method for Water
in Petroleum Products and Bituminous Materials by Distillation,
approved May 1, 2010, IBR approved for Sec.  63.10005(i)(4)(i).
    (20) ASTM Method D388-05, Standard Classification of Coals by Rank,
approved September 15, 2005, IBR approved for Sec.  63.10042.
* * * * *
    (22) ASTM Method D396-10, Standard Specification for Fuel Oils,
including Appendix X1, approved October 1, 2010, IBR approved for Sec.
63.10042.
    (23) ASTM D4006-11, Standard Test Method for Water in Crude Oil by
Distillation, including Annex A1 and Appendix X1, approved June 1,
2011, IBR approved for Sec.  63.10005(i)(4)(ii).
* * * * *
    (69) ASTM D4057-06 (Reapproved 2011), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, including Annex A1,
approved June 1, 2011, IBR approved for Sec.  63.10005(i)(4)(iv).
    (70) ASTM D4177-95 (Reapproved 2010), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, including
Annexes A1 through A6 and Appendices X1 and X2, approved May 1, 2010,
IBR approved for Sec.  63.10005(i)(4)(iii).
    (71) ASTM D6348-03 (Reapproved 2010), Standard Test Method for
Determination of Gaseous Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR) Spectroscopy, including Annexes A1
through A8, approved October 1, 2010, IBR approved for table 1 to
subpart UUUUU of this part, table 2 to subpart UUUUU of this part,
table 5 to subpart UUUUU of this part, and appendix B to subpart UUUUU
of this part.
    (72) ASTM D6784-02 (Reapproved 2008), Standard Test Method for
Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary Sources (Ontario Hydro Method),
approved April 1, 2008, IBR approved for table 5 to subpart UUUUU of
this part, and appendix A to subpart UUUUU of this part.
* * * * *
    (i) * * *
    (1) ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses [part
10, Instruments and Apparatus],'' IBR approved for Sec. Sec.
63.309(k)(1)(iii), 63.865(b), 63.3166(a)(3), 63.3360(e)(1)(iii),
63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3),
63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2),
63.9323(a)(3), 63.11148(e)(3)(iii), 63.11155(e)(3), 63.11162(f)(3)(iii)
and (f)(4), 63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii),
63.11551(a)(2)(i)(C), table 5 to subpart DDDDD of this part, table 1 to
subpart ZZZZZ of this part, table 4 to subpart JJJJJJ of this part, and
table 5 to subpart UUUUU of this part.
* * * * *

0
39. 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?
63.9985 What is a new EGU?

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 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 or tune-
ups?
63.10007 What methods and other procedures must I use for the
performance tests?
63.10008 [Reserved]
63.10009 May I use emissions 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, operating limits, and work practice standards?
63.10022 How do I demonstrate continuous compliance under the
emissions averaging provision?
63.10023 How do I establish my PM CPMS operating limit and determine
compliance with it?

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--Establishing PM CPMS Operating
Limits
Table 7 to Subpart UUUUU of Part 63--Demonstrating Continuous
Compliance
Table 8 to Subpart UUUUU of Part 63--Reporting Requirements
Table 9 to Subpart UUUUU of Part 63--Applicability of General
Provisions to Subpart UUUUU
Appendix A to Subpart UUUUU--Hg Monitoring Provisions
Appendix B to Subpart UUUUU--HCl and HF 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) as
defined in Sec.  63.10042 of this subpart. 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 as defined in Sec.  63.10042 of this subpart.

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

    (a) This subpart applies to each individual or group of two 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 63.10042, within a
subcategory.
    (2) The affected source of this subpart is each new or
reconstructed coal- or oil-fired EGU as defined in 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 steam generating unit that meets the applicability
requirements after the effective date of this final rule due to a
change process (e.g., fuel or utilization) is considered to be an
existing source under this subpart.

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

    The types of electric steam generating units listed in paragraphs
(a) through (d) 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) unit, covered by
40 CFR part 63, subpart YYYY.
    (b) Any electric utility steam generating unit that is not a coal-
or oil-fired EGU and combusts natural gas for more than 10.0 percent of
the average annual heat input during any 3 calendar years or for more
than 15.0 percent of the annual heat input during any calendar year.
    (c) Any electric utility steam generating unit that has the
capability of combusting more than 25 MW of coal or oil but did not
fire coal or oil for more than 10.0 percent of the average annual heat
input during any 3 calendar years or for more than 15.0 percent of the
annual heat input during any calendar year. 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).
    (d) Any electric steam generating unit combusting solid waste is a
solid waste incineration unit subject to standards established under
sections 129 and 111 of the Clean Air Act.

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 April 16, 2012 or upon startup of your EGU, whichever
is later, and as further provided for in Sec.  63.10005(g).
    (b) If you have an existing EGU, you must comply with this subpart
no later than April 16, 2015.
    (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.
    (d) An electric steam generating unit that does not meet the
definition of an EGU subject to this subpart on April 16, 2012 for new
sources or April 16, 2015 for existing sources must comply with the
applicable existing source provisions of this subpart on the date such
unit meets the definition of an EGU subject to this subpart.
    (e) If you own or operate an electric steam generating unit that is
exempted from this subpart under Sec.  63.9983(d), if the manner of
operating the unit changes such that the combustion of waste is
discontinued and the unit becomes a coal-fired or oil-fired EGU (as
defined in Sec.  63.10042), you must be in compliance with this subpart
on April 16, 2015 or on the effective date of the switch from waste
combustion to coal or oil combustion, whichever is later.
    (f) You must demonstrate that compliance has been achieved, by
conducting the required performance tests and other activities, no
later than 180 days after the applicable date in paragraph (a), (b),
(c), (d), or (e) of this section.

Sec.  63.9985  What is a new EGU?

    (a) A new EGU is an EGU that meets any of the criteria specified in
paragraph (a)(1) through (a)(2) of this section.
    (1) An EGU that commenced construction after May 3, 2011.
    (2) An EGU that commenced reconstruction or modification after May
3, 2011.
    (b) [Reserved]

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 with a heating value greater than or
equal to 8,300 Btu/lb, and
    (2) EGUs designed for low rank virgin coal.
    (b) Oil-fired EGUs are subcategorized as noted in paragraphs (b)(1)
through (b)(4) of this section and as defined in Sec.  63.10042.
    (1) Continental liquid oil-fired EGUs
    (2) Non-continental liquid oil-fired EGUs,
    (3) Limited-use liquid oil-fired EGUs, and
    (4) 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 Sec.  63.10009.
    (2) You must meet each operating limit in Table 4 to this subpart
that applies to your EGU.
    (b) As provided in Sec.  63.6(g), the Administrator may approve use
of an alternative to the work practice standards in this section.
    (c) You may use the alternate SO2 limit in Tables 1 and
2 to this subpart only if your coal-fired EGU:
    (1) Has a system using wet or dry flue gas desulfurization
technology and SO2 continuous emissions monitoring system
(CEMS) installed on the unit; and
    (2) At all times, you operate the wet or dry flue gas
desulfurization technology installed on the unit consistent with Sec.
63.10000(b).

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 except during periods of startup and shutdown; however, for coal-
fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs, you are
required to meet the work practice requirements in Table 3 to this
subpart during periods of startup or shutdown.
    (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, to
demonstrate compliance with the applicable emission limits.
    (i) For a coal-fired or solid oil-derived fuel-fired EGU or IGCC
EGU, you may conduct the initial performance testing in accordance with
Sec.  63.10005(h), to determine whether the unit qualifies as a low
emitting EGU (LEE) for one or more applicable emissions limits, with
two exceptions:
    (A) You may not pursue the LEE option if your coal-fired, IGCC, or
solid oil-derived fuel-fired EGU is equipped with an acid gas scrubber
and has a main stack and bypass stack exhaust configuration, and
    (B) You may not pursue the LEE option for Hg if your coal-fired,
solid oil-fired fuel fired EGU or IGCC EGU is new.
    (ii) For a qualifying LEE for Hg emissions limits, you must conduct
a 30-day performance test using Method 30B at least once every 12
calendar months to demonstrate continued LEE status.
    (iii) For a qualifying LEE of any other applicable emissions
limits, you must conduct a performance test at least once every 36
calendar months to demonstrate continued LEE status.
    (iv) If your coal-fired or solid oil-derived fuel-fired EGU or IGCC
EGU does not qualify as a LEE for total non-mercury HAP metals,
individual non-mercury HAP metals, or filterable particulate matter
(PM), you must demonstrate compliance through an initial performance
test and you must monitor continuous performance through either use of
a particulate matter continuous parametric monitoring system (PM CPMS),
a PM CEMS, or compliance performance testing repeated quarterly.
    (A) If you elect to use PM CPMS, you will establish a site-specific
operating limit corresponding to the results of the performance test
demonstrating compliance with the pollutant with which you choose to
comply: total non-mercury HAP metals, individual non-mercury HAP metals
or filterable PM. You will use the PM CPMS to demonstrate continuous
compliance with this operating limit. If you elect to use a PM CPMS,
you must repeat the performance test annually for the selected
pollutant limit and reassess and adjust the site-specific operating
limit in accordance with the results of the performance test.
    (B) You may also opt to install and operate a particulate matter
CEMS certified in accordance with Performance Specification 11 and
Procedure 2 of 40 CFR part 60, Appendices B and F, respectively, in
accordance with Sec.  63.10010(i).
    (v) If your coal-fired or solid oil-derived fuel-fired EGU does not
qualify as a LEE for hydrogen chloride (HCl), you may demonstrate
initial and continuous compliance through use of an HCl CEMS, installed
and operated in accordance with Appendix B to this subpart. As an
alternative to HCl CEMS, you may demonstrate initial and continuous
compliance by conducting an initial and periodic quarterly performance
stack test for HCl. If your EGU uses wet or dry flue gas
desulfurization technology (this includes limestone injection into a
fluidized bed combustion unit), you may apply a second alternative to
HCl CEMS by installing and operating a sulfur dioxide (SO2)
CEMS installed and operated in accordance with part 75 of this chapter
to demonstrate compliance with the applicable SO2 emissions
limit.
    (vi) If your coal-fired or solid oil-derived fuel-fired EGU does
not qualify as a LEE for Hg, you must demonstrate initial and
continuous compliance through use of a Hg CEMS or a sorbent trap
monitoring system, in accordance with appendix A to this subpart.
    (2) For liquid oil-fired EGUs, except limited use liquid oil-fired
EGUs, initial performance testing is required for all pollutants, to
demonstrate compliance with the applicable emission limits.
    (i) For an existing liquid oil-fired unit, you may conduct the
performance testing in accordance with Sec.  63.10005(h), to determine
whether the unit qualifies as a LEE for one or more pollutants. For a
qualifying LEE for Hg emissions limits, you must conduct a 30-day
performance test using Method 30B at least once every 12 calendar
months to demonstrate continued LEE status. For a qualifying LEE of any
other applicable emissions limits, you must conduct a performance test
at least once every 36 calendar months to demonstrate continued LEE
status.
    (ii) If your existing liquid oil-fired unit does not qualify as a
LEE for total HAP metals (including mercury), individual metals
(including mercury), or filterable PM you must demonstrate compliance
through an initial performance test and you must monitor continuous
performance through either use of a PM CPMS, a PM CEMS, or performance
testing conducted quarterly.
    (A) If you elect to use PM CPMS, you will establish a site-specific
operating limit corresponding to the results of the performance test
demonstrating compliance with the pollutant with which you choose to
comply: total HAP metals, individual HAP metals, or filterable PM. You
will use the PM CPMS to demonstrate continuous compliance with this
operating limit. If you elect to use a PM CPMS, you must repeat the
performance test at least annually for the selected pollutant limit and
reassess and adjust the site-specific operating limit in accordance
with the results of the performance test.
    (B) If you elect to use a PM CEMS, you will use the CEMS in
accordance with Sec.  63.10010(i) to demonstrate initial and continuous
compliance with the filterable PM emission limit.
    (iii) If your existing liquid oil-fired unit does not qualify as a
LEE for hydrogen chloride (HCl) or for hydrogen fluoride (HF), you may
demonstrate initial and continuous compliance through use of an HCl
CEMS, an HF CEMS, or an HCl and HF CEMS, installed and operated in
accordance with Appendix B to this rule. As an alternative to HCl CEMS,
HF CEMS, or HCl and HF CEMS, you may demonstrate initial and continuous
compliance by conducting periodic quarterly performance stack tests for
HCl and HF. If you elect to demonstrate compliance through quarterly
performance testing, then you must also develop a site-specific
monitoring plan to ensure that the operations of the unit remain
consistent with those during the performance test. As another
alternative, you may measure or obtain, and keep

records of, fuel moisture content; as long as fuel moisture does not
exceed 1.0 percent by weight, you need not conduct other HCl or HF
monitoring or testing.
    (iv) If your unit qualifies as a limited-use liquid oil-fired as
defined in Sec.  63.10042, then you are not subject to the emission
limits in Tables 1 and 2, but must comply with the performance tune-up
work practice requirements in Table 3.
    (d)(1) 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), 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. This requirement also
applies to you if you petition the 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. Using the process
described in Sec.  63.8(f)(4), you may request approval of monitoring
system quality assurance and quality control procedures alternative to
those specified in this paragraph of this section and, if approved,
include those in your site-specific monitoring plan. The monitoring
plan must address the provisions in paragraphs (d)(2) through (5) of
this section.
    (2) The site-specific monitoring plan shall include the information
specified in paragraphs (d)(5)(i) through (d)(5)(vii) of this section.
Alternatively, the requirements of paragraphs (d)(5)(i) through
(d)(5)(vii) are considered to be met for a particular CMS or sorbent
trap monitoring system if:
    (i) The CMS or sorbent trap monitoring system is installed,
certified, maintained, operated, and quality-assured either according
to part 75 of this chapter, or appendix A or B to this subpart; and
    (ii) The recordkeeping and reporting requirements of part 75 of
this chapter, or appendix A or B to this subpart, that pertain to the
CMS are met.
    (3) If requested by the Administrator, you must submit the
monitoring plan (or relevant portion of the plan) at least 60 days
before the initial performance evaluation of a particular CMS, except
where the CMS has already undergone a performance evaluation that meets
the requirements of Sec.  63.10010 (e.g., if the CMS was previously
certified under another program).
    (4) You must operate and maintain the CMS according to the site-
specific monitoring plan.
    (5) The provisions of the site-specific monitoring plan must
address the following items:
    (i) Installation of the CEMS 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). See Sec.  63.10010(a) for further details. For CPMS
installations, follow the procedures in Sec.  63.10010(h).
    (ii) Performance and equipment specifications for the sample
interface, the pollutant concentration or parametric signal analyzer,
and the data collection and reduction systems.
    (iii) Schedule for conducting initial and periodic performance
evaluations.
    (iv) 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).
    (v) On-going operation and maintenance procedures, in accordance
with the general requirements of Sec. Sec.  63.8(c)(1)(ii), (c)(3), and
(c)(4)(ii).
    (vi) Conditions that define a CMS 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).
    (vii) On-going recordkeeping and reporting procedures, in
accordance with the general requirements of Sec. Sec.  63.10(c),
(e)(1), and (e)(2)(i), or as specifically required under this subpart.
    (e) As part of your demonstration of continuous compliance, you
must perform periodic tune-ups of your EGU(s), according to Sec.
63.10021(e).
    (f) You are subject to the requirements of this subpart for at
least 6 months following the last date you met the definition of an EGU
subject to this subpart (e.g., 6 months after a cogeneration unit
provided more than one third of its potential electrical output
capacity and more than 25 megawatts electrical output to any power
distributions system for sale). You may opt to remain subject to the
provisions of this subpart beyond 6 months after the last date you met
the definition of an EGU subject to this subpart, unless you are a
solid waste incineration unit subject to standards under CAA section
129 (e.g., 40 CFR part 60, subpart CCCC (New Source Performance
Standards (NSPS) for Commercial and Industrial Solid Waste Incineration
Units, or Subpart DDDD (Emissions Guidelines (EG) for Existing
Commercial and Industrial Solid Waste Incineration Units).
Notwithstanding the provisions of this subpart, an EGU that starts
combusting solid waste is immediately subject to standards under CAA
section 129 and the EGU remains subject to those standards until the
EGU no longer meets the definition of a solid waste incineration unit
consistent with the provisions of the applicable CAA section 129
standards.
    (g) If you no longer meet the definition of an EGU subject to this
subpart you must be in compliance with any newly applicable standards
on the date you are no longer subject to this subpart. The date you are
no longer subject to this subpart is a date selected by you, that must
be at least 6 months from the date that you last met the definition of
an EGU subject to this subpart or the date you begin combusting solid
waste, consistent with Sec.  63.9983(d). Your source must remain in
compliance with this subpart until the date you select to cease
complying with this subpart or the date you begin combusting solid
waste, whichever is earlier.
    (h)(1) If you own or operate an EGU that does not meet the
definition of an EGU subject to this subpart on April 16, 2015, and you
commence or recommence operations that cause you to meet the definition
of an EGU subject to this subpart, you are subject to the provisions of
this subpart, including, but not limited to, the emission limitations
and the monitoring requirements, as of the first day you meet the
definition of an EGU subject to this subpart. You must complete all
initial compliance demonstrations for this subpart applicable to your
EGU within 180 days after you commence or recommence operations that
cause you to meet the definition of an EGU subject to this subpart.
    (2) You must provide 30 days prior notice of the date you intend to
commence or recommence operations that cause you to meet the definition
of an EGU subject to this subpart. The notification must identify:
    (i) The name of the owner or operator of the EGU, the location of
the facility, the unit(s) that will commence or recommence operations
that will cause the unit(s) to meet the definition of an EGU subject to
this subpart, and the date of the notice;
    (ii) The 40 CFR part 60, part 62, or part 63 subpart and
subcategory

currently applicable to your unit(s), and the subcategory of this
subpart that will be applicable after you commence or recommence
operation that will cause the unit(s) to meet the definition of an EGU
subject to this subpart;
    (iii) The date on which you became subject to the currently
applicable emission limits;
    (iv) The date upon which you will commence or recommence operations
that will cause your unit to meet the definition of an EGU subject to
this subpart, consistent with paragraph (f) of this section.
    (i)(1) If you own or operate an EGU subject to this subpart, and it
has been at least 6 months since you operated in a manner that caused
you to meet the definition of an EGU subject to this subpart, you may,
consistent with paragraph (g) of this section, select the date on which
your EGU will no longer be subject to this subpart. You must be in
compliance with any newly applicable section 112 or 129 standards on
the date you selected.
    (2) You must provide 30 days prior notice of the date your EGU will
cease complying with this subpart. The notification must identify:
    (i) The name of the owner or operator of the EGU(s), the location
of the facility, the EGU(s) that will cease complying with this
subpart, and the date of the notice;
    (ii) The currently applicable subcategory under this subpart, and
any 40 CFR part 60, part 62, or part 63 subpart and subcategory that
will be applicable after you cease complying with this subpart;
    (iii) The date on which you became subject to this subpart;
    (iv) The date upon which you will cease complying with this
subpart, consistent with paragraph (g) of this section.
    (j) All air pollution control equipment necessary for compliance
with any newly applicable emissions limits which apply as a result of
the cessation or commencement or recommencement of operations that
cause your EGU to meet the definition of an EGU subject to this subpart
must be installed and operational as of the date your source ceases to
be or becomes subject to this subpart.
    (k) All monitoring systems necessary for compliance with any newly
applicable monitoring requirements which apply as a result of the
cessation or commencement or recommencement of operations that cause
your EGU to meet the definition of an EGU subject to this subpart must
be installed and operational as of the date your source ceases to be or
becomes subject to this subpart. All calibration and drift checks must
be performed as of the date your source ceases to be or becomes subject
to this subpart. You must also comply with provisions of Sec. Sec.
63.10010, 63.10020, and 63.10021 of this subpart. Relative accuracy
tests must be performed as of the performance test deadline for PM
CEMS, if applicable. Relative accuracy testing for other CEMS need not
be repeated if that testing was previously performed consistent with
CAA section 112 monitoring requirements or monitoring requirements
under this subpart.

Sec.  63.10001  Affirmative defense for exceedence of emission limit
during malfunction.

    In response to an action to enforce the standards set forth in
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 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.
    (a) 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:
    (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 affected source 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) Notification. The owner or operator of the affected source
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 or, if it is not
possible to determine within two business days whether the malfunction
caused or contributed to an exceedance, no later than two business days
after the owner or operator knew or should have known that the
malfunction caused or contributed to an exceedance, but, in no event
later than two business days after the end of the averaging period, 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 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 exceedance.

Testing and Initial Compliance Requirements

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

    (a) General requirements. For each of your affected EGUs, you must
demonstrate initial compliance with each applicable emissions limit in
Table 1 or 2 of this subpart through performance testing. Where two
emissions limits are specified for a particular pollutant (e.g., a heat
input-based limit in lb/MMBtu and an electrical output-based limit in
lb/MWh), you may demonstrate compliance with either emission limit. For
a particular compliance demonstration, you may be required to conduct
one or more of the following activities in conjunction with performance
testing: collection of hourly electrical load data (megawatts);
establishment of operating limits according to Sec.  63.10011 and
Tables 4 and 7 to this subpart; and CMS performance evaluations. In all
cases, you must demonstrate initial compliance no later than the
applicable date in paragraph (f) of this section for tune-up work
practices for existing EGUs, in Sec.  63.9984 for other requirements
for existing EGUs, and in paragraph (g) of this section for all
requirements for new EGUs.
    (1) To demonstrate initial compliance with an applicable emissions
limit in Table 1 or 2 to this subpart using stack testing, the initial
performance test generally consists of three runs at specified process
operating conditions using approved methods. If you are required to
establish operating limits (see paragraph (d) of this section and Table
4 to this subpart), you must collect all applicable parametric data
during the performance test period. Also, if you choose to comply with
an electrical output-based emission limit, you must collect hourly
electrical load data during the test period.
    (2) To demonstrate initial compliance using either a CMS that
measures HAP concentrations directly (i.e., an Hg, HCl, or HF CEMS, or
a sorbent trap monitoring system) or an SO2 or PM CEMS, the
initial performance test consists of 30 boiler operating days of data
collected by the initial compliance demonstration date specified in
Sec.  63.10005 with the certified monitoring system.
    (i) The 30-boiler operating day CMS performance test must
demonstrate compliance with the applicable Hg, HCl, HF, PM, or
SO2 emissions limit in Table 1 or 2 to this subpart.
    (ii) If you choose to comply with an electrical output-based
emission limit, you must collect hourly electrical load data during the
performance test period.
    (b) Performance testing requirements. If you choose to use
performance testing to demonstrate initial compliance with the
applicable emissions limits in Tables 1 and 2 to this subpart for your
EGUs, you must conduct the tests according to Sec.  63.10007 and Table
5 to this subpart. For the purposes of the initial compliance
demonstration, you may use test data and results from a performance
test conducted prior to the date on which compliance is required as
specified in Sec.  63.9984, provided that the following conditions are
fully met:
    (1) For a performance test based on stack test data, the test was
conducted no more than 12 calendar months prior to the date on which
compliance is required as specified in Sec.  63.9984;
    (2) For a performance test based on data from a certified CEMS or
sorbent trap monitoring system, the test consists of all valid data CMS
data recorded in the 30 boiler operating days immediately preceding
that date;
    (3) The performance test was conducted in accordance with all
applicable requirements in Sec.  63.10007 and Table 5 to this subpart;
    (4) A record of all parameters needed to convert pollutant
concentrations to units of the emission standard (e.g., stack flow
rate, diluent gas concentrations, hourly electrical loads) is available
for the entire performance test period; and
    (5) For each performance test based on stack test data, you
certify, and keep documentation demonstrating, that the EGU
configuration, control devices, and fuel(s) have remained consistent
with conditions since the prior performance test was conducted.
    (c) Operating limits. In accordance with Sec.  63.10010 and Table 4
to this subpart, you may be required to establish operating limits
using PM CPMS and using site-specific monitoring for certain liquid
oil-fired units as part of your initial compliance demonstration.
    (d) CMS requirements. If, for a particular emission or operating
limit, you are required to (or elect to) demonstrate initial compliance
using a continuous monitoring system, the CMS must pass a performance
evaluation prior to the initial compliance demonstration. If a CMS has
been previously certified under another state or federal program and is
continuing to meet the on-going quality-assurance (QA) requirements of
that program, then, provided that the certification and QA provisions
of that program meet the applicable requirements of Sec. Sec.
63.10010(b) through (h), an additional performance evaluation of the
CMS is not required under this subpart.
    (1) For an affected coal-fired, solid oil-derived fuel-fired, or
liquid oil-fired EGU, you may demonstrate initial compliance with the
applicable SO2, HCl, or HF emissions limit in Table 1 or 2
of this subpart through use of an SO2, HCl, or HF CEMS
installed and operated in accordance with part 75 of this chapter or
Appendix B to this subpart, as applicable. You may also demonstrate
compliance with a filterable PM emission limit in Table 1 or 2 of this
subpart through use of a PM CEMS installed, certified, and operated in
accordance with Sec.  63.10010(i). Initial compliance is achieved if
the arithmetic average of 30-boiler operating days of quality-assured
CEMS data, expressed in units of the standard (see Sec.  63.10007(e)),
meets the applicable SO2, PM, HCl, or HF emissions limit in
Table 1 or 2 to this subpart. Use Equation 19-19 of Method 19 in
appendix A-7 to part 60 of this chapter to calculate the 30-boiler
operating day average emissions rate. (Note: for this calculation, the
term Ehj in Equation 19-19 must be in the same units of