commenced construction, reconstruction, or modification on or before
February 28, 2005 that combusts coal or combusts mixtures of coal with
other fuels, shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of the following
emission limits:
    (1) 22 ng/J (0.051 lb/MMBtu) heat input,
    (i) If the affected facility combusts only coal, or
    (ii) If the affected facility combusts coal and other fuels and has
an annual capacity factor for the other fuels of 10 percent (0.10) or
less.
    (2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility
combusts coal and other fuels and has an annual capacity factor for the
other fuels greater than 10 percent (0.10) and is subject to a
federally enforceable requirement limiting operation of the affected
facility to an annual capacity factor greater than 10 percent (0.10)
for fuels other than coal.
    (3) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility
combusts coal or coal and other fuels and
    (i) Has an annual capacity factor for coal or coal and other fuels
of 30 percent (0.30) or less,
    (ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or
less,
    (iii) Has a federally enforceable requirement limiting operation of
the affected facility to an annual capacity factor of 30 percent (0.30)
or less for coal or coal and other solid fuels, and
    (iv) Construction of the affected facility commenced after June 19,
1984, and before November 25, 1986.
    (4) An affected facility burning coke oven gas alone or in
combination with other fuels not subject to a PM standard under Sec.
60.43b and not using a post combustion technology (except a wet
scrubber) for reducing PM or SO2 emissions is not subject to
the PM limits under Sec.  60.43b(a).
    (b) On and after the date on which the performance test is
completed or required to be completed under Sec.  60.8, whichever comes
first, no owner or operator of an affected facility that commenced
construction, reconstruction, or modification on or before February 28,
2005, and that combusts oil (or mixtures of oil with other fuels) and
uses a conventional or emerging technology to reduce SO2
emissions 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.
    (c) On and after the date on which the initial performance test is
completed or is required to be completed under Sec.  60.8, whichever
comes first, no owner or operator of an affected facility that
commenced construction, reconstruction, or modification on or before
February 28, 2005, and that combusts wood, or wood with other fuels,
except coal, shall cause to be discharged from that affected facility
any gases that contain PM in excess of the following emission limits:
    (1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has
an annual capacity factor greater than 30 percent (0.30) for wood.
    (2) 86 ng/J (0.20 lb/MMBtu) heat input if
    (i) The affected facility has an annual capacity factor of 30
percent (0.30) or less for wood;
    (ii) Is subject to a federally enforceable requirement limiting
operation of the affected facility to an annual capacity factor of 30
percent (0.30) or less for wood; and
    (iii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or
less.
    (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
combusts municipal-type solid waste or mixtures of municipal-type solid
waste with other fuels, shall cause to be discharged into the
atmosphere from that affected facility any gases that

contain PM in excess of the following emission limits:
    (1) 43 ng/J (0.10 lb/MMBtu) heat input;
    (i) If the affected facility combusts only municipal-type solid
waste; or
    (ii) If the affected facility combusts municipal-type solid waste
and other fuels and has an annual capacity factor for the other fuels
of 10 percent (0.10) or less.
    (2) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility
combusts municipal-type solid waste or municipal-type solid waste and
other fuels; and
    (i) Has an annual capacity factor for municipal-type solid waste
and other fuels of 30 percent (0.30) or less;
    (ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or
less;
    (iii) Has a federally enforceable requirement limiting operation of
the affected facility to an annual capacity factor of 30 percent (0.30)
or less for municipal-type solid waste, or municipal-type solid waste
and other fuels; and
    (iv) Construction of the affected facility commenced after June 19,
1984, but on or before November 25, 1986.
    (e) For the purposes of this section, the annual capacity factor is
determined by dividing the actual heat input to the steam generating
unit during the calendar year from the combustion of coal, wood, or
municipal-type solid waste, and other fuels, as applicable, by the
potential heat input to the steam generating unit if the steam
generating unit had been operated for 8,760 hours at the maximum heat
input capacity.
    (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.
    (g) The PM and opacity standards apply at all times, except during
periods of startup, shutdown or malfunction. (h)(1) Except as provided
in paragraphs (h)(2), (h)(3), (h)(4), and (h)(5) 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 commenced
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 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,
    (2) As an alternative to meeting the requirements of paragraph
(h)(1) of this section, the owner or operator of an affected facility
for which modification commenced after February 28, 2005, may elect to
meet the requirements of this paragraph. 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
commences modification after February 28, 2005 shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain PM in excess of both:
    (i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion
of coal, oil, wood, a mixture of these fuels, or a mixture of these
fuels with any other fuels; and
    (ii) 0.2 percent of the combustion concentration (99.8 percent
reduction) when combusting coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any other fuels.
    (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 maximum
heat input capacity of 73 MW (250 MMBtu/h) or less 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) 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 maximum
heat input capacity greater than 73 MW (250 MMBtu/h) shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain PM in excess of 37 ng/J (0.085 lb/MMBtu) heat input.
    (5) 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 only oil that contains no more than 0.3
weight percent sulfur, coke oven gas, a mixture of these fuels, or
either fuel (or a mixture of these fuels) in combination with other
fuels not subject to a PM standard under Sec.  60.43b and not using a
post combustion technology (except a wet scrubber) to reduce
SO2 or PM emissions is subject to the PM limits under Sec.
60.43b(h)(1).

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

    (a) 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 is
subject to the provisions of this section and that combusts only coal,
oil, or natural gas shall cause to be discharged into the atmosphere
from that affected facility any gases that contain NOX
(expressed as NO2) in excess of the following emission
limits:

------------------------------------------------------------------------
                                                 Nitrogen Oxide Emission
                                                  Limits (expressed as
        Fuel/steam generating unit type              NO2) Heat Input
                                               -------------------------
                                                    ng/J       lb/MMBtu
------------------------------------------------------------------------
(1) Natural gas and distillate oil, except
 (4):
    (i) Low heat release rate.................           43         0.10
    (ii) High heat release rate...............           86         0.20
(2) Residual oil:
    (i) Low heat release rate.................          130         0.30
    (ii) High heat release rate...............          170         0.40
(3) Coal:

    (i) Mass-feed stoker......................          210         0.50
    (ii) Spreader stoker and fluidized bed              260         0.60
     combustion...............................
    (iii) Pulverized coal.....................          300         0.70
    (iv) Lignite, except (v)..................          260         0.60
    (v) Lignite mined in North Dakota, South            340         0.80
     Dakota, or Montana and combusted in a
     slag tap furnace.........................
    (vi) Coal-derived synthetic fuels.........          210         0.50
(4) Duct burner used in a combined cycle
 system:
    (i) Low heat release rate.................           86         0.20
    (ii) High heat release rate 43............          170         0.40
------------------------------------------------------------------------

    (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 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:
[GRAPHIC] [TIFF OMITTED] TP09FE07.028

Where:

En = NOX emission limit (expressed as
NO2), ng/J (lb/MMBtu);
ELgo = Appropriate emission limit from paragraph (a)(1)
for combustion of natural gas or distillate oil, ng/J (lb/MMBtu);
Hgo = Heat input from combustion of natural gas or
distillate oil, J (MMBtu);
ELro = Appropriate emission limit from paragraph (a)(2)
for combustion of residual oil, ng/J (lb/MMBtu);
Hro = Heat input from combustion of residual oil, J
(MMBtu);
ELc = Appropriate emission limit from paragraph (a)(3)
for combustion of coal, ng/J (lb/MMBtu); and
Hc = Heat input from combustion of coal, J (MMBtu).

    (c) 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 coal or oil, or a mixture of these fuels with natural gas, and
wood, municipal-type solid waste, or any other fuel shall cause to be
discharged into the atmosphere any gases that contain NOX in
excess of the emission limit for the coal or oil, or mixtures of these
fuels with natural gas combusted in the affected facility, as
determined pursuant to paragraph (a) or (b) of this section, unless the
affected facility has an annual capacity factor for coal or oil, or
mixture of these fuels with natural gas of 10 percent (0.10) or less
and is subject to a federally enforceable requirement that limits
operation of the affected facility to an annual capacity factor of 10
percent (0.10) or less for coal, oil, or a mixture of these fuels with
natural gas.
    (d) On and after the date on which the initial performance test is
completed or is required to be completed under Sec.  60.8, whichever
date comes first, no owner or operator of an affected facility that
simultaneously combusts natural gas 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 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.
    (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 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:
[GRAPHIC] [TIFF OMITTED] TP09FE07.029

Where:

    En = NOX emission limit (expressed as
NO2), ng/J (lb/MMBtu);
ELgo = Appropriate emission limit from paragraph (a)(1)
for combustion of natural gas or distillate oil, ng/J (lb/MMBtu);
Hgo = Heat input from combustion of natural gas,
distillate oil and gaseous byproduct/waste, J (MMBtu);
ELro = Appropriate emission limit from paragraph (a)(2)
for combustion of residual oil and/or byproduct/waste, ng/J (lb/
MMBtu);
Hro = Heat input from combustion of residual oil, J
(MMBtu);
ELc = Appropriate emission limit from paragraph (a)(3)
for combustion of coal, ng/J (lb/MMBtu); and
Hc = Heat input from combustion of coal, J (MMBtu).

    (f) Any owner or operator of an affected facility that combusts
byproduct/waste with either natural gas or oil may petition the
Administrator within 180 days of the initial startup of the affected
facility to establish a NOX emission limit that shall apply
specifically to that affected facility when the byproduct/waste is
combusted. The petition shall include sufficient and appropriate data,
as determined by the Administrator, such as NOX emissions
from the affected facility, waste composition (including nitrogen
content), and combustion conditions to allow the Administrator to
confirm that the affected facility is unable to comply with the
emission limits in paragraph (e) of this section and to determine the
appropriate emission limit for the affected facility.
    (1) Any owner or operator of an affected facility petitioning for a
facility-specific NOX emission limit under this section
shall:
    (i) Demonstrate compliance with the emission limits for natural gas
and distillate oil in paragraph (a)(1) of this section or for residual
oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, by
conducting a 30-day performance test as provided in Sec.  60.46b(e).
During the performance test only natural gas, distillate oil, or

residual oil shall be combusted in the affected facility; and
    (ii) Demonstrate that the affected facility is unable to comply
with the emission limits for natural gas and distillate oil in
paragraph (a)(1) of this section or for residual oil in paragraph
(a)(2) or (l)(1) of this section, as appropriate, when gaseous or
liquid byproduct/waste is combusted in the affected facility under the
same conditions and using the same technological system of emission
reduction applied when demonstrating compliance under paragraph
(f)(1)(i) of this section.
    (2) The NOX emission limits for natural gas or
distillate oil in paragraph (a)(1) of this section or for residual oil
in paragraph (a)(2) or (l)(1) of this section, as appropriate, shall be
applicable to the affected facility until and unless the petition is
approved by the Administrator. If the petition is approved by the
Administrator, a facility-specific NOX emission limit will
be established at the NOX emission level achievable when the
affected facility is combusting oil or natural gas and byproduct/waste
in a manner that the Administrator determines to be consistent with
minimizing NOX emissions. In lieu of amending this subpart,
a letter will be sent to the facility describing the facility-specific
NOX limit. The facility shall use the compliance procedures
detailed in the letter and make the letter available to the public. If
the Administrator determines it is appropriate, the conditions and
requirements of the letter can be reviewed and changed at any point.
    (g) Any owner or operator of an affected facility that combusts
hazardous waste (as defined by 40 CFR part 261 or 40 CFR part 761) with
natural gas or oil may petition the Administrator within 180 days of
the initial startup of the affected facility for a waiver from
compliance with the NOX emission limit that applies
specifically to that affected facility. The petition must include
sufficient and appropriate data, as determined by the Administrator, on
NOX emissions from the affected facility, waste destruction
efficiencies, waste composition (including nitrogen content), the
quantity of specific wastes to be combusted and combustion conditions
to allow the Administrator to determine if the affected facility is
able to comply with the NOX emission limits required by this
section. The owner or operator of the affected facility shall
demonstrate that when hazardous waste is combusted in the affected
facility, thermal destruction efficiency requirements for hazardous
waste specified in an applicable federally enforceable requirement
preclude compliance with the NOX emission limits of this
section. The NOX emission limits for natural gas or
distillate oil in paragraph (a)(1) of this section or for residual oil
in paragraph (a)(2) or (l)(1) of this section, as appropriate, are
applicable to the affected facility until and unless the petition is
approved by the Administrator. (See 40 CFR 761.70 for regulations
applicable to the incineration of materials containing polychlorinated
biphenyls (PCB's).) In lieu of amending this subpart, a letter will be
sent to the facility describing the facility-specific NOX
limit. The facility shall use the compliance procedures detailed in the
letter and make the letter available to the public. If the
Administrator determines it is appropriate, the conditions and
requirements of the letter can be reviewed and changed at any point.
    (h) For purposes of paragraph (i) of this section, the
NOX standards under this section apply at all times
including periods of startup, shutdown, or malfunction.
    (i) Except as provided under paragraph (j) of this section,
compliance with the emission limits under this section is determined on
a 30-day rolling average basis.
    (j) Compliance with the emission limits under this section is
determined on a 24-hour average basis for the initial performance test
and on a 3-hour average basis for subsequent performance tests for any
affected facilities that:
    (1) Combust, alone or in combination, only natural gas, distillate
oil, or residual oil with a nitrogen content of 0.30 weight percent or
less;
    (2) Have a combined annual capacity factor of 10 percent or less
for natural gas, distillate oil, and residual oil with a nitrogen
content of 0.30 weight percent or less; and
    (3) Are subject to a federally enforceable requirement limiting
operation of the affected facility to the firing of natural gas,
distillate oil, and/or residual oil with a nitrogen content of 0.30
weight percent or less and limiting operation of the affected facility
to a combined annual capacity factor of 10 percent or less for natural
gas, distillate oil, and residual oil with a nitrogen content of 0.30
weight percent or less.
    (k) Affected facilities that meet the criteria described in
paragraphs (j)(1), (2), and (3) of this section, and that have a heat
input capacity of 73 MW (250 MMBtu/hr) or less, are not subject to the
NOX emission limits under this section.
    (l) 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
commenced construction or reconstruction after July 9, 1997 shall cause
to be discharged into the atmosphere from that affected facility any
gases that contain NOX (expressed as NO2) in
excess of the following limits:
    (1) If the affected facility combusts coal, oil, or natural gas, or
a mixture of these fuels, or with any other fuels: A limit of 86 ng/JI
(0.20 lb/MMBtu) heat input 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 facility to an annual capacity factor of 10 percent
(0.10) or less for coal, oil, and natural gas; or
    (2) If the affected facility has a low heat release rate and
combusts natural gas or distillate oil in excess of 30 percent of the
heat input on a 30-day rolling average from the combustion of all
fuels, a limit determined by use of the following formula:
[GRAPHIC] [TIFF OMITTED] TP09FE07.030

Where:

En = NOX emission limit (lb/MMBtu);
Hgo = 30-day heat input from combustion of natural gas or
distillate oil; and
Hr = 30-day heat input from combustion of any other fuel.

    (3) After February 27, 2006, units where more than 33 percent of
total annual output is electrical or mechanical may comply with an
optional limit of 270 ng/J (2.1 lb/MWh) gross energy output, based on a
30-day rolling average. Units complying with this output-based limit
must demonstrate compliance according to the procedures of Sec.
60.48Da(i) of subpart Da of this part, and must monitor emissions
according to Sec.  60.49Da(c), (k), through (n) of subpart Da of this
part.

Sec.  60.45b  Compliance and performance test methods and procedures
for sulfur dioxide.

    (a) The SO2 emission standards under Sec.  60.42b apply
at all times. Facilities burning coke oven gas alone or in combination
with any other gaseous fuels or distillate oil and complying with the
fuel based limit under Sec.  60.42b(k)(2) are allowed to exceed the
limit 30 operating days per calendar year for by-product plant
maintenance.
    (b) In conducting the performance tests required under Sec.  60.8,
the owner or operator shall use the methods and

procedures in appendix A (including fuel certification and sampling) of
this part or the methods and procedures as specified in this section,
except as provided in Sec.  60.8(b). Section 60.8(f) does not apply to
this section. The 30-day notice required in Sec.  60.8(d) applies only
to the initial performance test unless otherwise specified by the
Administrator.
    (c) The owner or operator of an affected facility shall conduct
performance tests to determine compliance with the percent of potential
SO2 emission rate (% Ps) and the SO2 emission
rate (Es) pursuant to Sec.  60.42b following the procedures listed
below, except as provided under paragraph (d) and (k) of this section.
    (1) The initial performance test shall be conducted over 30
consecutive operating days of the steam generating unit. Compliance
with the SO2 standards shall be determined using a 30-day
average. The first operating day included in the initial performance
test shall be scheduled within 30 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.
    (2) If only coal, only oil, or a mixture of coal and oil is
combusted, the following procedures are used:
    (i) The procedures in Method 19 of appendix A of this part are used
to determine the hourly SO2 emission rate (Eho)
and the 30-day average emission rate (Eao). The hourly
averages used to compute the 30-day averages are obtained from the
continuous emission monitoring system (CEMS) of Sec.  60.47b (a) or
(b).
    (ii) The percent of potential SO2 emission rate
(%Ps) emitted to the atmosphere is computed using the
following formula:
[GRAPHIC] [TIFF OMITTED] TP09FE07.031

Where:

%Ps = Potential SO2 emission rate, percent;
%Rg = SO2 removal efficiency of the control
device as determined by Method 19 of appendix A of this part, in
percent; and
%Rf = SO2 removal efficiency of fuel
pretreatment as determined by Method 19 of appendix A of this part,
in percent.

    (3) If coal or oil is combusted with other fuels, the same
procedures required in paragraph (c)(2) of this section are used,
except as provided in the following:
    (i) An adjusted hourly SO2 emission rate
(Eho\o\) is used in Equation 19-19 of Method 19 of appendix
A of this part to compute an adjusted 30-day average emission rate
(Eao\o\). The Eho\o\ is computed using the
following formula:
[GRAPHIC] [TIFF OMITTED] TP09FE07.032

Where:

Eho\o\ = Adjusted hourly SO2 emission rate,
ng/J (lb/MMBtu);
Eho = Hourly SO2 emission rate, ng/J (lb/
MMBtu);
Ew = SO2 concentration in fuels other than
coal and oil combusted in the affected facility, as determined by
the fuel sampling and analysis procedures in Method 19 of appendix A
of this part, ng/J (lb/MMBtu). The value Ew for each fuel
lot is used for each hourly average during the time that the lot is
being combusted; and
Xk = Fraction of total heat input from fuel combustion
derived from coal, oil, or coal and oil, as determined by applicable
procedures in Method 19 of appendix A of this part.

    (ii) To compute the percent of potential SO2 emission
rate (%Ps), an adjusted %Rg (%Rg\o\)
is computed from the adjusted Eao\o\ from paragraph
(b)(3)(i) of this section and an adjusted average SO2 inlet
rate (Eai\o\) using the following formula:
[GRAPHIC] [TIFF OMITTED] TP09FE07.033

    To compute Eai\o\, an adjusted hourly SO2
inlet rate (Ehi\o\) is used. The Ehi\o\ is
computed using the following formula:
[GRAPHIC] [TIFF OMITTED] TP09FE07.034

Where:

Ehi\o\ = Adjusted hourly SO2 inlet rate, ng/J
(lb/MMBtu); and
Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu).

    (4) The owner or operator of an affected facility subject to
paragraph (b)(3) of this section does not have to measure parameters
Ew or Xk if the owner or operator elects to
assume that Xk = 1.0. Owners or operators of affected
facilities who assume Xk = 1.0 shall:
    (i) Determine %Ps following the procedures in paragraph
(c)(2) of this section; and
    (ii) Sulfur dioxide emissions (Es) are considered to be
in compliance with SO2 emission limits under Sec.  60.42b.
    (5) The owner or operator of an affected facility that qualifies
under the provisions of Sec.  60.42b(d) does not have to measure
parameters Ew or Xk under paragraph (b)(3) of
this section if the owner or operator of the affected facility elects
to measure SO2 emission rates of the coal or oil following
the fuel sampling and analysis procedures under Method 19 of appendix A
of this part.
    (d) Except as provided in paragraph (j) of this section, the owner
or operator of an affected facility that combusts only very low sulfur
oil, has an annual capacity factor for oil of 10 percent (0.10) or
less, and is subject to a federally enforceable requirement limiting
operation of the affected facility to an annual capacity factor for oil
of 10 percent (0.10) or less shall:
    (1) Conduct the initial performance test over 24 consecutive steam
generating unit operating hours at full load;
    (2) Determine compliance with the standards after the initial
performance test based on the arithmetic average of the hourly
emissions data during each steam generating unit operating day if a
CEMS is used, or based on a daily average if Method 6B of appendix A of
this part or fuel sampling and analysis procedures under Method 19 of
appendix A of this part are used.
    (e) The owner or operator of an affected facility subject to Sec.
60.42b(d)(1) shall demonstrate the maximum design capacity of the steam
generating unit by operating the facility at maximum capacity for 24
hours. This demonstration will be made during the initial performance
test and a subsequent demonstration may be requested at any other time.
If the 24-hour average firing rate for the affected facility is less
than the maximum design capacity provided by the manufacturer of the
affected facility, the 24-hour average firing rate shall be used to
determine the capacity utilization rate for the affected facility,
otherwise the maximum design capacity provided by the manufacturer is
used.
    (f) For the initial performance test required under Sec.  60.8,
compliance with the SO2 emission limits and percent
reduction requirements under Sec.  60.42b is based on the average
emission rates and the average percent reduction for SO2 for
the first 30 consecutive steam generating unit operating days, except
as provided under paragraph (d) of this section. The initial
performance test is the only test for 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 steam
generating unit operating day of the 30 successive steam generating
unit operating days is completed within 30 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. The boiler load during the 30-day period does not have to be
the

maximum design load, but must be representative of future operating
conditions and include at least one 24-hour period at full load.
    (g) After the initial performance test required under Sec.  60.8,
compliance with the SO2 emission limits and percent
reduction requirements under Sec.  60.42b is based on the average
emission rates and the average percent reduction for SO2 for
30 successive steam generating unit operating days, except as provided
under paragraph (d). A separate performance test is completed at the
end of each steam generating unit operating day after the initial
performance test, and a new 30-day average emission rate and percent
reduction for SO2 are calculated to show compliance with the
standard.
    (h) Except as provided under paragraph (i) of this section, the
owner or operator of an affected facility shall use all valid
SO2 emissions data in calculating %Ps and
Eho under paragraph (c), of this section whether or not the
minimum emissions data requirements under Sec.  60.46b are achieved.
All valid emissions data, including valid SO2 emission data
collected during periods of startup, shutdown and malfunction, shall be
used in calculating %Ps and Eho pursuant to
paragraph (c) of this section.
    (i) During periods of malfunction or maintenance of the
SO2 control systems when oil is combusted as provided under
Sec.  60.42b(i), emission data are not used to calculate %Ps
or Es under Sec.  60.42b (a), (b) or (c), however, the
emissions data are used to determine compliance with the emission limit
under Sec.  60.42b(i).
    (j) The owner or operator of an affected facility that combusts
very low sulfur oil is not subject to the compliance and performance
testing requirements of this section if the owner or operator obtains
fuel receipts as described in Sec.  60.49b(r).
    (k) The owner or operator of an affected facility seeking to
demonstrate compliance under Sec. Sec.  60.42b(d)(4), 60.42b(j), and
60.42b(k)(2) shall follow the applicable procedures under Sec.
60.49b(r).

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

    (a) The PM emission standards and opacity limits under Sec.  60.43b
apply at all times except during periods of startup, shutdown, or
malfunction. The NOX emission standards under Sec.  60.44b
apply at all times.
    (b) Compliance with the PM emission standards under Sec.  60.43b
shall be determined through performance testing as described in
paragraph (d) of this section, except as provided in paragraph (i) of
this section.
    (c) Compliance with the NOX emission standards under
Sec.  60.44b shall be determined through performance testing under
paragraph (e) or (f), or under paragraphs (g) and (h) of this section,
as applicable.
    (d) To determine compliance with the PM emission limits and opacity
limits under Sec.  60.43b, the owner or operator of an affected
facility shall conduct an initial performance test as required under
Sec.  60.8, and shall conduct subsequent performance tests as requested
by the Administrator, using the following procedures and reference
methods:
    (1) Method 3B of appendix A of this part is used for gas analysis
when applying Method 5 or 17 of appendix A of this part.
    (2) Method 5, 5B, or 17 of appendix A of this part shall be used to
measure the concentration of PM as follows:
    (i) Method 5 of appendix A of this part shall be used at affected
facilities without wet flue gas desulfurization (FGD) systems; and
    (ii) Method 17 of appendix A of this part may be used at facilities
with or without wet scrubber systems provided the stack gas temperature
does not exceed a temperature of 160 [deg]C (32 [deg]F). The procedures
of sections 2.1 and 2.3 of Method 5B of appendix A of this part may be
used in Method 17 of appendix A of this part only if it is used after a
wet FGD system. Do not use Method 17 of appendix A of this part after
wet FGD systems if the effluent is saturated or laden with water
droplets.
    (iii) Method 5B of appendix A of this part is to be used only after
wet FGD systems.
    (3) Method 1 of appendix A of this part is used to select the
sampling site and the number of traverse sampling points. The sampling
time for each run is at least 120 minutes and the minimum sampling
volume is 1.7 dscm (60 dscf) except that smaller sampling times or
volumes may be approved by the Administrator when necessitated by
process variables or other factors.
    (4) For Method 5 of appendix A of this part, the temperature of the
sample gas in the probe and filter holder is monitored and is
maintained at 16014 [deg]C (32025 [deg]F).
    (5) For determination of PM emissions, the oxygen (O2)
or CO2 sample is obtained simultaneously with each run of
Method 5, 5B, or 17 of appendix A of this part by traversing the duct
at the same sampling location.
    (6) For each run using Method 5, 5B, or 17 of appendix A of this
part, the emission rate expressed in ng/J heat input is determined
using:
    (i) The O2 or CO2 measurements and PM
measurements obtained under this section;
    (ii) The dry basis F factor; and
    (iii) The dry basis emission rate calculation procedure contained
in Method 19 of appendix A of this part.
    (7) Method 9 of appendix A of this part is used for determining the
opacity of stack emissions.
    (e) To determine compliance with the emission limits for
NOX required under Sec.  60.44b, the owner or operator of an
affected facility shall conduct the performance test as required under
Sec.  60.8 using the continuous system for monitoring NOX
under Sec.  60.48(b).
    (1) For the initial compliance test, NOX from the steam
generating unit are monitored for 30 successive steam generating unit
operating days and the 30-day average emission rate is used to
determine compliance with the NOX emission standards under
Sec.  60.44b. The 30-day average emission rate is calculated as the
average of all hourly emissions data recorded by the monitoring system
during the 30-day test period.
    (2) Following the date on which the initial performance test is
completed or is required to be completed under Sec.  60.8, whichever
date comes first, the owner or operator of an affected facility which
combusts coal or which combusts residual oil having a nitrogen content
greater than 0.30 weight percent shall determine compliance with the
NOX emission standards under Sec.  60.44b on a continuous
basis through the use of a 30-day rolling average emission rate. A new
30-day rolling average emission rate is calculated each steam
generating unit operating day as the average of all of the hourly
NOX emission data for the preceding 30 steam generating unit
operating days.
    (3) Following the date on which the initial performance test is
completed or is required to be completed under Sec.  60.8, whichever
date comes first, the owner or operator of an affected facility that
has a heat input capacity greater than 73 MW (250 MMBtu/hr) and that
combusts natural gas, distillate oil, or residual oil having a nitrogen
content of 0.30 weight percent or less shall determine compliance with
the NOX standards under Sec.  60.44b on a continuous basis
through the use of a 30-day rolling average emission rate. A new 30-day
rolling average emission rate is calculated each steam generating unit
operating day as the average of all of the hourly NOX
emission data for the preceding 30 steam generating unit operating
days.

    (4) Following 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 affected facility that has a
heat input capacity of 73 MW (250 MMBtu/hr) or less and that combusts
natural gas, distillate oil, or residual oil having a nitrogen content
of 0.30 weight percent or less shall upon request determine compliance
with the NOX standards under Sec.  60.44b through the use of
a 30-day performance test. During periods when performance tests are
not requested, NOX emissions data collected pursuant to
Sec.  60.48b(g)(1) or Sec.  60.48b(g)(2) are used to calculate a 30-day
rolling average emission rate on a daily basis and used to prepare
excess emission reports, but will not be used to determine compliance
with the NOX emission standards. A new 30-day rolling
average emission rate is calculated each steam generating unit
operating day as the average of all of the hourly NOX
emission data for the preceding 30 steam generating unit operating
days.
    (5) If the owner or operator of an affected facility that combusts
residual oil does not sample and analyze the residual oil for nitrogen
content, as specified in Sec.  60.49b(e), the requirements of Sec.
60.48b(g)(1) apply and the provisions of Sec.  60.48b(g)(2) are
inapplicable.
    (f) To determine compliance with the emissions limits for
NOX required by Sec.  60.44b(a)(4) or Sec.  60.44b(l) for
duct burners used in combined cycle systems, either of the procedures
described in paragraph (f)(1) or (2) of this section may be used:
    (1) The owner or operator of an affected facility shall conduct the
performance test required under Sec.  60.8 as follows:
    (i) The emissions rate (E) of NOX shall be computed
using Equation 1 in this section:
[GRAPHIC] [TIFF OMITTED] TP09FE07.035

Where:

E = Emissions rate of NOX from the duct burner, ng/J (lb/
MMBtu) heat input;
Esg = Combined effluent emissions rate, in ng/J (lb/
MMBtu) heat input using appropriate F factor as described in Method
19 of appendix A of this part;
Hg = Heat input rate to the combustion turbine, in J/hr
(MMBtu/hr);
Hb = Heat input rate to the duct burner, in J/hr (MMBtu/
hr); and
Eg = Emissions rate from the combustion turbine, in ng/J
(lb/MMBtu) heat input calculated using appropriate F factor as
described in Method 19 of appendix A of this part.

    (ii) Method 7E of appendix A of this part shall be used to
determine the NOX concentrations. Method 3A or 3B of
appendix A of this part shall be used to determine O2
concentration.
    (iii) The owner or operator shall identify and demonstrate to the
Administrator's satisfaction suitable methods to determine the average
hourly heat input rate to the combustion turbine and the average hourly
heat input rate to the affected duct burner.
    (iv) Compliance with the emissions limits under Sec.  60.44b (a)(4)
or Sec.  60.44b(l) is determined by the three-run average (nominal 1-
hour runs) for the initial and subsequent performance tests; or
    (2) The owner or operator of an affected facility may elect to
determine compliance on a 30-day rolling average basis by using the
CEMS specified under Sec.  60.48b for measuring NOX and
O2 and meet the requirements of Sec.  60.48b. The sampling
site shall be located at the outlet from the steam generating unit. The
NOX emissions rate at the outlet from the steam generating
unit shall constitute the NOX emissions rate from the duct
burner of the combined cycle system.
    (g) The owner or operator of an affected facility described in
Sec.  60.44b(j) or Sec.  60.44b(k) shall demonstrate the maximum heat
input capacity of the steam generating unit by operating the facility
at maximum capacity for 24 hours. The owner or operator of an affected
facility shall determine the maximum heat input capacity using the heat
loss method described in sections 5 and 7.3 of the ASME Power Test
Codes 4.1 (incorporated by reference, see Sec.  60.17). This
demonstration of maximum heat input capacity shall be made during the
initial performance test for affected facilities that meet the criteria
of Sec.  60.44b(j). It shall be made 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 start-up of each
facility, for affected facilities meeting the criteria of Sec.
60.44b(k). Subsequent demonstrations may be required by the
Administrator at any other time. If this demonstration indicates that
the maximum heat input capacity of the affected facility is less than
that stated by the manufacturer of the affected facility, the maximum
heat input capacity determined during this demonstration shall be used
to determine the capacity utilization rate for the affected facility.
Otherwise, the maximum heat input capacity provided by the manufacturer
is used.
    (h) The owner or operator of an affected facility described in
Sec.  60.44b(j) that has a heat input capacity greater than 73 MW (250
MMBtu/hr) shall:
    (1) Conduct an initial performance test as required under Sec.
60.8 over a minimum of 24 consecutive steam generating unit operating
hours at maximum heat input capacity to demonstrate compliance with the
NOX emission standards under Sec.  60.44b using Method 7,
7A, 7E of appendix A of this part, or other approved reference methods;
and
    (2) Conduct subsequent performance tests once per calendar year or
every 400 hours of operation (whichever comes first) to demonstrate
compliance with the NOX emission standards under Sec.
60.44b over a minimum of 3 consecutive steam generating unit operating
hours at maximum heat input capacity using Method 7, 7A, 7E of appendix
A of this part, or other approved reference methods.
    (i) The owner or operator of an affected facility seeking to
demonstrate compliance under paragraph Sec.  60.43b(h)(5) shall follow
the applicable procedures under Sec.  60.49b(r).
    (j) In place of PM testing with EPA Reference Method 5, 5B, or 17
of appendix A of this part, an owner or operator may elect to install,
calibrate, maintain, and operate a CEMS for monitoring PM emissions
discharged to the atmosphere and record the output of the system. The
owner or operator of an affected facility who elects to continuously
monitor PM emissions instead of conducting performance testing using
EPA Method 5, 5B, or 17 of appendix A of this part shall comply with
the requirements specified in paragraphs (j)(1) through (j)(13) of this
section.
    (1) Notify the Administrator one month before starting use of the
system.
    (2) Notify the Administrator one month before stopping use of the
system.
    (3) The monitor shall be installed, evaluated, and operated in
accordance with Sec.  60.13 of subpart A of this part.
    (4) The initial performance evaluation shall be completed no later
than 180 days after the date of initial startup of the affected
facility, as specified under Sec.  60.8 of subpart A of this part or
within 180 days of notification to the Administrator of use of the CEMS
if the owner or operator was previously determining compliance by
Method 5, 5B, or 17 of appendix A of this part performance tests,
whichever is later.
    (5) The owner or operator of an affected facility shall conduct an
initial performance test for PM emissions as required under Sec.  60.8
of subpart A of this part. Compliance with the PM emission limit shall
be determined by

using the CEMS specified in paragraph (j) of this section to measure PM
and calculating a 24-hour block arithmetic average emission
concentration using EPA Reference Method 19 of appendix A of this part,
section 4.1.
    (6) Compliance with the PM emission limit shall be determined based
on the 24-hour daily (block) average of the hourly arithmetic average
emission concentrations using CEMS outlet data.
    (7) At a minimum, valid CEMS hourly averages shall be obtained as
specified in paragraphs (j)(7)(i) of this section for 75 percent of the
total operating hours per 30-day rolling average.
    (i) At least two data points per hour shall be used to calculate
each 1-hour arithmetic average.
    (8) The 1-hour arithmetic averages required under paragraph (j)(7)
of this section shall be expressed in ng/J or lb/MMBtu heat input and
shall be used to calculate the boiler operating day daily arithmetic
average emission concentrations. The 1-hour arithmetic averages shall
be calculated using the data points required under Sec.  60.13(e)(2) of
subpart A of this part.
    (9) All valid CEMS data shall be used in calculating average
emission concentrations even if the minimum CEMS data requirements of
paragraph (j)(7) of this section are not met.
    (10) The CEMS shall be operated according to Performance
Specification 11 in appendix B of this part.
    (11) During the correlation testing runs of the CEMS required by
Performance Specification 11 in appendix B of this part, PM and
O2 (or CO2) data shall be collected concurrently
(or within a 30-to 60-minute period) by both the continuous emission
monitors and the test methods specified in paragraph (j)(7)(i) of this
section.
    (i) For PM, EPA Reference Method 5, 5B, or 17 of appendix A of this
part shall be used.
    (ii) For O2 (or CO2), EPA reference Method 3,
3A, or 3B of appendix A of this part, as applicable shall be used.
    (12) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 2 in appendix F
of this part. Relative Response Audits must be performed annually and
Response Correlation Audits must be performed every 3 years.
    (13) 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, valid emissions data for a
minimum of 75 percent of total operating hours per 30-day rolling
average.

Sec.  60.47b  Emission monitoring for sulfur dioxide.

    (a) Except as provided in paragraphs (b) and (g) of this section,
the owner or operator of an affected facility subject to the
SO2 standards under Sec.  60.42b shall install, calibrate,
maintain, and operate CEMS for measuring SO2 concentrations
and either O2 or CO2 concentrations and shall
record the output of the systems. For units complying with the percent
reduction standard, the SO2 and either O2 or
CO2 concentrations shall both be monitored at the inlet and
outlet of the SO2 control device.
    (b) As an alternative to operating CEMS as required under paragraph
(a) of this section, an owner or operator may elect to determine the
average SO2 emissions and percent reduction by:
    (1) Collecting coal or oil samples in an as-fired condition at the
inlet to the steam generating unit and analyzing them for sulfur and
heat content according to Method 19 of appendix A of this part. Method
19 of appendix A of this part provides procedures for converting these
measurements into the format to be used in calculating the average
SO2 input rate, or
    (2) Measuring SO2 according to Method 6B of appendix A
of this part at the inlet or outlet to the SO2 control
system. An initial stratification test is required to verify the
adequacy of the Method 6B of appendix A of this part sampling location.
The stratification test shall consist of three paired runs of a
suitable SO2 and CO2 measurement train operated
at the candidate location and a second similar train operated according
to the procedures in section 3.2 and the applicable procedures in
section 7 of Performance Specification 2. Method 6B of appendix A of
this part, Method 6A of appendix A of this part, or a combination of
Methods 6 and 3 or 3B of appendix A of this part or Methods 6C and 3A
of appendix A of this part are suitable measurement techniques. If
Method 6B of appendix A of this part is used for the second train,
sampling time and timer operation may be adjusted for the
stratification test as long as an adequate sample volume is collected;
however, both sampling trains are to be operated similarly. For the
location to be adequate for Method 6B of appendix A of this part 24-
hour tests, the mean of the absolute difference between the three
paired runs must be less than 10 percent.
    (3) A daily SO2 emission rate, ED, shall be determined
using the procedure described in Method 6A of appendix A of this part,
section 7.6.2 (Equation 6A-8) and stated in ng/J (lb/MMBtu) heat input.
    (4) The mean 30-day emission rate is calculated using the daily
measured values in ng/J (lb/MMBtu) for 30 successive steam generating
unit operating days using equation 19-20 of Method 19 of appendix A of
this part.
    (c) The owner or operator of an affected facility shall obtain
emission data for at least 75 percent of the operating hours in at
least 22 out of 30 successive boiler operating days. If this minimum
data requirement is not met with a single monitoring system, the owner
or operator of the affected facility shall supplement the emission data
with data collected with other monitoring systems as approved by the
Administrator or the reference methods and procedures as described in
paragraph (b) of this section.
    (d) The 1-hour average SO2 emission rates measured by
the CEMS required by paragraph (a) of this section and required under
Sec.  60.13(h) is expressed in ng/J or lb/MMBtu heat input and is used
to calculate the average emission rates under Sec.  60.42(b). Each 1-
hour average SO2 emission rate must be based on 30 or more
minutes of steam generating unit operation. The hourly averages shall
be calculated according to Sec.  60.13(h)(2). Hourly SO2
emission rates are not calculated if the affected facility is operated
less than 30 minutes in a given clock hour and are not counted toward
determination of a steam generating unit operating day.
    (e) The procedures under Sec.  60.13 shall be followed for
installation, evaluation, and operation of the CEMS.
    (1) All CEMS shall be operated in accordance with the applicable
procedures under Performance Specifications 1, 2, and 3 of appendix B
of this part.
    (2) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with Procedure 1 of appendix F
of this part.
    (3) For affected facilities combusting coal or oil, alone or in
combination with other fuels, the span value of the SO2 CEMS
at the inlet to the SO2 control device is 125 percent of the
maximum estimated hourly potential SO2 emissions of the fuel
combusted, and the span value of the CEMS at the outlet to the
SO2 control device is 50 percent of the maximum estimated
hourly potential SO2 emissions of the fuel combusted.
    (f) The owner or operator of an affected facility that combusts
very low sulfur oil or is demonstrating compliance under Sec.
60.45b(k) is not

subject to the emission monitoring requirements under paragraph (a) of
this section if the owner or operator maintains fuel records as
described in Sec.  60.49b(r).

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
CEMS for measuring the opacity of emissions discharged to the
atmosphere and record the output of the system.
    (b) Except as provided under paragraphs (g), (h), and (i) of this
section, the owner or operator of an affected facility subject to a
NOX standard under Sec.  60.44b shall comply with either
paragraphs (b)(1) or (b)(2) of this section.
    (1) Install, calibrate, maintain, and operate a CEMS, and record
the output of the system, for measuring NOX emissions
discharged to the atmosphere; or
    (2) If the owner or operator has installed a NOX
emission rate CEMS to meet the requirements of part 75 of this chapter
and is continuing to meet the ongoing requirements of part 75 of this
chapter, that CEMS may be used to meet the requirements of this
section, except that the owner or operator shall also meet the
requirements of Sec.  60.49b. Data reported to meet the requirements of
Sec.  60.49b shall not include data substituted using the missing data
procedures in subpart D of part 75 of this chapter, nor shall the data
have been bias adjusted according to the procedures of part 75 of this
chapter.
    (c) The CEMS required under paragraph (b) of this section shall be
operated and data recorded during all periods of operation of the
affected facility except for CEMS breakdowns and repairs. Data is
recorded during calibration checks, and zero and span adjustments.
    (d) The 1-hour average NOX emission rates measured by
the continuous NOX monitor required by paragraph (b) of this
section and required under Sec.  60.13(h) shall be expressed in ng/J or
lb/MMBtu heat input and shall be used to calculate the average emission
rates under Sec.  60.44b. The 1-hour averages shall be calculated using
the data points required under Sec.  60.13(h)(2).
    (e) The procedures under Sec.  60.13 shall be followed for
installation, evaluation, and operation of the continuous monitoring
systems.
    (1) For affected facilities combusting coal, wood or municipal-type
solid waste, the span value for a continuous monitoring system for
measuring opacity shall be between 60 and 80 percent.
    (2) For affected facilities combusting coal, oil, or natural gas,
the span value for NOX is determined as follows:

------------------------------------------------------------------------
                 Fuel                      Span values for NOX  (ppm)
------------------------------------------------------------------------
Natural gas..........................  500
Oil..................................  500
Coal.................................  1,000
Mixtures.............................  500(x + y) + 1,000z
------------------------------------------------------------------------

Where:

x = Fraction of total heat input derived from natural gas;
y = Fraction of total heat input derived from oil; and
z = Fraction of total heat input derived from coal.

    (3) All span values computed under paragraph (e)(2) of this section
for combusting mixtures of regulated fuels are rounded to the nearest
500 ppm.
    (f) When NOX emission data are not obtained because of
CEMS breakdowns, repairs, calibration checks and zero and span
adjustments, emission data will be obtained by using standby monitoring
systems, Method 7 of appendix A of this part, Method 7A of appendix A
of this part, or other approved reference methods to provide emission
data for a minimum of 75 percent of the operating hours in each steam
generating unit operating day, in at least 22 out of 30 successive
steam generating unit operating days.
    (g) The owner or operator of an affected facility that has a heat
input capacity of 73 MW (250 MMBtu/hr) or less, and that has an annual
capacity factor for residual oil having a nitrogen content of 0.30
weight percent or less, natural gas, distillate oil, or any mixture of
these fuels, greater than 10 percent (0.10) shall:
    (1) Comply with the provisions of paragraphs (b), (c), (d), (e)(2),
(e)(3), and (f) of this section; or
    (2) Monitor steam generating unit operating conditions and predict
NOX emission rates as specified in a plan submitted pursuant
to Sec.  60.49b(c).
    (h) The owner or operator of a duct burner, as described in Sec.
60.41b, that is subject to the NOX standards of Sec.
60.44b(a)(4) or Sec.  60.44b(l) is not required to install or operate a
continuous emissions monitoring system to measure NOX
emissions.
    (i) The owner or operator of an affected facility described in
Sec.  60.44b(j) or Sec.  60.44b(k) is not required to install or
operate a CEMS for measuring NOX emissions.
    (j) Units are not required to operate COMS for measuring opacity
if:
    (1) The affected facility uses a PM CEMS to monitor PM emissions;
or
    (2) The affected facility burns only liquid (excluding residual
oil) or gaseous fuels 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 SO2 or PM emissions. The owner or
operator must maintain fuel records of the sulfur content of the fuels
burned, as described under Sec.  60.49b(r); or
    (3) The affected facility burns coke oven gas alone or in
combination with fuels meeting the criteria in paragraph (j)(2) of this
section and does not use a post combustion technology to reduce
SO2 or PM emissions.
    (k) Owners or operators complying with the PM emission limit by
using a PM CEMS monitor instead of monitoring opacity must calibrate,
maintain, and operate a CEMS, and record the output of the system, for
PM emissions discharged to the atmosphere as specified in Sec.
60.46b(j). The CEMS specified in paragraph Sec.  60.46b(j) shall be
operated and data recorded during all periods of operation of the
affected facility except for CEMS breakdowns and repairs. Data is
recorded during calibration checks, and zero and span adjustments.

Sec.  60.49b  Reporting and recordkeeping requirements.

    (a) The owner or operator of each affected facility shall submit
notification of the date of initial startup, as provided by Sec.  60.7.
This notification shall include:
    (1) The design heat input capacity of the affected facility and
identification of the fuels to be combusted in the affected facility;
    (2) If applicable, a copy of any federally enforceable requirement
that limits the annual capacity factor for any fuel or mixture of fuels
under Sec. Sec.  60.42b(d)(1), 60.43b(a)(2), (a)(3)(iii), (c)(2)(ii),
(d)(2)(iii), 60.44b(c), (d), (e), (i), (j), (k), 60.45b(d), (g),
60.46b(h), or 60.48b(i);
    (3) The annual capacity factor at which the owner or operator
anticipates operating the facility based on all fuels fired and based
on each individual fuel fired; and
    (4) Notification that an emerging technology will be used for
controlling emissions of SO2. The Administrator will examine
the description of the emerging technology and will determine whether
the technology qualifies as an emerging technology. In making this
determination, the Administrator may require the owner or operator of
the

affected facility to submit additional information concerning the
control device. The affected facility is subject to the provisions of
Sec.  60.42b(a) unless and until this determination is made by the
Administrator.
    (b) The owner or operator of each affected facility subject to the
SO2, PM, and/or NOX emission limits under
Sec. Sec.  60.42b, 60.43b, and 60.44b shall submit to the Administrator
the performance test data from the initial performance test and the
performance evaluation of the CEMS using the applicable performance
specifications in appendix B of this part. The owner or operator of
each affected facility described in Sec.  60.44b(j) or Sec.  60.44b(k)
shall submit to the Administrator the maximum heat input capacity data
from the demonstration of the maximum heat input capacity of the
affected facility.
    (c) The owner or operator of each affected facility subject to the
NOX standard of Sec.  60.44b who seeks to demonstrate
compliance with those standards through the monitoring of steam
generating unit operating conditions under the provisions of Sec.
60.48b(g)(2) shall submit to the Administrator for approval a plan that
identifies the operating conditions to be monitored under Sec.
60.48b(g)(2) and the records to be maintained under Sec.  60.49b(j).
This plan shall be submitted to the Administrator for approval within
360 days of the initial startup of the affected facility. If the plan
is approved, the owner or operator shall maintain records of predicted
nitrogen oxide emission rates and the monitored operating conditions,
including steam generating unit load, identified in the plan. The plan
shall:
    (1) Identify the specific operating conditions to be monitored and
the relationship between these operating conditions and NOX
emission rates (i.e., ng/J or lbs/MMBtu heat input). Steam generating
unit operating conditions include, but are not limited to, the degree
of staged combustion (i.e., the ratio of primary air to secondary and/
or tertiary air) and the level of excess air (i.e., flue gas
O2 level);
    (2) Include the data and information that the owner or operator
used to identify the relationship between NOX emission rates
and these operating conditions; and
    (3) Identify how these operating conditions, including steam
generating unit load, will be monitored under Sec.  60.48b(g) on an
hourly basis by the owner or operator during the period of operation of
the affected facility; the quality assurance procedures or practices
that will be employed to ensure that the data generated by monitoring
these operating conditions will be representative and accurate; and the
type and format of the records of these operating conditions, including
steam generating unit load, that will be maintained by the owner or
operator under Sec.  60.49b(j).
    (d) The owner or operator of an affected facility shall record and
maintain records of the amounts of each fuel combusted during each day
and calculate the annual capacity factor individually for coal,
distillate oil, residual oil, natural gas, wood, and municipal-type
solid waste for the reporting period. The annual capacity factor is
determined on a 12-month rolling average basis with a new annual
capacity factor calculated at the end of each calendar month.
    (e) For an affected facility that combusts residual oil and meets
the criteria under Sec. Sec.  60.46b(e)(4), 60.44b (j), or (k), the
owner or operator shall maintain records of the nitrogen content of the
residual oil combusted in the affected facility and calculate the
average fuel nitrogen content for the reporting period. The nitrogen
content shall be determined using ASTM Method D4629 (incorporated by
reference, see Sec.  60.17), or fuel suppliers. If residual oil blends
are being combusted, fuel nitrogen specifications may be prorated based
on the ratio of residual oils of different nitrogen content in the fuel
blend.
    (f) For facilities subject to the opacity standard under Sec.
60.43b, the owner or operator shall maintain records of opacity.
    (g) Except as provided under paragraph (p) of this section, the
owner or operator of an affected facility subject to the NOX
standards under Sec.  60.44b shall maintain records of the following
information for each steam generating unit operating day:
    (1) Calendar date;
    (2) The average hourly NOX emission rates (expressed as
NO2) (ng/J or lb/MMBtu heat input) measured or predicted;
    (3) The 30-day average NOX emission rates (ng/J or lb/
MMBtu heat input) calculated at the end of each steam generating unit
operating day from the measured or predicted hourly nitrogen oxide
emission rates for the preceding 30 steam generating unit operating
days;
    (4) Identification of the steam generating unit operating days when
the calculated 30-day average NOX emission rates are in
excess of the NOX emissions standards under Sec.  60.44b,
with the reasons for such excess emissions as well as a description of
corrective actions taken;
    (5) Identification of the steam generating unit operating days for
which pollutant data have not been obtained, including reasons for not
obtaining sufficient data and a description of corrective actions
taken;
    (6) Identification of the times when emission data have been
excluded from the calculation of average emission rates and the reasons
for excluding data;
    (7) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
    (8) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
    (9) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or
3; and
    (10) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under appendix F, Procedure 1 of this part.
    (h) The owner or operator of any affected facility in any category
listed in paragraphs (h) (1) or (2) of this section is required to
submit excess emission reports for any excess emissions that occurred
during the reporting period.
    (1) Any affected facility subject to the opacity standards under
Sec.  60.43b(e) or to the operating parameter monitoring requirements
under Sec.  60.13(i)(1).
    (2) Any affected facility that is subject to the NOX
standard of Sec.  60.44b, and that:
    (i) Combusts natural gas, distillate oil, or residual oil with a
nitrogen content of 0.3 weight percent or less; or
    (ii) Has a heat input capacity of 73 MW (250 MMBtu/hr) or less and
is required to monitor NOX emissions on a continuous basis
under Sec.  60.48b(g)(1) or steam generating unit operating conditions
under Sec.  60.48b(g)(2).
    (3) For the purpose of Sec.  60.43b, excess emissions are defined
as all 6-minute periods during which the average opacity exceeds the
opacity standards under Sec.  60.43b(f).
    (4) For purposes of Sec.  60.48b(g)(1), excess emissions are
defined as any calculated 30-day rolling average NOX
emission rate, as determined under Sec.  60.46b(e), that exceeds the
applicable emission limits in Sec.  60.44b.
    (i) The owner or operator of any affected facility subject to the
continuous monitoring requirements for NOX under Sec.
60.48(b) shall submit reports containing the information recorded under
paragraph (g) of this section.
    (j) The owner or operator of any affected facility subject to the
SO2 standards under Sec.  60.42b shall submit reports.

    (k) For each affected facility subject to the compliance and
performance testing requirements of Sec.  60.45b and the reporting
requirement in paragraph (j) of this section, the following information
shall be reported to the Administrator:
    (1) Calendar dates covered in the reporting period;
    (2) Each 30-day average SO2 emission rate (ng/J or 1b/
MMBtu heat input) measured during the reporting period, ending with the
last 30-day period; reasons for noncompliance with the emission
standards; and a description of corrective actions taken;
    (3) Each 30-day average percent reduction in SO2
emissions calculated during the reporting period, ending with the last
30-day period; reasons for noncompliance with the emission standards;
and a description of corrective actions taken;
    (4) Identification of the steam generating unit operating days that
coal or oil was combusted and for which SO2 or diluent
(O2 or CO2) data have not been obtained by an
approved method for at least 75 percent of the operating hours in the
steam generating unit operating day; justification for not obtaining
sufficient data; and description of corrective action taken;
    (5) Identification of the times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and description of corrective action taken if data
have been excluded for periods other than those during which coal or
oil were not combusted in the steam generating unit;
    (6) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
    (7) Identification of times when hourly averages have been obtained
based on manual sampling methods;
    (8) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
    (9) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or
3;
    (10) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under appendix F, Procedure 1 of this part; and
    (11) The annual capacity factor of each fired as provided under
paragraph (d) of this section.
    (l) For each affected facility subject to the compliance and
performance testing requirements of Sec.  60.45b(d) and the reporting
requirements of paragraph (j) of this section, the following
information shall be reported to the Administrator:
    (1) Calendar dates when the facility was in operation during the
reporting period;
    (2) The 24-hour average SO2 emission rate measured for
each steam generating unit operating day during the reporting period
that coal or oil was combusted, ending in the last 24-hour period in
the quarter; reasons for noncompliance with the emission standards; and
a description of corrective actions taken;
    (3) Identification of the steam generating unit operating days that
coal or oil was combusted for which SO2 or diluent
(O2 or CO2) data have not been obtained by an
approved method for at least 75 percent of the operating hours;
justification for not obtaining sufficient data; and description of
corrective action taken;
    (4) Identification of the times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and description of corrective action taken if data
have been excluded for periods other than those during which coal or
oil were not combusted in the steam generating unit;
    (5) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
    (6) Identification of times when hourly averages have been obtained
based on manual sampling methods;
    (7) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
    (8) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or
3; and
    (9) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under appendix F, Procedure 1 of this part.
    (m) For each affected facility subject to the SO2
standards under Sec.  60.42(b) for which the minimum amount of data
required under Sec.  60.47b(f) were not obtained during the reporting
period, the following information is reported to the Administrator in
addition to that required under paragraph (k) of this section:
    (1) The number of hourly averages available for outlet emission
rates and inlet emission rates;
    (2) The standard deviation of hourly averages for outlet emission
rates and inlet emission rates, as determined in Method 19 of appendix
A of this part, section 7;
    (3) The lower confidence limit for the mean outlet emission rate
and the upper confidence limit for the mean inlet emission rate, as
calculated in Method 19 of appendix A of this part, section 7; and
    (4) The ratio of the lower confidence limit for the mean outlet
emission rate and the allowable emission rate, as determined in Method
19 of appendix A of this part, section 7.
    (n) If a percent removal efficiency by fuel pretreatment (i.e.,
%Rf) is used to determine the overall percent reduction
(i.e., %Ro) under Sec.  60.45b, the owner or operator of the
affected facility shall submit a signed statement with the report.
    (1) Indicating what removal efficiency by fuel pretreatment (i.e.,
%Rf) was credited during the reporting period;
    (2) Listing the quantity, heat content, and date each pre-treated
fuel shipment was received during the reporting period, the name and
location of the fuel pretreatment facility; and the total quantity and
total heat content of all fuels received at the affected facility
during the reporting period;
    (3) Documenting the transport of the fuel from the fuel
pretreatment facility to the steam generating unit; and
    (4) Including a signed statement from the owner or operator of the
fuel pretreatment facility certifying that the percent removal
efficiency achieved by fuel pretreatment was determined in accordance
with the provisions of Method 19 of appendix A of this part and listing
the heat content and sulfur content of each fuel before and after fuel
pretreatment.
    (o) All records required under this section shall be maintained by
the owner or operator of the affected facility for a period of 2 years
following the date of such record.
    (p) The owner or operator of an affected facility described in
Sec.  60.44b(j) or (k) shall maintain records of the following
information for each steam generating unit operating day:
    (1) Calendar date;
    (2) The number of hours of operation; and
    (3) A record of the hourly steam load.
    (q) The owner or operator of an affected facility described in
Sec.  60.44b(j) or Sec.  60.44b(k) shall submit to the Administrator a
report containing:
    (1) The annual capacity factor over the previous 12 months;
    (2) The average fuel nitrogen content during the reporting period,
if residual oil was fired; and
    (3) If the affected facility meets the criteria described in Sec.
60.44b(j), the results of any NOX emission tests required
during the reporting period, the hours of operation during the
reporting period, and the hours of operation since the last
NOX emission test.

    (r) The owner or operator of an affected facility who elects to use
the fuel based compliance alternatives in Sec.  60.42b or Sec.  60.43b
shall either:
    (1) The owner or operator of an affected facility who elects to
demonstrate that the affected facility combusts only very low sulfur
oil under Sec.  60.42b(j)(2) or Sec.  60.42b(k)(2) shall obtain and
maintain at the affected facility fuel receipts from the fuel supplier
that certify that the oil meets the definition of distillate oil 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 and/or pipeline quality
natural gas was combusted in the affected facility during the reporting
period; or
    (2) The owner or operator of an affected facility who elects to
demonstrate compliance based on fuel analysis in Sec.  60.42b or Sec.
60.43b shall develop and submit a site-specific fuel analysis plan to
the Administrator for review and approval no later than 60 days before
the date you intend to demonstrate compliance. Each fuel analysis plan
shall include a minimum initial requirement of weekly testing and each
analysis report shall contain, at a minimum, the following information:
    (i) The potential sulfur emissions rate of the representative fuel
mixture in ng/J heat input;
    (ii) The method used to determine the potential sulfur emissions
rate of each constituent of the mixture. For distillate oil and natural
gas a fuel receipt or tariff sheet is acceptable;
    (iii) The ratio of different fuels in the mixture; and
    (iv) The owner or operator can petition the Administrator to
approve monthly or quarterly sampling in place of weekly sampling.
    (s) Facility specific NOX standard for Cytec Industries
Fortier Plant's C.AOG incinerator located in Westwego, Louisiana:
    (1) Definitions.
    Oxidation zone is defined as the portion of the C.AOG incinerator
that extends from the inlet of the oxidizing zone combustion air to the
outlet gas stack.
    Reducing zone is defined as the portion of the C.AOG incinerator
that extends from the burner section to the inlet of the oxidizing zone
combustion air.
    Total inlet air is defined as the total amount of air introduced
into the C.AOG incinerator for combustion of natural gas and chemical
by-product waste and is equal to the sum of the air flow into the
reducing zone and the air flow into the oxidation zone.
    (2) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
    (ii) When natural gas and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 289 ng/J
(0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet air
provided for combustion shall be provided to the reducing zone of the
C.AOG incinerator.
    (3) Emission monitoring. (i) The percent of total inlet air
provided to the reducing zone shall be determined at least every 15
minutes by measuring the air flow of all the air entering the reducing
zone and the air flow of all the air entering the oxidation zone, and
compliance with the percentage of total inlet air that is provided to
the reducing zone shall be determined on a 3-hour average basis.
    (ii) The NOX emission limit shall be determined by the
compliance and performance test methods and procedures for
NOX in Sec.  60.46b(i).
    (iii) The monitoring of the NOX emission limit shall be
performed in accordance with Sec.  60.48b.
    (4) Reporting and recordkeeping requirements. (i) The owner or
operator of the C.AOG incinerator shall submit a report on any
excursions from the limits required by paragraph (a)(2) of this section
to the Administrator with the quarterly report required by paragraph
(i) of this section.
    (ii) The owner or operator of the C.AOG incinerator shall keep
records of the monitoring required by paragraph (a)(3) of this section
for a period of 2 years following the date of such record.
    (iii) The owner of operator of the C.AOG incinerator shall perform
all the applicable reporting and recordkeeping requirements of this
section.
    (t) Facility-specific NOX standard for Rohm and Haas
Kentucky Incorporated's Boiler No. 100 located in Louisville, Kentucky:
    (1) Definitions.
    Air ratio control damper is defined as the part of the low
NOX burner that is adjusted to control the split of total
combustion air delivered to the reducing and oxidation portions of the
combustion flame.
    Flue gas recirculation line is defined as the part of Boiler No.
100 that recirculates a portion of the boiler flue gas back into the
combustion air.
    (2) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
    (ii) When fossil fuel and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 473 ng/J
(1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at
a minimum of 5 inches (12.7 centimeters) out of the boiler, and the
flue gas recirculation line shall be operated at a minimum of 10
percent open as indicated by its valve opening position indicator.
    (3) Emission monitoring for nitrogen oxides. (i) The air ratio
control damper tee handle setting and the flue gas recirculation line
valve opening position indicator setting shall be recorded during each
8-hour operating shift.
    (ii) The NOX emission limit shall be determined by the
compliance and performance test methods and procedures for
NOX in Sec.  60.46b.
    (iii) The monitoring of the NOX emission limit shall be
performed in accordance with Sec.  60.48b.
    (4) Reporting and recordkeeping requirements. (i) The owner or
operator of Boiler No. 100 shall submit a report on any excursions from
the limits required by paragraph (b)(2) of this section to the
Administrator with the quarterly report required by Sec.  60.49b(i).
    (ii) The owner or operator of Boiler No. 100 shall keep records of
the monitoring required by paragraph (b)(3) of this section for a
period of 2 years following the date of such record.
    (iii) The owner of operator of Boiler No. 100 shall perform all the
applicable reporting and recordkeeping requirements of Sec.  60.49b.
    (u) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant
in Elkton, Virginia. (1) This paragraph (u) applies only to the
pharmaceutical manufacturing facility, commonly referred to as the
Stonewall Plant, located at Route 340 South, in Elkton, Virginia
(``site'') and only to the natural gas-fired boilers installed as part
of the powerhouse conversion required pursuant to 40 CFR 52.2454(g).
The requirements of this paragraph shall apply, and the requirements of
Sec. Sec.  60.40b through 60.49b(t) shall not apply, to the natural
gas-fired boilers installed pursuant to 40 CFR 52.2454(g).
    (i) The site shall equip the natural gas-fired boilers with low
NOX technology.
    (ii) The site shall install, calibrate, maintain, and operate a
continuous monitoring and recording system for measuring NOX
emissions discharged to the atmosphere and opacity using a continuous
emissions monitoring system or a predictive emissions monitoring
system.

    (iii) Within 180 days of the completion of the powerhouse
conversion, as required by 40 CFR 52.2454, the site shall perform a
performance test to quantify criteria pollutant emissions.
    (2) [Reserved]
    (v) 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 (h), (i), (j), (k) or (l) 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. Before submitting reports in the electronic format,
the owner or operator shall coordinate with the permitting authority to
obtain their agreement to submit reports in this alternative format.
    (w) The reporting period for the reports required under this
subpart is each 6 month period. All reports shall be submitted to the
Administrator and shall be postmarked by the 30th day following the end
of the reporting period.
    (x) Facility-specific NOX standard for Weyerhaeuser
Company's No. 2 Power Boiler located in New Bern, North Carolina:
    (1) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
    (ii) When fossil fuel and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 215 ng/J
(0.5 lb/MMBtu).
    (2) Emission monitoring for nitrogen oxides. (i) The NOX
emissions shall be determined by the compliance and performance test
methods and procedures for NOX in Sec.  60.46b.
    (ii) The monitoring of the NOX emissions shall be
performed in accordance with Sec.  60.48b.
    (3) Reporting and recordkeeping requirements. (i) The owner or
operator of the No. 2 Power Boiler shall submit a report on any
excursions from the limits required by paragraph (x)(2) of this section
to the Administrator with the quarterly report required by Sec.
60.49b(i).
    (ii) The owner or operator of the No. 2 Power Boiler shall keep
records of the monitoring required by paragraph (x)(3) of this section
for a period of 2 years following the date of such record.
    (iii) The owner or operator of the No. 2 Power Boiler shall perform
all the applicable reporting and recordkeeping requirements of Sec.
60.49b.
    (y) Facility-specific NOX standard for INEOS USA's AOGI
located in Lima, Ohio:
    (1) Standard for NOX. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
    (ii) When fossil fuel and chemical byproduct/waste are
simultaneously combusted, the NOX emission limit is 645 ng/J
(1.5 lb/MMBtu).
    (2) Emission monitoring for NOX. (i) The NOX
emissions shall be determined by the compliance and performance test
methods and procedures for NOX in Sec.  60.46b.
    (ii) The monitoring of the NOX emissions shall be
performed in accordance with Sec.  60.48b.
    (3) Reporting and recordkeeping requirements. (i) The owner or
operator of the AOGI shall submit a report on any excursions from the
limits required by paragraph (y)(2) of this section to the
Administrator with the quarterly report required by paragraph (i) of
this section.
    (ii) The owner or operator of the AOGI shall keep records of the
monitoring required by paragraph (y)(3) of this section for a period of
2 years following the date of such record.
    (iii) The owner or operator of the AOGI shall perform all the
applicable reporting and recordkeeping requirements of this section.

Subpart Dc--[Amended]

    6. Subpart Dc is revised to read as follows:
Subpart Dc--Standards of Performance for Small Industrial--Commercial--
Institutional Steam Generating Units
Sec.
60.40c Applicability and delegation of authority.
60.41c Definitions.
60.42c Standard for sulfur dioxide (SO2).
60.43c Standard for particulate matter (PM).
60.44c Compliance and performance test methods and procedures for
sulfur dioxide.
60.45c Compliance and performance test methods and procedures for
particulate matter.
60.46c Emission monitoring for sulfur dioxide.
60.47c Emission monitoring for particulate matter.
60.48c Reporting and recordkeeping requirements.

Subpart Dc--Standards of Performance for Small Industrial--
Commercial--Institutional Steam Generating Units

Sec.  60.40c  Applicability and delegation of authority.

    (a) Except as provided in paragraph (d) 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/hr)) or less, but greater than or equal to 2.9 MW (10
MMBtu/hr).
    (b) In delegating implementation and enforcement authority to a
State under section 111(c) of the Clean Air Act, Sec.  60.48c(a)(4)
shall be retained by the Administrator and not transferred to a State.
    (c) Steam generating units that meet the applicability requirements
in paragraph (a) of this section are not subject to the sulfur dioxide
(SO2) or particulate matter (PM) emission limits,
performance testing requirements, or monitoring requirements under this
subpart (Sec. Sec.  60.42c, 60.43c, 60.44c, 60.45c, 60.46c, or 60.47c)
during periods of combustion research, as defined in Sec.  60.41c.
    (d) Any temporary change to an existing steam generating unit for
the purpose of conducting combustion research is not considered a
modification under Sec.  60.14.
    (e) Heat recovery steam generators that are associated with
combined cycle gas turbines and meet the applicability requirements of
subpart GG or KKKK of this part are not subject to this subpart. This
subpart will continue to apply to all other heat recovery steam
generators that are capable of combusting more than or equal to 2.9 MW
(10 MMBtu/hr) heat input of fossil fuel but less than or equal to 29 MW
(100 MMBtu/hr) heat input of fossil fuel. If the heat recovery steam
generator is subject to this subpart, only emissions resulting from
combustion of fuels in the steam generating unit are subject to this
subpart. (The gas turbine emissions are subject to subpart GG or KKKK,
as applicable, of this part).
    (f) Any facility covered by subpart AAAA of this part is not
covered by this subpart.
    (g) Any facility covered by an EPA approved State or Federal
section 111(d)/129 plan implementing subpart BBBB of this part is not
covered by this subpart.

Sec.  60.41c  Definitions.

    As used in this subpart, all terms not defined herein shall have
the meaning given them in the Clean Air Act and in subpart A of this
part.
    Annual capacity factor means the ratio between the actual heat
input to a steam generating unit from an individual fuel or combination
of fuels during a period of 12 consecutive calendar months and the
potential heat input to the steam generating unit from all fuels had
the steam generating unit been operated for 8,760 hours during that 12-
month period at the maximum design heat input capacity. In the case of
steam generating units that are rented or leased, the actual heat input
shall be determined based on the combined heat input from all
operations of the affected facility during a period of 12 consecutive
calendar months.
    Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec.  60.17),
coal refuse, and petroleum coke. Coal-derived synthetic fuels derived
from coal for the purposes of creating useful heat, including but not
limited to solvent refined coal, gasified coal, coal-oil mixtures, and
coal-water mixtures, are also included in this definition for the
purposes of this subpart.
    Coal refuse means any by-product of coal mining or coal cleaning
operations with an ash content greater than 50 percent (by weight) and
a heating value less than 13,900 kilojoules per kilogram (kJ/kg) (6,000
Btu per pound (Btu/lb) on a dry basis.
    Cogeneration steam generating unit means a steam generating unit
that simultaneously produces both electrical (or mechanical) and
thermal energy from the same primary energy source.
    Combined cycle system means a system in which a separate source
(such as a stationary gas turbine, internal combustion engine, or kiln)
provides exhaust gas to a steam generating unit.
    Combustion research means the experimental firing of any fuel or
combination of fuels in a steam generating unit for the purpose of
conducting research and development of more efficient combustion or
more effective prevention or control of air pollutant emissions from
combustion, provided that, during these periods of research and
development, the heat generated is not used for any purpose other than
preheating combustion air for use by that steam generating unit (i.e.,
the heat generated is released to the atmosphere without being used for
space heating, process heating, driving pumps, preheating combustion
air for other units, generating electricity, or any other purpose).
    Conventional technology means wet flue gas desulfurization
technology, dry flue gas desulfurization technology, atmospheric
fluidized bed combustion technology, and oil hydrodesulfurization
technology.
    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).
    Dry flue gas desulfurization technology means a SO2
control system that is located between the steam generating unit and
the exhaust vent or stack, and that removes sulfur oxides from the
combustion gases of the steam generating unit by contacting the
combustion gases with an alkaline slurry or solution and forming a dry
powder material. This definition includes devices where the dry powder
material is subsequently converted to another form. Alkaline reagents
used in dry flue gas desulfurization systems include, but are not
limited to, lime and sodium compounds.
    Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source (such as a stationary gas turbine,
internal combustion engine, kiln, etc.) to allow the firing of
additional fuel to heat the exhaust gases before the exhaust gases
enter a steam generating unit.
    Emerging technology means any SO2 control system that is
not defined as a conventional technology under this section, and for
which the owner or operator of the affected facility has received
approval from the Administrator to operate as an emerging technology
under Sec.  60.48c(a)(4).
    Federally enforceable means all limitations and conditions that are
enforceable by the Administrator, including the requirements of 40 CFR
parts 60 and 61, requirements within any applicable State
implementation plan, and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 51.24.
    Fluidized bed combustion technology means a device wherein fuel is
distributed onto a bed (or series of beds) of limestone aggregate (or
other sorbent materials) for combustion; and these materials are forced
upward in the device by the flow of combustion air and the gaseous
products of combustion. Fluidized bed combustion technology includes,
but is not limited to, bubbling bed units and circulating bed units.
    Fuel pretreatment means a process that removes a portion of the
sulfur in a fuel before combustion of the fuel in a steam generating
unit.
    Heat input means heat derived from combustion of fuel in a steam
generating unit 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 kilns).
    Heat transfer medium means any material that is used to transfer
heat from one point to another point.
    Maximum design heat input capacity means the ability of a steam
generating unit to combust a stated maximum amount of fuel (or
combination of fuels) on a steady state basis as determined by the
physical design and characteristics of the steam generating unit.
    Natural gas means: (1) A naturally occurring mixture of hydrocarbon
and nonhydrocarbon gases found in geologic formations beneath the
earth's surface, of which the principal constituent is methane; or (2)
liquefied petroleum (LP) gas, as defined by the American Society for
Testing and Materials in ASTM D1835 (incorporated by reference, see
Sec.  60.17).
    Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
    Oil means crude oil or petroleum, or a liquid fuel derived from
crude oil or petroleum, including distillate oil and residual oil.
    Potential sulfur dioxide emission rate means the theoretical
SO2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat
input) that would result from combusting fuel in an uncleaned state and
without using emission control systems.
    Process heater means a device that is primarily used to heat a
material to initiate or promote a chemical reaction in which the
material participates as a reactant or catalyst.
    Residual oil means crude oil, fuel oil that does not comply with
the specifications under the definition of distillate oil, and all fuel
oil numbers 4, 5, and 6, as defined by the American Society for Testing
and Materials in ASTM D396 (incorporated by reference, see Sec.
60.17).
    Steam generating unit means a device that combusts any fuel and
produces steam or heats water or any other heat transfer medium. This
term includes any duct burner that combusts fuel and is part of a
combined cycle system. This term does not include process heaters as
defined in this subpart.
    Steam generating unit operating day means a 24-hour period between
12:00

midnight and the following midnight during which any fuel is combusted
at any time in the steam generating unit. It is not necessary for fuel
to be combusted continuously for the entire 24-hour period.
    Wet flue gas desulfurization technology means an SO2
control system that is located between the steam generating unit and
the exhaust vent or stack, and that removes sulfur oxides from the
combustion gases of the steam generating unit by contacting the
combustion gases with an alkaline slurry or solution and forming a
liquid material. This definition includes devices where the liquid
material is subsequently converted to another form. Alkaline reagents
used in wet flue gas desulfurization systems include, but are not
limited to, lime, limestone, and sodium compounds.
    Wet scrubber system means any emission control device that mixes an
aqueous stream or slurry with the exhaust gases from a steam generating
unit to control emissions of PM or SO2.
    Wood means wood, wood residue, bark, or any derivative fuel or
residue thereof, in any form, including but not limited to sawdust,
sanderdust, wood chips, scraps, slabs, millings, shavings, and
processed pellets made from wood or other forest residues.

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

    (a) Except as provided in paragraphs (b), (c), and (e) of this
section, on and after the date on which the performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, the owner or operator of an affected facility that
combusts only coal shall neither: Cause to be discharged into the
atmosphere from the affected facility any gases that contain
SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10
percent (0.10) of the potential SO2 emission rate (90
percent reduction), nor cause to be discharged into the atmosphere from
the affected facility any gases that contain SO2 in excess
of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other
fuels, the affected facility shall neither: Cause to be discharged into
the atmosphere from the affected facility any gases that contain
SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10
percent (0.10) of the potential SO2 emission rate (90
percent reduction), nor cause to be discharged into the atmosphere from
the affected facility any gases that contain SO2 in excess
of the emission limit is determined pursuant to paragraph (e)(2) of
this section.
    (b) Except as provided in paragraphs (c) and (e) of this section,
on and after the date on which the performance test is completed or
required to be completed under Sec.  60.8, whichever date comes first,
the owner or operator of an affected facility that:
    (1) Combusts only coal refuse alone in a fluidized bed combustion
steam generating unit shall neither:
    (i) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 87 ng/J
(0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential
SO2 emission rate (80 percent reduction); nor
    (ii) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 520 ng/J
(1.2 lb/MMBtu) heat input. If coal is fired with coal refuse, the
affected facility is subject to paragraph (a) of this section. If oil
or any other fuel (except coal) is fired with coal refuse, the affected
facility is subject to the 87 ng/J (0.20 lb/MMBtu) heat input
SO2 emissions limit or the 90 percent SO2
reduction requirement specified in paragraph (a) of this section and
the emission limit is determined pursuant to paragraph (e)(2) of this
section.
    (2) Combusts only coal and that uses an emerging technology for the
control of SO2 emissions shall neither:
    (i) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 50 percent
(0.50) of the potential SO2 emission rate (50 percent
reduction); nor
    (ii) Cause to be discharged into the atmosphere from that affected
facility any gases that contain SO2 in excess of 260 ng/J
(0.60 lb/MMBtu) heat input. If coal is combusted with other fuels, the
affected facility is subject to the 50 percent SO2 reduction
requirement specified in this paragraph and the emission limit
determined pursuant to paragraph (e)(2) of this section.
    (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, alone or in combination with any other fuel, and is listed in
paragraphs (c)(1), (2), (3), or (4) of this section shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the emission limit determined
pursuant to paragraph (e)(2) of this section. Percent reduction
requirements are not applicable to affected facilities under paragraphs
(c)(1), (2), (3), or (4).
    (1) Affected facilities that have a heat input capacity of 22 MW
(75 MMBtu/hr) or less.
    (2) Affected facilities that have an annual capacity for coal of 55
percent (0.55) or less and are subject to a federally enforceable
requirement limiting operation of the affected facility to an annual
capacity factor for coal of 55 percent (0.55) or less.
    (3) Affected facilities located in a noncontinental area.
    (4) Affected facilities that combust coal in a duct burner as part
of a combined cycle system where 30 percent (0.30) or less of the heat
entering the steam generating unit is from combustion of coal in the
duct burner and 70 percent (0.70) or more of the heat entering the
steam generating unit is from exhaust gases entering the duct burner.
    (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; 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) 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, oil, or coal and oil with any other fuel shall cause to be
discharged into the atmosphere from that affected facility any gases
that contain SO2 in excess of the following:
    (1) The percent of potential SO2 emission rate or
numerical SO2 emission rate required under paragraph (a) or
(b)(2) of this section, as applicable, for any affected facility that
    (i) Combusts coal in combination with any other fuel;
    (ii) Has a heat input capacity greater than 22 MW (75 MMBtu/hr);
and
    (iii) Has an annual capacity factor for coal greater than 55
percent (0.55); and
    (2) The emission limit determined according to the following
formula for any affected facility that combusts coal, oil, or coal and
oil with any other fuel:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.036

Where:

Es = SO2 emission limit, expressed in ng/J or
lb/MMBtu heat input;

Ka = 520 ng/J (1.2 lb/MMBtu);
Kb = 260 ng/J (0.60 lb/MMBtu);
Kc = 215 ng/J (0.50 lb/MMBtu);
Ha = Heat input from the combustion of coal, except coal
combusted in an affected facility subject to paragraph (b)(2) of
this section, in Joules (J) [MMBtu];
Hb = Heat input from the combustion of coal in an
affected facility subject to paragraph (b)(2) of this section, in J
(MMBtu); and
Hc KaHb = Heat input from the
combustion of oil, in J (MMBtu).

    (f) Reduction in the potential SO2 emission rate through
fuel pretreatment is not credited toward the percent reduction
requirement under paragraph (b)(2) of this section unless:
    (1) Fuel pretreatment results in a 50 percent (0.50) or greater
reduction in the potential SO2 emission rate; and
    (2) Emissions from the pretreated fuel (without either combustion
or post-combustion SO2 control) are equal to or less than
the emission limits specified under paragraph (b)(2) of this section.
    (g) Except as provided in paragraph (h) of this section, compliance
with the percent reduction requirements, fuel oil sulfur limits, and
emission limits of this section shall be determined on a 30-day rolling
average basis.
    (h) For affected facilities listed under paragraphs (h)(1), (2), or
(3) 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.
    (1) Distillate oil-fired affected facilities with heat input
capacities between 2.9 and 29 MW (10 and 100 MMBtu/hr).
    (2) Residual oil-fired affected facilities with heat input
capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).
    (3) Coal-fired facilities with heat input capacities between 2.9
and 8.7 MW (10 and 30 MMBtu/hr).
    (i) The SO2 emission limits, fuel oil sulfur limits, and
percent reduction requirements under this section apply at all times,
including periods of startup, shutdown, and malfunction.
    (j) Only the heat input supplied to the affected facility from the
combustion of coal and oil is counted under this section. No credit is
provided for the heat input to the affected facility from wood or other
fuels or for heat derived from exhaust gases from other sources, such
as stationary gas turbines, internal combustion engines, and kilns.

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/hr) 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:
    (1) 22 ng/J (0.051 lb/MMBtu) heat input if the affected facility
combusts only coal, or combusts coal with other fuels and has an annual
capacity factor for the other fuels of 10 percent (0.10) or less.
    (2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility
combusts coal with other fuels, has an annual capacity factor for the
other fuels greater than 10 percent (0.10), and is subject to a
federally enforceable requirement limiting operation of the affected
facility to an annual capacity factor greater than 10 percent (0.10)
for fuels other than coal.
    (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/hr) 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:
    (1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has
an annual capacity factor for wood greater than 30 percent (0.30); or
    (2) 130 ng/J (0.30 lb/MMBtu) heat input if the affected facility
has an annual capacity factor for wood of 30 percent (0.30) or less and
is subject to a federally enforceable requirement limiting operation of
the affected facility to an annual capacity factor for wood of 30
percent (0.30) or less.
    (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/
hr) 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.
    (d) The PM and opacity standards under this section apply at all
times, except during periods of startup, shutdown, or malfunction.
    (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/hr) 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.
    (2) As an alternative to meeting the requirements of paragraph
(e)(1) of this section, the owner or operator of an affected facility
for which modification commenced after February 28, 2005, may elect to
meet the requirements of this paragraph. 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 commences modification after February 28,
2005 shall cause to be discharged into the atmosphere from that
affected facility any gases that contain PM in excess of both:
    (i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion
of coal, oil, wood, a mixture of these fuels, or a mixture of these
fuels with any other fuels; and
    (ii) 0.2 percent of the combustion concentration (99.8 percent
reduction) when combusting coal, oil, wood, a mixture of these fuels,
or a mixture of these fuels with any other fuels.
    (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/hr) 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) 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 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 subject to the PM limit in this section.

Sec.  60.44c  Compliance and performance test methods and procedures
for sulfur dioxide.

    (a) Except as provided in paragraphs (g) and (h) of this section
and Sec.  60.8(b), performance tests required under Sec.  60.8 shall be
conducted following the procedures specified in paragraphs (b), (c),
(d), (e), and (f) of this section, as applicable. Section 60.8(f) does
not apply to this section. The 30-day notice required in Sec.  60.8(d)
applies only to the initial performance test unless otherwise specified
by the Administrator.
    (b) The initial performance test required under Sec.  60.8 shall be
conducted over 30 consecutive operating days of the steam generating
unit. Compliance with the percent reduction requirements and
SO2 emission limits under Sec.  60.42c shall be determined
using a 30-day average. The first operating day included in the initial
performance test shall be scheduled within 30 days after achieving the
maximum production rate at which the affect facility will be operated,
but not later than 180 days after the initial startup of the facility.
The steam generating unit load during the 30-day period does not have
to be the maximum design heat input capacity, but must be
representative of future operating conditions.
    (c) After the initial performance test required under paragraph (b)
of this section and Sec.  60.8, compliance with the percent reduction
requirements and SO2 emission limits under Sec.  60.42c is
based on the average percent reduction and the average SO2
emission rates for 30 consecutive steam generating unit operating days.
A separate performance test is completed at the end of each steam
generating unit operating day, and a new 30-day average percent
reduction and SO2 emission rate are calculated to show
compliance with the standard.
    (d) If only coal, only oil, or a mixture of coal and oil is
combusted in an affected facility, the procedures in Method 19 of
appendix A of this part are used to determine the hourly SO2
emission rate (Eho) and the 30-day average SO2
emission rate (Eao). The hourly averages used to compute the
30-day averages are obtained from the CEMS. Method 19 of appendix A of
this part shall be used to calculate Eao when using daily
fuel sampling or Method 6B of appendix A of this part.
    (e) If coal, oil, or coal and oil are combusted with other fuels:
    (1) An adjusted Eho (Ehoo) is used
in Equation 19-19 of Method 19 of appendix A of this part to compute
the adjusted Eao (Eaoo). The
Ehoo is computed using the following formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.037

Where:
Ehoo = Adjusted Eho, ng/J (lb/
MMBtu);
Eho = Hourly SO2 emission rate, ng/J (lb/
MMBtu);
Ew = SO2 concentration in fuels other than
coal and oil combusted in the affected facility, as determined by
fuel sampling and analysis procedures in Method 9 of appendix A of
this part, ng/J (lb/MMBtu). The value Ew for each fuel
lot is used for each hourly average during the time that the lot is
being combusted. The owner or operator does not have to measure
Ew if the owner or operator elects to assume
Ew=0.
Xk = Fraction of the total heat input from fuel
combustion derived from coal and oil, as determined by applicable
procedures in Method 19 of appendix A of this part.

    (2) The owner or operator of an affected facility that qualifies
under the provisions of Sec.  60.42c(c) or (d) (where percent reduction
is not required) does not have to measure the parameters Ew
or Xk if the owner or operator of the affected facility
elects to measure emission rates of the coal or oil using the fuel
sampling and analysis procedures under Method 19 of appendix A of this
part.
    (f) Affected facilities subject to the percent reduction
requirements under Sec.  60.42c(a) or (b) shall determine compliance
with the SO2 emission limits under Sec.  60.42c pursuant to
paragraphs (d) or (e) of this section, and shall determine compliance
with the percent reduction requirements using the following procedures:
    (1) If only coal is combusted, the percent of potential
SO2 emission rate is computed using the following formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.038

Where:

%Ps = Potential SO2 emission rate, in percent;
%Rg = SO2 removal efficiency of the control
device as determined by Method 19 of appendix A of this part, in
percent; and
%Rf = SO2 removal efficiency of fuel
pretreatment as determined by Method 19 of appendix A of this part,
in percent.

    (2) If coal, oil, or coal and oil are combusted with other fuels,
the same procedures required in paragraph (f)(1) of this section are
used, except as provided for in the following:
    (i) To compute the %Ps, an adjusted %Rg
(%Rgo) is computed from Eaoo from
paragraph (e)(1) of this section and an adjusted average SO2
inlet rate (Eaio) using the following formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.039

Where:

%Rgo = Adjusted %Rg, in percent;
Eaoo = Adjusted Eao, ng/J (lb/
MMBtu); and
Eaio = Adjusted average SO2 inlet
rate, ng/J (lb/MMBtu).
    (ii) To compute Eaio, an adjusted hourly
SO2 inlet rate (Ehio) is used. The
Ehio is computed using the following formula:

 [GRAPHIC] [TIFF OMITTED] TP09FE07.040

Where:

Ehio = Adjusted Ehi, ng/J (lb/
MMBtu);
Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu);
Ew = SO2 concentration in fuels other than
coal and oil combusted in the affected facility, as determined by
fuel sampling and analysis procedures in Method 19 of appendix A of
this part, ng/J (lb/MMBtu). The value Ew for each fuel
lot is used for each hourly average during the time that the lot is
being combusted. The owner or operator does not have to measure
Ew if the owner or operator elects to assume
Ew = 0; and
Xk = Fraction of the total heat input from fuel
combustion derived from coal and oil, as determined by applicable
procedures in Method 19 of appendix A of this part.

    (g) For oil-fired affected facilities where the owner or operator
seeks to demonstrate compliance with the fuel oil sulfur limits under
Sec.  60.42c based on shipment fuel sampling, the initial performance
test shall consist of sampling and analyzing the oil in the initial
tank of oil to be fired in the steam generating unit to demonstrate
that the oil contains 0.5 weight percent sulfur or less. Thereafter,
the owner or operator of the affected facility shall sample the oil in
the fuel tank after each new shipment of oil is received, as described
under Sec.  60.46c(d)(2).
    (h) For affected facilities subject to Sec.  60.42c(h)(1), (2), or
(3) where the owner or operator seeks to demonstrate

compliance with the SO2 standards based on fuel supplier
certification, the performance test shall consist of the certification,
the certification from the fuel supplier, as described under Sec.
60.48c(f), as applicable.
    (i) The owner or operator of an affected facility seeking to
demonstrate compliance with the SO2 standards under Sec.
60.42c(c)(2) shall demonstrate the maximum design heat input capacity
of the steam generating unit by operating the steam generating unit at
this capacity for 24 hours. This demonstration shall be made during the
initial performance test, and a subsequent demonstration may be
requested at any other time. If the demonstrated 24-hour average firing
rate for the affected facility is less than the maximum design heat
input capacity stated by the manufacturer of the affected facility, the
demonstrated 24-hour average firing rate shall be used to determine the
annual capacity factor for the affected facility; otherwise, the
maximum design heat input capacity provided by the manufacturer shall
be used.
    (j) The owner or operator of an affected facility shall use all
valid SO2 emissions data in calculating %Ps and
Eho under paragraphs (d), (e), or (f) of this section, as
applicable, whether or not the minimum emissions data requirements
under Sec.  60.46c(f) are achieved. All valid emissions data, including
valid data collected during periods of startup, shutdown, and
malfunction, shall be used in calculating %Ps or
Eho pursuant to paragraphs (d), (e), or (f) of this section,
as applicable.

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

    (a) The owner or operator of an affected facility subject to the PM
and/or opacity standards under Sec.  60.43c shall conduct an initial
performance test as required under Sec.  60.8, and shall conduct
subsequent performance tests as requested by the Administrator, to
determine compliance with the standards using the following procedures
and reference methods, except as specified in paragraph (c) of this
section.
    (1) Method 1 of appendix A of this part shall be used to select the
sampling site and the number of traverse sampling points.
    (2) Method 3 of appendix A of this part shall be used for gas
analysis when applying Method 5, 5B, or 17 of appendix A of this part.
    (3) Method 5, 5B, or 17 of appendix A of this part shall be used to
measure the concentration of PM as follows:
    (i) Method 5 of appendix A of this part may be used only at
affected facilities without wet scrubber systems.
    (ii) Method 17 of appendix A of this part may be used at affected
facilities with or without wet scrubber systems provided the stack gas
temperature does not exceed a temperature of 160 [deg]C (320 [deg]F).
The procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of
this part may be used in Method 17 of appendix A of this part only if
Method 17 of appendix A of this part is used in conjunction with a wet
scrubber system. Method 17 of appendix A of this part shall not be used
in conjunction with a wet scrubber system if the effluent is saturated
or laden with water droplets.
    (iii) Method 5B of appendix A of this part may be used in
conjunction with a wet scrubber system.
    (4) The sampling time for each run shall be at least 120 minutes
and the minimum sampling volume shall be 1.7 dry standard cubic meters
(dscm) [60 dry standard cubic feet (dscf)] except that smaller sampling
times or volumes may be approved by the Administrator when necessitated
by process variables or other factors.
    (5) For Method 5 or 5B of appendix A of this part, the temperature
of the sample gas in the probe and filter holder shall be monitored and
maintained at 16014 [deg]C (32025 [deg]F).
    (6) For determination of PM emissions, an oxygen (O2) or
carbon dioxide (CO2) measurement shall be obtained
simultaneously with each run of Method 5, 5B, or 17 of appendix A of
this part by traversing the duct at the same sampling location.
    (7) For each run using Method 5, 5B, or 17 of appendix A of this
part, the emission rates expressed in ng/J (lb/MMBtu) heat input shall
be determined using:
    (i) The O2 or CO2 measurements and PM
measurements obtained under this section,
    (ii) The dry basis F factor, and
    (iii) The dry basis emission rate calculation procedure contained
in Method 19 of appendix A of this part.
    (8) Method 9 of appendix A of this part (6-minute average of 24
observations) shall be used for determining the opacity of stack
emissions.
    (b) The owner or operator of an affected facility seeking to
demonstrate compliance with the PM standards under Sec.  60.43c(b)(2)
shall demonstrate the maximum design heat input capacity of the steam
generating unit by operating the steam generating unit at this capacity
for 24 hours. This demonstration shall be made during the initial
performance test, and a subsequent demonstration may be requested at
any other time. If the demonstrated 24-hour average firing rate for the
affected facility is less than the maximum design heat input capacity
stated by the manufacturer of the affected facility, the demonstrated
24-hour average firing rate shall be used to determine the annual
capacity factor for the affected facility; otherwise, the maximum
design heat input capacity provided by the manufacturer shall be used.
    (c) In place of PM testing with EPA Reference Method 5, 5B, or 17
of appendix A of this part, an owner or operator may elect to install,
calibrate, maintain, and operate a CEMS for monitoring PM emissions
discharged to the atmosphere and record the output of the system. The
owner or operator of an affected facility who elects to continuously
monitor PM emissions instead of conducting performance testing using
EPA Method 5, 5B, or 17 of appendix A of this part shall install,
calibrate, maintain, and operate a CEMS and shall comply with the
requirements specified in paragraphs (c)(1) through (c)(13) of this
section.
    (1) Notify the Administrator 1 month before starting use of the
system.