(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, an owner or operator of an affected facility that
commences construction, reconstruction, or modification after February
28, 2005, and that combusts only oil that contains no more than 0.50
weight percent sulfur or a mixture of 0.50 weight percent sulfur oil
with other fuels not subject to a PM standard under Sec.  60.43c and
not using a post-combustion technology (except a wet scrubber) to
reduce PM or SO2 emissions is not subject to the PM limit in
this section.

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] TR13JN07.033

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] TR13JN07.034

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] TR13JN07.035

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] TR13JN07.036

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 160 14 [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.
    (2) Notify the Administrator 1 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 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 (d) 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 paragraph (d)(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.
    (ii) [Reserved]
    (8) The 1-hour arithmetic averages required under paragraph (d)(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 (d)(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 (d)(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 Audit's 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 on a 30-day rolling
average.
    (d) The owner or operator of an affected facility seeking to
demonstrate compliance under Sec.  60.43c(e)(4) shall follow the
applicable procedures under Sec.  60.48c(f). For residual oil-fired
affected facilities, fuel supplier certifications are only allowed for
facilities with heat input capacities

between 2.9 and 8.7 MW (10 to 30 MMBtu/hr).

Sec.  60.46c  Emission monitoring for sulfur dioxide.

    (a) Except as provided in paragraphs (d) and (e) of this section,
the owner or operator of an affected facility subject to the
SO2 emission limits under Sec.  60.42c shall install,
calibrate, maintain, and operate a CEMS for measuring SO2
concentrations and either O2 or CO2
concentrations at the outlet of the SO2 control device (or
the outlet of the steam generating unit if no SO2 control
device is used), and shall record the output of the system. The owner
or operator of an affected facility subject to the percent reduction
requirements under Sec.  60.42c shall measure SO2
concentrations and either O2 or CO2
concentrations at both the inlet and outlet of the SO2
control device.
    (b) The 1-hour average SO2 emission rates measured by a
CEMS shall be expressed in ng/J or lb/MMBtu heat input and shall be
used to calculate the average emission rates under Sec.  60.42c. Each
1-hour average SO2 emission rate must be based on at least
30 minutes of operation, and shall be calculated using the data points
required under Sec.  60.13(h)(2). Hourly SO2 emission rates
are not calculated if the affected facility is operated less than 30
minutes in a 1-hour period and are not counted toward determination of
a steam generating unit operating day.
    (c) 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 subject to the percent reduction
requirements under Sec.  60.42c, the span value of the SO2
CEMS at the inlet to the SO2 control device shall be 125
percent of the maximum estimated hourly potential SO2
emission rate of the fuel combusted, and the span value of the
SO2 CEMS at the outlet from the SO2 control
device shall be 50 percent of the maximum estimated hourly potential
SO2 emission rate of the fuel combusted.
    (4) For affected facilities that are not subject to the percent
reduction requirements of Sec.  60.42c, the span value of the
SO2 CEMS at the outlet from the SO2 control
device (or outlet of the steam generating unit if no SO2
control device is used) shall be 125 percent of the maximum estimated
hourly potential SO2 emission rate of the fuel combusted.
    (d) As an alternative to operating a CEMS at the inlet to the
SO2 control device (or outlet of the steam generating unit
if no SO2 control device is used) as required under
paragraph (a) of this section, an owner or operator may elect to
determine the average SO2 emission rate by sampling the fuel
prior to combustion. As an alternative to operating a CEMS at the
outlet from the SO2 control device (or outlet of the steam
generating unit if no SO2 control device is used) as
required under paragraph (a) of this section, an owner or operator may
elect to determine the average SO2 emission rate by using
Method 6B of appendix A of this part. Fuel sampling shall be conducted
pursuant to either paragraph (d)(1) or (d)(2) of this section. Method
6B of appendix A of this part shall be conducted pursuant to paragraph
(d)(3) of this section.
    (1) For affected facilities combusting coal or oil, coal or oil
samples shall be collected daily in an as-fired condition at the inlet
to the steam generating unit and analyzed for sulfur content and heat
content according the 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.
    (2) As an alternative fuel sampling procedure for affected
facilities combusting oil, oil samples may be collected from the fuel
tank for each steam generating unit immediately after the fuel tank is
filled and before any oil is combusted. The owner or operator of the
affected facility shall analyze the oil sample to determine the sulfur
content of the oil. If a partially empty fuel tank is refilled, a new
sample and analysis of the fuel in the tank would be required upon
filling. Results of the fuel analysis taken after each new shipment of
oil is received shall be used as the daily value when calculating the
30-day rolling average until the next shipment is received. If the fuel
analysis shows that the sulfur content in the fuel tank is greater than
0.5 weight percent sulfur, the owner or operator shall ensure that the
sulfur content of subsequent oil shipments is low enough to cause the
30-day rolling average sulfur content to be 0.5 weight percent sulfur
or less.
    (3) Method 6B of appendix A of this part may be used in lieu of
CEMS to measure SO2 at the inlet or outlet of 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 Sec.  3.2 and the applicable
procedures in section 7 of Performance Specification 2 of appendix B of
this part. Method 6B of appendix A of this part, Method 6A of appendix
A of this part, or a combination of Methods 6 and 3 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 (0.10).
    (e) The monitoring requirements of paragraphs (a) and (d) of this
section shall not apply to affected facilities subject to Sec.
60.42c(h) (1), (2), or (3) where the owner or operator of the affected
facility seeks to demonstrate compliance with the SO2
standards based on fuel supplier certification, as described under
Sec.  60.48c(f), as applicable.
    (f) The owner or operator of an affected facility operating a CEMS
pursuant to paragraph (a) of this section, or conducting as-fired fuel
sampling pursuant to paragraph (d)(1) of this section, shall obtain
emission data for at least 75 percent of the operating hours in at
least 22 out of 30 successive steam generating unit 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.

Sec.  60.47c  Emission monitoring for particulate matter.

    (a) Except as provided in paragraphs (c), (d), (e), and (f) of this
section, the owner or operator of an affected facility combusting coal,
oil, or wood that is subject to the opacity standards under Sec.
60.43c shall install, calibrate, maintain, and operate a COMS for
measuring the opacity of the emissions discharged to the atmosphere and
record the output of the system.
    (b) All COMS for measuring opacity shall be operated in accordance
with the

applicable procedures under Performance Specification 1 of appendix B
of this part. The span value of the opacity COMS shall be between 60
and 80 percent.
    (c) Affected facilities that burn only distillate oil that contains
no more than 0.5 weight percent sulfur and/or liquid or gaseous fuels
with potential sulfur dioxide emission rates of 26 ng/J (0.06 lb/MMBtu)
heat input or less and that do not use a post-combustion technology to
reduce SO2 or PM emissions are not required to operate a
CEMS for measuring opacity if they follow the applicable procedures
under Sec.  60.48c(f).
    (d) 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.
60.45c(d). The CEMS specified in paragraph Sec.  60.45c(d) 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.
    (e) An affected facility that does not use post-combustion
technology (except a wet scrubber) for reducing PM, SO2, or
carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils
that contain less than or equal to 0.5 weight percent sulfur, and is
operated such that emissions of CO to the atmosphere from the affected
facility are maintained at levels less than or equal to 0.15 lb/MMBtu
on a boiler operating day average basis is not required to operate a
COMS for measuring opacity. Owners and operators of affected facilities
electing to comply with this paragraph must demonstrate compliance
according to the procedures specified in paragraphs (e)(1) through (4)
of this section.
    (1) You must monitor CO emissions using a CEMS according to the
procedures specified in paragraphs (e)(1)(i) through (iv) of this
section.
    (i) The CO CEMS must be installed, certified, maintained, and
operated according to the provisions in Sec.  60.58b(i)(3) of subpart
Eb of this part.
    (ii) Each 1-hour CO emissions average is calculated using the data
points generated by the CO CEMS expressed in parts per million by
volume corrected to 3 percent oxygen (dry basis).
    (iii) At a minimum, valid 1-hour CO emissions averages must be
obtained for at least 90 percent of the operating hours on a 30-day
rolling average basis. At least two data points per hour must be used
to calculate each 1-hour average.
    (iv) Quarterly accuracy determinations and daily calibration drift
tests for the CO CEMS must be performed in accordance with procedure 1
in appendix F of this part.
    (2) You must calculate the 1-hour average CO emissions levels for
each steam generating unit operating day by multiplying the average
hourly CO output concentration measured by the CO CEMS times the
corresponding average hourly flue gas flow rate and divided by the
corresponding average hourly heat input to the affected source. The 24-
hour average CO emission level is determined by calculating the
arithmetic average of the hourly CO emission levels computed for each
steam generating unit operating day.
    (3) You must evaluate the preceding 24-hour average CO emission
level each steam generating unit operating day excluding periods of
affected source startup, shutdown, or malfunction. If the 24-hour
average CO emission level is greater than 0.15 lb/MMBtu, you must
initiate investigation of the relevant equipment and control systems
within 24 hours of the first discovery of the high emission incident
and, take the appropriate corrective action as soon as practicable to
adjust control settings or repair equipment to reduce the 24-hour
average CO emission level to 0.15 lb/MMBtu or less.
    (4) You must record the CO measurements and calculations performed
according to paragraph (e) of this section and any corrective actions
taken. The record of corrective action taken must include the date and
time during which the 24-hour average CO emission level was greater
than 0.15 lb/MMBtu, and the date, time, and description of the
corrective action.
    (f) An affected facility that burns only gaseous fuels or fuel oils
that contain less than or equal to 0.5 weight percent sulfur and
operates according to a written site-specific monitoring plan approved
by the appropriate delegated permitting authority is not required to
operate a COMS for measuring opacity. This monitoring plan must include
procedures and criteria for establishing and monitoring specific
parameters for the affected facility indicative of compliance with the
opacity standard.

Sec.  60.48c  Reporting and recordkeeping requirements.

    (a) The owner or operator of each affected facility shall submit
notification of the date of construction or reconstruction and actual
startup, as provided by Sec.  60.7 of this part. This notification
shall include:
    (1) The design heat input capacity of the affected facility and
identification of 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.  60.42c, or Sec.  60.43c.
    (3) The annual capacity factor at which the owner or operator
anticipates operating the affected facility based on all fuels fired
and based on each individual fuel fired.
    (4) Notification if an emerging technology will be used for
controlling SO2 emissions. The Administrator will examine
the description of the control device 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.  60.42c(a) or (b)(1), unless and until this determination is made
by the Administrator.
    (b) The owner or operator of each affected facility subject to the
SO2 emission limits of Sec.  60.42c, or the PM or opacity
limits of Sec.  60.43c, shall submit to the Administrator the
performance test data from the initial and any subsequent performance
tests and, if applicable, the performance evaluation of the CEMS and/or
COMS using the applicable performance specifications in appendix B of
this part.
    (c) The owner or operator of each coal-fired, oil-fired, or wood-
fired affected facility subject to the opacity limits under Sec.
60.43c(c) shall submit excess emission reports for any excess emissions
from the affected facility that occur during the reporting period.
    (d) The owner or operator of each affected facility subject to the
SO2 emission limits, fuel oil sulfur limits, or percent
reduction requirements under Sec.  60.42c shall submit reports to the
Administrator.
    (e) The owner or operator of each affected facility subject to the
SO2 emission limits, fuel oil sulfur limits, or percent
reduction requirements under Sec.  60.42c shall keep records and submit
reports as required under paragraph (d) of this section, including the
following information, as applicable.
    (1) Calendar dates covered in the reporting period.
    (2) Each 30-day average SO2 emission rate (ng/J or lb/
MMBtu), or 30-day average sulfur content (weight percent), calculated
during the reporting period, ending with the last 30-day period;
reasons for any noncompliance with the

emission standards; and a description of corrective actions taken.
    (3) Each 30-day average percent of potential SO2
emission rate calculated during the reporting period, ending with the
last 30-day period; reasons for any noncompliance with the emission
standards; and a description of the corrective actions taken.
    (4) Identification of any steam generating unit operating days 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 a description of corrective actions taken.
    (5) Identification of any times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and a description of corrective actions 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 the F factor used in calculations, method of
determination, and type of fuel combusted.
    (7) Identification of whether averages have been obtained based on
CEMS rather than manual sampling methods.
    (8) If a CEMS is used, identification of any times when the
pollutant concentration exceeded the full span of the CEMS.
    (9) If a CEMS is used, description of any modifications to the CEMS
that could affect the ability of the CEMS to comply with Performance
Specifications 2 or 3 of appendix B of this part.
    (10) If a CEMS is used, results of daily CEMS drift tests and
quarterly accuracy assessments as required under appendix F, Procedure
1 of this part.
    (11) If fuel supplier certification is used to demonstrate
compliance, records of fuel supplier certification is used to
demonstrate compliance, records of fuel supplier certification as
described under paragraph (f)(1), (2), (3), or (4) of this section, as
applicable. In addition to records of fuel supplier certifications, the
report shall include a certified statement signed by the owner or
operator of the affected facility that the records of fuel supplier
certifications submitted represent all of the fuel combusted during the
reporting period.
    (f) Fuel supplier certification shall include the following
information:
    (1) For distillate oil:
    (i) The name of the oil supplier;
    (ii) A statement from the oil supplier that the oil complies with
the specifications under the definition of distillate oil in Sec.
60.41c; and
    (iii) The sulfur content of the oil.
    (2) For residual oil:
    (i) The name of the oil supplier;
    (ii) The location of the oil when the sample was drawn for analysis
to determine the sulfur content of the oil, specifically including
whether the oil was sampled as delivered to the affected facility, or
whether the sample was drawn from oil in storage at the oil supplier's
or oil refiner's facility, or other location;
    (iii) The sulfur content of the oil from which the shipment came
(or of the shipment itself); and
    (iv) The method used to determine the sulfur content of the oil.
    (3) For coal:
    (i) The name of the coal supplier;
    (ii) The location of the coal when the sample was collected for
analysis to determine the properties of the coal, specifically
including whether the coal was sampled as delivered to the affected
facility or whether the sample was collected from coal in storage at
the mine, at a coal preparation plant, at a coal supplier's facility,
or at another location. The certification shall include the name of the
coal mine (and coal seam), coal storage facility, or coal preparation
plant (where the sample was collected);
    (iii) The results of the analysis of the coal from which the
shipment came (or of the shipment itself) including the sulfur content,
moisture content, ash content, and heat content; and
    (iv) The methods used to determine the properties of the coal.
    (4) For other fuels:
    (i) The name of the supplier of the fuel;
    (ii) The potential sulfur emissions rate of the fuel in ng/J heat
input; and
    (iii) The method used to determine the potential sulfur emissions
rate of the fuel.
    (g)(1) Except as provided under paragraphs (g)(2) and (g)(3) of
this section, the owner or operator of each affected facility shall
record and maintain records of the amount of each fuel combusted during
each operating day.
    (2) As an alternative to meeting the requirements of paragraph
(g)(1) of this section, the owner or operator of an affected facility
that combusts only natural gas, wood, fuels using fuel certification in
Sec.  60.48c(f) to demonstrate compliance with the SO2
standard, fuels not subject to an emissions standard (excluding
opacity), or a mixture of these fuels may elect to record and maintain
records of the amount of each fuel combusted during each calendar
month.
    (3) As an alternative to meeting the requirements of paragraph
(g)(1) of this section, the owner or operator of an affected facility
or multiple affected facilities located on a contiguous property unit
where the only fuels combusted in any steam generating unit (including
steam generating units not subject to this subpart) at that property
are natural gas, wood, distillate oil meeting the most current
requirements in Sec.  60.42C to use fuel certification to demonstrate
compliance with the SO2 standard, and/or fuels, excluding
coal and residual oil, not subject to an emissions standard (excluding
opacity) may elect to record and maintain records of the total amount
of each steam generating unit fuel delivered to that property during
each calendar month.
    (h) The owner or operator of each affected facility subject to a
federally enforceable requirement limiting the annual capacity factor
for any fuel or mixture of fuels under Sec.  60.42c or Sec.  60.43c
shall calculate the annual capacity factor individually for each fuel
combusted. The annual capacity factor is determined on a 12-month
rolling average basis with a new annual capacity factor calculated at
the end of the calendar month.
    (i) All records required under this section shall be maintained by
the owner or operator of the affected facility for a period of two
years following the date of such record.
    (j) The reporting period for the reports required under this
subpart is each six-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.

Appendix B--[Amended]

0
7. Appendix B to part 60 is amended by revising section 8.3.1 in
Performance Specification 2, to read as follows:

Appendix B to Part 60--Performance Specifications

* * * * *

Performance Specification 2--Specifications and Test Procedures for
SO2 and NOX Continuous Emission Monitoring
Systems in Stationary Sources

* * * * *
    8.3.1 CD Test Period. While the affected facility is operating,
determine the magnitude of the CD once each day (at 24-hour
intervals) for 7 consecutive calendar days according to the
procedure given in Sections 8.3.2 through 8.3.4. Alternatively, the
CD test may be conducted over 7 consecutive unit operating days.
* * * * *

Appendix F--[Amended]

0
8. Procedure 1 in Appendix F to part 60 is amended by:
0
a. Revising the first sentence of section 5.1.1; and
0
b. Revising section 5.1.4.
    The revisions read as follows:

Appendix F to Part 60--Quality Assurance Procedures

* * * * *
    5.1.1 Relative Accuracy Test Audit (RATA). The RATA must be
conducted at least once every four calendar quarters, except as
otherwise noted in section 5.1.4 of this appendix.
* * * * *
    5.1.4 Other Alternative Audits. Other alternative audit
procedures may be used as approved by the Administrator for three of
four calendar quarters. One RATA is required at least every four
calendar quarters, except in the case where the affected facility is
off-line (does not operate) in the fourth calendar quarter since the
quarter of the previous RATA. In that case, the RATA shall be
performed in the quarter in which the unit recommences operation.
Also, cylinder gas audits are not be required for calendar quarters
in which the affected facility does not operate.
* * * * *

[FR Doc. E7-7673 Filed 6-12-07; 8:45 am]

BILLING CODE 6560-50-P


P-18-0108 Sanitized Support Documents Index:
 P-18-0108 Sanitized Determination Document (linked)
 P-18-0108 Sanitized CHEM Report (attached)
 P-18-0108 Sanitized ECO Report (attached)
 P-18-0108 Sanitized ENG Report (attached)
 P-18-0108 Sanitized EXP Report (attached)
 P-18-0108 Sanitized Fate Report (attached)
 P-18-0108 Sanitized HLTH Report_POST-FOCUS FINAL (attached)