emissions standard according to Sec.  60.4333(d)(2), the fuel analyses
may be performed either by you, a service contractor retained by you,
the fuel vendor, or any other qualified agency as determined by the
delegated permitting authority using the sampling frequency specified
in Sec.  60.4365.
    (b) Representative fuel analysis samples may be collected either
manually or by an automatic sampling system. For automatic sampling,
following ASTM D5287 (incorporated by reference, see Sec.  60.17) for
gaseous fuels or ASTM D4177 (incorporated by reference, see Sec.
60.17) for liquid fuels. For reference purposes when manually
collecting gaseous samples, see Gas Processors Association Standard
2166 (incorporated by reference, see Sec.  60.17). For reference
purposes when manually collecting liquid samples, see either Gas
Processors Association Standard 2174 or the procedures for manual
pipeline sampling in section 14 of ASTM D4057 (both of which are
incorporated by reference, see Sec.  60.17).
    (c) Each collected fuel analysis sample must be analyzed for the
total sulfur content of the fuel and heating value using the methods
specified in paragraphs (c)(1) or (2) of this section, as applicable to
the fuel type.
    (1) For the sulfur content of liquid fuels, ASTM D129, or
alternatively D1266, D1552, D2622, D4294, or D5453 (all of which are
incorporated by reference, see Sec.  60.17). For the heating value of
liquid fuels, ASTM D240 or D4809 (both of which are incorporated by
reference, see Sec.  60.17); or
    (2) For the sulfur content of gaseous fuels, ASTM D1072, or
alternatively D3246, D4468, or D6667 (all of which are incorporated by
reference, see Sec.  60.17). If the total sulfur content of the gaseous
fuel during the most recent compliance demonstration was less than half
the applicable standard, ASTM D4084, D4810, D5504, or D6228, or Gas
Processors Association Standard 2377 (all of which are incorporated by
reference, see Sec.  60.17), which measure the major sulfur compounds,
may be used. For the heating value of gaseous fuels, ASTM D1826, or
alternatively D3588, D4891, or D7164, or Gas Processors Association
Standard 2172 (all of which are incorporated by reference, see Sec.
60.17).

Sec.  60.4365  How frequently must I determine the fuel sulfur content?

    (a) If you are complying with requirements in Sec.  60.4360, the
total sulfur content of all fuels combusted in each stationary
combustion turbine subject to an SO2 emissions standard in
Sec.  60.4330 must be determined according to the schedule specified in
paragraphs (a)(1) or (2) of this section, as applicable to the fuel
type, unless you determine a custom schedule for the stationary
combustion turbine according to paragraph (b) of this section.
    (1) Liquid fuel. Use one of the total sulfur sampling options and
the associated sampling frequency described in sections 2.2.3, <IP_ADDRESS>,
<IP_ADDRESS>, and <IP_ADDRESS> in appendix D to part 75 of this chapter (i.e.
flow proportional sampling, daily sampling, sampling from the unit's
storage tank after each addition of fuel to the tank, or sampling each
delivery prior to combining it with liquid fuel already in the intended
storage tank).
    (2) Gaseous fuel. If the fuel is supplied without intermediate bulk
storage, the sulfur content value of the gaseous fuel must be
determined and recorded once per operating day.
    (b) Custom schedules. As an alternative to the requirements of
paragraph (a) of this section, you may implement custom schedules for
determination of the total sulfur content of gaseous fuels, based on
the design and operation of the affected facility and the
characteristics of the fuel supply using the procedures provided in
either paragraph (b)(1) and (2) of this section. Either you or the fuel
vendor may perform the sampling. As an alternative to using one of
these procedures, you may use a custom schedule that has been
substantiated with data and approved by the Administrator or delegated
authority as a change in monitoring prior to being used to comply with
the applicable standard in Sec.  60.4330.
    (1) You may determine and implement a custom sulfur sampling
schedule for your stationary combustion turbine using the procedure
specified in paragraphs (b)(1)(i) through (iv) of this section.
    (i) Obtain daily total sulfur content measurements for 30
consecutive operating days, using the applicable methods specified in
this subpart. Based on the results of the 30 daily samples, the
required frequency for subsequent monitoring of the fuel's total sulfur
content must be as specified in paragraph (b)(1)(ii), (iii), or (iv) of
this section, as applicable.
    (ii) If none of the 30 daily measurements of the fuel's total
sulfur content exceeds half the applicable standard, subsequent sulfur
content monitoring may be performed at 12-month intervals provided the
fuel source or supplier does not change. If any of the samples taken at
12-month intervals has a total sulfur content greater than half but
less than the applicable standard, follow the procedures in paragraph
(b)(1)(iii) of this section. If any measurement exceeds the applicable
standard, follow the procedures in paragraph (b)(1)(iv) of this
section.
    (iii) If at least one of the 30 daily measurements of the fuel's
total sulfur content is greater than half but less than the applicable
standard, but none exceeds the applicable standard, then:
    (A) Collect and analyze a sample every 30 days for 3 months. If any
sulfur content measurement exceeds the applicable standard, follow the
procedures in paragraph (b)(1)(iv) of this section. Otherwise, follow
the procedures in paragraph (b)(1)(iii)(B) of this section.
    (B) Begin monitoring at 6-month intervals for 12 months. If any
sulfur content measurement exceeds the applicable standard, follow the
procedures in paragraph (b)(1)(iv) of this section. Otherwise, follow
the procedures in paragraph (b)(1)(iii)(C) of this section.
    (C) Begin monitoring at 12-month intervals. If any sulfur content
measurement exceeds the applicable standard, follow the procedures in
paragraph (b)(1)(iv) of this section. Otherwise, continue to monitor at
this frequency.
    (iv) If a sulfur content measurement exceeds the applicable
standard, immediately begin daily monitoring according to paragraph
(c)(1)(i) of this section. Daily monitoring must continue until 30
consecutive daily samples, each having a sulfur content no greater than
the applicable standard, are obtained. At that point, the applicable
procedures of paragraph (b)(1)(ii) or (iii) of this section must be
followed.
    (2) You may use the data collected from the 720-hour sulfur
sampling demonstration described in section 2.3.6 in appendix D to part
75 of this chapter to determine and implement a sulfur sampling
schedule for your stationary combustion turbine using the procedure
specified in paragraphs (b)(2)(i) through (iii) of this section.
    (i) If the maximum fuel sulfur content obtained from any of the 720
hourly samples does not exceed half the applicable standard, then the
minimum required sampling frequency must be one sample at 12 month
intervals.

    (ii) If any sample result exceeds half the applicable standard, but
none exceeds the applicable standard, follow the provisions of
paragraph (b)(1)(iii) of this section.
    (iii) If the sulfur content of any of the 720 hourly samples
exceeds the applicable standard, follow the provisions of paragraph
(b)(1)(iv) of this section.

Sec.  60.4370  How do I demonstrate compliance with my SO2
emissions standard using records of the fuel sulfur content?

    (a) If you elect to demonstrate compliance with a SO2
emissions standard according to Sec.  60.4333(d)(3), you must maintain
on-site records (such as a current, valid purchase contract, tariff
sheet, or transportation contract) documenting that total sulfur
content for the fuel combusted in your stationary combustion turbine at
all times does not exceed the conditions specified in paragraph (b)
through (e) of this section, as applicable to your stationary
combustion turbine.
    (b) If your stationary combustion turbine is subject to the
SO2 emissions standard in Sec.  60.4330(a), then the fuel
combusted must have a potential SO2 emissions rate of 26 ng/
J (0.060 lb/MMBtu) heat input or less.
    (c) If your stationary combustion turbine is subject to the
SO2 emissions standard in Sec.  60.4330(b), then the total
sulfur content of the gaseous fuel combusted must be 650 (mg/scm) (28
gr/100 scf).
    (d) If your stationary combustion turbine is subject to the
SO2 emissions standard in Sec.  60.4330(c) or (d), the total
sulfur content of the fuel combusted must be:
    (1) For natural gas, 140 gr/100 scf or less.
    (2) For fuel oil, 0.40 weight percent (4,000 ppmw) or less.
    (3) For other fuels, potential SO2 emissions of 180 ng/J
(0.42 lb/MMBtu) heat input or less.
    (e) Representative fuel sampling data following the procedures
specified in section <IP_ADDRESS> or <IP_ADDRESS> in appendix D to part 75 of
this chapter documenting that the fuel meets the part 75 requirements
to be considered either pipeline natural gas or natural gas.

Sec.  60.4372  How do I demonstrate compliance with my SO2
emissions standard and determine excess emissions using a
SO2 CEMS?

    (a) If you demonstrate continuous compliance using a CEMS for
measuring SO2 emissions, excess emissions are defined as the
applicable averaging period, either 4-operating hour or 30-operating
day, during which the average SO2 emissions from your
stationary combustion turbine measured by the CEMS exceeds the
applicable SO2 emissions standard specified in Sec.  60.4330
as determined using the procedures specified in this section that apply
to your stationary combustion turbine.
    (b) You must install, calibrate, maintain, and operate a CEMS for
measuring SO2 concentrations and either O2 or
CO2 concentrations at the outlet of your stationary
combustion turbine, and record the output of the system.
    (c) The 1-hour average SO2 emissions rate measured by a
CEMS must be expressed in ng/J or lb/MMBtu heat input and must be used
to calculate the average emissions rate under Sec.  60.4330.
    (d) You must use the procedures for installation, evaluation, and
operation of the CEMS as specified in Sec.  60.13 and paragraphs (d)(1)
through (3) of this section.
    (1) Each CEMS must be operated according to the applicable
procedures under Performance Specifications 1, 2, and 3 in appendix B
of this part;
    (2) Quarterly accuracy determinations and daily calibration drift
tests must be performed according to Procedure 1 in appendix F of this
part; and
    (3) The span value of the SO2 CEMS at the outlet from
the SO2 control device (or outlet of the stationary
combustion turbine if no SO2 control device is used) must be
125 percent of either the highest applicable standard or highest
potential SO2 emissions rate of the fuel combusted.
    (e) Correction of measured SO2 concentrations to 15
percent O2 is not allowed.
    (f) If you have installed and certified a SO2 CEMS that
meets the requirements of part 75 of this chapter, the delegated
permitting authority can approve that only quality assured data from
the CEMS must be used to identify excess emissions under this subpart.
You must report periods where the missing data substitution procedures
in subpart D of part 75 are applied as monitoring system downtime in
the excess emissions and monitoring performance report required under
Sec.  60.7(c).
    (g) All required fuel flow rate, steam flow rate, temperature,
pressure, and megawatt data must be reduced to hourly averages.
    (h) Calculate the hourly average SO2 emissions rate, in
units of the emissions standard under Sec.  60.4330, using lb/MMBtu for
units complying with the input-based standard or using equation 11 of
this subpart for units complying with the output-based standard:
    (1) For simple-cycle operation:
    [GRAPHIC] [TIFF OMITTED] TP29AU12.012

Where:

E = Hourly SO2 emissions rate, in lb/MWh,
(SO2)h = Average hourly SO2
emissions rate, in lb/MMBtu,
Q = Hourly heat input rate to the stationary combustion turbine, in
MMBtu, measured using the fuel flow meter(s), e.g., calculated using
Equation D-15a in appendix D to part 75 of this chapter, an
O2 or CO2 CEMS and a stack flow meter, or the
methodologies in appendix F to part 75 of this chapter, and
P = Gross energy output of the stationary combustion turbine in MWh.

    (2) The gross energy output is calculated as the sum of the total
electrical and mechanical energy generated by the stationary combustion
turbine, the additional electrical or mechanical energy (if any)
generated by the steam turbine following the heat recovery steam
generating unit, and the total useful thermal energy output that is not
used to generate additional electricity or mechanical output, expressed
in equivalent MWh, as calculated using Equations 12 and 13 of this
subpart.
[GRAPHIC] [TIFF OMITTED] TP29AU12.013

Where:

P = Gross energy output of the stationary combustion turbine system
in MWh,
(Pe)t = Electrical or mechanical energy output of the
stationary combustion turbine in MWh,
(Pe)c = Electrical or mechanical energy output (if any)
of the steam turbine in MWh,

Ps = Useful thermal energy of the steam, measured
relative to ISO conditions, not used to generate additional electric
or mechanical output, in MWh, and
Po = Other useful heat recovery, measured relative to ISO
conditions, not used for steam generation or performance enhancement
of the stationary combustion turbine.
T = Electric Transmission and Distribution Factor. Equal to 0.95 for
CHP combustion turbine where at least 20.0 percent of the total
gross useful energy output consists of electric or direct mechanical
output and 20.0 percent of the total gross useful energy output
consists of useful thermal output on an annual basis. Equal to 1.0
for all other combustion turbines.

[GRAPHIC] [TIFF OMITTED] TP29AU12.014

Where:

Ps = Useful thermal energy of the steam, measured
relative to ISO conditions, not used to generate additional electric
or mechanical output, in MWh,
Qm = Measured steam flow rate in lb,
H = Enthalpy of the steam at measured temperature and pressure
relative to ISO conditions, in Btu/lb, and
3.413 x 10\6\ = Conversion factor from Btu to MWh.

    (3) For mechanical drive applications complying with the output-
based standard, use equation 14 of this subpart:
[GRAPHIC] [TIFF OMITTED] TP29AU12.015

Where:

E = SO2 emissions rate in lb/MWh,
(SO2)m = SO2 emissions rate in lb/
h,
BL = Manufacturer's base load rating of turbine, in MW, and
AL = Actual load as a percentage of the base load rating.

    (i) For stationary combustion turbines other than combined cycle
combustion turbines and CHP combustion turbines, you must determine
excess emissions on a 4-operating hour rolling average basis. The ``4-
operating hour rolling average SO2 measured emissions rate''
is the SO2 emissions measured by the CEMS for a given
operating hour and the 3 consecutive operating hours immediately
preceding that hour expressed in the units appropriate for the
SO2 emissions standard that is applied to your stationary
combustion turbine. Each operating hour, calculate the 4-operating hour
rolling average SO2 measured emissions rate using all of the
non out-of-control SO2 emission data obtained during the
previous 4-operating hour operating period. If the 4-operating hour
period contains more than one operating hour with no data points (one
or more CEMS was out-of-control for the entire hour), report the 4-
operating hour rolling average SO2 emissions rate determined
for the period as occurring during a period with monitor downtime. If
you elect to comply with the applicable heat input-based emissions rate
standard, calculate both the measured emissions rate and the emissions
standard using Equation 15 of this subpart. If you elect to comply with
the applicable output-based emissions standard, calculate the measured
emissions rate using Equation 16-1 of this subpart and calculate the
emissions standard using Equation 16-2 of this subpart.
[GRAPHIC] [TIFF OMITTED] TP29AU12.016

Where:

E = 4-operating hour rolling average SO2 measured
emissions rate or emissions standard for stationary combustion
turbines other than combined cycle combustion turbines and CHP
combustion turbines (lb/MMBtu or ng/J),
    Ei = Hourly average SO2 emissions rate or
emissions standard for non out-of-control operating hour ``i'' (lb/
MMBtu or ng/J), and
    Qi = Total heat input to stationary combustion
turbine for non out-of-control operating hour ``i'' (MMBtu or J as
appropriate).

[GRAPHIC] [TIFF OMITTED] TP29AU12.017

Where:

E = 4-operating hour rolling average SO2 measured
emissions rate for stationary combustion turbines other than
combined cycle combustion turbines and CHP combustion turbines (lb/
MWh or ng/J),
Ei = Hourly average SO2 emissions rate for non
out-of-control operating hour ``i'' (lb/MMBtu or ng/J),
Qi = Total heat input to stationary combustion turbine
for non out-of-control operating hour ``i'' (MMBtu or J as
appropriate), and
Pi = Total gross energy output from stationary combustion
turbine for non out-of-control operating hour ``i'' (MWh or J).
[GRAPHIC] [TIFF OMITTED] TP29AU12.018

Where:

E = 4-operating hour rolling average SO2 emissions
standard for stationary combustion turbines other than combined
cycle combustion turbines and CHP combustion turbines (lb/MWh or ng/
J),
Ei = Hourly SO2 emissions standard for non
out-of-control operating hour ``i'' (lb/MMBtu or ng/J), and
Pi = Total gross energy output from stationary combustion
turbine for non out-of-control operating hour ``i'' (MWh or J).

    (ii) For combined cycle combustion turbines and CHP combustion
turbines, you must determine excess emissions on a 30 operating-day
rolling average basis. The excess emissions level is the heat input
weighted-average of the SO2 emissions measured by the CEMS
for a given operating day and the 29 operating days immediately
preceding that day. Once each day, calculate a new 30-operating day
average measured emissions rate using all hourly average values based
on non out-of-control SO2 emission data for all operating
hours during the previous 30-operating day operating period. Report any
30-operating day periods for which you have less than 75 percent data
availability as monitor downtime. If you elect to comply with the
applicable heat input-based emissions standard, calculate the measured
emissions rate and emissions rate using Equation 17 of this subpart. If
you elect to comply with the applicable output-based standard,
calculate the measured emissions rate using Equation 18-1 of this
subpart and calculate the emissions standard using Equation 18-2 of
this subpart.
[GRAPHIC] [TIFF OMITTED] TP29AU12.019

Where:

E = 30-operating day rolling average SO2 measured
emissions rate or emissions standard for combined cycle combustion
turbines and CHP combustion turbines (lb/MMBtu or ng/J),
Ei = Hourly average SO2 emissions rate or
emissions standard for non out-of-control operating hour ``i'' (lb/
MMBtu or ng/J),
Qi = Total heat input to stationary combustion turbine
for non out-of-control operating hour ``i'' (MMBtu or J as
appropriate), and
n = Total number of non out-of-control operating hours in the 30
operating-day period.
[GRAPHIC] [TIFF OMITTED] TP29AU12.020

Where:

E = 30-operating day average SO2 measured emissions rate
for combined cycle combustion turbines and CHP combustion turbines
(lb/MWh or ng/J),
Ei = Hourly average SO2 measured emissions
rate for non out-of-control operating hour ``i'' (lb/MMBtu or ng/J),
Qi = Total heat input to stationary combustion turbine
for non out-of-control operating hour ``i'' (MMBtu or J as
appropriate),
Pi = Total gross energy output from stationary combustion
turbine for non out-of-control operating hour ``i'' (MWh or J), and
n = Total number of non out-of-control operating hours in the 30
operating-day period.
[GRAPHIC] [TIFF OMITTED] TP29AU12.021

Where:

E = 30-operating day average SO2 emissions standard for
combined cycle combustion turbines and CHP combustion turbines (lb/
MWh or ng/J),
Ei = Hourly SO2 emissions standard for non
out-of-control operating hour ``i'' (lb/MWh or ng/J),
Pi = Total gross energy output from stationary combustion
turbine for non out-of-control operating hour ``i'' (MWh or J), and
n = Total number of non out-of-control operating hours in the 30
operating-day period.

Recordkeeping and Reporting

Sec.  60.4375  What reports must I submit?

    (a) An owner or operator of a stationary combustion turbine that
elects to continuously monitor parameters or emissions, or to
periodically determine the fuel sulfur content under this subpart, must
submit reports of excess emissions and monitor downtime, according to
Sec.  60.7(c). Excess emissions must be reported for all periods of
unit operation, including startup, shutdown, and malfunction.
    (b) An owner or operator of a stationary combustion turbine that
performs performance tests to demonstrate compliance with this subpart
must submit a written report of the results of each performance test
before the close of business on the 60th day following the completion
of the performance test, except as specified in paragraph (c) of this
part.
    (c)(1) Within 60 days after the date of completing each performance
test (see Sec.  60.8) as required by this subpart you must submit the
results of the performance tests required by this subpart to EPA's
WebFIRE database by using the Compliance and Emissions Data Reporting
Interface (CEDRI) that is accessed through EPA's Central Data Exchange
(CDX) (www.epa.gov/cdx). Performance test data must be submitted in the
file format generated through use of EPA's Electronic Reporting Tool
(ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data
collected using test methods on the ERT Web site are subject to this
requirement for submitting reports electronically to WebFIRE. Owners or
operators who claim that some of the information being submitted for
performance tests is confidential business information (CBI) must
submit a complete ERT file including information claimed to be CBI on a
compact disk or other commonly used electronic storage media
(including, but not limited to, flash drives) to EPA. The electronic
media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE
CBI Office, Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page
Rd., Durham, NC 27703. The same ERT file with the CBI omitted must be
submitted to EPA via CDX as described earlier in this paragraph. At the
discretion of the delegated authority, you must also submit these
reports, including the confidential business information, to the
delegated authority in the format specified by the delegated authority.
    (2) Within 60 days after the date of completing each CEMS
performance evaluation test (see Sec.  60.13), you must submit the
relative accuracy test audit data electronically into EPA's Central
Data Exchange by using the Electronic Reporting Tool as mentioned in
paragraph (c)(1) of this section. Only data collected using test
methods compatible with ERT are subject to this requirement to be
submitted electronically to EPA's CDX.
    (3) All reports required by this subpart not subject to the
requirements in paragraphs (c)(1) and (2) of this section must be sent
to the Administrator or delegated authority at the appropriate address
listed in Sec.  63.13. The Administrator or delegated authority may
request a report in any form suitable for the specific case (e.g., by
commonly used electronic media such as Excel spreadsheet, on CD or hard
copy). The Administrator or delegated authority retains the right to
require submittal of reports subject to paragraphs (c)(1) and (2) of
this section in paper format.
    (d) The notification requirements of Sec.  60.8 apply to the
initial and subsequent performance tests.
    (e) An owner or operator of an affected facility complying with
Sec.  60.4333(b)(3) must notify the delegated permitting authority
within 15 calendar days after the facility recommences operation.
    (f) An owner or operator of an affected facility complying with
Sec.  60.4333(b)(4) must notify the delegated permitting authority
within 15 calendar days after the facility has operated more than 50
operating hours since the date the previous performance test was
required to be conducted.

Sec.  60.4380  How are NOX excess emissions and monitor
downtime reported?

    (a) For reports required under Sec.  60.4375(a), periods of excess
emissions and monitor downtime for stationary combustion turbines using
water or steam to fuel ratio monitoring are reported as specified in
paragraphs (a)(1) through (3) of this section.
    (1) An excess emission that must be reported is any operating hour
for which the 4-operating hour rolling average steam or water to fuel
ratio, as measured by the continuous monitoring system, is less than
the acceptable steam or water to fuel ratio needed to demonstrate
compliance with Sec.  60.4320, as established during the most recent
performance test. Any operating hour during which no water or steam is
injected into the turbine when the specific conditions require water or
steam injection for NOX control will also be considered an
excess emission.
    (2) A period of monitor downtime that must be reported is any
operating hour in which water or steam is injected into the turbine,
but the parametric data needed to determine the steam or water to fuel
ratio are unavailable or out-of-control.
    (3) Each report must include the average steam or water to fuel
ratio,

average fuel consumption, and the stationary combustion turbine load
during each excess emission.
    (b) For reports required under Sec.  60.4375(a), periods of excess
emissions and monitor downtime for stationary combustion turbines using
a CEMS, excess emissions are reported as specified in paragraphs (b)(1)
through (3) of this section.
    (1) An excess emission that must be reported is any unit operating
period in which the 4-operating hour or 30-operating day rolling
average NOX emissions rate exceeds the applicable emissions
standard in Sec.  60.4320 as determined in Sec.  60.4350.
    (2) A period of monitor downtime that must be reported is any
operating hour in which the data for any of the following parameters
are either missing or out-of-control: NOX concentration,
CO2 or O2 concentration, stack flow rate, heat
input rate, steam flow rate, steam temperature, steam pressure, or
megawatts. You are only required to monitor parameters used for
compliance purposes.
    (3) For hours with multiple emission standards, the applicable
standard for that hour is determined based on the condition, excluding
periods of monitor downtime, that corresponded to the highest emissions
standard.
    (c) For reports required under Sec.  60.4375(a), periods of excess
emissions and monitor downtime for stationary combustion turbines using
combustion parameters or parameters that document proper operation of
the NOX emission controls excess emissions and monitor
downtime are reported as specified in paragraphs (c)(1) and (2) of this
section.
    (1) Excess emissions that must be reported are each 4-operating
hour rolling average in which any monitored parameter (as averaged over
the 4 operating-hour period) does not achieve the target value or is
outside the acceptable range defined in the parameter monitoring plan
for the unit.
    (2) Periods of monitor downtime that must be reported are each
operating hour in which any of the required parametric data are either
not recorded or are out-of-control.

Sec.  60.4385  How are SO2 excess emissions and monitor
downtime reported?

    (a) If you choose the option to monitor the sulfur content of the
fuel, excess emissions and monitor downtime are defined as follows:
    (1) For samples obtained using daily sampling, flow proportional
sampling, or sampling from the unit's storage tank, excess emissions
occur each operating hour included in the period beginning on the date
and hour of any sample for which the sulfur content of the fuel being
fired in the stationary combustion turbine exceeds the applicable
standard and ending on the date and hour that a subsequent sample is
taken that demonstrates compliance with the sulfur standard.
    (2) If the option to sample each delivery of fuel oil has been
selected, you must immediately switch to one of the other oil sampling
options (i.e., daily sampling, flow proportional sampling, or sampling
from the unit's storage tank) if the sulfur content of a delivery
exceeds 0.05 weight percent, 0.15 weight percent, or 0.40 weight
percent as applicable. You must continue to use one of the other
sampling options until all of the oil from the delivery has been
combusted, and you must evaluate excess emissions according to
paragraph (a) of this section. When all of the fuel from the delivery
has been combusted, you may resume using the as-delivered sampling
option.
    (3) A period of monitor downtime begins when a required sample is
not taken by its due date. A period of monitor downtime also begins on
the date and hour of a required sample, if invalid results are
obtained. The period of monitor downtime ends on the date and hour of
the next valid sample.
    (b) If you choose the option to maintain records of the fuel sulfur
content, excess emissions are defined as any period during which you
burn a fuel that you do not have appropriate fuel records or that fuel
contains sulfur greater than the applicable standard.
    (c) For reports required under Sec.  60.4375(a), periods of excess
emissions and monitor downtime for stationary combustion turbines using
a CEMS, excess emissions are reported as specified in paragraphs (c)(1)
through (2) of this section.
    (1) An excess emission that must be reported is any unit operating
period in which the 4-operating hour or 30-operating day rolling
average SO2 emissions rate exceeds the applicable emissions
standard in Sec.  60.4330 as determined in Sec.  60.4372.
    (2) A period of monitor downtime that must be reported is any
operating hour in which the data for any of the following parameters
are either missing or out-of-control: SO2 concentration,
CO2 or O2 concentration, stack flow rate, heat
input rate, steam flow rate, steam temperature, steam pressure, or
megawatts. You are only required to monitor parameters used for
compliance purposes.

Sec.  60.4390  What records must I maintain?

    (a) You must maintain records of your information used to
demonstrate compliance with this subpart as specified in Sec.  60.7.
    (b) An owner or operator of a stationary combustion turbine that
uses the other fuels, part-load, or low temperature NOX
standards in the compliance demonstration must maintain concurrent
records of the hourly heat input, percent load, ambient temperature,
and emissions data as applicable.
    (c) An owner or operator of a stationary combustion turbine that
uses the tuning NOX standard in the compliance demonstration
must identify the hours on which the maintenance was performed and a
description of the maintenance.
    (d) An owner or operator of a stationary combustion turbine that
demonstrates compliance using the output-based standard must maintain
concurrent records of the total gross energy output and emissions data.
    (e) An owner or operator of a stationary combustion turbine that
demonstrates compliance using the water or steam to fuel ratio or a
parameter continuous monitoring system must maintain continuous records
of the appropriate parameters.
    (f) An owner or operator of a stationary combustion turbine
complying with the fuel based SO2 standard must maintain
records of the results of all fuel analyses or a current, valid
purchase contract, tariff sheet, or transportation contract.

Sec.  60.4395  When must I submit my reports?

    Consistent with Sec.  60.7(c), all reports required under Sec.
60.7(c) must be postmarked by the 30th day following the end of each 6-
month period.

Performance Tests

Sec.  60.4400  How do I conduct performance tests to demonstrate
compliance with my NOX emissions standard if I do not have a
NOX CEMS?

    (a) You must conduct the performance test according to the
requirements in Sec.  60.8 and paragraphs (b) through (d) of this
section.
    (b) You must use the methods in either paragraph (b)(1) or (2) of
this section to measure the NOX concentration for each test
run.
    (1) Measure the NOX concentration using EPA Method 7E in
appendix A-4 of this part or EPA Method 20 in appendix A-7 of this
part. In addition, when only natural gas is being combusted ASTM D6522
(incorporated by reference, see Sec.  60.17) can be used instead of EPA
Method 20 in appendix

A-7 of this part to determine the oxygen content in the exhaust gas.
For units complying with the output-based standard, concurrently
measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix
A-1 of this part, and measure and record the electrical and thermal
output from the unit. Then, use Equation 19 of this subpart to
calculate the NOX emissions rate:
[GRAPHIC] [TIFF OMITTED] TP29AU12.022

Where:

E = NOX emissions rate, in lb/MWh,
1.194 x 10-7 = Conversion constant, in lb/dscf-ppm,
(NOX)c = Average NOX concentration
for the run, in ppm,
Qstd = Average stack gas volumetric flow rate, in dscf/h,
and
P = Average gross electrical and mechanical energy output of the
stationary combustion turbine, in MW (for simple-cycle operation),
for combined-cycle operation, the sum of all electrical and
mechanical output from the combustion and steam turbines, or, for
CHP operation, the sum of all electrical and mechanical output from
the combustion and steam turbines plus all useful recovered thermal
output not used for additional electric or mechanical generation or
to enhance the performance of the stationary combustion turbine, in
MW, calculated according to Sec.  60.4350.

    (2) Measure the NOX and diluent gas concentrations,
using either EPA Method 7E in appendix A-4 of this part and EPA Method
3A in appendix A-2 of this part, or EPA Method 20 in appendix A-7 of
this part. In addition, when only natural gas is being combusted ASTM
D6522 (incorporated by reference, see Sec.  60.17) can be used instead
of EPA Method 3A in appendix A-2 of this part or EPA Method 20 in
appendix A-7 of this part to determine the oxygen content in the
exhaust gas. Concurrently measure the heat input to the unit, using a
fuel flowmeter (or flowmeters), an O2 or CO2 CEMS
along with a stack flow meter, or the methodologies in appendix F to
part 75 of this chapter, and for units complying with the output-based
standard measure the electrical, mechanical, and thermal output of the
unit. Use EPA Method 19 in appendix A-7 of this part to calculate the
NOX emissions rate in lb/MMBtu. Then, use Equations 1 and,
if necessary, 2 and 3 of this subpart in Sec.  60.4350(f) to calculate
the NOX emissions rate in lb/MWh.
    (c) You must use the methods in either paragraph (c)(1) or (2) of
this section to select the sampling traverse points for NOX
and (if applicable) diluent gas.
    (1) You must select the sampling traverse points for NOX
and (if applicable) diluent gas according to EPA Method 20 in appendix
A-7 of this part or EPA Method 1 in appendix A-1 of this part (non-
particulate procedures), and sampled for equal time intervals. The
sampling must be performed with a traversing single-hole probe, or, if
feasible, with a stationary multi-hole probe that samples each of the
points sequentially. Alternatively, a multi-hole probe designed and
documented to sample equal volumes from each hole may be used to sample
simultaneously at the required points.
    (2) As an alternative to paragraph (c)(1) of this section, you may
select the sampling traverse points for NOX and (if
applicable) diluent gas according to requirements in paragraphs
(c)(2)(i) and (ii) of this section.
    (i) You perform a stratification test for NOX and
diluent pursuant to the procedures specified in section <IP_ADDRESS>(a)
through (e) in appendix A of part 75 of this chapter.
    (ii) Once the stratification sampling is completed, you use the
following alternative sample point selection criteria for the
performance test specified in paragraphs (c)(2)(ii)(A) through (
    (A) If each of the individual traverse point NOX
concentrations is within 10 percent of the mean
concentration for all traverse points, or the individual traverse point
diluent concentrations differs by no more than 0.5 percent
CO2 (or O2) from the mean for all traverse
points, then you may use three points (located either 16.7, 50.0 and
83.3 percent of the way across the stack or duct, or, for circular
stacks or ducts greater than 2.4 meters (7.8 feet) in diameter, at 0.4,
1.2, and 2.0 meters from the wall). The three points must be located
along the measurement line that exhibited the highest average
NOX concentration during the stratification test; or
    (B) For a stationary combustion turbine subject to a NOX
emissions standard greater than 15 ppm at 15 percent O2, you
may sample at a single point, located at least 1 meter from the stack
wall or at the stack centroid if each of the individual traverse point
NOX concentrations is within 5 percent of the
mean concentration for all traverse points, or the individual traverse
point diluent concentrations differs by no more than 0.3
percent CO2 (or O2) from the mean for all
traverse points; or
    (C) For a stationary combustion turbine subject to a NOX
emissions standard less than or equal to 15 ppm at 15 percent
O2, you may sample at a single point, located at least 1
meter from the stack wall or at the stack centroid if each of the
individual traverse point NOX concentrations is within
2.5 percent of the mean concentration for all traverse
points, or the individual traverse point diluent concentrations differs
by no more than 0.15 percent CO2 (or
O2) from the mean for all traverse points.
    (d) The performance test must be done at any load condition within
plus or minus 25 percent of 100 percent of the base load rating. You
may perform testing at the highest achievable load point, if at least
75 percent of the base load rating cannot be achieved in practice. You
must conduct three separate test runs for each performance test. The
minimum time per run is 60 minutes.
    (1) If the stationary combustion turbine combusts both natural gas
and fuels other than natural gas as primary or backup fuels, separate
performance testing is required for each fuel.
    (2) For a combined cycle or CHP combustion turbine with
supplemental heat (duct burner), you must measure the total
NOX emissions downstream of the duct burner. The duct burner
must be in operation during the performance test.
    (3) If water or steam injection is used to control NOX
with no additional post-combustion NOX control and you
choose to monitor the steam or water to fuel ratio in accordance with
Sec.  60.4335, then that monitoring system must be operated
concurrently with each EPA Method 20 in appendix A-7 of this part or
EPA Method 7E in appendix A-4 of this part run and must be used to
determine the fuel consumption and the steam or water to fuel ratio
necessary to comply with the applicable Sec.  60.4320 NOX
emissions standard.
    (4) If you elect to install a CEMS, the performance evaluation of
the CEMS may either be conducted separately or

(as described in Sec.  60.4405) as part of the initial performance test
of the affected unit.
    (5) The ambient temperature must be greater than 0 [deg]F during
the performance test. The delegated permitting authority may approve
performance testing below 0 [deg]F if the timing of the required
performance test and environmental conditions make it impractical to
test at ambient conditions greater than 0 [deg]F.

Sec.  60.4405  How do I conduct a performance test if I use a
NOX CEMS?

    (a) If you use a CEMS the performance test must be performed
according to the procedures specified in paragraph (b) of this section.
    (b) The initial performance test must use the procedure specified
in paragraphs (b)(1) through (4) of this section.
    (1) Perform a minimum of nine RATA reference method runs, with a
minimum time per run of 21 minutes, at a single load level, within plus
or minus 25 percent of 100 percent of the base load rating. You may
perform testing at the highest achievable load point, if at least 75
percent of the base load rating cannot be achieved in practice. The
ambient temperature must be greater than 0[emsp14][deg]F during the
RATA runs. The delegated permitting authority may approve performance
testing below 0 [deg]F if the timing of the required performance test
and environmental conditions make it impractical to test at ambient
conditions greater than 0 [deg]F.
    (2) For each RATA run, concurrently measure the heat input to the
unit using a fuel flow meter (or flow meters) or the methodologies in
appendix F to part 75 of this chapter, and for units complying with the
output-based standard, measure the electrical and thermal output from
the unit.
    (3) Use the test data both to demonstrate compliance with the
applicable NOX emissions standard under Sec.  60.4320 and to
provide the required reference method data for the RATA of the CEMS
described under Sec.  60.4342.
    (4) Compliance with the applicable emissions standard in Sec.
60.4320 is achieved if the sum of the NOX emissions divided
by the heat input (or gross energy output) for all the RATA runs,
expressed in units of lb/MMBtu or lb/MWh, does not exceed the emissions
standard.

Sec.  60.4415  How do I conduct performance tests to demonstrate
compliance with my SO2 emissions standard?

    (a) An owner or operator of an affected facility complying with the
fuel based standard must submit fuel records (such as a current, valid
purchase contract, tariff sheet, transportation contract, or results of
a fuel analysis) to satisfy the requirements of Sec.  60.8.
    (b) An owner or operator of an affected facility complying with the
SO2 emissions standard must conduct the performance test by
measuring the SO2 emissions in the stationary combustion
turbine exhaust gases using the methods in either paragraph (b)(1) or
(2) of this section.
    (1) Measure the SO2 concentration using EPA Methods 6,
6C, 8 in appendix A-4 of this part, or EPA Method 20 in appendix A-7 of
this part. In addition, the American Society of Mechanical Engineers
(ASME) standard, ASME PTC 19-10-1981-Part 10, ``Flue and Exhaust Gas
Analyses,'' manual methods for sulfur dioxide (incorporated by
reference, see Sec.  60.17) can be used instead of EPA Method 6 in
appendix A-4 of this part or EPA Method 20 in appendix A-7 of this
part. For units complying with the output based standard, concurrently
measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix
A-1 of this part, and measure and record the electrical and thermal
output from the unit. Then use Equation 20 of this subpart to calculate
the SO2 emissions rate:
[GRAPHIC] [TIFF OMITTED] TP29AU12.023

Where:

E = SO2 emissions rate, in lb/MWh,
1.664 x 10-7 = Conversion constant, in lb/dscf-ppm,
(SO2)c = Average SO2 concentration
for the run, in ppm,
Qstd = Average stack gas volumetric flow rate, in dscf/h,
and
P = Average gross electrical and mechanical energy output of the
stationary combustion turbine, in MW (for simple-cycle operation),
for combined-cycle operation, the sum of all electrical and
mechanical output from the combustion and steam turbines, or, for
CHP operation, the sum of all electrical and mechanical output from
the combustion and steam turbines plus all useful recovered thermal
output not used for additional electric or mechanical generation or
to enhance the performance of the stationary combustion turbine, in
MW, calculated according to Sec.  60.4350(f)(2).

    (2) Measure the SO2 and diluent gas concentrations,
using either EPA Methods 6, 6C, or 8 in appendix A-4 of this part and
EPA Method 3A in appendix A-2 of this part, or EPA Method 20 in
appendix A-7 of this part. In addition, you may use the manual methods
for sulfur dioxide ASME PTC 19-10-1981-Part 10 (incorporated by
reference, see Sec.  60.17). Concurrently measure the heat input to the
unit, using a fuel flowmeter (or flowmeters), an O2 or
CO2 CEMS along with a stack flow meter, or the methodologies
in appendix F to part 75 of this chapter, and for units complying with
the output based standard measure the electrical and thermal output of
the unit. Use EPA Method 19 in appendix A-7 of this part to calculate
the SO2 emissions rate in lb/MMBtu. Then, use Equations 11
and, if necessary, 12 and 13 of this subpart in Sec.  60.4372 to
calculate the SO2 emissions rate in lb/MWh.

Definitions

Sec.  60.4420  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein will have the
meaning given them in the Clean Air Act and in subpart A (General
Provisions) of this part.
    Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which
are independently and objectively evaluated in a judicial or
administrative proceeding.
    Base load rating means 100 percent of the manufacturer's design
heat input capacity of the combustion turbine engine at ISO conditions
using the higher heating value of the fuel.
    Biogas means gas produced by the anaerobic digestion or
fermentation of organic matter including manure, sewage sludge,
municipal solid waste, biodegradable waste, or any other biodegradable
feedstock, under anaerobic conditions. Biogas is comprised primarily of
methane and CO2.
    Byproduct means any liquid or gaseous substance produced at
chemical manufacturing plants, petroleum refineries, or pulp and paper
mills (except natural gas and fuel oil) and combusted in a stationary
combustion

turbine. Gaseous substances with CO2 levels greater than 50
percent or carbon monoxide levels greater than 10 percent are not
byproduct.
    Combined cycle combustion turbine means any stationary combustion
turbine which recovers heat from the combustion turbine engine exhaust
gases to generate steam that is used exclusively to create additional
power output in a steam turbine.
    Combined heat and power (CHP) combustion turbine means any
stationary combustion turbine which recovers heat from the combustion
turbine engine exhaust gases to heat water or another medium, generate
steam for useful purposes other than exclusively for additional
electric generation, or directly uses the heat in the exhaust gases for
a useful purpose.
    Combustion turbine engine means the air compressor, combustor, and
turbine sections of a stationary combustion turbine.
    Combustion turbine test cell/stand means any apparatus used for
testing uninstalled stationary or uninstalled mobile (motive)
combustion turbines.
    Distillate oil means fuel oil that complies with the specifications
for fuel oil numbers 1 or 2, as defined by the American Society for
Testing and Materials in ASTM D396 (incorporated by reference, see
Sec.  60.17), diesel fuel oil numbers 1 or 2, as defined by the
American Society for Testing and Materials in ASTM D975 (incorporated
by reference, see Sec.  60.17), kerosine, as defined by the American
Society of Testing and Materials in ASTM D3699 (incorporated by
reference, see Sec.  60.17), biodiesel as defined by the American
Society of Testing and Materials in ASTM D6751 (incorporated by
reference, see Sec.  60.17), or biodiesel blends as defined by the
American Society of Testing and Materials in ASTM D7467 (incorporated
by reference, see Sec.  60.17).
    Dry standard cubic foot (dscf) means the quantity of gas, free of
uncombined water, that would occupy a volume of 1 cubic foot at 293
Kelvin (20.0 [deg]C) and 101.325 kPa of pressure.
    Duct burner means a device that combusts fuel and that is placed in
the exhaust duct from another source, such as a stationary combustion
turbine, internal combustion engine, kiln, etc., to allow the firing of
additional fuel to heat the exhaust gases.
    Emergency combustion turbine means any stationary combustion
turbine which operates in an emergency situation. Examples include
stationary combustion turbines used to produce power for critical
networks or equipment, including power supplied to portions of a
facility, when electric power from the local utility is interrupted, or
stationary combustion turbines used to pump water in the case of fire
or flood, etc. Emergency stationary combustion turbines do not include
stationary combustion turbines used as peaking units at electric
utilities or stationary combustion turbines at industrial facilities
that typically operate at low capacity factors. Emergency combustion
turbines may be operated for maintenance checks and readiness testing
to retain their status as emergency combustion turbines, provided that
the tests are required by the manufacturer, the vendor, or the
insurance company associated with the turbine. Required testing of such
units should be minimized, but there is no time limit on the use of
emergency combustion turbines.
    Excess emissions means a specified averaging period over which
either (1) the NOX or SO2 emissions rate are
higher than the applicable emissions standard in Sec.  60.4320 or Sec.
60.4330; (2) the total sulfur content of the fuel being combusted in
the affected facility or the SO2 emissions exceeds the
standard specified in Sec.  60.4330; or (3) the recorded value of a
particular monitored parameter, including ration of water or steam to
fuel, is outside the acceptable range specified in the parameter
monitoring plan for the affected unit.
    Federally enforceable means all limitations and conditions that are
enforceable by the Administrator or delegated authority, 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.
    Fuel oil means a fluid mixture of hydrocarbons that maintains a
liquid state at ISO conditions. Additionally, fuel oil must meet the
definition of either distillate oil or residual oil as defined by the
American Society for Testing and Materials in ASTM D396 (incorporated
by reference, see Sec.  60.17) or diesel fuel as defined by the
American Society for Testing and Materials in ASTM D975 (incorporated
by reference, see Sec.  60.17).
    Gross useful energy output means:
    (1) For simple cycle and combined cycle combustion turbines, the
gross useful work performed is the gross electrical or direct
mechanical output from both the combustion turbine engine and any
associated steam turbine(s).
    (2) For a CHP combustion turbine, the gross useful work performed
is the gross electrical or direct mechanical output from both the
combustion turbine engine and any associated steam turbine(s) plus any
useful thermal output measured relative to ISO conditions that is not
used to generate additional electrical or mechanical output or to
enhance the performance of the unit (i.e., steam delivered to an
industrial process).
    (3) For a CHP combustion turbine where at least 20.0 percent of the
total gross useful energy output consists of electric or direct
mechanical output and 20.0 percent of the total gross useful energy
output consists of useful thermal output on an annual basis, the gross
useful work performed is the gross electrical or direct mechanical
output from both the combustion turbine engine and any associated steam
turbine(s) divided by 0.95 plus any useful thermal output measured
relative to ISO conditions that is not used to generate additional
electrical or mechanical output or to enhance the performance of the
unit (i.e., steam delivered to an industrial process).
    Heat recovery steam generating unit (HRSG) means a unit where the
hot exhaust gases from the combustion turbine engine are routed in
order to extract heat from the gases and generate useful output. Heat
recovery steam generating units can be used with or without duct
burners.
    Integrated gasification combined cycle electric utility steam
generating unit (IGCC) means an electric utility steam generating unit
that burns solid-derived fuels in a combined-cycle combustion turbine.
No solid fuel is directly combusted in the unit during operation.
    ISO conditions means 288 Kelvin (15 [deg]C), 60 percent relative
humidity and 101.325 kilopascals (kPa) pressure.
    Lean premix stationary combustion turbine means any stationary
combustion turbine where the air and fuel are thoroughly mixed to form
a lean mixture before delivery to the combustor. Mixing may occur
before or in the combustion chamber. A lean premixed turbine may
operate in diffusion flame mode during operating conditions such as
startup and shutdown, extreme ambient temperature, or low or transient
load.
    Low-Btu gas means biogas or any gas with a heating value of less
than 26 megajoules per standard cubic meter (MJ/scm) (700 Btu/scf).
    Natural gas means a fluid mixture of hydrocarbons, composed of at
least 70 percent methane by volume or that has a gross calorific value
between 35 and 41 MJ/scm (950 and 1,100 Btu/scf), that maintains a
gaseous state under ISO conditions. In addition, natural gas

contains 460 mg/scm (20.0 gr/100 scf) or less of total sulfur. Finally,
natural gas does not include any gaseous fuel produced in a process
which might result in highly variable heating value.
    Noncontinental area means Guam, American Samoa, the Northern
Mariana Islands, or offshore platforms.
    Offshore turbine means a stationary combustion turbine located on a
platform in an ocean.
    Operating day means a 24-hour period between 12 midnight and the
following midnight during which any fuel is combusted at any time in
the unit. It is not necessary for fuel to be combusted continuously for
the entire 24-hour period.
    Operating hour means a clock hour during which any fuel is
combusted in the affected unit. If the unit combusts fuel for the
entire clock hour, it is considered to be a full operating hour. If the
unit combusts fuel for only part of the clock hour, it is considered to
be a partial operating hour.
    Out-of-control period means any period beginning with the quadrant
corresponding to the completion of a daily calibration error, linearity
check, or quality assurance audit that indicates that the instrument is
not measuring and recording within the applicable performance
specifications and ending with the quadrant corresponding to the
completion of an additional calibration error, linearity check, or
quality assurance audit following corrective action that demonstrates
that the instrument is measuring and recording within the applicable
performance specifications.
    Simple cycle combustion turbine means any stationary combustion
turbine which does not recover heat from the combustion turbine engine
exhaust gases for purposes other than enhancing the performance of the
stationary combustion turbine itself.
    Solid fuel means any fuel that has a definite shape and volume, has
no tendency to flow or disperse under moderate stress, and is not
liquid or gaseous at ISO conditions. This includes, but is not limited
to, coal, biomass, and pulverized solid fuels.
    Stationary combustion turbine means all equipment, including but
not limited to the combustion turbine engine, the fuel, air,
lubrication and exhaust gas systems, control systems, heat recovery
system, steam turbine, fuel compressor, heater, and/or pump, post-
combustion emission control technology, and any ancillary components
and sub-components. Stationary means that the combustion turbine is not
self propelled or intended to be propelled while performing its
function. It may, however, be mounted on a vehicle for portability.
    Standard cubic foot (scf) means the quantity of gas that would
occupy a volume of 1 cubic foot at 293 Kelvin (20.0 [deg]C) and 101.325
kPa of pressure.
    Standard cubic meter (scm) means the quantity of gas that would
occupy a volume of 1 cubic meter at 293 Kelvin (20.0 [deg]C) and
101.325 kPa of pressure.
    Turbine tuning means planned maintenance of a lean premix
combustion turbine engine involving adjustment of the operating
configuration to maintain proper combustion dynamics. Turbine tuning is
limited to 30 hours annually.
    Useful thermal output means the thermal energy made available for
processes and applications other than electrical or mechanical
generation or to enhance the performance of the stationary combustion
turbine (i.e., the thermal energy made available for use in any
industrial or commercial process or used in any heating application).
Useful thermal output for this subpart is measured relative to the
enthalpy of the thermal output in its most prevalent form at ISO
conditions (e.g., liquid water).

    Table 1 to Subpart KKKK of Part 60--Nitrogen Oxide Emission Standards for Stationary Combustion Turbines
                               [All numerical values have two significant figures]
----------------------------------------------------------------------------------------------------------------
                                                                                Alternate NOX
                                         Combustion turbine heat                                     emissions
        Combustion turbine type         input at base load rating      NOX emissions standard       standard in
                                                  (HHV)                                              ppm at 15
                                                                                percent O2
----------------------------------------------------------------------------------------------------------------
New turbine firing natural gas,         <= 15 MW (50 MMBtu/h)....  67 ng/J (0.16 lb/MMBtu) heat               42
 electric generating.                                               input or 290 ng/J of gross
                                                                    energy output (2.3 lb/MWh).
New turbine firing natural gas,         <= 15 MW (50 MMBtu/h)....  160 ng/J (0.37 lb/MMBtu) heat             100
 mechanical drive.                                                  input or 690 ng/J of gross
                                                                    energy output (5.5 lb/MWh).
New turbine firing natural gas........  > 15 MW (50 MMBtu/h) and   40 ng/J (0.093 lb/MMBtu) heat              25
                                         <= 250 MW (850 MMBtu/h).   input or 150 ng/J of gross
                                                                    energy output (1.2 lb/MWh).
New, modified, or reconstructed         > 250 MW (850 MMBtuh)....  24 ng/J (0.056 lb/MMBtu) heat              15
 turbine firing natural gas.                                        input or 54 ng/J of gross
                                                                    energy output (0.43 lb/MWh).
New turbine firing fuels other than     <= 15 MW (50 MMBtu/h)....  160 ng/J (0.38 lb/MMBtu) heat              96
 natural gas, electric generating.                                  input or 710 ng/J of gross
                                                                    energy output (5.6 lb/MWh).
New turbine firing fuels other than     <= 15 MW (50 MMBtu/h)....  250 ng/J (0.59 lb/MMBtu) heat             150
 natural gas, mechanical drive.                                     input or 1,100 ng/J of gross
                                                                    energy output (8.7 lb/MWh).
New turbine firing fuels other than     > 15 MW (50 MMBtu/h) and   120 ng/J (0.29 lb/MMBtu) heat              74
 natural gas.                            <= 250 MW (850 MMBtu/h).   input or 470 ng/J of gross
                                                                    energy output (3.7 lb/MWh).
New, modified, or reconstructed         > 250 MW (850 MMBtu/h)...  73 ng/J (0.17 lb/MMBtu) heat               42
 turbine firing fuels other than                                    input or 160 ng/J of gross
 natural gas.                                                       energy output (1.3 lb/MWh).
Modified or reconstructed turbine.....  <= 15 MW (50 MMBtu/h)....  250 ng/J (0.59 lb/MMBtu) heat             150
                                                                    input or 1,100 ng/J of gross
                                                                    energy output (8.7 lb/MWh).
Modified or reconstructed turbine       > 15 MW (50 MMBtu/h) and   67 ng/J (0.16 lb/MMBtu) heat               42
 firing natural gas.                     <= 250 MW (850 MMBtu/h).   input or 250 ng/J of gross
                                                                    energy output (2.0 lb/MWh).
Modified or reconstructed turbine       > 15 MW (50 MMBtu/h) and   160 ng/J (0.38 lb/MMBtu) heat              96
 firing fuels other than natural gas.    <= 250 MW (850 MMBtu/h).   input or 600 ng/J of gross
                                                                    energy output (4.8 lb/MWh).

Turbines located north of the Arctic    <= 100 MW (340 MMBtu/h)..  250 ng/J (0.59 lb/MMBtu) heat             150
 Circle (latitude 66.5 degrees north),                              input or 1,100 ng/J of gross
 turbines operating at less than 75                                 energy output (8.7 lb/MWh).
 percent of the base load rating,
 turbines operated during periods of
 turbine tuning, startup, or shutdown,
 modified and reconstructed offshore
 turbines, or turbines operating at
 temperatures less than minus 17
 [deg]C.
Turbines located north of the Arctic    > 100 MW (340 MMBtu/h)...  160 ng/J (0.38 lb/MMBtu) heat              96
 Circle (latitude 66.5 degrees north),                              input or 610 ng/J of gross
 turbines operating at less than 75                                 energy output (4.8 lb/MWh).
 percent of the base load rating,
 turbines operated during periods of
 turbine tuning, startup, or shutdown,
 modified and reconstructed offshore
 turbines, or turbines operating at
 temperatures less than minus 17
 [deg]C.
Heat recovery units operating           All sizes................  86 ng/J (0.20 lb/MMBtu) heat               50
 independent of the combustion turbine                              input or 110 ng/J of gross
 engine.                                                            energy output (0.90 lb/MWh).
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2012-20524 Filed 8-28-12; 8:45 am]
BILLING CODE 6560-50-P


[Federal Register Volume 77, Number 172 (Wednesday, September 5, 2012)]
[Notices]
[Page 54626]
[FR Doc No: 2012-21910]

-----------------------------------------------------------------------

SECURITIES AND EXCHANGE COMMISSION

Sunshine Act Meeting

    Notice is hereby given, pursuant to the provisions of the
Government in the Sunshine Act, Public Law 94-409, that the Securities
and Exchange Commission will hold a Closed Meeting on Thursday,
September 6, 2012 at 2 p.m.
    Commissioners, Counsel to the Commissioners, the Secretary to the
Commission, and recording secretaries will attend the Closed Meeting.
Certain staff members who have an interest in the matters also may be
present.
    The General Counsel of the Commission, or his designee, has
certified that, in his opinion, one or more of the exemptions set forth
in 5 U.S.C. 552b(c)(3), (5), (7), 9(B) and (10) and 17 CFR
200.402(a)(3), (5), (7), 9(ii) and (10), permit consideration of the
scheduled matters at the Closed Meeting.
    Commissioner Walter, as duty officer, voted to consider the items
listed for the Closed Meeting in a closed session.
    The subject matter of the Closed Meeting scheduled for Thursday,
September 6, 2012 will be:

    Institution and settlement of injunctive actions;
    Institution and settlement of administrative proceedings; and
    Other matters relating to enforcement proceedings.

    At times, changes in Commission priorities require alterations in
the scheduling of meeting items.
    For further information and to ascertain what, if any, matters have
been added, deleted or postponed, please contact:
    The Office of the Secretary at<PHONE_NUMBER>.

    Dated: August 30, 2012.
Elizabeth M. Murphy,
Secretary.
[FR Doc. 2012-21910 Filed 8-31-12; 11:15 am]
BILLING CODE 8011-01-P