(ii) Install CEMS and sorbent trap monitoring systems described in
this section in the common stack and attribute all of the emissions
measured at the common stack to the affected unit(s).
    (4) Unit with a Main Stack and a Bypass Stack. If the exhaust
configuration of an affected unit consists of a main stack and a bypass
stack, the owner and operator shall install CEMS and the monitoring
systems described in paragraph 2.1 of this section on both the main
stack and the bypass stack.
    (5) Unit with Multiple Stack or Duct Configuration. If the flue
gases from an affected unit either: are discharged to the atmosphere
through more than one stack; or are fed into a single stack through two
or more ducts and the owner or operator chooses to monitor in the ducts
rather than in the stack, the owner or operator shall either:
    (i) Install CEMS and sorbent trap monitoring systems described in
this section in each of the multiple stacks; or
    (ii) Install CEMS and sorbent trap monitoring systems described in
this section in each of the ducts that feed into the stack.
    (b) If you use an oxygen (O2) or carbon dioxide
(CO2) continuous emissions monitoring system (CEMS),
install, operate, and maintain a CEMS for oxygen or carbon dioxide
according to the procedures in paragraphs (b)(1) through (5) of this
section by the compliance date specified in Sec.  63.9984. The oxygen
or carbon dioxide shall be monitored at the same location as the other
pollutant CEMS, i.e., at the outlet of the EGU. Alternatively, an owner
or operator may install, certify, maintain, operate and quality assure
the data from an O2 or CO2 CEMS according to
Appendix A of this subpart in lieu of the procedures in paragraphs
(a)(1) through (a)(3) of this section.
    (1) Install, operate, and maintain the O2 or
CO2 CEMS according to the applicable procedures under
Performance Specification (PS) 3 of 40 CFR part 60, Appendix B; and
according to the applicable procedures under Quality Assurance
Procedure 1 of 40 CFR part 60, Appendix F; and according to the site-
specific monitoring plan developed according to Sec.  63.10000(d).
    (2) Conduct a performance evaluation of the CEMS according to the
requirements in Sec.  63.8 and according to PS 3 of 40 CFR part 60,
Appendix B.
    (3) Design and operate the CEMS to complete a minimum of one cycle
of operation (sampling, analyzing, and data recording) for each
successive 15-minute period.
    (4) Reduce the CEMS data as specified in Sec.  63.8(g)(2) and (4).
    (5) Consistent with Sec.  63.10020, calculate and record a 30
boiler operating day rolling average emissions rate on a daily basis.
Daily, calculate a new 30 boiler operating day rolling average
emissions rate as the average of all of the hourly oxygen emissions
data for the preceding 30 boiler operating days.
    (c) If you use an HCl CEMS, install, operate, and maintain a CEMS
for HCl according to the procedures in paragraphs (c)(1) through (5) of
this section by the compliance date specified in Sec.  63.9984. The HCl
shall be monitored at the outlet of the EGU.
    (1) Install, operate, and maintain the CEMS according to the
applicable procedures under Performance Specification (PS) 15 or 6 of
40 CFR part 60, Appendix B; and according to the applicable procedures
under Quality Assurance Procedure 1 of 40 CFR part 60, Appendix F; and
according to the site-specific monitoring plan developed according to
Sec.  63.10000(d).
    (2) Conduct a performance evaluation of the CEMS according to the
requirements in Sec.  63.8 and according to PS 15 or 6 of 40 CFR part
60, Appendix B.
    (3) Design and operate the CEMS to complete a minimum of one cycle
of operation (sampling, analyzing, and data recording) for each
successive 15-minute period.
    (4) Reduce the CEMS data as specified in Sec.  63.8(g)(2) and (4).
    (5) Consistent with Sec.  63.10020, calculate and record a 30
boiler operating day rolling average emissions rate on a daily basis.
Daily, calculate a new 30 boiler operating day rolling average
emissions rate as the average of all of the hourly HCl emissions data
for the preceding 30 boiler operating days.
    (d) If you use an HF CEMS, install, operate, and maintain a CEMS
for HF according to the procedures in paragraphs (d)(1) through (5) of
this section by the compliance date specified in Sec.  63.9984. The HF
shall be monitored at the outlet of the EGU.
    (1) Install, operate, and maintain the CEMS according to the
applicable procedures under Performance Specification (PS) 15 of 40 CFR
part 60, Appendix B; and according to the applicable procedures under
Quality Assurance Procedure 1 of 40 CFR part 60, Appendix F; and
according to the site-specific monitoring plan developed according to
Sec.  63.10000(d).
    (2) Conduct a performance evaluation of the CEMS according to the
requirements in Sec.  63.8 and according to PS 15 or 6 of 40 CFR part
60, Appendix B.
    (3) Design and operate the CEMS to complete a minimum of one cycle
of operation (sampling, analyzing, and data recording) for each
successive 15-minute period.
    (4) Reduce the CEMS data as specified in Sec.  63.8(g)(2) and (4).
    (5) Consistent with Sec.  63.10020, calculate and record a 30
boiler operating day rolling average emissions rate on a daily basis.
Daily, calculate a new 30 boiler operating day rolling average
emissions rate as the average of all of the hourly HF emissions data
for the preceding 30 boiler operating days.
    (e) If you use an SO2 CEMS, install, operate, and
maintain a CEMS for SO2 according to the procedures in
paragraphs (e)(1) through (5) of this section by the compliance date
specified in Sec.  63.9984. The SO2 shall be monitored at
the outlet of the EGU. Alternatively, for an affected source that is
also subject to the SO2 monitoring requirements of Part 75
of this chapter, the or operator may install, certify, maintain,
operate and quality assure the data from an SO2 CEMS
according to Part 75 of this chapter in lieu of the procedures in
paragraphs (g)(1) through (g)(3) of this section with the additional
provisions of paragraph (g)(6).
    (1) Install, operate, and maintain the CEMS according to the
applicable procedures under Performance Specification (PS) 2 of 40 CFR
part 60, Appendix B; and according to the applicable procedures under
Quality Assurance Procedure 1 of 40 CFR part 60, Appendix F; and
according to the site-specific monitoring plan developed according to
Sec.  63.10000(d).
    (2) Conduct a performance evaluation of the CEMS according to the

requirements in Sec.  63.8 and according to PS 2 or 6 of 40 CFR part
60, Appendix B.
    (3) Design and operate the CEMS to complete a minimum of one cycle
of operation (sampling, analyzing, and data recording) for each
successive 15-minute period.
    (4) Reduce the CEMS data as specified in Sec.  63.8(g)(2) and (4).
    (5) Consistent with Sec.  63.10020, calculate and record a 30
boiler operating day rolling average emissions rate on a daily basis.
Daily, calculate a new 30 boiler operating day rolling average
emissions rate is calculated as the average of all of the hourly
SO2 emissions data for the preceding 30 boiler operating
days.
    (6) When electing to use a Part 75 certified SO2 CEMS to
meet the requirements of this subpart, you must additionally meet the
provisions listed in paragraphs (6)(i) through (6)(iii) below.
    (i) You must perform the 7-day calibration error test required in
appendix A to Part 75 on the SO2 CEMS whether or not it has
a span of 50 ppm or less.
    (ii) You must perform the linearity check test required in appendix
A to Part 75 on the SO2 CEMS whether or not it has a span of
30 ppm or less.
    (iii) The initial and quarterly linearity checks required under
appendix A and appendix B of Part 75 must include a calibration gas (at
a fourth level, if necessary) nominally at a concentration level
equivalent to the applicable emission limit.
    (f) If you use a Hg CEMS or a sorbent trap monitoring system for
Hg, install, operate, and maintain the monitoring system in accordance
with Appendix A to this subpart.
    (g) If you use a PM CEMS, install, operate, and maintain a CEMS for
PM according to the procedures in paragraphs (g)(1) through (6) of this
section by the compliance date specified in Sec.  63.9984. The PM shall
be monitored at the outlet of the EGU.
    (1) Install, operate, and maintain according to the applicable
procedures under Performance Specification (PS) 11 of 40 CFR part 60,
Appendix B; and according to the applicable procedures under Quality
Assurance Procedure 2 of 40 CFR part 60, Appendix F; and according to
the site-specific monitoring plan developed according to Sec.
63.10000(d).
    (2) Conduct a performance evaluation of the CEMS according to the
requirements in Sec.  63.8 and according to PS 11 of 40 CFR part 60,
Appendix B.
    (3) Design and operate the CEMS to complete a minimum of one cycle
of operation (sampling, analyzing, and data recording) for each
successive 15-minute period.
    (4) Reduce the CEMS data as specified in Sec.  63.8(g)(2) and (4).
    (5) Consistent with Sec.  63.10020, calculate and record a 30
boiler operating-day rolling average emissions rate on a daily basis.
Daily, calculate a new 30 boiler operating day rolling average
emissions rate is calculated as the average of all of the hourly
particulate emissions data for the preceding 30 boiler operating days.
    (h) If you are required to install a continuous parameter
monitoring system (CPMS) as specified in Table 5 of this subpart, you
must install, operate, and maintain each CPMS according to the
requirements in paragraphs (h)(1) through (3) of this section by the
compliance date specified in Sec.  63.9984.
    (1) Install, operate, and maintain each CPMS according to the
procedures in your approved site-specific monitoring plan developed in
accordance with Sec.  63.10000(d) of this subpart and the design
criteria and quality assurance and quality control procedures specified
in paragraphs (h)(1) through (3) of this section. You may request
approval of monitoring system quality assurance and quality control
procedures alternative to those specified in paragraphs (h)(1) through
(3) of this section in your site-specific monitoring plan.
    (2) Design and operate the CPMS to collect and record data
measurements at least once every 15 minutes (see also Sec.  63.10020),
to reduce the measured values to a hourly averages or other appropriate
period (e.g., instantaneous alarms) for calculating operating values in
terms of the applicable averaging period, and to meet the specific CPMS
requirements given in (i) through (v) of this section.
    (i) If you have an operating limit that requires the use of a flow
monitoring system, you must meet the requirements in (i)(A) through (D)
of this section.
    (A) Install the flow sensor and other necessary equipment in a
position that provides a representative flow.
    (B) Use a flow sensor with a measurement sensitivity of no greater
than 2 percent of the expected flow rate.
    (C) Minimize the effects of swirling flow or abnormal velocity
distributions due to upstream and downstream disturbances.
    (D) Conduct a flow monitoring system performance evaluation in
accordance with your monitoring plan at the time of each performance
test but no less frequently than annually.
    (ii) If you have an operating limit that requires the use of a
pressure monitoring system, you must meet the requirements in (ii)(A)
through (F) of this section.
    (A) Install the pressure sensor(s) in a position that provides a
representative measurement of the pressure (e.g., PM scrubber pressure
drop).
    (B) Minimize or eliminate pulsating pressure, vibration, and
internal and external corrosion.
    (C) Use a pressure sensor with a minimum tolerance of 1.27
centimeters of water or a minimum tolerance of 1 percent of the
pressure monitoring system operating range, whichever is less.
    (D) Perform checks at least once each boiler operating day to
ensure pressure measurements are not obstructed (e.g., check for
pressure tap pluggage daily).
    (E) Conduct a performance evaluation of the pressure measurement
monitoring system in accordance with your monitoring plan at the time
of each performance test but no less frequently than annually.
    (F) If at any time the measured pressure exceeds the manufacturer's
specified maximum operating pressure range, conduct a performance
evaluation of the pressure monitoring system in accordance with your
monitoring plan and confirm that the pressure monitoring system
continues to meet the performance requirements in your monitoring plan.
Alternatively, install and verify the operation of a new pressure
sensor.
    (iii) If you have an operating limit that requires a total
secondary electric power monitoring system for an electrostatic
precipitator (ESP), you must meet the requirements in (iii)(A) through
(B) of this section.
    (A) Install sensors to measure (secondary) voltage and current to
the precipitator plates.
    (B) Conduct a performance evaluation of the electric power
monitoring system in accordance with your monitoring plan at the time
of each performance test but no less frequently than annually.
    (iv) If you have an operating limit that requires the use of a
monitoring system to measure sorbent injection rate (e.g., weigh belt,
weigh hopper, or hopper flow measurement device), you must meet the
requirements in (iv)(A) through (B) of this section.
    (A) Install each system in a position that provides a
representative measurement of the total sorbent injection rate.
    (B) Conduct a performance evaluation of the sorbent injection rate
monitoring system in accordance with your

monitoring plan at the time of each performance test but no less
frequently than annually.
    (v) If you have an operating limit that requires the use of a
fabric filter bag leak detection system to comply with the requirements
of this subpart, you must install, calibrate, maintain, and
continuously operate a bag leak detection system as specified in (v)(A)
through (F) of this section.
    (A) Install a bag leak detection sensor(s) in a position(s) that
will be representative of the relative or absolute PM loadings for each
exhaust stack, roof vent, or compartment (e.g., for a positive pressure
fabric filter) of the fabric filter.
    (B) Use a bag leak detection system certified by the manufacturer
to be capable of detecting PM emissions at concentrations of 10
milligrams per actual cubic meter or less.
    (C) Conduct a performance evaluation of the bag leak detection
system in accordance with your monitoring plan and consistent with the
guidance provided in EPA-454/R-98-015 (incorporated by reference, see
Sec.  63.14).
    (D) Use a bag leak detection system equipped with a device to
continuously record the output signal from the sensor.
    (E) Use a bag leak detection system equipped with a system that
will alert when an increase in relative PM emissions over a preset
level is detected. The alarm must be located where it can be detected
and recognized easily by an operator.
    (F) Where multiple bag leak detectors are required, the system's
instrumentation and alarm may be shared among detectors.
    (3) Conduct the CPMS equipment performance evaluations as specified
in your site-specific monitoring plan.

Sec.  63.10011  How do I demonstrate initial compliance with the
emission limits and work practice standards?

    (a) You must demonstrate initial compliance with each emission
limit that applies to you by conducting initial performance tests and
fuel analyses and establishing operating limits, as applicable,
according to Sec.  63.10007, paragraph (c) of this section, and Tables
5 and 7 to this subpart.
    (b) If you demonstrate compliance through performance testing, you
must establish each site-specific operating limit in Table 4 to this
subpart that applies to you according to the requirements in Sec.
63.10007, Table 7 to this subpart, and paragraph (c)(6) of this
section, as applicable. You must also conduct fuel analyses according
to Sec.  63.10008 and establish maximum fuel pollutant input levels
according to paragraphs (c)(1) through (5) of this section, as
applicable.
    (1) You must establish the maximum chlorine fuel input
(Cinput) during the initial performance testing according to
the procedures in paragraphs (c)(1)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could
burn in your EGU that has the highest content of chlorine.
    (ii) During the performance testing for HCl, you must determine the
fraction of the total heat input for each fuel type burned
(Qi) based on the fuel mixture that has the highest content
of chlorine, and the average chlorine concentration of each fuel type
burned (Ci).
    (iii) You must establish a maximum chlorine input level using
Equation 7 of this section.
[GRAPHIC] [TIFF OMITTED] TP03MY11.021

Where:

Clinput = Maximum amount of chlorine entering the EGU through fuels
burned in units of lb/MMBtu.
Ci = Arithmetic average concentration of chlorine in fuel type, i,
analyzed according to Sec.  63.10008, in units of lb/MMBtu.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest content of chlorine. If you do not
burn multiple fuel types during the performance testing, it is not
necessary to determine the value of this term. Insert a value of
``1'' for Qi.
n = Number of different fuel types burned in your EGU for the
mixture that has the highest content of chlorine.

    (2) You must establish the maximum Hg fuel input level
(Mercuryinput) during the initial performance testing using
the procedures in paragraphs (c)(3)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could
burn in your EGU that has the highest content of Hg.
    (ii) During the compliance demonstration for Hg, you must determine
the fraction of total heat input for each fuel burned (Qi)
based on the fuel mixture that has the highest content of Hg, and the
average Hg concentration of each fuel type burned (HGi).
    (iii) You must establish a maximum Hg input level using Equation 8
of this section.
[GRAPHIC] [TIFF OMITTED] TP03MY11.022

Where:

Mercuryinput = Maximum amount of Hg entering the EGU through fuels
burned in units of lb/TBtu.
HGi = Arithmetic average concentration of Hg in fuel type, i,
analyzed according to Sec.  63.10008, in units of lb/TBtu.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest Hg content. If you do not burn
multiple fuel types during the performance test, it is not necessary
to determine the value of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the
mixture that has the highest content of Hg.

    (3) You must establish the maximum non-Hg HAP metals fuel input
level (HAP metalinput) during the initial performance
testing using the procedures in paragraphs (c)(3)(i) through (iii) of
this section.
    (i) You must determine the fuel type or fuel mixture that you could
burn in your EGU that has the highest content of non-Hg HAP metals.
    (ii) During the compliance demonstration for non-Hg HAP metals, you
must determine the fraction of total heat input for each fuel burned
(Qi) based on the fuel mixture that has the highest content
of non-Hg HAP metals, and the average non-Hg HAP metals concentration
of each fuel type burned (HAP metali).
    (iii) You must establish a maximum non-Hg HAP metal input level
using Equation 9 of this section.
[GRAPHIC] [TIFF OMITTED] TP03MY11.023

Where:

HAP metalinput = Maximum amount of non-Hg HAP metals entering the
EGU through fuels burned in units of lb/MMBtu.
HAP metali = Arithmetic average concentration of non-Hg HAP metals
in fuel type, i, analyzed according to Sec.  63.10008, in units of
lb/MMBtu.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that

has the highest non-Hg HAP metal content. If you do not burn
multiple fuel types during the performance test, it is not necessary
to determine the value of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the
mixture that has the highest content of non-Hg HAP metals.

    (4) You must establish the maximum fluorine fuel input
(Finput) during the initial performance testing according to
the procedures in paragraphs (c)(1)(i) through (iii) of this section.
    (i) You must determine the fuel type or fuel mixture that you could
burn in your EGU that has the highest content of fluorine.
    (ii) During the performance testing for HF, you must determine the
fraction of the total heat input for each fuel type burned
(Qi) based on the fuel mixture that has the highest content
of fluorine, and the average fluorine concentration of each fuel type
burned (Fi).
    (iii) You must establish a maximum fluorine input level using
Equation 10 of this section.
[GRAPHIC] [TIFF OMITTED] TP03MY11.024

Where:

Fl input = Maximum amount of fluorine entering the EGU through fuels
burned in units of lb/MMBtu.
Fi = Arithmetic average concentration of fluorine in fuel type, i,
analyzed according to Sec.  63.10008, in units of lb/MMBtu.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest content of chlorine. If you do not
burn multiple fuel types during the performance testing, it is not
necessary to determine the value of this term. Insert a value of
``1'' for Qi.
n = Number of different fuel types burned in your EGU for the
mixture that has the highest content of fluorine.

    (6) You must establish parameter operating limits according to
paragraphs (c)(4)(i) through (v) of this section.
    (i) For a wet PM scrubber, you must establish the minimum liquid
flow rate and pressure drop as defined in Sec.  63.10042, as your
operating limits during the three-run performance test. If you use a
wet PM scrubber and you conduct separate performance tests for PM, non-
Hg HAP metals, or Hg emissions, you must establish one set of minimum
liquid flow rate and pressure drop operating limits. If you conduct
multiple performance tests, you must set the minimum liquid flow rate
and pressure drop operating limits at the highest minimum hourly
average values established during the performance tests.
    (ii) For a wet acid gas scrubber, you must establish the minimum
liquid flow rate and pH as defined in Sec.  63.10042, as your operating
limits during the three-run performance test. If you use a wet acid gas
scrubber and you conduct separate performance tests for HCl, HF, or
SO2 emissions, you must establish one set of minimum liquid
flow rate and pH operating limits. If you conduct multiple performance
tests, you must set the minimum liquid flow rate and pH operating
limits at the highest minimum hourly average values established during
the performance tests.
    (iii) For an electrostatic precipitator, you must establish the
minimum hourly average secondary voltage and secondary amperage and
calculate the total secondary power input as measured during the three-
run performance test and as defined in Sec.  63.10042, as your
operating limit.
    (iv) For a dry scrubber or dry sorbent injection (DSI) system, you
must establish the minimum hourly average sorbent injection rate for
each sorbent, as measured during the three-run performance test and as
defined in Sec.  63.10042, as your operating.
    (v) The operating limit for EGUs with fabric filters that choose to
demonstrate continuous compliance through bag leak detection systems is
that a bag leak detection system be installed according to the
requirements in Sec.  63.10010, and that the sum duration of bag leak
detection system alarms does not exceed 5 percent of the process
operating time during a 6-month period.
    (c) If you elect to demonstrate compliance with an applicable
emission limit through fuel analysis, you must conduct fuel analyses
according to Sec.  63.10008 and follow the procedures in paragraphs
(c)(1) through (7) of this section.
    (1) If you burn more than one fuel type, you must determine the
fuel mixture you could burn in your EGU that would result in the
maximum emission rates of the pollutants that you elect to demonstrate
compliance through fuel analysis.
    (2) You must determine the 90th percentile confidence level fuel
pollutant concentration of the composite samples analyzed for each fuel
type using the one-sided z-statistic test described in Equation 11 of
this section.
[GRAPHIC] [TIFF OMITTED] TP03MY11.025

Where:

P90 = 90th percentile confidence level pollutant concentration, in
lb/MMBtu (lb/TBtu for Hg).
mean = Arithmetic average of the fuel pollutant concentration in the
fuel samples analyzed according to Sec.  63.10008, in units of lb/
MMBtu (lb/TBtu for Hg).
SD = Standard deviation of the pollutant concentration in the fuel
samples analyzed according to Sec.  63.10008, in units of lb/MMBtu
(lb/TBtu for Hg).
t = t distribution critical value for 90th percentile (0.1)
probability for the appropriate degrees of freedom (number of
samples minus one) as obtained from a Distribution Critical Value
Table.

    (3) To demonstrate compliance with the applicable emission limit
for HCl, the HCl emission rate that you calculate for your EGU using
Equation 12 of this section must not exceed the applicable emission
limit for HCl.
[GRAPHIC] [TIFF OMITTED] TP03MY11.026

Where:

HCl = HCl emissions rate from the EGU in units of lb/MMBtu.
Ci90 = 90th percentile confidence level concentration of chlorine in
fuel type, i, in units of lb/MMBtu as calculated according to
Equation 12 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest content of chlorine. If you do not
burn multiple fuel types, it is not necessary to determine the value
of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the
mixture that has the highest content of chlorine.
1.028 = Molecular weight ratio of HCl to chlorine.

    \(4) To demonstrate compliance with the applicable emission limit
for Hg, the Hg emissions rate that you calculate for your EGU using
Equation 13 of this section must not exceed the applicable emission
limit for Hg.
[GRAPHIC] [TIFF OMITTED] TP03MY11.027

Where:

Mercury = Hg emissions rate from the EGU in units of lb/TBtu.
HGi90 = 90th percentile confidence level concentration of Hg in
fuel, i, in units of lb/TBtu as calculated according to Equation 8
of this section.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest Hg content. If you do not burn
multiple fuel types, it is not necessary to determine the value of
this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the
mixture that has the highest Hg content.

    (5) To demonstrate compliance with the applicable emission limit
for non-Hg HAP metals, the non-Hg HAP metal emissions rate that you
calculate for your EGU using Equation 14 of this

section must not exceed the applicable emissions limit for non-Hg HAP
metals.
[GRAPHIC] [TIFF OMITTED] TP03MY11.028

Where:

HAPmetals = Non-Hg HAP metals emission rate from the EGU in units of
lb/MMBtu.
HAPmetalsi90 = 90th percentile confidence level concentration of
non-Hg HAP metals in fuel, i, in units of lb/MMBtu as calculated
according to Equation 9 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest non-Hg HAP metals content. If you
do not burn multiple fuel types, it is not necessary to determine
the value of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the
mixture that has the highest non-Hg HAP metals content.

    (6) To demonstrate compliance with the applicable emission limit
for HF, the HF emissions rate that you calculate for your EGU using
Equation 15 of this section must not exceed the applicable emission
limit for HF.
[GRAPHIC] [TIFF OMITTED] TP03MY11.029

Where:

HF = HF emissions rate from the EGU in units of lb/MMBtu.
Fi90 = 90th percentile confidence level concentration of fluorine in
fuel type, i, in units of lb/MMBtu as calculated according to
Equation 7 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest content of fluorine. If you do not
burn multiple fuel types, it is not necessary to determine the value
of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your EGU for the
mixture that has the highest content of fluorine.
1.053 = Molecular weight ratio of HF to fluorine.

    (d) For units combusting coal or solid oil-derived fuel and
electing to use PM as a surrogate for non-Hg HAP metals, you must
install, certify, and operate PM CEMS in accordance with Performance
Specification (PS) 11 in Appendix B to 40 CFR part 60, and to perform
periodic, ongoing quality assurance (QA) testing of the CEMS according
to QA Procedure 2 in Appendix F to 40 CFR Part 60. You must determine
an operating limit (PM concentration in mg/dscm) during performance
testing for initial PM compliance. The operating limit will be the
average of the PM filterable results of the three Method 5 performance
test runs. To determine continuous compliance, the hourly average PM
concentrations will be averaged on a rolling 30 boiler operating day
basis. Each 30 boiler operating day average would have to meet the PM
operating limit.
    (e) You must submit the Notification of Compliance Status
containing the results of the initial compliance demonstration
according to the requirements in Sec.  63.10030(e).
    (f) If you are a LEE, the results of your initial performance test
demonstrate your initial compliance.

Continuous Compliance Requirements

Sec.  63.10020  How do I monitor and collect data to demonstrate
continuous compliance?

    (a) You must monitor and collect data according to this section and
the site-specific monitoring plan required by Sec.  63.10000(d).
    (b) You must operate the monitoring system and collect data at all
required intervals at all times that the affected EGU is operating,
except for periods of monitoring system malfunctions or out-of-control
periods (see Sec.  63.8(c)(7) of this part), and required monitoring
system quality assurance or quality control activities, including, as
applicable, calibration checks and required zero and span adjustments.
A monitoring system malfunction is any sudden, infrequent, not
reasonably preventable failure of the monitoring system to provide
valid data. Monitoring system failures that are caused in part by poor
maintenance or careless operation are not malfunctions. You are
required to affect monitoring system repairs in response to monitoring
system malfunctions and to return the monitoring system to operation as
expeditiously as practicable.
    (c) You may not use data recorded during monitoring system
malfunctions or out-of-control periods, repairs associated with
monitoring system malfunctions or out-of-control periods, or required
monitoring system quality assurance or control activities in
calculations used to report emissions or operating levels. You must use
all the data collected during all other periods in assessing the
operation of the control device and associated control system.
    (d) Except for periods of monitoring system malfunctions or out-of-
control periods, repairs associated with monitoring system malfunctions
or out-of-control periods, and required monitoring system quality
assurance or quality control activities including, as applicable,
calibration checks and required zero and span adjustments), failure to
collect required data is a deviation of the monitoring requirements.

Sec.  63.10021  How do I demonstrate continuous compliance with the
emission limitations and work practice standards?

    (a) You must demonstrate continuous compliance with each emission
limit, operating limit, and work practice standard in Tables 1 through
4 to this subpart that applies to you according to the methods
specified in Table 8 to this subpart and paragraphs (a)(1) through (17)
of this section.
    (1) Following the date on which the initial performance test is
completed or is required to be completed under Sec. Sec.  63.7 and
63.10005, whichever date comes first, you must not operate above any of
the applicable maximum operating limits or below any of the applicable
minimum operating limits listed in Table 4 to this subpart at any time.
Operation above the established maximum or below the established
minimum operating limits shall constitute a deviation of established
operating limits. Operating limits must be confirmed or reestablished
during performance tests.
    (2) As specified in Sec.  63.10031(c), you must keep records of the
type and amount of all fuels burned in each EGU during the reporting
period to demonstrate that all fuel types and mixtures of fuels burned
would either result in lower emissions of HCl, HF, SO2, non-
Hg HAP metals, or Hg, than the applicable emission limit for each
pollutant (if you demonstrate compliance through fuel analysis), or
result in lower fuel input of chlorine, fluorine, sulfur, non-Hg HAP
metals, or Hg than the maximum values calculated during the last
performance tests (if you demonstrate compliance through performance
stack testing).

    (3) If you demonstrate compliance with an applicable HCl emissions
limit through fuel analysis and you plan to burn a new type of fuel,
you must recalculate the HCl emissions rate using Equation 15 of Sec.
63.10011 according to paragraphs (a)(3)(i) through (iii) of this
section.
    (i) You must determine the chlorine concentration for any new fuel
type in units of lb/MMBtu, based on supplier data or your own fuel
analysis, according to the provisions in your site-specific fuel
analysis plan developed according to Sec.  63.10008(b).
    (ii) You must determine the new mixture of fuels that will have the
highest content of chlorine.
    (iii) Recalculate the HCl emissions rate from your EGU under these
new conditions using Equation 15 of Sec.  63.10011. The recalculated
HCl emissions rate must be less than the applicable emission limit.
    (4) If you demonstrate compliance with an applicable HCl emissions
limit through performance testing and you plan to burn a new type of
fuel or a new mixture of fuels, you must recalculate the maximum
chlorine input using Equation 7 of Sec.  63.10011. If the results of
recalculating the maximum chlorine input using Equation 7 of Sec.
63.10011 are higher than the maximum chlorine input level established
during the previous performance test, then you must conduct a new
performance test within 60 days of burning the new fuel type or fuel
mixture according to the procedures in Sec.  63.10007 to demonstrate
that the HCl emissions do not exceed the emissions limit. You must also
establish new operating limits based on this performance test according
to the procedures in Sec.  63.10011(b).
    (5) If you are a liquid oil-fired EGU and demonstrate compliance
with an applicable individual Hg emissions limit (rather than the total
HAP metal emission limit) through fuel analysis, and you plan to burn a
new type of fuel, you must recalculate the Hg emissions rate using
Equation 11 of Sec.  63.10011 according to the procedures specified in
paragraphs (a)(5)(i) through (iii) of this section.
    (i) You must determine the Hg concentration for any new fuel type
in units of lb/TBtu, based on supplier data or your own fuel analysis,
according to the provisions in your site-specific fuel analysis plan
developed according to Sec.  63.10008(b).
    (ii) You must determine the new mixture of fuels that will have the
highest content of Hg.
    (iii) Recalculate the Hg emissions rate from your EGU under these
new conditions using Equation 11 of Sec.  63.10011. The recalculated Hg
emission rate must be less than the applicable emission limit.
    (6) If you demonstrate compliance with an applicable Hg emissions
limit through performance testing, and you plan to burn a new type of
fuel or a new mixture of fuels, you must recalculate the maximum Hg
input using Equation 8 of Sec.  63.10011. If the results of
recalculating the maximum Hg input using Equation 8 of Sec.  63.10011
are higher than the maximum Hg input level established during the
previous performance test, then you must conduct a new performance test
within 60 days of burning the new fuel type or fuel mixture according
to the procedures in Sec.  63.10007 to demonstrate that the Hg
emissions do not exceed the emissions limit. You must also establish
new operating limits based on this performance test according to the
procedures in Sec.  63.10011(b).
    (7) If you are a liquid oil-fired EGU and demonstrate compliance
with an applicable HAP metals emission limit through fuel analysis, and
you plan to burn a new type of fuel, you must recalculate the HAP
metals emission rate using Equation 14 of Sec.  63.10011 according to
the procedures specified in paragraphs (a)(7)(i) through (iii) of this
section.
    (i) You must determine the HAP metals concentration for any new
fuel type in units of lb/MMBtu, based on supplier data or your own fuel
analysis, according to the provisions in your site-specific fuel
analysis plan developed according to Sec.  63.10008(b).
    (ii) You must determine the new mixture of fuels that will have the
highest content of HAP metals.
    (iii) Recalculate the HAP metals emission rate from your EGU under
these new conditions using Equation 14 of Sec.  63.10011. The
recalculated HAP metals emission rate must be less than the applicable
emissions limit.
    (8) If you demonstrate compliance with an applicable HAP metals
emissions limit through performance testing, and you plan to burn a new
type of fuel or a new mixture of fuels, you must recalculate the
maximum HAP metals input using Equation 9 of Sec.  63.10011. If the
results of recalculating the maximum Hg input using Equation 9 of Sec.
63.10011 are higher than the maximum HAP metals input level established
during the previous performance test, then you must conduct a new
performance test within 60 days of burning the new fuel type or fuel
mixture according to the procedures in Sec.  63.10007 to demonstrate
that the HAP metal emissions do not exceed the emissions limit. You
must also establish new operating limits based on this performance test
according to the procedures in Sec.  63.10011(b).
    (9) If your unit is controlled with a fabric filter, and you
demonstrate continuous compliance using a bag leak detection system,
you must initiate corrective action within 1 hour of a bag leak
detection system alarm and complete corrective actions as soon as
practical, and operate and maintain the fabric filter system such that
the sum duration of alarms does not exceed 5 percent of the process
operating time during a 6-month period. You must also keep records of
the date, time, and duration of each alarm, the time corrective action
was initiated and completed, and a brief description of the cause of
the alarm and the corrective action taken. You must also record the
percent of the operating time during each 6-month period that the alarm
sounds. In calculating this operating time percentage, if inspection of
the fabric filter demonstrates that no corrective action is required,
no alarm time is counted. If corrective action is required, each alarm
shall be counted as a minimum of 1 hour. If you take longer than 1 hour
to initiate corrective action, the alarm time shall be counted as the
actual amount of time taken to initiate corrective action.
    (10) If you are required to install a CEMS according to Sec.
63.10010(a), then you must meet the requirements in paragraphs
(a)(10)(i) through (iii) of this section.
    (i) You must continuously monitor oxygen according to Sec. Sec.
63.10010(a) and 63.10020.
    (ii) Keep records of oxygen levels according to Sec.  63.10032(b).
    (11) The owner or operator of an affected source using a CEMS
measuring PM emissions to meet requirements of this subpart shall
install, certify, operate, and maintain the CEMS as specified in
paragraphs (a)(11)(i) through (iv) of this section.
    (i) The owner or operator shall conduct a performance evaluation of
the CEMS according to the applicable requirements of Sec.  60.13 of 40
CFR, Performance Specification 11 in Appendix B of 40 CFR part 60, and
procedure 2 in Appendix F of 40 CFR part 60.
    (ii) During each PM correlation testing run of the CEMS required by
Performance Specification 11 in Appendix B of 40 CFR part 60, PM and
O2 (or CO2) data shall be collected concurrently
(or within a 30- to 60-minute period) by both the CEMS and conducting
performance tests using

Method 5 or 5D of Appendix A-3 of 40 CFR part 60.
    (iii) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 2 in Appendix F
of this chapter. Relative Response Audits must be performed annually
and Response Correlation Audits must be performed every 3 years.
    (iv) As of January 1, 2012 and within 60 days after the date of
completing each performance test, as defined in Sec.  63.2 and as
required in this subpart, you must submit performance test data, except
opacity data, electronically to EPA's Central Data Exchange (CDX) by
using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert_tool.html/). Only data collected using test methods
compatible with ERT are subject to this requirement to be submitted
electronically into EPA's WebFIRE database.
    (v) Within 60 days after the date of completing each CEMS
performance evaluation test, as defined in Sec.  63.2 and required by
this subpart, 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 (11)(iv) of this section. Only
data collected using test methods compatible with ERT are subject to
this requirement to be submitted electronically into EPA's WebFIRE
database.
    (vi) All reports required by this subpart not subject to the
requirements in paragraphs (11)(iv) and (v) of this section must be
sent to the Administrator at the appropriate address listed in Sec.
63.13. If acceptable to both the Administrator and the owner or
operator of a source, these reports may be submitted on electronic
media. The Administrator retains the right to require submittal of
reports subject to paragraph (11)(iv) and (v) of this section in paper
format.
    (12) The owner or operator of an affected source using a CEMS
measuring HCl emissions to meet requirements of this subpart shall
install, certify, operate, and maintain the CEMS as specified in
paragraphs (a)(12)(i) through (iii) of this section.
    (i) The owner or operator shall conduct a performance evaluation of
the CEMS according to the applicable requirements of Sec.  60.13 of 40
CFR, Performance Specifications 6 or 15 in Appendix B of 40 CFR part
60, and procedure 2 in Appendix F of 40 CFR part 60.
    (ii) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 1 in Appendix F
of 40 CFR part 60.
    (13) The owner or operator of an affected source using a CEMS
measuring SO2 emissions to meet requirements of this subpart
shall install, certify, operate, and maintain the CEMS as specified in
paragraphs (a)(13)(i) through (iii) of this section.
    (i) The owner or operator shall conduct a performance evaluation of
the CEMS according to the applicable requirements of Sec.  60.13 of 40
CFR part 60, Performance Specification 2 or 6 in Appendix B of 40 CFR
part 60, and procedure 1 in Appendix F of 40 CFR part 60.
    (ii) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 1 in Appendix F
of 40 CFR part 60.
    (14) The owner or operator of an affected source using a CEMS
measuring Hg emissions to meet requirements of this subpart shall
install, certify, operate, and maintain the CEMS as specified in
paragraphs (a)(14)(i) through (iii) of this section.
    (i) The owner or operator shall conduct a performance evaluation of
the CEMS according to the applicable requirements of Appendix A of this
subpart.
    (ii) Quarterly accuracy determinations and daily calibration drift
tests shall be performed in accordance with procedure 5 in Appendix F
of 40 CFR part 60.
    (15) As an alternative to measuring Hg emissions using Hg CEMS, the
owner or operator of an affected source using a sorbent trap monitoring
system to meet requirements of this subpart shall install, certify,
operate, and maintain the sorbent trap monitoring system in accordance
with Appendix A to this subpart.
    (16) You must conduct a performance tune-up of the EGU to
demonstrate continuous compliance as specified in paragraphs (a)(16)(i)
through (a)(16)(vii) of this section.
    (i) As applicable, inspect the burner, and clean or replace any
components of the burner as necessary (you may delay the burner
inspection until the next scheduled unit shutdown, but you must inspect
each burner at least once every 18 months);
    (ii) Inspect the flame pattern, as applicable, and make any
adjustments to the burner necessary to optimize the flame pattern. The
adjustment should be consistent with the manufacturer's specifications,
if available;
    (iii) Inspect the system controlling the air-to-fuel ratio, as
applicable, and ensure that it is correctly calibrated and functioning
properly;
    (iv) Optimize total emissions of CO and NOX. This
optimization should be consistent with the manufacturer's
specifications, if available;
    (v) Measure the concentration in the effluent stream of CO and
NOX in ppm, by volume, and oxygen in volume percent, before
and after the adjustments are made (measurements may be either on a dry
or wet basis, as long as it is the same basis before and after the
adjustments are made); and
    (vi) Maintain on-site and submit, if requested by the
Administrator, an annual report containing the information in
paragraphs (a)(16)(vi)(A) through (C) of this section,
    (A) The concentrations of CO and NOX in the effluent
stream in ppm by volume, and oxygen in volume percent, measured before
and after the adjustments of the EGU;
    (B) A description of any corrective actions taken as a part of the
combustion adjustment; and
    (C) The type and amount of fuel used over the 12 months prior to an
adjustment, but only if the unit was physically and legally capable of
using more than one type of fuel during that period.
    (vii) After December 31, 2011, and within 60 days after the date of
completing each performance tune-up conducted to demonstrate compliance
with this subpart, you must submit a notice of completion of the
performance tune-up to EPA by successfully submitting the data
electronically into an EPA database.
    (17) For LEEs, the results of your initial and subsequent emissions
tests, along with records of your fuel analyses, demonstrate your
continuous compliance and continued eligibility as a LEE.
    (i) As of January 1, 2012 and within 60 days after the date of
completing each performance test, as defined in Sec.  63.2 and as
required in this subpart, you must submit performance test data, except
opacity data, electronically to EPA's Central Data Exchange (CDX) by
using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert_tool.html/). Only data collected using test methods
compatible with ERT are subject to this requirement to be submitted
electronically into EPA's WebFIRE database.
    (ii) Within 60 days after the date of completing each CEMS
performance evaluation test, as defined in 63.2 and required by this
subpart, 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 (17)(i) of this section. Only
data collected using test methods compatible with ERT are subject to
this requirement to be submitted electronically into EPA's WebFIRE
database.
    (iii) All reports required by this subpart not subject to the
requirements in paragraphs (17)(i) and (ii) of this section must be
sent to the Administrator at the appropriate address listed in Sec.
63.13. If acceptable to both the Administrator and the owner or
operator of a source, these reports may be submitted on electronic
media. The Administrator retains the right to require submittal of
reports subject to paragraph (17)(i) and (ii) of this section in paper
format.
    (b) You must report each instance in which you did not meet each
emission limit and operating limit in Tables 1 through 4 to this
subpart that apply to you. These instances are deviations from the
emission limits in this subpart. These deviations must be reported
according to the requirements in Sec.  63.10031.
    (c) Consistent with Sec.  63.10010, Sec.  63.10020, and your site-
specific monitoring plan, you must determine the 3-hour rolling average
of the CPMS data collected for all periods the process is operating.

Sec.  63.10022  How do I demonstrate continuous compliance under the
emission averaging provision?

    (a) Following the compliance date, the owner or operator must
demonstrate compliance with this subpart on a continuous basis by
meeting the requirements of paragraphs (a)(1) through (8) of this
section.
    (1) For each calendar month, demonstrate compliance with the
average weighted emissions limit for the existing units participating
in the emissions averaging option as determined in Sec.  63.10009(f)
and (g);
    (2) For each existing unit participating in the emissions averaging
option that is equipped with a wet scrubber for PM control, maintain
the 3-hour average parameter values at or below the operating limits
established during the most recent performance test;
    (3) For each existing unit participating in the emissions averaging
option that is equipped with a fabric filter but without PM CEMS,
maintain the 3-hour average parameter values at or below the operating
limits established during the most recent performance test;
    (4) For each existing unit participating in the emissions averaging
option that is equipped with dry sorbent injection, maintain the 3-hour
average parameter values at or below the operating limits established
during the most recent performance test;
    (5) For each existing unit participating in the emissions averaging
option that is equipped with an ESP, maintain the 3-hour average
parameter values at or below the operating limits established during
the most recent performance test;
    (6) For each existing unit participating in the emissions averaging
option that is equipped with an ESP, maintain the monthly fuel content
values at or below the operating limits established during the most
recent performance test;
    (7) For each existing unit participating in the emissions averaging
option that has an approved alternative operating plan, maintain the 3-
hour average parameter values at or below the operating limits
established in the most recent performance test.
    (8) For each existing unit participating in the emissions averaging
option venting to a common stack configuration containing affected
units from other subcategories, maintain the appropriate operating
limit for each unit as specified in Table 4 to this subpart that
applies.
    (b) Any instance where the owner or operator fails to comply with
the continuous monitoring requirements in paragraphs (a)(1) through (8)
of this section is a deviation.

Notification, Reports, and Records

Sec.  63.10030  What notifications must I submit and when?

    (a) You must submit all of the notifications in Sec. Sec.  63.7(b)
and (c), 63.8(e), (f)(4) and (6), and 63.9(b) through (h) that apply to
you by the dates specified.
    (b) As specified in Sec.  63.9(b)(2), if you startup your affected
source before [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER], you must submit an Initial Notification not later
than 120 days after [DATE 60 DAYS AFTER PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER].
    (c) As specified in Sec.  63.9(b)(4) and (b)(5), if you startup
your new or reconstructed affected source on or after [DATE 60 DAYS
AFTER PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], you must
submit an Initial Notification not later than 15 days after the actual
date of startup of the affected source.
    (d) If you are required to conduct a performance test you must
submit a Notification of Intent to conduct a performance test at least
30 days before the performance test is scheduled to begin.
    (e) If you are required to conduct an initial compliance
demonstration as specified in Sec.  63.10011(a), you must submit a
Notification of Compliance Status according to Sec.  63.9(h)(2)(ii).
For each initial compliance demonstration, you must submit the
Notification of Compliance Status, including all performance test
results and fuel analyses, before the close of business on the 60th day
following the completion of the performance test and/or other initial
compliance demonstrations according to Sec.  63.10(d)(2). The
Notification of Compliance Status report must contain all the
information specified in paragraphs (e)(1) through (6), as applicable.
    (1) A description of the affected source(s) including
identification of which subcategory the source is in, the design
capacity of the source, a description of the add-on controls used on
the source, description of the fuel(s) burned, including whether the
fuel(s) were determined by you or EPA through a petition process to be
a non-waste under 40 CFR 241.3, whether the fuel(s) were processed from
discarded non-hazardous secondary materials within the meaning of 40
CFR 241.3, and justification for the selection of fuel(s) burned during
the performance test.
    (2) Summary of the results of all performance tests and fuel
analyses and calculations conducted to demonstrate initial compliance
including all established operating limits.
    (3) Identification of whether you plan to demonstrate compliance
with each applicable emission limit through performance testing and
fuel analysis; performance testing with operational limits (e.g., CEMS
for surrogates or CPMS); CEMS; or sorbent trap monitoring system.
    (4) Identification of whether you plan to demonstrate compliance by
emissions averaging.
    (5) A signed certification that you have met all applicable
emission limits and work practice standards.
    (6) If you had a deviation from any emission limit, work practice
standard, or operating limit, you must also submit a description of the
deviation, the duration of the deviation, and the corrective action
taken in the Notification of Compliance Status report.
    (7) In addition to the information required in Sec.  63.9(h)(2),
your notification of compliance status must include the following
certification of compliance and must be signed by a responsible
official:
    (i) ``This EGU complies with the requirement in Sec.
63.10021(a)(16)(i) through (vi).''

Sec.  63.10031  What reports must I submit and when?

    (a) You must submit each report in Table 9 to this subpart that
applies to you.
    (b) Unless the EPA Administrator has approved a different schedule
for submission of reports under Sec.  63.10(a), you must submit each
report by the date in Table 9 to this subpart and according to the
requirements in paragraphs (b)(1) through (5) of this section.
    (1) The first compliance report must cover the period beginning on
the compliance date that is specified for your affected source in Sec.
63.9984 and ending on June 30 or December 31, whichever date is the
first date that occurs at least 180 days after the compliance date that
is specified for your source in Sec.  63.9984.
    (2) The first compliance report must be postmarked or delivered no
later than July 31 or January 31, whichever date is the first date
following the end of the first calendar half after the compliance date
that is specified for your source in Sec.  63.9984.
    (3) Each subsequent compliance report must cover the semiannual
reporting period from January 1 through June 30 or the semiannual
reporting period from July 1 through December 31.
    (4) Each subsequent compliance report must be postmarked or
delivered no later than July 31 or January 31, whichever date is the
first date following the end of the semiannual reporting period.
    (5) For each affected source that is subject to permitting
regulations pursuant to 40 CFR part 70 or 40 CFR part 71, and if the
permitting authority has established dates for submitting semiannual
reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance
reports according to the dates the permitting authority has established
instead of according to the dates in paragraphs (b)(1) through (4) of
this section.
    (c) The compliance report must contain the information required in
paragraphs (c)(1) through (9) of this section.
    (1) Company name and address.
    (2) Statement by a responsible official with that official's name,
title, and signature, certifying the truth, accuracy, and completeness
of the content of the report.
    (3) Date of report and beginning and ending dates of the reporting
period.
    (4) The total fuel use by each affected source subject to an
emission limit, for each calendar month within the semiannual reporting
period, including, but not limited to, a description of the fuel,
whether the fuel has received a non-waste determination by EPA or your
basis for concluding that the fuel is not a waste, and the total fuel
usage amount with units of measure.
    (5) A summary of the results of the annual performance tests and
documentation of any operating limits that were reestablished during
this test, if applicable. If you are conducting stack tests once every
three years consistent with Sec.  63.10006(o) or (p), the date of the
last three stack tests, a comparison of the emission level you achieved
in the last three stack tests to the 50 percent emission limit
threshold required in Sec.  63.10006(o) or (p), and a statement as to
whether there have been any operational changes since the last stack
test that could increase emissions.
    (6) A signed statement indicating that you burned no new types of
fuel. Or, if you did burn a new type of fuel, you must submit the
calculation of chlorine input, using Equation 7 of Sec.  63.10011, that
demonstrates that your source is still within its maximum chlorine
input level established during the previous performance testing (for
sources that demonstrate compliance through performance testing) or you
must submit the calculation of HCl emission rate using Equation 15 of
Sec.  63.10011 that demonstrates that your source is still meeting the
emission limit for HCl emissions (for EGUs that demonstrate compliance
through fuel analysis). If you burned a new type of fuel, you must
submit the calculation of Hg input, using Equation 8 of Sec.  63.10011,
that demonstrates that your source is still within its maximum Hg input
level established during the previous performance testing (for sources
that demonstrate compliance through performance testing), or you must
submit the calculation of Hg emission rate using Equation 11 of Sec.
63.10011 that demonstrates that your source is still meeting the
emission limit for Hg emissions (for EGUs that demonstrate compliance
through fuel analysis).
    (7) If you wish to burn a new type of fuel and you cannot
demonstrate compliance with the maximum chlorine input operating limit
using Equation 7 of Sec.  63.10011 or the maximum Hg input operating
limit using Equation 8 of Sec.  63.10011, you must include in the
compliance report a statement indicating the intent to conduct a new
performance test within 60 days of starting to burn the new fuel.
    (8) If there are no deviations from any emission limits or
operating limits in this subpart that apply to you, a statement that
there were no deviations from the emission limits or operating limits
during the reporting period.
    (9) If there were no deviations from the monitoring requirements
including no periods during which the CMSs, including CEMS, and CPMS,
were out of control as specified in Sec.  63.8(c)(7), a statement that
there were no deviations and no periods during which the CMS were out
of control during the reporting period.
    (10) Include the date of the most recent tune-up for each unit
subject to the requirement to conduct a performance tune-up according
to Sec.  63.10021(a)(16)(i) through (vi). Include the date of the most
recent burner inspection if it was not done annually and was delayed
until the next scheduled unit shutdown.
    (d) For each deviation from an emission limit or operating limit in
this subpart that occurs at an affected source where you are not using
a CMS to comply with that emission limit or operating limit, the
compliance report must additionally contain the information required in
paragraphs (d)(1) through (4) of this section.
    (1) The total operating time of each affected source during the
reporting period.
    (2) A description of the deviation and which emission limit or
operating limit from which you deviated.
    (3) Information on the number, duration, and cause of deviations
(including unknown cause), as applicable, and the corrective action
taken.
    (4) A copy of the test report if the annual performance test showed
a deviation from the emission limits.
    (e) For each deviation from an emission limit, operating limit, and
monitoring requirement in this subpart occurring at an affected source
where you are using a CMS to comply with that emission limit or
operating limit, you must include the information required in
paragraphs (e)(1) through (12) of this section. This includes any
deviations from your site-specific monitoring plan as required in Sec.
63.10000(d).
    (1) The date and time that each deviation started and stopped and
description of the nature of the deviation (i.e., what you deviated
from).
    (2) The date and time that each CMS was inoperative, except for
zero (low-level) and high-level checks.
    (3) The date, time, and duration that each CMS was out of control,
including the information in Sec.  63.8(c)(8).
    (4) The date and time that each deviation started and stopped, and
whether each deviation occurred during

a period of startup, shutdown, or malfunction or during another period.
    (5) A summary of the total duration of the deviation during the
reporting period and the total duration as a percent of the total
source operating time during that reporting period.
    (6) An analysis of the total duration of the deviations during the
reporting period into those that are due to startup, shutdown, control
equipment problems, process problems, other known causes, and other
unknown causes.
    (7) A summary of the total duration of CMSs downtime during the
reporting period and the total duration of CMS downtime as a percent of
the total source operating time during that reporting period.
    (8) An identification of each parameter that was monitored at the
affected source for which there was a deviation.
    (9) A brief description of the source for which there was a
deviation.
    (10) A brief description of each CMS for which there was a
deviation.
    (11) The date of the latest CMS certification or audit for the
system for which there was a deviation.
    (12) A description of any changes in CMSs, processes, or controls
since the last reporting period for the source for which there was a
deviation.
    (f) Each affected source that has obtained a title V operating
permit pursuant to 40 CFR part 70 or 40 CFR part 71 must report all
deviations as defined in this subpart in the semiannual monitoring
report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR
71.6(a)(3)(iii)(A). If an affected source submits a compliance report
pursuant to Table 9 to this subpart along with, or as part of, the
semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or
40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all
required information concerning deviations from any emission limit,
operating limit, or work practice requirement in this subpart,
submission of the compliance report satisfies any obligation to report
the same deviations in the semiannual monitoring report. However,
submission of a compliance report does not otherwise affect any
obligation the affected source may have to report deviations from
permit requirements to the permit authority.
    (g) In addition to the information required in Sec.  63.9(h)(2),
your notification must include the following certification(s) of
compliance, as applicable, and signed by a responsible official:
    (1) ``This facility complies with the requirements in Sec.
63.10021(a)(10) to conduct an annual performance test of the unit''.
    (2) ``No secondary materials that are solid waste were combusted in
any affected unit.''
    (h)(1) As of January 1, 2012 and within 60 days after the date of
completing each performance test, as defined in Sec.  63.2 and as
required in this subpart, you must submit performance test data, except
opacity data, electronically to EPA's Central Data Exchange (CDX) by
using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert_tool.html/). Only data collected using test methods
compatible with ERT are subject to this requirement to be submitted
electronically into EPA's WebFIRE database.
    (2) Within 60 days after the date of completing each CEMS
performance evaluation test, as defined in 63.2 and required by this
subpart, 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 (h)(1) of this section. Only
data collected using test methods compatible with ERT are subject to
this requirement to be submitted electronically into EPA's WebFIRE
database.
    (3) All reports required by this subpart not subject to the
requirements in paragraphs (h)(1) and (2) of this section must be sent
to the Administrator at the appropriate address listed in Sec.  63.13.
If acceptable to both the Administrator and the owner or operator of a
source, these reports may be submitted on electronic media. The
Administrator retains the right to require submittal of reports subject
to paragraph (h)(1) and (2) of this section in paper format.
    (i) If you had a malfunction during the reporting period, the
report must include the number, duration, and a brief description for
each type of malfunction which occurred during the reporting period and
which caused or may have caused any applicable emission limitation to
be exceeded. The report must also include a description of actions
taken by an owner or operator during a malfunction of an affected
source to minimize emissions in accordance with Sec.  63.10000(b),
including actions taken to correct a malfunction.

Sec.  63.10032  What records must I keep?

    (a) You must keep records according to paragraphs (a)(1) through
(2) of this section.
    (1) A copy of each notification and report that you submitted to
comply with this subpart, including all documentation supporting any
Initial Notification or Notification of Compliance Status or semiannual
compliance report that you submitted, according to the requirements in
Sec.  63.10(b)(2)(xiv).
    (2) Records of performance stack tests, fuel analyses, or other
compliance demonstrations and performance evaluations, as required in
Sec.  63.10(b)(2)(viii).
    (b) For each CEMS and CPMS, you must keep records according to
paragraphs (b)(1) through (4) of this section.
    (1) Records described in Sec.  63.10(b)(2)(vi) through (xi).
    (2) Previous (i.e., superseded) versions of the performance
evaluation plan as required in Sec.  63.8(d)(3).
    (3) Request for alternatives to relative accuracy test for CEMS as
required in Sec.  63.8(f)(6)(i).
    (4) Records of the date and time that each deviation started and
stopped, and whether the deviation occurred during a period of startup,
shutdown, or malfunction or during another period.
    (c) You must keep the records required in Table 8 to this subpart
including records of all monitoring data and calculated averages for
applicable operating limits such as pressure drop and pH to show
continuous compliance with each emission limit and operating limit that
applies to you.
    (d) For each EGU subject to an emission limit, you must also keep
the records in paragraphs (d)(1) through (5) of this section.
    (1) You must keep records of monthly fuel use by each EGU,
including the type(s) of fuel and amount(s) used.
    (2) If you combust non-hazardous secondary materials that have been
determined not to be solid waste pursuant to 40 CFR 241.3(b)(1), you
must keep a record which documents how the secondary material meets
each of the legitimacy criteria. If you combust a fuel that has been
processed from a discarded non-hazardous secondary material pursuant to
40 CFR 241.3(b)(2), you must keep records as to how the operations that
produced the fuel satisfies the definition of processing in 40 CFR
241.2. If the fuel received a non-waste determination pursuant to the
petition process submitted under 40 CFR 241.3(c), you must keep a
record which documents how the fuel satisfies the requirements of the
petition process.
    (3) A copy of all calculations and supporting documentation of
maximum chlorine fuel input, using Equation 7 of Sec.  63.10011, that
were done to demonstrate continuous compliance with the HCl emission
limit, for sources

that demonstrate compliance through performance testing. For sources
that demonstrate compliance through fuel analysis, a copy of all
calculations and supporting documentation of HCl emission rates, using
Equation 15 of Sec.  63.10011, that were done to demonstrate compliance
with the HCl emission limit. Supporting documentation should include
results of any fuel analyses and basis for the estimates of maximum
chlorine fuel input or HCl emission rates. You can use the results from
one fuel analysis for multiple EGUs provided they are all burning the
same fuel type. However, you must calculate chlorine fuel input, or HCl
emission rate, for each EGU.
    (4) A copy of all calculations and supporting documentation of
maximum Hg fuel input, using Equation 8 of Sec.  63.10011, that were
done to demonstrate continuous compliance with the Hg emission limit
for sources that demonstrate compliance through performance testing.
For sources that demonstrate compliance through fuel analysis, a copy
of all calculations and supporting documentation of Hg emission rates,
using Equation 11 of Sec.  63.10011, that were done to demonstrate
compliance with the Hg emission limit. Supporting documentation should
include results of any fuel analyses and basis for the estimates of
maximum Hg fuel input or Hg emission rates. You can use the results
from one fuel analysis for multiple EGUs provided they are all burning
the same fuel type. However, you must calculate Hg fuel input, or Hg
emission rates, for each EGU.
    (5) If consistent with Sec.  63.10032(b) and (c), you choose to
stack test less frequently than annually, you must keep annual records
that document that your emissions in the previous stack test(s) were
less than 90 percent of the applicable emission limit, and document
that there was no change in source operations including fuel
composition and operation of air pollution control equipment that would
cause emissions of the pollutant to increase within the past year.
    (e) If you elect to average emissions consistent with Sec.
63.10009, you must additionally keep a copy of the emission averaging
implementation plan required in Sec.  63.10009(g), all calculations
required under Sec.  63.10009, including daily records of heat input or
steam generation, as applicable, and monitoring records consistent with
Sec.  63.10022.
    (f) Records of the occurrence and duration of each startup and/or
shutdown.
    (g) Records of the occurrence and duration of each malfunction of
operation (i.e., process equipment) or the air pollution control and
monitoring equipment.
    (h) Records of actions taken during periods of malfunction to
minimize emissions in accordance with Sec.  63.10000(b), including
corrective actions to restore malfunctioning process and air pollution
control and monitoring equipment to its normal or usual manner of
operation.

Sec.  63.10033  In what form and how long must I keep my records?

    (a) Your records must be in a form suitable and readily available
for expeditious review, according to Sec.  63.10(b)(1).
    (b) As specified in Sec.  63.10(b)(1), you must keep each record
for 5 years following the date of each occurrence, measurement,
maintenance, corrective action, report, or record.
    (c) You must keep each record on site for at least 2 years after
the date of each occurrence, measurement, maintenance, corrective
action, report, or record, according to Sec.  63.10(b)(1). You can keep
the records off site for the remaining 3 years.

Other Requirements and Information

Sec.  63.10040  What parts of the General Provisions apply to me?

    Table 10 to this subpart shows which parts of the General
Provisions in Sec. Sec.  63.1 through 63.15 apply to you.

Sec.  63.10041  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by U.S. EPA, or a
delegated authority such as your state, local, or tribal agency. If the
EPA Administrator has delegated authority to your state, local, or
tribal agency, then that agency (as well as the U.S. EPA) has the
authority to implement and enforce this subpart. You should contact
your EPA Regional Office to find out if this subpart is delegated to
your state, local, or tribal agency.
    (b) In delegating implementation and enforcement authority of this
subpart to a state, local, or tribal agency under 40 CFR part 63,
subpart E, the authorities listed in paragraphs (b)(1) through (4) of
this section are retained by the EPA Administrator and are not
transferred to the state, local, or tribal agency; however, the U.S.
EPA retains oversight of this subpart and can take enforcement actions,
as appropriate.
    (1) Approval of alternatives to the non-opacity emission limits and
work practice standards in Sec.  63.9991(a) and (b) under Sec.
63.6(g).
    (2) Approval of major change to test methods in Table 5 to this
subpart under Sec.  63.7(e)(2)(ii) and (f) and as defined in Sec.
63.90, approval of minor and intermediate changes to monitoring
performance specifications/procedures in Table 5 where the monitoring
serves as the performance test method (see definition of ``test
method'' in Sec.  63.2), and approval of alternative analytical methods
requested under Sec.  63.10008(b)(2).
    (3) Approval of major change to monitoring under Sec.  63.8(f) and
as defined in Sec.  63.90, and approval of alternative operating
parameters under Sec. Sec.  63.9991(a)(2) and 63.10009(g)(2).
    (4) Approval of major change to recordkeeping and reporting under
Sec.  63.10(e) and as defined in Sec.  63.90.

Sec.  63.10042  What definitions apply to this subpart?

    Terms used in this subpart are defined in the Clean Air Act (CAA),
in Sec.  63.2 (the General Provisions), and in this section as follows:
    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.
    Anthracite coal means solid fossil fuel classified as anthracite
coal by American Society of Testing and Materials (ASTM) Method D388-
77, 90, 91, 95, 98a, or 99 (incorporated by reference, see 40 CFR
63.14(b)(39)).
    Bag leak detection system means a group of instruments that are
capable of monitoring PM loadings in the exhaust of a fabric filter
(i.e., baghouse) in order to detect bag failures. A bag leak detection
system includes, but is not limited to, an instrument that operates on
electrodynamic, triboelectric, light scattering, light transmittance,
or other principle to monitor relative PM loadings.
    Bituminous coal means coal that is classified as bituminous
according to ASTM Method D388-77, 90, 91, 95, 98a, or 99 (Reapproved
2004) e1 (incorporated by reference, see 40 CFR
63.14(b)(39)).
    Boiler operating day means a 24-hour period between midnight and
the following midnight during which any fuel is combusted at any time
in the steam generating unit. It is not necessary for the fuel to be
combusted the entire 24-hour period.
    Coal means all solid fuels classifiable as anthracite, bituminous,
sub-bituminous, or lignite by ASTM Method D388-991\1\ (incorporated by
reference,

see 40 CFR 63.14(b)(39)), and coal refuse. Synthetic fuels derived from
coal for the purpose of creating useful heat including but not limited
to, coal derived gases (not meeting the definition of natural gas),
solvent-refined coal, coal-oil mixtures, and coal-water mixtures, are
considered ``coal'' for the purposes of this subpart.
    Coal-fired electric utility steam generating unit means an electric
utility steam generating unit meeting the definition of ``fossil fuel-
fired'' that burns coal or coal refuse either exclusively, in any
combination together, or in any combination with other fuels in any
amount.
    Coal refuse means any by-product of coal mining, physical coal
cleaning, and coal preparation operations (e.g. culm, gob, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material with an ash content greater than 50 percent (by weight) and a
heating value less than 13,900 kilojoules per kilogram (6,000 Btu per
pound) on a dry basis.
    Cogeneration means a steam-generating unit that simultaneously
produces both electrical (or mechanical) and useful thermal energy from
the same primary energy source.
    Cogeneration unit means a stationary, fossil fuel-fired EGU meeting
the definition of ``fossil fuel-fired'' or stationary, integrated
gasification combined cycle:
    (1) Having equipment used to produce electricity and useful thermal
energy for industrial, commercial, heating, or cooling purposes through
the sequential use of energy; and
    (2) Producing during the 12-month period starting on the date the
unit first produces electricity and during any calendar year after
which the unit first produces electricity:
    (i) For a topping-cycle cogeneration unit,
    (A) Useful thermal energy not less than 5 percent of total energy
output; and
    (B) Useful power that, when added to one-half of useful thermal
energy produced, is not less than 42.5 percent of total energy input,
if useful thermal energy produced is 15 percent or more of total energy
output, or not less than 45 percent of total energy input, if useful
thermal energy produced is less than 15 percent of total energy output.
    (ii) For a bottoming-cycle cogeneration unit, useful power not less
than 45 percent of total energy input.
    (3) Provided that the total energy input under paragraphs (2)(i)(B)
and (2)(ii) of this definition shall equal the unit's total energy
input from all fuel except biomass if the unit is a boiler.
    Combined-cycle gas stationary combustion turbine means a stationary
combustion turbine system where heat from the turbine exhaust gases is
recovered by a waste heat boiler.
    Common stack means the exhaust of emissions from two or more
affected units through a single flue.
    Deviation. (1) Deviation means any instance in which an affected
source subject to this subpart, or an owner or operator of such a
source:
    (i) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limit, operating
limit, work practice standard, or monitoring requirement; or
    (ii) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit.
    (2) A deviation is not always a violation.
    Distillate oil means fuel oils, including recycled oils, that
comply with the specifications for fuel oil numbers 1 and 2, as defined
by ASTM Method D396-02a (incorporated by reference, see Sec.
63.14(b)(40)).
    Dry flue gas desulfurization technology, or dry FGD, or spray dryer
absorber (SDA), or spray dryer, or dry scrubber means an add-on air
pollution control system located downstream of the steam generating
unit that injects a dry alkaline sorbent (dry sorbent injection) or
sprays an alkaline sorbent slurry (spray dryer) to react with and
neutralize acid gases such as SO2 and HCl in the exhaust
stream forming a dry powder material. Sorbent injection systems in
fluidized bed combustors (FBC) or circulating fluidized bed (CFB)
boilers are included in this definition.
    Dry sorbent injection (DSI) means an add-on air pollution control
system in which sorbent (e.g., conventional activated carbon,
brominated activated carbon, Trona, hydrated lime, sodium carbonate,
etc.) is injected into the flue gas steam upstream of a PM control
device to react with and neutralize acid gases (such as SO2
and HCl) or Hg in the exhaust stream forming a dry powder material that
may be removed in a primary or secondary PM control device.
    Electric utility steam generating unit (EGU) means a fossil fuel-
fired combustion unit of more than 25 megawatts electric (MWe) that
serves a generator that produces electricity for sale. A fossil fuel-
fired unit that cogenerates steam and electricity and supplies more
than one-third of its potential electric output capacity and more than
25 MWe output to any utility power distribution system for sale is
considered an electric utility steam generating unit.
    Electrostatic precipitator or ESP means an add-on air pollution
control device that is located downstream of the steam generating unit
used to capture PM by charging the particles using an electrostatic
field, collecting the particles using a grounded collecting surface,
and transporting the particles into a hopper.
    Emission limitation means any emissions limit or operating limit.
    Equivalent means the following only as this term is used in Table 6
to subpart UUUUU:
    (1) An equivalent sample collection procedure means a published
voluntary consensus standard or practice (VCS) or EPA method that
includes collection of a minimum of three composite fuel samples, with
each composite consisting of a minimum of three increments collected at
approximately equal intervals over the test period.
    (2) An equivalent sample compositing procedure means a published
VCS or EPA method to systematically mix and obtain a representative
subsample (part) of the composite sample.
    (3) An equivalent sample preparation procedure means a published
VCS or EPA method that: Clearly states that the standard, practice or
method is appropriate for the pollutant and the fuel matrix; or is
cited as an appropriate sample preparation standard, practice or method
for the pollutant in the chosen VCS or EPA determinative or analytical
method.
    (4) An equivalent procedure for determining heat content means a
published VCS or EPA method to obtain gross calorific (or higher
heating) value.
    (5) An equivalent procedure for determining fuel moisture content
means a published VCS or EPA method to obtain moisture content. If the
sample analysis plan calls for determining metals (especially the Hg,
selenium, or arsenic) using an aliquot of the dried sample, then the
drying temperature must be modified to prevent vaporizing these metals.
On the other hand, if metals analysis is done on an ``as received''
basis, a separate aliquot can be dried to determine moisture content
and the metals concentration mathematically adjusted to a dry basis.
    (6) An equivalent pollutant (Hg) determinative or analytical
procedure means a published VCS or EPA method that clearly states that
the standard, practice, or method is appropriate for the pollutant and
the fuel matrix and has a published detection limit equal or lower than
the methods listed in Table

6 to subpart UUUUU for the same purpose.
    Fabric filter, or FF, or baghouse means an add-on air pollution
control device that is located downstream of the steam generating unit
used to capture PM by filtering gas streams through filter media.
    Federally enforceable means all limitations and conditions that are
enforceable by the EPA Administrator, including the requirements of 40
CFR parts 60, 61, and 63; requirements within any applicable State
implementation plan; and any permit requirements established under 40
CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
    Fossil fuel means natural gas, oil, coal, and any form of solid,
liquid, or gaseous fuel derived from such material.
    Fossil fuel-fired means an electric utility steam generating unit
(EGU) that is capable of combusting more than 73 MWe (250 million Btu/
hr, MMBtu/hr) heat input (equivalent to 25 MWe output) of fossil fuels.
To be ``capable of combusting'' fossil fuels, an EGU would need to have
these fuels allowed in their permits and have the appropriate fuel
handling facilities on-site (e.g., coal handling equipment, including
coal storage area, belts and conveyers, pulverizers, etc.; oil storage
facilities). In addition, fossil fuel-fired means any EGU that fired
fossil fuels for more than 10.0 percent of the average annual heat
input during the previous 3 calendar years or for more than 15.0
percent of the annual heat input during any one of those calendar
years.
    Fuel type means each category of fuels that share a common name or
classification. Examples include, but are not limited to, bituminous
coal, subbituminous coal, lignite, anthracite, biomass, residual oil.
Individual fuel types received from different suppliers are not
considered new fuel types.
    Fluidized bed boiler, or fluidized bed combustor, or circulating
fluidized boiler, or CFB means a boiler utilizing a fluidized bed
combustion process.
    Fluidized bed combustion means a process where a fuel is burned in
a bed of granulated particles which are maintained in a mobile
suspension by the forward flow of air and combustion products.
    Gaseous fuel includes, but is not limited to, natural gas, process
gas, landfill gas, coal derived gas, solid oil-derived gas, refinery
gas, and biogas. Blast furnace gas is exempted from this definition.
    Generator means a device that produces electricity.
    Gross output means the gross useful work performed by the steam
generated and, for an IGCC electric utility steam generating unit, the
work performed by the stationary combustion turbines. For a unit
generating only electricity, the gross useful work performed is the
gross electrical output from the unit's turbine/generator sets. For a
cogeneration unit, the gross useful work performed is the gross
electrical, including any such electricity used in the power production
process (which process includes, but is not limited to, any on-site
processing or treatment of fuel combusted at the unit and any on-site
emission controls), or mechanical output plus 75 percent of the 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 input means heat derived from combustion of fuel in an EGU and
does not include the heat input from preheated combustion air,
recirculated flue gases, or exhaust gases from other sources such as
gas turbines, internal combustion engines, etc.
    Integrated gasification combined cycle electric utility steam
generating unit or IGCC means an electric utility steam generating unit
that burns a synthetic gas derived from coal or solid oil-derived fuel
in a combined-cycle gas turbine. No coal or solid oil-derived fuel is
directly burned in the unit during operation.
    ISO conditions means a temperature of 288 Kelvin, a relative
humidity of 60 percent, and a pressure of 101.3 kilopascals.
    Lignite coal means coal that is classified as lignite A or B
according to ASTM Method D388-77, 90, 91, 95, 98a, or 99 (Reapproved
2004) [egr]1 (incorporated by reference, see Sec.
63.14(a)(39)).
    Liquid fuel includes, but is not limited to, distillate oil and
residual oil.
    Minimum pressure drop means 90 percent of the test average pressure
drop measured according to Table 7 to this subpart during the most
recent performance test demonstrating compliance with the applicable
emission limit.
    Minimum scrubber effluent pH means 90 percent of the test average
effluent pH measured at the outlet of the wet scrubber according to
Table 7 to this subpart during the most recent performance test
demonstrating compliance with the applicable HCl emission limit.
    Minimum scrubber flow rate means 90 percent of the test average
flow rate measured according to Table 7 to this subpart during the most
recent performance test demonstrating compliance with the applicable
emission limit.
    Minimum sorbent injection rate means 90 percent of the test average
sorbent (or activated carbon) injection rate for each sorbent measured
according to Table 7 to this subpart during the most recent performance
test demonstrating compliance with the applicable emission limits.
    Minimum voltage or amperage means 90 percent of the test average
voltage or amperage to the electrostatic precipitator measured
according to Table 7 to this subpart during the most recent performance
test demonstrating compliance with the applicable emission limits.
    Natural gas means:
    (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of
which the principal constituent is methane; or
    (2) Liquid petroleum gas, as defined by ASTM Method D1835-03a
(incorporated by reference, see Sec.  63.14(b)(41)).
    Net-electric output means the gross electric sales to the utility
power distribution system minus purchased power on a calendar year
basis.
    Non-cogeneration unit means a unit that has a combustion unit of
more than 25 MWe and that supplies more than 25 MWe to any utility
power distribution system for sale.
    Noncontinental area means the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
    Non-mercury (Hg) HAP metals means Antimony (Sb), Arsenic (As),
Beryllium (Be), Cadmium (Cd), Chromium (Cr), Cobalt (Co), Lead (Pb),
Manganese (Mn), Nickel (Ni), and Selenium (Se).
    Oil means crude oil or petroleum or a fuel derived from crude oil
or petroleum, including distillate and residual oil, solid oil-derived
fuel (e.g., petroleum coke) and gases derived from solid oil-derived
fuels (not meeting the definition of natural gas).
    Oil-fired electric utility steam generating unit means an electric
utility steam generating unit that either burns oil exclusively, or
burns oil alternately with burning fuels other than oil at other times.
    Particulate matter or PM means any finely divided solid or liquid
material, other than uncombined water, as measured by the test methods
specified under this subpart, or an alternative method.
    Pulverized coal boiler means an EGU in which pulverized coal is
introduced into an air stream that carries the coal

to the combustion chamber of the EGU where it is fired in suspension.
    Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6,
as defined by ASTM Method D396-02a (incorporated by reference, see
Sec.  63.14(b)(40)).
    Responsible official means responsible official as defined in 40
CFR 70.2.
    Stationary combustion turbine means all equipment, including but
not limited to the turbine, the fuel, air, lubrication and exhaust gas
systems, control systems (except emissions control equipment), and any
ancillary components and sub-components comprising any simple cycle
stationary combustion turbine, any regenerative/recuperative cycle
stationary combustion turbine, the combustion turbine portion of any
stationary cogeneration cycle combustion system, or the combustion
turbine portion of any stationary combined cycle steam/electric
generating system. Stationary means that the combustion turbine is not
self propelled or intended to be propelled while performing its
function. Stationary combustion turbines do not include turbines
located at a research or laboratory facility, if research is conducted
on the turbine itself and the turbine is not being used to power other
applications at the research or laboratory facility.
    Steam generating unit means any furnace, boiler, or other device
used for combusting fuel for the purpose of producing steam (including
fossil-fuel-fired steam generators associated with integrated
gasification combined cycle gas turbines; nuclear steam generators are
not included).
    Stoker means a unit consisting of a mechanically operated fuel
feeding mechanism, a stationary or moving grate to support the burning
of fuel and admit undergrate air to the fuel, an overfire air system to
complete combustion, and an ash discharge system. There are two general
types of stokers: underfeed and overfeed. Overfeed stokers include mass
feed and spreader stokers.
    Subbituminous coal means coal that is classified as subbituminous
A, B, or C according to ASTM Method D388-77, 90, 91, 95, 98a, or 99
(Reapproved 2004) [epsiv]\1\ (incorporated by reference, see Sec.
60.14(a)(39)).
    Unit designed for coal  8,300 Btu/lb subcategory
includes any EGU designed to burn a coal having a calorific value
(moist, mineral matter-free basis) of greater than or equal to 19,305
kilojoules per kilogram (kJ/kg) (8,300 British thermal units per pound
(Btu/lb)) in an EGU with a height-to-depth ratio of less than 3.82.
    Unit designed for coal < 8,300 Btu/lb includes any EGU designed to
burn a nonagglomerating virgin coal having a calorific value (moist,
mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) in
an EGU with a height-to-depth ratio of 3.82 or greater.
    Unit designed to burn liquid oil fuel subcategory includes any EGU
that burned any liquid oil for more than 10.0 percent of the average
annual heat input during the previous 3 calendar years or for more than
15.0 percent of the annual heat input during any one of those calendar
years, either alone or in combination with gaseous fuels.
    Unit designed to burn solid oil-derived fuel subcategory includes
any EGU that burned a solid fuel derived from oil for more than 10.0
percent of the average annual heat input during the previous 3 calendar
years or for more than 15.0 percent of the annual heat input during any
one of those calendar years, either alone or in combination with other
fuels.
    Voluntary Consensus Standards or VCS mean technical standards
(e.g., materials specifications, test methods, sampling procedures,
business practices) developed or adopted by one or more voluntary
consensus bodies. EPA/OAQPS has by precedent only used VCS that are
written in English. Examples of VCS bodies are: American Society of
Testing and Materials (ASTM), American Society of Mechanical Engineers
(ASME), International Standards Organization (ISO), Standards Australia
(AS), British Standards (BS), Canadian Standards (CSA), European
Standard (EN or CEN) and German Engineering Standards (VDI). The types
of standards that are not considered VCS are standards developed by:
The U.S. States, e.g., California (CARB) and Texas (TCEQ); industry
groups, such as American Petroleum Institute (API), Gas Processors
Association (GPA), and Gas Research Institute (GRI); and other branches
of the U.S. government, e.g. Department of Defense (DOD) and Department
of Transportation (DOT). This does not preclude EPA from using
standards developed by groups that are not VCS bodies within their
rule. When this occurs, EPA has done searches and reviews for VCS
equivalent to these non-EPA methods.
    Wet flue gas desulfurization technology, or wet FGD, or wet
scrubber means any add-on air pollution control device that is located
downstream of the steam generating unit that mixes an aqueous stream or
slurry with the exhaust gases from an EGU to control emissions of PM
and/or to absorb and neutralize acid gases, such as SO2 and
HCl.
    Work practice standard means any design, equipment, work practice,
or operational standard, or combination thereof, which is promulgated
pursuant to CAA section 112(h).

Tables to Subpart UUUUU of Part 63

    As stated in Sec.  63.9991, you must comply with the following
applicable emission limits:

               Table 1 to Subpart UUUUU of Part 63--Emission Limits for New or Reconstructed EGUs
----------------------------------------------------------------------------------------------------------------
                                                                                Using these
                                                                                requirements, as
                                                                  You must meet the        appropriate, (e.g.,
      If your EGU is in this           For the following         following emission        specified sampling
        subcategory . . .               pollutants . . .      limits and work practice     volume or test run
                                                                   standards . . .       duration) with the test
                                                                                methods in Table 5 . . .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit designed for    a. Total particulate       0.050 lb per MWh........  Collect a minimum of 4
 coal >= 8,300 Btu/lb.              matter (PM).                                         dscm per run.
                                   OR                         OR                        ........................
                                   Total non-Hg HAP metals..  0.000040 lb per MWh.....  Collect a minimum of 4
                                                                                dscm per run.
                                   OR                         OR                        ........................
                                   Individual HAP metals:                               Collect a minimum of 4
                                                                                dscm per run.
                                   Antimony (Sb)............  0.000080 lb/GWh.........  ........................
                                   Arsenic (As).............  0.00020 lb/GWh..........  ........................
                                   Beryllium (Be)...........  0.000030 lb/GWh.........  ........................
                                   Cadmium (Cd).............  0.00040 lb/GWh..........  ........................

                                   Chromium (Cr)............  0.020 lb/GWh............  ........................
                                   Cobalt (Co)..............  0.00080 lb/GWh..........  ........................
                                   Lead (Pb)................  0.00090 lb/GWh..........  ........................
                                   Manganese (Mn)...........  0.0040 lb/GWh...........  ........................
                                   Nickel (Ni)..............  0.0040 lb/GWh...........  ........................
                                   Selenium (Se)............  0.030 lb/GWh............  ........................
                                   b. Hydrogen chloride       0.30 lb per GWh.........  For Method 26A, collect
                                    (HCl).                                               a minimum of 4 dscm per
                                                                                run.
                                   OR                                                   ........................
                                   Sulfur dioxide (SO2) \1\.  0.40 lb per MWh.........  SO2 CEMS.
                                   c. Mercury (Hg)..........  0.000010 lb per GWh.....  Hg CEMS or Sorbent trap
                                                                                monitoring system.
----------------------------------------------------------------------------------------------------------------
2. Coal-fired unit designed for    a. Total particulate       0.050 lb per MWh........  Collect a minimum of 4
 coal < 8,300 Btu/lb.               matter (PM).                                         dscm per run.
                                   OR                         OR                        ........................
                                   Total non-Hg HAP metals..  0.000040 lb per MWh.....  Collect a minimum of 4
                                                                                dscm per run.
                                   OR                         OR                        ........................
                                   Individual HAP metals:                               Collect a minimum of 4
                                                                                dscm per run.
                                   Antimony (Sb)............  0.000080 lb/GWh.........  ........................
                                   Arsenic (As).............  0.00020 lb/GWh..........  ........................
                                   Beryllium (Be)...........  0.000030 lb/GWh.........  ........................
                                   Cadmium (Cd).............  0.00040 lb/GWh..........  ........................
                                   Chromium (Cr)............  0.020 lb/GWh............  ........................
                                   Cobalt (Co)..............  0.00080 lb/GWh..........  ........................
                                   Lead (Pb)................  0.00090 lb/GWh..........  ........................
                                   Manganese (Mn)...........  0.0040 lb/GWh...........  ........................
                                   Nickel (Ni)..............  0.0040 lb/GWh...........  ........................
                                   Selenium (Se)............  0.030 lb/GWh............  ........................
                                   b. Hydrogen chloride       0.30 lb per GWh.........  For Method 26A, collect
                                    (HCl).                                               a minimum of 4 dscm per
                                                                                run.
                                   OR                         OR                        ........................
                                   Sulfur dioxide (SO2) \2\.  0.40 lb per MWh.........  SO2 CEMS.
                                   c. Mercury (Hg)..........  0.040 lb per GWh........  Hg CEMS or Sorbent trap
                                                                                monitoring system.
----------------------------------------------------------------------------------------------------------------
3. IGCC unit.....................  a. Particulate matter      0.050 lb per MWh........  Collect a minimum of 4
                                    (PM).                                                dscm per run.
                                   OR                         OR                        ........................
                                   Total non-Hg HAP metals..  0.000040 lb per MWh.....  Collect a minimum of 4
                                                                                dscm per run.
                                   OR                         OR                        ........................
                                   Individual HAP metals:                               Collect a minimum of 4
                                                                                dscm per run.
                                   Antimony (Sb)............  0.000080 lb/GWh.........  ........................
                                   Arsenic (As).............  0.00020 lb/GWh..........  ........................
                                   Beryllium (Be)...........  0.000030 lb/GWh.........  ........................
                                   Cadmium (Cd).............  0.00040 lb/GWh..........  ........................
                                   Chromium (Cr)............  0.020 lb/GWh............  ........................
                                   Cobalt (Co)..............  0.00080 lb/GWh..........  ........................
                                   Lead (Pb)................  0.00090 lb/GWh..........  ........................
                                   Manganese (Mn)...........  0.0040 lb/GWh...........  ........................
                                   Nickel (Ni)..............  0.0040 lb/GWh...........  ........................
                                   Selenium (Se)............  0.030 lb/GWh............  ........................
                                   b. Hydrogen chloride       0.30 lb per GWh.........  For Method 26A, collect
                                    (HCl).                                               a minimum of 4 dscm per
                                                                                run.
                                   OR                                                   ........................
                                   Sulfur dioxide (SO2) \3\.  0.40 lb per MWh.........  SO2 CEMS.
                                   c. Mercury (Hg)..........  0.000010 lb per GWh.....  Hg CEMS or Sorbent trap
                                                                                monitoring system.
----------------------------------------------------------------------------------------------------------------
4. Liquid oil-fired unit.........  a. Total HAP metals......  0.00040 lb/MWh..........  Collect a minimum of 4
                                                                                dscm per run.
                                   OR                         OR                        ........................
                                   Individual HAP metals:                               Collect a minimum of 4
                                                                                dscm per run.
                                   Antimony (Sb)............  0.0020 lb/GWh...........  ........................

                                   Arsenic (As).............  0.0020 lb/GWh...........  ........................
                                   Beryllium (Be)...........  0.00070 lb/GWh..........  ........................
                                   Cadmium (Cd).............  0.00040 lb/GWh..........  ........................
                                   Chromium (Cr)............  0.020 lb/GWh............  ........................
                                   Cobalt (Co)..............  0.0060 lb/GWh...........  ........................
                                   Lead (Pb)................  0.0060 lb/GWh...........  ........................
                                   Manganese (Mn)...........  0.030 lb/GWh............  ........................
                                   Nickel (Ni)..............  0.040 lb/GWh............  ........................
                                   Selenium (Se)............  0.0040 lb/GWh...........  ........................
                                   Mercury (Hg).............  0.00010 lb/GWh..........  For Method 30B sample
                                                                                volume determination
                                                                                (8.2.4), the estimated
                                                                                Hg concentration should
                                                                                nominally be < \1/2\
                                                                                the standard.
                                   b. Hydrogen chloride       0.00050 lb/MWh..........  For Method 26A, collect
                                    (HCl).                                               a minimum of 4 dscm per
                                                                                run.
                                   c. Hydrogen fluoride (HF)  0.00050 lb/MWh..........  For Method 26A, collect
                                                                                a minimum of 4 dscm per
                                                                                run.
----------------------------------------------------------------------------------------------------------------
5. Solid oil-derived fuel-fired    a. Particulate matter      0.050 lb/MWh............  Collect a minimum of 4
 unit.                              (PM).                                                dscm per run.
                                   OR                         OR                        ........................
                                   Total non-Hg HAP metals..  0.00020 lb/MWh..........  Collect a minimum of 4
                                                                                dscm per run.
                                   OR                         OR                        ........................
                                   Individual HAP metals:                               Collect a minimum of 4
                                                                                dscm per run.
                                   Antimony (Sb)............  0.00090 lb/GWh..........  ........................
                                   Arsenic (As).............  0.0020 lb/GWh...........  ........................
                                   Beryllium (Be)...........  0.000080 lb/GWh.........  ........................
                                   Cadmium (Cd).............  0.0070 lb/GWh...........  ........................
                                   Chromium (Cr)............  0.0060 lb/GWh...........  ........................
                                   Cobalt (Co)..............  0.0020 lb/GWh...........  ........................
                                   Lead (Pb)................  0.020 lb/GWh............  ........................
                                   Manganese (Mn)...........  0.0070 lb/GWh...........  ........................
                                   Nickel (Ni)..............  0.0070 lb/GWh...........  ........................
                                   Selenium (Se)............  0.00090 lb/GWh..........  ........................
                                   b. Hydrogen chloride       0.00030 lb/MWh..........  For Method 26A, collect
                                    (HCl).                                               a minimum of 4 dscm per
                                                                                run.
                                   OR                                                   ........................
                                   Sulfur dioxide (SO2) \4\.  0.40 lb/MWh.............  SO2 CEMS.
                                   c. Mercury (Hg)..........  0.0020 lb/GWh...........  Hg CEMS or Sorbent trap
                                                                                monitoring system.
----------------------------------------------------------------------------------------------------------------

    As stated in Sec.  63.9991, you must comply with the following
applicable emission limits: \5\

                     Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing EGUs
----------------------------------------------------------------------------------------------------------------
                                                                                Using these
                                                                                requirements, as
                                                                   You must meet the        appropriate (e.g.,
 If your EGU is in this subcategory .     For the following        following emission       specified sampling
                 . .                       pollutants . . .         limits and work         volume or test run
                                                                 practice standards . .  duration) with the test
                                                                           .              methods in Table 5 . .
                                                                                .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit designed for coal   a. Total particulate     0.030 lb/MMBtu or 0.30   Collect a minimum of 2
 >= 8,300 Btu/lb.                       matter (PM).             lb/MWh.                  dscm per run.
                                       OR                       OR
                                       Total non-Hg HAP metals  0.000040 lb/MMBtu        Collect a minimum of 4
                                                                0.00040 lb/MWh.........   dscm per run.
                                       OR                       OR
                                       Individual HAP metals:                            Collect a minimum of 4
                                                                                dscm per run.
                                       Antimony (Sb)..........  0.60 lb/TBtu or 0.0060
                                                                 lb/GWh.
                                       Arsenic (As)...........  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Beryllium (Be).........  0.20 lb/TBtu or 0.0020
                                                                 lb/GWh.
                                       Cadmium (Cd)...........  0.30 lb/TBtu or 0.0030
                                                                 lb/GWh.

                                       Chromium (Cr)..........  3.0 lb/TBtu or 0.030 lb/
                                                                 GWh.
                                       Cobalt (Co)............  0.80 lb/TBtu or 0.0080
                                                                 lb/GWh.
                                       Lead (Pb)..............  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Manganese (Mn).........  5.0 lb/TBtu or 0.050 lb/
                                                                 GWh.
                                       Nickel (Ni)............  4.0 lb/TBtu or 0.040 lb/
                                                                 GWh.
                                       Selenium (Se)..........  6.0 lb/TBtu or 0.060 lb/
                                                                 GWh.
                                       b. Hydrogen chloride     0.0020 lb per MMBtu or   For Method 26A, collect
                                        (HCl).                   0.020 lb per MWh.        a minimum of 0.75 dscm
                                                                                per run; for Method
                                                                                26, collect a minimum
                                                                                of 60 liters per run.
                                       OR
                                       Sulfur dioxide (SO2)     0.20 lb per MMBtu or     SO2 CEMS.
                                        \6\.                     2.0 lb per MWh.
                                       c. Mercury (Hg)........  1.0 lb/TBtu or 0.008 lb/ LEE Testing for 28-30
                                                                 GWh.                     days with 10 days
                                                                                maximum per run or Hg
                                                                                CEMS or Sorbent trap
                                                                                monitoring system.
----------------------------------------------------------------------------------------------------------------
2. Coal-fired unit designed for coal.  a. Total particulate     0.030 lb/MMBtu or 0.30   Collect a minimum of 4
< 8,300 Btu/lb.......................   matter (PM).             lb/MWh.                  dscm per run.
                                       OR                       OR
                                       Total non-Hg HAP metals  0.000040 lb/MMBtu        Collect a minimum of 4
                                                                0.00040 lb/MWh.........   dscm per run.
                                       OR                       OR
                                       Individual HAP metals:                            Collect a minimum of 4
                                                                                dscm per run.
                                       Antimony (Sb)..........  0.60 lb/TBtu or 0.0060
                                                                 lb/GWh.
                                       Arsenic (As)...........  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Beryllium (Be).........  0.20 lb/TBtu or 0.0020
                                                                 lb/GWh.
                                       Cadmium (Cd)...........  0.30 lb/TBtu or 0.0030
                                                                 lb/GWh.
                                       Chromium (Cr)..........  3.0 lb/TBtu or 0.030 lb/
                                                                 GWh.
                                       Cobalt (Co)............  0.80 lb/TBtu or 0.0080
                                                                 lb/GWh.
                                       Lead (Pb)..............  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Manganese (Mn).........  5.0 lb/TBtu or 0.050 lb/
                                                                 GWh.
                                       Nickel (Ni)............  4.0 lb/TBtu or 0.040 lb/
                                                                 GWh.
                                       Selenium (Se)..........  6.0 lb/TBtu or 0.060 lb/
                                                                 GWh.
                                       b. Hydrogen chloride     0.0020 lb per MMBtu or   For Method 26A, collect
                                        (HCl).                   0.020 lb per MWh.        a minimum of 0.75 dscm
                                                                                per run; for Method
                                                                                26, collect a minimum
                                                                                of 60 liters per run.
                                       OR
                                       Sulfur dioxide (SO2)     0.20 lb per MMBtu or     SO2 CEMS.
                                        \7\.                     2.0 lb per MWh.
                                       c. Mercury (Hg)........  4.0 lb/TBtu or 0.040 lb/ LEE Testing for 28-30
                                                                 GWh.                     days with 10 days
                                                                                maximum per run or Hg
                                                                                CEMS or Sorbent trap
                                                                                monitoring system.
----------------------------------------------------------------------------------------------------------------
3. IGCC unit.........................  a. Total particulate     0.050 lb/MMBtu or 0.30   Collect a minimum of 4
                                        matter (PM).             lb/MWh.                  dscm per run.
                                       OR                       OR
                                       Total non-Hg HAP metals  5.0 lb/TBtu or 0.050 lb/ Collect a minimum of 4
                                                                 GWh.                     dscm per run.
                                       OR                       OR
                                       Individual HAP metals:                            Collect a minimum of 4
                                                                                dscm per run.
                                       Antimony (Sb)..........  0.40 lb/TBtu or 0.0040
                                                                 lb/GWh.
                                       Arsenic (As)...........  2.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Beryllium (Be).........  0.030 lb/TBtu or 0.0030
                                                                 lb/GWh.
                                       Cadmium (Cd)...........  0.20 lb/TBtu or 0.0020
                                                                 lb/GWh.
                                       Chromium (Cr)..........  3.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Cobalt (Co)............  2.0 lb/TBtu or 0.0040
                                                                 lb/GWh.
                                       Lead (Pb)..............  0.0002 lb/MMBtu or
                                                                 0.003 lb/MWh.
                                       Manganese (Mn).........  3.0 lb/TBtu or 0.020 lb/
                                                                 GWh.
                                       Nickel (Ni)............  5.0 lb/TBtu or 0.050 lb/
                                                                 GWh.
                                       Selenium (Se)..........  22.0 lb/TBtu or 0.20 lb/
                                                                 GWh.
                                       b. Hydrogen chloride     0.00050 lb/MMBtu or      For Method 26A, collect
                                        (HCl).                   0.0030 lb/MWh.           a minimum of 4 dscm
                                                                                per run.

                                       c. Mercury (Hg)........  3.0 lb/TBtu or 0.020 lb/ LEE Testing for 28-30
                                                                 GWh.                     days with 10 days
                                                                                maximum per run or Hg
                                                                                CEMS or Sorbent trap
                                                                                monitoring system.
----------------------------------------------------------------------------------------------------------------
4. Liquid oil-fired unit.............  a. Total HAP metals....  0.000030 lb/MMBtu or     Collect a minimum of 4
                                                                 0.00030 lb/MWh.          dscm per run.
                                       OR                       OR
                                       Individual HAP metals:                            Collect a minimum of 4
                                                                                dscm per run.
                                       Antimony (Sb)..........  0.20 lb/TBtu or 0.0030
                                                                 lb/GWh.
                                       Arsenic (As)...........  0.60 lb/TBtu or 0.0070
                                                                 lb/GWh.
                                       Beryllium (Be).........  0.060 lb/TBtu or
                                                                 0.00070 lb/GWh.
                                       Cadmium (Cd)...........  0.10 lb/TBtu or 0.0020
                                                                 lb/GWh.
                                       Chromium (Cr)..........  2.0 lb/TBtu or 0.020 lb/