VA,<PHONE_NUMBER> or http://www.ntis.gov, and from http://www.epa.gov/ttn/emc/news.html or http://www.epa.gov/appcdwww/tsb/

index.html.
* * * * *
    5.1.9 Mercury Standards
    For 7-day calibration error tests of Hg concentration monitors
and for daily calibration error tests of Hg monitors, either NIST-
traceable elemental Hg standards (as defined in Sec.  72.2 of this
chapter) or a NIST-traceable source of oxidized Hg (as defined in
Sec.  72.2 of this chapter) may be used. For linearity checks, NIST-
traceable elemental Hg standards shall be used. For 3-level and
single-point system integrity checks under Sec.  75.20(c)(1)(vi),
sections 6.2(g) and 6.3.1 of this appendix, and sections 2.1.1,
2.2.1 and 2.6 of appendix B to this part, a NIST-traceable source of
oxidized Hg shall be used.

Alternatively, other NIST-traceable standards may be used for the
required checks, subject to the approval of the Administrator.
Notwithstanding these requirements, Hg calibration standards that
are not NIST-traceable may be used for the tests described in this
section until December 31, 2009. However, on and after January 1,
2010, only NIST-traceable calibration standards shall be used for
these tests.
* * * * *
    6.1 General Requirements
* * * * *
    6.1.2 Requirements for Air Emission Testing Bodies
    (a) On and after January 1, 2009, any Air Emission Testing Body
(AETB) conducting relative accuracy test audits of CEMS and sorbent
trap monitoring systems under this part must conform to the
requirements of ASTM D7036-04 (incorporated by reference under Sec.
75.6 of this part). This section is not applicable to daily
operation, daily calibration error checks, daily flow interference
checks, quarterly linearity checks or routine maintenance of CEMS.
    (b) The AETB shall provide to the affected source(s)
certification that the AETB operates in conformance with, and that
data submitted to the Agency has been collected in accordance with,
the requirements of ASTM D7036-04 (incorporated by reference under
Sec.  75.6 of this part). This certification may be provided in the
form of:
    (1) A certificate of accreditation of relevant scope issued by a
recognized, national accreditation body; or
    (2) A letter of certification signed by a member of the senior
management staff of the AETB.
    (c) The AETB shall either provide a Qualified Individual on-site
to conduct or shall oversee all relative accuracy testing carried
out by the AETB as required in ASTM D7036-04 (incorporated by
reference under Sec.  75.6 of this part). The Qualified Individual
shall provide the affected source(s) with copies of the
qualification credentials relevant to the scope of the testing
conducted.
* * * * *
    6.2 Linearity Check (General Procedures)
    * * * Notwithstanding these requirements, if the SO2
or NOX span value for a particular monitor range is <= 30
ppm, that range is exempted from the linearity check requirements of
this part, for initial certification, recertification, and for on-
going quality-assurance. For units with two measurement ranges (high
and low) for a particular parameter, perform a linearity check on
both the low scale (except for SO2 or NOX span
values < = 30 ppm) and the high scale. Note that for a
NOX-diluent monitoring system with two NOX
measurement ranges, if the low NOX scale has a span value
< = 30 ppm and is exempt from linearity checks, this does not exempt
either the diluent monitor or the high NOX scale (if the
span is > 30 ppm) from linearity check requirements.
* * * * *
    (g) For Hg monitors, follow the guidelines in section 2.2.3 of
this appendix in addition to the applicable procedures in section
6.2 when performing the system integrity checks described in Sec.
75.20(c)(1)(vi) and in sections 2.1.1, 2.2.1 and 2.6 of appendix B
to this part.
    (h) For Hg concentration monitors, if moisture is added to the
calibration gas during the required linearity checks or system
integrity checks, the moisture content of the calibration gas must
be accounted for. Under these circumstances, the dry basis
concentration of the calibration gas shall be used to calculate the
linearity error or measurement error (as applicable).
* * * * *
    6.3.1 Gas Monitor 7-day Calibration Error Test
    * * * Also for Hg monitors, if moisture is added to the
calibration gas, the added moisture must be accounted for and the
dry-basis concentration of the calibration gas shall be used to
calculate the calibration error.
* * * * *
    6.4. Cycle Time Test
    Perform cycle time tests for each pollutant concentration
monitor and continuous emission monitoring system while the unit is
operating, according to the following procedures. Use a zero-level
and a high-level calibration gas (as defined in section 5.2 of this
appendix) alternately. For Hg monitors, the calibration gas used for
this test may either be the elemental or oxidized form of Hg. To
determine the downscale cycle time, measure the concentration of the
flue gas emissions until the response stabilizes. Record the stable
emissions value. Inject a zero-level concentration calibration gas
into the probe tip (or injection port leading to the calibration
cell, for in situ systems with no probe). Record the time of the
zero gas injection, using the data acquisition and handling system
(DAHS). Next, allow the monitor to measure the concentration of the
zero gas until the response stabilizes. Record the stable ending
calibration gas reading. Determine the downscale cycle time as the
time it takes for 95.0 percent of the step change to be achieved
between the stable stack emissions value and the stable ending zero
gas reading. Then repeat the procedure, starting with stable stack
emissions and injecting the high-level gas, to determine the upscale
cycle time, which is the time it takes for 95.0 percent of the step
change to be achieved between the stable stack emissions value and
the stable ending high-level gas reading. Use the following criteria
to assess when a stable reading of stack emissions or calibration
gas concentration has been attained. A stable value is equivalent to
a reading with a change of less than 2.0 percent of the span value
for 2 minutes, or a reading with a change of less than 6.0 percent
from the measured average concentration over 6 minutes.
Alternatively, the reading is considered stable if it changes by no
more than 0.5 ppm, 0.5 [mu]g/m\3\ (for Hg), or 0.2% CO2
or O2 (as applicable) for two minutes. (Owners or
operators of systems which do not record data in 1-minute or 3-
minute intervals may petition the Administrator under Sec.  75.66
for alternative stabilization criteria). For monitors or monitoring
systems that perform a series of operations (such as purge, sample,
and analyze), time the injections of the calibration gases so they
will produce the longest possible cycle time. Refer to Figures 6a
and 6b in this appendix for example calculations of upscale and
downscale cycle times. Report the slower of the two cycle times
(upscale or downscale) as the cycle time for the analyzer. Prior to
January 1, 2009 for the NOX-diluent continuous emission
monitoring system test, either record and report the longer cycle
time of the two component analyzers as the system cycle time or
record the cycle time for each component analyzer separately (as
applicable). On and after January 1, 2009, record the cycle time for
each component analyzer separately. For time-shared systems, perform
the cycle time tests at each probe locations that will be polled
within the same 15-minute period during monitoring system
operations. To determine the cycle time for time-shared systems, at
each monitoring location, report the sum of the cycle time observed
at that monitoring location plus the sum of the time required for
all purge cycles (as determined by the continuous emission
monitoring system manufacturer) at each of the probe locations of
the time-shared systems. For monitors with dual ranges, report the
test results for each range separately. Cycle time test results are
acceptable for monitor or monitoring system certification,
recertification or diagnostic testing if none of the cycle times
exceed 15 minutes. The status of emissions data from a monitor prior
to and during a cycle time test period shall be determined as
follows:
* * * * *
    6.5 * * *
    (e) Complete each single-load relative accuracy test audit
within a period of 168 consecutive unit operating hours, as defined
in Sec.  72.2 of this chapter (or, for CEMS installed on common
stacks or bypass stacks, 168 consecutive stack operating hours, as
defined in Sec.  72.2 of this chapter). Notwithstanding this
requirement, up to 336 consecutive unit or stack operating hours may
be taken to complete the RATA of a Hg monitoring system, when ASTM
6784-02 (incorporated by reference under Sec.  75.6 of this part) or
Method 29 in appendix A-8 to part 60 of this chapter is used as the
reference method. For 2-level and 3-level flow monitor RATAs,
complete all of the RATAs at all levels, to the extent practicable,
within a period of 168 consecutive unit (or stack) operating hours;
however, if this is not possible, up to 720 consecutive unit (or
stack) operating hours may be taken to complete a multiple-load flow
RATA.
* * * * *
    <IP_ADDRESS> * * *
    (e) The owner or operator shall report the upper and lower
boundaries of the range of operation for each unit (or combination
of units, for common stacks), in units of megawatts or thousands of
lb/hr or mmBtu/hr of steam production or ft/sec (as applicable), in
the electronic monitoring plan required under Sec.  75.53. Except
for peaking units and LME units, the owner or operator shall
indicate, in the electronic monitoring plan, the load level (or
levels) designated as normal under this section and shall also
indicate the two most frequently used load levels.
* * * * *

    6.5.6 * * *
    (c) For Hg monitoring systems, use the same basic approach for
traverse point selection that is used for the other gas monitoring
system RATAs, except that the stratification test provisions in
sections 8.1.3 through <IP_ADDRESS> of Method 30A shall apply, rather
than the provisions of sections <IP_ADDRESS> through <IP_ADDRESS> of this
appendix.
    6.5.10 Reference Methods
    The following methods are from appendix A to part 60 of this
chapter or have been published by ASTM, and are the reference
methods for performing relative accuracy test audits under this
part: Method 1 or 1A in appendix A-1 to part 60 of this chapter for
siting; Method 2 in appendices A-1 and A-2 to part 60 of this
chapter or its allowable alternatives in appendix A to part 60 of
this chapter (except for Methods 2B and 2E in appendix A-1 to part
60 of this chapter) for stack gas velocity and volumetric flow rate;
Methods 3, 3A or 3B in appendix A-2 to part 60 of this chapter for
O2 and CO2; Method 4 in appendix A-3 to part
60 of this chapter for moisture; Methods 6, 6A or 6C in appendix A-4
to part 60 of this chapter for SO2; Methods 7, 7A, 7C, 7D
or 7E in appendix A-4 to part 60 of this chapter for NOX,
excluding the exceptions of Method 7E in appendix A-4 to part 60 of
this chapter identified in Sec.  75.22(a)(5); and for Hg, either
ASTM D6784-02 (the Ontario Hydro Method) (incorporated by reference
under Sec.  75.6 of this part), Method 29 in appendix A-8 to part 60
of this chapter, Method 30A, or Method 30B When using Method 7E in
appendix A-4 to part 60 of this chapter for measuring NOX
concentration, total NOX, both NO and NO2,
must be measured.
* * * * *
    7.6 Bias Test and Adjustment Factor
* * * * *
    7.6.1 * * * To calculate bias for a Hg monitoring system when
using the Ontario Hydro Method or Method 29 in appendix A-8 to part
60 of this chapter, ``d'' is, for each data point, the difference
between the average Hg concentration value (in [mu]g/m\3\) from the
paired Ontario Hydro or Method 29 in appendix A-8 to part 60 of this
chapter sampling trains and the concentration measured by the
monitoring system. For sorbent trap monitoring systems, use the
average Hg concentration measured by the paired traps in the
calculation of ``d''.
* * * * *
    7.7 * * *
    (a) * * *

Rref = Reference value of the flow-to-load ratio, from
the most recent normal-load flow RATA, scfh/megawatts, scfh/1000 lb/
hr of steam, or scfh/(mmBtu/hr of steam output).
* * * * *
Lavg = Average unit load during the normal-load flow
RATA, megawatts, 1000 lb/hr of steam, or mmBtu/hr of thermal output.
* * * * *
    (c) * * *

(GHR)ref = Reference value of the gross heat rate at the
time of the most recent normal-load flow RATA, Btu/kwh, Btu/lb steam
load, or Btu heat input/mmBtu steam output.
* * * * *
Lavg = Average unit load during the normal-load flow
RATA, megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output.
[GRAPHIC] [TIFF OMITTED] TR24JA08.000

[GRAPHIC] [TIFF OMITTED] TR24JA08.001

    A. To determine the upscale cycle time (Figure 6a), measure the
flue gas emissions until the response stabilizes. Record the
stabilized value (see section 6.4 of this appendix for the stability
criteria).
    B. Inject a high-level calibration gas into the port leading to
the calibration cell or thimble (Point B). Allow the analyzer to
stabilize. Record the stabilized value.
    C. Determine the step change. The step change is equal to the
difference between the final stable calibration gas value (Point D)
and the stabilized stack emissions value (Point A).
    D. Take 95% of the step change value and add the result to the
stabilized stack emissions value (Point A). Determine the time at
which 95% of the step change occurred (Point C).
    E. Calculate the upscale cycle time by subtracting the time at
which the calibration gas was injected (Point B) from the time at
which 95% of the step change occurred (Point C). In this example,
upscale cycle time = (11-5) = 6 minutes.
    F. To determine the downscale cycle time (Figure 6b) repeat the
procedures above, except that a zero gas is injected when the flue
gas emissions have stabilized, and 95% of the step change in
concentration is subtracted from the stabilized stack emissions
value.
    G. Compare the upscale and downscale cycle time values. The
longer of these two times is the cycle time for the analyzer.

0
41. Appendix B to Part 75 is amended by:
0
a. Adding section 1.1.4;
0
b. Revising section 2.1.1;
0
c. Revising paragraph (2) of section <IP_ADDRESS>;
0
d. Revising paragraph (2) of section <IP_ADDRESS>;
0
e. Adding paragraph (3) to section <IP_ADDRESS>;
0
f. Adding a new fourth sentence to paragraph (e) of section 2.2.3;
0
g. Revising the terms ``Rh'' and ``Lh'' in
paragraph (a) of section 2.2.5;
0
h. Revising the terms ``(GHR)h'' and ``Lh'' in
paragraph (a)(2) of section 2.2.5;
0
i. Removing the word ``five'' and adding in its place the word
``twenty'', and by removing the word ``years'' and adding in its place
the word ``quarters'', in paragraph (c)(4) of section <IP_ADDRESS>;
0
j. Revising paragraphs (d) and (g) of section 2.3.2;
0
k. Revising paragraphs (a)(2) and (c) of section 2.3.3;
0
l. Adding paragraph (d) to section 2.3.3;
0
m. Revising section 2.6;
0
n. Revising Figure 1; and
0
o. Revising Figure 2.
    The revisions and additions read as follows:

Appendix B to Part 75--Quality Assurance and Quality Control Procedures

1. Quality Assurance/Quality Control Program

* * * * *
    1.1.4 The requirements in section 6.1.2 of appendix A to this
part shall be met by any Air Emissions Testing Body (AETB)
performing the semiannual/annual RATAs described in section 2.3 of
this appendix and the Hg emission tests described in Sec. Sec.
75.81(c) and 75.81(d)(4).
* * * * *

2. Frequency of Testing

* * * * *
    2.1.1 Calibration Error Test
    Except as provided in section <IP_ADDRESS> of this appendix, perform
the daily calibration error test of each gas monitoring system
(including moisture monitoring systems consisting of wet- and dry-
basis O2 analyzers) according to the procedures in
section 6.3.1 of appendix A to this part, and perform the daily
calibration error test of each flow monitoring system according to
the procedure in section 6.3.2 of appendix A to this part. When two
measurement ranges (low and high) are required for a particular
parameter, perform sufficient calibration error tests on each range
to validate the data recorded on that range, according to the
criteria in section 2.1.5 of this appendix.
* * * * *

    <IP_ADDRESS> * * *
    (2) For each monitoring system that has passed the off-line
calibration demonstration, off-line calibration error tests may be
used on a limited basis to validate data, in accordance with
paragraph (2) in section <IP_ADDRESS> of this appendix.
* * * * *
    <IP_ADDRESS> * * *
    (2) For a monitor that has passed the off-line calibration
demonstration, a combination of on-line and off-line calibration
error tests may be used to validate data from the monitor, as
follows. For a particular unit (or stack) operating hour, data from
a monitor may be validated using a successful off-line calibration
error test if: (a) An on-line calibration error test has been passed
within the previous 26 unit (or stack) operating hours; and (b) the
26 clock hour data validation window for the off-line calibration
error test has not expired. If either of these conditions is not
met, then the data from the monitor are invalid with respect to the
daily calibration error test requirement. Data from the monitor
shall remain invalid until the appropriate on-line or off-line
calibration error test is successfully completed so that both
conditions (a) and (b) are met.
    (3) For units with two measurement ranges (low and high) for a
particular parameter, when separate analyzers are used for the low
and high ranges, a failed or expired calibration on one of the
ranges does not affect the quality-assured data status on the other
range. For a dual-range analyzer (i.e., a single analyzer with two
measurement scales), a failed calibration error test on either the
low or high scale results in an out-of-control period for the
monitor. Data from the monitor remain invalid until corrective
actions are taken and ``hands-off'' calibration error tests have
been passed on both ranges. However, if the most recent calibration
error test on the high scale was passed but has expired, while the
low scale is up-to-date on its calibration error test requirements
(or vice-versa), the expired calibration error test does not affect
the quality-assured status of the data recorded on the other scale.
* * * * *
    2.2.3 * * *
    (e) * * * For a dual-range analyzer, ``hands-off'' linearity
checks must be passed on both measurement scales to end the out-of-
control period. * * *
* * * * *
    2.2.5 * * *
    (a) * * *

Rh = Hourly value of the flow-to-load ratio, scfh/
megawatts, scfh/1000 lb/hr of steam, or scfh/(mmBtu/hr thermal
output).
* * * * *
Lh = Hourly unit load, megawatts, 1000 lb/hr of steam, or
mmBtu/hr thermal output; must be within + 10.0 percent of
Lavg during the most recent normal-load flow RATA.
* * * * *
    (2) * * *

(GHR)h = Hourly value of the gross heat rate, Btu/kwh,
Btu/lb steam load, or 1000 mmBtu heat input/mmBtu thermal output.
* * * * *
    Lh = Hourly unit load, megawatts, 1000 lb/hr of
steam, or mmBtu/hr thermal output; must be within + 10.0 percent of
Lavg during the most recent normal-load flow RATA.
* * * * *
    2.3.2 * * *
    (d) For single-load (or single-level) RATAs, if a daily
calibration error test is failed during a RATA test period, prior to
completing the test, the RATA must be repeated. Data from the
monitor are invalidated prospectively from the hour of the failed
calibration error test until the hour of completion of a subsequent
successful calibration error test. The subsequent RATA shall not be
commenced until the monitor has successfully passed a calibration
error test in accordance with section 2.1.3 of this appendix.
Notwithstanding these requirements, when ASTM D6784-02 (incorporated
by reference under Sec.  75.6 of this part) or Method 29 in appendix
A-8 to part 60 of this chapter is used as the reference method for
the RATA of a Hg CEMS, if a calibration error test of the CEMS is
failed during a RATA test period, any test run(s) completed prior to
the failed calibration error test need not be repeated; however, the
RATA may not continue until a subsequent calibration error test of
the Hg CEMS has been passed. For multiple-load (or multiple-level)
flow RATAs, each load level (or operating level) is treated as a
separate RATA (i.e., when a calibration error test is failed prior
to completing the RATA at a particular load level (or operating
level), only the RATA at that load level (or operating level) must
be repeated; the results of any previously-passed RATA(s) at the
other load level(s) (or operating level(s)) are unaffected, unless
re-linearization of the monitor is required to correct the problem
that caused the calibration failure, in which case a subsequent 3-
load (or 3-level) RATA is required), except as otherwise provided in
section <IP_ADDRESS>(c)(5) of this appendix.
* * * * *
    (g) Data validation for failed RATAs for a CO2
pollutant concentration monitor (or an O2 monitor used to
measure CO2 emissions), a NOX pollutant
concentration monitor, and a NOX-diluent monitoring
system shall be done according to paragraphs (g)(1) and (g)(2) of
this section:
    (1) For a CO2 pollutant concentration monitor (or an
O2 monitor used to measure CO2 emissions)
which also serves as the diluent component in a NOX-
diluent monitoring system, if the CO2 (or O2)
RATA is failed, then both the CO2 (or O2)
monitor and the associated NOX-diluent system are
considered out-of-control, beginning with the hour of completion of
the failed CO2 (or O2) monitor RATA, and
continuing until the hour of completion of subsequent hands-off
RATAs which demonstrate that both systems have met the applicable
relative accuracy specifications in sections 3.3.2 and 3.3.3 of
appendix A to this part, unless the option in paragraph (b)(3) of
this section to use the data validation procedures and associated
timelines in Sec.  75.20(b)(3)(ii) through (b)(3)(ix) has been
selected, in which case the beginning and end of the out-of-control
period shall be determined in accordance with Sec.
75.20(b)(3)(vii)(A) and (B).
    (2) This paragraph (g)(2) applies only to a NOX
pollutant concentration monitor that serves both as the
NOX component of a NOX concentration
monitoring system (to measure NOX mass emissions) and as
the NOX component in a NOX-diluent monitoring
system (to measure NOX emission rate in lb/mmBtu). If the
RATA of the NOX concentration monitoring system is
failed, then both the NOX concentration monitoring system
and the associated NOX-diluent monitoring system are
considered out-of-control, beginning with the hour of completion of
the failed NOX concentration RATA, and continuing until
the hour of completion of subsequent hands-off RATAs which
demonstrate that both systems have met the applicable relative
accuracy specifications in sections 3.3.2 and 3.3.7 of appendix A to
this part, unless the option in paragraph (b)(3) of this section to
use the data validation procedures and associated timelines in Sec.
75.20(b)(3)(ii) through (b)(3)(ix) has been selected, in which case
the beginning and end of the out-of-control period shall be
determined in accordance with Sec.  75.20(b)(3)(vii)(A) and (B).
* * * * *
    2.3.3 RATA Grace Period
    (a) * * *
    (2) A required 3-load flow RATA has not been performed by the
end of the calendar quarter in which it is due; or
* * * * *
    (c) If, at the end of the 720 unit (or stack) operating hour
grace period, the RATA has not been completed, data from the
monitoring system shall be invalid, beginning with the first unit
operating hour following the expiration of the grace period. Data
from the CEMS remain invalid until the hour of completion of a
subsequent hands-off RATA. The deadline for the next test shall be
either two QA operating quarters (if a semiannual RATA frequency is
obtained) or four QA operating quarters (if an annual RATA frequency
is obtained) after the quarter in which the RATA is completed, not
to exceed eight calendar quarters.
* * * * *
    (d) When a RATA is done during a grace period in order to
satisfy a RATA requirement from a previous quarter, the deadline for
the next RATA shall determined as follows:
    (1) If the grace period RATA qualifies for a reduced, (i.e.,
annual), RATA frequency the deadline for the next RATA shall be set
at three QA operating quarters after the quarter in which the grace
period test is completed.
    (2) If the grace period RATA qualifies for the standard, (i.e.,
semiannual), RATA frequency the deadline for the next RATA shall be
set at two QA operating quarters after the quarter in which the
grace period test is completed.
    (3) Notwithstanding these requirements, no more than eight
successive calendar quarters shall elapse after the quarter in which
the grace period test is completed, without a subsequent RATA having
been conducted.
* * * * *

    2.6 System Integrity Checks for Hg Monitors
    For each Hg concentration monitoring system (except for a Hg
monitor that does not have a converter), perform a single-point
system integrity check weekly, i.e., at least once every 168 unit or
stack operating hours, using a NIST-traceable source of oxidized Hg.
Perform this check using a mid- or high-level gas concentration, as
defined in section 5.2 of appendix A to this part. The performance
specifications in paragraph (3) of section 3.2 of appendix A to this
part must be met, otherwise the monitoring system is considered out-
of-control, from the hour of the failed check until a subsequent
system integrity check is passed. If a required system integrity
check is not performed and passed within 168 unit or stack operating
hours of last successful check, the monitoring system shall also be
considered out of control, beginning with the 169th unit or stack
operating hour after the last successful check, and continuing until
a subsequent system integrity check is passed. This weekly check is
not required if the daily calibration assessments in section 2.1.1
of this appendix are performed using a NIST-traceable source of
oxidized Hg.
* * * * *

                                         Figure 1 to Appendix B of Part 75.--Quality Assurance Test Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                            Basic QA test frequency requirements *
                Test                --------------------------------------------------------------------------------------------------------------------
                                             Daily *                 Weekly               Quarterly *            Semiannual *              Annual
--------------------------------------------------------------------------------------------------------------------------------------------------------
Calibration Error Test (2 pt.).....  ...............  ......................  .....................  .....................  .....................
Interference Check (flow)..........  ...............  ......................  .....................  .....................  .....................
Flow-to-Load Ratio.................  ......................  ......................  ..............  .....................  .....................
Leak Check (DP flow monitors)......  ......................  ......................  ..............  .....................  .....................
Linearity Check or System Integrity  ......................  ......................  ..............  .....................  .....................
 Check ** (3 pt.).
Single-point System Integrity Check  ......................  ...............  .....................  .....................  .....................
 **.
RATA (SO2, NOX, CO2, O2, H2O) \1\..  ......................  ......................  .....................  ..............  .....................
RATA (All Hg monitoring systems)...  ......................  ......................  .....................  .....................
RATA (flow) 1 2....................  ......................  ......................  .....................  ..............  .....................
--------------------------------------------------------------------------------------------------------------------------------------------------------
* ``Daily'' means operating days, only. ``Weekly'' means once every 168 unit or stack operating hours. ``Quarterly'' means once every QA operating
  quarter. ``Semiannual'' means once every two QA operating quarters. ``Annual'' means once every four QA operating quarters.
** The system integrity check applies only to Hg monitors with converters. The single-point weekly system integrity check is not required if daily
  calibrations are performed using a NIST-traceable source of oxidized Hg. The 3-point quarterly system integrity check is not required if a linearity
  check is performed.
\1\ Conduct RATA annually (i.e., once every four QA operating quarters), if monitor meets accuracy requirements to qualify for less frequent testing.
\2\ For flow monitors installed on peaking units, bypass stacks, or units that qualify for single-level RATA testing under section 6.5.2(e) of this
  part, conduct all RATAs at a single, normal load (or operating level). For other flow monitors, conduct annual RATAs at two load levels (or operating
  levels). Alternating single-load and 2-load (or single-level and 2-level) RATAs may be done if a monitor is on a semiannual frequency. A single-load
  (or single-level) RATA may be done in lieu of a 2-load (or 2-level) RATA if, since the last annual flow RATA, the unit has operated at one load level
  (or operating level) for >=85.0 percent of the time. A 3-level RATA is required at least once every five calendar years and whenever a flow monitor is
  re-linearized, except for flow monitors exempted from 3-level RATA testing under section 6.5.2(b) or 6.5.2(e) of appendix A to this part.

  Figure 2 to Appendix B of Part 75.--Relative Accuracy Test Frequency
                            Incentive System
------------------------------------------------------------------------
                                  Semiannual W
            RATA                    (percent)             Annual W
------------------------------------------------------------------------
SO2 or NOXY.................  7.5% < RA < =10.0% or   RA < = 7.5% or < plus-
                               15.0      minus>12.0 ppm X.
                               ppm X.
SO2-diluent.................  7.5% < RA < =10.0% or   RA < =7.5% or < plus-
                               0.030     minus>0.025 lb/
                               lb/mmBtu X.           mmBtu =G5X.
NOX-diluent.................  7.5% < RA < =10.0% or   RA < = 7.5% or < plus-
                               0.020     minus>0. 015 lb/
                               lb/mmBtu X.           mmBtu X.
Flow........................  7.5% <  RA < = 10.0%    RA < = 7.5% or < plus-
                               or 2.0    minus>1.5 fps X.
                               fps X.
CO2 or O2...................  7.5% <  RA < = 10.0%    RA < = 7.5% or < plus-
                               or 1.0%   minus>0.7% CO2/O2X.
                               CO2/O2 X.
Hg X........................  N/A.................  RA <  20.0% or < plus-
                                                     minus> 1.0 [mu]g/
                                                     scm X.
Moisture....................  7.5% < RA < =10.0% or   RA < =7.5% or < plus-
                               1.5%      minus>1.0% H2O X.
                               H2O X.
------------------------------------------------------------------------
W The deadline for the next RATA is the end of the second (if
  semiannual) or fourth (if annual) successive QA operating quarter
  following the quarter in which the CEMS was last tested. Exclude
  calendar quarters with fewer than 168 unit operating hours (or, for
  common stacks and bypass stacks, exclude quarters with fewer than 168
  stack operating hours) in determining the RATA deadline. For SO2
  monitors, QA operating quarters in which only very low sulfur fuel as
  defined in Sec.   72.2, is combusted may also be excluded. However,
  the exclusion of calendar quarters is limited as follows: the deadline
  for the next RATA shall be no more than 8 calendar quarters after the
  quarter in which a RATA was last performed.
X The difference between monitor and reference method mean values
  applies to moisture monitors, CO2, and O2 monitors, low emitters of
  SO2, NOX, or Hg, or and low flow, only. The specifications for Hg
  monitors also apply to sorbent trap monitoring systems.
Y A NOX concentration monitoring system used to determine NOX mass
  emissions under Sec.   75.71.

0
42. Appendix D to Part 75 is amended by:
0
a. Revising section <IP_ADDRESS>;
0
b. Removing all ``'' symbols from paragraph (c) of section
<IP_ADDRESS>;
0
c. Revising the Rbase and Lavg variable
definitions in paragraph (a) of section <IP_ADDRESS>;
0
d. Revising the terms ``(GHR) base'' and ``Lavg''
in paragraph (c) of section <IP_ADDRESS>;
0
e. Revising the terms ``Rh'' and ``Lh'' in
paragraph (a) of section <IP_ADDRESS>;
0
f. Revising the terms ``(GHR) h'' and ``Lh'' in
paragraph (c) of section <IP_ADDRESS>;
0
g. Removing ``D4177-82 (Reapproved 1990)'' and adding in its place
``D4177-95 (Reapproved 2000)'', in the first sentence of section 2.2.3;
0
h. Removing ``D4057-88 `Standard Practice for Manual Sampling of
Petroleum and Petroleum Products' (incorporated by reference under
Sec.  75.6)'' and adding in its place, ``ASTM D4057-95 (Reapproved
2000), Standard Practice for Manual Sampling of Petroleum and Petroleum
Products

(incorporated by reference under Sec.  75.6 of this part)'', in
sections <IP_ADDRESS> and <IP_ADDRESS>, and in paragraph (c) of section <IP_ADDRESS>;
0
i. Revising sections 2.2.5, 2.2.6, and 2.2.7;
0
j. Revising paragraphs (a)(2) and (e) of section <IP_ADDRESS>;
0
k. Revising section <IP_ADDRESS>.2;
0
l. Revising section 2.3.4;
0
m. Adding two sentences at the end of section <IP_ADDRESS>;
0
n. Revising paragraphs (b)(2) and (c) of section 2.3.7;
0
o. Revising section 3.2.2; and
0
p. Revising section 3.5.1.
    The revisions and additions read as follows:

Appendix D to Part 75--Optional SO2 Emissions Data Protocol
for Gas-Fired and Oil-Fired Units.

* * * * *

2. Procedure

* * * * *
    <IP_ADDRESS> Use the procedures in the following standards to verify
flowmeter accuracy or design, as appropriate to the type of
flowmeter: ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes
Using Orifice, Nozzle, and Venturi; ASME MFC-4M-1986 (Reaffirmed
1997), Measurement of Gas Flow by Turbine Meters; American Gas
Association Report No. 3, Orifice Metering of Natural Gas and Other
Related Hydrocarbon Fluids Part 1: General Equations and Uncertainty
Guidelines (October 1990 Edition), Part 2: Specification and
Installation Requirements (February 1991 Edition), and Part 3:
Natural Gas Applications (August 1992 edition) (excluding the
modified flow-calculation method in part 3); Section 8, Calibration
from American Gas Association Transmission Measurement Committee
Report No. 7: Measurement of Gas by Turbine Meters (Second Revision,
April 1996); ASME-MFC-5M-1985, (Reaffirmed 1994), Measurement of
Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic
Flowmeters; ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes
Using Vortex Flowmeters; ASME MFC-7M-1987 (Reaffirmed 1992),
Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles;
ISO 8316: 1987(E) Measurement of Liquid Flow in Closed Conduits-
Method by Collection of the Liquid in a Volumetric Tank; American
Petroleum Institute (API) Manual of Petroleum Measurement Standards,
Chapter 4--Proving Systems, Section 2--Pipe Provers (Provers
Accumulating at Least 10,000 Pulses), Second Edition, March 2001,
and Section 5--Master-Meter Provers, Second Edition, May 2000;
American Petroleum Institute (API) Manual of Petroleum Measurement
Standards, Chapter 22--Testing Protocol, Section 2--Differential
Pressure Flow Measurement Devices, First Edition, August 2005; or
ASME MFC-9M-1988 (Reaffirmed 2001), Measurement of Liquid Flow in
Closed Conduits by Weighing Method, for all other flowmeter types
(all incorporated by reference under Sec.  75.6 of this part). The
Administrator may also approve other procedures that use equipment
traceable to National Institute of Standards and Technology
standards. Document such procedures, the equipment used, and the
accuracy of the procedures in the monitoring plan for the unit, and
submit a petition signed by the designated representative under
Sec.  75.66(c). If the flowmeter accuracy exceeds 2.0 percent of the
upper range value, the flowmeter does not qualify for use under this
part.
* * * * *
    <IP_ADDRESS>
    (a) * * *

Where:

Rbase = Value of the fuel flow rate-to-load ratio during
the baseline period; 100 scfh/MWe, 100 scfh/klb per hour steam load,
or 100 scfh/mmBtu per hour thermal output for gas-firing; (lb/hr)/
MWe, (lb/hr)/klb per hour steam load, or (lb/hr)/mmBtu per hour
thermal output for oil-firing.
* * * * *
Lavg = Arithmetic average unit load during the baseline
period, megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output.
* * * * *
    (c) * * *

Where:

(GHR)base = Baseline value of the gross heat rate during
the baseline period, Btu/kwh, Btu/lb steam load, or 1000mmBtu heat
input/mmBtu thermal output.
* * * * *
Lavg = Average (mean) unit load during the baseline
period, megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output.
* * * * *
    <IP_ADDRESS>
    (a) * * *

Where:

Rh = Hourly value of the fuel flow rate-to-load ratio;
100 scfh/MWe, (lb/hr)/MWe, 100 scfh/1000 lb/hr of steam load, (lb/
hr)/1000 lb/hr of steam load, 100 scfh/(mmBtu/hr of steam load), or
(lb/hr)/(mmBtu/hr thermal output).
* * * * *
Lh = Hourly unit load, megawatts, 1000 lb/hr of steam, or
mmBtu/hr thermal output.
* * * * *
    (c) * * *

Where:

(GHR)h = Hourly value of the gross heat rate, Btu/kwh,
Btu/lb steam load, or mmBtu heat input/mmBtu thermal output.
* * * * *
Lh = Hourly unit load, megawatts, 1000 lb/hr of steam, or
mmBtu/hr thermal output.
* * * * *
    2.2.5 For each oil sample that is taken on-site at the affected
facility, split and label the sample and maintain a portion (at
least 200 cc) of it throughout the calendar year and in all cases
for not less than 90 calendar days after the end of the calendar
year allowance accounting period. This requirement does not apply to
oil samples taken from the fuel supplier's storage container, as
described in section <IP_ADDRESS> of this appendix. Analyze oil samples
for percent sulfur content by weight in accordance with ASTM D129-
00, Standard Test Method for Sulfur in Petroleum Products (General
Bomb Method), ASTM D1552-01, Standard Test Method for Sulfur in
Petroleum Products (High-Temperature Method), ASTM D2622-98,
Standard Test Method for Sulfur in Petroleum Products by Wavelength
Dispersive X-ray Fluorescence Spectrometry, ASTM D4294-98, Standard
Test Method for Sulfur in Petroleum and Petroleum Products by
Energy-Dispersive X-ray Fluorescence Spectrometry, or ASTM D5453-06,
Standard Test Method for Determination of Total Sulfur in Light
Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and
Engine Oil by Ultraviolet Fluorescence (all incorporated by
reference under Sec.  75.6 of this part). Alternatively, the oil
samples may be analyzed for percent sulfur by any consensus standard
method prescribed for the affected unit under part 60 of this
chapter.
    2.2.6 Where the flowmeter records volumetric flow rate rather
than mass flow rate, analyze oil samples to determine the density or
specific gravity of the oil. Determine the density or specific
gravity of the oil sample in accordance with ASTM D287-92
(Reapproved 2000), Standard Test Method for API Gravity of Crude
Petroleum and Petroleum Products (Hydrometer Method), ASTM D1217-93
(Reapproved 1998), Standard Test Method for Density and Relative
Density (Specific Gravity) of Liquids by Bingham Pycnometer, ASTM
D1481-93 (Reapproved 1997), Standard Test Method for Density and
Relative Density (Specific Gravity) of Viscous Materials by Lipkin
Bicapillary Pycnometer, ASTM D1480-93 (Reapproved 1997), Standard
Test Method for Density and Relative Density (Specific Gravity) of
Viscous Materials by Bingham Pycnometer, ASTM D1298-99, Standard
Test Method for Density, Relative Density (Specific Gravity), or API
Gravity of Crude Petroleum and Liquid Petroleum Products by
Hydrometer Method, or ASTM D4052-96 (Reapproved 2002), Standard Test
Method for Density and Relative Density of Liquids by Digital
Density Meter (all incorporated by reference under Sec.  75.6 of
this part). Alternatively, the oil samples may be analyzed for
density or specific gravity by any consensus standard method
prescribed for the affected unit under part 60 of this chapter.
    2.2.7 Analyze oil samples to determine the heat content of the
fuel. Determine oil heat content in accordance with ASTM D240-00,
Standard Test Method for Heat of Combustion of Liquid Hydrocarbon
Fuels by Bomb Calorimeter, ASTM D4809-00, Standard Test Method for
Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter
(Precision Method), or ASTM D5865-01a, Standard Test Method for
Gross Calorific Value of Coal and Coke (all incorporated by
reference under Sec.  75.6 of this part) or any other procedures
listed in section 5.5 of appendix F of this part. Alternatively,

the oil samples may be analyzed for heat content by any consensus
standard method prescribed for the affected unit under part 60 of
this chapter.
* * * * *
    <IP_ADDRESS> * * *
    (a) * * *
    (2) Historical fuel sampling data for the previous 12 months,
documenting the total sulfur content of the fuel and the GCV and/or
percentage by volume of methane. The results of all sample analyses
obtained by or provided to the owner or operator in the previous 12
months shall be used in the demonstration, and each sample result
must meet the definition of pipeline natural gas in Sec.  72.2 of
this chapter, except where the results of at least 100 daily (or
more frequent) total sulfur samples are provided by the fuel
supplier. In that case you may opt to convert these data to monthly
averages and then if, for each month, the average total sulfur
content is 0.5 grains/100 scf or less, and if the GCV or percent
methane requirement is also met, the fuel qualifies as pipeline
natural gas. Alternatively, the fuel qualifies as pipeline natural
gas if [gteqt] 98 percent of the 100 (or more) samples have a total
sulfur content of 0.5 grains/100 scf or less and if the GCV or
percent methane requirement is also met; or
* * * * *
    (e) If a fuel qualifies as pipeline natural gas based on the
specifications in a fuel contract or tariff sheet, no additional,
on-going sampling of the fuel's total sulfur content is required,
provided that the contract or tariff sheet is current, valid and
representative of the fuel combusted in the unit. If the fuel
qualifies as pipeline natural gas based on fuel sampling and
analysis, on-going sampling of the fuel's sulfur content is required
annually and whenever the fuel supply source changes. For the
purposes of this paragraph (e), sampling ``annually'' means that at
least one sample is taken in each calendar year. If the results of
at least 100 daily (or more frequent) total sulfur samples have been
provided by the fuel supplier since the last annual assessment of
the fuel's sulfur content, the data may be used as follows to
satisfy the annual sampling requirement for the current year. If
this option is chosen, all of the data provided by the fuel supplier
shall be used. First, convert the data to monthly averages. Then,
if, for each month, the average total sulfur content is 0.5 grains/
100 scf or less, and if the GCV or percent methane requirement is
also met, the fuel qualifies as pipeline natural gas. Alternatively,
the fuel qualifies as pipeline natural gas if the analysis of the
100 (or more) total sulfur samples since the last annual assessment
shows that [gteqt] 98 percent of the samples have a total sulfur
content of 0.5 grains/100 scf or less and if the GCV or percent
methane requirement is also met. The effective date of the annual
total sulfur sampling requirement is January 1, 2003.
* * * * *
    <IP_ADDRESS>.2 Use one of the following methods when using manual
sampling (as applicable to the type of gas combusted) to determine
the sulfur content of the fuel: ASTM D1072-06, Standard Test Method
for Total Sulfur in Fuel Gases by Combustion and Barium Chloride
Titration, ASTM D4468-85 (Reapproved 2006), Standard Test Method for
Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric
Colorimetry, ASTM D5504-01, Standard Test Method for Determination
of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas
Chromatography and Chemiluminescence, ASTM D6667-04, Standard Test
Method for Determination of Total Volatile Sulfur in Gaseous
Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet
Fluorescence, or ASTM D3246-96, Standard Test Method for Sulfur in
Petroleum Gas by Oxidative Microcoulometry, (all incorporated by
reference under Sec.  75.6 of this part). Alternatively, the gas
samples may be analyzed for percent sulfur by any consensus standard
method prescribed for the affected unit under part 60 of this
chapter.
* * * * *
    2.3.4 Gross Calorific Values for Gaseous Fuels
    Determine the GCV of each gaseous fuel at the frequency
specified in this section, using one of the following methods: ASTM
D1826-94 (Reapproved 1998), ASTM D3588-98, ASTM D4891-89 (Reapproved
2006), GPA Standard 2172-96, Calculation of Gross Heating Value,
Relative Density and Compressibility Factor for Natural Gas Mixtures
from Compositional Analysis, or GPA Standard 2261-00, Analysis for
Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (all
incorporated by reference under Sec.  75.6 of this part). Use the
appropriate GCV value, as specified in section <IP_ADDRESS>, <IP_ADDRESS>, or
<IP_ADDRESS> of this appendix, in the calculation of unit hourly heat
input rates. Alternatively, the gas samples may be analyzed for heat
content by any consensus standard method prescribed for the affected
unit under part 60 of this chapter.
    <IP_ADDRESS> GCV of Pipeline Natural Gas
    * * * If multiple GCV samples are taken and analyzed in a
particular month, the GCV values from all samples shall be averaged
arithmetically to obtain the monthly GCV. Then, apply the monthly
average GCV value as described in paragraph (c) in section 2.3.7 of
this appendix.
* * * * *
    2.3.7 * * *
    (b) * * *
    (2) For natural gas, if only one sample is taken, apply the
results beginning at the date on which the sample was taken. If
multiple samples are taken and averaged, apply the results beginning
at the date on which the last sample used in the annual assessment
was taken;
* * * * *
    (c) For monthly samples of the fuel GCV:
    (1) If the actual monthly value is to be used in the
calculations and only one sample is taken, apply the results
starting from the date on which the sample was taken. If multiple
samples are taken and averaged, apply the monthly average GCV value
to the entire month; or
    (2) If an assumed value (contract maximum or highest value from
previous year's samples) is to be used in the calculations, apply
the assumed value to all hours in each month of the quarter unless a
higher value is obtained in a monthly GCV sample (or, if multiple
samples are taken and averaged, if the monthly average exceeds the
assumed value). In that case, if only one monthly sample is taken,
use the sampled value, starting from the date on which the sample
was taken. If multiple samples are taken and averaged, use the
average value for the entire month in which the assumed value was
exceeded. Consider the sample (or, if applicable, monthly average)
results to be the new assumed value. Continue using the new assumed
value unless and until one of the following occurs (as applicable to
the reporting option selected): The assumed value is superseded by a
higher value from a subsequent monthly sample (or by a higher
monthly average); or the assumed value is superseded by a new
contract in which case the new contract value becomes the assumed
value at the time the fuel specified under the new contract begins
to be combusted in the unit; or both the calendar year in which the
new sampled value (or monthly average) exceeded the assumed value
and the subsequent calendar year have elapsed.
* * * * *
    3.2.2 Convert density, specific gravity, or API gravity of the
oil sample to density of the oil sample at the sampling location's
temperature using ASTM D1250-07, Standard Guide for Use of the
Petroleum Measurement Tables (incorporated by reference under (Sec.
75.6 of this part).
* * * * *
    3.5.1 Hourly SO2 Mass Emissions from the Combustion
of all Fuels. Determine the total mass emissions for each hour from
the combustion of all fuels using Equation D-12 (On and after
January 1, 2009, determine the total mass emission rate (in lbs/hr)
for each hour from the combustion of all fuels by dividing Equation
D-12 by the actual unit operating time for the hour):
[GRAPHIC] [TIFF OMITTED] TR24JA08.019

Where:
MSO2-hr = Total mass of SO2 emissions from all
fuels combusted during the hour, lb.
SO2 rate-I = SO2 mass emission rate for each
type of gas or oil fuel combusted during the hour, lb/hr.
ti = Time each gas or oil fuel was combusted for the hour (fuel
usage time), fraction of an hour (in equal increments that can

range from one hundredth to one quarter of an hour, at the option of
the owner or operator).
* * * * *

0
43. Appendix E to part 75 is amended by:
0
a. Adding a new sentence to the end of section 2.1;
0
b. Revising the seventh sentence of section <IP_ADDRESS>;
0
c. Revising sections <IP_ADDRESS> and <IP_ADDRESS>;
0
d. Removing the phrase ``(MWge or steam load in 1000 lb/hr)'' and
adding in its place the phrase ``(MWge or steam load in 1000 lb/hr, or
mmBtu/hr thermal output)'', in section 2.4.1;
0
e. Revising section 2.5.2; and
0
f. Adding section <IP_ADDRESS>.
    The revisions and additions read as follows:

Appendix E to Part 75--Optional NOX Emissions Estimation
Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units

* * * * *
    2.1 Initial Performance Testing
    * * * The requirements in section 6.1.2 of appendix A to this
part shall be met by any Air Emissions Testing Body (AETB)
performing O2 and NOX concentration
measurements under this appendix, either for units using the
excepted methodology in this appendix or for units using the low
mass emissions excepted methodology in Sec.  75.19.
* * * * *
    <IP_ADDRESS> * * * Use a minimum of 12 sample points, located
according to Method 1 in appendix A-1 to part 60 of this chapter.
* * * * *
    <IP_ADDRESS> For stationary gas turbines, sample at a minimum of 12
points per run at each load level. Locate the sample points
according to Method 1 in appendix A-1 to part 60 of this chapter.
For each fuel or consistent combination of fuels (and, optionally,
for each combination of fuels), measure the NOX and
O2 concentrations at each sampling point using methods 7E
and 3A in appendices A-4 and A-2 to part 60 of this chapter. For
diesel or dual fuel reciprocating engines, select the sampling site
to be as close as practicable to the exhaust of the engine.
    <IP_ADDRESS> Allow the unit to stabilize for a minimum of 15 minutes
(or longer if needed for the NOX and O2
readings to stabilize) prior to commencing NOX,
O2, and heat input measurements. Determine the
measurement system response time according to sections 8.2.5 and
8.2.6 of method 7E in appendix A-4 to part 60 of this chapter. When
inserting the probe into the flue gas for the first sampling point
in each traverse, sample for at least one minute plus twice the
measurement system response time (or longer, if necessary to obtain
a stable reading). For all other sampling points in each traverse,
sample for at least one minute plus the measurement system response
time (or longer, if necessary to obtain a stable reading). Perform
three test runs at each load condition and obtain an arithmetic
average of the runs for each load condition. During each test run on
a boiler, record the boiler excess oxygen level at 5 minute
intervals.
* * * * *
    2.5.2 Substitute missing NOX emission rate data using
the highest NOX emission rate tabulated during the most
recent set of baseline correlation tests for the same fuel or, if
applicable, combination of fuels, except as provided in sections
<IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, and <IP_ADDRESS> of this appendix.
* * * * *
    <IP_ADDRESS> Whenever 20 full calendar quarters have elapsed
following the quarter of the last baseline correlation test for a
particular type of fuel (or fuel mixture), without a subsequent
baseline correlation test being done for that type of fuel (or fuel
mixture), substitute the fuel-specific NOX MER (as
defined in Sec.  72.2 of this chapter) for each hour in which that
fuel (or mixture) is combusted until a new baseline correlation test
for that fuel (or mixture) has been successfully completed. For fuel
mixtures, report the highest of the individual MER values for the
components of the mixture.
* * * * *

0
44. Appendix F to Part 75 is amended by:
0
a. Removing the second and third sentences from the introductory text
of section 2;
0
b. Removing the phrase ``method 19 in appendix A of part 60 of this
chapter'' and adding in its place the phrase ``Method 19 in appendix A-
7 to part 60 of this chapter'', in the last sentence of section 3.1 and
in the last sentence of section 3.2;
0
c. Adding the phrase ``, or (if applicable) in the equations in Method
19 in appendix A-7 to part 60 of this chapter'' after the words ``of
this appendix'', in section 3.3;
0
d. Removing the second and third sentences from section 3.3.4;
0
e. Adding sections <IP_ADDRESS> and <IP_ADDRESS>;
0
f. Revising Table 1;
0
g. Revising the text preceding Equation F-7a, in section 3.3.6;
0
h. Revising section <IP_ADDRESS>;
0
i. Revising section <IP_ADDRESS>;
0
j. Revising sections <IP_ADDRESS> and <IP_ADDRESS>;
0
k. Adding section <IP_ADDRESS>;
0
l. Adding the words ``either measured directly with a CO2
monitor or calculated from wet-basis O2 data using Equation
F-14b,'' after the words ``wet basis,'' in the first sentence of the
Ch variable definition, and by removing the second and third
sentences from the Ch variable definition, in section 4.1;
0
m. Revising section 4.4.1;
0
n. Removing the second and third sentences from the %CO2w
variable definition in 5.2.1;
0
o. Removing the second and third sentences from the %CO2d
variable definition in 5.2.2;
0
p. Removing the second and third sentences from the %O2w
variable definition, and by adding a new sentence at the end of the
paragraph, in section 5.2.3;
0
q. Removing the second and third sentences from the %O2d
variable definition, in section 5.2.4;
0
r. Revising the definition of ``GCVo'' in paragraph (a) of
section 5.5.1;
0
s. Revising the definition of ``GCVg'' in section 5.5.2;
0
t. Revising section <IP_ADDRESS>;
0
u. Revising section <IP_ADDRESS>;
0
v. Removing the phrase ``as measured by ASTM D3176-89, D1989-92, D3286-
91a, or D2015-91, Btu/lb'' and adding in its place the phrase ``as
measured by ASTM D3176-89 (Reapproved 2002), or ASTM D5865-01a, Btu/lb.
(incorporated by reference under Sec.  75.6 of this part).'' in the
definition of the GCVc variable in Equation F-21;
0
w. Removing the word ``lb/hr'' and adding in its place the phrase ``lb/
hr, or mmBtu/hr'' in the definition of the SF variable in Equation F-
21b;
0
x. Revising the heading and text of section 7;
0
y. Adding the words ``of this appendix'' after the words ``section 8.1,
8.2, or 8.3'' and after the words ``section 8.4'' in the introductory
text for section 8;
0
z. Revising sections 8.1 and 8.1.1;
0
aa. Revising section 8.2;
0
bb. Adding sections 8.2.1 and 8.2.2;
0
cc. Revising section 8.3;
0
dd. Revising section 8.4; and
0
ee. Adding section 10.
    The revisions and additions read as follows:

Appendix F to Part 75--Conversion Procedures.

* * * * *
    3.3.4 * * *
    <IP_ADDRESS> For boilers, a minimum concentration of 5.0 percent
CO2 or a maximum concentration of 14.0 percent O2
may be substituted for the measured diluent gas concentration value
for any operating hour in which the hourly average CO2
concentration is < 5.0 percent CO2 or the hourly average
O2 concentration is > 14.0 percent O2. For
stationary gas turbines, a minimum concentration of 1.0 percent
CO2 or a maximum concentration of 19.0 percent O2
may be substituted for measured diluent gas concentration values for
any operating hour in which the hourly average CO2
concentration is < 1.0 percent CO2 or the hourly average
O2 concentration is > 19.0 percent O2.
    <IP_ADDRESS> If NOX emission rate is calculated using
either Equation 19-3 or 19-5 in Method 19 in appendix A-7 to part 60
of this chapter, a variant of the equation shall be used whenever
the diluent cap is applied. The modified equations shall be
designated as Equations 19-3D and 19-5D, respectively.

Equation 19-3D is structurally the same as Equation 19-3, except
that the term ``%O2w'' in the denominator is replaced
with the term ``%O2dc x [(100-% H2O)/100]'',
where %O2dc is the diluent cap value. The numerator of
Equation 19-5D is the same as Equation 19-5; however, the
denominator of Equation 19-5D is simply ``20.9-%O2dc'',
where %O2dc is the diluent cap value.
* * * * *

                     Table 1.--F- and Fc-Factors \1\
------------------------------------------------------------------------
                                     F-factor (dscf/     FC-factor (scf
               Fuel                       mmBtu)           CO2/mmBtu)
------------------------------------------------------------------------
Coal (as defined by ASTM D388-99
 \2\):
    Anthracite....................             10,100              1,970
    Bituminous....................              9,780              1,800
    Subbituminous.................              9,820              1,840
    Lignite.......................              9,860              1,910
Petroleum Coke....................              9,830              1,850
Tire Derived Fuel.................             10,260              1,800
Oil...............................              9,190              1,420
Gas:
    Natural gas...................              8,710              1,040
    Propane.......................              8,710              1,190
    Butane........................              8,710              1,250
Wood:
    Bark..........................              9,600              1,920
    Wood residue..................              9,240             1,830
------------------------------------------------------------------------
\1\ Determined at standard conditions: 20 [deg]C (68 [deg]F) and 29.92
  inches of mercury.
\2\ Incorporated by reference under Sec.   75.6 of this part.

* * * * *
    3.3.6 Equations F-7a and F-7b may be used in lieu of the F or
Fc factors specified in Section 3.3.5 of this appendix to
calculate a site-specific dry-basis F factor (dscf/mmBtu) or a site-
specific Fc factor (scf CO2/mmBtu), on either
a dry or wet basis. At a minimum, the site-specific F or
Fc factor must be based on 9 samples of the fuel. Fuel
samples taken during each run of a RATA are acceptable for this
purpose. The site-specific F or Fc factor must be re-
determined at least annually, and the value from the most recent
determination must be used in the emission calculations.
Alternatively, the previous F or Fc value may continue to
be used if it is higher than the value obtained in the most recent
determination. The owner or operator shall keep records of all site-
specific F or Fc determinations, active for at least 3
years. (Calculate all F- and Fc factors at standard
conditions of 20 [deg]C (68 [deg]F) and 29.92 inches of mercury).
* * * * *
    <IP_ADDRESS> H, C, S, N, and O are content by weight of hydrogen,
carbon, sulfur, nitrogen, and oxygen (expressed as percent),
respectively, as determined on the same basis as the gross calorific
value (GCV) by ultimate analysis of the fuel combusted using ASTM
D3176-89 (Reapproved 2002), Standard Practice for Ultimate Analysis
of Coal and Coke, (solid fuels), ASTM D5291-02, Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and
Nitrogen in Petroleum Products and Lubricants, (liquid fuels) or
computed from results using ASTM D1945-96 (Reapproved 2001),
Standard Test Method for Analysis of Natural Gas by Gas
Chromatography, or ASTM D1946-90 (Reapproved 2006), Standard
Practice for Analysis of Reformed Gas by Gas Chromatography,
(gaseous fuels) as applicable. (All of these methods are
incorporated by reference under Sec.  75.6 of this part.)
    <IP_ADDRESS> GCV is the gross calorific value (Btu/lb) of the fuel
combusted determined by ASTM D5865-01a, Standard Test Method for
Gross Calorific Value of Coal and Coke, and ASTM D240-00, Standard
Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by
Bomb Calorimeter, or ASTM D4809-00, Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter
(Precision Method) for oil; and ASTM D3588-98, Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density
of Gaseous Fuels, ASTM D4891-89 (Reapproved 2006), Standard Test
Method for Heating Value of Gases in Natural Gas Range by
Stoichiometric Combustion, GPA Standard 2172-96 Calculation of Gross
Heating Value, Relative Density and Compressibility Factor for
Natural Gas Mixtures from Compositional Analysis, GPA Standard 2261-
00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas
Chromatography, or ASTM D1826-94 (Reapproved 1998), Standard Test
Method for Calorific (Heating) Value of Gases in Natural Gas Range
by Continuous Recording Calorimeter, for gaseous fuels, as
applicable. (All of these methods are incorporated by reference
under Sec.  75.6 of this part).
    <IP_ADDRESS> For affected units that combust a combination of a fuel
(or fuels) listed in Table 1 in section 3.3.5 of this appendix with
any fuel(s) not listed in Table 1, the F or Fc value is
subject to the Administrator's approval under Sec.  75.66.
    <IP_ADDRESS> For affected units that combust combinations of fuels
listed in Table 1 in section 3.3.5 of this appendix, prorate the F
or Fc factors determined by section 3.3.5 or 3.3.6 of
this appendix in accordance with the applicable formula as follows:
[GRAPHIC] [TIFF OMITTED] TR24JA08.020

Where,
Xi = Fraction of total heat input derived from each type
of fuel (e.g., natural gas, bituminous coal, wood). Each
Xi value shall be determined from the best available
information on the quantity of fuel combusted and the GCV value,
over a specified time period. The owner or operator shall explain
the method used to calculate Xi in the hardcopy portion
of the monitoring plan for the unit. The Xi values may be
determined and updated either hourly, daily, weekly, or monthly. In
all cases, the prorated F-factor used in the emission calculations
shall be determined using the Xi values from the most
recent update.
Fi or (Fc)i = Applicable F or Fc
factor for each fuel type determined in accordance with Section
3.3.5 or 3.3.6 of this appendix.
n = Number of fuels being combusted in combination.

    <IP_ADDRESS> As an alternative to prorating the F or Fc factor as
described in section <IP_ADDRESS> of this appendix, a ``worst-case'' F or
Fc factor may be reported for any unit operating hour.

The worst-case F or Fc factor shall be the highest F or
Fc value for any of the fuels combusted in the unit.
* * * * *

4. Procedure for CO2 Mass Emissions

* * * * *
    4.4.1 If the owner or operator elects to use data from an
O2 monitor to calculate CO2 concentration, the
appropriate F and FC factors from section 3.3.5 of this
appendix shall be used in one of the following equations (as
applicable) to determine hourly average CO2 concentration
of flue gases (in percent by volume) from the measured hourly
average O2 concentration:
[GRAPHIC] [TIFF OMITTED] TR24JA08.021

Where:
CO2d = Hourly average CO2 concentration during
unit operation, percent by volume, dry basis.
F, FC = F-factor or carbon-based Fc-factor
from section 3.3.5 of this appendix.
20.9 = Percentage of O2 in ambient air.
O2d = Hourly average O2 concentration during
unit operation, percent by volume, dry basis.
[GRAPHIC] [TIFF OMITTED] TR24JA08.022

Where:
CO2w = Hourly average CO2 concentration during
unit operation, percent by volume, wet basis.
O2w = Hourly average O2 concentration during
unit operation, percent by volume, wet basis.
F, Fc = F-factor or carbon-based FC-factor from section
3.3.5 of this appendix.
20.9 = Percentage of O2 in ambient air.
%H2O = Moisture content of gas in the stack, percent.

    For any hour where Equation F-14a or F-14b results in a negative
hourly average CO2 value, 0.0% CO2w shall be
recorded as the average CO2 value for that hour.
* * * * *

5. Procedures for Heat Input

* * * * *
    5.2.3 * * * For any operating hour where Equation F-17 results
in an hourly heat input rate that is < = 0.0 mmBtu/hr, 1.0 mmBtu/hr
shall be recorded and reported as the heat input rate for that hour.
* * * * *
    5.5.1 (a) * * *
    GCVo = Gross calorific value of oil, as measured by
ASTM D240-00, ASTM D5865-01a, or ASTM D4809-00 for each oil sample
under section 2.2 of appendix D to this part, Btu/unit mass (all
incorporated by reference under (Sec.  75.6 of this part).
* * * * *
    5.5.2 * * *
    GCVg = Gross calorific value of gaseous fuel, as
determined by sampling (for each delivery for gaseous fuel in lots,
for each daily gas sample for gaseous fuel delivered by pipeline,
for each hourly average for gas measured hourly with a gas
chromatograph, or for each monthly sample of pipeline natural gas,
or as verified by the contractual supplier at least once every month
pipeline natural gas is combusted, as specified in section 2.3 of
appendix D to this part) using ASTM D1826-94 (Reapproved 1998), ASTM
D3588-98, ASTM D4891-89 (Reapproved 2006), GPA Standard 2172-96
Calculation of Gross Heating Value, Relative Density and
Compressibility Factor for Natural Gas Mixtures from Compositional
Analysis, or GPA Standard 2261-00 Analysis for Natural Gas and
Similar Gaseous Mixtures by Gas Chromatography, Btu/100 scf (all
incorporated by reference under Sec.  75.6 of this part).
* * * * *
    <IP_ADDRESS> Perform coal sampling daily according to section <IP_ADDRESS>
in Method 19 in appendix A to part 60 of this chapter and use ASTM
D2234-00, Standard Practice for Collection of a Gross Sample of
Coal, (incorporated by reference under Sec.  75.6 of this part) Type
I, Conditions A, B, or C and systematic spacing for sampling. (When
performing coal sampling solely for the purposes of the missing data
procedures in Sec.  75.36, use of ASTM D2234-00 is optional, and
coal samples may be taken weekly.)
    <IP_ADDRESS> All ASTM methods are incorporated by reference under
Sec.  75.6 of this part. Use ASTM D2013-01, Standard Practice for
Preparing Coal Samples for Analysis, for preparation of a daily coal
sample and analyze each daily coal sample for gross calorific value
using ASTM D5865-01a, Standard Test Method for Gross Calorific Value
of Coal and Coke. On-line coal analysis may also be used if the on-
line analytical instrument has been demonstrated to be equivalent to
the applicable ASTM methods under Sec. Sec.  75.23 and 75.66.
* * * * *

7. Procedures for SO2 Mass Emissions, Using Default
SO2 Emission Rates and Heat Input Measured by CEMS

    The owner or operator shall use Equation F-23 to calculate
hourly SO2 mass emissions in accordance with Sec.
75.11(e)(1) during the combustion of gaseous fuel, for a unit that
uses a flow monitor and a diluent gas monitor to measure heat input,
and that qualifies to use a default SO2 emission rate
under section <IP_ADDRESS>, <IP_ADDRESS>.1, or 2.3.6(b) of appendix D to this
part. Equation F-23 may also be applied to the combustion of solid
or liquid fuel that meets the definition of very low sulfur fuel in
Sec.  72.2 of this chapter, combinations of such fuels, or mixtures
of such fuels with gaseous fuel, if the owner or operator has
received approval from the Administrator under Sec.  75.66 to use a
site-specific default SO2 emission rate for the fuel or
mixture of fuels.

[GRAPHIC] [TIFF OMITTED] TR24JA08.023

Where:
Eh = Hourly SO2 mass emission rate, lb/hr.
ER = Applicable SO2 default emission rate for gaseous
fuel combustion, from section <IP_ADDRESS>, <IP_ADDRESS>.1, or 2.3.6(b) of
appendix D to this part, or other default SO2 emission
rate for the combustion of very low sulfur liquid or solid fuel,
combinations of such fuels, or mixtures of such fuels with gaseous
fuel, as approved by the Administrator under Sec.  75.66, lb/mmBtu.
HI = Hourly heat input rate, determined using the procedures in
section 5.2 of this appendix, mmBtu/hr.

8. Procedures for NOX Mass Emissions

* * * * *
    8.1 The own or operator may use the hourly NOX
emission rate and the hourly heat input rate to calculate the
NOX mass emissions in pounds or the NOX mass
emission rate in pounds per hour, (as required by the applicable
reporting format), for each unit or stack operating hour, as
follows:
    8.1.1 If both NOX emission rate and heat input rate
are monitored at the same unit or stack level (e.g., the
NOX emission rate value and the heat input rate value
both represent all of the units exhausting to the common stack),
then (as required by the applicable reporting format) either:
    (a) Use Equation F-24 to calculate the hourly NOX
mass emissions (lb).

[GRAPHIC] [TIFF OMITTED] TR24JA08.024

Where:
M(NOX)h = NOX mass emissions in lbs
for the hour.
ER(NOX)h = Hourly average NOX
emission rate for hour h, lb/mmBtu, from section 3 of this appendix,
from Method 19 in

appendix A-7 to part 60 of this chapter, or from section 3.3 of
appendix E to this part. (Include bias-adjusted NOX
emission rate values, where the bias-test procedures in appendix A
to this part shows a bias-adjustment factor is necessary.)
HIh = Hourly average heat input rate for hour h, mmBtu/
hr. (Include bias-adjusted flow rate values, where the bias-test
procedures in appendix A to this part shows a bias-adjustment factor
is necessary.)
th = Monitoring location operating time for hour h, in
hours or fraction of an hour (in equal increments that can range
from one hundredth to one quarter of an hour, at the option of the
owner or operator). If the combined NOX emission rate and
heat input are monitored for all of the units in a common stack, the
monitoring location operating time is equal to the total time when
any of those units was exhausting through the common stack; or
(b) Use Equation F-24a to calculate the hourly NOX mass
emission rate (lb/hr).
[GRAPHIC] [TIFF OMITTED] TR24JA08.025

Where:
E(NOX)h = NOX mass emissions rate
in lbs/hr for the hour.
ER(NOX)h = Hourly average NOX
emission rate for hour h, lb/mmBtu, from section 3 of this appendix,
from Method 19 in appendix A-7 to part 60 of this chapter, or from
section 3.3 of appendix E to this part. (Include bias-adjusted
NOX emission rate values, where the bias-test procedures
in appendix A to this part shows a bias-adjustment factor is
necessary.)
HIh = Hourly average heat input rate for hour h, mmBtu/
hr. (Include bias-adjusted flow rate values, where the bias-test
procedures in appendix A to this part shows a bias-adjustment factor
is necessary.)
* * * * *
    8.2 Alternatively, the owner or operator may use the hourly
NOX concentration (as measured by a NOX
concentration monitoring system) and the hourly stack gas volumetric
flow rate to calculate the NOX mass emission rate (lb/hr)
for each unit or stack operating hour, in accordance with section
8.2.1 or 8.2.2 of this appendix (as applicable). If the hourly
NOX mass emissions are to be reported in lb, Equation F-
26c in section 8.3 of this appendix shall be used to convert the
hourly NOX mass emission rates to hourly NOX
mass emissions (lb).
    8.2.1 When the NOX concentration monitoring system
measures on a wet basis, first calculate the hourly NOX
mass emission rate (in lb/hr) during unit (or stack) operation,
using Equation F-26a. (Include bias-adjusted flow rate or
NOX concentration values, where the bias-test procedures
in appendix A to this part shows a bias-adjustment factor is
necessary.)

[GRAPHIC] [TIFF OMITTED] TR24JA08.026

Where:
E(NOX)h = NOX mass emissions rate
in lb/hr.
K = 1.194 x 10-7 for NOX, (lb/scf)/ppm.
Chw = Hourly average NOX concentration during
unit operation, wet basis, ppm.
Qh = Hourly average volumetric flow rate during unit
operation, wet basis, scfh.
    8.2.2 When NOX mass emissions are determined using a
dry basis NOX concentration monitoring system and a wet
basis flow monitoring system, first calculate hourly NOX
mass emission rate (in lb/hr) during unit (or stack) operation,
using Equation F-26b. (Include bias-adjusted flow rate or
NOX concentration values, where the bias-test procedures
in appendix A to this part shows a bias-adjustment factor is
necessary.)
[GRAPHIC] [TIFF OMITTED] TR24JA08.027

Where:
E(NOX)h = NOX mass emissions rate,
lb/hr.
K = 1.194 x 10-7 for NOX, (lb/scf)/ppm.
Chd = Hourly average NOX concentration during
unit operation, dry basis, ppm.
Qh = Hourly average volumetric flow rate during unit
operation, wet basis, scfh.
%H2O = Hourly average stack moisture content during unit
operation, percent by volume.
    8.3 When hourly NOX mass emissions are reported in
pounds and are determined using a NOX concentration
monitoring system and a flow monitoring system, calculate
NOX mass emissions (lb) for each unit or stack operating
hour by multiplying the hourly NOX mass emission rate
(lb/hr) by the unit operating time for the hour, as follows:

[GRAPHIC] [TIFF OMITTED] TR24JA08.028

Where:
M(NOX)h = NOX mass emissions for
the hour, lb.
Eh = Hourly NOX mass emission rate during unit
(or stack) operation from Equation F-26a in section 8.2.1 of this
appendix or Equation F-26b in section 8.2.2 of this appendix (as
applicable), lb/hr.
th = Unit operating time or stack operating time (as
defined in Sec.  72.2 of this chapter) for hour ``h'', in hours or
fraction of an hour (in equal increments that can range from one
hundredth to one quarter of an hour, at the option of the owner or
operator).
    8.4 Use the following procedures to calculate quarterly,
cumulative ozone season, and cumulative yearly NOX mass
emissions, in tons:
    (a) When hourly NOX mass emissions are reported in
lb., use Eq. F-27.
[GRAPHIC] [TIFF OMITTED] TR24JA08.029

Where:
M(NOX)time period = NOX mass
emissions in tons for the given time period (quarter, cumulative
ozone season, cumulative year-to-date).
M(NOX)h = NOX mass emissions in lb
for the hour.
p = The number of hours in the given time period (quarter,
cumulative ozone season, cumulative year-to-date).

    (b) When hourly NOX mass emission rate is reported in
lb/hr, use Eq. F-27a.
[GRAPHIC] [TIFF OMITTED] TR24JA08.030

Where:
M(NOX)time period = NOX mass
emissions in tons for the given time period (quarter, cumulative
ozone season, cumulative year-to-date).
E(NOX)h = NOX mass emission rate in
lb/hr for the hour.
p = The number of hours in the given time period (quarter,
cumulative ozone season, cumulative year-to-date).
th = Monitoring location operating time for hour h, in
hours or fraction of an hour (in equal increments that can range
from one hundredth to one quarter of an hour, at the option of the
owner or operator).
* * * * *

10. Moisture Determination From Wet and Dry O2 Readings

    If a correction for the stack gas moisture content is required
in any of the emissions or heat input calculations described in this
appendix, and if the hourly moisture content is determined from wet-
and dry-basis O2 readings, use Equation F-31 to calculate
the percent moisture, unless a ``K'' factor or other mathematical
algorithm is developed as described in section 6.5.7(a) of appendix
A to this part:
[GRAPHIC] [TIFF OMITTED] TR24JA08.031

Where:
% H2O = Hourly average stack gas moisture content,
percent H2O
O2d = Dry-basis hourly average oxygen concentration,
percent O2
O2w = Wet-basis hourly average oxygen
concentration, percent O2

0
45. Appendix G to Part 75 is amended by:
0
a. Revising section 2.1.2;
0
b. Removing ``D3174-89 `Standard Test Method for Ash in the Analysis
Sample of Coal and Coke From Coal' '' and by adding in its place,
``D3174-00, Standard Test Method for Ash in the Analysis Sample of Coal
and Coke from Coal'' in section 2.2.1; and
0
c. Removing ``D3178-89 (1997), `Standard Test Methods for Carbon and
Hydrogen in the Analysis Sample of Coal and Coke' '' and adding in its
place ``D5373-02 (Reapproved 2007), Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal and Coke'' in section 2.2.2.
    The revisions read as follows:

Appendix G to Part 75--Determination of CO2 Emissions.

* * * * *
    2.1.2 Determine the carbon content of each fuel sample using one
of the following methods: ASTM D3178-89 (Reapproved 2002) or ASTM
D5373-02 (Reapproved 2007) for coal; ASTM D5291-02, Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and
Nitrogen in Petroleum Products and Lubricants, ultimate analysis of
oil, or computations based upon ASTM D3238-95 (Reapproved 2000) and
either ASTM D2502-92 (Reapproved 1996) or ASTM D2503-92 (Reapproved
1997) for oil; and computations based on ASTM D1945-96 (Reapproved
2001) or ASTM D1946-90 (Reapproved 2006) for gas (all incorporated
by reference under Sec.  75.6 of this part).
* * * * *

0
46. Appendix K to Part 75 is amended by:
0
a. Removing the words ``(see Sec. Sec.  75.11(b) and 75.12(b))'' and
adding in its place the words ``(see Sec.  75.11(b))'' in section 5;
0
b. Adding a sentence to the end of section 7.2.3;
0
c. Removing the words ``or Sec.  75.12(b)'' and ``or Sec.  75.12,''
from section 7.2.4;
0
d. Revising Table K-1 of section 8; and
0
e. Adding the words ``or in Table K-1'' following the words ``Sec.
75.15(h)'' in the second sentence of section 11.8.
    The revisions and additions read as follows:

Appendix K to Part 75--Quality Assurance and Operating Procedures for
Sorbent Trap Monitoring Systems

* * * * *
    7.2.3 * * * The sample flow rate through a sorbent trap
monitoring system during any hour (or portion of an hour) in which
the unit is not operating shall be zero.
* * * * *

           Table K-1.--Quality Assurance/Quality Control Criteria for Sorbent Trap Monitoring Systems
----------------------------------------------------------------------------------------------------------------
   QA/QC test or specification        Acceptance criteria             Frequency          Consequences if not met
----------------------------------------------------------------------------------------------------------------
Pre-test leak check..............  < =4% of target sampling    Prior to sampling.......  Sampling shall not
                                    rate.                                                commence until the leak
                                                                                check is passed.
Post-test leak check.............  < =4% of average sampling   After sampling..........  ** See Note, below.
                                    rate.
Ratio of stack gas flow rate to    No more than 5% of the     Every hour throughout     ** See Note, below.
 sample flow rate.                  hourly ratios or 5         data collection period.
                                    hourly ratios (whichever
                                    is less restrictive) may
                                    deviate from the
                                    reference ratio by more
                                    than  25%.
Sorbent trap section 2 break-      < =5% of Section 1 Hg mass  Every sample............  ** See Note, below.
 through.
Paired sorbent trap agreement....  < =10% Relative Deviation   Every sample............  Either invalidate the
                                    (RD) if the average                                  data from the paired
                                    concentration is > 1.0                               traps or report the
                                    [mu]g/m\3\.                                          results from the trap
                                   < = 20% RD if the average                              with the higher Hg
                                    concentration is < = 1.0                              concentration.
                                    [mu]g/m\3\.
                                   Results are also
                                    acceptable if absolute
                                    difference between
                                    concentrations from
                                    paired traps is < = 0.03
                                    [mu]g/m\3\.
Spike Recovery Study.............  Average recovery between   Prior to analyzing field  Field samples shall not
                                    85% and 115% for each of   samples and prior to      be analyzed until the
                                    the 3 spike                use of new sorbent        percent recovery
                                    concentration levels.      media.                    criteria has been met
Multipoint analyzer calibration..  Each analyzer reading      On the day of analysis,   Recalibrate until
                                    within  10%    before analyzing any      successful.
                                    of true value and r\2\     samples.
                                    >= 0.99.

Analysis of independent            Within  10%    Following daily           Recalibrate and repeat
 calibration standard.              of true value.             calibration, prior to     independent standard
                                                               analyzing field samples.  analysis until
                                                                                successful.
Spike recovery from section 3 of   75-125% of spike amount..  Every sample............  ** See Note, below.
 sorbent trap.
RATA.............................  RA < = 20.0% or Mean        For initial               Data from the system are
                                    difference < = 1.0 [mu]g/   certification and         invalidated until a
                                    dscm for low emitters.     annually thereafter.      RATA is passed.
Gas flow meter calibration.......  Calibration factor (Y)     At three settings prior   Recalibrate the meter at
                                    within  5%     to initial use and at     three orifice settings
                                    of average value from      least quarterly at one    to determine a new
                                    the most recent 3-point    setting thereafter. For   value of Y.
                                    calibration.               mass flow meters,
                                                               initial calibration
                                                               with stack gas is
                                                               required.
Temperature sensor calibration...  Absolute temperature       Prior to initial use and  Recalibrate. Sensor may
                                    measured by sensor         at least quarterly        not be used until
                                    within  1.5%   thereafter.               specification is met.
                                    of a reference sensor.
Barometer calibration............  Absolute pressure          Prior to initial use and  Recalibrate. Instrument
                                    measured by instrument     at least quarterly        may not be used until
                                    within  10     thereafter.               specification is met.
                                    mm Hg of reading with a
                                    mercury barometer.
----------------------------------------------------------------------------------------------------------------
** Note: If both traps fail to meet the acceptance criteria, the data from the pair of traps are invalidated.
  However, if only one of the paired traps fails to meet this particular acceptance criterion and the other
  sample meets all of the applicable QA criteria, the results of the valid trap may be used for reporting under
  this part, provided that the measured Hg concentration is multiplied by a factor of 1.111. When the data from
  both traps are invalidated and quality-assured data from a certified backup monitoring system, reference
  method, or approved alternative monitoring system are unavailable, missing data substitution must be used.

* * * * *
[FR Doc. E7-25071 Filed 1-23-08; 8:45 am]

BILLING CODE 6560-50-P


[Federal Register Volume 76, Number 102 (Thursday, May 26, 2011)]
[Proposed Rules]
[Page 30604]
[FR Doc No: 2011-13006]

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

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-R01-OAR-2010-1080; A-1-FRL-9311-1]

Approval of the Clean Air Act, Section 112(l), Authority for
Hazardous Air Pollutants: Perchloroethylene Air Emission Standards for
Dry Cleaning Facilities: State of Maine Department of Environmental
Protection

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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

SUMMARY: EPA proposes to approve Maine Department of Environmental
Protection's (``ME DEP'') request to implement and enforce the amended
Chapter 125 Perchloroethylene Dry Cleaner Regulation as a partial
substitution for the amended National Emissions Standards for Hazardous
Air Pollutants for Perchloroethylene Dry Cleaning Facilities (``Dry
Cleaning NESHAP''), as it applies to area sources. This approval would
make the ME DEP's amended rule federally enforceable. Major sources and
dry cleaners installed in a residence between July 13, 2006 and June
24, 2009 would remain subject to the Federal Dry Cleaning NESHAP.

DATES: Written comments must be received on or before June 27, 2011.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R01-
OAR-2010-1080 by one of the following methods:
    1. http://www.regulations.gov: Follow the on-line instructions for
submitting comments.
    2. E-mail<EMAIL_ADDRESS>    3. Fax:<PHONE_NUMBER>.
    4. Mail: ``EPA-R01-OAR-2010-1080,'' Ida E. McDonnell, U.S.
Environmental Protection Agency, EPA New England Regional Office, Five
Post Office Square, Suite 100 (OEP05-2), Boston, MA 02109-3912.
    5. Hand Delivery or Courier. Deliver your comments to: Ida E.
McDonnell, Manager, Air Permits, Toxics and Indoor Programs Unit,
Office of Ecosystem Protection, U.S. Environmental Protection Agency,
EPA New England Regional Office, Five Post Office Square, 5th Floor,
Suite 100 (OEP05-2), Boston, MA 02109-3912. Such deliveries are only
accepted during the Regional Office's normal hours of operation. The
Regional Office's official hours of business are Monday through Friday,
8:30 to 4:30, excluding legal holidays.
    Please see the direct final rule which is located in the Rules
Section of this Federal Register for detailed instructions on how to
submit comments. EPA will forward copies of all submitted comments to
the Maine Department of Environmental Protection.

FOR FURTHER INFORMATION CONTACT: Susan Lancey, Air Permits, Toxics and
Indoor Programs Unit, Office of Ecosystem Protection, U.S.
Environmental Protection Agency, EPA New England Regional Office, Five
Post Office Square, Suite 100 (OEP05-2), Boston, MA 02109-3912,
telephone number<PHONE_NUMBER>, fax number<PHONE_NUMBER>, e-mail
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: In the Final Rules Section of this Federal
Register, EPA is approving the State of Maine's Section 112(l)
submittal as a direct final rule without prior proposal because the
Agency views this as a noncontroversial submittal and anticipates no
adverse comments. A detailed rationale for the approval is set forth in
the direct final rule. If no adverse comments are received in response
to this action rule, no further activity is contemplated. If EPA
receives adverse comments, the direct final rule will be withdrawn and
all public comments received will be addressed in a subsequent final
rule based on this proposed rule. EPA will not institute a second
comment period. Any parties interested in commenting on this action
should do so at this time. Please note that if EPA receives adverse
comment on an amendment, paragraph, or section of this rule and if that
provision may be severed from the remainder of the rule, EPA may adopt
as final those provisions of the rule that are not the subject of an
adverse comment.
    For additional information, see the direct final rule which is
located in the Rules Section of this Federal Register.

    Dated: May 13, 2011.
Ira W. Leighton,
Acting Regional Administrator, EPA New England.
[FR Doc. 2011-13006 Filed 5-25-11; 8:45 am]
BILLING CODE 6560-50-P