No adverse comments were received. These corrections have been
finalized, as proposed.

I. Appendix B

1. 3-Load Flow RATA Frequency and RATA Grace Period
Background
    On May 26, 1999, EPA revised Appendix B of Part 75, to reduce the
required frequency of 3-load flow RATAs from annually to ``at least
once every 5 consecutive calendar years''. As written, this rule
provision actually allows more than five years (20 calendar quarters)
to elapse between 3-load flow RATAs. For instance, if successive 3-load
flow RATAs are performed in the 1st quarter of 2002 and in the 4th
quarter of 2007, this satisfies the ``once every 5 consecutive calendar
years'' requirement, but there would be 23 calendar quarters between
the two tests.
    In light of this, EPA proposed to revise Section <IP_ADDRESS>(c)(4) of
Appendix B, to require 3-load flow RATAs to be done at least once every
20 calendar quarters. This is consistent with both the other 5-year
testing requirements in Part 75 (i.e., for Appendix E and LME units)
and the maximum allowable interval between successive accuracy tests of
Appendix D fuel flowmeters.
    EPA also proposed to revise the RATA grace period provisions in
Section 2.3.3, by removing the method of determining the deadline for
the next RATA after a grace period test from paragraph (c) of Section
2.3.3 and replacing it with a different method described in new
paragraph (d).
    Paragraph (d) proposed a change to the methodology for determining
RATA deadlines, without changing the end result. The intent of
paragraph (c) in Section 2.3.3 had always been for the source to return
to its original RATA schedule following a grace period test, in order
to prevent the grace period provisions from being abused. However, for
infrequently operated units (e.g., many combustion turbines), the grace
period sometimes spans across many calendar quarters, which effectively
eliminates the possibility of establishing a meaningful relationship
between the original RATA due date and the deadline for the next test.
    In view of these considerations, EPA proposed a simpler methodology
for determining RATA deadlines that will work for both base load units
and combustion turbines that seldom operate. The deadline for the next
RATA following a grace period test would be two QA operating quarters
after the quarter of the test, if the RATA results trigger a semiannual
test frequency, and three QA operating quarters after the quarter of
the test if the RATA qualifies for an annual test frequency. As
proposed, there was one exception to these rules. Regardless of the
number of QA operating quarters that have elapsed following the grace
period test, the maximum allowable interval between a grace period RATA
and the next RATA would be eight calendar quarters. This is consistent
with Section <IP_ADDRESS>(a) of Appendix B.
    Finally, EPA proposed to amend paragraph (c ) of Section 2.3.3, to
state that when a RATA is performed after the expiration of a grace
period, the ``clock'' is reset, and the deadline for the next RATA is
determined in the usual manner, i.e., the next test would be due within
two QA operating quarters (for semiannual frequency) or four QA
operating quarters (for annual frequency), not to exceed eight calendar
quarters.
Summary of Rule Changes
    Commenters were supportive of the proposed amendments to the RATA
grace period provisions, and no comments were received on the proposal
to determine 3-load flow RATA deadlines on a calendar quarter basis.
Therefore, these provisions have been finalized, as proposed.

2. RATA Requirement for Shared Components
Background
    EPA proposed to amend paragraph (g) in section 2.3.2 of Appendix B,
to specify the consequences of a failed RATA, in the case where a
particular NOX pollutant concentration monitor is a
component of both a NOX concentration monitoring system and
a NOX-diluent monitoring system. In such cases, the Agency
proposed that if the NOX concentration system RATA is
failed, both the NOX concentration monitoring system and the
associated NOX-diluent monitoring system would be considered
out-of-control, and successful RATAs of both monitoring systems would
be required to get them back in-control.
Summary of Rule Changes
    No adverse comments were received. This amendment has been
finalized, as proposed.
3. AETB Requirements
Background
    EPA proposed to amend Appendix B by adding a new Section, 1.1.4, to
require that an Air Emissions Testing Body (AETB) that performs
emission testing or RATAs for on-going quality-assurance under Part 75
must conform to ASTM D7036-04.
Summary of Rule Changes
    No adverse comments were received. This provision has been
finalized, as proposed.
4. Calibration Error Tests and Linearity Checks-Dual Range Applications
Background
    EPA proposed to revise Sections 2.1.1, <IP_ADDRESS>, <IP_ADDRESS> and
2.2.3(e) of Appendix B, to clarify the data validation requirements for
daily calibration error tests and linearity checks of gas monitors when
two span values and two measurement ranges are required for a
particular parameter (e.g., SO2 or NOX).
    The proposed revisions to Section 2.1.1 of Appendix B would require
that ``sufficient'' calibration error tests be performed on the low and
high monitor ranges to validate the data recorded on each range, in
accordance with Section 2.1.5 of Appendix B. EPA also proposed to add a
new paragraph, (3), to Section <IP_ADDRESS> of Appendix B, to clarify how
the QA status of the low and high ranges is determined when: (a) a
calibration error test on one of the ranges is failed; or (b) the most
recent calibration error test of one of the ranges has expired. Under
proposed paragraph (3), when separate analyzers are used for the two
ranges, a failed or expired calibration error test on one of the ranges
would not affect the QA status of the other range. For a dual-range
analyzer (i.e., a single analyzer with two scales), a failed
calibration error test on either range would result in an out-of-
control period, and data from the monitor would remain invalid until
corrective actions are taken, followed by successful ``hands-off''
calibrations of both ranges. However, if the most recent calibration
error test on one range of a dual-range analyzer was successful, but
its data validation window expires, this would have no effect on the QA
status of the other range.
    Further, the Agency proposed to amend Section 2.2.3(e) of Appendix
B to make it clear that ``hands-off'' linearity checks of both ranges
of a dual-range analyzer are required whenever a linearity check on
either range fails or is aborted (unless, of course, a particular range
is exempted from linearity checks under Section 6.2 of Appendix A).
Summary of Rule Changes
    These provisions have been finalized, as proposed. Two commenters
did not understand why failure of a calibration error test or a
linearity check on one scale of a dual-range analyzer should invalidate
data on both ranges, and asked for EPA to more fully explain the
technical basis for this requirement.
    The requirement to perform calibration error tests or linearity
checks on both scales of a dual-range analyzer to resolve an out-of-
control period does not reflect a change in Agency policy. Rather,
EPA's proposal intended to clarify the existing requirement that each
range of a dual-range monitor must be known to be in-control in order
to validate data from the monitor.
    The final rule allows data to be considered valid from a particular
measurement range that has passed a calibration error check when the
calibration error test for the other measurement range has expired. In
such instances, since there is no indication that the monitor is not
functioning properly, but there is evidence that the measurement range
being used is properly calibrated, EPA is allowing that range to be
considered quality assured. However, whenever a monitor fails any
required daily, quarterly, semi-annual or annual quality assurance
test, regardless of range, EPA maintains that data from that monitor
must be considered invalid until the required quality assurance tests
are passed. A failed test on either range of a dual range monitor
indicates a problem with the monitor's ability to accurately measure
emissions. While it is possible that in some instances, the problem
causing the failure of a test on one range does not affect the accuracy
of the monitor's measurements on the other range, it is far from
certain. Therefore, the Agency's firm position is that whenever a
calibration error test or linearity check is failed on either
measurement scale of a dual-range analyzer, it is necessary to
calibrate both ranges following corrective actions (which usually
involve adjustments to the monitor), to verify that the monitor is back
in-control and is able to generate quality-assured data on both ranges.
5. Off-Line Calibration Error Tests
Background
    Section <IP_ADDRESS> of Appendix B allows the owner or operator to make
limited use of off-line calibration error tests to validate data if an
off-line calibration demonstration test is performed and passed. If the
off-line calibration error demonstration is successful, then off-line
calibrations may be used to validate up to 26 unit operating hours of
data before an on-line calibration error test is required.
    The off-line calibration provisions in Appendix B have not been
well-understood by many affected sources. Through the years, EPA has
received numerous requests for a more detailed explanation and/or
examples of how to apply these rule provisions. In view of this, the
Agency proposed to revise Sections <IP_ADDRESS> and <IP_ADDRESS> of Appendix B to
clarify the data validation rules for off-line calibration error tests.
    EPA proposed to revise paragraph (2) in Section <IP_ADDRESS> to state
that sources may make limited use of off-line calibrations if the off-
line calibration demonstration has been performed and passed. The
proposed changes to paragraph (2) of Section <IP_ADDRESS> would explain what
``limited use'' of off-line calibrations means. Off-line calibrations
could be used to validate up to 26 consecutive unit operating hours of
data before an on-line test is required. Each individual off-line
calibration would be valid only for 26 clock hours, and if the sequence
of consecutive operating hours validated by off-line calibrations is
broken before reaching the 26th consecutive unit operating hour, data
from the monitor would become invalid until an on-line calibration is
performed and passed.
Summary of Rule Changes
    Numerous commenters objected to the proposed revisions to Section
<IP_ADDRESS> of Appendix B. The commenters found the proposed rule language
to be confusing

rather than clarifying, and several of them asserted that EPA appeared
to be placing new restrictions on the use of off-line calibration error
tests.
    After careful consideration of these comments, EPA agrees that the
proposed rule language, particularly the term ``sequence of consecutive
unit operating hours'' can be misinterpreted. However, the Agency's
intent was (and is) simply to clarify the existing procedures for using
off-line calibrations to validate CEMS data. That is, a source desiring
to use the off-line calibration provisions in paragraph (2) of Appendix
B, section <IP_ADDRESS> must first pass the off-line calibration
demonstration described in section <IP_ADDRESS>. After successfully
completing this demonstration, off-line calibrations may be used on a
limited basis for data validation. In particular, off-line calibrations
may be used to validate data for up to 26 consecutive unit operating
hours following a passed on-line calibration error test.
    The term ``consecutive unit operating hours'' does not mean
consecutive clock hours. For example, two consecutive unit operating
hours could be separated by several hours, days, weeks, etc., due to a
unit outage. Each off-line calibration error test has the same
prospective, 26 clock hour window of data validation as an on-line
calibration error test.
    Therefore, for a source that has passed the off-line calibration
demonstration, EPA considers the data for a particular operating hour
to be valid if there is: (1) A passed on-line calibration within the 26
unit operating hours preceding that operating hour; and (2) a passed
off-line calibration within the 26 clock hours immediately preceding
that operating hour. The Agency has revised the proposed rule language
to clarify these requirements. For each hour of unit operation, these
criteria will be used to evaluate each monitoring system's control
status with respect to daily calibrations.
6. Weekly System Integrity Check--Data Validation
Background
    For a Hg CEMS that is equipped with a converter and that uses
elemental Hg for daily calibrations, Section 2.6 of Part 75, Appendix B
requires a weekly system integrity check, using a NIST-traceable source
of oxidized Hg. This ``weekly'' test is required once every 168 unit
operating hours. However, due to an apparent oversight, Section 2.6 did
not explain the consequences of either failing the test or failing to
perform the test on schedule. In view of this, EPA proposed to add the
following data validation rules for the weekly system integrity check
to Section 2.6 of Appendix B: (a) If the test fails, it would trigger
an out-of-control period until a subsequent system integrity check is
passed; and (b) if the test is not performed within 168 unit operating
hours of the previous successful system integrity check, data from the
CEMS would become invalid, starting with the 169th unit operating hour
and continuing until a system integrity check is passed.
    The Agency also proposed to correct a typographical error in
Section 2.6 of Appendix B. The performance specification for the weekly
system integrity check was incorrectly referenced as Section 3.2 (c)(3)
of Appendix A. The correct citation is Appendix A, Section 3.2,
paragraph (3)(iii).
Summary of Rule Changes
    The revision has been finalized as proposed. Several commenters
objected to the proposed data validation rules for weekly system
integrity checks of Hg CEMS. Commenters expressed concern that the
specified test frequency, i.e., once every 168 unit operating hours,
will cause scheduling difficulties, due to the limited availability of
qualified technicians and other factors. The commenters requested that
EPA provide a grace period of 72 to 96 hours for this QA test, to
minimize the possibility of data loss.
    EPA does not agree with the commenters' assertions that the 168
operating hour requirement will be difficult to implement and that a
grace period should be added. The number of operating hours since the
last weekly system integrity check can (and should) be tracked by the
data acquisition and handling system (DAHS). An alarm or prompt could
be activated when the deadline for the next test is near (e.g., when
120 or 144 operating hours have elapsed since the last test).
    EPA favors basing the interval between successive tests on
operating hours rather than clock hours in a week, primarily for
reasons of simplicity. The Agency acknowledges that this is distinctly
different from the way in which the deadlines for RATAs and linearity
checks are determined. For a RATA or linearity check, the deadline is
always at the end of a calendar quarter. Grace periods are provided for
these tests because the deadlines can pass while the unit is either
off-line or experiencing operational abnormalities that prevent the
monitors from being tested on time. Also, a limited number of RATA
deadline extensions and linearity check exemptions are provided for
``non-QA operating quarters'', i.e., calendar quarters in which the
unit operates for <  168 hours.
    However, the required frequency for the system integrity checks of
a Hg CEMS is weekly, not quarterly. This is the only weekly QA test
required by Part 75. Therefore, the existing ``QA operating quarter''
model and grace period scheme cannot be directly applied to the system
integrity check. A new concept, perhaps a ``QA operating week'' would
have to be introduced and an appropriate grace period determined. EPA
considered this approach and decided against it, believing that it
would unnecessarily complicate the process of QA status tracking for Hg
CEMS.
    The Agency believes that if the DAHS is programmed to track the
number of unit operating hours since the last system integrity check
and if an alert is provided to let plant personnel know when the test
deadline is approaching, there will seldom, if ever be a missed test.
Furthermore, the Agency believes that as experience is gained with Hg
monitors, it may be possible to automate the weekly system integrity
check so that during the 168th hour of operation since the last system
integrity check, the check is automatically initiated by the DAHS
computer system or other appropriate programmable logic controller
(PLC) systems. Such automation would further reduce the probability of
a missed test.
7. Correction of Hg Units of Measure--Figure 2
Background
    EPA proposed to correct a minor error in the units of measure for
Hg concentration in Figure 2 of Appendix B, changing the units of
micrograms per dry standard cubic meter ([mu]g/dscm) to micrograms per
standard cubic meter ([mu]g/scm). This change was proposed because not
all Hg monitoring systems measure Hg concentration on a dry basis.
Summary of Rule Changes
    No adverse comments were received. The proposed correction to
Figure 2 has been made.

J. Appendix D

1. Update of Incorporation by Reference
Background
    As previously noted, EPA proposed to update the list of test
methods, sampling and analysis procedures, and other items that are
incorporated by reference in Sec.  75.6. As such, the proposed rule

included corresponding updates to the references in Appendix D.
    EPA also proposed to add to Section <IP_ADDRESS> of Appendix D, the
American Petroleum Institute's (API) Manual of Petroleum Measurement
Standards Chapter 22--Testing Protocol: Section 2--Differential
Pressure Flow Measurement Devices (First Edition, August 2005) as a new
standard procedure for verifying flowmeter accuracy.
Summary of Rule Changes
    These provisions have been finalized, as proposed. Note that in
response to a comment, EPA has also incorporated by reference 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'' \1\, and has added ASTM D5453-
06 to the list of acceptable oil sampling methods in Section 2.2.5 of
Appendix D (see section 2.7 of the Response to Comments document for
further discussion). In addition, the equation for Hourly SO2
Mass Emissions from the Combustion of all Fuels in Appendix D, section
3.5.1 has been revised to be consistent with the new XLM format. This
change is considered to be insignificant and was made to be consistent
with the proposed changes to harmonize the units of measure for
reporting hourly mass emissions.
---------------------------------------------------------------------------

    \1\ ASTM D5453-05 is no longer available. EPA is thus adding
ASTM D5453-06, the version currently available. EPA considers this a
minor ministerial correction.
---------------------------------------------------------------------------

2. Pipeline Natural Gas--Method of Qualification and Monthly GCV Values
Background
    For a unit which combusts a fuel that meets the definition of
``pipeline natural gas'' (PNG) in Sec.  72.2, Section <IP_ADDRESS> of
Appendix D allows the owner or operator to estimate the unit's SO2
mass emissions using a default SO2 emission rate of 0.0006
lb/mmBtu. To qualify to use this SO2 emission rate, the
owner or operator must document that the natural gas has a total sulfur
content of 0.5 grains per 100 standard cubic foot or less. Section
<IP_ADDRESS> describes three ways to initially demonstrate that the gas
meets this total sulfur requirement: (1) Based on the gas quality
characteristics specified in a purchase contract, tariff sheet, or
pipeline transportation contract; or (2) based on historical fuel
sampling data from the previous 12 months; or (3) based on at least one
representative sample of the gas, if the requirements of (1) or (2)
cannot be met. When fuel sampling data are used to qualify, the rule
has required that each individual sample result must meet the total
sulfur limit. Once a fuel has qualified as pipeline natural gas,
Section <IP_ADDRESS>(e) of Appendix D requires annual sampling of the total
sulfur content to demonstrate that the fuel still meets the definition
of PNG. At least one sample per year must be taken and if multiple
samples are taken, the rule has required each one to meet the 0.5 gr/
100 scf total sulfur limit.
    Many suppliers of natural gas regularly sample the total sulfur
content of the gas (in many cases, daily) and provide that data to
their customers upon request. Sources desiring to use this data to meet
the initial or ongoing total sulfur sampling requirements of Appendix D
have asked whether the gas would be disqualified from using the 0.0006
lb/mmBtu SO2 emission rate if the total sulfur content of
one of these daily samples exceeded 0.5 gr/100 scf. EPA has been
handling these requests individually, on a case-by-case basis. However,
the Agency believes it will be more efficient to address the issue
through rulemaking. In view of this, amendments to Sections
<IP_ADDRESS>(a)(2) and (e) of Appendix D were proposed.
    For the initial documentation that the gas meets the 0.5 gr/100 scf
total sulfur limit, the proposed revisions to Section <IP_ADDRESS>(a)(2)
would allow sources with at least 100 total sulfur samples from the
previous 12 months to reduce the data to monthly averages. Then, if all
monthly averages meet the 0.5 gr/100 scf limit, the fuel would qualify
as pipeline natural gas, and the source could use the 0.0006 lb/mmBtu
default SO2 emission rate. Alternatively, if at least 98
percent of the 100 (or more) samples from the previous 12 months have a
total sulfur content of 0.5 gr/100 scf or less, the fuel would qualify
as pipeline natural gas.
    The proposed revisions to Section <IP_ADDRESS>(e) would allow this same
calculation methodology to be used for the annual total sulfur sampling
requirement. That is, each year, if the results of at least 100 total
sulfur samples from the past 12 months are obtained, the data could
either be reduced to monthly averages, or the percentage of the samples
that meet the 0.5 gr/100 scf limit could be determined.
    EPA also proposed to clarify the gross calorific value (GCV)
sampling requirements for pipeline natural gas in Section <IP_ADDRESS> of
Appendix D. The current rule requires monthly GCV sampling for PNG.
However, Section <IP_ADDRESS> refers only to the ``monthly sample''
(singular), whereas affected sources may collect and analyze multiple
GCV samples each month, or may receive the results of multiple GCV
samples from the fuel supplier each month. In view of this, the Agency
proposed to revise Section <IP_ADDRESS> to require that the monthly average
GCV value be used for Part 75 reporting, for any month in which
multiple samples are taken and analyzed. To implement this provision in
the case where the owner or operator has elected to use the actual
monthly GCV value in the emission calculations, revisions to Section
2.3.7(c) of Appendix D were proposed, requiring the monthly average GCV
value to be applied starting from the latest date of any of the
individual GCV samples used to calculate the monthly average. In the
case where an assumed GCV value is used in the calculations (i.e.,
either a contract value or the highest monthly average from the
previous year), the assumed value would continue to be used unless
superseded by a higher monthly average GCV value.
Summary of Rule Changes
    The provisions pertaining to documentation that a particular
gaseous fuel qualifies as pipeline natural gas have been finalized,
with only minor editorial changes. Regarding the proposed requirement
to average the results of all GCV samples of natural gas taken in each
calendar month, one commenter asked whether the monthly average would
be used to back-calculate the heat input values for each day in that
month.
    The proposed revisions to Section 2.3.7(c) of Appendix D specified
that when the option to use the actual monthly GCV in the calculations
is selected and multiple samples are taken, each monthly average GCV
would be applied prospectively, starting on the date of the last sample
taken during the month. However, in light of the commenter's question,
EPA has reconsidered this approach. The final rule requires instead
that each monthly GCV value be applied to every day in that month. The
Agency believes that this approach provides a more representative
estimate of the unit's true monthly heat input.
    Note that the text of paragraph (b)(2) in section 2.3.7 has also
been modified to address the new alternative methodology for making
annual assessments of the sulfur content of natural gas.
3. Requirement to Split Oil Samples
Background
    For affected units that combust fuel oil and use the Appendix D

methodology to quantify SO2 mass emissions and/or unit heat
input, Section 2.2 of Appendix D requires the owner or operator to
perform periodic sampling of the sulfur content, gross calorific value
and density of the oil (as applicable). Section 2.2.5 of Appendix D
requires each oil sample to be split and a portion (at least 200 cc) of
it to be maintained for at least 90 days after the end of the allowance
accounting period.
    The requirement to split and maintain a portion of each oil sample
has been in Appendix D since it was first promulgated on January 11,
1993. At that time, on-site fuel oil sampling was required on every day
that the unit combusted oil. Later, on May 17, 1995, an option to
sample each shipment upon delivery was added for diesel fuel. Then, on
May 26, 1999, the four basic oil sampling options in the current rule
were put in place. However, the requirement to split and maintain a
portion of each sample has remained unchanged through all of these
rulemakings.
    Believing that the requirement to split and maintain oil samples
should only apply to samples that are taken at the affected facility,
EPA proposed to revise Section 2.2.5 of Appendix D to limit this
requirement to samples that are taken on-site. If this proposed
amendment were finalized, sources electing to sample each fuel lot
would no longer be required to split and maintain oil samples in cases
where the samples are taken off-site, from the fuel supplier's storage
container.
Summary of Rule Changes
    No adverse comments were received. This provision has been
finalized, as proposed.

K. Appendix E

1. AETB Requirements
Background
    EPA proposed to revise Section 2.1 of Appendix E to require that
any Air Emissions Testing Body (AETB) performing emission measurements
to develop an Appendix E correlation curve or to derive a default
emission rate for a LME unit, would have to conform to ASTM D7036-04.
Summary of Rule Changes
    No adverse comments were received. This provision has been
finalized, as proposed.
2. Reporting Data When the Correlation Curve Expires
Background
    For oil and gas-fired peaking units using the Appendix E
methodology to estimate NOX emissions, the owner or operator
is required, for each fuel type, to perform four-load emission testing
for initial certification in order to develop a correlation curve of
NOX emission rate versus heat input rate. Each correlation
curve is programmed into the data acquisition and handling system
(DAHS), and retesting is required every five years (20 calendar
quarters) to develop a new curve.
    If the 20 calendar quarter test deadline passes without a retest
having been performed, the previous correlation curve expires and is no
longer valid. However, the appropriate missing data procedure to follow
when a correlation curve expires has been conspicuously absent from
Section 2.5 of Appendix E. To address this deficiency, EPA proposed to
add a new Section, <IP_ADDRESS>, to Appendix E, requiring the fuel-specific
maximum potential NOX emission rate (MER) to be reported,
from the date and hour in which a baseline correlation curve expires
until a new correlation curve is generated.
Summary of Rule Changes
    No adverse comments were received. This provision has been
finalized, as proposed.

L. Appendix F

1. NOX Mass Calculations
Background
    EPA proposed to revise the manner in which NOX mass data
are collected under the XML format that will be required in 2009 as
part of EPA's effort to re-engineer the Agency's data collection
systems. To achieve this, the hourly NOX mass emission rate
(lb/hr) would be reported instead of hourly NOX mass
emission (lb), when the source transitions from EDR reporting format to
the XML format.
    To effect this, Equations F-24, and F-27 in Appendix F of Part 75
would have to be modified and Equation F-26 removed. However, since the
current EDR reporting format will continue to be supported through
2008, these equations must remain in the rule until the transition to
XML is complete. Therefore, EPA proposed to revise Section 8 of
Appendix F by adding Equations F-24a for the reporting of hourly
NOX mass emission rate (lb/hr) and Equation F-27a , for the
calculation of cumulative NOX mass emissions. In 2009, the
use of Equations F-24a and F-27a would become mandatory for all sources
and Equations F-24 and F-27 would no longer be applicable.
    EPA also proposed to revise Section 8.2 of Appendix F, by splitting
it into two subsections, 8.2.1 and 8.2.2. Section 8.2 had described a
procedure for calculating the NOX mass emission rate in lb/
hr, when NOX mass emissions are determined using a
NOX concentration monitoring system and a flow monitor.
However, Section 8.2 simply cross-referenced other parts of the rule,
rather than showing the actual equations used. To correct this, the
Agency proposed to add Equation F-26a to subsection 8.2.1 and Equation
F-26b to subsection 8.2.2, clearly showing how the NOX mass
emission rate is calculated on a wet and dry basis, and to renumber
Equation F-26 in Section 8.3 as Equation F-26c. Proposed Equations F-
26a and F-26b have been used since 2002 by sources in the
NOX Budget Program, and the equations have been represented
in the EDR reporting instructions as Equations N-1 and N-2,
respectively.
Summary of Rule Changes
    No adverse comments were received. These provisions have been
finalized, as proposed.
2. Use of the Diluent Cap
Background
    EPA proposed to restrict the use of the diluent cap to
NOX emission rate determinations. The original purpose for
allowing the diluent cap to be used was to keep calculated
NOX emission rates from approaching infinity during periods
of unit startup and shutdown, when the diluent gas (CO2 or
O2) concentration is close to the level in the ambient air.
However, since 1999, Part 75 has allowed the diluent cap to be used for
heat input rate calculations, CO2 mass emission
calculations, and calculation of hourly CO2 concentration
from measured O2 concentrations, in addition to being used
for NOX emission rate. Sources have been allowed to use the
cap value for some of these calculations and not others, which greatly
complicates the data collection process. EPA has also found that using
the diluent cap for other parameters besides NOX emission
rate always leads to over-reporting of these parameters, which is
clearly contrary to the intended purpose of the diluent cap. Therefore,
the Agency proposed to remove all of the references in Sections 4 and 5
of Appendix F that allow the diluent cap to be used for other
parameters besides NOX emission rate.
Summary of Rule Changes
    No adverse comments were received. These provisions have been
finalized, as proposed.

3. Negative Emission Values
Background
    EPA proposed to provide special reporting instructions to account
for situations where the equations prescribed by the rule yield
negative values. First, when Equation 19-3 or 19-5 (from EPA Method 19
in 40 CFR Part 60, Appendix A) is used to calculate NOX
emission rate, modified forms of these equations, designated as
Equations 19-3D and 19-5D, would be used whenever the diluent cap is
applied. Second, for any hour where Equation F-14b results in a
negative hourly average CO2 value, EPA proposed to require
0.0% CO2 to be reported as the average CO2 value
for that hour. Third, the Agency proposed to require a default heat
input rate value of 1 mmBtu/hr to be reported for any hour in which
Equation F-17 results in a negative hourly heat input rate. These
changes would be accomplished by modifying Sections, 3.3.4, 4.4.1, and
5.2.3 of Appendix F.
Summary of Rule Changes
    These provisions have been finalized, with one notable change. The
final rule will require a default heat input rate value of 1 mmBtu/hr
to be reported for any hour in which Equation F-17 results in a hourly
heat input rate that is less than or equal to zero.
4. Calculation of Stack Gas Moisture Content
Background
    EPA proposed to add Equation F-31 to a new Section 10 in Appendix
F, to be used to calculate stack gas moisture values from wet and dry
oxygen measurements, as described in Appendix A, Section 6.5.7(a).
Sources have been using this equation for many years and it has been
represented in the EDR reporting instructions as Equation M-1.
Summary of Rule Changes
    No adverse comments were received. This provision has been
finalized, as proposed.
5. Site-Specific F-Factors (Single Fuel)
Background
    For units that use CEMS to measure the NOX emission rate
in lb/mmBtu and/or the unit heat input rate in mmBtu/hr, an equation
from Appendix F of Part 75 or from Method 19 of 40 CFR Part 60 is
required to convert the raw CEMS data into the proper units of measure.
Each of these equations contains an F-factor, which represents either
the total volume of flue gas or the volume of CO2 generated
per million Btu of heat input. The F-factor is fuel-specific.
    Sections 3.3.5 and 3.3.6 of Appendix F allow the owner or operator
to use either a default F-factor from Table 1 in Appendix F, or use
Equation F-7a or F-7b in Appendix F to calculate a site-specific F-
factor, based on the composition of the fuel. However, Appendix F has
never specified how much fuel sampling data is required to develop a
site-specific F-factor or how often the F-factor must be updated.
    To address this issue, EPA proposed to revise the introductory text
of Appendix F, Section 3.3.6 to require each site-specific F-factor to
be based on a minimum of 9 samples of the fuel. Fuel samples taken
during the 9 runs of an annual RATA would be acceptable for this
purpose. Further, re-determination of the F-factor would be required at
least annually, and the value from the most recent determination would
be used in the emission calculations.
Summary of Rule Changes
    No adverse comments were received. These provisions have been
finalized, as proposed.
6. Prorated F-Factors
Background
    For affected units that co-fire combinations of fossil fuels or
fossil fuels and wood residue and that use CEMS to monitor the
NOX emission rate or unit heat input rate, Section <IP_ADDRESS>
of Appendix F has required a prorated F-factor to be used in the
emission calculations. The prorated F-factor is calculated using
Equation F-8 in Appendix F. In applying Equation F-8, the F-factor for
each type of fuel is weighted according to the fraction of the total
heat input contributed by the fuel. However, Equation F-8 has never
specified how the total unit heat input and the fraction of the heat
input contributed by each fuel are determined. Data from the CEMS
cannot be used for this purpose because the prorated F-factor must be
known before the unit heat input rate can be calculated.
    To correct this situation, EPA proposed to revise the definition of
``Xi'' (the fraction of the total heat input derived from
each fuel) in the Equation F-8 nomenclature. The proposed revision
would require sources to determine Xi from the best
available information on the quantity of each fuel combusted and its
GCV value over a specified time period. The value of Xi
would be updated periodically, either hourly, daily, weekly, or
monthly, and the prorated F-factor used in the emission calculations
would be derived from the Xi values from the most recent
update. The owner or operator would be required to document in the hard
copy portion of the monitoring plan the method used to determine the
Xi values.
Summary of Rule Changes
    The revisions to Section <IP_ADDRESS> of Appendix F regarding the
prorating of F-factors have been finalized, with only minor changes.
However, several commenters requested that EPA consider allowing the
use of the ``worst-case'' (i.e., highest) F-factor as an alternative to
prorating, when combinations of fuels are co-fired. After careful
consideration of these comments, EPA is persuaded by the commenters'
arguments in favor of this option and has decided to incorporate this
suggestion into the final rule (see section 2.4 of the Response to
Comments document). New Section <IP_ADDRESS> of Appendix F allows sources
that burn combinations of fuels listed in Table 1 of Appendix F to use
the highest (``worst-case'') F-factor for any unit operating hour, in
lieu of prorating the F-factor. Note that in view of the revisions to
Section <IP_ADDRESS>, Agency has deemed it necessary to modify the language
in Section <IP_ADDRESS> of Appendix F. Administrative approval of the F-
factor is no longer required when combinations of fossil fuels with
wood or bark are combusted, since F-factors for these fuels are listed
in Table 1. Rather, revised Section <IP_ADDRESS> requires Administrative
approval of the F-factor only when a fuel not listed in Table 1 is co-
fired with a fuel (or fuels) listed in the Table.
7. Default F-Factors
Background
    In recent years, petroleum coke and tires have begun to be used as
primary or secondary fuels by a number of affected sources. In view of
this, EPA proposed to add default F-factors for petroleum coke and
tire-derived fuels to Table 1 in Section 3.3.5 of Appendix F. The
proposed values were 9,832 dscf/mmBtu for Fd and 1,853 scf
CO2/mmBtu for Fc for petroleum coke and 10,261
dscf/mmBtu for Fd and 1,803 scf CO2/mmBtu for
Fc for tire-derived fuels. The Agency also proposed F-
factors of 9,819 dscf/mmBtu (for Fd) and 1,840 scf
CO2/mmBtu (for Fc) for sub-bituminous coal. All
of the proposed F-factors were calculated using Equations F-7a and F-7b
and representative composition and gross calorific value (GCV) data for
each fuel.

Summary of Rule Changes
    These provisions have been finalized, with minor editorial changes.
One commenter recommended that the proposed F-factor values be rounded
off to the nearest multiple of 10, to be consistent with the other
values in Table 1. EPA agrees with this comment and has rounded off the
F-factors accordingly.
8. Revisions to Equation F-23
Background
    Consistent with the proposed changes to Sec.  75.11(e), expanding
the applicability of Equation F-23, EPA proposed to amend Section 7 of
Appendix F (introductory text), and the Equation F-23 nomenclature.

Summary of Rule Changes

    No adverse comments were received. These provisions have been
finalized, as proposed.

M. Appendix G

Background
    Consistent with the changes to other parts of the rule, EPA
proposed to update the current ASTM standards listed in Sections 2.1.2,
2.2.1, and 2.2.2, of Appendix G, citing the newer versions.
Summary of Rule Changes
    No adverse comments were received. These provisions have been
finalized, as proposed.

N. Appendix K

Background
    EPA proposed to addresses several issues regarding the use of
sorbent trap monitoring systems for the measurement and reporting of Hg
mass emissions. When this monitoring option is selected, paired sorbent
traps are required to measure the effluent Hg concentration. If the two
Hg concentrations measured by the paired traps meet the required
relative deviation (RD) specification in Appendix K of Part 75, and if
each trap individually meets certain other QA requirements of Appendix
K, then the two Hg concentrations are averaged arithmetically and the
average value is used to determine the Hg mass emissions in each hour
of the data collection period. However, in cases where either or both
of the traps fails to meet the acceptance criteria, Sec.  75.15(h) and
Table K-1 in Appendix K specify consequences of varying severity. In
the months following promulgation of these rule provisions, EPA
revisited them and concluded that some of the consequences were too
lenient and others unnecessarily severe. The Agency therefore proposed
to revise them to make them more consistent and equitable.
    Whenever one of the paired traps is accidentally lost, damaged, or
broken and cannot be analyzed, Sec.  75.15(h) has allowed the owner or
operator to use the remaining trap to determine the Hg concentration
for the data collection period, provided that the remaining trap meets
all of the QA requirements of Appendix K. But no adjustment of the data
has been required to compensate for the loss of one of the samples. In
view of this, EPA proposed to revise Sec.  75.15(h) to require that the
Hg concentration measured by the remaining valid trap be multiplied by
a ``single trap adjustment factor'' (STAF) of 1.222. The STAF
represents the maximum amount by which the Hg concentration from the
lost, damaged or broken trap could have exceeded the concentration
measured by the valid trap and still met the 10% RD specification.
    The Agency also proposed to revise Table K-1 in Appendix K, to
extend the use of the STAF to cases where one of the paired sorbent
traps either: (a) fails a post-test leak check; (b) has excessive
breakthrough in the second section; or (c) is unable to meet the
required percent recovery of the third section elemental Hg spike. In
all three of these cases, provided that the other trap meets all
Appendix K requirements, rather than invalidating the sorbent trap
system data for the entire collection period, the Hg concentration
measured by the valid trap, multiplied by the STAF, could be used for
Part 75 reporting.
    Section 7.2.3 of Appendix K requires that for each hour of the data
collection period, the ratio of the stack gas flow rate to the sample
flow rate through each sorbent trap must be maintained within < plus-
minus>25 percent of the initial ratio established in the first hour of
the data collection period. However, the rule has stated that when this
criterion is not met, the appropriate consequences are to be determined
on a ``case-by-case'' basis. EPA has reconsidered this approach and now
believes that it allows for inconsistent application of the sorbent
trap monitoring methodology. Therefore, the Agency proposed to revise
Table K-1 to specify that a sample is invalidated if either: (a) More
than 5 percent of the hourly ratios; or (b) more than 5 hourly ratios
in the data collection period (whichever is less restrictive) fail to
meet the 25 percent acceptance criterion. Further, if only
one of the paired traps is able to meet the specification, provided
that it also meets the rest of the Appendix K QA criteria, the valid
trap could be used for Part 75 reporting, if the STAF value of 1.222 is
applied to the measured Hg concentration.
    Appendix K has required data from a sorbent trap monitoring system
to be invalidated whenever the relative deviation between the Hg
concentrations measured by the paired traps is greater than 10 percent.
EPA proposed to revise this requirement, to allow sources to report the
higher of the two Hg concentrations measured by a pair of sorbent traps
whenever the RD specification is not met, rather than invalidating the
sorbent trap system data for the entire collection period. The Agency
also proposed, for consistency with the proposed changes Sec.
75.22(a), to revise Table K-1 to include an alternative relative
deviation specification of 20 percent for paired sorbent traps, when
low effluent concentrations of Hg (< = 1 [mu]g/m\3\) are encountered.
    EPA further proposed to add two new paragraphs, (k) and (l), to
Sec.  75.15. Proposed Sec.  75.15(k) would have required that whenever
the RATA of a sorbent trap system is performed, the sorbent traps used
to collect the RATA run data must be the same size as the traps used
for daily operation of the monitoring system. Likewise, the sorbent
material must be the same type that is used for daily operation.
Proposed Sec.  75.15(l) would have required a diagnostic RATA of the
sorbent trap system whenever either the size of the sorbent traps or
the type of sorbent material was changed. Data from the modified
sorbent trap system would not have been acceptable for Part 75
reporting until the RATA is passed, with one exception, i.e., data
collected during a successful diagnostic RATA test period could be
reported as quality-assured.
    Finally, revisions to section 7.2.3 of Appendix K were proposed,
requiring that the sample flow rate through a sorbent trap monitoring
system must be zero when the unit is not operating. EPA believes this
clarification is needed to prevent the system from sampling ambient air
during periods when the combustion unit is off-line, which would
artificially lower the Hg concentrations measured by the sorbent traps,
resulting in under-reporting of Hg mass emissions.
Summary of Rule Changes
    The commenters generally favored the proposal to add a 20 percent
alternative relative deviation (RD) specification for sources with low
Hg emissions (< = 1.0

[mu]g/m3). However, concerns were expressed that even a 20
percent RD specification might be difficult to meet when emissions are
exceptionally low. For instance, following a flue gas desulfurization
system, the Hg emission levels can be as low as 0.1 to 0.2 [mu]g/m\3\.
One commenter suggested that the allowable RD for low emitters should
be either 20 percent or 0.03 [mu]g/m\3\ absolute difference, whichever
is less restrictive (see section 2.9.2 of the Response to Comments
document). EPA agrees with this comment and has incorporated the 0.03
[mu]g/m\3\ alternative RD specification into both Appendix K (for
sorbent trap monitoring systems), and Sec.  75.22 (for the Ontario
Hydro Method and EPA Method 29).
    The commenters were divided on the proposed single trap adjustment
factor (STAF) provisions. Two commenters supported the proposed
amendments and four others objected to them. Those objecting expressed
concern that applying the proposed STAF value of 1.222 in cases where
one trap meets all of the QA requirements is unnecessarily punitive.
Several of the commenters recommended that the STAF value should be
1.111, which would be consistent with the averaging that is performed
when the results of both traps are available and would appropriately
weight the results of the valid trap (see section 4.3 of the Response
to Comments document for further discussion). After careful
consideration of the comments, EPA has decided to incorporate the
commenters' suggestion regarding the value of the STAF. Therefore, the
single-trap adjustment factor provisions have been finalized as
proposed, except that the value of the STAF is 1.111.
    Regarding proposed paragraphs (k) and (l) in Sec.  75.15, EPA has
reconsidered its position and has withdrawn the requirement for the
sorbent traps used for RATA testing to be the same size as the traps
used for daily operation of the monitoring system. Accordingly, the
proposed requirement to perform a diagnostic RATA when the trap size is
changed has also been withdrawn. The Agency is finalized paragraph (k)
as part of a direct-final rulemaking on September 7, 2007 (72 FR 51494-
51531). Paragraph (k) requires only that the type of sorbent material
used for the RATAs be the same as the sorbent material used for daily
operation. Today's rule finalizes paragraph (l) of Sec.  75.15, to
require a diagnostic RATA within 720 operating hours whenever a new
type of sorbent material begins to be used in the traps (e.g., using
brominated carbon instead of iodated carbon). Commenters on proposed
paragraph (l) questioned why data collected by the modified sorbent
trap system are considered invalid prior to the diagnostic RATA. The
commenters requested that EPA revise paragraph (l) to allow data
collected prior to the diagnostic RATA to be reported as valid if the
RATA is passed. The commenters' suggestion is reasonable and has been
incorporated into the final rule. A passed diagnostic RATA demonstrates
that the change in sorbent material has not significantly affected the
monitoring system's ability to accurately measure Hg emissions.
Therefore, Sec.  75.15(l) allows the data from the modified sorbent
trap system to be considered conditionally valid according to Sec.
75.20(b)(3), for up to 720 unit or stack operating hours after
switching to a new type of sorbent material. If the diagnostic RATA is
passed within the 720 operating hour window, the data recorded by the
modified system prior to the RATA may be reported as quality-assured.
If the RATA is failed, no data from the modified system may be reported
as quality-assured until a subsequent RATA is passed. If the diagnostic
RATA is not completed within the allotted 720 operating hour window but
is passed on the first attempt, data from the modified system are
considered to be invalid from the first hour after the expiration of
the 720 operating hour window until the completion of the RATA.
    No comments were received on the following proposed amendments: (1)
The proposal to allow the higher Hg concentration to be reported when
the RD criterion for the paired sorbent traps is not met; (2) the
proposed acceptance criteria for the hourly ratios of stack gas flow
rate to sample flow rate; and (3) the proposal to require the sample
flow rate through a sorbent trap monitoring system to be zero when the
affected unit is off-line. Therefore, these provisions have been
finalized, as proposed.

O. Other Rule revisions

1. Particulate Matter Monitoring Systems
Background
    EPA received a comment that was outside the scope of the proposed
rule, requesting that units with installed particulate matter (PM)
monitoring systems be exempted from the opacity monitoring requirements
of Sec.  75.14.
Summary of Rule Changes
    Although the comment was outside the scope of this rulemaking and
no response is required, EPA believes that it has merit in light of
June 13, 2007 amendments to Subparts Da and Db of 40 CFR Part 60 (see:
72 FR p.32710). For certain affected units (some of which are also
subject to Part 75), these rule revisions either require or allow a
particulate matter (PM) monitoring system to be used in lieu of an
opacity monitor (e.g., see Sec. Sec.  60.49Da(t), and 60.48b(j)).
Summary of Rule Changes
    Today's rule incorporates the commenter's recommendation, as new
paragraph (e) in Sec.  75.14. The Agency believes that this revision to
Part 75 is non-controversial and is consistent with EPA's ongoing
commitment to harmonization of the Part 60 and Part 75 continuous
monitoring regulations.
2. Default Moisture Values for Hg Monitoring
Background
    For dry-basis Hg CEMS and sorbent trap monitoring systems, the
hourly Hg emissions data must be corrected for the stack gas moisture
content. This requirement can be met by using one of the fuel-specific
default moisture values specified in Part 75. Several places in Sec.
75.80, Sec.  75.81, and Appendix K state that for the purposes of Hg
monitoring, a default moisture value from Sec.  75.11(b) or Sec.
75.12(b) may be used in lieu of installing a continuous moisture
monitoring system. However, the reference to Sec.  75.12(b) is
incorrect. Only the default moisture values in Sec.  75.11(b) are
appropriate for Hg monitoring applications. Equation F-29, the only Hg
mass emissions equation with a moisture correction term, is
structurally similar to Equation F-2 for SO2 mass emissions.
The default moisture values in Sec.  75.11(b) are the ones that apply
to Equation F-2. Hence, they apply also to Equation F-29. The default
moisture values in Sec.  75.12(b) are used for NOX emission
rate calculations, and several of them are not applicable to Hg mass
emissions monitoring.
Summary of Rule Changes
    All references to the default moisture values in Sec.  75.12(b)
have been removed from Sec.  75.80, Sec.  75.81, and Appendix K.
3. Hg Stratification Testing
Background
    To support the Clean Air Mercury Regulation (CAMR), which was
published in 2005 (see: 70 FR 28606, May 18, 2005), EPA added Hg
monitoring provisions to Part 75, among which were revisions to Sec.
75.22(a) and to section 6.5.10 of Appendix A, specifying ASTM D6784-02,
the ``Ontario Hydro Method'', as the appropriate reference method for

measuring Hg concentration. On August 22, 2006 EPA proposed to add
Method 29 (which is similar to Ontario Hydro) to Part 75, as an
alternative Hg reference method. Most recently, in a direct-final
action on September 7, 2007. EPA published two more alternative
reference methods (RMs) for measuring vapor phase Hg emissions, Method
30A (an instrumental method) and Method 30B (a sorbent-based method).
Today's rule allows the use of Methods 29, 30A, and 30B as alternatives
to the Ontario Hydro Method (see the revisions to Sec.  75.22(a) and
Section 6.5.10 of Appendix A). EPA anticipates that in 2008 and beyond,
all four of the Hg reference methods in Part 75 will be used, to a
greater or lesser extent, for the Hg emission testing required under
Sec. Sec.  75.81(c) and (d) and for RATAs of Hg monitoring systems.
    For Hg emission tests, Methods 30A and 30B require 12 sampling
points (located according to EPA Method 1) for each test run, unless
the results of a Hg stratification test justify using fewer points. The
Ontario Hydro Method and Method 29 each require a minimum of 12 sample
points and do not include any stratification test provisions or
alternative sampling point location criteria.
    For the RATAs of Part 75 Hg monitoring systems, when Methods 30A
and 30B are used, both methods defer to the RM point selection and
location procedures described in Part 75, Appendix A, section 6.5.6 and
Performance Specification 2 (PS2) in Appendix B of 40 CFR Part 60. This
is the familiar sampling approach that allows the use of a ``short'' 3-
point measurement line at locations where stratification is not
expected, but requires the use of a 3-point ``long'' measurement line
(which includes a point at the center of the stack) at locations where
stratification is suspected (e.g., after a wet scrubber), unless the
results of a stratification test justify using the 3-point short line
(or perhaps a single sampling point). As an alternative, Part 75 allows
the use of six Method 1 sampling points located along a diameter, at
any test location (including those where stratification is suspected).
This same RM sampling point location methodology applies to Hg RATAs in
which the Ontario Hydro Method or Method 29 is used as the reference
method.
    However, when testing is performed downstream of a scrubber,
measuring at the center of a large-diameter stack is extremely
difficult logistically, and testing at 6 points along a diameter may
not be possible for certain test platform and test port configurations.
Therefore, historically, most testers have opted to perform
stratification testing at scrubbed stacks to justify sampling along a
3-point short line (or at a single point), which greatly simplifies the
test procedures, in that all measurements can be made at one test port,
using a probe of reasonable length. Unfortunately, Part 75 does not
have a stratification test procedure for Hg, and, as previously noted,
neither the Ontario Hydro Method nor Method 29 has any stratification
test provisions--but there is a Hg stratification test procedure in
Method 30A.
Summary of Rule Changes
    In view of these considerations, EPA has deemed it necessary to
revise Section 6.5.6(c) of Appendix A, to cross-reference the Hg
stratification test provisions in Sections 8.1.3 through <IP_ADDRESS> of
Method 30A. Further, Sec.  75.22(a)(7) has been revised to address RM
sample point location and stratification testing when the Ontario Hydro
Method or Method 29 is used for the Hg low mass emission testing
required under Sec. Sec.  75.81(c) and (d). For that particular
application, revised Sec.  75.22(a)(7) requires the sampling points to
be located according to Section 8.1 of Method 30A and cross-references
the stratification test provisions in sections 8.1.3 through <IP_ADDRESS> of
Method 30A.
    These amendments to Appendix A and Sec.  75.22 provide a consistent
approach to stratification testing and RM sampling point location for
Hg emission testing and Hg monitoring system RATAs, irrespective of
which Hg reference method is used for the testing.

II. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This action is not a ``significant regulatory action'' under the
terms of Executive Order (EO) 12866 (58 FR 51735, October 4, 1993) and
is therefore not subject to review under the EO.

B. Paperwork Reduction Act

    The information collection requirements in the final rule have been
submitted for approval to OMB under the Paperwork Reduction Act, 44
U.S.C. 3501 et seq. The Information Collection Request (ICR) document
prepared by EPA has been assigned EPA ICR number 2203.02. The
information collection requirements are not enforceable until OMB
approves them.
    The information requirements are based on the revisions to the
monitoring, recordkeeping, and reporting requirements in 40 CFR Part
75, which are mandatory for all sources subject to the Acid Rain
Program under Title IV of the Clean Air Act and certain other emissions
trading programs administered by EPA. All information submitted to EPA
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to Agency
policies set forth in 40 CFR Part 2, subpart B. The preexisting Part 75
rule requirements amended in this final rule are covered by existing
ICRs for the Acid Rain Program (EPA ICR number 1633.14; OMB control
number 2060-0258), the NOX SIP Call (EPA ICR number 1857.04;
OMB number 2060-0445), and the Clean Air Interstate Rule (EPA ICR
number 2152.02; OMB number 2060-0570). The separate ICR for the final
rule revisions addresses the one-time costs necessary for sources to
review the rule revisions and adapt their recordkeeping and reporting
systems to the revised requirements. The EPA believes that the long
term implications of the rule revisions will be to reduce the ongoing
burdens and costs associated with Part 75 compliance, but those impacts
will be addressed as EPA renews the individual program ICRs. The annual
monitoring, reporting, and recordkeeping burden for this collection
(averaged over the first 3 years after the effective date of the final
rule) is estimated to be 124,976 labor hours per year at a total annual
cost of $8,581,420. This estimate includes burdens for rule review,
recordkeeping and reporting software upgrades, and software debugging
activities, as well as the capital costs of upgrading recordkeeping and
reporting software.
    Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information. An Agency may not
conduct or sponsor, and a person is not required to respond to a
collection of information unless it

displays a currently valid OMB control number. The OMB control numbers
for EPA's regulations in 40 CFR are listed in 40 CFR Part 9. When this
ICR is approved by OMB, the Agency will publish a technical amendment
to 40 CFR part 9 in the Federal Register to display the OMB control
number for the approved information collection requirements contained
in this final rule.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions. For purposes
of assessing the impacts of today's rule on small entities, small
entity is defined as: (1) A small business as defined by the SBA's
regulations at 13 CFR 121.201; (2) a small governmental jurisdiction
that is a government of a city, county, town, school district or
special district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.
    After considering the economic impacts of today's final rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. In
determining whether a rule has a significant economic impact on small
entities, the impact of concern is any significant adverse economic
impact on small entities, since the primary purpose of the regulatory
flexibility analysis is to identify and address regulatory alternatives
``which minimize any significant economic impact of the rule on small
entities.'' 5 U.S.C. 603 and 604. Thus, an agency may certify that a
rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden or
otherwise has a positive economic effect on all of the small entities
subject to the rule. These final rule revisions represent minor changes
to existing monitoring requirements used in EPA emission trading
programs and we expect these revisions to reduce the economic burden
for affected entities in the long term.
    Although there will be some small level of up front costs to
reprogram existing electronic data reporting software used under this
program, the long term effects of these revisions will be to allow
continued efficient electronic data submittals that should act to
relieve some of the long term reporting burdens for affected sources,
which include some small entities.

D. Unfunded Mandates Reform Act

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub.
L. 104-4, establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``Federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost effective or least burdensome alternative
that achieves the objectives of the rule. The provisions of section 205
do not apply when they are inconsistent with applicable law. Moreover,
section 205 allows EPA to adopt an alternative other than the least
costly, most cost-effective, or least burdensome alternative if the
Administrator publishes with the final rule an explanation why that
alternative was not adopted. Before EPA establishes any regulatory
requirements that may significantly or uniquely affect small
governments, including tribal governments, it must have developed under
section 203 of the UMRA a small government agency plan. The plan must
provide for notifying potentially affected small governments, enabling
officials of affected small governments to have meaningful and timely
input in the development of EPA regulatory proposals with significant
Federal intergovernmental mandates, and informing, educating, and
advising small governments on compliance with the regulatory
requirements. EPA has determined that this final rule does not contain
a Federal mandate that may result in expenditures of $100 million or
more for State, local, and tribal governments in the aggregate, or to
the private sector in any 1 year, nor does this rule significantly or
uniquely impact small governments, because it contains no requirements
that impose new obligations upon them. Thus, this final rule is not
subject to the requirements of sections 202 and 205 of the UMRA.
    EPA has determined that this rule contains no regulatory
requirements that might significantly or uniquely affect small
governments. The revisions primarily make certain changes EPA has
determined are necessary as part of upgrading the data systems used to
manage data submitted under the program and to streamline the methods
for sources to report their information. The revisions also clarify
certain issues that have been raised during ongoing implementation of
the existing rule and update the information on various voluntary
consensus standards incorporated by reference in the rule. Some States
do have programs that rely on the monitoring provisions in 40 CFR Part
75, and States may incur some costs associated with reviewing the
modifications to Part 75, but the rule revisions and the impact on the
States are not significant.

E. Executive Order 13132: Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.'' This final
rule does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. These rule revisions represent
minor adjustments to existing regulations. The revisions primarily make
certain changes EPA has determined are necessary as part of upgrading
the data systems used to manage data submitted under the program and to
streamline the methods for sources to report their information. The
revisions also clarify certain issues that have been raised during
ongoing implementation of the existing rule and update the information
on various voluntary consensus standards incorporated by reference in
the rule. Some States do have programs that rely on the monitoring
provisions in 40 CFR Part 75, and States may incur some costs

associated with reviewing the modifications to Part 75, but the rule
revisions and the impact on the States are not significant. Thus,
Executive Order 13132 does not apply to this final rule.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    Executive Order 13175, entitled ``Consultation and Coordination
With Indian Tribal Governments'' (65 FR 67249, November 9, 2000),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' This final rule does not have
tribal implications, as specified in Executive Order 13175. It will not
have substantial direct effects on tribal governments, on the
relationship between the Federal government and Indian tribes, or on
the distribution of power and responsibilities between the Federal
government and Indian tribes. Thus, Executive Order 13175 does not
apply to this final rule.

G. Executive Order 13045: Protection of Children From Environmental
Health and Safety Risks

    Executive Order 13045: ``Protection of Children From Environmental
Health Risks and Safety Risks'' (62 FR 19885, April 23, 1997) applies
to any rule that: (1) Is determined to be ``economically significant''
as defined under Executive Order 12866, and (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children. If the regulatory action
meets both criteria, the Agency must evaluate the environmental health
or safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency. EPA
interprets Executive Order 13045 as applying only to those regulatory
actions that are based on health or safety risks, such that the
analysis required under section 5-501 of the Order has the potential to
influence the regulation. This rule is not subject to Executive Order
13045 because it does not establish an environmental standard intended
to mitigate health or safety risks.

H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use

    This rule is not subject to Executive Order 13211, ``Actions
Concerning Regulations That Significantly Affect Energy Supply,
Distribution, or Use'' (66 FR 28355, May 22, 2001) because it is not a
significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No. 104-113, section 12(d) (15 U.S.C.
272 note) directs EPA to use voluntary consensus standards in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, and business practices) that are developed or
adopted by voluntary consensus standards bodies. The NTTAA directs EPA
to provide Congress, through OMB, explanations when the Agency decides
not to use available and applicable voluntary consensus standards. This
rule includes updated information on a number of voluntary consensus
standards previously included in 40 CFR Part 75, as well as the
addition of certain other voluntary consensus standards.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States. EPA has determined that this final
rule will not have disproportionately high and adverse human health or
environmental effects on minority or low-income populations because it
does not affect the level of protection provided to human health or the
environment. This final rule does not affect or relax the control
measures on sources impacted by emission trading programs that rely on
monitoring under 40 CFR Part 75.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the Agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on January 24, 2008 for good cause
found as explained in this rule.

L. Petitions for Judicial Review

    Under Clean Air Act section 307(b)(1), petitions for judicial
review of this action must be filed in the United States Court of
Appeals for the appropriate circuit by March 24, 2008. Filing a
petition for reconsideration by the Administrator of this final rule
does not affect the finality of this rule for the purposes of judicial
review, nor does it extend the time within which a petition for
judicial review may be filed, and shall not postpone the effectiveness
of such a rule or action. This action may not be challenged later in
proceedings to enforce its requirements. (See section 307(b)(2) of the
Administrative Procedures Act.)

M. Determination Under Section 307(d)

    Pursuant to Clean Air Act section 307(d)(1)(U), the Administrator
determines that this action is subject to the provisions of section
307(d). Section 307(d)(1)(U) provides that the provisions of section
307(d) apply to ``such other actions as the Administrator may
determine.'' While the Administrator did not make this determination
earlier, the Administrator believes that all of the procedural
requirements, e.g., docketing, hearing and comment periods, of section
307(d) have been complied with during the course of this rulemaking.

List of Subjects in 40 CFR Parts 72 and 75

    Environmental protection, Acid rain, Administrative practice and
procedure, Air pollution control, Carbon dioxide, Continuous emission
monitoring, Electric utilities, Incorporation by reference, Nitrogen
oxides, Reporting and recordkeeping requirements, Sulfur oxides.

    Dated: December 19, 2007.
Stephen L. Johnson,
Administrator.

0
For the reasons set forth in the preamble, parts 72 and 75 of chapter I
of title 40 of the Code of Federal Regulations are amended as follows:

PART 72--PERMITS REGULATION

0
1. The authority citation for part 72 continues to read as follows:

    Authority: 42 U.S.C. 7601 and 7651, et seq.

Subpart A--Acid Rain Program General Provisions

0
2. Section 72.2 is amended as follows:
0
a. Revising the definition of ``Capacity factor'';
0
b. In the definition of ``Diluent cap'', by removing the words ``,
CO2 mass emission rate, or heat input rate,'' after the
words ``NOX emission rate'';
0
c. In the definition of ``EPA protocol gas'', by adding a new sentence
to the end of the definition;
0
d. Revising the definition of ``Excepted monitoring system'';
0
e. Adding the new definitions in alphabetical order for ``Air Emission
Testing Body (AETB)'', ``EPA Protocol Gas Verification Program'',
``Long-term cold storage'', ``NIST traceable elemental Hg standards'',
``NIST traceable source of oxidized Hg'', ``Qualified Individual'', and
``Specialty gas producer''; and
0
f. Removing the definition for ``Research gas material (RGM)''
    The revisions and additions read as follows:

Sec.  72.2  Definitions.

* * * * *
    Air Emission Testing Body (AETB) means a company or other entity
that conducts Air Emissions Testing as described in ASTM D7036-04
(incorporated by reference under Sec.  75.6 of this part).
* * * * *
    Capacity factor means either:
    (1) The ratio of a unit's actual annual electric output (expressed
in MWe/hr) to the unit's nameplate capacity (or maximum observed hourly
gross load (in MWe/hr) if greater than the nameplate capacity) times
8760 hours; or
    (2) The ratio of a unit's annual heat input (in million British
thermal units or equivalent units of measure) to the unit's maximum
rated hourly heat input rate (in million British thermal units per hour
or equivalent units of measure) times 8,760 hours.
* * * * *
    EPA protocol gas * * * On and after January 1, 2009, vendors
advertising certification with the EPA Traceability Protocol or
distributing gases as ``EPA Protocol Gas'' must participate in the EPA
Protocol Gas Verification Program. Non-participating vendors may not
use ``EPA'' in any form of advertising for these products, unless
approved by the Administrator.
    EPA Protocol Gas Verification Program means the EPA Protocol Gas
audit program described in Section 2.1.10 of the ``EPA Traceability
Protocol for Assay and Certification of Gaseous Calibration
Standards,'' September 1997, EPA-600/R-97/121 (EPA Protocol Procedure)
or such revised procedure as approved by the Administrator.
* * * * *
    Excepted monitoring system means a monitoring system that follows
the procedures and requirements of Sec.  75.15 of this chapter, Sec.
75.19 of this chapter, Sec.  75.81(b) of this chapter or of appendix D,
or E to part 75 for approved exceptions to the use of continuous
emission monitoring systems.
* * * * *
    Long-term cold storage means the complete shutdown of a unit
intended to last for an extended period of time (at least two calendar
years) where notice for long-term cold storage is provided under Sec.
75.61(a)(7).
* * * * *
    NIST traceable elemental Hg standards means either:
    (1) Compressed gas cylinders having known concentrations of
elemental Hg, which have been prepared according to the ``EPA
Traceability Protocol for Assay and Certification of Gaseous
Calibration Standards''; or
    (2) Calibration gases having known concentrations of elemental Hg,
produced by a generator that fully meets the performance requirements
of the ``EPA Traceability Protocol for Qualification and Certification
of Elemental Mercury Gas Generators''.
* * * * *
    NIST traceable source of oxidized Hg means a generator that: Is
capable of providing known concentrations of vapor phase mercuric
chloride (HgCl2), and that fully meets the performance
requirements of the ``EPA Traceability Protocol for Qualification and
Certification of Oxidized Mercury Gas Generators''.
* * * * *
    Qualified Individual means an individual who meets the requirements
as described in ASTM D7036-04, ``Standard Practice for Competence of
Air Emission Testing Bodies'' (incorporated by reference under Sec.
75.6 of this part).
* * * * *
    Specialty gas producer means an organization that prepares and
analyzes compressed gas mixtures for use as calibration gases and that
offers the mixtures for sale to end users or to third-party vendors for
resale to end users.
* * * * *

PART 75--CONTINUOUS EMISSION MONITORING

0
3. The authority citation for Part 75 continues to read as follows:

    Authority: 42 U.S.C. 7601, and 7651k, and 7651k note.

Subpart A--General

0
4. Section 75.4 is amended by revising paragraph (d) to read as
follows:

Sec.  75.4  Compliance dates.

* * * * *
    (d) This paragraph, applies to affected units under the Acid Rain
Program and to units subject to a State or Federal pollutant mass
emissions reduction program that adopts the emission monitoring and
reporting provisions of this part. In accordance with Sec.  75.20, for
an affected unit which, on the applicable compliance date, is either in
long-term cold storage (as defined in Sec.  72.2 of this chapter) or is
shut down as the result of a planned outage or a forced outage, thereby
preventing the required continuous monitoring system certification
tests from being completed by the compliance date, the owner or
operator shall provide notice of such unit storage or outage in
accordance with Sec.  75.61(a)(3) or Sec.  75.61(a)(7), as applicable.
For the planned and unplanned unit outages described in this paragraph,
the owner or operator shall ensure that all of the continuous
monitoring systems for SO2, NOX, CO2,
Hg, opacity, and volumetric flow rate required under this part (or
under the applicable State or Federal mass emissions reduction program)
are installed and that all required certification tests are completed
no later than 90 unit operating days or 180 calendar days (whichever
occurs first) after the date that the unit recommences commercial
operation, notice of which date shall be provided under Sec.
75.61(a)(3) or Sec.  75.61(a)(7), as applicable. The owner or operator
shall determine and report SO2 concentration, NOX
emission rate, CO2 concentration, Hg concentration, and flow
rate data (as applicable) for all unit operating hours after the
applicable compliance date until all of the required certification
tests are successfully completed, using either:

    (1) The maximum potential concentration of SO2 (as
defined in section <IP_ADDRESS> of appendix A to this part), the maximum
potential NOX emission rate, as defined in Sec.  72.2 of
this chapter, the maximum potential flow rate, as defined in section
<IP_ADDRESS> of appendix A to this part, the maximum potential Hg
concentration, as defined in section <IP_ADDRESS> of appendix A to this
part, or the maximum potential CO2 concentration, as defined
in section <IP_ADDRESS> of appendix A to this part; or
    (2) The conditional data validation provisions of Sec.
75.20(b)(3); or
    (3) Reference methods under Sec.  75.22(b); or
    (4) Another procedure approved by the Administrator pursuant to a
petition under Sec.  75.66.
* * * * *

0
5. Section 75.6 is amended by:
0
a. Removing ``D129-91'' and adding in its place ``D129-00'', in
paragraph (a)(1);
0
b. Removing ``D240-87 (Reapproved 1991)'' and adding in its place
``D240-00'', in paragraph (a)(2);
0
c. Removing ``D287-82 (Reapproved 1987)'' and adding in its place
``D287-92 (Reapproved 2000)'', in paragraph (a)(3);
0
d. Removing ``D388-92'' and adding in its place ``D388-99'', in
paragraph (a)(4);
0
e. Removing and reserving paragraph (a)(5);
0
f. Removing ``D1072-90'' and adding in its place ``D1072-06'', and also
by adding the phrase ``by Combustion and Barium Chloride Titration''
after the word ``Gases'', in paragraph (a)(6);
0
g. Removing ``D1217-91'' and adding in its place ``D1217-93 (Reapproved
1998)'', in paragraph (a)(7);
0
h. Removing the phrase ``(Reapproved 1990)'', and by removing ``D1250-
80'' and adding in its place ``D1250-07'', and also by adding the
phrase ``Use of the'' after the first occurrence of the word ``for'',
in paragraph (a)(8);
0
i. Removing the phrase ``D1298-85 (Reapproved 1990), Standard Practice
for Density, Relative Density (Specific Gravity)'' and adding in its
place ``D1298-99, Standard Test Method for Density, Relative Density
(Specific Gravity),'', in paragraph (a)(9);
0
j. Removing ``D1480-91'' and adding in its place ``D1480-93 (Reapproved
1997)'', in paragraph (a)(10);
0
k. Removing ``D1481-91'' and adding in its place ``D1481-93 (Reapproved
1997)'', in paragraph (a)(11);
0
l. Removing ``D1552-90'' and adding in its place ``D1552-01'', and also
by removing the phrase, ``High Temperature'' and adding in its place
``High-Temperature'', in paragraph (a)(12);
0
m. Removing ``D1826-88'' and adding in its place ``D1826-94 (Reapproved
1998)'', in paragraph (a)(13);
0
n. Removing ``D1945-91'' and adding in its place ``D1945-96 (Reapproved
2001)'', in paragraph (a)(14);
0
o. Adding the phrase ``(Reapproved 2006)'' after ``D1946-90'', in
paragraph (a)(15);
0
p. Removing and reserving paragraph (a)(16);
0
q. Removing ``D2013-86'' and adding in its place ``D2013-01'', and also
by removing the phrase, ``Method of'', and adding in its place,
``Practice for'', in paragraph (a)(17);
0
r. Removing and reserving paragraph (a)(18);
0
s. Removing ``D2234-89'' and adding in its place ``D2234-00'', and also
by removing the phrase ``Test Methods'', and adding in its place,
``Practice'', in paragraph (a)(19);
0
t. Removing and reserving paragraph (a)(20);
0
u. Removing ``D2502-87'' and adding in its place ``D2502-92 (Reapproved
1996)'', in paragraph (a)(21);
0
v. Removing ``D2503-82 (Reapproved 1987)'' and adding in its place
``D2503-92 (Reapproved 1997)'', and also by removing the phrase
``Molecular Weight (Relative Molecular Mass)'', and by adding in its
place, ``Relative Molecular Mass (Molecular Weight)'', in paragraph
(a)(22);
0
w. Removing ``D2622-92'' and adding in its place ``D2622-98'', and also
by removing the phrase ``X-Ray Spectrometry'', and adding in its place
``Wavelength Dispersive X-ray Fluorescence Spectrometry'', in paragraph
(a)(23);
0
x. Removing ``D3174-89'' and adding in its place ``D3174-00'', and also
by removing the word ``From'' and adding in its place ``from'', in
paragraph (a)(24);
0
y. Adding the phrase ``(Reapproved 2002)'' after ``D3176-89'', in
paragraph (a)(25);
0
z. Removing ``D3177-89'' and adding in its place the phrase `` D3177-02
(Reapproved 2007)'' in paragraph (a)(26);
0
aa. 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 paragraph (a)(27);
0
bb. Removing ``D3238-90'' and adding in its place ``D3238-95
(Reapproved 2000)'', in paragraph (a)(28);
0
cc. Removing ``D3246-81 (Reapproved 1987)'' and adding in its place
``D3246-96'', and also by removing the word ``By'' and adding in its
place, ``by'', in paragraph (a)(29);
0
dd. Removing and reserving paragraph (a)(30);
0
ee. Removing ``D3588-91'' and adding in its place ``D3588-98'', and
also by removing the phrase, ``(Specific Gravity)'', in paragraph
(a)(31);
0
ff. Removing ``D4052-91'' and adding in its place ``D4052-96
(Reapproved 2002)'', in paragraph (a)(32);
0
gg. Removing ``D4057-88'' and adding in its place ``D4057-95
(Reapproved 2000)'', in paragraph (a)(33);
0
hh. Removing ``D4177-82 (Reapproved 1990)'' and adding in its place
``D4177-95 (Reapproved 2000)'', in paragraph (a)(34);
0
ii. Removing ``D4239-85'' and adding in its place ``D4239-02'', and
also by removing the phrase ``High Temperature'', and adding in its
place ``High-Temperature'', in paragraph (a)(35);
0
jj. Removing ``D4294-90'' and adding in its place ``D4294-98'', adding
the words ``and Petroleum'' after the word ``Petroleum'', by removing
the word ``X-Ray'' and adding in its place, ``X-ray'', and by removing
the word ``Spectroscopy'' and adding in its place, ``Spectrometry'' in
paragraph (a)(36);
0
kk. Removing the phrase ``(Reapproved 1989)'' and adding in its place
the phrase ``(Reapproved 2006)'', in paragraph (a)(37);
0
ll. Removing ``(reapproved 2004)'', and adding in its place,
``(Reapproved 2004)'', in paragraph (a)(38);
0
mm. Adding the phrase ``(Reapproved 2006)'' after ``D4891-89'', in
paragraph (a)(39);
0
nn. Removing ``D5291-92'' and adding in its place ``D5291-02'', in
paragraph (a)(40);
0
oo. Removing ``D5373-93'', and adding in its place ``D5373-02
(Reapproved 2007)'' and adding the word ``Test'' after the word
``Standard'', in paragraph (a)(41);
0
pp. Removing ``D5504-94'' and adding in its place ``D5504-01'', in
paragraph (a)(42);
0
qq. Adding new paragraphs (a)(45), (a)(46), (a)(47), (a)(48), and
(a)(49);
0
rr. Removing the phrase ``ASME MFC-3M-1989 with September 1990 Errata''
and adding in its place the phrase ``ASME MFC-3M-2004 (Revision of ASME
MFC-3M-1989 (R1995))'', in paragraph (b)(1);
0
ss. Removing the date ``1990'' and adding in its place the date
``1997'' in the parenthetical, in paragraph (b)(2);
0
tt. Adding the phrase ``(Reaffirmed 1994)'' after ``ASME-MFC-5M-
1985,'', in paragraph (b)(3);
0
uu. Removing the phrase ``1987 with June 1987 Errata'' and adding in
its

place the number ``1998'' at the end of ``MFC-6M-'', and also by
removing ``Flow Meters'' and adding in its place, ``Flowmeters'', in
paragraph (b)(4);
0
vv. Removing the phrase ``with December 1989 Errata'' and adding in its
place the phrase ``(Reaffirmed 2001)'', in paragraph (b)(6);
0
ww. Removing the number ``86'' and adding in its place the number
``96'' at the end of ``GPA Standard 2172-'', in paragraph (d)(1);
0
xx. Removing the number ``90'' and adding in its place the number
``00'' at the end of ``GPA Standard 2261-00'', in paragraph (d)(2);
0
yy. Revising paragraphs (f)(1) and (f)(3); and
0
zz. Adding new paragraph (f)(4).
    The revisions and additions read as follows:

Sec.  75.6  Incorporation by reference.

* * * * *
    (a) * * *
    (45) ASTM D6667-04, Standard Test Method for Determination of Total
Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases
by Ultraviolet Fluorescence, for appendix D of this part.
    (46) ASTM D4809-00, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), for
appendices D and F of this part.
    (47) ASTM D5865-01a, Standard Test Method for Gross Calorific Value
of Coal and Coke, for appendices A, D, and F of this part.
    (48) ASTM D7036-04, Standard Practice for Competence of Air
Emission Testing Bodies, for appendices A, B, and E of this part.
    (49) 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, for appendix D of
this part.
* * * * *
    (f) * * *
    (1) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 3--Tank Gauging, Section 1A, Standard
Practice for the Manual Gauging of Petroleum and Petroleum Products,
Second Edition, August 2005; Section 1B--Standard Practice for Level
Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic
Tank Gauging, Second Edition June 2001; Section 2--Standard Practice
for Gauging Petroleum and Petroleum Products in Tank Cars, First
Edition, August 1995 (Reaffirmed March 2006); Section 3--Standard
Practice for Level Measurement of Liquid Hydrocarbons in Stationary
Pressurized Storage Tanks by Automatic Tank Gauging, First Edition June
1996; Section 4--Standard Practice for Level Measurement of Liquid
Hydrocarbons on Marine Vessels by Automatic Tank Gauging, First Edition
April 1995 (Reaffirmed, March 2006); and Section 5--Standard Practice
for Level Measurement of Light Hydrocarbon Liquids Onboard Marine
Vessels by Automatic Tank Gauging, First Edition March 1997
(Reaffirmed, March 2003); for Sec.  75.19.
* * * * *
    (3) 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, for appendix D to this part.
    (4) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 22--Testing Protocol, Section 2--
Differential Pressure Flow Measurement Devices (First Edition, August
2005), for appendix D to this part.

0
6. Section 75.11 is amended by:
0
a. Revising the heading of the section;
0
b. Adding the phrase ``and 14.0% for natural gas (boilers, only);''
after the word ``wood;'', in paragraph (b)(1);
0
c. Revising paragraph (d)(3);
0
d. Revising paragraphs (e) introductory text and (e)(1);
0
e. Removing and reserving paragraph (e)(2);
0
f. Revising paragraph (e)(3) introductory text;
0
g. Add new paragraph (e)(4); and
0
h. Revising paragraph (f).
    The revisions and additions read as follows:

Sec.  75.11  Specific provisions for monitoring SO2 emissions.

* * * * *
    (d) * * *
    (3) By using the low mass emissions excepted methodology in Sec.
75.19(c) for estimating hourly SO2 mass emissions if the
affected unit qualifies as a low mass emissions unit under Sec.
75.19(a) and (b). If this option is selected for SO2, the
LME methodology must also be used for NOX and CO2
when these parameters are required to be monitored by applicable
program(s).
    (e) Special considerations during the combustion of gaseous fuels.
The owner or operator of an affected unit that uses a certified flow
monitor and a certified diluent gas (O2 or CO2)
monitor to measure the unit heat input rate shall, during any hours in
which the unit combusts only gaseous fuel, determine SO2
emissions in accordance with paragraph (e)(1) or (e)(3) of this
section, as applicable.
    (1) If the gaseous fuel qualifies for a default SO2
emission rate under Section <IP_ADDRESS>, <IP_ADDRESS>.1, or 2.3.6(b) of appendix
D to this part, the owner or operator may determine SO2
emissions by using Equation F-23 in appendix F to this part. Substitute
into Equation F-23 the hourly heat input, calculated using the
certified flow monitoring system and the certified diluent monitor
(according to the applicable equation in section 5.2 of appendix F to
this part), in conjunction with the appropriate default SO2
emission rate from section <IP_ADDRESS>, <IP_ADDRESS>.1, or 2.3.6(b) of appendix
D to this part. When this option is chosen, the owner or operator shall
perform the necessary data acquisition and handling system tests under
Sec.  75.20(c), and shall meet all quality control and quality
assurance requirements in appendix B to this part for the flow monitor
and the diluent monitor; or
    (2) [Reserved]
    (3) The owner or operator may determine SO2 mass
emissions by using a certified SO2 continuous monitoring
system, in conjunction with the certified flow rate monitoring system.
However, if the gaseous fuel is very low sulfur fuel (as defined in
Sec.  72.2 of this chapter), the SO2 monitoring system shall
meet the following quality assurance provisions when the very low
sulfur fuel is combusted:
* * * * *
    (4) The provisions in paragraph (e)(1) of this section, may also be
used for the combustion of a solid or liquid fuel that meets the
definition of very low sulfur fuel in Sec.  72.2 of this chapter,
mixtures of such fuels, or combinations of such fuels with gaseous
fuel, if the owner or operator submits a petition under Sec.  75.66 for
a default SO2 emission rate for each fuel, mixture or
combination, and if the Administrator approves the petition.
    (f) Other units. The owner or operator of an affected unit that
combusts wood, refuse, or other material in addition to oil or gas
shall comply with the monitoring provisions for coal-fired units
specified in paragraph (a) of this section, except where the owner or
operator has an approved petition to use the provisions of paragraph
(e)(1) of this section.

0
7. Section 75.12 is amended by:
0
a. Revising the section heading;
0
b. Removing the word ``and'' before the number ``15.0%'', and by adding
the phrase ``; and 18.0% for natural gas

(boilers, only)'' after the word ``wood'', in paragraph (b); and
0
c. Revising paragraph (e)(3).
    The revisions read as follows:

Sec.  75.12  Specific provisions for monitoring NOX emission
rate.

* * * * *
    (e) * * *
    (3) Use the low mass emissions excepted methodology in Sec.
75.19(c) for estimating hourly NOX emission rate and hourly
NOX mass emissions, if applicable under Sec.  75.19(a) and
(b). If this option is selected for NOX, the LME methodology
must also be used for SO2 and CO2 when these
parameters are required to be monitored by applicable program(s).
* * * * *

0
8. Section 75.13 is amended by revising paragraph (d)(3) to read as
follows:

Sec.  75.13  Specific provisions for monitoring CO2
emissions.

* * * * *
    (d) * * *
    (3) Use the low mass emissions excepted methodology in Sec.
75.19(c) for estimating hourly CO2 mass emissions, if
applicable under Sec.  75.19(a) and (b). If this option is selected for
CO2, the LME methodology must also be used for
NOX and SO2 when these parameters are required to
be monitored by applicable program(s).
0
9. Section 75.14 is amended by adding paragraph (e) to read as follows:

Sec.  75.14  Specific provisions for monitoring opacity.

* * * * *
    (e) Unit with a certified particulate matter (PM) monitoring
system. If, for a particular affected unit, the owner or operator
installs, certifies, operates, maintains, and quality-assures a
continuous particulate matter (PM) monitoring system in accordance with
Procedure 2 in appendix F to part 60 of this chapter, the unit shall be
exempt from the opacity monitoring requirement of this part.

0
10. Section 75.15 is amended by:
0
a. Removing the reference ``(j)'' and adding the reference ``(l)'' in
its place in the introductory paragraph;
0
b. Revising paragraph (h); and
0
c. Adding paragraph (l).
    The revisions and additions read as follows:

Sec.  75.15  Special provisions for measuring Hg mass emissions using
the excepted sorbent trap monitoring methodology.

* * * * *
    (h) The hourly Hg mass emissions for each collection period are
determined using the results of the analyses in conjunction with
contemporaneous hourly data recorded by a certified stack flow monitor,
corrected for the stack gas moisture content. For each pair of sorbent
traps analyzed, the average of the two Hg concentrations shall be used
for reporting purposes under ( 75.84(f). Notwithstanding this
requirement, if, due to circumstances beyond the control of the owner
or operator, one of the paired traps is accidentally lost, damaged, or
broken and cannot be analyzed, the results of the analysis of the other
trap may be used for reporting purposes, provided that:
    (1) The other trap has met all of the applicable quality-assurance
requirements of this part; and
    (2) The Hg concentration measured by the other trap is multiplied
by a factor of 1.111.
* * * * *
    (l) Whenever the type of sorbent material used by the traps is
changed, the owner or operator shall conduct a diagnostic RATA of the
modified sorbent trap monitoring system within 720 unit or stack
operating hours after the date and hour when the new sorbent material
is first used. If the diagnostic RATA is passed, data from the modified
system may be reported as quality-assured, back to the date and hour
when the new sorbent material was first used. If the RATA is failed,
all data from the modified system shall be invalidated, back to the
date and hour when the new sorbent material was first used, and data
from the system shall remain invalid until a subsequent RATA is passed.
If the required RATA is not completed within 720 unit or stack
operating hours, but is passed on the first attempt, data from the
modified system shall be invalidated beginning with the first operating
hour after the 720 unit or stack operating hour window expires and data
from the system shall remain invalid until the date and hour of
completion of the successful RATA.

0
11. Section 75.16 is amended by:
0
a. Revising paragraph (b)(1)(ii);
0
b. Adding the word ``rate'' after the phrase ``report heat input'' in
the last sentence, in paragraph (e)(1); and
0
c. In the second sentence of paragraphs (e)(3) by removing both
occurrences of the phrase ``steam flow'' and adding in its place the
phrase ``steam load'' and adding the phrase ``or mmBtu/hr thermal
output'' inside the parentheses, after the phrase ``in 1000 lb/hr'', in
paragraph (e)(3).
    The revisions read as follows:

Sec.  75.16  Special provisions for monitoring emissions from common,
bypass, and multiple stacks for SO2 emissions and heat input
determinations.

* * * * *
    (b) * * *
    (1) * * *
    (ii) Install, certify, operate, and maintain an SO2
continuous emission monitoring system and flow monitoring system in the
common stack and combine emissions for the affected units for
recordkeeping and compliance purposes.
* * * * *

0
12. Section 75.17 is amended by revising paragraph (d)(2) to read as
follows:

Sec.  75.17  Special provisions for monitoring emissions from common,
bypass, and multiple stacks for NOX emission rate.

* * * * *
    (d) * * *
    (2) Install, certify, operate, and maintain a NOX-
diluent CEMS only on the main stack. If this option is chosen, it is
not necessary to designate the exhaust configuration as a multiple
stack configuration in the monitoring plan required under Sec.  75.53,
with respect to NOX or any other parameter that is monitored
only at the main stack. For each unit operating hour in which the
bypass stack is used and the emissions are either uncontrolled (or the
add-on controls are not documented to be operating properly), report
the maximum potential NOX emission rate (as defined in Sec.
72.2 of this chapter). The maximum potential NOX emission
rate may be specific to the type of fuel combusted in the unit during
the bypass (see Sec.  75.33(c)(8)). Alternatively, for a unit with
NOX add-on emission controls, for each unit operating hour
in which the bypass stack is used and the add-on NOX
emission controls are not bypassed, the owner or operator may report
the maximum controlled NOX emission rate (MCR) instead of
the maximum potential NOX emission rate provided that the
add-on controls are documented to be operating properly, as described
in the quality assurance/quality control program for the unit, required
by section 1 in appendix B of this part. To provide the necessary
documentation, the owner or operator shall record parametric data to
verify the proper operation of the NOX add-on emission
controls as described in Sec.  75.34(d). Furthermore, the owner or
operator shall calculate the MCR using the procedure described in
section <IP_ADDRESS>(b) of appendix A to this part where the words ``maximum
potential NOX emission rate (MER)'' shall apply instead of
the words ``maximum

controlled NOX emission rate (MCR)'' and by using the
NOX MEC in the calculations instead of the NOX
MPC.

0
13. Section 75.19 is amended by:
0
a. Revising paragraph (a)(1);
0
b. Revising paragraph (c)(1)(i);
0
c. Revising paragraph (c)(1)(iv)(A)(3);
0
d. Removing the words ``Method 20'' from paragraph (c)(1)(iv)(A)(4);
0
e. Removing the words ``Method 20'' from the definition of
NOX obs in the nomenclature for Equation LM-1a under
paragraph (c)(1)(iv)(A);
0
f. Adding the phrase, ``that meets the quality assurance requirements
of either: this part, or appendix F to part 60 of this chapter, or a
comparable State CEM program,'' after the abbreviation ``CEMS'', in
paragraph (c)(1)(iv)(G);
0
g. Adding paragraphs (c)(1)(iv)(I)(3), (4), (5) and (6);
0
h. Revising paragraph (c)(3)(ii)(B)(2);
0
i. Revising paragraph (c)(3)(ii)(H);
0
j. Removing the words ``from Table LM-1 of this section'' from the
first sentence of paragraph (c)(4)(i)(A);
0
k. Revising the heading for paragraph (c)(4)(ii); and
0
l. Adding paragraph (c)(4)(ii)(D).
    The revisions and additions read as follows:

Sec.  75.19  Optional SO2, NOX, and
CO2 emissions calculation for low mass emissions units.

* * * * *
    (a) * * *
    (1) For units that meet the requirements of this paragraph (a)(1)
and paragraphs (a)(2) and (b) of this section, the low mass emissions
(LME) excepted methodology in paragraph (c) of this section may be used
in lieu of continuous emission monitoring systems or, if applicable, in
lieu of methods under appendices D, E, and G to this part, for the
purpose of determining unit heat input, NOX, SO2,
and CO2 mass emissions, and NOX emission rate
under this part. If the owner or operator of a qualifying unit elects
to use the LME methodology, it must be used for all parameters that are
required to be monitored by the applicable program(s). For example, for
an Acid Rain Program LME unit, the methodology must be used to estimate
SO2, NOX, and CO2 mass emissions,
NOX emission rate, and unit heat input.
* * * * *
    (c) * * *
    (1) * * *
    (i) If the unit combusts only natural gas and/or fuel oil, use
Table LM-1 of this section to determine the appropriate SO2
emission rate for use in calculating hourly SO2 mass
emissions under this section. Alternatively, for fuel oil combustion, a
lower, fuel-specific SO2 emission factor may be used in lieu
of the applicable emission factor from Table LM-1, if a federally
enforceable permit condition is in place that limits the sulfur content
of the oil. If this alternative is chosen, the fuel-specific
SO2 emission rate in lb/mmBtu shall be calculated by
multiplying the fuel sulfur content limit (weight percent sulfur) by
1.01. In addition, the owner or operator shall periodically determine
the sulfur content of the oil combusted in the unit, using one of the
oil sampling and analysis options described in section 2.2 of appendix
D to this part, and shall keep records of these fuel sampling results
in a format suitable for inspection and auditing. Alternatively, the
required oil sampling and associated recordkeeping may be performed
using a consensus standard (e.g., ASTM, API, etc.) that is prescribed
in the unit's Federally-enforceable operating permit, in an applicable
State regulation, or in another applicable Federal regulation. If the
unit combusts gaseous fuel(s) other than natural gas, the owner or
operator shall use the procedures in section 2.3.6 of appendix D to
this part to document the total sulfur content of each such fuel and to
determine the appropriate default SO2 emission rate for each such fuel.
* * * * *
    (iv) * * *
    (A) * * *
    (3) Do not correct the NOX concentration to 15%
O2.
* * * * *
    (I) * * *
    (3) The initial appendix E testing may be performed at a single
load, between 75 and 100 percent of the maximum sustainable load
defined in the monitoring plan for the unit, if the average annual
capacity factor of the LME unit, when calculated according to the
definition of ``capacity factor'' in Sec.  72.2 of this chapter, is 2.5
percent or less for the three calendar years immediately preceding the
year of the testing, and that the annual capacity factor does not
exceed 4.0 percent in any of those three years. Similarly, for a LME
unit that reports emissions data on an ozone season-only basis, the
initial appendix E testing may be performed at a single load between 75
and 100 percent of the maximum sustainable load if the 2.5 and 4.0
percent capacity factor requirements are met for the three ozone
seasons immediately preceding the date of the emission testing (see
Sec.  75.74(c)(11)). For a group of identical LME units, any unit(s) in
the group that meet the 2.5 and 4.0 percent capacity factor
requirements may perform the initial appendix E testing at a single
load between 75 and 100 percent of the maximum sustainable load.
    (4) The retest of any LME unit may be performed at a single load
between 75 and 100 percent of the maximum sustainable load if, for the
three calendar years immediately preceding the year of the retest (or,
if applicable, the three ozone seasons immediately preceding the date
of the retest), the applicable capacity factor requirements described
in paragraph (c)(1)(iv)(I)(3) of this section are met.
    (5) Alternatively, for combustion turbines, the single-load testing
described in paragraphs (c)(1)(iv)(I)(3) and (c)(1)(iv)(I)(4) of this
section may be performed at the highest attainable load level
corresponding to the season of the year in which the testing is
conducted.
    (6) In all cases where the alternative single-load testing option
described in paragraphs (c)(1)(iv)(I)(3) through (c)(1)(iv)(I)(5) of
this section is used, the owner or operator shall keep records
documenting that the required capacity factor requirements were met.
* * * * *
    (3) * * *
    (ii) * * *
    (B) * * *
    (2) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 3-Tank Gauging, Section 1A, Standard
Practice for the Manual Gauging of Petroleum and Petroleum Products,
Second Edition, August 2005; Section 1B-Standard Practice for Level
Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic
Tank Gauging, Second Edition June 2001; Section 2-Standard Practice for
Gauging Petroleum and Petroleum Products in Tank Cars, First Edition,
August 1995 (Reaffirmed March 2006); Section 3-Standard Practice for
Level Measurement of Liquid Hydrocarbons in Stationary Pressurized
Storage Tanks by Automatic Tank Gauging, First Edition June 1996
(Reaffirmed, March 2001); Section 4-Standard Practice for Level
Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank
Gauging, First Edition April 1995 (Reaffirmed, September 2000); and
Section 5-Standard Practice for Level Measurement of Light Hydrocarbon
Liquids Onboard Marine Vessels by Automatic Tank Gauging, First Edition
March 1997 (Reaffirmed, March 2003); for Sec.  75.19; Shop Testing of
Automatic Liquid Level Gages, Bulletin 2509 B, December 1961
(Reaffirmed August 1987, October 1992) (all incorporated by reference
under Sec.  75.6 of this part); or
* * * * *
    (H) For each low mass emissions unit or each low mass emissions
unit in a

group of identical units, the owner or operator shall determine the
cumulative quarterly unit load in megawatt hours or thousands of pounds
of steam. The quarterly cumulative unit load shall be the sum of the
hourly unit load values recorded under paragraph (c)(2) of this section
and shall be determined using Equations LM-5 or LM-6. For a unit
subject to the provisions of subpart H of this part, which is not
required to report emission data on a year-round basis and elects to
report only during the ozone season, the quarterly cumulative load for
the second calendar quarter of the year shall include only the unit
loads for the months of May and June.
[GRAPHIC] [TIFF OMITTED] TR24JA08.016

[GRAPHIC] [TIFF OMITTED] TR24JA08.017

Where:

MWqtr = Sum of all unit operating loads recorded during
the quarter by the unit (MWh).
STfuel-qtr = Sum of all hourly steam loads recorded
during the quarter by the unit (klb of steam/hr).
MW = Unit operating load for a particular unit operating hour (MWh).
ST = Unit steam load for a particular unit operating hour (klb of
steam).
* * * * *
    (4) * * *
    (ii) NOX mass emissions and NOX emission
rate.
    (D) The quarterly and cumulative NOX emission rate in
lb/mmBtu (if required by the applicable program(s)) shall be determined
as follows. Calculate the quarterly NOX emission rate by
taking the arithmetic average of all of the hourly EFNOX
values. Calculate the cumulative (year-to-date) NOX emission
rate by taking the arithmetic average of the quarterly NOX
emission rates.
* * * * *

0
14. Section 75.20 is amended by:
0
a. Adding a new sentence after the third sentence of paragraph (b)
introductory text;
0
b. Revising paragraph (c)(1)(v); and
0
c. Removing paragraphs (f)(1) and (f)(2).
    The revisions and additions read as follows:

Sec.  75.20  Initial certification and recertification procedures.

* * * * *
    (b) * * * The owner or operator shall also recertify the continuous
emission monitoring systems for a unit that has recommenced commercial
operation following a period of long-term cold storage as defined in
Sec.  72.2 of this chapter. * * *
* * * * *
    (c) * * *
    (1) * * *
    (v) A cycle time test, (where, for the NOX-diluent
continuous emission monitoring system, the test is performed separately
on the NOX pollutant concentration monitor and the diluent
gas monitor); and
* * * * *

Sec.  75.21  [Amended]

0
15. Section 75.21 is amended by removing the words ``or (e)(2)'' at the
end of the first sentence of paragraph (a)(4).
0
16. Section 75.22 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraphs (a)(5), (a)(6), and (a)(7);
0
c. Revising paragraph (b) introductory text;
0
d. Removing the word ``and'' at the end of paragraph (b)(3);
0
e. Revising paragraph (b)(5);
0
f. Adding paragraphs (b)(6), (b)(7), and (b)(8); and
0
g. Revising paragraph (c)(1) introductory text.
    The revisions and additions read as follows:

Sec.  75.22  Reference test methods.

    (a) The owner or operator shall use the following methods, which
are found in appendix A-4 to part 60 of this chapter or have been
published by ASTM, to conduct the following tests: monitoring system
tests for certification or recertification of continuous emission
monitoring systems and excepted monitoring systems under appendix E to
this part; the emission tests required under Sec.  75.81(c) and (d);
and required quality assurance and quality control tests:
* * * * *
    (5) Methods 6, 6A, 6B or 6C, and 7, 7A, 7C, 7D or 7E in appendix A-
4 to part 60 of this chapter, as applicable, are the reference methods
for determining SO2 and NOX pollutant
concentrations. (Methods 6A and 6B in appendix A-4 to part 60 of this
chapter may also be used to determine SO2 emission rate in
lb/mmBtu.) Methods 7, 7A, 7C, 7D, or 7E in appendix A-4 to part 60 of
this chapter must be used to measure total NOX emissions,
both NO and NO2, for purposes of this part. The owner or
operator shall not use the following sections, exceptions, and options
of method 7E in appendix A-4 to part 60 of this chapter:
    (i) Section 7.1 of the method allowing for use of prepared
calibration gas mixtures that are produced in accordance with method
205 in Appendix M of 40 CFR Part 51;
    (ii) The sampling point selection procedures in section 8.1 of the
method, for the emission testing of boilers and combustion turbines
under appendix E to this part. The number and location of the sampling
points for those applications shall be as specified in sections <IP_ADDRESS>
and <IP_ADDRESS> of appendix E to this part;
    (iii) Paragraph (3) in section 8.4 of the method allowing for the
use of a multi-hole probe to satisfy the multipoint traverse
requirement of the method;
    (iv) Section 8.6 of the method allowing for the use of ``Dynamic
Spiking'' as an alternative to the interference and system bias checks
of the method. Dynamic spiking may be conducted (optionally) as an
additional quality assurance check.
    (6) Method 3A in appendix A-2 and method 7E in appendix A-4 to part
60 of this chapter are the reference methods for determining
NOX and diluent emissions from stationary gas turbines for
testing under appendix E to this part.
    (7) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method) (incorporated by reference
under Sec.  75.6 of this part) is the reference method for determining
Hg concentration.
    (i) Alternatively, Method 29 in appendix A-8 to part 60 of this
chapter may be used, with these caveats: The procedures for preparation
of Hg

standards and sample analysis in sections <IP_ADDRESS> through <IP_ADDRESS>
ASTM D6784-02 (incorporated by reference under Sec.  75.6 of this part)
shall be followed instead of the procedures in sections 7.5.33 and
11.1.3 of Method 29 in appendix A-8 to part 60 of this chapter, and the
QA/QC procedures in section 13.4.2 of ASTM D6784-02 (incorporated by
reference under Sec.  75.6 of this part) shall be performed instead of
the procedures in section 9.2.3 of Method 29 in appendix A-8 to part 60
of this chapter. The tester may also opt to use the sample recovery and
preparation procedures in ASTM D6784-02 (incorporated by reference
under Sec.  75.6 of this part) instead of the Method 29 in appendix A-8
to part 60 of this chapter procedures, as follows: sections 8.2.8 and
<IP_ADDRESS> of Method 29 in appendix A-8 to part 60 of this chapter may be
replaced with sections <IP_ADDRESS> through <IP_ADDRESS> of ASTM D6784-02
(incorporated by reference under Sec.  75.6 of this part); sections
<IP_ADDRESS> and <IP_ADDRESS> of Method 29 in appendix A-8 to part 60 of this
chapter may be replaced with sections <IP_ADDRESS> through <IP_ADDRESS> of
ASTM D6784-02 (incorporated by reference under Sec.  75.6 of this
part); section 8.3.4 of Method 29 in appendix A-8 to part 60 of this
chapter may be replaced with section 13.3.4 or 13.3.6 of ASTM D6784-02
(as appropriate) (incorporated by reference under Sec.  75.6 of this
part); and section 8.3.5 of Method 29 in appendix A-8 to part 60 of
this chapter may be replaced with section 13.3.5 or 13.3.6 of ASTM
D6784-02 (as appropriate) (incorporated by reference under Sec.  75.6
of this part).
    (ii) Whenever 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, paired sampling trains are required. To validate a
RATA run or an emission test run, the relative deviation (RD),
calculated according to section 11.7 of appendix K to this part, must
not exceed 10 percent, when the average concentration is greater than
1.0 [mu]g/m\3\. If the average concentration is < =1.0 [mu]g/m\3\, the
RD must not exceed 20 percent. The RD results are also acceptable if
the absolute difference between the Hg concentrations measured by the
paired trains does not exceed 0.03 [mu]g/m\3\. If the RD criterion is
met, the run is valid. For each valid run, average the Hg
concentrations measured by the two trains (vapor phase, only).
    (iii) Two additional reference methods that may be used to measure
Hg concentration are: Method 30A, ``Determination of Total Vapor Phase
Mercury Emissions from Stationary Sources (Instrumental Analyzer
Procedure)'' and Method 30B, ``Determination of Total Vapor Phase
Mercury Emissions from Coal-Fired Combustion Sources Using Carbon
Sorbent Traps''.
    (iv) When Method 29 in appendix A-8 to part 60 of this chapter or
ASTM D6784-02 (incorporated by reference under Sec.  75.6 of this part)
is used for the Hg emission testing required under Sec. Sec.  75.81(c)
and (d), locate the reference method test points according to section
8.1 of Method 30A, and if Hg stratification testing is part of the test
protocol, follow the procedures in sections 8.1.3 through <IP_ADDRESS> of
Method 30A.
    (b) The owner or operator may use any of the following methods,
which are found in appendix A to part 60 of this chapter or have been
published by ASTM, as a reference method backup monitoring system to
provide quality-assured monitor data:
* * * * *
    (5) ASTM D6784-02, Standard Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired
Stationary Sources (Ontario Hydro Method) (incorporated by reference
under Sec.  75.6 of this part) for determining Hg concentration;
    (6) Method 29 in appendix A-8 to part 60 of this chapter for
determining Hg concentration;
    (7) Method 30A for determining Hg concentration; and
    (8) Method 30B for determining Hg concentration.
    (c)(1) Instrumental EPA Reference Methods 3A, 6C, and 7E in
appendices A-2 and A-4 of part 60 of this chapter shall be conducted
using calibration gases as defined in section 5 of appendix A to this
part. Otherwise, performance tests shall be conducted and data reduced
in accordance with the test methods and procedures of this part unless
the Administrator:
* * * * *

0
17. Section 75.31 is amended by adding a sentence to the end of
paragraph (c)(3) to read as follows:

Sec.  75.31  Initial missing data procedures.

* * * * *
    (c) * * *
    (3) * * * Alternatively, where a unit with add-on NOX
emission controls can demonstrate that the controls are operating
properly during the hour, as provided in Sec.  75.34(d), the owner or
operator may substitute, as applicable, the maximum controlled
NOX emission rate (MCR) or the maximum expected
NOX concentration (MEC).
* * * * *

0
18. Section 75.32 is amended by revising paragraph (b) to read as
follows:

Sec.  75.32  Determination of monitor data availability for standard
missing data procedures.

* * * * *
    (b) The monitor data availability shall be calculated for each hour
during each missing data period. The owner or operator shall record the
percent monitor data availability for each hour of each missing data
period to implement the missing data substitution procedures.
* * * * *

0
19. Section 75.33 is amended by:
0
a. Revising the section heading;
0
b. Removing the word ``Whenever'' and adding in its place the word
``If'', and by removing the words ``each hour of each'' and adding in
its place the words ``that hour of the'', in paragraph (b)(1)
introductory text;
0
c. Removing the word ``Whenever'' and adding in its place the word
``If'', and by removing the words ``each hour of each'' and adding in
its place the words ``that hour of the'', in paragraph (b)(2)
introductory text;
0
d. Removing the word ``Whenever'' and adding in its place the word
``If'', and by removing the word ``each'' and adding in its place the
words ``that hour of the'', in paragraphs (b)(3) and (b)(4);
0
e. Removing the word ``Whenever'' and adding in its place the word
``If'', and by removing the words ``each hour of each'' and adding in
its place the words ``that hour of the'', in paragraphs (c)(1)
introductory text, (c)(2) introductory text, (c)(3), and (c)(4);
0
f. Revising paragraph (c)(8)(iii);
0
g. Revising Tables 1 and 2 in paragraph (c)(8)(iv);
0
h. Removing the word ``Whenever'' and adding in its place the word
``If'', and by removing the words ``each hour of each'' and adding in
its place the words ``that hour of the'', in paragraphs (d)(1)
introductory text, (d)(2) introductory text, (d)(3) introductory text,
and (d)(4) introductory text.
0
i. Revising Table 3 in paragraph (e)(3); and
    The revisions and additions read as follows:

Sec.  75.33  Standard missing data procedures for SO2,
NOX, Hg, and flow rate.

* * * * *
    (c) * * *
    (8) * * *
    (iii) For the purposes of providing substitute data under paragraph
(c)(4) of this section, a separate, fuel-specific maximum potential
concentration (MPC), maximum potential NOX emission rate
(MER), or maximum

potential flow rate (MPF) value (as applicable) shall be determined for
each type of fuel combusted in the unit, in a manner consistent with
Sec.  72.2 of this chapter and with section <IP_ADDRESS> or <IP_ADDRESS> of
appendix A to this part. For co-firing, the MPC, MER or MPF value shall
be based on the fuel with the highest emission rate or flow rate (as
applicable). Furthermore, for a unit with add-on NOX
emission controls, a separate fuel-specific maximum controlled
NOX emission rate (MCR) or maximum expected NOX
concentration (MEC) value (as applicable) shall be determined for each
type of fuel combusted in the unit. The exact methodology used to
determine each fuel-specific MPC, MER, MEC, MCR or MPF value shall be
documented in the monitoring plan for the unit or stack.
    (iv) * * *

    Table 1.--Missing Data Procedure for SO2 CEMS, CO2 CEMS, Moisture CEMS, Hg CEMS, and Diluent (CO2 or O2)
                                      Monitors for Heat Input Determination
----------------------------------------------------------------------------------------------------------------
                    Trigger conditions                                      Calculation routines
----------------------------------------------------------------------------------------------------------------
     Monitor data availability       Duration (N) of CEMS
             (percent)                outage (hours) \2\             Method                 Lookback period
----------------------------------------------------------------------------------------------------------------
95 or more (90 or more for Hg)....  N < = 24..............  Average...................  HB/HA.
                                    N > 24...............  For SO2, CO2, Hg, and H2O
                                                            **, the greater of:
                                                              Average................  HB/HA.
                                                              90th percentile........  720 hours.*
                                                           For O2 and H2O\X\, the
                                                            lesser of:
                                                              10th percentile........  HB/HA.
                                                                                720 hours.*
90 or more, but below 95 (> 80 but  N <= 8...............  Average...................  HB/HA.
 <  90 for Hg).
                                    N > 8................  For SO2, CO2, Hg, and H2O
                                                            **, the greater of:
                                                              Average................  HB/HA.
                                                              95th percentile........  720 hours.*
                                                           For O2 and H2O\X\, the
                                                            lesser of:
                                                              Average................  HB/HA.
                                                              5th Percentile.........  720 hours.*
80 or more, but below 90 (> 70 but  N > 0................  For SO2, CO2, Hg, and H2O:
 <  80 for Hg).                                              **
                                                              Maximum value \1\......  720 hours.*
                                                           For O2 and H2O\X\:
                                                              Minimum value \1\......  720 hours.*
Below 80 (Below 70 for Hg)........  N > 0................  Maximum potential
                                                            concentration \3\ or %