98.254(d) and (e), provided that the gas chromatograph is operated,
maintained, and calibrated according to the manufacturer's
instructions. The methods used for operation, maintenance, and
calibration of the gas chromatograph must be documented in the written
monitoring plan for the unit under 40 CFR 98.3(g)(5). Paragraph (d) in
40 CFR 98.254 is also amended to apply to all gas composition monitors,
other than those included in 40 CFR 98.254(g), and not just flare gas
composition monitors.
    We are also amending 40 CFR 98.254(d) to specify that the methods
in this paragraph are also to be used for determining average molecular
weight of the gas, which is needed in Equations Y-1a and Y-3. We are
also adding an additional method (ASTM D2503-92) to this section for
determining average molecular weight.
    We are making a number of amendments to 40 CFR 98.254(f). The term
``exhaust gas flow meter'' is replaced with the term ``gas flow
meter,'' as proposed.
    We are retaining 40 CFR 98.254(f)(3) and portions of 40 CFR
98.254(f)(1) but only as general, supplementary guidelines for flow
monitor installation and operation. Thus, we are amending 40 CFR 98.254
to require that reporters must do all of the following:
     Install, operate, calibrate, and maintain each stack gas
flow meter according to the requirements in 40 CFR 63.1572(c);
     Locate the flow monitor at a site that provides
representative flow rates (avoiding locations where there is swirling
flow or abnormal velocity distributions); and
     Use a monitoring system capable of correcting for the
temperature, pressure, and moisture content to output flow in dry
standard cubic feet (standard conditions as defined in 40 CFR 98.6).
    We are making a technical correction to 40 CFR 98.254(g) to correct
the cross-reference from 40 CFR 63.1572(a) to 40 CFR 63.1572(c).
    We are amending 40 CFR 98.254(h) to require calibration of mass
measurement equipment according to the procedures specified by National
Institute of Standards and Technology (NIST)

Handbook 44 or the procedures specified by the manufacturer, and
removing reference to the calibration requirements in 40 CFR 98.3(i).
    Reporting requirements. This section covers reporting requirements
that have not been described in previous sections of this preamble.
    We are amending the reporting requirements in 40 CFR 98.256(e)(6)
and (8) for Equations Y-1 (renumbered to Y-1a) and Y-2, respectively,
to require reporting of whether daily or weekly measurement periods are
used, for verification purposes.
    In 40 CFR 98.256(f)(6), 40 CFR 98.256(h)(6), and 40 CFR
98.256(i)(6), we are amending the references to 40 CFR 98.36(e)(2)(vi)
to reference 40 CFR 98.36 more generally. This will make the references
consistent with the associated requirements in 40 CFR 98.253.
    We are amending 40 CFR 98.256(f) to require reporting of the unit-
specific emission factor for CH4 and N2O, if
used, in the newly designated 40 CFR 98.256(f)(11) and (12),
respectively.
    We are amending 40 CFR 98.256(i)(8) to make it consistent with the
information collected in 40 CFR 98.245(i)(7).
    We are also amending 40 CFR 98.256(j)(2) to clarify that the
reporting requirements for asphalt blowing apply at the unit level.
    We are also amending 40 CFR 98.256(o) to re-organize the reporting
requirements to separate and clarify the reporting requirement for
storage tanks used for processing unstabilized crude oil from those
reporting requirements for other types of storage tanks.
    Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
     Amending Equation Y-2 in subpart Y to provide two
alternative values of MVC in this equation (if mass flow monitors are
used) depending on the standard conditions at which the higher heating
value is determined.
     Amending requirements for gas flow meters on process vents
subject to reporting under 40 CFR 98.253(j) to comply with the
monitoring requirements in 40 CFR 98.254(c) rather than 40 CFR
98.254(f).
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional comments received can be found in the document, ``Response
to Comments: Revision to Certain Provisions of the Mandatory Reporting
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: One commenter stated that they have identified gas streams
that would otherwise fit the requirements for the use of the Tier 1 or
Tier 2 methodologies, as proposed in 40 CFR 98.252(a)(1) and (2), if it
were not for the fact that they are equipped with flow meters.
According to the commenter, these streams are not what industry would
define as ``refinery fuel gas'' but would fall under the realm of
``fuel gas'' as originally defined in 40 CFR 98.6 in the October 30,
2009, final Part 98, and in the amended definition. These can include
streams that are process off-gas or vent gases with properties much
different from traditional ``refinery fuel gas'' streams and are not
part of the refinery's fuel gas system. According to the commenter,
these off-gas streams may not be sampled currently. The commenter
asserted that many of these streams are difficult to sample (for
example, because of low pressure) or may present hazardous sampling
conditions. According to the commenter, the added rigor associated with
Tier 3 requirements is not justified for the increased safety risk,
considering the very small contribution of emissions (on the order of
0.1 percent of a refinery's total greenhouse gas emissions as estimated
by the commenter).
    Response: The proposed amendments provided limited exclusions to
the Tier 3 requirement for very small fuel gas lines or combustion
units that are not equipped with a flow meter. As noted in the preamble
of the August 11, 2010, proposed amendments, the exclusion was
specifically targeted to prevent the need to install flow meters for
these small fuel gas lines. EPA noted that ``[i]f flow meters are in
place at the process heater or at a common pipe location, we consider
that the Tier 3 monitoring requirements are reasonable and justified.''
(See 75 FR 48772.) The commenter indicated that these gas streams could
have a significantly different composition than typical refinery fuel
gas, which suggests the default fuel gas factor would have considerable
uncertainty for these gas streams, further indicating that Tier 3
sampling is necessary. While we recognize that there are inherent
safety issues with sampling any fuel gas streams, the commenter has not
provided any supporting information for the assertion that sampling
these ``process off-gas or vent gases'' is more hazardous than other
fuel gas streams at the refinery. Therefore, we are not expanding the
proposed exclusion to the Tier 3 methodology for fuel gas lines that
have a flow meter already installed in the line or upstream common
pipe. We also note that today's final amendments are not imposing new
requirements to sample these fuel gas streams; the October 30, 2009,
final Part 98 already required these fuel gas streams to be sampled for
carbon content no less than once per calendar week.
    Comment: One commenter objected to the proposed revision of 40 CFR
98.254(f) to also require exhaust gas flow meters associated with
process vents (i.e., subject to 40 CFR 98.253(j) requirements) to be
installed, operated, calibrated and maintained according the Petroleum
Refineries NESHAP (40 CFR part 63, subpart UUU) requirements in 40 CFR
63.1572(c). According to the commenter, the Petroleum Refineries NESHAP
requirements in 40 CFR 63.1572(c) contain provisions that are more
stringent than the monitoring and QA/QC requirements throughout Part
98. For example, 40 CFR 63.1572(c) requires each monitoring system to
have valid hourly average data from at least 75 percent of the hours
during which the process operated and to complete a minimum of one
cycle of operation for each successive 15-minute period with a minimum
of four successive cycles of operation to have a valid hour of data (or
at least two if a calibration check is performed during that hour or if
the continuous parameter monitoring system is out-of-control). The
commenter stated that, since the flow monitoring requirements for the
Petroleum Refineries NESHAP in 40 CFR 63.1572(c) were established to
demonstrate compliance with emission limits, they should not be used as
a template for requirements of flow metering for GHG reporting. The
commenter recommended that the process vent exhaust flow meter
requirements should be consistent with the requirements in 40 CFR
98.254(c) for flare and sour gas flow meters.
    Response: We proposed to include the requirements for flow meters
used to comply with the 40 CFR 98.253(j) for process vents within the
monitoring provisions of 40 CFR 98.254(f) because these meters are
exhaust gas flow meters rather than fuel gas flow meters. However, we
agree with the commenter that the inclusion of flow meters used to
comply with the 40 CFR 98.253(j) within the monitoring provisions of 40
CFR 98.254(f) added new requirements

to these flow meters. While we believe that the flow meter requirements
in 40 CFR 63.1572(c) of the Petroleum Refineries NESHAP are reasonable
requirements for exhaust gas flow meters in general (40 CFR 63.1572(c)
are requirements for parameter monitoring systems, not continuous
emission monitoring systems), we agree with the commenter that it is
inappropriate to add these requirements to process vent flow meters at
this juncture. Furthermore, the provisions in 40 CFR 98.253(j) allow
use of process knowledge or engineering calculations as an alternative
to direct flow measurement. As such, it is incongruous to subject
facilities that have flow meters on these process vents to additional
requirements when facilities that do not have flow meters on these
process vents may use process knowledge or engineering calculations.
Therefore, we are finalizing requirements for flow meters used to
comply with 40 CFR 98.253(j) for process vents to meet the monitoring
provisions of 40 CFR 98.254(c) rather than 40 CFR 98.254(f) as was
required per the October 30, 2009 final Part 98.

O. Subpart AA--Pulp and Paper Manufacturing

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending 40 CFR 98.273(a)(1), (b)(1) and (c)(1) to clarify
that owners and operators may choose to use a tier other than Tier 1
from 40 CFR 98.33 to calculate fossil-fuel based CO2
emissions.
    We have removed the CO2 emission factors from Table AA-2
and revised 40 CFR 98.273(c)(1) to direct owners and operators to use
the CO2 emission factors from Table C-1 of subpart C to
calculate CO2 emissions from lime kilns.
    With respect to calculating CH4 and N2O
emissions from fossil fuel combustion at lime kilns, and consistent
with the amendments to allow use of higher tiers than Tier 1 for units
subject to subpart AA, we are amending 40 CFR 98.273(a)(2), (b)(2), and
(c)(2) to allow reporters to also use site-specific high heating
values, as opposed to default values, when calculating CH4
and N2O emissions. We are making harmonizing amendments to
the definition of EF under Equation AA-1 to clarify that default or
site-specific emission factors may be used. Similarly, we are amending
40 CFR 98.276(e) to reflect the option to use default or site-specific
values.
    We are clarifying through this final rule that emissions from the
combustion of wastewater treatment sludge are calculated using the
emission factors included in Table C-1. We have determined that this
sludge falls within the definition of ``Wood and Wood Residuals''
included in Table C-1. Therefore, per 40 CFR 98.33(b)(1)(iii),
emissions from the combustion of this type of sludge may be determined
using Tier 1 in subpart C. In order to further clarify this, we are
adding the definition of ``Wood and Wood Residuals'' to 40 CFR 98.6 and
including wastewater process sludge from paper mills in this
definition, as further described in Section II.F of this preamble.
    We are adding solid petroleum coke to both Table C-1 and Table AA-
2. We have concluded that it is not necessary to have emission factors
for petroleum coke specific to kraft calciners in Table AA-2 because we
do not believe that any kraft calciners are combusting this fuel, nor
were any comments received suggesting this was not the case.
    There were no comments received specifically on subpart AA,
therefore the amendments are being finalized as proposed.

P. Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids

1. Summary of Final Amendments and Major Changes Since Proposal
    Threshold for natural gas local distribution companies. We are
amending 40 CFR Table A-5 of subpart A of 40 CFR part 98 to establish
an applicability threshold so that only local distribution companies
(LDCs) that deliver 460,000 thousand standard cubic feet (mscf) or more
of natural gas per year are subject to the reporting rule. No major
changes have been made since proposal.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: Two commenters requested that EPA apply the 460,000
thousand standard cubic feet (mscf) applicability threshold throughout
40 CFR part 98 wherever a threshold is expressed in mtCO2e.
Specifically, they contended that 40 CFR 98.2(i)(1) and (2) should be
changed to allow LDCs to stop reporting if they deliver less than 460
million cubic feet (mmcf) for 5 consecutive years or less than 276 mmcf
for 3 consecutive years (25,000 mtCO2e is approximately
equivalent to the CO2 emissions from the combustion of 460
mmcf of natural gas and 15,000 mtCO2e is approximately
equivalent to 276 mmcf of natural gas). The commenters urged EPA to
clarify that the threshold for natural gas distributors (460,000 mscf)
is equivalent to the threshold of 25,000 mtCO2e wherever
that metric ton threshold appears in the rule.
    Response: EPA has finalized an applicability threshold for LDCs of
460,000 mscf or more of natural gas delivered per year. As noted by the
commenters, we decided that it would be easier for LDCs to determine
whether or not they were above a reporting threshold expressed in mscf
than if that threshold were expressed in metric tons of carbon dioxide
equivalent for the first year of this reporting program.
    However, we have not changed the conditions for ceasing reporting.
In the 2009 final rule, 40 CFR 98.2(i) states, ``Except as provided in
this paragraph, once a facility or supplier is subject to the
requirements of this part, the owner or operator must continue for each
year thereafter to comply with all requirements of this part, including
the requirement to submit annual GHG reports, even if the facility or
supplier does not meet the applicability requirements in paragraph (a)
of this section in a future year.'' As noted by the commenter,
facilities and suppliers can cease reporting when reported emissions
are below 25,000 mtCO2e for five consecutive years or below
15,000 mtCO2e for three consecutive years, as specified in
40 CFR 98.2(i)(1) and (i)(2), respectively. It is clear in the final
rule that other than these two exceptions, a facility or supplier must
continue to report even if the facility or supplier no longer meets the
threshold for reporting
    EPA has concluded that applying a consistent threshold, expressed
in mtCO2e, in 98.2(i)(1) and 98.2(i)(2) for all reporters
levels the playing field for all reporters and is most logical. EPA
does not intend to provide equivalent thresholds under 40 CFR 98.2(i)
for various categories because it becomes too cumbersome. LDCs are
required to report, under 40 CFR 98.406(b)(8), the total annual
CO2 mass emissions that would result from complete
combustion of the natural gas delivered to end-users. By performing
this required calculation, LDCs have the necessary data to determine
whether they may cease reporting.

Q. Subpart OO--Suppliers of Industrial Greenhouse Gases

1. Summary of Final Amendments and Major Changes Since Proposal
    We are making several changes to subpart OO to respond to concerns
raised by producers of fluorinated GHGs regarding the scope of the
monitoring and reporting requirements, and clarify the scope and due
dates for certain reporting and recordkeeping requirements.
    Producers of fluorinated GHGs requested that EPA clarify that
subpart OO does not apply to fluorinated GHGs that are either emitted
or destroyed at the facility before the fluorinated GHG product is
packaged for sale or for shipment to another facility for destruction;
are produced and transformed at the same facility; or occur as low-
concentration constituents (e.g., impurities) in fluorinated GHG
products. The producers also requested that EPA amend the rule to
account for the fact that some fluorinated GHGs do not have global
warming potential values (GWPs) listed in Table A-1 of subpart A. For
fluorinated GHGs without GWPs in Table A-1, facilities cannot calculate
CO2-equivalent production as required by subpart A, and
importers and exporters cannot take advantage of the reporting
exemptions for small shipments under 40 CFR 98.416(c) and (d), which
are expressed in CO2-equivalents.
    In response to the concern regarding fluorinated GHGs that are
emitted or destroyed before the product is packaged for sale, we are
amending the definition of ``produce a fluorinated GHG'' at 40 CFR
98.410(b) to explicitly exclude the ``creation of fluorinated GHGs that
are released or destroyed at the production facility before the
production measurement at Sec.  98.414(a).'' We are also removing the
requirements at 40 CFR 98.414(j) and 98.416(a)(4) to monitor and report
the destruction of fluorinated GHGs ``that are not included in the
calculation of the mass produced in Sec.  98.413(a) because they are
removed from the production process as by-products or wastes.''
Finally, we are modifying the requirements at 40 CFR 98.414(h),
98.416(a)(3), and 98.416(a)(11) to limit them to the mass of each
fluorinated GHG that is fed into the destruction device (or
``destroyed'' in the case of 40 CFR 98.416(a)(3)) and that was
previously produced as defined at 40 CFR 98.410(b).
    These amendments will clarify that the scope of subpart OO is that
which EPA has always intended, and they will modify the destruction
monitoring and reporting requirements to be fully consistent with that
scope. As noted in the preamble to the final Part 98 (74 FR 56259), and
in the response to comments document, the intent of subpart OO is to
track the quantities of fluorinated GHGs entering and leaving the U.S.
supply of fluorinated GHGs. Specifically, subpart OO is intended to
address production of fluorinated GHGs, not emissions or destruction of
fluorinated GHGs that occur during the production process.
    As noted in the proposed Part 98 (74 FR 16580), the production
measurement at 40 CFR 98.414(a) could occur wherever it traditionally
occurs, e.g., at the inlet to the day tank or at the shipping dock, as
long as the subpart OO monitoring requirements were met (e.g., one-
percent precision and accuracy for the mass produced and for container
heels, if applicable). Emissions upstream of the production measurement
will be subject to the recently promulgated subpart L, which was signed
by EPA Administrator Lisa Jackson on November 8, 2010 and are not part
of the subpart OO source category.
    We are also amending 40 CFR 98.416(a)(3) and (a)(11) to limit the
monitoring and reporting of destroyed fluorinated GHGs to those
destroyed fluorinated GHGs that were previously ``produced'' under
today's revised definition.\6\ Such fluorinated GHGs include but are
not limited to quantities that are shipped to the facility by another
facility for destruction, and quantities that are returned to the
facility for reclamation but are found to be irretrievably
contaminated. While monitoring of some destroyed streams appears to
pose significant technical challenges,\7\ monitoring of quantities of
fluorinated GHGs that were previously produced does not. These
quantities can be weighed and analyzed by the facility upon receipt or
upon the facility's conclusion that they cannot be brought back to the
specifications for new or reusable product.
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    \6\ In Part 98, EPA required the monitoring of all streams being
destroyed because it was our understanding, based on conversations
with fluorinated GHG producers, that the mass flow of destroyed
fluorinated GHG streams was routinely monitored. To arrive at the
quantities being removed from the supply, EPA required facilities to
estimate the share of the total quantity of fluorinated GHGs
destroyed that consisted of fluorinated GHGs that were not included
in the calculation of the mass produced. This share could then be
subtracted from the total to arrive at the amounts destroyed that
were removed from the supply. In other words, monitoring and
reporting of the destruction of fluorinated GHGs that were not
included in the mass produced was required in order to estimate the
destruction of fluorinated GHGs that had been produced.
    \7\ These include (1) low-pressure conditions that make it
challenging to achieve good accuracies and precisions and under
which the installation of a flowmeter may lead to low- or no-flow
conditions, interfering with operations upstream of the meter, (2)
corrosive conditions that require the use of Tefzel-lined flow
meters, which are currently available in a limited range of sizes
and precisions, and (3) variations in stream flow rates and
compositions that are associated with purging of vessels and columns
and that make it difficult to select a meter that will measure the
full range of flows to the required accuracy and precision.
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    In response to the concern regarding fluorinated GHGs that are
produced and transformed at the same facility, we are amending the
definition of ``produce a fluorinated GHG'' to exclude ``the creation
of intermediates that are created and transformed in a single process
with no storage of the intermediates.'' We are also amending the
definition of ``produce a fluorinated GHG'' in 40 CFR 98.410(b) to
explicitly include ``the manufacture of a fluorinated GHG as an
isolated intermediate for use in a process that will result in its
transformation either at or outside of the production facility.'' We
are also adding a definition of ``isolated intermediate'' to 40 CFR
98.418. Finally, we are adding provisions to 40 CFR 98.414, 98.416, and
98.417 to clarify that isolated intermediates that are produced and
transformed at the same facility are exempt from subpart OO monitoring,
reporting, and recordkeeping requirements respectively.
    As noted by the producers, fluorinated GHGs that are produced and
transformed at the same facility never enter the U.S. supply of
industrial greenhouse gases; thus, they do not need to be reported
under subpart OO. This is true both of isolated intermediates and of
intermediates that are created and transformed in a single process with
no storage of the intermediate. However, while we are excluding the
latter from the definition of ``produce a fluorinated GHG,'' we are
including the former in that definition. This is because the
manufacture of isolated intermediates, which can lead to emissions of
those intermediates, will be of interest under the recently promulgated
subpart L and it is desirable to use the same definition of ``produce a
fluorinated GHG'' for subpart L as for subpart OO for consistency and
clarity. Thus, instead of excluding the manufacture of isolated
intermediates that are transformed at the same facility from the
definition of ``produce a fluorinated GHG,'' we are adding provisions
to exclude it from the subpart OO monitoring, reporting, and
recordkeeping requirements. We are also adding a definition of
``isolated

intermediate'' that is the same as that for the recently promulgated
subpart L.
    In response to the concern regarding fluorinated GHGs that occur as
low-concentration constituents of fluorinated GHG products, we are
defining and excluding low-concentration constituents from the
monitoring, reporting, and recordkeeping requirements for fluorinated
GHG production, exports, and imports. For purposes of production and
export, we are defining a low-concentration constituent in 40 CFR
98.418 as a fluorinated GHG constituent of a fluorinated GHG product
that occurs in the product in concentrations below 0.1 percent by mass.
This concentration is the same as that used in the definition of
``trace concentration'' used elsewhere in subpart OO. It is also
consistent with industry purity standards for HFC refrigerants (Air-
Conditioning, Heating, and Refrigeration Institute (AHRI) 700), for
SF6 used as an insulator in electrical equipment
(International Electrotechnical Commission (IEC) 60376), and for
perfluorocarbons and other fluorinated GHGs used in electronics
manufacturing (Semiconductor Equipment and Materials International
(SEMI) C3 series). To meet these standards, which set limits that range
from less than 0.1 percent to 0.5 percent for all fluorinated GHG
impurities combined, fluorinated GHG producers are likely to have
identified and quantified the concentrations of impurities at
concentrations at or above 0.1 percent for the products subject to the
standards. Finally, below concentrations of 0.1 percent, fluorinated
GHG impurities are not likely to have a significant impact on the GWP
of the product. For example, if a low-concentration constituent occurs
in concentrations of just less than 0.1 percent and has a GWP that is
ten times as large as the GWP of the main constituent of the product,
it will increase the weighted GWP of the product by just less than one
percent.
    To ensure that fluorinated GHG production facilities rely on data
of known and acceptable quality when determining whether or not to
report a minor fluorinated GHG constituent of a product, we are adding
product sampling and analytical requirements at 40 CFR 98.414(n),
corresponding calibration requirements at 40 CFR 98.414(o), and a
corresponding reporting requirement at 40 CFR 98.416(f). We are also
clarifying in 40 CFR 98.414(a) how to calculate production of each
fluorinated GHG constituent of a product.
    For purposes of fluorinated GHG imports, we are defining a ``low-
concentration constituent'' in 40 CFR 98.418 as a fluorinated GHG
constituent of a fluorinated GHG product that occurs in the product in
concentrations below 0.5 percent by mass. We are defining a higher
concentration for fluorinated GHG imports than for fluorinated GHG
production and exports because importers are less likely than producers
to have detailed information on the identities and concentrations of
minor fluorinated GHG constituents in their products.
    In response to the concerns regarding fluorinated GHGs that do not
have GWPs listed in Table A-1, we are amending subpart A to exempt such
compounds from the general subpart A requirement to report supply flows
in terms of CO2 equivalents and revising the reporting
exemptions for import and export of small shipments to be in terms of
kilograms of fluorinated GHGs or N2O, rather than tons of
CO2-equivalents. The amendment to subpart A is discussed in
more detail in Section II.F of this preamble. The exemptions for import
and export will be applied to shipments of less than 25 kilograms of
fluorinated GHGs or N2O rather than to shipments of less
than 250 metric tons of CO2e. This will enable small
shipments of fluorinated GHGs to be exempt from reporting regardless of
whether or not the fluorinated GHG has a GWP listed in Table A-1.
    Other corrections. We are also amending the reporting and
recordkeeping provisions in subpart OO to clarify those requirements
and to correct internal inconsistencies in the subpart.
    We are amending the reporting requirements in 40 CFR 98.416(a)(15)
and (c)(10) to remove N2O from the list of GHGs that must be
reported when they are transferred off site for destruction, because
N2O transferred off site for destruction is not required to
be monitored.
    We are amending 40 CFR 98.416(b) and (e) to clarify the due dates
of the one-time reports required by those paragraphs. The due date for
the one-time reports is March 31, 2011, or within 60 days of commencing
fluorinated GHG destruction or production (as applicable). The due date
in 40 CFR 98.416(e) in subpart OO was originally April 1, 2011, and
there was no provision for fluorinated GHG destruction or production
commenced after that date.
    We are amending the recordkeeping requirements in 40 CFR
98.417(a)(2) to correct and update an internal reference. The correct
reference is to ``Sec.  98.414(m) and (o),'' instead of ``Sec.
98.417(j) and (k).'' We are amending 40 CFR 98.417(b) to remove the
reference to the ``annual destruction device outlet reports'' in 40 CFR
98.416(e) since no such reporting requirement exists.
    Finally, we are amending 40 CFR 98.417(d)(2) to correct a
typographical error; that paragraph should refer to ``the invoice for
the export,'' rather than for the ``import.''
    EPA is making one clarifying editorial change in the final rule
amendments that was not in the proposed amendments. As discussed above
and in the preamble to the proposed amendments, 40 CFR 98.414(h)
requires facilities to measure the mass of each fluorinated GHG that is
fed into the destruction device and that was previously produced. If
the mass being fed into the destruction device includes more than trace
concentrations of materials other than the fluorinated GHG being
destroyed, facilities must estimate the concentrations of the
fluorinated GHGs being destroyed. They must then multiply these
concentrations by the mass measurement to obtain the mass of the
fluorinated GHGs fed into the destruction device. In the proposed
paragraph (h), the final sentence read, ``You must multiply this
concentration (mass fraction) by the mass measurement to obtain the
mass of the fluorinated GHG destroyed.'' To be consistent with the
beginning of the paragraph and to be mathematically correct, this
sentence has been corrected in the final rule to read, ``You must
multiply this concentration (mass fraction) by the mass measurement to
obtain the mass of the fluorinated GHG fed into the destruction
device.'' As specified in Equation OO-4 of 40 CFR 98.413(d), the mass
of the fluorinated GHG destroyed is obtained by multiplying the mass of
the fluorinated GHG fed into the destruction device by the destruction
efficiency of the destruction device.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: Two commenters expressed concerns that exempting low-
concentration constituents of products from monitoring and reporting
would exempt a significant amount of

emissions from reporting. These commenters requested additional
information on the GWPs of these low-concentration constituents and on
the emissions affected by the exemption.
    Response: We analyzed the potential impact of low-concentration
constituents on the total calculated flows of fluorinated GHGs into the
U.S. economy, considering both the possible masses of the low-
concentration constituents and their CO2-equivalents. We
concluded that at a level of 0.1 percent of production and 0.5 percent
of imports, identification of such constituents would have a negligible
impact on the total calculated flows of fluorinated GHGs into the U.S.
supply. It is important to note that, under the exemption for low-
concentration constituents, the masses and CO2e of low-
concentration constituents are not equated to zero. Instead, the mass
of the low-concentration constituent is assigned to the main
constituent of the product, and the GWP is assumed to be that of the
main constituent of the product. Only if the GWP or atmospheric
lifetime of the low-concentration constituent is significantly higher
than that of the main constituent is there a potential concern
associated with these assumptions.
    As noted in the preamble to the proposed rule, low-concentration
constituents are generally by-products of the reaction used to produce
the fluorinated GHG product. Although we do not have information on
every product and by-product combination, we believe, based on the
examples of which we are aware, that by-products rarely have GWPs that
are more than ten times as large as that of the product. We analyzed
the potential impact of a by-product that had ten times the GWP of the
product on the weighted GWP of the combination of the two. At a
concentration of 0.1 percent, the by-product would raise the weighted
GWP (and CO2e) above that of the product by just under one
percent. Given that the impacts of most low-concentration constituents
are likely to fall below this level, we do not consider them
significant.
    We also performed an analysis in which we conservatively assumed
that every HFC, PFC, and SF6 product had a PFC by-product
that was shipped along with it at a concentration of 0.1 percent. This
was intended to address the possibility that low-concentration
constituents had very long atmospheric lifetimes. Based on this worst-
case assumption, the quantity of PFCs flowing into the U.S. fluorinated
GHG supply was increased by less than 10 percent. It is extremely
unlikely that every HFC, PFC, and SF6 product has a PFC by-
product; in fact, the highest-volume products, the HFCs, are unlikely
to have PFC by-products. Therefore, in consideration of this analysis
and the GWP analysis, we have concluded that the exemption for low-
concentration constituents is very unlikely to lead to significant
errors in our understanding of potential emissions of fluorinated GHGs
from the U.S. supply.
    Comment: Two commenters expressed concerns regarding the proposal
to exclude from subpart OO fluorinated GHGs that are emitted or
destroyed before the fluorinated product is packaged for sale. They
requested that EPA ensure that these emissions were fully captured
under the reporting rule (e.g., subpart L) and requested that EPA
document the magnitude of these emissions and the identities and GWPs
of the compounds emitted.
    Response: As proposed, we are excluding from the definition of
``produce a fluorinated GHG'' the creation of fluorinated GHGs that are
released or destroyed at the production facility before the production
measurement. As discussed in the preamble to the proposed amendments,
such fluorinated GHGs never enter the U.S. supply of fluorinated GHGs,
and the goal of subpart OO is to monitor fluorinated GHG flows into and
out of this supply. However, the recently promulgated subpart L
requires monitoring and reporting of emissions that occur before the
production measurement. We have worked to ensure that no fluorinated
GHG emissions from fluorinated GHG production are ``missed'' under the
combined oversight of these two subparts. The magnitudes, identities,
and GWPs of the emissions that will be reported under subpart L of 40
CFR part 98 are discussed in the preamble to the proposed rule
including subpart L (75 FR 18652, April 12, 2010) and in the Technical
Support Document for subpart L.

R. Subpart PP--Suppliers of Carbon Dioxide

1. Summary of Final Amendments and Major Changes Since Proposal
    We are removing the words ``each'' from 40 CFR 98.422(a) and (b).
This change will align this section with the requirements of the rest
of subpart PP, which allow for monitoring of an aggregated flow of
CO2, versus monitoring at each production well or process
unit, if the monitoring is done at a gathering point downstream of
individual production wells or production process units.
    We are allowing suppliers to calculate the annual mass of
CO2 supplied in containers by using weigh bills, scales,
load cells, or loaded container volume readings as an alternative to
flow meters. We are making multiple amendments to the regulatory text
to accommodate this provision. First, we are redesignating 40 CFR
98.423(b) as 40 CFR 98.423(c) and adding a new 40 CFR 98.423(b) with
calculation procedures for CO2 supplied in containers.
Second, we are amending the first sentence of 40 CFR 98.423(a) to allow
use of the alternative procedures in 40 CFR 98.423(b). Third, we are
adding new QA/QC procedures for suppliers of CO2 in
containers to 40 CFR 98.424(a)(2). Fourth, we are adding missing data
procedures for suppliers of CO2 in containers to 40 CFR
98.425(d) and specifying that the missing data procedures in 40 CFR
98.425(a) are for suppliers using flow meters. Finally, we are making
multiple amendments to regulatory text in 40 CFR 98.426 so that all
data collected with weigh bills, scales, load cells, or loaded
container volume readings must be reported just as for all data
collected with flow meters.
    We are removing the requirement that CO2 measurement
must be made prior to subsequent purification, processing, or
compression at 40 CFR 98.423(a)(1), (a)(2), and (b) (which we are
redesignating as 40 CFR 98.423(c)). Because the purpose of subpart PP
is to collect accurate data on CO2 supplied to the economy,
we have concluded that measurements made after purification,
compression, or processing will continue to meet the level of data
quality and accuracy needed with respect to subpart PP, while
minimizing the burden on industry and providing greater flexibility in
measuring CO2 streams.
    To ensure that all reporters account for the appropriate quantity
of CO2 in situations where a CO2 stream is
segregated such that only a portion is captured for commercial
application or for injection and where a flow meter is used, we are
making a number of amendments. First, we are adding language at 40 CFR
98.424(a) regarding flow meter location. Reporters who have a flow
meter(s) on the main, captured CO2 stream(s) only must
locate the flow meter(s) after the point(s) of segregation. Reporters
who have a flow meter(s) on the main, captured CO2 stream
and a subsequent flow meter(s) on the CO2 stream(s) diverted
for on-site use and who choose to use the subsequent flow meter(s) to
calculate CO2 supply (i.e. the

two meter method) must locate the main flow meter(s) prior to the
point(s) of segregation and the subsequent flow meter(s) on the
CO2 stream(s) for on-site use after the point(s) of
segregation. We are also amending existing language in 40 CFR 98.424(a)
to reference this new requirement. Second, we are amending 40 CFR
98.423(a)(3) to provide reporters using the two meter approach a new
equation (Equation PP-3b) to calculate total CO2 supplied.
As a harmonizing change, we are redesignating Equation PP-3 as Equation
PP-3a. Third, we are amending 40 CFR 98.426(c) so that reporters using
the new Equation PP-3b are required to report the equation inputs and
output and the location of flow meters with respect to the point of
segregation.
    Because the amendments will allow flow meters to be located after
purification, compression, or processing, we are adding data reporting
requirements in 40 CFR 98.426 to collect additional information on flow
meter location. Specifically, we are adding that facilities will report
information on the placement of each flow meter used in relation to the
points of CO2 stream capture, dehydration, compression, and
other processing. Knowing where in the production process the flow
meter is located will enable EPA to effectively compare data across
reporters and learn about the efficacy of various CO2 stream
capture processes.
    We are specifying standard conditions under subpart PP as a
temperature and an absolute pressure of 60 [deg]F and 1 atmosphere. It
is our understanding that 60[deg] F and 1 atmosphere (which is
equivalent to 14.7 psia) are more commonly used by the industries
covered by subpart PP.
    We are making several amendments to allow the reporter to determine
the mass of a CO2 stream by converting the volumetric flow
of the CO2 stream from operating conditions to standard
conditions and then applying the density value for CO2 at
standard conditions and the measured concentration of CO2 in
the flow as a volume percent. First, we are specifying that, at the
revised standard conditions, the density of CO2 is 0.001868
metric tons per standard cubic meter. This is slightly different than
the density value proposed (0.018704) as the result of additional
research we have conducted. We are specifying that a reporter who
applies the density value for CO2 at standard conditions
must use this specified value.
    Second, we are revising the definitions of two of the input
variables to Equation PP-2 in paragraph (a)(2). Since it was finalized
(74 FR 56260, October 30, 2009), Equation PP-2 allows a reporter to
calculate annual mass of CO2 with an input for
CO2 concentration in weight percent and an input for density
of the CO2 stream. So that reporters can avail themselves of
the density value for CO2 being finalized in this action,
however, Equation PP-2 can now also be used to calculate annual mass of
CO2 with an input for CO2 concentration in volume
percent and an input for density of CO2. We note that when
we proposed this action, we did not propose to revise the definitions
of the input variables because we erroneously overlooked the mismatch
between the density value we were providing (CO2) and the
density value required by Equation PP-2 (the CO2 stream). In
order to provide all reporters with lower burden calculation
procedures, as intended by proposing a density value for
CO2, we are correcting this omission and harmonizing
Equation PP-2 with the finalized density value. We note that the
revision to the two input variables is being applied for both reporters
using flow meters and reporters using containers.
    Third, we are amending 40 CFR 98.426(b)(3) and (b)(4) to require
that for volumetric flow meters, the reporter must report quarterly
concentration either in volume or weight percent and a density value
for either CO2 or the CO2 stream, depending on
which of the two equation input descriptions provided the reporter
uses.
    Fourth, we are amending language in 40 CFR 98.424(a)(5), (a)(5)(i)
and (a)(5)(ii) to allow reporters to choose either a method published
by a consensus-based standards organization or an industry standard
practice to determine the density of the CO2 stream. We are
also replacing the word ``measure'' with the word ``determine.''
Previously, subpart PP required a reporter to use an appropriate method
published by a consensus-based standards organization to measure
density for CO2 at standard conditions, if such a method
existed. Only where no such method existed could an industry standard
practice be used. However, we have been unable to identify any method
published by a consensus-based standards organization for measuring the
density of the CO2 stream. Therefore, we are providing
reporters with more flexibility on this requirement so that they can
use an industry standard practice to calculate the density of the
CO2 stream rather than directly measure density with an
instrument, if preferred.
    Finally, we are amending the reference to the U.S. Food and Drug
Administration food-grade specifications for CO2 in 40 CFR
98.424(b)(2) to correct a typographical error. The correct reference is
21 CFR 184.1240, not 21 CFR 184.1250.
    Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
     We are adding a second aggregation equation (Equation PP-
3b) with appropriate flow meter location requirements so that a
reporter can select either the one-meter or two-meter approach for
calculating total annual mass of CO2.
     We are revising the definitions of two of the input
variables to Equation PP-2 in paragraphs 40 CFR 98.423(a)(2) and (b)(2)
so that the equation can be used to calculate annual mass of
CO2 with an input for CO2 concentration in either
volume percent and an input for density of CO2, or weight
percent CO2 and the density of the whole stream.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: One commenter asserted that one of their facilities has
already installed a CO2 meter prior to purification,
processing, or compression--as was required by 40 CFR 98.424 when Part
98 was finalized (74 FR 56260, October 30, 2009)--and because this
facility has segregation, this results in a flow meter location prior
to segregation. The commenter suggested that this facility and others
like it should be allowed to keep their flow meters in place rather
than be required to move them to a location after segregation, as was
proposed in the amendments of August 11, 2010. The commenter suggested
a two-meter approach, whereby a facility locates a main flow meter
prior to segregation on the main, captured CO2 stream and a
subsequent flow meter after segregation on the diverted CO2
stream and then calculates the CO2 for off-site commercial
use as the difference between the two. The commenter stated that this
two-meter approach should be

equally acceptable to the approach proposed.
    Response: EPA agrees that a reporter can calculate CO2
supplied for commercial transaction or injection with sufficient
accuracy with the two-meter approach suggested by the commenter, as
long as the CO2 stream diverted for on site use is the only
CO2 stream diversion after the location of the main flow
meter. If any of the main CO2 stream remaining after on-site
diversion is further diverted (to a vent for emission, for example)
then the difference between the captured CO2 stream and the
CO2 stream diverted for on-site use will not be an accurate
reflection of the CO2 supplied for commercial transaction or
injection. Therefore, EPA is finalizing two approaches for calculating
CO2 supplied, including aggregation equations with flow
meter location requirements, so that a reporter can select either the
one-meter or two-meter approach. However, we are specifying in the
monitoring and QA/QC requirements (40 CFR 98.424) that a reporter may
only follow the two-meter approach if the CO2 stream(s) for
on-site use is/are the only diversion(s) from the main, captured
CO2 stream after the main flow meter(s) location.

III. 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 12866 (58 FR 51735, October 4, 1993) and is
therefore not subject to review under the executive order.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden.
These amendments do not make substantive changes to the reporting
requirements in any of the amended subparts. In many cases, the
amendments to the reporting requirements reduce the reporting burden by
making the reporting requirements conform more closely to current
industry practices. While the final rule results in a net decrease in
collection burden, there is a new reporting requirement for facilities
with part 75 units. Previously, facilities with these units had the
option of reporting biogenic CO2 emissions separately. This
final rule requires separate reporting of biogenic CO2
emissions beginning in 2011; however facilities may use simplified
methods based on available information. The Office of Management and
Budget (OMB) has previously approved the information collection
requirements contained in the regulations promulgated on October 30,
2009, under 40 CFR part 98 under the provisions of the Paperwork
Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control
number 2060-0629. Burden is defined at 5 CFR 1320.3(b). 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.
    Further information on EPA's assessment on the impact on burden can
be found in the Revisions Cost Memo (EPA-HQ-OAR-2008-0508).

C. Regulatory Flexibility Act (RFA)

    The 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 these amendments on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration'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 these rule amendments on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities.
    The rule amendments will not impose any new significant
requirements on small entities that are not currently required by the
rules promulgated on October 30, 2009 (i.e., calculating and reporting
annual GHG emissions).
    Broadly, in developing the 2009 final rule EPA took several steps
to reduce the impact on small entities. For example, EPA determined
appropriate thresholds that reduced the number of small businesses
reporting. In addition, EPA did not require facilities to install CEMS
if they did not already have them. Facilities without CEMS can
calculate emissions using readily available data or data that are less
expensive to collect such as process data or material consumption data.
For some source categories, EPA developed tiered methods that are
simpler and less burdensome. Also, EPA required annual instead of more
frequent reporting. Finally, EPA continues to conduct significant
outreach on the mandatory GHG reporting rule and maintains an ``open
door'' policy for stakeholders to help inform EPA's understanding of
key issues for the industries.

D. Unfunded Mandates Reform Act (UMRA)

    This action contains no Federal mandates under the provisions of
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for State, local, or tribal governments or the private
sector. The action imposes no enforceable duty on any State, local or
tribal governments or the private sector. In addition, EPA determined
that the rule amendments contain no regulatory requirements that might
significantly or uniquely affect small governments because the
amendments will not impose any new requirements that are not currently
required by the rule promulgated on October 30, 2009 (i.e., calculating
and reporting annual GHG emissions), and the rule amendments will not
unfairly apply to small governments. Therefore, this action is not
subject to the requirements of section 203 of the UMRA.

E. Executive Order 13132: Federalism

    This action 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. However, for a more detailed
discussion about how these rule amendments will relate to existing
State programs, please see Section II of the preamble for the proposed
GHG reporting rule (74 FR 16457 to 16461, April 10, 2009).
    These amendments apply directly to facilities that supply fuel that
when used emit greenhouse gases or facilities that directly emit
greenhouses gases. They do not apply to governmental entities unless
the government entity owns a facility that directly emits greenhouse
gases above threshold levels (such as a landfill or stationary
combustion source), so relatively few government facilities will be
affected. This regulation also does not limit the

power of States or localities to collect GHG data and/or regulate GHG
emissions. Thus, Executive Order 13132 does not apply to this action.
    Although section 6 of Executive Order 13132 does not apply to this
action, EPA did consult with State and local officials or
representatives of State and local governments in developing the 2009
final rule. A summary of EPA's consultations with State and local
governments is provided in Section VIII.E of the preamble to the 2009
final rule (74 FR 56260, October 30, 2009).

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

    This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). The rule
amendments will not result in any changes to the requirements of Part
98. Thus, Executive Order 13175 does not apply to this action.
    Although Executive Order 13175 does not apply to this action, EPA
sought opportunities to provide information to Tribal governments and
representatives during the development of the rules promulgated on
October 30, 2009. A summary of the EPA's consultations with Tribal
officials is provided Sections VIII.E and VIII.F of the preamble to the
final GHG Reporting Rule (74 FR 56260, October 30, 2009).

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

    EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997)
as applying only to those regulatory actions that concern health or
safety risks, such that the analysis required under section 5-501 of
the Executive Order has the potential to influence the regulation. This
action 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 action is not subject to Executive Order 13211 (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 104-113 (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. NTTAA directs EPA to provide Congress,
through OMB, explanations when the Agency decides not to use available
and applicable voluntary consensus standards.
    This rulemaking involves the use of two new voluntary consensus
standards from ASTM International. Specifically, EPA will allow
facilities in the petroleum refining and petrochemical production
industries to use ASTM D2593-93(2009) Standard Test Method for
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, and
ASTM D7633-10 Standard Test Method for Carbon Black--Carbon Content, in
addition to the methods incorporated by reference in Part 98. These
additional voluntary consensus standards will provide alternative
method that owners or operators in these industries can use to monitor
GHG emissions.
    This rulemaking also involves the use of several standard methods
that are in EPA publications. These include the following:
     Protocol for Measurement of Tetrafluoromethane
(CF4) and Hexafluoroethane (C2F6)
Emissions from Primary Aluminum Production (April 2008); IBR approved
for 40 CFR 98.64(a).
     AP 42, Section 5.2, Transportation and Marketing of
Petroleum Liquids, July 2008 (AP 42, Section 5.2); http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf; in Chapter 5, Petroleum Industry,
of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition,
Volume I; IBR approved for 40 CFR 98.253(n).
     AP 42, Section 7.1, Organic Liquid Storage Tanks, November
2006 (AP 42, Section 7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf; in Chapter 7, Liquid Storage Tanks, of AP 42,
Compilation of Air Pollutant Emission Factors, 5th Edition, Volume 1;
IBR approved for 40 CFR 98.243(m)(1) and 40 CFR 98.256(o)(2)(i).
     Method 8015C, Nonhalogenated Organics By Gas
Chromatography, Revision 3, February 2007 (Method 8015C), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.pdf; in EPA
Publication No. SW-846, ``Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,'' Third Edition; IBR approved for 40 CFR
98.244(b)(4)(viii).
     Method 8021B, Aromatic And Halogenated Volatiles By Gas
Chromatography Using Photoionization And/Or Electrolytic Conductivity
Detectors, Revision 2, December 1996 (Method 8021B). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.pdf; in EPA
Publication No. SW-846, ``Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,'' Third Edition; IBR approved for 40 CFR
98.244(b)(4)(viii).
     Method 8031, Acrylonitrile By Gas Chromatography, Revision
0, September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; in EPA Publication No. SW-846, ``Test
Methods for Evaluating Solid Waste, Physical/Chemical Methods,'' Third
Edition; IBR approved for 40 CFR 98.244(b)(4)(viii).
     Method 9060A, Total Organic Carbon, Revision 1, November
2004 (Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf; in EPA Publication No. SW-846, ``Test Methods for
Evaluating Solid Waste, Physical/Chemical Methods,'' Third Edition; IBR
approved for 40 CFR 98.244(b)(4)(viii).
    These methods are being added by the final rule amendments as a
result of working with affected industries to identify existing methods
that can be used to provide the data needed to calculate GHG emissions,
proposing the addition of the methods, and considering the public
comments on the addition of the methods in the final rule making.
    No new test methods were developed for this action.

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

    Executive Order 12898 (59 FR 7629, February 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 Part 98 does 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 because it is a
rule addressing

information collection and reporting procedures.

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 (SBREFA),
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 U.S. 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 December 31, 2010.

List of Subjects in 40 CFR Part 98

    Environmental protection, Administrative practice and procedure,
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and
recordkeeping requirements.

    Dated: November 24, 2010.
Lisa P. Jackson,
Administrator.

0
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is amended as follows:

PART 98--[AMENDED]

0
1. The authority citation for part 98 continues to read as follows:

    Authority:  42 U.S.C. 7401-7671q.

Subpart A--[Amended]

0
2. Section 98.3 is amended by:
0
a. Revising paragraphs (c)(1), (c)(4) introductory text, (c)(4)(i),
(c)(4)(ii), and (c)(4)(iii) introductory text.
0
b. Adding paragraph (c)(4)(vi).
0
c. Adding a new sentence to the end of paragraph (c)(5)(i).
0
d. Adding paragraph (c)(12).
0
e. Revising the third sentence of paragraph (d)(3) introductory text.
0
f. Revising the first sentence of paragraph (f).
0
g. Revising paragraphs (g)(4) and (g)(5)(iii).
0
h. Revising paragraph (h).
0
i. Revising paragraph (i).
0
j. Adding paragraph (j).

Sec.  98.3  What are the general monitoring, reporting, recordkeeping
and verification requirements of this part?

* * * * *
    (c) * * *
    (1) Facility name or supplier name (as appropriate), and physical
street address of the facility or supplier, including the city, State,
and zip code.
* * * * *
    (4) For facilities, except as otherwise provided in paragraph
(c)(12) of this section, report annual emissions of CO2,
CH4, N2O, and each fluorinated GHG (as defined in
Sec.  98.6) as follows.
    (i) Annual emissions (excluding biogenic CO2) aggregated
for all GHG from all applicable source categories, expressed in metric
tons of CO2e calculated using Equation A-1 of this subpart.
    (ii) Annual emissions of biogenic CO2 aggregated for all
applicable source categories, expressed in metric tons.
    (iii) Annual emissions from each applicable source category,
expressed in metric tons of each applicable GHG listed in paragraphs
(c)(4)(iii)(A) through (c)(4)(iii)(E) of this section.
* * * * *
    (vi) Applicable source categories means stationary fuel combustion
sources (subpart C of this part), miscellaneous use of carbonates
(subpart U of this part), and all of the source categories listed in
Table A-3 and Table A-4 of this subpart present at the facility.
    (5) * * *
    (i) * * * For fluorinated GHGs, calculate and report
CO2e for only those fluorinated GHGs listed in Table A-1 of
this subpart.
* * * * *
    (12) For the 2010 reporting year only, facilities that have ``part
75 units'' (i.e. units that are subject to subpart D of this part or
units that use the methods in part 75 of this chapter to quantify
CO2 mass emissions in accordance with Sec.  98.33(a)(5))
must report annual GHG emissions either in full accordance with
paragraphs (c)(4)(i) through (c)(4)(iii) of this section or in full
accordance with paragraphs (c)(12)(i) through (c)(12)(iii) of this
section. If the latter reporting option is chosen, you must report:
    (i) Annual emissions aggregated for all GHG from all applicable
source categories, expressed in metric tons of CO2e
calculated using Equation A-1 of this subpart. You must include
biogenic CO2 emissions from part 75 units in these annual
emissions, but exclude biogenic CO2 emissions from any non-
part 75 units and other source categories.
    (ii) Annual emissions of biogenic CO2, expressed in
metric tons (excluding biogenic CO2 emissions from part 75
units), aggregated for all applicable source categories.
    (iii) Annual emissions from each applicable source category,
expressed in metric tons of each applicable GHG listed in paragraphs
(c)(12)(iii)(A) through (c)(12)(iii)(E) of this section.
    (A) Biogenic CO2 (excluding biogenic CO2
emissions from part 75 units).
    (B) CO2. You must include biogenic CO2
emissions from part 75 units in these totals and exclude biogenic
CO2 emissions from other non-part 75 units and other source
categories.
    (C) CH4.
    (D) N2O.
    (E) Each fluorinated GHG (including those not listed in Table A-1
of this subpart).
    (d) * * *
    (3) * * * An owner or operator that submits an abbreviated report
must submit a full GHG report according to the requirements of
paragraph (c) of this section beginning in calendar year 2012. * * *
* * * * *
    (f) Verification. To verify the completeness and accuracy of
reported GHG emissions, the Administrator may review the certification
statements described in paragraphs (c)(9) and (d)(3)(vi) of this
section and any other credible evidence, in conjunction with a
comprehensive review of the GHG reports and periodic audits of selected
reporting facilities. * * *
    (g) * * *
    (4) Missing data computations. For each missing data event, also
retain a record of the cause of the event and the corrective actions
taken to restore malfunctioning monitoring equipment.
    (5) * * *
    (iii) The owner or operator shall revise the GHG Monitoring Plan as
needed to reflect changes in production processes, monitoring
instrumentation, and quality assurance procedures; or to improve
procedures for the maintenance and repair of monitoring systems to
reduce the frequency of monitoring equipment downtime.
* * * * *
    (h) Annual GHG report revisions. (1) The owner or operator shall
submit a revised annual GHG report within 45 days of discovering that
an annual GHG report that the owner or operator previously submitted
contains one or more substantive errors. The revised report must
correct all substantive errors.
    (2) The Administrator may notify the owner or operator in writing
that an annual GHG report previously submitted by the owner or operator
contains one or more substantive errors. Such notification will
identify each such substantive error. The owner or

operator shall, within 45 days of receipt of the notification, either
resubmit the report that, for each identified substantive error,
corrects the identified substantive error (in accordance with the
applicable requirements of this part) or provide information
demonstrating that the previously submitted report does not contain the
identified substantive error or that the identified error is not a
substantive error.
    (3) A substantive error is an error that impacts the quantity of
GHG emissions reported or otherwise prevents the reported data from
being validated or verified.
    (4) Notwithstanding paragraphs (h)(1) and (h)(2) of this section,
upon request by the owner or operator, the Administrator may provide
reasonable extensions of the 45-day period for submission of the
revised report or information under paragraphs (h)(1) and (h)(2) of
this section. If the Administrator receives a request for extension of
the 45-day period, by e-mail to an address prescribed by the
Administrator, at least two business days prior to the expiration of
the 45-day period, and the Administrator does not respond to the
request by the end of such period, the extension request is deemed to
be automatically granted for 30 more days. During the automatic 30-day
extension, the Administrator will determine what extension, if any,
beyond the automatic extension is reasonable and will provide any such
additional extension.
    (5) The owner or operator shall retain documentation for 3 years to
support any revision made to an annual GHG report.
    (i) Calibration accuracy requirements. The owner or operator of a
facility or supplier that is subject to the requirements of this part
must meet the applicable flow meter calibration and accuracy
requirements of this paragraph (i). The accuracy specifications in this
paragraph (i) do not apply where either the use of company records (as
defined in Sec.  98.6) or the use of ``best available information'' is
specified in an applicable subpart of this part to quantify fuel usage
and/or other parameters. Further, the provisions of this paragraph (i)
do not apply to stationary fuel combustion units that use the
methodologies in part 75 of this chapter to calculate CO2
mass emissions.
    (1) Except as otherwise provided in paragraphs (i)(4) through
(i)(6) of this section, flow meters that measure liquid and gaseous
fuel feed rates, process stream flow rates, or feedstock flow rates and
provide data for the GHG emissions calculations shall be calibrated
prior to April 1, 2010 using the procedures specified in this paragraph
(i) when such calibration is specified in a relevant subpart of this
part. Each of these flow meters shall meet the applicable accuracy
specification in paragraph (i)(2) or (i)(3) of this section. All other
measurement devices (e.g., weighing devices) that are required by a
relevant subpart of this part, and that are used to provide data for
the GHG emissions calculations, shall also be calibrated prior to April
1, 2010; however, the accuracy specifications in paragraphs (i)(2) and
(i)(3) of this section do not apply to these devices. Rather, each of
these measurement devices shall be calibrated to meet the accuracy
requirement specified for the device in the applicable subpart of this
part, or, in the absence of such accuracy requirement, the device must
be calibrated to an accuracy within the appropriate error range for the
specific measurement technology, based on an applicable operating
standard, including but not limited to manufacturer's specifications
and industry standards. The procedures and methods used to quality-
assure the data from each measurement device shall be documented in the
written monitoring plan, pursuant to paragraph (g)(5)(i)(C) of this
section.
    (i) All flow meters and other measurement devices that are subject
to the provisions of this paragraph (i) must be calibrated according to
one of the following: You may use the manufacturer's recommended
procedures; an appropriate industry consensus standard method; or a
method specified in a relevant subpart of this part. The calibration
method(s) used shall be documented in the monitoring plan required
under paragraph (g) of this section.
    (ii) For facilities and suppliers that become subject to this part
after April 1, 2010, all flow meters and other measurement devices (if
any) that are required by the relevant subpart(s) of this part to
provide data for the GHG emissions calculations shall be installed no
later than the date on which data collection is required to begin using
the measurement device, and the initial calibration(s) required by this
paragraph (i) (if any) shall be performed no later than that date.
    (iii) Except as otherwise provided in paragraphs (i)(4) through
(i)(6) of this section, subsequent recalibrations of the flow meters
and other measurement devices subject to the requirements of this
paragraph (i) shall be performed at one of the following frequencies:
    (A) You may use the frequency specified in each applicable subpart
of this part.
    (B) You may use the frequency recommended by the manufacturer or by
an industry consensus standard practice, if no recalibration frequency
is specified in an applicable subpart.
    (2) Perform all flow meter calibration at measurement points that
are representative of the normal operating range of the meter. Except
for the orifice, nozzle, and venturi flow meters described in paragraph
(i)(3) of this section, calculate the calibration error at each
measurement point using Equation A-2 of this section. The terms ``R''
and ``A'' in Equation A-2 must be expressed in consistent units of
measure (e.g., gallons/minute, ft\3\/min). The calibration error at
each measurement point shall not exceed 5.0 percent of the reference
value.
[GRAPHIC] [TIFF OMITTED] TR17DE10.000

Where:

CE = Calibration error (%).
R = Reference value.
A = Flow meter response to the reference value.

    (3) For orifice, nozzle, and venturi flow meters, the initial
quality assurance consists of in-situ calibration of the differential
pressure (delta-P), total pressure, and temperature transmitters.
    (i) Calibrate each transmitter at a zero point and at least one
upscale point. Fixed reference points, such as the freezing point of
water, may be used for temperature transmitter calibrations. Calculate
the calibration error of each transmitter at each measurement point,
using Equation A-3 of this subpart. The terms ``R,'' ``A,'' and ``FS''
in Equation A-3 of this subpart must be in consistent units of measure
(e.g., milliamperes, inches of water, psi, degrees). For each
transmitter, the CE value at each

measurement point shall not exceed 2.0 percent of full-scale.
Alternatively, the results are acceptable if the sum of the calculated
CE values for the three transmitters at each calibration level (i.e.,
at the zero level and at each upscale level) does not exceed 6.0
percent.
[GRAPHIC] [TIFF OMITTED] TR17DE10.001

Where:
CE = Calibration error (%).
R = Reference value.
A = Transmitter response to the reference value.
FS = Full-scale value of the transmitter.

    (ii) In cases where there are only two transmitters (i.e.,
differential pressure and either temperature or total pressure) in the
immediate vicinity of the flow meter's primary element (e.g., the
orifice plate), or when there is only a differential pressure
transmitter in close proximity to the primary element, calibration of
these existing transmitters to a CE of 2.0 percent or less at each
measurement point is still required, in accordance with paragraph
(i)(3)(i) of this section; alternatively, when two transmitters are
calibrated, the results are acceptable if the sum of the CE values for
the two transmitters at each calibration level does not exceed 4.0
percent. However, note that installation and calibration of an
additional transmitter (or transmitters) at the flow monitor location
to measure temperature or total pressure or both is not required in
these cases. Instead, you may use assumed values for temperature and/or
total pressure, based on measurements of these parameters at a remote
location (or locations), provided that the following conditions are
met:
    (A) You must demonstrate that measurements at the remote
location(s) can, when appropriate correction factors are applied,
reliably and accurately represent the actual temperature or total
pressure at the flow meter under all expected ambient conditions.
    (B) You must make all temperature and/or total pressure
measurements in the demonstration described in paragraph (i)(3)(ii)(A)
of this section with calibrated gauges, sensors, transmitters, or other
appropriate measurement devices. At a minimum, calibrate each of these
devices to an accuracy within the appropriate error range for the
specific measurement technology, according to one of the following. You
may calibrate using a manufacturer's specification or an industry
consensus standard.
    (C) You must document the methods used for the demonstration
described in paragraph (i)(3)(ii)(A) of this section in the written GHG
Monitoring Plan under paragraph (g)(5)(i)(C) of this section. You must
also include the data from the demonstration, the mathematical
correlation(s) between the remote readings and actual flow meter
conditions derived from the data, and any supporting engineering
calculations in the GHG Monitoring Plan. You must maintain all of this
information in a format suitable for auditing and inspection.
    (D) You must use the mathematical correlation(s) derived from the
demonstration described in paragraph (i)(3)(ii)(A) of this section to
convert the remote temperature or the total pressure readings, or both,
to the actual temperature or total pressure at the flow meter, or both,
on a daily basis. You shall then use the actual temperature and total
pressure values to correct the measured flow rates to standard
conditions.
    (E) You shall periodically check the correlation(s) between the
remote and actual readings (at least once a year), and make any
necessary adjustments to the mathematical relationship(s).
    (4) Fuel billing meters are exempted from the calibration
requirements of this section and from the GHG Monitoring Plan and
recordkeeping provisions of paragraphs (g)(5)(i)(C), (g)(6), and (g)(7)
of this section, provided that the fuel supplier and any unit
combusting the fuel do not have any common owners and are not owned by
subsidiaries or affiliates of the same company. Meters used exclusively
to measure the flow rates of fuels that are used for unit startup are
also exempted from the calibration requirements of this section.
    (5) For a flow meter that has been previously calibrated in
accordance with paragraph (i)(1) of this section, an additional
calibration is not required by the date specified in paragraph (i)(1)
of this section if, as of that date, the previous calibration is still
active (i.e., the device is not yet due for recalibration because the
time interval between successive calibrations has not elapsed). In this
case, the deadline for the successive calibrations of the flow meter
shall be set according to one of the following. You may use either the
manufacturer's recommended calibration schedule or you may use the
industry consensus calibration schedule.
    (6) For units and processes that operate continuously with
infrequent outages, it may not be possible to meet the April 1, 2010
deadline for the initial calibration of a flow meter or other
measurement device without disrupting normal process operation. In such
cases, the owner or operator may postpone the initial calibration until
the next scheduled maintenance outage. The best available information
from company records may be used in the interim. The subsequent
required recalibrations of the flow meters may be similarly postponed.
Such postponements shall be documented in the monitoring plan that is
required under paragraph (g)(5) of this section.
    (7) If the results of an initial calibration or a recalibration
fail to meet the required accuracy specification, data from the flow
meter shall be considered invalid, beginning with the hour of the
failed calibration and continuing until a successful calibration is
completed. You shall follow the missing data provisions provided in the
relevant missing data sections during the period of data invalidation.
    (j) Measurement device installation--(1) General. If an owner or
operator required to report under subpart P, subpart X or subpart Y of
this part has process equipment or units that operate continuously and
it is not possible to install a required flow meter or other
measurement device by April 1, 2010, (or by any later date in 2010
approved by the Administrator as part of an extension of best available
monitoring methods per paragraph (d) of this section) without process
equipment or unit shutdown, or through a hot tap, the owner or operator
may request an extension from the Administrator to delay installing the
measurement device until the next scheduled process equipment or unit
shutdown. If approval for such an extension is granted by the
Administrator, the owner or operator must use best available monitoring
methods during the extension period.
    (2) Requests for extension of the use of best available monitoring
methods for measurement device installation. The owner or operator must
first provide the

Administrator an initial notification of the intent to submit an
extension request for use of best available monitoring methods beyond
December 31, 2010 (or an earlier date approved by EPA) in cases where
measurement device installation would require a process equipment or
unit shutdown, or could only be done through a hot tap. The owner or
operator must follow-up this initial notification with the complete
extension request containing the information specified in paragraph
(j)(4) of this section.
    (3) Timing of request. (i) The initial notice of intent must be
submitted no later than January 1, 2011, or by the end of the approved
use of best available monitoring methods extension in 2010, whichever
is earlier. The completed extension request must be submitted to the
Administrator no later than February 15, 2011.
    (ii) Any subsequent extensions to the original request must be
submitted to the Administrator within 4 weeks of the owner or operator
identifying the need to extend the request, but in any event no later
than 4 weeks before the date for the planned process equipment or unit
shutdown that was provided in the original request.
    (4) Content of the request. Requests must contain the following
information:
    (i) Specific measurement device for which the request is being made
and the location where each measurement device will be installed.
    (ii) Identification of the specific rule requirements (by rule
subpart, section, and paragraph numbers) requiring the measurement
device.
    (iii) A description of the reasons why the needed equipment could
not be installed before April 1, 2010, or by the expiration date for
the use of best available monitoring methods, in cases where an
extension has been granted under Sec.  98.3(d).
    (iv) Supporting documentation showing that it is not practicable to
isolate the process equipment or unit and install the measurement
device without a full shutdown or a hot tap, and that there was no
opportunity during 2010 to install the device. Include the date of the
three most recent shutdowns for each relevant process equipment or
unit, the frequency of shutdowns for each relevant process equipment or
unit, and the date of the next planned process equipment or unit
shutdown.
    (v) Include a description of the proposed best available monitoring
method for estimating GHG emissions during the time prior to
installation of the meter.
    (5) Approval criteria. The owner or operator must demonstrate to
the Administrator's satisfaction that it is not reasonably feasible to
install the measurement device before April 1, 2010 (or by the
expiration date for the use of best available monitoring methods, in
cases where an extension has been granted under paragraph (d) of this
section) without a process equipment or unit shutdown, or through a hot
tap, and that the proposed method for estimating GHG emissions during
the time before which the measurement device will be installed is
appropriate. The Administrator will not initially approve the use of
the proposed best available monitoring method past December 31, 2013.
    (6) Measurement device installation deadline. Any owner or operator
that submits both a timely initial notice of intent and a timely
completed extension request under paragraph (j)(3) of this section to
extend use of best available monitoring methods for measurement device
installation must install all such devices by July 1, 2011 unless the
extension request under this paragraph (j) is approved by the
Administrator before July 1, 2011.
    (7) One time extension past December 31, 2013. If an owner or
operator determines that a scheduled process equipment or unit shutdown
will not occur by December 31, 2013, the owner or operator may re-apply
to use best available monitoring methods for one additional time
period, not to extend beyond December 31, 2015. To extend use of best
available monitoring methods past December 31, 2013, the owner or
operator must submit a new extension request by June 1, 2013 that
contains the information required in paragraph (j)(4) of this section.
The owner or operator must demonstrate to the Administrator's
satisfaction that it continues to not be reasonably feasible to install
the measurement device before December 31, 2013 without a process
equipment or unit shutdown, or that installation of the measurement
device could only be done through a hot tap, and that the proposed
method for estimating GHG emissions during the time before which the
measurement device will be installed is appropriate. An owner or
operator that submits a request under this paragraph to extend use of
best available monitoring methods for measurement device installation
must install all such devices by December 31, 2013, unless the
extension request under this paragraph is approved by the
Administrator.

0
3. Section 98.4 is amended by revising paragraphs (i)(2) and (m)(2)(i)
to read as follows:

Sec.  98.4  Authorization and responsibilities of the designated
representative.

* * * * *
    (i) * * *
    (2) The name, organization name (company affiliation-employer),
address, e-mail address (if any), telephone number, and facsimile
transmission number (if any) of the designated representative and any
alternate designated representative.
* * * * *
    (m) * * *
    (2) * * *
    (i) The name, organization name (company affiliation-employer)
address, e-mail address (if any), telephone number, and facsimile
transmission number (if any) of such designated representative or
alternate designated representative.
* * * * *
0
4. Section 98.6 is amended by:

0
a. Adding in alphabetical order definitions for ``Agricultural by-
products,'' ``Primary fuel,'' ``Solid by-products,'' ``Used oil,'' and
``Wood residuals.''
0
b. Revising the definitions for ``Bulk natural gas liquid or NGL,''
``Distillate Fuel Oil,'' ``Fossil fuel,'' ``Fuel gas,'' ``Municipal
solid waste or MSW,'' ``Natural gas,'' ``Natural gas liquids (NGLs) and
``Standard conditions or standard temperature and pressure (STP).''
0
c. Removing the definition for ``Fossil fuel-fired.''

Sec.  98.6  Definitions.

* * * * *
    Agricultural by-products means those parts of arable crops that are
not used for the primary purpose of producing food. Agricultural by-
products include, but are not limited to, oat, corn and wheat straws,
bagasse, peanut shells, rice and coconut husks, soybean hulls, palm
kernel cake, cottonseed and sunflower seed cake, and pomace.
* * * * *
    Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons
that have been separated from natural gas as liquids through the
process of absorption, condensation, adsorption, or other methods.
Generally, such liquids consist of ethane, propane, butanes, and
pentanes plus. Bulk NGL is sold to fractionators or to refineries and
petrochemical plants where the fractionation takes place.
* * * * *
    Distillate fuel oil means a classification for one of the petroleum

fractions produced in conventional distillation operations and from
crackers and hydrotreating process units. The generic term distillate
fuel oil includes kerosene, kerosene-type jet fuel, diesel fuels
(Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1,
No. 2, and No. 4).
* * * * *
    Fossil fuel means natural gas, petroleum, coal, or any form of
solid, liquid, or gaseous fuel derived from such material, for purpose
of creating useful heat.
* * * * *
    Fuel gas means gas generated at a petroleum refinery or
petrochemical plant and that is combusted separately or in any
combination with any type of gas.
* * * * *
    Municipal solid waste or MSW means solid phase household,
commercial/retail, and/or institutional waste. Household waste includes
material discarded by single and multiple residential dwellings,
hotels, motels, and other similar permanent or temporary housing
establishments or facilities. Commercial/retail waste includes material
discarded by stores, offices, restaurants, warehouses, non-
manufacturing activities at industrial facilities, and other similar
establishments or facilities. Institutional waste includes material
discarded by schools, nonmedical waste discarded by hospitals, material
discarded by non-manufacturing activities at prisons and government
facilities, and material discarded by other similar establishments or
facilities. Household, commercial/retail, and institutional wastes
include yard waste, refuse-derived fuel, and motor vehicle maintenance
materials. Insofar as there is separate collection, processing and
disposal of industrial source waste streams consisting of used oil,
wood pallets, construction, renovation, and demolition wastes (which
includes, but is not limited to, railroad ties and telephone poles),
paper, clean wood, plastics, industrial process or manufacturing
wastes, medical waste, motor vehicle parts or vehicle fluff, or used
tires that do not contain hazardous waste identified or listed under 42
U.S.C. Sec.  6921, such wastes are not municipal solid waste. However,
such wastes qualify as municipal solid waste where they are collected
with other municipal solid waste or are otherwise combined with other
municipal solid waste for processing and/or disposal.
* * * * *
    Natural gas means a naturally occurring mixture of hydrocarbon and
non-hydrocarbon gases found in geologic formations beneath the earth's
surface, of which the principal constituent is methane. Natural gas may
be field quality or pipeline quality.
    Natural gas liquids (NGLs) means those hydrocarbons in natural gas
that are separated from the gas as liquids through the process of
absorption, condensation, adsorption, or other methods. Generally, such
liquids consist of ethane, propane, butanes, and pentanes plus. Bulk
NGLs refers to mixtures of NGLs that are sold or delivered as
undifferentiated product from natural gas processing plants.
* * * * *
    Primary fuel means the fuel that provides the greatest percentage
of the annual heat input to a stationary fuel combustion unit.
* * * * *
    Solid by-products means plant matter such as vegetable waste,
animal materials/wastes, and other solid biomass, except for wood, wood
waste, and sulphite lyes (black liquor).
* * * * *
    Standard conditions or standard temperature and pressure (STP), for
the purposes of this part, means either 60 or 68 degrees Fahrenheit and
14.7 pounds per square inch absolute.
* * * * *
    Used oil means a petroleum-derived or synthetically-derived oil
whose physical properties have changed as a result of handling or use,
such that the oil cannot be used for its original purpose. Used oil
consists primarily of automotive oils (e.g., used motor oil,
transmission oil, hydraulic fluids, brake fluid, etc.) and industrial
oils (e.g., industrial engine oils, metalworking oils, process oils,
industrial grease, etc).
* * * * *
    Wood residuals means materials recovered from three principal
sources: Municipal solid waste (MSW); construction and demolition
debris; and primary timber processing. Wood residuals recovered from
MSW include wooden furniture, cabinets, pallets and containers, scrap
lumber (from sources other than construction and demolition
activities), and urban tree and landscape residues. Wood residuals from
construction and demolition debris originate from the construction,
repair, remodeling and demolition of houses and non-residential
structures. Wood residuals from primary timber processing include bark,
sawmill slabs and edgings, sawdust, and peeler log cores. Other sources
of wood residuals include, but are not limited to, railroad ties,
telephone and utility poles, pier and dock timbers, wastewater process
sludge from paper mills, trim, sander dust, and sawdust from wood
products manufacturing (including resinated wood product residuals),
and logging residues.
* * * * *

0
5. Section 98.7 is amended by:
0
a. Removing and reserving paragraph (b).
0
b. Revising paragraphs (d)(1) through (d)(10).
0
c. Removing paragraph (d)(11).
0
d. Revising paragraph (e)(4).
0
e. Removing and reserving paragraph (e)(7).
0
f. Revising paragraphs (e)(8), (e)(10), (e)(11), (e)(14) and (e)(15).
0
g. Revising paragraphs (e)(19) and (e)(20).
0
h. Revising paragraphs (e)(24) through (e)(27).
0
i. Removing and reserving paragraph (e)(28).
0
j. Revising paragraph (e)(30).
0
k. Revising paragraph (e)(33).
0
l. Revising paragraph (e)(36).
0
m. Removing and reserving paragraph (e)(39).
0
n. Adding paragraphs (e)(48) and (e)(49).
0
o. Removing and reserving paragraph (f)(1).
0
p. Revising paragraph (f)(2).
0
q. Removing and reserving paragraph (g)(3).
0
r. Revising paragraph (m)(3).
0
s. Adding paragraphs (m)(8) through (m)(14).

Sec.  98.7  What standardized methods are incorporated by reference
into this part?

* * * * *
    (d) * * *
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved
for Sec.  98.124(m)(1), Sec.  98.324(e), Sec.  98.354(d), Sec.
98.354(h), Sec.  98.344(c) and Sec.  98.364(e).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters, IBR approved for Sec.  98.124(m)(2), Sec.  98.324(e),
Sec.  98.344(c), Sec.  98.354(h), and Sec.  98.364(e).
    (3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow
in Closed Conduits Using Transit-Time Ultrasonic Flow Meters, IBR
approved for Sec.  98.124(m)(3) and Sec.  98.354(d).
    (4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters, IBR approved for Sec.  98.124(m)(4), Sec.
98.324(e), Sec.  98.344(c), Sec.  98.354(h), and Sec.  98.364(e).
    (5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles, IBR approved for Sec.
98.124(m)(5),

Sec.  98.324(e), Sec.  98.344(c), Sec.  98.354(h), and Sec.  98.364(e).
    (6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow
in Closed Conduits by Weighing Method, IBR approved for Sec.
98.124(m)(6).
    (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters, IBR approved for Sec.  98.124(m)(7), Sec.
98.324(e), Sec.  98.344(c), and Sec.  98.354(h).
    (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters, IBR approved for Sec.  98.124(m)(8), Sec.
98.324(e), Sec.  98.344(c), Sec.  98.354(h), and Sec.  98.364(e).
    (9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits
with Electromagnetic Flow Meters, IBR approved for Sec.  98.354(d).
    (10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable
Area Meters, IBR approved for Sec.  98.324(e), Sec.  98.344(c), Sec.
98.354(h), and Sec.  98.364(e).
    (e) * * *
    (4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR
approved for Sec.  98.254(e).
* * * * *
    (8) ASTM D1826-94 (Reapproved 2003) Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter, IBR approved for Sec.  98.254(e).
* * * * *
    (10) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas
by Gas Chromatography, IBR approved for Sec.  98.74(c), Sec.
98.164(b), Sec.  98.244(b), Sec.  98.254(d), Sec.  98.324(d), Sec.
98.354(g), and Sec.  98.344(b).
    (11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis
of Reformed Gas by Gas Chromatography, IBR approved for Sec.  98.74(c),
Sec.  98.164(b), Sec.  98.254(d), Sec.  98.324(d), Sec.  98.344(b),
Sec.  98.354(g), and Sec.  98.364(c).
* * * * *
    (14) ASTM D2502-04 Standard Test Method for Estimation of Mean
Relative Molecular Mass of Petroleum Oils From Viscosity Measurements,
IBR approved for Sec.  98.74(c).
    (15) ASTM D2503-92 (Reapproved 2007) Standard Test Method for
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by
Thermoelectric Measurement of Vapor Pressure, IBR approved for Sec.
98.74(c) and Sec.  98.254(d)(6).
* * * * *
    (19) ASTM D3238-95 (Reapproved 2005) Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method, IBR approved for Sec.  98.74(c) and
Sec.  98.164(b).
    (20) ASTM D3588-98 (Reapproved 2003) Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels, IBR approved for Sec.  98.254(e).
* * * * *
    (24) ASTM D4809-06 Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for Sec.  98.254(e).
    (25) ASTM D4891-89 (Reapproved 2006) Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion, IBR approved for Sec.  98.254(e) and Sec.  98.324(d).
    (26) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants, IBR approved for Sec.  98.74(c),
Sec.  98.164(b), Sec.  98.244(b), and Sec.  98.254(i).
    (27) ASTM D5373-08 Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal, IBR approved for Sec.  98.74(c), Sec.  98.114(b), Sec.
98.164(b), Sec.  98.174(b), Sec.  98.184(b), Sec.  98.244(b), Sec.
98.254(i), Sec.  98.274(b), Sec.  98.284(c), Sec.  98.284(d), Sec.
98.314(c), Sec.  98.314(d), Sec.  98.314(f), and Sec.  98.334(b).
* * * * *
    (30) ASTM D6348-03 Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, IBR approved for Sec.  98.54(b), Sec.
98.124(e)(2), Sec.  98.224(b), and Sec.  98.414(n).
* * * * *
    (33) ASTM D6866-08 Standard Test Methods for Determining the
Biobased Content of Solid, Liquid, and Gaseous Samples Using
Radiocarbon Analysis, IBR approved for Sec.  98.34(d), Sec.  98.34(e),
and Sec.  98.36(e).
* * * * *
    (36) ASTM D7459-08 Standard Practice for Collection of Integrated
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived
Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved
for Sec.  98.34(d), Sec.  98.34(e), and Sec.  98.36(e).
* * * * *
    (48) ASTM D2593-93 (Reapproved 2009) Standard Test Method for
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography,
approved July 1, 2009, IBR approved for Sec.  98.244(b)(4)(xi).
    (49) ASTM D7633-10 Standard Test Method for Carbon Black--Carbon
Content, approved May 15, 2010, IBR approved for Sec.
98.244(b)(4)(xii).
* * * * *
    (f) * * *
    (1) [Reserved]
    (2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography, IBR approved for Sec.  98.164(b), Sec.
98.254(d), Sec.  98.344(b), and Sec.  98.354(g).
* * * * *
    (m) * * *
    (3) Protocol for Measuring Destruction or Removal Efficiency (DRE)
of Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing, Version 1, EPA-430-R-10-003, March 2010 (EPA 430-R-10-
003), http://www.epa.gov/semiconductor-pfc/documents/dre_protocol.pdf,
IBR approved for Sec.  98.94(f)(4)(i), Sec.  98.94(g)(3), Sec.
98.97(d)(4), Sec.  98.98, Sec.  98.124(e)(2), and Sec.  98.414(n)(1).
* * * * *
    (8) Protocol for Measurement of Tetrafluoromethane (CF4)
and Hexafluoroethane (C2F6) Emissions from
Primary Aluminum Production (2008), http://www.epa.gov/highgwp/aluminum-pfc/documents/measureprotocol.pdf, IBR approved for Sec.
98.64(a).
    (9) AP 42, Section 5.2, Transportation and Marketing of Petroleum
Liquids, July 2008, (AP 42, Section 5.2); http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf; in Chapter 5, Petroleum Industry, of AP 42,
Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I,
IBR approved for Sec.  98.253(n).
    (10) Method 9060A, Total Organic Carbon, Revision 1, November 2004
(Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf; in EPA Publication No. SW-846, ``Test Methods for Evaluating
Solid Waste, Physical/Chemical Methods,'' Third Edition, IBR approved
for Sec.  98.244(b)(4)(viii).
    (11) Method 8031, Acrylonitrile By Gas Chromatography, Revision 0,
September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; in EPA Publication No. SW-846, ``Test
Methods for Evaluating Solid Waste, Physical/Chemical Methods,'' Third
Edition, IBR approved for Sec.  98.244(b)(4)(viii).
    (12) Method 8021B, Aromatic and Halogenated Volatiles By Gas
Chromatography Using Photoionization and/or Electrolytic Conductivity
Detectors, Revision 2, December 1996 (Method 8021B). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.pdf; in EPA
Publication No. SW-846, ``Test Methods for Evaluating Solid

Waste, Physical/Chemical Methods,'' Third Edition, IBR approved for
Sec.  98.244(b)(4)(viii).
    (13) Method 8015C, Nonhalogenated Organics By Gas Chromatography,
Revision 3, February 2007 (Method 8015C). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.pdf; in EPA Publication No. SW-846,
``Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,''
Third Edition, IBR approved for Sec.  98.244(b)(4)(viii).
    (14) AP 42, Section 7.1, Organic Liquid Storage Tanks, November
2006 (AP 42, Section 7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf; in Chapter 7, Liquid Storage Tanks, of AP 42,
Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I,
IBR approved for Sec.  98.253(m)(1) and Sec.  98.256(o)(2)(i).

0
6. Table A-5 to subpart A of part 98 is amended by revising the entry
for paragraph (B) under the heading ``Natural gas and natural gas
liquids suppliers (subpart NN)'' to read as follows:

   Table A-5 to Subpart A of Part 98--Supplier Category List for Sec.
                               98.2(a)(4)
------------------------------------------------------------------------

-------------------------------------------------------------------------
       Supplier Categories \a\ Applicable in 2010 and Future Years
------------------------------------------------------------------------

                                * * * * *
Natural gas and natural gas liquids suppliers (subpart NN)

                                * * * * *
(B) Local natural gas distribution companies that deliver 460,000
 thousand standard cubic feet or more of natural gas per year.

                                * * * * *
------------------------------------------------------------------------
\a\ Suppliers are defined in each applicable subpart.

---------------------------------------------------------------------------
Subpart C--[Amended]

0
7. Section 98.30 is amended by:
0
a. Revising paragraph (b)(4).
0
b. Revising paragraph (c) introductory text.
0
c. Adding paragraph (d).

Sec.  98.30  Definition of the source category.

* * * * *
    (b) * * *
    (4) Flares, unless otherwise required by provisions of another
subpart of this part to use methodologies in this subpart.
* * * * *
    (c) For a unit that combusts hazardous waste (as defined in Sec.
261.3 of this chapter), reporting of GHG emissions is not required
unless either of the following conditions apply:
* * * * *
    (d) You are not required to report GHG emissions from pilot lights.
A pilot light is a small auxiliary flame that ignites the burner of a
combustion device when the control valve opens.

0
8. Section 98.32 is revised to read as follows:

Sec.  98.32  GHGs to report.

    You must report CO2, CH4, and N2O
mass emissions from each stationary fuel combustion unit, except as
otherwise indicated in this subpart.

0
9. Section 98.33 is amended by:
0
a. Revising paragraph (a) introductory text and paragraph (a)(1).
0
b. Revising the definition of ``HHV'' in Equation C-2a of paragraph
(a)(2)(i).
0
c. Revising the first two sentences of paragraph (a)(2)(ii)
introductory text.
0
d. In paragraph (a)(2)(ii)(A), revising the first sentence and the
definitions of ``(HHV)i,'' ``(Fuel)i,'' and ``n''
in Equation C-2b.
0
e. Revising paragraph (a)(2)(ii)(B).
0
f. Revising the definitions of ``CC'', ``MW'', and ``MVC'' in Equation
C-5 of paragraph (a)(3)(iii).
0
g. Revising paragraphs (a)(3)(iv), (a)(3)(v), (a)(4)(iii), and
(a)(4)(iv).
0
h. Adding paragraph (a)(4)(viii).
0
i. Revising paragraphs (a)(5) introductory text, (a)(5)(i) introductory
text, (a)(5)(i)(A), (a)(5)(i)(B), (a)(5)(ii) introductory text,
(a)(5)(ii)(A), (a)(5)(iii) introductory text, (a)(5)(iii)(A), and
(a)(5)(iii)(B).
0
j. Redesignating paragraph (a)(5)(iii)(D) as paragraph (a)(5)(iv), and
revising newly designated paragraph (a)(5)(iv).
0
k. Revising paragraph (b)(1)(iv).
0
l. Adding paragraphs (b)(1)(v), (b)(1)(vi) and (b)(1)(vii).
0
m. Revising paragraphs (b)(2)(ii), (b)(3)(ii)(A), (b)(3)(iii)
introductory text, and (b)(3)(iii)(B).
0
n. Adding paragraph (b)(3)(iv).
0
o. Adding a second sentence to paragraph (b)(4)(i).
0
p. Revising paragraphs (b)(4)(ii)(A), (b)(4)(ii)(B), (b)(4)(ii)(E),
(b)(4)(ii)(F), and (b)(4)(iii) introductory text.
0
q. Adding paragraph (b)(4)(iv).
0
r. Revising paragraph (b)(5) and the third sentence of paragraph
(b)(6).
0
s. Revising paragraph (c)(1) introductory text and the definition of
``HHV'' in Equation C-8.
0
t. Adding paragraphs (c)(1)(i) and (c)(1)(ii).
0
u. Revising the second sentence of paragraph (c)(2).
0
v. In paragraph (c)(4) introductory text, revising the only sentence
and revising the definition of ``(HI)A'' in Equation C-10.
0
w. Revising paragraphs (c)(4)(i) and (c)(4)(ii).
0
x. Revising paragraph (c)(5).
0
y. Adding paragraph (c)(6).
0
z. In paragraph (d)(1), revising the first sentence, adding a second
sentence, and revising the definition of ``R'' in Equation C-11.
0
aa. Revising paragraphs (d)(2), paragraph (e) introductory text,
paragraph (e)(1), and paragraph (e)(2) introductory text.
0
bb. Revising the definition of ``Fc'' in Equation C-13 of
paragraph (e)(2)(iii).
0
cc. Revising paragraphs (e)(2)(iv), (e)(2)(vi)(C), and (e)(3).
0
dd. Removing paragraph (e)(4).
0
ee. Redesignating paragraph (e)(5) as (e)(4).
0
ff. Revising the first sentence of newly designated paragraph (e)(4).
0
gg. Adding paragraph (e)(5).

Sec.  98.33  Calculating GHG emissions.

* * * * *
    (a) CO2 emissions from fuel combustion. Calculate CO2
mass emissions by using one of the four calculation methodologies in
paragraphs (a)(1) through (a)(4) of this section, subject to the
applicable conditions, requirements, and restrictions set forth in
paragraph (b) of this section. Alternatively, for units that meet the
conditions of paragraph (a)(5) of this section, you may use
CO2 mass emissions calculation methods from part 75 of this
chapter, as described in paragraph (a)(5) of this section. For units
that combust both biomass and fossil fuels, you must calculate and
report CO2 emissions from the combustion of biomass
separately using the methods in paragraph (e) of this section, except
as otherwise provided in paragraphs (a)(5)(iv) and (e) of this section
and in Sec.  98.36(d).
    (1) Tier 1 Calculation Methodology. Calculate the annual
CO2 mass emissions for each type of fuel by using Equation
C-1, C-1a, or C-1b of this section (as applicable).
    (i) Use Equation C-1 except when natural gas billing records are
used to quantify fuel usage and gas consumption is expressed in units
of therms or million Btu. In that case, use Equation C-1a or C-1b, as
applicable.

[GRAPHIC] [TIFF OMITTED] TR17DE10.015

Where:

CO2 = Annual CO2 mass emissions for the
specific fuel type (metric tons).
Fuel = Mass or volume of fuel combusted per year, from company
records as defined in Sec.  98.6 (express mass in short tons for
solid fuel, volume in standard cubic feet for gaseous fuel, and
volume in gallons for liquid fuel).
HHV = Default high heat value of the fuel, from Table C-1 of this
subpart (mmBtu per mass or mmBtu per volume, as applicable).
EF = Fuel-specific default CO2 emission factor, from
Table C-1 of this subpart (kg CO2/mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric
tons.

    (ii) If natural gas consumption is obtained from billing records
and fuel usage is expressed in therms, use Equation C-1a.
[GRAPHIC] [TIFF OMITTED] TR17DE10.016

Where:

CO2 = Annual CO2 mass emissions from natural
gas combustion (metric tons).
Gas = Annual natural gas usage, from billing records (therms).
EF = Fuel-specific default CO2 emission factor for
natural gas, from Table C-1 of this subpart (kg CO2/
mmBtu).
0.1 = Conversion factor from therms to mmBtu
1 x 10-3 = Conversion factor from kilograms to metric
tons.

    (iii) If natural gas consumption is obtained from billing records
and fuel usage is expressed in mmBtu, use Equation C-1b.
[GRAPHIC] [TIFF OMITTED] TR17DE10.017

Where:

CO2 = Annual CO2 mass emissions from natural
gas combustion (metric tons).
Gas = Annual natural gas usage, from billing records (mmBtu).
EF = Fuel-specific default CO2 emission factor for
natural gas, from Table C-1 of this subpart (kg CO2/
mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric
tons.

    (2) * * *
    (i) * * *

HHV = Annual average high heat value of the fuel (mmBtu per mass or
volume). The average HHV shall be calculated according to the
requirements of paragraph (a)(2)(ii) of this section.
* * * * *
    (ii) The minimum required sampling frequency for determining the
annual average HHV (e.g., monthly, quarterly, semi-annually, or by lot)
is specified in Sec.  98.34. The method for computing the annual
average HHV is a function of unit size and how frequently you perform
or receive from the fuel supplier the results of fuel sampling for HHV.
* * *
    (A) If the results of fuel sampling are received monthly or more
frequently, then for each unit with a maximum rated heat input capacity
greater than or equal to 100 mmBtu/hr (or for a group of units that
includes at least one unit of that size), the annual average HHV shall
be calculated using Equation C-2b of this section. * * *
* * * * *
(HHV)I = Measured high heat value of the fuel, for month
``i'' (which may be the arithmetic average of multiple
determinations), or, if applicable, an appropriate substitute data
value (mmBtu per mass or volume).
(Fuel)I = Mass or volume of the fuel combusted during
month ``i,'' from company records (express mass in short tons for
solid fuel, volume in standard cubic feet for gaseous fuel, and
volume in gallons for liquid fuel).
n = Number of months in the year that the fuel is burned in the
unit.

    (B) If the results of fuel sampling are received less frequently
than monthly, or, for a unit with a maximum rated heat input capacity
less than 100 mmBtu/hr (or a group of such units) regardless of the HHV
sampling frequency, the annual average HHV shall either be computed
according to paragraph (a)(2)(ii)(A) of this section or as the
arithmetic average HHV for all values for the year (including valid
samples and substitute data values under Sec.  98.35).
* * * * *
    (3) * * *
    (iii) * * *

CC = Annual average carbon content of the gaseous fuel (kg C per kg
of fuel). The annual average carbon content shall be determined
using the same procedures as specified for HHV in paragraph
(a)(2)(ii) of this section.
MW = Annual average molecular weight of the gaseous fuel (kg/kg-
mole). The annual average molecular weight shall be determined using
the same procedures as specified for HHV in paragraph (a)(2)(ii) of
this section.
MVC = Molar volume conversion factor at standard conditions, as
defined in Sec.  98.6. Use 849.5 scf per kg mole if you select 68
[deg]F as standard temperature and 836.6 scf per kg mole if you
select 60 [deg]F as standard temperature.
* * * * *
    (iv) Fuel flow meters that measure mass flow rates may be used for
liquid or gaseous fuels, provided that the fuel density is used to
convert the readings to volumetric flow rates. The density shall be
measured at the same frequency as the carbon content. You must measure
the density using one of the following appropriate methods. You may use
a method published by a consensus-based standards organization, if such
a method exists, or you may use industry standard practice. Consensus-
based standards organizations include, but are not limited to, the
following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700,
West Conshohocken, Pennsylvania 19428-B2959,<PHONE_NUMBER>, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L
Street, NW., 6th floor, Washington, DC 20036,<PHONE_NUMBER>, http://www.ansi.org), the American Gas Association (AGA), 400 North Capitol
Street, NW., 4th Floor, Washington, DC 20001,<PHONE_NUMBER>, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three
Park Avenue, New York, NY 10016-5990,<PHONE_NUMBER>, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street,
NW., Washington, DC 20005-4070,<PHONE_NUMBER>, http://www.api.org),
and the North American Energy Standards Board (NAESB, 801 Travis
Street, Suite 1675, Houston, TX 77002,

(713) 356-0060, http://www.api.org). The method(s) used shall be
documented in the GHG Monitoring Plan required under Sec.  98.3(g)(5).
    (v) The following default density values may be used for fuel oil,
in lieu of using the methods in paragraph (a)(3)(iv) of this section:
6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No.
6 oil.
* * * * *
    (4) * * *
    (iii) If the CO2 concentration is measured on a dry
basis, a correction for the stack gas moisture content is required. You
shall either continuously monitor the stack gas moisture content using
a method described in Sec.  75.11(b)(2) of this chapter or use an
appropriate default moisture percentage. For coal, wood, and natural
gas combustion, you may use the default moisture values specified in
Sec.  75.11(b)(1) of this chapter. Alternatively, for any type of fuel,
you may determine an appropriate site-specific default moisture value
(or values), using measurements made with EPA Method 4--Determination
Of Moisture Content In Stack Gases, in appendix A-3 to part 60 of this
chapter. Moisture data from the relative accuracy test audit (RATA) of
a CEMS may be used for this purpose. If this option is selected, the
site-specific moisture default value(s) must represent the fuel(s) or
fuel blends that are combusted in the unit during normal, stable
operation, and must account for any distinct difference(s) in the stack
gas moisture content associated with different process operating
conditions. For each site-specific default moisture percentage, at
least nine Method 4 runs are required, except where the option to use
moisture data from a RATA is selected, and the applicable regulation
allows a single moisture determination to represent two or more RATA
runs. In that case, you may base the site-specific moisture percentage
on the number of moisture runs allowed by the RATA regulation.
Calculate each site-specific default moisture value by taking the
arithmetic average of the Method 4 runs. Each site-specific moisture
default value shall be updated whenever the owner or operator believes
the current value is non-representative, due to changes in unit or
process operation, but in any event no less frequently than annually.
Use the updated moisture value in the subsequent CO2
emissions calculations. For each unit operating hour, a moisture
correction must be applied to Equation C-6 of this section as follows:
[GRAPHIC] [TIFF OMITTED] TR17DE10.002

Where:

CO2* = Hourly CO2 mass emission rate,
corrected for moisture (metric tons/hr).
CO2 = Hourly CO2 mass emission rate from
Equation C-6 of this section, uncorrected (metric tons/hr).
%H2O = Hourly moisture percentage in the stack gas
(measured or default value, as appropriate).

    (iv) An oxygen (O2) concentration monitor may be used in
lieu of a CO2 concentration monitor to determine the hourly
CO2 concentrations, in accordance with Equation F-14a or F-
14b (as applicable) in appendix F to part 75 of this chapter, if the
effluent gas stream monitored by the CEMS consists solely of combustion
products (i.e., no process CO2 emissions or CO2
emissions from sorbent are mixed with the combustion products) and if
only fuels that are listed in Table 1 in section 3.3.5 of appendix F to
part 75 of this chapter are combusted in the unit. If the O2
monitoring option is selected, the F-factors used in Equations F-14a
and F-14b shall be determined according to section 3.3.5 or section
3.3.6 of appendix F to part 75 of this chapter, as applicable. If
Equation F-14b is used, the hourly moisture percentage in the stack gas
shall be determined in accordance with paragraph (a)(4)(iii) of this
section.
* * * * *
    (viii) If a portion of the flue gases generated by a unit subject
to Tier 4 (e.g., a slip stream) is continuously diverted from the main
flue gas exhaust system for the purpose of heat recovery or some other
similar process, and then exhausts through a stack that is not equipped
with the continuous emission monitors to measure CO2 mass
emissions, CO2 emissions shall be determined as follows:
    (A) At least once a year, use EPA Methods 2 and 3A, and (if
necessary) Method 4 in appendices A-2 and A-3 to part 60 of this
chapter to perform emissions testing at a set point that best
represents normal, stable process operating conditions. A minimum of
three one-hour Method 3A tests are required, to determine the
CO2 concentration. A Method 2 test shall be performed during
each Method 3A run, to determine the stack gas volumetric flow rate. If
moisture correction is necessary, a Method 4 run shall also be
performed during each Method 3A run. Important parametric information
related to the stack gas flow rate (e.g., damper positions, fan
settings, etc.) shall also be recorded during the test.
    (B) Calculate a CO2 mass emission rate (in metric tons/
hr) from the stack test data, using a version of Equation C-6 in
paragraph (a)(4)(ii) of this section, modified as follows. In the
Equation C-6 nomenclature, replace the words ``Hourly average'' in the
definitions of ``CCO2'' and ``Q'' with the words ``3-run
average''. Substitute the arithmetic average values of CO2
concentration and stack gas flow rate from the emission testing into
modified Equation C-6. If CO2 is measured on a dry basis, a
moisture correction of the calculated CO2 mass emission rate
is required. Use Equation C-7 in paragraph (a)(4)(ii) of this section
to make this correction; replace the word ``Hourly'' with the words
``3-run average'' in the equation nomenclature.
    (C) The results of each annual stack test shall be used in the GHG
emissions calculations for the year of the test.
    (D) If, for the majority of the operating hours during the year,
the diverted stream is withdrawn at a steady rate at or near the tested
set point (as evidenced by fan and damper settings and/or other
parameters), you may use the calculated CO2 mass emission
rate from paragraph (a)(4)(viii)(B) of this section to estimate the
CO2 mass emissions for all operating hours in which flue gas
is diverted from the main exhaust system. Otherwise, you must account
for the variation in the flow rate of the diverted stream, as described
in paragraph (c)(4)(viii)(E) of this section.
    (E) If the flow rate of the diverted stream varies significantly
throughout the year, except as provided below, repeat the stack test
and emission rate calculation procedures described in paragraphs
(c)(4)(viii)(A) and (c)(4)(viii)(B) of this section at a minimum of two
more set points across the range of typical operating conditions to
develop a correlation between CO2 mass emission rate and the
parametric data. If additional testing is not feasible, use the
following approach to develop the necessary correlation. Assume that
the average CO2 concentration obtained in the annual stack
test is the same at all operating set points. Then, beginning

with the measured flow rate from the stack test and the associated
parametric data, perform an engineering analysis to estimate the stack
gas flow rate at two or more additional set points. Calculate the
CO2 mass emission rate at each set point.
    (F) Calculate the annual CO2 mass emissions for the
diverted stream as follows. For a steady-state process, multiply the
number of hours in which flue gas was diverted from the main exhaust
system by the CO2 mass emission rate from the stack test.
Otherwise, using the best available information and engineering
judgment, apply the most representative CO2 mass emission
rate from the correlation in paragraph (c)(4)(viii)(E) of this section
to determine the CO2 mass emissions for each hour in which
flue gas was diverted, and sum the results. To simplify the
calculations, you may count partial operating hours as full hours.
    (G) Finally, add the CO2 mass emissions from
paragraph(c)(4)(viii)(F) of this section to the annual CO2
mass emissions measured by the CEMS at the main stack. Report this sum
as the total annual CO2 mass emissions for the unit.
    (H) The exact method and procedures used to estimate the
CO2 mass emissions for the diverted portion of the flue gas
exhaust stream shall be documented in the Monitoring Plan required
under Sec.  98.3(g)(5).
    (5) Alternative methods for certain units subject to Part 75 of
this chapter. Certain units that are not subject to subpart D of this
part and that report data to EPA according to part 75 of this chapter
may qualify to use the alternative methods in this paragraph (a)(5), in
lieu of using any of the four calculation methodology tiers.
    (i) For a unit that combusts only natural gas and/or fuel oil, is
not subject to subpart D of this part, monitors and reports heat input
data year-round according to appendix D to part 75 of this chapter, but
is not required by the applicable part 75 program to report
CO2 mass emissions data, calculate the annual CO2
mass emissions for the purposes of this part as follows:
    (A) Use the hourly heat input data from appendix D to part 75 of
this chapter, together with Equation G-4 in appendix G to part 75 of
this chapter to determine the hourly CO2 mass emission
rates, in units of tons/hr;
    (B) Use Equations F-12 and F-13 in appendix F to part 75 of this
chapter to calculate the quarterly and cumulative annual CO2
mass emissions, respectively, in units of short tons; and
* * * * *
    (ii) For a unit that combusts only natural gas and/or fuel oil, is
not subject to subpart D of this part, monitors and reports heat input
data year-round according to Sec.  75.19 of this chapter but is not
required by the applicable part 75 program to report CO2
mass emissions data, calculate the annual CO2 mass emissions
for the purposes of this part as follows:
    (A) Calculate the hourly CO2 mass emissions, in units of
short tons, using Equation LM-11 in Sec.  75.19(c)(4)(iii) of this
chapter.
* * * * *
    (iii) For a unit that is not subject to subpart D of this part,
uses flow rate and CO2 (or O2) CEMS to report
heat input data year-round according to part 75 of this chapter, but is
not required by the applicable part 75 program to report CO2
mass emissions data, calculate the annual CO2 mass emissions
as follows:
    (A) Use Equation F-11 or F-2 (as applicable) in appendix F to part
75 of this chapter to calculate the hourly CO2 mass emission
rates from the CEMS data. If an O2 monitor is used, convert
the hourly average O2 readings to CO2 using
Equation F-14a or F-14b in appendix F to part 75 of this chapter (as
applicable), before applying Equation F-11 or F-2.
    (B) Use Equations F-12 and F-13 in appendix F to part 75 of this
chapter to calculate the quarterly and cumulative annual CO2
mass emissions, respectively, in units of short tons.
* * * * *
    (iv) For units that qualify to use the alternative CO2
emissions calculation methods in paragraphs (a)(5)(i) through
(a)(5)(iii) of this section, if both biomass and fossil fuel are
combusted during the year, separate calculation and reporting of the
biogenic CO2 mass emissions (as described in paragraph (e)
of this section) is optional, only for the 2010 reporting year, as
provided in Sec.  98.3(c)(12).
    (b) * * *
    (1) * * *
    (iv) May not be used if you routinely perform fuel sampling and
analysis for the fuel high heat value (HHV) or routinely receive the
results of HHV sampling and analysis from the fuel supplier at the
minimum frequency specified in Sec.  98.34(a), or at a greater
frequency. In such cases, Tier 2 shall be used. This restriction does
not apply to paragraphs (b)(1)(ii), (b)(1)(v), (b)(1)(vi), and
(b)(1)(vii) of this section.
    (v) May be used for natural gas combustion in a unit of any size,
in cases where the annual natural gas consumption is obtained from fuel
billing records in units of therms or mmBtu.
    (vi) May be used for MSW combustion in a small, batch incinerator
that burns no more than 1,000 tons per year of MSW.
    (vii) May be used for the combustion of MSW and/or tires in a unit,
provided that no more than 10 percent of the unit's annual heat input
is derived from those fuels, combined. Notwithstanding this
requirement, if a unit combusts both MSW and tires and the reporter
elects not to separately calculate and report biogenic CO2
emissions from the combustion of tires, Tier 1 may be used for the MSW