returned to the production facility for destruction after entering into
commerce (e.g., because they have become irretrievably contaminated).
    Regarding fluorinated GHGs that are produced and transformed at the
same facility, the fluorinated GHG producers noted that these
fluorinated GHGs never enter the U.S. supply of fluorinated GHGs
because they never leave the facility where they are produced. Thus, it
is not necessary to track them under subpart OO.
    Regarding fluorinated GHGs that occur as low-concentration
constituents of fluorinated GHG products, the producers observed that
such low-concentration constituents generally consist of by-products
that are packaged along with the main constituent of the product. They
noted that exempting the production, import, and export of these low-
concentration constituents from monitoring and reporting requirements
would be consistent with the exemption of ``trace'' concentrations from
other monitoring requirements in subpart OO, such as 40 CFR 98.414(f)
and (h).
    In response to the concern regarding fluorinated GHGs that are
emitted or destroyed before the product is packaged for sale, we are
proposing (1) to modify 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);'' (2) to remove 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 40 CFR 98.413(a) because they are
removed from the production process as byproducts or wastes;'' and (3)
to modify the requirements at 40 CFR 98.414(h) and 98.416(a)(3) to
limit them to ``the mass of each fluorinated GHGs that is fed into the
destruction device and that was previously produced as defined at Sec.
98.410(b).''
    These proposed amendments would clarify that the scope of subpart
OO is that which EPA has always intended, and they would 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. To clarify
this in the regulatory text, we are proposing to amend the definition
of ``produce a fluorinated GHG'' at 40 CFR 98.410(b) to exclude the
``creation of fluorinated GHGS that are released or destroyed at the
production facility before the production measurement at Sec.
98.414(a).''
    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). As noted above, emissions upstream of the
production measurement would be subject to proposed subpart L and are
not part of the subpart OO source category.
    We are also proposing to amend 40 CFR 98.416(a)(3) to limit the
monitoring and reporting of destroyed fluorinated GHGs to those
destroyed fluorinated GHGs that were previously ``produced'' under
today's revised definition.\4\ 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,\5\ 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.
---------------------------------------------------------------------------

    \4\ 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.
    \5\ 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.
---------------------------------------------------------------------------

    In response to the concern regarding fluorinated GHGs that are
produced and transformed at the same facility, we are proposing to (1)
amend 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;'' (2) amend the
definition of ``produce a fluorinated GHG'' 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;'' (3) add a definition of ``isolated
intermediate;'' and (4) add 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 proposing to
exclude the latter from the definition of ``produce a fluorinated
GHG,'' we are proposing to include the former in that definition. This
is because the manufacture of isolated intermediates, which can lead to
emissions of those intermediates, is of interest under subpart L, and
we would like 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 proposing to add provisions to
exclude it from the subpart OO monitoring, reporting, and recordkeeping
requirements. We are also proposing to add a definition of ``isolated
intermediate'' that is the same as that proposed for subpart L (75 FR
18652, April 12, 2010).
    In response to the concern regarding fluorinated GHGs that occur as
low-concentration constituents of fluorinated GHG products, we are
proposing to define and exclude 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 proposing to define low-concentration constituent 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 (AHRI 700), for
SF6 used as an insulator in electrical equipment (IEC
60376), and for perfluorocarbons and other fluorinated GHGs used in
electronics manufacturing (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 under 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
under 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 also
proposing product sampling and analytical requirements at 40 CFR
98.414(n) and corresponding calibration requirements at 40 CFR
98.414(o).
    For purposes of fluorinated GHG import, we are proposing to define
low-concentration constituent 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 proposing 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 proposing (1) to exempt such
compounds from the general subpart A requirement to report supply flows
in terms of CO2 equivalents and (2) to recast the reporting
exemptions for import and export of small shipments 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.G of this preamble. The exemptions for import
and export would 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 would enable small
shipments of fluorinated GHGs to be exempt from reporting regardless of
whether or not the fluorinated GHG had a GWP listed in Table A-1. Our
analysis of import and export data indicates that this change would
slightly increase both the number and total mass of the imports and
exports reported under the rule, but this analysis does not account for
fluorinated GHGs whose GWPs are not listed in Table A-1. If those
fluorinated GHGs were accounted for, we believe that the level of
reporting would increase even less and might even decrease slightly.
    Other Corrections. We are also proposing to amend the reporting and
recordkeeping provisions in subpart OO to correct internal
inconsistencies in the subpart and to clarify those requirements.
    We are proposing to amend 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 proposing to amend 40 CFR 98.416(b) and (e) to clarify the
due dates of the one-time reports required by those paragraphs. The
proposed 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 April
1, 2011, and there was no provision for commencing fluorinated GHG
destruction or production after that date. The proposed amendments will
make the due dates in 40 CFR 98.416(b) and (e) consistent with each
other, with the due date for a similar report required in subpart O,
and with the due date for other reporting under the rule.
    We are proposing to amend 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 proposing to amend 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 proposing to amend 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.''

R. Subpart PP (Suppliers of Carbon Dioxide)

    In subpart PP, we are proposing to remove the words ``each'' from
the list of GHGs to report in 40 CFR 98.422. This change would align
this section with the requirements of the rest of subpart PP, which
allow for monitoring of an aggregated flow of CO2 if it is
done at a gathering point downstream of individual production wells or
production process units.
    We are proposing to allow those suppliers that supply
CO2 in containers 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. As a result of many questions received during outreach in
support of alternative procedures for CO2 supplied in
containers, we have reevaluated the calculation procedures for
CO2 suppliers. We have concluded that measurements made with
weigh bills, scales, load cells, or loaded container volume readings
will continue to meet the level of data quality and accuracy needed by
EPA with respect to subpart PP. We have reached this conclusion with
consideration to minimizing the burden on and maximizing the
flexibility provided to industry.
    We are proposing multiple amendments to the regulatory text to
accommodate this proposed provision. First, we are proposing that 40
CFR 98.423(b) be renumbered to 40 CFR 98.423(c) and that a new 40 CFR
98.423(b) be added with calculation procedures for CO2
supplied in containers. Second, we are proposing to amend the first
sentence of 40 CFR 98.423(a) to allow suppliers that supply
CO2 in containers to use the alternative procedures in 40
CFR 98.423(b). Third, we are proposing to add new QA/QC procedures for
suppliers that supply CO2 in containers to 40 CFR 98.424(a).
Fourth, we are proposing to add missing data procedures for suppliers
that supply CO2 in containers to 40 CFR 98.425(d). Finally,
we are proposing to make 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 note that under the existing requirements, importers and
exporters that import and export CO2 in containers must
measure the mass of CO2 in containers using weigh bills,
scales, or load cells. In this action, we are not proposing that the
use of loaded container volume readings be allowed for such reporters
as an alternative to weigh bills, scales, or load cells because we have
received no questions from importers or exporters suggesting the need
for such an allowance. We seek comment on whether such an allowance
should be extended to importers and exporters of CO2 in
containers, and if so whether the calculation procedures, QA/QC
procedures, missing data procedures, and reporting requirements for
loaded container volume readings proposed in this action for suppliers
should be offered to importers and exporters.
    We are proposing to remove 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
proposing to redesignate as 40 CFR 98.423(c)). This provision created
confusion and conflict over where to place a flow meter. For example,
at least one reporter has indicated that only a portion of a
CO2 stream is transferred for commercial application while
the rest is retained for onsite use and emission, and this portion of
the stream is segregated only after processing. As a result of this and
other concerns that the requirement to install flow meters prior to
purification, processing, or compression could result in a requirement
to install the flow meter at a technically infeasible point, we
reevaluated the value of such a constraint on the CO2
calculations. Since 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 proposing to add
language at 40 CFR 98.424(a) requiring the flow meter to be located
after the point of segregation. We are also proposing to amend existing
language in 40 CFR 98.424(a) to reference this new requirement.
    Because the proposed amendments would allow flow meters to be
located after purification, compression, or processing, we are
proposing to add data reporting requirements in 40 CFR 98.426 to
collect additional information on flow meter location. Specifically, we
are proposing that facilities would report information on the placement
of each flow meter used in relation to the points of CO2
stream capture, deyhdration, compression, and other processing. Knowing
where in the production process the flow meter is located will enable
EPA to effectively compare data across and to learn about the efficacy
of various CO2 stream capture processes.
    The current subpart PP regulatory text requires that a reporter
using a volumetric flow meter to measure the flow of a CO2
stream measure density of that CO2 stream in order to
calculate the mass of CO2 supplied. As a result of new
analysis, we have concluded that the mass of CO2 in a stream
can be adequately determined by converting the volumetric flow of
CO2 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. This approach may also be less burdensome for reporters than
directly measuring density with equipment. Therefore, we are proposing
to amend 40 CFR 98.424(a)(5) by replacing the word ``measure'' with the
word ``determine.''
    We are also proposing to add a new paragraph 40 CFR 98.424(c) so
that suppliers will be able to calculate the mass of CO2 in
a stream from the measured volumetric flow (converted to standard
conditions) and CO2 concentration, and the given density of
CO2 at standard conditions.
    For the calculation in the proposed paragraph 40 CFR 98.424(c),
standard conditions under subpart PP would be a temperature and an
absolute pressure of 60[deg]F and 1 atmosphere. Note that this would be
different than the standard conditions defined in subpart A (40 CFR
98.6), which are 68[deg]F and 14.7 psia. 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, and we seek
comment on this conclusion. Given these conditions, we are proposing
that reporters must use 0.0018704 metric tons per standard cubic meter
as a density value for CO2 at standard conditions if this is
the industry standard practice used to determine density.
    The current subpart PP regulatory text also requires that an
appropriate method published by a consensus-based standards
organization be used to measure density if such a method exists. Where
no such method exists, an industry standard practice must be followed.
We have been unable to identify any method published by a consensus-
based standards organization that accounts for the approach for
determining density described above and have concluded that it would be
categorized as an industry standard practice. Therefore, we are
proposing to amend language in 40 CFR 98.424(a)(5) and (a)(5)(ii) to
allow reporters to choose equally from between a method published by a
consensus-based standards organization that is appropriate or an
industry standard practice to determine density.
    We are proposing to amend 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.

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

B. Paperwork Reduction Act

    This action does not impose any new information collection burden.
These proposed amendments do not make any substantive changes to the
reporting requirements in any of the subparts for which amendments are
being proposed. In many cases, the proposed amendments to the reporting
requirements could potentially reduce the reporting burden by making
the reporting requirements conform more closely to current industry
practices. 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. 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 this proposed rule 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 proposed 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 proposed rule amendments will not impose any new
requirement on small entities that are not currently required by the
rules promulgated on October 30, 2009 (i.e., calculating and reporting
annual GHG emissions).
    EPA took several steps to reduce the impact of Part 98 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.

    We continue to be interested in the potential impacts of the
proposed rule amendments on small entities and welcome comments on
issues related to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    This proposed rule does not contain a Federal mandate that may
result in expenditures of $100 million or more for State, local, and
tribal governments, in the aggregate, or the private sector in any one
year. EPA has estimated that, overall, the proposed revisions do not
significantly change the overall costs of compliance with Part 98. The
proposed amendments include providing additional flexibility for
reporters, clarifying existing reporting requirements, and requiring
reporting of information already required to be collected under Part
98. EPA estimates that the cost for all reporters in reviewing the
proposed rule and determining if, and if so how, it applies to their
facility, is approximately $2.5 million in the first year. Considering
the additional flexibilities proposed, in sum, EPA has estimated that
the proposed rule, if finalized, would reduce the burden to reporters
as compared to the 2009 final rule. Thus, this rule is not subject to
the requirements of sections 202 or 205 of UMRA. For more information
on the cost analysis, please refer to the memorandum titled ``Mandatory
Greenhouse Gas Reporting: Changes in National Cost Estimates Associated
with the Proposed Notice of Revisions'' found in the docket at (EPA-HQ-
OAR-2008-0508).
    This proposed rule is also not subject to the requirements of
section 203 of UMRA because it contains no regulatory requirements that
might significantly or uniquely affect small governments. EPA
determined that the proposed 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 rules published on October 30,
2009 (i.e., calculating and reporting annual GHG emissions). EPA
concluded in the preamble to that final rule that the rule ``* * *
contains no regulatory requrements that might significantly or uniquely
affect small governments'' (40 CFR 56260). Because the final rule was
not determined to significantly or uniquely affect small governments,
and because this proposed rule generally reduces the burden associated
with the 2009 final rule, these rule amendments would not unfairly
apply to small governments.

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 proposed rule amendments would relate to
existing State programs, please see Section II of the proposal preamble
for Part 98 (74 FR 16457 to 16461, April 10, 2009).
    These amendments apply directly to facilities that supply fuel or
chemicals 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
large stationary combustion source), so relatively few government
facilities would be affected. This regulation also does not limit the
power of States or localities to collect GHG data and/or regulate GHG
emissions. Thus, EO 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 Part 98. A
summary of EPA's consultations with State and local governments is
provided in Section VIII.E of the preamble to the final Part 98 (74 FR
56260, October 30, 2009).
    In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed action
from State and local officials.

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 proposed
rule amendments would not result in any changes to the requirements of
the 2009 rule. 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 Part 98 (74 FR 56260, October 30, 2009).

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

    EPA interprets EO 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 EO has the
potential to influence the regulation. This action is not subject to EO
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 No. 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 proposed rulemaking involves technical standards. No new test
methods were developed for this proposed rule; rather, EPA identified
existing means of monitoring, reporting, and keeping records of
greenhouse gas emissions. EPA proposes to use two additional voluntary
consensus standards from ASTM International. Part 98 includes the use
of over 40 voluntary consensus standards from various consensus
standards bodies, for example, ASTM International, the American Society
of Chemical Engineers, Gas Processors Association, the American Gas
Association, and the American Petroleum Institute. The proposed
addition of these two

voluntary consensus standards from ASTM International to Part 98 will
help petroleum refineries and petrochemical facilities monitor, report,
and keep records of greenhouse gas emissions. The test methods are
incorporated by reference into the proposed rule and are available as
specified in proposed amendments to 40 CFR 98.7.
    By incorporating voluntary consensus standards into this proposed
rule, EPA is both meeting the requirements of the NTTAA and presenting
multiple options and flexibility for measuring greenhouse gas
emissions.
    EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable voluntary consensus standards and to explain why such
standards should be used in this regulation.

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

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment because it is a rule addressing information collection and
reporting procedures.

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: July 20, 2010.
Lisa P. Jackson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is proposed to be amended as follows:

PART 98--[AMENDED]

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

    Authority:  42 U.S.C. 7401, et seq.

Subpart A--[Amended]

    2. Section 98.2 is amended by revising paragraph (a)(4)(iii)(B) to
read as follows:

Sec.  98.2  Who must report?

    (a) * * *
    (4) * * *
    (iii) * * *
    (B) Local natural gas distribution companies that deliver 460,000
thousand standard cubic feet or more of natural gas per year.
* * * * *
    3. Section 98.3 is amended by:
    a. Revising paragraphs (c)(1), (c)(4)(i), (c)(4)(ii), (c)(4)(iii)
introductory text, (c)(4)(iii)(A), (c)(4)(iii)(B), and (c)(5)(i).
    b. Revising the third sentence of paragraph (d)(3) introductory
text.
    c. Revising the first sentence of paragraph (f).
    d. Revising paragraphs (g)(4), (g)(5)(iii).
    e. Revising paragraph (h).
    f. Revising paragraph (i).
    g. 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), facility or
supplier ID number, and physical street address of the facility or
supplier, including the city, state, and zip code.
* * * * *
    (4) * * *
    (i) Annual emissions (including biogenic CO2) aggregated
for all GHG from all applicable source categories in subparts C through
JJ of this part and 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 in subparts C through JJ of this part in
metric tons. Units that use the methodologies in part 75 of this
chapter to calculate CO2 mass emissions are not required to
separately report biogenic CO2 emissions, but may do so as
an option.
    (iii) Annual emissions from each applicable source category in
subparts C through JJ of this part, expressed in metric tons of each
applicable GHG listed in this paragraph (4)(iii)(A) through
(4)(iii)(E).
    (A) Biogenic CO2. Units that use the methodologies in
part 75 of this chapter to calculate CO2 mass emissions are
not required to separately report biogenic CO2 emissions,
but may do so as an option.
    (B) CO2 (including biogenic CO2).
* * * * *
    (5) * * *
    (i) Total quantity of GHG aggregated for all GHG from all
applicable supply categories in subparts KK through PP of this part and
expressed in metric tons of CO2e calculated using Equation
A-1 of this subpart. For fluorinated GHGs, calculate and report
CO2e for only those fluorinated GHGs 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 and 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 industry standards and
manufacturer's specifications. 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] TP11AU10.000

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] TP11AU10.001

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 an industry consensus standards or a manufacturer's
specification.
    (C) You must document the methods used for the demonstration
described in paragraph (i)(3)(ii)(A) of this section in the written
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 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 Monitoring Plan and
recordkeeping provisions of paragraphs (g)(5)(i)(C) 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 or ignition 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
relavant 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 subsquent 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.
    4. 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.
* * * * *
    5. Section 98.6 is amended by:
    a. Adding in alphabetical order definitions for ``Agricultural
byproducts,'' ``Primary fuel,'' ``Solid byproducts,'' ``Waste oil,''
and ``Wood residuals.''
    b. Revising the definitions for ``Bulk natural gas liquid or NGL,''
``Distillate Fuel Oil,'' ``Fossil fuel,'' ``Municipal solid waste or
MSW,'' ``Natural gas,'' and ``Natural gas liquids (NGLs).''
    c. Removing the definition for ``Fossil fuel-fired.''

Sec.  98.6  Definitions.

* * * * *
    Agricultural byproducts means those parts of arable crops that are
not used for the primary purpose of producing food. Agricultural
byproducts 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.
* * * * *
    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 waste does not include used oil, wood pellets,
construction, renovation, and demolition wastes (which includes, but is
not limited to, railroad ties and telephone poles), clean wood,
industrial process or manufacturing wastes, medical waste, or motor
vehicles (including motor vehicle parts or vehicle fluff). Household,
commercial/retail, and institutional wastes include yard waste, refuse-
derived fuel, and motor vehicle maintenance materials, limited to
vehicle batteries and tires, except where a single waste stream
consisting of tires is combusted in a unit.
* * * * *
    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 is composed of at
least 70 percent methane by volume or has a high heat value between 910
and 1150 Btu per standard cubic foot.
    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 byproducts means plant matter such as vegetable waste, animal
materials/wastes, and other solid biomass, except for wood, wood waste,
and sulphite lyes (black liquor).
* * * * *
    Waste oil means a petroleum-derived or synthetically-derived oil
whose physical properties have changed as a result of storage, handling
or use, such that the oil cannot be used for its original purpose.
Waste 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 wood waste 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, and logging residues.
* * * * *
    6. Section 98.7 is amended by:
    a. Removing and reserving paragraph (b).
    b. Revising paragraphs (d)(1) and (d)(2).
    c. Removing and reserving paragraph (d)(3).
    d. Revising paragraphs (d)(4) and (d)(5).
    e. Removing and reserving paragraph (d)(6).
    f. Revising paragraphs (d)(7) and (d)(8).
    g. Removing and reserving paragraph (d)(9).
    h. Revising paragraph (d)(10).
    i. Removing and reserving paragraph (d)(11).
    j. Revising paragraph (e)(4).
    k. Removing and reserving paragraph (e)(7).
    l. Revising paragraphs (e)(8), (e)(10), (e)(11), (e)(14), (e)(15),
(e)(19), (e)(20), (e)(24) through (e)(27).
    m. Removing and reserving paragraph (e)(28).
    n. Revising paragraph (e)(30), (e)(33), and (e)(36).
    o. Adding paragraphs (e)(43) and (e)(44).
    p. Removing and reserving paragraph (f)(1) and (g)(3).
    q. Revising paragraph (f)(2)
    r. Removing and reserving paragraph (g)(3).
    s. Adding paragraph (m)(3).

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.  98.344(c) and Sec.  98.364(e).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters, IBR approved for Sec.  98.344(c) and Sec.  98.364(e).
    (3) [Reserved]
    (4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters, IBR approved for Sec.  98.344(c) 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.
98.344(c) and Sec.  98.364(e).
    (6) [Reserved]
    (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters, IBR approved for Sec.  98.344(c).
    (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters, IBR approved for Sec.  98.344(c) and Sec.
98.364(e).
    (9) [Reserved]
    (10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable
Area Meters, IBR approved for Sec.  98.344(c), and Sec.  98.364(e).
    (11) [Reserved]
    (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).
* * * * *
    (7) [Reserved]
    (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), 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.  98.344(b), 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).
* * * * *
    (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).
    (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).
    (28) [Reserved]
* * * * *
    (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.
98.224(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).
* * * * *
    (43) ASTM D2503-92(2007) Standard Test Method for Relative
Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric
Measurement of Vapor Pressure, IBR approved for Sec.  98.254(d).
    (44) ASTM D2593-93(2009) Standard Test Method for Butadiene Purity
and Hydrocarbon Impurities by Gas Chromatography, IBR approved for
Sec.  98.244(b).
* * * * *
    (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), and Sec.  98.344(b).
* * * * *
    (g) [Reserved]
* * * * *
    (k) The following material is available from the U.S. Environmental
Protection Agency, 1200 Pennsylvania Avenue, NW, Washington, D.C.
20460,<PHONE_NUMBER>, www.epa.gov.
    (1) Protocol for Measuring Destruction or Removal Efficiency (DRE)
of Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing, Version 1, EPA-430-R-10-003.

Subpart C--[Amended]

    7. Section 98.30 is amended by:
    a. Revising paragraph (b)(4).
    b. Revising paragraph (c) introductory text.
    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 permanent auxiliary flame that ignites the
burner of a combustion device when the control valve opens.
    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.
    9. Section 98.33 is amended by:
    a. Revising paragraphs (a) introductory text and (a)(1).
    b. Revising the definition of ``HHV'' in Equation C-2a of paragraph
(a)(2)(i).
    c. Revising and the first two sentences of paragraph (a)(2)(ii)
introductory text.
    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.
    e. Revising paragraph (a)(2)(ii)(B).
    f. Revising the definitions of ``CC'' and ``MW'' in Equation C-5 of
paragraph (a)(3)(iii).
    g. Revising paragraphs (a)(3)(iv), (a)(4)(iii), and (a)(4)(iv).
    h. Adding a new paragraph (a)(4)(viii).
    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),
(a)(5)(iii)(B).
    j. Redesignating paragraph (a)(5)(iii)(D) as paragraph (a)(5)(iv),
and revising newly designated paragraph (a)(5)(iv).
    k. Revising paragraph (b)(1)(iv).
    l. Adding paragraph (b)(1)(v).
    m. Revising paragraphs (b)(2)(ii), (b)(3)(ii)(A), (b)(3)(iii)
introductory text, and (b)(3)(iii)(B).
    n. Adding paragraph (b)(3)(iv).
    o. Adding a second sentence to paragraph (b)(4)(i).
    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.
    q. Adding a new paragraph (b)(4)(iv).
    r. Revising paragraph (b)(5) and the third sentence of paragraph
(b)(6).
    s. In paragraph (c)(1), revising the second sentence, and revising
the definition of ``HHV'' in Equation C-8.
    t. Revising the second sentence of paragraph (c)(2).
    u. In paragraph (c)(4) introductory text, revising the only
sentence and revising the definition of ``(HI)A'' in
Equation C-10.
    v. Revising paragraphs (c)(4)(i) and (c)(4)(ii).
    w. Adding a new paragraph (c)(6).
    x. In paragraph (d)(1), revising the first sentence, adding a
second sentence, and revising the definition of ``R'' in Equation C-11.

    y. Revising paragraphs (d)(2), (e) introductory text, (e)(1), and
(e)(2) introductory text.
    z. Revising the definition of ``Fc'' in Equation C-13 of
paragraph (e)(2)(iii).
    aa. Revising paragraphs (e)(2)(iv), (e)(2)(vi)(C), and (e)(3).
    bb. Reserving paragraph (e)(4).
    cc. Revising the first sentence of 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 or C-1a 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. In that case, use Equation C-1a.
[GRAPHIC] [TIFF OMITTED] TP11AU10.002

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] TP11AU10.003

Where:

CO2 = Annual CO2 mass emissions from natural
gas combustion (metric tons).
Gas = Annual natural gas consumption, 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.
(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'', 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 be computed 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.
* * * * *

    (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. For liquid fuels,
you must measure the density using one of the following appropriate
methods. You may use a method published by a consensus 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, the American National
Standards Institute (ANSI), the American Gas Association (AGA), the
American Society of Mechanical Engineers (ASME), the American Petroleum
Institute (API), and the North American Energy Standards Board (NAESB).
The method(s) used shall be documented in the Monitoring Plan required
under Sec.  98.3(g)(5). Alternatively, for fuel oil, you may use

an applicable default density value provided in paragraph (a)(3)(v) of
this section. For gaseous fuels, you may determine the density using
any of the following methods. You may use a density meter calibrated
according to the manufacturer's instructions, a method published by a
consensus standards organization, or an industry standard practice.
Document the method used to determine the fuel density in the
Monitoring Plan under Sec.  98.3(g)(5).
* * * * *
    (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 as
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. 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.
Moisture data from the relative accuracy test audit (RATA) of a CEMS
may be used for this purpose. 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] TP11AU10.004

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, provided that the CO2 concentration in the
diverted stream is not altered in any way (e.g., by chemical reaction
or dilution) before the diverted stream exits to the atmosphere, an
estimate of the hourly average volumetric flow rate (scfh) of the
diverted gas stream shall be made at the point where it exits the main
exhaust system, by using the best available information (e.g.,
correlations of operating parameters versus flow measurements made with
EPA Method 2 in appendix A-2 to part 60 of this chapter, engineering
analysis, or other methods). Each hourly average volumetric flow rate
(scfh) measured at the main flue gas stack shall then be added to the
corresponding estimate of the hourly average flow rate of the diverted
gas stream, to determine the total hourly average stack gas volumetric
flow rate ``Q'', for use in Equation C-6 of this section. The method
use to estimate the hourly flow rate of 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
chapterto 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.
    (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) and (b)(1)(v) 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.
    (2) * * *
    (ii) May be used in a unit with a maximum rated heat input capacity
greater than 250 mmBtu/hr for the combustion of natural gas and/or
distillate fuel oil.
* * * * *
    (3) * * *
    (ii) * * *
    (A) The use of Tier 1 or 2 is permitted, as described in paragraphs
(b)(1)(iii), (b)(1)(v), and (b)(2)(ii) of this section.
* * * * *
    (iii) Shall be used for a fuel not listed in Table C-1 of this
subpart if the fuel is combusted in a unit with a maximum rated heat
input capacity greater than 250 mmBtu/hr (or, pursuant to Sec.
98.36(c)(3), in a group of units served by a common supply pipe, having
at least one unit with a maximum rated heat input capacity greater than
250 mmBtu/hr), provided that both of the following conditions apply:
* * * * *
    (B) The fuel provides 10% or more of the annual heat input to the
unit or, if Sec.  98.36(c)(3) applies, to the group of units served by
a common supply pipe.
    (iv) Shall be used when specified in another applicable subpart of
this part, regardless of unit size.
    (4) * * *
    (i) * * * Tier 4 may also be used for any group of stationary fuel
combustion units, process units, or manufacturing units that share a
common stack or duct.
    (ii) * * *
    (A) The unit has a maximum rated heat input capacity greater than
250 mmBtu/hr, or if the unit combusts municipal solid waste and has a
maximum rated input capacity greater than 600 tons per day of MSW.
    (B) The unit combusts solid fossil fuel or MSW as the primary fuel.
* * * * *
    (E) The installed CEMS include a gas monitor of any kind or a stack
gas volumetric flow rate monitor, or both and the monitors have been
certified, either in accordance with the requirements of part 75 of
this chapter, part 60 of this chapter, or an applicable State
continuous monitoring program.
    (F) The installed gas or stack gas volumetric flow rate monitors
are required, either by an applicable Federal or State regulation or by
the unit's operating permit, to undergo periodic quality assurance
testing in accordance with either appendix B to part 75 of this
chapter, appendix F to part 60 of this chapter, or an applicable State
continuous monitoring program.
    (iii) Shall be used for a unit with a maximum rated heat input
capacity of 250 mmBtu/hr or less and for a unit that combusts municipal
solid waste with a maximum rated input capacity of 600 tons of MSW per
day or less, if the unit meets all of the following three conditions:
* * * * *
    (iv) May apply to common stack or duct configurations where:
    (A) The combined effluent gas streams from two or more stationary
fuel combustion units are vented through a monitored common stack or
duct. In this case, Tier 4 shall be used if all of the conditions in
paragraph (b)(4)(iv)(A)(1) of this section or all of the conditions in
paragraph (b)(4)(iv)(A)(2) of this section are met.
    (1) At least one of the units meets the requirements of paragraphs
(b)(4)(ii)(A) through (b)(4)(ii)(C) of this section, and the CEMS
installed at the common stack (or duct) meet the requirements of
paragraphs (b)(4)(ii)(D) through (b)(4)(ii)(F) of this section.
    (2) At least one of the units and the monitors installed at the
common stack or duct meet the requirements of paragraph (b)(4)(iii) of
this section.
    (B) The combined effluent gas streams from a process or
manufacturing unit and a stationary fuel combustion unit are vented
through a monitored common stack or duct. In this case, Tier 4 shall be
used if the combustion unit and the monitors installed at the common
stack or duct meet the applicability criteria specified in paragraph
(b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) of this section.
    (C) The combined effluent gas streams from two or more
manufacturing or process units are vented through a common stack or
duct. In this case, if any of the units is required by an applicable
subpart of this part to use Tier 4, the CO2 mass emissions
may either be monitored at each individual unit, or the combined
CO2 mass emissions may be monitored at the common stack or
duct. However, if it is not feasible to monitor the individual units,
the combined CO2 mass emissions shall be monitored at the
common stack or duct.
    (5) The Tier 4 Calculation Methodology shall be used:
    (i) Starting on January 1, 2010, for a unit that is required to
report CO2 mass emissions beginning on that date, if all of
the monitors needed to measure CO2 mass emissions have been
installed and certified by that date.
    (ii) No later than January 1, 2011, for a unit that is required to
report CO2 mass emissions beginning on January 1, 2010, if
all of the monitors needed to measure CO2 mass emissions
have not been installed and certified by January 1, 2010. In this case,
you may use Tier 2 or Tier 3 to report GHG emissions for 2010. However,
if the required CEMS are certified some time in 2010, you need not wait
until January 1, 2011 to begin using Tier 4. Rather, you may switch
from Tier 2 or Tier 3 to Tier 4 as soon as CEMS certification testing
is successfully completed. If this reporting option is chosen, you must
document the change in CO2 calculation methodology in the
Monitoring Plan required under Sec.  98.3(g)(5) and in the GHG
emissions report under Sec.  98.3(c). Data recorded by the CEMS during
a certification test period in 2010 may be used for reporting under
this part, provided that the following two conditions are met:
    (A) The certification tests are passed in sequence, with no test
failures.

    (B) No unscheduled maintenance or repair of the CEMS is performed
during the certification test period.
    (iii) No later than 180 days following the date on which a change
is made that triggers Tier 4 applicability under paragraph (b)(4)(ii)
or (b)(4)(iii) of this section (e.g., a change in the primary fuel,
manner of unit operation, or installed continuous monitoring
equipment).
    (6) * * * However, for units that use either the Tier 4 or the
alternative calculation methodology specified in paragraph (a)(5)(iii)
of this section, CO2 emissions from the combustion of all
fuels shall be based solely on CEMS measurements.
    (c) * * *
    (1) * * * Use the same values for fuel consumption that you use for
the Tier 1 or Tier 3 calculation.
* * * * *
HHV = Default high heat value of the fuel from Table C-1 of this
subpart; alternatively, for Tier 3, if actual HHV data are available
for the reporting year, you may average these data using the
procedures specified in paragraph (a)(2)(ii) of this section, and
use the average value in Equation C-8 (mmBtu per mass or volume).
* * * * *

    (2) * * * Use the same values for fuel consumption and HHV that you
use for the Tier 2 calculation.
* * * * *
    (4) Use Equation C-10 of this section for: units subject to subpart
D of this part; units that qualify for and elect to use the alternative
CO2 mass emissions calculation methodologies described in
paragraph (a)(5) of this section; and units that use the Tier 4
Calculation Methodology.
* * * * *
(HI)A = Cumulative annual heat input from combustion of
the fuel (mmBtu).
* * * * *

    (i) If only one type of fuel listed in Table C-2 of this subpart is
combusted during the reporting year, substitute the cumulative annual
heat input from combustion of the fuel into Equation C-10 of this
section to calculate the annual CH4 or N2O
emissions. For units in the Acid Rain Program and units that report
heat input data to EPA year-round according to part 75 of this chapter,
obtain the cumulative annual heat input directly from the electronic
data reports required under Sec.  75.64 of this chapter. For Tier 4
units, use the best available information, as described in paragraph
(c)(4)(ii)(C) of this section, to estimate the cumulative annual heat
input (HI)A.
    (ii) If more than one type of fuel listed in Table C-2 of this
subpart is combusted during the reporting year, use Equation C-10 of
this section separately for each type of fuel, except as provided in
paragraph (c)(4)(ii)(B) of this section. Determine the appropriate
values of (HI)A as follows:
    (A) For units in the Acid Rain Program and other units that report
heat input data to EPA year-round according to part 75 of this chapter,
obtain (HI)A for each type of fuel from the electronic data
reports required under Sec.  75.64 of this chapter, except as otherwise
provided in paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this section.
    (B) For a unit that uses CEMS to monitor hourly heat input
according to part 75 of this chapter, the value of (HI)A
obtained from the electronic data reports under Sec.  75.64 of this
chapter may be attributed exclusively to the fuel with the highest F-
factor, when the reporting option in <IP_ADDRESS> of appendix F to part 75
of this chapter is selected and implemented.
    (C) For Tier 4 units, use the best available information (e.g.,
fuel feed rate measurements, fuel heating values, engineering analysis)
to estimate the value of (HI)A for each type of fuel.
Instrumentation used to make these estimates is not subject to the
calibration requirements of Sec.  98.3(i) or to the QA requirements of
Sec.  98.34.
    (D) Units in the Acid Rain Program and other units that report heat
input data to EPA year-round according to part 75 of this chapter may
use the best available information described in paragraph (c)(4)(ii)(C)
of this section, to estimate (HI)A for each fuel type,
whenever fuel-specific heat input values cannot be directly obtained
from the electronic data reports under Sec.  75.64 of this chapter.
* * * * *
    (6) Calculate the annual CH4 and N2O mass
emissions from the combustion of blended fuels as follows:
    (i) If the mass or volume of each component fuel in the blend is
measured before the fuels are mixed and combusted, calculate and report
CH4 and N2O emissions separately for each
component fuel, using the applicable procedures in this paragraph (c).
    (ii) If the mass or volume of each component fuel in the blend is
not measured before the fuels are mixed and combusted, a reasonable
estimate of the percentage composition of the blend, based on best
available information, is required. Perform the following calculations
for each component fuel, ``i,'' that is listed in Table C-2:
    (A) Multiply (% Fuel)i, the estimated mass or volume
percentage (decimal fraction) of component fuel ``i,'' by the total
annual mass or volume of the blended fuel combusted during the
reporting year, to obtain an estimate of the annual consumption of
component ``i;''
    (B) Multiply the result from paragraph (c)(6)(ii)(A) of this
section by the HHV of the fuel (default value or, if available, the
measured annual average value), to obtain an estimate of the annual
heat input from component ``i;''
    (C) Calculate the annual CH4 and N2O
emissions from component ``i,'' using Equation C-8, C-9a, or C-10 of
this section, as applicable;
    (D) Sum the annual CH4 emissions across all component
fuels to obtain the annual CH4 emissions for the blend.
Similarly sum the annual N2O emissions across all component
fuels to obtain the annual N2O emissions for the blend.
Report these annual emissions totals.
    (d) * * *
    (1) When a unit is a fluidized bed boiler, is equipped with a wet
flue gas desulfurization system, or uses other acid gas emission
controls with sorbent injection to remove acid gases, if the chemical
reaction between the acid gas and the sorbent produces CO2
emissions, use Equation C-11 of this section to calculate the
CO2 emissions from the sorbent, except when those
CO2 emissions are monitored by CEMS. When a sorbent other
than CaCO3 is used, determine site-specific values of R and
MWS.
* * * * *
R = The number of moles of CO2 released upon capture of
one mole of the acid gas species being removed (R = 1.00 when the
sorbent is CaCO3 and the targeted acid gas species is
SO2).
* * * * *
    (2) The total annual CO2 mass emissions reported for the
unit shall include the CO2 emissions from the combustion
process and the CO2 emissions from the sorbent.
    (e) Biogenic CO2 emissions from combustion of biomass
with other fuels. Use the applicable procedures of this paragraph (e)
to estimate biogenic CO2 emissions from units that combust a
combination of biomass and fossil fuels (i.e., either co-fired or
blended fuels). Separate reporting of biogenic CO2 emissions
from the combined combustion of biomass and fossil fuels is required
for those biomass fuels listed in Table C-1 of this section and for
municipal solid waste. In addition, when a biomass fuel that is not
listed in Table C-1 is combusted in a unit that has a maximum rated
heat input greater than 250 mmBtu/hr, if the biomass fuel accounts for
10% or more of the annual heat input to the unit, and if the unit

does not use CEMS to quantify its annual CO2 mass emissions,
then, pursuant to Sec.  98.33(b)(3)(iii), Tier 3 must be used to
determine the carbon content of the biomass fuel and to calculate the
biogenic CO2 emissions from combustion of the fuel.
Notwithstanding these requirements, separate reporting of biogenic
CO2 emissions is optional for units subject to subpart D of
this part and for units that use the CO2 mass emissions
calculation methodologies in part 75 of this chapter, pursuant to
paragraph (a)(5) of this section; however, if the owner or operator
opts to report biogenic CO2 emissions separately for these
units, the appropriate method(s) in this paragraph (e) shall be used.
Separate reporting of biogenic CO2 emissions from the
combustion of tires is also optional, but may be reported by following
the provisons of paragraph (e)(3) of this section.
    (1) You may use Equation C-1 of this subpart to calculate the
annual CO2 mass emissions from the combustion of the biomass
fuels listed in Table C-1 of this subpart (except MSW and tires), in a
unit of any size, including units equipped with a CO2 CEMS,
except when the use of Tier 2 is required as specified in paragraph
(b)(1)(iv) of this section. Determine the quantity of biomass combusted
using one of the following procedures in this paragraph (e)(1), as
appropriate, and document the selected procedures in the Monitoring
Plan under Sec.  98.3(g):
    (i) Company records.
    (ii) The procedures in paragraph (e)(5) of this section.
    (iii) The best available information for premixed fuels that
contain biomass and fossil fuels (e.g., liquid fuel mixtures containing
biodiesel).
    (2) You may use the procedures of this paragraph if the following
three conditions are met: first, a CO2 CEMS (or a surrogate
O2 monitor) and a stack gas flow rate monitor are used to
determine the annual CO2 mass emissions (either according to
part 75 of this chapter, the Tier 4 Calculation Methodology, or the
alternative calculation methodology specified in paragraph (a)(5)(iii)
of this section); second, neither MSW nor tires is combusted in the
unit during the reporting year; and third, the CO2 emissions
consist solely of combustion products (i.e., no process or sorbent
emissions included).
* * * * *
    (iii) * * *

Fc = Fuel-specific carbon based F-factor, either a
default value from Table 1 in section 3.3.5 of appendix F to part 75
of this chapter, or a site-specific value determined under section
3.3.6 of appendix F to part 75 (scf CO2/mmBtu).
* * * * *

    (iv) Subtract Vff from Vtotal to obtain
Vbio, the annual volume of CO2 from the
combustion of biomass.
* * * * *
    (vi) * * *
    (C) From the electronic data report required under Sec.  75.64 of
this chapter, for units in the Acid Rain Program and other units using
CEMS to monitor and report CO2 mass emissions according to
part 75 of this chapter. However, before calculating the annual
biogenic CO2 mass emissions, multiply the cumulative annual
CO2 mass emissions by 0.91 to convert from short tons to
metric tons.
    (3) You must use the procedures in paragraphs (e)(3)(i) through
(e)(3)(iii) of this section to determine the annual biogenic
CO2 emissions from the combustion of MSW. These procedures
also may be used for any unit that co-fires biomass and fossil fuels,
including units equipped with a CO2 CEMS, and units for
which optional separate reporting of biogenic CO2 emissions
from the combustion of tires is selected.
    (i) Use an applicable CO2 emissions calculation method
in this section to quantify the total annual CO2 mass
emissions from the unit.
    (ii) Determine the relative proportions of biogenic and non-
biogenic CO2 emissions in the flue gas on a quarterly basis
using the method specified in Sec.  98.34(d) (for units that combust
MSW as the primary fuel or as the only fuel with a biogenic component)
or in Sec.  98.34(e) (for other units, including units that combust
tires).
    (iii) Determine the annual biogenic CO2 mass emissions
from the unit by multiplying the total annual CO2 mass
emissions by the annual average biogenic decimal fraction obtained from
Sec.  98.34(d) or Sec.  98.34(e), as applicable.
    (4) [Reserved]
    (5) If Equation C-1 or Equation C-2a of this section is selected to
calculate the annual biogenic mass emissions for wood, wood waste, or
other solid biomass-derived fuel, Equation C-15 of this section may be
used to quantify biogenic fuel consumption, provided that all of the
required input parameters are accurately quantified. * * *
* * * * *
    10. Section 98.34 is amended by:
    a. Revising paragraphs (a)(2), (a)(3), (a)(6), (b)(1) introductory
text, (b)(1)(i) introductory text, (b)(1)(i)(A), (b)(1)(i)(B),
(b)(1)(i)(C), (b)(1)(ii), (b)(1)(iii), (b)(1)(vi), (b)(3)(ii), and
(b)(3)(v).
    b. Removing paragraph (b)(4).
    c. Redesignating paragraph (b)(5) as (b)(4).
    d. Revising newly designated paragraph (b)(4).
    e. Revising paragraphs (c) introductory text, (c)(1)(i),
(c)(1)(ii), (c)(2), (c)(3), and (c)(4).
    f. Adding paragraphs (c)(6) and (c)(7).
    g. Revising paragraphs (d), (e), (f) introductory text, (f)(1),
(f)(3), and (f)(5).
    h. Adding new paragraphs (f)(7) and (f)(8).
    i. Removing paragraph (g).

Sec.  98.34  Monitoring and QA/QC requirements.

* * * * *
    (a) * * *
    (2) The minimum required frequency of the HHV sampling and analysis
for each type of fuel or fuel mixture (blend) is specified in this
paragraph. When the specified frequency for a particular fuel or blend
is based on a specified time period (e.g., week, month, quarter, or
half-year), fuel sampling and analysis is required only for those time
periods in which the fuel or blend is combusted. The owner or operator
may perform fuel sampling and analysis more often than the minimum
required frequency, in order to obtain a more representative annual
average HHV.
    (i) For natural gas, semiannual sampling and analysis is required
(i.e., twice in a calendar year, with consecutive samples taken at
least four months apart).
    (ii) For coal and fuel oil, and for any other solid or liquid fuel
that is delivered in lots, analysis of at least one representative
sample from each fuel lot is required. For fuel oil, as an alternative
to sampling each fuel lot, a sample may be taken upon each addition of
oil to the unit's storage tank. Flow proportional sampling, continuous
drip sampling, or daily manual oil sampling may also be used, in lieu
of sampling each fuel lot. For the purposes of this section, a fuel lot
is defined as either:
    (A) A shipment or delivery of a single fuel (e.g., ship load, barge
load, group of trucks, group of railroad cars, oil delivery via
pipeline from a tank farm, etc.); or
    (B) If multiple deliveries of a particular type of fuel are
received from the same supply source in a given calendar month, the
deliveries for that month are considered, collectively, to comprise a
fuel lot, requiring only one representative sample.
    (iii) For liquid fuels other than fuel oil, and for gaseous fuels
other than natural gas (including biogas), sampling and analysis is
required at least once per calendar quarter. To the extent

practicable, consecutive quarterly samples shall be taken at least 30
days apart.
    (iv) For other solid fuels (except MSW), weekly sampling is
required to obtain composite samples, which are then analyzed monthly.
    (v) For fuel blends that are received already mixed, as described
in paragraph (a)(3)(ii) of this section, determine the HHV of the blend
as follows. For blends of solid fuels (except MSW), weekly sampling is
required to obtain composite samples, which are analyzed monthly. For
blends of liquid or gaseous fuels, sampling and analysis is required at
least once per calendar quarter. More frequent sampling is recommended
if the composition of the blend varies significantly during the year.
    (3) Special Considerations for Blending of Fuels. In situations
where different types of fuel listed in Table C-1 of this subpart (for
example, different ranks of coal or different grades of fuel oil) are
in the same state of matter (i.e., solid, liquid, or gas), and are
blended prior to combustion, use the following procedures to determine
the appropriate CO2 emission factor and HHV for the blend.
    (i) If the fuels to be blended are received separately, and if the
quantity (mass or volume) of each fuel is measured before the fuels are
mixed and combusted, then, for each component of the blend, calculate
the CO2 mass emissions separately. Substitute into Equation
C-2a of this subpart the total measured mass or volume of the component
fuel (from company records), together with the appropriate default
CO2 emission factor from Table C-1, and the annual average
HHV, calculated according to Sec.  98.33(a)(2)(ii). In this case, the
fact that the fuels are blended prior to combustion is of no
consequence.
    (ii) If the fuel is received as a blend (i.e., already mixed), a
reasonable estimate of the relative proportions of the components of
the blend must be made, using the best available information (e.g., the
approximate annual average mass or volume percentage of each fuel,
based on the typical or expected range of values). Determine the
appropriate CO2 emission factor and HHV for use in Equation
C-2a of this subpart, as follows:
    (A) Consider the blend to be the ``fuel type,'' measure its HHV at
the frequency prescribed in paragraph (a)(2)(v) of this section, and
determine the annual average HHV value for the blend according to Sec.
98.33(a)(2)(ii).
    (B) Calculate a heat-weighted CO2 emission factor,
(EF)B, for the blend, using Equation C-16 of this section.
The heat-weighting in Equation C-16 is provided by the default HHVs
(from Table C-1) and the estimated mass or volume percentages of the
components of the blend.
    (C) Substitute into Equation C-2a of this subpart, the annual
average HHV for the blend (from paragraph (a)(3)(ii)(A) of this
section) and the calculated value of (EF)B, along with the
total mass or volume of the blend combusted during the reporting year,
to determine the annual CO2 mass emissions from combustion
of the blend.
[GRAPHIC] [TIFF OMITTED] TP11AU10.005

    Where:

(EF)B = Heat-weighted CO2 emission factor for
the blend (kg CO2/mmBtu)
(HHV)I = Default high heat value for fuel ``i'' in the
blend, from Table C-1 (mmBtu per mass or volume)
(%Fuel)I = Estimated mass or volume percentage of fuel
``i'' (mass % or volume %, as applicable, expressed as a decimal
fraction; e.g., 25% = 0.25)
(EF)I = Default CO2 emission factor for fuel
``i'' from Table C-1 (mmBtu per mass or volume)
(HHV)B = Annual average high heat value for the blend,
calculated according to Sec.  98.33(a)(2)(ii) (mmBtu per mass or
volume)

    (iii) Note that for the case described in paragraph (a)(3)(ii) of
this section, if measured HHV values for the individual fuels in the
blend or for the blend itself are not routinely received at the minimum
frequency prescribed in paragraph (a)(2) of this section (or at a
greater frequency), and if the unit qualifies to use Tier 1, calculate
(HHV)B*, the heat-weighted default HHV for the blend, using
Equation C-17 of this section. Then, use Equation C-16 of this section,
replacing the term (HHV)B with (HHV)B* in the
denominator, to determine the heat-weighted CO2 emission
factor for the blend. Finally, substitute into Equation C-1 of this
subpart, the calculated values of (HHV)B* and
(EF)B, along with the total mass or volume of the blend
combusted during the reporting year, to determine the annual
CO2 mass emissions from combustion of the blend.
[GRAPHIC] [TIFF OMITTED] TP11AU10.006

    Where:

(HHV)B* = Heat-weighted default high heat value for the
blend (mmBtu per mass or Volume)
(HHV)I = Default high heat value for fuel ``i'' in the
blend, from Table C-1 (mmBtu per mass or volume)
(%Fuel)I = Estimated mass or volume percentage of fuel
``i'' in the blend (mass % or volume %, as applicable, expressed as
a decimal fraction)

    (iv) If the fuel blend described in paragraph (a)(3)(ii) of this
section consists of a mixture of fuel(s) listed in Table C-1 of this
subpart and one or more fuels not listed in Table C-1, calculate
CO2 and other GHG emissions only for the Table C-1 fuel(s),
using the best available estimate of the mass or volume percentage(s)
of the Table C-1 fuel(s) in the blend. In this case, Tier 1 shall be
used, with the following modifications to Equations C-17 and C-1, to
account for the fact that not all of the fuels in the blend are listed
in Table C-1:
    (A) In Equation C-17, apply the term (Fuel)i only to the
Table C-1 fuels. For each Table C-1 fuel, (Fuel)i will be
the estimated mass or volume percentage of the fuel in the blend,
divided by the sum of the mass or volume percentages of the Table C-1
fuels. For example,

suppose that a blend consists of two Table C-1 fuels (``A'' and ``B'')
and one fuel type (``C'') not listed in the Table, and that the volume
percentages of fuels A, B, and C in the blend, expressed as decimal
fractions, are, respectively, 0.50, 0.30, and 0.20. The term
(Fuel)i in Equation C-17 for fuel A will be 0.50/(0.50 +
0.30) = 0.625, and for fuel B, (Fuel)i will be 0.30/(0.50 +
0.30) = 0.375.
    (B) In Equation C-1, the term ``Fuel'' will be equal to the total
mass or volume of the blended fuel combusted during the year multiplied
by the sum of the mass or volume percentages of the Table C-1 fuels in
the blend. For the example in paragraph (a)(3)(iv)(A) of this section,
``Fuel'' = (Annual volume of the blend combusted) (0.80).
* * * * *
    (6) You must use one of the following appropriate fuel sampling and
analysis methods. You may use a method published by a consensus
standards organization if such a method exists, or you may use industry
consensus standard practice to determine the high heat values.
Consensus-based standards organizations include, but are not limited
to, the following: ASTM International, the American National Standards
Institute (ANSI), the American Gas Association (AGA), the American
Society of Mechanical Engineers (ASME), the American Petroleum
Institute (API), and the North American Energy Standards Board (NAESB).
Alternatively, for gaseous fuels, the HHV may be calculated using
chromatographic analysis together with standard heating values of the
fuel constituents, provided that the gas chromatograph is operated,
maintained, and calibrated according to the manufacturer's
instructions. The method(s) used shall be documented in the Monitoring
Plan required under Sec.  98.3(g)(5).
    (b) * * *
    (1) You must calibrate each oil and gas flow meter according to
Sec.  98.3(i) and the provisions of this paragraph (b)(1).
    (i) Perform calibrations using any of the test methods and
procedures in this paragraph (b)(1)(i). The method(s) used shall be
documented in the Monitoring Plan required under Sec.  98.3(g)(5).
    (A) You may use an appropriate flow meter calibration method
published by a consensus standards organization, if such a method
exists. Consensus-based standards organizations include, but are not
limited to, the following: ASTM International, the American National
Standards Institute (ANSI), the American Gas Association (AGA), the
American Society of Mechanical Engineers (ASME), the American Petroleum
Institute (API), and the North American Energy Standards Board (NAESB).
    (B) You may use the calibration procedures specified by the flow
meter manufacturer.
    (C) You may use an industry-accepted or industry consensus standard
calibration practice.
    (ii) In addition to the initial calibration required by Sec.
98.3(i), recalibrate each fuel flow meter (except as otherwise provided
in paragraph (b)(1)(iii) of this section) either annually, at the
minimum frequency specified by the manufacturer, or at the interval
specified by industry consensus standard practice.
    (iii) Fuel billing meters are exempted from the initial and ongoing
calibration requirements of this paragraph and from the Monitoring Plan
and recordkeeping requirements of Sec.  98.3(g)(5)(i)(C) and (g)(7),
provided that the fuel supplier and the 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 only used for unit startup or ignition are also
exempted from the initial and ongoing calibration requirements of this
paragraph.
* * * * *
    (vi) If a mixture of liquid or gaseous fuels is transported by a
common pipe, you may either separately meter each of the fuels prior to
mixing, using flow meters calibrated according to Sec.  98.3(i), or
consider the fuel mixture to be the ``fuel type'' and meter the mixed
fuel, using a flow meter calibrated according to Sec.  98.3(i).
* * * * *
    (3) * * *
    (ii) For each type of fuel, the minimum required frequency for
collecting and analyzing samples for carbon content and (if applicable)
molecular weight is specified in this paragraph. When the sampling
frequency is based on a specified time period (e.g., week, month,
quarter, or half-year), fuel sampling and analysis is required for only
those time periods in which the fuel is combusted.
    (A) For natural gas, semiannual sampling and analysis is required
(i.e., twice in a calendar year, with consecutive samples taken at
least four months apart).
    (B) For coal and fuel oil and for any other solid or liquid fuel
that is delivered in lots, analysis of at least one representative
sample from each fuel lot is required. For fuel oil, as an alternative
to sampling each fuel lot, a sample may be taken upon each addition of
oil to the storage tank. Flow proportional sampling, continuous drip
sampling, or daily manual oil sampling may also be used, in lieu of
sampling each fuel lot. For the purposes of this section, a fuel lot is
defined as either of the following:
    (1) A shipment or delivery of a single fuel (e.g., ship load, barge
load, group of trucks, group of railroad cars, oil delivery via
pipeline from a tank farm, etc.).
    (2) If multiple deliveries of a particular type of fuel are
received from the same supply source in a given calendar month, the
deliveries for that month are considered, collectively, to comprise a
fuel lot, requiring only one representative sample.
    (C) For liquid fuels other than fuel oil and for biogas; sampling
and analysis is required at least once per calendar quarter. To the
extent practicable, consecutive quarterly samples shall be taken at
least 30 days apart.
    (D) For other solid fuels (except MSW), weekly sampling is required
to obtain composite samples, which are then analyzed monthly.
    (E) For gaseous fuels other than natural gas and biogas (e.g.,
process gas), daily sampling and analysis to determine the carbon
content and molecular weight of the fuel is required if continuous, on-
line equipment, such as a gas chromatograph, is in place to make these
measurements. Otherwise, weekly sampling and analysis shall be
performed.
    (F) For mixtures (blends) of solid fuels, weekly sampling is
required to obtain composite samples, which are analyzed monthly. For
blends of liquid fuels, and for gas mixtures consisting only of natural
gas and biogas, sampling and analysis is required at least once per
calendar quarter. For gas mixtures that contain gases other than
natural gas (including biogas), daily sampling and analysis to
determine the carbon content and molecular weight of the fuel is
required if continuous, on-line equipment is in place to make these
measurements. Otherwise, weekly sampling and analysis shall be
performed.
* * * * *
    (v) To calculate the CO2 mass emissions from combustion
of a blend of fuels in the same state of matter (solid, liquid, or
gas), you may either:
    (A) Apply Equation C-3, C-4 or C-5 of this subpart (as applicable)
to each component of the blend, if the mass or volume, the carbon
content, and (if applicable), the molecular weight of each component
are accurately measured prior to blending; or
    (B) Consider the blend to be the ``fuel type.'' Then, at the
frequency specified

in paragraph (b)(3)(ii)(F) of this section, measure the carbon content
and, if applicable, the molecular weight of the blend and calculate the
annual average value of each parameter in the manner described in Sec.
98.33(a)(2)(ii). Also measure the mass or volume of the blended fuel
combusted during the reporting year. Substitute these measured values
into Equation C-3, C-4, or C-5 of this subpart (as applicable).
    (4) You must use one of the following appropriate fuel sampling and
analysis methods. You may use a method published by a consensus
standards organization if such a method exists, or you may use industry
consensus standard practice to determine the carbon content and
molecular weight (for gaseous fuel) of the fuel. Consensus-based
standards organizations include, but are not limited to, the following:
ASTM International, the American National Standards Institute (ANSI),
the American Gas Association (AGA), the American Society of Mechanical
Engineers (ASME), the American Petroleum Institute (API), and the North
American Energy Standards Board (NAESB). Alternatively, the results of
chromatographic analysis of the fuel may be used, provided that the gas
chromatograph is operated, maintained, and calibrated according to the
manufacturer's instructions. The method(s) used shall be documented in
the Monitoring Plan required under Sec.  98.3(g)(5).
    (c) For the Tier 4 Calculation Methodology, the CO2,
flow rate, and (if applicable) moisture monitors must be certified
prior to the applicable deadline specified in Sec.  98.33(b)(5).
    (1) * * *
    (i) Sections 75.20(c)(2), (c)(4), and (c)(5) through (c)(7) of this
chapter and appendix A to part 75 of this chapter.
    (ii) The calibration drift test and relative accuracy test audit
(RATA) procedures of Performance Specification 3 in appendix B to part
60 of this chapter (for the CO2 concentration monitor) and
Performance Specification 6 in appendix B to part 60 of this chapter
(for the continuous emission rate monitoring system (CERMS)).
* * * * *
    (2) If an O2 concentration monitor is used to determine
CO2 concentrations, the applicable provisions of part 75 of
this chapter, part 60 of this chapter, or an applicable State
continuous monitoring program shall be followed for initial
certification and on-going quality assurance, and all required RATAs of
the monitor shall be done on a percent CO2 basis.
    (3) For ongoing quality assurance, follow the applicable procedures
in either appendix B to part 75 of this chapter, appendix F to part 60
of this chapter, or an applicable State continuous monitoring program.
If appendix F to part 60 of this chapter is selected for on-going
quality assurance, perform daily calibration drift assessments for both
the CO2 monitor (or surrogate O2 monitor) and the
flow rate monitor, conduct cylinder gas audits of the CO2
concentration monitor in three of the four quarters of each year
(except for non-operating quarters), and perform annual RATAs of the
CO2 concentration monitor and the CERMS.
    (4) For the purposes of this part, the stack gas volumetric flow
rate monitor RATAs required by appendix B to part 75 of this chapter
and the annual RATAs of the CERMS required by appendix F to part 60 of
this chapter need only be done at one operating level, representing
normal load or normal process operating conditions, both for initial
certification and for ongoing quality assurance.
* * * * *
    (6) For certain applications where combined process emissions and
combustion emissions are measured, the CO2 concentrations in
the flue gas may be considerably higher than for combustion emissions
alone. In such cases, the span of the CO2 monitor may, if
necessary, be set higher than the specified levels in the applicable
regulations. If the CO2 span value is set higher than 20
percent CO2, the cylinder gas audits of the CO2
monitor under appendix F to part 60 of this chapter may be performed at
40 to 60 percent and 80 to 100 percent of span, in lieu of the
prescribed calibration levels of 5 to 8 percent CO2 and 10
to 14 percent CO2.
    (7) Hourly average data from the CEMS shall be validated in a
manner consistent with one of the following: Sec. Sec.  60.13(h)(2)(i)
through (h)(2)(vi) of this chapter; Sec.  75.10(d)(1) of this chapter;
or the hourly data validation requirements of an applicable State CEM
regulation.
    (d) When municipal solid waste (MSW) is either the primary fuel
combusted in a unit or the only fuel with a biogenic component
combusted in the unit, determine the biogenic portion of the
CO2 emissions using ASTM D6866-08 Standard Test Methods for
Determining the Biobased Content of Solid, Liquid, and Gaseous Samples
Using Radiocarbon Analysis (incorporated by reference, see Sec.  98.7)
and 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 (incorporated
by reference, see Sec.  98.7). Perform the ASTM D7459-08 sampling and
the ASTM D6866-08 analysis at least once in every calendar quarter in
which MSW is combusted in the unit. Collect each gas sample during
normal unit operating conditions for at least 24 consecutive hours or
for as long as is deemed necessary to obtain a representative sample.
One suggested alternative sampling approach would be to collect an
integrated sample by extracting a small amount of flue gas (e.g., 1 to
5 cc) in each unit operating hour during the quarter. Separate the
total annual CO2 emissions into the biogenic and non-
biogenic fractions using the average proportion of biogenic emissions
of all samples analyzed during the reporting year. Express the results
as a decimal fraction (e.g., 0.30, if 30 percent of the CO2
is biogenic). When MSW is the primary fuel for multiple units at the
facility, and the units are fed from a common fuel source, testing at
only one of the units is sufficient.