Section 98.343(a)(2) of subpart HH specifically requires these waste
quantities [in units of mass] to be determined daily, and 40 CFR
98.344(a) states that ``[t]he quantity of waste landfilled must be
determined using mass measurement equipment * * *'' EPA answered
numerous questions regarding this requirement and communicated the
above interpretation to the industry in webinars and other outreach
materials. Consequently, we do not consider the proposed amendments in
40 CFR 98.343(a)(3) to be a substantial material change in the
requirements of the rule published on October 30, 2009. However, we
recognize that some reporters did not believe that the rule language
was explicit with respect to these requirements. Additionally, we
reconsidered our original position that scales must be installed. The
proposed amendments addressed both of these issues.
    We had not considered that there would be physical limitations to
accessing the scale. We also anticipated that the scales would cover
the range of sizes and weights received at the site. As we no longer
require the installation of permanent scales at a facility, we
certainly do not intend to require facilities to have to replace
existing scales to accommodate unusually sized or heavy loads. As such,
we conclude that it is reasonable to allow facilities to use the
methods in 40 CFR 98.343(a)(3)(ii) for certain waste loads even though
scales are present at the facility. However, because the mass of waste
is a critical input to Equation HH-1 and we desire accurate
measurements of this waste, the methods outlined in 40 CFR
98.343(a)(3)(ii) are limited to waste loads that cannot be measured
using the scales due to physical and operational limitations of the
scale. Physical limitations refers to the shape or size of the load so
that it cannot access the scale or does not fit on the scale.
Operational limitations refers to the weight of the load exceeding the
limits or sensitivity range of the scale. Operational limitations are
not intended to consider waiting times to access the scale. For all
other types of waste loads (other than passenger vehicles or light duty
trucks), the direct mass measurement methods in 40 CFR 98.343(a)(3)(i)
must be used.

Q. Subpart LL--Suppliers of Coal-Based Liquid Fuels

1. Summary of Final Amendments and Major Changes Since Proposal
    First, we are amending 40 CFR 98.386(a)(5) and (6) to clarify that
fossil-fuel products that enter the facility will not be reported when
exiting the facility if they are not further refined or otherwise used
on site (e.g. products stored in a tank). It was not EPA's intent that
such products be reported.
    Second, we are amending 40 CFR 98.386(a)(3), (a)(7), (b)(3), and
(c)(3) to harmonize the reporting requirements with the amendments in
40 CFR 98.393 of today's rule to account for denaturant in ethanol.
Third, we are replacing a comma with the words ``that were'' in 40 CFR
98.386(a)(16) and (a)(17) and adding a paragraph at 40 CFR 98.386(d) to
harmonize the reporting requirements with the amendment in 40 CFR
98.393(i) of today's rule to provide an optional method for calculating
GHG emissions from blended feedstock and products. Since subpart LL
reporters follow subpart MM methodologies for calculating GHG
emissions, these amendments are necessary to ensure complete reporting
of subpart LL data.
2. Summary of Comments and Responses
    EPA did not receive any comments on the proposed amendments to
subpart LL and is finalizing the amendments to this subpart as
proposed.

R. Subpart MM--Suppliers of Petroleum Products

1. Summary of Final Amendments and Major Changes Since Proposal
    We are adding a definition of ``batch'' in 40 CFR 98.398 to clarify
the crude oil reporting requirements in 40 CFR 98.396(a)(20) and to
minimize administrative burden. Under this final rule, a batch of crude
oil means either a volume that enters a refinery or a component of such
volume (e.g., the volumes of different crude streams that are blended
together and then delivered to a refinery). The batch volume is
dependent upon what a refiner knows about the crude oil it receives and
is the first appropriate tier in the following list:
    (1) Up to an annual volume of a type of crude oil identified by an
EIA crude stream code,\6\ if the EIA crude stream code is known.
---------------------------------------------------------------------------

    \6\ The EIA crude stream code is the numeric code used to
identify the type of domestic crude oil in Form EIA-182 (Domestic
Crude Oil First Purchase Report) and the alpha numeric code used to
identify the type of foreign crude oil in Form EIA-856 (Monthly
Foreign Crude Oil Acquisition Report).
---------------------------------------------------------------------------

    (2) Up to an annual volume of a type of crude oil identified by a
generic name for the crude stream and an appropriate EIA two-letter
country or state and production area code \7\ if the generic name and
EIA two-letter code are known but no appropriate EIA crude stream code
exists.
---------------------------------------------------------------------------

    \7\ EIA country code means the two-letter code identifying the
country associated with the alpha numeric crude stream codes used to
identify the type of foreign crude oil in Form EIA-856 and is
traditionally found in Appendix A of the form. The EIA state and
production area code is the two-letter code used to identify the
source of domestic crude oil in Form EIA-182 is traditionally found
in Appendix A of the instructions.
---------------------------------------------------------------------------

    (3) Up to a calendar month volume from a single known foreign
country of origin if the crude stream name is unknown.
    (4) Up to a calendar month volume from the United States if the
crude stream name and production area are unknown.
    (5) Up to a calendar month volume if the country of origin is
unknown.
    For example, if refiners know the EIA crude stream code of a volume
of crude oil that they receive, they must report the API gravity and
sulfur content of up to an annual volume of this type of crude oil. If
refiners only know the country of origin of a volume of foreign crude
oil (but not the crude stream name), they must report the API gravity
and sulfur content of up to a calendar month volume from that country.
    For data collection in 2010 only, a refiner that knows the
information that we require them to report under a specific tier of the
batch definition, but does not have the necessary data collection and
management in place to readily report this information, can use the
next most appropriate tier of the batch definition for reporting batch
information in 40 CFR 98.396(a)(20).
    With this definition of ``batch'', we are requiring refiners to
report on crude oil volumes in 40 CFR 98.396(a)(20) using the best data
they are collecting as part of normal business practices. For example,
refiners must use data on the American Petroleum Institute (API)
gravity and sulfur content of crude oil that they, or a third party,
currently collect as part of normal business practices, including data
refiners use to report monthly weighted average API gravity and sulfur
content to EIA. As another example, refiners must use data that they
currently collect on the EIA crude stream code or country of origin for
the components of a blended crude oil.

    We are making harmonizing amendments to 40 CFR 98.396(a)(20) to
allow refiners to report the country of origin, EIA crude stream code
and name, or the generic name of the crude stream and associated
production area code for a given batch as appropriate, if known.
    To better align the API gravity and sulfur content reporting
requirements with normal business practices, we are also amending the
recordkeeping requirements in 40 CFR 98.397 so that refiners will no
longer be required to maintain laboratory reports, calculations and
worksheets used in the measurement of API gravity and sulfur content of
crude oil. Instead, refiners must maintain sufficient records to
support the information they report to EPA (as required by 40 CFR
98.397(a) and (b)).
    We are also amending 40 CFR 98.394(d) and 40 CFR 98.396(a)(20) to
clarify that we are seeking the weighted average API gravity and sulfur
content from representative samples of each batch.
    To ensure that refiners can report readily available data in 40 CFR
98.386(a)(20) on the volume and associated characteristics of
components of a blended crude oil, we are amending the requirements for
determining quantity of crude oil in 40 CFR 98.394(a)(1) so that they
only apply to volumes of crude oil that refiners measure on site (e.g.,
the total volume rather than the components of such volume). Refiners
may now use an industry standard practice to determine volumes of crude
oil that are not measured on site, even if an appropriate standard
method published by a consensus-based standards organization exists, as
specified in a new paragraph, 40 CFR 98.394(a)(3). We are also amending
the recordkeeping requirements associated with quantity determination
in 40 CFR 98.397(b) so that refiners will not be required to maintain
metering and gauging records for quantities of crude oil that they do
not measure on site, including the date of initial calibration and
frequency of recalibration for associated measurement equipment. We are
also amending 98.394(d) to give refiners the option of following an
industry standard practice to measure API gravity and sulfur content of
crude oil.
    We are amending the definition of Producti (annual
volume of product ``i'' produced, imported, or exported) in Equation
MM-1 in 40 CFR 98.393(a)(1) and (2) to make it clear that GHG emissions
should not be calculated for products leaving the refinery if those
products had entered the refinery but were not further refined or
otherwise used on site (e.g., products stored in a tank). As a
harmonizing change, we are amending 40 CFR 98.396(a)(5) and (6) to
clarify that these products are not reported.
    We are amending the procedure in 40 CFR 98.393(f)(1) for
calculating emission factors for solid products when using Calculation
Method 1. The amendments will clarify that reporters should multiply
the default carbon share factor in column B of Table MM-1 to subpart MM
by 44/12 (the ratio of the molecular weight of CO2 to the
atomic weight of carbon) to convert the amount of carbon in the product
to CO2. Due to an oversight, 44/12 was not included in the
original formula. This amendment is necessary because otherwise
reporters would calculate the emissions of carbon instead of carbon
dioxide.
    We are amending Equation MM-9 in 40 CFR 98.393(h)(2) to correct a
typographical error. The correct emission factor (EF) term in the
equation is EFj not EFi.
    We are adding an optional method for reporters in 40 CFR 98.393(i)
to calculate CO2 emissions that would result from the
complete oxidation or combustion of a blended product or blended non-
crude feedstock. The procedures in the existing rule require reporters
to calculate CO2 emissions for blended products either by
selecting the default emission factor for the product listed in Table
MM-1 to subpart MM that resembles most closely the blended product
(Calculation Method 1) or by sampling and testing the blended product
(Calculation Method 2). If a reporter applies the former method, the
CO2 emissions calculation for the blended product will
likely reflect the CO2 content of only one blend component.
In such a case, the CO2 from the blended product will not be
as accurately accounted for in Equation MM-4 of subpart MM. The
optional method we are adding allows reporters to account for the
CO2 emissions of a blended product or blended non-crude
feedstock in the summary calculation of total facility CO2
by calculating the emissions of the blend's individual components using
appropriate default factors listed in Table MM-1 to subpart MM. This
increases flexibility for facilities that receive and supply blends.
This also improves accuracy of the summary calculation of total
refinery CO2 because it ensures that the same quantities and
emission factors are used for blend components coming in to the
refinery as for blended products going out.
    The optional method is not available for a product that is biomass-
based because such biomass-based products are subject to paragraph (h)
of 40 CFR 98.393.
    To align the existing regulatory text with the optional method for
blends, we are amending paragraphs (a)(1) and (b)(1) of 40 CFR 98.393
and paragraphs (a)(16) and (a)(17) of 40 CFR 98.396. We are also adding
paragraph (d) of 40 CFR 98.396 to create new data reporting
requirements for blends.
    We are amending the calculation procedures in 40 CFR 98.393(h) for
blended biomass-based fuels. Part 98 (as finalized in 70 CFR 56260,
October 30, 2009) directed refineries that supply a petroleum product
that was produced by blending a petroleum-based product with denatured
ethanol to report emissions from the denaturant leaving the refinery
but not the denaturant in the ethanol that enters the refinery as a
feedstock. This resulted in over-reporting of GHG emissions across
subpart MM reporters because the blending refinery accounted for the
CO2 from denaturant in its GHG emissions calculation even
though the original refinery that produced the denaturant ex-refinery
gate already accounted for the CO2 in its GHG emission
calculation. To address the over-reporting for refineries using
Calculation Method 1 for petroleum products or non-crude petroleum
feedstocks that contain denatured ethanol, we are amending Equations
MM-8 and MM-9 of subpart MM to exclude denaturant from the term
``%vol'', respectively.
    To address this over-reporting for refineries using Calculation
Method 2 for petroleum products that were produced by blending a
petroleum-based product with denatured ethanol on site, we are adding a
new Equation MM-10a of subpart MM. Equation MM-10a requires refineries
to sample the petroleum-based products prior to blending them with
denatured ethanol and use the resulting emissions factor and the volume
of the petroleum-based product to calculate emissions for the ultimate
petroleum products that leave the refinery. This new equation is
necessary and Equation MM-10 is incorrect for such situations because
the term for the biomass default emission factor in Equation MM-10 is
applied to the whole volume of biomass received for blending (which for
ethanol includes denaturant), even though the default factor for
ethanol does not account for denaturant. We are splitting 40 CFR
98.393(h)(3) into paragraphs (i) and (ii) so that Equation MM-10
remains in (i) for petroleum products blended with

biomass other than denatured ethanol while Equation MM-10a appears in
(ii) for petroleum products blended with denatured ethanol. We are
amending Equation MM-10 to exclude denaturant from the term ``%vol.''
    Together, these amendments ensure that the denaturant present in
ethanol is not accounted for in the calculation of CO2 that
would result from the complete combustion or oxidation of the biomass-
blended product or feedstock. We have concluded that these amendments
simplify reporting for reporters while maintaining the level of data
quality and accuracy required by EPA for subpart MM because we would
expect any denaturant in ethanol that enters the refinery in a
feedstock to leave the refinery in a product and therefore the
CO2 emissions from the denaturant would be a net of zero.
    We cannot identify a situation, nor did any commenters, in which a
refinery would want to use Calculation Method 2 for a non-crude
feedstock that contains denatured ethanol or an importer or exporter
would want to use Calculation Method 2 for products containing
denatured ethanol. Therefore, we are splitting 40 CFR 98.393(h)(4) into
paragraphs (i) and (ii) so that Equation MM-11 of subpart MM remains in
(i) for non-crude feedstocks blended with biomass other than denatured
ethanol while directions to use Calculation Method 1 appear in (ii) for
non-crude feedstocks blended with denatured ethanol by refineries. We
are also adding directions in 40 CFR 98.393(h)(3)(ii) for importers and
exporters of petroleum products blended with denatured ethanol to use
Calculation Method 1. We are amending Equation MM-11 to exclude
denaturant from the term ``%vol.''
    We are amending 40 CFR 98.396(a)(3), (a)(7), (b)(3), and (c)(3) to
align the reporting requirements with the amendments to account for
denaturant in ethanol.
    Major changes since the proposal are identified in the following
list. The rationale for these and any other significant changes can be
found in Response to Comments: Technical Corrections, Clarifying and
Other Amendments (see EPA-HQ-OAR-2010-0109).

     We expanded on the proposed definition of ``batch'' to
require refiners to report up to an annual volume of a type of crude
oil identified by an EIA crude stream code (or the generic crude
stream name and production area code if no appropriate EIA crude
stream code exists) if refiners know this information. If refiners
do not know this information, refiners must report according to the
proposed definition of batch (e.g., up to a calendar month volume
from a single country of origin or, if refiners do not know the
country of origin, up to a total calendar month volume).
     We clarified that ``batch'' can mean either the volume
that enters a refinery or the components of such volume. We amended
40 CFR 98.394(a) to allow refiners to use industry standard
practices to determine crude oil volumes that they do not measure on
site, rather than standard methods published by a consensus-based
standard, if desired. We also amended the recordkeeping requirements
associated with quantity determination in 40 CFR 98.397(b) so that
refiners are not required to maintain metering and gauging records
for quantities of crude oil that they do not measure on site.
     We amended 40 CFR 98.394(d) to allow refiners to use
industry standard practices to measure API gravity and sulfur
content of crude oil, rather than standard methods published by a
consensus-based standards organization, if desired.
     For reporting year 2010 only, we are providing
reporters some flexibility in defining a batch of crude oil. A
refiner that knows the information under a specific tier of the
batch definition, but does not have the necessary data collection
and management in place to readily report this information, can use
the next most appropriate tier of the batch definition for reporting
batch information in 40 CFR 98.396(a)(20).
     As a harmonizing amendment with the final definition of
crude oil (as discussed in Section II.B, Subpart A--General
Provisions, of this preamble), we added a reporting requirements for
refineries in 40 CFR 98.396(a). Refiners are now required to report
on the volume of crude oil that they inject into a crude supply or
reservoir under a new paragraph (22).
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in Response to
Comments: Technical Corrections, Clarifying and Other Amendments (see
EPA-HQ-OAR-2010-0109).
    Comment: We received three comments related to our proposed
amendments regarding the treatment of denatured ethanol. Two comments
supported the proposed change. The third commented that reporting of
gasoline-ethanol blends (i.e., a petroleum product that contains
denatured ethanol and is a blended biomass-based fuel) was burdensome
and suggested that only the petroleum portion of these blends should be
reported. That commenter stated that the blending of ethanol with
gasoline should not be considered ``to be further refined or otherwise
used on site'' (40 CFR 98.396(a)(1)) and that therefore, ethanol should
not have to be reported.
    Response: We are finalizing our proposed amendments related to
denaturant in ethanol in today's rule.
    When finalizing subpart MM, (74 FR 56260, October 30, 2009), EPA
concluded that reporting the total volume of gasoline-ethanol blends ex
refinery gate as well as the percentage of that volume that is
petroleum-based is not unnecessarily burdensome to reporters. The
changes to 40 CFR Part 98.396(a) that would be necessary to remove
biomass reporting as suggested by the commenter are outside the scope
of the specific amendments proposed for public comment in the Federal
Register notice of June 15, 2010. The proposed changes to 40 CFR
98.396(a) only addressed how the denaturant in ethanol should be
treated, and EPA did not seek comment on removing reporting on biomass
entirely.
    As a result of the comments we received, we have concluded that
there has been confusion regarding how ethanol should be reported when
it leaves the facility. When ethanol leaves a facility covered by
subpart MM, it is generally being blended with finished gasoline as it
is being loaded into a truck. We are clarifying here that EPA considers
the ethanol and the gasoline to be leaving the facility separately if
they are leaving through different ``spigots'' and being blended in the
truck. Under these circumstances, there is no gasoline-ethanol blend on
site at the facility. The gasoline is the petroleum product that must
be reported as leaving the facility. The denatured ethanol is not part
of a petroleum product leaving the facility and, as a result of the
technical correction being made in this rule for how to treat the
denaturant in ethanol, need not be reported as entering or leaving the
facility under these circumstances.
    The phrase ``to be further refined or otherwise used on site'' only
applies to petroleum products, including blended biomass-based fuels,
and natural gas liquids. EPA has clarified through guidance that a
petroleum product or natural gas liquid that stays in the same
container or vessel while on site and that is not blended with any
other product is not ``otherwise used on site'' and that blending is
considered ``otherwise used on site''. If refiners blend ethanol with a
petroleum product on site--for example, a refiner blends gasoline and
ethanol on site and stores the blend in a tank before it leaves the
facility--then the total volume of the ethanol-gasoline blend as well
as the percentage of that volume that is petroleum-based must be
reported when the blend leaves the facility. The

volume of ethanol entering the facility need not be reported.
    Comment: In the proposal, we sought comment on defining a ``batch''
to help clarify crude oil reporting requirements in 40 CFR
98.396(a)(20) and reduce administrative burden, while continuing to
collect adequate crude oil data to support the purposes of subpart MM.
    We received several comments on our proposed definition of batch
and potential alternatives. One commenter supported defining a batch as
the annual volume of a type of crude oil characterized by an EIA crude
stream code (rather than monthly volumes) if EPA maintains the
requirement to report API gravity, sulfur content, and country of
origin of crude oil. One commenter expressed support for the proposed
definition of batch but cautioned that it would limit refiners to
report the country of origin as ``unknown'' when the crude oil batch is
a blend of crude oil from several known countries. The commenter
therefore advised EPA to allow refiners to report on the components in
a crude oil blend and to amend the quantity determination requirements
so that refiners can use information obtained from normal business
practices on blend component volumes. The commenter further opined
that, similar to the problem of reporting a single country of origin,
refiners receiving a crude oil blend would be unable to report a single
EIA crude stream code. Therefore the commenter recommended that EPA
include annual crude volumes by EIA crude stream codes in the
definition of batch only if it is presented as one of multiple options.
Two commenters advocated that EPA limit the definition of batch to the
annual volume of each EIA crude stream code category and remove the
requirement to report API gravity, sulfur content, and country of
origin for every batch. One commenter expressed concern about limiting
the definition of batch to the annual volume of each EIA crude stream
code category if it means losing data on API gravity. That commenter
urged EPA to require refiners to report the sample data they already
collect for EIA reporting. The commenter also asked that EPA define
``batch'' in a way that captures the differences in crude oil
originating from the same country since different crude streams from
the same country can have different API gravity and sulfur contents.
    Response: In today's rule we are finalizing a definition of
``batch'' that builds on our proposed definition by adding two
additional features. First, we are requiring refiners to define a batch
as up to an annual volume of a type of crude oil identified by an EIA
crude stream code (or a generic crude stream name and production area
code) if refiners know this information. Second, we are defining batch
as either the total volume of crude oil that enters a refinery or the
components of such volume so that refiners will be able to report
representative data they currently collect on all three crude
parameters--(1) API gravity, (2) sulfur content, and (3) country of
origin or crude stream name and production area--for the components in
a blended crude volume instead of having to report the third parameter
as unknown. These amendments were generally supported by commenters and
we concluded that they would result in better data and be less
burdensome than the proposed definition.
    With regard to comments on defining a batch as a monthly versus
annual volume of crude, we determined that API gravity and sulfur
content of specific crude streams do not vary enough to warrant
requiring batch to be defined as only up to a monthly volume. On the
other hand, API gravity and sulfur content can vary significantly
between different crude streams coming from the same country of origin
(or multiple countries of origin). Therefore, we determined that
monthly reporting outlined in the proposed definition of ``batch''
would be necessary in those cases where refiners only know the country
of origin of their crude volume (rather than the crude stream name and
production area) or when they do not know the country of origin. We did
not conclude that reporting batches more frequently than a monthly
basis would be necessary in any situation.
    We considered eliminating the requirement that refiners report API
gravity and sulfur content if they report the EIA crude stream code
associated with the batch, but we determined that there were too many
EIA crude stream codes without corresponding API gravity and sulfur
content values and that even when present these values, while
illustrative, were based on limited information and would not always be
representative of the characteristics of the crude oil used at a
refinery. Furthermore, refiners already collect data on the API gravity
and sulfur content of their crude oil in order to report this
information to EIA on a monthly basis, and it is our understanding,
based on an industry comment, that refiners also track this information
to determine how well the physical characteristics of the crude oil
align with the processing capability of their refineries.
    Comment: In the proposal, we sought comment on other technical
amendments (besides defining ``batch'') that would help clarify crude
oil reporting requirements in 40 CFR 98.396(a)(20) and reduce
administrative burden. In particular, we sought comment on ways to
better align the provisions related to crude oil reporting with normal
business practices.
    We received two comments with input on ways to better align the
monitoring and QA/QC provisions related to crude oil reporting with
normal business practices. According to the two commenters, it is
normal business practice for refiners to maintain data on crude batch
volumes and other parameters required in 40 CFR 98.396(a)(20). They
described a number of different sources they use to identify the sulfur
content and API gravity of crude oil batches (including components of
blended crude oil volumes) such as grab samples, contract laboratory
records, crude assay reports, invoices, and pipeline receipt tickets.
They explained that the data contained in these sources are often
collected outside of the refinery under normal business practices,
which may be inconsistent with the current requirements in the rule to
use standard methods to measure these data (resulting in the need to
collect the data again inside the refinery). In addition, one of the
two commenters explained that they maintain data on the components of
blended crude volumes but they may not be able to determine the volume
of the components of blended crude according to the quantity
determination requirements in 40 CFR 98.394(a)(1) since the components
arrive at the refinery already blended. Therefore, they will be forced
to report the total volume of the blended crude oil and the country of
origin (or EIA crude stream code) as ``unknown'' even though they know
information about the volume components.
    We also received two comments in support of the proposed
elimination of recordkeeping requirements in 40 CFR 98.397 related to
the measurement of API gravity and sulfur content of crude oil because
it would support the use of data collected in normal business records.
We received one comment that objected to EPA's deletion of specific
recordkeeping requirements for API gravity and sulfur content
measurements on the basis that these records were important
verification tools.
    Response: In response to comments, we are retaining our proposed
amendment to eliminate the recordkeeping requirements in 40 CFR

98.397 related to the measurement of API gravity and sulfur content of
crude oil. We are also making several additional amendments to improve
the flexibility of the QA/QC and recordkeeping requirements in the rule
to facilitate the reporting of similar and, in many cases, better
quality data on API gravity, sulfur content, and geographic origin of
crude oil batches while reducing administrative burden. We are amending
40 CFR 98.394(d) to allow refiners to use industry standard practices
to determine the API gravity and sulfur content of crude oil. We are
amending the quantity determination monitoring and QA/QC requirements
in 40 CFR 98.394(a) so that refiners can use industry standard
practices to determine the volume of components of a blended crude
batch (which are never directly measured on site at a refinery).
Therefore, refiners will be able to report representative data they
currently collect on all three crude parameters--(1) API gravity, (2)
sulfur content, and (3) country of origin or crude stream name and
production area--of the components in a blended crude volume instead of
having to report the third parameter as unknown. We are also making a
harmonizing amendment to 40 CFR 98.397(b) to eliminate the requirement
that refiners maintain metering and gauging records for crude oil batch
volumes that they do not measure on site. Together, these amendments
will allow refiners to report crude characteristics contained in crude
assay reports, third party laboratory reports, or pipeline receipt
tickets if the characteristics are representative of the crude oil used
at the refinery and it is an industry standard practice to use these
sources. We have determined that these amendments will still ensure
that the data refiners report is adequately representative of the crude
oil they receive at the refinery and that the records they keep will be
sufficient to support EPA verification of the data. We made this
determination in light of the fact that crude oil data is not used to
calculate the CO2 emissions reported under subpart MM.
    Comment: We sought comment on our proposed timeline of implementing
the technical amendments to subpart MM for the 2010 reporting year and
whether this timeline was appropriate considering the nature of the
proposed changes and/or the way in which data have been collected thus
far in 2010. We received one comment indicating that defining ``batch''
in a manner that would require monthly reporting of crude oil volumes
may necessitate modifications to current refinery sampling and
monitoring practices and that refiners may not be able to provide this
information by the March 31, 2011 reporting deadline for 2010 data.
    Response: While data collection methods may vary by refinery, we
have determined that refiners currently collect data as part of normal
business practices on the API gravity and sulfur content for at least
one of the five tiers described in the definition of ``batch'' in
today's rule and should therefore be able to meet the crude oil
reporting requirements in 40 CFR 98.396(a)(20) in a timely manner.
However, since we did not include a definition of ``batch'' in the
final rule (74 FR 56260), refiners may not have established data
collection and management systems in 2010 to link the information they
collect on API gravity, sulfur content, and volumes of crude batches to
an EIA crude stream code or generic crude stream name and production
area code (i.e., tiers 1 and 2 of the ``batch'' definition). Likewise,
refiners may not have had adequate time to link data they collect on
API gravity and sulfur content from crude coming from a single country
of origin to ``up to a calendar month volume'' (i.e., tiers 3 and 4 of
the ``batch'' definition). We are therefore providing refiners the
flexibility to report at a lower tier for reporting year 2010 if they
do not have appropriate data collection and management systems in place
to readily report the information in the higher tier.

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

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending the definition of the term ``Fuelh'' in
Equation NN-1 of subpart NN to clarify that the abbreviation ``Mscf''
refers to ``thousand standard cubic feet'' in order to avoid confusion
on if this abbreviation means ``million standard cubic feet''. We are
also adding the subscript ``h'' to the terms for Fuel and HHV in
Equation NN-1.
    We are amending the definition of the term ``EF'' in Equation NN-7
of subpart NN to clarify that the emission factor is for each natural
gas liquid (NGL) product ``g'' and to add the subscript ``g'' to the
term ``EF.''
    We are amending Equation NN-8 of subpart NN to correct the term for
``Annual CO2 mass emissions that would result from the
combustion or oxidation of fractionated NGLs received from other
fractionators'' from ``CO2j'' to ``CO2m''. We are
also amending Equation NN-8 to remove the summation signs that were
unnecessary from this equation for clarification purposes. We are also
amending the definition of the term CO2i to clarify that
this term includes NGLs delivered to customers or, on behalf of,
customers, recognizing that some customers may not receive the NGLs
directly.
    We are amending 40 CFR 98.406(a)(6) to correct two cross
references. The incorrect references referred the reader to 40 CFR
98.406(b)(1) and (b)(2), when they were supposed to refer to 40 CFR
98.406(a)(1) and (a)(2). Similarly, we are amending an incorrect
reference in 40 CFR 98.407(d) to refer the reader to 40 CFR
98.406(b)(7) instead of 40 CFR 98.406(b)(6).
    We are amending 40 CFR 98.406(a)(9) to correct the abbreviation of
NGL (from LNG) and to specify that reporting under that paragraph is
for each product type.
    We are amending 40 CFR 98.407(a) to remove the word ``daily''
because daily meter readings are not specifically required under this
subpart.
    Finally, we are updating the high heat values (HHVs) and default
CO2 emission factors in Tables NN-1 and NN-2 to subpart NN
to be consistent with the emission factors in Tables C-1 to subpart C
and MM-1 to subpart MM.
2. Summary of Comments and Responses
    There were no major comments received on the proposed amendments to
this section. A few comments seeking minor technical clarification or
correction were received on this subpart. Responses to these comments
can be found in Response to Comments: Technical Corrections, Clarifying
and Other Amendments document (see EPA-HQ-OAR-2010-0109).

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

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

B. Paperwork Reduction Act

    This action does not impose any new information collection burden.
These amendments do not make any substantive changes to the reporting
requirements in any of the subparts for which amendments are being
made. In many cases, the amendments to the reporting requirements
reduce the reporting burden by making the reporting requirements
conform more

closely to current industry practices. However, the Office of
Management and Budget (OMB) has previously approved the information
collection requirements contained in the regulations promulgated on
October 30, 2009, under 40 CFR Part 98 under the provisions of the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB
control number 2060-0629. Burden is defined at 5 CFR 1320.3(b). An
agency may not conduct or sponsor, and a person is not required to
respond to, a collection of information unless it displays a currently
valid OMB control number. The OMB control numbers for EPA's regulations
in 40 CFR are listed in 40 CFR part 9.
    Further information on EPA's assessment on the impact on burden can
be found in the Technical Corrections and Amendments Cost Memo (EPA-HQ-
OAR-2010-0109).

C. Regulatory Flexibility Act (RFA)

    The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
    For purposes of assessing the impacts of these amendments on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's regulations at 13 CFR 121.201;
(2) a small governmental jurisdiction that is a government of a city,
county, town, school district or special district with a population of
less than 50,000; and (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not
dominant in its field.
    After considering the economic impacts of these rule amendments on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The rule
amendments will not impose any new requirement on small entities that
are not currently required by Part 98 promulgated on October 30, 2009
(i.e., calculating and reporting annual GHG emissions).
    EPA took several steps to reduce the impact on small entities. For
example, EPA determined appropriate thresholds that reduced the number
of small businesses reporting. In addition, EPA did not require
facilities to install CEMS if they did not already have them.
Facilities without CEMS can calculate emissions using readily available
data or data that are less expensive to collect such as process data or
material consumption data. For some source categories, EPA developed
tiered methods that are simpler and less burdensome. Also, EPA required
annual instead of more frequent reporting. Finally, EPA continues to
conduct significant outreach on the mandatory GHG reporting rule and
maintains an ``open door'' policy for stakeholders to help inform EPA's
understanding of key issues for the industries.

D. Unfunded Mandates Reform Act (UMRA)

    This action contains no Federal mandates under the provisions of
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for State, local, or tribal governments or the private
sector. The action imposes no enforceable duty on any State, local or
tribal governments or the private sector. In addition, EPA determined
that the rule amendments contain no regulatory requirements that might
significantly or uniquely affect small governments because the
amendments will not impose any new requirements that are not currently
required by Part 98 promulgated on October 30, 2009 (i.e., calculating
and reporting annual GHG emissions), and the rule amendments will not
unfairly apply to small governments. Therefore, this action is not
subject to the requirements of CAA section 203 of the UMRA.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. However, for a more detailed
discussion about how these rule amendments will relate to existing
State programs, please see Section II of the proposal preamble for the
Mandatory GHG Reporting Rule (74 FR 16457-16461, April 10, 2009).
    These amendments apply directly to facilities that supply fuel that
when used emit greenhouse gases or facilities that directly emit
greenhouses gases. They do not apply to governmental entities unless
the government entity owns a facility that directly emits greenhouse
gases above threshold levels (such as a landfill), so relatively few
government facilities will be affected. This regulation also does not
limit the power of States or localities to collect GHG data and/or
regulate GHG emissions. Thus, Executive Order 13132 does not apply to
this action.
    Although section 6 of Executive Order 13132 does not apply to this
action, EPA did consult with State and local officials or
representatives of State and local governments in developing Part 98. A
summary of EPA's consultations with State and local governments is
provided in Section VIII.E of the preamble to Part 98 (74 FR 56260,
October 30, 2009).

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

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

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

    EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997)
as applying only to those regulatory actions that concern health or
safety risks, such that the analysis required under section 5-501 of
the executive order has the potential to influence the regulation. This
action is not subject to Executive Order 13045 because it does not
establish an environmental standard intended to mitigate health or
safety risks.

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

    This action is not subject to Executive Order 13211 (66 FR 28355,
May 22, 2001), because it is not a significant regulatory action under
Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs
EPA to

use voluntary consensus standards in its regulatory activities unless
to do so would be inconsistent with applicable law or otherwise
impractical. Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary
consensus standards bodies. NTTAA directs EPA to provide Congress,
through OMB, explanations when the Agency decides not to use available
and applicable voluntary consensus standards.
    This rulemaking involves the use of one new voluntary consensus
standard from ASTM. Specifically, EPA will allow facilities in the
glass industry to use ASTM D6349-09 Standard Test Method for
Determination of Major and Minor Elements in Coal, Coke, and Solid
Residues from Combustion of Coal and Coke by Inductively Coupled
Plasma--Atomic Emission Spectrometry in addition to the methods
incorporated by reference in Part 98. This additional voluntary
consensus standard will provide an alternative method that owners or
operators in the glass industry can use to monitor GHG emissions. No
new test methods were developed for this action.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    EPA has determined that Part 98 does not have disproportionately
high and adverse human health or environmental effects on minority or
low-income populations because it does not affect the level of
protection provided to human health or the environment because it is a
rule addressing information collection and reporting procedures.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA),
generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of the Congress and to the Comptroller
General of the United States. EPA will submit a report containing this
rule and other required information to the U.S. Senate, the U.S. House
of Representatives, and the Comptroller General of the U.S. prior to
publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on November 29, 2010.

List of Subjects

40 CFR Part 86

    Environmental protection, Administrative practice and procedure,
Air pollution control, Reporting and recordkeeping requirements, Motor
vehicle pollution.

40 CFR Part 98

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

    Dated: October 7, 2010.
Lisa P. Jackson,
Administrator.

0
For the reasons set out in the preamble, title 40, Chapter I, of the
Code of Federal Regulations is amended as follows:

PART 86--[AMENDED]

0
1. The authority citation for part 86 continues to read as follows:

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

0
2. Section 86.1844-01 is amended by adding paragraph (j) to read as
follows:

Sec.  86.1844-01  Information requirements: Application for
certification and submittal of information upon request.

* * * * *
    (j) For complete heavy-duty vehicles only, measure CO2,
N2O, and CH4 as described in this paragraph (j)
with each certification test on an emission data vehicle. Do not apply
deterioration factors to the results. Use the analytical equipment and
procedures specified in 40 CFR part 1065 as needed to measure
N2O and CH4. Report these values in your
application for certification. The requirements of this paragraph (j)
apply starting with model year 2011 for CO2 and 2012 for
CH4. The requirements of this paragraph (j) related to
N2O emissions apply for test groups that depend on
NOX after-treatment to meet emission standards starting with
model year 2013. Businesses that are defined as a small business by the
Small Business Administration size standards in 13 CFR 121.201 may omit
measurement of N2O and CH4; other manufacturers
may provide appropriate data and/or information and omit measurement of
N2O and CH4 as described in 40 CFR 1065.5. Use
the same measurement methods as for your other results to report a
single value for CO2, N2O, and CH4.
Round the final values as follows:
    (1) Round CO2 to the nearest 1 g/mi.
    (2) Round N2O to the nearest 0.001 g/mi.
    (3) Round CH4 to the nearest 0.001 g/mi.

PART 98--[AMENDED]

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

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

Subpart A--[Amended]

0
4. Section 98.6 is amended by:
0
a. Removing the definition of ``Argon-oxygen decarburization (AOD)
vessel.''
0
b. Adding a definition for ``Decarburization vessel.''
0
c. Revising the definitions of ``Carbonate-based mineral,''
``Carbonate-based mineral mass fraction,'' ``Carbonate-based raw
material,'' ``Crude oil,'' ``Gas collection system or landfill gas
collection system,'' ``Mscf,'' and ``Non-crude feedstocks.''
    The addition and revisions read as follows:

Sec.  98.6  Definitions.

* * * * *
    Carbonate-based mineral means any of the following minerals used in
the manufacture of glass: Calcium carbonate (CaCO3), calcium
magnesium carbonate (CaMg(CO3)2), sodium
carbonate (Na2CO3), barium carbonate
(BaCO3), potassium carbonate (K2CO3),
lithium carbonate (Li2CO3), and strontium
carbonate (SrCO3).
    Carbonate-based mineral mass fraction means the following: For
limestone, the mass fraction of calcium carbonate (CaCO3) in
the limestone; for dolomite, the mass fraction of calcium magnesium
carbonate (CaMg(CO3)2) in the dolomite; for soda
ash, the mass fraction of sodium carbonate
(Na2CO3) in the soda ash; for barium carbonate,
the mass fraction of barium carbonate (BaCO3) in the barium
carbonate; for potassium carbonate, the mass fraction of potassium
carbonate (K2CO3) in the potassium carbonate; for
lithium carbonate, the mass fraction of lithium carbonate
(Li2CO3); and for strontium

carbonate, the mass fraction of strontium carbonate (SrCO3).
    Carbonate-based raw material means any of the following materials
used in the manufacture of glass: Limestone, dolomite, soda ash, barium
carbonate, potassium carbonate, lithium carbonate, and strontium
carbonate.
* * * * *
    Crude oil means a mixture of hydrocarbons that exists in liquid
phase in natural underground reservoirs and remains liquid at
atmospheric pressure after passing through surface separating
facilities. (1) Depending upon the characteristics of the crude stream,
it may also include any of the following:
    (i) Small amounts of hydrocarbons that exist in gaseous phase in
natural underground reservoirs but are liquid at atmospheric conditions
(temperature and pressure) after being recovered from oil well (casing-
head) gas in lease separators and are subsequently commingled with the
crude stream without being separately measured. Lease condensate
recovered as a liquid from natural gas wells in lease or field
separation facilities and later mixed into the crude stream is also
included.
    (ii) Small amounts of non-hydrocarbons, such as sulfur and various
metals.
    (iii) Drip gases, and liquid hydrocarbons produced from tar sands,
oil sands, gilsonite, and oil shale.
    (iv) Petroleum products that are received or produced at a refinery
and subsequently injected into a crude supply or reservoir by the same
refinery owner or operator.
    (2) Liquids produced at natural gas processing plants are excluded.
Crude oil is refined to produce a wide array of petroleum products,
including heating oils; gasoline, diesel and jet fuels; lubricants;
asphalt; ethane, propane, and butane; and many other products used for
their energy or chemical content.
* * * * *
    Decarburization vessel means any vessel used to further refine
molten steel with the primary intent of reducing the carbon content of
the steel, including but not limited to vessels used for argon-oxygen
decarburization and vacuum oxygen decarburization.
* * * * *
    Gas collection system or landfill gas collection system means a
system of pipes used to collect landfill gas from different locations
in the landfill by means of a fan or similar mechanical draft equipment
to a single location for treatment (thermal destruction) or use.
Landfill gas collection systems may also include knock-out or separator
drums and/or a compressor. A single landfill may have multiple gas
collection systems. Landfill gas collection systems do not include
``passive'' systems, whereby landfill gas flows naturally to the
surface of the landfill where an opening or pipe (vent) is installed to
allow for natural gas flow.
* * * * *
    Mscf means thousand standard cubic feet.
* * * * *
    Non-crude feedstocks means any petroleum product or natural gas
liquid that enters the refinery to be further refined or otherwise used
on site.
* * * * *
    5. Section 98.7 is amended by removing and reserving paragraph (a),
and adding paragraph (e)(45).

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

* * * * *
    (e) * * *
    (45) ASTM D6349-09 Standard Test Method for Determination of Major
and Minor Elements in Coal, Coke, and Solid Residues from Combustion of
Coal and Coke by Inductively Coupled Plasma--Atomic Emission
Spectrometry, IBR approved for Sec.  98.144(b).
* * * * *

Subpart E--[Amended]

0
6. Section 98.53 is revised to read as follows:

Sec.  98.53  Calculating GHG emissions.

    (a) You must determine annual N2O emissions from adipic
acid production according to paragraphs (a)(1) or (2) of this section.
    (1) Use a site-specific emission factor and production data
according to paragraphs (b) through (i) of this section.
    (2) Request Administrator approval for an alternative method of
determining N2O emissions according to paragraphs (a)(2)(i)
and (ii) of this section.
    (i) You must submit the request within 45 days following
promulgation of this subpart or within the first 30 days of each
subsequent reporting year.
    (ii) If the Administrator does not approve your requested
alternative method within 150 days of the end of the reporting year,
you must determine the N2O emissions for the current
reporting period using the procedures specified in paragraphs (b)
through (h) of this section.
    (b) You must conduct an annual performance test according to
paragraphs (b)(1) through (3) of this section.
    (1) You must conduct the test on the vent stream from the nitric
acid oxidation step of the process, referred to as the test point,
according to the methods specified in Sec.  98.54(b) through (f). If
multiple adipic acid production units exhaust to a common abatement
technology and/or emission point, you must sample each process in the
ducts before the emissions are combined, sample each process when only
one process is operating, or sample the combined emissions when
multiple processes are operating and base the site-specific emission
factor on the combined production rate of the multiple adipic acid
production units.
    (2) You must conduct the performance test under normal process
operating conditions.
    (3) You must measure the adipic acid production rate during the
test and calculate the production rate for the test period in metric
tons per hour.
    (c) Using the results of the performance test in paragraph (b) of
this section, you must calculate an emission factor for each adipic
acid unit according to Equation E-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.018

Where:

EFN2O,z = Average facility-specific
N2O emission factor for each adipic acid production unit
``z'' (lb N2O/ton adipic acid produced).
CN2O = N2O concentration per test
run during the performance test (ppm N2O).
1.14 x 10-7 = Conversion factor (lb/dscf-ppm
N2O).

Q = Volumetric flow rate of effluent gas per test run during the
performance test (dscf/hr).
P = Production rate per test run during the performance test (tons
adipic acid produced/hr).
n = Number of test runs.

    (d) If any N2O abatement technology ``N'' is located
after your test point, you must determine the destruction efficiency
according to paragraphs (d)(1), (2), or (3) of this section.
    (1) Use the manufacturer's specified destruction efficiency.
    (2) Estimate the destruction efficiency through process knowledge.
Examples of information that could constitute process knowledge include
calculations based on material balances, process stoichiometry, or
previous test results provided the results are still relevant to the
current vent stream conditions. You must document how process knowledge
was used to determine the destruction efficiency.
    (3) Calculate the destruction efficiency by conducting an
additional performance test on the vent stream following the
N2O abatement technology.
    (e) If any N2O abatement technology ``N'' is located
after your test point, you must determine the annual amount of adipic
acid produced while N2O abatement technology ``N'' is
operating according to Sec.  98.54(f). Then you must calculate the
abatement factor for N2O abatement technology ``N''
according to Equation E-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.019

Where:

AFN = Abatement utilization factor of N2O
abatement technology ``N'' (fraction of annual production that
abatement technology is operating).
Pz,N = Annual adipic acid production during which
N2O abatement technology ``N'' was used on unit ``z''
(ton adipic acid produced).
Pz = Total annual adipic acid production from unit ``z''
(ton acid produced).

    (f) You must determine the annual amount of adipic acid produced
according to Sec.  98.54(f).
    (g) You must calculate N2O emissions according to
paragraph (g)(1), (2), (3), or (4) of this section for each adipic acid
production unit.
    (1) If one N2O abatement technology ``N'' is located
after your test point, you must use the emissions factor (determined in
Equation E-1 of this section), the destruction efficiency (determined
in paragraph (d) of this section), the annual adipic acid production
(determined in paragraph (f) of this section), and the abatement
utilization factor (determined in paragraph (e) of this section),
according to Equation E-3a of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.020

Where:

Ea,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to this Equation E-3a (metric
tons).
EFN2Oz = N2O emissions factor for
unit ``z'' (lb N2O/ton adipic acid produced).
Pz = Annual adipic acid produced from unit ``z'' (tons).
DF = Destruction efficiency of N2O abatement technology
``N'' (percent of N2O removed from vent stream).
AF = Abatement utilization factor of N2O abatement
technology ``N'' (percent of time that the abatement technology is
operating).
2205 = Conversion factor (lb/metric ton).

    (2) If multiple N2O abatement technologies are located
in series after your test point, you must use the emissions factor
(determined in Equation E-1 of this section), the destruction
efficiency (determined in paragraph (d) of this section), the annual
adipic acid production (determined in paragraph (f) of this section),
and the abatement utilization factor (determined in paragraph (e) of
this section), according to Equation E-3b of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.021

Where:

Eb,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to this Equation E-3b (metric
tons).
EFN2O,z = N2O emissions factor for
unit ``z'' (lb N2O/ton adipic acid produced).
Pz = Annual adipic acid produced from unit ``z'' (tons).
DF1 = Destruction efficiency of N2O abatement
technology 1 (percent of N2O removed from vent stream).
AF1 = Abatement utilization factor of N2O
abatement technology 1 (percent of time that abatement technology 1
is operating).
DF2 = Destruction efficiency of N2O abatement
technology 2 (percent of N2O removed from vent stream).
AF2 = Abatement utilization factor of N2O
abatement technology 2 (percent of time that abatement technology 2
is operating).
DFN = Destruction efficiency of N2O abatement
technology N (percent of N2O removed from vent stream).
AFN = Abatement utilization factor of N2O
abatement technology N (percent of time that abatement technology N
is operating).
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies.

    (3) If multiple N2O abatement technologies are located
in parallel after your test point, you must use the emissions factor
(determined in Equation E-1 of this section), the destruction
efficiency (determined in paragraph (d) of this section), the annual
adipic acid production (determined in paragraph (f) of this section),
and the abatement utilization factor (determined in paragraph (e) of
this section), according to Equation E-3c of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.022

Where:

Ec,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to this Equation E-3c (metric
tons).
EFN2O,z = N2O emissions factor for
unit ``z'' (lb N2O/ton adipic acid produced).
Pz = Annual adipic acid produced from unit ``z'' (tons).
DFN = Destruction efficiency of N2O abatement
technology ``N'' (percent of N2O removed from vent
stream).
AFN = Abatement utilization factor of N2O
abatement technology ``N'' (percent of time that the abatement
technology is operating).
FCN = Fraction control factor of N2O abatement
technology ``N'' (percent of total emissions from unit ``z'' that
are sent to abatement technology ``N'').
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies with a
fraction control factor.

    (4) If no N2O abatement technologies are located after
your test point, you must use the emissions factor (determined using
Equation E-1 of this section) and the annual adipic acid production
(determined in paragraph (f) of this section) according to Equation E-
3d of this section for each adipic acid production unit.
[GRAPHIC] [TIFF OMITTED] TR28OC10.023

Where:

Ed,z = Annual N2O mass emissions from adipic
acid production for unit ``z'' according to this Equation E-3d
(metric tons).
EFN2O = N2O emissions factor for
unit ``z'' (lb N2O/ton adipic acid produced).
PZ = Annual adipic acid produced from unit ``z'' (tons).
2205 = Conversion factor (lb/metric ton).

    (h) You must determine the emissions for the facility by summing
the unit level emissions according to Equation E-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.024

Where:

Ea,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to Equation E-3a of this
section (metric tons).
Eb,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to Equation E-3b of this
section (metric tons).
Ec,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to Equation E-3c of this
section (metric tons).
Ed,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to Equation E-3d of this
section (metric tons).
M = Total number of adipic acid production units.

    (i) You must determine the amount of process N2O
emissions that is sold or transferred off site (if applicable). You can
determine the amount using existing process flow meters and
N2O analyzers.

0
7. Section 98.54 is amended by:
0
a. Revising paragraph (a) introductory text.
0
b. Adding second and third sentences to the end of paragraph (a)(1).
0
c. Revising paragraph (a)(3).
0
d. Revising paragraph (c) introductory text.
0
e. Revising the first sentence of paragraph (d) introductory text.
0
f. Revising paragraphs (e) and (f).
    The revisions and additions read as follows:

Sec.  98.54  Monitoring and QA/QC requirements.

    (a) You must conduct a new performance test and calculate a new
emissions factor for each adipic acid production unit according to the
frequency specified in paragraphs (a)(1) through (3) of this section.
    (1) * * * The test must be conducted at a point during production
that is representative of the average emissions rate from your process.
You must document the methods used to determine the representative
point.
* * * * *
    (3) If you requested Administrator approval for an alternative
method of determining N2O emissions under Sec.  98.53(a)(2),
you must conduct the performance test if your request has not been
approved by the Administrator within 150 days of the end of the
reporting year in which it was submitted.
* * * * *
    (c) You must determine the adipic acid production rate during the
performance test according to paragraph (c)(1) or (c)(2) of this
section.
* * * * *
    (d) You must determine the volumetric flow rate during the
performance test in conjunction with the applicable EPA methods in 40
CFR part 60, appendices A-1 through A-4. * * *
* * * * *
    (e) You must determine the monthly amount of adipic acid produced.
You must also determine the monthly amount of adipic acid produced
during which N2O abatement technology, located after the
test point, is operating. These monthly amounts are determined
according to the methods in paragraphs (c)(1) or (2) of this section.
    (f) You must determine the annual amount of adipic acid produced.
You must also determine the annual amount of adipic acid produced
during which N2O abatement technology located after the test
point is operating. These are determined by summing the respective
monthly adipic acid production quantities determined in paragraph (e)
of this section.

0
8. Section 98.56 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (c).
0
c. Revising paragraph (j) introductory text.
0
d. Revising paragraph (j)(1).
0
e. Revising paragraph (k) introductory text.
0
f. Adding paragraph (l).
    The revisions and addition read as follows:

Sec.  98.56  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (l) of this section at the facility level.
* * * * *
    (c) Annual adipic acid production during which N2O
abatement technology (located after the test point) is operating
(tons).
* * * * *
    (j) If you conducted a performance test and calculated a site-
specific emissions factor according to Sec.  98.53(a)(1), each annual
report must also contain the information specified in paragraphs (j)(1)
through (7) of this section for each adipic acid production unit.
    (1) Emission factor (lb N2O/ton adipic acid).
* * * * *
    (k) If you requested Administrator approval for an alternative
method of determining N2O emissions under Sec.  98.53(a)(2),
each annual report must also contain the information specified in
paragraphs (k)(1) through (4) of this

section for each adipic acid production facility.
* * * * *
    (l) Fraction control factor for each abatement technology (percent
of total emissions from the production unit that are sent to the
abatement technology) if equation E-3c is used.

0
9. Section 98.57 is amended by revising paragraphs (c) and (f) to read
as follows:

Sec.  98.57  Records that must be retained.

* * * * *
    (c) Number of facility and unit operating hours in calendar year.
* * * * *
    (f) Performance test reports.
* * * * *

Subpart H--[Amended]

0
10. Section 98.83 is amended by revising the introductory text of
paragraph (d)(3); and by revising the definitions of ``rm'', ``TOCrm'',
and ``M'' in Equation H-5 of paragraph (d)(3) to read as follows:

Sec.  98.83  Calculating GHG emissions.

* * * * *
    (d) * * *
    (3) CO2 emissions from raw materials. Calculate
CO2 emissions from raw materials using Equation H-5 of this
section:
* * * * *

rm = The amount of raw material i consumed annually, tons/yr (dry
basis) or the amount of raw kiln feed consumed annually, tons/yr
(dry basis).

* * * * *
TOCrm = Organic carbon content of raw material i or organic carbon
content of combined raw kiln feed (dry basis), as determined in
Sec.  98.84(c) or using a default factor of 0.2 percent of total raw
material weight.
M = Number of raw materials or 1 if calculating emissions based on
combined raw kiln feed.

* * * * *

0
11. Section 98.84 is amended by revising paragraphs (b) through (f) to
read as follows:

Sec.  98.84  Monitoring and QA/QC requirements.

* * * * *
    (b) You must determine the weight fraction of total CaO and total
MgO in clinker from each kiln using ASTM C114-09 Standard Test Methods
for Chemical Analysis of Hydraulic Cement (incorporated by reference,
see Sec.  98.7). The monitoring must be conducted monthly for each kiln
from a monthly clinker sample drawn from bulk clinker storage if
storage is dedicated to the specific kiln, or from a monthly arithmetic
average of daily clinker samples drawn from the clinker conveying
systems exiting each kiln.
    (c) The total organic carbon content (dry basis) of raw materials
must be determined annually using ASTM C114-09 Standard Test Methods
for Chemical Analysis of Hydraulic Cement (incorporated by reference,
see Sec.  98.7) or a similar industry standard practice or method
approved for total organic carbon determination in raw mineral
materials. The analysis must be conducted either on sample material
drawn from bulk raw kiln feed storage or on sample material drawn from
bulk raw material storage for each category of raw material (i.e.,
limestone, sand, shale, iron oxide, and alumina). Facilities that opt
to use the default total organic carbon factor provided in Sec.
98.83(d)(3), are not required to monitor for TOC.
    (d) The quantity of clinker produced monthly by each kiln must be
determined by direct weight measurement of clinker using the same plant
techniques used for accounting purposes, such as reconciling weigh
hopper or belt weigh feeder measurements against inventory
measurements. As an alternative, facilities may also determine clinker
production by direct measurement of raw kiln feed and application of a
kiln-specific feed-to-clinker factor. Facilities that opt to use a
feed-to-clinker factor must verify the accuracy of this factor on a
monthly basis.
    (e) The quantity of CKD not recycled to the kiln generated by each
kiln must be determined quarterly using the same plant techniques used
for accounting purposes, such as direct weight measurement using weigh
hoppers, truck weigh scales, or belt weigh feeders.
    (f) The annual quantity of raw kiln feed or annual quantity of each
category of raw materials consumed by the facility (e.g., limestone,
sand, shale, iron oxide, and alumina) must be determined monthly by
direct weight measurement using the same plant instruments used for
accounting purposes, such as weigh hoppers, truck weigh scales, or belt
weigh feeders.
* * * * *

0
12. Section 98.86 is amended by:
0
a. Revising paragraph (b)(3).
0
b. Revising paragraph (b)(4).
0
c. Revising paragraph (b)(12).
0
d. Revising paragraph (b)(13).
0
e. Adding paragraph (b)(15).
    The revisions and addition read as follows:

Sec.  98.86  Data reporting requirements.

* * * * *
    (b) * * *
    (3) Annual cement production at the facility.
    (4) Number of kilns and number of operating kilns.
* * * * *
    (12) Annual organic carbon content of raw kiln feed or annual
organic carbon content of each raw material (wt-fraction, dry basis).
    (13) Annual consumption of raw kiln feed or annual consumption of
each raw material (dry basis).
* * * * *
    (15) Method used to determine the monthly clinker production from
each kiln reported under (b)(2) of this section, including monthly
kiln-specific clinker factors, if used.
    13. Section 98.87 is revised to read as follows:

Sec.  98.87  Records that must be retained.

    (a) If a CEMS is used to measure CO2 emissions, then in
addition to the records required by Sec.  98.3(g), you must retain
under this subpart the records required for the Tier 4 Calculation
Methodology in Sec.  98.37.
    (b) If a CEMS is not used to measure CO2 emissions, then
in addition to the records required by Sec.  98.3(g), you must retain
the records specified in this paragraph (b) for each portland cement
manufacturing facility.
    (1) Documentation of monthly calculated kiln-specific clinker
CO2 emission factor.
    (2) Documentation of quarterly calculated kiln-specific CKD
CO2 emission factor.
    (3) Measurements, records and calculations used to determine
reported parameters.

Subpart K--[Amended]

0
14. Section 98.112 is amended by revising paragraph (a) to read as
follows:

Sec.  98.112  GHGs to report.

* * * * *
    (a) Process CO2 emissions from each electric arc furnace
(EAF) used for the production of any ferroalloy listed in Sec.  98.110,
and process CH4 emissions from each EAF that is used for the
production of any ferroalloy listed in Table K-1 to subpart K.
* * * * *

0
15. Section 98.113 is amended by revising the introductory text to read
as follows:

Sec.  98.113  Calculating GHG emissions.

    You must calculate and report the annual process CO2
emissions from each

EAF not subject to paragraph (c) of this section using the procedures
in either paragraph (a) or (b) of this section. For each EAF also
subject to annual process CH4 emissions reporting, you must
also calculate and report the annual process CH4 emissions
from the EAF using the procedures in paragraph (d) of this section.
* * * * *

0
16. Section 98.116 is amended by:
0
a. Revising paragraph (b).
0
b. Revising paragraph (c).
0
c. Revising paragraph (d) introductory text.
0
d. Revising paragraph (d)(1).
0
e. Revising paragraph (e)(1).
    The revisions read as follows:

Sec.  98.116  Data reporting requirements.

* * * * *
    (b) Annual production for each ferroalloy product identified in
Sec.  98.110, from each EAF (tons).
    (c) Total number of EAFs at facility used for production of
ferroalloy products.
    (d) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required by
Sec.  98.36 for the Tier 4 Calculation Methodology and the following
information specified in paragraphs (d)(1) through (d)(3) of this
section.
    (1) Annual process CO2 emissions (in metric tons) from
each EAF used for the production of any ferroalloy product identified
in Sec.  98.110.
* * * * *
    (e) * * *
    (1) Annual process CO2 emissions (in metric tons) from
each EAF used for the production of any ferroalloy identified in Sec.
98.110 (metric tons).
* * * * *

Subpart N--[Amended]

0
17. Section 98.144 is amended by revising paragraph (b) to read as
follows:

Sec.  98.144  Monitoring and QA/QC requirements.

* * * * *
    (b) You must measure carbonate-based mineral mass fractions at
least annually to verify the mass fraction data provided by the
supplier of the raw material; such measurements shall be based on
sampling and chemical analysis using ASTM D3682-01 (Reapproved 2006)
Standard Test Method for Major and Minor Elements in Combustion
Residues from Coal Utilization Processes (incorporated by reference,
see Sec.  98.7) or ASTM D6349-09 Standard Test Method for Determination
of Major and Minor Elements in Coal, Coke, and Solid Residues from
Combustion of Coal and Coke by Inductively Coupled Plasma--Atomic
Emission Spectrometry (incorporated by reference, see Sec.  98.7).
* * * * *

0
18. Section 98.146 is amended by:
0
a. Revising paragraph (a) introductory text.
0
b. Revising paragraph (a)(2).
0
c. Revising paragraph (b)(7).
0
d. Revising paragraph (b)(9).
    The revisions read as follows:

Sec.  98.146  Data reporting requirements.

* * * * *
    (a) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required under
Sec.  98.36 for the Tier 4 Calculation Methodology and the following
information specified in paragraphs (a)(1) and (2) of this section:
* * * * *
    (2) Annual quantity of glass produced by each glass melting furnace
and by all furnaces combined (tons).
    (b) * * *
    (7) Method used to determine fraction of calcination.
* * * * *
    (9) The number of times in the reporting year that missing data
procedures were followed to measure monthly quantities of carbonate-
based raw materials or mass fraction of the carbonate-based minerals
for any continuous glass melting furnace (months).

0
19. In the Table to Subpart N of Part 98, Table N-1 to subpart N is
amended by adding entries for ``Barium carbonate,'' ``Potassium
carbonate,'' ``Lithium carbonate,'' and ``Strontium carbonate'' to the
end of the table to read as follows:

Table to Subpart N of Part 98

  Table N-1 to Subpart N--CO2 Emission Factors for Carbonate-Based Raw
                                Materials
------------------------------------------------------------------------
                                                           CO2 emission
          Carbonate-based raw material--mineral             factor \a\
------------------------------------------------------------------------

                              * * * * * * *
Barium carbonate--BaCO3.................................           0.223
Potassium carbonate--K2CO3..............................           0.318
Lithium carbonate (Li2CO3)..............................           0.596
Strontium carbonate (SrCO3).............................           0.298
------------------------------------------------------------------------
\a\ Emission factors in units of metric tons of CO2 emitted per metric
  ton of carbonate-based raw material charged to the furnace.

Subpart O--[Amended]

0
20. Section 98.154 is amended by:
0
a. Revising the first and second sentences of paragraph (k).
0
b. Revising the second sentence of paragraph (l) introductory text.
0
c. Revising paragraph (o).
    The revisions read as follows:

Sec.  98.154  Monitoring and QA/QC requirements.

* * * * *
    (k) The mass of HFC-23 emitted from process vents shall be
estimated at least monthly by incorporating the results of the most
recent emissions test into Equation O-7 of this subpart. HCFC-22
production facilities that use a destruction device connected to the
HCFC-22 production equipment shall conduct emissions tests at process
vents at least once every five years or after significant changes to
the process. * * *
    (l) * * * HFC-23 destruction facilities shall conduct annual
measurements of HFC-23 concentrations at the outlet of the destruction
device in accordance with EPA Method 18 at 40 CFR part 60, appendix A-
6. * * *
* * * * *
    (o) In their estimates of the mass of HFC-23 destroyed, HFC-23
destruction facilities shall account for any temporary reductions in
the destruction efficiency that result from any startups, shutdowns, or
malfunctions of the destruction device, including departures from the
operating conditions defined in State or local permitting requirements

and/or destruction device manufacturer specifications.
* * * * *

0
21. Section 98.156 is amended by:
0
a. Revising paragraph (b)(1).
0
b. Revising paragraph (b)(3).
0
c. Revising paragraph (c).
0
d. Revising paragraph (d).
0
e. Revising paragraph (e) introductory text.
    The revisions read as follows:

Sec.  98.156  Data reporting requirements.

* * * * *
    (b) * * *
    (1) Annual mass of HFC-23 fed into the destruction device.
* * * * *
    (3) Annual mass of HFC-23 emitted from the destruction device.
    (c) Each HFC-23 destruction facility shall report the concentration
(mass fraction) of HFC-23 measured at the outlet of the destruction
device during the facility's annual HFC-23 concentration measurements
at the outlet of the device.
    (d) If the HFC-23 concentration measured pursuant to Sec.
98.154(l) is greater than that measured during the performance test
that is the basis for the destruction efficiency (DE), the facility
shall report the revised destruction efficiency calculated under Sec.
98.154(l) and the values used to calculate it, specifying whether Sec.
98.154(l)(1) or Sec.  98.154(l)(2) has been used for the calculation.
Specifically, the facility shall report the following:
    (1) Flow rate of HFC-23 being fed into the destruction device in
kg/hr.
    (2) Concentration (mass fraction) of HFC-23 at the outlet of the
destruction device.
    (3) Flow rate at the outlet of the destruction device in kg/hr.
    (4) Emission rate (in kg/hr) calculated from paragraphs (d)(2) and
(d)(3) of this section.
    (5) Destruction efficiency (DE) calculated from paragraphs (d)(1)
and (d)(4) of this section.
    (e) By March 31, 2011 or within 60 days of commencing HFC-23
destruction, HFC-23 destruction facilities shall submit a one-time
report including the following information for each destruction
process:
* * * * *

0
22. Section 98.157 is amended by revising paragraph (b)(1) to read as
follows:

Sec.  98.157  Records that must be retained.

* * * * *
    (b) * * *
    (1) Records documenting their one-time and annual reports in Sec.
98.156(b) through (e).
* * * * *

Subpart P--[Amended]

0
23. Section 98.160 is amended by revising paragraph (c) to read as
follows:

Sec.  98.160  Definition of the source category.

* * * * *
    (c) This source category includes merchant hydrogen production
facilities located within another facility if they are not owned by, or
under the direct control of, the other facility's owner and operator.

0
24. Section 98.162 is amended by revising paragraph (a) and removing
and reserving paragraph (b).
    The revision reads as follows:

Sec.  98.162  GHGs to report.

* * * * *
    (a) CO2 emissions from each hydrogen production process
unit.
* * * * *

0
25. Section 98.163 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (a).
0
c. Revising paragraph (b) introductory text.
0
d. In paragraph (b)(1), revising the introductory text and revising the
definition of ``CO2'' in Equation P-1.
0
e. Revising paragraphs (b)(2) introductory text and (b)(3) introductory
text.
    The revisions read as follows:

Sec.  98.163  Calculating GHG emissions.

    You must calculate and report the annual CO2 emissions
from each hydrogen production process unit using the procedures
specified in either paragraph (a) or (b) of this section.
    (a) Continuous Emissions Monitoring Systems (CEMS). Calculate and
report under this subpart the CO2 emissions by operating and
maintaining CEMS according to the Tier 4 Calculation Methodology
specified in Sec.  98.33(a)(4) and all associated requirements for Tier
4 in subpart C of this part (General Stationary Fuel Combustion
Sources).
    (b) Fuel and feedstock material balance approach. Calculate and
report CO2 emissions as the sum of the annual emissions
associated with each fuel and feedstock used for hydrogen production by
following paragraphs (b)(1) through (b)(3) of this section.
    (1) Gaseous fuel and feedstock. You must calculate the annual
CO2 emissions from each gaseous fuel and feedstock according
to Equation P-1 of this section:
* * * * *

CO2 = Annual CO2 emissions arising from fuel
and feedstock consumption (metric tons/yr).

* * * * *
    (2) Liquid fuel and feedstock. You must calculate the annual
CO2 emissions from each liquid fuel and feedstock according
to Equation P-2 of this section:
* * * * *
    (3) Solid fuel and feedstock. You must calculate the annual
CO2 emissions from each solid fuel and feedstock according
to Equation P-3 of this section:
* * * * *

0
26. Section 98.166 is amended by revising the introductory text and
paragraphs (a)(1), (b)(1), and (c) to read as follows:

Sec.  98.166  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
or (b) of this section, as appropriate, and paragraphs (c) and (d) of
this section:
    (a) * * *
    (1) Unit identification number and annual CO2 emissions.
* * * * *
    (b) * * *
    (1) Unit identification number and annual CO2 emissions.
* * * * *
    (c) Quantity of CO2 collected and transferred off site
in either gas, liquid, or solid forms, following the requirements of
subpart PP of this part.
* * * * *

Subpart Q--[Amended]

0
27. Section 98.172 is amended by revising paragraphs (b) and (c) to
read as follows:

Sec.  98.172  GHGs to report.

* * * * *
    (b) You must report CO2 emissions from flares that burn
blast furnace gas or coke oven gas according to the procedures in Sec.
98.253(b)(1) of subpart Y (Petroleum Refineries) of this part. When
using the alternatives set forth in Sec.  98.253(b)(1)(ii)(B) and Sec.
98.253(b)(1)(iii)(C), you must use the default CO2 emission
factors for coke oven gas and blast furnace gas from Table C-1 to
subpart C in Equations Y-2 and Y-3 of subpart Y. You must report
CH4 and N2O emissions from flares according to
the requirements in Sec.  98.33(c)(2) using the emission factors for
coke oven gas and blast furnace gas in Table C-2 to subpart C of this
part.
    (c) You must report process CO2 emissions from each
taconite indurating

furnace; basic oxygen furnace; non-recovery coke oven battery
combustion stack; coke pushing process; sinter process; EAF;
decarburization vessel; and direct reduction furnace by following the
procedures in this subpart.

0
28. Section 98.173 is amended by:
0
a. Revising the first sentence of the introductory text.
0
b. In paragraph (b)(1)(vi), revising the introductory text and the
definition of ``CO2'' in Equation Q-6 of subpart Q.
0
c. Revising the first sentence of paragraph (d).
    The revisions read as follows:

Sec.  98.173  Calculating GHG emissions.

    You must calculate and report the annual process CO2
emissions from each taconite indurating furnace, basic oxygen furnace,
non-recovery coke oven battery, sinter process, EAF, decarburization
vessel, and direct reduction furnace using the procedures in either
paragraph (a) or (b) of this section. * * *
* * * * *
    (b) * * *
    (1) * * *
    (vi) For decarburization vessels, estimate CO2 emissions
using Equation Q-6 of this section.
* * * * *

CO2 = Annual CO2 mass emissions from the
decarburization vessel (metric tons).

* * * * *
    (d) If GHG emissions from a taconite indurating furnace, basic
oxygen furnace, non-recovery coke oven battery, sinter process, EAF,
decarburization vessel, or direct reduction furnace are vented through
the same stack as any combustion unit or process equipment that reports
CO2 emissions using a CEMS that complies with the Tier 4
Calculation Methodology in subpart C of this part (General Stationary
Fuel Combustion Sources), then the calculation methodology in paragraph
(b) of this section shall not be used to calculate process emissions. *
* *

0
29. Section 98.174 is amended by revising the first sentence of
paragraph (c)(2) and revising paragraph (c)(7) to read as follows:

Sec.  98.174  Monitoring and QA/QC requirements.

* * * * *
    (c) * * *
    (2) For the furnace exhaust from basic oxygen furnaces, EAFs,
decarburization vessels, and direct reduction furnaces, sample the
furnace exhaust for at least three complete production cycles that
start when the furnace is being charged and end after steel or iron and
slag have been tapped. * * *
* * * * *
    (7) If your EAF and decarburization vessel exhaust to a common
emission control device and stack, you must sample each process in the
ducts before the emissions are combined, sample each process when only
one process is operating, or sample the combined emissions when both
processes are operating and base the site-specific emission factor on
the steel production rate of the EAF.
* * * * *

0
30. Section 98.175 is amended by revising the introductory text to read
as follows:

Sec.  98.175  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG
emissions calculations in Sec.  98.173 is required. Therefore, whenever
a quality-assured value of a required parameter is unavailable, a
substitute data value for the missing parameter shall be used in the
calculations as specified in the paragraphs (a) and (b) of this
section. You must follow the missing data procedures in Sec.  98.255(b)
of subpart Y (Petroleum Refineries) of this part for flares burning
coke oven gas or blast furnace gas. You must document and keep records
of the procedures used for all such estimates.
* * * * *

0
31. Section 98.176 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (c).
0
c. Revising paragraph (e)(3).
0
d. Adding paragraphs (g) and (h).
    The revisions and additions read as follows:

Sec.  98.176  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information required in paragraphs (a)
through (h) of this section for each coke pushing operation; taconite
indurating furnace; basic oxygen furnace; non-recovery coke oven
battery; sinter process; EAF; decarburization vessel; direct reduction
furnace; and flare burning coke oven gas or blast furnace gas. For
reporting year 2010, the information required in paragraphs (a) through
(h) of this section is not required for decarburization vessels that
are not argon-oxygen decarburization vessels. For reporting year 2011
and each subsequent reporting year, the information in paragraphs (a)
through (h) of this section must be reported for all decarburization
vessels.
* * * * *
    (c) If a CEMS is used to measure CO2 emissions, then you
must report the relevant information required under Sec.  98.36 for the
Tier 4 Calculation Methodology.
* * * * *
    (e) * * *
    (3) The annual volume of each type of gaseous fuel (reported
separately for each type in standard cubic feet), the annual volume of
each type of liquid fuel (reported separately for each type in
gallons), and the annual mass (in metric tons) of each other process
inputs and outputs used to determine CO2 emissions.
* * * * *
    (g) The annual amount of coal charged to the coke ovens (in metric
tons).
    (h) For flares burning coke oven gas or blast furnace gas, the
information specified in Sec.  98.256(e) of subpart Y (Petroleum
Refineries) of this part.

0
32. Section 98.177 is amended by revising paragraph (d) to read as
follows:

Sec.  98.177  Records that must be retained.

* * * * *
    (d) Annual operating hours for each taconite indurating furnace,
basic oxygen furnace, non-recovery coke oven battery, sinter process,
electric arc furnace, decarburization vessel, and direct reduction
furnace.
* * * * *

Subpart S--[Amended]

0
33. Section 98.190 is amended by revising paragraph (a) to read as
follows:

Sec.  98.190  Definition of the source category.

    (a) Lime manufacturing plants (LMPs) engage in the manufacture of a
lime product (e.g., calcium oxide, high-calcium quicklime, calcium
hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or
other lime products) by calcination of limestone, dolomite, shells or
other calcareous substances as defined in 40 CFR 63.7081(a)(1).
* * * * *

0
34. Section 98.193 is amended by:
0
a. In paragraph (b)(2)(i), revising the second sentence of the
introductory text and the definition of ``2000/2205'' in Equation S-1.
0
b. In paragraph (b)(2)(ii), revising the introductory text and the
definitions of ``EFLKD,i,n'', ``CaOLKD,i,n'',
``MgOLKD,i,n'', and ``2000/2205'' in Equation S-2.
0
c. In paragraph (b)(2)(iii), revising the introductory text and the
definitions of

``Ewaste,i'', ``CaOwaste,i'',
``MgOwaste,i'', ``Mwaste,i'', and ``2000/2205''
in Equation S-3.
0
d. In Paragraph (b)(2)(iv), revising the definitions of
``EFLIME,i,n'', ``MLIME,i,n'',
``EFLKD,i,n'', ``MLKD,i,n'',
``Ewaste,i'', ``t'', ``b'', and ``z'' in Equation S-4.
    The revisions read as follows:

Sec.  98.193  Calculating GHG emissions.

* * * * *
    (b) * * *
    (2) * * *
    (i) * * * Calcium oxide and magnesium oxide content must be
analyzed monthly for each lime product type that is produced:
* * * * *

2000/2205 = Conversion factor for tons to metric tons.

    (ii) You must calculate a monthly emission factor for each type of
calcined byproduct/waste sold (including lime kiln dust) using Equation
S-2 of this section:
* * * * *
EFLKD,i,n = Emission factor for calcined lime byproduct/
waste type i sold, for month n (metric tons CO2/ton lime
byproduct).

* * * * *

CaOLKD,i,n = Calcium oxide content for calcined lime
byproduct/waste type i sold, for month n (metric tons CaO/metric ton
lime).
MgOLKD,i,n = Magnesium oxide content for calcined lime
byproduct/waste type i sold, for month n (metric tons MgO/metric ton
lime).
2000/2205 = Conversion factor for tons to metric tons.

    (iii) You must calculate the annual CO2 emissions from
each type of calcined byproduct/waste that is not sold (including lime
kiln dust and scrubber sludge) using Equation S-3 of this section:
* * * * *

Ewaste,i = Annual CO2 emissions for calcined
lime byproduct/waste type i that is not sold (metric tons
CO2).

* * * * *

CaOwaste,i = Calcium oxide content for calcined lime
byproduct/waste type i that is not sold (metric tons CaO/metric ton
lime).
MgOwaste,i = Magnesium oxide content for calcined lime
byproduct/waste type i that is not sold (metric tons MgO/metric ton
lime).
Mwaste,i = Annual weight or mass of calcined byproducts/
wastes for lime type i that is not sold (tons).
2000/2205 = Conversion factor for tons to metric tons.

    (iv) * * *

EFLIME,i,n = Emission factor for lime type i produced, in
calendar month n (metric tons CO2/ton lime) from Equation
S-1 of this section.
MLIME,i,n = Weight or mass of lime type i produced in
calendar month n (tons).
EFLKD,i,n = Emission factor of calcined byproducts/wastes
sold for lime type i in calendar month n, (metric tons
CO2/ton byproduct/waste) from Equation S-2 of this
section.
MLKD,i,n = Monthly weight or mass of calcined byproducts/
waste sold (such as lime kiln dust, LKD) for lime type i in calendar
month n (tons).
Ewaste,i = Annual CO2 emissions for calcined
lime byproduct/waste type i that is not sold (metric tons
CO2) from Equation S-3 of this section.
t = Number of lime types produced
b = Number of calcined byproducts/wastes that are sold
z = Number of calcined byproducts/wastes that are not sold

* * * * *

0
35. Section 98.194 is amended by:
0
a. Revising the first sentence of paragraph (a).
0
b. Revising paragraph (c) introductory text.
0
c. Revising paragraph (d).
    The revisions read as follows:

Sec.  98.194  Monitoring and QA/QC requirements.

    (a) You must determine the total quantity of each type of lime
product that is produced and each calcined byproduct/waste (such as
lime kiln dust) that is sold. * * *
* * * * *
    (c) You must determine the chemical composition (percent total CaO
and percent total MgO) of each type of lime product that is produced
and each type of calcined byproduct/waste sold according to paragraph
(c)(1) or (2) of this section. You must determine the chemical
composition of each type of lime product that is produced and each type
of calcined byproduct/waste sold on a monthly basis. You must determine
the chemical composition for each type of calcined byproduct/waste that
is not sold on an annual basis.
* * * * *
    (d) You must use the analysis of calcium oxide and magnesium oxide
content of each lime product that is produced and that is collected
during the same month as the production data in monthly calculations.
* * * * *

0
36. Section 98.195 is amended by revising the first sentence of the
introductory text and paragraph (a) to read as follows:

Sec.  98.195  Procedures for estimating missing data.

    For the procedure in Sec.  98.193(b)(1), a complete record of all
measured parameters used in the GHG emissions calculations is required
(e.g., oxide content, quantity of lime products, etc.). * * *
    (a) For each missing value of the quantity of lime produced (by
lime type), and quantity of calcined byproduct/waste produced and sold,
the substitute data value shall be the best available estimate based on
all available process data or data used for accounting purposes.
* * * * *

0
37. Section 98.196 is revised to read as follows:

Sec.  98.196  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
or (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required by
Sec.  98.36 and the information listed in paragraphs (a)(1) through (8)
of this section.
    (1) Method used to determine the quantity of lime that is produced
and sold.
    (2) Method used to determine the quantity of calcined lime
byproduct/waste sold.
    (3) Beginning and end of year inventories for each lime product
that is produced, by type.
    (4) Beginning and end of year inventories for calcined lime
byproducts/wastes sold, by type.
    (5) Annual amount of calcined lime byproduct/waste sold, by type
(tons).
    (6) Annual amount of lime product sold, by type (tons).
    (7) Annual amount of calcined lime byproduct/waste that is not
sold, by type (tons).
    (8) Annual amount of lime product not sold, by type (tons).
    (b) If a CEMS is not used to measure CO2 emissions, then
you must report the information listed in paragraphs (b)(1) through
(17) of this section.
    (1) Annual CO2 process emissions from all kilns combined
(metric tons).
    (2) Monthly emission factors for each lime type produced.
    (3) Monthly emission factors for each calcined byproduct/waste by
lime type that is sold.
    (4) Standard method used (ASTM or NLA testing method) to determine
chemical compositions of each lime type produced and each calcined lime
byproduct/waste type.
    (5) Monthly results of chemical composition analysis of each type
of lime product produced and calcined byproduct/waste sold.
    (6) Annual results of chemical composition analysis of each type of
lime byproduct/waste that is not sold.

    (7) Method used to determine the quantity of lime produced and/or
lime sold.
    (8) Monthly amount of lime product sold, by type (tons).
    (9) Method used to determine the quantity of calcined lime
byproduct/waste sold.
    (10) Monthly amount of calcined lime byproduct/waste sold, by type
(tons).
    (11) Annual amount of calcined lime byproduct/waste that is not
sold, by type (tons).
    (12) Monthly weight or mass of each lime type produced (tons).
    (13) Beginning and end of year inventories for each lime product
that is produced.
    (14) Beginning and end of year inventories for calcined lime
byproducts/wastes sold.
    (15) Annual lime production capacity (tons) per facility.
    (16) Number of times in the reporting year that missing data
procedures were followed to measure lime production (months) or the
chemical composition of lime products sold (months).
    (17) Indicate whether CO2 was used on-site (i.e. for use
in a purification process). If CO2 was used on-site, provide
the information in paragraphs (b)(17)(i) and (ii) of this section.
    (i) The annual amount of CO2 captured for use in the on-
site process.
    (ii) The method used to determine the amount of CO2
captured.

Subpart V--[Amended]

0
38. Section 98.223 is amended by:
0
a. Revising paragraphs (a)(1) and (a)(2)(ii).
0
b. Revising paragraph (b) introductory text.
0
c. Revising paragraphs (b)(1) and (b)(2).
0
d. Revising paragraph (c).
0
e. Revising paragraph (d) introductory text.
0
f. Revising paragraph (e).
0
g. Removing and reserving paragraph (f).
0
h. Revising paragraph (g).
0
i. Adding paragraph (i).
    The revisions and addition read as follows:

Sec.  98.223  Calculating GHG emissions.

    (a) * * *
    (1) Use a site-specific emission factor and production data
according to paragraphs (b) through (i) of this section.
    (2) * * *
    (ii) If the Administrator does not approve your requested
alternative method within 150 days of the end of the reporting year,
you must determine the N2O emissions for the current
reporting period using the procedures specified in paragraph (a)(1) of
this section.
    (b) You must conduct an annual performance test for each nitric
acid train according to paragraphs (b)(1) through (3) of this section.
    (1) You must conduct the performance test at the absorber tail gas
vent, referred to as the test point, for each nitric acid train
according to Sec.  98.224(b) through (f). If multiple nitric acid
production units exhaust to a common abatement technology and/or
emission point, you must sample each process in the ducts before the
emissions are combined, sample each process when only one process is
operating, or sample the combined emissions when multiple processes are
operating and base the site-specific emission factor on the combined
production rate of the multiple nitric acid production units.
    (2) You must conduct the performance test under normal process
operating conditions.
* * * * *
    (c) Using the results of the performance test in paragraph (b) of
this section, you must calculate an average site-specific emission
factor for each nitric acid train ``t'' according to Equation V-1 of
this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.025

Where:

EFN2Ot = Average site-specific N2O
emissions factor for nitric acid train ``t'' (lb N2O/ton
nitric acid produced, 100 percent acid basis).
CN2O = N2O concentration for each test run
during the performance test (ppm N2O).
1.14 x 10-7 = Conversion factor (lb/dscf-ppm
N2O).
Q = Volumetric flow rate of effluent gas for each test run during
the performance test (dscf/hr).
P = Production rate for each test run during the performance test
(tons nitric acid produced per hour, 100 percent acid basis).
n = Number of test runs.

    (d) If nitric acid train ``t'' exhausts to any N2O
abatement technology ``N'' after the test point, you must determine the
destruction efficiency for each N2O abatement technology
``N'' according to paragraphs (d)(1), (d)(2), or (d)(3) of this
section.
* * * * *
    (e) If nitric acid train ``t'' exhausts to any N2O
abatement technology ``N'' after the test point, you must determine the
annual amount of nitric acid produced on train ``t'' while
N2O abatement technology ``N'' is operating according to
Sec.  98.224(f). Then you must calculate the abatement utilization
factor for each N2O abatement technology ``N'' for each
nitric acid train ``t'' according to Equation V-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.026

Where:

AFt,N = Abatement utilization factor of N2O
abatement technology ``N'' at nitric acid train ``t'' (fraction of
annual production that abatement technology is operating).
Pt = Total annual nitric acid production from nitric acid
train ``t'' (ton acid produced, 100 percent acid basis).
Pa,t,N = Annual nitric acid production from nitric acid
train ``t'' during which N2O abatement technology ``N''
was operational (ton acid produced, 100 percent acid basis).

* * * * *
    (g) You must calculate N2O emissions for each nitric
acid train ``t'' according to paragraph (g)(1), (g)(2), (g)(3), or
(g)(4) of this section.
    (1) If nitric acid train ``t'' exhausts to one N2O
abatement technology ``N'' after the test point, you must use the
emissions factor (determined in Equation V-1 of this section), the
destruction efficiency (determined in paragraph (d) of this section),
the annual nitric acid production (determined in paragraph (i) of this
section), and the abatement utilization factor (determined in paragraph
(e) of this section) according to Equation V-3a of this section:

[GRAPHIC] [TIFF OMITTED] TR28OC10.027

Where:

EN2Ot = Annual N2O mass emissions
from nitric acid production unit ``t'' according to this Equation V-
3a (metric tons).
EFN2Ot = Average site-specific N2O
emissions factor for nitric acid train ''t'' (lb N2O/ton
acid produced, 100 percent acid basis).
Pt = Annual nitric acid production from the train ``t''
(ton acid produced, 100 percent acid basis).
DF = Destruction efficiency of N2O abatement technology N
that is used on nitric acid train ``t'' (percent of N2O
removed from vent stream).
AF = Abatement utilization factor of N2O abatement
technology ``N'' for nitric acid train ``t'' (percent of time that
the abatement technology is operating).
2205 = Conversion factor (lb/metric ton).

    (2) If multiple N2O abatement technologies are located
in series after your test point, you must use the emissions factor
(determined in Equation V-1 of this section), the destruction
efficiency (determined in paragraph (d) of this section), the annual
nitric acid production (determined in paragraph (f) of this section),
and the abatement utilization factor (determined in paragraph (e) of
this section), according to Equation V-3b of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.028

Where:

EN2Ot = Annual N2O mass emissions
from nitric acid production unit ``t'' according to this Equation V-
3b (metric tons).
EFN2O,t = N2O emissions factor for
unit ``t'' (lb N2O/ton nitric acid produced).
Pt = Annual nitric acid produced from unit ``t'' (ton
acid produced, 100 percent acid basis).
DF1 = Destruction efficiency of N2O abatement
technology 1 (percent of N2O removed from vent stream).
AF1 = Abatement utilization factor of N2O
abatement technology 1 (percent of time that abatement technology 1
is operating).
DF2 = Destruction efficiency of N2O abatement
technology 2 (percent of N2O removed from vent stream).
AF2 = Abatement utilization factor of N2O
abatement technology 2 (percent of time that abatement technology 2
is operating).
DFN = Destruction efficiency of N2O abatement
technology N (percent of N2O removed from vent stream).
AFN = Abatement utilization factor of N2O
abatement technology N (percent of time that abatement technology N
is operating).
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies.

    (3) If multiple N2O abatement technologies are located
in parallel after your test point, you must use the emissions factor
(determined in Equation V-1 of this section), the destruction
efficiency (determined in paragraph (d) of this section), the annual
nitric acid production (determined in paragraph (f) of this section),
and the abatement utilization factor (determined in paragraph (e) of
this section), according to Equation V-3c of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.029

Where:

EN2Ot = Annual N2O mass emissions
from nitric acid production unit ``t'' according to this Equation V-
3c (metric tons).
EFN2O,t = N2O emissions factor for
unit ``t'' (lb N2O/ton nitric acid produced).
Pt = Annual nitric acid produced from unit ``t'' (ton
acid produced, 100 percent acid basis).
DFN = Destruction efficiency of N2O abatement
technology ``N'' (percent of N2O removed from vent
stream).
AFN = Abatement utilization factor of N2O
abatement technology ``N'' (percent of time that abatement
technology ``N'' is operating).
FCN = Fraction control factor of N2O abatement
technology ``N'' (percent of total emissions from unit ``t'' that
are sent to abatement technology ``N'').
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies with a
fraction control factor.

    (4) If nitric acid train ``t'' does not exhaust to any
N2O abatement technology after the test point, you must use
the emissions factor (determined in Equation V-1 of this section), and
the annual nitric acid production (determined in paragraph (i) of this
section) according to Equation V-3b of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.030

Where:

EN2Ot = Annual N2O mass emissions
from nitric acid production unit ``t'' according to this Equation V-
3d (metric tons).
EFN2Ot = Average site-specific N2O
emissions factor for nitric acid train ''t'' (lb N2O/ton
acid produced, 100 percent acid basis).
Pt = Annual nitric acid production from nitric acid train
``t'' (ton acid produced, 100 percent acid basis).
2205 = Conversion factor (lb/metric ton).

* * * * *
    (i) You must determine the total annual amount of nitric acid
produced on nitric acid train ``t'' for each nitric acid train (tons
acid produced, 100 percent acid basis), according to Sec.  98.224(f).

0
39. Section 98.224 is amended by:
0
a. Revising paragraph (a).
0
b. Revising the first sentence in paragraph (d) introductory text.
0
c. Revising paragraphs (e) and (f).
    The revisions read as follows:

Sec.  98.224  Monitoring and QA/QC requirements.

    (a) You must conduct a new performance test according to a test
plan as specified in paragraphs (a)(1) through (3) of this section.
    (1) Conduct the performance test annually. The test should be
conducted at a point during the campaign which is representative of the
average emissions rate from the nitric acid campaigns. Facilities must
document the methods used to determine the representative

point of the campaign when the performance test is conducted.
    (2) Conduct the performance test when your nitric acid production
process is changed, specifically when abatement equipment is installed.
    (3) If you requested Administrator approval for an alternative
method of determining N2O emissions under Sec.
98.223(a)(2), you must conduct the performance test if your request has
not been approved by the Administrator within 150 days of the end of
the reporting year in which it was submitted.
* * * * *
    (d) You must determine the volumetric flow rate during the
performance test in conjunction with the applicable EPA methods in 40
CFR part 60, appendices A-1 through A-4. * * *
* * * * *
    (e) You must determine the total monthly amount of nitric acid
produced. You must also determine the monthly amount of nitric acid
produced while N2O abatement technology (located after the
test point) is operating from each nitric acid train. These monthly
amounts are determined according to the methods in paragraphs (c)(1) or
(2) of this section.
    (f) You must determine the annual amount of nitric acid produced.
You must also determine the annual amount of nitric acid produced while
N2O abatement technology (located after the test point) is
operating for each train. These annual amounts are determined by
summing the respective monthly nitric acid quantities determined in
paragraph (e) of this section.

0
40. Section 98.226 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (g).
0
c. Revising paragraph (m) introductory text.
0
d. Revising paragraph (n) introductory text.
0
e. Adding paragraph (p).
    The revisions and addition read as follows:

Sec.  98.226  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (p) of this section.
* * * * *
    (g) Number of different N2O abatement technologies per
nitric acid train ``t''.
* * * * *
    (m) If you conducted a performance test and calculated a site-
specific emissions factor according to Sec.  98.223(a)(1), each annual
report must also contain the information specified in paragraphs (m)(1)
through (7) of this section.
* * * * *
    (n) If you requested Administrator approval for an alternative
method of determining N2O emissions under Sec.
98.223(a)(2), each annual report must also contain the information
specified in paragraphs (n)(1) through (4) of this section.
* * * * *
    (p) Fraction control factor for each abatement technology (percent
of total emissions from the production unit that are sent to the
abatement technology) if equation V-3c is used.

Subpart Z--[Amended]

0
41. Section 98.263 is amended by revising paragraph (b)(1) to read as
follows:

Sec.  98.263  Calculating GHG emissions.

* * * * *
    (b) * * *
    (1) Calculate the annual CO2 mass emissions from each
wet-process phosphoric acid process line using the methods in
paragraphs (b)(1)(i) or (ii) of this section, as applicable.
    (i) If your process measurement provides the inorganic carbon
content of phosphate rock as an output, calculate and report the
process CO2 emissions from each wet-process phosphoric acid
process line using Equation Z-1a of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.031

Where:

Em = Annual CO2 mass emissions from a wet-
process phosphoric acid process line m according to this Equation Z-
1a (metric tons).
ICn,i = Inorganic carbon content of a grab sample batch
of phosphate rock by origin i obtained during month n, from the
carbon analysis results (percent by weight, expressed as a decimal
fraction).
Pn,i = Mass of phosphate rock by origin i consumed in
month n by wet-process phosphoric acid process line m (tons).
z = Number of months during which the process line m operates.
b = Number of different types of phosphate rock in month, by origin.
If the grab sample is a composite sample of rock from more than one
origin, b = 1.
2000/2205 = Conversion factor to convert tons to metric tons.
44/12 = Ratio of molecular weights, CO2 to carbon.

    (ii) If your process measurement provides the CO2
emissions directly as an output, calculate and report the process
CO2 emissions from each wet-process phosphoric acid process
line using Equation Z-1b of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.032

Where:

Em = Annual CO2 mass emissions from a wet-
process phosphoric acid process line m according to this Equation Z-
1b (metric tons).
CO2n,i = Carbon dioxide emissions of a grab sample batch
of phosphate rock by origin i obtained during month n (percent by
weight, expressed as a decimal fraction).
Pn,i = Mass of phosphate rock by origin i consumed in
month n by wet-process phosphoric acid process line m (tons).
z = Number of months during which the process line m operates.
b = Number of different types of phosphate rock in month, by origin.
If the grab sample is a composite sample of rock from more than one
origin, b=1.
2000/2205 = Conversion factor to convert tons to metric tons.

* * * * *

0
42. Section 98.264 is amended by revising paragraphs (a) and (b) to
read as follows:

Sec.  98.264  Monitoring and QA/QC requirements.

    (a) You must obtain a monthly grab sample of phosphate rock
directly from the rock being fed to the process line before it enters
the mill using one of the following methods. You may conduct the
representative bulk sampling using a method published by a consensus
standards organization, or you may use industry consensus standard
practice methods, including but not limited to the Phosphate Mining
States Methods Used and Adopted by the Association of Fertilizer and
Phosphate Chemists (AFPC) (P.O. Box 1645, Bartow, Florida 33831, (863)
534-9755, http://afpc.net, paul.mcafee@mosaicco.com). If phosphate rock
is obtained from more than one origin in a month, you must obtain a
sample from each origin of rock or obtain a composite representative
sample.
    (b) You must determine the carbon dioxide or inorganic carbon
content of each monthly grab sample of phosphate rock (consumed in the
production of phosphoric acid). You may use a method published by a
consensus standards organization, or you may use industry consensus
standard practice methods, including but not limited to the Phosphate
Mining States Methods Used and Adopted by AFPC (P.O. Box 1645, Bartow,
Florida 33831,<PHONE_NUMBER>, http://afpc.net,
paul.mcafee@mosaicco.com).
* * * * *

0
43. Section 98.265 is amended by revising the first and second
sentences of paragraph (a) to read as follows:

Sec.  98.265  Procedures for estimating missing data.

* * * * *
    (a) For each missing value of the inorganic carbon content of
phosphate rock or carbon dioxide (by origin), you must use the
appropriate default factor provided in Table Z-1 this subpart.
Alternatively, you must determine a substitute data value by
calculating the arithmetic average of the quality-assured values of
inorganic carbon contents of phosphate rock of origin i from samples
immediately preceding and immediately following the missing data
incident. * * *
* * * * *

0
44. Section 98.266 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (c).
0
c. Revising paragraph (f) introductory text.
0
d. Revising paragraph (f)(2).
0
e. Revising paragraph (f)(4).
0
f. Revising paragraph (f)(5).
0
g. Adding paragraph (f)(9).
    The revisions and addition read as follows:

Sec.  98.266  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (f) of this section.
* * * * *
    (c) Annual arithmetic average percent inorganic carbon or carbon
dioxide in phosphate rock from monthly records (percent by weight,
expressed as a decimal fraction).
* * * * *
    (f) If you do not use a CEMS to measure emissions, then you must
report the information in paragraphs (f)(1) through (9) of this
section.
* * * * *
    (2) Annual CO2 emissions from each wet-process
phosphoric acid process line (metric tons) as calculated by either
Equation Z-1a or Equation Z-1b of this subpart.
* * * * *
    (4) Method used to estimate any missing values of inorganic carbon
content or carbon dioxide content of phosphate rock for each wet-
process phosphoric acid process line.
    (5) Monthly inorganic carbon content of phosphate rock for each
wet-process phosphoric acid process line for which Equation Z-1a is
used (percent by weight, expressed as a decimal fraction), or
CO2 (percent by weight, expressed as a decimal fraction) for
which Equation Z-1b is used.
* * * * *
    (9) Annual process CO2 emissions from phosphoric acid
production facility (metric tons).

Subpart CC--[Amended]

0
45. Section 98.294 is amended by revising the third sentence of
paragraph (a)(1) to read as follows:

Sec.  98.294  Monitoring and QA/QC requirements.

* * * * *
    (a) * * *
    (1) * * * The modified method referred to above adjusts the regular
ASTM method to express the results in terms of trona.* * *
* * * * *

0
46. Section 98.296 is amended by:
0
a. Revising paragraph (a)(1).
0
b. Revising paragraph (b)(3).
0
c. Revising paragraph (b)(6).
0
d. Revising paragraph (b)(10).
0
e. Removing paragraphs (b)(11)(iv) through (vi).
    The revisions read as follows:

Sec.  98.296  Data reporting requirements.

* * * * *
    (a) * * *
    (1) Annual consumption of trona or liquid alkaline feedstock for
each manufacturing line (tons).
* * * * *
    (b) * * *
    (3) Annual production of soda ash for each manufacturing line
(tons).
* * * * *
    (6) Monthly production of soda ash for each manufacturing line
(tons).
* * * * *
    (10) If you produce soda ash using the liquid alkaline feedstock
process and use the site-specific emission factor method (Sec.
98.293(b)(3)) to estimate emissions then you must report the following
relevant information for each manufacturing line or stack:
    (i) Stack gas volumetric flow rate during performance test (dscfm).
    (ii) Hourly CO2 concentration during performance test
(percent CO2).
    (iii) CO2 emission factor (metric tons CO2/
metric tons of process vent flow from mine water stripper/evaporator).
    (iv) CO2 mass emission rate during performance test
(metric tons/hour).
* * * * *

Subpart EE--[Amended]

0
47. Section 98.314 is amended by revising paragraph (e) to read as
follows:

Sec.  98.314  Monitoring and QA/QC requirements.

* * * * *
    (e) You must determine the quantity of carbon-containing waste
generated from each titanium dioxide production line on a monthly basis
using plant instruments used for accounting purposes including direct
measurement weighing the carbon-containing waste not used during the
process (by belt scales or a similar device) or through the use of
sales records.
* * * * *

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48. Section 98.316 is amended by revising paragraphs (b)(9) and (b)(11)
to read as follows:

Sec.  98.316  Data reporting requirements.

* * * * *
    (b) * * *
    (9) Monthly carbon content factor of petroleum coke (percent by
weight expressed as a decimal fraction).
* * * * *
    (11) Carbon content for carbon-containing waste for each process
line (percent by weight expressed as a decimal fraction).
* * * * *

Subpart GG--[Amended]

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49. Section 98.333 is amended by revising the definitions of
``(Electrode)k'' and ``(CElectrode)k''
in Equation GG-1 of paragraph (b)(1) to read as follows:

Sec.  98.333  Calculating GHG emissions.

* * * * *
    (b) * * *
    (1) * * * * *

(Electrode)k = Annual mass of carbon electrode consumed
in furnace ``k'' (tons).
(CElectrode)k = Carbon content of the carbon
electrode consumed in furnace ``k'', from the annual carbon analysis
(percent by weight, expressed as a decimal fraction).

* * * * *

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50. Section 98.336 is amended by revising paragraph (a) introductory
text; and by revising paragraphs (b)(1), (b)(7), and (b)(10) to read as
follows:

Sec.  98.336  Data reporting requirements.

* * * * *
    (a) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required for
the Tier 4 Calculation Methodology in Sec.  98.36 and the information
listed in this paragraph (a):
* * * * *
    (b) * * *
    (1) Identification number and annual process CO2
emissions from each individual Waelz kiln or electrothermic furnace
(metric tons).
* * * * *
    (7) Carbon content of each carbon-containing input material charged
to each kiln or furnace (including zinc bearing material, flux
materials, and other carbonaceous materials) from the annual carbon
analysis or from information provided by the material supplier for each
kiln or furnace (percent by weight, expressed as a decimal fraction).
* * * * *
    (10) Carbon content of the carbon electrode used in each furnace
from the annual carbon analysis or from information provided by the
material supplier (percent by weight, expressed as a decimal fraction).
* * * * *

Subpart HH--[Amended]

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51. Section 98.340 is amended by revising paragraph (b) to read as
follows:

Sec.  98.340  Definition of the source category.

* * * * *
    (b) This source category does not include Resource Conservation and
Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act (TSCA)
hazardous waste landfills, construction and demolition waste landfills,
or industrial waste landfills.
* * * * *
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52. Section 98.343 is amended by:
0
a. In paragraph (a)(1), revising Equation HH-1 and the definitions of
``x,'' ``S,'' ``Wx,'' ``MCF,'' ``DOCF,'' ``F,''
and ``k'' in Equation HH-1; and removing the definition of
``L0'' in Equation HH-1.
0
b. Revising the last sentence of paragraph (a)(2).
0
c. Redesignating paragraph (a)(3) as (a)(4) and revising new paragraph
(a)(4).
0
d. Adding a new paragraph (a)(3).
0
e. Revising paragraph (b)(1), and revising paragraph (b)(2)
introductory text.
0
f. Revising paragraphs (b)(2)(ii), (b)(2)(iii)(A), and (b)(2)(iii)(B).
0
g. Revising paragraph (c) introductory text.
    The revisions and additions read as follows:

Sec.  98.343  Calculating GHG emissions.

    (a) * * *
    (1) * * *
    [GRAPHIC] [TIFF OMITTED] TR28OC10.033

* * * * *
x = Year in which waste was disposed.
S = Start year of calculation. Use the year 1960 or the opening year
of the landfill, whichever is more recent.

* * * * *

Wx = Quantity of waste disposed in the landfill in year x
from measurement data, tipping fee receipts, or other company
records (metric tons, as received (wet weight)).
MCF = Methane correction factor (fraction). Use the default value of
1 unless there is active aeration of waste within the landfill
during the reporting year. If there is active aeration of waste
within the landfill during the reporting year, use either the
default value of 1 or select an alternative value no less than 0.5
based on site-specific aeration parameters.

* * * * *

DOCF = Fraction of DOC dissimilated (fraction). Use the
default value of 0.5.
F = Fraction by volume of CH4 in landfill gas from
measurement data on a dry basis, if available (fraction); default is
0.5.
k = Rate constant from Table HH-1 to this subpart
(yr-\1\). Select the most applicable k value for the
majority of the past 10 years (or operating life, whichever is
shorter).

    (2) * * * For years when waste composition data are not available,
use the bulk waste parameter values for k and DOC in Table HH-1 to this
subpart for the total quantity of waste disposed in those years.
    (3) Beginning in the first emissions reporting year and for each
year thereafter, if scales are in place, you must determine the annual
quantity of waste (in metric tons as received, i.e., wet weight)
disposed of in the landfill using paragraph (a)(3)(i) of this section
for all containers and for all vehicles used to haul waste to the
landfill, except for passenger cars, light duty pickup trucks, or waste
loads that cannot be measured using the scales due to physical
limitations (load cannot physically access or fit on the scale) and/or
operational limitations of the scale (load exceeding the limits or
sensitivity range of the scale). If scales are not in place, you must
use paragraph (a)(3)(ii) of this section to determine the annual
quantity of waste disposed. For waste hauled to the landfill in
passenger cars or light duty pickup trucks, you may use either