annually.
     An option to use data from existing online solids meters
to determine the annual mass of spent liquor solids fired is provided
(in lieu of conducting an annual TAPPI Test Method T 650).
     The requirement to report quarterly data was eliminated.
     The reporting requirements were revised to specify units
to standardize inputs into the data reporting system.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. A number of comments on pulp and paper manufacturing were
received covering numerous topics. Responses to significant comments
received can be found in ``Mandatory Greenhouse Gas Reporting Rule:
EPA's Response to Public Comments, Subpart AA: Pulp and Paper
Manufacturing.''
Definition of Source Category
    Comment: Two commenters stated that literal interpretation of 40
CFR part 98, subpart AA could require any facility operating paper
coating and laminating processes to report emissions for any system
used to add makeup chemicals. The commenters requested that language be
added to 40 CFR part 98, subpart AA to clearly exclude facilities not
intended to be covered and which have not traditionally been part of
the pulp and paper source category.
    Response: Definitions of terms used in 40 CFR part 98, subpart AA
are provided in 40 CFR 98.6 (in subpart A of part 98). The definition
of ``makeup chemicals'' is specific to the chemical recovery areas of
pulp mills and serves to limit the scope of the pulp and paper
subcategory. As defined in Sec.  98.6 (emphasis added):

    ``Chemical recovery combustion unit means a combustion device,
such as a recovery furnace or fluidized-bed reactor where spent
pulping liquor from sulfite or semi-chemical pulping processes is
burned to recover pulping chemicals.''
    ``Makeup chemicals means carbonate chemicals (e.g., sodium and
calcium carbonates) that are added to the chemical recovery areas of
chemical pulp mills to replace chemicals lost in the process.''

    Thus, we disagree that the rule could be interpreted to require any
facility operating coating and laminating processes to report emissions
for any system used to add makeup chemicals. This was not the intent of
the rule. Nevertheless, we have added language consistent with the
definition of ``makeup chemicals'' to 40 CFR 98.270(b)(5) and 98.272(e)
to further clarify that GHG emissions are to be reported for systems
adding makeup chemicals (CaCO3 and
Na2CO3) in the chemical recovery areas of pulp
mills.
    Comment: Commenters stated the rule should include categorical
exemptions for emissions from the combustion of non-condensable gases
(NCG), stripper off gases (SOG), tall oil and turpentine (small sources
of GHG that are difficult to measure). The commenters noted that these
streams are of biogenic origin. One commenter described safety issues
associated with sampling these gas streams.
    Response: Pulp mill NCG, SOG, tall oil and turpentine were
discussed in the Proposed Rule TSD for the pulp and paper manufacturing
sector. The Proposed Rule TSD noted that process vent gases such as NCG
and SOG and the byproducts tall oil and turpentine are derived from
biomass. We acknowledge the safety and measurement issues described by
commenters regarding sampling of NCG and SOG streams. No methods are
specified in the rule for calculation of GHG associated with combustion
of NCG, SOG, tall oil and turpentine. Thus, calculation of these
emissions is not required and there is no need for categorical
exemptions.
Method for Calculating GHG Emissions
    Comment: Commenters stated that monthly measurements of the mass of
spent liquor solids, HHV, and carbon content of spent liquor solids are
unnecessary. The commenters requested that EPA either allow default
fuel carbon content and heating value for spent pulping liquor, or
reduce the frequency of measurements to annually or every two years.
Commenters noted that spent liquor HHV and carbon content are measured
from time to time but less frequently than monthly. In addition, one
commenter pointed out that chemical recovery furnaces often have online
solids meters installed to provide continuous measurement of the mass
of spent liquor solids entering the furnace for safety and process
control reasons. This commenter requested that EPA allow use of such
continuous measurement devices instead of requiring monthly measurement
of the mass of spent liquor solids with TAPPI Test Method T 650.
    Response: We disagree with commenters that default fuel carbon
content and high heating values should be allowed instead of measured
values. These parameters are already measured by mills (though less
frequently than monthly) and thus are available for use and more
accurate than default values. We are reducing the frequency of fuel
property measurements from monthly to annual. There is little monthly
variation in fuel properties over the course of a year. Therefore,
annual measurements are sufficient to develop site specific emission
factors. This change also reduces the burden associated with complying
with the rule. These changes have been incorporated throughout the text
and equations of 40 CFR part 98, subpart AA.
    In addition, the final rule allows use of either an annual
measurement of the mass of spent liquor solids fired (with TAPPI Test
Method T 650) or use of annual spent liquor solids data calculated from
continuous measurements already performed for process control purposes
(e.g., with existing online solids meters). If the annual spent liquor
solids fired is determined using existing measurement equipment, then
reporters must retain records of the calculations used to determine the
annual mass of spent liquor solids fired from the continuous
measurements in order to demonstrate, if necessary, that calculations
where done correctly. Reporters must also document that these
measurement devices have been regularly and properly calibrated
according to the manufacturer's specifications.
Data Reporting Requirements
    Comment: One commenter noted that presenting quarterly data in
annual reports for pulp and paper manufacturing annual emissions,
consumption of biomass fuels, and quantity of spent liquor solids fired
is unnecessary for an annual reporting system.
    Response: We have revised 40 CFR 98.276 and 98.277(a) to remove the
requirement for providing quarterly details in the annual report. EPA
agrees that requiring quarterly details was not necessary for ensuring
the accuracy of data reported annually.
    Comment: One commenter requested that the spreadsheets developed by
the National Council for Air and Stream Improvement (NCASI) for the
International Council of Forest and Paper Associations (ICFPA) be
allowed as an option for facilities subject to the Rule to determine
emissions. These spreadsheets segregate calculated GHG emissions into
fossil fuel and biogenic categories. The commenter believes that tools
like those developed by NCASI and others should be allowed as an option
for facilities subject to the emission calculation requirements imposed
by 40 CFR 98.3. This streamlined approach will provide the Agency with
valid GHG emission data without imposing extraordinary capital and
labor burdens on the industry.
    Response: The ICFPA/NCASI tools were considered in developing the
requirements of the GHG reporting rule. However, the ICFPA/NCASI
spreadsheets, though valuable tools, are not broadly applicable to all
industrial sectors covered under the GHG reporting rule, as are the
monitoring, reporting, recordkeeping, and emissions verification
requirements specified in 40 CFR 98.3. Additionally, these tools often
use default factors and estimates, which differs from the approach
proposed by EPA. The data collected from all subparts of the GHG
reporting rule will be tabulated in EPA's electronic reporting system.
This system will be used to verify emission calculations and will
require specific data be reported in order to run the calculations used
for verification. The tools suggested by the commenter, however, would
only provide a total emission number. Consequently, EPA would not be
able to check the underlying calculations for accuracy. The final GHG
reporting rule reflects the data reporting requirements necessary for
emissions verification by EPA. Edits to the reporting and recordkeeping
language (40 CFR 98.276 and 98.277) of 40 CFR part 98, subpart AA were
made to clarify calculation inputs and units of measure to be reported.
As part of the implementation phase of today's final rule, EPA intends
to prepare guidance documents to assist the industry in complying with
the rule's requirements. In recognition of the fact that the pulp and
paper industry has been using the ICFPA/NCASI spreadsheets, EPA will
consider including in the guidance materials a comparison between these
spreadsheets and EPA's electronic reporting system to reduce the burden
on the industry and minimize confusion.

BB. Silicon Carbide Production

1. Summary of the Final Rule
    Source Category Definition. The silicon carbide production source
category consists of any process that produces silicon carbide for
abrasive purposes.
    Reporters must submit annual GHG reports for facilities that meet
the

applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.
    GHGs to Report. Report process CO2 and CH4
emissions from all silicon carbide production furnaces or process units
at the facility combined.
    In addition, report GHG emissions for other source categories at
the facility for which calculation methods are provided in the rule, as
applicable. For example, report CO2, N2O, and
CH4 emissions from each stationary combustion unit on site
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).
    GHG Emissions Calculation and Monitoring. For CO2
emissions, reporters must use one of the following methods, as
appropriate:
     Most reporters can elect to calculate and report process
CO2 emissions from silicon carbide production processes by
either (1) installing and operating CEMS and following the Tier 4
methodology (in 40 CFR part 98, subpart C) or (2) calculating emissions
using the measured petroleum coke consumption and a monthly facility-
specific emission factor. The facility-specific emission factor is the
carbon content of the petroleum coke (provided monthly by the supplier
or measured monthly using the appropriate test methods) adjusted for
carbon in the silicon carbide product.
     However, if process CO2 emissions from silicon
carbide production are vented through the same stack as a combustion
unit or process equipment that uses a CEMS and follows Tier 4
methodology to report process CO2 emissions, then the CEMS
must be used to measure and report combined CO2 emissions
from that stack. In such cases, the reporter cannot use the
CO2 calculation approach (2) outlined in the above bullet.
    For CH4 emissions, reporters must use the measured
petroleum coke consumption and a default emission factor of 10.2
kilograms (kg) per metric ton of coke consumed.
    Data Reporting. In addition to the information required to be
reported by the General Provisions (40 CFR 98.3(c)) and summarized in
Section II.A of this preamble, reporters must submit additional data
that are used to calculate GHG emissions. A list of the specific data
to be reported for this source category is contained in 40 CFR part 98,
subpart BB.
    Recordkeeping. In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions. A list of specific records that must be
retained for this source category is included in 40 CFR part 98,
subpart BB.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following
list. The rationale for these and any other significant changes can be
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's
Response to Public Comments, Subpart BB: Silicon Carbide Production.''
     The emissions calculation method under 40 CFR 98.283(b)
was revised to require data on monthly petroleum coke consumption and
monthly petroleum coke carbon contents rather than quarterly
determinations.
     Missing data procedures were added under 40 CFR 98.285 for
monthly parameters used to calculate emissions, including mass of
petroleum coke, and carbon contents of petroleum coke.
     40 CFR 98.286 was reorganized and updated to improve the
emissions verification process. Some data elements were moved from 40
CFR 98.287 to 40 CFR 98.286, and some data elements that a reporter
must already use to calculate GHGs as specified in 40 CFR 98.283 were
added to 40 CFR 98.286 for clarity.
3. Summary of Comments and Responses
    No specific comments were received pertaining to the proposed
reporting requirements for silicon carbide production facilities.
However, the proposed rule did not clearly specify how quarterly carbon
contents should be determined. This determination should be made on a
monthly basis as proposed for other chemical production processes where
process emissions arise from use of petroleum coke, such as titanium
dioxide production. Quarterly reporting of carbon contents of petroleum
coke consumed for the quarter would have to be averaged from monthly
data. For verification, EPA would require reporting of the monthly
carbon contents of the petroleum coke. Therefore, we revised the
emissions calculation method to directly require monthly petroleum coke
consumption and monthly petroleum coke contents, rather than quarterly
based on an arithmetic average of the monthly estimates to improve
accuracy of emissions calculations. We have retained the flexibility in
use of supplier data to determine carbon contents. We understand that
most supplier data on carbon contents of petroleum coke is readily
available and that businesses track production inputs and outputs on a
monthly basis as a part of normal business practice or existing
accounting procedures. The increased frequency of data collection from
quarterly to monthly provides greater clarity and accuracy without
significantly increasing burden. In addition, see the Section II.N of
this preamble for an explanation of the emissions verification
approach.

CC. Soda Ash Manufacturing

1. Summary of the Final Rule
    Source Category Definition. A soda ash manufacturing facility is
any facility with a manufacturing line that produces soda ash by
either: calcining trona or sodium sesquicarbonate; or by using a liquid
alkaline feedstock process that directly produces CO2. In
the context of the soda ash manufacturing sector, ``calcining'' means
the thermal/chemical conversion of the bicarbonate fraction of the
feedstock to sodium carbonate.
    Soda ash produced from a liquid alkaline feedstock using sodium
hydroxide does not emit process CO2 and therefore is not
subject to the requirements of Subpart CC. However, such facilities may
be covered under Subpart C (General Stationary Combustion) if they meet
the requirements of either Sec.  98.2(a)(1) or (2).
    Reporters must submit annual GHG reports for facilities that meet
the applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.
    GHGs to Report. For soda ash manufacturing, report the following
emissions:
     CO2 process emissions from soda ash
manufacturing, reported for each manufacturing line.
     CO2 combustion emissions from each soda ash
manufacturing line.
     N2O and CH4 emissions from fuel
combustion at each soda ash manufacturing line under 40 CFR part 98,
subpart C (General Stationary Fuel Combustion Sources) using the
methodologies in subpart C.
     CO2, N2O, and CH4
emissions from each stationary combustion unit other than soda ash
manufacturing lines under 40 CFR part 98, subpart C (General Stationary
Fuel Combustion Sources).
    In addition, report GHG emissions for any other source categories
at the facility for which calculation methods are provided in other
subparts of the rule, as applicable.
    GHG Emissions Calculation and Monitoring. For CO2
emissions from soda ash manufacturing lines, reporters must select one
of the following methods, as appropriate:

     For each soda ash manufacturing line with certain types of
CEMS in place, reporters must use the CEMS and follow the Tier 4
methodology (in 40 CFR part 98, subpart C) to report under the Soda Ash
Manufacturing subpart (40 CFR part 98, subpart CC) combined process and
combustion CO2 emissions.
     For other soda ash manufacturing lines, reporters can
elect to either (1) install and operate a CEMS and follow Tier 4
methodology to measure and report combined process and combustion
CO2 emissions or (2) calculate CO2 process
emissions using the procedures specified in 40 CFR part 98, subpart CC
and summarized below.
     If using approach 2, calculate process CO2
emissions using one of three alternative methods, as appropriate for
each manufacturing line:

--The trona input method calculates the calcination emissions using:
Monthly mass of trona input (required to be measured), the average
monthly mass-fraction of inorganic carbon in the trona (required to be
measured weekly), and the ratio of CO2 emitted for each ton
of trona consumed (a default value is provided).
--The soda ash output method calculates the calcination emissions
using: Monthly mass of soda ash produced (required to be measured), the
monthly average mass-fraction of inorganic carbon in the soda ash
(required to be measured weekly), and the ratio of CO2
emitted for each ton of soda ash produced (a default value is
provided).
--The site-specific emission factor method calculates emissions from
production of soda ash using liquid alkaline feedstock through an
annual performance test using: The average process vent flow rate from
the mine water stripper/evaporator for each manufacturing line, direct
measurements of hourly CO2 concentration, the hourly stack
gas volumetric flow rate, the annual process vent flow rate from mine
water stripper/evaporator, and annual operating hours.
--Report process CO2 emissions from each soda ash
manufacturing line under 40 CFR part 98, subpart CC (Soda Ash
Manufacturing), and report combustion CO2 emissions from
each calciner (kiln) in each manufacturing line under 40 CFR part 98,
subpart C (General Stationary Fuel Combustion Sources).

    Data Reporting. In addition to the information required to be
reported by the General Provisions (40 CFR 98.3(c)) and summarized in
Section II.A of this preamble, reporters must submit additional data
that are used to calculate GHG emissions. A list of the specific data
to be reported for this source category is contained in 40 CFR part 98,
subpart CC.
    Recordkeeping. In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions. A list of specific records that must be
retained for this source category is included in 40 CFR part 98,
subpart CC.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following
list. The rationale for these and any other significant changes can be
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's
Response to Public Comments, Subpart CC: Soda Ash Manufacturing.''
     A site-specific emission factor method has been added for
production of soda ash using liquid alkaline feedstock or mine water.
This method was not included in the proposed rule.
     The frequency of inorganic carbon content determination of
either trona or soda ash has been revised from daily to monthly based
on a weekly composite.
     Procedures were added to 40 CFR 98.295 for estimating
missing data for monthly values of inorganic carbon content of trona
and monthly values of trona consumption or soda ash production. We also
added missing data procedures for parameters specific to calculating
emissions from soda ash produced from liquid alkaline feedstock (i.e.
site-specific emission factor method).
     40 CFR 98.296 was reorganized and updated to improve the
emissions verification process. Some data elements were moved from 40
CFR 98.297 to 40 CFR 98.296, and some data elements that a reporter
must already use to calculate GHGs as specified in 40 CFR 98.293 were
added to 40 CFR 98.296 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. Two sets of comments on soda ash manufacturing were received
covering several topics. Responses to significant comments received can
be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response
to Public Comments, Subpart CC: Soda Ash Manufacturing.''
Method for Calculating GHG Emissions
    Comment: Both commenters noted that facilities produced soda ash
using alternative methods to calcining trona or other carbonate
containing minerals. Facilities also produce soda ash from mine water,
a liquid alkaline feedstock; this is a ``process'' emissive production
process, but was not addressed in the proposal. The methods in the
proposal did not include methods appropriate for calculating process
CO2 from the liquid alkaline feedstock production process.
One commenter using this production method recommended that the
appropriate method for calculating emissions from this process would be
an annual performance test and described the appropriate parameters
that would be measured during the annual performance test to establish
an emission factor for calculating annual emissions based on
concentration of the CO2 in the evaporated stripped mine
water and the annual flow from the mine water stripper/evaporator.
    Response: We agree that the final rule should address process
CO2 emissions generated from this relatively new alternative
production process which produces soda ash from liquid alkaline
feedstock or mine water. From additional information provided by the
commenter, process CO2 emissions from this production method
are likely to be significant and exceed 25,000 metric tons
CO2e. This process is currently used by a single company,
but could become more widespread within the industry in the future as
it makes more efficient use of raw materials previously not used. We
have updated all sections of 40 CFR part 98, subpart CC for
calculating, monitoring and QA/QC, and reporting of process
CO2 emissions specific to production of soda ash from liquid
alkaline feedstock or minewater. We added procedures for developing
site-specific emission factor based on an annual performance test
consistent with the recommendations provided by the commenter.
    Comment: One commenter noted that using the total alkalinity of
either trona or soda ash as prescribed in Equations CC-2 and CC-3 is
inappropriate given that the ratio of carbon dioxide to carbon is a
factor in the equations. The equations' results artificially inflated
the CO2 level by 3.67 times the actual amount.
    Response: Upon further review, we agree with the commenter's
analysis that the ratio 44/12 will overestimate emissions and have
removed this fraction, which is the ratio of carbon dioxide to carbon,
from Equations CC-2 and CC-3. Equations CC-2 and CC-3

provide results directly for CO2 therefore it is not
necessary to use a conversion factor to convert the carbon to carbon
dioxide.
    Comment: One commenter noted that Equation CC-3 does not address
plant inefficiency specific to each manufacturing line. The commenter
suggested that an efficiency factor should be added to Equations CC-3
to account for these inefficiencies.
    Response: The commenter has not suggested an efficiency factor or
otherwise provided data with enough specificity to modify the equations
and modify the calculation methods as suggested; therefore, we have
decided not to add efficiency factors to Equations CC-3.
    EPA needs more information to effectively evaluate this comment and
update the equations noted, if appropriate. Efficiency factors can
relate to a number of factors including combustion and also kiln
conditions, which may vary. We need more information to understand how
this factor would be derived for each kiln or manufacturing line. The
comment was specific to CC-3, and we suggest the use of Equation CC-2
as an alternative calculation method.
Monitoring and QA/QC Requirements
    Comment: One commenter stated that daily sampling of inorganic
carbon content of each manufacturing line is an unnecessary and
potentially extremely costly requirement. They suggested that instead
of daily testing, testing should be completed as a weekly composite
analysis which would then be used in calculating the monthly average.
    Response: We concur that testing of the inorganic carbon content
can be done on a weekly schedule and used to calculate a monthly
composite without significant loss in accuracy. The weekly composite
would still be based on several daily tests. We have updated the
monitoring and QA/QC requirements accordingly in the rule under 40 CFR
98.294.
    Comment: One commenter stated that the prescribed ASTM method, ASTM
E359-00(2005), for determining the inorganic carbon content of trona or
soda ash describes a manual titration method using a methyl orange
endpoint. They stated that procedures that use autotitrators with fixed
endpoint titration are commonly used in the soda ash manufacturing
industry and should be allowed as an acceptable equivalent alternative.
    Response: We agree that methods using autotitration to determine
inorganic carbon content of trona or soda ash expressed as total
alkalinity are acceptable equivalent methods for determining the
inorganic carbon content of trona or soda ash. We understand that
manual titration offers good levels of accuracy but are labor and time
intensive. From our understanding, autotitration methods provide
comparable or improved levels of accuracy and are less labor and time
intensive by ``automating'' the analysis process. Autotitration methods
could provide more consistency in results across the industry. We have
updated the procedures in 40 CFR 98.294 for monitoring and QA/QC in the
rule to allow for such comparable methods.

DD. Sulfur Hexafluoride (SF6) From Electrical Equipment

    At this time EPA is not going final with the electrical equipment
subpart. As we consider next steps, we will be reviewing the public
comments and the relevant information.
    Based on careful review of comments received on the preamble, rule,
and TSDs under 40 CFR part 98, subpart DD, EPA will perform additional
analysis and evaluate a range of data collection procedures and
methodologies. EPA's goal is to optimize methods of data collection to
ensure data accuracy while considering industry burden. In addition,
EPA will further evaluate the scope of coverage of electric power
systems and the reporting boundaries in other subparts.

EE. Titanium Dioxide Production

1. Summary of the Final Rule
    Source Category Definition. The titanium dioxide production source
category consists of any facility that uses the chloride process to
produce titanium dioxide.
    Reporters must submit annual GHG reports for facilities that meet
the applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.
    GHGs to Report. For titanium dioxide production, report
CO2 process emissions from each chloride process line.
    In addition, report GHG emissions for other source categories for
which calculation methods are provided in the rule, as applicable. For
example, facilities must report CO2, N2O, and
CH4 emissions from each stationary combustion unit on site
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).
    GHG Emissions Calculation and Monitoring. Reporters must calculate
CO2 process emissions using one of two methods, as
appropriate:
     Most reporters can elect to calculate and report process
CO2 emissions from titanium dioxide process lines by either
(1) installing and operating CEMS and following the Tier 4 methodology
(in 40 CFR part 98, subpart C) or (2) using the calculation procedures
specified below.
     However, if process CO2 emissions from titanium
dioxide production are emitted through the same stack as a combustion
unit or process equipment that uses a CEMS and follows Tier 4
methodology to report CO2 emissions, then the reporter must
use the CEMS to measure and report combined CO2 emissions
from that stack instead of using the calculation procedures described
below.
     If using approach 2, calculate the process
CO2 emissions using the equation provided 40 CFR part 98,
subpart EE and monthly determination of the mass and carbon content of
calcined petroleum coke consumed in each line and all lines combined.
Determine petroleum coke consumption by either direct measurement or
purchase records. Determine carbon content of petroleum coke using
supplier data or measurement using appropriate test methods. If
applicable, also determine the quantity of carbon containing waste
generated and its carbon contents using direct measurement.
    Data Reporting. In addition to the information required to be
reported by the General Provisions (40 CFR 98.3(c)) and summarized in
Section II.A of this preamble, reporters must submit additional data
that are used to calculate GHG emissions. A list of the specific data
to be reported for this source category is contained in 40 CFR part 98,
subpart EE.
    Recordkeeping. In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions. A list of specific records that must be
retained for this source category is included in 40 CFR part 98,
subpart EE.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following
list. The rationale for these and any other significant changes can be
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's
Response to Public Comments, Subpart EE: Titanium Dioxide Production.''
     Requirements were added for reporting of carbon-containing
waste generated from less than 100 percent oxidation of coke during the
titanium production process. 40 CFR 98.316

allows for reporting of quantity of carbon-containing waste generated
and associated carbon contents.
     Missing data procedures were added under 40 CFR 98.315 for
monthly parameters used to calculate emissions, including mass of
calcined petroleum coke, mass of carbon-containing waste, and carbon
contents of calcined petroleum coke.
     40 CFR 98.316 was reorganized and updated to improve the
emissions verification process. Some data elements were moved from 40
CFR 98.317 to 40 CFR 98.316, and some data elements that a reporter
must already use to calculate GHGs as specified in 40 CFR 98.313 were
added to 40 CFR 98.316 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. We received three sets of comments on titanium dioxide
production covering several topics. Several of these comments were
directed at the requirements for General Stationary Fuel Combustion
Sources in subpart C, and responses to those comments are provided in
the preamble section dealing with that source category. Responses to
significant comments received can be found in ``Mandatory Greenhouse
Gas Reporting Rule: EPA's Response to Public Comments, Subpart EE:
Titanium Dioxide Production.''
Method for Calculating GHG Emissions
    Comment: One commenter noted that the carbon oxidation factor for
calcined petroleum coke is not always 100 percent. They point out that
the calcined petroleum coke comes with impurities, and a certain amount
of the calcined coke is returned to the ground as landfill along with
components such as the un-converted TiO2. Thus, they suggest
that EPA should revise the carbon oxidation factor to allow facilities
to use the most appropriate factor for their process, with supporting
documentation of its derivation available for EPA review as needed.
    Response: EPA has considered the comment but maintains the
assumption of 100 percent oxidation across all sectors in the final
rule. Data reporting requirements have been added to 40 CFR 98.316 to
collect information on the quantity of carbon-containing waste
generated that is landfilled and its carbon contents which are not
emitted. This information will help inform future methods for
calculating process emissions from titanium dioxide production (e.g.,
how to address oxidation rates). EPA interpreted that this comment may
also be applicable to carbon content of calcined petroleum coke. EPA
agrees that carbon content may not always be 100 percent and therefore
has revised the rule to allow facilities to use supplier data or
determine carbon contents using appropriate test methods as part of
calculating emissions in 40 CFR 98.313.
Procedures for Estimating Missing Data
    Comment: Two commenters noted there can be numerous reasons data
may not be available, on time, or in the format EPA requires. In cases
where a required record is found to be missing or determined to be
incorrect, the commenters requested that EPA should provide a procedure
for estimating missing data.
    Response: We concur that there may be circumstances where data on
carbon contents of coke and petroleum coke consumption may be missing.
Records could be misplaced or lost. Thus, we have revised the rule and
added specific procedures for estimating missing data in 40 CFR 98.315.
These procedures are consistent with those allowed across the rule for
similar parameters. For example, if a facility is missing data on
carbon contents of petroleum coke we allow facilities to allow sources
to substitute the missing data with another quality assured parameter,
such as the arithmetic average of the carbon contents from the month
immediately preceding and the month immediately following the missing
data incident.
Data Reporting Requirements
    Comment: All commenters noted they are concerned that the level of
information to be reported, which is considered available for public
distribution, could put the domestic TiO2 producers at a
disadvantage relative to international producers. The commenters do not
believe that CBI provisions briefly outlined in the preamble are
adequate to safeguard the proprietary technical and financial positions
of titanium dioxide production facilities. The annual production of
titanium dioxide, annual amount of petroleum coke consumed, and annual
operating hours are considered CBI and are unnecessary to carry out the
purposes of this proposed regulation. This data should only be
available onsite or offsite (e.g., a centralized location), or as
requested for security cleared EPA personnel and their security cleared
contractors where a need is demonstrated for the purposes of this
inventory.
    Response: EPA reviewed CBI comments received across the rule (both
general and subpart-specific comments) and our response is discussed in
Section II.R of this preamble and in ``Mandatory Greenhouse Gas
Reporting Rule: EPA's Response to Public Comments, Legal Issues.''
    In addition, see the Section II.N of this preamble for the response
on the emissions verification approach. The amount of petroleum coke
consumed is necessary to calculate annual process CO2
emissions. Production capacity and annual production of titanium
dioxide are required for EPA to verify annual CO2 process
emissions. These parameters help EPA to determine whether reported
emissions are within a reasonable range. EPA concurs that data on
operating hours can be retained as a record and does not need to be
reported to EPA. It is not a parameter used in calculating process
CO2 emissions. However, operating hours would help to verify
any anomalies in reported emissions or supporting parameters related to
temporary closures for repairs or maintenance. This data has been moved
to recordkeeping requirements in 40 CFR 98.317.

FF. Underground Coal Mines

    At this time, EPA is not finalizing the Underground Coal Mines
Subpart (40 CFR part 98, subpart FF). As EPA considers next steps, we
will be reviewing the public comments on the proposal preamble, rule
and TSDs for proposed 40 CFR 98 Subpart FF and other relevant
information. EPA will perform additional analysis and consider
alternatives to the monitoring requirements.

GG. Zinc Production

1. Summary of the Final Rule
    Source Category Definition. Zinc production facilities consist of
zinc smelters and secondary zinc recycling facilities.
    Reporters must submit annual GHG reports for facilities that meet
the applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.
    GHGs to Report. For zinc production, report the following:
     CO2 process emissions from each Waelz kiln and
electrothermic furnace used for zinc production.
     CO2, N2O, and CH4
combustion emissions from each Waelz kiln and each other stationary
combustion unit on site under 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).
    In addition, report GHG emissions for other source categories at
the facility for which calculation methods are provided in the rule, as
applicable.

    GHG Emissions Calculation and Monitoring. Facilities must calculate
CO2 process emissions using one of two methods, as
appropriate:
     Most reporters can elect to calculate and report process
CO2 emissions from each Waelz kiln and electrothermic
furnace by either (1) installing and operating CEMS and following the
Tier 4 methodology (in 40 CFR part 98, subpart C) or (2) using the
calculation procedures specified in the rule.
     However, if process CO2 emissions from a Waelz
kiln or electrothermic furnace are emitted through the same stack as a
combustion unit or process equipment that uses a CEMS and follows Tier
4 methodology to report CO2 emissions, then the CEMS must be
used to measure and report combined CO2 emissions from that
stack, instead of the calculation procedure described below.
     If using approach 2, calculate process
CO2 emissions by determining on an annual basis the total
mass (metric tons) of carbon-containing input materials (i.e., zinc-
bearing material, flux, electrodes, and any other carbonaceous
materials) introduced into each kiln and furnace and the carbon content
of each material. Determine carbon content annually either by using
supplier data, or by direct measurement using appropriate test methods.
    Data Reporting. In addition to the information required to be
reported by the General Provisions (40 CFR 98.3(c)) and summarized in
Section II.A of this preamble, reporters must submit additional data
that are used to calculate GHG emissions. A list of the specific data
to be reported for this source category is contained in 40 CFR part 98,
subpart GG.
    Recordkeeping. In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions. A list of specific records that must be
retained for this source category is included in 40 CFR part 98,
subpart GG.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following
list. The rationale for these changes can be found below.
     The carbon input method was revised to require an annual
analysis of all process inputs and outputs for carbon content rather
than monthly sampling and monthly analysis.
     A de minimis was added to exclude accounting for carbon-
containing materials contributing less than one percent of the total
carbon into Waelz kiln or electrothermic furnaces. These materials do
not need to be included in carbon mass balance calculations.
     40 CFR 98.336 was reorganized and updated to improve the
emissions verification process. Some data elements were moved from 40
CFR 98.337 to 40 CFR 98.336, and some data elements that a reporter
must already use to calculate GHGs as specified in 40 CFR 98.333 were
added to 40 CFR 98.336 for clarity.
3. Summary of Comments and Responses
    No comments specific to regulation of the zinc production sector
were received. We revised the frequency of sampling and analysis of
carbon contents for carbon containing input materials from monthly to
annual consistent with revisions made in response to comments for
similar production processes (e.g., emissions from metal production,
see the preamble Section III.Q for iron and steel for specific
responses to comments). These revisions reduce the reporting burden for
zinc production facilities. We understand that the carbon content of
material inputs does not vary widely at a given facility for the
significant process inputs that contain carbon, and we continue to
account for variations due to changes in production rate, which is
likely a more significant source of variability.

HH. Municipal Solid Waste Landfills

1. Summary of the Final Rule
    Source Category Definition. This source category consists of
municipal solid waste (MSW) landfills that accepted waste on or after
January 1, 1980. The source category includes the MSW landfill,
landfill gas collection systems, and landfill gas destruction devices
(including flares) at the landfill.
    This source category does not include hazardous waste, construction
and demolition, or industrial landfills.
    Reporters must submit annual GHG reports for facilities that meet
the applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.
    GHGs to Report. For MSW landfills, report the following:
     Annual CH4 generation and CH4
emissions from the landfill.
     Annual CH4 destruction (for landfills with gas
collection and control systems).
     Annual CO2, CH4, and N2O
emissions from stationary fuel combustion devices under 40 CFR part 98,
subpart C (General Stationary Combustion Sources).
    GHG Emissions Calculation and Monitoring. All facilities must
calculate modeled annual CH4 generation based on:
     Measured or estimated values of historic annual waste
disposal quantities; and
     Appropriate values for model inputs (i.e., degradable
organic carbon fraction in the waste, CH4 generation rate
constant). Default parameter values are specified for bulk municipal
waste and individual waste categories.
    Facilities that do not collect and destroy landfill gas must adjust
the modeled annual CH4 generation to account for soil
oxidation (CH4 that is converted to CO2 as it
passes through the landfill cover before being emitted) using a default
soil oxidation factor. The resulting value must be reported and
represents both CH4 generation and CH4 emissions.
    Facilities that collect and control landfill gas must calculate the
annual quantity of CH4 recovered and destroyed based on
either continuous or weekly monitoring of landfill gas flow rate,
CH4 concentration, temperature, and pressure of the
collected gas prior to the destruction device.
    Those facilities that collect and control landfill gas must then
calculate CH4 emissions in two ways and report both results.
Emissions must be calculated by:
    1. Subtracting the measured amount of CH4 recovered from
the modeled annual CH4 generation (with adjustments for soil
oxidation using the default value and destruction efficiency of the
destruction device) using the equations provided; and
    2. Applying a gas collection efficiency to the measured amount of
CH4 recovered to calculate CH4 generation, then
subtracting the measured amount of CH4 recovered (with
adjustments for soil oxidation using the default value and destruction
efficiency of the destruction device) using the equations provided.
Default collection efficiencies are specified, based on cover material
and other factors.
    Data Reporting. In addition to the information required to be
reported by the General Provisions (40 CFR 98.3(c)) and summarized in
Section II.A of this preamble, reporters must submit additional data
that are used to calculate GHG emissions. A list of the specific data
to be reported for this source category is contained in 40 CFR part 98,
subpart HH.
    Recordkeeping. In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and

summarized in Section II.A of this preamble, reporters must keep
records of additional data used to calculate GHG emissions. A list of
specific records that must be retained for this source category is
included in 40 CFR part 98, subpart HH.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following
list. The rationale for these and any other significant changes can be
founds below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's
Response to Public Comments, Subpart HH: Landfills.''
     Industrial landfills were removed from the applicability
provisions of 40 CFR part 98, subpart HH. The applicability provisions
were also modified to exempt landfills that did not accept any waste
after January 1, 1980.
     Additional methods for estimating quantities of waste for
prior (historic) years are provided.
     The requirement to continuously monitor CH4
composition in the flare gas was removed. If a continuous monitoring
system is in place, that data must be used, but weekly sampling of the
gas is allowed if such a continuous system is not in place.
     Direct flame ionization methods were added to the rule as
an alternative to the gas chromatographic methods for determining
methane concentrations. To use a direct flame ionization method, a
correction factor must be determined at least once each reporting year
and applied to adjust the analyzer's total gaseous organic
concentration to an unbiased methane concentration.
     More detailed default values are provided for landfill gas
collection efficiencies based on cover material and other factors.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. A large number of comments on landfills were received
covering numerous topics. Responses to significant comments received
can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's
Response to Public Comments, Subpart HH: Landfills.''
Definition of Source Category
    Comment: Several commenters stated that EPA should limit the
applicability of the industrial landfills to landfills located at food
processing, pulp and paper, and ethanol production facilities (some
also listed petroleum refineries) because these are the only industries
for which landfills were specifically called out. Several commenters
noted that impacts were only estimated for pulp and paper and food
processing landfills, so EPA should limit the rule to those industries
or correct the cost analysis to reflect the true burden of the rule on
industrial landfills. Several commenters noted that the reporting
requirements seemed tailored for MSW landfills and were generally
inappropriate for industrial landfills (truck scales, etc.). One
commenter also noted that, if reporting of GHG emissions from
industrial landfills is not limited to the food processing, pulp and
paper, and ethanol production facilities, then EPA should amend Table
HH-1 of 40 CFR part 98, subpart HH and provide specific factors that
are relevant to the regulated industry. Several commenters requested
that EPA specifically exempt inorganic chemical manufacturing and
mining landfills because they do not contain organic waste; other
commenters suggested EPA delete requirements for landfills in 40 CFR
part 98, subpart Y because landfills are insignificant compared to
other sources at a petroleum refinery.
    On the other hand, one commenter suggested that EPA may be
overlooking an important source of methane emissions by excluding
construction and demolition landfills as it seems possible that these
landfills receive organic materials such as wood or yard waste that
could degrade in an anaerobic environment. This commenter requested EPA
provide information on the waste composition of construction and
demolition landfills to explain more fully the basis for its decision
to categorically exempt these sources from GHG reporting requirements.
    Response: At this time, EPA is not going final with the industrial
landfills proposed requirements of this subpart. In response to the
proposal, EPA received numerous detailed public comments on the
preamble, rule and TSDs under 40 CFR part 98, subpart HH. Comments
addressed the appropriateness, coverage, and methodology for addressing
GHG emissions from industrial landfills. In particular, commenters
questioned which industrial landfills should be covered by the rule and
the need for industry specific factors and methodologies for
calculating and reporting emissions. As EPA considers next steps, we
will be reviewing the comments and other relevant information and will
perform additional analysis and consider alternatives to the proposed
monitoring and reporting requirements for industrial landfills.
    With regard to construction and demolition landfills, we note that
the IPCC 2006 Guidelines for National Greenhouse Gas Inventories
estimates that construction and demolition waste has a degradable
organic content (DOC) of 0.04 kg/kg waste (see Table 2.5 in Volume 5:
Waste), and most of this organic matter is expected to be wood, with
slow degradation rates (k=0.02 yr-1). Based on the
anticipated properties of construction and demolition wastes, we
anticipated that methane generation at dedicated construction and
demolition debris landfills would be small compared to MSW landfills.
We will further review these assumptions as we review comments on
industrial landfills.
    Comment: Several commenters stated that the reporting requirements
for closed landfills are burdensome, and the rule should be limited to
reporting for active landfills. Information on waste disposal
quantities and waste composition data are usually not available for
closed MSW facilities. Thus, it is impossible to retain or provide the
agency with such records for many old landfill sites. Several
commenters suggested that EPA should provide additional guidance and
screening tools to identify landfills likely to be below the threshold.
The commenters noted that small and closed landfills have to collect
all of the data needed to report their emissions in order to determine
if they are above the reporting threshold.
    Response: Closed MSW landfills account for approximately half of
the nationwide methane emissions from MSW landfills. This is because
landfills can continue to emit for decades after they are closed and
because these landfills are older, and less likely to have been
required to add landfill gas collection systems. However, we do agree
that we can remove reporting requirements for a subset of closed
landfills to lessen the burden on long-closed landfill facilities. We
evaluated the various landfill characteristics and identified that a
30-year waste-in-place (i.e., the total quantity of waste added to the
landfill in the past 30 years) provided the best correlation of the
data to sites that account for the majority of the contribution to the
nationwide GHG emissions from landfills (see memorandum entitled
``Correlations with Landfill Methane Generation and Actual Emissions''
in the docket EPA-HQ-OAR-2008-0508-2165). Providing an applicability
date for closed landfills is essential to minimize the burden
associated with obtaining data on old landfills that provide only a
small contribution to the nationwide GHG

emissions for landfills, and landfills closed prior to 1980 would not
be relevant for the purposes of policy analyses. Therefore, the final
rule excludes MSW landfills that have not accepted waste since January
1, 1980. We have also expanded and clarified options for projecting
waste disposal quantities that will help ease the burden associated
with calculating emissions from landfills that have closed after 1980.
EPA remains committed to providing additional outreach materials,
guidelines, and screening tools to help potential reporters determine
whether the reporting rule applies to their landfill.
Method for Calculating GHG Emissions
    Comment: Several commenters requested additional guidance on how to
determine waste disposal rates for years prior to the first reporting
year. One commenter noted that the population method provided in the
rule was difficult for many landfills because of contract carriers that
may haul waste to different landfills in different years, so that the
population served by a landfill can be variable. Several commenters
noted that the data needed to estimate waste disposal rates for past
years was especially challenging for closed landfills and requested
guidance on how to comply with the rule if the necessary data do not
exist.
    Response: EPA acknowledges that the single proposed method of
estimating past year disposal rates is limiting and may not provide the
most accurate projection of waste disposal rates in all cases. We have
provided a number of alternative approaches that could be used to
estimate annual waste acceptance rates. These include using the current
year's annual waste acceptance rate for all past years of operation
(for active landfills) and using the landfill capacity and the
operating life of the landfill to calculate an average annual
acceptance rate (for active and closed landfills). These methods
provide a reasonable estimate of historic disposal quantities based on
readily available information, even for older landfills. Furthermore,
these alternative methods may be just as appropriate or more
appropriate for MSW landfills that do not serve a fixed population
area.
    Comment: A few commenters noted that the Solid Waste Industry for
Climate Solution (SWICS) has developed protocols for calculating GHG
emissions from landfills [see paper titled, Current MSW Industry
Position and State-of-the-Practice on LFG Collection Efficiency,
Methane Oxidation, and Carbon Sequestration in Landfills (July 2007)].
The commenters requested that the SWICS recommended defaults for gas
recovery system efficiency, soil oxidation, and flare combustion
efficiency be provided in the rule. They also stated that an accurate
inventory should account for carbon sequestered in the landfill.
    Response: We again reviewed the SWICS methods in light of these
comments. We agree that the SWICS default recommendations for gas
recovery system efficiency (which vary from 60 to 95 percent for
different types of soil covers) could provide more refined data than
using the default values provided in the rule. Therefore, we have
included these cover-specific gas recovery efficiencies (commensurate
with the SWICS Protocol) as an alternative to the 75 percent default
value for collection efficiency. We have also reviewed the SWICS
protocol for soil oxidation, which provides suggested oxidation factors
ranging from 0.22 to 0.55 depending on the soil cover type. We have
several concerns with these factors. First, the values were calculated
using arithmetic means which appear to be biased high due to a few high
oxidation factors; the median values were generally significantly lower
than the average values suggested. Second, the recommended values
included laboratory test values, which always yielded higher oxidation
fractions. The percent of methane oxidized at the landfill surface is
highly dependent on the velocity of gas flow. While areas of low flow
are expected to have significant oxidation, areas of high flow will
have little to no oxidation. Landfill gas will generally flow to the
surface in fissures and channels that offer the least resistance to
flow. Consequently, a significant portion of the landfill gas is likely
to exit the landfill in a limited number of areas under much higher
flow rates than other locations. These high volume flows will not have
significant oxidation. Consequently, field test data tend to show lower
oxidation factors than laboratory tests where flow is more uniform.
Data for five field studies for clay covers (the predominant soil cover
type used in the U.S.) were included in the SWICS report. Four of the
five field studies had oxidation factors ranging from 0.08 to 0.21, and
the median of all five field studies was 0.14. These data appear to
support the default 0.10 oxidation factor as provided in the final rule
more than they do the 0.22 oxidation factor suggested by SWICS. We will
continue to assess the available data to improve soil oxidation
estimates; however, we maintain that the use of the 10 percent default
rate is appropriate for this final rule, and clarify that the site-
specific oxidation factors (based on the SWICS method or other method)
are not to be used. We also find that the SWICS Protocol recommended
flare efficiency of 99.996 percent appears unreasonably high. The
combustion efficiency of flares is very difficult to assess and may be
affected by wind speed and other variables that are not under the
direct control of the landfill owner and operator. Consequently, we
retained the proposed flare efficiency default. Finally, with respect
to the suggested sequestration factors, since collecting data on carbon
sequestration is not the purpose of this rule, we do not require
facilities to calculate or report carbon storage in landfills.
Monitoring and QA/QC Requirements
    Comment: Several commenters stated that EPA's proposal to require
landfills with gas collection systems to continuously measure the
methane flow and concentration at the flare or energy device is
financially burdensome. According to commenters, the capital costs as
well as operation and maintenance costs of a continuous composition
analyzer are prohibitive for many facilities, and EPA underestimated
the number of facilities that would have to install the required
monitors. The commenters also stated that the composition of landfill
gas is not highly variable, so less frequent monitoring is justified.
One commenter noted that the standard operating procedure at many
landfills with gas collection systems is to collect monthly
CH4, flow, and concentration data at the flare. Another
commenter recommended that MSW landfills be allowed to calculate
quarterly, by means of engineering formulae and/or modeling, the amount
of methane present at the flare or energy device. The commenter further
noted that, in many cases, it is not practical or even possible for the
MSW facility to measure the amount of methane or even landfill gas at
the energy device because this device is not owned, operated, or
controlled by the facility. Several commenters also requested that EPA
allow direct flame ionization analyzers in addition to the gas
chromatography methods provided in the proposed rule.
    On the other hand, several commenters suggested that EPA should
allow, require, or otherwise move towards direct measurement
methodologies for characterizing landfill emissions.
    Response: Methane composition of landfill gas can be expected to
vary

based on extreme barometric changes, rainfall event, etc. We expect
diurnal variations as well (although not to the same extent as seasonal
variations). We also expect variations if the gas collection system has
a variable speed fan and the fan speed is adjusted. The commenters
provided no data to support the claim that the anticipated fluctuations
are not significant enough to warrant continuous monitoring. At
proposal, we required continuous flow and composition monitors to
improve the accuracy of the emissions estimate. However, after
additional uncertainty analysis, we determined that the cost of
continuous monitoring systems is not justified in relation to the
relatively small improvement in certainty over somewhat less frequent
monitoring, i.e. weekly. We do require landfill gas collection systems
already equipped with continuous monitoring systems to determine daily
average flow and concentrations and to use these data in their gas
recovery calculations. For collection systems that do not have
continuous gas monitors, weekly sampling is required. Weekly monitoring
provides an adequate number of samples to evaluate the variability and
uncertainty associated with methane generation. We did not select
monthly monitoring because monthly monitoring would result in greater
uncertainty and would not significantly reduce the costs compared to
weekly monitoring.
    We did provide for direct flame ionization analyzers to be used as
an alternative to the gas chromatography methods provided in the
proposed rule. This alternative reduces the burden on landfills that do
not have existing gas chromatography equipment. However, direct flame
ionization analyzers will measure both methane and non-methane organic
compounds and, as such, will tend to overstate the methane
concentration in the landfill gas and provide a high bias to the amount
of methane recovered. To eliminate this bias, we also required a
correction factor that must be determined at least annually, to arrive
at the ratio of the methane concentration to the direct flame
ionization analyzer response (calibrated with methane). Including this
alternative method with the correction factor reduces the burden on
landfills, but still ensures that the calculated methane recovery
quantities are unbiased and comparable to the recovery quantities
calculated when gas chromatographic methods are used to speciate
methane specifically.
    With respect to direct measurement methods, we find that direct
soil measurements have high uncertainties due to heterogeneity of the
landfill and cover soils and are, therefore, less desirable than the
methods provided in the rule (cost more and have higher uncertainty).
Optical sensing methods, while potentially more accurate, are very
expensive. If measurements were done for only a one-time performance
test, the measured emissions would have rather high uncertainties due
to variations in temperature and atmospheric pressure. If the
measurements were conducted more often, they would be prohibitively
expensive. At this time, we cannot justify requiring these types of
monitoring systems for this rule. Furthermore, we find that the
monitoring requirements in the final rule provide for accurate emission
estimates at a reasonable cost burden to reporters.

II. Wastewater Treatment

    At this time, EPA is not going final with the wastewater treatment
subpart (40 CFR part 98, subpart II). As EPA considers next steps, we
will be reviewing the public comments and other relevant information.
Please note, as originally proposed for this rule, centralized domestic
wastewater treatment plants continue to be excluded.
    The Agency received a number of comments regarding the
applicability of this subpart as well as clarification of the
definition of anaerobic wastewater treatment processes. In addition,
commenters requested that EPA consider a de minimus exemption for
emissions from wastewater treatment. The Agency also received a number
of comments requesting redefinition of the monitoring requirements for
this subpart.
    Based on careful review of comments received on the preamble, rule
and TSDs under proposed 40 CFR part 98, subpart II, EPA will consider
alternatives to data collection procedures and methodologies and
examine additional study results that have been released since the
proposal was issued. Specifically, EPA will consider requirements for
the location of meters for taking flow measurements, the frequency of
flow and chemical oxygen demand (COD) measurements taken, as well as
the potential use of alternate parameters, such as BOD. EPA will also
consider the inclusion of indirect or non-methane volatile organic
compound emissions. Lastly, EPA will consider the acceptable methods
for estimating missing data. EPA will consider optimal methods of data
collection in order to maximize data accuracy, while considering
industry burden.

JJ. Manure Management

1. Summary of the Final Rule
    Source Category Definition. A livestock facility that emits 25,000
metric tons CO2e or more per year from manure management
systems must report. A facility with an average annual animal
population below those listed in Table JJ-1 of 40 CFR part 98, subpart
JJ, does not need to calculate emissions or report. A facility with an
average annual animal population that exceeds those listed in Table JJ-
1 should conduct a more thorough analysis to determine applicability.
Average annual animal populations for static populations (e.g., dairy
cows, breeding swine, layers) are estimated by performing an animal
inventory or review of facility records. Average annual animal
populations for growing populations (meat animals such as beef and veal
cattle, market swine, broilers, and turkeys) are estimated using the
average number of days each animal is kept at the facility and the
number of animals produced annually. The rule also contains procedures
for facilities with more than one animal group present (e.g., swine and
poultry) to determine if they must report.
    A manure management system stabilizes or stores livestock manure,
or does both, in one or more of the following system components:
     Uncovered anaerobic lagoons.
     Liquid/slurry systems with and without crust covers
(including but not limited to ponds and tanks).
     Storage pits.
     Digesters, including covered anaerobic lagoons.
     Solid manure storage.
     Drylots, including feedlots.
     High-rise houses for poultry production (poultry without
litter).
     Poultry production with litter.
     Deep bedding systems for cattle and swine.
     Manure composting.
     Aerobic treatment.
    GHG emissions from sources at livestock facilities unrelated to the
stabilization and/or storage of manure are not covered under this rule
and are not reported. Sources considered to be unrelated to the
stabilization and/or storage of manure include daily spread or pasture/
range/paddock systems or land application activities or other methods
of manure utilization not listed above. In addition, manure management
activities located off site from a livestock operation are not included
in this rule. These off site activities include but are not limited to
off site

land application of manure, other off site methods of manure
utilization, or off site manure composting operations.
    Facilities that meet the applicability criteria in the General
Provisions (40 CFR 98.2) summarized in Section II.A of this preamble
must report GHG emissions.
    GHGs to Report. For all livestock facilities with a manure
management system that meets or exceeds the reporting threshold, the
facility must report aggregate CH4 and N2O
emissions from the system components listed above. For those manure
management systems that include digesters, CH4 generated and
destroyed, as well as any CH4 leakage, at the digester must
also be reported.
    A facility that is subject to this rule only because of emissions
from manure management systems is not required to report emissions
under 40 CFR part 98 subparts C through PP other than subpart JJ.
    GHG Emissions Calculation and Monitoring. Detailed methods for
calculating GHG emissions are included in the rule and are briefly
described below. For each manure management system component other than
digesters, facilities must calculate emissions using the following
inputs and data:
     Type of system component.
     Average annual animal population (by animal type)
contributing manure to the manure management system component.
     Typical animal mass (for each animal type).
     Fraction of manure by weight for each animal type managed
in each system component (assumed to be equal to the fraction of
volatile solids/nitrogen handled in each system component).
     Volatile solids excretion rates provided in look-up tables
for the animal populations contributing manure to the manure management
system component.
     Maximum CH4-producing potential of the managed
manure and CH4 conversion factors provided in look-up tables
for the animal populations contributing manure to the manure management
system component.
     Methane conversion factor used (for each manure management
system component).
     Nitrogen excretion rates (by animal type) using values
provided in look-up tables for the animal populations contributing
manure to the manure management system component.
     N2O emission factors (by animal type) provided
in look-up tables for the animal populations contributing manure to the
manure management system component.
    For anaerobic digesters, facilities must calculate CH4
emissions and the annual mass of CH4 generated and destroyed
based on the following inputs and data:
     Continuous monitoring of CH4 concentration,
flow rate, temperature, and pressure of the digester gas.
     CH4 destruction efficiency of the destruction
device and fugitive (leakage) emissions.
     The CH4 collection efficiency(ies) used (for
each digester).
    Data Reporting. In addition to the information required to be
reported by the General Provisions (40 CFR 98.3(c)) and summarized in
Section II.A of this preamble, facilities must submit additional data
that are used to calculate GHG emissions. A list of the specific data
to be reported for this source category is contained in 40 CFR part 98,
subpart JJ.
    Recordkeeping. In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, facilities must keep records of additional data used to
calculate GHG emissions. A list of specific records that must be
retained for this source category is included in 40 CFR part 98,
subpart JJ.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified below. The
rationale for these and any other significant changes can be found
below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response
to Public Comments, Subpart JJ: Manure Management.''
     To assist facilities in determining if they are subject to
this rule, a table has been provided that presents average annual
animal population values for specific livestock operations (i.e., beef,
dairy, swine, and poultry). Facilities that have average annual animal
population values below those shown in the table will not be required
to report or complete the calculations to determine whether they need
to report.
     Since proposal, the requirements for monthly manure
sampling to determine volatile solids (VS) and nitrogen (N) content
have been removed. Instead of obtaining VS and N content from manure
sampling, facilities must use default VS and N excretion values as
provided by EPA in look up tables. The default VS and N excretion
values are consistent with the 1990-2008 U.S. GHG inventory for manure
management and enteric fermentation. For beef and dairy cows, heifers,
and steers, VS and N excretion rates were calculated using the IPCC
Tier II methodology, based on the relationship between animal
performance characteristics such as diet, lactation, and weight gain
and energy utilization. In response to comments, EPA used the most up-
to-date information on U.S. animal diets to calculate these excretion
rates. For other animal groups, reference values from ASAE and USDA are
used.
     EPA has also adjusted the calculations for CH4
and N2O emissions from manure management systems to account
for volatile solids and nitrogen removal through solid separation. If
solid separation occurs prior to the manure management system
component, facilities must use default removal efficiencies as provided
by EPA in look up tables. The default values are consistent with those
cited in the ``Development Document for the Final Revisions to the
National Pollutant Discharge Elimination System Regulation and the
Effluent Guidelines for Concentrated Animal Feeding Operations'' (EPA-
821-R-03-001), published in December 2002.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. A large number of comments on manure management were
received covering numerous topics. Responses to significant comments
received can be found in the comment response document for manure
management in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response
to Public Comments, Subpart JJ: Manure Management.''
    Comment: A number of commenters supported EPA's decision to include
livestock facilities with manure management systems in the proposed
rule. These commenters noted that the establishment of a mandatory GHG
reporting rule is the next logical step in reducing and mitigating GHG
emissions in the U.S., and that manure management is a significant
source of GHG emissions in the U.S. that should be addressed.
    However, other commenters stated that livestock facilities should
not be required to report GHG emissions. These commenters noted that a
small number of facilities would be covered by the proposed rule, and
these facilities would represent a very small percentage of the total
number of livestock facilities in the U.S. which would not provide a
large enough set of data to help improve or reduce uncertainties
associated with GHG inventories. Several of the commenters stated that
manure management is not a major source of GHG emissions in the U.S.,
and the environmental benefits from the rule

would be minimal compared to the effort required to report emissions.
    Response: EPA disagrees that the manure management source category
be excluded from this rule. Manure management has been determined to be
a key source of GHG emissions in the U.S., based on the key source
category methodology developed by the Intergovernmental Panel on
Climate Change (IPCC). The IPCC identifies key sources as those sources
that have significant impacts on the total emissions or emission trends
in a country.
    While livestock manure GHG emissions represent a relatively small
fraction of the total U.S. GHG emissions, these emissions are large in
absolute terms. According to the 2009 U.S. GHG Inventory,
CH4 emissions from manure management systems totaled 44
million metric tons CO2e, and N2O emissions were
14.7 million metric tons CO2e in 2007; manure management
systems account for 7.5 percent of total anthropogenic CH4
emissions and 4.7 percent of N2O emissions in the U.S.
    In addition, the collection of facility level GHG emission data,
including the type of manure management systems in operation and the
number and types of animals serviced by those systems, will help to
inform future climate change policy decisions. While the actual number
of facilities reporting will be quite small in comparison to the total
number of facilities in the U.S., the data gathered through this effort
is valuable. For example, these data will help to improve the
understanding of emission rates and actions that facilities take to
reduce emissions and may improve the effectiveness and design of
voluntary and/or mandatory programs to reduce emissions.
    Comment: Multiple commenters stated that the monitoring
requirements in the proposed rule would be too burdensome and expensive
for industry to comply with. These commenters expressed concern that
sampling manure for VS and N would require more time and effort and be
more expensive than EPA estimated. Multiple commenters suggested that
default values such as from the American Society of Agricultural and
Biological Engineers (ASABE) be permitted for VS and N instead of
measured values to eliminate some of the expense associated with the
proposed rule.
    In addition, a number of commenters noted that there were some
methodological issues associated with the monitoring requirements for
VS and N. Multiple commenters noted that the requirements for manure
sampling should be clarified.
    Response: EPA acknowledges these concerns and has removed the
manure sampling requirements from the final rule. As discussed earlier,
EPA used default values for VS and N excretion from USDA and ASAE for
swine and poultry, and has calculated these rates for beef and dairy
cows, heifers, and steers using the IPCC Tier II methodology, based on
the relationship between animal performance characteristics such as
diet, lactation, and weight gain and energy utilization. The use of
these animal-specific default values for VS and N will greatly reduce
the burden to comply with the reporting rule, while only minimally
impacting the estimates of GHG emissions. The variation in sampling
techniques from facility to facility when characterizing manure ``as
excreted'' from the various animal populations on the facility (as
would have been required by the proposal) would negate the benefit
derived from this requirement. EPA considered designing a more complex
and rigorous program to ensure consistency in the implementation of a
manure sampling program and to ensure that manure samples represented
``as excreted'' manure (prior to any storage or treatment). However,
after reviewing comments, we determined that the expected burden of
such a program, in terms of time, effort, and expense, outweighed the
merits at this time.
    Comment: A number of commenters noted that calculation errors
caused threshold head numbers to be overestimated, which caused the
amount of emissions from these operations and the number of operations
that would need to report to be underestimated.
    Response: To estimate the number of facilities at each threshold,
EPA first developed a number of model facilities to represent the
manure management systems that are most common on large livestock
operations and have the greatest potential to exceed the GHG reporting
threshold. Next, EPA used the U.S. GHG inventory methodology for manure
management to estimate the numbers of livestock that would need to be
present to exceed the threshold for each model livestock operation
type. Finally, EPA combined the numbers of livestock required on each
model operation to meet the thresholds with U.S. Department of
Agriculture (USDA) data on farm sizes to determine how many farms in
the United States have the livestock populations required to meet the
GHG thresholds for each model livestock operation.
    Since proposal, EPA made revisions to the threshold analysis
spreadsheet calculations based on information and data provided by
commenters. EPA corrected conversion factors used in the nitrous oxide
emission calculations, and corrected spreadsheet cell reference errors
along with using updated VS and N values. EPA now estimates that there
will be approximately 107 livestock facilities that will need to report
under the rule.
    Comment: Commenters also expressed concerns with the emission
calculations. Multiple commenters noted that the maximum methane
producing capacity (Bo) values used do not reflect variations in animal
diet. Several commenters had concerns about the methodology used to
estimate the methane conversion factors. In addition, some commenters
suggested that other data sources should be considered, such as the
ASABE manure standards.
    Response: After a thorough review of available information, EPA has
determined that the methodologies and data sources used to calculate
emissions in this rule represent the best available methods and data.
EPA reviewed many protocols and approaches prior to selecting the
proposed methodology. EPA's selected methodology for reporting GHG
emissions (methane and nitrous oxide) associated with manure management
systems is based on EPA's Inventory of U.S. Greenhouse Gas Emissions
and Sinks, as well as the IPCC Guidelines for National Greenhouse Gas
Inventories. These methodologies rely on the use of activity data, such
as the number of head of livestock, operational characteristics (e.g.,
physical and chemical characteristics of the manure, type of management
system(s)), and climate data, to calculate GHG emissions associated
with traditional manure management systems. In addition, the selected
methodology for the reporting rule uses measured values for those
manure management systems (e.g., anaerobic digesters) that collect and
combust biogas.
    EPA considered requiring direct measurement of GHG emissions from
manure management systems, but rejected this approach due to the
extreme expense and complexity of such a measurement program. EPA is
promulgating an approach that allows the use of default factors, such
as a system emission factor, for certain elements of the calculation,
and encourages the use of some site-specific data. The cost of such an
approach is significantly lower than a direct measurement program. In
addition, this approach is consistent with the methods used in offset
programs throughout the world, including the California Climate Action
Registry's (CCAR) Manure

Management Project Reporting Protocol. For these offset programs,
livestock operations are required to complete calculations that
establish their ``baseline'' emissions (prior to the use of a biogas
collection system). These baseline emission calculations use similar
emissions calculations and default values as are in EPA's Reporting
Rule.
    The IPCC guidelines have been established by a recognized panel of
experts and underwent significant peer review prior to their adoption.
In addition, protocols for offset programs, such as CCAR, have gone
through similar public review processes prior to their acceptance and
use.
    Comment: Multiple commenters have requested more detailed look up
tables and a tool to provide more clarity on which facilities are
required to report under the final rule.
    Response: EPA agrees that additional tables and tools would
facilitate compliance with the rule and ease the burden associated with
reporting. In response to the comments, EPA has added a threshold table
to the final rule (Table JJ-1) to help livestock facilities with manure
management systems better determine if they might be subject to the
requirements of the rule. EPA also intends to develop applicability
tools that can assist facilities that could be covered by the rule,
based on table JJ-1 in 450 CFR part 98, subpart JJ, in conducting a
more detailed evaluation. These tools will include detailed look-up
tables showing the estimated livestock head numbers that would be
necessary in order to meet or exceed the threshold and a calculation
tool to assist in performing the calculations in the proposed rule.

KK. Suppliers of Coal

    At this time, EPA is not going final with a subpart for suppliers
of coal. As EPA considers next steps, we will be reviewing the public
comments and other relevant information.
    The Agency received a number of lengthy, detailed comments
regarding the coal suppliers subpart. Commenters generally opposed the
proposed reporting requirements and raised multiple issues with EPA's
legal authority for requiring coal suppliers to report CO2
emissions. Several commenters stated that reporting by coal suppliers
would represent a duplication of the reporting by coal users. For
example, electric utilities and industrial plants, which consume the
vast majority of coal supplied, are already required to report data on
emissions based on their coal purchases. Commenters also stated that
the reporting requirement would entail significant burden and capital
costs to coal suppliers. In most cases, commenters provided alternative
approaches to the reporting requirements proposed by EPA. For example,
commenters suggested that EPA exempt from reporting coal mines that
supply coal to mine-mouth power plants, modify the required coal
weighing and sampling standards, and eliminate the required statistical
correlation between HHV and carbon content.
    Commenters raised other issues regarding the reporting of data such
as concerns that coal suppliers and laboratories could not
realistically purchase and install new coal testing and sampling
equipment and provide training to meet the requirements of the proposed
rule.
    Based on careful review of comments received on the preamble, rule
and TSDs under proposed 40 CFR part 98, subpart KK, EPA will perform
additional analysis and consider alternatives to data collection
procedures and methodologies. These alternatives will provide coverage
of coal supplied, imported, or exported while concurrently taking into
account industry burden.

LL. Suppliers of Coal-Based Liquid Fuels

1. Summary of the Final Rule
    Source Category Definition. This source category consists of
producers, importers, and exporters of products listed in Table MM-1 of
40 CFR part 98, subpart MM that are coal-based (coal-to-liquid
products). A producer of coal-to-liquid products is any owner or
operator who converts coal into liquid products (e.g., gasoline,
diesel) using the Fischer-Tropsch or an alternative process.
    Suppliers of coal-to-liquid products that meet the applicability
criteria in the General Provisions (40 CFR 98.2) summarized in Section
II.A of this preamble must report GHG emissions.
    GHGs to Report. Suppliers of coal-to-liquid products must report
the CO2 emissions that would result from the complete
combustion or oxidation of the coal-to-liquid products.
    Suppliers of coal-to-liquid products are not required to report
data on emissions of other GHGs that would result from the complete
combustion or oxidation of their products, such as CH4 or
N2O.
    GHG Emissions Calculation and Monitoring. For each type of coal-to-
liquid product, suppliers must calculate CO2 emissions that
would result from the complete combustion or oxidation of the coal-to-
liquid products by following the procedures in 40 CFR 98.393.
    Data Reporting. In addition to the information required to be
reported by the General Provisions (40 CFR 98.3(c)) and summarized in
Section II.A of this preamble, reporters must submit additional data
that are used to calculate GHG emissions that would result from the
complete combustion or oxidation of their products. A list of the
specific data to be reported for this source category is contained in
40 CFR 98.386.
    Recordkeeping. In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions that would result from the complete combustion
or oxidation of their products. A list of specific records that must be
retained for this source category is included in 40 CFR 98.387.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following
list. The rationale for these and any other significant changes can be
found below.
     We replaced the procedures and calculations proposed in 40
CFR part 98, subpart LL with references to the 40 CFR part 98, subpart
MM procedures and calculations. As a result of considerable comment and
EPA analysis, 40 CFR part 98, subpart MM procedures and calculations
were significantly updated. Since the procedures and calculations
necessary for sampling, testing, and measuring coal-to-liquid products
are intrinsically linked to the procedures and calculations used for
petroleum products, we concluded that referencing 40 CFR part 98,
subpart MM in 40 CFR part 98, subpart LL would achieve consistency and
completeness.
     We reorganized and updated 40 CFR 98.386 by mirroring 40
CFR 98.396 in order to reflect the updates we made to procedures and
calculations and to assist in EPA data verification.
3. Summary of Comments and Responses
    EPA did not receive any specific comments on proposed 40 CFR part
98, subpart LL (suppliers of coal-based liquid fuels). Changes made to
this subpart were implemented to ensure consistency with changes made
to 40 CFR part 98, subpart MM based on public comments provided and EPA
analysis conducted.

MM. Suppliers of Petroleum Products

1. Summary of the Final Rule
    Source Category Definition. Suppliers of petroleum products consist
of:
     Petroleum refineries that produce petroleum products
through distillation of crude oil.
     Importers who satisfy the same meaning given in 40 CFR
98.6, including any entity that imports petroleum products or NGLs as
listed in Table MM-1 of 40 CFR part 98, subpart MM. Any blender or
refiner of refined or semi-refined petroleum products shall be
considered an importer if it otherwise satisfies the aforementioned
definition.
     Exporters who satisfy the same meaning given in 40 CFR
98.6, including any entity that exports petroleum products or NGLs as
listed in Table MM-1 of 40 CFR part 98, subpart MM. Any blender or
refiner of refined or semi-refined petroleum products shall be
considered an exporter if it otherwise satisfies the aforementioned
definition.
    Suppliers of petroleum products that meet the applicability
criteria in the General Provisions (40 CFR 98.2) summarized in Section
II.A of this preamble must report GHG emissions that would result from
the complete combustion or oxidation of the product(s) they supply.
    GHGs to Report. Suppliers of petroleum products must report
annually:
     CO2 emissions that would result from the
complete combustion or oxidation of each petroleum product and natural
gas liquid produced, used as feedstock, imported, or exported during
the calendar year.
     CO2 emissions that would result from the
complete combustion or oxidation of any biomass co-processed with
petroleum feedstocks at a refinery.
    Suppliers of petroleum products are not required to report data on
emissions of other GHGs that would result from the complete combustion
or oxidation of their products, such as CH4 or
N20.
    GHG Emissions Calculation and Monitoring. Suppliers of petroleum
products must choose one of two methods to calculate CO2
emissions that would result from the combustion or oxidation of each
petroleum product and natural gas liquid:
     Method 1: Use the default CO2 emission factors
provided in the regulations for a given petroleum product or NGL; or
     Method 2: Develop an emission factor for a given petroleum
product or natural gas liquid using direct measurements of density and
carbon share.
    To calculate CO2 emissions that would result from the
combustion or oxidation of biomass co-processed with petroleum
feedstock, reporters must use a CO2 emission factor that is
provided in the regulations for each type of biomass.
    In calculating total CO2 emissions that would result
from the combustion or oxidation of all petroleum products and natural
gas liquids that leave the refinery, refineries must subtract the
emissions from petroleum products and natural gas liquids that enter
the refinery to be further refined or used on site as well as biomass
and biomass-based fuels that are co-processed or blended with petroleum
feedstocks.
    Data Reporting. In addition to the information required to be
reported by the General Provisions (40 CFR 98.3(c)) and summarized in
Section II.A of this preamble, reporters must submit additional data
used to calculate GHG emissions that would result from the complete
combustion or oxidation of the product(s) supplied as well as
information on the characteristics of crude oil used at a refinery. The
specific list of data to be reported for this source category is
contained in 40 CFR part 98.396 and includes information to support the
data verification process.
    Recordkeeping. In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
determine the quantities and characteristics of product(s) reported
under this subpart and to calculate GHG emissions that would result
from the complete combustion or oxidation of the product(s) supplied. A
list of specific records that must be retained for this source category
is included in 40 CFR part 98.387.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following
list. The rationale for these and any other significant changes can be
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's
Response to Public Comments, Subpart MM: Suppliers of Petroleum
Products.''
     We established a reporting threshold for importers and
exporters of 25,000 metric tons of CO2 per year.
     We changed the source category definition of petroleum
refinery for the purposes of 40 CFR part 98, subpart MM to only include
facilities that process crude oil. As such, we are not requiring
reporting from facilities that only handle intermediary petroleum
products.
     We refined the definition of importers and exporters of
petroleum products to clarify reporting requirements for blenders.
     We are not requiring reporters to rely on an exclusive
list of standard methods for the measurement of the quantity of
products or the calibration and recalibration of equipment. Instead,
reporters must use an appropriate standard method published by a
consensus-based standards organization. If no such standard exists,
reporters are allowed to rely on industry standard practices.
     We provide more flexibility in the frequency of equipment
recalibration. Reporters must now comply with the frequency specified
by the manufacturer's directions or the selected quantity measurement
method.
     We removed the option for reporters to directly measure
density but not carbon share under Calculation Method 2. We determined
that using a measured density and a default carbon share factor will
likely adversely affect the accuracy of the calculated emission factor
since the density and carbon share of hydrocarbons are, in the absence
of impurities, correlated.
     We are not requiring reporters to rely on an exclusive
list of standard methods for sampling products, measuring density, and
measuring carbon share under Calculation Method 2. Instead, reporters
must use an appropriate standard method published by a consensus-based
standards organization.
     We added more specific requirements for the frequency of
sampling under Calculation Method 2 and now allow for mathematical
composites of samples in addition to physical composites of samples.
     To ensure consistent accounting of denaturant across
reporters, we are requiring reporters to assume that 2.5 percent of the
volume of any ethanol product that is blended into a petroleum-based
product is a petroleum-based denaturant. See below for further
explanation.
     For bulk NGLs, reporters must calculate the emissions that
would result from the complete combustion or oxidation of the
individual components that constitute the NGL (i.e., ethane, propane,
butane, isobutane, and pentanes plus).
     We updated the definition of petroleum products to be
clear that no petroleum product supplier must report on plastics and
plastic products and that

importers and exporters must report on asphalt, road oil, and
lubricants.
     We updated the default emissions factors based on
technical research since the proposal. We updated certain factors to
correct technical errors and to reflect more recent data. We expanded
the factors to four significant digits to enhance precision. We also
added grade-based sub-categories of finished motor gasoline and
blendstocks, combined diesel and fuel oil categories into ``distillate
fuel'' categories, and added sulfur-based subcategories of distillate
fuel No. 1 and 2 to better distinguish between product categories with
potentially different carbon contents. Full documentation of default
emissions factors can be found in the TSD.
     We updated 40 CFR 98.396. First, we made 40 CFR 98.396
more specific, in some cases breaking up one reporting requirement into
two for clarity. Second, to allow for EPA verification of reporter
calculations, we added reporting requirements for data that a reporter
must already use to calculate GHGs as specified in 40 CFR 98.393
through 98.396. Third, after removing the prescriptive list of
allowable methods, we added data reporting requirements on the method
selected to measure quantity, density, and carbon content and the
method selected to sample in order to track the appropriateness of
these methods.
    We require reporters to assume that ethanol contains 2.5 percent
petroleum-based denaturant because we want to ensure that reporters
account for the CO2 emissions that would result from the
combustion or oxidation of the denaturant. All ethanol that is blended
with petroleum products reported in 40 CFR part 98, subpart MM should
contain more than 1.96 percent petroleum-based denaturant by volume,
per the requirements in 27 CFR Parts 20 and 21 to make ethanol non-
potable. We considered relying on reporters to estimate the percent
volume of denaturant in their products, but we determined that, in many
cases, reporters would not know this information. We have concluded
that 2.5 percent is a suitable assumption for the level of denaturant
since, according to an Internal Revenue Service interpretation of
Section 15332 in the Food, Conservation, and Energy Act of 2008 in
notice 2009-06, ethanol containing greater than 2.5 percent denaturant
by volume would not be eligible for the full value of the Volumetric
Ethanol Excise Tax Credit. There may be cases where ethanol containing
less than 2.5 percent denaturant is blended with petroleum-based
products, but we concluded that it is better to conservatively account
for potential petroleum-based carbon emissions rather than arbitrarily
pick a number between 1.96 percent and 2.5 percent.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. A large number of comments on suppliers of petroleum
products were received covering numerous topics. Responses to
significant comments received can be found in ``Mandatory Greenhouse
Gas Reporting Rule: EPA's Response to Public Comments, Subpart MM:
Suppliers of Petroleum Products.''
Selection of Threshold
    Comment: In the proposed rule, EPA sought comment on whether or not
to establish a de minimis level of imported and exported petroleum
products, either in terms of the quantity of products or the
CO2 emissions associated with the combustion or oxidation of
products, to eliminate any reporting burden for parties that may import
or export a small amount of petroleum products on an annual basis. In
response, EPA received several comments in support of establishing some
type of de minimis value, including a threshold of 25,000 metric tons
of CO2 from the complete combustion or oxidation of all
products from individual importers and exporters. EPA also received at
least one comment in support of establishing a threshold value for
refineries reporting under 40 CFR part 98, subpart MM.
    Response: In today's rule, we are establishing a threshold of
25,000 metric tons of CO2 per year for importers and
exporters of petroleum products and natural gas liquids; the threshold
is based on a calculation of CO2 emissions that would result
from complete combustion or oxidation of the imported or exported
petroleum products and natural gas liquids.
    When we conducted the threshold analysis for the proposed rule, we
estimated from EIA data that 224 companies would be covered in 40 CFR
part 98, MM as importers. Through this analysis, we found that at a
threshold of 25,000 metric tons CO2 per year, 175 importers
and 99.9 percent of total emissions that would result from the
combustion or oxidation of imported products would be covered by the
proposed rule. Therefore, establishing a 25,000 metric ton
CO2 threshold would drop 49 reporters in exchange for a 0.1
percent drop in total emissions. Nonetheless, we decided to propose
reporting for all importers because we felt the reporting burden would
be minimal since importers already report the product quantity data to
other Federal agencies.
    Since proposing the rule, EPA has learned new information, through
comments and research, about importers that could be covered as
reporters under 40 CFR part 98, Subpart MM. EPA may have omitted some
importers of small volumes of petroleum products or natural gas liquids
from our original threshold analysis, due to lack of public data. We
never intended to cover such small volume imports with this rule (e.g.,
importers of non-fossil fuel products that contain small quantities of
petroleum or natural gas liquids, such as butane lighters). Therefore,
for the final rule, EPA concludes that establishing a 25,000 metric ton
CO2 threshold for importers will relieve burden on importers
of insignificant quantities of petroleum products and natural gas
liquids that we never intended to cover with this rule without
significantly diminishing the amount of information received by the
agency. In addition, a 25,000 metric ton CO2 threshold is
consistent with other upstream fuel and industrial gas supplier
thresholds for importers and exporters in today's rule.
    When we conducted the threshold analysis for the proposed rule, we
could not estimate the number of exporting companies that would be
covered in 40 CFR part 98, subpart MM because the necessary data was
not publically available. Nonetheless, we decided to propose reporting
for all exporters because we concluded that the reporting burden would
be minimal given the type of information that exporters must maintain
as part of their normal business operations.
    Since proposing the rule, based on analogous information learned on
importers, EPA has concluded that some exporters of very small volumes
of petroleum products or natural gas liquids could be covered as
reporters under 40 CFR part 98, subpart MM. We never intended to cover
such small volume exporters with this rule (e.g., exporters of non-
fossil fuel products that contain small quantities of petroleum or
natural gas liquids, such as butane lighters). Therefore, for the final
rule, EPA has concluded that establishing a threshold for exporters
will relieve burden on exporters of insignificant quantities of
petroleum products and natural gas liquids that we never intended to
cover with this rule. In today's rule, we have selected a 25,000 metric
ton CO2 threshold because we conclude that it will not
significantly diminish the amount of information received by the
agency;

overall, exports of refined and semi-refined products are lower than
imports, so the threshold adopted for imports will be adequate for
collecting data on exports. In addition, a 25,000 metric ton
CO2 threshold is consistent with other upstream fuel and
industrial gas supplier thresholds for importers and exporters in
today's rule.
    In today's rulemaking, we require all refineries as defined in 40
CFR part 98, subpart MM to report, as was proposed. Our threshold
analysis of refineries in the proposed rule indicated that all
refineries would be covered even if we were to establish a 100,000
metric ton CO2 threshold. Furthermore, we have determined
that all refineries covered by this subpart are already tracking the
necessary data to comply with the reporting requirements so the
requirements would not pose an undue burden.
Monitoring and QA/QC Requirements
    Comment: EPA received several comments that the proposed approach
to determining product quantity was too prescriptive. These comments
indicated that the list of allowable methods and equipment types for
determining the quantity of products in the proposed rule was
incomplete, would result in significant costs for industry, and could
adversely impact the quality of the measurements. Commenters noted that
industry uses a much larger and ever-growing number of industry methods
and equipment types to determine quantity for purposes of product
transfers and financial records, including methods and equipment types
used to comply with Internal Revenue Service, Securities and Exchange
Commission, and Department of Homeland Security's Bureau of U.S.
Customs & Border Protection regulations. Commenters suggested that
EPA's ability to develop and maintain a comprehensive list of methods
would require considerable resources, since companies and consensus-
based standards organizations review quantity measurement methods
regularly to ensure consistency with technological changes and
advancements. Commenters also suggested that methods may improve over
time for certain products as a direct result of this rulemaking.
    Response: In today's rule, we are addressing these concerns by
adopting an approach that recognizes the multitude of appropriate
industry standard methods and practices and leaves open the possibility
that industry may adopt better methods, equipment, and practices over
time to determine quantities of products. EPA is requiring that
petroleum product suppliers use an appropriate standard method
developed by a consensus-based standards organization, when such a
standard method exists. If no such standard method exists, reporters
are allowed to follow industry standard practices. Consensus-based
standards organizations include organizations such as ASTM
International, the American National Standards Institute (ANSI), the
American Gas Association (AGA), the American Society of Mechanical
Engineers (ASME), the American Petroleum Institute (API), and North
American Energy Standards Board (NAESB). Reporters must ensure that all
equipment used for measuring quantity is calibrated and periodically
recalibrated according to the manufacturer's directions or
specifications in the appropriate consensus-based industry standard
method.
    In order to further EPA's understanding of the methods and
equipment that reporters use, and to help us better assess the
appropriateness of the standard methods and industry practices that
individual reporters select, we are requiring that all petroleum
product suppliers report the standard method or industry standard
practice they use to measure each distinct product quantity that they
report to EPA.
    Comment: Several commenters recommended that EPA provide more
flexible approaches to the direct measurement of carbon share and
density under Calculation Method 2. Some noted that the proposed
requirement to test samples at the end of the year could negatively
impact the integrity and quality of those samples. These commenters
suggested that EPA allow reporters to test samples monthly and create a
mathematical composite of these test results at the end of the year.
Some commenters suggested that EPA develop a mechanism whereby
reporters could reduce the frequency of sampling once the reporter
demonstrates that the variability in the density and carbon share of
the product is sufficiently small, and even eliminate direct
measurement requirements and allow reporters to use emissions factors
developed in previous years. We also received comments requesting that
we expand our list of acceptable carbon share measurement methods.
    Response: We have incorporated several of the suggestions to
increase the flexibility of the Calculation Method 2 approach in
today's rule. Reporters are now allowed to test their monthly samples
throughout the year and conduct a mathematical composite of the test
results at the end of the year. We have also expanded the list of
acceptable sampling, density, and carbon share methods to include any
appropriate standard method published by a consensus-based standards
organization.
    We could not determine an adequate approach for allowing reporters
to reduce the sampling frequency of products based on statistical
evidence of low variability in the density and carbon share for a given
product. We want to capture changes in product characteristics over
time and have determined that taking monthly samples of an entire
product category would not be overly burdensome. Furthermore, reporters
are allowed to use default factors under Calculation Method 1 if they
so choose.
Data Reporting Requirements
    Comment: EPA received several comments requesting that we eliminate
reporting requirements related to products that have potentially non-
emissive uses, including plastics and plastic products, petrochemical
feedstocks, petroleum coke sent to landfill, asphalt and road oil, and
lubricants and waxes. One commenter questioned the incongruity in
reporting requirements proposed for refiners, who would report on all
products, and importers and exporters who would not be required to
report on asphalt, road oil, lubricants, waxes, plastics, and plastic
products.
    Response: Today's rule requires reporting on products with
potentially non-emissive uses. Comprehensive upstream data will provide
EPA with a full accounting of the emissions that would result from the
complete combustion or oxidation of all petroleum products and natural
gas liquids introduced into the economy. Furthermore, comprehensive
facility-level data can help us conduct a more robust mass balance
assessment for data verification purposes. While we recognize that
carbon in some petroleum products, such as asphalt, can remain un-
oxidized for long periods, petroleum product supplier cannot always
know with certainty whether or not the carbon in their products will be
released into the atmosphere. Even asphalt can be burned as fuel or
incinerated as waste. In the Inventory of US Greenhouse Gas Emissions
and Sinks, EPA notes several areas of uncertainty surrounding the fate
of carbon in petroleum products including those for which the Inventory
assumes a 100 percent storage factor for the purposes of the national
inventory (e.g., asphalt roofing, asphalt cement,

and asphalt paving materials). As discussed in the proposal, a
comprehensive and rigorous system for tracking the fate of petroleum
products that may have non-emissive uses is beyond the scope of this
rule, and would require a much more burdensome reporting obligation for
petroleum product suppliers and other downstream users of petroleum
products and natural gas liquids. The data reported as a result of this
rulemaking will allow EPA to conduct further research in the future on
the pathways and ultimate fate of products with potential non-emissive
uses.
    It was never EPA's intention to require reporting on plastics and
plastic products, so we made this explicit in the definition of
petroleum products as well as our definition of a refinery in 40 CFR
part 98, subpart MM, which now excludes any facility (e.g. a plastics
manufacturing plant) that does not process crude oil. Any
CO2 emissions that would result from the combustion or
oxidation of plastics and plastic products manufactured in the U.S.
should already be accounted for when a petroleum product supplier
introduces the petrochemical feedstock (e.g., propylene) into the
economy.
    In response to comments on the incongruity of the reporting burden
for refiners compared to importers and exporters, we have reevaluated
the list of petroleum products with potentially non-emissive uses that
importers and exporters do not have to report. In the proposed rule,
this list included asphalt, road oil, lubricants, waxes, plastics, and
plastic products. Our rationale for excluding these products for
importers and exporters was our assessment that there is a much larger
variety of these products entering and leaving the country than is
produced at a petroleum refinery. Upon further consideration, however,
we have concluded that only waxes, plastics, and plastic products would
pose an undue administrative burden on importers and exporters. Waxes,
plastics, and plastic products enter and leave the country in wide-
ranging forms (e.g., cosmetics, candles, lawn furniture, plastic wear)
making it difficult to accurately assess the petroleum-based carbon
content of these products. We have concluded that the types of asphalt,
road oil, and lubricants imported in and exported from the country is
much less variable, and importers already track these products and
report the quantities to EIA. We have also established a 25,000 metric
ton CO2 annual reporting threshold for importers and
exporters in today's rule, which should reduce the number of reporters
and minimize the reporting of products that are imported or exported in
very low quantities. Therefore, we are requiring importers and
exporters to report the volume and CO2 emissions that would
result from the complete combustion or oxidation of the asphalt, road
oil, and lubricants they supply.
    In response to comments that collecting data on products with
potentially non-emissive uses will overestimate actual emissions
released into the atmosphere, EPA has and will continue to characterize
CO2 emissions data reported under 40 CFR part 98, subpart MM
as emissions that would result from the complete combustion or
oxidation of the reported product(s) and not as actual emissions.
    Comment: EPA received many comments urging us to leverage data that
petroleum product suppliers already report to the Energy Information
Administration (EIA) and to follow EIA's data collection procedures and
protocols. For example, one commenter urged EPA to require refiners on
a facility-level and company-wide basis to report to EPA the same level
of information on crude imports and processing that is currently
reported to the EIA and to follow a process similar to the one used by
the EIA; and another commenter urged us to align our reporting
requirements with what the industry is already providing to the EIA.
Some commenters, urged EPA to make use of data already reported to EIA
or other Federal agencies instead of requiring reporting directly to
EPA through this rulemaking. EPA also received comments recommending
that EIA reporting remain separate from the reporting requirements of
this rule.
    Response: In the proposed rulemaking, EPA stated that we
considered, but did not propose, the option of obtaining data by
accessing existing Federal government reporting databases and we sought
comment on this decision.
    In today's rulemaking, we are requiring reporters to report data
directly to EPA. We have determined that in order to collect facility-
level data from refineries (and company-level data from importers and
exporters) that is consistent with other reporters in this rule, in
terms of timing, reporting, and verification procedures, we are not
able to rely upon EIA data. In addition, EIA relies on a number of
legal authorities to pledge confidentiality to statistical survey
respondents for company-level information. Some data are collected with
legal authority from the Confidential Information Protection and
Statistical Efficiency Act of 2002 (CIPSEA), under which reported
information must be held in confidence and must be used for statistical
purposes only. Collection of data directly by EPA in a central system
will allow EPA to electronically verify and publish the data quickly,
to use the information for non-statistical purposes, and to handle
confidential business information in accordance with the CAA (see the
general provisions preamble for addition discussion on CBI). In today's
rulemaking we did not replicate EIA's reporting requirements and
methodologies if we did not consider them sufficient to achieve our
objective, which is to collect comprehensive and accurate data on the
CO2 emissions that would result from the complete combustion
or oxidation of petroleum products introduced into the economy. For
example, we provide a comprehensive list in Tables MM-1 and MM-2 of 40
CFR part 98, subpart MM, according to which reporters must categorize
their products for reporting under today's rulemaking. This list
differs from EIA's list of products, according to which reporters must
report to EIA. Some of the products are the same on both lists (e.g.,
aviation gasoline and kerosene) while some products are classified
differently on one list than on the other (i.e., EPA's list breaks
reformulated gasoline up by summer and winter varieties while EIA
breaks reformulated gasoline up by type of oxygenate blended into it).
We crafted EPA's product list carefully and we feel that each category
has the potential to have a unique carbon share and/or density.
Overall, the items on our list are common products in commerce and are
already tracked by refineries, importers, and exporters. Therefore, we
estimate that the additional burden to comply with this rule will be
minimal.

NN. Suppliers of Natural Gas and Natural Gas Liquids

1. Summary of the Final Rule
    Source Category Definition. Suppliers of natural gas and natural
gas liquids are:
     NGL fractionators, which are installations that
fractionate NGLs into their constituent liquid products: ethane,
propane, normal butane, isobutane or pentanes plus for supply to
downstream facilities.
     Local natural gas distribution companies (LDCs) that own
or operate distribution pipelines that deliver natural gas to end
users. Companies that operate interstate pipelines transmission or
intrastate transmission pipelines are not part of this source category.
    Suppliers of natural gas and NGLs that meet the applicability
criteria in the General Provisions (40 CFR 98.2)

summarized in Section II.A of this preamble must report GHG emissions
that would result from complete combustion or oxidation of products
they supply.
    GHGs to Report. Natural gas fractionators must report
CO2 emissions that would result from the complete combustion
or oxidation of the annual quantities of propane, butane, ethane,
isobutene, and pentanes plus supplied.
    Local distribution companies must report CO2 emissions
that would result from the complete combustion or oxidation of the
annual volume of natural gas distributed to their customers.
    Suppliers of natural gas and NGLs are not required to report data
on emissions of other GHGs that would result from the complete
combustion or oxidation of their products, such as CH4 or
N20.
    GHG Emissions Calculation and Monitoring. Reporters must use one of
two methods to calculate the CO2 emissions that would result
from the complete combustion or oxidation of natural gas supply or NGL
supply:
     One method uses either a measured or default fuel heating
value and either a measured or default CO2 emissions factor.
This method is most appropriate for liquid fuels.
     The second method uses either a measured or default
CO2 emissions factor. This method is most appropriate for
gaseous fuels.
     A NGL fractionator must then follow two additional
equations, if applicable, to subtract the CO2 emissions that
would result from the complete combustion or oxidation of NGL supply
that are double-counted. A LDC must then follow up to four additional
equations, if applicable, to subtract the CO2 emissions that
would result from the complete combustion or oxidation of natural gas
supply that is double-counted.
    Data Reporting. In addition to the information required to be
reported by the General Provisions (40 CFR 98.3(c)) and summarized in
Section II.A of this preamble, reporters must submit additional data
that are used to calculate natural gas or NGL supply. A list of the
specific data to be reported for this source category is contained in
40 CFR part 98, subpart NN.
    Recordkeeping. In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate natural gas or NGL supply. A list of specific records that
must be retained for this source category is included in 40 CFR part
98, subpart NN.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following
list. The rationale for these and any other significant changes can be
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's
Response to Public Comments, Subpart NN: Suppliers of Natural Gas and
Natural Gas Liquids.''
     We changed the source category responsible for reporting
NGL supply in 40 CFR part 98, subpart NN from all natural gas
processors to only facilities that fractionate natural gas liquids.
     We eliminated the requirement to report bulk NGL since NGL
fractionators do not supply bulk NGL.
     We added equations to calculate emissions that would
result from the oxidation or combustion of the following volumes of
natural gas and NGLs because they should be subtracted from the
reporter's total emissions calculation, when applicable: fractionated
NGLs received from other fractionators; natural gas injected for
storage; natural gas delivered to individual customers already
reporting under another Subpart of this rule; and natural gas delivered
by an LDC to another LDC.
     We clarified the points of measurements for reporting
purposes.
     We changed the rule to allow local distribution companies
to use transmission pipeline metered volumes and calculated heating
value where the local distribution companies do not perform their own
measurements.
     We provide flexibility in frequency of equipment
calibration, requiring reporters to comply with standard industry
practices for measurements used for billing purposes as audited under
Sarbanes Oxley regulations.
     We added a procedure for measuring the carbon content of
blends of NGLs since NGL fractionators may supply blends of NGLs.
     We updated 40 CFR 98.406. First, we made 40 CFR 98.406
more specific, in some cases breaking up one reporting requirement into
two for clarity. Second, to allow for EPA verification of reporter
calculations, we added reporting requirements for data that a reporter
must already use to calculate GHGs as specified in 40 CFR 98.403 to 40
CFR 98.406. This includes the addition of reporting requirements for
new calculations introduced in the final rule to prevent supply double-
counting. Third, after removing the prescriptive list of allowed
standards and methods, we added data reporting requirements on the
method selected to measure quantity, HHV, and carbon content. Fourth,
we added a reporting requirement for the quantity of odorized propane.
Fifth, we added data reporting requirements for inputs received by a
NGL fractionator in order to conduct verification using a mass-balance
approach.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. A large number of comments on suppliers of natural gas and
NGLs were received covering numerous topics. Responses to significant
comments received can be found in ``Mandatory Greenhouse Gas Reporting
Rule: EPA's Response to Public Comments, Subpart NN: Suppliers of
Natural Gas and Natural Gas Liquids.''
Definition of Source Category
    Comment: EPA received many comments on the non-emissive use of
natural gas liquids (NGLs). In general, these comments stated that NGLs
such as ethane, butane, and isobutene, are either used as feedstocks in
the petrochemical industry or as blendstocks that are reported by
refineries in 40 CFR part 98, subpart MM, and should not be reported as
though they are completely combusted or oxidized. Several commenters
proposed that odorized propane should be the focus of 40 CFR part 98,
subpart NN rather than all NGLs because odorized propane is the only
NGL that is combusted as fuel.
    Response: Today's rule still requires reporting on all NGL
products, even those with potentially non-emissive uses. Comprehensive
upstream data will provide EPA with a full accounting of the emissions
that would result from the complete combustion or oxidation of all
natural gas liquids introduced into the economy.
    As discussed in the proposal, a comprehensive and rigorous system
for tracking the fate of natural gas liquids that may have non-emissive
uses is beyond the scope of this rule, and would require a much more
burdensome reporting obligation for NGL fractionators and downstream
users of natural gas liquids. Based on the data available today, we do
not believe that a NGL fractionator can know with certainty whether or
not the carbon in their products will be released into the atmosphere.
The data reported as a result of this rulemaking will allow EPA to
conduct further research on the pathways and ultimate fate of NGL and
to refine our understanding of and

policy on products with potential non-emissive uses.
    Therefore, EPA does not concur with the proposal to replace NGL
reporting with propane odorizers. However, EPA concurs that odorized
propane lines up closely with propane combusted downstream, and that
data collection on odorized propane would help EPA decide if and how to
carry out a wide variety of CAA provisions on emission sources, as
authorized broadly under CAA sections 114 and 208. As a result, we have
added reporting requirements on the volume of propane odorized on site
in today's rule.
    We do not concur that products reported under 40 CFR part 98,
subpart NN, such as isobutane to be blended with fuel, will be double-
counted as products reported under 40 CFR part 98, subpart MM. Subpart
MM requires refineries to report all non-crude feedstocks that enter
the facility in order to subtract the emissions that would result from
the oxidation or combustion of those products from their calculations.
Such methodology allows EPA to collect data on the entire petroleum and
natural gas liquids system without any double-counting.
    Finally, in response to comments that collecting data on products
with potentially non-emissive uses will overestimate actual emissions
released into the atmosphere, EPA will continue to characterize
CO2 emissions data reported under 40 CFR part 98, subpart NN
as emissions that would result from the complete combustion or
oxidation of the reported product(s) and not as actual emissions.
    Comment: Many commenters discouraged EPA from requiring reporting
from natural gas processors. In general, these comments stated that