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 §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 calciner (kilns) on each soda ash
manufacturing line.

N2O, and CH4 emissions from fuel combustion at each calciner (kiln)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 calciners (kilns)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 calciner in 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 the comment response document for“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 section40 CFR
98.297 to section40 CFR 98.296, and some data elements that a reporter
must already use to calculate GHGs as specified in section40 CFR 98.293
were added to section40 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 the comment response document for soda ash manufacturing in the
docket (EPA-HQ-OAR-2008-508-XXX).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 mtmetric 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 the rule (40 CFR part
98.290-297), 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 44/12, , 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. ItThe 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 accordingly 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
technical support documentsTSDs under Subpart40 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 the comment response document for“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 section40 CFR
98.317 to section40 CFR 98.316, and some data elements that a reporter
must already use to calculate GHGs as specified in section40 CFR 98.313
were added to section40 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 the comment response document for titanium
dioxide production in the docket (EPA-HQ-OAR-2008-508-XXX).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 is going to
maintainmaintains 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 section40 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 the comment response document for
legal issues.“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 is 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
technical support documentsTSDs 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 kilns 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
futnacefurnace 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 1one percent of the total carbon into
Waelz kiln or electrothermic furnaces.  These materials do not need to
be included carbon mass balance calculations.

Section40 CFR 98.336 was reorganized and updated to improve the
emissions verification process.  Some data elements were moved from
section40 CFR 98.337 to section40 CFR 98.336, and some data elements
that a reporter must already use to calculate GHG'sGHGs as specified in
section40 CFR 98.333 were added to section40 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 sectionSection 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
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 identifiesidentified in the
following list.  The rationale for these and any other significant
changes can be founds below or in the comment response documents for
landfills.“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments, Subpart HH: Landfills.”

Industrial landfills were removed from the applicability provisions of
Subpart40 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 usedin 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 the
comment response document for landfills in the docket
(EPA-HQ-OAR-2008-508-XXX).“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.subpart.  In response to
the proposal, EPA received numerous detailed public comments on the
preamble, rule and technical support documentsTSDs under Subpart40 CFR
part 98, subpart HH.  Comments addressed the appropriateness, coverage,
and methodology for addressing greenhouse gasGHG 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
greenhouse gasGHG 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
greenhouse gasGHG 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 vales, 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 5five field studies for clay covers (the predominant soil cover
type used in the U.S.) were included in the SWICS report.  Four of the
5five field studies had oxidation factors ranging from 0.08 to 0.21, and
the median of all 5five 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 (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 supart.subpart.

Based on careful review of comments received on the preamble, rule and
technical support documentsTSDs 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
VOCvolatile 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.  Reporters must submit annual GHG reports
for facilities A livestock facility that emits 25,000 metric tons CO2e
or more per year from manure management systems and meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.  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.

Feedlots and other drylots.

Drylots, including feedlots.

High-rise houses for poultry production.

Other  (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.  These sources 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 CH4 mass 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 handled by weight for each animal type managed in
each system component (assumed to be equal to the fraction of volatile
solids and /nitrogen handled in each system component).

Estimated annual average volatile solids (VS) value calculated using
values provided in look-up tables.

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 burned digester gas (based on the
manufacturer’s specified efficiency or 99 percent, whichever is
less),destruction device and fugitive (leakage) emissions.

For each manure management system component, calculate N2O emissions
using the following inputs:

Type of system component.

Average annual animal population.

Percent of manure handled in each component.

Estimated annual average nitrogen (N) value calculated using values
provided in look-up tables.

N2O emission factors provided in look-up tables.

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, reportersfacilities 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, reportersfacilities 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 the
comment response document for “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.  As an alternative to 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 arewere 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.  The method used is that outlined by the
IPCC Tier II methodology.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 calculationcalculations for methaneCH4 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 MMS manure management systemcomponent, 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 the
docket (EPA-HQ-OAR-2008-508-XXX).“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 operationssystems 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 United States .S. that should
be addressed.

However, other commenters stated that livestock farms facilities should
not be required to report GHG emissions.  These commenters noted that a
small number of farms facilities would be covered by the proposed rule,
and these farmsfacilities would represent a very small percentage of the
total number of farmslivestock 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.  Emissions from manure management represent
approximately 14% of all agricultural emissions. The 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 quite valuable.  For example, these data will help to improve the
understanding of emission rates and actions that facilities take to
reduce emissions and may potentially improve the effectiveness ofand
design of voluntary and/or mandatory programs designed 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
believes thatused 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
lessenreduce the burden to comply with the reporting rule, while only
minimally impacting the estimates of greenhouse gasGHG emissions.  EPA
also believes theThe variation in sampling techniques from farm facility
to farmfacility when characterizing manure “as excreted” from the
various animal populations on the farmfacility (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 both time, effort, and expense, outweighed the merits at this
time.

Comment:  Some commenters claimed that methodological issues existed
with the estimation of GHG emissions from manure management.  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
calculation methodologies.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 (MCFs).  In
addition, some commenters suggested that other data sources should be
considered, such as the ASABE manure standards.

Response:  EPA has corrected errors in the threshold estimation
calculations in the final rule.

EPA supportsResponse:  After a thorough review of available information,
EPA has determined that the methodologies and data sources that are
being used to calculate emissions in the 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
Intergovernmental Panel on Climate Change (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
greenhouse gasGHG 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 would allowallows the use of default
factors, such as a system emission factor, for certain elements of the
calculation, and encourageencourages the use of some site-specific data
wherever possible.  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, farms 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
technical support documentsTSDs under proposed 40 CFR part 98,
Subpartsubpart 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 N20.

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 Subpart40 CFR
part 98, subpart LL with references to the Subpart40 CFR part 98,
subpart MM procedures and calculations.  As a result of considerable
comment and EPA analysis, Subpart40 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
Subpart40 CFR part 98, subpart MM in Subpart40 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
Subpart40 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 natural gas liquidsNGLs 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 natural gas liquidsNGLs 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 eacha given petroleum product and natural gas liquid 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 as a
feedstock 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 the comment response document for suppliers“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart MM: Suppliers of petroleum products
(EPA-HQ-OAR-2008-508-XXX).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 natural gas liquids (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 section 40 CFR 98.396. First, we made section40 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 section40 CFR 98.393
to section  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 the comment response document for
suppliers“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart MM: Suppliers of petroleum products
(EPA-HQ-OAR-2008-508-XXX).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 subpart40
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 federalFederal 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 Subpart MM40 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 tons 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 the 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 federalFederal 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 Clean Air Act
CAA (see the general provisions preamble for addition discussion on
CBI).  In addition, EPA is collecting data that is not currently
reported to EIA, such as carbon content.

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 the most comprehensive and
accurate carbon data possible on 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., finished aviation gasoline and
kerosene) while some products are classified differently on one list
than on the other (i.e., the EPAEPA’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 the
EPAEPA’s product list carefully and we feel that each category has the
potential to have a unique carbon share and/or density.  Therefore, we
are continuing to require reporting on these products in today’s
rulemaking to meet our objective, even though our list deviates from the
EIA product list in certain cases.  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 would 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:

Natural gas liquids (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 fracionatorsfractionators 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 the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart NN:
Suppliers of Natural Gas and NGLs.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.  See Section 3 for
rationale.

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.  See
Section 3 for rationale.

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 section40 CFR 98.406.  First, we made section 98.39640 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 section40
CFR 98.403 to section40 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. See Section 3 for our rationale of this
decision. 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 the comment response document for
suppliers“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart NN: Suppliers of natural gasNatural Gas and
NGLs in the docket (EPA-HQ-OAR-2008-508-XXX).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 Subpart40 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 Subpart40 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 Sectionssections 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 subpart MM 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
processors do not know the constituents of the gas they process.  They
further stated that since bulk NGLs are often sent from one processor to
another, reporting by processors on bulk NGLs would result in
double-counting of supply.  Ultimately, several commenters were confused
by the multiple definitions provided in the rule for a natural gas
processor and were not clear on the exact covered party in 40 CFR part
98, subpart NN.

Response:  In the final rule, we specify the source category as NGL
fractionators rather than as natural gas processors, and we have removed
the requirement to report bulk NGLs.  To avoid any remaining potential
for double-counting, we provide an equation for a
fractionaterfractionator to subtract from its calculations any NGL
constituents received from other fractionators that would report those
products under this rule.

By requiring reporting from NGL fractionators, we have removed the need
for the term “natural gas processor” in Subpart40 CFR part 98,
subpart NN.  Multiple definitions for this term no long exist in the
rule.

Monitoring and QA/QC Requirements

Comment:  Many commenters interpreted EPA’s measurement and
calibration requirements differently than we intended, and as a result
pressed upon EPA the inability of industry to reasonably meet such
requirements.  Many commenters interpreted that EPA required meter
reading and calibration of every customer meter.  Other commenters
interpreted that EPA required daily measurement totals of throughput.

Response:  In today’s rule, we provide precise language to remove any
confusion about monitoring and quality assuranceQA requirements.  First,
we clarify that the point of measurement for natural gas supply is the
city gate meter.  If the LDC makes its own measurements at the city gate
according to business as usual practices, then it must use its own
measurements.  If not, it must use the delivering pipeline invoices
measurements.  The only exceptions are that the point of measurement for
natural gas delivered to large end-users is the customer meter and the
point of measurement for natural gas stored or removed from storage is
the appropriate storage meter.  However, we clarify that customer meters
and storage meters are not subject to the Subpart40 CFR part 98, subpart
NN calibration requirements.

Second, we clarify that the minimum frequency of the measurements of
quantities of NGLs and natural gas shall be based on the reporter’s
standard practices for commercial operations.  For NGL fractionators the
minimum frequency of measurements shall be the measurements taken at
custody transfers summed to the annual reportable volume.  For natural
gas the minimum frequency of measurement shall be based on the LDC’s
standard measurement schedules used for billing purposes and summed to
the annual reportable volume.  If daily measurements are not standard
practice for a reporter, then that reporter need not conduct daily
measurements.

EPA clarifies in the final rule that customer meters do not face
calibration requirements under Subpart40 CFR part 98, subpart NN.  Other
equipment used to measure quantities must be calibrated prior to their
first use for reporting under this subpart, using a suitable standard
test method published by a consensus based standards organization or
according to the equipment manufacturer’s directions. Such equipment
must also be recalibrated at the frequency specified by the standard
test method used or by the manufacturer’s directions. EPA has
concluded that initial calibration requirements are necessary to ensure
consistency across all reporters and accuracy of data. Since such a wide
variety of calibration methods is allowed and since commenters stated
that industry already calibrates carefully as a result of State Utility
Commission and other regulations, EPA concluded that industry is already
following such calibration requirements for usual business operations.

Data Reporting Requirements

Comment:  EPA received many comments on the requirement for LDCs to
report information on individual customers.  In general, commenters
interpreted the reason for EPA to collect this data differently than was
intended.  Many commented on the CBI nature of customer-specific
delivery information.  Others commented that LDCs do not or may not have
access to the EIA or EPA numbers of their customers.  One commenter told
us that a LDC can only attest to the gas volume delivered through a
single particular meter at a single particular location, which is not
necessarily an individual customer.

Response:  In the final rule, EPA has clarified that an LDC must report
on customers that receive more than 460,000 million standard cubic feet
(Mscf) per year in order to subtract that volume out of its total
calculations.  EPA’s intention is to use this data to remove potential
double-counting and to prevent a LDC from calculating and reporting an
overstated supply volume.  EPA can also use these data to verify that
covered direct emitters are approximately reporting under the rule.  In
response to comments that LDCs do not or may not have access to
customers’ EIA or EPA numbers, we have changed the reporting of this
from required to voluntary, if known.  We have further specified that
LDCs must report large volumes delivered to a single meter rather than
to a particular end-user.

OO.  Suppliers of Industrial GHGs

1.  Summary of the Final Rule

Source Category Definition.  Suppliers of industrial GHGs consist of the
following:

Facilities producing any fluorinated GHG or N2O, except those that
produce only HFC-23 generated as a byproduct during HCFC-22 production.

Bulk importers of fluorinated GHGs or N2O, if the total combined imports
of industrial GHGs and CO2 exceed 25,000 metric tons of CO2e per year.

Bulk exporters of fluorinated GHGs or N2O, if the total combined exports
of industrial GHGs and CO2 exceed 25,000 metric tons CO2e per year.

Suppliers of Industrial GHGs that meet the applicability criteria in the
General Provisions (40 CFR 98.2) summarized in Section II.A of this
preamble must report industrial GHG supply flows.

GHGs to Report.  Suppliers of industrial GHGs must report the amount of
N2O and each fluorinated GHG produced, imported, exported, transformed,
or destroyed during the calendar year.  Importers and exporters of CO2
must calculate and report annual amounts of CO2 according to 40 CFR part
98, subpart PP.

GHG Emissions Calculation and Monitoring.  Suppliers must use the
following methods to calculate annual industrial GHG supply flows:

The mass of each fluorinated GHG or N2O produced must be determined by
measurements of gas production, less the mass of that GHG added to the
process upstream (e.g., where used GHGs are added back to the production
process for reclamation).

The mass of each fluorinated GHG transformed must be determined
considering the mass of fluorinated GHG fed into the transformation
process and the efficiency of that process (as indicated by yield
calculations or quantities of unreacted fluorinated GHGs or nitrous
oxide permanently removed from the process and recovered, destroyed, or
emitted).

The mass of each fluorinated GHG destroyed must be determined by
measurements of the mass of fluorinated GHG fed to the destruction
device and a measurement of the destruction efficiency.

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 industrial GHG supply flows or that can be used to
verify industrial gas supply flows.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart OO.

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
OO.

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 the comment response document for industrial gas
supply.“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart OO: Suppliers of Industrial GHGs.”

EPA has elaborated on the definition of "produce" to clarify what it
does and does not include.  The definition now explicitly includes (1)
the manufacture of a fluorinated GHG for use in a process that will
result in the transformation of that GHG (either at or outside of the
production facility) and (2) the creation of a fluorinated GHG (with the
exception of HFC-23) that is captured and shipped off site for any
reason, including destruction.  The definition now explicitly excludes
the creation of by-products that are released or destroyed at the
production facility.

EPA has eased the accuracy and precision requirements for measuring
production, transformation, and destruction.  EPA is also permitting
facilities flexibility in the frequency of measurements and calibration
of measurement devices.  Masses produced, fed into transformation
processes, and fed into destruction devices must now be estimated to a
precision and accuracy of one percent rather than 0.2 percent.
Requirements to measure concentrations, which had previously been
associated with the transformation and destruction provisions, have been
changed to requirements to estimate concentrations or related
quantities.

EPA has eliminated the requirement that fluorinated GHG production
facilities that destroy fluorinated GHGs annually verify the
DEdestruction efficiency of their destruction devices.

EPA has added an additional method for estimating missing mass flow data
in the event that a secondary mass measurement for that stream
isn'tisn’t available.  In that event, producers can use a related
parameter and the historical relationship between the related parameter
and the missing parameter to estimate the flow.

EPA has removed the option for reporters to develop their own methods
for estimating missing data if they believe that the prescribed method
will over- or under-estimate the data.

EPA has added some reporting requirements to be consistent with the
changes to the calculations and monitoring sections and to permit
verification of emissions calculations.

EPA has added an exemption from reporting requirements for import or
export shipments containing less than 250 metric tons of CO2e.

EPA has clarified that the criteria for imported container heels at
paragraph 98.417(e) set forth the conditions under which importers do
not need to report heels; they do not establish requirements for all
containers containing residual gas.  If importers import containers with
residual gas that does not meet these conditions, they must simply
report these imports under paragraph 98.416(c).  In addition, EPA is
adding another condition under which imported heels do not need to be
reported; that is the case in which the heels are recovered and included
in a future shipment.

EPA is requiring fluorinated GHG production facilities to submit a
one-time report describing current measurement and estimation practices.

EPA is requiring the one-time report on measurement practices because
the Agency is providing some flexibility to reporters regarding the
methods that they use to calculate industrial gas supply flows.  This
flexibility permits reporters to use a larger range of methods and
measurement equipment than were proposed, and it is important for EPA to
understand the methods and equipment and their accuracies.  Similar
reports are required under EPA’s Stratospheric Ozone Protection
Regulations at 40 CFR part 82.

As noted above, EPA removed the option for reporters to develop their
own methods for estimating missing data if they believe that the
prescribed method will over- or underestimate the data.  EPA removed