the reporter must use the CEMS and follow the Tier 4 methodology (in 40
CFR part 98, subpart C) to measure and report under the Lead Production
subpart (40 CFR part 98, subpart R) combined process and combustion CO2
emissions.

For other affected smelting furnaces, the reporter can elect to either
(1) install and operate a CEMS and follow the Tier 4 methodology to
measure and report combined process and combustion CO2 emissions or (2)
calculate annual process CO2 emissions using a carbon mass balance
procedure specified in 40 CFR part 98, subpart R.  If using approach
(2):

Calculate emissions once per year using recorded monthly production data
and the average carbon content for each smelting furnace input material
determined by either using material supplier information or by annual
analysis of representative samples of the material.

Report process CO2 emissions from each smelting furnace under 40 CFR
part 98, subpart H (Cement Production), and report combustion CO2
emissions from each kiln 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 R.

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
R.

2.  Summary of Major Changes Since Proposal

The major changes to the rule since proposal for lead production
facilities were revisions to the carbon mass balance calculation
procedure used by reporters for calculating process CO2 emissions from
affected smelting furnaces.  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 R: Lead Production.  These changes
include:.”

The frequency of performing the carbon mass balance calculations was
revised to be required on an annual basis instead of the proposed
monthly basis.

The frequency of material carbon content sampling and analysis of each
smelting furnace input material used for the carbon mass balance was
revised to be performed by annual analysis of representative samples of
the material instead of the proposed monthly basis.

A de minimis carbon content level was added to exclude the need to
account for carbon-containing materials contributing less than
1one percent of the total carbon into the smelting furnace in the
carbon mass balance calculations.

Data reporting procedures (Section40 CFR 98.186) were  reorganized and
updated to consolidate and clarify the emissions verification process.
Some data elements for the carbon mass balance calculation were moved
from section40 CFR 98.187 to section40 CFR 98.186, and some data
elements that a reporter must already use to calculate GHGs as specified
in section40 CFR 98.183 were added to section40 CFR 98.186 for clarity.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses
specific to the lead production source category.  Comments were received
from one commenter regarding several topics.  Responses to significant
comments received are presented in the comment response document for
lead production in the docket (EPA-HQ-OAR-2008-508-XXX).“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart R: Lead Production.”

Selection of Threshold

Comment:  The commenter stated that Lead Production is not a source of
significant GHG emissions and that EPA cannot assert that the Lead
Production sector is a significant part of the stationary source
combustion sector.  The commenter notes that based on EPA'sEPA’s
estimates in the TSDs for the proposal, estimated emissions from the
Lead Production sector are 0.02% percent of the total estimated
nationwide emissions from stationary fossil fuel combustion.  Moreover,
they argue that the combustion-related emissions from lead production
are overstated by incorrect assumptions in the TSD.  The commenter
states that given Lead Production’s relative contribution, it is not a
significant source of emissions and should be eliminated from further
consideration.  The commenter further states that Lead Production is the
only category evaluated where raising the threshold to the 100,000 ton
level would results in zero facilities being covered.  Accordingly, when
the analysis shows that all facilities in a particular source category
are not covered at the 100,000 ton threshold level, no insignificant GHG
emitters in the category should be required to report under the Proposed
Rule.  The commenter noted that using the 100,000 threshold would not
significantly reduce the coverage of emissions of EPA'sEPA’s rule, as
the majority of sources identified would still have well over 90%
percent of emissions from that source category covered under the 100,000
threshold.  EPA provides no justification for imposing substantially
more costs on industry for limited estimated benefits and small
likelihood for regulation under the CAA.  For these reasons, the Lead
Production sector should be eliminated as a source category, and EPA
should raise the threshold to 100,000 for non-source category
facilities.

Response:  We acknowledge this comment and concerns; however the final
rule retains the applicability requirement for this source category.  To
balance the burden for lead producers, we did apply a We used
information available to us for estimating GHG emissions from this
industry which involved several assumptions related to the emission
factors in the IPCC Guidance and other sources.  As noted by the
commenter, many of the underlying assumptions were based on an
international perspective as opposed to the primary and secondary lead
production industry in the U.S.  The final rule contains a threshold of
25,000 metric tons CO2e and only lead production facilities with
emissions that equal or exceed 25,000 metric tons CO2e will have to
report emissions.  In addition, the final rule now contains a provision
provisions allowing a reporter to cease reporting if the annual reports
for a given facility demonstrate emissions less than 25,000 metric tons
CO2e per yearspecified levels for 5 consecutivemultiple years.  This
provision applies to These provisions apply to all reporting facilities,
including those with lead production processes.  See Section II.H of
this preamble for the response on provisions to cease reporting.

We have further simplified the reporting requirement to further reduce
burden for lead and similar industries by requiring annual as opposed to
monthly sampling of carbon inputs.  The purpose of this rule is to
collect information on emissions sources for future policy development.
Requiring reporting for these sources will provide EPA with valuable
data to better characterize them and provide a more credible position if
EPA elects to exclude these sources from future GHG policy analyses.
Additionally, while some of these sources are currently believed to be
small compared to the larger sources, they are not necessarily
insignificant.  The inclusion of reporting data for these sources is
critical to support analysis of future policy decisions for lead
production facilities.

When evaluating potential thresholds for reporting GHG emissions, we
considered several thresholds between 1,000 and 100,000 metric tons
CO2e.  We selected the 25,000 metric tons CO2e threshold for reporting
GHG emissions in order to achieve a balance between quantifying the
majority of the emissions, while minimizing the number of facilities
impacted.  For example, at a 1,000 metric tons CO2e threshold, 99
percent of emissions would be covered, with about 63 percent of
facilities being required to report.  The 100,000 metric tons CO2e
threshold captures no emissions or facilities while the proposed 25,000
metric tons CO2e threshold achieves reporting of 92 percent of the GHG
emissions while requiring less than 50 percent of the facilities to
report.  We consider this a significant coverage of the emissions, while
impacting a relatively small portion of the industry.  We believe the
proposed threshold of 25,000 metric tons CO2e represents the best option
for ensuring that the majority of emissions are reported without
imposing an unreasonable burden on the industry.  Also see also the
preamble and separate comment response document volume for the response
on selection of the threshold.See also Section II.E of this preamble and
“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to Public
Comments, Selection of Reporting Thresholds, Greenhouse Gases, and De
Minimis Provisions.”

Method for Calculating GHG Emissions

Comment:  The commenter made several comments regarding the proposed
procedures used to calculate process CO2 emissions from smelting
furnaces at secondary lead smelters.  First, use of default emission
factors should be allowed as a calculation method alternative because
the smelting furnaces operated at used lead battery recycling facilities
consistently process furnace feed materials with low carbon content
variability. For affected sources using the carbon mass balance
procedure, the frequency required for monitoring carbon content of the
smelting furnace input materials should be reduced to reflect
consistency and low carbon content variability of these materials.

Response:  We decided not to finalize the proposal using methodologies
for calculating CO2 emissions from lead production that relied on
published default emission factors or default values for carbon content
of materials because the differences among individual lead production
facilities could not be discerned using these factors.  Consequently,
the available default factors for lead production facilities are
inherently less accurate for calculating smelting furnace process CO2
emissions than using procedures that include use of site-specific
material carbon data.  Default approaches do not provide site-specific
estimates of emissions that reflect differences in use of and
variability in feedstocks, variability in fuels, operating conditions,
fuel combustion efficiency, and other differences among facilities.  For
some carbon-containing input materials, such as lead scrap,
representative published defaults do not exist.  Therefore, the use of
default values is more appropriate for sector wide or national total
estimates from aggregated production data for multiple facilities rather
than for providing an accurate representation of CO2 emissions from a
specific facility.

For the final rule, we did reduce the monitoring frequency for
determining carbon contents of the smelting furnace input materials used
for the carbon mass balance to be determined on annual rather than
monthly basis. Facilities can determine carbon contents either by using
material supplier information or by annual analysis of representative
samples of the input materials.  We agree that the carbon content for
the significant input materials typically does not vary widely at a
given lead production facility.  Annual carbon content determinations
will still provide representative carbon content data for the smelting
furnace process CO2 emissions calculations while minimizing the
monitoring burden reporters.  We continue to account for process
variations due to changes in production rate, which is likely a more
significant source of variability in the CO2 emissions from an affected
smelting furnace during the year, by maintaining the requirement to
measure and record monthly carbon containing input materials.

S.  Lime Manufacturing

1.  Summary of the Final Rule

Source Category Definition.  Lime manufacturing plants (LMPs) engage in
the manufacture of a lime product (e.g., calcium oxide, high-calcium
quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime,
dolomitic hydrate, or other products) by calcination of limestone,
dolomite, shells or other cacareous substances.  This source category
includes all LMPs unless the LMP is located at a kraft pulp mill, soda
pulp mill, sulfite pulp mill, or only processes sludge containing
calcium carbonate from water softening processes.

Lime kilns at pulp and paper manufacturing facilities need to report
emissions under 40 CFR part 98, subpart AA (Pulp and Paper
Manufacturing).

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 and meet the definition of
lime manufacturing plants in 40 CFR 63.7081(a)(1).

GHGs to Report.  For lime manufacturing, report the following emissions:

Total CO2 process emissions from all lime kilns combined.

CO2 combustion emissions from each lime kilns.

N2O, and CH4 emissions from fuel combustion at each kiln 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 kilns under 40 CFR part 98, subpart C (General Stationary Fuel
Combustion Sources).

CO2 collected and transferred off site under subpart 40 CFR part 98,
subpart PP (Suppliers of CO2),

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 kilns,
facilities must use one of two methods, as appropriate:

Kilns withIf all lime kilns at a facility have certain types of CEMS in
place, the reporter must use the CEMS and follow the Tier 4 methodology
(in 40 CFR part 98, subpart C) to measures and report under the Lime
Manufacturing subpart (40 CFR part 98, subpart S) combined process and
combustion CO2 emissions.

For otherIf CEMS meeting the specifications above are not in place for
all kilns at the facility, , the reporter can elect to either (1)
install and operate a CEMS and follow the Tier 4 methodology to measure
and report combined process and combustion CO2 emissions from all lime
kilns or (2) calculate CO2 process emissions for each lime type using an
emission factor for each lime type, the mass of lime produced, an
emission factor for byproduct/waste (such as lime kiln dust and scrubber
sludge), and the mass of byproduct/waste.  If using approach (2):

Each emission factor must be determined monthly for each lime type from
monthly measurements of the calcium oxide and magnesium oxide content of
the lime and stoichiometric ratios of CO2 to each oxide in the lime.

The emission factor for each lime byproduct/waste sold (such as lime
kiln dust) must be determined monthly.

The emissions from lime byproducts/wastes that are not sold (such as
lime kiln dust and scrubber sludge) must be determined annually.

The mass of each lime type produced and lime byproduct/waste sold (such
as lime kiln dust) must be recorded on a monthly basis.

The mass of each lime byproduct/waste not sold (such as lime kiln dust
and scrubber sludge) must be recorded annually.

Report process CO2 emissions from all kilns combined under 40 CFR part
98, subpart S (Lime Manufacturing), and report combustion CO2 emissions
from kilnseach kiln 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 S.

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
S.

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 S: Lime
Manufacturing.”

The definition of lime manufacturing was revised to be similar to the
definition in the Lime NESHAP at §§63.7081(a) and (a)(1).

Reporting requirements were revised from a “per kiln” basis to
“all kilns combined”.

The emissions calculations were revised to determine monthly emissions
factors for each lime type and byproduct/waste type rather than for each
kiln.

Emission calculations for byproducts/wastes were added.

The requirement to measure the calcium oxide and magnesium oxide content
of byproducts/wastes on a monthly basis was changed to an annual basis
for byproducts/wastes that are not sold.

The correction factor for byproducts/wastes was removed from the rule.

Additional direct measurement devices/methods are being allowed to
include those currently in use by the industry.

Section40 CFR 98.196 was reorganized and updated.  Some data elements
were moved from section40 CFR 98.197 to section40 CFR 98.196, and some
data elements that a reporter must already use to calculate GHGs as
specified in section40 CFR 98.193 were added to section40 CFR 98.196 for
clarity.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
A large number of comments on lime manufacturing were received covering
numerous topics.  Responses to significant comments received can be
found in the comment response document for lime manufacturing in the
docket (EPA-HQ-OAR-2008-0508-XXX).Responses to significant comments
received can be found in “Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart S: Lime Manufacturing.”

Definition of Source Category

Comment:  Multiple commenters requested more clarification in defining
which sources and equipment are covered by the proposed rule.
Currently, the The rule defines the source category as a facility that
contains “a rotary lime kiln to produce a lime product,” and other
equipment covered is referred to as “any other stationary
equipment”..” In addition, proposed 40 CFR 98.192(b) required
sources to report emissions from “each lime kiln and any other
stationary combustion unit.”

Response:  We have reviewed the rule language and decided the source
category definition should provide more clarity.  The source category is
meant to include all kiln types used in the lime manufacturing industry;
therefore, language in the final rule has been changed to be similar to
the definition from the Lime NESHAP sectionsin 40 CFR 63.7081(a) and
(a)(1).  This Lime NESHAP effectively characterizes lime plants as those
engaging in the manufacture of a lime product by calcination.  The final
rule requires all stationary combustion units to report under 40 CFR
part 98, subpart C of the final rule.

Final rule language under 40 CFR 98.192 requires facilities to report
CO2, CH4, and N2O emissions from kilns used in the lime manufacturing
process and all other combustion units at the lime manufacturing
facility other than kilns.  The language has also been clarified in 40
CFR 98.193.  Facilities using CEMS for all lime kilns report combined
process and combustion emissions from kilns under 40 CFR part 98,
subpart S, according to the Tier 4 methodology in 40 CFR part 98 subpart
C (General Stationary Fuel Combustion Sources).  Facilities must follow
the requirements of subpart C for estimating and reporting combustion
related emissions for all other combustion units and report these
emissions under subpart C.  See Section III.C of this rule.preamble for
an overview of the requirements for stationary combustion units.

Selection of Proposed GHG Emissions Calculation and Monitoring Methods

Comment:  Multiple commenters requested the language in 40 CFR part 98,
subpart S be changed to allow emissions to be reported by “all kilns
combined” instead of the proposed rule’s request to report emission
for each kiln.  Multiple commenters further recommended that the process
emissions calculations be changed to calculate emissions by the lime
type produced as opposed to the current rule calculations which use a
kiln specific emission factor.  Two commenters stated that lime products
are commonly aggregated at the plant making it difficult to estimate the
amount of product produced at an individual kiln.  These commenters
stated that current lime plant configuration do not allow accurate kiln
specific calculations.

Response:  We have reviewed the common lime plant configuration and the
currently proposed rule language and have decided that it is not
necessary to require kiln-specific emissions reporting, as emission
factors are determined in the proposed rule by lime type.  Some.  We
have observed that some kilns would have to retrofit weigh belt scales
in the production line between kilns and storage silos, since they do
not currently exist.  Calculating emissions by kiln could increase the
reporting burden for these facilities.  According to one commenter, when
kiln-specific emissions have been reported in the past, the data are
usually derived by distributing the aggregated emissions among the
kilns.  Accurate measurements at the kiln level are rarely
used.achieved.  If this is true for most lime manufacturing facilities,
the data does not necessarily provide a better estimate of emissions.

For the purposes of this rulemaking, reporting for all kilns combined
will simplify and minimize the reporting burden without significant loss
in accuracy because: (1) kilns may produce more than one type of lime in
a given reporting period, (2) emission factors are based on lime type,
and (3) lime plants collect products in combined bagging areas
(separated by lime type).  The final rule language has been changed to
require reporting by lime type from all kilnkilns combined rather than
all lime types for each kiln.  This final rule language is consistent
with the National Lime Association (NLA) Protocol, which was used as the
basis for the methodology in the proposed rule.  Information collected
under this rule will help to inform future methodologies and determine
whether kiln level reporting could be more appropriate for future
reporting.

Comment:  The proposed rule used a default correction factor in
calculating lime product and byproduct/waste emissions.  Multiple
commenters suggested using the National Lime Association Protocol to
determine lime product and by-product/waste process emissions.
According to the commenters, this method is more precise due to the use
of measured oxide values and stoichiometrystoichiometric ratios rather
than correction factors.

Response:  We have reviewed the proposed rule and NLA Protocol
calculation methods and noted that the use of actual oxide measurements
in calculating emissions from lime plants does not cause an additional
burden to the reporter andsince this is a currently used practice.  We
also agree that the use of actual measurements is more accurate.
Therefore, we have decided to remove the use of a correction factor in
the final rule equations; emissions will be calculated from actual oxide
measurements of each type of lime and calcined byproducts/wastes.

Monitoring and QA/QC Requirements

Comment:  Multiple commenters asked that the language pertaining to
allowable measurement devices for lime products and byproducts/wastes
sold, be changed to include measurement devices commonly used in the
lime industry.  The current rule language requires weigh hoppers and
belt weigh feeders as the measurement devices; the aforementioned
commenters have identified bag, truck and rail scales as reliable
(annually calibrated) direct measurement methods commonly used in the
lime industry.  In addition, commenters have requested lime
byproducts/wastes not sold be calculated by a facility generation rate.

Response:  After reviewing the rule language and common industry
practices, we have decided to include other direct measurement devices
used for accounting purposes, including but not limited to, weigh
feeders, calibrated bag, rail or truck scales, and barge measurements.
These methods are consistent with the original intent of the rule and
add further clarification on measurement methods applicable to determine
quantities of both lime produced and byproducts/waste generated.

In addition, reporters are required to perform an annual cross check by
measuring lime products at the beginning and end of the year.  For
calcined byproducts/wastes not sold, a material balance approach that
indirectly measures the generation rate should be used.

Comment:  Multiple commenters asked that the language in 40 CFR part 98,
subpart S pertaining to testing the chemical composition of each type of
lime (including the byproducts and waste) be changed to allow testing by
onsite lab facilities.  Currently the rule specifies an “off-site
laboratory analysis” but according to the commenter, commercial lime
plants normally have onsite lab facilities.

Response:  We agree that the analysis does not have to be performed by
an independent certified laboratory, especially since we specify the
analytical procedures that must be used by any laboratory, and we note
that in-house laboratories may have more applicable experience in
determining chemical composition.  Reporters can determine whether to
perform the test onsite or send the samples to offsite laboratory
facilities.  Therefore the language in the final rule has been changed.

Data Reporting Requirements

Comment:  Multiple commenters requested the language in 40 CFR part 98,
subpart S pertaining to reporting information to EPA be changed so that
business sensitive information is kept in company records.  Commenters
argueagree that while the production capacity, product
quantityproductquality (i.e., oxide content), emission factors and
operating hours and days for each kiln, are required for emissions
calculations but are concerned that making this information public,
would give information about their efficiency, productivity and capacity
of kilns and facility.

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 for legal issues.  Also, see Section II.N
of this preamble for the response to comments on the emissions
verification approach.

We agree that annual operating hours and capacities are not used in the
calculation of CO2 emissions and these parameters have been moved to
recordkeeping.  This information can help to verify anomalies in
emissions data if there were temporary shutdowns, etc.

We disagree that emission factors and product quantityquality be
maintained as records rather than be reported.  Emission factors and
product quantityquality are used in calculations to establish the site
specific rate of CO2 emissions generated for each type of lime produced.
 Therefore these data are required in order to verify the CO2 emissions
that are being reported.  This internal verification system ensures that
the GHG emissions reported are as accurate as possible.

T.  Magnesium Production

At this time EPA is not going final with the magnesium production
subpart (40 CFR part 98, subpart T).  For the immediate future, EPA
believes that emissions of greenhouse gasesGHGs from magnesium
production are sufficiently covered by the reporting requirements under
Subpart40 CFR part 98, subpart OO for Industrial Gas Supply.  This
information on U.S. production, imports, and exports of SF6 will provide
at least a general, order-of-magnitude check on consumption of SF6 by
magnesium production and other uses of SF6.  EPA will finalize the
proposed reporting requirements for the magnesium production industry at
a later date.

U.  Miscellaneous Uses of Carbonate

1.  Summary of the Final Rule

Source Category Definition.  The Miscellaneous Uses of Carbonate source
category consists of any facility that uses carbonates listed in Table
U-1 of 40 CFR part 98, subpart U in manufacturing processes that emit
carbon dioxide.  The Table includes the following carbonates: limestone,
dolomite, ankerite, magnesite, siderite, rhodochrosite, or sodium
carbonate, or any other carbonate in a manufacturing process that emits
carbon dioxide.

. Facilities are considered to emit CO2 if they consume at least 2,000
tons per year of the carbonates listed above and that are heated to a
temperature sufficient to allow calcination to occur.

This source category does not include facilities processing carbonates
or carbonate containing minerals consumed for producing cement, glass,
ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and
paper, soda ash, sodium bicarbonate, sodium hydroxide or zinc as CO2
emissions from these processes are covered elsewhere in the this rule.

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 miscellaneous uses of carbonates, report the
following emissions:

Annual CO2 process emissions for all miscellaneous uses of carbonates as
specified in this subpart.

CO2, N2O, and CH4 emissions from carbonates used in sorbent technology
and each 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.  Calculate process CO2
emissions using annual carbonate consumption.  All reporters must
calculate the annual mass of carbonates used in processes which are
heated to temperatures that allow calcination.  If the annual amount of
carbonates consumed is greater than 2,000 tons, CO2 emissions must be
calculated using either calcination fractions or the actual mass of
input/output carbonates.

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 U.

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 analyses and calculations
required for this source category.

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 U:
Miscellaneous Uses of Carbonates.”

The source category definition was revised to exclude non-emissive uses
of carbonates.

A de minimis reporting threshold was added to exclude facilities with
minor emissions based on annual carbonate consumption.

The GHG calculation methodology was changed to allow reporters to
determine emissions from the mass of carbonate input/output or
calcination fractions.

To improve the emissions verification process, 40 CFR 98.216 was
reorganized and updated.  Some data elements were moved from section40
CFR 98.217 to section40 CFR 98.216, and some data elements that a
reporter must already use to calculate GHG as specified in section40 CFR
98.213 were added to section40 CFR 98.216 for clarity.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
A large number of comments on miscellaneous uses of carbonates were
received covering numerous topics.  Most comments requested
clarification on the definition of the source category and its
applicability to affected sources.  Responses to significant comments
received can be found in the comment response document for miscellaneous
uses of carbonates in the docket (EPA-HQ-OAR-2008-0508-XXX).Responses to
significant comments received can be found in “Mandatory Greenhouse
Gas Reporting Rule: EPA’s Response to Public Comments, Subpart U:
Miscellaneous Uses of Carbonates.”

Definition of source category

Comment:  Multiple commenters requested that the source category be
revised to exclude non-emissive uses of carbonates.  Commenters stated
that the source category is poorly defined, making it difficult to
accurately assess its applicability to an industrial facility.
Commenters noted a number of non-emissive uses as examples, such as the
production of sodium bicarbonate and sodium hydroxide, during which
sodium carbonates are used, but no carbon dioxide is released; onsite
mixing of processed cement with aggregate, limestone used in poultry
grit and as an asphalt filler; or adding sodium carbonate to a water
softener system.

Response:  The rule language has been modified to exclude non-emissive
uses of carbonates.  Non-emissive uses do not result in CO2 emissions,
such as adding sodium carbonate to a water softener system.
Acid-induced releases of CO2 from the use of carbonates are addressed in
other subparts, where they are significant, such as Phosphoric Acid
Production.

Selection of Threshold

Comment:  Multiple commenters requested that a de minimus reporting
threshold be added to exclude facilities with minor emissions.  One
commenter noted that some facilities use limestone and other carbonate
as refractory in furnaces, and it is unclear whether or not this use of
carbonates triggers 40 CFR part 98, subpart U, and at what level it is
triggered.

One commenter noted that at a pharmaceutical manufacturing facility
there would also be a significant listing of small operations and
activities which use carbonate compounds in trace quantities, including
the creation of reagent solutions, and wastewater treatment operations
employing carbonate compounds for buffering, chemical precipitation, or
solids stabilization. This commenter recommended that EPA implement a
threshold of 2,000 tons per year of carbonates per facility, which would
correlate to CO2 emissions of about 1,000 tons per year.

One commenter requested that EPA incorporate a de minimis threshold to
only include equipment where carbonate is present at greater than 10%
percent by weight and heated to a temperature that allows for
decomposition.  This commenter suggested an alternative threshold, where
EPA would require facilities to calculate CO2 emissions from each type
of carbonate used in quantities exceeding 2,000 tons per year.

Response:  The rule language has been modified to specify that GHG
emissions from miscellaneous carbonate use are required to be reported
only from processes that consume at least 2,000 tons per year and,
further, where the carbonates are heated to a temperature sufficient to
allow the calcination reaction to occur.  This modification to the
definition of the source category allows facilities with minimal
carbonate consumption and low amounts of GHG emissions to be excluded
from reporting emissions.

Method for Calculating GHG Emissions

Comment:  Multiple commenters requested that EPA allow emission
calculations to be based on carbonate fraction of the product instead of
calcination fractions.  One commenter noted that in acid scrubbing for
SO2, one molecule of CO2 is formed for each molecule of SO2 captured,
thus direct measurement of sulfur removal efficiency is a more accurate
means of determining CO2 emissions from scrubber systems.

Response:  The rule has been changed to allow emission calculations by
either the mass of carbonate input/output or calcination fraction.
These methods should provide comparable estimates of emissions.

The calcination fraction method calculates the amount of CO2 emissions
based on the based on the amount of each carbonate that is calcined
during the process.  The mass and calcination fraction of each carbonate
are measured and used with a default CO2 emission factor to determine
CO2 emissions.

The carbonate fraction method calculates the amount of CO2 emissions as
a mass balance between the input and output amount of each type of
carbonate that is input and output from the kiln.  The masses are
measured and used with a default CO2 emission factor to determine CO2
emissions.

The mass of carbonate input/output is determined by use of the same
plant instruments used for accounting purposes or by direct measurement.
 Calcination fractions can be measured by the appropriate industry
consensus standards that require laboratory analysis of each carbonate
type.  Alternatively, a default value of 1 one can be used as the
calcination fraction.

Emissions from carbonates used in sorbent technology (such as scrubbers)
should be calculated and reported under subpart C (General Stationary
Combustion), 40 CFR 98.33 “Calculation of CO2 from Sorbent.”

Data Reporting Requirements and Records That Must be Retained

Comment:  One commenter requested that recordkeeping and reporting
requirements be exempted for carbonates kept on-site for emergency
purposes (not manufacturing or equipment), such as for neutralizing a
chemical spill.  This commenter explained that when used, these
emergency reserves of carbonate material typically generate
insignificant amounts of CO2 and should therefore be excluded from
reporting requirements.

Response:  The final rule does not cover carbonates that are used in
quantities of less than 2,000 tons per year and that are not heated to
the point of calcination.  Also, this subpart does not include
requirements for calculating and reporting CO2 emissions from acid
neutralization.  Therefore, the use of carbonates in the manner
described is not covered by the final rule.

Comment:  One commenter noted that the required records are duplicated
in sectionproposed 40 CFR 98.217(a) and 98.217(c), and requested that
EPA revise this so as not to place unnecessary costs on facilities.

Response:  EPA agrees that asking facilities to maintain records on
procedures used to ensure the accuracy of monthly carbonate consumption
will be duplicative with maintaining records of all carbonate purchases
and deliveries.  This is especially true if purchase records are used to
determine monthly carbonate consumption.  We removed this duplicative
recordkeeping requirement from the rule.

To improve the emissions verification process, section 40 CFR 98.216 was
reorganized and updated.  Some data elements were moved from section40
CFR 98.217 to section40 CFR 98.216, and some data elements that a
reporter must already use to calculate GHG as specified in section40 CFR
98.213 were added to section40 CFR 98.216 for clarity.  All affected
sources must follow the general recordkeeping provisions under 40 CFR
part 98.3(g) in subpart A.

Commenters may also want to review Section II.M  for the response on the
general recordkeeping requirements and Section II.N of this preamble for
the response on the emissions verification approach.

V.  Nitric Acid Production

1.  Summary of the Final Rule

Source Category Definition.  The nitric acid production source category
consists of facilities that use one or more trains to produce weak
nitric acid (30 to 70 percent in strength) through the catalytic
oxidation of ammonia.

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 nitric acid production facilities, report N2O
process emissions from each nitric acid train.

In addition, report GHG emissions for other source categories at the
facility for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources).

GHG Emissions Calculation and Monitoring.  Reporters must calculate N2O
process emissions for each nitric acid train.  Calculate the emissions
by multiplying the site-specific emission factor for each train by the
measured annual nitric acid production for that train.  Determine the
site-specific emission factor for each train through an annual
performance test to measure N2O from the absorber tail gas vent and the
production rate for that train.

When N2O abatement devices (such as nonselective catalytic reduction)
are used, adjust the N2O process emissions for the amount of N2O removed
using a destruction efficiency factor.  The destruction factor is the
destruction efficiency can be specified by the abatement device
manufacturer.  Reporters can also determine this factor or can be
determined using process knowledge or another performance test.

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 V.

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
V.

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 V: Nitric
Acid Production.”

The re-testing trigger was eliminated.changed.  Performance testing is
only required annually to determine the N2O emissions factor is required
annually and whenever new abatement technology is installed.  The
performance test should be conducted under normal operating parameters.

Equation V-2 was edited to correct a calculation error and to allow
multiple types of abatement technologies.

Reorganized and updated Section40 CFR 98.226 to improve the emissions
verification process.  Some data elements were moved from section40 CFR
98.227 to section40 CFR 98.226, and some data elements that a reporter
must already use to calculate GHGs as specified in section40 CFR 98.223
were added to section40 CFR 98.226 for clarity.

 3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
A large number of comments on nitric acid production were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response document for nitric acid 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 V: Nitric Acid
Production.”

GHGs to Report

Comment:  Multiple commenters asked that the language in section40 CFR
98.222(b) be clarified to include emissions under 40 CFR part 98,
subpart V only from units that are 100% percent dedicated to nitric acid
production to avoid double counting of combustion emissions.

Response:  We appreciate the comments but have decided not to make any
changes to 40 CFR part 98, subpart V.  According to the applicability
criteria in subpart C, all combustion unit emissions from nitric acid
facilities (regardless of whether or not the combustion units are
associated with nitric acid production operations) are to be reported
under subpart C.  There will be no potential for double counting of
combustion emissions at the facility because all combustion unit
emissions are to be reported under subpart C.  Subpart V provides
methods for reporting only the process N2O emissions.  Also see the
preamble for responses on comments related to Subpart C (General
Stationary Combustion).

Method for Calculating GHG Emissions

Comment:  Multiple commenters asked that the requirement to repeat the
annual performance test be removed.  In the proposal, re-testing was
triggered whenever the nitric acid production rate changed by more than
10 percent.  Commenters asserted that production depends on demand for
nitric acid and often varies by up to 20 percent.

Response:  We appreciate the comments and have decided to eliminate
re-testing.  We believe that annual determination of the N2O emissions
factor is sufficient to accurately calculate N2O emissions as long as
the train equipment remains consistent over the year-long period (i.e.
no installation of abatement technology).

Comment:  Multiple commenters asked that alternative methods be allowed
for calculating N2O emissions from nitric acid production.  Specifically
the commenters asked that EPA allow the use of N2O and flow CEMS to
directly measure N2O emissions and use the performance test to evaluate
the CEMS accuracy.  They also requested that EPA allow use of existing
process flow meters, process N2O analyzers to determine the amount of
N2O sent to control devices and conduct a performance test measuring
control device destruction efficiency for each control device and then
calculate N2O emissions.

Commenters also asked that finalizing a methodology for N2O stack
testing for nitric acid units be delayed until EPA can coordinate with
the commenters in formulating a more accurate means of measurement from
these sources.

Response:  We agree that there are other accurate means of determining
N2O emissions, such as N2O CEMS.  The final rule has been changed to
allow alternative test methods, in addition to the proposed methods.
Any alternative must be approved by the Administrator before being used
to comply with this rule.  An implementation plan that details how the
alternative method will be implemented must be included in the request
for the alternative method.  Currently there is no EPA method for using
N2O CEMs.CEMS.  EPA understands the need to further evaluate and
establish alternative comparable or potentially more accurate methods
for sources to use in calculating N2O emissions from nitric acid
production and will address in future rulemakings or amendments to
rulemaking.  Until the method is approved facilities must use the
alternatives proposed in the rule for a performance test.  At minimum
the performance test will help to QA/QC alternative methods currently
used to monitor N2O emissions (including N2O CEMS).

The final rule allows the use of existing process flow meters and
process knowledge in the determination of parameters used in the
calculation of N2O emissions, such as the destruction factorefficiency
of N2O abatement technologies.  These parameters are This parameter is
often based on site-specific knowledge and of operations in combination
with manufacturer specifications.  We believe that using existing
methods reduces the potential cost impacts of this rulemaking and that
it is in the best interest of the facilities that production rates and
destruction factors required parameters be accurately measured.

Comment:  Multiple commenters asked that Equation V-2 be edited to
follow the summation format used in the IPCC Tier 2 methodology.  The
current format does not allow for multiple abatement technologies
(including no abatement).

Response:  We agree with this comment.  The equation in the proposed
rule contained an error and did not allow for multiple abatement
technologies.  The final rule contains a corrected version of the
equation.

Data Reporting Requirements

Comment:  Multiple commenters argued that the annual production rates,
capacity and operating hours are considered CBI and should not be
reported.  The commenters asked that this information be maintained by
the facility and made available to the Agency upon request.

Response:  We 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.”  See also Section II.N of
this preamble for the response on the emissions verification approach.

We agree that annual operating hours are not used in the calculation of
N2O emissions and this parameter has been moved to recordkeeping.
However, this parameter is still important for emissions verification.
This information can help to verify anomalies in emissions data if there
were temporary shutdowns, etc.

We disagree that production be maintained as records rather than be
reported.  We need production rate in order to verify the N2O emissions
that are being reported.  Nitric acid production is a parameter in the
method for determining annual N2O emissions.  This so we need production
rate in order to verify the N2O emissions that are being reported.  The
internal verification system ensures that the GHG emissions reported are
as accurate as possible.

We disagree that capacities be considered confidential information.
During the data gathering process, we located multiple publicly
available sources that included production capacities for nitric acid
production facilities.  Capacity information can help EPA determine a
reasonable range within which reported emissions should be.  However, we
We agree that capacities are not used in the calculation of N2O
emissions; however, this is still an important parameter for verifying
emissions, so .  Therefore, this parameter has been moved to
recordkeeping.

W.  Oil and Natural Gas Systems

At this time, EPA is not going final with the fugitive and vented
methane emissions from the oil and gas sector under Subpart40 CFR part
98, subpart W.  As EPA considers next steps, we will be reviewing the
public comments and other relevant information.

EPA received a number of lengthy, detailed comments regarding Subpart40
CFR part 98, subpart W.  Commenters generally opposed the proposed
reporting requirements and thought they would entail significant burden
and cost.  For example, many commenters asserted that use of direct
measurement to collect data required under Subpart40 CFR part 98,
subpart W would entail significant burden and that the proposal lacked
standards for leak detection and measurement equipment.  In many cases,
commenters provided alternative approaches to the reporting requirements
proposed by EPA such as the use of emission factors and/or reducing the
number of sources and sites requiring direct measurement e.g., through
statistical sampling.  In addition to comments on burden, commenters
requested clarification from EPA on a number of proposed reporting
provisions.

As EPA received extensive comments on this subpart, EPA plans to take
additional time to perform additional analysis and consider alternatives
to data collection procedures and methodologies.  These alternatives
will provide similar coverage of vented and fugitive methane and other
greenhouse gasGHG emissions in the oil and gas sector, while
concurrently taking into account industry burden.  As stated in Section
V.W of the draft Subpart W preamble to the proposed rule (74 FR 166606,
April 10, 2009), EPA will also consider the inclusion of greenhouse
gasGHG reporting from other sectors of the oil and gas industry.

Where applicable, EPA will also consider the applicability of
engineering estimates, emissions modeling software and emissions factors
rather than relying so extensively on the use of direct measurement.
EPA will consider optimal methods of data collection in order to
maximize data accuracy, while considering industry burden.

X.  Petrochemical Production

1.  Summary of the Final Rule

Source Category Definition.  The petrochemical production source
category consists of all processes that produce acrylonitrile, carbon
black, ethylene, ethylene dichloride, ethylene oxide, or methanol, with
certain exceptions.  Exceptions include processes that produce a
petrochemical as a byproduct, processes that produce methanol from
synthesis gas when the annual mass production of hydrogen or ammonia
exceeds the annual mass of methanol produced, direct chlorination
processes operated independently of oxychlorination processes to produce
ethylene dichloride, processes that produce bone black, and processes
that produce a petrochemical from bio-based feedstock.

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 petrochemical production facilities, report CO2,
CH4, and N2O process emissions from each petrochemical production unit.
Process emissions include CO2 generated by reaction in the process.
Process emissions also include CO2, CH4, and N2O emissions generated by
combustion of off-gas from the process in stationary combustion units
and flares.  For some of the GHG emission calculation and monitoring
options, 40 CFR part 98, subpart X references procedures in 40 CFR part
98, subpart C for calculating emissions from stationary combustion
sources, and it references procedures in 40 CFR part 98, subpart Y for
calculating emissions from flares.

In addition, report GHG emissions for other source categories at the
facilities for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site that does not burn process off-gas
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).  The quantity of CO2 captured must also be reported by
following the requirements of 40 CFR part 98, subpart PP.

GHG Emissions Calculation and Monitoring.  CO2 process emissions from
petrochemical production must be determined by one of three methods.
Process emissions include emissions from CO2 generated by chemical
reactions in the process and from the combustion of process off-gas and
liquid wastes.

One emission calculation option is to route all process vent emissions
to one or more stacks and use CEMS to measure the CO2 emitted from each
stack (except flare stacks).  For each stack that includes emissions
from combustion of process off-gas, reporters must calculate CH4 and N2O
emissions by the procedures specified in 40 CFR part 98, subpart C.  For
each flare, the final rule requires CO2, CH4, and N2O emissions to be
calculated using the procedures in 40 CFR 98.253(b) (Petroleum
Refineries).  If CO2 CEMS are used on all subject stacks, even if the
CEMS were installed for reasons other than compliance with this rule,
then the rule requires the use of this reporting option.

A second emission calculation option is to use a mass balance.  Under
this option, the quantity of each carbon-containing feedstock added to
the process and the quantity of each carbon-containing product produced
by the process must be measured for each calendar month, or it may be
calculated based on measured changes in the liquid level in storage
tanks.  The carbon content of each feedstock and product also must be
determined at least once per month.  The carbon content may be measured
directly, or it may be calculated based on measurements of the
composition and known compound molecular weights.  Under this option,
the procedures for products also apply to byproducts and liquid organic
wastes that are not combusted onsite.  To prevent double-counting of
combustion emissions, this option specifies that the procedures for
stationary combustion sources in 40 CFR part 98, subpart C apply only to
the supplemental fuel (e.g., natural gas) burned in combustion units
that supply energy needs for petrochemical processes.  The final rule
specifies numerous measurement method options and related calibration
requirements in 40 CFR 98.244.  To potentially minimize the sampling and
analysis burden, the final rule, like the proposed rule, includes an
option that allows reporters to assume a feedstock or product is always
100 percent pure if they determine that the specified compound is always
present at greater than 99.5 percent.

A third emission calculation option is available only for ethylene
processes.  Because nearly all process emissions from this process are
from combustion of process off-gas, the final rule allows calculation of
emissions from all stationary combustion units that burn process off-gas
(with or without supplemental fuel) in accordance with the Tier 3 or
Tier 4 procedures in 40 CFR part 98, subpart C.  In addition, this
option requires CO2, CH4, and N2O emissions from each flare to be
calculated using the procedures in 40 CFR 98.253(b) (Petroleum
Refineries).

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 98.246.

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 98.247.

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 X:
Petrochemical Production.”

The definition of the source category was changed to exclude ethylene
dichloride production by the direct chlorination process alone from the
petrochemical production source category because the only GHG emissions
from this process are from the combustion of supplemental fuel and the
combustion of hydrocarbon emissions in air pollution control devices.
Ethylene dichloride produced by both direct chlorination and
oxychlorination in the “balanced process” is still part of the
source category.

For the mass balance option, the measurement and emission calculation
frequency was changed from weekly to monthly.

For ethylene processes, an alternative was added to the mass balance
option that allows reporters to calculate emissions from stationary
combustion sources that burn ethylene process off-gas (with or without
supplemental fuel) using the Tier 3 or Tier 4 procedures in 40 CFR part
98, subpart C.  This includes all such combustion units, including units
that supply energy to processes other than the ethylene process.  This
option does not affect requirements for stationary combustion sources
related to ethylene processes that burn no process off-gas; emissions
from these combustion units still must be calculated using the methods
in any applicable Tier in 40 CFR part 98, subpart C.

The reporting requirements in section40 CFR 98.246 were reorganized and
updated to facilitate the emissions verification process, simplify and
clarify requirements, and address requirements for the new monitoring
option for ethylene processes.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
Many comments on petrochemical production were received covering
numerous topics.  Responses to significant comments received can be
found in the comment response document for petrochemical 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 X: Petrochemical
Production.”

Definition of Source Category.

Comment:  Several commenters stated that ethylene production should be
removed from the petrochemical production source category because
essentially all GHG emissions from such processes are from combustion
sources, which would be subject to reporting under 40 CFR part 98,
subpart C regardless of whether the process is included in the
petrochemical production source category.  According to two commenters,
using a mass balance approach is irrelevant and confusing because
ethylene processes have no normal process vents.  One commenter noted
that methane is produced in ethylene processes, but the vast majority is
returned as fuel within the plant or another plant at the same site and
thus would produce CO2 emissions only when combusted.  Another commenter
noted that off-gas from ethylene processes that are co-located with a
petroleum refinery or other chemical plants is sent to the fuel gas
system where it is mixed with other process gases from non-ethylene
units in a fuel gas blend drum and then distributed to combustion units
throughout the refinery and/or chemical plant.  According to two
commenters, the mass balance approach is onerous due to the number of
product streams that would have to be measured, and the results of a
mass balance most likely would be less accurate than a fuel combustion
methodology.  These two commenters also noted that calculating GHG
emissions based on fuel combustion is the methodology used currently by
most ethylene units.  One commenter suggested that as an alternative to
excluding ethylene units from the petrochemical production source
category, EPA could add an emission calculation methodology to 40 CFR
part 98, subpart X that would allow facilities to calculate combustion
emissions based on fuel consumption.

Response:  As one commenter noted, methane (and other light ends) are
generally burned in combustion units to supply energy needs for the
ethylene process itself and possibly other processes.  Emissions from
combustion of these process off-gases are process emissions that are
intended to be reported under 40 CFR part 98, subpart X.  At facilities
where the ethylene process off-gases are not mixed with off-gas from
other processes, we do not believe that the mass balance approach is
illogical; the flows and carbon contents of feedstocks and products can
be determined for an ethylene process, and the resulting values can be
used in the mass balance equations, just as they can for any other
petrochemical process.  Furthermore, we do not know if the views of the
commenters reflect the views of all ethylene manufacturers.  Therefore,
we have retained ethylene in the petrochemical production source
category, and we have retained the mass balance option in the final
rule.

Although we still think a mass balance approach is appropriate and valid
for ethylene processes, we have also evaluated combustion-based
methodology options for the final rule.  Given that the cracking and
separation operations generate negligible CO2, we agree with the
commenters that the only significant source of emissions in ethylene
production is from combustion operations.  One concern we have with
using the Tier 1 and Tier 2 methodologies in 40 CFR part 98, subpart C
is that they rely on default emission factors and company records
(rather than measurements) of fuel flow.  Given the variety of
feedstocks and the corresponding variety in process off-gas, we do not
believe default emission factors or fuel flow based on company records
are appropriate.  Therefore, we rejected the Tier 1 and Tier 2
methodologies.  On the other hand, Tier 3 requires measurement of the
total fuel flow and relatively frequent measurement of the carbon
content of the fuel.  Using CEMS to measure CO2 emissions (i.e., the
Tier 4 methodology in 40 CFR part 98, subpart C) is also a good way to
measure CO2 emissions from any combustion unit.  Therefore, we
determined that use of the Tier 3 or Tier 4 methodology is acceptable
for calculating emissions from combustion units that burn ethylene
process off-gas (with or without mixing with supplemental fuel), and
these options are included in the final rule.  In addition, because the
methodology used for calculating emissions from one combustion unit has
no bearing on the emissions from any other combustion unit, the final
rule states that a facility is not required to use the same Tier for
each stationary combustion unit.

Comment:  One commenter requested that EPA remove ethylene dichloride
(EDC) from the petrochemical source category because EDC is not
manufactured using a fossil fuel-based feedstock (e.g., crude oil,
naphtha, natural gas condensate, methane, or other fossil fuel-based
chemicals), no GHGs are used in the manufacturing process, and only a
trace amount of CO2 is generated in the process.  Another commenter
requested clarification that EDC produced as an intermediate in the
production of vinyl chloride monomer is not part of the petrochemical
source category because the entire process is considered to be an
“integrated process”, and the primary product of the process is not
EDC.  The commenter noted that the term “primary product” is also
used in the Hazardous Organic NESHAP (HON) (40 CFR part 63, subpart F),
but it has a different definition.  To avoid confusion created by
multiple definitions for the same term, the commenter urged EPA to
consider alternatives to the concept of primary product for determining
applicability of an integrated process.

Response:  EDC is produced by two processes.  In one process, the direct
chlorination process, ethylene is reacted with chlorine to create EDC.
As the commenters noted, reactions in this process produce negligible
CO2 emissions and no other GHG emissions.  The only GHG emissions
associated with this process are from the combustion of process off-gas
and supplemental fuel.  We have determined that monitoring and reporting
of these emissions will be required under 40 CFR part 98, subpart C.
Therefore, we have removed this process from the petrochemical source
category.

In the second EDC process, the oxychlorination process, ethylene is
reacted with hydrochloric acid to create EDC and water.  Some of the
ethylene, however, oxidizes to CO2 and water in a competing side
reaction.  All facilities in the United States (U.S.) that operate this
process operate it as part of an integrated process that includes vinyl
chloride monomer production and a direct chlorination process.  This
integrated process is called a “balanced process”.  Although
available estimates suggest the amount of CO2 emitted is small relative
to emissions from combustion, we do not have data to support such
estimates.  Furthermore, even if small relative to other sources, the
total amount is not necessarily insignificant.  We continue to believe
information about these emissions is needed in order to support future
policy decisions regarding petrochemical processes.  Therefore, we have
not removed EDC production by the balanced process from the
petrochemical production source category.

In the proposed rule, an “integrated process” was defined as “a
process that produces a petrochemical as well as one or more other
chemicals that are part of other source categories” subject to
reporting under 40 CFR part 98.  This concept does not apply to
production of EDC as an intermediate that is used in the onsite
production of vinyl chloride monomer because vinyl chloride monomer
production is not a source category that is subject to reporting under
40 CFR part 98.  We used general language in the proposed rule that
would apply to various integrated process scenarios, but the only
scenario we know of that meets these conditions is methanol production
from synthesis gas that is sometimes also used to produce hydrogen
and/or ammonia (both of which are subject to reporting under other
subparts in 40 CFR part 98).  Because this is the only situation where
the “integrated process” concept would apply, we decided to replace
it in the final rule with language in §40 CFR 98.240 that explicitly
states the applicability determination procedures for a process that
produces methanol, hydrogen, and/or ammonia from synthesis gas.  Thus,
the term “primary product” has also been removed from the final
rule, which eliminates the potential conflict with the definition in the
HON.

Method for Calculating GHG Emissions.

Comment:  Two commenters stated that the proposed CEMS requirements are
overly restrictive.  According to these commenters, a facility should
have the option to install a CEMS on one or more sources without being
required to have a CEMS on all sources associated with a petrochemical
production process.  For example, the commenters suggested that a
facility should have the flexibility to use a CEMS on a large emission
point while being allowed to use the combustion equations and/or the
mass balance approach for smaller emission points in the process (e.g.,
start-up heaters and steam jet exhausts from distillation columns
operating under vacuum).

Response:  For the mass balance option to work, inputs and outputs of
process streams must be monitored.  It is not clear to us how to
accomplish this by monitoring only selected emission points within a
process.  Even if such monitoring is possible, it is unlikely that it is
being conducted currently, which would make such an approach more
burdensome than options specified in the rule.  Furthermore, we believe
the methodology should be standardized as much as possible, and it is
not clear how “small” emission points should be defined.Response:
If some emissions were from stacks monitored with CEMS and all other
emissions were from combustion units without CEMS, it would be possible
to use a combination of CEMS and the combustion equation methodology to
calculate the total GHG emissions from a petrochemical process.
However, this scenario is unlikely, which means other methodology would
be needed to estimate emissions from other emission points (e.g., the
steam jet exhausts cited by the commenters).  It is not clear to us how
the mass balance methodology would be used to estimate these other
emissions because the mass balance relies on knowledge of the total
carbon input to the process and the total amount of carbon in all
products (and organic liquid wastes); the difference is assumed to be
the total CO2 emissions.  Theoretically, other methodology could be
developed to calculate emissions from specific other emission points,
but the commenter has not suggested other techniques.  Therefore, the
final rule does not include an option to mix CEMS with the mass
balanceother methodology for a given process unit.

Comment:  According to several commenters, weekly measurements of
feedstocks and products are burdensome or unwarranted.  Two commenters
suggested changing the frequency to monthly because monthly accounting
would align better with existing industry accounting procedures, reduce
the burden, and provide 12 high-quality estimates per year.  One
commenter suggested monthly mass balance calculations for carbon black
facilities because the emissions from a carbon black manufacturing
facility do not vary significantly from week to week.  Another commenter
requested a provision to allow the reporter to determine a sampling
frequency that is consistent with the variability of the stream.

Response:  We are sensitive to the burden imposed by the rule and want
to minimize it when possible.  Based on the results of an uncertainty
analysis (see memorandum entitled “Monte Carlo Simulation of
Uncertainty Analysisin Monitoring Frequency for Mass Balance Option for
Petrochemical Production Facilities” in the docket), we believe longer
monitoring periods will not significantly compromise the monitoring
results for the mass balance option.  Therefore, the mass balance option
in the final rule requires monthly monitoring instead of the proposed
weekly monitoring.

Data Reporting Requirements

Comment:  Two commenters stated that the proposed reporting requirements
are excessive, particularly information such as each carbon content
measurement and information on the calibration of each flow meter.
According to the commenters, submitting this information will not
improve the overall quality of the GHG emission calculation, and it is
not necessary because the facilities are required to certify that the
submitted information is true, accurate, and complete.  Therefore, the
commenters recommended that facilities be required to retain records of
such information rather than submit it in reports.

Response:  A primary reason that additional information beyond annual
emissions must be reported is so that EPA can verify the results.  To
facilitate the emissions verification process, section40 CFR 98.246 was
reorganized and updated.  For example, the final rule requires reporting
of all input data used in the emission calculation equations, not just
the carbon content values and the annual quantities, because this
information is needed so the calculations can be reproduced and
confirmed as part of the emissions verification process.  Note, however,
that any increase in the burden to report flow measurements has been
offset by the reduction in monitoring frequency from weekly to monthly.
The reporting requirements in the final rule for the mass balance option
also have been simplified and clarified by replacing the requirement to
submit all information related to uncertainty estimates with a
requirement to submit only the dates and summarized results of
measurement device calibrations.  The estimated accuracy of measurement
devices and the technical basis for such measurements must also be
documented as part of the monitoring plan that is maintained onsite.
The reporting section also was updated to include reporting requirements
for the new monitoring option for ethylene processes.

Y.  Petroleum Refineries

1.  Summary of the Final Rule

i.  Source Category Definition

Petroleum refineries are facilities that produce gasoline, gasoline
blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel
oils, lubricants, or asphalt (bitumen) by the distillation of petroleum
or the redistillation, cracking, or reforming of petroleum derivatives.
The definition of petroleum refineries excludes facilities that distill
only pipeline transmix (off-spec material created when different
specification products mix during pipeline transportation), regardless
of the products produced.

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.

ii.  GHGs to Report

The refinery processes and gases that must be reported are listed in
Table Y-1 of this preamble along with the rule subpart that specifies
the calculation methodology that must be used.

Table Y-1.  GHGs to Report

For this refinery process…	Report emissions of the listed GHGs by
following the requirements of the 40 CFR part 98, subpart indicated…

	CO2	CH4	 N2O

Stationary combustion	C	C	C

Flares	Y	Y	Y

Catalytic cracking	Y	Y	Y

Traditional fluid coking	Y	Y	Y

Fluid coking with flexicoking design	C/Y	C/Y	C/Y

Delayed coking	-	Y	-

Catalytic reforming	Y	Y	Y

Onsite and offsite sulfur recovery	Y	-	-

Coke calcining	Y	Y	Y

Asphalt blowing 	Y	Y	-

Equipment leaks	-	Y	-

Storage tanks	-	Y	-

Other process vents	Y	Y	Y

Uncontrolled blowdown systems	-	Y	-

Loading operations	-	Y	-

Hydrogen plants (nonmerchant)	P	P	-

Key:

C = 40 CFR part 98, subpart C (General Stationary Combustion Sources)

P = 40 CFR part 98, subpart P (Hydrogen Production)

Y = 40 CFR part 98, subpart Y (Petroleum Refineries)

- = Reporting from this process is not required

iii.  GHG Emissions Calculation and Monitoring

Under 40 CFR part 98, subpart Y, petroleum refineries must calculate
CO2, CH4 and N2O emissions using the calculation methods described below
for each refinery process.

For CO2 emissions, reporters must use CEMS or specified calculation
methods as follows:

For refinery units with certain types of CEMS in place, reporters must
use the CEMS and follow the Tier 4 methodology of 40 CFR part 98,
subpart C to report combined process and combustion CO2 emissions.

For refinery units without CEMS in place, reporters can elect to either
(1) install and operate a CEMS to measure combined process and
combustion CO2 emissions according to the requirements specified in 40
CFR part 98, subpart C or (2) calculate CO2 emissions using the methods
summarized below.

Flares.  CO2 emissions from flares must be calculated using the gas flow
rate (either measured with a continuous flow meter or calculated using
engineering calculations) and either: (1) at least weekly measured
carbon content of the flare gas, or (2) at least weekly measured heat
content of the flare gas and an emission factor provided in the rule.
If the carbon content and heat content of the gas are not measured at
least weekly, engineering estimates of heat content during normal flare
use is allowed, but CO2 emissions for each startup, shutdown, and
malfunction event exceeding 500,000 standard cubic feet (scf) per day of
flare gas must be calculated separately using engineering estimates of
the quantity of gas discharged and the carbon content of the flared gas.
CH4 and N2O emissions from flares must be calculated using the methods
specified in 40 CFR part 98, subpart Y.

Catalytic Cracking Units, Fluid Coking Units, and Catalytic Reforming
Units.  CO2 emissions must be calculated using the volumetric flow rate
of the exhaust gas (measured or calculated) and hourly measured carbon
monoxide (CO) and CO2 concentrations in the exhaust stacks from the
catalytic cracking unit regenerator and fluid coking unit burner from
units exceeding 10,000 barrels per stream day.  Catalytic cracking and
fluid coking units below this threshold must use the required flow and
gas monitors if they are in-place, but may use engineering estimates for
determining CO2 emissions if the required flow and gas monitors are not
in place.  Similarly, catalytic reforming units may use the flow and gas
monitors required for large catalytic cracking and fluid coking units;
alternatively, reporters may use engineering estimates based on the
quantity of coke burned off, the carbon content of the coke (using
either a measured or a default value), and the number of regeneration
cycles.  CH4 and N2O emissions may be measured or may be calculated
using the CO2 emissions and default emission factors.  Fluid coking
units that use the flexicoking design may account for their GHG
emissions either by using the methods specified for traditional fluid
coking units, or by using the methods for stationary combustion
specified in 40 CFR part 98, subpart C.

Onsite and Off Site Sulfur Recovery.  CO2 emissions must be calculated
using the volumetric flow rate of the sour gas (measured continuously or
calculated from engineering calculations) and the carbon content of the
sour gas stream (using a measured or a default value).

Coke Calcining Units.  CO2 emissions must be calculated from the
difference between the carbon input as green coke and the carbon output
as marketable petroleum coke and as coke dust collected in the dust
collection system. The CH4 and N2O emissions from coke calcining units
may be measured or calculated using the calculated CO2 emissions and
default emission factors.

Asphalt Blowing Operations.  For uncontrolled asphalt blowing operations
or asphalt blowing operations controlled by vapor scrubbing, CH4 and CO2
emissions must be calculated using a facility-specific emission factor
based on test data or, where test data are not available, a default
emission factor provided in the rule.  For asphalt blowing operations
controlled by a thermal oxidizer or flare, CH4 and CO2 emissions must be
calculated by assuming 98 percent of the CH4 and other hydrocarbons
generated by the asphalt blowing operation are converted to CO2.

Delayed Coking Units.  CH4 emissions from the depressurization of
delayed coking vessels must be calculated using the method outlined
below for other process vents.  The emissions released during the
opening of vessels for coke cutting operations must be calculated using
the vessel parameters (height and diameter), vessel pressure, the number
of times the vessel was opened, the void fraction of the coking vessel
prior to steaming, and the mole fraction of CH4 in the gas released
(using a measured or a default value provided in the rule). The rule
provides an alternative of using only the vessel parameter equation if
no water or steam is added to the vessel after the vessel is vented to
the atmosphere.

Other Process Vents.  GHG emissions from other process vents that
contain CO2, CH4, or N2O exceeding concentration thresholds specified in
the rule must be calculated using the volumetric flow rate, the mole
fraction of the GHG in the exhaust gas, and the number of hours during
which venting occurred.

Uncontrolled Blowdown Systems.  CH4 emissions from uncontrolled blowdown
systems must be calculated using either the method specified for process
vents or a default emission factor and the sum of crude oil and
intermediate products received from off site and processed at the
facility.

Equipment Leaks.  CH4 emissions from equipment leaks must be calculated
using either default emission factors or process-specific CH4
composition data and leak data collected using the leak detection
methods specified in EPA’s Protocol for Equipment Leak Emission
Estimates.

Storage Tanks.  For storage tanks covered by the requirements of this
rule, the methodology used to calculate the CH4 emissions depends on the
material stored.  For storage tanks used to store unstabilized crude
oil, facilities must use either: (1) the CH4 composition of the
unstabilized crude oil (based on direct measurement or product
knowledge) and the measured gas generation rate; or (2) an emission
factor-based method using the quantity of unstabilized crude oil
received at the facility, the pressure difference between the previous
storage pressure and atmospheric pressure, the mole fraction of CH4 in
the vented gas (using either a measured or a default value), and an
emission factor provided in the rule.  For storage tanks used to store
material other than unstabilized crude oil with a vapor-phase CH4
concentration of 0.5 percent by volume or more, facilities must use
either tank-specific methane composition data and applicable
correlations in AP-42, Section 7.1 (as implemented in the TANKS Model
(Version 4.09D) or similar models) or a default emission factor provided
in the rule.

Loading Operations.  CH4 emissions from loading operations must be
calculated using vapor-phase methane composition data and the method in
Section 5.2 of AP-42: “Compilation of Air Pollution Emission
Factors..”  Facilities must calculate CH4 emissions only for loading
materials that have an equilibrium vapor-phase CH4 concentration equal
to or greater than 0.5 percent by volume.  Other facilities may assume
zero CH4 emissions.

iv.  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 Y.

v.  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 Y.

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 Y:
Petroleum Refineries.”

The minimum monitoring frequency for flare gas heat value or carbon
content was changed to weekly from daily.  (For background on the
selection of a weekly frequency, see memorandum entitled: “Uncertainty
in Flare Estimates Based on Sampling Frequency” in the docket.)
Engineering calculations are allowed in the final rule for reporters
that do not monitor flare gas flow continuously or flare heating value
or carbon content at least weekly.

The minimum monitoring frequency for refinery fuel gas carbon content
and molecular weight was changed to weekly from daily in 40 CFR part 98,
subpart C for reporters that do not have continuous monitoring
equipment, and we clarified in 40 CFR part 98, subpart Y that common
(fuel) pipe monitoring is allowed for petroleum refineries.

We added a flare combustion efficiency of 98 percent, and we revised the
equation for flare CH4 emissions to account for uncombusted methane.

The final rule allows engineering calculations to determine CO2
emissions for catalytic cracking units and fluid coking units below
10,000 bbl/stream day that do not have CO2/CO/O2 monitors already
installed.

The delayed coking unit depressurization emission equations and asphalt
blowing equations were amended to address comments received.

We added concentration thresholds for CO2, CH4 and N2O from process
vents below which GHG emissions are not required to be calculated and
reported.

The reporting requirements were updated to facilitate the emissions
verification process.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
A large number of comments on petroleum refineries were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response document for petroleum refineries
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 Y: Petroleum
Refineries.”

Definition of Source Category

Comment:  Several commenters expressed concern that EPA defined a
Petroleum Refinery so broadly that it could be interpreted to include
chemical facilities that use petroleum-based materials as raw materials.
 Of particular concern was the term “…and other products…” which
many commenters interpreted to include the manufacture of chemicals,
synthetic rubber, and a variety of plastics.  One commenter also
requested clarification that “other products” did not include
sulfur, ammonia, or hydrogen sulfide.  Several commenters requested
clarification that the definition of petroleum refineries did not
include lube oil production or fuel blending operations if the products
were produced without distilling, redistilling, cracking, or reforming
of the petroleum derivatives.

Response:  We have revised and clarified the definition of petroleum
refinery to list a few additional refinery products (specifically
gasoline blending stocks and naphtha) and deleted the term “or other
products.”  We believe that this change clarifies that companies that
use petroleum derivatives to make only petrochemicals, plastics,
synthetic rubber, sulfur, or any other product other than those
specifically listed are not considered petroleum refineries.  We feel
the definition also clearly excludes lube oil manufacturing provided the
lube oil manufacturer does not distill, redistill, crack, or reform the
petroleum derivatives at the facility.

Comment:  Numerous commenters requested that many of the emission
sources for which 40 CFR part 98, subpart Y required reporting were
small and should not have to be reported.  Several commenters noted that
EPA's Technical Support DocumentEPA’s TSD for the Petroleum Refining
Sector: Proposed Rule for Mandatory Reporting of Greenhouse Gases,
indicates that 92.9% percent of the refining sector'ssector’s GHG
emissions come from two sources, combustion and catalytic coke
operations. The remaining 7.1% percent of emissions come from eight
distinct categories, including: Hydrogen plants (2.7% percent); Sulfur
Plants (1.9% percent); Flaring (1.6% percent); Wastewater Treatment
(0.43% percent); Blowdown (0.18% percent); Asphalt Blowing (0.10%
percent); Delayed Coking (0.058% percent); Equipment Leaks (0.014%
percent); Storage Tanks (0.007% percent); and Cooling Towers (0.003%
percent).  The commenters argued that the burden associated with the
collection of data as prescribed in the proposed rule is not warranted
for small sources and/or not consistent with EPA‘’s stated intended
purpose of the rule which is to support analysis of future policy
decisions.

Response:  The Technical Support DocumentTSD estimates are based largely
on engineering estimates without significant supporting data.  For the
smaller sources, we have provided very simple methods to calculate the
GHG emissions from these sources to minimize the monitoring,
recordkeeping, and reporting burden associated with these sources when
no measurement data are available.  However, requiring reporting for
these sources will provide EPA with valuable data to better characterize
them and provide a better record upon which to formulate decisions
regarding whether to include or exclude these sources from future GHG
policy decisions.  Additionally, while some of these sources are
currently believed to be small compared to the larger sources present at
petroleum refineries, they are not necessarily insignificant.  The
inclusion of reporting data for these sources is critical to support
analysis of future policy decisions for petroleum refineries.

Comment:  Several commenters objected to the mandatory reporting of CH4
and N20 emissions within the Petroleum Refinery source category.  Many
commenters cited the Technical Support DocumenttheTSD, which indicated
that N20 emissions account for 0.09% percent of the GHG emissions and
CH4 account for only 0.87% percent of the GHG emissions.  The commenters
argued that the measurement error for the larger sources (stationary
combustion sources and catalytic cracking unit coke burn-off) exceeds
the contributions of these sources.  As such, the commenters stated that
the burden associated with reporting these emissions is not warranted
and/or not consistent with EPA‘’s stated intended purpose of the
rule which is to support analysis of future policy decisions.

Response:  The Technical Support DocumentTSD estimates for CH4 and N2O
are based largely on engineering estimates without significant
supporting data.  We specifically require reporting of these various
GHGs to obtain better data by which to support future policy analysis.
Moreover, EPA has pending before it a petition to reconsider the
recently revised New Source Performance Standard (NSPS) for petroleum
refineries asking EPA to reconsider, among other things, whether to
establish GHG standards under section 111 for refineries. As such, we
have a keen interest in obtaining improved GHG emissions data in order
to better analyze policy options.  For instance, refineries are a
significant source of NOX emissions, but we have no data to determine
the fraction of NOX that is N2O.  With the increased use at refineries
of NOX control devices, such as low-NOx burners, low excess air,
selective catalytic reduction (SCR) systems, and selective non-catalytic
reduction (SNCR) systems, it seems plausible that N2O may be a more
significant portion of a refinery’s NOX emissions.  Thus, if a
facility has measurement data for a source, the reporting of these data
are important for better understanding the impact of current and future
policy options, and they are encouraged to be reported.  Consequently,
we have provided additional alternatives that allow the use of measured
N2O (and CH4) emissions or site-specific emission factors in addition to
the default factors.  Nonetheless, we have provided very simple default
methods to calculate the emission of these GHGs when measurement data
are not available.  While emissions of CH4 and N2O may not be large
comparatively, the reporting method for these pollutants is
straightforward and commensurate with the anticipated emissions
contribution.

Method for Calculating GHG Emissions

Comment:  Several comments objected to the requirements for flares,
particularly the requirements for startup, shutdown, or malfunction
(SSM) events.  Some commenters also stated that daily sampling was too
burdensome.  The commenters suggested that flare emissions be dropped
from the rule or that refineries be allowed to perform a one-time
calculation.  One commenter noted that the proposed equation did not
account for flare combustion efficiency, which was inconsistent with
other subparts, and recommended that a flare efficiency factor be added
to the equation to calculate the CO2 emissions from flares.

Response:  EPA needs accurate data on flare emissions to better
understand this emission source, as flare use can vary significantly
from day-to-day and year-to-year.  Use of flares is too episodic and
variable to allow a one-time calculation.  However, we recognize that
flares may contribute about 2two percent of a refinery’s GHG
emissions.  Therefore, we sought to reduce the burden associated with
the flare monitoring and reporting requirements.  As proposed, special
calculations for SSM events were only required if daily measurement data
were not available.  In this final rule, we allow weekly monitoring of
flare use without triggering special SSM event calculations, which
should lessen the burden associated with calculating flare emissions
while not significantly changing the accuracy of the data.
Additionally, we included a threshold flaring rate of 500,000 scf/day
for SSM events.  Only SSM events exceeding this gas flare rate require
special SSM calculations in the final rule.  Some consent decree
requirements and stateState rules require root cause analysis and
quantification of emission events exceeding 500,000 scf/day.  We
consider events of this magnitude to be significant and believe a
separate analysis is justified in addition to the procedures that apply
to routine operation.  We have also revised the equations for CO2 and
CH4 to account for flare combustion efficiency.

Monitoring and QA/QC Requirements

Comment:  Several commenters argued that the monitoring and QA/QC
requirements were excessive and that EPA significantly underestimated
the costs associated with complying with the reporting requirements
under 40 CFR part 98, subpart Y.  One commenter noted that existing
facility CO2 CEMS, HHV monitors, carbon content monitors, and flow
meters are not necessarily for “regulatory” purposes and thus may
not meet the accuracy requirements of the rule.  The commenter suggested
many more refineries would have to add or replace monitors as a result
of the rule.  Many commenters suggested EPA significantly underestimated
the labor hours required to collect and analyze daily samples as well as
to develop and implement a QA plan.  Various commenters supplied labor
or cost estimates for various requirements in the rule, including costs
of implementing an LDAR program and flare SSM calculations.  Several
commenters stated that the requirement to use a CEMS for monitoring CO2
from the catalytic cracking unit was expensive and burdensome,
especially for small refineries that do not have a CEMS infrastructure.

Response:  We have significantly revised our rule requirements for
petroleum refineries and stationary combustion sources to reduce burden
to the industry.  We have provided in the final rule (in 40 CFR part 98,
subpart C) a default emission factor for refinery (still) gas to allow
combustion sources that combust refinery gas and meet the applicability
requirements in 40 CFR part 98, subpart C to use Tier 2 methods.  For
sources that do not meet the Tier 2 requirements, weekly monitoring for
refinery fuel gas under Tier 3 (40 CFR part 98, subpart C) and for flare
gas (40 CFR part 98, subpart Y) is allowed.  We have also re-assessed
our costs based on the comments received and increased the labor hours
estimated to collect and analyze samples, develop QA plans, and to
perform QA/QC of existing equipment.  We did review our QA/QC
requirements and see no validity to the argument that our QA/QC
requirements are so stringent that refineries will have to replace
existing monitors to comply with the rule.  While we note that some cost
elements suggested by commenters are relevant and have been addressed in
the changes in the labor estimates for sampling, analysis, and QA/QC as
described above, other cost elements suggested by commenters are not
relevant.  For example, revisions of LDAR programs are not required
under the rule; the proposed and final rule specifically provides a
simple process-based emission factor approach for estimating CH4
emissions from equipment leaks.  We are cognizant that refineries with
small catalytic cracking units are most likely to elect a compliance
option under Part40 CFR part 63, subpart UUU that does not require
monitoring of coke burn-off, so these small refineries are most likely
the facilities that would have been required to install monitoring
equipment under the proposed rule.  After reviewing these costs and
impacts on the small refineries, we have allowed engineering
calculations to determine CO2 emissions for catalytic cracking units
below 10,000 bbl/stream day that do not have CO2/CO/O2 monitors already
installed.

Even though we have reduced the stringency of the rule in many places,
our revised cost estimates indicate that the average cost per refinery
is approximately 60 percent higher than projected at proposal.  We
believe our revised refinery costs accurately portray the burden
associated with the final reporting requirements in 40 CFR part 98,
subpart Y.  Nonetheless, we continue to believe that the costs are
reasonable for this rule, especially considering that petroleum
refineries are among the larger sources of GHG emissions in the U.S.

Z.  Phosphoric Acid Production

1.  Summary of the Final Rule

Source Category Definition.  The phosphoric acid production source
category consists of facilities that use a wet-process phosphoric acid
process to produce phosphoric acid.  A wet-process phosphoric acid
process line is any system that manufactures phosphoric acid by reacting
phosphate rock and acid and is usually identified by an individual
identification number in a CAA operating permit.

Reporters must submit annual GHG reports for Facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  Report CO2 emissions from each wet-process phosphoric
acid process line.

In addition, report GHG emissions at each facility for other source
categories for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources).

GHG Emissions Calculation and Monitoring.  Calculate process emissions
of CO2 using one of two methods, as appropriate:

Most reporters can elect to either (1) install and operating CEMS and
follow the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2)
calculate CO2 emissions based on monthly measurements of the mass of
phosphate rock consumed and inorganic carbon content of each grab sample
of phosphate rock.

However, if process CO2 emissions from phosphoric acid 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 CEMS must be used to measure and report combined CO2 emissions
from that stack.  In such cases, the reporter cannot use the CO2
calculation methodology outlined in approach (2 above) in the previous
bullet.

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 Z.

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
Z.

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 Z:
Phosphoric Acid Production.”

The rule was revised to allow the use of techniques from Part 60 and
Part 63 for calculating the weight of phosphorous-containing rock.

The missing data provisions were revised to allow the use of default
inorganic carbon content values based on the origin of the
phosphorous-containing rock, in addition to determining missing
inorganic carbon contents of phosphate rock consumed using an arithmetic
average of measured values from of inorganic carbon contents of
phosphate rock of the appropriate origin preceding and following the
missing data incident.

40 CFR 98.266 was reorganized and updated to improve the emissions
verification process.  Some data elements were moved from section40 CFR
98.267 to section40 CFR 98.266, and some data elements that are already
used to calculate GHG emissions as specified in section40 CFR 98.263
were added to section40 CFR 98.266 for clarity.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
Several comments on phosphoric acid production were received covering
numerous topics shown below.  Responses to significant comments received
can be found in the comment response document for phosphoric acid
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 Z:
Phosphoric Acid Production.”

Selection of Threshold

Comment:  Multiple commenters asked that phosphoric acid production
units not be included as an “all-in” category.  According to the
commenters, the facilities are very minor sources of GHG emissions.  The
commenter conceded that most (if not all) would still fall within the
reporting threshold requirement, but asserted that it was unnecessary to
include all phosphoric acid production units as regulated facilities
regardless of the amount of emissions.  The commenters stated that EPA
inaccurately suggests that these units are major emitters of GHGs which
could have significant impacts on these minor sources.

Response:  We acknowledge the comments and concerns; however the final
rule retains the “all-in” applicability requirement for this source
category.  The “once in, always in” provision has been removed.  The
final rule now contains a provisionprovisions to cease reporting if
annual reports demonstrate emissions less than 25,000 metric tons CO2e
per yearspecified levels for 5 consecutivemultiple years.  This
provision appliesThese provisions apply to all reporting facilities,
including those with phosphoric acid production processes.  We believe
that obtaining GHG emissions from all phosphoric acid facilities over a
five year period will document the number of facilities (if any) that
fall below the suggested threshold.  The purpose of this rule is to
collect information on emissions sources for future policy development.
Requiring reporting for these sources will provide EPA with valuable
data to better characterize greenhouse gasGHG emissions from phosphoric
acid production and provide a more credible position if EPA elects to
exclude these sources from future GHG policy analyses.  We also believe
that the accurate assessment of the emissions from phosphoric acid
production will address the commenters’ concerns about potential
future impacts.

Commenters may also be interested in reviewing Section II.H of this
preamble for the response on provisions to cease reporting.

Method for Calculating GHG Emissions and Monitoring and QA/QC
Requirements

Comment:  Multiple commenters asked that production measurements in this
rule be consistent with the existing MACT and NSPS regulations for the
phosphate industry.  In these regulations, production measurement is
determined by the mass of phosphate feed (as P2O5).  Two commenters
stated that the change would provide consistency, and ensure a reporting
structure that fits with the actual practices of the industry.

Response:  We agree with the commenters that consistency among EPA
regulations is important.  Therefore, the final rule allows for
techniques from Part 60 and Part 63 to calculate the weight of
phosphorous-containing rock. This request is consistent with the intent
of the proposed rule.  Under existing regulations in Part 60 and Part
63, phosphoric acid manufacturing facilities already measure the mass of
phosphorous bearing feed on a ton/hour basis.  This feed rate can be
used to determine monthly phosphate rock consumption.  Process CO2
emissions from phosphoric acid production are calculated from the total
phosphate rock consumption multiplied by the inorganic carbon content of
that rock.  Further, Part 60 and Part 63 establish the appropriate
monitoring and QA/QC procedures for determining this feed rate.

Procedures for Estimating Missing Data

Comment:  Multiple commenters asked that the final rule allow options
for missing data.  The commenters asked that the use of default carbon
content values based on the origin of the rock be allowed if analytical
data are unavailable.  In addition, commenters requested that procedures
be added for measurement of the mass of phosphate rock consumed,
suggesting procedures similar to those in 40 CFR part 98, Subpart C, the
lesser of the maximum capacity of the system, the maximum rate the meter
can measure, or best available estimate based on available process data.

Response:  We agree with the commenters on this point.  The final rule
has been changed to allow the use of a default factor (by origin of the
phosphate rock) for each missing value of the inorganic carbon content
of phosphate rock.  Use of a default carbon value in place of the
missing data will provide a reasonable estimate of the total emissions
from the facility and will avoid assuming the maximum possible facility
emissions when no data isare available.  These default values have been
added to the final rule in Table Z-1 of 40 CFR part 98, subpart Z.

Missing data procedures have also been added as suggested for missing
monthly estimates of the mass of phosphate rock consumed consistent with
the later recommendation. Again use of the best available data based on
all available process data will avoid assuming the maximum possible
facility emissions when no data isare available.  Facilities must
document must document and keep records of the procedures used for all
such estimates.

AA.  Pulp and Paper Manufacturing

1.  Summary of the Final Rule

Source Category Definition.  This source category consists of facilities
that produce market pulp (i.e., stand-alone pulp facilities),
manufacture pulp and paper (i.e., integrated mills), produce paper
products from purchased pulp, produce secondary fiber from recycled
paper, convert paper into paperboard products (e.g., containers), or
operate coating and laminating processes.

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.  Table AA-1 of this preamble lists the GHG emission
sources at pulp and paper manufacturing facilities for which GHG
emissions must be reported along with the rule subpart that specifies
the calculation methodology.

Table AA-1.  GHGs to Report

For pulp and paper mills…	Report emissions of the listed GHGs by
following the requirements of the 40 CFR part 98, subpart indicated…

	CO2	Biogenic CO2 	CH4	N2O	Biogenic CH4 	Biogenic N2O

Chemical recovery furnaces at kraft and soda facilities	C	AA	C	C	AA	AA

Chemical recovery combustion units at sulfite facilities	C	AA	C	C	AA	AA

Chemical recovery combustion units at stand alone semi-chemical
facilities	C	AA	C	C	AA	AA

Lime kilns of kraft and soda facilities	AA/C	AA	AA/C	AA/C	AA	AA

Makeup chemicals used in pulp mills	AA

	Stationary combustion units	C	C	C	C	C	C

Key:

C = 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources)

AA = 40 CFR part 98, subpart AA (Pulp and Paper Manufacturing)

AA/C = use 40 CFR part 98, subpart AA for GHG emission factor and
subpart C to determine default High Heating Values.

GHG Emissions Calculation and Monitoring.  Under 40 CFR Subpartpart 98,
subpart AA, reporters must calculate emissions from pulp and paper
manufacturing facilities as follows:

Chemical recovery Furnaces: Calculate biogenic CO2 emissions from
combustion of biomass in spent pulping liquor using:

Measured quantities of spent liquor solids fired, site-specific high
heating value (HHV), and default or site-specific emission factors for
each chemical recovery furnace located at kraft or soda facilities.

Measured quantities of spent liquor solids fired and the carbon content
of the spent liquor solids for each chemical recovery unit at sulfite or
stand-alone semichemical facilities.

Calculate CO2 emissions from fossil fuels used in chemical recovery
furnaces using direct measurement of fossil fuels consumed and default
emission factors according to the Tier 1 methodology for stationary
combustion sources in 40 CFR part 98, subpart C.

Calculate CH4 and N2O emissions as the sum of emissions from the
combustion of fossil fuels and the combustion of biomass in spent
pulping liquor, as follows:

For fossil fuel emissions, use direct measurement of fuels consumed, a
default HHV, and default emission factors according to the methodology
for stationary combustion sources in 40 CFR 98.33(c).

For biomass emissions, use measured quantities of spent liquor solids
fired, site-specific HHV, and default or site-specific emission factors.

Lime kilns at kraft and soda facilities

Lime kilns: Calculate CO2, CH4, and N2O emissions from combustion of
fossil fuels in pulp mill lime kilns using direct measurement of fossil
fuels consumed and default emission factors and HHV found in 40 CFR part
98, subparts AA and C, respectively.

Makeup chemicals: Calculate CO2 emissions from the use of makeup
chemicals using direct or indirect measurement of the quantity of
chemicals added and ratios of the molecular weights of CO2 and the
makeup chemicals.

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 AA.

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
AA.

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 AA: Pulp
and Paper Manufacturing:.”

Language was added to clarify that 40 CFR part 98, subpart AA GHG
emissions are to be reported for makeup chemicals added in the chemical
recovery areas of pulp mills (as opposed to makeup chemicals used at
paper coating and laminating facilities).

The frequency of measurements for the spent liquor solids mass fired
(TAPPI Test Method T 650), heating value (TAPPI Test Method T 684), and
carbon content (ASTM D5373-08) was reduced from monthly to annually.

An option to use data from existing online solids meters to determine
the annual mass of spent liquor solids fired is provided (in lieu of
conducting an annual TAPPI Test Method T 650)

The requirement to report quarterly data was eliminated.

The reporting requirements were revised to specify units to standardize
inputs into the data reporting system.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
A number of comments on pulp and paper manufacturing were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response document for pulp“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart AA: Pulp and paper manufacturing in the docket
(EPA-HQ-OAR-2008-508-XXX).Paper Manufacturing.”

Definition of Source Category

Comment:  Two commenters stated that literal interpretation of 40 CFR
part 98, subpart AA could require any facility operating paper coating
and laminating processes to report emissions for any system used to add
makeup chemicals.  The commenters requested that language be added to 40
CFR part 98, subpart AA to clearly exclude facilities not intended to be
covered and which have not traditionally been part of the pulp and paper
source category.

Response:  Definitions of terms used in 40 CFR part 98, subpart AA are
provided in 40 CFR 98.6 (in subpart A orof part 98).  The definition of
“makeup chemicals” is specific to the chemical recovery areas of
pulp mills and serves to limit the scope of the pulp and paper
subcategory.  As defined in §98.6 (emphasis added):

“Chemical recovery combustion unit means a combustion device, such as
a recovery furnace or fluidized-bed reactor where spent pulping liquor
from sulfite or semi-chemical pulping processes is burned to recover
pulping chemicals.”

“Makeup chemicals means carbonate chemicals (e.g., sodium and calcium
carbonates) that are added to the chemical recovery areas of chemical
pulp mills to replace chemicals lost in the process.”

Thus, we disagree that the rule could be interpreted to require any
facility operating coating and laminating processes to report emissions
for any system used to add makeup chemicals.  This was not the intent of
the rule.  Nevertheless, we have added language consistent with the
definition of “makeup chemicals” to 40 CFR 98.270(b)(5) and
98.272(e) to further clarify that GHG emissions are to be reported for
systems adding makeup chemicals (CaCO3 and Na2CO3) in the chemical
recovery areas of pulp mills.

Comment:  Commenters stated the rule should include categorical
exemptions for emissions from the combustion of non-condensable gases
(NCG), stripper off gases (SOG), tall oil and turpentine (small sources
of GHG that are difficult to measure).  The commenters noted that these
streams are of biogenic origin.  One commenter described safety issues
associated with sampling these gas streams.

Response:  Pulp mill NCG, SOG, tall oil and turpentine were discussed in
the Proposed Rule TSD for the pulp and paper manufacturing sector.  The
Proposed Rule TSD noted that process vent gases such as NCG and SOG and
the byproducts tall oil and turpentine are derived from biomass.  We
acknowledge the safety and measurement issues described by commenters
regarding sampling of NCG and SOG streams.  No methods are specified in
the rule for calculation of GHG associated with combustion of NCG, SOG,
tall oil and turpentine.  Thus, calculation of these emissions is not
required and there is no need for categorical exemptions.

Method for Calculating GHG Emissions

Comment:  Commenters stated that monthly measurements of the mass of
spent liquor solids, HHV, and carbon content of spent liquor solids are
unnecessary.  The commenters requested that EPA either allow default
fuel carbon content and heating value for spent pulping liquor, or
reduce the frequency of measurements to annually or every two years.
Commenters noted that spent liquor HHV and carbon content are measured
from time to time but less frequently than monthly.  In addition, one
commenter pointed out that chemical recovery furnaces often have online
solids meters installed to provide continuous measurement of the mass of
spent liquor solids entering the furnace for safety and process control
reasons.  This commenter requested that EPA allow use of such continuous
measurement devices instead of requiring monthly measurement of the mass
of spent liquor solids with TAPPI Test Method T 650.

Response:  We disagree with commenters that default fuel carbon content
and high heating values should be allowed instead of measured values.
These parameters are already measured by mills (though less frequently
than monthly) and thus are available for use and more accurate than
default values.  We are reducing the frequency of fuel property
measurements from monthly to annual.  There is little monthly variation
in fuel properties over the course of a year.  Therefore, annual
measurements are sufficient to develop site specific emission factors.
This change also reduces the burden associated with complying with the
rule. These changes have been incorporated throughout the text and
equations of 40 CFR part 98, subpart AA.

In addition, the final rule allows use of either an annual measurement
of the mass of spent liquor solids fired (with TAPPI Test Method T 650)
or use of annual spent liquor solids data calculated from continuous
measurements already performed for process control purposes (e.g., with
existing online solids meters).  If the annual spent liquor solids fired
is determined using existing measurement equipment, then reporters must
retain records of the calculations used to determine the annual mass of
spent liquor solids fired from the continuous measurements in order to
demonstrate, if necessary, that calculations where done correctly.
Reporters must also document that these measurement devices have been
regularly and properly calibrated according to the manufacturer’s
specifications.

Data Reporting Requirements

Comment:  One commenter noted that presenting quarterly data in annual
reports for pulp and paper manufacturing annual emissions, consumption
of biomass fuels, and quantity of spent liquor solids fired is
unnecessary for an annual reporting system.

Response:  We have revised §§40 CFR 98.276 and 98.277(a) to remove the
requirement for providing quarterly details in the annual report.  EPA
agrees that requiring quarterly details was not necessary for ensuring
the accuracy of data reported annually.

Comment:  One commenter requested that the spreadsheets developed by the
National Council for Air and Stream Improvement (NCASI) for the
International Council of Forest and Paper Associations (ICFPA) be
allowed as an option for facilities subject to the Rule to determine
emissions.  These spreadsheets segregate calculated GHG emissions into
fossil fuel and biogenic categories.  The commenter believes that tools
like those developed by NCASI and others should be allowed as an option
for facilities subject to the emission calculation requirements imposed
by the Rule at §98.40 CFR 98.3.  This streamlined approach will provide
the Agency with valid GHG emission data without imposing extraordinary
capital and labor burdens on the industry.

Response: The ICFPA/NCASI tools were considered in developing the
requirements of the GHG reporting rule.  However, the ICFPA/NCASI
spreadsheets, though valuable tools, are not broadly applicable to all
industrial sectors covered under the GHG reporting rule, as are the
monitoring, reporting, recordkeeping, and emissions verification
requirements specified in 40 CFR 98.3.  Additionally, these tools often
use default factors and estimates, which differs from the approach
proposed by EPA.  The data collected from all subparts of the GHG
reporting rule will be tabulated in EPA’s electronic reporting system.
 This system will be used to verify emission calculations and will
require specific data be reported in order to run the calculations used
for verification.  The tools suggested by the commenter, however, would
only provide a total emission number.  Consequently, EPA would not be
able to check the underlying calculations for accuracy.  The final GHG
reporting rule reflects the data reporting requirements necessary for
emissions verification by EPA.  Edits to the reporting and recordkeeping
language (40 CFR 98.276 and 98.277) of 40 CFR part 98, subpart AA were
made to clarify calculation inputs and units of measure to be reported.
As part of the implementation phase of today’s final rule, EPA intends
to prepare guidance documents to assist the industry in complying with
the rule’s requirements.  In recognition of the fact that the pulp and
paper industry has been using the ICFPA/NCASI spreadsheets, EPA will
consider including in the guidance materials a comparison between these
spreadsheets and the EPAEPA’s electronic reporting system to reduce
the burden on the industry and minimize confusion.

BB.  Silicon Carbide Production

1.  Summary of the Final Rule

Source Category Definition.  The silicon carbide production source
category consists of any process that produces silicon carbide for
abrasive purposes.

Reporters must submit annual GHG reports for facilities that meet the
applicability criteria in the General Provisions (40 CFR 98.2)
summarized in Section II.A of this preamble.

GHGs to Report.  Report process CO2 and CH4 emissions from all silicon
carbide production furnaces or process units at the facility combined.

In addition, report GHG emissions for other source categories at the
facility for which calculation methods are provided in the rule, as
applicable.  For example, report CO2, N2O, and CH4 emissions from each
stationary combustion unit on site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources).

GHG Emissions Calculation and Monitoring.  For CO2 emissions, reporters
must use one of the following methods, as appropriate:

Most reporters can elect to calculate and report process CO2 emissions
from silicon carbide production processes by either (1) installing and
operating CEMS and following the Tier 4 methodology (in 40 CFR part 98,
subpart C) or (2) calculating emissions using the measured petroleum
coke consumption and a monthly facility-specific emission factor.  The
facility-specific emission factor is the carbon content of the petroleum
coke (provided monthly by the supplier or measured monthly using the
appropriate test methods) adjusted for carbon in the silicon carbide
product.

However, if process CO2 emissions from silicon carbide production are
vented through the same stack as a combustion unit or process equipment
that uses a CEMS and follows Tier 4 methodology to report process CO2
emissions, then the CEMS must be used to measure and report combined CO2
emissions from that stack.  In such cases, the reporter cannot use the
CO2 calculation approach (2) outlined in the above bullet.

For CH4 emissions, reporters must use the measured petroleum coke
consumption and a default emission factor of 10.2 kilograms (kg) per
metric ton of coke consumed.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that are
used to calculate GHG emissions.  A list of the specific data to be
reported for this source category is contained in 40 CFR part 98,
subpart BB.

Recordkeeping.  In addition to the records required by the General
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this
preamble, reporters must keep records of additional data used to
calculate GHG emissions.  A list of specific records that must be
retained for this source category is included in 40 CFR part 98, subpart
BB.

2.  Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
below or in the comment response document for“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Subpart BB: Silicon
Carbide Production.”

The emissions calculation method under 40 CFR 98.283(b) was revised to
require data on monthly petroleum coke consumption and monthly petroleum
coke carbon contents rather than quarterly determinations.

Missing data procedures were added under 40 CFR 98.285 for monthly
parameters used to calculate emissions, including mass of petroleum
coke, and carbon contents of petroleum coke.

Section40 CFR 98.286 was reorganized and updated to improve the
emissions verification process.  Some data elements were moved from
section40 CFR 98.287 to section40 CFR 98.286, and some data elements
that a reporter must already use to calculate GHGs as specified in
section40 CFR 98.283 were added to section40 CFR 98.286 for clarity.

3.  Summary of Comments and Responses

No specific comments were received pertaining to the proposed reporting
requirements for silicon carbide production facilities.  However, the
proposed rule did not clearly not specify how quarterly carbon contents
should be determined.  This determination should be made on a monthly
basis as proposed for other chemical production processes where process
emissions arise from use of petroleum coke, such as titanium dioxide
production.  Quarterly reporting of carbon contents of petroleum coke
consumed for the quarter would have to be averaged from monthly data.
For verification, EPA would require reporting of the monthly carbon
contents of the petroleum coke.  Therefore, we revised the emissions
calculation method to directly require monthly petroleum coke
consumption and monthly petroleum coke contents, rather than quarterly
based on an arithmetic average of the monthly estimates to improve
accuracy of emissions calculations.  We have retained the flexibility in
use of supplier data to determine carbon contents.  We understand that
most supplier data on carbon contents of petroleum coke is readily