data for the report and initiate QA activities during the year as the
data are collected.  Reporters would then only have to compile the most
recently collected information, complete the final calculations, and
review and certify the annual report after the reporting period has
ended.  Because the reports required by the rule rely on well-defined
calculation methodologies, EPA determined that three months is a
sufficient amount of time to complete the report.  Moreover, as
discussed in Section III of this preamble for the specific subparts, we
have made several changes to reporting requirements that will ease
burden and further facilitate reporting by March 31. In addition, EPA
intends to provide outreach and training on rule requirements and an
electronic reporting system that will help expedite report submission.

The March 31 reporting deadline is also consistent with the reporting
deadline implemented in 2005 for reporting GHG emissions under the EU
Emissions Trading System and is longer than the deadlines allowed for
reporting under many other CAA programs.  For example, many NESHAPs and
NSPSs, including those for large complex industrial facilities such as
chemical plants and refineries, require reports of excess emissions and
monitoring system performance to be submitted within 30 calendar days of
the end of each compliance period.  The ARP and Regional Greenhouse Gas
Initiative (RGGI) programs, which are established emission cap and trade
programs that rely on the same types of data many sources will have to
submit under the GHG reporting rule, require facilities to submit their
quarterly emissions reports within 30-days of the end of each quarter.

2.  Making Corrections to Annual Reports

Comment: Several commenters representing multiple stakeholders suggested
the rule should include provisions to submit revised annual reports.
Many commented that even with good-faith efforts to follow all the
monitoring and reporting requirements, there will likely be
unintentional errors that are not discovered by the reporter or by EPA
until after an annual report is submitted.  Some commenters added that
given the stringency of the self-certification provisions and potential
penalties involved, reporters need a way to submit corrected data, and
some provided examples of other reporting rules that include provisions
to submit revised reports.

Response: EPA has addressed this comment in the final rule.  We have
added a provision in 40 CFR 98.3 that requires the reporters to submit a
revised GHG report within 45 days of discovering or being notified by
EPA of errors in an annual GHG report.  The revised report must correct
all identified errors.  We agree that it is important for facilities to
correct errors, regardless of whether they are discovered by the
reporter or by EPA.  In order to ensure accurate data for future GHG
policies and programs, known errors should be corrected.  Furthermore,
adding a requirement to submit corrected reports is consistent with
other EPA reporting programs, such as ARP and TRI, as well as State and
other GHG programs.  EPA intends to review the annual GHG reports
submitted under this rule by performing electronic data QA checks and a
range of other emission verification activities.  When we find reporting
errors (as we have in ARP and other reporting programs), we will notify
reporters of errors and require them to submit revised reports.  The
time period of 45 days was selected to allow reporters time to retrieve
any needed data, perform revised calculations, and resubmit the report.
Because data for the calendar year covered by the report has already
been collected and must be retained according to the rule, it should be
readily available for any reanalyses needed to correct a reporting
error.  Given that facilities are allowed 3three months from the end of
a reporting period to submit the annual report, revising a report to
address a known error would logically require less time and EPA
concluded that 45 days is sufficient.

K.  Summary of Comments and Responses on De minimis Reporting

Comment:  Some commenters suggested that de minimis cutoffs or
simplified methods for de minimis sources should be provided to be
consistent with other programs, such as the California mandatory GHG
reporting rule.  The commenters argued that it makes sense to focus
effort on the significant emissions sources at a facility, rather than
spending a lot of effort to precisely calculate emissions from sources
that are a small percent of a facility’s total emissions.

Response:  EPA considered public comments on de minimis reporting, both
general comments and those received on individual source categories, in
addition to the analyses of de minimis provisions we conducted at
proposal of the rule.  Based on these considerations, we concluded that
de minimis provisions are not necessary for this rule.

As discussed in the preamble to the proposal (74 FR 16448, April 10,
2009), many existing reporting programs require corporate level
reporting of all emissions, including emissions from numerous remote
facilities and small onsite equipment (e.g., lawn mowers).  Other
reporting programs require reporting at the facility level but require
reporting of emissions from all types of emission sources.  These
reporting programs recognize that it may not be possible or efficient to
specify the reporting methods for every source that must be reported and
include de minimis provisions to reduce the reporting burden.  The de
minimis provisions included in these programs either allow the reporter
to exclude a portion of their emissions (e.g., the DOE 1605(b) voluntary
reporting program allows up to 3three percent of facility-level
emissions to be excluded) or allow simplified calculation methods for
small sources.

Since reporters must determine the de minimis emissions even when
reporting is not required, the trend for both mandatory and voluntary
reporting programs is to require reporting of all emissions but allow
simplified calculation methods for small sources of emissions.  Hence,
the de minimis provisions included in many existing reporting programs
are designed to avoid potentially unreasonable reporting burdens where
the reporting rule does not provide simplified calculation methods for
smaller emissions sources. . For example, TCR allows reporters to use
simplified calculation methods of their own design for calculating up to
5five percent of their emissions.  Some programs recognize that a small
percentage of emissions may still represent a large mass of emissions.
For this reason, some existing reporting programs include a cap on the
mass of de minimis emissions.  For example, both the California
mandatory reporting rule and EU Emissions Trading System cap de minimis
emissions at 20,000 metric tons CO2e/year cap.  For additional
information on the treatment of de minimis in existing GHG reporting
programs, please refer to the “Reporting Methods for Small Emission
Points (De Minimis Reporting)” (EPA–HQ–OAR–2008–0508–0048).

In contrast to such existing programs, this rule already avoids
burdensome reporting requirements for smaller emissions sources in two
ways.  First, the rule excludes small facilities through the application
of the 25,000 metric tons of CO2e threshold.  As described earlier in
this preamble, that threshold appropriately balances the number and size
of reporter with the coverage of emissions.  The source categories
included in the rule are typically for larger sources of emissions.
Second, reporters must report only the emissions from sources for which
calculation methods are provided in the rule.  Calculation methods are
generally not included for smaller sources of emissions (e.g., coal
piles on industrial sites, mobile sources, lawn equipment).  In some
cases, where a source category includes relatively small sources, the
rule provides simplified emissions calculation methods for those
sources.  For example, reporters may use a default emission factor and
heat rate to calculate emissions from small stationary combustion units,
rather than the fuel measurements required for larger stationary
combustion units.  Given that this rule has taken steps to avoid
burdensome calculations, we have concluded that de minimis reporting
cutoffs are not necessary.

Furthermore, de minimis cutoffs would compromise the quality of the data
collected.  The goal of this rule is to collect accurate and consistent
data of sufficient quality to inform future CAA policy and regulatory
decisions.  Allowing sources to report up to 20,000 metric tons CO2e
emissions annually using their own simplified calculation methods (as
allowed under some programs) would impact the usefulness of the data.
The reported emissions would not be comparable across a given industry
because the calculation methods, accuracy and reliability of a portion
of the reported emissions would vary substantially from one reporter to
another.

In response to comments, we have made several changes to this rule that
further reduce any need for a de minimis reporting provision.  As
discussed in Section III of this preamble for individual source
categories, we have revised monitoring and reporting requirements to
allow simpler GHG calculation methods for many combustion units and
other source categories.  These changes reduce the reporting burden for
various types of small emission sources.  Also, as noted earlier in
Section II.D of this preamble, there are a number of source categories
that are not being finalized at this time.  A few of them (e.g.,
industrial landfills and wastewater) represent the type of emission
sources that commenters referenced as de minimis at some facilities.
EPA is taking some additional time with these sources categories, which
affects commenters in two ways:  1) until EPA promulgates a final rule
for these source categories, these  emissions would not be included in a
facility’s annual report and 2) EPA can further consider the comments
and evaluate our options with respect to the methods for these source
categories to ensure the methods adequately address our need for high
quality data as well as recognize the commenters’ requests for
additional flexibility for smaller sources.

L.  Summary of Comments and Responses on General Monitoring Approach

This section contains a brief summary of major comments and responses on
general monitoring requirements.  See sections III.C through PP of this
preamble for summaries of comments and responses on specific monitoring
requirements for the individual source categories contained in 40 CFR
part 98, subparts C through PP.  A large number of comments were
received on general monitoring requirements covering numerous topics.
Responses to significant comments received can be found in “Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
General Montoring Approach, the comment response documents
(EPA-HQ-OAR-2008-0508-XXX).Need for Detailed Reporting, and Other
General Rationale Comments.”

Comment:  Many commenters favored the general monitoring approach
contained in the proposed rule, which is a combination of direct
emissions measurement and facility-specific calculations.  These
commenters agreed that the selected approach results in high quality
data and strikes a reasonable balance between data accuracy and cost.
Other commenters believed that the approach contained in the proposed
rule is overly stringent and costly.  They contended that since the data
are not being used to demonstrate compliance with a cap and trade
program or other regulation with emission limits or emissions reduction
requirements, a lower level of accuracy is acceptable, simpler
monitoring approaches should be allowed, and/or facilities should have
flexibility to choose monitoring methods.  Some commenters requested
clarification on whether there were accuracy requirements or performance
standards for flow monitoring equipment, outside of the accuracy
requirements already required for CEMS.  Some commenters requested
clarification on whether upgrades to CEMS were needed under various
circumstances.  Some requested additional time for upgrading CEMS or
installing and calibrating other equipment such as flow meters.

Response: After reviewing the comments in light of the analysis
presented in Section IV.H of the preamble to the proposed rule (74 FR
16474, April 10, 2009), EPA decided not to change the general monitoring
approach from the proposal.  In general, the rule requires direct
measurement of emissions from certain units that already are required to
collect and report data using CEMS under other programs (e.g., ARP,
NSPS, NESHAP, State Implementation Plans (SIPs)).  In some cases, this
may require upgrading existing CEMS that currently monitor criteria
pollutants to also monitor CO2 or add a volumetric flow meter.  For
facilities with units that do not have CEMS installed, reporters have
the choice to either install and operate CEMS to directly measure
emissions or to use facility-specific GHG calculation methods.  The
measurement and calculation methods for each source category are
specified in each subpart.  As policies and programs evolve and/or
particular calculation or monitoring equipment improves EPA will
evaluate whether or not to update the methodologies in this rule.

The data collected by the rule are expected to be used in analyzing and
developing a range of potential CAA GHG policies and programs.  A
consistent and accurate data set is crucial to serve this intended
purpose.  Therefore, the selected monitoring approach that combines
direct measurement and facility-specific calculations is warranted even
though the rule does not contain any emissions limits or emissions
reduction requirements.  EPA remains convinced that this approach
strikes an appropriate balance between data accuracy and cost.  It makes
use of existing data and methodologies to the extent feasible, and
avoids the cost of installing and operating CEMS at numerous facilities.
 It is consistent with the types of methods contained in other GHG
reporting programs (e.g., the California mandatory reporting rule, WCI,
RGGI, TCR, and Climate Leaders).  Because this option specifies methods
for each source category, it will result in data that are comparable
across facilities.

EPA chose not to adopt simplified calculation methods as a general
monitoring approach (e.g., using default emission factors) because the
data would be less accurate than under the selected option and would not
make use of site-specific data that many facilities already have
available and refined calculation approaches that many facilities are
already using.  EPA is not allowing reporters full flexibility to use
any method because the accuracy and reliability of the data would be
unknown.  Because consistent methods would not be used under such an
approach, the reported data would not be comparable across similar
facilities.

While the general approach is unchanged, it is important to note that
EPA has made changes to the General Provisions and to the specific
monitoring requirements for particular source categories in response to
public comments on the proposal.  EPA has added to the General
Provisions (40 CFR part 98, subpart A) an accuracy specification of plus
or minus 5five percent for the calibration of flow meters used to
collect data for the emissions calculations under this rule.  It
provides procedures for calculating calibration error, including
specific procedures for orifice, nozzle, and venturi flow meters.  Given
the comments that were submitted regarding concerns on the timing of
performing meter calibration, EPA is providing flexibility to reporters
subject to certain operational limitations.  For example, facilities
that operate continuously may postpone calibration until the next
scheduled maintenance outage to avoid operational disruptions.

Individual rule subparts for each source category, rather than the
General Provisions, contain the specific monitoring methods for that
source category.  Comments received on the specific methods are
described and responded to in Section III of this preamble and in the
comment response documents for the relevant subparts.source category
volumes of “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments.”  Where appropriate, the final rule has been
modified based on those comments.  For example, since proposal, in
response to public comments, EPA has made changes to individual subparts
of 40 CFR part 98 to clarify when CEMS and CEMS upgrades are required
and has made other changes to reduce the monitoring burden.  Interested
parties are encouraged to review the relevant sections of the preamble
and rule.  Furthermore, some subparts for which significant monitoring
approach comments were received are not included in the final rule and
will be consideredfinalized later as explained in Section II.D of this
preamble.  These changes to the rule address monitoring approach
concerns raised by some commenters.

Comment: Some commenters expressed concern that duplicative reporting
would occur if the rule was interpreted to require a reporter to submit
data on general stationary fuel combustion emissions at a facility both
under 40 CFR part 98, subpart C and also under one of the other source
category subparts that applies to the same facility.  Some of them
indicated that language used in the source category subparts to
reference subpart C was not sufficiently clear and consistent.  Other
commenters indicated the proposed rule was not clear about whether CEMS
can be used to report combustion emissions, process CO2 emissions, or
combined emissions.

Response: EPA reviewed each subpart in light of these comments and
acknowledges that the proposed rule language referencing 40 CFR part 98
subpart C and the language discussing the of CEMS was inconsistent
between subparts and was not always clear.  EPA has revised the final
rule to clarify our intent.

As indicated by the commenters, many manufacturing facilities are
subject to one of the source category subparts and also to the general
stationary fuel combustion subpart.  For most facilities, emissions from
stationary fuel combustion sources (e.g., boilers or engines) are
emitted from separate equipment and through separate stacks/emission
points than process GHG emissions covered by 40 CFR part 98, subparts E
through GG.  We have edited the rule to make it clear that in such
cases, the reporter would report stationary fuel combustion emissions
under 40 CFR part 98, subpart C, and they would report process GHG
emissions under each applicable source category subpart.

We have further clarified those source category subparts that require
reporting of process CO2 emissions.  We have made it clear that the
reporter can elect to monitor and report process CO2 emissions by
either: (1) installing and operating CEMS and following the Tier 4
methodology in 40 CFR part 98, subpart C, or (2) using the source
category-specific monitoring and calculation procedure specified in the
subpart.  In either case, process CO2 emissions would be reported under
the source category subpart.  The source category subparts have also
been revised to specify that if process CO2 emissions are comingled with
and emitted through the same stack as emissions from combustion units or
process equipment required to use CEMS, than the reporter must use the
CEMS and follow the Tier 4 methodology to report combined emissions from
the common stack under the specified subpart.  This approach makes sense
for comingled emissions because CEMS accurately measure total stack CO2
emissions and the reporter would not be able to accurately separate the
fraction of the CO2 emissions that came from the combustion units and
process emission points that are comingled in the same stack.

Source categories with direct-fired equipment (e.g., kilns, furnaces)
present a special situation.  Examples include cement production, glass
production, lead production, lime manufacturing, and soda ash
manufacturing.  In direct-fired units, fuel combustion emissions and
process emissions are both generated within the kiln or furnace and are
always emitted together.  If CEMS are used on such units, the CEMS will
always be measuring combined combustion and process emissions.  The
language regarding CO2 reporting and use of CEMS for these source
categories has been clarified and harmonized to reflect this situation.

For kilns or furnaces in these source categories that have CEMS in place
and meet specified conditions, the reporter must use the CEMS and follow
Tier 4 methodology to determine combined process and combustion CO2
emissions.  The combined emissions are reported under the relevant
source category subpart (e.g., for cement production, combined
combustion and process emissions from a kiln with a CEMS would be
reported under 40 CFR part 98, subpart H, Cement Production).

For other kilns or furnaces in these source categories, the reporter has
the choice to (1) install and operate CEMS to measure combined process
and combustion CO2 emissions, or (2) calculate process CO2 emissions
using the source category-specific monitoring and calculation procedures
contained in the subpart.  If reporters don’t have CEMS and choose the
source category-specific calculation approach, then they report process
CO2 emissions under the relevant source category subpart, and report
combustion emissions under 40 CFR part 98, subpart C (general stationary
fuel combustion).

See the sections for the relevant source categories in Section III of
this preamble for summary and discussion of the specific monitoring and
reporting requirements for each source category.

M.  Summary of Comments and Responses on General Recordkeeping
Requirements

This section contains a brief summary of major comments and responses on
the general recordkeeping requirements contained in the general
provisions (40 CRRCFR part 98, subpart A).  See sections III.C through
PP of this preamble for summaries of comments and responses on specific
recordkeeping requirements for the individual source categories
contained in 40 CFR part 98, subparts C through PP.  A large number of
comments were received on general recordkeeping requirements covering
numerous topics.  Responses to significant comments received can be
found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart A, Content of the comment response documents
(EPA-HQ-OAR-2008-508-XXX).Annual Report, the Abbreviated Emission
Report, Recordkeeping, and the Monitoring Plan” and in the individual
source category volumes of “Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments.”

1.  Record Retention

Comment:  Several commenters suggested that EPA require retention of
records for 3three years rather than the 5five years specified in the
proposed rule.  Some of these commenters stated that 3three years is
consistent with ARP, which is a comparable program that requires
electronic reporting of similar, detailed data.  Many contended that
retaining the large amount of data required by this rule for 5five years
rather than 3three years is overly burdensome and is not necessary.
They indicated that 3three years of records is sufficient to allow
verification of annual GHG reports.  A smaller number of commenters
supported record retention for 5five years, which is consistent with
permitting and other programs.

Response:  In response to public comments, EPA has changed the record
retention requirement in the final rule from 5five years to 3three
years.  We agree that a 3-year time period is sufficient to allow for
EPA audit and review of records needed to verify the emissions data
submitted in annual reports.  Changing the record retention duration
to 3three years will reduce the recordkeeping burden for many facilities
reporting under this rule.  As stated by various commenters, a 3-year
record retention requirement would be consistent with the
recordkeeping provisions of the ARP and other Federal reporting
programs, including the TRI rules and the DOE Energy Information
Administration'sAdministration’s 1605(b) Voluntary Reporting of GHG
Emission and Reductions program.

2.  Monitoring Plan

Comment:  We received several comments on the QAPP recordkeeping
requirement in proposed 40 CFR 98.3(g).  Some had questions about the
content and level of detail required in the QAPP, and indicated it would
be a costly and burdensome requirement.  Others stated that the QAPP
would be duplicative of their facility SOPs or documentation kept under
ARP or other programs.  Some commenters indicated that the list of items
to report in 40 CFR 98.3(g) was repetitive because a few of the items
listed separately would typically be contained in a QAPP.

Response: The final rule requires a “monitoring plan.”  The
“QAPP” terminology in the proposed rule caused confusion because
“QAPP” is used in a variety of other contexts, has various
connotations to different readers, and caused readers to presume
requirements EPA did not intend.  The final rule specifies monitoring
plan contents such as:

Identification of persons responsible for collecting emissions data.

Explanation of the processes and methods used to collect the necessary
data for the GHG emissions calculation.

Description of the procedures that are used for QA, maintenance, and
repair of all CEMS, flow meters, and other instrumentation used to
provide data for the GHG emissions reported under 40 CFR part 98.

The first two items in this list were formerly listed as separate line
items in the recordkeeping requirements, but would logically be a part
of the monitoring plan, so were consolidated under the monitoring plan
to avoid repetition.

The monitoring plan paragraph in the final rule explicitly states that
the monitoring plan can rely on references to existing corporate
documents.  Such documents include SOPs, QA programs under Appendix F to
40 CFR part 60 or Appendix B to 40 CFR part 75, and other documents
provided that the information required by the monitoring plan is clearly
recognizable.  The provision allowing the monitoring plan to refer to
such documents avoids duplicative effort and addresses the
commmenters’ concerns that monitoring plan information is already
contained in other documents.

The final rule also contains a provision to update the monitoring plan.
Reporters would need their monitoring plan to be up to date in order to
ensure that facility or supplier personnel follow the right monitoring
and QA procedures and that the reporter meets the requirements of the
reporting rule.  Likewise, EPA needs to be able to view an up-to-date
monitoring plan during facility audits.  Updates to the plan would be
needed if, for example, the facility makes a process change, changes
monitoring instrumentation or QA procedures, or improves procedures for
maintenance and repair of monitoring systems to reduce the frequency of
monitoring equipment downtime.

N.  Summary of Comments and Responses on Emissions Verification Approach

This section contains a brief summary of major comments and responses on
emissions verification of the GHG reports.  A large number of comments
were received covering numerous topics.  Responses to significant
comments received can be found in the comment response documents
(EPA-HQ-OAR-2008-0508-XXX).“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Approach to Verfication and Missing
Data.”

Comment: The majority of Many commenters, including most facilities and
suppliers required to report under the rule and several other
stakeholders, supported EPA’s proposal to require self-certification
with EPA verification of GHG reports.  These commenters provided a
variety of reasons.  Many supported EPA emissions verification because
the alternative of third party verification would be more costly to
reporters.  Several also commented that EPA emissions verification would
provide a consistent and transparent data set.

Some otherOther commenters suggested that EPA require third party
verification of GHG reports, and they provided a variety of reasons.  A
few noted that third party verification is consistent with other GHG
reporting systems (e.g., the European Emissions Trading Scheme, The
Climate Registry, the California mandatory GHG reporting rule, and other
stateState programs).  Many stated that third party emissions
verification will improve the quality of the data submittals and told us
that third party verification led to the correction of inaccuracies in
GHG emission reports submitted under other programs.  Some of the
commenters questioned whether EPA would have the time to conduct
verification, given the number of reports and volume of supporting data
that must be submitted.  Others were concerned that EPA verification
requires submittal of detailed supporting data and contended that some
of these supporting data would be CBI.

A smaller number of commenters favored self-certification without
independent emissions verification.  They believed the designated
representative provisions in the rule would cause reporters to take
self-certification seriously and ensure the emissions they report are
correct.  Some also stated that independent verification is not needed
for a reporting program that does not require emissions reductions.

Response:  In selecting the approach to emissions verification, EPA
reviewed all of the comments, as well as emissions verification
requirements and procedures under a number of existing EPA regulatory
programs and domestic and international GHG reporting programs.  Based
on this review, EPA considered three alternatives: (1)
self-certification without independent verification, (2)
self-certification with third party verification, and (3)
self-certification with EPA verification.  For this particular program,
EPA is not changing the verification approach from the proposal and is
requiring self-certification with EPA emissions verification.  We
decided to retain this verification approach because it provides greater
assurance of accuracy and impartiality than self-certification without
verification, and has a number of advantages over third party
verification for this type of Federal program.  Our objective with
emissions verification in this program is to ensure collection and
dissemination of high-quality data while providing the reporters a
“level playing field” in terms of requirements and process.

To enable effective review of the large volume of data reported, the
rule requires reporters to submit data electronically in a standard
format through a centralized data system.  EPA is developing this system
and intends to make it available to reporters, along with training and
instructional materials, before the reporting deadlines.  To the extent
possible, EPA will leverage existing reporting systems and work with
other State and regional programs and systems to develop a reporting
scheme that minimizes the burden on reporters.

In implementing the emissions verification under this rule, EPA
envisions a two step process.  First, we will conduct an initial
centralized review of the data which will be largely automated.  EPA
intends to build into the data system an electronic data QA program for
use by reporters and EPA to help assure the completeness and accuracy of
data.  In addition, to verify reported data and ensure consistency, EPA
may review facility-level monitoring plans and procedures, and will
perform detailed, automated checks on data utilizing recent and
historical data submittals, comparison against like facilities and/or
other electronic audit tools where appropriate.  Second, EPA intends to
follow-up with facilities should potential errors, discrepancies, or
questions arise through the review of reported data and conduct on-site
audits of selected facilities.  The on-site audits may be conducted by
private verifiers contracted by EPA or by Federal, State or local
personnel, as appropriate.  We plan to coordinate closely with the
States to develop an efficient approach toward on-site auditing that can
meet the needs of multiple programs.  We do not anticipate conducting
on-site audits of every facility every year.

EPA decided to finalize the rule with EPA emissions verification for
several reasons.  First, we determined that the combination of
comprehensive electronic review and a flexible and adaptive program of
on-site auditing will enable us to effectively target verification
resources while also providing the necessary consistency and quality in
the data.  Utilizing the national data set developed under this rule
will provide unique resources for the review of reports.  A centralized
emissions verification system provides greater ability for EPA to
identify trends and outliers in data and thus assist with targeted
follow-up review, and our approach can evolve over time as we gain
experience with GHG reporting.  This approach also provides opportunity
to work closely with and leverage both the experience and ongoing
activities of States and others already engaged in similar and different
types of GHG reporting.

Our emissions verification approach in this rule is consistent with
other EPA emission reporting programs and follows a model similar to the
ARP which is a highly successful emissions cap and trade program that
consistently produces credible, high-quality data.  Facilities regulated
under ARP must have a Designated Representative sign data reports to
self-certify that the reported data are accurate.  Then, facilities and
EPA use a series of electronic tools to ensure proper data collection
and reporting, including establishing a monitoring plan, calibrating
equipment to certain specifications, frequent testing and data
submittal.  Similar to what we are intending with this program, EPA
conducts site audits on those facilities targeted during the electronic
review as having been outliers or had anomalies in their reported data.
These audits are done by EPA personnel, States and/or contractors to
EPA.  We support these audits by providing a field audit manual to both
government and private auditors as well as additional training to State
and Federal auditors.

Second, this approach is the best way to address the many comments we
received on the importance of obtaining 2010 data and making the data
widely available.  EPA has determined that this verification approach
will enable us to make data available more quickly than under a third
party verification approach.  We will be able to share a complete data
set promptly upon completion of the electronic review (subject to
relevant CBI concerns, please see the discussion of our plans to address
CBI and emissions data in Section II.S of this preamble and the
associated“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments document [docket #]))., Legal Issues”).  We
determined that the third party verification approach could take from
3three to 6six months after initial data submission, and EPA would still
need to review and perform consistency checks after the third party
verification was complete.

In addition, developing the third party verification apporachapproach
would require EPA to establish and develop emissions verification
protocols and a system to qualify and accredit the third party
verifiers, and to develop and administer a process to ensure that
verifiers hired by reporting facilities do not have conflicts of
interest.  Such a program could require EPA to review numerous
individual conflict of interest screening determinations made each time
a reporter hires a third party verifier.  Even if EPA were to partner
with an existing program or organization to accredit verifiers, EPA
would still need to develop the criteria and systems described above to
implement this rule and ensure high quality emissions verification given
the unique reporting requirements of this rule.  These efforts would
slow down implementation of the rule and sharing of data.

Finally, we agree with many of the commenters regarding their concerns
about the cost of third party verification.  Given the information
currently available to us, under a third party verification approach we
would have required that each facility verify its submission each year.
As a national reporting program with a substantially larger number of
reporters than existing State programs, we determined that the costs to
the reporters of third party verification would have been substantial.
By finalizing self-certification with EPA emissions verification for
this rule, it also ensures a lower cost burden for reporters.

EPA’s decision to use self certification with EPA emissions
verification was made in the context of the specific scope of this
rulemaking, the types of data to be collected, and the intended uses of
the emissions data.  For other types of programs (e.g., offsets,
corporate footprinting, energy efficiency) other verification approaches
may be more suitable.  We recognize that many GHG reporting and
reduction programs developed by the States and Regions are broader in
scope and for this and other reasons, the use of third party verifiers
is an appropriate way to verify the data they collect.  EPA’s decision
in this rulemaking does not pre-empt State GHG reporting programs or any
other programs from requiring third party verification.  More
importantly, the selection of EPA emissions verification for this rule
is not intended to suggest that third party verification cannot result
in accurate, high quality data.

EPA received a smaller number of comments in support of
self-certification without emissions verification.  While recognizing
that this approach would place a low burden on both reporters and the
government, it also has major disadvantages.  Without any verification
of submitted reports, there is far greater potential for inconsistent
and inaccurate data and this will result in less confidence at EPA and
with public stakeholders in the data.  These disadvantages would make
the data collected under this option less useful for informing decisions
on climate policy and supporting the development of potential future
policies and regulations.

Comment:  Commenters asked what role State and local regulatory agencies
will have in verification of reported emissions data.  Some suggested
that State and local agencies should assist with emissions verification
because they already have detailed knowledge of the facilities in their
areas.  Some indicated that States would need resources to play a role
in verification and other rule implementation activities.

Response:  While EPA is responsible for emissions verification as
explained in the previous response, EPA will likely enlist State
assistance, when it is available, during the implementation phase of the
final rule.  (However, State and local agencies will not be required to
provide EPA any assistance with verification or implementation
activities, given State and local agency resource constraints and
priorities.)  For example, in concert with their routine inspection and
other compliance and enforcement activities for other CAA programs,
State and local agencies could, as resources allow, assist with
educating facilities and assuring compliance at facilities subject to
this rule.

Assistance from State and local agencies could include such activities
as identifying the facilities for on-site audits or conducting audits
where appropriate.  This type of assistance from State and local
governments has been valuable in other programs.  State and local air
pollution control agencies routinely interact as part of other
regulatory programs with many of the sources that would report under
this rule.  States have knowledge of specific facilities and sources
that would be required to report under this rule.  In addition, many
States have already implemented or are in the process of implementing
GHG reporting and reduction programs.  Therefore, some State and local
agencies willcould serve an important role in communicating the
requirements of the rule and providing compliance assistance.

O.  Summary of Comments and Responses on the Role of States and
Relationship of this Rule to Other Programs

This section contains a brief summary of major comments and responses.
A large number of comments on the relationship between this rule and
other programs were received covering numerous topics.  Responses to
significant comments received can be found in the comment response
documents (EPA-HQ-OAR-2008-0508-XXX).“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Relationship to
Other GHG Reporting Programs” and “Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Legal Issues.”

Comment:  Several commenters requested that EPA make it clear that
States can collect additional GHG data under State rules and GHG
programs and are not limited to collecting only the data in this Federal
mandatory reporting rule.  Other commenters requested that this rule
pre-empt or supersede State GHG reporting rules.

Response:  EPA reaffirms that States can collect additional data under
State rules and GHG programs, and that this rule does not pre-empt or
replace State reporting programs.  This rule has been developed in
response to a specific request from Congress (in the Appropriations Act)
and is narrower and more targeted than many existing State programs that
are coupled with GHG emission reduction programs.  As EPA stated in
Section II of the proposal preamble (74 FR 16457, April 10, 2009) and
Section I.E of this preamble, many State programs are broader in scope,
in a more advanced state of development, and have different policy
objectives than this rulemaking.  These are important programs that not
only led the way in reporting of GHG emissions before the Federal
government acted but also have catalyzed important GHG reductions.

EPA supports and recognizes the success and necessity of State programs
as a vital component in achieving GHG emissions reductions, particularly
those focused on energy efficiency improvements.  It is appropriate that
State and Regionalregional GHG reporting and reduction programs have
different scopes or implementation schedules, and that they require
reporting of different information than this rule for various
program-specific reasons.  For example, some State programs might
require reporting of electricity purchases and other data to provide
information for energy efficiency programs; they may require or allow
reporting of a variety of indirect emissions to gather data to help
facilities reduce their carbon footprint; they may require or allow
reporting of emissions such as from fleet vehicles to encourage fleet
operators to take steps to reduce emissions; or they may be  developing
or implementing GHG reduction rules including cap and trade programs,
and require specific information on emissions and offsets to implement
those programs.  State programs already have, or may evolve to include,
additional monitoring and reporting requirements than those included in
this rule.  Many States are actively collecting additional data they
need for their programs and policies, and this reporting rule does not
pre-empt State programs.

Comment:  Some commenters were concerned that the Federal GHG reporting
rule will result in duplicative reporting for facilities that are also
reporting GHG emissions under State rules or voluntary GHG reporting
programs.  Some requested that to reduce burden, facilities should be
required to submit data only once, and not have to submit different data
to multiple different programs.  Some commenters strongly recommended
that the electronic data systems used by this reporting rule and other
programs need to be consistent and allow data exchange between this rule
and TCR, State rules, National Emissions Inventory (NEI), ARP, or other
programs.  Many commenters supported submittal of all data directly to
EPA, while others favored delegation of data collection to State
agencies to encourage consistency between State and Federal data
collection efforts.

Response:  EPA carefully considered the issue of state State delegation,
particularly in light of the leadership and experience of several
statesStates in developing GHG reporting and reduction programs, and
also in the context of the pressing need for a national reporting
program and the strong emphasis placed by the vast majority of the
commenters on this rule for EPA to ensure that data collection begins on
January 1, 2010 and that data are reported early in 2011.  We determined
that developing a program to delegate to statesStates would take
additional time and would not be available for 2010 reporting, and we
also determined that a significant number of statesStates would likely
not request delegation, which would increase the complexity of
assembling a consistent national data set.  For these reasons, we
determined that the most effective way to achieve nationwide GHG
reporting of 2010 data was for reporters to submit data directly to EPA,
as proposed.  Additional reasons for selection of this data flow
approach are described in the response on emissions verification in
Section II.N of this preamble, the responses on collection, management,
and dissemination of GHG emissions data in Section V of this preamble,
and the responses on compliance and enforcement in Section VI of this
preamble.

While EPA is not formally delegating rule implementation and enforcement
to States, we are committed to working in partnership to address the
issues expressed in their comments on interaction between State and
Federal reporting programs.  Design and implementation of electronic
systems for data systems has been an area of particular focus in
determining how to ease reporting burdens and facilitate use of the many
different types of data collected by State and Federal reporting
programs by all levels of government.

EPA is committed to working with States to develop electronic reporting
tools that can both collect and share data in an efficient and timely
manner.  At this time, EPA is in the process of developing the reporting
format and tools and therefore has not specified the exact reporting
format, other than it will be electronic, in order to maintain
flexibility to modify the reporting format and tools in a timely manner.
 To the extent possible, EPA will work with existing reporting programs
and systems to develop a reporting scheme that minimizes the burden on
sources.

EPA recognizes the need to develop reporting tools that can support
reporting across programs that collect different types of data, and we
intend to coordinate with States and other organizations to explore
development of shared web-based tools that can simplify and expedite
reporting.  We recognize that State and Regionalregional programs may be
collecting additional GHG information beyond what is required in this
rule.  For example, many of these programs collect emissions data on
fleet vehicles, indirect emissions data for utility purchase, and other
data not required by the Federal rule.  Moreover, our rule requires
reporting of additional data necessary for emissions verification, which
is likely more expansive than what many existing State and regional
programs are collecting.  For example this rule requires reporting of
emissions at the process or unit level for many source categories,
rather than the company or facility level as allowed by various other
mandatory and voluntary reporting programs.  We will also collect
detailed monitoring data and activity data used to calculate emissions,
which will enable emissions verification.  We are interested in working
with others to determine the extent to which shared tools can be
designed to facilitate reporting across multiple programs, consistent
with obligations regarding CBI.

 EPA carefully reviewed Federal, State, and international voluntary and
mandatory programs during development of the reporting rule and
attempted to be consistent with the GHG protocols and requirements
within these rules, to the extent feasible given the differing scopes
and policy objectives.  (See Section II of the preamble for the proposed
rule (74 FR 16457, April 10, 2009), the Review of Existing Programs
memorandum (EPA-HQ-OAR-2008-0508-052), and the memorandum summarizing
State mandatory rules (EPA-HQ-OAR-2008-0508-056054).)  EPA has worked
with and will continue to coordinate closely with other Federal, State,
and regional programs to facilitate data exchange when designing the
data reporting systems that will be used for the rule and planning
implementation activities.  We will work with the States, TCR, and
others on data exchange standards to ease sharing of data between
systems, consistent with CBI obligations.  And finally, we see
substantial opportunities for EPA and States to cooperate on strategic
efforts to identify uses of the data collected under this rule and work
together on a broad array of climate change issues.

P.  Summary of Comments and Responses on Other General Rule Requirements

This section contains a brief summary of major comments and responses on
other general rule requirements.  A large number of other general
comments were received covering numerous topics.  Responses to
significant comments received can be found in the comment response
documents (EPA-HQ-OAR-2008-508-XXX)“Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public Comments” volumes on subpart A.

1.  Research and Development

Comment:  Commenters representing institutions and industries subject to
the reporting rule requested an exclusion for R&D activities.  They
noted that the aluminum production and glass production subparts of the
proposed rule excluded R&D process units, but requested that R&D be
excluded from the rule as a whole, not only from the two subparts.  Some
also commented that the exclusion should encompass R&D activities other
than R&D process units, including bench scale laboratory research and
pilot plants.  Commenters pointed out that many other EPA air rules
exclude R&D and they explained that R&D activities are small-scale,
emissions change frequently as the focus and scope of the R&D activity
changes, reliable information on CO2e emissions during any particular
phase of the research might not be available, and quantifying R&D
emissions would impose a high burden relative to the quantity of
emissions.

Response:  In response to these public comments, EPA has added an R&D
exclusion in 40 CFR 98.2(a)(5) stating that R&D activities are not
considered to be part of any source category defined in 40 CFR part 98.
Because R&D activities are not included in any source category, their
GHG emissions are not reported.  EPA agreed with the commenters that R&D
process units and laboratory R&D for new processes, technologies, or
products should be excluded.  It is not reasonable to calculate GHG
emissions from processes and activities that continually change as the
research focus changes and have highly variable inputs and operating
conditions due to their R&D nature.  Also, emissions from R&D are
expected to be small.  Therefore, the final rule defines R&D as
activities conducted in process units or at laboratory bench scale
settings whose purpose is to conduct R&D for new processes,
technologies, or products, and whose purpose is not for the manufacture
of products for commercial sale, except in a de minimis manner.

We point out that the exclusion applies to each individual R&D activity
that meets the R&D definition, not to an entire facility as a whole.
For example, a facility that has some commercial process units and some
R&D process units can exclude only the R&D process units.  A facility
that meets the applicability criteria in 40 CFR part 98, subpart A and
contains general stationary combustion sources must report emissions
from the combustion units, even if the steam, heat, or electricity
generated by a combustion unit is used in an R&D process unit.
Laboratory activities are excluded only if they are for R&D purposes.
Laboratory analyses activities conducted for commercial purposes,
process operating purposes, or to comply with a rule would not be
excluded.

We decided not to include pilot plants in the definition of R&D.  Pilot
plants that meet the rule applicability criteria must report their GHG
emissions.  Pilot plants tend to be relatively large in scale compared
to the excluded R&D activities.  Because pilot plants are designed to
prove the viability of a particular process or technology rather than to
research a wide range of processes and products, their operations and
emissions are more consistent than the excluded R&D activities.  Pilot
plants also tend to be operated for relatively long periods of time and
in some cases are converted to commercial facilities.  For these
reasons, EPA views the data as more useful and has not applied the R&D
exclusion to pilot plants.

2.  Determining Applicability

Comment:  Some commenters were concerned that the GHG reporting rule
will virtually require every commercial and industrial facility to
collect fuel usage data and perform relatively complex calculations, and
in some cases modeling, in strict accordance with the prescribed
monitoring methodologies and emissions calculation procedures, to
determine if they are subject to the rule.  The commenters added that
this will be burdensome, especially for small sources that will just be
documenting that the calculated GHG emissions from the facility are well
below the reporting threshold.  They also indicated that recordkeeping
would be needed to show that facilities are below the reporting
threshold, and anticipated that the rule will be nearly as burdensome on
facilities that do not have to report, as on those that must report.
Many of the commenters asked that EPA provide more simplesimplified
source category thresholds to determine applicability, like the 30
mmBtu/hr aggregate maximum rated heat input capacity for stationary fuel
combustion units, to reduce the burden on the majority of facilities
making applicability determinations.

Response:  We disagree that the initial applicability determination
process is burdensome.  While the rule requires reporters who are
subject to the rule to determine applicability using the calculation
procedures required in the rule, the rule does not contain any
requirements for facilities that are not subject to the rule.
Therefore, the rule does not necessarily require monitoring in 2010 to
determine applicability.  To determine applicability, anyone who
believes their facility might be subject to the rule could start by
calculating emissions using the relevant equations provided in each
applicable subpart along with the available data from company records
and the likely operating scenario for the reporting year that would lead
to worst case GHG emissions.  For example, for the input parameters
needed for the equations, use the 2010 production goals from the
company’s business plan, company records, process knowledge,
engineering judgment, and vendor data (e.g., vendor information could be
used to estimate the carbon content of feedstocks, using the highest
likely carbon content of those feedstocks.)  EPA expects that for most
facilities, emissions calculated in this manner are likely to be
significantly above or below the 25,000 metric ton CO2e per year
threshold, such that most potential reporters can determine their
applicability to the rule solely using the available data.

For those facilities with estimated emissions that are near the 25,000
tons/year threshold using available data, the company will have to make
the decision on whether to install monitoring equipment to calculate
emissions during the 2010 reporting year for purposes of determining
applicability and/or reporting emissions.  It is in a facility’s
interest to collect the GHG data required by the rule if they think they
will meet or exceed the applicability criteria in 40 CFR 98.2 by the end
of the year.  EPA anticipates that relatively few potential reporters
will face uncertainty in making this decision.

Given the large number of industrial and commercial facilities
potentially subject to the rule due to stationary fuel combustion
emissions, EPA has provided atin 40 CFR 98.2(b)(2) simplified procedures
for calculating emissions from fuel combustion.  These facilities may
first assess applicability based on the aggregate heat input capacity of
all their fuel combustion units.  Facilities Per 40 CFR 98.2(a)(3),
facilities with an aggregate maximum rated heat input capacity of less
than 30 mmBtu/hour are automatically not covered under the rule, because
emissions of CO2e will be less than 25,000 metric tons of CO2e per year
in all cases.  If a facility is not below the 30 mmBTU/hour cutoff, the
next logical step to determine applicability is to use any of the four
calculation methods provided in subpart C, as allowed by 40 CFR 98.2(b).
 The simplest of the four methods requires determination of only one
parameter – annual fuel use.  Most companies already record fuel use,
and can use this to calculate emissions and determine applicability.

To assist facilities in determining applicability, EPA plans to provide
implementation guidance with simplified means to determine
applicability.  For combustion sources, EPA plans to publish tables that
will specify by fuel type both an annual fuel assumptionconsumption
level and maximum heat input capacity that correlates with emissions of
25,000 metric tons per year of CO2e.  For non-combustion source
categories with a 25,000 metric ton CO2e threshold, EPA plans to publish
guidance, as feasible, on equipment capacities, production levels, or
other parameters that correlate with emissions of 25,000 metric tons per
year of CO2e.  The capacity and production levels provided in these
tables would be based on worst-case assumptions, but would allow
facilities to quickly and easily determine if they need to develop more
precise estimates or plan to implement monitoring in 2010.

Q.  Summary of Comments and Responses on Statutory Authority

This section contains a brief summary of some major comments and
responses.  A large number of comments on statutory authority were
received covering numerous topics.  This section will highlight only two
of the key categories of comments.  Additional discussion on these
comments and others can be found in the comment response documents.

Responses to significant comments received can be found in the comment
response documents (EPA-HQ-OAR-2008-508-XXX).“Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Legal Issues”.

Comment: EPA received numerous comments on whether the Clean Air ActCAA
or the FY 2008 Consolidated Appropriations Act authorized the rule.
Some commenters argued that EPA was required to issue the reporting rule
under the authority created by the Appropriations Act, not the CAA.
Others argued that the Appropriation Act could not create new authority,
and therefore either (1) EPA had to rely on the CAA, or (2) EPA was not
authorized to issue the rule at all.

Response:  As noted above, EPA is relying on the authority provided in
the CAA, not the Appropriations Act, for this final rule.  While the
Appropriations Act required that EPA spend a certain amount of money on
a rule requiring mandatory reporting of GHG emissions, the authority to
gather such information already existed in the CAA.  Indeed, EPA could
have promulgated this rule in the absence of the Appropriations Act.
Thus, the comments about the inability of an appropriations law to
create new legal authority are inapposite to this rulemaking.

Comment:  Commenters opined on whether the statute in question (either
the Appropriations Act or the CAA) contained sufficient authority for
various elements of the rule, ranging from broad issues like the scope
and duration of the rule as a whole, to more specific issues related to
particular source categories covered, and specific monitoring,
recordkeeping and reporting requirements.

Several commenters argued that the appropriations language contained
limitations on the scope of the rule EPA could promulgate, regardless of
the underlying authority for the rule.  For example, some commenters
contended that because the appropriations were for a single fiscal year,
EPA was authorized to promulgate only a one-time data collection.
Others argued that the Appropriations Act authorized the collection
solely of GHG emissions, and not any of the additional data elements
related to verification of emissions data.

As for the CAA, some commenters questioned whether section 114
authorized a broad reporting rule, as opposed to the targeted 114
information requests used by EPA in the past.  Many commenters
questioned whether EPA had adequately linked the requirements of the
reporting rule to particular provisions of the CAA that EPA was carrying
out.  Others questioned EPA’s general ability to gather information
about GHGs before it had made an endangerment finding and/or regulated
GHGs under the CAA.

Not all comments were negative.  Some commenters supported EPA’s
interpretation of the CAA, and agreed that it authorized the proposed
reporting rule.

Response:  We disagree that the language in the Appropriations Act
limited EPA’s authority for this rule.  First, the fact that
appropriations are for a single fiscal year does not mean that the
action taken pursuant to that appropriations cannot last longer than one
year.  First, the Environmental Programs and Management (EP&M) funds
Congress appropriated for the GHG reporting rule are available for two
fiscal years as are the funds EPA historically has used for most other
Agency rules. The fact that the appropriations EPA uses to develop rules
are available for specified fiscal years does not mean that the
effectiveness of the rules is limited by the same period of time that
the funds are available. Moreover, as noted above, EPA is issuing this
rule under the authority of the CAA, and indeed EPA could have issued
this rule absent the direct instruction from Congress to spend at least
a certain amount of money on a mandatory GHG reporting rule.  Thus, we
do not agree that the appropriations language limited EPA’s ability to
collect the information under this rule, either in duration or scope of
the information requested.

Regarding the scope of the rule, while it is true that EPA has used
section 114 in a more targeted fashion in the past, there is nothing in
the CAA that so limits our ability.  EPA is undertaking a comprehensive
evaluation of greenhouse gasesGHGs under the CAA and hence, is issuing a
comprehensive reporting rule.

Moreover, as noted above, CAA sections 114 and 208 of the CAA authorize
EPA to gather the information under this rule, which will prove useful
to EPA in carrying out numerous provisions of the CAA.  This final rule
imposes requirements on direct sources of GHG emissions.  These sources
are clearly persons from whom the Administrator may gather information
under CAA section 114, as long as that information is for purposes of
carrying out any provision of the CAA.  As discussed further in the
response“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
comments document,Public Comments, Selection of Source Categories to
Report and Level of Reporting” and “Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to Public Comments, Legal Issues,”
the information provided by direct emitters will prove invaluable to the
Agency in several areas, including the evaluation of the appropriate
action to take under section 111 regarding NSPS, and the investigation
into non-regulatory strategies to encourage pollution prevention
pursuant to section 103(g).  For example, the Agency currently has
pending before it a court remand, comments in an ongoing rulemaking, a
petition for reconsideration, notices of intent to sue and litigation
regarding EPA’s treatment of GHGs under section 111.

The requirements applicable to manufacturers of mobile sources are
authorized by section 208 because they will help inform various options
regarding the regulation of these sources under title II of the CAA.
The Agency currently has pending before it several petitions requesting
that the Agency regulate emissions from a variety of mobile sources,
including motor vehicles, aircraft, nonroad engines and marine engines.

Finally, the final rule also gathers information from upstream suppliers
of industrial GHGs and fossil fuels (except for suppliers of coal).  The
information gathered from suppliers of fossil fuels, in particular
petroleum products, is relevant to an evaluation of possible regulation
of fuels under title II of the CAA, as well as for potential efforts to
address GHG emissions at downstream sources.  Information from suppliers
of industrial greenhouse gasesGHGs is relevant to understanding the
quantities and types of gases being supplied to the economy, in
particular those that could be emitted downstream which will aid in
evaluating action under CAA section 111 as well as various sections of
title VI (e.g., 609 and 612) that address substitutes to ozone depleting
substances (ODS).  Additional discussion on this issue is available in
the response to comments document.“Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public Comments, Selection of Source
Categories to Report and Level of Reporting” and in “Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Legal Issues.”

Finally, we disagree with commenters who argue that we cannot use CAA
sections 114 of 208 of the CAA to gather information on a pollutant
until we have issued an endangerment finding for that pollutant, or
actually decided to regulate it under the CAA.  The statute is not so
inflexible.   For example, the information collected under sections 114
and 208 could inform the contribution element of endangerment
determinations (e.g., whether emissions from the relevant sector
contribute to air pollution which may reasonably be anticipated to
endanger public health or welfare).  Similarly, information gathered
under these sections could inform decisions on whether to regulate a
pollutant or source category.  Commenters’ interpretation would
prevent EPA from gathering information that could be critical to key
decisions until after those decisions are made.  EPA does not agree
with, and will not adopt, such an interpretation.

Thus, as discussed in more detail above and in the response to comments
document, the CAA provides“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Legal Issues,”  EPA has adequate
authority forto issue this final rule.

R.  Summary of Comments and Responses on CBI

This section contains a brief summary of major comments and responses on
CBI issues.  A large number of comments were received covering numerous
topics.  Responses to significant comments received can be found in the
comment response documents (EPA-HQ-OAR-2008-508-XXX).“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Legal Issues.”

Comment:  EPA received numerous comments addressing the issue of CBI.
Industry commenters generally expressed concern that much of the
information reported under this rule would be CBI (e.g., production and
process data).  Many commenters also presented arguments regarding why
certain information would not be “emissions data” under the CAA.
Among the various recommendations were that the final rule (i) not
require the reporting of such information at all, (ii) require only that
the source maintain such information on site, but not report it to EPA,
and/or (iii) clearly state that some classes of information are CBI.
Some commenters expressed concern about EPA’s ability to maintain the
confidentiality of CBI, and thus suggested that EPA should provide
further detail regarding how we will protect CBI from disclosure.  The
agricultural industry expressed particular concerns about making
information about the location of facilities public due to concerns
about biosecurity and other potential threats.  Other commenters favored
the wide dissemination of information, and argued that the information
gathered under this rule should be “emissions data” and hence not
protected as CBI.

Response:  As discussed in sectionSection II.N of this preamble, EPA is
finalizing its proposal that EPA verify the information collected by
this rule.  Data regarding inputs into emissions calculations and
monitoring are critical elements of that verification process.  Because
EPA will routinely need this data in order to verify the information
collected under this rule, we are not adopting the recommendation that
sources maintain such information on site and only provide it during an
inspection or when otherwise specifically requested.

EPA also recognizes the importance of this issue to both reporters and
the public.  EPA’s public information regulations contain a definition
of “emissions data” at 40 CFR 2.301, and EPA has discussed in an
earlier Federal Register notice what data elements constitute emissions
data that cannot be considered CBI withheld as CBI (56 FR 7042–7043,
February 21, 1991).  We further recognize that while determinations
about whether information claimed as CBI meets the definition of CBI, as
well as whether it meets the definition of emissions data, are usually
made on a case-by-case basis, such an approach would be cumbersome given
the scope of this rule and the potential inconsistencies across
reporters and source categories and the compelling need to make data
that are not CBI, or are emissions data, available to the public.  For
this reasons, EPA intends to undertake an effort similar to what was
done in 1991 for the data elements collected in this rule.  Through a
notice and comment process, we will establish those data elements that
are “emissions data” and therefore will not be afforded the
protections of CBI.  As part of that exercise, in response to requests
provided in comments, we may identify classes of information that are
not emissions data, and are CBI.  EPA plans to initiate this effort
later this year, or in early 2010.  We will consider the comments
received on this issue as part of that notice and comment process.

As stated in the proposed rule, EPA will protect any information claimed
as CBI in accordance with regulations in 40 CFR part 2, subpart B.  As
we noted previously however, in general the CAA prohibits the
treatementtreatment of emission data collected under CAA sections 114
and 208 as CBI.

S.  Summary of Comments and Responses on Other Legal Issues

This section contains a brief summary of major comments and responses on
other legal issues.  A large number of other legal issue comments were
received covering numerous topics.  Responses to significant comments
received can be found in the comment response document on legal issues
(EPA-HQ-OAR-2008-508-XXX).“Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Legal Issues.”

Comment:  We received numerous comments on EPA’s statements in the
proposed rule that a final rule requiring the monitoring and reporting
of GHG emissions would not render greenhouse gasesGHGs “regulated NSR
pollutants” for purposes ofunder the PSD program.CAA.  See ‘‘,
e.g., "EPA’s Interpretation of Regulations that Determine Pollutants
Covered By Federal Prevention of Significant Deterioration (PSD) Permit
Program’’" (Dec. 18, 2008).) (“PSD Interpretive Memo).  Some
agreed, while others took issue with the position in the December 2008
memorandum.

Response:  As we noted in the proposal, EPA is reconsidering the
December 2008 memorandumPSD Interpretive Memo and will be seeking public
comment on the issues raised in it. [UPDATE AS NEEDED]  That proceeding,
not this rulemaking, is the appropriate venue for submitting comments on
the substantive issue of whether monitoring regulations under the CAA
should trigger the PSD program.make GHGs subject to regulation.  At this
time however, the December 2008 memorandumPSD Interpretive Memo reflects
EPA’s current position, and hence, this final rule does not make GHGs
“regulated NSR pollutants” for the purposes of the PSD program.
subject to regulation under the CAA.

Comment:  EPA also received numerous comments about whether the
requirements imposed by this rule are “applicable requirements”
under the title V operating permit program.  The majority of the
comments took the position that the current definitions of “applicable
requirement” at 40 CFR 70.2 and 71.2 do not include a rule such as
this, promulgated under CAA section 114(a)(1) and 208 of the CAA.
Commenters requested that EPA confirm their interpretation of the
regulations.

Response:  As currently written, the definition of "applicable
requirement" in 40 CFR 70.2 and 71.2 does not include a monitoring rule
such as today'stoday’s action, which is promulgated under CAA sections
114(a)(1) and 208.

III. Reporting and Recordkeeping Requirements for Specific Source
Categories

A.  Overview

Once a reporter has determined that theirits facility or supply
operation meets any of the reporting rule applicability criteria in 40
CFR 98.2(a), theythe reporter must calculate and report GHG emissions or
alternate information as required (e.g., suppliers report quantities
supplied and the quantity of CO2e that could be emitted when the
products they supply are combusted or used).  The applicability
threshold determination is separately assessed for suppliers (fossil
fuel suppliers and industrial GHG suppliers) and downstream source
categories (facilities with direct GHG emissions).

The required GHG information must be reported for all source categories
at the facility for which there are measurement methods provided.  For
suppliers (facilities or corporations) that trigger only the
applicability criteria for upstream fossil fuel or industrial GHG supply
(40 CFR part 98, subparts KK through PP), reporters need only follow the
methods and report the information specified in those respective
subparts.  For downstream facilities that contain exclusively direct
emitting source categories covered in 40 CFR part 98, subparts C through
JJ, and are not suppliers, reporters must monitor and report GHG
emissions the methods presented in each applicable subpart.  Some
reporters will need to report under multiple subparts because multiple
source categories are collocated at their facility.  For example, a
facility with petrochemical production processes (described in
sectionSection III.X of the preamble), should also review
sectionsSections III.C (general stationary fuel combustion), III.G
(ammonia manufacturing) and III.Y (petroleum refineries) of this
preamble.  In some cases, such as petroleum refineries that supply
petroleum products and also meet applicability criteria for direct
emissions from the refinery, reporters will have to report on both
supply operations and direct facility emissions.

Table 2 of this preamble (in the “Supplementary Information” section
of this preamble) provides a cross walk to aid facilities and suppliers
in identifying potentially relevant source categories.  The cross-walk
table should only be seen as a guide as to the types of source
categories that may be present in any given facility and therefore the
methodological guidance in Section III of this preamble that should be
reviewed.  Additional source categories (beyond those listed in Table 2
of this preamble) may be relevant to a given reporter.  Similarly, not
all listed source categories will be relevant to all reporters.

Consistent with the requirements in the 40 CFR part 98, subpart A,
reporters must report GHG emissions from all source categories located
at their facility including stationary combustion 40 CFR part 98,
subpart C) and process emissions (e.g., from adipic acid production,
iron and steel production, and other source categories in 40 CFR
subparts C through JJ), as well as the required data for any supplier
source categories (KK through PP).  The methods presented typically
account for normal operating conditions, as well as startup, shutdown,
or malfunction (SSM), where significant (e.g., HCFC-22 production and
oil and gas systems).  Although SSM is not specifically addressed for
many source categories, emissions calculation methodologies relying on
CEMS or mass balance approaches would capture these different operating
conditions.

For many facilities, calculating facility-wide emissions will simply
involve adding GHG emissions from combustion sources calculated under
Section III.C of this preamble (General Stationary Fuel Combustion
Sources) and process GHG emissions calculated under the applicable the
source category subpart(s).  The rule also clarifies reporting for more
complex situations, such as where combustion and process emissions are
comingled.  See sectionSection II.L of this preamble for a response to
comments on the general monitoring and reporting approach for facilities
with both combustion and process emissions.  See sections III.C through
PP of this preamble for discussion of the specific monitoring and
reporting requirements for each source category.

B.  Electricity Purchases

1.  Summary of the Final Rule

The final rule does not require facilities to report their electricity
purchases or indirect emissions from electricity consumption.

2.  Summary of Major Changes Since Proposal

There have been no changes since proposal.  The proposed rule did not
require reporting of electricity purchases and neither does the final
rule.

3.  Summary of Comments and Responses

The proposal preamble (74 FR 16479, April 10, 2009) requested comments
on the value of collecting information on electricity purchases under
this rule.  It also outlined three options for reporting and requested
comments on these options:

Option 1: Do not require any reporting on electricity purchases or
associated indirect emissions from purchased electricity as part of this
rule.

Option 2: Require reporting of purchased electricity from all facilities
that are already required to report their GHG emissions under this rule.

Option 3: Require reporting of indirect emissions from purchased
electricity for facilities that exceed a prescribed total facility
emission threshold (including indirect emissions from the purchased
electricity).  Reporting under this option could be either in terms of
electricity purchases or calculated CO2e emission based on purchased
electricity.

This section containsWhile EPA is not including reporting requirements
for electricity purchases in the final rule at this time, below we have
provided a brief summary of major comments and our initial responses.  A
large number of comments on electricity purchases were received covering
two main topics: those in favor of collecting data on electricity
purchases and those against itAs EPA considers next steps, we will be
reviewing the public comments and other relevant information.

In Favor of Collecting Data on Electricity Purchases

Comment: Commenters in favor of collecting data on purchased electricity
stated that collection of this data, in conjunction with data on direct
emissions from facilities, will present a more comprehensive picture of
emissions nationwide.  They argued that collection of this data will
also serve to spur investment in energy efficiency and renewable energy
since companies will want to improve their emissions numbers once the
information is made public.  Several commenters noted that while this
reporting should occur, it should happen at the corporate level, rather
than at the facility level.  Others stated that the collection should
begin at a later time, perhaps in a second phase of this rule.

Response: While EPA is not collecting data on electricity purchases in
this rule, we understand that acquiring such data may be important in
the future.  Therefore, we are exploring options for possible future
data collection on electricity purchases and indirect emissions, and the
uses of such data.  Such a future data collection on indirect emissions
would complement EPA’s interest in spurring investment in energy
efficiency and renewable energy.  Energy efficiency is a low cost, vital
first step toward reducing greenhouse gasGHG emissions.  To this end,
EPA has in place several programs in which corporations and individual
facilities can participate to reduce their contribution to greenhouse
gasGHG emissions through increased energy efficiency of buildings and
industry.  These include EPA’s ENERGY STAR and Climate Leaders
programs.

EPA has been working for more than a decade through the ENERGY STAR
program to help companies reduce their energy use through cost-effective
energy efficiency investments and practices.  ENERGY STAR provides
nonresidential building owners and operators and energy intensive
industries with a wide variety of tools and resources to assist in their
efforts to reduce building energy use.  These include an online energy
benchmarking and tracking tool called Portfolio Manager, Guidelines for
Energy Management, technical resources to assist in assessing building
upgrades, and many others.

Through the Climate Leaders Program, EPA works corporate-wide with
companies to develop comprehensive climate change strategies.  Partner
companies commit to reducing their impact on the global environment by
completing a corporate-wide inventory of their greenhouse gasGHG
emissions based on a quality management system, setting aggressive
reduction goals to be achieved over 5 to 10 years, and annually
reporting their progress to EPA.  Through program participation,
companies create a credible record or audit of their accomplishments and
receive EPA recognition as corporate environmental leaders.

In addition to these programs that support greenhouse gasGHG emissions
reductions in both the private and public sectors, EPA’s Climate and
Energy State and Local Program assists governments in their clean energy
efforts by providing technical assistance, analytical tools, and
outreach support.  While EPA assists States in this way, we also have
much to learn from their efforts.  Throughout the country, States are
engaged in activities on energy efficiency, energy auditing, and some
collect data on electricity purchases for use in inventories and in
energy efficiency programming.

Since the goal of today’s rule is to collect data on emissions from
downstream direct emitters and upstream production, the collection of
indirect emissions will not be included at this time.  In exploring the
possibility of collecting data on electricity purchases nationwide, EPA
will be looking to the States as examples.  While facility level
collection is a possibility, collection from other sources, such as load
serving entities will also be explored.  Moreover, the collection of
indirect emissions data from the types of facilities covered by this
rule (e.g., facilities and suppliers with emissions over 25,000 metric
tons of CO2e) would not provide the complete picture or focus on the
types of facilities that likely have large indirect emissions.  Reports
from additional facilities could be required in any future data
collection.

Against Collecting Data on Electricity Purchases

Comment:  Many commenters were against the collection of data on
purchased electricity for several reasons.  Primarily they felt it would
constitute double counting if electricity data is are collected from
electric utilities and EPA also collects the same data from facilities
and adds it together.  Others stated that collecting information on
electricity purchases was outside the scope of the rule, that it is not
useful information in attempting to quantify emissions, that it would be
burdensome for facilities, and that it is CBI that companies are not
able to share with EPA.  Those commenters suggested instead the data
should come from utilities, as EPA proposed.

Response:  The final rule does not require facilities to report their
electricity purchases or indirect emissions from electricity
consumption.  While EPA is not collecting data on electricity purchases
in this rule, we understand that acquiring such data may be important in
the future.  Therefore, we are exploring options for possible future
data collection on electricity purchases and indirect emissions, and the
uses of such data.  In the event that a future data collection effort is
pursued, EPA will consider the issues raised by these commenters with
regard to the most effective source for this data, and methods to reduce
burden on reporting entities.

With regard to, double reporting and/or double counting of the same
data, the data collected under this rule is consistent with the
appropriations language, and provides valuable information to EPA and
stakeholders in the development of climate change policy and programs.
Policies such as low carbon fuel standards can only be applied upstream,
whereas end use emission standards can only be applied downstream.  Data
from upstream and downstream sources would be necessary to formulate and
assess the impacts of such potential policies.  Eliminating reporting by
either upstream or downstream sources would not satisfy EPA’s data
needs and policy objectives of this rule.  Any future rule makings to
collect data on electricity purchases and indirect emissions will follow
a similar approach in order to inform policy decisions.

With regard to CBI, as stated in the proposed rule, and will be stated
in any subsequent rule making process, EPA will protect any information
claimed as CBI in accordance with regulations in 40 CFR part 2, subpart
B.  As we noted previously, however, in general emissions data collected
under CAA sections 114 and 208 cannot be considered CBI.

EPAWith regard to CBI, EPA recognizes the importance of this issue to
both reporters and the public.  EPA’s public information regulations
contain a definition of “emissions data” at 40 CFR 2.301.  Although
determinations about whether information claimed as CBI meets the
definition of CBI, as well as whether it meets the definition of
emissions data, are usually made on a case-by-case basis,, and EPA has
issued guidancediscussed in an earlier Federal Register notice on what
data elements constitute emissions data that cannot be considered CBI
(956 FR 7042-7043, February 21, 1991).

  As explained in Section II.R. of this preamble, EPA intends to
undertake a similar effort regarding the data elements collected in this
rule, and any subsequent rules.  Through a notice and comment process,
we will establish those data elements that are “emissions data” and
therefore will not be afforded the protections of CBI.

C.  General Stationary Fuel Combustion Sources

1.  Summary of the Final Rule

Source Category Definition.  Stationary fuel combustion sources are
devices that combust any solid, liquid, or gaseous fuel to:

Produce electricity, steam, useful heat, or energy for industrial,
commercial, or institutional use; or

Reduce the volume of waste by removing combustible matter.

These devices include, but are not limited to, boilers, combustion
turbines, engines, incinerators, and process heaters.

Portable equipment, emergency generators, and emergency equipment are
excluded from this source category.  Stationary combustion devices that
combust hazardous waste must report emissions only from the co-firing of
any fuels that are covered by 40 CFR part 98, subpart C.  Flares are
also excluded from subpart 40 CFR part 98, subpart C.  Flare emissions
must be reported only if required by the provisions of another subpart
of part 98.

Reporters must submit annual GHG reports for stationary fuels combustion
units if the facility meets the applicability criteria in the General
Provisions (40 CFR 98.2) as summarized in Section II.A of this preamble.

EGUs that are subject to the ARP and other EGUs that are required to
monitor and report to EPA CO2 mass emissions year-round according to 40
CFR part 75, are covered under 40 CFR part 98, subpart D (Electricity
Generation).

GHGs to Report.  For stationary fuel combustion, report:

CO2, CH4, and N2O emissions from each stationary fuel combustion unit.
For each unit, CO2, CH4, and N2O emissions must be reported for each
fuel combusted (including biomass).  Reporters can aggregate emissions
from multiple units in certain cases.

Facility-level CO2 emissions from combustion of biomass (in addition to
unit-level reporting).

GHG Emissions Calculation and Monitoring.  Reporters must use the
following methodologies to calculate emissions:

Calculating CO2 Emissions from Combustion:  Calculate CO2 emissions
using one of four methodological tiers, subject to certain restrictions
based on unit size, type of fuel burned, and other factors.  For each
Tier, CO2  mass emissions are determined as follows:

Tier 1: Use annual fuel consumption (from company records) together with
fuel-specific default high heat values and default CO2 emission factors.

Tier 2: Use annual fuel consumption (from company records) together with
measured fuel-specific high heat values and default CO2 emission
factors.

Tier 3: Use annual fuel consumption, either from company records (for
solid fuels) or directly measured with fuel flow meters (for liquid and
gaseous fuels) together with periodic measurements of fuel carbon
content.

Tier 4: Use CEMS.  Use Tier 4 only for combustion units that have
certain types of existing CEMS in place and that meet several other
specific criteria, such as fuel type and hours of operation.  Sources
that have all of the necessary CEMS installed and certified by January
1, 2010 are required to use Tier 4 in 2010.  However, for sources that
need additional time to upgrade their CEMS, the use of CEMS can begin on
January 1, 2011; and a lower tier calculation methodology may be used in
2010.

As an alternative to any of the four tier methods, the rule provides
that units that report to EPA year-round heat input data under 40 CRF
part 75 can calculate CO2 mass emissions using part 75 calculation
methods.

Calculating CO2 Emissions From Sorbent Use.  For fluidized bed boilers
that use sorbent injection and units equipped with wet flue gas
desulfurization systems, calculate CO2 emissions from sorbent use using
methods provided in the rule, except when CO2 emissions are measured
with CEMS.

Calculating CO2 Emissions From Biomass Fuel Combustion.  Calculate CO2
emissions from biomass combustion for only the specific types of biomass
that are listed in the rule.  UseThe approach used for most units is to
use a default high heat value and default CO2 emission factor to
estimate emissions.  Use methods provided in the rule for For
determining the biomass fraction of CO2 emissions from units that burn
municipal solid wasteMSW or mixed fuels, and from units that co-fire
biomass with fossil fuels and measure CO2 emissions using CEMS, use the
specific methods provided in the rule.

Calculating N2O and CH4 Emissions From Combustion.  Calculate N2O and
CH4 emissions only for units that are required to report CO2 emissions
under this subpart and only for fuels for which default emission factors
are provided in 40 CFR part 98, subpart C.

Fuel Sampling and Analysis.  The Tier 2 and Tier 3 calculation
methodologies require periodic measurements of fuel heating value and
carbon content.  The minimum required frequency of these measurements is
daily, weekly, monthly, quarterly, or semiannually, depending on the
type of fuel combusted and other factors.

Data Reporting.  In addition to the information required to be reported
by the General Provisions (40 CFR 98.3(c)) and summarized in Section
II.A of this preamble, reporters must submit additional data that is are
needed for EPA verification of the reported GHG emissions from
stationary combustion.  The specific data to be reported are found in 40
CFR part 98, subpart C.

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.  These records are described in 40 CFR part 98,
subpart C.

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 C: General
Stationary Fuel Combustion. Sources.”

A number of exemptionsExemptions to GHG emissions reporting have been
added for certain unconventional types of fuel.  For units using Tiers 1
or 2, youReporters are not required to calculate GHG emissions if EPA
has not provided default values.  For units using Tier 3, youonly for
fuels that are listed in Table C-1 of subpart C, except that units
larger than 250 mmBtu/hr, also must calculate GHG emissions only for
theany other fuels that provide, on average, at least 10% percent of the
annual heat input to the unit.

The use of the Tier 2 calculation method for CO2 emissions has been
expanded to include units greater than 250 mmBtu/hr that combust only
pipeline natural gas and/or distillate oil.

Two new alternative methods have been added, allowing sources that
monitor and report heat input according to 40 CFR part 75, but are not
required to report CO2 mass emissions, to use established Part 75 CO2
emissions calculation methods to meet the 40 CFR part 98 reporting
requirements.

A definition of “company records”, as it pertains to quantifying
fuel consumption in Tiers 1, 2, and 3, has been added to 40 CFR 98.6.

The required fuel sampling frequency in Tiers 2 and 3 has been reduced
for many fuels, particularly those that are homogeneous or that are
delivered in shipments or lots.

Averaging of fuel sampling results is allowed for many fuels when the
frequency of sampling and analysis is less than the minimum monthly
frequency.

The rule has been clarified to affirm that the use of fuel sampling
results provided by the fuel supplier is permissible, and that the use
of fuel billing records to quantify fuel consumption is also allowed.

Additional deadline extensions for calibrating the fuel flow meters are
provided in certain situations.

The use of Tier 4 has been clarified; i.e., all of the conditions listed
in 40 CFR 98.33(b)(54)(ii) and all of the conditions listed in 40 CFR
98.33(b)(54)(iii) must be met before Tier 4 is required.

Units that must upgrade their existing CEMS to meet Tier 4 requirements
may use either Tier 2 or Tier 3 in 2010.

The methods for calculating CH4 and N2O emissions have been clarified.

An expanded list of default emission factors are provided for certain
solid, gaseous, and liquid biomass fuels.

The use of steam production and combustion unit efficiency to calculate
CO2 emissions is extended to other solid fuels in addition to municipal
solid waste (MSW).  These parameters may also be used to quantify the
amount of biomass combusted in a unit.

The use of American Society for Testing and Materials (ASTM) Methods
D7459-08 and D6866-06a to determine CO2 emissions from combustion of
mixed biomass fuels has been expanded to include the combustion of other
biomass fuels besides municipal solid wastein addition to those mixed
with  MSW.

The missing data provisions have been made more flexible.

The limit of 250 mmBtu/hr total heat input for aggregating units into
groups for reporting purposes has been lifted.

The reporting of combined units served by a common supply line, or
common pipe configuration, has been clarified.

The amount of required unit-level data and emissions verification
information has been reduced for some of the measurement Tiers.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
Many comments on general stationary fuel combustion were received
covering numerous topics.  Responses to significant comments received
can be found in the comment response document for general stationary
fuel combustion 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 C:
General Stationary Fuel Combustion Sources.”

Definition of Source Category

Comment:  Several commenters asked EPA to clarify whether sources such
as flares, hazardous waste incinerators, thermal oxidizers, pollution
control devices, fume incinerators, burnout furnaces, and small
equipment such as stoves and space heaters are included in the
stationary combustion source category.  Others suggested that EPA should
consider requiring that only the GHG emissions from combustion of
traditional fossil fuels (if any) in these types of sources be reported.

Comments were also received on the proposed language for excluding
emergency generators and the associated definitions.

Response:  The final rule retains the broad definition of a stationary
fuel combustion source, which is any device that combusts fuel.  Fuel is
defined very broadly to mean any combustible material.  However, in
evaluating public comments, we agree that in some cases the reporting of
GHG emissions is unreasonable given the cost of monitoring and the
relative level of GHG emissions.  Monitoring can be particularly
burdensome for vents with highly variable gas characteristics (e.g.,
carbon content and heat value).  Accordingly, the final rule expands the
list of combustion sources and fuels that are exempted from GHG
emissions reporting under 40 CFR part 98, subpart C, as summarized
below:

Flares are exempted from 40 CFR part 98, subpart C.  However, flares at
some facilities might be covered by other subparts of the rule.

Stationary combustion units that combust hazardous waste, as defined in
40 CFR 261.3, are also exempted.  These units would report only the
emissions from combustion of any fuels covered by subpart C that are
co-fired with hazardous wastes.

UnitsFor calculations at the unit level, units less than 250 mmBtu/hour
heat input are required to report GHG emissions only for fuels for which
EPA has provided default emission factors in the rule.

Units larger than 250 mmBtu/hour heat input GHG that combust
miscellaneous, non-traditional fuels such as refinery gas, process gas,
vent gases, waste liquids, and others must report only if CEMS are used
or if these fuels contribute 10 percent or more of the annual unit heat
input to the unit.  With this exclusion, we have concluded that devices
such as thermal oxidizers, pollution control devices, fume incinerators,
burnout furnaces, and other such equipment would report only GHG
emissions from the firing of supplemental fossil fuels.

In response to comments on the exclusion of emergency generators, EPA
removed proposed language that would have required emergency generators
to be identified as such in the facility’s State or local air permit
in order to qualify for an exemption.  We also added language to exclude
other emergency equipment.  See Section III.D of this preamble for the
response to the comments on exclusion of emergency generators from 40
CFR part 98, subparts C and D.  See the comment response document for
subpart“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart A: Definitions, Incorporation by Reference, and
Other Subpart A Comments” for responses to comments on definitions,
including changes to the emergency generator definition and the addition
of a definition for emergency equipment.

Comment:  Multiple commenters asked EPA to institute a “de minimis”
provision in the rule to exclude stationary combustion sources other
than the largest units at a facility.

Response:  The final rule contains no de minimis exclusions.  However,
to simplify reporting, the rule allows small units to be aggregated and
reported as a single emissions value, if certain conditions apply.  The
final rule has expanded the availability of this provision.  The
proposed rule limited the aggregation of any one group to a combined
maximum capacity of 250 mmBtu/hour heat input.  The final rule removes
this limit and allows grouping of any units that individually are less
than 250 mmBtu/hour heat input.  EPA has also clarified the use of the
common pipe metering option, so that all stationary combustion units at
a facility using the same fuel that is metered through a common supply
line may report a single emissions value under this rule.  In addition,
the changes listed above in Section III.C.2 of this preamble will
simplify emissions calculations for many combustion units.

Method for Calculating GHG Emissions

Comment:  EPA received numerous comments on the proposed GHG calculation
methods for stationary combustion sources.  Most of the comments
centered on the use of the four-tiered approach for calculating CO2
emissions.  Several commenters requested that EPA remove the 250
mmBtu/hr unit size restriction on the use of Tier 1 and 2 calculation
methods, especially for the combustion of relatively homogeneous fuels
such as natural gas and fuel oil.  Objections were raised to the
specified frequency of fuel sampling under Tiers 2 and 3, as being
excessive and unnecessary.  Two commenters recommended that annual
sampling be allowed for natural gas and fuel oil.  A number of
commenters asked the Agency to allow averaging of fuel sampling results
(to simplify the CO2 emissions calculations) and to affirm that the use
of fuel sampling results provided by the fuel supplier is permissible.
Others sought confirmation that fuel billing meters could be used to
quantify fuel usage.  Multiple commenters asked EPA to clarify who must
use the Tier 4 calculation method, which requires the use of continuous
emission monitoring systems (CEMS) to measure stack gas flow rate and
CO2 concentration.  A number of comments were received requesting that
sources currently monitoring and reporting heat input data under 40 CFR
Part 75, but not reporting CO2 mass emissions, be allowed to implement
established Part 75 CO2 emissions calculation methods in lieu of using
Tiers 1 through 4.  Finally, EPA received diverse comments on the
proposed calculation method for CH4 and N2O emissions.  Several
commenters recommended that these emissions either not be reported at
all, or that emissions reporting should be excluded for certain fuel
types.  Others asked for flexibility in determining the appropriate
emission factors for CH4 and N2O.  Some suggested that the use of
operator-defined emission factors or factors from other GHG registries
should be allowed.

Response:  The final rule significantly expands the use of Tier 1 and
Tier 2 calculation methodologies.  All units rated at 250 mmBtu/hr or
less are allowed to use the Tier 1 or Tier 2 calculation methodologies,
depending on fuel sampling provisions at either the facility or by the
supplier of the fuel.  In addition, units rated at over 250 mmBtu/hr
that combust pipeline quality natural gas and distillate oil are allowed
to use the Tier 2 calculation methodology, because of the homogeneous
nature and low variability in the characteristics of these fuels.
However, the 250 mmBtu/hr unit size cutoff remains for units that
combust residual oil, other gaseous fuels, and solid fossil fuel.

The mandatory monthly fuel sampling and analysis requirements for
traditional fossil fuels have been dropped from Tiers 2 and 3.  EPA
agrees with the commenters that for a homogeneous fuel such as pipeline
natural gas, monthly sampling is not necessary.  Therefore, 40 CFR 98.34
has been revised to require that natural gas be sampled semiannually.
For other fuels such as oil and coal, which are delivered in shipments
or lots, requiring monthly sampling may be impractical, because new fuel
lots or deliveries may not be received on a monthly basis.  For fuel oil
and coal, a representative sample is required for each fuel lot, i.e.,
for each shipment or delivery.  For other liquid fuels and biogas,
quarterly sampling is required.  For solid fuels other than coal,
excluding municipal solid wasteMSW, weekly composite sampling with
monthly analysis is required.  For gaseous fuels other than natural gas
and biogas, the daily sampling requirement has been retained, but only
for facilities with existing equipment in place that is capable of
providing the data.  Otherwise, weekly sampling is required if such
equipment for daily sampling is not installed.

The final rule clarifies that fuel sampling and analysis data provided
by the supplier may be used in the emission calculations, and that fuel
billing meters may be used to quantify fuel consumption.  To simplify
the emission calculations in Tiers 2 and 3, arithmetic averaging of
HHVhigher heating value  and carbon content data over the reporting year
is permitted if these data are collected less frequently than monthly
(see Equation C-2b in 40 CFR 98.33).  However, regardless of the
sampling frequency required by the rule, reporters must use the results
of all available valid fuel analyses in the emissions calculations.

Today’s rule clarifies the applicability of the Tier 4 methodology.
Many commenters were unsure whether only one or all six of the
conditions listed in proposed 40 CFR 98.33(b)(4)(ii) and all three of
the conditions listed in proposed 40 CFR 98.33(b)(4)(iii) must be met to
trigger the requirement to use CEMS.  EPA’s intent has always been
that a source must meet all conditions listed in those sections to
require the use of Tier 4.  This has been made clear in the final rule
text.

The final rule adds two alternative methods that can be used as an
alternativealternatives to any of the four tier calculation methods.
These alternative methods apply to sources that are currently required
to monitor and report heat input data according to 40 CFR part 75, but
are not required to report CO2 mass emissions.  Many units subject to
the Clean Air Interstate Regulation (CAIR) are in this category.  These
alternative methods allow these sources to use their 40 CFR part 75 heat
input data together with one of the CO2 emissions calculation
methodologies in part 75 to meet 40 CFR part 98 CO2 emissions reporting
requirements.  For instance, sources monitoring hourly heat input
according to Appendix D of 40 CFR part 75 may use Equation G-4 in
Appendix G of 40 CFR part 75 to calculate CO2 emissions.  Similarly, low
mass emitting sources monitoring heat input under 40 CFR 75.19 may use
Equation LM-11 in 40 CFR 75.19 to calculate CO2 emissions.  Sources
using 40 CFR part 75 flow rate and CO2 CEMS to continuously monitor heat
input may use the CEMS measurements together with an appropriate
equation from Appendix F of 40 CFR part 75 to determine CO2 mass
emissions.

The methodology for calculating CH4 and N2O emissions has been clarified
in the final rule.  Reporting of these emissions is required only for
the fuels listed in Table C-2 of 40 CFR part 98, subpart C.  Further,
reporting of CH4 and N2O emissions is required only for units that are
required to report CO2 emissions under 40 CFR part 98, subpart C and
only for fuels for which default emission factors are provided in
subpart C.  The emission factors in Table C-2 of 40 CFR part 98, subpart
C are both fuel-specific and heat input-based.  Therefore, when more
than one type of fuel is combusted in a unit, direct measurements or
engineering estimates of the annual heat input from each fuel are needed
to calculate the CH4 and N2O emissions.  Consequently, when CEMS (which
are not fuel-specific) are used to monitor the CO2 emissions and heat
input for a multi-fuel unit, the total heat input measured by the CEMS
must be apportioned to each fuel type.  The owner or operator should use
the best available information (e.g., fuel feed rates, high heat values)
to do the necessary heat input apportionment.  To provide greater
consistency in reporting, EPA has chosen to retain the requirements for
using the default factors in Table C-2 of 40 CFR part 98, subpart C,
rather than allow reporters to select their own emission factors.

Procedures for Estimating Missing Data

Comment:  EPA received several requests to modify the proposed missing
data substitution procedures in 40 CFR part 98, subpart C.  One
commenter recommended that a minimum data capture requirement should be
specified rather than requiring the use of substitute data to fill in
missing data gaps.  Another commenter suggested that only the
“before” value be used for data substitution, rather than the
average of the quality-assured values before and after the missing data
period.  Others favored using emission factors or the “best available
estimates” for all parameters, rather than following a prescriptive
missing data algorithm.  Finally, several commenters asserted that 40
CFO part 75 missing data procedures for CO2 are too conservative (i.e.,
may overestimate emissions significantly) and seem to be contrary to the
objectives of 40 CFR part 98.

Response:  The final rule provides additional flexibility to the missing
data provisions of 40 CFR part 98, subpart C.  The rule requires the use
of “before and after” average values for only three parameters (fuel
HHV, carbon content, and molecular weight).  If the “after” value is
not yet available when the GHG emissions report is due, the “before”
value may be used for missing data substitution.  For all other
parameters, the reporter can substitute data values that are based on
the best available estimates, based on all available process
information.

EPA does not agree with the commenters who believe that the 40 CFR part
75 CO2 missing data procedures are too conservative and contrary to 40
CFR part 98 program objectives.  Nearly all 40 CFR part 75 sources
maintain very high monitor data availability (95% percent or better) and
use very little substitute data.  Only when the data availability drops
below 80% percent (which very seldom occurs) are the substitute data
values significantly higher than the true CO2 concentrations.
Therefore, sources that monitor CO2 emissions according to 40 CFR part
75 should continue to use the standard part 75 missing data provisions,
and no adjustments to those substitute data values are deemed necessary
for 40 CFR part 98 reporting purposes.

Data Reporting Requirements

Comment:  A number of commenters objected to the amount of unit-level
data and emissions verification information that is required to be
reported electronically under 40 CFR 98.36 as “burdensome”,
“unnecessary,” and “excessive”..”  The commenters recommended
that the auxiliary information should instead be kept on file and made
available to EPA upon request.  Several commenters recommended that EPA
remove the 250 mmBtu/hr limit on the cumulative heat input capacity of
units that can be aggregated into groups for reporting purposes.  Other
commenters asserted that EPA should consider the 40 CFR part 75
emissions data submitted under the Acid Rain ProgramARP to be sufficient
to satisfy 40 CFR part 98 requirements, and that there is no need to
submit the same data twice.

Response:  EPA does not agree with the assertion that the amount of
unit-level data to be reported is excessive, burdensome, or unnecessary.
 For this mandatory GHG emissions reporting rule, two approaches to
emissions data verification were considered, EPA verification and
third-party verification.  The Agency decided on EPA emissions
verification.  To verify GHG emissions estimates, EPA needs supporting
data that are reported at the same level as the emissions are
calculated.  Because the rule requires that emissions be calculated at
the unit level, it is imperative for EPA to obtain unit level
verification data, particularly given the variety of requirements for
estimating fuel combustion emissions under 40 CFR part 98, subpart C.
Subpart C provides four different methods of estimating CO2 emissions.
The four methods require measurement of different parameters to estimate
emissions, and the use of the methods is conditioned on a variety of
operating factors.  In addition, facilities use fuel combustion units of
a variety of different sizes, types, and fuel firing scenarios.  Under
these circumstances, EPA could not verify that the correct methods were
selected or applied correctly without unit-level data.  If unit-level
data were not submitted or were aggregated at a gross level, EPA could
not reasonably verify the accuracy of reported facility-wide GHG
emissions data, because EPA could not evaluate the relationship between
unit capacity, fuel characteristics, fuel consumption, and emissions.
However, as explained below, in the final rule EPA has made a number of
significant adjustments to the data reporting requirements to clarify
requirements and to reduce the reporting burden.

First, for units that use Tiers 1, 2 and 3 to calculate CO2 mass
emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the
aggregation of units into groups has been dropped.  Rather, the 250
mmBtu/hr restriction applies only to the individual units in a group.
Therefore, for reporting purposes, individual units with maximum rated
heat input capacities of 250 mmBtu/hr or less may be aggregated without
limit into a single group, provided that the Tier 4 methodology is not
required for any of the units, and all units in the group use the same
calculation methodology for any common fuels that they combust.  Units
with maximum rated heat inputs greater than 250 mmBtu/hr using Tiers 1,
2, and 3 must report as individual units, unless they burn the same type
of fuel and the fuel is provided by a common pipe or supply line.  In
that case, the owner or operator may opt to aggregate emission for all
units fed by the common fuel line.  Units using Tier 4 must report as
individual units unless they share a monitored common stack.

Second, the rule requires minimal data to be reported for units that
monitor and report emissions and heat input data according to 40 CFR
part 75.  This includes Units that meet these criteria include units
that are subject to the ARP, and potentially units that are subject to
CAIR, and other programs.  The final rule clarifies that 40 CFR part 75
sources must report 40 CFR part 98 GHG emissions data under the exact
same unit, stack, or pipe ID numbers that are used for electronic
reporting in the part 75 programs (e.g., 1, 2, CT5, CS001, MS1A, CP001,
etc.).  Even though most 40 CFR part 75 sources report CO2 mass
emissions data to EPA year-round, these data alone are not sufficient to
satisfy the Part 98 reporting requirements for the following reasons.
The emissions reports required under 40 CFR part 98 are facility-wide
reports that require GHG emissions from all stationary combustion units
at the facility, whether or not the units are subject to a 40 CFR part
75 program.  Many electricity generating facilities have both ARP units
and non-ARP units on site.  Further, the CO2 emissions data reported
under 40 CFR part 75 are in units of short tons; Part 98 requires
reporting in metric tons.  Finally, 40 CFR part 98 also requires CH4 and
N2O emissions to be reported, neither of which are reported under any 40
CFR part 75 program.

Third, the required verification data have been clarified and, in some
cases, differ substantively from the proposed rule.  No additional
verification information is required for sources that monitor and report
emissions and heat input data using 40 CFR part 75.  This includes
sources that elect to use the new alternative calculation methodologies
for units monitoring heat input year round according to 40 CFR part 75
programs.  For sources using Tiers 1, 2, 3, and 4, the final rule
streamlines some of the reporting.  Sources using Tier 3 are required to
report only monthly averages of fuel carbon content and molecular weight
rather than the proposed requirement to submit the results of each
individual determination.  Sources that use Tier 4 are required to
report quarterly cumulative CO2 mass emissions, rather than daily CO2
emissions, as proposed.  Also, to address concerns raised by some of the
commenters, certain data elements need only be retained on file and
provided to EPA upon request.  These data elements include the methods
used for fuel sampling and analysis, the methods used to calibrate fuel
flow meters, the dates and results of fuel flow meter calibrations, and
the dates and results of CEMS certification tests and on-going quality
assuranceQA tests of the CEMS.

D.  Electricity Generation

1.  Summary of the Final Rule

Source Category Definition.  This source category consists of EGUs that
are subject to the ARP and any other EGUs that are required to monitor
and report to EPA CO2 mass emissions year-round according to 40 CFR part
75.  All other EGUs are part of the general stationary fuel combustion
source category and report under 40 CFR part 98 subpart C, if the
facility meets the reporting rule applicability criteria.  This source
category excludes portable equipment, emergency generators, and
emergency equipment.

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 annual CO2, N2O, and CH4 mass emissions from
each EGU.

GHG Emissions Calculation and Monitoring.  For EGUs subject to the ARP
and other EGUs that are required to montitor monitor and report to EPA
CO2 mass emissions year-round according to 40 CFR part 75, the reporter
must continue to monitor CO2 emissions according to 40 CFR part 75.  The
cumulative CO2 mass emissions reported in the fourth quarter electronic
data reports must be converted from short tons to metric tons, for 40
CFR part 98 reporting purposes.  The N2O and CH4 emissions must be
calculated using fuel-specific default emission factors and heat input
measurements in accordance with 40 CFR 98.33(c) in 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 unit-level data and other
information that are used to verify the reported GHG emissions.  The
additional data and information to be reported for this source category
are specified in 40 CFR 98.46.

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.  The specific records that must be retained for
this source category are identified in 40 CFR 98.47.

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 D:
Electricity Generation.”

The source category has been more precisely defined and includes only
EGUs subject to the ARP and any other EGUs that are required to monitor
and report to EPA CO2 mass emissions year-round according to 40 CFR part
75.

The proposed emergency generator exclusion language no longer requires
that emergency generators be identified as such in State or local air
permits.

A CO2 calculation methology was provided for units that are not in the
ARP, but report CO2 mass emissions year-round using 40 CFR part 75
methodologies.

3.  Summary of Comments and Responses

Definition of Source Category

Comment:  Several commenters were concerned that covering non-ARP EGUs
in both subparts C and D of proposed 40 CFR part 98 was confusing and
repetitive.  Several commenters stated that the definition of an EGU is
too inclusive and recommended that EPA revise it.  The commenters were
concerned that any unit, regardless of electrical output, could be
identified as an EGU and place a facility in the electricity generation
source category.  One commenter suggested that a 25 megawatts (MW)
threshold should be added to the EGU definition in 40 CFR 98.6 and to 40
CFR part 98, subpart D.  A multitude of commenters objected to the
language in proposed 40 CFR 98.40 requiring emergency generators to be
designated as such in a State or local air permit, in order for the
generators to be exempted from GHG emissions reporting.  Many of these
same commenters recommended changes to the definition of “emergency
generator” in 40 CFR 98.6, suggesting that the term “generator”
should be replaced with the term “reciprocating internal combustion
engine (RICE)”, to be consistent with 40 CFR 63.6675, subpart ZZZZ.
Others recommended that EPA should also exempt emergency equipment such
as fire pumps, fans, etc. from GHG emissions reporting.

Response: The electricity generation source category definition in
subpart D (40 CFR 98.40) has been modified based on the comments
received.  The final rule limits the source category to EGUs that are
subject to ARP and to other EGUs that monitor and report to EPA CO2 mass
emissions year-round according to 40 CFR part 75.  The final subpart D
does not cover any other EGUs.  The GHG emissions from other EGUs are
covered under subpart C (General Stationary Fuel Combustion).

The definition of an “emergency generator” in 40 CFR 98.6, the final
rule has been changed to clarify that it includes both reciprocating
internal combustion enginesRICE and turbines.  EPA has also added a
definition of “emergency equipment” to 40 CFR 98.6, and exempts such
equipment from GHG emissions reporting under both 40 CFR part 98,
subparts C and D.

The proposed requirements in 40 CFR part 98, subparts C and D for
emergency generators to be identified as such in State and local air
permits in order to be exempt from GHG emissions reporting has been
revised.  There is considerable variation from State to State regarding
the regulation of emergency generators, including whether or not permits
are required.  Some States specifically exempt emergency generators from
permitting requirements.  Other statesStates use a permit by rule
approach for emergency units.  In view of this, the Agency has revised
the wording of the exclusion for emergency generators to allow for
situations where they are not specifically identified in a facility’s
permit.

Method for Calculating GHG Emissions

Comment: Several commenters suggested that for units that are not in the
Acid Rain ProgramARP but are required by other regulatory programs to
report Partpart 75 emissions and heat input data, EPA should expand the
four-tiered calculation method for CO2 mass emissions in §40 CFR
98.33(a) to allow the use of CO2 emissions calculation methods based on
Appendices D and G of Partpart 75.

Response: The electricity generation source category definition has been
narrowed to only include EGUs that are subject to ARP and to other EGUs
that monitor and report to EPA CO2 mass emissions year-round according
to 40 CFR part 75 (e.g., RGGI units).  The final subpart D provides a
CO2 calculation methodology for such EGUs that are not in the ARP, but
report to EPA CO2 mass emissions year-round using part 75 methodologies.
 For the purposes of part 98, the CO2 emissions from these units are
calculated and reported using the same methods as part 75.

Other units that are not in the ARP but report data under part 75,
subpart C are now covered by 40 CFR part 98, subpart C instead of
subpart D, and subpart C has been revised to allow the use of part 75
calculation methodologies.  The response to the comment on these units
is contained in Section III.C of this preamble (General Stationary Fuel
Combustion Sources).

E.  Adipic Acid Production

1.  Summary of the Final Rule

Source Category Definition.  The adipic acid production source category
consists of all processes that use oxidation to produce adipic acid.

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 N2O process emissions from adipic acid
production.

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.  CalculateUnless an
alternative method of determining N2O emissions is requested, calculate
N2O process emissions from adipic acid production by multiplying a
facility-specific emission factor by the annual adipic acid production
level.  Determine the facility-specific emission factor by an annual
performance test to measure N2O emissions from the waste gas stream of
each oxidation process and the production rate recorded during the test.

When N2O abatement devices (such as nonselective catalytic reduction)
are used, adjust the N2O process emissions for the amount of N2O removed
using athe destruction factor efficiency for the control device and the
fraction of annual production for which the control device is operating.
 The destruction factor is the destruction efficiency can be specified
by the abatement device manufacturer.  This fact or can also 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 E.

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
E.

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
belowin this section or in the comment response document for“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart E: Adipic Acid Production.”

The re-testing trigger was eliminated.changed.  Performance testing is
only required annually to determine the N2O emissions factor is required
annually, whenever the ratio of cyclohexanone to cyclohexanol is
changed, and when new abatement equipment is installed.

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

40 CFR 98.56 was reorganized and updated to improve the data reporting
requirements as needed for the emissions verification process.  Some
data elements were moved from section40 CFR 98.57 to section40 CFR
98.56, and some data elements that a reporter must already use to