calculate GHGs as specified in section40 CFR 98.53 were added to
section40 CFR 98.56 for clarity.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
Several comments on adipic acid production were received covering
numerous topics.  Responses to significant comments received can be
found in the comment response document for adipic acid production in the
docket (EPA-HQ-OAR-2008-508-XXX).Responses to significant comments
received can be found in “Mandatory Greenhouse Gas Reporting Rule:
EPA’s Response to Public Comments, Subpart E: Adipic Acid
Production.”

GHGs to report

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

Response:  We reviewed this issue but decided not to make any changes to
40 CFR part 98, subpart E.  We do not foresee a potential for double
counting of combustion emissions at the facility because all combustion
unit emissions at adipic acid facilities are to be reported under 40 CFR
part 98, subpart C.  Subpart40 CFR part 98, subpart E provides methods
for reporting only the process N2O emissions.  Also see Section III.C of
this preamble for responses to comments related to Subpart40 CFR part
98, subpart C (General Stationary Combustion).

Selection of Proposed GHG Emissions Calculations and Monitoring Methods

Comment:  One commenter stated that emissions of N2O do not correlate
with the production of adipic acid at their facility.  A portion of the
process off gas, which contains N2O, is sold to an offsite facility via
dedicated piping.  The amount sold depends on customer needs and the
amount is metered.  The commenter asked that the language in the final
rule address this issue.

Response:  We agree that any N2O emitted from the production of adipic
acid that is sold or transferred offsite shouldis not covered in the
proposed rule.  The final rule has been changed to require this amount
of N2O to be reported.  Allowing for this additional reporting
requirement ensures that the reported N2O emissions attributed to the
adipic acid facility are accurate.  Reporting of the N2O sold or
transferred offsite will help EPA improve methodologies for reporting of
GHG emissions.

Method for Calculating GHG Emissions

Comment:  Multiple commenters asked that the requirement to repeat the
annual performance test be removed.  In the proposal, re-testing was
triggered whenever the adipic acid production rate changed by more than
10 percent.  Commenters asserted that production depends on demand for
adipic acid and often varies by 15 percent.

Response:  Upon review, we decided to eliminate re-testing.  We believe
that annual determination of the N2O emissions factor is sufficient to
accurately calculate N2O emissions as long as the production equipment
remains consistent over the year-long period (i.e. no new abatement
technology).

Comment:  Multiple commenters asked that alternative methods be allowed
for calculating N2O emissions from adipic acid production.  Specifically
the commenters asked that EPA allow the use of N2O and flow CEMS to
directly measure N2O emissions and use the performance test to evaluate
the CEMS accuracy.  The commenters also asked that EPA allow the use of
existing process flow meters and process N2O analyzers to determine the
amount of N2O sent to control devices and use the performance test to
measure control device destruction efficiency.

Response:  We agree that there are other means of determining
site-specific N2O emissions.  The final rule has been changed to allow
alternative test methods.  Any alternative must be approved by the
Administrator before being used to comply with this rule.  An
implementation plan that details how the alternative method will be
implemented must be included in the request for the alternative method.
Until the method is approved facilities must use the alternatives
proposed in the rule for a performance test.  As one commenter noted, at
minimum the performance test will help to QA/QC alternative methods
currently used to monitor N2O emissions (such as N2O CEMS).

EPA understands the need to further evaluate and establish alternative
comparable methods for sources to use in accurately calculating N2O
emissions from adipic production and will address in future rulemakings
or amendments to rulemaking.

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

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

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

F.  Aluminum Production

1.  Summary of the Final Rule

Source Category Definition.  The aluminum production source category
consists of facilities that manufacture primary aluminum using the
Hall-Héroult manufacturing process.  The primary aluminum manufacturing
process consists of the following operations:

Electrolysis in prebake and Søderberg cells.

Anode baking for prebake cells.

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

GHGs to Report.  For aluminum production, report:

Perfluoromethane (CF4) emissions and perfluoroethane (C2F6) emissions
from anode effects in all prebake and Søderberg electrolysis cells
combined.

CO2 emissions from anode consumption during electrolysis in all prebake
and Søderberg cells.

All CO2 emissions from anode baking.

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

GHG Emissions Calculation and Monitoring.  Reporters  must calculate
process emissions using the following methods:

CF4 from anode effects:  Calculate annual CF4 emissions based on the
frequency and duration of anode effects in the aluminum electrolytic
reduction process for each prebake and Søderberg electrolysis cell
using the following parameters:

Anode effect minutes (AEM) per cell-day calculated monthly.

Aluminum metal production calculated monthly.

A slope coefficient relating CF4 emissions to anode effect minutes per
cell-day and aluminum production.  The slope coefficient is specific to
each smelter and must be measured in accordance with the protocol
specified in the rule at least once every 10 years.

Facilities are allowed to use historic smelter-specific slope
coefficients for the first three years of reporting under the rule.
Historic measurements include all those made under the EPAEPA’s
Voluntary Aluminum Industry Partnership or at facilities owned or
operated by companies participating in the Voluntary Aluminum Industry
Partnership.  Facilities without historic measurements are required to
complete measurements by the end of first year of reporting.

Facilities which operate at less than 0.2 anode effect minutes per cell
day or, when overvoltage is recorded, operate with less than 1.4mV
overvoltage, can use either smelter-specific measured slope coefficients
or the technology-specific (Tier 2)default coefficients from Volume III,
Chapter 4, Section 4.4 Metal Industry Emissions of the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories as specified in the
rule.

C2F6 from anode effects: Calculate annual C2F6 emissions from anode
effects from each prebake and Søderberg electrolysis cell using the
calculated CF4 emissions and the mass ratio of C2F6 to CF4 emissions, as
determined during the same test during which the slope coefficient is
determined.

Process CO2 emissions – general approaches.  Most reporters can elect
to calculate and report process CO2 emissions from anode consumption
during electrolysis and from anode baking by either (1) installing and
operating CEMS and following the Tier 4 methodology (in 40 CFR part 98,
subpart C) or (2) using the calculation procedures specified below.

However, if process CO2 emissions from anode consumption during
electrolysis or anode baking are emitted through the same stack as a
combustion unit or process equipment that uses a CEMS and follows Tier 4
methodology to report CO2 emissions, then the CEMS must be used to
measure and report combined CO2 emissions from that stack, instead of
using the calculation procedures specified below.

CO2 emissions from anode consumption in prebake cells: Calculate annual
CO2 emissions at the facility level using a mass balance equation based
on measurements of the following parameters:

Net prebaked anode consumption rate per metric ton of aluminum metal
produced.

Ash and sulfur contents of the anodes.

Total mass of aluminum metal produced per year for all prebake cells.

CO2 emissions from Søderberg cells: Calculate CO2 emissions from paste
consumption in Søderberg cells using a mass balance equation at the
facility level based on the following parameters:

Paste consumption rate per metric ton of aluminum metal produced and the
total mass of aluminum metal produced per year for all Søderberg cells.

Emissions of cyclohexane-soluble matter per metric ton of aluminum
produced.

Binder content of the anode paste.

Sulfur, ash, and hydrogen contents of the coal tar pitch used as the
binder in the anode paste.

Sulfur and ash contents of the calcined coke used in the anode paste.

Carbon in the skimmed dust from the cell, per metric ton of aluminum
produced.

CO2 emissions from anode baking of prebake cells: Calculate CO2
emissions at the facility level separately for pitch volatiles
combustion and for bake furnace packing material.

To calculate CO2 emissions from the pitch volatiles, use a mass balance
equation based on the following parameters:

Initial weight of the green anodes.

Mass of hydrogen in the green anodes.

Mass of the baked anodes.

Mass of waste tar collected.

To calculate CO2 emissions from bake furnace packing material, use a
mass balance equation based on the following parameters:

Packing coke consumption rate per metric ton of baked anode production.

Sulfur and ash contents of the packing coke.

The variables used to calculate CO2 emissions from anode and paste
consumption (e.g., sulfur, ash, and hydrogen contents) can be determined
for each facility, or the source can use default values from the 2006
IPCC Guidelines for National Greenhouse Gas Inventories as specified in
40 CFR 98.64.

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 F.

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
F.

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 F: Aluminum
Production.”

A new subsection was added in 40 CFR 98.63 providing a new equation (Eq.
F-1) to sum monthly PFC emission values into annual PFC emission value.

The equation for CO2 emissions from Søderberg cells (paste consumption)
was corrected.

Language was updated to request reporting of all CO2 emissions from
on-site anode baking.

Language was updated to request reporting of smelter-specific slope
coefficients (plural).

A new equation was added in §40 CFR 98.63 (Eq. F-3) to calculate CF4
emissions from overvoltage; and updated language in subsequent sections
to accommodate the overvoltage method.

Language was added to permit facilities that operate with low anode
effect minutes or low overvoltages to use IPCC Tier 2 default slope
factors.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
Three comments on aluminum production were received covering numerous
topics.  Responses to significant comments received can be found in the
comment response document for aluminum production in the docket
(EPA-HQ-OAR-2008-0508-0005).Responses to significant comments received
can be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart F: Aluminum Production.”

Comment:  Several commenters suggested that smelters should be permitted
to use International AluminiumAluminum Institute default slope
coefficients which are based on global technology-specific averages to
calculate PFC emissions, especially at high performance facilities.

Response:  The use of smelter-specific slope coefficients as required in
the rule leads to significantly more precise PFC emission calculations
than the use of default slope coefficients (95% percent confidence
interval of ±15 compared to ±50 percent).  For a typical U.S. smelter
emitting 175,000 metric tons of CO2-eq in PFCs, these errors result in
absolute uncertainties of ±88,000 MTCO2e and ±26,000 MTCO2e,
respectively.  The reduction in uncertainty associated with moving from
default to smelter-specific slope coefficients, 62,000 MTCO2e, is as
large as the emissions from many of the sources that would be subject to
the rule.  However, for “high performance” facilities, which are
defined by the 2006 IPCC Guidelines as those at or below 0.2 anode
effect minutes per cell day or less than 1.4 mV overvoltage, the IPCC
analysis indicates that impact of moving from a Tier 2 to a Tier 3 slope
coefficient would not result in a significant improvement in PFC
emissions.  Therefore, EPA agrees that high performance facilities
should be allowed to use technology specific (Tier 2) default values
from Volume III, Chapter 4, Section 4.4 Metal Industry Emissions of the
2006 IPCC Guidelines for National GrenhouseGreenhouse Gas Inventories.
These values are identical to the Aluminium“Aluminum Sector Greenhouse
Gas Protocol (Addendum to the WRI/WBCSD Greenhouse Gas Protocol)),”
October, 2006 default coefficients.

Comment:  Several commenters argued the requirement to re-measure
smelter-specific slope coefficients every 3three years is expensive and
unnecessary.

Response:  While the cost to require smelter-specific slope coefficients
is significantly greater than the cost to use default slope
coefficients, the benefit of reduced uncertainty is considerable, as
noted above.  The costs that would be incurred by smelters measuring
slope factors are discussed in the Regulatory Impact Analysis (RIA) for
thisthe proposed rulemaking (EPA-HQ-OAR-2008-0508-002).

Of the currently operating U.S. smelters, all but one has measured a
smelter specific coefficient at least once; and at least three used the
2003 EPA/IAI protocol for measuring smelter-specific slope coefficients.

The USEPA/IAI Protocol for Measurement of Tetrafluoromethane and
Hexafluoroethane from Primary Aluminum Production establishes guidelines
to ensure that measurements of smelter-specific slope-coefficients are
consistent and accurate (e.g., representative of typical smelter
operating conditions and emission rates). The Protocol currently
recommends that smelter operators re-measure their slope coefficients at
least every three years, and more frequently if they adopt changes to
process control algorithms or observe changes to typical anode effect
duration.  Specifically, the Protocol recommends that operators repeat
measurements of slope coefficients for CF4 and C2F6 if one or more of
the following apply: (1) thirty-six months have passed since the last
measurements (i.e. triennial measurements are recommended); (2) a change
occurs in the control algorithm that affects the mix of types of anode
effects or the nature of the anode effect termination routine; and, (3)
changes occur in the distribution of duration of anode effects (e.g.
when the percentage of manual kills changes or if, over time, the number
of anode effects decreases and results in a fewer number of longer anode
effects).

Changes to process control algorithms or to the typical duration of
anode effects can change the relationship between anode effect minutes,
production, and emissions, that is, they can change slope coefficients.
In addition, more subtle changes can also change slope coefficients over
time.  According to industry experts, the rate of these more subtle
changes has not been sufficiently studied to specify a frequency for
re-measurement nor have there been a sufficient number of facilities
that have been measured repeatedly to document the benefit of the
additional incremental cost of measurement once every three years.

During the past few years, multiple U.S. smelters have adopted changes
to their production process which are likely to have changed their slope
coefficients. These include the adoption of slotted anodes and
improvements to process control algorithms.  Although some U.S. smelters
have recently updated their measurements of smelter-specific
coefficients, others may not have.

In view of these recent process changes, EPA is requiring smelters that
have not already measured their slope factors under the “2008
USEPA/IAI Protocol for Measurement of Tetrafluoromethane and
Hexafluoroethane from Primary Aluminum Production,” to do so in time
for the 2013 reporting year.  EPA believes that this will ensure that
slope factors are appropriately updated while providing sufficient
lead-time for smelters to perform the measurements without encountering
excessive costs or logistical barriers.  However, after this initial
update, EPA agrees that every three years is burdensome, therefore,
further updates are required only every ten years unless there are major
technological or process changes at a facility such as changes to the
control algorithm that affect the mix of types of anode effects or the
nature of the anode effect termination routine; or changes occur in the
distribution of duration of anode effects (e.g. when the percentage of
manual kills changes or if, over time, the number of anode effects
decreases and results in a fewer number of longer anode effects).

Comment:  Several commenters suggested that the rule should include the
overvoltage measurement method, which is specific to use with Pechiney
technology, in case one or more U.S. smelters decide to adopt this
technology in the future.

Response:  The Overvoltage Method relates PFC emissions to an
overvoltage coefficient, anode effect overvoltage, current efficiency,
and aluminum production. The overvoltage method was developed for
smelters using the Pechiney technology.  While it is EPA’s
understanding that no U.S. smelters have used the Pechiney technology
for at least a decade, if one or more U.S. smelters decide to adopt this
internationally accepted technology in the future they would be expected
to use the overvoltage method which follow the established guidelines in
the “USEPA/IAI Protocol for Measurement of Tetrafluoromethane and
Hexafluoroethane from Primary Aluminum Production.”

G.  Ammonia Manufacturing

1.  Summary of the Final Rule

Source Category Definition.  The ammonia manufacturing source category
consists of process units in which ammonia is manufactured from a
fossil-based feedstock via steam reforming of the hydrocarbon.  It also
includes ammonia manufacturing processes in which ammonia is
manufactured through the gasification of solid and liquid raw material.

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

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

CO2 process emissions from steam reforming of a hydrocarbon or the
gasification of solid and liquid raw material, reported for each ammonia
manufacturing process unit following the requirements of this part.

CO2, CH4, and N2O emissions from each stationary combustion unit.
Report these emissions under 40 CFR 98, subpart C (General Stationary
Fuel Combustion Sources) by following the requirements of 40 CFR part
98, subpart C.

For CO2 collected and transferred off site, report these emissions under
40 CFR part 98, subpart PP (Suppliers of CO2) following the requirements
of 40 CFR part 98, subpart PP.

In addition, report GHG emissions for any other source categories at the
facility for which calculation methods are provided in other subparts of
the rule, as applicable.

GHG Emissions Calculation and Monitoring.  FacilitiesReporters must use
one of two methods to calculate CO2 process emissions, as appropriate:

Most reporters can elect to calculate and report process CO2 emissions
from each ammonia manufacturing process unit by either (1) installing
and operating CEMS and following the Tier 4 methodology (in 40 CFR part
98, subpart C) or (2) using the calculation procedures contained in the
rule and summarized below.

However, if process CO2 emissions from an ammonia manufacturing process
unit are emitted through the same stack as CO2 emissions from a
combustion unit or process equipment that uses a CEMS and follows Tier 4
methodology to report CO2 emissions, then the CEMS must be used to
measure and report combined emissions from that stack, instead of using
the calculation procedures described below.

To calculate process CO2 emissions, use the equations provided in 40 CFR
part 98, subpart G for solid, liquid, and gaseous feedstock and the
following measurements:

Continuous measurement of gaseous or liquid feedstock consumed using a
flowmeter, or monthly aggregate of solid feedstock consumed.

Carbon content of the feedstock (required to be measured monthly using
supplier data or analysis using the appropriate test methods).  If
supplier data isare used, facilities must QA/QC the supplier analysis on
an annual basis using the appropriate test methods.

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

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
G.

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 Ammonia“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart G: Amonia Manufacturing.”

Monitoring and QA/QC requirements were revised to allow for obtaining
carbon content of feedstock used in ammonia manufacturing from the
feedstock supplier.  Facilities that obtain monthly carbon content
information from their supplier are required to QA/QC supplier
information through annual sampling and analysis of the feedstock.

Missing data procedures were added under section 40 CFR 98.75 for
parameters that facilities must measure such as feedstock consumption,
the quantity of the waste recycle stream, and the monthly carbon content
of both the feedstock consumption and waste recycle stream quantity.

Reporting requirements were added for the quantity of urea produced and
the emissions associated with waste recycle streams commonly found at
ammonia manufacturing facilities.

40 CFR 98.76 was reorganized and updated to improve the emissions data
verification process.  Some data elements were moved from section40 CFR
98.77 to section40 CFR 98.76, and some data elements that a reporter
must already use to calculate GHGs as specified in section40 CFR 98.73
were added to section40 CFR 98.76 for clarity.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
Several comments on ammonia manufacturing were received covering
numerous topics. Several of these comments were directed at the
requirements for 40 CFR part 98, subpart C (General Stationary Fuel
Combustion Sources in subpart C), and responses to those comments are
provided in theSection III.C of this preamble section III.C.  Responses
to significant comments received can be found in the comment response
document for ammonia manufacturing in the docket
(EPA-HQ-OAR-2008-508-XXX)..  Responses to significant comments received
can be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart G: Ammonia Manufacturing.”

Method for Calculating GHG Emissions

Comment:  Several commenters asked EPA to clarify that ammonia
production units must use Tier 4 calculation only if all of the
conditions under proposed 40 CFR section 98.33(b)(5)(ii)(A) through (F)
apply to the unit and only where the ammonia manufacturing unit already
has installed a stack gas volumetric flow rate monitor and a CO2
concentration monitor.

Response:  We agree with the comment and have modified the text under 40
CFR 98.73(a) and (b) to state that if a facility operates and maintains
CEMS that meet the requirements of §40 CFR 98.33(b)(54)(ii) or (iii),
then process or combined process and combustion CO2 emissions shall be
calculated and reported under this subpart by following the Tier 4
Calculation Methodology specified in §40 CFR 98.33(a)(4) and all
associated requirements for Tier 4 in 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).   If CEMS are not used to determine
CO2 emissions from ammonia processing units, then facilities must
calculate and report process CO2 emissions under this subpart by using
equations provided in section40 CFR 98.73(b)(1) through (b)(4).  CO2
combustion emissions from ammonia processing units must be reported
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).  For additional clarification on the requirements on use of
CEMS see 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources in subpart C), and Section III.C of this preamble.

Comment:  One commenter noted that most ammonia facilities utilize
natural gas combustion combined with approximately 5five percent recycle
flow of gas containing methane from the process.  The carbon content of
the recycle stream is already accounted for when measuring the feedstock
flow rate and carbon content to the process.  EPA should allow ammonia
manufacturers to exclude this recycle stream in calculating combustion
emissions, as the carbon in the recycle stream would be double counted.

Response:  We agreed with commenters that it is important to account for
use of the waste process stream in the case that it is recycled since
carbon in the recycle stream isn'tis not actually emitted.  In response
to this comment we have added reporting requirements for quantifying
emissions associated with the recycle stream.  This will help EPA
improve methodologies for calculating emissions from ammonia
manufacturing in the future.

Monitoring and QA/QC Requirements

Comment:  Several commenters stated that monthly carbon content sampling
and analysis requirement is overly burdensome.  Some commenters asked
that EPA allow the use of a default value for carbon content while one
commenter suggested use of carbon content data generated by the
feedstock supplier.

Response:  We agreed with commenters that flexibility should be added to
the rule to allow for use of supplier data. This information is readily
available from the feedstock supplier in most cases.  The most common
feedstock for ammonia production is pipeline quality natural gas.
Supplier data on carbon contents of feedstock will have sufficient or
comparable accuracy for the purposes of calculating CO2 emissions.  We
modified the monitoring and QA/QC procedures in the rule to allow use of
carbon content data obtained from the feedstock supplier(s).  Facilities
that obtain monthly carbon content information from their supplier are
required to QA/QC supplier information through annual sampling and
analysis of the feedstocks consumed.

Procedures for Missing Data

Comment:  Two commenters suggested that the proposed procedures for
calculating emissions in the event of missing feedstock data would yield
significant overstatements of GHG emissions.  As proposed, if feedstock
supply rate data isare missing for a specific day or days (e.g., if a
meter malfunctions during unit operation), the reporting entity must use
the lesser of the maximum supply rate that the production unit is
capable of processing or the maximum supply rate that the meter can
measure. If this substitution is applied to the feedstock for reformers
used in ammonia production, either of these proposed approaches would
likely result in significant over reporting of carbon emissions.  The
commenter proposed two alternatives that a reporting facility could use:
either (1) substitute an estimated value for feedstock supply rate,
based on the arithmetic average of the previous thirty days of available
feedstock supply rate data; or (2) utilize missing data estimating
procedures similar to the procedure proposed under §40 CFR 98.35(b)(2),
based upon all available process data.  These approaches would result in
much more accurate estimates of emissions derived from the true
historical operation of a specific ammonia manufacturing source.

Response:  We agreed with commenters that the proposed missing data
procedures would overestimate emissions when applied.  While some of
feedstock should be readily available and collected as a part of normal
business practices, circumstances could arise where data could be
missing.  We added procedures consistent with the commenter’s second
recommendation, referencing the proposed missing data procedures in
98.35(b)(2).  Ammonia facilities with missing data on feedstock supply
rate must provide the best available estimate from all available process
data.  Facilities must document and keep records of missing data
procedures applied.  We find that these revised procedures will provide
accurate information for the purposes of this rulemaking.

Data to be Reported

Comment:  One commenter noted that the CO2 produced through ammonia
manufacturing can be utilized and that much of it is in the manufacture
of urea.  The commenter stated that EPA makes unsubstantiated
assumptions that all CO2 in urea will be released into the atmosphere.
The commenter asked EPA not to tie emissions from applied urea, or
emissions that result from urea once the product has been sold, to the
producing industry.

Response:  We added reporting requirements for annual urea production
under 40 CFR 98.76.  Information on urea production will help us improve
our understanding of the quantity of CO2 consumed from ammonia
production that is used in the manufacture of urea.  We know from the US
GHG inventory and subsequent conversations with ammonia producers that
on average it takes 0.733 tons of CO2 to produce one ton of urea.  We
have also requested that producers report, if known, the uses of the
urea sold.  Collecting information on urea production and its uses will
help EPA to improve methodologies for calculating emissions from ammonia
manufacturersmanufacturing, urea production, and urea consumption in the
future.

H.  Cement Production

1.  Summary of the Final Rule

Source Category Definition.  The cement production source category
consists of each kiln and each inline kiln/raw mill at any Portland
cement manufacturing facility, including alkali bypasses and kilns and
inline kilns/raw mills that burn hazardous waste.

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

GHGs to Report.  For cement production, report the following emissions:

CO2 process emissions from calcination, reported for each kiln.

CO2 combustion emissions from each kiln.

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

CO2, N2O, and CH4 emissions from each stationary combustion unit other
than kilns under 40 CFR part 98, subpart C (General Stationary Fuel
Combustion Sources).

In addition, report GHG emissions for any other source categories for
which calculation methods are provided in other subparts of the rule, as
applicable.

GHG Emissions Calculation and Monitoring.  For CO2 emissions from kilns,
reporters must select one of two methods, as appropriate:

For kilns with certain types of CEMS in place, reporters must use the
CEMS and follow the Tier 4 methodology (in 40 CFR part 98, subpart C) to
measure and report under the Cement Production subpart (40 CFR part 98,
subpart H) combined calcination and fuel combustion CO2 emissions.

For other kilns, the reporter can elect to either (1) install or operate
a CEMS and follow the Tier 4 methodology to measure and report combined
calcination and fuel combustion CO2 emissions or (2) calculate process
CO2 emissions as the sum of clinker emissions and emissions from raw
materials.  If using approach (2):

Calculate clinker emissions monthly from each kiln using monthly clinker
production (required to be measured); a kiln-specific, monthly clinker
emission factor calculated from the monthly CaO and MgO content of the
clinker (required to be measured); quarterly cement kiln dust not
recycled to the kiln (required to be measured); and a quarterly
kiln-specific fractionfactor of calcined material in the cement kiln
dust not recycled to the kiln (measured or default values can be used).

Calculate raw material emissions annually from the annual consumption of
raw materials and the organic carbon content in the raw material
(measured annually for each type of raw material, or a default value of
0.2 percent may be used).

Report process CO2 emissions from each kiln under 40 CFR part 98,
subpart H (Cement Production), and report combustion CO2 emissions from
each kiln under 40 CFR part 98, subpart C (General Stationary Fuel
Combustion Sources).

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

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
H (Cement Production).

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 H: Cement
Production.”

The CO2CO2 calculation equations in §40 CFR 98.83 were revised to
account for non-carbonate sources of calcium and magnesium in the kiln
feed and uncalcined carbonates in the product.

Methods for monitoring CaO and MgO in clinker and CKD were changed from
XRF to ASTM c114-07, Standard Test Methods for Chemical Analysis of
Hydraulic Cement.

40 CFR 98.84 was revised to clarify required monitoring frequency and to
allow for alternative monitoring methods for raw materials and CKD.

Missing data procedures were added to 40 CFR 98.85 for parameters
reporters must measure, clinker, CKD not recycled to the kiln, raw
material consumption, carbonate contents of clinker and CKD, and
non-calcined content of clinker and CKD, and organic carbon content of
raw materials.

Requirements in sections 40 CFR 98.81 through 40 CFR 98.87 were revised
to clarify which requirements apply to reporters who elect to report CO2
emissions using CEMS.

40 CFR 98.86 was reorganized and updated to improve the emissions
verification process.  Some data elements were moved from 40 CFR 98.87
to 40 CFR 98.86, and some data elements that a reporter must already use
to calculate GHGs as specified in 40 CFR 98.83 were added to 40 CFR
98.86 for clarity.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
We received several comments on cement production covering a number of
topics.  Many of these comments were directed at the requirements for 40
CFR part 98, subpart C (General Stationary Fuel Combustion Sources in
subpart C), and responses to those comments are provided in Section
III.C of this preamble dealing with that source category.  Also see
Section II.N of this preamble for the response to comments on the
emissions verification approach.

Responses to significant comments received related to process emissions
from cement production can be found in the comment response document for
cement production in the docket (EPA-HQ-OAR-2008-508-XXX).“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart H: Cement Production.”

Selection of Threshold

Comment:  One commenter suggested that EPA could reduce the burden
presented by the Proposed Rule by reducing the number of facilities
required to report (i.e., raise the reporting thresholds).  The
commenter further noted that by requiring GHG reporting for all cement
plants, regardless of the magnitude of the plant’s emissions, EPA
removes an incentive for those plants to reduce GHG emissions to get
below a threshold in order to avoid the burden of monitoring and
reporting.

Response:  In considering the comment, we acknowledge the potential
benefit of a reporting threshold providing cement plants with incentive
to reduce their GHG emissions. The “once in, always in” provision
has been removed.  The final rule now contains a provisionprovisions to
cease reporting if annual reports demonstrate emissions less than 25,000
metric tons CO2e per yearspecified levels for 5 consecutivemultiple
years.  This provision appliesThese provisions apply to all reporting
facilities.  See Section II.H of this preamble for the response on
provisions to cease reporting.  See Section II.D of this preamble for
the response on selection of source categories to report.

In developing the Proposed Rule, we considered emission-based thresholds
of 1,000 metric tons CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e, and 100,000 metric tons CO2e.  All of these emission thresholds
covered more than 99.9 percent of CO2e emissions from cement facilities.
 Only one plant out of 107 in the dataset would be excluded by the
highest considered thresholds of 100,000 metric tons CO2e.  Therefore,
we determined that it was appropriate to include all cement production
facilities in the reporting requirements.

Method for Calculating GHG Emissions

Comment:  Two commenters stated that the cement industry already has an
established, proven protocol for calculating and reporting GHG
emissions, and requested that EPA use the existing cementCement CO2
protocolProtocol as the basis for the Proposed Rule.  Commenters further
stated that the cementCement CO2 protocolProtocol already provides many
of the benefits that EPA ascribes to the Proposed Rule, including
uniformity of reported data from one facility to another; availability
of verifiable data to provide to the public, investors, and others; and
other suggested benefits.

Both commenters stated that EPA needs to revise its clinker-based
calculation to account for any non-carbonated CaO or MgO in the raw
materials.

Response:  In developing the proposed Rule, we considered many domestic
and international GHG monitoring guidelines and protocols, including the
Cement Sustainability Initiative Protocol referenced in the cement
industry’s comments.  We combined elements of the cementCement CO2
protocolProtocol with elements of other protocols including the 2006
IPCC Guidelines, U.S. Inventory, DOE 1605(b), CARB mandatory GHG
emissions reporting program, EPA’s Climate Leaders program, and the EU
Emissions Trading System to develop two proposed methods for quantifying
GHG emissions from cement manufacturing.  These proposed methods include
the use of CEMS to directly measure emissions and the use of calculation
methods to determine emissions.

While finalizing today’s rule, we revisited the cementCement CO2
protocolProtocol and compared its requirements to our requirements.  We
feel that the rule closely mirrors the GHG calculation methods and
requirements of the Cement CO2 Protocol with some minor differences.
For example, our rule requires cement plants to use plant-specific
emission factors to calculate CO2 emissions and does not allow the use
of default emission factors.  As stated in the proposal, we have
determined that applying default emission factors to clinker production
is more appropriate for national-level emissions estimates than
facility-specific estimates, where data are readily available to develop
site-specific emission factors.  Default approaches would not provide
site-specific calculation of emissions that reflect differences in
inputs, operating conditions, fuel combustion efficiency, variability in
fuels, and other differences among facilities.  Further, it is our
understanding that facilities analyze data relevant for site-specific
determinations such as the carbonate contents of their raw materials to
the kiln and products on a frequent basis, either on a daily basis or
every time there is a change in the raw material mix.  Using data from
direct measurements will provide a more accurate representation of site
specific emissions rates.

We also note that the Cement CO2 Protocol does not specify measurement
methods.  Our rule specifies methods for measuring CaO, MgO, and clinker
weight.  We selected these methods to be consistent with measurement
techniques that are common within the cement industry.  Prescribing
standardized measurement procedures ensures the uniformity and
consistency in the results and quality of data reported that the
commenters agree is important for comparability of emissions.

We also used the Cement CO2 Protocol as a model for revising our
equations in 40 CFR 98.83 to account for non-carbonate sources of
calcium and magnesium that may be present in the kiln feed.

Monitoring and QA/QC Requirements

Comment:  One commenter expressed concern that 40 CFR 98.84(e) and (f)
seem to require continuous, direct weight measurement of CKD discarded
and raw materials used, by category of material.  The commenter stated
that most cement plants do not have that capability, and that the
Proposed Ruleproposed rule does not clearly state whether installation
of additional measurement equipment will be required if not already
installed.

One industry representative further recommended that EPA add truck
weight scales as an acceptable option for raw material weight
measurement to address certain limited cases in which this method may be
more appropriate to use. In addition, the commenter recommended that EPA
allow CKD samples to be taken either as CKD exits the kiln or from bulk
storage.

Response:  We revised the text in §40 CFR 98.84(e) and (f) to more
clearly state that CKD quantities are required to be measured on a
quarterly basis and raw material quantities are required to be measured
on a monthly basis.  Furthermore, the Proposed Rule was never intended
to require installation of new monitoring equipment for this purpose.
We agree with the commenter that continuous, direct weight measurement
of these materials and installation of additional measurement equipment
would be unnecessary.  The proposed Rulerule clearly stated that the
quantity of CKD produced and raw materials consumed must be determined
using the same plant instruments that the cement plant currently uses
for accounting purposes.  Moreover, because the quantities of raw
materials and CKD do not greatly impact the CO2 calculation, we added
further clarification to this section to allow cement plants to use
potentially less accurate, but commonly used, methods of measurement,
such as truck weigh scales, to determine quantities of CKD and raw
materials.  We also added clarification to §40 CFR 98.84 to allow
facilities to collect CKD samples either as CKD exits the kiln or from
bulk storage.

Data Reporting Requirements

Comment:  Two commenters asserted that EPA needs to provide clarifying
language within Subpart 40 CFR part 98, subpart H (Cement Production) to
define which requirements apply to facilities using CEMS to monitor CO2
emissions.  One commenter noted that the Proposed Rule, as written,
appears to require cement plants using CEMS to collect maintain, and
report process data related to calculating CO2 process emissions for
kilns pursuant to proposed §40 CFR 98.84- through 98.87.  This
commenter claimed that requiring plants to collect and report such
process data is are redundant if the facility is continuously monitoring
CO2 emissions.  Another commenter recommended that EPA state within
Subpart40 CFR part 98, subpart H (Cement Production) that all of the
requirements detailed in the subpart do not apply to cement kilns using
Tier 4 (CEMS) method.

Response:  We agree with the comment that reporters who are using CEMS
to monitor CO2 do not need to collect, report, and maintain all of the
process data required in proposed 40 CFR 98.84 through 98.87.  However,
we determined that some of the process data are necessary for emissions
verification purposes, and therefore, facilitiesplants using CEMS are
not completely excluded from the requirements in Subpart40 CFR part 98,
subpart H. (Cement Production).  We added clarifying language throughout
the Subpart to clearly state which requirements will apply to facilities
that use CEMS to measure CO2 emissions.  Specifically, we created
separate lists of reporting requirements and recordkeeping requirements
that for cement plants using CEMS.

Comment:  One commenter noted that the data reporting requirements for
cement plants, set forth in proposed 40 CFR 98.86, are expressed in
different terms that those used for the specified procedures for
calculating emissions.  For example, the commenter stated that it is
unclear what emission sources go into the “site-specific emission
factor (metric tons CO2/metric ton clinker produced)” required to be
reported under proposed section §40 CFR 98.86(h), and how that factor
would be calculated.

Response:  We agree with the commenter that there were inconsistencies
between sections §40 CFR 98.83 and §98.86.  We updated reporting
requirements in §40 CFR 98.86 to be consistent with the terms used in
the emission calculation procedures in §40 CFR 98.83 and provide
clarification in §40 CFR 98.83 for terms if needed.  As a result, some
calculations that are performed on a kiln-specific basis, such as CO2
emission factors, will be required to be reported on a kiln-specific
basis in §40 CFR 98.86.  Also see the Section II.N of this preamble for
the response to comments on the emissions verification approach.

I.  Electronics Manufacturing

At this time EPA is not going final with the electronics manufacturing
subpart.  As we consider next steps, we will be reviewing the public
comments and other relevant information.

The Agency received a number of lengthy, detailed comments regarding the
electronics manufacturing subpart.  Commenters generally opposed the
proposed reporting requirements and stated the proposal required
excessive detail.  For example, commenters asserted that they currently
do not collect the data required to report using an IPCC Tier 3 approach
and that to collect such data would entail significant burden and
capital costs.  In most cases, commenters provided alternative
approaches to each of the reporting requirements proposed by EPA.

 Commenters also requested clarification from EPA on a number of the
proposed reporting provisions.

Based on careful review of comments received on the proposal preamble,
rule, and technical support documents (TSDs) under proposed 40 CFR part
98, subpart I, EPA will perform additional analysis and evaluate a range
of data collection procedures and methodologies.  EPA’s goal is to
optimize methods of data collection to ensure data accuracy while
considering industry burden.

J.  Ethanol Production

At this time, EPA is not finalizing the Ethanol Production Subpart.  The
sources of GHG emissions at ethanol production facilities that were to
be reported under the proposed rule were stationary fuel combustion,
onsite landfills, and onsite wastewater treatment.  EPA has decided not
to finalize the portion of 40 CFR part 98, subpart HH (Landfills) that
addresses industrial landfills nor 40 CFR part 98, subpart II
(Wastewater Treatment).  Stationary fuel combustion sources at ethanol
production facilities are subject to the requirements of 40 CFR part 98,
subpart C if general stationary fuel combustion emissions exceed the
25,000 metric tons CO2e threshold.

 As EPA considers next steps, we will be reviewing the public comments
and other relevant information.  Based on careful review of comments
received on the proposal preamble, rule and technical support
documentsTSDs under proposed 40 CFR part 98, subparts J, HH, and II, EPA
will perform additional analysis and consider alternatives to data
collection procedures and methodologies contained in those subparts.

K.  Ferroalloy Production

1.  Summary of the Final Rule

Source Category Definition.  The ferroalloy production source category
consists of facilities that use pyrometallurgical techniques to produce
any of the following metals: ferrochromium, ferromanganese,
ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium,
ferrotungsten, ferrovanadium, silicomanganese, or silicon metal.

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

GHGs to Report.  For ferroalloy production, report the following
emissions.

Annual process CO2 emissions from each EAF used for production of any
ferroalloy listed in the source category definition.

Annual process CH4 emissions for those EAFs used for the production of
silicon metal, ferrosilicon 65 percent, ferrosilicon 75 percent, or
ferrosilicon 90 percent.

CO2, N2O, and CH4 emissions from each stationary combustion unit on site
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).

In addition, report emissions from any other source categories for which
calculation methodologies are specified in the rule, as applicable.

GHG Emissions Calculation and Monitoring.  To calculate process CO2
emissions from EAFs, reporters can use one of two methods, as
appropriate:

Most reporters can elect to calculate and report process CO2 emissions
from each EAF by either (1) installing and operating a CEMS and
following the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2)
using the carbon mass balance calculation procedure specified in the
rule and summarized below.

However, if CO2 process emissions from an EAF are emitted through the
same stack as CO2 emissions from a combustion unit or process equipment
that uses a CEMS and follows Tier 4 methodology to report CO2 emissions,
then the CEMS must be used to measure and report combined emissions from
that stack, instead of using the carbon mass balance calculation
procedure described below.

If using the carbon mass balance procedure, perform a once per year
calculation using equations in the rule and:

Recorded monthly production data, and

The average carbon content for each EAF input and output material
determined by either using material supplier information or by annual
analysis of representative samples of the material.

For those EAF’s for which the reporter must report annual CH4
emissions, annual ferroalloy production data are used with an applicable
emissions factor provided in the rule.

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 K.

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
K.

2.  Summary of Major Changes Since Proposal

The major changes to the rule since proposal for ferroalloy production
facilities were revisions to the carbon mass balance calculation
procedure for calculating process CO2 emissions from EAFs.  These
changes reduce the reporting burden and are consistent with revisions
made to other similar industries.  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 K: Ferroalloy Production.  Changes
include:.”

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

Frequency of material carbon content sampling and analysis of each EAF
input and output material used for the material balance was revised to
be performed by annual analysis of representative samples of the
material instead of the proposed monthly basis.

Materials contributing less than 1 one percent of the total carbon into
or out of the EAF do not need to be included carbon mass balance
calculations.

40 CFR 98.116 and 98.117 were reorganized and updated to improve the
emissions verification process.  Some data elements were moved from
section40 CFR 98.117 to section40 CFR 98.116, and some data elements
that a reporter must already use to calculate GHG'sGHGs as specified in
section40 CFR 98.173 were added to section40 CFR 98.116 for clarity.
See the Section II.N of this preamble for the response to comments on
the emissions verification approach.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
Other comments on ferroalloy production were received covering various
topics.  Responses to significant comments received can be found in the
comment response document for ferroalloy production in the docket
(EPA-HQ-OAR-2008-508-XXX).Responses to significant comments received can
be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments, Subpart K: Ferroalloy Production.”

Comment:  One comment was received on the proposed rule specific to
ferroalloy production facilities.  The commenter requested that EPA
allow ferroalloy production facilities to use alternative methods for
determining EAF process CO2 emissions other than those proposed, and
specifically a protocol for silicon metal production facilities
developed for use by the Chicago Climate Exchange.  This smelting
protocol was developed a protocol for calculating the CO2 emissions from
based on the World Resources Institute (WRI aluminium) aluminum smelting
protocol.

Response:  We reviewed the WRI aluminum smelting protocol, which was
publicly available and did not have a access towe tried to obtain a copy
of the specific protocol that the commenter mentions to fully evaluate
whether it is an appropriate alternative.  However, we never received it
in the long run.  The commenter did not provide additional or more
specific recommendations beyond the reference to improve or revise the
proposed methodology.  At this time, given insufficient information, we
have decided not to include additional alternative methods in the final
rule for ferroalloy production facilities. As we stated at proposal, the
selected methodology was based on review of several existing
methodologies used by the 2006 IPCC Guidelines for National Greenhouse
Gas Inventories, Canadian Mandatory Greenhouse Gas Reporting Program,
the Australian National Greenhouse Gas Reporting Program, and EU
Emissions Trading System.

However, we have revised the frequency of sampling and analysis of
carbon contents for carbon containing input and output materials monthly
to annual consistent with revisions made in response to comments for
similar production processes (e.g. emissions from metal production).
These revisions reduce the reporting burden for ferroalloy production
facilities.  We understand that the carbon content of material inputs
and outputs does not vary widely at a given facility for the significant
process inputs that contain carbon, and we continue to account for
variations due to changes in production rate, which is likely a more
significant source of variability.  The response to the comment can be
found in the comment response document for ferroalloy production in the
docket (EPA-HQ-OAR-2008-508-XXX).The response to the comment can be
found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart K: Ferroalloy Production.”

L.  Fluorinated GHG Production

At this time EPA is not going final with the subpart for emissions from
fluorinated GHG production.  As we consider next steps, we will be
reviewing the public comments and other relevant information.

The Agency received a number of lengthy, detailed comments regarding the
fluorinated GHG production subpart.  Commenters generally opposed the
proposed reporting requirements. Several commenters stated that
facilities could not meet the proposed accuracy, precision, and
frequency requirements using existing equipment and practices.  These
commenters stated that they would need to expend significant funds
(millions of dollars in some cases) and time to install Coriolis
flowmeters in multiple streams and to implement daily sampling protocols
to analyze the contents of these streams.  Some commenters stated that
even after such equipment was installed, the proposed mass-balance
approach was likely to be inaccurate, particularly for batch processes.
In most cases, commenters provided alternative approaches, such as
emission-factor based approaches, to the proposed mass-balance approach.

Based on careful review of comments received on the proposal preamble,
rule, and technical support documentsTSDs under proposed 40 CFR part 98,
subpart L, EPA will perform additional analysis and evaluate a range of
data collection procedures and methodologies.  EPA’s goal is to
optimize methods of data collection to ensure data accuracy while
considering industry burden.

M.  Food Processing

At this time, EPA is not going final with the Food Processing Subpart.
The sources of GHG emissions at food processing facilities that were to
be reported under the proposed rule were stationary fuel combustion,
onsite landfills, and onsite wastewater treatment.  EPA has decided not
to finalize the portion of 40 CFR part 98, subpart HH (Landfills) that
addresses industrial landfills nor 40 CFR part 98, subpart II
(Wastewater Treatment).  Note, however, that Stationary fuel combustion
sources at food processing facilities are subject to the requirements of
40 CFR part 98, subpart C if general stationary fuel combustion
emissions exceed the 25,000 metric ton CO2e threshold.  As EPA considers
next steps, we will be reviewing the public comments and other relevant
information.

Based on careful review of comments received on the proposal preamble,
rule and technical support documentsTSDs under proposed 40 CFR part 98,
subparts M, HH, and II, EPA will perform additional analysis and
consider alternatives to data collection procedures and methodologies
contained in those subparts.

N.  Glass Production

1.  Summary of the Final Rule

Source Category Definition.  The glass production source category
consists of facilities that manufacture glass (including flat,
container, pressed, or blown glass) or wool fiberglass using one or more
continuous glass melting furnaces.  Experimental furnaces and research
and development process units are excluded.

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

GHGs to Report.  For glass production facilities, report the following
emissions:

CO2 process emissions from each continuous glass melting furnace.

CO2 combustion emissions from each continuous glass melting furnace,

CH4 and N2O emissions from fuel combustion at each continuous glass
melting furnace under 40 CFR part 98, subpart C (General Stationary
Combustion Sources) using the methodologies in subpart C.

CO2, CH4, and N2O emissions and from each onsite stationary fuel
combustion unit other than continuous glass melting furnaces under 40
CFR part 98, subpart C (General Stationary Combustion Sources).

In addition, report GHG emissions for any other source categories at the
facility for which calculation methods are provided in other subparts of
the rule, as applicable.

GHG Emissions Calculation and Monitoring.  For CO2 process emissions
from glass melting furnaces, reporters must use one of two methods, as
appropriate:

For glass melting furnaces with certain types of CEMS in place,
reporters must use the CEMS and follow the Tier 4 methodology (in 40 CFR
part 98, subpart C) to measure and report under the glass production
subpart (40 CFR part 98, subpart N) combined process and combustion CO2
emissions.

For other glass melting furnaces, the reporter can elect to either (1)
install and operate a CEMS and follorfollow the Tier 4 methodology to
measure and report combined process and combustion CO2 emissions or (2)
calculate process CO2 emissions for each furnace using an emission
factor and process data.  If using approach (2), multiply a default
emission factor appropriate for the carbonate raw material by:

the annual mass of carbonate-based raw material charged to the furnace
(required to be measured); and

the mass-fraction of carbonate in the raw material (based on data
supplied by the raw material supplier and verified by an annual
measurement).

Under approach (2), report process CO2 emissions from each glass melting
furnace under 40 CFR part 98, subpart N (Glass Production), and report
combustion CO2 emissions from each glass furnace under 40 CFR part 98,
subpart C (General Stationary Fuel Combustion Sources).

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

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
N.

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 N: Glass
Production..”

The definition of the term "glass produced" was added to the
defintionsdefinitions in 40 CFR part 98, subpart A.

40 CFR 98.146 was reorganized and updated to improve the emissions
verification process.  Some data elements were moved from section40 CFR
98.147 to section40 CFR 98.146, and some data elements that a reporter
must already use to calculate GHG'sGHGs as specified in section40 CFR
98.143 were added to section40 CFR 98.146 for clarity.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
Several comments on glass production were received covering numerous
topics.  Responses to significant comments received can be found in the
comment response document for glass production in the docket
(EPA-HQ-OAR-2008-508-XXX).Responses to significant comments received can
be found in “Mandatory Greenhouse Gas Reporting Rule: EPA’s Response
to Public Comments, Subpart N: Glass Production.”

Definition of Source Category

Comment:  One commenter stated that EPA should exempt from the rule all
fiber glass and rock and slag wool insulation facilities within the
glass production source category because glass production facilities
subject to the proposed rule are a miniscule portion of the total
national emissions of CO2e, and amount to less than 0.1% percent of
total GHG emissions in the U.S. and the subset of fiber glass and rock
and slag wool insulation facilities is an even smaller portion.  The
commenter stated that there is virtually no benefit to having the glass
production source category subject to the proposed rule, and any benefit
is outweighed by the burden imposed on these facilities.  The commenter
also pointed out the importance of the fiber glass and rock and slag
wool insulation industry’s products in meeting the nation’s energy
needs and reducing greenhouse gasGHG emissions.  Exempting the industry
from the proposed rule’s reporting requirements will help the industry
focus more of its scarce resources on producing insulation.

Response:  We recognize that the glass manufacturing industry is
comprised of a wide range of facilities, many of which are small in size
and have relatively low levels of emissions.  However, the data we have
collected on the industry indicate that there are several large glass
manufacturing plants with significant GHG emissions.  These plants
include some that produce glass fiber, flat glass, and container glass,
as well as other types of pressed and blown glass products.  As a
result, we do not agree with the commenter that fiber glass and other
types of insulation facilities should be exempt from reporting.
However, we tried to reduce the burden on the glass manufacturing
industry by incorporating into the proposed rule a 25,000 metric ton
CO2e threshold, which should preclude small facilities from having to
report GHGs.  We have retained thisThis threshold remains in the final
rule.  Thus, any small fiber glass and rock and slag wool insulation
facilities with insignificantlow GHG emissions will fall under the
threshold and will be exempt from reporting.  To further minimize the
burden on the industry, we have tried to limit recordkeeping and
reporting requirements to the types of data that glass production
facilities already collect as part of normal business operations.

Commenters may also be interested in reviewing Section II.H of this
preamble for the response on provisions to cease reporting.  The final
rule contains a provisionprovisions to cease reporting if annual reports
demonstrate emissions less than 25,000 metric tons CO2e per
yearspecified levels for 5 consecutivemultiple years.

Selection of Threshold

Comment:  One commenter remarked that EPA should raise the threshold for
reporting for fiberglass and rock and slag wool insulation entities.
Doing so would reduce the number of entities reporting with only a
minimal impact on the amount of emissions covered.  The commenter stated
that EPA’s analysis did not address reasonable alternative thresholds
between 25,000 and 100,000 metric tons.

Response:  When evaluating potential thresholds for reporting GHG
emissions, we considered several thresholds between 1,000 and 100,000
mtmetric tons CO2e.  We selected the 25,000 mtmetric tons CO2e threshold
for reporting GHG emissions in order to achieve a balance between
quantifying the majority of the emissions and minimizing the number of
facilities impacted.  For example, at a 1,000 metric tons CO2e
threshold, 98 percent of emissions would be covered, with about 58
percent of facilities being required to report.  Compared to the 100,000
mtmetric tons CO2e threshold, the proposed 25,000 mtmetric tons CO2e
threshold achieves reporting of 11 times more emissions while requiring
less than 15 percent of the facilities to report.  Compared to the
10,000 metric tons CO2e threshold, the 25,000 mtmetric tons CO2e
threshold captures more than half of those emissions, but only requires
a third of the facilities in the industry to report.  This threshold
offers significant coverage of the GHG emissions while impacting a
relatively small portion of the industry.  Although a threshold of
50,000 mtmetric tons CO2e would greatly reduce the number of facilities
reporting, it would capture less than 20 percent of total emissions for
the industry.  We believe the proposed threshold of 25,000 mtmetric tons
CO2e represents the best option for ensuring that the majority of
emissions are reported without imposing an unreasonable burden on the
industry.

Section II.E of this preamble discussescontains a general discussion of
the selection of the 25,000 metric tons CO2e threshold and the
alternative thresholds considered.

Method for Calculating GHG Emissions

Comment:  One commenter fully supports EPA'sEPA’s proposed rule for
measuring, calculating, monitoring, and reporting emissions from the
glass melting process.  They agree that 40 CFR part 98, subpart N
represents a good balance between site reporting burden, cost, and data
accuracy and consistency.  Specifically, the commenter supports using
raw-material emissions factors and usage rates, as proposed, to
calculate emissions from glass production in lieu of requiring
installing CEMs on sources that another regulation does not currently
require to be installed.

Response:  We acknowledge this support for the proposal and appreciate
these comments.  We have retained the proposed calculation methodology
in the final rule.

Data Reporting Requirements

Comment:  One commenter stated that, at various places in the preamble
and proposed rule, EPA uses the phrase “glass produced,” but has not
defined this phrase in the rule.  The commenter noted that the phrase
could be interpreted to mean either glass melted or glass product
produced.  The commenter assumed that the phrase refers to the amount of
glass melted, but requested clarification.

Response:  We agree that the term glass produced is subject to
interpretation.  We have added a definition of the term to 40 CFR part
98, subpart A of the final rule.  “Glass produced” means the weight
of glass exiting a glass melting furnace.

Comment:  One commenter remarked that some of the information that would
have to be reported under the proposed rule, such as annual quantity of
glass produced, is considered to be company confidential and could be
used by competitors to back-calculate product formulas.  The commenter
requested that EPA remove these reporting requirements from the rule and
instead, require that the data be retained by the facility and made
available for review by EPA.  Should EPA require the reporting of all of
this information in the final rule, the commenter requests that EPA
explicitly state in the final rule and confirm in the preamble to the
final rule that all information provided under Subpart40 CFR part 98,
subpart N, other than the annual process emissions of CO2, is considered
confidential information and would not be considered “emission data”
under this reporting rule.  The commenter requests that a new paragraph
(e) be added to proposed Section40 CFR 98.146 that reads:  “No
information required to be reported by this section, other than the
information required by Section40 CFR 98.146(a), is considered to be
emission data under 40 CFR Section 2.301(a)(2)(i) and (ii).”

Response:  We acknowledge the commenter’s concerns.  However, the
quantity of glass produced is an important variable for EPA to verify
whether reported emissions are within a reasonable range and therefore
is a required reporting parameter under Subpart40 CFR part 98, subpart
N.

We have reviewed CBI comments received across the rule (both general and
subpart-specific comments) and our response is discussed in Section II.R
of this preamble and in the comment response document for legal
issues.“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Legal Issues.”

O.  HCFC-22 Production and HFC-23 Destruction

1.  Summary of the Final Rule

Source Category Definition.  This source category consists of:

Processes that produce HCFC-22 (chlorodifluoromethane or CHClF2) using
chloroform and hydrogen fluoride.

HFC-23 destruction processes located at HCFC-22 production facilities.

HFC-23 destruction processes that destroy more than 2.14 metric tons of
HFC-23 per year and that are not located at HCFC-22 production
facilities.

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

GHGs to Report.  For facilities that produce HCFC-22 or that destroy
HFC-23, report the following emissions:

HFC-23 emissions from all HCFC-22 production processes at the facility.

HFC-23 emissions from each destruction process.

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 by following the requirements of 40
CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

GHG Emissions Calculation and Monitoring.  Reporters must calculate
HFC-23 emissions as follows:

For HCFC-22 production processes that do not use a thermal oxidizer or
that have a thermal oxidizer that is not connected to the production
equipment, calculate annual HFC-23 emissions at the facility level using
a mass balance equation and the following information: annual HFC-23
generated, the annual HFC-23 sent off site for sale, the annual HFC-23
sent off site for destruction, the annual increase in the HFC-23
inventory, and the annual HFC-23 destroyed on site (calculated by
multiplying the mass of HFC-23 fed to the destruction device by the
destruction efficiency).

For HCFC-22 production processes with a thermal oxidizer that is
connected to the production equipment, calculate annual HFC-23 emissions
at the facility level by summing the following emissions:

Annual HFC-23 emissions from equipment leaks (calculated using default
emission factors and the measured number of leaks in valves, pump seals,
compressor seals, pressure relief valves, connectors, and open-ended
lines).

Annual HFC-23 emissions from process vents (calculated for each vent
using the HFC-23 emission rate from the most recent emission test and
the ratio of the actual production rate and the production rate during
the emission test).

Annual HFC-23 from the thermal oxidizer (calculated by subtracting the
amount of HFC-23 destroyed by the destruction device from the measured
mass of HFC-23 fed to the destruction device).

For other HFC-23 destruction processes, calculate HFC-23 emissions based
on the mass of HFC-23 fed to the destruction device and the destruction
efficiency.

For the destruction efficiency, conduct a performance test or use the
destruction efficiency determined during a previous performance test.
To confirm the destruction efficiency, measure the fluorinated GHG
concentration at the outlet to the destruction device annually.

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 O.

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
O.

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 O: HCFC-22
productionProduction and HFC-23 destruction:Destruction.”

The minimum required frequency of mass flow and concentration
measurements has been decreased from daily to weekly.

The required frequency of emissions tests at process vents has been
decreased to once every five years.  A test is also required after a
significant change is made to the process.

The required annual measurements at the outlet of the thermal oxidizer
now omit measurements of mass flow.  Three samples are required to be
taken; the average of these is compared to the concentration at the
outlet of the oxidizer that was measured during the initial performance
test that established the destruction efficiency (DE).

A term has been added to the mass-balance equation for HCFC-22
production facilities that do not have a thermal oxidizer that is
directly connected to the HCFC-22 production equipment.  This term
accounts for increases in the inventory of stored HFC-23 that can occur
during the year.

EPA has added an additional method for estimating missing mass flow data
in the event that a secondary mass measurement for that stream is not
available.

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

Some reporting requirements have been added to be consistent with the
changes to the calculations and monitoring sections and to permit
verification of emissions calculations.

EPA decreased the minimum frequency of gas flow and concentration
measurements from daily to weekly because EPA’s research indicates
that HFC-23 concentrations are not likely to vary significantly over a
one week period.  This change also makes the required measurement
frequency more consistent with current industry practice.

As noted above, EPA removed the option for reporters to develop their
own methods for estimating missing data if they believe that the
prescribed method will over- or underestimate the data.  EPA removed
this option for two reasons.  First, the proposed provision lacked clear
guidance on when alternative methods should be used (e.g., on the size
of an underestimate that would justify use of an alternative method) and
on how they should be developed.  Second, the proposed provision was
redundant with the new provision that permits reporters to estimate
missing data using a related parameter and the historical relationship
between the related parameter and the missing parameter.  This new
option provides reporters with flexibility in substituting for missing
data in the event that a secondary mass measurement is not available,
but sets out general guidance on how to select the substitute data.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses.
A number of comments on HCFC-22 production and HFC-23 destruction were
received covering numerous topics.  Responses to significant comments
received can be found in the comment response document for“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Subpart O: HCFC-22 productionProduction and HFC-23 destruction in the
docket (EPA-HQ-OAR-2008-508-XXX).Destruction.”

Monitoring and QA/QC Requirements

Comment:  EPA received a comment that the requirement to annually
conduct emissions tests at process vents is overly burdensome and
unnecessary because it is unlikely that the emissions rate would deviate
from an initial process vent test unless there were a significant change
in the process.  This commenter argued that testing should be required
at least every 5five years or after a significant change in the process.

Response: In response to this comment, EPA has reduced the required
frequency of emissions tests at process vents to once every five years,
or after a significant change to the process.  EPA has also clarified
that the requirement applies only to HCFC-22 production facilities that
use a thermal oxidizer connected to the HCFC-22 production equipment.
These are the only facilities that use process vent emission estimates
in their calculation of facility-wide HFC-23 emissions.

EPA is decreasing the frequency of emissions tests at process vents for
two reasons.  First, EPA agrees with the commenter that, in the absence
of a significant process change, the process vent emission rate is not
likely to vary much (in percentage terms) from year to year.  Second,
although small variations in the emission rate could still lead to
significant absolute errors for facilities with large process vent
emissions, the facilities that are required to test their process vent
emissions are likely to have small process vent emissions (because they
use thermal oxidizers connected to the production equipment).
(Facilities that do not use thermal oxidizers connected to the equipment
would be expected to have larger process vent emissions, but they are
required to use a mass-balance approach to calculate emissions rather
than summing emissions across process vents, equipment leaks, and
thermal oxidizers.)  Together, these considerations lead to the
conclusion that testing process vent emissions every five years should
sufficiently minimize errors in the overall HFC-23 emission calculations
of the facilities affected by the testing requirement.

Comment:  EPA should add a term to Equation O-4 (the mass-balance
equation for HCFC-22 production facilities that do not have a thermal
oxidizer that is directly connected to the HCFC-22 production equipment)
to account for increases in the inventory of stored HFC-23 that can
occur during the year.

Response:  EPA added a term to Equation O-4 for increases in the
inventory of stored HFC-23.  EPA agrees that the equation should account
for changes in the inventory of HFC-23 that is stored on site.  It is
important to track all reservoirs of HFC-23 at the facility;
mass-balance approaches used to track emissions from other sources
(e.g., from electrical equipment) frequently include terms to account
for the increase in inventory.

Definition of Source Category

Comment:  EPA received a comment that the measurement of HFC-23
emissions from HCFC-22 production should be moved to Subpart L, which
covers the reporting of fluorinated greenhouse gasGHG production.

Response:  EPA proposed provisions for facilities producing fluorinated
gases in three separate subparts: 40 CFR part 98, Subpart L, Subpart O,
and Subpart OO.  Although there are many similarities across the
chemicals and processes covered by the three subparts, the subparts were
deliberately tailored to different sources and types of emissions.
Subpart L was intended to address emissions of fluorinated GHGs from
fluorinated GHG production.  Subpart40 CFR part 98, subpart O was
intended to address HFC-23 generation and emissions from HCFC-22
production.  Subpart40 CFR part 98, subpart OO was intended to address
flows affecting the U.S. industrial gas supply, including production,
transformation, and destruction.

EPA determined that 40 CFR part 98, subpart O was necessary because
HCFC-22 production and HFC-23 destruction facilities differ from other
fluorinated gas production facilities in two key respects.  First, the
primary fluorinated GHG that they generate (HFC-23) is made as a
byproduct to the production of a substance that is not defined as a
fluorinated GHG (HCFC-22).  Second, due to the very high GWP of HFC-23,
each HCFC-22 facility generates very large quantities of CO2-equivalent.
 For the second reason, EPA has worked with HCFC-22 producers for over
ten years to understand and reduce HFC-23 emissions.  The requirements
for HCFC-22 producers are therefore based on a close knowledge of their
production processes and methods for accounting for emissions.  These
methods are also comprehensive (e.g., accounting for emissions from
equipment leaks and losses during transport of HFC-23 that is shipped
off-site for destruction).  These requirements may not be appropriate
for other fluorinated gas producers, and, at the same time, the
requirements for fluorinated gas producers may not be appropriate for
HCFC-22 producers.

P.  Hydrogen Production

1.  Summary of the Final Rule

Source Category Definition.  The merchant hydrogen production source
consists of process units that produce hydrogen by reforming,
gasification, or other transformation of feedstock and transfer the
hydrogen produced off site.  Hydrogen production facilities located at
petroleum refineries or other large facilities are included in this
source category only if they are not owned by or under the direct
control of the refinery owner.  Otherwise, they are considered to be a
captive hydrogen production source that reports emissions under the
subpart applicable to the larger facility, e.g., Subpart40 CFR part 98,
subpart Y (Petroleum Refineries).

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

GHGs to Report.  For hydrogen production, report the following
emissions:

CO2 process emissions from hydrogen production.

CO2, N2O, and CH4 emissions from each stationary combustion unit on site
by following the requirements of 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).

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

In addition, report GHG emissions for other source categories for which
calculation methods are provided in the rule, as applicable.

GHG Emissions Calculation and Monitoring.

To calculate and report process CO2 emissions from hydrogen production,
most reporters can elect to either (1) install and operate CEMS and
follow the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2)
calculate process CO2 emissions using equations in the 40 CFR part 98,
subpart P and the following data:

Measurements of monthly feedstocks and fuel consumed.

Carbon content of the feedstock measured monthly.

Molecular weight of the feedstock (gaseous fuels only).

However, if process CO2 emissions from hydrogen production are vented
through the same stack as a combustion unit or process equipment that
uses a CEMS to follows Tier 4 methodology to report CO2 emissions, then
the CEMS must be used to measure and report combined CO2 emissions from
that stack instead of the calculation procedure described in approach 2
above.

Monitoring and QA/QC Requirements.  The methods for the initial
calibration and annual recalibration of flow meters are defined in a
prescriptive list of industry standard test methods incorporated by
reference in the Tier 3 method in Subpart40 CFR part 98, subpart C,
while the methods for determining carbon content of fuels and feedstocks
are defined in a prescriptive list of an assortment of industry standard
test methods incorporated by reference.

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 P.

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
P.

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 P: Hydrogen
Production.Prodution.”

40 CFR 98.160 was reworded to clarify the definition of reporting
entity.

40 CFR 98.162 was revised to allow reporting of combined process and
combustion CO2, CH4, and N2O emissions.

In 40 CFR 98.162163(b), “feedstock” was changed to “fuel and
feedstock”.

40 CFR 98.164 was restructured to clarify between CEMS measurements and
QA/QC and feedstock method measurements and QA/QC.

40 CFR 98.164 was reworded to allow the characterization of feedstocks
to be conducted by either the consumer or the supplier, to allow
standard gaseous hydrocarbon fuels of commerce to be characterized
annually, and to allow liquid and solid hydrocarbon fuels of commerce to
be characterized upon delivery if delivered by bulk transport.

The recalibration requirements in 40 CFR 98.164 were changed to reduce
economic impact.

The list of standards incorporated by reference in 40 CFR 98.164 was
broadened.

The missing data procedures in 40 CFR 98.165 were revised to be
consistent with §40 CFR 98.35(b).

40 CFR 98.166 and 98.167 were restructured to clarifydistinguish between
CEMS recordkeeping and feedstock method recordkeeping.

40 CFR Section 98.166 was reorganized and updated to improve the
emissions verification process.  Some data elements were moved from
section40 CFR 98.167 to section40 CFR 98.166, and some data elements
that a reporter must already use to calculate GHG'sGHGs as specified in
section40 CFR 98.163 were added to section40 CFR 98.166 for clarity.

3.  Summary of Comments and Responses

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

Definition of Source Category

Comment:  Multiple commenters pointed out the lack of clarity regarding
the definition of the reporting entity, and suggested defining the
entity holding the air permit for an affected facility as the reporting
entity.  For example, “If the owner/operator of the facility is the
holder of the air permit for an affected facility, then the operator
should be responsible for reporting GHG emissions.  If not, then EPA
should clarify the responsibility for reporting.”

Response:  EPA reviewed this complex issue.  First, a facility is
defined in §40 CFR 98.6:  “Facility means any physical property,
plant, building, structure, source, or stationary equipment located on
one or more contiguous or adjacent properties in actual physical contact
or separated solely by a public roadway or other public right-of-way and
under common ownership or common control, that emits or may emit any
greenhouse gas.”  Therefore, a any hydrogen production process unit
that is not part of a larger facility, as defined above,  covered by
another subpart of this rule is a merchant hydrogen production facility
which reports emissions under Subpart40 CFR part 98, subpart P.  On the
other hand, a hydrogen production process unit that is part of a larger
facility, as defined above, covered by another subpart of this rule is a
captive hydrogen production facility that does not report emissions
under Subpart40 CFR part 98, subpart P.  Their emissions, including
those emissions from the captive hydrogen production facility, are
reported under the subpart applicable to the larger facility.  Second,
in answer to the question, “Do I need to report?”, 40 CFR 98.2
states that “A the rule applies to a facility that contains any of the
source categoriescategory listed in this paragraph [40 CFR §98.2(a)(2)
(which includes hydrogen production]) and that emits 25,000 metric tons
CO2e or more per year in combined emissions from stationary fuel
combustion units, miscellaneous uses of carbonates, and all source
categories that are listed in this paragraph in any calendar year
starting in 2010.listed in 40 CFR §98.2(a)(2).  EPA has concluded that
the rule explains this clearly in §40 CFR 98.2 and §98.6, and that it
is not necessary to change the rule.   To add clarity, however, EPA has
revised §40 CFR 98.160(c) as follows:  “This source category includes
merchant hydrogen production facilities located within a petroleum
refinery if they are not owned by, or under the direct control of, the
refinery owner and operator.”

GHGs to Report

Comment:  Multiple commenters requested clarification on the CO2
emission reporting obligation as combined “process” and
“combustion” CO2 emissions, regardless of the calculation method
employed.  If separate, discrete reporting of such emissions is actually
required, commenters asked EPA to provide explicit protection for this
information which they stated was very critical CBI.

Response:  In response to these multiple commenters, EPA has clarified
the rule in §40 CFR 98.162 to provide operators the option of providing
combined process and combustion CO2 emissions for each hydrogen
production process unit whether or not it meets the conditions in §40
CFR 98.33(b)(54)(ii) or and (iii) for CEMs.  Under 40 CFR 98.166,
facilities must report additional parameters for emissions verification.

See Sections II.I and II.N of this preamble for responses to the
comments received on the general content of the annual GHG report and
the emissions verification approach, respectively.  EPA reviewed CBI
comments received across the rule (both general and subpart-specific
comments) and our response is discussed in Section II.R of this preamble
and in the comment response document for legal issues.“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Legal Issues.”

Method for Calculating GHG Emissions

Comment:  Multiple commenters pointed out the need for a calculation
method to account for feedstock carbon that does not exit the hydrogen
production facility as CO2, but rather in the form of other products or
co-products that contain carbon (such as synthesis gas, CO, CH4).  Many
argued in favor of correcting equations P-1, P-2 and P-3 to account for
feedstock carbon that does not exit the hydrogen production facility as
CO2, but rather as products (such as synthesis gas, CO, CH4) that are
manufactured which contain carbon.

Response:  EPA generally concurs with the need to account for “carbon
other than CO2” that exits the facility.  EPA considered several
options for reporting such carbon and chose to have facilities report
CO2 and “carbon other than CO2” as separate data reporting elements
in §40 CFR 98.166 rather than including this carbon in equations P-1,
P-2, and P-3.  As a result, EPA has added data reporting elements under
§40 CFR 98.166 for (1) quarterly quantity of CO2 collected and
transferred off site in either gas, liquid, or solid forms (metric
tons), following the requirements of 40 CFR part 98, subpart PP of this
part, and (2) annual quantity of carbon other than CO2 collected and
transferred off site in either gas, liquid, or solid forms (metric
tons).

Monitoring and QA/QC Requirements

Comment:  Multiple commenters recommended that EPA should allow the
characterization of feedstocks (sampling and analysis) to be conducted
by either the feedstock consumer (the regulated source) or the feedstock
supplier. They state that the characterization of standard fuels of
commerce used as hydrogen production feedstocks, such as natural gas,
should not be required since default values will yield a sufficiently
accurate emission estimate. Commenters recommend that characterization
of such standard fuels of commerce used as feedstocks be optional, at
the source'ssource’s discretion.

Response:  EPA concurs  with this comment, since feedstock suppliers
regularly monitor the carbon content of their fuels and also, the carbon
content of standard fuels of commerce are quite consistent month to
month.  EPA has revised this section to allow the characterization of
feedstocks to be conducted by either the consumer or the supplier, to
allow standard gaseous hydrocarbon fuels of commerce to be characterized
annually, and allow liquid and solid hydrocarbon fuels of commerce to be
characterized upon delivery if delivered by bulk transport (e.g., by
truck or rail).  Other non-standard gaseous fuels and feedstocks must
still be subjected to weekly sampling and analysis to determine the
carbon content and molecular weight.

Comment:  Commenters recommended that EPA limit the requirement for
sampling non-gaseous fuels to new deliveries rather than monthly in
order to pinpoint the onset of fuel parameter variations.

Response:  EPA concurs that the carbon content of a liquid or solid
hydrocarbon fuel delivered in bulk will remain constant as the stock on
hand from the delivery is consumed, and therefore periodic testing
during the interim is not needed.  EPA has revised this section to allow
the characterization of feedstocks to be conducted by either the
consumer or the supplier, to allow standard gaseous hydrocarbon fuels of
commerce to be characterized annually, and allow liquid and solid
hydrocarbon fuels of commerce to be characterized upon delivery if
delivered by bulk transport (e.g., by truck or rail).  On the other
hand, other non-standard gaseous fuels and feedstocks must still be
subjected to weekly sampling and analysis to determine the carbon
content and molecular weight since their carbon content can vary
significantly from week to week.

Comment:  Multiple commenters recommended that EPA should include
provisions for an extension of the required meter/monitor calibration
deadline (as well as the initial calibration, if appropriate) when the
calibration would require removing the process line from service.  They
recommend that the calibration requirement be extended to the next
scheduled maintenance shutdown for the impacted unit/process.

Response:  EPA concurs that requiring the facility to remove the process
line from service represents an undue hardship and has therefore revised
Subpart40 CFR part 98, subpart P to refer to the less stringent
monitoring and QA/QC requirements for the Tier 3 methodology included in
Subpart40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).

Comment:  One commenter suggested adding ISO 5167-1 through ISO 5167-4
(Measurement of Fluid Flow by Means of Pressure Differential Devices) to
list of standards incorporated by reference.

Response:  EPA agrees ISO 5167-1 through ISO 5167-4 are suitable
calibration standards and would be good additions to the list of
standards.  However, given that the issues covered by these standards
(Venturi and orifice plate differential pressure flow meters) are
covered by two the American Society of Mechanical Engineers (ASME)
standards, one ASHRAE standard, and one AGA report which are already
included in §40 CFR 98.164, EPA has not explicitly added these
references to the list of standards incorporated by reference.

Procedures for Missing Data

Comment:  Multiple commenters recommended that the data substitution
method for missing feedstock supply rate data should be changed to be
consistent with §40 CFR 98.35(b)(2), allowing use of the “best
available estimate”, and that the data substitution method for missing
feedstock carbon content data should be changed to be consistent with
§40 CFR 98.35(b)(1), allowing use of the average before/after values.

Response:  EPA concurs that the required level of accuracy for hydrogen
production is similar to that required for stationary combustion, and
that the less stringent “best available estimate” approach is
appropriate for hydrogen production.  Therefore, EPA has changed the
language in Subpart P, §40 CFR 98.165, Procedures for Estimating
Missing Data, to follow the data substitution method for missing fuel
carbon content data prescribed in §40 CFR 98.35 and the data
substitution method for missing fuel usage data prescribed in §40 CFR
98.35 under Subpart C (General Stationary Combustion).

Data Reporting Requirements

Comment:  Multiple commenters stated that annual feedstock consumption,
annual hydrogen production, and feedstock carbon content are
confidential business information (CBI) and should not be reported.  The
commenters asked that this information be maintained by the facility and
be made available to the Agency upon request. One commenter further
stated that if data must be reported, the reporting rules must provide
explicit protection for this very critical confidential business
information.

Response:  Feedstock consumption and feedstock carbon content are
parameters used to calculate emissions.  Since annual CO2 emissions are
calculated from the sum of the products of monthly feedstock consumption
multiplied by the monthly average carbon content of the feedstock, all
of these parameters are required for emissions data verification
purposes.  Annual hydrogen production is an additional parameter which
is necessary for EPA to effectively verify emissions, since the ratio of
carbon emissions to hydrogen production is relatively consistent for
each hydrogen production facility.  See sectionSection II.N of this
preamble for information on emissions verification.  EPA reviewed CBI
comments received across the rule (both general and subpart-specific
comments) and our response is discussed in Section II.R of this preamble
and in the comment response document for legal issues.“Mandatory
Greenhouse Gas Reporting Rule: EPA’s Response to Public Comments,
Legal Issues.”

Q.  Iron and Steel Production

1.  Summary of the Final Rule

Source Category Definition.  The iron and steel production source
category consists of facilities with any of the following processes:

Taconite iron ore processing.

Integrated iron and steel manufacturing.

Cokemaking not co-located with an integrated iron and steel
manufacturing process.

EAF steelmaking not co-located with an integrated iron and steel
manufacturing process.

Integrated iron and steel manufacturing means the production of steel
from iron ore or iron ore pellets.  At a minimum, an integrated iron and
steel manufacturing process has a basic oxygen furnace for refining
molten iron into steel. Each cokemaking process and EAF process located
at a facility with an integrated iron and steel manufacturing process is
part of the integrated iron and steel manufacturing facility.

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.  Facilities must reportReport the following emissions
annually:

CO2, CH4, and N2O emissions from fuel combustion at each stationary
combustion unit according to the requirements in 40 CFR part 98, subpart
C (General Stationary Fuel Combustion Sources).  Stationary combustion
units include, but are not limited to, byproduct recovery coke oven
battery combustion stacks, blast furnace stoves, boilers, process
heaters, reheat furnaces, annealing furnaces, flame suppression, ladle
reheaters, and any other miscellaneous combustion sources (except
flares).

CO2 emissions from flares according to the requirements in 40 CFR part
98, subpart Y (Petroleum Refineries) and CH4 and N2O emissions from
flares using the default emission factors for coke oven gas and blast
furnace gas.

CO2 process emissions from each taconite indurating furnace, basic
oxygen furnace, nonrecovery coke oven battery combustion stack, coke
pushing process, sinter process, EAF, argon-oxygen decarburization
vessel, and direct reduction furnace.

In addition, report GHG emissions for any other source categories at the
facility for which calculation methods are provided in other subparts of
the rule, as applicable.

GHG Emissions Calculation and Monitoring.  For CO2 process emissions at
each taconite indurating furnace, basic oxygen furnace, nonrecovery coke
oven battery, sinter process, EAF, argon-oxygen decarburization vessel,
and direct reduction furnace, reporters must calculate emissions using
one of the following methods, as appropriate:

Most reporters can elect to calculate and report process CO2 emissions
by either: (1) installing and operating a CEMS and following the Tier 4
methodology (in 40 CFR part 98, subpart C) or (2) using one of the
following two calculation procedures:

Use a carbon balance method described in 40 CFR part 98, subpart Q to
calculate the annual mass emissions rate of CO2 for each process, based
on the annual mass of inputs and outputs and an annual analysis of the
respective weight fraction of carbon in each process input or output
that contains carbon.  Use separate procedures and equations for
taconite indurating furnaces, basic oxygen process furnaces, nonrecovery
coke oven batteries, sinter processes, EAFs, argon-oxygen
decarburization vessels, and direct reduction furnaces, or

Use a site-specific emission factor determined from a performance test
that measures CO2 emissions from all exhaust stacks and also measures
either the feed rate of materials into the process or the production
rate during the test for taconite indurating furnaces, basic oxygen
process furnaces, nonrecovery coke oven batteries, sinter processes,
EAFs, argon-oxygen decarburization vessels, and direct reduction
furnaces.

However, if process CO2 emissions from a taconite indurating furnace,
basic oxygen furnace, nonrecovery coke oven battery, sinter process,
EAF, argon-oxygen decarburization vessel, and direct reduction furnace
are emitted through the same stack as CO2 emissions from a combustion
unit or process equipment that uses a CEMS and follows the Tier 4
methodology to report CO2 emissions, then the CEMS must be used to
measure and report combined CO2 emissions from that stack.  In such
cases, the reporter cannot use the other process CO2 calculation
approaches outlined above.

For coke oven pushing, facilities must use a CO2 emission factor
provided in the rule.

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 Q.

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
Q.

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 Q: Iron and
Steel Production.”

The major changes made since proposal include:

The carbon mass balance method was revised to require an annual analysis
of all process inputs and outputs for carbon content rather than weekly
sampling and monthly analysis.

The site-specific emission factor method was revised to:  (1) require
testing based on representative performance rather than at 90 percent of
capacity, (2) sampling for a minimum of three hours or production cycles
rather than nine, (3) conducting separate tests for each different
process condition that is a part of normal operation if the change in
CO2 emissions at the different conditions is more than 20 percent, and
(4) adding a provision to clarify testing requirements when the EAF and
argon-oxygen decarburization vessel are ducted to the same control
device and stack.

To improve the emissions verification process, section40 CFR 98.176 was
reorganized and updated. Some data elements were moved from section40
CFR 98.177 to section40 CFR 98.176, and some data elements that a
reporter must already use to calculate GHG'sGHGs as specified in
section40 CFR 98.173 were added to section40 CFR 98.176 for clarity.

3.  Summary of Comments and Responses

This section contains a brief summary of major comments and responses
related to the requirements for iron and steel processes.  A large
number of comments on iron and steel production were received covering
numerous topics.  Many of these comments were directed at the
requirements for 40 CFR part 98, subpart C (General Stationary Fuel
Combustion Sources in subpart C), and responses to those comments are
provided in preamble section IISection III.C of this preamble.  Also see
the Section II.N of this preamble for the response to comments on the
emissions verification approach.  Responses to other significant
comments received related to process emissions from iron and steel
production can be found in the comment response document for
iron“Mandatory Greenhouse Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart Q: Iron and steel production in the docket
(EPA-HQ-OAR-2008-0508-XXX).Steel Production.”

Method for Calculating GHG Emissions.

Comment:  Several industry representatives and their three trade
associations requested that EPA allow the use of a simplified
facility-wide carbon balance approach developed by the American Iron and
Steel Institute (AISI) to calculate CO2 emissions from iron and steel
production facilities.  According to the commenters, the AISI
methodology has recently been adapted to facility-wide reporting and is
emerging as the preferred reporting protocol internationally.  The
commenters described the approach as based on determining the mass of
carbon in the most significant carbon-containing inputs entering the
plant and in the most significant carbon-containing outputs that leave
as products or byproducts (excluding, for example, iron ore, scrap,
steel).  The difference between the mass of carbon entering the facility
and leaving the facility is assumed to be converted to CO2.  The annual
mass rates of significant inputs and outputs are determined from company
records, and their carbon contents are based on typical or default
values.  The commenters noted that the AISI approach provides a single
estimate of the combined total CO2 emissions from all processes and
combustion sources at the facility.  The commenters claimed that the
approach would provide a more accurate and complete accounting of
facility-wide emissions at a much lower cost than that of the proposed
EPA process-specific methods.

Response:  As we explained at proposal (74 FR 16517), we considered the
many domestic and international monitoring guidelines and protocols for
process and combustion sources at iron and steel production facilities,
including the AISI facility-wide approach.  The vast majority of these
guidelines and protocols are process-specific rather than facility-wide
approaches (e.g., 2006 IPCC Guidelines, U.S. Inventory, the World
Business Council for Sustainable Development (WBCSD)/WRI GHG protocol,
DOE 1605(b), TCR, European Union Emissions Trading System, and
Environment Canada’s mandatory reporting guidelines).  In addition,
the “higher tier” (more accurate) site-specific methods use
process-specific approaches.  We explained at proposal (74 FR 16517)
that we did not choose to propose these approaches based on the use of
default values in general (such as the AISI approach) because the use of
default values and lack of direct measurements results in a very high
level of uncertainty (greater than ±25 percent), and default approaches
would not provide site-specific estimates of emissions that reflect
differences in feedstocks, operating conditions, fuel combustion
efficiency, variability in fuels, and other differences among
facilities.

We also stated at proposal that we decided not to finalize the proposal
using methodologies that relied on default emission factors or default
values for carbon content of materials because the differences among
facilities described above could not be discerned, such default
approaches are inherently inaccurate for site-specific determinations,
and the use of default values is more appropriate for sector wide or
national total estimates from aggregated activity data than for
determining emissions from a specific facility.

We further note here that the AISI approach is not adequate for our
reporting needs because it provides only a single emissions number
aggregated from the numerous individual processes and combustion units
at the iron and steel facility.  In contrast, the approaches we are
promulgating today for determining CO2 emissions provide information at
the process level and distinguish between combustion emissions and
process emissions.  Information at the process level is needed for many
reasons, such as verification of the reported emissions from comparison
with known ranges expected from various types of processes for a given
production rate and emissions verification based on data for different
plants for similar processes.  Process-level reporting also provides
information that will be useful in identifying processes that that have
reduced emissions over time and processes at specific plants that have
the most potential for future reductions in emissions.  In addition, the
process-level reporting may provide information that can be used to
improve methodologies for specific processes under future programs and
to identify processes that may use a technology that could be the basis
for an emission standard at a later time.

We developed estimates of costs for the proposed options for determining
CO2 emissions and concluded that the costs were reasonable.  However, as
explained below, we have revised the proposed options in response to
comments, and these revisions significantly reduce the burden and costs
of the carbon mass balance and site-specific emission factor methods
while maintaining a similar level of accuracy.

Comment:  Several commenters claimed that the proposed carbon mass
balance method is unnecessarily burdensome because it requires weekly
sampling, monthly analyses, and determining the monthly mass quantities
of all process inputs and outputs.  The commenters suggested that EPA
allow the use of default values for carbon content, neglect streams that
have very little or no carbon, drop the requirement for analysis by an
“independent certified laboratory,” and allow the use of analyses
from suppliers.  One commenter recommended sampling and analysis for
carbon content no more frequently than annually.  The commenters stated
that lime, dolomite and slag contain no appreciable carbon and do not
need to be tracked, and that it is not necessary to account for the
carbon in scrap that is charged to the furnace or in the steel product
because they offset each other.  One commenter noted that “independent
certified laboratory” is not defined or explained, and another claimed
that it is an unnecessary complication and expense because these carbon
analyses are typically done in an in-house laboratory.

One commenter stated that the carbon mass balance equations were
incomplete because they did not account for carbon removed by pollution
control devices.  Another commenter recommended that EPA use default
carbon contents for different grades of steel scrap and noted that
because companies already track the chemical content of each grade of
scrap, highly accurate carbon calculations could be made with minimal
additional burden.

Response:  We received several useful suggestions for improving the
carbon mass balance method without significantly decreasing the accuracy
in the estimates.  After a close review of the sampling and analysis
requirements and comparing them to the requirements applied to other
source categories in other subparts of this reporting rule, we concluded
that the weekly sampling and monthly analysis of carbon content could be
reduced in frequency to an annual analysis of all inputs and outputs at
each facility.  We also revised the rule to allow the use of carbon
content analyses from the material supplier, which is consistent with
what is required in other subparts using the carbon balance method.
Carbon content does not vary widely at a given facility for the
significant process inputs and outputs that contain carbon, and we
continue to account for variations due to changes in production rate,
which is likely a more significant source of variability.  We continue
to choose not to use default values for the reasons given in the
previous comment response, and we have determined that an annual
analysis of carbon content to provide plant-specific values is not
burdensome because facilities already perform many such analyses.  We
agree that the analysis does not have to be performed by an independent
certified laboratory, especially since we specify the analytical
procedures that must be used by any laboratory, and we note that
in-house laboratories may have more applicable experience in analyses of
their particular process inputs and outputs.

We agree with the suggestion to evaluate carbon content by the grade or
type of ferrous material charged to the furnace, and we incorporated a
provision to calculate an average carbon content of ferrous materials
charged based on the average weight percent of each type that is used.
In addition, we have corrected the equations as suggested to account for
carbon in the residue collected by emission control equipment.  Finally,
we agree that inputs and outputs that contain no carbon or an
insignificant amount (i.e., contributing to less than one percent of the
carbon in or out) do not need to be tracked in the carbon balance
method.

Comment:  Several commenters claimed that the site-specific emission
factor method is not a viable option as proposed and should be
streamlined to:  (1) eliminate annual re-testing, (2) reduce the test
length from 9nine hours (or from 9nine production cycles for batch
processes), (3) clarify that a separate test is not required for each
grade of steel, and (4) remove the requirement to operate at 90 percent
of capacity.  One commenter stated that the most frequent re-testing
currently required in operating permits is once every 2.5 years rather
than annually.  Another commenter noted that 9nine production cycles for
certain small specialty steel producers would require 27 hours of
testing for each grade of steel because each production cycle is 3three
hours.  Commenters stated that testing at 90 percent of production is
problematic and is beyond their control because it is dictated by
upstream and downstream production levels as well as economic
conditions.  In addition, capacity is difficult to determine because
steelmaking furnaces do not have a nameplate capacity since it is
determined by the iron production rate, how fast downstream processes
(such as the caster) operate, process inputs, and product specifications
that may require different operating cycle times.

One commenter questioned the value of the requirement to re-test if the
carbon content of feed materials changes by more than 10 percent because
this type of change could occur on a daily or weekly basis when the
grade of steel being produced changes.  Another commenter noted that EPA
did not define what constituted a significant change in fuel type or mix
and recommended that the provision be changed to 20 percent to allow for
environmentally beneficial process improvements.  Two commenters stated
that the 10 percent threshold for re-testing is infeasible for
steelmaking and sinter processes because of routine changes in the type
of steel produced and the types of materials recycled to the sinter
plant.  The commenters requested that they be permitted to develop
separate emission factors based on various modes that represent
different operating scenarios or product categories.  The commenters
also recommended that EPA eliminate the 10 percent change threshold for
re-testing and require that testing be conducted under conditions that
are representative of normal operation.  One commenter noted that the
rule did not address how a site-specific emission factor would be
developed when emissions from the EAF and argon-oxygen decarburization
vessel are combined and routed to a single emission control device and
stack.

Response:  We further reviewed the testing requirement in other rules
and those in operating permits and found that typical requirements (such
as test requirements for particulate matter) include 3 one-hour runs or
production cycles for representative testing of process emissions.
Consequently, we are revising the testing requirements to 3three hours
or 3three production cycles.  We also agree with the commenters who
noted that different routine operating modes may result in different
levels of CO2 emissions, and it is necessary to develop separate
emission factors for these different operating conditions.
Consequently, we have dropped the 10 percent re-testing threshold and
instead require that separate emission factors be developed for each of
different routine operating conditions that result in a change in CO2
emissions by 20 percent or more.

We disagree that annual re-testing is excessive because testing for CO2
emissions is much simpler and less costly than sampling for hazardous
pollutants or for particulate matter, and annual sampling is consistent
with our requirement for annual reporting.  We agree that it is not
necessary or always possible to test while operating at 90 percent of
capacity for the reasons identified by the commenters.  Instead, we are
requiring that the test be performed based on representative
performance, i.e., under normal operating conditions.  We have revised
the rule to clarify and provide options for testing when emissions from
the EAF and argon-oxygen decarburization vessel are combined.

Comment:  Several commenters asked EPA to clarify that CH4 and N2O
emissions do not have to be reported for iron and steel production
processes, and other commenters requested that CH4 and N2O emissions
reporting not be required for the combustion of coke oven gas and blast
furnace gas.  Commenters noted that default emission factors for CO2,
CH4, and N2O were not provided in the tables in 40 CFR part 98, subpart
C, and in the absence of such emission factors, asked if they would be
required to test for these minor emissions.

Response:  We have clarified that 40 CFR part 98, subpart Q does not
require reporting of CH4 and N2O emissions from the iron and steel
production processes because we expect these emissions (if any) to be
very low, and we have no protocols for calculating them.  However,
emission factors are available in the 2006 IPCC guidelines for
combustion sources, including the combustion of coke oven gas and blast
furnace gas.  We have added the IPCC default emission factors for CO2
and N2O for these process gases to the tables in 40 CFR part 98, subpart
C, and we developed new emission factors for CH4 based on the typical
CH4 content of coke oven gas (28 percent) and blast furnace gas (0.2
percent).

R.  Lead Production

1.  Summary of the Final Rule

Source Category Definition.  The lead production source category
consists of primary lead smelters and secondary lead smelters.  A
primary lead smelter is a facility engaged in the production of lead
metal from lead sulfide ore concentrates through the use of
pyrometallurgical techniques (smelting).  A secondary lead smelter is a
facility at which lead-bearing scrap materials (including but not
limited to lead-acid batteries) are recycled by smelting into elemental
lead or lead alloys.

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

GHGs to Report.  For lead production, report the following emissions:

CO2 process emissions from each smelting furnace used for lead
production.

CO2 combustincombustion emissions from each smelting furnace used for
lead production.

N2O and CH4 emissions from each smelting furnace under 40 CFR part 98,
subpart C (General Stationary Fuel Combustion Sources) using the
methodologies in subpart C.

CO2, N2O, and CH4 emissions from each on-site stationary combustion unit
other than smelting furnaces under 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).

In addition, report GHG emissions for any other source categories at the
facility for which calculation methods are provided in other subparts of
the rule, as applicable.

GHG Emissions Calculation and Monitoring.  To calculate annual process
CO2 emissions from an affected smelting furnace, the reporter must use
the following methods, as applicable to the affected smelting furnace.

For each affected smelting furnace with certain types of CEMS in place,