documented in the annual GHG emissions report (see 40 CFR 98.3(c)(6)).
    This revision will allow sources to discontinue using Tier 2 or 3
and begin reporting their 2010 emissions under Tier 4 as of the date on
which all required certification tests are passed. Data recorded during
the certification test period for a CEMS can also be used for Part 98
reporting, provided that: All required certification tests are passed
in sequence, with no test failures; and no unscheduled maintenance or
repair of the CEMS is required during the test period.
    We are also amending 40 CFR 98.33(b)(5) by adding a new paragraph,
(b)(5)(iii), to address situations where the owner or operator of an
affected unit that has been using Tier 1, 2, or 3 to calculate
CO2 mass emissions makes a change that triggers Tier 4
applicability by changing: The primary fuel, the manner of unit
operation, or the installed continuous monitoring equipment. In such
cases, the owner or operator will be required to begin using Tier 4 no
later than 180 days from the date on which the change is implemented.
This allows adequate time for the owner or operator to obtain and/or
certify any of the required Tier 4 continuous monitors.
    Methane and nitrous oxide calculations. Today's amendments remove
the term ``normal operation'' from 40 CFR 98.33(c)(4)(i) and
(c)(4)(ii). Therefore, calculation of CH4 and N2O
emissions is simply required for each Table C-2 fuel combusted in the
unit during the reporting year.
    We are also further amending 40 CFR 98.33(c)(4)(ii), to allow
additional reporting flexibility for certain units that combust more
than one type of fuel; specifically, for units that report heat input
data to EPA year-round using part 75 CEMS. Under the final amendments
to 40 CFR 98.33(c)(4)(ii), 40 CFR part 75 units that use the worst-case
F-factor reporting option can attribute 100 percent of the unit's
annual heat input to the fuel with the highest F-factor, as though it
were the only fuel combusted during the report year.
    For Tier 4 units, the requirement to use the best available
information to determine the annual heat input from each type of fuel
is being retained in 40 CFR 98.33(c)(4)(i), but we are also now
allowing it under 40 CFR 98.33(c)(4)(ii)(D) as an alternative for part
75 units, in cases where fuel-specific heat input values cannot be
determined solely from the part 75 electronic data reports.
    Carbon dioxide emissions from sorbent. We are amending 40 CFR
98.33(d) to make it more generally applicable to different types of
CO2-producing sorbents. The term ``R'' is redefined as the
number of moles of CO2 released upon capture of one mole of
acid gas. When the sorbent is CaCO3, the

value of R is 1.00. For other CO2-producing sorbents, a
specific value of R is determined by the reporting facility from the
chemical formula of the sorbent and the chemical reaction with the acid
gas species that is being removed.
    Biogenic CO2 emissions from biomass combustion.
    The title and introductory text of 40 CFR 98.33(e) are being
amended to more precisely define the requirements for reporting
biogenic CO2 emissions. In general, biogenic CO2
emissions reporting is required only for the combustion of the biomass
fuels listed in Table C-1 and for municipal solid waste (which consists
partly of biomass and partly of fossil fuel derivatives).
    We are also amending 40 CFR 98.33(e) to describe three cases in
which reporters may not need to report biogenic CO2
emissions separate from total CO2 emissions, for units that
combust biomass:
    1. If a biomass fuel is not listed in Table C-1 and is combusted in
a unit that is not required to use Tier 4, a reporter is not required
to separately report the biogenic CO2 emissions from
combustion of that fuel unless:

--The fuel is combusted in a large unit (greater than 250 mmBtu/hr heat
input capacity).
--The biomass fuel accounts for 10 percent or more of the annual heat
input to the unit.

    In that case, according to 40 CFR 98.33(b)(3)(iii), Tier 3 must be
used to determine the carbon content of the biomass fuel and to
calculate the biogenic CO2 emissions.
    2. If a unit is subject to subpart C or D and uses the
CO2 mass emissions calculation methodologies in 40 CFR part
75 to satisfy the Part 98 reporting requirements, the reporter has the
option to report biogenic CO2 emissions for the 2010
reporting year, but is required to report them thereafter.
    3. For the combustion of tires, which are also partly biogenic
(typically about 20 percent biomass, for car and truck tires), the
reporter has the option, but not the requirement, to separately report
the biogenic CO2 emissions, by following the applicable
provisions in 40 CFR 98.33(e).
    No comments were received on the proposal to make biogenic
CO2 emissions reporting optional for the combustion of
tires, and the proposal has been finalized without modification.
However, tire-derived fuel has a biomass component, and perhaps it
should be treated in the same manner as MSW, which is also partly
biogenic. A number of units that are subject to Part 98 combust tires
as the primary fuel or as a secondary fuel. Therefore, we are
considering whether these units should be required to account for their
biogenic CO2 emissions. However, before making this
mandatory we intend to open it to notice and comment in a future
rulemaking.
    We are amending 40 CFR 98.33(e)(1) by removing the restriction
against using Tier 1 to calculate biogenic CO2 emissions on
units that use CEMS to measure the total CO2 mass emissions.
However, the use of Tier 1 is not allowed for calculating biogenic
CO2 emissions for combustion of MSW, as originally specified
in 40 CFR 98.33(e)(1) of subpart C, and is also not allowed for the
combustion of tires, if biogenic CO2 emissions are
calculated for tires.
    We are amending the methodology in 40 CFR 98.33(e)(2), which is
specifically for units using a CEMS to measure CO2 mass
emissions, by limiting it to cases where the CO2 emissions
measured by the CEMS are solely from combustion, i.e., the stack gas
contains no additional process CO2 or CO2 from
sorbent; and prohibiting its use if the unit combusts MSW or tires.
    For sources that combust MSW, we are amending 40 CFR 98.33(e)(3) to
require, except as provided below, the quarterly use of ASTM methods
D7459-08 and D6866-08, as described in 40 CFR 98.34(d), when any MSW is
combusted either as the primary fuel or as the only fuel with a
biogenic component. We are also amending 40 CFR 98.33(e)(3) to allow
the ASTM methods to be used, as described in 40 CFR 98.34(e), for any
unit in which biogenic (or partly biogenic) fuels, and non-biogenic
fuels are combusted, in any proportions.
    In response to comments, we have added an alternative calculation
methodology for biogenic CO2 emissions from the combustion
of MSW and/or tires, which may be used when the total contribution of
these fuels to the unit's heat input is 10 percent or less. If a unit
combusts both MSW and tires and the reporter exercises the option not
to separately report biogenic CO2 emissions from the tires,
the alternative calculation methodology may still be used for the MSW,
provided that the contribution of MSW to the unit's total heat input
does not exceed 10 percent. The methodology may also be used for small,
batch incinerators that burn no more than 1,000 tons of MSW per year.
    Units that qualify for and elect to use the alternative methodology
will use Tier 1 to calculate the total annual CO2 emissions
from the combustion of the MSW or tires, and multiply the result by an
appropriate default factor that represents the biomass fraction of the
fuel, to obtain an estimate of the annual biogenic CO2
emissions. Based on additional background research conducted, we have
concluded that reasonable default factors are 0.20 for tires and 0.60
for MSW (please refer to the Background Technical Support Document--
Revision of Certain Provisions).
    We are also amending 40 CFR 98.33(e) to delete and reserve 40 CFR
98.33(e)(4) and the related subparagraphs. Although 40 CFR 98.33(e)(4)
allowed the ASTM methods to be used to determine biogenic
CO2 emissions for various combinations of biogenic and
fossil fuels, we are deleting and reserving that paragraph because the
paragraph also included an unnecessary restriction, i.e., it only
applied to units that use CEMS to measure total CO2 mass
emissions. The amendments to 40 CFR 98.33(e)(3) described above will
achieve the same intended purpose as paragraph (e)(4), without imposing
this restriction, so paragraph (e)(4) is no longer needed.
    We are amending 40 CFR 98.33(e)(5) so that it also applies to units
that are using Tier 2 (Equation C-2a), as well as Tier 1 (Equation C-
1), for calculating biogenic CO2 mass emissions. The
approach in 40 CFR 98.33(e)(5) for estimating solid biomass fuel
consumption is equally applicable to units using those two equations to
calculate biogenic CO2 emissions. Equation C-2a applies when
HHV data for a biomass fuel are available at the minimum frequency
specified in 40 CFR 98.34(a)(2).
    Finally, one commenter asked EPA to allow Part 75 units to
calculate biogenic CO2 emissions using the same general
approach that is used in 40 CFR 98.33(c)(4)(ii) for the CH4
and N2O emissions calculations. This requires a heat input-
based equation similar to Equation C-10 to be added to the rule. We
find this request to be reasonable and have added a new paragraph,
(e)(6), to 40 CFR 98.33(e). Paragraph (e)(6) provides the required
equation, i.e., Equation C-15a. In cases where (HI)A, the
fraction of unit heat input from combustion of the biomass fuel, cannot
be determined from the information in Part 75 electronic data reports
(e.g., for units that measure the total CO2 emissions with
CEMS, if the ``worst-case'' F-factor option is used, or if biomass and
fossil fuels with identical F-factors are combusted), facilities must
use the ``best available information'' (as described in 40 CFR
98.33(c)(4)(ii)(C) and (c)(4)(ii)(D)) to determine (HI)A.

    Fuel sampling for coal and fuel oil. We are amending 40 CFR
98.34(a)(2), to clarify the frequency at which the HHV needs to be
determined for different types of fuels.
    First, we are amending 40 CFR 98.34(a)(2)(ii) to expand the list of
fuels for which sampling of each fuel lot is sufficient to include
other solid or liquid fuels that are delivered in lots.
    Second, we are amending the definition of the term ``fuel lot'' in
40 CFR 98.34(a)(2)(ii), as it pertains to facilities that receive
multiple deliveries of a particular type of fuel from the same supply
source each month, either by truck, rail, or pipeline. The amendment
clarifies that a fuel lot consists of all of the deliveries of that
fuel for a given calendar month. Thus, for these facilities, the
required HHV sampling has to be no more frequent than once per month.
We did receive requests to clarify the meaning of the terms ``type of
fuel'' and ``supply source,'' pertaining to the proposal to require
only one monthly sample to represent multiple fuel deliveries. The
final rule clarifies that for coal, the type of fuel refers to the coal
rank (i.e., anthracite, bituminous, sub-bituminous, or lignite). For
fuel oil, the type of fuel refers to the grade number or classification
of the oil (e.g., No. 2 oil, No. 6 oil, jet-A fuel, etc.). The term
``supply source'' is not so easily defined. For the reasons set forth
in the Response to Comments (Section II.G.2 of this preamble), we have
chosen not to include a definition of ``supply source'' in the final
rule.
    Third, we are adding parallel language to 40 CFR 98.34(b)(3)(ii),
the Tier 3 fuel sampling provisions for coal and fuel oil, for
consistency with the revisions to 40 CFR 98.34(a)(2)(ii).
    Finally, we are amending 40 CFR 98.34(a)(2)(ii) and 40 CFR
98.34(b)(3)(ii) to allow manual oil samples to be taken after each
addition of oil to the storage tank. Daily manual sampling, flow-
proportional sampling, and continuous drip sampling are also allowed.
The final rule requires at least one sample to be obtained from each
storage tank that is currently in service, and whenever oil is added,
for as long as the tank remains in service. If multiple additions
(e.g., from multiple deliveries) are made on a given day, taking one
sample after the final addition is sufficient. No sampling is required
for addition of fuel to a tank that is out of service. Rather, a sample
must be taken when the tank is brought into service and whenever oil is
added to the tank, for as long as the tank remains in service. If the
daily manual sampling option is implemented, sampling from a particular
tank is required only on those days when oil from that tank is
combusted in the unit(s).
    Tier 3 sampling frequency for gaseous fuels.
    We are amending 40 CFR 98.34(b)(3)(ii)(E) to clarify that daily
sampling of gaseous fuels other than natural gas and biogas for carbon
content and molecular weight is only required where continuous, on-line
equipment is in place; weekly sampling is required in all other cases.
    GHG emissions from blended fuel combustion. One of the most
frequently asked questions by the regulated community since publication
of the October 30, 2009 final Part 98 is, ``How does one calculate
CO2 mass emissions from the combustion of blended fuels?''
Subpart C provided only limited guidance on this issue. We are now
finalizing amendments to 40 CFR 98.34(a)(3), (b)(1)(vi), and (b)(3)(v)
to clarify reporting requirements for calculating emissions from
blended fuels. The amendments make a clear distinction between cases
where the mass or volume of each fuel in the blend is accurately
measured prior to mixing (e.g., using individual flow meters for each
component) and cases where the exact composition of the blend is not
known. In the former case, the fact that the fuels are blended is of no
consequence; because the exact quantity of each fuel in the blend is
known, the CO2 emissions from combustion of each component
must be calculated separately. In the latter case, the blend is
considered to be a distinct ``fuel type,'' and the reporter must
measure its mass or volume and essential properties (e.g., HHV, carbon
content, etc.) at a prescribed frequency.
    When the mass or volume of each individual component of a blend is
not precisely known prior to mixing, the appropriate method used to
calculate the CO2 mass emissions from combustion of the
blend is as follows. For smaller combustion units (heat input capacity
not more than 250 mmBtu/hr), Tier 2 (or possibly Tier 1) can be used
when all components of the blend are listed in Table C-1 of subpart C.
In order to perform these CO2 emissions calculations for the
blend, a reasonable estimate of the percentage composition of the blend
would be required, using the best available information (e.g., from the
typical or expected range of values of each component). A heat-weighted
CO2 emission factor must be calculated, using new Equation
C-16. For Tier 1 applications, a heat-weighted default HHV must be
determined, using new Equation C-17.
    In cases where a fuel blend consists of a mixture of fuel(s) listed
in Table C-1 and fuel(s) not listed in Table C-1, calculation of
CO2 and other GHG emissions from combustion of the blend is
required only for the Table C-1 fuel(s), using the best available
estimate of the mass or volume percentage(s) of the Table C-1 fuel(s)
in the blend. In these cases, the use of Tier 1 is required, with
modifications to certain terms in Equations C-17 and C-1, to account
for the fact that the blend is not composed entirely of Table C-1
fuels. An example calculation is provided in 40 CFR 98.34(a)(3)(iv).
    For larger combustion units (heat input capacity greater than 250
mmBtu/hr) that do not qualify to use Tier 1 or 2, the owner or operator
must use Tier 3 to calculate the CO2 mass emissions from
combustion of a blended fuel. The mathematics for Tier 3 are simpler
than for Tiers 1 and 2, since no default values are used in the
calculations, and an estimate of the percentage composition of the
blend is not required. To apply Tier 3, the only requirements are to
accurately measure the annual consumption of the blended fuel and to
determine its carbon content and (if necessary) molecular weight, at a
prescribed frequency. By considering the blended fuel to be a distinct
``fuel type,'' in cases where that fuel is not listed in Table C-1, GHG
emissions reporting is required in accordance with 40 CFR
98.33(b)(3)(iii), if the blended fuel (as opposed to each individual
component of the blend) provides at least 10 percent of the annual heat
input to a unit or group of units, and if the use of Tier 4 is not
required.
    To address the calculation of CH4 and N2O
mass emissions from the combustion of blended fuels, we are adding a
new paragraph, (c)(6), to 40 CFR 98.33. Calculation of CH4
and N2O emissions is required only for components of a blend
that are listed in Table C-2 of subpart C.
    If the mass or volume of each component of a blend is measured
before the fuels are mixed and combusted, the existing CH4
and N2O mass emissions calculation procedures in 40 CFR
98.33(c)(1) through (5) must be followed for each component separately.
The fact that the fuels are mixed prior to combustion is of no
consequence in this case.
    If the mass or volume of each individual component is not measured
prior to mixing, a reasonable estimate of the percentage composition of
the blend is required, based on the best available information, and the
procedures in 40 CFR 98.33(c)(6)(ii) will be followed. First, the
annual consumption of each

component fuel in the blend is calculated by multiplying the total
quantity of the blend combusted during the reporting year by the
estimated mass or volume percentage of that component. Next, the annual
heat input from the combustion of each component is calculated by
multiplying its annual consumption by the appropriate HHV (either the
default HHV from Table C-1 or, if available, the measured annual
average value). The annual CH4 and N2O mass
emissions for each component must then be calculated using the
applicable equation in 40 CFR 98.33(c), i.e., Equation C-8, C-9a, or C-
10. Finally, the calculated CH4 and N2O emissions
are summed across all components, and these sums are reported as the
annual CH4 and N2O mass emissions for the blend.
    Use of consensus standard methods. We are amending 40 CFR
98.33(a)(3)(iv) and (a)(3)(v) to remove reference to specific standard
methods and allow the use of standards from consensus-based
organizations or industry standard practice. We are amending 40 CFR
98.34 to remove the specific ASTM and GPA method list for fuel sampling
and analysis in 40 CFR 98.34(a)(6), to remove the list of American Gas
Association (AGA) and American Society of Mechanical Engineers (ASME)
methods for fuel meter calibration in 40 CFR 98.34(b)(4), and to delete
the list of ASTM methods to determine carbon content and molecular
weight in 40 CFR 98.34(b)(5). We are also redesignating 40 CFR
98.34(b)(5) as 40 CFR 98.34(b)(4), and amending newly designated 40 CFR
98.34(b)(4). Finally, we are amending 40 CFR 98.34(b)(1)(A) to remove
the cross-reference to the fuel flow meter test methods listed in 40
CFR 98.34(b)(4). These amendments allow the owner or operator to use
manufacturers' procedures, appropriate methods published by consensus-
based standards organizations such as ASTM, ASME, American Petroleum
Institute (API), AGA, ISO, etc.; or use industry-accepted practice. The
methods used must be documented in the monitoring plan under 40 CFR
98.3(g)(5).
    CO2 monitor span values. The Tier 4 calculation method
in 40 CFR 98.33(a)(4) requires a CO2 concentration monitor
and a stack gas flow rate monitor to measure CO2 mass
emissions. The CO2 monitor must be certified and quality-
assured according to one of the following: 40 CFR part 60, 40 CFR part
75, or an applicable State CEM program. When the part 60 option is
selected, one of the required quality assurance (QA) tests of the
CO2 monitor is a cylinder gas audit (CGA). The CGA checks
the response of the CO2 analyzer at two calibration gas
concentrations, i.e., one between 5 and 8 percent CO2 and
one between 10 and 14 percent CO2. These CO2
concentration levels are appropriate for most stationary combustion
applications. However, when CO2 emissions from an industrial
process (e.g., cement manufacturing) are combined with combustion
CO2 emissions, the resultant CO2 concentration in
the stack gas can be substantially higher than for the combustion
emissions alone. In such cases, a span value of 30 percent
CO2 (or higher) may be required.
    When the CO2 span exceeds 20 percent CO2, the
CGA concentrations specified in Part 60 only evaluate the lower portion
of the measurement scale and are no longer representative. Therefore,
we are amending 40 CFR 98.34(c) by adding a new paragraph (c)(6), which
allows the CGA of a CO2 monitor to be performed using
calibration gas concentrations of 40 to 60 percent of span and 80 to
100 percent of span, when the CO2 span value is set higher
than 20 percent CO2.
    CEMS data validation. In subpart C, 40 CFR 98.34(c) provides the
monitoring and QA requirements for Tier 4. However, no criteria for
hourly CEMS data validation were specified in the final rule. We are
adding a new paragraph, (c)(7), to 40 CFR 98.34, which requires hourly
CEMS data validation to be consistent with the sections of 40 CFR part
60 or part 75 cited in the preceding paragraph of this preamble.
Alternatively, the hourly data validation procedures in an applicable
State CEM program can be followed.
    Use of ASTM Methods D7459-08 and D6866-08. Sections 98.34(d) and
(e) of subpart C, respectively, outline procedures for quantifying
biogenic CO2 emissions for units that combust MSW and other
units that combust combinations of fossil fuels and biomass. Flue gas
samples are taken quarterly using ASTM Method D7459-08 and analyzed
using ASTM Method D6866-08. We are amending 40 CFR 98.34(d) and (e), as
discussed in the following paragraphs.
    The amendments to 40 CFR 98.34(d) require the ASTM methods to be
used when MSW is combusted in a unit, either as the primary fuel, or as
the only fuel with a biogenic component, unless the unit qualifies for
the alternative Tier 1 calculation methodology described above, under
``Biogenic CO2 emissions from biomass combustion.''
Quarterly sampling with ASTM Method D7459-08 is required for a minimum
of 24 cumulative hours of sampling per quarter, except as provided
below.
    We are amending 40 CFR 98.34(e) to remove the restriction limiting
the use of ASTM Methods D7459-08 and D6866-08 to units with CEMS.
Rather, any unit that combusts combinations of fossil and biogenic
fuels (or partly biogenic fuels, such as tires), in any proportions, is
allowed to determine biogenic CO2 emissions using the ASTM
methods on a quarterly basis. At least 24 cumulative hours of sampling
per quarter are required, except as provided immediately below.
    We are adding an option to 40 CFR 98.34(d) and (e), allowing
sources to demonstrate that 8 hours of sampling per quarter is
sufficient. The demonstration requires a minimum of two 8-hour tests
and one 24-hour test, performed under normal, stable operating
conditions. The demonstration tests must be distinct, i.e., no
overlapping of the 8-hour and 24-hour test periods is permitted. If the
average biogenic fraction obtained from the 8-hour tests is within
5 percent of the results from the 24-hour test, then, in
subsequent quarters, the Method D7459-08 sampling time may be reduced
to 8 hours. The results of the demonstration must be documented in the
monitoring plan.
    We are also amending 40 CFR 98.34(d) by adding an alternative to
allow the owner or operator to collect an integrated sample by
extracting a small amount of flue gas (1 to 5 cubic centimeters (cc))
during every unit operating hour in the quarter, in order to obtain a
more representative sample for analysis.
    Procedures for estimating missing data. We are amending 40 CFR
98.35(a) to clarify that the missing data procedures in 40 CFR part 75
are only to be followed by units that are in the Acid Rain Program and
those that monitor and report emissions and heat input data year round.
Units that only monitor and report during the ozone season must follow
the missing data procedures in 40 CFR 98.35(b).
    Electronic data reporting and recordkeeping. We are amending the
data element lists in 40 CFR 98.36 by adding a number of essential data
elements and eliminating or modifying others. The most significant
revisions to the data element lists are summarized in the following
paragraphs. We are also adding an alternative reporting option to 40
CFR 98.36(c) to reduce the reporting burden for certain facilities.
    We are adding the reporting of methodology start and end dates in
several places throughout 40 CFR 98.36(b), (c), and (d).
    We are amending the data element lists in 40 CFR 98.36 to be
consistent

with respect to reporting of emissions by fuel type and reporting of
biogenic CO2 emissions. Specifically, for clarity and
consistency with the changes to 40 CFR 98.3(c), we have modified the
amendments to 40 CFR 98.36(d)(1)(ii), (d)(1)(ix), (d)(2)(ii)(I), and
(d)(2)(iii)(I) from the proposal. These sections state that for units
subject to 40 CFR part 75, reporting of biogenic CO2
emissions is optional only for the 2010 reporting year. Reporting of
these emissions becomes mandatory starting with the 2011 reporting
year.
    We are removing 40 CFR 98.36(b)(10) to remove the requirement to
report the customer meter number for units that combust natural gas.
    We are finalizing requirements in 40 CFR 98.36(c)(1)(ii) that only
the maximum rated heat input capacity of the largest unit in a group
must be reported. We are also finalizing requirements for 98.36(c)(3)
in a similar manner, for groups of units served by a common pipe.
    We are amending 40 CFR 98.36 to remove the requirement to report
the combined annual GHG emissions from fossil fuel combustion in metric
tons of CO2e (i.e., the sum of the CO2,
CH4, and N2O emissions) by removing 40 CFR
98.36(b)(9), (c)(1)(ix), (c)(2)(viii), and (c)(3)(viii). These data
elements were duplicative of requirements in subpart A.
    We are amending 40 CFR 98.36(b), (c), and (d) to require reporting
the fuel-specific annual heat input estimates, for the purpose of
verifying the reported CH4 and N2O emissions.
Also, we are amending 40 CFR 98.36(e)(2)(iv) to require reporting of
the annual average HHV when measured HHV data are used to calculate
CH4 and N2O emissions for a Tier 3 unit, in lieu
of using a default HHV from Table C-1.
    We are amending 40 CFR 98.36(b) and (d) to make the data elements
reported under Tiers 1 through 4 consistent for the reporting of
biogenic CO2 emissions and CO2 from fossil fuel
combustion. Also, as previously noted in Section II.C of this preamble,
the amendments to 40 CFR 98.36(d) state that reporting of biogenic
CO2 emissions is optional only for the 2010 reporting year
for units using the CO2 mass emissions calculation methods
in 40 CFR part 75.
    For units that use the Tier 4 methodology to calculate
CO2 mass emissions, we are amending 40 CFR 98.36(b)(7)(i)
and (b)(7)(ii) (redesignated as 40 CFR 98.36(b)(9)(i) and (b)(9)(ii),
respectively) and 40 CFR 98.36(c)(2)(vi) (redesignated as 40 CFR 98.36
(c)(2)(viii)). The amendments to these sections require the annual
``non-biogenic'' CO2 mass emissions to be reported instead
of reporting the annual CO2 mass emissions from fossil fuel
combustion.
    We are adding a new alternative reporting option, under 40 CFR
98.36(c)(4). This new option applies to specific situations where a
common liquid or gaseous fuel supply is shared between large combustion
units such as boilers or combustion turbines (including Acid Rain
Program units and other combustion units that use the methods in 40 CFR
part 75 to calculate CO2 mass emissions), and small
combustion sources such as space heaters, hot water heaters, etc. In
such cases, a source can simplify reporting by attributing all of the
GHG emissions from combustion of the shared fuel to the large
combustion unit(s), provided that:
     The total quantity of the shared fuel supply that is
combusted during the report year is measured, either at the ``gate'' to
the facility or at a point inside the facility, using a fuel flow
meter, a billing meter or tank drop measurements; and
     On an annual basis, at least 95 percent of the shared fuel
supply (by mass or volume) is burned in the large combustion unit(s)
and the remainder of the fuel is fed to the small combustion sources.
    Company records can be used to determine the percentage
distribution of the shared fuel to the large and small units.
Facilities using this reporting option are required to document in
their monitoring plan which units share the common fuel supply and the
method used to determine that the reporting option applies. For the
small combustion sources, a description of the type(s) and approximate
number of units involved is sufficient.
    Finally, we are amending 40 CFR 98.36(e)(2)(iii) to simplify the
recordkeeping requirements in cases where the results of fuel analyses
for HHV are provided by the fuel supplier. Parallel language is added
in a new paragraph, 40 CFR 98.36(e)(2)(v)(E), for the results of carbon
content and molecular weight analyses received from the fuel supplier.
In both cases, the owner or operator is required to keep records of
only the dates on which the fuel sampling results are received, rather
than keeping records of the dates on which the supplier's fuel samples
were taken (which may not be readily available).
    Common stack reporting option. Section 98.36(c)(2) of subpart C
allows subpart C stationary fuel combustion units that share a common
stack or duct to use the Tier 4 Calculation Methodology to monitor and
report the combined CO2 mass emissions at the common stack
or duct, in lieu of monitoring each unit individually. However, 40 CFR
98.36(c)(2) does not address circumstances where at least one of the
units sharing the common stack is not a subpart C stationary fuel
combustion unit, but is subject to another subpart of 40 CFR part 98.
In view of this, we are amending 40 CFR 98.36(c)(2) by extending the
applicability of the common stack monitoring and reporting option to
situations where off-gases from multiple process units or mixtures of
combustion products and process off-gases are combined together and
vented through a common stack or duct.
    The amendments to 40 CFR 98.36(c)(2) apply not only to ordinary
common stack or duct situations where the gas streams from multiple
units are combined together, but also apply when combustion and/or
process off-gas streams from a single unit (e.g., from a kiln, furnace,
petrochemical process unit, or smelter) are routed to a stack. To
accommodate this variation on the concept of a common stack, 40 CFR
98.36(c)(2)(ii) is amended to require sources to report ``1'' as the
``Number of units sharing the common stack or duct'' where combustion
and/or process emissions from a single unit are vented through the same
stack or duct.
    Finally, since the concept of maximum rated heat input capacity may
not be applicable to certain types of process or manufacturing units,
we are amending 40 CFR 98.36(c)(2)(iii), to require that the ``combined
maximum rated heat input capacity of the units sharing the common stack
or duct'' only be reported when all of the units sharing the common
stack or duct are stationary fuel combustion units.
    Common fuel supply pipe reporting option. Section 98.36(c)(3) of
subpart C allows units that are served by a common fuel supply pipe to
report the combined CO2 emissions from all of the units in
lieu of reporting CO2 emissions separately from each unit.
To use this reporting option, the total amount of fuel combusted in the
units must be accurately measured with a flow meter calibrated
according to the requirements in 40 CFR 98.34. Section 98.36(c)(3) also
states that the applicable tier to use for this reporting option is
based on the maximum rated heat input of the largest unit in the group.
    We are amending 40 CFR 98.36(c)(3) as follows. First, the erroneous
citation of ``Sec.  98.34(a)'' is corrected to read ``Sec.  98.34(b).''
Second, we are amending the requirement in 40 CFR 98.36(c)(3) to
calibrate the fuel flow meter to the accuracy required by 40 CFR
98.34(b)

(which cross-references the accuracy specifications in 40 CFR 98.3(i)),
so that this calibration requirement applies only when Tier 3 is the
required tier for calculating CO2 mass emissions. This is
consistent with the final amendments to 40 CFR 98.3(i), where we
clarify that the equipment used to generate company records under Tier
1 and 2 is not required to meet the calibration accuracy specifications
of 40 CFR 98.3(i).
    The applicable measurement tier for the common pipe option,
according to subpart C, is based on the rated heat input capacity of
the largest unit in the group. On the surface, this appears to mean
that the use of Tiers 1 and 2 is restricted to common pipe
configurations where the highest rated heat input capacity of any unit
is 250 mmBtu/hr or less, and that Tier 3 is required if any unit has a
maximum rated heat input capacity greater than 250 mmBtu/hr. In
general, this is true. However, there is one exception in the current
rule and we are amending the rule to add a second one. Section
98.33(b)(2)(ii) of the current rule allows the use of Tier 2 instead of
Tier 3 for the combustion of natural gas and/or distillate oil in a
unit with a rated heat input capacity greater than 250 mmBtu/hr.
Today's rule adds a new paragraph, (b)(1)(v), to 40 CFR 98.33, allowing
Tier 1 to be used when natural gas consumption is determined from
billing records, and fuel usage on those records is expressed in units
of therms or mmBtu. Therefore, we are also amending 40 CFR 98.36(c)(3)
to reflect these two exceptions for common pipe configurations that
include a unit with a maximum rated heat input capacity greater than
250 mmBtu/hr.
    Finally, we are amending the provision in 40 CFR 98.36(c)(3)
regarding the partial diversion of a fuel stream such as natural gas
that is measured ``at the gate'' to a facility (e.g., using a
calibrated flow meter or a gas billing meter). Subpart C specifies that
when part of a fuel stream is diverted to a chemical or industrial
process where it is used but not combusted, and the remainder of the
fuel is sent to a group of combustion units, you may subtract the
diverted portion of the fuel stream from the total quantity of the fuel
measured at the gate before applying the common pipe methodology to the
combustion units. We are amending the rule to expand this provision to
include cases where the diverted portion of the fuel stream is sent
either to a flare or to another stationary combustion unit (or units)
on site, including units that use 40 CFR part 75 methodologies to
calculate annual CO2 mass emissions (e.g., Acid Rain Program
units). Provided that the GHG emissions from the flare and/or other
combustion unit(s) are properly accounted for according to the
applicable subpart(s) of Part 98, you are allowed to subtract the
diverted portion of the fuel stream from the total quantity of the fuel
measured at the gate, and then apply the common pipe reporting option
to the group of combustion units served by the common pipe, using the
Tier 1, Tier 2, or Tier 3 calculation methodology (as applicable).
    Table C-1. Table C-1 of subpart C provides default HHV values and
default CO2 emission factors for various types of fuel. We
are finalizing several amendments to Table C-1; specifically, we have:
     Replaced the categories ``fossil fuel-derived fuels
(solid)'' and ``fossil fuel-derived fuels (gaseous)'' with more
inclusive terms, i.e., ``other fuels (solid)'' and ``other fuels
(gaseous).'' The ``other fuels (solid)'' category includes four fuels:
plastics, municipal solid waste, tires, and petroleum coke. The ``other
fuels (gaseous)'' category includes blast furnace gas, coke oven gas,
propane gas, and fuel gas.
     Removed the word ``pipeline'' from the description of
natural gas.
     Retained the following fuels: ``wood residuals,''
``agricultural by-products,'' and ``solid by-products'', and added
definitions of these terms to 40 CFR 98.6 (see section II.F of this
preamble for further discussion).
     Added ``Used oil'' to the list of petroleum products, and
added a definition to 40 CFR 98.6 (see section II.F of this preamble
for further discussion).
     Removed ``still gas'' from the list of petroleum products
and added ``fuel gas.''
     Corrected a typographic error in the HHV for ethane;
changing it to 0.069 mmBtu/gal, rather than 0.096 mmBtu/gal.
     Revised footnote 1 regarding municipal waste combustor
(MWC) units to make it clear that only MWC units that produce steam are
prohibited from using the default HHV for MSW in Table C-1; MWC units
that produce steam can still use the default CO2 emission
factor for MSW.
     Modified footnote 1 to Table C-1, to reflect the new
biogenic CO2 emissions calculation options for certain units
that combust MSW and/or tires.
     Revised footnote 2 to clarify that if the conditions in 40
CFR 98.243(d)(2)(i) and (d)(2)(ii) and 40 CFR 98.252(a)(1) and (a)(2)
do not apply, reporters subject to 40 CFR 98.243(d) of subpart X or
subpart Y shall use either Tier 3 or Tier 4.
     Remove the qualifier of 100 percent for ethanol and
biodiesel.
     Added a default CO2 emission factor and a
default high heat value for petroleum-derived ethanol. These are the
same as the default values for biomass-derived ethanol.
    Table C-2. We are finalizing the proposed amendments to remove the
first iteration of Table C-2 and make minor corrections to the second
one. The amendments consist of correcting the exponents (powers-of-ten)
of several emission factors.
    Standard conditions. A number of commenters requested that, for
consistency with the rest of Part 98, we allow sources to use 60 [deg]F
as standard temperature instead of 68 [deg]F, when Equation C-5 is used
to calculate CO2 mass emissions from the combustion of
gaseous fuel. We proposed to allow this alternative for subparts X and
Y, because the refining and petrochemical industries use 60 [deg]F as
standard temperature. We have concluded that the commenters' request to
modify Equation C-5 accordingly is reasonable, and we are revising the
definition of the term ``MVC (molar volume conversion)'' in the
nomenclature of Equation C-5 (see revised 40 CFR 98.33(a)(3)(iii)). The
revised definition of MVC allows sources to use a MVC value of either
849.5 standard cubic feet per kilogram mole (scf/kg mole) for a
standard temperature of 68 [deg]F, or 836.6 scf/kg mole for a standard
temperature of 60 [deg]F. A corresponding change has been made to the
definition of ``Standard conditions'' in 40 CFR 98.6. For verification
purposes, a data element has been added at 40 CFR 98.36(e)(2)(iv)(G),
requiring sources using Equation C-5 to report which MVC value was used
in the emissions calculations.
    Miscellaneous revisions. We are amending 40 CFR 98.34(c) by adding
the citations from 40 CFR part 75 that pertain to the initial
certification of Tier 4 moisture monitoring systems. These amendments
also correct an inadvertent omission in the verification section of
subpart C, specifically, in 40 CFR 98.36(e)(2)(v)(C). That section
requires units using the Tier 3 methodology to keep records of the
method(s) used for carbon content determination. However, no mention is
made of keeping records of the method(s) used to determine the
molecular weight, which is a requirement for gaseous fuels. To correct
this inadvertent oversight, we have amended 40 CFR 98.36(e)(2)(v)(C) to
require records to be kept of the method(s) used for both carbon
content and (if applicable) molecular weight determination. Finally, we
have

corrected typographical errors in the definition of ``CC'' in the
nomenclature of Equation C-5. This equation applies to gaseous fuels,
not liquid fuels, and the units of measure for CC must be kg C per kg
of fuel, rather than kg C per gallon.
    Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
     A new equation has been added to Tier 1 to accommodate
situations in which the fuel usage information on gas billing records
is expressed in mmBtu. We have also added two new equations to 40 CFR
98.33(c) for calculating CH4 and N2O emissions
when the fuel usage information on natural gas billing records is in
units of therms or mmBtu.
     For units using the Tier 2 methodology that receive HHV
data less frequently than monthly, or, for small units (< 100 mmBtu/hr)
regardless of the HHV sampling frequency, we are allowing Equation C-2b
to be used to calculate a fuel-weighted annual average HHV, instead of
calculating the arithmetic average annual HHV.
     For consistency with other subparts, we have revised the
nomenclature of Equation C-5, to allow reporters to use a molar volume
conversion (MVC) constant referenced to a standard temperature of
either 60 [deg]F or 68 [deg]F.
     For Tier 4 applications, we are allowing site-specific
moisture default values to be based on fewer than nine Method 4 runs in
cases where moisture data from the RATA of a CEMS are used to derive
the default value and the applicable regulation allows a single
moisture run to represent two or more RATA runs.
     We have modified the approach for calculating
CO2 mass emissions from an exhaust stream diverted from a
CEMS monitored stack.
     For consistency with Subpart A, we have added language in
several places stating that for Part 75 units, separate reporting of
biogenic CO2 emissions is optional in reporting year 2010
and mandatory thereafter.
     We have added a new paragraph, (e)(6), to 40 CFR 98.33,
allowing Part 75 units to calculate biogenic CO2 emissions
using the same general approach that is used in 40 CFR 98.33(c)(4)(ii)
for the CH4 and N2O emissions calculations.
     We have added an alternative calculation methodology, for
biogenic CO2 emissions from the combustion of MSW and tires
that may be used when the total contribution of these fuels to the
unit's heat input is 10 percent or less. The methodology, which uses
the Tier 1 equation together with default biogenic percentages, may
also be used for small, batch incinerators that burn no more than 1,000
tons of MSW per year.
     We have removed the term ``consecutive'' between the words
``24'' and ``hours'', in reference to the minimum required sampling
time for determining the percentage of biogenic CO2 in flue
gas when ASTM Method D7459-08 is used, thereby allowing samples to be
collected for 24 total hours in a quarter, rather than 24 consecutive
hours. We have also added a provision allowing sources to perform
additional testing to demonstrate that sampling for 8 hours is
sufficient.
     We have added language to 40 CFR 98.34(a)(2)(ii) and
(b)(3)(ii)(B) explaining how to implement certain fuel oil sampling
options, specifically, daily manual sampling and sampling after each
addition of oil to the tank.
     To minimize unnecessary burden related to collecting
information on small units aggregated in a group and for the common
pipe configuration, we are removing and reserving 40 CFR 98.36
(c)(1)(ii), (c)(1)(iii), and (c)(3)(ii). We are no longer requiring
sources to report the number of units in, or the cumulative heat input
capacity of, an aggregated group of units or a group of units served by
a common pipe. Only the maximum rated heat input capacity of the
largest unit in the group must be reported.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional comments received can be found in the document, ``Response
to Comments: Revision to Certain Provisions of the Mandatory Reporting
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Natural gas consumption expressed in therms.
    Comment: Commenters were generally supportive of EPA's proposal to
provide equations for cases where natural gas consumption is expressed
in therms in billing records. One commenter noted that the proposed
rule failed to take into account that on some natural gas billing
records, the fuel usage is expressed in units of mmBtu. The commenter
also brought to our attention that the proposed rule did not provide
corresponding equations for calculating CH4 and
N2O emissions when the fuel usage information on gas billing
records is expressed in therms.
    Response: We agree with these comments and have made the following
adjustments to the final rule text. First, a new equation, Equation C-
1b, has been added to Tier 1 to accommodate situations in which the
fuel usage information on gas billing records is expressed in mmBtu.
Second, we have added two new equations to 40 CFR 98.33(c), i.e.,
Equations C-8a and C-8b, for calculating CH4 and
N2O emissions when the fuel usage information on natural gas
billing records is in units of therms or mmBtu.
    Site-specific stack gas moisture content values.
    Comment: Commenters were generally supportive of the proposed rule
changes related to determining the site-specific moisture default
values. Two commenters requested that we allow the site-specific
moisture default values to be based on fewer than nine Method 4 runs,
in cases where moisture data from the RATA of a CEMS are used to derive
the default value and the applicable regulation allows a single
moisture run to represent two or more RATA runs.
    Response: We believe that this is a reasonable request and have
incorporated it into the final rule.
    Determining emissions from an exhaust stream diverted from a CEMS
monitored stack.
    Comment: Commenters were supportive of the intent of the proposed
amendments, but indicated that the proposed methodology for estimating
the CO2 mass emissions from the diverted gas stream would
not be implementable at every affected facility. Specifically,
commenters took issue with EPA's assumption that the CO2
concentration in the diverted stream will be the same as the
concentration in the main stack. According to the commenters, this is
not the case, because dilution air introduced via auxiliary fans and
other equipment will lower the CO2 concentration of the side
stream.
    Response: We agree with the commenters' assessment and have
modified the proposed approach for quantifying emissions in the
diverted stream. The final rule requires annual emission testing of the
diverted gas stream to be performed at a set point that best represents
normal operation, using EPA Methods 2 and 3A and (if moisture
correction is necessary) Method 4. A CO2 mass emission rate
is calculated from the test results. If, over time, flow rate of the
diverted stream

varies little from the tested flow rate, then the annual CO2
mass emissions for the diverted stream (which must be added to the
CO2 mass emissions measured at the main stack) will be
determined simply by multiplying the CO2 mass emission rate
from the emission testing by the number of operating hours in which a
portion of the flue gas was diverted from the main flue gas exhaust
system. However, if the flow rate of the diverted stream varies
significantly over the reporting year, the owner or operator must
either perform additional stack testing or use the best available
information (e.g., fan settings and damper positions) and engineering
judgment to estimate the CO2 mass emission rate at a minimum
of two additional set points, to represent the variation across the
normal operating range. Then, the most appropriate CO2 mass
emission rate must be applied to each hour in which a portion of flue
gas is diverted from the main exhaust system. The procedures used to
determine the annual CO2 mass emissions for the diverted
stream must be documented in the monitoring plan.
    Fuel sampling for coal and fuel oil.
    Comment: Commenters were generally supportive of the proposed
amendments to 40 CFR 98.34(a)(2)(ii) and 40 CFR 98.34(b)(3)(ii)
regarding the definition of ``fuel lot.'' However, we did receive
requests to clarify the meaning of the terms ``type of fuel'' and
``supply source,'' pertaining to the proposal to require only one
monthly sample to represent multiple fuel deliveries.
    Response: The final rule clarifies that for coal, the type of fuel
refers to the coal rank (i.e., anthracite, bituminous, sub-bituminous,
or lignite). For fuel oil, the type of fuel refers to the grade number
or classification of the oil (e.g., No. 2 oil, No. 6 oil, jet-A fuel,
etc.). The term ``supply source'' is not so easily defined, however,
and we have chosen not to include a definition to the final rule.
Instead, you may use the following general guidelines. The term
``supply source'' can certainly refer to the coal mine, bulk terminal,
or refinery from which the fuel is obtained. However, it also can apply
to a fuel vendor who receives a particular type of fuel from different
locations and distributes the fuel to his customers, provided the
important properties of the fuel, such as its heating value, sulfur
content, carbon content, etc., are guaranteed to be within specified
ranges.
    Comment: With respect to the HHV sampling requirements for each
fuel lot, commenters expressed concern that the option to sample fuel
oil after each addition of fuel to the storage tank might not represent
the fuel actually being combusted. For instance, fuel may be added to
an empty or a partly full tank that is out of service. Also, for a tank
that is currently in service, due to infrequent combustion of fuel oil,
it may have been months, or even years, since oil was last added to the
tank, and it may be months or years before oil is added again.
    Response: To address these concerns, the final rule requires at
least one sample to be obtained from each storage tank that is
currently in service, and an additional sample whenever fuel is added
to the tank while it remains in service. If multiple additions are made
to an in-service tank on a given day (e.g., from multiple deliveries)
one sample taken after the final addition is sufficient. No sampling is
required for addition of fuel to a tank that is out of service. Rather,
a sample must be taken when the tank is brought into service and
whenever oil is added to the tank, for as long as the tank remains in
service.
    Tier 4 monitoring threshold for units that combust MSW.
    Comment: Commenters were generally supportive of the proposed
amendment to increase the Tier 4 monitoring threshold for combustion of
municipal solid waste from 250 to 600 tons per day. One concern was
that the amendment might not be finalized before the end of 2010;
therefore, they asked for the final rule to provide a six month
extension of the January 1, 2011 regulatory deadline for installing and
certifying CEMS. Some commenters were concerned that this proposed
change would affect the quantity of emissions reported under the
program and were, therefore, concerned about finalizing this proposed
amendment.
    Response: There is no need for the requested extension because
units at or above the 600 ton per day threshold have been on notice
since the 2009 final rule that they are required to use CEMS. The
proposed revision to the Tier 4 monitoring threshold should not have
caused them to think otherwise. For units in-between the original
threshold of 250 tons per day and the revised threshold of 600 tons per
day, an extension is unnecessary because these units can use Tier 2 for
the 2010 reporting year. We disagree with concerns that the final
amendments will impact the quantity of data reported to the program,
because the final amendments still require the same units to report GHG
emissions. The only difference is that they may be using the Tier 2
methodology instead of Tier 4.
    Biogenic CO2 emissions from biomass combustion.
    Comment: Regarding the proposed revisions to the optional biogenic
CO2 emissions calculation methodology for units with CEMS
described in 40 CFR 98.33(e)(2), one commenter recommended that we make
the methodology more flexible by modifying Equation C-13. The change to
this equation proposed by the commenter would allow the volume of
CO2 from combustion of the biomass fuel (rather than the
fossil fuel) to be calculated directly and then used in Equation C-14
to calculate the biogenic percentage of the annual CO2 mass
emissions.
    Response: EPA has not incorporated the commenter's proposed
changes. Although the proposed modification to the methodology could
work for fuels such as wood residue and bark (which have F-factors
listed in Table 1 in section 3.3.5 of 40 CFR part 75, appendix F), the
commenter appears to be unaware that we proposed to remove from 40 CFR
98.33(e)(1) the restriction prohibiting units with CEMS from using the
Tier 1 methodology to calculate biogenic CO2 emissions. As
stated above, we are finalizing that amendment as proposed. Therefore,
since both Tier 1 and the commenter's suggested methodology require
sources to quantify the amount of biomass fuel combusted, and since the
Tier 1 methodology is significantly simpler than the commenter's
proposal, there is no need to revise the calculation procedures in 40
CFR 98.33(e)(2).
    Comment: Many units and industrial processes burn relatively small
amounts of partly biogenic fuels such as tires and MSW, as
supplementary fuels. Quarterly sampling and analysis of the flue gas
using ASTM Methods D7459-08 and D6866-08 is the only available
methodology in Part 98 for quantifying biogenic CO2
emissions from these fuels. Some commenters requested relief from
reporting biogenic CO2 emissions from such fuels when they
account for less than 10 percent of a unit's heat input. Another
commenter asked EPA to either make reporting of biogenic CO2
optional or reduce the amount of required testing with the ASTM methods
to once every five years, for small batch incinerators that combust
MSW. The commenter provided data for a typical batch incinerator,
showing that in 2009, less than 400 metric tons of biogenic
CO2 were emitted from the unit.
    Response: We do not intend to grant a reporting exemption for MSW
combustion, and, for tires, although the reporting is optional at
present, we intend to revisit this issue in the future. However, we are
persuaded that the cost

of performing the ASTM methods (roughly $5,000 to $10,000 each quarter)
is unreasonably high for sources that burn very small amounts of MSW
and/or tires and emit comparatively little biogenic CO2.
Also, for sources that combust tires and wish to report biogenic
CO2, the ASTM methods are their only option. In view of
these considerations, we have added an alternative calculation
methodology for biogenic CO2 emissions from the combustion
of tires and/or MSW. The methodology is found at 40 CFR
98.33(e)(3)(iv), and may be used when the total contribution of these
fuels to the unit's heat input is 10 percent or less. We are also
allowing this methodology to be used for small batch incinerators that
burn no more than 1,000 tons of MSW per year. Supplementary information
provided by the commenter who requested reduced testing of these
incinerators indicates that the rated capacities of the units can be as
high as 1,300 lb/hr of MSW, but that in practice, since the units
operate in batch mode, a more realistic estimate of the actual,
annualized capacity of the units is somewhere between 100 and 200 lb/hr
(see EPA-HQ-OAR-2008-0508). If one of these incinerators were to
combust as much as 200 lb/hr of MSW on an annualized basis, this would
equate to approximately 875 tons of MSW per year. The total annual
CO2 emissions from the combustion of 875 tons of MSW is
estimated to be about 800 metric tons, based on the default emission
factors in Table C-1. Assuming a biogenic fraction of 0.60 for MSW, the
biogenic portion of the total annual CO2 emissions would be
480 metric tons, which is less than 2 percent of the 25,000 metric ton
applicability threshold in 40 CFR 98.2 for Part 98 facilities. Based on
the above analysis, we have concluded that it is appropriate to allow
Tier 1 to be used together with a default biogenic percentage of 0.60
to estimate the biogenic CO2 emissions from MSW combustion
in small batch incinerators, in lieu of using ASTM Methods D7459-08 and
D6866-08. To allow for some possible variation in the annualized
capacity of these units, the final rule extends the use of the
alternative calculation methodology to batch incinerators that combust
no more than 1,000 tons of MSW per year (which corresponds to about 540
tons of biogenic CO2 per year).
    Comment: With regard to the use of ASTM Methods D7459-08 and D6866-
08, two commenters from facilities that combust refuse-derived fuel
(RDF) asked us to consider shortening the sampling time to 8 hours, in
cases where the fuel is relatively homogeneous. Both commenters
submitted data comparing the results of 8-hour samples against the
results of 24-hour samples. For one source, the 8-hour sample results
were within 3.3 percent of the 24-hour results, and for the other
source the results were within 1.7 percent.
    Response: EPA agrees that under certain circumstances, it may be
appropriate to shorten the sampling time. Therefore, we are adding an
option to 40 CFR 98.34(d) and (e), allowing sources to demonstrate that
8 hours of sampling per quarter is sufficient. The demonstration
requires a minimum of two 8-hour tests and one 24-hour test, performed
under normal, stable operating conditions. The demonstration tests must
be distinct, i.e., no overlapping of the 8-hour and 24-hour test
periods is permitted. If the average biogenic fraction obtained from
the 8-hour tests is within  5 percent of the results from
the 24-hour test, then, in subsequent quarters, the Method D7459-08
sampling time may be reduced to 8 hours. The results of the
demonstration must be documented in the monitoring plan. Note that
although the data provided by the commenters showed that the 8-hour and
24-hour sample results differed by no more that 3.3 percent, we believe
that  5 percent is a more reasonable acceptance criterion.
This is because the methodology will likely be used for the combustion
of tires as well as MSW. Tire-derived fuel (TDF) has a much lower
biogenic fraction than MSW (typically about 0.20, compared to 0.60 for
MSW). An acceptance criterion lower than 5 percent for TDF combustion
would require the difference between the 8-hour and 24-hour sample
results to be less than 0.01, and would be overly stringent.
    Use of consensus standard methods.
    Comment: We received both supportive and adverse comments on the
proposed amendments to remove reference to specific consensus
standards. Commenters that objected to the proposal stated that
elimination of the lists of acceptable methods and allowing the use of
``industry standard practice'' weakens the rule. According to these
commenters, there is no way to evaluate the technical merits of an
``industry standard practice,'' and the quality of the reported GHG
emissions data could suffer as a result.
    Response: We do not agree with the objections raised by these
commenters. Subpart C covers a large range of industries, perhaps
including some that we are not even aware of yet that are significant
emitters of GHG emissions and therefore covered by the rule. In these
early years of the program, we want to ensure that the methods required
by the rule are appropriate for all facilities subject to subpart C of
the rule. Although we attempted to assemble a comprehensive list of
methods and provide appropriate alternatives in the 2009 final rule,
based on questions received we determined that it was likely that other
valid methods from these organizations and practices were overlooked.
For instance, under the 2009 final rule, even updates to the IBR
methods to reflect the latest practices would not have been acceptable
without a rulemaking. The commenters did not sufficiently justify why
opening up to industry consensus standards would compromise data
quality. In fact, the opposite could be said where more updated
versions of previously incorporated standards are now allowable.
    Further, subpart C already includes a mechanism by which we can
evaluate the methods being used by industry. Sections 98.36(e)(2)(iii)
and 98.36(e)(2)(v) require that records be kept of the methods that are
used for flow meter calibration and for HHV and carbon content
determinations, and 40 CFR 98.36(e)(4) requires sources to provide this
information to EPA within 30 days of receiving a request for it.
    We note that we have not opened all subparts more broadly to
industry consensus standards. Please see the responses to comments in
Section II.K (Hydrogen Production) and Section II.M (Petrochemical
Production) of this preamble for our response to similar comments under
these subparts.
    Electronic data reporting and recordkeeping.
    Comment: Two commenters asked us to either remove or modify the
proposed requirement to report the number of units in an aggregated
group of units. One commenter suggested that reporting would be
simplified if very small sources such as water heaters, space heaters,
lab burners, etc., were lumped together and counted as one unit. The
other commenter stated that it is burdensome to keep an accurate count
of these small domestic units at large, complex industrial facilities.
That same commenter also suggested that only units with heat input
ratings of 10 mmBtu or greater should be included in the count. A third
commenter noted that it is also difficult to report the cumulative
maximum heat input rating of a group of units, as required under 40 CFR
98.36(c)(1)(iii), when numerous small domestic units, some of which may
not have a heat input rating, are included in an aggregated group.

    Response: We believe these comments have merit. After careful
consideration, we have concluded that for verification purposes, we do
not need to know either the exact number of units in an aggregated
group or the combined maximum rated heat input of the group. The only
critical data element is the maximum rated heat input capacity of the
largest unit in the group. This information is needed to confirm that
none of the units exceeds 250 mmBtu/hr, which is the condition that
must be met to use the unit aggregation option in 40 CFR 98.36(c)(1).
Therefore, in the final rule, we are withdrawing the proposed
requirement to report the number of units in an aggregated group of
units, and are removing the requirement to report the combined maximum
rated heat input of the group. We also are withdrawing the proposed
requirement under 40 CFR 98.36(c)(3)(ii) to report the number of units
served by a common fuel pipe. The issue is the same for the common pipe
configuration as for the aggregated group of units, i.e., hundreds of
small, domestic units may be served by the common pipe. To effect these
rule changes, 40 CFR 98.36(c)(1)(ii), (c)(1)(iii), and (c)(3)(ii) have
been removed and reserved.
    Table C-1.
    Comment: Two commenters questioned the appropriateness of listing
MSW with plastics and petroleum coke. Further, they noted that
petroleum coke is listed twice in the table, first under petroleum
products and then again under ``other fuels (solid).'' According to the
commenters, petroleum coke is a petroleum derivative, and is more
appropriately listed with the other ``petroleum products.''
    Response: The category ``other fuels (solid)'' in Table C-1 is not
intended to make any policy statement about the nature of the fuels
included in the category. The fuels included in ``other fuels (solid)''
are miscellaneous fuels that do not fit into any other existing
category for the purposes of this rule. Petroleum coke was included as
a petroleum product in the 2009 final rule (74 FR 56409). However, the
HHV units of measure for petroleum products listed in Table C-1 are in
mmBtu per gallon and some reporters were confused about how to
appropriately calculate CO2 emissions from petroleum coke,
since it is actually a solid fuel, and is nominally measured in units
of short tons. By listing petroleum coke as a solid fuel with a heating
value in units of mmBtu/short ton, EPA intends to alleviate confusion
about how emissions are to be calculated for petroleum coke. However,
we also understand that some facilities report petroleum coke usage to
the Energy Information Administration (EIA) in units of equivalent
barrels of petroleum, and may prefer to report petroleum coke
consumption in units of gallons under this rule. As such, EPA is not
proposing to remove petroleum coke from the list of petroleum products
in Table C-1. The two HHVs for petroleum coke differ only in units of
measure. They will give equivalent results when CO2 mass
emissions are calculated.
    Comment: Two commenters asserted that plastics are a small
component of MSW and there is no reason why plastics should be listed
as a separate fuel in Table C-1. These commenters stated that to the
best of their knowledge, plastics are not combusted as a separate fuel
stream, and they recommended that EPA delete plastics from Table C-1.
    Two other commenters, however, stated that plastics are, in fact,
sometimes separated out from MSW as a separate stream. These commenters
provided a suggested definition of ``plastics'' and requested that we
add it to 40 CFR 98.6. The commenters also asked us to modify the
definition of MSW, to specifically exclude plastics that are recovered
from MSW, processed separately, and disposed.
    Response: As mentioned in the preamble to the August 11, 2010
proposed rule (75 FR 48764), facilities have questioned EPA as to why
plastics and waste oil, two fuels that appeared in Table C-2 of the
April 10, 2009 proposed rule, were left out of the October 30, 2009
final rule. Responding to these concerns, on August 11, 2010 we
proposed to add both fuels to Table C-1. Today's rule retains these
entries, except that waste oil has been redesignated as ``used oil.''
In view of the input received from the commenters who brought to our
attention that plastics (including such things as ``* * * bottles,
containers, bags, CD cases, sheeting, packaging, broken consumer goods,
etc. * * *'') are sometimes recovered from MSW and processed
separately, we decided not to incorporate the recommendation of the
other commenters who asked us to delete plastics from the table.
    We see no need to add a definition of plastics to 40 CFR 98.6,
since plastic materials are readily identifiable. However, to address
the commenters' chief concern, we have modified the definition of MSW
to clearly state that insofar as plastics (along with certain other
materials) are separated out from MSW, processed and disposed of, they
are not considered to be ``municipal solid waste.''
    Comment: Two commenters argued against the inclusion of default
factors for ``fuel gas'' in Table C-1. They argued that this would have
a negative impact on chemical plant fuel gas streams that were
previously exempt from Tier 3 requirements when the streams provide
less than 10 percent of the annual heat input to a unit rated greater
than 250 mmBtu/hr) because Table C-1 previously had no factors for fuel
gas. According to the commenters, the proposed inclusion of default
factors for ``fuel gas'' in Table C-1 requires monitoring and reporting
of GHG emissions from these gas streams. Both commenters suggested that
Table C-1 should include default factors for ``refinery fuel gas''
rather than ``fuel gas.'' One commenter also suggested revising the
definition of ``fuel'' and Footnote 2 associated with the default
values for fuel gas in Table C-1 to clarify that fuel gas is specific
to refineries and petrochemical plants, but excludes process off-gases
from chemical production plants.
    Response: Default values for fuel gas in Table C-1 are necessary to
allow refineries and petrochemical plants to use Tier 1 or Tier 2
methods for certain small fuel gas streams that were proposed to be
excluded from the requirement to use Tier 3 for fuel gas in subparts X
and Y. In providing these factors, we did not intend to require
chemical plants to monitor and report GHG emissions generated by the
combustion of ``fuel gas'' that were excluded from reporting
requirements in the October 30, 2009, final Part 98. Therefore, we
agree that some additional clarification of terms is needed to prevent
the fuel gas factor from requiring measurement and reporting of GHG
from the chemical plant vent gases.
    While changing the term used in Table C-1 to ``refinery fuel gas''
may have helped to clarify the intent, we do not believe, given the
definition of ``fuel gas'' in the final rule, that this would
adequately address the issue. ``Fuel gas'' as defined in the October
30, 2009, final Part 98 means ``gas generated at a petroleum refinery,
petrochemical plant, or similar industrial process unit, and that is
combusted separately or in any combination with any type of gas.'' The
inclusion of the phrase ``or similar industrial process unit'' within
the definition of fuel gas expanded the meaning of fuel gas beyond
refineries and petrochemical plants. Without specifically defining the
term ``refinery fuel gas'' we expect that the rule language would have
remained ambiguous, especially since refinery

fuel gas was still intended to apply to some petrochemical processes.
    To clarify our original intent of the proposed inclusion of default
factors for fuel gas in Table C-1, we are revising the definition of
``fuel gas'' to delete reference to other similar industrial process
units. In Part 98, the term ``fuel gas'' is intended to apply to
petroleum refineries and petrochemical plants, so this revision does
not affect other Part 98 requirements; it simply clarifies that ``fuel
gas'' and the fuel gas factors are specific to petroleum refineries and
petrochemical plants.
    The commenter suggested revising the definition of fuel to mean
``solid, liquid or gaseous combustible material, but excludes process
waste off gases from chemical production plants that are not petroleum
refineries or petrochemical plants.'' We have determined that this
change is not necessary because we have addressed the commenter's
concerns through the change in the definition of fuel gas. We are
amending Footnote 2 of Table C-1, as requested, to clarify further that
only reporters subject to 40 CFR 98.243(d) of subpart X or subpart Y
are required to use Tier 3 or Tier 4 methodologies when the specific
conditions outlined in the footnote do not exist.

H. Subpart D--Electricity Generation

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending 40 CFR 98.40(a) by adding the word ``mass'' between
the words ``CO2'' and ``emissions'' to make it clear that
subpart D applies only to units in two categories: ARP units and non-
ARP electricity generating units (EGUs) that are required to report
CO2 mass emissions data to EPA year-round.
    Optional reporting of biogenic CO2. For consistency with the
amendments to subpart C, we have revised 40 CFR 98.43 to clarify that
for subpart D units, reporting of biogenic CO2 emissions is
optional only for the 2010 reporting year, and mandatory thereafter. We
are also adding a new paragraph 40 CFR 98.43(b) indicating that
biogenic CO2 emissions must be calculated and reported by
following the applicable methods specified in 40 CFR 98.33(e). Fossil
CO2 emissions are calculated by subtracting the biogenic
CO2 mass emissions calculated according to 40 CFR 98.33(e)
from the cumulative annual CO2 mass emissions from paragraph
(a)(1) of this section.
    Data reporting requirements. Section 98.46 of subpart D specified
that the owner or operator of a subpart D unit must comply with the
data reporting requirements of 40 CFR 98.36(b) and, if applicable, 40
CFR 98.36(c)(2) or (c)(3). These section citations were incorrect.
Subpart D units all use the CO2 mass emissions calculation
methodologies in 40 CFR part 75. Therefore, the applicable data
reporting section for these units is 40 CFR 98.36(d), not 40 CFR
98.36(b), 40 CFR 98.36(c)(2), or 40 CFR 98.36(c)(3). We are amending 40
CFR 98.46 to correct this error.
    Recordkeeping. We are amending 40 CFR 98.47 to state that the
records kept under 40 CFR 75.57(h) for missing data events satisfy the
recordkeeping requirements of 40 CFR 98.3(g)(4) for those same events.
We have concluded that, as a practical matter, the missing data records
required to be kept under 40 CFR 75.57(h) are substantially equivalent
to the records required under 40 CFR 98.3(g)(4).
    Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
     Making separate reporting of biogenic emissions optional
for part 75 units in the 2010 reporting year and mandatory every year
thereafter. See sections II.C and II.G of this preamble.
     Adding a provision to subpart D to clarify how to
calculate and report biogenic CO2 emissions, referencing the
applicable methods in 40 CFR 98.33(e) and the reporting requirements in
40 CFR 98.3(c)(4) and (c)(12).
2. Summary of Comments and Responses
    No significant comments were received on the specific technical
amendments to subpart D. Comments related to the proposed separate
reporting of biogenic emissions for units subject to 40 CFR part 75 can
be found in Sections II.C and II.G of this preamble.

I. Subpart F--Aluminum Production

1. Summary of Final Amendments and Major Changes Since Proposal
    Throughout subpart F we are making corrections as needed for
typographical errors and alphanumeric sequencing. We are amending 40
CFR 98.63 to clarify that each perfluorocarbon (PFC) compound
(perfluoromethane, CF4, also called tetrafluoromethane, and
perfluoroethane, C2F6, also called
hexafluoroethane) must be quantified and reported and to clarify in 40
CFR 98.63(c) that reporters must use CEMS if the process CO2
emissions from anode consumption during electrolysis or anode baking of
prebake cells are vented through the same stack as a combustion unit
required to use CEMS. This requirement existed in the final rule,
however, the cross-reference was omitted from the introductory language
of 40 CFR 98.63(c).
    We are amending 40 CFR 98.64 to clarify the type of parameters that
must be measured in accordance with the recommendations of the EPA/IAI
Protocol for Measurement of Tetrafluoromethane (CF4) and
Hexafluoroethane (C2F6) Emissions from Primary
Aluminum Production (2008), and the frequency of monitoring for those
parameters that are not measured annually, but are instead measured on
a more or less frequent basis. We are also inserting dates into this
paragraph. In inserting these dates, we have decided to use dates in
reference to the effective date of the 2009 final rule, as opposed to
the publication date as was written in the final rule. It was
determined to be more appropriate to use the effective date of the rule
as the basis for the timing of the requirements. Therefore, we are
amending the paragraph to read ``December 31, 2010'' in place of ``one
year after publication of the rule'' and are inserting ``December 31,
2012'' in place of ``three years after publication of the rule.''
    We are amending Table F-2 to clarify that default CO2
emissions from pitch volatiles combustion are relevant only for center
work pre-bake (CWPB) and side work pre-bake (SWPB) technologies.
    We are also amending Table F-1 to spell out the acronyms for the
technologies covered by that table; i.e., CWPB, SWPB, vertical stud
S[oslash]derberg (VSS), and horizontal stud S[oslash]derberg (HSS).
    The comments received supported the proposed amendments, so the
amendments to subpart F are finalized as proposed.
2. Summary of Comments and Responses
    One comment letter was received on this subpart, and it supported
the proposed amendments. The summary and response to this comment
letter can be found in the document, ``Response to Comments: Revision
to Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).

J. Subpart G--Ammonia Manufacturing

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending subpart G to remove reporting of the waste recycle
stream or

purge, and to make subpart G conform to the amendments to the
calibration requirements in subpart A. With respect to the waste
recycle stream, we are eliminating the calculation, monitoring and
reporting of the emissions associated with the waste recycle stream or
purge currently required by Equation G-6 from 40 CFR 98.73, 98.74,
98.75, and 98.76. Carbon dioxide emissions from waste recycle stream or
purge gas used as fuel will still be accounted for accurately using
Equation G-5 in subpart G. Because total process emissions, calculated
using Equation G-5, will also account for emissions associated with use
of the purge gas as a fuel, we are amending 40 CFR 98.72(b) so that
subpart C does not apply to CO2 emissions resulting from the
use of purge gas as a fuel.
    We are clarifying in 40 CFR 98.72(a) and in the definition of
CO2 in Equation G-5 that CO2 process emissions
reported under this subpart may include CO2 that is later
consumed on site for urea production and therefore is not released to
the ambient air from the ammonia manufacturing process unit. We have
included this clarification because although the equations accurately
reflect total CO2 that is generated from the ammonia
manufacturing process, not all of that CO2 is released on
site. Rather, some of the CO2 may be used for urea
production and not be actually released to the atmosphere until use of
the urea at an off-site location.
    We are amending 40 CFR 98.74(d) to limit the flow meter calibration
accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3) to only meters
that are used to measure liquid and gaseous feedstock volumes. In
accordance with 40 CFR 98.3(i)(1), each measurement device that is not
used to measure liquid and gaseous feedstock volumes, but is used to
provide data for the GHG emissions calculations, will have to be
calibrated to an accuracy within the appropriate error range for the
specific measurement technology, based on an applicable operating
standard, such as the manufacturer's specifications.
    We are amending the definition of CO2 emissions in
Equation G-5 to indicate that the CO2 emissions estimates
under subpart G may include CO2 that is later consumed on
site for urea production and therefore not released to the atmosphere
from the ammonia manufacturing process unit. This change does not
affect the total CO2 emissions that are quantified and
reported to EPA under the calculation equations in 40 CFR 98.73.
Likewise, we are amending 40 CFR 98.76(b) to require reporting of the
CO2 from the ammonia manufacturing process unit that is then
used to produce urea and the method used to determine that quantity of
CO2 consumed.
    In addition, we are amending subpart G to correct several
typographical errors and an incorrect cross-reference to another
subpart in 40 CFR part 98. We are correcting the terms and definitions
for annual CO2 emissions arising from gaseous, liquid, and
solid fuel feedstock consumption in Equations G-1, G-2, and G-3,
respectively, in 40 CFR 98.73. We are correcting 40 CFR 98.76(a) by
changing the cross-reference from ``Sec.  98.37(e)(2)(vi)'' to ``Sec.
98.37.''
    We are amending the data reporting requirements in 40 CFR
98.76(b)(6) and (15) for consistency with the calculation procedures in
40 CFR 98.73(b)(6). We are amending 40 CFR 98.76(b)(6) to change
``petroleum coke'' to ``feedstock'' because petroleum coke is the
incorrect term, and amending 40 CFR 98.76(b)(15) to specify that the
carbon content analysis method being reported is for each month. We are
also removing 40 CFR 98.76(b)(17) for the reporting of urea produced,
if known, as well as reporting requirements in 40 CFR 98.76(c) for
total pounds of synthetic fertilizer produced and total nitrogen
contained in that fertilizer.
    No major changes have been made to the amendatory language since
proposal.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: One commenter was supportive of all proposed amendments to
subpart G. However, we received adverse comments on the proposed
amendment to remove requirements to report the total quantity of
synthetic fertilizer produced and the nitrogen content of fertilizer.
The commenter asserted that EPA does not offer a reason for the
deletion of fertilizer reporting requirements, and noted that synthetic
fertilizer application drives a large fraction of N2O
emissions from agricultural soils. They asserted that the reporting
requirements should be retained for several reasons, including that
collecting information for N2O emissions, even if it is from
less than one-half of the total fertilizer produced, is valuable.
Further, the commenter contended that justifying removal of the
reporting requirement because of the availability of other data through
the Association of American Plant Food Control Officials is not
appropriate because those other data may not be available reliably into
the future and do not map emissions back to specific facilities. They
argued that reporting of synthetic fertilizer production is a good
first step in estimating N2O emissions from agricultural
soils.
    Another commenter countered many of the points raised above,
asserting that data on domestic synthetic fertilizer production is not
a good indicator of N2O emissions from farming because the
rule did not capture all fertilizer production and not all fertilizer
is applied to fields.
    Response: EPA has finalized, as proposed, the amendment to remove
reporting requirements of the total amount of synthetic fertilizer
produced and nitrogen contained in that fertilizer. EPA has concluded
that the burden placed on fertilizer production facilities to report on
total pounds of synthetic fertilizer and total nitrogen contained in
that fertilizer would not be commensurate with the value of the data we
would receive in terms of improving our ability to estimate
N2O emissions from soils. Specifically, facility specific
data from producers on the nitrogen content of synthetic fertilizer is
of minimal value in estimating soil N2O emissions by itself.
As explained in the proposal preamble (75 FR 48767), there are a
variety of inputs that would be valuable to consider to estimate
N2O emissions from agricultural soils, including fertilizer
application rates, timing of application, and the use of slow release
fertilizers and nitrification/release inhibitors, none of which would
be provided through the provision removed from the rule. Given that the
information required from the final rule would not provide sufficient
information to estimate N2O emissions from fertilizer
application to soils, we are removing the reporting requirement at this
time. While there is concern over the potential future loss of the
Association of American Plant Food Control Officials data, EPA has
determined that it is preferable to remove the incomplete reporting
requirement at this time and, if appropriate in the future, reconsider
in a comprehensive manner reporting of information on fertilizer
production, import and use practices.

K. Subpart P--Hydrogen Production

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending the definition of the terms for the average carbon
content (CCn) and molecular weight (MWn) in
Equation P-1 of 40 CFR 98.163 to clarify that, where measurements are
taken more frequently than monthly, CCn and MWn
should be calculated using the arithmetic average of measurement values
within the month.
    We are amending 40 CFR 98.164(b)(1) so it is consistent with
today's amendments to 40 CFR 98.3(i). First, we are limiting the flow
meter calibration accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3)
to meters that are used to measure liquid and gaseous feedstock
volumes. In accordance with 40 CFR 98.3(i)(1), all other measurement
devices that are used to provide data for the GHG emissions
calculations have to be calibrated only to an accuracy within the
appropriate error range for the specific measurement technology, based
on an applicable operating standard, such as the manufacturer's
specifications. Second, we are removing the requirements for solids
weighing equipment and oil tank drop measurements to be calibrated
according to 40 CFR 98.3(i), because the provisions of 40 CFR 98.3(i)
apply only to gas and liquid flow meters. For oil tank drop
measurements, the QA requirements of 40 CFR 98.34(b)(2) apply.
    As a harmonizing amendment with the amendment allowing the use of a
gas chromatograph (described in 40 CFR 98.164(b)(5)), we are adding the
phrase ``no less frequent'' to 40 CFR 98.164(b)(2). This change
indicates that when determining the carbon content and the molecular
weight of ``other gaseous fuels and feedstocks'' (e.g., biogas,
refinery gas, or process gas), you must undertake sampling and analysis
no less frequently than weekly. Replacing a ``weekly'' requirement with
``no less frequent than weekly'' allows for the use of continuous, on-
line equipment gas chromatographs.
    We are amending 40 CFR 98.164(b)(5) to allow the use of
chromatographic analysis of the fuel, provided that the gas
chromatograph is operated, maintained, and calibrated according to the
manufacturer's instructions.
    Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
     Modification of Equation P-1 to account for measurements
taken more frequently than monthly to determine the molecular weight of
the gaseous fuel and feedstock.
     Inclusion of the option to use a gas chromatograph (both
continuous and non-continuous) for determining the carbon content and
molecular weight of gaseous fuels.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: One commenter noted that the fuels and feedstocks to a
hydrogen plant subject to subpart P requirements are often the same
fuels that are burned in combustion units subject to subpart C
requirements. The commenter further noted that both subparts had
different monitoring and QA/QC requirements which would pose a problem
for a facility trying to determine which method to use.
    Response: No change has been made as a result of this comment. We
did not receive sufficient information from the commenter as to why
they would not be able to comply using the methods already prescribed
in subpart P for determining carbon content and molecular weight. As
noted by the commenter, facilities only subject to subpart C must use a
method published by a consensus standards organization if such a method
exists, or an industry consensus standard practice. Therefore, the
methods in the 2009 final rule for subpart P could be used to meet the
requirements in subpart C. We determined that it was appropriate to
open the methods to industry consensus standards or industry standard
practices for facilities subject to subpart C only, because the
industries covered by subpart C could be wide ranging and the specific
methods listed may not be appropriate for certain industry types.
Because the commenter does not provide specific concerns as to why the
methods listed in subpart P are not appropriate, we have decided not to
remove the applicable methods listed in subpart P and replace them with
the option to use consensus based standards or industry consensus
standards.
    Comment: One commenter requested that EPA allow the use of gas
chromatographs as an alternative method for determining the carbon
content in gaseous fuels and feedstocks.
    Response: EPA acknowledges the commenter's recommendation to
include the option to use gas chromatographs for measuring the carbon
content and molecular weight of fuels and feedstocks in subpart P. As a
result, EPA has revised the monitoring and QA/QC requirements to allow
the use of gas chromatographs, both continuous and non-continuous, to
determine the carbon content and molecular weight of fuels and
feedstocks provided that the gas chromatograph is operated, maintained,
and calibrated according to the manufacturer's instructions.

L. Subpart V--Nitric Acid Production

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending 40 CFR 98.226 to remove the synthetic fertilizer
and total nitrogen reporting requirement in 40 CFR 98.226(o). The
detailed rationale for this amendment is provided in Section II.J of
this preamble.
2. Summary of Comments and Responses
    Several comments were received on the proposal to remove the
synthetic fertilizer and total nitrogen reporting requirement in 40 CFR
98.226(o). Please see section II.J (Ammonia Production) of this
preamble for the comments and responses related to reporting of
fertilizer production data.

M. Subpart X--Petrochemical Production

1. Summary of Final Amendments and Major Changes Since Proposal
    Numerous issues have been raised by owners and operators in
relation to the requirements in subpart X for petrochemical production
facilities. The issues being addressed by the amendments include the
following:
     Distillation and recycling of waste solvent.
     Process vent emissions monitored by CEMS.
     Process off-gas combustion in flares.
     CH4 and N2O emissions from
combustion of process off-gas.
     Molar volume conversion (MVC) factors.
     Methodology for small ethylene off-gas streams.
     Monitoring and QA/QC requirements.
     Reporting requirements under the CEMS compliance option.

     Reporting requirements for the ethylene-specific option.
     Reporting measurement device calibrations.
     For the mass balance option, sampling frequency when
receiving multiple deliveries from same supply source.
    Distillation and recycling of waste solvent. We are adding a new
paragraph, as proposed, to 40 CFR 98.240(g) to specify that a process
that distills or recycles waste solvent that contains a petrochemical
is not part of the petrochemical production source category.
    Process vent emissions monitored by CEMS. We are adding a sentence,
as proposed, to 40 CFR 98.242(a)(1) that specifies CO2
emissions from process vents routed to stacks that are not associated
with stationary combustion units must be reported under subpart X when
you comply with the CEMS option in 40 CFR 98.243(b).
    Process off-gas combustion in flares. We are amending 40 CFR
98.242(b), as proposed, by removing the reference to flares.
    CH4 and N2O emissions from combustion of
process off-gas. We are amending 40 CFR 98.243(b), as proposed, to
clarify that either the default HHV for fuel gas or a site-specific
calculated HHV may be used when using Tier 3 procedures to calculate
CH4 and N2O emissions from combustion units that
burn petrochemical process off-gas and are monitored with a
CO2 CEMS.
    Sampling frequency for mass balance method. We are amending 40 CFR
98.243(c)(3) to clarify that when multiple deliveries of a particular
liquid or solid feedstock are received from the same supply source in a
month, one representative sample is sufficient for the month. The
amendment is being made in response to a comment received. As explained
in section II.M.2 of this preamble, we are amending 40 CFR 98.243(c)(3)
to make the language in subpart X consistent with a similar amendment
for fuel sampling in 40 CFR 98.34(b)(3)(ii)(B). The new language does
not change the requirements in 40 CFR 98.243(c).
    Molar volume conversion (MVC) factors. We are amending Equation X-
1, as proposed, to provide two alternative values of MVC that
correspond to the two most common standard conditions output by the
flow monitors. Additionally, the reporting requirements related to this
equation are being amended, as proposed, to include reporting of the
standard temperature at which the gaseous feedstock and product volumes
were determined (either 60 [deg]F or 68 [deg]F) and to afford
verification of the reported emissions.
    Methodology for small ethylene off-gas streams. We are finalizing
amendments to 40 CFR 98.243(d), as proposed, to allow the use of Tier 1
or Tier 2 methods for small flows (in cases where a flow meter is not
already installed). Specifically, Tier 1 or Tier 2 methods may be used
for ethylene process off-gas streams that meet either of the following
conditions:
     The annual average flow rate of fuel gas (that contains
ethylene process off-gas) in the fuel gas line to the combustion unit,
prior to any split to individual burners or ports, does not exceed 345
standard cubic feet per minute (scfm) at 60 [deg]F and 14.7 pounds per
square inch absolute (psia) and a flow meter is not installed at any
point in the line supplying fuel gas or at an upstream common pipe.
     The combustion unit has a maximum rated heat input
capacity of less than 30 mm Btu/hr, and a flow meter is not installed
at any point in the line supplying fuel gas (that contains ethylene
process off-gas) or an upstream common pipe.
    As in the proposal, this amendment also specifies how to calculate
the annual average flow rate under the first condition. Specifically,
the total flow obtained from company records is to be evenly
distributed over 525,600 minutes per year. In response to comments we
are making an editorial change to the introductory paragraph of 40 CFR
98.243(d) to clarify that the common pipe reporting alternative may be
used when applicable; the intent of the requirements in this section
are not changed by this editorial change. We are also making a number
of other editorial changes to 40 CFR 98.243(d), as proposed, to
integrate the amended option with the existing requirements. Finally,
we are amending 40 CFR 98.246(d)(2) and 98.247(c), as proposed, to add
reporting and recordkeeping requirements that are related to the
amendments in 40 CFR 98.243(d)(2).
    Monitoring methods for determining carbon content and composition.
We are finalizing the proposed addition of ASTM D2593-93 (Reapproved
2009), Standard Test Method for Butadiene Purity and Hydrocarbon
Impurities by Gas Chromatography, to 40 CFR 98.244(b)(4). We are
further amending 40 CFR 98.244(b)(4), as proposed, by adding a new
paragraph that will allow the use of industry standard practice to
determine the carbon content or composition of carbon black feedstock
oils and carbon black products.
    We also added two more published methods to the list in 40 CFR
98.244(b)(4) of the final rule: ASTM D7633, Standard Test Method for
Carbon Black--Carbon Content, and EPA Method 9060A in EPA publication
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods. We also added an option, already proposed in subparts C and Y,
to use results of chromatographic analysis of feedstocks and products,
provided that the gas chromatograph is operated, maintained, and
calibrated according to the manufacturer's instructions. Finally, we
added an option to use results of a mass spectrometer analysis of a
feedstock or product, provided that the mass spectrometer is operated,
maintained, and calibrated according to the manufacturer's
instructions.
    We are also amending 40 CFR 98.244(b)(4), as proposed, to provide
facilities the option to determine carbon content or composition of
feedstocks or products using modified versions of the analytical
methods listed in 40 CFR 98.244(b)(4) if the listed methods are not
appropriate for reasons noted below. The proposed amendments in this
section would have allowed the use of ``other analytical methods'' if
methods listed in 40 CFR 98.244(b)(4) are not appropriate for any of
the same reasons. However, in response to comments, we revised this
provision to allow the use of ``other methods'' rather than ``other
analytical methods'' so that non-analytical methods also can be used.
The conditions under which the listed methods may be considered
inappropriate are the same as at proposal. Specifically, a listed
method may be considered inappropriate if the relevant compounds cannot
be detected, the quality control requirements are not technically
feasible, or use of the method will be unsafe.
    We are amending the reporting requirements in 40 CFR 98.246(a)(11),
as proposed, so that if an alternative method is used, facilities must
include in the annual report the name or title of the method used and,
the first time it is used, a copy of the method and an explanation of
why the use of the alternative method is necessary. Also as proposed,
the amendments to 40 CFR 98.244(b)(4) may be used for the 2010
reporting year.
    QA/QC requirements. To maintain consistency with the amendments to
40 CFR 98.3(i), we are amending, as proposed, the QA/QC provisions for
weighing devices, flow meters, and tank level measurement devices in 40
CFR 98.244 (b)(1), (b)(2), and (b)(3).
    Reporting requirements under the CEMS compliance option. As
proposed, we are making a number of changes in

40 CFR 98.246(b)(1) through (b)(5) to clarify the reporting
requirements under the CEMS compliance option.
    First, we are moving the requirement for reporting of the
petrochemical process ID from 40 CFR 98.246(b)(3) to 40 CFR
98.246(b)(1) to be consistent with the structure in other reporting
sections, and we are renumbering the existing paragraphs (b)(1) and
(b)(2).
    Second, we are adding a statement in the renumbered paragraph 40
CFR 98.246(b)(2) to specify that the reporting requirements in 40 CFR
98.36(b)(9)(iii) (as numbered in today's action) for CH4 and
N2O do not apply under subpart X because applicable
reporting requirements are specified in 40 CFR 98.246(b)(5).
    Third, in the renumbered 40 CFR 98.246(b)(3), we are deleting the
requirement to report information required under 40 CFR
98.36(e)(2)(vii) because the referenced section specifies recordkeeping
requirements, not reporting requirements. Note that one must still keep
the applicable records because 40 CFR 98.247(a) references 40 CFR
98.37, which in turn requires you to keep all of the applicable records
in 40 CFR 98.36(e). We are also amending the reference to 40 CFR
98.36(e)(2)(vii) to a more general reference of 40 CFR 98.36. This
makes the reporting requirements consistent with the methodology for
calculating emissions in 40 CFR 98.243(b).
    Fourth, we are amending 40 CFR 98.246(b)(4) to clarify our intent.
The first sentence in 40 CFR 98.246(b)(4) requires reporting of the
total CO2 emissions from each stack that is monitored with
CO2 CEMS; this requirement will be unchanged. We are
amending the second sentence in 40 CFR 98.246(b)(4) to clarify that for
each CEMS that monitors a combustion unit stack, you must estimate the
fraction of the total CO2 emissions that is from combustion
of the petrochemical process off-gas in the fuel gas. This estimate
will give an indication of the total petrochemical process emissions,
whereas the CEMS data alone will also include emissions from combustion
of supplemental fuel (if any).
    Finally, as proposed, we are finalizing several amendments to 40
CFR 98.246(b)(5). In general, as noted above, the requirements in this
paragraph are consistent with the requirements in 40 CFR
98.36(b)(9)(iii) (as numbered in this action). Most of the amendments
to 40 CFR 98.246(b)(5) restate requirements from 40 CFR
98.36(b)(9)(iii); for example, the amendments clarify that emissions
are to be reported in metric tons of each gas and in metric tons of
CO2e. However, because 40 CFR 98.36(b)(9)(iii) allows you to
consider petrochemical process off-gas as a part of ``fuel gas'' rather
than as a separate fuel, under 40 CFR 98.246(b)(5) you must also
estimate the fraction of total CH4 and N2O
emissions in the exhaust from each stack that is from combustion of the
petrochemical process off-gas. In addition, because 40 CFR 98.243(b)
requires you to determine CH4 and N20 emissions
using Equation C-8 in subpart C (rather than Equation C-10), the
amendments to 40 CFR 98.246(b)(5) require reporting of the HHV that you
use in Equation C-8. We are also deleting the erroneous reference to
Equation C-10 that was included in 40 CFR 98.246(b)(5).
    Reporting requirements for the ethylene-specific option. As
proposed, we are finalizing several amendments to clarify the reporting
requirements in 40 CFR 98.246(c) for the combustion-based methodology
that is available to the ethylene-specific option. First, we are adding
a requirement to report each ethylene process ID to allow
identification of the applicable process units at facilities with more
than one ethylene process unit. Second, we are making editorial changes
to clarify that you must estimate the fraction of total combustion
emissions that is due to combustion of ethylene process off-gas,
consistent with the requirements described above for combustion units
that are monitored with CEMS. Third, we are replacing the requirement
to report the ``annual quantity of each type of petrochemical produced
from each process unit'' with a requirement to report the ``annual
quantity of ethylene produced from each process unit.''
    Reporting measurement device calibrations. As proposed in 40 CFR
98.246(a)(7) we are deleting the requirement for reporting of the dates
and summarized results of calibrations of each measurement device under
the mass balance option, and we are also adding 40 CFR 98.247(b)(4) to
require retention of these records.
    Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
     Additional methods for determining carbon content or
composition of feedstocks and products were added to 40 CFR
98.244(b)(4).
     For the optional combustion method for ethylene processes,
the introductory paragraph in 40 CFR 98.243(d) was edited to require
calculation of GHG emissions from ``combustion units'' rather than from
``each combustion unit.'' This change makes it clear that the common
pipe reporting alternative specified in 40 CFR 98.36(c)(3) of subpart C
may be used when applicable, and it makes 40 CFR 98.243(d) consistent
with the reporting requirements for the ethylene process option as
specified in 40 CFR 98.246(c).
     For the mass balance option, 40 CFR 98.243(c)(3) was
revised to specify that multiple deliveries of a particular liquid or
solid feedstock in a month from the same supply source may be
considered a single feedstock lot, requiring only one representative
sample for carbon content analysis. This change makes the analysis
requirements for feedstocks consistent with the amended requirements
for fuels in 40 CFR 98.34(b)(3)(ii)(B).
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: Several commenters requested either the addition of
specific carbon content or composition measurement methods in 40 CFR
98.244(b)(4) or other changes that would increase measurement
flexibility. One commenter requested that EPA Method 9060 of SW-846 be
added to the list of methods, and that the list of methods be modified
to allow for the use of a company-specific method for measuring
acetonitrile as an alternative to using EPA Method 8015 in SW-846. One
commenter requested that ASTM D7633, Standard Test Method for Carbon
Black--Carbon Content, be added to the list of methods because it has
recently been accepted and approved by ASTM. This commenter also noted
that ASTM is currently reviewing a method for carbon content in carbon
black feedstock oils and requested addition of a statement indicating
that once this method is approved and assigned an official number by
ASTM that it is effective as of January 1, 2010. One commenter
requested that EPA remove the reference to ``analytical'' in the phrase
``other analytical methods'' in proposed 40 CFR 98.244(b)(4)(xiii)
(renumbered as paragraph (xv)(A) in the final amendments) so that the
carbon content of ethylene oxide and water solutions

could be measured using a densitometer. One commenter stated that 40
CFR 98.244(b)(4) should be expanded to allow the use of an on-line mass
spectrometer to determine the carbon content and molecular weights. One
commenter stated that requirements for gas chromatography should be
consistent across all subparts and that EPA should extend the
requirements for the use of gas chromatographs under subpart C to
subpart X. Specifically, the commenter requested that the use of gas
chromatographs be allowed, ``provided that the gas chromatograph is
operated, maintained, and calibrated according to the manufacturer's
instructions.'' One commenter noted that the proposed amendments to
subpart C added flexibility to the carbon content analysis requirements
for fuels by eliminating the list of specific methods and instead
allowing a broader array of methods (i.e., industry consensus standard
practice, method published by a consensus-based standards organization,
or results of gas chromatographic analysis). This commenter stated that
the same flexibility should be allowed for feedstock and product
analysis under subpart X.
    Response: In the preamble to the proposed amendments we indicated
that we would consider adding carbon content methods for carbon black
and carbon black feedstock oil if they were approved by ASTM before
publication of the final amendments. Because it has been approved by
ASTM, we have added Method D7633, Standard Test Method for Carbon
Black--Carbon Content, to 40 CFR 98.244(b)(4). We have not added the
requested statement regarding the method for determining carbon content
in carbon black feedstock oil because we cannot cite a specific method
without being able to incorporate it by reference, and incorporation by
reference is possible only if a copy of the method is available.
However, if this method is a current industry standard practice, its
use since January 1, 2010, is allowed by 40 CFR 98.244(b)(4)(xv) of the
final amendments.
    We have also decided to make four of the other changes suggested by
commenters. First, we have added EPA Method 9060A in SW-846 because a
commenter indicated that it is much more effective at detecting organic
compounds in a liquid waste stream than any of the listed methods.
Because none of the currently listed methods effectively detect these
compounds in the waste stream, an alternative method such as EPA Method
9060A in SW-846 would already be allowed under 40 CFR
98.244(b)(4)(xv)(A) of the final amendments. However, specifically
listing the method will make demonstrating compliance more
straightforward.
    Second, we have deleted the word ``analytical'' from the phrase
``other analytical methods'' in 40 CFR 98.244(b)(4)(xv)(A) of the final
amendments so that non-analytical methods can be used. We agree with
the commenter that this change is needed so that a densitometer can be
used to determine the carbon content in an ethylene oxide and water
solution. We also agree that a non-analytical alternative must be
available in cases where the carbon content of the solution cannot
safely be determined using any of the listed analytical methods or
modifications of them.
    Third, we have added the option from subpart C to use results from
a gas chromatograph, provided the instrument is operated, maintained,
and calibrated according to the manufacturer's instructions. This
change means there is a common option in both subparts C and X, which
we have determined is important because some materials may be a fuel in
some applications and a petrochemical feedstock in others (e.g.,
ethylene feedstocks). With this change, a facility would not have to
use two methods to determine the carbon content of the same material.
    Fourth, we have added an option to use a mass spectrometer to
determine the carbon content of a feedstock or product. Although a mass
spectrometer would more commonly be used as one type of detector to
determine the concentration of individual compounds separated in a gas
chromatograph, using a mass spectrometer alone to determine the overall
carbon content is also acceptable.
    Finally, we have decided not to delete the list of specified
methods and replace them with a general statement allowing the use of
any industry consensus standard practice or method published by a
consensus-based standards organization. We have received considerable
input from the industry on methods that are actually being used. We
conclude that the existing flexibility in the final amendments is
sufficient, and that there is no need to allow the use of other
unspecified methods. We recognize that this is not consistent with the
methodologies allowed for determining carbon content in subpart C;
however, we have concluded that this is justified given the wide
variety of industries subject to subpart C versus the more narrowly-
focused sources subject to subpart X.
    We are not specifically allowing the use of a company-specific
method for the determination of carbon content in acetonitrile because
we are not convinced that it is necessary. The commenter indicated that
they can use EPA Method 8015 of SW-846, and they have not indicated any
problems with using this method. It is also possible that their
company-specific method would qualify as a modification to a listed
method that would be allowed if any of the criteria in 40 CFR
98.244(b)(4)(xv)(A) of the final amendments are met. Therefore, we have
not made the requested change.
    Comment: One commenter requested a modification to 40 CFR
98.243(c)(3) for carbon black production processes that specifies all
deliveries of a fuel or feedstock oil in a month from the same supply
source are considered to be a fuel lot, and carbon content must be
determined for only one representative sample from the lot.
    Response: Although we did not propose amendments to the sampling
and analysis requirements in 40 CFR 98.243(c)(3), we did propose a
change similar to that suggested by the commenter in 40 CFR
98.34(b)(3)(ii)(B) of subpart C for fuels. Subpart X currently requires
you to determine the carbon content for at least one sample of each
feedstock and product per month. In addition, if you make more than one
valid carbon content measurement during the month (from separate
samples), then you must average the results arithmetically. (Note that
this language does not require sampling and analysis for each delivery
of a feedstock. Furthermore, each delivery of the same material, even
from different suppliers, is not considered to be a separate
feedstock.) However, we agree with the commenter that if multiple
deliveries of the same feedstock are received from the same supply
source, one representative sample is sufficient for the month.
Therefore, we have amended 40 CFR 98.243(c)(3) in the interest of
improving the operating flexibility of the rule. We have also broadened
the statement so that it applies for any liquid or solid feedstock.
Please see the amended rule language to 40 CFR 98.243(c)(3).
    Comment: One commenter stated that the proposed term ``each
combustion unit'' in the introductory paragraph of 40 CFR 98.243(d)
appears to preclude the use of the common pipe reporting alternative in
40 CFR 98.36(c)(3). According to the commenter, the common pipe option
is appropriate for ethylene processes, and precluding it will not
improve the quality of GHG emission estimates. Therefore, the

commenter requests that ``each combustion unit'' be changed to
``combustion units.''
    Response: We have made the suggested change in the final amendments
because we agree with the commenter's assessment of the proposed
language. We did not intend to preclude the use of the common pipe
option, as evidenced by the fact that 40 CFR 98.243(d)(2)(i) and (ii)
both specify that the determination of when Tier 1 and Tier 2
procedures may be used is to be based on whether there is an existing
flow meter either in the line to the combustion device or an upstream
common pipe. Moreover, the reporting requirements in 40 CFR
98.246(c)(2) require reporting for each stationary combustion unit, or
group of stationary sources with a common pipe.

N. Subpart Y--Petroleum Refineries

1. Summary of Final Amendments and Major Changes Since Proposal
    Numerous issues have been raised by owners and operators in
relation to the requirements in subpart Y for petroleum refineries. The
issues being addressed by the amendments include the following:
     GHG emissions from flares.
     GHG emissions to report from combustion of fuel gas.
     GHG emissions to report from non-merchant hydrogen
production process units.
     Calculating GHG emissions from fuel gas combustion.
     Calculating combustion GHG emissions from flares and
asphalt blowing operations controlled by thermal oxidizer or flare.
     Molar volume conversion factors.
     Combined stacks monitored by CEMS.
     Nitrogen concentration monitoring to determine exhaust gas
flow rate.
     Calculating CO2 emissions from catalytic
reforming units.
     Calculating GHG emissions from sulfur recovery plants.
     Calculating CO2 emissions from coke calcining
units.
     Calculating CO2 emissions from process vents.
     Monitoring and QA/QC requirements.
     Reporting requirements.
    GHG emissions from flares. We are finalizing corrections to 40 CFR
98.252(a) (GHGs to report) as proposed to clarify the required
emissions methods for flares. We are proposing to amend the second
sentence in 40 CFR 98.252(a) to correctly require reporters to
``Calculate and report the emissions from stationary combustion units
under subpart C * * *'' and we are proposing to add an additional
sentence at the end of this section to clarify that reporters must
``Calculate and report the emissions from flares under this subpart.''
    GHG emissions to report from combustion of fuel gas. We are
finalizing amendments to 40 CFR 98.252(a) as proposed to clarify that
reporting of CH4 and N2O emissions is required
for the stationary combustion units fired with fuel gas. As described
in Section II.G of this preamble, we are also amending the definition
of fuel gas.
    GHG emissions to report from non-merchant hydrogen production
process units. As proposed, we are amending 40 CFR 98.252(i) to clarify
that reporting of only CO2 emissions is required for non-
merchant hydrogen production process units.
    Calculating GHG emissions from fuel gas combustion. We are
finalizing amendments to 40 CFR 98.252(a), as proposed, so that
petroleum refineries subject to subpart Y can use the Tier 1 or 2
methodologies in subpart C for combustion of fuel gas when either of
the following conditions exists:
 The annual average fuel gas flow rate in the fuel gas line to
the combustion unit, prior to any split to individual burners or ports,
does not exceed 345 scfm at 60 [deg]F and 14.7 psia, and either of the
following conditions exists:
    --A flow meter is not installed at any point in the line supplying
fuel gas or an upstream common pipe; or
    --The fuel gas line contains only vapors from loading or unloading,
waste or wastewater handling, and remediation activities that are
combusted in a thermal oxidizer or thermal incinerator.
 The combustion unit has a maximum rated heat input capacity of
less than 30 mmBtu/hr, and either of the following conditions exists:
    --A flow meter is not installed at any point in the line supplying
fuel gas or an upstream common pipe; or
    --The fuel gas line contains only vapors from loading or unloading,
waste or wastewater handling, and remediation activities that are
combusted in a thermal oxidizer or thermal incinerator.

    Calculating combustion GHG emissions from flares and asphalt
blowing operations controlled by thermal oxidizer or flare. As
proposed, we are finalizing amendments to 40 CFR 98.253 to renumber
existing Equations Y-1 and Y-16 as Equations Y-1a and Y-16a, and adding
the more detailed Equations Y-1b and Y-16b that provide more detailed
alternative methods for calculating emissions. We are also finalizing
corresponding amendments in 40 CFR 98.256 as proposed to require
reporting of which equation was used and, if the new equations are
used, reporting of the additional equation parameters.
    Molar volume conversion factors. We are finalizing amendments to
Equations Y-1, Y-3, Y-6, Y-12, Y-18, Y-19, Y-20, and Y-23 in subpart Y
as proposed to provide two alternative values of MVC depending on the
standard conditions output by the flow monitors. For reasons outlined
in the ``Response to Comments: Revision to Certain Provisions of the
Mandatory Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-
0508), we are also finalizing a similar amendment to Equation Y-2, as a
logical outgrowth of the proposal and comments received to provide two
alternative values of MVC in this equation (if mass flow monitors are
used) depending on the standard conditions at which the higher heating
value is determined. Additionally, the reporting requirements related
to each of these equations are being amended to include reporting of
the value of MVC used to support the calculations and to allow
verification of the reported emissions.
    Combined stacks monitored by CEMS. As proposed, we are amending the
language in 40 CFR 98.253(c)(1)(ii) and also the reporting requirements
in 40 CFR 98.256(f)(6) to generalize the language to include other
CO2 emission sources, not just a CO boiler.
    Nitrogen concentration monitoring to determine exhaust gas flow
rate. As proposed, we are amending 40 CFR 98.253(c)(2)(ii) to renumber
Equation Y-7 as Equation Y-7a and to add an Equation Y-7b to provide an
alternative N2 concentration monitoring approach for
determining the exhaust gas flow rate. We are also finalizing reporting
requirements in 40 CFR 98.256(f)(9) to report the input parameters for
Equation Y-7b if it is used.
    Calculating CO2 emissions from catalytic reforming units. We are
finalizing amendments to the definition of the coke burn-off quantity,
CBQ, and the term ``n'' in Equation Y-11 in 40 CFR
98.253(e)(3) as proposed to clarify the application of Equation Y-11 to
continuously regenerated catalytic reforming units.
    Calculating GHG emissions from sulfur recovery plants. We are
amending 40 CFR 98.253(f) as proposed to add ``and for sour gas sent
off site for sulfur recovery'' to clarify that this calculation
methodology applies ``For on-site sulfur recovery plants and for sour
gas sent off site for sulfur recovery, * * *'' and to

allow non-Claus sulfur recovery plants to alternatively follow the
requirements in 40 CFR 98.253(j) for process vents. We also are
finalizing amendments to the reporting requirements in 40 CFR 98.256(h)
as proposed to include the type of sulfur recovery plant, an indication
of the method used to calculate CO2 emissions, and reporting
requirements for non-Claus sulfur recovery plants that elect to follow
the requirements in 40 CFR 98.253(j) for process vents.
    Calculating CO2 emissions from coke calcining units. We are
amending the definition of Mdust (the mass of dust collected
in the dust collection system) in Equation Y-13 in 40 CFR 98.253(g) as
proposed to clarify that dust recycled back to the coke calciner is not
included in the mass of dust collected in the dust collection system
(Mdust). We also are finalizing amendments to 40 CFR
98.256(i)(5), as proposed, to require facilities that use Equation Y-13
to indicate whether or not the collected dust is recycled to the coke
calciner.
    Calculating CO2 emissions from process vents. We are finalizing
amendments to the process vent requirements in 40 CFR 98.253(j) as
proposed to account for the additional sources that may elect to use
Equation Y-19, specifically non-Claus sulfur recovery units (as
previously described) and uncontrolled blowdown vents (inadvertently
not referenced). We are also amending the reporting requirements for
process vents in 40 CFR 98.256(l) as proposed to clarify that the
requirements apply to each process vent, and 40 CFR 98.256(l)(5) to
require an indication of the measurement or estimation method for the
volumetric flow rate and the mole fraction of the GHG in the vent.
    Finally, we are finalizing amendments to 40 CFR 98.253(n) as
proposed to delete the words ``equilibrium'' and ``product-specific''
to clarify that the true vapor phase of the loading operation system
should be used when determining whether the vapor-phase concentration
of methane is 0.5 volume percent or more.
    Monitoring and QA/QC requirements. We are finalizing amendments to
the monitoring and QA/QC requirements in subpart Y, 40 CFR 98.254 as
proposed, except as provided below. We proposed amendments to require
all gas flow meters on process vents subject to reporting under 40 CFR
98.253(j) to comply with the monitoring requirements in 40 CFR
98.254(f). However, for the reasons set forth in the Response to
Comments (Section N.2. of this preamble), we are finalizing amendments
for gas flow meters on process vents subject to reporting under 40 CFR
98.253(j) to comply with the monitoring requirements in 40 CFR
98.254(c).
    A summary of the amendments to the monitoring and QA/QC
requirements that we are finalizing as proposed is below. Paragraph (a)
of 40 CFR 98.254 is amended to include also the phrase ``sources that
use a CEMS to measure CO2 emissions according to subpart C
of this part * * *'' to separate further these sources from those that
are covered by 40 CFR 98.254(b). We also are re-wording the phrase
``follow the monitoring and QA/QC requirements in Sec.  98.34'' with
``meet the applicable monitoring and QA/QC requirements in Sec.
98.34'' to clarify that the monitors must meet the requirements for the
specific tier for which monitoring was required (Tier 3 sources will
comply with the Tier 3 requirements; Tier 4 sources will comply with
the Tier 4 requirements; etc.).
    Because the QA/QC requirements for CO2 CEMS that were
formerly included in 40 CFR 98.254(l) will be included in the amended
paragraph 40 CFR 98.254(a), we are removing 40 CFR 98.254(l).
    Paragraph (b) of 40 CFR 98.254 is amended to clarify that these
requirements apply to gas flow meters, gas composition monitors, and
heating value monitors other than those subject to 40 CFR 98.254(a). We
are correcting the reference to ``paragraphs (c) through (e)'' to
correctly reference ``paragraphs (c) through (g)'' as gas monitoring
system requirements are specified in 40 CFR 98.254(c) through (g). We
are also clarifying that the calibration requirements in 40 CFR 98.3(i)
only apply to gas flow meters and allowing recalibration of gas flow
meters biennially (every two years), at the minimum frequency specified
by the manufacturer, or at the interval specified by the industry
consensus standard practice used. Paragraph (b) of 40 CFR 98.254 is
also amended to clarify that gas composition and heating value monitors
must be recalibrated either annually, at the minimum frequency
specified by the manufacturer, or at the interval specified by the
industry consensus standard practice used.
    Paragraph (c) of 40 CFR 98.254 is amended to clarify that the flare
or sour gas flow meters must be calibrated (in addition to operated and
maintained) using either a method published by a consensus-based
standards organization (e.g., ASTM, API, etc.) or the procedures
specified by the flow meter manufacturer. The 5 percent
accuracy specification is being removed from 40 CFR 98.254(c). We are
also amending 40 CFR 98.254(c) by removing the list of methods as this
is redundant to the existing phrase, ``a method published by a
consensus-based standards organization.''
    Paragraphs (d) and (e) of 40 CFR 98.254 are amended to allow the
use of any chromatographic analysis to determine flare gas composition
and high heat value, as an alternative to the methods listed in 40 CFR