Revisions to the Mandatory Reporting of A
Greenhouse Gases (GHGs) Rule
United States
Enviranmental Protection
Final Rule: Revision of Certain Provisions of the Mandatory Reporting of Greenhouse
Gases Rule
This final rule includes revisions to certain provisions of the Mandatory Reporting of
Greenhouse Gases (GHG) ride (hereafter referred to as Part 98). The major amendments being
finalized are summarized below. Minor technical and editorial corrections are not included in
this overview. This final ride is complementary to the final rulemaking: Technical Corrections,
Clarifying and Other Amendments, published October 28, 2010. Together, these two actions
address the most significant questions raised by stakeholders during implementation of the GHG
Reporting Program.
Subpart A (General Provisions)
•	Add a threshold for local distribution companies subject to subpart NN (Suppliers of Natural Gas
and Natural Gas Liquids) to 460,000 thousand standard cubic feet or more of natural gas
delivered per year.
•	Amend the data reporting requirements to clarify that separate reporting of biogenic emissions
from units that use Part 75 C02 mass emissions calculation methodologies is optional only for the
2010 reporting year, and becomes mandatory every year thereafter.
•	Add a requirement that the designated representative include the name of the organization for
which the report is being submitted.
•	Clarify that the suppliers of industrial fluorinated GHGs are required to report in metric tons of
carbon dioxide equivalent only for fluorinated GHGs listed in Table A-l.
•	Amend the recordkeeping requirements for missing data events to remove the requirement to
maintain records of the duration of missing events and actions to prevent or minimize occurrence
in the future.
•	Amend the requirements for correction and resubmission of annual reports so that resubmission is
triggered only by a "substantive error," to provide an opportunity for the facility to demonstrate
that there is no error, and to provide an opportunity to extend the 45 day period for resubmission.
•	Revise the 5% calibration accuracy requirements for measurement devices as follows:
o Limit the 5% accuracy requirement to certain flow meters, when required by a specific
o Require other measurement devices to meet the accuracy requirements of the relevant
subpart(s), or industry consensus standards or manufacturer's accuracy specifications,
o Clarify that the 5% requirement does not apply where data are gathered from company
records or best available information, where Part 75 methodologies are implemented, or
for flow meters that are used exclusively for unit startup,
o Clarify that in the event of failed calibration, data would become invalid prospectively,
o Clarify under what circumstances assumed values for temperature and/or pressure at the
flow meter location can be used,
o Clarify that, for units and processes that operate continuously and cannot meet the
calibration deadline without disrupting normal process operations, facilities can use
company records until the next scheduled maintenance outage.
•	Allow facilities subject to subpart P (Hydrogen Production), subpart X (Petrochemical
Production) or subpart Y (Petroleum Refineries) to petition EPA to approve use of best available
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monitoring methods beyond 2010 in limited circumstances where installation of a measurement
device would require a process equipment or unit shutdown.
•	Amend certain existing definitions, including the definition of "bulk natural gas liquid," "fossil
fuel," "fuel gas," "municipal solid waste (MSW)." "natural gas" and "supplier." Propose new
definitions, including "primary fuel," "solid byproducts", "waste oil," and "wood residuals."
Subpart C (General Stationary Fuel Combustion Sources)
•	Raise the Tier 4 monitoring threshold for units combusting MSW from 250 tons of MSW per
day to 600 tons of MSW per day.
•	Allow Tier 3 units to use actual HHV data to calculate CH4 and N20 emissions.
•	Amend Table C-l, including changing the categories "fossil fuel-derived fuels (solid)" and
"fossil fuel-derived fuels (gaseous)" to "other fuels (solid)," and "other fuels (gaseous),"
respectively, removing the term "pipeline" before "natural gas," adding "used oil," "plastics,"
"solid petroleum coke" and "propane gas" and replacing "still gas" with "fuel gas."
•	Clarify that reporting of emissions from pilot lightsis not required.
•	Provide an equation for estimating C02 emissions where gas billing records are in "therms"
or "MMBtu."
•	Allow use of site-specific moisture default values for fuels for which no applicable default
moisture value is available in Part 75.
•	Add provisions so owners or operators with Tier 4 units would not have to install a CEMS on
a slipstream.
•	Clarify the calculation, monitoring and reporting requirements for C02 emissions from
biomass combustion.
•	Clarify or amend various Tier 4 monitoring requirements, including reporting of CEMS data
prior to 2011, common stack configurations, C02 span values, and CEMS data validation.
•	Provide additional guidance on the calculation of C02, CH4 and N20 emissions from blended
•	Clarify how to apply the definition of fuel lot in instances where frequent deliveries of the
same fuel may occur by truck, rail or pipeline.
•	Amend data reporting elements, including:
o Add methodology start and end dates
o Remove reporting of the customer ID number for units that combust natural gas.
o Add reporting of fuel-specific annual heat input estimates for the purposes of quantifying
CH4 and N20 emissions
o Clarify how to use common stack reporting option when one or more units are not subject
to subpart C.
o Remove individual reporting of number of units and unit ID for aggregated groups of
units, common pipe configurations, and common stack configurations.
¦ Add an alternative reporting option where small units such as space heaters share a common
liquid or gaseous fuel supply with large combustion units.
Subpart D (Electricity Generation)
•	Clarify that subpart D applies only to Acid Rain Program (ARP) units, and non-ARP electricity
generating units that are required to report C02 mass emissions data to EPA year-round.
•	Provide procedures for separately reporting biogenic C02 emissions.
•	Clarify that the recordkeeping requirements in 40 CFR 75.57(h) for missing data events satisfy
the Part 98 requirements.
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Subpart F (Aluminum Production)
•	Clarify that each perfluorocarbon compound must be quantified and reported.
•	Clarify the frequency of monitoring for parameters which are not measured annually but on a
more or less frequent basis.
Subpart G (Ammonia Production)
•	Amend subpart G to remove calculation, monitoring and reporting requirements from the
waste recycle stream or purge.
•	Clarify calibration requirements, consistent with amendments to subpart A.
•	Remove requirement to report uses of urea produced, if known.
•	Remove requirement to report the total pounds of synthetic fertilizer produced and the total
nitrogen contained in that fertilizer.
Subpart P (Hydrogen Production)
•	Ensure consistency with the amendments to subpart A on the calibration accuracy
•	Allow use of methods published by a consensus standards organization if such a method
exists, or industry consensus standard practices to determine the carbon content and
molecular weight (for gaseous fuels) of the fuel. Also provide the option to use a gas
Subpart V (Nitric Acid Production)
•	Remove requirement to report the total pounds of synthetic fertilizer produced and the total
nitrogen contained in that fertilizer.
Subpart X (Petrochemical Production)
•	Amend Equation X-l to provide two alternative values for the molar volume conversion
factor, depending on the "standard conditions" used by the monitors.
•	For the optional methodology for ethylene production processes, allow use of lower-tiered
monitoring methods for limited units that currently do not have a flow meter installed at the
combustion source or common pipe and for which either the average fuel gas flow rate in the
fuel gas line does not exceed 350 scfm or the combustion source has a heat input of less than
30 MMBtu/hr.
•	Add several methods for determining carbon content, including :
o "ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene Purity
and Hydrocarbon Impurities by Gas Chromatography/'
o EPA Method 9060A in "Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,'' EPA Publication No. SW-846, Third Edition,
o ASTM D7633 Standard Test Method for Carbon Black—Carbon Content,
o Results of chromatographic analysis,
o Results of mass spectrometer.
o Industry consensus standards for determining carbon content for carbon black
feedstock oils and products,
o Allow facilities to use alternate methods for determining feedstock and product
carbon content in instances where none of the specific methods listed are appropriate
because the relevant compounds cannot be detected, the quality control requirements
are not technically feasible, or use of the method would be unsafe.
•	Clarify calibration requirements, consistent with the amendments to subpart A.
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•	Clarify that a process that distills or recycles waste solvent that contains a petrochemical is
not part of the petrochemical production source category.
•	Clarify that C02 emissions from process vents routed to stacks that are not associated with
stationary combustion units must be reported under Subpart X under the CEMS option.
•	Clarify procedures for calculating CH4 and N20 emissions from combustion units that burn
petrochemical off-gas under the CEMS and ethylene-specific options.
•	Clarify reporting requirements under CEMS option, including clarifying that for combustion
units that burn petrochemical process off gas and other fuels, an estimate must be made based
on engineering judgment of the fraction of the total C02, CH4, and N20 emissions that is
attributable to combustion of off-gas from the petrochemical process unit.
•	Delete the requirement for reporting of the dates and summarized results of calibrations of
each measurement device under the mass balance option.
•	For the ethylene-specific option, clarify that an estimate must be made based on engineering
judgment of the fraction of the total emissions that is attributable to combustion of off-gas
from the ethylene process unit.
Subpart Y (Petroleum Refineries)
•	Amend equations to provide two alternative values for the molar volume conversion factor
depending on the "standard conditions" used by the monitors.
•	Allow use of lower-tiered methods for limited units that currently do not have a flow meter
installed at the combustion source or common pipe and for which either the average fuel gas
flow rate in the fuel gas line does not exceed 350 scfm or the combustion source has a heat
input of less than 30 MMBtu/hr.
•	Clarify calibration requirements, consistent with the proposed amendments to subpart A.
•	Amend the requirements for determining gas composition and average molecular weight to
allow use of ASTM standard D2503-92 or chromatographic analysis.
•	Revise requirements for exhaust gas flow meters used for coke burn-off by retaining portions
of 40 CFR 98.254(f)(1) and (3), as additional (rather than alternative) requirements.
•	Clarify the required emissions methods for flares.
•	Clarify that reporting of CH4 and N20 emissions is required for the stationary combustion
units fired with fuel gas.
•	Provide an additional option for facilities using Equation Y-l or Y-16 to calculate emissions
from flares or asphalt blowing operations controlled by thermal oxidizers or flares; provide an
optional modified equation that does not assume a 98% combustion efficiency for C02.
•	Clarify the requirements for estimating emissions from a combined stack where CEMS are
used, particularly for the catalytic cracking unit.
•	Add nitrogen concentration monitoring alternative for calculating the exhaust gas flow rate of
catalytic cracking units and fluid coking units. Revise the definition of the coke burn-off
quantity, CBQ, and the term ""11" in Equation Y-l 1 to clarify how to use Equation Y-l 1 for
continuously regenerated catalytic reforming units.
•	Clarify that the calculation methods in subpart Y are for both onsite and off-site sulfur
recovery plants.
•	Amend the definition of Mdust in Equation Y-l3 to account for recycled dust.
•	Allow the use of the process vent method for non-Claus sulfur recovery plants.
Subpart AA (Pulp and Paper Manufacturing)
•	Allow combustion-related emissions from chemical recovery furnaces, chemical recovery
combustion units, and pulp mill lime kilns to be estimated using Tier 1 or higher, if chosen by
the facility.
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• Remove C02 specific emission factors from Table AA-2, and instead refer to factors in Table
C-l for lime kilns.
Subpart OO (Suppliers of Industrial Greenhouse Gases)
•	Clarify that to "produce a fluorinated GHG' excludes (1) the creation of intermediates that
are created and transformed in a single process with no storage of the intermediates and (2)
the creation of fluorinated GHGs that are released or destroyed at the production facility
before the production measurement.
•	Remove the requirements to estimate and report the destruction of of flurorinated GHGs that
are not included in the mass produced because they are removed from the production process
as byproducts or other wastes.
•	Clarify that isolated intermediates that are produced and transformed at the same facility are
exempt from subpart OO monitoring, reporting, and recordkeeping requirements.
•	Allow producers, importers and exporters to exclude low-concentration fluorinated GHG
constituents of their products from the monitoring and reporting requirements.
•	Require producers to use quality-assured methods to quantify and report their production of
other fluorinated GHG constituents of their products.
•	Recast the reporting exemptions for import and export of small shipments in terms of 25
kilograms of fluorinated GHGs or N20 rather than 250 tons of C02-equivalents.
•	Clarify that the due date for the submission of the one-time report for a fluorinated GHG
production facility or importer that destroys fluorinated GHGs is March 31, 2011 or within 60
days of commencing fluorinated GHG destruction.
•	Require submission of a one-time report by March 31, 2011, that includes the concentration
of each fluorinated GHG constituent in each fluorinated GHG product.
Subpart PP (Suppliers of Carbon Dioxide)
•	Remove term "each" in §98.422, consistent with monitoring and reporting requirements that
an aggregated flow of C02 can be monitored.
•	Allow reporters to calculate the annual mass of C02 supplied in containers by using weigh
bills, scales, load cells, or loaded container volume readings as an alternative to flow meters.
•	Remove the requirement that C02 calculations must be made prior to subsequent purification,
processing, or compression.
•	Provide a "one meter" or "two meter approach" to calculate the C02 supplied to the
o "One meter"- Place the meter(s) after all diversions (segregation) of the C02 for
onsite use.
o "Two meters"- Measure C02 before the point of segregation, and measure onsite use,
with the difference being the C02 supplied to the economy. This approach is only
feasible where on-site use is the only diversion(s) from the main, captured C02
stream(s) after the main flow meter location(s).
o Require a new reporting element to indicate where the flow meter is placed.
•	Allow calculation, in addition to measurement, to determine the density of the C02 stream.
•	Amend standard conditions for this subpart to be a temperature and an absolute pressure of 60
degrees Fahrenheit and 1 atmosphere.
For More Information
This document is provided solely for informational purposes. It does not provide legal advice, have
legally binding effect, or expressly or implicitly create, expand, or limit any legal rights, obligations,
responsibilities, expectations, or benefits in regard to any person. The series of information sheets is
intended to assist reporting facilities/owners in understanding key provisions of the final rule.
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Visit EPA's Web site ( for more
information, including the proposed and final preamble and amendments for this action. Additional
information sheets on specific source categories, the schedule for training sessions, and other documents
and tools related to the GHG Reporting Program may also be found on our website. For questions on the
rule that cannot be answered through the Web site, please contact us at:
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