Document ID: EPA-HQ-OAR-2008-0508-2329
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2010-08-03T04:00Z

Subpart A—General Provisions

§98.1  Purpose and Scope.

(a)  This part establishes mandatory greenhouse gas (GHG) reporting
requirements for owners and operators of certain facilities that
directly emit GHG as well as for certain fossil fuel suppliers and
industrial GHG suppliers. For suppliers, the GHGs reported are the
quantity that would be emitted from combustion or use of the products
supplied.

(b)  Owners and operators of facilities and suppliers that are subject
to this part must follow the requirements of subpart A and all
applicable subparts of this part.  If a conflict exists between a
provision in subpart A and any other applicable subpart, the
requirements of the subparts B through PP of this part shall take
precedence.

§98.2  Who must report?

(a)  The GHG reporting requirements and related monitoring,
recordkeeping, and reporting requirements of this part apply to the
owners and operators of any facility that is located in the United
States and that meets the requirements of either paragraph (a)(1),
(a)(2), or (a)(3) of this section;  and any supplier that meets the
requirements of paragraph (a)(4) of this section:

(1)  A facility that contains any source category (as defined in
subparts C through JJ of this part) that is listed in this paragraph
(a)(1) in any calendar year starting in 2010.  For these facilities, the
annual GHG report must cover all source categories and GHGs for which
calculation methodologies are provided in subparts C through JJ of this
part.

(i)  Electricity generation (units that report CO2 emissions year-round
through 40 CFR part 75).

(ii)  Adipic acid production.

(iii)  Aluminum production. 

(iv)  Ammonia manufacturing.

(v)  Cement production.

(vi)  HCFC-22 production.

(vii)  HFC-23 destruction processes that are not collocated with a
HCFC-22 production facility and that destroy more than 2.14 metric tons
of HFC-23 per year.

(viii)  Lime manufacturing.

(ix)  Nitric acid production.

(x)  Petrochemical production.

(xi)  Petroleum refineries.

(xii)  Phosphoric acid production.

(xiii)  Silicon carbide production.

(xiv)  Soda ash production.

(xv)  Titanium dioxide production.

(xvi)  Municipal solid waste landfills that generate CH4 in amounts
equivalent to 25,000 metric tons CO2e or more per year, as determined
according to subpart HH of this part.  

(xvii)  Manure management systems with combined CH4 and N2O emissions in
amounts equivalent to 25,000 metric tons CO2e or more per year, as
determined according to subpart JJ of this part.

(2)  A facility that contains any source category (as defined in
subparts C through JJ of this part) that is listed in this paragraph
(a)(2) in any calendar year starting in 2010 and that emits 25,000
metric tons CO2e or more per year in combined emissions from stationary
fuel combustion units, miscellaneous uses of carbonate, and all source
categories that are listed in this paragraph.  For these facilities, the
annual GHG report must cover all source categories and GHGs for which
calculation methodologies are provided in subparts C through JJ of this
part.

(i)  Ferroalloy Production.

(ii)  Glass Production.

(iii)  Hydrogen Production.

(iv)  Iron and Steel Production.

(v)  Lead Production.

(vi)  Pulp and Paper Manufacturing.

(vii)  Zinc Production.

(3)  A facility that in any calendar year starting in 2010 meets all
three of the conditions listed in this paragraph (a)(3).  For these
facilities, the annual GHG report must cover emissions from stationary
fuel combustion sources only.  

(i)  The facility does not meet the requirements of  either paragraph
(a)(1) or (a)(2) of this section.

(ii)  The aggregate maximum rated heat input capacity of the stationary
fuel combustion units at the facility is 30 mmBtu/hr or greater.

(iii)  The facility emits 25,000 metric tons CO2e or more per year in
combined emissions from all stationary fuel combustion sources.

(4)  A supplier (as defined in subparts KK through PP of this part) that
provides products listed in this paragraph (a)(4) in any calendar year
starting in 2010.  For these suppliers, the annual GHG report must cover
all applicable products for which calculation methodologies are provided
in subparts KK through PP of this part.

(i)  Coal-to-liquids suppliers, as specified in this paragraph (i).

(A)  All producers of coal-to-liquid products.

(B)  Importers of an annual quantity of coal-to-liquid products that is
equivalent to 25,000 metric tons CO2e or more.

(C)  Exporters of an annual quantity of coal-to-liquid products is
equivalent to 25,000 metric tons CO2e or more.

(ii)  Petroleum product suppliers, as specified in this paragraph (ii):

(A)  All petroleum refineries that distill crude oil.

(B)  Importers of an annual quantity of petroleum products that is
equivalent to 25,000 metric tons CO2e or more.

(C)  Exporters of an annual quantity of petroleum products that is
equivalent to 25,000 metric tons CO2e or more.

(iii)  Natural gas and natural gas liquids suppliers, as specified in
this paragraph (iii): 

(A)  All natural gas fractionators.

(B)  All lLocal natural gas distribution companies that deliver 460,000
thousand standard cubic feet or more of natural gas per year.

(iv)  Industrial greenhouse gas suppliers, as specified in this
paragraph (iv):

(A)  All producers of industrial greenhouse gases.

(B)  Importers of industrial greenhouse gases with annual bulk imports
of N2O, fluorinated GHG, and CO2 that in combination are equivalent to
25,000 metric tons CO2e or more.

(C)  Exporters of industrial greenhouse gases with annual bulk exports
of N2O, fluorinated GHG, and CO2 that in combination are equivalent to
25,000 metric tons CO2e or more.

(v)  Carbon dioxide suppliers, as specified in  this paragraph (v).

(A)  All producers of CO2.

(B)  Importers of CO2 with annual bulk imports of N2O, fluorinated GHG,
and CO2 that in combination are equivalent to 25,000 metric tons CO2e or
more.

(C)  Exporters of CO2 with annual bulk exports of N2O, fluorinated GHG,
and CO2 that in combination are equivalent to 25,000 metric tons CO2e or
more.

(5)  Research and development activities are not considered to be part
of any source category defined in this part.  

(b)  To calculate GHG emissions for comparison to the 25,000 metric ton
CO2e per year emission threshold in paragraph (a)(2) of this section,
the owner or operator shall calculate annual CO2e emissions, as
described in paragraphs (b)(1) through (b)(4) of this section. 

(1)  Calculate the annual emissions of CO2, CH4, N2O,and each
fluorinated GHG in metric tons from all applicable source categories
listed in paragraph (a)(2) of this section.  The GHG emissions shall be
calculated using the calculation methodologies specified in each
applicable subpart and available company records.  Include emissions
from only those gases listed in Table A-1 of this subpart.  

(2)  For each general stationary fuel combustion unit, calculate the
annual CO2 emissions in metric tons using any of the four calculation
methodologies specified in §98.33(a).  Calculate the annual CH4 and N2O
emissions from the stationary fuel combustion sources in metric tons
using the appropriate equation in §98.33(c).  Exclude carbon dioxide
emissions from the combustion of biomass, but include emissions of CH4
and N2O from biomass combustion.  

(3)  For miscellaneous uses of carbonate, calculate the annual CO2
emissions in metric tons using the procedures specified in subpart U of
this part.

(4)  Sum the emissions estimates from paragraphs (b)(1), (b)(2), and
(b)(3) of this section for each GHG and calculate metric tons of CO2e
using Equation A-1 of this section.

 	(Eq. A-1)

Where:  

CO2e 	=	Carbon dioxide equivalent, metric tons/year.

GHGi 	=	Mass emissions of each greenhouse gas listed in Table A-1 of
this subpart, metric tons/year. 

GWPi 	=	Global warming potential for each greenhouse gas from Table A-1
of this subpart. 

n 	=	The number of greenhouse gases emitted.

(5)  For purpose of determining if an emission threshold has been
exceeded, include in the emissions calculation any CO2 that is captured
for transfer off site.

(c)  To calculate GHG emissions for comparison to the 25,000 metric ton
CO2e/year emission threshold for stationary fuel combustion under
paragraph (a)(3) of this section, calculate CO2, CH4, and N2O emissions
from each stationary fuel combustion unit by following the methods
specified in paragraph (b)(2) of this section.  Then, convert the
emissions of each GHG to metric tons CO2e per year using Equation A-1 of
this section, and sum the emissions for all units at the facility.

(d)  To calculate GHG quantities for comparison to the 25,000 metric ton
CO2 per year threshold for importers and exporters of coal-to-liquid
products under paragraph (a)(4)(i) of this section, calculate the mass
in metric tons per year of CO2 that would result from the complete
combustion or oxidation of the quantity of coal-to-liquid products that
are imported during the reporting year and that are exported during the
reporting year.  Calculate the emissions using the methodology specified
in subpart LL of this part.

(e)  To calculate GHG quantities for comparison to the 25,000 metric ton
CO2e per year threshold for importers and exporters of petroleum
products under paragraph (a)(4)(ii) of this section, calculate the mass
in metric tons per year of CO2 that would result from the complete
combustion or oxidation of the volume of petroleum products and natural
gas liquids that are imported during the reporting year and that are
exported during the reporting year.  Calculate the emissions using the
methodology specified in subpart MM of this part.

(f)  To calculate GHG quantities for comparison to the 25,000 metric ton
CO2e per year threshold under paragraph (a)(4) of this section for
importers and exporters of industrial greenhouse gases and for importers
and exporters of CO2, the owner or operator shall calculate the mass in
metric tons per year of CO2e imports and exports as described in
paragraphs (f)(1) through (f)(3) of this section.  

(1)  Calculate the mass in metric tons per year of CO2, N2O, and each
fluorinated GHG that is imported and the mass in metric tons per year of
CO2, N2O, and each fluorinated GHG that is exported during the year. 
Include only those gases listed in Table A-1 of this subpart.  

(2)  Convert the mass of each imported and each GHG exported from
paragraph (f)(1) of this section to metric tons of CO2e using Equation
A-1 of this section.

(3)  Sum the total annual metric tons of CO2e in paragraph (f)(2) of
this section for all imported GHGs.  Sum the total annual metric tons of
CO2e in paragraph (f)(2) of this section for all exported GHGs. 

(g)  If a capacity or generation reporting threshold in paragraph (a)(1)
of this section applies, the owner or operator shall review the
appropriate records and perform any necessary calculations to determine
whether the threshold has been exceeded. 

(h)  An owner or operator of a facility or supplier that does not meet
the applicability requirements of paragraph (a) of this section is not
subject to this rule.  Such owner or operator would become subject to
the rule and reporting requirements §98.3(b)(3), if a facility or
supplier exceeds the applicability requirements of paragraph (a) of this
section at a later time.  Thus, the owner or operator should reevaluate
the applicability to this part (including the revising of any relevant
emissions calculations or other calculations) whenever there is any
change that could cause a facility or supplier to meet the applicability
requirements of paragraph (a) of this section.  Such changes include but
are not limited to process modifications, increases in operating hours,
increases in production, changes in fuel or raw material use, addition
of equipment, and facility expansion. 

(i)  Except as provided in this paragraph, once a facility or supplier
is subject to the requirements of this part, the owner or operator must
continue for each year thereafter to comply with all requirements of
this part, including the requirement to submit annual GHG reports, even
if the facility or supplier does not meet the applicability requirements
in paragraph (a) of this section in a future year.

(1)  If reported emissions are less than 25,000 metric tons CO2e per
year for five consecutive years, then the owner or operator may
discontinue complying with this part provided that the owner or operator
submits a notification to the Administrator that announces the cessation
of reporting and explains the reasons for the reduction in emissions. 
The notification shall be submitted no later than March 31 of the year
immediately following the fifth consecutive year of emissions less than
25,000 tons CO2e per year.  The  owner or operator must maintain the
corresponding records required under §98.3(g) for each of the five
consecutive years and retain such records for three years following the
year that reporting was discontinued.  The owner or operator must resume
reporting if annual emissions in any future calendar year increase to
25,000 metric tons CO2e per year or more.

(2)  If reported emissions are less than 15,000 metric tons CO2e per
year for three consecutive years, then the owner or operator may
discontinue complying with this part provided that the owner or operator
submits a notification to the Administrator that announces the cessation
of reporting and explains the reasons for the reduction in emissions. 
The notification shall be submitted no later than March 31 of the year
immediately following the third consecutive year of emissions less than
15,000 tons CO2e per year.  The  owner or operator must maintain the
corresponding records required under §98.3(g) for each of the three
consecutive years and retain such records for three years following the
year that reporting was discontinued.  The owner or operator must resume
reporting if annual emissions in any future calendar year increase to
25,000 metric tons CO2e per year or more.

(3)  If the operations of a facility or supplier are changed such that
all applicable GHG-emitting processes and operations listed in
paragraphs (a)(1) through (a)(4) of this section cease to operate, then
the owner or operator is exempt from reporting in the years following
the year in which cessation of such operations occurs, provided that the
owner or operator submits a notification to the Administrator that
announces the cessation of reporting and certifies to the closure of all
GHG-emitting processes and operations.  This paragraph (i)(2) does not
apply to seasonal or other temporary cessation of operations.  This
paragraph (i)(2) does not apply to facilities with municipal solid waste
landfills.  The owner or operator must resume reporting for any future
calendar year during which any of the GHG-emitting processes or
operations resume operation.

(j)  Table A-2 of this subpart provides a conversion table for some of
the common units of measure used in part 98.

§98.3  What are the general monitoring, reporting, recordkeeping and
verification requirements of this part?

The owner or operator of a facility or supplier that is subject to the
requirements of this part must submit GHG reports to the Administrator,
as specified in this section.

(a)  General.  Except as provided in paragraph (d) of this section,
follow the procedures for emission calculation, monitoring, quality
assurance, missing data, recordkeeping, and reporting that are specified
in each relevant subpart of this part.

(b)  Schedule.  The annual GHG report must be submitted no later than
March 31 of each calendar year for GHG emissions in the previous
calendar year.

(1)  For an existing facility or supplier that began operation before
January 1, 2010, report emissions for calendar year 2010 and each
subsequent calendar year.

(2)  For a new facility or supplier that begins operation on or after
January 1, 2010, report emissions beginning with the first operating
month and ending on December 31 of that year.  Each subsequent annual
report must cover emissions for the calendar year, beginning on January
1 and ending on December 31.

(3)  For any facility or supplier that becomes subject to this rule
because of a physical or operational change that is made after January
1, 2010, report emissions for the first calendar year in which the
change occurs, beginning with the first month of the change and ending
on December 31 of that year.  For a facility or supplier that becomes
subject to this rule solely because of an increase in hours of operation
or level of production, the first month of the change is the month in
which the increased hours of operation or level of production, if
maintained for the remainder of the year, would cause the facility or
supplier to exceed the applicable threshold. Each subsequent annual
report must cover emissions for the calendar year, beginning on January
1 and ending on December 31.

(c)  Content of the annual report.  Except as provided in paragraph (d)
of this section, each annual GHG report shall contain the following
information:

(1)  Facility name or supplier name (as appropriate), facility or
supplier ID number, and physical street address of the facility or
supplier, including the city, state, and zip code.

(2)  Year and months covered by the report.

(3)  Date of submittal.

(4)  For facilities, report annual emissions of CO2, CH4, N2O, and each
fluorinated GHG (as defined in §98.6) as follows:

(i)  Annual emissions (excluding including biogenic CO2) aggregated for
all GHG from all applicable source categories in subparts C through JJ
of this part and expressed in metric tons of CO2e calculated using
Equation A-1 of this subpart.

(ii)  Annual emissions of biogenic CO2 aggregated for all applicable
source categories in subparts C through JJ of this part in metric tons. 
Units that use the methodologies in part 75 of this chapter to calculate
CO2 mass emissions are not required to separately report biogenic CO2
emissions, but may do so as an option.

(iii)  Annual emissions from each applicable source category in subparts
C through JJ of this part, expressed in metric tons of each applicable
GHG listed in this paragraph (4)(iii)(A) through (4)(iii)(E). 

(A)  Biogenic CO2. Units that use the methodologies in part 75 of this
chapter to calculate CO2 mass emissions are not required to separately
report biogenic CO2 emissions, but may do so as an option.

(B)  CO2 (excluding including biogenic CO2). 

(C)  CH4.

(D)  N2O.

(E)  Each fluorinated GHG (including those not listed in Table A-1 of
this subpart).

(iv)  Emissions and other data for individual units. processes,
activities, and operations as specified in the “Data reporting
requirements” section of each applicable subpart of this part. 

(5)  For suppliers, report annual quantities of CO2, CH4, N2O, and each
fluorinated GHG (as defined in §98.6) that would be emitted from
combustion or use of the products supplied, imported, and exported
during the year. Calculate and report quantities at the following
levels:

(i)  Total quantity of GHG aggregated for all GHG from all applicable
supply categories in subparts KK through PP of this part and expressed
in metric tons of CO2e calculated using Equation A-1 of this subpart. 
For fluorinated GHGs, calculate and report CO2e for only those
fluorinated GHGs listed in Table A-1 of this subpart. 

(ii)  Quantity of each GHG from each applicable supply category in
subparts KK through PP of this part, expressed in metric tons of each
GHG.  For fluorinated GHG, report emissions of all fluorinated GHG,
including those not listed in Table A-1 of this subpart.

(iii)  Any other data specified in the “Data reporting requirements”
section of each applicable subpart of this part. 

(6)  A written explanation, as required under §98.3(e), if you change
emission calculation methodologies during the reporting period.

(7)  A brief description of each “best available monitoring method”
used according to paragraph (d) of this section, the parameter measured
using the method, and the time period during which the “best available
monitoring method” was used.

(8)  Each data element for which a missing data procedure was used
according to the procedures of an applicable subpart and the total
number of hours in the year that a missing data procedure was used for
each data element.

(9)  A signed and dated certification statement provided by the
designated representative of the owner or operator, according to the
requirements of §98.4(e)(1).

(d)  Special provisions for reporting year 2010.

(1)  Best available monitoring methods.  During January 1, 2010 through
March 31, 2010, owners or operators may use best available monitoring
methods for any parameter (e.g., fuel use, daily carbon content of
feedstock by process line) that cannot reasonably be measured according
to the monitoring and QA/QC requirements of a relevant subpart.  The
owner or operator must use the calculation methodologies and equations
in the “Calculating GHG Emissions” sections of each relevant
subpart, but may use the best available monitoring method for any
parameter for which it is not reasonably feasible to acquire, install,
and operate a required piece of monitoring equipment by January 1, 2010.
 Starting no later than April 1, 2010, the owner or operator must
discontinue using best available methods and begin following all
applicable monitoring and QA/QC requirements of this part, except as
provided in paragraphs (d)(2) and (d)(3) of this section.  Best
available monitoring methods means any of the following methods
specified in this paragraph:

(i)  Monitoring methods currently used by the facility that do not meet
the specifications of an relevant subpart.

(ii)  Supplier data.

(iii)  Engineering calculations.

(iv)  Other company records.

(2)  Requests for extension of the use of best available monitoring
methods.  The owner or operator may submit a request to the
Administrator to use one or more best available monitoring methods
beyond March 31, 2010.

(i)  Timing of request.  The extension request must be submitted to EPA
no later than 30 days after the effective date of the GHG reporting
rule.

(ii)  Content of request.  Requests must contain the following
information:

(A)  A list of specific item of monitoring instrumentation for which the
request is being made and the locations where each piece of monitoring
instrumentation will be installed.

(B)  Identification of the specific rule requirements (by rule subpart,
section, and paragraph numbers) for which the instrumentation is needed.
 

(C)  A description of the reasons why the needed equipment could not be
obtained and installed before April 1, 2010.

(D)  If the reason for the extension is that the equipment cannot be
purchased and delivered by April 1, 2010, include supporting
documentation such as the date the monitoring equipment was ordered,
investigation of alternative suppliers and the dates by which
alternative vendors promised delivery, backorder notices or unexpected
delays, descriptions of actions taken to expedite delivery, and the
current expected date of delivery.

(E)  If the reason for the extension is that the equipment cannot be
installed without a process unit shutdown, include supporting
documentation demonstrating that it is not practicable to isolate the
equipment and install the monitoring instrument without a full process
unit shutdown.  Include the date of the most recent process unit
shutdown, the frequency of shutdowns for this process unit, and the date
of the next planned shutdown during which the monitoring equipment can
be installed.  If there has been a shutdown or if there is a planned
process unit shutdown between promulgation of this part and April 1,
2010, include a justification of why the equipment could not be obtained
and installed during that shutdown.

(F)  A description of the specific actions the facility will take to
obtain and install the equipment as soon as reasonably feasible and the
expected date by which the equipment will be installed and operating. 

(iii)  Approval Criteria.  To obtain approval, the owner or operator
must demonstrate to the Administrator’s satisfaction that it is not
reasonably feasible to acquire, install, and operate a required piece of
monitoring equipment by April 1, 2010. The use of best available methods
will not be approved beyond December 31, 2010.

(3)  Abbreviated emissions report for facilities containing only general
stationary fuel combustion sources.  In lieu of the report required by
paragraph (c) of this section, the owner or operator of an existing
facility that is in operation on January 1, 2010 and that meets the
conditions of §98.2 (a)(3) may submit an abbreviated GHG report for the
facility for GHGs emitted in 2010.  The abbreviated report must be
submitted by March 31, 2011.  An owner or operator that submits an
abbreviated report must submit a full GHG report according to the
requirements of paragraph (c) of this section beginning in calendar year
2011 2012.  The abbreviated facility report must include the following
information:

(i)  Facility name and physical street address including the city, state
and zip code.

(ii)  The year and months covered by the report.

(iii)  Date of submittal.

(iv)  Total facility GHG emissions aggregated for all stationary fuel
combustion units calculated according to any method specified in
§98.33(a) and expressed in metric tons of CO2, CH4, N2O, and CO2e.  

(v)  Any facility operating data or process information used for the GHG
emission calculations. 

(vi)  A signed and dated certification statement provided by the
designated representative of the owner or operator, according to the
requirements of paragraph (e)(1) of this section.

(e)  Emission Calculations.  In preparing the GHG  report, you must use
the calculation methodologies specified in the relevant subparts, except
as specified in paragraph (d) of this section.  For each source
category, you must use the same calculation methodology throughout a
reporting period unless you provide a written explanation of why a
change in methodology was required.      

(f)  Verification.  To verify the completeness and accuracy of reported
GHG emissions, the Administrator may review the certification statements
described in paragraphs (c)(98) and (d)(3)(vi) of this section and any
other credible evidence, in conjunction with a comprehensive review of
the GHG reports and periodic audits of selected reporting facilities. 
Nothing in this section prohibits the Administrator from using
additional information to verify the completeness and accuracy of the
reports.

(g)  Recordkeeping.  An owner or operator that is required to report
GHGs under this part must keep records as specified in this paragraph. 
Retain all required records for at least 3 years.  The records shall be
kept in an electronic or hard-copy format (as appropriate) and recorded
in a form that is suitable for expeditious inspection and review.  Upon
request by the Administrator, the records required under this section
must be made available to EPA.  Records may be retained off site if the
records are readily available for expeditious inspection and review. 
For records that are electronically generated or maintained, the
equipment or software necessary to read the records shall be made
available, or, if requested by EPA, electronic records shall be
converted to paper documents.  You must retain the following records, in
addition to those records prescribed in each applicable subpart of this
part:

(1)  A list of all units, operations, processes, and activities for
which GHG emission were calculated.

(2)  The data used to calculate the GHG emissions for each unit,
operation, process, and activity, categorized by fuel or material type. 
These data include but are not limited to the following information in
this paragraph (g)(2):

(i)  The GHG emissions calculations and methods used.

(ii)  Analytical results for the development of site-specific emissions
factors.

(iii)  The results of all required analyses for high heat value, carbon
content, and other required fuel or feedstock parameters.

(iv)  Any facility operating data or process information used for the
GHG emission calculations.

(3)  The annual GHG reports.

(4)  Missing data computations.  For each missing data event, also
retain a record of the duration cause of the event, and the corrective
actions taken to restore malfunctioning monitoring equipment, the cause
of the event, and the actions taken to prevent or minimize occurrence in
the future.

(5)  A written GHG Monitoring Plan.  

(i)  At a minimum, the GHG Monitoring Plan shall include the elements
listed in this paragraph (i).

(A)  Identification of positions of responsibility (i.e., job titles)
for collection of the emissions data.

(B)  Explanation of the processes and methods used to collect the
necessary data for the GHG calculations.

(C)  Description of the procedures and methods that are used for quality
assurance, maintenance, and repair of all continuous monitoring systems,
flow meters, and other instrumentation used to provide data for the GHGs
reported under this part.

(ii)  The GHG Monitoring Plan may rely on references to existing
corporate documents (e.g., standard operating procedures, quality
assurance programs under appendix F to 40 CFR part 60 or appendix B to
40 CFR part 75, and other documents) provided that the elements required
by paragraph (g)(5)(i) of this section are easily recognizable.

(iii)  The owner or operator shall revise the GHG Monitoring Plan as
needed to reflect changes in production processes, monitoring
instrumentation, and quality assurance procedures; or to improve
procedures for the maintenance and repair of monitoring systems to
reduce the frequency of monitoring equipment downtime.  

(iv)  Upon request by the Administrator, the owner or operator shall
make all information that is collected in conformance with the GHG
Monitoring Plan available for review during an audit.  Electronic
storage of the information in the plan is permissible, provided that the
information can be made available in hard copy upon request during an
audit.

(6)  The results of all required certification and quality assurance
tests of continuous monitoring systems, fuel flow meters, and other
instrumentation used to provide data for the GHGs reported under this
part.

(7)  Maintenance records for all continuous monitoring systems, flow
meters, and other instrumentation used to provide data for the GHGs
reported under this part.

(h)  Annual GHG report revisions.  The owner or operator shall submit a
revised report within 45 days of discovering or being notified by EPA of
errors in an annual GHG report.  The revised report must correct all
identified errors.  The owner or operator shall retain documentation for
3 years to support any revisions made to an annual GHG report. 

(1)  The owner or operator shall submit a revised annual GHG report
within 45 days of discovering that an annual GHG report that the owner
or operator previously submitted contains one or more substantive
errors.  The revised report must correct all substantive errors. 

(2)  The Administrator may notify the owner or operator in writing that
an annual GHG report previously submitted by the owner or operator
contains one or more substantive errors.  Such notification will
identify each such substantive error.  The owner or operator shall,
within 45 days of receipt of the notification, either resubmit the
report that, for each identified substantive error, corrects the
identified substantive error (in accordance with the applicable
requirements of this part) or provide information demonstrating that the
previously submitted report does not contain the identified substantive
error or that the identified error is not a substantive error. 

(3)  A substantive error is an error that impacts the quantity of GHG
emissions reported or otherwise prevents the reported data from being
validated or verified.

(4)  Notwithstanding paragraphs (h)(1) and (h)(2) of this section, upon
request by the owner or operator, the Administrator may provide
reasonable extensions of the 45-day period for submission of the revised
report or information under paragraphs (h)(1) and (h)(2) of this
section.  If the Administrator receives a request for extension of the
45-day period, by e-mail to an address prescribed by the Administrator,
at least two business days prior to the expiration of the 45-day period,
and the Administrator does not respond to the request by the end of such
period, the extension request is deemed to be automatically granted for
30 more days.  During the automatic 30-day extension, the Administrator
will determine what extension, if any, beyond the automatic extension is
reasonable and will provide any such additional extension.

(5)  The owner or operator shall retain documentation for 3 years to
support any revision made to an annual GHG report. 

(i)  Calibration and accuracy requirements.  The owner or operator of a
facility or supplier that is subject to the requirements of this part
must meet the applicable flow meter calibration and accuracy
requirements of this paragraph (i).  The accuracy specifications in this
paragraph (i) do not apply where either the use of company records (as
defined in §98.6) or the use of “best available information” is
specified in an applicable subpart of this part to quantify fuel usage
and/or other parameters.  Further, the provisions of this paragraph (i)
do not apply to stationary fuel combustion units that use the
methodologies in part 75 of this chapter to calculate CO2 mass
emissions. 

(1)  Except as otherwise provided in paragraphs (i)(4) through (i)(6) of
this section, flow meters and other devices (e.g., belt scales) that
measure liquid and gaseous fuel feed rates, process stream flow rates,
or feedstock flow rates and provide data used tofor the GHG emissions
calculationse GHG emissions, shall be calibrated prior to April 1, 2010
using the procedures specified in this paragraph and each (i) when such
calibration is specified in a relevant subpart of this part.  Each of
these flow meters shall meet the applicable accuracy specification in
paragraph (i)(2) or (i)(3) of this section.  All other measurement
devices (e.g., weighing devices) that are required by a relevant subpart
of this part, and that are used to provide data for the GHG emissions
calculations, shall also be calibrated prior to April 1, 2010; however,
the accuracy specifications in paragraphs (i)(2) and (i)(3) of this
section do not apply to these devices.  Rather, each of these
measurement devices shall be calibrated to meet the accuracy requirement
specified for the device in the applicable subpart of this part, or, in
the absence of such accuracy requirement, the device must be calibrated
to an accuracy within the appropriate error range for the specific
measurement technology, based on an applicable operating standard,
including but not limited to industry standards and manufacturer’s
specifications.  The procedures and methods used to quality-assure the
data from each measurement device shall be documented in the written
Monitoring Plan, pursuant to paragraph (g)(5)(i)(C) of this section.

(i)  All flow meters and other measurement devices that are subject to
the provisions of this paragraph (i) must be calibrated according to one
of the following:.  You may use the manufacturer’s recommended
procedures,; an appropriate industry consensus standard method,; or a
method specified in a relevant subpart of this part.  The calibration
method(s) used shall be documented in the Monitoring Plan required under
paragraph (g) of this section. All measurement devices shall be
calibrated to an accuracy of 5 percent.   

(ii)  For facilities and suppliers that become subject to this part
after April 1, 2010, the initial calibration shall be conducted on the
date that data collection is required to begin.  Subsequent calibrations
shall be performed at the frequency specified in each applicable
subpart.all flow meters and other measurement devices (if any) that are
required by the relevant subpart(s) of this part to provide data for the
GHG emissions calculations shall be installed no later than the date on
which data collection is required to begin using the measurement device,
and the initial calibration(s) required by this paragraph (i) (if any)
shall be performed no later than that date.  

(iii)  Except as otherwise provided in paragraphs (i)(4) through (i)(6)
of this section, subsequent recalibrations of the flow meters and other
measurement devices subject to the requirements of this paragraph (i)
shall be performed at one of the following frequencies:

(A)  You may use the frequency specified in each applicable subpart of
this part.

(B)  You may use the frequency recommended by the manufacturer or by an
industry consensus standard practice, if no recalibration frequency is
specified in an applicable subpart.  

(2)  For flow meters, pPerform all flow meter calibrations at
measurement points that are representative of the normal operatingon
range of the meter.  Except for the orifice, nozzle, and venturi flow
meters described in paragraph (i)(3) of this section, calculate the
calibration error at each measurement point using Equation A-2 of this
section.  The terms “R” and “A” in Equation A-2 must be
expressed in consistent units of measure (e.g., gallons/minute,
ft3/min).  The calibration error at each measurement point shall not
exceed 5.0 percent of the reference value.

Where:

CE	=	Calibration error (%)

R	=	Reference value 

A	=	Flow meter response to the reference value

(3)  For orifice, nozzle, and venturi flow meters, the initial quality
assurance consists of in-situ calibration of the differential pressure
(delta-P), total pressure, and temperature transmitters.  

(i)  Calibrate each transmitter at a zero point and at least one upscale
point. Fixed reference points, such as the freezing point of water, may
be used for temperature transmitter calibrations.  Calculate the
calibration error of each transmitter at each measurement point, using
Equation A-3 of this subpart.  The terms “R”, “A”, and “FS”
in Equation A-3 of this subpart must be in consistent units of measure
(e.g., milliamperes, inches of water, psi, degrees).  For each
transmitter, the CE value at each measurement point shall not exceed 2.0
percent of full-scale.  Alternatively, the results are acceptable if the
sum of the calculated CE values for the three transmitters at each
calibration level (i.e., at the zero level and at each upscale level)
does not exceed: 56.0 percent.

Where:

CE	=	Calibration error (%)

R	=	Reference value 

A	=	Transmitter response to the reference value

FS	=	Full-scale value of the transmitter

(ii)  In cases where there are only two transmitters (i.e., differential
pressure and either temperature or total pressure) in the immediate
vicinity of the flow meter’s primary element (e.g., the orifice
plate), or when there is only a differential pressure transmitter in
close proximity to the primary element, calibration of these existing
transmitters to a CE of 2.0 percent or less at each measurement point is
still required, in accordance with paragraph (i)(3)(i) of this section;
alternatively, when two transmitters are calibrated, the results are
acceptable if the sum of the CE values for the two transmitters at each
calibration level does not exceed 4.0 percent.  However, note that
installation and calibration of an additional transmitter (or
transmitters) at the flow monitor location to measure temperature or
total pressure or both is not required in these cases.  Instead, you may
use assumed values for temperature and/or total pressure, based on
measurements of these parameters at a remote location (or locations),
provided that the following conditions are met:

(A)  You must demonstrate that measurements at the remote location(s)
can, when appropriate correction factors are applied, reliably and
accurately represent the actual temperature or total pressure at the
flow meter under all expected ambient conditions.

(B)  You must make all temperature and/or total pressure measurements in
the demonstration described in paragraph (i)(3)(ii)(A) of this section
with calibrated gauges, sensors, transmitters, or other appropriate
measurement devices.  At a minimum, calibrate each of these devices to
an accuracy within the appropriate error range for the specific
measurement technology, according to one of the following.  You may
calibrate using an industry consensus standards or a manufacturer’s
specification.  

(C)  You must document the methods used for the demonstration described
in paragraph (i)(3)(ii)(A) of this section in the written Monitoring
Plan under paragraph (g)(5)(i)(C) of this section.  You must also
include the data from the demonstration, the mathematical correlation(s)
between the remote readings and actual flow meter conditions derived
from the data, and any supporting engineering calculations in the
Monitoring Plan.  You must maintain all of this information in a format
suitable for auditing and inspection. 

(D)  You must use the mathematical correlation(s)  derived from the
demonstration described in paragraph (i)(3)(ii)(A) of this section to
convert the remote temperature or the total pressure readings, or both,
to the actual temperature or total pressure at the flow meter, or both,
on a daily basis.  You shall then use the actual temperature and total
pressure values to correct the measured flow rates to standard
conditions.   

(E)  You shall periodically check the correlation(s) between the remote
and actual readings (at least once a year), and make any necessary
adjustments to the mathematical relationship(s).

(4)  Fuel billing meters are exempted from the calibration requirements
of this section and from the Monitoring Plan and recordkeeping
provisions of paragraphs (g)(5)(i)(C) and (g)(7) of this section,
provided that the fuel supplier and any unit combusting the fuel do not
have any common owners and are not owned by subsidiaries or affiliates
of the same company.  Meters used exclusively to measure the flow rates
of fuels that are used for unit startup or ignition are also exempted
from the calibration requirements of this section.   

(5)  For a flow meter or other measurement device that has been
previously calibrated in accordance with this part, an initial paragraph
(i)(1) of this section, an additional calibration is not required by the
date specified in paragraph (i)(1) of this section if, as of the that
date required for the initial calibration, the previous calibration is
still active (i.e., the device is not yet due for recalibration because
the time interval between successive calibrations, as required bythis
part,  has not elapsed).  In this case, the deadline for the successive
calibrations of the flow meter shall be set according to one of the
following.  You may use either the manufacturer’s recommended
calibration schedule or you may use the industry consensus calibration
schedule. 

(6)  For units and processes that operate continuously with infrequent
outages, it may not be possible to meet the April 1, 2010 deadline for
the initial calibration of a flow meter or other measurement device
without removing the device from service and shipping it to a remote
location, thereby disrupting normal process operation.  In such cases,
the owner or operator may postpone the initial calibration until the
next scheduled maintenance outage.  The best available information from
company records may be used in the interim.  The , and may similarly
postpone the subsequent required recalibrations of the flow meters may
be similarly postponed.  Such postponements shall be documented in the
monitoring plan that is required under paragraph §98.3(g)(5) of this
section. 

(7)  If the results of an initial calibration or a recalibration fail to
meet the required accuracy specification, data from the flow meter shall
be considered invalid, beginning with the hour of the failed calibration
and continuing until a successful calibration is completed.  You shall
follow the missing data provisions provided in the relavant missing data
sections during the period of data invalidation.

(j)  Measurement Device Installation.

(1)  General.  If an owner or operator required to report under subpart
P, subpart X or subpart Y of this part has process equipment or units
that operate continuously and it is not possible to install a required
flow meter or other measurement device by April 1, 2010, (or by any
later date in 2010 approved by the Administrator as part of an extension
of best available monitoring methods per paragraph (d) of this section)
without process equipment or unit shutdown, or through a hot tap,  the
owner or operator may request an extension from the Administrator to
delay installing the measurement device until the next scheduled process
equipment or unit shutdown.  If approval for such an extension is
granted by the Administrator, the owner or operator must use best
available monitoring methods during the extension period.  

(2)  Requests for extension of the use of best available monitoring
methods for measurement device installation.  The owner or operator must
first provide the Administrator an initial notification of the intent to
submit an extension request for use of best available monitoring methods
beyond December 31, 2010 (or an earlier date approved by EPA) in cases
where measurement device installation would require a process equipment
or unit shutdown, or could only be done through a hot tap.  The owner or
operator must follow-up this initial notification with the complete
extension request containing the information specified in paragraph
(j)(4) of this section below.  

(3)  Timing of request.  

(i)  The initial notice of intent must be submitted no later than
January 1, 2011, or by the end of the approved use of best available
monitoring methods extension in 2010, whichever is earlier.  The
completed extension request must be submitted to the Administrator no
later than February 15, 2011. 

(ii)  Any subsquent extensions to the original request must be submitted
to the Administrator within 4 weeks of the owner or operator identifying
the need to extend the request, but in any event no later than 4 weeks
before the date for the planned process equipment or unit shutdown that
was provided in the original request.  

(4)  Content of the request.  Requests must contain the following
information:

(i)  Specific measurement device for which the request is being made and
the location where each measurement device will be installed. 

(ii)  Identification of the specific rule requirements (by rule subpart,
section, and paragraph numbers) requiring the measurement device.

(iii)  A description of the reasons why the needed equipment could not
be installed before April 1, 2010, or by the expiration date for the use
of best available monitoring methods, in cases where an extension has
been granted under §98.3(d).  

(iv)  Supporting documentation showing that it is not practicable to
isolate the process equipment or unit and install the measurement device
without a full shutdown or a hot tap, and that there was no opportunity
during 2010 to install the device.  Include the date of the three most
recent shutdowns for each relevant process equipment or unit, the
frequency of shutdowns for each relevant process equipment or unit, and
the date of the next planned process equipment or unit shutdown.  

(v)  Include a description of the proposed best available monitoring
method for estimating GHG emissions during the time prior to
installation of the meter.  

(5)  Approval criteria.  The owner or operator must demonstrate to the
Administrator’s satisfaction that it is not reasonably feasible to
install the measurement device before April 1, 2010 (or  by the
expiration date for the use of best available monitoring methods, in
cases where an extension has been granted under paragraph (d) of this
section) without a process equipment or unit shutdown, or through a hot
tap, and that the proposed method for estimating GHG emissions during
the time before which the measurement device will be installed is
appropriate.  The Administrator will not initially approve the use of
the proposed best available monitoring method past December 31, 2013. 

(6)  Measurement device installation deadline.  Any owner or operator
that submits both a timely initial notice of intent and a timely
completed extension request under paragraph (j)(3) of this section to
extend use of best available monitoring methods for measurement device
installation must install all such devices by July 1, 2011 unless the
extension request under this paragraph (j) is approved by the
Administrator before July 1, 2011.

(7)  One time extension past December 31, 2013.  If an owner or operator
determines that a scheduled process equipment or unit shutdown will not
occur by December 31, 2013, the owner or operator may re-apply to use
best available monitoring methods for one additional time period, not to
extend beyond December 31, 2015.  To extend use of best available
monitoring methods past December 31, 2013, the owner or operator must
submit a new extension request by June 1, 2013 that contains the
information required in paragraph (j)(4) of this section.  The owner or
operator must demonstrate to the Administrator’s satisfaction that it
continues to not be reasonably feasible to install the measurement
device before December 31, 2013 without a process equipment or unit
shutdown, or that installation of the measurement device could only be
done through a hot tap, and that the proposed method for estimating GHG
emissions during the time before which the measurement device will be
installed is appropriate. An owner or operator that submits a request
under this paragraph to extend use of best available monitoring methods
for measurement device installation must install all such devices by
December 31, 2013, unless the extension request under this paragraph is
approved by the Administrator. 

§98.4  Authorization and Responsibilities of the Designated
Representative.

(a)  General.  Except as provided under paragraph (f) of this section,
each facility, and each supplier, that is subject to this part, shall
have one and only one designated representative, who shall be
responsible for certifying, signing, and submitting GHG emissions
reports and any other submissions for such facility and supplier
respectively to the Administrator under this part.  If the facility is
required under any other part of title 40 of the Code of Federal
Regulations to submit to the Administrator any other emission report
that is subject to any requirement in 40 CFR part 75, the same
individual shall be the designated representative responsible for
certifying, signing, and submitting the GHG emissions reports and all
such other emissions reports under this part. 

(b)  Authorization of a designated representative.  The designated
representative of the facility or supplier shall be an individual
selected by an agreement binding on the owners and operators of such
facility or supplier and shall act in accordance with the certification
statement in paragraph (i)(4)(iv) of this section.  

(c)  Responsibility of the designated representative.  Upon receipt by
the Administrator of a complete certificate of representation under this
section for a facility or supplier, the designated representative
identified in such certificate of representation shall represent and, by
his or her representations, actions, inactions, or submissions, legally
bind each owner and operator of such facility or supplier in all matters
pertaining to this part, notwithstanding any agreement between the
designated representative and such owners and operators.  The owners and
operators shall be bound by any decision or order issued to the
designated representative by the Administrator or a court.

(d)  Timing.  No GHG emissions report or other submissions under this
part for a facility or supplier will be accepted until the Administrator
has received a complete certificate of representation under this section
for a designated representative of the facility or supplier. Such
certificate of representation shall be submitted at least 60 days before
the deadline for submission of the facility’s or supplier’s initial
emission report under this part.

(e)  Certification of the GHG emissions report.  Each GHG emission
report and any other submission under this part for a facility or
supplier shall be certified, signed, and submitted by the designated
representative or any alternate designated representative of the
facility or supplier in accordance with this section and §3.10.

(1)  Each such submission shall include the following certification
statement signed by the designated representative or any alternate
designated representative: “I am authorized to make this submission on
behalf of the owners and operators of the facility or supplier, as
applicable, for which the submission is made.  I certify under penalty
of law that I have personally examined, and am familiar with, the
statements and information submitted in this document and all its
attachments.  Based on my inquiry of those individuals with primary
responsibility for obtaining the information, I certify that the
statements and information are to the best of my knowledge and belief
true, accurate, and complete.  I am aware that there are significant
penalties for submitting false statements and information or omitting
required statements and information, including the possibility of fine
or imprisonment.”

(2)  The Administrator will accept a GHG emission report or other
submission for a facility or supplier under this part only if the
submission is certified, signed, and submitted in accordance with this
section.

(f)  Alternate designated representative.  A certificate of
representation under this section for a facility or supplier may
designate one alternate designated representative, who shall be an
individual selected by an agreement binding on the owners and operators,
and may act on behalf of the designated representative, of such facility
or supplier.  The agreement by which the alternate designated
representative is selected shall include a procedure for authorizing the
alternate designated representative to act in lieu of the designated
representative.

(1)  Upon receipt by the Administrator of a complete certificate of
representation under this section for a facility or supplier identifying
an alternate designated representative.

(i)  The alternate designated representative may act on behalf of the
designated representative for such facility or supplier.

(ii)  Any representation, action, inaction, or submission by the
alternate designated representative shall be deemed to be a
representation, action, inaction, or submission by the designated
representative.

(2)  Except in this section, whenever the term “designated
representative” is used in this part, the term shall be construed to
include the designated representative or any alternate designated
representative.

(g)  Changing a designated representative or alternate designated
representative.  The designated representative or alternate designated
representative identified in a     complete certificate of
representation under this section for a facility or supplier received by
the Administrator may be changed at any time upon receipt by the
Administrator of another later signed, complete certificate of
representation under this section for the facility or supplier. 
Notwithstanding any such change, all representations, actions,
inactions, and submissions by the previous designated representative or
the previous alternate designated representative of the facility or
supplier before the time and date when the Administrator receives such
later signed certificate of representation shall be binding on the new
designated representative and the owners and operators of the facility
or supplier.

(h)  Changes in owners and operators.  In the event an owner or operator
of the facility or supplier is not included in the list of owners and
operators in the certificate of representation under this section for
the facility or supplier, such owner or operator shall be deemed to be
subject to and bound by the certificate of representation, the
representations, actions, inactions, and submissions of the designated
representative and any alternate designated representative of the
facility or supplier, as if the owner or operator were included in such
list.  Within 90 days after any change in the owners and operators of
the facility or supplier (including the addition of a new owner or
operator), the designated representative or any alternate designated
representative shall submit a certificate of representation that is
complete under this section except that such list shall be amended to
reflect the change.  If the designated representative or alternate
designated representative determines at any time that an owner or
operator of the facility or supplier is not included in such list and
such exclusion is not the result of a change in the owners and
operators, the designated representative or any alternate designated
representative shall submit, within 90 days of making such
determination, a certificate of representation that is complete under
this section except that such list shall be amended to include such
owner or operator.  

(i)  Certificate of representation.  A certificate of representation
shall be complete if it includes the following elements in a format
prescribed by the Administrator in accordance with this section:

(1)  Identification of the facility or supplier for which the
certificate of representation is submitted.

(2)  The name, organization name (company affiliation-employer),
address, e-mail address (if any), telephone number, and facsimile
transmission number (if any) of the designated representative and any
alternate designated representative.  

(3)  A list of the owners and operators of the facility or supplier
identified in paragraph (i)(1) of this section, provided that, if the
list includes the operators of the facility or supplier and the owners
with control of the facility or supplier, the failure to include any
other owners shall not make the certificate of representation
incomplete.

(4)  The following certification statements by the designated
representative and any alternate designated representative:

(i)  “I certify that I was selected as the designated representative
or alternate designated representative, as applicable, by an agreement
binding on the owners and operators of the facility or supplier, as
applicable.”

(ii)  “I certify that I have all the necessary authority to carry out
my duties and responsibilities under 40 CFR part 98 on behalf of the
owners and operators of the facility or supplier, as applicable, and
that each such owner and operator shall be fully bound by my
representations, actions, inactions, or submissions.”

(iii)  “I certify that the owners and operators of the facility or
supplier, as applicable, shall be bound by any order issued to me by the
Administrator or a court regarding the facility or supplier.”

(iv)  “If there are multiple owners and operators of the facility or
supplier, as applicable, I certify that I have given a written notice of
my selection as the ‘designated representative’ or ‘alternate
designated representative’, as applicable, and of the agreement by
which I was selected to each owner and operator of the facility or
supplier."

(5)  The signature of the designated representative and any alternate
designated representative and the dates signed.

(j)  Documents of agreement.  Unless otherwise required by the
Administrator, documents of agreement referred to in the certificate of
representation shall not be submitted to the Administrator. The
Administrator shall not be under any obligation to review or evaluate
the sufficiency of such documents, if submitted.

(k)  Binding nature of the certificate of representation.  Once a
complete certificate of representation under this section for a facility
or supplier has been received, the Administrator will rely on the
certificate of representation unless and until a later signed, complete
certificate of representation under this section for the facility or
supplier is received by the Administrator.

(l)  Objections concerning a designated representative.

(1)  Except as provided in paragraph (g) of this section, no objection
or other communication submitted to the Administrator concerning the
authorization, or any representation, action, inaction, or submission,
of the designated representative or alternate designated representative
shall affect any representation, action, inaction, or submission of the
designated representative or alternate designated representative, or the
finality of any decision or order by the Administrator under this part.

(2)  The Administrator will not adjudicate any private legal dispute
concerning the authorization or any representation, action, inaction, or
submission of any designated representative or alternate designated
representative.

(m)  Delegation by designated representative and alternate designated
representative.

(1)  A designated representative or an alternate designated
representative may delegate his or her own authority, to one or more
individuals, to submit an electronic submission to the Administrator
provided for or required under this part, except for a submission under
this paragraph.

(2)  In order to delegate his or her own authority, to one or more
individuals, to submit an electronic submission to the Administrator in
accordance with paragraph (m) (1) of this section, the designated
representative or alternate designated representative must submit
electronically to the Administrator a notice of delegation, in a format
prescribed by the Administrator, that includes the following elements:

(i)  The name, organization name (company affiliation-employer) address,
e-mail address (if any), telephone number, and facsimile transmission
number (if any) of such designated representative or alternate
designated representative.

(ii)  The name, address, e-mail address, telephone number, and facsimile
transmission number (if any) of each such individual (referred to as an
“agent”).

(iii)  For each such individual, a list of the type or types of
electronic submissions under paragraph (m)(1) of this section for which
authority is delegated to him or her.

(iv)  For each type of electronic submission listed in accordance with
clause (iii), the facility or supplier for which the electronic
submission may be made.

(v)  The following certification statements by such designated
representative or alternate designated representative:

(A)  “I agree that any electronic submission to the Administrator that
is by an agent identified in this notice of delegation and of a type
listed, and for a facility or supplier designated, for such agent in
this notice of delegation and that is made when I am a designated
representative or alternate designated representative, as applicable,
and before this notice of delegation is superseded by another notice of
delegation under  §98.4(m)(3) shall be deemed to be an electronic
submission certified, signed, and submitted by me.”

(B)  “Until this notice of delegation is superseded by a later signed
notice of delegation under §98.4(m)(3), I agree to maintain an e-mail
account and to notify the Administrator immediately of any change in my
e-mail address unless all delegation of authority by me under §98.4(m)
is terminated.”

(v)  The signature of such designated representative or alternate
designated representative and the date signed. 

(3)  A notice of delegation submitted in accordance with paragraph
(m)(2) of this section shall be effective, with regard to the designated
representative or alternate designated representative identified in such
notice, upon receipt of such notice by the Administrator and until
receipt by the Administrator of another such notice that was signed
later by such designated representative or alternate designated
representative, as applicable.  The later signed notice of delegation
may replace any previously identified agent, add a new agent, or
eliminate entirely any delegation of authority.

(4)  Any electronic submission covered by the certification in paragraph
(m)(2)(iv)(A) of this section and made in accordance with a notice of
delegation effective under paragraph (m)(3) of this section shall be
deemed to be an electronic submission certified, signed, and submitted
by the designated representative or alternate designated representative
submitting such notice of delegation.

§98.5  How is the report submitted?

Each GHG report and certificate of representation for a facility or
supplier must be submitted electronically in accordance with the
requirements of §98.4 and in a format specified by the Administrator.  

§98.6  Definitions.

All terms used in this part shall have the same meaning given in the
Clean Air Act and in this section. 

Accuracy of a measurement at a specified level (e.g., one percent of
full scale or one percent of the value measured) means that the mean of
repeat measurements made by a device or technique are within 95 percent
of the range bounded by the true value plus or minus the specified
level.

Acid Rain Program means the program established under title IV of the
Clean Air Act, and implemented under parts 72 through 78 of this chapter
for the reduction of sulfur dioxide and nitrogen oxides emissions.

Administrator means the Administrator of the United States Environmental
Protection Agency or the Administrator’s authorized representative.

AGA means the American Gas Association

Agricultural byproducts means those parts of arable crops that are not
used for the primary purpose of producing food.  Agricultural byproducts
include, but are not limited to, oat, corn and wheat straws, bagasse,
peanut shells, rice and coconut husks, soybean hulls, palm kernel cake,
cottonseed and sunflower seed cake, and pomace.

Alkali bypass means a duct between the feed end of the kiln and the
preheater tower through which a portion of the kiln exit gas stream is
withdrawn and quickly cooled by air or water to avoid excessive buildup
of alkali, chloride and/or sulfur on the raw feed.  This may also be
referred to as the “kiln exhaust gas bypass.”

Anaerobic digester means the system where wastes are collected and
anaerobically digested in large containment vessels or covered lagoons. 
Anaerobic digesters stabilize waste by the microbial reduction of
complex organic compounds to CO2 and CH4, which is captured and may be
flared or used as fuel. Anaerobic digestion systems, include but are not
limited to covered lagoon, complete mix, plug flow, and fixed film
digesters.

Anaerobic lagoon means a type of liquid storage system component, either
at manure management system or a wastewater treatment system, that is
designed and operated to stabilize wastes using anaerobic microbial
processes. Anaerobic lagoons may be designed for combined stabilization
and storage with varying lengths of retention time (up to a year or
greater), depending on the climate region, the volatile solids loading
rate, and other operational factors.

Anode effect is a process upset condition of an aluminum electrolysis
cell caused by too little alumina dissolved in the electrolyte.  The
anode effect begins when the voltage rises rapidly and exceeds a
threshold voltage, typically 8 volts.  

Anode Effect Minutes Per Cell Day (24 hours) are the total minutes
during which an electrolysis cell voltage is above the threshold
voltage, typically 8 volts.

ANSI means the American National Standards Institute.

API means the American Petroleum Institute.

Argon-oxygen decarburization (AOD) vessel means any closed-bottom,
refractory-lined converter vessel with submerged tuyeres through which
gaseous mixtures containing argon and oxygen or nitrogen may be blown
into molten steel for further refining to reduce the carbon content of
the steel.

ASABE means the American Society of Agricultural and Biological
Engineers.

ASME means the American Society of Mechanical Engineers.

ASTM means the American Society of Testing and Materials.

Asphalt means a dark brown-to-black cement-like material obtained by
petroleum processing and containing bitumens as the predominant
component. It includes crude asphalt as well as the following finished
products: cements, fluxes, the asphalt content of emulsions (exclusive
of water), and petroleum distillates blended with asphalt to make
cutback asphalts. 

Aviation Gasoline means a complex mixture of volatile hydrocarbons, with
or without additives, suitably blended to be used in aviation
reciprocating engines. Specifications can be found in ASTM Specification
D910–07a, Standard Specification for Aviation Gasolines (incorporated
by reference, see §98.7).

B0 means the maximum CH4 producing capacity of a waste stream, kg CH4/kg
COD.

Basic oxygen furnace means any refractory-lined vessel in which
high-purity oxygen is blown under pressure through a bath of molten
iron, scrap metal, and fluxes to produce steel. 

bbl means barrel.

Biodiesel means a mono-akyl ester derived from biomass  and conforming
to ASTM D6751-08, Standard Specification for Biodiesel Fuel Blend Stock
(B100) for Middle Distillate Fuels.

Biogenic CO2 means carbon dioxide emissions generated as the result of
biomass combustion from combustion units for which emission calculations
are required by an applicable part 98 subpart.  

Biomass means non-fossilized and biodegradable organic material
originating from plants, animals or micro-organisms, including products,
by-products, residues and waste from agriculture, forestry and related
industries as well as the non-fossilized and biodegradable organic
fractions of industrial and municipal wastes, including gases and
liquids recovered from the decomposition of non-fossilized and
biodegradable organic material.  

Blast furnace means a furnace that is located at an integrated iron and
steel plant and is used for the production of molten iron from iron ore
pellets and other iron bearing materials.

Blendstocks are petroleum products used for blending or compounding into
finished motor gasoline. These include RBOB (reformulated blendstock for
oxygenate blending) and CBOB (conventional blendstock for oxygenate
blending), but exclude oxygenates, butane, and pentanes plus.

Blendstocks -- Others are products used for blending or compounding into
finished motor gasoline that are not defined elsewhere. Excludes
Gasoline Treated as Blendstock (GTAB), Diesel Treated as Blendstock
(DTAB), conventional blendstock for oxygenate blending (CBOB),
reformulated blendstock for oxygenate blending (RBOB), oxygenates (e.g.
fuel ethanol and methyl tertiary butyl ether), butane, and pentanes
plus. 

Blowdown mean the act of emptying or depressuring a vessel.  This may
also refer to the discarded material such as blowdown water from a
boiler or cooling tower.

British Thermal Unit or Btu means the quantity of heat required to raise
the temperature of one pound of water by one degree Fahrenheit at about
39.2 degrees Fahrenheit.

Bulk, with respect to industrial GHG suppliers and CO2 suppliers, means
the transfer of a product inside containers, including but not limited
to tanks, cylinders, drums, and pressure vessels.

Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons that
have been separated from natural gas as liquids through the process of
absorption, condensation, adsorption, or other methods at lease
separators and field facilities. Generally, such liquids consist of
ethane, propane, butanes, and pentanes plus. Bulk NGL is sold to
fractionators or to refineries and petrochemical plants where the
fractionation takes place.

Butane, or n-Butane, is a paraffinic straight-chain hydrocarbon with
molecular formula C4H10.

Butylene, or n-Butylene, is an olefinic straight-chain hydrocarbon with
molecular formula C4H8. 

By-product coke oven battery means a group of ovens connected by common
walls, where coal undergoes destructive distillation under positive
pressure to produce coke and coke oven gas from which by-products are
recovered.

Calcination means the process of thermally treating minerals to
decompose carbonates from ore.

Calculation methodology means a methodology prescribed under the section
“Calculating GHG Emissions” in any subpart of part 98.

Carbon dioxide equivalent or CO2e means the number of metric tons of CO2
emissions with the same global warming potential as one metric ton of
another greenhouse gas, and is calculated using Equation A-1 of this
subpart.

Carbon dioxide production well means any hole drilled in the earth for
the primary purpose of extracting carbon dioxide from a geologic
formation or group of formations which contain deposits of carbon
dioxide.

Carbon dioxide production well facility means one or more carbon dioxide
production wells that are located on one or more contiguous or adjacent
properties, which are under the control of the same entity.  Carbon
dioxide production wells located on different oil and gas leases,
mineral fee tracts, lease tracts, subsurface or surface unit areas,
surface fee tracts, surface lease tracts, or separate surface sites,
whether or not connected by a road, waterway, power line, or pipeline,
shall be considered part of the same CO2 production well facility if
they otherwise meet the definition.

Carbon dioxide stream means carbon dioxide that has been captured from
an emission source (e.g. a power plant or other industrial facility) or
extracted from a carbon dioxide production well plus incidental
associated substances either derived from the source materials and the
capture process or extracted with the carbon dioxide.

Carbon share means the percent of total mass that carbon represents in
any product..

Carbonate means compounds containing the radical CO3-2. Upon
calcination, the carbonate radical decomposes to evolve carbon dioxide
(CO2). Common carbonates consumed in the mineral industry include
calcium carbonate (CaCO3) or calcite; magnesium carbonate (MgCO3) or
magnesite; and  calcium-magnesium carbonate (CaMg(CO3)2) or dolomite.

Carbonate-based mineral means any of the following minerals used in the
manufacture of glass:  calcium carbonate (CaCO3), calcium magnesium
carbonate (CaMg(CO3)2), and sodium carbonate (Na2CO3).

Carbonate-based mineral mass fraction means the following:  for
limestone, the mass fraction of CaCO3 in the limestone; for dolomite,
the mass fraction of CaMg(CO3)2 in the dolomite; and for soda ash, the
mass fraction of Na2CO3 in the soda ash.

Carbonate-based raw material means any of the following materials used
in the manufacture of glass:  limestone, dolomite, and soda ash.

Catalytic cracking unit means a refinery process unit in which petroleum
derivatives are continuously charged and hydrocarbon molecules in the
presence of a catalyst are fractured into smaller molecules, or react
with a contact material suspended in a fluidized bed to improve
feedstock quality for additional processing and the catalyst or contact
material is continuously regenerated by burning off coke and other
deposits.  Catalytic cracking units include both fluidized bed systems,
which are referred to as fluid catalytic cracking units (FCCU), and
moving bed systems, which are also referred to as thermal catalytic
cracking units.  The unit includes the riser, reactor, regenerator, air
blowers, spent catalyst or contact material stripper, catalyst or
contact material recovery equipment, and regenerator equipment for
controlling air pollutant emissions and for heat recovery.

Deep bedding systems for cattle swine means a manure management system
in which, as manure accumulates, bedding is continually added to absorb
moisture over a production cycle and possibly for as long as 6 to 12
months.  This manure management system also is known as a bedded pack
manure management system and may be combined with a dry lot or pasture.

CBOB-Summer (conventional blendstock for oxygenate blending) means a
petroleum product which, when blended with a specified type and
percentage of oxygenate, meets the definition of Conventional-Summer.

CBOB-Winter (conventional blendstock for oxygenate blending) means a
petroleum product which, when blended with a specified type and
percentage of oxygenate, meets the definition of Conventional-Winter.

Certified standards means calibration gases certified by the
manufacturer of the calibration gases to be accurate to within 2 percent
of the value on the label or calibration gases.

CH4 means methane.

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

Chemical recovery furnace means an enclosed combustion device where
concentrated spent liquor produced by the kraft or soda pulping process
is burned to recover pulping chemicals and produce steam.  Includes any
recovery furnace that burns spent pulping liquor produced from both the
kraft and soda pulping processes.

Chloride process means a production process where titanium dioxide is
produced using calcined petroleum coke and chlorine as raw materials.

City gate means a location at which natural gas ownership or control
passes from one party to another, neither of which is the ultimate
consumer.  In this rule, in keeping with common practice, the term
refers to a point or measuring station at which a local gas distribution
utility receives gas from a natural gas pipeline company or transmission
system.  Meters at the city gate station measure the flow of natural gas
into the local distribution company system and typically are used to
measure local distribution company system sendout to customers.  

CO2 means carbon dioxide.

Coal means all solid fuels classified as anthracite, bituminous,
sub-bituminous, or lignite by the American Society for Testing and
Materials Designation ASTM D388–05 Standard Classification of Coals by
Rank (incorporated by reference, see §98.7).

COD means the chemical oxygen demand as determined using methods
specified pursuant to 40 CFR part 136.

Coke burn-off means the coke removed from the surface of a catalyst by
combustion during catalyst regeneration.  Coke burn-off also means the
coke combusted in fluid coking unit burner.

Cokemaking means the production of coke from coal in either a by-product
coke oven battery or a non-recovery coke oven battery.

Commercial Applications means executing a commercial transaction subject
to a contract. A commercial application includes transferring custody of
a product from one facility to another if it otherwise meets the
definition. 

Company records means, in reference to the amount of fuel consumed by a
stationary combustion unit (or by a group of such units), a complete
record of the methods used, the measurements made, and the calculations
performed to quantify fuel usage.  Company records may include, but are
not limited to, direct measurements of fuel consumption by gravimetric
or volumetric means, tank drop measurements, and calculated values of
fuel usage obtained by measuring auxiliary parameters such as steam
generation or unit operating hours.  Fuel billing records obtained from
the fuel supplier qualify as company records.     

Connector means to flanged, screwed, or other joined fittings used to
connect pipe line segments, tubing, pipe components (such as elbows,
reducers, “T’s” or valves) or a pipe line and a piece of equipment
or an instrument to a pipe, tube or piece of equipment.  A common
connector is a flange.  Joined fittings welded completely around the
circumference of the interface are not considered connectors for the
purpose of this part.

Container glass means glass made of soda-lime recipe, clear or colored,
which is pressed and/or blown into bottles, jars, ampoules, and other
products listed in North American Industry Classification System 327213
(NAICS 327213).

Continuous emission monitoring system or CEMS means the total equipment
required to sample, analyze, measure, and provide, by means of readings
recorded at least once every 15 minutes, a permanent record of gas
concentrations, pollutant emission rates, or gas volumetric flow rates
from stationary sources.

Continuous glass melting furnace means a glass melting furnace that
operates continuously except during periods of maintenance, malfunction,
control device installation, reconstruction, or rebuilding.

Conventional—Summer refers to finished gasoline formulated for use in
motor vehicles, the composition and properties of which do not meet the
requirements of the reformulated gasoline regulations promulgated by the
U.S. Environmental Protection Agency under 40 CFR 80.40, but which meet
summer RVP standards required under 40 CFR 80.27 or as specified by the
state. Note: This category excludes conventional gasoline for oxygenate
blending (CBOB) as well as other blendstock.

Conventional—Winter refers to finished gasoline formulated for use in
motor vehicles, the composition and properties of which do not meet the
requirements of the reformulated gasoline regulations promulgated by the
U.S. Environmental Protection Agency under 40 CFR 80.40 or the summer
RVP standards required under 40 CFR 80.27 or as specified by the state. 
Note: This category excludes conventional blendstock for oxygenate
blending (CBOB) as well as other blendstock.

Crude oil means a mixture of hydrocarbons that exists in the liquid
phase in the underground reservoir and remains liquid at atmospheric
pressure after passing through surface separating facilities.  

Daily spread means a manure management system component in which manure
is routinely removed from a confinement facility and is applied to
cropland or pasture within 24 hours of excretion.

Day means any consistently designated 24 hour period during which an
emission unit is operated.

Degradable organic carbon (DOC) means the fraction of the total mass of
a waste material that can be biologically degraded.

Delayed coking unit means one or more refinery process units in which
high molecular weight petroleum derivatives are thermally cracked and
petroleum coke is produced in a series of closed, batch system reactors.
 A delayed coking unit consists of the coke drums and ancillary
equipment associated with a single fractionator.

Density means the mass contained in a given unit volume (mass/volume).

Destruction means, with respect to landfills and manure management, the
combustion of methane in any on-site or off-site combustion technology. 
Destroyed methane includes, but is not limited to, methane combusted by
flaring, methane destroyed by thermal oxidation, methane combusted for
use in on-site energy or heat production technologies, methane that is
conveyed through pipelines (including natural gas pipelines) for
off-site combustion, and methane that is collected for any other on-site
or off-site use as a fuel.

Destruction means, with respect to fluorinated GHGs, the expiration of a
fluorinated GHG to the destruction efficiency actually achieved.  Such
destruction does not result in a commercially useful end product.   

Destruction Efficiency means the efficiency with which a destruction
device reduces the GWP-weighted mass of greenhouse gases fed into the
device, considering the GWP-weighted masses of both the greenhouse gases
fed into the device and those exhausted from the device.  The
Destruction Efficiency is expressed in Equation A-2 of this section:

 	(Eq. A-2)

Where:

DE	=	Destruction Efficiency 

tCO2eIN	=	The GWP-weighted mass of GHGs fed into the destruction device

tCO2eOUT	=	The GWP-weighted mass of GHGs exhausted from the destruction
device, including GHGs formed during the destruction process 

Destruction efficiency, or flaring destruction efficiency, refers to the
fraction of the gas that leaves the flare partially or fully oxidized.

Diesel–Other is any distillate fuel oil not defined elsewhere,
including Diesel Treated as Blendstock (DTAB).

DIPE (diisopropyl ether, (CH3)2CHOCH(CH3)2) is an ether as described in
"Oxygenates."

Direct liquefaction means the conversion of coal directly into liquids,
rather than passing through an intermediate gaseous state.

Direct reduction furnace means a high temperature furnace typically
fired with natural gas to produce solid iron from iron ore or iron ore
pellets and coke, coal, or other carbonaceous materials.

Distillate Fuel Oil means a classification for one of the petroleum
fractions produced in conventional distillation operations and from
crackers and hydrotreating process units.  The generic term distillate
fuel oil includes kerosene, kerosene-type jet fuel, diesel fuels (Diesel
Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1, No. 2,
and No. 4). 

Distillate Fuel No. 1 has a maximum distillation temperature of 550 °F
at the 90 percent recovery point and a minimum flash point of 100 °F
and includes fuels commonly known as Diesel Fuel No. 1 and Fuel Oil No.
1, but excludes kerosene. This fuel is further subdivided into
categories of sulfur content: High Sulfur (greater than 500 ppm), Low
Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and
Ultra Low Sulfur (less than or equal to 15 ppm).

Distillate Fuel No. 2 has a minimum and maximum distillation temperature
of 540 °F and 640 °F at the 90 percent recovery point, respectively,
and includes fuels commonly known as Diesel Fuel No. 2 and Fuel Oil No.
2. This fuel is further subdivided into categories of sulfur content:
High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to
500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or
equal to 15 ppm).

Distillate Fuel No. 4 is a distillate fuel oil made by blending
distillate fuel oil and residual fuel oil, with a minimum flash point of
131 °F.

DOCf means the fraction of DOC that actually decomposes under the
(presumably anaerobic) conditions within the landfill. 

Dry lot means a manure management system component consisting of a paved
or unpaved open confinement area without any significant vegetative
cover where accumulating manure may be removed periodically.

Electric arc furnace (EAF) means a furnace that produces molten alloy
metal and heats the charge materials with electric arcs from carbon
electrodes.

Electric arc furnace steelmaking means the production of carbon, alloy,
or specialty steels using an EAF.  This definition excludes EAFs at
steel foundries and EAFs used to produce nonferrous metals.

Electrothermic furnace means a furnace that heats the charged materials
with electric arcs from carbon electrodes.

Emergency generator means a stationary combustion device, such as a
reciprocating internal combustion engine or turbine that serves solely
as a secondary source of mechanical or electrical power whenever the
primary energy supply is disrupted or discontinued during power outages
or natural disasters that are beyond the control of the owner or
operator of a facility.  An emergency generator operates only during
emergency situations, for training of personnel under simulated
emergency conditions, as part of emergency demand response procedures,
or for standard performance testing procedures as required by law or by
the generator manufacturer.  A generator that serves as a back-up power
source under conditions of load shedding, peak shaving, power
interruptions pursuant to an interruptible power service agreement, or
scheduled facility maintenance shall not be considered an emergency
generator. 

Emergency equipment means any auxiliary fossil fuel-powered equipment,
such as a fire pump, that is used only in emergency situations.

ETBE (ethyl tertiary butyl ether, (CH3)3COC2H) is an ether as described
in "Oxygenates."

Ethane is a paraffinic hydrocarbon with molecular formula C2H6. 

Ethanol is an anhydrous alcohol with molecular formula C2H5OH. 

Ethylene is an olefinic hydrocarbon with molecular formula C2H4. 

Ex refinery gate means the point at which a petroleum product leaves the
refinery.

Experimental furnace means a glass melting furnace with the sole purpose
of operating to evaluate glass melting processes, technologies, or glass
products.  An experimental furnace does not produce glass that is sold
(except for further research and development purposes) or that is used
as a raw material for non-experimental furnaces.

Export means to transport a product from inside the United States to
persons outside the United States, excluding any such transport on
behalf of the United States military including foreign military sales
under the Arms Export Control Act.

Exporter means any person, company or organization of record that
transfers for sale or for other benefit, domestic products from the
United States to another country or to an affiliate in another country,
excluding any such transfers on behalf of the United States military or
military purposes including foreign military sales under the Arms Export
Control Act. An exporter is not the entity merely transporting the
domestic products, rather an exporter is the entity deriving the
principal benefit from the transaction.   

Facility means any physical property, plant, building, structure,
source, or stationary equipment located on one or more contiguous or
adjacent properties in actual physical contact or separated solely by a
public roadway or other public right-of-way and under common ownership
or common control, that emits or may emit any greenhouse gas.  Operators
of military installations may classify such installations as more than a
single facility based on distinct and independent functional groupings
within contiguous military properties.

Feed means the prepared and mixed materials, which include but are not
limited to materials such as limestone, clay, shale, sand, iron ore,
mill scale, cement kiln dust and flyash, that are fed to the kiln.  Feed
does not include the fuels used in the kiln to produce heat to form the
clinker product.

Feedstock means raw material inputs to a process that are transformed by
reaction, oxidation, or other chemical or physical methods into products
and by-products.  Supplemental fuel burned to provide heat or thermal
energy is not a feedstock.

Fischer-Tropsch process means a catalyzed chemical reaction in which
synthesis gas, a mixture of carbon monoxide and hydrogen, is converted
into liquid hydrocarbons of various forms.

Flare means a combustion device, whether at ground level or elevated,
that uses an open flame to burn combustible gases with combustion air
provided by uncontrolled ambient air around the flame. 

Flat glass means glass made of soda-lime recipe and produced into
continuous flat sheets and other products listed in NAICS 327211.

Flowmeter means a device that measures the mass or volumetric rate of
flow of a gas, liquid, or solid moving through an open or closed conduit
(e.g. flowmeters include, but are not limited to, rotameters, turbine
meters, coriolis meters, orifice meters, ultra-sonic flowmeters, and
vortex flowmeters).

Fluid coking unit means one or more refinery process units in which high
molecular weight petroleum derivatives are thermally cracked and
petroleum coke is continuously produced in a fluidized bed system.  The
fluid coking unit includes equipment for controlling air pollutant
emissions and for heat recovery on the fluid coking burner exhaust vent.
 There are two basic types of fluid coking units:  a traditional fluid
coking unit in which only a small portion of the coke produced in the
unit is burned to fuel the unit and the fluid coking burner exhaust vent
is directed to the atmosphere (after processing in a CO boiler or other
air pollutant control equipment) and a flexicoking unit in which an
auxiliary burner is used to partially combust a significant portion of
the produced petroleum coke to generate a low value fuel gas that is
used as fuel in other combustion sources at the refinery.

Fluorinated greenhouse gas means sulfur hexafluoride (SF6), nitrogen
trifluoride (NF3), and any fluorocarbon except for controlled substances
as defined at 40 CFR part 82, subpart A and substances with vapor
pressures of less than 1 mm of Hg absolute at 25 degrees C.  With these
exceptions, “fluorinated GHG” includes but is not limited to any
hydrofluorocarbon, any perfluorocarbon, any fully fluorinated linear,
branched or cyclic alkane, ether, tertiary amine or aminoether, any
perfluoropolyether, and any hydrofluoropolyether.  

Fossil fuel means natural gas, petroleum, coal, or any form of solid,
liquid, or gaseous fuel derived from such material, including for
example, consumer products that are derived from such materials and are
combustedfor purpose of creating useful heat.

Fossil fuel-fired means powered by combustion of fossil fuel, alone or
in combination with any other fuel, regardless of the percentage of
fossil fuel consumed.

Fractionators means plants that produce fractionated natural gas liquids
(NGLs) extracted from produced natural gas and separate the NGLs
individual component products: ethane, propane, butanes and pentane-plus
(C5+).  Plants that only process natural gas but do not fractionate NGLs
further into component products are not considered fractionators.  Some
fractionators do not process production gas, but instead fractionate
bulk NGLs received from natural gas processors.  Some fractionators both
process natural gas and fractionate bulk NGLs received from other
plants.

Fuel means solid, liquid or gaseous combustible material.

Fuel gas 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.

Fuel gas system means a system of compressors, piping, knock-out pots,
mix drums, and, if necessary, units used to remove sulfur contaminants
from the fuel gas (e.g., amine scrubbers) that collects fuel gas from
one or more sources for treatment, as necessary, and transport to a
stationary combustion unit.  A fuel gas system may have an overpressure
vent to a flare but the primary purpose for a fuel gas system is to
provide fuel to the various combustion units at the refinery or
petrochemical plant.

Gas collection system or landfill gas collection system means a system
of pipes used to collect landfill gas from different locations in the
landfill to a single location for treatment (thermal destruction) or
use.  Landfill gas collection systems may also include knock-out or
separator drums and/or a compressor.   

Gas-fired unit means a stationary combustion unit that derives more than
50 percent of its annual heat input from the combustion of gaseous
fuels, and the remainder of its annual heat input from the combustion of
fuel oil or other liquid fuels.   

Gas monitor means an instrument that continuously measures the
concentration of a particular gaseous species in the effluent of a
stationary source.

Gaseous fuel means a material that is in the gaseous state at standard
atmospheric temperature and pressure conditions and that is combusted to
produce heat and/or energy.

Gasification means the conversion of a solid or liquid raw material into
a gas.

Gasoline – Other is any gasoline that is not defined elsewhere,
including GTAB (gasoline treated as blendstock).  

Glass melting furnace means a unit comprising a refractory-lined vessel
in which raw materials are charged and melted at high temperature to
produce molten glass.

Glass produced means the weight of glass exiting a glass melting
furnace.

Global warming potential or GWP means the ratio of the time-integrated
radiative forcing from the instantaneous release of one kilogram of a
trace substance relative to that of one kilogram- of a reference gas,
i.e., CO2.  

GPA means the Gas Processors Association.

Greenhouse gas or GHG means carbon dioxide (CO2), methane (CH4), nitrous
oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and other fluorinated greenhouse gases as
defined in this section.

GTBA (gasoline-grade tertiary butyl alcohol,  HYPERLINK
"http://en.wikipedia.org/wiki/Chemical_formula" \o "Chemical formula"  
(CH3)3COH), or t-butanol, is an alcohol as described in "Oxygenates."

Heavy Gas Oils are petroleum distillates with an approximate boiling
range from 651 °F to 1,000 °F. 

Heel means the amount of gas that remains in a shipping container after
it is discharged or off-loaded (that is no more than ten percent of the
volume of the container).

High heat value or HHV means the high or gross heat content of the fuel
with the heat of vaporization included. The water is assumed to be in a
liquid state.

Hydrofluorocarbons or HFCs means a class of GHGs  consisting of
hydrogen, fluorine, and carbon.

Import means, to land on, bring into, or introduce into, any place
subject to the jurisdiction of the United States whether or not such
landing, bringing, or introduction constitutes an importation within the
meaning of the customs laws of the United States, with the following
exemptions:

(1)  Off-loading used or excess fluorinated GHGs or nitrous oxide of
U.S. origin from a ship during servicing.

(2)  Bringing fluorinated GHGs or nitrous oxide into the U.S. from
Mexico where the fluorinated GHGs or nitrous oxide had been admitted
into Mexico in bond and were of U.S. origin. 

(3)  Bringing fluorinated GHGs or nitrous oxide into the U.S. when
transported in a consignment of personal or household effects or in a
similar non-commercial situation normally exempted from U.S. Customs
attention.  

(4)  Bringing fluorinated GHGs or nitrous into U.S. jurisdiction
exclusively for U. S. military purposes.

Importer means any person, company, or organization of record that for
any reason brings a product into the United States from a foreign
country, excluding introduction into U.S. jurisdiction exclusively for
United States military purposes.  An importer is the person, company, or
organization primarily liable for the payment of any duties on the
merchandise or an authorized agent acting on their behalf.  The term
includes, as appropriate:

(1)  The consignee.

(2)  The importer of record. 

(3)  The actual owner.

(4) The transferee, if the right to draw merchandise in a bonded
warehouse has been transferred. 

Indurating furnace means a furnace where unfired taconite pellets,
called green balls, are hardened at high temperatures to produce fired
pellets for use in a blast furnace.  Types of indurating furnaces
include straight gate and grate kiln furnaces.

Industrial greenhouse gases means nitrous oxide or any fluorinated
greenhouse gas.

In-line kiln/raw mill means a system in a portland cement production
process where a dry kiln system is integrated with the raw mill so that
all or a portion of the kiln exhaust gases are used to perform the
drying operation of the raw mill, with no auxiliary heat source used. 
In this system the kiln is capable of operating without the raw mill
operating, but the raw mill cannot operate without the kiln gases, and
consequently, the raw mill does not generate a separate exhaust gas
stream.

Isobutane is a paraffinic branch chain hydrocarbon with molecular
formula C4H10.

Isobutylene is an olefinic branch chain hydrocarbon with molecular
formula C4H8.

Kerosene is a light petroleum distillate with a maximum distillation
temperature of 400 °F at the 10-percent recovery point, a final maximum
boiling point of 572 °F, a minimum flash point of 100 °F, and a
maximum freezing point of -22 °F. Included are No. 1-K and No. 2-K,
distinguished by maximum sulfur content (0.04 and 0.30 percent of total
mass, respectively), as well as all other grades of kerosene called
range or stove oil. Excluded is kerosene-type jet fuel (see definition
herein).

Kerosene-Type Jet Fuel means a kerosene-based product used in commercial
and military turbojet and turboprop aircraft. The product has a maximum
distillation temperature of 400 °F at the 10 percent recovery point and
a final maximum boiling point of 572 °F. Included are Jet A, Jet A-1,
JP-5, and JP-8.

Kiln means an oven, furnace, or heated enclosure used for thermally
processing a mineral or mineral-based substance.

Landfill means an area of land or an excavation in which wastes are
placed for permanent disposal and that is not a land application unit,
surface impoundment, injection well, or waste pile as those terms are
defined under 40 CFR 257.2.

Landfill gas means gas produced as a result of anaerobic decomposition
of waste materials in the landfill.  Landfill gas generally contains 40
to 60 percent methane on a dry basis, typically less than 1 percent
non-methane organic chemicals, and the remainder being carbon dioxide.

Lime is the generic term for a variety of chemical compounds that are
produced by the calcination of limestone or dolomite.  These products
include but are not limited to calcium oxide, high-calcium quicklime,
calcium hydroxide, hydrated lime, dolomitic quicklime, and dolomitic
hydrate.

Liquid/Slurry means a manure management component in which manure is
stored as excreted or with some minimal addition of water to facilitate
handling and is stored in either tanks or earthen ponds, usually for
periods less than one year.

Lubricants include all grades of lubricating oils, from spindle oil to
cylinder oil to those used in greases. Petroleum lubricants may be
produced from distillates or residues.

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

Manure composting means the biological oxidation of a solid waste
including manure usually with bedding or another organic carbon source
typically at thermophilic temperatures produced by microbial heat
production. There are four types of composting employed for manure
management: static, in vessel, intensive windrow and passive windrow.
Static composting typically occurs in an enclosed channel, with forced
aeration and continuous mixing. In vessel composting occurs in piles
with forced aeration but no mixing. Intensive windrow composting occurs
in windrows with regular turning for mixing and aeration. Passive
windrow composting occurs in windrows with infrequent turning for mixing
and aeration.

Maximum rated heat input capacity means the hourly heat input to a unit
(in mmBtu/hr), when it combusts the maximum amount of fuel per hour that
it is capable of combusting on a steady state basis, as of the initial
installation of the unit, as specified by the manufacturer.

Maximum rated input capacity means the maximum charging rate of a
municipal waste combustor unit expressed in tons per day of municipal
solid waste combusted, calculated according to the procedures under 40
CFR 60.58b(j).

Mcf means thousand cubic feet.

Methane conversion factor means the extent to which the CH4 producing
capacity (Bo) is realized in each type of treatment and discharge
pathway and system. Thus, it is an indication of the degree to which the
system is anaerobic.

Methane correction factor means an adjustment factor applied to the
methane generation rate to account for portions of the landfill that
remain aerobic.  The methane correction factor can be considered the
fraction of the total landfill waste volume that is ultimately disposed
of in an anaerobic state.  Managed landfills that have soil or other
cover materials have a methane correction factor of 1.  

Methanol (CH3OH) is an alcohol as described in "Oxygenates."

Midgrade gasoline has an octane rating greater than or equal to 88 and
less than or equal to 90.  This definition applies to the midgrade
categories of Conventional-Summer, Conventional-Winter,
Reformulated-Summer, and Reformulated-Winter. For midgrade categories of
RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition
refers to the expected octane rating of the finished gasoline after
oxygenate has been added to the RBOB or CBOB.

Miscellaneous Products include all refined petroleum products not
defined elsewhere. It includes, but is not limited to, naphtha-type jet
fuel (Jet B and JP-4), petrolatum lube refining by-products (aromatic
extracts and tars), absorption oils, ram-jet fuel, petroleum rocket
fuels, synthetic natural gas feedstocks, waste feedstocks, and specialty
oils. It excludes organic waste sludges, tank bottoms, spent catalysts,
and sulfuric acid.

MMBtu means million British thermal units.

Motor gasoline (finished) means a complex mixture of volatile
hydrocarbons, with or without additives, suitably blended to be used in
spark ignition engines. Motor gasoline includes conventional gasoline,
reformulated gasoline, and all types of oxygenated gasoline. Gasoline
also has seasonal variations in an effort to control ozone levels. This
is achieved by lowering the Reid Vapor Pressure (RVP) of gasoline during
the summer driving season. Depending on the region of the country the
RVP is lowered to below 9.0 psi or 7.8 psi. The RVP may be further
lowered by state regulations.

Mscf means million standard cubic feet.

MTBE (methyl tertiary butyl ether, (CH3)3COCH3) is an ether as described
in "Oxygenates." 

Municipal solid waste landfill or MSW landfill means an entire disposal
facility in a contiguous geographical space where household waste is
placed in or on land.  An MSW landfill may also receive other types of
RCRA Subtitle D wastes (40 CFR 257.2) such as commercial solid waste,
nonhazardous sludge, conditionally exempt small quantity generator
waste, and industrial solid waste.  Portions of an MSW landfill may be
separated by access roads, public roadways, or other public
right-of-ways.  An MSW landfill may be publicly or privately owned.

Municipal solid waste or MSW means solid phase household,
commercial/retail, and/or institutional waste, such as, but not limited
to, yard waste and refuse. Household waste includes material discarded
by single and multiple residential dwellings, hotels, motels, and other
similar permanent or temporary housing establishments or facilities. 
Commercial/retail waste includes material discarded by stores, offices,
restaurants, warehouses, non-manufacturing activities at industrial
facilities, and other similar establishments or facilities.
Institutional waste includes material discarded by schools, nonmedical
waste discarded by hospitals, material discarded by non-manufacturing
activities at prisons and government facilities, and material discarded
by other similar establishments or facilities.  Household,
commercial/retail, and institutional waste does not include used oil,
wood pellets, construction, renovation, and demolition wastes (which
includes, but is not limited to, railroad ties and telephone poles),
clean wood, industrial process or manufacturing wastes, medical waste,
or motor vehicles (including motor vehicle parts or vehicle fluff). 
Household, commercial/retail, and institutional wastes include yard
waste, refuse-derived fuel, and motor vehicle maintenance materials,
limited to vehicle batteries and tires, except where a single waste
stream consisting of tires is combusted in a unit. 

N2O means nitrous oxide.

Naphthas (< 401 °F) is a generic term applied to a petroleum fraction
with an approximate boiling range between 122 °F and 400 °F.  The
naphtha fraction of crude oil is the raw material for gasoline and is
composed largely of paraffinic hydrocarbons.

Natural gas means a naturally occurring mixture of hydrocarbon and
non-hydrocarbon gases found in geologic formations beneath the earth’s
surface, of which its constituents include, but are not limited to, the
principal constituent is methane., heavier hydrocarbons and carbon
dioxide.  Natural gas may be field quality (which varies widely) or
pipeline quality.  For the purposes of this subpart, the definition of
natural gas includes similarly constituted fuels such as field
production gas, process gas, and fuel gas.Natural gas is composed of at
least 70 percent methane by volume or has a high heat value between 910
and 1150 Btu per standard cubic foot.

Natural gas liquids (NGLs) means those hydrocarbons in natural gas that
are separated from the gas as liquids through the process of absorption,
condensation, adsorption, or other methods at lease separators and field
facilities.  Generally, such liquids consist of ethane, propane,
butanes, and pentanes plus.  Bulk NGLs refers to mixtures of NGLs that
are sold or delivered as undifferentiated product from natural gas
processing plants.

Natural gasoline means a mixture of liquid hydrocarbons (mostly pentanes
and heavier hydrocarbons) extracted from natural gas.  It includes
isopentane.   

NIST means the United States National Institute of Standards and
Technology.

Nitric acid production line means a series of reactors and absorbers
used to produce nitric acid. 

Nitrogen excreted is the nitrogen that is excreted by livestock in
manure and urine.

Non-crude feedstocks means any petroleum product or natural gas liquid
that enters the refinery as a feedstock to be further refined or
otherwise used on site.

Non-recovery coke oven battery means a group of ovens connected by
common walls and operated as a unit, where coal undergoes destructive
distillation under negative pressure to produce coke, and which is
designed for the combustion of the coke oven gas from which by-products
are not recovered.

Oil-fired unit means a stationary combustion unit that derives more than
50 percent of its annual heat input from the combustion of fuel oil, and
the remainder of its annual heat input from the combustion of natural
gas or other gaseous fuels.   

Open-ended valve or Lines (OELs) means any valve, except pressure relief
valves, having one side of the valve seat in contact with process fluid
and one side open to atmosphere, either directly or through open piping.

Operating hours means the duration of time in which a process or process
unit is utilized; this excludes shutdown, maintenance, and standby.

Operational change means, for purposes of §98.3(b), a change in the
type of feedstock or fuel used, a change in operating hours, or a change
in process production rate.

Operator means any person who operates or supervises a facility or
supplier.

Other Oils (> 401 °F) are oils with a boiling range equal to or greater
than 401 °F that are generally intended for use as a petrochemical
feedstock and are not defined elsewhere.

Owner means any person who has legal or equitable title to, has a
leasehold interest in, or control of a facility or supplier, except a
person whose legal or equitable title to or leasehold interest in the
facility or supplier arises solely because the person is a limited
partner in a partnership that has legal or equitable title to, has a
leasehold interest in, or control of the facility or supplier shall not
be considered an “owner” of the facility or supplier. 

Oxygenates means substances which, when added to gasoline, increase the
oxygen content of the gasoline. Common oxygenates are ethanol, methyl
tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), tertiary
amyl methyl ether (TAME), diisopropyl ether (DIPE), and methanol. 

Pasture/Range/Paddock means the manure from pasture and range grazing
animals is allowed to lie as deposited, and is not managed.

Pentanes Plus, or C5+, is a mixture of hydrocarbons that is a liquid at
ambient temperature and pressure, and consists mostly of pentanes (five
carbon chain) and higher carbon number hydrocarbons.  Pentanes plus
includes, but is not limited to, normal pentane, isopentane,
hexanes-plus (natural gasoline), and plant condensate.

Perfluorocarbons or PFCs means a class of greenhouse gases consisting on
the molecular level of carbon and fluorine.

Petrochemical means methanol, acrylonitrile, ethylene, ethylene oxide,
ethylene dichloride, and any form of carbon black.

Petrochemical Feedstocks means feedstocks derived from petroleum for the
manufacture of chemicals, synthetic rubber, and a variety of plastics. 
This category is usually divided into naphthas less than 401 °F and
other oils greater than 401 °F.

Petroleum means oil removed from the earth and the oil derived from tar
sands and shale.

Petroleum coke means a black solid residue, obtained mainly by cracking
and carbonizing of petroleum derived feedstocks, vacuum bottoms, tar and
pitches in processes such as delayed coking or fluid coking.  It
consists mainly of carbon (90 to 95 percent), has low ash content, and
may be used as a feedstock in coke ovens. This product is also known as
marketable coke or catalyst coke.

Petroleum product means all refined and semi-refined products that are
produced at a refinery by processing crude oil and other petroleum-based
feedstocks, including petroleum products derived from co-processing
biomass and petroleum feedstock together, but not including plastics or
plastic products.  Petroleum products may be combusted for energy use,
or they may be used either for non-energy processes or as non-energy
products. The definition of petroleum product for importers and
exporters excludes waxes.

Pit storage below animal confinement (deep pits) means the collection
and storage of manure typically below a slatted floor in an enclosed
animal confinement facility. This usually occurs with little or no added
water for periods less than one year.

Portable means designed and capable of being carried or moved from one
location to another. Indications of portability include but are not
limited to wheels, skids, carrying handles, dolly, trailer, or platform.
Equipment is not portable if any one of the following conditions exists:

(1)  The equipment is attached to a foundation. 

(2)  The equipment or a replacement resides at the same location for
more than 12 consecutive months. 

(3)  The equipment is located at a seasonal facility and operates during
the full annual operating period of the seasonal facility, remains at
the facility for at least two years, and operates at that facility for
at least three months each year. 

(4)  The equipment is moved from one location to another in an attempt
to circumvent the portable residence time requirements of this
definition.  

Poultry manure with litter means a manure management system component
that is similar to cattle and swine deep bedding except usually not
combined with a dry lot or pasture.  The system is typically used for
poultry breeder flocks and for the production of meat type chickens
(broiler) and other fowl.

Poultry manure without litter means a manure management system component
that may manage manure in a liquid form, similar to open pits in
enclosed animal confinement facilities.  These systems may alternatively
be designed and operated to dry manure as it accumulates.  The latter is
known as a high-rise manure management system and is a form of passive
windrow manure composting when designed and operated properly.

Precision of a measurement at a specified level(e.g., one percent of
full scale or one percent of the value measured) means that 95 percent
of repeat measurements made by a device or technique are within the
range bounded by the mean of the measurements plus or minus the
specified level.  

Premium grade gasoline is gasoline having an antiknock index, i.e.,
octane rating, greater than 90. This definition applies to the premium
grade categories of Conventional-Summer, Conventional-Winter,
Reformulated-Summer, and Reformulated-Winter. For premium grade
categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter,
this definition refers to the expected octane rating of the finished
gasoline after oxygenate has been added to the RBOB or CBOB.

Pressed and blown glass means glass which is pressed, blown, or both,
into products such as light bulbs, glass fiber, technical glass, and
other products listed in NAICS 327212.

Pressure relief device or pressure relief valve or pressure safety valve
means a safety device used to prevent operating pressures from exceeding
the maximum allowable working pressure of the process equipment.  A
common pressure relief device is but not limited to a spring-loaded
pressure relief valve. Devices that are actuated either by a pressure of
less than or equal to 2.5 psig or by a vacuum are not pressure relief
devices.

Primary fuel means the fuel that provides the greatest percentage of the
annual heat input to a stationary fuel combustion unit.

Process emissions means the emissions from industrial processes (e.g.,
cement production, ammonia production) involving chemical or physical
transformations other than fuel combustion.  For example, the
calcination of carbonates in a kiln during cement production or the
oxidation of methane in an ammonia process results in the release of
process CO2 emissions to the atmosphere. Emissions from fuel combustion
to provide process heat are not part of process emissions, whether the
combustion is internal or external to the process equipment.

Process unit means the equipment assembled and connected by pipes and
ducts to process raw materials and to manufacture either a final product
or an intermediate used in the onsite production of other products.  The
process unit also includes the purification of recovered byproducts. 

Process vent means means a gas stream that: (1) is discharged through a
conveyance to the atmosphere either directly or after passing through a
control device; (2) originates from a unit operation, including but not
limited to reactors (including reformers, crackers, and furnaces, and
separation equipment for products and recovered byproducts); and (3)
contains or has the potential to contain GHG that is generated in the
process.  Process vent does not include safety device discharges,
equipment leaks, gas streams routed to a fuel gas system or to a flare,
discharges from storage tanks.

Propane is a paraffinic hydrocarbon with molecular formula C3H8. 

Propylene is an olefinic hydrocarbon with molecular formula C3H6.

Pulp mill lime kiln means the combustion units (e.g., rotary lime kiln
or fluidized bed calciner) used at a kraft or soda pulp mill to calcine
lime mud, which consists primarily of calcium carbonate, into quicklime,
which is calcium oxide.

Pushing means the process of removing the coke from the coke oven at the
end of the coking cycle.  Pushing begins when coke first begins to fall
from the oven into the quench car and ends when the quench car enters
the quench tower.

Raw mill means a ball and tube mill, vertical roller mill or other size
reduction equipment, that is not part of an in-line kiln/raw mill, used
to grind feed to the appropriate size.  Moisture may be added or removed
from the feed during the grinding operation.  If the raw mill is used to
remove moisture from feed materials, it is also, by definition, a raw
material dryer.  The raw mill also includes the air separator associated
with the raw mill.

RBOB-Summer (reformulated blendstock for oxygenate blending) means a
petroleum product which, when blended with a specified type and
percentage of oxygenate, meets the definition of Reformulated-Summer.

RBOB-Winter (reformulated blendstock for oxygenate blending) means a
petroleum product which, when blended with a specified type and
percentage of oxygenate, meets the definition of Reformulated-Winter.

Reformulated—Summer refers to finished gasoline formulated for use in
motor vehicles, the composition and properties of which meet the
requirements of the reformulated gasoline regulations promulgated by the
U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR
80.41, and summer RVP standards required under 40 CFR 80.27 or as
specified by the state.  Reformulated gasoline excludes Reformulated
Blendstock for Oxygenate Blending (RBOB) as well as other blendstock.

Reformulated—Winter refers to finished gasoline formulated for use in
motor vehicles, the composition and properties of which meet the
requirements of the reformulated gasoline regulations promulgated by the
U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR
80.41, but which do not meet summer RVP standards required under 40 CFR
80.27 or as specified by the state. Note: This category includes
Oxygenated Fuels Program Reformulated Gasoline (OPRG).  Reformulated
gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB)
as well as other blendstock.

Regular grade gasoline  is gasoline having an antiknock index, i.e.,
octane rating, greater than or equal to 85 and less than 88.  This
definition applies to the regular grade categories of
Conventional-Summer, Conventional-Winter, Reformulated-Summer, and
Reformulated-Winter. For regular grade categories of RBOB-Summer,
RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the
expected octane rating of the finished gasoline after oxygenate has been
added to the RBOB or CBOB.

Rendered animal fat, or tallow, means fats extracted from animals which
are generally used as a feedstock in making biodiesel. 

Research and development means those activities conducted in process
units or at laboratory bench-scale settings whose purpose is to conduct
research and development for new processes, technologies, or products
and whose purpose is not for the manufacture of products for commercial
sale, except in a de minimis manner.

Residual Fuel Oil No. 5 (Navy Special) is a classification for the
heavier fuel oil generally used in steam powered vessels in government
service and inshore power plants. It has a minimum flash point of 131
°F.

Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a classification for the
heavier fuel oil generally used for the production of electric power,
space heating, vessel bunkering and various industrial purposes. It has
a minimum flash point of 140 °F.

Residuum is residue from crude oil after distilling off all but the
heaviest components, with a boiling range greater than 1,000 °F. 

Road Oil is any heavy petroleum oil, including residual asphaltic oil
used as a dust palliative and surface treatment on roads and highways. 
It is generally produced in six grades, from 0, the most liquid, to 5,
the most viscous.

Rotary lime kiln means a unit with an inclined rotating drum that is
used to produce a lime product from limestone by calcination.

  SEQ CHAPTER \h \r 1 Safety device means a closure device such as a
pressure relief valve, frangible disc, fusible plug, or any other type
of device which functions exclusively to prevent physical damage or
permanent deformation to a unit or its air emission control equipment by
venting gases or vapors directly to the atmosphere during unsafe
conditions resulting from an unplanned, accidental, or emergency event. 
A safety device is not used for routine venting of gases or vapors from
the vapor headspace underneath a cover such as during filling of the
unit or to adjust the pressure in response to normal daily diurnal
ambient temperature fluctuations.  A safety device is designed to remain
in a closed position during normal operations and open only when the
internal pressure, or another relevant parameter, exceeds the device
threshold setting applicable to the air emission control equipment as
determined by the owner or operator based on manufacturer
recommendations, applicable regulations, fire protection and prevention
codes and practices, or other requirements for the safe handling of
flammable, combustible, explosive, reactive, or hazardous materials.

Semi-refined petroleum product means all oils requiring further
processing.  Included in this category are unfinished oils which are
produced by the partial refining of crude oil and include the following:
naphthas and lighter oils; kerosene and light gas oils; heavy gas oils;
and residuum, and all products that require further processing or the
addition of blendstocks.

Sendout means, in the context of a local distribution company, the total
deliveries of natural gas to customers over a specified time interval
(typically hour, day, month, or year).  Sendout is the sum of gas
received through the city gate, gas withdrawn from on-system storage or
peak shaving plants, and gas produced and delivered into the
distribution system; and is net of any natural gas injected into
on-system storage.  It comprises gas sales, exchange, deliveries, gas
used by company, and unaccounted for gas.  Sendout is measured at the
city gate station, and other on-system receipt points from storage, peak
shaving, and production.  

Sensor means a device that measures a physical quantity/quality or the
change in a physical quantity/quality, such as temperature, pressure,
flow rate, pH, or liquid level.

SF6 means sulfur hexafluoride.

Shutdown means the cessation of operation of an emission source for any
purpose.

Silicon carbide means an artificial abrasive produced from silica sand
or quartz and petroleum coke.

Sinter process means a process that produces a fused aggregate of fine
iron-bearing materials suited for use in a blast furnace.  The sinter
machine is composed of a continuous traveling grate that conveys a bed
of ore fines and other finely divided iron-bearing material and fuel
(typically coke breeze), a burner at the feed end of the grate for
ignition, and a series of downdraft windboxes along the length of the
strand to support downdraft combustion and heat sufficient to produce a
fused sinter product.

Site means any combination of one or more graded pad sites, gravel pad
sites, foundations, platforms, or the immediate physical location upon
which equipment is physically located.

Smelting furnace means a furnace in which lead-bearing materials,
carbon-containing reducing agents, and fluxes are melted together to
form a molten mass of material containing lead and slag.

Solid byproducts means plant matter such as vegetable waste, animal
materials/wastes, and other solid biomass, except for wood, wood waste,
and sulphite lyes (black liquor).

Solid storage is the storage of manure, typically for a period of
several months, in unconfined piles or stacks. Manure is able to be
stacked due to the presence of a sufficient amount of bedding material
or loss of moisture by evaporation.

Sour gas means any gas that contains significant concentrations of
hydrogen sulfide.  Sour gas may include untreated fuel gas, amine
stripper off-gas, or sour water stripper gas. 

Special naphthas means all finished products with the naphtha boiling
range (290° to 470 °F) that are generally used as paint thinners,
cleaners or solvents. These products are refined to a specified flash
point. Special naphthas include all commercial hexane and cleaning
solvents conforming to ASTM Specification D1836-07, Standard
Specification for Commercial Hexanes, and D235-02 (Reapproved 2007),
Standard Specification for Mineral Spirits (Petroleum Spirits)
(Hydrocarbon Dry Cleaning Solvent), respectively.  Naphthas to be
blended or marketed as motor gasoline or aviation gasoline, or that are
to be used as petrochemical and synthetic natural gas (SNG) feedstocks
are excluded.

Spent liquor solids means the dry weight of the solids in the spent
pulping liquor that enters the chemical recovery furnace or chemical
recovery combustion unit.

Spent pulping liquor means the residual liquid collected from on-site
pulping operations at chemical pulp facilities that is subsequently
fired in chemical recovery furnaces at kraft and soda pulp facilities or
chemical recovery combustion units at sulfite or semi-chemical pulp
facilities.

Standard conditions or standard temperature and pressure (STP) means 68
degrees Fahrenheit and 14.7 pounds per square inch absolute.

Steam reforming means a catalytic process that involves a reaction
between natural gas or other light hydrocarbons and steam.  The result
is a mixture of hydrogen, carbon monoxide, carbon dioxide, and water.

Still gas means any form or mixture of gases produced in refineries by
distillation, cracking, reforming, and other processes.  The principal
constituents are methane, ethane, ethylene, normal butane, butylene,
propane, and propylene.

Storage tank means a vessel (excluding sumps) that is designed to
contain an accumulation of crude oil, condensate, intermediate
hydrocarbon liquids, or produced water and that is constructed entirely
of non-earthen materials (e.g., wood, concrete, steel, plastic) that
provide structural support.

Sulfur recovery plant means all process units which recover sulfur or
produce sulfuric acid from hydrogen sulfide (H2S) and/or sulfur dioxide
(SO2) from a common source of sour gas at a petroleum refinery.  The
sulfur recovery plant also includes sulfur pits used to store the
recovered sulfur product, but it does not include secondary sulfur
storage vessels or loading facilities downstream of the sulfur pits. 
For example, a Claus sulfur recovery plant includes:  reactor furnace
and waste heat boiler, catalytic reactors, sulfur pits, and, if present,
oxidation or reduction control systems, or incinerator, thermal
oxidizer, or similar combustion device.  Multiple sulfur recovery units
are a single sulfur recovery plant only when the units share the same
source of sour gas.  Sulfur recovery units that receive source gas from
completely segregated sour gas treatment systems are separate sulfur
recovery plants.

Supplemental fuel means a fuel burned within a petrochemical process
that is not produced within the process itself.

Supplier means a producer, importer, or exporter of a fossil fuel or an
industrial greenhouse gas.

Taconite iron ore processing means an industrial process that separates
and concentrates iron ore from taconite, a low grade iron ore, and heats
the taconite in an indurating furnace to produce taconite pellets that
are used as the primary feed material for the production of iron in
blast furnaces at integrated iron and steel plants.

TAME means tertiary amyl methyl ether, (CH3)2(C2H5)COCH3).

Trace concentrations means concentrations of less than 0.1 percent by
mass of the process stream.

Transform means to use and entirely consume (except for trace
concentrations) nitrous oxide or fluorinated GHGs in the manufacturing
of other chemicals for commercial purposes.  Transformation does not
include burning of nitrous oxide.

Transshipment means the continuous shipment of nitrous oxide or a
fluorinated GHG from a foreign state of origin through the United States
or its territories to a second foreign state of final destination, as
long as the shipment does not enter into United States jurisdiction.  A
transshipment, as it moves through the United States or its territories,
cannot be re-packaged, sorted or otherwise changed in condition.

Trona means the raw material (mineral) used to manufacture soda ash;
hydrated sodium bicarbonate carbonate (e.g.Na2CO3.NaHCO3.2H2O).

Ultimate analysis means the determination of the percentages of carbon,
hydrogen, nitrogen, sulfur, and chlorine and (by difference) oxygen in
the gaseous products and ash after the complete combustion of a sample
of an organic material.

Unfinished oils are all oils requiring further processing, except those
requiring only mechanical blending.

United States means the 50 states, the District of Columbia, and U.S.
possessions and territories.

Unstabilized crude oil means, for the purposes of this part, crude oil
that is pumped from the well to a pipeline or pressurized storage vessel
for transport to the refinery without intermediate storage in a storage
tank at atmospheric pressures.  Unstabilized crude oil is characterized
by having a true vapor pressure of 5 pounds per square inch absolute
(psia) or greater.

Valve means any device for halting or regulating the flow of a liquid or
gas through a passage, pipeline, inlet, outlet, or orifice; including,
but not limited to, gate, globe, plug, ball, butterfly and needle
valves.

Vegetable Oil means oils extracted from vegetation that are generally
used as a feedstock in making biodiesel.

Volatile solids are the organic material in livestock manure and consist
of both biodegradable and non-biodegradable fractions.

Waelz kiln means an inclined rotary kiln in which zinc–containing
materials are charged together with a carbon reducing agent (e.g.,
petroleum coke, metallurgical coke, or anthracite coal).

Waste oil means a petroleum-derived or synthetically-derived oil whose
physical properties have changed as a result of storage, handling or
use, such that the oil cannot be used for its original purpose.  Waste
oil consists primarily of automotive oils (e.g., used motor oil,
transmission oil, hydraulic fluids, brake fluid, etc.) and industrial
oils (e.g., industrial engine oils, metalworking oils, process oils,
industrial grease, etc).

Waxes means a solid or semi-solid material at 77 °F consisting of a
mixture of hydrocarbons obtained or derived from petroleum fractions, or
through a Fischer-Tropsch type process, in which the straight chained
paraffin series predominates.  This includes all marketable wax, whether
crude or refined, with a congealing point between 80 (or 85) and 240 °F
and a maximum oil content of 50 weight percent.

Wood residuals means wood waste recovered from three principal sources: 
municipal solid waste (MSW); construction and demolition debris; and
primary timber processing. Wood residuals recovered from MSW include
wooden furniture, cabinets, pallets and containers, scrap lumber (from
sources other than construction and demolition activities), and urban
tree and landscape residues.  Wood residuals from construction and
demolition debris originate from the construction, repair, remodeling
and demolition of houses and non-residential structures.  Wood residuals
from primary timber processing include bark, sawmill slabs and edgings,
sawdust, and peeler log cores.  Other sources of wood residuals include,
but are not limited to, railroad ties, telephone and utility poles, pier
and dock timbers, wastewater process sludge from paper mills, and
logging residues.

Wool fiberglass means fibrous glass of random texture, including
fiberglass insulation, and other products listed in NAICS 327993.

You means an owner or operator subject to Part 98.

Zinc smelters means a facility engaged in the production of zinc metal,
zinc oxide, or zinc alloy products from zinc sulfide ore concentrates,
zinc calcine, or zinc-bearing scrap and recycled materials through the
use of pyrometallurgical techniques involving the reduction and
volatization of zinc-bearing feed materials charged to a furnace.

§98.7  What standardized methods are incorporated by reference into
this part?

The materials listed in this section are incorporated by reference in
the corresponding sections noted.  These incorporations by reference
were approved by the Director of Federal Register in accordance with 5
U.S.C. 552(a) and 1 CFR part 51.  These materials are incorporated as
they exist on the date of approval, and a notice of any change in the
materials will be published in the Federal Register.  The materials are
available for purchase at the corresponding address in this section. 
The materials are available for inspection at the EPA Docket Center,
Public Reading Room, EPA West Building, Room 3334, 1301 Constitution
Avenue, NW, Washington, DC, phone (202) 566-1744 and at the National
Archives and Records Administration (NARA).  For information on the
availability of this material at NARA, call 202-741-6030, or go to:
http://www.archives.gov/federal_register/code_of_federal_regulations/ibr
_ locations.html.  

(a)  The following material is available for purchase from the
Association of Fertilizer and Phosphate Chemists (AFPC), P. O. Box 1645,
Bartow, Florida 33831, http://afpc.net.

(1)  Phosphate Mining States Methods Used and Adopted by the Association
of Fertilizer and Phosphate Chemists AFPC Manual 10th Edition 2009 -
Version 1.9, incorporation by reference (IBR) approved for §98.264(a)
and §98.264(b).

(b)  [Reserved]The following material is available for purchase from the
American Gas Association (AGA), 400 North Capitol Street, N.W., 4th
Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org.

(1)  AGA Report No. 3 Orifice Metering of Natural Gas and Other Related
Hydrocarbon Fluids Part 1: General Equations & Uncertainty Guidelines
(1990), incorporation by reference (IBR) approved for §98.34(b) and
§98.244(b).(2)  AGA Report No. 3 Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids Part 2: Specification and Installation
Requirements (2000), IBR approved for §98.34(b) and §98.244(b). (3) 
AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter (2003),
IBR approved for §98.244(b) and §98.254(c).(4)  AGA Transmission
Measurement Committee Report No. 7 Measurement of Natural Gas by Turbine
Meter (2006)/February, IBR approved for §98.34(b) and §98.244(b

(c)  The following material is available for purchase from the ASM
International, 9639 Kinsman Road, Materials Park, OH 44073, (440)
338-5151, http://www.asminternational.org.

(1)  ASM CS-104 UNS No. G10460 - Alloy Digest April 1985 (Carbon Steel
of Medium Carbon Content), incorporation by reference (IBR) approved for
§98.174(b).

(2)  [Reserved]

(d)  The following material is available for purchase from the American
Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY
10016-5990, (800) 843-2763, http://www.asme.org.

(1)  ASME MFC-3M–2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved
for §98.34(b), §98.244(b), §98.254(c), §98.344(c), and §98.364(e).

(2)  ASME MFC-4M–1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters, IBR approved for §98.34(b),  §98.244(b), §98.254(c),
§98.344(c), and §98.364(e).

(3)  [Reserved]ASME MFC-5M–1985 (Reaffirmed 1994) Measurement of
Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters,
IBR approved for §98.34(b) and §98.244(b).

(4)  ASME MFC-6M–1998 Measurement of Fluid Flow in Pipes Using Vortex
Flowmeters, IBR approved for §98.34(b),  §98.244(b), §98.254(c),
§98.344(c), and §98.364(e).

(5)  ASME MFC-7M–1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles, IBR approved for §98.34(b),
§98.244(b), §98.254(c), §98.344(c), and §98.364(e).

(6)  [Reserved]ASME MFC-9M–1988 (Reaffirmed 2001) Measurement of
Liquid Flow in Closed Conduits by Weighing Method, IBR approved for
§98.34(b) and §98.244(b).

(7)  ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis
Mass Flowmeters, IBR approved for §98.244(b), §98.254(c), and
§98.344(c).

(8)  ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters, IBR approved for §98.244(b), §98.254(c),
§98.344(c), and §98.364(e).

(9)  [Reserved]ASME MFC-16-2007 Measurement of Liquid Flow in Closed
Conduits with Electromagnetic Flowmeters, IBR approved for §98.244(b).

(10)  ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area
Meters, IBR approved for §98.244(b), §98.254(c),§98.344(c), and
§98.364(e).

(11)  [Reserved]ASME MFC-22-2007 Measurement of Liquid by Turbine
Flowmeters, IBR approved for §98.244(b).

(e)  The following material is available for purchase from the American
Society for Testing and Material (ASTM), 100 Barr Harbor Drive, P.O. Box
CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
http://www.astm.org.

(1)  ASTM C25-06 Standard Test Method for Chemical Analysis of
Limestone, Quicklime, and Hydrated Lime, incorporation by reference
(IBR) approved for §98.114(b), §98.174(b), §98.184(b), §98.194(c),
and §98.334(b).

(2)  ASTM C114-09 Standard Test Methods for Chemical Analysis of
Hydraulic Cement, IBR approved for §98.84(a), §98.84(b), and
§98.84(c).

(3)  ASTM D235-02 (Reapproved 2007) Standard Specification for Mineral
Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), IBR
approved for §98.6.

(4)  ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved
for §98.34(a) and §98.254(e).

(5)  ASTM D388-05 Standard Classification of Coals by Rank, IBR approved
for §98.6.

(6)  ASTM D910-07a Standard Specification for Aviation Gasolines, IBR
approved for §98.6.

(7)  ASTM D1298-99 (Reapproved 2005) Standard Test Method for Density,
Relative Density (Specific Gravity), or API Gravity of Crude Petroleum
and Liquid Petroleum Products by Hydrometer Method, IBR approved for
§98.33(a).[Reserved]

(8)  ASTM D1826-94 (Reapproved 2003) Standard Test Method for Calorific
(Heating) Value of Gases in Natural Gas Range by Continuous Recording
Calorimeter, IBR approved for §98.34(a) and §98.254(e).

(9)  ASTM D1836-07 Standard Specification for Commercial Hexanes, IBR
approved for §98.6.

(10)  ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by
Gas Chromatography, IBR approved for §98.34(b), §98.74(c),
§98.164(b), §98.244(b), §98.254(d), and §98.344(b).

(11)  ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography, IBR approved for §98.34(b),
§98.74(c), §98.164(b), §98.254(d), §98.344(b), and §98.364(c).

(12)  ASTM D2013-07 Standard Practice for Preparing Coal Samples for
Analysis, IBR approved for §98.164(b).

(13)  ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross
Sample of Coal, IBR approved for §98.164(b).

(14)  ASTM D2502-04 Standard Test Method for Estimation of Mean Relative
Molecular Mass of Petroleum Oils From Viscosity Measurements, IBR
approved for §98.34(b) and §98.74(c).

(15)  ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative
Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric
Measurement of Vapor Pressure, IBR approved for §98.34(b) and
§98.74(c).

(16)  ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene
by Gas Chromatography, IBR approved for §98.244(b).

(17)  ASTM D2597-94 (Reapproved 2004) Standard Test Method for Analysis
of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and
Carbon Dioxide by Gas Chromatography, IBR approved for §98.164(b).

(18)  ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate
Analysis of Coal and Coke, IBR approved for §98.74(c), §98.164(b),
§98.244(b), §98.254(i), §98.284(c), §98.284(d), §98.314(c),
§98.314(d), and §98.314(f).

(19)  ASTM D3238-95 (Reapproved 2005) Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method, IBR approved for §98.34(b),
§98.74(c), and §98.164(b).

(20)  ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating
Heat Value, Compressibility Factor, and Relative Density of Gaseous
Fuels, IBR approved for §98.34(a) and §98.254(e).

(21)  ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and
Minor Elements in Combustion Residues from Coal Utilization Processes,
IBR approved for §98.144(b).

(22)  ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum
and Petroleum Products, IBR approved for §98.164(b).

(23)  ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic
Sampling of Petroleum and Petroleum Products, IBR approved for
§98.164(b).

(24)  ASTM D4809-06 Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for §98.34(a) and §98.254(e).

(25)  ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating
Value of Gases in Natural Gas Range by Stoichiometric Combustion, IBR
approved for §98.34(a) and §98.254(e).

(26)  ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants, IBR approved for §98.34(b),
§98.74(c), §98.164(b), §98.244(b), and §98.254(i).

(27)  ASTM D5373-08 Standard Test Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, IBR
approved for §98.34(b), §98.74(c), §98.114(b), §98.164(b),
§98.174(b), §98.184(b), §98.244(b), §98.254(i), §98.274(b),
§98.284(c), §98.284(d), §98.314(c), §98.314(d), §98.314(f), and
§98.334(b).

(28)  [Reserved]ASTM D5865-07a Standard Test Method for Gross Calorific
Value of Coal and Coke, IBR approved for §98.34(a).

(29)  ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of
Process Vents With a Portable Gas Chromatograph, IBR approved for
§98.244(b).

(30)  ASTM D6348-03 Standard Test Method for Determination of Gaseous
Compounds by Extractive Direct Interface Fourier Transform Infrared
(FTIR) Spectroscopy, IBR approved for §98.54(b), and §98.224(b), and
§98.414(n).

(31)  ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal, IBR
approved for §98.164(b).

(32)  ASTM D6751-08 Standard Specification for Biodiesel Fuel Blend
Stock (B100) for Middle Distillate Fuels, IBR approved for §98.6.

(33)  ASTM D6866-08 Standard Test Methods for Determining the Biobased
Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon
Analysis, IBR approved for §98.33(e), §98.34(d), §98.34(e), and
§98.36(e).

(34)  ASTM D6883-04 Standard Practice for Manual Sampling of Stationary
Coal from Railroad Cars, Barges, Trucks, or Stockpiles, IBR approved for
§98.164(b). 

(35)  ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of
Coal, IBR approved for §98.164(b).

(36)  ASTM D7459-08 Standard Practice for Collection of Integrated
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived
Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved
for §98.33(e), §98.34(d), §98.34(e), and §98.36(e).

(37)  ASTM E359-00 (Reapproved 2005)e1 Standard Test Methods for
Analysis of Soda Ash (Sodium Carbonate), IBR approved for §98.294(a)
and §98.294(b).

(38)  ASTM E1019-08 Standard Test Methods for Determination of Carbon,
Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys
by Various Combustion and Fusion Techniques, IBR approved for
§98.174(b).

(39)  ASTM E1747-95 (Reapproved 2005) Standard Guide for Purity of
Carbon Dioxide Used in Supercritical Fluid Applications, IBR approved
for 98.424(b).

(40)  ASTM E1915-07a Standard Test Methods for Analysis of Metal Bearing
Ores and Related Materials by Combustion Infrared-Absorption
Spectrometry, IBR approved for §98.174(b).

(41)  ASTM E1941-04 Standard Test Method for Determination of Carbon in
Refractory and Reactive Metals and Their Alloys, IBR approved for
§98.114(b), §98.184(b), §98.334(b).

(42)  ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography, IBR
approved for §98.164(b), §98.244(b), and §98.254(d), and §98.344(b).

(43)  ASTM D2503-92(2007) Standard Test Method for Relative Molecular
Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of
Vapor Pressure, IBR approved for §98.254(d).

(44)  ASTM D2593-93(2009) Standard Test Method for Butadiene Purity and
Hydrocarbon Impurities by Gas Chromatography, IBR approved for
§98.244(b).

(f)  The following material is available for purchase from the Gas
Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma
74143, (918) 493-3872, http://www.gasprocessors.com.

(1)  [Reserved]GPA 2172-09 Calculation of Gross Heating Value, Relative
Density, Compressibility and Theoretical Hydrocarbon Liquid Content for
Natural Gas Mixtures for Custody Transfer, IBR approved for §98.34(a).

(2)  GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures
by Gas Chromatography, IBR approved for §98.34(a), §98.164(b),
§98.254(d), and §98.344(b).

(g)  The following material is available for purchase from the
International Standards Organization (ISO), 1, ch. de la Voie-Creuse,
Case postale 56, CH-1211 Geneva 20, Switzerland, +41 22 749 01 11,
http://www.iso.org/iso/home.htm.

(1)  ISO 3170: Petroleum liquids—Manual sampling - Third Edition
2004-02-01, IBR approved for §98.164(b).

(2)  ISO 3171: Petroleum Liquids—Automatic pipeline sampling - Second
Edition 1988-12-01, IBR approved for §98.164(b).

(3)  [Reserved]ISO 8316: Measurement of Liquid Flow in Closed Conduits -
Method by Collection of the Liquid in a Volumetric Tank (1987-10-01) -
First Edition, IBR approved for §98.244(b). 

(4)  ISO/TR 15349-1: 1998, Unalloyed steel—Determination of low carbon
content. Part 1: Infrared absorption method after combustion in an
electric resistance furnace (by peak separation) (1998-10-15) - First
Edition, IBR approved for §98.174(b).

(5)  ISO/TR 15349-3: 1998, Unalloyed steel—Determination of low carbon
content. Part 3: Infrared absorption method after combustion in an
electric resistance furnace (with preheating) (1998-10-15) - First
Edition, IBR approved for §98.174(b).

(h)  The following material is available for purchase from the National
Lime Association (NLA), 200 North Glebe Road, Suite 800, Arlington,
Virginia 22203, (703) 243-5463, http://www.lime.org.

(1)  CO2 Emissions Calculation Protocol for the Lime Industry—English
Units Version, February 5, 2008 Revision—National Lime Association,
incorporation by reference (IBR) approved for §98.194(c) and
§98.194(e).

(i)  The following material is available for purchase from the National
Institute of Standards and Technology (NIST), 100 Bureau Drive, Stop
1070, Gaithersburg, MD 20899-1070, (800) 877-8339,
http://www.nist.gov/index.html.

(1)  Specifications, Tolerances, and Other Technical Requirements For
Weighing and Measuring Devices, NIST Handbook 44 (2009), incorporation
by reference (IBR) approved for §98.244(b), §98.254(h), and
§98.344(a).

(j)  The following material is available for purchase from the Technical
Association of the Pulp and Paper Industry (TAPPI), 15 Technology
Parkway South, Norcross, GA 30092, (800) 332-8686, http://www.tappi.org.

(1)  T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation by
reference (IBR) approved for §98.276(c) and §98.277(d).

(2)  T684 om-06 Gross Heating Value of Black Liquor, TAPPI,
incorporation by reference (IBR) approved for §98.274(b).

(k)  The following material is available from the U.S. Environmental
Protection Agency, 1200 Pennsylvania Avenue, NW, Washington, D.C. 20460,
(202) 272-0167, www.epa.gov. 

(1)  Protocol for Measuring Destruction or Removal Efficiency (DRE) of
Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing, Version 1, EPA-430-R-10-003.

§98.8  What are the compliance and enforcement provisions of this part?
 

Any violation of any requirement of this part shall be a violation of
the Clean Air Act, including section 114 (42 U.S.C. §7414).  A
violation includes but is not limited to failure to report GHG
emissions, failure to collect data needed to calculate GHG emissions,
failure to continuously monitor and test as required, failure to retain
records needed to verify the amount of GHG emissions, and failure to
calculate GHG emissions following the methodologies specified in this
part.  Each day of a violation constitutes a separate violation.

§98.9  Addresses.

All requests, notifications, and communications to the Administrator
pursuant to this part, other than submittal of the annual GHG report,
shall be submitted to the following address:

(a)  For U.S. mail.

Director, Climate Change Division

1200 Pennsylvania Ave., NW

Mail Code: 6207J

Washington, DC 20460

(b)  For package deliveries.

Director, Climate Change Division

1310 L St, NW

Washington, DC 20005

Table A-1 of Subpart A—Global Warming Potentials (100-Year Time
Horizon)

Name	CAS #	Chemical formula	Global warming potential (100 yr.)

Carbon dioxide	124-38-9	CO2	1

Methane	74-82-8	CH4	21

Nitrous oxide	10024-97-2	N2O	310

HFC-23	75-46-7	CHF3	11,700

HFC-32	75-10-5	CH2F2	650

HFC-41	593-53-3	CH3F	150

HFC-125	354-33-6	C2HF5	2,800

HFC-134	359-35-3	C2H2F4	1,000

HFC-134a	811-97-2	CH2FCF3	1,300

HFC-143	430-66-0	C2H3F3	300

HFC-143a	420-46-2	C2H3F3	3,800

HFC-152	624-72-6	CH2FCH2F	53

HFC-152a	75-37-6	CH3CHF2	140

HFC-161	353-36-6	CH3CH2F	12

HFC-227ea	431-89-0	C3HF7	2,900

HFC-236cb	677-56-5	CH2FCF2CF3	1,340

HFC-236ea	431-63-0	CHF2CHFCF3	1,370

HFC-236fa	690-39-1	C3H2F6	6,300

HFC-245ca	679-86-7	C3H3F5	560

HFC-245fa	460-73-1	CHF2CH2CF3	1,030

HFC-365mfc	406-58-6	CH3CF2CH2CF3	794

HFC-43-10mee	138495-42-8	CF3CFHCFHCF2CF3	1,300

Sulfur hexafluoride	2551-62-4	SF6	23,900

Trifluoromethyl sulphur pentafluoride	373-80-8	SF5CF3	17,700

Nitrogen trifluoride	7783-54-2	NF3	17,200

PFC-14 (Perfluoromethane)	75-73-0	CF4	6,500

PFC-116 (Perfluoroethane)	76-16-4	C2F6	9,200

PFC-218 (Perfluoropropane)	76-19-7	C3F8	7,000

Perfluorocyclopropane	931-91-9	c-C3F6	17,340

PFC-3-1-10 (Perfluorobutane)	355-25-9	C4F10	7,000

Perfluorocyclobutane	115-25-3	c-C4F8	8,700

PFC-4-1-12 (Perfluoropentane)	678-26-2	C5F12	7,500

PFC-5-1-14

(Perfluorohexane)	355-42-0	C6F14	7,400

PFC-9-1-18	306-94-5	C10F18	7,500

HCFE-235da2 (Isoflurane)	26675-46-7	CHF2OCHClCF3  	350

HFE-43-10pccc (H-Galden 1040x)	E1730133	CHF2OCF2OC2F4OCHF2  	1,870

HFE-125  	3822-68-2	CHF2OCF3  	14,900

HFE-134  	1691-17-4	CHF2OCHF2  	6,320

HFE-143a	421-14-7	CH3OCF3  	756

HFE-227ea  	2356-62-9	CF3CHFOCF3  	1,540

HFE-236ca12 (HG-10)	78522-47-1	CHF2OCF2OCHF2  	2,800

HFE-236ea2 (Desflurane)	57041-67-5	CHF2OCHFCF3	989

HFE-236fa	20193-67-3	CF3CH2OCF3  	487

HFE-245cb2	22410-44-2	CH3OCF2CF3  	708

HFE-245fa1	84011-15-4	CHF2CH2OCF3  	286

HFE-245fa2	1885-48-9	CHF2OCH2CF3  	659

HFE-254cb2	425-88-7	CH3OCF2CHF2  	359

HFE-263fb2	460-43-5	CF3CH2OCH3	11

HFE-329mcc2	67490-36-2	CF3CF2OCF2CHF2  	919

HFE-338mcf2	156053-88-2	CF3CF2OCH2CF3  	552

HFE-338pcc13 (HG-01) 	188690-78-0	CHF2OCF2CF2OCHF2  	1,500

HFE-347mcc3	28523-86-6	CH3OCF2CF2CF3  	575

HFE-347mcf2	E1730135	CF3CF2OCH2CHF2  	374

HFE-347pcf2	406-78-0	CHF2CF2OCH2CF3  	580

HFE-356mec3	382-34-3	CH3OCF2CHFCF3  	101

HFE-356pcc3	160620-20-2	CH3OCF2CF2CHF2  	110

HFE-356pcf2	E1730137	CHF2CH2OCF2CHF2  	265

HFE-356pcf3	35042-99-0	CHF2OCH2CF2CHF2  	502

HFE-365mcf3	378-16-5	CF3CF2CH2OCH3	11

HFE-374pc2	512-51-6	CH3CH2OCF2CHF2	557

HFE-449sl (HFE-7100)

Chemical blend	163702-07-6

163702-08-7	C4F9OCH3

(CF3)2CFCF2OCH3	297

HFE-569sf2 (HFE-7200)

Chemical blend	163702-05-4

163702-06-5	C4F9OC2H5

(CF3)2CFCF2OC2H5	59

Sevoflurane	28523-86-6	CH2FOCH(CF3)2	345

HFE-356mm1	13171-18-1	(CF3)2CHOCH3	27

HFE-338mmz1	26103-08-2	CHF2OCH(CF3)2	380

(Octafluorotetramethy-lene)hydroxymethyl group 	NA	X-(CF2)4CH(OH)-X	73

HFE-347mmy1	22052-84-2	CH3OCF(CF3)2	343

Bis(trifluoromethyl)-methanol  	920-66-1	(CF3)2CHOH	195

2,2,3,3,3-pentafluoropropanol  	422-05-9	CF3CF2CH2OH	42

PFPMIE  	NA	CF3OCF(CF3)CF2OCF2OCF3  	10,300

NA = not available

Table A-2 of Subpart A—Units of Measure Conversions.

To convert from	To	Multiply by

Kilograms (kg)	Pounds (lbs)	2.20462

Pounds (lbs)	Kilograms (kg)	0.45359

Pounds (lbs)	Metric tons	4.53592 x 10-4

Short tons	Pounds (lbs)	2,000

Short tons	Metric tons	0.90718

Metric tons	Short tons	1.10231

Metric tons	Kilograms (kg)	1,000

Cubic meters (m3)	Cubic feet (ft3)	35.31467

Cubic feet (ft3)	Cubic meters (m3)	0.028317

Gallons (liquid, US)	Liters (l)	3.78541

Liters (l)	Gallons (liquid, US)	0.26417

Barrels of Liquid Fuel (bbl)	Cubic meters (m3)	0.15891

Cubic meters (m3)	Barrels of Liquid Fuel (bbl)	6.289

Barrels of Liquid Fuel (bbl)	Gallons (liquid, US)	42

Gallons (liquid, US)	Barrels of Liquid Fuel (bbl)	0.023810

Gallons (liquid, US)	Cubic meters (m3)	0.0037854

Liters (l)	Cubic meters (m3)	0.001

Feet (ft)	Meters (m)	0.3048

Meters (m)	Feet (ft)	3.28084

Miles (mi)	Kilometers (km)	1.60934

Kilometers (km)	Miles (mi)	0.62137

Square feet (ft2)	Acres	2.29568 x 10-5

Square meters (m2)	Acres	2.47105 x 10-4

Square miles (mi2)	Square kilometers (km2)	2.58999

Degrees Celsius (ºC)	Degrees Fahrenheit (ºF)	ºC = (5/9) x ( ºF-32)

Degrees Fahrenheit (ºF)	Degrees Celsius (ºC)	ºF = (9/5) x ºC + 32

Degrees Celsius (ºC)	Kelvin (K)	K = ºC + 273.15

Kelvin (K)	Degrees Rankine (ºR)	1.8

Joules	Btu	9.47817 x 10-4

Btu	MMBtu	1 x 10-6

Pascals (Pa)	Inches of Mercury (in Hg)	2.95334 x 10-4

Inches of Mercury (inHg)	Pounds per square inch (psi)	0.49110

Pounds per square inch (psi)	Inches of Mercury (in Hg)	2.03625

Subpart C—General Stationary Fuel Combustion Sources

§98.30  Definition of the source category. 

(a)  Stationary fuel combustion sources are devices that combust solid,
liquid, or gaseous fuel, generally for the purposes of producing
electricity, generating steam, or providing useful heat or energy for
industrial, commercial, or institutional  use, or reducing the volume of
waste by removing combustible matter.  Stationary fuel combustion
sources include, but are not limited to, boilers, simple and
combined-cycle combustion turbines, engines, incinerators, and process
heaters.

(b)  This source category does not include:

(1)  Portable equipment, as defined in §98.6. 

(2)  Emergency generators and emergency equipment, as defined in §98.6.

(3)  Irrigation pumps at agricultural operations.

(4)  Flares, unless otherwise required by provisions of another subpart
of 40 CFR part 98this part to use methodologies in this subpart.

(5)  Electricity generating units that are subject to subpart D of this
part.

(c)  For a unit that combusts hazardous waste (as defined in 40 CFR
§261.3 of this chapter), reporting of GHG emissions is not required
unless either of the following conditions apply:

(1)  Continuous emission monitors (CEMS) are used to quantify CO2 mass
emissions.

(2)  Any fuel listed in Table C-1 of this subpart is also combusted in
the unit.  In this case, report GHG emissions from combustion of all
fuels listed in Table C-1 of this subpart.

(d)  You are not required to report GHG emissions from pilot lights.  A
pilot light is a small permanent auxiliary flame that ignites the burner
of a combustion device when the control valve opens. 

§98.31  Reporting threshold. 

You must report GHG emissions under this subpart if your facility
contains one or more stationary fuel combustion sources and the facility
meets the applicability requirements of either §§98.2(a)(1),
98.2(a)(2), or 98.2(a)(3).

§98.32  GHGs to report.

You must report CO2, CH4, and N2O mass emissions from each stationary
fuel combustion unit, except as otherwise indicated in this subpart.    

§98.33  Calculating GHG emissions. 

You must calculate CO2 emissions according to paragraph (a) of this
section, and calculate CH4 and N2O emissions according to paragraph (c)
of this section.  

(a)  CO2 emissions from fuel combustion.  Calculate CO2 mass emissions
by using one of the four calculation methodologies in this paragraphs
(a)(1) through (a)(4) of this section, subject to the applicable
conditions, requirements, and restrictions set forth in paragraph (b) of
this section.  Alternatively, for units that meet the conditions of
paragraph (a)(5) of this section, you may use CO2 mass emissions
calculation methods from part 75 of this chapter, as described in
paragraph (a)(5) of this section.  If you co-fire For units that combust
both biomass fuels with and fossil fuels, you must calculate and report
CO2 emissions from the combustion of biomass separately using the
methods in paragraph (e) of this section, except as otherwise provided
in paragraphs (a)(5)(iv) and (e) of this section and in §98.36(d).

(1)  Tier 1 Calculation Methodology.  Calculate the annual CO2 mass
emissions for each type of fuel by using Equation C-1 or C-1a of this
section (as applicable).

(i)  Use Equation C-1 except when natural gas billing records are used
to quantify fuel usage and gas consumption is expressed in units of
therms.  In that case, use Equation C-1a.

 	(Eq. C-1)

Where:  

CO2 	=	Annual CO2 mass emissions for the specific fuel type (metric
tons).  

Fuel	=	Mass or volume of fuel combusted per year, from company records
as defined in §98.6 (express mass in short tons for solid fuel, volume
in standard cubic feet for gaseous fuel, and volume in gallons for
liquid fuel).

HHV	=	Default high heat value of the fuel, from Table C-1 of this
subpart (mmBtu per mass or mmBtu per volume, as applicable). 

EF	=	Fuel-specific default CO2 emission factor, from Table C-1 of this
subpart (kg CO2/mmBtu).

1 x 10-3	=	Conversion factor from kilograms to metric tons.

(ii)  If natural gas consumption is obtained from billing records and
fuel usage is expressed in therms, use Equation C-1a.

 	(Eq. C-1a)

Where:

CO2 	=	Annual CO2 mass emissions from natural gas combustion (metric
tons).  

Gas	=	Annual natural gas consumption, from billing records (therms). 

EF	=	Fuel-specific default CO2 emission factor for natural gas, from
Table C-1 of this subpart    (kg CO2/mmBtu).

0.1	=	Conversion factor from therms to mmBtu

1 x 10-3	=	Conversion factor from kilograms to metric tons.

(2)  Tier 2 Calculation Methodology.  Calculate the annual CO2 mass
emissions for each type of fuel by using either Equation C2a or C2c of
this section, as appropriate.  

(i)  Equation C-2a of this section applies to any type of fuel listed in
Table C-1 of the subpart, except for municipal solid waste (MSW).  For
MSW combustion, use Equation C-2c of this section. 

 	(Eq. C-2a)

Where:  

CO2  	=	Annual CO2 mass emissions for a specific fuel type (metric
tons). 

Fuel		=	Mass or volume of the fuel combusted during the year, from
company records as defined in §98.6 (express mass in short tons for
solid fuel, volume in standard cubic feet for gaseous fuel, and volume
in gallons for liquid fuel).

HHV	=	Annual average high heat value of the fuel from all valid samples
for the year (mmBtu per mass or volume).  The average HHV shall be
calculated according to the requirements of paragraph (a)(2)(ii) of this
section.

EF 	=	Fuel-specific default CO2 emission factor, from Table C-1 of this
subpart (kg CO2/mmBtu).

1 x 10-3	=	Conversion factor from kilograms to metric tons.

(ii)  The minimum number of HHV samples required sampling frequency for
determining the annual average HHV is specified (e.g., monthly,
quarterly, semi-annually, or by lot) is specified in §98.34.  The
method for computing the annual average HHV is a function of unit size
and how frequently you perform or receive from the fuel supplier the
results of fuel sampling for HHV.  The method is specified in paragraph
(a)(2)(ii)(A) or (a)(2)(ii)(B) of this section, as applicable.

(A)  If the results of fuel sampling are received monthly or more
frequently, then for each unit with a maximum rated heat input capacity
greater than or equal to 100 mmBtu/hr (or for a group of units that
includes at least one unit of that size), the annual average HHV shall
be calculated using Equation C-2b of this section.  If multiple HHV
determinations are made in any month, average the values for the month
arithmetically.

 	(Eq. C-2b)

Where:	

(HHV)annual =	Weighted annual average high heat value of the fuel (mmBtu
per mass or volume).

(HHV)i	=	HMeasured high heat value of the fuel, for month “i”, or,
if applicable, an appropriate substitute data value (mmBtu per mass or
volume).

(Fuel)i	=	Mass or volume of the fuel combusted during month “i,”
from company records (express mass in short tons for solid fuel, volume
in standard cubic feet for gaseous fuel, and volume in gallons for
liquid fuel).

n		=	Number of months in the year that the fuel is burned in the unit.

(B)  If the results of fuel sampling are received less frequently than
monthly, or, for a unit with a maximum rated heat input capacity less
than 100 mmBtu/hr (or a group of such units) regardless of the HHV
sampling frequency, then the annual average HHV shall be computed as the
arithmetic average HHV for all values for the year (including valid
samples and substitute data values under §98.35).  

(iii)  For units that combust municipal solid waste (MSW) and that
produce steam, use Equation C-2c of this section.  Equation C-2c of this
section may also be used for any other solid fuel listed in Table C-1 of
this subpart provided that steam is generated by the unit.  

 	(Eq. C-2c)

Where:

CO2  	=	Annual CO2 mass emissions from MSW or solid fuel combustion
(metric tons).

Steam	=	Total mass of steam generated by MSW or solid fuel combustion
during the reporting year (lb steam).

B	=	Ratio of the boiler’s maximum rated heat input capacity to its
design rated steam output capacity (mmBtu/lb steam).

EF 	=	Fuel-specific default CO2 emission factor, from Table C-1 of this
subpart (kg CO2/mmBtu).

1 x 10-3	=	Conversion factor from kilograms to metric tons.

(3)  Tier 3 Calculation Methodology.  Calculate the annual CO2 mass
emissions for each fuel by using either Equation C3, C4, or C5 of this
section, as appropriate.

(i)  For a solid fuel, use Equation C-3 of this section.

 	(Eq. C-3)

Where:  

CO2 	=	Annual CO2 mass emissions from the combustion of the specific
solid fuel (metric tons). 

Fuel 	=	Annual mass of the solid fuel combusted, from company records as
defined in §98.6 (short tons). 

CC 	=	Annual average carbon content of the solid fuel (percent by
weight, expressed as a decimal fraction, e.g., 95% = 0.95).  The annual
average carbon content shall be determined using the same procedures as
specified for HHV in paragraph (a)(2)(ii) of this section.

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.91	=	Conversion factor from short tons to metric tons.

(ii)  For a liquid fuel, use Equation C-4 of this section.

 	(Eq. C-4)

Where:  

CO2 	=	Annual CO2 mass emissions from the combustion of the specific
liquid fuel (metric tons). 

Fuel	=	Annual volume of the liquid fuel combusted (gallons). The volume
of fuel combusted must be measured directly, using fuel flow meters
calibrated according to §98.3(i).  Fuel billing meters may be used for
this purpose.  Tank drop measurements may also be used.

CC 	=	Annual average carbon content of the liquid fuel (kg C per gallon
of fuel).  The annual average carbon content shall be determined using
the same procedures as specified for HHV in paragraph (a)(2)(ii) of this
section.

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons.

(iii)  For a gaseous fuel, use Equation C-5 of this section.

 	(Eq. C-5)

Where:  

CO2 	=	Annual CO2 mass emissions from combustion of the specific gaseous
fuel (metric tons).

Fuel	=	Annual volume of the gaseous fuel combusted (scf).  The volume of
fuel combusted must be measured directly, using fuel flow meters
calibrated according to §98.3(i).  Fuel billing meters may be used for
this purpose.

CC 	=	Annual average carbon content of the liquid gaseous fuel (kg C per
gallon kg of fuel).  The annual average carbon content shall be
determined using the same procedures as specified for HHV in paragraph
(a)(2)(ii) of this section.

MW	=	Annual average molecular weight of the gaseous fuel (kg/kg-mole). 
The annual average carbon content molecular weight shall be determined
using the same procedures as specified for HHV in paragraph (a)(2)(ii)
of this section.

MVC	=	Molar volume conversion factor (849.5 scf per kg-mole at standard
conditions, as defined in §98.6).

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons.

(iv)  Fuel flow meters that measure mass flow rates may be used for
liquid or gaseous fuels, provided that the fuel density is used to
convert the readings to volumetric flow rates.  The density shall be
measured at the same frequency as the carbon content, using ASTM
D1298-99 (Reapproved 2005) “Standard Test Method for Density, Relative
Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid
Petroleum Products by Hydrometer Method” (incorporated by reference,
see §98.7).  For liquid fuels, you must measure the density using one
of the following appropriate methods.  You may use a method published by
a consensus standards organization, if such a method exists, or you may
use industry standard practice.  Consensus-based standards organizations
include, but are not limited to, the following: ASTM International, the
American National Standards Institute (ANSI), the American Gas
Association (AGA), the American Society of Mechanical Engineers (ASME),
the American Petroleum Institute (API), and the North American Energy
Standards Board (NAESB).  The method(s) used shall be documented in the
Monitoring Plan required under §98.3(g)(5).  Alternatively, for fuel
oil, you may use an applicable default density value provided in
paragraph (a)(3)(v) of this section.  For gaseous fuels, you may
determine the density using any of the following methods.  You may use a
density meter calibrated according to the manufacturer’s instructions,
a method published by a consensus standards organization, or an industry
standard practice.  Document the method used to determine the fuel
density in the Monitoring Plan under §98.3(g)(5).

(v)  The following default density values may be used for fuel oil, in
lieu of using the ASTM method in paragraph (a)(3)(iv) of this section:
6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No. 6
oil.

(4)  Tier 4 Calculation Methodology.  Calculate the annual CO2 mass
emissions from all fuels combusted in a unit, by using quality-assured
data from continuous emission monitoring systems (CEMS).  

(i)  This methodology requires a CO2 concentration monitor and a stack
gas volumetric flow rate monitor, except as otherwise provided in
paragraph (a)(4)(iv) of this section.  Hourly measurements of CO2
concentration and stack gas flow rate are converted to CO2 mass emission
rates in metric tons per hour.  

(ii)  When the CO2 concentration is measured on a wet basis, Equation
C-6 of this section is used to calculate the hourly CO2 emission rates:

 	(Eq. C-6)

Where:  

CO2	=	CO2 mass emission rate (metric tons/hr). 

CCO2 	=	Hourly average CO2 concentration (% CO2).

Q 	=	Hourly average stack gas volumetric flow 	rate (scfh).

5.18 x 10-7	=	Conversion factor (metric tons/scf/% CO2).

(iii)  If the CO2 concentration is measured on a dry basis, a correction
for the stack gas moisture content is required. You shall either
continuously monitor the stack gas moisture content as described in
§75.11(b)(2) of this chapter or, for certain types of fuel, use an
appropriate default moisture percentage.  For coal, wood, and natural
gas combustion, you may use the default moisture values specified in
from §75.11(b)(1) of this chapter.  Alternatively, for any type of
fuel, you may determine an appropriate site-specific default moisture
value (or values), using measurements made with EPA Method 4 -
Determination Of Moisture Content In Stack Gases, in appendix A-3 to
part 60 of this chapter.  If this option is selected, the site-specific
moisture default value(s) must represent the fuel(s) or fuel blends that
are combusted in the unit during normal, stable operation, and must
account for any distinct difference(s) in the stack gas moisture content
associated with different process operating conditions.  For each
site-specific default moisture percentage, at least nine Method 4 runs
are required.  Moisture data from the relative accuracy test audit
(RATA) of a CEMS may be used for this purpose.  Calculate each
site-specific default moisture value by taking the arithmetic average of
the Method 4 runs.  Each site-specific moisture default value shall be
updated whenever the owner or operator believes the current value is
non-representative, due to changes in unit or process operation, but in
any event no less frequently than annually.  Use the updated moisture
value in the subsequent CO2 emissions calculations.  For each unit
operating hour, a moisture correction must be applied to Equation C-6 of
this section as follows:

 	(Eq. C-7)

Where:  

CO2*  	=	Hourly CO2 mass emission rate, corrected for moisture (metric
tons/hr).

CO2 	=	Hourly CO2 mass emission rate from Equation C-6 of this section,
uncorrected (metric tons/hr). 

%H2O	=	Hourly moisture percentage in the stack gas (measured or default
value, as appropriate). 

(iv)  An oxygen (O2) concentration monitor may be used in lieu of a CO2
concentration monitor to determine the hourly CO2 concentrations, in
accordance with Equation F-14a or F-14b (as applicable) in appendix F to
40 CFR part 75 of this chapter, if the effluent gas stream monitored by
the CEMS consists solely of combustion products (i.e., no process CO2
emissions or CO2 emissions from sorbent are mixed with the combustion
products) and if only fuels that are listed in Table 1 in section 3.3.5
of appendix F to 40 CFR part 75 of this chapter are combusted in the
unit.  If the O2 monitoring option is selected, the F-factors used in
Equations F-14a and F-14b shall be determined according to section 3.3.5
or section 3.3.6 of appendix F to 40 CFR part 75 of this chapter, as
applicable.  If Equation F-14b is used, the hourly moisture percentage
in the stack gas shall be determined in accordance with paragraph
(a)(4)(iii) of this sectioneither a measured value in accordance with
§75.11(b)(2) of this chapter, or, for certain types of fuel, a default
moisture value from §75.11(b)(1) of this chapter.

(v)  Each hourly CO2 mass emission rate from Equation C-6 or C-7 of this
section is multiplied by the operating time to convert it from metric
tons per hour to metric tons.  The operating time is the fraction of the
hour during which fuel is combusted (e.g., the unit operating time is
1.0 if the unit operates for the whole hour and is 0.5 if the unit
operates for 30 minutes in the hour).  For common stack configurations,
the operating time is the fraction of the hour during which effluent
gases flow through the common stack.  

(vi)  The hourly CO2 mass emissions are then summed over each calendar
quarter and the quarterly totals are summed to determine the annual CO2
mass emissions.

(vii)  If both biomass and fossil fuel are combusted during the year,
determine and report the biogenic CO2 mass emissions separately, as
described in paragraph (e) of this section.

(viii)  If a portion of the flue gases generated by a unit subject to
Tier 4 (e.g., a slip stream) is continuously diverted from the main flue
gas exhaust system for the purpose of heat recovery or some other
similar process, and then exhausts through a stack that is not equipped
with the continuous emission monitors to measure CO2 mass emissions,
provided that the CO2 concentration in the diverted stream is not
altered in any way (e.g., by chemical reaction or dilution) before the
diverted stream exits to the atmosphere, an estimate of the hourly
average volumetric flow rate (scfh) of the diverted gas stream shall be
made at the point where it exits the main exhaust system, by using the
best available information (e.g., correlations of operating parameters
versus flow measurements made with EPA Method 2 in appendix A-2 to part
60 of this chapter, engineering analysis, or other methods).  Each
hourly average volumetric flow rate (scfh) measured at the main flue gas
stack shall then be added to the corresponding estimate of the hourly
average flow rate of the diverted gas stream, to determine the total
hourly average stack gas volumetric flow rate "Q", for use in Equation
C-6 of this section.  The method use to estimate the hourly flow rate
of the diverted portion of the flue gas exhaust stream shall be
documented in the Monitoring Plan required under §98.3(g)(5).

(5)  Alternative methods for certain units subject to 40 CFR Part 75 of
this chapterwith continuous monitoring systems.  Certain Uunits that are
not subject to the Acid Rain Programsubpart D of this part and that
report data to EPA according to 40 CFR part 75 of this chapter may
qualify to use the alternative methods in this paragraph (a)(5), in lieu
of using any of the four calculation methodology tiers.

(i)  For a unit that combusts only natural gas and/or fuel oil, is not
subject to subpart D of this partthe Acid Rain Program,   monitors and
reports heat input data year-round according to appendix D to 40 CFR
part 75 of this chapter, but is not required by the applicable 40 CFR
part 75 program to report CO2 mass emissions data, calculate the annual
CO2 mass emissions for the purposes of this part as follows: 

(A)  Use the hourly heat input data from appendix D to 40 CFR part 75 of
this chapter, together with Equation G-4 in appendix G to 40 CFR part 75
of this chapter to determine the hourly CO2 mass emission rates, in
units of tons/hr; 

(B)  Use Equations F-12 and F-13 in appendix F to 40 CFR part 75 of this
chapterto calculate the quarterly and cumulative annual CO2 mass
emissions, respectively, in units of short tons; and 

(C)  Divide the cumulative annual CO2 mass emissions value by 1.1 to
convert it to metric tons.

(ii)  For a unit that combusts only natural gas and/or fuel oil, is not
subject to the Acid Rain Programsubpart D of this part, monitors and
reports heat input data year-round according to 40 CFR §75.19 of this
chapter but is not required by the applicable 40 CFR part 75 program to
report CO2 mass emissions data, calculate the annual CO2 mass emissions
for the purposes of this part as follows:

(A)  Calculate the hourly CO2 mass emissions, in units of short tons,
using Equation LM-11 in 40 CFR §75.19(c)(4)(iii) of this chapter.

(B)  Sum the hourly CO2 mass emissions values over the entire reporting
year to obtain the cumulative annual CO2 mass emissions, in units of
short tons.

(C)  Divide the cumulative annual CO2 mass emissions value by 1.1 to
convert it to metric tons.

(iii)  For a unit that is not subject to the Acid Rain Programsubpart D
of this part, uses flow rate and CO2 (or O2) CEMS to report heat input
data year-round according to 40 CFR part 75 of this chapter, but is not
required by the applicable 40 CFR part 75 program to report CO2 mass
emissions data, calculate the annual CO2 mass emissions as follows:

(A)  Use Equation F-11 or F-2 (as applicable) in appendix F to 40 CFR
part 75 of this chapter to calculate the hourly CO2 mass emission rates
from the CEMS data.  If an O2 monitor is used, convert the hourly
average O2 readings to CO2 using Equation F-14a or F-14b in appendix F
to 40 CFR part 75 of this chapter (as applicable), before applying
Equation F-11 or F-2.

(B)  Use Equations F-12 and F-13 in appendix F to 40 CFR part 75 of this
chapter to calculate the quarterly and cumulative annual CO2 mass
emissions, respectively, in units of short tons. 

(C)  Divide the cumulative annual CO2 mass emissions value by 1.1 to
convert it to metric tons.

(Div)  For units that qualify to use the alternative CO2 emissions
calculation methods in paragraphs (a)(5)(i) through (a)(5)(iii) of this
section, Iif both biomass and fossil fuel are combusted during the year,
separate calculation and reporting of the biogenic CO2 mass emissions 
determine and report the biogenic CO2 mass emissions separately, (as
described in paragraph (e) of this section) is optional.  

(b)  Use of the four tiers.  Use of the four tiers of CO2 emissions
calculation methodologies described in paragraph (a) of this section is
subject to the following conditions, requirements, and restrictions:

(1)  The Tier 1 Calculation Methodology:

(i)  May be used for any fuel listed in Table C-1 of this subpart that
is combusted in a unit with a maximum rated heat input capacity of 250
mmBtu/hr or less. 

(ii)  May be used for MSW in a unit of any size that does not produce
steam, if the use of Tier 4 is not required. 

(iii)  May be used for solid, gaseous, or liquid biomass fuels in a unit
of any size provided that the fuel is listed in Table C-1 of this
subpart.

(iv)  May not be used if you routinely perform fuel sampling and
analysis for the fuel high heat value (HHV) or routinely receives the
results of HHV sampling and analysis from the fuel supplier at the
minimum frequency specified in §98.34(a), or at a greater frequency. 
In such cases, Tier 2 shall be used.  This restriction does not apply to
paragraphs (b)(1)(ii) and (b)(1)(v) of this section.

(v)  May be used for natural gas combustion in a unit of any size, in
cases where the annual natural gas consumption is obtained from fuel
billing records in units of therms. 

(2)  The Tier 2 Calculation Methodology:

(i)  May be used for the combustion of any type of fuel in a unit with a
maximum rated heat input capacity of 250 mmBtu/hr or less provided that
the fuel is listed in Table C-1 of this subpart.

(ii)  May be used in a unit with a maximum rated heat input capacity
greater than 250 mmBtu/hr for the combustion of pipeline quality natural
gas and/or distillate fuel oil. 

(iii)  May be used for MSW in a unit of any size that produces steam, if
the use of Tier 4 is not required.  

(3)  The Tier 3 Calculation Methodology:

(i)  May be used for a unit of any size that combusts any type of fuel
listed in Table C-1 of this subpart (except for MSW), unless the use of
Tier 4 is required. 

(ii)  Shall be used for a unit with a maximum rated heat input capacity
greater than 250 mmBtu/hr that combusts any type of fuel listed in Table
C-1 of this subpart (except MSW), unless either of the following
conditions apply:

(A)  The use of Tier 1 or 2 is permitted, as described in paragraphs
(b)(1)(iii), (b)(1)(v), and (b)(2)(ii) of this section.

(B)  The use of Tier 4 is required. 

(iii)  Shall be used for a fuel not listed in Table C-1 of this subpart
and are not exempted under §98.30(c), if the fuel is combusted in a
unit with a maximum rated heat input capacity greater than 250 mmBtu/hr
(or, pursuant to §98.36(c)(3), in a group of units served by a common
supply pipe, having at least one unit with a maximum rated heat input
capacity greater than 250 mmBtu/hr), provided that both of the following
conditions apply:

(A)  The use of Tier 4 is not required.

(B)  The fuel provides 10% or more of the annual heat input to the unit
or, if §98.36(c)(3)applies, to athe group of units served by a common
supply pipe.

(iv)  Shall be used when specified in another applicable subpart of this
part, regardless of unit size.

(4)  The Tier 4 Calculation Methodology:

(i)  May be used for a unit of any size, combusting any type of fuel. 
Tier 4 may also be used for any group of stationary fuel combustion
units, process units, or manufacturing units that share a common stack
or duct.

(ii)  Shall be used if the unit meets all six of the conditions
specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F) of this
section:

(A)  The unit has a maximum rated heat input capacity greater than 250
mmBtu/hr, or if the unit combusts municipal solid waste and has a
maximum rated input capacity greater than 250 600 tons per day of MSW. 

(B)  The unit combusts solid fossil fuel or MSW, either as a the primary
or secondary fuel.

(C)  The unit has operated for more than 1,000 hours in any calendar
year since 2005.

(D)  The unit has installed CEMS that are required either by an
applicable Federal or State regulation or the unit’s operating permit.

(E)  The installed CEMS include a gas monitor of any kind or a stack gas
volumetric flow rate monitor, or both and the monitors have been
certified, either in accordance with the requirements of 40 CFR part 75
of this chapter, part 60 of this chapter, or an applicable State
continuous monitoring program.

(F)  The installed gas or stack gas volumetric flow rate monitors are
required, either by an applicable Federal or State regulation or by the
unit’s operating permit, to undergo periodic quality assurance testing
in accordance with either appendix B to 40 CFR part 75 of this chapter,
appendix F to 40 CFR part 60 of this chapter, or an applicable State
continuous monitoring program.

(iii)  Shall be used for a unit with a maximum rated heat input capacity
of 250 mmBtu/hr or less and for a unit that combusts municipal solid
waste with a maximum rated input capacity of 250 600 tons of MSW per day
or less, if the unit meets all of the following three conditions:

(A)  The unit has both a stack gas volumetric flow rate monitor and a
CO2 concentration monitor.

(B)  The unit meets the conditions specified in paragraphs (b)(4)(ii)(B)
through (b)(4)(ii)(D) of this section.

(C)  The CO2 and stack gas volumetric flow rate monitors meet the
conditions specified in paragraphs (b)(4)(ii)(E) and (b)(4)(ii)(F) of
this section. 

(iv)  May apply to common stack or duct configurations where:

(A)  The combined effluent gas streams from two or more stationary fuel
combustion units are vented through a monitored common stack or duct. 
In this case, Tier 4 shall be used if all of the conditions in paragraph
(b)(4)(iv)(A)(1) of this section or all of the conditions in paragraph
(b)(4)(iv)(A)(2) of this section are met.

(1)  At least one of the units meets the requirements of paragraphs
(b)(4)(ii)(A) through (b)(4)(ii)(C) of this section, and the CEMS
installed at the common stack (or duct) meet the requirements of
paragraphs (b)(4)(ii)(D) through (b)(4)(ii)(F) of this section. 

(2)  At least one of the units and the monitors installed at the common
stack or duct meet the requirements of paragraph (b)(4)(iii) of this
section. 

(B)  The combined effluent gas streams from a process or manufacturing
unit and a stationary fuel combustion unit are vented through a
monitored common stack or duct.  In this case, Tier 4 shall be used if
the combustion unit and the monitors installed at the common stack or
duct meet the applicability criteria specified in paragraph
(b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) of this section.   

(C)  The combined effluent gas streams from two or more manufacturing or
process units are vented through a common stack or duct.  In this case,
if any of the units is required by an applicable subpart of this part to
use Tier 4, the CO2 mass emissions may either be monitored at each
individual unit, or the combined CO2 mass emissions may be monitored at
the common stack or duct.  However, if it is not feasible to monitor the
individual units, the combined CO2 mass emissions shall be monitored at
the common stack or duct.

(5)  The Tier 4 Calculation Methodology shall be used beginning on:

(i)  Starting on January 1, 2010, for a unit that is required to report
CO2 mass emissions beginning on that date, if all of the monitors needed
to measure CO2 mass emissions have been installed and certified by that
date.

(ii)  No later than January 1, 2011, for a unit that is required to
report CO2 mass emissions beginning on January 1, 2010, if  all of the
monitors needed to measure CO2 mass emissions have not been installed
and certified by January 1, 2010.  In this case, you may use Tier 2 or
Tier 3 to report GHG emissions for 2010.  However, if the required CEMS
are certified some time in 2010, you need not wait until January 1, 2011
to begin using Tier 4.  Rather, you may switch from Tier 2 or Tier 3 to
Tier 4 as soon as CEMS certification testing is successfully completed. 
If this reporting option is chosen, you must document the change in CO2
calculation methodology in the Monitoring Plan required under
§98.3(g)(5) and in the GHG emissions report under §98.3(c).  Data
recorded by the CEMS during a certification test period in 2010 may be
used for reporting under this part, provided that the following two
conditions are met:

(A)  The certification tests are passed in sequence, with no test
failures. 

(B)  No unscheduled maintenance or repair of the CEMS is performed
during the certification test period. 

(iii)  No later than 180 days following the date on which a change is
made that triggers Tier 4 applicability under paragraph (b)(4)(ii) or
(b)(4)(iii) of this section (e.g., a change in the primary fuel, manner
of unit operation, or installed continuous monitoring equipment).  

(6)  You may elect to use any applicable higher tier for one or more of
the fuels combusted in a unit.  For example, if a 100 mmBtu/hr unit
combusts natural gas and distillate fuel oil, you may elect to use Tier
1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could
have been used for both fuels.  However, for units that use either the
Tier 4 or the alternative calculation methodology specified in paragraph
(a)(5)(iii) of this section, CO2 emissions from the combustion of all
fuels shall be based solely on CEMS measurements. 

(c)  Calculation of CH4 and N2O emissions from stationary combustion
sources.  You must calculate annual CH4 and N2O mass emissions only for
units that are required to report CO2 emissions using the calculation
methodologies of this subpart and for only those fuels that are listed
in Table C-2 of this subpart. 

(1)  Use Equation C-8 of this section to estimate CH4 and N2O emissions
for any fuels for which you use the Tier 1 or Tier 3 calculation
methodologies for CO2.  Use the same values for fuel combustion
consumption that you use for the Tier 1 or Tier 3 calculation.

  	(Eq. C-8)

Where:  

CH4 or N2O	=	Annual CH4 or N2O emissions from the combustion of a
particular type of fuel (metric tons).

Fuel		=	Mass or volume of the fuel combusted, either from company
records or directly measured by a fuel flow meter, as applicable (mass
or volume per year).

HHV		=	Default high heat value of the fuel from Table C-1 of this
subpart; alternatively, for Tier 3, if actual HHV data are available for
the reporting year, you may average these data using the procedures
specified in paragraph (a)(2)(ii) of this section, and use the average
value in Equation C-8 (mmBtu per mass or volume).

EF 		=	Fuel-specific default emission factor for CH4 or N2O, from Table
C-2 of this subpart (kg CH4 or N2O per mmBtu).

1 x 10-3	=	Conversion factor from kilograms to metric tons.

(2)  Use Equation C-9a of this section to estimate CH4 and N2O emissions
for any fuels for which you use the Tier 2 Equation C-2a of this section
to estimate CO2 emissions.  Use the same values for fuel combustion
consumption and HHV that you use for the Tier 21 or Tier 3 calculation.

 	(Eq. C-9a)

Where:  

CH4 or N2O	=	Annual CH4 or N2O emissions from the combustion of a
particular type of fuel (metric tons).

Fuel 	=	Mass or volume of the fuel combusted during the reporting year.

HHV 	=	High heat value of the fuel, averaged for all valid measurements
for the reporting year (mmBtu per mass or volume).

EF	=	Fuel-specific default emission factor for CH4 or N2O, from Table
C-2 of this subpart (kg CH4 or N2O per mmBtu).

1 x 10-3 	=	Conversion factor from kilograms to metric tons. 

(3)  Use Equation C-9b of this section to estimate CH4 and N2O emissions
for any fuels for which you use Equation C-2c of this section to
calculate the CO2 emissions.  Use the same values for steam generation
and the ratio “B” that you use for Equation C-2c. 

 	  (Eq. C-9b)

Where:

CH4 or N2O	=	Annual CH4 or N2O emissions from the combustion of a solid
fuel (metric tons).

Steam	=	Total mass of steam generated by solid fuel combustion during
the reporting year (lb steam).

B	=	Ratio of the boiler’s maximum rated heat input capacity to its
design rated steam output (mmBtu/lb steam).

EF	=	Fuel-specific emission factor for CH4 or N2O, from Table C-2 of
this subpart (kg CH4 or N2O per mmBtu).

1 x 10-3 	=	Conversion factor from kilograms to metric tons. 

(4)  Use Equation C-10 of this section for: units in the Acid Rain
Programsubject to subpart D of this part, ; units that qualify for and
elect to use the alternative CO2 mass emissions calculation
methodologies described in paragraph (a)(5) of this section;monitor and
report heat input on a year-round basis according to 40 CFR part 75, and
units that use the Tier 4 Calculation Methodology.  

 	(Eq. C-10)

Where:  

CH4 or N2O	=	Annual CH4 or N2O emissions from the combustion of a
particular type of fuel (metric tons).

(HI)A 		=	Cumulative annual heat input from combustion of the fuel,
derived from the electronic data reports required under §75.64 of this
chapter or, for Tier 4 units, from the best available information as
described in paragraph (c)(4)(ii) of this section (mmBtu).

EF		=	Fuel-specific emission factor for CH4 or N2O, from Table C-2 of
this section (kg CH4 or N2O per mmBtu).

0.001		=	Conversion factor from kg to metric tons.

(i)  If only one type of fuel listed in Table C-2 of this subpart is
combusted during normal operationthe reporting year, substitute the
cumulative annual heat input from combustion of the fuel into Equation
C-10 of this section to calculate the annual CH4 or N2O emissions.  For
units  in the Acid Rain Program and units that report heat input data to
EPA year-round according to part 75 of this chapter, obtain the
cumulative annual heat input directly from the electronic data reports
required under §75.64 of this chapter.  For Tier 4 units, use the best
available information, as described in paragraph (c)(4)(ii)(C) of this
section, to estimate the cumulative annual heat input (HI)A.  

(ii)  If more than one type of fuel listed in Table C-2 of this subpart
is combusted during normal operation the reporting year, use Equation
C-10 of this section separately for each type of fuel, except as
provided in paragraph (c)(4)(ii)(B) of this section.  Determine the
appropriate values of (HI)A as follows:  

(A)  For units in the Acid Rain Program and other units that report heat
input data to EPA year-round according to part 75 of this chapter,
obtain (HI)A for each type of fuel from the electronic data reports
required under §75.64 of this chapter, except as otherwise provided in
paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this section.  

(B)  For a unit that uses CEMS to monitor hourly heat input according to
part 75 of this chapter, the value of (HI)A obtained from the electronic
data reports under §75.64 of this chapter may be attributed exclusively
to the fuel with the highest F-factor, when the reporting option in
3.3.6.5 of appendix F to part 75 of this chapter is selected and
implemented. 

(C)  For Tier 4 units, use the best available information (e.g., fuel
feed rate measurements, fuel heating values, engineering analysis) to
estimate the value of (HI)A for each type of fuel.  Instrumentation used
to make these estimates is not subject to the calibration requirements
of §98.3(i) or to the QA requirements of §98.34. 

(D)  Units in the Acid Rain Program and other units that report heat
input data to EPA year-round according to part 75 of this chapter may
use the best available information described in paragraph (c)(4)(ii)(C)
of this section, to estimate (HI)A for each fuel type, whenever
fuel-specific heat input values cannot be directly obtained from the
electronic data reports under §75.64 of this chapter..  If flow rate
and diluent gas monitors are used to measure the unit heat input, use
the best available information (e.g., fuel feed rate measurements, fuel
heating values, engineering analysis) to estimate the annual heat input
from each type of fuel.   

(5)  When multiple fuels are combusted during the reporting year, sum
the fuel-specific results from Equations C-8, C-9a, C-9b, or C-10 of
this section (as applicable) to obtain the total annual CH4 and N2O
emissions, in metric tons. 

(6)  Calculate the annual CH4 and N2O mass emissions from the combustion
of blended fuels as follows:  

(i)  If the mass or volume of each component fuel in the blend is
measured before the fuels are mixed and combusted, calculate and report
CH4 and N2O emissions separately for each component fuel, using the
applicable procedures in this paragraph (c).     

(ii) If the mass or volume of each component fuel in the blend is not
measured before the fuels are mixed and combusted, a reasonable estimate
of the percentage composition of the blend, based on best available
information, is required. Perform the following calculations for each
component fuel, “i”, that is listed in Table C-2:

(A)  Multiply (% Fuel)i, the estimated mass or volume percentage
(decimal fraction) of component fuel “i”, by the total annual mass
or volume of the blended fuel combusted during the reporting year, to
obtain an estimate of the annual consumption of component “i”;

(B)  Multiply the result from paragraph (c)(6)(ii)(A) of this section by
the HHV of the fuel (default value or, if available, the measured annual
average value), to obtain an estimate of the annual heat input from
component “i”;

(C)  Calculate the annual CH4 and N2O emissions from component “i”,
using Equation C-8, C-9a, or C-10 of this section, as applicable;

(D)  Sum the annual CH4 emissions across all component fuels to obtain
the annual CH4 emissions for the blend. Similarly sum the annual N2O
emissions across all component fuels to obtain the annual N2O emissions
for the blend.  Report these annual emissions totals.  

(d)  Calculation of CO2 from sorbent.  

(1)  When a unit is a fluidized bed boiler, is equipped with a wet flue
gas desulfurization system, or uses other acid gas emission controls
with sorbent injection to remove acid gases, if the chemical reaction
between the acid gas and the sorbent produces CO2 emissions, use
Equation C-11 of this section to calculate the CO2 emissions from the
sorbent, ifexcept when those CO2 emissions are not monitored by CEMS:. 
When a sorbent other than CaCO3 is used, determine site-specific values
of R and MWS. 

 	(Eq. C-11)

Where: 

CO2 	=	CO2 emitted from sorbent for the reporting year (metric tons).

S 	=	Limestone or other sorbent used in the reporting year, from company
records (short tons).

R 	=	1.00, the calcium-to-sulfur stoichiometric ratioThe number of moles
of CO2 released upon capture of one mole of the acid gas species being
removed (R = 1.00 when the sorbent is CaCO3 and the targeted acid gas
species is SO2). 

MWCO2 	=	Molecular weight of carbon dioxide (44).

MWS	=	Molecular weight of sorbent (100 if calcium carbonate).

0.91	=	Conversion factor from short tons to metric tons

(2)  The total annual CO2 mass emissions reported for the unit shall be
the sum of include the CO2 emissions from the combustion process and the
CO2 emissions from the sorbent. 

(e)  Biogenic CO2 emissions from combustion of biomass with other fuels.
 Use the applicable procedures of this paragraph (e) to estimate
biogenic CO2 emissions from units that combust a combination of biomass
and fossil fuels (i.e., either co-fired or blended fuels).  Separate
rReporting of biogenic CO2 emissions from the combined combustion of
biomass and fossil fuels is required only for those biomass fuels listed
in Table C-1 of this section and for municipal solid waste, unless
emissions are measured using CEMS.  In addition, when a biomass fuel
that is not listed in Table C-1 is combusted in a unit that has a
maximum rated heat input greater than 250 mmBtu/hr, if the biomass fuel
accounts for 10% or more of the annual heat input to the unit, and if
the unit does not use CEMS to quantify its annual CO2 mass emissions,
then, pursuant to §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 from combustion of the fuel.  Notwithstanding these
requirements, separate reporting of biogenic CO2 emissions is optional
for units subject to subpart D of this part and for units that use the
CO2 mass emissions calculation methodologies in part 75 of this chapter,
pursuant to paragraph (a)(5) of this section; however, if the owner or
operator opts to report biogenic CO2 emissions separately for these
units, the appropriate method(s) in this paragraph (e) shall be used. 
Separate reporting of biogenic CO2 emissions from the combustion of
tires is also optional, but may be reported by following the provisons
of paragraph (e)(3) of this section.

(1)  If CEMS are not used to measure CO2, You may use Equation C-1 of
this subpart to calculate the annual CO2 mass emissions from the
combustion of the biomass fuels listed in Table C-1 of this subpart
(except MSW and tires), forin a unit of any size, including units
equipped with a CO2 CEMS, except when the use of Tier 2 is required as
specified in paragraph (b)(1)(iv) of this section.  Determine the mass
quantity of biomass combusted using one of the following procedures in
this paragraph (e)(1), as appropriate, and document the selected
procedures in the Monitoring Plan under §98.3(g).:

(i)  Use cCompany records.

(ii)  Follow tThe procedures in paragraph (e)(54) of this section.

(iii)  The best available information, Ffor premixed fuels that contain
biomass and fossil fuels (e.g., liquid fuel mixtures containing
biodiesel), use best available information to determine the mass of
biomass fuels and document the procedure used in the GHG Monitoring Plan
required by §98.3(g)(5). 

(2)  You may use the procedures of this paragraph if the following three
conditions are met: first, a If a CO2 CEMS (or a surrogate O2 monitor)
and a stack gas flow rate monitor are used to determine the annual CO2
mass emissions (either according to 40 CFR part 75 of this chapter, the
Tier 4 Calculation Methodology, or the alternative calculation
methodology specified in paragraph (a)(5)(iii) of this section); and if
both fossil fuel and biomass (except for MSW) are combusted in the unit
during the reporting year, you may use the following procedure to
determine the annual biogenic CO2 mass emissions.  If MSW is combusted
in the unit, follow the procedures in paragraph (e)(3) of this
section.second, neither MSW nor tires is combusted in the unit during
the reporting year; and third, the CO2 emissions consist solely of
combustion products (i.e., no process or sorbent emissions included).

(i)  For each operating hour, use Equation C-12 of this section to
determine the volume of CO2 emitted.

  	(Eq. C-12)

Where:	

VCO2h 	=	Hourly volume of CO2 emitted (scf).

(%CO2)h	=	Hourly average CO2 concentration, measured by the CO2
concentration monitor, or, if applicable, calculated from the hourly
average O2  concentration (%CO2).

Qh	=	Hourly average stack gas volumetric flow rate, measured by the
stack gas volumetric flow rate monitor (scfh).

th 	=	Source operating time (decimal fraction of the hour during which
the source combusts fuel, i.e., 1.0 for a full operating hour, 0.5 for
30 minutes of operation, etc.).

100 	=	Conversion factor from percent to a decimal fraction.

(ii)  Sum all of the hourly VCO2h values for the reporting year, to
obtain Vtotal, the total annual volume of CO2 emitted.

(iii)  Calculate the annual volume of CO2 emitted from fossil fuel
combustion using Equation C-13 of this section.  If two or more types of
fossil fuel are combusted during the year, perform a separate
calculation with Equation C-13 of this section for each fuel and sum the
results.    

  	(Eq. C-13)

Where:  

Vff 	=	Annual volume of CO2 emitted from combustion of a particular
fossil fuel (scf).

Fuel 	=	Total quantity of the fossil fuel combusted in the reporting
year, from company records, as defined in §98.6 (lb for solid fuel,
gallons for liquid fuel, and scf for gaseous fuel).

Fc 	=	Fuel-specific carbon based F-factor, either a default value from
Table 1 in section 3.3.5 of appendix F to 40 CFR part 75 of this
chapter, or a site-specific value determined under section 3.3.6 of
appendix F to 40 CFR part 75 (scf CO2/mmBtu).

HHV 	=	High heat value of the fossil fuel, from fuel sampling and
analysis (annual average value in Btu/lb for solid fuel, Btu/gal for
liquid fuel and Btu/scf for gaseous fuel, sampled as specified (e.g.,
monthly, quarterly, semi-annually, or by lot) in §98.34(a)(2)).  The
average HHV shall be calculated according to the requirements of
paragraph (a)(2)(ii) of this section.

106 	=	Conversion factor, Btu per mmBtu.

(iv)  Subtract Vff from Vtotal to obtain Vbio, the annual volume of CO2
from the combustion of biomass.  If a CEMS is being used to measure the
combined combustion and process emissions from a unit that is subject to
another subpart of part 98, then also subtract CO2 process emissions
from Vtotal to determine Vbio.  The CO2 process emissions must be
calculated according to the requirements of the applicable subpart.

(v)  Calculate the biogenic percentage of the annual CO2
emissions,expressed as a decimal fraction, using Equation C-14 of this
section:

 	(Eq. C-14)

(vi)  Calculate the annual biogenic CO2 mass emissions, in metric tons,
by multiplying the results obtained from Equation C-14 of this section
by the annual CO2 mass emissions in metric tons, as determined:

(A)  Under paragraph (a)(4)(vi) of this section, for units using the
Tier 4 Calculation Methodology.

(B)  Under paragraph (a)(5)(iii)(B) of this section, for units using the
alternative calculation methodology specified in paragraph (a)(5)(iii).

(C)  From the electronic data report required under §75.64 of this
chapter, for units in the Acid Rain Program and other units using CEMS
to monitor and report CO2 mass emissions according to 40 CFR part 75 of
this chapter.  However, before calculating the annual biogenic CO2 mass
emissions, multiply the cumulative annual CO2 mass emissions by 0.91 to
convert from short tons to metric tons. 

(3)  For a unit that combusts MSW, the annual biogenic CO2 emissions
shall be calculated using You must use the procedures in this paragraphs
(e)(3)(i) through (e)(3)(iii) of this section to determine the annual
biogenic CO2 emissions from the combustion of MSW.  These procedures
also may be used for any unit that co-fires biomass and fossil fuels,
including units equipped with a CO2 CEMS, and units for which optional
separate reporting of biogenic CO2 emissions from the combustion of
tires is selected. 

(i)  If the Tier 1 or Tier 2 Use an applicable CO2 emissions calculation
method in this section Calculation Methodology is used to quantify the
total annual CO2 mass emissions from the unit:.

(A)  Use Equation C-1 or C-2c of this subpart, as appropriate, to
calculate the annual CO2 mass emissions from MSW combustion.

(Bii)  Determine the relative proportions of biogenic and non-biogenic
CO2 emissions in the flue gas on a quarterly basis using the method
specified in §98.34(d) (for units that combust MSW as the primary fuel
or as the only fuel with a biogenic component) or in §98.34(e) (for
other units, including units that combust tires).  

(Ciii)  Determine the annual biogenic CO2 mass emissions from the
unitMSW combustion by multiplying the total annual CO2 mass emissions by
the annual average biogenic decimal fraction obtained from §98.34(d) or
§98.34(e), as applicable. 

(ii)  If the unit uses Tier 4 to quantify CO2 emissions:

(A)  Follow the procedures in paragraphs (e)(2)(i) and (ii) of this
section, to determine Vtotal.

(B)  If any fossil fuel was combusted during the year, follow the
procedures in paragraph (e)(2)(iii) of this section, to determine Vff.

(C)  Subtract Vff from Vtotal, to obtain VMSW , the annual volume of CO2
emissions from MSW combustion.

(D)  Determine the annual volume of biogenic CO2 emissions (Vbio) from
MSW combustion as follows.  Multiply the annual volume of CO2 emissions
from MSW combustion (VMSW) by the annual average biogenic decimal
fraction obtained from ASTM D6866-08 and ASTM D7459-08. 

(E)  Calculate the biogenic percentage of the annual CO2 emissions from
the unit, using Equation C-14 of this section.  For the purposes of this
calculation, the term “Vbio” in the numerator of Equation C-14 of
this section shall be the results of the calculation performed under
paragraph (e)(3)(ii)(D) of this section. 

(F)  Calculate the annual biogenic CO2 mass emissions according to
paragraph (e)(2)(vi)(A) of this section.

(4)  [Reserved]As an alternative to the procedures in paragraph (e)(2)
of this section, use ASTM Methods D7459-08 and D6866-08 to determine the
biogenic portion of the annual CO2 emissions, as described in
§98.34(e).  If this option is selected, the results of each
determination shall be expressed as a decimal fraction (e.g., 0.30, if
30 percent of the CO2 is biogenic), and the values shall be averaged
over the reporting year.  The annual biogenic CO2 mass emissions shall
be calculated by multiplying the the total annual CO2 mass emissions by
the annual average biogenic fraction obtained from ASTM D6866-08 and
ASTM D7459-08.

(5)  If Equation C-1 or Equation C-2a of this section is selected to
calculate the annual biogenic mass emissions for wood, wood waste, or
other solid biomass-derived fuel, Equation C-15 of this section may be
used to quantify biogenic fuel consumption, provided that all of the
required input parameters are accurately quantified.  Similar equations
and calculation methodologies based on steam generation and boiler
efficiency may be used, provided that they are documented in the GHG
Monitoring Plan required by §98.3(g)(5). 

 	(Eq. C-15)

Where:

(Fuel)p	=	Quantity of biomass consumed during the measurement period
“p” (tons/year or tons/month, as applicable).

H	=	Average enthalpy of the boiler steam for the measurement period
(Btu/lb).

S	=	Total boiler steam production for the measurement period (lb/month
or lb/year, as applicable).

(HI)nb	=	Heat input from co-fired fossil fuels and non-biomass-derived
fuels for the measurement period, based on company records of fuel usage
and default or measured HHV values (Btu/month or Btu/year, as
applicable).

(HHV)bio	=	Default or measured high heat value of the biomass fuel
(Btu/lb).

(Eff)bio	=	Percent efficiency of biomass-to-energy conversion, expressed
as a decimal fraction.

2000	=	Conversion factor (lb/ton).

§98.34  Monitoring and QA/QC requirements.

The CO2 mass emissions data for stationary fuel combustion sources shall
be monitored as follows: 

(a)  For the Tier 2 Calculation Methodology:

(1)  All fuel samples shall be taken at a location in the fuel handling
system that provides a sample representative of the fuel combusted.  The
fuel sampling and analysis may be performed by either the owner or
operator or the supplier of the fuel.  

(2)  The minimum required frequency of the HHV sampling and analysis for
each type of fuel or fuel mixture (blend) is specified in this
paragraph.  When the specified frequency for a particular fuel or blend
is based on a specified time period (ie.eg., weekly, monthly, quarterly,
or semiannuallyhalf-year), fuel sampling and analysis is required only
for those time periods in which the fuel or blend is combustedunit
operates.  The owner or operator may perform fuel sampling and analysis
more often than the minimum required frequency, in order to obtain a
more representative annual average HHV.   

(i)  For natural gas, semiannual sampling and analysis is required
(i.e., twice in a calendar year, with consecutive samples taken at least
four months apart).

(ii)  For coal and fuel oil, and for any other solid or liquid fuel that
is delivered in lots, analysis of at least one representative sample
from each fuel lot is required.  For fuel oil, as an alternative to
sampling each fuel lot, a sample may be taken upon each addition of oil
to the unit’s storage tank.  Flow proportional sampling, continuous
drip sampling, or daily manual oil sampling may also be used, in lieu of
sampling each fuel lot.  For the purposes of this section, a fuel lot is
defined as either: 

(A)  aA shipment or delivery of a single fuel (e.g., ship load, barge
load, group of trucks, group of railroad cars, oil delivery via pipeline
from a tank farm, etc.); or. 

(B)  If multiple deliveries of a particular type of fuel are received
from the same supply source in a given calendar month, the deliveries
for that month are considered, collectively, to comprise a fuel lot,
requiring only one representative sample.  

(iii)  For liquid fuels other than fuel oil, and for gaseous fuels other
than natural gas (including for fossil fuel-derived gaseous fuels, and
for biogas),; sampling and analysis is required at least once per
calendar quarter. To the extent practicable, consecutive quarterly
samples shall be taken at least 30 days apart.

(iv)  For other solid fuels other than coal and(except MSW), weekly
sampling is required to obtain composite samples, which are then
analyzed monthly.

(v)  For fuel blends that are received already mixed, as described in
paragraph (a)(3)(ii) of this section, determine the HHV of the blend as
follows.  For blends of solid fuels (except MSW), weekly sampling is
required to obtain composite samples, which are analyzed monthly.  For
blends of liquid or gaseous fuels, sampling and analysis is required at
least once per calendar quarter.  More frequent sampling is recommended
if the composition of the blend varies significantly during the year.  

(3)  If different types of fuel (e.g., different ranks of coal or
different grades of fuel oil) are blended prior to combustion, use one
of the following procedures in this paragraph.Special Considerations for
Blending of Fuels.  In situations where different types of fuel listed
in Table C-1 of this subpart (for example, different ranks of coal or
different grades of fuel oil) are in the same state of matter (i.e.,
solid, liquid, or gas), and are blended prior to combustion, use the
following procedures to determine the appropriate CO2 emission factor
and HHV for the blend.  

(i)  Use a weighted HHV value in the emission calculations, based on the
relative proportions of each fuel in the blendIf the fuels to be blended
are received separately, and if the quantity (mass or volume) of each
fuel is measured  before the fuels are mixed and combusted, then, for
each component of the blend, calculate the CO2 mass emissions
separately.  Substitute into Equation C-2a of this subpart the total
measured mass or volume of the component fuel (from company records),
together with the appropriate default CO2 emission factor from Table
C-1, and the annual average HHV, calculated according to
§98.33(a)(2)(ii).  In this case, the fact that the fuels are blended
prior to combustion is of no consequence.

(ii)  Take a representative sample of the blend and analyze it for
HHV.If the fuel is received as a blend (i.e., already mixed), a
reasonable estimate of the relative proportions of the components of the
blend must be made, using the best available information (e.g., the
approximate annual average mass or volume percentage of each fuel, based
on the typical or expected range of values). Determine the appropriate
CO2 emission factor and HHV for use in Equation C-2a of this subpart, as
follows:

(A)  Consider the blend to be the “fuel type,” measure its HHV at
the frequency prescribed in paragraph (a)(2)(v) of this section, and
determine the annual average HHV value for the blend according to
§98.33(a)(2)(ii).   

(B)  Calculate a heat-weighted CO2 emission factor, (EF)B, for the
blend, using Equation C-16 of this section. The heat-weighting in
Equation C-16 is provided by the default HHVs (from Table C-1) and the
estimated mass or volume percentages of the components of the blend.  

(C)  Substitute into Equation C-2a of this subpart, the annual average
HHV for the blend (from paragraph (a)(3)(ii)(A) of this section) and the
calculated value of (EF)B, along with the total mass or volume of the
blend combusted during the reporting year, to determine the annual CO2
mass emissions from combustion of the blend.   

 	(Eq. C-16)

Where:

(EF)B	=	Heat-weighted CO2 emission factor for the blend (kg CO2/mmBtu)

(HHV)I	=	Default high heat value for fuel “i” in the blend, from
Table C-1 (mmBtu per mass or volume)

(%Fuel)I	=	Estimated mass or volume percentage of fuel “i” (mass %
or volume %, as applicable, expressed as a decimal fraction; e.g., 25% =
0.25) 

(EF)I	=	Default CO2 emission factor for fuel “i” from Table C-1
(mmBtu per mass or volume)

(HHV)B	=	Annual average high heat value for the blend, calculated
according to §98.33(a)(2)(ii) (mmBtu per mass or volume) 

(iii)  Note that for the case described in paragraph (a)(3)(ii) of this
section, if measured HHV values for the individual fuels in the blend or
for the blend itself are not routinely received at the minimum frequency
prescribed in paragraph (a)(2) of this section (or at a greater
frequency), and if the unit qualifies to use Tier 1, calculate (HHV)B*,
the heat-weighted default HHV for the blend, using Equation C-17 of this
section.  Then, use Equation C-16 of this section, replacing the term
(HHV)B with (HHV)B* in the denominator, to determine the heat-weighted
CO2 emission factor for the blend.  Finally, substitute into Equation
C-1 of this subpart, the calculated values of (HHV)B* and (EF)B, along
with the total mass or volume of the blend combusted during the
reporting year, to determine the annual CO2 mass emissions from
combustion of the blend.     

 	(Eq. C-17)

Where:

(HHV)B*	=	Heat-weighted default high heat value for the blend (mmBtu per
mass or Volume)

(HHV)I	=	Default high heat value for fuel “i” in the blend, from
Table C-1 (mmBtu per mass or volume)

(%Fuel)I	=	Estimated mass or volume percentage of fuel “i” in the
blend (mass % or volume %, as applicable, expressed as a decimal
fraction)

(iv)  If the fuel blend described in paragraph (a)(3)(ii) of this
section consists of a mixture of fuel(s) listed in Table C-1 of this
subpart and one or more fuels not listed in Table  C-1, calculate CO2
and other GHG emissions 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 this case, Tier 1 shall be used, with the
following modifications to Equations C-17 and C-1, to account for the
fact that not all of the fuels in the blend are listed in Table C-1:

(A)  In Equation C-17, apply the term (Fuel)i only to the Table C-1
fuels.  For each Table C-1 fuel, (Fuel)i will be the estimated mass or
volume percentage of the fuel in the blend, divided by the sum of the
mass or volume percentages of the Table C-1 fuels.  For example, suppose
that a blend consists of two Table C-1 fuels (“A” and “B”) and
one fuel type (“C”) not listed in the Table, and that the volume
percentages of fuels A, B, and C in the blend, expressed as decimal
fractions, are, respectively, 0.50, 0.30, and 0.20.  The term (Fuel)i in
Equation C-17 for fuel A will be 0.50/(0.50 + 0.30) = 0.625, and for
fuel B, (Fuel)i will be 0.30/(0.50 + 0.30) = 0.375.

(B)  In Equation C-1, the term “Fuel” will be equal to the total
mass or volume of the blended fuel combusted during the year multiplied
by the sum of the mass or volume percentages of the Table C-1 fuels in
the blend.  For the example in paragraph (a)(3)(iv)(A) of this section, 
  “Fuel” = (Annual volume of the blend combusted)(0.80).

(4)  If, for a particular type of fuel, HHV sampling and analysis is
performed more often than the minimum frequency specified in paragraphs
(a)(2)of this section, the results of all valid fuel analyses shall be
used in the GHG emission calculations. 

(5)  If, for a particular type of fuel, valid HHV values are obtained at
less than the minimum frequency specifed in paragraphs (a)(2) of this
section, appropriate substitute data values shall be used in the
emissions calculations, in accordance with missing data procedures of
§98.35.

(6)  You must use one of the following appropriate fuel sampling and
analysis methods.  You may use a method published by a consensus
standards organization if such a method exists, or you may use industry
consensus standard practice to determine the high heat values. 
Consensus-based standards organizations include, but are not limited to,
the following: ASTM International, the American National Standards
Institute (ANSI), the American Gas Association (AGA), the American
Society of Mechanical Engineers (ASME), the American Petroleum Institute
(API), and the North American Energy Standards Board (NAESB).   Use any
applicable fuel sampling and analysis methods in this paragraph (a)(6)
to determine the high heat values.  Alternatively, for gaseous fuels,
the HHV may be calculated using chromatographic analysis together with
standard heating values of the fuel constituents, provided that the gas
chromatograph is operated, maintained, and calibrated according to the
manufacturer’s instructions.  The method(s) used shall be documented
in the Monitoring Plan required under §98.3(g)(5).   

(i)  ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid
Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated
by reference, see §98.7). 

(ii)  ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated
by reference, see §98.7).

(iii)  ASTM D1826-94 (Reapproved 2003) Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter (incorporated by reference, see §98.7).

(iv)  ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating
Heat Value, Compressibility Factor, and Relative Density of Gaseous
Fuels (incorporated by reference, see §98.7).

(v)  ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating
Value of Gases in Natural Gas Range by Stoichiometric Combustion
(incorporated by reference, see §98.7).

(vi)  GPA Standard 2172–09 Calculation of Gross Heating Value,
Relative Density, Compressibility and Theoretical Hydrocarbon Liquid
Content for Natural Gas Mixtures for Custody Transfer (incorporated by
reference, see §98.7).

(vii)  GPA Standard 2261–00, Analysis for Natural Gas and Similar
Gaseous Mixtures by Gas Chromatography (incorporated by reference, see
§98.7).

(viii)  ASTM D5865-07a, Standard Test Method for Gross Calorific Value
of Coal and Coke (incorporated by reference, see §98.7).

(b)  For the Tier 3 Calculation Methodology:

(1)  Calibrate You must calibrate each oil and gas flow meter according
to §98.3(i) and the provisions of this paragraph (b)(1).

(i)  Perform calibrations using any of the test methods and procedures
in this paragraph (b)(1)(i).  The method(s) used shall be documented in
the Monitoring Plan required under §98.3(g)(5).:

(A)  You may use an appropriate flow meter calibration method published
by a consensus standards organization, if such a method exists. 
Consensus-based standards organizations include, but are not limited to,
the following: ASTM International, the American National Standards
Institute (ANSI), the American Gas Association (AGA), the American
Society of Mechanical Engineers (ASME), the American Petroleum Institute
(API), and the North American Energy Standards Board (NAESB).An
applicable flow meter test method listed in paragraphs (b)(4)(i) through
(b)(4)(viii) of this section.

(B)  You may use Tthe calibration procedures specified by the flow meter
manufacturer.

(C)  You may use aAn industry-accepted or industry consensus standard
calibration practice.

(ii)  In addition to the initial calibration required by §98.3(i),
recalibrate each fuel flow meter (except for qualifying billing meters
under as otherwise provided in paragraph (b)(1)(iii) of this section)
either annually, at the minimum frequency specified by the manufacturer,
or at the interval specified by the industry consensus standard practice
used.

(iii)  Fuel billing meters are exempted from the initial and ongoing
calibration requirements of this paragraph and from the Monitoring Plan
and recordkeeping requirements of §98.3(g)(5)(i)(C) and (g)(7),
provided that the fuel supplier and the unit combusting the fuel do not
have any common owners and are not owned by subsidiaries or affiliates
of the same company.  Meters used exclusively to measure the flow rates
of fuels that are only used for unit startup or ignition are also
exempted from the initial and ongoing calibration requirements of this
paragraph.

(iv)  For the initial calibration of an orifice, nozzle, or venturi
meter; in-situ calibration of the transmitters is sufficient.  A primary
element inspection (PEI) shall be performed at least once every three
years. 

(v)  For the continuously-operating units and processes described in
§98.3(i)(6), the required flow meter recalibrations and, if necessary,
the PEIs may be postponed until the next scheduled maintenance outage.

(vi)  If a mixture of liquid or gaseous fuels is transported by a common
pipe (e.g., still gas and supplementary natural gas), you must may
either separately meter each of the fuels prior to mixing, using flow
meters calibrated according to §98.3(i), or consider the fuel mixture
to be the “fuel type” and meter the mixed fuel, using ause flow
meters calibrated according to §98.3(i) to measure the mixed fuel at
the common pipe and to separately meter an appropriate subset of the
fuels prior to mixing.  If the latter option is chosen, quantify the
fuels that are not measured prior to mixing by subtracting out the fuels
measured prior to mixing from the fuel measured at the common pipe.

(2)  Oil tank drop measurements (if used to determine liquid fuel use
volume) shall be performed according to any an appropriate method
published by a consensus-based standards organization (e.g., the
American Petroleum Institute).

(3)  The carbon content and, if applicable, molecular weight of the
fuels shall be determined according to the procedures in paragraph
(b)(3). 

(i)  All fuel samples shall be taken at a location in the fuel handling
system that provides a sample representative of the fuel combusted.  The
fuel sampling and analysis may be performed by either the owner or
operator or by the supplier of the fuel.  

(ii)  At aFor each type of fuel, the minimum required frequency , fuel
samples shall be for collecteding and analyzing samples for carbon
content and (if applicable) molecular weight at the frequencyis
specified in this paragraph.  When the sampling frequency is required at
based on a specified time interval period (e.g., weekly, monthly,
quarterly, or semiannuallyhalf-year), fuel sampling and analysis is
required for only those time specified periods in which the fuel is
combustedunit operates.  

(A)  For natural gas, semiannual sampling and analysis is required
(i.e., twice in a calendar year, with consecutive samples taken at least
four months apart).

(B)  For coal and fuel oil and for any other solid or liquid fuel that
is delivered in lots, analysis of at least one representative sample
from each fuel lot is required.  For fuel oil, as an alternative to
sampling each fuel lot, a sample may be taken upn each addition of oil
to the storage tank.  Flow proportional sampling, continuous drip
sampling, or daily manual oil sampling may also be used, in lieu of
sampling each fuel lot.  For the purposes of this section, a fuel lot is
defined as either of the following: 

(1)  aA shipment or delivery of a single fuel (e.g., ship load, barge
load, group of trucks, group of railroad cars, oil delivery via pipeline
from a tank farm, etc.). 

(2)  If multiple deliveries of a particular type of fuel are received
from the same supply source in a given calendar month, the deliveries
for that month are considered, collectively, to comprise a fuel lot,
requiring only one representative sample.   

(C)  For other liquid fuels other than fuel oil, for fossil fuel-derived
gaseous fuels, and for biogas; sampling and analysis is required at
least once per calendar quarter.  To the extent practicable, consecutive
quarterly samples shall be taken at least 30 days apart.

(D)  For other solid fuels other than coal(except MSW), weekly sampling
is required to obtain composite samples, which are then analyzed
monthly.   

(E)  For gaseous fuels other than natural gas and biogas (e.g., refinery
process gas), daily sampling and analysis to determine the carbon
content and molecular weight of the fuel is required if the necessary
continuous, on-line equipment, such as a gas chromatograph, is in place
to make these measurements.  Otherwise, weekly sampling and analysis
shall be performed. 

(F)  For mixtures (blends) of solid fuels, weekly sampling is required
to obtain composite samples, which are analyzed monthly.  For blends of
liquid fuels, and for gas mixtures consisting only of natural gas and
biogas, sampling and analysis is required at least once per calendar
quarter.  For gas mixtures that contain gases other than natural gas
(including biogas), daily sampling and analysis to determine the carbon
content and molecular weight of the fuel is required if continuous,
on-line equipment is in place to make these measurements.  Otherwise,
weekly sampling and analysis shall be performed.

(iii)  If, for a particular type of fuel, sampling and analysis for
carbon content and molecular weight is performed more often than the
minimum frequency specified in paragraph (b)(3) of this section, the
results of all valid fuel analyses shall be used in the GHG emission
calculations. 

(iv)  If, for a particular type of fuel, sampling and analysis for
carbon content and molecular weight is performed at less than the
minimum frequency specifed in paragraph (b)(3) of this section,
appropriate substitute data values shall be used in the emissions
calculations, in accordance with the missing data procedures of §98.35.

(v)  To calculate the CO2 mass emissions from combustion of a blend of
fuels in the same state of matter (solid, liquid, or gas), you may
either:

(A)  Apply Equation C-3, C-4 or C-5 of this subpart (as applicable) to
each component of the blend, if the mass or volume, the carbon content,
and (if applicable), the molecular weight of each component are
accurately measured prior to blending; or 

(B)  Consider the blend to be the “fuel type”.  Then, at the
frequency specified in paragraph (b)(3)(ii)(F) of this section, measure
the carbon content and, if applicable, the molecular weight of the blend
and calculate the annual average value of each parameter in the manner
described in §98.33(a)(2)(ii).  Also measure the mass or volume of the
blended fuel combusted during the reporting year. Substitute these
measured values into Equation C-3, C-4, or C-5 of this subpart (as
applicable).The procedures of paragraphs (a)(3) of this section apply to
carbon content and molecular weight determinations.

(4)  Use any applicable standard method from the following list to
quality assure the data from each fuel flow meter.  

(i)  AGA Report No. 3, Orifice Metering of Natural Gas and Other Related
Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines
(1990) and Part 2: Specification and Installation Requirements
(2000)(incorporated by reference, see §98.7).

(ii)  AGA Transmission Measurement Committee Report No. 7, Measurement
of Gas by Turbine Meters (2006) (incorporated by reference, see §98.7).

(iii)  ASME MFC–3M–2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi (incorporated by reference, see §98.7).

(iv)  ASME MFC–4M–1986 (Reaffirmed 1997), Measurement of Gas Flow by
Turbine Meters (incorporated by reference, see §98.7).

(v)  ASME MFC–5M–1985 (Reaffirmed 1994), Measurement of Liquid Flow
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters
(incorporated by reference, see §98.7).

(vi)  ASME MFC–6M–1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters (incorporated by reference, see §98.7).

(vii)  ASME MFC–7M–1987 (Reaffirmed 1992), Measurement of Gas Flow
by Means of Critical Flow Venturi Nozzles (incorporated by reference,
see §98.7).

(viii)  ASME MFC–9M–1988 (Reaffirmed 2001), Measurement of Liquid
Flow in Closed Conduits by Weighing Method (incorporated by reference,
see §98.7).

(45)  You must use one of the following appropriate fuel sampling and
analysis methods.  You may use a method published by a consensus
standards organization if such a method exists, or you may use industry
consensus standard practice to determine the carbon content and
molecular weight (for gaseous fuel) of the fuel.  Consensus-based
standards organizations include, but are not limited to, the following:
ASTM International, the American National Standards Institute (ANSI),
the American Gas Association (AGA), the American Society of Mechanical
Engineers (ASME), the American Petroleum Institute (API), and the North
American Energy Standards Board (NAESB).  Alternatively, the results of
chromatographic analysis of the fuel may be used, provided that the gas
chromatograph is operated,  maintained, and calibrated according to the
manufacturer’s instructions.  The method(s) used shall be documented
in the Monitoring Plan required under §98.3(g)(5).Use any applicable
methods from the following list to determine the carbon content and
molecular weight (for gaseous fuel) of the fuel. Alternatively, the
results of chromatographic analysis of the fuel may be used, provided
that the gas chromatograph is operated,  maintained, and calibrated
according to the manufacturer’s instructions.

(i)  ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by reference, see §98.7).

(ii)  ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography (incorporated by reference, see
§98.7).

(iii)  ASTM D2502-04 (Reapproved 2002) Standard Test Method for
Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum
Oils from Viscosity Measurements (incorporated by reference, see
§98.7).

(iv)  ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative
Molecular Mass (Relative Molecular Weight) of Hydrocarbons by
Thermoelectric Measurement of Vapor Pressure (incorporated by reference,
see §98.7).

(v)  ASTM D3238-95 (Reapproved 2005) Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method (incorporated by reference, see
§98.7).

(vi)  ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants (incorporated by reference, see
§98.7).

(vii)  ASTM D5373-08 Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of
Coal (incorporated by reference, see §98.7).

(c)  For the Tier 4 Calculation Methodology, the CO2, and flow rate, and
(if applicable) moisture monitors must be certified prior to the
applicable deadline specified in §98.33(b)(5).  

(1)  For initial certification, you may use any one of the following
three procedures in this paragraph.

(i)  Sections §75.20(c)(2), and (c)(4), and (c)(5) though (c)(7) of
this chapter and appendix A to 40 CFR part 75 of this chapter.

(ii)  The calibration drift test and relative accuracy test audit (RATA)
procedures of Performance Specification 3 in appendix B to part 60 of
this chapter (for the CO2 concentration monitor) and Performance
Specification 6 in appendix B to part 60 of this chapter (for the
continuous emission rate monitoring system (CERMS)). 

(iii)  The provisions of an applicable State continuous monitoring
program.

(2)  If an O2 concentration monitor is used to determine CO2
concentrations, the applicable provisions of 40 CFR part 75 of this
chapter, 40 CFR part 60 of this chapter, or an applicable State
continuous monitoring program shall be followed for initial
certification and on-going quality assurance, and all required RATAs of
the monitor shall be done on a percent CO2 basis.    

(3)  For ongoing quality assurance, follow the applicable procedures in
either appendix B to 40 CFR part 75 of this chapter, appendix F to 40
CFR part 60 of this chapter, or an applicable State continuous
monitoring program.  If appendix F to 40 CFR part 60 of this chapter is
selected for on-going quality assurance, perform daily calibration drift
assessments for both the CO2 monitor (or surrogate O2 monitor) and the
flow rate monitor, conduct cylinder gas audits of the CO2 concentration
monitor in three of the four quarters of each year (except for
non-operating quarters), and perform annual RATAs of the CO2
concentration monitor and the CERMS.  

(4)  For the purposes of this part, the stack gas volumetric flow rate
monitor RATAs required by appendix B to 40 CFR part 75 of this chapter
and the annual RATAs of the CERMS required by appendix F to 40 CFR part
60 of this chapter need only be done at one operating level,
representing normal load or normal process operating conditions, both
for initial certification and for ongoing quality assurance.

(5)  If, for any source operating hour, quality assured data are not
obtained with a CO2 monitor (or surrogate O2 monitor), flow rate
monitor, or (if applicable) moisture monitor, use appropriate substitute
data values  in accordance with the missing data provisions of §98.35.

(6)  For certain applications where combined process emissions and
combustion emissions are measured, the CO2 concentrations in the flue
gas may be considerably higher than for combustion emissions alone.  In
such cases, the span of the CO2 monitor may, if necessary, be set higher
than the specified levels in the applicable regulations.  If the CO2
span value is set higher than 20 percent CO2, the cylinder gas audits of
the CO2 monitor under appendix F to part 60 of this chapter may be
performed at 40 to 60 percent and 80 to 100 percent of span, in lieu of
the prescribed calibration levels of 5 to 8 percent CO2 and 10 to 14
percent CO2. 

(7)  Hourly average data from the CEMS shall be validated in a manner
consistent with one of the following: §§60.13(h)(2)(i) through
(h)(2)(vi) of this chapter; §75.10(d)(1) of this chapter; or the hourly
data validation requirements of an applicable State CEM regulation.     

(d)  When municipal solid waste (MSW) is either the primary fuel
combusted in a unit or the only fuel with a biogenic component combusted
in the unit, determine the biogenic portion of the CO2 emissions from
MSW combustion using ASTM D6866-08 Standard Test Methods for Determining
the Biobased Content of Solid, Liquid, and Gaseous Samples Using
Radiocarbon Analysis (incorporated by reference, see §98.7) and ASTM
D7459-08 Standard Practice for Collection of Integrated Samples for the
Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide
Emitted from Stationary Emissions Sources (incorporated by reference,
see §98.7).  Perform the ASTM D7459-08 sampling and the ASTM D6866-08
analysis at least once in every calendar quarter in which MSW is
combusted in the unit.  Collect each gas sample during normal unit
operating conditions while MSW is the only fuel being combusted for at
least 24 consecutive hours or for as long as is deemed necessary to
obtain a representative sample large enough to meet the specifications
of ASTM D6866-08.  One suggested alternative sampling approach would be
to collect an  integrated sample by extracting a small amount of flue
gas (e.g., 1 to 5 cc) in each unit operating hour during the quarter. 
Separate the total annual CO2 emissions into the biogenic and
non-biogenic fractions using the average proportion of biogenic
emissions of all samples analyzed during the reporting year.  Express
the results as a decimal fraction (e.g., 0.30, if 30 percent of the CO2
from MSW combustion is biogenic).  When MSW is the primary fuel for
multiple units at the facility, and the units are fed from aIf there is
a common fuel source of MSW that feeds multiple units at the facility,
performing the testing at only one of the units is sufficient. 

(e)  For other units that use CEMS to measure the total CO2 mass
emissions and combust a combinations of biogenic fuelsbiomass fuel(s)
(or heterogeneous fuels that have a biomass component, e.g., tires) and
(other than MSW) with a fossil (or other non-biogenic) fuel(s), in any
proportions, ASTM D6866-08 and ASTM D7459-08 may be used to determine
the biogenic portion of the CO2 emissions.  Perform the ASTM D7459-08
sampling and the ASTM D6866-08 analysis at least once in every calendar
quarter in which biogenic biomass and non-biogenic fuels are co-fired in
the unit.  The relative proportions of the biogenic and non-biogenic
fuels during the sampling shall be representative of the average fuel
blend for a typical operating year.  Collect each gas sample using ASTM
D7459-08 during normal unit operation for at least 24 consecutive hours
or for as long as is necessary to obtain a representative sample large
enough to meet the specifications of ASTM D6866-08.  If the types of
fuels combusted in the unit and their relative proportions are not
consistent throughout the quarter, more frequent, periodic sampling of
the flue gas should be considered.  For example, an integrated sample
could be collected by extracting a small amount of the flue gas (e.g., 1
to 5 cc) in each unit operating hour of the quarter.  If the primary
fuel for multiple units at the facility consists of tires, and the units
are fed from a common fuel source, testing at only one of the units is
sufficient.  

(f)  Whenever company records are used in the calculation of CO2
emissions, tThe records required under §98.3(g)(2)(i) shall include an
explanation of how the following parameters are determined fromboth the
company records (or, if applicable, from the best available information)
and an explanation of how those records are used to estimate the
following parameters:

(1)  Fuel consumption, when the Tier 1 and Tier 2 Calculation
Methodologies are used, including cases where §98.36(c)(4) applies.

(2)  Fuel consumption, when solid fuel is combusted and the Tier 3
Calculation Methodology is used. 

(3)  Fossil fuel consumption when §98.33(e)(2) applies to a unit that
uses CEMS to quantify CO2 emissions and that combusts both fossil and
biomass fuels.

(4)  Sorbent usage, when §98.33(d) applies.  

(5)  Quantity of steam generated by a unit when §98.33(a)(2)(iii)
applies.

(6)  Biogenic fuel consumption under §98.33(e)(5). 

(7)  Fuel usage for CH4 and N2O emissions calculations under
§98.33(c)(4)(ii).

(8)  Mass of biomass combusted, for premixed fuels that contain biomass
and fossil fuels under §98.33(e)(1)(iii).(g)  As part of the GHG
Monitoring Plan required under §98.3(g)(5), you must document the
procedures used to ensure the accuracy of the estimates of fuel usage,
sorbent usage, steam production, and boiler efficiency (as applicable)
in paragraph (f) of this section, including but not limited to
calibration of weighing equipment, fuel flow meters, steam flow meters,
and other measurement devices.  The estimated accuracy of measurements
made with these devices shall also be recorded, and the technical basis
for these estimates shall be provided.  

§98.35  Procedures for estimating missing data. 

Whenever a quality-assured value of a required parameter is unavailable
(e.g., if a CEMS malfunctions during unit operation or if a required
fuel sample is not taken), a substitute data value for the missing
parameter shall be used in the calculations.  

(a)  For all units subject to the requirements of the Acid Rain Program,
and all other stationary combustion units subject to the requirements of
this part that monitor and report emissions and heat input data in
accordance with 40 CFR part 75 of this chapter, the missing data
substitution procedures in 40 CFR part 75 of this chapter shall be
followed for CO2 concentration, stack gas flow rate, fuel flow rate,
high heating value, and fuel carbon content.  

(b)  For units that use the Tier 1, Tier 2, Tier 3, and Tier 4
Calculation Methodologies, perform missing data substitution as follows
for each parameter:  

(1)  For each missing value of the high heating value, carbon content,
or molecular weight of the fuel, substitute the arithmetic average of
the quality-assured values of that parameter immediately preceding and
immediately following the missing data incident.  If the “after”
value has not been obtained by the time that the GHG emissions report is
due, you may use the “before” value for missing data substitution or
the best available estimate of the parameter, based on all available
process data (e.g., electrical load, steam production, operating hours).
 If, for a particular parameter, no quality-assured data are available
prior to the missing data incident, the substitute data value shall be
the first quality-assured value obtained after the missing data period. 

(2)  For missing records of CO2 concentration, stack gas flow rate,
percent moisture, fuel usage, and sorbent usage, the substitute data
value shall be the best available estimate of the parameter, based on
all available process data (e.g., electrical load, steam production,
operating hours, etc.).  You must document and retain records of the
procedures used for all such estimates.

§98.36  Data reporting requirements.  

(a)  In addition to the facility-level information required under
§98.3, the annual GHG emissions report shall contain the unit-level or
process-level emissions data in paragraphs (b) through (d) of this
section (as applicable) and the emissions verification data in paragraph
(e) of this section.

(b)  Units that use the four tiers.  You shall report the following
information for  stationary combustion units that use the Tier 1, Tier
2, Tier 3, or Tier 4 methodology in §98.33(a) to calculate CO2
emissions, except as otherwise provided in paragraphs (c) and (d) of
this section:

(1)  The unit ID number.

(2)  A code representing the type of unit.

(3)  Maximum rated heat input capacity of the unit, in mmBtu/hr for
boilers and process heaters only and relevant units of measure for other
combustion sources.

(4)  Each type of fuel combusted in the unit during the report year.

(5)  The methodology (i.e., tier) used to calculate the CO2 emissions
for each type of fuel combusted (i.e., Tier 1, 2, 3, or 4).

(6)  The methodology start date, for each fuel type.

(7)  The methodology end date, for each fuel type.

(86)  For a unit that uses Tiers 1, 2, and or 3;:

(i)  tThe annual CO2 mass emissions (including biogenic CO2), and the
annual, CH4, and N2O mass emissions for each type of fuel combusted
during the reporting year, expressed in metric tons of each gas and in
metric tons of CO2e; and

(ii)  Metric tons of biogenic CO2 emissions (if applicable).

(97)  For a unit that uses Tier 4:

(i)  For units that burn fossil fuels only, the annual CO2 emissions for
all fuels combined.  Reporting If the total annual CO2 mass emissions
measured by the CEMS consists entirely of non-biogenic CO2 (i.e., CO2
from fossil fuel combustion plus, if applicable, CO2 from sorbent and/or
process CO2), report the total annual CO2 mass emissions, expressed in
metric tons.  You are not required to report the combustion CO2
emissions by fuel type of fuel is not required.  

(ii)  For units that burn both fossil fuels and biomass, the annual CO2
emissions from combustion of all fossil fuels combined and the annual
CO2 emissions from combustion of all biomass fuels combined.  Reporting
If the total annual CO2 mass emissions measured by the CEMS includes
both biogenic and non-biogenic CO2, separately report the annual
non-biogenic CO2 mass emissions and the annual CO2 mass emissions from
biomass combustion, each expressed in metric tons.  You are not required
to report the combustion CO2 emissions by fuel type of fuel is not
required. 

(iii)  An estimate of the heat input from each type of fuel listed in
Table C-2 of this subpart that was combusted in the unit during the
report year, and the Aannual CH4 and N2O emissions for each type of
these fuels combusted, expressed in metric tons of each gas and in
metric tons of CO2e. 

(108)  Annual CO2 emissions from sorbent (if calculated using Equation
C-11 of this subpart), expressed in metric tons.

(9)  Annual GHG emissions from all fossil fuels burned in the unit
(i.e., the sum of the CO2 , CH4, and N2O emissions), expressed in metric
tons of CO2e.

(10)  Customer meter number for units that combust natural gas.

(c)  Reporting alternatives for units using the four Tiers.  You may use
any of the applicable reporting alternatives of this paragraph to
simplify the unit-level reporting required under paragraph (b) of this
section:

(1)  Aggregation of units.  If a facility contains two or more units
(e.g., boilers or combustion turbines), each of which has a maximum
rated heat input capacity of 250 mmBtu/hr or less, you may report the
combined GHG emissions for the group of units in lieu of reporting GHG
emissions from the individual units, provided that the use of Tier 4 is
not required or elected for any of the units and the units use the same
tier for any common fuels combusted.  If this option is selected, the
following information shall be reported instead of the information in
paragraph (b) of this section:

(i)  Group ID number, beginning with the prefix “GP”.

(ii)  TheAn identification number for eachof units in the group.

(iii)  Cumulative maximum rated heat input capacity of the group
(mmBtu/hr).

(iv)  The highest maximum rated heat input capacity of any unit in the
group (mmBtu/hr).

(v)  Each type of fuel combusted in the group of units during the
reporting year.

(vi)  Annual CO2 mass emissions and annual, CH4, and N2O mass emissions
aggregated for each type of fuel combusted in the group of units during
the report year, expressed in metric tons of each gas and in metric tons
of CO2e. If any of the units burn both fossil fuels and biomass, report
also the annual CO2 emissions from combustion of all fossil fuels
combined and annual CO2 emissions from combustion of all biomass fuels
combined, expressed in metric tons.

(vii)  The methodology (i.e., tier) used to calculate the CO2 mass
emissions for each type of fuel combusted in the units (i.e., Tier 1,
Tier 2, or Tier 3).

(viii)  The methodology start date, for each fuel type.

(ix)  The methodology end date, for each fuel type.

(xviii)  The calculated CO2 mass emissions (if any) from sorbent
expressed in metric tons.

(ix)  Annual GHG emissions from all fossil fuels burned in the group
(i.e., the sum of the CO2 , CH4, and N2O emissions), expressed in metric
tons of CO2e. 

(2)  Monitored common stack or duct configurations.  When the flue gases
from two or more stationary fuel combustion units at a facility are
discharged throughcombined together in a common stack or duct before
exiting to the atmosphere and if CEMS are used to continuously monitor
CO2 mass emissions at the common stack or duct according to the Tier 4
Calculation Methodology, you may report the combined emissions from the
units sharing the common stack or duct, in lieu of separately reporting
the GHG emissions from the individual units.  This monitoring and
reporting alternative may also be used when process off-gases or a
mixture of combustion products and process gases are combined together
in a common stack or duct before exiting to the atmosphere.  Whenever
the common stack or duct monitoring option is applied, tThe following
information shall be reported instead of the information in paragraph
(b) of this section:

(i)  Common stack or duct identification number, beginning with the
prefix “CS”.

(ii)  Identification nNumbers of the units sharing the common stack or
duct.  Report “1” when the flue gas flowing through the common stack
or duct includes both combustion products and process off-gases, and all
of the effluent comes from a single unit (e.g., a furnace, kiln, or
smelter).

(iii)  MCombined maximum rated heat input capacity of each the units
sharing the common stack or duct (mmBtu/hr).  This data element is
required only when all of the units sharing the common stack are
stationary fuel combustion units.

(iv)  Each type of fuel combusted in the units during the year.

(v)  The methodology (tier) used to calculate the CO2 mass emissions,
i.e., Tier 4.

(vi)  The methodology start date.

(vii)  The methodology end date. 

(viiivi)  Total annual CO2 mass emissions measured by the CEMS,
expressed in metric tons.  If the any of the units burn both fossil
fuels and biomass, separately report the annual non-biogenic CO2 mass
emissions (i.e., CO2 from fossil fuel combustion plus, if applicable,
CO2 from sorbent and/or process CO2), annual CO2 emissions from
combustion of fossil fuels, and the annual CO2 mass emissions from
combustion of biomass combustionmeasured at the common stack or duct,
each expressed in metric tons.

(ixvii)  An estimate of the heat input from each type of fuel listed in
Table C-2 of this subpart that was combusted during the report year in
the units sharing the common stack or duct during the report year, and,
for each of these fuels, tThe annual CH4 and N2O mass emissions from the
units sharing the common stack or duct, expressed in metric tons of each
gas and in metric tons of CO2e.

(viii)  Annual GHG emissions from all fossil fuels burned in the group
(i.e., the sum of the CO2 , CH4, and N2O emissions), expressed in metric
tons of CO2e.

(3)  Common pipe configurations.  When two or more  liquid-fired or
gaseous-fired stationary combustion units at a facility combust the same
type of fuel and the fuel is fed to the individual units through a
common supply line or pipe, you may report the combined emissions from
the units served by the common supply line, in lieu of separately
reporting the GHG emissions from the individual units, provided that the
total amount of fuel combusted by the units is accurately measured at
the common pipe or supply line using a fuel flow meter.  For Tier 3
applications, the flow meter shall be that is calibrated in accordance
with §98.34(a) §98.34(b).  If a portion of the fuel measured at the
common pipemain supply line is diverted to either:  a flare; or another
stationary fuel combustion unit (or units), including units that use a
CO2 mass emissions calculation method in part 75 of this chapter; or a
chemical or industrial process (where it is used as a raw material but
not combusted), and the remainder of the fuel is distributed to a group
of combustion units for which you elect to use the common pipe reporting
option, you may use company records to subtract out the diverted portion
of the fuel from the fuel measured at the main supply linecommon pipe
prior to performing the GHG emissions calculations, provided that the
amount of fuel diverted is also measured with a calibrated flow meter
per §98.3(i) for the group of units using the common pipe option.  If
the diverted portion of the fuel is combusted, the GHG emissions from
the diverted portion shall be accounted for in accordance with the
applicable provisions of this part.  When the common pipe option is
selected, the applicable tier shall be used based on the maximum rated
heat input capacity of the largest unit served by the common pipe
configuration, except where the applicable tier is based on criteria
other than unit size. For example, if the maximum rated heat input
capacity of the largest unit is greater than 250 mmBtu/hr, Tier 3 will
apply, unless the fuel transported through the common pipe is natural
gas or distillate oil, in which case Tier 2 may be used, in accordance
with §98.33(b)(2)(ii).  As a second example, in accordance with
§98.33(b)(1)(v), Tier 1 may be used regardless of unit size when
natural gas is transported through the common pipe, if the annual fuel
consumption is obtained from gas billing records in units of therms. 
When the common pipe reporting option is selected, Tthe following
information shall be reported instead of the information in paragraph
(b) of this section:

(i)  Common pipe identification number, beginning with the prefix
“CP”.

(ii)  The identification numbers of the units served by the common pipe.

(iii)  The highest mMaximum rated heat input capacity of eachany unit
served by the common pipe (mmBtu/hr).

(iv)  The fuels combusted in the units during the reporting year.

(v)  The methodology used to calculate the CO2 mass emissions (i.e.,
Tier 1, Tier 2, or Tier 3).

(vi)  If the any of the units burns both fossil fuels and biomass, the
annual CO2 mass emissions from combustion of all fossil fuels and annual
CO2 emissions from combustion of all biomass fuels from the units served
by the common pipe, expressed in metric tons.

(vii)  Annual CO2, mass emissions and annual CH4 and N2O emissions from
each fuel type for the units served by the common pipe, expressed in
metric tons of each gas and in metric tons of CO2e. 

(viii)  Methodology start date

(ix)  Methodology end date

(viii)  Annual GHG emissions from all fossil fuels burned in units
served by the common pipe (i.e., the sum of the CO2, CH4, and N2O
emissions), expressed in metric tons of CO2e. 

(4)  The following alternative reporting option applies to situations
where a common liquid or gaseous fuel supply is shared between one or
more large combustion units, such as boilers or combustion turbines
(including units subject to subpart D of this part); and small
combustion sources on-site, including but not limited to space heaters
and hot water heaters.  In this case, you may simplify reporting by
attributing all of the GHG emissions from combustion of the shared fuel
to the large combustion unit(s), provided that:

(i)  The total quantity of the fuel combusted during the report year in
the units sharing the fuel supply is measured, either at the “gate”
to the facility  or at a point inside the facility, using a fuel flow
meter, billing meter, or tank drop measurements (as applicable);

(ii)  On an annual basis, at least 95 percent (by mass or volume) of the
shared fuel is combusted in the large combustion unit(s), and the
remainder is combusted in the small combustion sources.  Company records
may be used to determine the percentage distribution of the shared fuel
to the large and small units; and

(iii)  The use of this reporting option is documented in the Monitoring
Plan required under §98.3(g)(5).   Indicate in the Monitoring Plan
which units share the common fuel supply and the method used to
demonstrate that this alternative reporting option applies.  For the
small combustion sources on-site, a description of the types of units
and the approximate number of units is sufficient.

(d)  Units subject to 40 CFR part 75 of this chapter.  

(1)  For stationary combustion units that are either subject to the Acid
Rain Program or not in the Acid Rain Program but monitor and report CO2
mass emissions year-round according to 40 CFR part 75 subject to subpart
D of this part, you shall report the following unit-level information: 

(i)  Unit or stack identification numbers.  Use exact same unit, common
stack, common pipe, or multiple stack identification numbers that
represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.)
that are reported under §75.64 of this chapter. 

(ii)  Annual CO2 emissions at each monitored location, expressed in both
short tons and metric tons.  Reporting of biogenic CO2 emissions under
§98.3(c)(4)(ii) and §98.3(c)(4)(iii)(A) is optional.  Subpart D units
are not required to report biogenic CO2 emissions under
§§98.3(c)(4)(ii) and (c)(4)(iii)(A).

(iiiii)  Annual CO2, CH4, and N2O emissions at each monitored location,
for each fuel type listed in Table C-2 that was combusted during the
year (except as otherwise provided in §98.33(c)(4)(ii)(B)), expressed
in metric tons of CO2e.  

(iv)  The total heat input from each fuel listed in Table C-2 that was
combusted during the year (except as otherwise provided in
§98.33(c)(4)(ii)(B)), expressed in mmBtu. 

(iiiv)  Identification of the Part 75 methodology used to determine the
CO2 mass emissions.

(vi)  Methodology start date. 

(vii)  Methodology end date. 

(viii)  Acid Rain Program indicator.

(ix)  Annual CO2 mass emissions from the combustion of biomass,
expressed in metric tons of CO2e (optional).  

(2)  For units that use the alternative CO2 mass emissions calculation
methods for units with continuous monitoring systems provided in
§98.33(a)(5), you shall report the following unit-level information:

(i)  Unit, stack, or pipe ID numbers.  Use exact same unit, common
stack, common pipe, or multiple stack identification numbers that
represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.)
that are reported under §75.64 of this chapter. 

(ii)  For units that use the alternative methods specified in
§98.33(a)(5)(i) and (ii) to monitor and report heat input data
year-round according to appendix D to 40 CFR part 75 of this chapter or
40 CFR §75.19 of this chapter:

(A)  Each type of fuel combusted in the unit during the reporting year.

(B)  The methodology used to calculate the CO2 mass emissions for each
fuel type. 

(C)  Methodology start date.

(D)  Methodology end date.

(EC)  A code or flag to indicate whether heat input is calculated
according to appendix D to 40 CFR part 75 of this chapter or 40 CFR
§75.19 of this chapter.

(DF)  Annual CO2, CH4, and N2O emissions at each monitored location,
across all fuel types, expressed in metric tons of CO2e. 

(G)  Annual heat input from each type of fuel listed in Table C-2 of
this subpart that was combusted during the reporting year, expressed in
mmBtu.

(H)  Annual CH4 and N2O emisions at each monitored location, from each
fuel type listed in Table C-2 of this subpart that was combusted during
the reporting year (except as otherwise provided in
§98.33(c)(4)(ii)(D)), expressed in metric tons CO2e.

(I)  Annual CO2 mass emissions from the combustion of biomass, expressed
in metric tons CO2e (optional).

(iii)  For units with continuous monitoring systems that use the
alternative method for units with continuous monitoring systems in
§98.33(a)(5)(iii) to monitor heat input year-round according to 40 CFR
part 75 of this chapter:

(A)  Each type of Ffuel combusted during the reporting year.

(B)  Methodology used to calculate the CO2 mass emissions.

(C)  Methodology start date.

(D)  Methodology end date.

(EC)  A code or flag to indicate that the heat input data is derived
from CEMS measurements.

(FD)  The total annual CO2, CH4, and N2O emissions at each monitored
location, expressed in metric tons of CO2e. 

(G)  Annual heat input from each type of fuel listed in Table C-2 of
this subpart that was combusted during the reporting year, expressed in
mmBtu.

(H)  Annual CH4 and N2O emisions at each monitored location, from each
fuel type listed in Table C-2 of this subpart that was combusted during
the reporting year (except as otherwise provided in
§98.33(c)(4)(ii)(B)), expressed in metric tons CO2e.

(I)  Annual CO2 mass emissions from the combustion of biomass, expressed
in metric tons CO2e (optional).

(e)  Verification data.  You must keep on file, in a format suitable for
inspection and auditing, sufficient data to verify the reported GHG
emissions.  This data and information must, where indicated in this
paragraph (e), be included in the annual GHG emissions report.  

(1)  The applicable verification data specified in this paragraph (e)
are not required to be kept on file or reported for units that meet any
one of the three following conditions:

(i)  Are subject to the Acid Rain Program.

(ii)  Use the alternative methods for units with continuous monitoring
systems provided in §98.33(a)(5).

(iii)  Are not in the Acid Rain Program, but are required to monitor and
report CO2 mass emissions and heat input data year-round, in accordance
with 40 CFR part 75 of this chapter.  

(2)  For stationary combustion sources using the Tier 1, Tier 2, Tier 3,
and Tier 4 Calculation Methodologies in §98.33(a) to quantify CO2
emissions, the following additional information shall be kept on file
and included in the GHG emissions report, where indicated: 

(i)  For the Tier 1 Calculation Methodology, report the total quantity
of each type of fuel combusted in the unit or group of aggregated units
(as applicable) during the reporting year, in short tons for solid
fuels, gallons for liquid fuels and standard cubic feet or, if
applicable, therms for gaseous fuels.

(ii)  For the Tier 2 Calculation Methodology, report:

(A)  The total quantity of each type of fuel combusted in the unit or
group of aggregated units (as applicable) during each month of the
reporting year.  Express the quantity of each fuel combusted during the
measurement period in  short tons for solid fuels, gallons for liquid
fuels, and scf for gaseous fuels.

(B)  The frequency of the HHV determinations (e.g., once a month, once
per fuel lot).

(C)  The high heat values used in the CO2 emissions calculations for
each type of fuel combusted during the reporting year, in mmBtu per
short ton for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu
per scf for gaseous fuels.  Report a HHV value for each calendar month
in which HHV determination is required.  If multiple values are obtained
in a given month, report the arithmetic average value for the month. 
Specify the date on which each fuel sample was taken. Indicate whether
each reported HHV is a measured value ofor a substitute data value.

(D)  If Equation C-2c of this subpart is used to calculate CO2 mass
emissions, report the total quantity (i.e., pounds) of steam produced
from MSW or solid fuel combustion during each month of the reporting
year, and the ratio of the maximum rate heat input capacity to the
design rated steam output capacity of the unit, in mmBtu per lb of
steam.  

(iii)  For the Tier 2 Calculation Methodology, keep records of the
methods used to determine the HHV for each type of fuel combusted and
the date on which each fuel sample was taken, except where fuel sampling
data are received from the fuel supplier.  In that case, keep records of
the dates on which the results of the fuel analyses for HHV are
received. 

(iv)  For the Tier 3 Calculation Methodology, report: 

(A)  The quantity of each type of fuel combusted in the unit or group of
units (as applicable) during each month of the reporting year, in short
tons for solid fuels, gallons for liquid fuels, and scf for gaseous
fuels.

(B)  The frequency of carbon content and, if applicable, molecular
weight determinations for each type of fuel for the reporting year
(e.g., daily, weekly, monthly, semiannually, once per fuel lot).  

(C)  The carbon content and, if applicable, gas molecular weight values
used in the emission calculations (including both valid and substitute
data values).  For each calendar month of the reporting year in which
carbon content and, if applicable, molecular weight determination is
required, report a value of each parameter.  If multiple values of a
parameter are obtained in a given month, report the arithmetic average
value for the month.Report all measured values if the fuel is sampled
monthly or less frequently.  Otherwise, for daily and weekly sampling,
report monthly average values determined using the calculation
procedures in Equation C-2b for each variable.  Express carbon content
as a decimal fraction for solid fuels, kg C per gallon for liquid fuels,
and kg C per kg of fuel for gaseous fuels.  Express the gas molecular
weights in units of kg per kg-mole. 

(D)  The total number of valid carbon content determinations and, if
applicable, molecular weight determinations made during the reporting
year, for each fuel type.

(E)  The number of substitute data values used for carbon content and,
if applicable, molecular weight used in the annual GHG emissions
calculations.

(F)  The annual average HHV, when measured HHV data, rather than a
default HHV from Table C-1 of this subpart, are used to calculate CH4
and N2O emissions for a Tier 3 unit, in accordance with §98.33(c)(1).

(v)  For the Tier 3 Calculation Methodology, keep records of the
following:

(A)  For liquid and gaseous fuel combustion, the dates and results of
the initial calibrations and periodic recalibrations of the required
fuel flow meters. 

(B)  For fuel oil combustion, the method from §98.34(b) used to make
tank drop measurements (if applicable).

(C)  The methods used to determine the carbon content for each type of
fuel combusted. 

(D)  The methods used to calibrate the fuel flow meters).

(E)  The date on which each fuel sample was taken, except where fuel
sampling data are received from the fuel supplier.  In that case, keep
records of the dates on which the results of the fuel analyses for
carbon content and (if applicable) molecular weight are received.

(vi)  For the Tier 4 Calculation Methodology, report:

(A)  The total number of source operating hours in the reporting year.

(B)  The cumulative CO2 mass emissions in each quarter of the reporting
year, i.e., the sum of the hourly values calculated from Equation C-6 or
C-7 of this subpart (as applicable), in metric tons. 

(C)  For CO2 concentration, stack gas flow rate, and (if applicable)
stack gas moisture content, the percentage of source operating hours in
which a substitute data value of each parameter was used in the
emissions calculations.

(vii)  For the Tier 4 Calculation Methodology, keep records of:  

(A)  Whether the CEMS certification and quality assurance procedures of
40 CFR part 75 of this chapter, 40 CFR part 60 of this chapter, or an
applicable State continuous monitoring program were used. 

(B)  The dates and results of the initial certification tests of the
CEMS. 

(C)  The dates and results of the major quality assurance tests
performed on the CEMS during the reporting year, i.e., linearity checks,
cylinder gas audits, and relative accuracy test audits (RATAs).    

(viii)  If CO2 emissions that are generated from acid gas scrubbing with
sorbent injection are not captured using CEMS, report:

(A)  The total amount of sorbent used during the report year, in short
tons. 

(B)  The molecular weight of the sorbent.

(C)  The ratio (“R”) in Equation C-11 of this subpart.

(ix)  For units that combust both fossil fuel and biomass, when CEMS are
used to quantify the annual CO2 emissions and biogenic CO2 is determined
according to §98.33(e)(2), you shall report the following additional
information, as applicable:

(A)   The annual volume of CO2 emitted from the combustion of all fuels,
i.e., Vtotal, in scf.

(B)  The annual volume of CO2 emitted from the combustion of fossil
fuels, i.e., Vff, in scf.  If more than one type of fossil fuel was
combusted, report the combustion volume of CO2 for each fuel separately
as well as the total.

(C)  The annual volume of CO2 emitted from the combustion of biomass,
i.e., Vbio, in scf.

(D)  The carbon-based F-factor used in Equation C-13 of this subpart,
for each type of fossil fuel combusted, in scf CO2 per mmBtu.

(E)  The annual average HHV value used in Equation C-13 of this subpart,
for each type of fossil fuel combusted, in Btu/lb, Btu/gal, or Btu/scf,
as appropriate.

(F)  The total quantity of each type of fossil fuel combusted during the
reporting year, in lb, gallons, or scf, as appropriate.

(G)  Annual biogenic CO2 mass emissions, in metric tons.  

(x)  When ASTM methods D7459-08 and D6866-08 are used to determine the
biogenic portion of the annual CO2 emissions from MSW combustion, as
described in §98.34(d), report:

(A)  The results of each quarterly sample analysis, expressed as a
decimal fraction (e.g., if the biogenic fraction of the CO2 emissions
from MSW combustion is 30 percent, report 0.30).

(B)  Annual combined biomass and fossil fuel  CO2 emissions from MSW
combustion, in metric tons of CO2e. 

(C)  The quantities Vff, Vtotal, and VMSW from §98.33(e)(4)(ii), if
CEMS are used to measure CO2 emissions.

(BD)  The annual volume of biogenic CO2 mass emissions from MSW
combustion, in metric tons.

(xi)  When ASTM methods D7459-08 and D6866-08 are used in accordance
with §98.34(e) to determine the biogenic portion of the annual CO2
emissions from a unit that co-fires biogenic fuels (or partly-biogenic
fuels, including tires if you are electing to report biogenic CO2
emissions from tire combustion) (other than MSW) and non-biogenic fuels,
you shall report the results of each quarterly sample analysis,
expressed as a decimal fraction (e.g., if the biogenic fraction of the
CO2 emissions is 30 percent, report 0.30).

(3)  Within 30 days of receipt of a written request from the
Administrator, you shall submit explanations of the following: 

(i)  An explanation of how company records are used to quantify fuel
consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to
calculate CO2 emissions.

(ii)  An explanation of how company records are used to quantify fuel
consumption, if solid fuel is combusted and the Tier 3 Calculation
Methodology is used to calculate CO2 emissions. 

(iii)  An explanation of how sorbent usage is quantified.

(iv)  An explanation of how company records are used to quantify fossil
fuel consumption in units that uses CEMS to quantify CO2 emissions and
combusts both fossil fuel and biomass.  

(v)  An explanation of how company records are used to measure steam
production, when it is used to calculate CO2 mass emissions under
§98.33(a)(2)(iii) or to quantify solid fuel usage under §98.33(c)(3). 

(4)  Within 30 days of receipt of a written request from the
Administrator, you shall submit the verification data and information
described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this
section.  

§98.37  Records That Must be Retained. 

In addition to the requirements of §98.3(g), you must retain the
applicable records specified in §§98.34(f) and (g), 98.35(b), and
98.36(e). 

§98.38  Definitions.

All terms used in this subpart have the same meaning given in the Clean
Air Act and subpart A of this part.

Table C-1 toof Subpart C—Default CO2 Emission Factors and High Heat
Values for Various Types of Fuel

Fuel Type	Default High Heat Value	Default CO2 Emission Factor

Coal and coke	mmBtu/short ton	kg CO2 /mmBtu

Anthracite	25.09	103.54

Bituminous	24.93	93.40

Subbituminous	17.25	97.02

Lignite	14.21	96.36

Coke	24.80	102.04

Mixed (Commercial sector)	21.39	95.26

Mixed (Industrial coking)	26.28	93.65

Mixed (Industrial sector)	22.35	93.91

Mixed (Electric Power sector)	19.73	94.38

Natural gas	mmBtu/scf	kg CO2 /mmBtu

Pipeline (Weighted U.S. Average)	1.028 x 10-3	53.02

Petroleum products	mmBtu/gallon	kg CO2 /mmBtu

Distillate Fuel Oil No. 1	0.139	73.25

Distillate Fuel Oil No. 2	0.138	73.96

Distillate Fuel Oil No. 4	0.146	75.04

Residual Fuel Oil No. 5	0.140	72.93

Residual Fuel Oil No. 6	0.150	75.10

Waste OilStill Gas	0.1350.143	74.0066.72

Kerosene	0.135	75.20

Liquefied petroleum gases (LPG)	0.092	62.98

Propane	0.091	61.46

Propylene	0.091	65.95

Ethane	0.096	62.64

Ethanol  	0.084	68.44

Ethylene	0.100	67.43

Isobutane	0.097	64.91

Isobutylene	0.103	67.74

Butane	0.101	65.15

Butylene	0.103	67.73

Naphtha (<401 deg F)	0.125	68.02

Natural Gasoline	0.110	66.83

Other Oil (>401 deg F)	0.139	76.22

Pentanes Plus	0.110	70.02

Petrochemical Feedstocks	0.129	70.97

Petroleum Coke	0.143	102.41

Special Naphtha	0.125	72.34

Unfinished Oils	0.139	74.49

Heavy Gas Oils	0.148	74.92

Lubricants	0.144	74.27

Motor Gasoline	0.125	70.22

Aviation Gasoline	0.120	69.25

Kerosene-Type Jet Fuel	0.135	72.22

Asphalt and Road Oil	0.158	75.36

Crude Oil	0.138	74.49

Fossil Fuel-derived Other fuels (solid)	mmBtu/short ton	kg CO2 /mmBtu

Municipal Solid Waste1	9.951	90.7

Tires	26.87	85.97

Plastics	38.00	75.00

Petroleum Coke	30.00	102.41

Fossil Fuel-derived Other fuels (gaseous)	mmBtu/scf	kg CO2 /mmBtu

Blast Furnace Gas	0.092 x 10-3	274.32

Coke Oven Gas	0.599 x 10-3	46.85

Propane Gas	2.516 x 10-3	61.46

Fuel Gas2	1.388 x 10-3	59.00

Biomass fuels - solid	mmBtu/short Tton	kg CO2 /mmBtu

Wood and Wood Residuals	15.38	93.80

Agricultural Byproducts	8.25	118.17

Peat	8.00	111.84

Solid Byproducts	25.83	105.51

Biomass fuels - gaseous	mmBtu/scf	kg CO2 /mmBtu

Biogas (Captured methane)	0.841 x 10-3	52.07

Biomass fuels - liquid	mmBtu/gallon	kg CO2 /mmBtu

Ethanol (100%) 	0.084	68.44

Biodiesel (100%) 	0.128	73.84

Rendered Animal Fat 	0.125	71.06

Vegetable Oil 	0.120	81.55

1 Use of this default HHV is Aallowed only for units that combust MSW,
do not generate steam, and are allowed to use Tier 1.

2 Reporters subject to subpart X of this part that are complying with
§98.243(d) or subpart Y of this part may only use the default HHV and
the default CO2 emission factor for fuel gas combustion under the
conditions prescribed in §98.243(d)(2)(i) and (d)(2)(ii) and
§98.252(a)(1) and (a)(2), respectively. Otherwise, Tier 3 (Equation
C-5) or Tier 4 must be used.

Table C-2 of Subpart C—Default CH4 and N2O Emission Factors for
Various Types of Fuel. 

Fuel Type	Default CH4 Emission Factor (kg CH4 /mmBtu)	Default N2O
Emission Factor (kg N2O/mmBtu)

Coal and Coke (All fuel types in Table C-1)	1.1 x 10-2	1.6 x 10-03

Natural Gas	1.0 x 10-03	1.0 x 10-04

Petroleum (All fuel types in Table C-1)	3.0 x 10-03	6.0 x 10-04

Municipal Solid Waste 	3.2 x 10-02	4.2 x 10-03

Tires	3.2 x 10-02	4.2 x 10-03

Blast Furnace Gas	2.2 x 10-05	1.0 x 10-04

Coke Oven Gas	4.8 x 10-04	1.0 x 10-04

Biomass Fuels - Solid (All fuel types in Table C-1)	3.2 x 10-02	4.2 x
10-03

Biogas	3.2 x 10-03	6.3 x 10-04

Biomass Fuels – Liquid (All fuel types in Table C-1)	1.1 x 10-03	1.1 x
10-04

Note:  Those employing this table are assumed to fall under the IPCC
definitions of the “Energy Industry” or “Manufacturing Industries
and Construction”.  In all fuels except for coal the values for these
two categories are identical.  For coal combustion, those who fall
within the IPCC “Energy Industry” category may employ a value of 1 g
of CH4/MMBtu.

1Allowed only for units that do not generate steam and use Tier 1.

Table C-2 toof Subpart C—Default CH4 and N2O Emission Factors for
Various Types of Fuel. 

Fuel Type	Default CH4 Emission Factor (kg CH4 /mmBtu)	Default N2O
Emission Factor (kg N2O/mmBtu)

Coal and Coke (All fuel types in Table C-1)	1.1 x 10-02	1.6 x 10--0303

Natural Gas	1.0 x 10-03	1.0 x 10--0404

Petroleum (All fuel types in Table C-1)	3.0 x 10-03	6.0 x 10--0404

Municipal Solid Waste 	3.2 x 10-02	4.2 x 10--0303

Tires	3.2 x 10-02	4.2 x 10--0303

Blast Furnace Gas	2.2 x 10-05	1.0 x 10--0404

Coke Oven Gas	4.8 x 10-04	1.0 x 10--0404

Biomass Fuels - Solid (All fuel types in Table C-1)	3.2 x 10-02	4.2 x
10--0303

Biogas	3.2 x 10-03	6.3 x 10--0404

Biomass Fuels – Liquid (All fuel types in Table C-1)	1.1 x 10-03	1.1 x
10--0404

Note:  Those employing this table are assumed to fall under the IPCC
definitions of the “Energy Industry” or “Manufacturing Industries
and Construction”.  In all fuels except for coal the values for these
two categories are identical.  For coal combustion, those who fall
within the IPCC “Energy Industry” category may employ a value of 1 g
of CH4/MMBtu.

Subpart D—Electricity Generation

§98.40  Definition of the source category.

(a)  The electricity generation source category comprises electricity
generating units that are subject to the requirements of the Acid Rain
Program and any other electricity generating units that are required to
monitor and report to EPA CO2 mass emissions year-round according to 40
CFR part 75.

(b)  This source category does not include portable equipment, emergency
equipment, or emergency generators, as defined in §98.6.

§98.41  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains one or more electricity generating units and the facility meets
the requirements of §98.2(a)(1).

§98.42  GHGs to report.

(a)  For each electricity generating unit that is subject to the
requirements of the Acid Rain Program or is otherwise required to
monitor and report to EPA CO2 emissions year-round according to 40 CFR
part 75, you must report under this subpart the annual mass emissions of
CO2, N2O, and CH4 by following the requirements of this subpart.  

(b)  For each electricity generating unit that is not subject to the
Acid Rain Program or otherwise required to monitor and report to EPA CO2
emissions year-round according to 40 CFR part 75, you must report under
subpart C of this part (General Stationary Fuel Combustion Sources) the
emissions of CO2, CH4, and N2O by following the requirements of subpart
C.

(c)  For each stationary fuel combustion unit that does not generate
electricity, you must report under subpart C of this part (General
Stationary Fuel Combustion Sources) the emissions of CO2, CH4, and N2O
by following the requirements of subpart C of this part.

§98.43  Calculating GHG emissions.

Continue to monitor and report CO2 mass emissions as required under
§75.13 or section 2.3 of apppendix G to 40 CFR part 75, and §75.64. 
Calculate CO2, CH4, and N2O emissions as follows: 

(a)  Convert the cumulative annual CO2 mass emissions reported in the
fourth quarter electronic data report required under §75.64 from units
of short tons to metric tons.  To convert tons to metric tons, divide by
1.1023.

(b)  Calculate and report annual CH4 and N2O mass emissions under this
subpart by following the applicable method specified in §98.33(c).

§98.44  Monitoring and QA/QC requirements 

Follow the applicable quality assurance procedures for CO2 emissions in
appendices B, D, and G to 40 CFR part 75.

§98.45  Procedures for estimating missing data.

Follow the applicable missing data substitution procedures in 40 CFR
part 75 for CO2 concentration, stack gas flow rate, fuel flow rate, high
heating value, and fuel carbon content.

§98.46  Data reporting requirements. 

The annual report shall comply with the data reporting requirements
specified in §98.36(d)(1)(b) and, if applicable, §98.36(c)(2) or
(c)(3).

§98.47  Records that must be retained. 

You shall comply with the recordkeeping requirements of §§98.3(g) and
98.37.  Records retained under §75.57(h) of this chapter for missing
data events satisfy the recordkeeping requirements of §98.3(g)(4) for
those same events.

§98.48  Definitions.

All terms used in this subpart have the same meaning given in the Clean
Air Act and subpart A of this part. 

Subpart F—Aluminum Production

§98.60  Definition of the source category.

(a)  A primary aluminum production facility manufactures primary
aluminum using the Hall-Héroult manufacturing process.  The primary
aluminum manufacturing process comprises the following operations:

(1)  Electrolysis in prebake and Søderberg cells.

(2)  Anode baking for prebake cells.

(b)  This source category does not include experimental cells or
research and development process units.

§98.61  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains an aluminum production process and the facility meets the
requirements of either §98.2(a)(1) or (a)(2).

§98.62  GHGs to report.

You must report:

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

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

(c)  CO2 emissions from on-site anode baking.

(d)  You must report under subpart C of this part (General Stationary
Fuel Combustion Sources) the emissions of CO2, N2O, and CH4 emissions
from each stationary fuel combustion unit by following the requirements
of subpart C. 

§98.63  Calculating GHG emissions.

(a)  The annual value of each PFC compound (CF4, C2F6)for PFC emissions
shall be estimated from the sum of monthly values using Equation F-1 of
this section:

 	(Eq. F-1)

Where:

EPFC	=	Annual emissions of each PFC compoundPFC emissions from aluminum
production (metric tons PFC).

Em	=	Emissions of the individual PFC compound PFC emissions from
aluminum production for the month “m” (metric tons PFC).

(b)  Use Equation F-2 of this section to estimate CF4 emissions from
anode effect duration or Equation F-3 of this section to estimate CF4
emissions from overvoltage, and use Equation F-4 of this section to
estimate C2F6 emissions from anode effects from each prebake and
Søderberg electrolysis cell.

	ECF4 = SCF4 × AEM × MP × 0.001	(Eq. F-2)

Where:

ECF4	=	Monthly CF4 emissions from aluminum production (metric tons CF4).

SCF4	=	The slope coefficient ((kg CF4/metric ton
Al)/(AE-Mins/cell-day)).

AEM	=	The anode effect minutes per cell-day (AE-Mins/cell-day).

MP	=	Metal production (metric tons Al), 	where AEM and MP are calculated
monthly.

	ECF4 = EFCF4 × MP × 0.001	(Eq. F-3)

Where:

ECF4	=	Monthly CF4 emissions from aluminum production (metric tons CF4).

EFCF4	=	The overvoltage emission factor (kg CF4/metric ton Al).

MP	=	Metal production (metric tons Al), where MP is calculated monthly.

	EC2F6 = ECF4 × FC2F6/CF4 × 0.001	(Eq. F-4)

Where:

EC2F6	=	Monthly C2F6 emissions from aluminum production (metric tons
C2F6).

ECF4	=	CF4 emissions from aluminum production(kg CF4). 

FC2F6/CF4	=	The weight fraction of C2F6/CF4 (kg C2F6/kg CF4).

0.001	=	Conversion factor from kg to metric tons, where ECF4 is
calculated monthly.

(c)  You must calculate and report the annual process CO2 emissions from
anode consumption during electrolysis and anode baking of prebake cells
using either the procedures in paragraph (d) of this section, or the
procedures in paragraphs (e) and (f) of this section, or the procedures
in paragraph (g) of this section.

(d)  Calculate and report under this subpart the process CO2 emissions
by operating and maintaining CEMS according to the Tier 4 Calculation
Methodology in §98.33(a)(4) and all associated requirements for Tier 4
in subpart C of this part (General Stationary Fuel Combustion Sources). 

(e)  Use the following procedures to calculate CO2 emissions from anode
consumption during electrolysis: 

(1)  For Prebake cells: you must calculate CO2 emissions from anode
consumption using Equation F-5 of this section:

ECO2 = NAC × MP ×([100 – Sa– Asha] / 100) × (44/12)	(Eq. F-5)

Where:

ECO2	=	Annual CO2 emissions from prebaked anode consumption (metric tons
CO2).

NAC	=	Net annual prebaked anode consumption per metric ton Al (metric
tons C/metric tons Al).

MP	=	Annual metal production (metric tons Al).

Sa	=	Sulfur content in baked anode (percent weight).

Asha	=	Ash content in baked anode(percent weight).

44/12	=	Ratio of molecular weights, CO2 to carbon.

(2)  For Søderberg cells you must calculate CO2 emissions using
Equation F-6 of this section:

ECO2 = (PC × MP – [CSM × MP] / 1000 – BC / 100 × PC × 

MP × [Sp + Ashp + Hp] / 100 – [100 - BC] / 100 × PC × MP × 

	[Sc + Ashc] / 100 – MP × CD) × (44/12)	(Eq. F-6)

Where:

ECO2	=	Annual CO2 emissions from paste consumption (metric ton CO2).

PC	=	Annual paste consumption (metric ton/metric ton Al).

MP	=	Annual metal production (metric ton Al).

CSM	=	Annual emissions of cyclohexane soluble matter (kg/metric ton Al).

BC	=	Binder content of paste (percent weight).

Sp	=	Sulfur content of pitch (percent weight).

Ashp	=	Ash content of pitch (percent weight).

Hp 	=	Hydrogen content of pitch (percent weight).

Sc 	=	Sulfur content in calcined coke (percent weight).

Ashc	=	Ash content in calcined coke (percent weight).

CD	=	Carbon in skimmed dust from Søderberg cells (metric ton C/metric
ton Al).

44/12	=	Ratio of molecular weights, CO2 to carbon.

(f)  Use the following procedures to calculate CO2 emissions from anode
baking of prebake cells:

(1)  Use Equation F-7 of this section to calculate emissions from pitch
volatiles combustion.

	ECO2PV = (GA – Hw – BA – WT) × (44/12)	(Eq. F-7)

Where:  

ECO2PV	=	Annual CO2 emissions from pitch volatiles combustion (metric
tons CO2).

GA	=	Initial weight of green anodes (metric tons).

Hw	=	Annual hydrogen content in green anodes (metric tons).

BA	=	Annual baked anode production (metric tons).

WT	=	Annual waste tar collected (metric tons).

44/12	=	Ratio of molecular weights, CO2 to carbon.

(2)  Use Equation F-8 of this section to calculate emissions from bake
furnace packing material.

ECO2PC = 	PCC × BA × ([100 – Spc – Ashpc] / 100) × (44/12)	(Eq.
F-8)

Where:

ECO2PC	=	Annual CO2 emissions from bake furnace packing material (metric
tons CO2).

PCC	=	Annual packing coke consumption (metric tons/metric ton baked
anode).

BA	=	Annual baked anode production (metric tons).

Spc	=	Sulfur content in packing coke (percent weight).

Ashpc	=	Ash content in packing coke (percent weight).

44/12	=	Ratio of molecular weights, CO2 to carbon.

(g)  If process CO2 emissions from anode consumption during electrolysis
or anode baking of prebake cells are vented through the same stack as
any combustion unit or process equipment that reports CO2 emissions
using a CEMS that complies with the Tier 4 Calculation Methodology in
subpart C of this part (General Stationary Fuel Combustion Sources),
then the calculation methodology in paragraphs (d) and (e) of this
section shall not be used to calculate those process emissions.  The
owner or operation shall report under this subpart the combined stack
emissions according to the Tier 4 Calculation Methodology in
§98.33(a)(4) and all associated requirements for Tier 4 in subpart C of
this part (General Stationary Fuel Combustion Sources).

§98.64  Monitoring and QA/QC requirements. 

(a)  Effective one year after publication of the rule for smelters with
no prior measurement or effective three years after publication for
facilities with historic measurements, the smelter-specific slope
coefficients, overvoltage emission factors, and wieight fractions used
in Equations F-2, F-3, and F-4 of this subpart 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), except the minimum
frequency of measurement shall be every 10 years unless a change occurs
in the control algorithm that affects the mix of types of anode effects
or the nature of the anode effect termination routine.  Facilities which
operate at less than 0.2 anode effect minutes per cell day or operate
with less than 1.4mV anode effect overvoltage can use either
smelter-specific slope coefficients or the technology specific default
values in Table F-1 of this subpart.

(b)  The minimum frequency of the measurement and analysis is annually
except as follows: Monthly – anode effect minutes per cell day (or
anode effect overvoltage and current efficiency), production

(i)  Monthly for anode effect minutes per cell day (or anode effect
overvoltage and current efficiency).

(ii)  Monthly for aluminum production. 

(iii)  Smelter-specific slope coefficients, overvoltage emission
factors, and weight fractions according to paragraph (a) of this
section.  

(c)  Sources may use either smelter-specific values from annual
measurements of parameters needed to complete the equations in §98.63
(e.g., sulfur, ash, and hydrogen contents) or the default values shown
in Table F-2 of this subpart. 

§98.65  Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions
calculations is required.  Therefore, whenever a quality-assured value
of a required parameter is unavailable (e.g., if a meter malfunctions
during unit operation or if a required sample measurement is not taken),
a substitute data value for the missing parameter shall be used in the
calculations, according to the following requirements:

(a)  Where anode or paste consumption data are missing, CO2 emissions
can be estimated from aluminum production using Tier 1 methodper
Equation F-8 of this section.  

	ECO2 = EFp x MPp + EFs x MPs	(Eq. F-8)

Where:  

ECO2	=	CO2 emissions from anode and/or paste consumption, metric tons
CO2.

EFp	=	Prebake technology specific emission factor (1.6 metric tons
CO2/metric ton aluminum produced).

MPp	=	Metal production from prebake process (metric tons Al).

EFs	=	Søderberg technology specific emission factor (1.7 metric tons
CO2/metric ton Al produced).

MPs	=	Metal production from Søderberg process (metric tons Al).

(b)  For other parameters, use the average of the two most recent data
points after the missing data.  

§98.66  Data reporting requirements. 

In addition to the information required by §98.3(c), you must report
the following information at the facility level: 

(a)  Annual aluminum production in metric tons.

(b)  Type of smelter technology used. 

(c)  The following PFC-specific information on an annual basis: 

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

(2)  Anode effect minutes per cell-day (AE-mins/cell-day), anode effect
frequency (AE/cell-day), anode effect duration (minutes). (Or anode
effect overvoltage factor ((kg CF4/metric ton Al)/(mV/cell day)),
potline overvoltage (mV/cell day), current efficiency (%).)

(3)  Smelter-specific slope coefficients (or overvoltage emission
factors) and the last date when the smelter-specific-slope coefficients
(or overvoltage emission factors) were measured.

(d)  Method used to measure the frequency and duration of anode effects
(or overvoltage).

(e)  The following CO2-specific information for prebake cells: 

(1)  Annual anode consumption.

(2)  Annual CO2 emissions from the smelter. 

(f)  The following CO2-specific information for Søderberg cells: 

(1)  Annual paste consumption. 

(2)  Annual CO2 emissions from the smelter.

(g)  Smelter-specific inputs to the CO2 process equations (e.g., levels
of sulfur and ash) that were used in the calculation, on an annual
basis. 

(h)  Exact data elements required will vary depending on smelter
technology (e.g., point-feed prebake or Søderberg) and process control
technology (e.g., Pechiney or other). 

§98.67  Records that must be retained. 

In addition to the information required by §98.3(g),  you must retain
the following records:

(a)  Monthly aluminum production in metric tons. 

(b)  Type of smelter technology used. 

(c)  The following PFC-specific information on a monthly basis: 

(1)  Perfluoromethane and perfluoroethane emissions from anode effects
in prebake and Søderberg electrolysis cells. 

(2)  Anode effect minutes per cell-day (AE-mins/cell-day), anode effect
frequency (AE/cell-day), anode effect duration (minutes). (Or anode
effect overvoltage factor ((kg CF4/metric ton Al)/(mV/cell day)),
potline overvoltage (mV/cell day), current efficiency (%).)) 

(3)  Smelter-specific slope coefficients and the last date when the
smelter-specific-slope coefficients were measured.

(d)  Method used to measure the frequency and duration of anode effects
(or to measure anode effect overvoltage and current efficiency).

(e)  The following CO2-specific information for prebake cells: 

(1)  Annual anode consumption.

(2)  Annual CO2 emissions from the smelter. 

(f)  The following CO2-specific information for Søderberg cells: 

(1)  Annual paste consumption.

(2)  Annual CO2 emissions from the smelter.

(g)  Smelter-specific inputs to the CO2 process equations (e.g., levels
of sulfur and ash) that were used in the calculation, on an annual
basis. 

(h)  Exact data elements required will vary depending on smelter
technology (e.g., point-feed prebake or Søderberg) and process control
technology (e.g., Pechiney or other).

§98.68  Definitions.

All terms used in this subpart have the same meaning given in the Clean
Air Act and subpart A of this part. 

Table F-1 to Subpart F—Slope and Overvoltage Coefficients for the
Calculation of PFC Emissions from Aluminum Production

Technology	CF4 Slope Coefficient

[(kg CF4/metric ton Al)/(AE-Mins/cell-day)]	CF4 Overvoltage Coefficient

[(kg CF4/metric ton Al)/(mV)]	Weight Fraction C2F6/CF4

[(kg C2F6/kg CF4)]

Center Worked Prebake (CWPB)	0.143	1.16	0.121

Side Worked Prebake (SWPB)	0.272	3.65	0.252

Vertical Stud Søderberg (VSS)	0.092	NA	0.053

Horizontal Stud Søderberg (HSS)	0.099	NA	0.085

Table F-2 to Subpart F—Default Data Sources for Parameters Used for
CO2 Emissions

CO2 Emissions from Prebake Cells (CWPB and SWPB)

Parameter	Data Source

MP:  metal production (metric tons Al)	Individual facility records

NAC:  net annual prebaked anode consumption per metric ton Al (metric
tons C/metric tons Al)	Individual facility records

Sa: sulfur content in baked anode (percent weight)	2.0

Asha:  ash content in baked anode(percent weight)	0.4

CO2 Emissions from Søderberg Cells (VSS and HSS)

Parameter	Data Source

MP:  metal production (metric tons Al)	Individual facility records

PC:  annual paste consumption (metric ton/metric ton Al)	Individual
facility records

CSM: annual emissions of cyclohexane soluble matter (kg/metric ton Al)
HSS:  4.0

VSS:  0.5

BC:  binder content of paste (percent weight)	Dry Paste:  24

Wet Paste:  27

Sp:  sulfur content of pitch (percent weight)	0.6

Ashp:  ash content of pitch (percent weight)	0.2

Hp:  hydrogen content of pitch (percent weight)	3.3

Sc:  sulfur content in calcined coke (percent weight)	1.9

Ashc:  ash content in calcined coke (percent weight)	0.2

CD:  carbon in skimmed dust from Søderberg cells (metric ton C/metric
ton Al)	0.01

CO2 Emissions from Pitch Volatiles Combustion (VSS and HSSCWPB and SWPB)

Parameter	Data Source

GA:  initial weight of green anodes (metric tons)	Individual facility
records

Hw:  annual hydrogen content in green anodes (metric tons)	0.005 × GA

BA:  annual baked anode production (metric tons)	Individual facility
records

WT:  annual waste tar collected (metric tons)

(a)  Riedhammer furnaces

(b)  all other furnaces	(a)  0.005 × GA

(b)  insignificant

CO2 Emissions from Bake Furnace Packing Materials (CWPB and SWPB)

Parameter	Data Source

PCC:  annual packing coke consumption (metric tons/metric ton baked
anode)	0.015

BA:  annual baked anode production (metric tons)	Individual facility
records

Spc:  sulfur content in packing coke (percent weight)	2

Ashpc: ash content in packing coke (percent weight)	2.5

Subpart G—Ammonia Manufacturing

§98.70  Definition of Source Category.

The ammonia manufacturing source category comprises the process units
listed in paragraphs (a) and (b) of this section. 

(a)  Ammonia manufacturing processes in which ammonia is manufactured
from a fossil-based feedstock produced via steam reforming of a
hydrocarbon.

(b)  Ammonia manufacturing processes in which ammonia is manufactured
through the gasification of solid and liquid raw material.

§98.71  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains an ammonia manufacturing process and the facility meets the
requirements of either §98.2(a)(1) or (2).

§98.72  GHGs to report.

You must report: 

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

(b)  CO2, CH4, and N2O emissions from each stationary fuel combustion
unit.  You must report these emissions under subpart C of this part
(General Stationary Fuel Combustion Sources), by following the
requirements of subpart C, except that for ammonia manufacturing
processes subpart C does not apply to any CO2 resulting from combustion
of the waste recycle stream (commonly referred to as the purge gas
stream). 

(c)  CO2 emissions collected and transferred off site under subpart PP
(Suppliers of CO2), following the requirements of subpart PP.

§98.73  Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each
ammonia manufacturing process unit using the procedures in either
paragraph (a) or (b) of this section.

(a)  Calculate and report under this subpart the process CO2 emissions
by operating and maintaining CEMS according to the Tier 4 Calculation
Methodology specified in §98.33(a)(4) and all associated requirements
for Tier 4 in subpart C of this part (General Stationary Fuel Combustion
Sources).  

(b)   Calculate and report under this subpart process CO2 emissions
using the procedures in paragraphs (b)(1) through (b)(65) of this
section for gaseous feedstock, liquid feedstock, or solid feedstock, as
applicable.   

(1)  Gaseous feedstock.  You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from gaseous feedstock
according to Equation G-1 of this section: 

 	(Eq. G-1)

Where:

CO2,G,k	=	Annual CO2 emissions arising from gaseous feedstock
consumption (metric tons). 

Fdstkn	=	Volume of the gaseous feedstock used in month n (scf of
feedstock).

CCn	=	Carbon content of the gaseous feedstock, for month n, (kg C per kg
of feedstock), determined according to 98.74(c). 

MW	=	Molecular weight of the gaseous feedstock (kg/kg-mole).

MVC 	=	Molar volume conversion factor (849.5 scf per kg-mole at standard
conditions).

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons. 

k	=	Processing unit.

n	=	Number of month

(2)  Liquid feedstock.  You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from liquid feedstock
according to Equation G-2 of this section:

 	(Eq. G-2)

Where:

CO2,L,k 	=	Annual CO2 emissions arising from liquid feedstock
consumption (metric tons). 

Fdstkn 	=	Volume of the liquid feedstock used in month n (gallons of
feedstock).

CCn 	=	Carbon content of the liquid feedstock, for month n, (kg C per
gallon of feedstock) determined according to 98.74(c).

44/12 	=	Ratio of molecular weights, CO2 to carbon.

0.001 	=	Conversion factor from kg to metric tons.

k	=	Processing unit.

n	=	Number of month

(3)  Solid feedstock.  You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from solid feedstock
according to Equation G-3 of this section:

 	(Eq. G-3)

Where:

CO2,S,k 	=	Annual CO2 emissions arising from solid feedstock consumption
(metric tons). 

Fdstkn	=	Mass of the solid feedstock used in month n (kg of feedstock).

CCn 	=	Carbon content of the solid feedstock, for month n, (kg C per kg
of feedstock), determined according to 98.74(c). 

44/12 	=	Ratio of molecular weights, CO2 to carbon.

0.001 	=	Conversion factor from kg to metric tons.

K	=	Processing unit.

n	=	Number of month.

(4)  You must calculate the annual process CO2 emissions from each
ammonia processing unit k at your facility summing emissions, as
applicable from Equation G-1, G-2, and G-3 of this section using
Equation G-4.

  CO2,G + CO2,S + CO2,L 	(Eq. G-4)

Where:

ECO2k	=	Annual CO2 emissions from each ammonia processing unit k (metric
tons).

k	=		Processing unit.

(5)  You must determine the combined CO2 emissions from all ammonia
processing units at your facility using Equation G-5 of this section.

 	(Eq. G-5)

Where:

CO2	=	Annual combined CO2 emissions from all ammonia processing units
(metric tons) (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(s)).

ECO2k	=	Annual CO2 emissions from each ammonia processing unit (metric
tons).

k	=		Processing unit.

n	=	Total number of ammonia processing units.

(6)  If applicable, ammonia manufacturing facilities that utilize the
waste recycle stream as a fuel must calculate emissions associated with
the waste stream for each ammonia process unit according to Equation G-6
of this section:  

 	(Eq. G-6)

Where:

CO2	=	Annual CO2 contained in waste recycle stream (metric tons). 

RecycleStreamn	=	Volume of the waste recycle stream in month n (scf).

CCn	=	Carbon content of the waste recycle stream, for month n, (kg C per
kg of waste recycle stream) determined according to 98.74(f). 

MW	=	Molecular weight of the waste recycle stream (kg/kg-mole).

MVC 	=	Molar volume conversion factor (849.5 scf per kg-mole at standard
conditions).

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons. 

n	=	Number of month

(c)  If GHG emissions from an ammonia manufacturing unit are vented
through the same stack as any combustion unit or process equipment that
reports CO2 emissions using a CEMS that complies with the Tier 4
Calculation Methodology in subpart C of this part (General Stationary
Fuel Combustion Sources), then the calculation methodology in paragraph
(b) of this section shall not be used to calculate process emissions. 
The owner or operator shall report under this subpart the combined stack
emissions according to the Tier 4 Calculation Methodology in
§98.33(a)(4) and all associated requirements for Tier 4 in subpart C of
this part.

§98.74  Monitoring and QA/QC requirements.

(a)  You must continuously measure the quantity of gaseous or liquid
feedstock consumed using a flow meter.  The quantity of solid feedstock
consumed can be obtained from company records and aggregated on a
monthly basis.

(b)  You must document the procedures used to ensure the accuracy of the
estimates of feedstock consumption. 

(c)  You must determine monthly carbon contents and the average
molecular weight of each feedstock consumed from reports from your
supplier. As an alternative to using supplier information on carbon
contents, you can also collect a sample of each feedstock on a monthly
basis and analyze the carbon content and molecular weight of the fuel
using any of the following methods listed in paragraphs (c)(1) through
(c)(8) of this section, as applicable. 

(1)  ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by reference, see §98.7).

(2)  ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography (incorporated by reference, see
§98.7).

(3)  ASTM D2502-04 (Reapproved 2002) Standard Test Method for Estimation
of Mean Relative Molecular Mass of Petroleum Oils from Viscosity
Measurements (incorporated by reference, see §98.7).

(4)  ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative
Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric
Measurement of Vapor Pressure (incorporated by reference, see §98.7).

(5)  ASTM D3238-95 (Reapproved 2005) Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method (incorporated by reference, see
§98.7).

(6)  ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants (incorporated by reference, see
§98.7).

(7)  ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate
Analysis of Coal and Coke (incorporated by reference, see §98.7).

(8)  ASTM D5373-08 Standard Methods for Instrumental Determination of
Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal
(incorporated by reference, see §98.7).  

(d) Calibrate all oil and gas flow meters that are used to measure
liquid and gaseous feedstock volumes and flow rates (except for gas
billing meters) and perform oil tank measurements according to the
monitoring and QA/QC requirements for the Tier 3 methodology in
§98.34(b)(1).  Perform oil tank drop measurements (if used to quantify
feedstock volumes) according to §98.34(b)(2).

(e)  For quality assurance and quality control of the supplier data, on
an annual basis, you must measure the carbon contents of a
representative sample of the feedstocks consumed using the appropriate
ASTM Method as listed in  paragraphs (c)(1) through (c)(8) of this
section.

(f)  [Reserved]Facilities must continuously measure the quantity of
waste gas recycled using a flow meter, as applicable.  You must
determine the carbon content and the molecular weight of the waste
recycle stream by collecting a sample of each waste recycle stream on a
monthly basis and analyzing the carbon content using the appropriate
ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this
section.

(g)  If CO2 from ammonia production is used to produce urea at the same
facility, you must determine the quantity of urea produced using methods
or plant instruments used for accounting purposes (such as sales
records).  You must document the procedures used to ensure the accuracy
of the estimates of urea produced.

§98.75  Procedures for estimating missing data.  

A complete record of all measured parameters used in the GHG emissions
calculations is required.  Therefore, whenever the monitoring and
quality assurance procedures in §98.74 cannot be followed  (e.g., if a
meter malfunctions during unit operation), a substitute data value for
the missing parameter shall be used in the calculations following
paragraphs (a) and (b) of this section. You must document and keep
records of the procedures used for all such estimates.

(a)  For missing data on monthly carbon contents of feedstock or the
waste recycle stream, the substitute data value shall be the arithmetic
average of the quality-assured values of that carbon content in the
month preceding and the month immediately following the missing data
incident. If no quality-assured data are available prior to the missing
data incident, the substitute data value shall be the first
quality-assured value for carbon content obtained in the month after the
missing data period.

(b)  For missing feedstock supply rates or waste recycle stream used to
determine monthly feedstock consumption or monthly waste recycle stream
quantity, you must determine the best available estimate(s) of the
parameter(s), based on all available process data.

§98.76  Data reporting requirements. 

In addition to the information required by §98.3(c), each annual report
must contain the information specified in paragraphs (a) and (b) of this
section, as applicable for each ammonia manufacturing process unit.

(a)  If a CEMS is used to measure CO2 emissions, then you must report
the relevant information required under §98.367(e)(2)(vi) for the Tier
4 Calculation Methodology and the following information in this
paragraph (a):

(1)  Annual quantity of each type of feedstock consumed for ammonia
manufacturing (scf of feedstock or gallons of feedstock or kg of
feedstock).

(2)  Method used for determining quantity of feedstock used.

(b)  If a CEMS is not used to measure emissions, then you must report
the following information:

(1)  Annual CO2 process emissions (metric tons) for each ammonia
manufacturing process unit.

(2)  Monthly quantity of each type of feedstock consumed for ammonia
manufacturing for each ammonia processing unit (scf of feedstock or
gallons of feedstock or kg of feedstock).

(3)  Method used for determining quantity of monthly feedstock used.

(4)  Whether carbon content for each feedstock for month n is based on
reports from the supplier or analysis of carbon content.

(5)  If carbon content of feedstock for month n is based on analysis,
the test method used.

(6)  Sampling analysis results of carbon content of petroleum
cokefeedstock as determined for QA/QC of supplier data under §98.74(e).

(7)  If a facility uses gaseous feedstock, the carbon content of the
gaseous feedstock, for month n, (kg C per kg of feedstock).

(8)  If a facility uses gaseous feedstock, the molecular weight of the
gaseous feedstock (kg/kg-mole).

(9)  If a facility uses gaseous feedstock, the molar volume conversion
factor of the gaseous feedstock (scf per kg-mole).

(10)  If a facility uses liquid feedstock, the carbon content of the
liquid feedstock, for month n, (kg C per gallon of feedstock).

(11)  If a facility uses solid feedstock, the carbon content of the
solid feedstock, for month n, (kg C per kg of feedstock).

(12)  Annual CO2 emissions associated with the waste recycle stream for
each ammonia process unit (metric tons)

(13)  Carbon content of the waste recycle stream for month n for each
ammonia process unit (kg C per kg of waste recycle stream).

(14)  Volume of the waste recycle stream for month n for each ammonia
process unit (scf)

(15)  Method used for analyzing carbon content of waste recycle stream.

(1216)  Annual urea production (metric tons) and method used to
determine urea production.

(13)  CO2 from the steam reforming of a hydrocarbon or the gasification
of solid and liquid raw material at the ammonia manufacturing process
unit used to produce urea and the method used to determine the CO2
consumed in urea production.

(17)  Uses of urea produced, if known, such as but not limited to
fertilizer, animal feed, manufacturing of plastics or resins, and
pollution control technologies.

(c)  Total pounds of synthetic fertilizer produced through and total
nitrogen contained in that fertilizer.

§98.77  Records that must be retained. 

In addition to the records required by §98.3(g), you must retain the
following records specified in paragraphs (a) and (b) of this section
for each ammonia manufacturing unit.

(a)  If a CEMS is used to measure emissions, retain records of all
feedstock purchases in addition to the requirements in §98.37 for the
Tier 4 Calculation Methodology.

(b)  If a CEMS is not used to measure process CO2 emissions, you must
also retain the records specified in paragraphs (b)(1) through (b)(2) of
this section:

(1)  Records of all analyses and calculations conducted for reported
data as listed in §98.76(b).

(2)  Monthly records of carbon content of feedstock from supplier and/or
all analyses conducted of carbon content.

§98.78  Definitions.

All terms used in this subpart have the same meaning given in the Clean
Air Act and subpart A of this part. 

Subpart P—Hydrogen Production

§98.160  Definition of the source category.

(a)  A hydrogen production source category consists of facilities that
produce hydrogen gas sold as a product to other entities. 

(b)  This source category comprises process units that produce hydrogen
by reforming, gasification, oxidation, reaction, or other
transformations of feedstocks.

(c)  This source category includes merchant hydrogen production
facilities located within a petroleum refinery if they are not owned by,
or under the direct control of, the refinery owner and operator. 

§98.161  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains a hydrogen production process and the facility meets the
requirements of either §98.2(a)(1) or (a)(2).

§98.162  GHGs to report.

You must report: 

(a)  CO2 process emissions from each hydrogen production process unit.

(b)  CO2, CH4 and N2O combustion emissions from each hydrogen production
process unit.  You must calculate and report these combustion emissions
under  subpart C of this part (General Stationary Fuel Combustion
Sources) by following the requirements of subpart C.

(c)  CO2, CH4, and N2O emissions from each stationary combustion unit
other than hydrogen production process units.  You must calculate and
report these emissions under subpart C of this part (General Stationary
Fuel Combustion Sources) by following the requirements of subpart C.

(d)  For CO2 collected and transferred off site, you must follow the
requirements of subpart PP of this part.

§98.163  Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each
hydrogen production process unit using the procedures specified in
either paragraph (a) or (b) of this section.

(a)  Continuous Emissions Montoring Systems (CEMS). Calculate and report
under this subpart the process CO2 emissions by operating and
maintaining CEMS according to the Tier 4 Calculation Methodology
specified in §98.33(a)(4) and all associated requirements for Tier 4 in
subpart C of this part (General Stationary Fuel Combustion Sources).  

(b)  Fuel and feedstock material balance approach. Calculate and report
process CO2 emissions as the sum of the annual emissions associated with
each fuel and feedstock used for hydrogen production by following
paragraphs (b)(1) through (b)(3) of this section.

(1)  Gaseous fuel and feedstock.  You must calculate the annual CO2
process emissions from gaseous fuel and feedstock according to Equation
P-1 of this section: 

 	(Eq. P-1)

Where:

CO2 	=	Annual CO2 process emissions arising from fuel and feedstock
consumption (metric tons/yr). 

Fdstkn 	=	Volume of the gaseous fuel and feedstock used in month n (scf
(at standard conditions of 68 °F and atmospheric pressure) of fuel and
feedstock).

CCn 	=	Average carbon content of the gaseous fuel and feedstock, from
the results of one or more analyses for month n (kg carbon per kg of
fuel and feedstock). 

MW	=	Molecular weight of the gaseous fuel and feedstock (kg/kg-mole).

MVC 	=	Molar volume conversion factor (849.5 scf per kg-mole at standard
conditions).

k 	=	Months in the year. 

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons.

(2)  Liquid fuel and feedstock.  You must calculate the annual CO2
process emissions from liquid fuel and feedstock according to Equation
P-2 of this section:

  	(Eq. P-2)

Where:

CO2 	=	Annual CO2 emissions arising from fuel and feedstock consumption
(metric tons/yr). 

Fdstkn	=	Volume of the liquid fuel and feedstock used in month n
(gallons of fuel and feedstock).

CCn 	=	Average carbon content of the liquid fuel and feedstock, from the
results of one or more analyses for month n (kg carbon per gallon of
fuel and feedstock).

k 	=	Months in the year. 

44/12 	=	Ratio of molecular weights, CO2 to carbon.

0.001 	=	Conversion factor from kg to metric tons. 

(3)  Solid fuel and feedstock.  You must calculate the annual CO2
process emissions from solid fuel and feedstock according to Equation
P-3 of this section:

 	(Eq.P-3)

Where:  

CO2 	=	Annual CO2 emissions from fuel and feedstock consumption in
metric tons per month (metric tons/yr).

Fdstkn	=	Mass of solid fuel and feedstock used in month n (kg of fuel
and feedstock). 

CCn 	=	Average carbon content of the solid fuel and feedstock, from the
results of one or more analyses for month n (kg carbon per kg of fuel
and feedstock).

k 	=	Months in the year.

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons. 

(c)  If GHG emissions from a hydrogen production process unit are vented
through the same stack as any combustion unit or process equipment that
reports CO2 emissions using a CEMS that complies with the Tier 4
Calculation Methodology in subpart C of this part (General Stationary
Fuel Combustion Sources), then the calculation methodology in paragraph
(b) of this section shall not be used to calculate process emissions. 
The owner or operator shall report under this subpart the combined stack
emissions according to the Tier 4 Calculation Methodology in
§98.33(a)(4) and all associated requirements for Tier 4 in subpart C of
this part (General Stationary Fuel Combustion Sources).

§98.164  Monitoring and QA/QC requirements.

The GHG emissions data for hydrogen production process units must be
quality-assured as specified in paragraphs (a) or (b) of this section,
as appropriate for each process unit:

(a)  If a CEMS is used to measure GHG emissions, then the facility must
comply with the monitoring and QA/QC procedures specified in §98.34(c).

(b)  If a CEMS is not used to measure GHG emissions, then you must: 

(1)  Calibrate all oil and gas flow meters that are used to measure
liquid and gaseous feedstock volumes (except for gas billing meters),
solids weighing equipment, and oil tank drop measurements (if used to
determine liquid fuel and feedstock use volume) according to
thecalibration accuracy requirements in §98.3(i) of this part
monitoring and QA/QC requirements for the Tier 3 methodology in
§98.34(b)(1).  Perform oil tank drop measurements (if used to quantify
liquid fuel or feedstock consumption) according to §98.34(b)(2). 
Calibrate all solids weighing equipment according to the procedures in
§98.3(i).

(2)  Determine the carbon content and the molecular weight annually of
standard gaseous hydrocarbon fuels and feedstocks having consistent
composition (e.g., natural gas). For other gaseous fuels and feedstocks
(e.g., biogas, refinery gas, or process gas), weekly sampling and
analysis is required to determine the carbon content and molecular
weight of the fuel and feedstock. 

(3)  Determine the carbon content of fuel oil, naphtha, and other liquid
fuels and feedstocks at least monthly, except annually for standard
liquid hydrocarbon fuels and feedstocks having consistent composition,
or upon delivery for liquid fuels delivered by bulk transport (e.g., by
truck or rail).  

(4)  Determine the carbon content of coal, coke, and other solid fuels
and feedstocks at least monthly, except annually for standard solid
hydrocarbon fuels and feedstocks having consistent composition, or upon
delivery for solid fuels delivered by bulk transport (e.g., by truck or
rail).   

(5)  You must use the following applicable methods to determine the
carbon content for all fuels and feedstocks, and molecular weight of
gaseous fuels and feedstocks. 

(i)  ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by reference, see §98.7).

(ii)  ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of
Reformed Gas by Gas Chromatography (incorporated by reference, see
§98.7).

(iii)  ASTM D2013-07 Standard Practice of Preparing Coal Samples for
Analysis (incorporated by reference, see §98.7).

(iv)  ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross
Sample of Coal (incorporated by reference, see §98.7).

(v)  ASTM D2597-94 (Reapproved 2004) Standard Test Method for Analysis
of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and
Carbon Dioxide by Gas Chromatography (incorporated by reference, see
§98.7).	

(vi)  ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate
Analysis of Coal and Coke (incorporated by reference, see §98.7). 

(vii)  ASTM D3238-95 (Reapproved 2005), Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method (incorporated by reference, see
§98.7).

(viii)  ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum
and Petroleum Products (incorporated by reference, see §98.7).

(ix)  ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic
Sampling of Petroleum and Petroleum Products (incorporated by reference,
see §98.7). 

(x)  ASTM D5291-02 (Reapproved 2007), Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants (incorporated by reference, see
§98.7).

(xi)  ASTM D5373-08 Standard Test Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal
(incorporated by reference, see §98.7). 

(xii)  ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal
(incorporated by reference, see §98.7).

(xiii)  ASTM D6883-04 Standard Practice for Manual Sampling of
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles
(incorporated by reference, see §98.7).

(xiv)  ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of
Coal (incorporated by reference, see §98.7).

(xv)  ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography
(incorporated by reference, see §98.7).

(xvi)  GPA 2261–00 Analysis for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography (incorporated by reference, see §98.7).

(xvii)  ISO 3170: Petroleum Liquids -- Manual sampling – Third Edition
(incorporated by reference, see §98.7).

(xviii)  ISO 3171: Petroleum Liquids -- Automatic pipeline sampling –
Second Edition (incorporated by reference, see §98.7). 

(c)  For units using the calculation methodologies described in this
section, the records required under §98.3(g) must include both the
company records and a detailed explanation of how company records are
used to estimate the following:

(1)  Fuel and feedstock consumption, when solid fuel and feedstock is
combusted and a CEMS is not used to measure GHG emissions. 

(2)  Fossil fuel consumption, when, pursuant to §98.33(e), the owner or
operator of a unit that uses CEMS to quantify CO2 emissions and that
combusts both fossil and biogenic fuels separately reports the biogenic
portion of the total annual CO2 emissions. 

(3)  Sorbent usage, if the methodology in §98.33(d) is used to
calculate CO2 emissions from sorbent.  

(d)  The owner or operator must document the procedures used to ensure
the accuracy of the estimates of fuel and feedstock usage and sorbent
usage (as applicable) in paragraph (b) of this section, including, but
not limited to, calibration of weighing equipment, fuel and feedstock
flow meters, and other measurement devices.  The estimated accuracy of
measurements made with these devices must also be recorded, and the
technical basis for these estimates must be provided.  

§98.165  Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions
calculations is required.  Therefore, whenever a quality-assured value
of a required parameter is unavailable (e.g., if a meter malfunctions
during unit operation), a substitute data value for the missing
parameter must be used in the calculations as specified in paragraphs
(a), (b), and (c) of this section:

(a)  For each missing value of the monthly fuel and feedstock
consumption, the substitute data value must be the best available
estimate of the fuel and feedstock consumption, based on all available
process data (e.g., hydrogen production, electrical load, and operating
hours).  You must document and keep records of the procedures used for
all such estimates. 

(b)  For each missing value of the carbon content or molecular weight of
the fuel and feedstock, the substitute data value must be the arithmetic
average of the quality-assured values of carbon contents or molecular
weight of the fuel and feedstock immediately preceding and immediately
following the missing data incident. If no quality-assured data on
carbon contents or molecular weight of the fuel and feedstock are
available prior to the missing data incident, the substitute data value
must be the first quality-assured value for carbon contents or molecular
weight of the fuel and feedstock obtained after the missing data period.
 You must document and keep records of the procedures used for all such
estimates.

(c)  For missing CEMS data, you must use the missing data procedures in
§98.35. 

§98.166  Data reporting requirements. 

In addition to the information required by §98.3(c), each annual report
must contain the information specified in paragraphs (a) or (b) of this
section, as appropriate: 

(a)  If a CEMS is used to measure CO2 emissions, then you must report
the relevant information required under §98.36 for the Tier 4
Calculation Methodology and the following information in this paragraph
(a):

(1)  Unit identification number and annual CO2 process emissions.

(2)  Annual quantity of hydrogen produced (metric tons) for each process
unit and for all units combined. 

(3)  Annual quantity of ammonia produced (metric tons), if applicable,
for each process unit and for all units combined. 

(b)  If a CEMS is not used to measure CO2 emissions, then you must
report the following information for each hydrogen production process
unit: 

(1)  Unit identification number and annual CO2 process emissions.

(2)  Monthly consumption of each fuel and feedstock used for hydrogen
production and its type (scf of gaseous fuels and feedstocks, gallons of
liquid fuels and feedstocks, kg of solid fuels and feedstocks). 

(3)  Annual quantity of hydrogen produced (metric tons). 

(4)  Annual quantity of ammonia produced, if applicable (metric tons). 

(5)  Monthly analyses of carbon content for each fuel and feedstock used
in hydrogen production (kg carbon/kg of gaseous and solid fuels and
feedstocks, (kg carbon per gallon of liquid fuels and feedstocks). 

(6)  Monthly analyses of the molecular weight of gaseous fuels and
feedstocks (kg/kg-mole) used, if any.

(c)  Quarterly quantity of CO2 collected and transferred off site in
either gas, liquid, or solid forms (kg), following the requirements of
subpart PP of this part. 

(d)  Annual quantity of carbon other than CO2 collected and transferred
off site in either gas, liquid, or solid forms (kg carbon).

§98.167  Records that must be retained.

In addition to the information required by §98.3(g), you must retain
the records specified in paragraphs (a) through (b) of this section for
each hydrogen production facility.  

(a)  If a CEMS is used to measure CO2 emissions, then you must retain
under this subpart the records required for the Tier 4 Calculation
Methodology in §98.37.

(b)  If a CEMS is not used to measure CO2 emissions, then you must
retain records of all analyses and calculations conducted as listed in
§§98.166(b), (c), and (d).

§98.168  Definitions.

All terms used in this subpart have the same meaning given in the Clean
Air Act and subpart A of this part.

Subpart V—Nitric Acid Production

§98.220 Definition of Source Category.

A nitric acid production facility uses one or more trains to produce
weak nitric acid (30 to 70 percent in strength). A nitric acid train
produces weak nitric acid through the catalytic oxidation of ammonia.

§98.221  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains a nitric acid train and the facility meets the requirements of
either §98.2(a)(1) or (a)(2).

§98.222  GHGs to report.

(a)  You must report N2O process emissions from each nitric acid
production train as required by this subpart.

(b)  You must report under subpart C of this part (General Stationary
Fuel Combustion Sources) the emissions of CO2, CH4, and N2O from each
stationary combustion unit by following the requirements of subpart C.

§98.223  Calculating GHG emissions. 

(a)  You must determine annual N2O process emissions from each nitric
acid train according to paragraphs (a)(1) or (a)(2) of this section.

(1)  Use a site-specific emission factor and production data according
to paragraphs (b) through (h) of this section.

(2)  Request Administrator approval for an alternative method of
determining N2O emissions according to paragraphs (a)(2)(i) and
(a)(2)(ii) of this section.

(i)  You must submit the request within 45 days following promulgation
of this subpart or within the first 30 days of each subsequent reporting
year.

(ii)  If the Administrator does not approve your requested alternative
method within 150 days of the end of the reporting year, you must
determine the N2O emissions factor for the current reporting period
using the procedures specified in paragraph (a)(1) of this section. 

(b)  You must conduct an annual performance test according to paragraphs
(b)(1) through (b)(3) of this section.

(1)  You must measure N2O emissions from the absorber tail gas vent for
each nitric acid train using the methods specified in §98.224(b)
through (d).

(2)  You must conduct the performance test under normal process
operating conditions and without using N2O abatement technology (if
applicable).

(3)  You must measure the production rate during the performance test
and calculate the production rate for the test period in metric tons
(100 percent acid basis) per hour.

(c)  You must determine an N2O emissions factor to use in Equation V-3
of this section according to paragraphs (c)(1) or (c)(2) of this
section.  

(1)  You may request Administrator approval for an alternative method of
determining N2O concentration according to the procedures in paragraphs
(a)(2)(i) and (a)(2)(ii) of this section.  Alternative methods include
the use of N2O CEMs.    

(2)  Using the results of the performance test in paragraph (b) of this
section, you must calculate an average site-specific emission factor for
each nitric acid train “t” according to Equation V-1 of this
section:

 	(Eq. V-1)

Where:  

EFN2Ot	=	Average site-specific N2O emissions factor for nitric acid
train “t” (lb N2O generated/ton nitric acid produced, 100 percent
acid basis).

CN2O	=	N2O concentration for each test run during the performance test
(ppm N2O).

1.14x10-7=	Conversion factor (lb/dscf-ppm N2O).

Q	=	Volumetric flow rate of effluent gas for each test run during the
performance test (dscf/hr).

P	=	Production rate for each test run during the performance test (tons
nitric acid produced per hour, 100 percent acid basis).

n	=	Number of test runs.

(d)  If applicable, you must determine the destruction efficiency for
each N2O abatement technology according to paragraphs (d)(1), (d)(2), or
(d)(3) of this section.

(1)  Use the manufacturer’s specified destruction efficiency.

(2)  Estimate the destruction efficiency through process knowledge. 
Examples of information that could constitute process knowledge include
calculations based on material balances, process stoichiometry, or
previous test results provided the results are still relevant to the
current vent stream conditions.  You must document how process knowledge
(if applicable) was used to determine the destruction efficiency.

(3)  Calculate the destruction efficiency by conducting an additional
performance test on the emissions stream following the N2O abatement
technology.

(e)  If applicable, you must determine the abatement factor for each N2O
abatement technology.  The abatement factor is calculated for each
nitric acid train according to Equation V-2 of this section.

 	(Eq. V-2)

Where:

AFN t	=	Abatement factor of N2O abatement technology at nitric acid
train “t” (fraction of annual production that abatement technology
is operating).

Pa t	= 	Total annual nitric acid production from nitric acid train
“t” (ton acid produced, 100 percent acid basis).

Pa t Abate 	=	 Annual nitric acid production from nitric acid train
“t” during which N2O abatement was used (ton acid produced, 100
percent acid basis).

(f)  You must determine the annual amount of nitric acid produced and
the annual amount of nitric acid produced while each N2O abatement
technology is operating from each nitric acid train (100 percent basis).

(g)  You must calculate N2O emissions for each nitric acid train by
multiplying the emissions factor (determined in Equation V-1 of this
section) by the annual nitric acid production and accounting for N2O
abatement, according to Equation V-3 of this section: 

 	(Eq. V-3)

Where:

EN2Ot	=	N2O mass emissions per year for nitric acid train “t”
(metric tons).

EFN2Ot	=	Average site-specific N2O emissions factor for nitric acid
train ”t” (lb N2O generated/ton acid produced, 100 percent acid
basis).

Pa t	=	Annual nitric acid production from the train “t” (ton acid
produced, 100 percent acid basis).

DFN t	=	Destruction efficiency of N2O abatement technology N that is
used on nitric acid train “t” (percent of N2O removed from air
stream).

AFN t	=	Abatement factor of N2O abatement technology for nitric acid
train “t” (fraction of annual production that abatement technology
is operating).

2204.63	=	Conversion factor (lb/metric ton).

	z	=	Number of different N2O abatement technologies.

(h)  You must determine the annual nitric acid production emissions
combined from all nitric acid trains at your facility using Equation V-4
of this section:

 	(Eq. V-4)

Where:

N2O	=	Annual process N2O emissions from nitric acid production facility
(metric tons)

EN2Ot	=	N2O mass emissions per year for nitric acid train “t”
(metric tons).

m	=	Number of nitric acid trains.

§98.224  Monitoring and QA/QC requirements.

(a)  You must conduct a new performance test and calculate a new
site-specific emissions factor according to a test plan as specified in
paragraphs (a)(1) through (a)(3) of this section.

(1)  Conduct the performance test annually.

(2)  Conduct the performance test when your nitric acid production
process is changed, specifically when abatement equipment is installed. 

(3)  If you requested Administrator approval for an alternative method
of determining N2O concentration under §98.223(a)(2), you must conduct
the performance test if your request has not been approved by the
Administrator within 150 days of the end of the reporting year in which
it was submitted. 

(b)  You must measure the N2O concentration during the  performance test
using one of the methods in paragraphs (b)(1) through (b)(3) of this
section.

(1)  EPA Method 320 at 40 CFR part 63, appendix A, Measurement of Vapor
Phase Organic and Inorganic Emissions by Extractive Fourier Transform
Infrared (FTIR) Spectroscopy.

(2)  ASTM D6348-03 Standard Test Method for Determination of Gaseous
Compounds by Extractive Direct Interface Fourier Transform Infrared
(FTIR) Spectroscopy (incorporated by reference in §98.7).

(3)  An equivalent method, with Administrator approval.

(c)  You must determine the production rate(s) (100 percent basis) from
each nitric acid train during the performance test according to
paragraphs (c)(1) or (c)(2) of this section.

(1)  Direct measurement of production and concentration (such as using
flow meters, weigh scales, for production and concentration
measurements). 

(2)  Existing plant procedures used for accounting purposes (i.e.
dedicated tank-level and acid concentration measurements).

(d)  You must conduct all performance tests in conjunction with the
applicable EPA methods in 40 CFR part 60, appendices A-1 through A-4. 
Conduct three emissions test runs of 1 hour each.  All QA/QC procedures
specified in the reference test methods and any associated performance
specifications apply.  For each test, the facility must prepare an
emission factor determination report that must include the items in
paragraphs (d)(1) through (d)(3) of this section.

(1)  Analysis of samples, determination of emissions, and raw data.

(2)  All information and data used to derive the emissions factor(s).   

(3)  The production rate during each test and how it was determined.

(e)  You must determine the monthly nitric acid production and the
monthly nitric acid production during which N2O abatement technology is
operating from each nitric acid train according to the methods in
paragraphs (c)(1) or (c)(2) of this section. 

(f)  You must determine the annual nitric acid production and the annual
nitric acid production during which N2O abatement technology is
operating for each train by summing the respective monthly nitric acid
production quantities.

§98.225  Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions
calculations is required.  Therefore, whenever a quality-assured value
of a required parameter is unavailable, a substitute data value for the
missing parameter shall be used in the calculations as specified in
paragraphs (a) and (b) of this section. 

(a)  For each missing value of nitric acid production, the substitute
data shall be the best available estimate based on all available process
data or data used for accounting purposes (such as sales records). 

(b)  For missing values related to the performance test, including
emission factors, production rate, and N2O concentration, you must
conduct a new performance test according to the procedures in §98.224
(a) through (d).

§98.226  Data reporting requirements. 

In addition to the information required by §98.3(c), each annual report
must contain the information specified in paragraphs (a) through (o) of
this section for each nitric acid production train.

(a)  Train identification number.

(b)  Annual process N2O emissions from each nitric acid train (metric
tons).

(c)  Annual nitric acid production from each nitric acid train (tons,
100 percent acid basis).

(d)  Annual nitric acid production from each nitric acid train during
which N2O abatement technology is operating (ton acid produced, 100
percent acid basis)

(e)  Annual nitric acid production from the nitric acid facility (tons,
100 percent acid basis).

(f)  Number of nitric acid trains.

(g)  Number of abatement technologies (if applicable).

(h)  Abatement technologies used (if applicable). 

(i)  Abatement technology destruction efficiency for each abatement
technology (percent destruction).

(j)  Abatement utilization factor for each abatement technology
(fraction of annual production that abatement technology is operating).

(k)  Type of nitric acid process used for each nitric acid train (low,
medium, high, or dual pressure).

(l)  Number of times in the reporting year that missing data procedures
were followed to measure nitric acid production (months).

(m)  If you conducted a performance test and calculated a site-specific
emissions factor according to §98.223(a)(1), each annual report must
also contain the information specified in paragraphs (m)(1) through
(m)(7) of this section for each nitric acid production facility.

(1)  Emission factor calculated for each nitric acid train (lb N2O/ ton
nitric acid, 100 percent acid basis).

(2)  Test method used for performance test.

(3)  Production rate per test run during performance test (tons nitric
acid produced/hr, 100 percent acid basis). 

(4)  N2O concentration per test run during performance test (ppm N2O).

(5)  Volumetric flow rate per test run during performance test
(dscf/hr).

(6)  Number of test runs during performance test.

(7)  Number of times in the reporting year that a performance test had
to be repeated (number).

(n)  If you requested Administrator approval for an alternative method
of determining N2O concentration under §98.223(a)(2), each annual
report must also contain the information specified in paragraphs (n)(1)
through (n)(4) of this section for each nitric acid production facility.

(1)  Name of alternative method.

(2)  Description of alternative method.

(3)  Request date.

(4)  Approval date.

(o)  Total pounds of synthetic fertilizer produced through and total
nitrogen contained in that fertilizer.

§98.227  Records that must be retained. 

In addition to the information required by §98.3(g), you must retain
the records specified in paragraphs (a) through (g) of this section for
each nitric acid production facility:

(a)  Records of significant changes to process.

(b)  Documentation of how process knowledge was used to estimate
abatement technology destruction efficiency (if applicable).

(c)  Performance test reports.

(d)  Number of operating hours in the calendar year for each nitric acid
train (hours).

(e)  Annual nitric acid permitted production capacity (tons).

(f)  Measurements, records, and calculations used to determine reported
parameters.

(g)  Documentation of the procedures used to ensure the accuracy of the
measurements of all reported parameters, including but not limited to,
calibration of weighing equipment, flow meters, and other measurement
devices.  The estimated accuracy of measurements made with these devices
must also be recorded, and the technical basis for these estimates must
be provided.

§98.228  Definitions.

All terms used in this subpart have the same meaning given in the Clean
Air Act and subpart A of this part. 

Subpart X—Petrochemical Production

§98.240  Definition of the source category.

(a)  The petrochemical production source category consists of all
processes that produce acrylonitrile, carbon black, ethylene, ethylene
dichloride, ethylene oxide, or methanol, except as specified in
paragraphs (b) through (fg) of this section.  The source category
includes processes that produce the petrochemical as an intermediate in
the onsite production of other chemicals as well as processes that
produce the petrochemical as an end product for sale or shipment
offsite.

(b)  A process that produces a petrochemical as a byproduct is not part
of the petrochemical production source category.

(c)  A facility that makes methanol, hydrogen, and/or ammonia from
synthesis gas is part of the petrochemical source category if the annual
mass of methanol produced exceeds the individual annual mass production
levels of both hydrogen recovered as product and ammonia.  The facility
is part of subpart P of this part (Hydrogen Production) if the annual
mass of hydrogen recovered as product exceeds the individual annual mass
production levels of both methanol and ammonia.  The facility is part of
subpart G of this part (Ammonia Manufacturing) if the annual mass of
ammonia produced exceeds the individual annual mass production levels of
both hydrogen recovered as product and methanol.

(d)  A direct chlorination process that is operated independently of an
oxychlorination process to produce ethylene dichloride is not part of
the petrochemical production source category.

(e)  A process that produces bone black is not part of the petrochemical
source category.

(f)  A process that produces a petrochemical from bio-based feedstock is
not part of the petrochemical production source category. 

(g)  A process that solely distills or recycles waste solvent that
contains a petrochemical is not part of the petrochemical production
source category.

§98.241  Reporting threshold.  

You must report GHG emissions under this subpart if your facility
contains a petrochemical process as specified in §98.240, and the
facility meets the requirements of either §98.2(a)(1) or (2).

§98.242  GHGs to report.

You must report the information in paragraphs (a) through (c) of this
section:

(a)  CO2 CH4, and N2O process emissions from each petrochemical process
unit.  Process emissions include CO2 generated by reaction in the
process and by combustion of process off-gas in stationary combustion
units and flares.  

(1)  If you comply with §98.243(b) or (d), report under this subpart
the calculated CO2, CH4, and N2O emissions for each stationary
combustion source and flare that burns any amount of petrochemical
process off-gas.  If you comply with §98.243(b), also report under this
subpart the measured CO2 emissions from process vents routed to stacks
that are not associated with stationary combustion units.

(2)  If you comply with §98.243(c), report under this subpart the
calculated CO2 emissions for each petrochemical process unit.

(b)  CO2, CH4, and N2O combustion emissions from stationary combustion
units and flares.  

(1)  If you comply with §98.243(b) or (d), report these emissions from
stationary combustion units that are associated with petrochemical
process units and burn only supplemental fuel under subpart C of this
part (General Stationary Fuel Combustion Sources) by following the
requirements of subpart C.

(2)  If you comply with §98.243(c), report CO2, CH4, and N2O combustion
emissions under subpart C of this part (General Stationary Fuel
Combustion Sources) by following the requirements of subpart C only for
the combustion of supplemental fuel.  Determine the applicable Tier in
subpart C of this part (General Stationary Fuel Combustion Sources)
based on the maximum rated heat input capacity of the stationary
combustion source.  

(c)  CO2 captured.  You must report the mass of CO2 captured under,
subpart PP of this part (Suppliers of Carbon Dioxide (CO2) by following
the requirements of subpart PP.  

§98.243  Calculating GHG emissions.

(a)  If you route all process vent emissions and emissions from
combustion of process off-gas to one or more stacks and use CEMS on each
stack to measure CO2 emissions (except flare stacks), then you must
determine process-based GHG emissions in accordance with paragraph (b)
of this section.  Otherwise, determine process-based GHG emissions in
accordance with the procedures specified in paragraph (c) or (d) of this
section. 

(b)  Continuous emission monitoring system (CEMS).   Route all process
vent emissions and emissions from combustion of process off-gas to one
or more stacks and determine CO2 emissions from each stack (except flare
stacks) according to the Tier 4 Calculation Methodology requirements in
subpart C of this part.  For each stack (except flare stacks) that
includes emissions from combustion of petrochemical process off-gas,
calculate CH4 and N20 emissions in accordance with subpart C of this
part (use the Tier 3 methodology and, emission factors for
“Petroleum” in Table C-2 of subpart C of this part, and either the
default high heat value for fuel gas in Table C-1 of subpart C of this
part or a calculated HHV, as allowed in Equation C-8 of subpart C of
this part).  For each flare, calculate CO2, CH4, and N2O emissions using
the methodology specified in §98.253(b)(1) through (b)(3). 

(c)  Mass balance for each petrochemical process unit.  Calculate the
emissions of CO2 from each process unit, for each calendar month as
described in paragraphs (c)(1) through (c)(5) of this section.

(1)  For each gaseous and liquid feedstock and product, measure the
volume or mass used or produced each calendar month with a flow meter by
following the procedures specified in §98.244(b)(2).  Alternatively,
for liquids, you may calculate the volume used or collected in each
month based on measurements of the liquid level in a storage tank at
least once per month (and just prior to each change in direction of the
level of the liquid) following the procedures specified in
§98.244(b)(3).  Fuels used for combustion purposes are not considered
to be feedstocks.

(2)  For each solid feedstock and product, measure the mass used or
produced each calendar month by following the procedures specified in
§98.244(b)(1).

(3)  Collect a sample of each feedstock and product at least once per
month and determine the carbon content of each sample according to the
procedures in §98.244(b)(4).  Alternatively, you may use the results of
analyses conducted by a fuel or feedstock supplier, provided the
sampling and analysis is conducted at least once per month using any of
the procedures specified in §98.244(b)(4).  If multiple valid carbon
content measurements are made during the monthly measurement period,
average them arithmetically.

(4)  If you determine that the monthly average concentration of a
specific compound in a feedstock or product is greater than 99.5 percent
by volume (or mass for liquids and solids), then as an alternative to
the sampling and analysis specified in paragraph (c)(3) of this section,
you may calculate the carbon content assuming 100 percent of that
feedstock or product is the specific compound during periods of normal
operation.  You must maintain records of any determination made in
accordance with this paragraph (c)(4) along with all supporting data,
calculations, and other information.  This alternative may not be used
for products during periods of operation when off-specification product
is produced.  You must reevaluate determinations made under this
paragraph (c)(4) after any process change that affects the feedstock or
product composition.  You must keep records of the process change and
the corresponding composition determinations.  If the feedstock or
product composition changes so that the average monthly concentration
falls below 99.5 percent, you are no longer permitted to use this
alternative method.

(5)  Calculate the CO2 mass emissions for each petrochemical process
unit using Equations X-1 through X-4 of this section.

(i)  Gaseous feedstocks and products.  Use Equation X-1 of this section
to calculate the net annual carbon input or output from gaseous
feedstocks and products.  Note that the result will be a negative value
if there are no gaseous feedstocks in the process but there are gaseous
products.

 	

	(Eq. X-1)

Where:  

Cg	=	Annual net contribution to calculated emissions from carbon (C) in
gaseous materials (kilograms/year, kg/yr).

(Fgf)i,n	= 	Volume of gaseous feedstock i introduced in month “n”
(standard cubic feet, scf).

(CCgf)i,n	= 	Average carbon content of the gaseous feedstock i for month
“n” (kg C per kg of feedstock).

(MWf)i 	=	Molecular weight of gaseous feedstock i (kg/kg-mole).

MVC 	=	Molar volume conversion factor (849.5 scf per kg-mole at standard
conditions 68 °F and 14.7 pounds per square inch absolute or 836.6
scf/kg-mole at 60 °F and 14.7 pounds per square inch absolute).

(Pgp)i,n	= 	Volume of gaseous product i produced in month “n” (scf).

(CCgp)i,n	= 	Average carbon content of gaseous product i, including
streams containing CO2 recovered for sale or use in another process, for
month “n” (kg C per kg of product).

(MWp)i 	=	Molecular weight of gaseous product i (kg/kg-mole).

j	=	Number of feedstocks.

k	=	Number of products.

(ii)  Liquid feedstocks and products.  Use Equation X-2 of this section
to calculate the net carbon input or output from liquid feedstocks and
products.  Note that the result will be a negative value if there are no
liquid feedstocks in the process but there are liquid products.

 	(Eq. X-2)

Where:

Cl	=	Annual net contribution to calculated emissions from carbon in
liquid materials, including liquid organic wastes (kg/yr).

(Flf)i,n	=	Volume or mass of liquid feedstock i introduced in month
“n” (gallons or kg).

(CClf)i,n	=	Average carbon content of liquid feedstock i for month
“n” (kg C per gallon or kg of feedstock).

(Plp)i,n	=	Volume or mass of liquid product i produced in month “n”
(gallons or kg).

(CClp)i,n	=	Average carbon content of liquid product i, including
organic liquid wastes, for month “n” (kg C per gallon or kg of
product).

j	=	Number of feedstocks.

k	=	Number of products.

(iii)  Solid feedstocks and products.  Use Equation X-3 of this section
to calculate the net annual carbon input or output from solid feedstocks
and products.  Note that the result will be a negative value if there
are no solid feedstocks in the process but there are solid products.

 	(Eq. X-3)

Where:

Cs	=	Annual net contribution to calculated emissions from carbon in
solid materials (kg/yr).

(Fsf)i,n	=	Mass of solid feedstock i introduced in month “n” (kg).

(CCsf)i,n	=	Average carbon content of solid feedstock i for month
“n” (kg C per kg of feedstock).

(Psp)i,n	=	Mass of solid product i produced in month “n” (kg).

(CCsp)i,n	=	Average carbon content of solid product i in month “n”
(kg C per kg of product).

j	=	Number of feedstocks.

k	=	Number of products.

(iv)  Annual emissions.  Use the results from Equations X-1 through X-3
of this section, as applicable, in Equation X-4 of this section to
calculate annual CO2 emissions.

 	(Eq. X-4)

Where:  

CO2	=	Annual CO2 mass emissions from process operations and process
off-gas combustion (metric tons/year).

0.001	=	Conversion factor from kg to metric tons.

44 	=	Molecular weight of CO2 (kg/kg-mole).

12	=	Atomic weight of carbon (C) (kg/kg-mole).

(d)  Optional combustion methodology for ethylene production processes. 
For any each ethylene production process, calculate CO2 GHG emissions
from each combustion of unit that burns fuel that contains any off-gas
from the ethylene process as specified in paragraphs (d)(1) through
(d)(5) of this section.  

(1)  Except as specified in paragraphs (d)(2) and (d)(5) of this
section, calculate CO2 emissions off-gas using the Tier 3 or Tier 4
methodology in subpart C of this part., 

(2)  You may use either Equation C-1 or Equation C-2a in subpart C of
this part to calculate CO2 emissions from combustion of any ethylene
process off-gas streams that meet either of the conditions in paragraphs
(d)(2)(i) or (d)(2)(ii) of this section (for any default values in the
calculation, use the defaults for fuel gas in Table C-1 of subpart C of
this part).  Follow the otherwise applicable procedures in subpart C to
calculate emissions from combustion of all other fuels in the combustion
unit.

(i)  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 at 60°F and 14.7 pounds per square inch absolute,
and a flow meter is not installed at any point in the line supplying
fuel gas or an upstream common pipe. Calculate the annual average flow
rate using company records assuming total flow is evenly distributed
over 525,600 minutes per year.

(ii)  The combustion unit has a maximum rated heat input capacity of
less than 30 MMBtu/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.

(3)  Except as specified in paragraph (d)(5) of this section, and
calculate CH4 and N2O emissions using the applicable procedures in
§98.33(c) for the same tier methodology that you used for calculating
CO2 emissions.

(i)  For all gaseous fuels that contain ethylene process off-gas, use
the emission factors for “Petroleum” in Table C-2 of subpart C of
this part (General Stationary Fuel Combustion Sources).

(ii)  For Tier 3, use either the default high heat value for fuel gas in
Table C-1 of subpart C of this part or a calculated HHV, as allowed in
Equation C-8 of subpart C of this part.  

(4)  You are not required to use the same Tier for each stationary
combustion unit that burns ethylene process off-gas.  

(5)  For each flare, calculate CO2, CH4, and N2O emissions using the
methodology specified in §98.253(b)(1) through (b)(3).

§98.244  Monitoring and QA/QC requirements.

(a)  If you use CEMS to determine emissions from process vents, you must
comply with the procedures specified in §98.34(c).

(b)  If you use the mass balance methodology in §98.243(c), use the
procedures specified in paragraphs (b)(1) through (b)(4) of this section
to determine feedstock and product flows and carbon contents.

(1)  Operate, and maintain, and calibrate belt scales or other weighing
devices as described in Specifications, Tolerances, and Other Technical
Requirements For Weighing and Measuring Devices NIST Handbook 44 (2009)
(incorporated by reference, see §98.7) or follow procedures specified
by the measurement device manufacturer.  You must Calibrate the
measurement device according to the procedures specified by the method,
the procedures specified by the manufacturer, or §98.3(i). 
Rrecalibrate each weighing device at one of the following frequencies. 
You may recalibrate either biennially (i.e., once every two years) or or
at the minimum frequency specified by the manufacturer.

(2)  Operate and maintain all flow meters used for gas and liquid
feedstocks and products according to the manufacturer’s recommended
procedures.  You must calibrate each of these flow meters according to
one of the following.  You may use either by following the procedures in
§98.3(i) and using any of the flow meter methods specified in
paragraphs (b)(2)(i) through (b)(2)(xv) of this section, as applicable,
use an industry consensus standard method or  published by a
consensus-based standards organization (e.g., ASTM, API, etc.), or
follow procedures methods specified by the flow meter manufacturer or
§98.3(i).  Each flow meter must meet the applicable accuracy
specification in §98.3(i), except as otherwise specified in
§98.3(i)(4) through (i)(6).  RYou must recalibrate each flow meter
according to one of the following frequencies.  You may recalibrate
either biennially or, at the minimum frequency specified by the
manufacturer, or at the interval specified by the industry consensus
standard practice used.

(i)  ASME MFC–3M–2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi (incorporated by reference, see §98.7).

(ii)  ASME MFC–4M–1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters (incorporated by reference, see §98.7).

(iii)  ASME MFC–5M–1985 (Reaffirmed 1994) Measurement of Liquid Flow
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters
(incorporated by reference, see §98.7).

(iv)  ASME MFC–6M–1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters (incorporated by reference, see §98.7).

(v)  ASME MFC–7M–1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference, see
§98.7).

(vi)  ASME MFC–9M–1988 (Reaffirmed 2001) Measurement of Liquid Flow
in Closed Conduits by Weighing Method (incorporated by reference, see
§98.7).

(vii)  ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis
Mass Flowmeters (incorporated by reference, see §98.7).

(viii)  ASME MFC-14M-2003 (Reaffirmed 2008), Measurement of Fluid Flow
Using Small Bore Precision Orifice Meters (incorporated by reference,
see §98.7).

(ix)  ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits
with Electromagnetic Flowmeters (incorporated by reference, see §98.7).

(x)  ASME MFC-18M-2001 (Reaffirmed 2006), Measurement of Fluid Flow
Using Variable Area Meters (incorporated by reference, see §98.7).

(xi)  ASME MFC-22-2007 Measurement of Liquid by Turbine Flowmeters
(incorporated by reference, see §98.7).

(xii)  AGA Report No. 3: Orifice Metering of Natural Gas and Other
Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty
Guidelines (1990), Part 2: Specification and Installation Requirements
(2000) (incorporated by reference, see §98.7).

(xiii)  AGA Transmission Measurement Committee Report No. 7: 
Measurement of Natural Gas by Turbine Meter (2006)/February
(incorporated by reference, see §98.7).

(xiv)  AGA Report No. 11: Measurement of Natural Gas by Coriolis Meter
(2003) (incorporated by reference, see §98.7).

(xv)  ISO 8316:  Measurement of Liquid Flow in Closed Conduits—Method
by Collection of the Liquid in a Volumetric Tank (1987–10-01) First
Edition (incorporated by reference, see §98.7).

(3)  You must pPerform tank level measurements (if used to determine
feedstock or product flows) according to one of the following methods. 
You may use any standard method published by a consensus-based standards
organization (e.g., ASTM, API, etc.) or you may use industry standard
practice.or follow procedures specified by the measurement device
manufacturer or §98.3(i).  Calibrate the measurement devices prior to
the effective date of the rule, and recalibrate either biennially or at
the minimum frequency specified by the manufacturer or §98.3(i).

(4)  Use any of the applicable standard methods specified in paragraphs
(b)(4)(i) through (b)(4)(xiii) of this section, as applicable, to
determine the carbon content or composition of feedstocks and products
and the average molecular weight of gaseous feedstocks and products. 
Calibrate instruments in accordance with the method and as specified in
paragraphs (b)(4)(i) through (b)(4)(xiii), as applicable.  For coal used
as a feedstock, the samples for carbon content determinations shall be
taken at a location that is representative of the coal feedstock used
during the corresponding monthly period.  For carbon black products,
samples shall be taken of each grade or type of product produced during
the monthly period.  Samples of coal feedstock or carbon black product
for carbon content determinations may be either grab samples collected
and analyzed monthly or a composite of samples collected more frequently
and analyzed monthly.  Analyses conducted in accordance with methods
specified in paragraphs (b)(4)(i) through (b)(4)(xiii) of this section
may be performed by the owner or operator, by an independent laboratory,
or by the supplier of a feedstock.

(i)  ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by reference, see §98.7).

(ii)  ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of
Process Vents With a Portable Gas Chromatograph (incorporated by
reference, see §98.7).

(iii)  ASTM D2505-88(Reapproved 2004)e1 Standard Test Method for
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene
by Gas Chromatography (incorporated by reference, see §98.7).

(iv)  ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography
(incorporated by reference, see §98.7).

(v)  ASTM D3176-89 (Reapproved 2002) Standard Practice Method for
Ultimate Analysis of Coal and Coke (incorporated by reference, see
§98.7).

(vi)  ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants (incorporated by reference, see
§98.7).

(vii)  ASTM D5373-08 Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of
Coal (incorporated by reference, see §98.7).

(viii)  Methods 8031, 8021, or 8015 in “Test Methods for Evaluating
Solid Waste, Physical/Chemical Methods,” EPA Publication No. SW-846,
Third Edition, September 1986, as amended by Update I, November 15,
1992.

(ix)  Method 18 at 40 CFR part 60, appendix A-6. 

(x)  Performance Specification 9 in 40 CFR part 60, appendix B for
continuous online gas analyzers. The 7-day calibration error test period
must be completed prior to the effective date of the rule.

(xi)  ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene
Purity and Hydrocarbon Impurities by Gas Chromatography, (incorporated
by reference, see §98.7), effective as of January 1, 2010. 

(xii)  An industry standard practice for carbon black feedstock oils and
carbon black products, effective as of January 1, 2010.

(xiii)  Modifications of existing analytical methods or other analytical
methods that are applicable to your process provided that the methods
listed in §98.244(b)(4)(i) through §98.244(b)(4)(xii) are not
appropriate because the relevant compounds cannot be detected, the
quality control requirements are not technically feasible, or use of the
method would be unsafe, effective as of January 1, 2010.

§98.245  Procedures for estimating missing data.

For missing feedstock flow rates, product flow rates, and carbon
contents, use the same procedures as for missing flow rates and carbon
contents for fuels as specified in §98.35.

§98.246  Data reporting requirements.

In addition to the information required by §98.3(c), each annual report
must contain the information specified in paragraphs (a), (b), or (c) of
this section, as appropriate for each process unit.

(a)  If you use the mass balance methodology in §98.243(c), you must
report the information specified in paragraphs (a)(1) through
(a)(10)(11) of this section for each type of petrochemical produced,
reported by process unit.

(1)  The petrochemical process unit ID number or other appropriate
descriptor.

(2)  The type of petrochemical produced, names of other products, and
names of carbon-containing feedstocks.

(3)  Annual CO2 emissions calculated using Equation X-4 of this subpart.

(4)  Each of the monthly volume, mass, and carbon content values used in
Equations X-1 through X-3 of this subpart (i.e., the directly measured
values, substitute values, or the calculated values based on other
measured data such as tank levels or gas composition) and the molecular
weights for gaseous feedstocks and products used in Equation X-1 of this
subpart, and the temperture (in °F) at which the gaseous feedstock and
product volumes used in Equation X-1 of this subpart were determined. 
Indicate whether you used the alternative to sampling and analysis
specified in §98.243(c)(4).

(5)  Annual quantity of each type of petrochemical produced from each
process unit (metric tons).

(6)  Name of each method listed in §98.244 used to determine a measured
parameter (or description of manufacturer’s recommended method).

(7)  [Reserved]The dates and summarized results (e.g., percent
calibration error) of the calibrations of each measurement device.

(8)  Identification of each combustion unit that burned both process
off-gas and supplemental fuel.

(9)  If you comply with the alternative to sampling and analysis
specified in §98.243(c)(4), the amount of time during which
off-specification product was produced, the volume or mass of
off-specification product produced, and if applicable, the date of any
process change that reduced the composition to less than 99.5 percent.

(10)  You may elect to report the flow and carbon content of wastewater,
and you may elect to report the annual mass of carbon content of
hydrocarbons released in fugitive emissions and in process vents that
are not controlled with a combustion device.  These values may be
estimated based on engineering analyses.  These values are not to be
used in the mass balance calculation.

(11)  If you determine carbon content or composition of a feedstock or
product using a method under §98.244(b)(4)(xiii), report the
information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of this
section.  Include the information in paragraph (a)(11)(i) of this
section in each annual report.  Include the information in paragraphs
(a)(11)(ii) and (a)(11)(iii) of this section only in the first
applicable annual report, and provide any changes to this information in
subsequent annual reports.

(i)  Name or title of the analytical method.

(ii)  A copy of the method.  If the method is a modification of a method
listed in §98.244(b)(4)(i) through (xii), you may provide a copy of
only the sections that differ from the listed method.

(iii)  An explanation of why an alternative to the methods listed in
§98.244(b)(4)(i) through (xii) is needed.

(b)  If you use CEMS to measure CO2 emissions in accordance with
§98.243(b), then you must report the relevant information required
under §98.36 for the Tier 4 Calculation Methodology and the information
listed in paragraphs (b)(1) through (b)(68) of this section.

(1)  The petrochemical process unit ID or other appropriate descriptor,
and the type of petrochemical produced.

(12)  For CEMS used on stacks for stationary combustion units, report
the relevant information required under §98.36 for the Tier 4
calculation methodology.  Section 98.36(b)(9)(iii) does not apply for
the purposes of this subpart.

(23)  For CEMS used on stacks that are not used for stationary
combustion units, report the information required under
§98.36(e)(2)(vi) and (vii).

(3)  The petrochemical process unit ID or other appropriate descriptor,
and the type of petrochemical produced.

(4)  The CO2 emissions from each stack and the combined CO2 emissions
from all stacks (except flare stacks) that handle process vent emissions
and emissions from stationary combustion units that burn process off-gas
for the petrochemical process unit.  If aFor each stationary combustion
unit (or group of combustion units monitored with a single CO2 CEMS)
that burns petrochemical process off-gassource serves multiple
petrochemical process units or units other than the petrochemical
process unit, provide an estimate based on engineering judgment of the
fraction of fuel energy andthe total emissions that is attributable to
combustion of off-gas from theeach petrochemical process unit.

(5)  For stationary combustion units that burn process off-gas from the
petrochemical process unit, report the information related to CH4 and
N2O emissions as specified in paragraphs (b)(5)(i) through (b)(5)(iv) of
this section.

(i)  The CH4 and N2O emissions from each stack that is monitored with a
CO2 CEMS, expressed in metric tons of each gas and in metric tons of
CO2e.  For each stack provide an estimate based on engineering judgment
of the fraction of the total emissions that is attributable to
combustion of off-gas from the petrochemical process unit.

(ii)  and tThe combined CH4 and N2O emissions from all stationary
combustion units, expressed in metric tons of each gas and in metric
tons of CO2e.

(iii)  The quantity of each type of fuel used in Equation C-8 in
§98.33(c) for each stationary combustion unit or group of units (as
applicable) during the reporting year, expressed in short tons for solid
fuels, gallons for liquid fuels, and scf for gaseous fuels.

(iv)  The HHV (either default or annual average from measured data) used
in Equation C-8 in §98.33(c) for each stationary combustion unit or
group of combustion units (as applicable) that burn process off-gas from
the petrochemical process unit, the cumulative annual heat input used in
Equation C-10 in §98.33(c) of this subpart, and the annual flow of each
fuel on which this heat input is based.

(6)  ID or other appropriate descriptor of each stationary combustion
unit that burns process off-gas.

(7)  Information listed in §98.256(e) of subpart Y of this part for
each flare that burns process off-gas.

(8)  Annual quantity of each type of petrochemical produced from each
process unit (metric tons).

(c)  If you comply with the combustion methodology specified in
§98.243(d), you must report under this subpart the information listed
in paragraphs (c)(1) through (c)(45) of this section.

(1)  The ethylene process unit ID or other appropriate descriptor. 

(12)  For each stationary combustion unit that burns ethylene process
off-gas (or group of stationary sources with a common pipe), except
flares, the relevant information listed in §98.36 for the applicable
Tier selected Tier 3 or Tier 4 methodology.  If aFor each stationary
combustion unit or group of units (as applicable) that burns ethylene
process off-gas, provide ansource serves multiple ethylene process units
or units other than the ethylene process unit, estimate based on
engineering judgment of the fraction of fuel energy andthe total
emissions that is attributable to combustion of off-gas from the each
ethylene process unit.

(23)  Information listed in §98.256(e) of subpart Y of this part for
each flare that burns ethylene process off-gas.

(34)  Name and annual quantity of each feedstock.

(45)  Annual quantity of each type of petrochemicalethylene produced
from each process unit (metric tons).

§98.247  Records that must be retained.

In addition to the recordkeeping requirements in §98.3(g), you must
retain the records specified in paragraphs (a) through (c) of this
section, as applicable.

(a)  If you comply with the CEMS measurement methodology in §98.243(b),
then you must retain under this subpart the records required for the
Tier 4 Calculation Methodology in §98.37, records of the procedures
used to develop estimates of the fraction of total emissions
attributable to combustion of petrochemical process off-gas as required
in §98.246(b), and records of any annual average HHV calculations.

(b)  If you comply with the mass balance methodology in §98.243(c),
then you must retain records of the information listed in paragraphs
(b)(1) through (b)(34) of this section.

(1)  Results of feedstock or product composition determinations
conducted in accordance with §98.243(c)(4).

(2)  Start and end times and calculated carbon contents for time periods
when off-specification product is produced, if you comply with the
alternative methodology in §98.243(c)(4) for determining carbon content
of feedstock or product.

(3)  A part of the monitoring plan required under §98.3(g)(5), record
the estimated accuracy of measurement devices and the technical basis
for these estimates.

(4) The dates and results (e.g., percent calibration error) of the
calibrations of each measurement device.

(c)  If you comply with the combustion methodology in §98.243(d), then
you must retain under this subpart the records required for the
applicable Tier 3 and/or Tier 4 Calculation Methodologies in §98.37. 
If you comply with §98.243(d)(2), you must also keep records of the
annual average flow calculations.

§98.248  Definitions.

Except as specified in this section, all terms used in this subpart have
the same meaning given in the Clean Air Act and subpart A of this part. 

Product, as used in §98.243, means each of the following
carbon-containing outputs from a process:  the petrochemical, recovered
byproducts, and liquid organic wastes that are not incinerated onsite. 
Product does not include process vent emissions, fugitive emissions, or
wastewater.

Subpart Y—Petroleum Refineries

§98.250  Definition of Source Category.

(a)  A petroleum refinery is any facility engaged in producing gasoline,
gasoline blending stocks, naphtha, kerosene, distillate fuel oils,
residual fuel oils, lubricants, or asphalt (bitumen) through
distillation of petroleum or through redistillation, cracking, or
reforming of unfinished petroleum derivatives, except as provided in
paragraph (b) of this section.

(b)  For the purposes of this subpart, facilities that distill only
pipeline transmix (off-spec material created when different
specification products mix during pipeline transportation) are not
petroleum refineries, regardless of the products produced.

(c)  This source category consists of the following sources at petroleum
refineries:  catalytic cracking units; fluid coking units; delayed
coking units; catalytic reforming units; coke calcining units; asphalt
blowing operations; blowdown systems; storage tanks; process equipment
components (compressors, pumps, valves, pressure relief devices,
flanges, and connectors) in gas service; marine vessel, barge, tanker
truck, and similar loading operations; flares; sulfur recovery plants;
and non-merchant hydrogen plants (i.e., hydrogen plants that are owned
or under the direct control of the refinery owner and operator).

§98.251  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains a petroleum refineries process and the facility meets the
requirements of either §98.2(a)(1) or (a)(2).

§98.252  GHGs to report.

You must report:

(a)  CO2, CH4, and N2O combustion emissions from stationary combustion
units and from each flare.  Calculate and report these emissions from
stationary combustion units under subpart C of this part (General
Stationary Fuel Combustion Sources) by following the requirements of
subpart C, except for CO2 emissions from combustion of refinery fuel
gas.  For CO2 emissions from combustion of fuel gas, use either
eEquation C-5 in subpart C of this part or the Tier 4 methodology in
subpart C of this part, unless either of the conditions in paragraphs
(a)(1) or (2) of this section are met, in which case use either
Equations C-1 or C-2a in subpart C of this part.  For CH4 and N2O
emissions from combustion of fuel gas, use the applicable procedures in
§98.33(c) for the same tier methodology that was used for calculating
CO2 emissions.  (Use the default CH4 and N2O emission factors for
“Petroleum (All fuel types in Table C-1)” in Table C-2 of this part.
 For Tier 3, use either the default high heat value for fuel gas in
Table C-1 of subpart C of this part or a calculated HHV, as allowed in
Equation C-8 of subpart C of this part.)  You may aggregate units,
monitor common stacks, or monitor common (fuel) pipes as provided in
§98.36(c) when calculating and reporting emissions from stationary
combustion units.  Calculate and report the emissions from flares under
this subpart.

(1)  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 standard cubic feet per minute at 60ºF and 14.7 pounds
per square inch absolute and either of the conditions in paragraph
(a)(1)(i) or (ii) of this section exist.  Calculate the annual average
flow rate using company records assuming total flow is evenly
distributed over 525,600 minutes per year. 

(i)  A flow meter is not installed at any point in the line supplying
fuel gas or an upstream common pipe.

(ii)  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.

(2)  The combustion unit has a maximum rated heat input capacity of less
than 30 MMBtu/hr and either of the following conditions exist:

(i)  A flow meter is not installed at any point in the line supplying
fuel gas or an upsteam common pipe; or

(ii)  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.

(b)  CO2, CH4, and N2O coke burn-off emissions from each catalytic
cracking unit, fluid coking unit, and catalytic reforming unit under
this subpart.

(c)  CO2 emissions from sour gas sent off site for sulfur recovery
operations under this subpart.  You must follow the calculation
methodologies from §98.253(f)and the monitoring and QA/QC methods,
missing data procedures, reporting requirements, and recordkeeping
requirements of this subpart.

(d)  CO2 process emissions from each on-site sulfur recovery plant under
this subpart.

(e)  CO2, CH4, and N2O emissions from each coke calcining unit under
this subpart. 

(f)  CO2 and CH4 emissions from asphalt blowing operations under this
subpart. 

(g)  CH4 emissions from equipment leaks, storage tanks, loading
operations, delayed coking units, and uncontrolled blowdown systems
under this subpart.

(h)  CO2, CH4, and N2O emissions from each process vent not specifically
included in paragraphs (a) through (g) of this section under this
subpart.

(i)  CO2 and CH4emissions from non-merchant hydrogen production process
units (not including hydrogen produced from catalytic reforming units)
under this subpart.  You must follow the calculation methodologies,
monitoring and QA/QC methods, missing data procedures, reporting
requirements, and recordkeeping requirements of subpart P of this part. 

§98.253  Calculating GHG emissions.

(a)  Calculate GHG emissions required to be reported in §98.252(b)
through (i) using the applicable methods in paragraphs (b) through (n)
of this section.  

(b)  For flares, calculate GHG emissions according to the requirements
in paragraphs (b)(1) through (b)(3) of this section.

(1)  Calculate the CO2 emissions according to the applicable
requirements in paragraphs (b)(1)(i) through (b)(1)(iii) of this
section.

(i)  Flow measurement.  If you have a continuous flow monitor on the
flare, you must use the measured flow rates when the monitor is
operational and the flow rate is within the calibrated range of the
measurement device to calculate the flare gas flow.  If you do not have
a continuous flow monitor on the flare and for periods when the monitor
is not operational or the flow rate is outside the calibrated range of
the measurement device, you must use engineering calculations, company
records, or similar estimates of volumetric flare gas flow.

(ii)  Heat value or carbon content measurement.  If you have a
continuous higher heating value monitor or gas composition monitor on
the flare or if you monitor these parameters at least weekly, you must
use the measured heat value or carbon content value in calculating the
CO2 emissions from the flare using the applicable methods in paragraphs
(b)(1)(ii)(A) and (b)(1)(ii)(B).  

(A)  If you monitor gas composition, calculate the CO2 emissions from
the flare using either Equation Y-1a or Equation Y-1b of this section. 
If daily or more frequent measurement data are available, you must use
daily values when using Equation Y-1a or Equation Y-1b of this section;
otherwise, use weekly values.

 	(Eq.Y-1a)

Where:  

CO2 	=	Annual CO2 emissions for a specific fuel type (metric tons/year).

0.98	=	Assumed combustion efficiency of a flare.

0.001	=	Unit conversion factor (metric tons per kilogram, mt/kg).

n	=	Number of measurement periods.  The minimum value for n is 52 (for
weekly measurements); the maximum value for n is 366 (for daily
measurements during a leap year).

p	=	Measurement period index.

44	=	Molecular weight of CO2 (kg/kg-mole).

12	=	Atomic weight of C (kg/kg-mole).

(Flare)p	=	Volume of flare gas combusted during measurement period
(standard cubic feet per period, scf/period).  If a mass flow meter is
used, measure flare gas flow rate in kg/period and replace the term
“(MW)p/MVC” with “1”.

(MW)p	=	Average molecular weight of the flare gas combusted during
measurement period (kg/kg-mole).  If measurements are taken more
frequently than daily, use the arithmetic average of measurement values
within the day to calculate a daily average.

MVC	=	Molar volume conversion factor (849.5 scf/kg-mole at 68 ºF and
14.7 pounds per square inch absolute (psia) or 836.6 scf/kg-mole at 60
ºF and 14.7 psia).

(CC)p	=	Average carbon content of the flare gas combusted during
measurement period (kg C per kg flare gas).  If measurements are taken
more frequently than daily, use the arithmetic average of measurement
values within the day to calculate a daily average.

 	(Eq.Y-1b)

Where:  

CO2 	=	Annual CO2 emissions for a specific fuel type (metric tons/year).

n	=	Number of measurement periods.  The minimum value for n is 52 (for
weekly measurements); the maximum value for n is 366 (for daily
measurements during a leap year).

p	=	Measurement period index.

(Flare)p	=	Volume of flare gas combusted during measurement period
(standard cubic feet per period, scf/period).  If a mass flow meter is
used, you must determine the average molecular weight of the flare gas
during the measurement period and convert the mass flow to a volumetric
flow.

44	=	Molecular weight of CO2 (kg/kg-mole).

MVC	=	Molar volume conversion factor (849.5 scf/kg-mole at 68ºF and
14.7 psia or 836.6 scf/kg-mole at 60ºF and 14.7 psia).

0.001	=	Unit conversion factor (metric tons per kilogram, mt/kg).

(%CO2)p	=	Mole percent CO2 concentration in the flare gas stream during
the measurement period (mole percent = percent by volume). 

y	=	Number of carbon-containing compounds other than CO2 in the flare
gas stream.

x	=	Index for carbon-containing compounds other than CO2.

0.98	=	Assumed combustion efficiency of a flare (mole CO2 per mole
carbon).

(%Cx)p	=	Mole percent concentration of compound “x” in the flare gas
stream during the measurement period (mole percent = percent by volume) 

CMNx	=	Carbon mole number of compound “x” in the flare gas stream
(mole carbon atoms per mole compound).  E.g., CMN for ethane (C2H6) is
2; CMN for propane (C3H8) is 3. 

(B)  If you monitor heat content but do not monitor gas composition,
calculate the CO2 emissions from the flare using Equation Y-2 of this
section.  If daily or more frequent measurement data are available, you
must use daily values when using Equation Y-2 of this section;
otherwise, use weekly values.

 	(Eq.Y-2)

Where:  

CO2 	=	Annual CO2 emissions for a specific fuel type (metric tons/year).

0.98	=	Assumed combustion efficiency of a flare.

0.001	=	Unit conversion factor (metric tons per kilogram, mt/kg).

n	=	Number of measurement periods.  The minimum value for n is 52 (for
weekly measurements); the maximum value for n is 366 (for daily
measurements during a leap year).

p	=	Measurement period index.

(Flare)p	=	Volume of flare gas combusted during measurement period
(million (MM) scf/period).  If a mass flow meter is used, you must also
measure molecular weight and convert the mass flow to a volumetric flow
as follows:  Flare[MMscf] = 0.000001 × Flare[kg] × MVC/(MW)p, where
MVC is the molar volume conversion factor (849.5 scf/kg-mole) and (MW)p
is the average molecular weight of the flare gas combusted during
measurement period (kg/kg-mole). 

(HHV)p	=	Higher heating value for the flare gas combusted during
measurement period (British thermal units per scf, Btu/scf =
MMBtu/MMscf). If measurements are taken more frequently than daily, use
the arithmetic average of measurement values within the day to calculate
a daily average.   

EmF	=	Default CO2 emission factor of 60 kilograms CO2/MMBtu (HHV basis).

(iii)  Alternative to heat value or carbon content measurements.  If you
do not measure the higher heating value or carbon content of the flare
gas at least weekly, determine the quantity of gas discharged to the
flare separately for periods of routine flare operation and for periods
of start-up, shutdown, or malfunction, and calculate the CO2 emissions
as specified in paragraphs (b)(1)(iii)(A) through (b)(1)(iii)(C) of this
section.

(A)  For periods of start-up, shutdown, or malfunction, use engineering
calculations and process knowledge to estimate the carbon content of the
flared gas for each start-up, shutdown, or malfunction event exceeding
500,000 scf/day. 

(B)  For periods of normal operation, use the average heating value
measured for the fuel gas for the heating value of the flare gas.  If
heating value is not measured, the heating value may be estimated from
historic data or engineering calculations.

(C)  Calculate the CO2 emissions using Equation Y-3 of this section.

 	(Eq.Y-3)

Where:  

CO2 	=	Annual CO2 emissions for a specific fuel type (metric tons/year).

0.98	=	Assumed combustion efficiency of a flare.

0.001	=	Unit conversion factor (metric tons per kilogram, mt/kg).

FlareNorm	=	Annual volume of flare gas combusted during normal
operations from company records, (million (MM) standard cubic feet per
year, MMscf/year).

HHV	=	Higher heating value for fuel gas or flare gas from company
records (British thermal units per scf, Btu/scf = MMBtu/MMscf).  

EmF	=	Default CO2 emission factor for flare gas of 60 kilograms
CO2/MMBtu (HHV basis).

n	=	Number of start-up, shutdown, and malfunction events during the
reporting year exceeding 500,000 scf/day.

p	=	Start-up, shutdown, and malfunction event index.

44	=	Molecular weight of CO2 (kg/kg-mole).

12	=	Atomic weight of C (kg/kg-mole).

(FlareSSM)p	=	Volume of flare gas combusted during indexed start-up,
shutdown, or malfunction event from engineering calculations,
(scf/event).

(MW)p	=	Average molecular weight of the flare gas, from the analysis
results or engineering calculations for the event (kg/kg-mole).

MVC	=	Molar volume conversion factor (849.5 scf/kg-mole at 68 ºF and
14.7 psia or 836.6 scf/kg-mole at 60 ºF and 14.7 psia).

(CC)p	=	Average carbon content of the flare gas, from analysis results
or engineering calculations for the event (kg C per kg flare gas).

(2)  Calculate CH4 using Equation Y-4 of this section. 

 	(Eq. Y-4)

Where:

CH4	=	Annual methane emissions from flared gas (metric tons CH4/year).

CO2	=	Emission rate of CO2 from flared gas calculated in paragraph
(b)(1) of this section (metric tons/year).

EmFCH4	=	Default CH4 emission factor for “PetroleumProducts” from
Table C-2 of subpart C of this part (General Stationary Fuel Combustion
Sources) (kg CH4/MMBtu).

EmF	=	Default CO2 emission factor for flare gas of 60 kg CO2/MMBtu (HHV
basis). 

0.02/0.98	=	correction factor for flare combustion efficiency.

16/44	=	correction factor ratio of the molecular weight of CH4 to CO2

fCH4	=	Weight fraction of carbon in the flare gas prior to combustion
that is contributed by methane from measurement values or engineering
calculations (kg C in methane in flare gas/kg C in flare gas); default
is 0.4.

(3)  Calculate N2O emissions using Equation Y-5 of this section. 

 	(Eq. Y-5)

Where:

N2O	=	Annual nitrous oxide emissions from flared gas (metric tons
N2O/year).

CO2	=	Emission rate of CO2 from flared gas calculated in paragraph
(b)(1) of this section (metric tons/year).

EmFN2O	=	Default N2O emission factor for “PetroleumProducts” from
Table C-2 of subpart C of this part (General Stationary Fuel Combustion
Sources)(kg N2O/MMBtu).

EmF	=	Default CO2 emission factor for flare gas of 60 kg CO2/MMBtu (HHV
basis).

(c)  For catalytic cracking units and traditional fluid coking units,
calculate the GHG emissions using the applicable methods described in
paragraphs (c)(1) through (c)(5) of this section.

(1)  If you operate and maintain a CEMS that measures CO2 emissions
according to subpart C of this part (General Stationary Fuel Combustion
Sources), you must calculate and report CO2 emissions as provided in
paragraphs (c)(1)(i) and (c)(1)(ii) of this section.  Other catalytic
cracking units and traditional fluid coking units must either install a
CEMS that complies with the Tier 4 Calculation Methodology in subpart C
of this part (General Stationary Combustion Souces), or follow the
requirements of paragraphs (c)(2) or (3) of this section.  

(i)  Calculate CO2 emissions by following the Tier 4 Calculation
Methodology specified in §98.33(a)(4) and all associated requirements
for Tier 4 in subpart C of this part (General Stationary Fuel Combustion
Sources).

(ii)  For catalytic cracking units whose process emissions are
discharged through a combined stack with other CO2 emissions (e.g.,
co-mingled with emissions from a If a CO boiler) or other
post-combustion device is used, you must also calculate the other CO2
emissions using from the fuel fired to the CO boiler or post-combustion
device using the applicable methods for the applicable subpart
(e.g.,stationary combustion units in subpart C of this part in the case
of a CO boiler).  Calculate the process emissions from the catalytic
cracking unit or fluid coking unit as the difference in the CO2 CEMS
emissions and the calculated combustion emissions associated with the
additional units discharging through the combined stack. CO boiler.

(2)  For catalytic cracking units and fluid coking units with rated
capacities greater than 10,000 barrels per stream day (bbls/sd) that do
not use a continuous CO2 CEMS for the final exhaust stack, you must
continuously or no less frequently than hourly monitor the O2, CO2, and
(if necessary) CO concentrations in the exhaust stack from the catalytic
cracking unit regenerator or fluid coking unit burner prior to the
combustion of other fossil fuels and calculate the CO2 emissions
according to the requirements of paragraphs (c)(2)(i) through
(c)(2)(iii) of this section:

(i)  Calculate the CO2 emissions from each catalytic cracking unit and
fluid coking unit using Equation Y-6 of this section.

 	(Eq. Y-6)

Where:

CO2	=	Annual CO2 mass emissions (metric tons/year).

Qr	=	Volumetric flow rate of exhaust gas from the fluid catalytic
cracking unit regenerator or fluid coking unit burner prior to the
combustion of other fossil fuels (dry standard cubic feet per hour,
dscfh).

%CO2	=	Hourly average percent CO2 concentration in the exhaust gas
stream from the fluid catalytic cracking unit regenerator or fluid
coking unit burner (percent by volume – dry basis).

%CO	=	Hourly average percent CO concentration in the exhaust gas stream
from the fluid catalytic cracking unit regenerator or fluid coking unit
burner (percent by volume – dry basis).  When there is no
post-combustion device, assume %CO to be zero.

44	=	Molecular weight of CO2 (kg/kg-mole).

MVC	=	Molar volume conversion factor (849.5 scf/kg-mole at 68 ºF and
14.7 psia or 836.6 scf/kg-mole at 60 ºF and 14.7 psia).

0.001	=	Conversion factor (metric ton/kg).

n	=	Number of hours in calendar year.

(ii)  Either continuously monitor the volumetric flow rate of exhaust
gas from the fluid catalytic cracking unit regenerator or fluid coking
unit burner prior to the combustion of other fossil fuels or calculate
the volumetric flow rate of this exhaust gas stream using either
Equation Y-7a or Equation Y-7b of this section.

	(Eq. Y-7a)

Where: 

Qr	=	Volumetric flow rate of exhaust gas from the fluid catalytic
cracking unit regenerator or fluid coking unit burner prior to the
combustion of other fossil fuels (dscfh).

Qa	=	Volumetric flow rate of air to the fluid catalytic cracking unit
regenerator or fluid coking unit burner, as determined from control room
instrumentation (dscfh).

Qoxy	=	Volumetric flow rate of oxygen enriched air to the fluid
catalytic cracking unit regenerator or fluid coking unit burner as
determined from control room instrumentation (dscfh).

%O2	=	Hourly average percent oxygen concentration in exhaust gas stream
from the fluid catalytic cracking unit regenerator or fluid coking unit
burner (percent by volume – dry basis).

%Ooxy	=	O2 concentration in oxygen enriched gas stream inlet to the
fluid catalytic cracking unit regenerator or fluid coking unit burner
based on oxygen purity specifications of the oxygen supply used for
enrichment (percent by volume – dry basis).

%CO2	=	Hourly average percent CO2 concentration in the exhaust gas
stream from the fluid catalytic cracking unit regenerator or fluid
coking unit burner (percent by volume – dry basis).

%CO	=	Hourly average percent CO concentration in the exhaust gas stream
from the fluid catalytic cracking unit regenerator or fluid coking unit
burner (percent by volume – dry basis).  When no auxiliary fuel is
burned and a continuous CO monitor is not required under 40 CFR part 63
subpart UUU, assume %CO to be zero.

 	(Eq. Y-7b)

Where: 

Qr	=	Volumetric flow rate of exhaust gas from the fluid catalytic
cracking unit regenerator or fluid coking unit burner prior to the
combustion of other fossil fuels (dscfh).

Qa	=	Volumetric flow rate of air to the fluid catalytic cracking unit
regenerator or fluid coking unit burner, as determined from control room
instrumentation (dscfh).

Qoxy	=	Volumetric flow rate of oxygen enriched air to the fluid
catalytic cracking unit regenerator or fluid coking unit burner as
determined from control room instrumentation (dscfh).

%N2,oxy	=	N2 concentration in oxygen enriched gas stream inlet to the
fluid catalytic cracking unit regenerator or fluid coking unit burner
based on measured value or maximum N2 impurity specifications of the
oxygen supply used for enrichment (percent by volume – dry basis).

%N2,exhaust =	Hourly average percent N2 concentration in the exhaust gas
stream from the fluid catalytic cracking unit regenerator or fluid
coking unit burner (percent by volume – dry basis).

(iii)  If you have a CO boiler that uses auxiliary fuels or combusts
materials other than catalytic cracking unit or fluid coking unit
exhaust gas, you must determine the CO2 emissions resulting from the
combustion of these fuels or other materials following the requirements
in subpart C and report those emissions by following the requirements of
subpart C of this part.

(3)  For catalytic cracking units and fluid coking units with rated
capacities of 10,000 barrels per stream day (bbls/sd) or less that do
not use a continuous CO2 CEMS for the final exhaust stack, comply with
the requirements in paragraphs (c)(3)(i) of this section or paragraphs
(c)(3)(ii) and (c)(3)(iii) of this section, as applicable.

(i)  If you continuously or no less frequently than daily monitor the
O2, CO2, and (if necessary) CO concentrations in the exhaust stack from
the catalytic cracking unit regenerator or fluid coking unit burner
prior to the combustion of other fossil fuels, you must calculate the
CO2 emissions according to the requirements of paragraphs (c)(2)(i)
through (c)(2)(iii) of this section, except that daily averages are
allowed and the summation can be performed on a daily basis.  

(ii)  If you do not monitor at least daily the O2, CO2, and (if
necessary) CO concentrations in the exhaust stack from the catalytic
cracking unit regenerator or fluid coking unit burner prior to the
combustion of other fossil fuels, calculate the CO2 emissions from each
catalytic cracking unit and fluid coking unit using Equation Y-8 of this
section. 

 	(Eq. Y-8)

Where:

CO2	=	Annual CO2 mass emissions (metric tons/year).

Qunit	=	Annual throughput of unit from company records (barrels (bbls)
per year, bbl/yr).

CBF	=	Coke burn-off factor from engineering calculations (kg coke per
barrel of feed); default for catalytic cracking units = 7.3; default for
fluid coking units = 11. 

0.001	=	Conversion factor (metric ton/kg).

CC	=	Carbon content of coke based on measurement or engineering estimate
(kg C per kg coke); default = 0.94.

44/12	=	Ratio of molecular weight of CO2 to C (kg CO2 per kg C).

(iii)  If you have a CO boiler that uses auxiliary fuels or combusts
materials other than catalytic cracking unit or fluid coking unit
exhaust gas, you must determine the CO2 emissions resulting from the
combustion of these fuels or other materials following the requirements
in subpart C of this part (General Stationary Fuel Combustion Sources)
and report those emissions by following the requirements of subpart C of
this part.

(4)  Calculate CH4 emissions using either unit specific measurement
data, a unit-specific emission factor based on a source test of the
unit, or Equation Y-9 of this section.

 	(Eq. Y-9)

Where:

CH4	=	Annual methane emissions from coke burn-off (metric tons
CH4/year).

CO2	=	Emission rate of CO2 from coke burn-off calculated in paragraphs
(c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or (g)(2) of this section, as
applicable (metric tons/year).

EmF1	=	Default CO2 emission factor for petroleum coke from Table C-1 of
subpart C of this part (General Stationary Fuel Combustion Sources) (kg
CO2/MMBtu).

EmF2	=	Default CH4 emission factor for ”PetroleumProducts” from
Table C-2 of subpart C of this part (General Stationary Fuel Combustion
Sources) (kg CH4/MMBtu).

(5)  Calculate N2O emissions using either unit specific measurement
data, a unit-specific emission factor based on a source test of the
unit, or Equation Y-10 of this section.

 	(Eq. Y-10)

Where:

N2O	=	Annual nitrous oxide emissions from coke burn-off (mt N2O/year).

CO2	=	Emission rate of CO2 from coke burn-off calculated in paragraphs
(c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or (g)(2) of this section, as
applicable (metric tons/year).

EmF1	=	Default CO2 emission factor for petroleum coke from Table C-1 of
subpart C of this part (General Stationary Fuel Combustion Sources) (kg
CO2/MMBtu).

EmF3	=	Default N2O emission factor for ”PetroleumProducts” from
Table C-2 of subpart C of this part (kg N2O/MMBtu).

(d)  For fluid coking units that use the flexicoking design, the GHG
emissions from the resulting use of the low value fuel gas must be
accounted for only once.  Typically, these emissions will be accounted
for using the methods described in subpart C of this part (General
Stationary Fuel Combustion Sources).  Alternatively, you may use the
methods in paragraph (c) of this section provided that you do not
otherwise account for the subsequent combustion of this low value fuel
gas. 

(e)  For catalytic reforming units, calculate the CO2 emissions using
the applicable methods described in paragraphs (e)(1) through (e)(3) of
this section and calculate the CH4 and N2O emissions using the methods
described in paragraphs (c)(4) and (c)(5) of this section, respectively.

(1)  If you operate and maintain a CEMS that measures CO2 emissions
according to subpart C of this part (General Stationary Fuel Combustion
Sources), you must calculate CO2 emissions as provided in paragraphs
(c)(1)(i) and (c)(1)(ii) of this section.  Other catalytic reforming
units must either install a CEMS that complies with the Tier 4
Calculation Methodology in subpart C of this part, or follow the
requirements of paragraph (e)(2) or (e)(3) of this section.

(2)  If you continuously or no less frequently than daily monitor the
O2, CO2, and (if necessary) CO concentrations in the exhaust stack from
the catalytic reforming unit catalyst regenerator prior to the
combustion of other fossil fuels, you must calculate the CO2 emissions
according to the requirements of paragraphs (c)(2)(i) through
(c)(2)(iii) of this section.

(3)  Calculate CO2 emissions from the catalytic reforming unit catalyst
regenerator using Equation Y-11 of this section.

 	(Eq. Y-11)

Where:

CO2	=	Annual CO2 emissions (metric tons/year). 

CBQ	=	Coke burn-off quantity per regeneration cycle or measurement
period from engineering estimates (kg coke/cycle or kg coke/measurement
period).

n	=	Number of regeneration cycles or measurement periods in the calendar
year. 

CC	=	Carbon content of coke based on measurement or engineering estimate
(kg C per kg coke); default = 0.94.

44/12	=	Ratio of molecular weight of CO2 to C (kg CO2 per kg C).

0.001	=	Conversion factor (metric ton/kg).

(f)  For on-site sulfur recovery plants and for sour gas sent off site
for sulfur recovery, calculate and report CO2 process emissions from
sulfur recovery plants according to the requirements in paragraphs
(f)(1) through (f)(5) of this section, or, for non-Claus sulfur recovery
plants, according to the requirements in paragraph (j) of this section
regardless of the concentration of CO2 in the vented gas stream. 
Combustion emissions from the sulfur recovery plant (e.g., from fuel
combustion in the Claus burner or the tail gas treatment incinerator)
must be reported under subpart C of this part (General Stationary Fuel
Combustion Sources).  For the purposes of this subpart, the sour gas
stream for which monitoring is required according to paragraphs (f)(2)
through (f)(5) of this section is not considered a fuel.

(1)  If you operate and maintain a CEMS that measures CO2 emissions
according to subpart C of this part, you must calculate CO2 emissions
under this subpart by following the Tier 4 Calculation Methodology
specified in §98.33(a)(4) and all associated requirements for Tier 4 in
subpart C of this part (General Stationary Fuel Combustion Sources). 
You must monitor fuel use in the Claus burner, tail gas incinerator, or
other combustion sources that discharge via the final exhaust stack from
the sulfur recovery plant and calculate the combustion emissions from
the fuel use according to subpart C of this part.  Calculate the process
emissions from the sulfur recovery plant as the difference in the CO2
CEMS emissions and the calculated combustion emissions associated with
the sulfur recovery plant final exhaust stack.  Other sulfur recovery
plants must either install a CEMS that complies with the Tier 4
Calculation Methodology in subpart C, or follow the requirements of
paragraphs (f)(2) through (f)(5) of this section, or (for non-Claus
sulfur recovery plants only) follow the requirements in paragraph (j) of
this section to determine CO2 emissions for the sulfur recovery plant.  

(2)  Flow measurement.  If you have a continuous flow monitor on the
sour gas feed to the sulfur recovery plant, you must use the measured
flow rates when the monitor is operational to calculate the sour gas
flow rate.  If you do not have a continuous flow monitor on the sour gas
feed to the sulfur recovery plant, you must use engineering
calculations, company records, or similar estimates of volumetric sour
gas flow. 

(3)  Carbon content.  If you have a continuous gas composition monitor
capable of measuring carbon content on the sour gas feed to the sulfur
recovery plant or if you monitor gas composition for carbon content on a
routine basis, you must use the measured carbon content value. 
Alternatively, you may develop a site-specific carbon content factor
using limited measurement data or engineering estimates or use the
default factor of 0.20.

(4)  Calculate the CO2 emissions from each sulfur recovery plant using
Equation Y-12 of this section. 

	(Eq. Y-12)

Where:

CO2	=	Annual CO2 emissions (metric tons/year).

FSG	=	Volumetric flow rate of sour gas feed (including sour water
stripper gas) to the sulfur recovery plant (scf/year).

44	=	Molecular weight of CO2 (kg/kg-mole).

MVC	=	Molar volume conversion factor (849.5 scf/kg-mole at 68 ºF and
14.7 psia or 836.6 scf/kg-mole at 60 ºF and 14.7 psia).

MFC	=	Mole fraction of carbon in the sour gas to the sulfur recovery
plant (kg-mole C/kg-mole gas); default = 0.20.

0.001	=	Conversion factor, kg to metric tons

(5)  If tail gas is recycled to the front of the sulfur recovery plant
and the recycled flow rate and carbon content is included in the
measured data under paragraphs (f)(2) and (f)(3) of this section,
respectively, then the annual CO2 emissions calculated in paragraph
(f)(4) of this section must be corrected to avoid double counting these
emissions.  You may use engineering estimates to perform this correction
or assume that the corrected CO2 emissions are 95 percent of the
uncorrected value calculated using Equation Y-12 of this section.   

(g)  For coke calcining units, calculate GHG emissions according to the
applicable provisions in paragraphs (g)(1) through (g)(3) of this
section.

(1)  If you operate and maintain a CEMS that measures CO2 emissions
according to subpart C of this part, you must calculate and report CO2
emissions under this subpart by following the Tier 4 Calculation
Methodology specified in §98.33(a)(4) and all associated requirements
for Tier 4 in subpart C of this part (General Stationary Fuel Combustion
Sources).  You must monitor fuel use in the coke calcining unit that
discharges via the final exhaust stack from the coke calcining unit and
calculate the combustion emissions from the fuel use according to
subpart C of this part.  Calculate the process emissions from the coke
calcining unit as the difference in the CO2 CEMS emissions and the
calculated combustion emissions associated with the coke calcining unit
final exhaust stack.  Other coke calcining units must either install a
CEMS that complies with the Tier 4 Calculation Methodology in subpart C
of this part, or follow the requirements of paragraph (g)(2) of this
section.

(2)  Calculate the CO2 emissions from the coke calcining unit using
Equation Y-13 of this section.

	(Eq. Y-13)

Where:

CO2	=	Annual CO2 emissions (metric tons/year).

Min	=	Annual mass of green coke fed to the coke calcining unit from
facility records (metric tons/year).

CCGC	=	Average mass fraction carbon content of green coke from facility
measurement data (metric ton carbon/metric ton green coke).

Mout	=	Annual mass of marketable petroleum coke produced by the coke
calcining unit from facility records (metric tons petroleum coke/year).

Mdust	=	Annual mass of petroleum coke dust removed from the process
through collected in the dust collection system of the coke calcining
unit from facility records (metric ton petroleum coke dust/year).  For
coke calcining units that recycle the collected dust, the mass of coke
dust removed from the process is the mass of coke dust collected less
the mass of coke dust recycled to the process.

CCMPC	=	Average mass fraction carbon content of marketable petroleum
coke produced by the coke calcining unit from facility measurement data
(metric ton carbon/metric ton petroleum coke).

44	=	Molecular weight of CO2 (kg/kg-mole).

12	=	Atomic weight of C (kg/kg-mole).

(3)  For all coke calcining units, use the CO2 emissions from the coke
calcining unit calculated in paragraphs (g)(1) or (g)(2), as applicable,
and calculate CH4 using the methods described in paragraph (c)(4) of
this section and N2O emissions using the methods described in paragraph
(c)(5) of this section.

(h)  For asphalt blowing operations, calculate GHGCO2 and CH4 emissions
according to the requirements in paragraph (j) of this section
regardless of the CO2 and CH4 concentrations or according to the
applicable provisions in paragraphs (h)(1) and (h)(2) of this section.

(1)  For uncontrolled asphalt blowing operations or asphalt blowing
operations controlled by vapor scrubbing, calculate CO2 and CH4
emissions using Equations Y-14 and Y-15 of this section, respectively. 

 	(Eq. Y-14)

Where:

CO2	=	Annual CO2 emissions from uncontrolled asphalt blowing (metric
tons CO2/year).

QAB	=	Quantity of asphalt blown (million barrels per year, MMbbl/year).

EFAB,CO2	=	Emission factor for CO2 from uncontrolled asphalt blowing
from facility-specific test data (metric tons CO2/MMbbl asphalt blown);
default = 1,100.

 	(Eq. Y-15)

Where:

CH4	=	Annual methane emissions from uncontrolled asphalt blowing (metric
tons CH4/year).

QAB	=	Quantity of asphalt blown (million barrels per year, MMbbl/year).

EFAB,CH4	=	Emission factor for CH4 from uncontrolled asphalt blowing
from facility-specific test data (metric tons CH4/MMbbl asphalt blown);
default = 580.

(2)  For asphalt blowing operations controlled by thermal oxidizer or
flare, calculate CO2 and CH4 emissions using either Equations Y-16a or
Equation Y-16b of this section and calculate CH4 emissions using
Equation Y-17 of this section, respectively, provided these emissions
are not already included in the flare emissions calculated in paragraph
(b) of this section or in the stationary combustion unit emissions
required under subpart C of this part (General Stationary Fuel
Combustion Sources). 

 	(Eq. Y-16a)

Where:

CO2	=	Annual CO2 emissions from controlled asphalt blowing (metric tons
CO2/year).

0.98	=	Assumed combustion efficiency of thermal oxidizer or flare.

QAB	=	Quantity of asphalt blown (MMbbl/year).

CEFAB	=	Carbon emission factor from asphalt blowing from
facility-specific test data (metric tons C/MMbbl asphalt blown); default
= 2,750.

44	=	Molecular weight of CO2 (kg/kg-mole).

12	=	Atomic weight of C (kg/kg-mole). 

 	(Eq. Y-16b)

Where:

CO2	=	Annual CO2 emissions from controlled asphalt blowing (metric tons
CO2/year).

QAB	=	Quantity of asphalt blown (MMbbl/year).

0.98	=	Assumed combustion efficiency of thermal oxidizer or flare.

EFAB,CO2	=	Emission factor for CO2 from uncontrolled asphalt blowing
from facility-specific test data (metric tons CO2/MMbbl asphalt blown);
default = 1,100.

CEFAB	=	Carbon emission factor from asphalt blowing from
facility-specific test data (metric tons C/MMbbl asphalt blown); default
= 2,750.

44	=	Molecular weight of CO2 (kg/kg-mole).

12	=	Atomic weight of C (kg/kg-mole).

 	(Eq. Y-17)

Where:

CH4	=	Annual methane emissions from controlled asphalt blowing (metric
tons CH4/year).

0.02	=	Fraction of methane uncombusted in thermal oxidizer or flare
based on assumed 98% combustion efficiency.

QAB	=	Quantity of asphalt blown (million barrels per year, MMbbl/year).

EFAB,CH4	=	Emission factor for CH4 from uncontrolled asphalt blowing
from facility-specific test data (metric tons CH4/MMbbl asphalt blown);
default = 580.

(i)  For delayed coking units, calculate the CH4 emissions from the
depressurization of the coking unit vessel (i.e., the "coke drum") to
atmosphere using either of the methods provided in paragraphs (i)(1) or
(i)(2), provided no water or steam is added to the vessel once it is
vented to the atmosphere.  You must use the method in paragraph (i)(1)
of this section if you add water or steam to the vessel after it is
vented to the atmosphere.

(1)  Use the process vent method in paragraph (j) of this section to
calculate the CH4 emissions from the depressurization of the coke drum
or vessel regardless of the CH4 concentration and also calculate the CH4
emissions from the subsequent opening of the vessel for coke cutting
operations using Equation Y-18 of this section.  If you have coke drums
or vessels of different dimensions, use the process vent method in
paragraph (j) of this section and Equation Y-18 for each set of coke
drums or vessels of the same size and sum the resultant emissions across
each set of coke drums or vessels to calculate the CH4 emissions for all
delayed coking units.

 	(Eq. Y-18)

Where:

CH4	=	Annual methane emissions from the delayed coking unit vessel
opening (metric ton/year).

N	=	Cumulative number of vessel openings for all delayed coking unit
vessels of the same dimensions during the year.

H	=	Height of coking unit vessel (feet).

PCV	=	Gauge pressure of the coking vessel when opened to the atmosphere
prior to coke cutting or, if the alternative method provided in
paragraph (i)(2) of this section is used, gauge pressure of the coking
vessel when depressurization gases are first routed to the atmosphere
(pounds per square inch gauge, psig)

14.7	=	Assumed atmospheric pressure (pounds per square inch, psi)

fvoid	=	Volumetric void fraction of coking vessel prior to steaming (cf
gas/cf of vessel); default = 0.6.

D	=	Diameter of coking unit vessel (feet).

16	=	Molecular weight of CH4 (kg/kg-mole). 

MVC	=	Molar volume conversion factor (849.5 scf/ kg-mole at 68 ºF and
14.7 psia or 836.6 scf/kg-mole at 60 ºF and 14.7 psia).

MFCH4	=	Mole fraction of methane in coking vessel gas (kg-mole
CH4/kg-mole gas, wet basis); default value is 0.01.

0.001	=	Conversion factor (metric ton/kg).

(2)  Calculate the CH4 emissions from the depressurization vent and
subsequent opening of the vessel for coke cutting operations using
Equation Y-18 of this section and the pressure of the coking vessel
when the depressurization gases are first routed to the atmosphere.  If
you have coke drums or vessels of different dimensions, use Equation
Y-18 for each set of coke drums or vessels of the same size and sum the
resultant emissions across each set of coke drums or vessels to
calculate the CH4 emissions for all delayed coking units.

(j)  For each process vent not covered in paragraphs (a) through (i) of
this section that can be reasonably expected to contain greater than 2
percent by volume CO2 or greater than 0.5 percent by volume of CH4 or
greater than 0.01 percent by volume (100 parts per million) of N2O,
calculate GHG emissions using the Equation Y-19 of this section.  You
must use Equation Y-19 of this section to calculate CH4 emissions for
catalytic reforming unit depressurization and purge vents when methane
is used as the purge gas or if you elected this method as an alternative
to the methods in paragraphs (f), (h)(1), or (k) (h)(2) of this section.

 	(Eq. Y-19)

Where:

Ex	=	Annual emissions of each GHG from process vent (metric ton/yr).

N	=	Number of venting events per year.

P	=	Index of venting events.

(VR)p	=	Average volumetric flow rate of process gas during the event
(scf per hour) from measurement data, process knowledge, or engineering
estimates.

(MFx)p	=	Mole fraction of GHG x in process vent during the event (kg-mol
of GHG x/kg-mol vent gas) from measurement data, process knowledge, or
engineering estimates.

MWx	=	Molecular weight of GHG x (kg/kg-mole); use 44 for CO2 or N2O and
16 for CH4.

MVC	=	Molar volume conversion factor (849.5 scf/kg-mole at 68 ºF and
14.7 psia or 836.6 scf/kg-mole at 60 ºF and 14.7 psia).

(VT)p	=	Venting time for the event, (hours).

0.001	=	Conversion factor (metric ton/kg) 

(k)  For uncontrolled blowdown systems, you must calculate CH4 emissions
either useusing the methods for process vents in paragraph (j) of this
section regardless of the CH4 concentration or calculate CH4 emissions
using Equation Y20 of this section.  Blowdown systems where the
uncondensed gas stream is routed to a flare or similar control device is
considered to be controlled and is not required to estimate emissions
under this paragraph (k).

 	(Eq. Y-20)

Where:

CH4	=	Methane emission rate from blowdown systems (mt CH4/year).

QRef	=	Quantity of crude oil plus the quantity of intermediate products
received from off site that are processed at the facility (MMbbl/year).

EFBD	=	Methane emission factor for uncontrolled blown systems (scf
CH4/MMbbl); default is 137,000.

16	=	Molecular weight of CH4 (kg/kg-mole).

MVC	=	Molar volume conversion factor (849.5 scf/kg-mole at 68 ºF and
14.7 psia or 836.6 scf/kg-mole at 60 ºF and 14.7 psia).

0.001	=	Conversion factor (metric ton/kg).

(l)  For equipment leaks, calculate CH4 emissions using the method
specified in either paragraph (l)(1) or (l)(2) of this section.

(1)  Use process-specific methane composition data (from measurement
data or process knowledge) and any of the emission estimation procedures
provided in the Protocol for Equipment Leak Emissions Estimates
(EPA-453/R-95-017, NTIS PB96-175401).

(2)  Use Equation Y-21 of this section. 

 	(Eq. Y-21)

Where:

CH4	=	Annual methane emissions from equipment leaks (metric tons/year)

NCD	=	Number of atmospheric crude oil distillation columns at the
facility.

NPU1	=	Cumulative number of catalytic cracking units, coking units
(delayed or fluid), hydrocracking, and full-range distillation columns
(including depropanizer and debutanizer distillation columns) at the
facility.

NPU2	=	Cumulative number of hydrotreating/hydrorefining units, catalytic
reforming units, and visbreaking units at the facility.

NH2	=	Total number of hydrogen plants at the facility.

NFGS	=	Total number of fuel gas systems at the facility. 

(m)  For storage tanks, except as provided in paragraph (m)(34) of this
section, calculate CH4 emissions using the applicable methods in
paragraphs (m)(1) throughand (m)(23) of this section.

(1)  For storage tanks other than those processing unstabilized crude
oil, you must either calculate CH4 emissions from storage tanks that
have a vapor-phase methane concentration of 0.5 volume percent or more
using tank-specific methane composition data (from measurement data or
product knowledge) and the AP-42 emission estimation methods provided in
Section 7.1 of the AP-42: “Compilation of Air Pollutant Emission
Factors, Volume 1: Stationary Point and Area Sources”, including TANKS
Model (Version 4.09D) or similar programs, or estimate CH4 emissions
from storage tanks using Equation Y-22 of this section. 

 	(Eq. Y-22)

Where:

CH4	=	Annual methane emissions from storage tanks (metric tons/year).

0.1	=	Default emission factor for storage tanks (metric ton CH4/MMbbl).

QRef	=	Quantity of crude oil plus the quantity of intermediate products
received from off site that are processed at the facility (MMbbl/year).

(2)  For storage tanks that process unstabilized crude oil, calculate
CH4 emissions from the storage of unstabilized crude oil using either
tank-specific methane composition data (from measurement data or product
knowledge) and direct measurement of the gas generation rate or by using
Equation Y-23 of this section. 

 	(Eq. Y-23)

Where:

CH4	=	Annual methane emissions from storage tanks (metric tons/year).

Qun	=	Quantity of unstabilized crude oil received at the facility
(MMbbl/year).

ΔP	=	Pressure differential from the previous storage pressure to
atmospheric pressure (pounds per square inch, psi).

MFCH4	=	Average mMole fraction of CH4 in vent gas from the unstabilized
crude oil storage tanks from facility measurements (kg-mole CH4/kg-mole
gas); use 0.27 as a default if measurement data are not available.

995,000	=	Correlation Equation factor (scf gas per MMbbl per psi)

16	=	Molecular weight of CH4 (kg/kg-mole).

MVC	=	Molar volume conversion factor (849.5 scf/kg-mole at 68 ºF and
14.7 psia or 836.6 scf/kg-mole at 60 ºF and 14.7 psia).

0.001	=	Conversion factor (metric ton/kg).

(3)  You do not need to calculate CH4 emissions from storage tanks that
meet any of the following descriptions: 

(i)  Units permanently attached to conveyances such as trucks, trailers,
rail cars, barges, or ships; 

(ii)  Pressure vessels designed to operate in excess of 204.9
kilopascals and without emissions to the atmosphere;

(iii)  Bottoms receivers or sumps;

(iv)  Vessels storing wastewater; or

(v)  Reactor vessels associated with a manufacturing process unit.

(n)  For crude oil, intermediate, or product loading operations for
which the equilibrium vapor-phase concentration of methane is 0.5 volume
percent or more, calculate CH4 emissions from loading operations using
product-specific, vapor-phase methane composition data (from measurement
data or process knowledge) and the emission estimation procedures
provided in Section 5.2 of the AP-42: “Compilation of Air Pollutant
Emission Factors, Volume 1: Stationary Point and Area Sources.”  For
loading operations in which the equilibrium vapor-phase concentration of
methane is less than 0.5 volume percent, you may assume zero methane
emissions.

§98.254  Monitoring and QA/QC requirements. 

(a)  Fuel flow meters, gas composition monitors, and heating value
monitors that are associated with sources that use a CEMS to measure CO2
emissions according to subpart C of this part or that are associated
with stationary combustion sources must follow meet the applicable
monitoring and QA/QC requirements in §98.34. 

(b)  All gas flow meters, gas composition monitors, and heating value
monitors that are used to provide data for the GHG emissions
calculations in this subpart for sources other than those subject to the
requirements in paragraph (a) of this sectionstationary combustion
sources shall be calibrated according to the procedures in the
applicable methods specified in paragraphs (c) through (eg) of this
section, or the procedures specified by the manufacturer.  In the case
of gas flow meters, all gas flow meters must meet the calibration
accuracy requirements in , or §§98.3(i).  RYou must recalibrate each
gas flow meter according to one of the following frequencies.  You may
recalibrate either biennially (every two years), or at the minimum
frequency specified by the manufacturer, or at the interval specified by
the industry consensus standard practice used.  RYou must recalibrate
each gas composition monitor and heating value monitor according to one
of the following frequencies.  You may recalibrate either annually, or
at the minimum frequency specified by the manufacturer, or at the
interval specified by the industry consensus standard practice used. 

(c)  For flare or sour gas flow meters, operate, calibrate, and maintain
the flow meter according to one of the following.  You may use using any
of the following methods, a method published by a consensus-based
standards organization (e.g., ASTM, API, etc.) or follow the procedures
specified by the flow meter manufacturer.  Consensus-based standards
include, but are not limited to, the following:  ASTM International, the
American Society of Mechanical Engineers (ASME), and the American Gas
Association (AGA).Flow meters must have a rated accuracy of +/- 5
percent or lower.

(1)  ASME MFC–3M–2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi (incorporated by reference, see §98.7).

(2)  ASME MFC–4M–1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters (incorporated by reference, see §98.7).

(3)  ASME MFC–6M–1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters (incorporated by reference, see §98.7).

(4)  ASME MFC–7M–1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles (incorporated by reference, see
§98.7).

(5)  ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis
Mass Flowmeters (incorporated by reference, see §98.7).

(6)  ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters (incorporated by reference, see §98.7).

(7)  ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area
Meters (incorporated by reference, see §98.7).

(8)  AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter
(2003) (incorporated by reference, see §98.7).

(d)  Except as provided in paragraph (g) of this section, dDetermine
flare gas composition and, if required, average molecular weight of the
gas using any of the following methods.  Alternatively, the results of
chromatographic analysis of the fuel may be used, provided that the gas
chromatograph is operated,  maintained, and calibrated according to the
manufacturer’s instructions; and the methods used for operation,
maintenance, and calibration of the gas chromatograph are documented in
the written Monitoring Plan for the unit under §98.3(g)(5).

(1)  Method 18 at 40 CFR part 60, appendix A-6.

(2)  ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by reference, see §98.7).

(3)  ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography (incorporated by reference, see
§98.7). 

(4)  GPA 2261–00 Analysis for Natural Gas and Similar Gaseous Mixtures
by Gas Chromatography (incorporated by reference, see §98.7).

(5)  UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated
by reference, see §98.7). 

(6)  ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative
Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric
Measurement of Vapor Pressure (incorporated by reference, see §98.7).

(e)  Determine flare gas higher heating value using any of the following
methods.  Alternatively, the results of chromatographic analysis of the
fuel  may be used, provided that the gas chromatograph is operated, 
maintained, and calibrated according to the manufacturer’s
instructions; and the methods used for operation, maintenance, and
calibration of the gas chromatograph are documented in the written
Monitoring Plan for the unit under §98.3(g)(5).

(1)  ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid
Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated
by reference, see §98.7). 

(2)  ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated
by reference, see §98.7).

(3)  ASTM D1826-94 (Reapproved 2003) Standard Test Method for Calorific
(Heating) Value of Gases in Natural Gas Range by Continuous Recording
Calorimeter (incorporated by reference, see §98.7).

(4)  ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating
Heat Value, Compressibility Factor, and Relative Density of Gaseous
Fuels (incorporated by reference, see §98.7).

(5)  ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating
Value of Gases in Natural Gas Range by Stoichiometric Combustion
(incorporated by reference, see §98.7).

(f)  For exhaustgas flow meters used to comply with the requirements in
§98.253(c)(2)(ii) or §98.253(j), install, operate, calibrate, and
maintain each exhaust gas flow meter according to the requirements in 40
CFR 63.1572(c) or according toand the following requirements. 

(1)  Locate the flow monitormeter(s) and other necessary equipment such
as straightening vanes in a position at a site that provides
representative flow rates;.  Avoid locations where there is reduce
swirling flow or abnormal velocity distributions due to upstream and
downstream disturbances.

(2) [Reserved]Use a flow rate meter with an accuracy within +/- 5
percent. 

(3)  Use a continuous monitoring system capable of correcting for the
temperature, pressure, and moisture content to output flow in dry
standard cubic feet (standard conditions as defined in §98.6).

(4) Install, operate, and maintain each continuous monitoring system
according to the manufacturer’s specifications and requirements.

(g)  For exhaust gas CO2/CO/O2 composition monitors used to comply with
the requirements in §98.253(c)(2), install, operate, calibrate, and
maintain exhaust gas composition monitors according to the the
requirements in 40 CFR 60.105a(b)(2) or 40 CFR 63.1572(ac) or according
to the manufacturer’s specifications and requirements.

(h)  Determine the mass of petroleum coke as required by Equation Y-13
of this subpart using mass measurement equipment meeting the
requirements for commercial weighing equipment as described in
Specifications, Tolerances, and Other Technical Requirements For
Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated by
reference, see §98.7).  Calibrate the measurement device according to
the procedures specified by NIST handbook 44 orthe method, the
procedures specified by the manufacturer, or §98.3(i).  Recalibrate
either biennially or at the minimum frequency specified by the
manufacturer.

(i)  Determine the carbon content of petroleum coke as required by
Equation Y-13 of this subpart using any one of the following methods. 
Calibrate the measurement device according to procedures specified by
the method or procedures specified by the measurement device
manufacturer.

(1)  ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate
Analysis of Coal and Coke (incorporated by reference, see §98.7). 

(2)  ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants (incorporated by reference, see
§98.7).

(3)  ASTM D5373-08 Standard Test Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal
(incorporated by reference, see §98.7).

(j)  Determine the quantity of petroleum process streams using company
records.  These quantities include the quantity of asphalt blown,
quantity of crude oil plus the quantity of intermediate products
received from off site, and the quantity of unstabilized crude oil
received at the facility.

(k)  The owner or operator shall document the procedures used to ensure
the accuracy of the estimates of fuel usage, gas composition, and
heating value including but not limited to calibration of weighing
equipment, fuel flow meters, and other measurement devices.  The
estimated accuracy of measurements made with these devices shall also be
recorded, and the technical basis for these estimates shall be provided.

(l)  All CO2 CEMS and flow rate monitors used for direct measurement of
GHG emissions must comply with the QA procedures in §98.34(c).  

§98.255  Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions
calculations is required (e.g., concentrations, flow rates, fuel heating
values, carbon content values).  Therefore, whenever a quality-assured
value of a required parameter is unavailable (e.g., if a CEMS
malfunctions during unit operation or if a required fuel sample is not
taken), a substitute data value for the missing parameter shall be used
in the calculations. 

(a)  For stationary combustion sources, use the missing data procedures
in subpart C of this part.

(b)  For each missing value of the heat content, carbon content, or
molecular weight of the fuel, substitute the arithmetic average of the
quality-assured values of that parameter immediately preceding and
immediately following the missing data incident.  If the “after”
value is not obtained by the end of the reporting year, you may use the
“before” value for the missing data substitution.  If, for a
particular parameter, no quality-assured data are available prior to the
missing data incident, the substitute data value shall be the first
quality-assured value obtained after the missing data period.

(c)  For missing CO2, CO, O2, CH4, or N2O concentrations, gas flow rate,
and percent moisture, the substitute data values shall be the best
available estimate(s) of the parameter(s), based on all available
process data (e.g., processing rates, operating hours, etc.).  The owner
or operator shall document and keep records of the procedures used for
all such estimates.

(d)  For hydrogen plants, use the missing data procedures in subpart P
of this part.

§98.256  Data reporting requirements. 

In addition to the reporting requirements of §98.3(c), you must report
the information specified in paragraphs (a) through (q) of this section.

(a)  For combustion sources, follow the data reporting requirements
under subpart C  of this part (General Stationary Fuel Combustion
Sources).

(b)  For hydrogen plants, follow the data reporting requirements under
subpart P of this part (Hydrogen Production). 

(c)  [Reserved]

(d)  [Reserved]

(e)  For flares, owners and operators shall report:

(1)  The flare ID number (if applicable).

(2)  A description of the type of flare (steam assisted, air-assisted).

(3)  A description of the flare service (general facility flare, unit
flare, emergency only or back-up flare).

(4)  The calculated CO2, CH4, and N2O annual emissions for each flare,
expressed in metric tons of each pollutant emitted.

(5)  A description of the method used to calculate the CO2 emissions for
each flare (e.g., reference section and equation number). 

(6)  If you use Equation Y-1a of this subpart, an indication of whether
daily or weekly measurement periods are used, the annual volume of flare
gas combusted (in scf/year) and the annual average molecular weight (in
kg/kg-mole), the molar volume conversion factor (in scf/kg-mole), and
annual average carbon content of the flare gas (in kg carbon per kg
flare gas).

(7)  If you use Equation Y-1b of this subpart, an indication of whether
daily or weekly measurement periods are used, the annual volume of flare
gas combusted (in scf/year), the molar volume conversion factor (in
scf/kg-mole), the annual average CO2 concentration (volume or mole
percent), the number of carbon containing compounds other than CO2 in
the flare gas stream, and for each of the carbon containing compounds
other than CO2 in the flare gas stream:

(i)  The annual average concentration of the compound (volume or mole
percent).

(ii)  The carbon mole number of the compound (moles carbon per mole
compound).

(78)  If you use Equation Y-2 of this subpart, an indication of whether
daily or weekly measurement periods are used, the annual volume of flare
gas combusted (in million (MM) scf/year) and the annual average higher
heating value of the flare gas (in MMBtu per MMscf).

(89)  If you use Equation Y-3 of this subpart, the annual volume of
flare gas combusted (in MMscf/year) during normal operations, the annual
average higher heating value of the flare gas (in MMBtu/MMscf), the
number of SSM events exceeding 500,000 scf/day, and the volume of gas
flared (in scf/event), and the average molecular weight (in kg/kg-mole),
the molar volume conversion factor (in scf/kg-mole), and carbon content
of the flare gas (in kg carbon per kg flare) for each SSM event over
500,000 scf/day.

(910)  The fraction of carbon in the flare gas contributed by methane
used in Equation Y-4 of this subpart and the basis for its value.

(f)  For catalytic cracking units, traditional fluid coking units, and
catalytic reforming units, owners and operators shall report:

(1)  The unit ID number (if applicable).

(2)  A description of the type of unit (fluid catalytic cracking unit,
thermal catalytic cracking unit, traditional fluid coking unit, or
catalytic reforming unit).

(3)  Maximum rated throughput of the unit, in bbl/stream day.

(4)  The calculated CO2, CH4, and N2O annual emissions for each unit,
expressed in metric tons of each pollutant emitted.

(5)  A description of the method used to calculate the CO2 emissions for
each unit (e.g., reference section and equation number).

(6)  If you use a CEMS, the relevant information required under
§98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the CO2 annual
emissions as measured by the CEMS (unadjusted to remove CO2 combustion
emissions associated with a CO boileradditional units, if present) and
the process CO2 emissions as calculated according to §98.253(c)(1)(ii).
 Report the CO2 annual emissions associated with fuel combustion under
subpart C of this part (General Stationary Fuel Combustion Sources).
Report the CO2 annual emissions associated with sources other than those
from the coke burn-off in the applicable subpart (e.g., subpart C of
this part in the case of a CO boiler).

(7)  If you use Equation Y-6 of this subpart, the annual average exhaust
gas flow rate, %CO2, and %CO, and the molar volume conversion factor (in
scf/kg-mole).

(8)  If you use Equation Y-7a of this subpart, the annual average flow
rate of inlet air and oxygen-enriched air, %O2, %Ooxy, %CO2, and %CO. 

(9)  If you use Equation Y-7b of this subpart, the annual average flow
rate of inlet air and oxygen-enriched air, %N2,oxy, and %N2,exhaust.

(910)  If you use Equation Y-8 of this subpart, the coke burn-off
factor, annual throughput of unit, and the average carbon content of
coke and the basis for the value.

(1011)  Indicate whether you use a measured value, a unit-specific
emission factor, or a default emission factor for CH4 emissions.  If you
use a unit-specific emission factor for CH4, report the unit-specific
emission factor for CH4units of measure for the unit-specific factor,
the units of measure for the unit-specific factor, the activity data for
calculating emissions (e.g., if the emission factor is based on coke
burn-off rate, the annual quantity of coke burned), and the basis for
the factor.

(1112)  Indicate whether you use a measured value, a unit-specific
emission factor, or a default emission factor for N2O emissions.  If you
use a unit-specific emission factor for N2O, report the unit-specific
emission factor for N2O, the units of measure for the unit-specific
factor, the activity data for calculating emissions (e.g., if the
emission factor is based on coke burn-off rate, the annual quantity of
coke burned), and the basis for the factor.  

(1213)  If you use Equation Y-11 of this subpart, the number of
regeneration cycles or measurement periods during the reporting year,
the average coke burn-off quantity per cycle or measurement period, and
the average carbon content of the coke.  

(g)  For fluid coking unit of the flexicoking type, the owner or
operator shall report:

(1)  The unit ID number (if applicable).

(2)  A description of the type of unit.

(3)  Maximum rated throughput of the unit, in bbl/stream day.

(4)  Indicate whether the GHG emissions from the low heat value gas are
accounted for in subpart C of this part or §98.253(c). 

(5)  If the GHG emissions for the low heat value gas are calculated at
the flexicoking unit, also report the calculated annual CO2, CH4, and
N2O emissions for each unit, expressed in metric tons of each pollutant
emitted, and the applicable equation input parameters specified in
paragraphs (f)(7) through (f)(1311) of this section.

(h)  For sulfur recovery plants and for emissions from sour gas sent
off-site for sulfur recovery, the owner and operator shall report:

(1)  The plant ID number (if applicable).

(2)  Maximum rated throughput of each independent sulfur recovery plant,
in metric tons sulfur produced/stream day, a description of the type of
sulfur recovery plant, and an indication of the method used to calculate
CO2 annual emissions for the sulfur recovery plant (e.g., CO2 CEMS,
Equation Y-12, or process vent method in §98.253(j)).

(3)  The calculated CO2 annual emissions for each sulfur recovery plant,
expressed in metric tons.  The calculated annual CO2 emissions from sour
gas sent off-site for sulfur recovery, expressed in metric tons.

(4)  If you use Equation Y-12 of this subpart, the annual volumetric
flow to the sulfur recovery plant (in scf/year), the molar volume
conversion factor (in scf/kg-mole),  and the annual average mole
fraction of carbon in the sour gas (in kg-mole C/kg-mole gas). 

(5)  If you recycle tail gas to the front of the sulfur recovery plant,
indicate whether the recycled flow rate and carbon content are included
in the measured data under §98.253(f)(2) and (3).  Indicate whether a
correction for CO2 emissions in the tail gas was used in Equation Y-12. 
If so, then report the value of the correction, the annual volume of
recycled tail gas (in scf/year) and the annual average mole fraction of
carbon in the tail gas (in kg-mole C/kg-mole gas). Indicate whether you
used the default (95%) or a unit specific correction, and if used,
report the approach used. 

(6)  If you use a CEMS, the relevant information required under
§98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the CO2 annual
emissions as measured by the CEMS and the annual process CO2 emissions
calculated according to §98.253(f)(1).  Report the CO2 annual emissions
associated with fuel combustion subpart C of this part (General
Stationary Fuel Combustion Sources).

(7)  If you use the process vent method in §98.253(j) for a non-Claus
sulfur recovery plant, the relevant information required under paragraph
(l)(5) of this section.

(i)  For coke calcining units, the owner and operator shall report:

(1)  The unit ID number (if applicable).

(2)  Maximum rated throughput of the unit, in metric tons coke
calcined/stream day.

(3)  The calculated CO2, CH4, and N2O annual emissions for each unit,
expressed in metric tons of each pollutant emitted.

(4)  A description of the method used to calculate the CO2 emissions for
each unit (e.g., reference section and equation number).

(5)  If you use Equation Y-13 of this subpart, annual mass and carbon
content of green coke fed to the unit, the annual mass and carbon
content of marketable coke produced, and the annual mass of coke dust
removed from the process through collected in dust collection systems,
and an indication of whether coke dust is recycled to the unit (e.g.,
all dust is recycled, a portion of the dust is recycled, or none of the
dust is recycled).

(6)  If you use a CEMS, the relevant information required under
§98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the CO2 annual
emissions  as measured by the CEMS and the annual process CO2 emissions
calculated according to §98.253(g)(1).  Report the CO2 annual emissions
associated with fuel combustion under subpart C of this part (General
Stationary Fuel Combustion Sources).

(7)  Indicate whether you use a measured value, a unit-specific emission
factor or a default for CH4 emissions.  If you use a unit-specific
emission factor for CH4, the unit-specific emission factor for CH4, the
units of measure for the unit-specific factor, the activity data for
calculating emissions (e.g., if the emission factor is based on coke
burn-off rate, the annual quantity of coke burned), and the basis for
the factor.  

(8)  Indicate whether you use a measured value, a unit-specific emission
factor, or a default emission factor for N2O emissions.  If you use a
unit-specific emission factor for N2O, report the unit-specific emission
factor for N2O, the units of measure for the unit-specific factor, the
activity data for calculating emissions (e.g., if the emission factor is
based on coke burn-off rate, the annual quantity of coke burned), and
the basis for the factor.  If you use a site-specific emission factor in
Equation Y-10 of this subpart, the site-specific emission factor and the
basis of the factor.

(j)  For asphalt blowing operations, the owner or operator shall report:

(1)  The unit ID number (if applicable).

(2)  The quantity of asphalt blown (in Million bbl) at the facility unit
in the reporting year.

(3)  The type of control device used to reduce methane (and other
organic) emissions from the unit.

(4)  The calculated annual CO2 and CH4 emissions for each unit,
expressed in metric tons of each pollutant emitted.

(5)  If you use Equation Y-14 of this subpart, the CO2 emission factor
used and the basis for the value. 

(6)  If you use Equation Y-15 of this subpart, the CH4 emission factor
used and the basis for the value.

(7)  If you use Equation Y-16a of this subpart, the carbon emission
factor used and the basis for the value. 

(8)  If you use Equation Y-16b of this subpart, the CO2 emission factor
used and the basis for its value and the carbon emission factor used and
the basis for its value.

(89)  If you use Equation Y-17 of this subpart, the CH4 emission factor
used and the basis for the value.

(k)  For delayed coking units, the owner or operator shall report:

(1)  The cumulative annual CH4 emissions (in metric tons of CH4each
pollutant emitted) for all delayed coking units at the facility.

(2)  A description of the method used to calculate the CH4 emissions for
each unit (e.g., reference section and equation number).

(3)  The total number of delayed coking units at the facility, the total
number of delayed coking drums at the facility, and for each coke drum
or vessel: the dimensions, the typical gauge pressure of the coking drum
when first vented to the atmosphere, typical void fraction, the typical
drum outage (i.e. the unfilled distance from the top of the drum, in
feet), the molar volume conversion factor (in scf/kg-mole), and annual
number of coke-cutting cycles.

(4)  For each set of coking drums that are the same dimensions:  the
number of coking drums in the set, the height and diameter of the coke
drums (in feet), the cumulative number of vessel openings for all
delayed coking drums in the set, the typical venting pressure (in psig),
void fraction (in cf gas/cf of vessel), and the mole fraction of methane
in coking gas (in kg-mole CF4/kg-mole gas, wet basis).

(5)  The basis for the volumetric void fraction of the coke vessel prior
to steaming and the basis for the mole fraction of methane in the coking
gas. 

(l)  For each process vents subject to §98.253(j), the owner or
operator shall report:

(1)  The vent ID number (if applicable).

(2)  The unit or operation associated with the emissions.

(3)  The type of control device used to reduce methane (and other
organic) emissions from the unit, if applicable.

(4)  The calculated annual CO2, CH4, and N2O emissions for each vent,
expressed in metric tons of each pollutant emitted.

(5)  The annual volumetric flow discharged to the atmosphere (in scf),
and an indication of the measurement or estimation method, annual
average mole fraction of each GHG above the concentration threshold, or
otherwise required to be reported and an indication of the measurement
or estimation method, the molar volume conversion factor (in
scf/kg-mole), and for intermittent vents, the number of venting events
and the cumulative venting time.

(m)  For uncontrolled blowdown systems, the owner or operator shall
report:

(1)  An indication of whether the uncontrolled blowdown emission are
reported under §98.253(k) or §98.253(j) or a statement that the
facility does not have any uncontrolled blowdown systems.

(21)  The cumulative annual CH4 emissions (in metric tons of CH4 each
pollutant emitted) for uncontrolled blowdown systems. 

(32)  For uncontrolled blowdown systems reporting under §98.253(k),
Tthe total quantity (in Million bbl) of crude oil plus the quantity of
intermediate products received from off-site that are processed at the
facility in the reporting year, .

(3)  Tthe methane emission factor used for uncontrolled blowdown
systems, and the basis for the value, and the molar volume conversion
factor (in scf/kg-mole).

(4)  For uncontrolled blowdown systems reporting under §98.253(j), the
relevant information required under paragraph (l)(5) of this section.

(n)  For equipment leaks, the owner or operator shall report:

(1)  The cumulative CH4 emissions (in metric tons of each pollutant
emitted) for all equipment leak sources.

(2)  The method used to calculate the reported equipment leak emissions.

(3)  The number of each type of emission source listed in Equation Y-21
of this subpart at the facility.

(o)  For storage tanks, the owner or operator shall report:

(1)  The cumulative annual CH4 emissions (in metric tons of CH4each
pollutant emitted) for all storage tanks, except for those used to
process unstabilized crude oil.

(2)  The method used to calculate the reported storage tank emissions
fFor storage tanks other than those processing unstabilized crude oil:

(i) (AP-42, TANKS 4.09D, Equation Y-22 of this subpart, other). The
method used to calculate the reported storage tank emissions for storage
tanks other than those processing unstabilized crude (Section 7.1 of the
AP-42: “Compilation of Air Pollutant Emission Factors, Volume 1:
Stationary Point and Area Sources”, including TANKS Model (Version
4.09D) or similar programs, or Equation Y-22 of this section, other).

(3ii)  The total quantity (in MMbbl) of crude oil plus the quantity of
intermediate products received from off-site that are processed at the
facility in the reporting year.

(43)  The cumulative CH4 emissions (in metric tons of CH4each pollutant
emitted) for storage tanks used to process unstabilized crude oil or a
statement that the facility did not receive any unstabilized crude oil
during the reporting year. 

(54)  For storage tanks that process unstabilized crude oil:

(i)  The method used to calculate the reported unstabilized crude oil
storage tank emissions for storage tanks processing unstabilized crude
oil.

(6ii)  The quantity of unstabilized crude oil received during the
calendar year (in MMbbl).

(iii),  Tthe average pressure differential (in psi).

(iv),  Tthe molar volume conversion factor (in scf/kg-mole).

(v), and  Tthe average mole fraction of CH4 in vent gas from the
unstabilized crude oil storage tanks, and the basis for the mole
fraction.

(7vi)  For storage tanks that process unstabilized crude oil, The If you
did not use Equation Y-23, the tank-specific methane composition data
and the gas generation rate data used to estimate the cumulative CH4
emissions for storage tanks used to process unstabilized crude oil, if
you did not use Equation Y-23.

(p)  For loading operations, the owner or operator shall report:

(1)  The cumulative annual CH4 emissions (in metric tons of each
pollutant emitted) for loading operations. 

(2)  The quantity and types of materials loaded by vessel type (barge,
tanker, marine vessel, etc.) that have an equilibrium vapor-phase
concentration of methane of 0.5 volume percent or greater, and the type
of vessels in which the material is loaded.

(3)  The type of control system used to reduce emissions from the
loading of material with an equilibrium vapor-phase concentration of
methane of 0.5 volume percent or greater, if any (submerged loading,
vapor balancing, etc.).

(q)  Name of each method listed in §98.254 or a description of
manufacturer's recommended method used to determine a measured
parameter.

§98.257  Records that must be retained. 

In addition to the records required by §98.3(g), you must retain the
records of all parameters monitored under §98.255.  If you comply with
the combustion methodology in §98.252(a), then you must retain under
this subpart the records required for the Tier 3 and/or Tier 4
Calculation Methodologies in §98.37 and you must keep records of the
annual average flow calculations.

§98.258  Definitions. 

All terms used in this subpart have the same meaning given in the Clean
Air Act and subpart A of this part.

Subpart AA—Pulp and Paper Manufacturing

§98.270  Definition of Source Category.

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

(b)  The emission units for which GHG emissions must be reported are
listed in paragraphs (b)(1) through (b)(5) of this section:

(1)  Chemical recovery furnaces at kraft and soda mills (including
recovery furnaces that burn spent pulping liquor produced by both the
kraft and semichemical process).

(2)  Chemical recovery combustion units at sulfite facilities.

(3)  Chemical recovery combustion units at stand-alone semichemical
facilities.

(4)  Pulp mill lime kilns at kraft and soda facilities.

(5)  Systems for adding makeup chemicals (CaCO3, Na2CO3) in the chemical
recovery areas of chemical pulp mills.

§98.271  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains a pulp and paper manufacturing process and the facility meets
the requirements of either §98.2(a)(1) or (a)(2).

§98.272  GHGs to report.

You must report the emissions listed in paragraphs (a) through (f) of
this section:

(a)  CO2, biogenic CO2, CH4, and N2O emissions from each kraft or soda
chemical recovery furnace.

(b)  CO2, biogenic CO2, CH4, and N2O emissions from each sulfite
chemical recovery combustion unit.

(c)  CO2, biogenic CO2, CH4, and N2O emissions from each stand-alone
semichemical chemical recovery combustion unit.

(d)  CO2, biogenic CO2, CH4, and N2O emissions from each kraft or soda
pulp mill lime kiln.

(e)  CO2 emissions from addition of makeup chemicals (CaCO3, Na2CO3) in
the chemical recovery areas of chemical pulp mills.

(f)  CO2, CH4, and N2O combustion emissions from each stationary
combustion unit.  You must calculate and report these emissions under
subpart C of this part  (General Stationary Fuel Combustion Sources) by
following the requirements of subpart C.

§98.273  Calculating GHG emissions. 

(a)  For each chemical recovery furnace located at a kraft or soda
facility, you must determine CO2, biogenic CO2, CH4, and N2O emissions
using the procedures in paragraphs (a)(1) through (a)(3) of this
section.  CH4 and N2O emissions must be calculated as the sum of
emissions from combustion of fossil fuels and combustion of biomass in
spent liquor solids.

(1)  Calculate fossil fuel-based CO2 emissions from direct measurement
of fossil fuels consumed and default emissions factors according to the
Tier 1 methodology for stationary combustion sources in §98.33(a)(1). 
A higher tier from §98.33(a) may be used to calculate fossil fuel-based
CO2 emissions if the respective monitoring and QA/QC requirements
described in §98.34 are met. 

(2)  Calculate fossil fuel-based CH4 and N2O emissions from direct
measurement of fossil fuels consumed, default or site-specific HHV, and
default emissions factors and convert to metric tons of CO2 equivalent
according to the methodology for stationary combustion sources in
§98.33(c).

(3)  Calculate biogenic CO2 emissions and emissions of CH4 and N2O from
biomass using measured quantities of spent liquor solids fired,
site-specific HHV, and default or site-specific emissions factors,
according to Equation AA-1 of this section: 

 

		(Eq.AA-1)

Where:  

CO2, CH4, or N2O,

 from Biomass	=	Biogenic CO2 emissions or emissions of CH4 or N2O from
spent liquor solids combustion (metric tons per year).

Solids			=	Mass of spent liquor solids combusted (short tons per year)
determined according to §98.274(b).

HHV			=	Annual high heat value of the spent liquor solids (mmBtu per
kilogram) determined according to 98.274(b).

EF 			=	Default emission factor for CO2, CH4, or N2O, from Table AA-1 of
this subpart (kg CO2, CH4, or N2O per mmBtu).

0.90718			=	Conversion factor from short tons to metric tons.

(b)  For each chemical recovery combustion unit located at a sulfite or
stand-alone semichemical facility, you must determine CO2, CH4, and N2O
emissions using the procedures in paragraphs (b)(1) through (b)(4) of
this section:

(1)  Calculate fossil CO2 emissions from fossil fuels from direct
measurement of fossil fuels consumed and default emissions factors
according to the Tier 1 Calculation Methodology for stationary
combustion sources in §98.33(a)(1).  A higher tier from §98.33(a) may
be used to calculate fossil fuel-based CO2 emissions if the respective
monitoring and QA/QC requirements described in §98.34 are met. 

(2)  Calculate CH4 and N2O emissions from fossil fuels from direct
measurement of fossil fuels consumed, default or site-specific HHV, and
default emissions factors and convert to metric tons of CO2 equivalent
according to the methodology for stationary combustion sources in
§98.33(c).

(3)  Calculate biogenic CO2 emissions using measured quantities of spent
liquor solids fired and the carbon content of the spent liquor solids,
according to Equation AA-2 of this section:  

 	(Eq. AA-2)

Where:  

Biogenic CO2	=	Annual CO2 mass emissions for spent liquor solids
combustion (metric tons per year).

Solids			=	Mass of the spent liquor solids combusted (short tons per
year) determined according to §98.274(b).

CC		=	Annual carbon content of the spent liquor solids, determined
according to §98.274(b) (percent by weight, expressed as a decimal
fraction, e.g., 95% = 0.95).

44/12		=	Ratio of molecular weights, CO2 to carbon.

0.90718		=	Conversion from short tons to metric tons

(4)  Calculate CH4 and N2O emissions from biomass using Equation AA-1 of
this section and the default CH4 and N2O emissions factors for kraft
facilities in Table AA-1 of this subpart and convert the CH4 or N2O
emissions to metric tons of CO2 equivalent by multiplying each annual
CH4 and N2O emissions total by the appropriate global warming potential
(GWP) factor from Table A-1 of subpart A of this part.

(c)  For each pulp mill lime kiln located at a kraft or soda facility,
you must determine CO2, CH4, and N2O emissions using the procedures in
paragraphs (c)(1) through (c)(3) of this section:

(1)  Calculate CO2 emissions from fossil fuel from direct measurement of
fossil fuels consumed and default HHV and default emissions factors,
according to the Tier 1 Calculation Methodology for stationary
combustion sources in §98.33(a)(1); use the default HHV listed in Table
C-1 of subpart C and the default CO2 emissions factors listed in Table
AA-2 of this subpart).  A higher tier from §98.33(a) may be used to
calculate fossil fuel-based CO2 emissions if the respective monitoring
and QA/QC requirements described in §98.34 are met.

(2)  Calculate CH4 and N2O emissions from fossil fuel from direct
measurement of fossil fuels consumed, default or site-specific HHV, and
default emissions factors and convert to metric tons of CO2 equivalent
according to the methodology for stationary combustion sources in
§98.33(c); use the default HHV listed in Table C-1 of subpart C and the
default CH4 and N2O emissions factors listed in Table AA-2 of this
subpart.

(3)  Biogenic CO2 emissions from conversion of CaCO3 to CaO are included
in the biogenic CO2 estimates calculated for the chemical recovery
furnace in paragraph (a)(3) of this section.

(d)  For makeup chemical use, you must calculate CO2 emissions by using
direct or indirect measurement of the quantity of chemicals added and
ratios of the molecular weights of CO2 and the makeup chemicals,
according to Equation AA-3 of this section:

 

(Eq. AA-3)

Where:

CO2	=	CO2 mass emissions from makeup chemicals (kilograms/yr).

M (CaCO3)	=	Make-up quantity of CaCO3 used for the reporting year
(metric tons per year).

M (NaCO3)	=	Make-up quantity of Na2CO3 used for the reporting year
(metric tons per year).

44	=	Molecular weight of CO2.

100	=	Molecular weight of CaCO3. 

105.99	=	Molecular weight of Na2CO3. 	

§98.274  Monitoring and QA/QC requirements. 

(a)  Each facility subject to this subpart must quality assure the GHG
emissions data according to the applicable requirements in §98.34.  All
QA/QC data must be available for inspection upon request. 

(b)  Fuel properties needed to perform the calculations in Equations
AA-1 and AA-2 of this subpart must be determined according to paragraphs
(b)(1) through (b)(3) of this section.

(1)  High heat values of black liquor must be determined no less than
annually using T684 om–06 Gross Heating Value of Black Liquor, TAPPI
(incorporated by reference, see §98.7).  If measurements are performed
more frequently than annually, then the high heat value used in Equation
AA-1 of this subpart must be based on the average of the representative
measurements made during the year.

(2)  The annual mass of spent liquor solids must be determined using
either of the methods specified in paragraph (b)(2)(i) or (b)(2)(ii).

(i)  Measure the mass of spent liquor solids annually (or more
frequently) using T-650 om–05 Solids Content of Black Liquor, TAPPI
(incorporated by reference in §98.7).  If measurements are performed
more frequently than annually, then the mass of spent liquor solids used
in Equation AA-1 of this subpart must be based on the average of the
representative measurements made during the year. 

(ii)  Determine the annual mass of spent liquor solids based on records
of measurements made with an online measurement system that determines
the mass of spent liquor solids fired in a chemical recovery furnace or
chemical recovery combustion unit.

(3)  Carbon analyses for spent pulping liquor must be determined no less
than annually using ASTM D5373-08 Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of
Coal (incorporated by reference, see §98.7). If measurements using ASTM
D5373-08 are performed more frequently than annually, then the spent
pulping liquor carbon content used in Equation AA-2 of this subpart must
be based on the average of the representative measurements made during
the year. 

(c)  Each facility must keep records that include a detailed explanation
of how company records of measurements are used to estimate GHG
emissions.  The owner or operator must also document the procedures used
to ensure the accuracy of the measurements of fuel, spent liquor solids,
and makeup chemical usage, including, but not limited to calibration of
weighing equipment, fuel flow meters, and other measurement devices. 
The estimated accuracy of measurements made with these devices must be
recorded and the technical basis for these estimates must be provided. 
The procedures used to convert spent pulping liquor flow rates to units
of mass (i.e., spent liquor solids firing rates) also must be
documented. 

(d)  Records must be made available upon request for verification of the
calculations and measurements.

§98.275  Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions
calculations is required.  Therefore, whenever a quality-assured value
of a required parameter is unavailable (e.g., if a meter malfunctions
during unit operation or if a required sample is not taken), a
substitute data value for the missing parameter shall be used in the
calculations, according to the requirements of paragraphs (a) through
(c) of this section:

(a)  There are no missing data procedures for measurements of heat
content and carbon content of spent pulping liquor.  A re-test must be
performed if the data from any annual measurements are determined to be
invalid. 

(b)  For missing measurements of the mass of spent liquor solids or
spent pulping liquor flow rates, use the lesser value of either the
maximum mass or fuel flow rate for the combustion unit, or the maximum
mass or flow rate that the fuel meter can measure.

(c)  For the use of makeup chemicals (carbonates), the substitute data
value shall be the best available estimate of makeup chemical
consumption, based on available data (e.g., past accounting records,
production rates).  The owner or operator shall document and keep
records of the procedures used for all such estimates.

§98.276  Data reporting requirements. 

In addition to the information required by §98.3(c) and the applicable
information required by §98.36, each annual report must contain the
information in paragraphs (a) through (k) of this section as applicable:

(a)  Annual emissions of CO2, biogenic CO2, CH4, biogenic CH4 N2O, and
biogenic N2O (metric tons per year).

(b)  Annual quantities fossil fuels by type used in chemical recovery
furnaces and chemical recovery combustion units in short tons for solid
fuels, gallons for liquid fuels and scf for gaseous fuels.

(c)  Annual mass of the spent liquor solids combusted (short tons per
year), and basis for determining the annual mass of the spent liquor
solids combusted (whether based on T650 om-05 Solids Content of Black
Liquor, TAPPI (incorporated by reference, see §98.7) or an online
measurement system).

(d)  The high heat value (HHV) of the spent liquor solids used in
Equation AA-1 of this subpart (mmBtu per kilogram).

(e)  The default emission factor for CO2, CH4, or N2O, used in Equation
AA-1 of this subpart (kg CO2, CH4, or N2O per mmBtu).

(f)  The carbon content (CC) of the spent liquor solids, used in
Equation AA-2 of this subpart (percent by weight, expressed as a decimal
fraction, e.g., 95% = 0.95).

(g)  Annual quantities of fossil fuels by type used in pulp mill lime
kilns in short tons for solid fuels, gallons for liquid fuels and scf
for gaseous fuels.

(h)  Make-up quantity of CaCO3 used for the reporting year (metric tons
per year) used in Equation AA-3 of this subpart. 

(i) Make-up quantity of Na2CO3 used for the reporting year (metric tons
per year) used in Equation AA-3 of this subpart.

(j)  Annual steam purchases(pounds of steam per year).

(k)  Annual production of pulp and/or paper products produced (metric
tons).

§98.277  Records that must be retained. 

In addition to the information required by §98.3(g), you must retain
the records in paragraphs (a) through (f) of this section. 

(a)  GHG emission estimates (including separate estimates of biogenic
CO2) for each emissions source listed under §98.270(b).

(b)  Annual analyses of spent pulping liquor HHV for each chemical
recovery furnace at kraft and soda facilities.

(c)  Annual analyses of spent pulping liquor carbon content for each
chemical recovery combustion unit at a sulfite or semichemical pulp
facility.

(d)  Annual quantity of spent liquor solids combusted in each chemical
recovery furnace and chemical recovery combustion unit, and the basis
for detemining the annual quantity of the spent liquor solids combusted
(whether based on T650 om–05 Solids Content of Black Liquor, TAPPI
(incorporated by reference, see §98.7) or an online measurement
system).  If an online measurement system is used, you must retain
records of the calaulations used to determine the annual quantity of
spent liquor solids combusted from the continuous measurements.

(e)  Annual steam purchases.

(f)  Annual quantities of makeup chemicals used.

§98.278  Definitions.

All terms used in this subpart have the same meaning given in the Clean
Air Act and subpart A of this part. 

Table AA-1 of Subpart AA—Kraft Pulping Liquor Emissions Factors for
Biomass-Based CO2, CH4, and N2O.

Wood Furnish	Biomass-Based Emissions Factors 

(kg/mmBtu HHV)

	CO2a	CH4	N2O

North American Softwood	94.4	0.030	0.005

North American Hardwood	93.7

Bagasse	95.5

Bamboo	93.7

Straw	95.1

a Includes emissions from both the recovery furnace and pulp mill lime
kiln.

Table AA-2 of Subpart AA—Kraft Lime Kiln and Calciner Emissions
Factors for Fossil Fuel-Based CO2, CH4, and N2O

Fuel	Fossil Fuel-Based Emissions Factors (kg/mmBtu HHV)

	Kraft Lime Kilns	Kraft Calciners

	CO2	CH4	N2O	CO2 	CH4	N2O

Residual Oil	76.7	0.0027	0	76.7	0.0027	0.0003

Distillate Oil	73.5

	73.5

0.0004

Natural Gas	56.0

	56.0

0.0001

Biogas	0

	0.0001

Petroleum coke

	NAa	NAa

a. Emission factors for kraft calciners are not available.

Subpart OO—Suppliers of Industrial Greenhouse Gases

§98.410  Definition of the source category.

(a)  The industrial gas supplier source category consists of any
facility that produces a fluorinated GHG or nitrous oxide, any bulk
importer of fluorinated GHGs or nitrous oxide, and any bulk exporter of
fluorinated GHGs or nitrous oxide.  

(b)  To produce a fluorinated GHG means to manufacture a fluorinated GHG
from any raw material or feedstock chemical.  Producing a fluorinated
GHG includes the manufacture of a fluorinated GHG as an isolated
intermediate for use in a process that will result in its transformation
either at or outside of the production facility.  Producing a
fluorinated GHG also includes the creation of a fluorinated GHG (with
the exception of HFC-23) that is captured and shipped off site for any
reason, including destruction.  Producing a fluorinated GHG does not
include the reuse or recycling of a fluorinated GHG, the creation of
HFC-23 during the production of HCFC-22, the creation of intermediates
that are created and transformed in a single process with no storage of
the intermediates, or the creation of by-productsfluorinated GHGs that
are released or destroyed at the production facility.   before the
production measurement at §98.414(a).  

(c)  To produce nitrous oxide means to produce nitrous oxide by
thermally decomposing ammonium nitrate (NH4NO3).  Producing nitrous
oxide does not include the reuse or recycling of nitrous oxide or the
creation of by-products that are released or destroyed at the production
facility.    

§98.411  Reporting threshold.

Any supplier of industrial greenhouse gases who meets the requirements
of §98.2(a)(4) must report GHG emissions.

§98.412  GHGs to report.

You must report the GHG emissions that would result from the release of
the nitrous oxide and each fluorinated GHG that you produce, import,
export, transform, or destroy during the calendar year. 

§98.413  Calculating GHG emissions.

(a)  Calculate the total mass of each fluorinated GHG or nitrous oxide
produced annually, except for amounts that are captured solely to be
shipped off site for destruction, by using Equation OO-1 of this
section: 

 	(Eq. OO-1)

P	=	Mass of fluorinated GHG or nitrous oxide produced annually. 

Pp	=	Mass of fluorinated GHG or nitrous oxide produced over the period
“p”.

(b)  Calculate the total mass of each fluorinated GHG or nitrous oxide
produced over the period “p” by using Equation OO-2 of this section:

 	(Eq. OO-2)

Where:

Pp	=	Mass of fluorinated GHG or nitrous oxide produced over the period
“p” (metric tons).

Op	=	Mass of fluorinated GHG or nitrous oxide that is measured coming
out of the production process over the period p(metric tons).

Up	=	Mass of used fluorinated GHG or nitrous oxide that is added to the
production process upstream of the output measurement over the period
“p” (metric tons). 

(c)  Calculate the total mass of each fluorinated GHG or nitrous oxide
transformed by using Equation OO-3 of this section:

 	(Eq. OO-3)

Where:

T	=	Mass of fluorinated GHG or nitrous oxide transformed annually
(metric tons).

FT	=	Mass of fluorinated GHG fed into the transformation process
annually (metric tons).

ET 	=	The fraction of the fluorinated GHG or nitrous oxide fed into the
transformation process that is transformed in the process (metric tons).

(d)  Calculate the total mass of each fluorinated GHG destroyed by using
Equation OO-4 of this section:

 	(Eq. OO-4)

Where:

D	=	Mass of fluorinated GHG destroyed annually (metric tons).

FD	=	Mass of fluorinated GHG fed into the destruction device annually
(metric tons).

DE 	=	Destruction efficiency of the destruction device (fraction).

§98.414  Monitoring and QA/QC requirements. 

(a)  The mass of fluorinated GHGs or nitrous oxide coming out of the
production process shall be measured using flowmeters, weigh scales, or
a combination of volumetric and density measurements with an accuracy
and precision of one percent of full scale or better.  If the measured
mass includes more than one fluorinated GHG, the concentrations of each
of the fluorinated GHGs, other than low-concentration constituents,
shall be measured as set forth in paragraph (n) of this section.  For
each fluorinated GHG, the mean of the concentrations of that fluorinated
GHG (mass fraction) measured under paragraph (n) of this section shall
be multiplied by the mass measurement to obtain the mass of that
fluorinated GHG coming out of the production process.

(b)  The mass of any used fluorinated GHGs or used nitrous oxide added
back into the production process upstream of the output measurement in
paragraph (a) of this section shall be measured using flowmeters, weigh
scales, or a combination of volumetric and density measurements with an
accuracy and precision of one percent of full scale or better. If the
mass in paragraph (a) of this section is measured by weighing containers
that include returned heels as well as newly produced fluorinated GHGs,
the returned heels shall be considered used fluorinated GHGs for
purposes of this paragraph (b) of this section and §98.413(b). 

(c)  The mass of fluorinated GHGs or nitrous oxide fed into the
transformation process shall be measured using flowmeters, weigh scales,
or a combination of volumetric and density measurements with an accuracy
and precision of one percent of full scale or better. 

(d)  The fraction of the fluorinated GHGs or nitrous oxide fed into the
transformation process that is actually transformed shall be estimated
considering yield calculations or quantities of unreacted fluorinated
GHGs or nitrous oxide permanently removed from the process and
recovered, destroyed, or emitted.   

(e)  The mass of fluorinated GHG or nitrous oxide sent to another
facility for transformation shall be measured using flowmeters, weigh
scales, or a combination of volumetric and density measurements with an
accuracy and precision of one percent of full scale or better.  

(f)  The mass of fluorinated GHG sent to another facility for
destruction shall be measured using flowmeters, weigh scales, or a
combination of volumetric and density measurements with an accuracy and
precision of one percent of full scale or better.  If the measured mass
includes more than trace concentrations of materials other than the
fluorinated GHG, the concentration of the fluorinated GHG shall be
estimated considering current or previous representative concentration
measurements and other relevant process information. This concentration
(mass fraction) shall be multiplied by the mass measurement to obtain
the mass of the fluorinated GHG sent to another facility for
destruction. 

(g)  You must estimate the share of the mass of fluorinated GHGs in
paragraph (f) of this section that is comprised of fluorinated GHGs that
are not included in the mass produced in §98.413(a) because they are
removed from the production process as by-products or other wastes.

(h)  The You must measure the mass of each fluorinated GHGs GHG that is
fed into the destruction device shall be measured usingand that was
previously produced as defined at §98.410(b).  Such fluorinated GHGs
include but are not limited to quantities that are shipped to the
facility by another facility for destruction and quantities that are
returned to the facility for reclamation but are found to be
irretrievably contaminated and are therefore destroyed.  You must use
flowmeters, weigh scales, or a combination of volumetric and density
measurements with an accuracy and precision of one percent of full scale
or better.  If the measured mass includes more than trace concentrations
of materials other than the fluorinated GHG being destroyed, you must
estimate the concentrations of fluorinated GHG being destroyed shall be
estimated considering current or previous representative concentration
measurements and other relevant process information.  ThisYou must
multiply this concentration (mass fraction) shall be multiplied by the
mass measurement to obtain the mass of the fluorinated GHG destroyed.

(i)  Very small quantities of fluorinated GHGs that are difficult to
measure because they are entrained in other media such as destroyed
filters and destroyed sample containers are exempt from paragraphs (f)
and (h) of this section.  

(j)  You must estimate the share of the mass of fluorinated GHGs in
paragraph (h) of this section that is comprised of fluorinated GHGs that
are not included in the mass produced in §98.413(a) because they are
removed from the production process as by-products or other wastes.

(j)  [Reserved]

(k)  For purposes of Equation OO-4 of this subpart, the destruction
efficiency can be equated to the destruction efficiency determined
during a previous performance test of the destruction device or, if no
performance test has been done, the destruction efficiency provided by
the manufacturer of the destruction device. 

(l)  In their estimates of the mass of fluorinated GHGs destroyed,
fluorinated GHG production facilities that destroy fluorinated GHGs
shall account for any temporary reductions in the destruction efficiency
that result from any startups, shutdowns, or malfunctions of the
destruction device, including departures from the operating conditions
defined in state or local permitting requirements and/or oxidizer
manufacturer specifications.

(m)  Calibrate all flow meters, weigh scales, and combinations of
volumetric and density measures that are used to measure or calculate
quantities that are to be reported under this subpart prior to the first
year for which GHG emissions are reported under this part.  Calibrations
performed prior to the effective date of this rule satisfy this
requirement.  Recalibrate all flow meters, weigh scales, and
combinations of volumetric and density measures at the minimum frequency
specified by the manufacturer.  Use NIST-traceable standards and
suitable methods published by a consensus standards organization (e.g.,
ASTM, ASME, ISO, or others).

(n)  If the mass coming out of the production process includes more than
one fluorinated GHG, you shall measure the concentrations of all of the
fluorinated GHGs, other than low-concentration constituents, as follows:

(1)  Analytical Methods.  Use a quality-assured analytical measurement
technology capable of detecting the analyte of interest at the
concentration of interest and use a procedure validated with the analyte
of interest at the concentration of interest.  Where standards for the
analyte are not available, a chemically similar surrogate may be used. 
Acceptable analytical measurement technologies include but are not
limited to gas chromatography (GC) with an appropriate detector,
infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic
resonance (NMR).  Acceptable methods include EPA Method 18 in Appendix
A-1 of 40 CFR part 60; EPA Method 320 in Appendix A of 40 CFR part 63;
the Protocol for Measuring Destruction or Removal Efficiency (DRE) of
Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing, Version 1, EPA-430-R-10-003, (March 2010) (incorporated
by reference, see §98.7); ASTM D6348-03 Standard Test Method for
Determination of Gaseous Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by
reference, see §98.7); or other analytical methods validated using EPA
Method 301 in Appendix A of 40 CFR part 63 or some other scientifically
sound validation protocol.  The validation protocol may include
analytical technology manufacturer specifications or recommendations. 

(2)  Documentation in GHG Monitoring Plan.  Describe the analytical
method(s) used under paragraph (n)(1) of this section in the site GHG
Monitoring Plan as required under §98.3(g)(5).  At a minimum, include
in the description of the method a description of the analytical
measurement equipment and procedures, quantitative estimates of the
method’s accuracy and precision for the analytes of interest at the
concentrations of interest, as well as a description of how these
accuracies and precisions were estimated, including the validation
protocol used.  

(3)  Frequency of measurement.  Perform the measurements at least once
by [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL
REGISTER] if the fluorinated GHG product is being produced on [INSERT
DATE OF PUBLICATION IN THE FEDERAL REGISTER].  Perform the measurements
within 60 days of commencing production of any  fluorinated GHG product
that was not being produced on [INSERT DATE OF PUBLICATION IN THE
FEDERAL REGISTER].  Repeat the measurements if an operational or process
change occurs that could change the identities or significantly change
the concentrations of the fluorinated GHG constituents of the
fluorinated GHG product.  Complete the repeat measurements within 60
days of the operational or process change.  

(4)  Measure all product grades.  Where a fluorinated GHG is produced at
more than one purity level (e.g., pharmaceutical grade and refrigerant
grade), perform the measurements for each purity level.

(5)  Number of samples.  Analyze a minimum of three samples of the
fluorinated GHG product that have been drawn under conditions that are
representative of the process producing the fluorinated GHG product.  If
the relative standard deviation of the measured concentrations of any of
the fluorinated GHG constituents (other than low-concentration
constituents) is greater than or equal to 15 percent, draw and analyze
enough additional samples to achieve a total of at least six samples of
the fluorinated GHG product.

(o)  All analytical equipment used to determine the concentration of
fluorinated GHGs, including but not limited to gas chromatographs and
associated detectors, IR, FTIR and NMR devices, shall be calibrated at a
frequency needed to support the type of analysis specified in the site
GHG Monitoring Plan as required under §98.414(n) and §98.3(g)(5) of
this part.  Quality assurance samples at the concentrations of concern
shall be used for the calibration.  Such quality assurance samples shall
consist of or be prepared from certified standards of the analytes of
concern where available; if not available, calibration shall be
performed by a method specified in the GHG Monitoring Plan. 

(p)  Isolated intermediates that are produced and transformed at the
same facility are exempt from the monitoring requirements of this
section.

(q)  Low-concentration constituents are exempt from the monitoring and
QA/QC requirements of this section.

§98.415  Procedures for estimating missing data.  

(a)  A complete record of all measured parameters used in the GHG
emissions calculations is required.  Therefore, whenever a
quality-assured value of a required parameter is unavailable (e.g., if a
meter malfunctions), a substitute data value for the missing parameter
shall be used in the calculations, according to paragraph (b) of this
section.

(b)  For each missing value of the mass produced, fed into the
production process (for used material being reclaimed), fed into the
transformation process, fed into destruction devices, sent to another
facility for transformation, or sent to another facility for
destruction, the substitute value of that parameter shall be a secondary
mass measurement where such a measurement is available.  For example, if
the mass produced is usually measured with a flowmeter at the inlet to
the day tank and that flowmeter fails to meet an accuracy or precision
test, malfunctions, or is rendered inoperable, then the mass produced
may be estimated by calculating the change in volume in the day tank and
multiplying it by the density of the product.  Where a secondary mass
measurement is not available, the substitute value of the parameter
shall be an estimate based on a related parameter.  For example, if a
flowmeter measuring the mass fed into a destruction device is rendered
inoperable, then the mass fed into the destruction device may be
estimated using the production rate and the previously observed
relationship between the production rate and the mass flow rate into the
destruction device. 

§98.416  Data reporting requirements.

In addition to the information required by §98.3(c), each annual report
must contain the following information:

(a)  Each fluorinated GHG or nitrous oxide production facility shall
report the following information:  

(1)  Mass in metric tons of each fluorinated GHG or nitrous oxide
produced at that facility by process, except for amounts that are
captured solely to be shipped off site for destruction. 

(2)  Mass in metric tons of each fluorinated GHG or nitrous oxide
transformed at that facility, by process. 

(3)  Mass in metric tons of each fluorinated GHG that is destroyed at
that facility, except fluorinated GHGs not included in the calculation
of mass and that was previously produced in §as defined at
§98.410(b).413(a) because they are removed from the production process
as by-products or other wastes.  Quantities to be reported under this
paragraph (a)(3) of this section could include,  but are not limited to
quantities that are shipped to the facility by another facility for
example,destruction and quantities that are returned to the facility for
reclamation but are found to be irretrievably contaminated and are
therefore destroyed. 

(4)  Mass in metric tons of each fluorinated GHG that is destroyed at
that facility except GHGs not included in the calculation of mass
produced in §98.413(a) because they are removed from the production
process as byproducts or other wastes.

(4)  [Reserved]

(5)  Total mass in metric tons of each fluorinated GHG or nitrous oxide
sent to another facility for transformation.

(6)  Total mass in metric tons of each fluorinated GHG sent to another
facility for destruction, except fluorinated GHGs that are not included
in the mass produced in §98.413(a) because they are removed from the
production process as by-products or other wastes. Quantities to be
reported under this paragraph (a)(6) could include, for example,
fluorinated GHGs that are returned to the facility for reclamation but
are found to be irretrievably contaminated and are therefore sent to
another facility for destruction.

(7)  Total mass in metric tons of each fluorinated GHG that is sent to
another facility for destruction and that is not included in the mass
produced in §98.413(a) because it is removed from the production
process as a byproduct or other waste.

(8)  Total mass in metric tons of each reactant fed into the F-GHG or
nitrous oxide production process, by process.

(9)  Total mass in metric tons of the reactants, by-products, and other
wastes permanently removed from the F-GHG or nitrous oxide production
process, by process. 

(10)  For transformation processes that do not produce an F-GHG or
nitrous oxide, mass in metric tons of any fluorinated GHG or nitrous
oxide fed into the transformation process, by process.

(11)  Mass in metric tons of each fluorinated GHG that is fed into the
destruction device. and that was previously produced as defined at
§98.410(b).  Quantities to be reported under this paragraph (a)(11) of
this section include but are not limited to quantities that are shipped
to the facility by another facility for destruction and quantities that
are returned to the facility for reclamation but are found to be
irretrievably contaminated and are therefore destroyed.

(12)  Mass in metric tons of each fluorinated GHG or nitrous oxide that
is measured coming out of the production process, by process.

(13)  Mass in metric tons of each used fluorinated GHGs or nitrous oxide
added back into the production process (e.g., for reclamation),
including returned heels in containers that are weighed to measure the
mass in §98.414(a), by process.

(14)  Names and addresses of facilities to which any nitrous oxide or
fluorinated GHGs were sent for transformation, and the quantities
(metric tons) of nitrous oxide and of each fluorinated GHG that were
sent to each for transformation.

(15)  Names and addresses of facilities to which any  fluorinated GHGs
were sent for destruction, and the quantities (metric tons) of nitrous
oxide and of each fluorinated GHG that were sent to each for
destruction.

(16)  Where missing data have been estimated pursuant to §98.415, the
reason the data were missing, the length of time the data were missing,
the method used to estimate the missing data, and the estimates of those
data.  

(b)  A fluorinated GHG production facility or importer that destroys
fluorinated GHGs shall submit a one-time report containing the following
information:

(1)  Destruction efficiency (DE) of each destruction unit. 

(2)  Methods used to determine the destruction efficiency.

(3)  Methods used to record the mass of fluorinated GHG destroyed.

(4)  Chemical identity of the fluorinated GHG(s) used in the performance
test conducted to determine DE.

(5)  Name of all applicable federal or state regulations that may apply
to the destruction process.  

(6)  If any process changes affect unit destruction efficiency or the
methods used to record mass of fluorinated GHG destroyed, then a revised
report must be submitted to reflect the changes.  The revised report
must be submitted to EPA within 60 days of the change.

(c)  AEach bulk importer of fluorinated GHGs or nitrous oxide shall
submit an annual report that summarizes theirits imports at the
corporate level, except for shipments including less than 250 metric
tonstwenty-five kilograms of CO2efluorinated GHGs or nitrous oxide,
transshipments, and heels that meet the conditions set forth at
§98.417(e).  The report shall contain the following information for
each import: 

(1)  Total mass in metric tons of nitrous oxide and each fluorinated GHG
imported in bulk., including each fluorinated GHG constituent of the
fluorinated GHG product that makes up between 0.5 percent and 100
percent of the product by mass.

(2)  Total mass in metric tons of nitrous oxide and each fluorinated GHG
imported in bulk and sold or transferred to persons other than the
importer for use in processes resulting in the transformation or
destruction of the chemical.

(3)  Date on which the fluorinated GHGs or nitrous oxide were imported.

(4)  Port of entry through which the fluorinated GHGs or nitrous oxide
passed. 

(5)  Country from which the imported fluorinated GHGs or nitrous oxide
were imported.

(6)  Commodity code of the fluorinated GHGs or nitrous oxide shipped. 

(7)  Importer number for the shipment. 

(8)  Total mass in metric tons of each fluorinated GHG destroyed by the
importer.

(9)  If applicable, the names and addresses of the persons and
facilities to which the nitrous oxide or fluorinated GHGs were sold or
transferred for transformation, and the quantities (metric tons) of
nitrous oxide and of each fluorinated GHG that were sold or transferred
to each facility for transformation.

(10)  If applicable, the names and addresses of the persons and
facilities to which the nitrous oxide or fluorinated GHGs were sold or
transferred for destruction, and the quantities (metric tons) of nitrous
oxide and of each fluorinated GHG that were sold or transferred to each
facility for destruction.

(d)  AEach bulk exporter of fluorinated GHGs or nitrous oxide shall
submit an annual report that summarizes theirits exports at the
corporate level, except for shipments including less than 250 metric
tonstwenty-five kilograms of CO2efluorinated GHGs or nitrous oxide,
transshipments, and heels.  The report shall contain the following
information for each export: 

(1)  Total mass in metric tons of nitrous oxide and each fluorinated GHG
exported in bulk.

(2)  Names and addresses of the exporter and the recipient of the
exports.

(3)  Exporter’s Employee Identification Number.

(4)  Commodity code of the fluorinated GHGs and nitrous oxide shipped.

(5)  Date on which, and the port from which, fluorinated GHGs and
nitrous oxide were exported from the United States or its territories.

(6)  Country to which the fluorinated GHGs or nitrous oxide were
exported.

(e)  By April 1, 2011, a fluorinated GHG production facility shall
submit a one-time report describing the following information:

(1)  The method(s) by which the producer in practice measures the mass
of fluorinated GHGs produced, including the instrumentation used
(Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its
accuracy and precision. 

(2)  The method(s) by which the producer in practice estimates the mass
of fluorinated GHGs fed into the transformation process, including the
instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale,
etc.) and its accuracy and precision. 

(3)  The method(s) by which the producer in practice estimates the
fraction of fluorinated GHGs fed into the transformation process that is
actually transformed, and the estimated precision and accuracy of this
estimate.

(4)  The method(s) by which the producer in practice estimates the
masses of fluorinated GHGs fed into the destruction device, including
the method(s) used to estimate the concentration of the fluorinated GHGs
in the destroyed material, and the estimated precision and accuracy of
this estimate. 

(5)  The estimated percent efficiency of each production process for the
fluorinated GHG produced.

(f)  By March 31, 2011, all fluorinated GHG production facilities shall
submit a one-time report that includes the concentration of each
fluorinated GHG constituent in each fluorinated GHG product as measured
under §98.414(n).  If the facility commences production of a
fluorinated GHG product that was not included in the initial report or
performs a repeat measurement under §98.414(n) that shows that the
identities or concentrations of the fluorinated GHG constituents of a
fluorinated GHG product have changed, then the new or changed
concentrations, as well as the date of the change, must be reflected in
a revision to the report.  The revised report must be submitted to EPA
by the March 31st that immediately follows the measurement under
§98.414(n).

 (g)  Isolated intermediates that are produced and transformed at the
same facility are exempt from the reporting requirements of this
section.

(h)  Low-concentration constituents are exempt from the reporting
requirements of this section.

§98.417  Records that must be retained.

(a)  In addition to the data required by §98.3(g), the fluorinated GHG
production facility shall retain the following records:

(1)  Dated records of the data used to estimate the data reported under
§98.416.

(2)  Records documenting the initial and periodic calibration of the gas
chromatographsanalytical equipment (including but not limited to GC, IR,
FTIR, or NMR), weigh scales, flowmeters, and volumetric and density
measures used to measure the quantities reported under this subpart,
including the industry standards or manufacturer directions used for
calibration pursuant to §98.414(jm) and (ko).

(b)  In addition to the data required by paragraph (a) of this section,
the fluorinated GHG production facility that destroys fluorinated GHGs
shall keep records of test reports and other information documenting the
facility’s one-time destruction efficiency report and annual
destruction device outlet reports in §98.416(b) and (e).

(c)  In addition to the data required by §98.3(g), the bulk importer
shall retain the following records substantiating each of the imports
that they report:

(1)  A copy of the bill of lading for the import.

(2)  The invoice for the import.

(3)  The U.S. Customs entry form.

(d)  In addition to the data required by §98.3(g), the bulk exporter
shall retain the following records substantiating each of the exports
that they report:

(1)  A copy of the bill of lading for the export and

(2)  The invoice for the import.

(e)  Every person who imports a container with a heel  that is not
reported under §98.416(c) shall keep records of the amount brought into
the United States that document that the residual amount in each
shipment is less than 10 percent of the volume of the container and
will:

(1)  Remain in the container and be included in a future shipment.

(2)  Be recovered and transformed.

(3)  Be recovered and destroyed.

(4)  Be recovered and included in a future shipment.

(f)  Isolated intermediates that are produced and transformed at the
same facility are exempt from the recordkeeping requirements of this
section.

(g)  Low-concentration constituents are exempt from the recordkeeping
requirements of this section.

§98.418  Definitions.

All Except as provided below, all of the terms used in this subpart have
the same meaning given in the Clean Air Act and subpart A of this part. 
If a conflict exists between a definition provided in this subpart and a
definition provided in subpart A, the definition in this subpart shall
take precedence for the reporting requirements in this subpart.

Isolated intermediate means a product of a process that is stored before
subsequent processing.  An isolated intermediate is usually a product of
chemical synthesis.  Storage of an isolated intermediate marks the end
of a process.  Storage occurs at any time the intermediate is placed in
equipment used solely for storage.

Low-concentration constituent means, for purposes of fluorinated GHG
production and export, a fluorinated GHG constituent of a fluorinated
GHG product that occurs in the product in concentrations below 0.1
percent by mass.  For purposes of fluorinated GHG import,
low-concentration constituent means a fluorinated GHG constituent of a
fluorinated GHG product that occurs in the product in concentrations
below 0.5 percent by mass.  Low-concentration constituents do not
include fluorinated GHGs that are deliberately combined with the product
(e.g., to affect the performance characteristics of the product).

Subpart PP—Suppliers of Carbon Dioxide

§98.420  Definition of the source category.

(a)  The carbon dioxide (CO2) supplier source category consists of the
following:

(1)  Facilities with production process units that capture a CO2 stream
for purposes of supplying CO2 for commercial applications or that
capture and maintain custody of a CO2 stream in order to sequester or
otherwise inject it underground.  Capture refers to the initial
separation and removal of CO2 from a manufacturing process or any other
process. 

(2)  Facilities with CO2 production wells that extract or produce a CO2
stream for purposes of supplying CO2 for commercial applications or that
extract and maintain custody of a CO2 stream in order to sequester or
otherwise inject it underground.  

(3)  Importers or exporters of bulk CO2.  

(b)  This source category is focused on upstream supply. It does not
cover: 

(1)  Storage of CO2 above ground or in geologic formations. 

(2)  Use of CO2 in enhanced oil and gas recovery. 

(3)  Transportation or distribution of CO2. 

(4)  Purification, compression, or processing of CO2.

(5)  On-site use of CO2 captured on site. 

(c)  This source category does not include CO2 imported or exported in
equipment, such as fire estinguishers. 

§98.421  Reporting threshold.

Any supplier of CO2 who meets the requirements of §98.2(a)(4) of
subpart A of this part must report the mass of CO2 captured, extracted,
imported, or exported.

§98.422  GHGs to report.

(a)  Mass of CO2 captured from each production process units.

(b)  Mass of CO2 extracted from each CO2 production wells.

(c)  Mass of CO2 imported.

(d)  Mass of CO2 exported.

§98.423  Calculating CO2 Supply.

(a)  Except as allowed in paragraph (b) of this section, Ccalculate the
annual mass of CO2 captured, extracted, imported, or exported through
each flow meter in accordance with the procedures specified in either
paragraph (a)(1) or (a)(2) of this section.  If multiple flow meters are
used, you shall calculate the annual mass of CO2 for all flow meters
according to the procedures specified in paragraph (a)(3) of this
section. 

(1)  For each mass flow meter, you shall calculate quarterly the mass of
CO2 in a CO2 stream in metric tons, prior to any subsequent
purification, processing, or compressing, by multiplying the mass flow
by the composition data, according to Equation PP-1 of this section. 
Mass flow and composition data measurements shall be made in accordance
with §98.424 of this subpart.

 	(Eq. PP-1)

Where:  

CO2,u	=	Annual mass of CO2 (metric tons) through flow meter u. 

CCO2,p,u 	=	Quarterly CO2 concentration measurement in flow for flow
meter u in quarter p (wt. %CO2).

Qp,u 	=	Quarterly mass flow rate measurement for flow meter u in quarter
p (metric tons). 

p	=	Quarter of the year.

u	=	Flow meter. 

(2)  For each volumetric flow meter, you shall calculate quarterly the
mass of CO2 in a CO2 stream in metric tons, prior to any subsequent
purification, processing, or compressing, by multiplying the volumetric
flow by the concentration and density data, according to Equation PP-2
of this section.  Volumetric flow, concentration and density data
measurements shall be made in accordance with §98.424 of this section.

 	(Eq. PP-2)

Where:  

CO2,u	=	Annual mass of CO2 (metric tons) through flow meter u. 

CCO2,p 	=	Quarterly CO2 concentration measurement in flow for flow meter
u in quarter p (wt. % CO2).

Qp 	=	Quarterly volumetric flow rate measurement for flow meter u in
quarter p (standard cubic meters).

Dp	=	Quarterly CO2 stream density measurement for flow meter u in
quarter p (metric tons per standard cubic meter). 

p	=	Quarter of the year.

u	=	Flow meter. 

(3)  To aggregate data, sum the mass of CO2 for all flow meters in
accordance with Equation PP-3 of this section. 

 	(Eq. PP-3)

Where:  

CO2	=	Annual mass of CO2 (metric tons) through all flow meters. 

CO2,u	=	Annual mass of CO2 (metric tons) through flow meter u. 

u	=	Flow meter.  

(b)  As an alternative to paragraphs (a)(1) through (3) of this section
for CO2 that is supplied in containers,  calculate the annual mass of
CO2 supplied in containers delivered by each CO2 stream in accordance
with the procedures specified in either paragraph (b)(1) or (b)(2) of
this section.  If multiple CO2 streams are used to deliver CO2 to
containers, you shall calculate the annual mass of CO2 supplied in
containers delivered by all CO2 streams according to the procedures
specified in paragraph (b)(3) of this section.

(1)  For each CO2 stream that delivers CO2 to containers, for which mass
is measured, you shall calculate CO2 supply in containers using Equation
PP-1 of this section.

Where:  

CO2,u	=	Annual mass of CO2 (metric tons) supplied in containers
delivered by CO2 stream u. 

CCO2,p,u 	=	Quarterly CO2 concentration measurement of CO2 stream u that
delivers CO2 to containers in quarter p (wt. %CO2).

Qp,u 	=	Quarterly mass of contents supplied in all containers delivered
by CO2 stream u in quarter p (metric tons). 

p	=	Quarter of the year.

u	=	CO2 stream that delivers to containers. 

(2)  For each CO2 stream that delivers to containers, for which volume
is measured, you shall calculate CO2 supply in containers using Equation
PP-2 of this section.

Where:  

CO2,u	=	Annual mass of CO2 (metric tons) supplied in containers
delivered by CO2 stream u. 

CCO2,p,u 	=	Quarterly CO2 concentration measurement of CO2 stream u that
delivers CO2 to containers in quarter p (vol. %CO2).

Qp 	=	Quarterly volume of contents supplied in all containers delivered
by CO2 stream u in quarter p (metric tons) (standard cubic meters).

Dp	=	Quarterly CO2 stream density determination for CO2 stream u in
quarter p (metric tons per standard cubic meter). 

p	=	Quarter of the year.

u	=	CO2 stream that delivers to containers. 

(3)  To aggregate data, sum the mass of CO2 supplied in containers
delivered by all CO2 streams in accordance with Equation PP-3 of this
section. 

Where:  

CO2	=	Annual mass of CO2 (metric tons) supplied in containers delivered
by all CO2 streams. 

CO2,u	=	Annual mass of CO2 (metric tons) supplied in containers
delivered by CO2 stream u. 

u	=	CO2 stream that delivers to containers.  

(cb)  Importers or exporters that import or export CO2 in containers
shall calculate the total mass of CO2 imported or exported in metric
tons, prior to any subsequent purification, processing, or compressing,
based on summing the mass in each CO2 container using weigh bills,
scales, or load cells according to Equation PP-4 of this section.

 	(Eq. PP-4)

Where:  

CO2	=	Annual mass of CO2 (metric tons). 

Q 	=	Annual mass in all CO2 containers imported or exported during the
reporting year (metric tons).

§98.424  Monitoring and QA/QC requirements.

(a)  Determination of quantity.

(1)  Reporters following the procedures in paragraph (a) of §98.423
shall determine quantity using a flow meter or meters located in
accordance with this paragraph. 

(i)  If the CO2 stream is segregated such that only a portion is
captured for commercial application or for injection, you must locate
the flow meter after the point of segregation.

(ii)  Reporters that have a mass flow meter or volumetric flow meter
installed to measure the flow of a CO2  stream that meets the
requirements of paragraph (i) of this section shall base calculations in
§98.423 of this subpart on the installed mass flow or volumetric flow
meters.  

(iii2)  Reporters that do not have a mass flow meter or volumetric flow
meter installed to measure the flow of the CO2 stream that meets the
requirements of paragraph (i) of this section shall base calculations in
§98.423 of this subpart on the flow of gas transferred off site using a
mass flow meter or a volumetric flow meter located at the point of
off-site transfer.

(2)  Reporters following the procedures in paragraph (b) of §98.423
shall determine quantity in accordance with this paragraph.   

(i)  Reporters that supply CO2 in containers using weigh bills, scales,
or load cells shall measure the mass of contents of each CO2 container
to which the CO2 stream delivered, sum the mass of contents supplied in
all containers to which the CO2 stream delivered during each quarter,
sample the CO2 stream delivering CO2 to containers on a quarterly basis
to determine the composition of the CO2 stream, and apply Equation PP-1.

(ii)  Reporters that supply CO2 in containers using loaded container
volumes shall measure the volume of contents of each CO2 container to
which the CO2 stream delivered, sum the volume of contents supplied in
all containers to which the CO2 stream delivered during each quarter,
sample the CO2 stream on a quarterly basis to determine the composition
of the CO2 stream, determine the density quarterly, and apply Equation
PP-2.

(3)  Importers or exporters that import or export CO2 in containers
shall measure the mass in each CO2 container using weigh bills, scales,
or load cells and sum the mass in all containers imported or exported
during the reporting year.

(4)  All flow meters, scales, and load cells used to measure quantities
that are reported in §98.423 of this subpart shall be operated and
calibrated according to the following procedure: 

(i)  You shall use an appropriate standard method published by a
consensus-based standards organization if such a method exists. 
Consensus-based standards organizations include, but are not limited to,
the following: ASTM International, the American National Standards
Institute (ANSI), the American Gas Association (AGA), the American
Society of Mechanical Engineers (ASME), the American Petroleum Institute
(API), and the North American Energy Standards Board (NAESB).  

(ii)  Where no appropriate standard method developed by a
consensus-based standards organization exists, you shall follow industry
standard practices.

(iii)  You must ensure that any flow meter calibrations performed are
NIST traceable.

(5)  Reporters using Equation PP-2 of this subpart shall measure
determine the density of the CO2 stream on a quarterly basis in order to
calculate the mass of the CO2 stream according to one of the following
procedures: 

(i)  You shall use an appropriate standard method published by a
consensus-based standards organization to measure density if such a
method exists. Consensus-based standards organizations include, but are
not limited to, the following: ASTM International, the American National
Standards Institute (ANSI), the American Gas Association (AGA), the
American Society of Mechanical Engineers (ASME), the American Petroleum
Institute (API), and the North American Energy Standards Board (NAESB). 

(ii)  Where no appropriate standard method developed by a
consensus-based standards organization exists, yYou shall follow
industry standard practices.

(b)  Determination of concentration.

(1)  Reporters using Equation PP-1 or PP-2 of this subpart shall sample
the CO2 stream on a quarterly basis to determine the composition of the
CO2 stream.  

(2)  Methods to measure the composition of the CO2  stream must conform
to applicable chemical analytical standards.  Acceptable methods include
U.S. Food and Drug Administration food-grade specifications for CO2 (see
21 CFR 184.12450) and ASTM standard E1747-95(Reapproved 2005) Standard
Guide for Purity of Carbon Dioxide Used in Supercritical Fluid
Applications (incorporated by reference, see §98.7 of subpart A of this
part).

(c)  If you measure the flow of the CO2 stream with a volumetric flow
meter, you shall convert all measured volumes of carbon dioxide to the
following standard industry temperature and pressure conditions:
standard cubic meters at a temperature of 60 degrees Fahrenheit and at
an absolute pressure of 1 atmosphere.  If you apply the density value
for CO2 at standard conditions, you must use must use 0.0018704 metric
tons per standard cubic meter.

§98.425  Procedures for estimating missing data.

(a)  Whenever the quality assurance procedures in §98.424(a)(2) of this
subpart cannot be followed to measure quarterly mass flow or volumetric
flow of CO2, the most appropriate of the following missing data
procedures shall be followed:

(1)  A quarterly CO2 mass flow or volumetric flow value that is missing
may be substituted with a quarterly value measured during another
quarter of the current reporting year. 

(2)  A quarterly CO2 mass flow or volumetric flow value that is missing
may be substituted with a quarterly value measured during the same
quarter from the past reporting year. 

(3)  If a mass or volumetric flow meter is installed to measure the CO2
stream, you may substitute data from a mass or volumetric flow meter
measuring the CO2 stream transferred for any period during which the
installed meter is inoperable.

(4)  The mass or volumetric flow used for purposes of product tracking
and billing according to the reporter’s established procedures may be
substituted for any period during which measurement equipment is
inoperable.

(b)  Whenever the quality assurance procedures in §98.424(b) of this
subpart cannot be followed to determine concentration of the CO2 stream,
the most appropriate of the following missing data procudures shall be
followed:

(1)  A quarterly concentration value that is missing may be substituted
with a quarterly value measured during another quarter of the current
reporting year. 

(2)  A quarterly concentration value that is missing may be substituted
with a quarterly value measured during the same quarter from the
previous reporting year.

(3)  The concentration used for purposes of product tracking and billing
according to the reporter’s established procedures may be substituted
for any quarterly value.

(c)  Missing data on density of the CO2 stream shall be substituted with
quarterly or annual average values from the previous calendar year.

(d)  Whenever the quality assurance procedures in §98.424(a)(2) of this
subpart cannot be followed to measure quarterly quantity of CO2 in
containers, the most appropriate of the following missing data
procedures shall be followed:

(1)  A quarterly quantity of CO2 in containers that is missing may be
substituted with a quarterly value measured during another
representative quarter of the current reporting year. 

(2)  A quarterly quantity of CO2 in containers that is missing may be
substituted with a quarterly value measured during the same quarter from
the past reporting year. 

(3)  The quarterly quantity of CO2 in containers recorded for purposes
of product tracking and billing according to the reporter’s
established procedures may be substituted for any period during which
measurement equipment is inoperable.

§98.426  Data reporting requirements.

In addition to the information required by §98.3(c) of subpart A of
this part, the annual report shall contain the following information, as
applicable:

(a)  If you use Equation PP-1 of this subpart, report the following
information for each mass flow meter or CO2 stream that delivers CO2 to
containers:

(1)  Annual mass in metric tons of CO2.

(2)  Quarterly mass flow in metric tons of CO2.

(3)  Quarterly concentration of the CO2 stream.

(4)  The standard used to measure CO2 concentration.

(5)  The location of the flow meter in your process chain in relation to
the points of CO2 stream capture, deyhdration, compression, and other
processing. 

(b)  If you use Equation PP-2 of this subpart, report the following
information for each volumetric flow meter or CO2 stream that delivers
CO2 to containers:

(1)  Annual mass in metric tons of CO2. 

(2)  Quarterly volume in standard cubic meterstric flow of CO2.

(3)  Quarterly concentration of the CO2 stream. 

(4)  Quarterly density of the CO2 stream.

(5)  The method used to measure density.

(6)  The standard used to measure CO2 concentration.

(7)  The location of the flow meter in your process chain in relation to
the points of CO2 stream capture, deyhdration, compression, and other
processing. 

(c)  If you use Equation PP-3 of this subpart report the annual CO2 mass
in metric tons from all flow meters and CO2 streams that delivers CO2 to
containers.

(d)  If you use Equation PP-4 of this subpart, report at the corporate
level the annual mass of CO2 in metric tons in all CO2 containers that
are imported or exported.

(e)  Each reporter shall report the following information:

(1)  The type of equipment used to measure the total flow of the CO2
stream or the total mass or volume in CO2 containers.

(2)  The standard used to operate and calibrate the equipment reported
in (e)(1) of this section.

(3)  The number of days in the reporting year for which substitute data
procedures were used for the following purpose:

(i)  To measure quantity.

(ii)  To measure concentration.

(iii)  To measure density.

(f)  Report the aggregated annual quantity of CO2 in metric tons that is
transferred to each of the following end use applications, if known:

(i)  Food and beverage.

(ii)  Industrial and municipal water/wastewater treatment.

(iii)  Metal fabrication, including welding and cutting.

(iv)  Greenhouse uses for plant growth.

(v)  Fumigants (e.g., grain storage) and herbicides.

(vi)  Pulp and paper.

(vii)  Cleaning and solvent use.

(viii)  Fire fighting.

(ix)  Transportation and storage of explosives.

(x)  Enhanced oil and natural gas recovery.

(xi)  Long-term storage (sequestration).

(xii)  Research and development.

(xiii)  Other.

(g)  Each production process unit that captures a CO2 stream for
purposes of supplying CO2 for commercial applications or in order to
sequester or otherwise inject it underground when custody of the CO2 is
maintained shall report the percentage of that stream, if any, that is
biomass-based during the reporting year.

§98.427  Records that must be retained.

In addition to the records required by §98.3(g) of subpart A of this
part, you must retain the records specified in paragraphs (a) through
(c) of this section, as applicable.

(a)  The owner or operator of a facility containing production process
units must retain quarterly records of captured or transferred CO2
streams and composition. 

(b)  The owner or operator of a CO2  production well facility must
maintain quarterly records of the mass flow or volumetric flow of the
extracted or transferred CO2 stream and concentration and density if
volumetric flow meters are used.  

(c)  Importers or exporters of CO2 must retain annual records of the
mass flow, volumetric flow, and mass of CO2 imported or exported.

§98.428  Definitions.

All terms used in this subpart have the same meaning given in the Clean
Air Act and subpart A of this part.

 PAGE   

 PAGE   408 

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