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