Any supplier of natural gas or natural gas liquids who
is required to report under section
95101 must comply with Subpart NN
of 40 CFR Part 98 (§§
98.400 to
98.408) in reporting emissions and
related data to ARB, except as otherwise provided in this section.
(a)
GHGs to Report.
(1) In addition to the
CO
2 emissions specified under
40 CFR §
98.402(a), natural gas
liquid fractionators must report the CO
2,
CH
4, N
2O and
CO
2e emissions that would result from the complete
combustion or oxidation of liquefied petroleum gas sold or delivered to others
that was produced on-site, except for products for which a final destination
outside California can be demonstrated.
(2) In addition to the
CO
2 emissions specified under
40 CFR §
98.402(b), local
distribution companies and intrastate pipelines delivering gas to California
end-users must report the CO
2,
CO
2 from biomass-derived fuels,
CH
4, N
2O, and
CO
2e emissions from the complete combustion or oxidation
of the annual volume of natural gas delivered to all entities on their
distribution systems in California.
(3) The importer of liquefied petroleum gas,
compressed natural gas, or liquefied natural gas into California must report
the CO2, CH4,
N2O and CO2e emissions that would
result from the complete combustion or oxidation of the annual quantity of
liquefied petroleum gas, compressed natural gas, and liquefied natural gas
imported into the state, except for products for which a final destination
outside California can be demonstrated.
(4) Operators of facilities that make
liquefied natural gas products or compressed natural gas products by liquefying
or compressing natural gas received from interstate pipelines must report the
CO2, CH4,
N2O, and CO2e emissions that
would result from the complete combustion or oxidation of all liquefied natural
gas sold or delivered to others, except for product for which a final
destination outside California can be demonstrated.
(b)
Calculating GHG
Emissions.
(1) Natural gas liquid
fractionators must use calculation methodology 2 as specified in
40 CFR §
98.403(a)(2) to estimate the
CO
2 emissions that would result from the complete
combustion of all natural gas liquid products supplied except that Table MM-1
must be used in place of Table NN-2. For calculating the emissions from
liquefied petroleum gas, the fractionators must sum the emissions from the
individual constituents of liquefied petroleum gas sold or delivered to others
that was produced onsite, except for products for which a final destination
outside of California can be demonstrated.
(2) For the calculation of
CO
2i in section
95122(b)(6),
local distribution companies must estimate CO
2 emissions
at the state border or city gate for pipeline quality natural gas using
calculation methodology 1 as specified in
40 CFR §
98.403(a)(1), except that
the product of HHV and Fuel is replaced by the annual MMBtu of natural gas
received.
(3) For the calculation
of CO
2j in section
95122(b)(6),
public utility gas corporations and publicly owned natural gas utilities must
estimate annual CO
2 emissions from instate receipts of
pipeline quality natural gas from other public utility gas corporations,
interstate pipelines and intrastate transmission pipelines, and annual
CO
2 emissions from all natural gas redelivered to other
public utility gas corporations or interstate pipelines. Annual
CO
2 emissions from redelivered natural gas to intrastate
pipelines or publicly owned natural gas utilities must be estimated only if
emissions from the redelivered natural gas equals or exceeds 25,000
MTCO
2e calculated according to subparagraph (2) above.
Emissions are calculated according to Equation NN-3 of
40 CFR §
98.403(b)(1) except that
CO
2j will be the product of
MMBtu
Total and the default emission factor from Table
NN-1 or the product of MMBtu
Total and the reporter
specific emission factor. MMBtu
Total must be calculated
as follows:
MMBtuTotal =
MMBturedelivery -
MMBtureceipts
Where
MMBtuTotal = Total annual MMBtu
used in equation NN-3
MMBturedelivery = Total annual
MMBtu of natural gas delivered to other companies as specified above
MMBtureceipts = Total annual
MMBtu of natural gas received from other companies as specified
above
(4) For the
calculation of CO
2l in section
95122(b)(6),
emissions from receipts of pipeline quality natural gas from in-state natural
gas producers and net volume of pipeline quality natural gas injected into
storage are estimated according to Equation NN-5 of
40 CFR §
98.403(b)(3) except that
CO
2l will be calculated as the product
of the net annual MMBtu and a default emission factor from Table NN-1 or the
product of the net annual MMBtu and a reporter specific emission
factor.
(5) Determination of
pipeline quality natural gas is based on the annual weighted average HHV,
determined according to Equation C-2b of
40 CFR §
98.33(a)(2)(ii)(A), for
natural gas from a single city gate, storage facility, or connection with an
in-state producer, interstate pipeline, intrastate pipeline or local
distribution company. If the HHV is outside the range of pipeline quality
natural gas, emissions will be calculated using the appropriate subparagraph of
section
95122(a)
replacing the default emission factor with either a reporter specific emission
factor as calculated in 40
CFR §
98.404(b)(2) or
one determined as follows:
(A) For natural gas
or biomethane with an annual weighted HHV below 970 Btu/scf and not exceeding 3
percent of total emissions estimated under this section, the local distribution
company may use the reporter specific weighted yearly average higher heating
value and the default emission factor or an emission factor as determined in
40 CFR §
98.404(c)(3). If emissions
exceed 3 percent of the total, then the Tier 3 method specified in
40 CFR §
98.33(a)(3)(iii) must be
used with monthly carbon content samples to calculate the annual emissions from
the portion of natural gas that is below 970 Btu/scf.
(B) For natural gas or biomethane with an
annual HHV above 1100 Btu/scf and not exceeding 3 percent of total emissions
estimated under this section, the local distribution company must use the
reporter specific weighted yearly average higher heating value and a default
emission factor of 54.67 kg CO
2/MMBtu or an emission
factor as determined in 40
CFR §
98.404(c)(3). If
emissions exceed 3 percent of the total, then the Tier 3 method specified in
40 CFR §
98.33(a)(3)(iii) must be
used with monthly carbon content samples to calculate the annual emissions from
the portion of natural gas that is above 1100 Btu/scf.
(6) When calculating total
CO
2 emissions for California, the equation below must be
used:
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Where:
CO2 = Total emissions.
CO2i = Emissions from natural
gas received at the state border or city gate, calculated pursuant to section
95122(b)(2).
CO2j = Emissions from natural
gas received for redistribution to or received from other natural gas
transmission companies, calculated pursuant to section
95122(b)(3).
CO2l = Emissions from storage
and direct deliveries from producers calculated pursuant to section
95122(b)(4).
(7) Natural gas liquid fractionators and
local distribution companies must estimate and report
CH
4 and N
2O emissions using
equation C-8 and Table C-2 as described in
40 CFR §
98.33(c)(1) for all fuels
where annual CO
2 emissions are required to be reported
by 40 CFR §
98.406 and this section. Local distribution
companies must use the annual MMBtu determined in paragraphs (2)-(4) above in
place of the product of the Fuel and HHV in equation C-8 when calculating
emissions.
(8) Local distribution
companies must separately and individually calculate end-user emissions of
CH
4, N
2O,
CO
2 from biomass-derived fuels, and
CO
2e by replacing CO
2 in the
equation in section
95122(b)(6) with
CH
4, N
2O,
CO
2 from biomass-derived fuels, and
CO
2e. CO
2 emissions from
biomass-derived fuel are based on the fuel the LDC has contractually purchased
on behalf of and delivered to end users. LDCs can elect to report biomethane
directly purchased by an end user and delivered by the LDC if the LDC can
provide the information required by section
95103(j)(3), and
can provide access during verification to the documentation necessary to
identify the biomethane as exempt or non-exempt pursuant to section
95103(j).
Emissions from contractually purchased biomethane are calculated using the
methods for natural gas required by this section, including the use of the
emission factor for natural gas found in
40 CFR §
98.408, table NN-1. Biomass-derived fuels
directly purchased by end users and delivered by the LDC must be reported as
natural gas by the LDC, unless the LDC has elected to report the delivery as
biomethane and can provide the necessary documentation during verification to
determine exemption status as stated above.
(9) The importer of liquefied petroleum gas
into California must use calculation methodology 2 described in
40 CFR §
98.403(a)(2) for calculating
CO
2 emissions except that for liquefied petroleum gas
table MM-1 of 40 CFR Part
98 must be used in place of Table NN-2. For liquefied
petroleum gas, the importer must sum the emissions from the individual
components of the gas to calculate the total emissions. If the composition is
not supplied by the producer, the importer must use the default value for
liquefied petroleum gas presented in Table C-1 of 40 CFR Part
98. The importer
of compressed natural gas or liquefied natural gas into California must
estimate CO
2 using calculation methodology 1 as
specified in 40 CFR §
98.403(a)(1), except that
the product of HHV and Fuel is replaced by the annual MMBtu of the imported
compressed natural gas and liquefied natural gas.
(10) The importer of liquefied petroleum gas,
compressed natural gas, or liquefied natural gas into California must estimate
and report CH
4 and N
2O emissions
using equation C-8 and Table C-2 as described in
40 CFR §
98.33(c)(1).
(11) Operators of facilities that make
liquefied natural gas products or compressed natural gas products as described
in section
95122(a)(4) must
estimate CO
2 using calculation methodology 1 as
specified in 40 CFR §
98.403(a)(1), except that
the product of HHV and Fuel is replaced by the annual MMBtu of the liquefied
natural gas sold or delivered in California.
(12) Operators of facilities that make
liquefied natural gas products or compressed natural gas products as described
in section
95122(a)(4) must
estimate and report CH
4 and N
2O
emissions based on the MMBtu of liquefied natural gas sold or delivered using
equation C-8 and Table C-2 as described in
40 CFR §
98.33(c)(1).
(13) All fuel suppliers in this section must
also estimate CO
2e emissions using the following
equation:
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Where:
CO2e = Carbon dioxide
equivalent, metric tons/year.
GHGi = Mass emissions of
CO2, CH4,
N2O from fuels combusted or oxidized.
GWPi = Global
warming potential for each greenhouse gas from as specified in the "global
warming potential" definition of this article.
n = Number of greenhouse gases
emitted.
(c)
Monitoring and QA/QC Requirements. For each emissions
calculation method chosen under this section, the supplier must meet all
monitoring and QA/QC requirements specified in
40 CFR §
98.404, except as modified in sections
95103,
95115, and below.
(1) All natural gas suppliers must measure
required values at least monthly.
(2) All natural gas suppliers must determine
reporter specific HHV at least monthly, or if the local distribution company
does not make its own measurements according to standard business practices it
must use the delivering pipeline measurement.
(3) All natural gas liquid fractionators must
sample for composition at least monthly.
(4) All importers of liquefied petroleum gas
into California must record composition, if provided by the supplier, and
quantity in barrels, corrected to 60 degrees Fahrenheit, for each shipment
received.
(d)
Data Reporting Requirements.
(1) For the emissions calculation method
selected under section
95122(b), natural
gas liquid fractionators must report, in addition to the data required by
40 CFR §
98.406(a), the annual volume
of liquefied petroleum gas, corrected to 60 degrees Fahrenheit, that was
produced onsite and sold or delivered to others, except for products for which
a final destination outside California can be demonstrated. Natural gas liquid
fractionators must report the annual quantity of liquefied petroleum gas
produced and sold or delivered to others as the total volume in barrels as well
as the volume of the individual components for all components listed in
40 CFR
98 Table MM-1. Fractionators must also
include the annual CO
2, CH
4,
N
2O, and CO
2e mass emissions
(metric tons) from the volume of liquefied petroleum gas reported in
40 CFR §
98.406(a)(5) as modified by
this regulation, calculated in accordance with section
95122(b).
(2) For the emissions calculation method
selected under section
95122(b), local
distribution companies must report all the data required by
40 CFR §
98.406(b) subject to the
following modifications:
(A) Publicly-owned
natural gas utilities that report in-state receipts at the city gate under
40 CFR §
98.406(b)(1) must also
identify each delivering entity by name and report the annual energy of natural
gas received in MMBtu.
(B) Local
distribution companies that report under
40 CFR §
98.406(b)(1) through (b)(7)
must also report the annual energy of natural gas in MMBtu associated with the
volumes.
(C) In addition to the
requirements in 40 CFR
§
98.406(b)(8), local
distribution companies must also include CO
2,
CO
2 from biomass-derived fuels,
CH
4, N
2O, and
CO
2e annual mass emissions in metric tons calculated in
accordance with 40 CFR
§
98.403(a) and (b)(1) through
(b)(3) as modified by section
95122(b).
(D) In lieu of reporting the information
specified in 40 CFR §
98.406(b)(6), local
distribution companies and intrastate pipelines that deliver natural gas to
downstream gas pipelines and other local distribution companies, must report
the annual energy in MMBtu, and the information required in
40 CFR §
98.406(b)(12). These
requirements are in addition to the requirements of
40 CFR §
98.406(b)(6).
(E) In lieu of reporting the information
specified in 40 CFR §
98.406(b)(7), local
distribution companies and intrastate pipelines must report the annual energy
in MMBtu, customer information required in
40 CFR §
98.406(b)(12), and ARB ID
number if available for all end-users registering supply equal to or greater
than 188,500 MMBtu during the calendar year. In addition to reporting the
information specified in 40
CFR §
98.406(b)(13),
local distribution companies and intrastate pipelines that deliver to end users
must report the annual energy in MMBtu delivered to the following end-use
categories: residential consumers; commercial consumers; industrial consumers;
electricity generating facilities; and other end-users not identified as
residential, commercial, industrial, or electricity generating facilities.
Local distribution companies must also report the total energy in MMBtu
delivered to all California end-users.
(F) Local distribution companies that report
under 40 CFR §
98.406(b)(9) must report
annual CO
2, CO
2 from
biomass-derived fuel, CH
4, N
2O,
and CO
2e emissions (metric tons) that would result from
the complete combustion or oxidation of the natural gas supplied to all
entities calculated in accordance with section
95122(b).
(3) In addition to the information required
in 40 CFR §
98.3(c), the operator of an
interstate pipeline, which is not a local distribution company, must report the
customer name, address, and ARB ID along with the annual energy of natural gas
in MMBtu for natural gas delivered to each customer, including
themselves.
(4) In addition to the
information required in 40
CFR §
98.3(c), the
operator of an intrastate pipeline that delivers natural gas directly to end
users must follow the reporting requirements described under Subpart NN of 40
CFR Part
98 and this section for local distribution companies. In lieu of the
city gate information specified by section
95122(b)(2), the
intrastate pipeline operator must report the summed energy (MMBtu) of natural
gas delivered to each entity receiving gas from the intrastate pipeline for
purposes of estimating the CO
2i parameter as specified
in section
95122(b)(6).
Additionally, intrastate pipeline operators are required to estimate a value
for CO
2j as specified in section
95122(b)(3) for
natural gas delivered to local distribution companies, interstate pipelines,
and other intrastate pipelines. The CO
2l parameter as
specified in section
95122(b)(4) must
have a value of 0 for calculating emissions as required by section
95122(b)(6).
(5) In addition to the information required
in 40 CFR §
98.3(c), the importer of
liquefied petroleum gas into California must report the annual quantity of
liquefied petroleum gas imported as the total volume in barrels as well as the
volume of its individual components for all components listed in
40 CFR
98 Table MM-1, if supplied by the producer,
and report CO
2, CH
4,
N
2O, and CO
2e annual mass
emissions in metric tons using the calculation methods in section
95122(b). All
importers of compressed or liquefied natural gas into California and liquefied
natural gas production facilities as described in section
95122(a)(4) must
report the annual quantities imported, and delivered or sold, respectively, in
MMBtu, and report CO
2, CH
4,
N
2O, and CO
2e annual mass
emissions in metric tons separately for compressed natural gas and liquefied
natural gas using the calculation methods in section
95122(b).
(6) In addition to the information required
in 40 CFR §
98.3(c), all local
distribution companies that report biomass emissions from biomethane fuel that
was contractually purchased by the LDC on behalf of and delivered to end users,
and all liquefied natural gas production facilities reporting biomass emission
from biomethane, must report, for each contracted delivery, the information
specified in section
95103(j)(3).
(7) All operators of facilities that make
liquefied natural gas products as described in section
95122(a)(4) must
report end-user information for deliveries of liquefied natural gas to
industrial facilities and natural gas utility customers, including customer
name, address, and the annual quantity of liquefied natural gas delivered to
each customer in MMBtu.
(8) All
natural gas liquid fractionators and importers of liquefied petroleum gas
identified in this section must report the total quantity in barrels of
liquefied petroleum gas that is excluded from emissions reporting due to
demonstration of final destination outside California.