Current through Register Vol. 24-06, March 15, 2024
This section establishes the scope of reportable GHG emissions
under this chapter and GHG emissions calculation methods for suppliers. Owners
and operators of suppliers must follow the requirements of this section to
determine if they are required to report under WAC
173-441-030(2).
Owners and operators of suppliers that are subject to this chapter must follow
the requirements of this section and all subparts of 40 C.F.R. Part 98 listed
in this section when calculating emissions. If a conflict exists between a
provision in WAC
173-441-010 through
173-441-110 and
173-441-140
through
173-441-170 and any
applicable provision of this section, the requirements of those sections must
take precedence.
(1)
General
requirements. An owner or operator of a supplier subject to the
requirements of this chapter must report GHG emissions, including GHG emissions
from biomass, from all applicable source categories with GHG emissions in
Washington state listed in (a) of this subsection using the methods in this
section. All GHG emissions in Washington state from a common primary parent
company or owner or operator are considered part of a single supplier for the
purposes of this section.
(a) Supplier source
categories:
(i) Position holders at terminals
and refiners delivering fuel products, other than natural gas described in
Subpart NN;
(ii) Enterers that
import fuel products, other than natural gas described in Subpart NN, outside
the bulk transfer/terminal system, and biofuel production facilities that
produce and deliver fuel products outside the bulk/terminal system;
(iii) Refiners that produce liquefied
petroleum gas;
(iv) Operators of
interstate pipelines delivering natural gas;
(v) Importers of liquefied petroleum gas,
compressed natural gas, or liquefied natural gas into Washington;
(vi) Local distribution companies who are
public utility gas corporations or publicly owned natural gas utilities
delivering natural gas;
(vii)
Operators of intrastate pipelines delivering natural gas;
(viii) Natural gas liquid
fractionators;
(ix) Producers,
importers, and exporters of carbon dioxide;
(x) Facilities that make and deliver
liquefied natural gas products or compressed natural gas products by liquefying
or compressing natural gas received from interstate pipelines.
(b) All references to 40 C.F.R.
Part 98 are modified consistent with WAC
173-441-120(2)(a)
through (e).
(c) The calculation methods for voluntary
reporting in WAC
173-441-120(3)
apply, except calculation methods in WAC
173-441-120(3)(b)
take precedence over the methods from WAC
173-441-120(3)(a).
(d) An owner or operator may petition ecology
to use calculation methods other than those specified in this section to
calculate its supplier GHG emissions. Such alternative calculation methods must
be approved by ecology prior to reporting and must meet the requirements of WAC
173-441-140.
(2)
Definitions specific to
suppliers. The definitions in this subsection apply throughout this
section unless the context clearly requires otherwise.
(a) "Biomethane" or "renewable methane" means
biogas that meets pipeline quality natural gas standards.
(b) "Biofuel production facility" means a
production facility that produces one or more biomass-derived fuels.
(c) "Biomass-derived fuels" means a fuel
listed in 40 C.F.R. Part 98 Table MM-2, or any renewable or biogenic version of
a product listed in 40 C.F.R. Part 98 Table MM-1.
(d) "Biogas" or "renewable natural gas" means
a gas consisting largely of methane and other hydrocarbons derived from the
decomposition of organic material in landfills, wastewater treatment
facilities, and anaerobic digesters.
(e) "Bulk transfer/terminal system" means a
fuel distribution system consisting of refineries, pipelines, vessels, and
terminals. Fuel storage and blending facilities that are not fed by pipeline or
vessel are considered outside the bulk transfer system.
(f) "Enterer" means an entity that imports
fuel products into Washington and who is the importer of record under federal
customs law or the owner of fuel upon import into Washington if the fuel is not
subject to federal customs law. Only enterers that import the fuels specified
in this definition outside the bulk transfer/terminal system are subject to
reporting under the regulation.
(g)
"Fractionator" 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.
(h) "Fuel transaction" means the record of
the exchange of fuel possession, ownership, or title from one entity to
another.
(i) "Importer of fuel"
means an entity that imports fuel products into Washington and who is the
importer of record under federal customs law. For imported fuel products not
subject to federal customs law, the "importer of fuel" is the owner of the fuel
product upon its entering into Washington if the eventual transfer of ownership
of the product to an end user or marketer located in Washington occurs at a
location inside Washington. However, where the transfer of ownership of the
fuel product to a Washington end user or marketer occurs at a location outside
of Washington, the "importer of fuel" is the producer, marketer, or distributor
that is the seller of the fuel product to the end user or marketer located
inside Washington. Pursuant to subsection (4) of this section, only importers
of liquefied petroleum gas, compressed natural gas, and liquefied natural gas
are subject to reporting as an importer of fuel.
(j) "Importer of record" means the owner or
purchaser of the goods that are imported into Washington.
(k) "Interstate pipeline" means any entity
that owns or operates a natural gas pipeline delivering natural gas to
consumers in the state and is subject to rate regulation by the Federal Energy
Regulatory Commission.
(l)
"Intrastate pipeline" means any pipeline or piping system wholly within
Washington state that is delivering natural gas to end users and is not
regulated as a public utility gas corporation by the Washington state utilities
and transportation commission, is not a publicly owned natural gas utility, and
is not regulated as an interstate pipeline by the Federal Energy Regulatory
Commission. Only in-trastate pipeline operators that physically deliver gas to
end users in Washington are subject to reporting under this chapter. This
definition includes onshore petroleum and natural gas production facilities and
natural gas processing facilities, as defined in 40 C.F.R. Part 98, that
deliver pipeline and/or nonpipeline quality natural gas to one or more end
users. Facility operators that operate an interconnection pipeline that
connects their facility to an interstate pipeline, or that share an
interconnection pipeline to an interstate pipeline with other nearby
facilities, are not considered intrastate pipeline operators. Facilities that
receive gas from an upstream LDC and redeliver a portion of the gas to one or
more adjacent facilities are not considered intrastate pipelines.
(m) "Local distribution company" or "LDC,"
for purposes of this chapter (chapter 173-441 WAC), means a company that owns
or operates distribution pipelines, not interstate pipelines, that physically
deliver natural gas to end users and includes public utility gas corporations,
publicly owned natural gas utilities and intrastate pipelines that are
delivering natural gas to end users.
(n) "Position holder" means an entity that
holds an inventory position in fuel products as reflected in the records of the
terminal operator or a terminal operator that owns fuel products in its
terminal. "Position holder" does not include inventory held outside of a
terminal, fuel jobbers (unless directly holding inventory at the terminal),
retail establishments, or other fuel suppliers not holding inventory at a fuel
terminal.
(o) "Producer" means a
person who owns, leases, operates, controls, or supervises a Washington state
production facility.
(p) "Rack"
means a mechanism for delivering motor vehicle fuel or diesel from a refinery
or terminal into a truck, trailer, railroad car, or other means of nonbulk
transfer.
(q) "Refiner" means, for
purposes of this chapter, an individual entity or a corporate-wide entity that
delivers fuel products to end users in Washington state that were produced by
petroleum refineries owned by that entity or a subsidiary of that
entity.
(r) "Terminal" means a fuel
product storage and distribution facility that is supplied by pipeline or
vessel, and from which fuel product may be removed at a rack. "Terminal"
includes a fuel production facility where fuel product is produced and stored
and from which fuel product may be removed at a rack.
(s) "Terminal operator" means any entity that
owns, operates, or otherwise controls a terminal that is supplied by pipeline
or vessel and from which accountable fuel products may be removed at a
rack.
(3)
Suppliers
of carbon dioxide. Any supplier of carbon dioxide with supplied
CO2 calculated under this subsection that exceeds the
reporting threshold in WAC
173-441-030(2)
of this chapter must comply with 40 C.F.R. Part 98 Subpart PP in reporting to
ecology, except as otherwise provided in this section. Also use Subpart PP for
threshold calculations.
(a) When reporting
imported and exported quantities of CO2 as required in
40 C.F.R. §
98.422, the supplier must report quantities
of carbon dioxide imported into and exported from Washington state. Exports for
purposes of geologic sequestration must be reported separately from exports for
other purposes.
(b) Facilities
required to report or voluntarily reporting under WAC
173-441-030(1) or
(5) with the following processes must report
supplied CO2 using the methods in this section as part
of their facility GHG report under WAC
173-441-070(1)
regardless of the amount of
CO2 supplied.
(i)
Production process units located in Washington state that capture a
CO2 stream for purposes of supplying
CO2 to another entity or facility or that capture the
CO2 stream in order to utilize it for geologic
sequestration where capture refers to the initial separation and removal of
CO2 from a manufacturing process or any other process;
or
(ii) CO2
production wells located in Washington state that extract or produce a
CO2 stream for purposes of supplying
CO2 for commercial applications or that extract a
CO2 stream in order to utilize it for geologic
sequestration.
(c)
Missing data substitution procedures. The supplier must comply with
40 C.F.R. §
98.425 when substituting for missing data,
except as otherwise provided below.
(i) If the
data capture rate is at least 90 percent for the data year, the supplier must
substitute for each missing value using the best available estimate of the
parameter, based on all available process data.
(ii) If the data capture rate is at least 80
percent but not at least 90 percent for the data year, the supplier must
substitute for each missing value with the highest quality assured value
recorded for the parameter during the given data year, as well as the two
previous data years.
(iii) If the
data capture rate is less than 80 percent for the data year, the supplier must
substitute for each missing value with the highest quality assured value
recorded for the parameter in all records kept according to WAC
173-441-050.
(iv) The supplier must document and retain
records of the procedure used for all missing data estimates pursuant to the
recordkeeping requirements of WAC
173-441-050.
(4)
Suppliers of natural gas.
Any supplier of natural gas, natural gas liquids, liquefied petroleum gas,
compressed natural gas, or liquefied natural gas with emissions calculated
under this subsection that exceeds the reporting threshold in WAC
173-441-030(2)
must comply with 40 C.F.R. Part 98 Subpart NN in reporting emissions and
related data to ecology, except as otherwise provided in this section. Also use
the methods in this section for threshold calculations.
(a)
GHGs to report. In
addition to the CO2 emissions specified under
40 C.F.R. §
98.402, all suppliers of natural gas covered
in this section must separately report the CO2,
CO2 from biomass-derived fuels,
CH4, N2O, and
CO2e emissions from the complete combustion or oxidation
of the annual volume of natural gas delivered, sold or imported in Washington
state.
(b)
Calculating GHG
emissions. When reporting imported and exported quantities of GHGs as
required in
40 C.F.R. §
98.403 and (a) of this subsection, the
supplier must report quantities of GHGs imported into and exported from
Washington state.
(i) Natural gas liquid
fractionators must use calculation methodology 2 as specified in
40 C.F.R. §
98.403(a)(2) to estimate the
CO2 emissions that would result from the complete
combustion of all natural gas liquid products supplied. 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 on-site, except for products for which a
final destination outside Washington state can be demonstrated.
(ii) Local distribution companies must
estimate CO2 emissions at the state border or city gate
for pipeline quality natural gas using calculation methodology 1 as specified
in
40 C.F.R. §
98.403(a)(1), except that
the product of HHV and Fuel is replaced by the annual MMBtu of natural gas
received.
(iii) For the calculation
of CO2j in Equation 122-2, public utility gas
corporations and publicly owned natural gas utilities must estimate annual
CO2 emissions from instate receipts of pipeline quality
natural gas from other public utility gas corporations, interstate pipelines
and intrastate transmission pipelines, and annual CO2
emissions from all natural gas redelivered to other public utility gas
corporations or interstate pipelines. Annual CO2
emissions from rede-livered natural gas to intrastate pipelines or publicly
owned natural gas utilities must be estimated only if the intrastate pipeline
or publicly owned natural gas utility also reports emissions under this
section. Emissions are calculated according to Equation NN-3 of
40 C.F.R. §
98.403(b)(1) except that
CO2j will be the product of
MMBtuTo-tal and the default emission factor from Table
NN-1 or the product of MMBtuTotal and the reporter
specific emission factor. MMBtuTotal must be calculated
as follows:
MMBtuTotal =
MMBturedelivery - MMBtureceipts
(Eq. 122-1)
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
(iv) For the calculation of
CO2l in Equation 122-2, 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-5a of
40 C.F.R. §
98.403(b)(3) except that
CO2l 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.
(v) For the calculation of
CO2n in Equation 122-2, emissions from natural gas
received directly by LDC systems from producers or natural gas processing
plants from local production, received as a liquid and vaporized for delivery,
or received from any other source that bypassed the city gate are estimated
according to Equation NN-5b of
40 C.F.R. §
98.403(b)(3) except that
CO2n 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 the reporter specific emission factor.
(vi) For the calculation of
CO2k in Equation 122-2, natural gas delivered to large
end users, use Equation NN-4 of
40 C.F.R. §
98.403(b)(2), except that
CO2k will be calculated as the product of the annual
MMBtu delivered and a default emission factor from Table NN-1 or the product of
the annual MMBtu delivered and the reporter specific emission factor. A large
end user means any end user facility required to report under WAC
173-441-030(1).
(vii) Determination of pipeline quality
natural gas is based on the annual weighted average HHV, determined according
to Equation C-2b of
40 C.F.R. §
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 subsection (4)
of this section replacing the default emission factor with either a reporter
specific emission factor as calculated in
40 C.F.R. §
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
three 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 C.F.R. §
98.404(c)(3). If emissions
exceed three percent of the total, then the Tier 3 method specified in
40 C.F.R. §
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 three percent of total
emissions estimated under this section, the local distribution company must use
the re porter specific weighted yearly average higher heating value and a
default emission factor of 54.67 kg CO2/MMBtu or an
emission factor as determined in
40 C.F.R. §
98.404(c)(3). If emissions
exceed three percent of the total, then the Tier 3 method specified in
40 C.F.R. §
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.
(viii) When calculating total
CO2 emissions for Washington state, 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 subsection
(4)(b)(ii) of this section.
CO2j = Emissions from natural gas
received for redistribution to or received from other natural gas transmission
companies, calculated pursuant to subsection (4)(b)(iii) of this
section.
CO2l = Emissions from storage and direct
deliveries from producers calculated pursuant to subsection (4)(b)(iv) of this
section.
CO2k = Emissions from natural gas
delivered to each large end user as calculated pursuant to subsection
(4)(b)(vi) of this section.
CO2n = Emissions from natural gas
received by the LDC directly from sources bypassing the city gate, and is not
otherwise accounted for, as calculated pursuant to subsection (4)(b)(v) of this
section.
(ix) The importer
of liquefied petroleum gas into Washington state must use calculation
methodology 2 described in
40 C.F.R. §
98.403(a)(2) for calculating
CO2 emissions. 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 C.F.R. Part 98. The importer of compressed natural gas or
liquefied natural gas into Washington state must estimate
CO2 using calculation methodology 1 as specified in
40 C.F.R. §
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.
(x) Operators of facilities that make
liquefied natural gas products or compressed natural gas products must estimate
CO2 using calculation methodology 1 as specified in
40 C.F.R. §
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 Washington state.
(xi) Operators of facilities that make
liquefied natural gas products or compressed natural gas products, importers of
liquefied petroleum gas, compressed natural gas, or liquefied natural gas into
Washington state, natural gas liquid fractionators, and local distribution
companies must estimate and report CH4 and
N2O emissions using
Equation C-8 and Table C-2 as described in
40 C.F.R. §
98.33(c)(1) for all fuels
where annual CO2 emissions are required to be reported.
Operators of facilities that make liquefied natural gas products or compressed
natural gas products must estimate CH4 and
N2O emissions based on the MMBtu of liquefied natural
gas sold or delivered. Local distribution companies must use the annual MMBtu
determined in (b)(ii) through (vi) of this subsection above in place of the
product of the fuel and HHV in Equation C-8 when calculating
emissions.
(xii) Local
distribution companies must separately and individually calculate end user
emissions of CH4, N2O,
CO2 from biomass-derived fuels, and
CO2e by replacing CO2 in Equation
122-2 with CH4, N2O,
CO2 from biomass-derived fuels, and
CO2e. CO2 emissions from
biomass-de-rived fuel are based on the fuel the LDC has contractually purchased
on behalf of and delivered to end users. LDCs can elect to report bio-methane
directly purchased by an end user and delivered by the LDC if the LDC can
provide the relevant documentation including invoices, shipping reports,
in-kind nomination reports, and contracts to demonstrate the receipt of
eligible biomethane and the following information for each contracted delivery:
(A) Name and address of the biomethane vendor
from which biome-thane is purchased;
(B) Annual MMBtu delivered by each biomethane
vendor;
(C) Name, address, and
facility type of the facility from which the biomethane is produced;
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
C.F.R. §
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 as stated above.
(xiii) All suppliers in this section must
also estimate CO2e emissions using Equation
A-1.
(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 C.F.R. §
98.404, except as modified in WAC
173-441-050,
173-441-120,
and below.
(i) All natural gas suppliers must
measure required values at least monthly.
(ii) 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.
(iii) All natural gas liquid fractionators
must sample for composition at least monthly.
(iv) All importers of liquefied petroleum gas
into Washington state 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.
(i) For the emissions calculation method
selected under (b) of this subsection, natural gas liquid fractionators must
report, in addition to the data required by
40 C.F.R. §
98.406(a), the annual volume
of liquefied petroleum gas, corrected to 60 degrees Fahrenheit, that was
produced on-site and sold or delivered to others, except for products for which
a final destination outside Washington state 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
C.F.R. Part 98 Table MM-1. Fractionators must also include the annual
CO2, CH4,
N2O, and CO2e mass emissions
(metric tons) from the volume of liquefied petroleum gas reported in
40 C.F.R. §
98.406(a)(5) as modified by
this regulation, calculated in accordance with (b) of this
subsection.
(ii) For the emissions
calculation method selected under (b) of this subsection, local distribution
companies must report all the data required by
40 C.F.R. §
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 C.F.R. §
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 C.F.R. §
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 C.F.R. §
98.406(b)(8), local
distribution companies must also include CO2,
CO2 from biomass-derived fuels,
CH4, N2O, and
CO2e annual mass emissions in metric tons calculated in
accordance with
40 C.F.R. §
98.403(a) and (b)(1) through
(b)(3) as modified by (b) of this
subsection.
(D) 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 C.F.R. §
98.406(b)(12). These
requirements are in addition to the requirements of
40 C.F.R. §
98.406(b)(6).
(E) Local distribution companies and
intrastate pipelines must also report the annual energy in MMBtu, customer
information required in
40 C.F.R. §
98.406(b)(12), and ecology
reporter ID if available, for all end users required to report under WAC
173-441-030(1).
In addition to reporting the information specified in
40 C.F.R. §
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 Washington state end users.
(F) Local distribution companies that report
under
40 C.F.R. §
98.406(b)(9) must report
annual CO2, CO2 from
biomass-derived fuel, CH4, N2O,
and CO2e emissions (metric tons) that would result from
the complete combustion or oxidation of the natural gas supplied to all
entities calculated in accordance with (b) of this
subsection.
(iii) In
addition to the information required in
40
C.F.R. §
98.3(c), the
operator of an interstate pipeline, which is not a local distribution company,
must report the customer name, address, and ecology reporter ID along with the
annual energy of natural gas in MMBtu for natural gas delivered to each
customer, including themselves.
(iv) In addition to the information required
in
40
C.F.R. §
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
C.F.R. Part 98 and this section for local distribution companies. The
intrastate pipeline operator must also report the summed energy (MMBtu) of
natural gas delivered to each entity receiving gas from the intrastate pipeline
for purposes of estimating the CO2i parameter as
specified in (b)(ii) of this subsection. Additionally, intrastate pipeline
operators are required to estimate a value for CO2j as
specified in (b)(iii) of this subsection for natural gas delivered to local
distribution companies, interstate pipelines, and other intrastate pipelines.
The CO2l parameter as specified in (b)(iv) of this
subsection must have a value of zero for calculating emissions.
(v) In addition to the information required
in
40
C.F.R. §
98.3(c), the
importer of liquefied petroleum gas into Washington state 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 C.F.R. Part 98 Table MM-1, if supplied by the producer, and report
CO2, CH4,
N2O, and CO2e annual mass
emissions in metric tons using the calculation methods in (b) of this
subsection. All importers of compressed or liquefied natural gas into
Washington state and liquefied natural gas production facilities must report
the annual quantities imported, and delivered or sold, respectively, in MMBtu,
and report CO2, CH4,
N2O, and CO2e annual mass
emissions in metric tons separately for compressed natural gas and liquefied
natural gas using the calculation methods in (b) of this subsection.
(vi) In addition to the information required
in
40
C.F.R. §
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 (b)(x) of this subsection.
(vii) All operators of facilities that make
liquefied natural gas products 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.
(viii) All natural gas liquid fractionators
and importers of liquefied petroleum gas must report the total quantity in
barrels of liquefied petroleum gas that is excluded from emissions reporting
due to demonstration of final destination outside Washington state.
(e)
Procedures for
estimating missing data. Suppliers must follow the missing data
procedures specified in
40 C.F.R. §
98.405. The operator must document and retain
records of the procedure used for all missing data estimates pursuant to the
recordkeeping requirements of WAC
173-441-050.
(5)
Fuel suppliers other than suppliers
of natural gas. Any supplier of petroleum products, biomass-derived
fuels, or coal-based liquid fuels with emissions calculated under this
subsection that exceeds the reporting threshold in WAC
173-441-030(2)
must comply with 40 C.F.R. Part 98 Subparts LL and MM in reporting emissions
and related data to ecology, except as otherwise provided in this section. Also
use the methods in this section for threshold calculations. For the purposes of
this subsection, fuel products do not include products reported under
subsection (4) of this section but do include all fuel products listed in 40
C.F.R. Part 98 Subpart MM Tables MM-1 and MM-2, including products listed in
Table MM-1 of Subpart MM that are coal-based (coal-to-liquid products).
Renewable or biogenic versions of fuel products listed in Table MM-1 are also
considered fuel products.
(a)
GHGs to
report.(i) In addition to the
CO2 emissions specified under
40 C.F.R. §
98.392, all refiners that produce liquefied
petroleum gas must report the CO2,
CO2 from biomass-derived fuels,
CH4, N2O and
CO2e emissions that would result from the complete
combustion or oxidation of the annual quantity of liquefied petroleum gas sold
or delivered, except for fuel products for which a final destination outside
Washington state can be demonstrated.
(ii) Refiners, position holders of fossil
fuel products, and bio-mass-derived fuel products that supply fuel products at
Washington state terminal racks, and enterers that import fuel products for
distribution outside the bulk transfer/terminal system must report the
CO2, CO2 from biomass-derived
fuels, CH4, N2O, and
CO2e emissions that would result from the complete
combustion or oxidation of each fuel product. However, emissions reporting is
not required for fuel products in which a final destination outside Washington
state can be demonstrated to ecology's satisfaction, or for fuel products that
can be demonstrated to ecology's satisfaction to have been previously delivered
by a position holder or refiner out of an upstream Washington state terminal or
refinery rack prior to delivery out of a second terminal rack. The volume of
all fuel products that are excluded from emissions reporting based on the
criteria in this paragraph must be reported pursuant to the requirements in
(d)(ix) of this subsection. No fuel product shall be reported as finished fuel.
Fuel products must be reported as the individual fuel product. For purposes of
this chapter, CARBOB blendstocks are reported as RBOB blendstocks.
(b)
Calculating GHG
emissions.(i) Refiners, position
holders at Washington state terminals, and enterers that import fuel products
for distribution outside the bulk transfer system must use Equation MM-1 as
specified in
40 C.F.R. §
98.393(a)(1) to estimate the
CO2 emissions that would result from the complete
combustion of the fuel product. Emissions must be based on the quantity of fuel
product removed from the rack (for refiners and position holders), fuel product
imported for distribution outside the bulk transfer/terminal system (by
enterers), and fuel product sold to unlicensed entities as specified in
(d)(iii) of this subsection (by refiners). For fuel products that are blended,
emissions must be reported for each individual fuel product separately, and not
as motor gasoline (finished), biofuel blends, or other similar finished fuel
product. Emissions from denatured fuel ethanol must be calculated as 100
percent ethanol only. The volume of denaturant is assumed to be zero and is not
required to be reported. Emission factors must be taken from column C of 40
C.F.R. Part 98 Table MM-1 or MM-2 as specified in Calculation Method 1 of
40 C.F.R. §
98.393(f)(1), except that
the emission factor for renewable diesel is equivalent to the emission factor
for Distillate No. 2. The emission factor for a renewable or biogenic version
of a fuel product is equivalent to the emission factor for the corresponding
nonrenewable or nonbiogenic version of the fuel product listed in Table MM-1.
If a position holder in diesel or biodiesel fuel does not have sealed or
financial transaction meters at the rack, and the position holder is the sole
position holder at the terminal, the position holder must calculate emissions
based on the delivering entity's invoiced volume of fuel product or a meter
that meets the requirements of
40 C.F.R. §
98.394 either at the rack or at a point prior
to the fuel product going into the terminal storage tanks.
(ii) Refiners that produce liquefied
petroleum gas must use Equation MM-1 as specified in
40 C.F.R. §
98.393(a)(1) to estimate the
CO2 emissions that would result from the complete
combustion of the fuel product supplied. For calculating the emissions from
liquefied petroleum gas, the emissions from the individual components must be
summed. Emission factors must be taken from column C of 40 C.F.R. Part 98 Table
MM-1 as specified in Calculation Method 1 of
40 C.F.R. §
98.393(f)(1).
(iii) Refiners, position holders at
Washington state terminals, and enterers identified in this section must
estimate and report CH4 and N2O
emissions using Equation C-8 and Table C-2 as described in
40 C.F.R. §
98.33(c)(1), except for fuel
products listed in Table 122-1, which must use the emission factors in Table
122-1 and Equation C-8 as described in
40 C.F.R. §
98.33(c)(1). Renewable or
biogenic versions of a fuel product must use the same emission factor as
required for the corresponding nonrenewable or nonbiogenic version of the fuel
product.
Table 122-1. Fuel Product CH4
and N2O Emission Factors
Fuel
|
CH4 (g/bbl)
|
N2O (g/bbl)
|
Blendstocks or finished gasoline
|
20
|
20
|
Distillate and diesel-other
|
2
|
1
|
Ethanol
|
37
|
27
|
Biodiesel and renewable diesel
|
2
|
1
|
Oxygenates
|
13
|
3
|
Residuum
|
18
|
4
|
Waxes
|
17
|
3
|
Still gas
|
19
|
4
|
Miscellaneous products
|
17
|
3
|
(iv)
All fuel suppliers in this section must estimate CO2e
emissions using Equation A-1.
(c)
Monitoring and QA/QC
requirements. The operator must meet all the monitoring and QA/QC
requirements as specified in
40 C.F.R. §
98.394, and the requirements of
40
C.F.R. §
98.3(i) as
further specified in WAC
173-441-050
and below.
(i) Position holders are exempt
from
40
C.F.R. §
98.3(i)
calibration requirements except when the position holder and entity receiving
the fuel product have common ownership or are owned by subsidiaries or
affiliates of the same company. In such cases the
40
C.F.R. §
98.3(i)
calibration requirements apply, unless:
(A)
The fuel supplier does not operate the fuel billing meter;
(B) The fuel billing meter is also used by
companies that do not share common ownership with the fuel supplier;
or
(C) The fuel billing meter is
sealed with a valid seal from the county sealer of weights and measures and the
operator has no reason to suspect inaccuracies.
(ii) As required by
40 C.F.R. §
98.394(a)(1)(iii), for fuel
products that are liquid at 60 degrees Fahrenheit and one standard atmosphere,
the volume reported must be temperature- and pressure-adjusted to these
conditions. For liquefied petroleum gas the volume reported must be
temperature-adjusted to 60 degrees Fahrenheit.
(d)
Data reporting
requirements. In addition to reporting the information required in 40
C.F.R. Part 98 Subpart MM, the following entities must also report the
information identified below:
(i) Washington
state position holders must report the annual quantity in barrels, as reported
by the terminal operator, of each fuel product, that is delivered across the
rack in Washington state, except for fuel products for which a final
destination outside Washington state can be demonstrated to ecology's
satisfaction, or for fuel products that can be demonstrated to ecology's
satisfaction to have been previously delivered by a position holder or refiner
out of an upstream Washington state terminal or refinery rack prior to delivery
out of a second terminal rack. Denatured fuel ethanol will be reported with the
entire volume as 100 percent ethanol only. The volume of denaturant is assumed
to be zero and is not required to be reported.
(ii) Washington state position holders that
are also terminal operators and refiners must report the annual quantity in
barrels delivered across the rack of each fuel product, except for fuel
products for which a final destination outside Washington state can be
demonstrated to ecology's satisfaction, or for fuel products that can be
demonstrated to ecology's satisfaction to have been previously delivered by a
position holder or refiner out of an upstream Washington state terminal or
refinery rack prior to delivery out of a second terminal rack. Denatured fuel
ethanol will be reported with the entire volume as 100 percent ethanol only.
The volume of denaturant is assumed to be zero and is not required to be
reported. If there is only a single position holder at the terminal, and only
diesel or biodiesel is being dispensed at the rack then the position holder
must report the annual quantity of fuel using a meter meeting the requirements
of
40 C.F.R. §
98.394 or billing invoices from the entity
delivering fuel to the terminal.
(iii) Refiners that supply fuel products
within the bulk transfer system to entities not licensed by the Washington
state department of licensing as a fuel supplier must report the annual
quantity in barrels delivered of each fuel product, except for fuel products
for which a final destination outside Washington state can be demonstrated to
ecology's satisfaction. Denatured fuel ethanol will be reported with the entire
volume as 100 percent ethanol only. The volume of de-naturant is assumed to be
zero and is not required to be reported.
(iv) Enterers delivering fuel products for
distribution outside the bulk transfer/terminal system must report the annual
quantity in barrels, as reported on the bill of lading or other shipping
documents of each fuel product that is imported as a blended component of a
finished fuel product, except for fuel products for which a final destination
outside Washington state can be demonstrated to ecology's satisfaction,
typically based on bills of lading. The denatured fuel ethanol component of a
finished fuel products must be reported with the entire denatured ethanol
volume as 100 percent ethanol only. The volume of denaturant is assumed to be
zero and is not required to be reported. Biomass-derived blends containing no
more than one percent petroleum-derived fuel by volume are considered to be 100
percent bio-mass-derived fuel. Individual biomass-derived fuels and
biomass-de-rived fuels that are a blended component of an imported fuel product
must be reported by enterers.
(v)
In addition to the information required in
40 C.F.R. §
98.396, refiners must also report the volume
of liquefied petroleum gas in barrels supplied in Washington state as well as
the volumes of the individual components as listed in 40 C.F.R. Part 98 Table
MM-1, except for fuel for which a final destination outside Washington state
can be demonstrated.
(vi) All fuel
suppliers identified in this section must also report
CO2, CO2 from biomass-derived
fuels, CH4, N2O, and
CO2e emissions in metric tons that would result from the
complete combustion or oxidation of each fuel product calculated according to
Equation A-1.
(vii) All fuel
suppliers identified in this section, except for refiners that report pursuant
to WAC
173-441-120,
must report the total quantity of each fuel product that was imported from
outside of Washington state for use in Washington state. In addition, for fuel
product imports, the designated percentage of oxygenate must be
reported.
(viii) Fuel suppliers
identified in this section, except for refiners that report pursuant to WAC
173-441-120,
must report the total quantity of biomass-derived fuel blended in Washington
state petroleum-derived fuel for use in Washington state.
(ix) Fuel suppliers identified in this
section must report the total quantity in barrels of each fuel product that is
excluded from emissions reporting due to demonstration of final destination
outside Washington state, or demonstration to ecology's satisfaction, typically
based on bills of lading, that the fuel product was previously delivered by a
position holder or refiner out of an upstream Washington state terminal or
refinery rack prior to delivery out of a second terminal rack.
(x) Owners and operators of petroleum
refineries and biofuel production facilities required to report or voluntarily
reporting under WAC
173-441-030(1) or
(5) must submit a complete refiner report, as
defined in 40 C.F.R. Part 98 Subpart MM, that includes all products listed in
Tables MM-1 and MM-2, as part of their facility GHG report under WAC
173-441-070(1)
regardless of the amount of fuel products produced.
(xi) Owners and operators may separately
indicate the quantity of each fuel type if the fuel supplier can demonstrate to
ecology's satisfaction that the fuel is used for one of the following purposes:
(A) Aviation fuels;
(B) Watercraft fuels that are combusted
outside of Washington state; or
(C)
Motor vehicle fuel or special fuel that is used exclusively for agricultural
purposes by a farm fuel user. The supplier must demonstrate to ecology's
satisfaction that the buyer of the fuel provided the seller with an exemption
certificate as described in
RCW
82.08.865. Fuel used for the purpose of
transporting agricultural products on public highways may be included if it is
flagged separately and meets the requirements in
RCW
82.08.865. For the purposes of (d)(xi) of
this subsection, "agricultural purposes" and "farm fuel user" have the same
meanings as provided in
RCW
82.08.865 and motor vehicle fuel and special
fuel have the same meanings as provided in
RCW
82.38.020.
(e)
Procedures for missing
data. For quantities of fuel products that are purchased, sold, or
transferred in any manner, fuel suppliers must follow the missing data
procedures specified in
40 C.F.R. §
98.395. The supplier must document and retain
records of the procedure used for all missing data estimates pursuant to the
recordkeeping requirements of WAC
173-441-050.