Current through Register 2024 Notice Reg. No. 38, September 20, 2024
The facilities, suppliers, and entities specified in
section 95101 must monitor emissions and
submit emissions data reports to the Air Resources Board following the
requirements specified in 40
CFR §
98.3 and §
98.4, except as otherwise provided
in this part.
(a)
Abbreviated
Reporting for Facilities with Emissions Below 25,000 Metric Tons of
CO2e. A facility operator may submit an abbreviated
emissions data report under this article if all of the following conditions
have been met: the facility operator does not have a compliance obligation
under the cap-and-trade regulation during any year of the current compliance
period; the operator is not subject to the reporting requirements of 40 CFR
Part 98 specified in this article; and the facility total stationary
combustion, process, fugitives and venting emissions are below 25,000 metric
tons of CO2e in the data year. This provision does not
apply to suppliers or electric power entities. Abbreviated reports must include
the information in paragraphs (1)-(7) below, and comply with the requirements
specified in paragraphs (8)-(11) below:
(1)
Facility name, assigned ARB identification number, physical street address
including the city, state and zip code, air basin, air district, county,
geographic location, natural gas supplier name, natural gas supplier customer
identification number, natural gas supplier service account identification
number or other primary account identifier, and annual billed MMBtu (10 therms
= 1 MMBtu).
(2) Facility GHG
stationary combustion emissions for all stationary fuel combustion units and
calculated according to any method in
40 CFR §
98.33(a), expressed in
metric tons of total CO2, CO2
from biomass-derived fuels, CH4, and
N2O. Using any applicable method in
40 CFR §
98.33 or
95153 (l),
reporting entities identified under section
95101(e) for
petroleum and natural gas systems must also quantify and report emissions of
CO2, CO2 from biomass-derived
fuels, CH4, and N2O resulting
from flaring activities. If a facility includes multiple stationary fuel
combustion units that belong to more than one unit type category listed in
section 95115(h), the
operator may report the multiple units in aggregate but must indicate the
percentage of the aggregated fuel consumption attributed to each unit type
category. In addition, if a facility includes an electricity generating unit,
the facility operator must report the electricity generating unit separate from
other stationary fuel combustion sources by following the unit aggregation
provisions in sections
95112(b) and
95103(a)(6). The
operator has the option of using engineering estimation or any combination of
existing meters to meet the requirements of this paragraph.
(3) Total facility GHG process emissions
aggregated for all process emissions sources and calculated according to the
requirements in the following parts, expressed in metric tons of total
CO2, CO2 from biomass-derived
fuels, CH4, and N2O, as
applicable:
(A)
40 CFR §
98.143 for glass production;
(B)
40 CFR §
98.163 for hydrogen production;
(C)
40 CFR §
98.173 for iron and steel
production;
(D)
40 CFR §
98.273 for pulp and paper
manufacturing;
(E) Subarticle 5 of
this article for petroleum and natural gas systems.
(4) Identification of the methods chosen for
determining emissions.
(5) Any
facility operating data or process information used for the GHG emission
calculations, including fuel use by fuel type, reported in million standard
cubic feet for gaseous fuels, gallons for liquid fuels, short tons for solid
fuels, and bone-dry short tons for biomass-derived solid fuels. If applicable,
include high heat values and carbon content values used to calculate emissions.
Missing fuel use or fuel characteristics data must be substituted according to
the requirements of 40 CFR
§
98.35.
(6) For facilities with on-site electricity
generation or cogeneration, the applicable information specified in section
95112(a)-(b) of
this article. Geothermal facilities must also report the information specified
in section
95112(e).
Operators of hydrogen fuel cells must report the information specified in
section 95112(f).
(7) A signed and dated certification
statement provided by the designated representative of the owner or operator,
according to the requirements of
40 CFR §
98.4(e)(1).
(8) Abbreviated emissions data reports
submitted under this provision must be certified as complete and accurate no
later than June 1 of each calendar year.
(9) Subsequent revisions according to the
requirements of 40 CFR
§
98.3(h) must be
submitted if an error is discovered after the submission of the emissions data
report. If the error correction would cause the emissions total to exceed
25,000 metric tons of CO2e, a report that meets the full
requirements of this article must be submitted within ninety days of
discovery.
(10) For abbreviated
reports submitted under this provision, records must be kept according to the
requirements of 40 CFR
§
98.3(g), except that
a written GHG Monitoring Plan is not required.
(11) An abbreviated emissions data report is
not subject to the third-party verification requirements of this
article.
(e)
Reporting Deadlines. Except as provided in section
95103(a)(7)-(8),
each facility operator or supplier must submit an emissions data report no
later than April 10 of each calendar year. Each electric power entity must
submit an emissions data report no later than June 1 of each calendar
year.
(f)
Verification
Requirement and Deadlines. The requirements of this paragraph apply to
each reporting entity submitting an emissions data report that indicates
emissions equaled or exceeded 25,000 metric tons of
CO2e, including CO2 from
biomass-derived fuels and geothermal sources, electric power entities that are
electricity importers or exporters, facilities with sources as identified in
section 95101(b)(3), or
each reporting entity that has or has had a compliance obligation under the
cap-and-trade regulation in any year of the current compliance period. The
requirements of this paragraph apply to reporting entities that have not met
the requirements for cessation of verification in section
95101(i). The
reporting entity subject to verification must obtain third-party verification
services for that report from a verification body that meets the requirements
specified in Subarticle 4 of this article. Such services must be completed and
separate verification statements for emissions data and for product data, as
applicable, must be submitted by the verification body to the Executive Officer
by August 10 each year. Each reporting entity must ensure that these
verification statements are submitted by this deadline. Contracting with a
verification body without providing sufficient time to complete the
verification statements by the applicable deadline will not excuse the
reporting entity from this responsibility. These requirements are additional to
the requirements in 40 CFR
§
98.3(f).
(g)
Non-submitted/Non-verified
Emissions Data Reports. When a reporting entity that holds a
compliance obligation under the cap-and-trade regulation fails to submit an
emissions data report or fails to obtain a positive emissions data verification
statement or qualified positive emissions data verification statement by the
applicable deadline, the Executive Officer shall develop an assigned emissions
level for the reporting entity as set forth in section
95131(c)(5)(A)-(C).
(h)
Reporting in 2018. All
provisions of the regulation are in full effect for 2019 data reporting in 2020
and beyond, except the following:
(1) The
requirements of 95101(h) and (i) are effective for 2018 data reported in
2019.
(2) The method in section
95153(a) for
continuous bleed pneumatic devices applies to 2019 data reported in
2020.
(3) The provisions of
Subarticle 6 of this article become effective for 2021 data submitted in 2022,
if U.S. EPA has approved, as memorialized by publication in the Federal
Register and Code of Federal Regulations, that provision as part of
California's plan for compliance with the Clean Power Plan.
(i)
Calculation and Reporting of De
Minimis Emissions. A facility operator may designate as de
minimis a portion of GHG emissions representing no more than 3 percent
of a facility's total CO2 equivalent emissions
(including emissions from biomass-derived fuels and feedstocks), not to exceed
20,000 metric tons of CO2e. The operator or supplier may
estimate de minimis emissions using alternative methods of the
operator's choosing, subject to the concurrence of the verification body that
the methods used are reasonable, not biased toward significant underestimation
or overestimation of emissions, and unlikely to exceed the de
minimis limits. The operator must separately identify and include in
the emissions data report the emissions from designated de
minimis sources. The operator must determine
CO2 equivalence according to the global warming
potentials as specified in the "global warming potential" definition of this
article.
(j)
Calculating,
Reporting, and Verifying Emissions from Biomass-Derived Fuels. The
operator or supplier must separately identify and report all biomass-derived
fuels as described in section
95852.2(a) of the
cap-and-trade regulation. Except for operators that use the methods of
40 CFR §
98.33(a)(2)(iii) or §
98.33(a)(4), the
operator or supplier must separately identify, calculate, and report all direct
emissions of CO2 resulting from the combustion of
biomass-derived fuels as specified in sections
95112 and
95115 for facilities, and sections
95121 and
95122 for suppliers. A
biomass-derived fuel not listed in section
95852.2(a) of the
cap-and-trade regulation must be identified as non-exempt biomass-derived fuel.
For a fuel listed under section
95852.2 of the cap-and-trade
regulation, reporting entities must also meet the verification requirements in
section 95131(i) of this
article and the requirements of section
95852.1.1 of the cap-and-trade
regulation, or the fuel must be identified as non-exempt biomass-derived fuel.
Carbon dioxide combustion emissions from non-exempt biomass-derived fuel will
be identified as non-exempt biomass-derived CO2. The
responsibility for obtaining verification of a biomass-derived fuel falls on
the entity that is claiming there is not a compliance obligation for the fuel,
as indicated in section
95852.2 of the cap-and-trade
regulation.
(1) When reporting solid waste,
the reporting entity must separately report the mass, in short tons, of urban
waste, agricultural waste, and municipal solid waste.
(2) When reporting the use of forest derived
wood and wood waste as identified in section
95852.2(a)(4) of
the cap-and-trade regulation and harvested pursuant to any section of the
California Forest Practice Rules Title 14, California Code of Regulations,
Chapters 4, 4.5 and 10 of the Federal National Environmental Policy Act, the
reporting entity must report: the bone-dry mass received; information about the
supplier, including the name, physical address, mailing address, contact person
with phone number and e-mail address; and the corresponding identification
number under which the wood was removed.
(3) When reporting biomethane, the operator
or supplier who is reporting biomass emissions from biomethane fuel must also
report the following information for each contracted delivery:
(A) Name and address of the biomethane vendor
from which biomethane is purchased;
(B) Annual MMBtu delivered by each biomethane
vendor.
The operator must also report the name, address, and
facility type of the facility from which the biomethane is produced. In
addition, relevant documentation including invoices, shipping reports,
allocation and balancing reports, storage reports, in-kind nomination reports,
and contracts must be made available for verifier or ARB review to demonstrate
the receipt of eligible biomethane.
(4) Reporting of fuel consumption from
non-exempt biomass-derived fuel is subject to the requirements of section
95103(k) and
reporting of emissions from non-exempt biomass-derived fuels is subject to the
requirements of sections
95110 to
95158.
(k)
Measurement Accuracy
Requirement. The operator or supplier subject to the requirements of
40 CFR §
98.3(i) must meet those
requirements for data used for calculating non-covered emissions and
non-covered product data, except as otherwise specified in this paragraph. In
addition, the following accuracy requirements apply to data used for
calculating covered emissions and covered product data. The operator or
supplier with covered product data or covered emissions equal to or exceeding
25,000 metric tons of CO2e or a compliance obligation
under the cap-and-trade regulation in any year of the current compliance period
must meet the requirements of paragraphs (k)(1)-(10) below for calibration and
measurement device accuracy. Inventory measurement, stock measurement, or tank
drop measurement methods are subject to paragraph (11) below. The requirements
of paragraphs (k)(1)-(11) apply to fuel consumption monitoring devices,
feedstock consumption monitoring devices, process stream flow monitoring
devices, steam flow devices, product data measuring devices, mass and fluid
flow meters, weigh scales, conveyer scales, gas chromatographs, mass
spectrometers, calorimeters, and devices for determining density, specific
gravity, and molecular weight. The provisions of paragraph (k)(1)-(11) do not
apply to: stationary fuel combustion units that use the methods in
40 CFR §
98.33(a)(4) to calculate
CO2 mass emissions; emissions reported as de
minimis under section
95103(i); and
devices that are solely used to measure parameters used to calculate emissions
that are not covered emissions or that are not covered product data. The
provisions of paragraphs (k)(1)-(9) and (k)(11) do not apply to stationary fuel
combustion units that use the methods in 40 CFR Part 75 Appendix G §2.3 to calculate
CO2 mass emissions, but the provisions in paragraph
(k)(10) are applicable to such units.
(1)
Except as otherwise provided in sections
95103(k)(7) through
(9), all flow meter and other measurement
devices used to provide data for the GHG emissions calculations or covered
product data must be calibrated prior to the year data collection is required
to begin using the procedures specified in this section, and subsequently
recalibrated according to the frequency specified in paragraph (4). Flow meters
and other measurement devices that were calibrated prior to January 1, 2012
using procedures specified in previous versions of the Mandatory Reporting
Regulation or methods specified in 40 CFR Part 98 must be subsequently
recalibrated according to the frequency specified in paragraph (4). A flow
meter device consists of a number of individual components which might include
a flow constriction component, mechanical component, and temperature and
pressure measurement components. Each meter or measurement device must meet the
applicable accuracy specification in section
95103(k)(6),
however each individual component of a flow meter device is not required to
meet the accuracy specifications. The procedures and methods used to
quality-assure the data from each measurement device must be documented in the
written monitoring plan required by section
95105(c).
(2) All flow meters and other measurement
devices that provide data used to calculate GHG emissions or product data must
be calibrated according to either the manufacturer's recommended procedures or
a method specified in an applicable subpart of 40 CFR Part 98. The calibration
method(s) used must be documented in the monitoring plan required under section
95105(c), and are
subject to verification under this article and review by ARB to ensure that
measurements used to calculate GHG emissions or product data have met the
accuracy requirements of this section.
(3) For facilities and suppliers that become
subject to this article after January 1, 2012, all flow meters and other
measurement devices that provide data used to calculate GHG emissions or
product data must be installed and calibrated no later than the date on which
data collection is required to begin under this article.
(4) Except as otherwise provided in sections
95103(k)(7) through
(9), subsequent recalibrations of the flow
meter and other measurement devices subject to the requirements of this section
must be performed no less frequently than at one of the following time
intervals, whichever is shortest:
(A) The
frequency specified in a subpart of 40 CFR Part 98 that is applicable under
this article.
(B) The frequency
recommended by the manufacturer.
(C) Once every 36 months.
(D) Immediately upon replacement of a
previously calibrated meter.
(E)
Immediately upon replacement or repair of a device that is deemed out of
calibration as determined in paragraph (6).
(F) If the device manufacturer explicitly
states in the product documentation that calibration is required at a period
exceeding three years, the operator may follow the procedures in paragraph (9)
to obtain Executive Officer approval to relieve the operator from having to
comply with provisions (A) and (C) of this subparagraph.
(5) All standards used for calibration must
be traceable to the National Institute of Standards and Technology or other
similar national government body responsible for measurement
standards.
(6) In addition to the
specific calibration requirements specified below, and, if applicable, the
field accuracy assessment requirements specified below, all flow meter and
other measurement devices covered by this section, regardless of type, must be
selected, installed, operated, and maintained in a manner to ensure accuracy
within +5 percent.
(A) Perform all mass and
volume measurement device calibration as specified in the original equipment
manufacturer's (OEM) documentation. If OEM documentation is unavailable,
calibrate as specified in 40
CFR §
98.3(i)(2)-(3),
except that a minimum of three calibration points must be used spanning the
normal operating conditions. When using the three calibration points, one point
must be at or near the zero point, one point must be at or near the upscale
point, and one point at or near the mid-point of the devices operating range.
If OEM documentation does not specify a method or is unavailable, and
calibration methods specified in
40 CFR §
98.3(i)(2)-(3) are not
possible for a particular device, the procedures in section
95109(b) must be
followed to obtain approval for an alternative calibration procedure.
Additionally:
1. Pressure differential
devices must be inspected at a frequency specified in paragraph (k)(4) of this
section, unless the device is located at a refinery or hydrogen plant that
operates continuously with infrequent outages. In such cases, the owner or
operator of the refinery or hydrogen plant must inspect each device at a
frequency of at least once every six years. The inspection must be conducted as
described in the appropriate part of ISO 5167-2 (2003), or AGA Report No 3
(2003) Part 2, both of which are incorporated by reference, or a method
published by an organization listed in
40 CFR §
98.7 applicable to the analysis being
conducted. If the device fails any one of the tests then the meter shall be
deemed out of calibration. If OEM guidance for a particular pressure
differential device recommends against disassembly and inspection of the
device, disassembly and inspection requirements in this paragraph do not apply.
Documentation of OEM guidance must be made available to verifiers and ARB upon
request.
a. Records of all tests, including an
as-found condition, must be preserved pursuant to section
95105 and made available to
verifiers and ARB upon request.
b.
Where inspection requirements apply, the primary element must also be
photographed on both sides prior to any treatment or cleanup of the element to
clearly show the condition of the element as it existed in the
pipe.
2. Devices used to
measure total pressure and temperature must be calibrated using methods
specified in section
95103(k)(2) and
at a frequency specified in section
95103(k)(4).
3. If temperature and/or total pressure
measurements are not available or are taken at a remote location, the
uncertainty caused by this must be factored into the evaluation of the overall
measurement accuracy required under section
95103(k)(6).
(B) Operators and suppliers may conduct an
annual field accuracy assessment of mass and volume measurement devices to test
for field accuracy in years between successive calibrations to ensure the
device is maintaining measurement accuracy within +5 percent. When performing a
field accuracy assessment, the as-found condition must be recorded to ensure
the device is measuring with accuracy within +5 percent. Should a device be
found to be operating outside the +5 percent accuracy bounds, the device shall
be deemed out of calibration. Records of all field accuracy assessments must
clearly indicate the assessment procedure and the as-found condition, be
preserved pursuant to section
95105, and be made available to
verifiers and ARB upon request. Device accuracy may be assessed using one of
the following options:
1. Engineering
analysis;
2. OEM calibration
guidance or other OEM recommended methods;
3. Standard industry practices; or
4. Portable instruments.
(C) Pursuant to paragraph (k)(10) of this
section, in the event of a failed calibration or recalibration, operators or
suppliers who choose not to perform the annual field accuracy assessment
specified in paragraph (6)(B) of this section for one or more mass or volume
measurement devices must demonstrate data accuracy going back multiple years to
the most recent successful calibration. Multiple years of data may be deemed
invalid if accuracy cannot be demonstrated by other means, including strap-on
meters or engineering methods. For operators and suppliers who conduct the
annual field accuracy assessment, and a device is found to be out of
calibration, accuracy must be demonstrated back to the most recent successful
calibration or the most recent successful field accuracy assessment, whichever
is most recent.
(7) The
requirements of section
95103(k) do not
apply under the following circumstances:
(A)
Financial transaction meters are exempted from the calibration requirements of
section 95103(k) if the
supplier and purchaser do not have any common owners and are not owned by
subsidiaries or affiliates of the same company. Financial transaction meters
where the supplier and the purchaser do have common owners or are owned by
subsidiaries or affiliates of the same company are exempt from the calibration
requirements of section
95103(k) if one
of the following is true:
1. The financial
transaction meter is also used by other companies that do not share common
ownership with the fuel supplier; or
2. The financial transaction meter is sealed
with a valid seal from the county sealer of weights and measures or from a
county certified designee; or
3.
The financial transaction meter is operated by a third
party.
(B) Upstream
ethanol and additive meters used to ensure proper blendstock percentage for
finished gasoline are exempted from the calibration requirements of section
95103(k).
(C) Non-financial transaction meters used by
Public Utility Gas Corporations for purposes of reporting natural gas supplier
emissions are exempt from the calibration requirements in sections
95103(k)(1)-(6)
if the supplier can demonstrate that the meters are operated and maintained in
conformance with a standard that meets the measurement accuracy requirements of
the California Public Utilities Commission General Order 58A
(1992).
(8) For units and
processes that operate continuously with infrequent outages, it may not be
possible to meet deadlines for the initial or subsequent calibrations of a flow
meter or other fuel measurement or sampling device, or inspection of orifice
plates without disrupting normal process operation. In such cases, the owner or
operator may submit a written request to the Executive Officer to postpone
calibration or inspection until the next scheduled maintenance outage. Such
postponements are subject to the procedures of section
95103(k)(9) and
must be documented in the monitoring plan that is required under section
95105(c).
(9) In cases of continuously operating units
and processes where calibration or inspection is not possible without
operational disruption, the operator must demonstrate by other means to the
satisfaction of the Executive Officer that measurements used to calculate GHG
emissions and product data still meet the accuracy requirements of section
95103(k)(6). The
Executive Officer must approve any postponement of calibration or required
recalibration beyond January 1, 2012.
(A) A
written request for postponement must be submitted to the Executive Officer not
less than 30 days before the required calibration, recalibration or inspection
date. The Executive Officer may request additional documentation to validate
the operator's claim that the device meets the accuracy requirements of this
section. The operator shall provide any additional documentation to ARB within
ten (10) working days of a request by ARB.
(B) The request must include:
1. The date of the required calibration,
recalibration, or inspection;
2.
The date of the last calibration or inspection;
3. The date of the most recent field accuracy
assessment, if applicable;
4. The
results of the most recent field accuracy assessment, if applicable, clearly
indicating a pass/fail status;
5.
The proposed date for the next field accuracy assessment, if
applicable;
6. The proposed date
for calibration, recalibration, or inspection which must be during the time
period of the next scheduled shutdown. If the next shutdown will not occur
within three years, this must be noted and a new request must be received every
three years until the shutdown occurs and the calibration, recalibration or
inspection is completed.
7. A
description of the meter or other device, including at a minimum:
a. make,
b. model,
c. install date,
d. location,
e. annual emissions calculated or annual
product data reported using data from the device,
f. sources for which the device is used to
calculate emissions or product data,
g. calibration or inspection
procedure,
h. reason for delaying
calibration or inspection,
i.
proposed method to assure the accuracy requirements of section
95103(k)(6) are
met,
j. name, title, phone number
and e-mail of contact person capable of responding to questions regarding the
device.
(10) If the results of an initial
calibration, recalibration, or field accuracy assessment fail to meet the
required accuracy specification, and the emissions or product data estimated
using the data provided by the device represent more than 5 percent of total
facility emissions or product data on an annual basis, the operator must
demonstrate by other means to the satisfaction of the verifier or ARB that
measurements used to calculate GHG emissions and product data still meet the +5
percent accuracy requirements going back to the last instance of successful
field accuracy assessment or calibration of the device. Where the results of an
initial calibration, recalibration, or field accuracy assessment fail to meet
the accuracy specifications, the verifier shall note at a minimum a
nonconformance as part of the emissions data verification statement.
(11) When using an inventory measurement,
stock measurement, or tank drop measurement method to calculate volumes and
masses, the method must be accurate to +5 percent for the time periods required
by this article, including annually for covered product data. Techniques used
to quantify amounts stored at the beginning and end of these time periods are
not subject to the calibration requirements of this section. Uncertainties in
beginning and end amounts are subject to verifier review for material
misstatement under section
95131(b)(12) of
this article. If any devices used to measure inputs and outputs do not meet the
requirements of paragraphs (1)-(10) above, the verifier must account for this
uncertainty when evaluating material misstatements. Reported values must be
calculated using the following equations:
Fuel consumed (volume or mass) = (inputs during
time period - outputs during time period) + (amount stored at beginning of time
period) - (amount stored at end of time period)
Product produced (volume or mass) = (outputs
during time period - inputs during time period) + (amount stored at end of time
period - amount stored at beginning of time
period)
(l)
Reporting and Verifying Product
Data. The reporting entity must separately identify, quantify, and
report all product data as specified in sections
95110-95124 and
95156 of this article. It is the
responsibility of the reporting entity to obtain verification services for the
product data. Product data will be evaluated for conformance and material
misstatement independent of GHG emissions data. Covered product data is
evaluated for material misstatement and conformance, while the remaining
reported product data is evaluated for conformance only. Reporting entities
must exclude inaccurate covered product data, and may elect to exclude accurate
covered product data. Reporting entities that exclude covered product data must
report a description of the excluded data and an estimated magnitude using best
available methods. The excluded covered product data will not be used for the
material misstatement assessment or for the total covered product data variable
described in section
95131(b)(12)(A).
Operators of cement plants may not exclude covered product data.
(m)
Changes in Methodology.
Except as specified below, where this article permits a choice between
different methods for the monitoring and calculation of GHGs and product data,
the operator must use the method chosen for all future emissions data reports,
except as provided pursuant to sections
95103(m)(1) and
(2).
(1)
Changes in Prescribed Methods.
(A) Permanent
Improvement in Monitoring or Calculation Methodology for Emissions Data. The
operator or supplier is permitted to permanently improve the emissions or
product data monitoring or calculation method to a higher-tier monitoring or
calculation method specified in this article, such as the addition of a
continuous emissions monitoring system. Permanent improvements to emissions
monitoring or calculation methods do not require approval in advance by the
Executive Officer; however, the operator or supplier must notify ARB by the
reporting deadline for the applicable reporting year.
(B) Permanent Change to a Lower-Tier
Methodology for Emissions Data. The operator or supplier is permitted to submit
a request for approval of a permanent change to a lower-tier monitoring or
calculation method specified in this article for emissions data. The request
must be provided to ARB prior to January 1 of the year for which the data will
be reported, and must be approved by the Executive Officer and implemented per
the timing requirements in sections
95103(m)(2)-(3).
The request must include a description of why the change in method is being
proposed, a detailed description of the data that are affected by the method
change, and a demonstration of differences in estimated data under the current
and proposed methods.
(C) Permanent
changes to all covered product data monitoring or calculation methods must be
submitted to ARB pursuant to section
95103(m)(2),
except in the circumstances described in section
95103(m)(4).
(2) Alternative Methods. If an operator or
supplier identifies a situation where conventional metering or methods are not
feasible, the operator may submit a request to the Executive Officer for
approval of an alternative measurement/monitoring method that achieves accuracy
at an equivalent level to the +5 percent required by section
95103(k)(6). The
request must include a description of why the change in method is being
proposed, include a detailed description of the data that are affected by the
alternative measurement/monitoring method, and include a demonstration of
differences in estimated data under the current and proposed methods. ARB will
make an approval determination based on the necessity of the alternative method
and whether the operator or supplier can sufficiently demonstrate accuracy of
the method during verification. The alternative method request must be provided
to ARB prior to January 1 of the year for which the new method would be
implemented for data collection, and must be approved by the Executive Officer.
If ARB approves the alternative method, and upon request by the reporting
entity, ARB may also determine whether the methodology can be applied to the
current data year based on the information submitted pursuant to this section.
In order to apply the method to the current data year, the reporting entity
must show that they have collected the necessary data to apply the method for
the entire current reporting year.
(3) When permitted under sections
95103(m)(1) and
(2), a change in the calculation or
monitoring method must be made for an entire data year and apply to the start
of a data year, except in the circumstances described in section
95103(m)(4).
(4) Use of a Temporary Methodology. The
operator or supplier is permitted to temporarily modify the emissions or
product data monitoring or calculation method when necessary for the avoidance
of missing data or to comply with the missing data provisions of this article.
For emissions data, in the event of an unforeseen breakdown in fuel analytical
data monitoring equipment or CEMS equipment, operators and suppliers must use
the procedures in section
95129(h) and
section 95129(i),
respectively, for seeking approval of interim data collection procedures. For
all other instances that temporary methods are used, ARB must be notified by
the reporting deadline of the following information: a description of the
temporary method, the affected data, and the duration that the temporary method
was used. A temporary method may be used for a period not to exceed 365 days
unless the method is concurrently or subsequently submitted and approved by the
Executive Officer as a permanent method per the requirements in section
95103(m)(1)(B) or
(2). Operators and suppliers must be able to
demonstrate during verification that the temporary method provides data
accuracy within +5 percent as specified in section
95103(k)(6).
Covered product data that does not meet the required accuracy specification
must be excluded using the procedure in section
95103 (l) to
avoid an adverse verification statement.
(5) When regulatory changes impose new or
revised reporting requirements or calculation methods on an operator or
supplier, the monitoring and calculation method must be in place on January 1
of the year in which data is first required to be collected pursuant to the
reporting requirements.
(n)
Changes in Ownership or
Operational Control. If a reporting entity undergoes a change of
ownership or operational control, the following requirements apply regarding
notifications to ARB and reporting responsibilities.
(1)
ARB Notifications. Prior
to the change of ownership or operational control, the previous owner or
operator of the reporting entity and the new owner or operator of the reporting
entity must provide the following information to ARB. Required information must
be submitted to the ARB email account: ghgreport@arb.ca.gov
(A) The previous owner or operator must
notify ARB via email of the ownership or operational control change including
the name of the new owner or operator and the date of the ownership or
operational control change.
(B) The
new owner or operator must notify ARB via email of the ownership or operational
control change, including the following information:
1. Previous owner or operator;
2. New owner or operator;
3. Date of ownership or operator
change.
4. Name of a new Designated
Representative pursuant to section
95104(b) for the
affected entity's account in the California Reporting Greenhouse Gas Reporting
Tool (Cal e-GGRT) specified in section
95104(e);
(2)
Reporting
Responsibilities. Except as specified in section
95103(n)(2)(D),
the owner or operator of record at the time of a reporting or verification
deadline specified in this article has the responsibility for complying with
the requirements of this article, including certifying that the emissions data
report is accurate and complete, obtaining verification services, and
completing verification.
(A) Except as
specified in section
95103(n)(2)(D),
the owner or operator of record at the time of a reporting deadline is
responsible for submitting the emissions data report covering the complete
calendar year data.
(B) Except as
specified in section
95103(n)(2)(D),
if an ownership change takes place during the calendar year, reported data must
not be split or subdivided for the year, based on ownership. A single annual
data report must be submitted for the entity by the current owner or operator.
This report must represent required data for the entire, calendar
year.
(C) Previous owners or
operators are required to provide data and records to new owners or operators
that is necessary and required for preparing annual emissions data reports
required by this article.
(D) Fuel
suppliers that cease to have reportable emissions as a result of an ownership
change that affects supplier operations retain the responsibility for complying
with the requirements of this article, including certifying that the emissions
data report is accurate and complete, obtaining verification services, and
completing verification, for the emissions from all fuel transactions that
occurred prior to the date of the change of
ownership.
(o)
Addresses. The following address shall be substituted for the
addresses provided in 40 CFR
§
98.9, and used for any necessary
notifications or materials that are not submitted by other means:
MANAGER, CLIMATE CHANGE REPORTING SECTION
PROGRAM PLANNING AND MANAGEMENT BRANCH
INDUSTRIAL STRATEGIES DIVISION
CALIFORNIA AIR RESOURCES BOARD
P.O. BOX 2815
SACRAMENTO, CA 95812
1. New
section filed 12-2-2008; operative 1-1-2009 (Register 2008, No.
49).
2. Amendment of section heading, section and NOTE filed
12-14-2011; operative 1-1-2012 pursuant to Government Code section
11343.4
(Register 2011, No. 50).
3. Amendment filed 12-19-2012; operative
1-1-2013 pursuant to Government Code section
11343.4
(Register 2012, No. 51).
4. Amendment filed 12-31-2013; operative
1-1-2014 pursuant to Government Code section
11343.4(b)(3)
(Register 2014, No. 1).
5. Amendment of subsection (h), repealer and
new subsection (h)(1), repealer of subsections (h)(2)-(11), amendment of
subsections (k)(2) and (l)-(m)(1), new subsection (m)(2), repealer and new
subsection (m)(3), subsection renumbering, repealer of subsection (m)(4),
amendment of newly designated subsection (m)(4) and amendment of subsection
(n)(1)(B)4. filed 12-31-2014; operative 1-1-2015 pursuant to Government Code
section
11343.4(b)(3)
(Register 2015, No. 1).
6. Amendment filed 9-1-2017; operative
1-1-2018 (Register 2017, No. 35).
7. Amendment of subsection (h),
repealer of subsections (h)(1)-(2) and (h)(5)-(6), new subsection (h)(1),
subsection renumbering and amendment of subsection (o) filed 3-29-2019;
operative 4-1-2019 pursuant to Government Code section
11343.4(b)(3)
(Register 2019, No. 13).
Note: Authority cited: Sections
38510,
38530,
39600,
39601,
39607,
39607.4
and
41511,
Health and Safety Code. Reference: Sections
38530,
39600
and
41511,
Health and Safety Code.
