Section 95122 - Suppliers of Natural Gas, Natural Gas Liquids, Liquefied Petroleum Gas, Compressed Natural Gas, and Liquefied Natural GasAny 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 CO2 emissions specified under 40 CFR § 98.402(a), natural gas liquid fractionators must report the CO2, CH4, N2O and CO2e 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 CO2 emissions specified under 40 CFR § 98.402(b), local distribution companies and intrastate pipelines delivering gas to California end-users must 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 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 CO2 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 CO2i in section 95122(b)(6), 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 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 CO2j in section 95122(b)(6), 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 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 MTCO2e calculated according to subparagraph (2) above. Emissions are calculated according to Equation NN-3 of 40 CFR § 98.403(b)(1) except that CO2j will be the product of MMBtuTotal 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
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 CO2l 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 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.(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 CO2/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 CO2 emissions for California, the equation below must be used: Click here to view image
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 CH4 and N2O emissions using equation C-8 and Table C-2 as described in 40 CFR § 98.33(c)(1) for all fuels where annual CO2 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 CH4, N2O, CO2 from biomass-derived fuels, and CO2e by replacing CO2 in the equation in section 95122(b)(6) with CH4, N2O, CO2 from biomass-derived fuels, and CO2e. CO2 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 CO2 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 CO2 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 CH4 and N2O 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 CO2 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 CH4 and N2O 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 CO2e emissions using the following equation: Click here to view image
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 CO2, CH4, N2O, and CO2e 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 CO2, CO2 from biomass-derived fuels, CH4, N2O, and CO2e 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 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 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 CO2i parameter as specified in section 95122(b)(6). Additionally, intrastate pipeline operators are required to estimate a value for CO2j as specified in section 95122(b)(3) for natural gas delivered to local distribution companies, interstate pipelines, and other intrastate pipelines. The CO2l 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 CO2, CH4, N2O, and CO2e 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 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 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.(e)Procedures for estimating missing data. Suppliers must follow the missing data procedures specified in 40 CFR § 98.405. The operator must document and retain records of the procedure used for all missing data estimates pursuant to the recordkeeping requirements of section 95105.Cal. Code Regs. Tit. 17, § 95122
1. New section filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).
2. Amendment of section heading and subsections (a)(3), (b)(9)-(10), (d)(2)(D) and (d)(5) and repealer of subsection (f) filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).
3. Amendment filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).
4. Amendment of subsections (a)(1), (b)(1), (b)(8), (d)(1), (d)(2)(E) and (d)(6) filed 12-31-2014; operative 1-1-2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).
5. Amendment of subsections (a)(2)-(4), (b)(5)(A)-(B), (b)(8)-(13), (c)(4), (d)(2)(A), (d)(2)(D)-(E) and (d)(3)-(5) and new subsections (d)(7)-(8) filed 9-1-2017; operative 1-1-2018 (Register 2017, No. 35). 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.
1. New section filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).
2. Amendment of section heading and subsections (a)(3), (b)(9)-(10), (d)(2)(D) and (d)(5) and repealer of subsection (f) filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).
3. Amendment filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).
4. Amendment of subsections (a)(1), (b)(1), (b)(8), (d)(1), (d)(2)(E) and (d)(6) filed 12-31-2014; operative 1/1/2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).
5. Amendment of subsections (a)(2)-(4), (b)(5)(A)-(B), (b)(8)-(13), (c)(4), (d)(2)(A), (d)(2)(D)-(E) and (d)(3)-(5) and new subsections (d)(7)-(8) filed 9-1-2017; operative 1/1/2018 (Register 2017, No. 35).