1. (a) General Accounting Provisions

   1. (1) Unbundled RECs, including those from a non-eligible renewable energy resource, shall not be used to calculate or adjust the fuel mix or GHG emissions intensity of an electricity portfolio.
   2. (2) A retail supplier's purchases of the specified system power from an asset-controlling supplier shall use the GHG emissions intensity assigned to the asset-controlling supplier by the CARB for the corresponding data year used for data reporting to CARB pursuant to section 95111(b)(3) of the MRR. A retail supplier's purchases of the specified system power of an asset-controlling supplier shall be categorized according to the fuel mix of the asset-controlling supplier pursuant to section 1393(f).
   3. (3) Procurements from nuclear or large hydroelectric generating units cannot be classified as specified purchases if the associated environmental attributes have been claimed by, or traded to, a separate party.
   4. (4) To claim the fuel type of an eligible renewable, a retail supplier shall procure specified purchases of electricity and the associated RECs from an eligible renewable generator, including through eligible firmed-and-shaped agreements. If claimed as a specified purchase on the power content label, the associated RECs shall not be sold. Electricity purchases from an eligible renewable generator without the associated RECs shall be classified and reported as unspecified power.

   5. (5) GHG emissions of specified purchases, including eligible firmed-and-shaped products, shall be calculated based on the delivered electricity.

      1. (A) In order for specified electricity to be assigned the GHG emissions intensity of the associated generator, a retail supplier 1) must have executed a purchase agreement or ownership arrangement prior to generation of the procured electricity and, 2) have e-tags for all delivered electricity that is imported. If the specified electricity does not meet both 1) and 2), it will be assigned the GHG intensity of unspecified power.
      2. (B) In order to be assigned the GHG emissions intensity of an eligible renewable generator, the delivered electricity from the renewable generator must be procured with the associated RECs. In order for electricity storage resources to claim a GHG intensity associated with an eligible renewable generator, the energy used for production must be procured with the associated RECs. If claimed as a specified purchase on the power content label, the associated RECs shall not be sold. Electricity purchases from an eligible renewable generator without the associated RECs shall be classified and reported as unspecified power.

   6. (6) GHG emissions intensities of generators

      1. (A) The Energy Commission shall annually assign a GHG emissions intensity to each generator that delivers electricity to a California balancing authority and provide the most recent GHG emissions intensities of generators for retail suppliers to use in annual reporting to the Energy Commission pursuant to section 1393.
      2. (B) For all generators with reported or assigned emissions under MRR, the Energy Commission shall calculate GHG emissions intensities by dividing the generator's total GHG emissions reported to MRR by the generator's net electricity production reported to MRR.
      3. (C) For any generators without reported or assigned emissions under MRR, the Energy Commission shall calculate the sum of GHG emissions associated with the generator using heat of combustion data and default emission factors by fuel type pursuant to section 95111(b)(2)(C) of the MRR.
      4. (D) For any generators that cannot be assigned a GHG emissions intensity using the methods described in subdivisions (a)(6)(B) or (C), including new generators and generators located outside the U.S., the Energy Commission shall assign an emissions intensity based on the average GHG emissions intensity of generators using the corresponding fuel type reported under this program.
      5. (E) The Energy Commission shall determine the portion of GHG emissions of a cogenerating unit attributable to electricity production in the previous calendar year by dividing the generator's fuel consumed for electricity production by the generator's total fuel consumption, then multiplying the result by the generator's total GHG emissions. This calculation shall be based the most recent final data on fuel consumption and GHG emissions released by the U.S. Energy Information Administration collected pursuant to 15 U.S.C. 722(b) via EIA Form-923 (Power Plant Operations Report). The GHG emissions intensity of the cogenerating unit shall then be calculated by dividing the portion of GHG emissions attributable to electricity production by the generator's net electricity production as reported to MRR.
      6. (F) For generators with discrete generating units that are owned by or contracted to separate retail suppliers, the Energy Commission shall calculate GHG emissions intensities for each generating unit in accordance with subdivision (a)(6)(B).
      7. (G) For multifuel generators that have contracted with a retail supplier for a single fuel source of generation, the Energy Commission shall calculate the GHG emissions intensities for each fuel input in accordance with subdivision (a)(6)(B).

   7. (7) GHG emissions intensity

      1. (A) The GHG emissions intensity of an electricity portfolio shall be calculated by dividing total GHG emissions attributed to the portfolio by the retail sales of the portfolio.
      2. (B) The GHG emissions intensity of a retail supplier's total power content shall be calculated by dividing a retail supplier's total GHG emissions by loss-adjusted load, taking any exceptions into account pursuant to Section 1393.1(d).
      3. (C) Imports of unspecified power shall be assigned the default emissions factor as provided in section 95111(b)(1) of the MRR.

   8. (8) Transmission and distribution losses

      1. (A) A retail supplier's transmission and distribution losses shall be determined by applying a loss factor to each specified resource and to unspecified power.
      2. (B) Each retail supplier shall apply default loss factors calculated annually by CEC staff. The CEC shall publish default statewide loss factors for specified in-state resources, specified imports, and unspecified power, as well as the underlying calculations, prior to the reporting period each year. These factors shall be based on the estimated losses divided by the total energy disposition reported in the most recent final statewide data released by the U.S. Energy Information Administration collected pursuant to 15 U.S.C. 722(b) via EIA Form-861 (Annual Electric Power Industry Report). Loss factors for in-state and imported resources shall be weighted according to the ratio of specified in-state and unspecified resources versus specified imports from the prior year as reported under this program.
      3. (C) As an alternative to the loss factors under subdivision (a)(8)(B), a retail supplier may calculate and report a transmission and distribution loss factor directly for any specified resource. The retail supplier must provide substantiating documentation supporting the loss factor claim.

2. (b) Annual Accounting and the Power Content Label

   1. (1) The fuel mix for each electricity portfolio and for total power content shall be calculated by aggregating net purchases of each fuel type and expressed as percentages of the retail sales of the electricity portfolio or loss-adjusted load for total power content.
   2. (2) Annual purchases of unspecified power shall be calculated as the difference between a retail supplier's loss-adjusted load and the sum of its specified purchases, minus any specified resales.
   3. (3) A retail supplier shall allocate net purchases of specified and unspecified power to each electricity portfolio it offered and to its transmission and distribution losses and other end uses for the previous calendar year. Remaining specified procurements shall be allocated to annual oversupply. However, specified procurements of coal shall not be removed from a retail supplier's inventory due to oversupply.
   4. (4) Energy Commission staff shall calculate the GHG emissions intensity for annual unspecified power each year. The annual GHG emissions intensity shall be calculated as the sum of all GHG emissions associated with unspecified imports, unclaimed in-state natural gas resources, and oversupply divided by the sum of all MWh associated with unspecified imports, unclaimed in-state natural gas resources, and oversupply, taking cogeneration into account using the method provided in Section 1392(a)(6)(E).

3. (c) Hourly Accounting

   1. (1) Specified procurements of coal shall not be removed from a retail supplier's inventory due to oversupply.
   2. (2) Total net procurement for each hour shall be calculated by deducting specified resales from gross specified purchases, then adding storage discharging and hourly unspecified power for that hour.

   3. (3) Load matching

      1. (A) In each hour of the year, a retail supplier shall stack its procurements of delivered electricity for comparison with its hourly loss-adjusted load. The retail supplier shall determine the stacking order used for load matching.
      2. (B) Hours in which a retail supplier's hourly loss-adjusted load to serve load exceeds its remaining total procurements shall be considered hours of undersupply.
      3. (C) Hours in which a retail supplier's total procurements exceeds its hourly loss-adjusted load shall be considered hours of oversupply.

   4. (4) Electricity Storage

      1. (A) Hourly charging shall be reported in aggregate and added to hourly loss-adjusted load for each hour of the year.

         1. (i) If the increase to hourly loss-adjusted load results in increased hourly undersupply pursuant to 1392(c)(6), the retail supplier shall be attributed the quantity of unspecified power and associated GHG emissions needed to cover the increase to hourly undersupply.
         2. (ii) If the increase to loss-adjusted load does not result in undersupply pursuant to 1392(c)(6) in a given hour, that hourly charging will not increase the GHG emissions attributed to the retail supplier's inventory in that hour.
      2. (B) Hourly discharging shall be reported in aggregate and added to total net procurements for each hour of the year. No fuel type or GHG emissions attributes shall be assigned to electricity associated with storage discharging.
   5. (5) During hours of undersupply, the difference between hourly loss-adjusted load and total net procurement shall be classified as hourly purchases of hourly unspecified power.

   6. (6) Hourly unspecified power

      1. (A) Energy Commission staff shall calculate hourly GHG emissions intensities for hourly unspecified power each year. Hourly GHG emissions intensities shall be calculated as the sum of all GHG emissions associated with unspecified imports, unclaimed in-state natural gas resources, and oversupply in that hour divided by the sum of all MWh associated with unspecified imports, unclaimed in-state natural gas resources, and oversupply in that hour, taking cogeneration into account using the method provided in Section 1392(a)(6)(E).
      2. (B) Staff shall address any data gaps in calculating hourly unspecified power emissions intensities using the methods provided in Section 1393(c).

   7. (7) Oversupply and avoided emissions

      1. (A) Oversupplied resources and associated emissions shall not be factored into a retail supplier's GHG emissions intensity. Instead, oversupplied resources and associated emissions shall be factored into the calculations for the hourly GHG emissions factor of unspecified power.
      2. (B) A retail supplier shall be attributed avoided emissions to the extent that its oversupplied resources reduced the hourly GHG emissions factor of unspecified power. Avoided emissions shall not alter or adjust a retail supplier's GHG emissions intensity.

Note: Authority cited: Section 25213, Public Resources Code; and Sections 398.4 and 398.6, Public Utilities Code. Reference: Sections 25216 and 25216.5, Public Resources Code; and Sections 398.4 and 398.6, Public Utilities Code.

History

1. New section filed 9-21-98; operative 10-21-98 (Register 98, No. 39).

2. Change without regulatory effect amending subsections (b)(3)(C)1. and (d)(2)(B) filed 1-14-99 pursuant to section 100, title 1, California Code of Regulations (Register 99, No. 3).

3. Amendment of subsections (b)(1)(C), (d)(2)(A)3. and (d)(3) filed 3-5-2001; operative 3-5-2001 pursuant to Government Code section 11343.4 (Register 2001, No. 10).

4. Amendment filed 10-31-2016; operative 10-31-2016 pursuant to Government Code section 11343.4 (Register 2016, No. 45).

5. New subsection (b)(3)(C)1.f. filed 5-4-2020; operative 5-4-2020 pursuant to Government Code section 11343.4(b)(3) (Register 2020, No. 19).

6. Change without regulatory effect amending subsection (d)(3) filed 8-24-2022 pursuant to section 100, title 1, California Code of Regulations (Register 2022, No. 34).

7. Renumbering of former section 1392 to section 1391.1 and renumbering of former section 1393 to section 1392, including amendment of section and Note, filed 6-18-2025; operative 6-18-2025 pursuant to Government Code section 11343.4(b)(3) (Register 2025, No. 25).