CAISO, Parties File Settlement Regarding Assignment of Costs Created by Market Participant Defaults

The California ISO, several California generators, and the state's major investor-owned utilities have filed a settlement at FERC governing the allocation of payments required of market participants to cover defaults in the CAISO market. Several municipal utilities as well as FERC Staff have indicated that they do not oppose the settlement, which addresses issues raised in a complaint by generators and other net wholesale suppliers in EL09-62.

Under the settlement, the ISO tariff would be revised to provide that each payment default amount that remains unpaid by the defaulting CAISO Debtor will be allocated on the next practicable Invoices to Default-Invoiced Scheduling Coordinator ID Codes (SCIDs) using the following methodology:

• 20% of the payment default amount will be allocated to the Default-Invoiced SCIDs in proportion to the net amounts that were payable in each applicable calendar quarter (and averaged within such calendar quarter) to the Default-Invoiced SCIDs over the applicable Default Look-Back Periods
• 30% of the payment default amount will be allocated to the Default-Invoiced SCIDs in proportion to the sum of absolute values of the dollar amounts shown on their Invoices payable or receivable in each applicable calendar quarter (and averaged within such calendar quarter) over the applicable Default Look-Back Periods, after excluding dollar amounts shown on the Invoices for Grid Management Charges, Reliability Must-Run services, and Wheeling Access Charges, and after excluding the billing of Access Charges and the payment of Transmission Revenue Requirements to Participating Transmission Owners
• 50% of the payment default amount will be allocated to the Default-Invoiced SCIDs in proportion to the largest of the following five amounts calculated in MWh for every month and averaged within each applicable calendar quarter for each Default-Invoiced SCID over the applicable Default Look-Back Periods:
  1. Cleared Day-Ahead Schedules to supply Energy, plus Day-Ahead Ancillary Services Awards and qualified Self-Provided Ancillary Services, plus scheduled supply obligation for Ancillary Services (including imports but excluding RUC Schedules), plus Virtual Supply Awards;
  2. Metered Generation, plus Real-Time Interchange Import Schedules, plus Real-Time Ancillary Services Awards and qualified Self-Provided Ancillary Services, plus HASP Ancillary Services Awards and qualified Self-Provided Ancillary Services, plus Real- Time supply obligation for Ancillary Services;
  3. Cleared Day-Ahead Schedules for Demand (including Demand served by Pumped-Storage Hydro Units and exports) multiplied by 103% to reflect Transmission Losses, plus scheduled demand obligation for Ancillary Services, plus Virtual Demand Awards;
  4. Metered Load multiplied by 103% to reflect Transmission Losses, plus Real-Time Interchange Export Schedules, plus Real-Time demand obligation for Ancillary Services; or
  5. The greater of (A) the quantity of CRRs acquired in CRR Auctions or transferred through the Secondary Registration System (excluding CRRs acquired in CRR Allocations) or (B) Inter-SC Trades of Energy.

In some circumstances, the Revised Default Allocation Tariff Provisions allow market participants that are Scheduling Coordinators, CRR Holders, Candidate CRR Holders, or Participating Transmission Owners to elect to consolidate data among multiple related SCIDs.

Since the tariff revisions will use a "look back" approach including prior calendar quarters, Market Participants that subsequently exit the ISO markets will continue to be responsible for allocated shares of payment default amounts to the extent required by the Revised Default Allocation Tariff Provisions even after their exit from the market.