Southern california edison company s proposal to participate in convergence bidding
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Southern California Edison Company’s Proposal to Participate in Convergence Bidding. August 23, 2010. Overview of SCE’s Convergence Bidding Proposal. Participate in the CAISO’s convergence bidding market on behalf of its customers as a component of its Commission-approved AB57 procurement plan

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Southern california edison company s proposal to participate in convergence bidding

Southern California Edison Company’s Proposalto Participate in Convergence Bidding

August 23, 2010

Overview of sce s convergence bidding proposal
Overview of SCE’s Convergence Bidding Proposal

  • Participate in the CAISO’s convergence bidding market on behalf of its customers as a component of its Commission-approved AB57 procurement plan

    • SCE should be afforded the same opportunity to participate in CAISO markets as is afforded other market participants

  • Obtain potential benefits of reduced costs and/or reduced risk for SCE’s customers

  • SCE’s participation subject to compliance with upfront standards and criteria in three categories

    • Volume limits

    • Locational volume limits

    • Process requirements

Uses of convergence bidding to benefit customers
Uses of Convergence Bidding to Benefit Customers

  • Manage the physical risks associated with its resource portfolio

    • For example, risk of an outage or derate of a generator, uncertainty in load forecasts

  • “Move” the pricing of transactions between day-ahead and real-time markets to reduce cost or mitigate risk

  • Obtain a better hedge against congestion charges by “moving” the settlement price of a congestion revenue right (CRR) from the day-ahead to the real-time market

  • Reduce the risk to customers of potential harmful outcomes associated with the convergence bidding activities of other market participants or unintended market anomalies

    • For example, bidding behavior to increase day-ahead energy prices described by CAISO’s DMM at the CPUC’s July 26 convergence bidding technical conference

Standard 1 volume limits
Standard #1 – Volume Limits

  • SCE proposes to place a limit (MW) on the amount of convergence bids SCE can submit in a given hour.

    • Specific limit is confidential

    • Volume limit based on bids submitted (not accepted bids)

  • SCE’s compliance with this specific volume limit would be demonstrated in SCE’s Quarterly Compliance Report (QCR) advice letter filings.

  • SCE believes its volume limit proposal provides SCE with sufficient flexibility to participate in convergence bidding on behalf of its customers while providing the Commission with sufficient oversight of SCE’s convergence bidding activities.

    • If SCE finds the volume limit overly restrictive, SCE will consider proposing a revised limit with appropriate justification

Standard 2 locational volume limits
Standard #2 – Locational Volume Limits

  • SCE proposes that its convergence bids be limited to locations that comport with SCE’s physical supply, physical load, transmission assets (including CRRs), or transmission usage.

  • Such locations would include, but not necessarily be limited to:

    • Nodes from which SCE schedules and settles physical load;

    • Nodes from which SCE schedules and settles supply resources;

    • Nodes that are identified in SCE’s CRRs;

    • Nodes that are price-correlated to those nodes in which SCE has physical load or resources; and

    • Nodes where prices can impact SCE’s demand costs and supply revenues

  • SCE proposes that this locational standard be further defined by a volume limit:

    • Submit convergence bids at such locations or correlated nodes in an amount not to exceed the potential volume of its price exposure at such locations/nodes.

    • For example, if SCE has a 200 MW generator, SCE’s locational volume standard would allow up to a 200 MW convergence bid at the generator’s price node or correlated nodes for purposes of hedging generation performance uncertainty.

Standard 3 process requirements
Standard #3 - Process Requirements

  • SCE will review each of its convergence bidding strategies with its PRG prior to the implementation of those strategies.

    • Address projected benefits (including risk reduction) and potential risks to customers of using convergence bids in the described strategy.

    • Provide information regarding the process that SCE will follow to implement its bidding strategy, the tools that SCE will employ to develop its convergence bids, and a description of the circumstances under which judgment will be applied to develop bids aimed at achieving a benefit to SCE’s customers

  • After convergence bidding is implemented, SCE proposes to review, on a quarterly basis, the results of its convergence bidding market participation with its PRG

Standard 3 process requirements cont
Standard #3 – Process Requirements (cont.)

  • Demonstrate compliance with the upfront standards for convergence bidding in its QCR advice letter filings

    • At a minimum the following information will be provided in SCE’s QCR and supporting workpapers regarding its participation in the convergence bidding market:

      • Date and hour the bid was submitted

      • Location of the bid

      • Type of bid (virtual supply or demand)

      • Quantity of bids submitted

      • Quantity of bids cleared

      • Day-ahead and real-time clearing price

      • Amount received (paid)

      • Triggering rationale or strategy that initiated the submittal of the bid

Standard 3 process requirements cont1
Standard #3 – Process Requirements (cont.)

  • If net losses from its convergence bidding activities exceed $10 million during any rolling 90-day period, SCE will convene a PRG meeting within two weeks of the date when the rolling 90-day net loss exceeded the $10 million trigger.

    • Discuss the results of it convergence bidding activity with the PRG (which includes members of the Commission’s Energy Division staff) and potential modifications to its convergence bidding activities on a going-forward basis

    • $10 million trigger value is designed to be high enough to avoid the need for frequent PRG consultation outside of normally scheduled meetings, while still representing less than a fraction of 1.0% of SCE’s overall annual procurement costs

  • Record revenues and costs associated with convergence bidding transactions in SCE’s ERRA balancing account

Additional considerations
Additional Considerations

  • SCE is strongly opposed to the adoption of a shareholder-ratepayer incentive mechanism for IOU participation in convergence bidding

    • Incompatible with other AB57 procurement standards, which do not include shareholder incentive mechanisms

    • A convergence bidding incentive mechanism for shareholders would result in an untenable conflict of interest

  • Uniform upfront standards for all three IOUs should not be imposed solely for the sake of uniformity

    • AB 57 acknowledges that differences may exist among the three IOUs, and does not require the adoption of uniform upfront standards

Customer benefit outage mitigation risk mitigation

= Payment

= Charge

Generation Sale

Virtual Sale

$ Paid (charged)

$ Paid (charged)

Uninstructed Charge

Virtual Purchase

Customer Benefit: Outage Mitigation (Risk Mitigation)

RTM w/ Virtual Demand

RTM w/ Virtual Demand


Virtual Sale

$ Paid (charged)

  • Assume a 100 MW physical generator clears market

  • Assume 100 MW virtual demand also clears market at the same node

  • Assume both transactions are by the same SC

  • Net day-ahead settlement = $0

  • If the generator runs (i.e. follows the day-ahead schedule), the only settlement is the virtual “sell-back”

  • This results in a net benefit if the RTM prices are higher than IFM

  • Net real-time settlement = 100 MW * real-time price

  • If the unit trips, it must pay the uninstructed deviation charges (i.e., the real-time price)

  • The virtual sale is paid the real-time price

  • Net real-time settlement = $0

Customer benefit optimal unit settlement cost reduction

= Payment

= Charge

Customer Benefit: Optimal Unit Settlement (Cost Reduction)

RTM w/ Virtual Demand


Note: If RTM prices are higher than IFM prices, the virtual demand bid increased generation revenues (resulting in lower customer costs)

Virtual Sale

Generation Sale

$ Paid (charged)

$ Paid (charged)

Virtual Purchase

  • Settlement of the Virtual Demand Bid in real-time results in a payment = 100 MW * real-time price

  • Assume a 100 MW physical generator is a Must Run/Must Offer unit

  • Assume RTM prices are forecast to be higher than IFM prices

  • The physical unit is scheduled in the IFM

  • Submitting a Virtual Demand Bid creates a net day-ahead settlement of $0