Demand Response Working Group and Stakeholder Meeting Agenda January 15, 2009

Transcription

1 Demand Response Working Group and Stakeholder Meeting Agenda January 15, 2009 Time 11:00 11:10 11:10 11:40 11:40 12:00 12:00 12:45 12:45 2:15 2:15 2:30 2:30 3:30 3:30 4:30 4:30 5:00 Topic Introduction & Meeting Objective Working Group Discussion: MRTU Release 1 Participating Load User Guide Working Group Discussion: PDR Implementation Detail Lunch FERC Order on Competition Adds to Requirements for Demand Response - Project Time Line - Addition of Direct Participation to the two DR Models for Post- MRTU Market Enhancements - Design Features and Issues Break Cash Flow Model and Settlements Issues Alternate Proposal for Proxy Demand Resource DR Process Issue Resolution Presenter Tom Cuccia John Goodin/ Farrokh Rahimi Jim Price Jim Price Margaret Miller Muir Davis John Goodin

2 Update on MRTU Release 1 Participating Loads Users Guide John Goodin, CAISO Farrokh Rahimi and Ali Ipakchi, OATI Demand Response Stakeholder Meeting January 15, 2009

3 Background Draft of MRTU Release 1 Participation Loads Users Guide was issued on December 9, 2008 Discussed at the Dec 12, 2008 Stakeholder meeting Comments were received from SCE and PG&E CAISO incorporated the comments received and made additional changes as necessary The next few slides indicate the main changes Slide 3

4 Main Changes Made in PL Users Guide Editorial corrections and cleanup Clarification of such issues as consideration of PL in RUC procurement target Correction of settlement examples involving A/S No-Pay Consideration of Distribution Losses for SC Metered Entities Elaboration of edac implementation requirements Slide 4

5 Main Changes Made in PL Users Guide Stakeholder Comment CAISO Response Source Section 2 - "In the RUC process, the day-ahead PL schedule is used as the forecast for PL's consumption so that RUC will factor PL in and not over-commit resources". Explain how the CAISO is generating a load forecast. CAISO treats max PL bid in DAM as PL forecast, carves it out of the UDC load and adds back in the PL that clears as load. PG&E Section 2 - SCs providing PL resources will not be given RUC payments, according to the last sentence on this page. However, the paragraph above this one states RUC will factor PL in based on the PL forecast. If CAISO is factoring PL into the RUC stack, why would we not get a RUC payment for it? The PL curtailment in the IFM is similar to a generator clearing IFM. Both reduce the RUC procurement target, and neither is paid RUC availability. Besides, PL resources are considered RA capacity and thus are ineligible to be paid RUC availability. SCE Section 2 - Please clarify point (b) the Non-spinning Reserve is deployed and delivered (based on telemetry), during a contingency, but the hourly metered consumption of the Participating Load is not adequate to cover the Energy associated with the total awarded Non-spinning Reserve capacity for the hour less the deployed Energy. Clarifications have been added to the document. Thanks for the comment SCE Slide 5

6 Main Changes Made in PL Users Guide (Cont d) Stakeholder Comment CAISO Response Source Section 5.1 states the "CAISO may adjust the A/S and realtime imbalance energy requirements temporarily", why is this here? It seems too generic. Agreed and paragraph deleted PG&E The third paragraph notes that "The CAISO may adjust the A/S and Real-time Imbalance Energy requirements temporarily to take into account, among other things, variation in conditions, real time dispatch constraints, contingencies, and voltage and dynamic stability assessment. SCE Section this is the first time that the words "non- Participating load bid" is used. Also the CAISO now references PL modeled at an "individual node", they need to revise to be consistent with 'custom laps' Agreed and text is edited accordingly PG&E, SCE Slide 6

7 Main Changes Made in PL Users Guide (Cont d) Stakeholder Comment CAISO Response Source Section Are SC s required to bid both a resource (pseudogenerator) and enough energy to cover that load (PL), or do they have the option to just bid the resource, and take the chance that they will be bid and will not have to purchase energy to cover the load? The SCs are not required to self-schedule enough load in the Day Ahead market to cover their non-spin bid or award but by not self-scheduling enough load they may risk a no-pay in real-time. There are minor edits in the document to clarify this. SCE PL Requirements Table: This Ancillary Services test appears to be another testing/certification in addition to the /PLIP/PLAT/RDT. What type of things are going to be tested on for this? How long will it take to get the test done? Are there WECC or CAISO standards? If this is a WECC requirement, we could be looking at another critical path for bidding a resource as an ancillary service. General -- most of the meters for DR will be connected to distribution lines. However, there is no discussion in the document about how DLF will be used for adjustment, if any. Will there be an adjustment to telemetry? How would those adjustments be compared to the meter, which per RQMT need to be adjusted by posted DLF by UDC area? The testing will include a) edac technology and b) resource capability for providing A/S. The CAISO resource eligibility testing requirements are based on the WECC requirements. The use of DLF has been incorporated for the SC Metered Entities. DLF (Distribution Loss Factor): Distribution Loss Factor represents the average electrical energy losses incurred when electricity is transmitted over a distribution network. DLF is represented as a percentage of energy transmitted. For the purposes of the CAISO PL, the DLF represents losses between the PL meter and the associate CAISO Pricing Point (substation connecting the load to the CAISO controlled grid). SCE PG&E Slide 7

8 Main Changes Made in PL Users Guide Corrections in PL Settlement Examples Although telemetry is required for provision of A/S, it is not used for compliance monitoring and No-Pay A/S No Pay applies based on metered consumption and (day-ahead load resource schedule minus dispatched real-time Energy from A/S capacity) Case 2: DA PL Load Resource cleared 14 MW PL RT consumption before contingency was 15 MW RT Energy Dispatch from PL A/S Capacity: 1 MWh Meter read: 14 MWh Although source reduced consumption based on telemetry, it is subject to No-Pay Case 3: DA PL Load Resource cleared 14 MW RT consumption before contingency was 13 MW RT Energy Dispatch from PL A/S Capacity: 1 MWh Meter read: 13 MWh Although source did not reduce consumption based on telemetry, it is not subject to No-Pay Slide 8

9 Questions or Issues? to: Slide 9

10 Implementation Detail in Proxy Demand Resource Design Jim Price Lead Engineering Specialist, Market Design & Regulatory Policy Demand Response Working Group Meeting January 15, 2009

11 ISO is Preparing for Detailed Design Stage of Post-MRTU Demand Response Enhancements Post-MRTU Release 1 market enhancements provide two DR models: Dispatchable Demand Resource (DDR) adds to MRTU PL: RT & DA energy, cooptimization of energy & AS, market functionality for spinning reserve & regulation, and recognition of operating characteristics. (Involves vendor development) Proxy Demand Resource (PDR) simplifies administration of Custom LAPs in initial DR integration into MRTU and migration of small loads, by scheduling load at Default LAP and dispatch Proxy Generators at local levels. This informs the PDR resource when significant costs can be achieved through DR. Initial PDR implementation modifies internal ISO systems. Initial review: ISO targets implementation for summer (Then, operating reserve and real-time energy targeted for fall 09, and full PDR with DDR 12 months after MRTU Go-Live. Timing is subject to MRTU staffing needs.) Implementation uses post-processing of market data. Must be no real-time data changes, no change in data format transferred between systems, no change in OASIS. Initial implementation cannot include significant business process changes (e.g., no baseline calculations of end use customers demand). ISO will present updates in DR working group meetings. Example of needed coordination: add Proxy Generators during network model updates

12 Working Group Discussion of DR Market Enhancements Showed Possible Refinement PDR implementation involves two conceptual steps: (1) subtract day-ahead (DA) Proxy Generator schedule from Scheduling Coordinator s DA Default LAP schedule, then (2) remove Proxy Generator from Settlement data. Result is to credit SC with DR response. Concern: When Direct Access customers are in utilities DR programs, utilities DA Default LAP schedules are adjusted, instead of the customers Electric Service Provider s schedule. Potential resolution: perform step 2 but not step 1 Advantage: Correct SC sees DR response in its metered demand. Disadvantage: DR response settles at real-time price, not DA price. Feedback needed: Would this be a helpful change in the initial PDR design?