Proposed Changes to AGC Minimum
Requirement (SE-33)
December 18, 2006
Action Items from Dispatch Issues Working Group December 18, 2006 Action Item 1: Investigate whether telemetry from intermittent generators trumps their forecast into the next hour in MIO. Intermittent and Self Schedulers – use of telemetered EMS values for future MIO intervals within the current dispatch hour, use of forecast/schedules values for future MIO intervals in the next hour. There is a three interval “ramp in” transition period starting in the first interval of the next hour, when the telemetered value differs from the forecast/schedule value. Action Item 2: Investigate benefits of altering ramp rate independently of the contracted amount of MW of AGC, including the impact of pegging ramp rate requirement to the amount of required MW in an hour. Eliminating the min ramp requirement will supply flexibility in contracting AGC from resource types other than hydroelectric, e.g. fossil or gas. Action Item 3: Investigate influences on OTDs, other than AGC, in the fall months. A cursory investigation of the fall of 2006, indicates that management of Segregated Mode of Operation transitions and CPS performance also contributed to OTDs in this time period. The IESO will investigate further to isolate AGC effects and report back to participants the first week of January. Action Item 4: Establish proposed criteria to judge effectiveness of setting AGC requirements, with an eye to avoiding undue interference in the market. This will be sent to the working group the first week of January. Action Item 5: Investigate impact for generators who were given day‐ahead signals for AGC and were subsequently changed in RT. This will form part of the IESO proposal. Action Item 6: Provide information on the movement by NERC and NPCC to specify minimum AGC requirements. On October 20, 2006, Federal Energy Regulatory Commission (FERC) issued a notice of proposed rulemaking (NOPR), “Mandatory Standards for the Bulk‐Power System.” Regarding the automatic generation control standard (BAL‐005‐0), FERC proposes to direct NERC to submit a modification that includes requirements that identify a minimum amount of AGC. Removing the prescriptive minimum MW and rate requirements on AGC from the current market rules, while maintaining the December 22, 2006 Public Page 1 of 2 obligation on the IESO to meet the reliability standard, would provide the necessary flexibility for alignment with any minimum AGC requirement that may be specified by NERC. Action Item 7: Investigate whether CMSC for OTD is subject to local market power mitigation, as well as the materiality of CMSC payments for OTDs. OTDs are not subject to local market power mitigation. Action Item 8: Investigate whether AGC instructions outside AGC ranges are captured as deviations in the dispatch deviation report. Any AGC action outside the contracted range in RT is not captured as an event in the Dispatch Deviation report. Action Item 9: Provide background information and criteria for ORA, OTD etc. and check whether help files are available for the dispatch deviation report. Definitions are provided on the report. Action Item 10: Finalize list of outstanding dispatch issues and find a forum for them. (a)
Investigate a longer dispatch interval for “slow movers”. (b)
Re visit co‐optimization of energy and OR. (c)
Tuning of “weighting” factors for MIO. (d)
Management of transmission limits in a more informal manner, similar to results of compliance aggregation program. (e)
Management of Intertie schedules ramping. IESO will designate the forum and the timeframe in which these remaining items will be addressed. DIWG members to review list and comment to IESO by end of January 2007. Action Item 11: Circulate a draft of shadow price report on how shadow price relates to dispatch. Drew Phillips to circulate draft. Action Item 12: Include “Items of Interest” in next DACP report, highlighting events of Dec. 5 Gordon Drake will incorporate this item into the January report. December 22, 2006 Public Page 2 of 2