1 / 27

NPC Meeting January 18, 2002 Boston, MA Operations Report

NPC Meeting January 18, 2002 Boston, MA Operations Report. Stephen G. Whitley Senior Vice President & COO. Discussion Points. System Operations Energy & Congestion Uplift Gas Study - Phase II Summer Pricing Action Plan Winter Capacity Update Security Update. System Operations.

rafer
Download Presentation

NPC Meeting January 18, 2002 Boston, MA Operations Report

An Image/Link below is provided (as is) to download presentation Download Policy: Content on the Website is provided to you AS IS for your information and personal use and may not be sold / licensed / shared on other websites without getting consent from its author. Content is provided to you AS IS for your information and personal use only. Download presentation by click this link. While downloading, if for some reason you are not able to download a presentation, the publisher may have deleted the file from their server. During download, if you can't get a presentation, the file might be deleted by the publisher.

E N D

Presentation Transcript

  1. NPC Meeting January 18, 2002 Boston, MA Operations Report Stephen G. Whitley Senior Vice President & COO

  2. Discussion Points • System Operations • Energy & Congestion Uplift • Gas Study - Phase II • Summer Pricing Action Plan • Winter Capacity Update • Security Update

  3. System Operations

  4. December Operations Highlights • Boston & Hartford weather pattern: • Monthly temperatures higher than average with below normal precipitation. • Peak Load, 19,982 MW, 12/17/01, HE 18 • M/S#2, OP #4, Generator Posturing not implemented during December. • Master Satellite Procedure #2 implemented on 12/20/01 in the greater Boston area for transmission reliability. • Simulated Manual Load Shed test held on 12/28/01. • Requests for Reserve Sharing • 12/29/01/ISO-NE requested 300 MW’s from NPCC • 12/31/01/PJM requested 150 MW’s from NPCC • Two new generating resources were added during December totaling approximately 84 MW’s.

  5. New Ombudsman Position • ISO’s intermediary for Customers • Not intended to replace Customer Service & Training Call Tracking Process • Investigates high level inquiries. • Contact for participant senior management • Acts to resolve inquires. • Reports on findings. • Logs issues as necessary • Position reports to the ISO’s COO.

  6. New Ombudsman Position • Customer Ombudsman Richard Berryman (Rich) • Office: 413-535-4315 • Fax: 413-540-4226 • Email: rberryman@iso-ne.com

  7. Energy and Congestion Uplift Reports

  8. Energy Uplift Comparison by Month2000 & 2001(Jan.- Nov. Energy Uplift Reduction $67.2 million)

  9. Congestion Uplift Comparison by Month - 2000 & 2001 (Jan.- Nov. Congestion Uplift Reduction $65.1 Million)

  10. Cause of Congestion by Category

  11. Gas Study Phase II Update

  12. Gas Study II Update • Final Gas Study II report expected to be available by February 1st, 2002. • NEGA reviewing and comments outstanding. • Study Results • New England’s gas pipeline (during coldest part of the Winter) can not meet the coincidental demands from both LDC’s and the electric generator sector. • On a peak day, approximately 1,350 MW of generation may be at risk. • 3,100 MW next Winter (Ref. Case) • Possibly 3,900 MW by Winter of 2004/5 (High case)

  13. Gas Study II Update, con’t. • Study Results • During 60-day Winter average (12/15 - 2/15) approximately 425 MW of generation may be at risk. • 1,300 MW next Winter (Ref Case) • Possibly 3,200 MW in 2004/5 (High Case) • The loss of vaporization (Winter peak day - 2001/2002) capability of Distrigas LNG would not be expected to undermine electric grid security objectives. • Margins are razor thin. • ISO-NE has approximately 3 - 48 hours to respond to gas pipeline contingency events. • Depends on location and nature of contingency.

  14. Gas Study II Update, con’t. • Recommendations • ISO New England should: • Determine all gas-fired generator’s fuel transportation arrangements. • Identify units that have on-site compression capability to supplement mainline pressure deviations during adverse operating events. • Determine the back-up fuel capability of each generator including options on refill arrangements. • Establish communication protocols directly with New England’s pipelines and LDC’s to monitor gas contingency events. This will strengthen the ISO’s ability to implement contingency plans for synchronization of replacement generation.

  15. Gas Study II Update, con’t. • Recommendations, con’t. • Participate in the Energy Industry Standard Board (EISB) committees that will be developing electronic communications protocols, template agreements for transmissions and scheduling standards to eliminate seams issues in energy transactions between electric and gas market counterparts. • Limit its dependency on gas-fired generation to provide operating reserve during Operational Flow Order events. • Maintain the steady state and transient flow simulation models in order to stay abreast of rapidly changing gas market dynamics in the greater Northeast.

  16. Summer Pricing Action Plan

  17. Market Efficiency Improvements Summary of Market Rule Changes 1. Reserves Reform/Lost Opportunity Payment 2. ECP Eligibility Rules 3. Transaction Scheduling Flexibility

  18. Market Efficiency Improvements Summer Response Action Plan

  19. Summer 2002Capacity Assessment SummaryWeek beginning June 22, 2002 - which has Least Operable Capacity Margin MW Projected Peak 24,200* Operating Reserve Required 1,700 Total Operable Cap. Required 25,900 Projected Capacity 28,540 Assumed Outages 2,500 Total Capacity 26,040 Operable Capacity Margin 140 *Peak Loads from the preliminary 2002 CELT Report.

  20. Summer 2002June - September 2002 • Positive capacity margins are currently forecasted for the Summer Period, ranging from approximately 140 MWs to 5,070 MW. • At this time, it is expected that there would be adequate capacity to meet expected demand. However delays in new generation expected to be online or extended heat wave could result in lower than expected positive margins.

  21. Winter Capacity Update

  22. Winter 2001/2002 Capacity SummaryWeek beginning January 19, 2002 MW • Projected Peak Demand 21,490 • Operating Reserve Required 1,700 • Total Operable Capacity Required 23,190 • Projected Capacity 28,670 • Assumed Outages -2,600 • Total Capacity 26,070 • Operable Capacity Margin 2,880 • Margin (%) 33.4

  23. Winter 2002Capacity Assessment SummaryWeek beginning January 19, 2002 MW Projected Peak 21,380* Operating Reserve Required 1,700 Total Operable Cap. Required 23,080 Projected Capacity 29,620 Assumed Outages 2,700 Total Capacity 26,920 Operable Capacity Margin 3,840 *Peak Loads from the preliminary 2002 CELT Report.

  24. Winter 2002January - March 2002 • Positive capacity margins are forecasted for the entire Winter Period, ranging from approximately 2,820 MWs to 5,070 MW. • Unless the region experiences an unusual event such as unexpected Fuel Supply Shortage, it is expected that there would be adequate capacity to meet expected demand.

  25. Security Update

  26. Security Update • NERC • Security level at “Threat-level Low” • A tool, Reliability Authority, was designed for the Control Room supervisor to send an email to all participants. • ISO - NE utilizes a NERC web-based tool to send and receive priority messages. • A direct “ring down” goes into effect when a message is received from the NERC hotline; messages are sent to all satellites and the New Brunswick Control Room.

  27. Security Update, con’t. • In development is a 3-way procedure to disseminate electric power grid, physical building and cyber threats. • ISO NE developed a web-based tool that send messages to all master satellites, New Brunswick Control Room and Operations Manager, along with key ISO management.

More Related