1 / 42

MARKET OPERATIONS RELATED TO AUGUST 14 & 15, 2003 NEPOOL Markets Committee Meeting

MARKET OPERATIONS RELATED TO AUGUST 14 & 15, 2003 NEPOOL Markets Committee Meeting October 22, 2003 Marlborough, MA. Introduction. Our purpose today is to review with you the operation of the NEPOOL Market during and after the disturbance of Aug 14 and 15, 2003

keefe
Download Presentation

MARKET OPERATIONS RELATED TO AUGUST 14 & 15, 2003 NEPOOL Markets Committee Meeting

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. MARKET OPERATIONS RELATED TOAUGUST 14 & 15, 2003 NEPOOL Markets Committee Meeting October 22, 2003 Marlborough, MA

  2. Introduction • Our purpose today is to review with you the operation of the NEPOOL Market during and after the disturbance of Aug 14 and 15, 2003 • We are fulfilling a commitment made to the Participants Committee Note: A forum on System Operations during and after the disturbance has been scheduled for Nov. 14, 2003.

  3. Outline • Disturbance Description and System Operation Highlights - S. Rourke • Day Ahead Market Operation – M. Taniwha • LMP Impacts – M. Taniwha • Market Data Impact – C. Ide • Settlement – R. Kirkpatrick • Market Consequences – C. Ide • Market Issues – C. Ide • Questions - All

  4. Disturbance Description and System Operation Highlights

  5. New York, New England, and Maritimes Interconnections Citizens 396 Highgate PV-20 K37 K6 E205W Phase II HVDC 393 690 398 1385 Cable Cross Sound Cable-OOS

  6. Initial Conditions for 8/14/03 • Forecasted Peak Load: 23,000 MW • Forecasted Weather: High 80’s in Boston & Hartford • Operating Reserve Requirement: 2,000 MW • Surplus: 2,100 MW above Operating Reserve Req. • All first contingency requirements satisfied. • Operating to second contingency limits where appropriate

  7. Initial Conditions - 4:00 pm, 8/14/03 1400 MW 50 MW 500 MW 200 MW Citizens 396 Highgate 400 MW NE to NY PV-20 K37 K6 E205W Phase II HVDC 393 New England Load 23,370 MW 690 398 1385 Cable Cross Sound Cable-OOS 0 MW

  8. Initial Surge To New England - 4:10:41 pm 1400 MW 50 MW 100+ MW 200 MW Citizens 396 Highgate Transient2000+ MW NY to NE PV-20 K37 K6 E205W Phase II HVDC Frequency rises to 60.3 HZ and NB 3001 SPS operates tripping 380 MW of generation in NB 393 690 398 1385 Cable Cross Sound Cable-OOS

  9. Initial Surge Toward New York - 4:10:45 pm 1400 MW 50 MW 100+ MW 200 MW Citizens 396 Highgate Transient2500+ MW NE to NY PV-20 K37 K6 E205W Phase II HVDC Frequency falls to 59.4 HZ 393 690 398 1385 Cable Cross Sound Cable-OOS

  10. Event Sequence – 8/14/03(all times approximate) • 4:10:41 • Maritimes rejected 380 MW of gen. due to high freq. • 4:10:46 until 4:10:55 • Northern AC tie lines tripped on impedance relaying • Many lines feeding SWCT tripped from impedance relaying • 31 generators in New England tripped, mostly in SWCT, by various protection systems (over-excitation, under-voltage, out-of-step, etc.) • *** Majority of New England & Maritimes Islanded ***

  11. Northern NE-NY Ties Open - 4:10+ pm 1400 MW 50 MW 100+ MW 0 MW Citizens 396 Highgate PV-20 K37 K6 E205W Phase II HVDC 393 Vermont Load lost: 60 MW 690 398 1385 Cable Cross Sound Cable-OOS

  12. Event Sequence – 8/14/03(all times approximate) • 16:11:25 – trip of 321 line Long Mountain To Plum Tree • SWCT connected via 1385 cable to Northport, NY • Some under-frequency load shedding in SWCT

  13. Long Mtn.-Plum Tree Trip 4:11:25 pm 1400 MW 50 MW 120 MW 0 MW Citizens 396 Highgate PV-20 K37 K6 E205W Phase II HVDC 393 SWCT connected only to NY via 1385 cable 690 398 1385 Cable Cross Sound Cable-OOS 475 MW

  14. Event Sequence – 8/14/03(all times approximate) • 16:11:45 • trip Norwalk to Northport 1385 cable *** all remaining load in SWCT lost *** *** total NE load lost: approx. 2500 MW ***

  15. Norwalk-Northport Trip - 4:11:45 pm 1400 MW 50 MW 150 MW 0 MW Citizens 396 Highgate PV-20 K37 K6 E205W Phase II HVDC 393 690 Total New England Load lost: 2500 MW 398 1385 Cable Cross Sound Cable-OOS 0 MW

  16. Event Sequence – 8/15/03 • 8/14/03 • 23:45 – all New England Bulk Transmission system restored except NY ties – New England and Maritimes remain an island • 8/15/03 • 01:53 – Northfield, MA to Alps, NY in service ***New England & Maritimes synchronized to Eastern Interconnection *** • 02:00 – 200-600 MW Emergency Energy sales to NY • 04:00 – all but 100 MW of load restored • 05:40 – all other NY-NE ties closed except for K37 & 1385 cable • 05:44 – Frost Br.-Southington (329/352) line tripped reduced emergency sales to 200 MW • 07:00 – OP-4 actions in SWCT due to loss of 329/352 • 12:00 – Cross Sound Cable energized – DOE Order • 23:45 – OP-4 cancelled

  17. Event Sequence (continued) • 8/16/03 • 03:27 – Frost Br.-Southington line restored • 03:45 – Discontinued emergency restoration procedure • 8/17/03 • 07:00 - Cross Sound Cable curtailed to zero. • 19:00 – emergency energy to NY curtailed • 8/18/03 • 10:00 – Blissville, VT to Whitehall,NE line restored *** last available tie NY tie restored ***

  18. Operational Objectives following the blackout event – Island Operation • Manage frequency and voltage • Stabilize dispatch of resources • Restore system transmission security • Restore Transmission facilities • Restore load • Re-synchronize lost generation • Prepare to re-synchronize with NYISO • Prepare to support Eastern Interconnection with emergency assistance – excess reserves via commitment

  19. Manage frequency and voltage/Stabilize dispatch of resources • Island operation can result in wide frequency swings due to over or under generation – swings experienced after UDS runs and DDP assignments • Due to some missing operations data it was necessary to put most generation in Unit Control Mode 3 (non-dispatchable) and control frequency with a few, very responsive AGC units • This mode of operation was used for a majority of the period from the event until restoring ties with NYISO

  20. Restore System Transmission Security/Restore Transmission & Generation Facilities • Regroup and assess impact on NEPOOL system • Restore and maintain first or second contingency protection across the system, as required • Manual commitment of fast start resources, especially in SWCT to secure area • Coordinate restoration of transmission & generation facilities in order to implement system restoration procedures – OP6

  21. Restore Synchronization with NYISO and the Eastern Interconnection • Close coordination with NYISO before re-synchronizing the systems • Set up unit commitment (RAA process) to have additional reserve on line to sell emergency power • Unusual use of certain generation resources in NEPOOL required to facilitate NY/NE reconnection

  22. Day-Ahead Market Operation

  23. Day Ahead Market • DAM results for 8/15/2003 posted to market at 16:00 on 10/14/2003 • Minutes later blackout occurs ~ 16:11 • DAM for 8/16/2003 operates normally with market closing at 12:00 and results posted at 16:00 • Special Notice issued in morning advising of normal market operation

  24. LMP Impacts

  25. Real Time Market LMPs • LMP calculator (LMPc) solves until 16:20 then stops • RTNET fails to solve immediately after 16:11 • LMPc designed to continue solving for 15 minutes after stale RTNET case • LMPc starts solving again from 16:40 to 16:50 and stops • Based on one valid RTNET at 16:35 • LMPc starts solving again from 18:20 • RTNET starts to solve again from ~ 18:15

  26. Real Time Market LMPs continued… • Black Out of parts of Connecticut creates “dead buses” in LMPc that were not able to be corrected automatically by real time LMPc dead bus logic

  27. Price Finalization • Day Ahead Market - no change market clears as per normal on both days • Real Time Market – corrections to LMPs required for both days • Corrections for “dead bus” prices • Corrections for LMPc outages • Prices finalized as per market rules and manuals • Normal processes and procedures followed

  28. Market Data Impact

  29. Eligibility for Operating Reserve Credit • Data quality/availability issues and State Estimator solution problems made automated failure to follow dispatch instruction calculations unreliable • Manual monitoring utilized • No resource performance problems were identified by System Operations staff and none were reflected in the data used for Operating Reserve Settlement • Automated calculations were resumed effective 1200 on August 15th.

  30. Settlement

  31. Market Settlements • Market Rule 1 and NEPOOL Manuals 20 and 28 were followed for all settlements for August 14 and 15, 2003. • No settlement processes were adjusted for the blackout. • Emergency Power Sales to NY • Processed approximately 65 hours of emergency sales (some multi-nodal). • Included allocating portion of RMR charges to NY in accordance with Manual 28. • Metering adjustments during this period to be recognized at 90-day Resettlement of August (December invoice issued in January 2004).

  32. Market Consequences

  33. Market Consequences to Participants Impacted by Outage • Load Serving Entity whose load was “lost” • Entity trading across Control Area boundaries to New York • Generator that “tripped”

  34. Load Serving Entity Whose Load was Lost • If entity purchased Energy in DAM (see example), entity incurred • DA Load Obligation and purchased Energy at DA LMP • RT Adjusted Load Obligation Deviation and sold Energy back at RT LMP • Load Deviation for Operating Reserve Settlement and resulting share of Operating Reserve Charges • If entity did not purchase Energy in Day-Ahead Market (DAM), no DA position, no RT position, no deviation for Operating Reserve Settlement

  35. Example – Lost Load with DA Purchase • Participant has Demand Bid for 100 MWh at location X cleared in DAM at LMP of $30 • In RT, actual Participant Load at Location X=0 MWh • RT LMP = $10 • Participant pays DA price for cleared Demand Bid (DA Locational Adjusted Net Interchange X DA LMP) -100MWh X $30 = -$3000 • Participant paid RT price for RT Deviation (RT Locational Adjusted Net Interchange Deviation X RT LMP) 100 MWh X $10 = $1000 • Net Energy Settlement Impact to Participant = -$2000 • In addition, Participant pays share of OR charges

  36. Entity Trading Across Control Area Boundary to New York • If entity purchased Energy in DAM in anticipation of Sale into New York (see example), entity incurred • DA Load Obligation and purchased Energy at DA LMP • RT Adjusted Load Obligation Deviation and sold Energy back at RT LMP • Load Deviation for Operating Reserve Settlement and resulting share of Operating Reserve Charges • If entity did not purchase Energy in DAM, no DA position, no RT position, no deviation for Operating Reserve Settlement

  37. Example – External Sale to NY with DA Purchase • Participant has Decrement Bid for 100 MWh at Roseton node cleared in DAM at LMP of $30 • In RT, actual contract schedule to NY at Roseton node = 0 MWh • RT LMP at Roseton node = $10 • Participant pays DA price for cleared Demand Bid (DA Locational Adjusted Net Interchange X DA LMP) -100MWh X $30 = -$3000 • Participant paid RT price for RT Deviation (RT Locational Adjusted Net Interchange Deviation X RT LMP) 100 MWh X $10 = $1000 • Net Energy Settlement Impact to Participant = -$2000 • In addition, Participant pays share of OR charges

  38. Generator that Tripped • If Generator cleared (sold Energy) in DAM (see example), it incurred • DA Generation Obligation and sold Energy at DA LMP • RT Generation Obligation Deviation and purchased Energy at RT LMP • Generation Deviation for Operating Reserve Settlement and a share of Operating Reserve Charges • If Generator did not clear in DAM, no DA position, no RT position, no deviation for Operating Reserve Settlement

  39. Example – Generator that Tripped with DA Sale • Generator has Supply Offer for 100 MWh at location X cleared in DAM at LMP of $30 • In RT, actual generation at location X = 0 MWh • RT LMP at location X = $10 • Generator paid DA price for cleared Supply Offer (DA Locational Adjusted Net Interchange X LMP) 100 MWh X $30 = $3000 • Generator pays RT price for RT Deviation (RT Locational Adjusted Net Interchange Deviation X LMP) -100 MWh X $10 = -$1000 • Net Energy Settlement Impact to Generator = $2000 • In addition, Generator pays share of Operating Reserve Charges

  40. Market Questions/Issues(source Customer Service contact) • Are Emergency Purchase/Sale Transactions and Prices posted anywhere? • Yes, at www.isone.com/settlement_reports/emergency_power_ purchase_and_sales • Why were RT Operating Reserve charges so high on August 14th and 15th • Additional generation was kept on/committed on to assure an adequate supply of Regulation and Operating Reserve capability and the ability support restoration efforts within and outside of New England. Some generators were manually dispatched making them ineligible to set LMP but eligible for Operating Reserve Credits.

  41. Market Questions/Issues cont’d • Why were RT LMPs at $0 for hours 0100 and 0200 on August 15 • NEPOOL experienced Minimum Generation conditions during those hours as a result of dispatch • NYISO did not allow bilateral sales from New England to the NY market. How will this be accounted for in market Settlement? • See earlier slides related to “Marketing Entity Trading Across Control Area Boundary to New York”

  42. QUESTIONS??

More Related