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Inter-ISO Dispatch Proposal

Inter-ISO Dispatch Proposal. Prepared by Scott M. Harvey Draft for Discussion NEPOOL Markets Committee February 11, 2003. MOTIVATION. There are currently a number of factors limiting price convergence between ISO coordinated real-time spot markets in the Northeast:

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Inter-ISO Dispatch Proposal

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  1. Inter-ISO Dispatch Proposal Prepared byScott M. HarveyDraft for Discussion NEPOOL Markets Committee February 11, 2003

  2. MOTIVATION • There are currently a number of factors limiting price convergence between ISO coordinated real-time spot markets in the Northeast: • Transmission and ramping constraints. • Export charges. • Export restrictions and non-LMP pricing. • Variations in shortage pricing across control areas. • Lags and forecasting error in adjusting interchange. • Scheduling time lags required for system dispatch. • The NERTO proposal addressed this problem by proposing a single economic dispatch of both control areas.

  3. MOTIVATION • ISO-NE and NYISO are exploring the possibility of adjusting inter-change with each other periodically during the dispatch hour in conjunction with the real-time dispatch to improve price convergence. • This redispatch would primarily address the impact of lags and forecasting error in hindering price convergence. • Because interchange would be adjusted at several points in time during the hour, it would indirectly also address ramping constraints.

  4. THE CONCEPT • The essence of the proposal is that ISO-NE and NYISO would periodically adjust real-time net interchange on the ISO-NE and NYISO interface to maintain price consistency across their markets. • Price consistency will be measured at a predetermined benchmark. • The benchmark could be a single location or a weighted average of several locations. • Export charges would not be eliminated. • The ISOs would adjust interchange on an objective least-cost basis, just as they internally dispatch generation to meet load and manage congestion. These adjustments would be based on the generation and load bids and offers in each control area.

  5. THE DETAILS • Implementation of real-time inter-ISO dispatch will potentially affect five areas of ISO operation: • Real-time dispatch • Hour-ahead security evaluation • Day-ahead market • Congestion hedges • Settlements • Transmission tariffs? • ICAP markets?

  6. BenchmarkLocation Dispatched Up NYISO ISO-NE $25 $38 Dispatched Down 5

  7. THE DETAILS Real-Time Operation • In real-time, if the NYISO prices for the benchmark location were $25, while the ISO-NE price for the same location was $38, and NYISO export charges were $3, then: • The NYISO would dispatch up New York generation, delivering energy to the benchmark location at an as-bid cost of $25. • ISO-NE would dispatch down ISO-NE generation having an as-bid cost of $38 to deliver energy to the benchmark location. • These adjustments to the dispatch and net interchange would continue until the price difference at the benchmark location was consistent with the export charge.

  8. THE DETAILS Real-Time Operation • Implementation requires addressing a number of detailed issues regarding real-time operation. • How will the ISOs determine adjustments to interchange? • What will be the frequency of interchange adjustments? • What will be the benchmark location? • Will interchange adjustments account for charges on exports? • Will real-time interchange be tagged and subject to TLR for coordination with other control areas? • How will differences in benchmark prices arising from differences in shortage pricing systems be addressed?

  9. THE DETAILS Hour-Ahead Evaluation • Market participants will no longer submit price-based offers on interfaces supporting real-time interchange adjustments. • Market participant inter-ISO schedules will become financial, like internal bilaterals. • Market participant inter-ISO schedules will not determine net interchange, just like internal bilaterals do not determine the dispatch. • There will be no bid production cost guarantee (or bids) on inter-ISO schedules.

  10. THE DETAILS Hour-Ahead Evaluation • Implementation issues pertaining to the hour-ahead evaluation process include: • How will real-time interchange levels be assessed for hour-ahead security evaluation? • What degree of consistency across ISO-NE and NYISO in assumed interchange is necessary in hour-ahead evaluations and how will this consistency be maintained?

  11. ISO NE-DAM NYISO DAM A B C 500 MW Exports D CongestionRents onNYISO Exports Bids E A B C D 700 MW Imports 10

  12. THE DETAILS Day-Ahead Market • At this point, it is not envisioned that the implementation of real-time dispatch would require substantial changes in day-ahead markets. • Day-ahead markets would operate sequentially and would clear export and import schedules based on bids and offers. • Export and import schedules cleared in the day-ahead market would be financial schedules in real time. • Settlement of interchange schedules would need to be coordinated so that when the second day-ahead market clears, there is a single set of interchange schedules that is common to both markets.

  13. THE DETAILS Congestion Hedges • The introduction of real-time interchange would be consistent with, but would not require, the introduction of inter-regional congestion hedges settling in the day-ahead market and inter-RTO congestion rent settlements.

  14. THE DETAILS Settlements • Real-time inter-regional transactions would be financial. • Deviations between market participant day-ahead and real-time schedules would settle at real-time prices. • The charge for exports would be the difference between the benchmark price in the importing control area and the benchmark price in the exporting control area. In effect, power being exported would be sold at the benchmark price in the exporting control area and would be purchased at the benchmark price of the importing control area. • Absent congestion or ramp constraints, these benchmark prices would differ by roughly the charges on exports.

  15. THE DETAILS Settlements • Retention of export charges introduces a few wrinkles in the settlement process but can be managed. • Market participants would settle charges on inter-control area transactions with the ISO of the exporting control area. • Market participants would not pay export charges on their real-time financial inter-regional schedules, but would pay the difference in benchmark prices. Transactions scheduled day-ahead that flow in real time would pay export charges. • The difference between real-time net interchange and the financial schedules of market participants would be the financial schedule of the importing control area. • The ISO of the exporting control area would retain export charges on real-time net interchange. The remaining charges on inter-control area transactions would accrue to an inter-regional congestion charge account.

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  17. THE DETAILS Settlements • Suppose the NYISO price benchmark was $30, the ISO-NE price was $33, market participants had 500 MW of financial exports to NEPOOL, total real-time net interchange was 700 MW of exports to NEPOOL, and the NYISO export charge was $3/MWh: • Payments to NYISO by market participants for exports 500 MW * $3 = $1,500 • Payments to NYISO by ISO-NE for exports 200 MW * $33 = $6,600 Total = $8,100

  18. THE DETAILS Settlements • The NYISO would, in turn, pay generation in NYISO dispatched to support the export schedules the LMP price for the energy sold into the ISO-NE market. • Absent congestion, NYISO generators would be paid $6,000 for the additional energy. • The actual change in NYISO generation would be more than 700 MWh, and the average price paid to generators would be less than $30/MWh, reflecting the cost of losses. • The NYISO would pay the remaining $2,100 to New York transmission owners for export charges.

  19. THE DETAILS Settlements • ISO-NE would charge loads in NEPOOL the LMP price at their location for the energy acquired from New York. • Absent congestion in NEPOOL, NEPOOL loads would pay $6,600 for this energy. • The actual amount of NEPOOL load met with imports would likely be less than 700 MWh and the average LMP price paid by loads would be more than $33/MWh, reflecting the cost of losses.

  20. THE DETAILS Settlements • Overall, the cash flows balance. NYISOGeneration NEPOOLLoads $6,000 NYISO $6,600 ISO-NE Inter-ISOSettlements NYISOTOs TransmissionCustomers $1,500 $2,100

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  22. THE DETAILS Settlements • Now assume that load in NEPOOL rises, and the ISO-NE benchmark price rises to $40/MWh. Net exports from NYISO to NEPOOL rise to 750 MW but are constrained by transmission limits between the control areas that are not modeled in the 5-minute dispatch. • Payments to NYISO by market participants 500 MW * $10 = $5,000 • Payments to NYISO by ISO-NE 250 MW * $40 = $10,000 Total = $15,000

  23. THE DETAILS Settlements • NYISO generators would collect -$7,500 • NYISO TOs would collect -$2,250 • NEPOOL loads would pay $10,000 • Transmission customers would pay $5,000 • Congestion Rent Residual $5,250

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  25. THE DETAILS Settlements • Finally, we assume that market participants scheduled 450 MW of these transactions in the day-ahead market. • Payment of export charges on day-ahead schedules 450 MW * $3 = $1,350 • Payments by market participants for real-time schedules 50 MW * $10 = $500 • Payments by ISO-NE for real-time energy 250 MW * $40 = $10,000 Total = $11,850 Paid for export charges = $2,250 Paid into congestion rent account = $2,100 Payment to NYISO generators = $7,500 Total $11,850

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  27. THE DETAILS Settlements • Suppose alternatively that there was congestion within NEPOOL but all of the constraints were on lines modeled in ISO-NE’s 5-minute dispatch. • NYISO and ISO-NE would adjust net interchange until the benchmark prices converged, with allowance for export charges. • ISO-NE would dispatch down generation, reflecting the LMP value of NYISO exports.

  28. THE DETAILS Settlements • Because real-time schedules would be financial, the financial responsibility for physical interchange schedules would shift to the ISOs. • Reliability criteria that constrain interchange but are not reflected in prices could give rise to revenue inadequacy if they cause physical flows to differ from day-ahead financial schedules.

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  30. THE DETAILS Settlements • Suppose that the NYISO real-time benchmark price were $700/MWh, and that the ISO-NE real-time benchmark price were $400. • We further assume that NEPOOL was actually in a much more serious reserve shortage than New York and NEPOOL LSEs scheduled 300 MW of financial imports into NEPOOL, for which they would be paid $300/MW under the proposed settlement rule. • If the physical flow of interchange in real time was from NYISO into NEPOOL (i.e., inconsistent with the prices), the real-time congestion settlements would not be revenue adequate.

  31. ALTERNATIVES • Why not address limits on price convergence arising from lags and forecasting error by permitting market participants to adjust interchange every 15 minutes, based on schedules submitted 15 minutes before the dispatch interval? • This approach may not lead to improved price convergence and may exacerbate price volatility, particularly under shortage pricing. • NYISO would find it more difficult to manage Central East, increasing Zone G price volatility. • Market participants would not be able to anticipate ISO decisions such as committing 30-minute GTs or activating demand response.

  32. ALTERNATIVES • Market participants could not observe the aggregate supply curve in either control area. • Market participants individually would not be able to anticipate changes in aggregate market participant schedules. • Market participants would likely be at a disadvantage to the ISOs in forecasting short-term load changes.

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