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ISO New England

ISO New England . Carol Chessmore Feiran Huang University of Texas at Arlington EE 5379: Fundamentals of Power and Energy Trading Dr. Ricson Chai Fall 2008. Introduction. Market Description Service Area Statistics and History Market Type LMP, FTRs, and ARRs Pricing Seams

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ISO New England

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  1. ISO New England Carol Chessmore Feiran Huang University of Texas at Arlington EE 5379: Fundamentals of Power and Energy Trading Dr. Ricson Chai Fall 2008

  2. Introduction • Market Description • Service Area • Statistics and History • Market Type • LMP, FTRs, and ARRs • Pricing • Seams • Operations • Operations Structure • Action During Capacity Deficiency • Transmission Outage Plans • Emergency Plan • Regulatory Agencies

  3. Service Area • 300 market participants • 8 pricing zones and a hub • Summer peaking system • Typical Peak Summer Demand: 19,000 MW to 24,000 MW • Typical Peak Winter Demand: 18,000 MW to 20,000 MW • Typical Fall and Spring Demand: 15,000 MW to 18,000 MW • Record Demand: 28,130 MW • 13 interconnections to New York and Canada • Part of the Eastern Interconnection

  4. Generation Types in New England ISO 2007 Generation in the ISO-NE 2007 Generation in ERCOT Source: ISO-NE Source: ERCOT

  5. Generation by State Source: ISO-NE

  6. Size Comparison of ERCOT and ISO-NE

  7. Brief History of New England Market • 1999 - Single energy clearing price market • March 2000 - Congestion Management (CMS) and Multi-Settlement Systems (MSS) added • CMS: Locational prices of electricity • MSS: Day Ahead and Real Time markets • March 2001 - Began use of Standard Market Design (SMD) • Used a PJM model • Worked with New York to standardize rules

  8. Comparison of Original System with SMD

  9. Available Trading Markets • Bilateral Transactions • Between wholesale buyers and sellers • Long term contract for set time frame • Set prices • 75% of transactions • Day Ahead Market (DAM) • Short term forward market • Used to manage risk of increases in real time prices • Real Time Market (RTM) • Spot market • Used for transactions not covered by bilateral transactions or DAM • Most risk since prices can change rapidly • Forward Capacity Market • Started in February 2008

  10. Forward Capacity Market • Economic incentive for investment in new and existing capacity resources • Demand Resources • Generation Resources • Auction • Forecasted requirements for 3 years in advance • Qualification process to prove they have their proposed capacity • Pay-for-Performance • Reduces payments to units not available during high demand • Peak Energy Rent • Reduces capacity costs for everyone when they reach a certain peak level • Theory: capacity market compensates for fixed costs while energy market compensates for variable costs • Prevents over-collection between the energy market and the capacity market during high demand

  11. Locational Marginal Price • LMP is “cost of congestion” • Value of locating new generation • Value of upgrading transmission • Value of reducing consumption • 3 costs • Energy (from least expensive unit) • Congestion (from more expensive unit) • Loss • Price calculated at 3 locations • Node (900 nodes) • Zone (8 zones) • Hub (1 hub) • Node • Not all Physical nodes have Pricing Nodes • Some Pricing Nodes are public and some are private • Zones • Load weighted average of the nodes in the zone • Zone LMP is public • Hub • Located in an area with low congestion • Price is average of the zone prices • Provides a stable reflection of the overall price • Eventually transition to full nodal market

  12. Uses of LMPs • LMPs used to calculate Charges or Credits for market services • Energy Market Energy • Energy Component • Transmission • Congestion Component • Transmission Losses • Loss Component • Net Commitment Period Compensation (NCPC) • Emergency Energy • Forward Reserves • Data Reconciliation • Inadvertent Energy Accounting

  13. Pricing using LMP • Calculated hourly for the Day Ahead Market • Calculated every 5 minutes for the Real Time Market • Real-Time Market • Participants with Generators are paid with Generator Node LMP • Participants with Asset Related Demands are charged based on the Load Node LMP • Participants with load other than Asset Related Demands are charged based on Zonal LMP • Day Ahead Market • Generators paid with Generator Node LMP • Participants with Increment Offers are paid with LMP at which the location cleared • Participants with Decrement Offers or Demand Bids are paid with LMP at which the location cleared • Rule of Thumb • If you are being paid, then use Node LMP • If you are being charged, then use Zonal LMP

  14. FTRs • “Congestion Revenue” • Zonal LMP (loads charged) > Nodal LMP (generators paid) • Congestion revenue = Zonal LMP – Nodal LMP • Financial Transmission Rights (FTR) • Sold at auction to participants • Gives owner the right to receive part of congestion revenue • Helps market participants manage their congestion risks • Obtained in 3 ways • Auction • Secondary market • Unregistered trades

  15. ARRs • Auction Revenue Rights (ARR) • NE ISO collects revenues from auction of FTRs • How are ARRs used? • Given out as Qualified Upgrade Awards (QUA) to pay for transmission upgrades that increase transfer capacity • Given to entities that pay congestion costs • Four stage process • Based on load served in the area • Allows them to recoup some of the congestion costs and some of the costs from acquiring FTRs

  16. Demand Response • General Features • Internet Based Communication System (IBCS) • Pre-planned actions to reduce load • Pre-determined rate paid per kWh • Monthly Capacity Payment based on ICAP or Market Price • Real-Time Demand Response Program • During emergency • 2 categories • Within 30 min • Within 2 hours • Real-Time Profiled Response • Without interval metering, but with directly controllable loads • Reduce load within 30 minutes • Real-Time Price Response Program • Reduce load when wholesale price forecast exceeds 10 ¢/kWh • Day-Ahead Program • Started in 2005 • Supplement to the Real-Time Program • Participants in either Real-Time Program • Offer electricity reduction bids based on day-ahead wholesale energy market

  17. Reserves • Operations Reserve • Can recover from the loss of 2 biggest sources with no interruption • Reserve margin of about 1,800 MW • Reserve Adequacy Analysis • Locational Forward Reserve Market • Twice a year auction for reserves • Online unused capacity or offline fast start generators

  18. Pricing for Reserves • Day Ahead Market • Operating reserves charges proportionate to DAM load obligations • Real Time Market • Charges are levied upon participants whose real time load deviates from the day ahead schedule • Charges for those whose generators deviate from day ahead schedules and who do not follow real time dispatch instructions • Forward Reserve Clearing Prices • Real Time Reserve Clearing Price • Set to zero unless need to redispatch • If need to redispatch, then equal to RCPF • Real Time Reserve Penalty Constraints • If reserve cannot be met • Local TMOR RCPF = $50/MWh • System TMOR RCPF = $100/MWh • System TMNSR RCPF = $850/MWh • System TMSR RCPF = $50/MWh

  19. Seams • Seams - Barriers that inhibit the economic trade of capacity and energy between neighboring wholesale electricity markets • ISO New England • New York ISO • PJM • Ontario • Hydro-Quebec • New Brunswick Power • Result of differences in • Market rules • Operating and scheduling protocols • In July 2002, FERC issued a Notice of Proposed Rulemaking for Standardized Market Design • In 2002, Northeastern Independent Market Operators Coordinating Committee was formed • Coordination of market design and system planning protocols • Sharing of regulation services • Sharing of reserves during short-term interruptions • Ensure that energy exporting procedures are similar so that trading across borders is easier

  20. Operations Structure • Departments • System Operations • Market Operations • System Planning • Committees • Participants Committee & Working Groups • Markets Committee & Working Groups • Reliability Committee & Working Groups • Transmission Committee & Working Groups • Other Committees • Inactive Committees

  21. Procedures and Manual • Operating Procedures (OP) • The procedures inform generators of operating and reliability requirements. • Total 21 OP • Summary of the Procedures and Manuals • Transmission • OP2, 6, 7, 11, 12, 13, 16, 17, 19 • Market • OP3, 4, 5, 8, 9, 14, 18, 21, M-06,-11,-35,-36 • Installed Capacity • M-20 • Accounting and Billing • M-27, -28, -29 • ISO Administrative • OP1, 10

  22. Action During a Capacity Deficiency • Operating Procedure 4 • 16 point plan • Action 1: Power caution • Action 2: All contracted 5MW generators come online • Action 3-5: Interrupt Real Time Demand with 2 hour or less notification • Action 6: Allow depletion of 30 minute reserve • Action 7-8: Continue to interrupt Real Time Demand • Action 9: Power Watch • Action 10: Request all generation contractually available

  23. Action During a Capacity Deficiency • Action11: Purchase energy from neighboring markets • Action 12: • Allow 5% less of normal operating voltage • Interrupt demand with 30 minutes or less • Inform NY ISO that sharing may be necessary • Action 13: Voltage reduction of 5% in 10 minutes • Action 14: Request all generation not contractually secured • Action 15: • Radio and Television Address for voluntary load curtailment • Power Warning • Action 16: New England State Governors to reinforce appeals for voluntary load curtailment

  24. Power Capacity Information • Normal • Power Caution • Issued to market participants • Prepare to implement OP 4 • No need for public action • Power Watch • Public action: Reduce AC, shutting off lights, and doing laundry at night instead of peak hours • Power Warning • Public action: Shut off unnecessary lights, equipment, and appliances

  25. Transmission Outages • Operating Procedure 3 • Outages: • Scheduled Outages • Long-Term Planned Transmission Outages • Short-Term Transmission Outages • Unplanned Outage • Emergency Outage • Forced Outage • Overrun Outage • Opportunity Outage

  26. Transmission Outages • Operating Procedure 3 • Categories of Transmission Facilities • Category “A”– Highest voltages >= 115kV except 115kV radial circuits and most critical facilities • Category “B”– All 115kV radial circuits and all 69kV circuit • Local Area – Below 69kV NOTE: Lists of Category A and B facilities are posted for the public The outage treatment will be different from category to category

  27. Operating Reserve • Operating Procedure 8 • An additional resource to meet the actual New England control area load • Control Area (CA) • An electrical power system to which a common Automatic Generation Control (AGC) is applied in order to • Match generation and load • Maintain interchange with other CA • Maintain frequency

  28. Operating Reserve • Ten-Minute Reserve • Ten-Minute Non-Spinning Reserve (TMNSR) • Ten-Minute Spinning Reserve (TMSR) • Thirty-Minute Operating Reserve (TMOR) • The same as Ten-Minute Non-Spinning Reserve • In 30 minutes • Replacement Reserve • Reserve other than TMSR, TMNSR, or TMOR

  29. Operating Reserve • First Contingency Loss • The largest capacity outage (MW) that would result from the loss of a single element • Second Contingency Loss • The largest capacity outage (MW) that would result from a single element after allowing for the First Contingency Loss

  30. Operating Reserve • Procedure • Real time Operating Reserve Requirement • Ten-Minute Reserve >= require to replace the First Contingency Loss • Thirty Minute Operating Reserve >= 50% of the Second Contingency Loss • Any excess of Ten Minute Reserve can be counted as Thirty Minute Reserve • Operating Reserve shall be sustainable for at least one hour from the time of activation • The output of the largest generating unit cannot be considered as Operating Reserve

  31. Emergency Plan • Operating Procedure No 7 • Procedure For Low Frequency Condition • If the cause is outside of New England CA • Increase the synchronized reserve, if needed • Make known to external area the available amount capacity • When the cause is due to a deficiency in NE CA • Request assistance from external area up to the emergency transfer limit of the interconnecting lines

  32. Emergency Plan • Procedure For Low Frequency Condition • When frequency reaches 59.90Hz • Disconnect any pumped storage resource operating in the pumping mode • Order fast-start non-synchronized resource into service • When frequency reaches 59.80 Hz • Automatic Generation Control will be tripped automatically • Direct all resources to maximum limits as maximum response rates, as appropriate

  33. Emergency Plan • When frequency reaches 59.30 Hz • Underfrequency relays will provide 10% load relief by the time the frequency reaches 59.00 Hz • When frequency reaches 58.80 Hz • Underfrequency relays will provide an additional 15% load relief by the time the frequency reaches 58.50 Hz • If it continues to decline below 58.50 Hz • Order manual load shedding (50% of the NE CA’s load can be shed manually)

  34. Regulation Market • FERC • Federal Guidelines • Prevents anti-competitive behavior • ISO New England's Market Monitoring and Mitigation Unit • Interacts with FERC's Office of Market Oversight and Investigation • Tries to suggest ways that SMD can be improved to prevent problems • Multiple PUCs: One PUC for each state • Multiple Energy Councils: One for each state

  35. Regulatory Agencies • New England Power Pool (NEPOOL) • Alliance of utility companies • Must have capacity • Looks at costs, benefits, and accountability • Dispatch: Meet demand with lowest fuel cost • Settlement: Accountability for dispatch • Forwards: Market to optimize generating resources by trading • Independent Market Monitoring • Evaluates SMD • Monitors markets for gaming

  36. Conclusion • Market Description • Standard Market Design • 8 zones and a hub • Locational Marginal Price (LMP) • Financial Transmission Rights (FTRs) • Auction Revenue Rights (ARRs) • 3 Markets • Real Time • Day Ahead • Forward Capacity • Pricing • Seams • Operations • Committees • Plan for Capacity Deficiency • Plan for Transmission Outages • Emergency Plan • Reserves • Regulation Market • Regulatory Agencies

  37. Thank you for your attention! Any questions on ?

  38. For More Information on ISO-NE • For more information on the ISO-NE, visit • www.iso-ne.com • News and Issues: Inside Grid & Markets Section • Market Operations Manual M-11 (Word doc) for discussion of uses of LMPs and pricing with LMPs • To see statistics about the ERCOT system, visit • www.ercot.com • About ERCOT: Media Kit: ERCOT Organization Backgrounder Section • ERCOT Quick Facts May 2008 (PDF document) • For more information on NEPOOL, visit • http://www.pur.com/pubs/820.cfm • All pictures, ISO-NE statistics, and the ISO-NE logo were taken from the ISO-NE website

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