Standard Market Design Technical Presentation April 18, 2001

1. Standard Market DesignTechnical PresentationApril 18, 2001 Presented to the NEPOOL Participants by ISO New England And PJM Office of the Interconnection

2. Benefits of the Standard Market Design Market Design Overview Congestion Management Locational Marginal Pricing Financial Transmission Rights Energy Market Day-Ahead Market Real-time Market Capacity Market Real-Time Market Ancillary Services Regulation Operating Reserves Spinning Reserves Market Settlements Next Steps Discussion Topics

3. Standard Market Design Drivers for ISO-NE • Implement Working Markets that have Congestion Management and Multi-Settlement, as quickly as possible • Take advantage of software and lessons learned in New England and elsewhere • Maintain allocation agreements negotiated by NEPOOL Participants

4. Benefits of the Standard Market Design • Increase ability of Market Participants to make decisions affecting their load and resources • Self-Scheduling • External Transactions • Assure that the price reflects the resources actually dispatched • Use “Ex-Poste” price calculations • Only units following instructions set price price based on actual, not predicted dispatch • Achieve a better balance between decisions made by software and operators • Operators need to assure that decisions made by software are reasonable

5. Increased Ability of Market Participants to Make Decisions • Previous design required that Market Participants turn all choices into prices and software would make decisions • SMD enables Market Participants to: • Self-Schedule Generators • Self-Schedule External Transactions • Self-Supply Regulation • Self-Supply Spinning Reserve • Hedge Financially in Day Ahead Market and bi-laterally

6. Self-Scheduling of Generators • In Day-Ahead Market, units can be self-scheduled up to their maximum output • Units can adjust output in real-time (either higher or lower) • This is done by specific request, not by submitting a price

7. Scheduling of External Transactions • External contracts can be self-scheduled in both Day-Ahead and Real-Time • Contracts willing to pay congestion will continue to flow • Unless self-curtailed • Physical curtailment needed • Unlikely as transmission costs increase, self-curtailment will occur • Dispatch should result in Economic Self-Curtailment

8. Achieving better balance between software and operator decision-making • Operator will review all constraints operative on the system and select those that affect dispatch • Pricing will be ex-poste, reflecting actual dispatch and operator entered constraints.

9. What the Standard Market Design Doesn’t Do • Change allocation in negotiated settlements in New England • All financial congestion rights will be auctioned • Proceeds from auction will be allocated per auction revenue rights in NEPOOL Agreement • Zonal pricing for load is retained

10. Market Design Overview

11. Market Objectives • Maintain System Reliability • Support an Efficient Market • Maximize ability of Participants to make market decisions • Provide value to all Participants

12. Requirements for Efficient Markets • LMP pricing based on actual system operating conditions • State estimator updated continuously • Same network model for day-ahead market, system scheduling, dispatch, and settlements • Cost causation for pricing to market Participants. • Locational • Consistent with Day Ahead Market • Consistency results in market confidence in prices

13. Standard Market Design • Maintains fundamental structure of New England market • Spot Market w/ Regional physical dispatch • Major Elements include: • Capacity Market • Energy Market • Financial Transmission Entitlements Markets • Ancillary Services Markets • Regulation • Spinning

14. Congestion Management

15. Transmission Congestion • ISO-NE energy market will use Locational Marginal Pricing (Nodal and Zonal Pricing) to manage transmission congestion • Energy market includes overlying trading hubs and zones to provide standard energy products for commercial markets • Energy market includes FTRs (Financial Transmission Rights) to allow Participants to manage congestion risk

16. What is LMP? • Pricing method ISO-NE will use to … • Price energy purchases and sales in ISO-NE Market • Price transmission congestion costs to move energy within ISO-NE Control Area • Physical, flow-based pricing system • Prices are based on • How energy actually flows, • NOT contract paths

17. Locational Marginal Price Generation Marginal Cost LMP = Cost of Marginal Losses Transmission Congestion Cost + + Cost to serve the next MW of load at a specific location, using the lowest production cost of all available generation, while observing all transmission limits

18. LMP Model • Price of energy is based on actual operating conditions, as described by state estimator • Price of energy at each location will be calculated and posted on the ISO-NE website at five-minute intervals • Five-minute LMP values will be integrated at end of each hour; hourly value will be posted on website • Accounting settlements will be performed based on hourly integrated LMPs (after LMP verification procedure)

19. LMP Characteristics • Based on … • actual flow of energy • actual system operating conditions • LMPs … • are equal (except for losses) when transmission system is unconstrained • vary by location when transmission system is constrained

20. Locational Marginal Pricing Model(LPA = Locational Pricing Algorithm) Generator Offers LPA Preprocessor System Economic Dispatch Rates Flexible Generating Units & Offers Real-time Data State Estimator Energy Demand Generator MW System Topology LMP’s for all locations LPA LPA Contingency Processor Dispatcher Input Binding Transmission Constraints

21. How will ISO-NE use LMP? • Generators get paid at generation bus LMP • Loads pay a zonal price, which is derived from the load bus LMPs • Transactions pay congestion charges equal to difference between source and sink LMPs

22. LMP Verification Procedure • Purpose - Ensure that LMP values are accurately and completely calculated for each of the 288 five-minute intervals of the previous operating day. • Procedure: • Market Engineers review dispatcher logs, program error logs, input data timestamps and LMP results for each interval. • Recalculate or Replace LMP values as required • Notify Settlements Department that the LMP results are verified and ready to use in accounting. • Post daily LMP file on web by noon next day

23. What are Financial Transmission Rights? • Financial Transmission Rights are … a financial contract that entitles holder to a stream of revenues (or charges) based on the hourly energy congestion cost difference between the source and sink

24. Allocation of FTRS in NEPOOL • In its June, 2000 order, FERC approved an auction of all Financial Transmission Rights, with the proceeds of the auction being allocated to the holders of Auction Revenue Rights • This proposal and allocation will remain as part of Standard Market Design

25. Auction Revenue Rights Allocation • FTR Auction Revenue allocated to: • Those paying for new transmission upgrades to the extent additional FTRs are created • Those paying Congestion Costs • Transmission Customers • Congestion Paying Entities • NEMA Load Serving Entities

26. Why Do We Need FTRs? • Challenge: • LMP exposes Market Participants to price uncertainty for congestion cost charges • During constrained conditions, ISO-NE Market collects more from loads than it pays generators • Solution: • Provides ability to have price certainty • FTRs provide hedging mechanism that can be traded separately from transmission service

27. Characteristics of FTRs • Defined from source to sink • Financially binding • Financial entitlement, not physical right • Independent of energy delivery

28. What are FTRs Worth? • Economic value determined by hourly LMPs in the Day Ahead Market • Benefit (Credit) • Same direction as congested flow • Liability (Charge) • Opposite direction as congested flow

29. Thermal Limit Energy Delivery = 100 MWh FTR = 100 MW Bus B Bus A Source (Sending End) Sink (Receiving End) LMP = $15 LMP = $30 Congestion Charge = 100 MWh * ($30-$15) = $1500 FTR Credit = 100 MW * ($30-$15) = $1500 Energy Delivery Consistent with FTR

30. Bus A FTR = 100 MW LMP = $10 Bus B Bus C Energy Delivery = 100 MWh LMP = $30 LMP = $15 Congestion Charge = 100 MWh * ($30-$15) = $1500 FTR Credit = 100 MW * ($30-$10) = $2000 Energy Delivery Not Consistent with FTR

31. Obtaining FTRs • FTR Auction -- Centralized Market for Obtaining Financial Rights to Transmission • Annual and Monthly Auctions for all available FTRs • Startup - 2 periods of 6 month and Monthly Auctions • Secondary Market -- Bilateral trading • FTRs that exist are bought or sold

32. What is the FTR Auction? • Provides method of auctioning FTR capability that exists on transmission system • Allows market Participants to bid for FTRs and offer to sell existing entitlements

33. Energy Market

34. Spot Market • Voluntary offer-based market • Unit Specific (start-up, no-load, and energy offers) • Slice of external system (energy only) • Offers “locked in” by noon day Ahead • Daily energy offers for generators • Energy pricing based on Locational Marginal Pricing with overlying zones and trading hubs • Central unit commitment (voluntary) and security constrained dispatch (voluntary) • Day-Ahead forward market • Real-time spot market

35. Market Mechanisms • Market supports financial contracts separate from physical spot market • Will settle based on data submitted after the fact, giving Participants ability to arrange sophisticated bi-laterals that ISO-NE will settle • Forward energy market • Trading hubs • Day-Ahead market (Two-Settlement system) • Transmission congestion - hedging mechanisms • External Transactions may specify not willing to pay congestion (ISO-NE curtails) or transactions may self-curtail (with notification) • Financial Transmission Rights • Financial energy contracts

36. Energy Market Options Self-schedule resources External Bilaterals Load Serving Entities obtain energy to serve customers Spot Market Bilateral Transactions with Generators CUSTOMERS Industrial Commercial Residential

37. Energy Market Operations • Day-Ahead Market - create a set of financial schedules that are physically feasible • Re-bid period (4 p.m. to 6 p.m.) for units not accepted in day ahead market • Reliability Scheduling - performed after re-bid period • Reserve adequacy • Transmission security • Regulation Market - evaluate regulation adequacy and set regulation floor price • Real-time Operations - near-term scheduling and real-time, security-constrained economic dispatch

38. Energy Markets • Day-Ahead Market • Develop day-ahead schedule using least-cost security constrained unit commitment and security constrained economic dispatch programs • Calculate hourly LMPs for next Operating Day using generation offers, increment bids, demand bids, decrement bids and external bilateral transaction schedules • Real-time Energy Market • Calculate hourly LMPs from LMPs calculated every five minutes, based on actual operating conditions

39. Energy Settlements • Day-Ahead Market Settlement • Based on scheduled hourly quantities and day-ahead hourly prices • Includes both Energy and FTR Settlement • Real-time Market Settlement • Based on actual hourly quantity deviations from day-ahead schedule using real-time prices

40. Day-Ahead Market Participation • Generation Resources • Submit market-based offers • Submit Self-schedule • Demand • Submit fixed quantity & location • Submit bids for price responsive load • External Transactions • Submit schedules into the day-ahead market • May specify maximum amount of congestion they are willing to pay • Financial • Submit increment offer • Submit decrement bid

41. Day-Ahead Market Mechanisms • Provides Market Participants with the option to ‘lock in’ day-ahead scheduled quantities at day-ahead prices • Provides additional price certainty to Market Participants by allowing them to ... • Commit & obtain commitments to energy prices & transmission congestion charges in advance of real-time dispatch (forward energy prices) • Submit price sensitive demand bids • Inform ISO-NE of maximum congestion charges it is willing to pay • Submit increment offers & decrement bids (virtual demand and supply positions)

42. Day Ahead Energy Market • Day-Ahead energy market is day-ahead hourly forward market • Objective is to develop financially binding schedules that are physically feasible • Full transmission system model • Unit commitment constraints • Reserve requirements model • Day-Ahead market results based on Participant demand bids and supply offers (both physical and financial)

43. Develop day-ahead financial schedules Coordinate financial schedules with reliability requirements Provide incentive for generation to follow real-time dispatch Provide incentive for resources & demand to submit day-ahead schedules Day Ahead Market Objectives

44. Day-Ahead Market Time Line 12:00 noon 4:00 pm ISO-NE posts day-ahead LMPs & hourly schedules 12:00 - 4:00 pm Day-Ahead market is closed for evaluation by ISO-NE Up to 12:00 noon ISO-NE receives bids and offers for energy next Operating Day 4:00 pm 4:00 - 6:00 pm Re-bidding period 6:00 pm Throughout Operating Day ISO-NE continually re-evaluates and sends out individual generation scheduleupdates, as required midnight

45. Unit Commitment Analyses Balancing Market Offer period closes Day-Ahead Market closes Day-Ahead Results Posted & Balancing Market Offer period opens Reserve Adequacy Assessment • focus is reliability • updated unit offers and availability • based on load forecast • minimizes startup and cost to run units at minimum Day-Ahead Market • determines commitment profile that satisfies fixed demand, price sensitive demand bids, virtual bids, and Operating Reserve Objectives • minimizes total production cost Transmission Security Assessment • focus is reliability • performed as necessary starting two days prior to the operating day • based on load forecast 45

46. Day-Ahead Market • Financial model - degree of similarity to physical dispatch is determined by Participant bids and offers • Full transmission model assures revenue adequacy for day-ahead schedules • Economic incentives drive convergence of day-ahead market and real-time market

47. Reserve Adequacy Assessment • Based on load forecast, physical generation assets, actual transaction schedules and full operating reserve requirements • Virtual bids and offers not included • To preserve economic incentives, any additional unit commitment needed for reliability objectives only minimizes cost to come on line (minimize startup and cost to operate at minimum output) and are settled at Real Time Prices

48. Transmission Security Assessment • Based on ISO-NE load forecast of actual system operating conditions • Performed starting 36 hours in advance of operating day and continuing up to real-time dispatch hour • Objective is to ensure reliability and to augment the transmission analysis that is performed in day-ahead market

49. EMS Market User Interface Other Systems Markets Database SPD (EconomicDispatch &Day-Ahead LMP) STCA (SecurityAnalysis) RSC (UnitCommitment) Settlements Database DMT Day-Ahead Market Subsystems

50. Market User Interface • Logging in • Viewing market messages • Submitting generation offers • Submitting demand bids • Submitting increment offers and decrement bids • Submitting redeclarations • Viewing public & private day-ahead results • Managing portfolios • Responding to error messages