MR 17 Discussion

1. MR 17 Discussion Bob Ethier, ISO-NE NEPOOL Markets Committee Westborough, MA April 17, 2002

2. Commission Staff Guidance • Pre-filing meeting 4/11 on RMR Amendments to MRP 17 • Outlined rule as approved by MC • Outlined generator alternative and NPC motion to table

3. Commission Staff Guidance • FERC Staff reaction • Encouraged development of CT Proxy option • Noted that existing precedent is not the “final word” • PJM approach not sufficient • Apparent interest in MISO proposal (150% of Reference price or LMP average) • Standard market design guidance will come later • Staff sees Commissioners as • Ready to referee policy issues • Not expecting NPC consensus on “hard” issues • Very concerned about incentives for new investment

4. Plan for Action • ISO will lead Markets Committee discussion of alternative proposed rule • New “Proxy CT” screen price for areas identified in advance • Mitigation agreements available only for units with incremental operating costs above “Proxy CT” screen price • Cost-of-Service option still available • Default measures for infrequent constraints

5. Alternative Proposal • Idea: Limit offer mitigation in congested areas to cost of alternative solution for alleviating constraint • Caveat: Idea fleshed out by ISO Staff for discussion only • Calculate ‘Constraint Relief Offer Mitigation’ price (CROM) • Per MWh CROM would be marginal production cost of generic CT plus all net fixed costs levelized over hours during which a constraint has been binding • CROM would mean that all offers in constrained areas below CROM threshold would not be mitigated • Offers above threshold would be mitigated to MC+10%

6. Alternative Proposal: An example • CT capital cost of $72k/MW-yr • ICAP revenues of $14k/MW-yr • Reserve market revenues of $4k/MW-yr • Assume CT only runs for congestion and reserves • If reserve payments reflect opportunity costs, unit should be indifferent between providing reserves and energy • Net fixed cost requirement of $72k-$14k-$4k=$54k • This fixed cost requirement is divided by the annual number of constrained hours for each interface to determine the interface-specific CROM

7. Alternative Proposal: An example • Calculation of CROM for a range of annual hours for which a constraint is binding:

8. Alternative Proposal: Some questions • Will congested areas always pay CROM price? • If congestion is uncertain, generators must balance offering at CROM price with foregoing potential in-merit revenues => incentive to offer below CROM price, though not at MC • Presence of one or more competitors will provide competition (assuming each has MC below COMF) • Will generators be limited to CROM revenues? • No, potentially will receive LMPs above CROM on days of high pool prices

9. Alternative Proposal: Some questions • What about interfaces which are seldom constrained? • Probably should have a limit on the minimum annual hours used for CROM calculation • Special rules for transmission maintenance or infrequent constraints which cause temporary congestion (NYISO plan?) • What number of annual hours should be used? • A three year average of hours the interface is constrained • Can units game the system by extending minimum run times, low operating limits, etc.? • Annual hours used in COMF calculation could be hours that units ran for congestion in each area, or physical parameters requirement.

10. Questions and Discussion