Interim January 2004 Cold Snap Report

1. Interim January 2004 Cold Snap Report Robert Ethier, Ph.D. Director, Market Monitoring May 14, 2004

2. Structure of Interim Cold Snap Report • Overview of New England Power System and Markets • Overview of New England Gas System and Markets • Narrative of January 14-16 Events • Analysis of Market Behavior and Results • Electricity and Fuel Prices • Supply Offers from Gas Units • Economic and Physical Withholding • Other Analysis, Including Out-of-Merit Operation • Conclusions and Recommendations • Appendices

3. Key Findings • Electricity and gas markets performed reasonably well • Availability of gas for non-firm generation customers affected gas unit availability: • Gas units typically relied on intra-day gas • Few gas units committed in the day-ahead electric market • Dual-fuel units had much better availability than gas-only units • No evidence of anti-competitive behavior • No evidence that economic outages approved by ISO-NE exacerbated reliability issues or resulted in increased electricity clearing prices

4. Key Findings (cont.) • Supply offers for gas-fired units were affected by timing inflexibility of electric market • Electricity markets provided only weak incentives for units, especially gas units, to be available during the Cold Snap

5. 20 15 10 2004 Temperature (F) 5 0 - 5 - 10 1984 1971 2004 1994 1965 1988 1974 1983 1996 1986 1963 1973 2000 1979 1962 1991 1989 1992 1967 1998 1960 1980 1993 1990 1968 1976 1981 1982 1961 2003 1970 1997 1977 1999 1972 1966 1987 1969 1964 1985 1975 1978 1995 2001 2002 New England Cold Temperature HistoryJanuary saw the sixth coldest temperatures in 45 years.

6. Electricity and Gas Prices • Electricity and gas prices were highly volatile • Electric price variation between load zones in the Day-Ahead and Real-Time Markets was small • Price rise consistent with the underlying conditions in the electric and gas markets • Electric • Highest electricity prices resulted from a capacity deficiency • General price rise resulted from a sharp increase in gas unit marginal costs • Gas • High gas prices occurred in a period of exceedingly high gas system utilization and extreme operating conditions

7. Electricity and Gas PricesNew England Hub Averages

8. Daily Average Day-Ahead Natural Gas Prices in New England at Select Hubs

9. Daily Oil Price Indexes: Select Locations

10. Implied Heat Rates During Cold Snap Day-Ahead Electricity vs. Day-Ahead Natural Gas

11. Gas Market Constraint Issues • Interstate pipelines issue Operational Flow Orders (“OFOs”) in the event of deliverability constraints to protect the physical integrity of pipelines • OFOs notify gas customers or “shippers” that they must conform with maximum daily or hourly quantities in the pipeline’s tariff • Failure to stay within tolerance levels can result in penalties up to five times the daily spot market price (for LDC customers) • Even merchant generators with firm transportation capacity are at risk of not being able to conform with tolerance levels given dispatch patterns of units • Implied heat-rate calculations, therefore, may overstate a generator’s true expected profitability

12. Trading and Scheduling Timelines • Deadlines and inflexibilities in the electricity and gas markets, combined with limits on the ability of participants to update offers in the electricity market, require participants to either: • Take a position in the gas market while uncertain of electric market obligations, or • Reflect uncertain gas costs and availability in electric market offers • While these conditions are always present, the problems became especially acute during the Cold Snap

13. Electric and Gas Days Not AlignedFormulating supply offers becomes a ‘guessing game’ during periods of tight gas supply.

14. Gas Price Behavior • Gas and electric market schedules, price uncertainty and gas consumption restrictions, up to curtailment of gas shipments, create a highly complicated environment in which to formulate electric market offers • These conditions should be expected to be reflected in the electricity supply offers from generators

15. Gas Unit Availability: Weather-related and Fuel-related OutagesFuel-related outages decreased despite falling temps

16. Gas Unit Availability: Firm vs. Non-Firm Arrangements • 40% of New England’s gas-fired capacity associated with some type of firm gas delivery contract • Units with firm gas arrangements had higher availability (56%) than units with non-firm arrangements (42%) • Units with firm gas still experienced outages due to lack of fuel, in part, because they sold firm fuel

17. Gas Arbitrage • Expected power prices were lower than expected production costs • Some generators sold firm gas back into the gas market • Arbitrage improves market efficiency by allocating resources to those who value them most • Gas sold by generators might be sold to other more efficient generators or to local gas companies

18. Market Power Analysis • Review of generation reveals low concentration of ownership • Residual Supply Index (RSI) showed many hours with at least one pivotal supplier • Benchmark analysis compares actual LMPs with estimated LMPs that would have occurred if every unit offered its estimated marginal cost • Most load (at least 73%) was hedged in January

19. Gas Unit Offers at Maximum Normal Output (EcoMax) January 12 - 18, 2004

20. Economic Withholding Analysis • Economic withholding evaluation tests for a “high” offer price • Analysis was based on published day-ahead gas prices plus variety of assumptions about imbalance charges and risks • At least 80% of gas generator supply offers at Economic Maximum (EcoMax) each day are within the $100 threshold after including estimates for imbalance charges, spot market premiums and uncertainty • Of this, 50% of gas generator supply offers are consistent with day-ahead prices and the $100 threshold

21. Generator Questionnaire Results • Generators confirmed submitted offers often reflected costs and risks beyond those suggested by day-ahead gas prices • Responses include: • LMP forecasted below cost of generation • Electric energy prices would not cover the cost of fuel • Offers based on expected intra-day prices for gas • Largest risk premium is that we must commit to purchase gas before we know whether the electric offer is accepted

22. Economic Withholding Analysis Conclusions • Evidence insufficient to conclude that generators, through “high” offers, sought to manipulate the market • Data are consistent with risk-averse generators seeking to incorporate high levels of risk into electric supply offers • Any attempted withholding by gas-fired generators is unlikely to have influenced LMPs because these units were not infra-marginal

23. Pivotal Suppliers Total Portfolio MW ActualParticipant Offer Unavailable Portfolio % of Portfolio Unavailable Total Gas MW in Portfolio Unavailable Gas - MW % of Gas Portfolio Unavailable January 14, 2004 Hour Ending 6 p.m. 15,102 12,115 2,987 20% 4,109 1,809 44% January 15, 2004 Hour Ending 7 p.m. 15,102 12,122 2,980 20% 4,109 905 22% January 16, 2004 Hour Ending 7 p.m. 15,102 12,052 3,050 20% 4,109 749 18% Non-Pivotal Suppliers January 14, 2004 Hour Ending 6 p.m. 17,538 11,598 5,940 34% 6,223 3,995 64% January 15, 2004 Hour Ending 7 p.m. 17,538 12,127 5,411 31% 6,223 4,145 67% January 16, 2004 Hour Ending 6 p.m. 17,538 14,275 3,263 19% 6,223 2,811 45% Physical WithholdingPivotal and Non-pivotal Suppliers

24. Availability of Dual Fuel Units

25. Economic Outages • Ten economic outages were requested and approved on January 13 for January 14, totaling 2,405 MW • All economic outages were requested by gas-only units and were located in New England’s export constrained zones: • Southeastern, MA (Six units) • Maine (Two units) • Rhode Island (Two units) • All economic outages cancelled at 10 a.m. on January 14 • One unit was able to return immediately and three returned by January 15 • Outages were likely not used to withhold capacity from the market

26. Economic Outages: ISO Scheduling • NEPOOL OP-5 governs outage scheduling • ISO approved most of the 10 outages after 9 am on January 13th • The granting of economic outages did not impact reliability beyond January 14th and may not have contributed to reliability concerns on the 14th

27. Operating Reserve Payments and Out-of-Merit Operation • Large gap between LMPs and the offer prices of the units receiving Operating Reserve (OR) payments • For reliability purposes, excess capacity levels are committed out of merit at a unit’s economic minimum • Not eligible to set LMPs at economic minimum • Units committed for pool-wide reserves • Contributes to insufficient price signals to gas-fired generators, inefficiently low LMPs • Practice serves to lower LMPs and increase operating reserves

28. Day-Ahead Market ActivityAverage Day-Ahead Generation Cleared as a Percent of Real-Time Load Forecast, Jan. 11-17

29. Day-Ahead Market ActivityWillingness to Pay for the Peak Hour of Each Day

30. Report Conclusions • Electric and gas markets worked and reliability was maintained • Analysis revealed many areas for improvement in four categories • System Operations and Reliability Issues • Market Timelines and Flexibility • ISO Operations and Implementation • Market Monitoring and Analysis

31. System Operations and Reliability: Issues • Outage reporting • Improved coordination with the natural gas pipelines • Additional dual-fuel capability • Actions to improve unit cold weather operations problems • Adoption of adequate market incentives • Scope of economic outages

32. System Operations and Reliability: Recommended Actions • Clarify and review OP-5 economic outages • Increase coordination with gas industry representatives and update gas study • Review operating reserve providers and quick-start units • Review of outage notifications • Inventory dual-fuel units • Review incentives and permitting issues associated with increasing dual-fuel capability • Evaluate modifications to the ICAP rule/UCAP calculations • Continue to seek resolution to commitment practices and LMP setting to ensure appropriate price signals • Review procedures for establishing transfer limits and evaluate disincentives to scheduling imports

33. Market Timelines and Flexibility: Issues • Day-ahead electric market timeline • Must also consider day-ahead commitment of needed resources • Electricity market offer inflexibility • Risk and uncertainty faced by gas-fired units • Accurate market signals are most critical in extreme circumstances

34. Market Timelines and Flexibility: Recommended Actions • Quantify additional gas that could have been made available • Investigate synchronization of trading deadlines • Evaluate ways to increase supply offer flexibility • Consider how to incent generators to make day-ahead gas purchases and transportation nominations

35. ISO Operations and Implementation: Issues • ISO lacks formal mechanism to communicate with the gas industry • Deadline to approve economic outages • Load and resource availability forecasting methods • Communication with state regulatory authorities and the public concerning potential OP-7

36. ISO Operations and Implementation: Recommended Actions • Working with the Northeast Gas Association, ISO should develop a protocol for gas pipeline/ISO communications • Evaluate revisions to the NEPOOL Information Policy • Revise economic outage provisions of OP-5 • Review short-term load and supply forecasting assumptions • Establish agreed upon protocols and procedures with state regulators for announcing unusual emergency actions

37. Market Monitoring and Analysis: Issues and Recommended Actions • Improve evaluation of unit offers through reduced risk, increased market flexibility and enhanced coordination • Coordinate market monitoring efforts with other jurisdictional agencies • Incorporate lessons learned into the monitoring of future events • Investigate out-of-merit operations • Continue and improve coordination with other monitoring entities to ensure adequate monitoring during critical periods

38. Next Steps • Report is “Interim” – issued on May 10 • Comments will be accepted through June • Please send comments, Attention: Cold Snap Comments, via: • Email: ejohnson@iso-ne.com • Fax: (413) 535-4379, or • Mail: ISO-NE, One Sullivan Rd., Holyoke, MA 01040 • Final report will be issued in September after review of Fuel Diversity Working Group and ISO/NEPOOL Cold Snap Task Force Recommendations