TEAC17

1. TEAC17 Thursday, July 10, 2003 Radisson Hotel Marlborough, Massachusetts Redacted Version for Posting

2. TEAC17 Agenda • Welcoming Remarks/Announcements • Natural Gas and Fuel Diversity Concerns • Reliability Analysis – Fuel Diversity Results • Environmental – Air Emission Impacts • Congestion Analysis – Additional Sensitivities • Interregional Issues • Transmission Planning Study Update • Resource Adequacy – Locational ICAP Modeling

3. TEAC Announcements • Technical Session • Limited Responses • Since TEAC16 ISO-NE sent MA DTE presentations to TEAC • Planning Studies regarding potential 345 kV Upgrades in Boston, SEMA/RI &CT incomplete • ISO-NE will again gauge interest mid- August

4. TEAC Announcements • Fuel Diversity Working Group Formation • To Draft Scope • Market Rules • Guidance to RTEP • Operating Procedure • Guidance to Regulators • Initial Meeting • August 5th • w/ NEPOOL RC • TEAC Interest • Contact at teacmatters@iso-ne.com by July 25, 2003

5. TEAC Announcements • TEAC18 • Comments on RTEP03 Draft • Draft report will be sent, on August 1st, to those registered and requests made to teacmatters@iso-ne.com. • Meeting to be held on August 14th (Thursday) • Springfield MA location TBA

6. Natural Gas and Fuel Diversity Concerns in New England and the Boston Metropolitan Electric Load PocketMark Babula ISO-NEJuly 10, 2003

7. Executive Summary/Findings • Adequacy of Natural Gas Resource Base • North American Gas Supply Outlook • Outlook in Atlantic Canada • Outlook on LNG Supply and Local Storage • Gas Delivery in New England • Infrastructure Adequacy • Deliverability within the Boston Load Pocket • Gas Pricing and Volatility in New England • Volatility Trends in New England • Electric Sector Impacts from High Prices • New England’s Fuel Mix Portfolio • Fuel Diversity Forecast: NEPOOL & Boston Area

8. Adequacy of Natural Gas Resource Base • Estimate of North American gas resource base = 1,900 Tcf • Equates to 70 years of supply at 2002 consumption levels • Current exploration & production (E&P) on a “treadmill effect” • Drilling has more than doubled from 1996 to 2001, while total average gas production has increased only by 3.1%

9. Adequacy of Natural Gas Resource Base

10. Adequacy of Natural Gas Resource Base Supply/Source 2001 Production Share of Total North Region(Bcf)American Production (%) Gulf Coast 11,612 45 Western Canada 5,981 23 Rocky Mountains 3,644 14 Mid-continent 1,849 7 Other * 1,489 6 Appalachia 758 3 Atlantic Canada 180 1 LNG 238 1 Total 25,751 100% Source = Natural Resources Canada, Canadian Natural Gas 2001 Market Review & Outlook, June 2002 & U.S. EIA/Natural Gas Monthly June 2002; Oil and Gas Journal * Includes Alaska, Pacific Coast, Illinois Basin, Michigan & Ontario

11. Adequacy of Natural Gas Resource Base • N. American depletion rates have increased at an accelerated rate • Production has nearly remained constant since 1990 • Depletion rates have been rising since 1990 • U.S. depletion rate from 16% to 28% • Canadian depletion rate from 16.5% to 23.5%

12. Adequacy of Natural Gas Resource Base

13. Outlook in Atlantic Canada • Current production from the Scotian Shelf is small in comparison to Gulf Coast & Western Canada • 0.5 Bcf Scotian vs. 27.2 Gulf & 16.2 Western Canada • Scotian shelf is in its infancy • Less than 200 wells drilled • Currently supporting roughly 20% of New England’s gas needs

14. Outlook in Atlantic Canada • Pipeline infrastructure poised for expansion • EnCana has taken a regulatory “time-out” • Next tranche of gas production likely in the 2008 – 2010 timeframe • Scotian gas will flow to New England through 2020

15. Outlook on LNG Supply & Storage • LNG is a globally traded commodity • Pacific rim is heavily dependent on LNG • Over 850 Tcf of reserves: Qatar (500 Tcf), Algeria (160 Tcf), Nigeria (124 Tcf), Trinidad (25 Tcf) • LNG set for major worldwide expansion – 150 tankers by 2005 • Deep pockets required to play this game • Only 4 terminals in US: Everett, MA = DOMAC/Distrigas Elba Island – GA / Lake Charles – LA / Cove Point - MD • Total LNG sendout from all facilities = 1,050 Bcf by end of 2003

16. Outlook on LNG Supply & Storage • Poor geology in New England for underground gas storage – thus above ground LNG tankage • Almost all of New England’s supply is from Trinidad • Distrigas storage capability = 3.5 Bcf • 14 other major satellite facilities around New England • Manufacture on-site & truck shipments • Total New England LNG storage capacity = 15.1 Bcf • Mystic 8 & 9 – sole fuel source is Distrigas LNG • Distrigas – susceptible to common-mode failures ?

17. Gas Delivery in New England • 5 major interstate pipelines • Proximity to Sable Island is a plus for New England • New projects include M&N Phase III & Hubline • Proposed projects: Deer Island Lateral & Everett Extension = A path to Mystic 8 & 9 & Distrigas

18. Gas Delivery in New England • Pipeline capacity still cannot serve coincidental winter loads • Phase I Gas Study: steady-state analysis • Phase II Gas Study: transient analysis • By winter of 2004/2005, “generation-at-risk” approx 2,800 MW – 3,900 MW • ISO-NE analysis had “idealized” assumptions about border gas supply

19. Winter Capacity (MW) of Gas Capable Units Includes 2003 units: AES GRANITE RIDGE, MILFORD PDC, SITHE FORE RIVER, SITHE MYSTIC Information Source: 2003 NEPOOL CELT Report, April 2003

20. Gas Delivery in New EnglandWinter Peak Day Gas-Fired Generation at Risk (MW)

21. Gas Delivery in New EnglandGas-Fired Generation Capacity Served by Pipeline (MW) (Winter 2004/2005)

22. Gas Delivery in Boston Load Pocket • KeySpan is the LDC for deliveries to in-city generators • Mystic 8 & 9 – single fuel = LNG • Everett Extension from Deer Island will provide operational flexibility and backup supply into Algonquin’s J system, esp. during winter • Salem Harbor could get access to pipeline gas

23. Gas Pricing and Volatility in N. England • Increased volatility at Henry Hub/Dracut due to: • Maturation of resource base • Growing demand from electric sector • Depletion of working gas storage • Concern over storage injections for upcoming winter • “Demand Destruction” – price will equalize this winter’s supply vs. demand imbalance i.e., trigger fuel switching

24. Gas Pricing and Volatility in N. England • Growing off-peak demand by electric sector will compete with LDC injection gas for reservoir replenishment • High prices through summer & fall and into winter 2003/2004 • Volatility hear to stay until new gas supplies commercialized in upcoming years

25. Gas Pricing and Volatility in N. EnglandComparative Fuel Costs Delivered to N.England Generators

26. Gas Pricing and Volatility in N. England • Wholesale electricity prices linked to natural gas prices • High gas prices affect dispatch of generation mix • RFO can be economically substituted for gas at dual fuel steam units. However, these units are losing market share due to superior transformation efficiencies of the new merchant CC units • Over 50% of all LMPs set by gas units • Salem Harbor on gas would probably increase wholesale electric prices in the Boston sub-area

27. Gas Pricing and Volatility in N. England Real Time Marginal Price Setter by Fuel Type(Source = ISO-NE Quarterly Markets Reports, Public Version)

28. Gas Pricing and Volatility in N. EnglandReal Time Marginal Price Setters by Unit Type(Source = ISO-NE Quarterly Markets Reports, Public Version)

29. Fuel Diversity in New England • Steady-State Analysis of New England’s Interstate Pipeline Delivery Capability, 2001-2005 (Phase I – Jan 2001) • Steady-State and Transient Analysis of New England’s Interstate Pipeline Delivery Capability, 2001-2005 (Phase II – Feb 2002) • RTEP02 (November 2003) & RTEP03 (ongoing) • Natural Gas and Fuel Diversity Concerns in New England and the Boston Metropolitan Electric Load Pocket (July 2003) • IMO Multi-Regional Gas Study (targeting completion – Sept 2003) • Related reliability analyses: Loss of nuclear & gas units

30. Fuel Diversity in New England • Recent build-out of merchant generation will yield approx 10,700 MW of gas-fired capacity being commercialized by 2005 • In 1999, gas-fired generation equaled 16% to total New England electric energy production • By 2003, natural gas will fuel 41% of overall energy production • By 2010, natural gas will fuel 49% of overall energy production • Other than the state of Texas, New England is by far the most dependent region in North America on gas for power generation

31. Fuel Diversity in New EnglandNERC Region Comparison: Generation by Fuel as % of Total (2002)(Source = EIA – Long Term Energy Forecast Supplemental Tables)

32. Fuel Diversity in Boston Load Pocket • Boston Import sub-region is transmission constrained • Once Mystic 8 & 9 are commercialized, with Salem Harbor continuing to operate on coal & oil, natural gas accounts for 65% of all energy production in the Boston sub-area • By 2010, reliance on natural gas will reach 80% (energy) • If Salem Harbor were converted to fired gas, natural gas will fuel 94% of Boston sub-area energy production • Boston’s gas requirements for electric power generation depend upon both pipeline gas & LNG

33. Fuel Diversity in Boston Load Pocket • Salem Harbor accounts for 85% of the total capacity in the North Shore sub-area • Coal fired units usually committed in-merit order and help satisfy both North Shore must-run requirements and Boston Import area operating reserve requirements • Salem Harbor needs to comply with MA 310 CMR 7.29 air regs • ISO-NE assessing reliability implications from the 18.4 Applications to retire Salem Harbor station, Mystic 4, 5 & 6, and New Boston

34. White Paper Findings – Where to from Here? Changes to State Statutes Market Rule Changes Gas Study Findings Task Force RTEP Projects • ISO-NE Lead • NECPUC Rep. • NEPOOL Rep. NERC/NPCC/ NEPOOL Reliability Rule Changes Possible Outcomes

35. Executive Summary/Findings 1. Between 1998 – 2005, 10,700 MW of new gas-fired generation will become commercialized • In 1999, 16% of New England’s electric energy production was by natural gas • In 2003, 41% of energy production by gas • By 2010, 49% of energy production by gas • Other than the State of Texas, New England is 2nd most dependant region in North America on naturalgas for power generation • The transmission constrained metropolitan Boston Area is highly dependant on gas-fired generation • Natural gas accounts for 65% energy production in sub-area (post commercialization of Mystic 8 & 9) • Increased reliance to 80% by 2010 • If Salem Harbor converted to gas, 94% reliance by 2010

36. Executive Summary/Findings 3. E&P in the Gulf Coast and Western Canada are experiencing maturation of traditional supply basins • Depletion rates accelerating (1990 – 16%, 2002 – 28%) • Resource base remains immense, however, sustained production improvements will require massive investments, thus anticipating; higher commodity prices, increased price volatility, and higher trading bandwidths 4. The increase in gas production in Atlantic Canada will be delayed • E&P around Sable Island has encountered significant set-backs, however, the supply basin is still in its infancy • Next wave of supply unlikely to materialize before end 2008, probably by 2010 • New England utilities and merchant generators will incur a premium to obtain incremental gas supplies from Gulf Coast orWestern Canada

37. Executive Summary/Findings 5. New England’s increasing dependence on gas exposes ratepayers to the impacts of high prices and volatility • Wholesale electricity prices linked to value of natural gas, I.e. spark spreads • Distrigas LNG helps tempers the run-up in winter basis differentials • Distrigas figures prominently in maintaining energy security (electric & gas) 6. Prior ISO-NE gas infrastructure analyses indicate that there is not sufficient pipeline capacity within New England’s borders to meet coincidental gas requirements of gas utilities and merchant generators during the coldest part of the winter heating season • ISO-NE Phase I Gas Study (Jan 2001) - Steady-state analysis • ISO-NE Phase II Gas Study (Feb 2002) - Transient analysis • By winter of 2004/05, 2,800 MW to 3,900 MW of unserved generation • Dual & liquid fuel generation is required to makeup winter unserved shortfalls

38. Executive Summary/Findings 7. Energy security in the Boston sub-area is critically dependent on LNG from Distrigas • A postulated loss of LNG from Distrigas during the winter heating season would impair regional energy security, both gas & electric • No other power plant in U.S. or Canada is currently dependent on LNG for ALL of its fuel supply - however - heavily utilized in Pacific rim • Existing pipeline capacity on Tennessee and Algonquin during winter cannot replace LNG deliveries to Mystic 8 & 9 • Mystic 8 & 9 capacity becomes increasingly important as older fossil steam units are pressured to retire within the Boston sub-area • The proposed pipeline expansion projects, Deer Island Lateral and Everett Extension, would provide two important functions: • Another pathway to Mystic Station to provide a secondary fuel source • An alternative send-out path to reach Algonquin system via Hubline

39. RTEP03 Fuel Diversity Analysis TEAC17 Presentation July 10, 2003 Peter Wong ISO-NE Power Supply & Reliability

40. Fuel Diversity Analysis The objective of this analysis is to investigate the impact on system resource adequacy due to different potential fuel shortages, covering 2003 through 2012, assuming: • Fixed NEPOOL generation capacity mix • Currently known transmission constraints • No change in bid strategy or behavior.

41. Fuel Diversity Analysis The analysis simulated system conditions on an annual basis to facilitate system modeling. Annual simulations allow results to be tabulated in various forms (annual, seasonal, monthly, etc.) as deemed appropriate.

42. Fuel Diversity Analysis Two types of impact on the NEPOOL bulk power system were conducted for this analysis, assuming shortages of nuclear, coal, oil, natural gas and hydro: • Impact on NEPOOL LOLE • Impact on NEPOOL energy needs

43. Fuel Diversity Analysis System load, generating capacity and static transmission interface limit assumptions are consistent with RTEP03 MARS (reliability) and IREMM (congestion) simulations. These assumptions are summarized in the following slides for reference.

44. 2003 New England Annual Peak Load Forecast 50 and 10 Percent Chance of Exceeding (MW)

45. 2003 RTEP Sub-Area Peak Load Forecast 50 Percent Chance of Exceeding (MW)

46. 2003 RTEP Sub-Area Peak Load Forecast 50 Percent Chance of Exceeding (MW)

47. Installed Capacity Forecast (Summer) • The base case annual installed capacity for the period 2003 through 2012 is 31,093 MW (summer rating). • This amount reflects the assumption that 3,452 MW of new units will be installed by June 1, 2003. • It also reflects that 564 MW of unit attritions assumed as of June 1, 2003.

48. Unit Addition Assumptions Summer Rating (MW) AES Granite Ridge (NH)678 Milford Units 1 + 2 (SWCT)490 Mystic Units 8 + 9 (BOSTON) 1,414 Fore River (SEMA) 700 English Station 7 + 8 (CT) 70 Great Northern Hydro (BHE)100 Total 3,452 All assumed in service by June 1, 2003

49. Unit Attrition Assumptions Summer Rating (MW) Devon 7 and 8 (SWCT) 214 New Boston 1 (BOSTON)350 Total 564 All assumed retired on June 1, 2003

50. Generating Unit Availability • Generator unit availabilities are based on 5-year average of historical data (1998 - 2002). • Data Sources are as follows: • NABS for 1998 thru April 1999. • ISO Short Term Generator Outage Data Base for May 1999 thru April 2000. • ISO Unit Availability Database for May 2000 thru December 2002.