New England Gas Overview Elements of the System Gas Price Considerations Discussion Presented by: Chris Fleming Vice President - Asset Optimization Sithe Energies, Inc.

Elements of the System Pipelines and Supplies Storage Markets Capacity Who controls it? Storage Capability to store gas in the region Markets Electric Power Generation Traditional LDC Markets Combined Market and Capacity Economics

Pipelines & Supplies

New England Pipelines PNGTS M&NE TGP Hub Line Iroquois AGT TGP 50 100 50 100 Scale in Miles

2001 Sources of Gas 12.5 % 22.5% 65.0 % Western Canadian (Alberta) Eastern Canadian (Sable Island) 2001 3,500,000 DTh/day 12.5 % 22.5% Domestic & W. Canadian LNG W. Canadian 65.0 % Domestic Domestic Sources of Gas (Delivery Capacity)

2004 Sources of Gas 11.0 % 34.0% 55.0% M&NE Line Expansion 4,100,000 DTh/day 11.0 % 34.0% LNG 55.0% Sources of Gas (Delivery Capacity)

Who Controls Gas Delivery Capacity? 3,500,000 DTh/day LNG Canadian Domestic 2001

Who Controls Gas Delivery Capacity? 4,100,000 DTh/day LNG Canadian Domestic 2004

Storage

Regional LNG Storage Distrigas controls terminal, LDCs control storage LDC Stg 14,200,000 DTh Terminal Stg 3,500,000 DTh Ship Cap 2,800,000 DTh Vaporization capacity in New England will soon exceed 2,000,000 DTh/day. 50 100 Scale in Miles

Markets & Capacity Economics

TURBINE-BASED PLANTS BY YEAR ONLINE 1,000 2,000 3,000 4,000 5,000 6,000 7,000 1999 or Prior 2000 2001 2002 2003 Capacity, MW Dual Fuel Natural Gas Only 1,866 2,420 3,441 4,752 3,330 Source: New Energy Ventures, Inc.

Locations of New CC-Powerplants Dual Fuel (Gas & Oil) Natural Gas Only Source: Energy Ventures Analysis, Inc. (10/00 Study)

Today’s Peak Hour Capacity Needs – Hot Summer

Today’s Peak Hour Capacity Needs – Cold Winter

Today’s Gas Needs* for CC-Power Generation * Heat rate of 7,200 BTU/kwh assumed for cc-power plant operation, on average

Today’s Gas Needs* for Traditional LDC Markets * Firm requirements only. Does not include interruptible markets.

2001-2002 Total Gas Market/Supply Balance – Cold Year

2001-2002 Total Gas Load Duration Curve – Cold Year

2001-2002 Total Gas Load Duration Curve – Warm Year

2004-2005 Total Gas Load Duration Curve – Cold Year

2004-2005 Total Gas Load Duration Curve – Warm Year

Capacity Economics Capacity cost is high at low load factors. Significant capacity likely to remain in hands of marketers. Firm capacity from M&NE expansion may be contracted to NY, PJM gencos.

Prices

Backflow from Sable will flatten average price differentials between New England and New York ------ Dracut Hub

October 2001 Bidweek Basis Differentials Source: NGI Weekly Gas Price Index AECO-C 0.67 0.30 0.37 Dracut Chicago - .07 PG&E 0.30 0.64 NY / NJ Opal 0.30 0.00 The prices of month ahead contracts in New York and New England are close at present. Henry Hub ($1.87)

January 2001 Bidweek Basis Differentials Source: NGI Weekly Gas Price Index AECO-C 11.31 7.14 3.43 Dracut Chicago - 5.31 PG&E 7.96 2.14 NY / NJ Opal 8.89 1.01 But basis differentials and the base cost of gas can vary dramatically, depending on the weather and wellhead availability. Henry Hub ($9.92)

When it gets cold, prices can be expected to spike and availability may even become constrained if capacity is contracted outside the region. ? This suggests a growing need for peakshaving mechanisms in New England.

Discussion