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

2. 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

3. Pipelines & Supplies

4. New England Pipelines PNGTS M&NE TGP Hub Line Iroquois AGT TGP 50 10050
100
Scale in Miles

5. 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)

6. 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)

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

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

9. Storage

10. 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

11. Markets & Capacity Economics

12. 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.

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

14. Today’s Peak Hour Capacity Needs – Hot Summer

15. Today’s Peak Hour Capacity Needs – Cold Winter

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

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

18. 2001-2002 Total Gas Market/Supply Balance – Cold Year

19. 2001-2002 Total Gas Load Duration Curve – Cold Year

20. 2001-2002 Total Gas Load Duration Curve – Warm Year

21. 2004-2005 Total Gas Load Duration Curve – Cold Year

22. 2004-2005 Total Gas Load Duration Curve – Warm Year

23. 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.

24. Prices

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

26. 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)

27. 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)

28. 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.

29. Discussion