CAMBRIDGE ENERGY UPDATES ON GAS AND POWER

---------------------- Forwarded by Vince J Kaminski/HOU/ECT on 10/13/2000
04:23 PM ---------------------------

Margaret Carson@ENRON
10/13/2000 01:43 PM
To: Julie A Gomez/HOU/ECT@ECT, Stephanie Miller/Corp/Enron@ENRON, Vince J
Kaminski/HOU/ECT@ECT, Scott Neal/HOU/ECT@ECT, Jeff Dasovich/NA/Enron@Enron,
Daniel Allegretti/HOU/EES@EES, Mike McGowan/ET&S/Enron@ENRON, Lorna
Brennan/ET&S/Enron@ENRON, Bill Cordes/ET&S/Enron@ENRON, Mark
Schroeder/LON/ECT@ECT, Mark Koenig/Corp/Enron@ENRON, Kathryn
Corbally/Corp/Enron@ENRON, James D Steffes/NA/Enron@Enron
cc:
Subject: CAMBRIDGE ENERGY UPDATES ON GAS AND POWER

The CERA executive roundtable meeting summary results are as follows:
If you are interested in a complete set of the graphs from the
presentations please let me know.

ELECTRIC POWER PART ONE
PEAK TRENDS
It is noteworthy how rapidly volatility can change geographically in the
electric markets. Last year the U.S. Midwest/South areas were the
peakiest, but it reversed this year with the West being highest at
the peaks and in New England -- but only in early May 2000 were hgih
peaks apparent there.

Demand can vary from half the peak max to the max. Peakers can be on the
margin on the upper half of the supply mix in many markets. We need to
watch gas prices this winter as they can effect winter peak power
prices--not just a summer phenomenon.

Where are the most gas plants now on the margin? Ercot, FRCC, Neepool,
NYPP, SERC, WSCC

A DISCONNECT
There is a disconnect in the on-peak forward market price for power in
Texas now; with the added 5 GW Texas forward markets do not seem to
take this into account yet. (Note: Vince Kaminski) The Texas forward
market should be very soft next summer unless we return to 105 degree
F temperatures. New England is just one year behind Texas in its
overbuild.

One main reason for the spikes in Calif is power plants did not get
built in Calif due to a lack of a capacity charge ..and this is not a
panacea...as Calif also has many enviro/siting hurdles that challenge
developers who want to site as well.

.

TSUNAMI OF MERCHANT CAPACITY PLANNED?
CERA sees over 240,000 MW of planned capacity over the 2000-2005
period; with 25,000 MW being completed in 2000; 35 MW under
construction for 2001 and 15 000 MW under construction for 2002-- but
the market only needing 13 000 to 15 000 MW a year. This shall
lead to many and large deferrals and delays, especially in 2001 and
2002. What has been the recent history? US wide over the
past 3 years just 11 percent of the planned capacity was actually
finished and 18 percent of that planned was actually under
construction. They assume a 24 month construction completion time.

FOR PROFIT TRANSMISSION
Cera sees Allegheny Energy in PJM West; Entergy in SPP; Southern in
SERC and Alliant in MAPP as all for profit transcos.
TYPICAL O&M COSTS IN U.S. TRANSCOS
Why do O&M costs differ widely among transcos? Some costs are 3
to 8 times higher than the norm at
$5000 in O&M expense per 5000 system miles in size. Regulatory
overhang allows this...this is weather adjusted to remove high costs
from big freezes etc.

USING REAL OPTION MODEL VS POWER PLANT NPV
You want to try to have the base value of an asset going forward when
you expect volatility and include historical spreads and fuel/power
price swing assumptions.

CALIFORNIA MARKET IS BROKEN
This market starts to work only after it gets into a reliability
crisis. No incentives to add power plant capacity and
huge hurdles against siting even when the market signals the need is
there. Will the regulator's post 2000 fix make it worse?

PEAK POWER DEMAND FORECAST
As percent per year change vs 2000 Cera sees 2001 as follows:
New Eng / New York 6.3 / 6.2 percent
PJM / ECAR 7.7 / 4.4 percent
MAIN / MAPP 3.0 / -0.1
SERC / FRCC 1.3 / 2.3 percent
SPP / ERCOT 4.0 / 2.3
NWPP / Rockies -6.8 / -0.6
AZNM / Calif-SoNV -0.9 / 4.0
USA avg up 2.6 percent It looks like Calif. in in for a touch
summer in 2001 as well.

NATURAL GAS PART TWO
SUPPLY SHORT
Year 2001 supply rebound could be 800mmcfd to 1.0 bcfd; Canada in
2001 up only 400 a day; in the US we need 2 bcfd more supply for
2001 demand. alone let alone storage refill.... yet a
cold winter now could add 3 to 4 bcfd to demand and slash
storages. The fall in drilling in 1999 and early 2000 took 3.5 bcfd
productive capacity out of the supply pool. It will take till 2005
for US production to reach a 4.1 bcfd gain versus today's production.

ADDED GAS FOR POWER PLANTS
Right now Cera expects an incremental need for 1 bcfd next year for
these plants..this will keep prices high

MUCH MORE POWER SWING
1990 to 1992 we needed 5 bcfd for power plant swings; now we need
10 bcfd; offpeak use is even up 5 bcfd vs 10 years ago.

RESI USE IS UP
The AGA disco members adds 750 000 new gas homes each year and
this builds demand year round.

INDUSTRIAL NUG DEMAND
Of the 24 bcfd ( 8.77 Tcf) industrials gas use in the US; 8.6
bcfd ( 3.1 Tcf) of this is for power plant and non-mfg use.

HOW FAST CAN CANADA ADD?
Canada can add 3.6 bcfd by 2005 versus now; adding each year
from 2001 to 2005 as follows: 500/800/900/700/700 mcfd annually.

IS ARCTIC GAS ON THE HORIZON?
Its is far away; maybe 4 or 5 bcfd by 2015.. This means up to
2.7 bcfd to flow to Midwest by 2015 and up to 2.4 bcfd to
Calif./PNW on expansions by 2015.