---------------------- Forwarded by Scott Neal/HOU/ECT on 10/17/2000 12:11 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.