From: steven.kean@enron.com
To: robin.kittel@enron.com
Date: 2000-08-18 14:23:00+00:00
Subject: Re: FERC INVESTIGATION IN CA - What should they be looking for?

---------------------- Forwarded by Steven J Kean/HOU/EES on 08/18/2000 02:23 
PM ---------------------------
From: Tim Belden@ECT on 08/17/2000 07:34 AM PDT
To: James D Steffes/HOU/EES@EES
cc: Jeff Dasovich/SFO/EES@EES, Mary Hain/HOU/ECT@ECT, Susan J 
Mara/SFO/EES@EES, Mona L Petrochko/SFO/EES@EES, Bruno Gaillard/SFO/EES@EES, 
Sarah Novosel/Corp/Enron@ENRON@EES, Paul Kaufman/PDX/ECT@ECT, Joe 
Hartsoe/Corp/Enron@ENRON@EES, Steven J Kean/HOU/EES@EES, Richard 
Shapiro/HOU/EES@EES 
Subject: Re: FERC INVESTIGATION IN CA - What should they be looking for?  

Here are some more thoughts:
FERC should take a hard look at why the ISO is almost always in an "inc" 
situation in real time.  Without structural incentives to go short into real 
time, I would expect the CAISO to "inc" in some hours and "dec" in others -- 
with no consistent patterns.
The IOU's have four choices for purchasing power:  PX Block Forward, PX Day 
Ahead, PX Day Of, and CAISO Ex Post.  They had ample opportunity to purchase 
lower cost power in the PX Block Forward but didn't buy enough.  That left 
them short in the Day Ahead.  They can reduce Day Ahead prices by moving some 
of their load to the Ex Post market.  Dave Parquet did an Econ 101 
presentation on this incentive at the CAISO board meeting in June.
The ISO remains primarily in "inc" mode even during the shoulder months when 
prices are lower, another indicator that the real time "inc" problem is 
driven by the load side rather than the supply side.  The IOU's continue to 
go short into the ISO Ex Post market even when the CAISO Ex Post price is 
consistently above the PX Day Ahead price.
There is evidence that the IOU's are not willing to pay above the CAISO price 
cap for energy from the PX in the Day Ahead market.  Does it matter that the 
price cap for the ISO also acts as a PX price cap?
The NOx market in California is very tight.  How has this contributed to 
higher costs and has the complete lack of available NOx credits prevented any 
generators from running?
How large was the impact of the below normal water year on the supply side?  
The attached presentation quantifies this effect in the Northwest.  (I have a 
theory on how hydro capacity completely overstates reserve margins in the 
west from an economic perspective.  I can go into more detail if you wish.)
Friction between California PX and ISO markets and other western markets.  
For example, why are actual flows going into the state yet prices out side of 
the state are higher?  Another example of anomylous behavior is at COB on 
8/11 and 8/12.  There was congestion from California TO the northwest those 
days in the Day Ahead market.  In real time the NW ended up being a net 
seller of about 3,000 MW from the NW TO California.
Demand Side - we really need to press on this issue because all of the 
proponents of price caps claim that as soon as the demand side is "workably 
competitive" then there is no need for price caps.  Is large-scale economic 
demand response required for a competitive market?  What if demand response 
is there, but at very high prices?  The demand response in California is a 
joke.  With 2700 MW of interuptible, why did the utilities and the CAISO only 
get around 600 MW of economic demand response.  Much of this response comes 
at $1500/MWh.  The assymetric treatment of supply side resources and demand 
side resources can be justified on environmental grounds, but not economic 
grounds.  So why this assymetric treatment?  This gets to the question of the 
fine line between "scarcity rents" which are ok, and market power which is 
not.  If power is scarce, and demand truly values it at $1500/MWh then 
shouldn't that be the price.  At what price would the rest of the 
interuptible load economically curtail?  Bottom line -- there are about 2,000 
MW of load that should be able to respond to price signals that chooses not 
to or values power at more than $1500/MWh.
Burden of proof -- what empirical measures should be used to assess market 
power?  The reports published to date have been unimpressive.  The Market 
Analysis Unit report, for example, does a bunch of handwaving and then 
concludes that there is market power.  But they never explain why.  I would 
think that proof might be something like this:  Generator X sets price y% of 
the time when loads exceed Z MWs.  Or, four generators set price 80% of the 
time when prices exceed $200/MWh.  They have all the data to be able to tell, 
yet they don't provide any empirical measures.  The only test I've heard of 
so far is the UC Energy Institute report that demonstrates that generators 
are submitting bids above their marginal cost.  The PX report states that 
supply bids are fewer and at higher prices than last year.  They fail to 
mention the fact that there are 5,000 fewer MW of hydro this year relative to 
last.



James D Steffes@EES
08/17/2000 06:18 AM
To: Tim Belden/HOU/ECT@ECT, Jeff Dasovich/SFO/EES@EES, Mary Hain/HOU/ECT@ECT, 
Susan J Mara/SFO/EES@EES, Mona L Petrochko/SFO/EES@EES, Bruno 
Gaillard/SFO/EES@EES, Sarah Novosel/Corp/Enron@ENRON, Paul 
Kaufman/PDX/ECT@ECT, Joe Hartsoe/Corp/Enron@ENRON
cc: Steven J Kean/HOU/EES@EES, Richard Shapiro/HOU/EES@EES 
Subject: FERC INVESTIGATION IN CA - What should they be looking for?

As we begin to meet with FERC Staff on the Wholesale market issues related to 
CA problems, I think that we need to put together a list of questions that 
FERC needs to be asking Western power market participants.  

The following are some questions that I think are important to have FERC ask; 
I'm sure there are more.

1. Were California utilities underscheduling load into the PX day ahead 
market?  
2. How many MWs did the CA ISO procure during each hour during the Summer 
2000?  How does this compare with CA ISO procurement during 1999?
3. Has PG&E changed its bidding behavior associated with its Hydro facilities 
in 2000?  
3. Are there baseload facilities that were operated differently in 2000 than 
in 1999?
4. Were any generation plants off-line due to unplanned maintenance during 
Summer 2000?
5. How did the CA ISO demand side program work?  Why didn't more load 
participate?  
6. What options did SDG&E have to "hedge" its retail rates?  What were prices 
in the CAL PX block forward market on Jan 15, 2000 and May 15, 2000?
7. How high did natural gas prices go in California for generation during 
Summer 2000?
8. Were other Western power markets prices higher (year-on-year)?
9. Did the CA ISO Board face political pressure to reduce bid caps?  Is this 
appropriate for a FERC jurisdictional entity?
10. What specific details is SDG&E referring to in its Complaint on 
"unworkably competitive" CA ISO markets?  Can these be fixed "quickly"?

Please add other questions.

Jim