Re:

---------------------- Forwarded by Scott Stoness/HOU/EES on 04/03/2001 09:42
AM ---------------------------

Scott Stoness
04/03/2001 09:25 AM
To: Harry Kingerski/NA/Enron@ENRON
cc: Don Black/HOU/EES@EES, James W Lewis/HOU/EES@EES, Tamara
Johnson/HOU/EES@EES, Jeff Dasovich/NA/Enron@Enron, James D
Steffes/NA/Enron@Enron, Dave Roberts/HOU/EES@EES
Subject: Re: Draft Testimony re PGE/SCE for Discussion

Harry. Tamara is finishing a model that give impact according to rate
design.

It is far more difficult to model the effects of behaviour change that will
ocur with higher prices in the summer. I spoke with David Roberts (EAM) and
ran this structure by him and he is of the same opinion as I that:
Very high rates from 12noon to 6PM do not encourage DSM because:
The risk of installing capital in time for June,July, Aug, Sep is significant
when the timing is short and each month lost decreases the value of the
investment by 1/4
Very high rates from 12noon to 6PM will result in behaviour changes by
changing behaviour more than DSM. ie. They will turn up the temperature for
these hours.
Very high rates for 12noon to 6PM encourage curtailment activities but not as
much load shifting. ie a 2 part rate would encourage doing your annual plant
turnaround in Aug ($250/MWh signal) more than the CPUC proposal for August
($110/MWh signal).
Very high rates starting in June, would be difficult to optimize, given the
lack of certainty today about whether the rates will be pasted and the short
lead time.

The rate design I have proposed below gives large price signals in the summer
and the winter, than those proposed by CPUC, while lessening the impact to
Enron tariff book.

Price Signals Comparison

Summer
(PGE=Jun-Oct, SCE=May-Sep) Summer Winter Winter
CPUC Proposal On Peak - 12noon to 6PM WD Off Peak On Peak Off Peak
PGE E19 Secondary $370/MWh $75/MWh $75/MWh $75/MWh
SCE TOU 8 Secondary $145/MWh $122/MWh $122/MWh $122/MWh
2 Part RTP Proposal
PGE E19 Secondary $290/MWh based on Apr 1 NP15 $150/MWh based on Apr 1 NP15 $180/MWh based
on Q4 Apr 1 NP15 $131/MWh based on Q4 Apr 1 NP15
SCE TOU 8 Secondary $157/MWh based on Apr 1 SP15 $122/MWh $156/MWh based on Q4 Apr 1
NP15 $98/MWh

Lets see if we can get together with the DSM people today.

Scott

From: Harry Kingerski@ENRON on 04/03/2001 07:40 AM
To: Scott Stoness/HOU/EES@EES
cc: Don Black/HOU/EES@EES, James W Lewis/HOU/EES@EES, Tamara
Johnson/HOU/EES@EES, Jeff Dasovich/NA/Enron@Enron, James D
Steffes/NA/Enron@Enron
Subject: Re: Draft Testimony re PGE/SCE for Discussion

I still think it is imperative that we use our book position, by rate
schedule and time period (on-peak, off-peak) , to quantify the sensitivity to
different types of rate designs. For instance, if there is a large increase
in summer on-peak, how much of the increase can we avoid with aggressive DSM,
etc. Can we look at this quantification today?

Scott Stoness@EES
04/02/2001 09:34 PM

To: James W Lewis/HOU/EES@EES
cc: Don Black, Tamara Johnson/HOU/EES@EES, harry kingerski
Subject: Draft Testimony re PGE/SCE for Discussion

Harry and I are meeting tomorrow. I would like any feedback you have related
to the following:

Based on our position we would prefer:
Later surcharges
Lower surcharges
Surcharges that are lower in the summer (flatter is better because it is
closer, the NPV effects and our rapidly diminishing position)

The proposal below could either result in:
Delay of a month while they consider this complicated affair (low likelihood)
Lower surcharge if we can convince people that market rates are $300/MWh for
a year when they are actually $200. We would only get a $20/MWh increase, as
compared to a $30/MWh increase. ie (1-90%) times $300/MWh yields $30/MWh is
our story when the actural is (1-90%)times $200/MWh yields $20/MWh.
The Enron rates below are effectively much flatter than the CPUC proposal.
Thus we would be better off if accepted.
Additionally if our noise causes a flat $30/MWh increase to replace the CPUC
proposal, we are better off.

Additionally,
we could sell hedging on the 10% exposed to markets.
DSM related to capital investments should be less risky.

The risks to Enron are:
Proposal makes it easy to hit the large customers with a lower baseline (ie
75% instead of 90%)
Would make DSM more risky. DSM providers would have to buy hedges to proceed.

The questions to answer are:
Could Enron provide witnesses without drawing more negatives
Would a partner tow the Enron line
---------------------- Forwarded by Scott Stoness/HOU/EES on 04/02/2001 09:22
PM ---------------------------

Scott Stoness
04/02/2001 09:21 PM
To: Tamara Johnson/HOU/EES@EES
cc: harry kingerski
Subject: Draft Testimony re PGE/SCE for Discussion

Summary:
The CPUC should implement two part RTP/TOU rates for PGE/SCE. A two part
rate is a rate where customers pay their historical rate for consumption of
normal load and pay market value for consumption incremental (or decremental)
to normal load.
The CPUC should define normal consumption as consumption over and above 90%
of historical 2000 consumption.
The CPUC should define the hourly rate as the highest hourly price paid by
DWR for spot purchases in that hour.
In the event that implementation of two part RTP/TOU rates is complicated to
design, the $30/MWh surcharge should be applied to all customers until the
implementation of two part RTP/TOU rates is possible.
The current draft design, of the CPUC, is discriminatory to large customers.
The current draft design, of the CPUC, does not provide appropriate price
signals.
The current draft design, of the CPUC, results in rate increases to large
customers that are unneccessarly high.
The current draft design, of the CPUC, results in rate increases to large
customers, that are far in excess of those which the CPUC intended.
The current draft design, of the CPUC, results is static and does not respond
to changing market conditions.

Design Goals:
The CPUC should design rates that:
Give appropriate price signals to customers to consume / conserve energy as
as close to marginal price as possible in as many hours as possible.
Treat all rate classes in a fair and consistent manner.
Achieve targeted revenue requirements.
Are easy to administer and understand.

Summary of CPUC Illustrative Design:
The CPUC has proposed rates that move on peak pricing in the summer close to
marginal rates:
Draft proposal provides marginal price signal of about $370/MWh for E19
Secondary from in Summer Weekdays from noon to 6PM
Draft proposal provides marginal price signal of about $75/MWh for E19
Secondary from in all other hours.
Critique based on Design Goals:
Draft proposals move toward marginal rates but fall short.
The rates for power, Mar 30 2001, based on DJ-NP15, on peak is $181.94/MWh.
The rates for power, Mar 30 2001, based on DJ-NP15, off peak is $93.46/MWh.
The proposed marginal rates for E19 Secondary, is $75/MWh for on peak and off
peak.
This rate design will not encourage investments in assets that result in
lower consumption in the winter or in off peak periods.
Draft proposal falls short on treating customers on a consistent basis:
E20 Transmission Voltage customers will experience a 87% rate increase.
E19 Secondary voltage customers will experience a 41% rate increase.
A10 Medium General Service customers will experience a 20% rate increase.
A1 Small L&P customers will experience a 16% rate increase.
The marginal price signal for A10 will be $121/MWh vs $370/MWh for E-20
transmission in the on peak summer.
The marginal price signal for E10 wills be 107/MWh vs $55/MWh for E-20
transmission in the off peak periods.
PGE has a longer summer period than SCE. This results in a 69% increase for
SCE TOU-8-Sub as compared to 87% increases for PGE E20 Transmission rate.
The proposal also results in far different marginal price signals for SCE
customers than PGE customers. For example the on peak rate for SCE TOU-8-Sub
is $128/MWh as compared to PGE E20 Transmission rate of $374/MWh.
Draft proposal does do a good job of recovering $2.2b of revenue.
Draft proposal require some implementation but given that the surcharge
increase does not ocur until May for PGE and June for SCE, it should be
possible to implement.

Enron Proposed Rates:
Enron proposes:
Two part real time pricing time of use rate,
Usage up to 90% of historical use would be billed at historical rates.
Usage incremental or decremental to 90% of historical use, would be billed at
DJ-NP15 On Peak and DJ-NP15 Off Peak, where customers has real time metering.
Usage incremental or decremental to 90% of historical use, would be billed at
DJ-NP15 On Peak and DJ-NP15 Off Peak averaged over the month, where customers
has time of use metering.
Usage incremental or decremental to 90% of historical use, would be billed at
45% of DJ-NP15 On Peak and 55% of DJ-NP15 Off Peak averaged over the month,
where customers has just energy metering.
Critique based on Design Goals:
Enron proposals charge all customer at very close to marginal rates.
Thus, within the constraints of using Dow Jones, the rates should be very
close to the actual marginal rates.
The rates will not be exact because they are:
Determined on the previous day
Ony differentiate between on and off peak, as compared to hour by hour.
To the extent that the customer does not have real time metering capability,
the rates will be determined on a class average basis.
However, the rates be far superior to the CPUC draft design because:
They give better price signals to night consumption
They give better signals to weekend consumption
They give better signals to winter consumption
They are self correcting in that they do not require predetermination of
marginal costs. For example, if summer costs are lower, the rate will be
lower.
The Enron proposal will motivate DSM activities in winter, summer and off
peak.
Enron proposal results in similar rate structure and impact regardless of
utility and rate class.
The Enron proposal results in a similar concept for commerical and industrial
as with residential. AB1X provides that residential customers that consume
energy below normal rates will not have increased rates. This design also
achieves the same effect for commercial and industrial customers.
Draft proposal does do a good job of recovering $2.2b of revenue but even
more importantly it ensures tracking of costs.
Setting the normal load at 90% of historical load results in a $30/MWh
increase if the market value for the entire year is $300/MWh.
In the event that the market value for the entire year is less than $300/MWh,
the resulting cost decreases will offset the lost revenue.
The Enron proposed rate design structure is flexi ble enough that it can
easily be changed to achieve greater or lessor revenue to achieve price
signals and revenue targets.
The revenue outcome is less certain than the CPUC draft design however the
impact should be more certain because the revenue will automatically go up
when the costs go up.
Draft proposal require greater implementation details than the CPUC design
but such extra costs are worthwhile.
The Enron proposal requires:
Determination of historical loads for large customers
Determination of class consumption profiles for demand metered customers
Determination of class consumption profiles for energy metered customers
Determination of customer profiles in the event that the customers is a new
customer
Then Enron proposal has the following negatives:
Some customers who have reduced load from historical levels will be better
off even though they have not changed their behaviour in response to the new
price signals
The rates will require greater administrative costs since they are different
for each customer.
The rates may take more work to put in place for the utility
The rates will result in similar customers paying dissimilar rates, depending
upon the historical consumption of the customers

Q. In the event that it is not possible to implement the Enron rates by June
1, 2001, what would you propose a an interim solution:
A. The CPUC draft rates are so flawed, that it would be superior to just
implement a flat $30/MWh surcharge to all customers. This approach would be
fairer and simpler.

Q. Who would pay for the decremental consumption of customers?
A. The DWR will incur a decline in their costs equal to the decrease in
rates of the utilities. The are indifferent to buy more generation or
selling less energy to customers. Thus the DWR should be willing to pay for
decremental consumption. In the event that the DWR is not agreeable to
paying for decremental consumption, the utility should be allowed to borrow
such funds and have the costs amortized for the next 10 years. In the event
that the utility is unable to fund decremental consumption, the normal load
could be defined 85% of historical and the CPUC could eliminate credits
resulting from decremental consumption. Such solution would discourage
conservation below 15% but would not be expected to diminish the
effectiveness of the Enron proposed rates.

Q. Why is DJ-NP15 the right index to choose?
A. DJ-NP15 and DJ-SP15 are availble for each weekday for on and off peak
pricing. The index is a mathematical average of trades in the previous day
for today. The DJ index is compiled based on the information provided by
many of the large trading companies including Enron. The numbers provided by
the participants are subject to audit. Thus DJ is the best avaible
information available for energy pricing.

Q. What index is suitable for weekends?
A. Enron proposes that the average DJ-NP15 off peak energy charges for friday
and monday be used to determine the weekend rates for the purpose of rate
setting.

From: Jeff Dasovich@ENRON on 04/04/2001 10:56 AM
Sent by: Jeff Dasovich@ENRON
To: Harry Kingerski/NA/Enron@Enron
cc: Don Black/HOU/EES@EES, James D Steffes/NA/Enron@ENRON,
jbennett@gmssr.com, Paul Kaufman/PDX/ECT@ECT, Robert
Neustaedter/ENRON_DEVELOPMENT@ENRON_DEVELOPMENT, Scott Stoness/HOU/EES@EES,
Susan J Mara/NA/Enron@ENRON, Tamara Johnson/HOU/EES@EES
Subject: Re:

I would suggest that we bring Bob in once we've had a chance to discuss
internally today.

Best,
Jeff