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.