Jim:
It was a pleasure speaking with you yesterday. Based on our conversation,=
=20
this email includes the following:

An Enron contact to discuss developing small-scale, distributed generation =
on=20
Tribal lands.

Our views on the impediments to small scale, distributed generation and=20
suggestions on how to remove those impediments.

A description of the credit issues that continue to impede DWR=01,s ability=
to=20
sign contracts with power suppliers, and options to resolve them. Two=20
possible options for addressing the credit issue are 1) a California PUC=20
order clarifying that DWR will recover its power purchase costs through=20
rates, and 2) an amendment to AB1X designed to accomplish the same goal. I=
=20
have attached talking points regarding the California PUC order and propose=
d=20
amendments to AB1X. We believe that an amendment to AB1X is the preferable=
=20
option.

Our assessment of the supply/demand picture in California and the West.

Our suggestions for a legislative package designed to solve both the near-=
=20
and long-term electricity crisis in California. We will deliver to your=20
office tomorrow detailed legislative language. In those materials we will=
=20
also identify existing bills that we believe can easily accommodate our=20
proposed language.

I hope that the information is useful. Please do not hesitate to contact m=
e=20
if you would like to discuss these materials further, or if there is anythi=
ng=20
else that I can do to assist you.

Regards,
Ken

1. Contact Information to Discuss Interest Expressed by Native American=20
Tribes in Installing Small-scale Generation on Tribal Lands

David Parquet, Vice-President
Enron North America
101 California Street, Suite 1950
San Francisco, CA 94111
Phone: 415.782.7822

2. Key Barriers to Distributed Generation

Excessive and Unnecessary Utility Stand-by Charges
Solution: The executive orders issued by the Governor on February 14th took=
a=20
step in the right direction. Utility stand-by charges have always been=20
designed by the utilities to protect their monopoly position, extract=20
monopoly prices from customers, or both. But there is no reason to limit t=
he=20
elimination of these charges to generation facilities that are less than=20
1MW. These limits will only lengthen unnecessarily the time it takes for=
=20
California to close the significant gap between supply and demand and reduc=
e=20
the risk of black outs. We would propose lifting the cap through amendment=
s=20
to SB27X, which is designed to facilitate development of distributed=20
generation.
=20
Excessive delays and costs related to interconnecting facilities with=20
investor-owned and municipal utilities
Solution: The Governor=01,s executive order regarding interconnection is =
a=20
step in the right direction=01*D-D-26-01 requires utilities to complete=20
interconnection studies within 7 days. California should ensure that this=
=20
requirement applies to all generation facilities, including distributed=20
generation. In addition, the financial conflicts the utilities face when=
=20
interconnecting generation facilities are simply too powerful to overcome=
=20
through executive orders or other regulations. To the greatest extent=20
possible, California should shift control over interconnection away from th=
e=20
utility and place that control with the California ISO. This could be=20
accomplished through amendments to SB 27X.

Permitting and Air Quality Issues
Developers of distributed (i.e., =01&on-site=018) generation that is 50 MWs=
or=20
greater must receive certification from the California Energy Commission an=
d=20
therefore faces all of the impediments to development that large-scale=20
generation faces. =20

Solution: California should ensure that the executive orders (D-22-01 thru=
=20
D-26-01) issued by the Governor to expedite plant siting and maximize plant=
=20
output apply equally to smaller scale, =01&distributed generation=018 facil=
ities.=20
In addition, distributed generation that is less than 50 MWs continues to=
=20
face local opposition. The State should ensure that local, parochial=20
interests cannot block otherwise beneficial distributed generation projects=
. =20
These objectives could be accomplished through amendments to SB27X.

3. Credit Concerns Regarding Authority Granted to DWR in AB1X to Purchase=
=20
Electricity on Behalf of the Utilities=20

Enron responded to the RFP issued by DWR to enter into power contracts with=
=20
suppliers.
Enron is in active discussions with DWR to establish contract terms with th=
e=20
goal of entering into a power purchase agreement as soon as possible.
However, ambiguities contained in AB1X have created significant credit risk=
=20
concerns that need to be resolved in order to finalize contract terms.
We understand that the lion=01,s share of counterparties share Enron=01,s c=
redit=20
risk concerns.
Enron has proposed several options for resolving the credit risk issues and=
=20
is working with DWR to arrive at a solution that is mutually agreeable to=
=20
both sides and that might serve as a template for power purchase agreements=
=20
going forward.

Summary of the Source of the Credit Risk Issue

Ambiguous Ratemaking Authority
The language in AB1X leaves ambiguous whether DWR has any authority to char=
ge=20
California ratepayers for the costs of purchasing power. From our analysis=
=20
of the bill, the language in AB1X appears to leave intact the California PU=
C=01,
s exclusive jurisdiction over ratemaking in California. As such, suppliers=
=20
have no assurance that the PUC will agree to include in rates adequate=20
charges to cover DWR=01,s costs of power purchases.

Ambiguous Regulatory Authority Regarding Contract =01&Prudence=018
The language in AB1X leaves open the possibility that the California Public=
=20
Utilities Commission could determine that power purchases made by DWR are=
=20
=01&imprudent.=018 On the basis of such a finding, the CPUC could then ref=
use to=20
allow DWR to collect from ratepayers the costs associated with its power=20
purchases. Consequently, suppliers have no assurance that the PUC will agr=
ee=20
to include in rates the charges to cover the costs of power contracts that=
=20
DWR has entered into with suppliers.
=20
Ambiguous Language Regarding the Ratemaking Mechanism that Will Be Used to=
=20
Recover DWR=01,s Costs of Power Purchases
In addition to the ambiguity regarding ratemaking and regulatory authority=
=20
noted above, the language in the bill is equally ambiguous with respect to=
=20
the specific ratemaking =01&mechanics=018 that AB1X directs the PUC to empl=
oy to=20
permit DWR to recover its power purchase costs. Based on our analysis, it i=
s=20
extremely difficult to determine how the PUC would design the rates to ensu=
re=20
DWR recovers its power purchase costs. Moreover, as currently drafted, it =
is=20
difficult to determine whether AB1X would even permit the PUC to include in=
=20
rates all of the charges necessary to fully recover DWR=01,s power purchase=
=20
costs. Again, this ambiguity raises significant credit risk concerns since=
=20
suppliers have little assurance that DWR will have the ability to recover=
=20
from ratepayers the costs of purchasing power.

Options to Resolve Concerns Regarding Credit Risk=20

We have been working diligently with DWR officials to resolve the credit ri=
sk=20
issues. We have identified three options:

Amend AB1X
The amendments, which are attached to this email, would clarify that a) the=
=20
PUC would accept as =01&prudent and reasonable=018 all purchase costs incur=
red by=20
DWR, and b) the PUC is obligated to include in rates the charges necessary =
to=20
ensure that DWR fully recovers its costs of power purchases. This is the=
=20
preferred option, though we understand that the there may be some political=
=20
challenges standing in the way of amending AB1X. (See attached file=20
entitled, =01&XXXX=018.)

Clarify the Ambiguities in AB1X through an Order Issued by the PUC, and=20
through Contract Language
This is the option that we are currently working with DWR officials to=20
implement. However, it is more complicated and could take significantly mo=
re=20
time to implement than the "legislative" fix. We have attached electronic=
=20
copies of the talking points related to the order that the California PUC=
=20
would need to issue under this option. (See attached file entitled, =01&XX=
XX.=018)

Make Use of Other Instruments Designed to Address Credit Risk
As indicated in our letter responding to DWR=01,s RFP, we are willing to ac=
cept=20
other forms of credit from DWR. Those options include a letter of credit,=
=20
cash prepayment, or an acceptable form of collateral. DWR officials have=
=20
indicated to us that it prefers to pursue the second options, that is,=20
clarifying the ambiguities in AB1X through a PUC order and through contract=
=20
amendments.

4. California=01,s Supply-demand Picture Heading into Summer 2001

Both the California Energy Commission and Cambridge Energy Research=20
Associates, a private sector energy think tank, have issued reports showing=
=20
that California faces a severe supply-demand imbalance. They differ only o=
n=20
how much and how soon additional supply will be made available. All credib=
le=20
sources agree supply supply will be very tight throughout the Summer of=20
2001. =20

CEC and CERA both forecast that California will be this summer short by=20
approximately 5,000 MW. These numbers are in line with our estimates. =20
California=01,s supply base currently has a 6% capacity margin, well below =
the=20
average 15-20% which is recommended for reliable system operation in the=20
West. Since the West relies more heavily upon hydroelectric power than oth=
er=20
regions, reserves are particularly important, owing to the unpredictability=
=20
of the weather and the dry year the West has had thus far.

In the event of a low rain and snow period, the system must possess the=20
flexibility to respond to the reduced availability of power supply. =20
California=01,s very low reserve margin makes it especially susceptible to=
=20
this. Other reasons for reduced supply for the Summer of 2001 include the=
=20
early draw down of reservoirs close the supply-demand gas this summer,=20
emissions restrictions on existing plants, and a reduced number of customer=
s=20
who can be curtailed. Cambridge Energy Research Associates asserts that at=
=20
the current pace of siting, permitting and construction, adequate supplies=
=20
will not be added to correct the market imbalance until 2003 at the earlies=
t.

CERA predicts that California is likely to face approximately 20 hours of=
=20
rolling black outs this summer. The CEC paints a considerably more=20
optomistic scenario, banking that California will bring an additional 5,000=
=20
MWs on line to meet peaking summer demand. It is our view that the=20
California should view the CEC's predictions regarding increased supply wit=
h=20
considerably skepticism.

5. Suggested Package of Legislative Proposals Designed to Solve California=
=01,s=20
Electricity Crisis

This email offers an overview of our proposed legislative solution. We wil=
l=20
deliver to your office tomorrow specific legislative language and existing=
=20
bills that we believe can accommodate our proposals.

As we have suggested throughout the crisis, any solution to California cris=
is=20
must focus on four issues:

Increase supply
Decrease demand
Establish a truly competitive retail electricity market
Return California=01,s Investor-owned utilities to solvency

Increase supply--Legislative vehicle: SB28X (Sher)
To site and construct a power plant in Texas takes approximately 2 years. =
=20
Enron and others have completed the entire process in other states in less=
=20
than a year. In California, complex and costly air quality regulations=20
exacerbate California=01,s inability to site power plants. =20

The Governor=01,s executive orders and Senator Sher=01,s siting reform legi=
slation=20
are steps in the right direction. Our suggested amendments can improve tho=
se=20
efforts by:

Decrease demand=01*Legislative Vehicle: AB31X
Because of the delay in implementing a solution to California=01,s electric=
ity=20
crisis, closing the supply-demand gap through energy conservation and=20
efficiency offers the best chance of avoiding blackouts this summer. This=
=20
can be accomplished most effectively and quickly in two ways:

Buy-down demand
California is tapping into an enormous amount of money from the General Fun=
d=20
to finance DWR=01,s power purchases. California could likely reduce demand=
more=20
cheaply by running an auction to determine the payments businesses would be=
=20
willing to receive to reduce demand for a sustained period (e.g., through t=
he=20
summer months). DWR could very easily run an on-line auction to determine=
=20
the best price it could pay for these demand reductions. To participate,=
=20
businesses would be required to have the metering equipment necessary to=20
monitor and verify that they are actually achieving the reductions. Enron=
=20
has developed an on-line auction software package, =01&Dealbench,=018 that =
it would=20
be willing to contribute to the effort.

Use Price Signals to Incent Voluntary Curtailment

To work, customers need access to the following key elements:

An internet based hour-ahead price posting system to track the market price=
=20
for hour-ahead power in real time.=20
Real-time metering systems for baseline demand and voluntarily curtailment=
=20
verification.
Settlement process that allows for market clearing prices of energy to be=
=20
paid for load reduction (=01&Negawatts=018).

The potential benefits of an effective demand response program would includ=
e:

=01&creation=018 of additional summer peaking capacity in California, parti=
cularly=20
in the short term, without requiring construction of additional generation=
=20
resources.
reduction of peak or super-peak load on the over-stressed California=20
electric system, thus potentially reducing the overall cost of electricity =
in=20
the state.
fostering of demand elasticity without subjecting customers to the full ris=
k=20
of hourly market price volatility by passing market price signals to=20
customers and allowing them to voluntarily shed load and be compensated for=
=20
responding.=20

We estimate that we could generate a summer 2001 on-peak demand response in=
=20
excess of 400 MW during certain high cost hours, and a demand response for=
=20
summer 2002 on-peak hours that could exceed 1000 MW. We further estimate=
=20
that the market response to this program from all ESPs who would also pay=
=20
Access Fees could be 2 to 3 times that amount. We recommend that the State=
=20
of California provide rebates directly to customers to fund the installatio=
n=20
of advanced metering and control systems that would support load curtailmen=
t=20
implementation.

Establish a truly competitive retail electricity market=01*Legislative vehi=
cle:=20
SB27X
The only customers who were protected from price volatility in San Diego we=
re=20
customers who chose Direct Access and signed fixed price deals with energy=
=20
service providers. Ironically, AB1X takes that important option away from=
=20
customers and businesses. It is critical that AB1X be amended to remove th=
e=20
prohibition against Direct Access.

In addition, California will only achieve a competitive retail market when=
=20
the utility is removed completely from the procurement function. Procureme=
nt=20
is not a utility core competency, as evidenced by the dire financial=20
condition in which the utilities now find themselves. California should=20
therefore begin now to gradually phase the utility out of the procurement=
=20
function entirely, with the goal having all customers served by a non-utili=
ty=20
provider within 36 months. To execute the transition, California should ho=
ld=20
a competitive solicitation in which competing service providers would bid f=
or=20
the right to serve segments, or =01&tranches,=018 of utility load.

Return California=01,s Investor-owned utilities to solvency=01*Legislative =
vehicle:=20
AB18X
Utility bankruptcy will not increase supply and it will not decrease demand=
. =20
In short, bankruptcy does nothing to solve California=01,s supply-demand=20
imbalance. In addition, bankruptcy increases the likelihood that consumers=
=20
and businesses will bear the significant financial risks of having Californ=
ia=20
State government assume the role of =01&electricity buyer=018 for an extend=
ed=20
period of time.

California can return the utilities to financial solvency by implementing a=
=20
series of staged rate increases. California should design those rate=20
increases with the dual goal of returning the utilities to solvency without=
=20
=01&shocking=018 the economy or consumers=01, wallets (e.g., amortize the r=
ecovery of=20
the utilities=01, debt over a 5-10 year period). The magnitude of the rate=
=20
increase can be reduced in two ways: First, the utilities could absorb some=
=20
portion of their existing debt in recognition of the risk they accepted whe=
n=20
they agreed to the structure of AB 1890. Second, California can =01&net=01=
8 the=20
revenues the utilities have received from selling electricity into the Powe=
r=20
Exchange against the debts they have accrued due to the retail price cap.