EIX 8-K

-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, NdUgdp0vywyTxp1LVThNNDAd66DMjERbfjNZD3qmwK9+E1NRQD1i16ptraEjrIaT jlqrpnJDFA9OgdCLq6LRog== 0000827052-01-500008.txt : 20010411 0000827052-01-500008.hdr.sgml : 20010411 ACCESSION NUMBER: 0000827052-01-500008 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20010327 ITEM INFORMATION: FILED AS OF DATE: 20010410 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EDISON INTERNATIONAL CENTRAL INDEX KEY: 0000827052 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 954137452 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-09936 FILM NUMBER: 1598634 BUSINESS ADDRESS: STREET 1: 2244 WALNUT GROVE AVE, STE 369 STREET 2: P O BOX 800 CITY: ROSEMEAD STATE: CA ZIP: 91770 BUSINESS PHONE: 6263022222 MAIL ADDRESS: STREET 1: 2244 WALNUT GROVE AVE, STE 369 STREET 2: P O BOX 800 CITY: ROSEMEAD STATE: CA ZIP: 91770 FORMER COMPANY: FORMER CONFORMED NAME: SCECORP DATE OF NAME CHANGE: 19920703 8-K 1 eix8k.htm NONE EIX 8-K

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): March 27, 2001

EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)

CALIFORNIA 001-9936 95-4137452
(State or principal jurisdiction of (Commission file (I.R.S. employer
incorporation or organization) number) identification no.)

2244 Walnut Grove Avenue
(P.O. Box 800)
Rosemead, California 91770
(Address of principal executive offices, including zip code)

626-302-2222
(Registrant's telephone number, including area code)

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Items 1 through 4, 6, 8 and 9 are not included because they are inapplicable.

Item 5. Other Events

On April 9, 2001, Edison International (EIX) and its electric utility subsidiary, Southern California Edison
Company (SCE), signed a memorandum of understanding (MOU) with the California Department of Water Resources
(CDWR) regarding the California energy crisis and its effects on SCE. California Governor Gray Davis and his
representatives participated in the negotiation of the MOU, and Governor Davis endorsed implementation of all the
elements of the MOU. The MOU sets forth a comprehensive plan calling for legislation, regulatory action and
definitive agreements to resolve important aspects of the energy crisis, and which is expected to help restore
SCE's creditworthiness and liquidity. A copy of the MOU is attached as Exhibit 99.1 Key elements of the MOU
include:

o SCE will sell its transmission assets to the CDWR, or another authorized California state agency, at a
price equal to 2.3 times their aggregate book value, or approximately $2.76 billion. If a sale of the
transmission assets is not completed under certain circumstances, SCE's hydroelectric assets and other
rights may be sold to the state in their place. SCE will use the proceeds of the sale in excess of book
value to reduce its undercollected costs and retire outstanding debt incurred in financing those costs. SCE
will agree to operate and maintain the transmission assets for at least three years, for a fee to be
negotiated.

o Two dedicated rate components will be established to assist SCE in recovering the net undercollected
amount of its power procurement costs through January 31, 2001, estimated to be approximately $3.5 billion.
The first dedicated rate component will be used to securitize the excess of the undercollected amount over
the expected gain on sale of SCE's transmission assets, as well as certain other costs. Such securitization
will occur as soon as reasonably practicable after passage of the necessary legislation and satisfaction of
other conditions of the MOU. The second dedicated rate component would not be securitized and would not
appear in rates unless the transmission sale failed to close within a two-year period. The second component
is designed to allow SCE to obtain bridge financing of the portion of the undercollection intended to be
recovered through the gain on the transmission sale.

o SCE will continue to own its generation assets, which will be subject to cost-based ratemaking, through
2010. SCE will be entitled to collect revenues sufficient to cover its costs from January 1, 2001
associated with the retained generation assets and existing power contracts. The MOU calls for the
California Public Utilities Commission (CPUC) to adopt cost recovery mechanisms consistent with SCE
obtaining and maintaining an investment grade credit rating.

o The CDWR will assume the entire responsibility for procuring the electricity needs of retail customers
within SCE's service territory through December 31, 2002, to the extent that those needs are not met by
generation sources owned by or under contract to SCE. (The unmet needs are referred to as SCE's "net short
position".) SCE will resume procurement of its net short position after 2002. The MOU calls for the CPUC
to adopt cost recovery mechanisms to make it financially practicable for SCE to reassume this responsibility.

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o SCE's authorized return on equity will not be reduced below its current level of 11.6% before
December 31, 2001. Through the same date, a ratemaking capital structure for SCE will not be established
with different proportions of common equity or preferred equity to debt than set forth in current
authorizations. These measures are intended to enable SCE to achieve and maintain an investment grade
credit rating.

o EIX and SCE will commit to make capital investments in SCE's regulated businesses of at least $3 billion
through 2006, or a lesser amount approved by the CPUC. The equity component of the investments will be
funded from SCE's retained earnings or, if necessary, from equity investments by EIX.

o An affiliate of EIX will execute a contract with the CDWR or another state agency for the provision of
power to the state at cost-based rates for ten years from a power project currently under development. The
EIX affiliate will use all commercially reasonable efforts to place the first phase of the project into
service before the end of Summer 2001.

o SCE will grant perpetual conservation easements over approximately 21,000 acres of lands associated with
SCE's Big Creek and Eastern Sierra hydroelectric facilities. The easements initially will be held by a
trust for the benefit of the State of California, but ultimately may be assigned to nonprofit entities or
certain governmental agencies. SCE will be permitted to continue utility uses of the subject lands.

o After the other elements of the MOU are implemented, SCE will enter into a settlement of or dismiss its
federal district court lawsuit against the CPUC seeking recovery of past undercollected costs. The
settlement or dismissal will include related claims against the State of California or any of its agencies,
or against the federal government.

The parties agree in the MOU that each of its elements is part of an integrated package, and effectuation of each
element will depend upon effectuation of the others. To implement the MOU, numerous actions must be taken by the
parties and by other agencies of the State of California. The California Legislature must enact legislation to
authorize purchase of SCE's transmission system or other assets, establish the dedicated rate components,
authorize and/or direct the CPUC to take certain actions, and authorize other agreements and actions. The CPUC
must also adopt the dedicated rate components and financing orders, modify existing decisions, and take various
ratemaking and other actions. The CDWR and other state agencies must enter into definitive agreements for the
purchase of assets from SCE and to embody various other elements of the MOU. The sale of SCE's transmission
system and other elements of the MOU must be approved by the Federal Energy Regulatory Commission (FERC). SCE,
EIX and the CDWR committed in the MOU to proceed in good faith to sponsor and support the required legislation
and to negotiate in good faith the necessary definitive agreements. The California Legislature, the CPUC, the
FERC, and other governmental entities on whose part action will be necessary to implement the MOU are not parties
to the MOU.

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The MOU may be terminated by either SCE or CDWR if required legislation is not adopted and definitive agreements
executed by August 15, 2001, or if the CPUC does not adopt required implementing decisions within 60 days after
the MOU was signed, or if certain other adverse changes occur. EIX and SCE cannot provide assurance that all the
required legislation will be enacted, regulatory actions taken, and definitive agreements executed before the
applicable deadlines.

EIX and SCE believe that the MOU is an important step towards an acceptable resolution of the major issues
affecting EIX and SCE as a result of the California energy crisis, including restoring their creditworthiness and
creating a positive framework for future financial stability, but achievement of those results is not assured. A
California voter initiative or referendum previously has been threatened against any measures that would raise
consumer rates or aid California's investor-owned utilities. In addition, execution of the MOU does not
eliminate the possibility that any of SCE's creditors could take steps to force SCE into bankruptcy proceedings.

On April 6, 2001, Pacific Gas and Electric Company (PG&E) announced that it had filed for reorganization under
Chapter 11 of the United States Bankruptcy Code. PG&E said that neither its parent holding company nor any of
the parent's other subsidiaries are affected by PG&E's filing. PG&E cited as reasons for its bankruptcy filing
the failure by the State of California to assume full procurement responsibility for PG&E's net short position,
the CPUC's actions on March 27 and April 3, 2001 that created new payment obligations for PG&E, lack of progress
in negotiations with the state to provide recovery of power purchase costs, the CPUC's adoption of an illegal and
retroactive accounting change, and the slow progress of discussions with Governor Davis's representatives. The
actions of the CPUC cited by PG&E are discussed below.

SCE is still working to avoid bankruptcy, despite PG&E's announcement that it is filing for bankruptcy court
protection. EIX and SCE continue to believe that a comprehensive solution to the current crisis through
agreements, legislation and regulatory actions, as contemplated by the MOU, is a preferable course of action.
Neither EIX nor SCE can predict the impact of PG&E's bankruptcy on implementation of the MOU and on EIX's and
SCE's other efforts to resolve their current financial and liquidity problems.

On March 27, 2001, the CPUC unanimously adopted several significant decisions regarding California's current
energy crisis. The CPUC's March 27 decisions deal with complex matters and in many respects are unclear or
ambiguous. Many elements of the decisions will be developed further in ongoing proceedings, the timing of which
is uncertain. EIX and SCE are still analyzing the decisions and cannot yet state with certainty the impacts of
the decisions on them. EIX and SCE believe that the CPUC, by increasing rates in its March 27 decisions, has
taken a positive step to address the general disparity between high wholesale power costs and frozen retail
rates. However, several aspects of the decisions are not helpful to SCE's efforts to recover its own costs and
regain creditworthiness. Key components of the decisions will have to be modified to implement the MOU.
Although CPUC representatives participated in the negotiation of the MOU, the CPUC is not a party to it. The MOU
acknowledges that the CPUC is an independent regulatory agency which may within its discretion determine to adopt

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or not adopt the actions and approvals described in the MOU. Important provisions of the CPUC's March 27
decisions which may be adverse to SCE include at least the following:

o The CPUC adopted methods for calculating the revenues that SCE must pay over to the CDWR to reimburse
the CDWR for power purchased on behalf of SCE's customers. SCE believes the calculation methods will leave
SCE without sufficient revenues to cover its generation, purchased power and transition costs. To implement
the MOU, the CPUC will need to modify the calculation methods and provide reasonable assurance that SCE will
be able to recover its ongoing costs.

o The CPUC ordered SCE to immediately make payments to the CDWR and power suppliers that are qualifying
facilities (QFs), but did not address SCE's past undercollected power procurement costs. To implement the
MOU, the CPUC will need to adopt mechanisms for SCE to recover its past costs.

o The CPUC also made dramatic, retroactive changes in regulatory accounting mechanisms that, in effect,
provide for recovery of past procurement costs but cause generation-related transition costs to be
undercollected. This situation, if not changed, would require SCE and EIX to take substantial charges
against earnings in their fourth quarter and year-end financial results. The changes also may materially
and adversely affect future financial results. To implement the MOU, the CPUC will need to modify these
changes. While EIX and SCE believe that implementation of the MOU should enable SCE to recover its costs,
under applicable accounting standards the fourth quarter charges may still be required pending adoption by
the CPUC of the cost recovery mechanisms contemplated by the MOU. (See the discussion below about possible
write-offs.)

EIX and SCE believe that in some respects the CPUC's decisions are unlawful and unconstitutional. Key provisions
of the CPUC's decisions are discussed further below.

In an interim order adopted on March 27, 2001, the CPUC granted SCE and other California utilities a rate
increase in the form of a three-cents per kilowatt-hour (kWh) surcharge on electricity sold, effective
immediately. However, the three-cent surcharge will not be collected in rates until the CPUC establishes an
appropriate rate design. The CPUC proposed a tiered rate design in an assigned commissioner's ruling and asked
for comments. The assigned commissioner said the tiered rate design is intended to encourage conservation by
requiring customers to pay more for electricity above a threshold usage level. The three-cent surcharge will not
apply to residential electricity usage below 130% of baseline rates or to certain low-income customers. The CPUC
will hold hearings on the rate design and may not issue a decision until some time in May 2001. SCE has asked
the CPUC to immediately adopt an interim rate increase that would allow the rate change to go into effect sooner.

The CPUC stated in its interim order that SCE is to use revenue generated by the three-cent surcharge to pay
power costs incurred after March 27, 2001. SCE must refund the surcharge to ratepayers if SCE does not properly
use it to pay for power purchases. If any refunds of power costs are obtained from power generators and sellers,

Page 5

those refunds will be used to reduce customer rates or to pay power costs. SCE also must refund the three-cent
surcharge to the extent that any court or administrative body denies refunds from power generators or sellers in
a proceeding where recovery is hampered by lack of cooperation from SCE. The CPUC also affirmed that an earlier
one-cent per kWh surcharge granted on January 4, 2001 is now permanent under California legislation adopted in
February 2001, known as AB1X. The CPUC stated that revenues from the one-cent surcharge must be used to pay for
power purchases and not for any other costs. The CPUC ordered that the three-cent surcharge must be added to the
rate paid to the CDWR to reimburse the CDWR for its costs of purchasing power for delivery to SCE's customers.

In another interim order on March 27, 2001, the CPUC ordered SCE to pay the CDWR for each kWh that the CDWR sells
to SCE's customers, at a price equal to SCE's applicable generation-related retail rate as in effect on
January 5, 2001. The CPUC determined that the generation-related retail rate should be equal to SCE's total
bundled electric rate (including the one-cent surcharge adopted on January 4, 2001) less certain
non-generation-related rates or charges. The CPUC determined that the applicable rate is 7.277 cents per kWh for
electricity delivered by the CDWR to SCE's retail customers after February 1, 2001, until more specific rates are
calculated. For the period of January 19 through January 31, 2001, the CPUC ordered SCE to pay the CDWR at a
rate of 6.277 cents per kWh for power delivered on an interim basis to SCE's customers. The CPUC ordered SCE to
pay the CDWR daily within 45 days after the CDWR supplies power to SCE's retail customers, subject to penalties
for each day that payment is late. Under the CPUC's decisions, the CDWR currently is entitled to be paid each
day an amount equal to the number of kWh that the CDWR provided 45 days earlier multiplied by 7.277 cents per kWh
(which will increase to 10.277 cents per kWh for electricity delivered after March 27, 2001, due to the 3-cent
surcharge described above).

In the interim order, the CPUC directed SCE to immediately pay sums owed to the CDWR for certain past purchases
of power for SCE's customers. SCE paid $43.5 million to the CDWR on March 28, 2001, for the period of January 19
through February 11, 2001. Based on the CPUC order, the rate for purchases from January 19 through January 31
was 6.277 cents per kWh, and for purchases from February 1 through February 11 the rate was 7.277 cents per kWh.

In addition, the interim order proposed a method by which the California Procurement Adjustment (CPA) should be
calculated. The CPA was established by AB1X. The CPA is used to determine the amount of bonds the CDWR can
issue to finance its power purchases. All or a portion of the CPA may be allocated by the CPUC to reimburse the
CDWR for its power purchases on behalf of utility customers. AB1X requires the CPUC to determine (1) the CPA,
which is the portion of each electric utility's electric retail rate effective on January 5, 2001 that is equal
to the difference between the generation-related component of the utility's retail rate in effect on January 5,
2001, and the sum of the costs of the utility's own generation, QF contracts, existing bilateral contracts and
ancillary services, and (2) the amount of the CPA that is allocable to the power sold by the CDWR. In its
March 27 decision, the CPUC proposed that the CPA should be a set rate calculated by determining each utility's
generation-related revenues (for SCE this would be equal to 7.277 cents per kWh multiplied by total kWh sales by

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SCE to retail customers), then subtracting each utility's statutorily authorized generation-related costs, and
dividing the result by each utility's total kWh sales. The CPUC states in the March 27 decision that each
utility's CPA rate will be used to determine a proposed CPA revenue amount, which can be used by the CDWR to
begin the process of issuing bonds. AB1X provides that the CDWR cannot issue bonds in an aggregate amount
greater than four times the annual revenues generated by the CPA.

SCE filed comments on the proposed CPA calculation method on March 29 and April 2, 2001. In the limited time
available to consider the impact of the CPUC's March 27 decisions, SCE estimated that its future revenues will
not be sufficient to cover its own costs of retained generation and power purchases. SCE provided a forecast
showing that the net effect of the rate increases described above, the decision on QF payments described below,
and the payments ordered to be made to CDWR could result in a shortfall in the CPA calculation of $1.743 billion
for SCE during 2001. SCE further stated that the proposed calculation method does not properly reflect all of
SCE's relevant generation costs, and that adoption of the method and later allocation of a portion of the CPA to
the CDWR would materially exacerbate SCE's revenue shortfall. SCE commented that other flaws in the calculation
are that: (1) the proposed CPA is for an indefinite period with no mechanism for adjustments based on changes in
actual costs; (2) it ignores the potential impact on SCE's costs if the CDWR is not responsible for the full
net-short position; (3) it assumes too low a cost for QF payments (as discussed below); (4) it may improperly
exclude authorized generation-related costs; (5) it improperly excludes revenues from nuclear incentive pricing;
and (6) the methodology for calculating the CPA is flawed and based on unreasonable assumptions. A copy of SCE's
comments is attached as Exhibit 99.2.

In an interim order on April 3, 2001, the CPUC adopted the method to calculate the CPA and then applied that
method to calculate a company-wide CPA rate for each California utility. The CPUC used that rate to determine
the CPA revenue amount which can be used by the CDWR for issuing bonds. The CPUC stated that its decision is
narrowly focused to calculate the maximum amount of bonds that the CDWR may issue and does not dedicate any
particular revenue stream to the CDWR. The CPUC determined that SCE's CPA rate is 1.120 cents per kWh, which
generates revenues of $856.43 million in 2001. According to the CPUC's methodology, the aggregate annual
revenues generated by the CPA rates determined for the three California investor-owned utilities would allow the
CDWR to issue up to $13.4 billion of bonds to pay for power purchases by the CDWR under the provisions of AB1X.
In its calculation of the CPA, the CPUC disregarded all the adjustments requested by SCE in its comments filed on
March 29, 2001 (discussed above). As to SCE's concerns that the CPA may be overstated and could cause
deleterious financial effects on SCE, the CPUC stated that the interim order does not allocate the CPA, and SCE
may comment on the allocation of the CPA at a later time.

On March 27, 2001, the CPUC also ordered SCE to begin making payments to QFs for power deliveries on a going
forward basis, commencing with April 2001 deliveries. SCE must pay QFs within 15 days of the end of the QF's
billing period, and QFs are allowed to establish 15-day billing periods. The CPUC provided two special payment
options for the month of April only. Failure to make a payment when due will result in a fine equal to the
amount owed. The CPUC also modified the formula used in calculating payments to QFs by substituting natural gas
index prices based on deliveries at the Oregon border in the place of index prices at the Arizona border. The

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order further revises other aspects of the payment formula to take into account changes in intrastate gas
transportation costs. The CPUC stated that the changes will probably result in lower QF energy prices. The
changes apply to all QFs whose payments are based on CPUC-approved short-run avoided cost regardless of whether
they use natural gas or other resources such as solar or wind.

In its comments on the CPUC's methodology for calculating the CPA (described above), SCE also discussed the QF
pricing resulting from the CPUC's March 27 decision on QF payments. SCE stated that the CPA calculation proposed
by the CPUC is based on an assumed QF price of $80 per megawatthour (MWH), which was a target price in earlier
negotiations with QFs seeking a settlement on lower prices. However, those negotiations failed. SCE provided to
the CPUC a forecast showing that QF prices through the remainder of 2001, based on the revised formula adopted by
the CPUC and independently forecasted gas prices, will be substantially higher than $80 per MWH.

In its March 27 decisions, CPUC granted a petition previously filed by The Utility Reform Network (TURN), a
ratepayer advocacy group, that was opposed by SCE and PG&E. The CPUC directed that the balance in SCE's
transition revenue account (TRA), whether positive or negative, be transferred on a monthly basis to SCE's
transition cost balancing account (TCBA), effective retroactively to January 1, 1998. The TRA is a regulatory
asset account in which SCE records the difference between revenues received from customers through currently
frozen rates and the costs of providing service to customers, including power procurement costs. The TCBA is a
regulatory balancing account that tracks the recovery of generation-related transition costs, including stranded
investments. The CPUC also ordered SCE to retroactively restate and record balances in its generation memorandum
accounts to the TRA on a monthly basis before any transfer of generation revenues to the TCBA. SCE believes that
this decision by the CPUC is a fundamental departure from established regulatory accounting and ratemaking
procedures and is unlawful and unconstitutional. SCE believes the CPUC's intent was to deny SCE lawful recovery
of its costs and to artificially extend the end of the current rate freeze. The CPUC characterized the changes
as merely reducing the prior revenues recorded in the TCBA, thereby affecting only the amount of transition cost
recovery achieved to date. Based upon the transfer of balances into the TCBA, the CPUC stated that the current
rate freeze has not ended and will not end until the earlier of recovery of all specified transition costs or
March 31, 2002. The CPUC said that any undercollection in the TRA cannot be recovered after the rate freeze
ends. But the CPUC also said that it will monitor the balances remaining in the TCBA and consider how to address
remaining balances in the ongoing proceedings. If the CPUC does not modify this decision in a manner consistent
with the MOU, SCE intends to challenge the decision through all appropriate avenues.

Although the CPUC has authorized a substantial rate increase, it has allocated the revenues from the increase
entirely to future power purchase costs without providing for recovery of SCE's past undercollections for the
costs of purchased power. The CPUC's decisions do not assure that SCE will be able to meet its ongoing
obligations or repay past due obligations. By ordering immediate payments to the CDWR and QFs, the CPUC has
exacerbated SCE's cash flow and liquidity problems. Moreover, the CPUC expressed the view that AB1X continues

Page 8

the utilities' obligations to serve their customers; and the CPUC said that it cannot assume that the CDWR will
purchase all the electricity needed above what the utilities either generate or have under contract (the net
short position) and cannot order the CDWR to do so. This could result in SCE incurring additional purchased
power costs for which the CPUC has allowed SCE no means of recovery. In addition, the CPUC's retroactive
modifications of established regulatory asset accounts, if not changed, would require EIX and SCE to take
substantial earnings charges for the fourth quarter of 2001. EIX and SCE believe that the CPUC's decisions
described above are inconsistent with the terms of the MOU in material respects. To implement the MOU, it will
be necessary for the CPUC to modify or rescind those decisions. Neither EIX nor SCE can provide any assurance
that the CPUC will do so.

As discussed in previous reports, applicable accounting standards permit SCE to defer costs as regulatory assets
if those costs are determined to be probable of recovery in future rates. If SCE determines that regulatory
assets, such as the TRA and TCBA, are no longer probable of recovery through regulated rates, they must be
written off. Because of the CPUC's decisions on and after March 27, 2001, including the retroactive transfer of
balances from SCE's TRA to its TCBA and related changes, EIX and SCE had to reassess the probability of recovery
of the undercollected costs that are now recorded in the TCBA. Absent a change in those CPUC decisions, or other
regulatory or legislative actions, that would make probable the recovery of generation-related regulatory assets,
SCE's and EIX's financial results for the fourth quarter and the fiscal year ended 2000 would include an
after-tax charge of approximately $2.5 billion ($4.2 billion on a pre-tax basis), reflecting a write-off of the
TCBA (as restated to reflect the CPUC's March 27, 2001 decisions) and regulatory assets to be recovered through
the TCBA mechanism, as of December 31, 2000. Furthermore, SCE currently does not have regulatory authority to
recover any power purchase costs it incurs during 2001 in excess of revenues from retail rates. Those amounts
also would be charged against earnings absent a regulatory or legislative solution, such as implementation of the
actions called for in the MOU, that makes recovery of such costs probable. This would result in further material
declines in reported common shareholders' equity, particularly in light of the CPUC's failure to provide SCE with
sufficient rate revenues to cover its ongoing costs and obligations as discussed above. The fourth quarter 2000
charge would cause SCE to be unable to meet an earnings test that must be met before SCE can issue additional
first mortgage bonds. If the MOU is implemented, or a rate mechanism provided by legislation or regulatory
authority is established that makes recovery from regulated rates probable as to all or a portion of the amounts
that were previously charged against earnings, current accounting standards provide that a regulatory asset would
be correspondingly reinstated with a corresponding increase in earnings.

On April 2, 2001, EIX and SCE each filed with the Securities and Exchange Commission a notification of late
filing on Form 12b-25 stating that each company could not timely file its annual report on Form 10-K without
unreasonable effort and expense because of the continuing developments in the California energy crisis, including
especially the CPUC's March 27, 2001 decisions that must be analyzed by EIX and SCE and reflected in their
year-end 2000 financial statements. Under Rule 12b-25, EIX's and SCE's respective Form 10-K reports will be
deemed to be timely filed if they are filed by April 17, 2001 (15 calendar days from the prescribed due date).
EIX and SCE presently intend to make their Form 10-K filings by April 17, 2001.

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At its March 27, 2000 meeting, the CPUC deferred action on a proposed order instituting an investigation whether
California's investor-owned utilities, including SCE, have complied with past CPUC decisions authorizing the
formation of their holding companies and governing affiliate transactions, as well as applicable statutes. On
March 29, 2001, an assigned commissioner's ruling was issued that requires SCE and EIX to respond within 10 days
to document requests and questions that are substantially identical to document requests and questions included
in the proposed order instituting investigation. At its April 3, 2001 meeting, the CPUC adopted the proposed
order. The order reopens past CPUC decisions authorizing the utilities to form holding companies and initiates
an investigation into (1) whether the holding companies violated requirements to give priority to the capital
needs of their respective utility subsidiaries; (2) whether "ring fencing" actions by EIX and PG&E Corporation
and their respective nonutility affiliates also violated the requirements to give priority to the capital needs
of their utility subsidiaries; (3) whether the payment of dividends by the utilities violated requirements that
the utilities maintain dividend policies as though they were comparable stand-alone utility companies; (4) any
additional suspected violations of laws or CPUC rules and decisions; and (5) whether additional rules,
conditions, or other changes to the holding company decisions are necessary. The MOU signed on April 9, 2001
with the CDWR calls for the CPUC to adopt a decision clarifying that the "first priority" condition in SCE's
holding company decision refers to equity investment, not working capital for operating costs. Neither EIX nor
SCE can provide assurance that the CPUC will adopt such a decision, or predict what effects the investigation or
any subsequent actions by the CPUC may have on either of them.

On March 27, 2001, SCE announced that it will commence payments on deferred indebtedness. These payments include
(1) past due interest on first and refunding mortgage bonds, Series 93C Due 2026 and Series 93H Due 2004 (which
was paid on March 30, 2001); (2) past due interest on senior unsecured notes, 5-7/8% Series Due 2001 (which will
be paid on April 19, 2001, to holders of record as of April 9, 2001, in accordance with the applicable
indenture); (3) interest on matured commercial paper; and (4) interest on extendible commercial notes. Payments
on the commercial paper and extendible commercial notes were made on April 6, 2001, and all interest was brought
current to March 31, 2001 for the commercial paper and March 28, 2001 for the extendible commercial notes.
Payments will also include interest on past due interest. Regular payments will be resumed on all interest due
going forward, including interest payments due under SCE's bank credit facilities. Interest on commercial paper
will be paid monthly, and interest on the 5-7/8% Series notes will be paid semiannually. Notices will be
provided to holders of the securities about the timing and amount of the interest payments they will receive.
The aggregate amount required to bring interest payments on outstanding indebtedness current as of March 31, 2001
is approximately $26 million.

On February 20, 2001, a group of geothermal energy suppliers affiliated with CalEnergy Operating Company filed a
lawsuit against SCE in the Superior Court of Imperial County, California which, as subsequently amended, seeks
immediate payment by SCE of $100 million for energy and capacity supplied under QF contracts during November 2000
through February 2001, plus exemplary damages. The lawsuit also seeks an order allowing the suppliers to stop
providing power to SCE and sell the power elsewhere in California. On March 22, 2001, the court issued an order
allowing the suppliers to make sales to third parties because of SCE's failure to make payments for power

Page 10

deliveries. SCE has requested, in a motion set for hearing on April 16, 2001, that the order be lifted in light
of the CPUC's March 27, 2001 decision requiring SCE to resume payments to QFs. A hearing that was set to be
heard on April 2, 2001 on the suppliers' motion for summary adjudication on the issue of breach of contract has
been continued to April 16, 2001, due to SCE's intention to seek coordination of this case with other actions
that QFs have commenced in various California courts on the payment issue.

On March 2, 2001, two geothermal energy suppliers affiliated with Caithness Corporation filed a lawsuit against
SCE in federal district court in Nevada seeking payment of more than $20 million for energy and capacity
delivered to SCE under QF contracts during November and December 2000 and January 2001. The suppliers sought a
writ of attachment against SCE's interest in the Mohave Generating Station for the amount of their claim. On
March 14, 2001, the court issued an order granting a prejudgment attachment, subject to the suppliers posting
surety in the amount of the attachment unless the parties otherwise agree. The suppliers have not yet posted
surety. The suppliers filed a summary judgment motion and requested that SCE's time to respond be significantly
shortened. The latter request was denied by the court, and SCE's opposition to the summary judgment motion is
due on April 11, 2001.

On March 5, 2001, a group of wind energy suppliers affiliated with FPL Group filed a lawsuit against SCE in the
Superior Court of Los Angeles County, California seeking payment of "several million dollars" for energy and
capacity delivered to SCE under QF contracts during November and December 2000 and January 2001. The suppliers
filed applications for writs of attachment against unspecified assets of SCE. On March 28, 2001, the court
denied the applications.

On March 28, 2001, IMC Chemicals Inc., a company that operates a cogeneration plant, filed a lawsuit against SCE
in the Superior Court of San Bernardino County, California seeking payment of $2.8 million for energy and
capacity delivered to SCE under QF contracts during the period from November 2000 through February 2001. The
lawsuit also seeks an order allowing the suppliers to stop providing power to SCE and sell the power to other
purchasers.

On March 28, 2001, SCE was served with a lawsuit filed in the Superior Court of Los Angeles County, California by
NP Cogen, the owner-operator of a cogeneration facility. The lawsuit seeks damages for SCE's alleged failure to
pay for power deliveries under a QF contract during the period from November 2000 through February 2001. The
amount of damages sought is not specified, but the complaint alleges that the amount currently owed by SCE under
the contract is approximately $8 million. The lawsuit also seeks a declaration that the owner-operator is
excused from further performance under the contract.

On March 29, 2001,Watson Cogeneration Company, which operates a cogeneration facility, filed a lawsuit against
SCE in the Superior Court of Los Angeles, California seeking payment of damages of at least $150 million for
energy, capacity and other services delivered to SCE under a QF contract during and since November 2000, plus
exemplary damages. The lawsuit also seeks an order allowing the supplier to stop providing power to SCE and sell
the power to other purchasers.

Page 11

On April 3, 2001, SCE was served with a lawsuit filed in the Superior Court of Los Angeles County, California by
four cogeneration companies affiliated with Delta Power LLC seeking damages of at least $42 million for
nonpayment by SCE for power deliveries under four QF contracts during the period from November 2000 through
February 2001. The lawsuit also seeks a declaration that the companies may terminate the contracts, stop
providing power to SCE and sell the power to other purchasers.

On April 3, 2001, SCE was served with a lawsuit filed in the Superior Court of Ventura County, California by EF
Oxnard, Inc., the owner-operator of a cogeneration facility, seeking damages of at least $13.5 million for
nonpayment by SCE for power deliveries under a QF contract during the period from November 2000 through February
2001.

On April 5, 2001, Brea Power Partners, L.P., a company that operates a landfill gas-fired plant, filed a lawsuit
against SCE and EIX in the Superior Court of Los Angeles County, California seeking payment of $1.65 million for
energy and capacity delivered to SCE under a QF contract during the period from November 2000 through March 2001,
plus $24 million of additional damages. The lawsuit also seeks an order allowing the company to stop providing
power to SCE and sell the power to other purchasers.

On April 9, 2001, SCE and the California Independent System Operator (ISO) were sued in federal district court in
Los Angeles, California by Inland Paperboard and Packaging, Inc., a company that owns a cogeneration facility.
The lawsuit seeks payment of $5.3 million for energy and capacity delivered to SCE under a QF contract during the
period from November 2000 through March 2001, plus additional and treble damages for alleged interference with
Inland Paperboard's ability to sell power to third parties. The lawsuit also seeks a temporary restraining order
and injunction to prevent SCE and the ISO from interfering with such third party sales.

Several other owners or operators of QFs have given SCE letters demanding that SCE pay them past due amounts,
requesting approval to sell their energy and capacity to third parties, and in some cases threatening legal
action.

In the preceding discussion and elsewhere in this report, the words "expects," "believes," "anticipates,"
"projects," "forecasts," "intends," "predicts," "probable," and other similar expressions are intended to identify
forward-looking information that involves risks and uncertainties. Actual results or outcomes could differ
materially as a result of such important factors as implementation (or non-implementation) of the MOU as
described above; legislative enactments; the outcome of regulatory and judicial proceedings regarding recovery of
costs and other matters; the outcome of state and federal regulatory proceedings concerning wholesale and retail
electric rates, accounting mechanisms and other matters; the actions of securities rating agencies; changes in
prices of electricity and fuel costs; the availability of credit; changes in financial market conditions; weather
conditions; and other unforeseen events, some of which are discussed above.

Page 12

Item 7. Financial Statements, Pro Forma Financial Information and Exhibits.

(a) Not applicable

(b) Not applicable

99.1 Memorandum of Understanding

99.2 SCE's Comments on Proposed CPA Calculation

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report
to be signed on its behalf by the undersigned thereunto duly authorized.

EDISON INTERNATIONAL
(Registrant)

KENNETH S. STEWART
-------------------------------------------------
KENNETH S. STEWART
Assistant General Counsel and Assistant Secretary

April 10, 2001

EX-99 2 exhib991.htm MEMORANDUM OF UNDERSTANDING Exhibit 99.1

                                            MEMORANDUM OF UNDERSTANDING


         THIS MEMORANDUM OF UNDERSTANDING ("MOU") is being entered into as of April 9, 2001, by and among the
California Department of Water Resources ("CDWR") separate and apart from its powers and responsibilities with
respect to the State Water Resources Development System, and Southern California Edison Company, a California
corporation ("SCE"), and, as to Sections 5, 8 and 12, Edison International, a California corporation ("EIX").


1.       Purpose


         The purposes of this MOU are to:

o        Set forth the understandings reached by the parties above (the "Parties") about a plan (the "Plan") to
         provide affordable and reliable electricity to customers of SCE by, among other things,
         maintaining the output of SCE's retained generation on a cost-of-service basis, providing for
         CDWR or another authorized agency of the State of California (the "State") to acquire SCE's
         transmission system (or certain other assets if the sale of the transmission system is not
         consummated under certain circumstances) (the "Transmission Sale"), dedicating a new generating
         facility owned by an EIX company to cost-of-service based rates for at least 10 years, and
         providing for easements and potential conveyances in fee of certain lands described herein to
         ensure the long-term conservation of these lands for their public interest value; and

o        Provide a framework for the timely implementation of those understandings; and



Page 1


o        As part of that implementation, provide for the resolution of certain claims which SCE has asserted
         against the State of California and certain agencies and subdivisions thereof.

         It is expressly understood that the Parties will act in good faith to implement all the elements of this
MOU, and that the Governor of the State of California has endorsed such implementation.  Such implementation
shall include seeking to obtain the consents and authorizations contemplated herein.  In addition, it is
expressly understood that there is no intention to change SCE's continuing to be a public utility that is subject
to the jurisdiction of the California Public Utilities Commission (the "CPUC").  The Parties recognize, in order
for a number of the initiatives contemplated by this MOU to be fulfilled, certain actions and approvals will need
to be obtained by SCE from the CPUC in an appropriate proceedings.  Those actions and approvals are referred to
herein as the "CPUC Implementing Decisions."  Inasmuch as the CPUC is an independent regulatory agency which may
within its discretion determine to adopt or not adopt the actions and approvals that are described herein as
"CPUC Implementing Decisions," this MOU provides for certain rights on the part of SCE to terminate the
implementation of this MOU in the event that the CPUC does not adopt all of the actions and approvals expressly
characterized herein as "CPUC Implementing Decisions" within the period of sixty (60) days after the date of the
execution of this MOU by all Parties.

         Subject to legislation that may be adopted implementing this MOU and to the CPUC Implementing Decisions,
nothing herein shall prohibit the CPUC from employing ratemaking and regulatory techniques, methods and standards
that have been historically used and may be used or implemented in the regulation of public utilities.

         Nothing herein is intended to provide SCE with actual recovery of a cost more than once.  In such
instance, if any, the CPUC is authorized to adjust rates to prevent multiple recovery of such cost.



Page 2


2.       General Overview


         The Plan is comprised of the elements described in more detail in Sections 3 through 14 of this MOU.
The Plan will be implemented through a combination of the following:

o        Legislative action, including, but not limited to, authorizing CDWR or another State entity to acquire
         the SCE transmission assets and enter into and implement the applicable contracts and
         activities contemplated herein, and, as applicable or necessary, authorizing and/or directing
         the CPUC to take certain actions called for hereby;

o        Contracts directly between SCE and CDWR or other pertinent State agencies;

o        Regulatory decisions, including actions by the Federal Energy Regulatory Commission ("FERC") and the
         CPUC Implementing Decisions;

o        Entry of a stipulated judgment in, or other form of mutually acceptable disposition of, SCE's federal
         court lawsuit; and

o        Releases or assignments of mutually agreed upon identified claims by SCE against third parties subject
          to the conditions specified herein.

         The Parties agree that the elements of the Plan are an integrated package, and this MOU does not
obligate any of the Parties to support any individual element separate from the entire package.  Further
principles of implementation are set forth in Section 15, and agreed upon next steps are provided in Section 16.

         The proceeds from the transactions contemplated herein are intended to eliminate SCE's net
undercollected amount as of January 31, 2001, as described herein. Accordingly, except as otherwise provided
herein, proceeds received from the securitizations and Transmission Sale described herein will be applied to

Page 3


reduce payments due for the procurement of power that are included in, and indebtedness (and refinancings
thereof) incurred by SCE to finance, the net undercollected amount.  In connection with the execution of the
Purchase and Sale Agreement (as defined in Section 4(b)), SCE will deliver to CDWR a schedule of sources and uses
setting forth SCE's uses of the proceeds being applied to the net undercollected amount.

3.       Utility Retained Generation


         Subject to execution of the Definitive Agreements (as defined in Section 4(b)), adoption of the CPUC
Implementing Decisions, and adoption of the legislation contemplated hereby, SCE's generation assets, including
all energy, capacity, ancillary services, and any combination thereof, to which SCE has a contractual right
(collectively "URG"), will be committed to cost-based ratemaking for SCE's bundled service customers, and SCE
will not seek authority to sell such assets, through December 31, 2010.  In addition, SCE will operate its URG in
accordance with good utility practices, subject to the further terms hereof.  SCE's URG includes its interests in
Units 2 and 3 of the San Onofre Nuclear Generating Station ("SONGS"), the Palo Verde Nuclear Generating Station
("PVNGS"), the Mohave Generating Station ("Mohave"), the Four Corners Generating Station ("Four Corners"), SCE's
hydroelectric facilities ("Hydro Facilities"), and the Pebbly Beach generating facility.  URG also includes, for
their respective terms, power purchase contracts that SCE currently has, and other contractual rights that SCE
currently has, to purchase energy, capacity, ancillary services and any combination thereof, from other
utilities, power suppliers or qualifying facilities.  Consistent with the purposes of this paragraph, SCE will
withdraw its pending application with the CPUC to sell its Mohave, PVNGS and Four Corners facilities.

         This MOU does not address any aspects of the status and ratemaking treatment of the URG or the
ratemaking treatment therefore after December 31, 2010, and does not bind any party to any obligation or exempt
any party from any requirement in respect thereof.



Page 4


         In return, subject to execution of the Definitive Agreements, the adoption of the legislation
contemplated hereby and the adoption or approval of the CPUC Implementing Decisions, SCE will be entitled to
collect revenues sufficient to cover its costs from January 1, 2001, associated with its URG (and all costs for
ancillary services or other ISO costs associated with CDWR's procurement of the net short allocated to SCE under
Section 10) on a timely basis, in accordance with the principles of cost-based ratemaking as applied in this
State.  In this regard, one of the CPUC Implementing Decisions shall be the adoption by the CPUC of procedures
(which may include one or more balancing accounts and trigger mechanisms) designed to ensure that any
undercollection or overcollection of URG costs (provided that actual costs of utility-owned generation shall
equal authorized costs, except for variable fuel costs) will be reconciled in a timely manner and that any
undercollection can be financed on reasonable terms consistent with SCE being an investment grade credit (the
"URG Cost Recovery Mechanism").  The legislation necessary for the implementation of the Plan shall include
legislation overriding any applicable limits in A.B. 1890 which may be inconsistent with the foregoing recovery
principle.  For the period from January 1 through 31, 2001, SCE will be deemed to have recovered its costs
associated with its URG through the operation of the Transition Cost Balancing Account ("TCBA"), except for
depreciation and amortization that SCE shall recover as a capital-related cost as described below.

         Subject to the further provisions of this MOU respecting recovery of investments, and the ratemaking
principles set forth herein, a CPUC Implementing Decision shall provide that SCE's costs associated with its URG
will include, through December 31, 2010:

o        All customary categories of operating costs, including, but not limited to, fuel costs (fixed and
         variable), operations and maintenance expenses, costs of emissions credits (subject to the
         further provisions of Section 7), direct, joint and common administrative and general (A&G)
         costs (excluding non-site specific general plant, which shall be treated as a capital cost),


Page 5
         taxes, scheduling and dispatch costs, congestion costs, ancillary service costs, and other
         transmission-related costs charged to generators.

o        For SONGS 2 and 3, other than transmission-related costs, operating costs will be recovered through 2003
         through the existing Incremental Cost Incentive Procedure ("ICIP") and will be recovered
         without regard to the ICIP mechanism thereafter.

o        All reasonably recorded capital-related costs, including a full return on SCE's investment in used and
         useful URG (except as provided herein with respect to SONGS 2 and 3).  SCE's investment in URG
         will be set at the net book value of such assets on December 31, 2000, including site specific
         and non-site specific general plant and capital additions made after December 31, 1995, the
         costs of which have been reasonably and prudently incurred, together with their associated
         income tax regulatory receivable or payable, provided that the $129,783,000 of non-nuclear
         site-specific general plant and capital additions made after December 31, 1995 and described on
         a schedule that has been provided to CDWR and which have not to date been disapproved by the
         CPUC shall be allowed in SCE's rate base temporarily until the final approval or disapproval of
         such additions which shall be accomplished by the CPUC as soon as practicable.  Depreciation
         schedules will be based on the expected remaining useful life of each plant, fixed for this
         purpose for the period ending December 31, 2010 for SONGS 2 and 3 and PVNGS.  For purposes of
         this Section 3, "net book value" means the original cost recorded in SCE's books for a
         particular asset, less any accumulated depreciation or amortization plus any deferred or flow
         through taxes.  Assets that have been expensed shall not have a book value.



Page 6


o        All reasonable and prudent incremental capital investments put into service after December 31, 2000.
         Such investments, including income taxes and a full return on investment, will be recovered in
         rates from the time they are placed in service.  Incremental investment which has not otherwise
         been expensed will be depreciated over the expected remaining useful life of the plant in
         question, which for purposes of SONGS 2 and 3 and PVNGS, will be determined by the remaining
         term of the applicable license for each plant, granted to SCE by the Nuclear Regulatory
         Commission ("NRC"), as such licenses may be extended by the NRC.  Notwithstanding anything to
         the contrary in this Section 3, through 2003 incremental capital expenditures for SONGS 2 and 3
         will be recovered through the ICIP mechanism.

         Operating decisions, including dispatch decisions, maintenance practices, energy/capacity exchange
decisions, and other operating practices shall be performed by SCE in a reasonable and prudent manner.

         Under current CPUC decisions, net revenues from PVNGS after 2001 and net revenues from SONGS 2 and 3
after 2003 are subject to a sharing mechanism whereby profits (as defined) are shared equally between
shareholders and customers.  A CPUC Implementing Decision shall provide that such sharing mechanism, and all
associated provisions for transfer of post-ICIP cost responsibility to SCE, will be eliminated through December
31, 2010.  The existing memorandum of understanding respecting SCE's Hydro Facilities will be rendered moot, and
SCE will withdraw its associated application under Public Utilities Code section 377.



Page 7


4.       Transmission Sale


(a)      Purchase of Assets and Assumed Liabilities


         Subject to enabling legislation and the negotiation and execution of the pertinent contracts, CDWR, or
another authorized State agency (the "Purchaser"), will purchase SCE's transmission system.

         Subject to the further provisions of this MOU, the Transmission Sale includes all of SCE's right, title,
and interest to: (i) all transmission assets under ISO control; (ii) any other assets not under ISO control that
are used exclusively in connection with transmission and included in SCE's FERC rates charged to SCE's bundled
service customers, or, in the case of any such assets acquired after the date of such rates, includable in SCE's
FERC rates charged to SCE's bundled service customers; and (iii) related agreements and contracts.  The
transmission assets shall also include rights to the real property associated with or held for use in connection
with the transmission system ("Real Property") as well as other mutually agreed-upon assets and rights of SCE in
assets which are subject to joint interests of other parties, including shared assets and rights, it being
understood by the parties that the transmission assets to be acquired by the Purchaser, whether through the
acquisition of assets to be exclusively owned by the Purchaser or through the acquisition of rights in shared
assets, shall be sufficient for the Purchaser to acquire a functional transmission system capable of providing
transmission services of the type that it has in the past, with sufficient rights to repair and upgrade the
transmission system and to operate it efficiently and effectively.  It is also understood by the Parties that
SCE's transmission system has been built and operated on a fully integrated basis with SCE's distribution system
and that the Purchaser's operation of the transmission system and SCE's operation of the distribution system will
therefore necessarily involve mutually acceptable arrangements for the sharing by SCE and the Purchaser of
certain systems and assets to avoid duplicative and potentially substantial costs to ratepayers and taxpayers.
To the extent the Purchaser desires physical separation of transmission assets from distribution assets, the
costs of such separation, if feasible, will be borne by the Purchaser.  The Real Property and other assets


Page 8


included in the Transmission Sale are collectively referred to herein as, the "Purchased Assets."  Subject to the
further provisions of this MOU, title transferred to the Purchaser will be the same as SCE's title, provided that
the Purchased Assets will be transferred free and clear of liens and encumbrances securing SCE's indebtedness for
money borrowed or other obligations of SCE not related to the transferred assets or (unless the same has been
adjusted for in the purchase price or in prorations) not required to be assumed by the Purchaser hereunder;
provided, that the Definitive Agreements shall include provisions pursuant to which, if SCE is unable, after
using commercially reasonable efforts, to obtain the release of any liens or encumbrances which it is responsible
to release in connection with the sale of the Purchased Assets (other than liens or encumbrances securing
indebtedness for borrowed money), then such failure shall not be a failure of the foregoing condition or
otherwise a default on the part of SCE if SCE is diligently contesting such lien or encumbrance; SCE indemnifies
the Purchaser from and against any liability, damage, cost or expense incurred by it on account thereof; and such
lien or encumbrance has no material adverse effect on Purchaser's ownership or operation of a functional
transmission system capable of providing transmission services of the type that it has in the past, with
sufficient rights to repair and upgrade the transmission system and to operate it efficiently and effectively.

         SCE will retain all of its right, title and interest in and to its existing assets used exclusively in
the operation of its non-transmission business, such as generation assets (other than designated assets specified
in the Purchase and Sale Agreement, such as mutually agreed upon radial lines), assets used in SCE's distribution
business, communications facilities, protection systems, control facilities and oil pipeline assets, and SCE will
retain rights in other assets necessary for such businesses to continue to provide the services as they have in
the past.  The Purchase and Sale Agreement will set forth the procedures and methods for transferring and
retaining interests in assets that are to be shared by the Parties after the closing (because of the integrated
nature of the transmission and distribution businesses), provided that each Party will be entitled to the
economic benefit of its ownership or rights in a shared asset.  The Parties will in any event grant and reserve,

Page 9


as appropriate, such licenses, easements and reciprocal easements as may be necessary or, in the reasonable
judgment of the Parties, desirable, to permit the Parties to own, operate and maintain their respective assets
and their interests therein.  Such licenses, easements and reciprocal easements shall, among other things, assure
ingress, egress, access, utilities and support; permit maintenance, relocation, construction and alteration; and
protect against encroachment, all as provided for in the Definitive Agreements and subject to appropriate
limitations and protections to be provided for therein.

         If, following the Transmission Sale, the Purchaser decides to explore the possible offer for sale of all
or substantially all of the Purchased Assets (including all or substantially all of a larger transmission grid of
which the Purchased Assets may then form a part) through a competitive bidding process, the Purchase and Sale
Agreement will provide to SCE a non-exclusive opportunity to bid for all, but not less than all, of the assets
the Purchaser proposes to sell, on the same terms and conditions as may be applicable to the other bidders
generally.

         The Purchase and Sale Agreement will contain mutually agreed upon representations and warranties, which
will not include any representations and warranties regarding or related to the physical condition of the
Purchased Assets, but will include covenants regarding operations in the ordinary course. The assets will be sold
to the Purchaser on an "AS IS, WHERE IS" and "WITH ALL FAULTS" basis, and the Purchaser will assume all
liabilities to the extent related to the transferred assets, including all contractual obligations (including
obligations to provide transmission service and, without limiting the parties' obligations under other provisions
of this MOU, SCE's obligations under the Transmission Control Agreement with the ISO, if such assumption is
required to transfer SCE's rights in the Purchased Assets or in order for SCE to be relieved of its ongoing
obligations under the Transmission Control Agreement), environmental obligations, liabilities related to the
operation of the assets and decommissioning obligations, subject to the following:



Page 10


o        Recurring operating expenses will be subject to customary pro-ration as of the closing;

o        To the extent the cost of a liability has already been collected in rates by SCE, SCE will indemnify the
         Purchaser against such liability;

o        Liabilities for pending insured claims (including deductibles applicable thereto) will be retained by
         SCE;

o        SCE will assign its rights against insurers and third parties for liabilities assumed by the Purchaser
         and each Party will cooperate and assist the other in pursuing its rights against
         insurers and third parties related to assumed and retained liabilities, provided that
         if consent to such assignment is not received from insurers, then SCE will assign the
         insurance proceeds arising from such claims; SCE and the Purchaser will also negotiate
         provisions relating to the extension of claims periods under insurance policies
         related to the Purchased Assets, including provisions related to the cost thereof;

o        SCE will indemnify the Purchaser for environmental liabilities which are the "fault" of SCE, which term
         shall be as defined in the Purchase and Sale Agreement (it being understood that
         liabilities related to EMF will be assumed by the Purchaser, except for EMF-related
         liabilities for which SCE would retain responsibility under the preceding bulleted
         provisions of this Section and the last two bulleted provisions of this Section);

o        SCE will indemnify the Purchaser for other liabilities caused by SCE's gross negligence or willful
         misconduct prior to the Closing;


Page 11


o        SCE will indemnify the Purchaser for pre-closing breaches of contract under contracts not assigned to
         the Purchaser;

o        Non-ordinary course operating contracts to be assumed by the Purchaser will be disclosed in schedules to
         the Definitive Agreements which have been approved by the Purchaser and SCE;

o        Material liabilities (to be defined in the Definitive Agreements) actually known to a responsible
         officer of SCE and to be assumed by the Purchaser will be disclosed in schedules to
         the Definitive Agreements which have been approved by the Purchaser and SCE;

o        The Purchaser will not assume liabilities for pre-closing taxes, pre-closing criminal violations,
         breaches of the Purchase and Sale Agreement or similar liabilities customarily
         excluded from "AS IS" transactions; and

o        The Purchaser will not assume liabilities to the extent related to the assets and interests retained by
         SCE.

         The authorizing legislation will provide that from and after the sale of the Purchased Assets,
transmission costs will be charged to retail customers within the SCE service area by the Purchaser, and if
requested, SCE will, as billing agent, bill such charges and remit to the Purchaser all amounts collected, less
prorated uncollectibles.

(b)      Agreements; Form of Transaction


         In addition to a purchase and sale agreement for the Transmission Sale ("Purchase and Sale Agreement"),
the Purchaser and SCE would enter into certain related agreements as part of the transaction ("Related
Agreements").  These would include the following:



Page 12



o        O&M Agreement - Pursuant to which the Purchaser, as the owner, shall have the right to make decisions
         commensurate with such interest, including the decisions to make upgrades and to establish
         budgets.  In addition, pursuant to the O&M Agreement, SCE will provide operations and
         maintenance including ordinary repairs and billing and collections services for a minimum term
         of three (3) years with renewal options exercisable by the Purchaser.  SCE would be compensated
         through a fee to be negotiated.  For work not included in the fee, SCE's charges will be
         determined in accordance with the O&M Agreement subject to audit by the Purchaser.  The
         Purchaser will be responsible for the costs of all capital improvements.  It is the intention
         of the Parties that the O&M Agreement be structured so that improvements thereunder can be
         financed by tax-exempt bonds to the extent reasonably practicable.

o        Transmission Service Agreements - Pursuant to which the Purchaser will agree to provide SCE with
         nondiscriminatory transmission service for its URG and will further agree to provide
         nondiscriminatory transmission service for other power being delivered to SCE's customers.

o        Facilities Services and Coordinated Operations Agreements - Pursuant to which the Parties will agree to
         the delineation of responsibilities and costs (including the sharing of capital improvement
         costs) related to certain interrelated or shared assets.

         The Purchase and Sale Agreement together with the agreements contemplated in Section 5 (power sale
contract regarding Sunrise), Section 6 (grants of conservation property), and 7 (agreements regarding claims of
third parties) of this MOU, and the agreement, if any, effectuating CDWR's obligations with respect to the net
short as provided for in Section 10 are collectively referred to herein as the "Definitive Agreements."  The
Definitive Agreements shall include all terms and conditions contained in this MOU that are to be implemented
contractually, except as the Parties may mutually agree. The descriptions herein of the Definitive Agreements are


Page 13



intended as a summary, and do not contain an exhaustive list of all provisions to be addressed in such
agreements; and provided, further, that any additional terms and conditions shall not be inconsistent with the
terms and conditions contained in this MOU, except as the Parties may mutually agree.

         The Definitive Agreements shall recognize that CDWR's actions as contemplated in this MOU shall be
separate and apart from its powers and responsibilities with respect to the State Water Resources Development
System and that any and all obligations incurred and the funding for all such obligations and activities arising
from this MOU or the Definitive Agreements shall be separate and distinct from the funds, monies, and obligations
of the State Water Resources Development System.

(c)        Purchase Price


         The purchase price will be 2.3 times SCE's net book value for the Purchased Assets as of December 31,
2000, subject to verification of recorded amounts in accordance with provisions to be negotiated in the
Definitive Agreements and the adjustments noted below, plus the sum of (i) approximately $63 million of
accelerated depreciation or similar tax benefits previously flowed through to ratepayers (grossed up for taxes
payable on the recovery of such benefits in accordance with past ratemaking practices) and (ii) the transfer
taxes payable in connection with the sale of the Purchased Assets.  For purposes of this Section 4, "net book
value" means the original cost recorded in SCE's books for a particular asset, less any accumulated
depreciation.  Assets that have been expensed shall not have a book value.  The Parties currently estimate that
the unadjusted purchase price will be approximately $2.76 billion.  The purchase price will be subject to the
following adjustments:

         (1)      To add the net book value at closing of reasonable and prudent capital additions made to the
                  Purchased Assets after December 31, 2000 to the extent not recovered in transmission rates
                  prior to the closing, provided that capital additions approved by CDWR or the ISO and capital


Page 14

                  additions that are in process or planned and that are disclosed in a schedule to the Definitive
                  Agreements shall be deemed reasonable and prudent.  Subject to the preceding sentence, capital
                  additions that are in process at the time of the closing of the Transmission Sale will be
                  valued at the investment made as of the closing date.

         (2)      To add the net book value of any spare parts and similar current items to the extent included
                  in the Purchased Assets;

         (3)      To subtract the post-December 31, 2000 depreciation of the Purchased Assets;

         (4)      To subtract the book value of any Purchased Assets existing as of December 31, 2000 that are
                  sold after that date, provided that if such assets are not sold in the ordinary course of
                  business and not replaced by assets intended as equivalent replacements, the amount subtracted
                  shall be 2.3 times the book value of the sold assets; and

         (5)      To add or subtract for such additional items as the Parties may agree upon.

Items such as rent, insurance, taxes and the like that are customarily pro-rated for partial periods will be
pro-rated at the closing.  For purposes of this MOU, references to the "gain on sale" of the Transmission Sale
shall mean proceeds of sale minus transaction costs paid or to be paid by SCE (other than those set forth in
Section 9), transfer taxes payable by SCE, net book value of the Purchased Assets (including undepreciated
capital additions as set forth above), and the recapture or recovery by tax authorities of approximately $63
million of accelerated depreciation or similar tax benefits previously flowed through to ratepayers (grossed up
for taxes payable on the recovery of such benefits in accordance with past ratemaking practices).



Page 15


(d)      Use of Proceeds


         Proceeds from the Transmission Sale (including the back-up transaction referred to in paragraph (f)
below) representing the net book value of the assets transferred at the closing (based on SCE's recorded amounts)
will be used to reduce debt and equity (including through dividends, to the extent permitted by the California
Corporations Code and consistent with SCE's authorized capital structure).  The proceeds representing the gain on
sale will be applied to recover SCE's "net undercollected amount," as described in Section 9 of this MOU, and
accordingly will be applied to payments due for the procurement of power that are included in, and indebtedness
(including interest thereon and refinancings thereof) incurred by SCE to finance, the net undercollected amount,
including any securitization of such indebtedness.

(e)      Closing Conditions


         In addition to any other conditions described in this MOU, closing of the Transmission Sale transaction
will be subject to other mutually agreed upon conditions, including receipt of all necessary approvals, without
unreasonable conditions materially adverse to either party, from FERC, the ISO and SCE's Indenture Trustee, if
required.  It is contemplated that, regarding the sale of the Purchased Assets to the Purchaser and the other
actions to be implemented contractually pursuant to this MOU, the legislative authorization will dispense with
CEQA compliance.  It is also contemplated that, regarding the sale of the Purchased Assets to the Purchaser, the
legislation will dispense with approvals by the CPUC.  Such legislation will also authorize the CDWR (or such
other agency) and the Purchaser to enter into the transactions as contemplated hereby.  The closing will also be
conditioned upon the absence of any injunction, restraining order or other order restraining or prohibiting the
consummation of the transactions contemplated in this MOU, and the absence of any suit by the Federal Government
seeking to restrain or prohibit the consummation of the transactions contemplated in this MOU.



Page 16


         SCE will be required to deliver assets and rights sufficient for the Purchaser to acquire a functional
transmission system capable of providing transmission services of the type that it has in the past, with
sufficient rights to repair and upgrade the transmission system and to operate it efficiently and effectively.
Subject to the foregoing, the Parties intend that a failure to obtain a necessary consent or approval to transfer
that relates to only a portion of the Purchased Assets, after the Parties have used commercially reasonable
efforts to do so, or a third party's exercise of a right of first refusal, will not result in a failure of
closing conditions so long as the Purchaser obtains substantially the same benefits of the contemplated bargain
as described below.  In the event such a consent or approval is not received in a timely manner, the Parties will
work in good faith to provide substantially the same benefits of the contemplated bargain to each of them through
contractual and other means not involving an actual transfer that is subject to such consent or approval.
Without limitation, the benefits of the contemplated bargain include, in the case of the Purchaser, the ability
of the Purchaser to have upgrades and improvements made to the transmission system intended to be purchased by
the Purchaser hereunder, without any material limitation.  If the Parties are unable to provide substantially the
same benefits of the contemplated bargain through contractual and other means (but in all events subject to the
condition that the assets and rights to be acquired by the Purchaser must be sufficient for the Purchaser to
acquire a functional transmission system capable of providing transmission services of the type that it has in
the past, with sufficient rights to repair and upgrade the transmission system and to operate it efficiently and
effectively), then the portion of the Purchased Assets in question will not be transferred, and there will be an
equitable adjustment in the purchase price.  In the event of any such exclusion of assets and equitable
adjustment of price, SCE shall nonetheless cooperate with the Purchaser after the closing in order to enable
upgrades and improvements to be made to that portion of the Purchased Assets that are not transferred.



Page 17


         (f) Back-Up Transaction

         If the Transmission Sale fails to close within 24 months (subject to extension by one party if the
failure to close is due to the breach of the other party) of the execution of the Purchase and Sale Agreement for
a "Qualified Triggering Reason" (as defined below), then SCE shall offer to sell to CDWR or its designated
Purchaser (i) its hydroelectric assets and, if such assets do not produce a gain on sale substantially equivalent
to the gain expected from the Transmission Sale, (ii) such rights, over a reasonable period of time, to the
output of SCE's interests in generating plants (including its interests in Four Corners, SONGS, PVNGS and Mohave
if then operated) after 2010 on terms and conditions that result in a value to CDWR determined on a net present
value basis at the time of the consummation of the sale of the hydroelectric assets, reasonably equal to the
difference between the gain expected from the Transmission Sale and the gain expected from the sale of the
hydroelectric assets.  If CDWR or such Purchaser so elects to purchase such assets, then the Parties will
promptly negotiate in good faith a definitive sale agreement respecting such assets that shall contain terms
comparable to the terms of the Transmission Sale.  Upon execution of an agreement in respect of the alternative
assets, the Purchase and Sale Agreement for the Transmission Sale will be cancelled and the references herein to
the "Purchase and Sale Agreement" shall mean the definitive sale agreement for such alternative assets, and to
the "Purchased Assets" shall mean the alternative assets purchased in such sale, mutatis mutandis.

         A Qualified Triggering Reason will be defined in the Purchase and Sale Agreement for the Transmission
Sale consistent with the following: Failure to close for any reason other than (x) a breach or default by the
Purchaser causing the failure to close, or (y) other reasons mutually agreed upon in the Definitive Agreements,
it being understood that it is the intent of the Parties that (i) breaches of the Purchase and Sale Agreement by
either Party that are compensable in damages or are immaterial will not provide a basis for the other Party's
failure to close (provided that, in the case of Purchaser, upon closing Purchaser would obtain the benefits of
the contemplated bargain as described above) and (ii) the Purchaser's or SCE's failure to close because a


Page 18


regulatory authority or the ISO reasonably conditions its approval of the Transmission Sale shall not constitute
a Qualified Triggering Reason.

5.       Sunrise Project


         An EIX company will commit by contract - for a term of not less than 10 years - the entire output of the
Sunrise power project (the "Sunrise Project") to CDWR or its designee under cost-of-service based rates on terms
and conditions to be set forth in a Definitive Agreement that incorporates the terms hereof (the "Sunrise
Agreement").  The EIX company will continue to use all commercially reasonable efforts to place Phase I of the
Sunrise Project in service before the end of the Summer, 2001.  Cost-of-service based rates shall be determined
on the basis of a 50/50 debt to equity leverage, permanent financing at the Phase II commercial operations date,
an assumed long-term interest rate of 9.0%, an 11.6% return on equity, a useful life of the facility of 30 years
and a value at the end of the contract term equal to book value less undepreciated acceleration costs to bring
Phase I online by Summer 2001.  The fuel cost shall be passed through to CDWR, with a right of CDWR to supply its
own fuel, provided CDWR gives the notice to be specified in the Sunrise Agreement.  All other prices shall be
fixed in the Sunrise Agreement.  The capacity price, based on capital cost estimates for the Sunrise Project as
of the signing of this MOU, would be $120/kW-yr for Phase I and $176/kW-yr for Phase II.  The final capacity
price will be based upon final costs incurred for the Project, which costs shall be subject to audit verification
by CDWR.  If the actual costs would result in a lower capacity price, the final price to CDWR shall be that lower
capacity price.  If the actual costs would result in a higher capacity price, CDWR and the EIX company shall
share the increased costs on a 50/50 basis and the capacity price on Phase II shall be increased accordingly.
The price for variable O&M, other than fuel costs, shall be fixed at $3.00/MW H for the term of the Sunrise
Agreement.  In addition to the above variable O&M payment, CDWR shall be responsible for start up payments per
start for each normal start up in excess of 100 normal start ups per contract year in accordance with the
following schedule:  101-135 starts at a cost of $300/start, 136-150 starts at a cost of $5,000/start, over 150



Page 19



starts at a cost of $14,000/start.  The Sunrise Agreement shall provide CDWR with the standard rights of dispatch
for this type of arrangement.  The Phase I capacity charge is based on a limitation of the hours of operation as
specified in the latest term sheet provided by the EIX company to CDWR prior to the date of this MOU based upon
emission credits which the EIX company has obtained for the Project.  Any increase in the hours of operation that
CDWR may request would reflect increased costs for additional emission credits which would be reflected in an
increase in the capacity charge to be agreed to by the Parties.  In the event that this MOU terminates, the
foregoing agreement for the Sunrise project would be withdrawn and subject to new discussions between the
parties.  Notwithstanding the foregoing, the Sunrise Agreement shall provide that if the Sunrise Project is not
placed in service on or before August 15, 2001 subject to extension for a force majeure event outside of the
control of the EIX company, the EIX company party thereto will credit the amount of $2,000,000 against the first
$2,000,000 in billings the CDWR would otherwise be required to pay the EIX company under the Sunrise Agreement.

6.         Conservation Property


          Pursuant to the Definitive Agreements, SCE will convey perpetual protective conservation easements to
approximately 20,600 acres of its Big Creek hydroelectric related lands and approximately 825 acres of its
Eastern Sierra hydroelectric related lands to a trust for the benefit of the State of California, which trust
will serve as the interim holder of these interests while disposition and management plans therefore are
developed as described below.  The easements will restrict public agency access over lands included in FERC
licensed areas to limited purposes consistent and that do not interfere with utility uses over such property.

         The purpose of these conveyances will be to ensure the long-term conservation of these lands for their
public interest value for the people of the State of California, including fish, wildlife, and other ecological
purposes; human recreation; preservation of open space and cultural resources; and for protection of water


Page 20




quality and watershed functions.  Accordingly, the trust conveyances will restrict future development over such
lands in perpetuity, subject to the following:  (i) existing non-utility uses based on current levels of activity
shall be permitted for a period equal to the longer of 5 years or the remaining term set forth in existing
leases, licenses, permits or other applicable agreements; (ii) existing utility uses (i.e., ownership and
operation of any existing hydroelectric plants located on said lands and related improvements, including, in
connection therewith, the maintenance, repair, replacement and installation of public utility infrastructure,
such as water and sewer pipelines, and electric and telecommunications lines for existing utility uses) based on
current levels of activity shall in all events be permitted for as long as the same continue; (iii) expansion of
hydroelectric facilities currently located on said lands shall be permitted, but only with the approval of the
state and federal agencies with jurisdiction over any such expansion; (iv) SCE's current timber harvesting,
logging or similar activities shall be subject to modification based on the approved management and disposition
plans referred to below; and (v) the maintenance, repair, replacement and installation of public utility
infrastructure, such as water and sewer pipelines, and electric and telecommunications lines for non-utility and
other uses to the extent permitted pursuant to the management and disposition plan.  SCE will indemnify the
trust, the State and any successor-in-interest against environmental liability associated with these lands, only
to the extent attributable to SCE's own negligent or willful acts.

         The Definitive Agreements will provide that during the period the trust holds these interests, the
Wildlife Conservation Board or another state agency whose primary mission includes the above purposes to be
identified in the Definitive Agreements will develop, with input from SCE, local governments, federal agencies
and other stakeholders, disposition and management plans for each of the conservation easements conveyed by SCE,
through a property-specific process in which public input shall be obtained.  All such disposition plans will be
subject to the reservations contained in the easement grant, as specified above.  The plans will analyze each
property's natural resource, recreational, and economic use value to the people of the State of California and to
the local community, subject to protection for existing uses and potential expansions of hydroelectric activities
as set forth above, and determine the appropriate interests in the various lands to be transferred to the State
or applicable agencies thereof (or, where appropriate, the U.S. Forest Service, or other applicable federal


Page 21



agencies, local governmental agencies or, after consultation with and subject to the approval of SCE,
non-governmental conservation organizations or other third parties specified in Civil Code Section 815.3) to
preserve these values.  As part of this process, the trust may request of SCE that it convey a fee interest in
specific properties, and SCE will consider any such request in good faith on the basis of the specific
justifications therefore and the necessity thereof in light of the existence of the conservation easement,
provided that any such conveyance will be subject to an easement back to SCE in form and substance reasonably
satisfactory to it to protect its interests, and no fee ownership request will relate to lands covering existing
hydroelectric facilities and related uses as well as reasonable expansions thereof.

         It is anticipated that these disposition and management plans will be completed within 18 months after
the conveyances of the easements to the trust (subject to compliance with applicable laws), and dispositions of
the property or interests therein to the State or applicable agencies thereof, to the U.S. Forest Service or
other applicable federal agencies, to local governmental agencies, or, after consultation with and subject to the
approval of SCE, non-governmental conservation organizations or other third parties specified in Civil Code
Section 815.3, will occur once such individual plans are finalized.

         The formal terms of the trust arrangement will be negotiated between the designated State agency and SCE
as part of the Definitive Agreements on the basis of the principles enumerated above. Except as provided in the
Definitive Agreements, SCE will continue to pay all expenses associated with the properties over which it has fee
title, including property taxes, and will receive all income generated from these properties.



Page 22



7.       BFMs; Emission Credits; Claims Against Third Parties


          Upon execution of the Definitive Agreements, SCE will relinquish all claims against the State for
commandeering SCE's block forward market contracts ("BFMs") purchased through the California Power Exchange
("PX"), and in connection therewith, CDWR will assume SCE's liabilities in respect of any claims arising on or
after February 2, 2001 or relating to the collateral value of the BFMs after such date brought by the PX and/or
PX Participants related to the BFMs.

         The Definitive Agreements shall obligate SCE, subject to pertinent regulatory approvals, to sell certain
mutually agreed upon emission credits related to its previously sold generating stations, with the proceeds of
such sale to be for the benefit of ratepayers, or, alternatively, SCE shall, subject to pertinent regulatory
approvals, convey such credits to the State's Mitigation Bank for no additional consideration.

         In connection with the Definitive Agreements, the parties will negotiate concerning their mutual
cooperation and coordination with respect to pursuing potential claims against third-party generators, and such
Definitive Agreements may contain provisions for the assignment of such claims from SCE to the State or its
agencies at times and upon terms to be mutually agreed upon.  To the extent SCE at any time after execution of
this MOU realizes a discount or credit in connection with the payment of any obligation included in the
undercollection amount described in Section 9 of this MOU, the amount of such discount or credit shall be applied
to the benefit of ratepayers in a manner to be more fully set forth in the Definitive Agreements.

8.       Tax Payments


         To the extent not previously refunded by EIX after January 1, 2001, EIX will, following its filing of a
final federal income tax return for the year 2000, refund to SCE its year 2000 estimated quarterly tax payments
(approximately $293 million), and will fund an additional payment to SCE equal to the federal loss carryback
(currently estimated at approximately $127 million) that SCE would have had if it were not part of EIX's



Page 23

consolidated group of taxpayers; provided that in no event will refunds from EIX to SCE attributable to tax year
2000 aggregate less than $400 million.

9.       Net Undercollected Amount


         For the purposes of this MOU, the "net undercollected amount" shall be computed as set forth in the
remainder of this paragraph.  For the purposes of this calculation, SCE's TCBA and Transition Revenue Account
("TRA") as of January 31, 2001 will not be combined.  The balance in SCE's TCBA as of January 31, 2001 (adjusted
(a) to exclude any amortization and depreciation for presently owned generating facilities, together with their
associated regulatory receivable or payable for taxes that has occurred since December 31, 2000, which shall be
recovered as provided in Section 3 of this MOU, (b) to include the associated Generation Memorandum Accounts, and
(c) to exclude any entries with corresponding entries in the Generation Asset Balancing Account) will be applied
to reduce the January 31, 2001 TRA balance (adjusted to remove amounts representing potential payments to CDWR or
the ISO for the period January 18 to 31, 2001 which are part of the procurement obligations which are being
assumed by CDWR pursuant to Section 10), resulting in a "net undercollected amount."  The net undercollected
amount (i) will include retail generation revenues in respect of power delivered in January 2001 received in
February 2001 and thereafter (until the end of the last full calendar month preceding the execution of the
Definitive Agreements), (ii) will exclude accrued QF costs as of January 31, 2001 not yet actually due and
payable as of that date (it being acknowledged that, notwithstanding the January 2001 cost recovery mechanism in
Section 3, SCE will be entitled to recover these accrued QF costs in a timely manner in rates going forward),
(iii) will exclude ISO charges (including imbalance energy charges) assumed by the CDWR, as set forth in Section
10, and (iv) will include CDWR charges on account of certain QF's not delivering power to SCE, set forth in
Section 10 of this MOU and SCE's cost obligations described in Section 15 of this MOU.  Subject to the foregoing,
the size of the net undercollected amount as computed under this paragraph will be subject to verification of
recorded amounts and any resulting adjustments by the CPUC, within 60 days of the passage of the legislation


Page 24



referred to below.  The net undercollected amount will be deemed to equal the amount submitted by SCE if the CPUC
does not complete the verification process (and any adjustments resulting therefrom) within the 60-day period.
The net undercollected amount and the costs reflected therein will not be subject to review by the CPUC or any
other legislative, administrative or judicial body for reasonableness.  SCE estimates that the net undercollected
amount, as of January 31, 2001 was approximately $3.5 billion.

         Legislation will direct the CPUC to establish an initial nonbypassable dedicated rate component
(including recovery of associated franchise fees and uncollectibles) intended to be securitized, subject to the
terms hereof, as soon as practicable after the establishment thereof.  Such dedicated rate component will enable
SCE to recover (i) the full net undercollected amount less the expected gain on the Transmission Sale described
in Sections 4(c) and 4(d) above; (ii) the discounted net present value of interest on the expected gain on the
Transmission Sale for a period commencing on the date of the consummation of the securitization of the Initial
Dedicated Rate Component as described below and ending two years after the date of the execution of the Purchase
and Sale Agreement; and (iii) interest on obligations included in the undercollection or interim financing
thereof during such period from January 31, 2001 until the securitization transaction covering (i), (ii) and
(iii) is consummated, based on an effective interest rate to be mutually agreed to and set forth in the
Definitive Agreements, net of interest earned by SCE on its balances of cash, cash equivalents and other liquid
assets, if any, during such period in excess of its normal cash balances.  Such dedicated rate component is
referred to herein as the "First Dedicated Rate Component."  SCE's actual borrowing costs are referred to herein
as "SCE's interest cost."  As indicated above, the amount of interest described in clause (ii) will be
appropriately discounted to reflect SCE's receipt of such amount in the securitization transaction before
interest on the expected gain on the Transmission Sale would actually accrue.   SCE's interest cost shall be
addressed as provided in this paragraph and, subject to the consummation of the financings and securitizations
contemplated hereby, shall not be recoverable in rates (other than through the dedicated rate component described
above), except that any difference between the amount of interest securitized by SCE pursuant to clause (ii)


Page 25


above and the actual net amount of interest incurred by SCE with respect to financing of a portion of the
undercollection equal to the expected gain on the Transmission Sale from the date of the consummation of the
securitization of the Initial Dedicated Rate Component until the earlier of two years after the date of the
execution of the Purchase and Sale Agreement or the consummation of the Transmission Sale (based on a rate to be
mutually agreed to and set forth in the Definitive Agreements) shall be recovered by or paid by SCE from or to
its ratepayers.

         Legislation will further direct the CPUC to establish a second nonbypassable dedicated rate component
(including recovery of associated franchise fees and uncollectibles) that enables SCE to recover the expected
gain on the Transmission Sale as described in Section 4(c) and 4(d) above, subject to the provisions set forth
below.  This dedicated rate component is referred to herein as the "Second Dedicated Rate Component."  The Second
Dedicated Rate Component is intended to provide a source to secure bridge financing of the expected gain on the
Transmission Sale.  It shall not appear in rates for two years after the execution of the Purchase and Sale
Agreement and shall be made subject to the Transmission Sale not closing before such time.  The Second Dedicated
Rate Component would not be eligible to be securitized through a public offering of debt securities by a special
purpose entity until it is eligible to appear in rates as provided above, but may be used to secure or facilitate
bridge financing prior to such time.  However, the Second Dedicated Rate Component will have the benefit of a
financing order of the kind described in Article 5.5 of the Public Utilities Code or order or action having
equivalent effect, and shall be effective no later than the effectiveness of the financing order or its
equivalent for the First Dedicated Rate Component.  If the actual gain on the Transmission Sale exceeds the
estimated amount, then the difference shall be refunded to SCE's customers; if the actual gain on the
Transmission Sale is less than the estimated amount, then the deficiency will be recovered from SCE's customers
in retail rates over the term of the securitization period.  Likewise, if there are other elements (other than


Page 26



interest, which is covered in the preceding paragraph) included in the amount securitized which are based upon
contingencies related to the consummation of the Transmission Sale (such as, for example, estimates of closing
costs), there shall be adjustments (to be refunded to or recovered from SCE's customers) if the actual amounts
are less than or greater than the estimated amounts.  In addition, if any amount paid to SCE from the proceeds of
the initial securitization is intended to cover costs other than procurement costs (such as interest or closing
costs), SCE shall maintain such amounts in one or more segregated accounts and use the amounts therein solely for
the purposes for which they were paid.  Further, the Definitive Agreements shall provide for appropriate
adjustments upon the Transmission Sale in the event that the Second Dedicated Rate Component has commenced but
the Transmission Sale has not yet occurred.

         The dedicated rate components will be used solely to recover the net undercollected amount, together
with (a) reasonable costs incurred by SCE associated with any financing of such amount (including any reasonable
hedging costs incurred by SCE in a reasonable hedging transaction approved by the Department of Finance to hedge
SCE's interest rate risk if the interest rate provided for in the financing order or equivalent is a fixed or
determined rate) and (b) costs incurred or anticipated to be incurred by the State and the CDWR in connection
with this MOU, the Transmission Sale, or the securitization, as more fully described in Section 15.  The terms of
any securitization transaction will be subject to the approval of the Director of the State Department of
Finance, which approval shall not be unreasonably withheld or delayed.  The net undercollected amount will be
amortized over a period of not less than 15 years unless placement of securities with such a maturity is not
reasonably practical, in which case a shorter maturity shall be authorized by the Department of Finance.

         The legislation will further contain provisions that are the same as Article 5.5 of the Public Utilities
Code, mutatis mutandis, and that are designed to facilitate the securitizing of the First and Second Dedicated
Rate Components, with such changes thereto as may be agreed upon by the Parties as necessary to effectuate the
foregoing provisions.



Page 27



         Amounts financed through such dedicated rate component(s) will not be regarded as long-term debt for
purposes of determining the utility's authorized capital structure.  Any tax benefits resulting from the timing
difference between the incurrence of procurement costs and the recovery thereof through the financing
contemplated in this Section 9 will be used to benefit retail customers.  The amount of benefit resulting from
any such tax timing difference during each applicable period will be determined by using a rate of return equal
to the weighted average yield applicable to the securities issued in such financing.

10.      Procurement Obligations


         Either through legislation and/or through a contract between SCE and CDWR (which, if in the form of a
contract, shall be a Definitive Agreement), the following will be effected:

o        Through December 31, 2002, CDWR will assume the entire responsibility for procuring the full net short
         needs of retail customers within the SCE service area (i.e., the electricity needed to meet
         SCE's load that is not met by the generation resources owned or under contract to SCE as of
         January 18, 2001, plus any additions thereafter).  CDWR shall also assume responsibility for
         ancillary services (other than regulation, except to the extent the parties agree pursuant to
         the next paragraph) associated with CDWR import energy purchases and responsibility for the
         cost of Reliability Must Run contracts from January 18, 2001.  In addition, CDWR will also
         assume responsibility for ISO charges to SCE for the energy cost component of energy purchased
         by the ISO since January 18, 2001, to meet the net short requirements in SCE's service area
         (such energy cost component shall not include charges for underscheduling, capacity charges,
         ancillary services or PX or similar chargebacks, except to the extent the parties agree
         pursuant to the next paragraph).



Page 28


o        It is the intent of both SCE and CDWR that the overall costs to SCE's retail customers be minimized, and
          accordingly SCE and CDWR agree that SCE's operation of URG and CDWR's net short procurement
          should be coordinated.  SCE and CDWR will negotiate a mutually-agreeable operational protocol
          which will address the use of URG for self-scheduling of ancillary services, and will allocate
          responsibility for procurement and costs of ancillary services.  In addition, the operational
          protocol will allocate cost responsibility for any ISO underscheduling penalties based upon
          SCE's good faith forecast of the net-short and CDWR's activities to procure sufficient
          quantities to meet SCE's forecast.  SCE shall be entitled to collect revenues through its
          retail rates sufficient to cover the costs of any ancillary services it is responsible for on a
          timely basis.


o        SCE will cooperate with CDWR to achieve operational efficiencies for bundled service customers; and


o        SCE power purchases, and, until it is creditworthy, utilization of URG, to meet its obligations under
         interutility contracts will be allowed with an offset for the net proceeds of any sale of
         power.

         CDWR desires to be relieved of its obligation to provide for the net short needs of SCE's retail
customers, and SCE agrees to resume procurement of the full net short needs and electric requirements for retail
customers within the SCE service area after 2002.  In addition, after 2002, CDWR may at least assign to SCE the
administration of any of CDWR's outstanding procurement contracts.  The Parties will work together to minimize
the burden on CDWR, without imposing direct or indirect financial risks on SCE for those contracts.  The Parties
recognize that legislation may be needed to achieve this result.


Page 29



         Given the magnitude of the net short and SCE's current financial condition, the practical ability of SCE
to resume such procurement responsibility after 2002, and to relieve CDWR of such burden, will depend in
substantial part upon prompt restoration of SCE's creditworthiness and its ability to recover such procurement
costs in rates on a timely basis.  Accordingly, the CPUC Implementing Decisions will include confirmation of
SCE's entitlement to recover its reasonable procurement costs on a timely basis and establish procedures (which
may include one or more balancing accounts and trigger mechanisms) designed to ensure that any undercollection or
overcollection of procurement costs will be reconciled in a timely manner and any undercollection will be able to
be financed on reasonable terms consistent with SCE being an investment grade credit, and mechanisms to mitigate
the potential risks of retrospective reasonableness review of procurement practices, including the development of
a framework and criteria for procurement practices, the submission of an annual procurement plan, and the prompt
approval or disapproval of contracts (the "Procurement Cost Recovery Mechanism").


         In addition, subject to execution of the Definitive Agreements and adoption of legislation necessary to
implement this MOU, SCE shall cooperate with CDWR in the implementation of AB 1X, including provision by SCE of
such information as CDWR may reasonably require in connection with the financing of its power purchase program.
SCE and CDWR shall also execute a mutually approved servicing agreement (which shall not be treated as a
Definitive Agreement hereunder) relating to the distribution, billing and collection of CDWR power for customers
in SCE's service area.

         Upon the securitization of the First Dedicated Rate Component referred to in Section 9 hereof, SCE shall
pay CDWR an amount to be agreed upon representing those costs incurred by CDWR in covering that portion of the
net short from January 18, 2001 through April 7, 2001 which is attributable to certain QF's not delivering power
to SCE, it being agreed that such payments to CDWR shall be added to the net undercollected amount referred to
herein and shall not be construed as any admission by SCE.



Page 30


         The Parties agree to discuss in good faith the terms pursuant to which SCE, as agent and not as
principal, would be willing to assist CDWR in the management of its power purchase contracts, on terms to be
resolved in a subsequent agreement.  Such subsequent agreement shall not be considered a "Definitive Agreement"
as defined herein.

11.      Investment Recovery


         One of the goals of the Plan is for SCE to be an investment grade credit.  The Parties recognize that
the creditworthiness and health of SCE, and the ability of SCE to finance infrastructure improvements, require
greater certainty in respect of SCE's ability to earn a fair return on invested capital.  Accordingly, new
legislation will provide that SCE's authorized return on equity may not be reduced by the CPUC below its current
11.6% before December 31, 2010, and that prior to such date, the CPUC will not establish a ratemaking capital
structure for SCE with different proportions of common equity or preferred equity to debt than that set forth in
current authorizations.

12.      Capital Commitment by EIX; "First Priority" Condition


         Pursuant to the Definitive Agreements, EIX and SCE shall commit to make capital investments in SCE's
regulated businesses of at least $3 billion through 2006, or such lesser amount as the CPUC may approve, with the
equity component thereof funded from utility retained earnings or, if insufficient, from EIX equity investment,
provided that SCE will receive a return of and on equity in retail rates as provided in Section 11 hereof.

         The CPUC Implementing Decisions will include a clarification that the "first priority" condition in the
decision authorizing the formation of a holding company for SCE (D. 88-01-063, Condition 12) refers to equity
investment, not working capital for operating costs.



Page 31



13.      Additional CPUC Implementing Decisions


         In addition to the URG Cost Recovery Mechanism, the Procurement Cost Recovery Mechanism, and the other
provisions of this MOU that are contemplated to be implemented through CPUC Implementing Decisions, the CPUC
Implementing Decisions shall include:

o        Orders resolving the responsibility of SCE to provide credits to direct access customers in respect of
         electricity deliveries after December 31, 2000 in respects which do not result in any material
         financial detriment to SCE; and

o        A favorable determination by the CPUC in response to a request to be submitted by SCE that SCE's 2002
         Utility Distribution Company's GRC will be deferred to test-year 2003.

14.      Litigation Settlement


         As part of the implementation steps, the Parties to the federal lawsuit either will enter into a
stipulated judgment resolving the federal lawsuit by abandonment of SCE's claims and reflecting those terms of
this MOU that have not been secured either by entering into a Definitive Agreement, by CPUC action or by
legislation, or, if reasonably acceptable at the time to SCE, will enter into a dismissal, with prejudice, of
those claims.  The claims to be abandoned or dismissed by SCE as part of the settlement of the Federal litigation
will include, without limitation:

o        any claim SCE may have or could have had against the State of California or any agency, department  or
         subdivision thereof, the Federal Government, or the CPUC for takings or under the filed rate
         doctrine arising from or related to the facts asserted in such litigation; and



Page 32


o        any claims challenging actions taken by the CPUC prior to execution of the last executed Definitive
         Agreement to implement AB 1X and 6X, including, without limitation, any determinations by the
         CPUC, State of California or any agency, department  or subdivision thereof of the California
         Procurement Adjustment or the Fixed Department of Water Resources Set Aside.

In addition as part of the Definitive Agreements, the parties thereto will negotiate in good faith releases of
certain other claims.  The judgment or dismissal will be filed promptly following passage of all legislation,
execution of the Definitive Agreements and issuance of the financing order or equivalent for the securitizations
of the First and Second Dedicated Rate Components.

15.      Implementation Principles


         The MOU signifies the intention of the Parties to act in good faith to sponsor and support legislation
effecting elements of the Plan to be implemented by legislation and to act in good faith to negotiate final
agreements for those elements of the Plan that are to be implemented by contract.  As part of such intention,
each Party will allow for reasonable due diligence by the other Party, and SCE will not seek to sell, encumber or
otherwise dispose of the transmission assets to any other person or entity or submit any application in respect
of the same to the CPUC or FERC.  This MOU shall be terminable by either Party upon written notice to the other
in the event that such legislation is not passed and the Definitive Agreements are not executed by August 15,
2001 unless the Parties otherwise agree.  This MOU shall also be terminable in the event that any of the
following (each, a "Material Adverse Change") occurs: (a) in the event any law is passed, adopted or repealed or
regulatory action taken which, in the good faith judgment of such Party, would materially impede or frustrate the
ability of the Parties to effectuate all of the elements of the Plan as a package; (b) as set forth above, in the
event that all of the actions and approvals expressly characterized herein as "CPUC Implementing Decisions" have
not been taken or adopted on or before sixty (60) days after the date this MOU is signed by all Parties; (c) in
the event of the adoption of or any change in any applicable rule, regulation or order which would have a
material adverse effect on any Party or which, in the case of SCE, would include the failure on the part of the
CPUC, following a motion therefor filed on behalf of SCE (i) to extend SCE's existing non-generation Performance



Page 33


Based Ratemaking and cost of capital mechanisms until SCE's new GRC is implemented; (ii) to terminate the
Accelerated Cost Recovery and Reduced Cost Recovery ("ACRA/RCRA") mechanisms; (iii) to permit the amortization of
the RCRA reserve, in accordance with prior CPUC decisions; (d) in the event that any material penalty is imposed
by the CPUC in respect of the relationship between SCE and EIX prior to the date hereof, including without
limitation any of the matters raised in Order Instituting Investigation 01-04-002 or (e) in the event any
bankruptcy proceeding in respect of any Party is commenced.  In the event of termination of this MOU or any
failure of the Definitive Agreements to be executed or become effective, there shall be no liability for damages
or otherwise on the part of a Party to another under or by reason of this MOU or any discussions, negotiations or
conduct pertaining to this MOU or by reason of the failure of the transactions contemplated hereby or thereby to
be consummated.

         Inasmuch as each element of the Plan is part of an integrated package, the effectuation of each will
depend upon effectuation of the others.  In particular:

                  (i)      Execution of the Definitive Agreements will be subject to final passage and
         effectiveness of legislation implementing all elements of the Plan that are required to be legislatively
         implemented and the adoption of the CPUC Implementing Decisions.  The Parties recognize that, as part of
         the Definitive Agreements, mutually acceptable provisions shall be made with respect to liabilities for
         PX chargebacks and ISO underscheduling charges.

                  (ii)     Any financing order implementing the dedicated rate component(s) will be subject to
         execution of the Definitive Agreements by the parties thereto, and the consummation of the effectiveness
         of the Definitive Agreements shall be conditioned upon the existence of financing orders or their
         equivalent establishing irrevocable dedicated rate components for the "net undercollected amount"
         referred to in Section 9.



Page 34


                  (iii)    Each Definitive Agreement will be subject to the Parties' execution of the other
         Definitive Agreements; provided that: (A) the Sunrise Agreement may be signed prior to the date the
         other agreements are signed; (B) EIX may thereafter terminate the Sunrise Agreement if the other
         Definitive Agreements are not executed when otherwise required by this MOU; and (C) the EIX company
         shall be excused from performance under the Sunrise Agreement in the event that, after the execution of
         the Definitive Agreements, either (I) any legislation is enacted or any rule, regulation or order is
         adopted by the CPUC which would have the effect of overturning, in respects materially adverse to SCE,
         those CPUC Implementing Decisions which were adopted prior to the execution of the Definitive Agreements
         or (II) any Material Adverse Change referred to in clause (d) of the definition thereof occurs.

                  (iv)     Execution of each Definitive Agreement called for by the Plan and dismissal or other
         resolution of the litigation referred to in Section 14 will be subject to there having been no Material
         Adverse Change and no commencement of any bankruptcy or similar proceeding to which any party hereto is
         subject.

         Implementation of the Plan will be further subject to the following:

                  (a)      Absence of any injunction, restraining order or other order restraining or prohibiting
         the consummation of the transactions contemplated in this MOU, and the absence of any suit by the
         Federal Government seeking to restrain or prohibit the consummation of the transactions contemplated in
         this MOU.

                  (b)      Receipt by each of the Parties upon or prior to execution of the Definitive Agreements
         of such opinions of their financial advisors as they deem reasonably necessary.




Page 35



         Provided the Definitive Agreements are entered into, SCE will pay all of the reasonable costs and
expenses incurred by the State directly in connection with the negotiation or effectuation of this MOU and the
Definitive Agreements, including legal fees, fees of financial advisors and accountants and expenses of its
representatives, whether or not the transactions contemplated by this MOU are consummated, subject to the
following:

o        SCE's obligations will only be for transaction costs identified to transactions with SCE (not including,
         for example, costs associated with State financing of its obligations or the conservation
         advertising program);

o        SCE's will not be obligated for State costs in excess of an amount to be agreed upon based on an
          estimate provided by the State in connection with the execution of the Definitive Agreements.
          All such costs shall be subject to audit verification; and

o        SCE recovers such expenses through the securitization of the First Dedicated Rate Component described in
         Section 9 of this MOU (in addition to the net undercollected amount) or if such securitization
         does not occur, in retail rates.

16.      Next Steps


         Subject to the provisions of Section 15, the Parties will act in good faith to implement this MOU and
effectuate the Plan as quickly as reasonably practicable.  In this regard, the Governor will submit to the State
Legislature, after review and comment by SCE, a comprehensive legislative package setting forth the legislative
elements of the Plan.  The Parties will then proceed diligently and in good faith to attempt to have the
necessary legislation adopted, and will negotiate in good faith in an attempt to execute the Definitive
Agreements, by August 15, 2001.



Page 36



         While time is of the essence of this MOU, failure to satisfy the calendar set forth in the preceding
paragraph will not result in a termination of this MOU, if the Parties are continuing to proceed diligently and
in good faith to achieve its implementation.  Failure of all implementing legislation to be adopted and effective
and Definitive Agreements to be signed on or before December 31, 2001, will entitle any Party thereafter to
terminate this MOU upon notice to the other Parties.

17.      Signatures


         This MOU may be executed in counterparts and via facsimile.  The individuals executing this MOU
represent that they are authorized to sign on behalf of the Parties they represent, it being understood, however,
that the execution of this MOU by representatives of SCE and EIX is following the approval of this MOU by the
Board of Directors of each such entity.



Page 37


         IN WITNESS WHEREOF, the undersigned have executed this Memorandum of Understanding as of the day and
year first above written.


SOUTHERN CALIFORNIA EDISON COMPANY,
a California corporation


By:      Stephen E. Frank
Name:    Stephen E. Frank
Title:   Chairman of the Board, President and CEO


EDISON INTERNATIONAL, INC.,
a California corporation


By:      John E. Bryson
Name:    John E. Bryson
Title:   Chairman of the Board, President and CEO


CALIFORNIA DEPARTMENT OF WATER RESOURCES


By:      Thomas M. Hannigan
Name:    Thomas M. Hannigan
Title:   Director

EX-99 3 exh992.htm CPUC APPLICATION Exhibit 99

                                   BEFORE THE PUBLIC UTILITIES COMMISSION OF THE
                                                STATE OF CALIFORNIA


Application of Southern California Edison                    )
Company (U 338-E) for Authority to                           )
Institute a Rate Stabilization Plan with a                   )             Application 00-11-038
Rate Increase and End of Rate Freeze                         )           (Filed November 16, 2000)
Tariffs.                                                     )
- -------------------------------------------------------------)
                                                             )
Emergency Application of Pacific Gas and Electric Company to )            Application 00-11-056
Adopt a Rate Stabilization Plan. (U 39 E)                    )        (Filed November 22, 2000)
- -------------------------------------------------------------)
                                                             )
Petition of THE UTILITY REFORM NETWORK for Modification of   )            Application 00-10-028
Resolution E-3527.                                           )           (Filed October 17, 2000
                                                             )
- -------------------------------------------------------------





                                  SOUTHERN CALIFORNIA EDISON COMPANY'S (U 338-E)
                                       COMMENTS ON PROPOSED CPA CALCULATION



                                            STEPHEN E. PICKETT
                                            ANN P. COHN
                                            FRANK J. COOLEY
                                            JAMES P. SCOTT SHOTWELL

                                            Attorneys for
                                            SOUTHERN CALIFORNIA EDISON COMPANY

                                                     2244 Walnut Grove Avenue
                                                     Post Office Box 800
                                                     Rosemead, California  91770
                                                     Telephone:   (626) 302-3115
                                                     Facsimile:   (626) 302-7740
                                                     E-mail:  Frank.Cooley@sce.com


Dated:  March 29, 2001






                                               TABLE OF CONTENTS

Section                                           Title                                                Page
- -------                                           -----                                                ----

I.   INTRODUCTION..........................................................................................1

II.  Discussion............................................................................................4

     A.   The Proposed CPA Is Fixed For An Indefinite Period With No Mechanism For
          Adjustments Based On Actual Costs................................................................4

     B.   The Proposed CPA Ignores DWR's Failure To Assume Financial Responsibility For
          The Entire Net-short position Of The Utility's Customers.........................................6

     C.   The CPA Is Inflated Because The Assumed Cost Of QF Payments Is Too Low...........................6

     D.   Authorized Generation-Related Costs Are Improperly Excluded......................................9

     E.   The Potential Exclusion From The CPA Of SONGS 2&3 ICIP Revenues Requested In
          Ordering Paragraph No. 10 Overturns Existing Commission Decisions And Is
          Contrary To State Law...........................................................................13

     F.   The Ratemaking Treatment Of Previously-Authorized Costs Should Be Clarified.....................15

     G.   The Methodology for Calculating The CPA Is Flawed And Is Based On Unreasonable
          Assumptions.....................................................................................16

          1.       Calculation Of The CPA Based On The CPUC's Methodology.................................16

          2.       Calculation Of The CPA Based On Realistic And Appropriate Assumptions
                   And Methodology........................................................................16

     H.   The Fixed DWR Set Aside Should Not Be Applied To Energy Supplied By DWR.........................17

III. CONCLUSION...........................................................................................18






                                  BEFORE THE PUBLIC UTILITIES COMMISSION OF THE
                                                STATE OF CALIFORNIA




Application of Southern California Edison                    )
Company (U 338-E) for Authority to                           )
Institute a Rate Stabilization Plan with a                   )             Application 00-11-038
Rate Increase and End of Rate Freeze                         )           (Filed November 16, 2000)
Tariffs.                                                     )
- -------------------------------------------------------------)
                                                             )
Emergency Application of Pacific Gas and Electric Company to )            Application 00-11-056
Adopt a Rate Stabilization Plan. (U 39 E)                    )        (Filed November 22, 2000)
- -------------------------------------------------------------)
                                                             )
Petition of THE UTILITY REFORM NETWORK for Modification of   )            Application 00-10-028
Resolution E-3527.                                           )           (Filed October 17, 2000
                                                             )
- -------------------------------------------------------------



                                  SOUTHERN CALIFORNIA EDISON COMPANY'S (U 338-E)
                                       COMMENTS ON PROPOSED CPA CALCULATION


                                                         I.
                                                   INTRODUCTION

         The Southern California Edison Company (SCE) comments on Decision No. 01-03-081 regarding the proposed
calculation of the California Procurement Adjustment (CPA).1/

         SCE appreciates the importance of determining the revenue stream available to compensate the California
Department of Water Resources (DWR) for its purchases on behalf of our customers pursuant to Senate Bill 7X and
Assembly Bill 1X.  Nevertheless, it is singularly important that the California Public Utilities Commission (CPUC
or Commission) make this determination correctly.  The Commission should acknowledge the critical interdependence
between the allocation of revenues to DWR and full-cost recovery of SCE's Commission-authorized costs.

- -----------------------

1/  D.01-03-081, Ordering Paragraph 10, mimeo, p.37.




Page 1


         The calculation of the CPA cannot be considered in isolation.  The CPA is one aspect of the three
decisions issued March 27, 2001.  In the limited time available to consider the impact of the decisions, SCE
estimates that revenues going forward will not be sufficient to cover retained generation and power purchase
costs.2/  In fact, Figure 1 on the next page shows that the net effect of the rate increases, the QF decision and
the payments ordered to be made to DWR result in a shortfall in the CPA calculation of $1.2 billion for SCE.
Accordingly, it is even more critical that the calculation of the CPA properly reflects all the costs allocated
to the utility.

         SCE continues to urge the Commission to establish three dedicated rate components with two-way balancing
accounts and triggers as the best way to ensure that DWR receives adequate funding and the utilities' financial
health does not deteriorate even further.  The three dedicated rate components would be for SCE's retained
generation, QF and bilateral contracts and payments to DWR.

         The proposed calculation of the CPA set forth in D.01-03-081, Sections C and D, does not properly
reflect all relevant generation costs.  If the Commission were to adopt such a calculation and later allocate a
portion of the CPA to the Fixed DWR Set Aside, it would materially exacerbate the utility's revenue shortfall.
In these comments SCE identifies several important corrections that must be made to the CPA calculation.

- --------------------

2/   SCE is commenting on the portions of D.01-03-081 as directed by the
     Commission. In so doing, SCE does not necessarily agree with, and reserves
     it right to challenge, these and other portions of D.01-03-081 and other
     decisions issued by the Commission on March 27, 2001.


Page 2

Page 3
II.

DISCUSSION

A. The Proposed CPA Is Fixed For An Indefinite Period With No Mechanism For Adjustments Based On Actual
Costs

The proposed CPA is a fixed rate. More importantly, the CPA is a fixed rate based on a one-time
calculation of costs. The Commission is effectively converting the revenue recovery for all generation to a
rate, rather than an absolute cost. So, for example, assuming a fixed demand, if output from Utility Retained
Generation (URG) decreases and delivery from DWR increases by a like amount, the State will receive an increment
in its revenue and SCE will receive a decrease,3/ even though its costs may not have decreased at all. This
effectively puts SCE's shareholders at risk for generation performance. Put another way, SCE's shareholders are
at risk for replacement power cost, at least to the extent of its generation rate. In stark contrast, assuming
no imprudence in the operation of URG, past Commission ratemaking decisions would provide recovery of increased
replacement power costs through the Energy Cost Adjustment Clause (ECAC). There would be no decrease in
generation revenue as a result of a decrease in output.

It is indisputable that SCE's retained generation and purchased power will change significantly over
time. The Commission's objective in setting a fixed rate is to achieve a stable source of revenue that will
allow DWR to finance its revenue bonds. Unfortunately, the stable source of revenue the Commission and DWR
desire is achieved at SCE's expense. By failing to allow for adjustments in costs and generation levels for
retained generation and purchased power, the proposed method for calculating the CPA transfers this cost
variability risk to the utilities. In our current financial condition, SCE cannot bear this risk. Moreover, it
creates perverse incentives for the utilities to avoid expenditures on retained generation units that may be the
least costly sources of supply.

- --------------------

3/ For purposes of this document, we assume that a portion of the CPA will be allocated
to the Fixed DWR Set Aside.

Page 4

The goals of achieving stable revenues for DWR and maintaining SCE's financial health are not mutually
exclusive. SCE offered an alternative that would allow the CPUC to achieve both objectives. The Commission
should establish three dedicated rate components with balancing accounts and triggers. The dedicated rate
components would be for utility retained generation, QF and bilateral contracts, and DWR purchases. The
advantages of this approach are compelling and were explained in SCE's response to the March 19, 2001 Assigned
Commissioner's Ruling.

Under SCE's proposed dedicated rate components, DWR would have an assured revenue stream that will allow
it to finance revenue bonds. The Commission could provide an assurance that the CPA rate would remain available
to repay the revenue bonds over their life. Revenue to pay DWR would be generated by the DWR's dedicated rate
component. This approach would contribute positively to SCE's financial health by removing the necessity to
finance large amounts of undercollections if they accumulate due to volatile costs. Triggers set at
appropriately low levels given SCE's weakened financial condition would assure lenders that a mechanism is in
place to recover power purchase costs and adequately fund CPA payments to DWR.

The approach envisioned by the proposed CPA is not practical. The fixed CPA rate does not reflect
likely variations in the cost of purchased power. There is no procedure for updating purchased power cost
factors. The upshot of the proposed CPA is to place the financing burden associated with these variations on the
financially weakened utility. SCE simply does not have the ability to finance any sizable undercollections.
Because the proposed CPA approach would deleteriously impact the utility's financial condition, DWR's ability to
finance power purchases would be affected.

Page 5

B. The Proposed CPA Ignores DWR's Failure To Assume Financial Responsibility For The Entire Net-short
position Of The Utility's Customers

It is unclear what portion of our customers' net-short position DWR is going to be financially
responsible for. The proposed CPA calculation implicitly assumes that DWR is financially responsible for
covering all of our customers' net-short position. While SCE understands and expects that DWR has this
responsibility, DWR has not formally acknowledged this responsibility, as reflected in D.01-03-082.4/ DWR has
stated that it will only pay the portion of our customer's net short costs that DWR considers to be reasonable.
DWR's reasonableness standard is not defined. Whatever portion of our customer's net-short position that is not
being covered by DWR must be included in the calculation of the CPA. SCE does not have the ability to finance an
undercollection of procurement costs. If, despite the intent and requirements of AB1X-1, the financial burden
for the uncovered net short is placed on SCE, the calculation of the CPA must reflect this fact. The proposed
CPA calculation does not.

C. The CPA Is Inflated Because The Assumed Cost Of QF Payments Is Too Low

The proposed CPA is based on an assumed QF price of $80 per MWH. This price is unrealistic and
inconsistent with the CPUC's own decision modifying the QF energy payment formula. Reasonable estimates of QF
payments based on the Commission's modifications to the QF energy payment formula would yield substantially
higher payments to QFs and a consequently lower estimate of the amount available to fund the CPA.

- ----------------------
4/ D. 01-03-082, p. 14. D.01-03-082 also affirms that the CPUC cannot require
DWR to purchase the entire net short on behalf of SCE's customers. Id.

Page 6

When SCE provided its scenarios based on the $80 per MWH price, there were ongoing negotiations with QFs
that everyone hoped would lead to a settlement near that price. Those negotiations failed and D.01-03-067 (the
QF Decision) recognizes this fact. In fact, it is only because the negotiations failed that the Commission was
forced to address the issue of QF energy payments. Unfortunately for California ratepayers, the energy payment
formula authorized by the Commission will result in higher payments to QFs than $80 per MWH that was assumed for
illustrative purposes.

Table 1 provides SCE's estimate of QF prices based on the formula adopted by the Commission and gas
prices as forecast by Data Resources Inc. (DRI):

Table 1
QF Price Forecast
($/MWH)

--------------------------- ------------------- -----------------

Month CPUC SCE
Assumed Forecast
--------------------------- ------------------- -----------------

May, 2001 80 121.30
June, 2001 80 111.10
July, 2001 80 172.90
August, 2001 80 187.20
September, 2001 80 193.40
October, 2001 80 187.20
November, 2001 80 94.60
December, 2001 80 98.50

Page 7

This forecast includes a forecast of QF energy, capacity and contract buyout payments. For energy
payments, QFs are divided into three types of contracted energy payments terms: (1) posted avoided cost of
energy; (2) fixed energy prices; and (3) heat rate floors ("IER Amendments"). In general, energy prices other
than the fixed priced contracts are determined by a base energy price, a border gas price, and a gas price
factor. Line loss factors, based on the generator meter multipliers (GMM), distribution loss factors (DLF), and
system GMM, are also applied to energy prices where appropriate.

QFs paid the posted avoided cost of energy are subject to the conditions in established in D.01-03-067.
For these contracts the Malin border gas price including a gas intrastate transportation rate to the Southern
California Gas Company interconnection point is used to determine the posted avoided cost of energy. In
addition, the gas price factor is adjusted monthly according the decision. The energy payments to QF subject to
"IER Amendments" are forecast using base energy prices, border gas price, and a gas price factor. The energy
payments to the fixed-priced contracts are forecast subject to specific contract terms. The border gas price
forecasts are taken from DRI's gas price forecast for March 2001. For all contracts, energy is forecast based on
historical behavior. The forecast of capacity payments is based on contract terms and historical payments and
the forecast of contract buyout payments is based on Commission-approved buyout payment schedules.

The Commission should recognize in its calculation of the CPA the fact that its QF decision, issued the
same day as D.01-03-081, earlier Commission decisions and specific QF contract terms increase the price of QF
power above the assumed $80 per MWH price. This would increase the costs to be deducted from generation-related
revenues used in the calculation of the CPA by approximately $1.6 billion in 2001.

Page 8

D. Authorized Generation-Related Costs Are Improperly Excluded

The proposed CPA improperly excludes legitimate generation-related costs. This unfairly inflates the
amount of the CPA. All authorized generation-related costs should be included in the calculation of the CPA to
properly implement the Legislature's intent.

Excluding certain authorized generation-related costs from the calculation of the CPA overstates the
amount of the CPA. For example, D.01-03-081 claims that franchise fees and uncollectibles should be excluded
from the calculation. With respect to franchise fees, the decision asserts that these costs "attach to all
retail revenues." This makes no sense. "All revenues" includes SCE's generation-related revenues. What SCE
proposed to deduct from generation-related revenues was the pro rata share of our total franchise fees that
relates to the generation-related revenues. The Commission in D. 97-08-056 explicitly ordered SCE and other
utilities to exclude from their distribution revenue requirement the portion of its revenue requirement
associated with generation revenues. The proposed calculation of the CPA is at odds with the Commission's
earlier treatment of these costs. Alternatively, DWR must assume financial responsibility for paying the
franchise fees associated with their "revenues."

The proposed calculation of CPA also excludes restructuring implementation costs, employee-related
transition costs, losses on sales and QF shareholder incentives. The decision claims that because these costs
are not enumerated in Code Section 360.5, they must be excluded. This assertion is disingenuous. The Commission
is intimately familiar with what is included in SCE's rates. Generation related rates have heretofore included
these costs. The Legislature could reasonably be excused from knowing precisely what is in SCE's generation
rates. The Commission is not so easily excused. In D.99-09-064 the Commission ordered recovery of these costs

Page 9

through the operation of the TRA. The effect of this treatment is to require them to be recovered through the
residually determined generation rate component. Consistent and fair treatment would remove these costs from the
generation related rate in the calculation of the CPA.

With respect to direct access implementation costs, the decision claims that these costs must be
excluded from the calculation of the CPA. This is contrary to the Commission's decisions implementing
restructuring. The Commission authorized recovery of direct access implementation costs from the TRA. Since the
generation rate is by Commission decisions residually determined under the rate freeze, in so doing the
Commission reduced the generation rate by a corresponding amount to maintain the rate freeze. This reduction can
not be ignored now in calculating the CPA. Direct access implementation costs were in SCE's "rates" on January
5, 2001 and must therefore be taken out of the generation-related rate to properly calculate the CPA. If instead
of recovering the direct access implementation costs through the TRA an unbundled rate component for their
recovery were established, then the residually determined generation rate would have been smaller and these costs
would not have been reflected in the January 5 generation rate.

Conversely, by inputing the Rate Reduction Bond (RRB) revenues , the Commission effectively increased
the generation rate. The proposed CPA should include these inputed amounts as well even though they were not
listed in Code Section 360.5. The RRBs are not included because they are generation costs but because the
Commission effectively authorized the reduction of the generation rates to allow recovery of these items.

The proposed CPA excludes customer service and information expenses, and administrative and general
costs because they "are not generation related costs and do not fall within the scope of the four items in Code

Page 10

Section 360.5."5/ These costs are in the same category as direct access implementation costs and the inputed RRB
amounts. For example, A&G costs associated with SCE's generating facilities include: pensions and benefits for
employees at the generating plants, payroll taxes for the employees at the generating plants, insurance for
property damage and personal injury, and worker's compensation. These costs are reasonable costs of operating
SCE's generating facilities. No business can operate without paying payroll taxes and pensions and benefits for
its employees. In addition, it would be imprudent for SCE to operate its generating facilities without insurance
for property damage and personal injury.

D.96-04-059, adopting the present SONGS 2&3 ratemaking mechanism, and D.96-12-083, adopting the present
Palo Verde ratemaking mechanism, provide for recovery of A&G costs associated with these nuclear generating
facilities. D.97-12-131 established the Hydroelectric Generating Facilities revenue requirement. Advice
Letter 1285-E-B, approved by the Commission by letter, dated June 25, 1999, implemented D.97-12-131. Advice
Letter 1285-E-B expressly includes A&G as part of the revenue requirement of SCE's hydroelectric generating
facilities. D.99-09-064 established "going-forward" costs of SCE's coal-fired generating facilities to be
recovered through market revenues. Advice Letter 1409-E-A, approved by the Commission by letter, dated
February 10, 2000, expressly includes A&G expenses as part of the legitimate operating costs of SCE's coal-fired
generating facilities eligible for recovery through market revenues. The Commission should not exclude such
legitimate generation costs in the calculation of the CPA because to do so would be inconsistent with past
Commission decisions and standard utility ratemaking practices. Moreover, they do fall within any reasonable
definition of the costs of "the utility's own generation" which Public Utilities Code Section 360.5 expressly
allows to be subtracted from SCE's generation-related revenue requirement in any calculation of the CPA.

- -----------------------

5/ D.01-03-081, p.19.

Page 11

In D.97-08-056 the Commission examined SCE's total C&I and A&G costs and allocated a portion of them to
the generation function. It is contrary to that decision and common sense to now exclude consideration of these
costs in the generation related rate. The Commission prohibited SCE from recovery of the generation related CS&I
and A&G costs through distribution rates and is now attempting to exclude them from recovery through the
generation rates by inflating the CPA. This is obviously unfair and should be corrected.

Finally the proposed calculation of the CPA ignores the reliability must run (RMR) costs that SCE must
pay to the ISO. SCE agrees that RMR costs are not generation related, but in D.98-04-019 the Commission allowed
for recovery of RMR costs through the TRA during the rate freeze. This treatment was in lieu of SCE filing with
the FERC to establish a separate rate component for RMR recovery. Had SCE done so, the residually determined
generation rate would have been smaller. The Commission in D.99-10-057 stated that in the post-transition period
SCE must request recovery of these costs through a FERC-approved rate component. SCE filed an application with
the FERC (Docket No. ER01-315-000, filed November 1, 2000) for adoption of an RMR rate component. For this
reason, the Commission should subtract the RMR costs from its generation rate before calculating the CPA. This
would result in the same outcome as SCE continuing to recover RMR costs through the residual generation revenues
recorded in the TRA.

Page 12

E. The Potential Exclusion From The CPA Of SONGS 2&3 ICIP Revenues Requested In Ordering Paragraph No. 10
Overturns Existing Commission Decisions And Is Contrary To State Law

Several changes contained in Ordering Paragraph No. 10 were not in the Alternate Decision issued March
26, 2001 that was ultimately adopted as D.01-03-081. These changes were not available for timely review as noted
by several Commissioners from the dais on March 27, 2001. The changes to the CPA calculation directed in
Ordering Paragraph No. 10 are not lawful. They would overturn existing Commission decisions regarding SONGS 2&3
Incremental Cost Incentive Pricing (ICIP) and are contrary to state law. SCE would have identified this serious
legal error in its March 26, 2001 oral argument if it had been on notice of this proposed change at that time.
These changes represent significant material revisions, not mere typographical corrections. The Commission
should not countenance such "star chamber" ratemaking.

Ordering Paragraph No. 10 states:

Comments on sections VI.C and D and section VIII of this decision and the
corresponding proposed findings of fact and proposed conclusions of law shall
be filed and served no later than 5:00 p.m. on Thursday, March 29, 2001. Each
utility shall include in its comments a revised version of that portion of the
Spreadsheet included as Attachment E to this Decision that relates to that
utility. This revised spreadsheet shall exclude in its calculation of Utility
Related Costs those nuclear incentive amounts (e.g., Diablo Canyon ICIP
payments) in excess of actual costs, and be accompanied by appropriate
supporting work papers. Any party asserting that the figures contained in
Attachment E contain miscalculations should submit a revised version of
Attachment E correcting the alleged errors, which should be accompanied by
appropriate work papers.

Page 13

The implication of the paragraph is that the Commission intends to exclude some portion of SONGS 2&3 ICIP
revenues from the CPA calculation. It directs the utilities to remove "actual generation costs" from their
calculation of Utility Related Costs in the CPA calculation. The Commission adopted SONGS 2&3 ICIP prices as the
operating cost of SONGS 2&3 and the Legislature affirmed these prices as the SONGS 2&3 actual costs in Public
Utilities Code Section 367(a)(4).

SONGS 2&3 ICIP is, by its very nature as acknowledged in its title, a cost-based rate. The ICIP assigns
all operational and financial risk to SCE, while offering a strictly limited opportunity for profit6/ based upon
excellent performance at the plants. SCE cannot assure continuation of recent (1996-2000) excellent performance,
as the current SONGS 3 outage demonstrates. The risk currently borne by SCE is evidenced by the $800,000 per day
of lost revenue to the company due to the present SONGS 3 outage.

As SCE stated on page 7 of its Motion to Strike Comments filed by TURN on California Procurement
Adjustment, dated March 9, 2001, in the Rate Stabilization Plan (RSP) docket:

In the SONG 2&3 ICIP mechanism, shareholders take on the operational risk of
plant performance. Under this ratemaking approach the opportunity for profits
must be commensurate with the risk of losses. SONGS 2&3 ICIP opportunity for
profits is commensurate with the higher risk of losses assumed by shareholders.

Furthermore, SCE's opportunity for profit is limited by the design and operation limits of the plants.

- ------------------------

Page 14

6/ SCE's realized "profit" under SONGS ICIP has been around 9% to date (RSP,
Phase 1, Tr. Worder, 15/1982.)

7/ RSP, Phase 1, SCE, Worden, Tr. 15/20/2015, lines 22-26. (Ratepayers would
be protected if the plants performed better than the historic capacity
factors because the ratepayer exposure and shareholder oppotunity is capped
by the physical limitations of the plant.")

Page 14

The Commission adopted present SONGS 2&3 ICIP pricing in D.96-01-011 and D.96-04-059. The Legislature
affirmed the SONGS 2&3 ICIP pricing in Assembly Bill 1890, at Public Utilities Code Section 367(a)(4), which
states:

Nuclear Incremental Cost Incentive plans for the San Onofre Nuclear Generating
Station shall continue for the full term as authorized by the Commission in
Decision 96-01-011 and Decision 96-04-059; provided that the recovery shall
not extend beyond December 31, 2003.

The Commission would unlawfully ignore its own orders and state law if it changes SCE's ratemaking for SONGS 2&3.

F. The Ratemaking Treatment Of Previously-Authorized Costs Should Be Clarified

As discussed in the previous sections, many of the costs that are excluded from the proposed CPA
calculation are authorized generation-related costs. If these costs are not allowed recovery through the
generation-related component of SCE's rates, it is not clear where SCE would get recovery of them. These costs
are reasonable and authorized costs. The Commission has previously allowed recovery of them through the
residually determined generation rates. There is nothing in the record that would in any way justify
disallowance of these costs. Yet, there is no readily apparent mechanism for their recovery. The Commission
should immediately clarify where and how these costs will be recovered to avoid any further negative harm to
SCE's financial condition.

Page 15

G. The Methodology for Calculating The CPA Is Flawed And Is Based On Unreasonable Assumptions

1. Calculation Of The CPA Based On The CPUC's Methodology

If the Commission makes no modifications to its CPA methodology, it should nevertheless adopt
reasonable estimates, including a reasonable estimate of QF costs. SCE estimates, based on the
methodology adopted in D. 01-03-08_, that its QF payments will be $1.629 billion higher than the
estimate included in Attachment E to D. 01-03-081. SCE's Attachment A contains a table that shows the
CPA including this correction, as well as a minor correction to gross generation revenues to correct the
amount shown in Column D of Table E. In addition, pursuant to Ordering Paragraph No. 10 of D.01-03-081,
an adjustment has been made to reflect the difference between the SONGS ICIP revenue requirement and
estimated costs. With these changes, the CPA would be zero cents per kWh.

2. Calculation Of The CPA Based On Realistic And Appropriate Assumptions And Methodology

The proposed calculation of the CPA rejects numerous adjustments that should be made to
accurately calculate the CPA. If these adjustments are made, the CPA would be higher than the corrected
CPA factor discussed above. The proposed adjustments are reasonable and consistent with prior CPUC or
FERC decisions which allocated these costs to the generation related component of SCE's rates.

Attachment A describes each of the adjustments that should be made to reflect an accurate
calculation of the CPA. The adjustment and the authority for making the adjustment are shown in the
table. If these adjustments are made, the CPA would continue to be zero cents per kWh. It should be
noted that the largest adjustments (for the imputed 10% bill credit and the imputed trust transfer
amount) will no longer exist in 2002. These adjustments increase the amount of the CPA in 2001. Their
absence in 2002 will decrease the calculated CPA in 2002. For this reason, if the Commission chooses to
make SCE's proposed adjustments, the CPA calculation will need to be updated for at least the
elimination of the 10% bill credit and the imputed Trust Transfer Amount revenue in 2002.

Page 16

H. The Fixed DWR Set Aside Should Not Be Applied To Energy Supplied By DWR

In its calculation of the CPA, the Commission used a denominator equating to SCE's total bundled sales.
One effect of this approach is to allocate the utility's costs against the generation revenues which are already
required to be forwarded to DWR. This is a double calculation and would effectively send the revenue requirement
to DWR twice. Either the CPA calculation should be modified to replace the denominator with only kwhs provided
by SCE, or, in the aternative, the DWR Set Aside should only be applied to kwhs supplied by the DWR.

Page 17

III.
CONCLUSION

For the reasons discussed above, SCE urges the Commission to modify the calculation of the CPA
consistent with SCE's recommendations in Attachment A.

Respectfully submitted,

STEPHEN E. PICKETT
ANN P. COHN
FRANK J. COOLEY
JAMES P. SCOTT SHOTWELL

Frank J. Cooley
-------------------------------------------------
By: Frank J. Cooley

Attorneys for
SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue
Post Office Box 800
Rosemead, California 91770
Telephone: (626) 302-3115
Facsimile: (626) 302-7740
E-mail: Frank.Cooley@sce.com

March 29, 2001

Page 18
APPENDIX A

A B C D E
- ----- ------------------------- ------------------- ---------------------------- ------------- ------------------ -----------------
Gross Gen-Related Rev
Gen-Related Revs Based on
Line Total Sales Reported in Bundled Reported in Bundled Service
Nos. Description Generation-Related Utilities' ABX1 Data (GWh) Service Utilities ABX1 Sales ($000s)
Rate (c/kWh) Sales ((GWh) Data ($000s)
- ----- ------------------------- ------------------- ---------------------------- ------------- ------------------ -----------------
A=D/B/10 E=A*C*10

1 As Attached to 7.277 84,400 76,466 6,141,557 5,564,251
D01.03-081 (For SCE)

Adjustments Pursuant to
Ordering Paragraph 10
of D.01-03-081

2 Corrects Amount shown 8,116
in column D

3 Updated QF payment
amounts based on
D.01-03-081

4 Adjustment to SONGS
Generation (GWh) due to
outage after fire

5 To reflect forecast of
SONGS O&M (Non-ICIP)
- ----- ------------------------- ------------------ ---------------------------- --------------- ------------------ -------------
6 Adjusted Commission CPA 7.286 84,400 76,466 6,149,673 5,571,604
Calculation
- ----- ------------------------- ------------------- ---------------------------- ---------------- ------------------ -------------

Additional Authorized
Adjustments:

Authority for Inclusion

7. Reverse Line 5 above PU Code Section PU Code Section 367 (a)(4)
which results in 367 (a)(4) states that "Nuclear
authorized SONGS ICIP D.96-02-011 and Incremental Cost Incentive
revenue requirement D.96-04-059 plans for SONGS shall
continue for the full
term as authorized by the
Commission in D.96-01-011
and D.96-04-059."

8 Franchise Fees and D.97-08-056, p.59 The Commission ordered (62,498)
Uncollectibles that the utilities
distribution revenue
requirement should be
reduced to recognize a
fair allocation of FF&U
costs between
distribution, transmission
and generation.

9 Reliability Services FERC Docket No. Reliability Service costs (39,551)
ER01-315-000 are FERC authorized that
are currently being
recovered through
generation rates.

10 Restructuring D.99-09-064 The Commission ordered the (33,606)
Implementation recovery of Industry
Restructuring costs
through the operation of
the TRA. Thus these costs
are actually recovered
through the residually
determined generation rate
component.

11 Demand Responsiveness D.01-03-xxx The Commission ordered SCE (38,440)
and Self Generation to increase its
Amount distribution revenue
requirement without
modifying current overall
rates. The adjustment is
needed to account for the
resultant reduction to
generation-related
revenues during the rate
freeze period. 1/

12 Imputed 10% Bill Credit D.97-09-056 The frozen generation rate 361,582
has been reduced by the
amount of the 10% bill
credit. This adjustment
is necessary in order to
remove the impact of the
RRB transaction from the
generation rate consistent
with the ratemaking
adopted by the Commission.

13 Imputed Trust Transfer The frozen generation rate 294,891
Amount has been reduced by the
amount of the TTA. This
adjustment is necessary in
order to remove the impact
of the RRB transaction
from the generation rate
consistent with the
ratemaking adopted by the
Commission.

14 Add-back CS&I and A&G RE: CS&I Costs The Commission ordered
related to SCE Retained D.97-08-056, p.59 that the utilities
Generation distribution revenue
requirement should be
reduced to recognize a
fair allocation of
customer service and
marketing costs between
distribution, transmission
and generation.

Res. E-3536 The Commission adopted a
generation allocation of
customer service and
marketing costs for hydro.

A&G Costs The Commission ordered
D.97-08-056, p. 59 that the utilities
distribution rev req
should be reduced to
recognize a fair
allocation of A&G costs
between distribution,
transmission and generation.

D.97-11-074, p. Commission defined
26-27 going-forward costs as all
costs necessary to
continue to operate the
plant. Going forward
costs may include both
fixed and variable costs.
This interpretation most
closely matches the
standards articulated in
the statue and our own
preference for market
recovery of such costs.

"Therefore, going forward
costs will be defined as
all costs that are
necessary for the
continued or future
operation of the plant...,
and include, but are not
limited to, all costs
associated with fuel
transportation and fuel
supply, administrative and
general, and operation and
maintenance, with the
statutory exceptions
established in Section 367
(c)(1) and (c)(2).

D.00-02-048 and Approved costs recorded in
D.00-10-047 GMA's including A&G and
CS&I

A=E/C/10 Sum lines X-Y
15 CPA as Proposed by SCE 7.917 76,466 6,053,982
- ----- ------------------------- ------------------- ---------------------------- ---------------- ---------------- -----------------

Note: 1/ Similar adjustments will be necessary during the rate freeze
period to reflect the impact on generation-related revenues that result from
changes in non-generation revenues.

- ----------------------------------------- --------------------------- ------------- --------------- ---------------- -------------
F G H I
Utility
Utility Related Costs CPA
Line Description Related less CSI and Revenues CPA Rate
Nos. Costs A&G ($000s) ($000s) (c/kWh)
($000s)
- ----------------------------------------- --------------------------- ------------- --------------- ---------------- -------------
H=E-G I=H/C

1 As Attached to 4,798,902 4,762,381 801,870 1.049
D01.03-081 (For
SCE)

Adjustments
Pursuant to
Ordering
Paragraph 10 of
D.01-03-081

2 Corrects Amount
shown in column D

3 Updated QF 1,629,446 1,629,446
payment amounts
based on
D.01-03-081

4 Adjustment to (131,671) (131,671)
SONGS Generation
(GWh) due to
outage after fire

5 To reflect (55,400) (55,400)
forecast of SONGS
O&M (Non-ICIP)

- ----------------------------------------- --------------------------- ------------- --------------- ---------------- -------------
6 Adjusted 6,241,277 6,204,756 (633,152) (0.828)
Commission CPA
Calculation
- ----------------------------------------- --------------------------- ------------- --------------- ---------------- -------------

Additional Authorized Adjustments

Authority for Inclusion

7. Reverse Line 5 PU Code Section PU Code Section 367 55,400 55,400
above which 367 (a)(4) (a)(4) states that
results in D.96-02-011 and "Nuclear Incremental Cost
authorized SONGS D.96-04-059 Incentive plans for SONGS
ICIP revenue shall continue for the
requirement full term as authorized
by the Commission in
D.96-01-011 and
D.96-04-059."

8 Franchise Fees D.97-08-056, p.59 The Commission ordered
and that the utilities
Uncollectibles distribution revenue
requirement should be
reduced to recognize a
fair allocation of FF&U
costs between
distribution,
transmission and
generation.

9 Reliability FERC Docket No. Reliability Service costs
Services ER01-315-000 are FERC authorized that
are currently being
recovered through
generation rates.

10 Restructuring D.99-09-064 The Commission ordered
Implementation the recovery of Industry
Restructuring costs
through the operation of
the TRA. Thus these costs
are actually recovered
through the residually
determined generation
rate component.

11 Demand D.01-03-xxx The Commission ordered
Responsiveness SCE to increase its
and Self distribution revenue
Generation Amount requirement without
modifying current overall
rates. The adjustment is
needed to account for the
resultant reduction to
generation-related
revenues during the rate
freeze period. 1/

12 Imputed 10% Bill D.97-09-056 The frozen generation
Credit rate has been reduced by
the amount of the 10%
bill credit. This
adjustment is necessary
in order to remove the
impact of the RRB
transaction from the
generation rate
consistent with the
ratemaking adopted by the
Commission.

13 Imputed Trust The frozen generation
Transfer Amount rate has been reduced by
the amount of the TTA..
This adjustment is
necessary in order to
remove the impact of the
RRB transaction from the
generation rate
consistent with the
ratemaking adopted by the
Commission.

14 Add-back CS&I and RE: CS&I Costs The Commission ordered 36,521
A&G related to D.97-08-056, p.59 that the utilities
SCE Retained distribution revenue
Generation requirement should be
reduced to recognize a
fair allocation of
customer service and
marketing costs between
distribution,
transmission and
generation.

Res. E-3536 The Commission adopted a
generation allocation of
customer service and
marketing costs for hydro.

A&G Costs The Commission ordered
D.97-08-056, p. that the utilities
59 distribution rev req
should be reduced to
recognize a fair
allocation of A&G costs
between distribution,
transmission and
generation.

D.97-11-074, p. Commission defined
26-27 going-forward costs as
all costs necessary to
continue to operate the
plant. Going forward
costs may include both
fixed and variable
costs. This
interpretation most
closely matches the
standards articulated in
the statue and our own
preference for market
recovery of such costs.

"Therefore, going forward
costs will be defined as
all costs that are
necessary for the
continued or future
operation of the plant...,
and include, but are not
limited to, all costs
associated with fuel
transportation and fuel
supply, administrative
and general, and
operation and
maintenance, with the
statutory exceptions
established in Section
367 (c)(1) and (c)(2).

D.97-11-074, Commission ordered
pg.26-27 tracking of the
above-mentioned going
forward costs in GMAs.

D.00-02-048 and Approved costs recorded
D.00-10-047 in GMA's including A&G
and CS&I.

H=E-G I=H/C
- ---------------------------------------- --------------------------- ------------- --------------- ---------------- ------------
15 CPA as Proposed 6,292,677 6,296,677 (242,695) (0.317)
by SCE
- ---------------------------------------- --------------------------- ------------- --------------- ---------------- ------------

Note: 1/ Similar adjustments will be necessary during the rate freeze
period to reflect the impact on generation-related revenues that result from
changes in non-generation revenues.

April 2, 2001

VIA FACSIMILE & U.S. MAIL

Docket Office
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, CA 94102

Re: A.00-11-038 - - Correction to Figure re. CPA

Docket Office:

On March 29, 2001 Southern California Edison (SCE) commented in response to Decision No.
01-03-081. Included in our comments was a "waterfall chart" showing the financial impact of two decisions issued
by the Commission - - D.01-03-081 and D.01-03-082.

Subsequent to issuing our comments, we discovered language was added to Ordering Paragraph
No. 1 which increased payments to the California Department of Water Resources after March 27, 2001 from 7.277
cents per kilowatt-hour to 10.277 cents per kilowatt-hour. We were unaware that this requirement was added to
D.01-03-082.

Attached is an updated chart showing the finiancial impact of the Commission's decisions based
on the mailed version of D.01-03-082. The financial impact of the mailed version of D.01-03-082 is to increase
the amount by which total expenses exceed SCE's total revenues in 2001 by $700 million.

If you have any questions regarding this matter, please call me at (626) 302-3115.

Very truly yours,

Frank J. Cooley
----------------------------
Frank J. Cooley
cc: All Parties of Record
President Loretta Lynch and Commissioners
Gary Cohen, General Counsel

Enclosure