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 April 10., 2001
(Date of earliest event reported)
Commission File No. 33-95538
-----------------------
SALTON SEA FUNDING CORPORATION
(Exact name of registrant as specified in its charter)
47-0790493
(IRS Employer Identification No.)
(Exact name of Registrants (State or other jurisdiction of (I.R.S. Employer
as specified in their charters)incorporation or organization)Identification No.)
- ------------------------------- ---------------------------- -------------------
Salton Sea Brine Processing L.P. California 33-0601721
Salton Sea Power Generation L.P. California 33-0567411
Fish Lake Power LLC Delaware 33-0453364
Vulcan Power Company Nevada 95-3992087
CalEnergy Operating Corporation Delaware 33-0268085
Salton Sea Royalty LLC Delaware 47-0790492
VPC Geothermal LLC Delaware 91-1244270
San Felipe Energy Company California 33-0315787
Conejo Energy Company California 33-0268500
Niguel Energy Company California 33-0268502
Vulcan/BN Geothermal Power Company Nevada 33-3992087
Leathers, L.P. California 33-0305342
Del Ranch, L.P. California 33-0278290
Elmore, L.P. California 33-0278294
Salton Sea Power LLC Delaware 47-0810713
CalEnergy Minerals LLC Delaware 47-0810718
CE Turbo LLC Delaware 47-0812159
CE Salton Sea Inc. Delaware 47-0810711
Salton Sea Minerals Corp. Delaware 47-0811261
302 S. 36th Street, Suite 400-A, Omaha, NE 68131
---------------------------------------------------
(Address of principal executive offices and Zip Code of Salton Sea Funding
Corporation)
Salton Sea Funding Corporation's Telephone Number, including area code:
(402) 341-4500
--------------------------------------------
N/A
- ------------------------------------------------------------------------------
(Former name or former address, if changed since last report)
Item 5. Other Events.
The Registrants have previously reported that Southern California
Edison Company ("Edison") has failed to make timely payment for power purchased
during November and December 2000 under long-term power sales contracts (the
"Contracts") with certain of the Registrants. Certain Registrants own and
operate eight operating geothermal plants with an approximate aggregate net
rated capacity of 267 MW located in the Imperial Valley, California and sell the
power to Edison pursuant to the Contracts. On February 20, 2001 a lawsuit was
filed on behalf of the Registrants in California's Imperial County Superior
Court seeking a court order requiring Edison to make payment of more than $45
million for power delivered in November and December 2000 in accordance with the
Contracts. The lawsuit also requested that the court order permit the
Registrants to discontinue providing such power to Edison during such times as
Edison continues non-payment and instead be allowed to sell it to other delivery
entities in California.
The Registrants also previously reported that on March 22, 2001, the
Superior Court granted Registrant's Motion for Summary Adjudication and a
Declaratory Judgment ordering that: 1) under the Contracts, Registrants have the
right to temporarily suspend deliveries of capacity and energy to Edison, 2)
Registrants are entitled to resell the energy and capacity to other purchasers
and 3) the interim suspension of deliveries to Edison shall not in any respect
result in the modifications or termination of the Contracts, and the Contracts
shall in all respects continue in full force and effect other than the temporary
suspension of deliveries to Edison.
The Registrant also noted that on April 10, 2001, Edison International
filed its current report on Form 8-K with the Securities and Exchange Commission
wherein it reported certain recent litigation, as well as recent legislative and
regulatory actions taken, or potentially to be taken, by the State of California
which could affect Edison. A copy of Edison International's current report on
Form 8-K is included as an exhibit to this report.
Certain information included in this report contains forward-looking statements
made pursuant to the Private Securities Litigation Reform Act of 1995 ("Reform
Act"). Such statements are based on current expectations and involve a number of
known and unknown risks and uncertainties that could cause the actual results
and performance of the Registrants to differ materially from any expected future
results or performance, expressed or implied, by the forward-looking statements
including expectations regarding the future results of operations of
Registrants. In connection with the safe harbor provisions of the Reform Act,
the Registrants have identified important factors that could cause actual
results to differ materially from such expectations, including development and
construction uncertainty, operating uncertainty, acquisition uncertainty,
uncertainties relating to geothermal resources, uncertainties relating to
economic and political conditions and uncertainties regarding the impact of
regulations, changes in government policy, industry deregulation and
competition. Reference is made to all of the Registrants' SEC Filings,
incorporated herein by reference, for a description of such factors. The
Registrants assume no responsibility to update forward-looking information
contained herein.
Item 7. Financial Statements and Exhibits
Form 8-K current report dated March 27, 2001, filed by Edison
International April 10, 2001.
SIGNATURE
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.
SALTON SEA FUNDING CORPORATION
Date: April 17, 2001 By: /s/ Douglas L. Anderson
----------------------------------------
Douglas L. Anderson
Vice President
Item 7:
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)
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.
Page 2
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.
Page 3
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
Page 4
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
Page 6
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
Page 7
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.
Page 9
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
(c) Exhibits
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
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:
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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
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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
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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
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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
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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
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
[figure]
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.")
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 distribution
Amount 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.5 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 orward 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
[rspcorrection]