Back to GetFilings.com
================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
/X/ Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2000
------------------------------------------------------
Commission File Number 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
California 95-1240335
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue (626) 302-1212
Rosemead, California 91770 (Registrant's telephone number,
(Address of principal executive offices)(Zip Code) including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------ ---------------------
Capital Stock
Cumulative Preferred American and Pacific
4.08% Series 4.32% Series
4.24% Series 4.78% Series
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
As of April 16, 2001, there were 434,888,104 shares of Common Stock outstanding,
all of which are held by the registrant's parent holding company. The aggregate
market value of registrant's voting stock held by non-affiliates was
approximately $197,534,061.75 on or about April 16, 2001, based upon prices
reported by the American Stock Exchange. The market values of the various
classes of voting stock held by non-affiliates, as of April 16, 2001, were as
follows: CUMULATIVE PREFERRED STOCK $40,079,061.75; $100 CUMULATIVE PREFERRED
STOCK $157,455,000.00.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents listed below have been incorporated by
reference into the parts of this report so indicated.
(1) Designated portions of the Annual Report to
Shareholders for the year ended December 31, 2000......Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement
relating to registrant's 2001 Annual
Meeting of Shareholders........................................ Part III
================================================================================
TABLE OF CONTENTS
Item Page
- ----------------------------------------------------------------------------------------------------------------
Part I
1. Business ............................................................................................... 1
Forward-Looking Statements.......................................................................... 1
Competitive Environment............................................................................. 3
Significant Developments in California Electric Utility Restructuring............................... 3
Regulation.......................................................................................... 10
Changing Regulatory Environment..................................................................... 11
Other Rate Matters.................................................................................. 16
Fuel Supply and Purchased Power Costs............................................................... 21
Environmental Matters............................................................................... 22
2. Properties.............................................................................................. 25
Existing Generating Facilities...................................................................... 25
Construction Program and Capital Expenditures....................................................... 27
Nuclear Power Matters............................................................................... 27
3. Legal Proceedings....................................................................................... 31
Geothermal Generators' Litigation................................................................... 31
San Onofre Personal Injury Litigation............................................................... 31
Navajo Nation Litigation.............................................................................32
Shareholder Litigation...............................................................................33
Power Generator Litigation.......................................................................... 34
PX Performance Bond Litigation...................................................................... 39
4. Submission of Matters to a Vote of Security Holders..................................................... 40
Executive Officers of the Registrant................................................................ 40
Part II
5. Market for Registrant's Common Equity and Related Stockholder Matters................................... 42
6. Selected Financial Data................................................................................. 42
7. Management's Discussion and Analysis of Results of Operations and Financial Condition................... 42
7A. Quantitative and Qualitative Disclosures About Market Risk.............................................. 42
8. Financial Statements and Supplementary Data............................................................. 42
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................... 42
Part III
10. Directors and Executive Officers of the Registrant...................................................... 42
11. Executive Compensation.................................................................................. 43
12. Security Ownership of Certain Beneficial Owners and Management.......................................... 43
13. Certain Relationships and Related Transactions.......................................................... 43
Part IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................................ 43
Financial Statements................................................................................ 43
Report of Independent Public Accountants and Schedules Supplementing Financial Statements........... 43
Exhibits............................................................................................ 44
Reports on Form 8-K ................................................................................ 44
Signatures.......................................................................................... 49
PART I
Item 1. Business
Southern California Edison Company (SCE) was incorporated in 1909 under the laws
of the State of California. SCE is a public utility primarily engaged in the
business of supplying electric energy to a 50,000 square-mile area of Central
and Southern California, excluding the City of Los Angeles and certain other
cities. The SCE service territory includes approximately 800 cities and
communities and a population of more than 11 million people. Beginning in April
1998, pursuant to the restructuring of the California electric utility industry
mandated by a 1996 state law, other entities have had the ability to sell
electricity in SCE's service territory, utilizing SCE's transmission and
distribution lines at tariffed rates. As a part of this utility industry
restructuring, SCE sold some of its electric generating plants in 1998. SCE
currently retains other electric generating plants, however, and it retains its
transmission and distribution lines over which it transmits and distributes the
electricity generated by SCE and other generators to the customers in SCE's
service territory. The Memorandum of Understanding (MOU) that Edison
International and SCE have entered into with the California Department of Water
Resources (CDWR) with the endorsement of the Governor of California (described
in Significant Developments in California Electric Utility Restructuring) calls
for the sale of SCE's transmission assets to an agency of the State of
California. As a further part of the industry restructuring, SCE had been
required for an intended interim transitional period (ending no later than
year-end 2001) to sell all SCE-generated electricity to the California Power
Exchange (PX) at prices determined by periodic public auctions, and to buy any
electricity needed to serve SCE's retail customers from the PX at similarly
determined prices. As part of a December 15, 2000, order, the Federal Energy
Regulatory Commission (FERC) eliminated the requirement that SCE buy and sell
power exclusively through the PX and California Independent System Operator
(ISO). In mid-January 2001, the PX suspended SCE's trading privileges for
failure to post collateral due to SCE's rating agency downgrades. The PX
suspended its day-ahead and day-of energy trading on January 30 and January 31,
2001, respectively. On March 9, 2001, the PX filed for Chapter 11 bankruptcy
protection. As discussed in Significant Developments in California Electric
Utility Restructuring below, the CDWR is providing power for sale to SCE's
customers to the extent SCE cannot provide sufficient power from SCE's own
generation and power contracts. SCE delivers such power and collects revenues
for it on behalf of CDWR. In 2000, SCE's total operating revenue was derived
from: 38.2% residential customers, 38.3% commercial customers, 8.4% industrial
customers, 6.6% public authorities, 2.3% agricultural and other customers, and
6.2% other electric revenue. SCE had 12,593 full-time employees at year-end
2000. SCE comprises the largest portion of the assets and revenue of its parent
holding company, Edison International.
Forward-Looking Statements
This annual report contains forward-looking statements that reflect SCE's
current expectations and projections about future events based on SCE's
knowledge of present facts and circumstances and assumptions about future
events. Other information distributed by SCE that is incorporated herein or
refers to or incorporates this annual report may also contain forward-looking
statements. In this annual report and elsewhere, the words "expects,"
"believes," "anticipates," "estimates," "intends," "plans," "probable" and
variations of such words and similar expressions are intended to identify
forward-looking statements. Such statements necessarily involve risks and
uncertainties that could cause actual results to differ materially from those
anticipated. Some of the risks, uncertainties and other important factors that
could cause results to differ are:
o Edison International's and SCE's financial condition, liquidity and credit
ratings have been adversely affected by California's electricity crisis.
Edison International and SCE have entered into a memorandum of
understanding (MOU) with the endorsement of the Governor of California,
which provides a plan for SCE's financial recovery by SCE selling its
transmission assets to an agency of the State of California and issuing
bonds to finance its undercollected power procurement costs, among other
steps. However, the MOU cannot be implemented unless the California
Legislature enacts necessary legislation, the California Public Utilities
Commission (CPUC) and FERC adopt necessary
1
orders, and various parties negotiate and execute definitive agreements.
Edison International and SCE cannot be certain that all the required
parties will take the necessary actions.
o Edison International and SCE are seeking to regain investment grade credit
ratings so they can re-enter the credit markets on reasonable terms. The
success of their efforts depends on the implementation of the MOU, which in
turn depends on actions of legislators, regulatory bodies and others.
o SCE is seeking to avoid bankruptcy. To conserve cash, SCE suspended certain
payments for debt service and purchased power. As a result numerous
creditors are suing SCE, and some have threatened the possible filing of an
involuntary bankruptcy petition against SCE. SCE's nonpayment of certain
debt obligations also entitles debtholders to exercise remedies against
Edison International, including possibly accelerating the repayment of
principal.
o The CPUC recently adopted retroactive changes in regulatory accounting
mechanisms and implemented other measures that impair SCE's ability to
recover its costs and investments. As a result, SCE has taken a $2.5
billion ($4.2 billion on a pre-tax basis) fourth quarter write-off of
regulatory assets. The write-off eliminates SCE's retained earnings and
SCE's ability to pay dividends and issue additional first mortgage bonds.
If the MOU described above 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 reinstated with a corresponding increase
in earnings. But to implement the MOU, SCE will need the cooperation of
legislators, regulators and other parties.
o SCE may be affected by actions of regulatory bodies setting rates, adopting
or modifying cost recovery, accounting or rate-setting mechanisms and
implementing the restructuring of the electric utility industry. For
example, regulatory actions in California affect SCE's ability to recover
its past investments in utility plant and earn competitive returns.
o SCE may be affected by legislative and regulatory measures adopted and
being contemplated by federal and state authorities to address the
California electricity crisis or deregulation in other states, pending
legislation that would repeal or amend key statutes governing the electric
industry.
o SCE may be affected by increased competition in the electric utility
business and other energy-related businesses, including among other things
the ability of customers to purchase energy and metering and billing
services from nonutility energy service providers.
o SCE owns and operates power generation facilities and, therefore, may be
affected by changes in the supply, demand and price for electric capacity
and energy in relevant markets and the cost and availability of fuel and
fuel transportation.
o As an owner-operator of power generation facilities, SCE also may be
affected by unpredictable weather conditions that may affect seasonal
patterns of revenue collection, cause changes in demand (and prices) for
electricity for heating and cooling purposes, and result in higher costs
for repair or maintenance of assets.
o SCE may be affected by financial market conditions such as inflation and
changes in interest rates, which could affect the availability and cost of
external financing, as well as the actions of securities rating agencies.
o SCE is subject to power plant operation risks, including strikes, equipment
failures and other issues.
o SCE may be affected by changes in tax laws or unfavorable interpretation
and application of the laws by tax authorities.
2
o The operation of power generation, transmission or distribution facilities
by SCE involves the potential for new or increased environmental
liabilities associated with power plants and other facilities or
operations, resulting from changes in laws, accidents or other events.
o SCE is seeking to create and expand new businesses, such as
telecommunications and other energy-related consumer products and services.
Those businesses are subject to various risks involved with start-up
activities, such as developing products, gaining customers, establishing
management processes, hiring qualified personnel, and so forth.
o SCE may be subject to legal proceedings arising out of financial reporting,
commercial disputes, property rights, personal injuries, and other
circumstances.
Additional information about the risk factors listed above is contained
throughout this annual report. Readers are urged to read this entire report and
carefully consider the risks, uncertainties and other factors that affect SCE's
business. The information contained in this report is subject to change without
notice. Readers should review future reports filed by SCE with the Securities
and Exchange Commission (SEC).
Competitive Environment
SCE operates in a highly regulated environment in which it has an obligation to
deliver electric service to customers in return for an exclusive franchise
within its service territory and certain obligations of the regulatory
authorities to provide just and reasonable rates. In 1994, state lawmakers and
the CPUC initiated the electric industry restructuring process. In 1996, the
California Legislature enacted comprehensive restructuring legislation. SCE was
directed by the CPUC to divest the bulk of its gas-fired generation portfolio.
Furthermore, under the legislation and CPUC decisions, prices for wholesale
purchases of electricity from power suppliers are set by markets while the
retail prices paid by utility customers for electricity delivered to them
remained frozen at June 1996 levels. California's electric utilities, including
SCE, are currently facing a financial and liquidity crisis as a result of the
changes brought about by restructuring. (See Significant Developments in
California Electric Utility Restructuring below for a description of the most
recent developments.)
Significant Developments in California Electric Utility Restructuring
Beginning in May 2000, SCE began experiencing adverse impacts from unusually
high prices for energy and ancillary services procured through the PX and the
ISO. These high wholesale prices, coupled with the freeze on SCE's retail rates
mandated by the 1996 restructuring legislation, resulted in substantial
increases in the amount of undercollections in SCE's transition revenue account
(TRA). SCE's TRA is a regulatory asset account in which SCE records the
difference between revenues received from customers through the frozen rates and
the costs of providing service to customers, (which includes purchased power
procurement costs). As of December 31, 2000, the amount of undercollections
recorded was $4.5 billion. Based on a CPUC decision on March 27, 2001 (see
further discussion below), this overcollection, and SCE's coal and hydroelectric
balancing account undercollections (which amounted to $1.5 billion as of
December 31, 2000), were reclassified. In addition, SCE's transition cost
balancing account (TCBA), representing recovery of stranded costs net of a
previously recorded credit for market valuation of hydroelectric generation
assets and the overcollections in the balancing accounts for the coal and
hydroelectric generating assets, was recalculated to be a $2.9 billion
undercollection.
On April 9, 2001, Edison International, SCE and the CDWR executed a Memorandum
of Understanding (MOU) which sets forth a comprehensive plan calling for
legislation, regulatory action and definitive agreements to resolve important
aspects of the energy crisis, and which, if implemented, is expected to help
restore SCE's creditworthiness and liquidity. The Governor of the State of
California and his representatives participated in the negotiation of the MOU,
and the Governor endorsed implementation of all the elements of the MOU. Edison
International, SCE 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
3
definitive agreements. If required legislation is not adopted and definitive
agreements executed by August 15, 2001, or if the CPUC does not adopt required
implementing decisions by June 8, 2001, the MOU may be terminated by Edison
International, SCE or the CDWR. Neither Edison International nor SCE can provide
assurance that all the required legislation will be enacted, regulatory actions
taken and definitive agreements executed before the applicable deadlines.
Implementation of the MOU, which is discussed in more detail below, will require
numerous actions by the parties and by other California state agencies and the
FERC, and would require significant changes in the regulatory decisions and
other actions discussed below.
The growing undercollections and the concerns of lenders and others that SCE
might not obtain regulatory approval of rate increases sufficient to cover
ongoing procurement costs and recover past costs materially and adversely
affected the liquidity of Edison International and SCE, becoming particularly
pronounced in January 2001. With its revenues providing substantially less cash
flow than needed for power purchases and other ongoing costs, SCE and its parent
company, Edison International, soon had no unused borrowing capacity under their
existing credit facilities and were unable to arrange any additional facilities.
Moreover, Edison International and SCE found themselves unable to issue
commercial paper or otherwise access the capital markets on reasonable terms. To
conserve cash and enable SCE to continue essential business operations, in
mid-January 2001, SCE temporarily suspended the payment of certain obligations
for principal and interest on outstanding debt and for purchased power.
As of March 31, 2001, SCE had $2.7 billion in obligations that were unpaid and
overdue including: (1) $626 million to the PX or the ISO; (2) $1.1 billion to
power producers that are qualifying facilities (QFs); (3) $229 million in PX
energy credits for energy service providers; (4) $506 million of matured
commercial paper; (5) $206 million of principal and interest on its 5-7/8%
notes; and (6) $7 million of other obligations. Unpaid obligations will continue
to accrue interest, as applicable. At March 31, 2001, SCE had estimated cash
reserves of approximately $2.0 billion, which is approximately $700 million less
than its outstanding obligations and preferred stock dividends in arrears. As of
March 31, 2001, the total preferred stock dividends in arrears was $6 million.
The amounts due to the ISO or PX in clause (1) above do not include $275 million
that has been charged back to SCE as a result of defaults in payments by Pacific
Gas and Electric Company (PG&E). SCE has disputed its obligation for such amount
in proceedings before the FERC and on April 6, 2001, the FERC ordered that such
charges be rescinded. As of March 31, 2001, SCE resumed payment of interest on
its debt obligations. Edison International has paid and expects to continue to
pay its obligations, as they are due, subject to obtaining financing. SCE has
repurchased $549 million of pollution control bonds that could not be remarketed
in accordance with their terms. These bonds may be remarketed in the future if
SCE's credit status improves sufficiently.
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 December 14, 2000, following an announcement from the ISO that electricity
generators were refusing to sell into the California market due to concerns
about the financial stability of SCE and Pacific Gas and Electric Company, the
U.S. Secretary of Energy issued an order requiring power generators to make
arrangements to generate and deliver electricity as required by the ISO after
the ISO certifies it has been unable to secure adequate electricity supplies in
the market. After being renewed multiple times, the order
4
expired on February 6, 2001. However, on February 7, 2001, a federal court judge
issued a temporary restraining order requiring power suppliers to sell to the
California grid. On February 23, 2001, a federal court judge issued a stay of
litigation in the case of four power suppliers who agreed to extend their power
sales pending a hearing set for March 16, 2001. On March 16, 2001, a federal
court judge put the case on hold until March 20, 2001. On March 21, 2001, a
federal court judge ordered one of the power suppliers to continue to sell power
to the California grid. The three other power suppliers had signed an agreement
with the judge voluntarily agreeing to continue to sell power to the grid while
awaiting a review of the issue by the FERC. On April 6, 2001, the United States
Ninth Circuit Court of Appeals issued a stay order, suspending the lower court's
March 21 order until a final appeals ruling can be issued.
On January 17, 2001, following rolling blackouts in the northern California
service territory of Pacific Gas and Electric Company, California Governor Gray
Davis signed an order declaring an emergency and authorizing the CDWR to
purchase power in order to prevent further blackouts.
Subsequently, on February 1, 2001, Governor Davis signed into law Assembly Bill
(AB) IX, which was passed by the California Legislature as an urgency measure
during a special session and took effect immediately. The new law authorized the
CDWR to enter into contracts to purchase electric power and sell power at cost
directly to retail customers being served by SCE, and authorized the CDWR to
issue revenue bonds to finance electricity purchases. The new law directed the
CPUC to determine the amount of a California Procurement Adjustment (CPA) to
determine further the amount of the CPA allocable to the power sold by the CDWR
which will be payable to the CDWR when received by SCE. On March 7, 2001, the
CPUC issued an interim order in which it held that the CDWR's purchases are not
subject to prudency review by the CPUC, and that the CPUC must approve and
impose, either as a part of existing rates or as additional rates, rates
sufficient to enable the CDWR to recover its revenue requirements.
On March 27, 2001, the CPUC adopted an interim CPA-related order requiring SCE
to pay the CDWR a per-kWh price equal to the applicable generation-related
retail rate per kWh established in the order (based on rates in effect on
January 5, 2001), for each kWh the CDWR sells to SCE's customers. The CPUC
determined that the generation-related component of retail rates should be equal
to the total bundled electric rate (including the 1(cent) per kWh surcharge
adopted by the CPUC on January 4, 2001) less certain non-generation related
rates or charges. For the period January 19 through January 31, 2001, the CPUC
ordered SCE to pay the CDWR at a rate of 6.277 cents per kWh. The CPUC
determined that the company-wide generation-related rate component is 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 discussed below) for
each kWh delivered to customers beginning February 1, 2001, until more specific
rates are calculated. The CPUC ordered SCE to pay the CDWR within 45 days after
the CDWR supplies power to retail customers. Using these rates, SCE has billed
customers $196 million for energy sales made by CDWR during the period January
19 through March 31, 2001, and has forwarded $52 million to CDWR on behalf of
these customers as of March 31, 2001. In compliance with that same order, SCE is
currently paying the CDWR amounts approximating $2.5 million to $4 million
daily.
In addition, this interim order proposed a method the CPUC will use to calculate
the CPA in accordance with AB 1X and applied the proposed method to propose a
company-wide average CPA rate. Using this rate, the order determined a proposed
CPA revenue amount, to be used by the CDWR to determine the amount of bonds it
may issue. 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.
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
annual revenues of $856.43 million. 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
AB 1X. In its
5
calculation of the CPA, the CPUC disregarded all the adjustments requested by
SCE in its comments filed on March 29, 2001 (discussed below). 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.
SCE believes that the intent of AB 1X was for the CDWR to assume full
responsibility for purchasing all power needed to serve the retail customers of
electric utilities, in excess of the output of generating plants owned by the
electric utilities and power delivered to the utilities under existing
contracts. However, the CDWR has stated that it is only purchasing power that it
considers to be reasonably priced, leaving the ISO to purchase in the short-term
market the additional power necessary to meet system requirements. The ISO, in
turn, takes the position that it will charge SCE for the costs of power it
purchases in this manner. If SCE is found responsible for any portion of the
ISO's purchases of power for resale to SCE's customers, SCE will continue to
incur purchased-power costs in addition to the unpaid costs described above. In
its March 27, 2001, interim order, the CPUC stated that it cannot assume that
the CDWR will pay for the ISO purchases and that it does not have the authority
to order the CDWR to do so. Litigation among certain power generators, the ISO
and the CDWR (to which SCE is not a party), and proceedings before the FERC (to
which SCE is a party), may result in rulings clarifying the CDWR's financial
responsibility for purchases of power. On April 6, 2001, the FERC issued an
order confirming that the ISO must have a creditworthy buyer for any
transactions, scheduled or not. In any event, SCE takes the position that it is
not responsible for purchases of power by the CDWR or the ISO from and after
January 18, 2001, the day after the Governor signed the order authorizing the
CDWR to begin purchasing power for utility customers. The MOU contemplates that
the CDWR will assume the entire responsibility for procuring the electricity
needs of SCE's customers through December 31, 2002, to the extent not met by
SCE's retained generation and power contracts. SCE cannot predict the outcome of
any of these proceedings or issues.
In addition to the CPA-related order discussed above, on March 27, 2001, the
CPUC adopted several other significant decisions regarding California's current
energy crisis. These March 27, 2001, decisions deal with complex matters and in
many respects are unclear or ambiguous. Edison International and SCE believe
that in some respects the CPUC's March 27, 2001, decisions are unlawful and
unconstitutional. Many elements of the decisions will be developed further in
ongoing proceedings, the timing of which is uncertain. Furthermore, key
components of the decisions would have to be modified, or the decisions
rescinded, to implement the MOU that Edison International and SCE signed on
April 9, 2001, with the CDWR (discussed 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 (rate
stabilization decision). 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 probably 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 power
costs. If any refunds of power costs are obtained from power generators and
sellers, those refunds will be used to reduce customer rates or to pay power
costs. SCE must also refund the three-cent surcharge to the extend 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 AB 1X. 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
6
to the rate paid to the CDWR to reimburse the CDWR for its costs of purchasing
power for delivery to SCE's customers (see above).
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 most 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 order further revises
other aspects of the payment formula to take into account changes in intrastate
gas transportation costs. SCE anticipates that the changes will probably result
in lower QF energy prices. The changes apply where appropriate regardless of
whether the QF uses natural gas or other resources such as solar or wind.
In its March 27 decisions, the CPUC granted a petition previously filed by The
Utility Reform Network (TURN), a ratepayer advocacy group, that was opposed by
SCE and Pacific Gas and Electric Company. The CPUC directed that the balance in
SCE's 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 this CPUC
decision through all appropriate avenues.
In response to the CPUC's request in the interim CPA-related order, 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 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.
In its comments on the CPUC's methodology for calculating the CPA, 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 MWh, which was a target price in earlier
negotiations with QFs seeking a settlement on lower prices. However, those
negotiations failed.
7
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.
On April 9, 2001, Edison International and SCE signed a MOU with the 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, if implemented, is expected to help restore SCE's
creditworthiness and liquidity. 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, then if the State elects,
SCE's hydroelectric assets, and potentially additional rights to output
from other generating stations, 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 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.
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 Edison International 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 Edison International.
8
o An affiliate of Edison International, Edison Mission Energy ("EME") will
execute a contract with the CDWR or another state agency for the provision
of power to the state at cost-based rates for 10 years from a power project
currently under development. EME 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 on 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 and the FERC. 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 FERC. Edison International, SCE, 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, and Governor Davis has endorsed the MOU and has agreed to work for
its complete implementation. 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.
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. Edison International and SCE
cannot provide assurance that all the required legislation will be enacted,
regulatory actions taken, and definitive agreements executed before the
applicable deadlines.
Edison International and SCE believe that the MOU is an important step towards
an acceptable resolution of the major issues affecting Edison International 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 representatives of Governor Davis (the
actions of the CPUC cited by PG&E are discussed above).
9
SCE is still working to avoid bankruptcy, despite PG&E's announcement that it is
filing for bankruptcy court protection. Edison International 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 Edison International nor SCE can predict the impact of
PG&E's bankruptcy on implementation of the MOU and on Edison International's and
SCE's other efforts to resolve their current financial and liquidity problems.
Regulation
SCE's retail operations are, for the most part, subject to regulation by the
CPUC. The CPUC has the authority to regulate, among other things, retail rates,
issuance of securities, and accounting practices. SCE's wholesale operations are
subject to regulation by the FERC. The FERC has the authority to regulate
wholesale rates as well as other matters, including retail transmission service
pricing, accounting practices, and licensing of hydroelectric projects.
SCE is subject to the jurisdiction of the U.S. Nuclear Regulatory Commission
(NRC) with respect to its nuclear power plants. NRC regulations govern the
granting of licenses for the construction and operation of nuclear power plants
and subject those power plants to continuing review and regulation.
The construction, planning, and siting of SCE's power plants within California
are subject to the jurisdiction of the California Energy Commission and the
CPUC. SCE is subject to the rules and regulations of the California Air
Resources Board and local air pollution control districts with respect to the
emission of pollutants into the atmosphere; the regulatory requirements of the
California State Water Resources Control Board and regional boards with respect
to the discharge of pollutants into waters of the state; and the requirements of
the California Department of Toxic Substances Control with respect to handling
and disposal of hazardous materials and wastes. SCE is also subject to
regulation by the Environmental Protection Agency (EPA), which administers
certain federal statutes relating to environmental matters. Other federal,
state, and local laws and regulations relating to environmental protection, land
use, and water rights also affect SCE.
The California Coastal Commission has continuing jurisdiction over the coastal
permit for San Onofre Nuclear Generating Station Units 2 and 3. Although the
units are operating, the permit's mitigation requirements have not yet been
completed. California Coastal Commission jurisdiction may continue for several
years due to implementation and oversight of permit mitigation conditions,
including restoration of wetlands and construction of an artificial reef for
kelp. Additionally, in the summer of 2000, SCE applied for a coastal permit to
construct a dry cask spent fuel storage installation for Units 2 and 3. This
permit application was approved, with certain conditions, by the California
Coastal Commission at its meeting on March 13, 2001.
The U.S. Department of Energy has regulatory authority over certain aspects of
SCE's operations and business relating to energy conservation, power plant fuel
use and disposal, electric sales for export, public utility regulatory policy,
and natural gas pricing.
In 1997, the CPUC adopted a decision which established new rules governing the
relationship between California's natural gas local distribution companies,
electric utilities, and certain of their affiliates. While SCE and its
affiliates have been subject to affiliate transaction rules since the
establishment of its holding company structure in 1988, these new rules are more
detailed and restrictive. As required by the new rules and an interim CPUC
resolution, SCE has filed preliminary and revised compliance plans which set
forth SCE's implementation of the new affiliate transaction rules. The CPUC has
not yet ruled on the sufficiency of SCE's October 1998 revised compliance plan.
In January 2001, the CPUC issued an Order Instituting Rulemaking to commence the
review of the 1997 Affiliate Transaction Rules that the original decision itself
requires. The CPUC proposes that some rules be considered for streamlining or
other revision, while inviting interested parties to submit proposals of their
own. No decision is expected before the end of the year 2001 at the earliest.
10
On January 29, 2001, independent auditors hired by the CPUC issued a report on
the financial condition and solvency of SCE and its affiliates. The report
confirmed what SCE had previously disclosed to the CPUC in public filings about
SCE's financial condition. The audit report covers, among other things, cash
needs, credit relationships, accounting mechanisms to track stranded cost
recovery, the flow of funds between SCE and Edison International, and earnings
of SCE's California affiliates. On March 15, 2001, the CPUC released a draft of
a proposed order instituting investigation.
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 Edison International and SCE to respond within 10 days to
document requests and questions that are identical to document requests and
questions included in the proposed order instituting investigation. At its
meeting on April 3, 2001, 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 Edison International 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 Edison International 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.
Changing Regulatory Environment
SCE currently operates in a highly regulated environment in which it has an
obligation to deliver electric service to customers in return for an exclusive
franchise within its service territory and certain obligations of the regulatory
authorities to provide just and reasonable rates. In 1994, state lawmakers and
the CPUC initiated the electric industry restructuring process. In 1996, the
California Legislature enacted comprehensive restructuring legislation. SCE was
directed by the CPUC to divest the bulk of its generation portfolio. Today,
those generating plants are owned by independent power companies. Along with
electric industry restructuring, a mandated multi-year freeze on the rates that
SCE could charge its customers was mandated and transition cost recovery
mechanisms allowing SCE to recover its stranded costs associated with
generation-related assets were implemented.
As described above, skyrocketing wholesale energy pricing and resulting
liquidity pressures placed upon SCE and other investor-owned utilities has
caused the restructuring process to change significantly as California adopted
short-term measures, and works to develop longer-term solutions, to address the
energy crisis. SCE's remaining generation portfolio was impacted by California
state legislation enacted in January 2001 barring the sale of utility generating
facilities, including SCE's Mohave, Palo Verde and Four Corners generating
facilities, until 2006. Under the MOU, SCE would continue to own its share of
these generating assets, which would be subject to cost-based ratemaking,
through 2010. SCE's efforts to recover its transition and power procurement
costs associated with restructuring are described below under Recovery of
Transition and Power Procurement Costs.
Recovery of Transition and Power Procurement Costs
SCE's transition costs included power purchases from QF contracts (which are the
direct result of prior legislative and regulatory mandates), recovery of certain
generating assets and regulatory commitments consisting of recovery of costs
incurred to provide service to customers. Such commitments include the
11
recovery of income tax benefits previously flowed through to customers,
postretirement benefit transition costs, accelerated recovery of investment in
San Onofre Units 2 and 3 and the Palo Verde units, and certain other costs.
Transition costs related to power-purchase contracts are being recovered through
the terms of each contract. The CPUC decisions provide that most of the
remaining transition costs are subject to recovery only through the end of the
transition period (not later than March 31, 2002). Although the MOU provides
for, among other things, SCE to be entitled to sufficient revenue to cover its
costs from January 2001 associated with retaining generation and existing power
contracts, the implementation of the MOU requires the CPUC to modify various
decisions. 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 and other regulatory and legislative actions (see discussion in
the Significant Developments in California Electric Utility Restructuring
above), SCE is not able to conclude that the regulatory assets and liabilities
related to purchased-power settlements, the unamortized loss on SCE's generating
plant sales in 1998, and various other regulatory assets and liabilities
(including income taxes previously flowed through to customers) related to
certain generating assets are probable of recovery through the rate-making
process. As a result, these balances were written off as a charge to earnings as
of December 31, 2000. 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 amount that has been
charged against earnings, a regulatory asset would be correspondingly reinstated
with a corresponding increase in earnings.
During the rate freeze period, there are three sources of revenue available to
SCE for transition cost recovery: competition transition charge (CTC) revenue,
revenue from the sale or valuation of generation assets in excess of book
values, and net market revenue from the sale of SCE-controlled generation into
the ISO and PX markets. However, due to the events discussed above (see
Significant Developments in California Electric Utility Restructuring), revenue
from the sale of SCE generation into the ISO and PX markets and from the sale or
valuation of generation assets in excess of book values (prohibited by state
legislation enacted in January 2001) is no longer available to SCE. CTC revenue
is determined residually (i.e., CTC revenue is the residual amount remaining
from monthly gross customer revenue under the rate freeze after subtracting the
revenue requirements for transmission, distribution, nuclear decommissioning and
public benefit programs, and ISO payments and power purchases from the PX and
ISO). The CTC applies to all customers who were using or began using utility
services on or after the CPUC's 1995 restructuring decision date. Residual CTC
revenue is calculated through the TRA mechanism.
Beginning in May 2000, SCE experienced adverse impacts from high prices for
energy and ancillary services procured through the PX and ISO. These high
wholesale prices, coupled with the current freeze on SCE's rates, resulted in
substantial increases in the amount of undercollections in SCE's TRA, reaching
$4.5 billion as of December 31, 2000. Additional information about the financial
impact of this undercollection and various ongoing and proposed legislative and
regulatory efforts and judicial proceedings designed to address or otherwise
relating to it, is provided in Management's Discussion and Analysis in SCE's
Annual Report to Shareholders for the year ended December 31, 2000 (Annual
Report), under Regulatory Environment - Status of Transition and Power
Procurement Costs Recovery section incorporated herein by reference pursuant to
General Instruction G(2).
Rate Reduction Notes
In December 1997, after receiving approval from the CPUC and the California
Infrastructure and Economic Development Bank, a limited liability company
created by SCE issued approximately $2.5 billion of rate reduction notes.
Residential and small commercial customers, whose 10% rate reduction began
January 1, 1998, are repaying the notes over the expected ten-year term through
non-bypassable charges based on electricity consumption. There were originally
seven classes of notes. The first class, in the amount of $246.3 million,
matured in December 1998, and the second class in the amount of $307.3 million
matured in March 2000. The remaining Notes consist of five classes with
scheduled maturities beginning in 2001 and ending in 2007, with interest rates
ranging from 6.17% to 6.42%.
12
Other Revenue and Cost-Recovery Mechanisms
Revenue is determined by various mechanisms depending on the utility operation:
distribution, transmission and generation. Moreover, in response to the
above-referenced skyrocketing wholesale energy pricing, SCE has initiated rate
stabilization proceedings at the CPUC. In addition, SCE jointly petitioned the
FERC to find that the California wholesale electricity market was not workably
competitive, to immediately impose a price cap for energy and ancillary
services, and to take other responsive measures.
Revenue related to distribution operations is being determined through a
performance-based rate-making mechanism (PBR) and the distribution assets have
the opportunity to earn a CPUC-authorized 9.49% return. The distribution PBR
will extend through December 2001. Key elements of the distribution PBR include:
distribution rates indexed for inflation based on the Consumer Price Index less
a productivity factor; adjustments for cost changes that are not within SCE's
control; a cost-of-capital trigger mechanism based on changes in a utility bond
index; standards for customer satisfaction; service reliability and safety; and
a net revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from distribution operations.
Transmission revenue is being determined through the FERC-authorized rates that
are subject to refund. Since the initiation of the ISO in April 1998,
transmission cost recovery has been under FERC authority. In July 2000, FERC
issued a final decision in SCE's 1998 FERC transmission rate case in which it
ordered a reduction of approximately $38 million to SCE's proposed annual base
transmission revenue requirement of $213 million. Of the total reduction of $38
million, about $24 million is associated with the rejection by FERC of SCE's
proposed method for allocating overhead costs to transmission operations. SCE
filed a Conditional Petition for Rehearing of the decision in August 2000,
asking that FERC reconsider the decision assuming that the CPUC does not allow
SCE to recover the $24 million in CPUC jurisdictional rates. In February 2001,
SCE filed with the CPUC a request to recover in CPUC-jurisdictional rates the
overhead costs not permitted by FERC to be included in transmission rates. A
CPUC decision is not expected until late in 2001. In the meantime, SCE continues
to collect transmission revenues based on the originally proposed $213 million
level, subject to refund pending final resolution of the 1998 rate case. SCE
expects that any refund amounts ultimately ordered by FERC associated with
transmission will not be refunded to retail customers but will be credited
against the amount of accrued transition/procurement costs.
Effective with the commencement of the ISO and PX operations on March 31, 1998,
generation costs were subject to recovery through the market and transition cost
recovery mechanisms, which included the nuclear rate-making agreements. During
the rate freeze, revenue from generation-related operations has been determined
through the market and transition cost recovery mechanisms, which included the
nuclear rate-making agreements. The portion of revenue related to coal
generation plant costs (Mohave Generating Station and Four Corners Generating
Station) that were made uneconomic by electric industry restructuring has been
recovered through the transition cost recovery mechanisms. After April 1, 1998,
coal generation operating costs have been recovered through the market. The
excess of power sales revenue from the coal generating plants over the plants'
operating costs has been accumulated in a coal generation balancing account.
SCE's costs associated with its hydroelectric plants have been recovered through
a performance-based mechanism. The mechanism set the hydroelectric revenue
requirement and established a formula for extending it through the duration of
the electric industry restructuring transition period, or until market valuation
of the hydroelectric facilities, whichever occurred first. The mechanism
provided that power sales revenue from hydroelectric facilities in excess of the
hydroelectric revenue requirement is accumulated in a hydroelectric balancing
account. In accordance with a CPUC decision issued in 1997, the credit balances
in the coal and hydroelectric balancing accounts were transferred to the TCBA at
the end of 1998 and 1999. However, due to the CPUC's March 27, 2001, rate
stabilization decision, the credit balances in these balancing accounts have now
been transferred to the TRA on a monthly basis, retroactive to January 1, 1998.
In addition, the TRA balance, whether over- or undercollected, has now been
transferred to the TCBA on a monthly basis, retroactive to January 1, 1998. Due
to a December 15, 2000, FERC order, SCE is no longer required to buy and sell
power exclusively through the ISO and PX. In mid-January 2001, the PX suspended
SCE's trading privileges for failure to post collateral due to SCE's rating
agency downgrades. As a result, power from SCE's coal and hydroelectric plants
is no longer being sold through the market and these two balancing accounts have
13
become inactive. As a key element of the MOU, SCE would continue to own its
generation assets, which would be subject to cost-based ratemaking, through
2010. The MOU calls for the CPUC to adopt cost recovery mechanisms consistent
with SCE obtaining and maintaining an investment grade credit rating.
In 1999, SCE filed an application with the CPUC proposing for purposes of the
application a market value for its hydroelectric generation-related assets at
approximately $1.0 billion (almost twice the assets' book value) and proposing
to retain and operate the hydroelectric assets under a performance-based,
revenue-sharing mechanism. Under the MOU, SCE would withdraw this application,
and would continue to operate the hydroelectric assets under cost-based
ratemaking, through 2010.
In April 2000, SCE agreed to sell its 15.8% interest in Palo Verde and its 48%
interest in Four Corners Generating Station to Pinnacle West Energy (PWE) for
$550 million, subject to certain adjustments. The transaction remained subject
to the approval of the CPUC, the NRC, the FERC and other state and federal
entities, and to the receipt of a favorable ruling from the Internal Revenue
Service. In January 2001, California state legislation was enacted which bars
the sale of utility generating facilities, including SCE's Palo Verde and Four
Corners generating facilities, until 2006. Under the MOU, SCE would withdraw its
application to sell these generation interests and would continue to own its
generating assets, which would be subject to cost-based ratemaking, through
2010.
In January 2000, SCE filed an application with the CPUC proposing rates that
would go into effect when the current rate freeze ends on March 31, 2002, or
earlier, depending on the pace of transition cost recovery. In light of its
four-point market reform proposal of October 2000, on November 16, 2000, SCE
filed a rate stabilization plan with the CPUC seeking, among other things, a
9.9% rate increase for all customers (excluding low-income customers whose
increase would be 4.95%) for a two-year period beginning January 1, 2001.
Hearings were held in late December 2000 and on January 4, 2001, and the CPUC
issued an interim decision authorizing SCE to establish an interim surcharge of
1(cent) per kilowatt-hour for 90 days, subject to refund. The revenue from the
surcharge is being tracked through a balancing account and applied to ongoing
power procurement costs. The surcharge resulted in rate increases, on average,
of approximately 7% to 25%, depending on the class of customer. As noted in the
decision, the 90-day period allowed independent auditors engaged by the CPUC to
perform a comprehensive review of SCE's financial position, as well as that of
Edison International and other affiliates.
In its interim rate stabilization order adopted on March 27, 2001, the CPUC
granted SCE a rate increase in the form of a 3(cent) per kWh surcharge applied
only to electric power costs, effective immediately, and affirmed that the
1(cent) interim surcharge granted on January 4, 2001, is now permanent. Also, in
the interim order, the CPUC granted a petition previously filed by TURN and
directed that the balance in SCE's TRA, over- or undercollected, be transferred
on a monthly basis to the TCBA, retroactive to January 1, 1998, (see Significant
Developments in California Electric Utility Restructuring).
In October 2000, SCE filed a joint petition urging the FERC to immediately find
the California wholesale electricity market to be not workably competitive;
immediately impose a cap on the price for energy and ancillary services; and
institute further expedited proceedings regarding the market failure, mitigation
of market power, structural solutions and responsibility for refunds. On
December 15, 2000, the FERC released a final order containing remedies and other
actions in response to the problems in the California electricity market. On
December 26, 2000, SCE filed an emergency petition in the federal Court of
Appeals challenging the FERC order and seeking a writ of mandamus requiring the
FERC to immediately establish cost-based wholesale rates. On January 5, 2001,
the Court denied SCE's petition. The effect of the denial is to leave in place
the FERC's market mechanisms. SCE's petition for rehearing remains pending.
In November 2000, SCE filed with the CPUC a request for approval to credit the
TCBA (and debit the Generation Asset Balancing Account) as soon as possible with
the aggregate net gain on the pending sales of the Mohave, Four Corners and Palo
Verde generation plants, which would have the effect of substantially
accelerating the end of SCE's statutory rate freeze. The CPUC dismissed the
request without full proceedings on the grounds that it was premature. Due to
events discussed above in Significant Developments in California Electric
Utility Restructuring (State legislation enacted in
14
January 2001 bars the sale or valuation of SCE's remaining generation assets
until 2006), revenue from the sale of generation assets in excess of book values
is no longer available to SCE. Additionally, as indicated above, under the MOU
SCE would continue to own its generating assets, which would be subject to
cost-based ratemaking, through 2010.
On March 9, 2001, the FERC directed 13 wholesale sellers of energy to refund $69
million or submit cost-of-service information to the FERC to justify their
prices above $273/MWh during ISO Stage 3 emergencies in January 2001. On April
9, 2001, SCE filed opposing the order as inadequate, particularly because the
FERC is unwilling to exercise any control over the sellers' exercise of market
power during periods other than Stage 3 emergencies. On March 16, 2001, the FERC
ordered six wholesale sellers of energy to refund an additional $55 million or
submit cost-of-service information to the FERC to justify their prices above
$430/MWh during ISO Stage 3 emergencies in February 2001. A Stage 3 emergency
refers to 1.5% or less in reserve power, which could trigger rotating blackouts
in some neighborhoods.
See Regulatory Environment - Generation and Power Procurement and Regulatory
Environment - Rate Stabilization Proceeding sections of the Management's
Discussion and Analysis in the Annual Report, incorporated herein by reference
pursuant to General Instruction G(2), for more information about SCE's revenue
from its generation-related operations, recovery of its investment in its
nuclear facilities, market valuation of its hydroelectric generation-related
assets, the proposed sales of its interests in the Palo Verde and Four Corners
generating facilities, rate stabilization proceedings before the CPUC and its
FERC petition seeking specific regulatory responses to the wholesale energy
market dysfunction, and on accounting for generation-related assets and power
procurement costs.
Restructuring Implementation Costs
In May 1998, SCE filed an application with the CPUC to identify the categories
of restructuring implementation costs (including costs related to the start-up
and development of both the PX and ISO, and related to the implementation of
direct access) and to establish the reasonableness of those costs incurred in
1997. In September 1999, the CPUC approved a settlement agreement between SCE,
the Office of Ratepayer Advocates (ORA) and several other parties allowing SCE
to recover substantially all (approximately $300 million) of its restructuring
implementation costs (incurred and estimated) for the period 1997-2001. In
addition, the settlement provides that up to $210 million of generation-related
costs (transition costs) that are displaced by recovery of the restructuring
implementation costs during the rate freeze may be recovered after December 31,
2001, the date SCE would no longer be allowed to recover these transition costs
under restructuring legislation.
Market Risk Exposures
In 1997, SCE bought gas call options to mitigate its transition cost recovery
exposure to increases in energy costs. In October 2000, SCE sold its remaining
options; the gains were credited to the TCBA. In July 1999, SCE began
participating in forward purchases through a PX block forward market. Initially,
the only product available in the PX block forward market provided a monthly
block of energy delivered six days a week (excluding Sundays and holidays), 16
hours a day. The CPUC originally limited SCE's use of the PX block forward
market to a maximum of approximately 2,000 MW in any month. The PX requested and
was granted authority from the FERC to sell other forward products including a
peak product that specified power delivery six days a week, eight hours a day
(excluding holidays). In March 2000, the CPUC approved SCE's request for
rate-making treatment for its use of these additional products and for an
expansion of the limits from all forward PX products up to 5,200 MW in summer
months. In April 2000, the CPUC approved SCE's request to begin a demand
responsiveness program that would allow customers to be paid to curtail their
load during times of very high PX energy prices. In August 2000, the CPUC
approved SCE's request to enter into bilateral power contracts. The CPUC
approval limited the quantity of power that could be contracted for, required
pre-approval for contracts extending beyond 2002, and required that all
contracts expire on or before December 31, 2005. SCE entered into bilateral
power contracts in November 2000. On December 31, 2000, the "mark-to-market"
value of SCE's block-forward and bilateral forward contracts (market value of
the contracted power less the contract cost) was $424 million and $398 million,
respectively. During the last eight months of 2000, SCE experienced
significantly
15
higher PX purchased-power expenses despite savings of $684 million realized from
its power hedging contracts over that period.
On February 2, 2001, the State of California seized SCE's block forward
contracts. Under law, the State must compensate SCE for the reasonable value of
the contracts. The PX has indicated that it will also seek to recover the monies
SCE owes to the PX from any proceeds from the contracts. On or about February
26, 2001, SCE filed a claim against the State Board of Control (now known as the
California Victim Compensation and Government Claims Board) seeking recovery of
damages incurred as a result of the State's seizure of the block forward
contracts. SCE has also notified Governor Gray Davis of SCE's intention to
pursue a claim for damages. The Board has yet to respond to SCE's claim. The
MOU, if implemented, calls for settlement of SCE's claim relating to these block
forward contracts.
Other Rate Matters
CPUC Retail Ratemaking
The CPUC regulates the charges for services provided by SCE to its retail
customers. As discussed above in the section on Changing Regulatory Environment,
the way in which the CPUC regulates SCE is changing. The CPUC has issued both
final and interim decisions regarding direct access, transition cost recovery,
and rate unbundling in the restructuring of the electric industry. While some of
them (such as those regarding transition cost recovery) are being challenged by
SCE both before the CPUC as well as in judicial proceedings, the above decisions
have affected cost recovery and rate regulation, and authorized new ratemaking
mechanisms which were implemented, replacing the Electric Revenue Adjustment
Mechanism, Energy Cost Adjustment Clause (ECAC) and base rates mechanism
(pre-restructuring ratemaking mechanisms) as of January 1, 1998.
Under the restructuring legislation, total rates for all customers were frozen
at June 10, 1996, levels, although residential and small commercial customers
received a 10% reduction from the June 10, 1996, rate levels beginning on
January 1, 1998. These rate levels were to remain in effect for the remainder of
the transition period; however, on January 4, 2001, the CPUC issued an interim
decision authorizing SCE to establish an interim surcharge of 1(cent) per
kilowatt-hour for 90 days, subject to refund. This was followed by the CPUC's
interim rate stabilization order adopted on March 27, 2001 (see Other Revenue
and Cost Recovery Mechanisms). Under these frozen rates, individual rate
components (distribution, transmission, nuclear decommissioning, and public
purpose programs) are determined according to CPUC- or FERC-authorized
mechanisms, with the generation rate determined residually by subtracting these
other components from the total rate. Beginning for rates effective in 1999, the
consolidation of the individual rate component changes and the calculation of
the residual generation rate are set forth for CPUC approval as part of the
Revenue Adjustment Proceeding (RAP). On June 1, 1998, SCE filed its first annual
RAP Report in compliance with CPUC directives to: (1) consolidate authorized
rates and revenue requirements associated with various proceedings and
mechanisms; (2) verify the residual CTC revenue calculation in the TRA; (3)
verify the regulatory account balances which were transferred to the TCBA on
January 1, 1998 (see Annual Transition Cost Proceeding below for further
discussion of the TCBA); (4) streamline certain balancing and memorandum
accounts; and (5) review the PX charge/credit calculation. On June 6, 1999, the
CPUC issued its final 1998 RAP decision. In compliance with that decision, SCE
updated its nongeneration rate components in October 1999. To maintain overall
frozen rate levels, to the extent nongeneration rate components are authorized
to change, the generation rate component changes equal and opposite from the
nongeneration rate component changes. The decision also instructed SCE to
include in the 1999 RAP Report a PX credit calculation that reflects the
long-run marginal costs of customer account managers, customer service
representatives, self-provision of ancillary services, and financing costs for
purchasing power from the PX.
In June 1999, the CPUC issued a decision regarding unbundling SCE's cost of
capital based on major utility functions. The decision was in response to SCE's
May 1998 application on this issue. The CPUC found no unbundling adjustment was
required in setting 1999 cost of capital for the California electric
16
utilities. Furthermore, the CPUC ruled that SCE's rate of return should continue
to be governed by the cost of capital trigger mechanism authorized as part of
SCE's performance-based ratemaking mechanism. (See discussion under Other
Revenue and Cost-Recovery Mechanisms.) As a result, SCE's return on equity for
1999 was unchanged at 11.6%.
On August 9, 1999, SCE filed its 1999 RAP Report requesting CPUC approval of the
following: (1) consolidation of the 2000 nongeneration revenue requirements; (2)
rate levels for 2000, including the residually determined generation rates; (3)
2000 kWh sales forecast; (4) entries to the TRA for the period June 1, 1998,
through May 31, 1999; (5) proposed retention, elimination, and modification of
balancing and memorandum accounts; (6) implementation and costs of electric
vehicle programs during the record period; (7) administration of SCE's
self-generation deferral rate contracts during the record period; and (8) the
proposed additional .007/kWh (7 cents/MWh) credit to direct access customers
associated with SCE's procurement of PX energy for bundled service customers.
The most hotly contested issue was the computation of the PX Credit Adder
intended to reflect each utility's long-run marginal cost of power procurement.
On August 2, 2000, two proposed decisions (PDs) were issued - a PD of ALJ
Barnett and an Alternate PD of Commissioner Neeper. ALJ Barnett adopted for all
three investor-owned utilities a PX Credit Adder of .007 cents per kWh (7 cents
per MWh). This is the PX Credit Adder that SCE had proposed. ALJ Barnett adopted
all of SCE's arguments on long-run marginal cost and used SCE's formulation of
the PX credit as a model for the other utilities. Commissioner Neeper adopted,
and later through a revised PD modified, a different PX Credit Adder. A revised
Alternate PD by Commissioner Bilas proposing yet another PX Credit Adder was
issued on November 6, 2000. Like other Alternates, it relied on the "average
cost" methodology of the ORA. On January 4, 2001, the PD of ALJ Barnett was
adopted by the CPUC. The decision put SCE on notice that it will no longer be
able to prospectively recover 100% of its reliability must-run costs in the TRA.
The decision adopted all other RAP issues SCE requested.
Nuclear Decommissioning and Public Purpose Program Rates
Recovery of SCE's nuclear decommissioning costs and legislatively mandated
public purpose program funding is made through rates set to recover 100% of
these costs. Public purpose programs include cost effective energy efficiency,
research, renewable technology development, and low income programs.
Annual Transition Cost Proceedings (ATCP)
In 1997, the CPUC established the ATCP to determine whether SCE's TCBA entries
are recorded pursuant to applicable CPUC decisions and the restructuring
legislation, and whether certain expenses are justified. The purpose of the ATCP
is to ensure the recovery of generation-related transition costs through the
TCBA that complies with the guidelines established by the CPUC. The TCBA tracks
the recovery of transition costs, including the accelerated recovery of plant
balances, QF and purchased power costs, and regulatory assets and obligations.
1998 ATCP
On September 1, 1998, SCE filed its first ATCP Report with the CPUC and
requested, among other things, that entries made to the TCBA and applicable
generation-related memorandum accounts during the record period of January 1,
1998, through June 30, 1998, be found to be justified and in compliance with
applicable CPUC decisions and the restructuring legislation. On March 31, 1999,
the ORA submitted its report and made the following recommendations adverse to
SCE: (1) $2.37 million in QF shareholder incentive amounts should be disallowed;
(2) $3.2 million in employee-related transition costs should be disallowed; and
(3) $9.67 million in post-retirement benefits other than pensions (PBOPs) and
$5.76 million in long-term disability regulatory assets should be rejected. On
June 14, 1999, the ALJ granted SCE's motion to strike the ORA's testimony and
recommendations on the third item. Prior to hearings, the ORA and SCE
recommended that the CPUC adopt a stipulation and joint recommendation
17
whereby SCE would not recover $895,000 in retention bonuses, and $1.19 million
of the total QF shareholder incentive amounts. On October 8, 1999, the matter
was submitted to the CPUC.
On January 6, 2000, an ALJ issued a proposed decision adopting the stipulation
and joint recommendation as specified above. In addition, the proposed decision
provided clarification on the following four accounting issues impacting the
operation of the TCBA: (1) It directs SCE and the other utilities to review
their estimates of market value for each divested generating plant and
recalculate the interest accrued on undercollections of the TCBA during the
record period. SCE believes it used the market value accounting directed by the
proposed decision; (2) It clarifies the accounting methodology used to estimate
the market value of retained generating assets. At this time, SCE believes there
will be no negative impact on earnings associated with this issue; (3) It
directs SCE to apply the TCBA overcollection of $350.7 million as of June 30,
1998, to further accelerate the depreciation of those transition cost assets
with the highest rate of return, and in a manner that provides the greater tax
benefits (i.e., to accelerate the recovery of nuclear sunk costs). It also
directs SCE to net a $238 million undercollection in the ISO/PX implementation
delay memorandum account against the TCBA overcollection in the calculation. SCE
estimates a $10 million impact over the entire transition period ending December
31, 2001, if this accounting change is adopted by the CPUC; and (4) It disallows
the recovery through the TCBA for the record period of certain
telecommunications, training, mechanical service shop and warehouse equipment
that were related to SCE's divested generating plants but was not purchased by
the new owners. The net book value of these retained assets is in the $8 million
to $10 million range. Comments to the proposed decision were filed in January
and a supplemental brief was filed on February 1, 2000.
On February 17, 2000, the ALJ prepared a revised proposed decision that
addressed these four matters and left intact other provisions of the proposed
decision. The revised proposed decision was approved by the CPUC on the same
day. The decision found that SCE's calculation of the TCBA for the record period
was correct and that SCE appropriately applied the overcollection as of June 30,
1998, to the subsequent undercollection. Therefore, the decision does not
require SCE to accelerate recovery of its nuclear assets. The decision changes
the accounting methodology used to estimate the market value of retained
generating assets and requires that SCE credit the TCBA for the aggregate net
book value of SCE's non-nuclear assets, including the land surrounding such
assets. SCE's shares of the Mohave Station and Four Corners Generating Station
(Four Corners) are excluded from this requirement. Ongoing depreciation, taxes,
and return will be recovered through market revenue. The decision disallows the
recovery through the TCBA for the record period of the retained assets but does
not preclude SCE from seeking recovery in future record periods. The
disallowance for the 1998 record period was $55,000.
On February 29, 2000, SCE made a request to the CPUC's Executive Director for an
extension of time to file the compliance advice letter so that the CPUC could
review SCE's soon-to-be filed petition for a stay of the decision, application
for rehearing and/or petition for modification of the decision. In a letter
dated March 3, 2000, the Executive Director granted SCE an extension of time
until May 31, 2000, to file its advice letter compliance filing.
Once SCE had the opportunity to fully review the decision adopted by the CPUC,
it discovered that the revisions by the CPUC in response to the parties'
comments had inadvertently omitted establishing a new account to record the
corresponding debit to the TCBA credit for the aggregate net book value of any
remaining non-nuclear generation assets. SCE immediately informed the Assigned
Commissioner of the omission, and the Assigned Commissioner issued on March 2,
2000, an Assigned Commissioner's Ruling (ACR) proposing the CPUC establish a
generation asset memorandum account to record this debit. If no debit account
was established by the CPUC, any offsetting debit would be considered as a $300
million charge to earnings on an after tax basis.
In its comments to the ACR, SCE proposed that this account be established as a
balancing account, the Generation Asset Balancing Account, or GABA, in order to
avoid problems associated with limits for short-term borrowing purposes. The
CPUC agreed, and on June 8, 2000, established the GABA. SCE filed its
18
compliance advice letter in June 2000. On April 13, 2000, SCE filed a petition
for modification seeking modification of the decision to restore recovery of
authorized return, taxes, and depreciation for its hydro assets through the
TCBA. It is not known when the CPUC will act on SCE's petition for modification.
On November 9, 2000, SCE filed a petition for modification of D.00-02-048
requesting the CPUC to allow SCE to credit its TCBA (and debit its GABA) with
the aggregate net above-book gain reflected in the pending sales of SCE's
interest in Mohave, Four Corners and Palo Verde generating plants. Crediting
these amounts to the TCBA would allow SCE to accelerate the end of its rate
freeze as requested in SCE's Rate Stabilization Application, A.00-11-038 (as
revised on December 20, 2000).
1999 ATCP
On September 1, 1999, SCE filed its 1999 ATCP setting forth entries made to the
TCBA and other generation-related accounts for the months of July 1998 through
June 1999. On February 23, 2000, the ORA issued its report and made the
following disallowance recommendations adverse to SCE: (1) approximately $5.5
million in post-record period adjustments booked after the date of divestiture
for capital additions made in 1996 to divested fossil generating plants that was
transferred to the TCBA; (2) $17.2 million related to the termination contract
with the Sacramento Municipal Utility District (SMUD); (3) $252,000 in
employee-related transition costs; and (4) a $136,000 adjustment to the QF
subaccount of the TCBA. SCE served its rebuttal testimony on March 29, 2000, and
supplemental testimony on April 3, 2000. Prior to hearings, ORA and SCE executed
a Settlement Agreement that resolved all issues associated with SCE's filing.
The parties agreed that (1) SCE made the $5.5 million adjustment and a $136,000
adjustment to the TCBA as referred to above; (2) ORA no longer contests the
reasonableness of SCE's termination contracts with SMUD; and (3) $192,000 in
employee-related transition costs are to be disallowed. In the settlement, the
parties agree that the Union Worker Protection Benefit (WPB) Agreements were
reviewed for reasonableness by ORA in this proceeding and that the programs and
benefits in each of the WPB Agreements are reasonable and qualify for recovery
as transition costs through the TCBA. On October 19, 2000, the CPUC issued its
decision that approved the Settlement Agreement, closing this proceeding.
2000 ATCP
On September 1, 2000, SCE filed its 2000 ATCP setting forth entries made to the
TCBA and other generation-related accounts for the months of July 1999 through
June 2000. ORA issued its report on February 27, 2001. In its report, ORA
recommended, among other things, that the Commission: (1) defer review of SCE's
natural gas procurement and management activities, including a $10 million post
record period adjustment, until the 2001 ATCP; (2) disallow $882,000 of
employee-related transition costs; and (3) adjust the TCBA undercollection
downward $4.35 million to reflect the reasonableness of post record period
adjustments. On March 15, 2001, in response to SCE's First Set of Data Requests
based on ORA's Report, ORA withdrew its recommendation to defer its review of
SCE's natural gas procurement and management activities, including a $10,000,000
gas options post-record period adjustment, until the 2001 ATCP. ORA found the
$10,000,000 post-period adjustment to be reasonable as well as SCE's natural gas
procurement and management activities during the record period with respect to
the El Paso contract. Since ORA no longer objects to the $10,000,000 gas options
post-record period adjustment, ORA no longer recommends that the TCBA needs to
be further adjusted and now agrees with SCE's June 30, 2000, TCBA balance. The
only contested issue that remains is the $882,000 in employee-related transition
costs. SCE's rebuttal testimony was mailed on March 27, 2001, and hearings are
scheduled for May 21 through May 25, 2001.
Annual Energy Cost Adjustment Clause (ECAC) Proceedings
Through 1998, SCE filed ECAC applications each year with the CPUC regarding its
fuel and purchased power expenses, seeking the CPUC's determination that SCE's
fuel and purchased power costs, including payments to QFs, were reasonable. The
last ECAC application filed in 1998 was closed in 1999. The
19
ECAC reasonableness revision of certain costs, including QF payments, is now
reviewed in the ATCP proceedings discussed above.
Palo Verde Nuclear Generating Station
In January 1997, the CPUC authorized a further acceleration of the recovery of
SCE's remaining investment of $1.2 billion in Palo Verde Units 1, 2, and 3. The
accelerated recovery will continue through December 2001, earning a 7.35% fixed
rate of return. The future operating costs, including nuclear fuel and nuclear
fuel financing costs, and incremental capital expenditures, are subject to
balancing account treatment through 2001. Beginning January 1, 1998, the
balancing account became part of the TCBA mechanism. The existing NUIP will
continue only for purposes of calculating a reward for performance of any unit
above an 80% capacity factor for a fuel cycle. These rate-making plans and the
TCBA mechanism will continue for rate-making purposes through the end of the
rate freeze period. However, due to the various unresolved regulatory and
legislative issues (see discussion in the Significant Developments in California
Electric Utility Restructuring above), SCE is not able to conclude that the
unamortized nuclear investment regulatory assets are probable of recovery
through the rate-making process. As a result, these balances were written off as
a charge to earnings as of December 31, 2000. Beginning in 2002, SCE will be
required to share the net benefits received from the operation of Palo Verde
equally with ratepayers. 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 amount that has been
charged against earnings, a regulatory asset would be correspondingly reinstated
with a corresponding increase in earnings. In addition, if the MOU is
implemented, the requirement that SCE share the net benefits received from the
post-2001 operation of Palo Verde equally with ratepayers will be eliminated.
San Onofre Nuclear Generating Station Units 2 and 3
In April 1996, the CPUC authorized a further acceleration of the recovery of
SCE's remaining investment of $2.6 billion in San Onofre Units 2 and 3. The
accelerated recovery will continue through December 2001, earning a 7.35% fixed
rate of return. San Onofre's operating costs, including nuclear fuel, nuclear
fuel financing costs, and incremental capital expenditures, are recovered
through an incentive pricing plan which allows SCE to receive about 4(cent) per
kWh through December 31, 2003. Beginning January 1, 1998, the accelerated plant
recovery and incremental cost incentive pricing became part of the TCBA
mechanism. These rate-making plans and the TCBA mechanism will continue for
rate-making purposes through the end of the rate freeze period. However, due to
the various unresolved regulatory and legislative issues (as discussed in
Significant Developments in California Electric Utility Restructuring), SCE is
not able to conclude that the unamortized nuclear investment regulatory assets
are probable of recovery through the rate-making process. As a result, these
balances were written off as a charge to earnings as of December 31, 2000. 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 amount that has been charged against
earnings, a regulatory asset would be correspondingly reinstated with a
corresponding increase in earnings. Beginning in 2004, SCE will be required to
share the benefits received from operation of San Onofre Units 2 and 3 equally
with ratepayers. In addition, if the MOU is implemented, the sharing of net
benefits received from the post-2003 operation of San Onofre Units 2 and 3
equally between shareholders and ratepayers would be eliminated, but these units
would continue to be subject to cost-based ratemaking through December 31, 2010.
New Accounting Rules
An accounting rule, which requires that costs related to start-up activities be
expensed as incurred, became effective January 1, 1999. This new accounting rule
did not materially affect SCE's results of operations or its financial position.
20
On January 1, 2001, SCE adopted a new accounting standard for derivative
instruments and hedging activities. The new standard requires all derivatives be
recognized on the balance sheet at fair value. Gains or losses from changes in
fair value would be recognized in earnings in the period of change unless the
derivative is designated as a hedging instrument. Gains or losses from hedges of
a forecasted transaction or foreign currency exposure would be recorded as a
separate component of shareholders' equity under the caption Accumulated Other
Comprehensive Income. Gains or losses from hedges of a recognized asset or
liability or a firm commitment would be reflected in earnings for the
ineffective portion of the hedge. SCE's derivatives qualify for hedge accounting
under the new standard. On the implementation date, SCE recorded its interest
rate swap agreement (terminated January 5, 2001), and its block forward power
purchase contracts (seized by the State of California on February 2, 2001) at
fair value on its balance sheet. SCE does not anticipate any earnings impact
from its derivatives, since it expects that any market price changes will be
recovered in rates.
Fuel Supply and Purchased Power Costs
Since April 1, 1998, SCE had been required to sell all of its generated and
purchased power through the PX and ISO, schedule delivery of the power through
the ISO, and acquire all of its power from the PX and ISO to distribute to its
retail customers. These PX and ISO transactions were reported net. As of
December 15, 2000, the FERC eliminated this buying and selling requirement. On
January 30, 2001, the PX suspended its day-ahead and day-of energy trading, and
it subsequently ceased operations and filed for bankruptcy. Furthermore,
beginning in January 2001, the CDWR began purchasing power for SCE's customers.
The MOU contemplates that the CDWR will assume the entire responsibility for
procuring the electricity needs of SCE's customers through December 31, 2002, to
the extent not met by SCE's retained generation and power contracts.
In 2000, PX/ISO purchased-power expense increased significantly due to
electricity shortages and dramatic price increases for natural gas, a key input
of electricity production. The increased volume of higher priced PX purchases
was minimally offset by increases in PX sales revenue and ISO net revenue, as
well as an increase in the market value of gas call options. Increases in the
options' market value decreased purchased-power expense. These gas call options
(which were sold in October 2000) mitigated SCE's transition cost recovery
exposure to increases in energy prices.
SCE's sources of energy during 2000 were as follows: 58.6% purchased power;
22.3% nuclear; 13.7% coal; and 5.4% hydro.
Natural Gas Supply
As a result of the sale of all of its gas-fired generating stations, SCE has
terminated four long-term natural gas supply and three long-term gas
transportation contracts which had been used to import gas from Canada. In
addition, SCE has exercised an option under its 15-year gas transportation
commitment with El Paso Natural Gas Company to reduce its capacity obligation
from 200 million to 130 million cubic feet per day. SCE permanently assigned its
contract with El Paso in November 2000 paying $12.3 million in consideration to
the assignee.
Nuclear Fuel Supply
SCE has contractual arrangements covering 100% of the projected nuclear fuel
requirements for San Onofre through the years indicated below:
Uranium concentrates(*)........................................ 2003
Conversion................................................ 2003
Enrichment................................................ 2003
Fabrication............................................... 2005
---------------
(*) Assumes the San Onofre participants meet their supply obligations in a
timely manner.
21
Assuming normal operation and full utilization of existing on-site storage
capacity, San Onofre Units 2 and 3 will maintain full-core offload reserve
through 2005. The Nuclear Waste Policy Act of 1982 requires that the United
States Department of Energy provide for the disposal of utility spent nuclear
fuel beginning January 31, 1998. The Department of Energy has defaulted on its
obligation to begin acceptance of spent nuclear fuel from the commercial nuclear
industry by that date. Additional spent fuel storage either on-site or at
another location will be required to permit continued operations beyond 2005.
Participants at Palo Verde have contractual agreements for uranium concentrates
to meet projected requirements through 2002. Independent of arrangements made by
other participants, SCE will furnish its share of uranium concentrates
requirement through at least 2001 from existing contracts. Contracts covering
100% of requirements are in place for enrichment through 2003 and fabrication
through 2015. Contracts covering 75% of conversion requirements in 2001 are in
place with negotiations on-going for the remainder.
Palo Verde has existing fuel storage pools and is in the process of completing
construction of a new facility for on-site dry storage of spent fuel. With the
existing storage pools and the addition of the new facility, spent fuel storage
or disposal methods will be available for use by Palo Verde to allow its
continued operation through the term of the plant license.
Environmental Matters
Legislative and regulatory activities in the areas of air and water pollution,
waste management, hazardous chemical use, noise abatement, land use, aesthetics,
and nuclear control continue to result in the imposition of numerous
restrictions on SCE's operation of existing facilities, on the timing, cost,
location, design, construction, and operation by SCE of new facilities, and on
the cost of mitigating the effect of past operations on the environment. These
activities substantially affect future planning and will continue to require
modifications of SCE's existing facilities and operating procedures. SCE is
unable to predict the extent to which additional regulations may affect its
operations and capital expenditure requirements.
In California, pursuant to federal, state and regional Clean Air Act programs,
SCE generating stations were required to reduce emissions of oxides of nitrogen
and certain other pollutants. During 1998, SCE sold all of its oil- and
gas-fueled generating stations within the Mohave Desert Air Quality Management
District, Ventura County Air Pollution Control District, and in the Santa
Barbara County Air Pollution Control District. SCE has sold all but one of its
oil- and gas-fired generating stations within the South Coast Air Quality
Management District. The remaining plant, the small diesel-fired Pebbly Beach
Generating Station, supplies power to Santa Catalina Island.
SCE also owns a 56% undivided interest in the Mohave Generating Station (Mohave
Station) located in Laughlin, Nevada, which is subject to certain air quality
programs. In 1998, several environmental groups filed suit against the co-owners
of the Mohave Station regarding alleged violations of emissions limits. In order
to accelerate resolution of key environmental issues regarding the plant, the
parties filed, in concurrence with SCE and the other station owners, a consent
decree, which was approved by the Court in December 1999. The decree was
designed also to address concerns raised by two EPA programs regarding
visibility and regional haze. The EPA issued its final rulemaking regarding
regional haze regulations on July 1, 1999. The final rule is not expected to
impose any additional emissions control requirements on the Mohave Station
beyond meeting the provisions of the consent decree. The EPA and SCE also
participated in a study to determine the specific impact of air contaminant
emissions from the Mohave Station on visibility in Grand Canyon National Park.
The final report on this study, which was issued in March 1999, found negligible
correlation between measured Mohave Station tracer concentrations and visibility
impairment. The absence of any obvious relationship cannot rule out Mohave
Station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze. Finally, in
June, 1999, the EPA issued an advanced notice of proposed rulemaking regarding
assessment of visibility impairment at the Grand Canyon. SCE filed
22
comments on the proposed rulemaking in November 1999. In July 2000, EPA
published a proposed rule and on August 21, 2000, SCE provided comments to the
proposed rule. In a letter to SCE, the EPA has expressed its belief that the
controls provided in the consent decree will likely resolve the potential Clean
Air Act visibility concerns. The Agency is considering incorporating the decree
into the visibility provisions of its Federal Implementation Plan for Nevada.
The Clean Air Act also requires the EPA to carry out a three-year study of risk
to public health from the emissions of toxic air contaminants from electric
utility steam generating plants, and to regulate such emissions if the
Administrator makes certain findings. The study's final report to Congress
concluded that mercury from coal-fired utilities is the hazardous air pollutant
of greatest potential concern and merits additional research and monitoring to
better understand the risks of mercury exposure. Other pollutants that may
potentially need further study are dioxins and arsenic from coal-fired plants,
and nickel from oil-fired plants. The EPA concluded that the impacts from
emissions from gas-fired utilities are negligible and that there is no need for
further evaluation of the risks of hazardous air pollutants emitted from such
plants.
On November 3, 1999, the United States Department of Justice filed suit against
a number of electric utilities for alleged violations of the Clean Air Act's
"new source review" requirements related to modifications of air emissions
sources at electric generating stations located in the southern and midwestern
regions of the United States. Several states have joined these lawsuits. In
addition, the EPA has also issued administrative notices of violation alleging
similar violations at additional power plants owned by some of the same
utilities named as defendants in the Department of Justice lawsuit, as well as
other utilities, and also issued an administrative order to the Tennessee Valley
Authority for similar violations at certain of its power plants. The EPA has
also issued requests for information pursuant to the Clean Air Act to numerous
other electric utilities seeking to determine whether these utilities also
engaged in activities that may have been in violation of the Clean Air Act's new
source review requirements.
To date, one utility--the Tampa Electric Company--has reached a formal agreement
with the United States (February 2000) to resolve alleged new source review
violations. Two other utilities, the Virginia Electric Power Co. and Cinergy
Corp., have reached agreements in principle with the EPA (November and December
2000, respectively). In each case, the settling party has agreed to incur over
$1 billion in expenditures over several years for the installation of additional
pollution control, the retirement or repowering of coal-fired generating units,
supplemental environmental projects and civil penalties. These agreements
provide for a phased approach to achieving required emission reductions over the
next 10 to 15 years. The settling utilities have also agreed to pay civil
penalties ranging from $3.5 million to $8.5 million.
On June 27, 2000, the EPA issued a Request For Information (RFI) for the Four
Corners plant. SCE owns a 48% share of Four Corners' Units 4 and 5 and on
September 1, 2000, replied to the RFI. To date, no further action has been taken
with respect to Four Corners.
In December 2000, the EPA announced its intentions to regulate mercury emissions
from coal-fired and oil-fired electric power plants under Section 112 of the
Clean Air Act and indicated that it would propose a rule to regulate these
emissions by no later than December 15, 2003. EPA expects to finalize this rule
by December 15, 2004. Because SCE does not know what the EPA may require with
respect to this issue, SCE is presently unable to evaluate the impact of
potential mercury regulations on the operations of its facilities.
Regulations under the Clean Water Act require permits for the discharge of
certain pollutants into U.S. waters. Under this act, the EPA issues effluent
limitation guidelines, pretreatment standards, and new source performance
standards for the control of certain pollutants. Individual states may impose
more stringent limitations. SCE incurs additional expenses and capital
expenditures in order to comply with guidelines and standards applicable to
steam electric power plants. SCE presently has discharge permits for all
applicable facilities.
23
The Safe Drinking Water and Toxic Enforcement Act prohibits the exposure to
individuals of chemicals known to the State of California to cause cancer or
reproductive harm and the discharge of such listed chemicals into potential
sources of drinking water. Additional chemicals are continuously being put on
the State's list, requiring constant monitoring.
The Resource Conservation and Recovery Act provides the statutory authority for
the EPA to implement a regulatory program for the safe treatment, recycling,
storage, and disposal of solid and hazardous waste. An unresolved issue remains
regarding the degree to which coal waste should be regulated under the act.
Currently, coal waste has been determined to be non-hazardous. Increased
regulation may result in increased expenses relating to the operation of the
Mohave Station.
The Toxic Substances Control Act and accompanying regulations govern the
manufacturing, processing, distribution in commerce, use, and disposal of listed
compounds, such as polychlorinated biphenyls, a toxic substance used in certain
electrical equipment. Current costs for disposal of this substance are
immaterial.
SCE records its environmental liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be
estimated. SCE reviews its sites and measures the liability quarterly, by
assessing a range of reasonably likely costs for each identified site using
currently available information, including existing technology, presently
enacted laws and regulations, experience gained at similar sites, and the
probable level of involvement and financial condition of other potentially
responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring, and site closure. Unless
there is a probable amount, SCE records the lower end of this reasonably likely
range of costs (classified as other long-term liabilities at discounted
amounts).
SCE's recorded estimated minimum liability to remediate its 44 currently
identified sites is $114 million. The ultimate costs to clean up SCE's
identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process, such as: (1) the extent and
nature of contamination; (2) the scarcity of reliable data for identified sites;
(3) the varying costs of alternative cleanup methods; (4) developments resulting
from investigatory studies; (5) the possibility of identifying additional sites;
and (6) the time periods over which site remediation is expected to occur. SCE
believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $272 million. The
upper limit of this range of costs was estimated using assumptions least
favorable to SCE among a range of reasonably possible outcomes. SCE has sold all
of its gas- and oil-fueled generation plants (except the Pebbly Beach Generating
Station) and has retained some liability associated with the divested
properties.
The CPUC allows SCE to recover environmental-cleanup costs at certain sites,
representing $45 million of its recorded liability, through an incentive
mechanism (SCE may seek to include additional sites). Under this mechanism, SCE
will recover 90% of cleanup costs through customer rates; shareholders fund the
remaining 10%, with the opportunity to recover these costs from insurance
carriers and other third parties. SCE has successfully settled insurance claims
with all responsible carriers. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a regulatory
asset of $75 million for its estimated minimum environmental-cleanup costs
expected to be recovered through customer rates. SCE's identified sites include
several sites for which there is a lack of currently available information,
including the nature and magnitude of contamination, and the extent, if any,
that SCE may be held responsible for contributing to any costs incurred for
remediating these sites. Thus, no reasonable estimate of cleanup costs can be
made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years.