ML021200026

Annual Certified Financial Statement

ML021200026
Person / Time
Site:	Palo Verde, San Onofre
Issue date:	04/25/2002
From:	Scherer A Southern California Edison Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML021200026 (103)

Text

I SOUTHERN CALIFORNIA A Edward Scherer Manager of Nuclear EDISON Oversight and Regulatory Affairs An EDISON INTERNATIONAL* Company April 25, 2002 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D. C. 20555 Gentlemen:

Subject:

Docket Nos. 50-361, 50-362, 50-528, 50-529, and 50-530 Annual Certified Financial Statement San Onofre Nuclear Generating Station Units 2 and 3 Palo Verde Nuclear Generating Station Units 1, 2, and 3 Southern California Edison (SCE), as agent for the owners of the San Onofre Nuclear Generating Station Units 2 and 3 and SCE's 15.8% ownership share of Palo Verde Units 1, 2, and 3, submits the following documents in accordance with 10 CFR 140.21(e):

0 2002 Cash Reserve statement which is derived from the Annual Report to the Securities and Exchange Commission (Form 10K) for the fiscal year ending December 31, 2001

• SCE's Annual Report to Shareholders for the fiscal year ending December 31, 2001

• SCE's Annual Report to the Securities and Exchange Commission (Form 10K) for the fiscal year ending December 31, 2001 If you have any questions or require further information about these documents, please contact me or Mr. Jack Rainsberry (949/368-7420).

Sincerely, Enclosures cc:

E. W. Merschoff, Regional Administrator, NRC Region IV A. B. Wang, NRC Project Manager, San Onofre Units 2, and 3 C. C. Osterholtz, NRC Senior Resident Inspector, San Onofre Units 2 & 3 P. 0. Box 128 San Clemente, CA 92674-0128 o04 949-368-7501 Fax 949-368-6085

SOUTHERN CALIFORNIA EDISON COMPANY 2002 Cash Reserve (Dollars in Thousands)

Cash Reserve as of December 31, 2001

$3,414,000 Percentage Ownership in All Nuclear Units:

San Onofre Nuclear Generating Station Units 2 & 3 o Southern California Edison Company 75.05%

o San Diego Gas & Electric Company 20.00%

o City of Anaheim 3.16%

o City of Riverside 1.79%

Palo Verde Nuclear Generating Station Units 1, 2 & 3 15.80%

Maximum Total Contingent Liability:

San Onofre Nuclear Generating Station Unit 2

$10,000 San Onofre Nuclear Generating Station Unit 3

$10,000 Palo Verde Nuclear Generating Station Unit 1

$1,580 Palo Verde Nuclear Generating Station Unit 2

$1,580 Palo Verde Nuclear Generating Station Unit 3 Total

$24,740

F SOUTHERN CALIFORNIA EDISON An EDISON INTERNATIONAL Company 2001 Annual Report

1I Southern California Edison Company Southern California Edison Company (SCE) is one of the nation's largest investor-owned electric utilities.

Headquartered in Rosemead, California, SCE is a subsidiary of Edison International.

SCE, a 116-year-old electric utility, serves a 5 0,000-square-mile area of central, coastal and southern California.

Contents 1

Selected Financial and Operating Data: 1997 - 2001 2

Management's Discussion and Analysis of Results of Operations and Financial Condition 21 Consolidated Financial Statements 26 Notes to Consolidated Financial Statements 49 Quarterly Financial Data 50 Responsibility for Financial Reporting 51 Report of Independent Public Accountants 52 Board of Directors 52 Management Team

Califnrnia EIdison Companv Selected Financial and Operating Data: 1997 - 2uu1 uoiiars in minios oI I

2000 1999 Income statement data:

Operating revenue

$ 8,126 Operating expenses 3,509 Fuel and purchased power expenses 3,982 Income tax (benefit) 1,658 Provisions for regulatory adjustment clauses - net (3,028)

Interest expense - net of amounts capitalized 785 Net income (loss) 2,408 Net income (loss) available for common stock 2,386 Ratio of earnings to fixed charges 6.15 Balance sheet data:

Assets Gross utility plant Accumulated provision for depreciation and decommissioning Short-term debt Common shareholder's equity Preferred stock:

Not subject to mandatory redemption Subject to mandatory redemption Long-term debt Capital structure:

Common shareholder's equity Preferred stock:

Not subject to mandatory redemption Subject to mandatory redemption Long-term debt

$ 22,453

$ 15,966 15,982 15,653 7,969 2,127 3,146 129 151 4,739 7,834 1,451 780 129 256 5,631

$17,657 14,852 7,520 796 3,133 129 256 5,137

$16,947

$18,059 14,150 21,483 6,896 470 3,335 129 256 5,447 38.5%

11.5%

36.2%

36.4%

1.6%/6 1.9%

1.5%

1.4%

1.9%

3.8%

2.9%

2.8%

58.0%

82.8%

59.4%/o 59.4%

10,544 322 3,958 184 275 6,145 37.5%

1.7%

2.6%

58.2%

Operating data:

Peak demand in megawatts (MW)

Generation capacity at peak (MW)

Kilowatt-hour deliveries (in millions)

Total energy requirement (kWh) (in millions)

Energy mix:

Thermal Hydro Purchased power and other sources Customers (in millions)

Full-time employees 9nnfl 2000 1999

$ 7,548 6,242 3,405 438 (763) 483 509 484 2.94

$7,870 10,529 4,882 (1,022) 2,301 572 (2,028)

(2,050)

(4.28) 1998

$ 7,500 6,136 3,586 442 (473) 485 515 490 2.95 1997

$ 7,953 6,311 3,735 520 (411) 444 606 576 3.49 17,890 9,802 78,524 83,496 32.5%

3.6%

63.9%

4.47 11,663 19,757 9,886 84,430 82,503 36.0%

5.4%

58.6%

4.42 12,593 19,122 10,431 78,602 78,752 35.5%

5.6%

58.9%

4.36 13,040 19,935 10,546 76,595 80,289 38.8%

7.4%

53.8%

4.27 13,177 19,118 21,511 77,234 86,849 44.6%

6.5%

48.9%

4.25 12,642 1

I'*--ll--=--

• ,=

lI;^*^

II Management's Discussion and Analysis of Results of Operations and Financial Condition The following discussion contains forward-looking statements. These statements are based on Southern California Edison's (SCE) current expectations about future events, based on knowledge of present facts and assumptions about future developments. These forward-looking statements are subject to risks and uncertainties that could cause actual future activities and results of operations to be materially different from those set forth in this discussion. Important factors that could cause actual results to differ include risks discussed in the Market Risk Exposures and Forward-Looking Statements sections.

Until early 2002, SCE faced a crisis resulting from deregulation of the generation side of the electric utility industry through legislation enacted by the California Legislature and decisions issued by the California Public Utilities Commission (CPUC). 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 except for the 10%

residential rate reduction starting in 1998 and the 4C-per-kWh surcharge effective in 2001. See further discussion of the CPUC rate increases in Rate Stabilization Proceedings. Beginning in May 2000, SCE's costs to obtain power (at wholesale electricity prices) for resale to its customers substantially exceeded revenue from frozen rates. The shortfall was accumulated in the transition revenue account (TRA), a CPUC-authorized regulatory asset. As a result of a March 27, 2001, CPUC decision, the TRA balance was transferred retroactively to the transition cost balancing account (TCBA). The TCBA was a regulatory balancing account that tracked the recovery of generation-related transition costs, including stranded investments. SCE has borrowed significant amounts of money to finance its electricity purchases. Uncertainty regarding SCE's ability to recover funds spent to purchase power created a severe liquidity crisis at SCE. However, based on the settlement agreement with the CPUC (discussed below) permitting full recovery of past power procurement costs, SCE was able to arrange new financing and together with cash on hand, was able to repay its undisputed past-due obligations in March 2002.

In October 2001, a federal district court in California entered a stipulated judgment approving an agreement between the CPUC and SCE to settle a lawsuit. On January 23, 2002, the CPUC adopted a resolution approving the establishment of the procurement-related obligations account (PROACT). See discussion below. SCE believes that the settlement agreement will enable SCE to recover its previously undercollected power procurement costs. In compliance with the terms of the settlement agreement and the CPUC resolution, in the fourth quarter of 2001, SCE established a $3.6 billion regulatory asset for these previously incurred procurement costs, called the PROACT. A corresponding credit to earnings was recorded, in connection with this regulatory asset, in the amount of $3.6 billion ($2.1 billion after tax).

On September 1, 2001, SCE began applying to the PROACT the difference between SCE's revenue from retail electric rates and the costs that SCE is authorized by the CPUC to recover in retail electric rates.

The settlement also calls for the end of the TCBA mechanism as of August 31, 2001, and continuation of the rate freeze until the earlier of December 31, 2003, or the date that SCE recovers the PROACT balance. If SCE has not recovered the entire PROACT balance by the end of 2003, the remaining balance will be amortized in retail rates for up to an additional two years. For further details on the settlement with the CPUC and the CPUC resolution, see CPUC Litigation Settlement Agreement and PROACT Regulatory Asset discussions.

Accounting principles generally accepted in the United States permit SCE to defer costs and record regulatory assets if those costs are determined to be probable of recovery in future rates. SCE assessed the probability of recovery of the undercollected costs that were previously recorded in the TCBA in light of the CPUC's March 27, 2001, and April 3, 2001, decisions, including the retroactive transfer of balances from SCE's TRA to its TCBA and related changes that are discussed in more detail in Rate Stabilization Proceedings. These decisions and other regulatory and legislative actions did not meet SCE's prior expectation that the CPUC would provide adequate cost recovery mechanisms. As a result, SCE's financial results for the year ended December 31, 2000, included an after-tax charge of approximately

$2.5 billion ($4.2 billion pre-tax), reflecting a write-off of the TCBA and net regulatory assets to be recovered through the TCBA mechanism, as of December 31, 2000. Transition costs in excess of transition revenue were also incurred during 2001, resulting in additional net charges against earnings of

$328 million ($552 million pre-tax) through August 31, 2001 (the effective date of the PROACT mechanism).

2

Southern California Edison Company The following pages include a discussion of the history of the TRA and TCBA and related circumstances, the significantly negative effect on the financial condition of SCE of undercollections recorded in the TRA and TCBA, the current status of the undercollections, the impact of the CPUC's March 27, 2001, decisions and related matters, and the implementation of the CPUC settlement agreement and the PROACT mechanism, and SCE's March 2002 financing.

Results of Operations Earnings In 2001, SCE earned $2.4 billion, compared with a loss of $2.1 billion in 2000 and earnings of $484 million in 1999. SCE's 2001 earnings included a $2.1 billion (after tax) benefit resulting from the reestablishment of procurement-related regulatory assets and liabilities as a result of the PROACT resolution and recovery of $178 million (after tax) of previously written off generation-related regulatory assets, partially offset by

$328 million (after tax) of net undercollected transition costs incurred between January and August 2001.

SCE's loss in 2000 included a $2.5 billion (after tax) write-off of regulatory assets and liabilities as of December 31, 2000. SCE's 1999 earnings included a $15 million one-time tax benefit due to an Internal Revenue Service ruling. Excluding the $2.0 billion net benefit in 2001, the $2.5 billion (after tax) write-off in 2000 and the $15 million benefit in 1999, SCE's earnings were $408 million in 2001, $471 million in 2000 and $469 million in 1999. The $63 million decrease in 2001 was primarily due to the February 2001 fire and resulting outage at San Onofre Nuclear Generation Station Unit 3 and lower kilowatt-hour sales.

In 2000, superior operating performance at San Onofre and higher kilowatt-hour sales were almost completely offset by adjustments to reflect potential regulatory refunds and lower gains from sales of equity investments.

Accounting principles generally accepted in the United States require SCE at each financial statement date to assess the probability of recovering its regulatory assets through a regulatory process. Based on the rules arising from the CPUC's March 27, 2001, rate stabilization decision, the $4.5 billion TRA undercollection as of December 31, 2000, and the coal and hydroelectric balancing account overcollections were reclassified, and the TCBA balance was recalculated to be a $2.9 billion undercollection (see further discussion of the CPUC rate increase in the Rate Stabilization Proceeding section and the components of the TCBA undercollection in the Status of Transition and Power Procurement Cost Recovery section of Regulatory Environment). As a result, SCE was unable to conclude that, under applicable accounting principles, the $2.9 billion TCBA undercollection (as recalculated above) and $1.3 billion (book value) of other net regulatory assets that were to be recovered through the TCBA mechanism by the end of the rate freeze, were probable of recovery through the rate making process as of December 31, 2000. As a result, SCE's December 31, 2000, income statement included a $4.0 billion charge to provisions for regulatory adjustment clauses and a $1.5 billion net reduction in income tax expense, to reflect the $2.5 billion (after tax) write-off.

Based on the rules arising from the CPUC's January 23, 2002, PROACT resolution, SCE was able to conclude that $3.6 billion in regulatory assets previously written off were probable of recovery through the rate-making process as of December 31, 2001. As a result, SCE's December 31, 2001, consolidated income statement included a $3.6 billion credit to provisions for regulatory adjustment clauses and a

$1.5 billion charge to income tax expense, to reflect the $2.1 billion (after tax) credit to earnings.

Operating Revenue From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an energy service provider (thus becoming direct access customers) or continue to have SCE purchase power on their behalf. Most direct access customers continued to be billed by SCE, but were given a credit for the generation purchased from the energy service provider. Operating revenue is reported net of this credit. On September 20, 2001, the CPUC suspended the ability of retail customers to select alternative providers of electricity until the California Department of Water Resources (CDWR) stops buying power for retail customers, pending further review by the CPUC. On March 21, 2002, the 3

Management's Discussion and Analysis of Results of Operations and Financial Condition CPUC issued a final decision affirming September 20, 2001, as the date when direct access was suspended in the state.

During 2000, as a result of the power shortage in California, SCE's customers on interruptible rate programs (which provide for lower generation rates with a provision that service can be interrupted if needed, with penalties for noncompliance) were asked to curtail their electricity usage at various times.

As a result of noncompliance with SCE's requests, those customers were assessed significant penalties.

On January 26, 2001, the CPUC waived the penalties assessed to noncompliant customers after October 1, 2000, until the interruptible programs can be reevaluated.

Operating revenue increased in 2001 (as shown in the table below), primarily due to the effects of the reduced credits given to direct access customers in 2001 and the 40-per-kWh (10 in January and 30 in June) surcharge effective in 2001. The increases were partially offset by: a decrease in retail sales volume primarily attributable to conservation efforts; a decrease in revenue related to penalties customers incurred for not complying with their interruptible contracts; a decrease in revenue related to operation and maintenance services; and a decrease in revenue related to electric power provided to SCE customers by the CDWR or Independent System Operator (ISO). Amounts SCE bills to and collects from its customers for electric power purchased and sold by the CDWR or through the ISO on behalf of SCE's customers (beginning January 17, 2001) are being remitted to the CDWR and are not recognized as revenue by SCE. In 2001, this amount was $2.0 billion. See CDWR Power Purchases discussion.

Operating revenue increased in 2000 (as shown in the table below), primarily due to: warmer weather in the second and third quarters of 2000 as compared to the same periods in 1999; increased resale sales; and an increase in revenue related to penalties customers incurred for not complying with their interruptible contracts.

The changes in operating revenue resulted from:

In millions Year ended December 31, 2001 2000 1999 Operating revenue Rate changes (including refunds)

$ 422

$ 120

$ (75)

Direct access credit 566 (434)

(213)

Interruptible noncompliance penalty (117) 102 6

Sales volume changes (544) 520 195 Other (71) 14 136 Total

$ 256

$ 322

$ 49 More than 94% of operating revenue was from retail sales. Retail rates are regulated by the CPUC and wholesale rates are regulated by the Federal Energy Regulatory Commission (FERC).

Due to warmer weather during the summer months, operating revenue during the third quarter of each year is significantly higher than other quarters.

Operating Expenses Fuel expense increased in 2001 and decreased in 2000. The increase in 2001 and the decrease in 2000 were both due to fuel-related refunds resulting from a settlement with another utility that SCE recorded in the second and third quarters of 2000.

Purchased-power expense decreased in 2001 and increased in 2000. The 2001 decrease resulted from the absence of California Power Exchange (PX)/ISO purchased-power expense after mid-January 2001, partially offset by increased expenses related to qualifying facilities (QFs), bilateral contracts and interutility contracts.

See Purchased Power table in Note 1 to the Consolidated Financial Statements and discussion in CDWR Power Purchases. PX/ISO purchased-power expense increased significantly between May 2000 and mid 4

1I

Southern California Edison Company January 2001, due to a number of factors, including increased demand for electricity in California, dramatic price increases for natural gas (a key input of electricity production), and problems in the structure and conduct of the PX and ISO markets. In December 2000, the FERC eliminated the requirement that SCE buy and sell all power through the PX and ISO. Due to SCE's noncompliance with the PX's tariff requirement for posting collateral for all transactions in the day-ahead and day-of markets as a result of the downgrade in its credit rating, the PX suspended SCE's market trading privileges effective mid January 2001.

Prior to April 1998, federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated prices even though energy and capacity prices under many of these contracts are generally higher than other sources. These contracts expire on various dates through 2025.

See further discussion regarding new OF agreements in Litigation. Purchased-power expense related to QFs increased due to the short-run avoided cost factor (which is based on the price of natural gas) of the QF contracts causing a significant increase in the payments to QFs. In early 2001, structural problems in the market caused abnormally high gas prices. The increase related to bilateral contracts was the result of SCE not having these contracts in 2000. The increase related to interutility contracts was volume driven.

SCE has contracts with certain QFs in which Edison Mission Energy (a wholly owned subsidiary of Edison International) has 49% - 50% interests. The terms and pricing of these contracts are approved by the CPUC. SCE's power purchases from these facilities were $983 million in 2001, $716 million in 2000 and

$513 million in 1999.

Provisions for regulatory adjustment clauses decreased for 2001 and increased for 2000. The 2001 decrease resulted from SCE recording the $3.6 billion PROACT regulatory asset in fourth quarter 2001. The increase in 2000 was mainly due to SCE's write-off as of December 31, 2000, of $4.2 billion in regulatory assets and liabilities as a result of the California energy crisis. Adjustments to reflect potential regulatory refunds related to the outcome of the CPUC's reevaluation of the operation of the interruptible rate programs also contributed to the increase in 2000.

Other operation and maintenance expense decreased in 2000. The decrease was primarily due to a $120 million decrease in mandated transmission service (known as reliability must-run services) expense and a

$19 million decrease in operating expenses at San Onofre. The decrease at San Onofre in 2000 was primarily due to scheduled refueling outages for both units in the first half of 1999. San Onofre had only one refueling outage in 2000.

Depreciation, decommissioning and amortization expense decreased in 2001, mainly due to SCE's nuclear investment amortization expense ceasing since the unamortized nuclear investment regulatory asset was included in the December 31, 2000, write-off.

Net gain on sale of utility plant in 2000 resulted from the sale of additional property related to four of the generating stations SCE sold in 1998. The gains were returned to the ratepayers through the TCBA mechanism.

Other Income and Deductions Interest and dividend income increased in both 2001 and 2000. The increase in 2001 was mainly due to an overall higher cash balance, as SCE conserved cash due to its liquidity crisis. The increase in 2000 was mostly due to increases in interest earned on higher balancing account undercollections.

Other nonoperating income decreased in both 2001 and 2000. The decrease in 2001 primarily reflects the gains on sales of marketable securities in 2000. The decrease in 2000 was primarily due to larger gains on sales of marketable securities in 1999.

Interest expense - net of amounts capitalized increased in both 2001 and 2000. The increase in 2001 reflects additional long-term debt and higher short-term debt balances. The increase in 2000 was mostly 5

Management's Discussion and Analysis of Results of Operations and Financial Condition due to higher overall short-term debt balances necessary to meet general cash requirements (especially PX and ISO payments) and higher interest expense related to balancing account overcollections.

Other nonoperating deductions decreased in 2001 primarily due to lower accruals for regulatory matters in 2001.

Income Taxes Income taxes increased in 2001 and decreased in 2000. The increase in 2001 reflects $1.5 billion in income tax expense related to the PROACT regulatory asset establishment in fourth quarter 2001. The decrease in 2000 was primarily due to the $1.5 billion income tax benefit related to the write-off as of December 31, 2000, of regulatory assets and liabilities in the amount of $2.5 billion (after tax). Absent the impact of the PROACT regulatory asset in 2001 and the write-off in 2000, SCE's income tax expense increased in both 2001 and 2000 due to higher pre-tax income in both years.

Financial Condition SCE's liquidity is affected primarily by regulation affecting its ability to recover the cost of power purchases, debt maturities, access to capital markets, credit ratings, dividend payments and capital expenditures. Capital resources include cash from operations and external financings.

Liquidity Issues Sustained higher wholesale energy prices that began in May 2000 persisted through June 2001. This resulted in undercollections in the TRA and TCBA. Undercollections, coupled with SCE's anticipated near-term capital requirements (detailed in Projected Commitments) and the adverse reaction of the credit markets to continued regulatory uncertainty regarding SCE's ability to recover its current and future power procurement costs, materially and adversely affected SCE's liquidity throughout 2001. As a result of its liquidity concerns, SCE took steps to conserve cash to continue to provide service to its customers. As a part of this process, beginning in January 2001, SCE suspended payments owed to the ISO, the PX and QFs, deferred payments of certain obligations for principal and interest on outstanding debt and did not declare dividends on any of its cumulative preferred stock. As applicable, unpaid obligations continued to accrue interest. As of March 31, 2001, SCE resumed payment of interest on its debt obligations.

However, since June 30, 2001, SCE deferred the interest payments on its quarterly income debt securities (subordinated debentures), as allowed by the terms of the securities. All interest in arrears must be paid at the end of the deferral period. As long as accumulated dividends on SCE's preferred stock remain unpaid, SCE could not pay dividends on its common stock. Common stock dividends are additionally restricted as detailed in the CPUC Litigation Settlement discussion.

Based on the rights to cost recovery and revenue established by the settlement agreement with the CPUC and CPUC implementing orders, including the PROACT resolution, SCE repaid its undisputed past-due obligations on March 1, 2002, with lump-sum payments to creditors from the proceeds of $1.6 billion in senior secured credit facilities, the remarketing of $196 million in pollution-control bonds which were repurchased in late 2000, and existing cash on hand. The $1.6 billion senior secured credit facilities consist of a $300 million, two-year revolving credit loan, a $600 million, one-year loan and a $700 million, three-year loan.

The proceeds from the senior secured credit facilities and pollution-control bond remarketing were used, along with SCE's available cash, to repay $3.2 billion in past-due obligations and $1.65 billion in near-term debt maturities. The past-due obligations consisted of: (1) $875 million to the PX; (2) $99 million to the ISO; (3) $1.1 billion to QFs; (4) $193 million in PX energy credits for energy service providers; (5) $531 million of matured commercial paper; (6) $400 million of principal on its 5-7/8% and 6-1/2% senior unsecured notes which were issued prior to the energy crisis; and (7) $23 million in preferred dividends in arrears. The near-term debt maturities consisted of credit facilities whose maturity dates were extended several times and were scheduled to mature in March and May 2002. In addition, SCE entered into an agreement with the CDWR to pay for prior deliveries of energy in installments of $100 million on April 1, 6

Southern California Edison Company 2002, $150 million on June 3, 2002, and the balance on July 1, 2002. After making the above-described payments, SCE has no material undisputed obligations that are past due or in default.

SCE expects to meet its continuing obligations from remaining cash on hand and future operating cash flows.

For additional discussion on the impact of California's energy crisis on SCE's liquidity, see Cash Flows from Financing Activities. For a discussion on the settlement agreement with the CPUC and the PROACT resolution to resolve SCE's crisis, see CPUC Litigation Settlement Agreement and PROACT Regulatory Asset sections.

Cash Flows from Operating Activities Net cash provided by operating activities was $3.3 billion in 2001, $829 million in 2000 and $1.5 billion in 1999. The increase in 2001 was primarily due to SCE suspending payments for purchased power and other obligations beginning in January 2001. Cash provided by operating activities also reflects the CPUC-approved surcharges (10 per kWh in January and 3o per kWh in June) that were billed in 2001.

The decrease in 2000 was the result of extremely high prices SCE paid for energy and ancillary services procured through the PX and ISO.

Cash Flows from Financing Activities At December 31, 2001, SCE had drawn on its entire credit lines of $1.65 billion. These unsecured lines of credit have various expiration dates and, when available, could be drawn down at negotiated or bank index rates. On March 1, 2002, SCE's credit lines ($1.65 billion) were repaid using proceeds from the March 1, 2002, financing. See additional discussion in Liquidity Issues.

Short-term debt is used to finance balancing account undercollections, fuel inventories and general cash requirements, including purchased-power payments. Long-term debt is used mainly to finance capital expenditures. External financings are influenced by market conditions and other factors. Because of the

$2.5 billion charge to earnings as of December 31, 2000, SCE does not currently meet the interest coverage ratio that is required for SCE to issue additional preferred stock.

As a result of investors' concerns regarding the California energy crisis and its impact on SCE's liquidity and overall financial condition, during December 2000 and early 2001, SCE had to repurchase $550 million of pollution-control bonds that could not be remarketed in accordance with their terms. SCE remarketed $196 million of these bonds in March 2002 (see additional discussion in Liquidity Issues). The remaining amount of these bonds may be remarketed in the future. In addition, SCE remains unable to sell its commercial paper and other short-term financial instruments.

Although Fitch IBCA, Standard & Poor's and Moody's Investors Service raised their credit ratings significantly for SCE in March 2002, the new ratings are still below investment grade. The new ratings reflect the ongoing financial recovery of SCE that began in October 2001 with SCE's settlement agreement with the CPUC and has continued with the CPUC's January 2002 PROACT resolution and the repayment of SCE's past-due obligations. SCE lost its investment-grade ratings in January 2001.

California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure, thereby limiting the dividends it may pay Edison International.

In December 1997, $2.5 billion of rate reduction notes were issued on behalf of SCE by SCE Funding LLC, a special purpose entity. These notes were issued to finance the 10% rate reduction mandated by state law. The proceeds of the rate reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable right known as transition property. Transition property is a current property right created by the restructuring legislation and a financing order of the CPUC and consists generally of the right to be paid a specified amount from non-bypassable rates charged to residential and small commercial customers. The rate reduction notes are being repaid over 10 years through these non-bypassable residential and small commercial customer rates, which constitute the transition property 7

Management's Discussion and Analysis of Results of Operations and Financial Condition purchased by SCE Funding LLC. The remaining series of outstanding rate reduction notes have scheduled maturities beginning in 2002 and ending in 2007, with interest rates ranging from 6.22% to 6.42%. The notes are secured by the transition property and are not secured by, or payable from, assets of SCE or Edison International. SCE used the proceeds from the sale of the transition property to retire debt and equity securities. Although, as required by accounting principles generally accepted in the United States, SCE Funding LLC is consolidated with SCE and the rate reduction notes are shown as long-term debt in the consolidated financial statements, SCE Funding LLC is legally separate from SCE.

The assets of SCE Funding LLC are not available to creditors of SCE or Edison International and the transition property is legally not an asset of SCE or Edison International. Due to its credit rating downgrade in late 2000, in January 2001, SCE began remitting its customer collections related to the rate reduction notes on a daily basis.

Cash Flows from Investing Activities Cash flows from investing activities are affected by additions to property and plant and funding of nuclear decommissioning trusts. Decommissioning costs are recovered in utility rates. These costs are expected to be funded from independent decommissioning trusts that receive SCE contributions of approximately

$25 million per year. In 1995, the CPUC determined the restrictions related to the investments of these trusts. They are: not more than 50% of the fair market value of the qualified trusts may be invested in equity securities; not more than 20% of the fair market value of the trusts may be invested in international equity securities; up to 100% of the fair market values of the trusts may be invested in investment grade fixed-income securities including, but not limited to, government, agency, municipal, corporate, mortgage backed, asset-backed, non-dollar, and cash equivalent securities; and derivatives of all descriptions are prohibited. Contributions to the decommissioning trusts are reviewed every three years by the CPUC.

The contributions are determined from an analysis of estimated decommissioning costs, the current value of trust assets and long-term forecasts of cost escalation and after-tax return on trust investments.

Favorable or unfavorable investment performance in a period will not change the amount of contributions for that period. However, trust performance for the three years leading up to a CPUC review proceeding will provide input into future contributions. SCE's costs to decommission San Onofre Unit 1 are paid from the nuclear decommissioning trust funds. These withdrawals from the decommissioning trusts are netted with the contributions to the trust funds in the Consolidated Statements of Cash Flows.

Projected Commitments SCE's projected construction expenditures for 2002 are $921 million.

Long-term debt maturities and sinking fund requirements for the next five years are: 2002 - $1.1 billion; 2003 - $1.4 billion; 2004 - $371 million; 2005 - $246 million; and 2006 - $446 million.

Fuel supply contract payments for the next five years are: 2002 - $168 million; 2003 - $108 million; 2004 - $103 million; 2005- $106 million; and 2006 - $109 million.

Purchased-power capacity payments for the next five years are: 2002 - $629 million; 2003 - $629 million; 2004 - $626 million; 2005 - $624 million; and 2006 - $572 million.

Preferred stock redemption requirements for the next five years are: 2002 - $105 million; 2003

$9 million; 2004 - $9 million; 2005 - $9 million; and 2006 - $9 million.

Market Risk Exposures SCE's primary market risk exposures include commodity price risk and interest rate risk that could adversely affect results of operations or financial position. Commodity price risk arises from fluctuations in the market price of an energy commodity, such as electricity, natural gas, or coal. Interest rate risk arises from fluctuations in interest rates. Additionally, natural gas is a key input for the prices specified in approximately half of SCE's QF (including non-gas QF) contracts. Virtually all of SCE's exposure to changes in the spot market price for natural gas through 2003 is hedged through financial derivatives or fixed-price contracts. SCE's risk management policy allows the use of derivative financial instruments to 8

I

Southern California Edison Company manage its financial exposures, but prohibits the use of these instruments for speculative or trading purposes.

SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used for liquidity purposes and to fund business operations, as well as to finance capital expenditures.

The nature and amount of SCE's long-term and short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors. As a result of California's energy crisis, SCE has been exposed to significantly higher interest rates, which intensified its liquidity crisis during 2001 (further discussed in the Liquidity Issues section of Financial Condition).

At December 31, 2001, SCE did not believe that its short-term debt was subject to interest rate risk, due to the fair market value being approximately equal to its carrying value. SCE did believe that the fair market value of its fixed-rate long-term debt was subject to interest rate risk. At December 31, 2001, a 10%

increase in market interest rates would have resulted in a $128 million decrease in the fair market value of SCE's long-term debt. A 10% decrease in market interest rates would have resulted in a $141 million increase in the fair market value of SCE's long-term debt.

Since April 1998, the price SCE paid to acquire power on behalf of customers was allowed to float, in accordance with the 1996 electric utility restructuring law. Until May 2000, retail rates were sufficient to cover the cost of power and other SCE costs. However, between May 2000 and June 2001, market power prices escalated, creating a substantial gap between costs and retail rates. In response to the dramatically higher prices, the ISO and the FERC have placed certain caps on the price of power (see further discussion in Wholesale Electricity Markets).

Under the terms of the CPUC settlement agreement, SCE purchased $209 million in hedging instruments (gas call options) in October and November 2001 to hedge a majority of its natural gas price exposure associated with QF contracts for 2002 and 2003. Although these gas call options are reflected in the income statement, any fair value changes of the gas call options are offset through a regulatory balancing account; therefore, fair value changes do not affect earnings. At December 31, 2001, a 10% increase in market gas prices would have resulted in a $32 million increase in the fair market-value of SCE's gas call options. A 10% decrease in market gas prices would have resulted in a $27 million decrease in the fair market value of the gas call options.

In accordance with an accounting standard for derivatives, on January 1, 2001, SCE recorded its block-forward contracts at fair value on the balance sheet. Because SCE suspended payments for purchased power on January 16, 2001, the PX sought to liquidate SCE's remaining block-forward contracts. Before the PX could do so, on February 2, 2001, the state seized the contracts. On September 20, 2001, a federal appeals court ruled that the governor of California acted illegally when he seized the power contracts held by SCE. In conjunction with its settlement agreement with the CPUC (discussed in CPUC Litigation Settlement Agreement), SCE has agreed to release any claim for compensation against the state for these contracts. However, if the PX prevails in its claims against the state, SCE may receive some refunds. Due to its speculative grade credit ratings, SCE has been unable to purchase additional bilateral forward contracts, and some of the existing contracts were terminated by the counterparties.

Regulatory Environment SCE operates in a highly regulated environment and has an exclusive franchise within its service territory.

SCE has an obligation to deliver electric service to its customers and regulatory authorities have an obligation to provide just and reasonable rates. In the mid-1990s, state lawmakers and the CPUC initiated the electric industry restructuring process. SCE was directed by the CPUC to divest the bulk of its gas-fired generation portfolio. Today, independent power companies own the divested generating plants.

The electric industry restructuring plan also instituted a multi-year freeze on the rates that SCE could charge its customers and transition cost recovery mechanisms (as described in Status of Transition and Power-Procurement Cost Recovery) designed to allow SCE to recover its stranded costs associated with generation-related assets. California's electric industry restructuring statute included provisions to finance a portion of the stranded costs that residential and small commercial customers would have paid between 9

Management's Discussion and Analysis of Results of Operations and Financial Condition 1998 and 2001, which allowed SCE to reduce rates by at least 10% to these customers, effective January 1, 1998. These frozen rates (except for the surcharge effective in 2001) were to remain in effect until the earlier of March 31, 2002, or the date when the CPUC-authorized costs for utility-owned generation assets and obligations are recovered. However, between May 2000 and June 2001, the prices charged by sellers of power escalated far beyond what SCE could charge its customers. As a result, SCE incurred $2.7 billion (after tax), or $4.7 billion (pre-tax), in write-offs as of December 31, 2000, and net undercollected transition costs through August 31, 2001. As indicated below, implementation of the CPUC settlement agreement and CPUC approval of SCE's Utility-Retained Generation (URG) application is expected to allow SCE to recover substantially all of the $4.7 billion.

Generation and Power Procurement During the rate freeze, recovery of generation-related transition costs was tracked through the TCBA mechanism. Revenue from generation-related operations was determined through the market and transition cost recovery mechanisms, which included the nuclear rate-making agreements. During fourth quarter 2001, the TCBA mechanism was terminated retroactive to September 1, 2001, and a $3.6 billion PROACT regulatory asset was created in accordance with the October 2001 settlement agreement with the CPUC and the PROACT resolution adopted in January 2002. In accordance with a state law passed in January 2001, SCE will continue to own its remaining generation assets, which will be subject to cost based ratemaking, through 2006 (see further discussion in URG Proceeding).

Through December 31, 2000, SCE had been recovering its investment in its nuclear facilities on an accelerated basis (over four years) in exchange for a lower authorized rate of return on investment.

SCE's nuclear assets were earning an annual rate of return on investment of 7.35%. However, due to the various unresolved regulatory and legislative issues (as discussed in Status of Transition and Power Procurement Cost Recovery), as of December 31, 2000, SCE was no longer able to conclude that the

$610 million balance of unamortized nuclear investment regulatory assets was probable of recovery through the rate-making process. As a result, this balance was written off as a charge to earnings at that time (see further discussion in Earnings). Should the URG application be approved, SCE expects to reestablish for financial reporting purposes its unamortized nuclear investment and related flow-through taxes retroactive to August 31, 2001, with recovery based on a 10-year period, effective January 1, 2001, with a corresponding credit to earnings, and adjust the PROACT regulatory asset balance as necessary to reflect recovery of the nuclear investment in accordance with the final URG decision.

The San Onofre incentive-pricing plan authorizes a fixed rate of approximately 40 per kWh generated for operating costs including incremental capital costs, nuclear fuel and nuclear fuel financing costs. The San Onofre incentive-pricing plan started in April 1996 and ends in December 2003. The Palo Verde Nuclear Generating Station's operating costs, including incremental capital costs, and nuclear fuel and nuclear fuel financing costs, were subject to balancing account treatment. The Palo Verde plan started in January 1997 and was to end in December 2001. The benefits of operation of the San Onofre units and the Palo Verde units were required to be shared equally with ratepayers beginning in 2004 and 2002, respectively. In a June 2001 decision, the CPUC granted SCE's request to eliminate the San Onofre post 2003 sharing mechanism based on compliance with a state law enacted in early 2001. In a September 2001 decision, the CPUC granted SCE's request to eliminate the Palo Verde post-2001 sharing mechanism and to continue the current rate-making treatment for Palo Verde, including the continuation of the existing nuclear incentive procedure with a 50 per kWh cap on replacement power costs, until resolution of SCE's next general rate case or further CPUC action. Beginning January 1, 1998, both the San Onofre and Palo Verde rate-making plans became part of the TCBA mechanism. These rate-making plans and the TCBA mechanism were to continue for rate-making purposes at least through the end of the rate freeze period. However, in its URG application, SCE proposed to move the recovery of nuclear costs to another balancing account mechanism. See discussion in URG Proceeding for the proposed and alternate decisions' impact on the incentive-pricing plans.

CPUC Litigation Settlement Agreement In November 2000, SCE filed a lawsuit against the CPUC in federal district court seeking a ruling that SCE is entitled to full recovery of its past electricity procurement costs in accordance with the tariffs filed with 10

Southern California Edison Company the FERC. By agreement of the parties, a stay of the lawsuit was issued in April 2001 while SCE sought implementation of legislative, regulatory and executive actions to resolve the California energy crisis and SCE's related financial and liquidity problems. In October 2001, the federal district court entered a stipulated judgment approving an agreement between the CPUC and SCE to settle the pending lawsuit.

On January 23, 2002, the CPUC adopted a resolution implementing the settlement agreement. See discussion below in PROACT Regulatory Asset.

Key elements of the settlement agreement include the following items:

Establishment of the PROACT, as of September 1, 2001, with an opening balance equal to the amount of SCE's procurement-related liabilities as of August 31, 2001 (approximately $6.4 billion),

less SCE's cash and cash equivalents as of that date (approximately $2.5 billion), and less

$300 million.

Beginning on September 1, 2001, SCE will apply to the PROACT, on a monthly basis, the difference between SCE's revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the CPUC to recover in retail electric rates. Unrecovered obligations in the PROACT will accrue interest from September 1, 2001.

Maintain current rates (including surcharges) in effect until December 31, 2003, subject to certain adjustments, or, if earlier, until the date that SCE recovers the entire PROACT balance. If SCE has not recovered the entire balance by December 31, 2003, the unrecovered balance will be amortized for up to an additional two years. The parties project that existing retail electric rates, including surcharges and as adjusted to reflect certain costs, will likely result in SCE recovering substantially all of its unrecovered procurement-related obligations prior to the end of 2003.

If the CPUC concludes that it is desirable to authorize a securitized financing of SCE's procurement related obligations, the parties will work together to achieve the securitization. Proceeds of any securitization will be credited to the PROACT when they are actually received.

During the period that SCE is recovering its previously incurred procurement-related obligations, no penalty will be imposed by the CPUC on SCE for any noncompliance with CPUC-mandated capital structure requirements.

SCE can incur up to $250 million of recoverable costs to acquire financial instruments and engage in other transactions intended to hedge fuel cost risks associated with SCE's retained generation assets and power purchase contracts with QUs and other utilities. As of December 31, 2001, SCE had purchased $209 million in hedging instruments. See discussion in Market Risk Exposures.

SCE will not declare or pay dividends or other distributions on its common stock (all of which is held by its parent) prior to the earlier of the date SCE has recovered all of its procurement-related obligations in the PROACT or January 1, 2005. However, if SCE has not recovered all of its procurement-r'elated obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume common stock dividends, and the CPUC will not unreasonably withhold its consent.

"* To ensure the ability of SCE to continue to provide adequate service, SCE may make capital expenditures above the level contained in current rates, up to $900 million per year, which will be treated as recoverable costs.

Subject to certain qualifications, SCE will cooperate with the CPUC and the California Attorney General to pursue and resolve SCE's claims and rights against sellers of energy and related services, SCE's defenses to claims arising from any failure to make payments to the PX or ISO, and similar claims by the State of California or its agencies against the same adverse parties. During the recovery period discussed above, refunds obtained by SCE related to its procurement-related liabilities will be applied to the balance in the PROACT.

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Management's Discussion and Analysis of Results of Operations and Financial Condition The settlement agreement states that one of its purposes is to restore the investment grade creditworthiness of SCE as rapidly as reasonably practicable so that it will be able to provide reliable electrical service as a state-regulated entity as it has in the past. SCE cannot provide assurance that it will regain investment grade credit ratings by any particular date.

On November 28, 2001, a federal court of appeals denied a California consumer group's request for a long-term stay of the settlement. The group had alleged that it was denied due process and that the CPUC had no authority to agree with SCE to violate the statutory rate freeze. In its ruling, the federal court of appeals also granted SCE's request for an expedited hearing of an appeal of the settlement filed by the consumer group. On March 4, 2002, the court of appeals heard argument on the appeal and the matter is now under submission. A decision could be issued anytime during the next several months.

SCE cannot predict the outcome of the appeal or the impact that any outcome would have upon the stipulated judgment or the settlement, at this time. Possible outcomes include affirmance, a return to the district court or reversal of the stipulated judgment. SCE cannot predict whether or how a ruling on the stipulated judgment could also affect the settlement agreement.

PROACT Regulatory Asset According to the terms of the settlement agreement and the CPUC resolution, in the fourth quarter of 2001, SCE established (retroactive to August 31, 2001) a $3.6 billion PROACT regulatory asset for its previously incurred procurement costs.

The beginning balance of the PROACT, as verified by the CPUC, was calculated as follows:

In millions Past-due bills:

PX or ISO 924 QFs 1,219 PX energy credits 236 Imbalance energy (CDWR) 383 Ancillary services for resale cities 30 Total past-due bills 2,792 Procurement-related debt (including accrued interest):

Credit facilities 1,298 Bilateral credit facilities 415 Defaulted commercial paper 563 Floating rate notes due May 2002 313 Variable rate notes due November 2003 1,043 Total procurement-related debt 3,632 Total procurement-related liabilities 6,424 Less: Cash and cash equivalents on hand (2,547)

Less: Amount stipulated in agreement (300)

Net PROACT balance as of August 31, 2001

$3,577 For a comparison between the PROACT balance as of August 31, 2001, and the TCBA balance as of that date, see discussion in Status of Transition and Power-Procurement Cost Recovery.

CDWR Power Purchases In accordance with an emergency order signed by the governor, the CDWR began making emergency power purchases for SCE's customers on January 17, 2001. Amounts SCE bills to and collects from its customers for electric power purchased and sold by the CDWR and through the ISO are remitted directly to the CDWR and are not recognized as revenue by SCE. In February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1 X) was enacted into law. AB 1X authorized the CDWR to enter into contracts 12

Southern California Edison Company to purchase electric power and sell power at cost directly to retail customers being served by SCE, and authorized the CDWR to issue bonds to finance electricity purchases.

On March 27, 2001, the CPUC issued an interim order requiring SCE to pay the CDWR a per-kWh price equal to the applicable generation-related retail rate per kWh for electricity (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 retail rate should be equal to the total bundled electric rate (including the 1 0-per-kWh surcharge adopted by the CPUC on January 4, 2001) less certain nongeneration-related rates or charges.

For the period January 19 through January 31, 2001, the CPUCr ordered SCE to pay the CDWR at a rate of 6.2770 per kWh for power delivered to SCE's customers. The CPUC determined that the applicable rate component is 7.2770 per kWh (which increased to 10.2770 per kWh for electricity delivered after March 27, 2001, due to the 30-surcharge discussed in Rate Stabilization Proceedings), for electricity delivered by the CDWR to SCE's retail customers after 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, subject to penalties for each day the payment is late.

On February 21, 2002, the CPUC issued a decision implementing a CDWR revenue requirement of

$9.0 billion to pay its bonds' costs and energy procurement costs for the period January 17, 2001, through December 31, 2002. The decision states that SCE's allocated share of this revenue requirement would be approximately $3.6 billion, and changes SCE's payment to 9.7440 per kWh for all bills rendered on or after March 15, 2002. The decision requires SCE to pay the CDWR in equal monthly installments over a six-month period the difference in rates between January 17, 2001, and March 15, 2002. SCE estimates that this amount could be approximately $41 million.

On February 28, 2002, SCE and the CDWR executed an agreement that resolves outstanding issues relating to the payment for electric power purchased for SCE's customers through the ISO real-time market (known as imbalance energy). Under this agreement, SCE will pay the CDWR for imbalance energy previously delivered in three installments ($100 million on April 1, 2002; $150 million on June 3, 2002; and the balance on July 1, 2002).

Status of Transition and Power-Procurement Cost Recovery SCE's transition costs to be recovered through the TCBA mechanism included power purchases from OF contracts (which are the direct result of prior legislative and regulatory mandates), recovery of certain generating assets and other costs incurred to provide service to customers. Other costs included the recovery of income tax benefits previously flowed through to customers, postretirement benefit transition costs and accelerated recovery of investment in nuclear generating units. Recovery of costs related to power-purchase OF contracts was permitted through the terms of each contract. Legislation and regulatory decisions issued prior to the beginning of the rate freeze called for most of the remaining transition costs to be recovered through the end of the four-year transition period (not later than March 31, 2002). Because regulatory and legislative actions that make such recovery probable were not taken in a timely manner during the energy crisis, as of December 31, 2000, SCE was unable to conclude that the net regulatory assets related to purchased-power settlements, the unamortized loss on SCE's generating plant sales in 1998, and various other generation regulatory assets were probable of recovery through the rate-making process. As a result, these balances were written off as a charge to earnings at that time (see further discussion in Earnings).

There were three sources of revenue available to SCE for transition cost recovery through the TCBA mechanism: revenue from the sale or valuation of generation assets in excess of book values, net market revenue from the sale of SCE-controlled generation into the ISO and PX markets and competition transition charge (CTC) revenue. Revenue from the first two sources has not been available since January 2001. Net proceeds of the 1998 plant sales were used to reduce transition costs, which otherwise had been expected to be collected through the TCBA mechanism. However, state legislation enacted in January 2001 prohibits the sale of SCE's remaining generation assets until 2006. SCE stopped selling power from its generation into the ISO and PX markets in January 2001, after SCE's credit ratings were downgraded and the PX suspended SCE's trading privileges (see discussion in Generation and Power Procurement).

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Management's Discussion and Analysis of Results of Operations and Financial Condition CTC revenue was determined residually (i.e., CTC revenue was 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 applied to all customers who were using or began using utility services on or after the CPUC's 1995 restructuring decision date. Residual CTC revenue was calculated through the TRA mechanism. In accordance with the March 27, 2001, rate stabilization decision, both positive and negative residual CTC revenue was transferred from the TRA to the TCBA on a monthly basis, retroactive to January 1, 1998 (see further discussion in Rate Stabilization Proceedings). A previous decision had called only for a transfer of positive residual CTC revenue (TRA overcollections) to the TCBA and there had not been any positive residual CTC revenue between May 2000 and June 2001.

Because the regulatory and legislative actions that made such recovery probable were not taken, SCE was unable to conclude as of December 31, 2000, that the recalculated TCBA net undercollection was probable of recovery through the rate-making process. As a result, the $2.9 billion TCBA net undercollection was written off as a charge to earnings as of that date (see further discussion in Earnings),

and an additional $552 million (pre-tax) of net undercollected transition costs was charged to earnings between January 1, 2001, and August 31, 2001. Although the TCBA was written off, SCE continued to calculate the account for rate-making purposes, and the account reflected a $4.2 billion undercollection as of August 31, 2001, the effective date of the beginning of the PROACT mechanism and the end of the TCBA mechanism. If the TCBA would have been adjusted for the impact of SCE's treatment of the nuclear facilities as proposed in the URG proceeding, the TCBA balance as of August 31, 2001, would have reflected an undercollection of $3.626 billion, substantially equal to the $3.577 billion undercollection in the PROACT regulatory asset.

For more details on the matters discussed above, see discussions in Rate Stabilization Proceedings, URG Proceeding and PROACT Regulatory Asset.

Litigation In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International.

As amended in December 2000 and March 2001, the lawsuit involves securities fraud claims arising from alleged improper accounting for the TRA undercollections. The second amended complaint is supposedly filed on behalf of a class of persons who purchased Edison International common stock between July 21, 2000, and April 17, 2001. This lawsuit has been consolidated with another similar lawsuit filed on March 15, 2001. A consolidated class action complaint was filed on August 3, 2001. On September 17, 2001, SCE and Edison International filed a motion to dismiss for failure to state a claim. On March 8, 2002, the district court issued an order dismissing the complaint with prejudice. The plaintiffs could appeal this ruling to the court of appeals.

In addition to the lawsuits filed against Edison International and SCE discussed above, SCE has been a defendant in a number of legal actions brought by various QFs arising out of SCE's suspension of payments for electricity delivered by the QFs during the period November 1, 2000, through March 26, 2001. The QF claims were eventually largely subsumed within agreements with the litigating QFs providing for a provisional settlement of the parties' disputes. On March 1, 2002, SCE paid the amounts due under settlement agreements with these QFs, which triggered the releases and other provisions of the settlements. As a result, the litigation with those QFs to whom payment in full has been made under the parties' settlement agreements should be dismissed during 2002. However, SCE's March 1, 2002, payments excluded several QFs or did not result in immediate releases under the settlement agreements based on unique disputes or other unique circumstances, including the status of regulatory approval.

Rate Stabilization Proceedings In January 2000, SCE filed an application with the CPUC proposing rates that would go into effect when the four-year rate freeze was to end on March 31, 2002, or earlier, depending on the pace of transition cost recovery. In December 2000, SCE filed an amended rate stabilization plan application, stating that the statutory rate freeze had ended in accordance with California law, and requesting the CPUC to approve an immediate 30% increase to be effective, subject to refund, January 4, 2001.

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Southern California Edison Company In January 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 covered, 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. In April 2001, the CPUC adopted an order instituting investigation that reopens the past CPUC decision authorizing the utilities to form holding companies and initiates an investigation into: whether the holding companies violated CPUC requirements to give first priority to the capital needs of their respective utility subsidiaries; 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; 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; any additional suspected violations of laws or CPUC rules and decisions; and whether additional rules, conditions, or other changes to the holding company decisions are necessary. The CPUC ordered testimony and briefing on these matters, which SCE filed in May and June 2001. On January 9, 2002, the CPUC issued an interim decision on the first priority condition. The decision stated that, at least under certain circumstances, the condition includes the requirement that holding companies infuse all types of capital into their respective utility subsidiaries when necessary to fulfill the utility's obligation to serve. On February 11, 2002, SCE filed an application for rehearing of the decision stating that the decision is an unlawful and erroneous attempt to rewrite the first priority condition rather than interpret it and that the decision would result in higher rates for SCE's customers. SCE cannot predict what effects this investigation or any subsequent actions by the CPUC may have on SCE.

In March 2001, the CPUC ordered a rate increase in the form of a 30-per-kWh surcharge applied only to going-forward electric power procurement costs and affirmed that a 10 interim surcharge granted in January 2001 is permanent. The 30 surcharge is to be added to the rate paid to the CDWR (see CDWR Power Purchases). Although the 30-increase was authorized as of March 27, 2001, the surcharge was not collected in rates until the CPUC established a rate design in early June 2001. To compensate for the two-month delay in collecting the 30 surcharge, the CPUC authorized an additional

¢/20 surcharge for a 12-month period beginning in June 2001.

URG Proceedina In June 2001, SCE filed a comprehensive proposal for new cost-of-service ratemaking for utility retained generation through the end of 2002. After that time, SCE's URG-related revenue requirement will be determined by the general rate case. The URG proposal calls for balancing accounts for SCE-owned generation, QF and interutility contracts, procurement costs and ISO charges based on either actual or CPUC-authorized revenue requirements. Under the proposal, the four new balancing accounts would be effective January 1, 2001, for capital-related costs, and February 1, 2001, for non-capital-related costs. In addition, SCE's unamortized nuclear investment would be amortized and recovered in rates over a 10 year period, effective January 1, 2001. Should this application be approved as filed, SCE expects to reestablish for financial reporting purposes its unamortized nuclear investment and regulatory assets related to purchased-power settlements and flow-through taxes, with a corresponding credit to earnings, and adjust the PROACT regulatory asset balance in accordance with the final URG decision.

On January 18, 2002, a CPUC administrative law judge issued a proposed decision and a CPUC commissioner issued an alternate proposed decision. Both the proposed and alternate proposed decisions adopt most of the elements of SCE's application, but propose eliminating an incentive-pricing plan for San Onofre, effective January 1, 2002, and replacing it with balancing account treatment for San Onofre's operating costs, subject to a later reasonableness review. On February 7, 2002, another CPUC commissioner issued an alternate proposed decision recommending continuing the incentive-pricing plan for San Onofre Units 2 and 3 through December 31, 2003, as originally provided in CPUC decisions adopted in early 1996. A final decision is expected in second quarter 2002.

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Management's Discussion and Analysis of Results of Operations and Financial Condition Generation Procurement Proceeding In October 2001, the CPUC issued an order instituting rulemaking (OIR) to establish policies and cost recovery mechanisms for generation procurement. The OIR directed SCE and the other major California electric utilities to provide recommendations for establishing these policies and mechanisms to enable the utilities to resume their power procurement responsibilities in 2003. In comments filed with the CPUC on November 26, 2001, SCE recommended that the CPUC issue a procurement framework decision in February 2002, and direct the utilities to submit their specific procurement plan proposals and related framework compliance proposals in March 2002. SCE also proposed that a final decision be issued in October 2002 adopting utility-specific procurement plans. The CPUC has not yet acted on SCE's recommendations, but is expected in second quarter 2002 to issue a scoping memo setting forth issues to be addressed in this proceeding.

Accounting for Generation-Related Assets and Power Procurement Costs In 1997, SCE discontinued application of accounting principles for rate-regulated enterprises for its generation assets. At that time, SCE did not write off any of its generation-related assets, including related regulatory assets, because the electric utility industry restructuring plan made probable their recovery through a non-bypassable charge to distribution customers.

During the second quarter of 1998, in accordance with asset impairment accounting standards, SCE reduced its remaining nuclear plant investment by $2.6 billion (as of June 30, 1998) and recorded a regulatory asset on its balance sheet for the same amount. For this impairment assessment, the fair value of the investment was calculated by discounting expected future net cash flows. This reclassification had no effect on SCE's results of operations.

As of December 31, 2000, SCE assessed the probability of recovery of its generation-related assets and power procurement costs in light of the CPUC's March 27, 2001, and April 3, 2001, decisions, and could not conclude that its $2.9 billion TCBA undercollection (as redefined in the March 27 decisions) and

$1.3 billion (book value) of its net generation-related regulatory assets to be amortized into the TCBA, were probable of recovery through the rate-making process. As a result, accounting principles generally accepted in the United States required that the balances in the accounts be written off as a charge to earnings. In addition to the $4.2 billion pre-tax write-off, SCE incurred approximately $552 million (pre-tax) in net undercollected transition costs through August 31, 2001 (see Earnings).

In accordance with the CPUC settlement agreement and the PROACT resolution, in fourth quarter 2001, SCE established a $3.6 billion regulatory asset for previously incurred power procurement costs, called the PROACT, retroactive to August 31, 2001. See further discussion in PROACT Regulatory Asset.

CPUC approval of the URG application, as filed (see URG Proceeding), together with implementation of the PROACT mechanism is expected to allow SCE to recover substantially all of the $4.7 billion in write offs as of December 31, 2000, and net undercollected transition costs incurred through August 31, 2001.

If the CPUC approves SCE's URG application, as filed, SCE expects to reapply accounting principles for rate-regulated enterprises for its generation assets. These assets will then be subject to traditional cost-of-service regulation.

Distribution Revenue related to distribution operations is determined through a performance-based rate-making (PBR) mechanism and the distribution assets have the opportunity to earn a CPUC-authorized 9.49% return on investment. 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. The distribution PBR was to have ended in December 2001, but in June 2001 the CPUC extended the mechanism until SCE's next general rate case, which will be effective in 2003. A CPUC proposed decision on the PBR 16

Southern California Edison Company mechanism for 2002 was issued in January 2002. The proposed decision authorized SCE to use a formula to determine its distribution revenue requirement for the last half of 2001 and 2002, and a revenue balancing account to ensure that variations in sales do not result in under or overcollections. A final decision is expected in second quarter 2002. At this time, SCE cannot predict the effect of the final decision on its results of operations.

In December 2001, SCE filed its 2003 general rate case with the CPUC, requesting an increase of approximately $500 million in revenue (compared to 2000 recorded revenue) for its distribution and generation operations. Hearings are expected to begin in July 2002, with a final decision expected in second quarter 2003.

Transmission Transmission revenue is determined through FERC-authorized rates and is subject to refund.

Wholesale Electricity Markets 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. In December 2000, the FERC took limited action and failed to impose a price cap. SCE filed an emergency petition in the federal court of appeals challenging the FERC order and requesting the FERC to immediately establish cost-based wholesale rates. The court denied SCE's petition in January 2001.

In its December 2000 order, the FERC established an underscheduling penalty effective January 1, 2001, applicable to scheduling coordinators that do not schedule sufficient resources to supply 95% of their respective loads. In December 2001, the FERC eliminated the underscheduling penalty retroactive to January 1, 2001.

On April 25, 2001, after months of extremely high power prices, the FERC issued an order providing for energy price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve power).

The order establishes an hourly clearing price based on the costs of the least efficient generating unit during the period. Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non emergency periods and price mitigation in the 11-state western region. The latest order is in effect until September 30, 2002.

After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25, 2001, the FERC issued an order that limits potential refunds from alleged overcharges to the ISO and PX spot markets during the period from October 2, 2000, through June 20, 2001, and adopted a refund methodology based on daily spot market gas prices. An administrative law judge will conduct evidentiary hearings on this matter. SCE cannot predict the amount of any potential refunds. Under the settlement of litigation with the CPUC, refunds will be applied to the balance in the PROACT.

Environmental Protection SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.

As further discussed in Note 12 to the Consolidated Financial Statements, 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's recorded estimated minimum liability to remediate its 42 identified sites is $111 million. SCE believes that, due to uncertainties inherent in the estimation process, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $279 million. In 1998, SCE sold all of its gas-fueled power plants but has retained some liability associated with the divested properties.

17

Management's Discussion and Analysis of Results of Operations and Financial Condition The CPUC allows SCE to recover environmental-cleanup costs at certain sites, representing $50 million of its recorded liability, through an incentive mechanism, which is discussed in Note 12. SCE has recorded a regulatory asset of $76 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. As a result, 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. Remediation costs in each of the next several years are expected to range from $10 million to $25 million. Recorded costs for the year ended December 31, 2001, were $18 million.

Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental cleanup costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

The Clean Air Act requires power producers to have emissions allowances to emit sulfur dioxide. Power companies receive emissions allowances from the federal government and may bank or sell excess allowances. SCE expects to have excess allowances under Phase 11 of the Clean Air Act (2000 and later).

A study was undertaken to determine the specific impact of air contaminant emissions from the Mohave Generating 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. In June 1999, the Environmental Protection Agency (EPA) issued an advanced notice of proposed rulemaking regarding assessment of visibility impairment at the Grand Canyon. The EPA issued its final rule on February 8, 2002, which incorporates the terms of the consent decree into the visibility provisions of its Federal Implementation Plan for Nevada, making the terms of the consent decree federally enforceable.

SCE's share of the costs of complying with the consent decree and taking other actions to continue operation of the Mohave station is estimated to be approximately $560 million over the next four years.

However, SCE has suspended its efforts to seek approval to install the Mohave controls because it has not obtained reasonable assurance of an adequate coal supply for operating Mohave beyond 2005. If an adequate coal supply is not obtained, it will become necessary to shut down the Mohave station after December 31, 2005. If the station is shut down at that time, the shutdown is not expected to have a material adverse impact on SCE's financial position or results of operations, assuming the remaining book value of the station (approximately $88 million as of December 31, 2001), and plant closure and decommissioning-related costs are recoverable in future rates. SCE cannot predict what effect any future actions by the CPUC may have on this matter.

SCE's projected environmental capital expenditures are $1.3 billion for the 2002-2006 period, mainly for undergrounding certain transmission and distribution lines.

San Onofre Nuclear Generating Station In February 2001, SCE's San Onofre Unit 3 experienced a fire due to an electrical fault in the non-nuclear portion of the plant. The turbine rotors, bearings and other components of the turbine generator system were damaged extensively. In June 2001, Unit 3 returned to service. Under the currently effective San Onofre rate-recovery plan (discussed in the Generation and Power Procurement section of Regulatory Environment),

SCE's lost revenue was approximately $98 million as a result of the fire and related outage.

18

Southern California Edison Company The San Onofre Units 2 and 3 steam generators' design allows for the removal of up to 10% of the tubes before the rated capacity of the unit must be reduced. Increased tube degradation was found during routine inspections in 1997. To date, 8% of Unit 2's tubes and 6% of Unit 3's tubes have been removed from service. A decreasing (favorable) trend in degradation has been observed in more recent inspections.

Critical Accounting Policies The accounting policies described below are viewed by management as critical because their application is the most relevant and material to SCE's results of operations and financial position and these policies require the use of material judgments and estimates.

SCE applies accounting principles for rate-regulated enterprises to the portion of its operations, where regulators set rates at levels intended to recover the estimated costs of providing service, plus a return on capital. Due to timing and other differences in the collection of revenue, these principles allow a cost that would otherwise be charged to expense by a non-regulated entity to be capitalized as a regulatory asset, if it is probable that the cost is recoverable through future rates, and conversely allow creation of a regulatory liability for probable future costs collected through rates in advance. See further discussion of regulatory assets and liabilities in Note 1 to the Consolidated Financial Statements.

SCE applied judgment in the use of the above principles when it concluded, as of December 31, 2000, that $4.2 billion of generation-related regulatory assets and liabilities were no longer probable of recovery, and wrote off these assets as a charge to earnings, and again in fourth quarter 2001 when it created the

$3.6 billion PROACT regulatory asset with a corresponding credit to earnings upon receiving regulatory assurance of collection of these costs. See further discussion in Earnings section.

New Accounting Standards On January 1, 2001, SCE adopted a new accounting standard for derivative instruments and hedging activities. The standard requires derivatives to be recognized on the balance sheet at fair value, unless they meet the definition of a normal purchase or sale. Gains or losses from changes in the fair value of a recognized asset or liability or a firm commitment are reflected in earnings for the ineffective portion of the hedge. For a hedge of the cash flows of a forecasted transaction, the effective portion of the gain or loss is initially recorded as a separate component of shareholder's equity under the caption accumulated other comprehensive income, and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the hedge is reflected in earnings immediately. SCE does not anticipate any earnings impact from any derivatives, since it expects that any market price changes will be recovered in rates. In October 2001, additional implementation guidance, which will be effective April 1, 2002, was issued. SCE is still evaluating the impact of this new implementation guidance.

In July and August 2001, three new accounting standards were issued: Business Combinations; Goodwill and Other Intangibles; and Accounting for Asset Retirement Obligations.

The new Business Combinations standard eliminates the pooling-of-interests method, effective June 30, 2001. After that, all business combinations will be recorded under the purchase method (i.e., record purchase based upon value exchanged and record goodwill for excess of costs over the net assets acquired).

The new Goodwill and Other Intangibles standard requires that companies cease amortizing goodwill, effective January 1, 2002. Goodwill initially recognized after June 30, 2001, will not be amortized.

Goodwill on the balance sheet at June 30, 2001, was amortized until December 31, 2001. Under the new standard, goodwill will be tested for impairment using a fair-value approach when events or circumstances occur indicating that impairment might exist. Also, a benchmark assessment for goodwill is required within six months of the date of adoption of the standard.

The Accounting for Asset Retirement Obligations standard requires entities to record the fair value of a liability for a legal asset retirement obligation in the period in which it is incurred. When the liability is 19

Management's Discussion and Analysis of Results of Operations and Financial Condition initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for SCE beginning on January 1, 2003.

SCE is studying the impact of the new Asset Retirement Obligations standard and is unable to predict at this time the effect on its financial statements. SCE does not anticipate any material impact on its results of operations or financial position from the other two new accounting standards.

In October 2001, a new accounting standard was issued related to accounting for the impairment or disposal of long-lived assets. Although the standard supersedes a prior accounting standard related to the impairment of long-lived assets, it retains the fundamental provisions of the impairment standard regarding recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived assets to be disposed of by sale. Under the new accounting standard, asset write-downs from discontinuing a business segment will be treated the same as other assets held for sale.

The new standard also broadens the financial statement presentation of discontinued operations to include the disposal of an asset group (rather than a segment of a business). The standard (effective on January 1, 2002) was adopted early, in fourth quarter 2001. The adoption of this standard had no effect on SCE's financial statements.

Forward-looking Information In the preceding Management's Discussion and Analysis of Results of Operations and Financial Condition and elsewhere in this annual report, the words estimates, expects, anticipates, believes, and other similar expressions are intended to identify forward-looking information that involves risks and uncertainties.

Actual results or outcomes could differ materially as a result of important factors that may be outside SCE's control, including among other things: the outcome of the pending appeals of the stipulated judgment approving the settlement agreement with the CPUC, and the effects of other legal actions or ballot initiatives, if any, attempting to undermine the provisions of the settlement agreement or otherwise adversely affecting SCE; changes in prices of wholesale electricity and natural gas or in SCE's operating costs, which could cause SCE's cost recovery to be less than anticipated; the actions of securities rating agencies, including the determination of whether or when to make changes in SCE's credit ratings, the ability of SCE to regain investment grade ratings, and the impact of current or lowered ratings and other financial market conditions on the ability of SCE to obtain needed financing on reasonable terms; further actions by state and federal regulatory bodies setting rates, adopting or modifying cost recovery, accounting or rate-setting mechanisms and implementing the restructuring of the electric utility industry, as well as legislative or judicial actions affecting the same matters; the effects of increased competition in energy-related businesses, including the market entrants and the effects of new technologies that may be developed in the future; new or increased environmental liabilities; and weather conditions, natural disasters, and other unforeseen events.

20

Consolidated Statements of Income (Loss)

Southern California Edison Company In millions Year ended December 31, 2001 2000 1999 Operating revenue

$ 8,126

$ 7,870

$ 7,548

'Fuel 212 195 215 Purchased power 3,770 4,687 3,190 Provisions for regulatory adjustment clauses - net (3,028) 2,301 (763)

Other operation and maintenance 1,771 1,772 1,933 Depreciation, decommissioning and amortization 681 1,473 1,548 Property and other taxes 112 126 122 Net gain on sale of utility plant (9)

(25)

(3)

Total operating expenses 3,509 10,529 6,242 Operating income (loss) 4,617 (2,659) 1,306 Interest and dividend income 215 173 69 Other nonoperating income 57 118 162 Interest expense - net of amounts capitalized (785)

(572)

(483)

Other nonoperating deductions (38)

(110)

(107)

Income (loss) before taxes 4,066 (3,050) 947 Income tax (benefit) 1,658 (1,022) 438 Net income (loss) 2,408 (2,028) 509 Dividends on preferred stock 22 22 25 Net income (loss) available for common stock

$ 2,386

$ (2,050)

$ 484 Consolidated Statements of Comprehensive Income (Loss)

In millions Year ended December 31, 2001 2000 1999 Net income (loss)

$ 2,408

$(2,028)

$ 509 Other comprehensive income, net of tax:

Unrealized gain on securities - net 3

28 Cumulative effect of change in accounting for derivatives 398 Unrealized loss on cash flow hedges (420)

Reclassification adjustment for loss included in net income (loss)

(25)

(45)

Comprehensive income (loss)

$ 2,386

$ (2,050)

$ 492 The accompanying notes are an integral part of these financial statements.

21

Consolidated Balance Sheets In millions December 31, 2001 2000 ASSETS Cash and equivalents

$ 3,414 583 Receivables, less allowances of $32 and $23 for uncollectible accounts at respective dates 1,093 919 Accrued unbilled revenue 451 377 Fuel inventory 14 12 Materials and supplies, at average cost 146 132 Accumulated deferred income taxes - net 433 545 Regulatory assets - net 83 Prepayments and other current assets 145 124 Total current assets 5,779 2,692 Nonutility property - less accumulated provision for depreciation of $17 and $11 at respective dates 159 102 Nuclear decommissioning trusts 2,275 2,505 Other investments 224 90 Total investments and other assets 2,658 2,697 Utility plant, at original cost:

Transmission and distribution 13,568 13,129 Generation 1,729 1,745 Accumulated provision for depreciation and decommissioning (7,969)

(7,834)

Construction work in progress 556 636 Nuclear fuel, at amortized cost 129 143 Total utility plant 8,013 7,819 Regulatory assets - net 5,528 2,390 Other deferred charges 475 368 Total deferred charges 6,003 2,758 Total assets

$22,453

$15,966 The accompanying notes are an integral part of these financial statements.

22

Southern California Edison Company In millions, except share amounts December 31, 2001 2000 LIABILITIES AND SHAREHOLDER'S EQUITY Short-term debt

$ 2,127

$ 1,451 Long-term debt due within one year 1,146 646 Preferred stock to be redeemed within one year 105 Accounts payable 3,261 1,055 Accrued taxes 823 536 Regulatory liabilities - net 195 Other current liabilities 1,645 1,502 Total current liabilities 9,107 5,385 Long-term debt 4,739 5,631 Accumulated deferred income taxes - net 3,365 2,009 Accumulated deferred investment tax credits 153 164 Customer advances and other deferred credits 739 722 Power-purchase contracts 356 467 Accumulated provision for pensions and benefits 420 296 Other long-term liabilities 148 127 Total deferred credits and other liabilities 5,181 3,785 Commitments and contingencies (Notes 3, 11 and 12)

Preferred stock:

Not subject to mandatory redemption 129 129 Subject to mandatory redemption 151 256 Total preferred stock 280 385 Common stock (434,888,104 shares outstanding at each date) 2,168 2,168 Additional paid-in capital 336 334 Accumulated other comprehensive income (loss)

(22)

Retained earnings (deficit) 664 (1,722)

Total common shareholder's equity 3,146 780 Total liabilities and shareholder's equity

$22,453

$15,966 The accompanying notes are an integral part of these financial statements.

23

Consolidated Statements of Cash Flows In millions Year ended December 31, 2001 2000 1999 Cash flows from operating activities:

Net income (loss)

$ 2,408

$ (2,028)

$ 509 Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, decommissioning and amortization 681 1,473 1,548 Other amortization 82 97 95 Deferred income taxes and investment tax credits 1,313 (928) 178 Regulatory assets - long-term - net (3,135) 1,759 (1,354)

Gas call options (91) 20 11 Net gain on sale of marketable securities (41)

(77)

Other assets (68) 24 (73)

Other liabilities 17 (13) 17 Changes in working capital:

Receivables and accrued unbilled revenue (243)

(282) 99 Regulatory liabilities - short-term - net (278) 97 363 Fuel inventory, materials and supplies (16) 29 (5)

Prepayments and other current assets (21)

(14)

(19)

Accrued interest and taxes 365 48 (186)

Accounts payable and other current liabilities 2,251 588 352 Net cash provided by operating activities 3,265 829 1,458 Cash flows from financing activities:

Long-term debt issued 1,760 491 Long-term debt repaid (525)

(363)

Bonds repurchased and funds held in trust (130)

(440)

Rate reduction notes repaid (246)

(246)

(246)

Nuclear fuel financing - net (21) 9 (37)

Short-term debt financing - net 676 655 326 Dividends paid (1)

(395)

(686)

Net cash provided (used) by financing activities 278 818 (515)

Cash flows from investing activities:

Additions to property and plant (688)

(1,096)

(986)

Funding of nuclear decommissioning trusts (36)

(69)

(116)

Proceeds from sales of marketable securities 41 84 Sales of investments in other assets 12 34 19 Net cash used by investing activities (712)

(1,090)

(999)

Net increase (decrease) in cash and equivalents 2,831 557 (56)

Cash and equivalents, beginning of year 583 26 82 Cash and equivalents, end of year

$3,414

$ 583

$ 26 Cash payments for interest and taxes:

Interest - net of amounts capitalized Tax payments (receipts) 455 (105)

$ 303 306

$ 287 433 The accompanying notes are an integral part of these financial statements.

24

Consolidated Statements of Changes in Common Southern California Edison Company Shareholder's Equity Accumulated Total Additional Other Retained Common Common Paid-in Comprehensive Earnings Shareholder's In millions Stock Capital Income (Loss)

(Deficit)

Equity Balance at December 31, 1998

$2,168

$334

$ 39 794

$ 3,335 Net income 509 509 Unrealized gain on securities 46 46 Tax effect (18)

(18)

Reclassified adjustment for gain included in net income (77)

(77)

Tax effect 32 32 Dividends declared on common stock (666)

(666)

Dividends declared on preferred stock (25)

(25)

Stock option appreciation (3)

(3)

Capital stock expense and other 1

(1)

Balance at December 31, 1999

$ 2,168

$ 335

$ 22 608

$ 3,133 Net income (loss)

(2,028)

(2,028)

Unrealized gain on securities 8

8 Tax effect (5)

(5)

Reclassified adjustment for gain included in net income (41)

(41)

Tax effect 16 16 Dividends declared on common stock (279)

(279)

Dividends declared on preferred stock (22)

(22)

Stock option appreciation (1)

(1)

Capital stock expense and other (1)

(1)

Balance at December 31, 2000

$ 2,168

$ 334

$(1,722)

$ 780 Net income 2,408 2,408 Cumulative effect of change in accounting for derivatives 398 398 Unrealized loss on cash flow hedges (420)

(420)

Dividends accrued on preferred stock (22)

(22)

Capital stock expense and other 2

2 Balance at December 31, 2001

$2,168

$336

$(22) 664

$ 3,146 Authorized common stock is 560 million shares with no par value.

The accompanying notes are an integral part of these financial statements.

25

Notes to Consolidated Financial Statements Note 1. Summary of Significant Accounting Policies Nature of Operations Southern California Edison Company (SCE) is a rate-regulated electric utility that supplies electric energy to a 50,000 square-mile area of central, coastal and southern California.

SCE operates in a highly regulated environment and has an exclusive franchise within its service territory.

SCE has an obligation to deliver electric service to its customers and regulatory authorities have an obligation to provide just and reasonable rates. In the mid-1 990s, state lawmakers and the California Public Utilities Commission (CPUC) initiated an electric industry restructuring process. SCE, as directed by the CPUC, sold its gas-fired generating stations. See Note 3 for a further discussion of regulatory changes in the electric utility industry.

Basis of Presentation The consolidated financial statements include SCE and its subsidiaries. Intercompany transactions have been eliminated. Certain prior-year amounts were reclassified to conform to the December 31, 2001, financial statement presentation.

SCE's accounting policies conform to accounting principles generally accepted in the United States, including the accounting principles for rate-regulated enterprises, which reflect the rate-making policies of the CPUC and the Federal Energy Regulatory Commission (FERC). Since 1997, as a result of industry restructuring legislation enacted by the State of California and related changes in the rate recovery of generation-related assets, SCE has used accounting principles applicable to enterprises in general for its investment in generation facilities.

Financial statements prepared in compliance with accounting principles generally accepted in the United States require management to make estimates and assumptions that affect the amounts reported in the financial statements and disclosure of contingencies. Actual results could differ from those estimates.

Certain significant estimates related to regulatory matters, financial instruments, decommissioning and contingencies are further discussed in Notes 3, 4, 11 and 12 to the Consolidated Financial Statements, respectively.

SCE's outstanding common stock is owned entirely by its parent company, Edison International.

Revenue Operating revenue includes amounts for services rendered but unbilled at the end of each year. Since January 17, 2001, power purchased by the California Department of Water Resources (CDWR) or through the Independent System Operator (ISO) for SCE's customers is not considered a cost to SCE, since SCE is acting as an agent for these transactions. Further, amounts billed to ($2.0 billion in 2001) and collected from its customers for these power purchases are being remitted to the CDWR and are not recognized as revenue to SCE. See further discussion in Note 3.

Related Party Transactions Certain Edison Mission Energy (a wholly owned subsidiary of Edison International) subsidiaries have 49% - 50% ownership in partnerships (qualifying facilities (QFs)) that sell electricity generated by their project facilities to SCE under long-term power purchase agreements with terms and pricing approved by the CPUC. SCE's purchases from these partnerships were $983 million in 2001, $716 million in 2000 and

$513 million in 1999.

26

Southern California Edison Company Purchased Power SCE purchased power through the California Power Exchange (PX) from April 1998 through mid-January 2001. SCE has bilateral forward contracts with other entities (as discussed in Note 4) and power purchase contracts with other utilities and independent power producers classified as QFs. Purchased power detail is provided below:

In millions PX/ISO:

Purchases Generation sales Year ended December 31.

Purchased power - PX/ISO - net Purchased power - bilateral contracts Purchased power - interutility/QF contracts Total 2001 775 324 451 188 3.131 2000

$ 8,449 6,120 2,329 2.358 1999

$ 2,490 1,719 771 2.419

$3,770

$4,687

$3,190 Since January 17, 2001, all other power is purchased by the CDWR for delivery to SCE's customers and is not considered a cost to SCE.

Planned Major Maintenance Certain plant facilities require major maintenance on a periodic basis. All such costs are expensed as incurred.

Other Nonoperating Income and Deductions Other nonoperating income and deductions was comprised of:

In millions Year ended December 31, 2001 2000 1999 Gain on sale of marketable securities

$ 41

$ 77 AFUDC 16 21 24 Other 41 56 61 Total other nonoperating income

$ 57

$118

$162 Provisions for regulatory issues and refunds 7

$ 78

$ 79 Other 31 32 28 Total other nonoperating deductions

$ 38

$110

$107 Cash Equivalents Cash equivalents include time deposits and other investments with original maturities of three months or less.

All investments are classified as available for sale.

Fuel Inventory Fuel inventory is valued under the last-in, first-out method for fuel oil and under the first-in, first-out method for coal.

Investments Net unrealized gains (losses) on equity investments are recorded as a separate component of shareholder's equity under the caption "Accumulated other comprehensive income." Unrealized gains and losses on decommissioning trust funds are recorded in the accumulated provision for decommissioning.

All investments are classified as available-for-sale.

27

Notes to Consolidated Financial Statements Utility Plant Utility plant additions, including replacements and betterments, are capitalized. Such costs include direct material and labor, construction overhead and an allowance for funds used during construction (AFUDC).

AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction.

AFUDC is capitalized during plant construction and reported in current earnings in other nonoperating income. AFUDC is recovered in rates through depreciation expense over the useful life of the related asset. Depreciation of utility plant is computed on a straight-line, remaining-life basis.

AFUDC - equity was $7 million in 2001, $11 million in 2000 and $13 million in 1999. AFUDC - debt was

$9 million in 2001, $10 million in 2000 and $11 million in 1999.

Replaced or retired property and removal costs less salvage are charged to the accumulated provision for depreciation. Depreciation expense stated as a percent of average original cost of depreciable utility plant was 3.6% for 2001, 2000 and 1999.

SCE's net investment in generation-related utility plant was $1.0 billion at both December 31, 2001, and December 31, 2000.

Nuclear During the second quarter of 1998, SCE reduced its remaining nuclear plant investment by $2.6 billion (book value as of June 30, 1998) and recorded a regulatory asset on its balance sheet for the same amount in accordance with asset impairment accounting standards. For this impairment assessment, the fair value of the investment was calculated by discounting expected future net cash flows. The reclassification had no effect on SCE's 1998 results of operations.

SCE had been recovering its investments in San Onofre Nuclear Generating Station Units 2 and 3 and Palo Verde Nuclear Generating Station on an accelerated basis, as authorized by the CPUC. The accelerated recovery was to continue through December 2001, earning a 7.35% fixed rate of return on investment. San Onofre's operating costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, were recovered through an incentive pricing plan that allows SCE to receive about 40 per kilowatt-hour through 2003. Any differences between these costs and the incentive price would flow through to the shareholders. Palo Verde's accelerated plant recovery, as well as operating costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, were subject to balancing account treatment through December 31, 2001. The San Onofre and Palo Verde rate recovery plans and the Palo Verde balancing account were part of the transition cost balancing account (TCBA).

The nuclear rate-making plans and the TCBA mechanism were to continue for rate-making purposes at least through 2001 for Palo Verde operating costs and through 2003 for the San Onofre incentive pricing plan. However, due to the various unresolved regulatory and legislative issues (as discussed in Note 3),

as of December 31, 2000, SCE was no longer able to conclude that the unamortized nuclear investment was probable of recovery through the rate-making process. As a result, this balance was written off as a charge to earnings at that time. Should SCE's utility-retained generation (URG) application be approved, SCE would reestablish for financial reporting purposes its unamortized nuclear investment and related flow-through taxes, retroactive to August 31, 2001, based on a 10-year recovery period, effective January 1, 2001, with a corresponding credit to earnings, and adjust the PROACT regulatory asset balance to reflect recovery of the nuclear investment in accordance with the final URG decision.

The benefits of operation of the Palo Verde and San Onofre units were required to be shared equally with ratepayers beginning in 2002 and 2004, respectively. In a June 2001 decision, the CPUC granted SCE's request to eliminate the San Onofre post-2003 benefit sharing mechanism. The CPUC based its action on compliance with a new state law. In a September 2001 decision, the CPUC granted SCE's request to eliminate the Palo Verde post-2001 benefit sharing mechanism and to continue the current rate-making treatment for Palo Verde, including the continuation of the existing nuclear unit incentive procedure with a 28

Southern California Edison Company 50 per kWh cap on replacement power costs, until resolution of SCE's next general rate case or further CPUC action. Palo Verde's existing nuclear unit incentive procedure calculates a reward for performance of any unit above an 80% capacity factor for a fuel cycle. See discussion in Note 3 for the proposed and alternate decisions' impact on the incentive pricing plans.

Regulatory Assets and Liabilities In accordance with accounting principles for rate-regulated enterprises, SCE records regulatory assets, which represent probable future revenue associated with certain costs that will be recovered from customers through the rate-making process, and regulatory liabilities, which represent probable future reductions in revenue associated with amounts that are to be credited to customers through the rate making process.

The TCBA was established for the recovery of generation-related transition costs during the four-year rate freeze period. The transition revenue account (TRA) was a CPUC-authorized regulatory asset account in which SCE recorded the difference between revenue received from customers through frozen rates and the costs of providing service to customers, including power procurement costs. SCE's discontinuance of accounting principles for rate-regulated enterprises applicable to its generation assets did not result in a write-off of its generation-related regulatory assets at that time since the CPUC had approved recovery of these assets through the TCBA mechanism.

The gains resulting from the sale of 12 of SCE's generating plants during 1998 have been credited to the TCBA. The coal and hydroelectric generation balancing accounts tracked the differences between market revenue from coal and hydroelectric generation and the plants' operating costs after April 1, 1998.

On March 27, 2001, the CPUC issued a decision stating, among other things, that the rate freeze had not ended, and the TCBA mechanism was to remain in place. However, the decision required SCE to recalculate the TCBA retroactive to January 1, 1998, the beginning of the rate freeze period. The new calculation required the coal and hydroelectric balancing account overcollections (which amounted to

$1.5 billion as of December 31, 2000) to be transferred monthly to the TRA, rather than annually to the TCBA (as previously required). In addition, it required the TRA to be transferred to the TCBA on a monthly basis. Previous rules had called only for overcollections to be transferred to the TCBA monthly, while undercollections were to remain in the TRA until they were recovered from future overcollections or the end of the rate freeze, whichever came first.

There are many factors that affect SCE's ability to recover its regulatory assets. SCE assessed the probability of recovery of its generation-related regulatory assets in light of the CPUC's March 27, 2001, decisions, including the retroactive transfer of balances from SCE's TRA to the TCBA and related changes. These decisions and other regulatory and legislative actions did not meet SCE's prior expectation that the CPUC would provide adequate cost recovery mechanisms. SCE was unable to conclude that its generation-related regulatory assets were probable of recovery through the rate-making process as of December 31, 2000. Therefore, in accordance with accounting rules, SCE recorded a

$2.5 billion after-tax charge to earnings at that time, to write off the TCBA and other regulatory assets.

In addition to the TCBA, generation-related regulatory assets totaling $1.3 billion (including the unamortized nuclear investment, flow-through taxes, unamortized loss on sale of plant, purchased-power settlements and other regulatory assets) were written off as of December 31, 2000.

In accordance with an October 2001 settlement agreement between the CPUC and SCE, the CPUC passed a resolution on January 23, 2002, allowing SCE to establish the procurement-related obligations account (PROACT) regulatory asset for previously incurred energy procurement costs, retroactive to August 31, 2001. The settlement agreement calls for the end of the TCBA mechanism as of August 31, 2001, and continuation of the rate freeze (including surcharges) until the earlier of December 31, 2003, or the date SCE recovers its previously incurred (undercollected) power procurement costs. During a period beginning on September 1, 2001, and ending on the earlier of the date that SCE has recovered all of its procurement-related obligations recorded in the PROACT or December 31, 2005, SCE will apply to the 29

Notes to Consolidated Financial Statements PROACT the difference between SCE's revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the CPUC to recover in retail electric rates. The balance in the PROACT will accrue interest. If SCE has not recovered the entire balance by December 31, 2003, the unrecovered balance will be amortized for up to an additional two years.

Regulatory assets, less regulatory liabilities, included in the consolidated balance sheets are:

In millions December 31, 2001 2000 PROACT

$ 2,641 S

Rate reduction notes - transition cost deferral 1,453 1,090 Other:

Flow-through taxes 1,017 874 Unamortized loss on reacquired debt 254 273 Environmental remediation 57 52 Regulatory balancing accounts and other 189 (94)

Total

$5,611

$2,195 The regulatory asset related to the rate reduction notes will be recovered over the terms of those notes.

The other regulatory assets and liabilities are being recovered through other components of electric rates.

Balancing account undercollections and overcollections accrue interest based on a three-month commercial paper rate published by the Federal Reserve. Income tax effects on all balancing account changes are deferred.

New Accounting Standards On January 1, 2001, SCE adopted a new accounting standard for derivative instruments and hedging activities. Adoption of this standard had no material impact on SCE's financial statements. An authoritative accounting interpretation issued in October 2001 precludes fuel contracts that have variable amounts from qualifying under the normal purchases and sales exception effective April 1, 2002. SCE is still evaluating the impact of this new interpretation.

In July and August 2001, three new accounting standards were issued: Business Combinations; Goodwill and Other Intangibles; and Accounting for Asset Retirement Obligations.

The new Business Combinations standard eliminates the pooling-of-interests method, effective June 30, 2001. After that, all business combinations will be recorded under the purchase method (record goodwill for excess of costs over the net assets acquired).

The new Goodwill and Other Intangibles standard requires that companies cease amortizing goodwill, effective January 1, 2002. Goodwill initially recognized after June 30, 2001, was not amortized. Goodwill on the balance sheet at June 30, 2001, was amortized until December 31, 2001. Under the new standard, goodwill will be tested for impairment using a fair-value approach when events or circumstances occur indicating that impairment might exist. Also, a benchmark assessment for goodwill is required within six months of the date of adoption of the standard.

The Accounting for Asset Retirement Obligations standard requires entities to record the fair value of a liability for a legal asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for SCE on January 1, 2003.

30

Southern California Edison Company SCE is studying the impact of the new Asset Retirement Obligations standard, and is unable to predict at this time the effect on its financial statements. SCE does not anticipate any material impact on its results of operations or financial position from the Business Combinations and Goodwill and Other Intangibles accounting standards.

In October 2001, a new accounting standard was issued related to accounting for the impairment or disposal of long-lived assets. Although the standard supersedes a prior accounting standard related to the impairment of long-lived assets, it retains the fundamental provisions of the impairment standard regarding recognition/measurement of impairment of long-lived assets to be held and used and measurement of long-lived assets to be disposed of by sale. Under the new accounting standard, asset write-downs from discontinuing a business segment will be treated the same as other assets held for sale.

The new standard also broadens the financial statement presentation of discontinued operations to include the disposal of an asset group (rather than a segment of a business). The standard (effective on January 1, 2002) was adopted early, in fourth quarter 2001. The adoption of this new standard had no effect on SCE's financial statements.

Note 2. Liquidity Issues SCE's liquidity is affected primarily by regulation affecting its ability to recover the cost of power purchases, debt maturities, access to capital markets, credit ratings, dividend payments and capital expenditures. Capital resources include cash from operations and external financings.

Undercollections in the TRA and TCBA mechanisms, coupled with SCE's anticipated near-term capital requirements and the adverse reaction of the credit markets to continued regulatory uncertainty regarding SCE's ability to recover its current and future power procurement costs, materially and adversely affected SCE's liquidity throughout 2001. As a result of its liquidity concerns, SCE took steps to conserve cash to continue to provide service to its customers. As a part of this process, beginning in January 2001, SCE suspended payments owed to the ISO, the PX and QFs, deferred payments of certain obligations for principal and interest on outstanding debt and did not declare dividends on any of its cumulative preferred stock. As applicable, unpaid obligations continued to accrue interest. As of March 31, 2001, SCE resumed payment of interest on its debt obligations. However, since June 30, 2001, SCE deferred the interest payments on its quarterly income debt securities (subordinated debentures), as allowed by the terms of the securities. See Note 5. As long as accumulated dividends on SCE's preferred stock remained unpaid, SCE could not pay any dividends on its common stock. Common stock dividends are additionally restricted as detailed in Note 3.

Based on the rights to cost recovery and revenue established by the settlement agreement with the CPUC and CPUC implementing orders, including the PROACT resolution, SCE repaid its undisputed past-due obligations on March 1, 2002, with lump-sum payments to creditors from the proceeds of $1.6 billion in senior secured credit facilities, the remarketing of $196 million in pollution control bonds which were repurchased in late 2000, and existing cash on hand. The $1.6 billion senior secured credit facilities consist of a $300 million, two-year revolving credit loan, a $600 million, one-year loan and a $700 million, three-year loan. See Note 5.

The proceeds from the senior secured credit facilities and pollution control bond remarketing were used along with SCE's available cash to repay $3.2 billion in past-due obligations and $1.65 billion in near-term debt maturities. The past-due obligations consisted of: (1) $875 million to the PX; (2) $99 million to the ISO; (3) $1.1 billion to QFs; (4) $193 million in PX energy credits for energy service providers; (5) $531 million of matured commercial paper; (6) $400 million of principal on its 5-7/8% and 6-1/2% senior unsecured notes which were issued prior to the energy crisis; and (7) $23 million in preferred dividends in arrears. After making these payments, SCE has no material undisputed obligations that are past due or in default. The near-term debt maturities consisted of credit facilities whose maturity dates were extended several times and were scheduled to mature in March and May 2002. In addition, SCE has entered into an agreement with the CDWR to pay for prior deliveries of energy in installments of $100 million on April 1, 2002, $150 million on June 3, 2002, and the balance on July 1, 2002.

31

Notes to Consolidated Financial Statements SCE's Board of Directors has not declared quarterly common stock dividends to SCE's parent, Edison International, since September 2000. Payment of dividends on SCE's common stock is restricted by the settlement agreement between the CPUC and SCE as detailed in Note 3.

Note 3. Regulatory Matters CPUC Litigation Settlement Agreement In November 2000, SCE filed a lawsuit against the CPUC in federal district court, seeking a ruling that SCE is entitled to full recovery of its past electricity procurement costs in accordance with the tariffs filed with the FERC. By agreement of the parties, a stay of the lawsuit was issued in April 2001 while SCE sought implementation of legislative, regulatory and executive actions to resolve the California energy crisis and SCE's related financial and liquidity problems. In October 2001, the court entered a stipulated judgment approving an agreement between the CPUC and SCE to settle the pending lawsuit. On January 23, 2002, the CPUC adopted a resolution implementing the settlement agreement.

Key elements of the settlement agreement include the following items:

"* Establishment of the PROACT as of September 1, 2001, with an opening balance equal to the amount of SCE's procurement-related liabilities as of August 31, 2001 (approximately $6.4 billion), less SCE's cash and cash equivalents as of that date (approximately $2.5 billion), and less $300 million.

Beginning September 1, 2001, SCE will apply to the PROACT, on a monthly basis, the difference between SCE's revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the CPUC to recover in retail electric rates. Unrecovered obligations in the PROACT will accrue interest from September 1, 2001.

Maintain current rates (including surcharges) in effect until December 31, 2003, subject to certain adjustments or, if earlier, until the date that SCE recovers the entire PROACT balance. If SCE has not recovered the entire balance by December 31, 2003, the unrecovered balance will be amortized for up to an additional two years. The parties project that existing retail electric rates, including surcharges and as adjusted to reflect certain costs, will likely result in SCE recovering substantially all of its unrecovered procurement-related obligations prior to the end of 2003.

"* If the CPUC concludes that it is desirable to authorize a securitized financing of SCE's procurement related obligations, the parties will work together to achieve the securitization. Proceeds of any securitization will be credited to the PROACT when they are actually received.

"* During the period that SCE is recovering its previously incurred procurement-related obligations, no penalty will be imposed by the CPUC on SCE for any noncompliance with CPUC-mandated capital structure requirements.

SCE can incur up to $250 million of recoverable costs to acquire financial instruments and engage in other transactions intended to hedge fuel cost risks associated with SCE's retained generation assets and power purchase contracts with QFs and other utilities. As of December 31, 2001, SCE had purchased $209 million in hedging instruments.

SCE will not declare or pay dividends or other distributions on its common stock (all of which is held by its parent) prior to the earlier of the date SCE has recovered all of its procurement-related obligations in the PROACT or January 1, 2005. However, if SCE has not recovered all of its procurement-related obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume common stock dividends, and the CPUC will not unreasonably withhold its consent.

32

Southern California Edison Company

"* To ensure the ability of SCE to continue to provide adequate service, SCE may make capital expenditures above the level contained in current rates, up to $900 million per year, which will be treated as recoverable costs.

Subject to certain qualifications, SCE will cooperate with the CPUC and the California Attorney General to pursue and resolve SCE's claims and rights against sellers of energy and related services, SCE's defenses to claims arising from any failure to make payments to the PX or ISO, and similar claims by the State of California or its agencies against the same adverse parties. During the recovery period discussed above, refunds obtained by SCE related to its procurement-related liabilities will be applied to the balance in the PROACT.

The settlement agreement states that one of its purposes is to restore the investment grade creditworthiness of SCE as rapidly as reasonably practicable so that it will be able to provide reliable electrical service as a state-regulated entity as it has in the past. SCE cannot provide assurance that it will regain investment grade credit ratings by any particular date.

On November 28, 2001, a federal court of appeals denied a California consumer group's request for a long-term stay of the settlement. The group had alleged that it was denied due process and that the CPUC had no authority to agree with SCE to violate the statutory rate freeze. In its ruling, the federal court of appeals also granted SCE's request for an expedited hearing of the appeal of the settlement filed by the consumer group. On March 4, 2002, the court of appeals heard argument on the appeal and the matter is now under submission. A decision could be issued anytime during the next several months.

SCE cannot predict the outcome of the appeal or the impact that any outcome would have upon the stipulated judgment or settlement. Possible outcomes include affirmance, a return to the district court or reversal of the stipulated judgment. SCE cannot predict whether or how a ruling on the stipulated judgment could also affect the settlement agreement.

CDWR Power Purchases In accordance with an emergency order signed by the governor, the CDWR began making emergency power purchases for SCE's customers on January 17, 2001. Amounts SCE bills to and collects from its customers for electric power purchased and sold by the CDWR and through the ISO are remitted directly to the CDWR and are not recognized as revenue by SCE. In February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1 X) was enacted into law. AB lX 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 bonds to finance electricity purchases.

On March 27, 2001, the CPUC issued an interim order requiring SCE to pay the CDWR a per-kWh price equal to the applicable generation-related retail rate per kWh for electricity (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 retail rate should be equal to the total bundled electric rate (including the 10 per kWh surcharge adopted by the CPUC on January 4, 2001) less certain nongeneration-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 6.277o per kWh for power delivered to SCE's customers. The CPUC determined that the applicable rate component is 7.2770 per kWh (which increased to 10.2770 per kWh for electricity delivered after March 27, 2001, due to the 30 surcharge discussed in Rate Stabilization Proceedings), for electricity delivered by the CDWR to SCE's retail customers after 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, subject to penalties for each day the payment is late.

On February 21, 2002, the CPUC issued a decision implementing a CDWR revenue requirement of

$9.0 billion to pay its bonds' costs and energy procurement costs for the period January 17, 2001, through December 31, 2002. The decision states that SCE's allocated share of this revenue requirement would be approximately $3.6 billion, and changes SCE's payment to 9.7440 per kWh for all bills rendered on or after March 15, 2002. The decision requires SCE to pay the CDWR in equal monthly installments over a 33

Notes to Consolidated Financial Statements six-month period the difference in rates between January 17, 2001, and March 15, 2002. SCE estimates that this amount is approximately $41 million.

On February 28, 2002, SCE and the CDWR executed an agreement that resolves outstanding issues relating to the payment for electric power purchased for SCE's customers through the ISO real-time market (known as imbalance energy). Under this agreement, SCE will pay the CDWR for imbalance energy previously delivered in three installments ($100 million on April 1, 2002; $150 million on June 3, 2002; and the balance on July 1, 2002).

Rate Stabilization Proceedings In January 2000, SCE filed an application with the CPUC proposing rates that would go into effect when the four-year rate freeze was to end on March 31, 2002, or earlier, depending on the pace of transition cost recovery. In December 2000, SCE filed an amended rate stabilization plan application, stating that the statutory rate freeze had ended in accordance with California law, and requesting the CPUC to approve an immediate 30% increase to be effective, subject to refund, January 4, 2001.

In January 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 covered, 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. In April 2001, the CPUC adopted an order instituting investigation that reopens the past CPUC decision authorizing the utilities to form holding companies and initiates an investigation into: whether the holding companies violated CPUC requirements to give first priority to the capital needs of their respective utility subsidiaries; whether ring-fencing actions by Edison International and PG&E Corporation and their respective nonutility affiliates also violated the requirements to give first priority to the capital needs of their utility subsidiaries; 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; any additional suspected violations of laws or CPUC rules and decisions; and whether additional rules, conditions, or other changes to the holding company decisions are necessary. The CPUC ordered testimony and briefing on these matters, which SCE filed in May and June 2001. On January 9, 2002, the CPUC issued an interim decision on the first priority condition. The decision stated that, at least under certain circumstances, the condition includes the requirement that holding companies infuse all types of capital into their respective utility subsidiaries when necessary to fulfill the utility's obligation to serve. On February 11, 2002, SCE filed an application for rehearing of the decision stating that the decision is an unlawful and erroneous attempt to rewrite the first priority condition rather than interpret it and that the decision could result in higher rates for SCE's customers. Neither Edison International nor SCE can predict what effects this investigation or any subsequent actions by the CPUC may have on either one of them.

In March 2001, the CPUC ordered a rate increase in the form of a 3¢ per kWh surcharge applied only to going-forward electric power procurement costs, effective immediately, and affirmed that a 1 o interim surcharge granted in January 2001 is permanent. The 3o surcharge is to be added to the rate paid to the CDWR. Although the 30 increase was authorized as of March 27, 2001, the surcharge was not collected in rates until the CPUC established a rate design in early June 2001. To compensate for the two-month delay in collecting the 30 surcharge, the CPUC authorized an additional 1/2 surcharge for a 12-month period beginning in June 2001.

Utility-Retained Generation Proceeding In June 2001, SCE filed a comprehensive proposal for new cost-of-service ratemaking for utility retained generation through the end of 2002. After that time, SCE's URG-related revenue requirement will be determined in the general rate case. The URG proposal calls for balancing accounts for SCE-owned generation, OF and interutility contracts, procurement costs and ISO charges based on either actual or CPUC-authorized revenue requirements. Under the proposal, the four new balancing accounts would be effective January 1, 2001, for capital-related costs, and February 1, 2001, for non-capital-related costs. In 34

Southern California Edison Company addition, SCE's unamortized nuclear investment would be amortized and recovered in rates over a 10-year period, effective January 1, 2001. Should this application be approved as filed, SCE expects to reestablish for financial reporting purposes its unamortized nuclear investment and regulatory assets related to purchased-power settlements and flow-through taxes, with a corresponding credit to earnings, and adjust the PROACT regulatory asset balance in accordance with the final URG decision.

On January 18, 2002, a CPUC administrative law judge issued a proposed decision and a CPUC commissioner issued an alternate proposed decision. Both the proposed and alternate proposed decisions adopt most of the elements of SCE's application, but propose eliminating an incentive pricing plan for San Onofre, effective January 1, 2002, and replacing it with balancing account treatment for San Onofre's operating costs, subject to a later reasonableness review. On February 7, 2002, another CPUC commissioner issued an alternate proposed decision recommending continuing the incentive pricing plan for San Onofre Units 2 and 3 through December 31, 2003, as originally provided in CPUC decisions adopted in early 1996. A final decision is expected in second quarter 2002.

Wholesale Electricity Markets 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. In December 2000, the FERC took limited action and failed to impose a price cap. SCE filed an emergency petition in the federal court of appeals challenging the FERC order and requesting the FERC to immediately establish cost-based wholesale rates. The court denied SCE's petition in January 2001.

In its December 2000 order, the FERC established an "underscheduling" penalty effective January 1, 2001, applicable to scheduling coordinators that do not schedule sufficient resources to supply 95% of their respective loads. In December 2001, the FERC eliminated the underscheduling penalty retroactive to January 1, 2001.

On April 25, 2001, after months of extremely high power prices, the FERC issued an order providing for energy price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve power).

The order establishes an hourly clearing price based on the costs of the least efficient generating unit during the period. Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non emergency periods and price mitigation in the 11-state western region. The latest order is in effect until September 30, 2002.

After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25, 2001, the FERC issued an order that limits potential refunds from alleged overcharges to the ISO and PX spot markets during the period from October 2, 2000, through June 20, 2001, and adopted a refund methodology based on daily spot market gas prices. An administrative law judge will conduct evidentiary hearings on this matter. SCE cannot predict the amount of any potential refunds. Under the settlement of litigation with the CPUC, refunds will be applied to the balance in the PROACT.

Note 4. Derivative Instruments and Hedging Activities SCE's risk management policy allows the use of derivative financial instruments to manage financial exposure on its investments, fluctuations in interest rates and energy prices, but prohibits the use of these instruments for speculative or trading purposes.

On January 1, 2001, SCE adopted a new accounting standard for derivative instruments and hedging activities. The standard requires derivative instruments to be recognized on the balance sheet at fair value unless they meet the definition of a normal purchase or sale. The normal purchases and sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Gains or losses from changes in the fair value of a recognized asset or liability or a firm commitment are reflected in earnings for the ineffective portion of the 35

Notes to Consolidated Financial Statements hedge. For a hedge of the cash flows of a forecasted transaction, the effective portion of the gain or loss is initially recorded as a separate component of shareholder's equity under the caption "accumulated other comprehensive income," and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the hedge is reflected in earnings immediately.

SCE recorded its interest rate swap agreement (terminated January 5, 2001) and its block forward power purchase contracts at fair value effective January 1, 2001. The realized loss of $26 million on the interest rate swap will be amortized over a period ending in 2008. Due to downgrades in SCE's credit ratings and SCE's failure to pay its obligations to the PX, the PX suspended SCE's market trading privileges and sought to liquidate SCE's remaining block forward contracts. Before the PX could do so, on February 2, 2001, the state seized the contracts. On September 30, 2001, a federal appeals court ruled that the governor of California acted illegally when he seized the contracts held by SCE. In conjunction with its settlement agreement with the CPUC, SCE has agreed to release any claim for compensation against the state for these contracts. However, if the PX prevails in its claims against the state, SCE may receive some refunds SCE has bilateral forward power contracts, which are considered normal purchases under accounting rules. SCE is exposed to credit loss in the event of nonperformance by the counterparties to its bilateral forward contracts, but does not expect the counterparties to fail to meet their obligations. The counterparties are required to post collateral depending on the creditworthiness of each counterparty.

In October and November 2001, SCE purchased $209 million of call options that mitigate its exposure to increases in natural gas prices. Amounts paid to QFs for energy are based on natural gas prices. The options cover various periods from 2002 through 2003, averaging 11 million MMBtus per month. Any fair value changes for gas call options are offset through a regulatory balancing account; therefore, fair value changes do not affect earnings.

Fair values of financial instruments were:

In millions December 31, 2001 2000 Financial assets:

Decommissioning trusts

$ 2,275

$ 2,505 Gas options 91 Financial liabilities:

DOE decommissioning and decontamination fees 25 31 Interest rate swap 21 Short-term debt 2,103 1,339 Long-term debt 4,659 5,178 Preferred stock subject to mandatory redemption 118 157 Preferred stock to be redeemed within one year 102 The fair value of financial assets is based on quoted market prices.

Financial liabilities' fair values are based on: discounted future cash flows for U.S. Department of Energy (DOE) decommissioning and decontamination fees; quoted market prices for the interest rate swap; and brokers' quotes for short-term debt, long-term debt and preferred stock. Due to their short maturities, amounts reported for cash equivalents approximate fair value.

Note 5. Long-Term Debt California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates.

36

Southern California Edison Company Almost all SCE properties are subject to a trust indenture lien. SCE has pledged first and refunding mortgage bonds as security for borrowed funds obtained from pollution control bonds issued by government agencies. SCE uses these proceeds to finance construction of pollution control facilities.

Bondholders have limited discretion in redeeming certain pollution-control bonds, and SCE has arrangements with securities dealers to remarket or purchase them if necessary. As a result of investors' concerns regarding SCE's liquidity difficulties and overall financial condition, SCE had to repurchase

$550 million of pollution control bonds in December 2000 and early 2001 that could not be remarketed in accordance with their terms. On March 1, 2002, SCE sold approximately $196 million of the pollution control bonds that SCE had repurchased in late 2000.

Debt premium, discount and issuance expenses are amortized over the life of each issue. Under CPUC rate-making procedures, debt reacquisition expenses are amortized over the remaining life of the reacquired debt or, if refinanced, the life of the new debt.

Commercial paper intended to be refinanced for a period exceeding one year, for which SCE has the ability to refinance, and used to finance nuclear fuel scheduled to be used more than one year after the balance sheet date is classified as long-term debt.

In December 1997, $2.5 billion of rate reduction notes were issued on behalf of SCE by SCE Funding LLC, a special purpose entity. These notes were issued to finance the 10% rate reduction mandated by state law. The proceeds of the rate reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable right known as transition property. Transition property is a current property right created by the restructuring legislation and a financing order of the CPUC and consists generally of the right to be paid a specified amount from non-bypassable rates charged to residential and small commercial customers. The rate reduction notes are being repaid over 10 years through these non-bypassable residential and small commercial customer rates which constitute the transition property purchased by SCE Funding LLC. The notes are secured by the transition property and are not secured by, or payable from, assets of SCE or Edison International. SCE used the proceeds from the sale of the transition property to retire debt and equity securities. Although, as required by accounting principles generally accepted in the United States, SCE Funding LLC is consolidated with SCE and the rate reduction notes are shown as long-term debt in the consolidated financial statements, SCE Funding LLC is legally separate from SCE. The assets of SCE Funding LLC are not available to creditors of SCE or Edison International and the transition property is legally not an asset of SCE or Edison International. Due to SCE's credit downgrade, in January 2001, SCE began remitting its customer collections related to the rate-reduction notes on a daily basis.

Long-term debt consisted of:

In millions December 31, 2001 2000 First and refunding mortgage bonds:

2002 - 2026 (5.625% to 7.25%)

$1,175

$1,175 Rate reduction notes:

2002 - 2007 (6.22% to 6.42%)

1,478 1,724 Pollution-control bonds:

2008 - 2040 (5.125% to 7.2% and variable) 1,216 1,216 Bonds repurchased (550)

(420)

Funds held by trustees (20)

(20)

Debentures and notes:

2001 - 2029 (5.875% to 7.625% and variable) 2,450 2,450 Subordinated debentures:

2044 (8.375%)

100 100 Commercial paper for nuclear fuel 60 79 Long-term debt due within one year (1,146)

(646)

Unamortized debt discount - net (24)

(27)

Total

$4,739

$5,631 37

Notes to Consolidated Financial Statements Long-term debt maturities and sinking-fund requirements for the next five years are: 2002 - $1.1 billion; 2003 - $1.4 billion; 2004 - $371 million; 2005 - $246 million; and 2006 - $446 million.

As a result of its liquidity concerns, SCE took steps to conserve cash to continue to provide service to its customers. As a part of this process, SCE suspended payments of certain obligations, including

$400 million of maturing principal on its 5-7/8% and 6-1/2% senior unsecured notes. From June 30, 2001, SCE deferred the interest payments on its quarterly income debt securities (subordinated debentures), as allowed by the terms of the securities. All interest in arrears will be paid on April 1, 2002.

On March 1, 2002, SCE closed on $1.6 billion in syndicated senior secured credit facilities providing for

$600 million of one-year term loans, $700 million of three-year term loans, and $300 million of two-year revolving credit loans. The interest rate for the revolving credit loans and the one-year loan is a eurodollar rate plus 2.5% or a bank prime or equivalent rate plus 1.5%, at SCE's election. The interest rate for the three-year loans is a eurodollar rate plus 3% or a bank prime or equivalent rate plus a margin of 2%, at SCE's election. The credit facilities are secured by three newly issued series of SCE first mortgage bonds. The proceeds of the loans, along with available cash, were used to repay all of SCE's past due obligations and near-term maturities, which include the senior notes.

Note 6. Short-Term Debt Short-term debt is used to finance fuel inventories, balancing account undercollections and general cash requirements, including power purchase payments. Commercial paper intended to finance nuclear fuel scheduled to be used more than one year after the balance sheet date is classified as long-term debt in connection with refinancing terms under five-year term lines of credit with commercial banks.

Short-term debt consisted of:

In millions December 31, 2001 2000 Commercial paper

$ 531

$ 700 Bank loans 1,650 835 Other 6

Amount reclassified as long-term debt (60)

(79)

Unamortized discount (5)

Total

$2,127

$1,451 Weighted average interest rates 5.3%

6.9%

As of January 2001, SCE had borrowed the entire $1.65 billion in funds available under its credit lines. The proceeds were used in part to repurchase pollution control bonds; the balance was retained as a liquidity reserve. SCE conserved cash by deferring payment of $531 million of matured commercial paper.

SCE repaid its credit line borrowings and commercial paper using proceeds from its March 1, 2002, financings. See further discussion in Note 2.

Note 7. Preferred Stock Authorized shares of preferred and preference stocks are: $25 cumulative preferred - 24 million;

$100 cumulative preferred - 12 million; and preference-50 million. All cumulative preferred stocks are redeemable. Mandatorily redeemable preferred stocks are subject to sinking-fund provisions. When preferred shares are redeemed, the premiums paid are charged to common equity.

Preferred stock redemption requirements for the next five years are: 2002 - $105 million; 2003

$9 million; 2004 - $9 million; 2005 - $9 million; and 2006 - $9 million.

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Southern California Edison Company Cumulative preferred stocks consisted of:

Dollars in millions, except per share amounts December 31, 2001 2000 December 31, 2001 Shares Redemption Outstanding Price Not subject to mandatory redemption:

$25 par value:

4.08% Series 1,000,000

$ 25.50

$ 25

$ 25 4.24 1,200,000 25.80 30 30 4.32 1,653,429 28.75 41 41 4.78 1,296,769 25.80 33 33 Total

$129

$129 Subject to mandatory redemption:

$100 par value:

6.05% Series 750,000

$100.00

$ 75

$ 75 6.45 1,000,000 100.00 100 100 7.23 807,000 100.00 81 81 Preferred stock to be redeemed within one year (105)

Total

$151

$256 SCE did not issue or redeem any preferred stock in the last three years.

In 2001, SCE's Board did not declare the regular quarterly dividends for any of SCE's cumulative preferred stock. As of February 28, 2002, SCE's preferred stock dividends in arrears were $23 million. On March 11, 2002, SCE repaid its past due preferred stock dividends.

Note 8. Income Taxes SCE and its subsidiaries are included in Edison International's consolidated federal income tax and combined state franchise tax returns. Under an income tax allocation agreement approved by the CPUC, SCE calculates its tax liability on a stand-alone basis.

Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Investment tax credits are amortized over the lives of the related properties.

39

Notes to Consolidated Financial Statements The components of the net accumulated deferred income tax liability were:

In millions December 31, 2001 2000 Deferred tax assets:

Decommissioning 99 98 Accrued charges 472 379 investment tax credits 72 81 Property-related 192 277 Regulatory balancing accounts 1,709 1,763 Unbilled revenue

10) 1 01 Unrealized gains or losses (10) 101 Other 310 420 othe 145 56 Total

$ 2,989

$ 3,175 Deferred tax liabilities:

Property-related

$ 2,248

$ 2,184 Capitalized software costs 224 264 Regulatory balancing accounts 229 163 Unrealized gains and losses 2,929 1,632 Other 208 317 othe 312 242 Total

$ 5,921

$ 4,639 Accumulated deferred income taxes - net

$ 2,932

$ 1,464 Classification of accumulated deferred income taxes:

Included in deferred credits

$ 3,365

$ 2,009 Included in current assets 433 545 The current and deferred components of income tax expense (benefit) were:

In millions Year ended December 31, 2001 2000 1999 Current:

Federal 240

$ (104)

$ 299 State 29 79 269 (104) 378 Deferred - federal and state:

Accrued charges (79)

(133)

(76)

Investment and energy tax credits - net (6)

(41)

(45)

Property-related 174 (302)

(194)

Regulatory asset amortization (138) 251 7

Regulatory balancing accounts 1,345 (740) 371 State tax - privilege year (36) 31 7

Unbilled revenue 101 20 (5)

Other 28 (4)

(5) 1,389 (918) 60 Total

$1,658

$(1,022)

$ 438 The composite federal and state statutory income tax rate was 40.551% for all years presented.

40

Southern California Edison Company The federal statutory income tax rate is reconciled to the effective tax rate below:

Year ended December 31, Federal statutory rate Capitalized software Investment and energy tax credits Property-related and other State tax - net of federal deduction Effective tax rate 2001 35.0%

(0.1) 0.1 5.8 2000 35.0%

1.4 (6.6) 3.7 508%3 1999 35.0%

(2.4)

(4.4) 9.3 8.5 Note 9. Employee Compensation and Benefit Plans Employee Savings Plan SCE has a 401 (k) defined-contribution savings plan designed to supplement employees' retirement income. The plan received employer contributions of $29 million in 2001, $29 million in 2000 and

$25 million in 1999.

Pension Plan SCE has a noncontributory, defined-benefit pension plan that covers employees meeting minimum service requirements. SCE recognizes pension expense as calculated by the actuarial method used for ratemaking. In April 1999, SCE adopted a cash balance feature for its pension plan.

Information on plan assets and benefit obligations is shown below:

In millions Year ended December 31, 2001 2000 Change in benefit obligation Benefit obligation at beginning of year

$ 2,200

$ 2,075 Service cost 67 63 Interest cost 154 155 Actuarial loss (gain) 88 90 Benefits paid (182)

(183)

Benefit obligation at end of year

$2,327

$ 2,200 Change in plan assets Fair value of plan assets at beginning of year

$ 3,067

$ 3,078 Actual return on plan assets (162) 143 Employer contributions 29 Benefits paid (182)

(183)

Fair value of plan assets at end of year

$2,723

$ 3,067 Funded status

$ 396

$ 867 Unrecognized net loss (gain)

(234)

(745)

Unrecognized transition obligation 17 22 Unrecognized prior service cost 109 118 Recorded asset

$ 288 262 Discount rate Rate of compensation increase Expected return on plan assets 7.0%

5.0%

8.5%

7.25%

5.0%

8.5%

41 Southern California Edison Company 40.8 40.8%

33.5%

463.0~

Notes to Consolidated Financial Statements Expense components were:

in millions Year ended December 31, 2001 2000 1999 Service cost 67 63 66 Interest cost 154 155 146 Expected return on plan assets (251)

(266)

(188)

Special termination benefits 13 Net amortization and deferral (9)

(40) 12 Expense under accounting standards (26)

(88) 36 Regulatory adjustment - deferred 39 88 14 Total expense recognized 13 50 Postretirement Benefits Other Than Pensions Employees retiring at or after age 55 with at least 10 years of service are eligible for postretirement health and dental care, life insurance and other benefits.

Information on plan assets and benefit obligations is shown below:

In millions Year ended December 31, 2001 2000 Change in benefit obligation Benefit obligation at beginning of year

$1,762

$1,462 Service cost 44 39 Interest cost 129 121 Actuarial loss (gain) 61 202 Benefits paid (71)

(62)

Benefit obligation at end of year

$1,925

$1,762 Change in plan assets Fair value of plan assets at beginning of year

$1,200

$1,283 Actual return on plan assets (92)

(40)

Employer contributions 102 19 Benefits paid (71)

(62)

Fair value of plan assets at end of year

$1,139

$1,200 Funded status

$ (786)

$ (562)

Unrecognized net loss (gain) 390 141 Unrecognized transition obligation 295 323 Recorded asset (liability)

$ (101)

(98)

Discount rate 7.25%

7.5%

Expected return on plan assets 8.2%

8.2%

Expense components were:

In millions Year ended December 31, 2001 2000 1999 Service cost 44 39 46 interest cost 129 121 109 Expected return on plan assets (98)

(106)

(79)

Special termination benefits 2

Net amortization and deferral 27 27 27 Total expense 104 81 103 The assumed rate of future increases in the per-capita cost of health care benefits is 10.5% for 2002, gradually decreasing to 5.0% for 2008 and beyond. Increasing the health care cost trend rate by one 42

Southern California Edison Company percentage point would increase the accumulated obligation as of December 31, 2001, by $300 million and annual aggregate service and interest costs by $33 million. Decreasing the health care cost trend rate by one percentage point would decrease the accumulated obligation as of December 31, 2001, by

$243 million and annual aggregate service and interest costs by $26 million.

Stock Options and Other Equity-Based Awards In 1998, Edison International shareholders approved the Edison International equity compensation plan, replacing the long-term incentive compensation program that had been adopted by Edison International shareholders in 1992. The 1998 plan authorizes a limited annual award of Edison International common shares and options on shares. The annual authorization is cumulative, allowing subsequent issuance of previously unutilized awards. In May 2000, the Edison International Board of Directors adopted an additional plan, the 2000 equity plan, under which the special options discussed below were awarded.

Under the 1992, 1998 and 2000 plans, options on 4.9 million shares of Edison International common stock are currently outstanding to officers and senior managers.

Each option may be exercised to purchase one share of Edison International common stock, and is exercisable at a price equivalent to the fair market value of the underlying stock at the date of grant.

Options expire 10 years after date of grant, and vest over a period of up to five years.

Edison International stock options awarded prior to 2000 include a dividend equivalent feature. Dividend equivalents on stock options issued after 1993 and prior to 2000 are accrued to the extent dividends are declared on Edison International common stock, and are subject to reduction unless certain performance criteria are met. Only a portion of 1999 Edison International stock option awards include a dividend equivalent feature.

Options issued after 1997 generally have a four-year vesting period. The special options granted in 2000 vest over five years, but vesting does not begin until May 2002. Earlier options had a three-year vesting period with one-third of the total award vesting annually. If an option holder retires, dies, is terminated by the company, or is terminated while permanently and totally disabled (qualifying event) during the vesting period, the unvested options will vest on a pro rata basis.

Unvested options of any person who has served in the past on the SCE management committee (which was dissolved in 1993) will vest and be exercisable upon a qualifying event. If a qualifying event occurs, the vested options may continue to be exercised within their original terms by the recipient or beneficiary except that in the case of termination by the company where the option holder is not eligible for retirement, vested options are forfeited unless exercised within one year of termination date. If an option holder is terminated other than by a qualifying event, options which had vested as of the prior anniversary date of the grant are forfeited unless exercised within 180 days of the date of termination. All unvested options are forfeited on the date of termination.

The fair value for each option granted, reflecting the basis for the above pro forma disclosures, was determined on the date of grant using the Black-Scholes option-pricing model. The following assumptions were used in determining fair value through the model:

December 31, 2001 2000 Expected life 7 years - 10 years 7 years - 10 years Risk-free interest rate 4.7% - 6.1%

4.7% - 6.0%

Expected volatility 17% - 52%

17% - 46%

The application of fair-value accounting to calculate the pro forma disclosures above is not an indication of future income statement effects. The pro forma disclosures do not reflect the effect of fair-value accounting on stock-based compensation awards granted prior to 1995.

43

Notes to Consolidated Financial Statements The weighted-average fair value of options granted during 2001 and 2000 was $4.53 per share option and

$5.50 per share option, respectively. The weighted-average remaining life of options outstanding as of December 31, 2001, and December 31, 2000, was 6 years and 7 years, respectively.

For the years after 1999, a portion of the executive long-term incentives was awarded in the form of performance shares. The 2000 performance shares were restructured as retention incentives in December 2000, which pay as a combination of Edison International common stock and cash if the executive remains employed at the end of the performance period. The performance period ended December 31, 2001, for half of the award, and ends on December 31, 2002, for the remainder. Additional performance shares were awarded in January 2001 and January 2002. The 2001 performance shares vest December 31, 2003, half in shares of Edison International common stock and half in cash. The 2002 performance shares vest December 31, 2004, also half in shares of common stock and half in cash. The number of shares that will be paid out from the 2002 performance share awards will depend on the performance of Edison International common stock relative to the stock performance of a specified group of peer companies.

The 2000 and 2001 performance shares and deferred stock unit values are accrued ratably over a three year performance period. The 2002 performance shares will be valued based on Edison International's stock performance relative to the stock performance of other such entities.

In March 2001, deferred stock units were awarded as part of a retention program. These vest and will be paid between March 12, 2002, and March 12, 2003, depending on performance. The deferred stock units are payable on the vesting date in shares of Edison International common stock.

In October 2001, a stock option retention exchange offer was extended, offering holders of Edison International stock options granted in 2000 the opportunity to exchange those options for a lesser number of deferred stock units. The exchange ratio was based on the Black-Scholes value of the options and the stock price at the time the offer was extended. The exchange took place in November 2001; the options that participants elected to exchange were cancelled, and deferred stock units were issued.

Approximately three options were cancelled for each deferred stock unit issued. The deferred stock units will vest 25% per year over four years, with the first vesting date in November 2002. The following assumptions were used in determining fair value through the Black-Scholes option-pricing model:

expected life: 8-9 years; risk-free interest rate: 5.10%; expected volatility: 52%.

SCE measures compensation expense related to stock-based compensation by the intrinsic value method.

Compensation expense recorded under the stock-compensation program was $1 million in 2001, $4 million in 2000 and $5 million in 1999.

Stock-based compensation expense under the fair-value method of accounting would have resulted in pro forma net income (loss) available for common stock of $2.383 billion for 2001, $(2.054) billion for 2000 and

$484 million for 1999.

Note 10. Jointly Owned Utility Projects SCE owns interests in several generating stations and transmission systems for which each participant provides its own financing. SCE's share of expenses for each project is included in the consolidated statements of income.

44

Southern California Edison Company The investment in each project as of December 31, 2001, was:

Investment in Accumulated Depreciation and Ownership In millions Facility Amortization in[eres[

Transmission systems:

Eldorado 41 11 60%

Pacific Intertie 240 84 50 Generating stations:

Four Corners Units 4 and 5 (coal) 469 365 48 Mohave (coal) 334 246 56 Palo Verde (nuclear)(')

1,653 1,648 16 San Onofre (nuclear)(1) 4,305 4,283 75 Total

$ 7,042

$ 6,637

) Regulatory assets, which were written off as a charge to earnings as of December 31, 2000, as discussed in Note 1.

Note 11. Commitments Leases SCE has operating leases, primarily for vehicles, with varying terms, provisions and expiration dates.

Operating lease expense was $19 million in 2001, $20 million in 2000 and $17 million in 1999.

Estimated remaining commitments for noncancelable leases at December 31, 2001, were:

Year ended December 31, In millions 2002

$14 2003 13 2004 11 2005 8

2006 6

Thereafter 13 Total

$ 65 Nuclear Decommissioning Decommissioning is estimated to cost $2.1 billion in current-year dollars, based on site-specific studies performed in 1998 for San Onofre and Palo Verde. Changes in the estimated costs, timing of decommissioning, or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission in the near term. SCE estimates that it will spend approximately

$8.6 billion through 2060 to decommission its nuclear facilities. This estimate is based on SCE's current dollar decommissioning costs, escalated at rates ranging from 0.3% to 10.0% (depending on the cost element) annually. These costs are expected to be funded from independent decommissioning trusts, which effective June 1999 receive contributions of approximately $25 million per year. SCE estimates annual after-tax earnings on the decommissioning funds of 3.9% to 4.9%.

SCE plans to decommission its nuclear generating facilities by a prompt removal method authorized by the Nuclear Regulatory Commission. Decommissioning is expected to begin after the plants' operating licenses expire. The operating licenses expire in 2022 for San Onofre Units 2 and 3, and in 2026 and 2028 for the Palo Verde units. Decommissioning costs, which are recovered through non-bypassable customer rates over the term of each nuclear facility's operating license, are recorded as a component of depreciation expense.

45

Notes to Consolidated Financial Statements Decommissioning of San Onofre Unit 1 (shut down in 1992 per CPUC agreement) started in 1999 and will continue through 2008. All of SCE's San Onofre's Unit 1 decommissioning costs will be paid from its nuclear decommissioning trust funds.

Decommissioning expense was $96 million in 2001, $106 million in 2000 and $124 million in 1999. The accumulated provision for decommissioning, excluding San Onofre Unit 1 and unrealized holding gains, was $1.5 billion at December 31, 2001, and $1.4 billion at December 31, 2000. The estimated cost to decommission San Onofre Unit 1 is recorded as a liability.

Decommissioning funds collected in rates are placed in independent trusts, which, together with accumulated earnings, will be utilized solely for decommissioning.

Trust investments (cost basis) include:

Maturity In millions Dates December 31, 2001 2000 Municipal bonds 2001 -2034 463 S

548 Stocks 637 531 U.S. government issues 2001 -2029 332 421 Short-term and other 2001 334 220 Total

$ 1,766

$ 1,720 Trust fund earnings (based on specific identification) increase the trust fund balance and the accumulated provision for decommissioning. Net earnings were $13 million in 2001, $38 million in 2000 and $58 million in 1999. Proceeds from sales of securities (which are reinvested) were $3.9 billion in 2001, $4.7 billion in 2000 and $2.6 billion in 1999. Approximately 91% of the trust fund contributions were tax-deductible.

Other Commitments SCE has fuel supply contracts which require payment only if the fuel is made available for purchase.

Certain SCE gas and coal fuel contracts require payment of certain fixed charges whether or not gas or coal is delivered.

SCE has power-purchase contracts with certain QFs (cogenerators and small power producers) and other utilities. These contracts provide for capacity payments if a facility meets certain performance obligations and energy payments based on actual power supplied to SCE. There are no requirements to make debt service payments. In an effort to replace higher-cost contract payments with lower-cost replacement power, SCE has entered into purchased-power settlements to end its contract obligations with certain QFs. The settlements are reported as power purchase contracts on the balance sheets.

SCE has unconditional purchase obligations for part of a power plant's generating output, as well as firm transmission service from another utility. Minimum payments are based, in part, on the debt-service requirements of the provider, whether or not the plant or transmission line is operable. SCE's minimum commitment under both contracts is approximately $158 million through 2017. The purchased-power contract is expected to provide approximately 5% of current or estimated future operating capacity, and is reported as power purchase contracts (approximately $31 million). The transmission service contract requires a minimum payment of approximately $6 million a year.

Certain commitments for the years 2002 through 2006 are estimated below:

In millions 2002 2003 2004 2005 2006 Fuel supply contract payments

$168

$108

$103

$106

$109 Purchased-power capacity payments 629 629 626 624 572 46

Southern California Edison Company Note 12. Contingencies In addition to the matters disclosed in these notes, SCE is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. SCE believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.

Energy Crisis Issues In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International.

As amended in December 2000 and March 2001, the lawsuit involves securities fraud claims arising from alleged improper accounting for the TRA undercollections. The second amended complaint is supposedly filed on behalf of a class of persons who purchased Edison International common stock between July 21, 2000, and April 17, 2001. This lawsuit has been consolidated with another similar lawsuit filed on March 15, 2001. A consolidated class action complaint was filed on August 3, 2001. On September 17, 2001, SCE and Edison International filed a motion to dismiss for failure to state a claim. On March 8, 2002, the district court issued an order dismissing the complaint with prejudice. The plaintiffs could appeal this ruling to the court of appeals.

SCE has been a defendant in a number of legal actions brought by various QFs arising out of SCE's suspension of payments for electricity delivered by the QFs during the period November 1, 2000, through March 26, 2001. The QF claims were eventually largely subsumed within agreements with the litigating QFs providing for a provisional settlement of the parties' disputes. On March 1, 2002, SCE paid the amounts due under settlement agreements with these QFs, which triggered the releases and other provisions of the settlements. As a result, the litigation with those QFs to whom payment in full has been made under the parties' settlement agreements should be dismissed during 2002. However, SCE's March 1, 2002, payments excluded several QFs or did not result in immediate releases under the settlement agreements based on unique disputes or other unique circumstances, including the status of regulatory approval.

Environmental Protection SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.

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 mnaintenance, 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 undiscounted amounts.

SCE's recorded estimated minimum liability to remediate its 42 identified sites is $111 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: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and 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 $279 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-fueled generation plants and has retained some liability associated with the divested properties.

47

Notes to Consolidated Financial Statements The CPUC allows SCE to recover environmental-cleanup costs at certain sites, representing $50 million of its recorded liability, through an incentive mechanism (SCE may request 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 $76 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 now be made for these sites.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $10 million to $25 million. Recorded costs for 2001 were $18 million.

Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental cleanup costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

Nuclear Insurance Federal law limits public liability claims from a nuclear incident to $9.5 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available

($200 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the U.S. results in claims and/or costs which exceed the primary insurance at that plant site. Federal regulations require this secondary level of financial protection. The Nuclear Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $88 million per reactor, but not more than $10 million per reactor may be charged in any one year for each incident. Based on its ownership interests, SCE could be required to pay a maximum of

$175 million per nuclear incident. However, it would have to pay no more than $20 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary

$500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. These policies are issued by a mutual insurance company owned by utilities with nuclear facilities. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to $35 million per year. Insurance premiums are charged to operating expense.

Spent Nuclear Fuel Under federal law, the DOE is responsible for the selection and development of a facility for disposal of spent nuclear fuel and high-level radioactive waste. Such a facility was to be in operation by January 1998. However, the DOE did not meet its obligation. It is not certain when the DOE will begin 48

Southern California Edison Company accepting spent nuclear fuel from San Onofre or from other nuclear power plants. Extended delays by the DOE could lead to consideration of costly alternatives involving siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to one mill per kilowatt-hour of nuclear-generated electricity sold after April 6, 1983.

SCE, as operating agent,. has primary responsibility for the interim storage of its spent nuclear fuel at San Onofre. Current capability to store spent fuel is estimated to be adequate through 2005. SCE plans to spend approximately $34 million for the initial interim spent fuel storage at San Onofre Units 2 and 3 through 2008.

Palo Verde on-site spent fuel storage capacity will accommodate needs until 2003 for Unit 2, and until 2004 for Units 1 and 3. Arizona Public Service Company, operating agent for Palo Verde, is constructing an interim fuel storage facility that is expected to be completed in 2002.

Quarterly Financial Data 2001 2000 In millions Total Fourth Third Second First Total Fourth Third Second First Operating revenue

$8,126

$2,296

$2,726

$1,592

$1,512

$7,870

$1,755

$2,432

$1,853 $1,830 Operating income (loss) 4,617 3,956 1,294 204 (837)

(2,659)

(3,840) 447 385 349 Net income (loss) 2,408 2,310 657 34 (593)

(2,028)

(2,485) 177 161 119 Net income (loss) available for common stock 2,386 2,304 652 28 (598)

(2,050)

(2,491) 172 156 113 Common dividends declared 279 92 91 96 49

Responsibility for Financial Reporting Southern California Edison Company The management of Southern California Edison Company (SCE) is responsible for the integrity and objectivity of the accompanying financial statements. The statements have been prepared in accordance with accounting principles generally accepted in the United States and are based, in part, on management estimates and judgment.

SCE maintains systems of internal control to provide reasonable, but not absolute, assurance that assets are safeguarded, transactions are executed in accordance with management's authorization and the accounting records may be relied upon for the preparation of the financial statements. There are limits inherent in all systems of internal control, the design of which involves management's judgment and the recognition that the costs of such systems should not exceed the benefits to be derived. SCE believes its systems of internal control achieve this appropriate balance. These systems are augmented by internal audit programs through which the adequacy and effectiveness of internal controls and policies and procedures are monitored, evaluated and reported to management. Actions are taken to correct deficiencies as they are identified.

SCE's independent public accountants, Arthur Andersen LLP, are engaged to audit the financial statements in accordance with auditing standards generally accepted in the United States and to express an informed opinion on the fairness, in all material respects, of SCE's reported results of operations, cash flows and financial position.

As a further measure to assure the ongoing objectivity of financial information, the audit committee of the board of directors, which is composed of outside directors, meets periodically, both jointly and separately, with management, the independent public accountants and internal auditors, who have unrestricted access to the committee. The committee recommends annually to the board of directors the appointment of a firm of independent public accountants to conduct audits of SCE's financial statements; considers the independence of such firm and the overall adequacy of the audit scope and SCE's systems of internal control; reviews financial reporting issues; and is advised of management's actions regarding financial reporting and internal control matters.

SCE maintains high standards in selecting, training and developing personnel to assure that its operations are conducted in conformity with applicable laws and is committed to maintaining the highest standards of personal and corporate conduct. Management maintains programs to encourage and assess compliance with these standards.

Thomas M. Noonan Alan. Fohrer Vice President Chairman of the Board and Controller and Chief Executive Officer March 25, 2002 50

Report of Independent Public Accountants Southern Calitornia aison omparuy To Southern California Edison Company:

We have audited the accompanying consolidated balance sheets of Southern California Edison Company (SCE, a California corporation) and its subsidiaries as of December 31, 2001, and 2000, and the related consolidated statements of income (loss), comprehensive income (loss), cash flows and changes in common shareholder's equity for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of SCE's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States.

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of SCE and its subsidiaries as of December 31, 2001, and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

ARTHUR ANDERSEN LLP Los Angeles, California March 25, 2002 51 Southern California Edison C;ompany Report of Independent Public Accountants

Board of Directors Southern California Edison Company Warren Christopher*

Senior Partner, O'Melveny & Myers (law firm),

Los Angeles, California Alan J. Fohrer Chairman of the Board and Chief Executive Officer, Southern California Edison Company Joan C. Hanley The Former General Partner and

Manager, Miramonte Vineyards, Rancho Palos Verdes, California

• Retiring on May 14, 2002.

Carl F. Huntsinger*

General Partner, DAE Limited Partnership Ltd.

(agricultural management),

Ojai, California Charles D. Miller*

Retired Chairman of the Board, Avery Dennison Corporation (manu facturer of self-adhesive products),

Pasadena, California Luis G. Nogales Managing Partner, Nogales Investors (a private equity investment company),

Los Angeles, California Ronald L. Olson Senior Partner, Munger, Tolles and Olson (law firm),

Los Angeles, California James M. Rosser President, California State University, Los Angeles, Los Angeles, California Robert H. Smith Managing Director, Smith and Crowley Inc.

(merchant banking),

Pasadena, California Thomas C. Sutton Chairman of the Board and Chief Executive Officer Pacific Life Insurance Company, Newport Beach, California Daniel M. Tellep Retired Chairman of the Board, Lockheed Martin Corporation (aerospace industry),

Bethesda, Maryland Management Team Alan J. Fohrer Chairman of the Board and Chief Executive Officer Robert G. Foster President Harold B. Ray Executive Vice President, Generation Business Unit Pamela A. Bass Senior Vice President, Customer Service Business Unit John R. Fielder Senior Vice President, Regulatory Policy and Affairs Stephen E. Pickett Senior Vice President and General Counsel Richard M. Rosenblum Senior Vice President, Transmission and Distribution Business Unit Mahvash Yazdi Senior Vice President and Chief Information Officer Emiko Banfield Vice President, Shared Services Robert C. Boada Vice President and Treasurer Clarence Brown Vice President, Corporate Communications Bruce C. Foster Vice President, San Francisco Regulatory Operations A. L. Grant Vice President, Engineering and Technical Services Frederick J. Grigsby, Jr.

Vice President, Human Resources and Labor Relations Lawrence D. Hamlin Vice President, Power Production Harry B. Hutchison Vice President, Mass Customers James A. Kelly Vice President, Regulatory Compliance Russell W. Krieger Vice President, Nuclear Generation Thomas M. Noonan Vice President and Controller Dwight E. Nunn Vice President, Nuclear Engineering and Technical Services Pedro J. Pizarro Vice President, Business Development Frank J. Quevedo Vice President, Equal Opportunity W. James Scilacci Vice President and Chief Financial Officer Dale E. Shull, Jr.

Vice President, Power Delivery Anthony L. Smith Vice President, Tax Joseph J. Wambold Vice President, Nuclear Business and Support Services Beverly P. Ryder Secretary 52

Shareholder Information Annual Meeting of Shareholders Tuesday, May 14, 2002 10:00 a.m.

DoubleTree Hotel Ontario 222 N. Vineyard Avenue Ontario, California 91764 Stock Listing and Trading Information SCE Preferred Stock SCE's preferred stocks are listed on the American and Pacific stock exchanges under the ticker symbol SCE. Previous day's closing prices, when traded, are listed in the daily newspapers in the American Stock Exchange composite table. The 6.05%, 6.45% and 7.23% series are not listed.

Where to Buy and Sell Stock The listed preferred stocks may be purchased through any brokerage firm. Firms handling unlisted series can be located through your broker.

Transfer Agent and Registrar Wells Fargo Bank Minnesota, N.A. maintains shareholder records and is the transfer agent and registrar for SCE preferred stock. Shareholders may call Wells Fargo Shareowner Services, (800) 347-8625, between 7:00 a.m. and 7:00 p.m. (Central Time), Monday through Friday, regarding:

"* stock transfer and name-change requirements;

"* address changes, including dividend addresses;

"* electronic deposit of dividends;

"* taxpayer identification number submission or changes;

"* duplicate 1099 forms and W-9 forms;

"* notices of, and replacement of, lost or destroyed stock certificates and dividend checks; and

"* requests for access to online account information.

The address of Wells Fargo Shareowner Services is:

161 North Concord Exchange Street South St. Paul, MN 55075-1139 FAX: (651) 450-4033 E-mail: stocktransfer@wellsfarpo.com SCE Web Address:

www.edisoninvestor.com

EJT SOUTHERN CALIFORNIA EDISON An EDISON INTERNATIONAL Company 2244 Walnut Grove Avenue, Rosemead, California 91770 626.302.1212 www. edison.corn

SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K DX/

Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2001 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.

[X]

As of March 25, 2002, 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 $323,592.460.35 on or about March 25, 2002, 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 March 25, 2001, were as follows: CUMULATIVE PREFERRED STOCK $75,829,990.35;

$100 CUMULATIVE PREFERRED STOCK $247,762,470.00.

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, 2001............................................

Parts I, II and IV (2) Designated portions of the Joint Proxy Statement relating to registrant's 2002 Annual Meeting of Shareholders................................

Part III

TABLE OF CONTENTS Item Page Part I

1.

Business..........................................................................................................................................................

1 Forward-Looking Statements and Risk Factors.......................................................................................

1 Competitive Environment..........................................................................................................................

3 Regulation.................................................................................................................................................

3 Changing Regulatory Environment......................................................................................................

4 Other Rate Matters...................................................................................................................................

13 Fuel Supply and Purchased Power Costs.............................................................................................

17 Environmental Matters..............................................................................................................................

19

2.

Properties.........................................................................................................................................................

22 Existing Generating Facilities...................................................................................................................

22 Construction Program and Capital Expenditures...................................................................................

24 Nuclear Power Matters.............................................................................................................................

24

3.

Legal Proceedings..........................................................................................................................................

27 San Onofre Personal Injury Litigation....................................................................................................

27 Navajo Nation Litigation............................................................................................................................

28 Shareholder Litigation...............................................................................................................................

28 Qualifying Facilities Litigation...................................................................................................................

29 Power Exchange (PX) Performance Bond Litigation..............................................................................

30 CPUC Litigation and Settlement...............................................................................................................

31

4.

Subm ission of Matters to a Vote of Security Holders...................................................................................

31 Executive Officers of the Registrant.....................................................................................................

31 Part II

5.

Market for Registrant's Common Equity and Related Stockholder Matters................................................

33

6.

Selected Financial Data...................................................................................................................................

33

7.

Management's Discussion and Analysis of Results of Operations and Financial Condition........................ 33 7A. Quantitative and Qualitative Disclosures About Market Risk.......................................................................

33

8.

Financial Statements and Supplementary Data............................................................................................

33

9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......................

33 Part III

10. Directors and Executive Officers of the Registrant.......................................................................................

34

11. Executive Compensation.................................................................................................................................

34

12. Security Ownership of Certain Beneficial Owners and Management.............................

34

13. Certain Relationships and Related Transactions.........................................................................................

34 Part IV

14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.........................................................

35 Financial Statements................................................................................................................................

35 Report of Independent Public Accountants and Schedules Supplementing Financial Statements.......... 35 Exhibits.....................................................................................................................................................

35 Reports on Form 8-K................................................................................................................................

35 Signatures.................................................................................................................................................

40

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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, coastal 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. In 2001, SCE's total operating revenue was derived from: 34%

residential customers, 42% commercial customers, 10% industrial customers, 7% public authorities, 2%

agricultural and other customers, and 5% other electric revenue. SCE had 11,663 full-time employees at year-end 2001.

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 retained other electric generating plants, however, and it retained 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. As a further part of the industry restructuring, SCE was required for an interim transitional period 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. Due to the California energy crisis and SCE's resulting financial difficulties, as described below under "Changing Regulatory Environment," in January 2001 SCE ceased buying and selling power through the PX. In 2001, legislation was enacted in California prohibiting SCE and other California utilities from selling their remaining generating facilities. SCE has continued to provide power for its customers from its own generation sources and from existing contracts with other utilities and power producers. The California Department of Water Resources (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 and remits revenues on behalf of the CDWR.

Forward-Looking Statements and Risk Factors This annual report on Form 10-K 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, or that otherwise could impact SCE, are:

SCE's financial condition, liquidity and credit ratings were adversely affected by California's electricity crisis. SCE is seeking to regain an investment grade credit rating so it can re-enter the credit markets on more efficient and reasonable terms. Whether and when investment grade credit ratings can be regained will have a significant impact on SCE's financial condition. Based on the rights to cost recovery and revenue established by the settlement agreement with the California Public Utilities Commission (CPUC) (discussed below) and CPUC implementing orders, including the procurement related obligations account (PROACT) resolution (discussed below), SCE's credit ratings were raised and the company repaid all of its undisputed past-due obligations in March 2002 to creditors from a combination of cash on hand and the proceeds of senior secured credit facilities and.a remarketing of pollution control bonds. Although Fitch IBCA, Standard & Poor's and Moody's Investors Service

raised their credit ratings significantly for both Edison International and SCE in March 2002, the new ratings are still below investment grade.

The court order approving SCE's settlement agreement with the CPUC is being appealed by a consumer advocacy group to the federal court of appeals. If the order is successfully challenged on appeal, implementation of the settlement agreement by SCE and the CPUC could be affected adversely, which in turn may have an adverse affect on SCE's ability to restore its financial condition.

SCE is 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.

SCE may be affected by legislative measures adopted and being contemplated by federal and state authorities to address the California electricity crisis or deregulation in other states, and pending legislation that would repeal or amend key statutes governing the electric industry.

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.

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.

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.

"* 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.

"* SCE is subject to power plant operation risks, including strikes, equipment failures and other issues.

"* SCE may be affected by changes in tax laws or unfavorable interpretation and application of the laws by tax authorities.

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. Environmental advocacy groups and regulatory agencies have been focusing considerable attention on carbon dioxide emissions from coal-fired plants and their potential role in the "global-warming" issue. The adoption of new laws and regulations to implement carbon dioxide or other emission controls could adversely affect SCE's coal plants. For further discussion, see "Business - Environmental Matters."

"* 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 and other risks and uncertainties is contained throughout this report and in the Notes to Consolidated Financial Statements and Management's Discussion and Analysis of Results of Operations and Financial Condition (MD&A) that are incorporated by reference into Part II of this annual report. Readers are urged to read this entire report, including the information incorporated by reference, 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, and 2

SCE is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by SCE with the Securities and Exchange Commission (SEC).

Competitive Environment Throughout most of its history, SCE provided integrated electric generation, transmission, and distribution services on a bundled basis to its customers and had an exclusive franchise within its service territory.

Customers had the right to generate their own electricity through cogeneration or other means, but third parties were not permitted to sell energy directly to customers within SCE's service territory. In 1994, the CPUC commenced the electric industry restructuring process. In 1996, the California Legislature enacted comprehensive restructuring legislation. SCE's business was unbundled into separate generation, transmission, and distribution components, and the development of a competitive generation market was authorized. SCE was directed by the CPUC to divest the bulk of its gas-fired generation portfolio. Those plants are now owned and operated by independent power producers. Under the legislation and CPUC decisions, independent power producers and other energy service providers were authorized to enter into contracts to provide electricity to retail customers over SCE's distribution system. Power producers and suppliers were authorized to sell energy to the PX at wholesale prices set by the market. In 2001, as a result of the California energy crisis, the PX ceased operation and the CDWR took over the purchase of power for utility customers. The ability of customers to depart utility service and buy power from power producers and suppliers other than SCE was suspended. The future of the competitive market in California is uncertain. The effects on SCE of this changing competitive environment are discussed below under "Business - Changing Regulatory Environment."

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 Federal Energy Regulatory Commission (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 United States 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 (San Onofre) 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, SCE has a coastal permit to construct a dry cask spent fuel storage installation for Units 2 and 3.

3

The United States 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.

Changing Regulatory Environment SCE operates in a highly regulated environment in which it has an obligation to deliver electric service to customers within its service territory in return for 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, as discussed above under "Competitive Environment". As part of California's electric industry restructuring, a multi-year freeze on the rates that SCE could charge its customers was mandated and transition cost recovery mechanisms were implemented allowing SCE to recover certain specified costs associated with generation-related assets (referred to as "stranded costs").

California's electric utility industry restructuring statute included provisions to finance a portion of the stranded costs that residential and small commercial customers would have paid between 1998 and 2001, which allowed SCE to reduce rates by at least 10% to these customers, effective January 1, 1998. These frozen rates were to remain in effect until the earlier of March 31, 2002, or the date when the CPUC authorized costs for utility-owned generation assets and obligations were recovered.

In May 2000, SCE began experiencing adverse impacts from unusually high prices for energy and ancillary services procured through the PX and the California Independent System Operator (ISO).

These high wholesale prices, coupled with the freeze on SCE's retail rates resulted in substantial revenue undercollections. Pursuant to CPUC and accounting rules, SCE recorded the undercollections in the transition revenue account (TRA). 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 in "Recovery of Transition and Power Procurement Costs" below), the TRA undercollection, along with SCE's coal and hydroelectric balancing account overcollections (which amounted to $1.5 billion as of December 31, 2000), were reclassified to a transition cost balancing account (TCBA). In addition, the CPUC recalculated the TCBA to be a $2.9 billion undercollection.

Liquidity Issues Sustained higher wholesale energy prices that exceeded SCE's retail rate levels resulted in large undercollections in the TRA and TCBA regulatory balancing accounts. The undercollections in these accounts, coupled with near-term capital requirements and the adverse reaction of the credit markets to regulatory uncertainty regarding SCE's ability to recover its power procurement costs, materially and adversely affected SCE's liquidity throughout late 2000 and 2001. As a result of its liquidity crisis, SCE took steps to conserve cash while continuing to provide service to its customers. Beginning in January 2001, SCE suspended payments owed to the ISO, the PX, and qualifying facilities (QFs), deferred payments of certain obligations for principal and interest on outstanding debt, and did not declare dividends on any of its cumulative preferred stock. The suspension or deferral of payments caused defaults on two series of SCE's senior unsecured notes and all of SCE's commercial paper. In March 2001, the CPUC ordered SCE to commence payments to QFs for future energy deliveries and by April 1, 2001, SCE resumed payment of interest on its debt obligations.

In October 2001, SCE entered into an agreement settling a lawsuit against the CPUC concerning SCE's right to recover its power procurement costs in retail rates. On January 23, 2002, the CPUC adopted a resolution implementing a mechanism for recovery of these costs. (See "CPUC Settlement Agreement" below for a discussion of this matter.)

On March 1, 2002, SCE closed on a $1.6 billion credit facility, secured by three newly issued series of SCE's first mortgage bonds, and remarketed approximately $196 million of pollution control bonds that SCE repurchased in late 2000.

4

The proceeds from the credit facilities and pollution-control bond remarketing were used along with SCE's available cash to repay $3.2 billion in past-due obligations and $1.65 billion in near-term debt maturities.

The past-due obligations consisted of: (1) $875 million to the PX; (2) $99 million to the ISO; (3) $1.1 billion to QFs; (4) $193 million in PX energy credits for energy service providers; (5) $531 million of matured commercial paper; (6) $400 million of principal on its 5-7/8% and 6-1/2% senior unsecured notes which were issued prior to the energy crisis; and (7) $23 million in preferred dividends in arrears. The near-term debt maturities consisted of credit facilities whose maturity dates were extended several times and were scheduled to mature in March and May 2002. After making the above-described payments, SCE has no material undisputed obligations that are past-due or in default. In addition, SCE entered into an agreement with the CDWR to pay for prior deliveries of energy of $100 million on April 1, 2002,

$150 million on June 3, 2002, and the balance on July 1, 2002.

CDWR Power Purchases On January 17, 2001, following rolling blackouts in the northern California service territory of Pacific Gas and Electric Company (PG&E), California Governor Gray Davis signed an order declaring an emergency and authorizing the CDWR to purchase power in order to prevent further blackouts.

In accordance with the emergency order, the CDWR began making emergency power purchases for SCE's customers on January 17, 2001. Amounts SCE bills to and collects from its customers for electric power purchased and sold by the CDWR and through the ISO are remitted directly to the CDWR and are not recognized as revenue by SCE. In February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1 X) was enacted into law. AB 1X 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 bonds to finance electricity purchases.

On March 27, 2001, the CPUC issued an interim order requiring SCE to pay the CDWR a per-kWh price equal to the applicable generation-related retail rate per kWh for electricity for each kWh the CDWR sells to SCE's customers. The CPUC determined that the generation-related retail rate should be equal to the total bundled electric rate (including the 1 o per kWh and 30 per kWh surcharges adopted by the CPUC on January 4, 2001, and March 27, 2001, respectively) less certain nongeneration-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 6.277o per kWh for power delivered to SCE's customers. This amount increased per the 10 and 30 surcharges referenced above. The CPUC ordered SCE to pay the CDWR its applicable generation rate within 45 days after the CDWR supplies power to retail customers, subject to penalties for each day the payment is late.

On February 21, 2002, the CPUC issued a decision implementing a CDWR revenue requirement of

$9.0 billion to pay its costs associated with bonds issued to finance the CDWR's energy procurement costs for the period January 17, 2001, through December 31, 2002. The decision states that SCE's allocated share of this revenue requirement would be approximately $3.6 billion, and changes SCE's payment from an average recorded rate of 11.460 per kWh to 9.7440 per kWh. Amounts remitted to the CDWR on or after March 15, 2002, will be based on the new rate. The decision also requires SCE to pay the CDWR the difference in the amount SCE previously paid the CDWR for electricity delivered from January 17, 2001, through March 15, 2002, and the amount that would have been paid had the new rate been in effect for the entire period (approximately $41 million). This amount may be paid in equal monthly installments over a six-month period.

On February 14, 2001, FERC issued an order that denied the ISO's request to relax creditworthiness standards in the ISO tariff to the extent this would affect third-party suppliers. FERC, however, allowed the ISO to revise its tariff so that a "creditworthy counterparty" could assume responsibility for procuring power with respect to utilities that do not have the credit rating required by the ISO tariff, such as SCE or PG&E. On April 6, 2001, FERC issued an order essentially reaffirming the February 14 order and holding that the ISO must assure that there is a creditworthy buyer for power delivered to loads through the ISO.

SCE has not met the ISO's creditworthiness requirements since its credit ratings were downgraded in mid-January 2001. As a result, SCE protested and returned the bills it had received from the ISO. On 5

August 9, 2001, the ISO filed a petition for review of the FERC's April 6, 2002, order with the court of appeals for the D.C. Circuit Court.

On November 7, 2001, the FERC issued an order directing the ISO, within 15 days of the order, to invoice the CDWR for all ISO transactions it entered into on behalf of SCE and PG&E. The FERC also directed the ISO, within 15 days from the date of the order, to file a compliance report with the FERC indicating overdue amounts from the CDWR and a schedule for payment of those overdue amounts within three months of the date of the order. On November 21, 2001, the ISO filed the compliance report. On December 7, 2001, SCE sought a limited rehearing of the November 7, 2001, order. On the same day, the CDWR also filed its rehearing request. On December 21, 2001, SCE filed comments on the ISO's compliance filing and many parties, including the CDWR, protested the compliance filing.

On February 28, 2002, SCE and the CDWR executed an agreement that resolves outstanding issues relating to payment for imbalance energy delivered to SCE's customers (imbalance energy is energy obtained from the ISO's real-time market) and responsibility for certain ISO charges. Under this agreement, SCE will pay the CDWR for imbalance energy previously delivered in three installments

($100 million on April 1, 2002; $150 million on June 3, 2002; and the balance on July 1, 2002). The agreement also establishes a mechanism for SCE to pay the CDWR for imbalance energy that the CDWR sells to SCE's customers in the future. Additionally, the agreement allocates responsibility for ISO charges between the CDWR and SCE. The agreement provides that SCE will reimburse the CDWR by September 1, 2002, for ISO charges which the CDWR previously paid and which SCE agrees to pay in the agreement. The agreement also provides a mechanism for payment of ISO charges that are incurred in the future.

Direct Access A related power-procurement issue is the extent to which customers should be allowed to purchase power directly from energy service providers (Direct Access) instead of through SCE. As part of emergency legislation authorizing the CDWR to purchase power on behalf of utility customers, the CPUC was ordered to suspend Direct Access until such time as the CDWR was no longer supplying power. The CPUC was given flexibility as to the timing of its order. In early 2001, when extremely high power prices prevailed in the wholesale markets, many customers who had previously chosen Direct Access returned to SCE bundled utility service, and the CDWR purchased power on their behalf. As the crisis in the wholesale energy markets eased in summer of 2001, customers again sought to move to Direct Access suppliers.

On September 20, 2001, the CPUC suspended Direct Access on an interim basis, reserving its right to review the suspension date. On March 21, 2002, the Commission voted to maintain the September 20, 2001, suspension date. The Commission also ordered that Direct Access surcharges or exit fees shall be developed in a separate proceeding so that there is an equitable allocation of the CDWR costs and that Direct Access customers pay their fair share of CDWR costs. Based on the September 20, 2001, suspension, approximately 14% or more of SCE's retail energy load will likely be served through Direct Access. Because the CDWR is presently supplying all power in excess of SCE's own generation and long-term contracts, a change in the amount of Direct Access load could affect the CDWR's total costs going forward.

The CPUC has also initiated hearings on an additional Direct Access issue. Until June 3, 2001, Direct Access customers were receiving a credit based on SCE's weighted-average energy cost. When wholesale energy costs skyrocketed in early 2001, this energy cost often exceeded the generation rate component of frozen rates. Thus, during these times, SCE incurred a liability to fund both energy purchases for bundled service customers and energy credits for Direct Access customers. These costs were reflected in SCE's regulatory asset accounts. As a result, Direct Access customers contributed to SCE's procurement related liabilities in the same manner as SCE's bundled customers. The CPUC is investigating whether and how to allocate to Direct Access customers an appropriate share of the balance in the PROACT, which is described under "CPUC Settlement Agreement" and "PROACT" below. Briefs were filed on this issue on February 13 and February 20, 2002, with a draft decision expected by mid 2002. As part of the Direct Access proceeding, the CPUC will consider whether the method used to calculate the credits paid to Direct Access customers after January 17, 2001, was appropriate.

6

Affiliate and Holding Company Proceedings 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 has yet been issued.

In April 2001, the CPUC adopted an order instituting investigation that reopened the past CPUC decisions authorizing the utilities to form holding companies and initiated an investigation into: whether the holding companies violated CPUC requirements to give first priority to the capital needs of their respective utility subsidiaries; whether actions by Edison International and PG&E Corporation and their respective nonutility affiliates to shield, or "ring-fence," nonutility assets also violated the requirements that the holding companies give first priority to the capital needs of their utility subsidiaries; 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; any additional suspected violations of laws or CPUC rules and decisions; and whether additional rules, conditions, or other changes to the holding company decisions are necessary. On January 9, 2002, the CPUC issued a decision regarding the "first priority" condition that defined the term "capital" as encompassing all of the following: "the money and property with which a company carries on its corporate business; a company's assets, regardless of source, utilized for the conduct of the corporate business and for the purpose of deriving gains and profits; and a company's working capital," and which found that the first priority condition does not preclude the requirement that the holding companies infuse all types of "capital" into their respective utility subsidiaries where necessary to-fulfill the utility's obligation to serve. The CPUC stated that it had not conclusively found that any holding company has violated such condition. Also on January 9. 2002, the CPUC denied motions by Edison International and the other holding companies to dismiss the proceeding as it pertains to them for lack of jurisdiction. Both Edison International and SCE filed requests for rehearing of the decision on the first priority condition, and Edison International filed a request for rehearing of the denial of its motion to dismiss for lack of jurisdiction.

Although the CPUC denied the holding companies' motions to dismiss foir lack of jurisdiction, the CPUC then dismissed PG&E Corporation from the proceeding so that the issue of whether PG&E Corporation's bankruptcy plan would result in a violation of the first priority condition could be resolved "in the appropriate judicial forums." On January 10, 2002, the California Attorney General filed a civil lawsuit in state court alleging that PG&E Corporation had violated California's Unfair Competition Act by, among other things, failing to infuse capital into Pacific Gas and Electric Company as required by the first priority condition and seeking to insulate assets from the CPUC's jurisdiction through the improper use of the power of the bankruptcy court. The lawsuit seeks injunctions, restitution, and a civil penalty of at least

$500 million. The CPUC announced that it intends to join in the lawsuit against PG&E Corporation, based on the CPUC's January 9, 2002 decisions.

SCE cannot predict what effects the CPUC's investigation or any other actions by the CPUC or the Attorney General may have.

Qualifying Facilities On March 27, 2001, the CPUC ordered SCE to begin making payments to QFs for power deliveries on a going forward basis. Under the order, SCE was directed to pay QFs within 15 days of the end of the QFs' billing period, and QFs are allowed to establish 15-day billing periods. A supplemental order issued on December 11, 2001, deleted the automatic penalty provisions and instead advised SCE that it could be 7

subject to an order to show cause in the event of a violation. Furthermore, settlement agreement amendments entered into with the vast majority of the QFs under contract with SCE resulted in the QFs' waiver of the 15-day payment opportunity coincident with the making of a "final" settlement payment by SCE on March 1, 2002. SCE is pursuing agreements with the remaining QFs that likewise would result in a waiver of the 15-day payment directive. In the March 27 order, 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 OF energy prices. The changes apply where appropriate regardless of whether the OF uses natural gas or other resources such as solar or wind. In March 2002, SCE paid $1.1 billion to QFs to resolve issues related to SCE's suspension of payments for deliveries by QFs during the period November 1, 2000, through March 26, 2001. For additional information about lawsuits filed against SCE by QFs, see "Qualifying Facilities Litigation" in Part 1, Item 3 of this report.

CPUC Settlement Agreement In November 2000, SCE filed a complaint in federal District Court against the Commissioners of the CPUC, alleging that their refusal to allow SCE to recover its wholesale costs of purchasing power in its retail rates violated federal law. The case was stayed in April 2001 by agreement of SCE and the CPUC, with the support of Governor Davis, to create an opportunity to implement a consensual resolution. The state legislature, however, did not pass legislation to implement such a resolution by late September 2001.

At that point, the CPUC and SCE negotiated a settlement agreement (CPUC Settlement Agreement) to resolve the litigation, and the district court entered a stipulated judgment on October 5, 2001, incorporating the settlement. Several entities appealed the stipulated judgment entered by the district court, including a California consumer group that had been allowed to intervene in the litigation as a permissive intervenor, and three other entities whose motions to intervene had been denied.

On November 28, 2001, a federal court of appeals denied the consumer group's request for a stay of the settlement. The group had alleged that it was denied due process, that the settlement violated state law, and that the CPUC had no authority to agree to the settlement. In its ruling, the court of appeals also granted SCE's request for an expedited hearing of the appeal. On March 4, 2002, the court of appeals heard argument on the appeal, and the matter is now under submission. A decision could be issued anytime within the next several months. It is impossible to predict the outcome of the appeal, or the impact that any outcome would have upon the stipulated judgment or the settlement.

Key elements of the CPUC Settlement Agreement include the following items:

Establishment of an account called the procurement-related obligations account, or PROACT, as of September 1, 2001, which will have an opening balance equal to the amount of SCE's procurement related liabilities as of August 31, 2001 (approximately $6.4 billion), less SCE's cash and cash equivalents as of that date (approximately $2.5 billion), and less $300 million.

Beginning September 1, 2001, and ending on the earlier of the date that SCE has recovered all of its procurement-related obligations recorded in the PROACT or December 31, 2005, SCE will apply to the PROACT, on a monthly basis, the difference between SCE's revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the CPUC to recover in retail electric rates. Unrecovered obligations in the PROACT will accrue interest from September 1, 2001.

SCE will recover in retail electric rates its procurement-related obligations in the PROACT, with interest, by December 31, 2005. Subject to certain adjustments, the CPUC will maintain current rates (including surcharges) in effect until December 31, 2003, or, if earlier, until the date that SCE recovers the entire PROACT balance. If SCE has not recovered the entire balance by December 31, 2003, the unrecovered balance will be amortized over a period not to extend beyond December 31, 2005. The parties project that existing retail electric rates, including surcharges and as adjusted to reflect certain 8

costs, will likely result in SCE recovering substantially all of its unrecovered procurement-related obligations prior to the end of 2003.

"* If the CPUC concludes that it is desirable to authorize a securitized financing of SCE's procurement related obligations, the parties will work together to achieve the securitization. Proceeds of any securitization will be credited to the PROACT when they are actually received.

"o During the period that SCE is recovering its procurement-related obligations, no penalty will be imposed by the CPUC on SCE for any noncompliance with CPUC-mandated capital structure requirements.

SCE will incur up to $250 million of recoverable costs to acquire financial instruments and engage in other transactions intended to hedge fuel cost risks-associated with SCE's retained generation assets and power purchase contracts with qualifying facilities and other utilities. As of December 31, 2001, SCE had purchased $209 million in hedging instruments. See discussion under "Market Risk Exposures" in the MD&A that is incorporated by reference into Part II, Item 7 of this report.

SCE will not declare or pay dividends or other distributions on its common stock (all of which is held by its parent) prior to the earlier of the date SCE has recovered all of its procurement-related obligations in the PROACT or January 1, 2005. However, if SCE has not recovered all of its procurement-related obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume common stock dividends, and the CPUC will not unreasonably withhold its consent.

To ensure the ability of SCE to continue to provide adequate service until the effectiveness of SCE's next general rate case, SCE may make capital expenditures above the level contained in current rates, up to $900 million per year, which will be treated as recoverable costs.

Subject to certain qualifications, SCE will cooperate with the CPUC and the California Attorney General to pursue and resolve SCE's claims and rights against sellers of energy and related services, SCE's defenses to claims arising from any failure to make payments to the PX or ISO, and similar claims by the State of California or its agencies against the same adverse parties. During the recovery period discussed above, refunds obtained by SCE related to its procurement-related liabilities will be applied to the balance in the PROACT.

The CPUC Settlement Agreement states that one of its purposes is to restore the investment grade creditworthiness of SCE as rapidly as reasonably practicable so that it will be able to provide reliable electrical service as a state-regulated entity as it has in the past. SCE cannot provide assurance that it will regain investment grade credit ratings by any particular date.

PROACT On January 23, 2002, the CPUC issued a resolution that approved the new ratemaking and accounting structure that SCE proposed to implement the CPUC Settlement Agreement. Among other things, the new structure eliminates the TCBA as of August 31, 2001, and creates the new PROACT. This change implements the provision of the CPUC Settlement Agreement declaring that "balances in SCE's TCBA as of August 31, 2001, shall have no further impact on SCE's retail electric rates." According to the terms of the CPUC Settlement Agreement and the CPUC's implementing resolution, in the fourth quarter of 2001, SCE established (retroactive to August 31, 2001) a $3.6 billion PROACT regulatory asset for its previously incurred procurement costs. On February 25, 2002, TURN submitted an application for rehearing, of the CPUC's January 23, 2002, resolution. In its application for rehearing, TURN challenges the CPUC Settlement Agreement and its implementation. On March 12, 2002, SCE submitted to the CPUC its opposition to the TURN application for rehearing.

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Recovery of Transition and Power Procurement Costs SCE's transition costs include power purchases from QF contracts (which are the direct result of prior legislative and regulatory mandates), recovery of certain generating assets and other costs incurred to provide service to customers. Other costs include the recovery of income tax benefits previously flowed through to customers, postretirement benefit transition costs and accelerated recovery of investment in SCE's nuclear plants. Recovery of costs related to power-purchase QF contracts is permitted through the terms of each contract. Legislation and regulatory decisions issued prior to the beginning of the rate freeze called for most of the remaining transition costs to be recovered through the end of the four-year transition period (not later than March 31, 2002).

There were three sources of revenue available to SCE for transition cost recovery through the TCBA mechanism: revenue from the sale or valuation of generation assets in excess of book values, net market revenue from the sale of SCE-controlled generation into the ISO and PX markets, and competition transition charge (CTC) revenue. Revenue from the first two sources has not been available since January 2001. Net proceeds of the 1998 plant sales were used to reduce transition costs, which otherwise had been expected to be collected through the TCBA mechanism. State legislation enacted in January 2001 prohibits the sale of SCE's remaining generation assets until 2006. SCE stopped selling power from its generation into the ISO and PX markets in January 2001, after SCE's credit ratings were downgraded and the PX suspended SCE's trading privileges.

The CTC applied to all customers who were using or began using utility services on or after the CPUC's 1995 restructuring decision date. CTC revenue was determined residually (i.e., CTC revenue was 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). Residual CTC revenue was calculated through the TRA mechanism. In accordance with the March 27, 2001, rate stabilization decision, both positive and negative residual CTC revenue was transferred from the TRA to the TCBA on a monthly basis, retroactive to January 1, 1998. A previous decision had called only for a transfer of positive residual CTC revenue (TRA overcollections) to the TCBA and there had not been any positive residual CTC revenue between May 2000 and June 2001.

Because the regulatory and legislative actions did rVot occur that would have made recovery of transition costs probable, SCE was unable to conclude as of December 31, 2000, that the recalculated TCBA net undercollection was probable of recovery through the ratemaking process. As a result, the $2.9 billion TCBA net undercollection was written off as a charge to earnings as of that date, and an additional

$552 million (pre-tax) in net undercollected transition costs were charged to earnings in 2001. Although the TCBA was written off, SCE continued to calculate the account for ratemaking purposes, and the account reflected a $4.2 billion undercollection as of September 1, 2001, which, as discussed below, is the effective date of the beginning of the PROACT mechanism and the end of the TCBA mechanism.

Additional information about the financial impact of this undercollection and various ongoing and proposed regulatory efforts and judicial proceedings designed to address or otherwise relating to it, is provided under "Regulatory Environment - Status of Transition and Power Procurement Cost Recovery" in the MD&A that is incorporated by reference into Part II, Item 7 of this report.

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 four classes of notes matured in December 1998 and March 2000, 2001, and 2002, respectively. The remaining three classes of notes valued at approximately $1.5 billion have maturities beginning in 2003 and ending in 2007, with interest rates ranging from 6.28% to 6.42%.

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Other Revenue and Cost-Recovery Mechanisms Revenue is determined by various mechanisms depending on the utility operation: distribution, transmission and generation.

Distribution Revenue related to distribution operations is being determined through a performance-based ratemaking mechanism (PBR) and the distribution assets have the opportunity to earn a CPUC-authorized 9.49% return.

The PBR mechanism was to have ended in 2001, and SCE's distribution costs were to be established for 2002 in a general rate case (GRC). Due to the industry upheaval of the last year, SCE was allowed to defer the GRC for one year, and a proceeding was established to extend the existing PBR mechanism through 2002. In addition, legislative changes required that the mechanism be altered to eliminate revenue volatility due to sales fluctuations. As a result, the proceeding also addresses how to establish balancing accounts such that the revenues set in this proceeding for 2001 and 2002 will be fully recovered. A CPUC proposed decision on the PBR mechanism for 2002 was issued in January 2002. The proposed decision authorized SCE to use a formula to determine its distribution revenue requirement for the last half of 2001 and 2002, and a revenue balancing account to ensure that variations in sales do not result in under or overcollections.

A final decision is expected by mid-2002. At this time, SCE cannot predict the effect of the final decision on its results of operation.

At the expiration of the PBR, SCE is to begin recovering costs based on cost of service ratemaking. In December 2001, SCE filed its 2003 general rate case with the CPUC, requesting an increase of approximately $500 million in revenue (compared to 2000 recorded revenue) for its distribution and generation operations. Hearings are expected to begin in July 2002, with a final decision expected in second quarter 2003.

Transmission 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, the FERC issued a final decision in SCE's 1998 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 the 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 the 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 the FERC to be included in transmission rates. A CPUC decision is pending. 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 the FERC associated with transmission will not be refunded to retail customers but will be credited to the PROACT balance reflecting SCE's procurement-related obligations. Additionally, on January 31, 2002, SCE filed to increase the base transmission revenue requirement to $280 million. This proposed increase is to reflect higher costs of capital, increased depreciation expense, and increased operation and maintenance costs attributable to FERC-jurisdictional services. FERC action on whether and when the proposed transmission rates will be placed into effect, subject to refund, is expected in April 2002.

As discussed above, under "CPUC Settlement Agreement," total rates to retail customers were unchanged.

Thus, SCE intends to file an equal and opposite reduction in generation rates upon acceptance by the FERC of the increased transmission rates.

Generation 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 ratemaking agreements. During the rate freeze, revenue from generation-related operations has also been determined through the market and transition cost recovery mechanisms, which also included the nuclear 11

ratemaking agreements. The portion of revenue related to coal generation plant costs (Mohave Generating Station (Mohave Station) and Four Corners Generating Station (Four Corners)) 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 were transferred to the TRA on a monthly basis, retroactive to January 1, 1998, which later were transferred to the TCBA on a monthly basis, retroactive to January 1, 1998, and subsequently replaced by the PROACT mechanism effective September 1, 2001.

In June 2001, SCE filed a comprehensive proposai for new cost-of-service ratemaking for utility retained generation (URG) through the end of 2002. After that time, SCE's URG-related revenue requirement will be determined by the general rate case. The URG proposal calls for balancing accounts for SCE-owned generation, QFs and interutility contracts, procurement costs and ISO charges based on either actual or CPUC-authorized revenue requirements. Under the proposal, the four new balancing accounts would be effective January 1, 2001, for capital-related costs, and February 1, 2001, for non-capital-related costs.

In addition, SCE's unamortized nuclear investment would be amortized and recovered in rates over a 10-year period, effective January 1, 2001. Should this application be approved as filed, SCE expects to reestablish for financial reporting purposes its unamortized nuclear investment and regulatory assets related to purchased-power settlement and flow-through taxes, with a corresponding credit to earnings, and adjust the PROACT regulatory asset in accordance with the final URG decision.

On January 18, 2002, a CPUC administrative law judge issued a proposed decision and a CPUC commissioner issued an alternate proposed decision in the URG proceeding. Both the proposed and alternate proposed decisions adopt most of the elements of SCE's application, but propose eliminating incremental cost incentive pricing for San Onofre, effective January 1, 2002, and replacing it with balancing account treatment for San Onofre's operating costs, subject to a later reasonableness review.

On February 7, 2002, another CPUC commissioner issued an alternate proposed decision recommending continuing the incentive pricing plan for San Onofre Units 2 and 3 through December 31, 2003, as originally provided in CPUC decisions adopted in early 1996. If the CPUC approves SCE's URG application, as filed, SCE expects to reapply accounting principles for rate-regulated enterprises for its generation assets. These assets will then be subject to traditional cost-of-service regulation.

Generation Procurement Proceeding In October 2001, the CPUC issued an order instituting rulemaking (OIR) to establish policies and cost recovery mechanisms for generation procurement. The OIR directed SCE and the other major California electric utilities to provide recommendations for establishing these policies and mechanisms to enable the utilities to resume their power procurement responsibilities in 2003. In comments filed with the CPUC on November 26, 2001, SCE recommended that the CPUC issue a procurement framework decision in February 2002, and direct the utilities to submit their specific procurement plan proposals and related framework compliance proposals in March 2002. SCE also proposed that a final decision be issued in October 2002 adopting utility-specific procurement plans. The CPUC has not yet acted on SCE's recommendations, but is expected in second quarter 2002 to issue a scoping memo setting forth issues to be addressed in this proceeding.

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FERC Related Matters 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.

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 its December 2000 order, the FERC established an "underscheduling" penalty applicable to scheduling coordinators that do not schedule sufficient resources to supply 95% of their respective loads. In December 2001, the FERC eliminated the underscheduling penalty, retroactive to January 1; 2001.

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 per 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 per 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.

On April 25, 2001, after months of extremely high power prices, the FERC issued an order providing for energy price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve power).

The order established an hourly clearing price based on the costs of the least efficient generating unit during the period. Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non-emergency periods and price mitigation in the 11-state western region. The latest order is in effect until September 30, 2002.

After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25, 2001, the FERC issued an order that limited potential refunds from alleged overcharges to the ISO and PX spot markets during the period from October 2, 2000, through June 20, 2001, and adopted a refund methodology based on daily spot market gas prices. An administrative law judge will conduct evidentiary hearings on this matter. SCE cannot predict the amount of any potential refunds. Under the CPUC Settlement Agreement, refunds will be applied to the balance in the PROACT.

See the "Regulatory Environment - Generation and Power Procurement" and "Regulatory Environment Rate Stabilization Proceedings" sections of the MD&A that is incorporated by reference into Part II, Item 7 for more information about SCE's revenue from its generation-related operations, recovery of its investment in its nuclear facilities, and on accounting for generation-related assets and power procurement costs.

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 13

has been 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 the decisions (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.

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 0 per kilowatt-hour for 90 days, subject to refund. This was followed by a 30 per kilowatt-hour surcharge pursuant to the CPUC's interim rate stabilization order adopted on March 27, 2001. 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.

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; (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; (7) administration of SCE's self-generation deferral rate contracts; and (8) the proposed additional 70 per MWh credit to Direct Access customers associated with SCE's procurement of PX energy for bundled service customers. On January 4, 2001, the CPUC issued its decision, which put SCE on notice that it will no longer be able to prospectively recover 100% of its reliability must-run costs in the TRA, and adopted all other RAP issues SCE requested.

On September 4, 2001, SCE filed its 2000/2001 RAP Report. On November 30, 2001, SCE amended its 2000/2001 RAP report to reflect the CPUC Settlement Agreement. The CPUC Settlement Agreement indicates that the TCBA (which, by definition, includes the TRA) shall have no further impact on SCE's retail electric rates. Thus, the only issues remaining in SCE's 2000/2001 RAP Report are a review of SCE's Low Emission Vehicle program and SCE's special contracts.

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 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. As a result, SCE's return on equity from 1999 through 2001 was unchanged at 11.6%.

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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 Proceeding 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 was to ensure the recovery of generation-related transition costs through the TCBA. The TCBA tracked the recovery of transition costs, including the accelerated recovery of plant balances, QF and purchased power costs, and regulatory assets and obligations. As discussed above, the CPUC recently approved the new ratemaking and accounting structure, referred to as the PROACT, to implement the CPUC Settlement Agreement. See the discussion above under "Changing Regulatory Environment - PROACT." The PROACT mechanism replaces the ATCP mechanism effective as of September 1, 2001. SCE will prepare and file revised testimony in its ATCP proceedings described below to withdraw all matters related to entries made on or before August 31, 2001. It is not known at this time whether or to what extent the CPUC's Office of Ratepayer Advocates (ORA), may recommend any disallowances related to the revised testimony.

1998 A TCP 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 February 17, 2000, the CPUC issued a decision finding that SCE's calculation of the TCBA for the record period was correct. The decision changed the accounting methodology used to estimate the market value of retained generating assets and required that SCE credit the TCBA for the aggregate net book value of certain of SCE's non-nuclear assets.

SCE reviewed the decision and discovered that the CPUC had inadvertently omitted establishing a new account to record the corresponding debit to the TOBA credit for the aggregate net book value of any remaining non-nuclear generation assets. SCE proposed that the Generation Asset Balancing Account (GABA) be established 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 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.

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 CPUC: (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. ORA subsequently withdrew its recommendation to defer its review of SCE's natural gas procurement and management activities and found the $10,000,000 post-period adjustment to be reasonable as well as SCE's natural gas procurement and management activities. The only contested issue that remains is the $882,000 in employee-related transition costs. Hearings were held in May 2001, and briefs were filed in June 2001. The CPUC has not yet issued a decision concerning the 2000 ATCP.

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2001 A TCP On September 4, 2001, SCE filed its 2001 ATCP report setting forth entries made to the TCBA and other generation memorandum accounts for the months of July 2000 through June 2001. On October 11, 2001, the ORA filed a protest to SCE's application which included a motion to consolidate SCE's application with those of PG&E and SDG&E. SCE opposed consolidation of its ATCP with the other application. A prehearing conference to establish a procedural schedule was held on November 14, 2001, at which time the administrative law judge ruled that SCE's ATCP would not be consolidated with those of PG&E and SDG&E.

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 would have continued through December 2001, earning a 7.35% fixed rate of return. However, due to the various unresolved regulatory and legislative issues (see discussion in "Changing Regulatory Environment" above), SCE is not able to conclude that the unamortized nuclear investment regulatory assets are probable of recovery through the ratemaking process. As a result, these balances were written off as a charge to earnings as of December 31, 2000.

In 1996, the CPUC adopted an incentive plan for SCE's San Onofre Units 2 and 3 under which SCE would have recovered its remaining investment in the San Onofre Units at a reduced rate of return of 7.35%, but on an accelerated basis during the eight-year period from the effective date in 1996 through December 31, 2003. California's restructuring legislation, however, required the recovery of the San Onofre investment to be completed by December 31, 2001. Due to the various unresolved regulatory and legislative issues (see discussion in "Regulation" above), SCE was not able to conclude that the unamortized nuclear investment regulatory assets were probable of recovery through the ratemaking process. As a result, these balances were written off as a charge to earnings as of December 31, 2000.

In addition, the incentive plan adopted by the CPUC in 1996 adopted a preset price for each kWh of energy generated at San Onofre during the eight-year period. Under the CPUC Settlement Agreement, SCE also retained the ability to request recovery of the cost of replacement energy for periods in which San Onofre will not generate power through energy cost adjustment clause filings and, beginning September 1, 2001, as part of the PROACT mechanism. San Onofre Units 2 and 3 incentive pricing was authorized to continue through December 31, 2003. On January 18, 2002, the assigned administrative law judge issued a proposed decision and CPUC President Loretta Lynch issued an alternate proposed decision in the URG proceeding both proposing to eliminate the existing cost recovery procedure for San Onofre Units 2 and 3, effective January 1, 2002, and to replace it with a balancing account treatment of San Onofre Units 2 and 3 operating costs, subject to a later reasonableness review. On February 7, 2002, CPUC Commissioner Bilas issued an alternate proposed decision that continued the existing procedure for San Onofre Units 2 and 3 through December 31, 2003. The restructuring legislation allows SCE to continue to collect funds for decommissioning expenses through traditional ratemaking treatment.

SCE requested in its URG application to recover the unamortized cost of the nuclear investment regulatory asset over a ten-year period, retroactive to January 1, 2001. All present proposed decisions and alternates in the URG proceeding would authorize this recovery. If any of the present URG proposed decisions are adopted, SCE would reestablish for financial reporting purposes its unamortized nuclear investment in San Onofre and Palo Verde and related flow-through taxes as regulatory assets with a corresponding credit to earnings.

In 1997, the CPUC approved San Diego Gas & Electric's (SDG&E) and SCE's joint petition to modify, requesting continued recovery of certain corporate administrative and general costs allocable to San Onofre Units 2 and 3, at rates of 0.28o and 0.21 o per kWh, respectively, for the period January 1, 1998, through December 31, 2003.

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Palo Verde Nuclear Generating Station In 1996, SCE filed an application requesting adoption of a new rate mechanism for Palo Verde consistent with that of San Onofre Units 2 and 3. See the discussion under "Other Rate Matters - San Onofre Nuclear Generating Station Units 2 and 3." On November 15, 1996, SCE, the ORA, and a consumer group entered into a settlement agreement, which was approved by the CPUC on December 20, 1996.

The settling parties agreed that SCE would recover its share of Palo Verde incremental operating costs, except if those costs exceed 95% of the levels forecast by SCE in its application by more than 30% in any given year. In such cases, SCE must demonstrate that the aggregate amount of the costs exceeding the forecast in that year is reasonable. If the annual Palo Verde site gross capacity factor is less than 55% in a calendar year, SCE will bear the burden of proof to demonstrate that the site's operations causing the gross capacity factor to fall below 55% were reasonable in that year. If operations are determined to be unreasonable by the CPUC, SCE's replacement power purchases associated with that period of Palo Verde operations below 55% gross capacity factor may be disallowed.

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 would have continued through December 2001, earning a 7.35% fixed rate of return. However, due to certain unresolved regulatory and legislative issues discussed above with respect to San Onofre, the unamortized nuclear investment regulatory assets were written off as a charge to earnings as of December 31, 2000. See the discussion under "Changing Regulatory Environment," above.

In January 1997, the CPUC authorized the future Palo Verde operating costs, including nuclear fuel costs and incremental capital expenditures, to be subject to balancing account treatment through 2001.

Beginning August 31, 2001, the balancing account became part of the PROACT mechanism. In January 1997, the CPUC also authorized continuation of the existing nuclear unit incentive procedure for Palo Verde. The existing procedure will continue only for purposes of calculating a reward for performance of any unit above an 80% capacity factor for a fuel cycle.

Beginning in 2002, SCE was required to share the net benefits received from the operation of Palo Verde equally with ratepayers. In a September 2001 decision, the CPUC granted SCE's request to eliminate the Palo Verde post-2001 benefit sharing mechanism and to continue the current rate treatment for Palo Verde, including the continuation of the existing nuclear unit incentive procedure with a 5o per kWh cap on replacement power costs, until resolution of SCE's next general rate case or further CPUC action. Palo Verde's existing nuclear unit incentive procedure calculates a reward for performance of any unit above an 80% capacity factor for a fuel cycle.

Fuel Supply and Purchased Power Costs In 2001, PX/ISO purchased power expense decreased in accordance with an emergency order signed by Governor Davis authorizing the CDWR to begin making emergency power purchases for SCE's customers beginning on January 17, 2001. In February 2001, Assembly Bill 1 (First Extraordinary Session, AB lX) was enacted into law. AB 1 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 bonds to finance electricity purchases. (See discussion above under "Changing Regulatory Environment - CDWR Power Purchases").

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.

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SCE's sources of energy during 2001 were as follows: 34% purchased power; 29.9% CDWR, ISO and PX; 19.1% nuclear; 13.4% coal; and 3.6% 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 a third party.

Nuclear Fuel Supply SCE has contractual arrangements covering 100% of the projected nuclear fuel requirements for San Onofre through the years indicated below:

U ranium concentrates(*)..................................................................................

2003 C o n v e rs io n................................................................................................

2 0 0 3 E n ric h m e nt................................................................................................

2 0 0 3 F a b ric a tio n................................................................................................

2 0 0 5

(*) Assumes the San Onofre participants meet their supply obligations in a timely manner.

Assuming normal operation and full utilization of existing on-site fuel-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. Additional on-site spent fuel storage capacity is being developed for availability in 2003 for San Onofre Unit 1, and by 2006 for San Onofre Units 2 and 3.

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 requirements through at least 2001 from existing contracts. Contracts covering 100% of requirements are in place for uranium enrichment and conversion through 2008 and fabrication through 2015.

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.

Coal Supply SCE purchases coal pursuant to long term contracts to provide stable and reliable fuel supplies to its two coal-fired generating stations (Mohave Station and Four Corners). SCE entered into a coal contract, dated September 1, 1966, with BHP Navajo Coal Company, the predecessor to the current owner of the Navajo mine, to supply coal to Units 4 and 5 of Four Corners. The coal supply contract's initial term is through 2004 and includes extension options for up to 15 additional years. For additional discussion of the litigation affecting the coal supply contract for the Mohave Station, see "Navajo Nation Litigation" in Part I, Item 3 of this report. SCE does not have reasonable assurance of an adequate coal supply for operating the Mohave Station after 2005. If reasonable assurance of an adequate coal supply is not obtained, it will become necessary to shut down the Mohave Station after December 31, 2005. If the station is shut down 18

at that time, the shutdown is not expected to have a material adverse impact on SCE's financial position or results of operations, assuming the remaining book value of the station (approximately $88 million as of December 31, 2001), and plant closure and decommissioning-related costs are recoverable in future rates. SCE cannot predict what effect any future actions by the CPUC may have on this matter.

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 Station located in Laughlin, Nevada, which is subject to certain air quality programs. SCE is the operator of the Mohave Station on behalf of its co-owners. 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 co-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 regional haze and visibility. The EPA issued its final rulemaking regarding regional haze regulations on July 1, 1999. That final rule does not impose any additional emissions control requirements on the Mohave Station beyond meeting the provisions of the consent decree.

Regarding visibility, a study was undertaken 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. In June 1999, the EPA issued an advanced notice of proposed rulemaking regarding assessment of visibility impairment at the Grand Canyon. The EPA issued its final rule on February 8, 2002, which incorporates the terms of the consent decree into the Visibility Federal Implementation Plan for the state of Nevada, making the terms of the consent decree federally enforceable.

SCE's share of the costs of complying with the consent decree and taking other actions to continue operation of the Mohave Station is estimated to be approximately $560 million over the next four years.

However, SCE has suspended its efforts to seek approval from the CPUC to install the Mohave Station controls because it has not obtained reasonable assurance of an adequate coal supply for operating Mohave Station beyond 2005. For additional discussion, see "Business - Fuel Supply and Purchased Power Costs - Coal Supply."

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 19

emissions if the EPA's Administrator makes certain findings. The study's final report to Congress concluded that mercury from coal-fired plants 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 plants are negligible and that there is no need for further evaluation of the risks of hazardous air pollutants emitted from such plants.

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. The 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 coal-and oil-fired generating facilities.

On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities, not including SCE, 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 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 controls, 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.

SCE owns a 48% undivided interest in Units 4 and 5 at the Four Corners coal plant in New Mexico, which is operated by Arizona Public Service Company (APS). On June 27, 2000, the EPA issued a request for information to the Four Corners plant. On September 1, 2000, APS replied to the request. To date, no further action has been taken with respect to the Four Corners plant.

Regulations under the Clean Water Act require permits for the discharge of certain pollutants into United States 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.

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 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 20

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 undiscounted amounts).

SCE's environmental liabilities include expenses to remediate sites currently owned by SCE or by third parties, and for which SCE has been named as one of the potential responsible parties. They also include mitigation expenses associated with the construction of its San Onofre nuclear power plant.

As of December 31, 2001, SCE's recorded estimated minimum liability to remediate its 42 identified sites is $111 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: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and 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

$279 million. The upper limit of this range of costs ($390.2 million) was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. SCE has sold all of its gas fueled generation plants and has retained some liability associated with the divested properties.

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. No reasonable estimate of cleanup costs can now be made for these sites. Thus, the estimated minimum liability and possible range does not include any monetary information associated with these sites.

The CPUC allows SCE to recover environmental-cleanup costs at certain sites, representing $50 million of its recorded liability, through an incentive mechanism. 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 subject to certain time limitations. 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

$76 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.

SCE expects to clean up its identified sites over a period of up to 30 years. Remediation expenditures in each of the next several years are expected to range from $10 million to $25 million. Recorded expenditures for 2001 were $16.8 million.

Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental cleanup costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.

Currently, environmental advocacy groups and regulatory agencies in the United States are focusing considerable attention on carbon dioxide emissions from coal-fired power plants and their potential role in the "global-warming" issue. SCE believes that evolving environmental laws and regulations will need to recognize that coal-fired power plants must continue to play an essential role in providing electricity 21

supply. Nevertheless, the fact that SCE is a co-owner of two coal-fired power plants exposes the company to the uncertainties and risks inherent in the environmental laws and regulations applicable to such plants. The adoption of laws and regulations to implement carbon dioxide controls could adversely impact SCE's coal plants. Coal plant emissions of nitrogen and sulphur oxides, mercury and particulates also are potentially subject to increased controls. The Bush administration, Congress and the EPA are now considering various proposals that would impose, or modify, controls on these power plant emissions.

As a regulated utility, SCE has access to cost-of-service ratemaking that may allow it to recover costs reasonably incurred in complying with environmental regulations. For additional discussion, see "Business - Environmental Matters."

SCE's projected environmental capital expenditures are $1.3 billion for the 2002 - 2006 period, mainly for undergrounding certain transmission and distribution lines.

Item 2. Properties Existing Generating Facilities SCE owns and operates one diesel-fueled generating plant located on Santa Catalina Island, 37 hydroelectric plants, and an undivided 75.05% interest (1,614 MW net) in San Onofre nuclear generating station Units 2 and 3. These plants are located in Central and Southern California.

SCE also operates and owns a 56% undivided interest (885 MW) in the Mohave Station, which consists of two coal-fueled generating units in Clark County, Nevada. See "Business - Environmental Matters and

- Fuel Supply and Purchased Power Costs - Coal Supply," above, for a discussion of the coal supply and environmental issues affecting the Mohave Station.

SCE also owns a 15.8% (590 MW net) share of Palo Verde nuclear generating station, which is located near Phoenix, Arizona, and a 48% undivided interest (754 MW net) in Units 4 and 5 at the Four Corners, which is a coal-fueled generating plant located in New Mexico. Palo Verde and Four Corners are operated by other utilities.

In April 2000, SCE agreed to sell its 15.8% interest in Palo Verde and its 48% interest in Four Corners to Pinnacle West Energy. In May 2000, after conducting an auction that had been approved by the CPUC, SCE agreed to sell its 56% interest in Mohave to The AES Corporation. All three of these transactions remained subject to certain conditions, including the final approval of the CPUC. However, the CPUC suspended action on these sales as problems began to develop in the California electricity market. As indicated above, subsequently enacted California state legislation barred the sale of utility generating facilities until 2006. Consequently, SCE then withdrew its applications to sell its shares of Palo Verde, Four Corners and Mohave plants.

During the fall of 2003, the steam generators are scheduled to be replaced at Palo Verde Unit 2. SCE and the other participants are also considering issues related to the potential replacement of the steam generators in Units 1 and 3. Although a final determination of whether Units 1 and 3 steam generators will be replaced has not yet been made, SCE and the other participants have approved the expenditure of

$25.6 million ($4.0 million SCE share) in 2002 to procure long lead-time materials for fabrication of a spare set of steam generators for either Unit 1 or 3. This action will provide Palo Verde participants an option to replace the steam generators in Unit 1 as early as fall 2005 or in Unit 3 as early as fall 2007 should they ultimately decide to do so. If the participants decide to proceed with the earliest possible steam generator replacement at both Units 1 and 3, SCE estimates that its portion of the fabrication and installation costs and associated power upgrade modifications would be approximately $70 million over the next seven years.

At year-end 2001, the existing SCE-owned generating capacity (summer effective rating) was divided approximately as follows: 44% nuclear, 32% coal, 24% hydroelectric, and less than 1% diesel. San Onofre, Four Corners, certain of SCE's substations and portions of its transmission, distribution and communication systems are located on lands of the United States or others under (with minor exceptions) 22

licenses, permits, easements or leases, or on public streets or highways pursuant to franchises. Certain of such documents obligate SCE, under specified circumstances and at its expense, to relocate transmission, distribution, and communication facilities located on lands owned or controlled by federal, state, or local governments.

The 37 hydroelectric plants (some with related reservoirs) have an effective operating capacity of 1,156 MW, and are, with five exceptions, located in whole or in part on United States lands pursuant to, 30- to 50-year governmental licenses that expire at various times between 2001 and 2029. Such licenses impose numerous restrictions and obligations on SCE, including the right of the United States to acquire projects upon payment of specified compensation. When existing licenses expire, the FERC has the authority to issue new licenses to third parties, but only if their license application is superior to SCE's and then only upon payment of specified compensation to SCE. Any new licenses issued to SCE are expected to be issued under terms and conditions less favorable than those of the expired licenses.

SCE's applications for the relicensing of certain hydroelectric projects with an aggregate dependable operating capacity of about 112.67 MW are pending. Annual licenses have been issued to SCE hydroelectric projects that are undergoing relicensing and whose long-term licenses have expired. The annual licenses will be renewed until the long-term licenses are issued.

SCE filed an application with the CPUC on December 15, 1999, seeking authorization to market value and retain the ownership and operation of the hydroelectric plants pursuant to the State's electric utility industry restructuring legislation. In June 2000, SCE credited the TCBA with the proposed excess of market value over book value of its hydroelectric generation assets and simultaneously recorded the same amount in the GABA (see "1998 ATCP" above), pursuant to a CPUC decision. This balance was to remain in GABA until final market valuation of the hydroelectric assets. Due to the various unresolved regulatory and legislative issues (as discussed in Regulation), the GABA transaction was reclassified back to the TCBA, and the TCBA balance (as recalculated based on a March 27, 2001, CPUC interim decision) was written off as of December 31, 2000. Pursuant to the terms of the CPUC Settlement Agreement, SCE is no longer proposing to market value its hydro facilities. Accordingly, SCE filed a motion on November 15, 2001, to withdraw its December 1999 petition.

In 2001, the capacity factors in 2001 for SCE's principal generation resources were: 30% for SCE's hydroelectric plants (lower than average due to below-normal water conditions); 80% for San Onofre; 74% for the Mohave Station; 87% for Four Corners Units 4 and 5; and 88% for Palo Verde.

Substantially all of SCE's properties are subject to the lien of a trust indenture securing First and Refunding Mortgage Bonds (Trust Indenture), of which approximately $3.6 billion in principal amount was outstanding on March 1, 2002. Such lien and SCE's title to its properties are subject to the terms of franchises, licenses, easements, leases, permits, contracts, and other instruments under which properties are held or operated, certain statutes and governmental regulations, liens for taxes and assessments, and liens of the trustees under the Trust Indenture. In addition, such lien and SCE's title to its properties are subject to certain other liens, prior rights and other encumbrances, none of which, with minor or insubstantial exceptions, affect SCE's right to use such properties in its business, unless the matters with respect to SCE's interest in Four Corners and the related easement and lease referred to below may be so considered.

SCE's rights in Four Corners, which is located on land of The Navajo Nation of Indians under an easement from the United States and a lease from The Navajo Nation, may be subject to possible defects.

These defects include possible conflicting grants or encumbrances not ascertainable because of the absence of, or inadequacies in, the applicable recording law and the record systems of the Bureau of Indian Affairs and The Navajo Nation, the possible inability of SCE to resort to legal process to enforce its rights against The Navajo Nation without Congressional consent, possible impairment or termination under certain circumstances of the easement and lease by The Navajo Nation, Congress, or the Secretary of the Interior, and the possible invalidity of the Trust Indenture lien against SCE's interest in the easement, lease, and improvements on Four Corners.

23

Construction Program and Capital Expenditures Cash required by SCE for its capital expenditures totaled $569 million in 2001, $1.0 billion in 2000, and

$959 million in 1999. Construction expenditures for the 2002 - 2006 period are forecasted at $6.2 billion, but may have to be changed depending on SCE's financial situation.

In addition to cash required for construction expenditures for the next five years as discussed above,

$3.6 billion is needed to meet requirements for long-term debt maturities and sinking fund redemption requirements.

SCE's estimates of cash available for operations for the five years through 2006 assume, among other things, satisfactory reimbursement of cost incurred during the California energy crisis, the receipt of adequate and timely rate relief and the realization of its assumptions regarding cost increases, including the cost of capital. SCE's estimates and underlying assumptions are subject to continuous review and periodic revision.

The timing, type, and amount of all additional long-term financing are also influenced by market conditions, rate relief, and other factors, including limitations imposed by SCE's Articles of Incorporation and Trust Indenture. SCE's ability to obtain financing has been affected adversely by the effects of California's energy crisis during 2000 and 2001, as described above in Part I under "Changing Regulatory Environment - Liquidity Issues."

Nuclear Power Matters SCE's nuclear facilities have been reliable sources of inexpensive, non-polluting power for SCE's customers for more than a decade. Throughout the operating life of these facilities, SCE's customers have supported the revenue requirements of SCE's capital investment in these facilities and for their incremental costs through traditional cost-of-service ratemaking.

SCE requested in its URG application to recover the unamortized cost of the nuclear investment regulatory asset over a ten-year period, retroactive to January 1, 2001. All present proposed decisions and alternates in the URG proceeding would authorize this recovery. If any of the present URG proposed decisions are adopted, SCE would reestablish for financial reporting purposes its unamortized nuclear investment in San Onofre and Palo Verde and related flow-through taxes as regulatory assets with a corresponding credit to earnings.

San Onofre Nuclear Generating Station San Onofre Unit 3 suffered a forced outage because of the failure of an electrical component in the non-nuclear portion of the plant resulting in a fire on February 3, 2001. The electrical circuit breaker failure and resultant fire had significant consequences beyond just the damage to the electrical components and cabling. Loss of electrical power supply also resulted in loss of lubricating oil to the turbine generator system while it was still rotating. This caused severe and extensive damage to the turbine generator rotors, bearings and other components. San Onofre Unit 3 returned to service on June 1, 2001, and has operated reliably since that date. The lost revenue due to this repair outage was covered by SCE's insurance.

The San Onofre Units 2 and 3 steam generator design allows for the removal of up to 10% of the tubes before the rated capacity of the unit must be reduced. Increased tube degradation was found during routine inspections in 1997. To date, 8% of Unit 2's tubes and 6% of Unit 3's tubes have been removed from service. A decreasing (favorable) trend in degradation has been observed in more recent inspections.

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Additionally, in the summer of 2000, SCE applied for a coastal permit to construct a dry cask spent fuel storage facilities for Units 2 and 3. This permit was approved, with certain conditions, by the California Coastal Commission at its meeting on March 13, 2001.

Nuclear Facility Decommissioning In 1992, the CPUC approved a settlement agreement between SCE and the ORA to discontinue operation of San Onofre Unit 1 at the end of its then-current fuel cycle. In November 1992, SCE discontinued operation of Unit 1. As part of the agreement, SCE recovered its remaining investment over a four-year period ending August 1996. On December 21, 1998, SCE filed an application with the CPUC requesting authorization to access its nuclear decommissioning trust funds for Unit 1 for the purpose of commencing decommissioning of Unit 1 in 2000. On March 8, 1999, SCE, SDG&E, the ORA and TURN entered into a settlement agreement that provided for SCE to access its nuclear decommissioning trust funds for Unit 1 decommissioning. On June 3,1999, the CPUC adopted the settlement agreement. On December 6, 1999, SCE applied for a coastal permit to demolish and remove San Onofre Unit 1 buildings and other structures and to construct a temporary dry cask spent fuel storage facility as part of the San Onofre Unit 1 decommissioning project. On February 15, 2000, the California Coastal Commission approved SCE's application. Decommissioning of Unit 1 is now underway and will be completed in three phases, (1) decontamination and dismantling of all structures and most foundations, (2) spent fuel storage monitoring, and (3) fuel storage facility dismantling and site restoration. Phase one is anticipated to continue through 2008. Phase two is expected to continue until 2026. Phase three will be conducted concurrently with San Onofre Units 2 and 3 decommissioning projects. All of SCE's reasonable San Onofre Unit 1 decommissioning costs will be paid from its nuclear decommissioning trust funds.

SCE plans to decommission its nuclear generating facilities as expeditiously as possible once authorized by the NRC. Decommissioning is expected to begin after the plants' operating licenses expire. The operating licenses expire in 2022 for San Onofre Units 2 and 3, and in 2026 and 2028 for the Palo Verde units. Decommissioning costs, which are recovered through non-bypassable customer rates and are recorded as a component of depreciation expense.

Decommissioning is estimated to cost $2.1 billion in year 2001 dollars based on site-specific studies performed in 1998 for San Onofre and Palo Verde. This estimate considers the total cost of decommissioning and dismantling the plant, including labor, material, burial, and other costs. The site specific studies are updated approximately every three years. Changes in the estimated costs, timing of decommissioning, or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission in the near-term. SCE estimates that it will spend approximately

$8.6 billion in nominal dollars through completion of decommissioning of its nuclear facilities.

Decommissioning expenses were $96 million in 2001, $106 million in 2000, and $124 million in 1999.

The accumulated provision for decommissioning excluding San Onofre Unit 1 and unrealized holding gains was $1.5 billion at December 31, 2001, $1.4 billion at December 31, 2000, and $1.3 billion at December 31, 1999. The estimated cost to decommission San Onofre Unit 1 is approximately $300 million in year 2001 dollars and is recorded as a liability.

Decommissioning funds collected in rates are placed in independent trust accounts which, together with accumulated earnings, will be utilized solely for decommissioning.

Nuclear Insurance Federal law limits public liability claims from a nuclear incident to $9.5 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available

($200 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site. Federal 25

regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $88 million per reactor, but not more than $10 million per reactor may be charged in any one year for each incident. Based on its ownership interests, SCE could be required to pay a maximum of $175 million per nuclear incident. It would have to pay, however, no more than $20 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators.

Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary

$500 million has also been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. These policies are issued by a mutual insurance company owned by utilities with nuclear facilities. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to $35 million per year. Insurance premiums are charged to operating expense.

The Federal law requiring the nuclear insurance described above for all new NRC licensed reactors was due to expire in August 2002. The United States Senate passed an amendment to the Energy bill which renews the law for another 10 years. The United States House of Representatives has also passed a bill renewing the law for another 10 years. Congressional action to reconcile differences between the House and Senate versions appears to be necessary. Even if this Federal law did expire, all of the nuclear insurance provisions required by the law, as described above, will still apply to SCE, as an owner of the existing San Onofre and Palo Verde units, until the termination of each unit's NRC license and the removal of all radioactive materials from its site.

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Item 3. Legal Proceedings San Onofre Personal Injury Litigation SCE is actively involved in four lawsuits claiming personal injuries allegedly resulting from exposure to radiation at San Onofre.

On August 31, 1995, the wife and daughter of a former San Onofre security supervisor sued SCE and SDG&E in the United States District Court for the Southern District of California. Plaintiffs also named Combustion Engineering and the Institute of Nuclear Power Operations as defendants. All trial court proceedings were stayed pending ruling of the Ninth Circuit Court of Appeals, on an appeal of a lower court's judgment in favor of SCE in two earlier cases raising similar allegations. On May 28, 1998, the Court of Appeals affirmed these judgments. Pursuant to an agreement of the parties as described below, all proceedings in this matter have been stayed.

On November 17, 1995, an SCE employee and his wife sued SCE in the United States District Court for the Southern District of California. Plaintiffs also named Combustion Engineering. The trial in this case resulted in a jury verdict for both defendants. The plaintiffs' motion for a new trial was denied. Plaintiffs filed an appeal of the trial court's judgment to the Ninth Circuit Court of Appeals. Briefing on the appeal was completed in January 1999, oral argument took place on February 10, 2000, and the matter was taken under submission. On July 20, 2000, the Ninth Circuit Court of Appeals issued an opinion reversing the District Court judgment and ordering a retrial as to both defendants. On August 10, 2000, SCE filed a petition for rehearing with the Ninth Circuit Court of Appeals. On September 27, 2001, the Ninth Circuit issued a new opinion affirming the District Court judgment in favor of all defendants. On October 9, 2001, plaintiffs filed a petition for rehearing or, in the alternative, for a rehearing en banc, with the Ninth Circuit. On December 28, 2001, the Ninth Circuit denied plaintiffs' petition for rehearing and its alternative petition for a rehearing en banc. Plaintiffs could seek further review in the United States Supreme Court.

On November 28, 1995, a former contract worker at San Onofre, her husband, and her son, sued SCE in the United States District Court for the Southern District of California. Plaintiffs also named Combustion Engineering. On August 12, 1996, the Court dismissed the claims of the former worker and her husband with prejudice, leaving only the son as plaintiff. Pursuant to an agreement of the parties as described below, all proceedings in the matter have been stayed.

On May 9, 2001, SCE was served with a complaint filed on March 1, 2001, by a former contract worker at San Onofre and his wife in the United States District Court for the Southern District of California. In addition to SCE, plaintiffs also named as defendants Combustion Engineering and Bechtel Construction Company, the employer of the former San Onofre worker. Pursuant to an agreement of the parties as described below, all proceedings in this matter have been stayed.

In March 1999, SCE reached an agreement with the plaintiffs in the above four cases at the United States District Court level to stay all proceedings including trial, pending the results of the case currently before the Ninth Circuit Court of Appeals. The parties agreed that if the plaintiffs do not receive a favorable determination on appeal then the two cases at the District Court level will be dismissed. If, however, those plaintiffs receive a favorable determination on their appeal, then the two District Court cases will be set for trial. On March 23, 1999, the District Court approved the parties' stay agreement in both cases. The stay will remain in effect until the conclusion of the appellate process, including filing and disposition of any petitions for rehearing in the Ninth Circuit or petitions for certiorari in the United States Supreme Court.

SCE was previously involved, along with other defendants, in two earlier cases raising allegations similar to those described above. Plaintiffs in those cases have agreed to a stay of proceedings similar to the stay agreements entered into by plaintiffs with SCE in the above four lawsuits. Although SCE is no longer actively involved in these actions, the impact on SCE, if any, from further proceedings in those cases against the remaining defendants cannot be determined at this time.

27

Navajo Nation Litigation On June 18, 1999, SCE, was served with a complaint filed by the Navajo Nation in the United States District Court for the District of Columbia against Peabody Holding Company and certain of its affiliates (Peabody), Salt River Project Agricultural Improvement and Power District, and SCE. The complaint asserts claims against the defendants for, among other things, violations of the federal RICO statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentation by nondisclosure, and various contract-related claims. Peabody supplies coal from mines on Navajo Nation lands to the Mohave Station. The complaint claims that the defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal. The complaint seeks damages of not less than

$600 million, trebling of that amount, and punitive damages of not less than $1 billion, as well as a declaration that Peabody's lease and contract rights to mine coal on Navajo Nation lands should be terminated. SCE joined Peabody's motion to strike the Navajo Nation's complaint. In addition, SCE and the other defendants have filed motions to dismiss.

The Navajo Nation had previously filed suit in the Court of Claims against the United States Department of Interior, alleging that the Government had breached its fiduciary duty concerning the above-referenced contract negotiations. On February 4, 2000 the Court of Claims issued a decision in the Government's favor, finding that while there had been a breach, there was no available redress from the Government. In its decision, the Court indicated that it was making no statements regarding, or findings in, the above federal civil court action. That decision is on appeal. On February 28, 2000, the Hopi Tribe filed a motion to intervene in the pending litigation, alleging that the royalty payments set for their interest in the coal leases with Peabody had been impacted by the events at issue in the Navajo case. The defendants filed an opposition to the motion, and the Court calendared all pending motions for hearing on March 15, 2001. On March 15, 2001, the District Court heard arguments, granted the Hopi Tribe's motion to intervene and denied Peabody and SCE's motions to dismiss. The Court, however, did grant Salt River's motion on jurisdictional grounds. The Court denied SCE's and Peabody's motions to allow an interlocutory appeal.

Peabody and SCE filed cross claims against the Navajo Nation on February 21, 2002, alleging that the Navajo breached a settlement agreement between Peabody and the Navajo Nation by filing their lawsuit.

Additionally, Peabody has filed a motion to transfer the matter to Arizona in conjunction with their demand that the matter be submitted to arbitration pursuant to the settlement agreement. A response to the cross claim or the motion to transfer has not yet been received.

Shareholder Litigation Two purported class actions were filed in October 2000 and March 2001, and involved securities fraud claims arising from alleged improper accounting by Edison International and SCE of undercollections in SCE's TRA. These actions, as described below, were dismissed with prejudice on March 8, 2002.

On October 30, 2000, a purported class action lawsuit was filed in federal district court in Los Angeles against SCE and Edison International. By agreement of the parties and the Court, plaintiffs amended their complaint on two occasions. Pursuant to this stipulation, on March 5, 2001, plaintiffs filed a second amended complaint. The second amended complaint alleged that the companies were engaging in securities fraud by over-reporting income and improperly accounting for the TRA undercollections. The second amended complaint purported to be filed on behalf of a class of persons who purchased Edison international common stock beginning June 1, 2000, and continuing until such time as TRA-related undercollections were recorded as a loss on SCE's income statements. The second amended complaint sought compensatory damages caused by the alleged fraud as well as punitive damages. As discussed below, this lawsuit was consolidated with another action, a new consolidated complaint was filed and defendants responded to the consolidated complaint.

On March 15, 2001, a purported class action lawsuit was filed in federal district court in Los Angeles, California, against Edison International and SCE and certain of their officers. The complaint alleged that the defendants engaged in securities fraud by misrepresenting and/or failing to disclose material facts 28

concerning the financial condition of Edison International and SCE, including that the defendants allegedly overreported income and improperly accounted for the TRA undercollections. The complaint purported to be filed on behalf of a class of persons who purchased publicly-traded securities of Edison International between May 12, 2000, and December 22, 2000. Plaintiffs sought damages, in an unstated amount, in connection with their purchase of securities during the class period.

On August 3, 2001, the plaintiffs in both cases filed a consolidated complaint on behalf of alleged shareholders of Edison International, naming as defendants SCE, Edison International, and certain officers of Edison International. The consolidated complaint alleged that the defendants engaged in securities fraud by misrepresenting and/or failing to disclose material facts concerning the financial condition of Edison International and SCE, including that defendants allegedly over-reported income and improperly accounted for the TRA undercollections. The complaint purported to be filed on behalf of a class of persons who purchased Edison International stock between July 21, 2000, and April 17, 2001.

Plaintiffs sought damages in an unstated amount in connection with their purchase of securities during the class period. On September 17, 2001, the defendants filed a motion to dismiss for failure to state a claim.

On March 8, 2002, the Court issued an order granting the motion and dismissing the complaint with prejudice as to all defendants. Plaintiffs could appeal this ruling to the Ninth Circuit Court of Appeals.

Qualifying Facilities Litigation SCE is involved in a number of legal actions brought by various QFs, alleging SCE failed to timely pay for power deliveries made from November 1, 2000, through March 26, 2001. The OF plaintiffs include gas-fired cogenerators and owners of solar, wind, geothermal and biomass projects. The lawsuits, in aggregate, seek payments of more than $833,000,000 for energy and capacity supplied to SCE under QF contracts, and in some cases additional damages. Many of these OF lawsuits also seek an order allowing the suppliers to stop providing power to SCE so that they may sell to other purchasers.

The table below sets forth the principal parties, filing date and court jurisdiction of the OF litigation:

Principal Party Date Filed Court Jurisdiction City of Long Beach Salton Sea Power Generation, L.P.

Beowawe Power, L.L.C.

Mohave 16/17/18 LLC; Ridgetop Energy, L.L.C.

IMC Chemicals, Inc.

NP Cogen, Inc.

Watson Cogeneration Co.

O.L.S. Energy-Chino E.F. Oxnard, Inc.

Herber Geothermal Company Inland Paperboard and Packaging, Inc.

Mammoth Pacific, L.P.

Brea Power Partners, L.P.

Kern River Cogeneration Company February 9, 2001 February 20, 2001 March 2, 2001 March 5, 2001 March 26, 2001 March 28, 2001 March 29, 2001 March 30, 2001 April 2, 2001 April 6, 2001 April 9, 2001 April 9, 2001 April 5, 2001 April 10, 2001 Los Angeles County Superior Court, South District Imperial County Superior Court United States District Court, District of Nevada Los Angeles County Superior Court, Central District San Bernardino County Superior Court, Barstow District Los Angeles County Superior Court, Central District Los Angeles County Superior Court Los Angeles County Superior Court, Central District United States District Court, Central District Imperial County Superior Court United States District Court, Central District Mono County Superior Court Los Angeles County Superior Court, Central District Kern County Superior Court 29

Southern California Sunbelt Developers Corona Energy Partners, LTD Procter & Gamble Paper Products Company Oak Creek Wind Power, Inc.

Willamette Industries, Inc.

Mammoth Pacific, L.P.

Berry Petroleum Company Ace Cogeneration Company Cabazon Power Partners LLC U.S. Borax Inc.

Black Hills Ontario, LLC Luz Solar Partners LTD., III Rio Bravo Jasmin CalWind Resources Wheelabrator Norwalk Energy Co. Inc.

Smurfit Stone Container Ripon Cogeneration, Inc.

San Gorgonio Westwinds II, LLC Colmac Energy, Inc.

Midway-Sunset Cogeneration Company March 27, 2001 April 5, 2001 April 11, 2001 April 16, 2001 April 12, 2001 May 25, 2001 May 2, 2001 May 1,2001 May 2, 2001 May 6, 2001 May 7, 2001 May 8, 2001 May 16, 2001 May 18, 2001 May 18, 2001 May 24, 2001 June 6, 2001 June 8, 2001 June 12, 2001 June 7, 2001 Riverside County Superior Court, Indio Branch Riverside County Superior Court Ventura County Superior Court Kern County Superior Court, Central District Ventura County Superior Court Los Angeles County Superior Court Los Angeles County Superior Court, Central District Los Angeles County Superior Court, Central District Los Angeles County Superior Court, Central District Kern County Superior Court San Bernardino County Superior Court, Rancho Cucamonga District Sacramento County Superior Court Los Angeles County Superior Court Los Angeles County Superior Court Los Angeles County Superior Court, Southeast District United States District Court, Central District Los Angeles County Superior Court Riverside County Superior Court Los Angeles County Superior Court Kern County Superior Court Plaintiffs in most of these cases have entered into settlement agreements providing for stays of litigation, payments to the QFs upon the occurrence of specified conditions, modifications in some cases to the contract prices going forward, releases and dismissals of the litigation upon payment by SCE. On March 1, 2002, and with several exceptions related to unique disputes or other unique circumstances, including the status of regulatory approval, SCE paid the amounts due under the settlement agreements with these QFs, which triggered the releases and other provisions effectuating the settlements. As a result, the litigation with those QFs to whom payment in full has been made under the parties' settlement agreements should be dismissed during 2002.

Power Exchange (PX) Performance Bond Litigation On January 19, 2001, American Home Assurance Company (American Home) notified SCE that due to SCE's failure to comply with its payment obligations to the PX, the PX issued a demand to American Home on a $20,000,000 pool performance bond. American Home demanded payment from SCE by January 29, 2001, of $20,000,000 under an indemnity agreement between SCE and American Home.

SCE has exercised its right under the indemnity agreement to assume the defense of American Home against claims arising from the pool performance bond. As required by the indemnity agreement, in February 2001, SCE deposited $20,200,000 in an account in trust to be available to satisfy any judgment, should there be one, against American Home as a result of SCE's alleged default. SCE has further instituted the alternative dispute resolution provisions provided for in the applicable PX tariff, which provide for negotiation followed by mediation and, if unsuccessful, arbitration. On or about September 13, 2001, 30

the PX submitted a demand for arbitration against American Home, asserting causes of action for breach of contract and bad faith refusal to pay. On September 25, 2001, American Home demanded that SCE indemnify and defend American Home in connection with the demand for arbitration, pursuant to the operative documents between the parties. SCE assumed the defense of the arbitration. On March 1, 2002, SCE made payment directly to CaIPX on the full amount of its outstanding obligations. See "Business - Changing Regulatory Environment - Liquidity Issues." CaIPX was unwilling to provide American Home with an exoneration of the pool performance bond, and has continued to pursue the arbitration, asserting, among other things, that it is entitled to the face amount of the bond on account of PG&E's default. On March 19, 2002, American Home initiated suit against SCE, alleging that SCE's failure to obtain an exoneration of the bond in connection with SCE's payment of its indebtedness was a material breach of the indemnity agreement.

CPUC Litigation and Settlement See the discussion under "Changing Regulatory Environment" for a description of SCE's lawsuit against the CPUC, its settlement (referred to as the CPUC Settlement Agreement), and the legal proceedings associated with the CPUC Settlement Agreement, including the appeal thereof.

Item 4. Submission of Matters to a Vote of Security Holders Inapplicable Pursuant to Form 10-K's General Instruction (General Instruction) G(3), the following information is included as an additional item in Part 1:

Executive Officers(') of the Registrant Age at Executive Officer December 31, 2001 Company Position Alan J. Fohrer 51 Chairman of the Board, Chief Executive Officer and Director Robert G. Foster 54 President Harold B. Ray 61 Executive Vice President, Generation Business Unit Pamela A. Bass 54 Senior Vice President, Customer Service Business Unit John R. Fielder 56 Senior Vice President, Regulatory Policy and Affairs Stephen E. Pickett 51 Senior Vice President and General Counsel Richard M. Rosenblum 51 Senior Vice President, Transmission and Distribution Business Unit Mahvash Yazdi 50 Senior Vice President and Chief Information Officer Bruce C. Foster 49 Vice President, Regulatory Operations Frederick J. Grigsby, Jr.

54 Vice President, Human Resources & Labor Relations Thomas M. Noonan 50 Vice President and Controller W. James Scilacci 46 Vice President and Chief Financial Officer Executive Officers are defined by Rule 3b-7 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended.

31

None of SCE's executive officers is related to each other by blood or marriage. As set forth in Article IV of SCE's Bylaws, the elected officers of SCE are chosen annually by and serve at the pleasure of SCE's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. All of the above officers have been actively engaged in the business of SCE for more than five years except Mahvash Yazdi and Frederick J. Grigsby, Jr. Those officers who have not held their present position with SCE for the past five years had the following business experience during that period:

Executive Officer Company Position Effective Dates Alan J. Fohrer Chairman of the Board, Chief Executive January 2002 to present Officer and Director, SCE President and Chief Executive Officer, January 2000 to December 2001 Edison Mission Energy Executive Vice President and Chief Financial September 1996 to January 2000 Officer, Edison International Chairman of the Board, Edison Enterprises January 1998 to September 1999 Executive Vice President and Chief Financial September 1996 to December 1999 Officer, SCE Vice Chairman of the Board, Edison Mission May 1993 to January 1999 Energy Robert G. Foster President, SCE January 2002 to present Senior Vice President, External Affairs, SCE April 2001 to December 2001 and Edison International Senior Vice President, Public Affairs, SCE November 1996 to April 2001 and Edison International Pamela A. Bass Senior Vice President, Customer Service March 1999 to present Business Unit, SCE Vice President, Customer Solutions June 1996 to February 1999 Business Unit, SCE John R. Fielder Senior Vice President, Regulatory Policy and February 1998 to present Affairs, SCE Vice President, Regulatory Policy and February 1992 to February 1998 Affairs, SCE Stephen E. Pickett Senior Vice President and General Counsel, January 2002 to present SCE Vice President and General Counsel, SCE January 2000 to December 2001 Associate General Counsel, SCE November 1993 to December 1999 Richard M. Rosenblum Senior Vice President, Transmission and February 1998 to present Distribution Business Unit, SCE Vice President, Distribution Business Unit, January 1996 to February 1998 SCE Mahvash Yazdi Senior Vice President and Chief Information January 2000 to present Officer, SCE and Edison International Vice President and Chief Information Officer, May 1997 to December 1999 SCE and Edison International Vice President of Information Technology September 1995 to May 1997 and Chief Information Officer, Hughes Aircraft Company"'

Frederick J. Grigsby, Jr.

Vice President, Human Resources & Labor July 2001 to present Relations Senior Vice President, Human Resources, December 1998 to October 2000 Fluor Corporation"'

Vice President, Human Resources, Thermo December 1995 to November 1998 King Corporation (_)(3) 32

Thomas M. Noonan Vice President and Controller, SCE and March 1999 to present Edison International Assistant Controller, SCE and Edison September 1993 to February 1999 International W. James Scilacci Vice President and Chief Financial Officer, January 2000 to present SCE Director, 2002 General Rate Case, SCE August 1999 to December 1999 1 Director, Qualifying Facility Resources, SCE January 1995 to August 1999 (1) This entity is not a parent, subsidiary or other affiliate of SCE.

2)'The Fluor Corporation is one of the world's largest, publicly owned engineering, procurement, construction, and maintenance services organizations.

(3)Thermo King Corporation provides climate control solutions for global transportation industries.

PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters Certain information responding to Item 5 with respect to frequency and amount of cash dividends is included in SCE's Annual Report to Shareholders for the year ended December 31, 2001 (Annual Report),

under Quarterly Financial Data on page 49 and is incorporated by reference pursuant to General Instruction G(2). As a result of the formation of a holding company described above in Item 1, all of the issued and outstanding common stock of SCE is owned by Edison International and there is no market for such stock.

Item 6. Selected Financial Data Information responding to Item 6 is included in the Annual Report under Selected Financial and Operating Data: 1996 - 2001 on page 1 and is incorporated herein by reference pursuant to General Instruction G(2).

Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition Information responding to Item 7 is included in the Annual Report under Management's Discussion and Analysis of Results of Operations and Financial Condition on pages 2 through 20 and is incorporated herein by reference pursuant to General Instruction G(2).

Item 7A. Quantitative and Qualitative Disclosures About Market Risk Information responding to Item 7A is included in the Annual Report under Management's Discussion and Analysis of Results of Operations and Financial Condition on pages 8 through 9 incorporated herein by reference pursuant to General Instruction G(2).

Item 8. Financial Statements and Supplementary Data Certain information responding to Item 8 is set forth after Item 14 in Part IV. Other information responding to Item 8 is included in the Annual Report on pages 21 through 49, and is incorporated herein by reference pursuant to General Instruction G(2).

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.

33

PART III Item 10. Directors and Executive Officers of the Registrant Information concerning executive officers of SCE is set forth in Part I in accordance with General Instruction G(3), pursuant to Instruction 3 to Item 401 (b) of Regulation S-K. Other information responding to Item 10 will be incorporated by reference from SCE's definitive Joint Proxy Statement (Proxy Statement) filed with the SEC in connection with SCE's Annual Shareholders' Meeting to be held on May 14, 2002, under the headings, "Election of Directors" and is incorporated herein by reference pursuant to General Instruction G(3).

In addition, the following information is furnished with respect to certain Directors of SCE, who are expected to retire from the Board on May 14, 2002:

Warren Christopher, age 76, has been a Director of SCE from August 1971 through January 1977, from June 1981 through January 1993, and from May 1997 to date. He is also a Director of Edison International. He is a Senior Partner of the law firm of O'Melveny & Myers (1958-1967, 1969-1977, 1981-1993, and since 1997) and is the former United States Secretary of State (1993-1997).

Carl F. Huntsinger, age 72, has been a Director of SCE since 1983 and is also a Director of Edison International. He has been a General Partner of DAE Limited Partnership, Ltd. (agricultural management) since 1986.

Charles D. Miller, age 73, has been a Director of SCE since 1987 and is also a Director of Edison International. He is a Director of Avery Dennison Corporation, Nationwide Health Properties (Chairman),

The Air Group, Mellon Financial Group-West Coast, and Korn/Ferry International. He is also the Retired Chairman of the Board of Avery Dennison Corporation (manufacturer of self-adhesive products) (1998 2000); and the prior Chairman of the Board and Chief Executive Officer of Avery Dennison Corporation (1983-1998).

Item 11. Executive Compensation Information responding to Item 11 will be incorporated by reference from SCE's definitive Proxy Statement under the headings "Board Compensation," "Executive Compensation - Summary Compensation Table,"

"Aggregated Option/SAR Exercises in 2001 and FY-End Option/SAR Values," "Long-Term Incentive Plan Awards in Last Fiscal Year," "Pension Plan Table," "Other Retirement Benefits," "Employment Contracts and Termination of Employment Arrangements," "Compensation and Executive Personnel Committees' Report on Executive Compensation," and "Compensation and Executive Personnel Committees' Interlocks and Insider Participation," and is incorporated herein by reference pursuant to General Instruction G(3).

Item 12. Security Ownership of Certain Beneficial Owners and Management Information responding to Item 12 will be incorporated by reference from SCE's definitive Proxy Statement under the headings "Stock Ownership of Directors and Executive Officers" and "Stock Ownership of Certain Shareholders," and is incorporated herein by reference pursuant to General Instruction G(3).

Item 13. Certain Relationships and Related Transactions Information responding to Item 13 will be incorporated by reference from SCE's definitive Proxy Statement under the heading "Certain Relationships and Transactions of Nominees and Executive Officers" and "Other Management Transactions," and is incorporated herein by reference pursuant to General Instruction G(3).

34

In addition, Mr. Christopher is a Senior Partner of the law firm of O'Melveny and Myers. The firm provided legal services to SCE and/or its subsidiaries in 2001, and such services are expected to continue to be provided in the future. The amount paid to O'Melveny and Myers for legal services was below the threshold requiring disclosure by the SEC. SCE believes that these transactions are comparable to those which would have been undertaken under similar circumstances with nonaffiliated entities or persons.

PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a)(1)

Financial Statements The following items contained in the Annual Report are found on pages 2 through 51, and incorporated by reference in this report.

Management's Discussion and Analysis of Results of Operations and Financial Condition Consolidated Statements of Income - Years Ended December 31, 2001, 2000, and 1999 Consolidated Balance Sheets - December 31, 2001, and 2000 Consolidated Statements of Cash Flows - Years Ended December 31, 2001, 2000, and 1999 Consolidated Statements of Changes in Common Shareholder's Equity - Years Ended December 31, 2001, 2000, 1999 and 1998 Notes to Consolidated Financial Statements Responsibility for Financial Reporting Report of Independent Public Accountants (a)(2)

Report of Independent Public Accountants and Schedules Supplementing Financial Statements The following documents may be found in this report at the indicated page numbers.

Paae Report of Independent Public Accountants on Supplemental Schedules 36 Schedule II - Valuation and Qualifying Accounts for the Years Ended December 31, 2001, 2000, and 1999 37 Schedules I through V, inclusive, except those referred to above, are omitted as not required or not applicable.

(a)(3)

Exhibits See Exhibit Index beginning on page 41 of this report.

The Company will furnish a copy of any exhibit listed in the accompanying Exhibit Index upon written request and upon payment to the Company of its reasonable expenses of furnishing such exhibit, which shall be limited to photocopying charges and, if mailed to the requesting party, the cost of first-class postage.

(b)

Reports on Form 8-K October 2, 2001 Item 5: Other Events Settlement Agreement October 30, 2001 Item 5: Other Events Settlement Agreement 35

ANDERSEN REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SUPPLEMENTAL SCHEDULES To Southern California Edison Company:

We have audited, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements included in the 2001 Annual Report to Shareholders of Southern California Edison Company (SCE) incorporated by reference in this Form 10-K, and have issued our report thereon dated March 25, 2002. Our audits were made for the purpose of forming an opinion on those consolidated financial statements taken as a whole. The supplemental schedules listed in Part IV of this Form 10-K are the responsibility of SCE's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and regulations, and are not part of the consolidated financial statements. These supplemental schedules have been subjected to the auditing procedures applied in the audits of the consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the consolidated financial statements taken as a whole.

ARTHUR ANDERSEN LLP Los Angeles, California March 25, 2002 36

Southern California Edison Company SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 2001 Balance at Beginning of Additions Charged to Charged to Balance Costs and Other at End Description Period Expenses Accounts Deductions of Period (In thousands)

Group A:

Geothermal projects reserves Projects in development stage Uncollectible Accounts:

Customers

$ 19,793

$ 28,926

$ 20,419

$ 28,300 All other 3,427 1,836 1,607 3,656 Total

$ 23,220

$ 30,762

$ 22,026(a)

$ 31,956 Group B:

DOE Decontamination and Decommissioning

$ 29,920 5,520(b) $ 24,400 Purchased-power settlements 466,232 110,353(c) 355,879 Pension and benefits 296,278 195,558 72,037(d) 419,799 Maintenance Accrual Insurance, casualty and other 64,058 54,827 43,815(e) 75,070 Total

$ 856,488

$ 250,385

$ 231,725

$ 875,148 (a) Accounts written off, net.

(b) Represents amounts paid.

(c) Represents the amortization of the liability established for purchased-power contract settlement agreements.

(d) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.

(e) Amounts charged to operations that were not covered by insurance.

37

Southern California Edison Company SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 2000 Balance at Beginning of Additions Charged to Charged to Costs and Other Balance at End Description Period Expenses Accounts Deductions of Period (In thousands)

Group A:

Uncollectible accounts Customers

$ 21,656

$ 24,017

$ 25,880

$ 19,793 All other 3,009 1,201 783 3,427 Total

$ 24,665

$ 25,218

$ 26,663(a)

$ 23,220 Group B:

DOE Decontamination and Decommissioning

$ 34,590 (219)(b) 4,451(c)

$ 29,920 Purchased-power settlements 563,459 17,188 114,415(d) 466,232 Pension and benefits 232,901 44,244 24,101 (e) 4,968(f) 296,278 Insurance, casualty and other 68,880 42,749 47,571 (g) 64,058 Total

$899,830

$ 104,181

$ 23,882

$ 171,405

$ 856,488 (a) Accounts written off, net.

(b) Represents revision to estimate based on actual billings.

(c) Represents amounts paid.

(d) Represents the amortization of the liability established for purchased-power contract settlement agreements.

(e) Primarily represents transfers from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts.

(f) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.

(g) Amounts charged to operations that were not covered by insurance.

38

Southern California Edison Company SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1999 Additions Balance at Beginning of Charged to Costs and Charged to Other Balance at End Description Period Expenses Accounts Deductions of Period (In thousands)

Group A:

Uncollectible accounts Customers

$ 19,596

$ 21,968 19,908

$ 21,656 All other 2,634 1,288 913 3,009 Total

$ 22,230

$ 23,256

$ 20,821(a) $ 24,665 Group B:

DOE Decontamination and Decommissioning

$ 39,419 (134)(b) $

4,695(c)

$ 34,590 Purchased-power settlements 129,697 466,043 32,281 (d) 563,459 Pension and benefits 239,668 48,894 21,674(e) 77,335(f) 232,901 Insurance, casualty and other 73,249 37,674 42,043(g) 68,880 Total

$ 482,033

$ 552,611

$ 21,540

$156,354

$ 899,830 (a) Accounts written off, net.

(b) Represents revision to estimate based on actual billings.

(c) Represents amounts paid.

(d) Represents the amortization of the liability established for purchased-power contract settlement agreements.

(e) Primarily represents transfers from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts.

(f) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.

(g) Amounts charged to operations that were not covered by insurance.

39

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

SOUTHERN CALIFORNIA EDISON COMPANY By:

Kenneth S. Stewart Assistant General Counsel Date: March 29, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature Title Date Principal Executive Officer:

Alan J. Fohrer*

Principal Financial Officer:

W. James Scilacci*

Controller or Principal Accounting Officer:

Thomas M. Noonan*

Chairman of the Board, Chief Executive Officer and Director Vice President and Chief Financial Officer Vice President and Controller March 29, 2002 March 29, 2002 March 29, 2002 Board of Directors:

Warren Christopher*

Joan C. Hanley*

Carl F. Huntsinger*

Charles D. Miller*

Luis G. Nogales*

Ronald L. Olson*

James M. Rosser*

Robert H. Smith*

Thomas C. Sutton*

Daniel M. Tellep*

Director Director Director Director Director Director Director Director Director Director March 29, 2002 March 29, 2002 March 29, 2002 March 29, 2002 March 29, 2002 March 29, 2002 March 29, 2002 March 29, 2002 March 29, 2002 March 29, 2002

• By:

Kenneth S. Stewart Assistant General Counsel 40

EXHIBIT INDEX Exhibit Number Description 3.1 Certificate of Amendment and Restated Articles of Incorporation of SCE effective June 1, 1993 (File No. 1-2313, Form 10-K for the year ended December 31, 1993)*

3.2 Certificate of Correction of Restated Articles of Incorporation of SCE dated effective August 21, 1997 (File No. 1-2313, Form 1 0-Q for the quarter ended September 30, 1997)*

3.3 Amended Bylaws of Southern California Edison Company as adopted by the Board of Directors on January 1, 2002 4.1 SCE First Mortgage Bond Trust Indenture, dated as of October 1, 1923 (Registration No. 2-1369)*

4.2 Supplemental Indenture, dated as of March 1, 1927 (Registration No. 2-1369)*

4.3 Third Supplemental Indenture, dated as of June 24, 1935 (Registration No. 2-1602)*

4.4 Fourth Supplemental Indenture, dated as of September 1, 1935 (Registration No. 2-4522)*

4.5 Fifth Supplemental Indenture, dated as of August 15, 1939 (Registration No. 2-4522)*

4.6 Sixth Supplemental Indenture, dated as of September 1, 1940 (Registration No. 2-4522)*

4.7 Eighth Supplemental Indenture, dated as of August 15, 1948 (Registration No. 2-7610)*

4.8 Twenty-Fourth Supplemental Indenture, dated as of February 15, 1964 (Registration No. 2-22056)*

4.9 Eighty-Eighth Supplemental Indenture, dated as of July 15 1992 (File No. 1-2313, Form 8-K dated July 22, 1992)*

4.10 Indenture dated as of January 15, 1993 (File No. 1-2313, Form 8-K dated January 28, 1993)*

4.11 Indenture dated as of May 1, 1995 (File No. 1-2313, Form 8-K dated May 24, 1995)*

4.12 Ninety-Seventh Supplemental Indenture, dated as of February 21, 2002 10.1 1981 Deferred Compensation Agreement (File No. 1-2313, filed as Exhibit 10.2 to Form 10-K for the year ended December 31, 1981)*

10.2 1985 Deferred Compensation Agreement for Executives (File No. 1-2313, filed as Exhibit 10.3 to Form 10-K for the year ended December 31, 1986)*

10.3 1985 Deferred Compensation Agreement for Directors (File No. 1-2313, filed as Exhibit 10.4 to Form 10-K for the year ended December 31, 1986)*

10.4 Director Deferred Compensation Plan (File No. 1-9936, filed as Exhibit 10.3 to the Edison International Form 10-Q for the quarter ended June 30, 1998)*

10.5 Director Grantor Trust Agreement (File No. 1-9936, filed as Exhibit 10.10 to the Edison International Form 10-K for the year ended December 31, 1995)*

10.6 Executive Deferred Compensation Plan (File No. 1-9936, filed as Exhibit 10.2 to the Edison International Form 1 0-Q for the quarter ended March 31, 1998)*

10.7 Executive Grantor Trust Agreement (File No. 1-9936, filed as Exhibit 10.12 to the Edison International Form 10-K for the year ended December 31, 1995)*

10.8 Executive Supplemental Benefit Program (File No. 1-9936, filed as Exhibit 10.2 to the Edison International Form 1 0-Q for the quarter ended September 20, 1999)*

10.9 Dispute resolution amendment of 1981 Executive Deferred Compensation Plan, 1985 Executive and Director Deferred Compensation Plans and Executive Supplemental Benefit Program (File No. 1-9936, filed as Exhibit 10.21 to the Edison International Form 10-K for the year ended December 31, 1998)*

10.10 Executive Retirement Plan (File No. 1-9936, filed as Exhibit 10.1 to the Edison International Form 10-Q for the quarter ended September 30, 1999)*

10.10.1 Executive Retirement Plan Amendment 2001 -1 (File No. 1-9936, filed as Exhibit 10.1 to the Edison International Form 10-Q for the quarter ended March 31, 2001)*

10.11 Executive Incentive Compensation Plan (File No. 1-9936, filed as Exhibit 10.12 to the Edison International Form 10-K for the year ended December 31, 1997)*

10.12 Executive Disability and Survivor Benefit Program (File No. 1-9936, filed as Exhibit 10.22 to the Edison International Form 10-K for the year ended December 31, 1994)*

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10.13 Retirement Plan for Directors (File No. 1-9936, filed as Exhibit 10.2 to the Edison International Form 10-Q for the quarter ended June 30, 1998)*

10.14 Officer Long-Term Incentive Compensation Plan (File No. 1-9936, filed as Exhibit 10.3 to the Edison International Form 1 0-Q for the quarter ended March 31, 1998)*

10.15 Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.1 to the Edison International Form 10-0 for the quarter ended June 30, 1998)*

10.15.1 Amendment No. 1 to the Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.3 to the Edison International Form 10-Q for the quarter ended June 30, 2000)*

10.16 2000 Equity Plan (File No. 1-9936, filed as Exhibit 10.1 to the Edison International Form 10-Q for the quarter ended June 30, 2000)*

10.17 Forms of Agreement for long-term compensation awards under the Officer Long-Term Incentive Compensation Plan, the Equity Compensation Plan or the 2000 Equity Plan (File No. 1-9936, for 1991-1995 stock option awards filed as Exhibit 10.21.1 to the Edison International Form 10-K for the year ended December 31, 1995, for 1996 stock option awards filed as Exhibit 10.16.2 to the Edison International Form 10-K for the year ended December 31, 1996, for 1997 stock option awards filed as Exhibit 10.16.3 to the Edison International Form 10-K for the year ended December 31, 1997, for 1998 stock option awards filed as Exhibit 10.4 to the Edison International Form 10-Q for the quarter ended June 30, 1998, for 1999 stock option awards filed as Exhibit 10.1 to the Edison International Form 10-Q for the quarter ended March 31, 1999, for January 2000 stock option and performance share awards as restated filed as Exhibit 10.2 to the Edison International Form 10-Q for the quarter ended March 31, 2001, for May 2000 special stock option awards filed as Exhibit 10.2 to the Edison International Form 10-0 for the quarter ended June 30, 2000, for 2001 basic stock option and performance share awards filed as Exhibit 10.3 to the Edison International Form 10-0 for the quarter ended March 31, 2001, for 2001 special stock option awards filed as Exhibit 10.4 to the Edison International Form 10-0 for the quarter ended March 31, 2001, for 2001 retention incentives filed as Exhibit 10.5 to the Edison International Form 10-Q for the quarter ended March 31, 2001, and for 2001 exchange offer deferred stock units filed as Attachment C of Exhibit (a)(1) to Schedule TO-I dated October 26, 2001)*

10.18 Form of Agreement for 2001 Director Awards under the Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.21 to the Edison International Form 10-K for the year ended December 31, 2001)*

10.19 Estate and Financial Planning Program as amended April 1, 1999 (File No. 1-2313, filed as Exhibit 10.2 to Form 10-0 for the quarter ended June 30, 1999)*

10.20 Option Gain Deferral Plan as restated September 15, 2000 (File No. 1-9936, filed as Exhibit 10.25 to the Edison International Form 10-K for the year ended December 31, 2000)*

10.21 Employment Letter Agreement with Stephen E. Frank (File No. 1-2313, filed as Exhibit 10.25 to Form 10-K for the year ended December 31, 1995)*

10.22 Retirement Agreement with Stephen E. Frank 10.23 Consulting Agreement with Stephen E. Frank 10.24 Election Terms for Warren Christopher (File No. 1-9936, filed as Exhibit 10.22 to the Edison International Form 10-K for the year ended December 31, 1997)*

10.25 Executive Severance Plan as adopted effective January 1, 2001 (File No. 1-9936, filed as Exhibit 10.34 to the Edison International Form 10-K for the year ended December 31, 2001)*

12.

Computation of Ratios of Earnings to Fixed Charges

13.

Annual Report to Shareholders for year ended December 31, 2001

23.

Consent of Independent Public Accountants - Arthur Andersen LLP 24.1 Power of Attorney 24.2 Certified copy of Resolution of Board of Directors Authorizing Signature 99 Letter to United States Securities and Exchange Commission Regarding the Issuer's Independent Public Accountants, Arthur Andersen LLP

• Incorporated by reference pursuant to Rule 12b-32.

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