-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, MlavM2Q2oMyvLFGLQeMv32qRuWevZzjk7l3FDI0j4EExE+I9EpeoTDCMEg5a3F9s wPgUgety/yqtFshhBZTW4Q== 0000949149-01-000009.txt : 20010418 0000949149-01-000009.hdr.sgml : 20010418 ACCESSION NUMBER: 0000949149-01-000009 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20010410 ITEM INFORMATION: ITEM INFORMATION: FILED AS OF DATE: 20010417 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SALTON SEA FUNDING CORP CENTRAL INDEX KEY: 0000949149 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 470790493 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 033-95538 FILM NUMBER: 1603878 BUSINESS ADDRESS: STREET 1: 302 S 36TH STE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4023414500 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH ST STREET 2: STE 400 A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SALTON SEA BRINE PROCESSING L P CENTRAL INDEX KEY: 0000949256 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 330601721 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 033-95538-01 FILM NUMBER: 1603879 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SALTON SEA POWER GENERATION L P CENTRAL INDEX KEY: 0000949258 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 330567411 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 033-95538-02 FILM NUMBER: 1603880 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: FISH LAKE POWER LLC CENTRAL INDEX KEY: 0000949260 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 330453364 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 033-95538-03 FILM NUMBER: 1603881 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FORMER COMPANY: FORMER CONFORMED NAME: FISH LAKE POWER CO DATE OF NAME CHANGE: 19950810 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SALTON SEA ROYALTY CO CENTRAL INDEX KEY: 0000949262 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 470790492 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 033-95538-06 FILM NUMBER: 1603882 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VULCAN POWER CO /NV CENTRAL INDEX KEY: 0000949462 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 953992087 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 033-95538-04 FILM NUMBER: 1603883 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400 A CITY: OMAJA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VULCAN/BN GEOTHERMAL POWER CO CENTRAL INDEX KEY: 0001017939 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC, GAS & SANITARY SERVICES [4900] IRS NUMBER: 953992087 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-07527-07 FILM NUMBER: 1603884 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SAN FELIPE ENERGY CO CENTRAL INDEX KEY: 0001017941 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC, GAS & SANITARY SERVICES [4900] IRS NUMBER: 330315787 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-07527-09 FILM NUMBER: 1603885 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONEJO ENERGY CO CENTRAL INDEX KEY: 0001017943 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC, GAS & SANITARY SERVICES [4900] IRS NUMBER: 330268500 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-07527-10 FILM NUMBER: 1603886 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: LEATHERS L P CENTRAL INDEX KEY: 0001017945 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC, GAS & SANITARY SERVICES [4900] IRS NUMBER: 330305342 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-07527-12 FILM NUMBER: 1603887 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DEL RANCH LP CENTRAL INDEX KEY: 0001017946 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 330278290 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-07527-13 FILM NUMBER: 1603888 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ELMORE LP CENTRAL INDEX KEY: 0001017947 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 330278294 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-07527-14 FILM NUMBER: 1603889 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VPC GEOTHERMAL LLC CENTRAL INDEX KEY: 0001087415 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 330268085 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-79581-12 FILM NUMBER: 1603890 BUSINESS ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 S 36TH STE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4023414500 MAIL ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 SOUTH 36TH ST #400A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SALTON SEA POWER LLC CENTRAL INDEX KEY: 0001087416 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 470810713 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-79581-13 FILM NUMBER: 1603891 BUSINESS ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 S 36TH STE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4023414500 MAIL ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 SOUTH 36TH ST #400A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CALENERGY MINERALS LLC CENTRAL INDEX KEY: 0001087417 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 470810713 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-79581-14 FILM NUMBER: 1603892 BUSINESS ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 S 36TH STE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4023414500 MAIL ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 SOUTH 36TH ST #400A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CE TURBO LLC CENTRAL INDEX KEY: 0001087418 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 470810713 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-79581-15 FILM NUMBER: 1603893 BUSINESS ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 S 36TH STE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4023414500 MAIL ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 SOUTH 36TH ST #400A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CE SALTON SEA INC CENTRAL INDEX KEY: 0001087419 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 470810713 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-79581-16 FILM NUMBER: 1603894 BUSINESS ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 S 36TH STE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4023414500 MAIL ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 SOUTH 36TH ST #400A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SALTON SEA MINERALS CORP CENTRAL INDEX KEY: 0001087420 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 470810713 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-79581-17 FILM NUMBER: 1603895 BUSINESS ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 S 36TH STE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4023414500 MAIL ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 SOUTH 36TH ST #400A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CALENERGY OPERATING CORP CENTRAL INDEX KEY: 0001087421 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 470810713 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-79581-18 FILM NUMBER: 1603896 BUSINESS ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 S 36TH STE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4023414500 MAIL ADDRESS: STREET 1: C/O SALTON SEA FUNDING CORP STREET 2: 302 SOUTH 36TH ST #400A CITY: OMAHA STATE: NE ZIP: 68131 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NIGUEL ENERGY CO CENTRAL INDEX KEY: 0001087460 STANDARD INDUSTRIAL CLASSIFICATION: STEAM & AIR CONDITIONING SUPPLY [4961] IRS NUMBER: 330268502 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 333-79581-19 FILM NUMBER: 1603897 BUSINESS ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 BUSINESS PHONE: 4022311641 MAIL ADDRESS: STREET 1: 302 SOUTH 36TH STREET STREET 2: SUITE 400-A CITY: OMAHA STATE: NE ZIP: 68131 8-K 1 0001.txt 8-K EDISON 8-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K Current Report Pursuant to Section 13 or 15 (d) of the Securities Exchange Act of 1934 Date of Report April 10., 2001 (Date of earliest event reported) Commission File No. 33-95538 ----------------------- SALTON SEA FUNDING CORPORATION (Exact name of registrant as specified in its charter) 47-0790493 (IRS Employer Identification No.) (Exact name of Registrants (State or other jurisdiction of (I.R.S. Employer as specified in their charters)incorporation or organization)Identification No.) - ------------------------------- ---------------------------- ------------------- Salton Sea Brine Processing L.P. California 33-0601721 Salton Sea Power Generation L.P. California 33-0567411 Fish Lake Power LLC Delaware 33-0453364 Vulcan Power Company Nevada 95-3992087 CalEnergy Operating Corporation Delaware 33-0268085 Salton Sea Royalty LLC Delaware 47-0790492 VPC Geothermal LLC Delaware 91-1244270 San Felipe Energy Company California 33-0315787 Conejo Energy Company California 33-0268500 Niguel Energy Company California 33-0268502 Vulcan/BN Geothermal Power Company Nevada 33-3992087 Leathers, L.P. California 33-0305342 Del Ranch, L.P. California 33-0278290 Elmore, L.P. California 33-0278294 Salton Sea Power LLC Delaware 47-0810713 CalEnergy Minerals LLC Delaware 47-0810718 CE Turbo LLC Delaware 47-0812159 CE Salton Sea Inc. Delaware 47-0810711 Salton Sea Minerals Corp. Delaware 47-0811261 302 S. 36th Street, Suite 400-A, Omaha, NE 68131 --------------------------------------------------- (Address of principal executive offices and Zip Code of Salton Sea Funding Corporation) Salton Sea Funding Corporation's Telephone Number, including area code: (402) 341-4500 -------------------------------------------- N/A - ------------------------------------------------------------------------------ (Former name or former address, if changed since last report) Item 5. Other Events. The Registrants have previously reported that Southern California Edison Company ("Edison") has failed to make timely payment for power purchased during November and December 2000 under long-term power sales contracts (the "Contracts") with certain of the Registrants. Certain Registrants own and operate eight operating geothermal plants with an approximate aggregate net rated capacity of 267 MW located in the Imperial Valley, California and sell the power to Edison pursuant to the Contracts. On February 20, 2001 a lawsuit was filed on behalf of the Registrants in California's Imperial County Superior Court seeking a court order requiring Edison to make payment of more than $45 million for power delivered in November and December 2000 in accordance with the Contracts. The lawsuit also requested that the court order permit the Registrants to discontinue providing such power to Edison during such times as Edison continues non-payment and instead be allowed to sell it to other delivery entities in California. The Registrants also previously reported that on March 22, 2001, the Superior Court granted Registrant's Motion for Summary Adjudication and a Declaratory Judgment ordering that: 1) under the Contracts, Registrants have the right to temporarily suspend deliveries of capacity and energy to Edison, 2) Registrants are entitled to resell the energy and capacity to other purchasers and 3) the interim suspension of deliveries to Edison shall not in any respect result in the modifications or termination of the Contracts, and the Contracts shall in all respects continue in full force and effect other than the temporary suspension of deliveries to Edison. The Registrant also noted that on April 10, 2001, Edison International filed its current report on Form 8-K with the Securities and Exchange Commission wherein it reported certain recent litigation, as well as recent legislative and regulatory actions taken, or potentially to be taken, by the State of California which could affect Edison. A copy of Edison International's current report on Form 8-K is included as an exhibit to this report. Certain information included in this report contains forward-looking statements made pursuant to the Private Securities Litigation Reform Act of 1995 ("Reform Act"). Such statements are based on current expectations and involve a number of known and unknown risks and uncertainties that could cause the actual results and performance of the Registrants to differ materially from any expected future results or performance, expressed or implied, by the forward-looking statements including expectations regarding the future results of operations of Registrants. In connection with the safe harbor provisions of the Reform Act, the Registrants have identified important factors that could cause actual results to differ materially from such expectations, including development and construction uncertainty, operating uncertainty, acquisition uncertainty, uncertainties relating to geothermal resources, uncertainties relating to economic and political conditions and uncertainties regarding the impact of regulations, changes in government policy, industry deregulation and competition. Reference is made to all of the Registrants' SEC Filings, incorporated herein by reference, for a description of such factors. The Registrants assume no responsibility to update forward-looking information contained herein. Item 7. Financial Statements and Exhibits Form 8-K current report dated March 27, 2001, filed by Edison International April 10, 2001. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934 the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. SALTON SEA FUNDING CORPORATION Date: April 17, 2001 By: /s/ Douglas L. Anderson ---------------------------------------- Douglas L. Anderson Vice President Item 7: SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): March 27, 2001 EDISON INTERNATIONAL (Exact name of registrant as specified in its charter) CALIFORNIA 001-9936 95-4137452 (State or principal jurisdiction of (Commission file (I.R.S. employer incorporation or organization) number) identification no.) 2244 Walnut Grove Avenue (P.O. Box 800) Rosemead, California 91770 (Address of principal executive offices, including zip code) 626-302-2222 (Registrant's telephone number, including area code) Items 1 through 4, 6, 8 and 9 are not included because they are inapplicable. Item 5. Other Events On April 9, 2001, Edison International (EIX) and its electric utility subsidiary, Southern California Edison Company (SCE), signed a memorandum of understanding (MOU) with the California Department of Water Resources (CDWR) regarding the California energy crisis and its effects on SCE. California Governor Gray Davis and his representatives participated in the negotiation of the MOU, and Governor Davis endorsed implementation of all the elements of the MOU. The MOU sets forth a comprehensive plan calling for legislation, regulatory action and definitive agreements to resolve important aspects of the energy crisis, and which is expected to help restore SCE's creditworthiness and liquidity. A copy of the MOU is attached as Exhibit 99.1 Key elements of the MOU include: o SCE will sell its transmission assets to the CDWR, or another authorized California state agency, at a price equal to 2.3 times their aggregate book value, or approximately $2.76 billion. If a sale of the transmission assets is not completed under certain circumstances, SCE's hydroelectric assets and other rights may be sold to the state in their place. SCE will use the proceeds of the sale in excess of book value to reduce its undercollected costs and retire outstanding debt incurred in financing those costs. SCE will agree to operate and maintain the transmission assets for at least three years, for a fee to be negotiated. o Two dedicated rate components will be established to assist SCE in recovering the net undercollected amount of its power procurement costs through January 31, 2001, estimated to be approximately $3.5 billion. The first dedicated rate component will be used to securitize the excess of the undercollected amount over the expected gain on sale of SCE's transmission assets, as well as certain other costs. Such securitization will occur as soon as reasonably practicable after passage of the necessary legislation and satisfaction of other conditions of the MOU. The second dedicated rate component would not be securitized and would not appear in rates unless the transmission sale failed to close within a two-year period. The second component is designed to allow SCE to obtain bridge financing of the portion of the undercollection intended to be recovered through the gain on the transmission sale. o SCE will continue to own its generation assets, which will be subject to cost-based ratemaking, through 2010. SCE will be entitled to collect revenues sufficient to cover its costs from January 1, 2001 associated with the retained generation assets and existing power contracts. The MOU calls for the California Public Utilities Commission (CPUC) to adopt cost recovery mechanisms consistent with SCE obtaining and maintaining an investment grade credit rating. o The CDWR will assume the entire responsibility for procuring the electricity needs of retail customers within SCE's service territory through December 31, 2002, to the extent that those needs are not met by generation sources owned by or under contract to SCE. (The unmet needs are referred to as SCE's "net short position".) SCE will resume procurement of its net short position after 2002. The MOU calls for the CPUC to adopt cost recovery mechanisms to make it financially practicable for SCE to reassume this responsibility. Page 2 o SCE's authorized return on equity will not be reduced below its current level of 11.6% before December 31, 2001. Through the same date, a ratemaking capital structure for SCE will not be established with different proportions of common equity or preferred equity to debt than set forth in current authorizations. These measures are intended to enable SCE to achieve and maintain an investment grade credit rating. o EIX and SCE will commit to make capital investments in SCE's regulated businesses of at least $3 billion through 2006, or a lesser amount approved by the CPUC. The equity component of the investments will be funded from SCE's retained earnings or, if necessary, from equity investments by EIX. o An affiliate of EIX will execute a contract with the CDWR or another state agency for the provision of power to the state at cost-based rates for ten years from a power project currently under development. The EIX affiliate will use all commercially reasonable efforts to place the first phase of the project into service before the end of Summer 2001. o SCE will grant perpetual conservation easements over approximately 21,000 acres of lands associated with SCE's Big Creek and Eastern Sierra hydroelectric facilities. The easements initially will be held by a trust for the benefit of the State of California, but ultimately may be assigned to nonprofit entities or certain governmental agencies. SCE will be permitted to continue utility uses of the subject lands. o After the other elements of the MOU are implemented, SCE will enter into a settlement of or dismiss its federal district court lawsuit against the CPUC seeking recovery of past undercollected costs. The settlement or dismissal will include related claims against the State of California or any of its agencies, or against the federal government. The parties agree in the MOU that each of its elements is part of an integrated package, and effectuation of each element will depend upon effectuation of the others. To implement the MOU, numerous actions must be taken by the parties and by other agencies of the State of California. The California Legislature must enact legislation to authorize purchase of SCE's transmission system or other assets, establish the dedicated rate components, authorize and/or direct the CPUC to take certain actions, and authorize other agreements and actions. The CPUC must also adopt the dedicated rate components and financing orders, modify existing decisions, and take various ratemaking and other actions. The CDWR and other state agencies must enter into definitive agreements for the purchase of assets from SCE and to embody various other elements of the MOU. The sale of SCE's transmission system and other elements of the MOU must be approved by the Federal Energy Regulatory Commission (FERC). SCE, EIX and the CDWR committed in the MOU to proceed in good faith to sponsor and support the required legislation and to negotiate in good faith the necessary definitive agreements. The California Legislature, the CPUC, the FERC, and other governmental entities on whose part action will be necessary to implement the MOU are not parties to the MOU. Page 3 The MOU may be terminated by either SCE or CDWR if required legislation is not adopted and definitive agreements executed by August 15, 2001, or if the CPUC does not adopt required implementing decisions within 60 days after the MOU was signed, or if certain other adverse changes occur. EIX and SCE cannot provide assurance that all the required legislation will be enacted, regulatory actions taken, and definitive agreements executed before the applicable deadlines. EIX and SCE believe that the MOU is an important step towards an acceptable resolution of the major issues affecting EIX and SCE as a result of the California energy crisis, including restoring their creditworthiness and creating a positive framework for future financial stability, but achievement of those results is not assured. A California voter initiative or referendum previously has been threatened against any measures that would raise consumer rates or aid California's investor-owned utilities. In addition, execution of the MOU does not eliminate the possibility that any of SCE's creditors could take steps to force SCE into bankruptcy proceedings. On April 6, 2001, Pacific Gas and Electric Company (PG&E) announced that it had filed for reorganization under Chapter 11 of the United States Bankruptcy Code. PG&E said that neither its parent holding company nor any of the parent's other subsidiaries are affected by PG&E's filing. PG&E cited as reasons for its bankruptcy filing the failure by the State of California to assume full procurement responsibility for PG&E's net short position, the CPUC's actions on March 27 and April 3, 2001 that created new payment obligations for PG&E, lack of progress in negotiations with the state to provide recovery of power purchase costs, the CPUC's adoption of an illegal and retroactive accounting change, and the slow progress of discussions with Governor Davis's representatives. The actions of the CPUC cited by PG&E are discussed below. SCE is still working to avoid bankruptcy, despite PG&E's announcement that it is filing for bankruptcy court protection. EIX and SCE continue to believe that a comprehensive solution to the current crisis through agreements, legislation and regulatory actions, as contemplated by the MOU, is a preferable course of action. Neither EIX nor SCE can predict the impact of PG&E's bankruptcy on implementation of the MOU and on EIX's and SCE's other efforts to resolve their current financial and liquidity problems. On March 27, 2001, the CPUC unanimously adopted several significant decisions regarding California's current energy crisis. The CPUC's March 27 decisions deal with complex matters and in many respects are unclear or ambiguous. Many elements of the decisions will be developed further in ongoing proceedings, the timing of which is uncertain. EIX and SCE are still analyzing the decisions and cannot yet state with certainty the impacts of the decisions on them. EIX and SCE believe that the CPUC, by increasing rates in its March 27 decisions, has taken a positive step to address the general disparity between high wholesale power costs and frozen retail rates. However, several aspects of the decisions are not helpful to SCE's efforts to recover its own costs and regain creditworthiness. Key components of the decisions will have to be modified to implement the MOU. Although CPUC representatives participated in the negotiation of the MOU, the CPUC is not a party to it. The MOU acknowledges that the CPUC is an independent regulatory agency which may within its discretion determine to adopt Page 4 or not adopt the actions and approvals described in the MOU. Important provisions of the CPUC's March 27 decisions which may be adverse to SCE include at least the following: o The CPUC adopted methods for calculating the revenues that SCE must pay over to the CDWR to reimburse the CDWR for power purchased on behalf of SCE's customers. SCE believes the calculation methods will leave SCE without sufficient revenues to cover its generation, purchased power and transition costs. To implement the MOU, the CPUC will need to modify the calculation methods and provide reasonable assurance that SCE will be able to recover its ongoing costs. o The CPUC ordered SCE to immediately make payments to the CDWR and power suppliers that are qualifying facilities (QFs), but did not address SCE's past undercollected power procurement costs. To implement the MOU, the CPUC will need to adopt mechanisms for SCE to recover its past costs. o The CPUC also made dramatic, retroactive changes in regulatory accounting mechanisms that, in effect, provide for recovery of past procurement costs but cause generation-related transition costs to be undercollected. This situation, if not changed, would require SCE and EIX to take substantial charges against earnings in their fourth quarter and year-end financial results. The changes also may materially and adversely affect future financial results. To implement the MOU, the CPUC will need to modify these changes. While EIX and SCE believe that implementation of the MOU should enable SCE to recover its costs, under applicable accounting standards the fourth quarter charges may still be required pending adoption by the CPUC of the cost recovery mechanisms contemplated by the MOU. (See the discussion below about possible write-offs.) EIX and SCE believe that in some respects the CPUC's decisions are unlawful and unconstitutional. Key provisions of the CPUC's decisions are discussed further below. In an interim order adopted on March 27, 2001, the CPUC granted SCE and other California utilities a rate increase in the form of a three-cents per kilowatt-hour (kWh) surcharge on electricity sold, effective immediately. However, the three-cent surcharge will not be collected in rates until the CPUC establishes an appropriate rate design. The CPUC proposed a tiered rate design in an assigned commissioner's ruling and asked for comments. The assigned commissioner said the tiered rate design is intended to encourage conservation by requiring customers to pay more for electricity above a threshold usage level. The three-cent surcharge will not apply to residential electricity usage below 130% of baseline rates or to certain low-income customers. The CPUC will hold hearings on the rate design and may not issue a decision until some time in May 2001. SCE has asked the CPUC to immediately adopt an interim rate increase that would allow the rate change to go into effect sooner. The CPUC stated in its interim order that SCE is to use revenue generated by the three-cent surcharge to pay power costs incurred after March 27, 2001. SCE must refund the surcharge to ratepayers if SCE does not properly use it to pay for power purchases. If any refunds of power costs are obtained from power generators and sellers, Page 5 those refunds will be used to reduce customer rates or to pay power costs. SCE also must refund the three-cent surcharge to the extent that any court or administrative body denies refunds from power generators or sellers in a proceeding where recovery is hampered by lack of cooperation from SCE. The CPUC also affirmed that an earlier one-cent per kWh surcharge granted on January 4, 2001 is now permanent under California legislation adopted in February 2001, known as AB1X. The CPUC stated that revenues from the one-cent surcharge must be used to pay for power purchases and not for any other costs. The CPUC ordered that the three-cent surcharge must be added to the rate paid to the CDWR to reimburse the CDWR for its costs of purchasing power for delivery to SCE's customers. In another interim order on March 27, 2001, the CPUC ordered SCE to pay the CDWR for each kWh that the CDWR sells to SCE's customers, at a price equal to SCE's applicable generation-related retail rate as in effect on January 5, 2001. The CPUC determined that the generation-related retail rate should be equal to SCE's total bundled electric rate (including the one-cent surcharge adopted on January 4, 2001) less certain non-generation-related rates or charges. The CPUC determined that the applicable rate is 7.277 cents per kWh for electricity delivered by the CDWR to SCE's retail customers after February 1, 2001, until more specific rates are calculated. For the period of January 19 through January 31, 2001, the CPUC ordered SCE to pay the CDWR at a rate of 6.277 cents per kWh for power delivered on an interim basis to SCE's customers. The CPUC ordered SCE to pay the CDWR daily within 45 days after the CDWR supplies power to SCE's retail customers, subject to penalties for each day that payment is late. Under the CPUC's decisions, the CDWR currently is entitled to be paid each day an amount equal to the number of kWh that the CDWR provided 45 days earlier multiplied by 7.277 cents per kWh (which will increase to 10.277 cents per kWh for electricity delivered after March 27, 2001, due to the 3-cent surcharge described above). In the interim order, the CPUC directed SCE to immediately pay sums owed to the CDWR for certain past purchases of power for SCE's customers. SCE paid $43.5 million to the CDWR on March 28, 2001, for the period of January 19 through February 11, 2001. Based on the CPUC order, the rate for purchases from January 19 through January 31 was 6.277 cents per kWh, and for purchases from February 1 through February 11 the rate was 7.277 cents per kWh. In addition, the interim order proposed a method by which the California Procurement Adjustment (CPA) should be calculated. The CPA was established by AB1X. The CPA is used to determine the amount of bonds the CDWR can issue to finance its power purchases. All or a portion of the CPA may be allocated by the CPUC to reimburse the CDWR for its power purchases on behalf of utility customers. AB1X requires the CPUC to determine (1) the CPA, which is the portion of each electric utility's electric retail rate effective on January 5, 2001 that is equal to the difference between the generation-related component of the utility's retail rate in effect on January 5, 2001, and the sum of the costs of the utility's own generation, QF contracts, existing bilateral contracts and ancillary services, and (2) the amount of the CPA that is allocable to the power sold by the CDWR. In its March 27 decision, the CPUC proposed that the CPA should be a set rate calculated by determining each utility's generation-related revenues (for SCE this would be equal to 7.277 cents per kWh multiplied by total kWh sales by Page 6 SCE to retail customers), then subtracting each utility's statutorily authorized generation-related costs, and dividing the result by each utility's total kWh sales. The CPUC states in the March 27 decision that each utility's CPA rate will be used to determine a proposed CPA revenue amount, which can be used by the CDWR to begin the process of issuing bonds. AB1X provides that the CDWR cannot issue bonds in an aggregate amount greater than four times the annual revenues generated by the CPA. SCE filed comments on the proposed CPA calculation method on March 29 and April 2, 2001. In the limited time available to consider the impact of the CPUC's March 27 decisions, SCE estimated that its future revenues will not be sufficient to cover its own costs of retained generation and power purchases. SCE provided a forecast showing that the net effect of the rate increases described above, the decision on QF payments described below, and the payments ordered to be made to CDWR could result in a shortfall in the CPA calculation of $1.743 billion for SCE during 2001. SCE further stated that the proposed calculation method does not properly reflect all of SCE's relevant generation costs, and that adoption of the method and later allocation of a portion of the CPA to the CDWR would materially exacerbate SCE's revenue shortfall. SCE commented that other flaws in the calculation are that: (1) the proposed CPA is for an indefinite period with no mechanism for adjustments based on changes in actual costs; (2) it ignores the potential impact on SCE's costs if the CDWR is not responsible for the full net-short position; (3) it assumes too low a cost for QF payments (as discussed below); (4) it may improperly exclude authorized generation-related costs; (5) it improperly excludes revenues from nuclear incentive pricing; and (6) the methodology for calculating the CPA is flawed and based on unreasonable assumptions. A copy of SCE's comments is attached as Exhibit 99.2. In an interim order on April 3, 2001, the CPUC adopted the method to calculate the CPA and then applied that method to calculate a company-wide CPA rate for each California utility. The CPUC used that rate to determine the CPA revenue amount which can be used by the CDWR for issuing bonds. The CPUC stated that its decision is narrowly focused to calculate the maximum amount of bonds that the CDWR may issue and does not dedicate any particular revenue stream to the CDWR. The CPUC determined that SCE's CPA rate is 1.120 cents per kWh, which generates revenues of $856.43 million in 2001. According to the CPUC's methodology, the aggregate annual revenues generated by the CPA rates determined for the three California investor-owned utilities would allow the CDWR to issue up to $13.4 billion of bonds to pay for power purchases by the CDWR under the provisions of AB1X. In its calculation of the CPA, the CPUC disregarded all the adjustments requested by SCE in its comments filed on March 29, 2001 (discussed above). As to SCE's concerns that the CPA may be overstated and could cause deleterious financial effects on SCE, the CPUC stated that the interim order does not allocate the CPA, and SCE may comment on the allocation of the CPA at a later time. On March 27, 2001, the CPUC also ordered SCE to begin making payments to QFs for power deliveries on a going forward basis, commencing with April 2001 deliveries. SCE must pay QFs within 15 days of the end of the QF's billing period, and QFs are allowed to establish 15-day billing periods. The CPUC provided two special payment options for the month of April only. Failure to make a payment when due will result in a fine equal to the amount owed. The CPUC also modified the formula used in calculating payments to QFs by substituting natural gas index prices based on deliveries at the Oregon border in the place of index prices at the Arizona border. The Page 7 order further revises other aspects of the payment formula to take into account changes in intrastate gas transportation costs. The CPUC stated that the changes will probably result in lower QF energy prices. The changes apply to all QFs whose payments are based on CPUC-approved short-run avoided cost regardless of whether they use natural gas or other resources such as solar or wind. In its comments on the CPUC's methodology for calculating the CPA (described above), SCE also discussed the QF pricing resulting from the CPUC's March 27 decision on QF payments. SCE stated that the CPA calculation proposed by the CPUC is based on an assumed QF price of $80 per megawatthour (MWH), which was a target price in earlier negotiations with QFs seeking a settlement on lower prices. However, those negotiations failed. SCE provided to the CPUC a forecast showing that QF prices through the remainder of 2001, based on the revised formula adopted by the CPUC and independently forecasted gas prices, will be substantially higher than $80 per MWH. In its March 27 decisions, CPUC granted a petition previously filed by The Utility Reform Network (TURN), a ratepayer advocacy group, that was opposed by SCE and PG&E. The CPUC directed that the balance in SCE's transition revenue account (TRA), whether positive or negative, be transferred on a monthly basis to SCE's transition cost balancing account (TCBA), effective retroactively to January 1, 1998. The TRA is a regulatory asset account in which SCE records the difference between revenues received from customers through currently frozen rates and the costs of providing service to customers, including power procurement costs. The TCBA is a regulatory balancing account that tracks the recovery of generation-related transition costs, including stranded investments. The CPUC also ordered SCE to retroactively restate and record balances in its generation memorandum accounts to the TRA on a monthly basis before any transfer of generation revenues to the TCBA. SCE believes that this decision by the CPUC is a fundamental departure from established regulatory accounting and ratemaking procedures and is unlawful and unconstitutional. SCE believes the CPUC's intent was to deny SCE lawful recovery of its costs and to artificially extend the end of the current rate freeze. The CPUC characterized the changes as merely reducing the prior revenues recorded in the TCBA, thereby affecting only the amount of transition cost recovery achieved to date. Based upon the transfer of balances into the TCBA, the CPUC stated that the current rate freeze has not ended and will not end until the earlier of recovery of all specified transition costs or March 31, 2002. The CPUC said that any undercollection in the TRA cannot be recovered after the rate freeze ends. But the CPUC also said that it will monitor the balances remaining in the TCBA and consider how to address remaining balances in the ongoing proceedings. If the CPUC does not modify this decision in a manner consistent with the MOU, SCE intends to challenge the decision through all appropriate avenues. Although the CPUC has authorized a substantial rate increase, it has allocated the revenues from the increase entirely to future power purchase costs without providing for recovery of SCE's past undercollections for the costs of purchased power. The CPUC's decisions do not assure that SCE will be able to meet its ongoing obligations or repay past due obligations. By ordering immediate payments to the CDWR and QFs, the CPUC has exacerbated SCE's cash flow and liquidity problems. Moreover, the CPUC expressed the view that AB1X continues Page 8 the utilities' obligations to serve their customers; and the CPUC said that it cannot assume that the CDWR will purchase all the electricity needed above what the utilities either generate or have under contract (the net short position) and cannot order the CDWR to do so. This could result in SCE incurring additional purchased power costs for which the CPUC has allowed SCE no means of recovery. In addition, the CPUC's retroactive modifications of established regulatory asset accounts, if not changed, would require EIX and SCE to take substantial earnings charges for the fourth quarter of 2001. EIX and SCE believe that the CPUC's decisions described above are inconsistent with the terms of the MOU in material respects. To implement the MOU, it will be necessary for the CPUC to modify or rescind those decisions. Neither EIX nor SCE can provide any assurance that the CPUC will do so. As discussed in previous reports, applicable accounting standards permit SCE to defer costs as regulatory assets if those costs are determined to be probable of recovery in future rates. If SCE determines that regulatory assets, such as the TRA and TCBA, are no longer probable of recovery through regulated rates, they must be written off. Because of the CPUC's decisions on and after March 27, 2001, including the retroactive transfer of balances from SCE's TRA to its TCBA and related changes, EIX and SCE had to reassess the probability of recovery of the undercollected costs that are now recorded in the TCBA. Absent a change in those CPUC decisions, or other regulatory or legislative actions, that would make probable the recovery of generation-related regulatory assets, SCE's and EIX's financial results for the fourth quarter and the fiscal year ended 2000 would include an after-tax charge of approximately $2.5 billion ($4.2 billion on a pre-tax basis), reflecting a write-off of the TCBA (as restated to reflect the CPUC's March 27, 2001 decisions) and regulatory assets to be recovered through the TCBA mechanism, as of December 31, 2000. Furthermore, SCE currently does not have regulatory authority to recover any power purchase costs it incurs during 2001 in excess of revenues from retail rates. Those amounts also would be charged against earnings absent a regulatory or legislative solution, such as implementation of the actions called for in the MOU, that makes recovery of such costs probable. This would result in further material declines in reported common shareholders' equity, particularly in light of the CPUC's failure to provide SCE with sufficient rate revenues to cover its ongoing costs and obligations as discussed above. The fourth quarter 2000 charge would cause SCE to be unable to meet an earnings test that must be met before SCE can issue additional first mortgage bonds. If the MOU is implemented, or a rate mechanism provided by legislation or regulatory authority is established that makes recovery from regulated rates probable as to all or a portion of the amounts that were previously charged against earnings, current accounting standards provide that a regulatory asset would be correspondingly reinstated with a corresponding increase in earnings. On April 2, 2001, EIX and SCE each filed with the Securities and Exchange Commission a notification of late filing on Form 12b-25 stating that each company could not timely file its annual report on Form 10-K without unreasonable effort and expense because of the continuing developments in the California energy crisis, including especially the CPUC's March 27, 2001 decisions that must be analyzed by EIX and SCE and reflected in their year-end 2000 financial statements. Under Rule 12b-25, EIX's and SCE's respective Form 10-K reports will be deemed to be timely filed if they are filed by April 17, 2001 (15 calendar days from the prescribed due date). EIX and SCE presently intend to make their Form 10-K filings by April 17, 2001. Page 9 At its March 27, 2000 meeting, the CPUC deferred action on a proposed order instituting an investigation whether California's investor-owned utilities, including SCE, have complied with past CPUC decisions authorizing the formation of their holding companies and governing affiliate transactions, as well as applicable statutes. On March 29, 2001, an assigned commissioner's ruling was issued that requires SCE and EIX to respond within 10 days to document requests and questions that are substantially identical to document requests and questions included in the proposed order instituting investigation. At its April 3, 2001 meeting, the CPUC adopted the proposed order. The order reopens past CPUC decisions authorizing the utilities to form holding companies and initiates an investigation into (1) whether the holding companies violated requirements to give priority to the capital needs of their respective utility subsidiaries; (2) whether "ring fencing" actions by EIX and PG&E Corporation and their respective nonutility affiliates also violated the requirements to give priority to the capital needs of their utility subsidiaries; (3) whether the payment of dividends by the utilities violated requirements that the utilities maintain dividend policies as though they were comparable stand-alone utility companies; (4) any additional suspected violations of laws or CPUC rules and decisions; and (5) whether additional rules, conditions, or other changes to the holding company decisions are necessary. The MOU signed on April 9, 2001 with the CDWR calls for the CPUC to adopt a decision clarifying that the "first priority" condition in SCE's holding company decision refers to equity investment, not working capital for operating costs. Neither EIX nor SCE can provide assurance that the CPUC will adopt such a decision, or predict what effects the investigation or any subsequent actions by the CPUC may have on either of them. On March 27, 2001, SCE announced that it will commence payments on deferred indebtedness. These payments include (1) past due interest on first and refunding mortgage bonds, Series 93C Due 2026 and Series 93H Due 2004 (which was paid on March 30, 2001); (2) past due interest on senior unsecured notes, 5-7/8% Series Due 2001 (which will be paid on April 19, 2001, to holders of record as of April 9, 2001, in accordance with the applicable indenture); (3) interest on matured commercial paper; and (4) interest on extendible commercial notes. Payments on the commercial paper and extendible commercial notes were made on April 6, 2001, and all interest was brought current to March 31, 2001 for the commercial paper and March 28, 2001 for the extendible commercial notes. Payments will also include interest on past due interest. Regular payments will be resumed on all interest due going forward, including interest payments due under SCE's bank credit facilities. Interest on commercial paper will be paid monthly, and interest on the 5-7/8% Series notes will be paid semiannually. Notices will be provided to holders of the securities about the timing and amount of the interest payments they will receive. The aggregate amount required to bring interest payments on outstanding indebtedness current as of March 31, 2001 is approximately $26 million. On February 20, 2001, a group of geothermal energy suppliers affiliated with CalEnergy Operating Company filed a lawsuit against SCE in the Superior Court of Imperial County, California which, as subsequently amended, seeks immediate payment by SCE of $100 million for energy and capacity supplied under QF contracts during November 2000 through February 2001, plus exemplary damages. The lawsuit also seeks an order allowing the suppliers to stop providing power to SCE and sell the power elsewhere in California. On March 22, 2001, the court issued an order allowing the suppliers to make sales to third parties because of SCE's failure to make payments for power Page 10 deliveries. SCE has requested, in a motion set for hearing on April 16, 2001, that the order be lifted in light of the CPUC's March 27, 2001 decision requiring SCE to resume payments to QFs. A hearing that was set to be heard on April 2, 2001 on the suppliers' motion for summary adjudication on the issue of breach of contract has been continued to April 16, 2001, due to SCE's intention to seek coordination of this case with other actions that QFs have commenced in various California courts on the payment issue. On March 2, 2001, two geothermal energy suppliers affiliated with Caithness Corporation filed a lawsuit against SCE in federal district court in Nevada seeking payment of more than $20 million for energy and capacity delivered to SCE under QF contracts during November and December 2000 and January 2001. The suppliers sought a writ of attachment against SCE's interest in the Mohave Generating Station for the amount of their claim. On March 14, 2001, the court issued an order granting a prejudgment attachment, subject to the suppliers posting surety in the amount of the attachment unless the parties otherwise agree. The suppliers have not yet posted surety. The suppliers filed a summary judgment motion and requested that SCE's time to respond be significantly shortened. The latter request was denied by the court, and SCE's opposition to the summary judgment motion is due on April 11, 2001. On March 5, 2001, a group of wind energy suppliers affiliated with FPL Group filed a lawsuit against SCE in the Superior Court of Los Angeles County, California seeking payment of "several million dollars" for energy and capacity delivered to SCE under QF contracts during November and December 2000 and January 2001. The suppliers filed applications for writs of attachment against unspecified assets of SCE. On March 28, 2001, the court denied the applications. On March 28, 2001, IMC Chemicals Inc., a company that operates a cogeneration plant, filed a lawsuit against SCE in the Superior Court of San Bernardino County, California seeking payment of $2.8 million for energy and capacity delivered to SCE under QF contracts during the period from November 2000 through February 2001. The lawsuit also seeks an order allowing the suppliers to stop providing power to SCE and sell the power to other purchasers. On March 28, 2001, SCE was served with a lawsuit filed in the Superior Court of Los Angeles County, California by NP Cogen, the owner-operator of a cogeneration facility. The lawsuit seeks damages for SCE's alleged failure to pay for power deliveries under a QF contract during the period from November 2000 through February 2001. The amount of damages sought is not specified, but the complaint alleges that the amount currently owed by SCE under the contract is approximately $8 million. The lawsuit also seeks a declaration that the owner-operator is excused from further performance under the contract. On March 29, 2001,Watson Cogeneration Company, which operates a cogeneration facility, filed a lawsuit against SCE in the Superior Court of Los Angeles, California seeking payment of damages of at least $150 million for energy, capacity and other services delivered to SCE under a QF contract during and since November 2000, plus exemplary damages. The lawsuit also seeks an order allowing the supplier to stop providing power to SCE and sell the power to other purchasers. Page 11 On April 3, 2001, SCE was served with a lawsuit filed in the Superior Court of Los Angeles County, California by four cogeneration companies affiliated with Delta Power LLC seeking damages of at least $42 million for nonpayment by SCE for power deliveries under four QF contracts during the period from November 2000 through February 2001. The lawsuit also seeks a declaration that the companies may terminate the contracts, stop providing power to SCE and sell the power to other purchasers. On April 3, 2001, SCE was served with a lawsuit filed in the Superior Court of Ventura County, California by EF Oxnard, Inc., the owner-operator of a cogeneration facility, seeking damages of at least $13.5 million for nonpayment by SCE for power deliveries under a QF contract during the period from November 2000 through February 2001. On April 5, 2001, Brea Power Partners, L.P., a company that operates a landfill gas-fired plant, filed a lawsuit against SCE and EIX in the Superior Court of Los Angeles County, California seeking payment of $1.65 million for energy and capacity delivered to SCE under a QF contract during the period from November 2000 through March 2001, plus $24 million of additional damages. The lawsuit also seeks an order allowing the company to stop providing power to SCE and sell the power to other purchasers. On April 9, 2001, SCE and the California Independent System Operator (ISO) were sued in federal district court in Los Angeles, California by Inland Paperboard and Packaging, Inc., a company that owns a cogeneration facility. The lawsuit seeks payment of $5.3 million for energy and capacity delivered to SCE under a QF contract during the period from November 2000 through March 2001, plus additional and treble damages for alleged interference with Inland Paperboard's ability to sell power to third parties. The lawsuit also seeks a temporary restraining order and injunction to prevent SCE and the ISO from interfering with such third party sales. Several other owners or operators of QFs have given SCE letters demanding that SCE pay them past due amounts, requesting approval to sell their energy and capacity to third parties, and in some cases threatening legal action. In the preceding discussion and elsewhere in this report, the words "expects," "believes," "anticipates," "projects," "forecasts," "intends," "predicts," "probable," and other similar expressions are intended to identify forward-looking information that involves risks and uncertainties. Actual results or outcomes could differ materially as a result of such important factors as implementation (or non-implementation) of the MOU as described above; legislative enactments; the outcome of regulatory and judicial proceedings regarding recovery of costs and other matters; the outcome of state and federal regulatory proceedings concerning wholesale and retail electric rates, accounting mechanisms and other matters; the actions of securities rating agencies; changes in prices of electricity and fuel costs; the availability of credit; changes in financial market conditions; weather conditions; and other unforeseen events, some of which are discussed above. Page 12 Item 7. Financial Statements, Pro Forma Financial Information and Exhibits. (a) Not applicable (b) Not applicable (c) Exhibits 99.1 Memorandum of Understanding 99.2 SCE's Comments on Proposed CPA Calculation SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. EDISON INTERNATIONAL (Registrant) KENNETH S. STEWART ------------------------------------------------- KENNETH S. STEWART Assistant General Counsel and Assistant Secretary April 10, 2001 MEMORANDUM OF UNDERSTANDING THIS MEMORANDUM OF UNDERSTANDING ("MOU") is being entered into as of April 9, 2001, by and among the California Department of Water Resources ("CDWR") separate and apart from its powers and responsibilities with respect to the State Water Resources Development System, and Southern California Edison Company, a California corporation ("SCE"), and, as to Sections 5, 8 and 12, Edison International, a California corporation ("EIX"). 1. Purpose The purposes of this MOU are to: o Set forth the understandings reached by the parties above (the "Parties") about a plan (the "Plan") to provide affordable and reliable electricity to customers of SCE by, among other things, maintaining the output of SCE's retained generation on a cost-of-service basis, providing for CDWR or another authorized agency of the State of California (the "State") to acquire SCE's transmission system (or certain other assets if the sale of the transmission system is not consummated under certain circumstances) (the "Transmission Sale"), dedicating a new generating facility owned by an EIX company to cost-of-service based rates for at least 10 years, and providing for easements and potential conveyances in fee of certain lands described herein to ensure the long-term conservation of these lands for their public interest value; and o Provide a framework for the timely implementation of those understandings; and Page 1 o As part of that implementation, provide for the resolution of certain claims which SCE has asserted against the State of California and certain agencies and subdivisions thereof. It is expressly understood that the Parties will act in good faith to implement all the elements of this MOU, and that the Governor of the State of California has endorsed such implementation. Such implementation shall include seeking to obtain the consents and authorizations contemplated herein. In addition, it is expressly understood that there is no intention to change SCE's continuing to be a public utility that is subject to the jurisdiction of the California Public Utilities Commission (the "CPUC"). The Parties recognize, in order for a number of the initiatives contemplated by this MOU to be fulfilled, certain actions and approvals will need to be obtained by SCE from the CPUC in an appropriate proceedings. Those actions and approvals are referred to herein as the "CPUC Implementing Decisions." Inasmuch as the CPUC is an independent regulatory agency which may within its discretion determine to adopt or not adopt the actions and approvals that are described herein as "CPUC Implementing Decisions," this MOU provides for certain rights on the part of SCE to terminate the implementation of this MOU in the event that the CPUC does not adopt all of the actions and approvals expressly characterized herein as "CPUC Implementing Decisions" within the period of sixty (60) days after the date of the execution of this MOU by all Parties. Subject to legislation that may be adopted implementing this MOU and to the CPUC Implementing Decisions, nothing herein shall prohibit the CPUC from employing ratemaking and regulatory techniques, methods and standards that have been historically used and may be used or implemented in the regulation of public utilities. Nothing herein is intended to provide SCE with actual recovery of a cost more than once. In such instance, if any, the CPUC is authorized to adjust rates to prevent multiple recovery of such cost. Page 2 2. General Overview The Plan is comprised of the elements described in more detail in Sections 3 through 14 of this MOU. The Plan will be implemented through a combination of the following: o Legislative action, including, but not limited to, authorizing CDWR or another State entity to acquire the SCE transmission assets and enter into and implement the applicable contracts and activities contemplated herein, and, as applicable or necessary, authorizing and/or directing the CPUC to take certain actions called for hereby; o Contracts directly between SCE and CDWR or other pertinent State agencies; o Regulatory decisions, including actions by the Federal Energy Regulatory Commission ("FERC") and the CPUC Implementing Decisions; o Entry of a stipulated judgment in, or other form of mutually acceptable disposition of, SCE's federal court lawsuit; and o Releases or assignments of mutually agreed upon identified claims by SCE against third parties subject to the conditions specified herein. The Parties agree that the elements of the Plan are an integrated package, and this MOU does not obligate any of the Parties to support any individual element separate from the entire package. Further principles of implementation are set forth in Section 15, and agreed upon next steps are provided in Section 16. The proceeds from the transactions contemplated herein are intended to eliminate SCE's net undercollected amount as of January 31, 2001, as described herein. Accordingly, except as otherwise provided herein, proceeds received from the securitizations and Transmission Sale described herein will be applied to Page 3 reduce payments due for the procurement of power that are included in, and indebtedness (and refinancings thereof) incurred by SCE to finance, the net undercollected amount. In connection with the execution of the Purchase and Sale Agreement (as defined in Section 4(b)), SCE will deliver to CDWR a schedule of sources and uses setting forth SCE's uses of the proceeds being applied to the net undercollected amount. 3. Utility Retained Generation Subject to execution of the Definitive Agreements (as defined in Section 4(b)), adoption of the CPUC Implementing Decisions, and adoption of the legislation contemplated hereby, SCE's generation assets, including all energy, capacity, ancillary services, and any combination thereof, to which SCE has a contractual right (collectively "URG"), will be committed to cost-based ratemaking for SCE's bundled service customers, and SCE will not seek authority to sell such assets, through December 31, 2010. In addition, SCE will operate its URG in accordance with good utility practices, subject to the further terms hereof. SCE's URG includes its interests in Units 2 and 3 of the San Onofre Nuclear Generating Station ("SONGS"), the Palo Verde Nuclear Generating Station ("PVNGS"), the Mohave Generating Station ("Mohave"), the Four Corners Generating Station ("Four Corners"), SCE's hydroelectric facilities ("Hydro Facilities"), and the Pebbly Beach generating facility. URG also includes, for their respective terms, power purchase contracts that SCE currently has, and other contractual rights that SCE currently has, to purchase energy, capacity, ancillary services and any combination thereof, from other utilities, power suppliers or qualifying facilities. Consistent with the purposes of this paragraph, SCE will withdraw its pending application with the CPUC to sell its Mohave, PVNGS and Four Corners facilities. This MOU does not address any aspects of the status and ratemaking treatment of the URG or the ratemaking treatment therefore after December 31, 2010, and does not bind any party to any obligation or exempt any party from any requirement in respect thereof. Page 4 In return, subject to execution of the Definitive Agreements, the adoption of the legislation contemplated hereby and the adoption or approval of the CPUC Implementing Decisions, SCE will be entitled to collect revenues sufficient to cover its costs from January 1, 2001, associated with its URG (and all costs for ancillary services or other ISO costs associated with CDWR's procurement of the net short allocated to SCE under Section 10) on a timely basis, in accordance with the principles of cost-based ratemaking as applied in this State. In this regard, one of the CPUC Implementing Decisions shall be the adoption by the CPUC of procedures (which may include one or more balancing accounts and trigger mechanisms) designed to ensure that any undercollection or overcollection of URG costs (provided that actual costs of utility-owned generation shall equal authorized costs, except for variable fuel costs) will be reconciled in a timely manner and that any undercollection can be financed on reasonable terms consistent with SCE being an investment grade credit (the "URG Cost Recovery Mechanism"). The legislation necessary for the implementation of the Plan shall include legislation overriding any applicable limits in A.B. 1890 which may be inconsistent with the foregoing recovery principle. For the period from January 1 through 31, 2001, SCE will be deemed to have recovered its costs associated with its URG through the operation of the Transition Cost Balancing Account ("TCBA"), except for depreciation and amortization that SCE shall recover as a capital-related cost as described below. Subject to the further provisions of this MOU respecting recovery of investments, and the ratemaking principles set forth herein, a CPUC Implementing Decision shall provide that SCE's costs associated with its URG will include, through December 31, 2010: o All customary categories of operating costs, including, but not limited to, fuel costs (fixed and variable), operations and maintenance expenses, costs of emissions credits (subject to the further provisions of Section 7), direct, joint and common administrative and general (A&G) costs (excluding non-site specific general plant, which shall be treated as a capital cost), Page 5 taxes, scheduling and dispatch costs, congestion costs, ancillary service costs, and other transmission-related costs charged to generators. o For SONGS 2 and 3, other than transmission-related costs, operating costs will be recovered through 2003 through the existing Incremental Cost Incentive Procedure ("ICIP") and will be recovered without regard to the ICIP mechanism thereafter. o All reasonably recorded capital-related costs, including a full return on SCE's investment in used and useful URG (except as provided herein with respect to SONGS 2 and 3). SCE's investment in URG will be set at the net book value of such assets on December 31, 2000, including site specific and non-site specific general plant and capital additions made after December 31, 1995, the costs of which have been reasonably and prudently incurred, together with their associated income tax regulatory receivable or payable, provided that the $129,783,000 of non-nuclear site-specific general plant and capital additions made after December 31, 1995 and described on a schedule that has been provided to CDWR and which have not to date been disapproved by the CPUC shall be allowed in SCE's rate base temporarily until the final approval or disapproval of such additions which shall be accomplished by the CPUC as soon as practicable. Depreciation schedules will be based on the expected remaining useful life of each plant, fixed for this purpose for the period ending December 31, 2010 for SONGS 2 and 3 and PVNGS. For purposes of this Section 3, "net book value" means the original cost recorded in SCE's books for a particular asset, less any accumulated depreciation or amortization plus any deferred or flow through taxes. Assets that have been expensed shall not have a book value. Page 6 o All reasonable and prudent incremental capital investments put into service after December 31, 2000. Such investments, including income taxes and a full return on investment, will be recovered in rates from the time they are placed in service. Incremental investment which has not otherwise been expensed will be depreciated over the expected remaining useful life of the plant in question, which for purposes of SONGS 2 and 3 and PVNGS, will be determined by the remaining term of the applicable license for each plant, granted to SCE by the Nuclear Regulatory Commission ("NRC"), as such licenses may be extended by the NRC. Notwithstanding anything to the contrary in this Section 3, through 2003 incremental capital expenditures for SONGS 2 and 3 will be recovered through the ICIP mechanism. Operating decisions, including dispatch decisions, maintenance practices, energy/capacity exchange decisions, and other operating practices shall be performed by SCE in a reasonable and prudent manner. Under current CPUC decisions, net revenues from PVNGS after 2001 and net revenues from SONGS 2 and 3 after 2003 are subject to a sharing mechanism whereby profits (as defined) are shared equally between shareholders and customers. A CPUC Implementing Decision shall provide that such sharing mechanism, and all associated provisions for transfer of post-ICIP cost responsibility to SCE, will be eliminated through December 31, 2010. The existing memorandum of understanding respecting SCE's Hydro Facilities will be rendered moot, and SCE will withdraw its associated application under Public Utilities Code section 377. Page 7 4. Transmission Sale (a) Purchase of Assets and Assumed Liabilities Subject to enabling legislation and the negotiation and execution of the pertinent contracts, CDWR, or another authorized State agency (the "Purchaser"), will purchase SCE's transmission system. Subject to the further provisions of this MOU, the Transmission Sale includes all of SCE's right, title, and interest to: (i) all transmission assets under ISO control; (ii) any other assets not under ISO control that are used exclusively in connection with transmission and included in SCE's FERC rates charged to SCE's bundled service customers, or, in the case of any such assets acquired after the date of such rates, includable in SCE's FERC rates charged to SCE's bundled service customers; and (iii) related agreements and contracts. The transmission assets shall also include rights to the real property associated with or held for use in connection with the transmission system ("Real Property") as well as other mutually agreed-upon assets and rights of SCE in assets which are subject to joint interests of other parties, including shared assets and rights, it being understood by the parties that the transmission assets to be acquired by the Purchaser, whether through the acquisition of assets to be exclusively owned by the Purchaser or through the acquisition of rights in shared assets, shall be sufficient for the Purchaser to acquire a functional transmission system capable of providing transmission services of the type that it has in the past, with sufficient rights to repair and upgrade the transmission system and to operate it efficiently and effectively. It is also understood by the Parties that SCE's transmission system has been built and operated on a fully integrated basis with SCE's distribution system and that the Purchaser's operation of the transmission system and SCE's operation of the distribution system will therefore necessarily involve mutually acceptable arrangements for the sharing by SCE and the Purchaser of certain systems and assets to avoid duplicative and potentially substantial costs to ratepayers and taxpayers. To the extent the Purchaser desires physical separation of transmission assets from distribution assets, the costs of such separation, if feasible, will be borne by the Purchaser. The Real Property and other assets Page 8 included in the Transmission Sale are collectively referred to herein as, the "Purchased Assets." Subject to the further provisions of this MOU, title transferred to the Purchaser will be the same as SCE's title, provided that the Purchased Assets will be transferred free and clear of liens and encumbrances securing SCE's indebtedness for money borrowed or other obligations of SCE not related to the transferred assets or (unless the same has been adjusted for in the purchase price or in prorations) not required to be assumed by the Purchaser hereunder; provided, that the Definitive Agreements shall include provisions pursuant to which, if SCE is unable, after using commercially reasonable efforts, to obtain the release of any liens or encumbrances which it is responsible to release in connection with the sale of the Purchased Assets (other than liens or encumbrances securing indebtedness for borrowed money), then such failure shall not be a failure of the foregoing condition or otherwise a default on the part of SCE if SCE is diligently contesting such lien or encumbrance; SCE indemnifies the Purchaser from and against any liability, damage, cost or expense incurred by it on account thereof; and such lien or encumbrance has no material adverse effect on Purchaser's ownership or operation of a functional transmission system capable of providing transmission services of the type that it has in the past, with sufficient rights to repair and upgrade the transmission system and to operate it efficiently and effectively. SCE will retain all of its right, title and interest in and to its existing assets used exclusively in the operation of its non-transmission business, such as generation assets (other than designated assets specified in the Purchase and Sale Agreement, such as mutually agreed upon radial lines), assets used in SCE's distribution business, communications facilities, protection systems, control facilities and oil pipeline assets, and SCE will retain rights in other assets necessary for such businesses to continue to provide the services as they have in the past. The Purchase and Sale Agreement will set forth the procedures and methods for transferring and retaining interests in assets that are to be shared by the Parties after the closing (because of the integrated nature of the transmission and distribution businesses), provided that each Party will be entitled to the economic benefit of its ownership or rights in a shared asset. The Parties will in any event grant and reserve, Page 9 as appropriate, such licenses, easements and reciprocal easements as may be necessary or, in the reasonable judgment of the Parties, desirable, to permit the Parties to own, operate and maintain their respective assets and their interests therein. Such licenses, easements and reciprocal easements shall, among other things, assure ingress, egress, access, utilities and support; permit maintenance, relocation, construction and alteration; and protect against encroachment, all as provided for in the Definitive Agreements and subject to appropriate limitations and protections to be provided for therein. If, following the Transmission Sale, the Purchaser decides to explore the possible offer for sale of all or substantially all of the Purchased Assets (including all or substantially all of a larger transmission grid of which the Purchased Assets may then form a part) through a competitive bidding process, the Purchase and Sale Agreement will provide to SCE a non-exclusive opportunity to bid for all, but not less than all, of the assets the Purchaser proposes to sell, on the same terms and conditions as may be applicable to the other bidders generally. The Purchase and Sale Agreement will contain mutually agreed upon representations and warranties, which will not include any representations and warranties regarding or related to the physical condition of the Purchased Assets, but will include covenants regarding operations in the ordinary course. The assets will be sold to the Purchaser on an "AS IS, WHERE IS" and "WITH ALL FAULTS" basis, and the Purchaser will assume all liabilities to the extent related to the transferred assets, including all contractual obligations (including obligations to provide transmission service and, without limiting the parties' obligations under other provisions of this MOU, SCE's obligations under the Transmission Control Agreement with the ISO, if such assumption is required to transfer SCE's rights in the Purchased Assets or in order for SCE to be relieved of its ongoing obligations under the Transmission Control Agreement), environmental obligations, liabilities related to the operation of the assets and decommissioning obligations, subject to the following: Page 10 o Recurring operating expenses will be subject to customary pro-ration as of the closing; o To the extent the cost of a liability has already been collected in rates by SCE, SCE will indemnify the Purchaser against such liability; o Liabilities for pending insured claims (including deductibles applicable thereto) will be retained by SCE; o SCE will assign its rights against insurers and third parties for liabilities assumed by the Purchaser and each Party will cooperate and assist the other in pursuing its rights against insurers and third parties related to assumed and retained liabilities, provided that if consent to such assignment is not received from insurers, then SCE will assign the insurance proceeds arising from such claims; SCE and the Purchaser will also negotiate provisions relating to the extension of claims periods under insurance policies related to the Purchased Assets, including provisions related to the cost thereof; o SCE will indemnify the Purchaser for environmental liabilities which are the "fault" of SCE, which term shall be as defined in the Purchase and Sale Agreement (it being understood that liabilities related to EMF will be assumed by the Purchaser, except for EMF-related liabilities for which SCE would retain responsibility under the preceding bulleted provisions of this Section and the last two bulleted provisions of this Section); o SCE will indemnify the Purchaser for other liabilities caused by SCE's gross negligence or willful misconduct prior to the Closing; Page 11 o SCE will indemnify the Purchaser for pre-closing breaches of contract under contracts not assigned to the Purchaser; o Non-ordinary course operating contracts to be assumed by the Purchaser will be disclosed in schedules to the Definitive Agreements which have been approved by the Purchaser and SCE; o Material liabilities (to be defined in the Definitive Agreements) actually known to a responsible officer of SCE and to be assumed by the Purchaser will be disclosed in schedules to the Definitive Agreements which have been approved by the Purchaser and SCE; o The Purchaser will not assume liabilities for pre-closing taxes, pre-closing criminal violations, breaches of the Purchase and Sale Agreement or similar liabilities customarily excluded from "AS IS" transactions; and o The Purchaser will not assume liabilities to the extent related to the assets and interests retained by SCE. The authorizing legislation will provide that from and after the sale of the Purchased Assets, transmission costs will be charged to retail customers within the SCE service area by the Purchaser, and if requested, SCE will, as billing agent, bill such charges and remit to the Purchaser all amounts collected, less prorated uncollectibles. (b) Agreements; Form of Transaction In addition to a purchase and sale agreement for the Transmission Sale ("Purchase and Sale Agreement"), the Purchaser and SCE would enter into certain related agreements as part of the transaction ("Related Agreements"). These would include the following: Page 12 o O&M Agreement - Pursuant to which the Purchaser, as the owner, shall have the right to make decisions commensurate with such interest, including the decisions to make upgrades and to establish budgets. In addition, pursuant to the O&M Agreement, SCE will provide operations and maintenance including ordinary repairs and billing and collections services for a minimum term of three (3) years with renewal options exercisable by the Purchaser. SCE would be compensated through a fee to be negotiated. For work not included in the fee, SCE's charges will be determined in accordance with the O&M Agreement subject to audit by the Purchaser. The Purchaser will be responsible for the costs of all capital improvements. It is the intention of the Parties that the O&M Agreement be structured so that improvements thereunder can be financed by tax-exempt bonds to the extent reasonably practicable. o Transmission Service Agreements - Pursuant to which the Purchaser will agree to provide SCE with nondiscriminatory transmission service for its URG and will further agree to provide nondiscriminatory transmission service for other power being delivered to SCE's customers. o Facilities Services and Coordinated Operations Agreements - Pursuant to which the Parties will agree to the delineation of responsibilities and costs (including the sharing of capital improvement costs) related to certain interrelated or shared assets. The Purchase and Sale Agreement together with the agreements contemplated in Section 5 (power sale contract regarding Sunrise), Section 6 (grants of conservation property), and 7 (agreements regarding claims of third parties) of this MOU, and the agreement, if any, effectuating CDWR's obligations with respect to the net short as provided for in Section 10 are collectively referred to herein as the "Definitive Agreements." The Definitive Agreements shall include all terms and conditions contained in this MOU that are to be implemented contractually, except as the Parties may mutually agree. The descriptions herein of the Definitive Agreements are Page 13 intended as a summary, and do not contain an exhaustive list of all provisions to be addressed in such agreements; and provided, further, that any additional terms and conditions shall not be inconsistent with the terms and conditions contained in this MOU, except as the Parties may mutually agree. The Definitive Agreements shall recognize that CDWR's actions as contemplated in this MOU shall be separate and apart from its powers and responsibilities with respect to the State Water Resources Development System and that any and all obligations incurred and the funding for all such obligations and activities arising from this MOU or the Definitive Agreements shall be separate and distinct from the funds, monies, and obligations of the State Water Resources Development System. (c) Purchase Price The purchase price will be 2.3 times SCE's net book value for the Purchased Assets as of December 31, 2000, subject to verification of recorded amounts in accordance with provisions to be negotiated in the Definitive Agreements and the adjustments noted below, plus the sum of (i) approximately $63 million of accelerated depreciation or similar tax benefits previously flowed through to ratepayers (grossed up for taxes payable on the recovery of such benefits in accordance with past ratemaking practices) and (ii) the transfer taxes payable in connection with the sale of the Purchased Assets. For purposes of this Section 4, "net book value" means the original cost recorded in SCE's books for a particular asset, less any accumulated depreciation. Assets that have been expensed shall not have a book value. The Parties currently estimate that the unadjusted purchase price will be approximately $2.76 billion. The purchase price will be subject to the following adjustments: (1) To add the net book value at closing of reasonable and prudent capital additions made to the Purchased Assets after December 31, 2000 to the extent not recovered in transmission rates prior to the closing, provided that capital additions approved by CDWR or the ISO and capital Page 14 additions that are in process or planned and that are disclosed in a schedule to the Definitive Agreements shall be deemed reasonable and prudent. Subject to the preceding sentence, capital additions that are in process at the time of the closing of the Transmission Sale will be valued at the investment made as of the closing date. (2) To add the net book value of any spare parts and similar current items to the extent included in the Purchased Assets; (3) To subtract the post-December 31, 2000 depreciation of the Purchased Assets; (4) To subtract the book value of any Purchased Assets existing as of December 31, 2000 that are sold after that date, provided that if such assets are not sold in the ordinary course of business and not replaced by assets intended as equivalent replacements, the amount subtracted shall be 2.3 times the book value of the sold assets; and (5) To add or subtract for such additional items as the Parties may agree upon. Items such as rent, insurance, taxes and the like that are customarily pro-rated for partial periods will be pro-rated at the closing. For purposes of this MOU, references to the "gain on sale" of the Transmission Sale shall mean proceeds of sale minus transaction costs paid or to be paid by SCE (other than those set forth in Section 9), transfer taxes payable by SCE, net book value of the Purchased Assets (including undepreciated capital additions as set forth above), and the recapture or recovery by tax authorities of approximately $63 million of accelerated depreciation or similar tax benefits previously flowed through to ratepayers (grossed up for taxes payable on the recovery of such benefits in accordance with past ratemaking practices). Page 15 (d) Use of Proceeds Proceeds from the Transmission Sale (including the back-up transaction referred to in paragraph (f) below) representing the net book value of the assets transferred at the closing (based on SCE's recorded amounts) will be used to reduce debt and equity (including through dividends, to the extent permitted by the California Corporations Code and consistent with SCE's authorized capital structure). The proceeds representing the gain on sale will be applied to recover SCE's "net undercollected amount," as described in Section 9 of this MOU, and accordingly will be applied to payments due for the procurement of power that are included in, and indebtedness (including interest thereon and refinancings thereof) incurred by SCE to finance, the net undercollected amount, including any securitization of such indebtedness. (e) Closing Conditions In addition to any other conditions described in this MOU, closing of the Transmission Sale transaction will be subject to other mutually agreed upon conditions, including receipt of all necessary approvals, without unreasonable conditions materially adverse to either party, from FERC, the ISO and SCE's Indenture Trustee, if required. It is contemplated that, regarding the sale of the Purchased Assets to the Purchaser and the other actions to be implemented contractually pursuant to this MOU, the legislative authorization will dispense with CEQA compliance. It is also contemplated that, regarding the sale of the Purchased Assets to the Purchaser, the legislation will dispense with approvals by the CPUC. Such legislation will also authorize the CDWR (or such other agency) and the Purchaser to enter into the transactions as contemplated hereby. The closing will also be conditioned upon the absence of any injunction, restraining order or other order restraining or prohibiting the consummation of the transactions contemplated in this MOU, and the absence of any suit by the Federal Government seeking to restrain or prohibit the consummation of the transactions contemplated in this MOU. Page 16 SCE will be required to deliver assets and rights sufficient for the Purchaser to acquire a functional transmission system capable of providing transmission services of the type that it has in the past, with sufficient rights to repair and upgrade the transmission system and to operate it efficiently and effectively. Subject to the foregoing, the Parties intend that a failure to obtain a necessary consent or approval to transfer that relates to only a portion of the Purchased Assets, after the Parties have used commercially reasonable efforts to do so, or a third party's exercise of a right of first refusal, will not result in a failure of closing conditions so long as the Purchaser obtains substantially the same benefits of the contemplated bargain as described below. In the event such a consent or approval is not received in a timely manner, the Parties will work in good faith to provide substantially the same benefits of the contemplated bargain to each of them through contractual and other means not involving an actual transfer that is subject to such consent or approval. Without limitation, the benefits of the contemplated bargain include, in the case of the Purchaser, the ability of the Purchaser to have upgrades and improvements made to the transmission system intended to be purchased by the Purchaser hereunder, without any material limitation. If the Parties are unable to provide substantially the same benefits of the contemplated bargain through contractual and other means (but in all events subject to the condition that the assets and rights to be acquired by the Purchaser must be sufficient for the Purchaser to acquire a functional transmission system capable of providing transmission services of the type that it has in the past, with sufficient rights to repair and upgrade the transmission system and to operate it efficiently and effectively), then the portion of the Purchased Assets in question will not be transferred, and there will be an equitable adjustment in the purchase price. In the event of any such exclusion of assets and equitable adjustment of price, SCE shall nonetheless cooperate with the Purchaser after the closing in order to enable upgrades and improvements to be made to that portion of the Purchased Assets that are not transferred. Page 17 (f) Back-Up Transaction If the Transmission Sale fails to close within 24 months (subject to extension by one party if the failure to close is due to the breach of the other party) of the execution of the Purchase and Sale Agreement for a "Qualified Triggering Reason" (as defined below), then SCE shall offer to sell to CDWR or its designated Purchaser (i) its hydroelectric assets and, if such assets do not produce a gain on sale substantially equivalent to the gain expected from the Transmission Sale, (ii) such rights, over a reasonable period of time, to the output of SCE's interests in generating plants (including its interests in Four Corners, SONGS, PVNGS and Mohave if then operated) after 2010 on terms and conditions that result in a value to CDWR determined on a net present value basis at the time of the consummation of the sale of the hydroelectric assets, reasonably equal to the difference between the gain expected from the Transmission Sale and the gain expected from the sale of the hydroelectric assets. If CDWR or such Purchaser so elects to purchase such assets, then the Parties will promptly negotiate in good faith a definitive sale agreement respecting such assets that shall contain terms comparable to the terms of the Transmission Sale. Upon execution of an agreement in respect of the alternative assets, the Purchase and Sale Agreement for the Transmission Sale will be cancelled and the references herein to the "Purchase and Sale Agreement" shall mean the definitive sale agreement for such alternative assets, and to the "Purchased Assets" shall mean the alternative assets purchased in such sale, mutatis mutandis. A Qualified Triggering Reason will be defined in the Purchase and Sale Agreement for the Transmission Sale consistent with the following: Failure to close for any reason other than (x) a breach or default by the Purchaser causing the failure to close, or (y) other reasons mutually agreed upon in the Definitive Agreements, it being understood that it is the intent of the Parties that (i) breaches of the Purchase and Sale Agreement by either Party that are compensable in damages or are immaterial will not provide a basis for the other Party's failure to close (provided that, in the case of Purchaser, upon closing Purchaser would obtain the benefits of the contemplated bargain as described above) and (ii) the Purchaser's or SCE's failure to close because a Page 18 regulatory authority or the ISO reasonably conditions its approval of the Transmission Sale shall not constitute a Qualified Triggering Reason. 5. Sunrise Project An EIX company will commit by contract - for a term of not less than 10 years - the entire output of the Sunrise power project (the "Sunrise Project") to CDWR or its designee under cost-of-service based rates on terms and conditions to be set forth in a Definitive Agreement that incorporates the terms hereof (the "Sunrise Agreement"). The EIX company will continue to use all commercially reasonable efforts to place Phase I of the Sunrise Project in service before the end of the Summer, 2001. Cost-of-service based rates shall be determined on the basis of a 50/50 debt to equity leverage, permanent financing at the Phase II commercial operations date, an assumed long-term interest rate of 9.0%, an 11.6% return on equity, a useful life of the facility of 30 years and a value at the end of the contract term equal to book value less undepreciated acceleration costs to bring Phase I online by Summer 2001. The fuel cost shall be passed through to CDWR, with a right of CDWR to supply its own fuel, provided CDWR gives the notice to be specified in the Sunrise Agreement. All other prices shall be fixed in the Sunrise Agreement. The capacity price, based on capital cost estimates for the Sunrise Project as of the signing of this MOU, would be $120/kW-yr for Phase I and $176/kW-yr for Phase II. The final capacity price will be based upon final costs incurred for the Project, which costs shall be subject to audit verification by CDWR. If the actual costs would result in a lower capacity price, the final price to CDWR shall be that lower capacity price. If the actual costs would result in a higher capacity price, CDWR and the EIX company shall share the increased costs on a 50/50 basis and the capacity price on Phase II shall be increased accordingly. The price for variable O&M, other than fuel costs, shall be fixed at $3.00/MW H for the term of the Sunrise Agreement. In addition to the above variable O&M payment, CDWR shall be responsible for start up payments per start for each normal start up in excess of 100 normal start ups per contract year in accordance with the following schedule: 101-135 starts at a cost of $300/start, 136-150 starts at a cost of $5,000/start, over 150 Page 19 starts at a cost of $14,000/start. The Sunrise Agreement shall provide CDWR with the standard rights of dispatch for this type of arrangement. The Phase I capacity charge is based on a limitation of the hours of operation as specified in the latest term sheet provided by the EIX company to CDWR prior to the date of this MOU based upon emission credits which the EIX company has obtained for the Project. Any increase in the hours of operation that CDWR may request would reflect increased costs for additional emission credits which would be reflected in an increase in the capacity charge to be agreed to by the Parties. In the event that this MOU terminates, the foregoing agreement for the Sunrise project would be withdrawn and subject to new discussions between the parties. Notwithstanding the foregoing, the Sunrise Agreement shall provide that if the Sunrise Project is not placed in service on or before August 15, 2001 subject to extension for a force majeure event outside of the control of the EIX company, the EIX company party thereto will credit the amount of $2,000,000 against the first $2,000,000 in billings the CDWR would otherwise be required to pay the EIX company under the Sunrise Agreement. 6. Conservation Property Pursuant to the Definitive Agreements, SCE will convey perpetual protective conservation easements to approximately 20,600 acres of its Big Creek hydroelectric related lands and approximately 825 acres of its Eastern Sierra hydroelectric related lands to a trust for the benefit of the State of California, which trust will serve as the interim holder of these interests while disposition and management plans therefore are developed as described below. The easements will restrict public agency access over lands included in FERC licensed areas to limited purposes consistent and that do not interfere with utility uses over such property. The purpose of these conveyances will be to ensure the long-term conservation of these lands for their public interest value for the people of the State of California, including fish, wildlife, and other ecological purposes; human recreation; preservation of open space and cultural resources; and for protection of water Page 20 quality and watershed functions. Accordingly, the trust conveyances will restrict future development over such lands in perpetuity, subject to the following: (i) existing non-utility uses based on current levels of activity shall be permitted for a period equal to the longer of 5 years or the remaining term set forth in existing leases, licenses, permits or other applicable agreements; (ii) existing utility uses (i.e., ownership and operation of any existing hydroelectric plants located on said lands and related improvements, including, in connection therewith, the maintenance, repair, replacement and installation of public utility infrastructure, such as water and sewer pipelines, and electric and telecommunications lines for existing utility uses) based on current levels of activity shall in all events be permitted for as long as the same continue; (iii) expansion of hydroelectric facilities currently located on said lands shall be permitted, but only with the approval of the state and federal agencies with jurisdiction over any such expansion; (iv) SCE's current timber harvesting, logging or similar activities shall be subject to modification based on the approved management and disposition plans referred to below; and (v) the maintenance, repair, replacement and installation of public utility infrastructure, such as water and sewer pipelines, and electric and telecommunications lines for non-utility and other uses to the extent permitted pursuant to the management and disposition plan. SCE will indemnify the trust, the State and any successor-in-interest against environmental liability associated with these lands, only to the extent attributable to SCE's own negligent or willful acts. The Definitive Agreements will provide that during the period the trust holds these interests, the Wildlife Conservation Board or another state agency whose primary mission includes the above purposes to be identified in the Definitive Agreements will develop, with input from SCE, local governments, federal agencies and other stakeholders, disposition and management plans for each of the conservation easements conveyed by SCE, through a property-specific process in which public input shall be obtained. All such disposition plans will be subject to the reservations contained in the easement grant, as specified above. The plans will analyze each property's natural resource, recreational, and economic use value to the people of the State of California and to the local community, subject to protection for existing uses and potential expansions of hydroelectric activities as set forth above, and determine the appropriate interests in the various lands to be transferred to the State or applicable agencies thereof (or, where appropriate, the U.S. Forest Service, or other applicable federal Page 21 agencies, local governmental agencies or, after consultation with and subject to the approval of SCE, non-governmental conservation organizations or other third parties specified in Civil Code Section 815.3) to preserve these values. As part of this process, the trust may request of SCE that it convey a fee interest in specific properties, and SCE will consider any such request in good faith on the basis of the specific justifications therefore and the necessity thereof in light of the existence of the conservation easement, provided that any such conveyance will be subject to an easement back to SCE in form and substance reasonably satisfactory to it to protect its interests, and no fee ownership request will relate to lands covering existing hydroelectric facilities and related uses as well as reasonable expansions thereof. It is anticipated that these disposition and management plans will be completed within 18 months after the conveyances of the easements to the trust (subject to compliance with applicable laws), and dispositions of the property or interests therein to the State or applicable agencies thereof, to the U.S. Forest Service or other applicable federal agencies, to local governmental agencies, or, after consultation with and subject to the approval of SCE, non-governmental conservation organizations or other third parties specified in Civil Code Section 815.3, will occur once such individual plans are finalized. The formal terms of the trust arrangement will be negotiated between the designated State agency and SCE as part of the Definitive Agreements on the basis of the principles enumerated above. Except as provided in the Definitive Agreements, SCE will continue to pay all expenses associated with the properties over which it has fee title, including property taxes, and will receive all income generated from these properties. Page 22 7. BFMs; Emission Credits; Claims Against Third Parties Upon execution of the Definitive Agreements, SCE will relinquish all claims against the State for commandeering SCE's block forward market contracts ("BFMs") purchased through the California Power Exchange ("PX"), and in connection therewith, CDWR will assume SCE's liabilities in respect of any claims arising on or after February 2, 2001 or relating to the collateral value of the BFMs after such date brought by the PX and/or PX Participants related to the BFMs. The Definitive Agreements shall obligate SCE, subject to pertinent regulatory approvals, to sell certain mutually agreed upon emission credits related to its previously sold generating stations, with the proceeds of such sale to be for the benefit of ratepayers, or, alternatively, SCE shall, subject to pertinent regulatory approvals, convey such credits to the State's Mitigation Bank for no additional consideration. In connection with the Definitive Agreements, the parties will negotiate concerning their mutual cooperation and coordination with respect to pursuing potential claims against third-party generators, and such Definitive Agreements may contain provisions for the assignment of such claims from SCE to the State or its agencies at times and upon terms to be mutually agreed upon. To the extent SCE at any time after execution of this MOU realizes a discount or credit in connection with the payment of any obligation included in the undercollection amount described in Section 9 of this MOU, the amount of such discount or credit shall be applied to the benefit of ratepayers in a manner to be more fully set forth in the Definitive Agreements. 8. Tax Payments To the extent not previously refunded by EIX after January 1, 2001, EIX will, following its filing of a final federal income tax return for the year 2000, refund to SCE its year 2000 estimated quarterly tax payments (approximately $293 million), and will fund an additional payment to SCE equal to the federal loss carryback (currently estimated at approximately $127 million) that SCE would have had if it were not part of EIX's Page 23 consolidated group of taxpayers; provided that in no event will refunds from EIX to SCE attributable to tax year 2000 aggregate less than $400 million. 9. Net Undercollected Amount For the purposes of this MOU, the "net undercollected amount" shall be computed as set forth in the remainder of this paragraph. For the purposes of this calculation, SCE's TCBA and Transition Revenue Account ("TRA") as of January 31, 2001 will not be combined. The balance in SCE's TCBA as of January 31, 2001 (adjusted (a) to exclude any amortization and depreciation for presently owned generating facilities, together with their associated regulatory receivable or payable for taxes that has occurred since December 31, 2000, which shall be recovered as provided in Section 3 of this MOU, (b) to include the associated Generation Memorandum Accounts, and (c) to exclude any entries with corresponding entries in the Generation Asset Balancing Account) will be applied to reduce the January 31, 2001 TRA balance (adjusted to remove amounts representing potential payments to CDWR or the ISO for the period January 18 to 31, 2001 which are part of the procurement obligations which are being assumed by CDWR pursuant to Section 10), resulting in a "net undercollected amount." The net undercollected amount (i) will include retail generation revenues in respect of power delivered in January 2001 received in February 2001 and thereafter (until the end of the last full calendar month preceding the execution of the Definitive Agreements), (ii) will exclude accrued QF costs as of January 31, 2001 not yet actually due and payable as of that date (it being acknowledged that, notwithstanding the January 2001 cost recovery mechanism in Section 3, SCE will be entitled to recover these accrued QF costs in a timely manner in rates going forward), (iii) will exclude ISO charges (including imbalance energy charges) assumed by the CDWR, as set forth in Section 10, and (iv) will include CDWR charges on account of certain QF's not delivering power to SCE, set forth in Section 10 of this MOU and SCE's cost obligations described in Section 15 of this MOU. Subject to the foregoing, the size of the net undercollected amount as computed under this paragraph will be subject to verification of recorded amounts and any resulting adjustments by the CPUC, within 60 days of the passage of the legislation Page 24 referred to below. The net undercollected amount will be deemed to equal the amount submitted by SCE if the CPUC does not complete the verification process (and any adjustments resulting therefrom) within the 60-day period. The net undercollected amount and the costs reflected therein will not be subject to review by the CPUC or any other legislative, administrative or judicial body for reasonableness. SCE estimates that the net undercollected amount, as of January 31, 2001 was approximately $3.5 billion. Legislation will direct the CPUC to establish an initial nonbypassable dedicated rate component (including recovery of associated franchise fees and uncollectibles) intended to be securitized, subject to the terms hereof, as soon as practicable after the establishment thereof. Such dedicated rate component will enable SCE to recover (i) the full net undercollected amount less the expected gain on the Transmission Sale described in Sections 4(c) and 4(d) above; (ii) the discounted net present value of interest on the expected gain on the Transmission Sale for a period commencing on the date of the consummation of the securitization of the Initial Dedicated Rate Component as described below and ending two years after the date of the execution of the Purchase and Sale Agreement; and (iii) interest on obligations included in the undercollection or interim financing thereof during such period from January 31, 2001 until the securitization transaction covering (i), (ii) and (iii) is consummated, based on an effective interest rate to be mutually agreed to and set forth in the Definitive Agreements, net of interest earned by SCE on its balances of cash, cash equivalents and other liquid assets, if any, during such period in excess of its normal cash balances. Such dedicated rate component is referred to herein as the "First Dedicated Rate Component." SCE's actual borrowing costs are referred to herein as "SCE's interest cost." As indicated above, the amount of interest described in clause (ii) will be appropriately discounted to reflect SCE's receipt of such amount in the securitization transaction before interest on the expected gain on the Transmission Sale would actually accrue. SCE's interest cost shall be addressed as provided in this paragraph and, subject to the consummation of the financings and securitizations contemplated hereby, shall not be recoverable in rates (other than through the dedicated rate component described above), except that any difference between the amount of interest securitized by SCE pursuant to clause (ii) Page 25 above and the actual net amount of interest incurred by SCE with respect to financing of a portion of the undercollection equal to the expected gain on the Transmission Sale from the date of the consummation of the securitization of the Initial Dedicated Rate Component until the earlier of two years after the date of the execution of the Purchase and Sale Agreement or the consummation of the Transmission Sale (based on a rate to be mutually agreed to and set forth in the Definitive Agreements) shall be recovered by or paid by SCE from or to its ratepayers. Legislation will further direct the CPUC to establish a second nonbypassable dedicated rate component (including recovery of associated franchise fees and uncollectibles) that enables SCE to recover the expected gain on the Transmission Sale as described in Section 4(c) and 4(d) above, subject to the provisions set forth below. This dedicated rate component is referred to herein as the "Second Dedicated Rate Component." The Second Dedicated Rate Component is intended to provide a source to secure bridge financing of the expected gain on the Transmission Sale. It shall not appear in rates for two years after the execution of the Purchase and Sale Agreement and shall be made subject to the Transmission Sale not closing before such time. The Second Dedicated Rate Component would not be eligible to be securitized through a public offering of debt securities by a special purpose entity until it is eligible to appear in rates as provided above, but may be used to secure or facilitate bridge financing prior to such time. However, the Second Dedicated Rate Component will have the benefit of a financing order of the kind described in Article 5.5 of the Public Utilities Code or order or action having equivalent effect, and shall be effective no later than the effectiveness of the financing order or its equivalent for the First Dedicated Rate Component. If the actual gain on the Transmission Sale exceeds the estimated amount, then the difference shall be refunded to SCE's customers; if the actual gain on the Transmission Sale is less than the estimated amount, then the deficiency will be recovered from SCE's customers in retail rates over the term of the securitization period. Likewise, if there are other elements (other than Page 26 interest, which is covered in the preceding paragraph) included in the amount securitized which are based upon contingencies related to the consummation of the Transmission Sale (such as, for example, estimates of closing costs), there shall be adjustments (to be refunded to or recovered from SCE's customers) if the actual amounts are less than or greater than the estimated amounts. In addition, if any amount paid to SCE from the proceeds of the initial securitization is intended to cover costs other than procurement costs (such as interest or closing costs), SCE shall maintain such amounts in one or more segregated accounts and use the amounts therein solely for the purposes for which they were paid. Further, the Definitive Agreements shall provide for appropriate adjustments upon the Transmission Sale in the event that the Second Dedicated Rate Component has commenced but the Transmission Sale has not yet occurred. The dedicated rate components will be used solely to recover the net undercollected amount, together with (a) reasonable costs incurred by SCE associated with any financing of such amount (including any reasonable hedging costs incurred by SCE in a reasonable hedging transaction approved by the Department of Finance to hedge SCE's interest rate risk if the interest rate provided for in the financing order or equivalent is a fixed or determined rate) and (b) costs incurred or anticipated to be incurred by the State and the CDWR in connection with this MOU, the Transmission Sale, or the securitization, as more fully described in Section 15. The terms of any securitization transaction will be subject to the approval of the Director of the State Department of Finance, which approval shall not be unreasonably withheld or delayed. The net undercollected amount will be amortized over a period of not less than 15 years unless placement of securities with such a maturity is not reasonably practical, in which case a shorter maturity shall be authorized by the Department of Finance. The legislation will further contain provisions that are the same as Article 5.5 of the Public Utilities Code, mutatis mutandis, and that are designed to facilitate the securitizing of the First and Second Dedicated Rate Components, with such changes thereto as may be agreed upon by the Parties as necessary to effectuate the foregoing provisions. Page 27 Amounts financed through such dedicated rate component(s) will not be regarded as long-term debt for purposes of determining the utility's authorized capital structure. Any tax benefits resulting from the timing difference between the incurrence of procurement costs and the recovery thereof through the financing contemplated in this Section 9 will be used to benefit retail customers. The amount of benefit resulting from any such tax timing difference during each applicable period will be determined by using a rate of return equal to the weighted average yield applicable to the securities issued in such financing. 10. Procurement Obligations Either through legislation and/or through a contract between SCE and CDWR (which, if in the form of a contract, shall be a Definitive Agreement), the following will be effected: o Through December 31, 2002, CDWR will assume the entire responsibility for procuring the full net short needs of retail customers within the SCE service area (i.e., the electricity needed to meet SCE's load that is not met by the generation resources owned or under contract to SCE as of January 18, 2001, plus any additions thereafter). CDWR shall also assume responsibility for ancillary services (other than regulation, except to the extent the parties agree pursuant to the next paragraph) associated with CDWR import energy purchases and responsibility for the cost of Reliability Must Run contracts from January 18, 2001. In addition, CDWR will also assume responsibility for ISO charges to SCE for the energy cost component of energy purchased by the ISO since January 18, 2001, to meet the net short requirements in SCE's service area (such energy cost component shall not include charges for underscheduling, capacity charges, ancillary services or PX or similar chargebacks, except to the extent the parties agree pursuant to the next paragraph). Page 28 o It is the intent of both SCE and CDWR that the overall costs to SCE's retail customers be minimized, and accordingly SCE and CDWR agree that SCE's operation of URG and CDWR's net short procurement should be coordinated. SCE and CDWR will negotiate a mutually-agreeable operational protocol which will address the use of URG for self-scheduling of ancillary services, and will allocate responsibility for procurement and costs of ancillary services. In addition, the operational protocol will allocate cost responsibility for any ISO underscheduling penalties based upon SCE's good faith forecast of the net-short and CDWR's activities to procure sufficient quantities to meet SCE's forecast. SCE shall be entitled to collect revenues through its retail rates sufficient to cover the costs of any ancillary services it is responsible for on a timely basis. o SCE will cooperate with CDWR to achieve operational efficiencies for bundled service customers; and o SCE power purchases, and, until it is creditworthy, utilization of URG, to meet its obligations under interutility contracts will be allowed with an offset for the net proceeds of any sale of power. CDWR desires to be relieved of its obligation to provide for the net short needs of SCE's retail customers, and SCE agrees to resume procurement of the full net short needs and electric requirements for retail customers within the SCE service area after 2002. In addition, after 2002, CDWR may at least assign to SCE the administration of any of CDWR's outstanding procurement contracts. The Parties will work together to minimize the burden on CDWR, without imposing direct or indirect financial risks on SCE for those contracts. The Parties recognize that legislation may be needed to achieve this result. Page 29 Given the magnitude of the net short and SCE's current financial condition, the practical ability of SCE to resume such procurement responsibility after 2002, and to relieve CDWR of such burden, will depend in substantial part upon prompt restoration of SCE's creditworthiness and its ability to recover such procurement costs in rates on a timely basis. Accordingly, the CPUC Implementing Decisions will include confirmation of SCE's entitlement to recover its reasonable procurement costs on a timely basis and establish procedures (which may include one or more balancing accounts and trigger mechanisms) designed to ensure that any undercollection or overcollection of procurement costs will be reconciled in a timely manner and any undercollection will be able to be financed on reasonable terms consistent with SCE being an investment grade credit, and mechanisms to mitigate the potential risks of retrospective reasonableness review of procurement practices, including the development of a framework and criteria for procurement practices, the submission of an annual procurement plan, and the prompt approval or disapproval of contracts (the "Procurement Cost Recovery Mechanism"). In addition, subject to execution of the Definitive Agreements and adoption of legislation necessary to implement this MOU, SCE shall cooperate with CDWR in the implementation of AB 1X, including provision by SCE of such information as CDWR may reasonably require in connection with the financing of its power purchase program. SCE and CDWR shall also execute a mutually approved servicing agreement (which shall not be treated as a Definitive Agreement hereunder) relating to the distribution, billing and collection of CDWR power for customers in SCE's service area. Upon the securitization of the First Dedicated Rate Component referred to in Section 9 hereof, SCE shall pay CDWR an amount to be agreed upon representing those costs incurred by CDWR in covering that portion of the net short from January 18, 2001 through April 7, 2001 which is attributable to certain QF's not delivering power to SCE, it being agreed that such payments to CDWR shall be added to the net undercollected amount referred to herein and shall not be construed as any admission by SCE. Page 30 The Parties agree to discuss in good faith the terms pursuant to which SCE, as agent and not as principal, would be willing to assist CDWR in the management of its power purchase contracts, on terms to be resolved in a subsequent agreement. Such subsequent agreement shall not be considered a "Definitive Agreement" as defined herein. 11. Investment Recovery One of the goals of the Plan is for SCE to be an investment grade credit. The Parties recognize that the creditworthiness and health of SCE, and the ability of SCE to finance infrastructure improvements, require greater certainty in respect of SCE's ability to earn a fair return on invested capital. Accordingly, new legislation will provide that SCE's authorized return on equity may not be reduced by the CPUC below its current 11.6% before December 31, 2010, and that prior to such date, the CPUC will not establish a ratemaking capital structure for SCE with different proportions of common equity or preferred equity to debt than that set forth in current authorizations. 12. Capital Commitment by EIX; "First Priority" Condition Pursuant to the Definitive Agreements, EIX and SCE shall commit to make capital investments in SCE's regulated businesses of at least $3 billion through 2006, or such lesser amount as the CPUC may approve, with the equity component thereof funded from utility retained earnings or, if insufficient, from EIX equity investment, provided that SCE will receive a return of and on equity in retail rates as provided in Section 11 hereof. The CPUC Implementing Decisions will include a clarification that the "first priority" condition in the decision authorizing the formation of a holding company for SCE (D. 88-01-063, Condition 12) refers to equity investment, not working capital for operating costs. Page 31 13. Additional CPUC Implementing Decisions In addition to the URG Cost Recovery Mechanism, the Procurement Cost Recovery Mechanism, and the other provisions of this MOU that are contemplated to be implemented through CPUC Implementing Decisions, the CPUC Implementing Decisions shall include: o Orders resolving the responsibility of SCE to provide credits to direct access customers in respect of electricity deliveries after December 31, 2000 in respects which do not result in any material financial detriment to SCE; and o A favorable determination by the CPUC in response to a request to be submitted by SCE that SCE's 2002 Utility Distribution Company's GRC will be deferred to test-year 2003. 14. Litigation Settlement As part of the implementation steps, the Parties to the federal lawsuit either will enter into a stipulated judgment resolving the federal lawsuit by abandonment of SCE's claims and reflecting those terms of this MOU that have not been secured either by entering into a Definitive Agreement, by CPUC action or by legislation, or, if reasonably acceptable at the time to SCE, will enter into a dismissal, with prejudice, of those claims. The claims to be abandoned or dismissed by SCE as part of the settlement of the Federal litigation will include, without limitation: o any claim SCE may have or could have had against the State of California or any agency, department or subdivision thereof, the Federal Government, or the CPUC for takings or under the filed rate doctrine arising from or related to the facts asserted in such litigation; and Page 32 o any claims challenging actions taken by the CPUC prior to execution of the last executed Definitive Agreement to implement AB 1X and 6X, including, without limitation, any determinations by the CPUC, State of California or any agency, department or subdivision thereof of the California Procurement Adjustment or the Fixed Department of Water Resources Set Aside. In addition as part of the Definitive Agreements, the parties thereto will negotiate in good faith releases of certain other claims. The judgment or dismissal will be filed promptly following passage of all legislation, execution of the Definitive Agreements and issuance of the financing order or equivalent for the securitizations of the First and Second Dedicated Rate Components. 15. Implementation Principles The MOU signifies the intention of the Parties to act in good faith to sponsor and support legislation effecting elements of the Plan to be implemented by legislation and to act in good faith to negotiate final agreements for those elements of the Plan that are to be implemented by contract. As part of such intention, each Party will allow for reasonable due diligence by the other Party, and SCE will not seek to sell, encumber or otherwise dispose of the transmission assets to any other person or entity or submit any application in respect of the same to the CPUC or FERC. This MOU shall be terminable by either Party upon written notice to the other in the event that such legislation is not passed and the Definitive Agreements are not executed by August 15, 2001 unless the Parties otherwise agree. This MOU shall also be terminable in the event that any of the following (each, a "Material Adverse Change") occurs: (a) in the event any law is passed, adopted or repealed or regulatory action taken which, in the good faith judgment of such Party, would materially impede or frustrate the ability of the Parties to effectuate all of the elements of the Plan as a package; (b) as set forth above, in the event that all of the actions and approvals expressly characterized herein as "CPUC Implementing Decisions" have not been taken or adopted on or before sixty (60) days after the date this MOU is signed by all Parties; (c) in the event of the adoption of or any change in any applicable rule, regulation or order which would have a material adverse effect on any Party or which, in the case of SCE, would include the failure on the part of the CPUC, following a motion therefor filed on behalf of SCE (i) to extend SCE's existing non-generation Performance Page 33 Based Ratemaking and cost of capital mechanisms until SCE's new GRC is implemented; (ii) to terminate the Accelerated Cost Recovery and Reduced Cost Recovery ("ACRA/RCRA") mechanisms; (iii) to permit the amortization of the RCRA reserve, in accordance with prior CPUC decisions; (d) in the event that any material penalty is imposed by the CPUC in respect of the relationship between SCE and EIX prior to the date hereof, including without limitation any of the matters raised in Order Instituting Investigation 01-04-002 or (e) in the event any bankruptcy proceeding in respect of any Party is commenced. In the event of termination of this MOU or any failure of the Definitive Agreements to be executed or become effective, there shall be no liability for damages or otherwise on the part of a Party to another under or by reason of this MOU or any discussions, negotiations or conduct pertaining to this MOU or by reason of the failure of the transactions contemplated hereby or thereby to be consummated. Inasmuch as each element of the Plan is part of an integrated package, the effectuation of each will depend upon effectuation of the others. In particular: (i) Execution of the Definitive Agreements will be subject to final passage and effectiveness of legislation implementing all elements of the Plan that are required to be legislatively implemented and the adoption of the CPUC Implementing Decisions. The Parties recognize that, as part of the Definitive Agreements, mutually acceptable provisions shall be made with respect to liabilities for PX chargebacks and ISO underscheduling charges. (ii) Any financing order implementing the dedicated rate component(s) will be subject to execution of the Definitive Agreements by the parties thereto, and the consummation of the effectiveness of the Definitive Agreements shall be conditioned upon the existence of financing orders or their equivalent establishing irrevocable dedicated rate components for the "net undercollected amount" referred to in Section 9. Page 34 (iii) Each Definitive Agreement will be subject to the Parties' execution of the other Definitive Agreements; provided that: (A) the Sunrise Agreement may be signed prior to the date the other agreements are signed; (B) EIX may thereafter terminate the Sunrise Agreement if the other Definitive Agreements are not executed when otherwise required by this MOU; and (C) the EIX company shall be excused from performance under the Sunrise Agreement in the event that, after the execution of the Definitive Agreements, either (I) any legislation is enacted or any rule, regulation or order is adopted by the CPUC which would have the effect of overturning, in respects materially adverse to SCE, those CPUC Implementing Decisions which were adopted prior to the execution of the Definitive Agreements or (II) any Material Adverse Change referred to in clause (d) of the definition thereof occurs. (iv) Execution of each Definitive Agreement called for by the Plan and dismissal or other resolution of the litigation referred to in Section 14 will be subject to there having been no Material Adverse Change and no commencement of any bankruptcy or similar proceeding to which any party hereto is subject. Implementation of the Plan will be further subject to the following: (a) Absence of any injunction, restraining order or other order restraining or prohibiting the consummation of the transactions contemplated in this MOU, and the absence of any suit by the Federal Government seeking to restrain or prohibit the consummation of the transactions contemplated in this MOU. (b) Receipt by each of the Parties upon or prior to execution of the Definitive Agreements of such opinions of their financial advisors as they deem reasonably necessary. Page 35 Provided the Definitive Agreements are entered into, SCE will pay all of the reasonable costs and expenses incurred by the State directly in connection with the negotiation or effectuation of this MOU and the Definitive Agreements, including legal fees, fees of financial advisors and accountants and expenses of its representatives, whether or not the transactions contemplated by this MOU are consummated, subject to the following: o SCE's obligations will only be for transaction costs identified to transactions with SCE (not including, for example, costs associated with State financing of its obligations or the conservation advertising program); o SCE's will not be obligated for State costs in excess of an amount to be agreed upon based on an estimate provided by the State in connection with the execution of the Definitive Agreements. All such costs shall be subject to audit verification; and o SCE recovers such expenses through the securitization of the First Dedicated Rate Component described in Section 9 of this MOU (in addition to the net undercollected amount) or if such securitization does not occur, in retail rates. 16. Next Steps Subject to the provisions of Section 15, the Parties will act in good faith to implement this MOU and effectuate the Plan as quickly as reasonably practicable. In this regard, the Governor will submit to the State Legislature, after review and comment by SCE, a comprehensive legislative package setting forth the legislative elements of the Plan. The Parties will then proceed diligently and in good faith to attempt to have the necessary legislation adopted, and will negotiate in good faith in an attempt to execute the Definitive Agreements, by August 15, 2001. Page 36 While time is of the essence of this MOU, failure to satisfy the calendar set forth in the preceding paragraph will not result in a termination of this MOU, if the Parties are continuing to proceed diligently and in good faith to achieve its implementation. Failure of all implementing legislation to be adopted and effective and Definitive Agreements to be signed on or before December 31, 2001, will entitle any Party thereafter to terminate this MOU upon notice to the other Parties. 17. Signatures This MOU may be executed in counterparts and via facsimile. The individuals executing this MOU represent that they are authorized to sign on behalf of the Parties they represent, it being understood, however, that the execution of this MOU by representatives of SCE and EIX is following the approval of this MOU by the Board of Directors of each such entity. Page 37 IN WITNESS WHEREOF, the undersigned have executed this Memorandum of Understanding as of the day and year first above written. SOUTHERN CALIFORNIA EDISON COMPANY, a California corporation By: Stephen E. Frank Name: Stephen E. Frank Title: Chairman of the Board, President and CEO EDISON INTERNATIONAL, INC., a California corporation By: John E. Bryson Name: John E. Bryson Title: Chairman of the Board, President and CEO CALIFORNIA DEPARTMENT OF WATER RESOURCES By: Thomas M. Hannigan Name: Thomas M. Hannigan Title: Director BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Application of Southern California Edison ) Company (U 338-E) for Authority to ) Institute a Rate Stabilization Plan with a ) Application 00-11-038 Rate Increase and End of Rate Freeze ) (Filed November 16, 2000) Tariffs. ) - --------------------------------------------) ) Emergency Application of Pacific Gas and Electric Company to ) Application 00-11-056 Adopt a Rate Stabilization Plan.(U 39 E) ) (Filed November 22, 2000) - --------------------------------------------) ) Petition of THE UTILITY REFORM NETWORK for Modification of ) Application 00-10-028 Resolution E-3527. ) (Filed October 17, 2000) - --------------------------------------------) SOUTHERN CALIFORNIA EDISON COMPANY'S (U 338-E) COMMENTS ON PROPOSED CPA CALCULATION STEPHEN E. PICKETT ANN P. COHN FRANK J. COOLEY JAMES P. SCOTT SHOTWELL Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY 2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-3115 Facsimile: (626) 302-7740 E-mail: Frank.Cooley@sce.com Dated: March 29, 2001 TABLE OF CONTENTS Section Title Page - ------- ----- ---- I. INTRODUCTION............................................................. 1 II. Discussion............................................................... 4 A. The Proposed CPA Is Fixed For An Indefinite Period With No Mechanism For Adjustments Based On Actual Costs................................4 B. The Proposed CPA Ignores DWR's Failure To Assume Financial Responsibility For The Entire Net-short position Of The Utility's Customers........................................................... 6 C. The CPA Is Inflated Because The Assumed Cost Of QF Payments Is Too Low................................................................. 6 D. Authorized Generation-Related Costs Are Improperly Excluded......... 9 E. The Potential Exclusion From The CPA Of SONGS 2&3 ICIP Revenues Requested In Ordering Paragraph No. 10 Overturns Existing Commission Decisions And Is Contrary To State Law ............................ 13 F. The Ratemaking Treatment Of Previously-Authorized Costs Should Be Clarified.......................................................... 15 G. The Methodology for Calculating The CPA Is Flawed And Is Based On Unreasonable Assumptions........................................... 16 1. Calculation Of The CPA Based On The CPUC's Methodology........ 16 2. Calculation Of The CPA Based On Realistic And Appropriate Assumptions And Methodology....................................16 H. The Fixed DWR Set Aside Should Not Be Applied To Energy Supplied By DWR................................................................ 17 III. CONCLUSION.............................................................. 18 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Application of Southern California Edison ) Company (U 338-E) for Authority to ) Institute a Rate Stabilization Plan with a ) Application 00-11-038 Rate Increase and End of Rate Freeze ) (Filed November 16, 2000) Tariffs. ) - --------------------------------------------) ) Emergency Application of Pacific Gas and Electric Company to ) Application 00-11-056 Adopt a Rate Stabilization Plan. (U 39 E) ) (Filed November 22, 2000) - --------------------------------------------) ) Petition of THE UTILITY REFORM NETWORK for Modification of ) Application 00-10-028 Resolution E-3527. ) (Filed October 17, 2000) - --------------------------------------------) SOUTHERN CALIFORNIA EDISON COMPANY'S (U 338-E) COMMENTS ON PROPOSED CPA CALCULATION I. INTRODUCTION The Southern California Edison Company (SCE) comments on Decision No. 01-03-081 regarding the proposed calculation of the California Procurement Adjustment (CPA).1/ SCE appreciates the importance of determining the revenue stream available to compensate the California Department of Water Resources (DWR) for its purchases on behalf of our customers pursuant to Senate Bill 7X and Assembly Bill 1X. Nevertheless, it is singularly important that the California Public Utilities Commission (CPUC or Commission) make this determination correctly. The Commission should acknowledge the critical interdependence between the allocation of revenues to DWR and full-cost recovery of SCE's Commission-authorized costs. - ----------------------- 1/ D.01-03-081, Ordering Paragraph 10, mimeo, p.37. Page 1 The calculation of the CPA cannot be considered in isolation. The CPA is one aspect of the three decisions issued March 27, 2001. In the limited time available to consider the impact of the decisions, SCE estimates that revenues going forward will not be sufficient to cover retained generation and power purchase costs.2/ In fact, Figure 1 on the next page shows that the net effect of the rate increases, the QF decision and the payments ordered to be made to DWR result in a shortfall in the CPA calculation of $1.2 billion for SCE. Accordingly, it is even more critical that the calculation of the CPA properly reflects all the costs allocated to the utility. SCE continues to urge the Commission to establish three dedicated rate components with two-way balancing accounts and triggers as the best way to ensure that DWR receives adequate funding and the utilities' financial health does not deteriorate even further. The three dedicated rate components would be for SCE's retained generation, QF and bilateral contracts and payments to DWR. The proposed calculation of the CPA set forth in D.01-03-081, Sections C and D, does not properly reflect all relevant generation costs. If the Commission were to adopt such a calculation and later allocate a portion of the CPA to the Fixed DWR Set Aside, it would materially exacerbate the utility's revenue shortfall. In these comments SCE identifies several important corrections that must be made to the CPA calculation. - -------------------- 2/ SCE is commenting on the portions of D.01-03-081 as directed by the Commission. In so doing, SCE does not necessarily agree with, and reserves it right to challenge, these and other portions of D.01-03-081 and other decisions issued by the Commission on March 27, 2001. Page 2 [figure] Page 3 II. DISCUSSION A. The Proposed CPA Is Fixed For An Indefinite Period With No Mechanism For Adjustments Based On Actual Costs The proposed CPA is a fixed rate. More importantly, the CPA is a fixed rate based on a one-time calculation of costs. The Commission is effectively converting the revenue recovery for all generation to a rate, rather than an absolute cost. So, for example, assuming a fixed demand, if output from Utility Retained Generation (URG) decreases and delivery from DWR increases by a like amount, the State will receive an increment in its revenue and SCE will receive a decrease,3/ even though its costs may not have decreased at all. This effectively puts SCE's shareholders at risk for generation performance. Put another way, SCE's shareholders are at risk for replacement power cost, at least to the extent of its generation rate. In stark contrast, assuming no imprudence in the operation of URG, past Commission ratemaking decisions would provide recovery of increased replacement power costs through the Energy Cost Adjustment Clause (ECAC). There would be no decrease in generation revenue as a result of a decrease in output. It is indisputable that SCE's retained generation and purchased power will change significantly over time. The Commission's objective in setting a fixed rate is to achieve a stable source of revenue that will allow DWR to finance its revenue bonds. Unfortunately, the stable source of revenue the Commission and DWR desire is achieved at SCE's expense. By failing to allow for adjustments in costs and generation levels for retained generation and purchased power, the proposed method for calculating the CPA transfers this cost variability risk to the utilities. In our current financial condition, SCE cannot bear this risk. Moreover, it creates perverse incentives for the utilities to avoid expenditures on retained generation units that may be the least costly sources of supply. - -------------------- 3/ For purposes of this document, we assume that a portion of the CPA will be allocated to the Fixed DWR Set Aside. Page 4 The goals of achieving stable revenues for DWR and maintaining SCE's financial health are not mutually exclusive. SCE offered an alternative that would allow the CPUC to achieve both objectives. The Commission should establish three dedicated rate components with balancing accounts and triggers. The dedicated rate components would be for utility retained generation, QF and bilateral contracts, and DWR purchases. The advantages of this approach are compelling and were explained in SCE's response to the March 19, 2001 Assigned Commissioner's Ruling. Under SCE's proposed dedicated rate components, DWR would have an assured revenue stream that will allow it to finance revenue bonds. The Commission could provide an assurance that the CPA rate would remain available to repay the revenue bonds over their life. Revenue to pay DWR would be generated by the DWR's dedicated rate component. This approach would contribute positively to SCE's financial health by removing the necessity to finance large amounts of undercollections if they accumulate due to volatile costs. Triggers set at appropriately low levels given SCE's weakened financial condition would assure lenders that a mechanism is in place to recover power purchase costs and adequately fund CPA payments to DWR. The approach envisioned by the proposed CPA is not practical. The fixed CPA rate does not reflect likely variations in the cost of purchased power. There is no procedure for updating purchased power cost factors. The upshot of the proposed CPA is to place the financing burden associated with these variations on the financially weakened utility. SCE simply does not have the ability to finance any sizable undercollections. Because the proposed CPA approach would deleteriously impact the utility's financial condition, DWR's ability to finance power purchases would be affected. Page 5 B. The Proposed CPA Ignores DWR's Failure To Assume Financial Responsibility For The Entire Net-short position Of The Utility's Customers It is unclear what portion of our customers' net-short position DWR is going to be financially responsible for. The proposed CPA calculation implicitly assumes that DWR is financially responsible for covering all of our customers' net-short position. While SCE understands and expects that DWR has this responsibility, DWR has not formally acknowledged this responsibility, as reflected in D.01-03-082.4/ DWR has stated that it will only pay the portion of our customer's net short costs that DWR considers to be reasonable. DWR's reasonableness standard is not defined. Whatever portion of our customer's net-short position that is not being covered by DWR must be included in the calculation of the CPA. SCE does not have the ability to finance an undercollection of procurement costs. If, despite the intent and requirements of AB1X-1, the financial burden for the uncovered net short is placed on SCE, the calculation of the CPA must reflect this fact. The proposed CPA calculation does not. C. The CPA Is Inflated Because The Assumed Cost Of QF Payments Is Too Low The proposed CPA is based on an assumed QF price of $80 per MWH. This price is unrealistic and inconsistent with the CPUC's own decision modifying the QF energy payment formula. Reasonable estimates of QF payments based on the Commission's modifications to the QF energy payment formula would yield substantially higher payments to QFs and a consequently lower estimate of the amount available to fund the CPA. - ---------------------- 4/ D. 01-03-082, p. 14. D.01-03-082 also affirms that the CPUC cannot require DWR to purchase the entire net short on behalf of SCE's customers. Id. Page 6 When SCE provided its scenarios based on the $80 per MWH price, there were ongoing negotiations with QFs that everyone hoped would lead to a settlement near that price. Those negotiations failed and D.01-03-067 (the QF Decision) recognizes this fact. In fact, it is only because the negotiations failed that the Commission was forced to address the issue of QF energy payments. Unfortunately for California ratepayers, the energy payment formula authorized by the Commission will result in higher payments to QFs than $80 per MWH that was assumed for illustrative purposes. Table 1 provides SCE's estimate of QF prices based on the formula adopted by the Commission and gas prices as forecast by Data Resources Inc. (DRI): Table 1 QF Price Forecast ($/MWH) --------------------------- ------------------- ----------------- Month CPUC SCE Assumed Forecast --------------------------- ------------------- ----------------- May, 2001 80 121.30 June, 2001 80 111.10 July, 2001 80 172.90 August, 2001 80 187.20 September, 2001 80 193.40 October, 2001 80 187.20 November, 2001 80 94.60 December, 2001 80 98.50 Page 7 This forecast includes a forecast of QF energy, capacity and contract buyout payments. For energy payments, QFs are divided into three types of contracted energy payments terms: (1) posted avoided cost of energy; (2) fixed energy prices; and (3) heat rate floors ("IER Amendments"). In general, energy prices other than the fixed priced contracts are determined by a base energy price, a border gas price, and a gas price factor. Line loss factors, based on the generator meter multipliers (GMM), distribution loss factors (DLF), and system GMM, are also applied to energy prices where appropriate. QFs paid the posted avoided cost of energy are subject to the conditions in established in D.01-03-067. For these contracts the Malin border gas price including a gas intrastate transportation rate to the Southern California Gas Company interconnection point is used to determine the posted avoided cost of energy. In addition, the gas price factor is adjusted monthly according the decision. The energy payments to QF subject to "IER Amendments" are forecast using base energy prices, border gas price, and a gas price factor. The energy payments to the fixed-priced contracts are forecast subject to specific contract terms. The border gas price forecasts are taken from DRI's gas price forecast for March 2001. For all contracts, energy is forecast based on historical behavior. The forecast of capacity payments is based on contract terms and historical payments and the forecast of contract buyout payments is based on Commission-approved buyout payment schedules. The Commission should recognize in its calculation of the CPA the fact that its QF decision, issued the same day as D.01-03-081, earlier Commission decisions and specific QF contract terms increase the price of QF power above the assumed $80 per MWH price. This would increase the costs to be deducted from generation-related revenues used in the calculation of the CPA by approximately $1.6 billion in 2001. Page 8 D. Authorized Generation-Related Costs Are Improperly Excluded The proposed CPA improperly excludes legitimate generation-related costs. This unfairly inflates the amount of the CPA. All authorized generation-related costs should be included in the calculation of the CPA to properly implement the Legislature's intent. Excluding certain authorized generation-related costs from the calculation of the CPA overstates the amount of the CPA. For example, D.01-03-081 claims that franchise fees and uncollectibles should be excluded from the calculation. With respect to franchise fees, the decision asserts that these costs "attach to all retail revenues." This makes no sense. "All revenues" includes SCE's generation-related revenues. What SCE proposed to deduct from generation-related revenues was the pro rata share of our total franchise fees that relates to the generation-related revenues. The Commission in D. 97-08-056 explicitly ordered SCE and other utilities to exclude from their distribution revenue requirement the portion of its revenue requirement associated with generation revenues. The proposed calculation of the CPA is at odds with the Commission's earlier treatment of these costs. Alternatively, DWR must assume financial responsibility for paying the franchise fees associated with their "revenues." The proposed calculation of CPA also excludes restructuring implementation costs, employee-related transition costs, losses on sales and QF shareholder incentives. The decision claims that because these costs are not enumerated in Code Section 360.5, they must be excluded. This assertion is disingenuous. The Commission is intimately familiar with what is included in SCE's rates. Generation related rates have heretofore included these costs. The Legislature could reasonably be excused from knowing precisely what is in SCE's generation rates. The Commission is not so easily excused. In D.99-09-064 the Commission ordered recovery of these costs Page 9 through the operation of the TRA. The effect of this treatment is to require them to be recovered through the residually determined generation rate component. Consistent and fair treatment would remove these costs from the generation related rate in the calculation of the CPA. With respect to direct access implementation costs, the decision claims that these costs must be excluded from the calculation of the CPA. This is contrary to the Commission's decisions implementing restructuring. The Commission authorized recovery of direct access implementation costs from the TRA. Since the generation rate is by Commission decisions residually determined under the rate freeze, in so doing the Commission reduced the generation rate by a corresponding amount to maintain the rate freeze. This reduction can not be ignored now in calculating the CPA. Direct access implementation costs were in SCE's "rates" on January 5, 2001 and must therefore be taken out of the generation-related rate to properly calculate the CPA. If instead of recovering the direct access implementation costs through the TRA an unbundled rate component for their recovery were established, then the residually determined generation rate would have been smaller and these costs would not have been reflected in the January 5 generation rate. Conversely, by inputing the Rate Reduction Bond (RRB) revenues , the Commission effectively increased the generation rate. The proposed CPA should include these inputed amounts as well even though they were not listed in Code Section 360.5. The RRBs are not included because they are generation costs but because the Commission effectively authorized the reduction of the generation rates to allow recovery of these items. The proposed CPA excludes customer service and information expenses, and administrative and general costs because they "are not generation related costs and do not fall within the scope of the four items in Code Page 10 Section 360.5."5/ These costs are in the same category as direct access implementation costs and the inputed RRB amounts. For example, A&G costs associated with SCE's generating facilities include: pensions and benefits for employees at the generating plants, payroll taxes for the employees at the generating plants, insurance for property damage and personal injury, and worker's compensation. These costs are reasonable costs of operating SCE's generating facilities. No business can operate without paying payroll taxes and pensions and benefits for its employees. In addition, it would be imprudent for SCE to operate its generating facilities without insurance for property damage and personal injury. D.96-04-059, adopting the present SONGS 2&3 ratemaking mechanism, and D.96-12-083, adopting the present Palo Verde ratemaking mechanism, provide for recovery of A&G costs associated with these nuclear generating facilities. D.97-12-131 established the Hydroelectric Generating Facilities revenue requirement. Advice Letter 1285-E-B, approved by the Commission by letter, dated June 25, 1999, implemented D.97-12-131. Advice Letter 1285-E-B expressly includes A&G as part of the revenue requirement of SCE's hydroelectric generating facilities. D.99-09-064 established "going-forward" costs of SCE's coal-fired generating facilities to be recovered through market revenues. Advice Letter 1409-E-A, approved by the Commission by letter, dated February 10, 2000, expressly includes A&G expenses as part of the legitimate operating costs of SCE's coal-fired generating facilities eligible for recovery through market revenues. The Commission should not exclude such legitimate generation costs in the calculation of the CPA because to do so would be inconsistent with past Commission decisions and standard utility ratemaking practices. Moreover, they do fall within any reasonable definition of the costs of "the utility's own generation" which Public Utilities Code Section 360.5 expressly allows to be subtracted from SCE's generation-related revenue requirement in any calculation of the CPA. - ----------------------- 5/ D.01-03-081, p.19. Page 11 In D.97-08-056 the Commission examined SCE's total C&I and A&G costs and allocated a portion of them to the generation function. It is contrary to that decision and common sense to now exclude consideration of these costs in the generation related rate. The Commission prohibited SCE from recovery of the generation related CS&I and A&G costs through distribution rates and is now attempting to exclude them from recovery through the generation rates by inflating the CPA. This is obviously unfair and should be corrected. Finally the proposed calculation of the CPA ignores the reliability must run (RMR) costs that SCE must pay to the ISO. SCE agrees that RMR costs are not generation related, but in D.98-04-019 the Commission allowed for recovery of RMR costs through the TRA during the rate freeze. This treatment was in lieu of SCE filing with the FERC to establish a separate rate component for RMR recovery. Had SCE done so, the residually determined generation rate would have been smaller. The Commission in D.99-10-057 stated that in the post-transition period SCE must request recovery of these costs through a FERC-approved rate component. SCE filed an application with the FERC (Docket No. ER01-315-000, filed November 1, 2000) for adoption of an RMR rate component. For this reason, the Commission should subtract the RMR costs from its generation rate before calculating the CPA. This would result in the same outcome as SCE continuing to recover RMR costs through the residual generation revenues recorded in the TRA. Page 12 E. The Potential Exclusion From The CPA Of SONGS 2&3 ICIP Revenues Requested In Ordering Paragraph No. 10 Overturns Existing Commission Decisions And Is Contrary To State Law Several changes contained in Ordering Paragraph No. 10 were not in the Alternate Decision issued March 26, 2001 that was ultimately adopted as D.01-03-081. These changes were not available for timely review as noted by several Commissioners from the dais on March 27, 2001. The changes to the CPA calculation directed in Ordering Paragraph No. 10 are not lawful. They would overturn existing Commission decisions regarding SONGS 2&3 Incremental Cost Incentive Pricing (ICIP) and are contrary to state law. SCE would have identified this serious legal error in its March 26, 2001 oral argument if it had been on notice of this proposed change at that time. These changes represent significant material revisions, not mere typographical corrections. The Commission should not countenance such "star chamber" ratemaking. Ordering Paragraph No. 10 states: Comments on sections VI.C and D and section VIII of this decision and the corresponding proposed findings of fact and proposed conclusions of law shall be filed and served no later than 5:00 p.m. on Thursday, March 29, 2001. Each utility shall include in its comments a revised version of that portion of the Spreadsheet included as Attachment E to this Decision that relates to that utility. This revised spreadsheet shall exclude in its calculation of Utility Related Costs those nuclear incentive amounts (e.g., Diablo Canyon ICIP payments) in excess of actual costs, and be accompanied by appropriate supporting work papers. Any party asserting that the figures contained in Attachment E contain miscalculations should submit a revised version of Attachment E correcting the alleged errors, which should be accompanied by appropriate work papers. Page 13 The implication of the paragraph is that the Commission intends to exclude some portion of SONGS 2&3 ICIP revenues from the CPA calculation. It directs the utilities to remove "actual generation costs" from their calculation of Utility Related Costs in the CPA calculation. The Commission adopted SONGS 2&3 ICIP prices as the operating cost of SONGS 2&3 and the Legislature affirmed these prices as the SONGS 2&3 actual costs in Public Utilities Code Section 367(a)(4). SONGS 2&3 ICIP is, by its very nature as acknowledged in its title, a cost-based rate. The ICIP assigns all operational and financial risk to SCE, while offering a strictly limited opportunity for profit6/ based upon excellent performance at the plants. SCE cannot assure continuation of recent (1996-2000) excellent performance, as the current SONGS 3 outage demonstrates. The risk currently borne by SCE is evidenced by the $800,000 per day of lost revenue to the company due to the present SONGS 3 outage. As SCE stated on page 7 of its Motion to Strike Comments filed by TURN on California Procurement Adjustment, dated March 9, 2001, in the Rate Stabilization Plan (RSP) docket: In the SONG 2&3 ICIP mechanism, shareholders take on the operational risk of plant performance. Under this ratemaking approach the opportunity for profits must be commensurate with the risk of losses. SONGS 2&3 ICIP opportunity for profits is commensurate with the higher risk of losses assumed by shareholders. Furthermore, SCE's opportunity for profit is limited by the design and operation limits of the plants. - ------------------------ Page 14 6/ SCE's realized "profit" under SONGS ICIP has been around 9% to date (RSP, Phase 1, Tr. Worder, 15/1982.) 7/ RSP, Phase 1, SCE, Worden, Tr. 15/20/2015, lines 22-26. (Ratepayers would be protected if the plants performed better than the historic capacity factors because the ratepayer exposure and shareholder oppotunity is capped by the physical limitations of the plant.") The Commission adopted present SONGS 2&3 ICIP pricing in D.96-01-011 and D.96-04-059. The Legislature affirmed the SONGS 2&3 ICIP pricing in Assembly Bill 1890, at Public Utilities Code Section 367(a)(4), which states: Nuclear Incremental Cost Incentive plans for the San Onofre Nuclear Generating Station shall continue for the full term as authorized by the Commission in Decision 96-01-011 and Decision 96-04-059; provided that the recovery shall not extend beyond December 31, 2003. The Commission would unlawfully ignore its own orders and state law if it changes SCE's ratemaking for SONGS 2&3. F. The Ratemaking Treatment Of Previously-Authorized Costs Should Be Clarified As discussed in the previous sections, many of the costs that are excluded from the proposed CPA calculation are authorized generation-related costs. If these costs are not allowed recovery through the generation-related component of SCE's rates, it is not clear where SCE would get recovery of them. These costs are reasonable and authorized costs. The Commission has previously allowed recovery of them through the residually determined generation rates. There is nothing in the record that would in any way justify disallowance of these costs. Yet, there is no readily apparent mechanism for their recovery. The Commission should immediately clarify where and how these costs will be recovered to avoid any further negative harm to SCE's financial condition. Page 15 G. The Methodology for Calculating The CPA Is Flawed And Is Based On Unreasonable Assumptions 1. Calculation Of The CPA Based On The CPUC's Methodology If the Commission makes no modifications to its CPA methodology, it should nevertheless adopt reasonable estimates, including a reasonable estimate of QF costs. SCE estimates, based on the methodology adopted in D. 01-03-08_, that its QF payments will be $1.629 billion higher than the estimate included in Attachment E to D. 01-03-081. SCE's Attachment A contains a table that shows the CPA including this correction, as well as a minor correction to gross generation revenues to correct the amount shown in Column D of Table E. In addition, pursuant to Ordering Paragraph No. 10 of D.01-03-081, an adjustment has been made to reflect the difference between the SONGS ICIP revenue requirement and estimated costs. With these changes, the CPA would be zero cents per kWh. 2. Calculation Of The CPA Based On Realistic And Appropriate Assumptions And Methodology The proposed calculation of the CPA rejects numerous adjustments that should be made to accurately calculate the CPA. If these adjustments are made, the CPA would be higher than the corrected CPA factor discussed above. The proposed adjustments are reasonable and consistent with prior CPUC or FERC decisions which allocated these costs to the generation related component of SCE's rates. Attachment A describes each of the adjustments that should be made to reflect an accurate calculation of the CPA. The adjustment and the authority for making the adjustment are shown in the table. If these adjustments are made, the CPA would continue to be zero cents per kWh. It should be noted that the largest adjustments (for the imputed 10% bill credit and the imputed trust transfer amount) will no longer exist in 2002. These adjustments increase the amount of the CPA in 2001. Their absence in 2002 will decrease the calculated CPA in 2002. For this reason, if the Commission chooses to make SCE's proposed adjustments, the CPA calculation will need to be updated for at least the elimination of the 10% bill credit and the imputed Trust Transfer Amount revenue in 2002. Page 16 H. The Fixed DWR Set Aside Should Not Be Applied To Energy Supplied By DWR In its calculation of the CPA, the Commission used a denominator equating to SCE's total bundled sales. One effect of this approach is to allocate the utility's costs against the generation revenues which are already required to be forwarded to DWR. This is a double calculation and would effectively send the revenue requirement to DWR twice. Either the CPA calculation should be modified to replace the denominator with only kwhs provided by SCE, or, in the aternative, the DWR Set Aside should only be applied to kwhs supplied by the DWR. Page 17 III. CONCLUSION For the reasons discussed above, SCE urges the Commission to modify the calculation of the CPA consistent with SCE's recommendations in Attachment A. Respectfully submitted, STEPHEN E. PICKETT ANN P. COHN FRANK J. COOLEY JAMES P. SCOTT SHOTWELL Frank J. Cooley ------------------------------------- By: Frank J. Cooley Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY 2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-3115 Facsimile: (626) 302-7740 E-mail: Frank.Cooley@sce.com March 29, 2001
Page 18 APPENDIX A A B C D E - ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ---------------- Gross Gen-Related Rev Gen-Related Revs Based on Line Total Sales Reported in Bundled Reported in Bundled Service Nos. Description Generation-Related Utilities' ABX1 Data (GWh) Service Utilities ABX1 Sales ($000s) Rate (c/kWh) Sales ((GWh) Data ($000s) - ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ---------------- A=D/B/10 E=A*C*10 1 As Attached to 7.277 84,400 76,466 6,141,557 5,564,251 D01.03-081 (For SCE) Adjustments Pursuant to Ordering Paragraph 10 of D.01-03-081 2 Corrects Amount shown 8,116 in column D 3 Updated QF payment amounts based on D.01-03-081 4 Adjustment to SONGS Generation (GWh) due to outage after fire 5 To reflect forecast of SONGS O&M (Non-ICIP) - ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ---------------- 6 Adjusted Commission CPA 7.286 84,400 76,466 6,149,673 5,571,604 Calculation - ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ----------------
Additional Authorized Adjustments: Authority for Inclusion 7. Reverse Line 5 above PU Code Section PU Code Section 367 (a)(4) which results in 367 (a)(4) states that "Nuclear authorized SONGS ICIP D.96-02-011 and Incremental Cost Incentive revenue requirement D.96-04-059 plans for SONGS shall continue for the full term as authorized by the Commission in D.96-01-011 and D.96-04-059." 8 Franchise Fees and D.97-08-056, p.59 The Commission ordered (62,498) Uncollectibles that the utilities distribution revenue requirement should be reduced to recognize a fair allocation of FF&U costs between distribution, transmission and generation. 9 Reliability Services FERC Docket No. Reliability Service costs (39,551) ER01-315-000 are FERC authorized that are currently being recovered through generation rates. 10 Restructuring D.99-09-064 The Commission ordered the(33,606) Implementation recovery of Industry Restructuring costs through the operation of the TRA. Thus these costs are actually recovered through the residually determined generation rate component. 11 Demand Responsiveness D.01-03-xxx The Commission ordered SCE(38,440) and Self Generation to increase its distribution Amount revenue requirement without modifying current overall rates. The adjustment is needed to account for the resultant reduction to generation-related revenues during the rate freeze period. 1/ 12 Imputed 10% Bill Credit D.97-09-056 The frozen generation rate 361,582 has been reduced by the amount of the 10% bill credit. This adjustment is necessary in order to remove the impact of the RRB transaction from the generation rate consistent with the ratemaking adopted by the Commission. 13 Imputed Trust Transfer The frozen generation rate 294,891 Amount has been reduced by the amount of the TTA. This adjustment is necessary in order to remove the impact of the RRB transaction from the generation rate consistent with the ratemaking adopted by the Commission. 14 Add-back CS&I and A&G RE: CS&I Costs The Commission ordered related to SCE Retained D.97-08-056, p.5 that the utilities Generation distribution revenue requirement should be reduced to recognize a fair allocation of customer service and marketing costs between distribution, transmission and generation. Res. E-3536 The Commission adopted a generation allocation of customer service and marketing costs for hydro. A&G Costs The Commission ordered D.97-08-056, p.59 that the utilities distribution rev req should be reduced to recognize a fair allocation of A&G costs between distribution, transmission and generation. D.97-11-074, p. Commission defined 26-27 going-forward costs as all costs necessary to continue to operate the plant. Going forward costs may include both fixed and variable costs. This interpretation most closely matches the standards articulated in the statue and our own preference for market recovery of such costs. "Therefore, going forward costs will be defined as all costs that are necessary for the continued or future operation of the plant..., and include, but are not limited to, all costs associated with fuel transportation and fuel supply, administrative and general, and operation and maintenance, with the statutory exceptions established in Section 367 (c)(1) and (c)(2). D.00-02-048 and Approved costs recorded in D.00-10-047 GMA's including A&G and CS&I
A=E/C/10 Sum lines X-Y 15 CPA as Proposed by SCE 7.917 76,466 6,053,982 - ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ----------------
Note: 1/ Similar adjustments will be necessary during the rate freeze period to reflect the impact on generation-related revenues that result from changes in non-generation revenues.
- ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ---------------- F G H I Utility Utility Related Costs CPA Line Description Related less CSI and Revenues CPA Rate Nos. Costs A&G ($000s) ($000s) (c/kWh) ($000s) - ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ---------------- H=E-G I=H/C 1 As Attached to 4,798,902 4,762,381 801,870 1.049 D01.03-081 (For SCE) Adjustments Pursuant to Ordering Paragraph 10 of D.01-03-081 2 Corrects Amount shown in column D 3 Updated QF 1,629,446 1,629,446 payment amounts based on D.01-03-081 4 Adjustment to (131,671) (131,671) SONGS Generation (GWh) due to outage after fire 5 To reflect (55,400) (55,400) forecast of SONGS O&M (Non-ICIP) - ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ---------------- 6 Adjusted 6,241,277 6,204,756 (633,152) (0.828) Commission CPA Calculation - ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ----------------
Additional Authorized Adjustments Authority for Inclusion 7. Reverse Line 5 PU Code Section PU Code Section 367 55,400 55,400 above which 367 (a)(4) (a)(4) states that results in D.96-02-011 and "Nuclear Incremental Cost authorized SONGS D.96-04-059 Incentive plans for SONGS ICIP revenue shall continue for the requirement full term as authorized by the Commission in D.96-01-011 and D.96-04-059." 8 Franchise Fees D.97-08-056, p.59 The Commission ordered and that the utilities Uncollectibles distribution revenue requirement should be reduced to recognize a fair allocation of FF&U costs between distribution, transmission and generation. 9 Reliability FERC Docket No. Reliability Service costs Services ER01-315-000 are FERC authorized that are currently being recovered through generation rates. 10 Restructuring D.99-09-064 The Commission ordered Implementation the recovery of Industry Restructuring costs through the operation of the TRA. Thus these costs are actually recovered through the residually determined generation rate component. 11 Demand D.01-03-xxx The Commission ordered Responsiveness SCE to increase its and Self distribution revenue Generation Amount requirement without modifying current overall rates. The adjustment is needed to account for the resultant reduction to generation-related revenues during the rate freeze period. 1/ 12 Imputed 10% Bill D.97-09-056 The frozen generation Credit rate has been reduced by the amount of the 10% bill credit. This adjustment is necessary in order to remove the impact of the RRB transaction from the generation rate consistent with the ratemaking adopted by the Commission. 13 Imputed Trust The frozen generation Transfer Amount rate has been reduced by the amount of the TTA.. This adjustment is necessary in order to remove the impact of the RRB transaction from the generation rate consistent with the ratemaking adopted by the Commission. 14 Add-back CS&I and RE: CS&I Costs The Commission ordered 36,521 A&G related to D.97-08-056, p.59 that the utilities SCE Retained distribution revenue Generation requirement should be reduced to recognize a fair allocation of customer service and marketing costs between distribution, transmission and generation. Res. E-3536 The Commission adopted a generation allocation of customer service and marketing costs for hydro. A&G Costs The Commission ordered D.97-08-056, p. that the utilities 59 distribution rev req should be reduced to recognize a fair allocation of A&G costs between distribution, transmission and generation. D.97-11-074, p. Commission defined 26-27 going-forward costs as all costs necessary to continue to operate the plant. Going forward costs may include both fixed and variable costs. This interpretation most closely matches the standards articulated in the statue and our own preference for market recovery of such costs. "Therefore, going orward costs will be defined as all costs that are necessary for the continued or future operation of the plant..., and include, but are not limited to, all costs associated with fuel transportation and fuel supply, administrative and general, and operation and maintenance, with the statutory exceptions established in Section 367 (c)(1) and (c)(2). D.97-11-074, Commission ordered pg.26-27 tracking of the above-mentioned going forward costs in GMAs. D.00-02-048 and Approved costs recorded D.00-10-047 in GMA's including A&G and CS&I.
H=E-G I=H/C - ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ---------------- 15 CPA as Proposed 6,292,677 6,296,677 (242,695) (0.317) by SCE - ----- ---------------------------- ------------------- -------------------- ------------------- ------------------- ----------------
Note: 1/ Similar adjustments will be necessary during the rate freeze period to reflect the impact on generation-related revenues that result from changes in non-generation revenues. April 2, 2001 VIA FACSIMILE & U.S. MAIL Docket Office California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 Re: A.00-11-038 - - Correction to Figure re. CPA Docket Office: On March 29, 2001 Southern California Edison (SCE) commented in response to Decision No. 01-03-081. Included in our comments was a "waterfall chart" showing the financial impact of two decisions issued by the Commission - - - D.01-03-081 and D.01-03-082. Subsequent to issuing our comments, we discovered language was added to Ordering Paragraph No. 1 which increased payments to the California Department of Water Resources after March 27, 2001 from 7.277 cents per kilowatt-hour to 10.277 cents per kilowatt-hour. We were unaware that this requirement was added to D.01-03-082. Attached is an updated chart showing the finiancial impact of the Commission's decisions based on the mailed version of D.01-03-082. The financial impact of the mailed version of D.01-03-082 is to increase the amount by which total expenses exceed SCE's total revenues in 2001 by $700 million. If you have any questions regarding this matter, please call me at (626) 302-3115. Very truly yours, Frank J. Cooley ---------------------------- Frank J. Cooley cc: All Parties of Record President Loretta Lynch and Commissioners Gary Cohen, General Counsel Enclosure [rspcorrection] -----END PRIVACY-ENHANCED MESSAGE-----