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California Consumer Protection Foundation, California Democratic Party, California Public Utilities Commission, California Supreme Court, CaliforniaALL, CPUC, Geoffrey Brown, Gilles Attia, Golden Gate University, John F. Kennedy University College of Law, Michael Peevey, Michael Shames, Ophelia Basgal, Peter Arth, Peter Keane, PG & E, Sempra Energy, Timothy Simon, Uncategorized

SEMPRA ENERGY – Annual Report

SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2003 OR [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to
 
SEMPRA ENERGY


——————————————————————- –> (Exact name of registrant as specified in its charter)

CALIFORNIA                    1-14201               33-0732627 ------------------------------------------------------------------- (State of incorporation        (Commission         (I.R.S. Employer or organization)               File Number)     Identification No.)  101 ASH STREET, SAN DIEGO, CALIFORNIA                        92101 ------------------------------------------------------------------- (Address of principal executive offices)                 (Zip Code)  Registrant's telephone number, including area code    (619)696-2000 -------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:  Name of each exchange Title of each class                             on which registered -------------------                           --------------------- Common stock, without par value               New York and Pacific

Mandatorily redeemable trust preferred securities New York Equity units, due 2007 New York

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [ X ] No [ ]

Exhibit Index on page 44. Glossary on page 52.

Aggregate market value of the voting stock held by non-affiliates of the registrant as of January 31, 2004 was $7.1 billion.

Registrant’s common stock outstanding as of January 31, 2004 was 227,231,411 shares.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the 2003 Annual Financial Report to Shareholders are incorporated by reference into Parts I, II, and IV.

Portions of the Proxy Statement prepared for the May 2004 annual meeting of shareholders are incorporated by reference into Part III.


TABLE OF CONTENTS  PART I Item 1.  Business . . . . . . . . . . . . . . . . . . . . . . .  4 Item 2.  Properties . . . . . . . . . . . . . . . . . . . . . . 30 Item 3.  Legal Proceedings. . . . . . . . . . . . . . . . . . . 31 Item 4.  Submission of Matters to a Vote of Security Holders. . 32  PART II Item 5.  Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . 32 Item 6.  Selected Financial Data. . . . . . . . . . . . . . . . 32 Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . 33 Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . 33 Item 8.  Financial Statements and Supplementary Data. . . . . . 33 Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . 33 Item 9A. Controls and Procedures. . . . . . . . . . . . . . . . 33  PART III Item 10. Directors and Executive Officers of the Registrant . . 34 Item 11. Executive Compensation . . . . . . . . . . . . . . . . 35 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. . . . . 35 Item 13. Certain Relationships and Related Transactions . . . . 35 Item 14. Principal Accountant Fees and Services . . . . . . . . 35  PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . 36  Independent Auditors' Consent and Report on Schedule. . . . . . 38  Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 43  Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 44  Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 52


INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report contains statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words “estimates,” “believes,” “expects,” “anticipates,” “plans,” “intends,” “may,” “could,” “would” and “should” or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward- looking statements.

Forward-looking statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, including, among others, local, regional, national and international economic, competitive, political, legislative and regulatory conditions and developments; actions by the California Public Utilities Commission (CPUC), the California Legislature, the California Department of Water Resources (DWR), environmental and other regulatory bodies in countries other than the United States, and the Federal Energy Regulatory Commission (FERC); capital market conditions, inflation rates, interest rates and exchange rates; energy and trading markets, including the timing and extent of changes in commodity prices; weather conditions and conservation efforts; war and terrorist attacks; business, regulatory and legal decisions; the status of deregulation of retail natural gas and electricity delivery; the timing and success of business development efforts; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the company. Readers are cautioned not to rely unduly on any forward-looking statements and are urged to review and consider carefully the risks, uncertainties and other factors which affect the company’s business described in this report and other reports filed by the company from time to time with the Securities and Exchange Commission.


 
PART I  
ITEM 1. BUSINESS

Description of Business

A description of Sempra Energy and its subsidiaries (the company) is given in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2003 Annual Report to Shareholders, which is incorporated by reference. The company has four separately managed reportable segments comprised of Southern California Gas Company (SoCalGas), San Diego Gas & Electric (SDG&E), Sempra Energy Trading (SET) and Sempra Energy Resources (SER). SoCalGas and SDG&E are collectively referred to as “the California Utilities.”

Company Website

The company’s website address is http://www.sempra.com/investor.htm. The company makes available free of charge through its website its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. The charters of the company’s board of directors’ (the board) audit, compensation and corporate governance committees, the board’s corporate governance guidelines and the code of business conduct and ethics for directors and officers are posted on the company’s website. Printed copies may be obtained by writing to the company’s Corporate Secretary at Sempra Energy, 101 Ash Street, San Diego, CA 92101-3017.

RISK FACTORS

The following risk factors and all other information contained in this report should be considered carefully when evaluating Sempra Energy and its subsidiaries. These risk factors could affect the actual results of Sempra Energy and its subsidiaries and cause such results to differ materially from those expressed in any forward-looking statements of, or made by or on behalf of, Sempra Energy or its subsidiaries. Other risks and uncertainties, in addition to those that are described below, may also impair their business operations. If any of the following risks occurs, Sempra Energy’s business, cash flows, results of operations and financial condition could be seriously harmed. In addition, the trading price of its securities could decline due to the occurrence of any of these risks. These risk factors should be read in conjunction with the other detailed information concerning Sempra Energy and its subsidiaries set forth in the notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” incorporated by reference in this report.

Risks Related to the California Utilities

The California Utilities are subject to extensive regulation by state, federal and local legislation and regulatory authorities, which may adversely affect the operations, performance and growth of their businesses.

The CPUC, which consists of five commissioners appointed by the Governor of California for staggered six-year terms, regulates the California


Utilities’ rates and conditions of service, sales of securities, rates of return, rates of depreciation, uniform systems of accounts, examination of records and long-term resource procurement. The CPUC conducts various reviews of utility performance (including reasonableness and prudency reviews) and conducts audits and investigations into various matters which may, from time to time, result in disallowances and penalties adversely affecting earnings and cash flows. The CPUC also regulates the relationship of utilities with their affiliates and is currently conducting an investigation into this relationship. Various proceedings involving the CPUC and relating to the California Utilities’ rates, costs, incentive mechanisms, performance-based regulation and affiliate and holding company rule compliance are discussed in the notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” incorporated by reference in this report.

Periodically the California Utilities’ rates are approved by the CPUC based on forecasts of capital and operating costs. If the California Utilities’ actual capital and operating costs were to exceed the amount included in its base rates approved by the CPUC, it would adversely affect earnings and cash flows.

To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC adopted Performance-Based Regulation (PBR) for SDG&E effective in 1994 and for SoCalGas effective in 1997. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity goals, rather than relying solely on expanding utility plant to increase earnings. The three areas that are eligible for PBR rewards are: operational incentives based on measurements of safety, reliability and customer satisfaction; demand-side management (DSM) rewards based on the effectiveness of the programs; and natural gas procurement rewards. Although the California Utilities have received significant PBR rewards in the past, there can be no assurance that the California Utilities will receive rewards at similar levels in the future, or at all. Additionally, if the California Utilities fail to achieve certain minimum performance levels established under the PBR mechanisms, they may be assessed financial disallowances or penalties which could adversely affect their earnings and cash flows.

The FERC regulates the transmission and wholesale sales of electricity in interstate commerce, transmission access and other similar matters involving SDG&E.

The California Utilities may be impacted by new regulations, decisions, orders or interpretations of the CPUC, FERC or other regulatory bodies. New legislation, regulations, decisions, orders or interpretations could change how the California Utilities operate, could affect their ability to recover their various costs through rates or adjustment mechanisms, or could require the California Utilities to incur additional expenses.

SDG&E may incur substantial costs and liabilities as a result of its ownership of nuclear facilities.

SDG&E owns a 20% interest in the San Onofre Nuclear Generating Station (SONGS), a 2,150 megawatt nuclear generating facility near San Clemente,


California. The Nuclear Regulatory Commission has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. SDG&E’s ownership interest in SONGS subjects it to the risks of nuclear generation, which include:

— the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
— limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and — uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

The California Utilities’ future results of operations and financial condition may be materially adversely affected by the outcome of pending litigation against them.

Lawsuits filed in 2000 and currently consolidated in San Diego Superior Court seek class-action certification and damages, alleging Sempra Energy and the California Utilities, along with El Paso Energy Corp. and several of its affiliates, unlawfully sought to control natural gas markets. Similar lawsuits have been filed by the Attorneys General of Arizona and Nevada and by others. Although the California Utilities expect to prevail in these cases, they have expended or accrued substantial amounts to pay the costs of defending these claims. If the plaintiffs in these cases were to prevail in their claims, the future results of operations and financial condition of Sempra Energy and the California Utilities may be materially adversely affected. In addition, various other lawsuits are pending against SDG&E and other Sempra Energy subsidiaries alleging that the companies unlawfully manipulated the electric energy market.

In December 2002, the CPUC approved a settlement with SDG&E allocating between SDG&E’s customers and shareholders the profits from certain intermediate-term power purchase contracts that SDG&E had entered into during the early stages of California’s electric utility industry restructuring. As a result of the CPUC’s decision, SDG&E recognized additional after-tax income of $65 million in 2003. The Utility Consumers’ Action Network (UCAN) has appealed the decision and the California Court of Appeals granted the petition for review.

These proceedings are discussed in the notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” incorporated by reference in this report.


Risks Related to Sempra Energy’s Electric Generation, Energy Trading, Liquefied Natural Gas (LNG), Energy Solutions, International and Other Businesses

Sempra Energy’s businesses are exposed to market risk, and its financial condition, results of operations, cash flows and liquidity may be adversely affected by fluctuations in commodity market prices that are beyond its control.

Sempra Energy Trading (SET) is a full-service trading company that markets and trades physical and financial commodity products. Its trading portfolios consist of physical and financial commodity contracts including contracts for natural gas, electricity, petroleum products, base metals and other commodities that are settled by the delivery of the commodity or cash. Although SET generally seeks to structure its trading contracts so that a substantial majority of its trading revenues are realizable within 24 months and strives to maintain proper hedging mechanisms for its trading book, at times SET may have unhedged trading positions in the market, resulting from the management of its trading portfolios or from its inability to hedge, in whole or in part, particular risks.

Sempra Energy Resources (SER) generates and sells electricity on a long- term basis, or into the spot market or other competitive markets, and purchases natural gas for its power plants and sometimes purchases electricity in the open market to satisfy its contractual obligations.

Sempra Energy Solutions (SES) procures electricity and natural gas for its commercial and industrial customers. The market prices for these commodities may fluctuate substantially over relatively short periods of time.

Sempra Energy’s sales and results of operations could be adversely affected if the prevailing market prices for electricity, natural gas or other commodities that are procured for power plants or to satisfy contractual obligations (whether to trading counterparties or otherwise), or that are provided to customers in regional markets and other competitive markets in which the company competes, change in a direction or manner that it does not anticipate.

Unanticipated changes in market prices for energy-related and other commodities result from multiple factors, including: weather conditions; seasonality; changes in demand; transmission or transportation constraints or inefficiencies; availability of competitively priced alternative energy sources; commodity production levels; actions by OPEC (Organization of the Petroleum Exporting Countries) with respect to the supply of crude oil; federal, state and foreign energy and environmental regulation and legislation; natural disasters, wars, embargoes and other catastrophic events; and expropriation of assets by foreign countries.

In 2001 the FERC, which has jurisdiction over wholesale power and transmission rates and independent system operators and other entities that control transmission facilities or that administer wholesale power sales in some of the markets in which the company operates, imposed price limitations which resulted in unexpected moves in electricity prices. The FERC may impose additional price limitations, bidding rules


and other mechanisms or terminate existing price limitations from time to time in the future. Any such action by the FERC may result in prices for electricity changing in an unanticipated direction or manner, and may have an adverse effect on Sempra Energy’s sales and results of operations.

Sempra Energy and its subsidiaries cannot and do not attempt to fully hedge their assets or positions against changes in commodity prices, and their hedging procedures may not work as planned.

To lower financial exposure related to commodity price fluctuations, Sempra Energy’s subsidiaries routinely enter into contracts to hedge a substantial portion of their purchase and sale commitments and inventories of electricity, natural gas, crude oil, refined petroleum products and other commodities. As part of this strategy, they routinely utilize fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. However, the company does not always cover the entire exposure of its assets or its positions to market price volatility and the coverage will vary over time. To the extent Sempra Energy or its subsidiaries have unhedged positions, or if their hedging positions do not work as planned, fluctuating commodity prices could have a material adverse effect on Sempra Energy’s business, results of operations, cash flows and financial condition.

Risk management procedures may not prevent losses.

Although Sempra Energy and its subsidiaries have risk management systems and control systems in place that use advanced methodologies to quantify risk, these systems may not prevent material losses. The risk management procedures the company has in place may not always be followed or may not always work as planned. In addition, daily value- at-risk and loss limits are derived from historic price movements. If prices significantly deviate from historic prices, the limits may not protect the company from significant losses. As a result of these and other factors, there can be no assurances that Sempra Energy’s risk management procedures will prevent losses that would negatively affect its business, results of operations, cash flows and financial condition.

A downgrade in Sempra Energy’s credit ratings could negatively affect its energy trading and other non-utility businesses.

If Sempra Energy’s credit ratings were to be downgraded, the business prospects of its energy trading and other non-utility businesses, which generally rely on the creditworthiness of Sempra Energy, would be adversely affected. SET would be required to comply with various margin or other credit enhancement obligations under many of the trading and marketing contracts into which it has entered, substantially all of which are guaranteed by Sempra Energy, and it may be able to continue to trade only on less favorable terms. To meet liquidity requirements, Sempra Energy and its subsidiaries maintain substantial unused committed lines of credit for which borrowings are available without regard to credit ratings. A ratings downgrade could require Sempra Energy to divert to SET all or a portion of the liquidity that these lines would otherwise provide for the expansion of Sempra Energy’s other non-utility businesses. In addition, if these lines were to become unavailable or to be inadequate to meet SET’s margin or other credit enhancement


requirements, SET’s trading partners could exercise other remedies such as liquidating and netting their exposures to SET, making it more difficult or impossible for SET to manage effectively its remaining trading positions or to continue its trading business, and Sempra Energy and its subsidiaries may not have sufficient liquidity to meet their obligations.

Sempra Energy’s businesses depend on counterparties, customers and suppliers performing in accordance with their agreements, and any failure by them to perform could require the company to incur substantial expenses and expose it to commodity price risk and volatility, which could adversely affect Sempra Energy’s liquidity, cash flows and results of operations.

Sempra Energy’s subsidiaries are exposed to the risk that counterparties, customers and suppliers that owe money or energy as a result of market transactions or other long-term agreements will not perform their obligations under such agreements. Should they fail to perform, the company may be required to acquire alternative hedging arrangements or to honor the underlying commitment at then-current market prices. In such event, Sempra Energy’s subsidiaries may incur additional losses to the extent of amounts already paid to such counterparties or suppliers. In addition, the subsidiaries often extend credit to counterparties and customers. While the company performs significant credit analyses prior to extending credit, Sempra Energy and its subsidiaries are exposed to the risk that they may not be able to collect amounts owed to them.

If the DWR were to succeed in setting aside, or were to fail to perform its obligations under its long-term power contract with SER, Sempra Energy’s business, results of operations and cash flows will be materially adversely affected.

In 2001, SER entered into a 10-year power sales agreement with the DWR, to supply up to 1,900 megawatts to the state. Sempra expects the contract with the DWR will be a source of significant revenue over the 10-year period. The validity of the power sales agreement with the DWR has been the subject of extensive litigation between the parties before the FERC and in California courts. Although SER has prevailed in all of these challenges to date, the plaintiffs in these actions have appealed several of these rulings. Although SER expects to prevail in these appeals, if the DWR were to succeed in setting aside its obligations under the contract, or if the DWR fails or is unable to meet its contractual obligations on a timely basis, it could have a material adverse effect on Sempra Energy’s business, results of operations, cash flows and financial condition. These proceedings are described in the notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” incorporated by reference in this report.

In the future, Sempra Energy and its subsidiaries may elect not to or may not be able to enter into long-term supply and sales agreements or long-term firm capacity agreements for their projects, which would subject Sempra Energy’s sales to increased volatility and its businesses to increased competition.


The electric generation and wholesale power sales industries have become highly competitive. As more plants are built and competitive pressures increase, the wholesale pricing of electricity becomes more volatile. Without the benefit of long-term power sales agreements, such as the 10- year power sales agreement between SER and the DWR, Sempra Energy’s sales will be subject to increased price volatility, and it may be unable to sell the power generated by SER’s facilities or operate those facilities profitably.

Sempra Energy LNG Corp. (SELNG) does not intend to commence significant construction of its proposed LNG terminals without first entering into long-term LNG supply agreements and corresponding natural gas sales agreements, or long-term firm capacity service agreements, for a substantial portion of the processing capacity of these facilities. However, if these plans were to change and the company were to construct its terminals without the benefit of such long-term agreements, its sales would be subject to increased price volatility, and it may be unable to sell the services of its LNG facilities or to operate the facilities profitably. If the counterparties, customers or suppliers to one or more of the key agreements for the LNG facilities were to fail or become unable to meet their contractual obligations on a timely basis, it could have a significant negative impact on Sempra Energy’s business, results of operations, cash flows and financial condition.

Business development activities may not be successful and projects under construction may not commence operation as scheduled, which could increase Sempra Energy’s costs and impair its ability to recover its investments.

The acquisition, development and construction of electric generating facilities and LNG receiving terminals involve numerous risks. Sempra Energy and its subsidiaries may be required to expend significant sums for preliminary engineering, permitting, fuel supply, resource exploration, legal and other expenses in preparation for competitive bids which they may not win or before it can be established whether a project is feasible, economically attractive or capable of being built. Sempra Energy’s success in developing a particular project is contingent upon, among other things, negotiation of satisfactory engineering, procurement and construction agreements, fuel supply and power sales contracts (for generating facilities), LNG supply and natural gas sales agreements or firm capacity service agreements (for LNG receiving terminals), receipt of required governmental permits and timely implementation and satisfactory completion of construction. Successful completion of a particular project may also be adversely affected by unforeseen engineering problems, construction delays and contractor performance shortfalls, work stoppages, adverse weather conditions, environmental and geological conditions, and other factors. If the company is unable to complete the development of a facility, it typically will not be able to recover its investment in the project.

Generation facilities and/or LNG terminals may not operate as planned, which may adversely affect Sempra Energy’s business, cash flows and results of operations.

The operation of power plants and LNG receiving terminals involves many risks, including the breakdown or failure of generation or regasification and storage facilities or other equipment or processes,


labor disputes, fuel interruption and operating performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, regasification and transmission delivery systems. The occurrence of any of these events could lead to operation of power plants or LNG terminals below their expected capacity levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties, and could adversely affect Sempra Energy’s business, cash flows and results of operations.

Competition among developers and operators of LNG terminals is rapidly increasing, which may adversely affect the profitability of SELNG’s proposed LNG terminals.

Although there are only a limited number of LNG terminal facilities operating in North America today, many companies have announced plans to develop LNG facilities to serve the North American market. Some of these competitors have more operating experience, more development experience, larger staffs and greater financial resources than the company. Industry analysts have predicted that if all of the proposed LNG facilities in North America that have been announced by developers are actually built, there will likely be substantial excess capacity for such terminals in the near future. Excess capacity is likely to lead to decreased prices for such services. Although its proposed LNG facilities in Mexico and Louisiana are more advanced in the siting, permitting and regulatory approval processes than the proposed projects of most of its competitors, there can be no assurance that Sempra Energy will be able to maintain that advantage.

Sempra Energy’s subsidiaries rely on transmission and distribution assets that they do not own or control to deliver electricity and natural gas.

Sempra Energy’s subsidiaries depend on transmission and distribution facilities owned and operated by third parties to deliver the electricity and natural gas they sell to wholesale markets, to supply some of their electric generation facilities, and to provide retail energy services to customers. SELNG also will rely on natural gas transmission facilities to transport natural gas for customers of its proposed LNG terminal facilities. If transmission is disrupted, or if capacity is inadequate, the ability of Sempra Energy’s subsidiaries to sell and deliver their products and services may be hindered. As a result, they may be responsible for damages incurred by their customers, such as the additional cost of acquiring alternative supply at then- current spot market rates.

Sempra Energy’s businesses require numerous permits and other governmental approvals from various federal, state, local and foreign governmental agencies, and any failure to obtain or maintain required permits or approvals could cause Sempra Energy’s sales to decline and/or its costs to increase.

The acquisition, ownership and operation of electric generation facilities, natural gas pipelines and LNG receiving terminals require numerous permits, approvals and certificates from federal, state, local and foreign governmental agencies. All of the existing and planned development projects of Sempra Energy’s subsidiaries require multiple


permits. They may not be able to obtain or maintain all required regulatory approvals. If there is a delay in obtaining any required regulatory approvals or if the company fails to obtain any required approvals or to comply with any applicable laws or regulations, it may not be able to operate its facilities, or it may be forced to incur additional costs.

Sempra Energy’s future results of operations, cash flows and financial condition may be adversely affected by the outcomes of pending litigation and other adversarial proceedings involving Sempra Energy and some of its subsidiaries, including SET and SER.

Lawsuits have been filed by the Attorneys General of Arizona and Nevada, alleging that Sempra Energy and some of its subsidiaries, along with El Paso Energy and several of its affiliates, unlawfully sought to control the natural gas markets in their respective states. Similar lawsuits have been filed elsewhere. In addition, various lawsuits are pending against Sempra Energy, SET, SER and other Sempra Energy subsidiaries, alleging that the companies unlawfully manipulated the electric energy market. Although the company expects to prevail in these cases, it has expended or accrued substantial amounts to pay the costs of defending these claims. If the plaintiffs in these cases were to prevail in their claims, Sempra Energy’s future results of operations, cash flows and financial condition may be materially adversely affected. These proceedings are discussed in the notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” incorporated by reference in this report.

Sempra Energy’s energy and energy trading businesses are subject to complex government regulations and may be adversely affected by changes in these regulations or in their interpretation or implementation.

In recent years, the regulatory environment applicable to the electric power and natural gas industries has undergone significant changes, both on a federal and state level, which have impacted the nature of these industries and the manner in which their participants conduct their businesses. These changes are ongoing, and Sempra Energy cannot predict the future course of changes in this regulatory environment or the ultimate affect that this changing regulatory environment will have on its businesses. Moreover, existing regulations may be revised or reinterpreted, and new laws and regulations may be adopted or become applicable to the company and its facilities. Future changes in laws and regulations may have a detrimental effect on Sempra Energy’s business, cash flows, financial condition and/or results of operations.

Sempra Energy’s energy and energy trading operations are subject to affiliate rules relating to transactions with the California Utilities. These businesses could be adversely affected by changes in these rules or by additional CPUC or FERC rules’ further restricting their ability to sell electricity or gas or to trade with the California Utilities. Affiliate transaction rules also could require these businesses to obtain the prior approval of the CPUC before entering into any such transactions with the California Utilities. Any such restrictions or approval requirements could adversely affect SER’s and SEI’s electric generation plants or natural gas pipelines, SELNG’s proposed LNG receiving terminals, or SET trading operations.


Various proceedings, inquiries and investigations relating to the business activities of SER and SET are currently pending before the FERC. For a description of such proceedings, inquiries and investigations, see the notes to Consolidated Financial Statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” incorporated by reference in this report.

Sempra Energy’s businesses have significant environmental compliance costs, and future environmental compliance costs could adversely affect Sempra Energy’s profitability.

Sempra Energy’s subsidiaries are subject to extensive federal, state, local and foreign statutes, rules and regulations relating to environmental protection. They are required to obtain numerous governmental permits, licenses and other approvals to construct and operate their businesses. Additionally, to comply with these legal requirements, they must spend significant sums on environmental monitoring, pollution control equipment and emissions fees. The company also is generally responsible for all on-site liabilities associated with the environmental condition of its electric generation facilities and other energy projects which it has acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. If Sempra Energy’s subsidiaries fail to comply with applicable environmental laws, they may be subject to penalties, fines and/or curtailments of their operations.

The scope and extent of any new environmental regulations, including their affects on operations, are difficult to predict. In addition, existing environmental regulations could be revised or reinterpreted and new laws and regulations could be adopted or become applicable to the company and its facilities.

Sempra Energy’s international businesses are exposed to different local, regulatory and business risks and challenges, which could have a material adverse effect on Sempra Energy’s financial condition, cash flows and results of operations.

Sempra Energy subsidiaries currently have interests in electricity generation, natural gas transmission and LNG terminal projects in Mexico, and also have trading, marketing and risk management operations in Canada, Europe and Asia. Sempra Energy International (SEI) also has electricity and natural gas distribution businesses in Argentina, Chile and Peru. Having energy infrastructure projects, owning energy assets and operating businesses in foreign jurisdictions subject the company to significant political and financial risks which vary by country, including:

— changes in foreign laws and regulations, including tax and environmental laws and regulations;
— changes in U.S. laws and regulations, including tax and environmental laws and regulations, related to foreign operations;
— high rates of inflation;
— changes in government policies or personnel; — trade restrictions;


— limitations on U.S. company ownership in foreign countries; — permitting and regulatory compliance; — changes in labor supply and labor relations in operations outside the United States;
— adverse rulings by foreign courts or tribunals and difficulty in enforcing contractual rights in foreign jurisdictions; and — general political, economic and business conditions.

Sempra Energy’s international businesses also are subject to foreign currency risks. These risks arise from both volatility in foreign currency exchange rates and devaluations of foreign currencies. In such cases, an appreciation of the U.S. dollar against a local currency could reduce the amount of cash and income received from those foreign subsidiaries. For example, the devaluation of the Argentine peso against the U.S. dollar in recent years (as well as the Argentine government’s unilateral, retroactive abrogation of utility agreements early in 2002) has had a material adverse effect on SEI’s two unconsolidated subsidiaries in Argentina. On September 6, 2002, SEI initiated arbitration proceedings under the 1994 Bilateral Investment Treaty between the United States and Argentina for recovery of the diminution of the value of its investments that has resulted from Argentine governmental actions. SEI has claimed damages of at least $258 million these proceedings, which are continuing. For a description of legal proceedings relating to SEI’s business operations in Argentina, see the notes to Consolidated Financial Statements incorporated by reference in this report. While SEI believes that it has contracts and other measures in place to mitigate its most significant foreign currency exchange risks, it has some exposure that is not fully mitigated.

Other Risks Related to the Company

Sempra Energy’s cash flows, ability to pay dividends and ability to meet its debt obligations largely depend on the performance of its subsidiaries.

Sempra Energy is a holding company and conducts its operations entirely through its subsidiaries. Sempra Energy’s California Utilities are its major source of liquidity. Funding of other business units’ capital expenditures is largely dependent on the California Utilities’ paying sufficient dividends to Sempra Energy, which depends on the sufficiency of utility earnings and cash flows in excess of utility needs. In addition, Sempra Energy’s cash flows, ability to meet its obligations to creditors and its ability to pay dividends on its common stock are largely dependent upon the earnings of the subsidiaries and the distribution of such earnings to Sempra Energy in the form of dividends. The subsidiaries are separate and distinct legal entities and could be precluded from making such distributions under certain circumstances, including as a result of legislation or regulation or in times of financial distress.

Natural disasters, catastrophic accidents or acts of terrorism could materially adversely affect Sempra Energy’s business, earnings and cash flows.


Like other major industrial facilities, Sempra Energy’s generation plants (including SONGS), electric transmission facilities, LNG receiving terminals and storage facilities, chartered oil tankers and natural gas pipelines may be damaged by natural disasters, catastrophic accidents or acts of terrorism. Any such incidents could result in severe business disruptions, significant decreases in revenues and/or significant additional costs to the company, which could have a material adverse effect on Sempra Energy’s earnings and cash flows. Given the nature and location of these facilities, any such incidents also could cause fires, leaks, explosions, spills or other significant damage to natural resources and/or property belonging to third parties, or personal injuries, which could lead to significant claims against Sempra Energy and its subsidiaries. Insurance coverage may become unavailable for certain of these risks and the insurance proceeds received for any loss of or damage to any of its facilities, or for any loss of or damage to natural resources or property or personal injuries caused by its operations, may be insufficient to cover the company’s losses or liabilities without materially adversely affecting the company’s financial condition, earnings and cash flows.

Sempra Energy could incur significant income tax expense and its results of operations and cash flows may be materially adversely affected if the Internal Revenues Service (IRS) denies or otherwise makes income tax credits related to its coal and synthetic fuels businesses unusable.

Sempra Energy generates substantial income tax credits as a result of synthetic fuel operations and affordable-housing investments. These credits substantially reduce the company’s income tax expense.

In 2003, the IRS questioned the scientific validity of the testing procedures used to support synthetic fuel credits. The IRS has completed its review of these procedures and resumed issuing letter rulings based on its previous requirements, including one involving operations owned by Sempra Energy. However, as part of its recently commenced normal audit program for the company for the period 1998-2001, the IRS has begun auditing the company’s synthetic fuel operations. In addition, a U.S. Senate subcommittee has initiated an investigation into income tax credits, and Sempra Energy and other companies are responding to subcommittee requests regarding their synthetic fuel operations. Through December 31, 2003, Sempra Energy has recorded cumulative synthetic fuel income tax credits of $256 million, including $106 million for the fiscal year ended December 31, 2003.

Although Sempra Energy believes the retroactive disallowance of its synthetic fuel credits is unlikely, any such retroactive disallowance could result in a significant liability for income tax credits previously taken. In addition, Sempra Energy’s use of income tax credits in the future could be limited by any new IRS interpretations or regulations or by any new income tax legislation.

GOVERNMENT REGULATION

The most significant government regulation affecting Sempra Energy is that affecting its utility subsidiaries.


California Utility Regulation

The CPUC, which consists of five commissioners appointed by the Governor of California for staggered six-year terms, regulates SDG&E’s and SoCalGas’ rates and conditions of service, sales of securities, rate of return, rates of depreciation, uniform systems of accounts, examination of records, and long-term resource procurement. The CPUC conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition and the environment, to determine its future policies. The CPUC also regulates the relationship of utilities with their holding companies and is currently conducting an investigation into this relationship.

The California Energy Commission (CEC) has discretion over electric demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines the need for additional energy sources and for conservation programs. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs and maintains a state-wide plan of action in case of energy shortages. In addition, the CEC certifies power-plant sites and related facilities within California.

The CEC conducts a 20-year forecast of supply availability and prices for every market sector consuming natural gas in California. This forecast includes resource evaluation, pipeline capacity needs, natural gas demand and wellhead prices, and costs of transportation and distribution. This analysis is used to support long-term investment decisions.

United States Utility Regulation

The FERC regulates the interstate sale and transportation of natural gas, the transmission and wholesale sales of electricity in interstate commerce, transmission access, the uniform systems of accounts, rates of depreciation and electric rates involving sales for resale. Both the FERC and the CPUC are currently investigating prices charged to the California investor-owned utilities (IOUs) by various suppliers of natural gas and electricity. See further discussion in Notes 13 and 14 of the notes to Consolidated Financial Statements of the 2003 Annual Report to Shareholders, which is incorporated by reference.

The Nuclear Regulatory Commission (NRC) oversees the licensing, construction and operation of nuclear facilities. NRC regulations require extensive review of the safety, radiological and environmental aspects of these facilities. Periodically, the NRC requires that newly developed data and techniques be used to re-analyze the design of a nuclear power plant and, as a result, requires plant modifications as a condition of continued operation in some cases.

Local Regulation

SoCalGas has natural gas franchises with the 240 legal jurisdictions in its service territory. These franchises allow SoCalGas to locate facilities for the transmission and distribution of natural gas in the streets and other public places. Some franchises have fixed terms, such as that for the city of Los Angeles, which expires in 2012. Most of the franchises do not have fixed terms and continue indefinitely. The range


of expiration dates for the franchises with definite terms is 2005 to 2048.

SDG&E has electric franchises with the two counties and the 26 cities in its electric service territory, and natural gas franchises with the one county and the 18 cities in its natural gas service territory. These franchises allow SDG&E to locate facilities for the transmission and distribution of electricity and/or natural gas in the streets and other public places. The franchises do not have fixed terms, except for the electric and natural gas franchises with the cities of Encinitas (2012), San Diego (2021) and Coronado (2028), and the natural gas franchises with the city of Escondido (2036) and the county of San Diego (2030). The franchise agreement with the city of Chula Vista expired during 2003 but continues on a month-to-month basis while a new agreement is being negotiated.

SEI’s Mexican subsidiaries Distribuidora de Gas Natural (DGN) de Mexicali, DGN de Chihuahua and DGN de La Laguna Durango build and operate natural gas distribution systems in Mexicali, Chihuahua and the La Laguna-Durango zone in north-central Mexico. These companies are regulated by city and state government labor and environmental agencies.

Other Regulation

The company’s unconsolidated utility affiliates have operations in Argentina, Chile and Peru. These operations are subject to the local, federal and other regulations of the countries and/or political subdivisions in which they are located.

SET has trading locations in North America, Europe and Asia that are subject to regulation as to operations and financial position. Among other things, its operations are subject to the New York Mercantile Exchange, the London Metals Exchange, the Commodity Futures Trading Commission, the FERC and the National Futures Association.

Other subsidiaries are also subject to varying amounts of regulation by various governments, including various states in the United States.

Licenses and Permits

The California Utilities obtain a number of permits, authorizations and licenses in connection with the transmission and distribution of natural gas. In addition, SDG&E obtains a number of permits, authorizations and licenses in connection with the transmission and distribution of electricity. Both require periodic renewal, which results in continuing regulation by the granting agency.

The company’s unregulated affiliates are also required to obtain permits, authorizations and licenses in the normal course of business. Some of these permits, authorizations and licenses require periodic renewal. SER and its subsidiaries obtain a number of permits, authorizations and licenses in connection with the construction and operation of power generation facilities. In addition, SER obtains permits in connection with wholesale distribution of electricity. SES obtains permits in connection with the construction and operation of various facilities and with the retail sale of electricity and natural gas. SEI’s Mexican subsidiaries obtain construction permits for their


distribution systems from the local governments where the service is provided. SELNG obtains licenses and permits for LNG construction and operations.

Other regulatory matters are described in Notes 13 and 14 of the notes to Consolidated Financial Statements of the 2003 Annual Report to Shareholders, which is incorporated by reference.

SOURCES OF REVENUE

Industry segment information is contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 16 of the notes to Consolidated Financial Statements of the 2003 Annual Report to Shareholders, which is incorporated by reference. Various information concerning revenue and revenue recognition is provided in Note 1 of the notes to Consolidated Financial Statements of the 2003 Annual Report to Shareholders.

NATURAL GAS OPERATIONS

Resource Planning and Natural Gas Procurement and Transportation

The company is engaged in the sale, distribution, storage and transportation of natural gas through the California Utilities. The company’s resource planning, natural gas procurement, contractual commitments and related regulatory matters are discussed below and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 14 and 15 of the notes to Consolidated Financial Statements of the 2003 Annual Report to Shareholders, which is incorporated by reference.

Customers

For regulatory purposes, customers are separated into core and noncore customers. Core customers are primarily residential and small commercial and industrial customers without alternative fuel capability. Noncore customers consist primarily of electric generation (EG), wholesale, large commercial, industrial and enhanced oil recovery customers.

Most core customers purchase natural gas directly from the California Utilities. Core customers are permitted to aggregate their natural gas requirement and purchase directly from brokers or producers. The California Utilities continue to be obligated to purchase reliable supplies of natural gas to serve the requirements of the core customers.

Natural Gas Procurement and Transportation

Most of the natural gas purchased and delivered by the California Utilities is produced outside of California, primarily in the southwestern U.S. and Canada. The California Utilities purchase natural gas under short-term contracts primarily based on monthly spot-market prices.

To ensure the delivery of the natural gas supplies to the distribution system and to meet the seasonal and annual needs of customers, SoCalGas is committed to firm pipeline capacity contracts that require the payment of fixed reservation charges to reserve firm transportation


entitlements. SoCalGas releases and brokers excess capacity on a short- term basis. Interstate pipeline companies, primarily El Paso Natural Gas Company and Transwestern Pipeline Company, provide transportation services into SoCalGas’ intrastate transmission system for supplies purchased by SoCalGas or its transportation customers from outside of California. The last of these contracts expires in 2007. The rates that interstate pipeline companies may charge for natural gas and transportation services are regulated by the FERC.

SDG&E also has long-term natural gas transportation contracts with various interstate pipelines which expire on various dates through 2023. SDG&E currently purchases natural gas on a spot basis to fill its long- term pipeline capacity and purchases additional spot market supplies delivered directly to California for its remaining requirements. SDG&E continues to evaluate its long-term pipeline capacity portfolio, including the release of a portion of this capacity to third parties. All of SDG&E’s natural gas is delivered through SoCalGas pipelines under a short-term transportation agreement authorized by the CPUC. In addition, under a separate agreement expiring March 2005, SoCalGas provides SDG&E 8 bcf of storage inventory capacity with firm injection and withdrawal rights.

According to “Btu’s Daily Gas Wire,” the annual average spot price of natural gas at the California/Arizona border was $5.10 per million British thermal unit (mmbtu) in 2003 ($5.59 in December 2003), compared with $3.14 per mmbtu in 2002 and $7.27 per mmbtu in 2001. A number of factors associated with California’s energy crisis from late 2000 through early 2001 resulted in higher natural gas prices during that period. Prices for natural gas decreased in the later part of 2001 and increased toward the end of 2002 and in 2003. The following table summarizes the average commodity costs of natural gas sold for the last three years, which are above previous levels:

 

Years ended December 31, ------------------------------------- 2003           2002          2001 ------------------------------------- Cost of natural gas                       $2,071         $1,381         $2,549 Volumes delivered (bcf)                      394            406            410 Average cost of natural gas (dollars per bcf)                       $ 5.26         $ 3.40         $ 6.22

With improved delivery capacity to California, the company expects adequate resources to be available at prices that generally will follow national natural gas pricing trends and volatility.

Natural Gas Storage

SoCalGas provides natural gas storage services for use by the core, noncore and off-system customers. Core customers are allocated a portion of SoCalGas storage capacity. Remaining customers can bid and negotiate the desired amount of storage on a contract basis. The storage service program provides opportunities for customers to store natural gas, usually during the summer, to reduce winter purchases when natural gas costs are generally higher. This allows customers to select the level of


service they desire to assist them to manage their fuel procurement and transportation needs.

Demand for Natural Gas

The California Utilities face competition in the residential and commercial customer markets based on the customers’ preferences for natural gas compared with other energy products. The demand for natural gas by electric generators is influenced by a number of factors. In the short-term, natural gas use by EGs is impacted by the availability of alternative sources of generation. The availability of hydroelectricity is highly dependent on precipitation in the western United States. In addition, natural gas use is impacted by the performance of other generation sources in the western United States, including nuclear and coal, and other natural gas facilities outside the service area. Natural gas use is also impacted by changes in end-use electricity demand. For example, natural gas use generally increases during summer heat waves. Over the long-term, natural gas use will be greatly influenced by additional factors such as the location of new power plant construction. More generation capacity currently is being constructed outside Southern California than within the utility service area. This new generation will likely displace the output of older, less efficient local generation, reducing EG natural gas use.

Effective March 31, 1998, electric industry restructuring provided out- of-state producers the option to purchase energy for California utility customers. As a result, natural gas demand for electric generation within Southern California competes with electric power generated throughout the western United States. Although electric industry restructuring has no direct impact on the California Utilities’ natural gas operations, future volumes of natural gas transported for electric generating plant customers may be significantly affected to the extent that regulatory changes divert electric generation from the California Utilities’ service area.

Growth in the natural gas markets is largely dependent upon the health and expansion of the Southern California economy and prices of other energy products. External factors such as weather, the price of electricity, electric deregulation, the use of hydroelectric power, competing pipelines and general economic conditions can result in significant shifts in demand and market price. The California Utilities added 83,000 and 75,000 new customer meters in 2003 and 2002, respectively, representing growth rates of 1.4 percent and 1.2 percent respectively. The California Utilities expect that their growth rate for 2004 will approximate that for 2003.

In the interruptible industrial market, customers are capable of burning a fuel other than natural gas. Fuel oil is the most significant competing energy alternative. The company’s ability to maintain its industrial market share is largely dependent on price. The relationship between natural gas supply and demand has the greatest impact on the price of the company’s product. With the reduction of natural gas production from domestic sources, the cost of natural gas from non- domestic sources may play a greater role in the company’s competitive position in the future. The price of oil depends upon a number of factors beyond the company’s control, including the relationship between supply and demand, and policies of foreign and domestic governments.


The natural gas distribution business is seasonal in nature as variations in weather conditions generally result in greater revenues during the winter months when temperatures are colder. As is prevalent in the industry, the company injects natural gas into storage during the summer months (usually April through October) for withdrawal storage during the winter months (usually November through March) when customer demand is higher.

ELECTRIC OPERATIONS

Customers

At December 31, 2003 the company had 1.3 million meters consisting of 1,150,000 residential, 136,000 commercial, 450 industrial, 1,800 street and highway lighting, 8,000 direct access and 24 off-system. The company’s service area covers 4,100 square miles. The company added 18,000 new customer meters in 2003 and 20,000 in 2002, representing growth rates of 1.4% and 1.6% respectively.

Resource Planning and Power Procurement

SDG&E’s resource planning, power procurement and related regulatory matters are discussed below and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 13 of the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference.


 
Electric Resources

Based on CPUC-approved purchased-power contracts currently in place with SDG&E’s various suppliers and SDG&E’s 20-percent share of a generating plant, as of December 31, 2003, the supply of electric power available to SDG&E is as follows:

Megawatts  Generation: SONGS                                                  430 ----- Purchased power contracts: Expiration Supplier                   Source               date ------------------------------------------------------------- Long-term contracts: Portland General Electric (PGE)         Coal             December 2013          84 ----- DWR-allocated contracts: Williams Energy Marketing & Trading      Natural gas      December 2010       1,875 Sunrise Power Co. LLC      Natural gas      June 2012             572 Other                      Natural gas/wind 2004 to 2013          328 ----- Total                                                         2,775 ----- Other contracts with Qualifying Facilities (QFs): Applied Energy Inc.        Cogeneration     November 2019         107 Yuma Cogeneration          Cogeneration     May 2024               57 Goal Line Limited Partnership              Cogeneration     February 2025          50 Other (73 contracts)       Cogeneration     Various                16 Total                                                         ----- 230 ----- Other contracts with renewable sources: Various (9 contracts)      Bio-gas          5-15 year terms starting in 2003       28 Various (1 contract)       Bio-mass         5 year term starting in 2003       49 Various (5 contracts)      Wind             10-15 year terms starting in 2003      159 ----- Total sources                                                   236 -----

Total generation and contracted 3,755


Under the contract with PGE, SDG&E pays a capacity charge plus a charge based on the amount of energy received and or PGE’s costs. Costs under the contracts with QFs are based on SDG&E’s avoided cost. Charges under the remaining contracts are for firm and as-available energy and are based on the amount of energy received. The prices under these contracts are at the market value at the time the contracts were negotiated.

SONGS:

SDG&E owns 20 percent of the three nuclear units at SONGS (located south of San Clemente, California). The cities of Riverside and Anaheim own a total of 5 percent of Units 2 and 3. Southern California Edison (Edison) owns the remaining interests and operates the units.


Unit 1 was removed from service in November 1992 when the CPUC issued a decision to permanently shut it down. Storage and decommissioning of Unit 1’s spent nuclear fuel is now in progress.

Units 2 and 3 began commercial operation in August 1983 and April 1984, respectively. SDG&E’s share of the capacity is 214 megawatts (MW) of Unit 2 and 216 MW of Unit 3.

SDG&E has fully recovered its SONGS capital investment through December 31, 2003.

Additional information concerning the SONGS units, nuclear decommissioning and industry restructuring is provided below and in “Environmental Matters” herein, and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 6, 13, 14 and 15 of the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference.

Nuclear Fuel Supply

The nuclear-fuel cycle includes services performed by others under various contracts through 2008, including mining and milling of uranium concentrate, conversion of uranium concentrate to uranium hexafluoride, enrichment services, and fabrication of fuel assemblies.

Spent fuel from SONGS is being stored on site, where storage capacity is expected to be adequate at least through 2022, the expiration date of the NRC operating license. Pursuant to the Nuclear Waste Policy Act of 1982, SDG&E entered into a contract with the U.S. Department of Energy (DOE) for spent-fuel disposal. Under the agreement, the DOE is responsible for the ultimate disposal of spent fuel. SDG&E pays a disposal fee of $1.00 per megawatt-hour of net nuclear generation, or $3 million per year. The DOE projects that it will not begin accepting spent fuel until 2010 at the earliest.

To the extent not currently provided by the contracts, the availability and the cost of the various components of the nuclear-fuel cycle for SDG&E’s nuclear facilities cannot be estimated at this time.

Additional information concerning nuclear-fuel costs is provided in Note 15 of the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference.

Power Pools

SDG&E is a participant in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement with utilities and power agencies located throughout the United States and Canada. More than 280 investor-owned and municipal utilities, state and federal power agencies, energy brokers, and power marketers share power and information in order to increase efficiency and competition in the bulk power market. Participants are able to make power transactions on standardized terms that have been pre-approved by FERC.

Transmission Arrangements

Pacific Intertie (Intertie): The Intertie, consisting of AC and DC transmission lines, connects the Northwest with SDG&E, Pacific Gas & Electric (PG&E), Edison and others under an agreement that expires in July 2007. SDG&E’s share of the Intertie is 266 MW.

Southwest Powerlink: SDG&E’s 500-kilovolt Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego. SDG&E’s share of the line is 970 MW, although it can be less, depending on specific system conditions.

Mexico Interconnection: Mexico’s Baja California Norte system is connected to SDG&E’s system via two 230-kilovolt interconnections with firm capability of 408 MW in the north to south direction and 800 MW in the south to north direction.

Due to electric-industry restructuring (see “Transmission Access” below), the operating rights of SDG&E on these lines have been transferred to the Independent System Operator (ISO).


Transmission Access

The FERC has established rules to implement the transmission-access provisions of the National Energy Policy Act of 1992. These rules specify procedures for others’ requests for transmission service. In October 1997, the FERC approved the California IOUs’ transfer of control of their transmission facilities to the ISO. In 1998, operation and control of the transmission lines was transferred to the ISO. Additional information regarding the ISO and transmission access is provided below and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2003 Annual Report to Shareholders, which is incorporated by reference.

SEMPRA ENERGY GLOBAL ENTERPRISES

Sempra Energy Global Enterprises (Global) consists of most of the businesses of Sempra Energy other than the California Utilities, and serves a broad range of customers’ energy needs. Global includes SET, SER, SEI, SES, SELNG and several smaller business units. See below for a discussion of each of these business units.

Additional information concerning these and other aspects of the operations of Global Enterprises and Sempra Energy Financial (SEF) is provided under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 3 and 15 of the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference.

SEMPRA ENERGY TRADING

SET is a full-service trading company that markets and trades physical and financial commodity products, including natural gas, power, petroleum products and base metals. SET combines trading, risk- management and physical commodity expertise to provide innovative solutions to its customers worldwide.


SEMPRA ENERGY RESOURCES

SER is an energy company engaged in the development, construction, ownership and operation of power generation facilities and the sale of electricity, primarily in the western United States.

In May 2001, SER entered into a ten-year agreement with the DWR to supply up to 1,900 MW of electricity to the state. SER may deliver most of this electricity from its plants in the western United States and Baja California, Mexico. Sales under the contract comprise more than two-thirds of the projected capacity of these facilities and the profits therefrom are significant to the company’s ability to increase its earnings.

The company believes that SER’s contract prices are just and reasonable, but has offered to renegotiate certain aspects of the contract (which would not affect the long-term profitability) in a manner mutually beneficial to SER and the state. Although the contract is subject to ongoing litigation and regulatory proceedings, both SER and the State of California are performing under this contract. Information concerning the litigation is provided in Note 15 of the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference.

During 2003 construction was completed on the 1,250-megawatt Mesquite Power plant, with commercial operations commencing at 50% capacity in June 2003 and 100% capacity in December 2003. The project had been initially financed through a synthetic lease agreement. As a result of the implementation of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities an interpretation of ARB No. 51,” the company consolidated Mesquite Trust, the legal entity which owns Mesquite Power, in its consolidated balance sheet as of December 31, 2003. In January 2004, SER exercised the lease purchase option and acquired the power plant. See further discussion on FIN 46 in Note 1 of the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference. Additionally, during 2003, construction was completed on Termoelectrica de Mexicali, a 600-megawatt power plant near Mexicali, and the Elk Hills Power Project (Elk Hills), both of which commenced commercial operations in July 2003.

In August 2003, SER obtained approval from the appropriate state agencies to construct the Palomar Energy project, a 550-megawatt power plant in Escondido, California. In October 2003, SDG&E announced that it plans to purchase the power plant from SER when construction is completed in 2006 if the CPUC approves the purchase. On October 3, 2003 SER entered into a cost reimbursement and sharing agreement with SDG&E that became effective December 1, 2003.

In October 2002, SER purchased a 305-megawatt, coal-fired power plant (renamed Twin Oaks Power) from Texas-New Mexico Power Company for $120 million. SER has a five-year contract to sell substantially all of the output of the plant.


SEMPRA ENERGY LNG

In April 2003, SELNG completed its previously announced acquisition of the proposed Cameron LNG project from a subsidiary of Dynegy, Inc. The total cost of the project is expected to be $700 million. The project could begin commercial operations in 2007. FERC approval was granted on September 11, 2003. Other state and federal approvals required to commence construction are in progress.

In December 2003, in connection with plans to develop Energia Costa Azul, an LNG receiving terminal in Baja California, on the west coast of Mexico, 50 miles south of San Diego, SELNG and Shell International Gas Limited (Shell) announced plans to form a 50/50 joint venture to build, own and operate the $600 million facility. The terminal would be capable of supplying 1 billion cubic feet (bcf) of natural gas per day. Shell and SELNG would share the investment costs of the terminal equally and each would take 50 percent of the capacity in the terminal. 500 million cubic feet per day of natural gas from the terminal would be used to meet the growing energy demands in western Mexico. Any surplus gas from the facility would be used to provide new natural gas supplies for the southwestern United States. The proposed joint venture would combine the two separate Baja California LNG receiving terminals proposed by Shell and SELNG into a single project, significantly reducing the impact on the local environment. It is expected that construction would begin in 2004 with terminal operations commencing in 2007.

In connection with this project, Mexico’s national environmental agency issued an environmental permit in April 2003. Three other significant permits, an operating permit from Mexico’s Energy Regulatory Commission, a coastal zone use permit and a local land-use permit from the City of Ensenada, were granted in 2003. The permit to construct marine facilities is pending and is expected to be received in the near future.

See additional discussion concerning these projects in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 2 and 15 of the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference.

SEMPRA ENERGY INTERNATIONAL

SEI develops, operates and invests in energy-infrastructure systems. SEI has interests in natural gas and/or electric transmission and distribution projects in Argentina, Chile, Mexico, Peru and the eastern United States. SEI’s interests in operations in South America are not consolidated and, therefore, are not included in these discussions.

During the third quarter of 2003, SEI recorded a $77 million before-tax write-down of the carrying value of the assets of Frontier Energy, a small North Carolina utility subsidiary, as a result of reductions in actual and previously anticipated sales of natural gas by the utility.

In the third quarter of 2002, SEI completed construction of the 140-mile Gasoducto Bajanorte Pipeline that connects the Rosarito Pipeline south of Tijuana, Mexico, with a pipeline built by PG&E Corporation that will


connect to Arizona. The 30-inch pipeline can deliver up to 500 million cubic feet per day of natural gas to new generation facilities in Baja California, including SER’s Termoelectrica de Mexicali power plant discussed above. Capacity on the pipeline is over 90 percent subscribed.

SEMPRA ENERGY SOLUTIONS

SES sells energy commodities and provides integrated energy-related products and services to commercial, industrial, government and institutional markets.

SEMPRA ENERGY FINANCIAL

SEF invests as a limited partner in affordable-housing properties. SEF’s portfolio includes 1,300 properties throughout the United States, including Puerto Rico and the Virgin Islands. These investments are expected to provide income tax benefits (primarily from income tax credits) over 10-year periods. SEF also has invested in a limited partnership that produces synthetic fuel from coal. Whether SEF will invest in additional properties will depend on Sempra Energy’s income tax position.

RATES AND REGULATION — CALIFORNIA UTILITIES

Information concerning rates and regulations applicable to the California Utilities is provided in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 1, 13 and 14 of the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference.

ENVIRONMENTAL MATTERS

Discussions about environmental issues affecting the company are included in Note 15 of the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference. The following additional information should be read in conjunction with those discussions.

Hazardous Substances

In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum account, allowing California’s IOUs to recover their hazardous waste cleanup costs, including those related to Superfund sites or similar sites requiring cleanup. Recovery of 90 percent of hazardous waste cleanup costs and related third-party litigation costs and 70 percent of the related insurance-litigation expenses is permitted. In addition, the company has the opportunity to retain a percentage of any insurance recoveries to offset the 10 percent of costs not recovered in rates. Cleanup costs at sites related to electric generation were specifically excluded from the collaborative by the CPUC.

During the early 1900s, the California Utilities and their predecessors manufactured gas from coal or oil. The manufactured-gas plants (MGPs) often have become contaminated with the hazardous residues of the process. SoCalGas has identified 42 such sites at which it (together with other users as to 21 of these sites) may have cleanup obligations. Preliminary investigations, at a minimum, have been completed on 41 of


the sites. As of December 31, 2003, 26 of these sites have been remediated, of which 20 have received certification from the California Environmental Protection Agency. At December 31, 2003, SoCalGas’ estimated remaining investigation and remediation liability for the MGPs is $42.9 million. SDG&E identified three former MGPs, remediation of which was completed at two of the sites in 1998 and 2000. Closure letters have been received for the two sites. At December 31, 2003 estimated remaining remediation liability on the third site is $5.8 million.

SDG&E sold its fossil-fuel generating facilities in 1999. As a part of its due diligence for the sale, SDG&E conducted a thorough environmental assessment of the facilities. Pursuant to the sale agreements for such facilities, SDG&E and the buyers have apportioned responsibility for such environmental conditions generally based on contamination existing at the time of transfer and the cleanup level necessary for the continued use of the sites as industrial sites. While the sites are relatively clean, the assessments identified some instances of significant contamination, principally resulting from hydrocarbon releases, for which SDG&E has a cleanup obligation under the agreement. Total costs to perform the necessary remediation were estimated at $11 million at the time of sale. These costs were offset against the sales price for the facilities, together with other appropriate costs, and the remaining net proceeds were included in the calculation of customer rates. Remediation of the plants commenced in early 2001. During 2002, cleanup was completed at several minor sites at a cost of $0.4 million. In late 2002, additional assessments were started at the primary sites, where cleanup commenced in 2003 and is expected to be completed by 2005. In 2003, at a cost of $0.8 million, cleanup was completed at the site of a power plant that was sold in 1999. Remaining costs to remediate these sites are estimated at $8 million at December 31, 2003.

The California Utilities lawfully dispose of wastes at permitted facilities owned and operated by other entities. Operations at these facilities may result in actual or threatened risks to the environment or public health. Under California law, businesses that arrange for legal disposal of wastes at a permitted facility from which wastes are later released, or threaten to be released, can be held financially responsible for corrective actions at the facility.

The company and certain subsidiaries are currently named as potentially responsible parties (PRPs) for one landfill site and two industrial waste disposal sites, from which releases have occurred, as described below.

At December 31, 2003, the company’s estimated remaining investigation and remediation liability related to hazardous waste sites, including the MGPs, was $50.6 million, of which 90 percent is authorized to be recovered through the Hazardous Waste Collaborative mechanism. This estimated cost excludes remediation costs associated with SDG&E’s former fossil-fuel power plants. The company believes that any costs not ultimately recovered through rates, insurance or other means will not have a material adverse effect on the company’s consolidated results of operations or financial position.

Estimated liabilities for environmental remediation are recorded when amounts are probable and estimable. Amounts authorized to be recovered


in rates under the Hazardous Waste Collaborative mechanism are recorded as a regulatory asset.

Electric and Magnetic Fields (EMFs)

Although scientists continue to research the possibility that exposure to EMFs causes adverse health effects, science has not demonstrated a cause-and-effect relationship between exposure to the type of EMFs emitted by power lines and other electrical facilities and adverse health effects. Some laboratory studies suggest that such exposure creates biological effects, but those effects have not been shown to be harmful. The studies that have most concerned the public are epidemiological studies, some of which have reported a weak correlation between the proximity of homes to certain power lines and equipment and childhood leukemia. Other epidemiological studies found no correlation between estimated exposure and any disease. Scientists cannot explain why some studies using estimates of past exposure report correlations between estimated EMF levels and disease, while others do not.

To respond to public concerns, the CPUC has directed California IOUs to adopt a low-cost EMF-reduction policy that requires reasonable design changes to achieve noticeable reduction of EMF levels that are anticipated from new projects. However, consistent with the major scientific reviews of the available research literature, the CPUC has indicated that no health risk has been identified.

Air and Water Quality

California’s air quality standards are more restrictive than federal standards. However, as a result of the sale of the company’s fossil-fuel generating facilities, the company’s primary air-quality issue, compliance with these standards now has less significance to the company’s operation, although that could change as SER owns and operates more generating facilities.

The transmission and distribution of natural gas require the operation of compressor stations, which are subject to increasingly stringent air- quality standards. Costs to comply with these standards are recovered in rates.

In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached agreement with the California Coastal Commission to mitigate the environmental damage to the marine environment attributed to the cooling-water discharge from SONGS Units 2 and 3. This mitigation program includes an enhanced fish-protection system, a 150-acre artificial kelp reef and restoration of 150 acres of coastal wetlands. In addition, the owners must deposit $3.6 million with the state for the enhancement of fish hatchery programs and pay for monitoring and oversight of the mitigation projects. SDG&E’s share of the cost is estimated to be $34.0 million. These mitigation projects are expected to be completed in 2007. Through December 31, 2003, SONGS mitigation costs were recovered through the ICIP mechanism. SONGS mitigation costs incurred after December 31, 2003, will be capitalized and recovered from ratepayers over the remaining life of the SONGS units, subject to CPUC approval in Edison’s general rate case. Additional information on SONGS cost recovery is provided in Note 13 of


the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference.

OTHER MATTERS

Research, Development and Demonstration (RD&D)

The SoCalGas RD&D portfolio is focused in five major areas: operations, utilization systems, power generation, public interest and transportation. Each of these activities provides benefits to customers and society by providing more cost-effective, efficient natural gas equipment with lower emissions, increased safety, and reduced operating costs. The CPUC has authorized SoCalGas to recover its operating costs associated with RD&D. SoCalGas’ annual RD&D costs have averaged $6.9 million over the past three years.

For 2003, the CPUC authorized SDG&E to fund $1.2 million and $5.6 million for its natural gas and electric RD&D programs, respectively, including $5.6 million to the CEC for its PIER (Public Interest Energy Research) Program. SDG&E’s annual RD&D costs have averaged $5.7 million over the past three years.

Employees of Registrant

As of December 31, 2003, the company had 12,807 employees, compared to 12,197 at December 31, 2002.

Labor Relations

Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers’ Union of America or the International Chemical Workers’ Council. The collective bargaining agreement for field, technical and most clerical employees at SoCalGas covering wages, hours, working conditions, medical and various benefit plans is in effect through December 31, 2004.

Certain employees at SDG&E are represented by the Local 465 International Brotherhood of Electrical Workers. The current contract runs through August 31, 2004. At some of its field job sites, SES employs mechanics who are represented by the International Union of Operating Engineers, Local 501. One collective bargaining agreement runs through November 1, 2006 and the other expires on July 7, 2007.

 
ITEM 2. PROPERTIES

Electric Properties – SDG&E

SDG&E’s interest in SONGS is described in “Electric Resources” herein. At December 31, 2003, SDG&E’s electric transmission and distribution facilities included substations, and overhead and underground lines. The electric facilities are located in San Diego, Imperial and Orange counties and in Arizona, and consist of 1,805 miles of transmission lines and 21,353 miles of distribution lines. Periodically, various areas of the service territory require expansion to accommodate customer growth.


Natural Gas Properties – California Utilities

At December 31, 2003, the California Utilities’ natural gas facilities included 3,014 miles of transmission and storage pipeline, 54,518 miles of distribution pipeline and 51,672 miles of service piping. They also included 13 transmission compressor stations and 4 underground storage reservoirs, with a combined working capacity of 122 bcf.

Energy Properties – Other

At December 31, 2003, Sempra Energy completed the construction of three additional power plants and commenced operations in California, Arizona and Mexico. For additional information, see Notes 2 and 3 of the notes to Consolidated Financial Statements of the 2003 Annual Report to Shareholders, which is incorporated by reference from Item 8 herein.

At December 31 2003, SEI’s operations in Mexico included 1,465 miles of distribution pipeline, 163 miles of transmission pipeline and one compressor station.

At December 31 2003, the company’s two small natural gas utilities located in the eastern United States owned 166 miles of transmission lines and 206 miles of distribution lines.

Other Properties

The 21-story corporate headquarters building at 101 Ash Street, San Diego is occupied pursuant to a capital lease with an original term through 2005. The lease has four separate five-year renewal options.

SoCalGas leases approximately half of a 52-story office building in downtown Los Angeles through 2011. The lease has six separate five-year renewal options.

SDG&E occupies an office complex in San Diego pursuant to an operating lease ending in 2007. The lease can be renewed for two five-year periods.

Global leases office facilities at various locations in the U.S, Mexico and Europe with the leases ending from 2004 to 2009. SELNG owns land to develop a LNG receiving terminal in Baja California, Mexico. SELNG also has a land lease to develop a LNG receiving terminal in Hackberry, Louisiana. The lease expires in February 2005 and has five five-year renewal options remaining.

The company owns or leases other offices, operating and maintenance centers, shops, service facilities and equipment necessary in the conduct of its business.

 
ITEM 3. LEGAL PROCEEDINGS

Except for the matters referred to in Notes 13, 14 and 15 of the notes to Consolidated Financial Statements incorporated by reference in Item 8 or referred to elsewhere in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” incorporated by reference in this Annual Report, neither the company nor its subsidiaries are party to, nor is their property the subject of, any material pending


legal proceedings other than routine litigation incidental to their businesses.

 
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None

 

PART II

 
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Sempra Energy common stock is traded on the New York and Pacific stock exchanges. At January 31, 2004, there were 60,000 registered holders and record holders of the company’s common stock. The quarterly common stock information required by Item 5 is included in the schedule of Quarterly Financial Data of the 2003 Annual Report to Shareholders, which is incorporated by reference.

 
ITEM 6. SELECTED FINANCIAL DATA

 

(Dollars in millions)                    At December 31, or for the years then ended ------------------------------------------------------------------------------------ 2003      2002      2001      2000      1999 -------   -------   -------   -------   ------- Income Statement Data: Operating revenues                $ 7,887   $ 6,048   $ 7,730   $ 6,760   $ 5,360 Operating income                  $   939   $   987   $   997   $   884   $   763 Net income                        $   649   $   591   $   518   $   429   $   394  Balance Sheet Data: Total assets                      $22,009   $20,242   $17,476   $17,850   $13,312 Long-term debt                    $ 3,841   $ 4,083   $ 3,436   $ 3,268   $ 2,902 Short-term debt (a)               $ 1,461   $   851   $ 1,117   $   936   $   337 Shareholders' equity              $ 3,890   $ 2,825   $ 2,692   $ 2,494   $ 2,986  Per Common Share Data: Income before extraordinary item and cumulative effect of changes in accounting principles per common share: Basic                       $  3.29   $  2.80   $  2.54   $  2.06   $  1.66 Diluted                     $  3.24   $  2.79   $  2.52   $  2.06   $  1.66 Income before cumulative effect of changes in accounting principles per common share: Basic                       $  3.29   $  2.88   $  2.54   $  2.06   $  1.66 Diluted                     $  3.24   $  2.87   $  2.52   $  2.06   $  1.66 Net income per common share: Basic                       $  3.07   $  2.88   $  2.54   $  2.06   $  1.66 Diluted                     $  3.03   $  2.87   $  2.52   $  2.06   $  1.66 Dividends declared                $  1.00   $  1.00   $  1.00   $  1.00   $  1.56 Book value                        $ 17.17   $ 13.79   $ 13.16   $ 12.35   $ 12.58  (a)     Includes long-term debt due within one year.

This data should be read in conjunction with the Consolidated Financial Statements and the notes to Consolidated Financial Statements contained


in the 2003 Annual Report to Shareholders, which is incorporated by reference.

 
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND  
RESULTS OF OPERATIONS

The information required by Item 7 is incorporated by reference from pages 1 through 38 of the 2003 Annual Report to Shareholders.

 
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by Item 7A is incorporated by reference from pages 30 through 33 of the 2003 Annual Report to Shareholders.

 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by Item 8 is incorporated by reference from pages 42 through 129 of the 2003 Annual Report to Shareholders. Item
15(a)1 includes a listing of financial statements included in the 2003 Annual Report to Shareholders.

 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

None.

 
ITEM 9A. CONTROLS AND PROCEDURES

The company has designed and maintains disclosure controls and procedures to ensure that information required to be disclosed in the company’s reports under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, management recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired objectives and necessarily applies judgment in evaluating the cost- benefit relationship of other possible controls and procedures. In addition, the company has investments in unconsolidated entities that it does not control or manage and, consequently, its disclosure controls and procedures with respect to these entities are necessarily substantially more limited than those it maintains with respect to its consolidated subsidiaries.

Under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, the company as of December 31, 2003 has evaluated the effectiveness of the design and operation of the company’s disclosure controls and procedures. Based on that evaluation, the company’s Chief Executive Officer and Chief Financial Officer have concluded that the controls and procedures are effective.

There have been no significant changes in the company’s internal controls or in other factors that could significantly affect the


internal controls subsequent to the date the company completed its evaluation.

 

PART III

 
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required on Identification of Directors is incorporated by reference from “Election of Directors” in the Proxy Statement prepared for the May 2004 annual meeting of shareholders. The information required on the company’s executive officers is provided below.

 
EXECUTIVE OFFICERS OF THE REGISTRANT

Name                     Age*    Position --------------------------------------------------------------------- Stephen L. Baum           62     Chairman, Chief Executive Officer and President  Donald E. Felsinger       56     Group President, Sempra Energy Global Enterprises  Edwin A. Guiles           54     Group President, Sempra Energy Utilities  M. Javade Chaudhri        51     Executive Vice President and General Counsel  Neal E. Schmale           57     Executive Vice President and Chief Financial Officer  Frank H. Ault             59     Senior Vice President and Controller  Frederick E. John         57     Senior Vice President, External Affairs and Communications  G. Joyce Rowland          49     Senior Vice President, Human Resources

* As of December 31, 2003.

Each Executive Officer has been an officer of the company or one of its subsidiaries for more than five years, with the exception of Mr. Chaudhri. Prior to joining the company in 2003, Mr. Chaudhri was Senior Vice President and General Counsel of Gateway, Inc.


 
ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated by reference from “Election of Directors” and “Executive Compensation” in the Proxy Statement prepared for the May 2004 annual meeting of shareholders.

 
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Securities Authorized for Issuance Under Equity Compensation Plans

Information regarding securities authorized for issuance under equity compensation plans as required by Item 12 is incorporated by reference from “Share Ownership” and “Equity Compensation Plans” in the Proxy Statement prepared for the May 2004 annual meeting of shareholders.

See additional discussion of stock-based compensation in Note 9 of the notes to Consolidated Financial Statements of the 2003 Annual Report to Shareholders, which is incorporated by reference.

Security Ownership of Certain Beneficial Owners

The security ownership information required by Item 12 is incorporated by reference from “Share Ownership” in the Proxy Statement prepared for the May 2004 annual meeting of shareholders.

 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

None.

 
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding principal accountant fees and services as required by Item 14 is incorporated by reference from “Proposal 3: Ratification of Independent Auditors” in the Proxy Statement prepared for the May 2004 annual meeting of shareholders.


 
PART IV

 
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) The following documents are filed as part of this report:

 

1. Financial statements Page in Annual Report*  Statement of Management's Responsibility for Consolidated Financial Statements. . . . . . . . . . . . . 40  Independent Auditors' Report . . . . . . . . . . . . . . . . 41  Statements of Consolidated Income for the years ended December 31, 2003, 2002 and 2001 . . . . . . . . . . 42  Consolidated Balance Sheets at December 31, 2003 and 2002. . . . . . . . . . . . . . . . . . . . . . . 43  Statements of Consolidated Cash Flows for the years ended December 31, 2003, 2002 and 2001 . . . . . . . 45  Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 2003, 2002 and 2001 . . . . . . . . . . . . . 47  Notes to Consolidated Financial Statements . . . . . . . . . 48

*Incorporated by reference from the indicated pages of the 2003 Annual Report to Shareholders.

2. Financial statement schedules

The following document may be found in this report at the indicated page number.

Schedule I–Condensed Financial Information of Parent. . . . 39

Any other schedules for which provision is made in Regulation S-X are not required under the instructions contained therein or are inapplicable.

3. Exhibits

See Exhibit Index on page 44 of this report.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after September 30, 2003:

Current Report on Form 8-K filed October 9, 2003, announcing the execution of an underwriting agreement for the issuance and sale of common stock and reporting several recent developments related to credit rating changes, litigation, and other events.


Current Report on Form 8-K filed November 6, 2003, filing as an exhibit Sempra Energy’s press release of November 6, 2003, giving the financial results for the three months ended September 30, 2003.

Current Report on Form 8-K filed December 31, 2003, to update information on the August 25, 2003 CPUC decision regarding the allocation of profits from SDG&E’s intermediate-term purchase power contracts. Updates when the Court of Appeals will have a decision on the petition submitted by an advocacy group for small consumers.

Current Report on Form 8-K filed February 24, 2004, filing as an exhibit Sempra Energy’s press release of February 24, 2004, giving the financial results for the three months ended December 31, 2003.


 
INDEPENDENT AUDITORS’ CONSENT AND REPORT ON SCHEDULE

To the Board of Directors and Shareholders of Sempra Energy:

We consent to the incorporation by reference in Registration Statement Numbers 333-51309, 333-52192, 333-77843, 333-70640 and 333-103588 on Form S-3 and Registration Statement Numbers 333-56161, 333-50806 and 333-49732 on Form S-8 of Sempra Energy of our report dated February 23, 2004, incorporated by reference in this Annual Report on Form 10-K of Sempra Energy for the year ended December 31, 2003.

Our audits of the financial statements referred to in our aforementioned report also included the financial statement schedule of Sempra Energy, listed in Item 15. This financial statement schedule is the responsibility of the company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/S/ DELOITTE & TOUCHE LLP  San Diego, California February 24, 2004


 
Schedule I — CONDENSED FINANCIAL INFORMATION OF PARENT

SEMPRA ENERGY  Condensed Statements of Income (Dollars in millions, except per share amounts)  Years ended December 31, 2003        2002        2001 --------    --------    -------- Other income                                $    126     $    52     $    52 Interest expense                                (187)       (134)       (130) Trust preferred distributions                     (9)        (18)        (18) Operating expenses                               (21)        (14)        (25) Income tax benefits                               57          38          55 --------    --------    -------- Loss before subsidiary earnings                  (34)        (76)        (66) Subsidiary earnings before extraordinary item and cumulative effect of changes in accounting principles                           729         651         584 --------    --------    -------- Income before extraordinary item and cumulative effect of changes in accounting principles                           695         575         518 Extraordinary item, net of tax                    --          16          -- --------    --------    -------- Income before cumulative effect of changes in accounting principles, net of tax            695         591         518 Cumulative effect of changes in accounting principles, net of tax                          (46)         --          -- --------    --------    -------- Net income                                   $   649     $   591     $   518 ========    ========    ======== Weighted-average number of shares outstanding (thousands): Basic                                     211,740     205,003     203,593 ========    ========    ======== Diluted                                   214,482     206,062     205,338 ========    ========    ======== Income before extraordinary item and cumulative effect of changes in accounting principles per share of common stock Basic                                     $  3.29     $  2.80     $  2.54 ========    ========    ======== Diluted                                   $  3.24     $  2.79     $  2.52 ========    ========    ======== Income before cumulative effect of changes in accounting principles per share of common stock Basic                                     $  3.29     $  2.88     $  2.54 ========     ========    ======== Diluted                                   $  3.24     $  2.87     $  2.52 ========     ========    ======== Net income per share of common stock Basic                                     $  3.07     $  2.88     $  2.54 ========     ========    ======== Diluted                                   $  3.03     $  2.87     $  2.52 ========     ========    ========



 

SEMPRA ENERGY

Condensed Balance Sheets (Dollars in millions)

December 31, 2003        2002 --------    -------- Assets: Cash and cash equivalents                         $     59    $      3 Due from affiliates                                     52          72 Other current assets                                    43           7 --------    -------- Total current assets                              154          82 --------    --------  Investments in subsidiaries                          5,518       4,995 Due from affiliates                                  2,521       1,730 Other assets                                           435         388 --------    -------- Total assets                                 $  8,628    $  7,195 ========    ========  Liabilities and Shareholders' Equity: Current portion of long-term debt                 $    525    $      2 Income taxes payable                                   323         247 Due to affiliates                                    1,403       1,500 Other current liabilities                              178         157 --------    -------- Total current liabilities                       2,429       1,906 --------    --------  Long-term debt                                       1,900       2,043 Due to affiliate                                       200          -- Other long-term liabilities                            209         421 Shareholders' equity                                 3,890       2,825 --------    -------- Total liabilities and shareholders' equity   $  8,628    $  7,195 ========    ========


 

SEMPRA ENERGY  Condensed Statements of Cash Flows (Dollars in millions)  Years ended December 31, 2003       2002       2001 --------   --------   -------- Net cash provided by (used in) operating activities                           $    (80)  $    144   $   (253) --------   --------   -------- Dividends received from subsidiaries                 250        100        340 Expenditures for property, plant and equipment        (4)       (12)       (35) Increase in investments and other assets              --        (20)       (30) --------   --------   -------- Cash provided by investing activities                246         68        275 --------   --------   -------- Common stock dividends paid                         (207)      (205)      (203) Repurchase of common stock                            (6)       (16)        (1) Sale of common stock                                 549         13         41 Issuances of long-term debt                          400        600        581 Payment on long-term debt                             --        (26)       (84) Loans to affiliates - net                           (842)      (628)      (345) Other                                                 (4)       (19)        (2) --------   --------   -------- Cash used in financing activities                   (110)      (281)       (13) --------   --------   -------- Increase (decrease) in cash and cash equivalents      56        (69)         9 Cash and cash equivalents, January 1                   3         72         63 --------   --------   -------- Cash and cash equivalents, December 31          $     59   $      3   $     72 ========   ========   ========



 
SEMPRA ENERGY

Note to Condensed Financial Statements  Long-term Debt ----------------------------------------------------------------- December 31, (Dollars in millions)                         2003         2002 -----------------------------------------------------------------  Other long-term debt 5.60% equity units May 17, 2007           $  600       $  600 Notes payable at variable rates after a fixed-to-floating rate swap (2.49% at December 31, 2003) July 1, 2004         500          500 7.95% Notes March 1, 2010                    500          500 6.0% Notes due February 1, 2013              400           -- 6.95% Notes December 1, 2005                 300          300 Employee Stock Ownership Plan Bonds at 7.375% November 1, 2014            82           82 Bonds at variable rates (1.65% at December 31, 2003) November 1, 2014       19           19 Capitalized leases                             3            5 Market value adjustments for interest rate swaps - net (expires July 1, 2004)     23           42 ------------------------ Total                                   $2,427       $2,048 ------------------------ Less: Current portion of long-term debt            525            2 Unamortized discount on long-term debt         2            3 ------------------------ 527            5 ------------------------ Total                                       $1,900       $2,043 ------------------------------------------------------------------

Excluding market value adjustments for interest-rate swaps, maturities of long-term debt are $502 million in 2004, $301 million in 2005, $600 million in 2007 and $1 billion thereafter.

Additional information on Sempra Energy’s long-term debt is provided in Note 5 of the notes to Consolidated Financial Statements in the 2003 Annual Report to Shareholders, which is incorporated by reference.


 
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

SEMPRA ENERGY

By: /s/ Stephen L. Baum  Stephen L. Baum Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.

 

Name/Title                          Signature                              Date Principal Executive Officer: Stephen L. Baum Chairman, President and Chief Executive Officer            /s/ Stephen L. Baum                 February 20, 2004  Principal Financial Officer: Neal E. Schmale Executive Vice President and Chief Financial Officer                /s/ Neal E. Schmale                 February 20, 2004  Principal Accounting Officer: Frank H. Ault Senior Vice President and Controller                             /s/ Frank H. Ault                   February 20, 2004  Directors: Stephen L. Baum, Chairman              /s/ Stephen L. Baum                 February 20, 2004  Hyla H. Bertea, Director               /s/ Hyla H. Bertea                  February 20, 2004  James G. Brocksmith, Jr., Director     /s/ James G. Brocksmith, Jr.        February 20, 2004  Herbert L. Carter, Director            /s/ Herbert L. Carter               February 20, 2004  Richard A. Collato, Director           /s/ Richard A. Collato              February 20, 2004  Wilford D. Godbold, Jr., Director      /s/ Wilford D. Godbold, Jr.         February 20, 2004  William D. Jones, Director             /s/ William D. Jones                February 20, 2004  Richard G. Newman, Director            /s/ Richard G. Newman               February 20, 2004  William G. Ouchi, Director             /s/ William G. Ouchi                February 20, 2004  William C. Rusnack, Director           /s/ William C. Rusnack              February 20, 2004  William P. Rutledge, Director          /s/ William P. Rutledge             February 20, 2004  Thomas C. Stickel, Director            /s/ Thomas C. Stickel               February 20, 2004  Diana L. Walker, Director              /s/ Diana L. Walker                 February 20, 2004


 
EXHIBIT INDEX

The Forms 8, 8-B/A, 8-K, S-4, 10-K and 10-Q referred to herein were filed under Commission File Number 1-14201 (Sempra Energy), Commission File Number 1-40 (Pacific Enterprises), Commission File Number 1-3779 (San Diego Gas & Electric), Commission File Number 1-1402 (Southern California Gas Company), Commission File Number 1-11439 (Enova Corporation) and/or Commission File Number 333-30761 (SDG&E Funding LLC).

3.a The following exhibits relate to Sempra Energy and its subsidiaries

 
Exhibit 1 — Underwriting Agreements

Enova Corporation and San Diego Gas & Electric Company

1.01   Underwriting Agreement dated December 4, 1997 (Incorporated by reference from Form 8-K filed by SDG&E Funding LLC on December 23, 1997 (Exhibit 1.1)).

 
Exhibit 3 — Bylaws and Articles of Incorporation

Bylaws  Sempra Energy ------------- 3.01   Amended and Restated Bylaws of Sempra Energy effective May 26, 1998 (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration No. 333-56161 dated June 5, 1998 (Exhibit 3.2)).  Articles of Incorporation  Sempra Energy ------------- 3.02   Amended and Restated Articles of Incorporation of Sempra Energy (Incorporated by reference to the Registration Statement on Form S-3 File No. 333-51309 dated April 29, 1998, Exhibit 3.1).

Exhibit 4 — Instruments Defining the Rights of Security Holders, Including Indentures

The company agrees to furnish a copy of each such instrument to the Commission upon request.

 
Enova Corporation and San Diego Gas & Electric Company

4.01   Mortgage and Deed of Trust dated July 1, 1940. (Incorporated by reference from SDG&E Registration No. 2-49810, Exhibit 2A.)  4.02   Second Supplemental Indenture dated as of March 1, 1948. (Incorporated by reference from SDG&E Registration No. 2-49810, Exhibit 2C.)


4.03   Ninth Supplemental Indenture dated as of August 1, 1968. (Incorporated by reference from SDG&E Registration No. 2-68420, Exhibit 2D.)  4.04   Tenth Supplemental Indenture dated as of December 1, 1968. (Incorporated by reference from SDG&E Registration No. 2-36042, Exhibit 2K.)  4.05   Sixteenth Supplemental Indenture dated August 28, 1975. (Incorporated by reference from SDG&E Registration No. 2-68420, Exhibit 2E.)  4.06   Thirtieth Supplemental Indenture dated September 28, 1983. (Incorporated by reference from SDG&E Registration No. 33-34017, Exhibit 4.3.)

 
Pacific Enterprises and Southern California Gas

4.07   First Mortgage Indenture of Southern California Gas Company to American Trust Company dated as of October 1, 1940 (Registration Statement No. 2-4504 filed by Southern California Gas Company on September 16, 1940, Exhibit B-4).  4.08   Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of July 1, 1947 (Registration Statement No. 2-7072 filed by Southern California Gas Company on March 15, 1947, Exhibit B-5).  4.09   Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of August 1, 1955 (Registration Statement No. 2-11997 filed by Pacific Lighting Corporation on October 26, 1955, Exhibit 4.07).  4.10   Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of June 1, 1956 (Registration Statement No. 2-12456 filed by Southern California Gas Company on April 23, 1956, Exhibit 2.08).  4.11   Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of August 1, 1972 (Registration Statement No. 2-59832 filed by Southern California Gas Company on September 6, 1977, Exhibit 2.19).  4.12   Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of May 1, 1976 (Registration Statement No. 2-56034 filed by Southern California Gas Company on April 14, 1976, Exhibit 2.20).  4.13   Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of September 15, 1981 (Pacific Enterprises 1981 Form 10-K, Exhibit 4.25).


4.14   Supplemental Indenture of Southern California Gas Company to Manufacturers Hanover Trust Company of California, successor to Wells Fargo Bank, National Association, and Crocker National Bank as Successor Trustee dated as of May 18, 1984 (Southern California Gas Company 1984 Form 10-K, Exhibit 4.29).  4.15   Supplemental Indenture of Southern California Gas Company to Bankers Trust Company of California, N.A., successor to Wells Fargo Bank, National Association dated as of January 15, 1988 (Pacific Enterprises 1987 Form 10-K, Exhibit 4.11).  4.16   Supplemental Indenture of Southern California Gas Company to First Trust of California, National Association, successor to Bankers Trust Company of California, N.A. dated as of August 15, 1992 (Registration Statement No. 33-50826 filed by Southern California Gas Company on August 13, 1992, Exhibit 4.37).  4.17   Supplemental Indenture of Southern California Gas Company to U.S. Bank, N.A., successor to First Trust of California, N.A., dated as of October 1, 2002.  Exhibit 10 -- Material Contracts (Previously filed exhibits are incorporated by reference from Forms 8-K, S-4, 10-K or 10-Q as referenced below).  Sempra Energy ------------- 10.01  Energy Purchase Agreement between Sempra Energy Resources and the California Department of Water Resources, executed May 4, 2001 (2001 Form 10-K, Exhibit 10.01).  10.02  Form of Employment Agreement between Sempra Energy and Stephen L. Baum (September 30, 2002 Form 10-Q, Exhibit 10.1).  10.03  Amendment to Employment Agreement, effective December 1, 1998 (Employment agreement, dated as of October 12, 1996 between Mineral Energy Company and Stephen L. Baum (Enova 8-K filed October 15, 1996, Exhibit 10.2)).  10.04  Form of Employment Agreement between Sempra Energy and Donald E. Felsinger (September 30, 2002 Form 10-Q, Exhibit 10.2).  10.05  Amendment to Employment Agreement effective December 1, 1998 (Employment contract, dated as of October 12, 1996 between Mineral Energy Company and Donald E. Felsinger (Enova 8-K filed October 15, 1996, Exhibit 10.4)).

 
Enova Corporation and San Diego Gas & Electric Company

10.06  Operating Agreement between San Diego Gas & Electric and the California Department of Water Resources dated April 17, 2003.  10.07  Servicing Agreement between San Diego Gas & Electric and the California Department of Water Resources dated December 19, 2002.  10.08  Transition Property Purchase and Sale Agreement dated December 16, 1997 (Incorporated by reference from Form 8-K filed by SDG&E Funding LLC on December 23, 1997 (Exhibit 10.1)).


10.09  Transition Property Servicing Agreement dated December 16, 1997 (Incorporated by reference from Form 8-K filed by SDG&E Funding LLC on December 23, 1997 (Exhibit 10.2)).

 
Compensation

Sempra Energy

10.10 2003 Sempra Energy Executive Incentive Plan B.

10.11 2003 Executive Incentive Plan (June 30, 2003 Form 10-Q, Exhibit 10.1).

10.12  Amended 1998 Long-Term Incentive Plan (June 30, 2003 Form 10-Q, Exhibit 10.2).  10.13  Sempra Energy Executive Incentive Plan effective January 1, 2003 (2002 Form 10-K Exhibit 10.09).  10.14  Amended Sempra Energy Retirement Plan for Directors (2002 Form 10-K Exhibit 10.10).  10.15  Amended and Restated Sempra Energy Deferred Compensation and Excess Savings Plan (September 30, 2002 Form 10-Q, Exhibit 10.3).  10.16  Form of Sempra Energy Severance Pay Agreement for Executives (2001 Form 10-K, Exhibit 10.07).  10.17  Sempra Energy Executive Security Bonus Plan effective January 1, 2001 (2001 Form 10-K, Exhibit 10.08).  10.18  Sempra Energy Deferred Compensation and Excess Savings Plan effective January 1, 2000 (2000 Form 10-K, Exhibit 10.07).  10.19  Sempra Energy 1998 Long Term Incentive Plan (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration No. 333-56161 dated June 5, 1998 (Exhibit 4.1)).  10.20  Sempra Energy 1998 Non-Employee Directors' Stock Plan (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration No. 333-56161 dated June 5, 1998 (Exhibit 4.2)).

 
Financing

Enova Corporation and San Diego Gas & Electric

10.21  Loan agreement with the City of Chula Vista in connection with the issuance of $25 million of Industrial Development Bonds, dated as of October 1, 1997 (Enova 1997 Form 10-K, Exhibit 10.34).


10.22  Loan agreement with the City of Chula Vista in connection with the issuance of $38.9 million of Industrial Development Bonds, dated as of August 1, 1996 (Enova 1996 Form 10-K, Exhibit 10.31).  10.23  Loan agreement with the City of Chula Vista in connection with the issuance of $60 million of Industrial Development Bonds, dated as of November 1, 1996 (Enova 1996 Form 10-K, Exhibit 10.32).  10.24  Loan agreement with City of San Diego in connection with the issuance of $57.7 million of Industrial Development Bonds, dated as of June 1, 1995 (June 30, 1995 SDG&E Form 10-Q, Exhibit 10.3).  10.25  Loan agreement with the City of San Diego in connection with the issuance of $92.9 million of Industrial Development Bonds 1993 Series C dated as of July 1, 1993 (June 30, 1993 SDG&E Form 10-Q, Exhibit 10.2).  10.26  Loan agreement with the City of San Diego in connection with the issuance of $70.8 million of Industrial Development Bonds 1993 Series A dated as of April 1, 1993 (March 31, 1993 SDG&E Form 10-Q, Exhibit 10.3).  10.27  Loan agreement with the City of San Diego in connection with the issuance of $118.6 million of Industrial Development Bonds dated as of September 1, 1992 (Sept. 30, 1992 SDG&E Form 10-Q, Exhibit 10.1).  10.28  Loan agreement with the City of Chula Vista in connection with the issuance of $250 million of Industrial Development Bonds, dated as of December 1, 1992 (1992 SDG&E Form 10-K, Exhibit 10.5).  10.29  Loan agreement with the California Pollution Control Financing Authority in connection with the issuance of $129.82 million of Pollution Control Bonds, dated as of June 1, 1996 (Enova 1996 Form 10-K, Exhibit 10.41).  10.30  Loan agreement with the California Pollution Control Financing Authority in connection with the issuance of $60 million of Pollution Control Bonds dated as of June 1, 1993 (June 30, 1993 SDG&E Form 10-Q, Exhibit 10.1).  10.31  Loan agreement with the California Pollution Control Financing Authority, dated as of December 1, 1991, in connection with the issuance of $14.4 million of Pollution Control Bonds (1991 SDG&E Form 10-K, Exhibit 10.11).


 
Natural Gas Transportation

Enova Corporation and San Diego Gas & Electric

10.32  Amendment to Firm Transportation Service Agreement, dated December 2, 1996, between Pacific Gas and Electric Company and San Diego Gas & Electric Company (1997 Enova Corporation Form 10-K, Exhibit 10.58).  10.33  Firm Transportation Service Agreement, dated December 31, 1991 between Pacific Gas and Electric Company and San Diego Gas & Electric Company (1991 SDG&E Form 10-K, Exhibit 10.7).  10.34  Firm Transportation Service Agreement, dated October 13, 1994 between Pacific Gas Transmission Company and San Diego Gas & Electric Company (1997 Enova Corporation Form 10-K, Exhibit 10.60).

 
Nuclear

Enova Corporation and San Diego Gas & Electric

10.35  Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station, approved November 25, 1987 (1992 SDG&E Form 10-K, Exhibit 10.7).  10.36  Amendment No. 1 to the Qualified CPUC Decommissioning Master Trust Agreement dated September 22, 1994 (see Exhibit 10.35 herein)(1994 SDG&E Form 10-K, Exhibit 10.56).  10.37  Second Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.35 herein)(1994 SDG&E Form 10-K, Exhibit 10.57).  10.38  Third Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.35 herein)(1996 SDG&E Form 10-K, Exhibit 10.59).  10.39  Fourth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.35 herein)(1996 SDG&E Form 10-K, Exhibit 10.60).  10.40  Fifth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generation Station (see Exhibit 10.35 herein)(1999 SDG&E Form 10-K, Exhibit 10.26).  10.41  Sixth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.35 herein)(1999 SDG&E Form 10-K, Exhibit 10.27).


10.42  Seventh Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated December 24, 2003 (see Exhibit 10.35 herein).  10.43  Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station, approved November 25, 1987 (1992 SDG&E Form 10-K, Exhibit 10.8).  10.44  First Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.43 herein)(1996 Form 10-K, Exhibit 10.62).  10.45  Second Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.43 herein)(1996 Form 10-K, Exhibit 10.63).  10.46  Third Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.43 herein)(1999 SDG&E Form 10-K, Exhibit 10.31).  10.47  Fourth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.43 herein)(1999 SDG&E Form 10-K, Exhibit 10.32).  10.48  Fifth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated December 24, 2003 (see Exhibit 10.43 herein).  10.49  Second Amended San Onofre Operating Agreement among Southern California Edison Company, SDG&E, the City of Anaheim and the City of Riverside, dated February 26, 1987 (1990 SDG&E Form 10-K, Exhibit 10.6).  10.50  U. S. Department of Energy contract for disposal of spent nuclear fuel and/or high-level radioactive waste, entered into between the DOE and Southern California Edison Company, as agent for SDG&E and others; Contract DE-CR01-83NE44418, dated June 10, 1983 (1988 SDG&E Form 10-K, Exhibit 10N).

Exhibit 12 — Statement re: Computation of Ratios

 

12.01  Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends for the years ended December 31, 2003, 2002, 2001, 2000, and 1999.


 
Exhibit 13 — Annual Report to Security Holders

13.01  Sempra Energy 2003 Annual Report to Shareholders. (Such report, except for the portions thereof which are expressly incorporated by reference in this Annual Report, is furnished for the information of the Securities and Exchange Commission and is not to be deemed "filed" as part of this Annual Report).

Exhibit 21 — Subsidiaries

21.01 Schedule of Significant Subsidiaries at December 31, 2003.

Exhibit 23 — Independent Auditors’ Consent, page 38.

 
Exhibit 31 — Section 302 Certifications

 

31.1  Statement of Registrant's Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.  31.2  Statement of Registrant's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

 
Exhibit 32 — Section 906 Certifications

 

32.1  Statement of Registrant's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.  32.2  Statement of Registrant's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.


 
GLOSSARY

AB                   California Assembly Bill  AB X1                A California Assembly bill authorizing the California   Department of Water Resources to purchase energy for California consumers.  AEG                  Atlantic Electric & Gas Limited  AFUDC                Allowance for Funds Used During Construction  ALJ                  Administrative Law Judge  APB                  Accounting Principles Board  APS                  Arizona Public Service Co.  ARB                  Accounting Research Bulletin  BCAP                 Biennial Cost Allocation Proceeding  Bcf                  One Billion Cubic Feet (of natural gas)  Calpine              Calpine Corporation  CEC                  California Energy Commission  CEMA                 Catastrophic Event Memorandum Account  CFTC                 Commodity Futures Trading Commission  CPUC                 California Public Utilities Commission  CRS                  Cost Responsibility Surcharge  DA                   Direct Access  DGN                  Distribuidora de Gas Natural  DOE                  Department of Energy  DSM                  Demand-Side Management  DWR                  Department of Water Resources  Edison               Southern California Edison Company  EITF                 Emerging Issues Task Force  El Paso              El Paso Energy Corp.  Elk Hills            Elk Hills Power Project  EG                   Electric Generation  EMFs                 Electric and Magnetic Fields


ERMG                 Energy Risk Management Group  ERMOC                Energy Risk Management Oversight Committee  ESOP                 Employee Stock Ownership Plan  FASB                 Financial Accounting Standards Board  FERC                 Federal Energy Regulatory Commission  FIN                  FASB Interpretation No.  FSP                  FASB Staff Position  GCIM                 Gas Cost Incentive Mechanism  GIR                  Gas Industry Restructuring  Global               Sempra Energy Global Enterprises  HOA                  Heads of Agreement  ICIP                 Incremental Cost Incentive Pricing  IID                  Imperial Irrigation District  Intertie             Pacific Intertie  IOUs                 Investor-Owned Utilities  IRS                  Internal Revenue Service  ISO                  Independent System Operator  kWh                  Kilowatt Hour  LIFO                 Last-In First-Out inventory costing method  LNG                  Liquefied Natural Gas  Luz del Sur          Luz del Sur S.A.A.  MGPs                 Manufactured-Gas Plants  mmbtu                Million British Thermal Units (of natural gas)  Moody's              Moody's Investor Services, Inc.  MW                   Megawatt  NRC                  Nuclear Regulatory Commission  Occidental           Occidental Energy Ventures Corporation  OIR                  Order Instituting Ratemaking


OPEC                 Organization of the Petroleum Exporting Countries  ORA                  Office of Ratepayer Advocates  OTC                  Over the counter  PBR                  Performance-Based Regulation  PE                   Pacific Enterprises  PG&E                 PG&E Corporation  PGA                  Purchased Gas Balancing Account  PGE                  Portland General Electric Company  PIER                 Public Interest Energy Research  PPA                  Power Purchase Agreement  PRPs                 Potentially Responsible Parties  PSEG                 PSEG Global  PX                   Power Exchange  QFs                  Qualifying Facilities  RD&D                 Research, Development and Demonstration  RFP                  Request for Proposals  ROE                  Return on Equity  ROR                  Return on Ratebase  S&P                  Standard & Poor's  SDG&E                San Diego Gas & Electric Company  SEC                  Securities and Exchange Commission  SELNG                Sempra Energy LNG Corp.  SEF                  Sempra Energy Financial  SEI                  Sempra Energy International  SER                  Sempra Energy Resources  SES                  Sempra Energy Solutions  SET                  Sempra Energy Trading  SFAS                 Statement of Financial Accounting Standards  Shell                Shell International Gas Limited


SoCalGas             Southern California Gas Company  SONGS                San Onofre Nuclear Generating Station  Southwest Powerlink  A transmission line connecting San Diego to Phoenix and intermediate points.  SPEs                 Special Purpose Entities  Sunat                Peruvian tax authorities  TDM                  Termoelectrica de Mexicali  The Act              Medicare Prescription Drug Improvement Modernization Act  The Board            Sempra Energy's Board of Directors  Trust                ESOP Trust  UCAN                 Utility Consumers Action Network  VaR                  Value at Risk  VIEs                 Variable Interest Entities


   

EXHIBIT 10.06

SDG&E OPERATING AGREEMENT Between

STATE OF CALIFORNIA DEPARTMENT OF WATER RESOURCES And SAN DIEGO GAS & ELECTRIC COMPANY

THIS AGREEMENT HAS BEEN FILED WITH AND APPROVED BY THE CALIFORNIA PUBLIC UTILITIES COMMISSION (“COMMISSION”) FOR USE BETWEEN THE STATE OF CALIFORNIA DEPARTMENT OF WATER RESOURCES (“DWR”) AND SAN DIEGO GAS & ELECTRIC COMPANY (“UTILITY”).

Execution Date: April 16 , 2003 Date of Commission Approval:

Effective Date:

OPERATING AGREEMENT This OPERATING AGREEMENT (this “Agreement”) is between the State of California Department of Water Resources (“DWR”), acting solely under the authority and powers granted by AB1X, codified as Sections 80000 through 80270 of the Water Code, and not under its powers and responsibilities with respect to the State Water Resources Development System, and San Diego Gas & Electric Company, a California corporation (“Utility”). DWR and Utility are sometimes collectively referred to herein as the “Parties” and individually referred to as a “Party.” Unless otherwise noted, all capitalized terms shall have the meanings set forth in Article I of this Agreement.

R E C I T A L S

WHEREAS, under the Act, DWR has entered into a number of long- term power purchase agreements for the purpose of providing the net short requirements to the retail ratepayers of the State’s electrical corporations, including Utility; and

WHEREAS, the Contract Allocation Order of the Commission provides that such long-term power purchase agreements are to be operationally allocated among the State’s electrical corporations, including Utility; solely for the purpose of causing the State’s electrical corporations to perform certain specified functions on behalf of DWR, as DWR’s limited agent, including dispatching, scheduling, billing and settlements functions, and to sell surplus energy, all as such functions relate to those certain power purchase agreements that are operationally allocated to each electrical corporation under the Contract Allocation Order; and

WHEREAS, DWR wishes to provide for the performance of such functions under the Allocated Contracts by Utility on behalf of DWR in accordance with such long-term power purchase agreements as provided in this Agreement; and

WHEREAS, consistent with the Contract Allocation Order, DWR will retain legal and financial obligations, together with ongoing responsibility for any other functions not explicitly provided in this Agreement to be performed by Utility, with respect to each of the Allocated Contracts and it is the intent of DWR and the Utility that the provisions of this Agreement will not constitute an “assignment” of the Allocated Contracts to Utility.

NOW, THEREFORE, in consideration of the mutual obligations of the Parties, the Parties agree as follows:

ARTICLE I
DEFINITIONS

Section 1.01. Definitions. The following terms shall have the respective meanings in this Agreement:

The following terms, when used herein (and in the attachments hereto) with initial capitalization, shall have the meaning specified in this Section 1.01. Certain additional terms are defined in the attachments hereto. The singular shall include the plural and the masculine shall include the feminine and neuter, and vice versa. “Includes” or “including” shall mean “including without limitation.” References to a section or attachment shall mean a section or attachment of this Agreement, as the case may be, unless the context requires otherwise, and reference to a given agreement or instrument shall be a reference to that agreement or instrument as modified, amended, supplemented or restated through the date as of which such reference is made (except as otherwise specifically provided herein). Unless the context otherwise requires, references to Applicable Laws or Applicable Tariffs shall be deemed references to such laws or tariffs as they may be amended, replaced or restated from time to time. References to the time of day shall be deemed references to such time as measured by prevailing Pacific time.

“Act” means Chapter 4 of Statutes of 2001 (Assembly Bill 1 of the First 2001-02 Extraordinary Session) of the State of California, as amended.

“Agreement”, means this Operating Agreement, together with all attached Schedules, Exhibits and Attachments, as such may be amended from time to time as evidenced by a written amendment executed by the Parties.

“Allocated Contracts” means the long-term power purchase agreements operationally allocated to Utility under the Contract Allocation Order, without legal and financial assignment of such agreements to Utility, as provided in Schedule 1 attached hereto.

“Allocated Power” means all power and energy, including the use of such power or energy as ancillary services, delivered or to be delivered under the Contracts.

“Applicable Commission Orders” means such rules, regulations, decisions, opinions or orders as the Commission may lawfully issue or promulgate from time to time, which relate to the subject matter of this Agreement.

“Applicable Law” means the Act, Applicable Commission Orders and any other applicable statute, constitutional provision, rule, regulation, ordinance, order, decision or code of a Governmental Authority.

“Applicable Tariffs” means Utility’s tariffs, including all rules, rates, schedules and preliminary statements, governing electric energy service to Utility’s customers in its service territory, as filed with and approved by the Commission and, if applicable, the Federal Energy Regulatory Commission.

“Assign(s)” shall have the meaning set forth in Section 14.01.

“Bonds” shall have the meaning set forth in the Rate Agreement.

“Bond Charges” shall have the meaning set forth in the Rate Agreement.

“Business Day” means the regular Monday through Friday weekdays which are customary working days, excluding holidays, as established by Applicable Tariffs.

“Commission” means the California Public Utilities Commission.

“Confidential Information” shall have the meaning set forth in
Section 11.01(c).

“Contracts” means the Allocated Contracts.

“Contract Allocation Order” means Decision 02-09-053 of the Commission, issued on September 19, 2002, as such Decision may be modified, revised, amended, supplemented or superseded from time to time by the Commission.

“DWR Power” shall have the same meaning set forth in the Servicing Arrangement with such amendments to incorporate the Settlement Principles for Remittances and Surplus Revenues as provided in Exhibit C of this Agreement.

“DWR Revenues” means those amounts required to be remitted to DWR by Utility in accordance with this Agreement and as further provided in the Servicing Arrangement.

“Effective Date” means the effective date in accordance with
Section 14.13, as such date is set forth on the cover page hereof.

“Fund” means the Department of Water Resources Electric Power Fund established by Section 80200 of the California Water Code.

“Good Utility Practice” means any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice does not require the optimum practice, method, or act to the exclusion of all others, but rather is intended to include acceptable practices, methods, or acts generally accepted in the Western Electric Coordinating Council region.

“Governmental Authority” means any nation or government, any state or other political subdivision thereof, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to a government, including the Commission.

“Governmental Program” means any program or directive established by Applicable Law which directly or indirectly affects the rights or obligations of the Parties under this Agreement and which obligates or authorizes DWR to make payments or give credits to customers or other third parties under such programs or directives.

“ISO” means the California Independent System Operator Corporation.

“Order” means Decision 02-12-069 of the Commission, issued on December 19, 2002 as such decision may be amended or supplemented from time to time by the Commission.

“Power Charges” shall have the meaning set forth in the Rate Agreement.

“Priority Long Term Power Contract” shall have the meaning set forth in the Rate Agreement.

“Rate Agreement” means the Rate Agreement between DWR and the Commission adopted by the Commission on February 21, 2001 in Decision 02-02-051.

“Remittance” means a payment by Utility to DWR or its Assign(s) in accordance with the Servicing Arrangement.

“Servicing Arrangement” means the First Amended and Restated Servicing Agreement, dated March 29, 2002, between DWR and Utility, as amended.

“Supplier” means those certain third parties who are supplying power pursuant to the Contracts.

“Term” means term provided in Section 2.05 hereof.

“URG” means utility-retained generation, including without limitation Utility’s portfolio of generation resources and power purchase agreements prior to or after the Effective Date by Utility.

Section 1.02. Undefined Terms. Capitalized terms not otherwise defined in Section 1.01 herein shall have the meanings set forth in the Act or the Servicing Arrangement.

ARTICLE II
OPERATIONAL ALLOCATION OF POWER PURCHASE AGREEMENTS; MANAGEMENT OF THE CONTRACTS; ALLOCATED POWER; TERM

Section 2.01. Operational Allocation and Management of Power Purchase Agreements. On behalf of DWR, as its limited agent, Utility will perform certain day-to-day scheduling and dispatch functions, billing and settlements and surplus energy sales and certain other tasks with respect to the Allocated Contracts, as more fully set forth in this Agreement.

As further provided in Contract Administration and Performance Test Monitoring Protocols set forth in Exhibit E, DWR will continue to monitor and audit the Supplier performance under the Contracts. Upon development of a mutually agreeable plan, Utility will monitor the performance of Suppliers, as further provided in Exhibit E, subject, however, to DWR’s right but not the obligation to audit and monitor all functions contemplated to be performed by Utility, all as further provided in this Agreement.

Section 2.02. Standard of Contract Management.

(a) Utility agrees to perform the functions specified in this Agreement relating to the Allocated Contracts in a commercially reasonable manner, exercising Good Utility Practice, and in a fashion reasonably designed to serve the overall best interests of retail electric customers. Utility shall provide to DWR such information specifically provided in Exhibit F hereto to facilitate DWR’s verification of Utility’s compliance with this Section 2.02. In addition, the Parties acknowledge that DWR is not subject to the Commission’s jurisdiction, and the Parties agree that none of the provisions of this Agreement, including Section 13.04 herein, shall be interpreted to subject DWR to the Commission’s jurisdiction or authority.

(b) To the extent requested by Utility, DWR shall provide evidence in Commission proceedings describing Utility’s and DWR’s performance, rights and obligations under this Agreement.

(c) DWR acknowledges the Commission’s exclusive authority over whether the Utility has managed Allocated Power available under the Contracts in a just and reasonable manner and DWR and Utility agrees that none of the provisions of this Agreement shall be interpreted to reduce, diminish, or otherwise limit the scope of any Commission authority or to give DWR any authority over such matters.

(d) The Utility acknowledges DWR’s separate and independent right to evaluate and enforce Utility’s commercial performance under this Agreement.

(g) Utility agrees to provide any information not otherwise required herein that is reasonably necessary to allow DWR to exercise its rights in subsection (d) above, provided that all such information shall be used solely for the purposes of exercising such rights.

Section 2.03. Good Faith. Each Party hereby covenants that it shall perform its actions, obligations and duties in connection with this Agreement in good faith.

Section 2.04. DWR Power. During the term of this Agreement, the electric power and energy, including but not limited to capacity, and output, or any of them from the Contracts delivered to retail end-use customers in Utility’s service area shall constitute DWR Power for all purposes of the Servicing Arrangement. Utility shall arrange for transmission service to accommodate surplus sales to the extent that transmission service is available and cost effective, all as further provided in Exhibit A.

Section 2.05. Term.

(a) The Term of this Agreement shall commence on the Effective Date and shall terminate on the earlier of (a) the termination of the Servicing Arrangement, or (b) the termination of this Agreement by DWR upon ninety days’ written notice to Utility, or
(c) upon consultation with the Commission, the termination of the Agreement by DWR upon reasonable written notice to Utility no shorter than 30 days, or (d) pursuant to Article VII hereof, the termination of this Agreement by a non-defaulting Party after an Event of Default. In addition, this Agreement will terminate as to each Contract that terminates in accordance with its terms. DWR agrees to notify Utility as to the termination of each Contract as provided in Section 5.01(e) hereof.

(b) If an event occurs which has the effect of materially altering and materially adversely impacting the economic position of the Parties or either of them under this Agreement, then the affected Party may, by written notice, request that the Commission approve amendments to this Agreement or other arrangements incidental to this Agreement as necessary to preserve or restore the economic position under this Agreement held by the affected Party immediately prior to such event. Such notice shall describe the event and shall include reasonable particulars as to the manner and extent to which the economic position of the party giving notice has been adversely affected.

ARTICLE III
LIMITED AGENCY / NO ASSIGNMENT

Section 3.01. Limited Agency. Utility is hereby appointed as DWR’s agent for the limited purposes set forth in this Agreement. Utility shall not be deemed to be acting, and shall not hold itself out, as agent for DWR for any purpose other than those described in this Agreement. Utility’s duties and obligations shall be limited to those duties and obligations that are specified in this Agreement.

Section 3.02. No Assignment. DWR shall remain legally and financially responsible for performance under each of the Contracts and shall retain liability to the counterparty for any failure of Utility to perform the functions referred to in this Agreement on behalf of DWR as its limited agent, under such Contracts in accordance with the terms thereof. It is the intent of DWR and Utility that the provisions of this Agreement shall not constitute or result in an “assignment” of the Allocated Contracts in any respect.

ARTICLE IV
LIMITED DUTIES OF UTILITY

Section 4.01. Limited Duties of Utility as to the Contracts. During the Term of this Agreement, Utility shall:

(a) On behalf of DWR, as its limited agent, perform the day-to- day scheduling and dispatch functions, including day-ahead, hour- ahead and real time trading, scheduling transactions with all involved parties, under the Allocated Contracts, perform billing and settlements functions and obtain relevant information for these functions such as transmission availability and others, with respect to the Allocated Contracts set forth in Schedule 1 hereto, all as more specifically provided in the Operating Protocols attached hereto as Exhibit A;

(b) On behalf of DWR, as its limited agent, enter into transactions for the purchase (or sale, as the case may be) of gas, gas transmission services, gas storage services and financial hedges, and perform the operational and administrative responsibilities for such purchases under gas tolling provisions under the Allocated Contracts, including the review of fuel plans and consideration of alternative fuel supply, all as more specifically provided in the Fuel Management Protocols attached hereto as Exhibit B;

(c) On behalf of DWR, as its limited agent, perform all necessary billing and settlement functions under the Allocated Contracts, in accordance with the terms of the applicable Contracts. In addition, perform all necessary billing and settlement functions related to DWR Revenues and remit DWR Revenues to DWR, consistent with the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C and the Servicing Arrangement;

(d) Assume financial responsibility for the ISO charges listed on Exhibit D attached hereto;

(e) On behalf of DWR, as its limited agent, upon development of a mutually agreeable plan, monitor the performance of Suppliers under the Allocated Contracts and undertake the administration of the Allocated Contracts, as more specifically provided in the Contract Administration and Performance Monitoring Protocols attached hereto as Exhibit E;

(f) Provide to DWR the necessary information required by DWR as more specifically provided in the DWR Data Requirements From Utility attached hereto as Exhibit F to facilitate DWR’s continued performance of financial obligations related to Allocated Contracts and to facilitate DWR’s verification, audit and monitoring related to the Allocated Contracts and reporting requirements set forth in Applicable Laws or agreements;

(g) At all times in performing its obligations under this Agreement (i) comply with the provisions of each of the Allocated Contracts, (ii) follow Good Utility Practice, and (iii) comply with all Applicable Laws and Applicable Commission Orders;

(h) Appoint a primary and secondary contact person, as set forth in Schedule 2 hereto, to coordinate the responsibilities listed in this Section 4.01; and

(i) On behalf of DWR, as its limited agent, make surplus energy sales as more specifically provided in this Agreement. Provided, however, in the event that DWR fails to provide or provides inaccurate information which results in Utility’s non- compliance with its obligations under this Agreement, the resulting non-compliance by Utility shall not constitute an Event of Default under Section 7.01 hereof.

Section 4.02. Dispatch or Sale of Allocated Power. Subject to any existing or new ISO tariff provisions that may affect the dispatch of such Contracts, Allocated Power from all Contracts shall be dispatched or sold, as the case may be, by Utility pursuant to the Operating Protocols attached hereto as Exhibit A.

Section 4.03. DWR Revenues. DWR Revenues shall be accounted and remitted to DWR consistent with the principles provided in the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C and the provisions of the Servicing Arrangement. Unless otherwise specifically provided in this Agreement, Utility will not be required at any time to advance or pay any of its own funds in the fulfillment of its responsibilities under this Agreement.

Section 4.04. Ownership of Allocated Power. Notwithstanding any other provision herein, and in accordance with the Act and Section 80110 of the California Water Code, Utility and DWR agree that DWR shall retain title to all Allocated Power, including DWR Power. In accordance with the Act and Section 80104 of the California Water Code, upon the delivery of Allocated Power to Utility’s customers, those customers shall be deemed to have purchased that power from DWR, and payment for such sale shall be a direct obligation of such customer to DWR. In addition, Utility and DWR agree that DWR shall retain title to any surplus Allocated Power sold by Utility as limited agent to DWR as provided in this Agreement.

ARTICLE V
DUTIES OF DWR

Section 5.01. Duties of DWR. Consistent with the Contract Allocation Order, during the Term of this Agreement, DWR shall:

(a) Remain legally and financially responsible under each of the Contracts and cooperate with Utility in the transition from DWR to Utility the performance of the functions provided in this Agreement;

(b) Assume legal and financial responsibilities and enter into or facilitate Utility’s entering into transactions as DWR’s limited agent, for the purchase (or sale, as the case may be) of gas, gas transmission services, gas storage services and financial hedges, and timely consent to or approve the Utility’s performance of the operational and administrative responsibilities for such purchases under gas tolling provisions under the Allocated Contracts, including the review of fuel plans and consideration of alternative fuel supply, all as more specifically provided in the Fuel Management Protocols attached hereto as Exhibit B;

(c) Pay invoices to the Suppliers and perform all necessary verification, audit and monitoring of the billing and settlement functions to be performed on DWR’s behalf, as its limited agent, by Utility relating to the Contracts. In addition, perform all necessary verification, audit and monitoring of the billing and settlement functions to be performed on DWR’s behalf, as its limited agent, by Utility related to DWR Revenues, consistent with the principles set forth in the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C;

(d) Until such time as a mutually agreed upon plan may be entered into with Utility and approved by the Commission, and no earlier than January 1, 2004, continue to monitor the performance of Suppliers and conduct certain contract administration duties under the Allocated Contracts, all as more specifically provided in the Contract Administration and Performance Monitoring Protocols attached hereto as Exhibit E. In addition, continue to perform all other administrative functions related to Contracts not explicitly provided in this Agreement to be performed by Utility on behalf of DWR, as its limited agent;

(e) Upon the termination of any Contract, submit in writing to Utility appropriate Schedules and Attachments to Exhibit A amended to reflect the termination of any Contract. Such amended Schedules and Attachments shall become effective only upon the effective date of the termination of such Contract. Provided, however, rights or obligations of the Parties that arise or relate to Utility’s performance of its duties under this Agreement in respect of any terminated Contract shall survive until the expiration of any such right or obligation; and

(f) Appoint a primary and secondary contact person, as set forth in Schedule 2 hereto, to coordinate the responsibilities listed in this Section 5.01.

ARTICLE VI
[RESERVED]

Section 6.01. [Intentionally left blank.]

ARTICLE VII`
EVENTS OF DEFAULT

Section 7.01. Events of Default. The following events shall constitute “Events of Default” under this Agreement:

(a) any material failure by a Party to pay any amount due and payable under this Agreement that continues unremedied for five
(5) Business Days after the earlier of the day the defaulting Party receives written notice thereof from the non-defaulting Party; or

(b) any material failure by Utility to schedule and dispatch Contracts, consistent with the principles set forth in Exhibit A; or

(c) any failure (except as provided in (a) or (b)) by a Party to duly observe or perform in any material respect any other covenant or agreement of such Party set forth in this Agreement, which failure continues unremedied for a period of 15 calendar days after written notice of such failure has been given to such Party by the non-defaulting Party; or

(d) any material representation or warranty made by a Party shall prove to be false, misleading or incorrect in any material respect as of the date made; or

(e) an Event of Default (as defined under the Servicing Arrangement) shall have occurred and is continuing under the Servicing Arrangement.

Section 7.02. Consequences of Utility Event of Default. Upon any Event of Default by Utility, DWR may, in addition to exercising any other remedies available under this Agreement or under Applicable Law,
(i) terminate this Agreement in whole or in part; and (ii) apply in an appropriate forum for sequestration and payment to DWR or its Assign(s) of DWR Revenues or for specific performance of the functions related to the Contracts to be performed by Utility on behalf of DWR, as its limited agent, as provided in this Agreement.

Section 7.03. Consequences of DWR Event of Default. Upon an Event of Default by DWR (other than an Event of Default under 7.01(a)), Utility shall request that the Commission terminate this Agreement in whole or in part, Section 2.05 notwithstanding.

Section 7.04. Remedies. Subject to Article XIII of this Agreement, upon any Event of Default, the non-defaulting Party may exercise any other legal or equitable right or remedy that may be available to it under applicable law or under this Agreement.

Section 7.05. Remedies Cumulative. Except as otherwise provided in this Agreement, all rights of termination, cancellation, or other remedies in this Agreement are cumulative. Use of any remedy shall not preclude any other remedy available under this Agreement.

Section 7.06. Waivers. None of the provisions of this Agreement shall be considered waived by either Party unless the Party against whom such waiver is claimed gives such waiver in writing. The failure of either Party to insist in any one or more instances upon strict performance of any of the provisions of this Agreement or to take advantage of any of its rights hereunder shall not be construed as a waiver of any such provisions or the relinquishment of any such rights for the future, but the same shall continue and remain in full force and effect. Waiver by either Party of any default by the other Party shall not be deemed a waiver of any other default.

ARTICLE VIII
PAYMENT OF FEES AND CHARGES

Section 8.01. Utility Fees and Charges. As noted in the Contract Allocation Order, the details of the amount and recovery of administrative costs to Utility associated with the Contracts are expected to be considered in another Commission proceeding. As such, the Parties agree that the administrative costs to Utility will be recovered pursuant to such Commission proceeding. Utility shall enter the cost of such fees and charges in its Purchased Electric Commodity Account, or its successor or another account designated by the Commission on a current basis, for recovery in retail rates subject to subsequent Commission review.

ARTICLE IX
REPRESENTATIONS AND WARRANTIES

Section 9.01. Representations and Warranties.
(a) Each person executing this Agreement for the respective Parties expressly represents and warrants that he or she has authority to bind the Party on whose behalf he or she has executed this Agreement.

(b) Each Party represents and warrants that it has the full power and authority to execute and deliver this Agreement and to perform its terms, that execution, delivery and performance of this Agreement have been duly authorized by all necessary corporate or other action by such Party, and that this Agreement constitutes such Party’s legal, valid and binding obligation, enforceable against such Party in accordance with its terms.

(c) DWR represents and warrants that all necessary and appropriate notices, inducements, undertakings, approvals, and consents have been obtained from each Supplier to the Contract allocated to Utility in order for Utility to undertake its duties set forth in this Agreement in a timely and appropriate fashion.

ARTICLE X
LIMITATIONS ON LIABILITY

Section 10.01. Consequential Damages. In no event will either Party be liable to the other Party for any indirect, special, exemplary, incidental, punitive, or consequential damages under any theory. Nothing in this Section 10.01 shall limit either Party’s rights as provided in Article VII above.

Section 10.02. Limited Obligations of DWR. Any amounts payable by DWR under this Agreement shall be payable solely from moneys on deposit in the Department of Water Resources Electric Power Fund established pursuant to Section 80200 of the California Water Code (the “Fund”).

Section 10.03. Sources of Payment; No Debt of State. DWR’s obligation to make payments hereunder shall be limited solely to the Fund and shall be payable as an operating expense of the Fund solely from Power Charges subject and subordinate to each Priority Long Term Power Contract in accordance with the priorities and limitations established with respect to the Fund’s operating expenses in any indenture providing for the issuance of Bonds and in the Rate Agreement and in the Priority Long Term Power Contracts. Any liability of DWR arising in connection with this Agreement or any claim based thereon or with respect thereto, including, but not limited to, any payment arising as the result of any breach or Event of Default under this Agreement, and any other payment obligation or liability of or judgment against DWR hereunder, shall be satisfied solely from the Fund.
NEITHER THE FULL FAITH AND CREDIT NOR THE TAXING POWER OF THE STATE OF CALIFORNIA ARE OR MAY BE PLEDGED FOR ANY PAYMENT UNDER THIS AGREEMENT. Revenues and assets of the State Water Resources Development System, and Bond Charges under the Rate Agreement, shall not be liable for or available to make any payments or satisfy any obligation arising under this Agreement. If moneys on deposit in the Fund are insufficient to pay all amounts payable by DWR under this Agreement, or if DWR has reason to believe such funds may become insufficient to pay all amounts payable by DWR under this Agreement, DWR shall diligently pursue an increase to its revenue requirements as permitted under the Act from the appropriate Governmental Authority as soon as practicable. To the extent DWR’s obligations are “administrative costs,” they will require annual appropriation by the legislature.

Section 10.04. Cap on Liability. In no event will Utility be liable to DWR for damages under this Agreement, including indemnification obligations, whether in contract, warranty, tort (including negligence), strict liability or otherwise (referred to as “Damages” for purposes of this Section), in an amount in excess of: 1) on an annual calendar year basis, $5 million plus ten percent of Damages in excess of $5 million and 2) for the entire term of this Agreement, $50 million in total payments of Damages to DWR. For example, if Damages for an event are $100 million, Utility’s total liability for this event would be $14.5 million ($5 million plus10% of $95 million) and that would be the full extent of Utility’s liability for such Damages. All Damages associated with an event will apply only to the annual limit in the first year in which Damages for that event were assessed. For example, if Damages for an event were paid as follows: $15 million in year 1 and $10 million in year 2, the Utility would pay DWR $7 million ($5 million plus10% of $10 million for year 1 and 10% of $10 million for year 2). In this example, the $1 million paid to DWR in year 2 (10% of $10 million) does not count against the year 2 $5 million calendar year threshold. DWR hereby releases Utility from any liability for Damages in excess of the limitations on liability set forth in this Section 10.04, provided however, that this limitation on Utility liability shall not apply to the extent the liability is a result of Utility’s gross negligence or willful misconduct.

ARTICLE XI
CONFIDENTIALITY

Section 11.01. Proprietary Information.
(a) Nothing in this Agreement shall affect Utility’s obligations to observe any Applicable Law prohibiting the disclosure of Confidential Information regarding its customers.

(b) Nothing in this Agreement, and in particular nothing in Sections 11.01(e)(x) through 11.01(e)(z) of this Agreement, shall affect the rights of the Commission to obtain from Utility, pursuant to Applicable Law, information requested by the Commission, including Confidential Information provided by DWR to Utility. Applicable Law, and not this Agreement, will govern what information the Commission may disclose to third parties, subject to any confidentiality agreement between DWR and the Commission.

(c) The Parties acknowledge that each Party may acquire information and material that is the other Party’s confidential, proprietary or trade secret information. As used herein, “Confidential Information” means any and all technical, commercial, financial and customer information disclosed by one Party to the other (or obtained from one Party’s inspection of the other Party’s records or documents), including any patents, patent applications, copyrights, trade secrets and proprietary information, techniques, sketches, drawings, maps, reports, specifications, designs, records, data, models, inventions, know- how, processes, apparati, equipment, algorithms, software programs, software source documents, object code, source code, and information related to the current, future and proposed products and services of each of the Parties, and includes, without limitation, the Parties’ respective information concerning research, experimental work, development, design details and specifications, engineering, financial information, procurement requirements, purchasing, manufacturing, business forecasts, sales and merchandising, and marketing plans and information. In all cases, Confidential Information includes proprietary or confidential information of any third party disclosing such information to either Party in the course of such third party’s business or relationship with such Party. Utility’s Confidential Information also includes any and all lists of customers, and any and all information about customers, both individually and aggregated, including but not limited to customers’ names, street addresses of customer residences and/or facilities, email addresses, identification numbers, Utility account numbers and passwords, payment histories, energy usage, rate schedule history, allocation of energy uses among customer residences and/or facilities, and usage of DWR Power. All Confidential Information disclosed by the disclosing Party (“Discloser”) will be considered Confidential Information by the receiving Party (“Recipient”) if identified as confidential and received from Discloser.

(d) Each Party agrees to take all steps reasonably necessary to hold in trust and confidence the other Party’s Confidential Information. Without limiting the generality of the immediately preceding sentence, each Party agrees (i) to hold the other Party’s Confidential Information in strict confidence, not to disclose it to third parties or to use it in any way, commercially or otherwise, other than as permitted under this Agreement; and (ii) to limit the disclosure of the Confidential Information to those of its employees, agents or directly related subcontractors with a need to know who have been advised of the confidential nature thereof and who have acknowledged their express obligation to maintain such confidentiality. DWR shall not disclose Confidential Information to employees, agents or subcontractors that are in any respect responsible for power marketing or trading activities associated with the State Water Resources Development System.

(e) The foregoing two paragraphs will not apply to any item of Confidential Information if: (i) it has been published or is otherwise readily available to the public other than by a breach of this Agreement; (ii) it has been rightfully received by Recipient from a third party without breach of confidentiality obligations of such third party and outside the context of the provision of services under this Agreement; (iii) it has been independently developed by Recipient personnel having no access to the Confidential Information; (iv) it was known to Recipient prior to its first receipt from Discloser, or (v) it has been summarized, processed and incorporated for incorporation into reports, discussions, statements or any other further work product. In addition, Recipient may disclose Confidential Information if and to the extent required by law or a Governmental Authority, provided that (x) Recipient shall give Discloser a reasonable opportunity to review and object to the disclosure of such Confidential Information, (y) Discloser may seek a protective order or confidential treatment of such Confidential Information, and (z) Recipient shall make commercially reasonable efforts to cooperate with Discloser in seeking such protective order or confidential treatment. Discloser shall pay Recipient its reasonable costs of cooperating.

Section 11.02. No License. Nothing contained in this Agreement shall be construed as granting to a Party a license, either express or implied, under any patent, copyright, trademark, service mark, trade dress or other intellectual property right, or to any Confidential Information now or hereafter owned, obtained, controlled by, or which is or may be licensable by, the other Party.

Section 11.03. Survival of Provisions. The provisions of this Article XI shall survive the termination of this Agreement.

ARTICLE XII
RECORDS AND AUDIT RIGHTS

Section 12.01. Records. Utility shall maintain accurate records and accounts relating to the Contracts in sufficient detail to permit DWR to audit and monitor the functions to be performed by Utility on behalf of DWR, as its limited agent, under this Agreement. In addition, Utility shall maintain accurate records and accounts relating to DWR Revenues to be remitted by Utility to DWR, consistent with the Settlement Principles for Remittances and Surplus Revenues set forth in Exhibit C hereto. Utility shall provide to DWR and its Assign(s) access to such records. Access shall be afforded without charge, upon reasonable request made pursuant to Section 12.02. Access shall be afforded only during Business Hours and in such a manner so as not to interfere unreasonably with Utility’s normal operations. Utility shall not treat DWR Revenues as income or assets of Utility or any affiliate for any tax, financial reporting or regulatory purposes, and the financial books or records of Utility and affiliates shall be maintained in a manner consistent with the absolute ownership of DWR Revenues by DWR and Utility’s holding of DWR Revenues in trust for DWR (whether or not held together with other monies).

Section 12.02. Audit Rights.
(a) Upon 30 calendar days’ prior written notice, DWR may request an audit, conducted by DWR or its agents (at DWR’s expense), of Utility’s records and procedures, which shall be limited to records and procedures containing information bearing upon Utility’s performance of its obligations under this Agreement. The audit shall be conducted during Business Hours without interference with Utility’s normal operations, and in compliance with Utility’s security procedures.

(b) As provided in the Act, the State of California Bureau of State Audits (the “Bureau”) shall conduct a financial and performance audit of DWR’s implementation of Division 27 (commencing with Section 80000) of the California Water Code, and the Bureau shall issue a final report on or before March 31, 2003. In addition, as provided in Section 8546.7 of the California Government Code, Utility agrees that, pursuant to this
Section 12.02, DWR or the State of California Department of General Services, the Bureau, or their designated representative (“DWR’s Agent”) shall have the right to review and to copy (at DWR’s expense) any non-confidential records and supporting documentation pertaining to the performance of this Agreement and to conduct an on-site review of any Confidential Information pursuant to Section 12.03 hereof. Utility agrees to maintain such records for such possible audit for three years after final Remittance to DWR. Utility agrees to allow such auditor(s) access to such records during Business Hours and to allow interviews of any employees who might reasonably have information related to such records. Further, Utility agrees to include a similar right for DWR or DWR’s Agent to audit records and interview staff in any contract between Utility and a subcontractor directly related to performance of this Agreement.

Section 12.03. Confidentiality. Materials reviewed by either Party or its agents in the course of an audit may contain Confidential Information subject to Article XI above. The use of all materials provided to DWR or Utility or their agents, as the case may be pursuant to this Article XII, shall comply with the provisions in Article XI and shall be limited to use in conjunction with the conduct of the audit and preparation of a report for appropriate distribution of the results of the audit consistent with Applicable Law.

Section 12.04. Annual Certifications. At least annually, and in no event later than the tenth Business Day after the end of the calendar year, Utility shall deliver to DWR a certificate of an authorized representative certifying that to the best of such representative’s knowledge, after a review of Utility performance under this Agreement, Utility has fulfilled its obligations under this Agreement in all material respects and is in compliance herewith in all material respects.

Section 12.05. Additional Applicable Laws. Each Party shall make an effort to promptly notify the other Party in writing to the extent such Party becomes aware of any new Applicable Laws or changes (or proposed changes) in Applicable Tariffs hereafter enacted, adopted or promulgated that may have a material adverse effect on either Party’s ability to perform its duties under this Agreement. A Party’s failure to so notify the other Party pursuant to this Section 12.05 will not constitute a material breach of this Agreement, and will not give rise to any right to terminate this Agreement or cause either Party to incur any liability to the other Party or any third party.

Section 12.06. Other Information. Upon the reasonable request of DWR or its Assign(s), Utility shall provide to DWR or its Assign(s) any public financial information in respect of Utility applicable to services provided by Utility under this Agreement, to the extent such information is reasonably available to Utility, which (i) is reasonably necessary and permitted by Applicable Law to monitor the performance by Utility hereunder, or (ii) otherwise relates to the exercise of DWR’s rights or the discharge of DWR’s duties under this Agreement or any Applicable Law. In particular, but without limiting the foregoing, Utility shall provide to DWR any such information that is necessary or useful to calculate DWR’s revenue requirements (as described in Sections 80110 and 80134 of the California Water Code).

Section 12.07. Data and Information Retention. All data and information associated with the provision and receipt of services pursuant to this Agreement shall be maintained for the greater of (a) the retention time required by Applicable Law or Applicable Tariffs for maintaining such information, or (b) three (3) years.

ARTICLE XIII
DISPUTE RESOLUTION

Section 13.01. Dispute Resolution. Should any dispute arise between the Parties or should any dispute between the Parties arise from the exercise of either Party’s audit rights contained in Section 12.02 hereof, the Parties shall remit any undisputed amounts and agree to enter into good faith negotiations as soon as practicable to resolve such disputes within (10) Business Days so as to resolve such disputes, as appropriate, within the timeframes provided under this Agreement, or as soon as possible thereafter. For any disputed Remittances, if such resolution cannot be made before the remittance date, Utility shall remit the undisputed portion to DWR. In addition, the disputed portion of the Remittances shall be deposited into an escrow account held by a qualified, independent escrow holder. Upon resolution of such disputes, the Party that escrowed the disputed amount shall reimburse the other Party from the escrow account as necessary.

Section 13.02. ISO Settlements Disputes. Utility shall review, validate and verify all ISO charges/credits contained on all ISO settlement statements, including any charges/credits resulting from functions related to the Contracts to be performed by Utility as provided in this Agreement. Utility shall inform DWR of any discrepancies and shall dispute any such discrepancies with the ISO in accordance with the ISO’s tariff and protocols. Except as provided in
Section 13.03, if any ISO charge type settlement amount appearing on a Preliminary or Final Settlement Statement (as defined in the ISO tariff) resulting or relating to the Utility’s performance of functions related to the Contracts under this Agreement is in dispute, it shall be the responsibility of Utility, on behalf of DWR, as its limited agent, to seek resolution of said dispute through the ISO dispute resolution process as provided in the ISO’s tariff.

For disputes affecting Utility’s Remittances to DWR, including disputes on ISO charges to non-DWR parties that would affect Remittances to DWR, Utility shall provide to DWR: a) notification of submission of the dispute through the ISO dispute resolution process, identifying, among other items, the dispute type, quantity, price and allocation; b) a copy of the submitted dispute and all supporting data; and c) a copy of all ensuing documentation resulting from the ongoing dispute resolution process. Utility shall track and validate all disputed ISO charges involving any financial responsibility of DWR.

Section 13.03. Supplier Invoice Disputes. DWR shall continue to be responsible for all dispute resolution relating to Supplier invoices. In addition, except as specifically provided in Exhibit E of this Agreement, all other contract administration functions shall remain DWR’s responsibility.

Section 13.04. Good-Faith Negotiations. Should any dispute arise between the Parties relating to this Agreement, the Parties shall undertake good-faith negotiations to resolve such dispute. If the Parties are unable to resolve such dispute through good-faith negotiations, either Party may submit a detailed written summary of the dispute to the other Party. Upon such written presentation, each Party shall designate an executive with authority to resolve the matter in dispute. If the Parties are unable to resolve such dispute within 30 days from the date that a detailed summary of such dispute is presented in writing to the other Party, then either Party may, at its sole discretion, submit the dispute to the Commission for resolution, in accordance with Applicable Law. Nothing herein shall preclude either Party from challenging the decision or action which such Party deems may adversely affect its interests in any appropriate forum of the Party’s choosing.

Section 13.05. Costs. Each Party shall bear its own respective costs and attorney fees in connection with respect to any dispute resolution process undertaken by it pursuant to this Article. Provided, however, DWR shall reimburse Utility all reasonably incurred costs, including, but not limited to, in-house and retained attorneys, consultants, witnesses, and arbitration costs, arising from or pertaining to all disputes relating to ISO charges/credits contained on all ISO settlement statements resulting from the operational, dispatch and administrative functions related to the Contracts performed by Utility on behalf of DWR, as its limited agent, pursuant to the standards set forth in Section 2.02 herein and consistent with the provisions of the ISO tariff, as may be amended from time to time, including disputes on ISO charges to non-DWR parties that would affect Remittances to DWR. These costs shall be recorded and invoiced in the manner set forth in Section 8.01 hereof.

ARTICLE XIV
MISCELLANEOUS

Section 14.01. Assignment
(a) Except as provided in paragraphs (b) and (c) below, neither Party shall assign or otherwise dispose of this Agreement, its right, title or interest herein or any part hereof to any part hereof to any entity, without the prior written consent of the other Party. No assignment of this Agreement shall relieve the assigning Party of any of its obligations under this Agreement until such obligations have been assumed by the assignee. When duly assigned in accordance with this Section 14.01(a) and when accepted by the assignee, this Agreement shall be binding upon and shall inure to the benefit of the assignee. Any assignment in violation of this Section 14.01(a) shall be void.

(b) Utility acknowledges and agrees that DWR may assign or pledge its rights to receive performance hereunder to a trustee or another party (“Assign(s)”) in order to secure DWR’s obligations under its bonds (as that term is defined in the Act), and any such Assign shall be a third party beneficiary of this Agreement; provided, however, that this authority to assign or pledge rights to receive performance hereunder shall in no event extend to any person or entity that sells power or other goods or services to DWR.

(c) Any person (i) into which Utility may be merged or consolidated, (ii) which may result from any merger or consolidation to which Utility shall be a party or (iii) which may succeed to the properties and assets of Utility substantially as a whole, which person in any of the foregoing cases executes an agreement of assumption to perform every obligation of Utility hereunder, shall be the successor to Utility under this Agreement without further act on the part of any of the Parties to this Agreement; provided, however, that Utility shall have delivered to DWR and DWR its Assign(s) an opinion of counsel reasonably acceptable to DWR stating that such consolidation, merger or succession and such agreement of assumption complies with this
Section 13.01(c) and that all of Utility’s obligations hereunder have been validly assumed and are binding on any such successor or assign.

(d) Notwithstanding anything to the contrary herein, DWR’s rights and obligations hereunder shall be transferred, without any action or consent of either Party hereto, to any entity created by the State legislature which is required under Applicable Law to assume the rights and obligations of DWR under Division 27 of the California Water Code.

Section 14.02. Force Majeure. Neither Party shall be liable for any delay or failure in performance of any part of this Agreement
(including the obligation to remit money at the times specified herein)
from any cause beyond its reasonable control, including but not limited to, unusually severe weather, flood, fire, lightning, epidemic, quarantine restriction, war, sabotage, act of a public enemy, earthquake, insurrection, riot, civil disturbance, strike, restraint by court order or Government Authority, or any combination of these causes, which by the exercise of due diligence and foresight such Party could not reasonably have been expected to avoid and which by the exercise of due diligence is unable to overcome.

Section 14.03. Severability. In the event that any one or more of the provisions of this Agreement shall for any reason be held to be unenforceable in any respect under applicable law, such unenforceability shall not affect any other provision of this Agreement, but this Agreement shall be construed as if such unenforceable provision or provisions had never been contained herein.

Section 14.04. Survival of Payment Obligations. Upon termination of this Agreement, each Party shall remain liable to the other Party for all amounts owing under this Agreement. Utility shall continue to collect and remit, pursuant to the terms of the Servicing Arrangement and the principles provided in the Settlement Principles for Remittances and Surplus Revenues provided in Exhibit C hereto and any DWR Charges billed to customers or any DWR Surplus Energy Sales Revenues attributable to sales entered into before the effective date of termination of the Servicing Arrangement.

Section 14.05. Third-Party Beneficiaries. The provisions of this Agreement are exclusively for the benefit of the Parties and any permitted assignee of either Party and there are no third party beneficiaries under this Agreement.

Section 14.06. Governing Law. This Agreement shall be interpreted, governed and construed under the laws of the State of California without regard to choice of law provisions.

Section 14.07. Multiple Counterparts. This Agreement may be executed in multiple counterparts, each of which shall be an original.

Section 14.08. Section Headings. Section and paragraph headings appearing in this Agreement are inserted for convenience only and shall not be construed as interpretations of text.

Section 14.09. Amendments. No amendment, modification, or supplement to this Agreement shall be effective unless it is in writing and signed by the authorized representatives of both Parties and approved as required, and by reference incorporates this Agreement and identifies the specific portions that are amended, modified, or supplemented or indicates that the material is new. No oral understanding or agreement not incorporated in this Agreement is binding on either of the Parties.

Section 14.10. Amendment Upon Changed Circumstances. The Parties acknowledge that compliance with any Commission decision, legislative action or other governmental action (whether issued before or after the Effective Date of this Agreement) affecting the operation of this Agreement, including but not limited to (i) dissolution of the ISO, (ii) changes in the ISO market structure, (iii) a decision regarding direct access currently pending before the Commission,
(iv) the establishment of other Governmental Programs, or (v) a modification to the Contract Allocation Agreement may require that amendment(s) be made to this Agreement. The Parties therefore agree that if either Party reasonably determines that such a decision or action would materially affect the services to be provided hereunder or the reasonable costs thereof, then upon the issuance of such decision or the approval of such action (unless and until it is stayed), the Parties will negotiate the amendment(s) to this Agreement that is (or are) appropriate in order to effectuate the required changes in services to be provided or the reimbursement thereof. If the Parties are unable to reach agreement on such amendments within 60 days after the issuance of such decision or approval of such action, either Party may, in the exercise of its sole discretion, submit the disagreement to the Commission for proposed resolution. Nothing herein shall preclude either Party from challenging the decision or action which such Party deems may adversely affect its interests in any appropriate forum of the Party’s choosing.

The Parties agree that, if the rating agencies request changes to this Agreement which the Parties reasonably determine are necessary and appropriate, the Parties will negotiate in good faith, but will be under no obligation to reach agreement or to ask the Commission to amend this Agreement to accommodate the rating agency requests and will cooperate in obtaining any required approvals of the Commission or other entities for such amendments.

Section 14.11 Indemnification.
(a) Indemnification of DWR. Utility (the “Indemnitor”) shall at all times protect, indemnify, defend and hold harmless DWR, and its elected officials, appointed officers, employees, representatives, agents and contractors (each, an “Indemnified Party” or an “Indemnitee”) from and against (and pay the full amount of) any and all claims (whether in tort, contract or otherwise), demands, expenses (including, without limitation, in- house and retained attorneys’ fees) and liabilities for losses, damage, injury and liability of every kind and nature and however caused, and taxes (of any kind and by whomsoever imposed), to third parties arising from or in connection with (or alleged to arise from in connection with): (1) any failure by Utility to perform its material obligations under this Agreement; (2) any material representation or warranty made by Utility shall prove to be false, misleading or incorrect in any material respect as of the date made; (3) the gross negligence or willful misconduct of Utility or any of its officers, directors, employees, agents, 0representatives, subcontractors or assignees in connection with this Agreement; and (4) any violation of or failure by Utility or Indemnitor to comply with any Applicable Commission Orders or Applicable Law; provided, however, that the foregoing indemnifications and protections shall not extend to any losses arising from gross negligence or willful misconduct of any Indemnified Party.

(b) Obligation of Utility. Consistent with the Contract Allocation Order, Utility shall not, in acting as limited agent of DWR hereunder be required to perform any obligations of any Supplier under any Allocated Contract or to make any payments on behalf of such Supplier or as the result of the failure of such Supplier to perform under any Allocated Contract.

(c) Indemnification of Utility. To the extent permitted by law, DWR (“Indemnitor”) shall at all times protect, indemnify, defend and hold harmless Utility, and its officers, employees, representatives, agents and contractors (each, an “Indemnified Party” or “Indemnitee”), from and against (and pay the full amount of) any and all claims (whether in tort, contract or otherwise), demands, expenses (including, without limitation, in- house and retained attorneys’ fees) and liabilities for losses, damage, injury and liability of every kind and nature and however caused, and taxes (of any kind and by whomsoever imposed), to third parties arising from or in connection with (or alleged to arise from on in connection with): (1) any failure by DWR to perform its material obligations under this Agreement or any Allocated Contract; (2) any material representation or warranty made by DWR shall prove to be false, misleading or incorrect in any material respect as of the date made; (3) the gross negligence or willful misconduct of the DWR or any of its officers, directors or employees, agents, representatives, subcontractors or assignees in connection with this Agreement;
(4) any action claiming Utility failed to perform any Supplier’s obligations under an Allocated Contract; and (5) any violation of or failure by DWR or Indemnitor to comply with any Applicable Law; and provided, however, that the foregoing indemnifications and protections shall not extend to any losses arising from the gross negligence or willful misconduct of any Indemnified Party.

(d) Indemnification Procedures. Indemnitee shall promptly give notice to Indemnitor of any claim or action to which it seeks indemnification from Indemnitor. Indemnitor shall defend any such claim or action brought against it, and may also defend such claim or action on behalf of the Indemnitee (with counsel reasonably satisfactory to Indemnitor) unless there is any actual or potential conflict between Indemnitor and Indemnitee with respect to such claim or action. If there is any actual or potential conflict between Indemnitor and Indemnitee with respect to such claim or action, Indemnitee shall have the opportunity to assume (at Indemnitor’s expense) defense of any claim or action brought against Indemnitee by a third party; however, failure by Indemnitee to request defense of such claim or action by the Indemnitor shall not affect Indemnitee’s right to indemnity under this Section 14.11. In any action or claim involving Indemnitee, Indemnitor shall not settle or compromise any claim without the prior written consent of Indemnitee.

Section 14.12. Notices and Demands. (a) Except as otherwise provided under this Agreement, all notices, demands, or requests pertaining to this Agreement shall be in writing and shall be deemed to have been given (i) on the date delivered in person, (ii) on the date when sent by facsimile (with receipt confirmed by telephone by the intended recipient or his or her authorized representative) or electronic transmission (with receipt confirmed telephonically or electronically by the intended recipient or his or her authorized representative) or by special messenger, or (iii) 72 hours following delivery to a United States post office when sent by certified or registered United States mail postage prepaid, and addressed as set forth below:

Utility: San Diego Gas & Electric Company  

8330 Century Park Court, CP32D San Diego, California 92123  Attn:     Lad Lorenz Vice President, Electric and Gas Procurement Telephone: (858) 650-6150 Facsimile: (858) 650-6191 Email: llorenz@SDGE.com  DWR:      State of California The Resources Agency Department of Water Resources California Energy Resources Scheduling Division 3310 El Camino Avenue, Suite 120 Sacramento, California  95821  Attn:     Peter S. Garris Deputy Director Telephone:  (916) 574-2733 Facsimile:  (916) 574-0301 Email:  pgarris@water.ca.gov  (b)  Each Party  shall be entitled to specify as its proper

address any other address in the United States, or specify any change to the above information, upon written notice to the other Party complying with this Section 14.12.

(c) Each Party shall designate on Attachment A the person(s) to be contacted with respect to specific operational matters. Each Party shall be entitled to specify any change to such person(s) upon written notice to the other Party complying with this
Section 14.12.

Section 14.13. Approval. This Agreement shall be effective upon the execution by both Parties and approval of such executed agreement by the Commission. Except as expressly provided otherwise herein, neither Party may commence performance hereunder until such date. Any delay in the commencement of performance hereunder as a consequence of waiting for such approval(s) shall not be a breach or default under this Agreement.

Section 14.14. Government Code and Public Contract Code Inapplicable. DWR has determined, pursuant to Section 80014(b) of the California Water Code, that application of certain provisions of the Government Code and Public Contract Code applicable to State contracts, including but not limited to advertising and competitive bidding requirements and prompt payment requirements, would be detrimental to accomplishing the purposes of Division 27 (commencing with
Section 80000) of the California Water Code and that such provisions and requirements are therefore not applicable to or incorporated in this Agreement.

Section 14.15. Annual Review. The provisions of the Exhibits are subject to annual review by DWR and Utility to ensure their relevance and usefulness. In the event that the Parties mutually agree that certain provisions of the Exhibits should be amended or supplemented, an amendment to the Exhibit should be executed and Utility shall submit to the Commission for approval.

Section 14.16 Other Operating Agreement. It is DWR’s intent to have a consistent operating agreement with all three investor-owned utilities (IOUs). Should DWR reach an operating agreement with another IOU relating to the subject matter of this Agreement, that in Utility’s judgment is more favorable on the whole than this Agreement, Utility shall have the right to receive the same terms and conditions as such other IOU. This provisions specifically does not allow Utility to select particular portions or provisions of such other IOU’s operating agreement. In addition, if Utility elects to be subject to such other IOU’s operating agreement’s terms and conditions, Utility shall be subject to such other IOU’s operating agreement with only such modifications agreed to by DWR as necessary to address operating differences between that other IOU and Utility. Utility shall exercise the foregoing right within 60 days following Commission approval of such other operating agreement.

IN WITNESS WHEREOF, the Parties have executed this Agreement on the date or dates indicated below, to be effective as of the Effective Date.

 

CALIFORNIA STATE DEPARTMENT                SAN DIEGO GAS & ELECTRIC OF WATER RESOURCES, acting solely under    COMPANY, a California corporation the authority and powers granted by ABIX, codified as Sections 80000 through 80270 of the Water Code, and not under its powers and responsibilities with respect to the State Water Resources Development System   By:  ____________________________   By:  ________________________________  Name: ___________________________   Name:___JAMES P. AVERY____________  Title: __________________________   Title:____SENIOR VICE PRESIDENT____  Date:___________________________    Date:_______________________________


Schedule 1

ALLOCATED CONTRACTS


Schedule 2

REPRESENTATIVES AND CONTACTS

LAD LORENZ
SAN DIEGO GAS & ELECTRIC
ELECTRIC & GAS PROCURMENT VP
8413 CENTURY PARK CP41D
SAN DIEGO CA 92123

MIKE McCLENAHAN
SAN DIEGO GAS & ELECTRIC
ELECTRIC PROCUREMENT MANAGER
8413 CENTURY PARK CT CP41D
SAN DIEGO CA 92123


SDG&E EXHIBIT A
OPERATING PROTOCOLS


EXHIBIT A

OPERATING PROTOCOLS

Pursuant to Section 4.01 of this Agreement, on behalf of DWR as its limited agent, Utility shall perform the day-to-day scheduling and dispatch functions, including day-ahead, hour- ahead and real-time trading, scheduling of transactions with all involved parties, making surplus energy sales and obtaining relevant information for these functions such as transmission availability and others, with respect to the Allocated Contracts set forth in Schedule 1 to the Agreement, all as more specifically provided below and in compliance with the provisions of each of the Contracts:

I. Resource Commitment and Dispatch. Utility agrees to use good faith efforts to dispatch Allocated Contracts, based on the principle of “least cost dispatch” to retail customers, consistent with the Contract Allocation Order and other Applicable Commission Orders. Utility shall undertake these least cost dispatch functions both of Allocated Contracts and its URG so as to minimize the cost of service to retail customers based on circumstances known or that reasonably could have been known by Utility at the time dispatch decisions are made. DWR shall have no role in enforcement or review of Utility least cost dispatch under this Agreement and all issues of Utility compliance with least cost dispatch shall be within the sole review of the Commission.

A. Annual, Quarterly and Weekly Load and Resource Assessment Studies. Utility shall provide to DWR copies of its annual and quarterly load and resource assessment studies. Provided that Utility submits substantially the same information to the Commission, copies of the Commission submission will be simultaneously sent to DWR to satisfy requirements of this section. In addition, Utility will provide a weekly commitment and dispatch plan for informational purposes to DWR in the same form that such plan is used internally.

B. Scheduling Protocols.

1. DWR is responsible for notifying the counter-party to each of the Allocated Contracts that scheduling under the Allocated Contracts will be performed by Utility before the first day that schedules are due to be submitted by Utility. DWR is responsible for notifying Utility of any changes to the Allocated Contracts that it has negotiated, including changes to the scheduling terms. DWR agrees to provide such notice as soon as possible following the negotiation of any changed provisions and in any case prior to the time that any changed provisions become effective.

2. Utility agrees to schedule Contracts in accordance with their terms and in accordance with the requirements of the Control Area operator or operators with whom the Contract must be scheduled to provide for power delivery.

II. ISO Ancillary Service (AS) Market. Among the Contracts are resources that are or may be qualified to be bid into the ISO’s Ancillary Services (“AS”) market or that Utility may use in its self-provision of AS. Utility is authorized to develop protocols and procedures for the use of DWR resources for AS. Utility shall, upon DWR’s request, provide to DWR such information concerning Utility’s intended use of DWR resources for AS as DWR may reasonably request for planning and revenue requirement purposes.

III. Surplus Energy Sales and Energy Exchanges
A. Over-generation. If the ISO announces an over- generation situation Utility will back down resources in accordance with the ISO tariff and Good Utility Practice. In order to reduce the need for physical curtailment in over-generation situations, DWR and Utility shall develop pay for curtailment protocols and procedures that will enable Utility to instruct a must- take resource not to deliver energy under specified conditions. The costs and charges associated with mitigation of an over-generation situation shall be allocated among the Parties on a pro-rata basis consistent with the surplus sales allocation principles set forth in Exhibit C.

B. Energy Exchange Arrangements. Existing non-DWR/CERS exchanges and those that might be transacted post-2002, will be considered URG exchanges. The accounting of energy necessary to support energy exchanges is addressed in Exhibit C.

C. Surplus Energy Sales Arrangement. Utility shall on a monthly basis prepare a sales plan addressing all surplus sales, including without limitation sales to manage over-generation, contemplated by the Utility for review by DWR. Such plan shall address sales of power from the combined portfolio of URG resources and Allocated Contracts, which will be administered by Utility on its own behalf and acting as DWR’s limited agent. As specified in Section 2.02 of the Agreement, Utility shall pursue surplus sales in a fashion reasonably designed to serve the overall best interests of retail electric customers based on information known or could have been known by Utility at the time. Utility agrees to include sufficient details in the sales plans to allow DWR to satisfy its financial management and reporting requirements. To the extent there is surplus power uncommitted to a forward energy surplus sales transaction, Utility shall be required to bid such surplus energy in the day-ahead, hour-ahead or real-time market. Utility shall arrange for transmission service to accommodate surplus sales to the extent that transmission service is available and cost effective. The costs of transmission service, ISO charges and the costs of firm transmission rights associated with such surplus energy sales transactions shall be treated in accordance with the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C.

IV. Outage Coordination and Determination of Resource Availability of Contracts. Utility shall communicate with the Scheduling Coordinator of each Contract to coordinate, approve, document and report planned Contract outages. For those Contracts where resource availability affects capacity payments, Utility will use good faith efforts to verify supplier actual resource availability, and keep records of resource availability as reported by Supplier. In addition, Utility shall document all outages (forced and planned) and notices of outages of DWR contract resources and provide such documents to DWR within five (5) business days after the end of each calendar month.


SDG&E EXHIBIT B
FUEL MANAGEMENT PROTOCOLS


EXHIBIT B

FUEL MANAGEMENT PROTOCOLS

Certain of the Contracts listed on Schedule 1 of this Agreement provide DWR the option of either (i) letting the Supplier provide the necessary natural gas for its generating units at an index- based price or agreed upon fixed price or (ii) DWR procuring the gas supply and causing such supply to be delivered to the Supplier under a tolling arrangement (“Fuel Option”). Certain of the Contracts with Fuel Option provide that DWR can decide on a monthly basis whether to procure the gas and others provide that the decision be made annually or semi-annually when DWR reviews the Supplier’s proposed fuel plan.

The purpose of this Exhibit B is to describe the relationship which will exist between DWR and Utility and the specific responsibilities of each as they all relate to managing the natural gas provisions of the Contracts which include Fuel Options. Specifically, this Exhibit B will address responsibilities for the following activities: (i) determining types and lengths of gas contracts, (ii) nominating deliveries,
(iii) contracting for gas transportation and storage, (iv) managing imbalances, (v) reviewing, authorizing and making payment of gas invoices and (vi) determining and implementing hedge strategies, as appropriate.

I. Operating Relationship Between DWR and Utility

While DWR will retain legal and financial responsibility for gas and related services, Utility shall, as a limited agent acting for DWR, perform the administrative and operational activities, as further specified below, required to ensure adequate gas is supplied to Suppliers’ generating units, consistent with the tolling provisions included in the Contracts. The intent of this relationship is to provide Utility sufficient flexibility and authority to execute normal day-to-day activities associated with managing the fuel provisions of tolling Contracts and procurement of natural gas and related services, as a limited agent acting on behalf of DWR without direct involvement by DWR but in a manner consistent with Utility Gas Supply Plans which have been reviewed and approved by DWR and the Commission.

II. Fuel Activities

Consistent with the terms of the Contracts with Fuel Options, Utility shall have administrative and operational authority to act, as a limited agent, for fuel supply related activities, consistent with the following goals and guidelines whenever Utility has recommended, and DWR has reviewed and approved such recommendation that gas for a Contract with Fuel Option be caused to be supplied by Utility from a list of approved providers.

1. Utility shall use reasonable commercial efforts to secure delivery of gas in a reliable manner and consistent with gas requirements for producing scheduled energy.

2. Utility shall develop a portfolio of gas supply for the Contracts that contain Fuel Options and where Utility is to supply gas, acting as limited agent on behalf of DWR, consistent with the approved Utility Gas Supply Plans. Such portfolio should be diversified in terms of price mechanism, period of performance, and gas suppliers.

3. Utility shall develop a portfolio of supply, which is reasonably priced relative to the market and in accordance with an approved Utility Gas Supply Plan.

III. Review of Supplier Fuel Plans

In accordance with the terms of each of the Contracts with Fuel Options, Utility, acting as a limited agent on behalf of DWR, shall review each fuel plan prepared and submitted by the Supplier, and forwarded to the Utility by DWR, and determine whether to recommend (i) approval of the Supplier Fuel Plan and authorization for the Supplier to provide gas to its generating unit(s), or (ii) procurement and management of gas supplies to the generating unit(s) by Utility. Utility, acting as a limited agent on behalf of DWR, shall advise DWR and the Commission on a timely basis of its recommendation regarding responsibility for supplying natural gas. DWR shall, on a timely basis, review Utility’s recommendation and either approve or identify requested changes. Once approved, Utility shall advise the Supplier in accordance with the time requirements included in the appropriate Contract with Fuel Option. In addition, for any Supplier Fuel Plans which have been implemented and are operative as of the Effective Date, and where DWR has previously elected to be responsible for gas supply, Utility may advise DWR that it would rather have Supplier provide the gas as of the Effective Date. DWR shall coordinate with Utility and Supplier to revise such Supplier Fuel Plans, to the extent possible, prior to the Effective Date.

IV. Fuel Procurement Strategies

Under the Contracts with Fuel Option, upon Utility’s recommendation, and DWR’s review and approval of such recommendation, Utility will be responsible for procuring the natural gas fuel from a list of approved gas providers. Utility shall, acting as the limited agent of DWR, have administrative and operational responsibility for determining its gas procurement strategies, including but not limited to
(i) types of contracts, (ii) length of contracts, (iii) pricing terms, (iv) use of storage, (v) types of gas transportation, (vi) delivery point(s), (vii) whether and how to obtain gas price forecasts, (viii) if and what risk management tools are to be used, and (ix) how to maintain current market intelligence.

Utility shall consolidate these strategies and submit them to DWR and the Commission as a “Utility Gas Supply Plan” by April 17, 2003 and, thereafter on a semi-annual basis during the Term. Utility may also provide a copy of such Gas Supply Plan to DWR in advance of the filing with the Commission so as to be able to indicate DWR’s approval of such plan. Utility shall indicate in its Advice letter filing to the Commission whether DWR has approved such plan as appropriate. DWR shall also formally notify the Commission when it has approved such plan.

DWR and the Commission will review and approve the Utility Gas Supply Plans. In the event of conflicting guidance between the Commission and DWR regarding various aspects of the Gas Supply Plan they respectively approve or reject, where DWR only approves a subset of what the Commission approves, then Utility shall operate within the sphere of DWR’s approval. If, however, the Commission explicitly rejects portions of the Gas Supply Plan that DWR would authorize, then Utility must operate within the limitations of the Commission’s decision. After a reasonable period of time operating within the framework of the Gas Supply Plans and the Commission’s and DWR’s respective approval and/or rejection of various pieces of the Gas Supply Plan, the Parties agree to meet and confer to determine whether the approval process may need to be revised in some manner, and Utility shall submit to Commission any such proposed revisions. Once approved, Utility may act within such Utility Gas Supply Plan without further DWR involvement, except as provided below.

V. Gas Purchasing

Utility and DWR shall jointly determine a list of approved gas providers who can be used to supply gas under the Contracts with Fuel Options. Master agreements intended to cover normal day-to-day volumes will then be executed with such approved providers. While DWR will be the executing party under all DWR gas contracts, such agreements shall specifically authorize Utility to act for and on behalf of DWR, as a limited agent, in negotiating specific prices, quantities and delivery periods for specific purchases under such master agreements; provided however, on the earliest practicable date after the execution of this Agreement, DWR agrees to provide to Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR. If Utility determines it would be beneficial to enter into any DWR gas contract which exceeds 3 months or have a total value exceeding $10 million, it shall negotiate such agreement(s) and submit them to DWR for advance approval and execution.

VI. Gas Transportation

Utility shall have responsibility for recommending to DWR which pipelines should transport gas if Utility, acting as limited agent on behalf of DWR is to supply gas under a Contract with Fuel Option. Following approval of or revision of Utility Gas Supply Plan, Utility shall negotiate firm and/or interruptible agreements with such pipelines, consistent with the Utility Gas Supply Plan and submit them to DWR for execution. While DWR will be the executing party, such agreements with pipelines shall specifically authorize Utility to act for and on behalf of DWR in nominating gas deliveries, making imbalance trades and managing gas volumes transported under such agreements; provided, however, on the earliest practicable date after the execution of this Agreement, DWR agrees to provide to Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR.

VII. Gas Scheduling

If permitted under the Allocated Contracts, the Utility shall have full administrative and operational responsibility for scheduling gas deliveries, whether to a specific generating plant or to storage for all gas contracts entered into by DWR or by Utility on DWR’s behalf pursuant to this Exhibit B. This function includes use of interstate and intrastate gas pipeline provider websites, confirming via telephone, and all other activities required to move gas from the designated delivery point, as determined by the Utility, to its destination, as determined by the Utility.

VIII. Storage Capacity, Injections and Withdrawals

Utility shall have responsibility for devising plans for gas storage, if Utility, acting as limited agent on behalf of DWR, is to supply gas under Contracts with Fuel Option from a list of approved providers. Following approval of the Utility Gas Supply Plans, Utility shall negotiate firm and/or interruptible agreements with such storage service providers and submit them to DWR for execution. While DWR will be the executing party with DWR remaining the principal under such contracts, such agreements with storage service providers shall specifically authorize Utility to act for and on behalf of DWR in nominating gas injections and withdrawals under such agreements; provided, however, on the earliest practicable date after the execution of this Agreement, DWR agrees to provide to Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR.

IX. Managing Gas Delivery/Usage Imbalances

For gas that it purchases and transports on behalf of DWR, Utility shall have full administrative and operational responsibility for monitoring and managing the daily status of gas usage vs. gas deliveries (i.e. gas imbalances). In addition, to the extent that gas transportation providers issue operational flow orders or require adjustments in scheduled gas deliveries due to system constraints, Utility, acting as limited agent on behalf of DWR, shall be responsible for compliance with such orders. Utility shall also be responsible for any penalties imposed by gas transportation providers for imbalances caused by Utility, due to its failure to exercise prudent gas management practices.

X. Invoice Review, Approval and Payment

For natural gas, pipeline transportation and storage services it purchases in accordance with this Exhibit B, Utility, acting as limited agent on behalf of DWR, shall have responsibility for receiving invoices from gas, transportation and storage suppliers, reviewing them for accuracy, approving/rejecting invoices for payment and forwarding to DWR for payment; provided, however, on the earliest practicable date after the execution of this Agreement, DWR agrees to cause Utility to be authorized to receive such information from Suppliers. Utility shall provide DWR sufficient documentation to verify payment of the invoices.

XI. Forecasting

Utility shall be responsible for all gas price, demand and supply forecasts which Utility believes are consistent with any accepted gas supply responsibilities.

XII. Risk Management

Utility shall develop and include in its Gas Supply Plans, plans for the hedging of DWR Fuel Supply costs. Final decisions relating to the use or non-use of financial tools such as futures, options and swaps to hedge future gas price exposure on any gas volumes not hedged by Utility under the Utility Gas Supply Plans shall be made and implemented by DWR. Any such contracts executed by DWR on a “portfolio basis” should be utility-specific.

XIII. Market Intelligence

Any and all efforts to obtain, analyze and utilize market intelligence for decision-making purposes shall be the responsibility of Utility.

XIV. Payment of Gas Costs

For natural gas, pipeline transportation, financial hedges and storage services that are purchased and provided by a Supplier under an approved Fuel Supply Plan, DWR shall pay such gas related costs as part of the invoice for commodity, product, or services submitted by the Supplier. For natural gas, pipeline transportation and storage services provided under DWR contracts and administered by Utility on behalf of DWR, DWR shall pay invoices after they have been reviewed and approved for payment by Utility.

XV. Allocation of Existing DWR Gas Contracts

DWR has entered into gas supply, transportation and storage contracts as provided in Attachment 1 to this Exhibit B that have expiration dates after the Effective Date of this Agreement. The administrative and operational control of the contracts listed on Attachment 1 to this Exhibit B will become the responsibility of Utility. This shall include (i) scheduling gas transportation, (ii) confirming gas deliveries,
(iii) nominating gas withdrawals from and injections into storage, if applicable, (iv) and reviewing and approving invoices for payment. When approved, invoices shall be transmitted to DWR for payment within 10 days of receipt of invoice from the gas supplier, gas storage or gas transportation provider.

XVI. Pre-existing Financial Hedge Instruments

If DWR has entered into any financial hedge transactions that will remain operable after the Effective Date of this Agreement, DWR shall retain full administrative and operational control over such transactions.


SDG&E EXHIBIT C
SETTLEMENT PRINCIPLES
FOR REMITTANCES AND
SURPLUS REVENUES


EXHIBIT C
SETTLEMENT PRINCIPLES FOR REMITTANCES AND SURPLUS REVENUES

This Exhibit C outlines the principles by which Utility will calculate revenues associated with surplus energy sales and DWR energy delivered to retail customers. This Exhibit C also addresses the information that Utility will provide to DWR to support DWR payment of Contract invoices, and invoices from natural gas supplier(s) for fuel provided to service DWR Contracts where tolling options have been implemented.

This Exhibit C works in conjunction with the applicable Servicing Arrangement with Utility for purposes of determining the remittance amounts by Utility, which will serve as DWR’s billing and collection agent.

In accordance with the Contract Allocation Order, this Exhibit C provides that:

— Revenues will be allocated for both surplus sales and retail customer deliveries
— Revenues will be allocated pro rata, based on dispatched quantities of energy
— The principle of balancing least cost economic dispatch while maintaining reliability is reinforced through these revenue allocation protocols.
— Surplus sales quantities will be calculated as the difference between Utility’s Energy Delivery Obligations (EDO) and the combination of energy from URG and energy dispatched from Contracts.

Where Utility’s Energy Delivery Obligations is defined as: (1) Utility’s retail load which includes distribution losses, (2) all pumping load, (3) all energy exchange transactions between Utility and counter parties, (3) wholesale obligations existing as of January 1, 2003, (4) transmission losses.

The principles herein, together with the applicable methods and calculations contained in the Servicing Arrangement, form a substantive component of the accounting protocols required to implement the Contract Allocation Order. This Exhibit should also be read in conjunction with Exhibit F (“Data Requirements”).

Utility Remittance to DWR

Utility shall remit to DWR an Energy Payment for the delivery of Contract energy to Utility retail customers and a separate payment for DWR’s share of Surplus Energy Sales Revenues. The principles for the remittances to DWR of Surplus Energy Sales Revenue and Energy Payment are contained in Sections A and B of this Exhibit C, respectively. The details for determination of the remittances to DWR by Utility are contained in the Servicing Arrangement between the Utility and DWR.

A. Utility Remittance to DWR of Revenue from Surplus Energy Sales

Surplus Energy and Revenues

Surplus energy exists when dispatched supply from Utility portfolio and DWR Contracts exceeds Utility’s Energy Delivery Obligations. When such a condition exists, the revenues from the sale of surplus energy shall be shared between Utility and DWR. Surplus sale revenues can occur either through a forward market sale or a delivery of the excess energy into the ISO real time market. In addition to the sharing of surplus energy revenues, the quantity of any surplus energy shall likewise be shared between Utility and DWR, and used in the determination of the Hourly Percentage Factor described in Section I(B).

Surplus energy sales revenues shall be placed by Utility into a separate account (Surplus Sales Fund) to be held in trust and shall be disbursed by Utility to DWR in accordance with the pro- rata allocation principles in Exhibit C and consistent with the provisions of Attachment J of the Servicing Arrangement. For surplus energy sales to third parties, Utility shall apply reasonable credit risk management criteria that is consistent with industry accepted credit standards.

Surplus Energy Quantity

The Surplus Energy quantity shall be determined by subtracting Utility’s Energy Delivery Obligations from the sum of dispatched URG energy and dispatched DWR Supply. URG energy shall include dispatched energy from URG, new Utility contracts and Utility market purchases plus adjustments for Ancillary Services and ISO Instructed Energy as described under “Definitions and Adjustments.” DWR Supply shall include dispatched energy from DWR must take and dispatchable contracts net of adjustments described below.

DWR Surplus Energy quantity shall be the product of Surplus Energy quantity multiplied by the DWR Surplus Energy Percentage. Utility Surplus Energy quantity shall be the remaining portion of Surplus Energy. Both Utility and DWR Surplus Energy quantities shall be applied to the respective Party’s energy supply quantities for determination of the Hourly Percentage Factor described in Section (B).

Surplus Energy Sales Revenues

Surplus Energy Sales Revenues shall be shared between Utility and DWR in the same manner as Surplus Energy.

Forward Market Sale

DWR share of revenues from a forward market sale of surplus energy shall be the product of the net revenue multiplied by the DWR Surplus Energy Percentage. Utility share of these revenues shall be net revenue less DWR share of net revenues. Revenues from a forward market sale shall not be distributed to the Parties until after Utility receives the revenues from the sales and pays sale-related charges. Shared revenues from forward market sales shall be net of transmission costs and broker fees.

ISO Real Time Market Sales

Revenues from delivery of surplus energy to the ISO real time market shall be determined from the product of positive load or supply deviation multiplied by the ISO real time market price. These revenues will be netted against any ISO charges related to the load deviation, including a negative ISO price. Load deviation is determined by subtracting the Utility metered load from the Final Hour Ahead Load Schedule, however only positive quantities, where schedule exceeds meter, reflect surplus conditions for revenue sharing. Supply deviation is determined by subtracting the Final Hour Ahead Supply Schedule (adjusted by real time instructions) from metered supply, however, only positive quantities, where meter exceeds the adjusted schedule, reflect surplus conditions for revenue sharing.

DWR share of revenues from delivery of surplus energy to ISO real time market shall be the product of the net revenues multiplied by the DWR Surplus Energy Percentage. Utility share of these net revenues shall be the net revenue less DWR share of net revenues. Revenues from delivery of surplus energy to the ISO real-time market shall not be distributed to the Parties until after the Utility received payment for final monthly invoice from the ISO for the month in which the surplus energy was delivered.

Over-generation Periods

During periods of over-generation condition as announced by the ISO, surplus sales may be made at very low, zero or even negative prices. In such conditions, the surplus sale revenue calculations as described above still hold. However it is recognized that the sales may result in little or no revenue. Sales could even be done at a cost to the seller. That seller could be Utility or the ISO selling in an “out-of-market” condition. During these conditions, ISO-related charges assigned to Utility for such sales (e.g. – ISO selling out-of-market) are included in the surplus sales revenue as a cost. During over- generation conditions there may be no market in which to sell surplus energy. In that event, or in expectation of that event, Utility shall declare that no valid market exists for surplus energy and shall begin curtailing must-take resources in accordance with Utility’s procedures for mitigating over- generation conditions. Such mitigation measures shall be consistent with good utility practice, specifically hydroelectric facilities at spill or near-spill conditions and nuclear facilities scheduled by Utility are the last resources to be reduced in power output.

Over-generation for purposes of this Exhibit C is defined as the condition in which total supply exceeds total loads in the ISO control area.

Revenues or costs from delivery of surplus energy to the ISO real time market under an over-generation condition shall not be distributed to the Parties until after Utility receives payment for final monthly invoice from the ISO for the month in which the surplus energy was delivered.

Calculation of Surplus Energy Percentage

DWR Surplus Energy Percentage shall be equal to the pro rata share of DWR Supply to the sum of Utility Supply and DWR Supply, expressed as follows:

DWR Surplus Energy Percentage = DWR Supply / (Utility Supply + DWR Supply)

Where:

DWR Supply is total energy dispatched from DWR Contracts with adjustments for transmission losses. Ancillary Services and ISO Instructed Energy transactions described below.
Utility Supply is total energy dispatched from URG, new Utility contracts and Utility market purchases with adjustments for transmission losses, existing wholesale obligations, Ancillary Services and ISO Instructed Energy, exchange transactions, all pumping loads, and ISO Uninstructed Energy as described below.

B. Definitions and Adjustments

Certain energy and capacity transactions, which may be conducted by Utility in its normal course of business, may affect the Utility and DWR Supply quantities used in pro rata calculations.

Exchanges are transactions where energy is delivered to a third party in one period and a similar, but not necessarily equal, amount of energy is returned by third party in a different period. For the purposes of pro rata share calculation, exchanges use energy from the Utility’s URG.

Forward Sales are transactions where energy is sold in a forward market to balance supply with demand. In general, for the purposes of remittance determination, forward sales are made using energy from the joint Utility/DWR portfolio.

Ancillary Services are transactions where capacity from certain qualifying resources is sold to ISO for ancillary services rather than being used as energy to serve retail load. Resources from both Utility portfolio and DWR Contracts may qualify for use as ancillary services. Since the capacity used for ancillary services does not serve retail energy load, ancillary service capacity is not considered as a joint Utility/DWR portfolio transaction for the purpose of remittance determination. If Utility or DWR Contract resource capacity is used for ancillary services, the capacity quantity will not be included in the supply quantity of the owning party for the purpose of pro rata share calculations, and owning party will retain all the revenues from the ancillary services as well as all associated transaction costs and ISO charges.

ISO Instructed Energy is a transaction where certain qualifying resources are able to sell energy from unused capacity to the ISO in the real time market. The energy delivered from these resources is directed by the ISO in real time to balance supply and load imbalances on the grid. Either Utility portfolio or DWR Contracts may contain resources that have ability to provide instructed energy to ISO. Since instructed energy is resource specific and does not directly serve the retail load of any utility, instructed energy is not considered as a joint Utility/DWR portfolio transaction for the purpose of remittance determination. If Utility or DWR Contract resources are dispatched as instructed energy, the energy quantity will not be included in the supply quantity of the owning party for the purpose of pro rata share calculations, and owning party will retain all the revenues from the instructed energy as well as all associated transaction costs and ISO charges.

ISO Uninstructed Energy is a transaction where energy is delivered or received from the ISO grid in the real time based on the actual consumption of retail load and actual deliveries of supply resources.

Uninstructed Retail Load Deviations–Uninstructed retail Load Deviations are the difference between scheduled load and metered load. If retail load deviations are positive (schedule exceeds meter), it is considered that any excess supply (less any positive uninstructed supply deviation) was dispatched from the joint Utility/DWR portfolio in excess of quantity needed to serve retail load, and that the ISO credit for the excess supply should be shared pro rata as described above. If retail load deviations are negative (meter exceed schedule), to the extent deviations are not compensated by a positive uninstructed supply deviation, it is considered that Utility had to procure additional supply from ISO real time market. The negative load deviation quantity procured from ISO real time market is considered a Utility market purchase and the quantity will be included in Utility Supply for pro rata share calculation purposes.

Uninstructed Supply Deviations

Uninstructed Supply Deviations are the difference between scheduled supply and metered supply plus an ISO allocation for transmission losses. If Utility’s net supply deviations are positive (meter exceeds schedule), to the extent not needed to compensate a negative uninstructed retail load deviation, it is considered that excess supply was a Utility market sale and will not be included in Utility Supply for pro rate calculation purposes. If Utility’s net supply deviations are negative (schedule exceeds meter), to the extent not balanced by a positive uninstructed retail load deviation, it is considered that Utility had to procure additional supply from the ISO real time market. The negative supply deviation quantity procured from the ISO real time market is considered a Utility market purchase and the quantity will be included in Utility Supply for pro rata share calculation purposes.

C. Utility Remittance to DWR for Sales of DWR Energy to Utility Retail Customers -Energy Payment

Utility shall remit to DWR its Energy Payments according to the terms of each Utility’s respective Servicing Arrangement.

The DWR Energy Payment is billed by each utility to customers in accordance with the terms of each applicable Utility Servicing Arrangement. The DWR Energy Payment is billed kWhs served by Net DWR Supply at the applicable CPUC approved DWR rate. Net DWR Supply is total DWR Supply less DWR share of surplus energy. The DWR Energy Payment is allocated based on the percentage of energy supplied by DWR to Utility, which is the “Hourly Percentage Factor” multiplied by the retail load of each customer. The Hourly Percentage Factor is determined by calculating the percentage of net energy supplied by DWR to Utility to serve retail load, as expressed below:

Hourly Percentage Factor = Net DWR Supply / (Net Utility Supply + Net DWR Supply)

Where:

Net DWR Supply is DWR Supply quantity used for the determination of DWR Surplus Energy Percentage less DWR share of surplus energy quantity, which is determined by the product of surplus energy multiplied by DWR Surplus Energy Percentage.

Net Utility Supply is Utility Supply quantity used for the determination of DWR Surplus Energy Percentage less Utility share of surplus energy quantity, which is total surplus energy less the DWR share of surplus energy quantity.

In the Event of any conflict between the formulas and procedures in this Exhibit C and the formulas and procedures in Utility’s Servicing Arrangement, those contained in Utility’s Servicing Arrangement shall govern.

II. Bilateral Settlement

Under the Contract Allocation Order DWR remains financially obligated for the Contracts. DWR will continue to pay suppliers and this requires DWR to apply appropriate procedures and controls to ensure that payments are made accurately and in a timely manner. Information supporting Contract settlements will be provided by Utility, and additional information may also be required to address contract performance issues (such as availability and other items as discussed in Exhibit E) and to allow DWR to settle disputes in an appropriate manner.

DWR requires sufficient information to support payment requests so that it can meet the accountability requirements of the State Controller’s Office and the State Auditor, and simultaneously comply with the applicable statutes concerning disbursement of public monies. The Utility shall reconcile schedules with suppliers invoice. DWR shall make the associated payments to suppliers after performing its verification, and Utility will provide the data as required in Exhibit F to allow it to perform these duties in a timely manner as set forth herein.

DWR shall continue to perform validation of settlement data and invoices and pay Contract costs directly to the suppliers upon validation of invoices.

III. Fuel Cost Verification and Settlement

Exhibit B provides a detailed discussion concerning Utility’s responsibility for fuel management. DWR will continue to pay fuel suppliers and others involved in providing fuel management services for the delivery of fuel for those DWR Contracts where the Fuel Option has been elected. Consistent with the above, Utility will perform settlements activities to reconcile quantities and associated charges, and DWR will perform verification, audit and monitoring to support its disbursement of funds. Utility will comply with the requirements contained in Exhibit F to provide DWR with the necessary information to apply appropriate procedures and controls to ensure that fuel payments and payments for fuel management services are made accurately and in a timely manner and to allow DWR to settle disputes in an appropriate manner.


SDG&E EXHIBIT D
ISO SCHEDULING COORDINATOR CHARGES


EXHIBIT D

ISO SCHEDULING COORDINATOR CHARGES

The financial obligation for ISO charges incurred after the Effective Date will be allocated to the Utility, unless otherwise extended under the existing letter agreement with DWR related to the ISO charges and any future Applicable Commission Orders. Unless specifically provided in Exhibit C hereto, all ISO charges incurred after the Effective Date attributable to load and resources shall be the responsibility of Utility.

Utility agrees that any refunds, reruns or credits through the ISO attributable to costs incurred by DWR for trade dates beginning February 7, 2001 up to the Effective Date shall belong to DWR and Utility shall take all necessary action to remit such refunds or credits to DWR within reasonable time. In addition, DWR shall be responsible for any ISO charges incurred during this period pursuant to the existing letter agreement between the Parties. Utility shall invoice DWR for such ISO charges within a reasonable period of time and DWR shall pay Utility for such ISO charges within 10 days of receipt of such invoice. Without making any assurances as to Commission action, DWR agrees to take appropriate action to ensure that such refunds or credits are applied consistent with DWR’s Revenue Requirement cost allocation method for the same trade dates.


SDG&E EXHIBIT E
CONTRACT MANAGEMENT AND
ADMINISTRATION PROTOCOLS


EXHIBIT E

CONTRACT MANAGEMENT AND ADMINISTRATION PROTOCOLS

DWR will retain all contract management, administration and monitoring responsibilities for the Contracts, including due diligence, performance testing, contract performance assessment, formal correspondence and notifications with Suppliers, exercise of contract options, contract interpretation and dispute resolution, and financial reporting. Upon development by Utility and DWR in the future to a transition plan that transfers the Due Diligence and Performance Test Monitoring functions set forth in this Exhibit E from DWR to the Utility, , including a transition schedule, and a transition plan , Utility agrees to submit such transition plan to the Commission as an amendment to this Exhibit E for approval by the Commission. Upon agreement of the Parties to an acceptable transition plan and the Commission approval of Utility submitted transition plan, the agreed upon functions will transfer from DWR to the Utility (“the Transition Date”).

I. Due-Diligence

The Due Diligence function assesses the progress of permitting, construction and performance capability of new generating facilities under to the Contracts. Due Diligence includes (i) monitoring activities associated with the development, construction, and performance of new generating facilities; (ii) identification and tracking of key projects milestones including permitting, equipment procurement, construction, commissioning, and performance testing; (iii) coordination with permitting agencies and the Suppliers, review of project documents, physical inspections, and witnessing of acceptance tests, (iv) verification that the new facilities can perform in a manner that is consistent with the obligations under the appropriate Contract and (v) review and approval of commercial operation dates and documentation.

II. Performance Test Monitoring

A. Annual Performance Tests

Annual Performance Tests verify ongoing compliance with the Contracts and establish plants capacities and efficiencies that are used to calculate contract payments, either for capacity or energy. Annual Performance Test responsibilities generally consist of (i) verification of testing procedures, (ii) witness of performance tests,
(iii) review of test results and test reports for compliance with Contract terms and conditions, and (iv) identification of contract non-compliance for dispute resolution with the Supplier. Prior to the Transition Date, the Utility will cooperate and assist DWR with scheduling of upcoming Annual Performance Tests, and the Utility may have its staff witness such testing.

B. Scheduled Performance Tests

Prior to the Transition Date, on occasion, DWR may request that Utility schedule a peaking or dispatchable generating facility for testing (to assure that such generation facility is available according to the terms of the contract between such generation facility and DWR). The utility will cooperate and shall coordinate with the DWR on a mutually acceptable date for performance of the test. On the date agreed upon, the Utility shall schedule the specified facility or unit for operation to test the availability, reliability, and performance of the scheduled unit.

C. Test Procedures and Protocols

Prior to January 1, 2003, Utility shall meet with DWR staff to review, discuss, and verify test procedures and protocols developed by DWR.

III. Contract Performance Assessments

DWR shall continue to perform an after-the-fact review (“Performance Assessment”) of each Contract on a periodic basis. The purpose of the Performance Assessment is to assess, analyze, and document the overall performance of each Supplier, assure that the Supplier is satisfying the terms and conditions of their respective contract(s), and identify potential issues, disputes, and other matters that may require corrective action by either Utility or DWR as part of contract administration.

IV. Other Administrative Matters

A. Correspondence with Suppliers

Utility and DWR agree to copy each other on all written correspondence and written notifications sent to or received from a Supplier of an Allocated Contract or Interim Contract related to the activities described in this Exhibit E. The Parties agree to provide additional information as requested related to verification and support of the activities described in this Exhibit E.

B. Reports

Results of the activities described in this Exhibit E will be documented by DWR in written reports (“Reports”) and shall be discussed periodically between DWR and the Utility. Such Reports may include, but are not limited to, summary of test results, status of projects, recommendations for operational changes, procedural changes, dispute resolution, and results of Performance Assessments.
Such Reports, documentation, or other material developed by either Party shall be shared and reviewed with the other Party on a timely basis.

 


 

 

ALJ/JSW/sid Mailed 12/23/2002

EXHIBIT 10.07

 

Decision 02-12-070 December 19, 2002

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

The application of SAN DIEGO GAS & ELECTRIC (U 902 E) for approval of servicing agreement between the State of California Department of Water Resources (“DWR”) and SDG&E Company Pursuant to Chapter 4 of the Statutes of 2001 (Assembly Bill 1 of the First 2001-2002 Extraordinary Session).

Application 01-06-039
(Filed June 22, 2001)

 

OPINION APPROVING THE 2003 SERVICING ORDER CONCERNING
SAN DIEGO GAS & ELECTRIC COMPANY AND THE CALIFORNIA DEPARTMENT OF WATER RESOURCES

 

Summary

On October 8, 2002, the California Department of Water Resources (DWR) submitted to this Commission a memorandum and proposed modifications to the “First Amended and Restated Servicing Agreement” (Amended Servicing Agreement) between DWR and San Diego Gas & Electric Company (SDG&E). DWR’s submission was made in response to D.02-09-053 (the “Contract Allocation Decision”), which directed DWR and SDG&E to negotiate appropriate modifications to the Amended Servicing Agreement as a result of the allocation of energy from, and operational responsibility for, DWR’s electricity contracts to SDG&E and the other two large electric utilities.

Today’s decision approves a modified version of DWR’s proposed modifications, which we have labeled as the “2003 Servicing Order Concerning State of California Department of Water Resources And San Diego Gas & Electric Company” (Servicing Order). Because the changes that DWR proposed, and that we here approve with modifications, were not agreed to by SDG&E, we are constrained to issue a Servicing Order rather than approve a Servicing Agreement. Appendix A of this decision contains a marked version of the revisions to the Servicing Order that we approve today. Appendix B of this decision is a “clean” copy of the approved Servicing Order. SDG&E is ordered to comply with the terms and conditions of the Servicing Order. The Servicing Order sets forth the terms and conditions under which SDG&E will provide the transmission and distribution of DWR-purchased electricity, as well as billing, collection, and related services on behalf of DWR. The Servicing Order also addresses DWR’s compensation to SDG&E for providing those services.

Today’s Servicing Order is needed because DWR and SDG&E have been unable to negotiate a mutually agreeable servicing arrangement. Due to the upcoming date when SDG&E is to assume operational control of the DWR contracts allocated to it, a Servicing Order needs to be put into place prior to year’s end.

Background

In January 2001, in response to the energy crisis facing California, the Legislature gave DWR the authority to purchase electricity and sell it to the retail customers of California’s electric utilities. This authority was provided for in Assembly Bill 1 of the First Extraordinary Session of 2001-2002 (Stats. 2001, Ch. 4) (AB X1).

In March 2001, the Commission ordered SDG&E to segregate, and hold in trust for the benefit of DWR, certain amounts its customers had paid for DWR’s electricity. (D.01-03-081.) This arrangement was formalized in the “Servicing Agreement Between State of California Department of Water Resources and San Diego Gas & Electric Company,” which was approved by the Commission with certain modifications in D.01-09-013.

As a result of D.01-09-013, D.02-02-051, and D.02-02-052, SDG&E and DWR discussed and negotiated amendments and restatements to the Servicing Agreement. These changes were reflected in the Amended Servicing Agreement, which the two parties signed on March 29, 2002. Subsequently, SDG&E sought Commission approval of the Amended Servicing Agreement by filing a petition for modification of D.01-09-013. The Commission granted SDG&E’s petition and approved the Amended Servicing Agreement in D.02-04-048.

In D.02-07-038, the Commission approved SDG&E’s second petition to modify D.01-09-013. This petition sought Commission approval of “Amendment No. 1” to the Amended Servicing Agreement. Thus, prior to today’s decision, the existing servicing arrangements between SDG&E and DWR are composed of the Amended Servicing Agreement and Amendment No. 1.

Under AB X1, DWR’s authority to contract for electricity purchases expires on January 1, 2003. (Water Code Sec. 80260.) Rulemaking (R.) 01-10-024 was initiated by the Commission to allow the electric utilities to resume the responsibility of procuring electricity for their customers. In D.02-09-053, the Commission ordered SDG&E, and the other two large electric utilities, to assume all of the operational, dispatch, and administrative functions for the electricity contracts that DWR had entered into, effective January 1, 2003. D.02-09-053 also allocated the DWR contracts to the resource portfolios of the three utilities, who are to schedule and dispatch the contracts in a least-cost manner.

As a result of the assumption of the operational duties for the DWR contracts, the Contract Allocation Decision recognized that the “servicing arrangements” that DWR had entered into with SDG&E, would need to be altered. (D.02-09-053, pp. 15, 59.) In Ordering Paragraph 3 of D.02-09-053, DWR and SDG&E were directed to negotiate appropriate modifications to their servicing arrangements, and DWR was directed to “submit its proposed modifications” by October 1, 2002. DWR and the three electric utilities were also directed to jointly file proposed operational agreements and proposed standards for reasonableness review by October 1, 2002.

The three utilities requested an extension of the submission date for the proposed modifications to the servicing arrangements and proposed operational agreements. The Commission’s Executive Director, in a letter dated September 27, 2002, granted an extension of one week, to October 8, 2002.

In response to the submissions ordered in D.02-09-053, on October 8, 2002, DWR electronically transmitted to the Commission, and to the service list, a memorandum from Peter Garris of DWR, along with the proposed modifications to the existing servicing arrangements for SDG&E, and the other two utilities. The document containing DWR’s proposed modifications to SDG&E’s servicing arrangements is labeled “2003 Servicing Agreement Between State of California Department of Water Resources And San Diego Gas & Electric Company.” DWR also transmitted two other documents, one which contains Attachments A through H of the Servicing Order, and the other which contains Attachment J of the Servicing Order.

Due to the earlier extension by the Executive Director, the assigned administrative law judge (ALJ) issued a ruling on October 10, 2002, allowing interested parties additional time to submit comments on the proposed modifications to SDG&E’s servicing arrangements, and reply comments. SDG&E filed comments and reply comments on October 18, 2002 and October 23, 2002, respectively. On October 23, 2002, DWR transmitted a memorandum entitled “Comments Concerning Submissions Requested by the California Public Utilities Commission Decision 02-09-053.”

Summary of Proposed Modifications to
the Amended Servicing Agreement

The proposed modifications to the Amended Servicing Agreement and related attachments have been compared to the Amended Servicing Agreement that was approved in D.02-04-048, and to Amendment No. 1 approved in D.02-07-038. In addition, the proposed modifications have been reviewed in light of the Contract Allocation Decision. Appendix A of this decision reflects the proposed modifications to the Amended Servicing Agreement through the use of underlining and strikeout markings.

The proposed modifications fall into the following categories:

  • Definitions and requirements relating to the DWR contracts allocated to SDG&E in the Contract Allocation Decision.
  • Definitions and requirements relating to the surplus energy sales and remittances that SDG&E will be responsible for.
  • Definitions and requirements relating to the Operating Order.
  • Incorporation of Amendment No. 1 into the modified version of the Amended Servicing Agreement.
  • Certain attachments to be provided by SDG&E in Service Attachment 2.
  • Incorporation of Attachment F, approved in D.02-07-038, into the modified version of the Amended Servicing Agreement.

In addition to the proposed modifications, additional changes have been made to the Amended Servicing Agreement and the related attachments. These additional changes are described in the discussion section below, and also reflect that SDG&E is being ordered to provide the services in accordance with the attached Servicing Order and that an Operating Order is expected to be approved, rather than an Operating Agreement.

Position of the Parties

  1. DWR

According to DWR’s October 8, 2002 memorandum, DWR distributed the proposed modifications to SDG&E’s servicing arrangements on October 3 and 4, 2002. As of October 8, 2002, DWR was unable to ascertain whether the proposed modifications were acceptable to SDG&E.

DWR has proposed modifying the Amended Servicing Agreement by making certain changes to the accounting and reporting procedures. According to DWR, these changes are found in Attachments C and J of the Servicing Order, and parallel accounting and reporting provisions are contained in Exhibits C and F of the Operating Order. DWR states that these accounting and reporting procedures are consistent with the policy set forth in the Contract Allocation Decision.

In its October 23, 2002 memorandum, DWR noted that, consistent with AB X1 and the Contract Allocation Decision, that it would still be subject to continuing obligations with respect to the DWR contracts. In particular, these obligations include:

  • Servicing the bonds as issuer;
  • Managing legal and financial obligations under its long-term contracts;
  • Ensuring the integrity of its revenues; and
  • Fulfilling its substantial reporting obligations associated with the above.

DWR states that it is working to ensure that there is an efficient and timely transition to the utilities of the operational functions of the DWR contracts, while ensuring that DWR is able to fulfill its continuing obligations. To accomplish this goal:

“DWR believes that certain principles and arrangements must be established regarding utilities’ performance of certain functions under the allocated DWR long-term contracts on behalf of DWR. The operating agreement is a compilation of such principles and arrangements that DWR believes are necessary to achieve these goals.

. . .

“In preparing the operating agreement, DWR’s objective has been to minimize DWR’s involvement in the utilities’ operation of the integrated portfolio, consisting of utility and allocated DWR contract resources, and to allow the utilities to make substantially all the operating decisions. The operating agreement is intended to provide appropriate mechanisms that allow the utilities to optimize the use of the integrated portfolio of resources on a service territory basis. . . After the operational transition, DWR will continue to be legally and financially responsible for the direct costs under the allocated DWR long-term contracts, including gas-related costs. As a result, DWR needs to receive timely reporting of data outlined in Exhibit F of the operating agreement.

“To implement checks and balances while operating the integrated portfolio, DWR has proposed certain accounting and revenue sharing principles in Exhibit C of the operating agreement. DWR believes that the proposed accounting and revenue sharing principles provide greater certainty of revenues and cash flows to the utilities and DWR and, accordingly, aid the utilities in their quest for creditworthy status. Finally, DWR believes that the pro rata revenue-sharing methodology articulated in the Contract Allocation Decision and further reflected in DWR’s accounting and revenue sharing principles results in an equitable sharing of risk and reward. The information and data being requested under Exhibit F of the operating agreement are to facilitate DWR’s verification of the utilities’ remittances to DWR and costs incurred under the allocated contracts rather than to conduct an operational review of the utilities decisions.

“At this time, DWR does not believe that there is a consensus on the accounting and revenue sharing principles proposed by DWR. . . . The resolution of the issues related to the accounting and revenue sharing principles will require a significant shift from the existing remittance policy and DWR believes that such a policy implementation can only be achieved with the Commission’s support and active involvement.” (DWR October 23, 2002 Memorandum, pp. 1-2.)

  • SDG&E
  • SDG&E’s comments emphasize three points that the Commission should keep in mind while considering the proposed modifications to the Amended Servicing Agreement. First, that DWR and SDG&E are still continuing to negotiate, and that more time is needed to reach a consensus with DWR concerning the proposed modifications. Second, that the proposed modifications to the Amended Servicing Agreement are duplicative or in conflict with the proposed Operating Agreement. Whatever is adopted in the proposed Operating Agreement will affect certain provisions in the proposed modifications to the Amended Servicing Agreement. And third, that the proposed modifications to the Amended Servicing Agreement should provide that any revenues for surplus sales will be net of expenses.

    SDG&E’s comments also lists a series of concerns with the proposed modifications to the Amended Servicing Agreement and to the attachments. These issues fall into the following categories:

    • Text changes to reflect the pro rata sharing of revenues contained in D.02-09-053.
    • Text changes to reflect whether an agency relationship is created from the surplus sales made from a pro rata resource pool of DWR and investor owned utility energy, and indemnification and waiver of liability issues.
    • Text changes regarding credit risk management and the associated incremental costs related to the sale of surplus energy.
    • When SDG&E should forward DWR’s share of the surplus energy sales revenues.
    • Changes to Service Attachment 2, and Attachments B, F and G.

    Discussion

    In deciding whether we should approve the proposed modifications to the Amended Servicing Agreement and related attachments, the Commission is mindful of the course of action we have taken in R.01-10-024 and in D.02-09-053. One of the goals of R.01-10-024 is to allow the utilities “to resume purchasing electric energy, capacity, ancillary services and related hedging instruments to fulfill their obligation to serve and meet the needs of their customers.” (R.01-10-024, p. 1.)

    In order for SDG&E and the other utilities to undertake the operational responsibilities associated with the allocated DWR contracts beginning on January 1, 2003, certain operational arrangements and servicing arrangements need to be in place. With less than one month to go before the utilities are to take over the operational responsibilities for the DWR contracts, DWR and SDG&E have been unable to agree on a mutually acceptable servicing arrangement. To ensure a seamless transition of the DWR contracts allocated to SDG&E, while ensuring that DWR’s legal and financial responsibilities for the DWR contracts continue to be fulfilled, it is imperative that servicing arrangements be in place before the end of 2002.

    D.02-09-053 also required DWR to submit proposed operational agreements. As noted in the positions of the parties, certain provisions of the proposed operational agreement that DWR submitted may affect certain provisions of the proposed modifications to the Amended Servicing Agreement and the related attachments. The proposed operating agreement is being considered by the Commission in R.01-10-024. Since DWR and the utilities have been unable to mutually agree on a proposed operational agreement, we believe that the Commission will concurrently adopt an Operating Order when a Servicing Order for SDG&E is adopted.

    On December 9, 2002, SDG&E filed its comments on the draft decision regarding the Servicing Order, and DWR submitted a memorandum on the three draft decisions regarding the Servicing Order. DWR’s memorandum included a copy of “Amendment No. 2 To The First Amended and Restated Servicing Agreement Between The State of California Department of Water Resources and San Diego Gas & Electric Company” (Amendment No. 2). DWR states that Amendment No. 2 is intended to effect changes to the Agreement requested in D.02-11-074, the Bond Charge Decision. That decision, among other things, ordered SDG&E to make changes to its billing systems to impose the bond charges. As of December 9, 2002, SDG&E and DWR were in the process of executing Amendment No. 2. DWR states that it agrees to the provisions of Amendment No. 2, and requests that the Commission approve Amendment No. 2, or that the provisions of Amendment No. 2 be incorporated in the Commission’s final 2003 Servicing Order decision.

    DWR’s December 9, 2002 memorandum also states that it reserves comment on the draft decisions which would adopt the Servicing Orders. DWR considers it premature to comment on these draft decisions because DWR submitted a request to the Commission on December 9, 2002, requesting that the Commission order the utilities to enter into an operating agreement with DWR pursuant to Water Code Sec. 80106(b). DWR states that any Servicing Order adopted by the Commission must be consistent with the operating agreement request.

    SDG&E’s December 9, 2002 comments note that it has agreed with DWR on the terms of Amendment No. 2, and that it anticipates submitting a signed copy of Amendment No. 2 to the Commission with SDG&E’s December 16, 2002 reply comments. SDG&E states that the purpose of Amendment No. 2 is to revise the procedures found in the existing Servicing Agreement, and that the “revisions contemplate the manner by which SDG&E collects the DWR bond charges from its customers and remits them to DWR and the collection of fees by SDG&E for undertaking these agency services.” (SDG&E Comments, p. 4.)

    Amendment No. 2 makes four changes to SDG&E’s existing Amended Servicing Agreement. The first change is to add Section 7.5 to the Amended Servicing Agreement. Section 7.5 provides for a reconciliation payment in the event there is a change in the applicable law, or a payment procedure is inconsistent with applicable law. The second change makes a revision to Section 7.4 of the Amended Servicing Agreement to reference the addition of Section 7.5. The third change is a revised Attachment C to the Amended Servicing Agreement. The new Attachment C revises the format of the daily and monthly reports to include additional information about the implementation of the bond charges. The fourth change is a revised Attachment G to the Amended Servicing Agreement. As revised, Attachment G provides an estimate of SDG&E’s implementation costs associated with the DWR bond charge, and the reimbursement procedure that SDG&E and DWR will follow.

    We will incorporate the provisions of Amendment No. 2, as agreed to by DWR and SDG&E, into the Servicing Order that we adopt today. The revisions in Amendment No. 2 enable SDG&E to carry out the Commission’s directives contained in the Bond Charge Decision.

    We now turn to SDG&E’s concerns with the proposed modifications to the Amended Servicing Agreement.

    SDG&E’s first concern is that the use of “deemed” in sections 1.51 and 2.2.(c) of Amended Servicing Agreement are unnecessary because it may conflict with the pro rata sharing of revenues ordered in D.02-09-053 and because Attachments H and J specify how to determine the amount of energy provided by DWR and SDG&E.

    We agree with SDG&E. Attachments H and J explain how to determine the amount of energy provided by DWR and SDG&E. The use of the term or phrase starting with “deemed” could be interpreted to mean that another calculation of DWR energy is possible. We will delete the references in sections 1.51. and 2.2.(c).

    SDG&E’s second concern is whether the utility is acting as DWR’s agent for surplus sales, as found in the proposed modification to sections 2.3., 3.5. and 14.1. SDG&E urges the Commission to modify the draft decision to state that SDG&E’s agency role cannot be allowed to interfere with providing service to SDG&E’s customers. SDG&E states that its primary fiduciary obligation is to undertake its operational responsibilities, whether of its assets or of the allocated DWR contracts, in the best interests of the utility’s ratepayers and shareholders.”

    We decline to delete those references. The draft decision regarding the Operating Order notes that the utilities are operating as DWR’s agent for limited purposes, and that it reflects the nature of the capacity in which the utilities are undertaking these functions.

    SDG&E’s third concern is with the costs associated with credit risk management and the incremental costs associated with the sales of surplus energy. SDG&E states that the provisions of Section 3 of the Operating Order would place the credit risk management and costs on SDG&E. SDG&E states that credit risk management should be in the Operating Agreement, and not in the Servicing Order. If costs are incurred from the credit management, SDG&E states that DWR must share in these costs and that they should be included in the Servicing Order as part of the surplus energy sales revenue remittance calculation. SDG&E asserts that costs that are incremental to the sale should be attributed to the sales and any revenues should be net of any sales costs. SDG&E contends that under AB X1, SDG&E cannot be given any financial responsibility for DWR’s costs. In addition, SDG&E contends that AB 57 requires that its creditworthiness cannot be impaired. SDG&E raised similar arguments with respect to the Operating Order.

    We will accept DWR’s proposed modification to sections 3.1(c) and 3.1(d) of the Servicing Order. This is consistent with the Commission’s goal of reducing the utilities’ reliance on the use of state resources to fulfill their obligations to serve customers. As noted in the Operating Order decision, the collateral requirements are not imposed by the DWR Contracts, but rather by exogenous variables such as the ISO tariff. With respect to the incremental costs associated with surplus energy sales, the Operating Order decision addresses the recovery of those costs.

    SDG&E’s fourth concern is with sections 3.5 and 12, and whether DWR must provide indemnification or a waiver of liability in situations involving the sale of surplus energy and disputes with third-party purchasers. Section 12 of the Amended Servicing Agreement addresses indemnification issues, but does not specifically address how specific situations would be handled. SDG&E contends that the draft decision should be modified to state that DWR must provide indemnification or waiver of liability if SDG&E is going to act on DWR’s behalf. Neither DWR or SDG&E have proposed language to clarify the indemnification issue. We refrain from crafting additional indemnification language for the Servicing Order. This issue is best left to DWR and SDG&E to work out.

    The fifth concern of SDG&E is the timing of when SDG&E shall make its remittances to DWR for the sale of surplus energy. Under section 4.2(g) and Attachment J, SDG&E is to remit DWR’s share of the surplus sales revenues on the first business day after the 20th day of the month following each delivery month. SDG&E takes the position that it should not have to advance any funds to DWR, and that it should only remit DWR’s share of the surplus sales revenues when the purchasers of the power pay SDG&E.

    In SDG&E’s comments to the draft decision, SDG&E points out that the provision in Section 4.2(g) of the proposed Servicing Order requiring SDG&E to remit surplus sales revenue to DWR on the 20th of the month following delivery could result in SDG&E having to incur the cost of a 40- to 55- day float. SDG&E states that this would require a revenue increase for additional cash working capital in SDG&E’s next cost of service filing, which is contrary to, and not permitted under AB X1. SDG&E also points out that in DWR’s December 5, 2002 memorandum to the Commission, that DWR indicated that surplus sales revenue should be remitted on “an actual receipts basis” and not on a “cost incurred” basis. SDG&E states that the draft decision regarding the Operating Order refers to the “receipts” concept, while the Servicing Order uses an obsolete reference to 20 days.

    In D.02-09-053, at page 46, we stated that although DWR remains financially responsible for paying all contract-related bills, we expect that the utilities will “verify the invoices and instruct DWR to pay the bills.” This statement suggests that SDG&E should not have to advance funds to DWR before DWR has to pay its invoices. The provisions in section 4.2(g) and Attachment J would require SDG&E to remit payments within 20 days of each delivery month, which presumably does not match up with when the invoices are due. Exhibit C of the Operating Order, which is entitled “Settlement Principles For Remittances And Surplus Revenues,” provides at page C-3 that the: “Revenues from a forward market sale shall not be distributed to the Parties until after Utility receives the revenues from the sales and any sale-related charges.” In reference to “ISO Real Time Market Sales,” Exhibit C states that the: “Revenues from delivery of surplus energy to the ISO real time market shall not be distributed to the Parties until after Utility receives payment for final monthly invoice from the ISO for the month in which the surplus energy was delivered.” Both of the quoted passages mean that SDG&E should not have to remit revenues from the energy sales to DWR until SDG&E has received payment. Accordingly, we shall change the reference in Section 4.2(g) of the Servicing Order regarding the 20 days to make it consistent with Exhibit C of the Operating Order.

    Attachment J of the proposed Servicing Order is premised on remitting a preliminary amount of the surplus energy sales revenues to DWR on the first business day after the 20th day of the month. However, as discussed above, Exhibit C of the Operating Order specifies that revenues from forward sales, and sales to the ISO, are to be remitted to DWR after the utility has received payment. In order to make the Servicing Order consistent with the Operating Order, proposed Attachment J should be deleted from the Servicing Order that we adopt in this decision. In addition, other references to Attachment J that appear in the following sections of the Servicing Order shall also be deleted: 1.30.5.; 2.2.(d); 2.2.(f); 2.5.; 4.1.; 4.2.(g); 4.2.(h); 5.1.; 5.5.; and 14.17.

    SDG&E’s sixth concern is with the proposed modifications to sections H and I of Attachment B. SDG&E notes in its comments that section H.2. “should be deleted since this deals with the reconciliation SDG&E just completed.”

    We note that in DWR’s October 8, 2002 transmittal of the proposed modifications to Attachment B, that section H.2. had already been deleted. As for the proposed modifications to section I of Attachment B, the addition of this section is consistent with the Post-Transition Remittance Methodology that is to take effect on and after the effective date of the Operating Order as provided for in Attachment H.

    The seventh concern of SDG&E is that SDG&E has not included the Commission approved version of Attachment F in its proposed modifications. We have compared DWR’s submission of Attachment F to the version that was approved in D.02-07-038. DWR’s submission is virtually identical to what was approved in D.02-07-038, except that DWR’s October 8, 2002 submission does not contain the table entitled “Summary Results of 20/20 Conservation Program: August 2002.” We have indicated on Appendix A and Appendix B that the table approved in D.02-07-038 should be used in Attachment F.

    SDG&E’s eighth concern is with Attachment G, the DWR billing agent cost estimates. SDG&E states that this chart is outdated because it does not include bond charges and exit fees. SDG&E states that this section will need to be updated once these charges and fees are known. With that understanding, we recognize that Attachment G will need to be changed to reflect these additional charges and fees.

    SDG&E’s ninth concern is with the information that DWR wants in Service Attachment 2. SDG&E states that it is working with DWR to determine what kind of information DWR wants. DWR’s October 8, 2002 submission only included the one page “Service Attachment 2,” which described the “Title” of seven sections. DWR’s Service Attachment 2 also notes that this is “To be provided by Utility.” We will retain the Service Attachment 2 page as part of the Servicing Order, with the understanding that DWR and SDG&E will need to discuss what kind of information DWR wants from SDG&E.

    The majority of the proposed modifications to the Amended Servicing Agreement reflect the actions taken in the Contract Allocation Decision, and are also linked to the proposed operating agreement. All of the proposed modifications, as shown in the attached Servicing Order and as discussed above, are consistent with the directives ordered in D.01-09-013, D.02-02-051, D.02-02-052, and D.02-09-053.

    Since DWR and SDG&E have been unable to timely agree on a mutually acceptable modified Amended Servicing Agreement, we have further modified DWR’s proposed modifications to the Amended Servicing Agreement to turn the document into a Servicing Order. The marked and clean versions of the Servicing Order, which are attached to this decision as Appendix A and Appendix B, are approved. SDG&E shall be directed to comply with the terms and conditions of the attached Servicing Order.

    We note that today’s approval of the Servicing Order does not prevent DWR and SDG&E from negotiating a mutually agreeable modified servicing agreement in the future and bringing such an agreement to us for approval. However, due to the approaching deadline for when SDG&E is to take over the operational aspects of the DWR contracts allocated to SDG&E, the attached Servicing Order is needed so that the operational transition for the DWR contracts can proceed smoothly.

    Southern California Edison Company (SCE) raised a point in its comments to the draft decision regarding SCE’s Servicing Order that has applicability to SDG&E as well. SCE states in its comments that it has had discussions with DWR as to the possible terms and conditions that could be included in the Amended Servicing Agreement. Although it is unclear at this point whether such discussions will lead to an agreement, SCE seeks clarification from the Commission that SCE be allowed to seek the termination of any Servicing Order that may be adopted, with an executed agreement between SCE and DWR “which substantially and fundamentally comport with the terms and conditions set forth in the . . .Servicing Order and the related attachments as they then exist.” (SCE December 9, 2002 Comments, p. 11.)

    We are receptive to reviewing a mutually agreeable servicing arrangement between SDG&E and DWR, so long as the terms do not substantially deviate from what’s adopted in today’s servicing order. Should SDG&E and DWR negotiate such an arrangement, SDG&E is free to request that the Commission consider replacing the Servicing Order adopted in today’s decision with the mutually agreeable arrangement.

    Rehearing and Judicial Review

    This decision construes, applies, implements, and interprets the provisions of AB X1. Pursuant to Public Utilities Code Sec. 1731(c) any application for rehearing of this decision must be filed within 10 days of the date of issuance of this decision, and the provisions of Public Utilities Code Sec. 1768 are applicable to any judicial review of this decision.

     

    Comments on Draft Decision

    Pursuant to Public Utilities Code Sec. 311(g)(1) and Rule 77.7 of the Commission’s Rules of Practice and Procedure, the draft decision of the ALJ was mailed to the parties on November 20, 2002. The comments on the draft decision have been reviewed, and appropriate changes have been made to the Servicing Order and the attachments.

    Assignment of Proceeding

    Loretta M. Lynch is the Assigned Commissioner and John S. Wong is the assigned ALJ in this proceeding.

    Findings of Fact

    1. In response to D.02-09-053, on October 8, 2002, DWR submitted a memorandum and its proposed modifications to the Amended Servicing Agreement.
    2. Prior to today’s decision, the existing servicing arrangement between DWR and SDG&E are composed of the Amended Servicing Agreement and Amendment No. 1.
    3. D.02-09-053 allocated the DWR contracts, and ordered SDG&E and the other two large electric utilities, to assume all of the operational, dispatch, and administrative functions for the allocated electricity contracts, effective January 1, 2003.
    4. The proposed modifications to the Amended Servicing Agreement and related attachments have been compared to the Amended Servicing Agreement that was approved in D.02-04-048, to Amendment No. 1 approved in D.02-07-038, and have been reviewed in light of the Contract Allocation Decision.
    5. One of the goals of R.01-10-024 is to allow the utilities to resume purchasing electric energy, capacity, ancillary services and related hedging instruments to fulfill their obligation to serve and meet the needs of their customers.
    6. In order for SDG&E and the other utilities to undertake the operational responsibilities associated with the allocated DWR contracts beginning on January 1, 2003, certain operational arrangements and servicing arrangements need to be in place before that date.
    7. Certain provisions of the proposed operating agreement may affect certain provisions of the proposed modifications to the Amended Servicing Agreement and related attachments.
    8. The proposed operational agreement is being considered by the Commission in R.01-10-024.
    9. The concerns of SDG&E over the proposed modifications to the Amended Servicing Agreement and related attachments have been reviewed and considered, and appropriate changes have been made as discussed in this decision.
    10. Notwithstanding today’s approval of the Servicing Order, DWR and SDG&E are free to submit a mutually agreeable modified servicing agreement for our approval.
    11. Conclusions of Law

      1. All of the proposed modifications to the Amended Servicing Agreement and the related attachments are consistent with the directives ordered in prior Commission decisions.
      2. Since DWR and SDG&E have been unable to timely agree on a mutually acceptable modified Amended Servicing Agreement, the Commission has made additional modifications to convert the modified Amended Servicing Agreement into a Servicing Order.
      3. The Servicing Order attached to this decision should be approved.
      4. SDG&E should be directed to comply with the terms and conditions contained in the approved Servicing Order.
      5. ORDER

        IT IS ORDERED that:

        1. The marked version, attached hereto as Appendix A, and the clean version, attached hereto as Appendix B, of the “2003 Servicing Order Concerning State of California Department of Water Resources And San Diego Gas & Electric Company” (Servicing Order) is approved.
        2. San Diego Gas & Electric Company shall comply with all of the terms and conditions of the approved Servicing Order.
        3. This proceeding is closed.

        This order is effective today.

        Dated December 19, 2002, at San Francisco, California.

         

        LORETTA M. LYNCH

        President

        HENRY M. DUQUE

        CARL W. WOOD

        GEOFFREY F. BROWN

        MICHAEL R. PEEVEY

        Commissioners

         

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        About Leslie Brodie

        Leslie Brodie is a reporter, writer, blogger, activist, and a religious leader in the community.

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