ITEM 1. BUSINESS
DESCRIPTION OF BUSINESS
A description of San Diego Gas & Electric (SDG&E or the company) is given in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
GOVERNMENT REGULATION
Local Regulation SDG&E has electric franchises with the three counties and the 26 cities, and gas franchises with one county and the 23 cities in its 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 Chula Vista (2003), 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).
California Utility Regulation The State of California Legislature, from time to time, passes laws that regulate SDG&E's operations. For example, in 1996 the legislature passed an electric industry deregulation bill, and then in 2000 and 2001 passed additional bills aimed at addressing problems in the deregulated electric industry. In addition, the legislature enacted a law in 1999 addressing natural gas industry restructuring. The California Public Utilities Commission (CPUC), which consists of five commissioners appointed by the Governor of California for staggered six-year terms, regulates SDG&E's 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 also 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 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.
United States Utility Regulation The Federal Energy Regulatory Commission (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. 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.
Licenses and Permits SDG&E obtains a number of permits, authorizations and licenses in connection with the transmission and distribution of natural gas and electricity. They require periodic renewal, which results in continuing regulation by the granting agency. Other regulatory matters are described in Notes 12 and 13 of the notes to Consolidated Financial Statements herein.
SOURCES OF REVENUE
Information on this topic is provided in Note 2 of the notes to Consolidated Financial Statements herein.
ELECTRIC OPERATIONS
Resource Planning In 1996, California enacted legislation restructuring California's investor-owned electric utility industry. The legislation and related decisions of the CPUC were intended to stimulate competition and reduce rates. Beginning on March 31, 1998, customers were given the opportunity to choose to continue to purchase their electricity from the local utility under regulated tariffs, to enter into contracts with other energy service providers (direct access), or to buy their power from the California Power Exchange (PX) that served as a wholesale power pool allowing all energy producers to participate competitively. However, supply/demand imbalances and a number of factors resulted in abnormally high wholesale electric prices beginning in mid-2000, which caused SDG&E's monthly customer bills to be substantially higher than normal. These conditions and the resultant abnormally high electric-commodity prices continued into 2001. In response to these high commodity prices, the California legislature has adopted legislation intended to stabilize the California electric utility industry and reduce wholesale electric commodity prices. These actions include the California Department of Water and Resources (DWR) purchasing the net short position of SDG&E (the power needed by SDG&E's customers, other than that provided by SDG&E's nuclear generating facilities or its previously existing purchase power contracts) and the Memorandum of Understanding (MOU) entered into by representatives of California Governor Davis, the DWR, Sempra Energy, and SDG&E. Subject to CPUC approval, the MOU contemplated the implementation of a series of transactions and regulatory settlements and actions to resolve many of the issues affecting SDG&E and its customers arising out of the California energy crisis. Additional information concerning the MOU and electric-industry restructuring in general is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 12 and 13 of the notes to Consolidated Financial Statements herein.
Electric Resources In connection with California's electric-industry restructuring, beginning March 31, 1998, the California investor-owned utilities (IOUs) were obligated to bid their power supply, including owned generation and purchased-power contracts, into the PX. The IOUs also were obligated to purchase from the PX the power that they sell. In 1999, SDG&E completed divestiture of its owned generation other than nuclear. An Independent System Operator (ISO) schedules power transactions and access to the transmission system. As discussed in Note 12 of the notes to Consolidated Financial Statements, due to the conditions in the California electric utility industry, the PX suspended its trading operations on January 31, 2001. SDG&E has been granted authority by the CPUC to purchase up to 1,900 megawatts of power through bilateral contracts. Also, as discussed above, the California legislature passed laws (e.g., Assembly Bill 1 in February 2001), authorizing the DWR to enter into long-term contracts to purchase the portion of power used by SDG&E customers that is not provided by SDG&E's existing supply. Based on generating plants in service and purchased-power contracts currently in place, at February 28, 2002, the megawatts (mW) of electric power available to SDG&E are as follows:
Source mW -------------------------------------------------- Nuclear generating plants 430* Long-term contracts with other utilities 84 Contracts with others 359 ----- Total 873 ===== * Net of plants' internal usage
San Onofre Nuclear Generating Station (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 down the unit. At that time SDG&E began the recovery of its remaining capital investment, with full recovery completed in April 1996. The unit's spent nuclear fuel has been removed from the reactor and is stored on-site. In March 1993, the NRC issued a Possession-Only License for Unit 1, and the unit was placed in a long-term storage condition in May 1994. In June 1999, the CPUC granted authority to begin decommissioning Unit 1. Decommissioning work 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 mW of Unit 2 and 216 mW of Unit 3. SDG&E deposits funds in an external trust to provide for the decommissioning of all three units. During 2001, SDG&E spent $6 million on capital additions and modifications of Units 2 and 3, and expects to spend $9 million in 2002. Additional information concerning the SONGS units, nuclear decommissioning and industry restructuring is provided below and in "Environmental Matters" and "Electric Properties" herein, and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 5, 11 and 12 of the notes to Consolidated Financial Statements herein.
Purchased Power: The following table lists contracts with SDG&E's various suppliers:
Expiration Megawatt Supplier Date Commitment Source - ------------------------------------------------------------------
Long-Term Contracts with Other Utilities:
Portland General Electric (PGE) December 2013 84 Coal ------ Total 84 ====== Other Contracts:
Qualifying Facilities (QFs) --
Applied Energy December 2019 102 Cogeneration
Yuma Cogeneration June 2024 50 Cogeneration
Goal Line Limited Partnership December 2025 50 Cogeneration
Other QFs (73) Various 32 Cogeneration ------ Others --
Various (3) December 2003 125 System Supply ------ Total 359 ======
Under the contract with PGE, SDG&E pays a capacity charge plus a charge based on the amount of energy received. Charges under this contract are based on PGE's costs, including lease payments, fuel expenses, operating and maintenance expenses, transmission expenses, administrative and general expenses, and state and local taxes. Costs under the contracts with QFs are based on SDG&E's avoided cost. Charges under the remaining contracts are for firm energy only 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. Additional information concerning SDG&E's purchased-power contracts is provided below, and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 12 of the notes to Consolidated Financial Statements herein.
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 220 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 ISO.
Transmission Access As a result of the enactment of the National Energy Policy Act of 1992, the FERC has established rules to implement the Act's transmission-access provisions. These rules specify FERC-required 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. On March 31, 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" herein.
Fuel and Purchased-Power Costs The following table shows the percentage of each electric-fuel source used by SDG&E and compares the kilowatt hour (kWh) costs of the fuels with each other and with the total cost of purchased power:
Percent of kWh Cents per kWh - --------------------------------------------------------------- 2001 2000 1999 2001 2000 1999 ----- ----- ----- ---- ---- ---- Natural gas * -- -- 6.5 -- -- 3.0 Nuclear fuel 30.1 14.9 12.6 0.5 0.5 0.5 ----- ----- ----- Total generation 30.1 14.9 19.1 Purchased power and ISO/PX 69.9 85.1 80.9 9.4 9.7 3.7 ----- ----- ----- Total 100.0% 100.0% 100.0% ====== ====== ======
* SDG&E sold its fossil-fuel generating plants during the quarter ended June 30, 1999. The cost of purchased power includes capacity costs as well as the costs of fuel. The cost of natural gas includes transportation costs. The costs of natural gas and nuclear fuel do not include SDG&E's capacity costs. While fuel costs are significantly less for nuclear units than for other units, capacity costs are higher. As discussed above in "Resource Planning" and "Electric Resources", during February 2001 the DWR began purchasing the portion of power used by SDG&E customers that was not provided by SDG&E's nuclear generating facilities or its previously existing purchase power contracts.
Electric Fuel Supply Natural Gas: Information concerning natural gas is provided in "Natural Gas Operations" herein. Nuclear Fuel: The nuclear-fuel cycle includes services performed by others under contract through 2003, 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 will be adequate at least through 2005. If necessary, modifications in fuel storage technology can be implemented to provide on-site storage capacity for operation 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 $0.90 per megawatt-hour of net nuclear generation, or approximately $3 million per year. The DOE projects it will not begin accepting spent fuel until 2010. To the extent not currently provided by contract, 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 11 of the notes to Consolidated Financial Statements herein.
NATURAL GAS OPERATIONS
SDG&E purchases and distributes natural gas to 774,000 end-use customers throughout the western portion of San Diego County. The company also transports natural gas to over 1,000 customers who procure their natural gas from other sources.
Supplies of Natural Gas SDG&E buys natural gas under several short-term and long-term contracts. Short-term purchases are from various Southwest U.S. and Canadian suppliers and are primarily based on monthly spot-market prices. SDG&E transports gas under long-term firm pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SDG&E has long-term natural gas transportation contracts with various interstate pipelines which expire on various dates between 2003 and 2023. SDG&E has a long-term purchase agreement with a Canadian supplier that expires in August 2003, and in which the delivered cost is tied to the California border spot-market price. SDG&E purchases natural gas on a spot basis to fill its additional long-term pipeline capacity. SDG&E intends to continue using the long- term pipeline capacity in other ways as well, including the transport of other natural gas for its own use and the release of a portion of this capacity to third parties. Most of the natural gas purchased and delivered by the company is produced outside of California. These supplies are delivered to the pipeline owned by an SDG&E affiliate, Southern California Gas Company (SoCalGas), at the California border by interstate pipeline companies, primarily El Paso Natural Gas Company and Transwestern Natural Gas Company. These interstate companies provide transportation services for supplies purchased from other sources by the company or its transportation customers. The rates that interstate pipeline companies may charge for natural gas and transportation services are regulated by the FERC. All natural gas is delivered to SDG&E under a transportation and storage agreement with SoCalGas.
The following table shows the sources of natural gas deliveries from 1997 through 2001.
Market-sensitive natural gas supplies (supplies purchased on the spot market, ranging from one month to two years, as well as under longer- term contracts based on spot prices) accounted for nearly all of total natural gas volumes purchased by the company. The average price of natural gas at the California/Arizona border was $7.27/mmbtu in 2001, compared with $6.25/mmbtu in 2000, and $2.33/mmbtu in 1999. Supply/demand imbalances and a number of other factors associated with California's energy crisis in late 2000 and in early 2001 resulted in higher natural gas prices during that period. Prices for natural gas have subsequently decreased in the later part of 2001. As of December 31, 2001, the average spot cash price at the California/Arizona border was $2.63/mmbtu. The company provided transportation services for the customer- owned natural gas. The company estimates that sufficient natural gas supplies will be available to meet the requirements of its customers for the next several years.
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. There are 775,000 core customers (746,000 residential and 29,000 small commercial and industrial). There are 82 noncore customers which consist primarily of electric generating plants (UEG), wholesale purchasers, and large commercial and industrial customers. Most core customers purchase natural gas directly from the company. Core customers are permitted to aggregate their natural gas requirement and, up to a limit of 10 percent of the company's core market, to purchase natural gas directly from brokers or producers. Beginning in 2002, the CPUC authorized the removal of the 10 percent limit. The company continues to be obligated to purchase reliable supplies of natural gas to serve the requirements of its core customers. The California utilities recently filed an application with the CPUC to combine their core procurement portfolios. On March 6, 2002, a proposed decision was issued which, if approved, will allow SDG&E and SoCalGas to combine their core procurement portfolios. A final CPUC decision is expected in mid-2002. Beginning in 2002, utility procurement services offered to noncore customers will be phased out. Noncore customers will have the option to either become core customers, and continue to receive utility procurement services, or remain noncore customers and purchase their natural gas from other sources, such as brokers or producers. Noncore customers will also have to make arrangements to deliver their purchases to the company's receipt points for delivery through the company's transmission and distribution system. In 2001, approximately 89 percent of the CPUC-authorized natural gas margin was allocated to the core customers, with 11 percent allocated to the noncore customers. Although revenues from transportation throughput is less than for natural gas sales, the company generally earns the same margin whether the company buys the gas and sells it to the customer or transports natural gas already owned by the customer.
Demand for Natural Gas Natural gas is a principal energy source for residential, commercial, industrial and electric generating plant customers. Natural gas competes with electricity for residential and commercial cooking, water heating, space heating and clothes drying, and with other fuels for large industrial, commercial customers and UEG uses. Growth in the natural gas markets is largely dependent upon the health and expansion of the southern California economy. The company added approximately 12,000 and 13,000 new customer meters in 2001 and 2000, respectively, representing growth rates of approximately 1.6 percent and 1.8 percent, respectively. The company expects its growth rate for 2002 will approximate that of 2001. During 2001, 90 percent of residential energy customers in the company's service area used natural gas for water heating, 75 percent for space heating, 55 percent for cooking and 40 percent for clothes drying. Demand for natural gas by noncore customers is very sensitive to the price of competing fuels. Although the number of noncore customers in 2001 was only 82, they accounted for approximately 8 percent of the authorized natural gas revenues and 67 percent of total natural gas volumes. 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 demand for natural gas by large UEG customers is also greatly affected by the price and availability of electric power generated in other areas. Effective March 31, 1998, electric industry restructuring gave California consumers the option of selecting their electric energy provider from a variety of local and out-of-state producers. 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 company's 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 electricity generation from the company's service area.
Other Additional information concerning customer demand and other aspects of natural gas operations is provided under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 11, 12 and 13 of the notes to Consolidated Financial Statements herein.
RATES AND REGULATION
Electric Industry Restructuring A flawed electric-industry restructuring plan, electricity supply/demand imbalances and legislative and regulatory responses have significantly impacted the company's operations. Additional information on electric-industry restructuring is provided above under "Electric Operations," in "Management's Discussion and Analysis of Financial Condition and Results of Operations," and in Note 12 of the notes to Consolidated Financial Statements herein.
Natural Gas Industry Restructuring The natural gas industry in California experienced an initial phase of restructuring during the 1980s. In December 2001 the CPUC issued a decision adopting provisions affecting the structure of the natural gas industry in California, some of which could introduce additional volatility into the earnings of SDG&E and other market participants. Additional information on natural gas industry restructuring is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 13 of the notes to Consolidated Financial Statements herein.
Balancing Accounts In general, earnings fluctuations from changes in the costs of natural gas and consumption levels for the majority of natural gas are eliminated through balancing accounts authorized by the CPUC. As a result of California's electric restructuring law, overcollections recorded in the electric balancing accounts were applied to transition cost recovery, and fluctuations in certain costs and consumption levels can now affect earnings from electric operations. Additional information on balancing accounts is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 2 of the notes to Consolidated Financial Statements herein.
Biennial Cost Allocation Proceeding (BCAP) Rates to recover the changes in the cost of natural gas transportation services are determined in the BCAP. The BCAP adjusts rates to reflect variances in customer demand from estimates previously used in establishing customer natural gas transportation rates. The mechanism substantially eliminates the effect on income of variances in market demand and natural gas transportation costs. Additional information on the BCAP is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 13 of the notes to Consolidated Financial Statements herein.
Cost of Capital The authorized cost of capital is determined by an automatic adjustment mechanism based on changes in certain capital market indices. Additional information on SDG&E's cost of capital is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 12 of the notes to Consolidated Financial Statements herein.
ENVIRONMENTAL MATTERS
Discussions about environmental issues affecting SDG&E are included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein. 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, a mechanism that allows SDG&E and other utilities to recover in rates the costs associated with the cleanup of sites contaminated with hazardous waste. In general, utilities are allowed to recover 90 percent of their cleanup costs and any related costs of litigation. During the early 1900s, SDG&E and its predecessors manufactured gas from coal or oil. The manufacturing sites often have become contaminated with the hazardous residual by-products of the process. SDG&E has identified three former manufactured-gas plant sites. These sites have been remediated and closure letters have been received for two of the sites (discussed below). Under authority from the Redevelopment Agency for the City of San Diego, and under oversight by the County of San Diego, Station A (a former electric generating facility) has been undergoing remediation since 1998. The vast majority of remedial activities were completed in 1999 and early 2000. $8.7 million was spent in 1999, with an additional $1.3 million spent in 2000 and $0.3 million spent in 2001. Included in the activity was remediation of several underground storage tanks, cleanup of lead-contaminated soil on one block of Station A, and remediation of fuel oil believed to have leaked from pipelines under city streets. All closure letters have been received from the County, with the exception of one open case related to ongoing groundwater monitoring. At December 31, 2001, the estimated remaining remediation liability is less than $0.2 million. As properties are developed, there remains a possibility that additional contaminated soil will be found. Remediation was completed in 2000 at SDG&E's former manufactured- gas plant site in Oceanside at the cost of $0.5 million. Offsite cleanup was completed in 2001 at a cost of $47,000. 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. Estimated costs to perform the necessary remediation are $11 million. 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 2001, cleanup was completed at three minor sites at a cost of $0.3 million. Also during 2001, additional assessments were performed at the primary sites at a cost of $0.3 million. Cleanup completion is expected by the end of 2002. Demolition of the Encanto Gas Holder Station began in 2000. The site, taken out of service in 1995, consisted of a compressor building and over nine miles of 30-inch diameter steel pipe used to store gas. Contamination issues at the site include asbestos and hydrocarbons. Completion of the cleanup is expected in 2002. Cleanup expenses through the end of 2001 were $0.9 million and remaining expenses, expected to be incurred in 2002, are estimated at $0.5 million. SDG&E lawfully disposed 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. SDG&E and 10 other entities have been named potentially responsible parties (PRPs) by the California Department of Toxic Substances Control (DTSC) as liable for any required corrective action regarding contamination at an industrial waste disposal site in Pico Rivera, California. DTSC has taken this action because SDG&E and others sold used electrical transformers to the site's owner. SDG&E and the other PRPs have entered into a cost-sharing agreement to provide funding for the implementation of a consent order between DTSC and the site owner for the development of a cleanup plan. SDG&E's interim share under the agreement is 10.1 percent, subject to adjustment based on ultimate responsibility allocations. The total estimate for all PRPs is $1 million for the development of the cleanup plan and $2 million to $8 million for the actual cleanup. Since inception, SDG&E's share of the cleanup expenses was $0.2 million, including $47,000 in 2001. At December 31, 2001, SDG&E's estimated remaining investigation and remediation liability related to hazardous waste sites, including the manufactured-gas sites, was $1 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-fueled 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 SDG&E'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 adverse health effects and exposure to the type of EMFs emitted by power lines and other electrical facilities. 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 childhood leukemia and the proximity of homes to certain power lines and equipment. 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 utilities 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 has now less significance to the company's operations. 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 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 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 $27.7 million. These mitigation projects are expected to be completed by 2007.
OTHER MATTERS
Research, Development and Demonstration (RD&D) For 2001, the CPUC authorized SDG&E to fund $1.2 million and $4 million for its natural gas and electric RD&D programs, respectively, which includes $3.9 million to the CEC for its PIER (Public Interest Energy Research) Program. SDG&E co-funded several of these projects with the CEC. Annual RD&D costs have averaged $4.4 million over the past three years.
Employees of Registrant As of December 31, 2001, SDG&E had 3,106 employees, compared to 3,248 at December 31, 2000.
Wages Certain employees at SDG&E are represented by the International Brotherhood of Electrical Workers, Local 465. The current contract runs through August 31, 2004.
ITEM 2.
ITEM 2. PROPERTIES
Electric Properties SDG&E's generating capacity is described in "Electric Resources" herein. SDG&E's electric transmission and distribution facilities include substations, and overhead and underground lines. The electric facilities are located in San Diego, Imperial and Orange counties and in Arizona, and consist of 1,799 miles of transmission lines and 20,428 miles of distribution lines. Periodically various areas of the service territory require expansion to accommodate customer growth.
Natural Gas Properties SDG&E's natural gas facilities are located in San Diego and Riverside counties and consist of the Moreno and Rainbow compressor stations, 166 miles of high pressure transmission pipelines, 7,449 miles of high and low pressure distribution mains, and 5,989 miles of service lines.
Other Properties 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. SDG&E owns or leases other offices, operating and maintenance centers, shops, service facilities, and equipment necessary in the conduct of business.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Except for the matters described in Note 11 of the notes to Consolidated Financial Statements or referred to elsewhere in this Annual Report, neither the company nor its subsidiary 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of the issued and outstanding common stock of SDG&E is owned by Enova Corporation, a wholly owned subsidiary of Sempra Energy. The information required by Item 5 concerning dividends declared is included in the "Statements of Consolidated Changes in Shareholders' Equity" set forth in Item 8 of this Annual Report herein.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Since San Diego Gas & Electric Company is a wholly owned subsidiary of Enova Corporation, per share data has been omitted. This data should be read in conjunction with the Consolidated Financial Statements and the notes to Consolidated Financial Statements contained herein.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
This section includes management's discussion and analysis of operating results from 1999 through 2001, and provides information about the capital resources, liquidity and financial performance of San Diego Gas & Electric (SDG&E or the company). It also focuses on the major factors expected to influence future operating results and discusses investment and financing plans. It should be read in conjunction with the Consolidated Financial Statements included in this Annual Report. The company is an operating public utility engaged in electric and natural gas businesses which provide services to 3 million customers. It generates and purchases electric energy and distributes it through 1.2 million electric meters in San Diego County and an adjacent portion of southern Orange County, California. It also purchases and distributes natural gas through 0.8 million meters in San Diego County and transports electricity and gas for others. SDG&E's only subsidiary is SDG&E Funding LLC, which was formed to facilitate the issuance of SDG&E's rate reduction bonds as described in Note 4 of the notes to Consolidated Financial Statements.
Business Combination
Sempra Energy was formed to serve as a holding company for Pacific Enterprises (PE), the parent corporation of the Southern California Gas Company (SoCalGas), and Enova Corporation (Enova), the parent corporation for SDG&E, in connection with a tax-free business combination that became effective on June 26, 1998 (the business combination). In connection with the business combination, the holders of common stock of PE and Enova became the holders of Sempra Energy's common stock. See Note 1 of the notes to Consolidated Financial Statements for additional information.
Capital Resources and Liquidity
The company's operations have historically been a major source of liquidity. However, beginning in the third quarter of 2000 and continuing into the first quarter of 2001, SDG&E's liquidity and its ability to make funds available to Sempra Energy were adversely affected by the electric cost undercollections resulting from a temporary ceiling on electric rates legislatively imposed in response to high electric costs. Significant growth in these undercollections has ceased as a result of an agreement with the California Department of Water and Resources (DWR), under which the DWR is obligated to purchase SDG&E's full net short position consisting of the power and ancillary services required by SDG&E's customers that are not provided by SDG&E's nuclear generating facilities or its previously existing purchase power contracts. The agreement extends through December 31, 2002. In addition, the California Public Utilities Commission (CPUC) is conducting proceedings intended to establish guidelines and procedures for the eventual resumption of electricity procurement by SDG&E and the other California investor-owned utilities (IOUs). In addition, electric costs are now below and are expected to remain below the rates under the rate ceiling. See further discussion in Note 12 of the notes to Consolidated Financial Statements. In June 2001, representatives of California Governor Davis, the DWR, Sempra Energy and SDG&E entered into a Memorandum of Understanding (MOU) contemplating the implementation of a series of transactions and regulatory settlements and actions to resolve many of the issues affecting SDG&E and its customers arising out of the California energy crisis. Many of the significant elements of the MOU have received the requisite approvals of the CPUC and have been implemented. These include settlement of reasonableness reviews and the application by SDG&E of its $100 million refund involving the prudence of its purchased-power costs and its overcollections in other regulatory balancing accounts to reduce the rate-ceiling balancing account to $392 million at December 31, 2001. However, in January 2002, the CPUC rejected the MOU's proposed settlement regarding the rate-making treatment of favorably priced intermediate-term electricity purchase contracts held by SDG&E. In May 2001, the CPUC issued a decision that, effective February 1, 2001, electricity purchased under these contracts was to be provided by SDG&E to its customers at cost. This decision is inconsistent with prior CPUC staff positions that the electricity was to be provided at current market prices, with any resulting profits or losses borne by SDG&E. In accordance with the May 2001 CPUC decision, SDG&E ceased recording profits from these contracts effective February 1, 2001, and none of the profits from the contracts, which have now expired, are included in the rate-ceiling balancing account. SDG&E had appealed the CPUC's decision to the California Court of Appeals, but held the appeal in abeyance pending the settlement contemplated by the MOU, under which $219 million of the contract profits (including those that would have been attributable to periods subsequent to February 1, 2001 and, therefore, are not reflected in income) would have been applied to reduce the rate-ceiling balancing account, with the balance of the profits retained by SDG&E. Following the CPUC rejection of this portion of the MOU in January 2002, SDG&E is proceeding with its appeal and has also filed a complaint in federal district court in San Diego against the CPUC alleging that the CPUC's actions constitute an unconstitutional taking and have denied SDG&E its due process rights. The timing and manner of resolution of this issue will affect SDG&E's cash flows from the rate-ceiling balancing account. For additional discussion, see "Factors Influencing Future Performance--Electric Industry Restructuring and Electric Rates" herein and Note 12 of the notes to Consolidated Financial Statements.
Cash Flows From Operating Activities
Net cash provided by operating activities totaled $557 million, $174 million and $520 million for 2001, 2000 and 1999, respectively. The increase in cash flows from operating activities in 2001 compared to 2000 was primarily due to lower customer refunds paid by SDG&E in 2001 (see below) and the increase in overcollected regulatory balancing accounts, partially offset by a decrease in accounts payable. The decrease in accounts payable was due to decreases in the average prices for natural gas and the DWR's purchasing of SDGE's net short position for power. The decrease in cash flows from operating activities in 2000 was primarily due to SDG&E's refunds to customers for surplus rate- reduction-bond proceeds, SDG&E's cost undercollections related to high-electric commodity prices, and energy charges in excess of the 6.5 cents per kilowatt-hour(kWh) ceiling in accordance with AB 265 (see "Results of Operations" below and Note 12 of the notes to Consolidated Financial Statements). These factors were partially offset by higher deferred income taxes and accounts payable. The increase in accounts payable is primarily due to higher sales volumes and higher prices for natural gas and purchased power. The increase in deferred income taxes primarily relates to the timing of deductions for undercollections associated with the higher electricity costs referred to above.
Cash Flows From Investing Activities
Net cash provided by (used in) investing activities totaled ($310) million, $288 million and ($225) million for 2001, 2000 and 1999, respectively. For 2001, cash flows used in investing activities consisted primarily of capital expenditures of $307 million for the upgrade and expansion of utility plant. The decrease in cash flows from investing activities in 2001 was attributable to loan repayments from Sempra Energy in 2000. In addition, the increase in proceeds from sale of assets was due to the sale of property in Blythe, California, for $42 million. Net cash provided by investing activities increased in 2000 primarily due to the loan repayments noted above, partially offset by higher capital expenditures. For 2000, cash flows used in investing activities consisted primarily of capital expenditures of $324 million for the upgrade and expansion of utility plant.
Capital Expenditures Capital expenditures in 2001 were down slightly from 2000, which was $79 million higher than 1999 primarily due to additions and improvements to SDG&E's natural gas and electric distribution systems. Over the next five years, the company expects to make capital expenditures of approximately $2 billion. Construction, investment and financing programs are continuously reviewed and revised by the company in response to changes in economic conditions, competition, customer growth, inflation, customer rates, the cost of capital, and environmental and regulatory requirements. Capital expenditures in 2002 are expectedly to be significantly higher than in 2001. Significant capital expenditures in 2002 are expected to include $460 million for additions to the company's natural gas and electric distribution systems. These expenditures are expected to be financed by operations and security issuances. These capital expenditures are dependent on SDG&E's ability to recover its electricity costs, including the balancing account undercollections referred to above.
Cash Flows From Financing Activities
Net cash used in financing activities totaled $181 million, $543 million and $242 million for 2001, 2000 and 1999, respectively. Net cash used in financing activities decreased in 2001 primarily due to higher dividends paid to Sempra Energy in 2000 and the increase in the issuance of long-term debt in 2001. The increase in net cash used in financing activities in 2000 is attributable to the higher dividends noted above.
Long-Term Debt In 2001, repayments on long-term debt included $66 million of rate- reduction bonds and $25 million of unsecured variable-rate bonds. During December 2000, $60 million of variable-rate industrial development bonds were put back by the holders and subsequently remarketed in February 2001 at a fixed interest rate of 7 percent. In 2000 and 1999, repayments on long-term debt included $66 million of rate-reduction bonds in each year. $10 million and $28 million of first-mortgage bonds were also repaid in 2000 and 1999, respectively.
Dividends Dividends paid to Sempra Energy amounted to $150 million in 2001, compared to $400 million in 2000 and $100 million in 1999. The payment of future dividends and the amount thereof are within the discretion of the company's board of directors. The CPUC's regulation of SDG&E's capital structure limits to $178 million the portion of its December 31, 2001, retained earnings that is available for dividends to Sempra Energy.
Capitalization Total capitalization, including the current portion of long-term debt, was $2.5 billion at December 31, 2001. The debt-to-capitalization ratio was 53 percent at December 31, 2001.
Cash and Cash Equivalents At December 31, 2001, the company had $250 million of revolving lines of credit, none of which was borrowed. A description of the credit lines and other information concerning them and related matters is provided in Notes 3, 4 and 12 of the notes to Consolidated Financial Statements. Management believes that these amounts, cash flows from operations and new security issuances will be adequate to finance capital expenditure requirements and other commitments.
Commitments The following is a summary of the company's contractual commitments at December 31, 2001 (in millions of dollars). Additional information concerning these commitments is provided above and in Notes 4 and 11 of the notes to Consolidated Financial Statements.
Credit Ratings The credit ratings for SDG&E are as follows:
(As of February 21, 2002) S&P Moody's Fitch - ---------------------------------------------------------------- Secured Debt AA- Aa3 AA Unsecured Debt A+ A1 AA- Preferred Stock A A3 A+ Commercial Paper A-1+ P-1 +
In late 2000, California regulatory uncertainties led the credit- rating agencies to change their rating outlooks on some of these securities to negative. SDG&E still has negative outlooks from the three agencies.
Results of Operations
To understand the operations and financial results of SDG&E, it is important to understand the ratemaking procedures that SDG&E follows. SDG&E is regulated by the CPUC. It is the responsibility of the CPUC to determine that utilities operate in the best interests of their customers and have the opportunity to earn a reasonable return on investment. In 1996, California enacted legislation restructuring California's investor-owned electric utility industry. The legislation and related decisions of the CPUC were intended to stimulate competition and reduce electric rates. As part of the framework for a competitive electric-generation market, the legislation established the California Power Exchange (PX) and the Independent System Operator (ISO). The PX served as a wholesale power pool and the ISO scheduled power transactions and access to the transmission system. Due to subsequent industry restructuring developments, the PX suspended its trading operations in January 2001. The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. In December 2001, the CPUC issued a decision adopting several provisions that the company believes will make gas service more reliable, efficient and better tailored to the desires of customers. The CPUC is still considering the schedule for implementation of these regulatory changes, but it is expected that most of the changes will be implemented during 2002. In connection with restructuring of the electric and natural gas industries, SDG&E received approval from the CPUC for Performance-Based Ratemaking (PBR). Under PBR, income potential is tied to achieving or exceeding specific performance and productivity measures, rather than to expanding utility plant in a market where a utility already has a highly developed infrastructure. See additional discussion of these matters under "Factors Influencing Future Performance" and in Notes 12 and 13 of the notes to Consolidated Financial Statements. The tables below summarize the components of electric and natural gas volumes and revenues by customer class.
2001 Compared to 2000 Net income increased from $151 million in 2000 to $183 million in 2001. The increase is primarily due to the gain on sale of SDG&E's Blythe property and lower interest expense incurred as the result of refunds made to customers in 2000 for the rate-reduction bond liability, as well as the $30 million after-tax charge for regulatory issues in 2000 (see discussion below). This increase is partially offset by lower interest income from affiliates resulting from loan repayments by Sempra Energy in 2000. Net income increased to $46 million for the fourth quarter of 2001, compared to $39 million for the corresponding period in 2000. This increase was primarily due to the sale of the Blythe property, noted above, during the fourth quarter of 2001. Electric revenues decreased from $2.2 billion in 2000 to $1.6 billion in 2001, and the cost of electric fuel and purchased power decreased from $1.3 billion in 2000 to $0.7 billion in 2001. These decreases were primarily due to the DWR's purchases of SDG&E's net short position. These purchases and the corresponding sale to SDG&E's customers are not included in the Statements of Consolidated Income since SDG&E was merely transporting the electricity from the DWR to the customers. Similarly, PX/ISO power revenues have been netted against purchased-power expense to avoid double-counting as SDG&E sells power into the PX/ISO and then purchases power therefrom. In addition, volumes were down compared to 2000 due to reductions in customer demand, arising from conservation efforts encouraged by the State of California program to give bill credits (funded by the DWR) to customers who significantly reduced usage. It is uncertain when SDG&E's electric volumes will return to levels of prior years. Natural gas revenues increased from $487 million in 2000 to $686 million in 2001, and the cost of natural gas distributed increased from $273 million in 2000 to $457 million in 2001. These increases were primarily due to higher average prices for natural gas in 2001. Under the current regulatory framework, changes in core-market natural gas prices (gas purchased for customers who are primarily residential and small commercial and industrial customers, without alternative fuel capability) do not affect net income, since core customer rates generally recover the actual cost of natural gas on a substantially concurrent basis. See discussion of balancing accounts in Note 2 of the notes to Consolidated Financial Statements. Other operating expenses increased from $412 million in 2000 to $495 million in 2001. The increase was primarily due to increased wages and employee benefits costs, as well as an increase in operating costs associated with balancing accounts.
2000 Compared to 1999 Net income decreased from $199 million in 1999 to $151 million in 2000. The decrease is primarily due to a $30 million after-tax charge as noted above for a potential regulatory disallowance related to the acquisition of wholesale power in the deregulated California market. Net income increased to $39 million for the three months ended December 31, 2000, compared to net income of $36 million for the corresponding period in 1999. This increase was primarily due to higher natural gas sales. Electric revenues increased from $1.8 billion in 1999 to $2.2 billion in 2000. The increase was primarily due to higher sales to industrial customers and the effect of higher electric commodity costs, partially offset by the charge noted above, which reduced revenues by $50 million, and the decrease in base electric rates (the noncommodity portion) from the completion of stranded cost recovery. For 2000, SDG&E's electric revenues included an undercollection of $447 million as a result of the 6.5-cent rate cap. Natural gas revenues increased from $389 million in 1999 to $487 million in 2000, primarily due to higher prices for natural gas in 2000 and higher electric generation plant revenues. The increase in electric generation plant revenues was due to higher demand for electricity in 2000 and the sale of SDG&E's fossil fuel generating plants in the second quarter of 1999. Prior to the plant sale, SDG&E's natural gas revenues from these plants consisted of the margin from the sales. Subsequent to the plant sale, SDG&E gas revenues consisted of the price of the natural gas transportation services, since the sales now are to unrelated parties. In addition, the generating plants receiving gas transportation from SDG&E were operating at higher capacities than previously, as discussed below. The cost of electric fuel and purchased power increased from $0.5 billion in 1999 to $1.3 billion in 2000. The increase was primarily due to the higher cost of electricity from the PX that has resulted from higher demand for electricity and the shortage of power plants in California, higher prices for natural gas used to generate electricity (as described above), the sale of SDG&E's fossil fuel generating plants, and warmer weather in California. Under the current regulatory framework, changes in on-system prices normally do not affect net income. See the discussions of balancing accounts and electric revenues in Note 2 of the notes to Consolidated Financial Statements. In September 2000, as a result of high electricity costs the CPUC authorized SDG&E to purchase up to 1,900 megawatts of power directly from third-party suppliers under both short-term contracts and long- term contracts. Subsequent to December 31, 2000, the state of California authorized the DWR to purchase all of SDG&E's power requirements not covered by its own generation or by existing contracts. These and related events are discussed more fully in Note 12 of the notes to Consolidated Financial Statements. The cost of natural gas distributed increased from $168 million in 1999 to $273 million in 2000. The increase was largely due to higher prices for natural gas. Prices for natural gas have increased due to the increased use of natural gas to fuel electric generation, colder winter weather and population growth in California. Depreciation and decommissioning expense decreased from $561 million in 1999 to $210 million in 2000 and other operating expenses decreased from $479 million in 1999 to $412 million in 2000. Both decreases were primarily due to the 1999 sale of SDG&E's fossil fuel generating plants.
Other Income and Deductions, Interest Expense, and Income Taxes
Other Income and Deductions Other income and deductions, which primarily consists of interest income and/or expense from short-term investments and regulatory balancing accounts, were $56 million, $34 million and $38 million in 2001, 2000 and 1999, respectively. The increase from 2000 to 2001 is primarily due to the $19 million gain on sale of SDG&E's Blythe, California property (discussed above in Cash Flows From Investing Activities), partially offset by lower interest income from affiliates due to loan repayments by Sempra Energy in 2000.
Interest Expense Interest expense was $92 million, $118 million and $120 million in 2001, 2000 and 1999, respectively. The decrease in interest expense in 2001 was primarily due to lower interest incurred as the result of refunds made to customers in 2000 for the rate reduction bond liability. Interest rates on certain of the company's debt can vary with credit ratings, as described in Notes 3 and 4 of the notes to Consolidated Financial Statements. See additional discussion of rate- reduction bonds in Note 4 of the notes to Consolidated Financial Statements.
Income Taxes Income tax expense was $141 million, $144 million and $126 million for the years ended December 31, 2001, 2000 and 1999, respectively. The effective income tax rates were 43.5 percent, 48.8 percent and 38.8 percent for the same years. The increase in income tax expense for 2000 compared to 1999 was primarily due to the fact that SDG&E made a charitable contribution to the San Diego Unified Port District in 1999 in connection with the sale thereto of its South Bay generating plant.
Factors Influencing Future Performance
Factors influencing future performance are summarized below.
Electric Industry Restructuring and Electric Rates In 1996, California enacted legislation restructuring California's investor-owned electric utility industry. The legislation and related decisions of the CPUC were intended to stimulate competition and reduce electric rates. During the transition period, utilities were allowed to charge frozen rates that were designed to be above current costs by amounts assumed to provide a reasonable opportunity to recover the above-market "stranded" costs of investments in electric- generating assets. The rate freeze was to end for each utility when it completed recovery of its stranded costs, but no later than March 31, 2002. SDG&E completed recovery of its stranded costs in June 1999 and, with its rates no longer frozen, SDG&E's overall rates became subject to fluctuation with the actual cost of electricity purchases. Supply/demand imbalances and a number of other factors resulted in abnormally high electric-commodity costs beginning in mid-2000 and continuing into 2001. This caused SDG&E's monthly customer bills to be substantially higher than normal. In response, legislation enacted in September 2000 imposed a ceiling of 6.5 cents/kWh on the cost of electricity that SDG&E could pass on to its residential, small- commercial and lighting customers. The legislation provides for the future recovery of undercollections in a manner (not specified in the decision) intended to make SDG&E whole for the reasonable and prudent costs of procuring electricity. The undercollection, included as a noncurrent regulatory asset on the Consolidated Balance Sheets, amounted to $392 million at December 31, 2001. As a result of the passage of Assembly Bill 1 in February 2001, the DWR began to purchase power from generators and marketers to supply a portion of the power requirements of the state's population that is served by IOUs. The DWR is now purchasing SDG&E's full net short position (the power needed by SDG&E's customers, other than that provided by SDG&E's nuclear generating facilities or its previously existing purchase power contracts). Therefore, increases in SDG&E's undercollections would result only from these contracts and interest, offset by nuclear generation, the cost of which is below the 6.5-cent customer rate cap. Any increases are not expected to be material. On June 18, 2001, representatives of California Governor Davis, the DWR, Sempra Energy and SDG&E entered into the MOU, contemplating the implementation of a series of transactions and regulatory settlements and actions to resolve many of the issues affecting SDG&E and its customers arising out of the California energy crisis. The MOU contemplated, subject to requisite approvals of the CPUC, the elimination from SDG&E's rate-ceiling balancing account of the undercollected costs that otherwise would be recovered in future rates charged to SDG&E customers; settlement of reasonableness reviews, electricity purchase contract issues and various other regulatory matters affecting SDG&E. During 2001, the CPUC dealt with several of these regulatory settlements, including approval of a reduction of the rate-ceiling balancing account by the application thereto of overcollections in certain other balancing accounts totaling $70 million and approval of a delay in the effective date of revised base rates for the California utilities to 2004. In addition, the CPUC approved a $100 million reduction of the rate-ceiling balancing account in settlement of the reasonableness of SDG&E's electric procurement practices between July 1, 1999 through February 7, 2001. In January 2002, the CPUC rejected the part of the MOU dealing with a settlement on electricity purchase contracts held by SDG&E. The MOU would have granted SDG&E ownership of its power sale profits in exchange for crediting $219 million to customers to offset the rate- ceiling balancing account. Instead, the CPUC asserted that all the profits associated with the energy purchase contracts should accrue to the benefit of customers. The CPUC estimated these profits as $363 million. The company believes the CPUC's calculation is incorrect and the CPUC has not explained to the company how it arrived at that amount. In addition, the company believes the CPUC's position is incorrect and has challenged the CPUC's original disallowance in the Court of Appeals. The court challenge was put on hold when the MOU was reached. SDG&E has now reactivated the case and has also filed a similar suit in federal court. Further discussion is included in Note 12 of the notes to Consolidated Financial Statements. As discussed in Note 13 of the notes to Consolidated Financial Statements, the company will make new cost of service filings at the end of 2002. Upon approval by the CPUC, new rates will be effective January 1, 2004. See additional discussion of these and related topics in Note 13 of the notes to Consolidated Financial Statements. In September 2001, the CPUC suspended the ability of retail electricity customers to choose their power provider ("direct access") until at least the end of 2003 in order to improve the probability that enough revenue would be available to the DWR to cover the state's power purchases. The decision forbids new direct access contracts after September 20, 2001. In January 2002, a draft decision was issued modifying the direct access suspension decision, suspending direct access retroactively to July 1, 2001. This issue is on the CPUC's agenda for March 21, 2002. Any effect is not expected to be material to the company's financial position. The CPUC is studying whether the incentive plan for the San Onofre Nuclear Generating Station (SONGS) should be terminated earlier than currently scheduled. This is discussed in Note 2 of the notes to Consolidated Financial Statements. The effects of an earlier termination are not yet determinable.
Natural Gas Restructuring and Gas Rates On December 11, 2001, the CPUC issued a decision adopting the following provisions affecting the structure of the natural gas industry in California, some of which could introduce additional volatility into the earnings of the company and other market participants: a system for shippers to hold firm, tradable rights to capacity on SoCalGas' major gas transmission lines; new balancing services including separate core and noncore balancing provisions; a reallocation among customer classes of the cost of interstate pipeline capacity held by SoCalGas and an unbundling of interstate capacity for gas marketers serving core customers; and the elimination of noncore customers' option to obtain gas supply service from SDG&E and SoCalGas. The CPUC is still considering the schedule for implementation of these regulatory changes, but it is expected that most of the changes will be implemented during 2002.
Allowed Rate of Return SDG&E is authorized to earn an 8.75 percent rate of return on rate base (ROR) and a 10.6 percent rate of return on common equity (ROE), effective July 1, 1999, and remaining in effect through 2002. SDG&E is required to file an application by May 8, 2002, addressing ROE, ROR and capital structure for 2003. The company can earn more than the authorized rate by controlling costs below approved levels or by achieving favorable results in certain areas, such as various incentive mechanisms. In addition, earnings are affected by changes in sales volumes.
Utility Integration On September 20, 2001, the CPUC approved Sempra Energy's request to integrate the management teams of SDG&E and SoCalGas. The decision retains the separate identities of each utility and is not a merger. Instead, utility integration is a reorganization that consolidates senior management functions of the two utilities and returns to the utilities a significant portion of shared support services currently provided by Sempra Energy's centralized corporate center. Once implementation is completed, the integration is expected to result in more efficient and effective operations. In a related development, a CPUC draft decision would allow SDG&E and SoCalGas to combine their natural gas procurement activities. The CPUC is scheduled to act on the draft decision at its April 4, 2002 meeting.
Environmental Matters The company's operations are subject to federal, state and local environmental laws and regulations governing such things as hazardous wastes, air and water quality, land use, solid-waste disposal and the protection of wildlife. Utility costs to comply with environmental requirements are generally recovered in customer rates. Therefore, the likelihood of the company's financial position or results of operations being adversely affected in a significant manner is believed to be remote. The environmental issues currently facing the company or resolved during the latest three-year period include investigation and remediation of its manufactured-gas sites, cleanup at its former fossil fuel power plants, cleanup of third-party waste-disposal sites used by the company, and mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS. See further discussion of environmental matters in Note 11 of the notes to Consolidated Financial Statements.
Market Risk Market risk is the risk of erosion of the company's cash flows, net income asset values and equity due to adverse changes in prices for natural gas and electric commodities, and in interest and foreign- currency rates. The company's policy is to use derivative financial instruments to reduce its exposure to fluctuations in interest rates and commodity prices. Transactions involving these financial instruments are with firms believed to be credit worthy. The use of these instruments exposes the company to market and credit risks which, at times, may be concentrated with certain counterparties. There were no unusual concentrations at December 31, 2001, that would indicate an unacceptable level of risk. The company uses energy derivatives to manage natural gas price risk associated with servicing its load requirements. These instruments can include forward contracts, futures, swaps, options and other contracts. In the case of price-risk management and trading activities, the use of derivative financial instruments by the company is subject to certain limitations imposed by company policy and regulatory requirements. See the continuing discussion below and Note 9 of the notes to Consolidated Financial Statements for further information regarding the use of energy derivatives by the company. The company has adopted corporate-wide policies governing its market-risk management and trading activities. An Energy Risk Management Oversight Committee, consisting of senior officers, oversees company-wide energy risk management activities and monitors the results of trading activities to ensure compliance with the company's stated energy-risk management and trading policies. In addition, SDG&E's risk-management committee monitors energy-price risk management and trading activities independently from the groups responsible for creating or actively managing these risks. Along with other tools, the company uses Value at Risk (VaR) to measure its exposure to market risk. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence interval. The company has adopted the variance/covariance methodology in its calculation of VaR, and uses both the 95-percent and 99-percent confidence intervals. Historical volatilities and correlations between instruments and positions are used in the calculation. As of December 31, 2001, the total VaR of SDG&E's natural gas positions was not material. The following discussion of the company's primary market-risk exposures as of December 31, 2001, includes further discussion of how these exposures are managed.
Commodity-Price Risk Market risk related to physical commodities is based upon potential fluctuations in the prices and basis of natural gas and electricity. The company's market risk is impacted by changes in volatility and liquidity in the markets in which these instruments are traded. The company is exposed, in varying degrees, to price risk in the natural gas and electricity markets. The company's policy is to manage this risk within a framework that considers the unique markets, and operating and regulatory environments. The company's natural gas market risk exposure is limited due to CPUC authorized rate recovery of natural gas purchase, sale and storage activity. However, the company may at times, be exposed to market risk as a result of activities under SDG&E's natural gas PBR, which is discussed in Note 13 of the notes to Consolidated Financial Statements. SDG&E manages this risk within the parameters of the company's market-risk management and trading framework. At December 31, 2001 the company's exposure to market risk was not material.
Interest-Rate Risk The company is exposed to fluctuations in interest rates primarily as a result of its fixed-rate long-term debt. The company has historically funded operations through long-term debt issues with fixed interest rates and these interest rates are recorded in rates. With the restructuring of the regulatory process, the CPUC has permitted greater flexibility within the debt-management process. As a result, recent debt offerings have been selected with short-term maturities to take advantage of yield curves, or have used a combination of fixed-rate and floating-rate debt. Subject to regulatory constraints, interest-rate swaps may be used to adjust interest-rate exposures when appropriate, based upon market conditions. At December 31, 2001, SDG&E had $1,165 million of fixed-rate debt and $157 million of variable-rate debt. Interest on fixed-rate utility debt is fully recovered in historical cost basis rates and interest on variable-rate debt is generally recovered on a forecasted basis. At December 31, 2001, SDG&E's fixed-rate debt had a one-year VaR of $245 million and its variable-rate debt had a one-year VaR of $1 million At December 31, 2001, the notional amount of the company's interest-rate swap transaction was $45 million. See Note 4 of the notes to Consolidated Financial Statements for further information regarding this swap transaction.
Credit Risk Credit risk relates to the risk of loss that would be incurred as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The company avoids concentration of counterparties and maintains credit policies with regard to counterparties that management believes significantly minimize overall credit risk. These policies include an evaluation of prospective counterparties' financial position (including credit ratings), collateral requirements under certain circumstances, and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. The company monitors credit risk through a credit-approval process and the assignment and monitoring of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. The company periodically enters into interest-rate swap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. The company would be exposed to interest-rate fluctuations on the underlying debt should other parties to the agreement not perform.
Critical Accounting Policies
The company's most significant accounting policies are described in Note 2 of the notes to Consolidated Financial Statements. The most critical policies are Statement of Financial Accounting Standards (SFAS) 71 "Accounting for the Effects of Certain Types of Regulation," and SFAS 133 and SFAS 138 "Accounting for Derivative Instruments and Hedging Activities" and "Accounting for Certain Derivative Instruments and Certain Hedging Activities," (see below). All of these policies are mandatory under generally accepted accounting principles and the regulations of the Securities and Exchange Commission. Each of these policies has a material effect on the timing of revenue and expense recognition for significant company operations. In connection with the application of these and other accounting policies, the company makes estimates and judgments about various matters. The most significant of these involve the calculation of fair values, and the collectibility of regulatory and other assets. As discussed elsewhere herein, the company uses exchange quotations or other third-party pricing to estimate fair values whenever possible. When no such data is available, it uses internally developed models or other techniques. The assumed collectibility of regulatory assets considers legal and regulatory decisions involving the specific items or similar items. The assumed collectibility of other assets considers the nature of the item, the enforceability of contracts where applicable, the creditworthiness of other parties and other factors.
New Accounting Standards Effective January 1, 2001, the company adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." As amended, SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative qualifies as an effective hedge that offsets certain exposure. The company utilizes derivative financial instruments to reduce its exposure to unfavorable changes in energy prices, which are subject to significant and often volatile fluctuation. Derivative financial instruments include futures, forwards, swaps, options and long-term delivery contracts. These contracts allow the company to predict with greater certainty the effective prices to be received and the prices to be charged to its customers. Upon adoption of SFAS 133 on January 1, 2001, the company is classifying its forward contracts as follows:
Normal Purchase and Sales: These forward contracts are excluded from the requirements of SFAS No. 133. The realized gains and losses on these contracts are reflected in the income statement at the contract settlement date. The contracts that generally qualify as normal purchases and sales are long-term contracts that are settled by physical delivery.
Cash Flow Hedges: The unrealized gains and losses related to these forward contracts would be included in accumulated other comprehensive income, a component of shareholders' equity, but not reflected in the Statements of Consolidated Income until the corresponding hedged transaction is settled. The company has not used this type of hedge so far.
Electric and Gas Purchases and Sales: The unrealized gains and losses related to these forward contracts are reflected on the balance sheet as regulatory assets and liabilities, to the extent derivative gains and losses will be recoverable or payable in future rates. If gains and losses at the company are not recoverable or payable through future rates, the company will apply hedge accounting if certain criteria are met. In instances where hedge accounting would be applied to energy derivatives, cash flow hedge accounting would be elected and, accordingly, changes in fair values of the derivatives would be included in other comprehensive income, but not reflected in the Statements of Consolidated Income until the corresponding hedged transaction was settled. There was no effect on other comprehensive income for the year ended December 31, 2001. In instances where energy derivatives do not qualify for hedge accounting, gains and losses are recorded in the Statements of Consolidated Income. The adoption of this new standard on January 1, 2001, did not have a material impact on the company's earnings. However, $93 million in current assets, $5 million in noncurrent assets, $2 million in current liabilities, and $238 million in noncurrent liabilities were recorded in the Consolidated Balance Sheets as fixed-priced contracts and other derivatives as of January 1, 2001. Due to the regulatory environment in which the company operates, regulatory assets and liabilities were established to the extent that derivative gains and losses are recoverable or payable through future rates. As such, $93 million in current regulatory liabilities, $5 million in noncurrent regulatory liabilities, $2 million in current regulatory assets, and $238 million in noncurrent regulatory assets were recorded in the Consolidated Balance Sheets as of January 1, 2001. See Note 9 of the notes to Consolidated Financial Statements for additional information on the effects of SFAS 133 on the financial statements at December 31, 2001. The ongoing effects will depend on future market conditions and the company's hedging activities. In July 2001, the Financial Accounting Standards Board (FASB) issued three statements, SFAS 141 "Business Combinations," SFAS 142 "Goodwill and Other Intangible Assets" and SFAS 143 "Accounting for Asset Retirement Obligations." The first two are not presently relevant to the company. SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of a long-lived asset, such as nuclear plants. It requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset. SFAS 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. Upon adoption of SFAS 143, the company estimates it would record an addition of $468 million to utility plant, representing the company's share of SONGS estimated future decommissioning costs, and a corresponding retirement obligation liability of $468 million. The nuclear decommissioning trusts' balance of $526 million at December 31, 2001 represents amounts collected for future decommissioning costs and has a corresponding amount included in accumulated depreciation. Any difference between the amount of capitalized cost that would have been recorded and depreciated and the amounts collected in the nuclear decommissioning trusts will be recorded as a regulatory asset or liability. Additional information on SONGS decommissioning is included in Note 5 of the notes to Consolidated Financial Statements. Except for SONGS, the company has not yet determined the effect of SFAS 143 on its financial statements. In August 2001, the FASB issued SFAS 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" that replaces SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS 144 applies to all long-lived assets, including discontinued operations. SFAS 144 requires that those long- lived assets classified as held for sale be measured at the lower of carrying amount or fair value less cost to sell. Discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of SFAS 144 are effective for fiscal years beginning after December 15, 2001. The company has not yet determined the effect of SFAS 144 on its financial statements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A is set forth under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of San Diego Gas & Electric Company:
We have audited the accompanying consolidated balance sheets of San Diego Gas & Electric Company and subsidiary as of December 31, 2001 and 2000, and the related statements of consolidated income, cash flows and changes in shareholders' equity for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of San Diego Gas & Electric Company and subsidiary as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
San Diego, California February 4, 2002 (February 21, 2002 as to Note 12)
The following table provides the amounts recognized under "Deferred credits and other liabilities" on the Consolidated Balance Sheets at December 31:
The following table provides the components of net periodic benefit cost (income) for the plans:
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percent change in assumed health care cost trend rates would have the following effects:
- -------------------------------------------------------------------------- (Dollars in millions) 1% Increase 1% Decrease - -------------------------------------------------------------------------- Effect on total of service and interest cost components of net periodic postretirement health-care benefit cost -- --
Effect on the health-care component of the accumulated other postretirement benefit obligation $ 2 $ (2)
- --------------------------------------------------------------------------
Other postretirement benefits include retiree life insurance and medical benefits for retirees and their spouses.
Savings Plan The company offers a savings plan, administered by plan trustees, to all eligible employees. Eligibility to participate in the plan begins after one month of completed service. Employees may contribute, subject to plan provisions, from one percent to 15 percent of their regular earnings. After one year of completed service, the company begins to make matching contributions. Employer contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees. Employer contributions are invested in Sempra Energy common stock (new issuances or market purchases) and must remain so invested until termination of employment. At the direction of the employees, the employees' contributions are invested in Sempra Energy common stock, mutual funds or institutional trusts. Company contributions to the savings plan were $5 million in 2001, $5 million in 2000 and $4 million in 1999.
NOTE 8. STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans intended to align employee and shareholder objectives related to Sempra Energy's long- term growth. The plans permit a wide variety of stock-based awards, including Sempra Energy non-qualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments and dividend equivalents. In 1995, SFAS No. 123, "Accounting for Stock-Based Compensation," was issued. It encourages a fair-value-based method of accounting for stock-based compensation. As permitted by SFAS No. 123, Sempra Energy and its subsidiaries adopted only its disclosure requirements and continues to account for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." The subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans, or that subsidiaries are allocated a portion of Sempra Energy's costs of the plans. SDG&E recorded expenses of $2 million and $1 million in 2001 and 2000, respectively. There were no expenses recorded in 1999.
NOTE 9. FINANCIAL INSTRUMENTS
Fair Value The fair values of certain of the company's financial instruments (cash, temporary investments and customer deposits) approximate the carrying amounts. The following table provides the carrying amounts and fair values of the remaining financial instruments at December 31:
The fair values of long-term debt and preferred stock were estimated based on quoted market prices for them or for similar issues.
Accounting for Derivative Instruments and Hedging Activities Effective January 1, 2001, the company adopted SFAS 133, as amended by SFAS 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities." As amended, SFAS 133 requires that an entity recognize all derivative instruments as either assets or liabilities in the statement of financial position, measure the instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative instrument qualifies as an effective hedge that offsets certain exposures. At December 31, 2001, $1 million in other current assets, $89 million in current liabilities and $673 million in noncurrent liabilities were recorded in the Consolidated Balance Sheets for fixed-priced contracts and other derivatives. Regulatory assets and liabilities were established to the extent that derivative gains and losses are recoverable or payable through future rates. As such, $88 million in current regulatory assets, $673 million in noncurrent regulatory assets, and $1 million in other current liabilities were recorded in the Consolidated Balance Sheets as of December 31, 2001. For the year ended December 31, 2001, $1 million in non-operating losses was recorded in "Other--net" in the Statements of Consolidated Income.
Market Risk The company's policy is to use derivative financial instruments to manage exposure to fluctuations in interest rates and energy prices. Transactions involving these financial instruments are with firms believed to be credit-worthy. The use of these instruments exposes the company to market and credit risk which may at times be concentrated with certain counterparties, although counterparty nonperformance is not anticipated.
Interest-Rate Risk Management The company periodically enters into interest-rate swap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. At December 31, 2001, SDG&E has one interest-rate swap agreement that matures in 2002 and effectively fixes the interest rate on $45 million of SDG&E's variable-rate underlying debt at 5.4 percent. This floating-to-fixed-rate swap does not qualify for hedge accounting and therefore the gains and losses associated with the change in fair value are recorded in the Statements of Consolidated Income. For the year ended December 31, 2001, the effect on income was a $1 million loss as noted above. Although this financial instrument does not meet the hedge accounting criteria of SFAS 133, it continues to be effective in achieving the risk management objectives for which it was intended.
Energy Derivatives SDG&E utilizes derivative financial instruments to reduce its exposure to unfavorable changes in energy prices, which are subject to significant and often volatile fluctuation. Derivative financial instruments are comprised of futures, forwards, swaps, options and long-term delivery contracts. These contracts allow SDG&E to predict with greater certainty the effective prices to be received and to be charged to its customers. See Note 2 for discussion of how these derivatives are classified under SFAS 133.
Energy Contracts SDG&E records natural gas and electric energy contracts in "Cost of gas distributed" and "Electric fuel and net purchased power," respectively, in the Statements of Consolidated Income. For open contracts not expected to result in physical delivery, changes in market value of the contracts are recorded in these accounts during the period the contracts are open, with an offsetting entry to a regulatory asset or liability. The majority of the company's contracts result in physical delivery. There was no impact on the financial statements of consolidated income for changes in the fair value of derivative instruments, other than the $1 million loss on the interest-rate swap noted above.
NOTE 10. PREFERRED STOCK AND DIVIDEND RESTRICTIONS
All series of SDG&E's preferred stock have cumulative preferences as to dividends. The $20 par value preferred stock has two votes per share on matters being voted upon by shareholders of SDG&E and a liquidation value at par, whereas the no-par-value preferred stock is nonvoting and has a liquidation value of $25 per share, plus any unpaid dividends. SDG&E is authorized to issue 10,000,000 shares of no-par-value preferred stock (both subject to and not subject to mandatory redemption). All series are currently callable except for the $1.70 and $1.7625 Series (callable in 2003). The $1.7625 Series has a sinking fund requirement to redeem 50,000 shares per year from 2003 to 2007; the remaining 750,000 shares must be redeemed in 2008.
Dividend Restrictions The CPUC's regulation of SDG&E's capital structure limits to $178 million the portion of the company's December 31, 2001 retained earnings that is available for dividends.
NOTE 11. COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts SDG&E buys natural gas under short-term and long-term contracts. Short-term purchases are from various Southwest U.S. and Canadian suppliers and are primarily based on monthly spot-market prices. SDG&E transports gas under long-term firm pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SDG&E has long-term natural gas transportation contracts with various interstate pipelines which expire on various dates between 2003 and 2023. SDG&E has a long-term purchase agreement with a Canadian supplier that expires in August 2003, and in which the delivered cost is tied to the California border spot-market price. SDG&E purchases natural gas on a spot basis to fill its additional long-term pipeline capacity. SDG&E intends to continue using the long-term pipeline capacity in other ways as well, including the transport of other natural gas for its own use and the release of a portion of this capacity to third parties. All of SDG&E's gas is delivered through SoCalGas pipelines under a short-term transportation agreement. In addition, under a separate agreement expiring in March 2003, SoCalGas provides SDG&E 4.5 billion cubic feet of storage capacity with an option for an additional 1.5 billion cubic feet as capacity becomes available. At December 31, 2001, the future minimum payments under natural gas contracts were: Storage and (Dollars in millions) Transportation Natural Gas - ----------------------------------------------------------------- 2002 $ 16 $ 24 2003 14 16 2004 14 - 2005 14 - 2006 13 - Thereafter 151 - ---------------------------------- Total minimum payments $ 222 $ 40 - -----------------------------------------------------------------
Total payments under the natural gas contracts were $457 million in 2001, $273 million in 2000 and $220 million in 1999.
Purchased-Power Contracts SDG&E buys electric power under several long-term contracts. The contracts expire on various dates between 2003 and 2025. Prior to the electric rate ceiling described in Note 12, the above-market cost of contracts was recovered from SDG&E's customers. In general, the market value of these contracts was recovered by bidding them into the California Power Exchange (PX) and receiving revenue from the PX for bids accepted. As of January 1, 2001, in compliance with a FERC order prohibiting sales to the PX, SDG&E no longer bids those contracts into the PX. Those contracts are now used to serve customers in compliance with a CPUC order. In late 2000, SDG&E entered into additional contracts to serve customers instead of buying all of its power from the PX. These contracts expire in 2003. At December 31, 2001, the estimated future minimum payments under the long-term contracts were:
(Dollars in millions) - ----------------------------------------------------------------- 2002 $ 224 2003 218 2004 172 2005 173 2006 170 Thereafter 2,000 ---------- Total minimum payments $2,957 - -----------------------------------------------------------------
The payments represent capacity charges and minimum energy purchases. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. Total payments under the contracts were $512 million in 2001, $257 million in 2000 and $251 million in 1999. On January 17, 2001, the California Assembly passed a bill (AB1) to allow the DWR to purchase power under long-term contracts for the benefit of California consumers. In accordance with AB1, SDG&E entered into an agreement with the DWR under which the DWR purchases SDG&E's full net short position (the power needed by SDG&E's customers, other than that provided by SDG&E's nuclear generating facilities or its previously existing purchased-power contracts) through December 31, 2002. The CPUC is conducting proceedings intended to establish guidelines and procedures for the eventual resumption of electricity procurement by SDG&E and the other California IOUs. For additional discussion of this matter see Note 12.
Leases SDG&E has operating leases on real and personal property expiring at various dates from 2002 to 2045. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2 percent to 5 percent. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain extension options, which are exercisable by SDG&E. SDG&E terminated its capital lease agreement for nuclear fuel in mid-2001 and now owns its nuclear fuel. At December 31, 2001, the minimum rental commitments payable in future years under all noncancellable leases were:
(Dollars in millions) - ------------------------------------------------------------ 2002 $10 2003 8 2004 7 2005 5 2006 4 Thereafter 16 -------- Total future rental commitment $50 - ------------------------------------------------------------
Rent expense totaled $21 million in 2001, $32 million in 2000 and $39 million in 1999.
Environmental Issues The company's operations are subject to federal, state and local environmental laws and regulations governing hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. As applicable, appropriate and relevant, these laws and regulations require that the company investigate and remediate the effects of the release or disposal of materials at sites associated with past and present operations, including sites at which the company has been identified as a Potentially Responsible Party under the federal Superfund laws and comparable state laws. Costs incurred to operate the facilities in compliance with these laws and regulations generally have been recovered in customer rates. Costs that mitigate or prevent future environmental contamination or extend the life, increase the capacity or improve the safety or efficiency of property utilized in current operations are capitalized. The company's capital expenditures to comply with environmental laws and regulations were $1 million in 2001, $2 million in 2000 and $160,000 in 1999. The increase in 2000 was due to the installation of air quality control equipment on a compressor facility. The cost of compliance with these regulations over the next five years is not expected to be significant. Costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the assurance that these costs will be recovered in rates. In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum account, allowing California's energy utilities to recover their hazardous waste cleanup costs, including those related to Superfund sites or similar sites requiring cleanup. Cleanup costs at electric generation related sites were specifically excluded from the collaborative by the CPUC. 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. The environmental issues currently facing the company or resolved during the latest three-year period include investigation and remediation of its manufactured-gas sites (all three sites completed as of December 31, 2001 and site-closure letters received for two), cleanup at its former fossil fuel power plants (all sold in 1999 and actual or estimated cleanup costs included in the transactions), cleanup of third-party waste-disposal sites used by the company, which has been identified as a Potentially Responsible Party (investigations and remediations are continuing), and mitigation of damage to the marine environment caused by the cooling-water discharge from the SONGS (the requirements for enhanced fish protection, a 150-acre artificial reef and restoration of 150 acres of coastal wetlands are in process). Environmental liabilities are recorded when the company's liability is probable and the costs are reasonably estimable. In many cases, however, investigations are not yet at a stage where the company has been able to determine whether it is liable or, if liability is probable, to reasonably estimate the amount or range of amounts of the cost, or certain components thereof. Estimates of the company's liability are further subject to other uncertainties, such as the nature and extent of site contamination, evolving remediation standards and imprecise engineering evaluations. The accruals are reviewed periodically and, as investigations and remediation proceed, adjustments are made as necessary. At December 31, 2001, the company's accrued liability for environmental matters was $10 million related to cleanup at SDG&E's former fossil-fueled power plants. These accruals are expected to be paid ratably over the next two years. There are no circumstances currently known to management that would require adjustment to the accruals.
Nuclear Insurance SDG&E and the co-owners of SONGS have purchased primary insurance of $200 million, the maximum amount available, for public-liability claims. An additional $9.3 billion of coverage is provided by secondary financial protection required by the Nuclear Regulatory Commission and provides for loss sharing among utilities owning nuclear reactors if a costly accident occurs. SDG&E could be assessed retrospective premium adjustments of up to $36 million in the event of a nuclear incident involving any of the licensed, commercial reactors in the United States, if the amount of the loss exceeds $200 million. In the event the public-liability limit stated above is insufficient, the Price-Anderson Act provides for Congress to enact further revenue- raising measures to pay claims, which could include an additional assessment on all licensed reactor operators. Insurance coverage is provided for up to $2.8 billion of property damage and decontamination liability. Coverage is also provided for the cost of replacement power, which includes indemnity payments for up to three years, after a waiting period of 12 weeks. Coverage is provided primarily through mutual insurance companies owned by utilities with nuclear facilities. If losses at any of the nuclear facilities covered by the risk-sharing arrangements were to exceed the accumulated funds available from these insurance programs, SDG&E could be assessed retrospective premium adjustments of up to $7 million. Both the public-liability and property insurance (including replacement power coverage) include coverage for losses resulting from acts of terrorism. This includes the risk-sharing arrangement with other nuclear facilities.
Department Of Energy Decommissioning The Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the Department of Energy (DOE) nuclear fuel enrichment facilities. Utilities which have used DOE enrichment services are being assessed a total of $2.3 billion, subject to adjustment for inflation, over a 15-year period ending in 2006. Each utility's share is based on its share of enrichment services purchased from the DOE through 1992. SDG&E's annual assessment is approximately $1 million. This assessment is recovered through SONGS revenue.
Department Of Energy Nuclear Fuel Disposal The Nuclear Waste Policy Act of 1982 made the DOE responsible for the disposal of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. Continued delays by the DOE can lead to increased cost of disposal, which could be significant. If this occurs and the company is unable to recover the increased costs from the federal government or from its customers, the company's profitability from SONGS would be adversely affected.
Litigation Lawsuits filed in 2000 and currently consolidated in San Diego Superior Court seek class-action certification and allege that Sempra Energy, SoCalGas, SDG&E and El Paso Energy Corp. acted to drive up the price of natural gas for Californians by agreeing to stop a pipeline project that would have brought new and less-expensive natural gas supplies into California. Management believes the allegations are without merit. Except for the matter referred to above, the company is not party to, nor is its property the subject of, any material pending legal proceedings other than routine litigation incidental to its business. Management believes that these matters will not have a material adverse effect on the company's financial condition or results of operations.
Electric Distribution System Conversion Under a CPUC-mandated program and through franchise agreements with various cities, SDG&E is committed, in varying amounts, to converting overhead distribution facilities to underground. As of December 31, 2001, the aggregate unexpended amount of this commitment was approximately $110 million. Capital expenditures for underground conversions were $12 million in 2001, $26 million in 2000 and $20 million in 1999.
Concentration of Credit Risk SDG&E maintains credit policies and systems to manage overall credit risk. These policies include an evaluation of potential counterparties' financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. SDG&E grants credit to its utility customers, substantially all of whom are located in its service territory, which covers all of San Diego County and an adjacent portion of Orange County. Supply/demand imbalances and a number of other factors resulted in abnormally high electric-commodity costs beginning in mid-2000 and continuing into 2001. This caused SDG&E's monthly customer bills to be substantially higher than normal. In response, legislation imposed a ceiling of 6.5 cents/kWh on the cost of electricity that SDG&E could pass on to its residential, small-commercial and lighting customers on a current basis. The ceiling extends through December 31, 2002 (December 31, 2003 if deemed by the CPUC to be in the public interest). Once SDG&E is able to pass on these costs, the company may experience an increase in customer credit risk. Additional information on this issue is discussed in Note 12.
NOTE 12. ELECTRIC INDUSTRY RESTRUCTURING
Background In 1996, California enacted legislation (AB 1890) restructuring California's investor-owned electric utility industry. The legislation and related decisions of the CPUC were intended to stimulate competition and reduce electric rates. As part of the framework for a competitive electric-generation market, the legislation established the PX, which served as a wholesale power pool to which the California IOUs were required to sell all of their power supply (including owned generation and purchased-power contracts) and, except to the extent otherwise authorized by the CPUC, from which they were required to buy all of the electricity needed to serve their retail consumers. The PX also purchased power from nonutility generators through an auction process intended to establish competitive market prices for the power that it sells to the IOUs. An Independent System Operator (ISO) scheduled power transactions and access to the transmission system. In connection with the deregulation of California's electric-utility industry, during 1999 and 2000, the company sold and purchased electricity to and from the PX. Net purchase power reflects sales and purchases to and from the PX/ISO commencing April 1, 1998, at market prices of energy from SDG&E's power plants and from long-term purchase-power contracts. Due to subsequent industry restructuring developments (described below), the PX suspended its trading operations on January 31, 2001. The restructuring legislation also established a rate freeze on amounts that the IOUs could charge their customers. The rate freeze was designed to generate revenue levels assumed to be sufficient to provide the IOUs with a reasonable opportunity to recover, by December 31, 2001, their costs of generation and purchased power that are fixed and unavoidable and included in customer rates. The rate freeze was to end as to each IOU when it completed recovery of the costs, but in no event later than March 31, 2002. In June 1999, SDG&E completed the recovery of its stranded costs, other than the future above-market portion of its purchased-power contracts that were in effect at December 31, 1995, and SONGS costs, both of which continue to be collected in rates. Recovery of the other costs was effected by, among other things, the sale of SDG&E's fossil power plants and combustion turbines during the quarter ended June 30, 1999. Therefore, SDG&E is no longer subject to the rate freeze imposed by AB 1890. With the rate freeze no longer applicable, SDG&E lowered its base rates (the portion of its rates not attributable to electric-commodity costs) and began to pass through to its customers, without markup, the cost of electricity purchased from the PX. SDG&E's overall rates were lower than during the rate freeze, but they also became subject to fluctuation with the actual cost of electricity purchases.
Effect on Customer Rates As noted above supply/demand imbalances and a number of other factors resulted in abnormally high electric-commodity prices beginning in mid-2000 and continuing into 2001. This caused SDG&E's monthly customer bills to be substantially higher than normal. These higher prices were initially passed through to SDG&E's customers and resulted in customer bills that in most cases were double or triple those from 1999 and early 2000. This resulted in several legislative and regulatory responses. California Assembly Bill 265 (AB 265), enacted in September 2000, imposed a ceiling of 6.5 cents/kWh on the cost of the electric commodity that SDG&E could pass on to its small-usage customers on a current basis. Customers covered under the commodity rate ceiling generally include residential, small-commercial and lighting customers. The ceiling, retroactive to June 1, 2000, extends through December 31, 2002, and may be extended through December 31, 2003, if the CPUC determines that it is in the public interest to do so. The 6.5-cent rate ceiling is a "floating cap" that can float downward as prices decrease, but cannot exceed actual commodity costs without the approval of the CPUC. The CPUC subsequently approved an increase to the system average rate paid by SDG&E customers (to 7.96 cents per kWh) in order to pass through, without markup, the rates to repay the DWR for its purchases of power, as described below. The agreement for the ending of the earlier rate freeze provided for future recovery of SDG&E's electricity costs that could not be passed on to customers on a current basis. Although it delayed such recovery, AB 265 reaffirmed SDG&E's right to later collect undercollections resulting from the reasonable and prudent costs of procuring the commodity. The reasonableness reviews related to the commodity costs have been settled, as discussed below. SDG&E accumulates the amount that it pays for electricity in excess of the ceiling rate (the undercollected costs) in an interest- bearing balancing account. SDG&E expects to amortize these amounts, together with interest, in rates charged to customers following the end of the rate-ceiling period. Due to their long-term nature, these undercollected costs are classified as a noncurrent regulatory asset on the company's Consolidated Balance Sheets. The undercollection was $447 million (of which $352 million was included in regulatory assets and $95 million was included in regulatory balancing accounts on the Consolidated Balance Sheets) at December 31, 2000. It increased to approximately $750 million in the first quarter of 2001 and decreased to $392 million at December 31, 2001. The decrease was due primarily to the $100 million refund related to prudence of purchase-power costs and the application of overcollections in other balancing accounts.
Role of the Department of Water Resources In February 2001, through the passage of AB 1, the DWR began to purchase power from generators and marketers, who had previously sold their power to the PX/ISO, and has entered into long-term contracts for the purchase of a portion of the power requirements of the state's population that is served by IOUs. SDG&E and the DWR have entered into an agreement under which the DWR will continue to purchase power for SDG&E's customers until December 31, 2002. As the DWR is now purchasing SDG&E's full net short position (the power needed by SDG&E's customers, other than that provided by SDG&E's nuclear generating facilities or its previously existing purchased- power contracts) significant growth in these undercollections has ceased. In April 2001, California law AB 43X took effect, extending the temporary 6.5-cent rate cap to include SDG&E's large customers (the only customer class not previously covered by the rate cap) retroactive to February 7, 2001. The reduced future bills did not add to the undercollection nor did the fourth quarter refunds of past charges above 6.5 cents, since, in large part, the purchases for these customers are covered by the agreement between SDG&E and the DWR.
Memorandum of Understanding On June 18, 2001 representatives of California Governor Davis, the DWR, Sempra Energy and SDG&E entered into a Memorandum of Understanding (MOU) contemplating the implementation of a series of transactions and regulatory settlements and actions to resolve many of the issues affecting SDG&E and its customers arising out of the California energy crisis. The MOU contemplated the elimination from SDG&E's rate-ceiling balancing account of the undercollected costs that otherwise would be recovered in future customer rates; settlement of reasonableness reviews, electricity purchase contract issues and other regulatory matters. On August 2, 2001, the CPUC approved a reduction of the rate- ceiling balancing account, as contemplated by the MOU, by the application thereto of overcollections in certain other balancing accounts totaling $70 million. On October 10, 2001, the CPUC issued a decision approving the delay until 2004 of the effects of revised revenue requirements for SDG&E and SoCalGas. However, the decision also denied the request by SDG&E and SoCalGas to continue equal sharing between ratepayers and shareholders of estimated savings stemming from the 1998 merger between PE and Enova. Instead, the CPUC ordered that all of the estimated 2003 merger savings go to ratepayers. The portion to be refunded to electric ratepayers would be credited to the Transition Cost Balancing Account (TCBA), based on the net present value (NPV) in 2001 of the savings for 2003. Merger savings related to 2001 and 2002 also would be so credited. The combined NPV is estimated to be $39 million. Merger savings allocable to natural gas ratepayers would be refunded through once-a-year bill credit, as has been the case. On November 8, 2001, the CPUC approved a $100 million reduction of the rate-ceiling balancing account, in settlement of the reasonableness of SDG&E's electric procurement practices between July 1, 1999 through February 7, 2001. In January 2002, the CPUC rejected the part of the MOU dealing with a settlement on electricity purchase contracts held by SDG&E. The MOU would have granted SDG&E ownership of its power sale profits in exchange for crediting $219 million to customers to offset the rate- ceiling balancing account. Instead, the CPUC asserted that all the profits associated with the energy purchase contracts should accrue to the benefit of customers. The CPUC estimated these profits as $363 million. The company believes the CPUC's calculation is incorrect and the CPUC has not explained to the company how it arrived at that amount. In addition, the company believes the CPUC's position is incorrect and has challenged the CPUC's original disallowance in the Court of Appeals. The court challenge was put on hold when the MOU was reached. SDG&E has now reactivated the case and has also filed a similar suit in federal court.
Recent Rate Changes In order to provide sufficient revenues to repay the DWR for the $10 billion of power purchases it made on behalf of the state's three IOUs during the energy crisis, the CPUC issued a decision in September 2001 that established interim rate increases for SDG&E's electric customers in an average amount of approximately 1.46 cents per kWh, resulting in a system average rate of 7.96 cents per kWh when added to the 6.5 cents per kWh rate ceiling discussed above. On February 21, 2002, the CPUC issued a final decision about the DWR revenue requirement, approving allocation of the DWR's cost of providing power based on actual cost of service, which was lower for SDG&E customers than for those in Northern California and, therefore, avoids a rate hike for SDG&E customers. Based on this allocation, the price SDG&E pays to the DWR drops from the previously proposed rate of 9.02 cents per kWh to 7.29 cents per kWh. SDG&E's system average rate of 7.96 cents per kWh (described above) remains unchanged and will be addressed separately. The CPUC also voted to relinquish oversight over DWR power purchases, which allows the state to proceed with the bond sale of up to $11.1 billion to repay the state's general fund (used for DWR power purchases during the energy crisis) and to cover continuing power purchases. Interested parties have 30 days to appeal the decision.
Direct Access In September 2001, the CPUC suspended the ability of retail electricity customers to choose their power provider ("direct access") until at least the end of 2003 in order to improve the probability that enough revenue would be available to the DWR to cover the state's power purchases. The decision forbids new direct access contracts after September 20, 2001. In January 2002, a draft decision was issued modifying the direct access suspension decision, suspending direct access retroactively to July 1, 2001. This issue is on the CPUC's agenda for March 21, 2002. Any such effect is not expected to be material to the company's financial position or liquidity.
FERC Actions The FERC has been investigating prices charged to the California IOUs by various electric suppliers. The FERC appears to be proceeding in the direction of awarding to the California IOUs a partial refund of the amounts charged. Any such refunds would reduce SDG&E's rate- ceiling balancing account. A FERC decision is not expected before the second half of 2002. More recently, FERC has launched an investigation whether there was manipulation of short-term energy prices in the West that resulted in unjust and unreasonable long-term power sales contracts. The results of this investigation will be used by FERC to determine how it should proceed on existing and future complaints about long-term contracts, but will not address or prejudge any arguments made in these proceedings.
NOTE 13. OTHER REGULATORY MATTERS
Gas Industry Restructuring The natural gas industry in California experienced an initial phase of restructuring during the 1980s, but the CPUC did not make major changes after the early 1990s. In January 1998, the CPUC released a staff report initiating a project to assess the current market and regulatory framework for California's natural gas industry. In July 1999, after hearings, the CPUC issued a decision stating which natural gas regulatory changes it found most promising, encouraging parties to submit settlements addressing those changes, and providing for further hearings if necessary. On December 11, 2001, the CPUC issued a decision adopting much of a settlement that had been submitted in 2000 by SDG&E and approximately 30 other parties representing all segments of the gas industry in Southern California, but which was opposed by other parties. The CPUC decision adopts the following provisions: a system for shippers to hold firm, tradable rights to capacity on SoCalGas' major gas transmission lines; new balancing services including separate core and noncore balancing provisions; a reallocation among customer classes of the cost of interstate pipeline capacity held by SoCalGas and an unbundling of interstate capacity for gas marketers serving core customers; and the elimination of noncore customers' option to obtain gas supply service from SDG&E. The CPUC modified the settlement to provide increased protection against the exercise of market power by persons who would acquire rights on the SoCalGas gas transmission system. The CPUC also rejected certain aspects of the settlement that would have provided more options for natural gas marketers serving core customers. The CPUC is still considering the schedule for implementation of these regulatory changes, but it is expected that most of the changes will be implemented during 2002. SDG&E believes the decision will make natural gas service more reliable, efficient and better tailored to the desires of customers. The decision is not expected to negatively impact SDG&E's earnings.
Performance-Based Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for SDG&E. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity goals, as well as cost reductions, rather than relying solely on expanding utility plant in a market where a utility already has a highly developed infrastructure. In April 2001, SDG&E filed its 2000 PBR report with the CPUC. For 2000, SDG&E exceeded all six performance indicator benchmarks, resulting in a request for a total net reward of $11.7 million. The CPUC has not yet approved this report and these awards have not been recorded. In addition, SDG&E achieved an actual 2000 rate of return (applicable only to electric distribution and natural gas transportation) of 8.74 percent, which is below the authorized 8.75 percent. This results in no sharing of earnings in 2000 under the PBR sharing mechanism (as described below). SDG&E's PBR mechanism was to have been in effect through December 31, 2002, at which time the mechanism was to be updated. That update was to include, among other things, a reexamination of SDG&E's reasonable costs of operation to be allowed in rates. The PBR and Cost of Service (COS) cases for SDG&E were both due to be filed on December 21, 2001. However, SDG&E's PBR/COS cases were delayed by an October 10, 2001 CPUC decision such that the resulting rates would be effective in 2004 instead of 2003. The decision also denies SDG&E's request to continue equal sharing between ratepayers and shareholders of the estimated savings for the merger discussed in Note 1 and, instead, orders that all of the estimated 2003 merger savings go to ratepayers. The portion to be refunded to electric ratepayers was credited to the TCBA during the fourth quarter of 2001, based on the NPV in 2001 of the savings for 2003. Merger savings related to 2001 and 2002 also were credited. The combined NPV was $39 million. Merger savings allocable to gas ratepayers will be refunded through once-a- year bill credits, as has been the case. Key elements of the current mechanisms include an annual indexing mechanism that adjusts rates by the inflation rate less a productivity factor and other adjustments to accommodate major unanticipated events, a sharing mechanism with customers that applies to earnings that exceed the authorized rate of return on rate base, rate refunds to customers if service quality deteriorates or awards if service quality exceeds set standards, and a change in authorized rate of return and customer rates if interest rates change by more than a specified amount. The rate change is triggered by a six-month trailing average and a 100-basis-point change in interest rates. If these events occur, there would be an automatic adjustment of rates for the change in the cost of capital according to a formula which applies a percentage of the change to various capital components.
Demand Side Management Awards In recent years, the IOUs have participated in a CPUC program whereby they could earn awards for operating and/or administering energy- conservation efforts involving their retail customers. SDG&E has participated in these programs and has consistently achieved significant earnings therefrom. As part of the CPUC's review of the program, a draft decision is proposing that the program be reduced in scope and that award potentials for the IOUs be eliminated. An alternate proposal would maintain the award concept, but the potential awards would probably be reduced. The CPUC is scheduled to review both proposals at its March 21, 2002 meeting.
Biennial Cost Allocation Proceeding(BCAP) Rates to recover the changes in the cost of natural gas transportation services are determined in the BCAP. The BCAP adjusts rates to reflect variances in customer demand from estimates previously used in establishing customer natural gas transportation rates. The mechanism substantially eliminates the effect on income of variances in market demand and natural gas transportation costs. SDG&E filed its 2003 BCAP on October 5, 2001. On April 20, 2000, the CPUC issued a decision on the 1999 BCAP, adopting overall decreases in natural gas revenues of $37 million for SDG&E for transportation rates effective June 1, 2000. Since the decreases reflect anticipated changes in corresponding costs, they have no effect on net income.
Cost of Capital In June 1999, the CPUC adopted a 10.6 percent return on common equity (ROE) and an 8.75 percent return on rate base (ROR) for SDG&E's electric distribution and natural gas businesses. These rates remain in effect through 2002. The electric-transmission cost of capital is determined under a separate FERC proceeding. SDG&E is required to file an application by May 8, 2002, addressing ROE, ROR and capital structure for 2003. The application will, among other things, consider the recent and ongoing financial impacts on SDG&E of electric industry restructuring.
Utility Integration On September 20, 2001 the CPUC approved Sempra Energy's request to integrate the management teams of SDG&E and SoCalGas. The decision retains the separate identities of each utility and is not a merger. Instead, utility integration is a reorganization that consolidates senior management functions of the two utilities and returns to the utilities a significant portion of shared support services currently provided by Sempra Energy's centralized corporate center. Once implementation is completed, the integration is expected to result in more efficient and effective operations. In a related development, a CPUC draft decision would allow SDG&E and SoCalGas to combine their natural gas procurement activities. The CPUC is scheduled to act on the draft decision at its April 4, 2002 meeting.
CPUC Investigation of Energy-Utility Holding Companies The CPUC has initiated an investigation into the relationship between California's IOUs and their parent holding companies. Among the matters to be considered in the investigation are utility dividend policies and practices and obligations of the holding companies to provide financial support for utility operations under the agreements with the CPUC permitting the formation of the holding companies. On January 11, 2002, the CPUC issued a decision to clarify under what circumstances, if any, a holding company would be required to provide financial support to its utility subsidiaries. The CPUC broadly determined that it would require the holding company to provide cash to a utility subsidiary to cover its operating expenses and working capital to the extent they are not adequately funded through retail rates. This would be in addition to the requirement of holding companies to cover their utility subsidiaries' capital requirement, as the IOUs have previously acknowledged in connection with the holding companies' formations. On January 14, 2002, the CPUC ruled on jurisdictional issues, deciding that the CPUC had jurisdiction to create the holding company system and, therefore, retains jurisdiction to enforce conditions to which the holding companies had agreed. The company has filed to request rehearing on the issues.
NOTE 14. QUARTERLY FINANCIAL DATA (Unaudited)
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
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 Information Statement prepared for the May 2002 annual meeting of shareholders. The information required on the company's executive officers is provided below.
EXECUTIVE OFFICERS OF THE REGISTRANT Name Age* Positions - -------------------------------------------------------------------
Edwin A. Guiles 52 Chairman and Chief Executive Officer
Debra L. Reed 45 President and Chief Financial Officer
James P. Avery 45 Senior Vice President, Electric Transmission
Steven D. Davis 45 Senior Vice President, Customer Service and External Relations Terry M. Fleskes 45 Vice President and Controller
Margot A. Kyd 48 Senior Vice President, Corporate Business Solutions
Roy M. Rawlings 57 Senior Vice President, Distribution Operations
William L. Reed 49 Senior Vice President, Regulatory Affairs
Lee M. Stewart 56 Senior Vice President, Gas Transmission
* As of December 31, 2001.
Except for Mr. Avery, each Executive Officer has been an officer or employee of Sempra Energy or one of its subsidiaries for more than five years. Prior to joining SDG&E in 2001, Mr. Avery was a consultant with R.J. Rudden Associates. Except for Mr. Avery, each executive officer at San Diego Gas & Electric Company holds the same position at Southern California Gas Company.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference from "Election of Directors" and "Executive Compensation" in the Information Statement prepared for the May 2002 annual meeting of shareholders.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is incorporated by reference from "Election of Directors" in the Information Statement prepared for the May 2002 annual meeting of shareholders.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14.
ITEM 14. 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 This Report Independent Auditors' Report . . . . . . . . . . . . . . 31
Statements of Consolidated Income for the years ended December 31, 2001, 2000 and 1999 . . . . . . . . 32
Consolidated Balance Sheets at December 31, 2001 and 2000. . . . . . . . . . . . . . . . . . . . . 33
Statements of Consolidated Cash Flows for the years ended December 31, 2001, 2000 and 1999 . . . . . 35
Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 2001, 2000 and 1999 . . . . . . . . . . . 36
Notes to Consolidated Financial Statements . . . . . . . 37
2. Financial statement schedules Other schedules for which provision is made in Regulation S-X are not required under the instructions contained therein, are inapplicable or the information is included in the Consolidated Financial Statements and notes thereto.
3. Exhibits See Exhibit Index on page 70 of this report.
(b) Reports on Form 8-K The following reports on Form 8-K were filed after September 30, 2001:
None
INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Numbers 33-45599, 33-52834, 333-52150, and 33-49837 on Form S-3 of our report dated February 4, 2002 (February 21, 2002 as to Note 12), appearing in the Annual Report on Form 10-K of San Diego Gas and Electric Company for the year ended December 31, 2001.
/S/ DELOITTE & TOUCHE LLP
San Diego, California March 15, 2002
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.
SAN DIEGO GAS & ELECTRIC COMPANY
By: /s/ Edwin A. Guiles . Edwin A. Guiles Chairman 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.
EXHIBIT INDEX The Forms 8-K, 10-K and 10-Q referred to herein were filed under Commission File Number 1-3779 (SDG&E), Commission File Number 1-11439 (Enova Corporation, Commission File Number 1-14201 (Sempra Energy) and/or Commission File Number 333-30761 (SDG&E Funding LLC).
Exhibit 1 -- Underwriting Agreements
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 3.01 Restated Bylaws of San Diego Gas & Electric as of November 6, 2001.
Articles of Incorporation 3.02 Amended and Restated Articles of Incorporation of San Diego Gas & Electric Company (Incorporated by reference from the SDG&E Form 10-Q for the three months ended March 31, 1994 (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.
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.)
Exhibit 10 -- Material Contracts 10.01 Restated Letter Agreement between San Diego Gas & Electric Company and the California Department of Water Resources dated April 5, 2001 (2001 Sempra Energy Form 10-K Exhibit 10.04).
10.02 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).
10.03 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 10.04 Form of Sempra Energy Severance Pay Agreement for Executives (2001 Sempra Energy Form 10-K Exhibit 10.07).
10.05 Sempra Energy Executive Security Bonus Plan effective January 1, 2001 (2001 Sempra Energy Form 10-K Exhibit 10.08).
10.06 Sempra Energy Deferred Compensation and Excess Savings Plan effective January 1, 2000 (2000 Sempra Energy Form 10-K Exhibit 10.07).
10.07 Sempra Energy Supplemental Executive Retirement Plan as amended and restated effective July 1, 1998 (1998 Sempra Energy Form 10-K Exhibit 10.09).
10.08 Sempra Energy Executive Incentive Plan effective June 1, 1998 (1998 Sempra Energy Form 10-K Exhibit 10.11).
10.09 Sempra Energy Executive Deferred Compensation Agreement Effective June 1, 1998(1998 Sempra Energy Form 10-K Exhibit 10.12).
10.10 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)).
10.11 Supplemental Executive Retirement Plan restated as of July 1, 1994 (1994 SDG&E Form 10-K Exhibit 10.14).
Financing 10.12 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).
10.13 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 (1996 Form 10-K Exhibit 10.31).
10.14 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 (1996 Form 10-K Exhibit 10.32).
10.15 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).
10.16 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).
10.17 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).
10.18 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).
10.19 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).
10.20 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 (1996 Form 10-K Exhibit 10.41).
10.21 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).
10.22 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).
Nuclear 10.23 Uranium enrichment services contract between the U.S. Department of Energy (DOE assigned its rights to the U.S. Enrichment Corporation, a U.S. government-owned corporation, on July 1, 1993) and Southern California Edison Company, as agent for SDG&E and others; Contract DE-SC05-84UEO7541, dated November 5, 1984, effective June 1, 1984, as amended (1991 SDG&E Form 10-K Exhibit 10.9).
10.24 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).
10.25 Amendment No. 1 to the Qualified CPUC Decommissioning Master Trust Agreement dated September 22, 1994 (see Exhibit 10.24 herein)(1994 SDG&E Form 10-K Exhibit 10.56).
10.26 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 10.24 herein)(1994 SDG&E Form 10-K Exhibit 10.57).
10.27 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 10.24 herein)(1996 Form 10-K Exhibit 10.59).
10.28 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 10.24 herein)(1996 Form 10-K Exhibit 10.60).
10.29 Fifth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.24 herein)(1999 Form 10-K Exhibit 10.26).
10.30 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 10.24 herein)(1999 Form 10-K Exhibit 10.27).
10.31 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).
10.32 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 10.31 herein)(1996 Form 10-K Exhibit 10.62).
10.33 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 10.31 herein)(1996 Form 10-K Exhibit 10.63).
10.34 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 10.31 herein)(1999 Form 10-K Exhibit 10.31).
10.35 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 10.31 herein)(1999 Form 10-K Exhibit 10.32).
10.36 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).
10.37 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).
Natural Gas Transportation and Storage 10.38 Master Services Contract, Schedule J, Transaction Based Storage Service Agreement dated April 1, 2002 and expiring March 31, 2003 between San Diego Gas & Electric Company and Southern California Gas Company.
10.39 Master Services Contract, Schedule J, Transaction Based Storage Service Agreement dated April 1, 2001 and expiring March 31, 2002 between San Diego Gas & Electric Company and Southern California Gas Company.
10.40 Master Services Contract (Intrastate Transmission Service), dated July 1, 1998 (month to month) between San Diego Gas & Electric Company and Southern California Gas Company (1998 10-K Exhibit 10.64).
10.41 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).
10.42 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).
10.43 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).
Other 10.44 Lease agreement dated as of March 25, 1992 with CarrAmerica Development and Construction as lessor of an office complex at Century Park (1994 SDG&E Form 10-K Exhibit 10.70).
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, 2001, 2000, 1999, 1998 and 1997.
Exhibit 21 - Subsidiaries
21.01 Schedule of Subsidiaries at December 31, 2001.
Exhibit 23 - Independent Auditors' Consent, page 68.
GLOSSARY
AB 1 A California Assembly bill authorizing the California Department of Water Resources to purchase energy for California consumers.
AB 43X A California Assembly bill to extend AB265 to include large consumers. AB 265 California Assembly Bill 265 (AB 265)imposed a rate ceiling of 6.5 cents/kWh
AB 1421 A California Assembly bill requiring that natural gas utilities provide bundled basic gas service to certain customers.
AB 1890 A California Assembly bill restructuring the electric energy law in California.
AFUDC Allowance for Funds Used During Construction
BCAP Biennial Cost Allocation Proceeding
Bcf One Billion Cubic Feet (of natural gas)
CEC California Energy Commission
COS Cost of Service
CPUC California Public Utilities Commission
DOE Department of Energy
DTSC Department of Toxic Substances Control
DWR Department of Water Resources
Edison Southern California Edison Company
EMFs Electric and Magnetic Fields
Enova Enova Corporation
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Intertie Pacific Intertie
IOUs Investor-Owned Utilities
ISO Independent System Operator
kWh Kilowatt Hour
LIFO Last in first out inventory
mmbtu Million British Thermal Units (of natural gas)
MOU Memorandum of Understanding
mW Megawatt
NRC Nuclear Regulatory Commission
Parent Enova Corporation
PBR Performance-Based Ratemaking/Regulation
PIER Public Interest Energy Research
PE Pacific Enterprises
PG&E Pacific Gas and Electric Company
PGE Portland General Electric Company
PRP Potentially Responsible Party
PX Power Exchange
QFs Qualifying Facilities
ROE Return on Equity
ROR Rate of Return
SDG&E San Diego Gas & Electric Company
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
SoCalGas Southern California Gas Company
SONGS San Onofre Nuclear Generating Station
Southwest Powerlink A transmission line connecting San Diego to Phoenix and intermediate points.
TCBA Transition Cost Balancing Account
UEG Utility Electric Generation
VaR Value at Risk