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 25 cities and gas franchises with two counties and the 25 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). State 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, 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) 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.
Federal 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 Note 12 of the notes to Consolidated Financial Statements, herein.
SOURCES OF REVENUE
Industry segment information is contained 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.
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, a number of factors, including supply/demand imbalances, resulted in abnormally high wholesale electric prices beginning in mid-2000. In response to these high commodity prices, the California legislature has adopted or is proposing to adopt legislation intended to stabilize the California electric utility industry and reduce wholesale electric commodity prices.
Additional information concerning electric-industry restructuring is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 11 and 12 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. As discussed in Note 12 of the notes to Consolidated Financial Statements, due to current 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, the California legislature recently passed a bill authorizing the Department of Water Resources (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. An Independent System Operator (ISO) schedules power transactions and access to the transmission system. In 1999, SDG&E completed divestiture of its owned generation other than nuclear. Based on generating plants in service and purchased-power contracts currently in place, at February 28, 2001, 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 186 Contracts with others 593 ----- Total 1,209 ===== * Net of plants' internal usage
Natural Gas/Oil Generating Plants: In connection with electric- industry restructuring, in December 1998, SDG&E entered into agreements for the sale of its South Bay and Encina power plants and 17 combustion turbines. During the quarter ended June 30, 1999, these sales were completed for total net proceeds of $466 million. The South Bay Power Plant sale to the San Diego Unified Port District for $110 million was completed on April 23, 1999. Duke South Bay, a subsidiary of Duke Energy Power Services, will manage the plant for the Port District. The sale of the Encina Power Plant and 17 combustion-turbine generators to Dynegy Inc. and NRG Energy Inc. for $356 million was completed on May 21, 1999. SDG&E is operating and maintaining both facilities for the new owners for two years.
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.
During 2000, SDG&E spent $4 million on capital additions and modifications of Units 2 and 3, and expects to spend $7 million in 2001.
SDG&E deposits funds in an external trust to provide for the decommissioning of all three units.
Additional information concerning the SONGS units, nuclear decommissioning and industry restructuring (including SDG&E's divestiture of its electric generation assets) is provided below and in "Environmental Matters" herein, and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 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 86 Coal
Public Service Company of New Mexico (PNM) April 2001 100 System Supply ------ Total 186 ====== Other Contracts: 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 16 Cogeneration ------ Others --
Avista Supply December 2001 150 System Supply
PacifiCorp December 2001 100 System Supply
Others December 2003 125 System Supply ------ Total 593 ======
Under the contracts with PGE and PNM, SDG&E pays a capacity charge plus a charge based on the amount of energy received. Charges under these contracts are based on the selling utility's costs, including a return on and depreciation of the utility's rate base (or lease payments in cases where the utility does not own the property), fuel expenses, operating and maintenance expenses, transmission expenses, administrative and general expenses, and state and local taxes. Costs under the contracts with Qualifying Facilities 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 (WSPP), which includes an electric-power and transmission-rate agreement with utilities and power agencies located throughout the United States and Canada. More than 200 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.
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 costs of the fuels with each other and with the total cost of purchased power: Percent of kWh Cents per kWh - ------------------------------------------------------------------- 2000 1999 1998 2000 1999 1998 ----- ----- ----- ---- ---- ---- Natural gas * -- 6.5% 17.3% -- 3.0 3.0 Nuclear fuel 14.9 12.6 11.5 0.5 0.5 0.6 ----- ----- ----- Total generation 14.9 19.1 28.8 Purchased power and ISO/PX 85.1 80.9 71.2 9.7 3.7 3.5 ----- ----- ----- Total 100.0% 100.0% 100.0% ====== ====== ====== * As described previously, SDG&E sold its South Bay and Encina power plants and 17 combustion turbines 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.
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 Units 2 and 3 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 $0.99 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 760,000 end-use customers throughout the western portion of San Diego County. The Company also transports gas to over 1,000 customers who procure their 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. SDG&E recovers such fixed charges in rates. These contracts expire at various dates between 2007 and 2023.
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.
SDG&E had been involved in negotiations and litigation with four Canadian suppliers concerning contract terms and prices related to long-term natural gas supply contracts. In 1999, SDG&E settled with the last of the four suppliers, terminating the contract. SDG&E continues to purchase natural gas from one of the suppliers under terms of the settlement agreement. Additional information regarding natural gas contracts is provided in Note 11 of the notes to Consolidated Financial Statements herein.
The following table shows the sources of natural gas deliveries from 1996 through 2000.
Market-sensitive natural gas supplies (supplies purchased on the spot market as well as under longer-term contracts based on spot prices) accounted for nearly 100 percent of total natural gas volumes purchased by the Company during the last five years. Supply/demand imbalances have increased the price of natural gas in California more than in the rest of the country because of California's dependence on natural gas fired electric generation due to air-quality considerations. The average price of natural gas at the California/Arizona border was $6.25/mmbtu in 2000, compared with $2.33/mmbtu in 1999. On December 11, 2000, the average spot cash gas price at the CA/AZ border reached a record high $56.91/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 763,000 core customers (734,000 residential and 29,000 small commercial and industrial). Noncore customers consist primarily of utility electric generation (UEG), wholesale, and large commercial and industrial customers, and total 123.
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. The Company continues to be obligated to purchase reliable supplies of natural gas to serve the requirements of its core customers. SoCalGas and SDG&E recently filed an application with the CPUC to combine the two companies' core procurement portfolios.
Noncore customers have the option of purchasing natural gas either from the Company or from other sources, such as brokers or producers, for delivery through the Company's transmission and distribution system. The only natural gas supplies that the Company may offer for sale to noncore customers are the same supplies that it purchases for its core customers. Most noncore customers procure their own natural gas supply.
In 2000, 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 revenue 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 UEG 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 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 13,000 and 27,000 new customer meters in 2000 and 1999, respectively, representing a growth rate of approximately 1.8 percent and 3.7 percent, respectively. The Company expects its growth rate for 2001 will be at the 2000 level.
During 2000, 91 percent of residential energy customers in the Company's service area used natural gas for water heating, 73 percent
for space heating, 52 percent for cooking and 35 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 2000 was only 123, they accounted for approximately 14 percent of the authorized natural gas revenues and 64 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. The increase in UEG demand in 2000 was due to higher demand for electricity and increased use of natural gas for electric generation, a colder 2000- 2001 winter and population growth in California. Natural gas demand in 1999 for UEG customer use increased primarily due to higher electric energy usage in the summer, as a result of warmer weather.
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 UEG customers may be adversely 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 and 12 of the notes to Consolidated Financial Statements herein.
RATES AND REGULATION
SDG&E is regulated by the CPUC, which consists of five commissioners appointed by the Governor of California for staggered six-year terms. It is the responsibility of the CPUC to determine that utilities operate within the best interests of their customers. The regulatory structure is complex and has a substantial impact on the profitability of the Company. Both the electric and natural gas industries are currently undergoing transitions to competition and are being impacted by abnormally high commodity prices resulting from supply/demand imbalances.
Electric Industry Restructuring A flawed electric-industry restructuring plan, electricity supply/demand imbalances, and legislative and regulatory responses significantly impact the Company's operations. Additional information on electric-industry restructuring 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.
Natural Gas Industry Restructuring The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. The CPUC is currently assessing the current market and regulatory framework for California's natural gas industry. Supply/demand imbalances are affecting the price of natural gas in California more than in the rest of the country because of California's dependence on natural gas fired electric generation due to air-quality considerations. 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 12 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.
Performance-Based Regulation (PBR) In recent years, the CPUC has directed utilities to use PBR. To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, PBR has replaced the general rate case and certain other regulatory proceedings for SDG&E. Additional information on PBR 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.
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. The BCAP will continue under PBR. Additional information on the BCAP 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.
Cost of Capital Under PBR, annual Cost of Capital proceedings have been replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. 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. In early 1998, the CPUC modified this mechanism to exclude these costs related to electric generation activities. These costs are now eligible for inclusion in the competition transition cost recovery process. The effect of this decision is that SDG&E's costs of compliance with environmental regulations may not be fully recoverable if they exceed the estimates included in the transaction costs (see "Electric Resources" above).
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 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. Included in the 2000 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, 2000, it is estimated that less than $300,000 worth of work remains to resolve known liabilities. 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 $450,000. Offsite cleanup in 2001 is not expected to be significant.
SDG&E sold its fossil-fuel power plants and combustion turbines in 1999. As a part of its due diligence for the sale, SDG&E conducted a thorough environmental assessment of the South Bay and Encina power plants and 17 combustion turbine sites. 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 for electric generation. 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 $7 million to $8 million at the South Bay power plant, $0.9 million at the Encina power plant, and $1.9 million at the combustion turbine sites. These costs were offset against the sales price for the facilities, together with other appropriate costs, and the remaining net proceeds were offset against SDG&E's other transition costs. Remediation of the plants commenced in early 2001; completion is expected in mid-2001.
Cleanup of Station B, a steam and electric generating facility operated in San Diego between 1911 and 1993, was completed during 1999. Activities included removal of asbestos and lead-based paint and the removal or cleanup of other substances. The sale of the facility was completed in December 1999.
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 a 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.
At December 31, 2000, SDG&E's estimated remaining investigation and remediation liability related to hazardous waste sites was $1 million, of which 90 percent is authorized to be recovered through the Hazardous Waste Collaborative mechanism. 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 power plants and combustion turbines, the Company's primary air- quality issue, compliance with these standards is less significant 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 $27.4 million. The pricing structure contained in the CPUC's decision regarding accelerated recovery of SONGS Units 2 and 3 (described in "Electric Resources" above) is expected to accommodate these added mitigation costs.
OTHER MATTERS
Research, Development and Demonstration (RD&D) For 2000, the CPUC authorized SDG&E to fund $1.2 million and $4.2 million for its 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 $4.5 million over the past three years.
Employees of Registrant As of December 31, 2000, SDG&E had 3,248 employees, compared to 3,071 at December 31, 1999.
Wages Certain employees at SDG&E are represented by the International Brotherhood of Electrical Workers, Local 465, under two labor agreements. The current generation contract runs through May 25, 2001. The transmission and distribution contract runs through August 31, 2001.
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. Periodically various areas of the service territory require expansion to handle 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, 171 miles of high pressure transmission pipelines, 7,068 miles of high and low pressure distribution mains, and 5,859 miles of service lines.
Other Properties SDG&E occupies an office complex at Century Park Court in San Diego pursuant to an operating lease ending in the year 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.
Dividend Restrictions CPUC regulation of SDG&E's capital structure limits to $154 million the portion of the Company's December 31, 2000 retained earnings that is available for dividends. Additional information is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" 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 1998 through 2000, and provides information about the capital resources, liquidity and financial performance of San Diego Gas & Electric (SDG&E or the Company). This section 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 the electric and natural gas businesses. It generates and purchases electric energy and distributes it to 1.2 million customers in San Diego County and an adjacent portion of southern Orange County, California. It also purchases and distributes natural gas to 0.8 million customers in San Diego County and transports electricity and gas for others. The Company is the principal subsidiary of Enova Corporation (Enova or the Parent), which is wholly owned by Sempra Energy. SDG&E's only subsidiary is SDG&E Funding LLC, which is described below under "Electric Rates." The uncertainties shaping California's electric industry and business environment significantly affect the Company's operations. A flawed electric-industry restructuring plan, electricity supply/demand imbalances, and legislative and regulatory responses, including a temporary rate ceiling on the cost of electricity that SDG&E can pass on to its small-usage customers on a current basis, have materially and adversely affected the timing of revenue collections by the Company and related cash flows. These, together with concerns with California utility regulation generally and increased electricity cost undercollections, have significantly impaired the Company's access to the capital markets and ability to obtain financing on commercially reasonable terms. In addition, supply/demand imbalances are affecting the price of natural gas in California more than in the rest of the country because of California's dependence on natural gas fired electric generation due to air-quality considerations. These recent developments are continuing to change rapidly. Information as of March 7, 2001, the date this report was prepared, is found herein, primarily under "Results of Operations" and "Factors Influencing Future Performance" and in Note 12 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, and Enova, in connection with a business combination that became effective on June 26, 1998 (the PE/Enova business combination). In connection with the PE/Enova business combination, the holders of common stock of PE and Enova became the holders of Sempra Energy's common stock. The preferred stock of SDG&E remained outstanding. The combination was a tax-free transaction. Expenses incurred by SDG&E in connection with the business combination were $35 million, after tax, in 1998. No significant expenses were incurred subsequently. These costs consist primarily of employee-related costs, and investment banking, legal, regulatory and consulting fees. See Note 1 of the notes to the Consolidated Financial Statements for additional information. Capital Resources and Liquidity The Company's operations have historically been a major source of liquidity. However, higher electric-commodity prices and the inability of SDG&E to bill its small-usage customers on a current basis for the full purchase cost of electricity due to legislative actions, have resulted in a significant decrease in cash flows available from SDG&E's operating activities in 2000. SDG&E had incurred costs in excess of amounts which it can bill its customers on a current basis, or "undercollected costs," of $447 million at December 31, 2000, and $605 million at January 31, 2001. California recently enacted legislation authorizing the California Department of Water Resources (DWR) to purchase electricity for resale to all California investor-owned utility retail end-use customers (including customers of SDG&E), that is intended to halt or substantially slow the growth of cost undercollections by SDG&E and other California Investor-Owned Utilities (IOUs). Consequently, SDG&E believes that its continued accumulation of undercollected costs will depend primarily upon the effects of this legislation and other legislative and regulatory developments. For additional discussion, see "Results of Operations" herein and Note 12 of the notes to Consolidated Financial Statements. Additional working capital and other requirements are met primarily through the issuance of long-term debt. Cash requirements primarily consist of capital expenditures for utility plant. Due to the factors described herein and in Note 12 of the notes to Consolidated Financial Statements regarding high electricity costs, and the Company's inability to bill its small-usage customers on a current basis for the full cost of electricity purchases, management is unable to determine whether the sources of funding described above are sufficient to provide for all of the capital expenditures it would otherwise intend to make after funding its basic liquidity needs. The Company's ability to fund its capital expenditure program and liquidity requirements is significantly affected by the Company's credit ratings and related ability to obtain financing on commercially reasonable terms. Continued purchases by the DWR for resale to SDG&E's customers of substantially all of the electricity that would otherwise be purchased by SDG&E (as further discussed under "Results of Operations" herein) or dramatic decreases in wholesale electricity prices, favorable action by the CPUC on SDG&E's electric rate surcharge application discussed below and SDG&E's access to the capital markets are required to manage and finance SDG&E's cost undercollections and provide adequate liquidity.
Cash Flows From Operating Activities 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, and SDG&E's cost undercollections related to high electric commodity prices and energy charges in excess of the 6.5 cents/kWh ceiling in accordance with AB 265 (see "Results of Operations" below and Note 12 of the notes to Consolidated Financial Statements). This decrease was partially offset by higher deferred incomes 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 related to higher electricity costs referred to above. The decrease in cash flows from operating activities in 1999 was primarily due to the completion of the recovery of SDG&E's stranded costs in 1999 and to reduced revenues, both the result of the sale of SDG&E's fossil power plants and combustion turbines in the second quarter of 1999. This decrease was partially offset by the absence of business-combination expenses in 1999. See additional discussion on the sale of the power plants in Note 12 of notes to Consolidated Financial Statements.
Cash Flows From Investing Activities Net cash provided by investing activities increased in 2000 primarily due to loan repayments from Sempra Energy, partially offset by higher capital expenditures for utility plant. Cash flows from investing activities in 1999 included the proceeds from the sale of SDG&E's two fossil power plants and combustion turbines, offset by loans to Sempra Energy and capital expenditures. The South Bay Power Plant was sold to the San Diego Unified Port District for $110 million. The Encina Power Plant and 17 combustion-turbine generators were sold to Dynegy, Inc. and NRG Energy, Inc. for $356 million. See additional discussion in Note 12 of the notes to Consolidated Financial Statements.
Capital Expenditures Capital expenditures were $79 million higher in 2000 compared to 1999 primarily due to additions and improvements to the natural gas and electric distribution systems. Capital expenditures were $18 million higher in 1999 compared to 1998 primarily due to improvements to the electric distribution system as a result of higher demand and an expansion of the natural gas system. Capital expenditures in 2001 are expected to be comparable to those of 2000. They will include improvements and additions to the Company's gas and electric distribution systems and are intended to be financed primarily by operations and debt 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 increased in 2000 primarily due to higher dividends paid to the Parent. Net cash used in financing activities decreased in 1999 compared to 1998 primarily due to lower dividends paid to the Parent and lower long-term debt repayments in 1999.
Long-Term Debt
In 2000, repayments on long-term debt included $65 million of rate- reduction bonds and $10 million of first-mortgage bonds. In addition, 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 7.0 percent fixed interest rate. Between January 24 and February 5, 2001, the Company drew down $250 million from its $285 million available credit facilities. In 1999, repayments on long-term debt included $28 million of first-mortgage bonds and $66 million of rate-reduction bonds. In 1998, repayments included $147 million of first-mortgage bonds and $66 million of rate-reduction bonds.
Dividends
Dividends paid to the Parent amounted to $400 million in 2000, compared to $100 million in 1999 and $263 million in 1998. The payment of future dividends and the amount thereof are within the discretion of the Company's board of directors. CPUC regulation of SDG&E's capital structure limits to $154 million the portion of the Company's December 31, 2000, retained earnings that is available for dividends.
Capitalization Total capitalization including the current portion of long-term debt was $2.5 billion at December 31, 2000. The debt-to-capitalization ratio was 54 percent at December 31, 2000. Significant changes in capitalization during 2000 included higher dividends declared to the Parent, partially offset by lower outstanding debt.
Cash and Cash Equivalents Cash and cash equivalents were $256 million at December 31, 2000. This cash is available for investment in projects consistent with the Company's strategic direction, the retirement of debt, the payment of dividends and other corporate purposes. However, as discussed above, funds available for these purposes may be limited by SDG&E's ability to recover from its customers on a current basis the full amount of the high electricity prices. If the impacts of the high electricity costs and the Company's inability to bill customers for these costs on a current basis are favorably resolved, the Company anticipates that operating cash required in 2001 for common stock dividends and debt payments will be provided by cash generated from operating activities and existing cash balances. Cash required for capital expenditures will be provided by cash generated both from operating activities and from long-term and short-term debt issuances. In addition to cash generated from ongoing operations, SDG&E has credit agreements that permit short-term borrowings of up to $285 million, and/or support its commercial paper. These agreements expire at various dates in 2001. Because of the ramifications of the high electric costs (as discussed in Notes 3 and 12 of the notes to Consolidated Financial Statements), between January 24 and February 5, 2001, SDG&E drew down $250 million from its available credit facilities. In December 2000, SDG&E filed a shelf registration for the public offering of up to $800 million of debt. As yet, no debt securities have been issued under these registration statements. For additional information see Notes 4 and 12 of the notes to Consolidated Financial Statements. For additional discussion see "Factors Influencing Future Performance" below and Note 12 of the notes to Consolidated Financial Statements
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. The California Power Exchange (PX) served as a wholesale power pool and the Independent System Operator (ISO) scheduled power transactions and access to the transmission system. A flawed electric-industry restructuring plan, electricity supply/demand imbalances, and legislative and regulatory responses, including the rate ceiling as described in "Factors Influencing Future Performance" below, have materially and adversely affected the timing of revenue collections by the Company and related cash flows. Additional legislation passed in early 2001, as well as future legislation and regulatory actions concerning California's energy crisis, could have a significant impact on SDG&E's future operations, liquidity and financial results. The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. The CPUC currently is studying the issue of restructuring for sales to core customers and, as mentioned above, supply/demand imbalances are affecting the price of natural gas in California more than in the rest of the country because of California's dependence on natural gas fired electric generation due to air-quality considerations. 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 situations under "Factors Influencing Future Performance" and in Note 12 of the notes to Consolidated Financial Statements. The table below summarizes the components of utility electric and natural gas volumes and revenues by customer class for 2000, 1999 and 1998.
2000 Compared to 1999
Net income decreased from $199 million in 1999 to $151 million in 2000. The decrease is primarily due to an after-tax charge of $30 million 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 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 $50 million pretax charge referred to above 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 a 6.5-cent rate cap. In January 2001, SDG&E filed with the CPUC for a temporary electric surcharge to reduce the growing undercollection of electric commodity costs. SDG&E is unable to predict the amount, if any, of the request that the CPUC would grant, or when it would issue a decision. The CPUC has deferred this proceeding pending resolution of the broader issues related to the state-wide high costs. Additional information concerning electric rates is described in "Factors Influencing Future Performance" below and in Note 12 of the notes to Consolidated Financial Statements. Natural gas revenues increased from $389 million in 1999 to $487 million in 2000, primarily due to higher prices for natural gas in 2000 (see discussion of balancing accounts in Note 2 of the notes to Consolidated Financial Statements) and higher utility electric generation (UEG) revenues. The increase in UEG 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 consist of the price of the natural gas transportation service since the sales now are to unrelated parties. In addition, the generating plants receiving gas transportation from SDG&E are operating at higher capacities than previously, as discussed below. The cost of electric fuel and purchased power increased from $536 million 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 power plants and warmer weather in California. Additional information concerning the recent supply/demand conditions is provided in Note 12 of the notes to Consolidated Financial Statements. 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. PX/ISO power revenues have been netted against purchased-power expenses. 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. Under the current regulatory framework, changes in core-market natural gas prices do not affect net income, since the actual commodity cost of natural gas for core customers is included in customer rates on a substantially current basis. Depreciation and decommissioning expense decreased from $561 million in 1999 to $210 million in 2000. The decrease was primarily due to the mid-1999 completion of the accelerated recovery of SDG&E's generation assets. Operating expenses decreased from $479 million in 1999 to $412 million in 2000. The decrease was primarily due to the 1999 sale of SDG&E's fossil fuel generating plants.
1999 Compared to 1998
Net income for 1999 increased to $199 million, compared to net income of $191 million in 1998. The increase is primarily due to $35 million, after-tax, of PE/Enova business combination expense in 1998 (none in 1999) partially offset by lower income from electric operations. Net income decreased to $36 million for the three months ended December 31, 1999, compared to net income of $50 million for the corresponding period in 1998. The decrease is due to lower income from electric operations in 1999 and higher interest on the portion of the rate- reduction bond liability which was refundable to customers. Electric revenues decreased from $1.9 billion in 1998 to $1.8 billion in 1999. The decrease was primarily due to a temporary decrease in base electric rates following the completion of SDG&E's stranded cost recovery as noted above and as more fully described in Note 12 of the notes to Consolidated Financial Statements. Natural gas revenues increased from $384 million in 1998 to $389 million in 1999. The increase was primarily due to higher residential and UEG revenues. The increased residential revenues are due to slightly higher volumes sold in 1999 compared to 1998. The increase in UEG revenues was primarily due to the sale of SDG&E's fossil fuel generating plants in the second quarter of 1999, as explained above. The Company's cost of natural gas distributed increased from $166 million in 1998 to $168 million in 1999. The increase was largely due to an increase in the average price of natural gas purchased. Depreciation and decommissioning expense decreased from $603 million in 1998 to $561 million in 1999. The decrease was primarily due to the mid-1999 completion of the accelerated recovery of generation assets. Operating expenses decreased from $541 million in 1998 to $479 million in 1999. The decrease was primarily due to the lower business-combination costs, as previously discussed
Other Income and Deductions, Interest Expense, and Income Taxes
Other Income and Deductions
Other income and deductions were $34 million, $38 million and $11 million in 2000, 1999, and 1998 respectively. The increase from 1998 to 1999 is primarily due to higher interest earned on a loan to Sempra Energy.
Interest Expense
Interest expense for 2000 decreased to $118 million from $120 million in 1999 primarily due to lower interest on long-term debt as a result of a lower average balance on the rate reduction bonds during 2000. Interest expense for 1999 increased to $120 million from $106 million in 1998 primarily due to interest of $28 million on the portion of the rate-reduction bond liability which was refundable to customers, partially offset by lower interest expense on long-term debt as a result of lower long-term debt balances during 1999. See additional discussion of rate reduction bonds in Note 4 of the notes to Consolidated Financial Statements.
Income Taxes
Income tax expense was $144 million, $126 million and $142 million for the years ended December 31, 2000, 1999 and 1998, respectively. The effective income tax rates were 48.8 percent, 38.8 percent and 42.6 percent for the same years. The increase in income tax expense for 2000 compared to 1999 was primarily due to lower charitable contributions (during 1999 SDG&E made a charitable contribution to the San Diego Unified Port District in connection with the sale of the South Bay generating plant), partially offset by lower income before income taxes. The decrease in income taxes for 1999 compared to 1998 was primarily due to the charitable contribution to the San Diego Unified Port District. 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 were initially lower, but became subject to fluctuation with the actual cost of electricity purchases. A number of factors, including supply/demand imbalances, resulted in abnormally high electric-commodity costs beginning in mid-2000 and continuing into 2001. During the second half of 2000, the average electric-commodity cost was 15.51 cents/kWh (compared to 4.15 cents/kWh in the second half of 1999). 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 may 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, which was retroactive to June 1, 2000, extends through December 31, 2002 (December 31, 2003 if deemed by the CPUC to be in the public interest). As a result of the ceiling, SDG&E is not able to pass through to its small-usage customers on a current basis the full purchase cost of electricity that it provides. 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. In the meantime, the amount paid for electricity in excess of the ceiling (the undercollected costs) is accumulated in an interest-bearing balancing account. The undercollection, included in Regulatory Assets on the Consolidated Balance Sheets, was $447 million at December 31, 2000 and $605 million at January 31, 2001, and is expected to increase to $700 million in March 2001, and remain constant thereafter, except for interest, if the DWR continues to purchase SDG&E's power requirements, as more fully described in "Results of Operations" herein. The rate ceiling has materially and adversely affected SDG&E's revenue collections and its related cash flows and liquidity. SDG&E has fully drawn upon substantially all of its short-term credit facilities. Its ability to access the capital markets and obtain additional financing has been substantially impaired by the financial distress being experienced by other California investor-owned utilities (IOUs) as well as by lender uncertainties concerning California utility regulation generally and the rapid growth of utility cost undercollections. Continued purchases by the DWR for resale to SDG&E's customers of substantially all of the electricity that would otherwise be purchased by SDG&E or dramatic decreases in wholesale electricity prices, favorable action by the CPUC on SDG&E's electric rate surcharge application and SDG&E access to the capital markets are required to manage and finance SDG&E's cost undercollections and provide adequate liquidity. Consequently, in January 2001, SDG&E filed an application with the CPUC requesting a temporary electric-rate surcharge of 2.3 cents/kWh, subject to refund, beginning March 1, 2001. The surcharge is intended to provide SDG&E with continued access to financing on commercially reasonable terms by managing the growth of SDG&E's undercollected power costs. The CPUC has deferred this proceeding, pending resolution of the broader issues related to the state-wide high costs. In response to the situation facing the California IOUs, the state of California passed legislation to permit its governor to negotiate with the IOUs to acquire their transmission assets. There is no assurance that these negotiations will result in a sale of the transmission assets. SDG&E has been having discussions with representatives of the governor concerning the possibility of such a transaction and what the terms might be. There is no assurance that these discussions will result in a sale of the transmission assets. SDG&E would consider entering into such a transaction only if the sales price and the conditions of the sale and of future operating arrangements are reasonable. See additional discussion in Note 12 of the notes to Consolidated Financial Statements.
Natural Gas Restructuring and Gas Rates
The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. In January 1998, the CPUC released a staff report initiating a proceeding to assess the current market and regulatory framework for California's natural gas industry. The general goals of the plan are to consider reforms to the current regulatory framework, emphasizing market-oriented policies benefiting California's natural gas consumers. A CPUC decision is expected in 2001. In October 1999, the state of California enacted a law that requires natural gas utilities to provide "bundled basic gas service" (including transmission, storage, distribution, purchasing, revenue- cycle services and after-meter services) to all core customers, unless the customer chooses to purchase gas from a nonutility provider. The law prohibits the CPUC from unbundling distribution- related gas services (including meter reading and billing) and after- meter services (including leak investigation, inspecting customer piping and appliances, pilot relighting and carbon monoxide investigation) for most customers. The objective is to preserve both customer safety and customer choice. Supply/demand imbalances have increased the price of natural gas in California more than in the rest of the country because of California's dependence on natural gas fired electric generation due to air-quality considerations. The average price of natural gas at the California/Arizona (CA/AZ) border was $6.25/mmbtu in 2000, compared with $2.33/mmbtu in 1999. On December 11, 2000, the average spot-market price at the CA/AZ border reached a record high of $56.91/mmbtu. Underlying the high natural gas prices are several factors, including the increase in natural gas usage for electric generation, colder winter weather and reduced natural gas supply resulting from historically low storage levels, lower gas production and a major pipeline rupture. In December 2000, SDG&E filed with the Federal Energy Regulatory Commission (FERC) for a reinstitution of price caps on short-term interstate capacity to the CA/AZ border and between the interstate pipelines and California's local distribution companies, effective until March 31, 2001. The FERC responded by issuing extensive data requests, but has not otherwise acted on the SDG&E request. A recent lawsuit, which seeks class-action certification, alleges that SDG&E, Sempra Energy, SoCalGas 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 cheaper natural gas supplies into California. SDG&E believes the allegations are without merit.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to move away from reasonableness reviews and potential disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for the Company. 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 by relying solely on expanding utility plant in a market where a utility already has a highly developed infrastructure. See additional discussion of PBR in "Results of Operations" above and in Note 12 of the notes to Consolidated Financial Statements.
Allowed Rate of Return
For 2001, the Company is authorized to earn a rate of return on rate base of 8.75 percent and a rate of return on common equity of 10.6 percent, compared to 9.35 percent and 11.6 percent, respectively, prior to July 1, 1999. 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 incentive mechanisms. In addition, earnings are affected by changes in sales volumes.
Management Control of Expenses and Capital Expenditures
In the past, management has been able to control operating expenses and investment within the amounts authorized to be collected in rates. However, that effort is now increasing. Due to the ever- increasing financial pressures experienced by SDG&E in the current electric industry environment, in January 2001 the Company launched a cash-conservation plan, which includes sales of nonessential property, containment of new hiring, reduction of outside contractors, and deferral of information system and construction projects that do not affect the core reliability of service to customers. While the Company is not planning employee layoffs at this time, all expenses and activities not directly tied to the maintenance of essential services and safety will continue to be scrutinized and deferred if possible.
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. The Company's capital costs to comply with environmental requirements are generally recovered through the depreciation components of customer rates. The Company's customers generally are responsible for 90 percent of the non-capital costs associated with hazardous substances and the normal operating costs associated with safeguarding air and water quality, disposing properly of solid waste, and protecting endangered species and other wildlife. Therefore, the likelihood of the Company's financial position or results of operations being adversely affected in a significant manner is 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 (all three sites completed as of December 31, 2000 and site-closure letters received for two), asbestos and other 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 (investigation and remediations are continuing), and mitigation of damage to the marine environment caused by the cooling-water discharge from the San Onofre Nuclear Generating Station (the requirements for enhanced fish protection, a 150-acre artificial reef and restorations on 150 acres of coastal wetlands are in process).
Market Risk The Company's policy is to use derivative financial instruments to reduce its exposure to fluctuations in interest rates, foreign- currency exchange rates and energy prices. Transactions involving these financial instruments are with credit-worthy firms and major exchanges. The use of these instruments exposes the Company to market and credit risks which, at times, may be concentrated with certain counterparties. The Company periodically enters into interest-rate swap and cap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. These swap and cap agreements generally remain off the balance sheet as they involve the exchange of fixed-rate and variable-rate interest payments without the exchange of the underlying principal amounts. The related gains or losses are reflected in the income statement as part of interest expense. The Company would be exposed to interest-rate fluctuations on the underlying debt should other parties to the agreement not perform. Such nonperformance is not anticipated. See the "Interest- Rate Risk" section below for additional information regarding the Company's use of interest-rate swap and cap agreements. 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, with maturities ranging from 30 days to 12 months. In the case of price-risk management, the use of derivative financial instruments by the Company is subject to certain limitations imposed by Sempra Energy's risk management policies and regulatory requirements. The counterparties with whom the Company enters into derivative transactions must also meet corporate credit standards. See Note 9 of the notes to Consolidated Financial Statements and the "Market Risk Management Activities" section below for further information regarding the use of energy derivatives by the Company.
Market-Risk Management Activities
Market risk is the risk of erosion of the Company's cash flows, net income and asset values due to adverse changes in interest and foreign-currency rates, and in prices for equity and energy. Sempra Energy has adopted corporate-wide policies governing its market-risk management activities. An Energy Risk Management Oversight Committee, consisting of senior officers, oversees company-wide energy-price risk-management and trading activities to ensure compliance with Sempra Energy's stated energy risk management and trading policies. In addition, all affiliates have groups that monitor and control 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 level. The Company has adopted the variance/covariance methodology in its calculation of VaR, and uses a 95 percent confidence level. Holding periods are specific to the types of positions being measured, and are determined based on the size of the position or portfolios, market liquidity, purpose and other factors. Historical volatilities and correlations between instruments and positions are used in the calculation. The following discussion of the Company's primary market-risk exposures as of December 31, 2000, includes a discussion of how these exposures are managed.
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 bond issues with fixed interest rates. With the restructuring of the regulatory process, greater flexibility has been permitted 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 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, 2000, the notional amount of interest-rate swap transactions totaled $45 million. See Note 9 of the notes to Consolidated Financial Statements for further information regarding this swap transaction. The VaR on the Company's fixed-rate long-term debt is estimated at approximately $114 million as of December 31, 2000, assuming a one-year holding period.
Energy-Price Risk
Market risk related to physical commodities is based upon potential fluctuations in natural gas and electricity prices and basis. 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, operating and regulatory environment.
Market Risk
SDG&E may, at times, be exposed to limited market risk in its natural gas purchase, sale and storage activities as a result of activities under its gas PBR. SDG&E manages this risk within the parameters of the Company's market-risk management and trading framework. As of December 31, 2000, the total VaR of SDG&E's natural gas positions was not material. 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 condition (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. Almost all of the Company's accounts receivable are with customers located in California and, therefore, potentially affected by the high costs of electricity and natural gas in California, as described in "Factors Influencing Future Performance" and in Note 12 of the notes to Consolidated Financial Statements.
New Accounting Standards Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards (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 exposures. 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 as of January 1, 2001, in the Consolidated Balance Sheet as fixed-priced contracts and other derivatives. Due to the regulatory environment in which SDG&E 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 as of January 1, 2001, in the Consolidated Balance Sheet. The ongoing effects will depend on future market conditions and the Company's hedging activities. In December 1999, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB) 101 - Revenue Recognition. SABs are not rules issued by the SEC. Rather, they represent interpretations and practices followed by the SEC's staff in administering the disclosure requirements of the federal securities laws. SAB 101 provides guidance on the recognition, presentation and disclosure of revenue in financial statements; it does not change the existing rules on revenue recognition. SAB 101 sets forth the basic criteria that must be met before revenue should be recorded. Implementation of SAB 101 was required by the fourth quarter of 2000 and had no effect on the Company's consolidated financial statements. Information Regarding Forward-Looking Statements This Annual Report contains statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, including statements regarding SDG&E's ability to finance undercollected costs on reasonable terms and retain its financial strength, estimates of future accumulated undercollected costs, and its plans to obtain future financing. The words "estimates," "believes," "expects," "anticipates," "plans," "intends," "may," "would" and "should" or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward-looking statements. Forward-looking statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, including, among others, local, regional, national and international economic, competitive, political, legislative and regulatory conditions; actions by the CPUC, the California Legislature, the DWR and the FERC; the financial condition of other investor-owned utilities; inflation rates and interest rates; energy markets, including the timing and extent of changes in commodity prices; weather conditions; business, regulatory and legal decisions; the pace of deregulation of retail natural gas and electricity delivery; the timing and success of business-development efforts; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the Company. Readers are cautioned not to rely unduly on any forward-looking statements and are urged to review and consider carefully the risks, uncertainties and other factors which affect the Company's business described in this Annual Report and other reports filed by the Company from time to time with the SEC.
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 Management Activities."
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, 2000 and 1999, 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, 2000. 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, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
San Diego, California January 26, 2001(February 27,2001 as to Notes 3,4 and 12)
NOTE 1: BUSINESS COMBINATION
On June 26, 1998, Enova Corporation (Enova or Parent), the parent company of San Diego Gas & Electric (SDG&E or the Company), and Pacific Enterprises (PE), parent company of Southern California Gas Company (SoCalGas), combined into a new company named Sempra Energy. As a result of the combination, (i) each outstanding share of common stock of Enova was converted into one share of common stock of Sempra Energy, (ii) each outstanding share of common stock of PE was converted into 1.5038 shares of common stock of Sempra Energy and (iii) the preferred stock and preference stock of the combining companies and their subsidiaries remained outstanding.
NOTE 2: SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The Consolidated Financial Statements include the accounts of SDG&E and its sole subsidiary, SDG&E Funding LLC. The Company's policy is to consolidate subsidiaries that are more than 50 percent owned and controlled. All material intercompany accounts and transactions have been eliminated. As a subsidiary of Sempra Energy, the Company receives certain services therefrom. Although it is charged its allocable share of the cost of such services, that cost is less than if the Company had to provide those services itself.
Effects of Regulation
The accounting policies of SDG&E conform with generally accepted accounting principles for regulated enterprises and reflect the policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). SDG&E prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," under which a regulated utility records a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. Regulatory liabilities represent future reductions in rates for amounts due to customers. To the extent that portions of the utility operations were to be no longer subject to SFAS No. 71, or recovery was to be no longer probable as a result of changes in regulation or the utility's competitive position, the related regulatory assets and liabilities would be written off. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," affects utility plant and regulatory assets such that a loss must be recognized whenever a regulator excludes all or part of an asset's cost from rate base. The application of SFAS No. 121 continues to be evaluated in connection with industry restructuring. Information concerning regulatory assets and liabilities is described below in "Revenues and Regulatory Balancing Accounts" and industry restructuring is described in Note 12.
Revenues and Regulatory Balancing Accounts
Revenues from utility customers consist of deliveries to customers and the changes in regulatory balancing accounts. Prior to 1998, earnings fluctuations from changes in the costs of fuel oil, purchased energy and natural gas, and consumption levels for electricity and the majority of natural gas were eliminated by balancing accounts authorized by the CPUC. However, as a result of California's electric-restructuring law, previous overcollections recorded in SDG&E's applicable balancing accounts were applied to recovery of prior generation costs (as described in Note 12), and fluctuations in certain costs and consumption levels can now affect earnings from electric operations. In addition, fluctuations in certain costs and consumption levels can affect earnings from the Company's gas operations. Additional information on regulatory matters is included in Note 12.
Regulatory Assets
Regulatory assets include undercollected electric-commodity costs accumulated due to the temporary rate ceiling imposed in mid-2000. Regulatory assets also include unrecovered premiums on early retirement of debt, postretirement benefit costs, deferred income taxes recoverable in rates and other expenditures that the utilities expect to recover in future rates. See Note 12 for additional information on the rate ceiling, industry restructuring and other regulatory matters.
Inventories
Included in inventories at December 31, 2000, were $38 million of materials and supplies ($50 million in 1999), and $12 million of natural gas and fuel oil ($11 million in 1999). Materials and supplies are generally valued at the lower of average cost or market; fuel oil and natural gas are valued by the last-in first-out method.
Loan to Affiliate
SDG&E has a promissory note receivable from Sempra Energy. The note bears interest based on short-term commercial paper rates, and is due on demand. The note receivable was $19 million and $612 million at December 31, 2000 and 1999, respectively.
Utility Plant
This primarily represents the buildings, equipment and other facilities used by SDG&E to provide natural gas and electric utility service. The cost of utility plant includes labor, materials, contract services and related items, and an allowance for funds used during construction. The cost of retired depreciable utility plant, plus removal costs minus salvage value, is charged to accumulated depreciation. Information regarding electric industry restructuring and its effect on utility plant is included in Note 12. Utility plant balances by major functional categories at December 31, 2000, were: natural gas operations $0.9 billion, electric distribution $2.7 billion, electric transmission $0.8 billion, and other electric $0.4 billion. The corresponding amounts at December 31, 1999, were: natural gas operations $0.9 billion, electric distribution $2.5 billion, electric transmission $0.7 billion, and other electric $0.4 billion. Accumulated depreciation and decommissioning of natural gas and electric utility plant in service at December 31, 2000, were $0.5 billion and $2.0 billion, respectively, and at December 31, 1999, were $0.5 billion and $1.8 billion, respectively. Depreciation expense is based on the straight-line method over the useful lives of the assets or a shorter period prescribed by the CPUC. The provisions for depreciation as a percentage of average depreciable utility plant (by major functional categories) in 2000, 1999 and 1998, respectively were: natural gas operations 3.79, 3.83, 4.01, electric distribution 4.67, 4.69, 4.49, electric transmission 3.21, 3.50, 3.31, and other electric 8.33, 8.21, 6.29. See Note 12 for discussion of the sale of generation facilities and industry restructuring.
Allowance for Funds Used During Construction (AFUDC)
The allowance represents the cost of funds used to finance the construction of utility plant and is added to the cost of utility plant. AFUDC also increases income, partly as an offset to interest charges shown in the Statements of Consolidated Income, although it is not a current source of cash.
Nuclear-Decommissioning Liability
Deferred credits and other liabilities at December 31, 2000, and 1999, include $162 million and $165 million, respectively, of accumulated decommissioning costs associated with SDG&E's interest in San Onofre Nuclear Generating Station (SONGS) Unit 1, which was permanently shut down in 1992. Additional information on SONGS Unit 1 decommissioning costs is included in Note 5. The corresponding liability for Units 2 and 3 is included in accumulated depreciation and amortization.
Comprehensive Income
Comprehensive income includes all changes, except those resulting from investments by owners and distributions to owners, in the equity of a business enterprise from transactions and other events including, as applicable, minimum pension liability adjustments.
Use of Estimates in the Preparation of the Financial Statements
The preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the current year's presentation.
New Accounting Standards
Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards (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 exposures. 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 as of January 1, 2001, in the Consolidated Balance Sheet as fixed-priced contracts and other derivatives. Due to the regulatory environment in which SDG&E 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 as of January 1, 2001, in the Consolidated Balance Sheet. The ongoing effects will depend on future market conditions and the Company's hedging activities. In December 1999, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB) 101 - Revenue Recognition. SABs are not rules issued by the SEC. Rather, they represent interpretations and practices followed by the SEC's staff in administering the disclosure requirements of the federal securities laws. SAB 101 provides guidance on the recognition, presentation and disclosure of revenue in financial statements; it does not change the existing rules on revenue recognition. SAB 101 sets forth the basic criteria that must be met before revenue should be recorded. Implementation of SAB 101 was required by the fourth quarter of 2000 and had no effect on the Company's consolidated financial statements.
NOTE 3: SHORT-TERM BORROWINGS
At December 31, 2000, SDG&E had $285 million of bank lines available to support commercial paper and variable-rate long-term debt. The credit agreements expire at varying dates in mid-2001, but $200 million of the then outstanding borrowings may be extended, at SDG&E's option, to a term maturity of an additional year. Any debt under the lines would bear interest at various rates based on market rates and SDG&E's credit rating. SDG&E's bank lines of credit were unused at both December 31, 2000, and 1999. Between January 24 and February 5, 2001, SDG&E drew down $250 million on these credit facilities. NOTE 4: LONG-TERM DEBT
- ------------------------------------------------------------------- December 31, (Dollars in millions) 2000 1999 - ------------------------------------------------------------------- First-mortgage Bonds 7.625% June 15, 2002 $ 28 $ 28 6.800% June 1, 2015 14 14 5.900% June 1, 2018 68 68 5.900% September 1, 2018 93 93 6.100% September 1, 2018 40 40 6.400% September 1, 2018 43 43 6.100% September 1, 2019 35 35 Variable rates September 1, 2020 58 58 5.850% June 1, 2021 60 60 8.500% April 1, 2022 10 10 5.420% December 1, 2027 45 45 6.400% December 1, 2027 75 75 Variable rates December 1, 2027 45 105 9.625% April 15, 2020 - 10 ------------------------ 614 684 ------------------------ Unsecured Bonds 5.900% June 1, 2014 130 130 Variable rates July 1, 2021 39 39 Variable rates December 1, 2021 60 60 Variable rates March 1, 2023 25 25 ------------------------ 254 254 ------------------------ Rate-reduction bonds, various rates (payable annually through 2007) 461 526 Capital leases 19 21 ------------------------ Total 1,348 1,485 Less: Current portion of long-term debt 66 66 Unamortized debt discount - net 1 1 ------------------------ Total $1,281 $1,418 - -------------------------------------------------------------------
Excluding capital leases, which are described in Note 11, maturities of long-term debt, including rate-reduction bonds, are $66 million in 2001, $94 million in 2002, $66 million in 2003, $66 million in 2004, $66 million in 2005 and $971 million thereafter. Although holders of variable-rate bonds may elect to redeem them prior to scheduled maturity, for purposes of determining the maturities listed above, since redeemed bonds are remarketed and are backed by long-term lines of credit, it is assumed the bonds will be held to maturity. SDG&E has CPUC authorization to issue an additional $938 million in short-term or long-term debt (see discussion under "Recent Shelf Registration" below).
First-Mortgage Bonds
First-mortgage bonds are secured by a lien on substantially all of SDG&E's utility plant. SDG&E may issue additional first-mortgage bonds upon compliance with the provisions of their bond indentures, which permit, among other things, the issuance of an additional $1.6 billion of first-mortgage bonds as of December 31, 2000, subject to CPUC authorization (see discussion under "Recent Shelf Registration" below. During May 2000, by the Company called $10 million of first- mortgage bonds prior to scheduled maturity. During December 2000, $60 million of variable-rate first-mortgage bonds were put back by the holders and subsequently remarketed on February 1, 2001 at 7.0 percent fixed interest rate.
Callable Bonds
At SDG&E's option, certain first-mortgage bonds may be called at a premium. SDG&E has $227 million of variable-rate bonds that are callable at various dates in 2001. Of the Company's remaining callable bonds, $45 are callable in year 2001, $204 million are callable in 2002 and $221 million in 2003.
Rate-Reduction Bonds
In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26 percent. These bonds were issued to facilitate the 10-percent rate reduction mandated by California's electric-restructuring law. See Note 12 for additional information. These bonds are being repaid over 10 years by SDG&E's residential and small commercial customers via a charge on their electricity bills. These bonds are secured by the revenue streams collected from customers and are not secured by, or payable from, utility assets. The sizes of the rate-reduction bond issuances were set so as to make the IOUs neutral as to the 10-percent rate reduction, and were based on a four-year period to recover stranded costs. Because SDG&E recovered its stranded costs in only 18 months (due to the greater- than-anticipated plant-sale proceeds), the bond sale proceeds were greater than needed. Accordingly, during the third quarter of 2000, SDG&E returned to its customers, via a combination of cash refunds and billing credits, $388 million of surplus bond proceeds in accordance with a June 8, 2000 CPUC decision. The bonds and their repayment schedule are not affected by this refund.
Unsecured Debt
Various long-term obligations totaling $254 million are unsecured. Unsecured bonds totaling $124 million have variable-interest-rate provisions.
Recent Shelf Registration
In December 2000, SDG&E filed a shelf registration for the public offering of up to $800 million of debt securities and requested CPUC authorization to incur additional indebtedness. On February 8, 2001, the CPUC approved SDG&E's financing application, but denied SDG&E authority to issue first-mortgage bonds beyond the $138 million previously authorized. SDG&E has requested a rehearing of this denial. Any securities under this shelf registration are offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933. At December 31, 2000, no debt securities were issued under this registration statement.
Interest Rate Swaps SDG&E periodically enters into interest-rate swap and cap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing. At December 31, 2000, SDG&E had such an agreement, maturing in 2002, with underlying debt of $45 million.
NOTE 5: FACILITIES UNDER JOINT OWNERSHIP
SONGS and the Southwest Powerlink transmission line are owned jointly with other utilities. The Company's interests at December 31, 2000, are:
- ------------------------------------------------------------------- (Dollars in millions) Southwest Project SONGS Powerlink - ------------------------------------------------------------------- Percentage ownership 20 88 Utility plant in service $ 63 $217 Accumulated depreciation and amortization $ 32 $119 Construction work in progress $ 5 $ 2 - -------------------------------------------------------------------
The Company's share of operating expenses is included in the Statements of Consolidated Income. Participants in each project must provide their own financing. The amounts specified above for SONGS include nuclear production, transmission and other facilities. Certain substation equipment at SONGS is wholly owned by the Company.
SONGS Decommissioning
Objectives, work scope and procedures for the future dismantling and decontamination of the SONGS units must meet the requirements of the Nuclear Regulatory Commission, the Environmental Protection Agency, the CPUC and other regulatory bodies. The Company's share of decommissioning costs for the SONGS units is estimated to be $449 million in current dollars, based on a cost study completed in 1998. Cost studies are updated every three years and approved by the CPUC. Rate recovery of decommissioning costs is allowed until the time that the costs are fully recovered. The amount accrued each year, which is currently being collected in rates, is based on the amount allowed by regulators. This amount is considered sufficient to cover the Company's share of future decommissioning costs. Payments to the nuclear decommissioning trusts are expected to continue until SONGS is fully decommissioned, which is not expected to occur before 2022, or until sufficient funds have been collected. Unit 1 was permanently shut down in 1992, and physical decommissioning began in January 2000. Several structures have been dismantled, and preparations have been made for major work to be performed in 2001 and beyond. That work will include dismantling, removal and disposal of all Unit 1 equipment and facilities, (both nuclear and non-nuclear components), decontamination of the site and construction of an on-site storage facility for Unit 1 spent fuel. These activities are expected to be completed by 2008. The amounts collected in rates are invested in externally managed trust funds. The securities held by the trust are considered available for sale and the trust is shown on the Consolidated Balance Sheets at market value. These values reflect unrealized gains of $158 million and $164 million at December 31, 2000, and 1999, respectively. The Financial Accounting Standards Board (FASB) is reviewing the accounting for liabilities related to closure and removal of long- lived assets, such as nuclear power plants, including the recognition, measurement and classification of such costs. The FASB could require, among other things, that the Company's future balance sheets include a liability for the estimated decommissioning costs, and a related increase in the carrying value of the asset. Additional information regarding SONGS is included in Notes 11 and 12.
NOTE 6: INCOME TAXES
The reconciliation of the statutory federal income tax rate to the effective income tax rate is as follows: - ------------------------------------------------------------- 2000 1999 1998 - ------------------------------------------------------------- Statutory federal income tax rate 35.0% 35.0% 35.0% Depreciation 6.6 5.2 1.3 State income taxes - net of federal income tax benefit 8.5 5.9 5.6 Tax credits (1.5) (2.1) (1.7) Charitable contribution of plant - (7.9) - Other - net 0.2 2.7 2.4 --------------------------- Effective income tax rate 48.8% 38.8% 42.6% - -------------------------------------------------------------
The components of income tax expense are as follows: - ------------------------------------------------------------- (Dollars in millions) 2000 1999 1998 - ------------------------------------------------------------- Current Federal $ (115) $ 90 $ 150 State (41) 39 41 --------------------------- Total current taxes (156) 129 191 --------------------------- Deferred Federal 244 11 (30) State 59 (9) (16) --------------------------- Total deferred taxes 303 2 (46) --------------------------- Deferred investment tax credits - net (3) (5) (3) --------------------------- Total income tax expense $ 144 $ 126 $ 142 - ------------------------------------------------------------- Federal and state income taxes are allocated between operating income and other income.
Accumulated deferred income taxes at December 31 result from the following: - ------------------------------------------------------------- (Dollars in millions) 2000 1999 - ------------------------------------------------------------- Deferred tax liabilities: Differences in financial and tax bases of utility plant $ 341 $ 356 Regulatory balancing accounts 470 150 Loss on reacquired debt 24 30 Other 83 70 --------------------------- Total deferred tax liabilities 918 606 --------------------------- Deferred tax assets: Investment tax credits 33 35 Other 131 138 --------------------------- Total deferred tax assets 164 173 --------------------------- Net deferred income tax liability $ 754 $ 433 - -------------------------------------------------------------
The net liability is recorded on the Consolidated Balance Sheets at December 31, 2000 as follows: - ------------------------------------------------------------- (Dollars in millions) 2000 1999 - ------------------------------------------------------------- Current liability $ 252 $ 106 Noncurrent liability 502 327 - ------------------------------------------------------------- Total $ 754 $ 433 - -------------------------------------------------------------
NOTE 7: EMPLOYEE BENEFIT PLANS
The information presented below describes the plans of the Company. In connection with the PE/Enova business combination described in Note 1, numerous participants have been transferred from the Company's plans to plans of related entities.
In connection with voluntary separations related to the business combination, the Company recorded a $9 million special termination benefit in 1998. During 2000, the Company participated in another voluntary separation program. As a result, the Company recorded a $5 million special termination benefit in 2000.
Pension and Other Postretirement Benefits
The Company sponsors qualified and nonqualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two years, and a statement of the funded status as of each year end:
- ------------------------------------------------------------------------------- Other Pension Benefits Postretirement Benefits ----------------------------------------------- (Dollars in millions) 2000 1999 2000 1999 - ------------------------------------------------------------------------------- Weighted-Average Assumptions as of December 31: Discount rate 7.25%(1) 7.75% 7.75% 7.75% Expected return on plan assets 8.00% 8.00% 4.00% 4.00% Rate of compensation increase 5.00% 5.00% 5.00% 5.00% Cost trend of covered health care charges - - 7.50%(2) 7.75%(2)
Change in Benefit Obligation: Net benefit obligation at January 1 $ 476 $ 494 $ 45 $ 48 Service cost 10 11 1 1 Interest cost 36 34 3 3 Plan participants' contributions - - - 2 Actuarial (gain) loss 9 4 3 (4) Transfer of liability(3) - (15) - - Curtailments (1) - - - Special termination benefits 5 - - - Gross benefits paid (58) (52) (3) (5) ---------------------------------------------- Net benefit obligation at December 31 477 476 49 45 ---------------------------------------------- Change in Plan Assets: Fair value of plan assets at January 1 713 587 18 17 Actual return on plan assets (51) 178 3 - Employer contributions - - 4 4 Plan participants' contributions - - - 2 Gross benefits paid (58) (52) (3) (5) ---------------------------------------------- Fair value of plan assets at December 31 604 713 22 18 ---------------------------------------------- Funded status at December 31 127 237 (27) (27) Unrecognized net actuarial gain (182) (317) - (2) Unrecognized prior service cost 16 20 - - ---------------------------------------------- Net recorded liability at December 31 $ (39) $ (60) $ (27) $ (29) - -------------------------------------------------------------------------------- (1) Discount rate decreased from 7.75% to 7.25%, effective March 1, 2000. (2) Decreasing to ultimate trend of 6.50% in 2004. (3) To reflect transfer of plan liability to Sempra Energy.
The following table provides the amounts recognized on the Consolidated Balance Sheets at December 31: - ------------------------------------------------------------------------------- Other Pension Benefits Postretirement Benefits -------------------------------------------- (Dollars in millions) 2000 1999 2000 1999 - ------------------------------------------------------------------------------- Accrued benefit cost $(36) $(57) $(27) $(29) Accumulated other comprehensive income, pretax (3) (3) - - - ------------------------------------------------------------------------------- Net recorded liability $(39) $(60) $(27) $(29) - -------------------------------------------------------------------------------
The following table provides the components of net periodic benefit cost (income) for the plans: - ------------------------------------------------------------------------------ Other Pension Benefits Postretirement Benefits ----------------------------------------------- For the years ended December 31 2000 1999 1998 2000 1999 1998 (Dollars in millions) ----------------------------------------------- Service cost $ 10 $ 11 $ 19 $ 1 $ 1 $ 1 Interest cost 36 34 43 3 3 3 Expected return on assets (57) (47) (60) (1) - (1) Amortization of: Transition obligation - - - 2 2 2 Prior service cost 3 3 3 - - - Actuarial gain (17) (9) (11) - - - Special termination benefits 5 - 9 1 - - Regulatory adjustment - - - (2) - - ----------------------------------------------- Total net periodic benefit cost (income) $(20) $ (8) $ 3 $ 4 $ 6 $ 5 - ------------------------------------------------------------------------------
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 $ 2 $ (2) obligation - ------------------------------------------------------------------------
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 service. Employees may contribute, subject to plan provisions, from 1 percent to 15 percent of their regular earnings. Employer contributions, after one year of service, are used to purchase shares of Sempra Energy common stock. Employer contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees. The employees' contributions, at the direction of the employees, are primarily invested in Sempra Energy common stock, mutual funds or institutional trusts. During 2000, SDG&E's plan contribution was age-based for represented employees. Company contributions to the savings plan were $5 million in 2000, $4 million in 1999 and $5 million in 1998.
NOTE 8: STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans that align employee and shareholder objectives related to Sempra Energy's long-term growth. The long-term incentive stock compensation plan provides for aggregate awards of Sempra Energy non-qualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments or 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 $1 million and $2 million in 2000 and 1998, respectively. There were no expenses recorded in 1999.
NOTE 9: FINANCIAL INSTRUMENTS
Fair Value
The fair values of the Company's financial instruments (cash, temporary investments, notes receivable, dividends payable, short-term and long-term debt, customer deposits, and preferred stock) are not materially different from the carrying amounts, except for long-term debt and preferred stock. The carrying amounts and fair values of long-term debt were $1.3 billion and $1.4 billion, respectively, at December 31, 2000. The carrying amounts and fair values of long-term debt were both $1.5 billion at December 31, 1999. Included in long- term debt are SDG&E's rate-reduction bonds. The carrying amounts and fair values of the bonds were $461 million and $462 million, respectively, at December 31, 2000, and $526 million and $511 million, respectively, at December 31, 1999. The carrying amounts and fair values of preferred stock were $104 million and $89 million, respectively, at December 31, 2000, and $104 million and $97 million, respectively, at December 31, 1999. The fair values of the long-term debt and preferred stock were estimated based on quoted market prices for them or for similar issues.
Off-Balance-Sheet Financial Instruments
The Company's policy is to use derivative financial instruments to manage its exposure to fluctuations in interest rates, foreign- currency exchange rates and energy prices. Transactions involving these financial instruments expose the Company to market and credit risks which may at times be concentrated with certain counterparties, although counterparty nonperformance is not anticipated.
Swap Agreements
The Company periodically enters into interest-rate-swap and cap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. These agreements generally remain off the balance sheet as they involve the exchange of fixed-rate and variable-rate interest payments without the exchange of the underlying principal amounts. The related gains or losses are reflected in the Statements of Consolidated Income as part of interest expense. At December 31, 2000, and 1999, the Company had one interest- rate-swap agreement: a floating-to-fixed-rate swap associated with $45 million of variable-rate bonds maturing in 2002. SDG&E expects to hold this financial instrument to its maturity. This swap agreement has effectively fixed the interest rate on the underlying variable-rate debt at 5.4 percent. SDG&E would be exposed to interest-rate fluctuations on the underlying debt should the counterparty to the agreement not perform. Such nonperformance is not anticipated. This agreement, if terminated, would result in an obligation of $1.3 million at both December 31, 2000, and December 31, 1999. Additional information on this topic is included in Note 4.
Energy Derivatives
The Company uses energy derivatives for price-risk management purposes within certain limitations imposed by Company policies and regulatory requirements. Energy derivatives are used to mitigate risk and better manage costs. These instruments include forward contracts, swaps, options and other contracts which have maturities ranging from 30 days to 12 months. At December 31, 2000, and 1999, gains and/or losses from these activities were not material to SDG&E's financial statements.
NOTE 10: SHAREHOLDERS' EQUITY AND PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
- -------------------------------------------------------------------- Call December 31, (Dollars in millions, except call price) Price 2000 1999 - --------------------------------------------------------------------- COMMON EQUITY Common stock, without par value, authorized 255,000,000 shares, all outstanding shares are owned by Enova Corporation $ 857 $ 857 Retained earnings 205 460 Accumulated other comprehensive income (3) (3) --------------------- Total $1,059 $1,314 --------------------- PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION $20 par value, authorized 1,375,000 shares: 5% Series, 375,000 shares outstanding $ 24.00 $ 8 $ 8 4.50% Series, 300,000 shares outstanding $ 21.20 6 6 4.40% Series, 325,000 shares outstanding $ 21.00 7 7 4.60% Series, 373,770 shares outstanding $ 20.25 7 7 Without par value: $1.70 Series, 1,400,000 shares outstanding $ 25.85 35 35 $1.82 Series, 640,000 shares outstanding $ 26.00 16 16 --------------------- Total $79 $79 ---------------------- Total Shareholders' Equity $1,138 $1,393 ----------------------
- ----------------------------------------------------------------- Call December 31, (Dollars in millions except call price) Price 2000 1999 - -------------------------------------------------------------------- PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Without par value, $1.7625 Series, 1,000,000 shares outstanding $ 25.00 $25 $25 - --------------------------------------------------------------------
Dividend Restrictions
CPUC regulation of SDG&E's capital structure limits to $154 million the portion of the Company's December 31, 2000 retained earnings that is available for dividends. 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. 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.
NOTE 11: COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts 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. SDG&E recovers such fixed charges in rates. These contracts expire at various dates between 2007 and 2023. SDG&E had been involved in negotiations and litigation with four Canadian suppliers concerning contract terms and prices related to long-term natural gas supply contracts. In 1999, SDG&E settled with the last of the four suppliers, terminating the contract. SDG&E continues to purchase natural gas from one of the suppliers under terms of the settlement agreement. SDG&E purchases natural gas on a spot basis to fill its additional long-term pipeline capacity. SDG&E continues to use the long-term pipeline capacity in other ways as well, including the transport of replacement natural gas 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, SoCalGas provides SDG&E six billion cubic feet of natural gas storage capacity under an agreement expiring March 2002. At December 31, 2000, the future minimum payments under natural gas contracts were: - ----------------------------------------------------------------- Storage and (Dollars in millions) Transportation Natural Gas - ----------------------------------------------------------------- 2001 $ 14 $ 108 2002 11 34 2003 10 17 2004 12 - 2005 12 - Thereafter 150 - ---------------------------------- Total minimum payments $ 209 $ 159 - -----------------------------------------------------------------
Total payments under the contracts were $273 million in 2000, $220 million in 1999 and $324 million in 1998.
Purchased-Power Contracts
SDG&E buys electric power under several long-term contracts. The contracts expire on various dates between 2001 and 2025. Prior to the electric rate ceiling described in Note 14, the above-market cost of contracts was recovered from virtually all of 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, SDG&E no longer bid those contracts into the PX in compliance with a FERC order prohibiting sales to the PX. Since then those contracts have been used to serve customers. In late 2000, SDG&E entered into additional contracts to serve customers instead of buying all of its power from the PX. On January 17, 2001, The California Assembly passed a bill (AB1) to allow the California Department of Water Resources (DWR) to purchase power under long-term contracts for the benefit of California consumers. For additional discussion of this matter see Note 12. At December 31, 2000, the estimated future minimum payments under the long-term contracts were: - ----------------------------------------------------------------- (Dollars in millions) - ----------------------------------------------------------------- 2001 $ 320 2002 223 2003 211 2004 162 2005 164 Thereafter 2,295 ---------- Total minimum payments $3,375 - -----------------------------------------------------------------
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 $257 million in 2000, $251 million in 1999 and $293 million in 1998.
Leases
SDG&E has capital and operating leases on real and personal property expiring at various dates from 2001 to 2032. 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 options to extend, which are exercisable by SDG&E. SDG&E also has nuclear fuel and real property that are financed by long-term capital leases. Property, plant and equipment included $58 million at December 31, 2000, and $46 million at December 31, 1999 related to these leases. The associated accumulated amortization is $38 million and $24 million, respectively.
At December 31, 2000, the minimum rental commitments payable in future years under all noncancellable leases were: - ----------------------------------------------------------------- Operating Capitalized (Dollars in millions) Leases Leases - ----------------------------------------------------------------- 2001 $ 14 $20 2002 13 - 2003 11 - 2004 9 - 2005 8 - Thereafter 23 - ------------------------------ Total future rental commitment $ 78 20 Imputed interest (6%) (1) ----------- Net commitment $19 - -----------------------------------------------------------------
Rent expense totaled $32 million in 2000, $39 million in 1999 and $50 million in 1998.
Other Commitments and Contingencies
At December 31, 2000, commitments for capital expenditures were approximately $12 million.
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. The Company incurs significant costs to operate its facilities in compliance with these laws and regulations and these costs generally have been recovered in customer rates. In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum account allowing utilities to recover their hazardous waste costs, including those related to Superfund sites or similar sites requiring cleanup. Recovery of 90 percent of 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. Environmental liabilities that may arise are recorded when remedial efforts are probable and the costs can be estimated. The Company's capital expenditures to comply with environmental laws and regulations were $2 million in 2000, $160,000 in 1999 and $1 million in 1998. The increase in 2000 is due to the installation of emission-control equipment on the Company's Rainbow compressor facility. Compliance with these regulations over the next five years is not expected to be significant. The Company has been associated with various sites, which may require remediation under federal, state or local environmental laws. The Company is unable to determine fully the extent of its responsibility for remediation of these sites until assessments are completed. Furthermore, the number of others that also may be responsible, and their ability to share in the cost of the cleanup, is not known. 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, 2000 and site-closure letters received for two), asbestos and other 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 (investigation and remediations are continuing), and mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS (the requirements for enhanced fish protection, a 150-acre artificial reef and restorations on 150 acres of coastal wetlands are in process). As discussed in Note 12, restructuring of the California electric utility industry has changed the way utility rates are set and costs are recovered. In 1998, the CPUC modified the Hazardous Waste Collaborative mechanism by providing that electric-generation-related cleanup costs be included in transition-cost recovery. The effect of this decision is that the Company's costs of compliance with environmental regulations may not be fully recoverable.
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 $4 million.
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
A recent lawsuit, which seeks class-action certification, alleges 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 cheaper natural gas supplies into California. The Company believes the allegations are without merit. Except for the matters 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 their businesses. Management believes that these matters will not have a material adverse effect on the Company's results of operations, financial condition or liquidity.
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, 2000, the aggregate unexpended amount of this commitment was approximately $100 million. Capital expenditures for underground conversions were $26 million in 2000, $20 million in 1999 and $17 million in 1998.
Concentration of Credit Risk
SDG&E maintains credit policies and systems to minimize overall credit risk. These policies include, when applicable, the use of 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 SDG&E's service territory, which covers all of San Diego County and an adjacent portion of Orange County. Supply/demand imbalances have caused a significant increase in the price of electricity and, although there is currently a temporary ceiling on the cost of electricity that SDG&E may pass on to its customers, 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: REGULATORY MATTERS
Electric Industry Restructuring
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 California Power Exchange (PX). The PX served as a wholesale power pool to which the California investor-owned utilities (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. 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. Certain costs such as those related to purchased-power contracts (including those with qualifying facilities) may be recovered beyond December 31, 2001. The rate freeze was to end as to each utility 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 will 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 the 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. A number of factors, including supply/demand imbalances, resulted in abnormally high electric-commodity 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. During the second half of 2000, the average electric-commodity cost was 15.51 cents/kWh (compared to 4.15 cents/kWh in the second half of 1999). In December 2000, the average was 17.91 cents/kWh (compared to 3.73 cents/kWh in December 1999). 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 the prior year. This resulted in legislative and regulatory responses. California Assembly Bill 265 (AB 265), enacted in September 2000, imposes a ceiling of 6.5 cents/kWh on the cost of the electric- commodity that SDG&E may 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. This is a "floating cap" that can float downward as prices decrease, but cannot exceed actual commodity costs without the permission of the CPUC. 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 legislation also provides for the future recovery of undercollections (the cost of electricity purchased by SDG&E that cannot be passed on to customers on a current basis) resulting from the reasonable and prudent costs of procuring the commodity. In accordance with AB 265, the CPUC is examining the prudence and reasonableness of SDG&E's procurement of wholesale energy on behalf of its customers for the period July 1999 through August 2000. A decision is expected in the third quarter of 2001. Based upon historical experience with the CPUC, SDG&E recorded a $50 million pretax charge during the third quarter of 2000 related to the recent legislative and regulatory actions associated with power acquisition costs. SDG&E accumulates the amount that it pays for electricity in excess of the rate ceiling (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 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 at December 31, 2000 and $605 million at January 31, 2001. The rate ceiling materially and adversely affects the timing of SDG&E's revenue collections and related cash flows. The rate at which the undercollected costs accumulate will depend primarily upon the effects of the recently enacted AB 1 discussed under "Purchased-Power Contracts" in Note 11 and below under "Recent State of California Actions," and other legislative and regulatory developments, wholesale prices for electric power and, to a lesser extent, variations in the volume of electricity used by SDG&E's customers (which is significantly affected by seasonal and other temperature variations) and the availability, price and use of longer-term fixed-price purchase contracts. Because of these and many other factors, the amount of undercollected costs that will accumulate in future periods cannot be estimated with any reasonable certainty. However, as discussed below under "Recent State of California Actions," AB 1 could end material growth in SDG&E's cost undercollections. The rate ceiling has materially and adversely affected SDG&E's revenue collections and its related cash flows and liquidity. SDG&E has fully drawn upon substantially all of its short-term credit facilities. Its ability to access the capital markets and obtain additional financing has been substantially impaired by the financial distress being experienced by other California IOUs as well as by lender uncertainties concerning California utility regulation generally and the rapid growth of utility cost undercollections. On January 24, 2001, SDG&E filed an application with the CPUC requesting a temporary 2.3 cents/kWh electric rate surcharge, subject to refund, beginning March 1, 2001. The surcharge is intended to provide SDG&E with continued access to financing on commercially reasonable terms by managing the growth of SDG&E's undercollected power costs and to provide for the amortization of the undercollections in customer rates. SDG&E's application also renews a previous request that the CPUC freeze the commodity rate SDG&E can charge its customers at 6.5 cents/kWh instead of using that rate as a ceiling. SDG&E is unable to predict the amount, if any, of the request that the CPUC would grant, or when it would issue a decision. The CPUC has deferred this proceeding pending resolution of the broader issues related to the state-wide high costs.
FERC Actions On November 1, 2000, the FERC reported its findings from its formal investigation of the electric rates and structure of the ISO/PX, as well as of market-based sellers in the California market. The investigation found no specific abuse of market power by individual generators and determined that constraints within the market structure, such as hedging restrictions imposed by the CPUC, and a long-term shortage of power in the state, resulted in the high electric commodity prices. Federal regulators proposed several remedies to fix California's flawed market, but stated that past profits from generators and traders could not be ordered refunded to customers. The FERC did state that the high short-term energy rates during the summer of 2000 were "unjust and unreasonable" and left the door open to future customer refunds should specific instances of market abuses be uncovered. The report proposed various remedies and on December 15, 2000, the FERC issued an order adopting these remedies. Among other things, the order allows the California IOUs to buy and sell power outside the PX to afford the IOUs more favorable pricing, to replace the ISO/PX stakeholder governing boards with independent boards, and to require market buyers to schedule 95 percent of their transactions in the day-ahead markets to reduce the over-reliance on the real-time market to meet supply. The order fails to require sellers to enter into forward contracts at reasonable prices, fails to provide an effective price cap and does not address issues associated with retroactive refund and retroactive remedial authority issues. The IOUs have requested a rehearing, which is pending, of the FERC's decision based on insufficiency of remedies for the wholesale electric market situation. In connection with reaction to the FERC order, the PX suspended its trading operations on January 31, 2001.
PX/ISO Billings Although it has experienced substantial undercollections of its costs of purchasing electricity for its customers, SDG&E has nonetheless remained current in paying for its electricity purchases as well as its other payment obligations. However, on February 9, 2001, SDG&E received a "charge-back" billing of $29 million relating to a default by another California utility in paying for power purchased by the other utility from the ISO. SDG&E believes the charge-back is improper under applicable tariffs. SDG&E and other recipients of the charge-back billings have obtained an order preventing their collection pending the outcome of litigation contesting the charges. SDG&E may receive additional charge-back billings in respect to defaults in electricity purchase payments by other California IOUs in paying for electricity purchased from the ISO and the PX. It also expects that it may receive billings for its own purchases of electricity from the PX that do not reflect proper compliance by the PX with wholesale price caps ordered by the FERC. These billings are expected to cease in March 2001, since SDG&E is no longer selling electricity to the PX. SDG&E will contest all such billings to the extent that it believes they are inconsistent with applicable tariffs and orders.
Recent State of California Actions Federal and California officials met with power generators, marketers and utility representatives several times in January 2001 to try to end California's power crisis. The parties conceptually agreed that, among other things, the state of California would buy electricity through long-term contracts at reduced rates, which it would resell to consumers. In order to implement these plans, the California Legislature passed AB 1, signed by the governor on February 1, 2001, to allow the DWR to purchase power via long-term contracts for resale to consumers. The bill authorizes the DWR to enter into long-term contracts of up to 10 years to purchase power and to sell it to consumers at not more than the acquisition costs. This authority ends on December 31, 2002. Repayment will come from utility customers' monthly bills. The bill also authorizes funds from the state's general fund for immediate power purchases and authorizes the DWR to issue up to $10 billion in revenue bonds to purchase power. Ratepayers will pay off these advances and bonds over time. The law also encourages energy conservation by prohibiting higher rates for customers that do not exceed 130 percent of a baseline allotment for energy consumption and setting penalties for businesses that don't reduce their outside lighting. The first state power auction was held in January 2001. In early February 2001, the DWR announced agreements on contracts totaling about 5,000 megawatts and ranging from three years to 10 years. The state is expected to purchase about one-third of the electricity used by the IOUs' customers. Also in early February 2001, the CPUC approved emergency regulations for delivery and payment mechanisms for the sale of electricity procured by the DWR. In an interim agreement between the DWR and SDG&E, effective February 7, 2001, the DWR is purchasing the entire portion of the power used by SDG&E customers that is not provided by SONGS or SDG&E's existing contracts. SDG&E believes that the DWR's purchase of all of SDG&E's power needs would end material growth in SDG&E's cost undercollections. To the extent that the DWR does not purchase all of SDG&E's power needs, SDG&E may be required to begin again making purchases and to purchase any shortfall at market prices for resale to its customers at SDG&E's rate ceiling (which remains unchanged by the legislation) with any related undercollections continuing to increase SDG&E's total undercollected costs. The California Legislature continues to remain in emergency session to address the California energy crisis. Various legislative and other proposals that would significantly affect the structure of California's electric industry, the rates that SDG&E and other IOUs may charge their customers and the ability of the utilities to purchase electricity for their customers, and to finance and recover undercollected costs have been advanced. Among these proposals is that of the governor that would, among other things, have the state of California purchase the IOUs' transmission systems for amounts at least equal to their net book value to provide the IOUs with funds to mitigate the situation. SDG&E has been having discussions with representatives of the governor concerning the possibility of such a transaction and what the terms might be. There is no assurance that these discussions will result in a sale of the transmission assets. SDG&E would consider entering into such a transaction only if the sales price and conditions of the sale and of future operating arrangements are reasonable.
Credit Ratings Although the credit ratings of the Company have not changed, California regulatory uncertainties have led the major credit-rating agencies to change their rating outlooks on most of the Company's securities to negative.
Liquidity and Capital Resources The rate ceiling has materially and adversely affected SDG&E's revenue collections and its related cash flows and liquidity. SDG&E has fully drawn upon substantially all of its short-term credit facilities. Its ability to access the capital markets and obtain additional financing has been substantially impaired by the financial distress being experienced by other California IOUs as well as by lender uncertainties concerning California utility regulation generally and the rapid growth of utility cost undercollections. Continued purchases by the DWR for resale to SDG&E's customers of substantially all of the electricity that would otherwise be purchased by SDG&E or dramatic decreases in wholesale electricity prices, favorable action by the CPUC on SDG&E's electric-rate-surcharge application and SDG&E access to the capital markets are required to manage and finance SDG&E's cost undercollections and provide adequate liquidity.
Natural Gas Supply/demand imbalances are affecting the price of natural gas in California more than in the rest of the country because of California's dependence on natural gas fired electric generation due to air-quality considerations. The average price of natural gas at the California/Arizona (CA/AZ) border was $6.25/mmbtu in 2000, compared with $2.33/mmbtu in 1999. On December 11, 2000, the average spot cash gas price at the CA/AZ border reached a record high of $56.91/mmbtu. Underlying the high natural gas prices are several factors, including the increase in natural gas throughput for electric generation (a 40- percent increase in Southern California compared to 1999), colder winter weather and reduced natural gas supply resulting from historically low storage levels, lower natural gas production and a major pipeline rupture. In December 2000, SDG&E filed with the FERC for a reinstitution of price caps on short-term interstate capacity to the CA/AZ border and between the interstate pipelines and California's local distribution companies, effective until March 31, 2001. SDG&E requested that, if the price of natural gas sold into California exceeds 150 percent of the national average, the price should be capped at that level, plus FERC-imposed transportation costs. The FERC responded by issuing extensive data requests, but has not otherwise acted on the SDG&E request.
Restructuring of Electric Distribution Thus far, the CPUC's electric industry restructuring has been confined to generation. Transmission and distribution have remained subject to traditional cost-of-service regulation. However, the CPUC is exploring the possibility of opening up electric distribution to competition. A CPUC staff report on this issue was submitted to the CPUC in July 2000, with dissenting opinions recommending against changing electric distribution regulation at this time due to the current state of electric industry restructuring. A proposed decision is expected in mid-2001.
Gas Industry Restructuring
The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. 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. The general goals of the plan are to consider reforms to the current regulatory framework emphasizing market-oriented policies benefiting California's natural gas consumers. 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. In October 1999, the state of California enacted a law (AB 1421) which requires that natural gas utilities provide "bundled basic gas service" (including transmission, storage, distribution, purchasing, revenue-cycle services and after-meter services) to all core customers, unless the customer chooses to purchase natural gas from a nonutility provider. The law prohibits the CPUC from unbundling most distribution-related natural gas services (including meter reading) and after-meter services (including leak investigation, inspecting customer piping and appliances, pilot relighting and carbon monoxide investigation) for core customers. The objective is to preserve both customer safety and customer choice. Between late 1999 and April 2000, several conflicting settlement proposals were filed by various groups of parties that addressed the changes the CPUC found promising in July 1999. The issues in dispute included, among other things, recovery of the utilities' costs to implement whatever regulatory changes are adopted. Additional proposals included improving the access of energy service providers to sell natural gas supply to core customers of SDG&E. Hearings were held in mid-2000 and a Proposed Decision (PD) was released in November 2000. The PD recommends some, but not all, of the changes proposed by SDG&E. If adopted, the PD is not expected to have a negative earnings impact on the SDG&E. A CPUC decision is expected in 2001.
Performance-Based Regulation (PBR)
In recent years, the CPUC has directed utilities to use PBR. To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, PBR has replaced the general rate case and certain other regulatory proceedings for SDG&E. Under PBR, regulators generally require future income potential to be tied to achieving or exceeding specific performance and productivity measures, 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. The Company's PBR mechanism is in effect through December 31, 2002, at which time the mechanism will be updated. That update will include, among other things, a reexamination of the Company's reasonable costs of operation in 2003 to be allowed in rates. Key elements of the current mechanism include an annual indexing mechanism that adjusts customer 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. A rate change is triggered by a six-month trailing average and a 100-basis-point change in interest rates. If this occurs, 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.
Biennial Cost Allocation Proceeding
On April 20, 2000, the CPUC issued a decision on the Company's 1999 BCAP, adopting an overall decrease in natural gas revenues of $37 million for transportation rates effective June 1, 2000. Since the decrease reflects anticipated changes in corresponding costs, it has no effect on net income.
Cost of Capital
Electric industry restructuring has changed the method of calculating the Company's annual 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 for 2000 and 2001. The electric-transmission cost of capital is determined under a separate FERC proceeding. SDG&E is required by its last cost of capital proceeding to file an application on or before May 8, 2001, proposing revisions to its authorized ROE, ROR and capital structure, to be in effect for 2002. The application will, among other things, consider the recent and ongoing financial impacts on SDG&E of electric industry restructuring.
Integration of Core Gas Purchase Functions
On January 11, 2001, SoCalGas and SDG&E filed an application with the CPUC to integrate their natural gas purchasing departments. The filing calls for a single natural gas acquisition group to purchase natural gas for the two utilities' core gas customers by using their pooled gas portfolio assets. These assets include storage, interstate capacity and natural gas supply contracts. The two utilities would charge their core customers the same natural gas commodity rate from the diversified portfolio. The change would bring increased efficiency to the utilities' core gas purchase functions. The filing requests that this change be effective November 1, 2001. A CPUC decision is not expected until October 2001.
NOTE 13: SEGMENT INFORMATION
The Company previously had three separately managed reportable segments: electric transmission and distribution, electric generation, and natural gas service. Effective with the sale of its fossil fuel generation facilities in 1999 and other organizational changes, the Company no longer operates in multiple business segments.
NOTE 14: QUARTERLY FINANCIAL DATA (UNAUDITED)
The sum of the quarterly amounts does not necessarily equal the annual total due to rounding. Reclassifications have been made to certain of the amounts since they were presented in the Quarterly Reports on Form 10-Q.
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 2001 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 51 Chairman
Debra L. Reed 44 President and Chief Financial Officer
Gary D. Cotton 60 Senior Vice President
Steven D. Davis 44 Vice President and Corporate Secretary
Pamela J. Fair 42 Vice President
* As of December 31, 2000.
Except for Mr. Davis, each Executive Officer has been an officer of SDG&E or one of its affiliates for more than five years.
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 2001 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 2001 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 . . . . . . . . . . . . . . 34
Statements of Consolidated Income for the years ended December 31, 2000, 1999 and 1998 . . . . . . . . 35
Consolidated Balance Sheets at December 31, 2000 and 1999. . . . . . . . . . . . . . . . . . . . . 36
Statements of Consolidated Cash Flows for the years ended December 31, 2000, 1999 and 1998 . . . . . 38
Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 2000, 1999 and 1998 . . . . . . . . . . . 40
Notes to Consolidated Financial Statements . . . . . . . 41
2. Financial statement schedules The following documents may be found in this report at the indicated page numbers:
Independent Auditors' Consent. . . . . . . . . . . . . . 68
Other schedules for which provision is made in Regulation S-X are not required under the instructions contained therein or are inapplicable.
3. Exhibits See Exhibit Index on page 70 of this report.
(b) Reports on Form 8-K The following reports on Form 8-K were filed after September 30, 2000:
Current Report on Form 8-K filed December 5, 2000, announcing distribution of a Preliminary Prospectus Supplement related to the offering of $300 million of notes by Sempra Energy and including an exhibit entitled "Recent Developments," excerpted from the preliminary prospectus, related to California electric industry restructuring.
Current Report on Form 8-K filed January 24, 2001, announcing SDG&E's application to the CPUC for authority to implement an electric rate surcharge, which would increase the rates it may charge its electric customers.
Current Report on Form 8-K filed February 16, 2001, reporting a discussion of recent developments affecting SDG&E contained in supplemental information distributed in connection with the remarketing from short term to long term of certain unsecured, variable-rate SDG&E bonds. INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Numbers 33-45599, 33-52834, 333-52150 and 33-49837 of San Diego Gas and Electric Company on Forms S-3 of our report dated January 26, 2001 (February 9, 2001 as to Notes 3 and 12) for the year ended December 31, 2000.
/S/ DELOITTE & TOUCHE LLP
San Diego, California March 9, 2001
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/ Debra L. Reed ---------------------------------. Debra L. Reed President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated.
Name/Title Signature Date
Principal Executive Officer: Debra L. Reed President, Chief Financial Officer /s/ Debra L. Reed March 6, 2001 --------------------- Principal Financial Officer: Debra L. Reed President, Chief Financial Officer /s/ Debra L. Reed March 6,2001 --------------------- Principal Accounting Officer: Debra L. Reed President, Chief Financial Officer /s/ Debra L. Reed March 6,2001 --------------------- Directors: Edwin A. Guiles Chairman /s/ Edwin A. Guiles March 6,2001 ----------------------
Hyla H. Bertea, Director /s/ Hyla H. Bertea March 6,2001 ---------------------- Ann L. Burr, Director /s/ Ann L. Burr March 6,2001 ---------------------- Herbert L. Carter, Director /s/ Herbert L. Carter March 6,2001 ---------------------- Richard A. Collato, Director /s/ Richard A. Collator March 6,2001 ----------------------- Daniel W. Derbes, Director /s/ Daniel W. Derbes March 6,2001 ---------------------- Wilford D. Godbold, Jr., Director /s/ Wilford D. Godbold, Jr. March 6,2001 ---------------------- William D. Jones, Director /s/ William D. Jones March 6,2001 ---------------------- Ralph R. Ocampo, Director /s/ Ralph R. Ocampo March 6,2001 ---------------------- William G. Ouchi, Director /s/ William G. Ouchi March 6,2001 ---------------------- Richard J. Stegemeier, Director /s/ Richard J. Stegemeier March 6,2001 ---------------------- Thomas C. Stickel, Director /s/ Thomas C. Stickel March 6,2001 ---------------------- Diana L. Walker, Director /s/ Diana L. Walker March 6,2001 ----------------------
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 September 1, 1998. (SDG&E 1998 Form 10-K Exhibit 3.01) 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 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.)
10.02 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 10.03 Sempra Energy Deferred Compensation and Excess Savings Plan effective January 1, 2000 (2000 Sempra Energy Form 10-K Exhibit 10.07).
10.04 Sempra Energy Supplemental Executive Retirement Plan as amended and restated effective July 1, 1998 (1998 Sempra Energy Form 10-K Exhibit 10.09).
10.05 Sempra Energy Executive Incentive Plan effective June 1, 1998 (1998 Sempra Energy Form 10-K Exhibit 10.11).
10.06 Sempra Energy Executive Deferred Compensation Agreement Effective June 1, 1998(1998 Sempra Energy Form 10-K Exhibit 10.12).
10.07 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)).
10.08 Supplemental Executive Retirement Plan restated as of July 1, 1994 (1994 SDG&E Form 10-K Exhibit 10.14).
Financing 10.09 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).
10.10 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).
10.11 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).
10.12 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).
10.13 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).
10.14 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).
10.15 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).
10.16 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).
10.17 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).
10.18 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).
10.19 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 10.20 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).
10.21 Fuel Lease dated as of September 8, 1983 between SONGS Fuel Company, as Lessor and San Diego Gas & Electric Company, as Lessee, and Amendment No. 1 to Fuel Lease, dated September 14, 1984 and Amendment No. 2 to Fuel Lease, dated March 2, 1987 (1992 SDG&E Form 10-K Exhibit 10.11).
10.22 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).
10.23 Amendment No. 1 to the Qualified CPUC Decommissioning Master Trust Agreement dated September 22, 1994 (see Exhibit 10.21 herein)(1994 SDG&E Form 10-K Exhibit 10.56).
10.24 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 10.22 herein)(1994 SDG&E Form 10-K Exhibit 10.57).
10.25 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 10.22 herein)(1996 Form 10-K Exhibit 10.59).
10.26 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 10.22 herein)(1996 Form 10-K Exhibit 10.60).
10.27 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 10.22 herein)(1999 Form 10-K Exhibit 10.26).
10.28 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 10.22 herein)(1999 Form 10-K Exhibit 10.27).
10.29 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).
10.30 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 10.29 herein)(1996 Form 10-K Exhibit 10.62).
10.31 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 10.29 herein)(1996 Form 10-K Exhibit 10.63).
10.32 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 10.29 herein)(1999 Form 10-K Exhibit 10.31).
10.33 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 10.29 herein)(1999 Form 10-K Exhibit 10.32).
10.34 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).
10.35 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 10.36 Master Services Contract, Schedule J, Transaction Based Storage Service Agreement dated April 1, 2000 and expiring March 31, 2001 between San Diego Gas & Electric Company and Southern California Gas Company. (1999 10-K Exhibit 10.35)
10.37 Master Services Contract, Schedule J, Transaction Based Storage Service Agreement dated April 1, 1999 and expiring March 31, 2000 between San Diego Gas & Electric Company and Southern California Gas Company. (1998 10-K Exhibit 10.61)
10. 38 Master Services Contract (Intrastate Transmission Service ), dated July 1, 1998 and expiring July 1, 2000 between San Diego Gas & Electric Company and Southern California Gas Company. (1998 10-K Exhibit 10.64) 10.39 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).
10.40 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).
10.41 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 10.42 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, 2000, 1999, 1998, 1997 and 1996.
Exhibit 21 - Subsidiaries
21.01 Schedule of Subsidiaries at December 31, 2000.
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 265 California Assembly Bill imposing a 6.5 cent/kWh electric commodity rate ceiling.
AB 1890 California Assembly Bill - California's electric restructuring law.
AB 1421 A California Assembly bill requiring that natural gas utilities provide bundled basic gas service to certain customers.
AFUDC Allowance for Funds Used During Construction
BCAP Biennial Cost Allocation Proceeding
Bcf Billion Cubic Feet (of natural gas)
CA/AZ California/Arizona
CEC California Energy Commission
CPUC California Public Utilities Commission
DOE Department of Energy
DTSC Department of Toxic Substances Control
DWR California Department of Water Resources
Edison Southern California Edison Company
EMF Electric and Magnetic Fields
Enova Enova Corporation, the Company's parent
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Intertie Pacific Intertie
IOUs Investor-Owned Utilities
ISO California Independent System Operator
kWh Kilowatt Hour
mmbtu Million British Thermal Units (of natural gas)
mW Megawatt
NRC Nuclear Regulatory Commission
Parent Enova Corporation
PBR Performance-Based Regulation/Ratemaking
PD Proposed Decision
PE Pacific Enterprises, an affiliate of the Company
PG&E Pacific Gas and Electric Company
PGE Portland General Electric Company
PNM Public Service Company of New Mexico
PRP Potentially Responsible Party
PX California Power Exchange
SAB Staff Accounting Bulletin(SEC)
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
UEG Utility Electric Generation
VaR Value at Risk
WSPP Western Systems Power Pool