ITEM 1. BUSINESS AND RISK FACTORS
Description of Business
Pacific Enterprises (PE or the company) is an energy services company whose only significant subsidiary is Southern California Gas Company (SoCalGas), the nation's largest natural gas distribution utility. PE's common stock is wholly owned by Sempra Energy, a California-based Fortune 500 holding company, and PE owns all of the common stock of SoCalGas. The financial statements herein are, in one case, the Consolidated Financial Statements of PE and its subsidiary, SoCalGas, and, in the second case, the Consolidated Financial Statements of SoCalGas and its subsidiaries, which comprise less than one percent of SoCalGas' consolidated financial position and results of operations. Sempra Energy also indirectly owns all of the common stock of San Diego Gas & Electric Company (SDG&E). SoCalGas and SDG&E are collectively referred to herein as "the California Utilities." A description of SoCalGas is given in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
As PE itself has no operations, PE's financial position and operations consist of those of SoCalGas and some additional items attributable to PE's position as a holding company (e.g. cash, intercompany accounts, debt and equity).
Company Website
The company's website address is http://www.socalgas.com and Sempra Energy's website address is http://www.sempra.com. The company makes available free of charge via a hyperlink on its website its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission.
Risk Factors
The following risk factors and all other information contained in this report should be considered carefully when evaluating the company. These risk factors could affect the actual results of the company and cause such results to differ materially from those expressed in any forward-looking statements of, or made by or on behalf of, the company. Other risks and uncertainties, in addition to those that are described below, may also impair its business operations. If any of the following risks occurs, the company's business, cash flows, results of operations and financial condition could be seriously harmed. These risk factors should be read in conjunction with the other detailed information concerning the company set forth in the notes to Consolidated Financial Statements and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
SoCalGas is subject to extensive regulation by state, federal and local legislation and regulatory authorities, which may adversely affect the operations, performance and growth of its business.
The California Public Utilities Commission (CPUC), which consists of five commissioners appointed by the Governor of California for staggered six-year terms, regulates SoCalGas' rates and conditions of service, sales of securities, rates of return, rates of depreciation, uniform systems of accounts, examination of records and long-term resource procurement. The CPUC conducts various reviews of utility performance (which may include reasonableness and prudency reviews) and affiliate relationships and conducts audits and investigations into various matters which may, from time to time, result in disallowances and penalties adversely affecting earnings and cash flows. Various proceedings involving the CPUC and relating to SoCalGas' rates, costs, incentive mechanisms, performance-based regulation and compliance with affiliate and holding company rules are discussed in the notes to Consolidated Financial Statements and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
Periodically, SoCalGas' rates are approved by the CPUC based on forecasts of capital and operating costs. If the company's actual capital and operating costs were to exceed the amount included in its base rates approved by the CPUC, it would adversely affect earnings and cash flows.
To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC adopted Performance-Based Regulation (PBR) for the California Utilities. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and operating income goals, rather than relying solely on expanding utility plant to increase earnings. The three areas that are eligible for PBR rewards are: operational incentives based on measurements of safety, reliability and customer satisfaction; energy efficiency rewards based on the effectiveness of the programs; and natural gas procurement rewards. Although SoCalGas has received PBR rewards in the past, there can be no assurance that it will receive rewards in the future, or that they would be of comparable amounts. Additionally, if the company fails to achieve certain minimum performance levels established under the PBR mechanisms, it may be assessed financial disallowances or penalties which could negatively affect earnings and cash flows.
The company may be adversely affected by new regulations, decisions, orders or interpretations of the CPUC or other regulatory bodies. New legislation, regulations, decisions, orders or interpretations could change how the company operates, could affect its ability to recover various costs through rates or adjustment mechanisms, or could require the company to incur additional expenses.
The California Utilities' future results of operations and financial condition may be materially adversely affected by the outcome of pending litigation against them.
The California energy crisis of 2000 and 2001 has generated numerous lawsuits, governmental investigations and regulatory proceedings involving many energy companies, including Sempra Energy and the California Utilities. In January 2006, Sempra Energy and the California Utilities reached agreement to settle several of these lawsuits including, subject to court and other approvals, the principal class action antitrust lawsuits in which they are defendants. The companies remain defendants in several additional lawsuits arising out of the energy crisis, including lawsuits commenced in the fourth quarter of 2005 by the California Attorney General. The company is also responding to an ongoing CPUC proceeding related to the increase in natural gas prices at the California-Arizona border in 2000-2001. Sempra Energy and the California Utilities have expended and continue to expend substantial amounts defending these lawsuits and in connection with related investigations and regulatory proceedings. Sempra Energy and the California Utilities have established reserves for the agreed and unresolved issues. However, given the uncertainties involved in resolving litigation, Sempra Energy's and the California Utilities' results of operations and financial condition may be materially adversely affected.
These proceedings are discussed in the notes to Consolidated Financial Statements and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
The company's cash flows, ability to pay dividends and ability to meet its debt obligations largely depend on the performance of its utility operations.
The company's utility operations are the major source of liquidity. The company's ability to pay dividends on its preferred stock is largely dependent on the sufficiency of utility earnings and cash flows in excess of operational needs.
Natural disasters, catastrophic accidents or acts of terrorism could materially adversely affect the company's business, earnings and cash flows.
Like other major industrial facilities, the company's natural gas pipelines may be damaged by natural disasters, catastrophic accidents or acts of terrorism. Any such incidents could result in severe business disruptions, significant decreases in revenues or significant additional costs to the company, which could have a material adverse effect on the company's earnings and cash flows. Given the nature and location of these facilities, any such incidents also could cause fires, leaks, explosions, spills or other significant damage to natural resources or property belonging to third parties, or personal injuries, which could lead to significant claims against the company and its subsidiaries. Insurance coverage may become unavailable for certain of these risks and the insurance proceeds received for any loss of or damage to any of its facilities, or for any loss of or damage to natural resources or property or personal injuries caused by its operations, may be insufficient to cover the company's losses or liabilities without materially adversely affecting the company's financial condition, earnings and cash flows.
GOVERNMENT REGULATION
California Utility Regulation
The CPUC, which consists of five commissioners appointed by the Governor of California for staggered six-year terms, regulates SoCalGas' rates and conditions of service, sales of securities, rate of return, rates of depreciation, uniform systems of accounts, examination of records, and long-term resource procurement. The CPUC conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition and the environment, to determine its future policies. The CPUC also regulates the relationship of the California Utilities with Sempra Energy and is currently investigating this relationship, as discussed further in Note 8 of the notes to Consolidated Financial Statements herein.
United States Utility Regulation
The Federal Energy Regulatory Commission (FERC) regulates the interstate sale and transportation of natural gas, the uniform systems of accounts and rates of depreciation. Both the FERC and the CPUC are currently investigating prices charged to the California investor-owned utilities (IOUs) by various suppliers of natural gas and electricity. Further discussion is provided in Notes 8 and 9 of the notes to Consolidated Financial Statements herein.
Local Regulation
SoCalGas has natural gas franchises with the 240 legal jurisdictions in its service territory. These franchises allow SoCalGas to locate, operate and maintain facilities for the transmission and distribution of natural gas in streets and other public places. Some franchises have fixed lives, such as that for the city of Los Angeles, which expires in 2012. The range of expiration dates for the franchises with definite lives is 2006 to 2048. Most of the franchises have indeterminate lives with no termination date.
Licenses and Permits
SoCalGas obtains numerous permits, authorizations and licenses in connection with the transmission and distribution of natural gas. They require periodic renewal, which results in continuing regulation by the granting agency.
Other regulatory matters are described in Note 8 of the notes to Consolidated Financial Statements herein.
NATURAL GAS UTILITY OPERATIONS
Resource Planning and Natural Gas Procurement and Transportation
The company is engaged in the purchase, sale, distribution, storage and transportation of natural gas. The company's resource planning, natural gas procurement, contractual commitments and related regulatory matters are discussed below and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 8 and 9 of the notes to Consolidated Financial Statements herein.
Customers
For regulatory purposes, customers are separated into core and noncore customers. Core customers are primarily residential and small commercial and industrial customers, without alternative fuel capability. Noncore customers consist primarily of electric generation, wholesale, large commercial, industrial and enhanced oil recovery customers.
Most core customers purchase natural gas directly from the company. Core customers are permitted to aggregate their natural gas requirement and purchase directly from brokers or producers. The company continues to be obligated to purchase reliable supplies of natural gas to serve the requirements of core customers.
Natural Gas Procurement and Transportation
Most of the natural gas purchased and delivered by the company is produced outside of California, primarily in the southwestern U.S. and Canada. The company purchases natural gas under short-term and long-term contracts, which are primarily based on monthly spot-market prices.
To ensure the delivery of the natural gas supplies to the distribution system and to meet the seasonal and annual needs of customers, SoCalGas is committed to firm pipeline capacity contracts that require the payment of fixed reservation charges to reserve firm transportation entitlements. SoCalGas sells excess capacity, if any, on a short-term basis. Interstate pipeline companies, primarily El Paso Natural Gas Company, Transwestern Pipeline Company and Kern River Gas Transmission, provide transportation services into SoCalGas' intrastate transmission system for supplies purchased by SoCalGas or its transportation customers from outside of California. During 2005, SoCalGas renegotiated certain expiring capacity contracts with new expiration dates up to 2011. The rates that interstate pipeline companies may charge for natural gas and transportation services are regulated by the FERC.
According to "Btu's Daily Gas Wire", the annual average spot price of natural gas at the California/Arizona border was $7.62 per million British thermal unit (mmbtu) in 2005 ($11.42 per mmbtu in December 2005), compared with $5.57 per mmbtu in 2004 and $5.13 per mmbtu in 2003. The company's weighted average cost (including transportation charges) per mmbtu of natural gas was $7.71 in 2005, $5.92 in 2004 and $5.05 in 2003.
Natural Gas Storage
SoCalGas provides natural gas storage services for use by the core, noncore and off-system customers. Core customers are allocated a portion of SoCalGas storage capacity. Remaining customers, including SDG&E, can bid and negotiate the desired amount of storage on a contract basis. The storage service program provides opportunities for customers to store natural gas, usually during the summer, to reduce winter purchases when natural gas costs are generally higher. This allows customers to select the level of service they desire to assist them in managing their fuel procurement and transportation needs.
Demand for Natural Gas
The company faces competition in the residential and commercial customer markets based on the customers' preferences for natural gas compared with other energy products. In the non-core industrial market, some customers are capable of using alternate fuels, which can affect the demand for natural gas. The company's ability to maintain its industrial market share is largely dependent on energy prices. The demand for natural gas by electric generators is influenced by a number of factors. In the short-term, natural gas use by electric generators is impacted by the availability of alternative sources of generation. The availability of hydroelectricity is highly dependent on precipitation in the western United States. In addition, natural gas use is impacted by the performance of other generation sources in the western United States, including nuclear and coal, and other natural gas facilities outside the service area. Natural gas use is also impacted by changes in end-use electricity demand. For example, natural gas use generally increases during summer heat waves. Over the long-term, natural gas used to generate electricity will be influenced by additional factors such as the location of new power plant construction and the development of renewable resources. More generation capacity currently is being constructed outside Southern California than within the California Utilities' service area. This new generation will likely displace the output of older, less efficient local generation, reducing the use of natural gas for local electric generation.
Effective March 31, 1998, electric industry restructuring provided out-of-state producers the option to provide power to California utility customers. As a result, natural gas demand for electric generation within Southern California competes with electric power generated throughout the western United States. Although electric industry restructuring has no direct impact on the company's natural gas operations, future volumes of natural gas transported for electric generating plant customers may be significantly affected to the extent that regulatory changes divert electric generation from the company's service area.
Growth in the natural gas markets is largely dependent upon the health and expansion of the Southern California economy and prices of other energy products. External factors such as weather, the price of electricity, electric deregulation, the use of hydroelectric power, development of renewable resources, development of new natural gas supply sources and general economic conditions can result in significant shifts in demand and market price. SoCalGas added 75,000 new customer meters in each of 2005 and 2004, representing growth rates of 1.4 percent in both years. The company expects that its growth rate for 2006 will approximate 2005's.
The natural gas distribution business is seasonal in nature and revenues generally are greater during the winter months. As is prevalent in the industry, the company injects natural gas into storage during the summer months (usually April through October) for withdrawal from storage during the winter months (usually November through March) when customer demand is higher.
RATES AND REGULATION
Information concerning rates and regulations applicable to the company is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 1 and 8 of the notes to Consolidated Financial Statements herein.
ENVIRONMENTAL MATTERS
Discussions about environmental issues affecting the company are included in Note 9 of the notes to Consolidated Financial Statements 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, allowing California's IOUs to recover their hazardous waste cleanup costs, including those related to Superfund sites or similar sites requiring cleanup. Recovery of 90 percent of hazardous waste cleanup costs and related third-party litigation costs, and 70 percent of the related insurance-litigation expenses is permitted. In addition, the company has the opportunity to retain a percentage of any insurance recoveries to offset the 10 percent of costs not recovered in rates.
At December 31, 2005, the company had accrued its estimated remaining investigation and remediation liability related to hazardous waste sites, including numerous locations that had been manufactured-gas plants, of $38.8 million, of which 90 percent is authorized to be recovered through the Hazardous Waste Collaborative mechanism. The company believes that any costs not ultimately recovered through rates, insurance or other means will not have a material adverse effect on the company's consolidated results of operations or financial position.
Estimated liabilities for environmental remediation are recorded when amounts are probable and estimable. Amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism are recorded as a regulatory asset.
Air and Water Quality
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.
OTHER MATTERS
Research, Development and Demonstration (RD&D)
Effective January 2005, a surcharge was established by the CPUC for natural gas public interest RD&D. The natural gas public interest research program is administered by the CEC. For 2005, the funding level is subject to a statewide cap of $12 million. The statewide cap increases to $15 million in 2006. For 2005, SoCalGas funding for the natural gas public purpose RD&D program was $6 million. In addition, SoCalGas operates a separate natural gas RD&D program as discussed below.
The SoCalGas ratepayer-funded RD&D program is focused on utility operations, end use utilization, advanced distributed power generation and transportation. Each of these activities provides benefits to customers and society by providing more cost-effective, efficient natural gas equipment with lower emissions, increased safety and reduced operating costs. For 2005, SoCalGas' RD&D expenditures were $11 million and expenditures averaged $9 million over the past three years.
Employees of Registrant
As of December 31, 2005, the company had 6,473 employees, compared to 6,448 at December 31, 2004.
Labor Relations
Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers' Union of America (UWUA) or the International Chemical Workers' Union Council (ICWUC). The collective bargaining agreement for field, technical and most clerical employees at SoCalGas covering wages, hours, working conditions, medical and various benefit plans is in effect through September 30, 2008.
ITEM 2.
ITEM 2. PROPERTIES
Natural Gas Properties
At December 31, 2005, SoCalGas' natural gas facilities included 2,871 miles of transmission and storage pipeline, 48,013 miles of distribution pipeline and 46,372 miles of service piping. They also included 11 transmission compressor stations and 4 underground storage reservoirs, with a combined working capacity of 125 billion cubic feet (bcf).
Other Properties
SoCalGas leases approximately half of a 52-story office building in downtown Los Angeles through 2011. The lease has six separate five-year renewal options.
The company owns or leases other warehouses, offices, operating and maintenance centers, shops, service facilities and equipment necessary in the conduct of its business.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Except for the matters described in described in Note 9 of the notes to Consolidated Financial Statements or referred to elsewhere in this Annual Report, neither the company nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings.
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 PE is owned by Sempra Energy. The information required by Item 5 concerning dividend declarations is included in the "Statements of Consolidated Changes in Shareholders' Equity" set forth in Item 8 of the 2005 Annual Report to Shareholders herein.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Since Pacific Enterprises is a wholly owned subsidiary of Sempra Energy and SoCalGas is a wholly owned subsidiary of Pacific enterprises, per share data is not provided.
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 of the 2005 Annual Report includes management's discussion and analysis of operating results from 2003 through 2005, and provides information about the capital resources, liquidity and financial performance of Pacific Enterprises (PE) and Southern California Gas Company (SoCalGas). SoCalGas, PE or the two together are also referred to herein as "the company," the distinction being indicated by the context. This section also focuses on the major factors expected to influence future operating results and discusses investment and financing activities and plans. It should be read in conjunction with the Consolidated Financial Statements included in this Annual Report.
PE is the holding company for SoCalGas, the nation's largest natural gas distribution utility. SoCalGas owns and operates a natural gas distribution, transmission and storage system supplying natural gas throughout approximately 20,000 square miles of service territory. Its service territory extends from San Luis Obispo on the north to the Mexican border in the south, excluding San Diego County, the City of Long Beach and the desert area of San Bernardino County. SoCalGas provides natural gas service to residential, commercial, industrial, utility electric generation and wholesale customers, through 5.6 million meters, covering a population of 19.8 million. SoCalGas and its sister utility, San Diego Gas & Electric Company (SDG&E), are collectively referred to herein as "the California Utilities."
RESULTS OF OPERATIONS
The following table shows net income for each of the last five years.
Comparison of Earnings
To assist the reader in understanding the trend of earnings, the following tables summarize the major unusual factors affecting net income and operating income in 2005, 2004 and 2003. The numbers in parentheses are the page numbers where each 2005 item is discussed therein.
Pacific Enterprises
Demand side management (DSM)
Southern California Gas
Demand side management (DSM)
SoCalGas is subject to federal, state and local governmental agencies. The primary regulatory agency is the CPUC, which regulates utility rates and operations. The FERC regulates interstate transportation of natural gas and various related matters. Municipalities and other local authorities regulate the location of utility assets, including natural gas pipelines.
Natural Gas Revenue and Cost of Natural Gas. Natural gas revenues increased by $620 million (16%) to $4.6 billion in 2005, and the cost of natural gas increased by $547 million (24%) to $2.8 billion in 2005. The increases in 2005 were due to higher natural gas prices, which are passed on to customers, offset by a small decrease in volume. In addition, natural gas revenues increased due to higher authorized margin of $28 million, the CPUC's 2005 Cost of Service decision eliminating 2004 revenue sharing (for which $18 million was included in revenue in 2005), $14 million in DSM awards in 2005 and $14 million of higher revenues for recoverable expenses, which are fully offset in other operating expenses. SoCalGas' weighted average cost per million British thermal units (mmbtu) of natural gas was $7.71 in 2005, $5.92 in 2004 and $5.05 in 2003.
Although the current regulatory framework provides that the cost of natural gas purchased for customers and the variations in that cost are passed through to the customers on a substantially concurrent basis, SoCalGas' Gas Cost Incentive Mechanism (GCIM) allows SoCalGas to share in the savings or costs from buying natural gas for customers below or above market-based monthly benchmarks. The mechanism permits full recovery of all costs within a tolerance band around the benchmark price. The costs or savings outside the tolerance band are shared between customers and shareholders. Further discussion is provided in Notes 1 and 8 of the notes to Consolidated Financial Statements.
Natural gas revenues increased by $456 million (13%) to $4.0 billion in 2004 compared to 2003, and the cost of natural gas increased by $453 million (25%) to $2.3 billion in 2004 compared to 2003. The increase in 2004 was primarily attributable to natural gas price increases, an increase in margin of $33 million and $18 million from a favorable Cost of Service decision in 2004, offset by $48 million of GCIM awards and $1 million of Performance-Based Regulation (PBR) awards recognized during 2003. Performance awards are discussed in Note 8 of the notes to Consolidated Financial Statements.
The table below summarizes natural gas volumes and revenues by customer class for the years ended December 31, 2005, 2004 and 2003.
Natural Gas Sales, Transportation and Exchange
(Volumes in billion cubic feet, dollars in millions)
Litigation Expenses.
Litigation expenses were $99 million, $41 million and $34 million for 2005, 2004 and 2003, respectively. The increase in 2005 was primarily due to an increase in litigation reserves related to matters arising from the 2000 - 2001 California energy crisis. Note 9 of the notes to Consolidated Financial Statements provides additional information concerning this matter.
Other Operating Expenses. Other operating expenses at SoCalGas were $954 million, $908 million and $916 million in 2005, 2004 and 2003, respectively. The increase in 2005 was primarily due to $25 million favorable resolution of regulatory matters in 2004 and $14 million higher recoverable expenses in 2005.
Other Income, Net. Other income, net, as discussed further in Note 1 of the notes to Consolidated Financial Statements, consists primarily of interest income from short-term investments, income taxes on non-operating income, interest income/expense from regulatory balancing accounts and allowance for equity funds used during construction. Excluding the impact of income taxes on non-operating income, other income at SoCalGas was $10 million, $17 million, and $40 million in 2005, 2004 and 2003, respectively. The decrease in 2005 was due to the favorable impact on 2004 interest income from a CPUC Cost of Service decision, offset by an increase in interest income in 2005. The decrease in 2004 from 2003 was due to higher interest income in 2003 resulting from the favorable $30 million before-tax resolution of prior years' income tax issues with the Internal Revenue Service (IRS).
Income Taxes. Income tax expense at SoCalGas was $97 million, $154 million and $150 million in 2005, 2004 and 2003, respectively. The corresponding effective income tax rates were 31 percent, 40 percent and 42 percent. The decrease in 2005 expense was due to lower pre-tax income and the lower effective tax rate. The decrease in the effective rate was due primarily to a $24 million favorable resolution of prior years' income tax issues in 2005 at SoCalGas.
Net Income.
SoCalGas recorded net income of $212 million, $233 million and $210 million in 2005, 2004 and 2003, respectively. The decrease in 2005 was due primarily to the resolution of the 2004 Cost of Service proceedings (as discussed further in Note 8 of the notes to Consolidated Financial Statement) which favorably affected 2004 net income by $34 million, an increase of $32 million after-tax in California energy crisis litigation expenses (as discussed further in Note 9 of the notes to Consolidated Financial Statements) and the $9 million after-tax gain from the sale of the Hawaiian Gardens property in 2004, offset by favorable resolution of income tax issues in 2005 of $24 million, higher margins in 2005 of $17 million after-tax and the recognition of DSM awards of $8 million after-tax in 2005. In addition to the 2004 matters noted above, the increase in 2004 from 2003 was due to higher margins in 2004 and losses in 2003 associated with a long-term sublease of portions of its headquarters building, offset by the favorable resolution of income tax issues and by higher GCIM awards in 2003.
CAPITAL RESOURCES AND LIQUIDITY
SoCalGas' utility operations generally are the major source of liquidity. In addition, working capital requirements can be met through the issuance of short-term and long-term debt. Cash requirements primarily consist of capital expenditures for utility plant.
At December 31, 2005, there was $90 million in unrestricted cash and $412 million in available unused, committed lines of credit at SoCalGas. Management believes that these amounts and cash flows from operations and security issuances will be adequate to finance capital expenditures and meet liquidity requirements and other commitments. Forecasted capital expenditures for the next five years are discussed in "Future Capital Expenditures for Utility Plant." Management continues to regularly monitor SoCalGas' ability to finance the needs of its operating, investing and financing activities in a manner consistent with its intention to maintain strong, investment-quality credit ratings.
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by PE's consolidated operating activities totaled $288 million, $546 million and $377 million for 2005, 2004 and 2003, respectively. Net cash provided by SoCalGas' operating activities totaled $264 million, $501 million and $385 million for 2005, 2004 and 2003, respectively.
The 2005 change in net cash provided by operating activities was primarily due to a $261 million change in overcollected regulatory balancing accounts, a $197 million change in income taxes payable mainly due to an increase in income tax payments and a $58 million decrease in accounts payable in 2005, partially offset by a $104 million reduction of accounts receivable and a $157 million increase in other liabilities in 2005. The 2005 change in net cash provided by SoCalGas' operating activities was primarily due to a $261 million change in overcollected regulatory balancing accounts and a $210 million change in income taxes payable mainly due to an increase in income tax payments in 2005, partially offset by a $102 million reduction of accounts receivable and a $140 million increase in other liabilities in 2005.
The increase in 2004 compared to 2003 was primarily attributable to changes in regulatory balancing accounts and an increase in accounts payable in 2004, offset by a higher increase in accounts receivable in 2004.
The company made pension plan and other postretirement benefit plan contributions of $1 million and $36 million, respectively, during 2005. During 2004, the company contributed $42 million to other postretirement benefit plans but made no contribution to the pension plan.
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used in PE's consolidated investing activities totaled $381 million, $295 million and $218 million for 2005, 2004 and 2003, respectively. Net cash used in SoCalGas' investing activities totaled $361 million, $253 million and $279 million for 2005, 2004 and 2003, respectively. The increase in cash used in investing activities in 2005 was due to a $50 million increase in capital expenditures and a $30 million (of which $51 million applied to SoCalGas) increase in loans to affiliates.
PE's increase in cash used in investing activities in 2004 compared to 2003 was primarily due to lower affiliate loan repayments received in 2004. For SoCalGas, the decrease in cash used in investing activities was due to higher repayments received from Sempra Energy in 2004.
Future Capital Expenditures for Utility Plant
Significant capital expenditures in 2006 are expected to include $400 million for improvements to the distribution and transmission systems. These expenditures are expected to be financed by cash flows from operations, asset sales and security issuances.
Over the next five years, the company expects to make capital expenditures of $2 billion, including $400 million in each of the next five years.
Construction programs are periodically reviewed and revised by the company in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost of capital and environmental requirements, as discussed in Note 9 of the notes to Consolidated Financial Statements.
The company intends to finance its capital expenditures in a manner that will maintain its strong investment-grade ratings and capital structure.
The amounts and timing of capital expenditures are subject to approvals by the CPUC, the FERC and other regulatory bodies.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash provided by (used in) financing activities totaled $149 million, $(249) million and $(149) million for 2005, 2004 and 2003, respectively. Net cash provided by (used in) SoCalGas' financing activities totaled $153 million, $(246) million and $(96) million for 2005, 2004 and 2003, respectively.
The 2005 increase was primarily due to a $150 million increase in issuances of long-term debt , a $50 million decrease in common dividends paid in 2005 and a $175 million repayment on long-term debt in 2004.
The cash used in financing activities for 2004 increased due to lower issuances of long-term debt, offset by lower payments on long-term debt.
Long-Term and Short-Term Debt
In November 2005, the company publicly offered and sold $250 million of 5.75% first mortgage bonds, maturing in 2035.
In December 2004, SoCalGas issued $100 million of floating rate first mortgage bonds maturing in December 2009. The interest rate is based on the 3-month LIBOR rate plus 0.17%.
Payments on long-term debt in 2004 included $175 million of SoCalGas' first mortgage bonds.
In 2003, SoCalGas issued $500 million of first mortgage bonds.
Payments on long-term debt in 2003 included $325 million of SoCalGas' first mortgage bonds. In addition, $70 million of SoCalGas' $75 million medium-term notes were put back to the company.
Note 2 of the notes to Consolidated Financial Statements provides information concerning lines of credit and further discussion of debt activity.
Dividends
Common dividends paid to Sempra Energy were $150 million in 2005, compared to $200 million in 2004 and $250 million in 2003. Dividends paid by SoCalGas to PE amounted to $150 million in 2005 and $200 million in each of 2004 and 2003.
The payment and amount of future dividends are within the discretion of the companies' boards of directors. The CPUC's regulation of SoCalGas' capital structure limits the amounts that are available for loans and dividends to Sempra Energy from SoCalGas. At December 31, 2005, the company could have provided a total (combined loans and dividends) of $118 million to Sempra Energy.
Capitalization
Total capitalization, including the current portion of long-term debt, at December 31, 2005 was $3 billion, of which $2.6 billion applied to SoCalGas. The debt-to-capitalization ratios were 39 percent and 46 percent at December 31, 2005 for PE and SoCalGas, respectively.
Commitments
The following is a summary of the companies' principal contractual commitments at December 31, 2005. Additional information concerning commitments is provided above and in Notes 2, 4 and 9 of the notes to Consolidated Financial Statements.
(1) Based on forward rates in effect at December 31, 2005.
(2) Amounts are after reduction for the Medicare Part D subsidy and only include expected payments to the plans for the next 10 years.
The table excludes contracts between affiliates, intercompany debt, individual contracts that have annual cash requirements of less than $1 million and employment contracts.
Credit Ratings
Credit ratings of the company remained at investment grade levels in 2005. As of January 31, 2006, company credit ratings were still as follows:
As of January 31, 2006, the company has a stable outlook rating from all three credit rating agencies.
FACTORS INFLUENCING FUTURE PERFORMANCE
Performance of the company will depend primarily on the ratemaking and regulatory process, natural gas industry restructuring, and the changing energy marketplace. Performance will also depend on the successful completion of construction programs, which are discussed in various places in this report. These factors are discussed in Note 8 of the notes to Consolidated Financial Statements.
Litigation
Note 9 of the notes to Consolidated Financial Statements describes litigation (primarily cases arising from the California energy crisis), the ultimate resolution of which could have a material adverse effect on future performance.
Industry Developments
Note 8 of the notes to Consolidated Financial Statements describes natural gas restructuring and rates, and other pending proceedings and investigations.
Market Risk
Market risk is the risk of erosion of the company's cash flows, net income, asset values and equity due to adverse changes in prices for various commodities, and in interest rates.
The company has adopted policies governing its market risk management and trading activities of all affiliates. Assisted by the company's Risk Management Department (RMD), the company's Risk Management Committee (RMC) consisting of senior officers, establishes policy for and oversees company-wide energy risk management activities and monitors the results of trading and other activities to ensure compliance with the company's stated energy risk management policies and applicable regulatory requirements. The RMD receives daily information detailing positions regarding market positions that create credit, liquidity and market risk and monitors energy price risk management and measures and reports the market and credit risk associated with these positions to the RMC.
Along with other tools, the company uses Value at Risk (VaR) to measure its exposure to market risk. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence interval. The company has adopted the variance/covariance methodology in its calculation of VaR, and uses both the 95-percent and 99-percent confidence intervals. VaR is calculated independently by the RMD for the company. Historical and implied volatilities and correlations between instruments and positions are used in the calculation. The company uses energy and natural gas derivatives to manage natural gas and energy price risk associated with servicing load requirements. The use of energy and natural gas derivatives is in compliance with risk management and trading activity plans that have been filed and approved by the CPUC. Any costs or gains/losses associated with the use of energy and natural gas derivatives, which use is in compliance with CPUC approved plans, are considered to be commodity costs that are passed on to customers in a substantially concurrent basis.
Revenue recognition is discussed in Note 1 and the additional market risk information regarding derivative instruments is discussed in Note 6 of the notes to Consolidated Financial Statements.
The following discussion of the company's primary market risk exposures as of December 31, 2005 includes a discussion of how these exposures are managed.
Commodity Price Risk
Market risk related to physical commodities is created by volatility in the prices and basis of natural gas. The company's market risk is impacted by changes in volatility and liquidity in the markets in which these commodities or related financial instruments are traded. The company is exposed, in varying degrees, to price risk, primarily in the natural gas markets. The company's policy is to manage this risk within a framework that considers the unique markets, and operating and regulatory environments.
The company's market risk exposure is limited due to CPUC-authorized rate recovery of the costs of natural gas purchases and sales. However, the company may, at times, be exposed to market risk as a result of SoCalGas' GCIM, which is discussed in Note 8 of the notes to Consolidated Financial Statements. If commodity prices were to rise too rapidly, it is likely that volumes would decline. This would increase the per-unit fixed costs, which could lead to further volume declines. The company manages its risk within the parameters of its market risk management framework. As of December 31, 2005, the company's VaR was not material and the procurement activities are in compliance with the procurement plans filed with and approved by the CPUC.
Interest Rate Risk
The company is exposed to fluctuations in interest rates primarily as a result of its short-term and long-term debt. The company historically has funded operations through long-term debt issues at fixed rates of interest recovered in utility rates. Some more-recent debt offerings have been issued with floating rates. Subject to regulatory constraints, interest-rate swaps may be used to adjust interest-rate exposures.
At December 31, 2005, the company had $863 million of fixed-rate debt and $248 million of variable-rate debt. Interest on fixed-rate debt is fully recovered in rates on a historical cost basis and interest on variable-rate debt is provided for in rates on a forecasted basis. At December 31, 2005, the company's fixed-rate debt had a one-year VaR of $105 million and its variable-rate debt had a one-year VaR of $7 million.
At December 31, 2005, the notional amount of interest-rate swap transactions totaled $150 million. Note 2 of the notes to Consolidated Financial Statements provides further information regarding interest-rate swap transactions.
In addition, the company is subject to the effect of interest-rate fluctuations on the assets of its pension plans and other postretirement plans. However, the effects of these fluctuations are expected to be passed on to customers.
Credit Risk
Credit risk is the risk of loss that would be incurred as a result of nonperformance by counterparties of their contractual obligations. As with market risk, the company has adopted policies governing the management of credit risk. Credit risk management is performed by the company's credit department and overseen by the company's RMC. Using rigorous models, the RMD and the company calculate current and potential credit risk to counterparties on a daily basis and monitor actual balances in comparison to approved limits. The company avoids concentration of counterparties whenever possible, and management believes its credit policies associated with counterparties significantly reduce overall credit risk. These policies include an evaluation of prospective counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances, the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty, and other security such as lock-box liens and downgrade triggers. The company believes that adequate reserves have been provided for counterparty nonperformance.
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.
As noted above under "Interest Rate Risk," the company periodically enters into interest-rate swap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. The company would be exposed to interest-rate fluctuations on the underlying debt should counterparties to the agreement not perform.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND KEY NON-CASH PERFORMANCE INDICATORS
Certain accounting policies are viewed by management as critical because their application is the most relevant, judgmental and/or material to the company's financial position and results of operations, and/or because they require the use of material judgments and estimates.
The company's significant accounting policies are described in Note 1 of the notes to Consolidated Financial Statements. The most critical policies, all of which are mandatory under generally accepted accounting principles and the regulations of the Securities and Exchange Commission, are the following:
Statement of Financial Accounting Standards (SFAS) 5, "Accounting for Contingencies," establishes the amounts and timing of when the company provides for contingent losses. Details of the company's issues in this area are discussed in Note 9 of the notes to Consolidated Financial Statements.
SFAS 71, "Accounting for the Effects of Certain Types of Regulation," has a significant effect on the way the California Utilities record assets and liabilities, and the related revenues and expenses that would not be recorded absent the principles contained in SFAS 71.
SFAS 109, "Accounting for Income Taxes," governs the way the company provides for income taxes. Details of the company's issues in this area are discussed in Note 3 of the notes to Consolidated Financial Statements.
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," and Emerging Issues Task Force (EITF) Issue 02-3, "Issues Involved in Accounting for Derivative Contracts held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities," have a significant effect on the balance sheets of the company but have no significant effect on its income statements because of the principles contained in SFAS 71.
In connection with the application of these and other accounting policies, the company makes estimates and judgments about various matters. The most significant of these involve:
The calculation of fair or realizable values.
The probable costs to be incurred in the resolution of litigation.
The collectibility of receivables, regulatory assets, deferred tax assets and other assets.
The resolution of various income tax issues between the company and the various taxing authorities.
Differences between estimates and actual amounts have had significant impacts in the past and are likely to have significant impacts in the future.
As discussed elsewhere herein, the company uses exchange quotations or other third-party pricing to estimate fair values. When no such data is available, it uses internally developed models and other techniques. The assumed collectibility of receivables considers the aging of the receivables, the credit-worthiness of customers and the enforceability of contracts, where applicable. The assumed collectibility of regulatory assets considers legal and regulatory decisions involving the specific items or similar items. The assumed collectibility of other assets considers the nature of the item, the enforceability of contracts where applicable, the credit-worthiness of the other parties and other factors. The anticipated resolution of income tax issues considers past resolutions of the same or similar issue, the status of any income tax examination in progress and positions taken by taxing authorities with other taxpayers with similar issues. Actuarial assumptions are based on the advice of the company's independent actuaries. The likelihood of deferred tax recovery is based on analyses of the deferred tax assets and the company's expectation of future financial and/or taxable income, based on its strategic planning.
Choices among alternative accounting policies that are material to the company's financial statements and information concerning significant estimates have been discussed with the audit committee of the board of directors.
Key non-cash performance indicators for the company include numbers of customers and quantities of natural gas sold. The information is provided in "Overview" and "Results of Operations."
NEW ACCOUNTING STANDARDS
Relevant pronouncements that have recently become effective and have had a significant effect on the company's financial statements are SFAS 143 and Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47. They are described below.
SFAS 143, "Accounting for Asset Retirement Obligations" and FIN 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143": SFAS 143 requires entities to record the fair value of liabilities for legal obligations related to asset retirements in the period in which they are incurred. It also requires the company to reclassify amounts recovered in rates for future removal costs not covered by a legal obligation from accumulated depreciation to a regulatory liability. Issued in March 2005, FIN 47 clarifies that the term conditional asset-retirement obligation as used in SFAS 143 refers to a legal obligation to perform an asset-retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires companies to recognize a liability for the fair value of a conditional asset-retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 is effective for the company's 2005 annual report.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A is set forth under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Market Risk."
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - Pacific Enterprises
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of company management, including the principal executive officer and principal financial officer, the company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the company's evaluation under the framework in Internal Control -- Integrated Framework, management concluded that the company's internal control over financial reporting was effective as of December 31, 2005. Management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, as stated in its report, which is included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Pacific Enterprises:
We have audited the accompanying consolidated balance sheets of Pacific Enterprises and subsidiaries (the "Company") as of December 31, 2005 and 2004, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2005. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
As described in Note 1 to the financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, effective December 31, 2005.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 21, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Pacific Enterprises:
We have audited management's assessment, included in the accompanying Management's Report on Internal Control over Financial Reporting, that Pacific Enterprises and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2005 of the Company and our report dated February 21, 2006 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company's adoption of a new accounting standard.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 21, 2006
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)
See notes to Consolidated Financial Statements.
PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
See notes to Consolidated Financial Statements.
PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
See notes to Consolidated Financial Statements.
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
See notes to Consolidated Financial Statements.
PACIFIC ENTERPRISE AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2005, 2004 and 2003
(Dollars in millions)
See notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA
Principles of Consolidation
The Consolidated Financial Statements include the accounts of Pacific Enterprises (PE or the company) and its subsidiary, Southern California Gas Company (SoCalGas or the company). The financial statements herein are, in one case, the Consolidated Financial Statements of PE and its subsidiary, SoCalGas, and, in the second case, the Consolidated Financial Statements of SoCalGas and its subsidiaries, which comprise less than one percent of SoCalGas' consolidated financial position and results of operations. All material intercompany accounts and transactions have been eliminated.
As a subsidiary of Sempra Energy, the company receives certain services therefrom, for which it is charged its allocable share of the cost of such services. Management believes that cost is reasonable, but probably less than if the company had to provide those services itself. In addition, in connection with charges related to litigation, the significant instances of which are discussed in Note 9, Sempra Energy management determines the allocation of the charges among its business units, including the company, based on the extent of their involvement with the subject of the litigation.
Quasi-Reorganization
In 1993, PE effected a quasi-reorganization for financial reporting purposes as of December 31, 1992. Certain of the liabilities established in connection with the quasi-reorganization were favorably resolved in 2003 and 2004, resulting in adjustments to common equity in these years. The remaining liabilities will be resolved in future years and management believes the provisions established for these matters are adequate.
Use of Estimates in the Preparation of the Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting period, and the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Although management believes the estimates and assumptions are reasonable, actual amounts can differ significantly from those estimates.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the current year's presentation.
Regulatory Matters
Effects of Regulation
The accounting policies of the company conform with GAAP for regulated enterprises and reflect the policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). SoCalGas and its affiliate, San Diego Gas & Electric Company (SDG&E), are collectively referred to herein as "the California Utilities."
The company prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standard (SFAS) 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. To the extent that recovery is no longer probable as a result of changes in regulation or the utility's competitive position, the related regulatory assets would be written off. In addition, SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, requires that a loss be recognized whenever a regulator excludes all or part of utility plant or regulatory assets from ratebase. Regulatory liabilities represent reductions in future rates for amounts due to customers. Information concerning regulatory assets and liabilities is provided below in "Revenues," "Regulatory Balancing Accounts" and "Regulatory Assets and Liabilities."
Regulatory Balancing Accounts
The amounts included in regulatory balancing accounts at December 31, 2005, represent net payables (payables net of receivables) that are returned to customers by reducing future rates.
Except for certain costs subject to balancing account treatment, fluctuations in most operating and maintenance accounts affect utility earnings. Balancing accounts provide a mechanism for charging utility customers the amount actually incurred for certain costs, primarily commodity costs. The CPUC has also approved balancing account treatment for variances between forecast and actual for SoCalGas' volumes and commodity costs, eliminating the impact on earnings from any throughput and revenue variances from adopted forecast levels. Additional information on regulatory matters is included in Note 8.
Regulatory Assets and Liabilities
In accordance with the accounting principles of SFAS 71, the company records regulatory assets and regulatory liabilities as discussed above.
Regulatory assets (liabilities) as of December 31 relate to the following matters:
* This is related to SFAS 143, Accounting for Asset Retirement Obligations, which is discussed below in "New Accounting Standards."
Net regulatory assets (liabilities) are recorded on the Consolidated Balance Sheets at December 31 as follows:
* Included in Other Current Liabilities.
All of these assets either earn a return, generally at short-term rates, or the cash has not yet been expended and the assets are offset by liabilities that do not incur a carrying cost.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with maturities of three months or less at the date of purchase.
Non-cash Investing and Financing Activities
In 2003, the company received $48 million of assets from Sempra Energy and assumed related liabilities of $17 million.
Collection Allowances
The allowance for doubtful accounts was $6 million, $5 million and $4 million at December 31, 2005, 2004 and 2003, respectively. The company recorded provisions for doubtful accounts of $10 million, $9 million and $3 million in 2005, 2004 and 2003, respectively.
Inventories
At December 31, 2005, inventory shown on the Consolidated Balance Sheets included natural gas of $110 million and materials and supplies of $11 million. The corresponding balances at December 31, 2004 were $61 million and $11 million, respectively. Natural gas is valued by the last-in first-out (LIFO) method. When the inventory is consumed, differences between the LIFO valuation and replacement cost are reflected in customer rates. Materials and supplies at SoCalGas are generally valued at the lower of average cost or market.
Income Taxes
Income tax expense includes current and deferred income taxes from operations during the year. In accordance with SFAS 109, Accounting for Income Taxes, the company records deferred income taxes for temporary differences between the book and tax bases of assets and liabilities. Investment tax credits from prior years are being amortized to income over the estimated service lives of the properties. Other credits are recognized in income as earned. The company follows certain provisions of SFAS 109 that permit regulated enterprises to recognize deferred taxes as regulatory assets or liabilities to offset deferred tax liabilities and assets, respectively, if it is probable that such amounts will be recovered from, or returned to, customers.
Property, Plant and Equipment
Utility plant primarily represents the buildings, equipment and other facilities used by the company to provide natural gas services.
The cost of plant includes labor, materials, contract services, and certain expenditures incurred during a major maintenance outage of a generating plant. Maintenance costs are expensed as incurred. In addition, the cost of plant includes an allowance for funds used during construction (AFUDC). The cost of most retired depreciable utility plant minus salvage value is charged to accumulated depreciation.
Accumulated depreciation for natural gas utility plant at SoCalGas was $3.0 billion and $2.9 billion at December 31, 2005 and 2004, respectively. Depreciation expense is based on the straight-line method over the useful lives of the assets, an average of 23 years in each of 2005, 2004 and 2003, or a shorter period prescribed by the CPUC. The provision for depreciation as a percentage of average depreciable utility plant was 3.69, 3.68 and 4.36 in 2005, 2004 and 2003, respectively. The discussion of SFAS 143 under "New Accounting Standards" describes a change in the presentation of accumulated depreciation.
AFUDC, which represents the cost of debt and equity funds used to finance the construction of utility plant, is added to the cost of utility plant. Although it is not a current source of cash, AFUDC increases income and is recorded partly as an offset to interest charges and partly as a component of Other Income, Net in the Statements of Consolidated Income. AFUDC amounted to $7 million, $6 million and $12 million for 2005, 2004 and 2003, respectively.
Legal Fees
Legal fees that are associated with a past event for which a contingent liability has been recorded are accrued when it is probable that fees also will be incurred.
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 foreign-currency translation adjustments, minimum pension liability adjustments and certain hedging activities. The components of other comprehensive income, which consists of all these changes other than net income as shown on the Statements of Consolidated Income, are shown in the Statements of Consolidated Changes in Shareholders' Equity. At December 31, 2005, Accumulated Other Comprehensive Income consisted entirely of minimum pension liability adjustments, net of related income tax.
Revenues
Revenues of SoCalGas are primarily derived from deliveries of natural gas to customers and changes in related regulatory balancing accounts. Revenues from natural gas sales and services are recorded under the accrual method and recognized upon delivery. Natural gas storage contract revenues are accrued on a monthly basis and reflect reservation, storage and injection charges in accordance with negotiated agreements, which have terms of up to three years. Operating revenue includes amounts for services rendered but unbilled (approximately one-half month's deliveries) at the end of each year.
Additional information concerning utility revenue recognition is discussed above under "Regulatory Matters."
Transactions with Affiliates
On a daily basis, SoCalGas and SDG&E share numerous functions with each other and they also receive various services from and provide various services to Sempra Energy.
At December 31, 2005, PE has intercompany receivables from various affiliates of $5 million. At December 31, 2004, PE had an intercompany receivable of $4 million from Sempra Energy and receivables from other affiliates of $3 million. Such amounts are included in current assets as Due from Unconsolidated Affiliates.
PE also has a promissory note due from Sempra Energy which bears a variable interest rate based on short-term commercial paper rates (4.01% at December 31, 2005). The balances of the note were $413 million and $394 million at December 31, 2005 and 2004, respectively, and are included in noncurrent assets as Due from Unconsolidated Affiliates. PE also had $1 million and $2 million due from other affiliates at December 31, 2005 and 2004, respectively.
In addition, PE has an intercompany payable to Sempra Energy for $19 million, a dividend payable to Sempra Energy of $50 million and intercompany payables due to other affiliates of $107 million at December 31, 2005. PE had an intercompany payable to Sempra Energy for $25 million and intercompany payables due to other affiliates of $102 million at December 31, 2004. Of the total balances, $52 million and $55 million were recorded at SoCalGas at December 31, 2005 and 2004, respectively. These are reported in current liabilities as Due to Unconsolidated Affiliates. Except for the dividend payable to Sempra Energy, which was due and paid on January 15, 2006, these balances are due on demand.
In addition, SoCalGas has a dividend payable to PE of $50 million at December 31, 2005 which was due and paid January 15, 2006.
Other Income, Net
Other Income, Net consists of the following:
New Accounting Standards
SFAS 123 (revised 2004), "Share-Based Payment" (SFAS 123R): In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS 123R, a revision of SFAS 123, Accounting for Stock-Based Compensation (SFAS 123), which establishes the accounting for transactions in which an entity exchanges its equity instruments for goods or services received. This statement requires companies to measure and record the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. Sempra Energy expects to adopt the provisions of SFAS 123R using a modified prospective application. The modified prospective method requires companies to recognize compensation cost for unvested awards that are outstanding on the effective date based on the fair value that the company had originally estimated for purposes of preparing its SFAS 123 pro forma disclosures. For all new awards that are granted or modified after the effective date, a company would use SFAS 123R's measurement model. The effect of adopting FAS 123R has not been determined. The effective date of this statement is January 1, 2006 for Sempra Energy.
SFAS 143, "Accounting for Asset Retirement Obligations" and FASB Interpretation No. (FIN) 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS 143": Beginning in 2003, SFAS 143 requires entities to record the present value of liabilities for future costs expected to be incurred when assets are retired from service, if the retirement process is legally required. It requires recording of the estimated retirement cost over the life of the related asset by depreciating the present value of the obligation (measured at the time of the asset's acquisition) and accreting the discount until the liability is settled. The adoption of SFAS 143 on January 1, 2003 resulted in the recording of asset retirement obligations of $10 million associated with the future retirement of three storage facilities.
In March 2005, the FASB issued FIN 47, "Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS 143." The interpretation clarifies that the term "conditional asset-retirement obligation" as used in SFAS 143, refers to a legal obligation to perform an asset-retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 requires companies to recognize a liability for the fair value of a conditional asset-retirement obligation if the fair value of the obligation can be reasonably estimated.
The adoption of FIN 47 on December 31, 2005 resulted in the recording of an addition to utility plant of $159 million and accumulated depreciation of $60 million related to the increase to utility plant, for a net increase of $99 million. In addition, the company recorded a corresponding retirement obligation liability of $495 million (which includes accretion of that discounted value to December 31, 2005) and a regulatory liability of $899 million to reflect that the company has collected the funds from customers more quickly than FIN 47 would accrete the retirement liability and depreciate the asset.
The adoption of SFAS 143 required the reclassification of estimated removal costs collected in rates, which had historically been recorded in accumulated depreciation, to a regulatory liability. At December 31, 2005 and 2004, these costs were $200 million and $1.4 billion, respectively. The change in the balance is due to the implementation of FIN 47, which required the reclassification of disposal costs that previously have been included in the company's estimated cost of removal obligations to a regulatory liability and to Asset Retirement Obligations.
In accordance with FIN 47, the company has determined that the amount of asbestos-containing materials could not be determined and, therefore, no liability has been recognized for the related removal obligations. Since most, if not all, of the cost of removing such materials would be expected to be recovered in rates, the effect of not recognizing these liabilities is not material to the company's financial condition or results of operations. A liability for the obligations will be recorded in the period in which sufficient information is available to reasonably estimate the removal cost.
Had FIN 47 been in effect on December 31, 2004, the asset retirement obligation liability would have been $466 million as of that date.
Except for the items noted above, the company has determined that there are no other material retirement obligations associated with tangible long-lived assets.
Implementation of SFAS 143 and FIN 47 had no significant effect on results of operations and is not expected to have a significant effect in the future.
The changes in the asset retirement obligations for the years ended December 31, 2005 and 2004 are as follows (dollars in millions):
* The current portion of the obligation is included in Other Current Liabilities on the Consolidated Balance Sheets.
SFAS 154, "Accounting Changes and Error Corrections, a replacement of Accounting Principles Board Opinion (APBO) 20 and FASB Statement No. 3:" This statement applies to all voluntary changes in accounting principles and to changes required by an accounting pronouncement in instances where the pronouncement does not include specific transition provisions. APBO 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 requires retrospective application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to do so. This statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
NOTE 2. DEBT AND CREDIT FACILITIES
Committed Lines of Credit
SoCalGas and its affiliate, SDG&E, have a combined $600 million five-year syndicated revolving credit facility expiring in 2010, under which each utility individually may borrow up to $500 million, subject to the combined borrowing limit for both utilities of $600 million. Borrowings under the agreement bear interest at rates varying with market rates and SoCalGas' credit rating. The agreement requires SoCalGas to maintain, at the end of each quarter, a ratio of total indebtedness to total capitalization (as defined in the facility) of no more than 65 percent. Borrowings under the agreement are individual obligations of the borrowing utility and a default by one utility would not constitute a default, or preclude borrowings by, the other. At December 31, 2005, SoCalGas had no amounts outstanding under this facility. The facility provides support for $88 million of commercial paper outstanding at December 31, 2005.
The company's weighted average interest rates on the total short-term debt outstanding were 4.26% and 2.25% at December 31, 2005 and 2004, respectively.
LONG-TERM DEBT
Excluding market value adjustments for interest-rate swaps, maturities of long-term debt are:
Callable Bonds
At the company's option, $8 million of bonds is callable in 2006. In addition, $1 billion of bonds is callable subject to make-whole provisions.
First Mortgage Bonds
First mortgage bonds are secured by a lien on utility plant. SoCalGas may issue additional first mortgage bonds upon compliance with the provisions of its bond indenture, which requires, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of an additional $377 million of first mortgage bonds at December 31, 2005.
In November 2005, SoCalGas issued $250 million of first mortgage bonds maturing in 2035.
Unsecured Long-Term Debt
Various long-term obligations totaling $13 million at December 31, 2005 are unsecured.
Interest-Rate Swaps
The company periodically enters into interest-rate swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing.
Fair Value Hedges
During 2003, SoCalGas entered into an interest-rate swap that effectively exchanged the fixed rate on $150 million of its $250 million 4.375% first mortgage bonds maturing in 2011 for a floating rate. The swap expires in 2011. At December 31, 2005, a market value adjustment of ($4) million was recorded as an increase primarily in noncurrent Fixed-price Contracts and Other Derivatives Liabilities and an offsetting decrease in Long-term Debt without affecting net income or other comprehensive income. At December 31, 2004, a market value adjustment of $2 million was recorded as an increase in Sundry Assets and a corresponding increase in Long-term Debt without affecting net income or other comprehensive income. There has been no hedge ineffectiveness on these swaps.
NOTE 3. INCOME TAXES
Reconciliations of the U.S. statutory federal income tax rate to the effective income tax rate are as follows:
The components of income tax expense are as follows:
On the Statements of Consolidated Income, federal and state income taxes are allocated between operating income and other income. The company is included in the consolidated income tax return of Sempra Energy and is allocated income tax expense from Sempra Energy in an amount equal to that which would result from the company's having always filed a separate return. At December 31, 2005, income taxes receivable from Sempra Energy are $166 million.
Accumulated deferred income taxes at December 31 relate to the following:
The net deferred income tax liability is recorded on the Consolidated Balance Sheets at December 31 as follows:
Pacific Enterprises' Quasi-Reorganization
Effective December 31, 1992, PE effected a quasi-reorganization for financial reporting purposes. The reorganization resulted in a restatement of the company's assets and liabilities to their estimated fair value at December 31, 1992 and the elimination of PE's retained earnings deficit. Since the reorganization was for financial purposes and not a taxable transaction, the company established deferred taxes relative to the book and tax bases differences.
During 2004, the company completed an extensive analysis of PE's deferred tax accounts. The analysis resulted in a $72 million reduction of the deferred tax liabilities and an offsetting credit to equity. The credit was recorded to equity because the balances related to tax effects of transactions prior to the quasi-reorganization. In 2004, the company also concluded its outstanding Internal Revenue Service (IRS) examinations and appeals. As of December 31, 2005, the company's balance sheet includes a net deferred tax asset of $11 million related to remaining reserves arising from the quasi-reorganization.
NOTE 4. EMPLOYEE BENEFIT PLANS
The company has funded and unfunded noncontributory defined benefit plans that together cover substantially all of its employees. The plans provide defined benefits based on years of service and either final average or career salary.
The company also has other postretirement benefit plans covering substantially all of its employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory, with participants' contributions adjusted annually. Other postretirement benefits include medical benefits for retirees' spouses.
Pension and other postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. These assumptions include discount rates, expected return on plan assets, rates of compensation increase, health care cost trend rates, mortality rates, and other factors. These assumptions are reviewed on an annual basis prior to the beginning of each year and updated when appropriate. The company considers current market conditions, including interest rates, in making these assumptions.
The company's pension plan was amended effective January 1, 2005, to increase the pension formula for service credit in excess of 30 years as well as service credit in excess of 35 years resulting in an increase of the pension benefit obligation of $3 million.
Effective January 1, 2006 the company's non-represented other postretirement benefit plans were amended to integrate the benefits plan design across the California Utilities, resulting in a $58 million decrease in the benefit obligation as of December 31, 2005.
December 31 is the measurement date for the pension and other postretirement benefit plans. The following table provides a reconciliation of the changes in the plans' projected benefit obligations during the latest two years, and the fair value of assets and a statement of the funded status as of the latest two year ends:
The assets and liabilities of the pension and other postretirement benefit plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in gains and losses. Investment gains and losses are deferred and recognized in pension and postretirement benefit costs over a period of years. The company uses the asset "smoothing" method for the assets held for its pension and other postretirement plans and recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used to determine the expected return-on-assets component of net periodic cost. If, as of the beginning of a year, unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants. The asset smoothing and 10-percent corridor accounting methods help mitigate volatility of net periodic costs from year to year.
The net asset (liability) is recorded on the Consolidated Balance Sheets as follows:
At December 31, 2005 and 2004, the company had an unfunded and a funded pension plan. The funded plan had projected benefit obligations in excess of its plan assets. The following table provides information for the funded plan at December 31:
The following table provides the components of net periodic benefit costs (income) for the years ended December 31:
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was enacted in December of 2003. The Act establishes a prescription drug benefit under Medicare (Medicare Part D) and a tax-exempt federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that actuarially is at least equivalent to Medicare Part D. The company and its actuarial advisors determined that benefits provided to certain participants actuarially will be at least equivalent to Medicare Part D, and, accordingly, the company expects to be entitled to a tax-exempt subsidy that reduces the company's accumulated postretirement benefit obligation under the plan at January 1, 2005 by $76 million and reduces the net postretirement benefit cost for 2005 by $9 million.
The significant assumptions related to the company's pension and other postretirement benefit plans are as follows:
The company utilizes a bond-pricing model that is tailored to the attributes of its pension and other postretirement plans to determine the appropriate discount rate to use for its benefit plans.
The expected long-term rate of return on plan assets is derived from historical returns for broad asset classes consistent with expectations from a variety of sources, including pension consultants and investment advisors.
* This is the weighted average of the increases for the company's health plans. The rate for these plans ranged from 8.50% to 10% in 2005 and from 10% to 20% in 2004.
Assumed health-care cost trend rates have a significant effect on the amounts reported for the health-care plan costs. A one-percent change in assumed health-care cost trend rates would have the following effects:
Pension Plan Investment Strategy
The asset allocation for Sempra Energy's pension trust (which includes the company's pension plan) at December 31, 2005 and 2004 and the target allocation for 2006 by asset categories are as follows:
The company's investment strategy is to stay fully invested at all times and maintain its strategic asset allocation, keeping the investment structure relatively simple. The equity portfolio is balanced to maintain risk characteristics similar to the Morgan Stanley Capital International (MSCI) 2500 index with respect to industry and sector exposures and market capitalization. The foreign equity portfolios are managed to track the MSCI Europe, Pacific Rim and Emerging Markets indexes. Bond portfolios are managed with respect to the Lehman Aggregate Bond Index and Lehman Long Government Credit Bond Index. The plan does not invest in securities of Sempra Energy.
Investment Strategy for Other Postretirement Benefit Plans
The asset allocation for the company's other postretirement benefit plans at December 31, 2005 and 2004 and the target allocation for 2006 by asset categories are as follows:
The company's other postretirement benefit plans that are not included in the pension trust (shown above) are funded by cash contributions from the company and the retirees. The asset allocation is designed to match the long-term growth of the plan's liability. These plans are managed using index funds.
Future Payments
The company expects to contribute $2 million to the pension plan and $23 million to the other postretirement benefit plans in 2006.
The following table reflects the total benefits expected to be paid for the next 10 years to current employees and retirees from the plans or from the company's assets, including both the company's share of the benefit cost and, where applicable, the participants' share of the costs, which is funded by participant contributions to the plans.
The expected future Medicare Part D subsidy payments are as follows:
Savings Plan
The company offers a trusteed savings plan to all eligible employees. Eligibility to participate in the plan is immediate for salary deferrals. Subject to plan provisions, employees may contribute from one percent to 25 percent of their regular earnings, beginning with the start of employment. After one year of each employee's completed service, the company begins to make matching contributions. Employer contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees and, if certain company goals are met, an additional amount related to incentive compensation payments.
Employer contributions are initially invested in Sempra Energy common stock but may be transferred by the employee into other investments. Employee contributions are invested in Sempra Energy stock, mutual funds, or institutional trusts (the same investments to which employees may now direct the employer contributions) as elected by the employee. Employer contributions for the SoCalGas plans are partially funded by the Sempra Energy Employee Stock Ownership Plan and Trust. Company contributions to the savings plan were $11 million in 2005, $10 million in 2004 and $9 million in 2003.
NOTE 5. STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of the company. The plans permit a wide variety of stock-based awards, including nonqualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments and dividend equivalents.
In 1995, SFAS 123 was issued. It encouraged a fair-value-based method of accounting for stock-based compensation. As permitted by SFAS 123, Sempra Energy and its subsidiaries adopted only its disclosure requirements and continued to account for stock-based compensation in accordance with the provisions of APBO 25. The issuance of SFAS 123R will require the company to begin accelerated recognition of stock-based compensation expense for participants who are eligible for retirement-related vesting, beginning in 2006. Discussion of SFAS 123R (a revision of SFAS 123) is provided in Note 1.
Sempra Energy subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans or that the subsidiaries are allocated a portion of Sempra Energy's costs of the plans. PE recorded expenses of $14 million, $9 million and $9 million in 2005, 2004 and 2003, respectively.
NOTE 6. FINANCIAL INSTRUMENTS
Fair Value Hedges
The company periodically enters into interest-rate swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing. The company's interest-rate swaps are discussed in Note 2.
Natural Gas Contracts
At SoCalGas, the use of derivative instruments is subject to certain limitations imposed by company policy and regulatory requirements. These instruments allow the company to estimate with greater certainty the effective prices to be received by the company and the prices to be charged to customers. The company records transactions for natural gas contracts in Cost of Natural Gas in the Statements of Consolidated Income. Unrealized gain and losses related to these derivatives have offsetting regulatory assets and liabilities on the Consolidated Balance Sheets to the extent derivative gains and losses will be recoverable from or payable to customers in future rates.
Fair Value of Financial Instruments
The fair values of certain of the company's financial instruments (cash, temporary investments, notes receivable, short-term debt and customer deposits) approximate their carrying amounts. The following table provides the carrying amounts and fair values of the remaining financial instruments at December 31:
The fair values of long-term debt and preferred stock are based on their quoted market prices or quoted market prices for similar securities.
NOTE 7. PREFERRED STOCK
Preferred Stock of Southern California Gas Company
None of SoCalGas' preferred stock is callable. All series have one vote per share, cumulative preferences as to dividends and liquidation values of $25 per share plus any unpaid dividends.
Preferred Stock of Pacific Enterprises
NOTE 8. REGULATORY MATTERS
Utility Ratemaking Incentive Awards
Performance-Based Regulation (PBR) consists of three primary components. The first is a mechanism to adjust rates in years between general rate cases or cost of service cases. It annually adjusts base rates from those of the prior year to provide for inflation based on the most recent Consumer Price Index (CPI) forecast, subject to minimum and maximum percentage increases that change annually.
The second component is a mechanism whereby any earnings in excess of those authorized plus a narrow band above that are shared with customers in varying degrees depending upon the amount of the additional earnings.
The third component consists of a series of measures of utility performance. Generally, if performance is outside of a band around specified benchmarks, the utility is rewarded or penalized certain dollar amounts. The three areas that have been eligible for PBR rewards or penalties are operational incentives based on measurements of safety, reliability and customer service; demand-side management (DSM) rewards based on the effectiveness of the DSM programs; and natural gas procurement rewards or penalties. As noted below, the latest Cost of Service proceeding established formula-based performance measures for customer service and reliability.
PBR, DSM and Gas Cost Incentive Mechanism (GCIM) awards are not included in the company's earnings until CPUC approval of the award is received. During 2005, the incentive rewards approved and included in earnings consisted of $2.4 million related to SoCalGas' Year 10 (2003-2004) GCIM
In October 2005, the CPUC approved the settlement agreement between the California Utilities and the CPUC's Division of Ratepayer Advocates resolving all outstanding shareholder earnings claims associated with DSM, energy efficiency and low-income energy efficiency programs through various dates, depending on the program. The decision provides for $14 million in awards to SoCalGas, including interest, franchise fees, uncollectible amounts and awards earned in prior years that had not yet then been requested. The $14 million award was included in fourth quarter 2005 income.
The cumulative amount of these awards that is subject to refund based on the outcome of the Border Price Investigation discussed in "Legal Proceedings" in Note 9 below is $59.4 million, the majority of which has been included in income.
Cost of Service
The California Utilities' proposed settlement of Phase II of their cost of service proceedings, addressing attrition allowances and performance-based incentive mechanisms, was approved by the CPUC and related performance measures and incentives were adopted. The CPUC's decision establishes an indexing methodology for post-test-year ratemaking that includes inflation adjustments and earnings-sharing mechanisms. The decision is retroactive to January 1, 2005 and is applicable to years 2005-2007. It eliminates earnings sharing and incentive awards for 2004.
For 2005-2007, the California Utilities' authorized base-rate revenues will be annually increased by the increase in the CPI, subject to minimum and maximum percentage increases that vary with the particular utility and increase yearly. The annual minimum increases range from 2.0% to 3.3% and the annual maximum percentage increases range from 3.0% to 4.3%. Pursuant to the indexing mechanisms, SoCalGas increased its 2006 base margin revenue requirements by $52 million. The base margin adjustments included the recalibration of the 2005 base margin escalation to reflect actual index values before calculating the 2006 base margin revenue. For 2005-2007, any utility base-rate earnings that exceed the CPUC-authorized rate of return on ratebase plus 0.5 percentage point will be shared with customers, in proportions that vary with the amount of the excess, beginning with customers' receiving 75% of the excess, declining to 25% as the excess increases. The decision authorizes either utility to file for a suspension of the indexing and sharing mechanisms if its base-rate earnings for any year are at least 1.75 percentage points below its authorized rate of return and authorizes others to file for a suspension if either utility's base-rate earnings for any year are at least 1.75 percentage points above its authorized rate of return. The mechanisms would be automatically suspended for either utility if its base-rate earnings for 2005 or 2006 are at least 3 percentage points above or below its authorized rate of return.
The decision also establishes formula-based performance measures for customer service and reliability. These provide symmetrical annual reward and penalty potentials aggregating approximately $8 million.
CPUC Investigation of Compliance with Affiliate Rules
In November 2004, the CPUC initiated the independent audit (known as the GDS audit) to evaluate energy-related holding company systems and affiliate activities undertaken by Sempra Energy within the service territories of the California Utilities. A draft audit report covering years 1997 through 2003 was provided to the CPUC's Energy Division in December 2005. The Energy Division is reviewing the draft audit report and plans to make the final audit report available in the first half of 2006. The scope of the audit is broader than the annual affiliate audit.
In May 2005, the California Utilities filed with the CPUC the results of the annual independent audit of the California Utilities' 2004 transactions with other Sempra Energy affiliates. Although the company does not agree with a finding of the auditor that utility procurement information was improperly provided to an affiliated risk-management consulting firm employed by Sempra Energy, the California Utilities have adopted the auditor's recommendation to perform risk management functions themselves rather than utilizing Sempra Energy's Risk Management Department.
"CPUC Investigation of Energy-Utility Holding Companies" and "Natural Gas Market OIR" (below) also discuss issues related to affiliate relationships.
CPUC Investigation of Energy-Utility Holding Companies
On October 27, 2005, the CPUC initiated a proceeding to re-examine the relationships between the California Investor-Owned Utilities (IOUs) and their respective parent holding companies and other non-utility affiliates. It contemplates a review of the capital budgets, capital allocation processes, and dividend and capital retention policies of the utilities and their non-utility affiliates to better understand the amount of capital to be allocated for investment in energy infrastructure to meet California's need for reliable energy. The CPUC has broadly determined that, in appropriate circumstances, it could require the holding company to provide cash to a utility subsidiary to cover its operating expenses and working capital to the extent it is not adequately funded through retail rates. The CPUC may propose additional rules or regulations to ensure that the utilities retain sufficient capital and the ability to access such capital to meet their customers' needs, and to address potential conflicts between the interests of utility ratepayers and those of non-utility affiliates to ensure that they do not undermine the utilities' ability to meet their public service obligations at the lowest possible cost. A preliminary schedule contemplates that any proposed rules and final rules would be issued for comment and final rules be adopted in the first half of 2006.
Natural Gas Industry Restructuring (GIR)
In December 2001, the CPUC issued a decision related to GIR, with implementation anticipated during 2002. On April 1, 2004, after many delays and changes, the CPUC issued a decision that adopts tariffs to implement the 2001 decision. However, that decision stayed implementation of the GIR tariffs until the CPUC issued a decision in Phase I of the Natural Gas Market Order Instituting Ratemaking (OIR) discussed below. At that time, the CPUC ordered the California Utilities to file a new proposal for system integration, firm access rights and off-system deliveries, as referenced below. The company is required to file a new Biennial Cost Allocation Proceeding (BCAP) application after the stay in the GIR implementation proceeding is lifted.
Natural Gas Market OIR
The CPUC's Natural Gas Market OIR was instituted in January 2004 and is being addressed in two phases. The focus of the Natural Gas Market OIR is the period from 2006 to 2016. The California Utilities have made comprehensive filings in the OIR, outlining a proposed market structure that is intended to create access to new natural gas supply sources, such as liquefied natural gas, for California. In their filings, the California Utilities proposed a framework to provide firm tradable access rights for intrastate natural gas transportation; provide SoCalGas with continued balancing account protection for intrastate transmission and distribution revenues, thereby eliminating throughput risk; and integrate their transmission systems so as to have common rates and rules. The California Utilities also proposed that the capital expenditures necessary to access new sources of supply be included in ratebase and that the total amount of the expenditures would be $200 million to $300 million. A decision on Phase I was issued in September 2004. The California Utilities were required to file separate applications to address system integration, firm access rights and off-system deliveries. The CPUC also determined that the ratemaking treatment and cost responsibility for any access-related infrastructure will be addressed in future applications to be filed when more is known about the particular project.
Evidentiary hearings on the system integration proposal were held in September 2005 to consider whether the transmission component of the natural gas transportation rates of the California Utilities should be equalized. System integration would allow customers in the California Utilities' service territories to access upstream supplies of natural gas on an equal basis. A decision on this phase is expected during the first quarter of 2006. Evidentiary hearings on infrastructure adequacy were held in August 2005 and addressed a variety of issues including the infrastructure adequacy of the California Utilities' transmission and storage facilities. Natural gas quality standards and interconnection requirements are being addressed in separate phases. In the second phase, to be addressed in mid-2006, the CPUC will consider establishing a system of firm access rights into the California Utilities' system and off-system deliveries.
The California Utilities proposed a methodology and framework to be used by the CPUC for granting pre-approval of new interstate transportation agreements. The Phase I decision approved the California Utilities' transportation capacity pre-approval procedures with some modifications. SoCalGas' existing pipeline capacity contracts with Transwestern Pipeline Company (Transwestern) expired in November 2005 and its primary contracts with El Paso Natural Gas Company (El Paso) expire in August 2006. SoCalGas was granted pre-approval by the CPUC of a contract for released capacity on the Kern River Gas Transmission Company (Kern River) system, and four capacity contracts with El Paso. The contracts would expire between 2007 and 2011. In 2005, SoCalGas was granted pre-approval of two new capacity contracts with Transwestern that expire in 2009 and 2011. All interstate transportation capacity under the pre-approved contracts will be used to transport natural gas supplies on behalf of the California Utilities' core residential and small commercial customers, and all costs of the capacity will be recovered in the customers' procurement rates.
California Utilities' Structural Changes
On January 4, 2006, the company announced an agreement that, subject to court approval, would settle the Continental Forge antitrust litigation, an identical proceeding in Nevada and class action lawsuits alleging price misreporting and wash trading. The agreement included that the California Utilities will seek approval from the CPUC to integrate their natural gas transmission facilities and to develop both firm, tradable natural gas receipt point rights for access to their combined intrastate transmission system and firm storage capacity rights on SoCalGas' underground natural gas storage system. Additional discussion of the settlement is provided in Note 9 under "Legal Proceedings."
Gain on Sale Rulemaking
A rulemaking was issued in September 2004 to standardize the treatment of gains on sales of property by the IOUs. This rulemaking may result in the adoption of a general ratemaking policy for allocation between utility shareholders and ratepayers of any gain or loss on sale of utility property. The CPUC will consider adopting a standard percentage allocation, probably between 5 percent and 50 percent to shareholders, rather than resolving such allocations on a case-by-case basis, as is now its practice. In unusual circumstances the CPUC would be able to depart from the standard allocation to be adopted. The CPUC intends to apply this standard percentage to sales of both depreciable and non-depreciable property. The rulemaking states that the new policy would replace the CPUC's current policy of allocating to shareholders all gain or loss to shareholders on sale to a municipality of a utility operating system. In November 2005, a proposed decision was issued that, if approved, would adopt a process for allocating gains on sale received by certain electric, natural gas, telecommunications and water utilities when they sell utility land, assets such as buildings, or other tangible or intangible assets formerly used to serve utility customers. In most cases, utility customers should receive 75% of the gain. The utilities' shareholders should receive the remaining 25% of the gain on sale. Opening and reply comments to the proposed decision were filed in January 2006. The final outcome of the rulemaking may be different than that proposed for comment in the order instituting the rulemaking.
NOTE 9. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
In January 2006, the company reached agreements, subject to court approval, to settle certain litigation arising out of the 2000 - 2001 California energy crisis. As a result of that settlement, the company increased its reserves at December 31, 2005, to $168 million, of which $155 million relates to the settled matters.
Other reserves of $13 million have been established for the litigation that is continuing at February 22, 2006. The uncertainties inherent in complex legal proceedings make it difficult to estimate with any degree of certainty the costs and effects of resolving these matters. Accordingly, costs ultimately incurred may differ materially from estimated costs and could materially adversely affect the company's business, cash flows, results of operations and financial condition.
Settlement Agreements
The litigation that is the subject of the settlement agreements is frequently referred to as the Continental Forge litigation, although the settlements also include other cases. The Continental Forge litigation, consisting of class-action and individual antitrust and unfair competition lawsuits consolidated in San Diego Superior Court, allege that Sempra Energy and the California Utilities, along with El Paso and several of its affiliates, unlawfully sought to control natural gas and electricity markets and claim damages of $23 billion after applicable trebling. Plaintiff class members include virtually all natural gas and electric consumers served by the California IOUs. The settlement of Continental Forge would also include the settlement of class action price reporting litigation, consisting of antitrust and unfair competition lawsuits coordinated in the San Diego Superior Court, alleging that Sempra Energy and its subsidiaries unlawfully misreported natural gas transactions to publishers of price indices and engaged in natural gas wash trading transactions. A second settlement agreement relates to class-action litigation brought by the Nevada Attorney General in Nevada Clark County District Court and involves virtually identical allegations to those in the Continental Forge litigation.
To settle the California and Nevada litigation, the company would make cash payments in installments aggregating $377 million, of which $347 million relates to the Continental Forge and California class action price reporting litigation and $30 million relates to the Nevada antitrust litigation. Of the $377 million, $83 million would be paid within thirty days of final approval of the settlement by the San Diego County Superior Court and an additional $83 million would be paid on the first anniversary of that approval. Of the remaining amount, $27.3 million would be paid on the closing date of the settlement and $26.3 million would be paid on each successive anniversary of the closing date through the seventh anniversary of the closing date. At any time after the first anniversary of the closing date, the company would have the option to prepay all or any portion of the remaining unpaid settlement amounts at a discount rate of 7%, with any partial prepayment applied to and reducing each remaining payment on an equal and proportionate basis.
Additional consideration for the California settlement includes an agreement that Sempra LNG would sell to the California Utilities, subject to CPUC approval, re-gasified liquefied natural gas from its liquefied natural gas terminal being constructed in Baja California, Mexico at the California border index price minus $0.02. The volumes to be purchased and sold would be up to 500 million cubic feet per day that Sempra Energy subsidiaries currently have contractual rights to purchase and that is not delivered or sold to Mexican entities. The California Utilities also would seek approval from the CPUC to integrate their natural gas transmission facilities and to develop both firm, tradable natural gas receipt point rights for access to their combined intrastate transmission system and SoCalGas' underground natural gas storage system. In addition, as described below, Sempra Generation voluntarily would reduce the price that it charges for power and limit the places at which it would deliver power under its contract with the DWR.
The California settlement is subject to the approval of the San Diego Superior Court, which has preliminarily approved the settlement, and authorized providing notice to the plaintiff class. The Los Angeles City Council has not yet voted to approve the City of Los Angeles's participation in the settlement and it may elect to continue pursuing its individual case against Sempra Energy and the California Utilities. If the City of Los Angeles decides not to participate, Sempra Energy may, at its option, either proceed with the settlement of the class action and other individual cases or terminate the entire agreement. The California Attorney General, the DWR, the California Energy Oversight Board, Edison, and Pacific Gas & Electric Company unsuccessfully challenged the proposed notice to the class based on their concern that, among other things, the releases in the settlement agreement may be sufficiently broad to encompass other proceedings against Sempra Energy and its subsidiaries to which they are parties. The final approval hearing for the Continental Forge settlement is scheduled to occur on June 8, 2006. The Nevada settlement is subject to approval by the Nevada Clark County District Court, which has not yet approved notice to the class or scheduled a final approval hearing. Both the California and Nevada settlements must be approved for either settlement to take effect, but Sempra Energy is permitted to waive this condition. The settlements are not conditioned upon approval by the CPUC, the DWR, or any other governmental or regulatory agency to be effective.
Sempra Energy recorded an after-tax charge of $116 million for the quarter ended December 31, 2005 (all at the parent company) to provide additional reserves to reflect the costs of the settlements that exceed amounts previously reserved. The additional and previously reserved amounts for the California and Nevada settlements aggregate $585 million (including $76 million at SDG&E and $155 million at SoCalGas) and fully provide for the present value of both the cash amounts to be paid in the settlements and the price discount to be provided on electricity expected to be delivered under the DWR contract.
Other Natural Gas Cases
On November 21, 2005, the California Attorney General and the CPUC filed a lawsuit against Sempra Energy and the California Utilities in San Diego County Superior Court alleging that in 1998 Sempra Energy and the California Utilities had intentionally misled the CPUC in ultimately obtaining CPUC approval to use the utilities' California natural gas pipeline capacity to enable Sempra Energy's non-utility subsidiaries to deliver natural gas to a power plant in Mexico. It further alleges that, as a result of insufficient utility pipeline capacity to serve both the power plant and California customers, SDG&E curtailed natural gas service to electric generators and large California commercial and industrial customers 17 times in 2000 - 2001, with service disruptions resulting in increased air pollution and higher electricity prices for California consumers from the use of oil as an alternate fuel source by electric generating plants. The lawsuit seeks statutory penalties of not less than $1 million, $2,500 for each of an unspecified number of instances of unfair business practices, and unspecified amounts of actual and punitive damages. It also seeks an injunction to require divestiture by Sempra Energy of non-utility subsidiaries to an extent to be determined by the court.
In April 2003, Sierra Pacific Resources and its utility subsidiary Nevada Power filed a lawsuit in U.S. District Court in Las Vegas against major natural gas suppliers, and included Sempra Energy, the California Utilities and Sempra Commodities, seeking recovery of damages alleged to aggregate in excess of $150 million (before trebling). The U.S. District Court dismissed the case in November 2004, determining that the FERC had exclusive jurisdiction to resolve the claims. In January 2005, plaintiffs filed an appeal with the Ninth Circuit Court of Appeals.
During 2004, 12 antitrust actions were filed against the company, alleging that energy prices were unlawfully manipulated by the reporting of artificially inflated natural gas prices to trade publications and by entering into wash trades. Several of those lawsuits seek class action certification. On April 8, 2005, one of those lawsuits, filed in the Nevada U.S. District Court, was dismissed, on the grounds that the claims asserted were preempted by federal law and the Filed Rate Doctrine. In June 2005, the three remaining lawsuits pending in the Nevada U.S. District Court were amended to name the California Utilities as defendants and to include conspiracy allegations similar to those made in the Continental Forge litigation. On December 27, 2005, the District Court dismissed these three actions, on the grounds that the claims asserted in these suits were preempted under federal law and the Filed Rate Doctrine. In addition, in June 2005, a class action lawsuit similar to the pending individual suits in the Nevada federal court was filed in the U.S. District Court for the Eastern District of California and has now been coordinated with the Nevada federal court proceeding. That action was stayed pending the court's determination of the motions to dismiss in the other federal cases. The company will proceed to seek the dismissal of this action as well. With respect to the lawsuits coordinated before the San Diego Superior Court, on June 29, 2005, the court denied the defendants' motion to dismiss on preemption and Filed Rate Doctrine grounds. A separate motion to dismiss filed by Sempra Energy for improper joinder remains pending resolution by the court. On January 4, 2006, the parties agreed to settle the class action cases coordinated in the San Diego Superior Court as part of the overall Continental Forge settlement described above.
CPUC Border Price Investigation
In November 2002, the CPUC instituted an investigation into the Southern California natural gas market and the price of natural gas delivered to the California - Arizona border between March 2000 and May 2001. The Administrative Law Judge's (ALJ) proposed decision highly critical of SoCalGas' natural gas purchase, sales, hedging and storage activities during the period was rejected by the CPUC in December 2004.
The portion of this investigation relating to the California Utilities is still open. If the investigation were to determine that the conduct of either of the California Utilities contributed to the natural gas price spikes that occurred during the investigation period, the CPUC may modify the party's natural gas procurement incentive mechanism, reduce the amount of any shareholder award for the period involved, and/or order the party to issue a refund to ratepayers. At December 31, 2005, the cumulative amount of these shareholder awards, substantially all of which has been included in income, was $59.4 million.
The CPUC may hold additional hearings to consider whether other companies, including other California utilities, contributed to the natural gas price spikes, or issue an order terminating the investigation. Discovery is ongoing and initial testimony was filed in November 2005. Hearings are expected to begin in late July 2006.
Other Litigation
In 1998, SoCalGas converted its traditional pension plan for non-union employees to a cash balance plan. On July 8, 2005, a lawsuit was filed against the company in the U.S. District Court for the Central District of California alleging that the conversion unlawfully discriminated against older employees and failed to provide required disclosure of a reduction in benefits. The lawsuit has been dismissed except for a single claim for alleged failure to make proper notification of plan changes. The company intends to seek to dismiss the remaining claim but believes that any adverse determination in the litigation would not be material.
Natural Gas Contracts
SoCalGas buys natural gas under short-term and long-term contracts. Purchases are from various suppliers and are primarily based on monthly spot-market prices. The company transports natural gas primarily under long-term firm pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments with pipeline companies for firm pipeline capacity under contracts that expire at various dates through 2011.
At December 31, 2005, the future minimum payments under existing natural gas contracts were:
Total payments under natural gas contracts $2.9 billion in 2005, $2.3 billion in 2004 and $1.8 billion in 2003.
Leases
PE and SoCalGas have operating leases on real and personal property expiring at various dates from 2006 to 2030. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 4 percent to 5 percent. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain extension options which are exercisable by the company.
At December 31, 2005, the minimum rental commitments payable in future years under all noncancellable leases were as follows:
Rent expense for operating leases totaled $59 million in 2005, $57 million in 2004 and $56 million in 2003, which included rent expense for SoCalGas of $46 million, $44 million and $43 million, respectively.
Guarantees
As of December 31, 2005, the company did not have any outstanding guarantees.
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. Laws and regulations require that the company investigate and remediate the effects of the release or disposal of materials at sites associated with past and present operations, including sites at which the company has been identified as a Potentially Responsible Party (PRP) under the federal Superfund laws and comparable state laws. The company is required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate its businesses, and must spend significant sums on environmental monitoring, pollution control equipment and emissions fees. Costs incurred to operate the facilities in compliance with these laws and regulations generally have been recovered in customer rates.
Significant costs incurred to mitigate or prevent future environmental contamination or extend the life, increase the capacity or improve the safety or efficiency of property utilized in current operations are capitalized. The company's capital expenditures to comply with environmental laws and regulations were $5 million in 2005, $2 million in 2004 and $6 million in 2003. The cost of compliance with these regulations over the next five years is not expected to be significant.
Costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.
The environmental issues currently facing the company or resolved during the last three years include investigation and remediation of its manufactured-gas sites (29 completed as of December 31, 2005 and 13 to be completed), and cleanup of third-party waste-disposal sites used by the company, which has been identified as a PRP (investigations and remediations are continuing).
Environmental liabilities are recorded when the company's liability is probable and the costs are reasonably estimable. In many cases, however, investigations are not yet at a stage where the company has been able to determine whether it is liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the cost or certain components thereof. Estimates of the company's liability are further subject to other uncertainties, such as the nature and extent of site contamination, evolving remediation standards and imprecise engineering evaluations. The accruals are reviewed periodically and, as investigations and remediation proceed, adjustments are made as necessary. Not including the liability for SONGS marine mitigation, which SDG&E is participating in jointly with Edison, at December 31, 2005, the company's accrued liability for environmental matters was $38.8 million, of which $37.9 million is related to manufactured-gas sites, $0.4 million to waste-disposal sites used by the company (which has been identified as a PRP) and $0.5 million to other hazardous waste sites. The majority of these accruals are expected to be paid ratably over the next two years.
Concentration Of Credit Risk
The company maintains credit policies and systems to manage overall credit risk. These policies include an evaluation of potential counterparties' financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. The company grants credit to customers and counterparties, substantially all of whom are located in its service territories, which cover most of Southern California and a portion of central California.
NOTE 10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating expenses for the third quarter of 2005 included an $88 million before-tax California energy crisis litigation expense. Net income for the third quarter of 2005 was favorably impacted by the resolution of prior years' income tax issues.
Operating expenses in the fourth quarter of 2004 included $41 million of litigation expense, offset by a $25 million favorable impact of the final Cost of Service decision.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - Southern California Gas Company
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of company management, including the principal executive officer and principal financial officer, the company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the company's evaluation under the framework in Internal Control -- Integrated Framework, management concluded that the company's internal control over financial reporting was effective as of December 31, 2005. Management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, as stated in its report, which is included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Southern California Gas Company:
We have audited the accompanying consolidated balance sheets of Southern California Gas Company and subsidiaries (the "Company") as of December 31, 2005 and 2004, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2005. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.
As described in Note 1 to the financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, effective December 31, 2005.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 21, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Southern California Gas Company:
We have audited management's assessment, included in the accompanying Management's Report on Internal Control over Financial Reporting, that Southern California Gas Company and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2005 of the Company and our report dated February 21, 2006 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company's adoption of a new accounting standard.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 21, 2006
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2005, 2004 and 2003
(Dollars in millions)
See notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SOUTHERN CALIFORNIA GAS COMPANY
The following notes to Consolidated Financial Statements of Pacific Enterprises are incorporated herein by reference insofar as they relate to Southern California Gas Company:
Note 1 - Significant Accounting Policies
Note 2 - Debt and Credit Facilities
Note 4 - Employee Benefit Plans
Note 5 - Stock-based Compensation
Note 6 - Financial Instruments
Note 8 - Regulatory Matters
Note 9 - Commitments and Contingencies
The following additional notes apply only to Southern California Gas Company:
NOTE 3. INCOME TAXES
Reconciliations of the U.S. statutory federal income tax rate to the effective income tax rate are as follows:
The components of income tax expense are as follows:
On the Statements of Consolidated Income, federal and state income taxes are allocated between operating income and other income. The company is included in the consolidated income tax return of Sempra Energy and is allocated income tax expense from Sempra Energy in an amount equal to that which would result from the company's having always filed a separate return. At December 31, 2005, income taxes receivable from Sempra Energy are $85 million.
Accumulated deferred income taxes at December 31 relate to the following:
The net deferred income tax liability is recorded on the Consolidated Balance Sheets at December 31 as follows:
NOTE 7. PREFERRED STOCK
None of SoCalGas' preferred stock is callable. All series have one vote per share, cumulative preferences as to dividends and liquidation values of $25 per share plus any unpaid dividends.
PE is authorized to issue 15,000,000 shares of preferred stock without par value. The preferred stock is subject to redemption at PE's option at any time upon at least 30 days' notice, at the applicable redemption price for each series plus any unpaid dividends. All series have one vote per share, cumulative preferences as to dividends, and a liquidation value of $100 per share plus any unpaid dividends.
NOTE 10. QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating expenses for the third quarter of 2005 included an $88 million before-tax California energy crisis litigation expense. Net income for the third quarter of 2005 was favorably impacted by the resolution of prior years' income tax issues.
Operating expenses in the fourth quarter of 2004 included $41 million of litigation expense, offset by a $25 million favorable impact of the final Cost of Service decision.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). The company has designed and maintains disclosure controls and procedures to ensure that information required to be disclosed in the company's reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, management recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired objectives and necessarily applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures.
During the year ended December 31, 2005, management outsourced certain human resource, payroll, and employee benefit functions to a third party service provider, and implemented a new software application that automates the calculation of the income tax provision. The changes strengthen the design and effectiveness of the internal controls and improve the efficiency of these systems. As part of the conversion processes, management performed substantial testing of related internal controls intended to provide reasonable assurances that the converted data and subsequent ongoing process meet the company's objective to provide reliable financial reporting. Management has determined that the design of the controls surrounding these new processes satisfies the control objectives and that the controls are operating effectively.
Except for these changes, there have been no changes in the company's internal controls over financial reporting during the company's most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the company's internal controls over financial reporting.
The company evaluates the effectiveness of its internal control over financial reporting based on the framework in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, the company evaluated the effectiveness of the design and operation of the company's disclosure controls and procedures as of December 31, 2005, the end of the period covered by this report. Based on that evaluation, the company's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures were effective at the reasonable assurance level.
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 2006 annual meeting of shareholders. The information required on the companies' executive officers is set forth below.
EXECUTIVE OFFICERS OF THE REGISTRANT
* As of February 22, 2006.
Each executive officer has been an officer or employee of Sempra Energy or one of its subsidiaries for more than five years, with the exception of Mr. Schlax. Prior to joining the company in 2005, Mr. Schlax was Chief Financial Officer, Treasurer and Vice President of Finance of Mercury Air Group, Inc. Each executive officer of Southern California Gas Company holds the same position at San Diego Gas & Electric Company.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference from "Election of Directors" and "Executive Compensation" in the Information Statement prepared for the May 2006 annual meeting of shareholders.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners
The security ownership information required by Item 12 is incorporated by reference from "Share Ownership" in the Information Statement prepared for the May 2006 annual meeting of shareholders.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information regarding principal accountant fees and services as required by Item 14 is incorporated by reference from "Proposal 3: Ratification of Independent Auditors" in the Information Statement prepared for the May 2006 annual meeting of shareholders.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial statements
2. Financial statement schedules
The following document may be found in this report at the indicated page number.
Schedule I--Condensed Financial Information of Parent. . 83
Schedules for which provision is made in Regulation S-X are not required under the instructions contained therein, are inapplicable or the information is included in the Consolidated Financial Statements and notes thereto.
3. Exhibits
See Exhibit Index on page 87 of this report.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed after September 30, 2005:
Current Report on Form 8-K filed November 2, 2005, including as exhibits Sempra Energy's press release of November 2, 2005, giving the financial results for the three months ended September 30, 2005, and related Income Statement Data by Business Unit.
Current Report on Form 8-K filed November 17, 2005, discussing the status of the company's energy crisis era legal proceedings.
Current Report on Form 8-K filed November 18, 2005, discussing the company's $250 million bond offering.
Current Report on Form 8-K filed November 23, 2005, discussing the status of an action filed by the Attorney General of California against the company.
Current Report on Form 8-K filed January 5, 2006, announcing the agreement to settle certain litigation and the effect of the settlements on the company's results of operations and financial condition for the year ended December 31, 2005.
Current Report on Form 8-K filed January 6, 2006, announcing certain officer changes at Pacific Enterprises to conform the positions to those at SoCalGas.
Current Report on Form 8-K filed February 22, 2006, including as exhibits Sempra Energy's press release of February 22, 2006, giving the financial results for the three months ended December 31, 2005, and related Income Statement Data by Business Unit.
CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM AND REPORT ON SCHEDULES
To the Board of Directors and Shareholders of Pacific Enterprises:
We consent to the incorporation by reference in Registration Statement Numbers 2-96782, 33-26357, 2-66833, 2-96781, 33-21908 and 33-54055 on Form S-8 and Registration Statement Numbers 33-24830, 333-52926 and 33-44338 on Form S-3 of our reports dated February 21, 2006 relating to the financial statements of Pacific Enterprises (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Company's adoption of Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, effective December 31, 2005) and management's report on the effectiveness of internal control over financial reporting, appearing in and incorporated by reference in this Annual Report on Form 10-K of Pacific Enterprises for the year ended December 31, 2005.
Our audits of the financial statements referred to in our aforementioned report also included the financial statement schedule of Pacific Enterprises, listed in Item 15. This financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects, the information set forth therein.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 21, 2006
To the Board of Directors and Shareholders of Southern California Gas Company:
We consent to the incorporation by reference in Registration Statement Numbers 333-70654, 333-45537, 33-51322, 33-53258, 33-59404 and 33-52663 on Form S-3 of our reports dated February 21, 2006 relating to the financial statements of Southern California Gas Company (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Company's adoption of Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143, effective December 31, 2005) and management's report on the effectiveness of internal control over financial reporting, appearing in and incorporated by reference in this Annual Report on Form 10-K of Southern California Gas Company for the year ended December 31, 2005.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 21, 2006
Schedule I -- Condensed Financial Information of Parent
PACIFIC ENTERPRISES
Condensed Statements of Income
(Dollars in millions)
Condensed Balance Sheets
(Dollars in millions)
Schedule I (continued)
PACIFIC ENTERPRISES
Condensed Statements of Cash Flows
(Dollars in millions)
EXHIBIT INDEX
The Forms S-8, 8-K, 10-K and 10-Q referred to herein were filed under Commission File Number 1-14201 (Sempra Energy), Commission File Number 1-40 (Pacific Enterprises) and/or Commission File Number 1-1402 (Southern California Gas Company).
Exhibit 3 -- By-Laws and Articles Of Incorporation
3.01 Articles of Incorporation of Pacific Enterprises (Pacific Enterprises 1996 Form 10-K, Exhibit 3.01).
3.02 Restated Bylaws of Pacific Enterprises dated November 6, 2001. (2001 Form 10-K, Exhibit 3.02).
3.03 Restated Articles of Incorporation of Southern California Gas Company (Southern California Gas Company 1996 Form 10-K, Exhibit 3.01).
3.04 Restated Bylaws of Southern California Gas Company dated November 6, 2001. (2001 Form 10-K, Exhibit 3.04).
Exhibit 4 -- Instruments Defining The Rights Of Security Holders
The Company agrees to furnish a copy of each such instrument to the Commission upon request.
4.01 Specimen Common Stock Certificate of Pacific Enterprises (Pacific Enterprises 1988 Form 10-K, Exhibit 4.01).
4.02 Specimen Preferred Stock Certificates of Pacific Enterprises (Pacific Lighting Corporation 1980 Form 10-K, Exhibit 4.02).
4.03 Specimen Preferred Stock Certificates of Southern California Gas Company (Southern California Gas Company 1980 Form 10-K, Exhibit 4.01).
4.04 First Mortgage Indenture of Southern California Gas Company to American Trust Company dated October 1, 1940 (Registration Statement No. 2-4504 filed by Southern California Gas Company on September 16, 1940, Exhibit B-4).
4.05 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of July 1, 1947 (Registration Statement No. 2-7072 filed by Southern California Gas Company on March 15, 1947, Exhibit B-5).
4.06 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of August 1, 1955 (Registration Statement No. 2-11997 filed by Pacific Lighting Corporation on October 26, 1955, Exhibit 4.07).
4.07 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of June 1, 1956 (Registration Statement No. 2-12456 filed by Southern California Gas Company on April 23, 1956, Exhibit 2.08).
4.08 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of August 1, 1972 (Registration Statement No. 2-59832 filed by Southern California Gas Company on September 6, 1977, Exhibit 2.19).
4.09 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of May 1, 1976 (Registration Statement No. 2-56034 filed by Southern California Gas Company on April 14, 1976, Exhibit 2.20).
4.10 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of September 15, 1981 (Pacific Enterprises 1981 Form 10-K, Exhibit 4.25).
4.11 Supplemental Indenture of Southern California Gas Company to Manufacturers Hanover Trust Company of California, successor to Wells Fargo Bank, National Association, and Crocker National Bank as Successor Trustee dated as of May 18, 1984 (Southern California Gas Company 1984 Form 10-K, Exhibit 4.29).
4.12 Supplemental Indenture of Southern California Gas Company to Bankers Trust Company of California, N.A., successor to Wells Fargo Bank, National Association dated as of January 15, 1988 (Pacific Enterprises 1987 Form 10-K, Exhibit 4.11).
4.13 Supplemental Indenture of Southern California Gas Company to First Trust of California, National Association, successor to Bankers Trust Company of California, N.A. dated as of August 15, 1992 (Registration Statement No. 33-50826 filed by Southern California Gas Company on August 13, 1992, Exhibit 4.37).
4.14 Specimen 7 3/4% Series Preferred Stock Certificate (Southern California Gas Company 1992 Form 10-K, Exhibit 4.15).
4.15 Supplemental Indenture of Southern California Gas Company to U.S. Bank, N.A., successor to First Trust of California, N.A. dated as of October 1, 2002 (2002 Sempra Energy Form 10-K, Exhibit 4.17).
4.16 Supplemental Indenture of Southern California Gas Company to U.S. Bank, N.A., successor to First Trust of California, N.A., Dated as of October 17, 2003 (2004 Sempra Energy Form 10-K, Exhibit 4.19).
4.17 Supplemental Indenture of Southern California Gas Company to U.S. Bank, N.A., successor to First Trust of California, N.A., Dated as of December 15, 2003 (2004 Sempra Energy Form 10-K, Exhibit 4.20).
4.18 Supplemental Indenture of Southern California Gas Company to U.S. Bank, N.A., successor to First Trust of California, N.A., Dated as of December 10, 2004 (2004 Sempra Energy Form 10-K, Exhibit 4.21).
4.19 Supplemental Indenture of Southern California Gas Company to U.S. Bank, N.A., successor to First Trust of California, N.A., Dated as of November 18, 2005 (Form 8-K filed on November 18, 2005, Exhibit 4.1)
Exhibit 10 -- Material Contracts
10.01 Form of Continental Forge and California Class Action Price Reporting Settlement Agreement dated as of January 4, 2006 (Form 8-K filed on January 5, 2006, Exhibit 99.1)
10.02 Form of Nevada Antitrust Settlement Agreement dated as of January 4, 2006 (Form 8-K filed on January 5, 2006, Exhibit 99.2)
10.03 Text of Stipulation in Continental Forge Litigation (Form 8-K filed on September 9, 2005, Exhibit 99.1)
10.04 Southern California Gas Company Underwriting Agreement dated November 15, 2005
(Form 8-K filed on November 18, 2005, Exhibit 1.1)
10.05 Southern California Gas Company Pricing Agreement dated November 15, 2005 (Form 8-K filed on November 18, 2005, Exhibit 1.2)
Compensation
10.06 Form of Severance Pay Agreement (2004 Sempra Energy Form 10-K, Exhibit 10.10).
10.07 Sempra Energy 2005 Deferred Compensation Plan (Pacific Enterprises Form 8-K filed on December 07, 2004, Exhibit 10.1).
10.08 Sempra Energy Employee Stock Incentive Plan (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.1).
10.09 Sempra Energy Amended and Restated Executive Life Insurance Plan (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.2).
10.10 Sempra Energy Excess Cash Balance Plan (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.3).
10.11 Form of Sempra Energy 1998 Long Term Incentive Plan Performance-Based Restricted Stock Award (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.4).
10.12 Form of Sempra Energy 1998 Long Term Incentive Plan Nonqualified Stock Option Agreement (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.5).
10.13 Form of Sempra Energy 1998 Non-Employee Directors' Stock Plan Nonqualified Stock Option Agreement (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.6).
10.14 Sempra Energy Supplemental Executive Retirement Plan (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.7).
10.15 Neal Schmale Restricted Stock Award Agreement (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.8).
10.16 Severance Pay Agreement between Sempra Energy and Donald E. Felsinger (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.9).
10.17 Severance Pay Agreement between Sempra Energy and Neal Schmale (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.10).
10.18 Sempra Energy Executive Personal Financial Planning Program Policy Document (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.11).
10.19 Sempra Energy 2003 Executive Incentive Plan B (2003 Sempra Energy Form 10-K, Exhibit 10.10).
10.20 Sempra Energy 2003 Executive Incentive Plan (June 30, 2003 Sempra Energy Form 10-Q, Exhibit 10.1).
10.21 Amended 1998 Long-Term Incentive Plan (June 30, 2003 Sempra Energy Form 10-Q, Exhibit 10.2).
10.22 Sempra Energy Executive Incentive Plan effective January 1, 2003 (2002 Sempra Energy Form 10-K, Exhibit 10.09).
10.23 Amended Sempra Energy Retirement Plan for Directors (2002 Sempra Energy Form 10-K, Exhibit 10.10).
10.24 Amended and Restated Sempra Energy Deferred Compensation and Excess Savings Plan (Sempra Energy September 30, 2002 Form 10-Q, Exhibit 10.3).
10.25 Sempra Energy Executive Security Bonus Plan effective January 1, 2001 (2001 Sempra Energy Form 10-K, Exhibit 10.08).
10.26 Form of Sempra Energy Severance Pay Agreement for Executives (2001 Sempra Energy Form 10-K, Exhibit 10.07).
10.27 Sempra Energy Deferred Compensation and Excess Savings Plan effective January 1, 2000 (Sempra Energy 2000 Form 10-K, Exhibit 10.07).
10.28 Sempra Energy 1998 Long Term Incentive Plan (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration Statement No. 333-56161 dated June 5, 1998, Exhibit 4.1).
10.29 Pacific Enterprises Employee Stock Ownership Plan and Trust Agreement as amended effective October 1, 1992. (Pacific Enterprises 1992 Form 10-K, Exhibit 10.18).
10.30 Amended and Restated Pacific Enterprises Employee Stock Option Plan (Southern California Gas Company 1996 Form 10-K, Exhibit 10.10).
Exhibit 12 -- Statement Re: Computation of Ratios
12.01 Pacific Enterprises Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2005, 2004, 2003, 2002 and 2001.
12.02 Southern California Gas Company Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2005, 2004, 2003, 2002 and 2001.
Exhibit 21 -- Subsidiaries
21.01 Pacific Enterprises Schedule of Subsidiaries at December 31, 2005.
21.02 Southern California Gas Company Schedule of Subsidiaries at December 31, 2005.
Exhibit 23 -- Consent of Independent Registered Public Accounting Firm, page 82.
Exhibit 31 -- Section 302 Certifications
31.1 Statement of PE's Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2 Statement of PE's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.3 Statement of SoCalGas' Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.4 Statement of SoCalGas' Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Exhibit 32 -- Section 906 Certifications
32.1 Statement of PE's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.2 Statement of PE's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
32.3 Statement of SoCalGas' Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.4 Statement of SoCalGas' Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
GLOSSARY
AFUDC
Allowance for Funds Used During Construction
ALJ
Administrative Law Judge
APBO
Accounting Principles Board Opinion
BCAP
Biennial Cost Allocation Proceeding
bcf
Billion Cubic Feet (of natural gas)
California Utilities
Southern California Gas Company and San Diego Gas & Electric
CPI
Consumer Price Index
CPUC
California Public Utilities Commission
DSM
Demand Side Management
EITF
Emerging Issues Task Force
El Paso
El Paso Natural Gas Company
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FIN
FASB Interpretation Number
GAAP
Generally Accepted Accounting Principles
GCIM
Gas Cost Incentive Mechanism
GIR
Gas Industry Restructuring
IRS
Internal Revenue Service
ICWUC
International Chemical Workers' Union Council
IOUs
Investor-Owned Utilities
Kern River
Kern River Gas Transmission Company
LIBOR
London Interbank Offered Rate
LIFO
Last in first out inventory costing method
mmbtu
Million British Thermal Units (of natural gas)
MSCI
Morgan Stanley Capital International
OIR
Order Instituting Ratemaking
PBR
Performance-Based Ratemaking/Regulation
PE
Pacific Enterprises
PRP
Potentially Responsible Party
RD&D
Research Development and Demonstration
RMC
Risk Management Committee
RMD
Risk Management Department
SDG&E
San Diego Gas & Electric Company
SFAS
Statement of Financial Accounting Standards
SoCalGas
Southern California Gas Company
Transwestern
Transwestern Pipeline Company
UWUA
Utility Workers' Union of America
VaR
Value at Risk