Sempra Energy
PACIFIC ENTERPRISES INC (Form: 10-K, Received: 02/26/2008 16:47:38)


 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

[X]

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended

December 31, 2007

 

 

[  ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from

 

to

 

 

 

 

 

Commission File No.

Exact Name of Registrant as Specified in its Charter, Address and Telephone Number

State of Incorporation

I.R.S. Employer Identification No.

1-40

PACIFIC ENTERPRISES

California

94-0743670

 

101 Ash Street

 

 

 

San Diego, California 92101

 

 

 

(619)696-2020

 

 

 

 

 

 

1-1402

SOUTHERN CALIFORNIA GAS COMPANY

California

95-1240705

 

555 West Fifth Street

 

 

 

Los Angeles, California 90013

 

 

 

(213)244-1200

 

 

 

 

 

 

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

 

Title of Each Class

 

Name of Each Exchange on Which Registered

 


Pacific Enterprises Preferred Stock:
$4.75 dividend, $4.50 dividend
$4.40 dividend, $4.36 dividend

 


American

 

 

 

 

 

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

 

 

 

 

Pacific Enterprises

None

 

Southern California Gas Company

None


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 

 

 

 

 

 

 

Yes

 

 

No

X



1





Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

 

Yes

 

 

No

X



Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

 

Yes

X

 

No

 



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

 

 

 

 

 

X


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer

[  ]

Accelerated filer

[ ]

Non-accelerated filer

[ X ]

 


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

Yes

 

 

No

X


Exhibit Index on page 91. Glossary on page 95.

 

Aggregate market value of the voting and non-voting common equity stock held by non-affiliates of the registrant as of June 30, 2007:

Pacific Enterprises

$0

Southern California Gas Company

$0

 

Common Stock outstanding without par value as of January 31, 2008:

 

 

 

 

 

 

Pacific Enterprises

Wholly owned by Sempra Energy

Southern California Gas Company

Wholly owned by Pacific Enterprises

 

 

 

 

 

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

 

 

 

Portions of the Information Statement prepared for the June 2008 annual meeting of shareholders are incorporated by reference into Part III.

 

 







2




TABLE OF CONTENTS

Page

PART I

 

 

Item 1.

Business and Risk Factors

5

Item 2.

Properties

11

Item 3.

Legal Proceedings

11

Item 4.

Submission of Matters to a Vote of Security Holders

12

 

 

 

PART II

 

 

Item 5.

Market for Registrant's Common Equity and Related Stockholder Matters

12

Item 6.

Selected Financial Data

13

Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations

14

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

26

Item 8.

Financial Statements and Supplementary Data

26

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosures

80

Item 9A.

Controls and Procedures

80

 

 

 

PART III

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

81

Item 11.

Executive Compensation

81

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

81

Item 13.

Certain Relationships and Related Transactions, and Director Independence

82

Item 14.

Principal Accountant Fees and Services

82

 

 

 

PART IV

 

 

Item 15.

Exhibits and Financial Statement Schedules

83

 

 

 

Consents of Independent Registered Public Accounting Firm and Report on Schedule

85

 

 

 

Schedule I - Condensed Financial Information of Parent

87

 

 

 

Signatures

 

89

 

 

 

Exhibit Index

91

 

 

 

Glossary

 

95





3



 

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS


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


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




4




PART I


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 Sempra 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, its 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 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 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, capital structure, rates of return, rates of depreciation, the uniform systems of accounts and long-term resource procurement. The CPUC conducts various reviews of utility performance (which may include reasonableness and prudency reviews of capital expenditures, natural gas procurement, and other costs, and reviews and audits of the company's records) and affiliate



5



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 and performance-based regulation are discussed in Note 9 of the Notes to Consolidated Financial Statements and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.


The company may expend funds prior to receiving regulatory approval to proceed with a major capital project. If the project does not receive regulatory approval or management decides not to proceed with the project, the company may not be able to recover the amount expended for that project.


Periodically, SoCalGas' rates are approved by the CPUC based on authorized capital expenditures and operating costs. If the company's actual capital expenditures and operating costs were to exceed the amount approved by the CPUC, it could adversely affect earnings and cash flows.


To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC applies Performance-Based Regulation (PBR) to the Sempra 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 areas that are eligible for PBR rewards are: operational incentives based on measurements of safety and customer service; 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 construction and expansion of the company’s natural gas pipelines and storage facilities require numerous permits and approvals from federal, state and local governmental agencies. If there are delays in obtaining required approvals, or if the company fails to obtain or maintain required approvals or to comply with applicable laws or regulations, its business, cash flows, results of operations and financial condition could be materially adversely affected.


The Sempra Utilities' future results of operations, financial condition and cash flows may be materially adversely affected by the outcome of pending litigation against them.


Sempra Energy and the Sempra Utilities are defendants in numerous lawsuits. They have expended and continue to expend substantial amounts defending these lawsuits and in connection with related investigations and regulatory proceedings and have established reserves that they believe to be appropriate for their ultimate resolution. However, uncertainties inherent in complex legal proceedings make it difficult to estimate with any degree of certainty the costs and effects of resolving legal matters. Accordingly, costs ultimately incurred may differ materially from estimated costs and could materially adversely affect Sempra Energy's and the Sempra Utilities' business, cash flows, results of operations and financial condition.


These proceedings are discussed in Note 10 of the Notes to Consolidated Financial Statements and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.



6




Future environmental compliance costs could adversely affect SoCalGas' profitability.


SoCalGas is subject to extensive federal, state and local statutes, rules and regulations relating to environmental protection, including, in particular, global warming and greenhouse gas (GHG) emissions. It is required to obtain numerous governmental permits, licenses and other approvals to construct and operate its business. The company also is generally responsible for all on-site liabilities associated with the environmental condition of its facilities, regardless of when the liabilities arose and whether they are known or unknown. If SoCalGas fails to comply with applicable environmental laws, it may be subject to penalties, fines and/or curtailments of its operations.


The scope and effect of new environmental laws and regulations, including their effects on current operations and future expansions, are difficult to predict. Increasing international, national, regional and state-level concerns as well as new or proposed legislation and regulation may have substantial effects on operations, operating costs, and the scope and economics of proposed expansion. In particular, state-level laws and regulations as well as proposed national and international legislation and regulation relating to GHG emissions (including carbon dioxide, methane, nitrogen oxide, hydrofluorocarbon, perfluorocarbon and sulfur hexafluoride) may limit or otherwise adversely affect the operations of the company. The company may be affected if costs are not recoverable in rates and because the effects of significantly tougher standards may cause rates to increase to levels that substantially reduce customer demand and growth.


In addition, existing and future laws and regulation on mercury, nitrogen and sulfur oxides, particulates or other emissions could result in requirements for additional pollution control equipment or emission fees and taxes that could adversely affect the company. Moreover, existing rules and regulations may be interpreted or revised in ways that may adversely affect the company and its facilities and operations.


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 and storage facilities 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 financial condition, 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. 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.


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 and meet its debt obligations is largely dependent on the sufficiency of utility earnings and cash flows in excess of operational needs.




7



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, rates of return, capital structure, rates of depreciation, uniform systems of accounts and long-term resource procurement, except as described below under "United States Utility Regulation." The CPUC also has jurisdiction over the proposed construction of major new natural gas transmission and distribution facilities. The CPUC conducts various reviews of utility performance, conducts audits for compliance with regulatory guidelines, and conducts investigations into various matters, such as deregulation, competition and the environment, to determine its future policies. The CPUC also regulates the interactions and transactions of the Sempra Utilities with Sempra Energy and its affiliates. Further discussion is provided in Note 9 of the Notes to Consolidated Financial Statements herein.


California Assembly Bill 32, the California Global Warming Solutions Act of 2006, makes the California Air Resources Board (CARB) responsible for monitoring and reducing GHG emissions. The bill requires CARB to develop and adopt a comprehensive plan for achieving real, quantifiable and cost-effective GHG emission reductions including, among other things, a statewide GHG emissions cap, mandatory reporting rules, and regulatory and market mechanisms to achieve reductions of GHG emissions. CARB is a part of the California Environmental Protection Agency, an organization which reports directly to the Governor's Office in the Executive Branch of California State Government.


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.


Local Regulation


SoCalGas has natural gas franchises with the 241 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 public places. Some franchises, such as that for the city of Los Angeles, which expires in 2012, have fixed expiration dates ranging from 2008 to 2048. Most of the franchises have indefinite lives with no expiration 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 9 of the Notes to Consolidated Financial Statements herein.


NATURAL GAS UTILITY OPERATIONS


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



8



Condition and Results of Operations" and in Notes 9 and 10 of the Notes to Consolidated Financial Statements herein.


Customers


For regulatory purposes, customers are classified as either core or 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. While customers are permitted to aggregate their natural gas requirement and purchase directly from brokers or producers, the company continues to be obligated to provide 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 U.S. Rockies. 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 its 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 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. The rates that interstate pipeline companies may charge for natural gas and transportation services are regulated by the FERC.


Natural Gas Storage


SoCalGas provides natural gas storage services for use by core, noncore and off-system customers. Sempra Utilities’ customers are allocated a portion of SoCalGas' storage capacity. Other customers can bid and negotiate the desired amount of storage on a contract basis. The storage service program provides opportunities for these customers to purchase and store natural gas when natural gas costs are low, 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 better manage 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 the relative spread between 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 U.S. and Canada. In addition, natural gas use is impacted by the performance of other generation sources in the western U.S., including nuclear and coal, renewable



9



energy 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 extended 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 energy resources. Recently, more generation capacity has been constructed outside Southern California than within the Sempra Utilities' service area. This new generation will displace the output of older, less-efficient local generation, reducing the use of natural gas for local electric generation. Over the next few years, however, construction and planned construction of smaller natural gas-fired peaking and other electric generation facilities within the Sempra Utilities’ service area are expected to result in a slight overall increase in the demand for local natural gas for 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 U.S. Natural gas transported for electric generating plant customers may be significantly affected to the extent that regulatory changes and electric transmission infrastructure investment 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 energy resources, development of new natural gas supply sources and general economic conditions can result in significant shifts in demand and market price. SoCalGas added 57,000 and 77,000 new customer meters in 2007 and 2006, respectively, representing growth rates of 1.0 percent and 1.4 percent, respectively. The company expects that its growth rate for 2008 will approximate that of 2007.


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.


ENVIRONMENTAL MATTERS


Discussions about environmental issues affecting the company are included in Note 10 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 mechanism, allowing California's investor-owned utilities to recover certain hazardous waste cleanup costs, including those related to Superfund sites or similar sites requiring cleanup. Rate 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, 2007, 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 $48 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,



10



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, such as those established by the CARB as discussed under "Government Regulation – California Utility Regulation" herein. Costs to comply with these standards are generally recovered in rates.


OTHER MATTERS


Employees of Registrant


As of December 31, 2007, the company had 7,222 employees, compared to 7,242 at December 31, 2006.

 

Labor Relations


Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers Union of America or the International Chemical Workers Union Council. The collective bargaining agreement for these employees covering wages, hours, working conditions, and medical and other benefit plans is in effect through September 30, 2008.


ITEM 2. PROPERTIES


Natural Gas Properties


At December 31, 2007, SoCalGas' natural gas facilities included 2,887 miles of transmission and storage pipeline, 53,366 miles of distribution pipeline and 47,076 miles of service pipelines. They also included 11 transmission compressor stations and 4 underground natural gas storage reservoirs with a combined working capacity of 131 billion cubic feet.


Other Properties


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


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


ITEM 3. LEGAL PROCEEDINGS


Except for the matters described in Note 10 of the Notes to Consolidated Financial Statements or referred to in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein, neither the company nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings.




11



ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS


None.



PART II



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


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 Comprehensive Income and Changes in Shareholders' Equity" set forth in Item 8 herein.


Dividend Restrictions


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. Additional information regarding these restrictions is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" under "Capital Resources and Liquidity--Dividends" herein.



12



ITEM 6. SELECTED FINANCIAL DATA


 

 

At December 31, or for the years then ended

 

(Dollars in millions)

 

 

2007

 

 

 

2006

 

 

 

2005

 

 

 

2004

 

 

 

2003

 

Pacific Enterprises

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income Statement Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

4,282

 

 

$

4,181

 

 

$

4,617

 

 

$

3,997

 

 

$

3,541

 

 

Operating income

 

$

436

 

 

$

439

 

 

$

347

 

 

$

407

 

 

$

369

 

 

Dividends on preferred stock

 

$

4

 

 

$

4

 

 

$

4

 

 

$

4

 

 

$

4

 

 

Earnings applicable to common shares

 

$

238

 

 

$

235

 

 

$

221

 

 

$

232

 

 

$

217

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

6,802

 

 

$

6,841

 

 

$

6,531

 

 

$

6,085

 

 

$

5,833

 

 

Long-term debt

 

$

1,113

 

 

$

1,107

 

 

$

1,100

 

 

$

864

 

 

$

762

 

 

Short-term debt (a)

 

$

--

 

 

$

--

 

 

$

96

 

 

$

30

 

 

$

175

 

 

Shareholders’ equity

 

$

1,916

 

 

$

1,930

 

 

$

1,834

 

 

$

1,814

 

 

$

1,697

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SoCalGas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income Statement Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

4,282

 

 

$

4,181

 

 

$

4,617

 

 

$

3,997

 

 

$

3,541

 

 

Operating income

 

$

437

 

 

$

439

 

 

$

347

 

 

$

409

 

 

$

365

 

 

Dividends on preferred stock

 

$

1

 

 

$

1

 

 

$

1

 

 

$

1

 

 

$

1

 

 

Earnings applicable to common shares

 

$

230

 

 

$

223

 

 

$

211

 

 

$

232

 

 

$

209

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

$

6,406

 

 

$

6,359

 

 

$

6,007

 

 

$

5,633

 

 

$

5,349

 

 

Long-term debt

 

$

1,113

 

 

$

1,107

 

 

$

1,100

 

 

$

864

 

 

$

762

 

 

Short-term debt (a)

 

$

--

 

 

$

--

 

 

$

96

 

 

$

30

 

 

$

175

 

 

Shareholders’ equity

 

$

1,470

 

 

$

1,490

 

 

$

1,417

 

 

$

1,407

 

 

$

1,376

 

(a)

Includes long-term debt due within one year.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


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.



13




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


INTRODUCTION


This section of the 2007 Annual Report includes management's discussion and analysis of operating results from 2005 through 2007, 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, California in 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 5.7 million meters, covering a population of 20.3 million. SoCalGas and its sister utility, San Diego Gas & Electric Company (SDG&E), are collectively referred to herein as "the Sempra Utilities."


RESULTS OF OPERATIONS


The following table shows net income for each of the last five years.


(Dollars in millions)

 

PE

SoCalGas

2007

 

$ 242

$ 231

2006

 

$ 239

$ 224

2005

 

$ 225

$ 212

2004

 

$ 236

$ 233

2003

 

$ 221

$ 210


SoCalGas is subject to regulation by federal, state and local governmental agencies. The primary regulatory agency is the California Public Utility Commission (CPUC), which regulates utility rates and operations in California. The Federal Energy Regulatory Commission (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 Revenues and Cost of Natural Gas. Natural gas revenues increased by $101 million (2%) to $4.3 billion, and the cost of natural gas remained constant at $2.4 billion in 2007. The increase in revenues in 2007 was primarily due to a $63 million increase in authorized base margin and $41 million of higher revenues for recoverable expenses, which are fully offset in other operating expenses. SoCalGas' weighted average cost (including transportation charges) per million British thermal units (MMBtu) of natural gas was $6.39 in 2007, $6.49 in 2006 and $7.71 in 2005.




14



Natural gas revenues decreased by $436 million (9%) to $4.2 billion, and the cost of natural gas decreased by $420 million (15%) to $2.4 billion in 2006 compared to 2005. The decreases in 2006 were due to lower average costs of natural gas, which are passed on to customers, offset by higher volumes. In addition, natural gas revenues decreased due to the CPUC's decision in 2005 eliminating 2004 revenue sharing (for which $18 million was included in revenue in 2005), $14 million in demand-side management (DSM) awards in 2005 and $50 million of lower revenues for decreased recoverable expenses. The decreases were offset by a $52 million increase in authorized base margin and $10 million from the positive resolution in 2006 of a natural gas royalty matter.


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 9 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, 2007, 2006 and 2005.


Natural Gas Sales, Transportation and Exchange

(Volumes in billion cubic feet, dollars in millions)


 

 

 

 

 

 

 

 

 

 

 

         Transportation

 

 

 

 

 

 

 

 

 

 

 

      Natural Gas Sales

         and Exchange

         Total

 

 

 

 

 

 

Volumes

Revenue

Volumes

Revenue

Volumes

Revenue

2007:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

245

 

$

2,660

 

1

 

$

5

 

246

 

$

2,665

 

Commercial and industrial

 

111

 

 

999

 

277

 

 

208

 

388

 

 

1,207

 

Electric generation plants

 

--

 

 

--

 

204

 

 

72

 

204

 

 

72

 

Wholesale

 

--

 

 

--

 

142

 

 

59

 

142

 

 

59

 

 

 

 

 

 

 

356

 

$

3,659

 

624

 

$

344

 

980

 

 

4,003

 

Balancing accounts and other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

279

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

4,282

2006:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

247

 

$

2,727

 

1

 

$

5

 

248

 

$

2,732

 

Commercial and industrial

 

107

 

 

988

 

272

 

 

217

 

379

 

 

1,205

 

Electric generation plants

 

--

 

 

--

 

183

 

 

74

 

183

 

 

74

 

Wholesale

 

--

 

 

--

 

136

 

 

44

 

136

 

 

44

 

 

 

 

 

 

 

354

 

$

3,715

 

592

 

$

340

 

946

 

 

4,055

 

Balancing accounts and other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

126

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

4,181

2005:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Residential

 

240

 

$

2,812

 

1

 

$

6

 

241

 

$

2,818

 

Commercial and industrial

 

106

 

 

1,083

 

269

 

 

186

 

375

 

 

1,269

 

Electric generation plants

 

--

 

 

--

 

142

 

 

49

 

142

 

 

49

 

Wholesale

 

--

 

 

--

 

141

 

 

61

 

141

 

 

61

 

 

 

 

 

 

 

346

 

$

3,895

 

553

 

$

302

 

899

 

 

4,197

 

Balancing accounts and other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

420

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

4,617



15



Other Operating Expenses. Other operating expenses at SoCalGas were $1,020 million, $951 million and $954 million in 2007, 2006 and 2005, respectively. The increase in 2007 was due to $41 million higher recoverable expenses (offset in revenues) and $28 million higher other operational costs. The decrease in 2006 compared to 2005 included $50 million lower recoverable expenses offset by $47 million higher other operational costs.


Litigation Expense. Litigation expense was $1 million, $(2) million and $99 million for 2007, 2006 and 2005, respectively. The higher amount in 2005 was primarily due to an increase in litigation reserves related to a settlement of matters arising from the 2000 - 2001 California energy crisis. Note 10 of the Notes to Consolidated Financial Statements provides additional information concerning this matter.


Interest Income. Interest income was $51 million, $64 million and $25 million ($27 million, $29 million and $12 million at SoCalGas) in 2007, 2006 and 2005, respectively. Interest income in 2006 included $13 million from the resolution of an insurance claim at PE related to a quasi-reorganization issue (discussed in Note 1 of the Notes to Consolidated Financial Statements) and $6 million from an income tax audit settlement at SoCalGas.


The increase in 2006 compared to 2005 was primarily due to the items noted above and higher interest resulting from increases in short-term investments.


Interest Expense. Interest expense at SoCalGas was $70 million, $70 million and $48 million in 2007, 2006 and 2005, respectively. The increase in 2006 compared to 2005 was primarily due to higher interest expense associated with the $250 million first mortgage bonds issued in November 2005, higher variable interest rates and interest expense related to the accretion of the California energy crisis litigation settlement liability.


Income Taxes . Income tax expense at SoCalGas was $160 million, $173 million and $97 million in 2007, 2006 and 2005, respectively. The corresponding effective income tax rates were 41 percent, 44 percent and 31 percent. The decrease in income tax expense in 2007 was primarily due to a lower effective tax rate and lower pretax income. The lower effective tax rate was due to a higher deduction for basis differences in fixed assets and a higher federal deduction for state taxes. The increase in 2006 expense compared to 2005 was due to the higher effective tax rate and higher pretax income. The increase in the effective tax rate in 2006 was due primarily to a $24 million favorable resolution of prior years' income tax issues in 2005.


Net Income. SoCalGas recorded net income of $231 million, $224 million and $212 million in 2007, 2006 and 2005, respectively. The increase in 2007 was due primarily to $9 million of higher authorized base margins, net of higher operating expenses, and $10 million of lower income tax expense due to a lower effective tax rate in 2007, offset by $7 million from the favorable resolution of a natural gas royalty matter in 2006.


The increase in 2006 compared to 2005 was due primarily to the California energy crisis reserve of $56 million recorded in litigation expense in 2005 and $7 million from the positive resolution in 2006 of a natural gas royalty matter, offset by $24 million in 2005 from the favorable resolution of prior years' income tax issues, $11 million from the reversal in 2005 of the 2004 revenue-sharing reserve resulting from the CPUC's 2004 Cost of Service decision, higher income tax expense in 2006 of $13 million due to a higher effective tax rate in 2006 (excluding the effect of the resolution of prior years' income tax issues in 2005) and a DSM awards settlement of $8 million in 2005.




16




CAPITAL RESOURCES AND LIQUIDITY


SoCalGas' utility operations generally are the major source of liquidity. In addition, cash 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, 2007, the company had $59 million in unrestricted cash and cash equivalents, and $500 million in available unused credit on its committed line at SoCalGas, which is shared with SDG&E and is discussed more fully in Note 3 of the Notes to Consolidated Financial Statements. 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 to fund shareholder dividends 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 $491 million, $911 million and $288 million for 2007, 2006 and 2005, respectively. Net cash provided by SoCalGas' operating activities totaled $478 million, $873 million and $264 million for 2007, 2006 and 2005, respectively.


Cash provided by operating activities in 2007 decreased by $420 million (46%). For SoCalGas, net cash provided by operating activities decreased by $395 million (45%). The changes were primarily due to a decrease of $13 million in overcollected regulatory balancing accounts in 2007 compared to an increase of $185 million in 2006, a $79 million decrease in accounts payable in 2007 compared to an increase of $83 million in 2006, and a $31 million increase in accounts receivable in 2007 compared to a decrease of $52 million in 2006. The changes in net cash provided by PE’s operating activities were substantially the same as for SoCalGas.


The increase in cash provided by operating activities in 2006 compared to 2005 was primarily due to a $185 million increase in overcollected regulatory balancing accounts in 2006 compared to a $168 million decrease in 2005, a $113 million increase in income tax payable in 2006 compared to a $136 million decrease in 2005 and a $93 million decrease in accounts receivable, offset by an $84 million decrease in other liabilities. The changes in net cash provided by SoCalGas' operating activities were substantially the same as for PE.


The company made pension plan and other postretirement benefit plan contributions of $1 million and $28 million, respectively, during 2007, $1 million and $19 million, respectively, during 2006 and $1 million and $36 million, respectively, during 2005.


CASH FLOWS FROM INVESTING ACTIVITIES


Net cash used in PE's consolidated investing activities totaled $489 million, $548 million and $381 million for 2007, 2006 and 2005, respectively. Net cash used in SoCalGas’ investing activities totaled $479 million, $513 million and $361 million for 2007, 2006 and 2005, respectively.




17



Cash used in PE’s investing activities in 2007 decreased by $59 million (11%). For SoCalGas, cash used in investing activities decreased by $34 million (7%) in 2007. The changes were primarily due to a $111 million decrease in advances to Sempra Energy (of which $87 million was associated with advances made by SoCalGas), partially offset by a $44 million increase in capital expenditures in 2007.


Cash used in PE's investing activities in 2006 compared to 2005 increased by $167 million and by $152 million at SoCalGas. The changes were primarily due to a $126 million increase in advances to Sempra Energy (of which $111 million was associated with advances made by SoCalGas) and a $52 million increase in capital expenditures in 2006.


Future Capital Expenditures for Utility Plant


Significant capital expenditures and investments in 2008 are expected to include $400 million for improvements to distribution and transmission systems. These expenditures are expected to be financed by cash flows from operations 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. Capital expenditure amounts include the portion of AFUDC (allowance for funds used during construction) related to debt, and exclude the portion of AFUDC related to equity. AFUDC is discussed in Note 1 of the Notes to Consolidated Financial Statements.


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 10 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 $(154) million, $(242) million and $149 million for 2007, 2006 and 2005, respectively. Net cash provided by (used in) SoCalGas' financing activities totaled $(151) million, $(239) million and $153 million for 2007, 2006 and 2005, respectively. The 2007 changes at PE and SoCalGas were due to an $88 million decrease in short-term debt in 2006.


The 2006 change from 2005 at PE and SoCalGas was primarily due to $250 million in issuances of long-term debt in 2005 and an $88 million decrease in short-term debt in 2006 compared to an increase of $58 million in 2005.


Long-Term Debt


In November 2005, SoCalGas publicly offered and sold $250 million of 5.75-percent first mortgage bonds, maturing in 2035.


Note 3 of the Notes to Consolidated Financial Statements provides information concerning lines of credit and further discussion of debt activity.



18




Dividends


Common dividends paid to Sempra Energy were $150 million in each of 2007, 2006 and 2005. In December 2007, PE declared a common dividend of $150 million, which was paid in January 2008. Dividends paid by SoCalGas to PE amounted to $150 million in each of 2007, 2006 and 2005. In December 2007, SoCalGas declared a common dividend of $150 million, which was paid in January 2008.


The payment and amount of future dividends are at 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, 2007, the company could have provided a total (combined loans and dividends) of $30 million to Sempra Energy.


Capitalization


At December 31, 2007, total capitalization, including all debt, was $3 billion, of which $2.6 billion applied to SoCalGas. The debt-to-capitalization ratios were 37 percent and 43 percent at December 31, 2007 for PE and SoCalGas, respectively. The significant change affecting capitalization during 2007 was comprehensive income exceeding dividends.


Commitments


The following is a summary of the companies' principal contractual commitments at December 31, 2007. Additional information concerning commitments is provided above and in Notes 2, 3, 5 and 10 of the Notes to Consolidated Financial Statements.


(Dollars in millions)

 

2008

 

 

2009 and 2010

 

 

2011 and 2012

 

 

Thereafter

 

 

Total

SOCALGAS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

$

--

 

$

100

 

$

500

 

 

$

513

 

$

1,113

Interest on debt (1)

 

57

 

 

109

 

 

79

 

 

 

406

 

 

651

Natural gas contracts

 

1,240

 

 

1,266

 

 

408

 

 

 

82

 

 

2,996

Operating leases

 

50

 

 

92

 

 

44

 

 

 

6

 

 

192

Litigation reserves

 

24

 

 

23

 

 

23

 

 

 

23

 

 

93

Environmental commitments

 

31

 

 

14

 

 

3

 

 

 

--

 

 

48

Pension and postretirement benefit

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    obligations (2)

 

21

 

 

46

 

 

114

 

 

 

554

 

 

735

Asset retirement obligations

 

15

 

 

27

 

 

33

 

 

 

502

 

 

577

 Total

 

1,438

 

 

1,677

 

 

1,204

 

 

 

2,086

 

 

6,405

PE - operating leases

 

13

 

 

20

 

 

--

 

 

 

--

 

 

33

Total PE consolidated

$

1,451

 

$

1,697

 

$

1,204

 

 

$

2,086

 

$

6,438

(1)

Expected interest payments were calculated using the stated interest rate for fixed rate obligations. Expected interest payments were calculated based on forward rates in effect at December 31, 2007 for variable rate obligations, including fixed-to-floating interest rate swaps.

(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 intercompany debt and individual contracts that have annual cash requirements less than $1 million. The table also excludes income tax liabilities of $18 million



19



recorded in accordance with Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48), because the company is unable to reasonably estimate the timing of future payments of these liabilities due to uncertainties in the timing of the effective settlement of tax positions. Additional information on FIN 48 is provided in Note 2 of the Notes to Consolidated Financial Statements.


Credit Ratings


Credit ratings remained at investment grade levels in 2007. As of January 31, 2008, company credit ratings were as follows:


 

 

Standard

& Poor's

 

Moody's Investor

 Services, Inc.

 

Fitch

SOCALGAS

 

 

 

 

 

 

Secured debt

 

A+

 

A1

 

AA

Unsecured debt

 

A-

 

A2

 

AA-

Preferred stock

 

BBB+

 

Baa1

 

A+

Commercial paper

 

A-1

 

P-1

 

F1+

 

 

 

 

 

 

 

PE - preferred stock

 

BBB+

 

--

 

A


As of January 31, 2008, the companies have a stable ratings outlook 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 CPUC’s final decision regarding the 2008 General Rate Case and the successful completion of capital projects which are discussed in various places in this report. These factors are discussed in Note 9 of the Notes to Consolidated Financial Statements.


Litigation


Note 10 of the Notes to Consolidated Financial Statements describes litigation, the ultimate resolution of which could have a material adverse effect on future performance.


Industry Developments


Note 9 of the Notes to Consolidated Financial Statements describes natural gas regulation 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 policies governing its market risk management and trading activities. The company maintains a risk management committee, organization and processes to provide oversight of these activities. The committee, consisting of senior officers, establishes policy for and oversees energy risk management activities and monitors the results of trading and other activities to ensure compliance with the company's stated energy risk management and trading policies. This includes monitoring daily,



20



detailed information detailing positions regarding market positions that create credit, liquidity and market risk. Independently from the company’s energy procurement department, the oversight organization and committee monitor energy price risk management and measure and report the credit, liquidity and market risk associated with these positions.


Along with other tools, the company uses Value at Risk (VaR) to measure daily 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 risk management oversight organization. Historical and implied volatilities and correlations between instruments and positions are used in the calculation.


The company uses natural gas derivatives to manage natural gas price risk associated with servicing load requirements. The use of natural gas derivatives is subject to certain limitations imposed by company policy and 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 natural gas derivatives, which use is in compliance with CPUC approved plans, are considered to be commodity costs that are passed on to customers on a substantially concurrent basis.


Revenue recognition is discussed in Note 1 of the Notes to Consolidated Financial Statements and the additional market-risk information regarding derivative instruments is discussed in Note 7 of the Notes to Consolidated Financial Statements.


The following discussion of the company's primary market-risk exposures as of December 31, 2007 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, intrastate transportation and storage activity. However, the company may, at times, be exposed to market risk as a result of SoCalGas' GCIM, which is discussed in Note 9 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, 2007, the company's VaR was not material, and the procurement activities were 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. Subject to regulatory constraints, interest-rate swaps may be used to adjust interest-rate exposures. The company periodically enters into interest-rate swap agreements to moderate its exposure to interest-rate changes and to lower its overall costs of borrowing.




21



At December 31, 2007, after the effects of interest-rate swaps, the company had $863 million of fixed-rate, long-term debt and $250 million of variable-rate, long-term debt. Interest on fixed-rate utility 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, 2007, the company's fixed-rate, long-term debt, after the effects of interest-rate swaps, had a one-year VaR of $161 million and its variable-rate, long-term debt, after the effects of interest-rate swaps, had a one-year VaR of $9 million.


At December 31, 2007, the notional amount of interest-rate swap transactions totaled $333 million. Note 7 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 benefit 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 policies governing the management of credit risk that are administered by the company's credit department and overseen by its risk management committee. Using rigorous models, this oversight includes calculating current and potential credit risk on a daily basis and monitoring actual balances in comparison to approved limits. The company avoids concentration of counterparties whenever possible, and management believes its credit policies 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 NONCASH 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 in the United States of America and the regulations of the Securities and Exchange Commission, are the following:



22




Description

 

Assumptions & Approach Utilized

 

Effect if Different Assumptions Used

 

 

 

 

 

Contingencies

 

 

 

 

Statement of Financial Accounting Standards (SFAS) 5, Accounting for Contingencies , establishes the amounts and timing of when the company provides for contingent losses. The company continuously assesses potential loss contingencies for litigation claims, environmental remediation and other events.


 

The company accrues losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, the loss is accrued if (1) information is available that indicates it is probable that the loss has been incurred, given the likelihood of uncertain future events, and (2) the amounts of the loss can be reasonably estimated. SFAS 5 does not permit the accrual of contingencies that might result in gains.

 

Details of the company's issues in this area are discussed in Note 10 of the Notes to Consolidated Financial Statements.

 

 

 

 

 

Regulatory Accounting

 

 

 

 

SFAS 71, Accounting for the Effects of Certain Types of Regulation , has a significant effect on the way the Sempra Utilities record assets and liabilities, and the related revenues and expenses that would not be recorded absent the principles contained in SFAS 71.

 

The company records a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. Similarly, the company records regulatory liabilities for amounts recovered in rates in advance of the expenditure. The company reviews probabilities associated with regulatory balances whenever new events occur, such as changes in the regulatory environment or the utility's competitive position, issuance of a regulatory commission order or passage of new legislation. To the extent that circumstances associated with regulatory balances change, the regulatory balances could be adjusted.

 

Details of the company's  regulatory assets and liabilities are discussed in Note 1 of the Notes to Consolidated Financial Statements.

 

 

 

 

 

Income Taxes

 

 

 

 

SFAS 109, Accounting for Income Taxes , governs the way the company provides for income taxes.



 

The company's income tax expense and related balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. 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. The likelihood of deferred tax recovery is based on analyses of the deferred tax assets and the company's expectation of future taxable income, based on its strategic planning.

 

Actual income taxes could vary from estimated amounts due to the future impacts of various items including changes in tax laws, the company's financial condition in future periods, and the resolution of various income tax issues between the company and the various taxing authorities. Details of the company's issues in this area are discussed in Note 4 of the Notes to Consolidated Financial Statements.




23







Description

 

Assumptions & Approach Utilized

 

Effect if Different Assumptions Used

 

 

 

 

 

Income Taxes (continued)

 

 

 

 

FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements. FIN 48 addresses how an entity should recognize, measure, classify and disclose in its financial statements uncertain tax positions that it has taken or expects to take in an income tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

 

For a position to qualify for benefit recognition under FIN 48, the position must have at least a "more likely than not" chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term "more likely than not" means a likelihood of more than 50 percent. If the company does not have a more likely than not position with respect to a tax position, then the company may not recognize any of the potential tax benefit associated with the position. A tax position that meets the "more likely than not" recognition shall initially and subsequently be measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon the effective resolution of the tax position.

 

Unrecognized tax benefits involve management judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect the company’s results of operations, financial position and cash flows.

 

Additional information related to accounting for uncertainty in income taxes is discussed in Note 2 of the Notes to Consolidated Financial Statements.

 

 

 

 

 

Derivatives

 

 

 

 

SFAS 133, Accounting for Derivative Instruments and Hedging Activities , as amended, and related Emerging Issues Task Force Issues govern the accounting requirements for derivatives.

 

The company values derivative instruments at fair value on the balance sheet. Depending on the purpose for the contract and the applicability of hedge accounting, the impact of instruments may be offset in earnings, on the balance sheet, or in other comprehensive income. The company also utilizes normal purchase or sale accounting for certain contracts.

 

The application of hedge accounting to certain derivatives and the normal purchase or sale election is made on a contract-by-contract basis. Utilizing hedge accounting or the normal purchase or sale election in a different manner could materially impact reported results of operations. The effects of derivatives' accounting have a significant impact on the balance sheet of the company but have no significant effect on its results of operations because of the principles contained in SFAS 71. Details of the company's financial instruments are discussed in Note 7 of the Notes to Consolidated Financial Statements.

 

 

 

 

 




24




Description

 

Assumptions & Approach Utilized

 

Effect if Different Assumptions Used

 

 

 

 

 

Defined Benefit Plans

 

 

 

 

The company has funded and unfunded noncontributory defined benefit plans that together cover substantially all of its employees. The company also has other postretirement benefit plans covering substantially all of its employees. The company accounts for its pension and other postretirement benefit plans under SFAS 87, Employers' Accounting for Pensions , and SFAS 106, Employers' Accounting for Postretirement Benefits Other than Pensions , respectively, and under SFAS 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R) .

 

The measurement of the company's pension and postretirement obligations, costs and liabilities is dependent on a variety of assumptions used by the company. The critical assumptions used in developing the required estimates include the following key factors: discount rate, expected return on plan assets, health-care cost trend rates, mortality rates, rate of compensation increases and payout elections (lump sum or annuity). 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 actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter participant life spans, or more or fewer lump sum versus annuity payout elections made by plan participants.


The health-care cost trend rate is 9.48 percent for 2007. Increasing the health-care cost trend rate by one percentage point would increase the accumulated obligation for postretirement benefit plans by $86 million and total service and interest cost by $10 million. Decreasing the health-care cost trend rate by one percentage point would decrease the accumulated obligation by $71 million and total service and interest cost by $8 million.


However, these differences have minimal impact on the company's net income due to rate recovery of most benefit plan costs. Additional discussion of pension plan assumptions is included in Note 5 of the Notes to Consolidated Financial Statements.


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 Sempra Energy board of directors.


Key noncash performance indicators for the company include number of customers and natural gas volumes sold. The information is provided in "Results of Operations."


NEW ACCOUNTING STANDARDS


Relevant pronouncements that have recently become effective and have had or may have a significant effect on the company's financial statements are described in Note 2 of the Notes to Consolidated Financial Statements.




25



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. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- Pacific Enterprises


MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS


Management is responsible for the preparation of the company's consolidated financial statements and related information appearing in this report. Management believes that the consolidated financial statements fairly present the form and substance of transactions and that the financial statements reasonably present the company's financial position and results of operations in conformity with accounting principles generally accepted in the United States of America. Management also has included in the company's financial statements amounts that are based on estimates and judgments, which it believes are reasonable under the circumstances.


The board of directors of Sempra Energy, the company's parent company, has an Audit Committee composed of six non-management directors. The committee meets periodically with financial management and the internal auditors to review accounting, control, auditing and financial reporting matters.



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, 2007. The effectiveness of the company’s internal control over financial reporting as of December 31, 2007, has been audited by Deloitte & Touche LLP, as stated in their report, which is included in Item 8.





26



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of Pacific Enterprises:


We have audited the internal control over financial reporting of Pacific Enterprises and subsidiaries (the "Company") as of December 31, 2007 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, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.


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, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, 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



27



ended December 31, 2007 of the Company and our report dated February 25, 2008 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company’s adoption of two new accounting standards in 2007.


/S/ DELOITTE & TOUCHE LLP


San Diego, California
February 25, 2008




28



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, 2007 and 2006, and the related statements of consolidated income, comprehensive income and changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. 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 Pacific Enterprises and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.


As discussed in Note 2 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board ("FASB") Statement No. 157, Fair Value Measurements , effective January 1, 2007 and FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 , effective January 1, 2007. As discussed in Note 5 to the consolidated financial statements, the Company adopted FASB Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R), effective December 31, 2006.


We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2007, 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 25, 2008 expressed an unqualified opinion on the Company's internal control over financial reporting.


/S/ DELOITTE & TOUCHE LLP


San Diego, California
February 25, 2008




29




PACIFIC ENTERPRISES AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

 

 

 

 

Years ended December 31,

(Dollars in millions)

 

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

4,282

 

 

$

4,181

 

 

$

4,617

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas

 

 

2,420

 

 

 

2,410

 

 

 

2,830

 

 

Other operating expenses

 

 

1,021

 

 

 

951

 

 

 

954

 

 

Depreciation

 

 

281

 

 

 

267

 

 

 

264

 

 

Franchise fees and other taxes

 

 

125

 

 

 

121

 

 

 

121

 

 

Litigation expense

 

 

1

 

 

 

(2

)

 

 

99

 

 

Gains on sale of assets

 

 

(2

)

 

 

(5

)

 

 

--

 

 

Impairment losses

 

 

--

 

 

 

--

 

 

 

2

 

 

 

Total operating expenses

 

 

3,846

 

 

 

3,742

 

 

 

4,270

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

 

436

 

 

 

439

 

 

 

347

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income (expense), net

 

 

(4

)

 

 

(2

)

 

 

5

 

Interest income

 

 

51

 

 

 

64

 

 

 

25

 

Interest expense

 

 

(76

)

 

 

(76

)

 

 

(53

)

Income before income taxes

 

 

407

 

 

 

425

 

 

 

324

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax expense

 

 

165

 

 

 

186

 

 

 

99

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

242

 

 

 

239

 

 

 

225

 

Preferred dividend requirements

 

 

4

 

 

 

4

 

 

 

4

 

Earnings applicable to common shares

 

$

238

 

 

$

235

 

 

$

221

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Consolidated Financial Statements.





30



 

PACIFIC ENTERPRISES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

December 31,

(Dollars in millions)

 

 

2007

 

2006

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

59

 

 

$

211

 

 

Accounts receivable – trade

 

 

671

 

 

 

640

 

 

Accounts receivable – other

 

 

22

 

 

 

33

 

 

Interest receivable

 

 

--

 

 

 

10

 

 

Due from unconsolidated affiliates

 

 

5

 

 

 

63

 

 

Income taxes receivable

 

 

37

 

 

 

54

 

 

Deferred income taxes

 

 

33

 

 

 

43

 

 

Inventories

 

 

98

 

 

 

106

 

 

Other regulatory assets

 

 

40

 

 

 

41

 

 

Other

 

 

23

 

 

 

17

 

 

 

Total current assets

 

 

988

 

 

 

1,218

 

 

 

 

 

 

 

 

 

 

 

 

Other assets:

 

 

 

 

 

 

 

 

 

Due from unconsolidated affiliates

 

 

457

 

 

 

448

 

 

Regulatory assets arising from pension and other

 

 

 

 

 

 

 

 

 

     postretirement benefit obligations

 

 

--

 

 

 

136

 

 

Other regulatory assets

 

 

100

 

 

 

95

 

 

Pension plan assets in excess of benefit obligations

 

 

62

 

 

 

8

 

 

Sundry

 

 

39

 

 

 

33

 

 

 

Total other assets

 

 

658

 

 

 

720

 

  

 

 

 

 

 

 

 

 

 

Property, plant and equipment:

 

 

 

 

 

 

 

 

 

 

Property, plant and equipment

 

 

 

8,448

 

 

 

8,151

 

 

Less accumulated depreciation

 

 

 

(3,292

)

 

 

(3,248

)

 

 

Property, plant and equipment, net

 

 

 

5,156

 

 

 

4,903

 

Total assets

 

$

6,802

 

 

$

6,841

 

 

 

 

 

 

 

 

 

 

See Notes to Consolidated Financial Statements.

 

 

 

 

 

 

 

 

  



31




PACIFIC ENTERPRISES AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

December 31,

(Dollars in millions)

 

2007

 

2006

 

 

 

LIABILITIES AND SHAREHOLDERS' EQUITY

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

Accounts payable – trade

 

$

300

 

 

$

416

 

 

Accounts payable – other

 

 

130

 

 

 

114

 

 

Due to unconsolidated affiliates

 

 

125

 

 

 

102

 

 

Regulatory balancing accounts, net

 

 

183

 

 

 

167

 

 

Customer deposits

 

 

90

 

 

 

88

 

 

Other

 

 

310

 

 

 

305

 

 

 

Total current liabilities

 

 

1,138

 

 

 

1,192

 

  

 

 

 

 

 

 

 

 

Long-term debt

 

 

1,113

 

 

 

1,107

 

  

 

 

 

 

 

 

 

 

Deferred credits and other liabilities:

 

 

 

 

 

 

 

 

 

Customer advances for construction

 

 

123

 

 

 

91

 

 

Pension and other postretirement benefit obligations, net of plan assets

 

 

58

 

 

 

172

 

 

Deferred income taxes

 

 

102

 

 

 

107

 

 

Deferred investment tax credits

 

 

33

 

 

 

36

 

 

Regulatory liabilities arising from removal obligations

 

 

1,187

 

 

 

1,019

 

 

Regulatory liabilities arising from pension and

 

 

 

 

 

 

 

 

 

     other postretirement benefit obligations

 

 

34

 

 

 

--

 

 

Asset retirement obligations

 

 

562

 

 

 

655

 

 

Deferred taxes refundable in rates

 

 

231

 

 

 

221

 

 

Preferred stock of subsidiary

 

 

20

 

 

 

20

 

 

Deferred credits and other

 

 

285

 

 

 

291

 

 

 

Total deferred credits and other liabilities

 

 

2,635

 

 

 

2,612

 

  

 

 

 

 

 

 

 

 

Commitments and contingencies (Note 10)

 

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

 

Shareholders' equity:

 

 

 

 

 

 

 

 

 

Preferred stock

 

 

80

 

 

 

80

 

 

Common stock (600 million shares authorized;

 

 

 

 

 

 

 

 

 

 

84 million shares outstanding; no par value)

 

 

1,462

 

 

 

1,464

 

 

Retained earnings

 

 

378

 

 

 

391

 

 

Accumulated other comprehensive income (loss)

 

 

(4

)

 

 

(5

)

 

Total shareholders' equity

 

 

1,916

 

 

 

1,930

 

Total liabilities and shareholders' equity

 

$

6,802

 

 

$

6,841

 

 

 

 

 

 

 

 

 

 

See Notes to Consolidated Financial Statements.

 

 

 

 

 

 

 

 






32



PACIFIC ENTERPRISES AND SUBSIDIARIES

 

 

 

STATEMENTS OF CONSOLIDATED CASH FLOWS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years ended December 31,

(Dollars in millions)

 

 

 

 

 

 

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

$

242

 

 

$

239

 

 

$

225

 

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation

 

 

 

281

 

 

 

267

 

 

 

264

 

 

 

 

 

Deferred income taxes and investment tax credits

 

 

 

10

 

 

 

(26

)

 

 

(14

)

 

 

 

 

Gains on sale of assets

 

 

 

(2

)

 

 

(5

)

 

 

--

 

 

 

 

 

Other

 

 

 

2

 

 

 

3

 

 

 

--

 

 

Quasi-reorganization resolution

 

 

 

--

 

 

 

12

 

 

 

--

 

 

Changes in other assets

 

 

 

4

 

 

 

(2

)

 

 

20

 

 

Changes in other liabilities

 

 

 

29

 

 

 

26

 

 

 

110

 

 

Changes in working capital components:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 

 

(31

)

 

 

52

 

 

 

(41

)

 

 

 

Interest receivable

 

 

 

10

 

 

 

(1

)

 

 

22

 

 

 

 

Inventories

 

 

 

8

 

 

 

18

 

 

 

(49

)

 

 

 

Other current assets

 

 

 

(2

)

 

 

(7

)

 

 

(1

)

 

 

 

Accounts payable

 

 

 

(79

)

 

 

83

 

 

 

49

 

 

 

 

Income taxes

 

 

 

42

 

 

 

113

 

 

 

(136

)

 

 

 

Due to/from affiliates, net

 

 

 

4

 

 

 

(19

)

 

 

(4

)

 

 

 

Regulatory balancing accounts

 

 

 

(13

)

 

 

185

 

 

 

(168

)

 

 

 

Customer deposits

 

 

 

3

 

 

 

8

 

 

 

31

 

 

 

 

Other current liabilities

 

 

 

(17

)

 

 

(35

)

 

 

(20

)

 

 

 

 

Net cash provided by operating activities

 

 

 

491

 

 

 

911

 

 

 

288

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Expenditures for property, plant and equipment

 

 

 

(457

)

 

 

(413

)

 

 

(361

)

 

Increase in loans to affiliates, net

 

 

 

(34

)

 

 

(145

)

 

 

(19

)

 

Proceeds from sale of assets

 

 

 

2

 

 

 

11

 

 

 

--

 

 

Other

 

 

 

--

 

 

 

(1

)

 

 

(1

)

 

 

 

Net cash used in investing activities

 

 

 

(489

)

 

 

(548

)

 

 

(381

)

  

 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common dividends paid

 

 

 

(150

)

 

 

(150

)

 

 

(150

)

 

Preferred dividends paid

 

 

 

(4

)

 

 

(4

)

 

 

(4

)

 

Issuances of long-term debt

 

 

 

--

 

 

 

--

 

 

 

250

 

 

Increase (decrease) in short-term debt

 

 

 

--

 

 

 

(88

)

 

 

58

 

 

Other

 

 

 

--

 

 

 

--

 

 

 

(5

)

 

 

 

Net cash provided by (used in) financing activities

 

 

 

(154

)

 

 

(242

)

 

 

149

 

Increase (decrease) in cash and cash equivalents

 

 

 

(152

)

 

 

121

 

 

 

56

 

Cash and cash equivalents, January 1

 

 

 

211

 

 

 

90

 

 

 

34

 

Cash and cash equivalents, December 31

 

 

$

59

 

 

$

211

 

 

$

90

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Consolidated Financial Statements.

 

 

 

 

 

 

 

 

 

 

 

 

 







33



PACIFIC ENTERPRISES AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years ended December 31,

(Dollars in millions)

 

 

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SUPPLEMENTAL DISCLOSURE OF CASH FLOW

 

 

 

 

 

 

 

 

 

 

 

 

INFORMATION

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest payments, net of amounts capitalized

$

72

 

 

$

69

 

 

$

45

 

 

 

Income tax payments, net of refunds

$

114

 

 

$

99

 

 

$

248

 


SUPPLEMENTAL SCHEDULE OF NONCASH

 

 

 

 

 

 

 

 

 

 

 

 

INVESTING ACTIVITY

 

 

 

 

 

 

 

 

 

 

 

 

    Increase in accounts payable for investments in property, plant and equipment

$

5

 

 

$

4

 

 

$

7

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Consolidated Financial Statements.

 

 

 

 

 

 

 

 

 

 

 

 

 





34



PACIFIC ENTERPRISES AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME AND CHANGES IN SHAREHOLDERS' EQUITY

Years ended December 31, 2007, 2006 and 2005

 

 

 

 

 

 

 

 


(Dollars in millions)

 

Comprehensive Income

 

Preferred Stock

 

Common Stock

 

Retained Earnings

 

Accumulated Other Comprehensive Income (Loss)

 

Total Shareholders' Equity

 

Balance at December 31, 2004

 

 

 

$ 80

 

$ 1,453

 

$ 285

 

$ (4

)

$ 1,814

 

Net income

 

$ 225

 

 

 

 

 

225

 

 

 

225

 

    Pension adjustment

 

(1

)

 

 

 

 

 

 

(1

)

(1

)

Comprehensive income

 

$ 224

 

 

 

 

 

 

 

 

 

 

 

Preferred stock dividends declared    

 

 

 

 

 

 

 

(4

)

 

 

(4

)

Common stock dividends declared    

 

 

 

 

 

 

 

(200

)

 

 

(200

)

Balance at December 31, 2005

 

 

 

80

 

1,453

 

306

 

(5

)

1,834

 

Net income

 

$ 239

 

 

 

 

 

239

 

 

 

239

 

    Pension adjustment

 

2

 

 

 

 

 

 

 

2

 

2

 

Comprehensive income   

 

$ 241

 

 

 

 

 

 

 

 

 

 

 

Adoption of FASB Statement No. 158

 

 

 

 

 

 

 

 

 

(2

)

(2

)

Quasi-reorganization adjustment

 

 

 

 

 

11

 

 

 

 

 

11

 

Preferred stock dividends declared

 

 

 

 

 

 

 

(4

)

 

 

(4

)

Common stock dividends declared

 

 

 

 

 

 

 

(150

)

 

 

(150

)

Balance at December 31, 2006

 

 

 

80

 

1,464

 

391

 

(5

)

1,930

 

Adoption of  FIN 48

 

 

 

 

 

 

 

(1

)

 

 

(1

)

Net income

 

$ 242

 

 

 

 

 

242

 

 

 

242

 

    Financial instruments

 

1

 

 

 

 

 

 

 

1

 

1

 

Comprehensive income

 

$ 243

 

 

 

 

 

 

 

 

 

 

 

Quasi-reorganization adjustment

 

 

 

 

 

(2

)

 

 

 

 

(2

)

Preferred stock dividends declared    

 

 

 

 

 

 

 

(4

)

 

 

(4

)

Common stock dividends declared

 

 

 

 

 

 

 

(250

)

 

 

(250

)

Balance at December 31, 2007

 

 

 

$ 80

 

$ 1,462

 

$ 378

 

$ (4

)

$ 1,916

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Consolidated Financial Statements.

 

 

 

 

 

 

 

 





35


PACIFIC ENTERPRISES AND SUBSIDIARIES

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) and its subsidiary, Southern California Gas Company (SoCalGas) (collectively referred to as the company or the companies). 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. All material intercompany accounts and transactions have been eliminated.


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 Sempra Utilities.


As a subsidiary, the company receives certain services from Sempra Energy, for which it is charged its allocable share of the cost of such services. Management believes that the cost is reasonable and probably less than if the company had to provide those services itself.


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 2006, resulting in increases in common equity. Cash received in 2006 from the resolution of an insurance claim related to quasi-reorganization issues was reported in Quasi-Reorganization Resolution on the Statements of Consolidated Cash Flows. An adjustment to the liabilities in 2007 resulted in a decrease to equity. The remaining liabilities of $16 million 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 ultimately may differ significantly from those estimates.





36


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).


The company prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 71 , Accounting for the Effects of Certain Types of Regulation (SFAS 71), 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. 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, 2007, represent net payables (payables net of receivables) that are returned to customers through the reduction of future rates.

 

Except for certain costs subject to balancing account treatment, fluctuations in most operating and maintenance accounts from forecasted amounts approved by the CPUC in establishing rates affect utility earnings. Balancing accounts provide a mechanism for charging utility customers, over time, 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' commodity volumes and 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 9.


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:


(Dollars in millions)

 

 

2007

 

 

 

2006

 

Fixed-price contracts and other derivatives

 

$

(1

)

 

$

(1

)

Environmental costs

 

 

43

 

 

 

39

 

Unamortized loss on reacquired debt, net

 

 

34

 

 

 

37

 

Removal obligations*

 

 

(1,187

)

 

 

(1,019

)

Deferred taxes refundable in rates

 

 

(231

)

 

 

(221

)

Employee benefit costs

 

 

41

 

 

 

36

 

Pension and other postretirement benefit obligations

 

 

(34

)

 

 

136

 

Other

 

 

22

 

 

 

24

 

 

Total

 

$

(1,313

)

 

$

(969

)

*

This is related to SFAS 143, Accounting for Asset Retirement Obligations, which is discussed below in "Asset Retirement Obligations."





37


Net regulatory assets (liabilities) are recorded on the Consolidated Balance Sheets at December 31 as follows:


(Dollars in millions)

 

 

2007

 

 

 

2006

 

Current regulatory assets

 

$

40

 

 

$

41

 

Noncurrent regulatory assets

 

 

100

 

 

 

231

 

Current regulatory liabilities*

 

 

(1

)

 

 

(1

)

Noncurrent regulatory liabilities

 

 

(1,452

)

 

 

(1,240

)

 

Total

 

$

(1,313

)

 

 

(969

)

* Included in Other Current Liabilities.


Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from natural gas transportation contracts. The regulatory asset is reduced as payments are made for services under these contracts. SoCalGas expects to recover net regulatory assets related to deferred income taxes over the lives of the assets that give rise to the accumulated deferred income taxes. The regulatory assets related to unamortized losses on reacquired debt are being recovered over the remaining original amortization periods of the loss on reacquired debt over periods ranging from 5 to 18 years. SoCalGas’ regulatory asset related to environmental remediation represents the portion of the company’s environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. This amount is expected to be recovered in future rates as expenditures are made. Regulatory liabilities related to pension and other postretirement benefit obligations are offset by corresponding assets and are being recovered in rates as the costs are incurred.


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.


Collection Allowances


The allowance for doubtful accounts was $5 million, $4 million and $6 million at December 31, 2007, 2006 and 2005, respectively. The company recorded provisions for doubtful accounts of $11 million, $11 million and $10 million in 2007, 2006 and 2005, respectively. The company wrote off doubtful accounts of $10 million, $13 million and $9 million in 2007, 2006 and 2005, respectively.


Inventories


At December 31, 2007, inventory shown on the Consolidated Balance Sheets included natural gas of $80 million, and materials and supplies of $18 million. The corresponding balances at December 31, 2006 were $89 million and $17 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.





38


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 (SFAS 109), 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 require regulated enterprises to recognize 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.


Note 2 describes the impact of the adoption of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 .


Property, Plant and Equipment


Property, plant and equipment primarily represents the buildings, equipment and other facilities used by the company to provide natural gas services.


The cost of plant includes labor, materials, and contract services. Maintenance costs are expensed as incurred. In addition, the cost of plant includes an allowance for funds used during construction (AFUDC), as discussed below. The cost of most retired depreciable utility plant minus salvage value is charged to accumulated depreciation.


Property, plant and equipment balances by major functional categories are as follows:


 

Property, Plant and Equipment at

 

Depreciation rates
for the years ended

 

December 31,

 

December 31,

(Dollars in billions)

2007

2006

 

2007

 

2006

 

2005

 

Natural gas operations

$

8.2

$

8.0

 

3.63

%

 3.58

%

3.69

%

Construction work in progress

 

0.2

 

0.2

 

NA

 

NA

 

NA

 

 

Total

$

8.4

$

8.2

 

 

 

 

 

 

 


Depreciation expense is based on the straight-line method over the useful lives of the assets, or a shorter period prescribed by the CPUC.


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 expense and partly as a component of Other Income, Net in the Statements of Consolidated Income. AFUDC amounted to $7 million, $8 million and $7 million for 2007, 2006 and 2005, respectively.

 

Asset Retirement Obligations


The company accounts for its tangible long-lived assets under SFAS 143, Accounting for Asset Retirement Obligations (SFAS 143), and FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of SFAS 143 (FIN 47). SFAS 143 and FIN 47 require the company to record an asset retirement obligation for the present value of liabilities of future costs expected to be incurred when assets are retired from service, if the retirement process is legally required and if a




39


reasonable estimate of fair value can be made. 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. Rate-regulated entities may recognize regulatory assets or liabilities as a result of the timing difference between the recognition of costs as recorded in accordance with SFAS 143 and FIN 47, and costs recovered through the rate-making process. A regulatory liability has been recorded to reflect that the company has collected the funds from customers more quickly than SFAS 143 and FIN 47 would accrete the retirement liability and depreciate the asset.


The company has recorded asset retirement obligations related to fuel storage tanks, underground natural gas storage facilities and wells, hazardous waste storage facilities, asbestos-containing construction materials, the California natural gas transmission pipeline and natural gas distribution systems assets.


The changes in asset retirement obligations for the years ended December 31, 2007 and 2006 are as follows:


(Dollars in millions)

2007

2006

Balance as of January 1*

 

 

$

669

 

$

505

 

Accretion expense

 

 

 

41

 

 

32

 

Liabilities incurred

 

 

 

1

 

 

--

 

Payments

 

 

 

 (1

)

 

--

 

Revision to estimated cash flows

 

 

 

(133

)

 

132

 

Balance as of December 31*

 

 

$

577

 

$

669

 

*

The current portion of the obligation is included in Other Current Liabilities on the Consolidated Balance Sheets.


Legal Fees


Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred.


In connection with charges related to litigation, the significant instances of which are discussed in Note 10, 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.


Comprehensive Income


Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including amortization of net actuarial loss and prior service cost related to pension and other postretirement benefits plans, and changes in minimum pension liability. The components of other comprehensive income, which consist of all these changes other than net income as shown on the Statements of Consolidated Income, are shown in the Statements of Consolidated Comprehensive Income and Changes in Shareholders' Equity.





40


The components of Accumulated Other Comprehensive Income (Loss), net of income taxes, at December 31, 2007 and 2006 are as follows:


(Dollars in millions)

 2007

 2006

Unamortized net actuarial loss, net of $4 and $4 income tax benefit,

 

 

$

(6

)

$

(6

)

 

respectively

Unamortized prior service credit, net of $1 and $1 income tax expense,

 

 

 

1

 

 

1

 

 

respectively

Financial instruments, net of $1 income tax expense

 

 

 

1

 

 

--

 

Balance as of December 31

 

 

$

(4

)

$

(5

)


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 and performance. 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 15 years. Operating revenues include amounts for services rendered but unbilled (approximately one-half month's deliveries) at the end of each year. The company presents its operating revenues net of sales taxes.


Additional information concerning utility revenue recognition is discussed above under "Regulatory Matters."


Other Operating Expenses


Other operating expenses include operating and maintenance costs, and general and administrative costs, consisting primarily of personnel costs, purchased materials and services and outside services.


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.


PE had intercompany receivables of $5 million due from other affiliates at December 31, 2007. PE had intercompany receivables of $58 million from Sempra Energy at December 31, 2006, which are net of dividends payable to Sempra Energy discussed below, and $5 million from various affiliates at December 31, 2006. Such amounts are included in current assets as Due from Unconsolidated Affiliates.


SoCalGas had intercompany receivables due from Sempra Energy of $129 million and $108 million at December 31, 2007 and 2006, respectively, which are shown net of amounts due to Sempra Energy at PE.


PE also has a promissory note due from Sempra Energy which bears a variable interest rate based on short-term commercial paper rates (4.48 percent at December 31, 2007). The balances of the note were $457 million and $448 million at December 31, 2007 and 2006, respectively, and are included in noncurrent assets as Due from Unconsolidated Affiliates.


In addition, PE had intercompany payables due to various affiliates of $103 million and $102 million at December 31, 2007 and 2006, respectively. Of the total balances, $21 million and $24 million were recorded at SoCalGas at December 31, 2007 and 2006, respectively. PE had an intercompany payable to Sempra Energy for $22 million at December 31, 2007 which includes the dividend payable to Sempra




41


Energy discussed below, and is shown net of intercompany receivables from Sempra Energy. These amounts are reported in current liabilities as Due to Unconsolidated Affiliates.


PE also had dividends payable to Sempra Energy of $150 million and $50 million at December 31, 2007 and 2006, respectively, which were due and paid on January 15, 2008 and 2007, respectively.


SoCalGas also had dividends payable to PE of $150 million and $50 million at December 31, 2007 and 2006, respectively, which were due and paid on January 15, 2008 and 2007, respectively.


Dividends


The CPUC's regulation of the company's capital structure limits the amounts that are available for dividends and loans to Sempra Energy. At December 31, 2007, SoCalGas could have provided a total of $30 million to Sempra Energy through dividends and loans.


Capitalized Interest


SoCalGas recorded $3 million, $3 million and $2 million of capitalized interest for 2007, 2006 and 2005, respectively, including the portion of AFUDC related to debt.


Other Income (Expense) , Net


Other Income (Expense), Net consists of the following:


 

 

 

 

 

 

 

 

 

 

 

 

Years ended December 31,

(Dollars in millions)

 

 

 

 

 

 

 

2007

 

2006

 

2005

Regulatory interest, net

 

 

$

(6

)

 

$

(6

)

 

$

(3

)

Allowance for equity funds used during construction

 

 

 

5

 

 

 

6

 

 

 

5

 

Sundry, net

 

 

 

(2

)

 

 

(1

)

 

 

(4

)

 

Total at SoCalGas

 

 

 

 

 

 

 

(3

)

 

 

(1

)

 

 

(2

)

Additional at Pacific Enterprises:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sundry, net

 

 

 

 

 

 

 

--

 

 

 

--

 

 

 

8

 

Reclassification of preferred dividends

 

 

 

(1

)

 

 

(1

)

 

 

(1

)

 

Total at Pacific Enterprises

 

 

 

 

 

 

$

(4

)

 

$

(2

)

 

$

5

 


NOTE 2. NEW ACCOUNTING STANDARDS


Pronouncements that have recently become effective that have had or may have a significant effect on the company's financial statements are described below.


SFAS 157, "Fair Value Measurements" (SFAS 157): SFAS 157 defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not expand the application of fair value accounting to any new circumstances. The company applies recurring fair value measurements to certain assets and liabilities, primarily commodity and other derivatives.


SFAS 157: (1) establishes that fair value is based on a hierarchy of inputs into the valuation process (as described in Note 7), (2) clarifies that an issuer's credit standing should be considered when measuring liabilities at fair value, (3) precludes the use of a liquidity or blockage factor discount when measuring instruments traded in an actively quoted market at fair value, and (4) requires costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred. SFAS 157 requires that a fair value measurement reflect the assumptions market participants would use in pricing an asset or liability




42


based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model.


The provisions of SFAS 157 are to be applied prospectively, except for the initial impact on three specific items: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under Emerging Issues Task Force Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, (2) existing hybrid financial instruments measured initially at fair value using the transaction price and (3) blockage factor discounts. Adjustments to these items required under SFAS 157 are to be recorded as a transition adjustment to beginning retained earnings in the year of adoption.


The company elected to early-adopt SFAS 157 in the first quarter of 2007. There was no transition adjustment as a result of the company's adoption of SFAS 157. SFAS 157 also requires new disclosures regarding the level of pricing observability associated with financial instruments carried at fair value. This additional disclosure is provided in Note 7.


SFAS 159, "The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115" (SFAS 159): SFAS 159 allows measurement at fair value of eligible financial assets and liabilities that are not otherwise measured at fair value. If the fair value option for an eligible item is elected, unrealized gains and losses for that item are reported in current earnings at each subsequent reporting date. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between the different measurement attributes the company elects for similar types of assets and liabilities. This statement is effective for fiscal years beginning after November 15, 2007. The company does not anticipate electing the fair value option at the adoption of SFAS 159 for its eligible financial assets or liabilities.


SFAS 160, "Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51" (SFAS 160): SFAS 160 amends Accounting Research Bulletin (ARB) 51, Consolidated Financial Statements, to establish accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. This statement also requires disclosures that clearly identify and distinguish between the interest of the parent and the interest of the noncontrolling owners. SFAS 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. SFAS 160 requires retroactive application for the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 shall be applied prospectively. The company is in the process of evaluating the effect of this statement on its financial position and results of operations.


SFAS 141 (revised 2007), "Business Combinations" (SFAS 141R): SFAS 141R applies to all transactions or events in which an entity obtains control of one or more businesses, including those combinations achieved without transfer or consideration. In the context of a business combination, SFAS 141R establishes principles and requirements for how the acquirer recognizes assets acquired including goodwill, liabilities assumed, noncontrolling interest in the acquiree, contractual contingencies and contingent consideration measured at fair value. SFAS 141R requires that the acquirer in a business combination achieved in stages recognize identifiable assets and liabilities at the full amounts of their fair values. This statement also establishes disclosure requirements that will enable users to evaluate the nature and financial effect of the business combination. SFAS 141R applies prospectively to business




43


combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Early adoption is prohibited.


FIN 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" (FIN 48): FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with SFAS 109. FIN 48 addresses how an entity should recognize, measure, classify and disclose in its financial statements uncertain tax positions that it has taken or expects to take in an income tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Additionally, the FASB issued FASB Staff Position (FSP) FIN 48-1, Definition of Settlement in FASB Interpretation No. 48 , which amends FIN 48 to provide guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. The company's implementation of FIN 48 as of January 1, 2007 was consistent with the guidance in this FSP.


The company adopted the provisions of FIN 48 on January 1, 2007 and SoCalGas recognized a $1 million decrease in retained earnings. Including this adjustment, the companies had unrecognized tax benefits of $33 million (of which $32 million applied to SoCalGas) as of January 1, 2007. Of this amount, $26 million (of which $25 million applied to SoCalGas) related to tax positions that, if recognized, would decrease the effective tax rate; however, $21 million (all of which applied to SoCalGas) related to tax positions that would increase the effective tax rate in subsequent years.


As of December 31, 2007, the companies had unrecognized tax benefits of $40 million (all of which applied to SoCalGas). Of this amount, $22 million related to tax positions that, if recognized, would decrease the effective tax rate; however, $21 million related to tax positions that would increase the effective tax rate in subsequent years.


A reconciliation of the companies' unrecognized tax benefits from January 1, 2007 to December 31, 2007 is provided in the following table:


(Dollars in millions)

 

 

 

 

2007

 

Balance as of January 1, 2007

 

 

 

$

33

 

 

Increase in prior period tax positions

 

 

 

 

12

 

 

Decrease in prior period tax positions

 

 

 

 

(2

)

 

Settlements with taxing authorities

 

 

 

 

(3

)

Balance as of December 31, 2007

 

 

 

$

40

 


It is reasonably possible that the companies' unrecognized tax benefits could decrease by up to $3 million within the next 12 months due to the expiration of statutes of limitations on tax assessments, by up to $22 million due to the potential resolution of audit issues with various federal and state taxing authorities, and by up to $10 million due to the impact of federal and state timing items affecting taxable income.


Effective January 1, 2007, the companies' policy is to recognize accrued interest and penalties on accrued tax balances as components of tax expense. Prior to the adoption of FIN 48, the companies accrued interest expense and penalties as components of tax expense and interest income as a component of interest income. As of January 1, 2007, the companies had accrued a total of $2 million (all of which applied to SoCalGas) of such interest expense. As of December 31, 2007, the companies had accrued a total of $3 million of interest expense (all of which applied to SoCalGas). The companies had no accrued penalties as of either January 1, 2007 or December 31, 2007. Amounts accrued for interest expense associated with income taxes are included in income tax expense on the Statements of Consolidated Income and in various income tax balances on the Consolidated Balance Sheets.





44


The companies are subject to U.S. federal income tax as well as income tax of state jurisdictions. The companies remain subject to examination by U.S. federal and major state tax jurisdictions only for years after 2001.


In addition, the companies have filed federal and state refund claims for tax years back to 1998. The pre-2002 tax years are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these years.


NOTE 3. 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 a 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, 2007, SoCalGas had no amounts outstanding under this facility.


Long-Term Debt


 

 

 

December 31,

 

(Dollars in millions)

 

 

2007

 

 

 

2006

 

First mortgage bonds:

 

 

 

 

 

 

 

 

 

Variable rate (5.29% at December 31, 2007) December 1, 2009

 

$

100

 

 

$

100

 

 

4.375% January 15, 2011

 

 

100

 

 

 

100

 

 

Variable rates after fixed-to-floating rate swaps

 

 

 

 

 

 

 

 

 

(3.88% at December 31, 2007) January 15, 2011

 

 

150

 

 

 

150

 

 

4.8% October 1, 2012

 

 

250

 

 

 

250

 

 

5.45% April 15, 2018

 

 

250

 

 

 

250

 

 

5.75% November 15, 2035

 

 

250

 

 

 

250

 

 

 

 

1,100

 

 

 

1,100

 

Other long-term debt:

 

 

 

 

 

 

 

 

 

4.75% May 14, 2016

 

 

8

 

 

 

8

 

 

5.67% January 18, 2028

 

 

5

 

 

 

5

 

 

 

 

 

13

 

 

 

13

 

Market value adjustments for interest rate swaps - net

 

 

2

 

 

 

(3

)

 

 

 

1,115

 

 

 

1,110

 

Unamortized discount on long-term debt

 

 

(2

)

 

 

(3

)

Total

 

$

1,113

 

 

$

1,107

 


Excluding market value adjustments for interest-rate swaps, maturities of long-term debt are:


(Dollars in millions)

 

 

2008

$

--

2009

 

100

2010

 

--

2011

 

250

2012

 

250

Thereafter

 

513

Total

$

1,113




45


Callable Long-Term Debt


At the company's option, $8 million of bonds are callable after 2012. In addition, $1 billion of bonds are 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 $505 million of first mortgage bonds at December 31, 2007.


Unsecured Long-Term Debt


Various long-term obligations totaling $13 million at December 31, 2007 are unsecured.


Interest-Rate Swaps


The company's fair value interest-rate swaps and interest-rate swaps to hedge cash flows are discussed in Note 7.

 

NOTE 4. INCOME TAXES


Reconciliations of the U.S. statutory federal income tax rate to the effective income tax rate are as follows:


 

 

 

 

Years ended December 31,

 

 

 

 

2007

 

 

 

2006

 

 

 

2005

 

Statutory federal income tax rate

 

 

35

%

 

 

35

%

 

 

35

%

Depreciation

 

 

6

 

 

 

6

 

 

 

8

 

State income taxes, net of federal income tax benefit

 

 

5

 

 

 

6

 

 

 

5

 

Tax credits

 

 

(1

)

 

 

(1

)

 

 

(1

)

Resolution of Internal Revenue Service audits

 

 

--

 

 

 

1

 

 

 

(6

)

Utility repair allowance

 

 

(1

)

 

 

(1

)

 

 

(4

)

Other, net

 

 

(3

)

 

 

(2

)

 

 

(6

)

 

Effective income tax rate

 

 

41

%

 

 

44

%

 

 

31

%





46


The components of income tax expense are as follows:


 

 

 

 

Years ended December 31,

 

(Dollars in millions)

 

 

2007

 

 

 

2006

 

 

 

2005

 

Current:

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal

 

$

122

 

 

$

168

 

 

$

89

 

 

State

 

 

33

 

 

 

44

 

 

 

24

 

 

Total

 

 

155

 

 

 

212

 

 

 

113

 

Deferred:

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal

 

 

15

 

 

 

(17

)

 

 

(5

)

 

State

 

 

(2

)

 

 

(6

)

 

 

(6

)

 

Total

 

 

13

 

 

 

(23

)

 

 

(11

)

Deferred investment tax credits

 

 

(3

)

 

 

(3

)

 

 

(3

)

Total income tax expense

 

$

165

 

 

$

186

 

 

$

99

 


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, 2007, income taxes of $4 million were payable to Sempra Energy.


Accumulated deferred income taxes at December 31 relate to the following:


(Dollars in millions)

 

 

2007

 

 

 

2006

 

Deferred tax liabilities:

 

 

 

 

 

 

 

 

 

Differences in financial and tax bases of utility plant and other assets

 

$

206

 

 

$

220

 

 

Regulatory balancing accounts

 

 

79

 

 

 

119

 

 

Loss on reacquired debt

 

 

14

 

 

 

15

 

 

Property taxes

 

 

12

 

 

 

12

 

 

Other

 

 

3

 

 

 

3

 

 

Total deferred tax liabilities

 

 

314

 

 

 

369

 

Deferred tax assets:

 

 

 

 

 

 

 

 

 

Other accruals not yet deductible

 

 

99

 

 

 

114

 

 

Postretirement benefits

 

 

48

 

 

 

90

 

 

Investment tax credits

 

 

23

 

 

 

25

 

 

Compensation-related items

 

 

45

 

 

 

43

 

 

State income taxes

 

 

19

 

 

 

23

 

 

Other

 

 

11

 

 

 

10

 

 

Total deferred tax assets

 

 

245

 

 

 

305

 

Net deferred income tax liability

 

$

69

 

 

$

64

 


The net deferred income tax liability is recorded on the Consolidated Balance Sheets at December 31 as follows:


(Dollars in millions)

 

 

2007

 

 

 

2006

 

Current asset

 

$

(33

)

 

$

(43

)

Noncurrent liability

 

 

102

 

 

 

107

 

Total

 

$

69

 

 

$

64

 


The impact of the company’s adoption of FIN 48 is discussed in Note 2.





47


NOTE 5. EMPLOYEE BENEFIT PLANS


The company accounts for its employee benefit plans in accordance with SFAS 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106 and 132(R) (SFAS 158), which requires an employer to recognize in its statement of financial position an asset for a plan's overfunded status or a liability for a plan's underfunded status, measure a plan's assets and its obligations that determine its funded status as of the end of the company's fiscal year (with limited exceptions), and recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. Generally, those changes are reported in the company's comprehensive income and as a separate component of shareholders' equity.


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 uses a December 31 measurement date for all of its plans.


Effective January 1, 2008, the pension plan was amended to increase the death benefit for beneficiaries of vested non-represented participants that die prior to retirement. This amendment resulted in a $1 million increase in the benefit obligation and unrecognized prior service costs as of December 31, 2007.


Effective January 1, 2008, the company’s other postretirement benefit plan was amended to provide a health benefit for both represented and non-represented participants that are surviving spouses over the age of 65. This amendment resulted in an $18 million increase in the benefit obligation and unrecognized prior service costs as of December 31, 2007.


Effective March 1, 2007, the pension plan for the non-represented employees of SoCalGas was amended to change the calculation of the benefit for certain participants. The affected participants are those who had an accrued benefit under the plan at the date the plan transitioned from a traditional defined benefit plan to a cash balance plan. The transition date for participants was July 1, 1998. Before the amendment date, these participants received the greater of their accrued benefit in the cash balance plan or the present value of their benefit under the prior plan as of June 30, 2003. After the amendment date, they receive the greater of the accrued benefit under the cash balance plan, or the present value of their accrued benefit under the prior plan at June 30, 2003 plus the cash balance benefit accrued after that date. This amendment resulted in a $21 million increase in the company’s benefit obligation and in the unrecognized prior service cost at the end of 2006.





48


In the third quarter of 2006, the Pension Protection Act of 2006 was enacted. This act increases the funding requirements for qualified pension plans beginning in 2008. It also changes certain costs of providing pension benefits, including the interest rate for benefits paid as lump sums and the level of benefits that may be provided through qualified pension plans. The $56 million decrease in the company’s pension obligation due to the plan changes required by this legislation were recognized in the benefit obligation and in the unrecognized prior service cost at the end of 2006.


Effective January 1, 2006, the pension plan for the non-represented employees of SoCalGas was amended to include deferred compensation, beginning January 1, 2006, in pension-eligible earnings. Also effective January 1, 2006, the company’s pension plan for non-represented employees was amended to change the early retirement requirements. The service requirement necessary to qualify for early retirement was changed from 15 years to 10 years for participants in that plan that had an accrued benefit in the company’s prior pension plan as of June 30, 2003. These two changes resulted in a net $1 million increase in the company’s benefit obligation and in the unrecognized prior service cost at the end of 2006.


Effective January 1, 2006, the other postretirement benefit plans for non-represented employees at SoCalGas were amended to integrate the benefits plan design across the Sempra Utilities, resulting in a $58 million decrease in the benefit obligation as of December 31, 2005.


The company's pension plan was amended effective January 1, 2005, to increase the pension formula for service credit in excess of 30 years resulting in an increase in the pension benefit obligation of $3 million.


The following table provides a reconciliation of the changes in the plans' projected benefit obligations and the fair value of assets during the latest two years, and a statement of the funded status as of the latest two year ends:




49



 



Pension Benefits

 

Other
 Postretirement
Benefits

 

(Dollars in millions)

 

2007

 

 

2006

 

 

2007

 

 

2006

 

CHANGE IN PROJECTED BENEFIT OBLIGATION:

 

 

 

 

 

 

 

 

 

 

 

 

Net obligation at January 1

$

1,692

 

$

1,767

 

$

776

 

$

708

 

Service cost

 

41

 

 

40

 

 

19

 

 

17

 

Interest cost

 

95

 

 

95

 

 

44

 

 

36

 

Plan amendments

 

1

 

 

(34

)

 

18

 

 

--

 

Actuarial loss (gain)

 

(51

)

 

(52

)

 

(127

)

 

48

 

Transfer of liability from Sempra Energy

 

--

 

 

1

 

 

--

 

 

--

 

Benefit payments

 

(154

)

 

(125

)

 

(38

)

 

(35

)

Federal subsidy (Medicare Part D)

 

--

 

 

--

 

 

2

 

 

2

 

Net obligation at December 31

 

1,624

 

 

1,692

 

 

694

 

 

776

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CHANGE IN PLAN ASSETS:

 

 

 

 

 

 

 

 

 

 

 

 

Fair value of plan assets at January 1

 

1,672

 

 

1,573

 

 

630

 

 

569

 

Actual return on plan assets

 

137

 

 

222

 

 

43

 

 

77

 

Employer contributions

 

1

 

 

1

 

 

28

 

 

19

 

Transfer of assets from Sempra Energy

 

1

 

 

1

 

 

--

 

 

--

 

Benefit payments

 

(154

)

 

(125

)

 

(38

)

 

(35

)

Fair value of plan assets at December 31

 

1,657

 

 

1,672

 

 

663

 

 

630

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Funded status at December 31

$

33

 

$

(20

)

$

(31

)

$

(146

)

Net recorded asset (liability) at December 31

$

33

 

$

(20

)

$

(31

)

$

(146

)


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 included in the following captions on the Consolidated Balance Sheets at December 31 as follows:


 

Pension Benefits

 

Other
Postretirement Benefits

 

(Dollars in millions)

 

2007

 

 

2006

 

 

2007

 

 

2006

 

Noncurrent assets

$

62

 

$

8

 

$

--

 

$

--

 

Current liabilities

 

(2

)

 

(2

)

 

--

 

 

--

 

Noncurrent liabilities

 

(27

)

 

(26

)

 

(31

)

 

(146

)

Net recorded asset (liability)

$

33

 

$

(20

)

$

(31

)

$

(146

)





50


Amounts recorded in Accumulated Other Comprehensive Income (Loss) as of December 31, 2007 and 2006, net of tax effects and amounts recorded as regulatory assets, are as follows:


 

 

 

 

 

 

 

 

Pension Benefits

 

(Dollars in millions)

 

2007

 

 

2006

 

Net actuarial loss

$

6

 

$

6

 

Prior service credit

 

(1

)

 

(1

)

Total

$

5

 

$

5

 

 

 

 

 

 

 

 


The company has an unfunded and a funded pension plan. At December 31, 2007 and 2006, the funded plan had assets in excess of projected benefit obligations.


The following table provides the components of net periodic benefit cost and amounts recognized in other comprehensive income for the years ended December 31:


 

 

 

 

Other

 

 

Pension Benefits

 

Postretirement Benefits

 

(Dollars in millions)

 

2007

 

 

2006

 

 

2005

 

 

2007

 

 

2006

 

 

2005

 

Net Periodic Benefit Cost

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Service cost

$

41

 

$

40

 

$

36

 

$

19

 

$

17

 

$

18

 

Interest cost

 

96

 

 

95

 

 

95

 

 

44

 

 

36

 

 

41

 

Expected return on assets

 

(102

)

 

(98

)

 

(98

)

 

(40

)

 

(37

)

 

(37

)

Amortization of:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prior service cost (credit)

 

2

 

 

7

 

 

7

 

 

(6

)

 

(6

)

 

--

 

 

Actuarial loss

 

1

 

 

5

 

 

9

 

 

6

 

 

3

 

 

6

 

Regulatory adjustment

 

(36

)

 

(46

)

 

(47

)

 

5

 

 

5

 

 

8

 

Transfer of retirees

 

--

 

 

--

 

 

18

 

 

--

 

 

--

 

 

(9

)

Total net periodic benefit cost

 

2

 

 

3

 

 

20

 

 

28

 

 

18

 

 

27

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amortization of actuarial loss

 

(1

)

 

--

 

 

--

 

 

--

 

 

--

 

 

--

 

 

Total recognized in other comprehensive income

 

(1

)

 

--

 

 

--

 

 

--

 

 

--

 

 

--

 

 

Total recognized in net periodic benefit cost and other comprehensive income

$

1

 

$

3

 

$

20

 

$

28

 

$

18

 

$

27

 


The estimated net loss and prior service credit for the pension plans that will be amortized from Accumulated Other Comprehensive Income (Loss) into net periodic benefit cost in 2008 are both negligible amounts.


The Medicare Prescription Drug, Improvement and Modernization Act of 2003 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 determined that benefits provided to certain participants actuarially will be at least equivalent to Medicare Part D, and, accordingly, the company is entitled to a tax-exempt subsidy that reduced the company's accumulated postretirement benefit obligation under the plan at January 1, 2007 by $77 million and reduced the net periodic cost for 2007 by $9 million.





51


The significant assumptions related to the company's pension and other postretirement benefit plans are as follows:


 

 

 

 

 

 

 

Other

 

 

Pension Benefits

 

Postretirement Benefits

 

 

 

2007

 

 

2006

 

 

2007

 

 

2006

 

WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE BENEFIT OBLIGATION AS OF DECEMBER 31:

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

6.10%

 

 

5.75%

 

 

6.20%

 

 

5.85%

 

Rate of compensation increase

 

4.50%

 

 

4.50%

 

 

4.00%

 

 

4.50%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COSTS FOR THE YEARS ENDED DECEMBER 31:

 

 

 

 

 

 

 

 

 

 

 

 

Discount rate

 

5.75%

 

 

5.50%

 

 

5.85%

 

 

5.60%

 

Expected return on plan assets

 

7.00%

 

 

7.00%

 

 

7.00%

 

 

7.00%

 

Rate of compensation increase

 

    *

 

 

  *

 

 

     **

 

 

     **

 

*

4.50% for non-qualified pension plans and 4.00% for the qualified pension plan for SoCalGas' unions. All other qualified plan participants use an age-based table.

**

4.00% in 2007 and 4.50% in 2006 for the life insurance benefits for SoCalGas' unions. There are no compensation-based benefits for all other postretirement benefits.

 

 

 

 

 

 

 

 

 

 

 

 

 


The company develops the discount rate assumptions based on the results of a third party modeling tool that matches each plan's expected future benefit payments to a bond yield curve to determine their present value. It then calculates a single equivalent discount rate that produces the same present value. The modeling tool uses an actual portfolio of 500 to 600 non-callable bonds with a Moody’s Aa rating with an outstanding value of at least $50 million to develop the bond yield curve. This reflects over $300 billion in outstanding bonds with approximately 50 issues having maturities in excess of 20 years.


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.


 

 

2007

 

 

 2006

 

ASSUMED HEALTH CARE COST

 

 

 

 

 

 

 

TREND RATES AT DECEMBER 31:

 

 

 

 

 

 

Health-care cost trend rate *

 

9.48

%

 

 

9.52

%

 

Rate to which the cost trend rate is assumed to

 

 

 

 

 

 

 

 

 

decline (the ultimate trend)

 

5.50

%

 

 

5.50

%

 

Year that the rate reaches the ultimate trend

2014 and 2016 **

 

2009

 

 

*

 

This is the weighted average of the increases for the company's health plans. The rate for these plans ranged from 8.50% to 10.00% in 2006 and 2007.

**

 

The ultimate trend rate is reached in 2014 for HMOs and 2016 for Anthem Blue Cross Plans.





52


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:


(Dollars in millions)

 

1% Increase

 

1% Decrease

 

Effect on total of service and interest cost components of net

 

 

 

 

 

 

 

 

periodic postretirement health-care benefit cost

 

$

10

 

$

(8

)

Effect on the health-care component of the accumulated other

 

 

 

 

 

 

 

 

postretirement benefit obligation

 

$

86

 

$

(71

)


Pension Trust Investment Strategy


The asset allocation for Sempra Energy's pension trust (which includes the company's pension plan) at December 31, 2007 and 2006 and the target allocation for 2008 by asset categories are as follows:


 

Target

 

Percentage of Plan

 

Allocation

 

Assets at December 31,

Asset Category

2008

 

2007

 

2006

U.S. Equity

45

%

 

45

%

 

46

%

Foreign Equity

25

 

 

25

 

 

24

 

Fixed Income

30

 

 

30

 

 

30

 

 

Total

100

%

 

100

%

 

100

%


The company's investment strategy is to stay fully invested at all times and maintain its strategic asset allocation. The equity portfolio is balanced to maintain risk characteristics similar to the Morgan Stanley Capital International (MSCI) 2500 index with respect to industry, sector and market capitalization exposures. The foreign equity portfolios are managed to track the MSCI Europe, Pacific Rim and Emerging Markets indices. Bond portfolios are managed with respect to the Lehman Aggregate Bond Index and Lehman Long Government Credit Bond Index. Other than index weight, 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, 2007 and 2006 and the target allocation for 2008 by asset categories are as follows:


 

Target

 

Percentage of Plan

 

Allocation

 

Assets at December 31,

Asset Category

2008

 

2007

 

2006

U.S. Equity

70

%

 

75

%

 

74

%

Fixed Income

30

 

 

25

 

 

26

 

 

Total

100

%

 

100

%

 

100

%


The company's other postretirement benefit plans are funded by cash contributions from the company and the retirees. The asset allocation is designed to match the long-term growth of the plans' liability. These plans are managed using index funds.


Future Payments


The company expects to contribute $2 million to its pension plan and $19 million to its other postretirement benefit plans in 2008.




53



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.


 

 

 

Other

(Dollars in millions)

Pension Benefits

 

Postretirement Benefits

2008

$

143

 

 

$

32

 

2009

$

149

 

 

$

35

 

2010

$

154

 

 

$

37

 

2011

$

156

 

 

$

39

 

2012

$

158

 

 

$

41

 

2013-2017

$

843

 

 

$

244

 


The expected future Medicare Part D subsidy payments are as follows:

 

(Dollars in millions)

 

 

 

2008

 

 

 

 

$

2

 

2009

 

 

 

 

$

2

 

2010

 

 

 

 

$

3

 

2011

 

 

 

 

$

3

 

2012

 

 

 

 

$

3

 

2013-2017

 

 

 

 

$

19

 

 

Savings Plan


The company offers a trusteed savings plan to all employees. Participation in the plan is immediate for salary deferrals for all employees except for the represented employees, who are eligible upon completion of one year of service. 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 direct the employer contributions) as elected by the employee. Employer contributions for the SoCalGas plan are partially funded by the Sempra Energy Employee Stock Ownership Plan and Trust. Company contributions to the savings plan were $12 million in 2007, $11 million in 2006 and $11 million in 2005.


NOTE 6. SHARE-BASED COMPENSATION


Sempra Energy has share-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 share-based awards, including non-qualified stock options, incentive stock options, restricted stock, restricted stock units, stock appreciation rights, performance awards, stock payments and dividend equivalents. Certain company employees are eligible to participate in Sempra Energy's share-based compensation plans as a component of their compensation package.


At December 31, 2007, Sempra Energy had the following types of equity awards outstanding:





54


·

Non-Qualified Stock Options: Options have an exercise price equal to the market price of the common stock at the date of grant; are service-based; become exercisable over a four-year period (subject to accelerated vesting and/or exercisability upon a change in control, in accordance with severance pay agreements or upon retirement eligibility); and expire 10 years from the date of grant. Options are subject to forfeiture or earlier expiration upon termination of employment.


·

Restricted Stock: Substantially all restricted stock vests at the end of a four-year period based on Sempra Energy’s total return to shareholders relative to that of market indices (subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control, in accordance with severance pay agreements or upon retirement eligibility). Holders of restricted stock have full voting rights. They also have full dividend rights, except for company officers, whose dividends are reinvested to purchase additional shares that become subject to the same vesting conditions as the restricted stock to which the dividends relate.

 

Sempra Energy accounts for share-based awards in accordance with SFAS 123 (revised 2004), Share-Based Payment (SFAS 123(R)), which requires the measurement and recognition of compensation expense for all share-based payment awards made to the company’s employees and directors based on estimated fair values . Sempra Energy adopted the provisions of SFAS 123(R) on January 1, 2006, using the modified prospective transition method. In accordance with this transition method , Sempra Energy's consolidated financial statements for prior periods have not been restated to reflect the impact of SFAS 123(R). Under the modified prospective transition method, share-based compensation expense for 2006 includes compensation expense for all share-based compensation awards granted prior to, but for which the requisite service had not yet been performed as of January 1, 2006, based on the fair value estimated in accordance with the original provisions of SFAS 123, Accounting for Stock-Based Compensation (SFAS 123). Share-based compensation expense for all share-based compensation awards granted after January 1, 2006 is based on the grant date fair value estimated in accordance with the provisions of SFAS 123(R) . Sempra Energy recognizes compensation costs net of an assumed forfeiture rate and recognizes the compensation costs for non-qualified stock options and restricted shares on a straight-line basis over the requisite service period of the award, which is generally four years. However, in the year that an employee becomes eligible for retirement, the remaining expense related to the employee's awards is recognized immediately . Sempra Energy estimates the forfeiture rate based on its historical experience . Sempra Energy accounts for these awards as equity awards in accordance with SFAS 123(R).


Sempra Energy subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans and/or the subsidiaries are allocated a portion of the Sempra Energy plans’ corporate staff costs. The company recorded expense of $8 million, $10 million and $14 million in 2007, 2006 and 2005, respectively. Capitalized compensation cost was $1 million in each of 2007 and 2006.


NOTE 7. FINANCIAL INSTRUMENTS


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


As of both December 31, 2007 and 2006, the company has a fair value hedge for a notional amount of debt totaling $150 million. The fair value hedge balance was an asset of $2 million and a liability of $3 million for the respective years. The hedge expires in 2011.


Market value adjustments since inception of the hedge were recorded as an increase in fixed-price contracts and other derivatives (in noncurrent assets as Sundry or in Deferred Credits and Other) and as a




55


corresponding increase or decrease in Long-Term Debt without affecting net income or other comprehensive income. There has been no hedge ineffectiveness on this swap.


Cash Flow Hedges


As of December 31, 2007, the company had established a cash flow interest-rate swap hedge for a notional amount of debt totaling $183 million. The swap expires in 2038. There has been no hedge ineffectiveness on this swap.


Natural Gas Contracts


The use of derivative instruments is subject to certain limitations imposed by company policy and regulatory requirements. These instruments enable the company to estimate with greater certainty the effective prices to be received by the company and the prices to be charged to its customers. The company records realized gains or losses on derivative instruments associated with transactions for natural gas contracts in Cost of Natural Gas on the Statements of Consolidated Income. On the Consolidated Balance Sheets, the company records corresponding regulatory assets and liabilities related to unrealized gains and losses from these derivative instruments to the extent derivative gains and losses associated with these derivative instruments will be payable or recoverable in future rates.


Fair Value of Financial Instruments


The fair values of certain of the company's financial instruments (cash, temporary investments, notes receivable 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:


 

2007

 

2006

 

 

Carrying

 

 

Fair

 

 

Carrying

 

 

Fair

(Dollars in millions)

 

Amount

 

 

Value

 

 

Amount

 

 

Value

Total long-term debt*

$

1,115

 

$

1,100

 

$

1,110

 

$

1,090

PE:

 

 

 

 

 

 

 

 

 

 

 

 

Preferred stock

$

80

 

$

66

 

$

80

 

$

69

 

Preferred stock of subsidiary

 

20

 

 

17

 

 

20

 

 

20

 

$

100

 

$

83

 

$

100

 

$

89

SoCalGas:

 

 

 

 

 

 

 

 

 

 

 

 

Preferred stock

$

22

 

$

19

 

$

22

 

$

22

*

Before reductions for unamortized discount of $2 million and $3 million at December 31, 2007 and 2006, respectively.


The fair values of long-term debt and preferred stock were based on their quoted market prices or quoted market prices for similar securities.


Adoption of SFAS 157


Effective January 1, 2007, the company early-adopted SFAS 157 as discussed in Note 2, which, among other things, requires enhanced disclosures about assets and liabilities carried at fair value.


As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). However, as permitted under SFAS 157, the company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing the majority of its assets and




56


liabilities measured and reported at fair value. The company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The company primarily applies the market approach for recurring fair value measurements and endeavors to utilize the best available information. Accordingly, the company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The company is able to classify fair value balances based on the observability of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:


Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.


Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.


Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance sheet date, the company performs an analysis of all instruments subject to SFAS 157 and includes in level 3 all of those whose fair value is based on significant unobservable inputs. During 2007, the company had no significant level 3 measurements.


The following table sets forth by level within the fair value hierarchy the company's financial assets that were accounted for at fair value on a recurring basis as of December 31, 2007. The company's financial liabilities were a negligible amount as of December 31, 2007. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.


Recurring Fair Value Measures

 

At fair value as of December 31, 2007

 

(Dollars in millions)

Level 1

 

Level 2

 

Level 3

 

 

Total

 

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity derivatives

 

$

7

 

 

$

1

 

 

$

--

 

 

$

8

 

 

Other derivatives

 

 

--

 

 

 

5

 

 

 

--

 

 

 

5

 

 

Total

 

$

7

 

 

$

6

 

 

$

--

 

 

$

13

 





57


Commodity derivatives include commodity derivative positions entered into to manage customer price exposures, and other derivatives include interest-rate management instruments.


NOTE 8. PREFERRED STOCK


Preferred Stock of Pacific Enterprises


 

 

 

 

Call

December 31,

 

 

 

 

Price

2007 and 2006

 

 

 

 

 

 

(in millions)

 

 

Without par value, authorized 15,000,000 shares:

 

 

 

 

 

 

 

 

 

$4.75 Dividend, 200,000 shares outstanding

$

100.00

$

20

 

 

 

$4.50 Dividend, 300,000 shares outstanding

$

100.00

 

30

 

 

 

$4.40 Dividend, 100,000 shares outstanding

$

101.50

 

10

 

 

 

$4.36 Dividend, 200,000 shares outstanding

$

101.00

 

20

 

 

 

$4.75 Dividend, 253 shares outstanding

$

101.00

 

--

 

 

 

 Total

 

 

$

80


Preferred Stock of Southern California Gas Company


 

 

 

 

December 31,

 

 

 

 

 

2007 and 2006

 

 

 

 

 

 

(in millions)

 

 

$25 par value, authorized 1,000,000 shares:

 

 

 

 

 

 

 

 

 

6% Series, 28,041 shares outstanding

 

 

$

 

1

 

 

 

 

6% Series A, 783,032 shares outstanding

 

 

 

 

19

 

 

 

 

 Total

 

 

$

 

20

 


PE 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.


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. SoCalGas is currently authorized to issue 5 million shares of series preferred stock and 5 million shares of preference stock, both without par value and with cumulative preferences as to dividends and with liquidation value (the preference stock would rank junior to all series of preferred stock), and other rights and privileges that would be established by the board of directors at the time of issuance.


NOTE 9. REGULATORY MATTERS


General Rate Case (GRC)


In April 2007, the company filed an amendment to its original 2008 General Rate Case application (2008 GRC) as filed in December 2006 with the CPUC. The 2008 GRC application, as amended, establishes the 2008 authorized margin requirements and the ratemaking mechanisms by which those margin requirements would change annually effective in 2009 through 2013 (2008 GRC rate period).


As part of the General Rate Case process, applications are subject to review and testimony by various groups representing the interests of ratepayers and other constituents. In December 2007, the company filed with the CPUC a settlement agreement reached in principle with the CPUC's Division of Ratepayer




58


Advocates (DRA), The Utility Reform Network (TURN) and Aglet Consumer Alliance. If approved, the settlement would provide a 2008 revenue requirement of $1.685 billion and would resolve all 2008 revenue requirement issues. Comments were submitted in January 2008. If adopted, the settlement represents an increase in the annual authorized margin in 2008 of $29 million, as compared to 2007 authorized margin. The company also reached a settlement agreement with the DRA, TURN and Aglet Consumer Alliance regarding post test-year provisions including the term of the GRC period, earnings sharing and the year-to-year attrition allowances during the GRC period. As part of the settlement, the parties agreed to a GRC term of four years (2008 through 2011) with the DRA separately agreeing to a term of five years (through 2012). The parties also agreed to post test-year revenue requirement increases in fixed dollar amounts (i.e., no escalation, true-up or after-the-fact modification) as follows: $52 million for 2009, $51 million for 2010 and $53 million for 2011. The DRA separately agreed to revenue requirement increases of $52 million for 2012. These amounts exclude any CPUC-approved revenue requirements or rate base changes that are outside the scope of the GRC (e.g., Cost of Capital). The parties also agreed that there would be no earnings sharing between the company and ratepayers should the company exceed the authorized return on equity for any year in the post test-year period. The settlement was filed with the CPUC on January 18, 2008, and parties have an opportunity to comment on the filing.

 

The company has filed a request with the CPUC to make any decision on the 2008 GRC effective retroactive to January 1, 2008. In December 2007, the CPUC issued a decision allowing SoCalGas to establish regulatory memorandum accounts to record any difference between their current and future adopted revenue requirements on and after January 1, 2008 until a final decision is issued. This would enable the company to recover or refund these amounts in the future. However, the decision asks parties to comment on the extent to which SoCalGas may have improperly caused a delay in the proceeding and to what extent, if any, these recorded amounts should be reduced as a result. A final CPUC decision on all GRC Phase I issues is expected in the second quarter of 2008.


Utility Ratemaking Incentive Awards

 

Performance-Based Regulation (PBR) 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 are eligible for incentive awards or penalties are PBR operational incentives, which measure safety, reliability and customer service; energy efficiency (sometimes referred to as demand-side management, or DSM or EE) awards based on the effectiveness of the energy efficiency programs; and natural gas procurement awards or penalties. The operational PBR incentives and the associated benchmarks are determined as a component of a general rate case or cost of service decision. The operational PBR incentives to be in effect for fiscal year 2008 through the end of the 2008 GRC rate period are under consideration as part of the 2008 GRC. The company has recommended continuing the PBR measures in effect through 2007 with slight modifications to the benchmarks. The company expects a final CPUC decision on this issue in the second quarter of 2008.


PBR, DSM and Gas Cost Incentive Mechanism (GCIM) awards are not included in the company's earnings until CPUC approval of each award is received. All awards discussed below are on a pretax basis.


Operational PBR and Natural Gas Procurement


During the year ended December 31, 2007, SoCalGas’ pretax earnings included $1 million related to PBR awards and $10 million related to GCIM awards. In January 2008, the CPUC approved GCIM awards for SoCalGas of $9 million, which will be recorded in the first quarter of 2008.





59


Energy Efficiency


In September 2007, the CPUC established a mechanism to financially reward or penalize the California investor-owned utilities (IOUs) for their performance on post-2005 energy-efficiency programs. The mechanism rewards or penalizes the IOUs based upon specific portfolio performance goals to reduce energy consumption by its customers. The program provides for three-year cycles, with the first three-year cycle covering 2006 through 2008. The company's maximum rewards and penalties for the three-year program period, on a pretax basis, are $20 million. Generally, the company will be entitled to rewards when the energy cost savings are 80-110 percent of goal. The company is subject to penalties when the savings are less than 65 percent of goal, with the maximum penalty reached when savings are 55 percent of goal. No incentive or penalty applies for performance between 65-80 percent.


In January 2008, the CPUC issued a decision modifying the measurement and verification process of this earnings mechanism, which will enhance the predictability of earnings (or penalties) from energy efficiency programs. The company expects to file its initial report on its 2006 and 2007 energy efficiency results as compared to goal with the CPUC in the second quarter of 2008, with a decision anticipated by the end of 2008.


Omnibus Gas Settlements


In August 2006, SoCalGas, SDG&E and Southern California Edison jointly filed an application with the CPUC seeking its approval of a series of revisions to the natural gas operations and service offerings of the Sempra Utilities. The proposals resulted from the successful resolution of various litigation matters related to the 2000 - 2001 energy crisis. The CPUC issued a final decision in December 2007 approving some, but not all, of the proposals and deferring a number of issues to the Sempra Utilities’ next Biennial Cost Allocation Proceeding (BCAP), which is scheduled to begin in February 2008. As part of the decision, the natural gas supply portfolios for SDG&E’s and SoCalGas’ core customers will be combined into a single natural gas supply portfolio to be administered by SoCalGas effective April 1, 2008. All SDG&E assets associated with its core natural gas supply portfolio will be transferred or assigned to SoCalGas, which will be responsible for meeting the needs of both SDG&E’s and SoCalGas’ core natural gas customers at the same core gas monthly price. As a result, effective April 1, 2008, SoCalGas’ GCIM will apply to the natural gas procured for the combined portfolio. Regarding SoCalGas’ natural gas storage program, the CPUC concluded there was an insufficient record to decide matters related to the revenue sharing between SoCalGas’ shareholders and ratepayers. The CPUC directed that the issue of sharing the revenues and costs from the non-core storage program be deferred and that the mechanism to determine the amount of revenue sharing between SoCalGas’ shareholders and ratepayers be addressed more fully in the current BCAP. SoCalGas has been recognizing annual pretax shareholder benefits from the natural gas storage revenue sharing mechanism ranging from $14 million to $29 million in recent years. Until such time as a resolution is achieved, the revenues and costs that would have been shared associated with this mechanism will be deferred in a regulatory account effective January 1, 2008. In January 2008, SoCalGas filed a petition for modification asking the CPUC to revise its December 2007 decision so that the storage revenue sharing would remain at 50 percent ratepayer and 50 percent shareholder, as it was prior to the decision, until the issue is decided in the current BCAP. The CPUC is expected to act on the petition in mid-2008. SDG&E and SoCalGas filed a joint BCAP application with the CPUC in February 2008, seeking a decision by year-end 2008.


Natural Gas Market OIR


The CPUC considered natural gas market issues, including market design and infrastructure requirements, as part of its Natural Gas Market Order Instituting Rulemaking (OIR). A final decision in Phase II of this proceeding was issued in September 2006, reaffirming the adequacy of the capacity of the SoCalGas and




60


SDG&E systems to meet current demand. In particular, this decision established natural gas quality standards that would permit the introduction of regasified liquefied natural gas (LNG) supplies into California’s natural gas distribution system. The South Coast Air Quality Management District and the City of San Diego (jointly with Ratepayers for Affordable Clean Energy) have filed petitions for review in the California Court of Appeal and the California Supreme Court challenging the CPUC's September 2006 decision and contending that the California Environmental Quality Act (CEQA) applies to the changes in natural gas quality standards approved by the CPUC, and that impacts on the environment should be fully considered. In November 2007, the Court of Appeal determined that the California Supreme Court has exclusive jurisdiction to consider a CEQA challenge to a CPUC decision. A decision by the California Supreme Court is expected by the end of 2008.


Gain On Sale Rulemaking


In May 2006, the CPUC adopted a decision standardizing the treatment of gains and losses on future sales of utility property. It provided for an allocation of 100 percent of the gains and losses from depreciable property to ratepayers and a 50/50 allocation of gains and losses from non-depreciable property between ratepayers and shareholders. Under certain circumstances, the CPUC would be able to depart from the standard allocation. The DRA and TURN filed a joint request for rehearing of the decision requesting, among other things, that the CPUC adopt a 90/10 allocation of gains from non-depreciable assets between ratepayers and shareholders. In December 2006, the CPUC denied the request for rehearing, but modified its prior decision revising the allocation between ratepayers and shareholders to 67/33. In July 2007, the CPUC issued a resolution which adopted a gross-up formula for calculating the ratepayers’ allocation of taxes associated with any gains or losses from the sale of utility assets.


Southern California Wildfires


In October 2007, major wildfires throughout Southern California destroyed many homes, damaged utility infrastructure and disrupted utility services. On October 21, 2007, Governor Arnold Schwarzenegger declared a state of emergency for seven California counties, including the county of San Diego and six counties within SoCalGas' service territory. With a declaration of a state of emergency, the Sempra Utilities can request recovery of any material incremental costs of restoring utility services and utility facilities damaged by the wildfires in cost recovery proceedings applicable to disaster events. In January 2008, the company informed the CPUC that it would not seek recovery of its incremental costs estimated at approximately $1 million.


NOTE 10. COMMITMENTS AND CONTINGENCIES


Legal Proceedings


At December 31, 2007, the company’s reserves for litigation matters were $75 million, all of which related to settlements reached to resolve certain litigation arising out of the 2000 – 2001 California energy crisis. The uncertainties inherent in complex legal proceedings make it difficult to estimate with any degree of certainty the costs and effects of resolving legal 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.


Sempra Commodities, Sempra Generation and Sempra LNG, referred to in the following discussion, are business units of Sempra Energy.





61


Continental Forge Settlement


The litigation that is the subject of the settlements and $75 million of reserves is frequently referred to as the Continental Forge litigation, although the settlements also include other cases. The Continental Forge class-action and individual antitrust and unfair competition lawsuits in California and Nevada alleged that Sempra Energy and the Sempra Utilities unlawfully sought to control natural gas and electricity markets and claimed damages in excess of $23 billion after applicable trebling.


The San Diego County Superior Court entered a final order approving the settlement of the Continental Forge class-action litigation as fair and reasonable in July 2006. The California Attorney General and the Department of Water Resources (DWR) have appealed the final order. Oral argument is expected to take place in 2008. The Nevada Clark County District Court entered an order approving the Nevada class-action settlement in September 2006. 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 settle the California and Nevada litigation, in January 2006, Sempra Energy agreed to 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. The Los Angeles City Council had not previously voted to approve the City of Los Angeles' participation in the January 2006 California settlement. In March 2007, Sempra Energy and the Sempra Utilities entered into a separate settlement agreement with the City of Los Angeles resolving all of its claims in the Continental Forge litigation in return for the payment of $8.5 million in April 2007. This payment was made in lieu of the $12 million payable in eight annual installments that the City of Los Angeles was to receive as part of the January 2006 California settlement.


Additional consideration for the January 2006 California settlement includes an agreement that Sempra LNG would sell to the Sempra Utilities, subject to CPUC approval, regasified LNG from its LNG terminal being constructed in Baja California, Mexico, for a period of 18 years at the California border index price minus $0.02 per million British thermal units (MMBtu). Also, Sempra Generation voluntarily would reduce the price that it charges for power and limit the locations at which it would deliver power under its DWR contract. Based on the expected contractual power deliveries, this discount would have potential value aggregating $300 million over the contract's then remaining six-year term.


Under the terms of the January 2006 settlements, $83 million was paid in August 2006 and an additional $83 million was paid in August 2007. Of the remaining amounts, $25.8 million is to be paid on the closing date of the January 2006 settlements, which will take place after the resolution of all appeals, and $24.8 million will be paid on each successive anniversary of the closing date through the seventh anniversary of the closing date, as adjusted for the City of Los Angeles settlement. Under the terms of the City of Los Angeles settlement, $8.5 million was paid in April 2007. The reserves recorded for the California and Nevada settlements by Sempra Energy, including SoCalGas, in 2005 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 to be delivered under the DWR contract. A portion of the reserves was discounted at 7 percent, the rate specified for prepayments in the settlement agreement. For payments not addressed in the agreement and for periods from the settlement date through the estimated date of the first payment, 5 percent was used to approximate Sempra Energy's average cost of financing.





62


Other Natural Gas Cases


In April 2003, Sierra Pacific Resources and its utility subsidiary Nevada Power filed a lawsuit in the U.S. District Court in Nevada against major natural gas suppliers, including Sempra Energy, the Sempra Utilities and Sempra Commodities, seeking recovery of damages alleged to aggregate in excess of $150 million (before trebling). The lawsuit alleges a conspiracy to manipulate and inflate the prices that Nevada Power had to pay for its natural gas by preventing the construction of natural gas pipelines to serve Nevada and other Western states, and reporting artificially inflated prices to trade publications. The U.S. District Court dismissed the case in November 2004, determining that the FERC had exclusive jurisdiction to resolve the claims. In September 2007, the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit Court of Appeals) reversed the dismissal and returned the case to the District Court for further proceedings.


Apart from the claims settled in connection with the Continental Forge settlement, the remaining 13 state antitrust actions that were coordinated in San Diego Superior Court against Sempra Energy, the Sempra Utilities and Sempra Commodities and other, unrelated energy companies, 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 and churning transactions, were settled on January 4, 2008, for $2.5 million.


Pending in the U.S. District Court in Nevada are five cases against Sempra Energy, Sempra Commodities, the Sempra Utilities and various other companies, which make similar allegations to those in the state proceedings, four of which also include conspiracy allegations similar to those made in the Continental Forge litigation. The court dismissed four of these actions, determining that the FERC had exclusive jurisdiction to resolve the claims. The remaining case, which includes conspiracy allegations, was stayed. In September 2007, the Ninth Circuit Court of Appeals reversed the dismissal and these cases are expected to return to the District Court for further proceedings.


Other Litigation


In 1998, SoCalGas converted its traditional pension plan for non-union employees to a cash balance plan. In July 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. In October 2005, the court dismissed three of the four causes of action and, in March 2006, dismissed the remaining cause of action. The Ninth Circuit Court of Appeals heard oral argument on the matter on February 15, 2008, and took the matter under submission.


Natural Gas Contracts


SoCalGas buys natural gas under short-term and long-term contracts. Purchases are from various southwestern U.S. and U.S. Rockies 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 2018. Note 9 discusses the CPUC's Natural Gas Market OIR.





63


At December 31, 2007, the future minimum payments under existing natural gas contracts were:


(Dollars in millions)

 

 

Transportation

 

Natural Gas

 

 

Total

 

2008

 

 

 

$

120

 

 

$

1,120

 

$

1,240

 

2009

 

 

 

105

 

 

541

 

 

646

 

2010

 

 

 

80

 

 

540

 

 

620

 

2011

 

 

 

43

 

 

346

 

 

389

 

2012

 

 

 

15

 

 

4

 

 

19

 

Thereafter

 

 

 

82

 

 

--

 

 

82

 

Total minimum payments

 

 

 

$

445

 

 

$

2,551

 

$

2,996

 


Total payments under natural gas contracts were $2.4 billion in 2007, $2.4 billion in 2006 and $2.9 billion in 2005.


Leases


PE and SoCalGas have operating leases on real and personal property expiring at various dates from 2008 to 2035. Certain leases on office facilities contain escalation clauses requiring annual increases in rent of 3 percent to 5 percent. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain extension options that are exercisable by the company. Rent expense totaled $68 million in 2007, $62 million in 2006 and $59 million in 2005, which included rent expense for SoCalGas of $54 million, $49 million and $46 million, respectively.


At December 31, 2007, the minimum rental commitments payable in future years under all noncancelable leases were as follows:


(Dollars in millions)

 

 

PE

 

 

SoCalGas

 

2008

 

$

63

 

 

$

50

 

2009

 

 

60

 

 

 

47

 

2010

 

 

52

 

 

 

45

 

2011

 

 

38

 

 

 

38

 

2012

 

 

6

 

 

 

6

 

Thereafter

 

 

6

 

 

 

6

 

Total future rental commitments

 

$

225

 

 

$

192

 

 

 

 

 

 

 

 

 

 


Guarantees


As of December 31, 2007, 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, mitigation costs and emissions fees. Costs incurred to operate the facilities in compliance with these laws and regulations generally have been recovered in customer rates.




64



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 generally capitalized. The company's capital expenditures to comply with environmental laws and regulations were $6 million in 2007, $6 million in 2006 and $5 million in 2005. 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 (31 completed as of December 31, 2007 and 11 to be completed, including one site reopened during 2007), and cleanup of third-party waste-disposal sites used by the company, which has been identified as a PRP (investigations and remediations continuing).


Environmental liabilities are recorded at undiscounted amounts 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. At December 31, 2007, the company's accrued liability for environmental matters was $48 million, of which $46.9 million is related to manufactured-gas sites, $0.3 million to waste-disposal sites used by the company (which has been identified as a PRP) and $0.8 million to other hazardous waste sites. The majority of these accruals are expected to be paid 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 territory, which covers most of Southern California and a portion of central California.





65


NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED)


 

 

 

 

 

 

Quarters ended

(Dollars in millions)

 

 

 

 

March 31

June 30

September 30

December 31

2007

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

 

 

 

 

$

1,368

 

 

$

981

 

 

$

819

 

 

$

1,114

Operating expenses

 

 

 

 

 

 

1,260

 

 

 

877

 

 

 

701

 

 

 

1,008

Operating income

 

 

 

 

 

$

108

 

 

$

104

 

 

$

118

 

 

$

106

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

 

$

58

 

 

$

56

 

 

$

66

 

 

$

62

Dividends on preferred stock

 

 

 

 

 

 

1

 

 

 

1

 

 

 

1

 

 

 

1

Earnings applicable to common shares

 

 

 

 

 

$

57

 

 

$

55

 

 

$

65

 

 

$

61

2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

 

 

 

 

$

1,425

 

 

$

908

 

 

$

812

 

 

$

1,036

Operating expenses

 

 

 

 

 

 

1,324

 

 

 

803

 

 

 

680

 

 

 

935

Operating income

 

 

 

 

 

$

101

 

 

$

105

 

 

$

132

 

 

$

101

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

 

 

$

51

 

 

$

67

 

 

$

61

 

 

$

60

Dividends on preferred stock

 

 

 

 

 

 

1

 

 

 

1

 

 

 

1

 

 

 

1

Earnings applicable to common shares

 

 

 

 

 

$

50

 

 

$

66

 

 

$

60

 

 

$

59







66


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- Southern California Gas Company



MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS


Management is responsible for the preparation of the company's consolidated financial statements and related information appearing in this report. Management believes that the consolidated financial statements fairly present the form and substance of transactions and that the financial statements reasonably present the company's financial position and results of operations in conformity with accounting principles generally accepted in the United States of America. Management also has included in the company's financial statements amounts that are based on estimates and judgments, which it believes are reasonable under the circumstances.


The board of directors of Sempra Energy, the company's parent company, has an Audit Committee composed of six non-management directors. The committee meets periodically with financial management and the internal auditors to review accounting, control, auditing and financial reporting matters.



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, 2007. The effectiveness of the company’s internal control over financial reporting as of December 31, 2007, has been audited by Deloitte & Touche LLP, as stated in their report, which is included in Item 8.






67


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Southern California Gas Company:


We have audited the internal control over financial reporting of Southern California Gas Company and subsidiaries (the "Company") as of December 31, 2007 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, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.


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, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.





68


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, 2007 of the Company and our report dated February 25, 2008 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the Company’s adoption of two new accounting standards in 2007.


/S/ DELOITTE & TOUCHE LLP


San Diego, California
February 25, 2008






69


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, 2007 and 2006, and the related statements of consolidated income, comprehensive income and changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. 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 Southern California Gas Company and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.


As discussed in Note 2 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board ("FASB") Statement No. 157, Fair Value Measurements , effective January 1, 2007 and FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 , effective January 1, 2007. As discussed in Note 5 to the consolidated financial statements, the Company adopted FASB Statement No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R), effective December 31, 2006.


We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2007, 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 25, 2008 expressed an unqualified opinion on the Company's internal control over financial reporting.


/S/ DELOITTE & TOUCHE LLP


San Diego, California
February 25, 2008





70



SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

 

 

 

Years ended December 31,

(Dollars in millions)

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

4,282

 

 

$

4,181

 

 

$

4,617

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas

 

 

2,420

 

 

 

2,410

 

 

 

2,830

 

 

Other operating expenses

 

 

1,020

 

 

 

951

 

 

 

954

 

 

Depreciation

 

 

281

 

 

 

267

 

 

 

264

 

 

Franchise fees and other taxes

 

 

125

 

 

 

121

 

 

 

121

 

 

Litigation expense

 

 

1

 

 

 

(2

)

 

 

99

 

 

Gains on sale of assets

 

 

(2

)

 

 

(5

)

 

 

--

 

 

Impairment losses

 

 

--

 

 

 

--

 

 

 

2

 

 

 

Total operating expenses

 

 

3,845

 

 

 

3,742

 

 

 

4,270

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

 

437

 

 

 

439

 

 

 

347

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other expense, net

 

 

(3

)

 

 

(1

)

 

 

(2

)

Interest income

 

 

27

 

 

 

29

 

 

 

12

 

Interest expense

 

 

(70

)

 

 

(70

)

 

 

(48

)

Income before income taxes

 

 

391

 

 

 

397

 

 

 

309

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income tax expense

 

 

160

 

 

 

173

 

 

 

97

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

231

 

 

 

224

 

 

 

212

 

Preferred dividend requirements

 

 

1

 

 

 

1

 

 

 

1

 

Earnings applicable to common shares

 

$

230

 

 

$

223

 

 

$

211

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See Notes to Consolidated Financial Statements.








 





71



SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

December 31,

(Dollars in millions)

 

 

2007

 

2006

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

59

 

 

$

211

 

 

Accounts receivable - trade

 

 

671

 

 

 

640

 

 

Accounts receivable - other

 

 

22

 

 

 

33

 

 

Interest receivable

 

 

--

 

 

 

10

 

 

Due from unconsolidated affiliates

 

 

129

 

 

 

108

 

 

Deferred income taxes

 

 

33

 

 

 

42

 

 

Inventories

 

 

98

 

 

 

106

 

 

Other regulatory assets

 

 

40

 

 

 

41

 

 

Other

 

 

22

 

 

 

18

 

 

 

Total current assets

 

 

1,074

 

 

 

1,209

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

Other assets:

 

 

 

 

 

 

 

 

 

Regulatory assets arising from pension and other
    postretirement benefit obligations

 

 

--

 

 

 

136

 

 

Other regulatory assets

 

 

100

 

 

 

95

 

 

Pension plan assets in excess of benefit obligations

 

 

62

 

 

 

8

 

 

Sundry

 

 

16

 

 

 

11

 

 

 

Total other assets

 

 

178

 

 

 

250

 

  

 

 

 

 

 

 

 

 

Property, plant and equipment:

 

 

 

 

 

 

 

 

 

Property, plant and equipment

 

 

8,446

 

 

 

8,148

 

 

Less accumulated depreciation

 

 

(3,292

)

 

 

(3,248

)

 

 

Property, plant and equipment, net

 

 

5,154

 

 

 

4,900

 

Total assets

 

$

6,406

 

 

$

6,359

 

 

 

 

 

 

 

 

 

 

See Notes to Consolidated Financial Statements.







72



SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

 

 

 

 

 

 

December 31,

 

December 31,

(Dollars in millions)

2007

 

2006

 

 

 

 

 

 

 

 

 

LIABILITIES AND SHAREHOLDERS' EQUITY

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

Accounts payable - trade

 

$

300

 

 

$

416

 

 

Accounts payable - other

 

 

130

 

 

 

114

 

 

Due to unconsolidated affiliates

 

 

171

 

 

 

74

 

 

Income taxes payable

 

 

26

 

 

 

13

 

 

Regulatory balancing accounts, net

 

 

183

 

 

 

167

 

 

Customer deposits

 

 

90

 

 

 

88

 

 

Other

 

 

310

 

 

 

304

 

 

 

Total current liabilities

 

 

1,210

 

 

 

1,176

 

  

 

 

 

 

 

 

 

 

Long-term debt

 

 

1,113

 

 

 

1,107

 

  

 

 

 

 

 

 

 

 

Deferred credits and other liabilities:

 

 

 

 

 

 

 

 

 

Customer advances for construction

 

 

123

 

 

 

91

 

 

Pension and other postretirement benefit

 

 

 

 

 

 

 

 

 

     obligations, net of plan assets

 

 

58

 

 

 

172

 

 

Deferred income taxes

 

 

117

 

 

 

124

 

 

Deferred investment tax credits

 

 

33

 

 

 

36

 

 

Regulatory liabilities arising from removal obligations

 

 

1,187

 

 

 

1,019

 

 

Regulatory liabilities arising from pension and

 

 

 

 

 

 

 

 

 

     other postretirement benefit obligations

 

 

34

 

 

 

--

 

 

Asset retirement obligations

 

 

562

 

 

 

655

 

 

Deferred taxes refundable in rates

 

 

231

 

 

 

221

 

 

Deferred credits and other

 

 

268

 

 

 

268

 

 

 

Total deferred credits and other liabilities

 

 

2,613

 

 

 

2,586

 

  

 

 

 

 

 

 

 

 

Commitments and contingencies (Note 10)

 

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

 

Shareholders' equity:

 

 

 

 

 

 

 

 

 

Preferred stock

 

 

22

 

 

 

22

 

 

Common stock (100 million shares authorized;

 

 

 

 

 

 

 

 

 

    

91 million shares outstanding; no par value)

 

 

866

 

 

 

866

 

 

Retained earnings

 

 

586

 

 

 

607

 

 

Accumulated other comprehensive income (loss)

 

 

(4

)

 

 

(5

)

 

Total shareholders' equity

 

 

1,470

 

 

 

1,490

 

Total liabilities and shareholders' equity

 

$

6,406

 

 

$

6,359

 

 

 

 

 

 

 

 

 

 

See Notes to Consolidated Financial Statements.





73



SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years ended December 31,

(Dollars in millions)

 

 

2007

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CASH FLOWS FROM OPERATING ACTIVITIES

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

 

$

231

 

 

$

224

 

 

$

212

 

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation

 

 

 

281

 

 

 

267

 

 

 

264

 

 

 

 

 

Deferred income taxes and investment tax credits

 

 

 

8

 

 

 

(24

)

 

 

(9

)

 

 

 

 

Gains on sale of assets

 

 

 

(2

)

 

 

(5

)

 

 

--

 

 

 

 

 

Other

 

 

 

5

 

 

 

6

 

 

 

2

 

 

Changes in other assets

 

 

 

--

 

 

 

(5

)

 

 

15

 

 

Changes in other liabilities

 

 

 

37

 

 

 

31

 

 

 

115

 

 

Changes in working capital components:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 

 

(31

)

 

 

52

 

 

 

(42

)

 

 

 

Interest receivable

 

 

 

10

 

 

 

(1

)

 

 

22

 

 

 

 

Inventories

 

 

 

8

 

 

 

18

 

 

 

(49

)

 

 

 

Other current assets

 

 

 

(2

)

 

 

(7

)

 

 

(1

)

 

 

 

Accounts payable

 

 

 

(79

)

 

 

83

 

 

 

49

 

 

 

 

Income taxes

 

 

 

38

 

 

 

98

 

 

 

(148

)

 

 

 

Due to/from affiliates, net

 

 

 

1

 

 

 

(22

)

 

 

(9

)