SAN DIEGO GAS & ELECTRIC CO (Form: 10-K, Received: 02/26/2013 17:21:08)

REVENUES FROM UNCONSOLIDATED AFFILIATES AT SDG&E AND SOCALGAS

(Dollars in millions)

Years ended December 31,


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, 2012

		OR

[ ]		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 Registrants as Specified in their Charters, Address and Telephone Number	State of Incorporation	I.R.S. Employer Identification Nos.
1-14201			SEMPRA ENERGY	California	33-0732627
			101 Ash Street
			San Diego, California 92101
			(619)696-2000

1-03779			SAN DIEGO GAS & ELECTRIC COMPANY	California	95-1184800
			8326 Century Park Court
			San Diego, California 92123
			(619)696-2000

1-01402			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
	Sempra Energy Common Stock, without par value			NYSE
	SDG&E Preference Stock (Cumulative) Without Par Value – $1.82 Series SDG&E Cumulative Preferred Stock, $20 Par Value 4.50% Series, 4.40% Series 5.00% Series			NYSE Amex NYSE Amex

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

Southern California Gas Company Preferred Stock, $25 par value 6% Series A, 6% Series


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

Sempra Energy			Yes		X	No
San Diego Gas & Electric Company			Yes			No		X
Southern California Gas Company			Yes			No		X
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Sempra Energy			Yes			No		X
San Diego Gas & Electric Company			Yes			No		X
Southern California Gas Company			Yes			No		X
Indicate by check mark whether the registrants (1) have 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) have been subject to such filing requirements for the past 90 days.

			Yes		X	No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Sempra Energy			Yes		X	No
San Diego Gas & Electric Company			Yes		X	No
Southern California Gas Company			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 registrants’ 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.

Sempra Energy								X
San Diego Gas & Electric Company								X
Southern California Gas Company								X
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

	Large accelerated filer	Accelerated filer		Non-accelerated filer			Smaller reporting company
Sempra Energy	[ X ]	[ ]		[ ]			[ ]
San Diego Gas & Electric Company	[ ]	[ ]		[ X ]			[ ]
Southern California Gas Company	[ ]	[ ]		[ X ]			[ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Sempra Energy			Yes			No		X
San Diego Gas & Electric Company			Yes			No		X
Southern California Gas Company			Yes			No		X


Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2012:

Sempra Energy	$16.6 billion (based on the price at which the common equity was last sold as of the last business day of the most recently completed second fiscal quarter)
San Diego Gas & Electric Company	$0
Southern California Gas Company	$0

Common Stock outstanding, without par value, as of February 22, 2013:

Sempra Energy	243,290,805 shares
San Diego Gas & Electric Company	Wholly owned by Enova Corporation, which is wholly owned by Sempra Energy
Southern California Gas Company	Wholly owned by Pacific Enterprises, which is wholly owned by Sempra Energy

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the 2012 Annual Report to Shareholders of Sempra Energy, San Diego Gas & Electric Company and Southern California Gas Company are incorporated by reference into Parts I, II and IV.

Portions of the Sempra Energy Proxy Statement prepared for the May 2013 annual meeting of shareholders are incorporated by reference into Part III.

Portions of the San Diego Gas & Electric Company and Southern California Gas Company Information Statements prepared for their June 2013 annual meetings of shareholders are incorporated by reference into Part III.

SEMPRA ENERGY FORM 10-K SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-K SOUTHERN CALIFORNIA GAS COMPANY FORM 10-K TABLE OF CONTENTS
		Page
Information Regarding Forward-Looking Statements		6

PART I
Item 1.	Business	7
	Description of Business	7
	Company Websites	7
	Government Regulation	8
	California Natural Gas Utility Operations	11
	Electric Utility Operations	12
	Rates and Regulation – Utilities	17
	Sempra International and Sempra U.S. Gas & Power	18
	Environmental Matters	20
	Executive Officers of the Registrants	21
	Other Matters	22
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	33
Item 2.	Properties	33
Item 3.	Legal Proceedings	34
Item 4.	Mine Safety Disclosures	34

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 8.	Financial Statements and Supplementary Data	36
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	36
Item 9A.	Controls and Procedures	36
Item 9B.	Other Information	36

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	37
Item 11.	Executive Compensation	37
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	37
Item 13.	Certain Relationships and Related Transactions, and Director Independence	37
Item 14.	Principal Accountant Fees and Services	37

SEMPRA ENERGY FORM 10-K

SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-K

SOUTHERN CALIFORNIA GAS COMPANY FORM 10-K

TABLE OF CONTENTS (CONTINUED)

		Page
PART IV
Item 15.	Exhibits, Financial Statement Schedules	38

Sempra Energy: Consent of Independent Registered Public Accounting Firm and Report on Schedule		39
San Diego Gas & Electric Company: Consent of Independent Registered Public Accounting Firm		40
Southern California Gas Company: Consent of Independent Registered Public Accounting Firm		41

Schedule I – Sempra Energy Condensed Financial Information of Parent		42

Signatures		47
Exhibit Index		50
Glossary		59

This combined Form 10-K is separately filed by Sempra Energy, San Diego Gas & Electric Company and Southern California Gas Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.

You should read this report in its entirety as it pertains to each respective reporting company. No one section of the report deals with all aspects of the subject matter. Separate Item 6 and 8 sections are provided for each reporting company, except for the Notes to Consolidated Financial Statements in Item 8. The Notes to Consolidated Financial Statements for all of the reporting companies are combined. All Items other than Items 6 and 8 are combined for the reporting companies.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

We make statements in this report that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are necessarily based upon assumptions with respect to the future, involve risks and uncertainties, and are not guarantees of performance. These forward-looking statements represent our estimates and assumptions only as of the filing date of this report. We assume no obligation to update or revise any forward-looking statement as a result of new information, future events or other factors.

In this report, when we use words such as “believes,” “expects,” “anticipates,” “plans,” “estimates,” “projects,” “contemplates,” “intends,” “depends,” “should,” “could,” “would,” “will,” “may,” “potential,” “target,” “pursue,” “goals,” or similar expressions, or when we discuss our guidance, strategy, plans, goals, initiatives, objectives or intentions, we are making forward-looking statements.

Factors, among others, that could cause our actual results and future actions to differ materially from those described in forward-looking statements include

§	local, regional, national and international economic, competitive, political, legislative and regulatory conditions and developments;

actions and the timing of actions by the California Public Utilities Commission, California State Legislature, Federal Energy Regulatory Commission, U.S. Department of Energy, Nuclear Regulatory Commission, California Energy Commission, California Air Resources Board, and other regulatory, governmental and environmental bodies in the United States and other countries in which we operate;

§	capital markets conditions, including the availability of credit and the liquidity of our investments;

§	inflation, interest and exchange rates;

§	the impact of benchmark interest rates, generally U.S. Treasury bond and Moody’s A-rated utility bond yields, on our California Utilities’ cost of capital;

§	the timing and success of business development efforts and construction, maintenance and capital projects, including risks inherent in the ability to obtain, and the timing of granting of, permits, licenses, certificates and other authorizations;

§	energy markets, including the timing and extent of changes and volatility in commodity prices;

§	the availability of electric power, natural gas and liquefied natural gas, including disruptions caused by failures in the North American transmission grid, pipeline explosions and equipment failures;

§	weather conditions, natural disasters, catastrophic accidents, and conservation efforts;

§	risks inherent in nuclear power generation and radioactive materials storage, including the catastrophic release of such materials, the disallowance of the recovery of the investment in or operating costs of the generation facility due to an extended outage, and increased regulatory oversight;

§	risks posed by decisions and actions of third parties who control the operations of investments in which we do not have a controlling interest;

§	wars, terrorist attacks and cybersecurity threats;

§	business, regulatory, environmental and legal decisions and requirements;

§	expropriation of assets by foreign governments and title and other property disputes;

§	the status of deregulation of retail natural gas and electricity delivery;

§	the inability or determination not to enter into long-term supply and sales agreements or long-term firm capacity agreements;

§	the resolution of litigation; and

§	other uncertainties, all of which are difficult to predict and many of which are beyond our control.

We caution you not to rely unduly on any forward-looking statements. You should review and consider carefully the risks, uncertainties and other factors that affect our business as described in this report and other reports that we file with the Securities and Exchange Commission.

PART I

ITEM 1. BUSINESS

DESCRIPTION OF BUSINESS

We provide a description of Sempra Energy and its subsidiaries in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2012 Annual Report to Shareholders (Annual Report), which is attached as Exhibit 13.1 to this report and is incorporated by reference.

This report includes information for the following separate registrants:

§	Sempra Energy and its consolidated entities

§	San Diego Gas & Electric Company (SDG&E)

§	Southern California Gas Company (SoCalGas)

References in this report to “we,” “our,” “us,” “our company” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by the context. SDG&E and SoCalGas are collectively referred to as the California Utilities. They are subsidiaries of Sempra Energy, and Sempra Energy indirectly owns all of the common stock and substantially all of the voting stock of each of the two companies.

Sempra Energy’s principal operating units are

§	SDG&E and SoCalGas, which are separate, reportable segments;

§	Sempra International, which includes our Sempra South American Utilities and Sempra Mexico reportable segments; and

§	Sempra U.S. Gas & Power, which includes our Sempra Renewables and Sempra Natural Gas reportable segments.

During the fourth quarter of 2012, we revised the manner in which we make resource allocation decisions to our Sempra Mexico segment and assess its performance, as we discuss in Notes 16 and 18 of the Notes to Consolidated Financial Statements in the Annual Report. As a result, we have reclassified certain amounts from Parent and Other, which contains interest and other corporate costs and certain holding company activities, to our Sempra Mexico segment. In accordance with accounting principles generally accepted in the United States (U.S. GAAP), the historical segment disclosures have been restated to be consistent with the current presentation.

All references to “Sempra International,” “Sempra U.S. Gas & Power” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name. Sempra International and Sempra U.S. Gas & Power also own utilities which are not included in our references to the California Utilities. We provide financial information about all of our reportable segments and about the geographic areas in which we do business in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 16 of the Notes to Consolidated Financial Statements in the Annual Report.

COMPANY WEBSITES

Company website addresses are:

Sempra Energy – http://www.sempra.com

SDG&E – http://www.sdge.com

SoCalGas – http://www.socalgas.com

We make available free of charge on our website our 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 (SEC). The charters of the audit, compensation and corporate governance committees of Sempra Energy’s board of directors (the board), the board’s corporate governance guidelines, and Sempra Energy’s code of business conduct and ethics for directors and officers are posted on Sempra Energy’s website.

SDG&E and SoCalGas make available free of charge via a hyperlink on their websites their annual reports 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 SEC.

Printed copies of all of these materials may be obtained by writing to our Corporate Secretary at Sempra Energy, 101 Ash Street, San Diego, CA 92101-3017.

The information on the websites of Sempra Energy, SDG&E and SoCalGas is not part of this report or any other report that we file with or furnish to the SEC, and is not incorporated herein by reference.

GOVERNMENT REGULATION

The most significant government regulation affecting Sempra Energy is the regulation of the California Utilities.

California State Utility Regulation

The California Utilities are regulated by the California Public Utilities Commission (CPUC), the California Energy Commission (CEC) and the California Air Resources Board (CARB).

The California Public Utilities Commission:

§	consists of five commissioners appointed by the Governor of California for staggered, six-year terms.

§	regulates SDG&E’s and SoCalGas’ rates and conditions of service, sales of securities, rates of return, capital structure, rates of depreciation, and long-term resource procurement, except as described below in “United States Utility Regulation.”

§	has jurisdiction over the proposed construction of major new electric generation, transmission and distribution, and natural gas storage, transmission and distribution facilities in California.

§	conducts reviews and audits of utility performance and compliance with regulatory guidelines, and conducts investigations into various matters, such as deregulation, competition and the environment, to determine its future policies.

§	regulates the interactions and transactions of the California Utilities with Sempra Energy and its other affiliates.

We provide further discussion in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E is also subject to regulation by the CEC, which publishes electric demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC:

§	determines the need for additional energy sources and conservation programs;

§	sponsors alternative-energy research and development projects;

§	promotes energy conservation programs;

§	maintains a statewide plan of action in case of energy shortages; and

§	certifies power-plant sites and related facilities within California.

The CEC conducts a 20-year forecast of available supplies and prices for every market sector that consumes natural gas in California. This forecast includes resource evaluation, pipeline capacity needs, natural gas demand and wellhead prices, and costs of transportation and distribution. This analysis is one of many resource materials used to support the California Utilities’ long-term investment decisions.

In 2010, the State of California required certain California electric retail sellers, including SDG&E, to deliver 20 percent of their retail energy sales from renewable energy sources. The rules governing this requirement, administered by both the CPUC and the CEC, are generally known as the Renewables Portfolio Standard (RPS) Program. In December 2011, California Senate Bill 2(1X) (33% RPS Program) went into effect, superseding the previous RPS program. The 33% RPS Program requires each California utility to procure 33 percent of its annual electric energy requirements from renewable energy sources by 2020, with an average 20 percent required over the three-year period January 1, 2011 through December 31, 2013; 25 percent by December 31, 2016; and 33 percent by December 31, 2020. We discuss this requirement as it applies to SDG&E in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Certification of a generation project by the CEC as an Eligible Renewable Energy Resource (ERR) allows the purchase of output from such generation facility to be counted towards fulfillment of the RPS Program requirements, if such purchase meets the provisions of California Senate Bill 2(1X). This may affect the demand for output from renewables projects developed by Sempra Renewables and Sempra Mexico, particularly from California utilities. Sempra Renewables’ Copper Mountain Solar 1 facility in Nevada, which includes the 10-MW solar facility formerly referred to as El Dorado Solar, is certified as an ERR. Sempra Renewables has also submitted an application for ERR certification for their Copper Mountain Solar 2 facility. We plan to obtain ERR certification for all of our renewable facilities operating in and/or providing power to California as they become operational.

California Assembly Bill 32, the California Global Warming Solutions Act of 2006, assigns responsibility to CARB for monitoring and establishing policies for reducing greenhouse gas (GHG) emissions. The bill requires CARB to develop and adopt a comprehensive plan for achieving real, quantifiable and cost-effective GHG emission reductions, including a statewide GHG emissions cap, mandatory reporting rules, and regulatory and market mechanisms to achieve reductions of GHG emissions. CARB is a department within the California Environmental Protection Agency, an organization that reports directly to the Governor’s Office in the Executive Branch of California State Government. We provide further discussion in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

United States Utility Regulation

The California Utilities are also regulated by the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and the U.S. Department of Transportation (DOT).

In the case of SDG&E, the FERC regulates the interstate sale and transportation of natural gas, the transmission and wholesale sales of electricity in interstate commerce, transmission access, rates of return on transmission investment, the uniform systems of accounts, rates of depreciation and electric rates involving sales for resale.

In the case of SoCalGas, the FERC regulates the interstate sale and transportation of natural gas and the uniform systems of accounts.

The NRC oversees the licensing, construction and operation of nuclear facilities in the United States, including the San Onofre Nuclear Generating Station (SONGS), in which SDG&E owns a 20-percent interest. NRC regulations require extensive review of the safety, radiological and environmental aspects of these facilities. Periodically, the NRC requires that newly developed data and techniques be used to reanalyze the design of a nuclear power plant and, as a result, may require plant modifications as a condition of continued operation. We provide further discussion of current SONGS matters involving the NRC in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

The DOT has established regulations regarding engineering standards and operating procedures applicable for the California Utilities’ natural gas transmission and distribution pipelines. The DOT has certified the CPUC to administer oversight and compliance with these regulations for the entities they regulate in California.

State and Local Regulation Within the U.S.

SoCalGas has natural gas franchises with the 12 counties and 233 cities in its service territory. These franchises allow SoCalGas to locate, operate and maintain facilities for the transmission and distribution of natural gas. Most of the franchises have indefinite lives with no expiration date. Some franchises have fixed expiration dates, ranging from 2013 to 2062.

SDG&E has

§	electric franchises with the three counties and the 27 cities in or adjoining its electric service territory; and

§	natural gas franchises with the one county and the 18 cities in its natural gas service territory.

These franchises allow SDG&E to locate, operate and maintain facilities for the transmission and distribution of electricity and/or natural gas. Most of the franchises have indefinite lives with no expiration dates. Some natural gas and some electric franchises have fixed expiration dates that range from 2015 to 2037.

Sempra Natural Gas also operates Mobile Gas Service Corporation (Mobile Gas), a natural gas distribution utility serving southwest Alabama that is regulated by the Alabama Public Service Commission. Mobile Gas has franchise agreements with the two counties and eight cities in its service territory, with fixed expiration dates ranging from 2015 to 2033, which allow it to locate, operate and maintain facilities for the transmission and distribution of natural gas.

Sempra Renewables has operations or development projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Nevada and Pennsylvania. Sempra Natural Gas develops and operates natural gas storage and related pipeline facilities in Alabama, Louisiana and Mississippi, operates its Mesquite natural gas generation facility in Arizona and has marketing operations in Texas. Sempra Natural Gas also operates Willmut Gas Company (Willmut Gas), a natural gas distribution utility serving Hattiesburg, Mississippi and regulated by the Mississippi Public Service Commission. These entities are subject to state and local laws, and to regulations in the states in which they operate.

Other U.S. Regulation

In the United States, the FERC, with ratemaking authority over sales of wholesale power and the transportation and storage of natural gas in interstate commerce, and siting and permitting authority for liquefied natural gas (LNG) terminals, regulates Sempra Renewables’ and Sempra Natural Gas’ operations. Sempra Natural Gas also owns an interest in the Rockies Express Pipeline, a natural gas pipeline that operates in several states in the United States and is subject to regulation by the FERC. We discuss our investment in the pipeline further in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.

The FERC may regulate rates and terms of service based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be sufficiently competitive, rates may be market-based. Our LNG terminal in the United States is subject to market-based rates and terms of service. FERC-regulated rates at the following businesses are

§	Sempra Renewables and Sempra Natural Gas: market-based for wholesale electricity sales

§	Sempra Natural Gas: cost-based and market-based for the transportation and storage of natural gas, respectively

§	Sempra Natural Gas: market-based for the receipt, storage, and vaporization of LNG and liquefaction of natural gas and the purchase and sale of LNG and natural gas

Sempra Natural Gas is also subject to DOT rules and regulations regarding pipeline safety.

Foreign Regulation

Our Sempra Mexico segment owns and operates the following in Mexico:

§	a natural gas-fired power plant in Baja California, Mexico

§	natural gas distribution systems in Mexicali, Chihuahua, and the La Laguna-Durango zone in north-central Mexico

§	natural gas pipelines between the U.S. border and Baja California, Mexico and Sonora, Mexico. Sempra Mexico also owns a 50-percent interest in a joint venture with PEMEX (the Mexican state-owned oil company) that operates two natural gas pipelines and a propane system in northern Mexico

§	the Energía Costa Azul LNG terminal located in Baja California, Mexico

These operations are subject to regulation by the Energy Regulatory Commission (Comisión Reguladora de Energía, or CRE) and by the labor and environmental agencies of city, state and federal governments in Mexico.

Sempra South American Utilities has two utilities in South America that are subject to laws and regulations in the localities and countries in which they operate. Chilquinta Energía S.A. (including its subsidiaries, Chilquinta Energía) is an electric distribution utility serving customers in the cities of Valparaiso and Viña del Mar in central Chile. Luz del Sur S.A.A. (including its subsidiaries, Luz del Sur) is an electric distribution utility in the southern zone of metropolitan Lima, Peru. These utilities serve primarily regulated customers, and their revenues are based on tariffs that are set by the National Energy Commission (Comisión Nacional de Energ í a, or CNE) in Chile and the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería, or OSINERGMIN) of the National Electricity Office under the Ministry of Energy and Mines in Peru.

Licenses and Permits

The California Utilities obtain numerous permits, authorizations and licenses in connection with the transmission and distribution of natural gas and electricity and the operation and construction of related assets, some of which may require periodic renewal.

Our other subsidiaries are also required to obtain numerous permits, authorizations and licenses in the normal course of business. Some of these permits, authorizations and licenses require periodic renewal.

Sempra Mexico and Sempra South American Utilities obtain numerous permits, authorizations and licenses for their electric and natural gas distribution and transmission systems from the local governments where the service is provided. The concession to operate from the Ministerio de Energ í a for both Chilquinta Energ í a’s and Luz del Sur’s distribution operations is for an indefinite term, not requiring renewal.

Sempra Mexico and Sempra Natural Gas obtain licenses and permits for the operation and expansion of LNG facilities, and the import and export of LNG and natural gas.

Sempra Renewables obtains a number of permits, authorizations and licenses in connection with the construction and operation of power generation facilities, and in connection with the wholesale distribution of electricity.

Sempra Natural Gas obtains a number of permits, authorizations and licenses in connection with the construction and operation of power generation facilities and natural gas storage facilities and pipelines, and in connection with the wholesale distribution of electricity.

Most of the permits and licenses associated with construction and operations within the Sempra Renewables and Sempra Natural Gas businesses are for periods generally in alignment with the construction cycle or life of the asset and in many cases greater than 20 years. We do not anticipate that our ongoing requirement to renew or extend shorter duration permits and licenses would have a material impact to the ongoing operations of these businesses.

We describe other regulatory matters in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

CALIFORNIA NATURAL GAS UTILITY OPERATIONS

SoCalGas and SDG&E sell, distribute and transport natural gas. SoCalGas purchases and stores natural gas for its core customers and SDG&E’s core customers on a combined portfolio basis and provides natural gas storage services for others. The California Utilities’ resource planning, natural gas procurement, contractual commitments, and related regulatory matters are discussed below. We also provide further discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Customers

At December 31, 2012, SoCalGas had 5.8 million customer meters consisting of approximately:

§	5,545,500 residential

§	246,100 commercial

§	27,200 industrial

§	50 electric generation and wholesale

At December 31, 2012, SDG&E had approximately 860,000 natural gas customer meters consisting of approximately:

§	827,000 residential

§	28,600 commercial

§	3,600 electric generation and transportation

For regulatory purposes, end-use customers are classified as either core or noncore customers. Core customers are primarily residential and small commercial and industrial customers. Noncore customers at SoCalGas consist primarily of electric generation, wholesale, large commercial, industrial, and enhanced oil recovery customers. SoCalGas’ wholesale customers are primarily other investor-owned utilities (IOUs), including SDG&E, or municipally owned natural gas distribution systems. Noncore customers at SDG&E consist primarily of electric generation and large commercial and industrial customers.

Most core customers purchase natural gas directly from SoCalGas or SDG&E. While core customers are permitted to purchase directly from producers, marketers or brokers, the California Utilities are obligated to provide reliable supplies of natural gas to serve the requirements of their core customers. Noncore customers are responsible for the procurement of their natural gas requirements.

In 2012, SoCalGas added approximately 18,000 new connected natural gas customer meters, representing an annual growth rate of 0.3 percent; in 2011, it added approximately 15,000 new connected meters, representing an annual growth rate of 0.3 percent. SDG&E’s connected natural gas customer meters increased by approximately 5,000 in both 2012 and 2011, representing an annual growth rate of 0.6 percent in both years. Based on forecasts of new housing starts, SoCalGas and SDG&E each expects that its new meter annual growth rates in 2013 will be slightly higher than those in 2012.

Natural Gas Procurement and Transportation

SoCalGas purchases natural gas under short-term and long-term contracts for the California Utilities’ core customers. SoCalGas purchases natural gas from Canada, the U.S. Rockies and the southwestern U.S. to meet its and SDG&E’s core customer requirements and maintain pipeline reliability. It also purchases some California natural gas production and additional supplies delivered directly to California for its remaining requirements. Purchases of natural gas are primarily priced based on published monthly bid-week indices.

To ensure the delivery of the natural gas supplies to its distribution system and to meet the seasonal and annual needs of customers, SoCalGas has entered into firm interstate pipeline capacity contracts that require the payment of fixed reservation charges to reserve firm transportation rights. Pipeline companies, primarily El Paso Natural Gas Company, Transwestern Pipeline Company, Gas Transmission Northwest, Pacific Gas and Electric Company, and Kern River Gas Transmission Company, provide transportation services into SoCalGas’ intrastate transmission system for supplies purchased by SoCalGas or its transportation customers from outside of California. These contracts expire on various dates between 2013 and 2028. The FERC regulates the rates that interstate pipeline companies may charge for natural gas and transportation services.

Natural Gas Storage

SoCalGas provides natural gas storage services for core, noncore and non-end-use customers. The California Utilities’ core customers are allocated a portion of SoCalGas’ storage capacity. SoCalGas offers the remaining storage capacity for sale to others, including SDG&E for its non-core customer requirements, through an open bid process. 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, thereby reducing purchases when natural gas costs are expected to be higher. This program allows customers to better manage their natural gas procurement and transportation needs.

Demand for Natural Gas

Growth in the demand for natural gas largely depends on the health and expansion of the Southern California economy, prices of alternative energy products, environmental regulations, renewable energy, legislation, and the effectiveness of energy efficiency programs. 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 also result in significant shifts in market price, which may in turn impact demand.

The California Utilities face competition in the residential and commercial customer markets based on customers’ preferences for natural gas compared with other energy products. In the noncore industrial market, some customers are capable of securing alternate fuel supplies from other suppliers which can affect the demand for natural gas. The California Utilities’ ability to maintain their respective industrial market shares is largely dependent on the relative spread between delivered energy prices.

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 affected by the growth in renewable generation, the addition of more efficient gas technologies and to the extent that regulatory changes and electric transmission infrastructure investment divert electric generation from the California Utilities’ respective service areas. The demand may also fluctuate due to volatility in the demand for electricity and the availability of competing supplies of electricity such as hydroelectric generation and other renewable energy sources. We provide additional information regarding the electric industry in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

The natural gas distribution business is seasonal, and revenues generally are greater during the winter heating months. As is prevalent in the industry, SoCalGas 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.

ELECTRIC UTILITY OPERATIONS

SDG&E

Customers

SDG&E’s service area covers 4,100 square miles. At December 31, 2012, SDG&E had 1.4 million customer meters consisting of approximately:

§	1,245,900 residential

§	147,400 commercial

§	500 industrial

§	2,100 street and highway lighting

§	5,400 direct access

SDG&E’s active electric customer meters increased by approximately 7,000 and 8,000 in 2012 and 2011, respectively, representing annual growth rates of 0.5 percent and 0.6 percent, respectively. Based on forecasting of new housing starts, SDG&E expects the number of active meters to increase in 2013 by approximately 11,000, representing a growth rate of 0.8 percent.

Resource Planning and Power Procurement

SDG&E’s resource planning, power procurement and related regulatory matters are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Electric Resources

The supply of electric power available to SDG&E for resale is based on CPUC-approved purchased-power contracts currently in place with its various suppliers, its wholly owned generating facilities, its 20-percent ownership interest in SONGS (when SONGS returns to service) and purchases on a spot basis. This supply as of December 31, 2012 is as follows:

SDG&E ELECTRIC RESOURCES
Supplier		Source	Expiration date	Megawatts (MW)
PURCHASED-POWER CONTRACTS(1):
Department of Water Resources (DWR)-
allocated contracts:
	Shell Wind (2 contracts)	Wind	2013		104
Other contracts with Qualifying Facilities (QFs)(2):
	Applied Energy Inc.	Cogeneration	2019 and thereafter		114
	Yuma Cogeneration	Cogeneration	2024		57
	Goal Line Limited Partnership	Cogeneration	2025		50
	Other (2 contracts)	Cogeneration	2015 and thereafter		27
	Total				248
Other contracts with renewable sources:
	Pacific Wind	Wind	2032		140
	Iberdrola Renewables	Wind	2032		100
	Mesa Wind	Wind	2013		30
	NaturEner	Wind	2023 to 2024		210
	Oasis Power Partners	Wind	2019		60
	Kumeyaay	Wind	2025		50
	Iberdrola Renewables	Wind	2018		25
	WTE/FPL	Wind	2018		17
	Covanta Delano	Biomass	2017		49
	Blue Lake Power	Biomass	2025		11
	Calpine Geysers	Geothermal	2014		25
	Southern California Edison	Various	2013		29
	Other (15 contracts)	Bio-gas/Hydro/Wind	2013 to 2031		41
	Total				787
Other long-term and tolling contracts(3):
	Olivenhain-Hodges Pump Storage	Hydro/Pump Storage	2037		40
	Otay Mesa Energy Center LLC	Natural gas	2019		603
	Orange Grove Energy L.P.	Natural gas	2035		100
	El Cajon Energy, LLC	Natural gas	2035		49
	Portland General Electric Company (PGE)	Coal	2013		89
	EnerNOC	Demand response/
		Distributed generation	2016		25
	Total				906
Total contracted					2,045

GENERATION:
	Palomar Energy Center	Natural gas			560
	SONGS (4)	Nuclear			430
	Miramar Energy Center	Natural gas			96
	Desert Star Energy Center	Natural gas			495
	Cuyamaca Peak Energy Plant	Natural gas			42
Total generation					1,623
TOTAL CONTRACTED AND GENERATION					3,668
(1)	Contracts covering 2013 - 2037.
(2)	A QF is a generating facility which meets the requirements for QF status under the Public Utility Regulatory Policies Act of 1978. It includes cogeneration facilities, which produce electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, residential or institutional purposes. It also includes small power production facilities, which are generating facilities whose primary energy source is renewable (hydro, wind, solar, etc.), biomass, waste, or geothermal resources. Small power production facilities are generally limited in size to 80 MW.
(3)	Tolling contracts are purchased-power agreements under which we provide the fuel for generation to the energy supplier.
(4)	SONGS is currently offline for an extended period of time, as we discuss below.

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

Natural Gas Supply

SDG&E buys natural gas under short-term contracts for its Palomar, Miramar, Desert Star and Cuyamaca Peak generating facilities and for the Otay Mesa Energy Center LLC, Orange Grove Energy L.P., and El Cajon Energy, LLC tolling contracts. Purchases are from various southwestern U.S. suppliers and are primarily priced based on published monthly bid-week indices. SDG&E’s natural gas is typically delivered from Southern California border receipt points to the SoCal CityGate pool via backbone transmission system rights which expire on September 30, 2014. The natural gas is then delivered to the generating facilities through SoCalGas’ and SDG&E’s pipeline systems in accordance with a transportation agreement that expires on May 31, 2013. SDG&E will be executing a new two-year transportation agreement that will be effective June 1, 2013. SDG&E has also contracted with SoCalGas for natural gas storage from April 1, 2012 to March 31, 2014.

SONGS

SDG&E has a 20-percent ownership interest in SONGS, which is located south of San Clemente, California. SONGS consists of two operating nuclear generating units. The city of Riverside owns 1.79 percent and Southern California Edison Company (Edison), the operator of SONGS, owns the remaining interest of 78.21 percent.

The two units began commercial operation in August 1983 and April 1984, respectively. SDG&E’s share of the capacity from the two units is 430 MW. In 2005, the CPUC authorized a project to install four new steam generators in Units 2 and 3 at SONGS and remove and dispose of their predecessor generators. Edison completed the installation of these steam generators in 2010 and 2011 for Units 2 and 3, respectively. In January 2012, a water leak occurred in the Unit 3 steam generator which caused it to be shut down. Edison conducted inspection testing and determined that the water leak was the result of excessive wear from tube-to-tube contact. During a planned maintenance and refueling outage on the Unit 2 steam generators in February 2012, inspections found high levels of unexpected wear in some heat transfer tubes of the Unit 2 steam generators. As of December 31, 2012, both Units 2 and 3 remain offline. The units cannot be restarted until plans have been approved by the NRC. In October 2012, Edison submitted a restart plan for Unit 2 to the NRC. Unit 3 will remain offline while Edison continues to study the potential solutions that are unique to that unit. We discuss the current SONGS outage, inspection and repair issues and related regulatory matters in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

A third unit was removed from service in November 1992. Decommissioning of that unit is largely complete, with the remaining work to be done in the future when the remaining two units are decommissioned. Its spent nuclear fuel is being stored on site in an independent spent fuel storage installation (ISFSI) licensed by the NRC.

SDG&E has fully recovered the capital it invested in SONGS through December 31, 2003 and earns a return only on subsequent capital additions, including SDG&E’s share of costs associated with the steam generator replacement project, completed in 2011.

In November 2012, the CPUC issued an Order Instituting Investigation (OII) into the extended outages of Units 2 and 3. The OII requires that all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account, with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, should be refunded to rate payers.

As we discuss in “Item 1A. Risk Factors” herein, our influence may be limited over businesses in which we do not have a controlling interest, including SONGS. We provide additional information concerning the SONGS units and nuclear decommissioning below in “Environmental Matters” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Nuclear Fuel Supply

The nuclear fuel supply cycle includes materials and services performed by others under various contracts that extend through 2020. Fuel supply contracts are index-priced and provide nuclear fuel through 2022, the expiration of SONGS’ NRC license.

Spent fuel from SONGS is being stored on site in both the ISFSI and spent fuel pools. With the completion of the current phase of decommissioning, the site has adequate space to build ISFSI storage capacity through 2022. Pursuant to the Nuclear Waste Policy Act of 1982, SDG&E entered into a contract with the U.S. Department of Energy (DOE) for spent-fuel disposal. Under the agreement, the DOE is responsible for the ultimate disposal of spent fuel from SONGS. SDG&E pays the DOE a disposal fee of $1.00 per megawatt-hour of net nuclear generation, or approximately $3 million per year when SONGS is operating at normal capacity. It is uncertain when the DOE will begin accepting spent fuel from any nuclear generation facility.

We provide additional information concerning nuclear fuel costs and the storage and movement of spent fuel in Notes 6 and 15, respectively, of the Notes to Consolidated Financial Statements in the Annual Report.

Power Pool

SDG&E is a participant in the Western Systems Power Pool, which includes an electric-power and transmission-rate agreement with utilities and power agencies located throughout the United States and Canada. More than 300 investor-owned and municipal utilities, state and federal power agencies, energy brokers and power marketers share power and information in order to increase efficiency and competition in the bulk power market. Participants are able to make power transactions on standardized terms, including market-based rates, preapproved by the FERC.

Transmission Arrangements

SDG&E’s 500-kilovolt (kV) Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego, California. SDG&E’s share of the line is 1,162 MW, although it can be less under certain system conditions.

SDG&E’s Sunrise Powerlink is a 500-kV transmission line project built by SDG&E and designed to deliver more than 1,000 MW of power from the Imperial Valley to the San Diego region. The line was placed in service in June 2012. We provide further discussion of Sunrise Powerlink in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Mexico’s Baja California system is connected to SDG&E’s system via two 230-kV interconnections with combined capacity up to 408 MW in the north to south direction and 800 MW in the south to north direction, although it can be less under certain system conditions.

Edison’s transmission is connected to SDG&E’s system at SONGS via five 230-kV transmission lines with a total firm capacity up to 2,500 MW into SDG&E’s system, although it can be less under certain system conditions.

Transmission Access

The National Energy Policy Act governs procedures for requests for transmission service. The FERC approved the California IOUs’ transfer of operation and control of their transmission facilities to the Independent System Operator in 1998. We provide additional information regarding transmission issues in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

Chilquinta Energía

Customers

Chilquinta Energía is an electric distribution utility serving approximately 620,000 customers in the cities of Valparaiso and Viña del Mar in central Chile, with a main service area covering 4,400 square miles. At December 31, 2012, its customers consisted of approximately:

§	576,000 residential

§	36,000 commercial

§	1,000 industrial

§	5,000 street and highway lighting

§	5,000 agricultural

In Chile, customers are also classified as regulated and non-regulated customers based on installed capacity. Regulated customers are those whose installed capacity is less than 500 kilowatts (kW). Non-regulated customers are those whose installed capacity is greater than 2,000 kW. Customers with installed capacity between 500 kW and 2,000 kW may choose to be classified as regulated or non-regulated. Non-regulated customers can buy power from other sources, such as directly from the generator.

In 2012, Chilquinta Energía added approximately 14,000 new customers at a growth rate of 2.3 percent. Chilquinta Energía expects that its customer growth rate in 2013 will be comparable to that in 2012.

Chilquinta Energía’s electric energy sales increased by approximately 178,000 megawatt hours (MWh) and 171,000 MWh in 2012 and 2011, respectively, representing an annual growth rate of 7 percent in both years. Based on expected customer and overall economic growth in Chile, Chilquinta Energía expects its annual electric sales to increase in 2013 by approximately 210,000 MWh, representing a growth rate of 8 percent.

Electric Resources

The supply of electric power available to Chilquinta Energía comes from power purchase contracts currently in place with its various suppliers and its generating facilities. This supply as of December 31, 2012 is as follows:

CHILQUINTA ENERGÍA ELECTRIC RESOURCES
Supplier		Source(2)	Expiration date	Megawatts (MW)
PURCHASED-POWER CONTRACTS(1):
	Endesa	Thermal	2020 to 2024		47
	Gener	Thermal	2023 to 2024		125
	Tecnored	Thermal	2013		4
	Total				176

	Endesa	Hydro	2020 to 2024		161
	Gener	Hydro	2023 to 2024		61
	Total				222

	Endesa	Wind	2020 to 2024		3
Total contracted					401

GENERATION:
	Small generation plants(3)	Thermal			8
TOTAL CONTRACTED AND GENERATION					409
(1)	Contracts covering 2013 - 2024.
(2)	Contracts with fuel sources that include natural gas, coal or diesel are collectively referred to as thermal.
(3)	Compañía de Petróleos de Chile Copec S.A. supplies diesel fuel to six small generation plants using trucks from different stations throughout the region.

Power Generation System

The Centers for Economic Load Dispatch (Centros de Despacho Económico de Carga, or CDEC) are private organizations in charge of coordinating the operation of the electricity system. Each interconnected system is subject to its own CDEC; there is a CDEC-SIC (Sistema Interconectado Central, Central Interconnected System) and CDEC-SING (Sistema Interconectado del Norte Grande, Northern Interconnected System) for the central and the northern interconnected system, respectively. Chilquinta Energía operates within CDEC-SIC.

Transmission System and Access

Chile’s transmission system is divided into two parts, main transmission (sistema de transmisión troncal) and the sub-transmission (sistema de subtransmisión). In Chile, main transmission lines must be greater than or equal to 220 kV. Chilquinta Energía uses Transelec, a third party, for all of its main transmission. In general, sub-transmission systems operate at voltage levels greater than 23 kV and lower than or equal to 110 kV. Sub-transmission systems, including those owned by Chilquinta Energía, are comprised of infrastructure that is interconnected to the electricity system to supply non-regulated or regulated end-users located in the distribution service area.

Luz del Sur

Customers

Luz del Sur is an electric distribution utility serving approximately 950,000 customers in the southern zone of metropolitan Lima, Peru, with a main service area covering 1,160 square miles. At December 31, 2012, its customers consisted of approximately:

§	893,000 residential

§	56,000 commercial

§	4,000 industrial

§	5,000 street and highway lighting

§	1,000 agricultural

In Peru, customers are also classified as regulated and non-regulated customers based on capacity demand. Regulated customers are those whose capacity demand is less than 200 kW and their energy supply is considered public service. Customers with capacity demand between 200 kW and 2,500 kW may choose to be classified as regulated or non-regulated.

In 2012, Luz del Sur added approximately 33,000 new customers at a growth rate of 3.6 percent. Luz del Sur expects that its customer growth rate in 2013 will be comparable to that in 2012.

Luz del Sur’s electric energy sales increased by approximately 359,000 MWh and 351,000 MWh in 2012 and 2011, respectively, representing an annual growth rate of 6 percent in both years. Based on expected customer and overall economic growth in Peru, Luz del Sur expects its annual electric energy sales to increase in 2013 by approximately 467,000 MWh, representing a growth rate of 7 percent.

Electric Resources

The supply of electric power available to Luz del Sur comes from power purchase contracts currently in place with various suppliers, as well as purchases made on a spot basis. This supply as of December 31, 2012 is as follows:

LUZ DEL SUR ELECTRIC RESOURCES
Supplier		Source(2)	Expiration date	Megawatts (MW)
PURCHASED-POWER CONTRACTS(1):
Bilateral contracts:
	Celepsa	Hydro	2014		65
	Eepsa S.A.	Thermal	2013		25
	Edegel S.A.A.	Hydro/Thermal	2013		50
	Chinango S.A.C.	Hydro	2013		23
	Kallpa Generación S.A.	Thermal	2013		300
	EnerSur S.A.	Hydro/Thermal	2013		159
	Total				622
Auction contracts:
	Edegel S.A.A.	Hydro/Thermal	2013		123
	EnerSur S.A.	Hydro/Thermal	2013		227
	Kallpa Generación S.A.	Thermal	2013		106
	Chinango S.A.C.	Hydro	2013		18
	Termoselva S.R.L.	Thermal	2013		64
	DE-Egenor S. en C. por A.	Hydro/Thermal	2013		61
	Eepsa S.A.	Thermal	2013		80
	H. Huanchor S.A.C.	Hydro	2013		5
	Total				684
TOTAL CONTRACTED					1,306
(1)	Contracts covering 2013 - 2014.
(2)	Contracts with fuel sources that include natural gas, coal or diesel are collectively referred to as thermal.

Power Generation System

The Sistema Eléctrico Interconectado Nacional (SEIN) is the Peruvian national interconnected system. Peru also has several isolated regional and smaller systems that provide electricity to specific areas. The OSINERGMIN is an autonomous public regulatory entity that controls and enforces compliance with legal and technical regulations related to electric activities, sets tariffs and supervises the bidding processes required by distribution companies to purchase energy from generators.

The Committee of Economic Operation of the System (Comité de Operación Económica del Sistema Interconectado Nacional, or COES) coordinates the operation and dispatch of electricity of the SEIN, and manages the short-term market. The COES oversees generation, transmission and distribution companies, as well unregulated customers with a demand higher than 200 kW.

Transmission System and Access

Transmission lines in Peru are divided into principal and secondary systems. The principal system lines are accessible by all generators and allow the flow of energy through the national grid. The secondary system lines connect principal transmission with the network of distribution companies or connect directly to certain final customers. The transmission company receives tariff revenues and collects tolls based on a charge per unit of electricity.

RATES AND REGULATION – UTILITIES

We provide information concerning rates and regulation applicable to our utilities in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 1 and 14 of the Notes to Consolidated Financial Statements in the Annual Report.

SEMPRA INTERNATIONAL AND SEMPRA U.S. GAS & POWER

Sempra International and Sempra U.S. Gas & Power contain most of our subsidiaries that are not subject to California utility regulation. In addition to the discussion of our South American utilities above, we provide descriptions of these operating units’ segments and information concerning their operations in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 1, 3, 4, 15 and 16 of the Notes to Consolidated Financial Statements in the Annual Report.

Competition

Sempra Energy’s non-utility businesses are among many others in the energy industry providing similar products and services. They are engaged in highly competitive activities that require significant capital investments and highly skilled and experienced personnel. Among these competitors there may be significant variation in financial, personnel and other resources compared to Sempra International and Sempra U.S. Gas & Power.

Generation – Renewables

Sempra Renewables primarily competes for wholesale contracts for the generation and sale of electricity through its development of and investments in wind and solar generation facilities. For sales of non-contracted renewable energy, Sempra Renewables competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, and other energy service companies. The number and type of competitors may vary based on location, generation type and project size. Also, recently enacted regulatory initiatives designed to enhance energy consumption from renewable resources for regulated utility companies may increase competition from these types of institutions. These utilities may have a lower cost of capital than most independent renewable power producers and often are able to recover fixed costs through rate base mechanisms. This recovery allows them to build, buy and upgrade renewable generation projects without relying exclusively on market clearing prices to recover their investments. Additionally, generation from Sempra Renewables’ renewable energy assets is exposed to fluctuations in naturally occurring conditions such as wind, inclement weather and hours of sunlight.

Our renewable energy competitors include, among others:

§ BP

§ Exelon Energy

§ Iberdrola Renewables

§ MidAmerican Energy

§ NextEra Energy Resources

§ NRG Energy

Generation – Natural Gas

For sales of non-contracted power, Sempra Natural Gas is subject to competition from energy marketers, utilities, industrial companies and other independent power producers. For a number of years, natural gas has been the fuel of choice for new power generation facilities for economic, operational and environmental reasons. While natural gas-fired facilities will continue to be an important part of the nation’s generation portfolio, some regulated utilities are now constructing units powered by renewable resources, often with subsidies or under legislative mandate. These utilities may have a lower cost of capital than most independent power producers and often are able to recover fixed costs through rate base mechanisms. This recovery may allow them to build, buy and upgrade generation without relying exclusively on market clearing prices to recover their investments.

When Sempra Natural Gas sells power not subject to long-term contract commitments, it is exposed to market fluctuations in prices based on a number of factors, including the amount of capacity available to meet demand, the price and availability of fuel, and the presence of transmission constraints. Some of our competitors, such as electric utilities and generation companies, have their own generation capacity, including natural gas, coal and nuclear generation. These companies, generally larger than our segments engaged in the natural gas business, may have a lower cost of capital and may have competitive advantages as a result of their scale and the location of their generation facilities.

Our natural gas generation competitors include, among others:

§ Calpine	§ NextEra Energy Resources
§ Dynegy	§ NRG Energy

Because Sempra Mexico sells the power that it generates at its Termoeléctrica de Mexicali plant into California, it is also impacted by these competitive factors.

Natural Gas Pipelines and Storage Facilities

Within its market area, Sempra Natural Gas’ and Sempra Mexico’s pipelines businesses and Sempra Natural Gas’ storage facilities businesses compete with other regulated and unregulated storage facilities and pipelines. They compete primarily on the basis of price (in terms of storage and transportation fees), available capacity and interconnections to downstream markets.

Sempra Natural Gas’ competitors include, among others:

§ AES Corporation

§ Boardwalk Pipeline Partners

§ Duke Energy

§ Enbridge, Inc.

§ Endesa

§ Energy Transfer Partners

§ Enstor

§ Enterprise Product Partners

§ Kinder Morgan

§ NiSource, Inc.

§ Phillips 66

§ Plains All-American

§ Spectra Energy

§ Tallgrass Energy Partners, L.P.

§ TransCanada

§ The Williams Companies

Sempra Mexico’s natural gas pipeline competitors include, among others:

§ EDF Energy

§ Elecnor

§ Fermaca

§ GDF SUEZ

§ Kinder Morgan

§ Mitsubishi

§ Mitsui

§ PEMEX (MGI)

§ Samsung

§ TransCanada

LNG

New supplies to meet North America’s natural gas demand may be developed from a combination of the following sources:

§	previously inaccessible or uneconomic natural gas reserves through hydraulic fracturing (natural gas recovery from shale formations) and other new exploration, drilling and production techniques;

§	existing producing basins in the United States, Canada and Mexico;

§	frontier basins in Alaska, Canada and offshore North America;

§	areas currently restricted from exploration and development due to public policies, such as areas in the Rocky Mountains and offshore Atlantic, Pacific and Gulf of Mexico coasts;

§	LNG imported into LNG terminals in operation or under development in the United States, Canada and Mexico; and

§	biogas recovery from landfills and livestock operations.

In addition, the demand for energy currently met by natural gas could be met by other energy forms such as coal, hydroelectric, oil, wind, solar, geothermal, biomass and nuclear energy. Our LNG businesses will, therefore, face competition from companies that supply each of these energy sources.

From time to time, our LNG businesses compete with other companies that operate LNG receiving terminals, purchase and sell LNG and purchase and sell natural gas. As of December 31, 2012, there were 16 existing and operating LNG receipt terminals in North America. Worldwide, there are 94 existing and operating LNG receipt terminals in 26 countries. There are also other proposed LNG receipt terminals worldwide with which, if developed, our LNG businesses would compete to be the most economical delivery point for LNG supply of both long-term contracted and spot volumes.

Our current LNG businesses’ major domestic and international competitors include, among others, the following companies and their related LNG affiliates:

§ BG	§ Gas Natural Fenosa
§ BP	§ Gazprom
§ Cheniere Energy	§ GDF SUEZ
§ Chevron	§ Kinder Morgan
§ ConocoPhillips	§ Petronas
§ Dominion Resources	§ Qatar Petroleum
§ Energy Transfer Partners	§ Repsol
§ Eni	§ Royal Dutch Shell
§ Excelerate Energy	§ Statoil
§ ExxonMobil	§ Total S.A.

Sempra Natural Gas is currently progressing with plans for a development project to utilize its Cameron LNG terminal for the liquefaction of natural gas and export of LNG. The objective is to obtain long-term contracts for liquefaction services that allow us to fully utilize our existing regasification infrastructure while minimizing our future additional capital investment. The liquefaction facility will utilize Cameron LNG’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability of 1.5 billion cubic feet (Bcf) per day. In January 2012, the DOE approved Cameron LNG’s application for a license to export LNG to Free Trade Agreement (FTA) countries. The authorization to export LNG to countries with which the U.S. does not have an FTA is pending review by the DOE.

Prospective liquefaction customers of Cameron LNG compete globally to market and sell LNG to end users including gas and electric utilities located in LNG importing countries around the world. By providing liquefaction services to Cameron LNG’s customers, Cameron LNG would indirectly be competing with liquefaction projects currently operating and those under development in the world LNG market. These competitors are located in the Middle East, Southeast Asia, Africa, South America, Australia and Europe.

Our planned LNG liquefaction business’s major domestic and international competitors include, among others, the following companies and their related LNG affiliates:

§ BG	§ Kogas
§ BP	§ Mitsubishi
§ Cheniere Energy	§ Mitsui
§ Chevron	§ Petronas
§ China National Petroleum Company	§ Qatar Petroleum
§ ConocoPhillips	§ Santos
§ Dow Chemical	§ Shell
§ ExxonMobil	§ Total S.A.
§ GDF SUEZ	§ Woodside
§ Kinder Morgan

ENVIRONMENTAL MATTERS

We discuss environmental issues affecting us in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report. You should read the following additional information in conjunction with those discussions.

Hazardous Substances

In 1994, the CPUC approved the Hazardous Waste Collaborative mechanism, allowing California’s IOUs to recover hazardous waste cleanup costs for certain sites, including those related to certain Superfund sites. This mechanism permits the California Utilities to recover in rates 90 percent of hazardous waste cleanup costs and related third-party litigation costs, and 70 percent of the related insurance-litigation expenses. In addition, the California Utilities have the opportunity to retain a percentage of any recoveries from insurance carriers and other third parties to offset the cleanup and associated litigation costs not recovered in rates.

At December 31, 2012, we had accrued estimated remaining investigation and remediation liabilities of $0.7 million at SDG&E and $15.9 million at SoCalGas, both related to hazardous waste sites for which the Hazardous Waste Collaborative mechanism applies, as described above. The accruals include costs for numerous locations, most of which had been manufactured-gas plants at SoCalGas. This estimated cost excludes remediation costs of $0.2 million associated with SDG&E’s former fossil-fuel power plants and other locations for which the cleanup costs are not being recovered in rates. We believe that any costs not ultimately recovered through rates, insurance or other means will not have a material adverse effect on the consolidated results of operations, cash flows or financial condition of Sempra Energy, SDG&E or SoCalGas.

We record estimated liabilities for environmental remediation when amounts are probable and estimable. In addition, we record amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism as regulatory assets.

Air and Water Quality

The electric and natural gas industries are subject to increasingly stringent air-quality and greenhouse gas standards, such as those established by the United States Environmental Protection Agency (EPA) and the CARB. We discuss these standards in “Government Regulation – California Utility Regulation” above. The California Utilities generally recover in rates the costs to comply with these standards.

In connection with the issuance of operating permits, SDG&E and the other owners of SONGS have an agreement with the California Coastal Commission to mitigate environmental impacts to the marine environment attributed to the cooling-water discharge from SONGS. SDG&E’s share of the mitigation costs is estimated to be $48 million, of which $38 million had been incurred through December 31, 2012, and $10 million is accrued for the remaining costs through 2050. Artificial kelp reef, fish hatchery and wetlands restoration projects are complete, but continue to be studied until the California Coastal Commission accepts the projects. The remaining costs are to maintain the projects through 2050.

EXECUTIVE OFFICERS OF THE REGISTRANTS

Sempra Energy

Name	Age(1)	Position(1)
Debra L. Reed	56	Chairman of the Board and Chief Executive Officer
Mark A. Snell	56	President
Javade Chaudhri	60	Executive Vice President and General Counsel
Joseph A. Householder	57	Executive Vice President and Chief Financial Officer
Trevor I. Mihalik	46	Controller and Chief Accounting Officer
G. Joyce Rowland	58	Senior Vice President – Human Resources, Diversity and Inclusion

(1) Ages and positions are as of February 26, 2013.

With the exception of Mr. Mihalik, each executive officer has been an officer of Sempra Energy or its subsidiaries for more than the last five years. Before joining Sempra Energy in July 2012, Mr. Mihalik served as Senior Vice President of Finance for the past two years and as Vice President—Controller for the prior four years, in each case at Iberdrola Renewables Holdings, Inc., a diversified renewables and natural gas company.

SDG&E and SoCalGas

Name	Age(1)	Position(1)
SAN DIEGO GAS & ELECTRIC COMPANY
Jessie J. Knight, Jr.	62	Chairman and Chief Executive Officer
Michael R. Niggli	63	President and Chief Operating Officer
James P. Avery	56	Senior Vice President – Power Supply
J. Chris Baker	53	Senior Vice President – Strategic Planning and Technology and Chief Information Officer
Lee Schavrien	58	Senior Vice President – Finance, Regulatory and Legislative Affairs
W. Davis Smith	63	Senior Vice President and General Counsel
Robert M. Schlax	57	Vice President, Controller, Chief Financial Officer, Chief Accounting Officer and Treasurer

SOUTHERN CALIFORNIA GAS COMPANY
Anne S. Smith	59	Chairman and Chief Executive Officer
Dennis V. Arriola	52	President and Chief Operating Officer
J. Chris Baker	53	Senior Vice President – Strategic Planning and Technology and Chief Information Officer
Erbin B. Keith	52	Senior Vice President and General Counsel
Lee Schavrien	58	Senior Vice President – Finance, Regulatory and Legislative Affairs
Robert M. Schlax	57	Vice President, Controller, Chief Financial Officer, Chief Accounting Officer and Treasurer

(1) Ages and positions are as of February 26, 2013.

With the exception of Mr. Arriola, each executive officer of SDG&E and SoCalGas has been an officer or employee of Sempra Energy or its subsidiaries for at least the last five years. Mr. Arriola was a Senior Vice President and the Chief Financial Officer of SDG&E and SoCalGas from September 2006 to November 2008, and held numerous management positions with Sempra Energy or its subsidiaries prior to that. In November 2008, Mr. Arriola became a Senior Vice President and the Chief Financial Officer of SunPower Corporation. From April 2010 to March 2012, he was the Executive Vice President and Chief Financial Officer of SunPower. In August 2012, he rejoined SoCalGas as President and Chief Operating Officer, and in December 2012 also joined the SoCalGas Board of Directors.

OTHER MATTERS

Employees of Registrants

As of December 31, each company had the following number of employees:

		December 31,
		2012	2011
Sempra Energy Consolidated(1)		16,893	16,298
SDG&E		4,996	5,008
SoCalGas		7,788	7,370
(1)	Excludes employees of variable interest entities as defined by U.S. GAAP.

Labor Relations

SoCalGas

Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers Union of America or the International Chemical Workers Union Council (collectively “Union”) under a single collective bargaining agreement. The collective bargaining agreement for these employees covering wages, hours, working conditions and medical and other benefit plans was ratified on March 1, 2012, and is effective January 1, 2012 through September 30, 2015.

SDG&E

Field employees and some clerical and technical employees at SDG&E are represented by the International Brotherhood of Electrical Workers. Provisions of the collective bargaining agreement for these employees covering wages are in effect through August 31, 2014 and through August 31, 2015, for hours and working conditions. For these same employees, the agreement covering pension and savings plan benefits is in effect through October 1, 2015, and the agreement covering health and welfare benefits is in effect through December 31, 2013.

Luz del Sur

Field, technical and administrative employees at Luz del Sur representing 37 percent of the total workforce are represented by the Unified Trade Union of Electricity Workers of Lima and Callao, and the Trade Union of Employees of Electrolima. A collective bargaining agreement signed on December 13, 2012 covers these employees and is also extended to 125 non-represented employees. It covers wages, working conditions and medical and other benefit plans and is in effect from January 1, 2013 through December 31, 2013.

Chilquinta Energía

Field, technical and administrative employees at Chilquinta Energía are represented by Labor Union Number 1 Chilquinta Energía, Litoral Labor Union and Tecnored Labor Union Number 1. The collective bargaining agreements for employees represented by these unions cover wages, hours, working conditions and medical and other benefit plans and are in effect through various dates in 2013.

Professional employees at Chilquinta Energía are represented by Group of University Graduates of Chilquinta Energía. The collective bargaining agreement for these employees covers wages, hours, working conditions and medical and other benefit plans and is in effect through August 31, 2013.

Sempra Mexico

At December 31, 2012, Sempra Mexico had 437 employees, of whom 413 provide operation and maintenance services to our facilities and are covered by various collective bargaining agreements with different labor unions. Sempra Mexico’s collective bargaining agreements are negotiated on a facility-by-facility basis, and the compensation terms are adjusted on an annual basis, whereas all other terms are renegotiated every two years. The collective bargaining agreements are subject to renegotiation by each facility on an annual basis with respect to wages, and otherwise on a bi-annual basis.

Mobile Gas

Field employees at Mobile Gas are represented by the United Steelworkers Union under a single collective bargaining agreement. The agreement for these employees covers wages, hours, working conditions and medical and other benefit plans and is in effect through November 30, 2013.

ITEM 1A. RISK FACTORS

When evaluating our company and its subsidiaries, you should consider carefully the following risk factors and all other information contained in this report. These risk factors could materially adversely affect our actual results and cause such results to differ materially from those expressed in any forward-looking statements made by us or on our behalf. We may also be materially harmed by risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of the following occurs, our businesses, cash flows, results of operations, financial condition and/or prospects could be materially negatively impacted. In addition, the trading price of our securities could substantially decline due to the occurrence of any of these risks. These risk factors should be read in conjunction with the other detailed information concerning our company set forth in the Annual Report, including, without limitation, the information set forth in the Notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” In this section, when we state that a risk or uncertainty may, could or will have a “material adverse effect” on us or may, could or will materially adversely affect us we mean that the risk or uncertainty may, could or will have a material adverse effect on our businesses, cash flows, results of operations, financial condition, prospects and/or the market prices of our securities.

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

Sempra Energy’s ability to pay dividends and meet its debt obligations depends almost entirely on cash flows from its subsidiaries and, in the short term, its ability to raise capital from external sources. In the long term, cash flows from the subsidiaries depend on their ability to generate operating cash flows in excess of their own capital expenditures and long-term debt obligations. In addition, the subsidiaries are separate and distinct legal entities and could be precluded from making such distributions under certain circumstances, including, without limitation, as a result of legislation, regulation, court order, contractual restrictions or in times of financial distress.

Conditions in the financial markets and economic conditions generally may materially adversely affect us.

Our businesses are capital intensive and we rely significantly on long-term debt to fund a portion of our capital expenditures and refund outstanding debt, and on short-term borrowings to fund a portion of day-to-day business operations.

The credit markets and financial services industry have experienced a period of extreme world-wide turmoil characterized by the bankruptcy, failure, collapse or sale of many financial institutions and by extraordinary levels of government intervention and proposals for further intervention and additional regulation.

Limitations on the availability of credit and increases in interest rates or credit spreads may materially adversely affect our businesses, cash flows, results of operations, financial condition and/or prospects, as well as our ability to meet contractual and other commitments. In difficult credit markets, we may find it necessary to fund our operations and capital expenditures at a higher cost or we may be unable to raise as much funding as we need to support business activities. This could cause us to reduce capital expenditures and could increase our cost of funding, both of which could significantly reduce our short-term and long-term profitability.

The availability and cost of credit for our businesses may be greatly affected by credit ratings. If the credit ratings of SoCalGas or SDG&E were to be reduced, their cash flows and results of operations could be materially adversely affected and any reduction in Sempra Energy’s ratings could materially adversely affect the cash flows and results of operations of Sempra Energy and its non-utility subsidiaries.

Risks Related to All Sempra Energy Subsidiaries

Our businesses are subject to complex government regulations and may be materially adversely affected by changes in these regulations or in their interpretation or implementation.

In recent years, the regulatory environment that applies to the electric power and natural gas industries has undergone significant changes, on both federal and state levels. These changes have affected the nature of these industries and the manner in which their participants conduct their businesses. These changes are ongoing, and we cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on our businesses. Moreover, existing regulations, laws and tariffs may be revised or reinterpreted, and new regulations, laws and tariffs may be adopted or become applicable to us and our facilities. Special tariffs may also be imposed on components used in our businesses that could increase costs if applicable. Our businesses are subject to increasingly complex accounting and tax requirements, and the regulations, laws and tariffs that affect us may change in response to economic or political conditions. Compliance with these requirements could increase our operating costs, and new tax legislation, regulations or other interpretations could materially adversely affect our tax expense. Changes in regulations, laws and tariffs and changes in the way regulations, laws and tariffs are implemented and interpreted may have a material adverse effect on our businesses, cash flows, financial condition, results of operations and/or prospects.

Our operations are subject to rules relating to transactions among the California Utilities and other Sempra Energy operations. These rules are commonly referred to as the Affiliate Transaction Rules. These businesses could be materially adversely affected by changes in these rules or by additional CPUC or FERC rules that further restrict our ability to sell electricity or natural gas, or to trade with the California Utilities and with each other. Affiliate Transaction Rules also could require us to obtain prior approval from the CPUC before entering into any such transactions with the California Utilities. Any such restrictions or approval requirements could materially adversely affect the LNG terminals, natural gas pipelines, electric generation facilities, or other operations of our subsidiaries, which could have a material adverse effect on our businesses, results of operations and/or prospects.

Our businesses require numerous permits and other governmental approvals from various federal, state, local and foreign governmental agencies; any failure to obtain or maintain required permits or approvals could cause our sales to materially decline and/or our costs to materially increase, and otherwise materially adversely affect our businesses, cash flows, financial condition, results of operations and/or prospects.

All of our existing and planned development projects require multiple approvals. The acquisition, construction, ownership and operation of LNG terminals, natural gas pipelines and storage facilities, and electric generation and transmission facilities require numerous permits, licenses, certificates and other approvals from federal, state, local and foreign governmental agencies. Once received, approvals may be subject to litigation, and projects may be delayed or approvals reversed in litigation. In addition, permits, licenses, certificates, and other approvals may be modified or rescinded by one or more of the governmental agencies and authorities that oversee our businesses. If there is a delay in obtaining any required regulatory approvals or if we fail to obtain or maintain any required approvals or to comply with any applicable laws or regulations, we may not be able to construct or operate our facilities, or we may be forced to incur additional costs. Any such delay or failure to obtain or maintain the necessary permits, licenses, certificates and other approvals could cause our sales to materially decline, and/or our costs to increase, and otherwise materially adversely affect our businesses, cash flows, financial condition, results of operations and/or prospects.

Our businesses have significant environmental compliance costs, and future environmental compliance costs could have a material adverse effect on our cash flows and results of operations.

We are subject to extensive federal, state, local and foreign statutes, rules and regulations relating to environmental protection, including, in particular, climate change and GHG emissions. We are required to obtain numerous governmental permits, licenses, certificates and other approvals to construct and operate our businesses. Additionally, to comply with these legal requirements, we must spend significant sums on environmental monitoring, pollution control equipment, mitigation costs and emissions fees. In addition, we are generally responsible for all on-site liabilities associated with the environmental condition of our electric generation facilities and other energy projects, regardless of when the liabilities arose and whether they are known or unknown. If we fail to comply with applicable environmental laws, we may be subject to substantial penalties and fines and/or significant curtailments of our operations, which could materially adversely affect our cash flows and/or results of operations.

The scope and effect of new environmental laws and regulations, including their effects on our 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 negative effects on our operations, operating costs, and the scope and economics of proposed expansion, which could have a material adverse effect on our results of operations, cash flows and/or prospects. In particular, state-level laws and regulations, as well as proposed national and international legislation and regulation relating to the control and reduction of GHG emissions (including carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride), may materially limit or otherwise materially adversely affect our operations. The implementation of recent and proposed California and federal legislation and regulation may materially adversely affect our unregulated businesses by imposing, among other things, additional costs associated with emission limits, controls and the possible requirement of carbon taxes or the purchase of emissions credits. Similarly, the California Utilities may be materially adversely affected if these additional costs are not recoverable in rates. Even if recoverable, the effects of existing and proposed greenhouse gas emission reduction standards may cause rates to increase to levels that substantially reduce customer demand and growth. SDG&E may also be subject to significant penalties and fines if certain mandated renewable energy goals are not met.

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 materially adversely affect our results of operations and/or cash flows. Moreover, existing rules and regulations may be interpreted or revised in ways that may materially adversely affect our results of operations and/or cash flows.

We provide further discussion of these matters in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Natural disasters, catastrophic accidents or acts of terrorism could materially adversely affect our businesses, financial condition, results of operations, cash flows and/or prospects.

Like other major industrial facilities, ours may be damaged by natural disasters, catastrophic accidents, or acts of terrorism. Because we are in the business of using, storing, transporting and disposing of highly flammable and explosive materials, as well as radioactive materials, and operating highly energized equipment, the risk to our facilities and infrastructure, as well as the risks to the surrounding communities is substantially greater than a typical business. Such facilities and infrastructure include, but are not limited to:

§ power generation plants	§ natural gas, propane and ethane pipelines and storage
§ electric transmission and distribution	§ nuclear waste storage facilities
§ LNG terminals and storage	§ nuclear power generation facilities
§ chartered LNG tankers

Such incidents could result in severe business disruptions, significant decreases in revenues, and/or significant additional costs to us. Any such incident could have a material adverse effect on our businesses, financial condition, results of operations, cash flows and/or prospects.

Depending on the nature and location of the facilities and infrastructure affected, any such incident also could cause catastrophic fires, leaks, radioactive releases, explosions, spills or other significant damage to natural resources or property belonging to third parties, or cause personal injuries or fatalities. Any of these consequences could lead to significant claims against us. In some cases, we may be liable for damages even though we are not at fault, and in cases where the concept of inverse condemnation applies, we may be liable for damages without being found to be at fault or to have been negligent. Insurance coverage may significantly increase in cost or become unavailable for certain of these risks, and any insurance proceeds we receive may be insufficient to cover our losses or liabilities, which could materially adversely affect our businesses, financial condition, results of operations, cash flows and/or prospects.

Our businesses, results of operations, financial condition and/or cash flows may be materially adversely affected by the outcome of pending litigation against us.

Sempra Energy and its subsidiaries are defendants in numerous lawsuits. We have spent, and continue to spend, substantial amounts of money and time defending these lawsuits, and in related investigations and regulatory proceedings. In particular, SDG&E is subject to numerous lawsuits arising out of San Diego County wildfires in 2007. We discuss these proceedings in Note 15 of the Notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report. The uncertainties inherent in legal proceedings make it difficult to estimate with any degree of certainty the costs and effects of resolving these matters. In addition, California juries have demonstrated a willingness to grant large awards, including punitive damages, in personal injury, product liability, property damage and other claims. Accordingly, actual costs incurred may differ materially from insured or reserved amounts and may not be recoverable in whole or in part from our customers, which in each case could materially adversely affect our businesses, cash flows, results of operations and/or financial condition.

We cannot and do not attempt to fully hedge our assets or contract positions against changes in commodity prices. In addition, for those contract positions that are hedged, our hedging procedures may not mitigate our risk as planned.

To reduce financial exposure related to commodity price fluctuations, we may enter into contracts to hedge our known or anticipated purchase and sale commitments, inventories of natural gas and LNG, electric generation capacity, and natural gas storage and pipeline capacity. As part of this strategy, we may use forward contracts, physical purchase and sales contracts, futures, financial swaps, and options. We do not hedge the entire exposure to market price volatility of our assets or our contract positions, and the coverage will vary over time. To the extent we have unhedged positions, or if our hedging strategies do not work as planned, fluctuating commodity prices could have a material adverse effect on our results of operations, cash flows and/or financial condition.

In addition, certain of the contracts we use for hedging purposes are subject to fair value accounting. Such accounting may result in gains or losses in earnings for that contract. In certain cases, these gains or losses may not reflect the associated losses or gains of the underlying position being hedged.

Risk management procedures may not prevent losses.

Although we have in place risk management systems and control systems that use advanced methodologies to quantify and manage risk, these systems may not always prevent material losses. Risk management procedures may not always be followed as required by the companies or may not always work as planned. In addition, daily value-at-risk and loss limits are based on historic price movements. If prices significantly or persistently deviate from historic prices, the limits may not protect us from significant losses. As a result of these and other factors, there is no assurance that our risk management procedures will prevent losses that would materially adversely affect our results of operations, cash flows and/or financial condition.

The operation of our facilities depends on good labor relations with our employees.

Several of our businesses have entered into and have in place collective bargaining agreements with different labor unions. Our collective bargaining agreements are generally negotiated on a facility-by-facility basis.

Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. These potential labor disruptions could have a material adverse effect on our businesses, results of operations and/or cash flows. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our businesses, results of operations and/or cash flows.

New business technologies present a risk for attacks on our information systems and the integrity of our energy grid.

Cybersecurity and the protection of our operations and activities are a priority at Sempra Energy, SDG&E and SoCalGas. We believe that the most significant cybersecurity risks to our businesses reside within the operations of our utilities. In addition to general information and cyber risks that all Fortune 500 corporations face (e.g. malware, malicious intent by insiders and inadvertent disclosure of sensitive information), the utility industry faces new cybersecurity risks associated with automated metering (virtually all of our SDG&E customers have such metering and SoCalGas is beginning the process of converting its customers to such metering) and with Smart Grid infrastructure. Deployment of these new business technologies represents a new and large-scale opportunity for attacks on the utilities’ information systems and, more importantly, on the integrity of the energy grid. While addressing these risks is the subject of significant ongoing activities across Sempra Energy’s businesses, we cannot ensure that a successful attack will not occur. Such an attack to our information systems, the integrity of the energy grid, or one of our facilities could have a material adverse effect on our businesses, cash flows, financial condition, results of operations and/or prospects.

Risks Related to the California Utilities

The California Utilities are subject to extensive regulation by state, federal and local legislative and regulatory authorities, which may materially adversely affect us.

The CPUC regulates the California Utilities’ rates, except SDG&E’s electric transmission rates which are regulated by the FERC. The CPUC also regulates the California Utilities’:

§ conditions of service	§ rates of depreciation
§ capital structure	§ long-term resource procurement
§ rates of return	§ sales of securities

The CPUC conducts various reviews and audits of utility performance, compliance with CPUC regulations and standards, affiliate relationships and other matters. These reviews and audits may result in disallowances, fines and penalties that could materially adversely affect our financial condition, results of operations and/or cash flows. SoCalGas and SDG&E may be subject to penalties or fines related to their operation of natural gas pipelines under new regulations concerning natural gas pipeline safety, which could have a material adverse effect on their results of operations, financial condition and/or cash flows. We discuss various CPUC proceedings relating to the California Utilities’ rates, costs, incentive mechanisms, and performance-based regulation in Note 14 of the Notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

The California Utilities may spend significant amounts of money related to a major capital project prior to receiving regulatory approval. If the project does not receive regulatory approval, if the regulatory approval is conditioned on major changes, or if management decides not to proceed with the project, they may be unable to recover all amounts spent for that project, which could materially adversely affect their financial condition, results of operations, cash flows and/or prospects.

The CPUC periodically approves the California Utilities’ rates based on authorized capital expenditures, operating costs and an authorized rate of return on investment. If actual capital expenditures and/or operating costs were to exceed the amounts approved by the CPUC, results of operations, financial condition, cash flows and/or prospects could be materially adversely affected. Reductions in key benchmark interest rates may trigger automatic adjustment mechanisms which would reduce the California Utilities’ authorized rates of return, changes in which could materially adversely affect results of operations, financial condition, cash flows and/or prospects, as we discuss under “Cost of Capital” in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

The CPUC applies performance-based measures and incentive mechanisms to all California utilities. Under these, earnings potential above authorized base margins is tied to achieving or exceeding specific performance and operating goals, rather than relying solely on expanding utility plant (rate base) to increase earnings. At the California Utilities, the areas that are eligible for incentives are operational activities such as employee safety, energy efficiency programs and, at SoCalGas, natural gas procurement and unbundled natural gas storage and system operator hub services. Although the California Utilities have received incentive awards in the past, there can be no assurance that they will receive awards in the future, or that any future awards earned would be in amounts comparable to prior periods. Additionally, if the California Utilities fail to achieve certain minimum performance levels established under such mechanisms, they may be assessed financial disallowances, penalties and fines which could have a material adverse effect on their results of operations, financial condition and/or cash flows.

The FERC regulates electric transmission rates, the transmission and wholesale sales of electricity in interstate commerce, transmission access, the rates of return on investments in electric transmission assets, and other similar matters involving SDG&E.

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

The construction and expansion of the California Utilities’ natural gas pipelines, SoCalGas’ storage facilities, and SDG&E’s electric transmission and distribution facilities require numerous permits, licenses and other approvals from federal, state and local governmental agencies. If there are delays in obtaining these approvals, or failure to obtain or maintain these approvals, or to comply with applicable laws or regulations, the California Utilities’ businesses, cash flows, results of operations, financial condition and/or prospects could be materially adversely affected. Coordinating these projects so that they are on time and within budget requires superior execution from our employees and contractors, cooperation of third parties and the absence of litigation and regulatory delay. In the event that one or more of these major projects is delayed or experiences significant cost overruns, this could have a material adverse effect on the California Utilities.

Recovery of 2007 Wildfire Litigation Costs Requires Future Regulatory Approval.

SDG&E is subject to numerous lawsuits arising out of the San Diego County wildfires in 2007. Through December 31, 2012, SDG&E’s costs to settle these claims and its estimated future settlement costs and defense costs are approximately $2.4 billion, exceeding its $1.1 billion of liability insurance coverage and the approximately $824 million recovered from third parties. SDG&E is seeking to recover in rates its reasonably incurred costs of resolving 2007 wildfire claims in excess of its liability insurance coverage and amounts recovered from third parties. SDG&E has concluded that it is probable that SDG&E will be permitted to recover a substantial portion of these excess costs in rates, and at December 31, 2012, Sempra Energy’s and SDG&E’s Consolidated Balance Sheets include assets of $364 million in Regulatory Assets Arising From Wildfire Litigation Costs, of which $317 million is related to CPUC-regulated operations and $47 million is related to FERC-regulated operations, with respect to these excess costs. However, recovery of these amounts in rates will require future regulatory approval.

In August 2009, SDG&E and SoCalGas filed an application with the CPUC proposing a new mechanism for the future recovery of wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. In December 2012, the CPUC issued a final decision that denied the proposed blanket cost recovery framework for the utilities but allowed SDG&E to maintain its authorized memorandum account, enabling SDG&E to file applications with the CPUC requesting recovery of amounts properly recorded in the memorandum account, subject to reasonableness review, at a later date. For a description of this proceeding and information about 2007 wildfire litigation costs and their recovery, see Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E will continue to assess the probability of recovery of these excess wildfire costs in rates. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated as of December 31, 2012, the resulting after-tax charge against earnings would have been up to $190 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated costs to litigate or settle pending wildfire claims.

As noted above, recovery of excess wildfire costs in rates will require future regulatory approval, and a failure to obtain all or a significant portion of the expected recovery, or a conclusion that recovery in rates is no longer probable, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s cash flows, financial condition and/or results of operations. In addition, if recovery is permitted, the collection process may extend over a number of years and Sempra Energy’s and SDG&E’s cash flows may be materially adversely affected due to the timing differences between resolution of claims and the recovery in rates. We discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

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

SDG&E has a 20-percent ownership interest in SONGS, a 2,150-MW nuclear generating facility near San Clemente, California, operated by Southern California Edison Company. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. SDG&E’s ownership interest in SONGS subjects it to the risks of nuclear generation, which include

the potential that a natural disaster such as an earthquake or tsunami could cause a catastrophic failure of the safety systems in place that are designed to prevent the release of radioactive material. If such a failure were to occur, a substantial amount of radiation could be released and cause catastrophic harm to human health and the environment;

§	the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;

§	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations;

§	uncertainties with respect to the technological and financial aspects of equipment maintenance, and the decommissioning of nuclear plants;

§	a substantial increase in oversight and new and more onerous regulations due to the nuclear disaster at Japan’s Fukushima Daiichi plant in early 2011; and

§	the results of the CPUC’s Order Instituting Investigation (OII), as described in more detail below, into the SONGS outage that began in the first quarter of 2012.

The occurrence of any of these events could have a material adverse effect on SDG&E’s and Sempra Energy’s businesses, cash flows, financial condition, results of operations and/or prospects.

Ongoing regulatory and maintenance issues at SONGS may have a material adverse effect on us.

As discussed in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, SONGS’s Units 2 and 3 are offline. The timing of the restart of either of these Units is dependent upon approval by the NRC, which could result in substantial additional expenditures that may not be recoverable, in whole or in part, in customer rates. In November 2012, the CPUC issued an OII into the SONGS outage to determine whether SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires all costs related to SONGS incurred since January 1, 2012, be tracked in newly established memorandum accounts, with all revenues collected since January 1, 2012, in recovery of such costs and the return on SDG&E’s investment in SONGS subject to refund. The OII will address the extent to which such revenues, if any, will be required to be refunded to customers. Any extended shut down of one or both of these Units and the costs required to bring those Units back online could materially adversely affect SDG&E’s and Sempra Energy’s results of operations, cash flows, financial condition and/or prospects. In addition, any decision by the CPUC to require SDG&E to refund some or all of the revenues collected in recovery of the costs described above could materially adversely affect SDG&E’s and Sempra Energy’s results of operations, cash flows, financial condition and/or prospects.

Risks Related to our Sempra International and Sempra U.S. Gas & Power Businesses

Our businesses are exposed to market risks, including fluctuations in commodity prices, and our businesses, financial condition, results of operations, cash flows and/or prospects may be materially adversely affected by these risks.

Sempra Mexico, Sempra Renewables and Sempra Natural Gas generate electricity that they sell under long-term contracts and into the spot market or other competitive markets. Sempra Mexico and Sempra Natural Gas purchase natural gas to fuel their power plants and may also purchase electricity in the open market to satisfy their contractual obligations. As part of their risk management strategy, they may hedge a substantial portion of their electricity sales and natural gas purchases to manage their portfolios, which subjects us to the risk that the counterparty to such hedge may be unable to fulfill its obligations. Such a failure could materially adversely affect our cash flows, financial condition and/or results of operations.

We buy energy-related commodities from time to time, for power plants or for LNG terminals to satisfy contractual obligations with customers, in regional markets and other competitive markets in which we compete. Our revenues and results of operations could be materially adversely affected if the prevailing market prices for electricity, natural gas, LNG or other commodities that we buy change in a direction or manner not anticipated and for which we had not provided adequately through purchase or sale commitments or other hedging transactions.

Unanticipated changes in market prices for energy-related commodities result from multiple factors, including:

§	weather conditions

§	seasonality

§	changes in supply and demand

§	transmission or transportation constraints or inefficiencies

§	availability of competitively priced alternative energy sources

§	commodity production levels

§	actions by oil producing nations or organizations affecting the global supply of crude oil

§	federal, state and foreign energy and environmental regulation and legislation

§	natural disasters, wars, embargoes and other catastrophic events

§	expropriation of assets by foreign countries

The FERC has jurisdiction over wholesale power and transmission rates, independent system operators, and other entities that control transmission facilities or that administer wholesale power sales in some of the markets in which we operate. The FERC may impose additional price limitations, bidding rules and other mechanisms, or terminate existing price limitations from time to time. Any such action by the FERC may result in prices for electricity changing in an unanticipated direction or manner and, as a result, may have a material adverse effect on our businesses, cash flows, results of operations and/or prospects.

When our businesses enter into fixed-price long-term contracts to provide services or commodities, we are exposed to inflationary pressures such as rising commodity prices, and interest rate risks.

Sempra Mexico, Sempra Renewables and Sempra Natural Gas generally endeavor to secure long-term contracts with customers for services and commodities to optimize the use of their facilities, reduce volatility in earnings, and support the construction of new infrastructure. However, if these contracts are at fixed prices, the profitability of the contract may be materially adversely affected by inflationary pressures, including rising operational costs, costs of labor, materials, equipment and commodities, and rising interest rates that affect financing costs. We may try to mitigate these risks by using variable pricing tied to market indices, anticipating an escalation in costs when bidding on projects, providing for cost escalation or entering into hedges. However, these measures, if implemented, may not ensure that the increase in revenues they provide will fully offset increases in operating expenses and/or financing costs. The failure to so fully or substantially offset these increases could have a material adverse effect on our financial condition, cash flows and/or results of operations.

Business development activities may not be successful and projects under construction may not commence operation as scheduled or be completed within budget, which could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.

The acquisition, development, construction and expansion of LNG terminals, natural gas, propane and ethane pipelines and storage facilities, electric generation and transmission facilities, and other energy infrastructure projects involve numerous risks. We may be required to spend significant sums for preliminary engineering, permitting, fuel supply, resource exploration, legal, and other expenses before we can determine whether a project is feasible, economically attractive, or capable of being built.

Success in developing a particular project is contingent upon, among other things:

§	negotiation of satisfactory engineering, procurement and construction agreements

§	negotiation of supply and natural gas sales agreements or firm capacity service agreements

§	timely receipt of required governmental permits and rights of way

§	timely implementation and satisfactory completion of construction

Successful completion of a particular project may be materially adversely affected by:

§	unforeseen engineering problems

§	construction delays and contractor performance shortfalls

§	work stoppages

§	equipment unavailability or delay and cost increases

§	adverse weather conditions

§	environmental and geological conditions

§	litigation

§	unsettled property rights

§	other factors

If we are unable to complete the development of a facility or if we have substantial delays or cost overruns, this could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.

The operation of existing and future facilities also involves many risks, including the breakdown or failure of generation or regasification and storage facilities or other equipment or processes, labor disputes, fuel interruption, environmental contamination and operating performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, regasification, storage and transmission systems. The occurrence of any of these events could lead to our facilities being idled for an extended period of time or our facilities operating well below expected capacity levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Such occurrences could materially adversely affect our businesses, financial condition, cash flows, results of operations and/or prospects.

With respect to our proposed project to add LNG export capability at our Cameron facility, we currently anticipate building a facility consisting of three liquefaction trains with a total nameplate capacity of 13.5 million tonnes per annum (Mtpa) of LNG and expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. Total cost will be approximately $6 billion to $7 billion, excluding capitalized interest and other financing costs and subject to final design specifications. While we have signed commercial development agreements with Mitsubishi Corporation, Mitsui & Co. and a subsidiary of GDF SUEZ S.A., these agreements only bind the parties to fund certain development costs, including design, permitting and engineering costs of the proposed project and to negotiate in good faith 20-year tolling agreements with respect to 12 Mtpa of LNG. The development agreements do not obligate the parties to finance the actual construction of this new facility, and there can be no assurance that the parties will reach agreement on the terms of the 20-year tolling agreements. If one or more of the parties decides not to move forward with the project or does not enter into a tolling agreement, or if we are unable to arrange suitable financing, the project may be substantially delayed, reduced or terminated. If the project is terminated, we may not recover our share of any project development or other related costs expended and may be required to write off our share of any such previously capitalized costs. In addition, this project may be delayed, reduced or terminated in the event we are unable to obtain all of the necessary permits, licenses and authorizations in a timely manner. If the application to export to non-FTA countries is not approved, the size of the project may be reduced, or the project may be delayed or terminated. The anticipated cost of this project is based on a number of assumptions that may prove incorrect, and the ultimate cost could significantly exceed the current estimate of $6 billion to $7 billion, excluding capitalized interest and other financing costs and subject to final design specifications. Customers look at a number of factors when evaluating participation in a project, and changes in these factors, including global natural gas and LNG prices, could have an impact on the project going forward. Prior to our final investment decision and in the event we decide not to proceed with the project, these risks could have a material adverse effect on our prospects. Following our final investment decision and in the event we decide to proceed with the project, these risks could have a material adverse effect on our business, results of operations, cash flows, financial condition, and/or prospects.

We may elect not to, or may not be able to, enter into long-term supply and sales agreements or long-term firm capacity agreements for our projects, which would subject our revenues to increased volatility and our businesses to increased competition.

The electric generation and wholesale power sales industries are highly competitive. As more plants are built and competitive pressures increase, wholesale electricity prices may become more volatile. Without the benefit of long-term power sales agreements, our revenues may be subject to increased price volatility. The 10-year power sales agreement between Sempra Natural Gas and the DWR, which comprised 6 percent of our revenues in 2011 and 8 percent of our revenues in 2010, expired on September 30, 2011. As a result, we may be unable to sell the power that Sempra Natural Gas’ and Sempra Mexico’s facilities are capable of producing or to sell it at favorable prices, which could materially adversely affect our results of operations, cash flows and/or prospects.

Sempra Mexico and Sempra Natural Gas utilize their LNG terminals by entering into long-term capacity agreements. Under these agreements, customers pay us capacity reservation and usage fees to receive, store and regasify the customer’s LNG. These segments also may enter into short-term and/or long-term supply agreements to purchase LNG to be received, stored and regasified at their terminals for sale to other parties. The long-term supply agreement contracts are expected to reduce our exposure to changes in natural gas prices through corresponding natural gas sales agreements or by tying LNG supply prices to prevailing natural gas market price indices. However, if our LNG operations are unable to obtain sufficient long-term agreements or if the counterparties, customers or suppliers to one or more of the key agreements for the LNG facilities were to fail to perform or become unable to meet their contractual obligations on a timely basis, it could have a material adverse effect on our results of operations, cash flows and/or prospects. Our potential LNG suppliers also may be subject to international political and economic pressures and risks, which may also affect the supply of LNG.

Sempra Mexico’s and Sempra Natural Gas’ natural gas pipeline operations are dependent on demand for and supply of LNG and/or natural gas from their transportation customers, which may include our LNG facilities.

We provide information about these matters in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Our businesses depend on counterparties, business partners, customers, and suppliers performing in accordance with their agreements. If they fail to so perform, we could incur substantial expenses and business disruptions and be exposed to commodity price risk and volatility, which could materially adversely affect our businesses, financial condition, cash flows, results of operations and/or prospects.

We are exposed to the risk that counterparties, business partners, customers, and suppliers that owe money or commodities as a result of market transactions or other long-term agreements will not perform their obligations in accordance with such agreements. Should they fail to so perform, we may be required to acquire alternative hedging arrangements or to honor the underlying commitment at then-current market prices. In such event, we may incur additional losses to the extent of amounts already paid to such counterparties or suppliers. In addition, many of our agreements are essential to the conduct and growth of our businesses. The failure of any of the parties to perform in accordance with these agreements could materially adversely affect our businesses, results of operations, cash flows, financial condition and/or prospects. Finally, we often extend credit to counterparties and customers. While we perform significant credit analyses prior to extending credit, we are exposed to the risk that we may not be able to collect amounts owed to us.

Sempra Mexico’s and Sempra Natural Gas’ obligations and those of their suppliers for LNG supplies are contractually subject to (1) suspension or termination for “force majeure” events beyond the control of the parties; and (2) substantial limitations of remedies for other failures to perform, including limitations on damages to amounts that could be substantially less than those necessary to provide full recovery of costs for breach of the agreements, which in either event could have a material adverse effect on our results of operations, cash flows, financial condition and/or prospects.

Legal actions challenging our property rights could materially adversely affect our businesses, financial condition, cash flows, results of operations and/or prospects.

We are engaged in disputes regarding our title to the properties on which our LNG terminal in Mexico is located and our title to the property on which our Termoeléctrica de Mexicali power generation facility is located. In June 2012, the state civil court in Mexicali ruled that our title to the property on which our Termoeléctrica de Mexicali power generation facility is located was invalid due to procedural errors made by our predecessor in title. However, the court also declined to award title to the claimant, and we are appealing the ruling invalidating our title. In the event that we are unable to defend and retain title to the properties on which our LNG terminal is located or the property on which our power generation facility is located, we could lose our rights to occupy and use such properties and the related facility or terminal, which could result in breaches of one or more permits or contracts that we have entered into with respect to such facility and/or terminal. If we are unable to occupy and use such properties and the related facility or terminal, it could have a material adverse effect on our businesses, financial condition, results of operations, cash flows and/or prospects.

We rely on transportation assets and services, much of which we do not own or control, to deliver electricity and natural gas.

We depend on electric transmission lines, natural gas pipelines, and other transportation facilities owned and operated by third parties to:

§	deliver the electricity and natural gas we sell to wholesale markets,

§	supply natural gas to our electric generation facilities, and

§	provide retail energy services to customers.

Sempra Mexico and Sempra Natural Gas also depend on natural gas pipelines to interconnect with their ultimate source or customers of the commodities they are transporting. Sempra Mexico and Sempra Natural Gas also rely on specialized ships to transport LNG to their facilities and on natural gas pipelines to transport natural gas for customers of the facilities. Sempra Natural Gas, Sempra Renewables, Sempra South American Utilities and Sempra Mexico rely on transmission lines to sell electricity to their customers. If transportation is disrupted, or if capacity is inadequate, we may be unable to sell and deliver our commodities, electricity and other services to some or all of our customers. As a result, we may be responsible for damages incurred by our customers, such as the additional cost of acquiring alternative natural gas supplies at then-current spot market rates, which could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.

Our international businesses are exposed to different local, regulatory and business risks and challenges, which could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.

We own or have interests in electricity generation and transmission, natural gas distribution and transportation, and LNG terminal projects in Mexico, and electricity and natural gas distribution businesses in Argentina, Chile and Peru. Developing infrastructure projects, owning energy assets, and operating businesses in foreign jurisdictions subject us to significant political, legal, regulatory and financial risks that vary by country, including:

§	changes in foreign laws and regulations, including tax and environmental laws and regulations, and U.S. laws and regulations, in each case, that are related to foreign operations

§	governance by and decisions of local regulatory bodies, including setting of rates and tariffs that may be earned by our businesses

§	high rates of inflation

§	volatility in exchange rates between the U.S. dollar and currencies of the countries in which we operate

§	changes in government policies or personnel

§	trade restrictions

§	limitations on U.S. company ownership in foreign countries

§	permitting and regulatory compliance

§	changes in labor supply and labor relations

§	adverse rulings by foreign courts or tribunals, challenges to permits and approvals, difficulty in enforcing contractual and property rights, and unsettled property rights and titles in Mexico and other foreign jurisdictions

§	expropriation of assets

§	adverse changes in the stability of the governments in the countries in which we operate

§	general political, social, economic and business conditions

Our international businesses also are subject to foreign currency risks. These risks arise from both volatility in foreign currency exchange and inflation rates and devaluations of foreign currencies. In such cases, an appreciation of the U.S. dollar against a local currency could materially reduce the amount of cash and income received from those foreign subsidiaries. Fluctuations in foreign currency exchange and inflation rates may result in significantly increased taxes in foreign countries and materially adversely affect our cash flows, financial condition, results of operations and/or prospects.

We discuss litigation related to Sempra Mexico’s Energía Costa Azul LNG terminal, Termoeléctrica de Mexicali power generation facility and other international energy projects in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Other Risks

Sempra Energy has substantial investments and other obligations in businesses that it does not control or manage or in which it shares control.

Sempra Energy is a partner with The Royal Bank of Scotland plc in RBS Sempra Commodities LLP (RBS Sempra Commodities), a commodities-marketing firm, which divested substantially all of its businesses and assets in 2010 and early 2011, as we discuss in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report. The investment balance of $126 million at December 31, 2012 reflects remaining distributions expected to be received from the partnership as it is dissolved. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report. In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership. We have guaranteed various obligations of businesses previously owned and operated by RBS Sempra Commodities, as we discuss in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report. The failure to collect all or a substantial portion of our remaining investment in the partnership could have a corresponding effect on our cash flows, financial condition and results of operations.

As described above, SDG&E holds a 20-percent ownership interest in SONGS, which is operated by Edison. Also, Sempra Natural Gas owns a 25-percent interest in Rockies Express Pipeline LLC (Rockies Express), a joint venture that operates a natural gas pipeline. Our investment in Rockies Express is $361 million at December 31, 2012. Rockies Express is controlled by Tallgrass Energy Partners, which holds a 50-percent interest. At December 31, 2012, Sempra Renewables has investments totaling $592 million in several joint ventures to develop and operate renewable generation facilities. Sempra Mexico owns a 50-percent interest in a joint venture with PEMEX that operates two natural gas pipelines and a propane system in northern Mexico. At December 31, 2012, this investment is $340 million. We also have smaller investments in other entities that we do not control or manage, or in which we share control, totaling $97 million at December 31, 2012. We continue to make such investments. We discuss these investments further in Notes 3, 4 and 11 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra Natural Gas is currently progressing with plans to develop its Cameron LNG regasification facility for liquefaction capability in a joint venture structure with three partners. We discuss these plans further in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Influencing Future Performance” in the Annual Report.

We have limited influence over these and other businesses in which we do not have a controlling interest. In addition to the other risks inherent in these businesses, if their management were to fail to perform adequately or the other investors in the businesses were unable or otherwise failed to perform their obligations to provide capital and credit support for these businesses, it could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

ELECTRIC PROPERTIES – SDG&E

At December 31, 2012, SDG&E owns and operates five natural gas-fired power plants:

§	a 560-megawatt (MW) electric generation facility (the Palomar generation facility) in Escondido, California

§	a 495-MW electric generation facility (the Desert Star generation facility) in Boulder City, Nevada

§	a 47.6-MW and a 48.6-MW electric generation peaking facility (collectively, the Miramar Energy Center) in San Diego, California

§	a 52-MW electric generation facility (the Cuyamaca Peak Energy Plant) in El Cajon, California

SDG&E’s interest in SONGS is described above in Item 1 under “Electric Utility Operations – SDG&E.” We also discuss matters related to a current outage and inspection and repair issues at SONGS in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.

At December 31, 2012, SDG&E’s electric transmission and distribution facilities included substations, and overhead and underground lines. These electric facilities are located in San Diego, Imperial and Orange counties of California, and in Arizona and Nevada. The facilities consist of 2,063 miles of transmission lines and 22,940 miles of distribution lines. Periodically, various areas of the service territory require expansion to accommodate customer growth.

SDG&E completed construction of and placed in service the Sunrise Powerlink electric transmission line in June 2012. The Sunrise Powerlink is a 117-mile, 500-kV electric transmission line that delivers up to 800 MW of energy, with plans to eventually carry 1,000 MW of energy, from the Imperial Valley to the San Diego region.

NATURAL GAS PROPERTIES – CALIFORNIA UTILITIES

At December 31, 2012, SDG&E’s natural gas facilities consisted of two compressor stations, 168 miles of transmission pipelines, 8,524 miles of distribution pipelines and 6,402 miles of service pipelines.

At December 31, 2012, SoCalGas’ natural gas facilities included 2,964 miles of transmission and storage pipelines, 49,874 miles of distribution pipelines and 47,413 miles of service pipelines. They also included 11 transmission compressor stations and four underground natural gas storage reservoirs with a combined working capacity of 138 Bcf.

ENERGY PROPERTIES – SEMPRA INTERNATIONAL AND SEMPRA U.S. GAS & POWER

At December 31, 2012, Sempra Mexico, Sempra Renewables and Sempra Natural Gas operate or own interests in power plants and renewable generation facilities in North America with a total capacity of 3,257 MW. Our share of this capacity is 2,717 MW. In December 2012, Sempra Natural Gas entered into a definitive agreement to sell one 625-MW block of Mesquite Power to the Salt River Project Agricultural Improvement and Power District. We expect the transaction to close in the first quarter of 2013. We provide additional information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra South American Utilities operates Chilquinta Energía located in Valparaiso, Chile. Its property consists of 9,737 miles of distribution lines, 339 miles of transmission lines and 46 substations.

Sempra South American Utilities operates Luz del Sur located in Lima, Peru. Its property consists of 12,031 miles of distribution lines and 175 miles of transmission lines. Luz del Sur expects to complete construction of Santa Teresa, a 98-MW hydroelectric power plant located in the Cusco region of Peru, in 2014.

At December 31, 2012, Sempra Mexico’s operations included 1,921 miles of distribution pipelines, 224 miles of transmission pipelines and three compressor stations. Sempra Mexico operates its Energía Costa Azul LNG terminal on land it owns in Baja California, Mexico.

Sempra Renewables leases properties in Arizona and Nevada for currently operating solar electric generation facilities with the potential to develop additional solar electric generation facilities on these properties. Sempra Renewables also owns property in California for potential development of solar and wind electric generation facilities. Sempra Mexico leases properties in Mexico for potential development of wind electric generation facilities.

In 2006, Sempra Natural Gas and ProLiance Transportation and Storage, LLC acquired three existing salt caverns representing 10 Bcf to 12 Bcf of potential natural gas storage capacity in Cameron Parish, Louisiana, with plans for development of a natural gas storage facility.

Sempra Natural Gas owns and operates Mobile Gas, a natural gas distribution utility located in Mobile and Baldwin counties in Alabama. Its property consists of distribution mains, service lines and regulating equipment.

Sempra Natural Gas also owns and operates Willmut Gas, a natural gas distribution utility located in Forrest County, Mississippi, serving Forrest, Simpson, Lamar, Jones, Covington and Rankin counties. Its property consists of distribution mains, service lines and regulating equipment.

In Washington County, Alabama, Sempra Natural Gas operates a 15.5 Bcf natural gas storage facility under a land lease, with current plans to expand total working capacity to 21 Bcf to be in-service in 2013. Sempra Natural Gas also owns land in Simpson County, Mississippi, on which it operates a 15 Bcf natural gas storage facility, with current plans to expand total working capacity to 22 Bcf to be in-service in 2013. Portions of both these properties are currently under construction.

Sempra Natural Gas has a land lease and owns land in Hackberry, Louisiana, where it operates its Cameron LNG terminal. Sempra Natural Gas also owns land in Port Arthur, Texas, for potential development.

OTHER PROPERTIES

Sempra Energy occupies its 19-story corporate headquarters building in San Diego, California, pursuant to an operating lease that expires in 2015. The lease has two five-year renewal options.

SoCalGas leases approximately one-fourth of a 52-story office building in downtown Los Angeles, California, pursuant to an operating lease expiring in 2026. The lease has four five-year renewal options.

SDG&E occupies a six-building office complex in San Diego pursuant to two separate operating leases, both ending in December 2017. One lease has four five-year renewal options and the other lease has three five-year renewal options.

Sempra International and Sempra U.S. Gas & Power own or lease office facilities at various locations in the U.S., Mexico, Chile and Peru, with the leases ending from 2013 to 2020.

Sempra Energy, SDG&E and SoCalGas own or lease other land, easements, rights of way, warehouses, offices, operating and maintenance centers, shops, service facilities and equipment necessary to conduct their businesses.

ITEM 3. LEGAL PROCEEDINGS

We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters (1) described in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, or (2) referred to in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

COMMON STOCK AND RELATED SHAREHOLDER MATTERS

The common stock, related shareholder, and dividend restriction information required by Item 5 is included in “Common Stock Data” in the Annual Report.

SEMPRA ENERGY EQUITY COMPENSATION PLANS

Sempra Energy has long term incentive plans that permit the grant of a wide variety of equity and equity-based incentive awards to directors, officers and key employees. At December 31, 2012, outstanding awards consisted of stock options, restricted stock, and restricted stock units held by 339 employees.

The following table sets forth information regarding our equity compensation plans at December 31, 2012.

		Number of shares to
		be issued upon			Number of
		exercise of	Weighted-average		additional
		outstanding	exercise price of		shares remaining
		options, warrants	outstanding options,		available for future
		and rights(A)	warrants and rights		issuance
Equity compensation plans approved
by shareholders:
2008 Long Term Incentive Plan		2,689,318	$	51.87	1,701,461	(B)

Equity compensation plans not approved
by shareholders:
2008 Long Term Incentive Plan for
EnergySouth, Inc. Employees and
Other Eligible Individuals(C)		11,800	$	49.57	195,488	(D)
Total		2,701,118	$	51.86	1,896,949

(A)	Consists solely of options to purchase shares of our common stock, all of which were granted at an exercise price of 100% of the grant date fair market value of the shares subject to the option.
(B)	The number of shares available for future issuance is increased by the number of shares withheld to satisfy tax withholding obligations relating to stock option and other plan awards and by the number of shares subject to awards that lapse, expire or are otherwise terminated or are settled other than by the issuance of shares.
(C)	Adopted in connection with our acquisition of EnergySouth, Inc. in October 2008 to utilize shares remaining available under the 2008 Incentive Plan of EnergySouth, Inc., which had been previously approved by EnergySouth, Inc. shareholders.
(D)	The number of shares available for future issuance is increased by the number of shares subject to awards that terminate without the issuance of shares.

We provide additional discussion of share-based compensation in Note 9 of the Notes to Consolidated Financial Statements in the Annual Report.

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

On September 11, 2007, the Sempra Energy board of directors authorized the repurchase of Sempra Energy common stock provided that the amounts spent for such purpose do not exceed the greater of $2 billion or amounts spent to purchase no more than 40 million shares.

During 2008, we expended $1 billion to purchase a total of 18,416,241 shares. No shares were repurchased under this authorization during 2009.

In 2010, we entered into a Collared Accelerated Share Acquisition Program with JPMorgan Chase Bank, National Association, under which we prepaid $500 million to repurchase shares of our common stock. We received 8,078,000 shares in 2010 and 1,496,435 shares in March 2011. We discuss this program, which was completed in March 2011, in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.

Therefore, approximately $500 million remains authorized by the board for the purchase of additional shares, not to exceed approximately 12 million shares. We also may, from time to time, purchase shares of our common stock from restricted stock plan participants who elect to sell a sufficient number of vesting restricted shares to meet minimum statutory tax withholding requirements.

ITEM 6. SELECTED FINANCIAL DATA

The information required by Item 6 is included in “Five-Year Summaries” in the Annual Report.

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

The information required by Item 7 is set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report, on pages 2 through 71.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by Item 7A is set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk” in the Annual Report.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by Item 8 is set forth on pages 83 through 223 of the Annual Report. Item 15(a)1 of Part IV of this report includes a listing of financial statements included.

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

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES

The information required by Item 9A is provided in “Controls and Procedures” in the Annual Report.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

SEMPRA ENERGY

We provide the information required by Item 10 with respect to executive officers for Sempra Energy in Part I, Item 1. Business under “Executive Officers of the Registrants – Sempra Energy.” All other information required by Item 10 is incorporated by reference from “Corporate Governance” and “Share Ownership” in the Proxy Statement prepared for the May 2013 annual meeting of shareholders.

SDG&E AND SOCALGAS

We provide the information required by Item 10 with respect to executive officers for SDG&E and SoCalGas in Part I, Item 1. Business under “Executive Officers of the Registrants – SDG&E and SoCalGas.” All other information required by Item 10 is incorporated by reference from the companies’ Information Statements prepared for their June 2013 annual meetings of shareholders.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 is incorporated by reference from “Corporate Governance” and “Executive Compensation,” including “Compensation Discussion and Analysis” and “Compensation Committee Report” in the Proxy Statement prepared for the May 2013 annual meeting of shareholders for Sempra Energy and from the Information Statements prepared for the June 2013 annual meetings of shareholders for SDG&E and SoCalGas.

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

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

Information regarding securities authorized for issuance under equity compensation plans as required by Item 12 is included in Item 5.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

The security ownership information required by Item 12 is incorporated by reference from “Share Ownership” in the Proxy Statement prepared for the May 2013 annual meeting of shareholders for Sempra Energy and from the Information Statements prepared for the June 2013 annual meetings of shareholders for SDG&E and SoCalGas.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by Item 13 is incorporated by reference from “Corporate Governance” in the Proxy Statement prepared for the May 2013 annual meeting of shareholders for Sempra Energy and from the Information Statements prepared for the June 2013 annual meetings of shareholders for SDG&E and SoCalGas.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding principal accountant fees and services, as required by Item 14, is incorporated by reference from “Proposals To Be Voted On - Proposal 2: Ratification of Independent Registered Public Accounting Firm” in the Proxy Statement prepared for the May 2013 annual meeting of shareholders for Sempra Energy and from the Information Statements prepared for the June 2013 annual meetings of shareholders for SDG&E and SoCalGas.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

1. FINANCIAL STATEMENTS

	Page in Annual Report(1)

	Sempra Energy	San Diego Gas & Electric Company	Southern California Gas Company

Management’s Report On Internal Control Over Financial Reporting	76	76	76

Reports of Independent Registered Public Accounting Firm	77	79	81

Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010	83	91	98

Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010	84	92	99

Consolidated Balance Sheets at December 31, 2012 and 2011	85	93	100

Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010	87	95	102

Consolidated Statements of Changes in Equity for the years ended December 31, 2012, 2011 and 2010	89	97	N/A

Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2012, 2011 and 2010	N/A	N/A	103

Notes to Consolidated Financial Statements	104	104	104
(1) Incorporated by reference from the indicated pages of the 2012 Annual Report to Shareholders, filed as Exhibit 13.1.

2. FINANCIAL STATEMENT SCHEDULES

Sempra Energy

Schedule I--Sempra Energy Condensed Financial Information of Parent may be found on page 42 of this report.

Any other schedule for which provision is made in Regulation S-X is not required under the instructions contained therein, is inapplicable or the information is included in the Consolidated Financial Statements and Notes thereto in the Annual Report.

3. EXHIBITS

See Exhibit Index on page 50 of this report.

CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM AND REPORT ON SCHEDULE

SEMPRA ENERGY

To the Board of Directors and Shareholders of Sempra Energy:

We consent to the incorporation by reference in Registration Statement No. 333-176855 on Form S-3 and 333-182225, 333-56161, 333-50806, 333-49732, 333-121073, 333-128441, 333-151184, 333-155191, 333-129774 and 333-157567 on Form S-8 of our reports dated February 26, 2013, relating to the consolidated financial statements of Sempra Energy and subsidiaries (the “Company”) , and the effectiveness of the Company’s internal control over financial reporting, incorporated by reference in this Annual Report on Form 10-K of Sempra Energy for the year ended December 31, 2012.

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

/S/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2013

SAN DIEGO GAS & ELECTRIC COMPANY

To the Board of Directors and Shareholders of San Diego Gas & Electric Company:

We consent to the incorporation by reference in Registration Statement No. 333-181639 on Form S-3 of our reports dated February 26, 2013, relating to the consolidated financial statements of San Diego Gas & Electric Company (the “Company”), and the effectiveness of the Company’s internal control over financial reporting, incorporated by reference in this Annual Report on Form 10-K of San Diego Gas & Electric Company for the year ended December 31, 2012.

/S/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2013

SOUTHERN CALIFORNIA GAS COMPANY

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

We consent to the incorporation by reference in Registration Statement No. 333-182557 on Form S-3 of our reports dated February 26, 2013, relating to the consolidated financial statements of Southern California Gas Company and subsidiaries (the “Company”), and the effectiveness of the Company’s internal control over financial reporting, incorporated by reference in this Annual Report on Form 10-K of Southern California Gas Company for the year ended December 31, 2012.

/S/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2013

SCHEDULE I – SEMPRA ENERGY CONDENSED FINANCIAL INFORMATION OF PARENT

SEMPRA ENERGY
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
		Years ended December 31,
		2012		2011		2010

Interest income		$	83	$	109	$	146
Interest expense			(247)		(242)		(265)
Operation and maintenance			(68)		(64)		(59)
Other income, net			66		42		65
Income tax benefits			145		82		79
Loss before equity in earnings of subsidiaries			(21)		(73)		(34)
Equity in earnings of subsidiaries, net of income taxes			880		1,404		743
Net income/earnings		$	859	$	1,331	$	709

Basic earnings per common share		$	3.56	$	5.55	$	2.90
Weighted-average number of shares outstanding (thousands)			241,347		239,720		244,736

Diluted earnings per common share		$	3.48	$	5.51	$	2.86
Weighted-average number of shares outstanding (thousands)			246,693		241,523		247,942
	See Notes to Condensed Financial Information of Parent.

SEMPRA ENERGY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
		Years ended December 31, 2012, 2011 and 2010
		Pretax		Income Tax		Net-of-tax
		Amount(1)		(Expense) Benefit		Amount
2012:
Net income		$	859			$	859
Other comprehensive income (loss):
Foreign currency translation adjustments			119	$	―		119
Pension and other postretirement benefits			(4)		2		(2)
Financial instruments			(6)		2		(4)
Total other comprehensive income			109		4		113
Total comprehensive income		$	968	$	4	$	972
2011:
Net income		$	1,331			$	1,331
Other comprehensive income (loss):
Foreign currency translation adjustments			(79)	$	3		(76)
Reclassification to net income of foreign
currency translation adjustment related
to remeasurement of equity method
investments			(54)		―		(54)
Available-for-sale securities			(2)		1		(1)
Pension and other postretirement benefits			(20)		8		(12)
Financial instruments			(26)		10		(16)
Total other comprehensive income (loss)			(181)		22		(159)
Total comprehensive income		$	1,150	$	22	$	1,172
2010:
Net income		$	709			$	709
Other comprehensive income (loss):
Foreign currency translation adjustments			47	$	―		47
Available-for-sale securities			(10)		2		(8)
Pension and other postretirement benefits			23		(10)		13
Financial instruments			(22)		9		(13)
Total other comprehensive income			38		1		39
Total comprehensive income		$	747	$	1	$	748
(1)	Except for Net Income and Total Comprehensive Income (Loss).
See Notes to Condensed Financial Information of Parent.

SEMPRA ENERGY
CONDENSED BALANCE SHEETS
(Dollars in millions)
	December 31,		December 31,
	2012		2011
Assets:
Cash and cash equivalents	$	18	$	11
Due from affiliates		125		112
Deferred income taxes		109		―
Other current assets		16		16
Total current assets		268		139

Investments in subsidiaries		12,545		12,209
Due from affiliates		1,759		1,730
Deferred income taxes		1,541		1,200
Other assets		576		548
Total assets	$	16,689	$	15,826

Liabilities and shareholders’ equity:
Current portion of long-term debt	$	652	$	8
Due to affiliates		539		1,014
Income taxes payable		26		246
Other current liabilities		260		336
Total current liabilities		1,477		1,604

Long-term debt		4,409		3,957
Other long-term liabilities		521		490
Shareholders’ equity		10,282		9,775
Total liabilities and shareholders’ equity	$	16,689	$	15,826
See Notes to Condensed Financial Information of Parent.

SEMPRA ENERGY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010

Net cash (used in) provided by operating activities	$	(809)	$	(287)	$	218

Dividends received from subsidiaries		250		50		100
Expenditures for property, plant and equipment		(1)		(2)		(1)
Purchase of trust assets		(6)		(7)		―
Proceeds from sales by trust		10		12		11
Capital contribution to subsidiary		―		(200)		―
(Increase) decrease in loans to affiliates, net		(33)		82		1,204
Cash provided by (used in) investing activities		220		(65)		1,314

Common stock dividends paid		(550)		(440)		(364)
Issuances of common stock		78		28		40
Repurchases of common stock		(16)		(18)		(502)
Issuances of long-term debt		1,100		799		40
Payments on long-term debt		(8)		(24)		(565)
Decrease in loans from affiliates, net		―		(136)		(40)
Other		(8)		(3)		9
Cash provided by (used in) financing activities		596		206		(1,382)

Increase (decrease) in cash and cash equivalents		7		(146)		150
Cash and cash equivalents, January 1		11		157		7
Cash and cash equivalents, December 31	$	18	$	11	$	157
See Notes to Condensed Financial Information of Parent.

SEMPRA ENERGY

NOTES TO CONDENSED FINANCIAL INFORMATION OF PARENT

Note 1. Basis of Presentation

Sempra Energy accounts for the earnings of its subsidiaries under the equity method in this unconsolidated financial information.

Other Income, Net, on the Condensed Statements of Operations includes $41 million, $22 million and $35 million of gains associated with investment earnings or losses on dedicated assets in support of our executive retirement and deferred compensation plans in 2012, 2011 and 2010, respectively.

Because of its nature as a holding company, Sempra Energy classifies dividends received from subsidiaries as an investing cash flow.

Note 2. Long-Term Debt

	December 31,		December 31,
(Dollars in millions)	2012		2011

6% Notes February 1, 2013	$	400	$	400
8.9% Notes November 15, 2013, including $200 at variable rates after
fixed-to-floating rate swaps effective January 2011 (8.05% at December 31, 2012)		250		250
2% Notes March 15, 2014		500		500
Notes at variable rates (1.07% at December 31, 2012) March 15, 2014		300		300
6.5% Notes June 1, 2016, including $300 at variable rates after
fixed-to-floating rate swaps effective January 2011 (4.64% at December 31, 2012)		750		750
2.3% Notes April 1, 2017		600		―
6.15% Notes June 15, 2018		500		500
9.8% Notes February 15, 2019		500		500
2.875% Notes October 1, 2022		500		―
6% Notes October 15, 2039		750		750
Employee Stock Ownership Plan Bonds at variable rates payable on demand
(0.40% at December 31, 2011) November 1, 2014		―		8
Market value adjustments for interest rate swaps, net
(expire November 2013 and June 2016)		19		16
		5,069		3,974
Current portion of long-term debt		(652)		(8)
Unamortized discount on long-term debt		(8)		(9)
Total long-term debt	$	4,409	$	3,957

Maturities of long-term debt are $650 million in 2013, $800 million in 2014, $750 million in 2016, $600 million in 2017 and $2.3 billion thereafter.

Additional information on Sempra Energy’s long-term debt is provided in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.

Note 3. Commitments and Contingencies

For contingencies and guarantees related to Sempra Energy, refer to Notes 5 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra Energy:
SIGNATURES

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

		SEMPRA ENERGY, (Registrant)

		By: /s/ Debra L. Reed
		Debra L. Reed Chairman and Chief Executive Officer

		Date: February 26, 2013

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

Name/Title	Signature		Date
Principal Executive Officer: Debra L. Reed Chief Executive Officer	/s/ Debra L. Reed		February 26, 2013

Principal Financial Officer: Joseph A. Householder Executive Vice President and Chief Financial Officer	/s/ Joseph A. Householder		February 26, 2013

Principal Accounting Officer: Trevor I. Mihalik Controller and Chief Accounting Officer	/s/ Trevor I. Mihalik		February 26, 2013

Directors:
Debra L. Reed, Chairman	/s/ Debra L. Reed		February 26, 2013


Alan L. Boeckmann, Director	/s/ Alan L. Boeckmann		February 26, 2013


James G. Brocksmith, Jr., Director	/s/ James G. Brocksmith, Jr.		February 26, 2013


Wilford D. Godbold, Jr., Director	/s/ Wilford D. Godbold, Jr.		February 26, 2013


William D. Jones, Director	/s/ William D. Jones		February 26, 2013


William G. Ouchi, Ph.D., Director	/s/ William G. Ouchi		February 26, 2013


William C. Rusnack, Director	/s/ William C. Rusnack		February 26, 2013


William P. Rutledge, Director	/s/ William P. Rutledge		February 26, 2013


Lynn Schenk, Director	/s/ Lynn Schenk		February 26, 2013


Jack T. Taylor, Director	/s/ Jack T. Taylor		February 26, 2013


Luis M. Téllez, Ph.D., Director	/s/ Luis M. Téllez		February 26, 2013

San Diego Gas & Electric Company:
SIGNATURES

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

	SAN DIEGO GAS & ELECTRIC COMPANY, (Registrant)

	By: /s/ Jessie J. Knight, Jr.
	Jessie J. Knight, Jr. Chairman and Chief Executive Officer

	Date: February 26, 2013


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

Name/Title	Signature	Date
Principal Executive Officer: Jessie J. Knight, Jr. Chief Executive Officer	/s/ Jessie J. Knight, Jr.	February 26, 2013

Principal Financial and Accounting Officer: Robert M. Schlax Vice President, Controller, Chief Financial Officer and Chief Accounting Officer	/s/ Robert M. Schlax	February 26, 2013

Directors:
Jessie J. Knight, Jr., Chairman	/s/ Jessie J. Knight, Jr.	February 26, 2013


Javade Chaudhri, Director	/s/ Javade Chaudhri	February 26, 2013


Steven D. Davis, Director	/s/ Steven D. Davis	February 26, 2013


Joseph A. Householder, Director	/s/ Joseph A. Householder	February 26, 2013


Michael R. Niggli, Director	/s/ Michael R. Niggli	February 26, 2013

Southern California Gas Company:
SIGNATURES

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

	SOUTHERN CALIFORNIA GAS COMPANY, (Registrant)

	By: /s/ Anne S. Smith
	Anne S. Smith Chairman and Chief Executive Officer

	Date: February 26, 2013


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

Name/Title	Signature	Date
Principal Executive Officer: Anne S. Smith Chief Executive Officer	/s/ Anne S. Smith	February 26, 2013

Principal Financial and Accounting Officer: Robert M. Schlax Vice President, Controller, Chief Financial Officer and Chief Accounting Officer	/s/ Robert M. Schlax	February 26, 2013

Directors:
Anne S. Smith, Chairman	/s/ Anne S. Smith	February 26, 2013


Dennis V. Arriola, Director	/s/ Dennis V. Arriola	February 26, 2013


Javade Chaudhri, Director	/s/ Javade Chaudhri	February 26, 2013


Steven D. Davis, Director	/s/ Steven D. Davis	February 26, 2013


Joseph A. Householder, Director	/s/ Joseph A. Householder	February 26, 2013

EXHIBIT INDEX

The exhibits filed under the Registration Statements, Proxy Statements and Forms 8-K, 10-K and 10-Q that are incorporated herein by reference were filed under Commission File Number 1-14201 (Sempra Energy), Commission File Number 1-40 (Pacific Lighting Corporation), Commission File Number 1-3779 (San Diego Gas & Electric Company) and/or Commission File Number 1-1402 (Southern California Gas Company).

The following exhibits relate to each registrant as indicated.
EXHIBIT 3 -- BYLAWS AND ARTICLES OF INCORPORATION
Sempra Energy
3.1	Amended and Restated Articles of Incorporation of Sempra Energy effective May 23, 2008 (Appendix B to the 2008 Sempra Energy Definitive Proxy Statement, filed on April 15, 2008).

3.2	Amended and Restated Bylaws of Sempra Energy effective September 13, 2012 (Sempra Energy Form 8-K filed on September 18, 2012, Exhibit 3(ii)).
San Diego Gas & Electric Company
3.3	Amended and Restated Bylaws of San Diego Gas & Electric effective June 15, 2010 (Form 8-K filed on June 17, 2010, Exhibit 3).

3.4	Restated Articles of Incorporation of San Diego Gas & Electric Company as amended effective November 13, 2006 (2006 SDG&E Form 10-K, Exhibit 3.02).
Southern California Gas Company
3.5	Amended and Restated Bylaws of Southern California Gas Company effective June 14, 2010 (Form 8-K filed on June 17, 2010, Exhibit 3.1).

3.6	Restated Articles of Incorporation of Southern California Gas Company effective October 7, 1996 (1996 SoCalGas Form 10-K, Exhibit 3.01).
EXHIBIT 4 -- INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS, INCLUDING INDENTURES
The companies agree to furnish a copy of each such instrument to the Commission upon request.
Sempra Energy
4.1	Description of rights of Sempra Energy Common Stock (Amended and Restated Articles of Incorporation of Sempra Energy effective May 23, 2008, Exhibit 3.1 above).

4.2	Indenture dated as of February 23, 2000, between Sempra Energy and U.S. Bank Trust National Association, as Trustee (Sempra Energy Registration Statement on Form S-3 (No. 333-153425), filed on September 11, 2008, Exhibit 4.1).
San Diego Gas & Electric Company
4.3	Description of preferences of Cumulative Preferred Stock, Preference Stock (Cumulative) and Series Preference Stock (SDG&E Restated Articles of Incorporation as amended effective November 13, 2006, Exhibit 3.4 above).
Southern California Gas Company
4.4	Description of preferences of Preferred Stock, Preference Stock and Series Preferred Stock (Southern California Gas Company Restated Articles of Incorporation, Exhibit 3.6 above).
Sempra Energy / San Diego Gas & Electric Company
4.5	Mortgage and Deed of Trust dated July 1, 1940 (SDG&E Registration Statement No. 2-4769, Exhibit B-3).

4.6	Second Supplemental Indenture dated as of March 1, 1948 (SDG&E Registration Statement No. 2-7418, Exhibit B-5B).

4.7	Ninth Supplemental Indenture dated as of August 1, 1968 (SDG&E Registration Statement No. 333-52150, Exhibit 4.5).

4.8	Tenth Supplemental Indenture dated as of December 1, 1968 (SDG&E Registration Statement No. 2-36042, Exhibit 2-K).

4.9	Sixteenth Supplemental Indenture dated August 28, 1975 (SDG&E Registration Statement No. 33-34017, Exhibit 4.2).
Sempra Energy / Southern California Gas Company
4.10	First Mortgage Indenture of Southern California Gas Company to American Trust Company dated October 1, 1940 (Registration Statement No. 2-4504 filed by Southern California Gas Company on September 16, 1940, Exhibit B-4).

4.11	Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of August 1, 1955 (Registration Statement No. 2-11997 filed by Pacific Lighting Corporation on October 26, 1955, Exhibit 4.07).

4.12	Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of December 1, 1956 (2006 Sempra Energy Form 10-K, Exhibit 4.09).

4.13	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank dated as of June 1, 1965 (2006 Sempra Energy Form 10-K, Exhibit 4.10).

4.14	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of August 1, 1972 (Registration Statement No. 2-59832 filed by Southern California Gas Company on September 6, 1977, Exhibit 2.19).

4.15	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of May 1, 1976 (Registration Statement No. 2-56034 filed by Southern California Gas Company on April 14, 1976, Exhibit 2.20).

4.16	Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of September 15, 1981 (Registration Statement No. 333-70654, Exhibit 4.24).
EXHIBIT 10 -- MATERIAL CONTRACTS
Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
10.1	Form of Continental Forge and California Class Action Price Reporting Settlement Agreement dated as of January 4, 2006 (Form 8-K filed on January 5, 2006, Exhibit 99.1).

10.2	Form of Nevada Antitrust Settlement Agreement dated as of January 4, 2006 (Form 8-K filed on January 5, 2006, Exhibit 99.2).
Sempra Energy
10.3	Indemnity Agreement, dated as of April 1, 2008, between Sempra Energy, Pacific Enterprises, Enova Corporation and The Royal Bank of Scotland plc (Sempra Energy March 31, 2008 Form 10-Q, Exhibit 10.2).

10.4	First Amendment to Indemnity Agreement, dated as of March 30, 2009, by and among Sempra Energy, Pacific Enterprises, Enova Corporation and The Royal Bank of Scotland plc (Sempra Energy March 31, 2009 Form 10-Q, Exhibit 10.3).

10.5	Second Amendment to Indemnity Agreement, dated as of June 30, 2009, by and among Sempra Energy, Pacific Enterprises, Enova Corporation and The Royal Bank of Scotland plc (Sempra Energy June 30, 2009 Form 10-Q, Exhibit 10.1).

10.6	Third Amendment to Indemnity Agreement, dated as of December 3, 2009, by and among Sempra Energy, Pacific Enterprises, Enova Corporation and The Royal Bank of Scotland plc (2009 Sempra Energy Form 10-K, Exhibit 10.06).

10.7	Fourth Amendment to Indemnity Agreement, dated as of April 15, 2011, by and among The Royal Bank of Scotland plc, Sempra Energy, Pacific Enterprises and Enova Corporation (Sempra Energy Form 8-K filed on April 21, 2011, Exhibit 10.2).

10.8	Letter Agreement, dated as of April 15, 2011, by and among The Royal Bank of Scotland plc, Sempra Energy, Sempra Commodities, Inc. and Sempra Energy Holdings VII B.V. (Sempra Energy Form 8-K/A filed on April 21, 2011, Exhibit 10.1).

10.9	Master Confirmation for Share Purchase Agreement, dated as of September 21, 2010, between Sempra Energy and JPMorgan Chase Bank, National Association. (Sempra Energy September 30, 2010 Form 10-Q, Exhibit 10.1).

10.10	Purchase and Sale Agreement, dated as of February 16, 2010, entered into by and among J.P. Morgan Ventures Energy Corporation, Sempra Energy Trading LLC, RBS Sempra Commodities LLP, Sempra Energy and The Royal Bank of Scotland plc (Sempra Energy Form 8-K filed on February 19, 2010, Exhibit 10.1).

10.11	First Amendment to Purchase and Sale Agreement, dated as of June 30, 2010, entered into by and among J.P. Morgan Ventures Energy Corporation, Sempra Energy Trading LLC, RBS Sempra Commodities LLP, Sempra Energy and The Royal Bank of Scotland plc (Sempra Energy June 30, 2010 Form 10-Q, Exhibit 10.1).

10.12	Letter Agreement, dated as of February 16, 2010, entered into by and between Sempra Energy and The Royal Bank of Scotland plc (Sempra Energy Form 8-K filed on February 19, 2010, Exhibit 10.2).

10.13	Limited Liability Partnership Agreement, dated as of April 1, 2008, between Sempra Energy, Sempra Commodities, Inc., Sempra Energy Holdings, VII B.V., RBS Sempra Commodities LLP and The Royal Bank of Scotland plc (Sempra Energy March 31, 2008 Form 10-Q, Exhibit 10.1).

10.14	First Amendment to Limited Liability Partnership Agreement, dated as of April 6, 2009 and effective as of November 14, 2008, by and among The Royal Bank of Scotland plc, Sempra Energy, Sempra Commodities, Inc., Sempra Energy Holdings VII B.V. and RBS Sempra Commodities LLP (Sempra Energy March 31, 2009 Form 10-Q, Exhibit 10.4).

10.15	Second Amendment to Limited Liability Partnership Agreement, dated December 23, 2009, by and among The Royal Bank of Scotland plc, Sempra Energy, Sempra Commodities, Inc., Sempra Energy Holdings VII B.V. and RBS Sempra Commodities LLP (2009 Sempra Energy Form 10-K, Exhibit 10.11).

10.16	Master Formation and Equity Interest Purchase Agreement, dated as of July 9, 2007, by and among Sempra Energy, Sempra Global, Sempra Energy Trading International, B.V. and The Royal Bank of Scotland plc (Sempra Energy Form 8-K filed on July 9, 2007, Exhibit 10.2).

10.17	First amendment to the Master Formation and Equity Interest Purchase Agreement, dated as of April 1, 2008, by and among Sempra Energy, Sempra Global, Sempra Energy Trading International, B.V. and The Royal Bank of Scotland plc (Sempra Energy March 31, 2008 Form 10-Q, Exhibit 10.3).

10.18	Energy Purchase Agreement between Sempra Energy Resources and the California Department of Water Resources, executed May 4, 2001 (2001 Sempra Energy Form 10-K, Exhibit 10.01).
Sempra Energy / San Diego Gas & Electric Company
10.19	Amended and Restated Operating Order between San Diego Gas & Electric Company and the California Department of Water Resources effective March 10, 2011. (Sempra Energy March 31, 2011 Form 10-Q, Exhibit 10.4).

10.20	Amended and Restated Servicing Order between San Diego Gas & Electric Company and the California Department of Water Resources effective March 10, 2011. (Sempra Energy March 31, 2011 Form 10-Q, Exhibit 10.5).
Compensation
Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
10.21	Third Amendment to the Sempra Energy Employee and Director Retirement Savings Plan.

10.22	Sempra Energy Amended and Restated Executive Life Insurance Plan.

10.23	Severance Pay Agreement between Sempra Energy and Dennis Arriola. (September 30, 2012 Sempra Energy Form 10-Q, Exhibit 10.1).

10.24	Second Amendment to the Sempra Energy Employee and Director Retirement Savings Plan (June 30, 2012 Sempra Energy Form 10-Q, Exhibit 10.1).

10.25	General Release Agreement between Sempra Energy and Michael W. Allman (June 30, 2012 Sempra Energy Form 10-Q, Exhibit 10.2).

10.26	Severance Pay Agreement between Sempra Energy and Trevor Mihalik (June 30, 2012 Sempra Energy Form 10-Q, Exhibit 10.3).

10.27	Severance Pay Agreement between Sempra Energy and Anne S. Smith (June 30, 2012 Sempra Energy Form 10-Q, Exhibit 10.4).

10.28	Form of Sempra Energy 2008 Long Term Incentive Plan 2012 Performance-Based Restricted Stock Unit Award (March 31, 2012 Sempra Energy Form 10-Q, Exhibit 10.1).

10.29	First Amendment to the Sempra Energy Employee and Director Savings Plan (2011 Sempra Energy Form 10-K, Exhibit 10.22).

10.30	Severance Pay Agreement between Sempra Energy and M. Javade Chaudhri (2011 Sempra Energy Form 10-K, Exhibit 10.23).

10.31	Severance Pay Agreement between Sempra Energy and Jessie J. Knight, Jr. (2011 Sempra Energy Form 10-K, Exhibit 10.24).

10.32	Severance Pay Agreement between Sempra Energy and Michael W. Allman (2011 Sempra Energy Form 10-K, Exhibit 10.25).

10.33	Severance Pay Agreement between Sempra Energy and G. Joyce Rowland (2011 Sempra Energy Form 10-K, Exhibit 10.26).

10.34	Amended and Restated Sempra Energy Severance Pay Agreement between Sempra Energy and Debra L. Reed (Sempra Energy Form 8-K filed on July 1, 2011, Exhibit 10.1).

10.35	Amendment to Severance Pay Agreement between Sempra Energy and Mark A. Snell (Sempra Energy Form 8-K filed on September 15, 2011, Exhibit 10.1).

10.36	Severance Pay Agreement between Sempra Energy and Joseph A. Householder (Sempra Energy Form 8-K filed on September 15, 2011, Exhibit 10.2).

10.37	Amendment to the Amendment and Restatement of the Sempra Energy 2005 Deferred Compensation Plan (2010 Sempra Energy Form 10-K, Exhibit 10.20).

10.38	Amendment to the Amended and Restated Sempra Energy Severance Pay Agreement between Sempra Energy and Donald E. Felsinger (see Exhibit 10.49 below) (2010 Sempra Energy Form 10-K, Exhibit 10.21).

10.39	Form of Sempra Energy 2008 Long Term Incentive Plan, 2011 Performance-Based Restricted Stock Unit Award. (Sempra Energy March 31, 2011 Form 10-Q, Exhibit 10.2).

10.40	Form of Sempra Energy 2008 Long Term Incentive Plan, 2010 Performance-Based Restricted Stock Unit Award (Sempra Energy March 31, 2010 Form 10-Q, Exhibit 10.1).

10.41	Form of 2009 Sempra Energy Severance Pay Agreement (2009 Sempra Energy Form 10-K, Exhibit 10.18).

10.42	Form of Sempra Energy 2008 Long Term Incentive Plan, 2009 Performance-Based Restricted Stock Unit Award (March 31, 2009 Sempra Energy Form 10-Q, Exhibit 10.1).

10.43	Form of Sempra Energy 2008 Long Term Incentive Plan, 2009 Nonqualified Stock Option Agreement (March 31, 2009 Sempra Energy Form 10-Q, Exhibit 10.2).

10.44	Sempra Energy 2008 Long Term Incentive Plan (Appendix A to the 2008 Sempra Energy Definitive Proxy Statement, filed on April 15, 2008).

10.45	Form of Indemnification Agreement with Directors and Executive Officers (June 30, 2008 Sempra Energy Form 10-Q, Exhibit 10.2).

10.46	Form of Sempra Energy 2008 Long Term Incentive Plan, 2008 Performance-Based Restricted Stock Unit Award (June 30, 2008 Sempra Energy Form 10-Q, Exhibit 10.3).

10.47	Form of Sempra Energy 2008 Long Term Incentive Plan, 2008 Nonqualified Stock Option Agreement (June 30, 2008 Sempra Energy Form 10-Q, Exhibit 10.4).

10.48	Amendment and Restatement of the Sempra Energy Cash Balance Restoration Plan (2008 Sempra Energy Form 10-K, Exhibit 10.16).

10.49	Form of Amended and Restated Sempra Energy Severance Pay Agreement (2008 Sempra Energy Form 10-K, Exhibit 10.17).

10.50	Amendment and Restatement of the Sempra Energy 2005 Deferred Compensation Plan (2008 Sempra Energy Form 10-K, Exhibit 10.18).

10.51	Amendment and Restatement of the Sempra Energy Supplemental Executive Retirement Plan (2008 Sempra Energy Form 10-K, Exhibit 10.19).

10.52	Sempra Energy Executive Personal Financial Planning Program Policy Document (September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.11).

10.53	2003 Sempra Energy Executive Incentive Plan B (2003 Sempra Energy Form 10-K, Exhibit 10.10).

10.54	Sempra Energy Executive Incentive Plan effective January 1, 2003 (2002 Sempra Energy Form 10-K, Exhibit 10.09).

10.55	Amended and Restated Sempra Energy Deferred Compensation and Excess Savings Plan (September 30, 2002 Sempra Energy Form 10-Q, Exhibit 10.3).

10.56	Sempra Energy Employee Stock Ownership Plan and Trust Agreement effective January 1, 2001 (September 30, 2008 Sempra Energy Form 10-Q, Exhibit 10.1).

10.57	Amendment to the Amended and Restated Sempra Energy Deferred Compensation and Excess Savings Plan (2008 Sempra Energy Form 10-K, Exhibit 10.25).

10.58	Sempra Energy Amended and Restated Executive Medical Plan (2008 Sempra Energy Form 10-K, Exhibit 10.26).

10.59	Form of Sempra Energy 1998 Long Term Incentive Plan, 2008 Non-Qualified Stock Option Agreement (2007 Sempra Energy Form 10-K, Exhibit 10.10).

10.60	Amended and Restated Sempra Energy 1998 Long-Term Incentive Plan (June 30, 2003 Sempra Energy Form 10-Q, Exhibit 10.2).
Sempra Energy
10.61	Form of Sempra Energy 2008 Long Term Incentive Plan, 2010 Restricted Stock Unit Award for Sempra Energy’s Board of Directors (Sempra Energy June 30, 2010 Form 10-Q, Exhibit 10.2).

10.62	Sempra Energy 2008 Long Term Incentive Plan for EnergySouth, Inc. Employees and Other Eligible Individuals (Registration Statement on Form S-8 Sempra Energy Registration Statement No. 333-155191 dated November 7, 2008, Exhibit 10.1).

10.63	Form of Sempra Energy 2008 Non-Employee Directors’ Stock Plan, Nonqualified Stock Option Agreement (June 30, 2008 Sempra Energy Form 10-Q, Exhibit 10.5).

10.64	Sempra Energy Amended and Restated Sempra Energy Retirement Plan for Directors (June 30, 2008 Sempra Energy Form 10-Q, Exhibit 10.7).

10.65	Form of Sempra Energy 1998 Non-Employee Directors’ Stock Plan Non-Qualified Stock Option Agreement (2006 Sempra Energy Form 10-K, Exhibit 10.09).

10.66	Sempra Energy 1998 Non-Employee Directors’ Stock Plan (Registration Statement on Form S-8 Sempra Energy Registration Statement No. 333-56161 dated June 5, 1998, Exhibit 4.2).
Nuclear
Sempra Energy / San Diego Gas & Electric Company
10.67	Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station, approved November 25, 1987 (1992 SDG&E Form 10-K, Exhibit 10.7).

10.68	Amendment No. 1 to the Qualified CPUC Decommissioning Master Trust Agreement dated September 22, 1994 (see Exhibit 10.67 above)(1994 SDG&E Form 10-K, Exhibit 10.56).

10.69	Second Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.67 above)(1994 SDG&E Form 10-K, Exhibit 10.57).

10.70	Third Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.67 above)(1996 SDG&E Form 10-K, Exhibit 10.59).

10.71	Fourth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.67 above)(1996 SDG&E Form 10-K, Exhibit 10.60).

10.72	Fifth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.67 above)(1999 SDG&E Form 10-K, Exhibit 10.26).

10.73	Sixth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.67 above)(1999 SDG&E Form 10-K, Exhibit 10.27).

10.74	Seventh Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated December 24, 2003 (see Exhibit 10.67 above)(2003 Sempra Energy Form 10-K, Exhibit 10.42).

10.75	Eighth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated October 12, 2011 (see Exhibit 10.67 above)(2011 SDG&E Form 10-K, Exhibit 10.70).

10.76	Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station, approved November 25, 1987 (1992 SDG&E Form 10-K, Exhibit 10.8).

10.77	First Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.76 above)(1996 SDG&E Form 10-K, Exhibit 10.62).

10.78	Second Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.76 above)(1996 SDG&E Form 10-K, Exhibit 10.63).

10.79	Third Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.76 above)(1999 SDG&E Form 10-K, Exhibit 10.31).

10.80	Fourth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.76 above)(1999 SDG&E Form 10-K, Exhibit 10.32).

10.81	Fifth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated December 24, 2003 (see Exhibit 10.76 above)(2003 Sempra Energy Form 10-K, Exhibit 10.48).

10.82	Sixth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station dated October 12, 2011 (see Exhibit 10.76 above) )(2011 SDG&E Form 10-K, Exhibit 10.77).

10.83	Second Amended San Onofre Operating Agreement among Southern California Edison Company, SDG&E, the City of Anaheim and the City of Riverside, dated February 26, 1987 (1990 SDG&E Form 10-K, Exhibit 10.6).

10.84	U. S. Department of Energy contract for disposal of spent nuclear fuel and/or high-level radioactive waste, entered into between the DOE and Southern California Edison Company, as agent for SDG&E and others; Contract DE-CR01-83NE44418, dated June 10, 1983 (1988 SDG&E Form 10-K, Exhibit 10N).

10.85	San Onofre Unit No. 1 Decommissioning Agreement between Southern California Edison Company and San Diego Gas & Electric Company dated March 23, 2000 (2009 Sempra Energy Form 10-K, Exhibit 10.62).

10.86	First Amendment to the San Onofre Unit No. 1 Decommissioning Agreement between Southern California Edison Company and San Diego Gas & Electric Company dated January 22, 2010 (2009 Sempra Energy Form 10-K, Exhibit 10.63).
EXHIBIT 12 -- STATEMENTS RE: COMPUTATION OF RATIOS
Sempra Energy
12.1	Sempra Energy Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends for the years ended December 31, 2012, 2011, 2010, 2009 and 2008.
San Diego Gas & Electric Company
12.2	San Diego Gas & Electric Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends for the years ended December 31, 2012, 2011, 2010, 2009 and 2008.
Southern California Gas Company
12.3	Southern California Gas Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends for the years ended December 31, 2012, 2011, 2010, 2009 and 2008.
EXHIBIT 13 -- ANNUAL REPORT TO SECURITY HOLDERS
Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
13.1	Sempra Energy 2012 Annual Report to Shareholders. (Such report, except for the portions thereof which are expressly incorporated by reference in this Annual Report, is furnished for the information of the Securities and Exchange Commission and is not to be deemed “filed” as part of this Annual Report).
EXHIBIT 14 -- CODE OF ETHICS
San Diego Gas & Electric Company / Southern California Gas Company
14.1	Sempra Energy Code of Business Conduct and Ethics for Board of Directors and Senior Officers (also applies to directors and officers of San Diego Gas & Electric Company and Southern California Gas Company) (2006 SDG&E and SoCalGas Forms 10-K, Exhibit 14.01).
EXHIBIT 21 -- SUBSIDIARIES
Sempra Energy
21.1	Sempra Energy Schedule of Certain Subsidiaries at December 31, 2012.
EXHIBIT 23 -- CONSENTS OF EXPERTS AND COUNSEL
23.1	Consents of Independent Registered Public Accounting Firm and Report on Schedule, pages 39 through 41.
EXHIBIT 31 -- SECTION 302 CERTIFICATIONS
Sempra Energy
31.1	Statement of Sempra Energy’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.2	Statement of Sempra Energy’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
San Diego Gas & Electric Company
31.3	Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.4	Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Southern California Gas Company
31.5	Statement of Southern California Gas Company’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.6	Statement of Southern California Gas Company’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
EXHIBIT 32 -- SECTION 906 CERTIFICATIONS
Sempra Energy
32.1	Statement of Sempra Energy’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.

32.2	Statement of Sempra Energy’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
San Diego Gas & Electric Company
32.3	Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.

32.4	Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
Southern California Gas Company
32.5	Statement of Southern California Gas Company’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.

32.6	Statement of Southern California Gas Company’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
EXHIBIT 101 -- INTERACTIVE DATA FILE
101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

GLOSSARY


Annual Report	2012 Annual Report to Shareholders	kW	Kilowatt
Bcf	Billion cubic feet (of natural gas)	LNG	Liquefied natural gas
California Utilities	San Diego Gas & Electric Company and Southern California Gas Company	Luz del Sur	Luz del Sur S.A.A. and its subsidiaries
CARB	California Air Resources Board	Mobile Gas	Mobile Gas Service Corporation
CEC	California Energy Commission	Mtpa	Million tonnes per annum
CDEC	Centros de Despacho Económico de Carga (Chile)	MW	Megawatt
CDEC-SIC	Sistema Interconectado Central (Central Interconnected System) (Chile)	MWh	Megawatt hours
CDEC-SING	Sistema Interconectado del Norte Grande (Northern Interconnected System) (Chile)	NRC	Nuclear Regulatory Commission
Chilquinta Energía	Chilquinta Energía S.A. and its subsidiaries	OII	Order Instituting Investigation
CNE	Comisión Nacional de Energía (National Energy Commission) (Chile)	OSINERGMIN	Organismo Supervisor de la Inversión en Energía y Minería (Energy and Mining Investment Supervisory Body) (Peru)
COES	Comité de Operación Económica del Sistema Interconectado Nacional (Peru)	PEMEX	Petroleos Mexicanos (Mexican state-owned oil company)
CPUC	California Public Utilities Commission	PGE	Portland General Electric Company
CRE	Comisión Reguladora de Energía (Energy Regulatory Commission) (Mexico)	QFs	Qualifying Facilities
DOE	U.S. Department of Energy	RBS Sempra Commodities	RBS Sempra Commodities LLP
DOT	U.S. Department of Transportation	Rockies Express	Rockies Express Pipeline LLC
DWR	Department of Water Resources	RPS	Renewables Portfolio Standard
Edison	Southern California Edison Company	SDG&E	San Diego Gas & Electric Company
EPA	Environmental Protection Agency	SEC	Securities and Exchange Commission
ERR	Eligible Renewable Energy Resource	SEIN	Sistema Eléctrico Interconectado Nacional (Peru)
FERC	Federal Energy Regulatory Commission	SoCalGas	Southern California Gas Company
FTA	Free Trade Agreement	SONGS	San Onofre Nuclear Generating Station
GHG	Greenhouse Gas	The Board	Sempra Energy’s board of directors
IOUs	Investor-owned utilities	U.S. GAAP	Accounting principles generally accepted in the United States
ISFSI	Independent Spent Fuel Storage Installation	Willmut Gas	Willmut Gas Company
kV	Kilovolt

Exhibit 10.21

AMENDMENT
TO THE SEMPRA ENERGY
EMPLOYEE AND DIRECTOR SAVINGS PLAN

Sempra Energy maintains the Sempra Energy Employee and Director Savings Plan (the “Plan”). In order to amend the Plan in certain respects, this Amendment to the Plan is hereby adopted, effective as of December 13, 2012.

The Plan is hereby amended, effective December 13, 2012 as follows:

Section 1.1 (mm) of the Plan defining "Restricted Stock Units" is hereby amended in its entirety to read as follows:

"(mm) "Restricted Stock Units" shall mean phantom shares of restricted stock granted to a Participant under the 2008 Long Term Incentive Plan and any successor plan thereto."

The first sentence of Section 3.1(b)(2) of the Plan is hereby amended to read as follows:

"Each Eligible Individual designated by the Committee as so eligible to defer, may elect to defer Restricted Stock Units (or a portion thereof), in accordance with such rules as the Committee may establish, which such rules shall not be inconsistent with the deferral election rules set forth in Sections 3.1 and 3.2 or the distribution provisions of Section 7.1."

Section 3.1(b)(3) of the Plan is hereby amended to add the following thereto:

"Notwithstanding anything contained in the Plan to the contrary, a Participant may not elect a Scheduled Withdrawal Date with respect to the deferral of any Restricted Stock Units."

Section 7.1(a)(1)(A) of the Plan is hereby amended to read in its entirety as follows:

"(A)

Except as provided in subparagraph (B), paragraph (2), paragraph (3) or Section 7.3, upon the Separation from Service or Disability of a Participant, a Participant’s Distributable Amount with respect to each Plan Year shall be paid to the Participant in a lump sum in cash (or shares of Sempra Energy common stock for Restricted Stock Unit subaccounts) on the Participant’s Payment Date."

Section 7.1(a)(2) of the Plan is hereby amended to read in its entirety as follows:

"(2)

Optional Forms . Instead of receiving his Distributable Amount with respect to each Plan Year as described at Section 7.1(a)(1)(A), the Participant may elect in accordance with Section 3.2 one of the following optional forms of payment (or shares of Sempra Energy common stock for Restricted Stock Unit subaccounts) at the time of his deferral election for such Plan Year:

(i)

equal annual installments in cash (or shares of Sempra Energy common stock for Restricted Stock Unit subaccounts) (calculated as set forth in paragraph 7.1(a)(6)) over five years beginning on the Participant’s Payment Date,

(ii)

equal annual installments in cash (or shares of Sempra Energy common stock for Restricted Stock Unit subaccounts) (calculated as set forth in paragraph 7.1(a)(6)) over ten (10) years beginning on the Participant’s Payment Date, or

(iii)

equal annual installments in cash (or shares of Sempra Energy common stock for Restricted Stock Unit subaccounts) (calculated as set forth in paragraph 7.1(a)(6)) over fifteen (15) years beginning on the Participant’s Payment Date.

The payment of such Participant’s Distributable Amount with respect each Plan Year shall be made or commence on such Participant’s Payment Date (or, if applicable, the date determined under subparagraph (a)(1)(B))."

Executed at San Diego, California this 13 ^th day of December, 2012.

SEMPRA ENERGY

By:

______________________

G. Joyce Rowland

Title:

Sr. Vice President, Human Resources, Diversity & Inclusion

Date:

December 13, 2012

Exhibit 10.22

SEMPRA ENERGY

AMENDED AND RESTATED

EXECUTIVE LIFE INSURANCE PLAN

Effective November 12, 2012

Sempra Energy, a California corporation (“Sempra”), hereby amends and restates the Sempra Energy Executive Life Insurance Plan (the “Plan”), which was originally effective June 1, 1998. The Plan was amended and restated effective as of July 1, 2003, and was subsequently amended and restated effective as of December 12, 2008.

Sempra hereby amends and restates the Plan effective as of November 12, 2012, except as otherwise provided herein. This amendment and restatement of the Plan is intended to comply with the requirements of Sections 409A(a)(2), (3) and (4) of the Code (as defined below) and the Treasury Regulations thereunder.

PURPOSE OF PLAN

The purpose of this Plan is to assist certain of Sempra’s senior executives to obtain additional life insurance coverage. In connection with this, the Plan provides that the Company will make certain life insurance premium payments on the policies obtained under the terms and conditions of this Plan.

ARTICLE I

DEFINITIONS

Whenever capitalized in this Plan document, the following terms shall have the meanings set forth below unless otherwise expressly provided:

1.1

“Board” shall mean the Board of Directors of the Company.

1.2

“Code” means the Internal Revenue Code of 1986, as amended.

1.3

“Committee” shall mean the Compensation Committee of the Board, or such other committee as the Compensation Committee shall appoint from time to time to administer the Plan.

1.4

“Company” shall mean Sempra Energy, a California corporation, and any successor thereto, including any corporation that is a successor to all or substantially all of the Company’s assets or business. “Company” shall also include any corporation or other entity a majority of whose outstanding voting stock or voting power is owned, directly or indirectly, by Sempra Energy, Inc.

1.5

“Participant” shall mean any senior executive of the Company who is selected to participate in the Plan and who has satisfied the conditions for Plan participation as set forth in Section 2.1.

1.6

“Plan” shall mean this Sempra Energy Executive Life Insurance Plan, as it may be amended from time to time.

1.7

“Plan Year” shall mean the calendar year.

1.8

“Policy” shall mean the life insurance policy (or life insurance policies if more than one is required because of death benefit amounts or otherwise) purchased on a Participant’s life that is subject to the terms and conditions of this Plan.

1.9

“ Separation from Service ”, with respect to a Participant (or another Service Provider) means the Participant’s (or such Service Provider’s) “separation from service,” as defined in Treasury Regulation Section 1.409A-1(h).

1.10

“ Service Provider ” means a Participant or any other “service provider,” as defined in Treasury Regulation Section 1.409A-1(f).

1.11

“ Service Recipient ,” with respect to a Participant, means the Company and all persons considered part of the “service recipient,” as defined in Treasury Regulation Section 1.409A-1(g), as determined from time to time. As provided in Treasury Regulation Section 1.409A-1(g), the “Service Recipient” shall mean the person for whom the services are performed and with respect to whom the legally binding right to compensation arises, and all persons with whom such person would be considered a single employer under Section 414(b) or 414(c) of the Code.

1.12

“ Specified Employee ” means a Service Provider who, as of the date of the Service Provider’s Separation from Service, is a “ Key Employee ” of the Service Recipient any stock of which is publicly traded on an established securities market or otherwise. For purposes of this definition, a Service Provider is a “ Key Employee ” if the Service Provider meets the requirements of Section 416(i)(1)(A)(i), (ii) or (iii) of the Code (applied in accordance with the Treasury Regulations thereunder and disregarding Section 416(i)(5) of the Code) at any time during the Testing Year. If a Service Provider is a “ Key Employee ” (as defined above) as of a Specified Employee Identification Date, the Service Provider shall be treated as “ Key Employee ” for the entire twelve (12) month period beginning on the Specified Employee Effective Date. For purposes of this definition, a Service Provider’s compensation for a Testing Year shall mean such Service Provider’s compensation, as determined under Treasury Regulation Section 1.415(c)-2(a) (and applied as if the Service Recipient were not using any safe harbor provided in Treasury Regulation Section 1.415(c)-2(d), were not using any of the elective special timing rules provided in Treasury Regulation Section 1.415(c)-2(e), and were not using any of the elective special rules provided in Treasury Regulation Section 1.415(c)-2(g)). The “Specified Employees” shall be determined in accordance with Section 409A(a)(2)(B)(i) of the Code and Treasury Regulation Section 1.409A-1(i).

1.13

“ Specified Employee Effective Date ” means the first day of the fourth month following the Specified Employee Identification Date. The Specified Employee Effective Date may be changed by the Company, in its discretion, in accordance with Treasury Regulation Section 1.409A-1(i)(4).

1.14

“ Specified Employee Identification Date ”, for purposes of Treasury Regulation Section 1.409A-1(i)(3), means December 31. The “ Specified Employee Identification Date ” shall apply to all “nonqualified deferred compensation plans” (as defined in Treasury Regulation Section 1.409A-1(a)) of the Service Recipient and all affected Service Providers. The “ Specified Employee Identification Date ” may be changed by Sempra Energy, in its discretion, in accordance with Treasury Regulation Section 1.409A-1(i)(3).

1.15

[Intentionally Left Blank].

1.16

“ Testing Year ” means the twelve (12) month period ending on the Specified Employee Identification Date, as determined from time to time.

1.17

“Years of Service” shall mean the total number of full years of employment in which a Participant has been employed by the Company. For purposes of this definition, a year of employment shall be a 365 day period (or 366 day period in the case of a leap year) that, for the first year of employment, commences on the Participant’s date of hiring and that, for any subsequent year, commences on an anniversary of that hiring date. Any partial year of employment shall not be counted.

ARTICLE II

ELIGIBILITY

2.1

Eligibility for Participation. A senior executive of the Company shall participate in this Plan as a Participant if either he or she is participating in the Plan as of the effective date of this amendment and restatement or meets all of the following requirements:

(1)

Has been designated in writing by the Committee, in its sole and absolute discretion, as a Participant;

(2)

Completes and returns to the Committee, no later than thirty (30) days after he or she receives written notice of such designation, such administrative and other forms as the Committee may require for participation;

(3)

Completes such insurance forms, exams, and questions as the Committee may designate from time to time;

(4)

Timely completes any other participation conditions as may be prescribed by the Committee from time to time; and

If a senior executive fails to meet all of the above-listed requirements within a reasonable time, as determined by the Committee in its sole discretion, the Committee shall provide that executive with written notice within thirty (30) days of such failure, and that person shall not become a Participant under this Plan.

2.2

Acquisition of Insurance. As a condition of participation in this Plan, the Participant shall be required to cooperate in applying for and obtaining a Policy on his or her life. The selection of the Policy shall be at the sole discretion of the Company. The Policy shall be issued in the name of the Participant as the sole and exclusive owner of the Policy, subject to the rights and interests granted to the Company, as provided in this Plan. At the sole discretion of the Committee, the Participant may designate a person or entity other than the Participant as the owner of the Policy, provided that such owner agrees to be bound to the terms and conditions of this Plan.

2.3

Additional Life Insurance Coverage. During the term of this Plan, the death benefit coverage under the Policy may be increased from time to time, to reflect increases in the Participant’s compensation pursuant to the provisions of Sections 3.1 and 3.2. As a condition of receiving the benefits of any such increase, the Participant shall be required to cooperate in applying for and obtaining such additional coverage. If the Participant does not so cooperate, and such coverage cannot be obtained because of the Participant’s failure to cooperate, the Company shall have no obligation under this Plan to provide such additional coverage. Further, if the Participant is not insurable at the time such additional coverage is sought on a guaranteed issue basis, or if simplified or full medical underwriting is required, on a rated basis that is no lower than standard, smoker, then the Company shall have no obligation under this Plan to provide such additional coverage. The Committee, in its sole discretion, may reduce the minimum standard referred to in the previous sentence, in its sole discretion, based on the cost of insurance or otherwise.

ARTICLE III

BONUS AMOUNTS

3.1

Life Insurance Coverage Prior to Separation from Service. Subject to Article II above, for each Plan Year of the Participant’s participation in the Plan and prior to the Participant’s Separation from Service, the Company shall pay to the life insurance carrier the premiums on the Policy in accordance with this Section 3.1, as determined by the Company in its sole discretion, which Policy shall provide a death benefit equal to the sum of the following amounts, as those amounts are determined as of the last day of each Plan Year, as determined by the Committee in its sole discretion: (i) two (2) times the Participant’s annual base salary, plus (ii) two (2) times the Participant’s average annual bonus under the 2003 Executive Incentive Plan, or any successor thereto (the “Bonus Plan”), including any amount deferred, in the three (3) highest years in the ten (10) previous years, or during the Participant’s actual years of employment with the Company, if less. In determining the amounts described in the previous sentence for any Plan Year, the Committee shall substitute the Participant’s target bonus under the Bonus Plan for a Participant who is in his or her first Plan Year of participation and has not received any bonus under the Bonus Plan. The premium for any Plan Year shall be paid by the Company not later than March 15 of the next following Plan Year; provided, however, that such premium shall not be paid if the Participant has a Separation from Service prior to the payment of such premium. If a Participant’s compensation increases after the Committee has determined the Participant’s death benefit as of the last day of the Plan Year, the Participant’s death benefit under the Policy shall not be adjusted until the last day of the next following Plan Year and then it will be based on the Participant’s compensation at that time. These premium payments shall be treated as bonus payments to the Participant.

3.2

Life Insurance Coverage after Separation from Service with Age and Service. If at the time of the Participant’s Separation from Service (other than by reason of the Participant’s death), the Participant has attained age 62 and has completed at least five Years of Service, then the Participant shall be entitled to the benefit, if any, specified in this Section 3.2. Upon such Separation from Service, the Committee shall have the life insurance carrier which issued the Policy prepare a life insurance projection for the Policy, determined as of the January 1 of the Plan Year next following such Separation from Service (the “ Projection Date ”), based on the following assumptions: (i) the then current policy charges, (ii) a crediting rate of 6.5% net of investment management fees (but before mortality and expense charges), and (iii) death benefit coverage until the Participant’s 100 ^th birthday equal to (x) one and a half (1 1/2) times the Participant’s annual base salary (determined as of the date of the Participant’s Separation from Service), plus (y) one and a half (1 1/2) times the Participant’s average annual bonus under the Bonus Plan, including any amount deferred, in the three (3) highest years in the ten (10) previous years, or during the Participant’s actual years of employment with the Company, if less (determined as of the date of the Participant’s Separation from Service). If the illustration shows that the Policy will sustain itself until at least the Participant’s 100 ^th birthday without lapsing based on these assumptions, then the Company shall have no further obligations under the Plan. If the illustration provides that the Policy will not so sustain itself until that time without lapsing, the Company shall have the life insurance carrier determine the minimum premium, determined as of the January 1 of the Plan Year next following such Separation from Service, required to be paid into the Policy to sustain the Policy until the Participant’s 100 ^th birthday without lapsing, based on these assumptions. Except as provided below in this Section 3.2 or in Section 5.1(2), the Company will then pay such premium to the life insurance carrier during the Plan Year next following the Plan Year in which such Participant’s Separation from Service occurs and the Company shall have no further obligation to the Participant under this Plan. The Company shall not make a premium payment under this Section 3.2 in the event of the Participant’s Separation from Service by reason of death. If the Participant’s Policy is held in an irrevocable life insurance trust at the time a payment is otherwise required to be paid to the life insurance carrier under this Section 3.2, the Participant may elect in writing prior to January 1of the year in which the payment is to be made to have the payment paid to the Participant, rather than to the life insurance carrier, at the time otherwise specified for the payment.

3.3

Life Insurance Coverage after Separation from Service without Age and Service. If at the time of the Participant’s Separation from Service, the Participant has not attained age 62, or has not completed at least five Years of Service, the Company’s obligations under this Plan to pay any future premiums on the Policy shall cease immediately upon the Participant’s Separation from Service and the Company shall have no further obligation to the Participant under the Plan.

3.4

Tax Withholding. The Company shall withhold from the Participant’s compensation all federal, state and local income, employment and other taxes required to be withheld by the Company in connection with the premium payments, in amounts and in a manner to be determined in the sole discretion of the Company.

3.5

Right to Invest Cash Surrender Value. Until the earlier of the Participant’s Separation from Service or the termination of the Plan, the Company shall have the sole and absolute right to invest and reallocate the Participant’s Policy’s cash surrender value as the Company determines in its sole discretion. The Participant shall cooperate with the Company with respect to any actions required by the life insurance carrier issuing the Policy to grant to the Company such power. The Company shall not have any liability associated with such investment authority and discretion, provided that the Company makes all premium payments required under this Plan.

ARTICLE IV

ADMINISTRATION

4.1

Administration. This Plan shall be administered by the Committee. The Committee shall be authorized to construe and interpret all of the provisions of this Plan, to adopt procedures and practices concerning the administration of this Plan, and to make any determinations necessary hereunder, which shall, subject to Section 4.8 below, be binding and conclusive on all parties. The Committee may appoint one or more individuals and delegate such of its power and duties as it deems desirable to any such individual, in which case every reference herein made to the Committee shall be deemed to mean or include the individuals as to matters within their jurisdiction.

4.2

Decisions and Actions of the Committee. The Committee may act at a meeting or in writing without a meeting. All decisions and actions of the Committee shall be made by vote of the majority, including actions in writing taken without a meeting.

4.3

Rules and Records of the Committee. The Committee shall make such rules and regulations in connection with its administration of the Plan as are consistent with the terms and provisions hereof. The Committee shall keep a record of each Participant’s name, address, social security number, benefit commencement date, and the amount of benefit.

4.4

Employment of Agents. The Committee may employ agents, including without limitation, accountants, actuaries, consultants, or attorneys, to exercise and perform the powers and duties of the Committee as the Committee delegates to them, and to render such services to the Committee as the Committee may determine, and the Committee may enter into agreements setting forth the terms and conditions of such service.

4.5

Agents for Service of Legal Process. The Chairman of the Committee shall serve as agent for service of legal process.

4.6

Plan Expenses. The Company shall pay all expenses reasonably incurred in the administration of this Plan. The members of the Committee shall serve without compensation for their services as such, but all expenses of the Committee shall be paid by the Company. No employee of the Company shall receive compensation from this Plan regardless of the nature of his services to this Plan.

4.7

Indemnification. To the extent permitted by law, the Committee and all agents and representatives of the Committee shall be indemnified by the Company and saved harmless against any claims, and the expenses of defending against such claims, resulting from any action or conduct relating to the administration of this Plan except claims arising from gross negligence, willful neglect, or willful misconduct.

4.8

Claims Procedure.

(1)

Claim. A Participant, beneficiary or other person who believes that he is being denied a benefit to which he is entitled under this Plan (hereinafter referred to as “Claimant”) may file a written request for such benefit with the Committee, setting forth his claim. The request must be addressed to the Committee at Sempra Energy at its then principal place of business. The claims procedure of this Section shall be applied in accordance with Section 503 of ERISA and Department of Labor Regulation Section 2560.503-1. A Participant, beneficiary or other person may assert a claim, or request review of the denial of a claim, through such Participant’s, beneficiary’s or person’s authorized representative, provided that such Participant, beneficiary or person has submitted a written notice evidencing the authority of such representative to the Committee.

A Claimant or his duly authorized representative shall submit his claim under the Plan in writing to the Committee. The Claimant may include documents, records or other information relating to the claim for review by the Committee in connection with such claim.

(2)

Claim Decision. The Committee shall review the Claimant’s claim (including any documents, records or other information submitted with such claim) and determine whether such claim shall be approved or denied in accordance with the Plan.

Upon receipt of a claim, the Committee shall advise the Claimant that a claim decision shall be forthcoming within ninety (90) days and shall, in fact, deliver such claim decision within such period. The Committee may, however, extend the claim decision period for an additional ninety (90) days for special circumstances. If the Committee extends the claim decision period, the Committee shall provide the Claimant with written notice of such extension prior to the end of the initial ninety (90) day period. The extension notice shall indicate the special circumstances requiring the extension of time and the date by which the Committee expects to render a claim decision.

If the claim is denied in whole or in part, the Committee shall inform the Claimant in writing, using language calculated to be understood by the Claimant, setting forth: (i) the specified reason or reasons for such denial; (ii) references to the specific provisions of this Plan on which such denial is based; (iii) a description of any additional material or information necessary for the Claimant to perfect his claim and an explanation of why such material or such information is necessary; and (iv) a description of the Plan’s procedures for review and the time limits applicable to such procedures, including a statement of the Claimant’s right to bring a civil action under Section 502(a) of ERISA following a denial of the review of the denial of the claim.

The Claimant may request a review of any denial of the claim in writing to the Committee within sixty (60) days after receipt of the Committee’s notice of denial of claim. The Claimant’s failure to appeal the denial of the claim by the Committee in writing within the sixty (60) day period shall render the Committee’s determination final, binding, and conclusive.

(3)

Request for Review. With sixty (60) days after the receipt by the Claimant of the denial of the claim described above, the Claimant may request in writing a review the determination of the Compensation Committee. Such review shall be completed by the Compensation Committee. Such request must be addressed to the Committee, at Sempra Energy’s then principal place of business.

The Claimant shall be afforded the opportunity to submit written comments, documents, records, and other information relating to the claim, and the Claimant shall be provided, upon request and free of charge, reasonable access to all documents, records, and other information relevant to the Claimant’s claim. A document, record or other information shall be considered “relevant” to the claim, as provided in Department of Labor Regulation Section 2560.503-1(m)(8). The review by the Committee shall take into account all comments, documents, records, and other information submitted by the Claimant, without regard to whether such information was submitted or considered in the Committee’s initial determination with respect to the claim.

The Committee shall advise the Claimant in writing of the Committee’s determination of the review within sixty (60) days of the Claimant’s written request for review, unless special circumstances (such as a hearing) would make the rendering of a determination within the sixty (60) day period infeasible, but in no event shall the Committee render a determination regarding the denial of a claim later than one hundred twenty (120) days after its receipt of a request for review. If an extension of time for review is required because of special circumstances, written notice of the extension shall be furnished to the Claimant prior to the date the extension period commences. The extension notice shall indicate the special circumstances requiring the extension of time and the date by which the Committee expects to render a review decision.

(4)

Review of Decision. The Committee shall inform the Claimant in writing, in a manner calculated to be understood by the Claimant, the decision on the review of the denial of the claim, setting forth: (i) the specific reasons for the decision, (ii) if the claim is denied, reference to the specific Plan provisions on which the denial of the claim is based; (iii) a statement that the Claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the Claimant’s claim (and a document, record or other information shall be considered “relevant” to the benefits claim, as provided in Department of Labor Regulation Section 2560.503-1(m)(8)); and (iv) a statement describing Claimant’s right to bring an action under Section 502(a) of ERISA.

ARTICLE V
SECTION 409A OF THE CODE

5.1

Compliance with Section 409A of the Code .

(1)

Plan Interpretation and Administration . This Plan shall be interpreted, construed and administered in a manner that satisfies the requirements of Sections 409A(a)(2), (3) and (4) of the Code and the Treasury Regulations thereunder (subject to the transitional relief under Internal Revenue Service Notice 2005-1, the Proposed Regulations under Section 409A of the Code, Internal Revenue Service Notice 2006-79, Internal Revenue Service Notice 2007-78, Internal Revenue Service Notice 2007-86 and other applicable authority issued by the Internal Revenue Service). As provided in Internal Revenue Notice 2007-86, notwithstanding any other provision of this Plan, with respect to an election or amendment to change a time and form of payment under the Plan made on or after January 1, 2008 and on or before December 31, 2008, the election or amendment shall apply only to amounts that would not otherwise be payable in 2008 and shall not cause an amount to be paid in 2008 that would not otherwise be payable in 2008.

(2)

Premium Payment for Specified Employees . In the case of a Participant who is a Specified Employee on the date of such Participant’s Separation from Service, the premium payment under Section 3.2 with respect to such Participant (if any) shall not be made before the date which is six months after the date of such Participant’s Separation from Service in accordance with Section 409A(a)(2)(B)(i) of the Code and the Treasury Regulations thereunder. Any premium payment under Section 3.2 with respect to such Participant that otherwise would have been made during the first six months following the date of such Participant’s Separation from Service shall be accumulated (without interest) and paid on the first day of the seventh month following the date of such Participant’s Separation from Service; provided, however, that such premium shall not be paid in the event of such Participant’s death prior to the first day of the seventh month following the date of such Participant’s Separation from Service.

(3)

Prohibition of Acceleration of Premiums . The time of payment of any payment of the premium with respect to a Participant under Section 3.2 shall not be subject to acceleration, except as provided under Treasury Regulations promulgated in accordance with Section 409A(a)(3) of the Code.

5.2

Short-Term Deferral Exemption . The premium payments under Section 3.1 with respect to a Participant are intended to be short-term deferrals under Treasury Regulation Section 1.409A-1(b)(4) and exempt from Section 409A of the Code. The premium payments under Section 3.1 with respect to a Participant shall be made on or before the last day of the applicable 2 ½ month period, as defined in Treasury Regulation Section 1.409A-1(b)(4).

ARTICLE VI
MISCELLANEOUS

6.1

Amendment and Termination. This Plan may be amended or terminated, in whole or in part, at any time by written action of the Board, or the Compensation Committee of the Board, in its discretion; provided that any amendment or termination that materially and adversely affects any payments under Article III at the time of such amendment or termination must be consented to in writing by any Participant so affected before it shall have any effect as to that Participant. Notwithstanding the foregoing, the Board, or the Compensation Committee of the Board, may terminate the Plan without the Participants’ consent, provided that (i) such Plan termination is treated for purposes of this Plan as a Separation from Service of all Participants (assuming that each had obtained age 62 with five Years of Service, regardless of whether such requirements were actually met), (ii) the Company pays the premium, if any, required by Section 3.2, and (iii) such termination of the Plan and the payment of such premiums comply with Section 409A of the Code and the Treasury Regulations thereunder.

6.2

Binding Effect. This Plan shall bind the Participant and the Company and their beneficiaries, survivors, executors, administrators, and transferees.

6.3

No Guarantee of Employment. This Plan is not an employment policy or contract. It does not give the Participant the right to remain an employee of the Company, nor does it interfere with the Company’s right to discharge the Participant, with or without cause. If also does not require the Participant to remain an employee nor interfere with the Participant’s right to terminate employment at any time.

6.4

Applicable Law. This Plan and all rights hereunder shall be governed by the internal laws of the State of California without regard to its conflict of laws provisions, except to the extent preempted by the laws of the United States of America.

6.5

Non-Transferability.

(1)

Prior to the Participant’s termination of employment, benefits under this Plan cannot be sold, transferred, or assigned and the Participant cannot withdraw the cash surrender value of the policy.

(2)

The previous sentence shall not in any way limit or prohibit the right of a Participant to transfer ownership of the life insurance policy described in this Plan to a trust for which the Participant is the grantor.

6.6

Named Fiduciary. The Company shall be the named fiduciary and plan administrator under this Plan. The named fiduciary may delegate to others certain aspects of the management and operation responsibilities of the plan including the employment of advisors and the delegation of ministerial duties to qualified individuals.

IN WITNESS WHEREOF, the Company has executed this amendment and restatement of the Plan as of November 12, 2012.

SEMPRA ENERGY

By: ______________________________

G. Joyce Rowland

Sr. Vice President, Human Resources,

Diversity and Inclusion


EXHIBIT 12.1
SEMPRA ENERGY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)


			2008		2009		2010		2011		2012
Fixed charges and preferred stock dividends:
Interest		$	353	$	455	$	492	$	549	$	601
Interest portion of annual rentals			3		2		3		2		2
Preferred dividends of subsidiaries (1)			13		13		11		10		6
Total fixed charges			369		470		506		561		609
Preferred dividends for purpose of ratio			-		-		-		-		-
Total fixed charges and preferred dividends for purpose of ratio		$	369	$	470	$	506	$	561	$	609
Earnings:
Pretax income from continuing operations before adjustment for income or loss from equity investees		$	1,009	$	977	$	1,078	$	1,747	$	1,255
Add:
Total fixed charges (from above)			369		470		506		561		609
Distributed income of equity investees			133		493		260		96		50
Less:
Interest capitalized			100		73		74		27		53
Preferred dividends of subsidiaries (1)			10		13		11		10		6
Total earnings for purpose of ratio		$	1,401	$	1,854	$	1,759	$	2,367	$	1,855
Ratio of earnings to combined fixed charges and preferred stock dividends			3.80		3.94		3.48		4.22		3.05

Ratio of earnings to fixed charges			3.80		3.94		3.48		4.22		3.05

(1)	In computing this ratio, “Preferred dividends of subsidiaries” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.


EXHIBIT 12.2
SAN DIEGO GAS & ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)


			2008		2009		2010		2011		2012
Fixed Charges and Preferred Stock Dividends:
Interest		$	107	$	118	$	153	$	193	$	220
Interest portion of annual rentals			1		1		1		1		1
Total fixed charges			108		119		154		194		221
Preferred stock dividends (1)			7		7		7		7		7
Combined fixed charges and preferred stock dividends for purpose of ratio		$	115	$	126	$	161	$	201	$	228
Earnings:
Pretax income from continuing operations		$	451	$	550	$	531	$	692	$	705
Total fixed charges (from above)			108		119		154		194		221
Less: Interest capitalized			13		4		1		1		-
Total earnings for purpose of ratio		$	546	$	665	$	684	$	885	$	926
Ratio of earnings to combined fixed charges and preferred stock dividends			4.75		5.28		4.25		4.40		4.06

Ratio of earnings to fixed charges			5.06		5.59		4.44		4.56		4.19

(1)	In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.


EXHIBIT 12.3
SOUTHERN CALIFORNIA GAS COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)


			2008		2009		2010		2011		2012
Fixed Charges:
Interest		$	65	$	74	$	72	$	77	$	77
Interest portion of annual rentals			2		1		2		1		1
Total fixed charges			67		75		74		78		78
Preferred stock dividends (1)			2		2		2		2		2
Combined fixed charges and preferred stock dividends for purpose of ratio		$	69	$	77	$	76	$	80	$	80
Earnings:
Pretax income from continuing operations		$	385	$	418	$	463	$	431	$	369
Add: Total fixed charges (from above)			67		75		74		78		78
Less: Interest capitalized			-		1		1		1		1
Total earnings for purpose of ratio		$	452	$	492	$	536	$	508	$	446
Ratio of earnings to combined fixed charges and preferred stock dividends			6.55		6.39		7.05		6.35		5.58

Ratio of earnings to fixed charges			6.75		6.56		7.24		6.51		5.72

(1)	In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.

Exhibit 21.1

Sempra Energy

Schedule of Certain Subsidiaries

at December 31, 2012


Subsidiary	State of Incorporation or Other Jurisdiction
AEI Asosiacion en Participacion	Peru
Enova Corporation	California
Luz del Sur S.A.A.	Peru
Pacific Enterprises	California
Pacific Enterprises International	California
San Diego Gas & Electric Company	California
Sempra Energy International	California
Sempra Energy Holdings III B.V.	Netherlands
Sempra Energy Holdings VIII B.V.	Netherlands
Sempra Energy Holdings XI B.V.	Netherlands
Sempra Energy International Holdings N.V.	Netherlands
Sempra Global	Delaware
Sempra Mexico, S. de R.L. de C.V.	Mexico
Southern California Gas Company	California

EXHIBIT 31.1

CERTIFICATION

I, Debra L. Reed, certify that:

I have reviewed this report on Form 10-K of Sempra Energy;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 26, 2013

/S/ Debra L. Reed

Debra L. Reed

Chief Executive Officer

EXHIBIT 31.2

CERTIFICATION

I, Joseph A. Householder, certify that:

I have reviewed this report on Form 10-K of Sempra Energy;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 26, 2013

/S/ Joseph A. Householder

Joseph A. Householder

Chief Financial Officer

EXHIBIT 31.3

CERTIFICATION

I, Jessie J. Knight, Jr., certify that:

I have reviewed this report on Form 10-K of San Diego Gas & Electric Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 26, 2013

/S/ Jessie J. Knight, Jr .

Jessie J. Knight, Jr.

Chief Executive Officer

EXHIBIT 31.4

CERTIFICATION

I, Robert M. Schlax, certify that:

I have reviewed this report on Form 10-K of San Diego Gas & Electric Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 26, 2013

/S/ Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

EXHIBIT 31.5

CERTIFICATION

I, Anne S. Smith, certify that:

I have reviewed this report on Form 10-K of Southern California Gas Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 26, 2013

/S/ Anne S. Smith

Anne S. Smith

Chief Executive Officer

EXHIBIT 31.6

CERTIFICATION

I, Robert M. Schlax, certify that:

I have reviewed this report on Form 10-K of Southern California Gas Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

February 26, 2013

/S/ Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

Exhibit 32.1

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Sempra Energy (the "Company") certifies that:

(i)

the Annual Report on Form 10-K of the Company filed with the Securities and Exchange Commission for the year ended December 31, 2012 (the "Annual Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and

(ii)

the information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 26, 2013

/S/ Debra L. Reed

Debra L. Reed

Chief Executive Officer

Exhibit 32.2

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Sempra Energy (the "Company") certifies that:

(i)

(ii)

the information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 26, 2013

/S/ Joseph A. Householder

Joseph A. Householder

Chief Financial Officer

Exhibit 32.3

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of San Diego Gas & Electric Company (the "Company") certifies that:

(i)

(ii)

the information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 26, 2013

/S/ Jessie J. Knight, Jr.

Jessie J. Knight, Jr.

Chief Executive Officer

Exhibit 32.4

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of San Diego Gas & Electric Company (the "Company") certifies that:

(i)

(ii)

the information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 26, 2013

/S/ Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

Exhibit 32.5

Statement of Chief Executive Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Southern California Gas Company (the "Company") certifies that:

(i)

(ii)

the information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 26, 2013

/S/ Anne S. Smith

Anne S. Smith

Chief Executive Officer

Exhibit 32.6

Statement of Chief Financial Officer

Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Southern California Gas Company (the "Company") certifies that:

(i)

(ii)

the information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 26, 2013

/S/ Robert M. Schlax

Robert M. Schlax

Chief Financial Officer

Exhibit 13.1


SEMPRA ENERGY FINANCIAL REPORT TABLE OF CONTENTS
			Page
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our Business			2
Executive Summary			9
Business Strategy			9
Key Events and Issues in 2012			9
Results of Operations			10
Overall Results of Operations of Sempra Energy and Factors Affecting the Results			10
Segment Results			12
Changes in Revenues, Costs and Earnings			17
Transactions with Affiliates			35
Book Value Per Share			35
Capital Resources and Liquidity			35
Overview			35
Cash Flows from Operating Activities			39
Cash Flows from Investing Activities			41
Cash Flows from Financing Activities			46
Credit Ratings			52
Factors Influencing Future Performance			53
Sempra Energy Overview			53
California Utilities			56
Other Sempra Energy Matters			58
Financial Derivatives Reforms			58
Litigation			58
California Utilities – Industry Developments and Capital Projects			58
Sempra International and Sempra U.S. Gas & Power Investments			58
Market Risk			60
Critical Accounting Policies and Estimates, and Key Noncash Performance Indicators			64
New Accounting Standards			70
Information Regarding Forward-Looking Statements			71
Common Stock Data			72
Performance Graph – Comparative Total Shareholder Returns			73
Five-Year Summaries			74
Controls and Procedures
Evaluation of Disclosure Controls and Procedures			76
Management’s Report on Internal Control over Financial Reporting			76
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure			76
Reports of Independent Registered Public Accounting Firm			77
Consolidated Financial Statements
Sempra Energy			83
San Diego Gas & Electric Company			91
Southern California Gas Company			98
Notes to Consolidated Financial Statements			104
Glossary			224

This Financial Report is a combined report for the following separate companies (each a separate Securities and Exchange Commission registrant):

Sempra Energy	San Diego Gas & Electric Company	Southern California Gas Company

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

We provide below:

§	A description of our business

§	An executive summary

§	A discussion and analysis of our operating results for 2010 through 2012

§	Information about our capital resources and liquidity

§	Major factors expected to influence our future operating results

§	A discussion of market risk affecting our businesses

§	A table of accounting policies that we consider critical to our financial condition and results of operations

You should read Management’s Discussion and Analysis of Financial Condition and Results of Operations in conjunction with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements included in this Annual Report.

OUR BUSINESS

Sempra Energy is a Fortune 500 energy-services holding company whose operating units develop energy infrastructure, operate utilities and provide related services to their customers. Our operations are divided principally between our California Utilities, which are San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), and Sempra International and Sempra U.S. Gas & Power. SDG&E and SoCalGas are separate, reportable segments. Sempra International includes two reportable segments – Sempra South American Utilities and Sempra Mexico. Sempra U.S. Gas & Power also includes two reportable segments – Sempra Renewables and Sempra Natural Gas. (See Figure 1.)

[A002.GIF]

Figure 1: Sempra Energy’s Operating Units and Reportable Segments

This report includes information for the following separate registrants:

§	Sempra Energy and its consolidated entities

SDG&E

SoCalGas

References to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by its context. All references to “Sempra International” and “Sempra U.S. Gas & Power,” and to their respective principal segments, are not intended to refer to any legal entity with the same or similar name.

During the fourth quarter of 2012, we revised the manner in which we make resource allocation decisions to our Sempra Mexico segment and assess its performance, as we discuss in Notes 16 and 18 of the Notes to Consolidated Financial Statements. As a result, we have reclassified certain amounts from Parent and Other, which contains interest and other corporate costs and certain holding company activities, to our Sempra Mexico segment. In accordance with accounting principles generally accepted in the United States (U.S. GAAP), our historical segment disclosures have been restated to be consistent with the current presentation. All discussions of our operating units and reportable segments reflect the revised segment information.

RBS Sempra Commodities LLP (RBS Sempra Commodities) is a joint venture partnership that held commodities-marketing businesses previously owned by us. We and The Royal Bank of Scotland plc (RBS), our partner in the joint venture, sold substantially all of the partnership’s businesses and assets in four separate transactions completed in July, November and December of 2010 and February of 2011. We discuss these transactions and other matters concerning the partnership in Notes 4, 5 and 15 of the Notes to Consolidated Financial Statements. We account for our investment in RBS Sempra Commodities under the equity method and report our share of partnership earnings and other associated costs in Parent and Other.

Below are summary descriptions of our operating units and their reportable segments.

SEMPRA ENERGY OPERATING UNITS AND REPORTABLE SEGMENTS

CALIFORNIA UTILITIES
	MARKET	SERVICE TERRITORY
SAN DIEGO GAS & ELECTRIC COMPANY (SDG&E) A regulated public utility; infrastructure supports electric generation, transmission and distribution, and natural gas distribution	§ Provides electricity to 3.4 million consumers (1.4 million meters) § Provides natural gas to 3.1 million consumers (860,000 meters)	Serves the county of San Diego, California and an adjacent portion of southern Orange County covering 4,100 square miles
SOUTHERN CALIFORNIA GAS COMPANY (SOCALGAS) A regulated public utility; infrastructure supports natural gas distribution, transmission and storage	§ Residential, commercial, industrial, utility electric generation and wholesale customers § Covers a population of 21.1 million (5.8 million meters)	Southern California and portions of central California (excluding San Diego County, the city of Long Beach and the desert area of San Bernardino County) covering 20,000 square miles

We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International or Sempra U.S. Gas & Power operating units described below.

SDG&E

SDG&E provides electricity to 3.4 million consumers and natural gas to 3.1 million consumers. It delivers the electricity through 1.4 million meters in San Diego County and an adjacent portion of southern Orange County, California. SDG&E’s electric energy is purchased from others or generated from its own electric generation facilities and its 20-percent ownership interest in the San Onofre Nuclear Generating Station (SONGS). Due to operating issues at SONGS, this facility has been offline since the first quarter of 2012. SDG&E has purchased and continues to purchase power to replace the amount of power that would have been provided to SDG&E from SONGS. We discuss the current SONGS outage and related issues in “Factors Influencing Future Performance” below and in Note 14 of the Notes to Consolidated Financial Statements. SDG&E’s electric generation facilities include Palomar Energy Center, Miramar Energy Center, Desert Star Energy Center (purchased from Sempra Natural Gas in October 2011) and Cuyamaca Peak Energy Plant (purchased in January 2012). SDG&E also delivers natural gas through 860,000 meters in San Diego County and transports electricity and natural gas for others. SDG&E’s service territory encompasses 4,100 square miles.

Sempra Energy indirectly owns all of the common stock of SDG&E. SDG&E also has publicly held preferred stock. The preferred stock has liquidation preferences totaling $79 million and represents less than 3% of the ordinary voting power of SDG&E shares.

SDG&E’s financial statements include a variable interest entity (VIE), Otay Mesa Energy Center LLC (Otay Mesa VIE), of which SDG&E is the primary beneficiary. As we discuss in Note 1 of the Notes to Consolidated Financial Statements under “Variable Interest Entities,” SDG&E has a long-term power purchase agreement with Otay Mesa VIE.

SoCalGas

SoCalGas is the nation’s largest natural gas distribution utility. It owns and operates a natural gas distribution, transmission and storage system that supplies natural gas throughout its 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 5.8 million meters, covering a population of 21.1 million.

Sempra Energy indirectly owns all of the common stock of SoCalGas. SoCalGas also has publicly held preferred stock. The preferred stock has liquidation preferences totaling $22 million and represents less than 1% of the ordinary voting power of SoCalGas shares.

We provide descriptions of our Sempra International and Sempra U.S. Gas & Power businesses below.

SEMPRA INTERNATIONAL
	MARKET	GEOGRAPHIC REGION
SEMPRA SOUTH AMERICAN UTILITIES Infrastructure supports electric transmission and distribution	§ Provides electricity to approximately 620,000 customers in Chile and more than 950,000 customers in Peru	§ Chile § Peru
SEMPRA MEXICO Develops, owns and operates, or holds interests in: § natural gas transmission pipelines and propane and ethane systems § a natural gas distribution utility § electric generation facilities, including wind § a terminal for the importation of liquefied natural gas (LNG) § marketing operations for the purchase of LNG and the purchase and sale of natural gas	§ Natural gas § Wholesale electricity § Liquefied natural gas	§ Mexico

Sempra International

Sempra South American Utilities

Sempra South American Utilities operates electric transmission and distribution utilities in Chile and Peru, and owns interests in utilities in Argentina.

On April 6, 2011, Sempra South American Utilities completed the acquisition of AEI’s interests in Chilquinta Energía S.A. (Chilquinta Energía) in Chile and Luz del Sur S.A.A. (Luz del Sur) in Peru. Upon completion of the transaction, Sempra South American Utilities owned 100 percent of Chilquinta Energía and approximately 76 percent of Luz del Sur, and the companies are now consolidated. Pursuant to a tender offer that was completed in September 2011, Sempra South American Utilities now owns 79.82 percent of Luz del Sur, as we discuss in Note 3 of the Notes to Consolidated Financial Statements. The remaining shares of Luz del Sur are held by institutional investors and the general public. Prior to the acquisition in 2011, we accounted for our 50-percent interest in Chilquinta Energía and approximately 38-percent interest in Luz del Sur as equity method investments.

Chilquinta Energía is an electric distribution utility serving approximately 620,000 customers in the cities of Valparaiso and Viña del Mar in central Chile. Luz del Sur is an electric distribution utility that serves more than 950,000 customers in the southern zone of metropolitan Lima, Peru, and delivers approximately one-third of all power used in the country. As part of the transaction, Sempra South American Utilities also acquired AEI’s interests in two energy-services companies, Tecnored S.A. (Tecnored) and Tecsur S.A. (Tecsur).

Sempra South American Utilities also is currently pursuing the sale of its interests in the Argentine utilities, which we discuss further in Note 4 of the Notes to Consolidated Financial Statements.

Sempra Mexico

Gas Business

Pipelines . Sempra Mexico develops, owns and operates natural gas transmission pipelines and propane and ethane systems in Mexico. These facilities are contracted under long-term, U.S. dollar-based agreements with PEMEX (the Mexican state-owned oil company), the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE), Shell México Gas Natural (Shell), Gazprom Marketing & Trading Mexico (Gazprom) and other similar counterparties. Its natural gas pipeline systems had a contracted capacity for up to 4,650 million cubic feet per day in 2012.

Sempra Mexico also owns a 50-percent interest in Gasoductos de Chihuahua, a joint venture with PEMEX that operates two natural gas pipelines and a propane system in northern Mexico and is developing an ethane system in southern Mexico.

LNG . Sempra Mexico’s Energía Costa Azul LNG terminal in Baja California, Mexico is capable of processing 1 billion cubic feet (Bcf) of natural gas per day. The Energía Costa Azul facility generates revenue under a capacity services agreement with Shell, expiring in 2028, that originally permitted Shell to use one-half of the terminal’s capacity. In April 2009, Shell assigned a portion of its terminal capacity at Energía Costa Azul to Gazprom, transferring all further rights and obligations with respect to the assigned capacity, and a separate capacity services agreement between Energía Costa Azul and Gazprom was put into place.

A nitrogen-injection facility at Energía Costa Azul allows the terminal to process LNG cargoes from a wider variety of sources and provides additional revenue from payments for capacity reservation and usage fees for nitrogen injection services for Shell and Gazprom.

In connection with Sempra Natural Gas’ LNG purchase agreement with Tangguh PSC Contractors (Tangguh PSC), which we discuss below, Sempra Mexico purchases from Sempra Natural Gas the LNG delivered to Energía Costa Azul by Tangguh PSC. Sempra Mexico uses the natural gas produced from this LNG to supply a contract through 2022 for the sale of an average of approximately 150 million cubic feet per day of natural gas to Mexico’s national electric company, the CFE, at prices that are based on the Southern California border index. If LNG volumes received from Tangguh PSC are not sufficient to satisfy the commitment to the CFE, Sempra Mexico may purchase natural gas from Sempra Natural Gas’ natural gas marketing operations. Under an agreement that expires in the third quarter of 2014 among Sempra Natural Gas, Sempra Mexico, J.P. Morgan Mexico and J.P. Morgan Ventures Energy Corporation (J.P. Morgan Ventures), Sempra Natural Gas and Sempra Mexico sell to J.P. Morgan Ventures and J.P. Morgan Mexico any volumes received from Tangguh PSC that are not sold to the CFE. The agreement was previously with RBS Sempra Commodities. In connection with the 2010 sale of businesses within RBS Sempra Commodities, substantially all contracts with RBS Sempra Commodities were assigned to J.P. Morgan Ventures by May 1, 2011, as we discuss under “Transactions with RBS Sempra Commodities” in Note 1 of the Notes to Consolidated Financial Statements.

Natural Gas Distribution . Sempra Mexico’s natural gas distribution utility, Ecogas Mexico, S de RL de CV (Ecogas), operates in three separate areas in Mexico, and had approximately 93,000 customers and sales volume of 62 million cubic feet per day in 2012.

Power Business

Natural Gas-Fired Generation . Sempra Mexico’s Termoeléctrica de Mexicali, a 625-megawatt (MW) natural gas-fired power plant, is located in Mexicali, Baja California, Mexico. In January 2013, Sempra Mexico’s Termoeléctrica de Mexicali entered into an Energy Management Agreement (EMA), effective January 1, 2012, with our Sempra Natural Gas segment for energy marketing, scheduling and other related services to support its sales of generated power into the California electricity market. Under the EMA, Termoeléctrica de Mexicali pays fees to Sempra Natural Gas for these revenue-generating services. Termoeléctrica de Mexicali also purchases fuel from Sempra Natural Gas. J.P. Morgan Ventures and J.P. Morgan Mexico facilitate the natural gas transactions between the segments. Sempra Mexico records revenue for the sale of power generated by Termoeléctrica de Mexicali, and records cost of sales for the purchases of natural gas and energy management services provided by Sempra Natural Gas.

The EMA replaced a similar agreement that was in effect in prior years, under which Sempra Mexico recorded revenue for the sale of power generated by Termoeléctrica de Mexicali to Sempra Natural Gas, and recorded cost of sales for the purchases from Sempra Natural Gas of natural gas to fuel the facility. J.P. Morgan Ventures and J.P. Morgan Mexico facilitated the natural gas transactions between the segments.

Wind Power Generation . Sempra Mexico is developing a wind power generation project, Energía Sierra Juárez, in Baja California, Mexico. The project will be developed in phases. In April 2011, SDG&E entered into a 20-year contract for up to 156 MW of renewable power supplied from the first phase of the project, which we expect to be fully operational in 2014.

SEMPRA U.S. GAS & POWER
	MARKET	GEOGRAPHIC REGION
SEMPRA RENEWABLES Develops, owns, operates, or holds interests in renewable energy generation projects	§ Wholesale electricity	§ U.S.A.
SEMPRA NATURAL GAS Develops, owns and operates, or holds interests in: § a natural gas-fired electric generation plant § natural gas pipelines and storage facilities § natural gas distribution utilities § a terminal in the U.S. for the importation and export of LNG and sale of natural gas § marketing operations	§ Wholesale electricity § Natural gas § Liquefied natural gas	§ U.S.A.

Sempra U.S. Gas & Power

Sempra Renewables

The following table provides information about the Sempra Renewables facilities that were operational as of December 31, 2012. The generating capacity of these facilities is fully contracted under long-term contracts, as we discuss below.

SEMPRA RENEWABLES OPERATING FACILITIES
Capacity in Megawatts (MW) at December 31, 2012
Name		Generating Capacity		First In Service	Location
Fowler Ridge 2 Wind Farm (50% owned)		100	(1)	2009	Benton County, Indiana
Copper Mountain Solar 1		58	(2)	2010	Boulder City, Nevada
Cedar Creek 2 Wind Farm (50% owned)		125	(1)	2011	New Raymer, Colorado
Mesquite Solar 1		42/108	(3)	2011/2012	Arlington, Arizona
Copper Mountain Solar 2		92		2012	Boulder City, Nevada
Flat Ridge 2 Wind Farm (50% owned)		235	(1)	2012	Wichita, Kansas
Mehoopany Wind Farm (50% owned)		71	(1)	2012	Wyoming County, Pennsylvania
Auwahi Wind (50% owned)		11	(1)	2012	Maui, Hawaii
	Total MW in operation	842
(1)	Sempra Renewables’ share. We account for our interests in these facilities as equity method investments.
(2)	Includes the 10-MW facility previously referred to as El Dorado Solar, which was first placed in service in 2008.
(3)	Represents the portion of the project that was completed in the year indicated.

Fowler Ridge 2 Wind Farm. Fowler Ridge 2 Wind Farm (Fowler Ridge 2), a joint venture with BP Wind Energy (a wholly owned subsidiary of BP p.l.c.), is a 200-MW wind power facility located in Benton County, Indiana. Fowler Ridge 2’s entire output is sold under four long-term contracts, each for 50 MW and 20-year terms.

Copper Mountain Solar 1. In December 2010, Sempra Renewables completed the construction of Copper Mountain Solar, a 48-MW solar generation facility located in Boulder City, Nevada, on land adjacent to a 10-MW solar facility formerly referred to as El Dorado Solar. Pacific Gas and Electric Company (PG&E) has contracted for all of the power from these facilities, now combined and referred to as Copper Mountain Solar 1, under separate 20-year contracts.

Cedar Creek 2 Wind Farm. In October 2010, Sempra Renewables invested $209 million for a 50-percent ownership interest in Cedar Creek 2 Wind Farm (Cedar Creek 2), a joint venture with BP Wind Energy for the development of a 250-MW wind farm in northern Colorado, which was placed in service in June 2011. Public Service Company of Colorado, an Xcel Energy subsidiary, has contracted for all of the power from the facility for 25 years.

Mesquite Solar 1. Construction on the 150-MW Mesquite Solar 1 photovoltaic solar installation in Arlington, Arizona, began in June 2011 and was completed in December 2012. Power from the facility is sold to PG&E under a 20-year contract.

Copper Mountain Solar 2. Copper Mountain Solar 2 (CMS 2) began construction in December 2011 and will total 150 MW when completed. CMS 2 is divided into two phases, with the first phase of 92 MW placed in service in November 2012 and the remaining 58 MW planned to be placed in service in 2015. PG&E has contracted for all of the solar power at CMS 2 for 25 years.

Flat Ridge 2 Wind Farm. In December 2012, construction was completed on the Flat Ridge 2 Wind Farm (Flat Ridge 2), a joint venture between Sempra Renewables and BP Wind Energy.

Flat Ridge 2 is located near Wichita, Kansas, and is capable of generating up to 470 MW of energy, which includes 419 MW from the original phase and 51 MW in the expansion phase. The power output from the original phase has been sold under three contracts for 20- and 25-year terms, including contracts with Associated Electric Cooperative, Inc. and Southwestern Electric Power Company. The power output from the expansion phase has been sold under a purchase power agreement with Arkansas Electric Cooperative approved by the Rural Utilities Service in April 2012.

Mehoopany Wind Farm. In December 2012, construction was completed on the Mehoopany Wind Farm (Mehoopany), a joint venture between Sempra Renewables and BP Wind Energy. Located in Wyoming County, Pennsylvania, the facility is capable of generating up to 141 MW of energy. The power output from the wind farm has been sold under 20-year contracts to Old Dominion Electric Cooperative and Southern Maryland Electric Cooperative Inc.

Auwahi Wind Farm. Significant project costs were incurred during late 2011, and physical construction on the 21-MW Auwahi Wind facility began in March 2012 and was completed in December 2012. The project is a joint venture with BP Wind Energy and is located in the southeastern region of Maui. The power from the facility has been sold to Maui Electric Company under a 20-year contract.

Sempra Natural Gas

Generation . Sempra Natural Gas sells electricity under short-term and long-term contracts and into the spot market and other competitive markets. While it may also purchase electricity in the open market to satisfy its contractual obligations, Sempra Natural Gas generally purchases natural gas to fuel its Mesquite Power natural gas-fired power plant, and, as we discuss above, Sempra Mexico’s Termoeléctrica de Mexicali plant. The Mesquite Power plant is a 1,250-MW facility located in Arlington, Arizona. In December 2012, Sempra Natural Gas entered into a definitive agreement to sell one 625-MW block of Mesquite Power to the Salt River Project Agricultural Improvement and Power District for approximately $370 million. We expect the transaction to close in the first quarter of 2013.

In June 2011, Sempra Natural Gas entered into a 25-year contract with various members of Southwest Public Power Resources Group (SPPR Group), an association of 40 not-for-profit utilities in Arizona and southern Nevada, for 240 MW of electricity. This contract was amended in early 2013 to increase the capacity to 271 MW. Under the terms of the agreement, Sempra Natural Gas will provide 21 participating SPPR Group members with firm, day-ahead dispatchable power delivered to the Palo Verde hub beginning in January 2015.

Sempra Natural Gas also has various power sale transactions intended to hedge its generation capacity. Through 2012, Sempra Natural Gas sold its power to various counterparties, including J.P. Morgan Ventures. Contracts with J.P. Morgan Ventures were initially with RBS Sempra Commodities. In connection with the 2010 sale of businesses within RBS Sempra Commodities, substantially all of these transactions with RBS Sempra Commodities were assigned to J.P. Morgan Ventures by May 1, 2011. In addition, Sempra Natural Gas has power sale transactions for various quantities of power for delivery in 2013 and 2014. Finally, Sempra Natural Gas has sold certain quantities of expected future generation output under long-term contracts. The remaining output of our natural gas-fired generation facilities, including that of Sempra Mexico’s Termoeléctrica de Mexicali power plant, is available to be sold into energy markets on a day-to-day basis.

In January 2013, Sempra Natural Gas entered into an EMA, effective January 1, 2012, with Sempra Mexico to provide energy marketing, scheduling and other related services to Sempra Mexico’s Termoeléctrica de Mexicali to support its sales of generated power into the California electricity market. We discuss the EMA in “Sempra Mexico – Power Business” above.

Sempra Natural Gas sold its El Dorado natural gas-fired generation plant (excluding the solar facility) to SDG&E on October 1, 2011. This sale, pursuant to an option to acquire the plant that was exercised by SDG&E in 2007, coincided with the end of a contract with the California Department of Water Resources (DWR). Prior to September 30, 2011, the Mesquite Power plant and the El Dorado generation plant, along with Sempra Mexico’s Termoeléctrica de Mexicali power plant, sold the majority of their output under this long-term purchased-power contract with the DWR which provided for 1,200 MW to be supplied during all hours and an additional 400 MW during on-peak hours, and which ended on September 30, 2011.

From 2003 through 2010, Sempra Natural Gas had a 50-percent equity interest in Elk Hills Power (Elk Hills), a 550-MW merchant plant located in Bakersfield, California. Elk Hills offered its output into the California market on a daily basis. Sempra Natural Gas sold its interest in Elk Hills on December 31, 2010, as we discuss in Note 4 of the Notes to Consolidated Financial Statements.

Transportation and Storage . Sempra Natural Gas owns and operates, or holds interests in, natural gas underground storage and related pipeline facilities in Alabama, Louisiana and Mississippi. Sempra Natural Gas provides natural gas marketing, trading and risk management activities through the utilization and optimization of contracted natural gas supply, transportation and storage capacity, as well as optimizing its assets in the short-term services market.

Sempra Natural Gas, Tallgrass Energy Partners, L.P. (Tallgrass) and Phillips 66 jointly own, through Rockies Express Pipeline LLC (Rockies Express), the Rockies Express Pipeline (REX) that links producing areas in the Rocky Mountain region to the upper Midwest and the eastern United States. Our ownership interest in the pipeline is 25 percent. Tallgrass purchased its 50-percent equity interest in Rockies Express from Kinder Morgan Energy Partners, L.P. (Kinder Morgan or KMP) in November 2012, as we discuss in Notes 4 and 11 of the Notes to Consolidated Financial Statements. Sempra Rockies Marketing has an agreement through November 2019 with Rockies Express for 200 million cubic feet per day of capacity on REX, which has a total capacity of 1.8 Bcf per day. Sempra Rockies Marketing released a portion of its capacity to RBS Sempra Commodities, which capacity was assigned to J.P. Morgan Ventures effective January 1, 2011 in connection with the sale of businesses within RBS Sempra Commodities. This contract expires December 31, 2013.

In 2012, we recorded a noncash impairment charge of $239 million after-tax to write down our investment in the partnership that operates REX. We discuss our investment in Rockies Express and the impairments in Notes 4 and 11 of the Notes to Consolidated Financial Statements.

Distribution . Sempra Natural Gas owns and operates Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas Company (Willmut Gas), regulated natural gas distribution utilities in southwest Alabama and in Mississippi, respectively. Mobile Gas and Willmut Gas serve approximately 88,000 customers and 20,000 customers, respectively. Sempra Natural Gas acquired Willmut Gas in May 2012, as we discuss in Note 3 of the Notes to Consolidated Financial Statements.

LNG . Sempra Natural Gas’ Cameron LNG terminal in Hackberry, Louisiana is capable of processing 1.5 Bcf of natural gas per day. Cameron LNG generates revenue under a terminal services agreement for approximately 3.75 Bcf of natural gas storage and associated send-out rights of approximately 600 million cubic feet of natural gas per day through 2029. The agreement allows the customer to pay Sempra Natural Gas capacity reservation and usage fees to use its facilities to receive, store and regasify the customer’s LNG. Sempra Natural Gas also may enter into short-term and/or long-term supply agreements to purchase LNG to be received, stored and regasified at its terminal for sale to other parties. Sempra Natural Gas is currently progressing with the development of a natural gas liquefaction and LNG export facility at the Cameron LNG terminal. We discuss these activities below in “Factors Influencing Future Performance.”

Sempra Natural Gas has an LNG purchase agreement with Tangguh PSC for the supply of the equivalent of 500 million cubic feet of natural gas per day from Tangguh PSC’s Indonesian liquefaction facility with delivery to Sempra Mexico’s Energía Costa Azul receipt terminal at a price based on the Southern California border index for natural gas. As discussed above, Sempra Natural Gas has an agreement to sell to J.P. Morgan Ventures any volumes purchased from Tangguh PSC that are not sold to the CFE or J.P. Morgan Mexico. This agreement was previously with RBS Sempra Commodities. In connection with the 2010 sale of businesses within RBS Sempra Commodities, substantially all contracts with RBS Sempra Commodities were assigned to J.P. Morgan Ventures by May 1, 2011. Sempra Natural Gas may also record revenues from non-delivery of cargoes under the provisions of the contract with Tangguh PSC that allow for deliveries to be diverted to other global markets in exchange for cash differential payments.

REGULATION OF OUR UTILITIES

SDG&E and SoCalGas are regulated by federal, state and local governmental agencies. The primary regulatory agency is the California Public Utilities Commission (CPUC). The CPUC regulates the California Utilities’ rates and operations in California, except for SDG&E’s electric transmission operations. The Federal Energy Regulatory Commission (FERC) regulates SDG&E’s electric transmission operations. The FERC also regulates interstate transportation of natural gas and various related matters.

The Nuclear Regulatory Commission (NRC) regulates SONGS, in which SDG&E owns a 20-percent interest. Municipalities and other local authorities regulate the location of utility assets, including natural gas pipelines and electric lines. Sempra Energy’s other operating units are also regulated by the FERC, various state commissions, local governmental entities, and other similar authorities in countries other than the United States.

Our South American utilities are regulated by federal and local government agencies. The National Energy Commission (Comisión Nacional de Energ í a, or CNE) regulates Chilquinta Energía in Chile. The Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería, or OSINERGMIN) of the National Electricity Office under the Ministry of Energy and Mines regulates Luz del Sur in Peru.

Ecogas, our natural gas distribution utility in northern Mexico, is subject to regulation by the Energy Regulatory Commission (Comisión Reguladora de Energía, or CRE) and by the labor and environmental agencies of city, state and federal governments in Mexico.

Mobile Gas, our natural gas distribution utility serving southwest Alabama, is regulated by the Alabama Public Service Commission. Willmut Gas, our natural gas distribution utility serving customers in Hattiesburg, Mississippi, is regulated by the Mississippi Public Service Commission.

EXECUTIVE SUMMARY

BUSINESS STRATEGY

Our focus is to deliver superior total shareholder returns and meet customer needs by developing and operating a safe and stable portfolio of integrated energy businesses with long-term, predictable cash flows.

The key components of our strategy include the following three disciplined growth platforms:

§	U.S. utilities

§	South American utilities and Mexican midstream

§	U.S. natural gas midstream and renewables

Our organization is aligned based on these platforms so that we obtain the greatest value from the integration of our assets and businesses. Our goal is to deliver superior shareholder returns by having top quartile annual growth and providing a strong dividend.

KEY EVENTS AND ISSUES IN 2012

Below are several key events and issues that affected our business in 2012; some of these may continue to affect our future results. Each event/issue includes the page number you may reference for additional details.

§	In June 2012, SDG&E completed the construction of and placed in service the Sunrise Powerlink electric transmission line (206).

§	During 2012, Sempra Renewables installed a total generating capacity of 832 MW at Mesquite Solar 1, Flat Ridge 2 Wind Farm, Mehoopany Wind Farm, Auwahi Wind Farm and the first phase of Copper Mountain Solar 2, of which 517 MW represents our share based on ownership interest (6).

§	Sempra Natural Gas executed commercial development agreements with three project participants to develop a natural gas liquefaction export facility at its Cameron LNG terminal (55).

o	In January 2012, the Department of Energy (DOE) approved Cameron LNG’s application for a license to export LNG to Free Trade Agreement (FTA) countries.

o	In December 2012, we filed our formal FERC permit application.

§	In October 2012, Sempra Mexico was awarded two contracts by the CFE to build and operate an approximately $1 billion, 500-mile natural gas pipeline network in northern Mexico (59).

§	Both SDG&E and SoCalGas have their 2012 General Rate Case (GRC) applications pending at the CPUC. The retroactive impact on 2012 of the final decisions, which are expected in the first half of 2013, will be recorded when the decisions are issued (56).

§	In January and February 2012, Units 3 and 2 of SONGS, respectively, were shut down and remain offline due to a water leak and the detection of excessive wear resulting from tube-to-tube contact (200).

§	In December 2012, the CPUC issued a final decision in SDG&E’s and SoCalGas’ cost of capital proceeding (196).

In December 2012, the CPUC issued a final decision in the California Utilities’ request for a cost recovery framework for the future recovery of wildfire-related expenses for claims and litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC. SDG&E intends to pursue recovery of such costs in a future application to the CPUC, and continues to assess the potential for recovery of these costs in rates (204).

§	SDG&E continues to settle claims related to the 2007 California wildfire litigation; however, a substantial number of unresolved claims against SDG&E remain (205).

§	We recorded $239 million in after-tax noncash impairment charges in 2012 to write down our investment in Rockies Express (136).

RESULTS OF OPERATIONS

We discuss the following in Results of Operations:

§	Overall results of our operations and factors affecting those results

§	Our segment results

§	Significant changes in revenues, costs and earnings between periods

OVERALL RESULTS OF OPERATIONS OF SEMPRA ENERGY AND FACTORS AFFECTING THE RESULTS

The graphs below show our overall operations from 2008 to 2012.

OVERALL OPERATIONS OF SEMPRA ENERGY FROM 2008 TO 2012

(Dollars and shares in millions, except per share amounts)

[A004.GIF]

[A008.GIF]

Our earnings in 2012 decreased by $472 million (35%) to $859 million compared to 2011 primarily due to:

§	a $277 million gain resulting from the remeasurement of our equity method investments at our South American Utilities segment related to its acquisition of additional interests in Chilquinta Energía and Luz del Sur in April 2011;

§	$239 million in noncash impairment charges in 2012 to write down our investment in Rockies Express, partially offset by a $25 million income tax make-whole payment received from Kinder Morgan; and

§	lower earnings at Sempra Natural Gas and Sempra Mexico in 2012 compared to 2011 primarily due to the end of the DWR contract in September 2011; offset by

§	improved results at the California Utilities, Sempra Renewables and Parent and Other.

Diluted earnings per share for 2012 decreased by $2.03 per share to $3.48 per share. Components of this decrease include

§	the remeasurement gain in 2011 ($1.15 per share);

§	the Rockies Express investment write-down in 2012 ($0.97 per share); and

§	an increase in the number of shares outstanding ($0.08 per share); offset by

§	the income tax make-whole payment received from Kinder Morgan in 2012 ($0.10 per share); and

§	a small increase in earnings (excluding the impacts of the 2011 remeasurement gain, and the Rockies Express investment write-down and income tax make-whole payment received in 2012).

Our earnings increased by $622 million in 2011 to $1.3 billion primarily due to:

§	a gain of $277 million resulting from the remeasurement of our equity method investments at Sempra South American Utilities related to its acquisition of additional interests in Chilquinta Energía and Luz del Sur;

§	a $139 million write-down in 2010 of our investment in RBS Sempra Commodities;

§	$93 million litigation expense in 2010 related to an agreement to settle certain energy crisis litigation ($87 million at Sempra Natural Gas and $6 million at Parent and Other), as we discuss in Note 15 of the Notes to Consolidated Financial Statements;

§	higher earnings at SDG&E and Sempra Mexico; and

§	higher earnings at Sempra South American Utilities primarily related to the acquisition of additional interests in Chilquinta Energía and Luz del Sur; offset by

§	lower earnings at Sempra Natural Gas (excluding the energy crisis litigation expense) in 2011 compared to 2010, primarily due to the expiration of the DWR contract; and

§	higher losses at Parent and Other (excluding the investment write-down and energy crisis litigation expense in 2010).

Diluted earnings per share for 2011 increased by $2.65 per share to $5.51 per share. Components of this increase include

§	the remeasurement gain in 2011 ($1.15 per share);

§	the investment write-down in 2010 ($0.56 per share);

§	the settlement-related litigation expense in 2010 ($0.38 per share);

§	higher earnings (excluding the impacts of the 2011 remeasurement gain and the investment write-down and litigation settlement charge in 2010); and

§	a decrease in the number of shares outstanding primarily as a result of our $500 million share repurchase program initiated in September 2010 and completed in March 2011.

The following table shows our earnings (losses) by segment, which we discuss below in “Segment Results.”

SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT 2010-2012
(Dollars in millions)
		Years ended December 31,
		2012				2011				2010
California Utilities:
SDG&E(1)		$	484	56	%	$	431	32	%	$	369	52	%
SoCalGas(1)			289	34			287	22			286	40
Sempra International:
Sempra South American Utilities			164	19			425	32			69	10
Sempra Mexico			157	18			192	14			116	17
Sempra U.S. Gas & Power:
Sempra Renewables			61	7			7	1			9	1
Sempra Natural Gas			(241)	(28)			115	9			71	10
Parent and other(2)			(55)	(6)			(126)	(10)			(211)	(30)
Earnings		$	859	100	%	$	1,331	100	%	$	709	100	%
(1)	After preferred dividends.
(2)	Includes after-tax interest expense ($150 million in 2012, $138 million in 2011 and $144 million in 2010), results from our former Sempra Commodities segment, intercompany eliminations recorded in consolidation and certain other corporate costs.

SEGMENT RESULTS

The following section is a discussion of earnings (losses) by Sempra Energy segment, as presented in the table above. Variance amounts are the after-tax earnings impact, unless otherwise noted.

EARNINGS BY SEGMENT – CALIFORNIA UTILITIES

(Dollars in millions)

[A010.GIF]

SDG&E

Our SDG&E segment recorded earnings of:

§	$484 million in 2012 ($489 million before preferred dividends)

§	$431 million in 2011 ($436 million before preferred dividends)

§	$369 million in 2010 ($374 million before preferred dividends)

The increase in earnings of $53 million (12%) in 2012 was primarily due to:

§	$52 million reduction in 2012 income tax expense primarily due to a change in the income tax treatment of certain repairs expenditures that are capitalized for financial statement purposes for 2011 and 2012, as we discuss below in “Income Taxes;”

§	$33 million higher earnings related to Sunrise Powerlink;

§	$13 million higher earnings for Desert Star in 2012, which was acquired in October 2011;

§	$11 million higher electric transmission margin (excluding Sunrise Powerlink);

§	$8 million increase in allowance for funds used during construction (AFUDC) related to equity (excluding Sunrise Powerlink);

§	$7 million lower expense associated with the settlement of 2007 wildfire claims; and

§	$6 million for the recovery in 2012 of incremental costs incurred in prior years for the long-term storage of spent nuclear fuel; offset by

$28 million higher depreciation and operation and maintenance expenses related to CPUC-regulated operations (excluding insurance premiums for wildfire coverage, litigation and Desert Star) with no corresponding increase in the CPUC-authorized margin in 2012 due to the delay in the 2012 GRC decision;

§	$18 million unfavorable earnings impact due to higher revenues in 2011 associated with incremental wildfire insurance premiums (revenues in 2011 were for an 18-month period compared to a 12-month period in 2012, as we discuss in Note 14 of the Notes to Consolidated Financial Statements);

§	$18 million higher interest expense;

§	$6 million lower regulatory incentive awards; and

§	$5 million higher litigation expense.

The increase of $62 million (17%) in 2011 was primarily due to:

§	$31 million increase in AFUDC related to equity, net of higher interest expense;

§	$28 million favorable earnings impact due to higher revenues associated with incremental wildfire insurance premiums. Revenues in 2011 were for an 18-month period compared to a 12-month period in 2010;

§	$13 million higher authorized margin for CPUC-regulated operations, net of higher depreciation and operation and maintenance expenses (excluding insurance premiums for wildfire coverage and litigation);

§	$7 million lower expenses associated with the settlement of 2007 wildfire claims; and

§	$5 million higher regulatory incentive awards; offset by

§	$10 million primarily from the favorable resolution of prior year’s tax matters in 2010; and

§	$8 million lower favorable resolution of litigation matters in 2011.

SoCalGas

Our SoCalGas segment recorded earnings of:

§	$289 million in 2012 ($290 million before preferred dividends)

§	$287 million in 2011 ($288 million before preferred dividends)

§	$286 million in 2010 ($287 million before preferred dividends)

The increase of $2 million (1%) in 2012 was primarily due to:

§	$37 million from a lower effective tax rate, primarily due to a change in the income tax treatment of certain repairs expenditures that are capitalized for financial statement purposes, as we discuss below in “Income Taxes;” and

§	$6 million from an increase in AFUDC related to equity; offset by

§	$37 million increase in non-refundable operating expenses, primarily due to depreciation and expenses related to the Transmission Integrity Management Program (TIMP), with no corresponding increase in CPUC-authorized margin in 2012 due to the delay in the 2012 GRC decision; and

§	$2 million higher bad debt accruals.

The $1 million increase in earnings in 2011 was primarily due to:

§	$13 million due to the write-off of deferred tax assets in 2010 as a result of the change in U.S. tax law regarding the Medicare Part D subsidy;

§	$9 million higher authorized margin for CPUC-regulated operations, net of higher depreciation and operation and maintenance expenses; and

§	$3 million higher equity-related AFUDC, net of higher interest expense; offset by

§	$7 million lower regulatory incentive awards;

§	$7 million due to the favorable resolution of a legal matter in 2010; and

§	$6 million lower non-core natural gas storage revenue.

EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL

(Dollars in millions)

[A011.GIF]

Sempra South American Utilities

Our Sempra South American Utilities segment recorded earnings of:

§	$164 million in 2012

§	$425 million in 2011

§	$69 million in 2010

The decrease in earnings of $261 million in 2012 was primarily due to:

§	the $277 million gain related to the remeasurement of the Chilquinta Energía and Luz del Sur equity method investments in April 2011; and

§	$12 million earnings in 2011 from foreign currency rate effect mainly for a previously held U.S. dollar monetary position in Chile; offset by

§	$21 million higher earnings in 2012 due to the acquisition of additional interests in Chilquinta Energía and Luz del Sur in April 2011; and

§	$7 million higher earnings from operations in 2012 primarily attributable to an increase in customer base and higher consumption.

The increase of $356 million in 2011 was primarily due to:

§	the $277 million gain related to the remeasurement of the Chilquinta Energía and Luz del Sur equity method investments;

§	$55 million higher earnings primarily related to the acquisition of additional interests in Chilquinta Energía and Luz del Sur in April 2011;

§	$44 million (pretax) write-down of our investment in Argentina in 2010, less a related income tax benefit of $15 million; and

§	$17 million higher earnings from foreign currency rate effect primarily for a previously held net U.S. dollar monetary position in Chile; offset by

§	$48 million (pretax) in proceeds received from a legal settlement in 2010, less a related income tax effect of $17 million.

Sempra Mexico

Sempra Mexico recorded earnings of:

§	$157 million in 2012

§	$192 million in 2011

§	$116 million in 2010

The decrease in earnings of $35 million (18%) in 2012 was primarily due to:

$43 million lower earnings at our Mexicali power plant in 2012 compared to 2011 primarily due to the expiration of the DWR contract in September 2011, which resulted in a change in the intercompany agreement with Sempra Natural Gas effective January 1, 2012. This decrease was partially offset by an increase in earnings from a prior year outage at the plant; and

§	$8 million income tax expense in 2012 compared to $12 million income tax benefit in 2011, primarily related to Mexican currency translation and inflation adjustments and to changes in tax valuation allowances, net of the effects of a Mexican peso income tax hedge; offset by

§	$22 million in improved operations primarily due to increased earnings from Sempra Mexico’s joint venture with PEMEX and from Sempra Mexico’s LNG operations; and

§	$4 million positive translation effect on Peso-denominated receivables.

The increase of $76 million (66%) in 2011 was primarily due to:

§	$25 million higher earnings from gas power plant operations primarily due to scheduled plant maintenance at the Mexicali power plant and associated down time in 2010;

§	$13 million higher earnings from pipeline assets acquired in April 2010;

§	$9 million income tax benefit in 2011 compared to $19 million of income tax expense in 2010 related to Mexican currency translation and inflation adjustments, net of the effects of a Mexican peso income tax hedge in 2011; and

§	a $6 million release of a tax valuation allowance in Mexico.

EARNINGS (LOSSES) BY SEGMENT – SEMPRA U.S. GAS & POWER

(Dollars in millions)

[A012.GIF]

Sempra Renewables

Sempra Renewables recorded earnings of:

§	$61 million in 2012

§	$7 million in 2011

§	$9 million in 2010

The increase in earnings of $54 million in 2012 was primarily due to:

§	$35 million higher deferred income tax benefits as a result of increased investments in solar and wind generating assets in 2012;

§	$7 million higher production tax credits from our wind assets;

§	$6 million higher earnings attributable to our solar assets; and

§	$3 million higher interest income.

The decrease in earnings in 2011 of $2 million (22%) was primarily due to:

§	$5 million higher operating losses at our facilities and equity method investments; offset by

§	$4 million higher production tax credits in 2011.

Sempra Natural Gas

Sempra Natural Gas recorded (losses) earnings of:

§	$(241) million in 2012

§	$115 million in 2011

§	$71 million in 2010

The change in 2012 was primarily due to:

§	$239 million write-down of our investment in Rockies Express in 2012;

§	$121 million lower earnings from natural gas power plant operations in 2012 compared to 2011 primarily from lower natural gas and power prices, including the impact from the end of the DWR contract as of September 30, 2011; and

§	$44 million lower earnings from LNG primarily due to lower natural gas prices, timing of cargo marketing operations and costs in 2012 related to the development of the Cameron liquefaction project; offset by

§	a $25 million payment received from Kinder Morgan due to tax impacts related to the sale of their interest in Rockies Express; and

§	$23 million operating losses in 2011 from the El Dorado power plant sold to SDG&E as of October 1, 2011.

The increase in 2011 of $44 million (62%) was primarily due to:

§	$85 million decreased litigation expense primarily related to a 2010 agreement to settle energy crisis litigation, as we discuss in Note 15 of the Notes to Consolidated Financial Statements;

§	$17 million higher earnings from LNG operations, including from contractual counterparty obligations for non-delivery of cargoes and $18 million in gains in 2011 associated with marketing activities not expected to recur;

§	$10 million decreased gas power plant operation and maintenance expense primarily as a result of 2010 major maintenance at the Mesquite power plant, and from the sale of El Dorado to SDG&E as of October 1, 2011; and

§	$8 million higher earnings primarily related to natural gas optimization activities; offset by

§	$76 million lower earnings from gas power plant operations in 2011 compared to 2010 primarily due to the end of the DWR contract as of September 30, 2011, and less favorable pricing in 2011; and

§	$9 million higher mark-to-market losses on forward contracts from our gas power plant operations in 2011.

Parent and Other

Losses for Parent and Other were

§	$55 million in 2012

§	$126 million in 2011

§	$211 million in 2010

The decrease in losses of $71 million (56%) in 2012 was primarily due to:

§	$54 million income tax benefit primarily associated with the decision to hold life insurance contracts to term, as we discuss below in “Income Taxes;”

§	$20 million higher investment gains on dedicated assets in support of our executive retirement and deferred compensation plans, net of the increase in deferred compensation liability associated with the investments;

§	$15 million equity losses in 2011 from the RBS Sempra Commodities joint venture, including a $10 million write-down of the investment; and

§	higher earnings from foreign currency exchange effects mainly related to a Chilean holding company, and hedging transactions; offset by

§	$27 million lower income tax benefits, excluding the $54 million income tax benefit discussed above.

The decrease in losses of $85 million (40%) in 2011 was primarily due to:

§	a $10 million write-down of our investment in the RBS Sempra Commodities joint venture in 2011 compared to a $139 million write-down in 2010; and

§	other joint venture related expenses in 2010, including transaction costs related to the sales within RBS Sempra Commodities and litigation expense; offset by

§	$5 million equity loss in 2011 from our former commodities-marketing businesses compared to equity earnings of $25 million in 2010; and

§	lower earnings from foreign currency exchange effects related to a Chilean holding company, and hedging transactions.

CHANGES IN REVENUES, COSTS AND EARNINGS

This section contains a discussion of the differences between periods in the specific line items of the Consolidated Statements of Operations for Sempra Energy, SDG&E and SoCalGas.

Utilities Revenues

Our utilities revenues include

Natural gas revenues at:

SDG&E

SoCalGas

§	Sempra Mexico’s Ecogas

§	Sempra Natural Gas’ Mobile Gas and Willmut Gas

Electric revenues at:

SDG&E

§	Sempra South American Utilities’ Chilquinta Energía and Luz del Sur

Intercompany revenues included in the separate revenues of each utility are eliminated in the Sempra Energy Consolidated Statements of Operations.

The California Utilities

The current regulatory framework for SoCalGas and SDG&E permits the cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred. However, SoCalGas’ Gas Cost Incentive Mechanism provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Notes 1 and 14 of the Notes to Consolidated Financial Statements.

The regulatory framework also permits SDG&E to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered in the next year through rates.

The table below summarizes Utilities Revenues and Cost of Sales for Sempra Energy, net of intercompany activity.

UTILITIES REVENUES AND COST OF SALES 2010-2012
(Dollars in millions)
		Years ended December 31,
		2012		2011		2010
Electric revenues:
SDG&E		$	3,226	$	2,830	$	2,535
Sempra South American Utilities			1,349		1,009		―
Eliminations and adjustments			(7)		(6)		(7)
	Total		4,568		3,833		2,528
Natural gas revenues:
SoCalGas			3,282		3,816		3,822
SDG&E			468		543		514
Sempra Mexico			75		91		94
Sempra Natural Gas			96		93		106
Eliminations and adjustments			(48)		(54)		(45)
	Total		3,873		4,489		4,491
Total utilities revenues		$	8,441	$	8,322	$	7,019
Cost of electric fuel and purchased power:
SDG&E		$	892	$	715	$	637
Sempra South American Utilities			868		682		―
	Total	$	1,760	$	1,397	$	637
Cost of natural gas:
SoCalGas		$	1,074	$	1,568	$	1,699
SDG&E			151		226		217
Sempra Mexico			45		63		67
Sempra Natural Gas			25		27		44
Eliminations and adjustments			(5)		(18)		(15)
	Total	$	1,290	$	1,866	$	2,012

Sempra Energy Consolidated

Electric Revenues

In 2012, our electric revenues increased by $735 million (19%) to $4.6 billion primarily due to:

§	$396 million increase at SDG&E, which we discuss below; and

$340 million increase at our South American utilities, primarily from the consolidation of Chilquinta Energía and Luz del Sur acquired in April 2011. In addition, electric revenues increased due to higher commodity prices and volume at Luz del Sur, offset by lower commodity prices at Chilquinta Energía.

Our utilities’ cost of electric fuel and purchased power increased by $363 million (26%) to $1.8 billion in 2012 compared to 2011 primarily due to:

§	$186 million increase at Chilquinta Energía and Luz del Sur associated with the higher revenues; and

§	$177 million increase at SDG&E, which we discuss below.

In 2011 compared to 2010, electric revenues increased by $1.3 billion (52%) to $3.8 billion and our cost of electric fuel and purchased power increased by $760 million (119%) to $1.4 billion. The increase in electric revenues included

§	$1.0 billion from the consolidation of electric revenues of Chilquinta Energía and Luz del Sur acquired in April 2011; and

§	$295 million at SDG&E, which we discuss below.

The increase in our cost of electric fuel and purchased power for 2011 compared to 2010 included

§	$682 million from the consolidation of Chilquinta Energía and Luz del Sur acquired in April 2011; and

§	$78 million at SDG&E, which we discuss below.

Natural Gas Revenues

In 2012, Sempra Energy’s natural gas revenues decreased by $616 million (14%) to $3.9 billion, and the cost of natural gas decreased by $576 million (31%) to $1.3 billion. The decrease in natural gas revenues included

§	$494 million and $75 million decreases in cost of natural gas sold at SoCalGas and SDG&E, respectively, from lower natural gas prices and volumes sold; and

§	$64 million lower recovery of the California Utilities’ costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.

Our natural gas revenues in 2011 were essentially unchanged when compared to 2010 at $4.5 billion, while the cost of natural gas sold decreased by $146 million (7%) to $1.9 billion. Natural gas revenues in 2011 compared to 2010 were impacted by:

§	$131 million decrease in cost of natural gas sold at SoCalGas, which was caused primarily by lower natural gas prices, partially offset by higher volumes sold;

§	$13 million lower revenues at Sempra Natural Gas’ Mobile Gas utility; and

§	$12 million lower regulatory awards in 2011 at SoCalGas; offset by

§	$105 million higher recovery of the California Utilities’ costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and

§	$62 million higher authorized base margin at the California Utilities.

We discuss the changes in revenues and cost of natural gas individually for SDG&E and SoCalGas below.

SDG&E: Electric Revenues and Cost of Electric Fuel and Purchased Power

The table below shows electric revenues for SDG&E. Because the cost of electricity is substantially recovered in rates, changes in the cost are reflected in the changes in revenues.

SDG&E
ELECTRIC DISTRIBUTION AND TRANSMISSION 2010-2012
(Volumes in millions of kilowatt-hours, dollars in millions)
	2012			2011			2010
Customer class	Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
Residential	7,587	$	1,242	7,374	$	1,215	7,304	$	1,039
Commercial	6,902		1,017	6,736		1,000	6,738		884
Industrial	2,042		249	2,037		247	2,131		229
Direct access	3,399		148	3,265		148	3,202		124
Street and highway lighting	95		13	100		14	108		13
	20,025		2,669	19,512		2,624	19,483		2,289
Other revenues			198			117			108
Balancing accounts			359			89			138
Total(1)		$	3,226		$	2,830		$	2,535
(1) Includes sales to affiliates of $7 million in 2012, $6 million in 2011, and $7 million in 2010.

In 2012, electric revenues increased by $396 million (14%) to $3.2 billion at SDG&E, primarily due to:

§	$177 million increase in cost of electric fuel and purchased power in 2012 including:

o	$100 million due to the incremental cost of renewable energy and other purchased power, and

o	$77 million due to the cost of power purchased to replace power scheduled to be generated and delivered to SDG&E from SONGS;

§	$130 million higher authorized revenues from electric transmission including:

o	$83 million from placing the Sunrise Powerlink transmission line in service in June 2012, and

o	$47 million from increased investment in other transmission assets;

§	$45 million higher authorized revenues from electric generation, primarily due to the acquisition of the Desert Star generation facility in October 2011;

§	$42 million higher recoverable expenses that are fully offset in operation and maintenance expenses; and

§	$21 million from advanced meter program costs; offset by

§	$22 million lower revenues associated with incremental wildfire insurance premiums; and

§	$10 million lower regulatory awards.

SDG&E’s electric revenues increased by $295 million (12%) to $2.8 billion in 2011 compared to 2010, primarily due to:

§	$81 million higher authorized base margin on electric generation and distribution, including $26 million due to the acquisition of the Desert Star generation facility on October 1, 2011;

§	$78 million increase in the cost of electric fuel and purchased power due to higher prices;

§	$57 million higher revenues associated with incremental wildfire insurance premiums;

§	$29 million higher recoverable expenses that are fully offset in operation and maintenance expenses;

§	$9 million higher authorized transmission margin; and

§	$7 million higher regulatory awards.

We do not include in the Consolidated Statements of Operations the commodity costs (and the revenues to recover those costs) associated with long-term contracts that are allocated to SDG&E by the California DWR. However, we do include the associated volumes and distribution revenues in the table above. We provide further discussion of these contracts in Notes 1 and 14 of the Notes to Consolidated Financial Statements.

SDG&E and SoCalGas: Natural Gas Revenues and Cost of Natural Gas

The following tables show natural gas revenues for SDG&E and SoCalGas. Because the cost of natural gas is recovered in rates, changes in the cost are reflected in the changes in revenues. In addition to the change in market prices, natural gas revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 1 of the Notes to Consolidated Financial Statements.

SDG&E
NATURAL GAS SALES AND TRANSPORTATION 2010-2012
(Volumes in billion cubic feet, dollars in millions)

	Natural Gas Sales			Transportation			Total
Customer class	Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
2012:
Residential	30	$	266	―	$	1	30	$	267
Commercial and industrial	15		76	8		11	23		87
Electric generation plants	―		―	37		15	37		15
	45	$	342	45	$	27	90		369
Other revenues									40
Balancing accounts									59
Total(1)								$	468
2011:
Residential	32	$	341	―	$	1	32	$	342
Commercial and industrial	15		103	8		10	23		113
Electric generation plants	―		―	25		8	25		8
	47	$	444	33	$	19	80		463
Other revenues									36
Balancing accounts									44
Total(1)								$	543
2010:
Residential	31	$	340	―	$	―	31	$	340
Commercial and industrial	14		106	8		12	22		118
Electric generation plants	―		―	28		7	28		7
	45	$	446	36	$	19	81		465
Other revenues									36
Balancing accounts									13
Total(1)								$	514
(1) Includes sales to affiliates of $2 million in 2012 and $1 million in each of 2011 and 2010.

In 2012, SDG&E’s natural gas revenues decreased by $75 million (14%) to $468 million, and the cost of natural gas decreased by $75 million (33%) to $151 million. The decrease in revenues was primarily due to:

§	the decrease in cost of natural gas sold from lower natural gas prices and volumes sold, as we discuss below; and

§	$13 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; offset by

§	$10 million increase associated with the advanced meter program.

SDG&E’s natural gas revenues increased by $29 million (6%) to $543 million in 2011 and the cost of natural gas sold increased by $9 million (4%) to $226 million. The increase in revenues was primarily due to:

§	$9 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses;

§	an increase in cost of natural gas, which was caused primarily by higher volumes sold and higher natural gas prices, as we discuss below; and

§	$8 million higher authorized base margin.

The average cost of natural gas was $3.62 per thousand cubic feet (Mcf) for 2012, $4.83 per Mcf for 2011 and $4.79 per Mcf for 2010. In 2012, the 25-percent decrease of $1.21 per Mcf resulted in lower revenues and cost of $54 million compared to 2011. The decrease in the cost of natural gas sold was also attributable to lower volumes, which resulted in lower revenues and cost of $9 million.

In 2011, the 1-percent increase of $0.04 per Mcf resulted in higher revenues and cost of $2 million compared to 2010.

SOCALGAS
NATURAL GAS SALES AND TRANSPORTATION 2010-2012
(Volumes in billion cubic feet, dollars in millions)

	Natural Gas Sales			Transportation			Total
Customer class	Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
2012:
Residential	234	$	1,963	2	$	8	236	$	1,971
Commercial and industrial	101		608	283		240	384		848
Electric generation plants	―		―	231		39	231		39
Wholesale	―		―	175		24	175		24
	335	$	2,571	691	$	311	1,026		2,882
Other revenues									91
Balancing accounts									309
Total(1)								$	3,282
2011:
Residential	253	$	2,358	1	$	4	254	$	2,362
Commercial and industrial	103		759	272		219	375		978
Electric generation plants	―		―	166		42	166		42
Wholesale	―		―	148		19	148		19
	356	$	3,117	587	$	284	943		3,401
Other revenues									99
Balancing accounts									316
Total(1)								$	3,816
2010:
Residential	245	$	2,302	1	$	4	246	$	2,306
Commercial and industrial	102		763	268		228	370		991
Electric generation plants	―		―	187		44	187		44
Wholesale	―		―	149		15	149		15
	347	$	3,065	605	$	291	952		3,356
Other revenues									92
Balancing accounts									374
Total(1)								$	3,822
(1) Includes sales to affiliates of $46 million in 2012, $53 million in 2011, and $44 million in 2010.

In 2012, SoCalGas’ natural gas revenues decreased by $534 million (14%) to $3.3 billion, and the cost of natural gas sold decreased by $494 million (32%) to $1.1 billion. The decrease in revenues was primarily due to:

§	the decrease in cost of natural gas sold from lower natural gas prices and volumes sold (as we discuss below); and

§	$51 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.

SoCalGas’ natural gas revenues in 2011 were essentially unchanged when compared to 2010 at $3.8 billion, while the cost of natural gas sold decreased by $131 million (8%) to $1.6 billion in 2011 compared to 2010. Natural gas revenues in 2011 compared to 2010 were impacted by:

§	the decrease in cost of natural gas sold, which was caused primarily by lower natural gas prices, as we discuss below, offset by higher volumes sold; and

§	$12 million lower regulatory awards in 2011; offset by

§	$96 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and

§	$54 million higher authorized base margin.

The average cost of natural gas was $3.21 per Mcf for 2012, $4.41 per Mcf for 2011, and $4.90 per Mcf for 2010. In 2012, the 27-percent decrease of $1.20 per Mcf resulted in lower revenues and cost of $402 million compared to 2011. The decrease in the cost of natural gas sold was also attributable to lower demand for natural gas from a warmer winter in 2012.

In 2011, the 10-percent decrease of $0.49 per Mcf resulted in lower revenues and cost of $175 million compared to 2010.

Other Utilities: Revenues and Cost of Sales

Revenues generated by Chilquinta Energía and Luz del Sur are based on tariffs that are set by government agencies in their respective countries based on an efficient model distribution company defined by those agencies. The basis for the tariffs do not meet the requirement necessary for treatment under applicable U.S. GAAP for regulatory accounting. We discuss revenue recognition further for Chilquinta Energía and Luz del Sur in Note 1 of the Notes to Consolidated Financial Statements.

Operations of Mobile Gas, Willmut Gas and Ecogas qualify for regulatory accounting treatment under applicable U.S. GAAP, similar to the California Utilities.

The table below summarizes natural gas and electric revenue for our utilities outside of California:

OTHER UTILITIES
NATURAL GAS AND ELECTRIC REVENUES 2010-2012
(Dollars in millions)
		2012			2011			2010
		Volumes	Revenue		Volumes	Revenue		Volumes	Revenue
Natural Gas Sales (billion cubic feet):
Sempra Mexico - Ecogas		23	$	75	22	$	91	21	$	94
Sempra Natural Gas:
Mobile Gas		43		86	40		93	37		106
Willmut Gas(1)		15		10	―		―	―		―
Total		81	$	171	62	$	184	58	$	200

Electric Sales (million kilowatt hours)(2):
Sempra South American Utilities:
Luz del Sur		6,668	$	759	4,715	$	487	―	$	―
Chilquinta Energía		2,698		533	1,859		481	―		―
		9,366		1,292	6,574		968	―		―
Other service revenues				57			41			―
Total			$	1,349		$	1,009		$	―
(1)	We acquired Willmut Gas in May 2012.
(2)	We accounted for Luz del Sur and Chilquinta Energía under the equity method until April 6, 2011, when they became consolidated entities upon our acquisition of additional ownership interests.

Energy-Related Businesses: Revenues and Cost of Sales

The table below shows revenues and cost of sales for our energy-related businesses.

ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES 2010-2012
(Dollars in millions)
		Years ended December 31,
		2012				2011				2010
REVENUES
Sempra South American Utilities		$	92	8	%	$	71	4	%	$	1	―	%
Sempra Mexico			530	44			645	38			733	37
Sempra Renewables			68	6			22	1			9	―
Sempra Natural Gas			835	69			1,539	90			1,903	96
Intersegment revenues, adjustments
and eliminations(1)			(319)	(27)			(563)	(33)			(662)	(33)
Total revenues		$	1,206	100	%	$	1,714	100	%	$	1,984	100	%
COST OF SALES(2)
Sempra Mexico		$	197	41	%	$	276	37	%	$	399	38	%
Sempra Renewables			3	―			―	―			―	―
Sempra Natural Gas			581	121			1,034	139			1,308	125
Adjustments and eliminations(1)			(300)	(62)			(564)	(76)			(661)	(63)
Total cost of natural gas, electric fuel
and purchased power		$	481	100	%	$	746	100	%	$	1,046	100	%

Sempra South American Utilities		$	66	41	%	$	45	33	%	$	―	―	%
Sempra Mexico			21	13			4	3			3	3
Sempra Natural Gas			90	57			89	65			86	98
Adjustments and eliminations(1)			(18)	(11)			(1)	(1)			(1)	(1)
Total other cost of sales		$	159	100	%	$	137	100	%	$	88	100	%
(1)	Includes eliminations of intercompany activity.
(2)	Excludes depreciation and amortization, which are shown separately on the Consolidated Statements of Operations.

In 2012, revenues from our energy-related businesses decreased by $508 million (30%) to $1.2 billion. The decrease included

$704 million decrease at Sempra Natural Gas due to decreased power sales in 2012 compared to 2011 primarily from the end of the DWR contract in September 2011, lower natural gas revenues from its LNG operations as a result of lower natural gas prices and volumes, and lower revenues due to power sales associated with the EMA with Sempra Mexico, which we discuss above in “Sempra Mexico – Power Business;” and

$115 million decrease in 2012 compared to 2011 at Sempra Mexico primarily due to the expiration of the DWR contract, which resulted in a change in the intercompany agreement with Sempra Natural Gas effective January 1, 2012, and from lower natural gas prices at its LNG operations, partially offset by an increase in revenues due to an outage at the Mexicali power plant in 2011; offset by

§	$244 million lower intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas; and

§	$46 million increase at Sempra Renewables mainly from revenues generated by our solar and wind assets.

The cost of natural gas, electric fuel and purchased power for our energy-related businesses in 2012 compared to 2011 decreased by $265 million (36%) to $481 million. The decrease was primarily due to:

§	$453 million decrease at Sempra Natural Gas primarily associated with lower natural gas prices and lower power costs associated with the EMA with Sempra Mexico, which we discuss above in “Sempra Mexico – Power Business;” and

§	$79 million decrease at Sempra Mexico primarily due to lower natural gas prices; offset by

§	$264 million lower intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas.

Revenues from our energy-related businesses decreased by $270 million (14%) to $1.7 billion in 2011 compared to 2010. The decrease included

§	$364 million at Sempra Natural Gas primarily due to decreased power sales primarily from the end of the DWR contract as of September 30, 2011, and less favorable pricing. The decrease was also due to lower natural gas revenues from its LNG operations; and

§	$88 million at Sempra Mexico primarily due to lower volumes of natural gas sold, partially offset by increased revenues from gas power plant operations; offset by

§	$70 million increase at Sempra South American Utilities primarily from its consolidation of revenues of Tecnored and Tecsur, two energy-services companies we acquired in April 2011; and

§	$99 million decreased intercompany activity, which is eliminated in consolidation.

The cost of natural gas, electric fuel and purchased power from our energy-related businesses decreased by $300 million (29%) to $746 million in 2011 compared to 2010. The decrease was primarily driven by the lower revenues at Sempra Natural Gas and Sempra Mexico, offset by decreased intercompany activity.

In 2012, other cost of sales from our energy-related businesses increased by $22 million (16%) to $159 million primarily due to twelve months of cost of sales in 2012 for Tecnored and Tecsur compared to only nine months in 2011. We started consolidating Tecnored and Tecsur in April 2011.

In 2011 compared to 2010, other cost of sales for our energy-related businesses increased by $49 million (56%) to $137 million primarily due to $45 million from the consolidation of Tecnored and Tecsur.

Operation and Maintenance (including Litigation Expense)

In the table below, we provide a breakdown of our operation and maintenance expenses by segment.

OPERATION AND MAINTENANCE(1) 2010-2012
(Dollars in millions)
		Years ended December 31,
		2012				2011				2010
California Utilities:
SDG&E		$	1,154	39	%	$	1,072	38	%	$	987	37	%
SoCalGas			1,304	44			1,305	46			1,174	44
Sempra International:
Sempra South American Utilities			177	6			132	5			7	―
Sempra Mexico			94	3			98	3			110	4
Sempra U.S. Gas & Power:
Sempra Renewables			27	1			17	1			16	1
Sempra Natural Gas			168	6			169	6			320	12
Parent and other(2)			25	1			32	1			54	2
Total operation and maintenance		$	2,949	100	%	$	2,825	100	%	$	2,668	100	%
(1)	Includes Litigation Expense and Other Operation and Maintenance for Sempra Energy Consolidated.
(2)	Includes intercompany eliminations recorded in consolidation.

Sempra Energy Consolidated

In 2012, our operation and maintenance expenses increased by $124 million (4%) to $2.9 billion. The increase included

§	$82 million increase at SDG&E, which we discuss below;

§	$45 million increase at Sempra South American Utilities primarily from the consolidation of expenses in Chile and Peru for a full year; and

§	$10 million higher costs at Sempra Renewables primarily due to growth in the business.

Our other operation and maintenance expenses increased by $157 million (6%) to $2.8 billion in 2011 compared to 2010 primarily due to:

§	higher operation and maintenance expenses at the California Utilities, as we discuss below; and

§	$125 million increase at Sempra South American Utilities, including $106 million from the consolidation of expenses of entities in Chile and Peru in 2011; offset by

§	$151 million decrease at Sempra Natural Gas, including $145 million litigation expense in 2010 related to an agreement to settle certain energy crisis litigation, major scheduled plant maintenance in 2010 at the Mesquite power plant, and from the sale of El Dorado as of October 1, 2011; and

$22 million decrease at Parent and Other, which included $9 million litigation expense in 2010 related to an agreement to settle certain energy crisis litigation and lower expenses associated with our former commodities-marketing businesses, including transaction costs in 2010 related to the sales within RBS Sempra Commodities.

SDG&E

In 2012, SDG&E’s operation and maintenance expenses increased by $82 million (8%) to $1.2 billion. The increase was primarily due to:

§	$56 million higher other operation and maintenance costs, including:

o	$14 million associated with the Desert Star generation facility acquired by SDG&E in October 2011 and from increased costs from the operations of other electric generating facilities,

o	$12 million of advanced meter program costs, and

o	$9 million increase in liability insurance premiums for wildfire coverage, offset by

o	$10 million recovery in 2012 of incremental costs incurred in prior years for the long-term storage of spent nuclear fuel; and

§	$29 million higher recoverable expenses primarily due to an increase in electric transmission-related operating expenses.

SDG&E’s operation and maintenance expenses increased by $85 million (9%) to $1.1 billion in 2011 compared to 2010 primarily due to:

§	$46 million higher other operational and maintenance costs, including a $15 million increase in liability insurance premiums for wildfire coverage; and

§	$38 million higher recoverable expenses, primarily from expenses associated with customer distributed generation incentive programs and transmission expenses.

SoCalGas

SoCalGas’ operation and maintenance expenses decreased by $1 million to $1.3 billion in 2012 primarily due to:

§	$51 million lower recoverable expenses, primarily from reduced funding requirements for employee benefit programs; offset by

§	$49 million higher other operational and maintenance costs, including expenses related to the TIMP, with no corresponding increase in CPUC-authorized margin in 2012 due to the delay in the 2012 GRC decision.

SoCalGas’ operation and maintenance expenses increased by $131 million (11%) to $1.3 billion in 2011 compared to 2010 primarily due to:

§	$96 million higher recoverable expenses, primarily from expenses associated with energy efficiency and funding of employee benefit programs;

§	$20 million higher other operational and maintenance costs; and

§	$5 million litigation expense in 2011 compared to a $10 million favorable impact from the resolution of a litigation matter in 2010.

Depreciation and Amortization

Sempra Energy Consolidated

Our depreciation and amortization expense was

§	$1,090 million in 2012

§	$976 million in 2011

§	$866 million in 2010

The increase in 2012 included

§	$68 million at SDG&E, primarily from higher electric plant depreciation;

§	$31 million at SoCalGas from an increase in net utility plant base;

§	$16 million from the consolidation of entities in Chile and Peru for a full year; and

§	$10 million at Sempra Renewables mainly due to Mesquite Solar 1 going into service starting in December 2011; offset by

§	$10 million decrease at Sempra Natural Gas primarily due to the sale of El Dorado in 2011.

The increase in 2011 included

§	$41 million at SDG&E, primarily from higher electric plant depreciation;

§	$40 million from the consolidation of entities in Chile and Peru in April 2011; and

§	$22 million at SoCalGas from an increase in net utility plant base.

Equity Earnings (Losses), Before Income Tax

Sempra Energy Consolidated

Losses from our investment in RBS Sempra Commodities, which was formed in 2008, were

§	$0 million in 2012

§	$24 million in 2011

§	$314 million in 2010

We and RBS, our partner in the joint venture, sold substantially all of the partnership’s businesses and assets in four separate transactions completed in July, November and December of 2010 and February of 2011. Results for 2011 include a $16 million write-down of and $8 million equity loss from our investment in RBS Sempra Commodities.

Equity earnings from our investment in RBS Sempra Commodities were adversely impacted by several factors in 2010, as we discuss in “Segment Results—Parent and Other.” Results for 2010 include a $305 million write-down of our investment in RBS Sempra Commodities. This amount includes a $480 million loss related to the U.S. portion of our investment, partially offset by a $175 million gain on the non-U.S. portion. We discuss the write-down and additional information about the determination and allocation of this investment’s earnings in Note 4 of the Notes to Consolidated Financial Statements.

Equity (losses) earnings from our investment in Rockies Express were $(312) million in 2012, $43 million in 2011 and $43 million in 2010. Equity losses in 2012 included a write-down of our investment in Rockies Express of $400 million, offset by a $41 million make-whole income tax provision payment received from our previous joint venture partner, Kinder Morgan.

Equity losses, before income tax, from our other equity method investments were

§	$7 million in 2012

§	$10 million in 2011

§	$21 million in 2010

The decrease in equity losses, before income tax, in 2011 compared to 2010 was primarily due to:

§	$13 million of losses in 2010 from Sempra Natural Gas’ investment in Elk Hills, including a $10 million loss on the sale of the investment in December 2010; and

§	$5 million decreased losses from other investments at Parent and Other; offset by

§	$6 million of equity losses in 2011 from energy projects at Sempra Renewables compared to $1 million of equity earnings in 2010.

We provide further details about our investment in RBS Sempra Commodities, the impairment of our Rockies Express investment and other equity method investments in Note 4 of the Notes to Consolidated Financial Statements.

Remeasurement of Equity Method Investments

In the second quarter of 2011, we recorded a $277 million non-taxable gain from the remeasurement of our equity method investments in Chilquinta Energía in Chile and Luz del Sur in Peru. We provide additional discussion related to this gain below in “Income Taxes” and in Note 3 of the Notes to Consolidated Financial Statements.

Other Income, Net

Sempra Energy Consolidated

Other income, net, was

§	$172 million in 2012

§	$130 million in 2011

§	$140 million in 2010

We include here equity-related AFUDC at the California Utilities, interest on regulatory balancing accounts, gains and losses from our investments and interest rate swaps, and other sundry amounts.

In 2012, other income, net, increased by $42 million (32%) primarily due to:

§	$10 million gains on interest rate and foreign exchange instruments in 2012 compared to $14 million losses in 2011; and

§	$19 million higher gains from investment activity related to our executive retirement and deferred compensation plans in 2012.

Other income, net, decreased by $10 million (7%) in 2011 compared to 2010 primarily due to:

§	proceeds of $48 million from a legal settlement at Sempra South American Utilities in 2010; offset by

§	$37 million increase in equity-related AFUDC in 2011 attributable to SDG&E primarily associated with the construction of the Sunrise Powerlink electric transmission line; and

$10 million lower losses on interest rate and foreign exchange instruments, including $34 million of losses on interest rate instruments in 2010 related to Otay Mesa VIE (discussed below), offset by a $15 million Mexican peso exchange loss in 2011 (discussed in “Income Taxes – Mexican Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity” below) and a $10 million gain recognized on an interest rate instrument in 2010 at Parent and Other.

SDG&E

Other income, net, was

§	$69 million in 2012

§	$79 million in 2011

§	$10 million in 2010

Other income, net, decreased by $10 million (13%) in 2012 primarily due to lower AFUDC as a result of completion of construction on the Sunrise Powerlink project in June 2012.

In 2011, other income, net, increased by $69 million as compared to 2010 primarily due to:

§	$37 million increase in AFUDC primarily due to construction on the Sunrise Powerlink project; and

§	$34 million of losses on interest rate instruments at Otay Mesa VIE in 2010. Otay Mesa VIE’s interest rate instrument’s activity was designated as a cash flow hedge as of April 1, 2011.

We provide further details of the components of other income, net, in Note 1 of the Notes to Consolidated Financial Statements.

Interest Expense

The table below shows the interest expense for Sempra Energy Consolidated, SDG&E and SoCalGas.

INTEREST EXPENSE 2010-2012
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
Sempra Energy Consolidated	$	493	$	465	$	436
SDG&E		173		142		136
SoCalGas		68		69		66

Sempra Energy Consolidated

In 2012, our interest expense increased by $28 million (6%) primarily due to:

§	$31 million higher interest expense at SDG&E, which we discuss below; and

§	$19 million higher long-term debt interest expense at Parent and Other from debt issuances in 2012; offset by

§	$24 million higher capitalized interest associated with energy projects at Sempra Renewables.

In 2011 compared to 2010, our interest expense increased by $29 million (7%) primarily due to:

§	$26 million at Sempra South American Utilities, primarily from the consolidation of Chile and Peru in April 2011;

§	$15 million lower capitalized interest at Sempra Natural Gas in 2011 primarily due to natural gas storage caverns at Bay Gas Storage Company, Ltd. (Bay Gas) and Mississippi Hub, LLC (Mississippi Hub) going into service; and

§	$6 million at SDG&E, which we discuss below; offset by

§	$6 million lower interest expense related to energy crisis litigation reserves at Parent and Other; and

§	$4 million higher capitalized interest associated with energy projects at Sempra Renewables.

SDG&E

In 2012, SDG&E’s interest expense increased by $31 million (22%) primarily due to issuances of long-term debt in the second half of 2011 and in March 2012, and the decrease in AFUDC debt in 2012 due to the completion of construction of Sunrise Powerlink.

Interest expense for SDG&E increased by $6 million (4%) in 2011 primarily due to issuances of long-term debt in 2011 and 2010, partially offset by higher AFUDC related to debt.

Income Taxes

The table below shows the income tax expense and effective income tax rates for Sempra Energy, SDG&E and SoCalGas.

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES 2010-2012
(Dollars in millions)
		Years ended December 31,
		2012				2011				2010
		Income Tax	Effective Income			Income Tax	Effective Income			Income Tax	Effective Income
		Expense	Tax Rate			Expense	Tax Rate			Expense	Tax Rate
Sempra Energy Consolidated	$	59	6	%	$	394	23	%	$	133	17	%
SDG&E		190	27			237	34			173	33
SoCalGas		79	21			143	33			176	38

Sempra Energy Consolidated

Sempra Energy’s income tax expense in 2012 decreased due to significantly lower pretax income (due to the write-down of our investment in Rockies Express in 2012) and a lower effective income tax rate. The lower effective income tax rate was primarily due to:

a change in the income tax treatment of certain repairs expenditures at SDG&E and SoCalGas that are capitalized for financial statement purposes, which resulted in a $70 million higher income tax benefit compared to 2011, including a $22 million income tax benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012. This higher income tax benefit reflects the offsetting impact of lower income tax depreciation and unrecognized income tax benefits. The change in income tax treatment of certain repairs expenditures for electric transmission and distribution assets was made pursuant to an Internal Revenue Service (IRS) Revenue Procedure providing a safe harbor for deducting certain repairs expenditures from taxable income when incurred for tax years beginning on or after January 1, 2011. The change in income tax treatment of certain repairs expenditures for gas plant assets was made pursuant to an IRS Revenue Procedure which allows, under an Internal Revenue Code (IRC) section, for such expenditures to be deducted from taxable income when incurred;

a $62 million income tax benefit for life insurance contracts, of which $54 million is primarily associated with our decision in the second quarter of 2012 to hold life insurance contracts kept in support of certain benefit plans to term. Previously, we took the position that we might cash in or sell these contracts before maturity, which required that we record deferred income taxes on unrealized gains on investments held within the insurance contracts;

§	higher renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; and

§	higher deductions for self-developed software expenditures; offset by

§	the impact of the $277 million remeasurement gain (non-U.S. earnings) in 2011 related to our acquisition of controlling interests in Chilquinta Energía and Luz del Sur, which was non-taxable;

§	higher book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and

§	higher income tax expense due to Mexican currency translation and inflation adjustments.

Sempra Energy’s income tax expense increased in 2011 compared to 2010 due to both higher pretax income and a higher effective income tax rate. Nonrecurring events in both 2011 and 2010, related to our acquisitions in South America and the sale transactions within RBS Sempra Commodities, respectively, significantly impacted both the pretax income and the effective rate in both years. The higher rate in 2011 compared to 2010, including these impacts and others, was primarily due to:

§	a lower percentage of pretax income in 2011 compared to 2010 in countries with lower statutory rates. The activity in each year related primarily to:

§	in 2011, a $277 million non-taxable gain related to the remeasurement of our equity method investments in South America, as we discuss in Note 3 of the Notes to Consolidated Financial Statements

§	in 2010, activity related to RBS Sempra Commodities, including a large non-taxable gain related to our share of the RBS Sempra Commodities sale to J.P. Morgan Ventures, as we discuss below;

§	a lower favorable impact of renewable energy income tax credits and deferred income tax benefits related to renewable energy projects in 2011 compared to 2010;

§	higher income tax benefit in 2010 due to favorable adjustments to prior years’ income tax items;

§	higher state income taxes; and

§	lower favorable impact from deductions for self-developed software expenditures at the California Utilities; offset by

§	income tax benefit in 2011 versus income tax expense in 2010 due to Mexican currency translation and inflation adjustments;

§	lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets;

§	a $16 million write-down in 2010 of the deferred income tax assets related to other postretirement benefits, as a result of a change in U.S. tax law that eliminates a future deduction, starting in 2013, for retiree healthcare funded by the Medicare Part D subsidy; and

§	the impact of Otay Mesa VIE, as we discuss below.

As noted above, the effective income tax rate in 2010 was low primarily due to the following related to RBS Sempra Commodities:

§	approximately $150 million of a total $175 million non-U.S. gain on sale of the businesses and assets within the joint venture was non-taxable; and

§	approximately $40 million non-U.S. earnings from the operations of the joint venture and approximately $25 million of the non-U.S. gain on sale of the businesses and assets within the joint venture were net of income tax paid by the partnership.

We use the deferral method of accounting for investment tax credits (ITC). For certain solar and wind generating assets being placed into service during 2011 and 2012, we have elected to seek cash grants rather than ITC for which the projects also qualify. Accordingly, cash grant accounting is required to be applied. Grant accounting for cash grants is very similar to the deferral method of accounting for ITC, the primary difference being the recording of a cash grant receivable instead of an income tax receivable. We discuss our accounting for ITC and cash grants further in Note 7 of the Notes to Consolidated Financial Statements.

The results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is consolidated, and therefore, Sempra Energy Consolidated’s and SDG&E’s effective income tax rates are impacted by the VIE’s stand-alone effective income tax rate, as we discuss in Note 1 of the Notes to Consolidated Financial Statements. For 2012, 2011 and 2010, the impacts on the Sempra Energy Consolidated and SDG&E effective income tax rates shown above were not material.

We report as part of our pretax results the income or loss attributable to noncontrolling interests. However, we do not record income taxes for a portion of this income or loss, as some of our entities with noncontrolling interests are currently treated as partnerships for income tax purposes and thus we are only liable for income taxes on the portion of the earnings that are allocated to us. As our entities with noncontrolling interests grow, and as we may continue to invest in such entities, the impact on our effective income tax rate may become more significant.

In 2013, we anticipate that Sempra Energy Consolidated’s effective income tax rate will be approximately 33% compared to 6% in 2012. This increase is primarily due to a forecasted increase in pretax book income and because we are not currently anticipating any similar one-time events as incurred in 2012. In addition, we are forecasting a lower favorable impact of renewable energy income tax credits and deferred income tax benefits related to renewable energy projects, and a lower favorable impact of self-developed software expenditures and repairs expenditures that are capitalized for financial statement purposes.

In the years 2014 through 2017, we anticipate that Sempra Energy Consolidated’s effective income tax rate will range from 28% to 32% primarily due to a forecasted increase in pretax book income, a lower favorable impact of renewable energy income tax credits and deferred income tax benefits related to renewable energy projects, and a lower favorable impact of self-developed software expenditures and repairs expenditures that are capitalized for financial statement purposes.

SDG&E

SDG&E’s income tax expense decreased in 2012 compared to 2011 primarily due to a lower effective income tax rate. The lower effective income tax rate was primarily due to a change in the income tax treatment of certain repairs expenditures that are capitalized for financial statement purposes, which resulted in a $36 million higher income tax benefit compared to 2011, including a $22 million income tax benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012. This higher income tax benefit reflects the offsetting impact of lower income tax depreciation. The change in income tax treatment of certain repairs expenditures for electric transmission and distribution assets was made pursuant to an IRS Revenue Procedure providing a safe harbor for deducting certain repairs expenditures from taxable income when incurred for tax years beginning on or after January 1, 2011.

SDG&E’s income tax expense increased in 2011 compared to 2010 due to higher pretax book income and a higher effective tax rate. The higher effective tax rate was primarily due to:

§	income tax benefit in 2010 due to favorable adjustments to prior years’ income tax items; offset by

§	higher exclusions from taxable income of the equity portion of AFUDC;

§	the impact of Otay Mesa VIE, as we discuss above;

§	higher deductions for self-developed software expenditures;

§	lower impact from higher book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and

§	a $3 million write-down in 2010 of the deferred income tax assets related to other postretirement benefits as a result of a change in U.S. tax law, as we discuss above.

In 2013, we anticipate that SDG&E’s effective income tax rate will be approximately 35% compared to 27% in 2012. This increase is primarily due to a forecasted increase in pretax book income, higher book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets, a lower favorable impact of self-developed software expenditures and a lower favorable impact of repairs expenditures due to recognizing in 2012 a $22 million income tax benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012.

In the years 2014 through 2017, we anticipate that SDG&E’s effective income tax rate will range from 34% to 35% primarily due to an increase in forecasted production tax credits from wind energy projects, partially offset by forecasted increases in pretax book income and a lower favorable impact of self-developed software expenditures.

SoCalGas

SoCalGas’ income tax expense decreased in 2012 due to lower pretax book income and a lower effective tax rate. The lower rate in 2012 compared to 2011 was primarily due to:

a change in the income tax treatment of certain repairs expenditures that are capitalized for financial statement purposes, which resulted in a $34 million higher income tax benefit compared to 2011. This higher income tax benefit reflects the offsetting impact of lower income tax depreciation and unrecognized income tax benefits. The change in income tax treatment of certain repairs expenditures for gas plant assets was made pursuant to an IRS Revenue Procedure which allows, under an IRC section, for such expenditures to be deducted from taxable income when incurred; and

§	higher deductions for self-developed software expenditures; offset by

§	higher book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets.

SoCalGas’ income tax expense decreased in 2011 due to lower pretax book income and a lower effective tax rate. The lower rate in 2011 compared to 2010 was primarily due to:

§	a $13 million write-down in 2010 of the deferred income tax assets related to other postretirement benefits as a result of a change in U.S. tax law, as we discuss above;

§	higher deductions for self-developed software expenditures; and

§	higher exclusions from taxable income of the equity portion of AFUDC; offset by

§	higher book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets.

In 2013, we anticipate that SoCalGas’ effective income tax rate will be approximately 33% compared to 21% in 2012. This increase is primarily due to a forecasted increase in pretax book income, higher book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets, and a lower favorable impact of self-developed software expenditures and repairs expenditures that are capitalized for financial statement purposes.

In the years 2014 through 2017, we anticipate that SoCalGas’ effective income tax rate will range from approximately 31% to 40%, primarily due to forecasted increases in pretax book income, higher book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets, and a lower favorable impact of self-developed software expenditures and repairs expenditures that are capitalized for financial statement purposes.

In general, the following items are subject to flow-through treatment at the California Utilities:

§	repairs expenditures related to a certain portion of utility plant fixed assets

§	the equity portion of AFUDC

§	a portion of the cost of removal of utility plant assets

§	self-developed software expenditures

§	depreciation on a certain portion of utility plant fixed assets

We discuss the impact of items subject to flow-through treatment on our effective income tax rates in Note 7 of the Notes to Consolidated Financial Statements.

In January 2013, the American Taxpayer Relief Act of 2012 (2012 Tax Act) was signed into law. The 2012 Tax Act included retroactive extensions from January 1, 2012 through December 31, 2013 of certain business income tax provisions that had expired at the end of 2011, including the look-through rule. The look-through rule allows, under certain situations, for certain non-operating income (e.g., dividend income, royalty income, interest income, rental income, etc.), of a greater than 50-percent owned non-U.S. subsidiary, to not be taxed under U.S. federal income tax law. The retroactive application of the look-through rule to 2012 would result in a $6 million income tax benefit. However, as the 2012 Tax Act was not signed into law as of December 31, 2012, the extension of the look-through rule will be treated as a 2013 event, and the related income tax benefit for 2012 will be recorded in the first quarter of 2013. The 2012 Tax Act also extended the 50 percent bonus depreciation for qualified property placed in service before January 1, 2014, the impact of which is discussed below.

In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act) was signed into law. The 2010 Tax Act included the extension of bonus depreciation for U.S. federal income tax purposes for years 2010 through 2012 and an increase in the rate of bonus depreciation from 50 percent to 100 percent. This increased rate only applies to certain investments made after September 8, 2010 through December 31, 2012. Self-constructed property, where the construction period exceeds one year, construction started between December 31, 2007 and January 1, 2013, and the property is placed in service by December 31, 2013, will qualify for bonus depreciation in 2013 at either the original or increased rate.

Due to the extension of bonus depreciation, Sempra Energy generated a large U.S. federal net operating loss (NOL) in 2011 and 2012. We currently project that the total NOL will not be fully utilized until approximately 2017. Because of the carryforward of NOL and U.S. federal income tax credits discussed below, Sempra Energy expects no U.S. federal income tax payments in years 2013 through 2016. Because bonus depreciation only creates a temporary difference between Sempra Energy’s U.S. federal income tax return and its U.S. GAAP financial statements, it does not impact Sempra Energy’s effective income tax rate. We expect larger U.S. federal income tax payments in the future as these temporary differences reverse.

SDG&E and SoCalGas both generated a large U.S. federal NOL in 2011 primarily due to bonus depreciation. In 2012, SoCalGas was able to, on a stand-alone basis, carry back its 2011 NOL to 2009 to offset taxable income in that year. In 2012, SDG&E was able to, on a stand-alone basis, carry back a majority of its 2011 NOL to 2009 and 2010 to offset taxable income in those years. The remaining portion of SDG&E’s 2011 NOL is recorded as a current deferred income tax asset.

SDG&E and SoCalGas both generated a large U.S. federal NOL in 2012. SDG&E’s 2012 NOL will be carried forward, and is therefore recorded as a deferred income tax asset. We currently project that SDG&E’s NOL carryforward, on a stand-alone basis, will be fully utilized by 2015. Because of the carryforward of NOL and U.S. federal income tax credits discussed below, SDG&E expects no U.S. federal income tax payments in 2013 and 2014. SoCalGas’ 2012 NOL remaining after carry back will be carried forward, and is therefore recorded as a deferred income tax asset. We currently project that SoCalGas’ NOL carryforward, on a stand-alone basis, will be fully utilized by 2013. Because bonus depreciation only creates a temporary difference between SDG&E’s and SoCalGas’ U.S. federal income tax returns and U.S. GAAP financial statements, it does not impact SDG&E’s and SoCalGas’ effective income tax rates. We expect larger U.S. federal income tax payments in the future as these temporary differences reverse.

Bonus depreciation, in addition to impacting Sempra Energy’s and SDG&E’s U.S. federal income tax payments, will also have a temporary impact on Sempra Energy’s and SDG&E’s ability to utilize their U.S. federal income tax credits, which primarily are investment tax credits and production tax credits generated by Sempra Energy’s and SDG&E’s current and future renewable energy investments. However, based on current projections, Sempra Energy and SDG&E do not expect, based on more-likely-than-not criteria required under U.S. GAAP, any of these income tax credits to expire prior to the end of their 20-year carryforward period, as allowed under current U.S. federal income tax law. We also expect bonus depreciation to increase the deferred income tax liability component of SDG&E’s and SoCalGas’ rate base, which reduces rate base.

We are planning to repatriate a portion of future earnings beginning in 2013 from certain of our non-U.S. subsidiaries in Mexico and Peru. However, we expect to continue to indefinitely reinvest future earnings from our Chilean subsidiaries. Currently, all future repatriated earnings would be subject to U.S. income tax (with a credit for foreign income taxes) and future repatriations from Peru would be subject to local country withholding tax. Because this potential repatriation would only be from future earnings, it does not change our current assertion, as we discuss in Note 7 of the Notes to Consolidated Financial Statements, that we intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings as of December 31, 2012.

Mexican Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity

Our Mexican subsidiaries have U.S. dollar denominated receivables and payables (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities that are denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes.

The fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar, with regard to Mexican monetary assets and liabilities, and Mexican inflation are subject to Mexican income tax and thus may expose us to fluctuations in our income tax expense. The income tax expense of Sempra Mexico is impacted by these factors.

For Sempra Energy Consolidated, the impacts in 2010-2012 related to the factors described above are as follows:

MEXICAN CURRENCY IMPACT ON INCOME TAXES AND RELATED ECONOMIC HEDGING ACTIVITY
(Dollars in millions)
		Years ended December 31,
		2012		2011		2010
Income tax (expense) benefit on currency exchange
	rate movement of monetary assets and liabilities	$	(6)	$	11	$	(10)
Translation of non-U.S. deferred income tax balances			(2)		11		(2)
Income tax expense on inflation			(2)		(4)		(7)
	Total impact on income taxes		(10)		18		(19)
After-tax gains (losses) on Mexican peso exchange rate
	instruments (included in Other Income, Net)		6		(9)		―
Net impacts on Sempra Energy Consolidated
	Statements of Operations	$	(4)	$	9	$	(19)

Equity Earnings, Net of Income Tax

Sempra Energy Consolidated

Equity earnings of unconsolidated subsidiaries, net of income tax, which are primarily earnings from Sempra South American Utilities’ and Sempra Mexico’s equity method investments, were

§	$36 million in 2012

§	$52 million in 2011

§	$49 million in 2010

The decrease in 2012 was primarily due to:

§	$24 million earnings in 2011 related to equity method investments in Chile and Peru, for entities that we have consolidated since April 2011; offset by

§	$7 million higher earnings from Sempra Mexico’s joint-venture interest in pipeline assets.

The increase in 2011 compared to 2010 was primarily due to:

§	a $44 million pretax write-down of Sempra South American Utilities’ investment in Argentina in 2010; and

§	$10 million higher earnings at Sempra Mexico from the joint-venture interest in pipeline assets acquired in April 2010; offset by

§	$50 million lower earnings related to equity method investments in Chile and Peru, for entities that are now consolidated.

(Earnings) Losses Attributable to Noncontrolling Interests

Sempra Energy Consolidated

Earnings attributable to noncontrolling interests increased by $13 million in 2012 primarily due to:

§	$7 million higher earnings attributable to noncontrolling interest at Otay Mesa VIE, which we discuss below; and

§	$5 million higher earnings at Sempra South American Utilities primarily from noncontrolling interests at Luz del Sur.

Earnings attributable to noncontrolling interests were $42 million in 2011 compared to losses of $16 million in 2010. The change was primarily due to:

§	$19 million earnings attributable to noncontrolling interest in 2011 compared to losses of $16 million in 2010 at Otay Mesa VIE, which we discuss below; and

§	$22 million earnings primarily from noncontrolling interests at Luz del Sur in 2011.

SDG&E

In 2012, earnings attributable to noncontrolling interest at Otay Mesa VIE increased by $7 million due to higher operating income.

Earnings attributable to noncontrolling interest, all related to Otay Mesa VIE, were $19 million in 2011 compared to losses of $16 million in 2010. The change was primarily due to $34 million of losses on interest rate instruments in 2010.

Earnings

We summarize variations in overall earnings in “Overall Results of Operations of Sempra Energy and Factors Affecting the Results” above. We discuss variations in earnings (losses) by segment above in “Segment Results.”

TRANSACTIONS WITH AFFILIATES

We provide information about our related party transactions in Note 1 of the Notes to Consolidated Financial Statements.

BOOK VALUE PER SHARE

Sempra Energy’s book value per share on the last day of each year was

§	$42.43 in 2012

§	$40.74 in 2011

§	$37.39 in 2010

The increases in 2012 and 2011 were primarily the result of comprehensive income exceeding dividends.

CAPITAL RESOURCES AND LIQUIDITY

OVERVIEW

We expect our cash flows from operations to fund a substantial portion of our capital expenditures and dividends. In addition, we may meet our cash requirements through the issuance of short-term and long-term debt and distributions from our equity method investments.

Significant events in 2012 affecting capital resources, liquidity and cash flows were

§	long-term debt issuances of $1.7 billion, including $350 million at SoCalGas and $250 million at SDG&E

§	$1.1 billion of debt retirements and paydowns, including $250 million at SoCalGas

§	$3.0 billion in expenditures for property, plant and equipment, including $1.2 billion at SDG&E and $639 million at SoCalGas

§	$445 million in expenditures for investments, primarily related to $372 million of projects at Sempra Renewables

We discuss these events in more detail later in this section.

Our committed lines of credit provide liquidity and support commercial paper. As we discuss in Note 5 of the Notes to Consolidated Financial Statements, in March 2012, Sempra Energy, Sempra Global (the holding company for our subsidiaries not subject to California utility regulation) and the California Utilities each entered into new five-year revolving credit facilities, expiring in 2017, which replaced the previous principal credit agreements that were scheduled to expire in 2014. At Sempra Energy and the California Utilities, the agreements are syndicated broadly among 24 different lenders and at Sempra Global, among 25 different lenders. No single lender has greater than a 7-percent share in any agreement.

The table below shows the amount of available funds at year-end 2012:

AVAILABLE FUNDS AT DECEMBER 31, 2012
(Dollars in millions)
		Sempra Energy
		Consolidated		SDG&E		SoCalGas
Unrestricted cash and cash equivalents		$	475	$	87	$	83
Available unused credit(1)			3,254		658		658
(1)	Borrowings on the shared line of credit at SDG&E and SoCalGas, discussed in Note 5 of the Notes to Consolidated Financial Statements, are limited to $658 million for each utility and a combined total of $877 million.

Sempra Energy Consolidated

We believe that these available funds and cash flows from operations, distributions from equity method investments and security issuances, combined with current cash balances, will be adequate to fund our anticipated operations, including to:

§	finance capital expenditures

§	meet liquidity requirements

§	fund shareholder dividends

§	fund new business acquisitions or start-ups

§	repay maturing long-term debt

In September 2012, Sempra Energy publicly offered and sold $500 million of 2.875-percent notes maturing in 2022, and SoCalGas publicly offered and sold $350 million of 3.75-percent first mortgage bonds maturing in 2042. In March 2012, Sempra Energy publicly offered and sold $600 million of 2.30-percent notes maturing in 2017, and SDG&E publicly offered and sold $250 million of 4.30-percent first mortgage bonds maturing in 2042. Sempra Energy and SDG&E issued long-term debt in 2011 in the aggregate principal amounts of $800 million and $600 million, respectively. Changing economic conditions could affect the availability and cost of both short-term and long-term financing. If cash flows from operations were to be significantly reduced or we were unable to borrow under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety) and investments in new businesses. If these measures were necessary, they would primarily impact certain of our Sempra International and Sempra U.S. Gas & Power businesses before we would reduce funds necessary for the ongoing needs of our utilities. We continuously monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our intention to maintain strong, investment-grade credit ratings and capital structure.

In three separate transactions during 2010 and one in early 2011, we and RBS sold substantially all of the businesses and assets of our joint-venture partnership that comprised our commodities-marketing businesses. Distributions from the partnership in 2011 were $623 million. The investment balance of $126 million at December 31, 2012 reflects remaining distributions expected to be received from the partnership as it is dissolved. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 15 of the Notes to Consolidated Financial Statements under “Other Litigation.” In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership. We are providing transitional back-up guarantees, a few of which may continue for a prolonged period of time. Either RBS or JP Morgan Chase & Co., one of the buyers’ parties in the sales transactions, has fully indemnified us for any claims or losses in connection with the related transactions.

We provide additional information about RBS Sempra Commodities and the sales transactions and guarantees in Notes 4, 5 and 15 of the Notes to Consolidated Financial Statements.

In April 2011, Sempra South American Utilities acquired AEI’s interests in Chilquinta Energía, Luz del Sur, and related entities for $611 million in cash (net of cash acquired). This transaction was funded with excess funds from foreign operations, proceeds from divestitures and short-term debt.

We provide additional information about Chilquinta Energía and Luz del Sur in Note 3 of the Notes to Consolidated Financial Statements.

At December 31, 2012, our cash and cash equivalents held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated are approximately $280 million. At December 31, 2011, these cash balances were negative when netted against loans from Sempra Energy to fund the acquisitions in South America in April 2011. We are planning to repatriate future earnings beginning in 2013 from certain non-U.S. subsidiaries in Mexico and Peru. Because this potential repatriation would only be from future earnings, it does not change our current assertion, as we discuss in Note 7 of the Notes to Consolidated Financial Statements, that we intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings as of December 31, 2012. Therefore, we do not intend to use these cumulative undistributed earnings as a source of funding for U.S. operations.

We have significant investments in several trusts to provide for future payments of pensions and other postretirement benefits, and nuclear decommissioning. Changes in asset values, which are dependent on the activity in the equity and fixed income markets, have not affected the trust funds’ abilities to make required payments, but may impact funding requirements for pension and other postretirement benefit plans. At the California Utilities, funding requirements are generally recoverable in rates.

On February 22, 2013, our board of directors approved an increase to Sempra Energy’s quarterly common stock dividend to $0.63 per share ($2.52 annually), an increase of $0.03 per share ($0.12 annually) from $0.60 per share ($2.40 annually) authorized in February 2012. Declarations of dividends on our common stock are made at the discretion of the board. While we view dividends as an integral component of shareholder return, the amount of future dividends will depend upon earnings, cash flows, financial and legal requirements, and other relevant factors at that time.

On February 24, 2012, our board of directors approved an increase to Sempra Energy’s quarterly common stock dividend to $0.60 per share ($2.40 annually), an increase of $0.12 per share ($0.48 annually) from $0.48 per share ($1.92 annually) authorized in February 2011. We provide further information regarding dividends and dividend restrictions in “Dividends” below and under “Restricted Net Assets” in Note 1 of the Notes to Consolidated Financial Statements.

We discuss our principal credit agreements further in Note 5 of the Notes to Consolidated Financial Statements.

Short-Term Borrowings

Our short-term debt is primarily used to meet liquidity requirements, fund shareholder dividends, temporarily finance capital expenditures, and fund new business acquisitions or start-ups. Our corporate short-term, unsecured promissory notes, or commercial paper, were our primary source of short-term debt funding in 2012.

The following table shows selected statistics for our commercial paper borrowings for 2012:

COMMERCIAL PAPER STATISTICS
(Dollars in millions)
		Commercial Paper
Sempra Energy Consolidated
	Amount outstanding at December 31, 2012(1)	$	825
	Weighted average interest rate at December 31, 2012		0.62%

	Maximum month-end amount outstanding during 2012(2)	$	1,072

	Monthly weighted average amount outstanding during 2012	$	750
	Monthly weighted average interest rate during 2012		0.59%

SDG&E
	Amount outstanding at December 31, 2012	$	―

	Maximum month-end amount outstanding during 2012(2)	$	173

	Monthly weighted average amount outstanding during 2012	$	35
	Monthly weighted average interest rate during 2012		0.17%
(1)	Includes $300 million classified as long-term, as we discuss in Note 5 of the Notes to Consolidated Financial Statements.
(2)	The largest amount outstanding at the end of the last day of any month during the year.

Significant cash flows impacting commercial paper levels at Sempra Energy Consolidated during 2012 include issuance of long-term debt at Sempra Energy ($1.1 billion) and proceeds and distributions from investments at Sempra Renewables related to project financings (approximately $570 million), offset by payments of common dividends ($550 million) and capital investments and expenditures made for energy projects at Sempra Renewables (approximately $1 billion).

California Utilities

SDG&E and SoCalGas expect that cash flows from operations and debt issuances will continue to be adequate to meet their working capital and capital expenditure requirements. In March 2011, Sempra Energy made a $200 million capital contribution to SDG&E.

SoCalGas declared and paid $250 million in common dividends in 2012 and a $50 million common dividend in 2011. SoCalGas also declared and paid a $100 million common dividend in 2010. However, as a result of the increase in SoCalGas’ capital investment programs over the next few years, and the increase in SoCalGas’ authorized common equity weighting as approved by the CPUC in the cost of capital proceeding, management expects that SoCalGas’ dividends on common stock will be reduced, when compared to the dividends on common stock declared on an annual basis historically, or temporarily suspended over the next few years to maintain SoCalGas’ authorized capital structure during the periods of high capital investments. We discuss the cost of capital proceeding in Note 14 of the Notes to Consolidated Financial Statements.

As a result of SDG&E’s large capital investment program over the past few years and the level of capital investment in 2012, SDG&E did not pay common dividends to Sempra Energy in 2012. However, due to the completion of construction of the Sunrise Powerlink transmission power line in June 2012, SDG&E expects to be able to resume the declaration and payment of dividends on its common stock in 2014.

Sempra South American Utilities

We expect projects at Chilquinta Energía and Luz del Sur to be funded by external borrowings and funds internally generated by Chilquinta Energía and Luz del Sur.

Sempra Mexico

We expect projects in Mexico to be funded through a combination of funds internally generated by the Mexico businesses, project financing, raising other external capital, and partnering in joint ventures. On February 14, 2013, Sempra Mexico publicly offered and sold $306 million U.S. equivalent of fixed-rate, Peso-denominated notes maturing in 2023 and $102 million U.S. equivalent variable-rate, Peso-denominated notes maturing in 2018. Sempra Mexico will use the proceeds of the notes for capital projects, including the development of natural gas pipelines, and repayment of intercompany debt. Sempra Mexico entered into cross-currency swaps for U.S. dollars at the time of issuance. We discuss this offering further in Note 18 of the Notes to Consolidated Financial Statements.

On February 25, 2013, we announced that Sempra Mexico intends to offer, subject to market and other conditions, shares of its common stock in a private placement and, concurrently, in a registered public offering in Mexico. We currently expect Sempra Mexico to sell shares representing between 15 percent to 20 percent of the ownership interests in Sempra Mexico. The exact number of shares to be sold and the offering price of the shares will be determined at the time of the pricing of the offerings. Sempra Mexico expects to use the net proceeds of the offerings primarily for general corporate purposes, including the funding of its current investments and ongoing expansion plans. The closings of the offerings, which are expected to occur by April 2013, are conditioned on each other.

Sempra Renewables

We expect Sempra Renewables to require funds for the development of and investment in electric renewable energy projects. Projects at Sempra Renewables may be financed through a combination of operating cash flow, project financing, funds from the parent, and partnering in joint ventures. The Sempra Renewables projects have planned in-service dates through 2016.

Sempra Natural Gas

We expect Sempra Natural Gas to require funding for the expansion of its portfolio of projects, including natural gas storage, pipelines, and natural gas liquefaction facility. Funding for the development and expansion of its natural gas storage and transmission projects may be financed through a combination of operating cash flow, funding from the parent and the sale of one 625-megawatt block of Mesquite Power to the Salt River Project Agricultural Improvement and Power District (SRP). Sempra Natural Gas also plans to develop a natural gas liquefaction export facility at its Cameron LNG terminal. Sempra Natural Gas expects the majority of the liquefaction project to be project-financed and the remainder to be provided by the project partners in a joint venture agreement.

Cash flows from operations at Sempra Natural Gas decreased substantially in 2012 compared to 2011 since its contract with the DWR expired in September 2011, due to less favorable pricing on any replacement contracts obtained, and the sale of its El Dorado natural gas generation plant to SDG&E in 2011. Sempra Natural Gas may not be able to replace all of the lost revenue due to decreased market demand. Sales to the DWR comprised six percent of Sempra Energy’s revenues in 2011.

Some of Sempra Natural Gas’ long-term power sale contracts contain collateral requirements which require its affiliates and/or the counterparty to post cash, guarantees or letters of credit to the other party for exposure in excess of established thresholds. Sempra Natural Gas may be required to provide collateral when market price movements adversely affect the counterparty’s cost of replacement energy supplies if Sempra Natural Gas fails to deliver the contracted amounts. We have neither collateral posted nor owed to counterparties at December 31, 2012 pursuant to these requirements.

CASH FLOWS FROM OPERATING ACTIVITIES

CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
	2012		2012 Change				2011		2011 Change				2010
Sempra Energy Consolidated	$	2,018	$	151	8	%	$	1,867	$	(287)	(13)	%	$	2,154
SDG&E		1,101		219	25			882		153	21			729
SoCalGas		846		292	53			554		(182)	(25)			736

Sempra Energy Consolidated

Cash provided by operating activities at Sempra Energy increased in 2012 due to:

§	$290 million higher net income, adjusted for noncash items included in earnings, in 2012 compared to 2011;

§	$375 million of funds received in 2012 compared to $300 million received in 2011 from wildfire litigation settlements;

§	$130 million settlement payment in 2011 related to energy crisis litigation;

§	a $36 million decrease in accounts receivable in 2012 compared to a $32 million increase in accounts receivable in 2011; and

§	an $85 million payment received by SDG&E from Citizens Sunrise Transmission, LLC (Citizens) in July 2012, which we discuss in Note 15 of the Notes to Consolidated Financial Statements; offset by

§	$29 million increase in income taxes receivable in 2012 compared to a $269 million decrease in income taxes receivable in 2011;

an increase of $291 million in net undercollected regulatory balancing accounts in 2012 compared to an increase of $150 million in such accounts in 2011. Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time. See further explanation for changes in regulatory balances at SDG&E and SoCalGas below; and

§	$53 million of distributions from RBS Sempra Commodities in 2011.

Cash provided by operating activities at Sempra Energy decreased in 2011 due to:

§	$402 million in settlement payments for the 2007 wildfires in 2011 (using $381 million of restricted cash), compared to $43 million net settlement payments for the 2007 wildfires in 2010;

§	$130 million settlement payment related to energy crisis litigation in 2011, which was an increase to other current liabilities when accrued in 2010;

§	$145 million lower distributions from RBS Sempra Commodities in 2011; and

§	a $32 million increase in accounts receivable in 2011 compared to an $89 million decrease in accounts receivable in 2010; offset by

§	$269 million decrease in income taxes receivable in 2011 compared to a $12 million decrease in income taxes receivable in 2010;

§	$202 million higher net income, adjusted for noncash items included in earnings, in 2011 compared to 2010; and

§	$300 million of funds received in 2011 from a wildfire litigation settlement compared to $144 million of funds received in 2010, which is offset by an increase in restricted cash in cash flows from investing activities.

SDG&E

Cash provided by operating activities at SDG&E increased in 2012 due to:

§	$375 million of funds received in 2012 compared to $300 million received in 2011 from wildfire litigation settlements;

§	$242 million net income tax refunds in 2012 compared to $59 million net income tax payments in 2011;

§	$129 million higher net income, adjusted for noncash items included in earnings, in 2012 compared to 2011; and

§	an $85 million payment received from Citizens in July 2012; offset by

§	$42 million decrease in accounts payable in 2012 compared to a $68 million increase in accounts payable in 2011; and

§	an increase of $322 million in net undercollected regulatory balancing accounts in 2012 compared to an increase of $87 million in such accounts in 2011, as follows:

o	the increase in net undercollected regulatory balancing accounts in 2012 was primarily due to:

§	$214 million undercollection of electric resource costs; and

§	$71 million return of prior year’s overcollection to customers and $83 million of unrecovered current year spending for advanced metering infrastructure costs; offset by

§	$54 million reduction of prior year’s undercollected electric distribution fixed costs.

o	the increase in net undercollected regulatory balancing accounts in 2011 was primarily due to:

§	$18 million undercollection of electric resource costs;

§	$36 million undercollection of power commodity costs and costs associated with SDG&E’s contracts with qualifying electric generation facilities; and

§	$18 million undercollection of rate design settlement costs.

We expect the undercollected electric resource costs to be recovered from customers in rates in 2013 and the unrecovered current year spending for advanced metering infrastructure costs to be addressed as part of the 2012 GRC.

Cash provided by operating activities at SDG&E increased in 2011 due to:

§	$305 million higher net income, adjusted for noncash items included in earnings, in 2011 compared to 2010;

§	a higher increase in accounts payable in 2011 compared to 2010; and

§	$300 million of funds received in 2011 from a wildfire litigation settlement compared to $144 million of funds received in 2010; which is offset by an increase in restricted cash in cash flows from investing activities; offset by

§	$111 million increase in income taxes receivable in 2011 compared to a $12 million decrease in income taxes receivable in 2010; and

§	$402 million in settlement payments for the 2007 wildfires in 2011 (using $381 million of restricted cash), compared to $43 million net settlement payments for the 2007 wildfires in 2010.

SoCalGas

Cash provided by operating activities at SoCalGas increased in 2012 due to:

§	$37 million decrease in accounts receivable in 2012 compared to a $57 million increase in accounts receivable in 2011;

§	a $54 million increase in accounts payable in 2012 compared to a $7 million decrease in accounts payable in 2011;

§	$46 million increase in inventory in 2011;

§	$25 million higher net income, adjusted for noncash items included in earnings, in 2012 compared to 2011; and

§	an increase of $31 million in net overcollected regulatory balancing accounts in 2012 as compared to a decrease of $63 million in net overcollected regulatory balancing accounts in 2011, as follows:

o	the increase in net overcollected regulatory balancing accounts in 2012 was primarily due to:

§	overcollection of California alternate rates for energy (CARE) program costs of $54 million; and

§	overcollection of advanced metering infrastructure costs of $38 million; offset by

§	undercollection of fixed costs associated with core customer activities of $59 million.

o	the decrease in net overcollected regulatory balancing accounts in 2011 was primarily due to:

§	undercollection of direct assistance program costs of $32 million; and

§	undercollection of postretirement benefits plans costs of $27 million.

Cash provided by operating activities at SoCalGas decreased in 2011 due to:

§	an increase in accounts receivable in 2011 compared to a decrease in 2010;

§	a decrease in accounts payable in 2011 compared to an increase in 2010 primarily due to lower natural gas prices in 2011; and

§	a higher increase in inventory in 2011 compared to 2010; offset by

§	$40 million higher net income, adjusted for noncash items included in earnings, in 2011 compared to 2010.

The table below shows the contributions to pension and other postretirement benefit plans for each of the past three years.

CONTRIBUTIONS TO PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS 2010-2012
(Dollars in millions)
	Pension Benefits						Other Postretirement Benefits
	2012		2011		2010		2012		2011		2010
Sempra Energy Consolidated	$	123	$	212	$	159	$	39	$	72	$	52
SDG&E		45		69		61		13		15		15
SoCalGas		47		95		71		23		55		35

The contributions to our pension plans in 2012 have decreased significantly due to the passage of legislation in July 2012, the Moving Ahead for Progress in the 21st Century Act, that significantly reduces the minimum contributions required for single employer defined benefit plans, but increases premiums to the Pension Benefit Guaranty Corporation. The contributions to our other postretirement plans at SoCalGas and Sempra Energy in 2012 have decreased significantly mainly due to the impact of lower than expected retiree claims costs, our election to switch to an Employer Group Waiver Plan for administering prescription drug benefits for retirees and the change in the participation rates assumption to reflect lower anticipated utilization.

CASH FLOWS FROM INVESTING ACTIVITIES

CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
	2012		2012 Change				2011		2011 Change				2010
Sempra Energy Consolidated	$	(3,158)	$	88	3	%	$	(3,070)	$	1,787	139	%	$	(1,283)
SDG&E		(1,235)		(529)	(30)			(1,764)		450	34			(1,314)
SoCalGas		(643)		9	1			(634)		68	12			(566)

Sempra Energy Consolidated

Cash used in investing activities at Sempra Energy increased in 2012 due to:

§	$570 million in distributions received from RBS Sempra Commodities in 2011;

§	$381 million in payments in 2011 for claims related to wildfire litigation using restricted funds received from a wildfire litigation settlement;

§	$127 million increase in investments in wind assets; and

§	$112 million increase in capital expenditures; offset by

§	$611 million in cash used to fund Sempra South American Utilities’ purchase of South American entities in 2011;

§	a $300 million increase in SDG&E’s restricted cash in 2011 due to funds received from a wildfire litigation settlement;

§	$148 million in distributions received from Flat Ridge 2 in 2012; and

§	$59 million from the sale of Chilquinta Energía bonds in 2012.

Cash used in investing activities at Sempra Energy increased in 2011 due to:

§	a $782 million increase in capital expenditures;

§	$611 million in cash used to fund Sempra South American Utilities’ purchase of South American entities;

§	$279 million lower distributions received from RBS Sempra Commodities related to the sale of joint venture businesses and assets, as we discuss in Note 4 of the Notes to Consolidated Financial Statements;

§	a $300 million increase in SDG&E’s restricted cash due to funds received from a wildfire litigation settlement compared to $144 million of funds received in 2010;

§	$180 million of distributions from Fowler Ridge 2 Wind Farm at Sempra Renewables in 2010; and

§	$175 million of proceeds received from Sempra Natural Gas’ 2010 sale of its investment in Elk Hills; offset by

§	$381 million in payments for claims related to wildfire litigation using restricted funds received from a wildfire litigation settlement; and

§	Sempra Mexico’s $292 million acquisition (net of cash acquired) resulting in the purchase of pipeline and natural gas infrastructure assets in 2010.

SDG&E

Cash used in investing activities decreased at SDG&E in 2012 primarily due to:

§	a $594 million decrease in capital expenditures, primarily due to the completion of the Sunrise Powerlink project in June 2012; and

§	a $300 million increase in restricted cash in 2011 due to funds received from a wildfire litigation settlement; offset by

§	$381 million in payments for claims in 2011 related to wildfire litigation using restricted funds received from a wildfire litigation settlement.

Cash used in investing activities increased at SDG&E in 2011 primarily due to:

§	a $621 million increase in capital expenditures; and

§	a $300 million increase in restricted cash due to funds received from a wildfire litigation settlement compared to $144 million of funds received in 2010; offset by

§	$381 million in payments for claims related to wildfire litigation using restricted funds received from a wildfire litigation settlement.

SoCalGas

Cash used in investing activities increased at SoCalGas in 2012 primarily due to:

§	a $4 million increase in advances to Sempra Energy in 2012 compared to a $49 million decrease in advances to Sempra Energy in 2011; offset by

§	a $44 million decrease in capital expenditures.

Cash used in investing activities increased at SoCalGas in 2011 primarily due to:

§	a $180 million increase in capital expenditures; offset by

§	a $49 million decrease in advances to Sempra Energy in 2011 compared to a $63 million increase in advances to Sempra Energy in 2010.

CAPITAL EXPENDITURES AND INVESTMENTS

The table below shows our expenditures for property, plant and equipment, and for investments. We provide capital expenditure information by segment in Note 16 of the Notes to Consolidated Financial Statements.

SEMPRA ENERGY CONSOLIDATED
CAPITAL EXPENDITURES AND INVESTMENTS/ACQUISITIONS
(Dollars in millions)
	Property, plant and equipment		Investments and acquisition of businesses
2012	$	2,956	$	445
2011		2,844		941
2010		2,062		611
2009		1,912		939
2008		2,061		2,675

Capital Expenditures

California Utilities

The California Utilities’ capital expenditures for property, plant and equipment were

(Dollars in millions)	2012		2011		2010
SDG&E	$	1,237	$	1,831	$	1,210
SoCalGas		639		683		503

Capital expenditures at the California Utilities in 2012 consisted primarily of:

SDG&E

§	$611 million of improvements to natural gas and electric distribution systems

§	$291 million of improvements to electric transmission systems

§	$242 million for the Sunrise Powerlink transmission line and substation expansions

§	$93 million for electric generation plants and equipment

SoCalGas

§	$554 million of improvements to distribution and transmission systems and storage facilities

§	$85 million for advanced metering infrastructure

Through December 31, 2012, SDG&E has recorded $1.8 billion to property, plant and equipment related to the Sunrise Powerlink project, including $182 million of AFUDC related to debt and equity.

Sempra South American Utilities

Sempra South American Utilities had capital expenditures at its utilities of $183 million in 2012 and $110 million in 2011, related to distribution infrastructure and generation projects, including a hydroelectric power plant in Peru.

Sempra Mexico

Total capital expenditures in 2012 were $45 million, primarily for the development of natural gas pipeline projects. Total capital expenditures were $16 million in 2011 and $15 million in 2010.

Sempra Renewables

In 2012, capital expenditures include $399 million for the construction of the Mesquite Solar 1 facility and $315 million for the construction of the Copper Mountain Solar 2 facility. In 2011, capital expenditures include $181 million for the construction of the Mesquite Solar 1 facility. In 2010, capital expenditures were $123 million for construction of the Copper Mountain Solar 1 facility.

Sempra Natural Gas

In 2012, Sempra Natural Gas increased its operational working natural gas storage capacity by approximately 7 Bcf at Mississippi Hub and had capital expenditures related to the development of approximately 13 Bcf of additional capacity at Bay Gas and Mississippi Hub. In 2011, Sempra Natural Gas had capital expenditures related to the development of approximately 20 Bcf of additional capacity at Bay Gas and Mississippi Hub. In 2010, Sempra Natural Gas increased its operational working natural gas storage capacity by approximately 12 Bcf at Bay Gas and Mississippi Hub. Related amounts included in total capital expenditures were $61 million in 2012, $122 million in 2011 and $170 million in 2010.

In 2012, Sempra Natural Gas had $48 million of capital expenditures and development costs related to the Cameron LNG terminal and liquefaction project.

Sempra Energy Consolidated Investments and Acquisitions

In 2012, investments consisted primarily of:

§	$291 million for the investment in Flat Ridge 2 Wind Farm

§	$62 million for the investment in Auwahi Wind Farm

§	the purchase of $53 million in industrial development bonds

In 2011, investments and acquisitions consisted primarily of:

§	$611 million in cash used to fund Sempra South American Utilities’ purchase of South American entities

§	$146 million for the initial investment in Flat Ridge 2 Wind Farm

§	$88 million for the initial investment in Mehoopany Wind Farm

§	the purchase of $84 million in industrial development bonds

In 2010, investments and acquisitions consisted primarily of:

§	acquisition of Mexican pipelines and infrastructure assets for approximately $300 million

§	$209 million for the initial investment in Cedar Creek 2 Wind Farm

§	$65 million invested in Rockies Express

Sempra Energy Consolidated Distributions From Other Investments

Sempra Energy’s Distributions From Other Investments are primarily the return of investment from equity method and other investments at Sempra South American Utilities, Sempra Renewables and Sempra Natural Gas as follows:

(Dollars in millions)		2012		2011		2010
Sempra South American Utilities
	Luz del Sur	$	―	$	―	$	31

Sempra Renewables
	Flat Ridge 2		148		―		―
	Fowler Ridge 2		―		2		180
	Mehoopany Wind		17		―		―
	Cedar Creek 2		2		5		96

Sempra Natural Gas
	Rockies Express		37		57		55
	Elk Hills		―		―		9

Other			3		―		―
Total		$	207	$	64	$	371

The 2012 distributions from Flat Ridge 2 and Mehoopany Wind and 2010 distributions from Fowler Ridge 2 and Cedar Creek 2 were made by the joint ventures upon entering into loans to finance the projects. Distributions of earnings from these investments are included in cash flows from operations.

Purchase and Sale of Bonds Issued by Unconsolidated Affiliate

In November 2009, Sempra Energy, at Parent and Other, purchased $50 million of 2.75-percent bonds issued by Chilquinta Energía S.A., a then unconsolidated affiliate, that are adjusted for Chilean inflation. In October 2012, these bonds were sold for $59 million. We discuss these bonds in Note 5 of the Notes to Consolidated Financial Statements.

FUTURE CONSTRUCTION EXPENDITURES AND INVESTMENTS

The amounts and timing of capital expenditures are generally subject to approvals by the CPUC, the FERC and other regulatory bodies. However, in 2013, we expect to make capital expenditures and investments of approximately $3.3 billion. These expenditures include

§	$2.5 billion at the California Utilities for capital projects and plant improvements ($1.5 billion at SDG&E and $1.0 billion at SoCalGas)

§	$800 million at our other subsidiaries for capital projects in Mexico and South America, and development of natural gas and renewable generation projects

In 2013, the California Utilities expect their capital expenditures and investments to include

§	$550 million for improvements to SDG&E’s natural gas and electric distribution systems

§	$300 million for SDG&E’s renewable energy projects

§	$300 million for improvements to SDG&E’s electric transmission systems

§	$290 million at SDG&E for substation expansions (transmission)

§	$80 million for SDG&E’s electric generation plants and equipment

§	$730 million for improvements to SoCalGas’ distribution and transmission systems, and for pipeline safety

§	$220 million for SoCalGas’ advanced metering infrastructure

§	$70 million for SoCalGas’ underground natural gas storage fields

The California Utilities expect to finance these expenditures and investments with cash flows from operations and debt issuances.

Over the next five years and subject to the factors described below which could cause these estimates to vary substantially, the California Utilities expect to make capital expenditures and investments of:

§	$5.8 billion at SDG&E

§	$5.9 billion at SoCalGas

In 2013, the expected capital expenditures and investments of approximately $800 million at our other subsidiaries include

Sempra South American Utilities

§	approximately $150 million to $200 million for capital projects in South America (approximately $100 million to $150 million in Peru and approximately $50 million in Chile)

Sempra Mexico

§	approximately $425 million to $475 million for capital projects in Mexico, including approximately $350 million for the development of natural gas pipeline projects developed solely by Sempra Mexico

§	approximately $330 million of expenditures for pipeline projects within our joint venture with PEMEX. We expect expenditures for projects done within the joint venture to be funded by the joint venture’s cash flows from operations without additional contributions from its partners

Sempra Renewables

§	approximately $50 million for investment in the third phase of Copper Mountain Solar, a 250-MW solar project located near Boulder City, Nevada

Sempra Natural Gas

§	approximately $100 million for development of natural gas projects, including approximately $50 million for natural gas storage at Bay Gas and Mississippi Hub

Over the next five years and subject to the factors described below which could cause these estimates to vary substantially, Sempra Energy expects to make aggregate capital expenditures at its other subsidiaries of approximately $2.9 billion.

Capital expenditure amounts include capitalized interest. At the California Utilities, the amounts also include the portion of AFUDC related to debt, but exclude the portion of AFUDC related to equity. We provide further details about AFUDC in Note 1 of the Notes to Consolidated Financial Statements.

Periodically, we review our construction, investment and financing programs and revise them in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost and availability of capital, and environmental requirements. We discuss these considerations in more detail in Notes 14 and 15 of the Notes to Consolidated Financial Statements and in “Factors Influencing Future Performance” below.

Our level of capital expenditures and investments in the next few years may vary substantially and will depend on the cost and availability of financing, regulatory approvals, changes in U.S. federal tax law and business opportunities providing desirable rates of return. We intend to finance our capital expenditures in a manner that will maintain our strong investment-grade credit ratings and capital structure.

CASH FLOWS FROM FINANCING ACTIVITIES

CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
	2012		2012 Change		2011		2011 Change		2010
Sempra Energy Consolidated	$	1,355	$	821	$	534	$	603	$	(69)
SDG&E		192		(592)		784		85		699
SoCalGas		(156)		145		(301)		(499)		198

Sempra Energy Consolidated

Cash provided by financing activities in 2012 increased due to:

§	$999 million higher issuances of debt, primarily long-term debt of $693 million (issuances of $2,267 million in 2012 compared to $1,574 million in 2011) and commercial paper with maturities greater than 90 days of $309 million (issuances of $824 million in 2012 compared to $515 million in 2011);

§	$47 million decrease in short-term debt in 2012 compared to a $498 million decrease in 2011;

§	$80 million for the redemption of subsidiary preferred stock in 2011; and

§	$43 million related to Sempra South American Utilities’ September 2011 tender offer discussed in Note 3 of the Notes to Consolidated Financial Statements; offset by

§	$628 million higher payments of commercial paper with maturities greater than 90 days, offset by $31 million lower payments on long-term debt; and

§	$110 million increase in common dividends paid.

Cash from financing activities in 2011 increased due to:

§	$973 million higher issuances of debt with maturities greater than 90 days;

§	$500 million common stock repurchase program in 2010; and

§	$423 million lower payments on debt with maturities greater than 90 days; offset by

§	$498 million decrease in short-term debt in 2011 compared to a $568 million increase in 2010;

§	$80 million for the redemption of subsidiary preferred stock;

§	$76 million increase in common dividends paid; and

§	$43 million related to Sempra South American Utilities’ September 2011 tender offer.

SDG&E

Cash provided by financing activities in 2012 decreased primarily due to:

§	$349 million lower issuances of long-term debt;

§	a $200 million capital contribution from Sempra Energy in 2011; and

§	$40 million of capital distributions made by Otay Mesa VIE in 2012.

Cash provided by financing activities in 2011 increased due to:

§	a $200 million capital contribution from Sempra Energy in 2011; offset by

§	$146 million lower issuances of long-term debt.

SoCalGas

Cash used by financing activities at SoCalGas in 2012 decreased primarily due to:

§	$348 million issuance of long-term debt in 2012; offset by

§	$200 million increase in common dividends paid.

At SoCalGas, financing activities used cash in 2011 compared to providing cash in 2010, primarily due to:

§	a $250 million long-term debt payment in 2011; and

§	$300 million issuance of long-term in 2010; offset by

§	$50 million lower common dividends paid.

LONG-TERM DEBT

Long-term debt balances (including the current portion of long-term debt) at December 31 were

(Dollars in millions)	2012		2011		2010
Sempra Energy Consolidated	$	12,346	$	10,414	$	9,329
SDG&E		4,308		4,077		3,498
SoCalGas		1,413		1,321		1,582

At December 31, 2012, the following information applies to long-term debt, excluding commercial paper classified as long-term:

	Sempra Energy
(Dollars in millions)	Consolidated		SDG&E		SoCalGas
Weighted average life to maturity, in years	13.0		18.1		18.6
Weighted average interest rate	4.86	%	4.90	%	5.02	%

Issuances of Long-Term Debt

Major issuances of long-term debt over the last three years included the following:

(Dollars in millions)			Amount	Rate		Maturing

Sempra Energy
	Notes, September 2012	$	500	2.875	%	2022
	Notes, March 2012		600	2.30		2017
	Variable rate notes (1.07% at December 31, 2012),
	March 2011		300	1.07		2014
	Notes, March 2011		500	2.00		2014

SDG&E
	First mortgage bonds, March 2012		250	4.30		2042
	First mortgage bonds, November 2011		250	3.95		2041
	First mortgage bonds, August 2011		350	3.00		2021
	First mortgage bonds, August 2010		500	4.50		2040
	First mortgage bonds, May 2010		250	5.35		2040

SoCalGas
	First mortgage bonds, September 2012		350	3.750		2042
	First mortgage bonds, November 2010		300	5.125		2040

Sempra Energy used the proceeds from its issuances of long-term debt primarily for general corporate purposes and to repay commercial paper.

The California Utilities used the proceeds from their issuances of long-term debt:

§	for general working capital purposes;

§	to repay maturing long-term bonds at SoCalGas;

§	to support their electric (at SDG&E) and natural gas (SDG&E and SoCalGas) procurement programs;

§	to repay commercial paper at SDG&E; and

§	to replenish amounts expended and fund future expenditures for the expansion and improvement of their utility plants.

Payments on Long-Term Debt

Payments on long-term debt in 2012 included $250 million of SoCalGas 4.8-percent first mortgage bonds at maturity in October 2012.

Payments on long-term debt in 2011 included

§	$100 million of SoCalGas 4.375-percent first mortgage bonds at maturity in January 2011

§	$150 million of SoCalGas variable rate first mortgage bonds at maturity in January 2011

Payments on long-term debt in 2010 included

§	$500 million of Sempra Energy notes payable at maturity in March 2010

§	retirement of $128 million of industrial development bonds related to Sempra Natural Gas’ Liberty project

In Note 5 of the Notes to Consolidated Financial Statements, we provide information about our lines of credit and additional information about debt activity.

CAPITAL STOCK TRANSACTIONS

Sempra Energy

Cash provided by employee stock option exercises and newly issued shares for our dividend reinvestment and 401(k) saving plans was

§	$78 million in 2012

§	$28 million in 2011

§	$40 million in 2010

In 2010, we entered into a Collared Accelerated Share Acquisition Program under which we prepaid $500 million to repurchase shares of our common stock in a share forward transaction. We received 8.1 million shares under the program during 2010 and an additional 1.5 million shares when the program was completed in March 2011. We discuss the repurchase program in Note 13 of the Notes to Consolidated Financial Statements.

DIVIDENDS

Sempra Energy

Sempra Energy paid cash dividends on common stock of:

§	$550 million in 2012

§	$440 million in 2011

§	$364 million in 2010

The increase in 2012 was due to an increase in the per-share quarterly dividend from $0.48 in 2011 to $0.60 in 2012. The increase in 2011 was due to an increase in the per-share quarterly dividend from $0.39 in 2010 to $0.48 in 2011.

On December 14, 2012, Sempra Energy declared a quarterly dividend of $0.60 per share of common stock that was paid on January 15, 2013. We provide additional information about Sempra Energy dividends above in “Capital Resources and Liquidity – Overview – Sempra Energy Consolidated.”

SDG&E did not pay any common dividends to Sempra Energy in 2012, 2011 and 2010 to preserve cash to fund its capital expenditures program, which included the Sunrise Powerlink.

SoCalGas paid dividends to Pacific Enterprises (PE) and PE paid corresponding dividends to Sempra Energy of:

§	$250 million in 2012

§	$50 million in 2011

§	$100 million in 2010

PE, a wholly owned subsidiary of Sempra Energy, owns all of SoCalGas’ outstanding common stock. Accordingly, dividends paid by SoCalGas to PE and dividends paid by PE to Sempra Energy are both eliminated in Sempra Energy’s consolidated financial statements.

The board of directors for each of Sempra Energy, SDG&E and SoCalGas has the discretion to determine the payment and amount of future dividends by each such entity. The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts that are available for loans and dividends to Sempra Energy. At December 31, 2012, Sempra Energy could have received combined loans and dividends of approximately $917 million from SoCalGas and approximately $660 million from SDG&E.

We provide additional information about restricted net assets in Note 1 of the Notes to Consolidated Financial Statements and about the CPUC’s regulation of the California Utilities’ capital structures in Note 14 of the Notes to Consolidated Financial Statements.

CAPITALIZATION

TOTAL CAPITALIZATION AND DEBT-TO-CAPITALIZATION RATIOS
(Dollars in millions)
		As of December 31, 2012
		Sempra Energy
		Consolidated(1)			SDG&E(1)			SoCalGas
Total capitalization		$	23,654		$	8,685		$	3,648
Debt-to-capitalization ratio			55	%		50	%		39	%

		As of December 31, 2011
		Sempra Energy
		Consolidated(1)			SDG&E(1)			SoCalGas
Total capitalization		$	21,120		$	7,997		$	3,514
Debt-to-capitalization ratio			51	%		51	%		38	%
(1)	Includes noncontrolling interests and debt of Otay Mesa Energy Center LLC for Sempra Energy and SDG&E with no significant impact.

Significant changes during 2012 that affected capitalization include the following:

§	Sempra Energy Consolidated: net increases in long-term debt, partially offset by comprehensive income exceeding dividends

§	SDG&E: comprehensive income, partially offset by an increase in long-term debt

§	SoCalGas: a net increase in long-term debt, partially offset by comprehensive income exceeding dividends

We provide additional information about these significant changes in Notes 1, 5 and 13 of the Notes to Consolidated Financial Statements.

COMMITMENTS

The following tables summarize principal contractual commitments, primarily long-term, at December 31, 2012 for Sempra Energy, SDG&E and SoCalGas. We provide additional information about commitments above and in Notes 5, 8 and 15 of the Notes to Consolidated Financial Statements.

PRINCIPAL CONTRACTUAL COMMITMENTS OF SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		2013		2014 and 2015		2016 and 2017		Thereafter		Total
Long-term debt(1)		$	731	$	1,704	$	1,473	$	7,946	$	11,854
Interest on long-term debt(2)			553		993		872		5,221		7,639
Operating leases			78		148		130		572		928
Capital leases			9		10		6		164		189
Purchased-power contracts			1,257		2,624		2,782		10,978		17,641
Natural gas contracts			682		336		140		322		1,480
LNG contracts(3)			565		1,337		1,479		11,311		14,692
Construction commitments			592		358		47		80		1,077
SONGS decommissioning			2		―		―		556		558
Sunrise wildfire mitigation fund			3		6		6		309		324
Other asset retirement obligations			21		43		41		1,393		1,498
Pension and other postretirement benefit
obligations(4)			181		408		434		802		1,825
Environmental commitments			9		14		3		5		31
Other			24		23		12		26		85
Totals		$	4,707	$	8,004	$	7,425	$	39,685	$	59,821
(1)	Excludes $300 million commercial paper classified as long-term, as we discuss in Note 5 of the Notes to Consolidated Financial Statements.
(2)	We calculate expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps. We calculate expected interest payments for variable-rate obligations, including fixed-to-floating interest rate swaps, based on forward rates in effect at December 31, 2012.
(3)	Our LNG facilities have various LNG purchase agreements with major international companies for the supply of LNG to our Energía Costa Azul and Cameron terminals. The agreements range from short-term to multi-year periods and are priced using a predetermined formula based on U.S. market indices. The expected payments under the contracts are based on forward prices of the applicable market index from 2013 to 2022 and an estimated one percent escalation per year after 2022. We provide more information about these contracts in Note 15 of the Notes to Consolidated Financial Statements.
(4)	Amounts represent expected company contributions to the plans for the next 10 years.

PRINCIPAL CONTRACTUAL COMMITMENTS OF SDG&E
(Dollars in millions)
		2013		2014 and 2015		2016 and 2017		Thereafter		Total
Long-term debt		$	10	$	414	$	20	$	3,691	$	4,135
Interest on long-term debt(1)			203		391		361		2,757		3,712
Operating leases			20		39		37		21		117
Capital leases			6		9		6		164		185
Purchased-power contracts			405		755		740		3,999		5,899
Construction commitments			229		47		41		62		379
SONGS decommissioning			2		―		―		556		558
Sunrise wildfire mitigation fund			3		6		6		309		324
Other asset retirement obligations			5		10		10		158		183
Pension and other postretirement benefit
obligations(2)			68		147		119		204		538
Environmental commitments			3		2		2		4		11
Totals		$	954	$	1,820	$	1,342	$	11,925	$	16,041
(1)	SDG&E calculates expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps. SDG&E calculates expected interest payments for variable-rate obligations based on forward rates in effect at December 31, 2012.
(2)	Amounts represent expected company contributions to the plans for the next 10 years.

PRINCIPAL CONTRACTUAL COMMITMENTS OF SOCALGAS
(Dollars in millions)
		2013		2014 and 2015		2016 and 2017		Thereafter		Total
Long-term debt		$	―	$	250	$	8	$	1,155	$	1,413
Interest on long-term debt(1)			71		117		114		939		1,241
Natural gas contracts			538		200		78		158		974
Operating leases			29		58		52		198		337
Capital leases			3		1		―		―		4
Construction commitments			76		29		6		18		129
Environmental commitments			3		11		1		1		16
Pension and other postretirement benefit
obligations(2)			80		200		243		448		971
Asset retirement obligations			15		32		32		1,174		1,253
Totals		$	815	$	898	$	534	$	4,091	$	6,338
(1)	SoCalGas calculates interest payments using the stated interest rate for fixed-rate obligations.
(2)	Amounts represent expected company contributions to the plans for the next 10 years.

The tables exclude

§	contracts between consolidated affiliates

§	intercompany debt

§	individual contracts that have annual cash requirements less than $1 million

§	employment contracts

The tables also exclude income tax liabilities of

§	$44 million for Sempra Energy Consolidated

§	$12 million for SDG&E

§	$5 million for SoCalGas

These liabilities relate to uncertain tax positions and were excluded from the tables because we are unable to reasonably estimate the timing of future payments due to uncertainties in the timing of the effective settlement of tax positions. We provide additional information about unrecognized tax benefits in Note 7 of the Notes to Consolidated Financial Statements.

OFF BALANCE-SHEET ARRANGEMENTS

Sempra Energy has provided maximum guarantees aggregating $252 million at December 31, 2012 to related parties. We discuss these guarantees in Notes 5 and 15 of the Notes to Consolidated Financial Statements.

CREDIT RATINGS

The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels in 2012. In August 2011, Fitch downgraded the rating on Sempra Energy’s unsecured debt from A- with a negative outlook to BBB+ with a stable outlook, consistent with Moody’s and Standard & Poor’s (S&P) ratings. Also at that time, Fitch affirmed that this downgrade had no effect on SDG&E’s and SoCalGas’ ratings.

Sempra Energy, SDG&E and SoCalGas have committed lines of credit to provide liquidity and to support commercial paper and variable-rate demand notes. Borrowings under these facilities bear interest at benchmark rates plus a margin that varies with market index rates and each borrower’s credit rating. Each facility also requires a commitment fee on available unused credit.

Under these committed lines, if Sempra Energy were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 to 50 basis points, depending on the severity of the downgrade. The commitment fee on available unused credit would also increase 5 to 10 basis points, depending on the severity of the downgrade.

Under these committed lines, if SDG&E or SoCalGas were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 to 75 basis points, depending on the severity of the downgrade. The commitment fee on available unused credit would also increase 2.5 to 17.5 basis points, depending on the severity of the downgrade.

For Sempra Energy and SDG&E, their credit ratings may affect credit limits related to derivative instruments, as we discuss in Note 10 of the Notes to Consolidated Financial Statements.

FACTORS INFLUENCING FUTURE PERFORMANCE

SEMPRA ENERGY OVERVIEW

California Utilities

The California Utilities’ operations have historically provided relatively stable earnings and liquidity. However, for the next few years, SoCalGas intends to limit its common stock dividends to reinvest its earnings in significant capital projects.

The California Utilities’ performance will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature to address state budget concerns and the changing energy marketplace. Their performance will also depend on the successful completion of capital projects that we discuss in various sections of this report and below. We discuss certain regulatory matters below and in Note 14 of the Notes to Consolidated Financial Statements.

SDG&E may also be significantly impacted by matters at San Onofre Nuclear Generating Station (SONGS). We discuss SONGS below, in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements and in Risk Factors in our 2012 Annual Report on Form 10-K.

Sempra South American Utilities

In April 2011, Sempra South American Utilities increased its investment in two utilities in South America. As anticipated, the acquisition has continued to be accretive to our earnings per share. However, in connection with our increased interests in Chilquinta Energía and Luz del Sur, Sempra Energy has $1 billion in goodwill on its Consolidated Balance Sheet as of December 31, 2012. Goodwill is subject to impairment testing, annually and under other potential circumstances, which may cause its fair value to vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions.

We discuss the acquisition in Note 3 of the Notes to Consolidated Financial Statements. Sempra South American Utilities is also expected to provide earnings from construction projects when completed and other investments, but will require substantial funding for these investments.

Revenues at Chilquinta Energía are based on tariffs set by the National Energy Commission every four years. Rates for four-year periods related to distribution and transmission are reviewed separately on an alternating basis every two years. In late 2011, Chilquinta Energía initiated the process to establish their distribution rates for the period from November 2012 to October 2016. This process was completed in November 2012, with rates established through October 2016 but not formally effective until certain governmental reviews are finalized. We expect completion of these reviews and official publication of Chilquinta Energía’s distribution rates in the first quarter of 2013, with tariff adjustments going into effect retroactively from November 2012. Their next review is scheduled to be completed, with tariff adjustments also going into effect, in November 2014 for transmission, and again for distribution in November 2016.

Luz del Sur serves primarily regulated customers in Peru and revenues are based on rates set by the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería, or OSINERGMIN). The rates are reviewed and adjusted every four years. The next review is scheduled to be completed, with rate adjustments also going into effect, in November 2013. In 2012, Luz del Sur initiated the process to establish their distribution rates subject to this review.

Sempra South American Utilities owns 43 percent of two Argentine natural gas holding companies, as we discuss in Note 4 of the Notes to Consolidated Financial Statements. We expect to dispose of this investment by the end of 2013.

Sempra Mexico

Based on current market prices for electricity, contracts that Sempra Mexico enters into at its natural gas-fired plant to replace the DWR contract, if obtained, or merchant (daily) sales will provide substantially lower earnings. Sempra Mexico’s earnings from generation have decreased and may remain at lower levels compared to 2011 due to the completion of the DWR contract. Effective January 1, 2012, Sempra Mexico’s Termoeléctrica de Mexicali entered into an Energy Management Agreement with Sempra Natural Gas for energy marketing, scheduling and other related services to support its sales of generated power into the California electricity market. We provide additional information above in “Our Business–Sempra Energy Operating Units and Reportable Segments–Sempra International–Sempra Mexico–Power Business.”

Sempra Mexico is expected to provide earnings from construction projects when completed and other investments, but will require substantial funding for these investments. On February 14, 2013, Sempra Mexico publicly offered and sold $408 million U.S. equivalent fixed- and variable-rate notes. The notes and related interest are denominated in Mexican Pesos. Sempra Mexico will use the proceeds of the notes for capital projects, including development of natural gas pipeline projects, repayment of intercompany debt, and general corporate uses. Sempra Mexico entered into cross-currency swaps for U.S. dollars at the time of the issuance. We discuss this financing further in Note 18 of the Notes to Consolidated Financial Statements.

On February 25, 2013, we announced that Sempra Mexico intends to offer, subject to market and other conditions, shares of its common stock in a private placement and, concurrently, in a registered public offering in Mexico. We currently expect Sempra Mexico to sell shares representing between 15 percent and 20 percent of the ownership interests in Sempra Mexico, which will reduce our earnings from Sempra Mexico and have a dilutive effect on our earnings per share. The exact number of shares to be sold and the offering price of the shares will be determined at the time of the pricing of the offerings. The closings of the offerings, which are expected to occur by April 2013, are conditioned on each other.

Sempra Renewables

Sempra Renewables is developing and investing in renewable energy generation projects that have long-term contracts with utilities. The renewable energy projects have planned in-service dates through 2016. These projects require construction financing which has come and may come from a variety of sources including operating cash flow, project financing, low-cost financing procured under the DOE’s loan guaranty program, U.S. Treasury Department cash grants, funds from the parent, partnering in joint ventures and, potentially, other forms of equity sales. The varying costs of these alternative financing sources impact the projects’ returns.

Sempra Renewables’ Mesquite Solar 1, the first phase of Copper Mountain Solar 2, Flat Ridge 2 Wind Farm, Mehoopany Wind Farm and Auwahi Wind Farm projects were placed in service in 2012.

Sempra Renewables’ future performance and the demand for renewable energy is impacted by various market factors, most notably state mandated requirements to deliver a portion of total energy load from renewable energy sources. The rules governing these requirements are generally known as Renewables Portfolio Standards (RPS). Additionally, the phase out or extension of U.S. federal income tax incentives, primarily investment tax credits and production tax credits, and grant programs could significantly impact future renewable energy resource availability and investment decisions.

The Budget Control Act of 2011 requires that, unless an approved federal budget achieves a deficit reduction of greater than $1.2 trillion, automatic federal budget cuts, known as “sequestration,” are to be triggered starting in fiscal year 2013. Such cuts would result in across-the-board budget cuts for many government programs. Amounts payable to taxpayers that are qualified to receive the cash grant for renewable energy projects under Section 1603 of the American Recovery and Reinvestment Tax Act of 2009 (ARTA) would be subject to the automatic sequester of spending cuts. Although ARTA postpones the automatic sequester for two months, if the United States Congress (Congress) cannot reach a workable long-term agreement by March 1, 2013 and sequestration goes into effect, cash grants to eligible taxpayers that have not received payment will be reduced. In September 2012, the Office of Management and Budget (OMB) issued a report providing that, if sequestration occurred, the cash grant program, categorized as a non-exempt non-defense mandatory program, would be subject to a 7.6 percent reduction starting in 2013. Neither the Department of Treasury nor the OMB has provided clarity on which renewable projects would be affected. If sequestration is triggered, Section 1603 grants will not be reduced immediately. Rather, the reduction is expected to go into effect March 27, 2013 or when Congress completes the final budget authorization, whichever occurs later. Tax credits—such as the production tax credit under Section 45 and the investment tax credit under Section 48—are exempt from sequestration. However, the phase-out or extension of these programs is uncertain.

Sempra Natural Gas

Current energy market prices are significantly lower than those under Sempra Natural Gas’ former contract with the DWR, which ended on September 30, 2011 and had provided a significant portion of Sempra Natural Gas’ revenues. Revenues from Sempra Natural Gas’ natural gas-fired generation are also expected to continue to be lower than 2011 and prior years due to a decline in market demand and the sale of Sempra Natural Gas’ El Dorado natural gas generation plant to SDG&E on October 1, 2011. Based on current market prices for electricity, contracts that Sempra Natural Gas enters into to replace the DWR contract, if obtained, or merchant (daily) sales will provide substantially lower earnings.

In December 2012, Sempra Natural Gas entered into a definitive agreement to sell one 625-MW block of Mesquite Power to the Salt River Project Agricultural Improvement and Power District for approximately $370 million. We expect the transaction to close in the first quarter of 2013.

In June 2011, Sempra Natural Gas entered into a 25-year contract with various members of Southwest Public Power Resources Group (SPPR Group), an association of 40 not-for-profit utilities in Arizona and southern Nevada, for 240 MW of electricity. Under the terms of the agreement, Sempra Natural Gas will provide 21 participating SPPR Group members with firm, day-ahead dispatchable power delivered to the Palo Verde hub beginning in January 2015.

Sempra Natural Gas is currently progressing with plans for a development project to utilize its Cameron LNG terminal for the liquefaction of natural gas and export of LNG. The objective is to obtain long-term contracts for liquefaction services that allow us to fully utilize our existing regasification infrastructure while minimizing our future additional capital investment. The liquefaction facility will utilize Cameron LNG’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability of 1.5 Bcf per day. In January 2012, the DOE approved Cameron LNG’s application for a license to export LNG to FTA countries. The authorization to export LNG to countries with which the U.S. does not have a Free Trade Agreement is pending review by the DOE.

In April and May 2012, Sempra Natural Gas signed commercial development agreements with Mitsubishi Corporation, Mitsui & Co., Ltd., and a subsidiary of GDF SUEZ S.A. to develop a natural gas liquefaction export facility at the Cameron LNG terminal. The completed liquefaction facility is expected to be comprised of three liquefaction trains and is being designed to a nameplate capacity of 13.5 million tonnes per annum (Mtpa) of LNG and expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. Sempra Natural Gas filed for the required permits from the FERC in December 2012, and expects to enter into a turnkey engineering, procurement and construction contract for the project in 2013. Pending regulatory approvals and the achievement of other key milestones, we expect to make a final investment decision before the end of 2013 and start field construction in early 2014. We expect commercial operations to begin for the first train in the second half of 2017, and all three trains to be completed by the end of 2018. The anticipated incremental investment in the three-train liquefaction project, subject to final design specifications, is estimated to be approximately $6 billion to $7 billion, excluding capitalized interest and other financing costs, the majority of which will be project-financed and the balance provided by the project partners in a joint-venture arrangement. The total cost of the facility, including the cost of our original facility plus interest during construction, financing costs and required reserves, is estimated to be approximately $9 billion to $10 billion.

Sempra Natural Gas’ existing assets will provide substantially all of its capital contribution to the joint venture, however we may contribute up to an additional $600 million to the joint venture, which may come from our share of cash flows from operations from the first and second trains. We expect to own 50.2 percent of the joint venture and the three other joint venture partners are expected to each own 16.6 percent.

The commercial development agreements bind the parties to fund certain development costs, including design, permitting and engineering, as well as to negotiate in good faith 20-year tolling agreements, based on agreed-upon key terms outlined in the commercial development agreements. Each tolling agreement for the respective customers would be for the export of approximately 4 Mtpa.

As we discuss above under “Our Business–Sempra Energy Operating Units and Reportable Segments–Sempra U.S. Gas & Power–Sempra Natural Gas,” Sempra Natural Gas, Tallgrass and Phillips 66 jointly own REX. We have recorded noncash, after-tax impairment charges of $239 million in 2012 to write down our investment in Rockies Express, the partnership that operates REX. Sempra Rockies Marketing, a subsidiary of Sempra Natural Gas, has an agreement for capacity on the Rockies Express Pipeline through November 2019. The capacity costs are offset by revenues from releases of the capacity to RBS Sempra Commodities prior to 2011, and to J.P. Morgan Ventures starting in 2011, and other third parties. Certain capacity release commitments will conclude during 2013. Accordingly, new contracting activity related to that capacity may not be sufficient to offset all of our capacity payments to REX. We discuss our investment in Rockies Express and the impairment charges in Notes 4 and 11 of the Notes to Consolidated Financial Statements.

Sempra Commodities

In three separate transactions in 2010 and one in early 2011, we and RBS sold substantially all of the businesses and assets of our commodities-marketing partnership. The investment balance of $126 million at December 31, 2012 reflects remaining distributions expected to be received from the partnership as it is dissolved. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 15 of the Notes to Consolidated Financial Statements under “Other Litigation.” In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership. We provide additional information in Notes 4, 5 and 15 of the Notes to Consolidated Financial Statements.

CALIFORNIA UTILITIES

Joint Matters

General Rate Case (GRC)

Both SDG&E and SoCalGas have their 2012 General Rate Case (GRC) applications pending at the CPUC. The California Utilities filed their initial applications for the 2012 GRC in December 2010 to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. In July 2011, SDG&E and SoCalGas filed revised applications and in February 2012, SDG&E and SoCalGas filed amendments to update the July 2011 filing. The 2012 amendments revised the requested increases to their authorized revenue requirements, as compared to their 2011 authorized revenues, to $235 million at SDG&E, of which $67 million is for the cost recovery of incremental wildfire insurance premiums, and to $268 million at SoCalGas. The Division of Ratepayer Advocates is recommending that the CPUC reduce the utilities’ revenue requirements in 2012 by approximately 5 percent compared to 2011.

Evidentiary hearings were completed in January 2012 and final briefs reflecting the results from these hearings were filed with the CPUC in May 2012. Because a final decision for the 2012 GRC was not issued in 2012, the California Utilities have recorded revenues in 2012 based on levels authorized in 2011 plus, for SDG&E, consistent with the recent CPUC decisions for cost recovery for SDG&E’s incremental wildfire insurance premiums, an amount for the recovery of 2012 wildfire insurance premiums. We expect a final CPUC decision for the 2012 GRC, which will be made effective retroactive to January 1, 2012, in the first half of 2013. Sempra Energy and the California Utilities will reflect the impact of the final decision, including the financial effect associated with the retroactive application to January 1, 2012, in 2013 financial results in the period in which such final decision is issued. The timing of the CPUC decision and the outcome from these proceedings will have an impact on the financial condition, operating results and cash flows of the California Utilities. If the CPUC’s final decision grants a significantly lower authorized revenue requirement, it could have a material adverse effect on the California Utilities’ cash flows, financial condition, results of operations and prospects starting in 2013 as compared to 2011. We provide additional information regarding the 2012 GRC in Note 14 of the Notes to Consolidated Financial Statements.

Natural Gas Pipeline Operations Safety Assessments

Pending the outcome of the various regulatory agency evaluations of natural gas pipeline safety regulations, practices and procedures, Sempra Energy, including the California Utilities, may incur incremental expense and capital investment associated with its natural gas pipeline operations and investments. In August 2011, SoCalGas, SDG&E, PG&E and Southwest Gas filed implementation plans with the CPUC to test or replace all natural gas transmission pipelines that have not been pressure tested, as we discuss in Note 14 of the Notes to Consolidated Financial Statements. The California Utilities are currently estimating that the total cost for Phase 1 of the two-phase plan is $3.1 billion over a 10-year period. The California Utilities requested that the incremental capital investment required as a result of any approved plan be included in rate base and that cost recovery be allowed for any other incremental cost not eligible for rate-base recovery. The costs that are the subject of these plans are outside the scope of the 2012 GRC proceedings discussed above. If the CPUC were to decide that the incremental capital investment not be considered as incremental rate base outside the GRC process or that this incremental capital investment earn an ROR lower than what is otherwise authorized, it could materially adversely affect the respective company’s cash flows, financial condition, results of operations and prospects upon commencement of this program. We provide additional information in Note 14 of the Notes to Consolidated Financial Statements.

SDG&E Matters

2007 Wildfire Litigation

In regard to the 2007 wildfire litigation, SDG&E’s settlement of claims and the estimate of outstanding claims and legal fees is approximately $2.4 billion, which is in excess of the $1.1 billion of liability insurance coverage and the approximately $824 million recovered from third parties. However, SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and amounts recovered from third parties. Consequently, Sempra Energy and SDG&E expect no significant earnings impact from the resolution of the remaining wildfire claims. As of December 31, 2012, Sempra Energy’s and SDG&E’s Consolidated Balance Sheets reflect $364 million in Regulatory Assets Arising From Wildfire Litigation Costs, including $317 million related to CPUC-regulated operations and $47 million related to FERC-regulated operations, for costs incurred and the estimated settlement of pending claims. However, SDG&E’s cash flow may be materially adversely affected by timing differences between the resolution of claims and recoveries in rates, which may extend over a number of years. In addition, recovery in rates will require future regulatory approval, and a failure to obtain substantial or full recovery, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s financial condition, cash flows and results of operations.

SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of recoveries in rates and will make appropriate adjustments to wildfire reserves and the related regulatory assets as additional information becomes available.

Should SDG&E conclude that recovery of excess wildfire costs in rates is no longer probable, at that time SDG&E will record a charge against earnings. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated, as of December 31, 2012, the resulting after-tax charge against earnings would have been up to $190 million. In addition, in periods following any such conclusion by SDG&E that recovery is no longer probable, Sempra Energy’s and SDG&E’s earnings will be adversely impacted by increases in the estimated costs to litigate or settle pending wildfire claims. We discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements.

We provide additional information concerning these matters in Notes 14 and 15 of the Notes to Consolidated Financial Statements.

SONGS

As a result of the extended outage at SONGS, the CPUC has issued an Order Instituting Investigation (OII) to determine whether SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires that all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account, with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, will be required to be refunded to customers.

Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. For the year ended December 31, 2012, SDG&E has recognized (and collected through customer rates) an estimated $199 million of revenue associated with its 2012 investment in SONGS and related operating costs. Following is a summary of SDG&E’s December 31, 2012 net book investment, excluding any decommissioning-related assets and liabilities, and its rate base investment in SONGS.

SUMMARY OF SDG&E NET BOOK INVESTMENT AND RATE BASE INVESTMENT IN SONGS(1)
(Dollars in millions)
			Unit 2		Unit 3		Common Plant		Total
Net book investment:
	Net property, plant and equipment, including
	construction work in progress	$	152	$	115	$	120	$	387
	Materials and supplies		―		―		10		10
	Nuclear fuel		―		―		115		115
	Net book investment	$	152	$	115	$	245	$	512

Rate base investment		$	103	$	93	$	79	$	275
(1)	Excludes nuclear decommissioning-related assets and liabilities.

If the CPUC were to order SDG&E to remove all or most of the authorized revenue requirement associated with SONGS from customer rates, refund all or most of the revenue from its investment in SONGS charged to customers since January 1, 2012, or remove all or most of SDG&E’s rate base investment in SONGS from its rate base, it would likely have a material adverse effect on Sempra Energy’s and SDG&E’s financial condition, cash flows, results of operations and prospects.

We provide additional information concerning SONGS in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements.

Investment in Wind Farm

In 2011, the CPUC and FERC approved SDG&E’s tax equity investment in a wind farm project. The investment may be made after the project has met all of the conditions precedent set forth in the definitive documents and upon the initiation of commercial operation of the project. The conditions precedent have not yet been met.

OTHER SEMPRA ENERGY MATTERS

We discuss additional potential and expected impacts of the 2012 Tax Act and the 2010 Tax Act on our income tax expense, earnings and cash flows in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” above.

We may be further impacted by depressed and rapidly changing economic conditions. Moreover, the dollar may fluctuate significantly compared to some foreign currencies, especially in Mexico and South America where we have significant operations. We discuss foreign currency rate risk further under “Market Risk – Foreign Currency Rate Risk” below. North American natural gas prices, which affect profitability at Sempra Renewables and Sempra Natural Gas, are currently significantly below Asian and European prices. These factors could, if they remain unchanged, adversely affect profitability. However, management expects that future export capability at Sempra Natural Gas’ Cameron LNG facility would benefit from lower gas prices in North America compared to other regions.

We discuss additional matters that could affect our future performance in Notes 14 and 15 of the Notes to Consolidated Financial Statements.

FINANCIAL DERIVATIVES REFORMS

In July 2010, federal legislation to reform financial markets was enacted that significantly alters how over-the-counter (OTC) derivatives are regulated, which may impact all of our businesses. The law increased regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the U.S. Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users. These requirements could cause our OTC transactions to be more costly and have a material adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products, they could limit the effectiveness of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate.

LITIGATION

We describe legal proceedings which could adversely affect our future performance in Note 15 of the Notes to Consolidated Financial Statements.

CALIFORNIA UTILITIES – INDUSTRY DEVELOPMENTS AND CAPITAL PROJECTS

We describe capital projects, electric and natural gas regulation and rates, and other pending proceedings and investigations that affect the California Utilities in Note 14 of the Notes to Consolidated Financial Statements.

SEMPRA INTERNATIONAL AND SEMPRA U.S. GAS & POWER INVESTMENTS

As we discuss in “Cash Flows From Investing Activities,” our investments will significantly impact our future performance. In addition to the discussion below, we provide information about these investments in “Capital Resources and Liquidity.”

Sempra South American Utilities

Santa Teresa

In May 2011, groundbreaking took place for Santa Teresa, a project at Luz del Sur to build a 98-MW hydroelectric power plant in Peru’s Cusco region. It is planned to be completed in 2014.

Transmission Projects

In May 2012, Chilquinta Energía, in a joint venture with Sociedad Austral de Electricidad Sociedad Anonima (SAESA), was awarded two 220-kilovolt (kV) transmission lines in Chile. The transmission lines will extend 150 miles, and we estimate it will cost the joint venture approximately $150 million and be completed in 2017.

Sempra Mexico

Energía Sierra Juárez

In April 2011, SDG&E entered into a 20-year contract for up to 156 MW of renewable power supplied from the first phase of Sempra Mexico’s Energía Sierra Juárez wind project in Baja California, Mexico. The contract was approved by the CPUC in March 2012 and by the FERC in July 2012. In June 2012, the Comisión Reguladora de Energía (CRE) of Mexico issued a permit for the project, conditioned on approval from the Comisión Federal de Electricidad (CFE). The CFE has issued a negative advisory opinion with respect to the issuance of the permit. We will continue to work with the CRE and CFE to obtain the permit. We expect construction on the project to begin in 2013, and the project to be fully operational in 2014. Delays in obtaining the CRE permit could potentially prevent Energía Sierra Juárez from being operational at the time required by the SDG&E contract, which would permit SDG&E to terminate the contract without penalty. Energía Sierra Juárez has the right to terminate the contract if it is unable to timely obtain the necessary permits.

Sempra Mexico intends to develop the project within the framework of a joint venture, and is working on an agreement for the sale of a 50-percent partnership interest.

Pipeline Projects

In October 2012, Sempra Mexico was awarded two contracts by the CFE to build and operate an approximately 500-mile pipeline network to transport natural gas from the U.S.-Mexico border south of Tucson, Arizona through the Mexican state of Sonora to the northern part of the Mexican state of Sinaloa along the Gulf of California. The network will be comprised of two segments that will interconnect to the U.S. interstate pipeline system. We estimate it will cost approximately $1 billion. The first segment of the project, approximately 300 miles, is expected to be completed by the second half of 2014, and the remaining segment is expected to be completed by the second half of 2016. The capacity is fully contracted by CFE under two 25-year contracts denominated in U.S. dollars. Our ability to secure rights of way and construct the lines within budgeted amounts will impact future performance. A competitor for one of the two contracts filed suit against the CFE contending that the bidding process was not proper, seeking to invalidate the award.

In December 2012, through its joint venture with PEMEX, Sempra Mexico executed an ethane transportation services agreement with PEMEX to construct and operate an approximately 140-mile pipeline to transport ethane from Tabasco, Mexico to Veracruz, Mexico. We estimate it will cost approximately $330 million and be funded by the joint venture from its cash flow from operations without additional capital contributions from the partners. It is expected to be completed in the second half of 2014. The capacity is fully contracted by PEMEX under a 21-year contract denominated in U.S. dollars.

In January 2013, PEMEX announced that the first phase of the Los Ramones project was assigned to and will be developed by our joint venture with PEMEX. The project will consist of a 70-mile natural gas pipeline from the northern portion of the state of Tamaulipas bordering the United States to Los Ramones in the Mexican state of Nuevo León. The specifics of the project are still under negotiations with PEMEX.

Sempra Renewables

Copper Mountain Solar

Copper Mountain Solar is a photovoltaic generation facility operated and under development by Sempra Renewables in Boulder City, Nevada. If fully developed, the project will be capable of producing up to approximately 450 MW of solar power; it is being developed in multiple phases as contracted. Copper Mountain Solar is comprised of three separate projects. Copper Mountain Solar 1 is a 58-MW photovoltaic generation facility currently in operation, and now includes the 10-MW facility previously referred to as El Dorado Solar.

Copper Mountain Solar 2 (CMS 2) began construction in December 2011 and will total 150 MW when completed. CMS 2 is divided into two phases, with the first phase of 92 MW placed in service in November 2012 and the remaining 58 MW planned to be placed in service in 2015. PG&E has contracted for all of the solar power at CMS 2 for 25 years.

Copper Mountain Solar 3 (CMS 3) will begin construction during the first half of 2013 and will total 250 MW when completed. CMS 3 is planned to be placed in service in late 2015. The cities of Los Angeles and Burbank have contracted for all of the solar power at CMS 3 for 20 years.

Mesquite Solar

Mesquite Solar is a photovoltaic generation facility under development by Sempra Renewables in Maricopa County, Arizona. If fully developed, the project will be capable of producing up to approximately 700 MW of solar power. Construction on the first phase (Mesquite Solar 1) of 150 MW began in June 2011 and was completed in December 2012. PG&E has contracted for all of the solar power at Mesquite Solar 1 for 20 years.

Sempra Natural Gas

Natural Gas Storage

Currently, Sempra Natural Gas has 30 Bcf of operational working natural gas storage capacity. We are currently developing another 13 Bcf of capacity with planned in-service dates through 2013 and may, over the long term, develop as much as 76 Bcf of total storage capacity.

Sempra Natural Gas’ natural gas storage facilities and projects include

Bay Gas, a facility located 40 miles north of Mobile, Alabama, that provides underground storage and delivery of natural gas. Sempra Natural Gas owns 91 percent of the project. It is the easternmost salt dome storage facility on the Gulf Coast, with direct service to the Florida market and markets across the Southeast, Mid-Atlantic and Northeast regions.

§	Mississippi Hub, located 45 miles southeast of Jackson, Mississippi, an underground salt dome natural gas storage project with access to shale basins of East Texas and Louisiana, traditional gulf supplies and LNG, with multiple interconnections to serve the Southeast and Northeast regions.

LA Storage, previously referred to as Liberty natural gas storage expansion, a salt cavern development project in Cameron Parish, Louisiana. Sempra Natural Gas owns 75 percent of the project and ProLiance Transportation LLC owns the remaining 25 percent. The project’s location provides access to several LNG facilities in the area.

Cameron LNG

In April and May 2012, Sempra Natural Gas signed commercial development agreements with Mitsubishi Corporation, Mitsui & Co., Ltd., and a subsidiary of GDF SUEZ S.A. to develop a natural gas liquefaction export facility at the site of its Cameron LNG terminal in Hackberry, Louisiana. We discuss these agreements above in “Factors Influencing Future Performance – Sempra Energy Overview.”

MARKET RISK

Market risk is the risk of erosion of our cash flows, earnings, asset values and equity due to adverse changes in market prices, and interest and foreign currency rates.

Risk Policies

Sempra Energy has policies governing its market risk management and trading activities. Sempra Energy and the California Utilities maintain separate and independent risk management committees, organizations and processes for the California Utilities and for all non-CPUC regulated affiliates to provide oversight of these activities. The committees consist of senior officers who establish policy, oversee energy risk management activities, and monitor the results of trading and other activities to ensure compliance with our stated energy risk management and trading policies. These activities include, but are not limited to, daily monitoring of market positions that create credit, liquidity and market risk. The respective oversight organizations and committees are independent from the energy procurement departments.

Along with other tools, we use Value at Risk (VaR) and liquidity metrics to measure our exposure to market risk associated with the commodity portfolios. 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. A liquidity metric is intended to monitor the amount of financial resources needed for meeting potential margin calls as forward market prices move. VaR and liquidity risk metrics are calculated independently by the respective risk management oversight organizations.

The California Utilities use power and natural gas derivatives to manage natural gas and electric price risk associated with servicing load requirements. The use of power and 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 with and approved by the CPUC. Any costs or gains/losses associated with the use of power and natural gas derivatives are considered to be commodity costs. Commodity costs are generally passed on to customers as incurred. However, SoCalGas is subject to incentive mechanisms that reward or penalize the utility for commodity costs below or above certain benchmarks.

In 2010 and early 2011, Sempra Energy and RBS completed the divestiture of substantially all of the businesses and assets of RBS Sempra Commodities, their joint venture partnership, in four separate transactions, as we discuss in Note 4 of the Notes to Consolidated Financial Statements. In connection with each of these transactions, the buyers were, subject to certain qualifications, obligated to replace any guarantees that we had issued in connection with the applicable businesses sold with guarantees of their own. At December 31, 2012, the buyers have substantially completed this process for those counterparties with existing, open positions. For those guarantees which have not been replaced, the buyers are obligated to indemnify us in accordance with the applicable transaction documents for any claims or losses in connection with the guarantees that we issued associated with the businesses sold. We provide additional information in Note 1 of the Notes to Consolidated Financial Statements.

In addition, as a transitional measure, Sempra Energy continues to provide back-up guarantees and credit support for RBS Sempra Commodities, as we discuss above in “Capital Resources and Liquidity” and in Note 5 of the Notes to Consolidated Financial Statements.

We discuss revenue recognition in Notes 1 and 10 of the Notes to Consolidated Financial Statements and the additional market-risk information regarding derivative instruments in Note 10 of the Notes to Consolidated Financial Statements.

We have exposure to changes in commodity prices, interest rates and foreign currency rates and exposure to counterparty nonperformance. The following discussion of these primary market-risk exposures as of December 31, 2012, 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 certain commodities. Our various subsidiaries are exposed, in varying degrees, to price risk, primarily to prices in the natural gas and electricity markets. Our policy is to manage this risk within a framework that considers the unique markets and operating and regulatory environments of each subsidiary.

Segments within our Sempra International and Sempra U.S. Gas & Power operating units are generally exposed to commodity price risk indirectly through their LNG, natural gas pipeline and storage, and power generating assets and their power purchase agreements. Those segments may utilize commodity transactions in the course of optimizing these assets. These transactions are typically priced based on market indices, but may also include fixed price purchases and sales of commodities. Any residual exposure is monitored as described above.

The California Utilities’ market-risk exposure is limited due to CPUC-authorized rate recovery of the costs of commodity purchases, interstate and intrastate transportation, and storage activity. However, SoCalGas may, at times, be exposed to market risk as a result of incentive mechanisms that reward or penalize the utility for commodity costs below or above certain benchmarks for SoCalGas’ Gas Cost Incentive Mechanism, which we discuss in Note 14 of the Notes to Consolidated Financial Statements. If commodity prices were to rise too rapidly, it is likely that volumes would decline. This decline would increase the per-unit fixed costs, which could lead to further volume declines. The California Utilities manage their risk within the parameters of their market risk management framework. As of and for the year ended December 31, 2012, the total VaR of the California Utilities’ natural gas and electric positions was not material, and the procurement activities were in compliance with the procurement plans filed with and approved by the CPUC.

A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of our commodity-based financial derivatives as of December 31, 2012 and 2011. The impact of a change in energy commodity prices on our commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Also, the impact of a change in energy commodity prices on our commodity-based financial derivative instruments does not typically include the generally offsetting impact of our underlying asset positions.

Interest Rate Risk

We are exposed to fluctuations in interest rates primarily as a result of our having issued short- and long-term debt. Subject to regulatory constraints, we periodically enter into interest rate swap agreements to moderate our exposure to interest rate changes and to lower our overall costs of borrowing.

The table below shows the nominal amount and the one-year VaR for long-term debt, excluding commercial paper classified as long-term debt, capital lease obligations and interest rate swaps, and before reductions/increases for unamortized discount/premium, at December 31, 2012 and 2011:

	Sempra Energy
	Consolidated				SDG&E				SoCalGas
	Nominal		One-Year		Nominal		One-Year		Nominal		One-Year
(Dollars in millions)	Debt		VaR(1)		Debt		VaR(1)		Debt		VaR(1)
At December 31, 2012
California Utilities fixed-rate	$	5,203	$	601	$	3,790	$	451	$	1,413	$	150
California Utilities variable-rate		345		14		345		14		―		―
All other, fixed-rate and variable-rate		6,306		302		―		―		―		―
At December 31, 2011
California Utilities fixed-rate	$	4,617	$	782	$	3,304	$	623	$	1,313	$	159
California Utilities variable-rate		591		25		591		25		―		―
All other, fixed-rate and variable-rate		4,602		377		―		―		―		―
(1) After the effects of interest rate swaps.

At December 31, 2012, the total notional amount of interest rate swap transactions ranged from $6 million to $369 million at Sempra Energy and $285 million to $345 million at SDG&E (ranges relate to amortizing notional amounts). We provide further information about interest rate swap transactions in Note 10 of the Notes to Consolidated Financial Statements.

We also are subject to the effect of interest rate fluctuations on the assets of our pension plans, other postretirement benefit plans, and SDG&E’s nuclear decommissioning trusts. However, we expect the effects of these fluctuations, as they relate to the California Utilities, to be passed on to customers.

Credit Risk

Credit risk is the risk of loss that would be incurred as a result of nonperformance of our counterparties’ contractual obligations. We monitor credit risk through a credit-approval process and the assignment and monitoring of credit limits. We establish these credit limits based on risk and return considerations under terms customarily available in the industry.

As with market risk, we have policies governing the management of credit risk that are administered by the respective credit departments for each of the California Utilities and, on a combined basis, for all non-CPUC regulated affiliates and overseen by their separate risk management committees.

This oversight includes calculating current and potential credit risk on a daily basis and monitoring actual balances in comparison to approved limits. We avoid concentration of counterparties whenever possible, and we believe our credit policies significantly reduce overall credit risk. These policies include an evaluation of the following:

§	prospective counterparties’ financial condition (including credit ratings)

§	collateral requirements

§	the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty

§	downgrade triggers

We believe that we have provided adequate reserves for counterparty nonperformance.

When development projects at Sempra International and Sempra U.S. Gas & Power become operational, they rely significantly on the ability of their suppliers to perform on long-term agreements and on our ability to enforce contract terms in the event of nonperformance. Also, the factors that we consider in evaluating a development project include negotiating customer and supplier agreements and, therefore, we rely on these agreements for future performance. We also may base our decision to go forward on development projects on these agreements.

As noted above under “Interest Rate Risk,” we periodically enter into interest rate swap agreements to moderate exposure to interest rate changes and to lower the overall cost of borrowing. We would be exposed to interest rate fluctuations on the underlying debt should a counterparty to the swap fail to perform.

Foreign Currency Rate Risk

We have investments in entities whose functional currency is not the U.S. dollar, exposing us to foreign exchange movements, primarily in Latin American currencies.

The Mexican subsidiaries have U.S. dollar receivables and payables that give rise to foreign exchange movements for Mexican taxes, which are based on financial statements prepared in accordance with accounting principles generally accepted in Mexico. In addition, monetary assets and liabilities are adjusted for inflation for Mexican tax purposes. The fluctuations in foreign currency and inflation are subject to Mexican taxes and may expose us to significant fluctuations in tax expense from changes in the exchange and inflation rates in Mexico.

Our primary objective in reducing foreign currency risk is to preserve the economic value of our overseas investments and to reduce earnings volatility that would otherwise occur due to exchange rate fluctuations. We may offset material cross-currency transactions and net income exposure through various means, including financial instruments and short-term investments. Because we do not hedge our net investment in foreign countries, we are susceptible to volatility in other comprehensive income caused by exchange rate fluctuations.

The hypothetical effects for every one percent appreciation in the U.S. dollar from year-end 2012 levels against the currencies of Latin American countries in which we have operations and investments are as follows:

(Dollars in millions)			Hypothetical Effects
	Translation of 2012 earnings to U.S. dollars	$	(2)
	Transactional exposures		-
	Translation of net assets of foreign subsidiaries and investments in foreign entities		(19)

Although the balances of monetary assets and liabilities at our Mexican subsidiaries may fluctuate significantly throughout the year, based on long-term debt balances with non-Mexican entities of $415 million at December 31, 2012, the hypothetical effect for Sempra Energy for every one percent increase in the Mexican inflation rate is approximately $1 million of additional income tax expense at our Mexican subsidiaries.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, AND KEY NONCASH PERFORMANCE INDICATORS

Management views certain accounting policies as critical because their application is the most relevant, judgmental, and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates.

We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements. We discuss choices among alternative accounting policies that are material to our financial statements and information concerning significant estimates with the audit committee of the Sempra Energy board of directors.

CRITICAL ACCOUNTING POLICIES
SEMPRA ENERGY, SDG&E AND SOCALGAS
CONTINGENCIES
Assumptions & Approach Used		We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and: § information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events, and § the amount of the loss can be reasonably estimated. We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.
Effect if Different Assumptions Used	Details of our issues in this area are discussed in Note 15 of the Notes to Consolidated Financial Statements.
REGULATORY ACCOUNTING
Assumptions & Approach Used		The California Utilities record a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. Similarly, regulatory liabilities are recorded for amounts recovered in rates in advance of the expenditure. The California Utilities review 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 § passage of new legislation To the extent that circumstances associated with regulatory balances change, the regulatory balances are adjusted accordingly.
Effect if Different Assumptions Used	Details of the California Utilities’ regulatory assets and liabilities and additional factors that management considers when assessing probabilities associated with regulatory balances are discussed in Notes 1, 14 and 15 of the Notes to Consolidated Financial Statements.

SEMPRA ENERGY, SDG&E AND SOCALGAS (CONTINUED)
INCOME TAXES
Assumptions & Approach Used		Our 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. When we evaluate the anticipated resolution of income tax issues, we consider § past resolutions of the same or similar issue § the status of any income tax examination in progress § 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 our expectation of future taxable income, based on our strategic planning.
Effect if Different Assumptions Used		Actual income taxes could vary from estimated amounts because of: § future impacts of various items, including changes in tax laws § our financial condition in future periods § the resolution of various income tax issues between us and taxing authorities We discuss details of our issues in this area in Note 7 of the Notes to Consolidated Financial Statements.
Assumptions & Approach Used		For an uncertain position to qualify for benefit recognition, 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 we do not have a more likely than not position with respect to a tax position, then we do not recognize any of the potential tax benefit associated with the position. A tax position that meets the “more likely than not” recognition is 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.
Effect if Different Assumptions Used		Unrecognized tax benefits involve management’s 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 our results of operations, financial position and cash flows. We discuss additional information related to accounting for uncertainty in income taxes in Note 7 of the Notes to Consolidated Financial Statements.

SEMPRA ENERGY, SDG&E AND SOCALGAS (CONTINUED)
DERIVATIVES
Assumptions & Approach Used	We value 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. We also use normal purchase or sale accounting for certain contracts. As discussed elsewhere in this report, whenever possible, we use exchange quotations or other third-party pricing to estimate fair values; if no such data is available, we use internally developed models and other techniques. The assumed collectability of derivative assets and receivables considers § events specific to a given counterparty § the tenor of the transaction § the credit-worthiness of the counterparty
Effect if Different Assumptions Used	The application of hedge accounting to certain derivatives and the normal purchase or sale accounting election is made on a contract-by-contract basis. Using hedge accounting or the normal purchase or sale election in a different manner could materially impact Sempra Energy’s results of operations. However, such alternatives would not have a significant impact on the California Utilities’ results of operations because of regulatory accounting principles. We provide details of our financial instruments in Note 10 of the Notes to Consolidated Financial Statements.
DEFINED BENEFIT PLANS
Assumptions & Approach Used		To measure our pension and postretirement obligations, costs and liabilities, we rely on several assumptions. We consider current market conditions, including interest rates, in making these assumptions. We annually review these assumptions prior to the beginning of each year and update when appropriate. The critical assumptions used to develop the required estimates include the following key factors: § discount rates § expected return on plan assets § health care cost trend rates § mortality rates § rate of compensation increases § termination and retirement rates § utilization of postretirement welfare benefits § payout elections (lump sum or annuity) § lump sum interest rates

SEMPRA ENERGY, SDG&E AND SOCALGAS (CONTINUED)
DEFINED BENEFIT PLANS (CONTINUED)
Effect if Different Assumptions Used		The actuarial assumptions we use may differ materially from actual results due to: § return on plan assets § changing market and economic conditions § higher or lower withdrawal rates § longer or shorter participant life spans § more or fewer lump sum versus annuity payout elections made by plan participants § retirement rates These differences, other than those related to the California Utilities’ plans, where rate recovery offsets any effects of the assumptions on earnings, may result in a significant impact to the amount of pension and postretirement benefit expense we record. For the remaining plans, the approximate annual effect on earnings of a 25 basis point increase or decrease in the assumed discount rate would be less than $1 million and the effect of a 25 basis point increase or decrease in the assumed rate of return on plan assets would be less than $1 million. We provide additional information, including the impact of increases and decreases in the health care cost trend rate, in Note 8 of the Notes to Consolidated Financial Statements.

SEMPRA ENERGY AND SDG&E
ASSET RETIREMENT OBLIGATIONS
Assumptions & Approach Used	SDG&E’s legal asset retirement obligations (AROs) related to the decommissioning of SONGS are recorded at fair value based on a site specific study performed every three years. The fair value of the obligations includes § estimated decommissioning costs, including labor, equipment, material and other disposal costs § inflation adjustment applied to estimated cash flows § discount rate based on a credit-adjusted risk-free rate § expected date of decommissioning
Effect if Different Assumptions Used		Changes in the estimated decommissioning costs, or in the assumptions and judgments made by management underlying these estimates, could cause revisions to the estimated total cost associated with retiring the assets. Due to regulatory recovery of SDG&E’s nuclear decommissioning expense, rate-making accounting treatment is applied to SDG&E’s nuclear decommissioning activities, so they have no impact on SDG&E’s reported earnings. We provide additional detail in Note 6 of the Notes to the Consolidated Financial Statements.

SEMPRA ENERGY
IMPAIRMENT TESTING OF LONG-LIVED ASSETS
Assumptions & Approach Used	Whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable, we consider if the estimated future undiscounted cash flows are less than the carrying amount of the assets. If so, we estimate the fair value of these assets to determine the extent to which cost exceeds fair value. For these estimates, we may consider data from multiple valuation methods, including data from market participants. We exercise judgment to estimate the future cash flows and the useful lives of long-lived assets and to determine our intent to use the assets. Our intent to use or dispose of assets is subject to re-evaluation and can change over time.
Effect if Different Assumptions Used	If an impairment test is required, the fair value of long-lived assets can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. We discuss impairment of long-lived assets in Note 1 of the Notes to Consolidated Financial Statements.
IMPAIRMENT TESTING OF GOODWILL
Assumptions & Approach Used		On an annual basis or whenever events or changes in circumstances necessitate an evaluation, we consider whether goodwill may be impaired. For our annual goodwill impairment testing, we have the option to first make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step, quantitative goodwill impairment test. We evaluate relevant events and circumstances to decide whether to perform the qualitative assessment or to proceed directly to the two-step, quantitative goodwill impairment test. When we perform the two-step, quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and the corresponding goodwill. Our fair value estimates are developed from the perspective of a knowledgeable market participant. In the absence of observable transactions in the marketplace for similar investments, we consider an income-based approach such as discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include § consideration of market transactions § future cash flows § the appropriate risk-adjusted discount rate § country risk § entity risk
Effect if Different Assumptions Used		When we choose to make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the two-step, quantitative goodwill impairment test is not required if we determine that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount. When we determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount or when we choose to proceed directly to the two-step, quantitative goodwill impairment test, the test requires us to first determine if the carrying value of a reporting unit exceeds its fair value and if so, to measure the amount of goodwill impairment, if any. When determining if goodwill is impaired, the fair value of the reporting unit and goodwill can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. As a result, recognizing a goodwill impairment may or may not be required. Sempra Energy added $975 million in goodwill to its Consolidated Balance Sheet in 2011. The estimated fair values of the reporting units to which this goodwill was allocated substantially exceeded their carrying values as of October 1, 2012, our most recent goodwill impairment testing date. We discuss goodwill in Notes 1 and 3 of the Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CARRYING VALUE OF EQUITY METHOD INVESTMENTS
Assumptions & Approach Used		We generally account for investments under the equity method when we have an ownership interest of 20 to 50 percent. The premium, or excess cost over the underlying carrying value of net assets, is referred to as equity method goodwill, which is included in the impairment testing of the equity method investment. We consider whether the fair value of each equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. To help evaluate whether a decline in fair value below cost has occurred and if the decline is other than temporary, we may develop fair value estimates for the investment. Our fair value estimates are developed from the perspective of a knowledgeable market participant. In the absence of observable transactions in the marketplace for similar investments, we consider an income-based approach such as discounted cash flow analysis or, with less weighting, the replacement cost of the underlying net assets. A discounted cash flow analysis may be based directly on anticipated future distributions from the investment, or may be performed based on free cash flows generated within the entity and adjusted for our ownership share total. When calculating estimates of fair or realizable values, we also consider whether we intend to hold or sell the investment. For certain held investments, critical assumptions may include § equity sale offer price for the investment § transportation rates for natural gas § the appropriate risk-adjusted discount rate § the availability and costs of natural gas § competing fuels (primarily propane) and electricity For investments that we hold for sale, such as our Argentine investments, we consider comparable sales values, executed sales transactions or indications of value determined by cash and affiliate receivables within the entity when determining our estimates of fair value.
Effect if Different Assumptions Used		The risk assumptions applied by other market participants to value the investments could vary significantly or the appropriate approaches could be weighted differently. These differences could impact whether or not the fair value of the investment is less than its cost, and if so, whether that condition is other than temporary. This could result in an impairment charge or a different amount of impairment charge, and, in cases where an impairment charge has been recorded, additional loss or gain upon sale. We provide additional details in Note 4 of the Notes to Consolidated Financial Statements.

KEY NONCASH PERFORMANCE INDICATORS

A discussion of key noncash performance indicators related to each segment follows:

California Utilities

Key noncash performance indicators include number of customers, and natural gas volumes and electricity sold. Additional noncash performance indicators include goals related to safety, customer service, customer reputation, environmental considerations, on-time and on-budget completion of major projects and initiatives, and in the case of SDG&E, electric reliability. We discuss natural gas volumes and electricity sold in “Results of Operations – Changes in Revenues, Costs and Earnings” above.

Sempra South American Utilities

Key noncash performance indicators for our South American distribution operations are customer count and consumption. We discuss these above in “Our Business.” Additional noncash performance indicators include goals related to safety, environmental considerations, and regulatory compliance.

Sempra Mexico

Key noncash performance indicators for Sempra Mexico include natural gas sales volume, facility availability, capacity utilization and, for its distribution operations, customer count and consumption. Additional noncash performance indicators include goals related to safety, environmental considerations and regulatory performance. We discuss these above in “Our Business.”

Sempra Natural Gas

Key noncash performance indicators at Sempra Natural Gas include natural gas sales volume, facility availability, capacity utilization and, for its distribution operations, customer count and consumption. Additional noncash performance indicators include goals related to safety, environmental considerations and regulatory compliance. We discuss these above in “Our Business.”

Electric Generation Facilities (Sempra Mexico, Sempra Renewables and Sempra Natural Gas)

Key noncash performance indicators include plant availability factors and sales volume at our renewable energy facilities and natural gas-fired generating plants. For competitive reasons, we do not disclose plant availability factors. We discuss these above in “Our Business” and “Factors Influencing Future Performance.” Additional noncash performance indicators include goals related to safety, environmental considerations, and compliance with reliability standards.

LNG Facilities (Sempra Mexico and Sempra Natural Gas)

At our LNG terminals, key noncash performance indicators include plant availability and capacity utilization. We discuss these above in “Our Business” and “Factors Influencing Future Performance.” Additional noncash performance indicators include goals related to safety, environmental considerations, regulatory compliance, and on-time and on-budget completion of development projects.

NEW ACCOUNTING STANDARDS

We discuss the relevant pronouncements that have recently become effective and have had or may have a significant effect on our financial statements in Note 2 of the Notes to Consolidated Financial Statements.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

Factors, among others, that could cause our actual results and future actions to differ materially from those described in forward-looking statements include

§	local, regional, national and international economic, competitive, political, legislative and regulatory conditions and developments;

§	capital markets conditions, including the availability of credit and the liquidity of our investments;

§	inflation, interest and exchange rates;

§	the impact of benchmark interest rates, generally U.S. Treasury bond and Moody’s A-rated utility bond yields, on our California Utilities’ cost of capital;

§	the timing and success of business development efforts and construction, maintenance and capital projects, including risks inherent in the ability to obtain, and the timing of granting of, permits, licenses, certificates and other authorizations;

§	energy markets, including the timing and extent of changes and volatility in commodity prices;

§	the availability of electric power, natural gas and liquefied natural gas, including disruptions caused by failures in the North American transmission grid, pipeline explosions and equipment failures;

§	weather conditions, natural disasters, catastrophic accidents, and conservation efforts;

§	risks inherent in nuclear power generation and radioactive materials storage, including the catastrophic release of such materials, the disallowance of the recovery of the investment in or operating costs of the generation facility due to an extended outage, and increased regulatory oversight;

§	risks posed by decisions and actions of third parties who control the operations of investments in which we do not have a controlling interest;

§	wars, terrorist attacks and cybersecurity threats;

§	business, regulatory, environmental and legal decisions and requirements;

§	expropriation of assets by foreign governments and title and other property disputes;

§	the status of deregulation of retail natural gas and electricity delivery;

§	the inability or determination not to enter into long-term supply and sales agreements or long-term firm capacity agreements;

§	the resolution of litigation; and

§	other uncertainties, all of which are difficult to predict and many of which are beyond our control.

We caution you not to rely unduly on any forward-looking statements. You should review and consider carefully the risks, uncertainties and other factors that affect our business as described herein and in our Annual Report on Form 10-K and other reports that we file with the Securities and Exchange Commission.

COMMON STOCK DATA

SEMPRA ENERGY COMMON STOCK

Our common stock is traded on the New York Stock Exchange. At February 22, 2013, there were approximately 35,400 record holders of our common stock.

The following table shows Sempra Energy quarterly common stock data:

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
2012
Market price
High	$	60.36	$	69.46	$	72.32	$	72.87
Low	$	54.70	$	60.04	$	63.87	$	64.47

2011
Market price
High	$	54.44	$	55.97	$	53.76	$	55.61
Low	$	50.32	$	51.53	$	44.78	$	48.38

We declared dividends of $0.60 per share and $0.48 per share in each quarter of 2012 and 2011, respectively. On February 22, 2013, our board of directors approved an increase to our quarterly common stock dividend to $0.63 per share ($2.52 annually), an increase of $0.03 per share ($0.12 annually) from $0.60 per share ($2.40 annually) authorized in February 2012.

SOCALGAS AND SDG&E COMMON STOCK

Pacific Enterprises (PE), a wholly owned subsidiary of Sempra Energy, owns all of SoCalGas’ outstanding common stock. Enova Corporation, a wholly owned subsidiary of Sempra Energy, owns all of SDG&E’s issued and outstanding common stock.

Information concerning dividend declarations for SoCalGas and SDG&E is included in their Statement of Changes in Shareholders’ Equity and Statement of Changes in Equity, respectively, set forth in the Consolidated Financial Statements.

DIVIDEND RESTRICTIONS

The payment and the amount of future dividends for Sempra Energy, SDG&E, and SoCalGas are within the discretion of their boards of directors. The CPUC’s regulation of the California Utilities’ capital structures limits the amounts that the California Utilities can pay us in the form of loans and dividends. We discuss these matters in Note 1 of the Notes to the Consolidated Financial Statements under “Restricted Net Assets” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” in the “Overview – California Utilities,” “Overview – Sempra Energy Consolidated” and “Dividends” sections.

PERFORMANCE GRAPH -- COMPARATIVE TOTAL SHAREHOLDER RETURNS

The following graph (Figure 2) compares the percentage change in the cumulative total shareholder return on Sempra Energy common stock for the five-year period ending December 31, 2012, with the performance over the same period of the Standard & Poor’s (S&P) 500 Index and the Standard & Poor’s 500 Utilities Index.

These returns were calculated assuming an initial investment of $100 in our common stock, the S&P 500 Index and the S&P 500 Utilities Index on December 31, 2007, and the reinvestment of all dividends.

[I002.GIF]

Figure 2: Comparison of Cumulative Five-Year Total Return

FIVE-YEAR SUMMARIES

The following tables present selected financial data of Sempra Energy, SDG&E and SoCalGas for the five years ended December 31, 2012. The data is derived from the audited consolidated financial statements of each company. You should read this information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes contained in this Annual Report.

FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA FOR SEMPRA ENERGY
(In millions, except for per share amounts)
	At December 31 or for the years then ended
	2012			2011			2010			2009			2008
Sempra Energy Consolidated
Revenues
Utilities:
Natural gas	$	3,873		$	4,489		$	4,491		$	4,002		$	5,573
Electric		4,568			3,833			2,528			2,419			2,553
Energy-related businesses		1,206			1,714			1,984			1,685			2,632
Total revenues	$	9,647		$	10,036		$	9,003		$	8,106		$	10,758

Income from continuing operations	$	920		$	1,381		$	703		$	1,122		$	1,061
(Earnings) losses from continuing operations attributable
to noncontrolling interests		(55)			(42)			16			7			55
Preferred dividends of subsidiaries		(6)			(8)			(10)			(10)			(10)
Earnings/Income from continuing operations attributable
to common shares	$	859		$	1,331		$	709		$	1,119		$	1,106

Attributable to common shares:
Earnings/Income from continuing operations
Basic	$	3.56		$	5.55		$	2.90		$	4.60		$	4.47
Diluted	$	3.48		$	5.51		$	2.86		$	4.52		$	4.40

Dividends declared per common share	$	2.40		$	1.92		$	1.56		$	1.56		$	1.37
Return on common equity		8.6	%		14.2	%		7.9	%		13.2	%		13.6	%
Effective income tax rate		6	%		23	%		17	%		29	%		31	%
Price range of common shares:
High	$	72.87		$	55.97		$	56.61		$	57.18		$	63.00
Low	$	54.70		$	44.78		$	43.91		$	36.43		$	34.29

Weighted average rate base:
SoCalGas	$	3,178		$	2,948		$	2,860		$	2,758		$	2,702
SDG&E	$	6,295		$	5,071		$	4,697		$	4,362		$	4,050

AT DECEMBER 31
Current assets	$	3,695		$	2,332		$	3,363		$	2,296		$	2,476
Total assets	$	36,499		$	33,249		$	30,231		$	28,501		$	26,389
Current liabilities	$	4,258		$	4,152		$	3,786		$	3,887		$	3,612
Long-term debt (excludes current portion)	$	11,621		$	10,078		$	8,980		$	7,460		$	6,544
Short-term debt(1)	$	1,271		$	785		$	507		$	1,191		$	913
Contingently redeemable preferred stock of subsidiary	$	79		$	79		$	79		$	79		$	79
Sempra Energy shareholders’ equity	$	10,282		$	9,775		$	8,990		$	9,000		$	7,962
Common shares outstanding		242.4			239.9			240.4			246.5			243.3
Book value per share	$	42.43		$	40.74		$	37.39		$	36.51		$	32.72
(1) Includes long-term debt due within one year.

We discuss the impact of natural gas prices on revenues in 2012, 2011 and 2010 and the changes in our effective income tax rate in 2012 and 2011 in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Changes in Revenues, Costs and Earnings.”

On April 6, 2011, we increased our interests in two South American utilities, which are now consolidated. Prior to the acquisition, we accounted for our investments in these entities as equity method investments. On April 30, 2010, we completed an acquisition resulting in the purchase of Mexican pipeline and natural gas infrastructure. We discuss these acquisitions in Note 3 of the Notes to Consolidated Financial Statements.

On April 1, 2008, we sold our commodities-marketing businesses into a joint venture, and began accounting for these businesses under the equity method. In 2010 and early 2011, we and RBS sold substantially all of the businesses and assets of the joint venture. We discuss these transactions further in Notes 3 and 4 of the Notes to Consolidated Financial Statements.

We discuss litigation and other contingencies in Note 15 of the Notes to Consolidated Financial Statements.

FIVE-YEAR SUMMARIES OF SELECTED FINANCIAL DATA FOR SDG&E AND SOCALGAS
(Dollars in millions)
	At December 31 or for the years then ended
	2012		2011		2010		2009		2008
SDG&E
Statement of Operations Data:
Operating revenues	$	3,694	$	3,373	$	3,049	$	2,916	$	3,251
Operating income		809		755		657		589		570
Dividends on preferred stock		5		5		5		5		5
Earnings attributable to common shares		484		431		369		344		339

Balance Sheet Data:
Total assets	$	14,744	$	13,555	$	12,077	$	10,229	$	9,079
Long-term debt (excludes current portion)		4,292		4,058		3,479		2,623		2,142
Short-term debt(1)		16		19		19		78		2
Contingently redeemable preferred stock		79		79		79		79		79
SDG&E shareholder's equity		4,222		3,739		3,108		2,739		2,542
SoCalGas
Statement of Operations Data:
Operating revenues	$	3,282	$	3,816	$	3,822	$	3,355	$	4,768
Operating income		420		486		516		476		434
Dividends on preferred stock		1		1		1		1		1
Earnings attributable to common shares		289		287		286		273		244

Balance Sheet Data:
Total assets	$	9,071	$	8,475	$	7,986	$	7,287	$	7,351
Long-term debt (excludes current portion)		1,409		1,064		1,320		1,283		1,270
Short-term debt(1)		4		257		262		11		100
SoCalGas shareholders’ equity		2,235		2,193		1,955		1,766		1,490
(1) Includes long-term debt due within one year.

CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

SEMPRA ENERGY, SDG&E, SOCALGAS

Sempra Energy, SDG&E and SoCalGas have designed and maintain disclosure controls and procedures to ensure that information required to be disclosed in their respective reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the management of each company, including each respective Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures.

Under the supervision and with the participation of management, including the Chief Executive Officers and Chief Financial Officers of Sempra Energy, SDG&E and SoCalGas, each company evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of December 31, 2012, the end of the period covered by this report. Based on these evaluations, the Chief Executive Officers and Chief Financial Officers of Sempra Energy, SDG&E and SoCalGas concluded that their respective company’s disclosure controls and procedures were effective at the reasonable assurance level.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

SEMPRA ENERGY, SDG&E, SOCALGAS

The respective management of each company 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 the management of each company, including each company’s principal executive officer and principal financial officer, the effectiveness of each company’s internal control over financial reporting was evaluated based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluations, each company concluded that its internal control over financial reporting was effective as of December 31, 2012. Deloitte & Touche, LLP audited the effectiveness of each company’s internal control over financial reporting as of December 31, 2012, as stated in their reports, which are included in this Annual Report.

There have been no changes in the companies’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the companies’ internal control over financial reporting.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not applicable.

REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

SEMPRA ENERGY

To the Board of Directors and Shareholders of Sempra Energy:

We have audited the internal control over financial reporting of Sempra Energy and subsidiaries (the “Company”) as of December 31, 2012, 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, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Company and our report dated February 26, 2013 expressed an unqualified opinion on those financial statements.

/S/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2013

To the Board of Directors and Shareholders of Sempra Energy:

We have audited the accompanying consolidated balance sheets of Sempra Energy and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. 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 Sempra Energy and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

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, 2012, 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 26, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/S/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2013

SAN DIEGO GAS & ELECTRIC COMPANY

To the Board of Directors and Shareholders of San Diego Gas & Electric Company:

We have audited the internal control over financial reporting of San Diego Gas & Electric Company (the “Company”) as of December 31, 2012, 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.

/S/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2013

To the Board of Directors and Shareholders of San Diego Gas & Electric Company:

We have audited the accompanying consolidated balance sheets of San Diego Gas & Electric Company (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of San Diego Gas & Electric Company as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

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, 2012, 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 26, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/S/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2013

SOUTHERN CALIFORNIA GAS COMPANY

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, 2012, 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.

/S/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2013

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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. 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.

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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

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, 2012, 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 26, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/S/ DELOITTE & TOUCHE LLP

San Diego, California

February 26, 2013

SEMPRA ENERGY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)
	Years ended December 31,
	2012		2011		2010

REVENUES
Utilities	$	8,441	$	8,322	$	7,019
Energy-related businesses		1,206		1,714		1,984
Total revenues		9,647		10,036		9,003
EXPENSES AND OTHER INCOME
Utilities:
Cost of natural gas		(1,290)		(1,866)		(2,012)
Cost of electric fuel and purchased power		(1,760)		(1,397)		(637)
Energy-related businesses:
Cost of natural gas, electric fuel and purchased power		(481)		(746)		(1,046)
Other cost of sales		(159)		(137)		(88)
Litigation expense		(26)		(37)		(169)
Other operation and maintenance		(2,923)		(2,788)		(2,499)
Depreciation and amortization		(1,090)		(976)		(866)
Franchise fees and other taxes		(359)		(343)		(327)
Equity earnings (losses), before income tax:
RBS Sempra Commodities LLP		―		(24)		(314)
Rockies Express Pipeline LLC		(312)		43		43
Other		(7)		(10)		(21)
Remeasurement of equity method investments		―		277		―
Other income, net		172		130		140
Interest income		24		26		16
Interest expense		(493)		(465)		(436)
Income before income taxes and equity earnings
of certain unconsolidated subsidiaries		943		1,723		787
Income tax expense		(59)		(394)		(133)
Equity earnings, net of income tax		36		52		49
Net income		920		1,381		703
(Earnings) losses attributable to noncontrolling interests		(55)		(42)		16
Preferred dividends of subsidiaries		(6)		(8)		(10)
Earnings	$	859	$	1,331	$	709


Basic earnings per common share	$	3.56	$	5.55	$	2.90
Weighted-average number of shares outstanding, basic (thousands)		241,347		239,720		244,736

Diluted earnings per common share	$	3.48	$	5.51	$	2.86
Weighted-average number of shares outstanding, diluted (thousands)		246,693		241,523		247,942

Dividends declared per share of common stock	$	2.40	$	1.92	$	1.56
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
		Years ended December 31, 2012, 2011 and 2010
		Sempra Energy Shareholders' Equity
		Pretax		Income Tax		Net-of-Tax		Noncontrolling
		Amount(1)		(Expense) Benefit		Amount		Interests (After-Tax)		Total
2012:
Net income		$	865			$	865	$	55	$	920
Other comprehensive income (loss):
Foreign currency translation adjustments			119	$	―		119		15		134
Pension and other postretirement benefits			(4)		2		(2)		―		(2)
Financial instruments			(6)		2		(4)		(11)		(15)
Total other comprehensive income			109		4		113		4		117
Total comprehensive income			974		4		978		59		1,037
Preferred dividends of subsidiaries			(6)		―		(6)		―		(6)
Total comprehensive income, after preferred
dividends of subsidiaries		$	968	$	4	$	972	$	59	$	1,031
2011:
Net income		$	1,339			$	1,339	$	42	$	1,381
Other comprehensive income (loss):
Foreign currency translation adjustments			(79)	$	3		(76)		6		(70)
Reclassification to net income of foreign
currency translation adjustment related
to remeasurement of equity method
investments			(54)		―		(54)		―		(54)
Available-for-sale securities			(2)		1		(1)		―		(1)
Pension and other postretirement benefits			(20)		8		(12)		―		(12)
Financial instruments			(26)		10		(16)		(36)		(52)
Total other comprehensive income (loss)			(181)		22		(159)		(30)		(189)
Total comprehensive income			1,158		22		1,180		12		1,192
Preferred dividends of subsidiaries			(8)		―		(8)		―		(8)
Total comprehensive income, after preferred
dividends of subsidiaries		$	1,150	$	22	$	1,172	$	12	$	1,184
2010:
Net income (loss)		$	719			$	719	$	(16)	$	703
Other comprehensive income (loss):
Foreign currency translation adjustments			47	$	―		47		―		47
Available-for-sale securities			(10)		2		(8)		―		(8)
Pension and other postretirement benefits			23		(10)		13		―		13
Financial instruments			(22)		9		(13)		7		(6)
Total other comprehensive income			38		1		39		7		46
Total comprehensive income (loss)			757		1		758		(9)		749
Preferred dividends of subsidiaries			(10)		―		(10)		―		(10)
Total comprehensive income (loss), after
preferred dividends of subsidiaries		$	747	$	1	$	748	$	(9)	$	739
(1)	Except for Net Income (Loss) and Total Comprehensive Income (Loss).
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,		December 31,
	2012		2011
ASSETS
Current assets:
Cash and cash equivalents	$	475	$	252
Restricted cash		46		24
Trade accounts receivable, net		1,146		1,198
Other accounts and notes receivable, net		153		147
Income taxes receivable		56		―
Deferred income taxes		148		―
Inventories		408		346
Regulatory balancing accounts – undercollected		395		38
Regulatory assets		62		89
Fixed-price contracts and other derivatives		95		85
U.S. Treasury grants receivable		258		―
Asset held for sale, power plant		296		―
Settlements receivable related to wildfire litigation		5		10
Other		152		143
Total current assets		3,695		2,332

Investments and other assets:
Restricted cash		22		22
Regulatory assets arising from pension and other postretirement
benefit obligations		1,151		1,126
Regulatory assets arising from wildfire litigation costs		364		594
Other regulatory assets		1,227		1,060
Nuclear decommissioning trusts		908		804
Investments		1,516		1,671
Goodwill		1,111		1,036
Other intangible assets		436		448
Sundry		878		691
Total investments and other assets		7,613		7,452

Property, plant and equipment:
Property, plant and equipment		33,528		31,192
Less accumulated depreciation and amortization		(8,337)		(7,727)
Property, plant and equipment, net ($466 and $494 at December 31, 2012 and
2011, respectively, related to VIE)		25,191		23,465
Total assets	$	36,499	$	33,249
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,		December 31,
	2012		2011
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$	546	$	449
Accounts payable – trade		976		983
Accounts payable – other		134		124
Income taxes payable		―		5
Deferred income taxes		―		173
Dividends and interest payable		266		219
Accrued compensation and benefits		337		323
Regulatory balancing accounts – overcollected		141		105
Current portion of long-term debt		725		336
Fixed-price contracts and other derivatives		77		92
Customer deposits		143		142
Reserve for wildfire litigation		305		586
Other		608		615
Total current liabilities		4,258		4,152
Long-term debt ($335 and $345 at December 31, 2012 and 2011, respectively,
related to VIE)		11,621		10,078

Deferred credits and other liabilities:
Customer advances for construction		144		142
Pension and other postretirement benefit obligations, net of plan assets		1,456		1,423
Deferred income taxes		2,100		1,520
Deferred investment tax credits		46		49
Regulatory liabilities arising from removal obligations		2,720		2,551
Asset retirement obligations		2,033		1,905
Other regulatory liabilities		1		87
Fixed-price contracts and other derivatives		252		301
Reserve for wildfire litigation		22		10
Deferred credits and other		1,084		774
Total deferred credits and other liabilities		9,858		8,762
Contingently redeemable preferred stock of subsidiary		79		79

Commitments and contingencies (Note 15)

Equity:
Preferred stock (50 million shares authorized; none issued)		―		―
Common stock (750 million shares authorized; 242 million and 240 million
shares outstanding at December 31, 2012 and 2011, respectively; no par value)		2,217		2,104
Retained earnings		8,441		8,162
Deferred compensation		―		(2)
Accumulated other comprehensive income (loss)		(376)		(489)
Total Sempra Energy shareholders’ equity		10,282		9,775
Preferred stock of subsidiary		20		20
Other noncontrolling interests		381		383
Total equity		10,683		10,178
Total liabilities and equity	$	36,499	$	33,249
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	920	$	1,381	$	703
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization		1,090		976		866
Deferred income taxes and investment tax credits		(43)		3		37
Equity losses (earnings)		324		(61)		243
Remeasurement of equity method investments		―		(277)		―
Fixed-price contracts and other derivatives		(26)		2		13
Other		34		(15)		(55)
Net change in other working capital components		(630)		(224)		100
Distributions from RBS Sempra Commodities LLP		―		53		198
Changes in other assets		219		34		54
Changes in other liabilities		130		(5)		(5)
Net cash provided by operating activities		2,018		1,867		2,154

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(2,956)		(2,844)		(2,062)
Proceeds from sale of assets and investments		74		2		303
Expenditures for investments and acquisition of businesses,
net of cash acquired		(445)		(941)		(611)
Distributions from RBS Sempra Commodities LLP		―		570		849
Distributions from other investments		207		64		371
Purchases of nuclear decommissioning and other trust assets		(738)		(755)		(371)
Proceeds from sales by nuclear decommissioning and other trusts		733		753		372
Decrease in restricted cash		196		653		195
Increase in restricted cash		(218)		(541)		(318)
Other		(11)		(31)		(11)
Net cash used in investing activities		(3,158)		(3,070)		(1,283)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(550)		(440)		(364)
Redemption of subsidiary preferred stock		―		(80)		―
Preferred dividends paid by subsidiaries		(6)		(8)		(10)
Issuances of common stock		78		28		40
Repurchases of common stock		(16)		(18)		(502)
Issuances of debt (maturities greater than 90 days)		3,097		2,098		1,125
Payments on debt (maturities greater than 90 days)		(1,112)		(482)		(905)
(Decrease) increase in short-term debt, net		(47)		(498)		568
Purchase of noncontrolling interests		(7)		(43)		―
Distributions to noncontrolling interests		(61)		(16)		(24)
Other		(21)		(7)		3
Net cash provided by (used in) financing activities		1,355		534		(69)

Effect of exchange rate changes on cash and cash equivalents		8		9		―

Increase (decrease) in cash and cash equivalents		223		(660)		802
Cash and cash equivalents, January 1		252		912		110
Cash and cash equivalents, December 31	$	475	$	252	$	912
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
		Years ended December 31,
		2012		2011		2010
CHANGES IN OTHER WORKING CAPITAL COMPONENTS
(Excluding cash and cash equivalents, and debt due within one year)
Accounts and notes receivable		$	36	$	(32)	$	89
Income taxes, net			(29)		269		12
Inventories			(78)		(84)		(62)
Regulatory balancing accounts			(291)		(150)		(155)
Regulatory assets and liabilities			(6)		(2)		6
Other current assets			180		295		310
Accounts and notes payable			3		60		79
Other current liabilities			(445)		(580)		(179)
Net change in other working capital components		$	(630)	$	(224)	$	100

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized		$	458	$	440	$	415
Income tax payments, net of refunds			130		144		68

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Acquisition of businesses:
Assets acquired		$	29	$	2,833	$	303
Cash paid, net of cash acquired			(19)		(611)		(292)
Fair value of equity method investments immediately prior to the acquisition			―		(882)		―
Fair value of noncontrolling interests			―		(279)		―
Additional consideration accrued			―		(32)		―
Liabilities assumed		$	10	$	1,029	$	11


Accrued capital expenditures		$	357	$	368	$	341
U.S. Treasury grants receivable(1)			213		―		―
Return of investment (industrial development bonds)			―		180		―
Increase in capital lease obligations for investments in property, plant and equipment			3		―		192

SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
Dividends declared but not paid		$	150	$	120	$	96
Cancellation of debt (industrial development bonds)			―		180		―
Conversion of debt into equity			―		30		―
(1)	Cash grants, excluding $45 million previously recorded in 2011 as investment tax credits.
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Dollars in millions)
	Years ended December 31, 2012, 2011 and 2010
					Deferred
					Compen-		Accumulated
					sation		Other		Sempra
					Relating		Compre-		Energy		Non-
	Common		Retained		to		hensive		Shareholders’		controlling		Total
	Stock		Earnings		ESOP		Income (Loss)		Equity		Interests		Equity
Balance at December 31, 2009	$	2,418	$	6,964	$	(13)	$	(369)	$	9,000	$	244	$	9,244

Net income (loss)				719						719		(16)		703
Other comprehensive income								39		39		7		46

Share-based compensation expense		38								38				38
Common stock dividends declared				(381)						(381)				(381)
Preferred dividends of subsidiaries				(10)						(10)				(10)
Issuance of common stock		64								64				64
Tax benefit related to share-based
compensation		5								5				5
Repurchases of common stock		(502)								(502)				(502)
Common stock released from ESOP		13				5				18				18
Distributions to noncontrolling interests												(24)		(24)
Balance at December 31, 2010		2,036		7,292		(8)		(330)		8,990		211		9,201

Net income				1,339						1,339		42		1,381
Other comprehensive loss								(159)		(159)		(30)		(189)

Share-based compensation expense		48								48				48
Common stock dividends declared				(461)						(461)				(461)
Preferred dividends of subsidiaries				(8)						(8)				(8)
Issuance of common stock		28								28				28
Repurchases of common stock		(18)								(18)				(18)
Common stock released from ESOP		14				6				20				20
Distributions to noncontrolling interests												(16)		(16)
Equity contributed by noncontrolling interests												36		36
Acquisition of South American entities												279		279
Purchase of noncontrolling interests in
subsidiary		(4)								(4)		(39)		(43)
Redemption of preferred stock of subsidiary												(80)		(80)
Balance at December 31, 2011	$	2,104	$	8,162	$	(2)	$	(489)	$	9,775	$	403	$	10,178
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (CONTINUED)
(Dollars in millions)
	Years ended December 31, 2012, 2011 and 2010
					Deferred
					Compen-		Accumulated
					sation		Other		Sempra
					Relating		Compre-		Energy		Non-
	Common		Retained		to		hensive		Shareholders’		controlling		Total
	Stock		Earnings		ESOP		Income (Loss)		Equity		Interests		Equity
Balance at December 31, 2011	$	2,104	$	8,162	$	(2)	$	(489)	$	9,775	$	403	$	10,178

Net income				865						865		55		920
Other comprehensive income								113		113		4		117

Share-based compensation expense		44								44				44
Common stock dividends declared				(580)						(580)				(580)
Preferred dividends of subsidiaries				(6)						(6)				(6)
Issuance of common stock		78								78				78
Repurchases of common stock		(16)								(16)				(16)
Common stock released from ESOP		7				2				9				9
Distributions to noncontrolling interests												(62)		(62)
Equity contributed by noncontrolling interests												8		8
Purchase of noncontrolling interest in
subsidiary												(7)		(7)
Balance at December 31, 2012	$	2,217	$	8,441	$	―	$	(376)	$	10,282	$	401	$	10,683
See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
Operating revenues
Electric	$	3,226	$	2,830	$	2,535
Natural gas		468		543		514
Total operating revenues		3,694		3,373		3,049
Operating expenses
Cost of electric fuel and purchased power		892		715		637
Cost of natural gas		151		226		217
Operation and maintenance		1,154		1,072		987
Depreciation and amortization		490		422		381
Franchise fees and other taxes		198		183		170
Total operating expenses		2,885		2,618		2,392
Operating income		809		755		657
Other income, net		69		79		10
Interest expense		(173)		(142)		(136)
Income before income taxes		705		692		531
Income tax expense		(190)		(237)		(173)
Net income		515		455		358
(Earnings) losses attributable to noncontrolling interest		(26)		(19)		16
Earnings		489		436		374
Preferred dividend requirements		(5)		(5)		(5)
Earnings attributable to common shares	$	484	$	431	$	369
See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
		Years ended December 31, 2012, 2011 and 2010

		San Diego Gas & Electric Shareholder's Equity
		Pretax		Income Tax		Net-of-Tax		Noncontrolling
		Amount(1)		(Expense) Benefit		Amount		Interest (After-Tax)		Total
2012:
Net income		$	489			$	489	$	26	$	515
Other comprehensive loss:
Pension and other postretirement benefits			(1)	$	―		(1)		―		(1)
Financial instruments			―		―		―		(11)		(11)
Total other comprehensive loss			(1)		―		(1)		(11)		(12)
Total comprehensive income		$	488	$	―	$	488	$	15	$	503
2011:
Net income		$	436			$	436	$	19	$	455
Other comprehensive loss:
Financial instruments			―	$	―		―		(36)		(36)
Total other comprehensive loss			―		―		―		(36)		(36)
Total comprehensive income (loss)		$	436	$	―	$	436	$	(17)	$	419
2010:
Net income (loss)		$	374			$	374	$	(16)	$	358
Other comprehensive income (loss):
Pension and other postretirement benefits			(1)	$	1		―		―		―
Financial instruments			―		―		―		7		7
Total other comprehensive income (loss)			(1)		1		―		7		7
Total comprehensive income (loss)		$	373	$	1	$	374	$	(9)	$	365
(1)	Except for Net Income (Loss) and Total Comprehensive Income (Loss).
See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,		December 31,
	2012		2011
ASSETS
Current assets:
Cash and cash equivalents	$	87	$	29
Restricted cash		10		21
Accounts receivable – trade, net		252		267
Accounts receivable – other, net		21		23
Due from unconsolidated affiliates		39		67
Income taxes receivable		35		102
Inventories		82		82
Regulatory balancing accounts, net		395		38
Regulatory assets arising from fixed-price contracts and other derivatives		39		67
Other regulatory assets		10		11
Fixed-price contracts and other derivatives		41		27
Settlements receivable related to wildfire litigation		5		10
Other		71		51
Total current assets		1,087		795

Other assets:
Restricted cash		22		22
Deferred taxes recoverable in rates		718		570
Regulatory assets arising from fixed-price contracts and other derivatives		110		191
Regulatory assets arising from pension and other postretirement
benefit obligations		303		309
Regulatory assets arising from wildfire litigation costs		364		594
Other regulatory assets		252		160
Nuclear decommissioning trusts		908		804
Sundry		117		70
Total other assets		2,794		2,720

Property, plant and equipment:
Property, plant and equipment		14,124		13,003
Less accumulated depreciation and amortization		(3,261)		(2,963)
Property, plant and equipment, net ($466 and $494 at December 31, 2012
and 2011, respectively, related to VIE)		10,863		10,040
Total assets	$	14,744	$	13,555
See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,		December 31,
	2012		2011
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	300	$	375
Due to unconsolidated affiliate		19		14
Deferred income taxes		26		62
Dividends and interest payable		36		32
Accrued compensation and benefits		129		124
Current portion of long-term debt		16		19
Fixed-price contracts and other derivatives		56		55
Customer deposits		60		62
Reserve for wildfire litigation		305		586
Other		157		107
Total current liabilities		1,104		1,436
Long-term debt ($335 and $345 at December 31, 2012 and 2011, respectively,
related to VIE)		4,292		4,058

Deferred credits and other liabilities:
Customer advances for construction		17		20
Pension and other postretirement benefit obligations, net of plan assets		340		342
Deferred income taxes		1,636		1,167
Deferred investment tax credits		25		26
Regulatory liabilities arising from removal obligations		1,603		1,462
Asset retirement obligations		733		693
Fixed-price contracts and other derivatives		209		243
Reserve for wildfire litigation		22		10
Deferred credits and other		386		178
Total deferred credits and other liabilities		4,971		4,141
Contingently redeemable preferred stock		79		79

Commitments and contingencies (Note 15)

Equity:
Common stock (255 million shares authorized; 117 million shares outstanding;
no par value)		1,338		1,338
Retained earnings		2,895		2,411
Accumulated other comprehensive income (loss)		(11)		(10)
Total SDG&E shareholder’s equity		4,222		3,739
Noncontrolling interest		76		102
Total equity		4,298		3,841
Total liabilities and equity	$	14,744	$	13,555
See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	515	$	455	$	358
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization		490		422		381
Deferred income taxes and investment tax credits		285		290		52
Fixed-price contracts and other derivatives		(12)		(13)		22
Other		(63)		(68)		(32)
Changes in other assets		201		33		14
Changes in other liabilities		129		7		(3)
Changes in working capital components:
Accounts receivable		12		6		―
Due to/from affiliates, net		29		6		(2)
Inventories		―		(11)		(10)
Other current assets		208		309		343
Income taxes		85		(111)		12
Accounts payable		(42)		68		23
Regulatory balancing accounts		(322)		(87)		(99)
Interest payable		5		6		10
Other current liabilities		(419)		(430)		(340)
Net cash provided by operating activities		1,101		882		729

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(1,237)		(1,831)		(1,210)
Purchases of nuclear decommissioning trust assets		(732)		(748)		(362)
Proceeds from sales by nuclear decommissioning trusts		723		741		352
Decrease in loans to affiliates, net		―		―		14
Proceeds from sale of assets		―		1		―
Decrease in restricted cash		92		520		152
Increase in restricted cash		(81)		(447)		(260)
Net cash used in investing activities		(1,235)		(1,764)		(1,314)

CASH FLOWS FROM FINANCING ACTIVITIES
Capital contribution		―		200		―
Preferred dividends paid		(5)		(5)		(5)
Issuances of long-term debt		249		598		744
Payments on long-term debt		(10)		(10)		(10)
Capital contribution received by Otay Mesa VIE		―		5		―
Capital distributions made by Otay Mesa VIE		(40)		―		(24)
Other		(2)		(4)		(6)
Net cash provided by financing activities		192		784		699
Increase (decrease) in cash and cash equivalents		58		(98)		114
Cash and cash equivalents, January 1		29		127		13
Cash and cash equivalents, December 31	$	87	$	29	$	127
See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	162	$	131	$	120
Income tax (refunds) payments, net		(242)		59		108

SUPPLEMENTAL DISCLOSURE OF NONCASH ACTIVITIES
Increase in capital lease obligations for investments in property, plant
and equipment	$	3	$	―	$	188
Accrued capital expenditures		153		187		173
Dividends declared but not paid		1		1		1
See Notes to Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Dollars in millions)
	Years ended December 2012, 2011 and 2010
					Accumulated
					Other		SDG&E
	Common		Retained		Comprehensive		Shareholder’s		Noncontrolling		Total
	Stock		Earnings		Income (Loss)		Equity		Interest		Equity
Balance at December 31, 2009	$	1,138	$	1,611	$	(10)	$	2,739	$	146	$	2,885

Net income (loss)				374				374		(16)		358
Other comprehensive income										7		7

Preferred stock dividends declared				(5)				(5)				(5)
Distributions to noncontrolling interest										(24)		(24)
Balance at December 31, 2010		1,138		1,980		(10)		3,108		113		3,221

Net income				436				436		19		455
Other comprehensive loss										(36)		(36)

Preferred stock dividends declared				(5)				(5)				(5)
Capital contribution		200						200				200
Equity contributed by noncontrolling interest										6		6
Balance at December 31, 2011		1,338		2,411		(10)		3,739		102		3,841

Net income				489				489		26		515
Other comprehensive loss						(1)		(1)		(11)		(12)

Preferred stock dividends declared				(5)				(5)				(5)
Distributions to noncontrolling interest										(41)		(41)
Balance at December 31, 2012	$	1,338	$	2,895	$	(11)	$	4,222	$	76	$	4,298
See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010

Operating revenues	$	3,282	$	3,816	$	3,822
Operating expenses
Cost of natural gas		1,074		1,568		1,699
Operation and maintenance		1,304		1,305		1,174
Depreciation and amortization		362		331		309
Franchise fees and other taxes		122		126		124
Total operating expenses		2,862		3,330		3,306
Operating income		420		486		516
Other income, net		17		13		12
Interest income		―		1		1
Interest expense		(68)		(69)		(66)
Income before income taxes		369		431		463
Income tax expense		(79)		(143)		(176)
Net income		290		288		287
Preferred dividend requirements		(1)		(1)		(1)
Earnings attributable to common shares	$	289	$	287	$	286
See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
		Years ended December 31, 2012, 2011 and 2010
		Pretax		Income Tax		Net-of-Tax
		Amount(1)		(Expense) Benefit		Amount
2012:
Net income		$	290			$	290
Other comprehensive income (loss):
Pension and other postretirement benefits			5	$	(3)		2
Financial instruments			2		(1)		1
Total other comprehensive income (loss)			7		(4)		3
Total comprehensive income (loss)		$	297	$	(4)	$	293
2011:
Net income		$	288			$	288
Other comprehensive income (loss):
Pension and other postretirement benefits			(2)	$	1		(1)
Financial instruments			3		(1)		2
Total other comprehensive income			1		―		1
Total comprehensive income		$	289	$	―	$	289
2010:
Net income		$	287			$	287
Other comprehensive income (loss):
Financial instruments			5	$	(2)		3
Total other comprehensive income (loss)			5		(2)		3
Total comprehensive income (loss)		$	292	$	(2)	$	290
(1)	Except Net Income and Total Comprehensive Income (Loss).
See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,		December 31,
	2012		2011
ASSETS
Current assets:
Cash and cash equivalents	$	83	$	36
Accounts receivable – trade, net		539		578
Accounts receivable – other, net		51		63
Due from unconsolidated affiliates		24		40
Income taxes receivable		104		17
Deferred income taxes		3		―
Inventories		151		151
Regulatory assets		4		9
Other		35		28
Total current assets		994		922

Other assets:
Regulatory assets arising from pension and other postretirement
benefit obligations		835		808
Other regulatory assets		148		137
Sundry		77		8
Total other assets		1,060		953

Property, plant and equipment:
Property, plant and equipment		11,187		10,565
Less accumulated depreciation and amortization		(4,170)		(3,965)
Property, plant and equipment, net		7,017		6,600
Total assets	$	9,071	$	8,475
See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
	December 31,		December 31,
	2012		2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable – trade	$	383	$	315
Accounts payable – other		82		78
Due to unconsolidated affiliate		37		2
Deferred income taxes		―		44
Accrued compensation and benefits		116		99
Regulatory balancing accounts, net		141		105
Current portion of long-term debt		4		257
Customer deposits		76		75
Other		124		172
Total current liabilities		963		1,147
Long-term debt		1,409		1,064
Deferred credits and other liabilities:
Customer advances for construction		111		110
Pension and other postretirement benefit obligations, net of plan assets		855		833
Deferred income taxes		881		576
Deferred investment tax credits		20		23
Regulatory liabilities arising from removal obligations		1,103		1,075
Asset retirement obligations		1,238		1,161
Deferred taxes refundable in rates		―		87
Deferred credits and other		256		206
Total deferred credits and other liabilities		4,464		4,071

Commitments and contingencies (Note 15)

Shareholders’ equity:
Preferred stock		22		22
Common stock (100 million shares authorized; 91 million shares outstanding;
no par value)		866		866
Retained earnings		1,365		1,326
Accumulated other comprehensive income (loss)		(18)		(21)
Total shareholders’ equity		2,235		2,193
Total liabilities and shareholders’ equity	$	9,071	$	8,475
See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	290	$	288	$	287
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization		362		331		309
Deferred income taxes and investment tax credits		128		130		107
Other		(12)		(6)		―
Changes in other assets		14		19		(7)
Changes in other liabilities		4		(7)		8
Changes in working capital components:
Accounts receivable		37		(57)		18
Inventories		(1)		(46)		(12)
Other current assets		(6)		5		(2)
Accounts payable		54		(7)		52
Income taxes		(83)		(12)		5
Due to/from affiliates, net		51		(18)		11
Regulatory balancing accounts		31		(63)		(56)
Customer deposits		1		2		(13)
Other current liabilities		(24)		(5)		29
Net cash provided by operating activities		846		554		736

CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment		(639)		(683)		(503)
(Increase) decrease in loans to affiliate, net		(4)		49		(63)
Net cash used in investing activities		(643)		(634)		(566)

CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid		(250)		(50)		(100)
Preferred dividends paid		(1)		(1)		(1)
Issuances of long-term debt		348		―		299
Payments on long-term debt		(250)		(250)		―
Debt issuance costs		(3)		―		―
Net cash (used in) provided by financing activities		(156)		(301)		198

Increase (decrease) in cash and cash equivalents		47		(381)		368
Cash and cash equivalents, January 1		36		417		49
Cash and cash equivalents, December 31	$	83	$	36	$	417

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized	$	62	$	65	$	54
Income tax payments, net of refunds		16		25		64

SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
Accrued capital expenditures	$	115	$	97	$	103
Increase in capital lease obligations for investments in property, plant and
equipment		―		―		4
See Notes to Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Dollars in millions)
	Years ended December 31, 2012, 2011 and 2010
							Accumulated
							Other		Total
	Preferred		Common		Retained		Comprehensive		Shareholders’
	Stock		Stock		Earnings		Income (Loss)		Equity
Balance at December 31, 2009	$	22	$	866	$	903	$	(25)	$	1,766

Net income						287				287
Other comprehensive income								3		3

Preferred stock dividends declared						(1)				(1)
Common stock dividends declared						(100)				(100)
Balance at December 31, 2010		22		866		1,089		(22)		1,955

Net income						288				288
Other comprehensive income								1		1

Preferred stock dividends declared						(1)				(1)
Common stock dividends declared						(50)				(50)
Balance at December 31, 2011		22		866		1,326		(21)		2,193

Net income						290				290
Other comprehensive income								3		3

Preferred stock dividends declared						(1)				(1)
Common stock dividends declared						(250)				(250)
Balance at December 31, 2012	$	22	$	866	$	1,365	$	(18)	$	2,235
See Notes to Consolidated Financial Statements.

SEMPRA ENERGY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA

PRINCIPLES OF CONSOLIDATION

Sempra Energy

Sempra Energy’s Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 holding company, and its consolidated subsidiaries and variable interest entities (VIEs). Sempra Energy’s principal operating units are

§	San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), which are separate, reportable segments;

§	Sempra International, which includes our Sempra South American Utilities and Sempra Mexico reportable segments; and

§	Sempra U.S. Gas & Power, which includes our Sempra Renewables and Sempra Natural Gas reportable segments.

We provide descriptions of each of our segments in Note 16.

We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International and Sempra U.S. Gas & Power operating units. Sempra Global is the holding company for most of our subsidiaries that are not subject to California utility regulation. All references in these Notes to “Sempra International,” “Sempra U.S. Gas & Power” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name.

Sempra Energy uses the equity method to account for investments in affiliated companies over which we have the ability to exercise significant influence, but not control. We discuss our investments in unconsolidated subsidiaries in Notes 3 and 4.

During the fourth quarter of 2012, we revised the manner in which we make resource allocation decisions to our Sempra Mexico segment and assess its performance, as we discuss in Notes 16 and 18. As a result, we have reclassified certain amounts from Parent and Other, which contains interest and other corporate costs and certain holding company activities, to our Sempra Mexico segment. In accordance with accounting principles generally accepted in the United States (U.S. GAAP), our historical segment disclosures have been restated to be consistent with the current presentation.

SDG&E

SDG&E’s Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E is the primary beneficiary, as we discuss below under “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy.

SoCalGas

SoCalGas’ Consolidated Financial Statements include its subsidiaries, which comprise less than one percent of its consolidated financial position and results of operations. SoCalGas’ common stock is wholly owned by Pacific Enterprises (PE), which is a wholly owned subsidiary of Sempra Energy.

BASIS OF PRESENTATION

This is a combined report of Sempra Energy, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. References in this report to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, unless otherwise indicated by the context. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity.

Regulated Operations

Sempra South American Utilities has controlling interests in two electric distribution utilities in South America. Sempra Natural Gas owns Mobile Gas Service Corporation (Mobile Gas) in southwest Alabama and Willmut Gas Company (Willmut Gas) in Mississippi, and Sempra Mexico owns Ecogas Mexico, S de RL de CV (Ecogas) in northern Mexico, all natural gas distribution utilities. The California Utilities, Sempra Natural Gas’ Mobile Gas and Willmut Gas, and Sempra Mexico’s Ecogas prepare their financial statements in accordance with U.S. GAAP provisions governing regulated operations, as we discuss below under “Regulatory Matters.” We discuss revenue recognition at our utilities in “Revenues − Utilities” below.

Use of Estimates in the Preparation of the Financial Statements

We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP). This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates.

Subsequent Events

We evaluated events and transactions that occurred after December 31, 2012 through the date the financial statements were issued, and in the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation. We discuss subsequent events further in Note 18.

REGULATORY MATTERS

Effects of Regulation

The accounting policies of our regulated utility subsidiaries in California, SDG&E and SoCalGas, conform with U.S. GAAP for regulated enterprises and reflect the policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).

The California Utilities prepare their financial statements in accordance with U.S. GAAP provisions governing regulated operations. Under these provisions, 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, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from ratepayers, the excess would be refunded to customers, generally by reducing future rates. Regulatory liabilities may also arise from other transactions such as unrealized gains on fixed price contracts and other derivatives or certain deferred income tax benefits which are passed through to customers in future rates. In addition, the California Utilities record regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods.

Determining probability of recovery requires significant judgment by management and may include, but is not limited to, consideration of

§	the nature of the event giving rise to the assessment;

§	existing statutes and regulatory code;

§	legal precedence;

§	regulatory principles and analogous regulatory actions;

§	testimony presented in regulatory hearings;

§	proposed regulatory decisions;

§	final regulatory orders;

§	a commission-authorized mechanism established for the accumulation of costs;

§	status of applications for rehearings or state court appeals;

§	specific approval from a commission; and

§	historical experience.

A commission has not denied the recovery of any material costs previously recognized by either SDG&E or SoCalGas as regulatory assets during 2012, 2011, nor 2010.

Our other natural gas distribution utilities, Mobile Gas, Willmut Gas and Ecogas, also apply U.S. GAAP for regulated utilities to their operations.

We provide information concerning regulatory assets and liabilities below in “Regulatory Balancing Accounts” and “Regulatory Assets and Liabilities.”

Regulatory Balancing Accounts

The following table summarizes our regulatory balancing accounts at December 31.


SUMMARY OF REGULATORY BALANCING ACCOUNTS AT DECEMBER 31
(Dollars in millions)
		Sempra Energy
		Consolidated				SDG&E				SoCalGas
		2012		2011		2012		2011		2012		2011
Overcollected		$	643	$	709	$	340	$	419	$	303	$	290
Undercollected			(897)		(642)		(735)		(457)		(162)		(185)
Net (receivable) payable(1)		$	(254)	$	67	$	(395)	$	(38)	$	141	$	105
(1)	At December 31, 2012 and 2011, the net receivable at SDG&E and the net payable at SoCalGas are shown separately on Sempra Energy's Consolidated Balance Sheet.

Over- and under-collected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs, primarily commodity costs. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. Balancing account treatment eliminates the impact on earnings from variances in the covered costs from authorized amounts. Absent balancing account treatment, variations in the cost of fuel supply and certain operating and maintenance costs from amounts approved by the CPUC would increase volatility in utility earnings.

We provide additional information about regulatory matters in Notes 14 and 15.

Regulatory Assets and Liabilities

We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below.

REGULATORY ASSETS (LIABILITIES) AT DECEMBER 31
(Dollars in millions)
		2012		2011
SDG&E
Fixed-price contracts and other derivatives		$	149	$	258
Costs related to wildfire litigation			364		594
Deferred taxes recoverable in rates			718		570
Pension and other postretirement benefit obligations			303		309
Removal obligations (1)			(1,603)		(1,462)
Unamortized loss on reacquired debt, net			16		20
Environmental costs			16		17
Legacy meters			90		91
Sunrise Powerlink fire mitigation			117		―
Other			23		43
Total SDG&E			193		440
SoCalGas
Pension and other postretirement benefit obligations			835		808
Employee benefit costs			58		66
Removal obligations (1)			(1,103)		(1,075)
Deferred taxes recoverable (refundable) in rates			38		(87)
Unamortized loss on reacquired debt, net			17		20
Environmental costs			14		21
Workers’ compensation			27		44
Other			(2)		(5)
Total SoCalGas			(116)		(208)
Other Sempra Energy
Mobile Gas regulatory assets			20		10
Mobile Gas regulatory liabilities			(15)		(15)
Willmut Gas			(2)		―
Ecogas			1		3
Total Other Sempra Energy			4		(2)
Total Sempra Energy Consolidated		$	81	$	230
(1)	Related to obligations discussed below in “Asset Retirement Obligations.”

NET REGULATORY ASSETS (LIABILITIES) AS PRESENTED ON THE CONSOLIDATED BALANCE SHEETS AT DECEMBER 31
(Dollars in millions)
		2012						2011
		Sempra						Sempra
		Energy						Energy
		Consolidated		SDG&E		SoCalGas		Consolidated		SDG&E		SoCalGas
Current regulatory assets		$	62	$	49	$	4	$	89	$	78	$	9
Noncurrent regulatory assets			2,742		1,747		983		2,780		1,824		945
Current regulatory liabilities (1)			(2)		―		―		(1)		―		―
Noncurrent regulatory liabilities			(2,721)		(1,603)		(1,103)		(2,638)		(1,462)		(1,162)
Total		$	81	$	193	$	(116)	$	230	$	440	$	(208)
(1)	Included in Other Current Liabilities.

In the tables above:

Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts.

§	Regulatory assets arising from costs related to wildfire litigation are costs in excess of liability insurance coverage and amounts recovered from third parties, as we discuss in Note 14 under “Excess Wildfire Claims Cost Recovery” and Note 15 under “SDG&E—2007 Wildfire Litigation.”

Deferred taxes recoverable/refundable in rates are based on current regulatory ratemaking and income tax laws. SDG&E and SoCalGas expect to recover/refund net regulatory assets/liabilities related to deferred income taxes over the lives of the assets that give rise to the accumulated deferred income tax liabilities/assets.

§	Regulatory assets related to pension and other postretirement benefit obligations are offset by corresponding liabilities and are being recovered in rates as the plans are funded.

§	Regulatory assets related to unamortized losses on reacquired debt are recovered over the remaining original amortization periods of the losses on reacquired debt. These periods range from 1 month to 15 years for SDG&E and from 5 months to 13 years for SoCalGas.

Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made.

§	The regulatory asset related to the legacy meters removed from service and replaced under the Smart Meter Program is their undepreciated value. SDG&E expects to recover this asset over a remaining life of 27 years.

§	The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a 50-year period.

For substantially all of these assets, the cash has not yet been expended and the assets are offset by liabilities that do not incur a carrying cost.

FAIR VALUE MEASUREMENTS

We apply recurring fair value measurements to certain assets and liabilities, primarily nuclear decommissioning and benefit plan trust assets and other miscellaneous derivatives. “Fair value” is defined as 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).

A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability 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. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value.

We establish 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 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. Our Level 1 financial instruments primarily consist of listed equities, U.S. government treasury securities and exchange-traded derivatives.

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

§	current market and contractual prices for the underlying instruments

§	volatility factors

§	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. Our financial instruments in this category include the Nuclear Decommissioning Trusts’ investments at SDG&E and non-exchange-traded derivatives such as interest rate instruments and over-the-counter (OTC) 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 from the perspective of a market participant.

CASH AND CASH EQUIVALENTS

Cash equivalents are highly liquid investments with maturities of three months or less at the date of purchase.

RESTRICTED CASH

Restricted cash at Sempra Energy, including amounts at SDG&E discussed below, was $68 million and $46 million at December 31, 2012 and 2011, respectively. Of this, $46 million and $24 million were classified as current and $22 million and $22 million were classified as noncurrent at December 31, 2012 and 2011, respectively.

Sempra Renewables had restricted cash at December 31, 2012 of $35 million classified as current, which represents funds held in accordance with long-term debt agreements at Mesquite Solar 1 and Copper Mountain Solar 1. We discuss the debt agreements further in Note 5 and in “Restricted Net Assets” below.

SDG&E had $32 million and $29 million of restricted cash at December 31, 2012 and 2011, respectively, which represents funds held by a trustee for Otay Mesa VIE (see “Variable Interest Entities—Otay Mesa VIE” below) to pay certain operating costs. Of this, $10 million and $7 million were classified as current and $22 million and $22 million were classified as noncurrent at December 31, 2012 and 2011, respectively. In addition, SDG&E had restricted cash at December 31, 2011 of $14 million related to the purchase of a power plant on January 1, 2012.

COLLECTION ALLOWANCES

We record allowances for the collection of trade and other accounts and notes receivable which include allowances for doubtful customer accounts and for other receivables. We show the changes in these allowances in the table below:

COLLECTION ALLOWANCES
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
Sempra Energy Consolidated
Allowances for collection of receivables at January 1	$	29	$	29	$	27
Provisions for uncollectible accounts		21		20		22
Write-offs of uncollectible accounts		(19)		(20)		(20)
Allowances for collection of receivables at December 31	$	31	$	29	$	29
SDG&E
Allowances for collection of receivables at January 1	$	6	$	5	$	4
Provisions for uncollectible accounts		5		8		7
Write-offs of uncollectible accounts		(5)		(7)		(6)
Allowances for collection of receivables at December 31	$	6	$	6	$	5
SoCalGas
Allowances for collection of receivables at January 1	$	12	$	14	$	16
Provisions for uncollectible accounts		12		8		8
Write-offs of uncollectible accounts		(10)		(10)		(10)
Allowances for collection of receivables at December 31	$	14	$	12	$	14

We evaluate accounts receivable collectability using a combination of factors, including past due status based on contractual terms, trends in write-offs, the age of the receivable, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies. Adjustments to the allowance for doubtful accounts are made when necessary based on the results of analysis, the aging of receivables, and historical and industry trends.

We write off accounts receivable in the period in which we deem the receivable to be uncollectible. We record recoveries of accounts receivable previously written off when it is known that they will be received.

INVENTORIES

The California Utilities value natural gas inventory by the last-in first-out (LIFO) method. As inventories are sold, differences between the LIFO valuation and the estimated replacement cost are reflected in customer rates. Materials and supplies at the California Utilities are generally valued at the lower of average cost or market.

Sempra Mexico, Sempra South American Utilities and Sempra Natural Gas value natural gas inventory and materials and supplies at the lower of average cost or market. Sempra Natural Gas and Sempra Mexico value liquefied natural gas (LNG) inventory by the first-in first-out method.

The components of inventories by segment are as follows:

INVENTORY BALANCES AT DECEMBER 31
(Dollars in millions)
	Natural Gas					LNG			Materials and supplies				Total
	2012		2011			2012	2011		2012		2011		2012		2011
SDG&E	$	3	$	6	$	―	$	―	$	79	$	76	$	82	$	82
SoCalGas		128		128		―		―		23		23		151		151
Sempra South American Utilities		―		―		―		―		34		36		34		36
Sempra Mexico		―		―		8		10		8		7		16		17
Sempra Renewables		―		―		―		―		3		―		3		―
Sempra Natural Gas		109		47		8		4		5		9		122		60
Sempra Energy Consolidated	$	240	$	181	$	16	$	14	$	152	$	151	$	408	$	346

U.S. TREASURY GRANTS RECEIVABLE

As of December 31, 2012, Sempra Renewables has recorded grants receivable totaling $258 million. Based on eligible costs at its Mesquite Solar 1 and Copper Mountain Solar 2 generating facilities, the grants are recognized when the projects, or portions of projects, are placed into service. The grants are expected to be received in 2013.

INCOME TAXES

Income tax expense includes current and deferred income taxes from operations during the year. We record deferred income taxes for temporary differences between the book and the tax bases of assets and liabilities. Investment tax credits from prior years are amortized to income by the California Utilities over the estimated service lives of the properties as required by the CPUC. At our other businesses, we reduce the book basis of the related asset by the amount of investment tax credit earned. At Sempra Renewables, production tax credits are recognized in income tax expense as earned.

The California Utilities, Mobile Gas, and Willmut Gas recognize

§	regulatory assets to offset deferred tax liabilities if it is probable that the amounts will be recovered from customers; and

§	regulatory liabilities to offset deferred tax assets if it is probable that the amounts will be returned to customers.

Other than local country withholding tax on current Peruvian earnings, we currently do not record deferred income taxes for basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries because their cumulative undistributed earnings are indefinitely reinvested.

When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to 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. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the “more likely than not” criterion at the largest amount of tax benefit that is greater than 50 percent likely of being realized upon its effective resolution.

Unrecognized tax benefits involve management’s 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 our results of operations, financial position and cash flows.

We provide additional information about income taxes in Note 7.

RENEWABLE ENERGY CERTIFICATES

Renewable energy certificates (RECs) represent property rights established by governmental agencies for the environmental, social, and other nonpower qualities of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.

Retail sellers of electricity obtain RECs through renewable power purchase agreements, internal generation or separate purchases in the market to comply with renewable portfolio standards established by the governmental agencies. RECs are the mechanism used to verify renewable portfolio standards compliance. The cost of RECs is recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Consolidated Statements of Operations.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment primarily represents the buildings, equipment and other facilities used by the California Utilities to provide natural gas and electric utility services, and by Sempra International and Sempra U.S. Gas & Power. It also reflects projects included in construction work in progress at these operating units.

Our plant costs include

labor

§	materials and contract services

§	expenditures for replacement parts incurred during a major maintenance outage of a generating plant

In addition, the cost of our utility plant includes an allowance for funds used during construction (AFUDC). We discuss AFUDC below. The cost of non-utility plant includes capitalized interest.

Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant minus salvage value is charged to accumulated depreciation.

We discuss assets pledged as security for loans in Note 5.

PROPERTY, PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY
(Dollars in millions)
		Property, Plant
		and Equipment at				Depreciation rates for
		December 31,				years ended December 31,
		2012		2011		2012		2011		2010
SDG&E:
Natural gas operations		$	1,406	$	1,349	3.20	%	3.15	%	3.00	%
Electric distribution			5,217		4,894	4.15		4.13		4.06
Electric transmission			3,714		1,938	2.63		2.74		2.70
Electric generation(1)			2,242		2,166	4.68		4.92		4.30
Other electric(2)			679		604	7.92		8.26		8.19
Construction work in progress			866		2,052	NA		NA		NA
Total SDG&E			14,124		13,003
SoCalGas:
Natural gas operations(3)			10,756		10,055	3.74		3.62		3.54
Other non-utility			129		129	1.36		1.62		1.74
Construction work in progress			302		381	NA		NA		NA
Total SoCalGas			11,187		10,565

						Estimated			Weighted Average
Other operating units and parent (4) :						Useful Lives			Useful Life
Land and land rights			298		292	20 to 50 years(5)			47
Machinery and equipment:
Utility electric distribution operations			1,459		1,267	10 to 46 years			40
Generating plants			1,568		1,278	3 to 50 years			32
LNG terminals			2,061		2,059	3 to 50 years			47
Pipelines and storage			1,634		1,510	3 to 50 years			45
Other			241		168	2 to 50 years			15
Construction work in progress			692		849	NA			NA
Other			264		201	3 to 80 years			31
			8,217		7,624
Total Sempra Energy Consolidated		$	33,528	$	31,192
(1)	Includes capital lease assets of $183 million at both December 31, 2012 and 2011, primarily related to variable interest entities of which SDG&E is not the primary beneficiary.
(2)	Includes capital lease assets of $23 million and $26 million at December 31, 2012 and 2011, respectively.
(3)	Includes capital lease assets of $32 million and $33 million at December 31, 2012 and 2011, respectively.
(4)	December 31, 2012 balances include $144 million, $171 million and $18 million of utility plant, primarily pipelines and other distribution assets, at Ecogas, Mobile Gas and Willmut Gas, respectively. December 31, 2011 balances include $126 million and $163 million of utility plant, primarily pipelines and other distribution assets, at Ecogas and Mobile Gas, respectively.
(5)	Estimated useful lives are for land rights.

Depreciation expense is based on the straight-line method over the useful lives of the assets or, for the California Utilities, a shorter period prescribed by the CPUC. Depreciation expense is computed using the straight-line method over the asset’s estimated original composite useful life, the CPUC-prescribed period or the remaining term of the site leases, whichever is shortest.

The accumulated depreciation and decommissioning amounts on our Consolidated Balance Sheets are as follows:

ACCUMULATED DEPRECIATION AND DECOMMISSIONING AMOUNTS
(Dollars in millions)
		December 31,
		2012		2011
SDG&E:
Accumulated depreciation and decommissioning of utility plant in service:
Electric(1)		$	2,660	$	2,387
Natural gas			601		576
Total SDG&E			3,261		2,963
SoCalGas:
Accumulated depreciation of natural gas utility plant in service(2)			4,067		3,863
Accumulated depreciation – other non-utility			103		102
Total SoCalGas			4,170		3,965
Other operating units and parent:
Accumulated depreciation – other(3)			806		755
Accumulated depreciation of utility electric distribution operations			100		44
			906		799
Total Sempra Energy Consolidated		$	8,337	$	7,727
(1)	Includes accumulated depreciation for assets under capital lease of $21 million and $16 million at December 31, 2012 and 2011, respectively.
(2)	Includes accumulated depreciation for assets under capital lease of $28 million and $22 million at December 31, 2012 and 2011, respectively.
(3)	December 31, 2012 balances include $34 million, $21 million and $1 million of accumulated depreciation for utility plant at Ecogas, Mobile Gas and Willmut Gas, respectively. December 31, 2011 balances include $28 million and $15 million of accumulated depreciation for utility plant at Ecogas and Mobile Gas, respectively.

The California Utilities finance their construction projects with borrowed funds and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of property, plant and equipment. The California Utilities earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from their customers over the expected useful lives of the assets.

Sempra International and Sempra U.S. Gas & Power businesses capitalize interest costs incurred to finance capital projects. The California Utilities also capitalize certain interest costs.

CAPITALIZED FINANCING COSTS
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
Sempra Energy Consolidated:
AFUDC related to debt	$	38	$	40	$	24
AFUDC related to equity		96		99		57
Other capitalized financing costs		52		26		33
Total Sempra Energy Consolidated	$	186	$	165	$	114
SDG&E:
AFUDC related to debt	$	30	$	33	$	18
AFUDC related to equity		71		80		43
Total SDG&E	$	101	$	113	$	61
SoCalGas:
AFUDC related to debt	$	8	$	7	$	6
AFUDC related to equity		25		19		14
Other capitalized financing costs		1		―		―
Total SoCalGas	$	34	$	26	$	20

ASSETS HELD FOR SALE

We classify assets as held for sale when management approves and commits to a formal plan to actively market an asset for sale and we expect the sale to close within the next twelve months. Upon classifying an asset as held for sale, we record the asset at the lower of its carrying value or its estimated fair value reduced for selling costs, and we stop recording depreciation expense on the asset.

In December 2012, management approved a formal plan and executed an agreement to sell one 625-megawatt (MW) gas-fired power block of Sempra Natural Gas’ Mesquite Power natural gas-fired power plant in Arizona in exchange for approximately $370 million in cash to Salt River Project Agricultural Improvement and Power District. We expect the transaction to close in the first quarter of 2013.

At December 31, 2012, the carrying amount of the major classes of assets and related liability held for sale associated with the plant includes the following:

(Dollars in millions)		2012
Property, plant, and equipment, net		$	292
Inventories			4
Total assets held for sale			296
Liability held for sale - asset retirement obligation(1)			(5)
Total		$	291
(1)	Included in Other Current Liabilities on the Consolidated Balance Sheet.

For the year ended December 31, 2012, there was no impairment of the assets held for sale as the estimated fair value less costs to sell exceeded the carrying amount.

GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized but is tested for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. Impairment of goodwill occurs when the carrying amount (book value) of goodwill exceeds its implied fair value. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, and the book value of goodwill is greater than its fair value on the test date, we record a goodwill impairment loss.

For our annual goodwill impairment testing, under current U.S. GAAP guidance we have the option to first make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step, quantitative goodwill impairment test. We evaluate relevant events and circumstances to decide whether to perform the qualitative assessment or to proceed directly to the two-step, quantitative goodwill impairment test. When we perform the two-step, quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and the corresponding goodwill. Our fair value estimates are developed from the perspective of a knowledgeable market participant. In the absence of observable transactions in the marketplace for similar investments, we consider an income-based approach such as discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include

§	consideration of market transactions

§	future cash flows

§	the appropriate risk-adjusted discount rate

§	country risk

§	entity risk

Sempra Natural Gas recorded goodwill of $10 million in connection with the acquisition of Willmut Gas Company in May 2012. Sempra South American Utilities recorded goodwill of $975 million in April 2011 in connection with the acquisition of AEI’s interests in Chilquinta Energía S.A. (Chilquinta Energía) in Chile, Luz del Sur S.A.A. (Luz del Sur) in Peru, and their subsidiaries. We discuss these acquisitions in Note 3.

Goodwill included on the Sempra Energy Consolidated Balance Sheets is as follows:

GOODWILL
(Dollars in millions)
			Sempra
		South American			Sempra		Sempra
			Utilities		Mexico		Natural Gas		Total
Balance at December 31, 2010		$	―	$	25	$	62	$	87
Acquisition of subsidiaries			975		―		―		975
Foreign currency translation(1)			(26)		―		―		(26)
Balance at December 31, 2011			949		25		62		1,036
Acquisition of subsidiary			―		―		10		10
Foreign currency translation(1)			65		―		―		65
Balance at December 31, 2012		$	1,014	$	25	$	72	$	1,111
(1)	We record the offset of this fluctuation to other comprehensive income.

We provide additional information concerning goodwill related to our equity method investments and the impairment of investments in unconsolidated subsidiaries in Note 4.

Other Intangible Assets

Sempra Natural Gas recorded $460 million of intangible assets in connection with the acquisition of EnergySouth, Inc. in 2008. These intangible assets represent storage and development rights related to the natural gas storage facilities of Bay Gas Storage Company, Ltd. (Bay Gas) and Mississippi Hub, LLC (Mississippi Hub) and were recorded at estimated fair value as of the date of the acquisition using discounted cash flows analysis. Our assumptions in determining fair value include estimated future cash flows, the estimated useful life of the intangible assets and our use of appropriate discount rates. We are amortizing these intangible assets over their estimated useful lives as shown in the table below.

Other Intangible Assets included on the Sempra Energy Consolidated Balance Sheets are as follows:

OTHER INTANGIBLE ASSETS
(Dollars in millions)
	Amortization period	December 31,		December 31,
	(years)	2012		2011
Storage rights	46	$	138	$	138
Development rights	50		322		322
Other	15 years to indefinite		19		21
			479		481
Less accumulated amortization:
Storage rights			(13)		(10)
Development rights			(27)		(21)
Other			(3)		(2)
			(43)		(33)
Total		$	436	$	448

Intangible assets subject to amortization are amortized over their estimated useful lives. Amortization expense for such intangible assets was $10 million in each of 2012, 2011 and 2010. We estimate the amortization expense for the next five years to be $10 million per year.

LONG-LIVED ASSETS

We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated subsidiaries. Events or changes in circumstances that indicate that the carrying amount of a long-lived asset may not be recoverable may include

§	significant decreases in the market price of an asset

§	a significant adverse change in the extent or manner in which we use an asset or in its physical condition

§	a significant adverse change in legal or regulatory factors or in the business climate that could affect the value of an asset

§	a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection of continuing losses associated with the use of a long-lived asset

§	a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life

Impairment of long-lived assets occurs when the estimated future undiscounted cash flows are less than the carrying amount of the assets. If that comparison indicates that the assets’ carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the assets. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

VARIABLE INTEREST ENTITIES (VIE)

We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based upon qualitative and quantitative analyses, which assess

§	the purpose and design of the VIE;

§	the nature of the VIE’s risks and the risks we absorb;

§	the power to direct activities that most significantly impact the economic performance of the VIE; and

§	the obligation to absorb losses or right to receive benefits that could be significant to the VIE.

SDG&E

Tolling Agreements

SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based upon our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If we determine that SDG&E is the primary beneficiary, SDG&E and Sempra Energy consolidate the entity that owns the facility as a VIE, as we discuss below.

Otay Mesa VIE

SDG&E has an agreement to purchase power generated at the Otay Mesa Energy Center (OMEC), a 605-MW generating facility. In addition to tolling, the agreement provides SDG&E with the option to purchase the power plant at the end of the contract term in 2019, or upon earlier termination of the purchased-power agreement, at a predetermined price subject to adjustments based on performance of the facility. If SDG&E does not exercise its option, under certain circumstances, it may be required to purchase the power plant at a predetermined price, which we refer to as the put option.

The facility owner, Otay Mesa Energy Center LLC (OMEC LLC), is a VIE (Otay Mesa VIE), of which SDG&E is the primary beneficiary. SDG&E has no OMEC LLC voting rights and does not operate OMEC. In addition to the risks absorbed under the tolling agreement, SDG&E absorbs separately through the put option a significant portion of the risk that the value of Otay Mesa VIE could decline. SDG&E and Sempra Energy have consolidated Otay Mesa VIE since the second quarter of 2007. Otay Mesa VIE’s equity of $76 million at December 31, 2012 and $102 million at December 31, 2011 is included on the Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.

OMEC LLC has a loan outstanding of $345 million at December 31, 2012, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is secured by OMEC’s property, plant and equipment. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC. The loan fully matures in April 2019 and bears interest at rates varying with market rates. In addition, OMEC LLC has entered into interest rate swap agreements to moderate its exposure to interest rate changes. We provide additional information concerning the interest rate swaps in Note 10.

Other Variable Interest Entities

SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various power purchase arrangements which include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and thereby Sempra Energy, is the primary beneficiary. SDG&E has determined that no contracts, other than the one relating to Otay Mesa VIE mentioned above, result in SDG&E being the primary beneficiary as of December 31, 2012. In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, including certain construction costs, tax credits, and other components of cash flow expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects are not expected to significantly affect the financial position, results of operations, or liquidity of SDG&E. In addition, SDG&E is not exposed to losses or gains as a result of these other VIEs, because all such variability would be recovered in rates.

Sempra Energy’s other operating units also enter into arrangements which could include variable interests. We evaluate these arrangements and applicable entities based upon the qualitative and quantitative analyses described above. Certain of these entities are service companies that are VIEs. As the primary beneficiary of these service companies, we consolidate them. In all other cases, we have determined that these contracts are not variable interests in a VIE and therefore are not subject to the U.S. GAAP requirements concerning the consolidation of VIEs.

The Consolidated Financial Statements of Sempra Energy and SDG&E include the following amounts associated with Otay Mesa VIE. The amounts are net of eliminations of transactions between SDG&E and Otay Mesa VIE. The financial statements of other consolidated VIEs are not material to the financial statements of Sempra Energy. The captions on the tables below correspond to SDG&E’s Consolidated Balance Sheets and Consolidated Statements of Operations.

AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
			December 31,
			2012		2011
Cash and cash equivalents			$	8	$	12
Restricted cash				10		7
Accounts receivable - trade, net				―		7
Inventories				2		2
Other				1		1
Total current assets				21		29
Restricted cash				22		22
Sundry				5		6
Property, plant and equipment, net				466		494
Total assets			$	514	$	551

Current portion of long-term debt			$	10	$	10
Fixed-price contracts and other derivatives				17		16
Other				8		9
Total current liabilities				35		35
Long-term debt				335		345
Fixed-price contracts and other derivatives				64		65
Deferred credits and other				4		4
Other noncontrolling interest				76		102
Total liabilities and equity			$	514	$	551

	Years ended December 31,
	2012		2011		2010
Operating revenues
Electric	$	―	$	―	$	(1)
Natural gas		―		―		(3)
Total operating revenues		―		―		(4)
Operating expenses
Cost of electric fuel and purchased power		(83)		(72)		(82)
Operation and maintenance		19		19		20
Depreciation and amortization		26		22		26
Total operating expenses		(38)		(31)		(36)
Operating income		38		31		32
Other (expense) income, net		(1)		(1)		(34)
Interest expense		(11)		(11)		(14)
Income (loss) before income taxes/Net income (loss)		26		19		(16)
(Earnings) losses attributable to noncontrolling interest		(26)		(19)		16
Earnings	$	―	$	―	$	―

ASSET RETIREMENT OBLIGATIONS

For tangible long-lived assets, we record asset retirement obligations 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 reasonable estimate of fair value can be made. We also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated, but performance is conditional upon a future event. We record 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 record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through the rate-making process. We have recorded a regulatory liability to show that the California Utilities have collected funds from customers more quickly and for larger amounts than we would accrete the retirement liability and depreciate the asset in accordance with U.S. GAAP.

We have recorded asset retirement obligations related to various assets including:

SDG&E and SoCalGas

§	fuel and storage tanks

§	natural gas distribution system

§	hazardous waste storage facilities

§	asbestos-containing construction materials

SDG&E

§	decommissioning of nuclear power facilities

§	electric distribution and transmission systems

§	site restoration of a former power plant

§	power generation plant (natural gas)

SoCalGas

§	natural gas transmission pipelines

§	underground natural gas storage facilities and wells

Sempra Mexico

§	power generation plant (natural gas)

§	natural gas distribution and transportation systems

§	LNG terminal

Sempra Renewables

§	certain power generation plants (solar)

Sempra Natural Gas

§	power generation plant (natural gas)

§	natural gas distribution and transportation systems

§	underground natural gas storage facilities

The changes in asset retirement obligations are as follows:

CHANGES IN ASSET RETIREMENT OBLIGATIONS
(Dollars in millions)
		Sempra Energy
		Consolidated				SDG&E				SoCalGas
		2012		2011		2012		2011		2012		2011
Balance as of January 1(1)		$	1,925	$	1,468	$	698	$	623	$	1,175	$	803
Accretion expense			92		82		42		38		48		41
Liabilities incurred			21		12		―		3		―		―
Reclassification(2)			(5)		―		―		―		―		―
Payments			(2)		(1)		―		―		(1)		―
Revisions(3)			25		364		1		34		31		331
Balance as of December 31(1)		$	2,056	$	1,925	$	741	$	698	$	1,253	$	1,175
(1)	The current portions of the obligations are included in Other Current Liabilities on the Consolidated Balance Sheets.
(2)	Reclassification to liability held for sale - asset retirement obligation which is included in Other Current Liabilities on the Consolidated Balance Sheets, as we discuss in "Assets Held for Sale" above.
(3)	The increase in obligations at SDG&E and SoCalGas for revisions in 2011 resulted from changes in assets in service and a decrease in the discount rate from 5.13 percent in 2010 to 4.00 percent in 2011, based on the risk-free rate plus an estimated credit spread.

CONTINGENCIES

We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and:

§	information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and

§	the amounts of the loss can be reasonably estimated.

We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.

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.

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:

§	foreign currency translation adjustments

§	changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans

§	unrealized gains or losses on available-for-sale securities

§	certain hedging activities

The Consolidated Statements of Comprehensive Income show the changes in the components of other comprehensive income (OCI), including the amounts attributable to noncontrolling interests. The components of Accumulated Other Comprehensive Income (Loss) (AOCI), shown net of income taxes on the Consolidated Balance Sheets, and the related income tax balances at December 31, 2012 and 2011 are as follows:

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) AND
ASSOCIATED INCOME TAX EXPENSE (BENEFIT)
(Dollars in millions)
	Accumulated Other Comprehensive Income (Loss)				Income Tax Expense (Benefit)
	2012		2011		2012		2011
Sempra Energy Consolidated
Foreign currency translation loss	$	(240)	$	(359)	$	―	$	(3)
Financial instruments		(35)		(31)		(24)		(22)
Unamortized net actuarial loss		(102)		(100)		(70)		(68)
Unamortized prior service credit		1		1		1		1
Balance as of December 31	$	(376)	$	(489)	$	(93)	$	(92)
SDG&E
Unamortized net actuarial loss	$	(12)	$	(11)	$	(8)	$	(8)
Unamortized prior service credit		1		1		1		1
Balance as of December 31	$	(11)	$	(10)	$	(7)	$	(7)
SoCalGas
Financial instruments	$	(15)	$	(16)	$	(10)	$	(11)
Unamortized net actuarial loss		(4)		(6)		(1)		(4)
Unamortized prior service credit		1		1		―		―
Balance as of December 31	$	(18)	$	(21)	$	(11)	$	(15)

NONCONTROLLING INTERESTS

Ownership interests that are held by owners other than Sempra Energy and SDG&E in subsidiaries or entities consolidated by them are accounted for and reported as noncontrolling interests. As a result, noncontrolling interests are reported as a separate component of equity on the Consolidated Balance Sheets. Net income or loss attributable to the noncontrolling interests is separately identified on the Consolidated Statements of Operations, and net income or loss and comprehensive income or loss attributable to the noncontrolling interests is separately identified on the Consolidated Statements of Comprehensive Income and Consolidated Statements of Changes in Equity.

The preferred stock at SoCalGas is presented at Sempra Energy as a noncontrolling interest at December 31, 2012 and 2011. The preferred stock of SDG&E is contingently redeemable preferred stock. At Sempra Energy, the preferred stock dividends of SDG&E, SoCalGas and PE are charges against income related to noncontrolling interests. We provide additional information concerning preferred stock in Note 12.

At December 31, 2012 and 2011, we reported the following noncontrolling ownership interests held by others (not including preferred shareholders) recorded in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Consolidated Balance Sheets:

OTHER NONCONTROLLING INTERESTS AS OF DECEMBER 31
(Dollars in millions)
		Percent Ownership Held by Others			2012		2011
Otay Mesa VIE (at SDG&E)		100	%	$	76	$	102
Chilquinta Energía subsidiaries		24 - 43			29		34
Luz del Sur		20			236		216
Tecsur		10			4		4
Bay Gas Storage Company, Ltd.(1)		9			20		17
Liberty Gas Storage, LLC(1)		25			15		9
Southern Gas Transmission Company(1)		49			1		1
Total Sempra Energy				$	381	$	383
(1)	Part of Sempra Natural Gas.

REVENUES

Utilities

Our California Utilities generate revenues primarily from deliveries to their customers of electricity by SDG&E and natural gas by both SoCalGas and SDG&E and from related services. They record these revenues following the accrual method and recognize them upon delivery and performance. They also record revenue from CPUC-approved incentive awards, some of which require approval by the CPUC prior to being recognized. We provide additional discussion on utility incentive mechanisms in Note 14.

Under an operating agreement with the California Department of Water Resources (DWR), SDG&E acts as a limited agent on behalf of the DWR in the administration of energy contracts, including natural gas procurement functions under the DWR contracts allocated to SDG&E’s customers. The legal and financial responsibilities associated with these activities continue to reside with the DWR. Accordingly, the commodity costs associated with long-term contracts allocated to SDG&E from the DWR (and the revenues to recover those costs) are not included in SDG&E’s or Sempra Energy’s Consolidated Statements of Operations. We provide discussion on electric industry regulation related to the DWR in Note 14.

On a monthly basis, SoCalGas accrues natural gas storage contract revenues, which consist of storage reservation and variable charges based on negotiated agreements with terms of up to 15 years.

Our natural gas utilities outside of California (Mobile Gas, Willmut Gas and Ecogas) apply U.S. GAAP for regulated utilities consistent with the California Utilities.

Our utilities in South America, which were consolidated as part of our Sempra South American Utilities segment beginning April 6, 2011 as we discuss in Note 3, are Chilquinta Energía and Luz del Sur. Chilquinta Energía is an electric distribution utility serving customers in the cities of Valparaiso and Viña del Mar in central Chile. Luz del Sur is an electric distribution utility in the southern zone of metropolitan Lima, Peru. The companies serve primarily regulated customers, and their revenues are based on tariffs that are set by the National Energy Commission (Comisión Nacional de Energía, or CNE) in Chile and the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería, or OSINERGMIN) of the National Electricity Office under the Ministry of Energy and Mines in Peru.

The tariffs charged are based on an efficient model distribution company defined by Chilean law in the case of Chilquinta Energía, and OSINERGMIN in the case of Luz del Sur. The tariffs include operation and maintenance costs, an internal rate of return on the new replacement value (Valor Nuevo de Reemplazo, or VNR) of depreciable assets, charges for the use of transmission systems, and a component for the value added by the distributor. Tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on the distributor’s regulated asset base. Because the tariffs are based on a model and are intended to cover the costs of the model company, but are not based on the costs of the specific utility and may not result in full cost recovery, they do not meet the requirement necessary for treatment under applicable U.S. GAAP for regulatory accounting.

For Chilquinta Energía, rates for four-year periods related to distribution and transmission are reviewed separately on an alternating basis every two years. In late 2011, Chilquinta Energía initiated the process to establish their distribution rates for the period from November 2012 to October 2016. This process was completed in November 2012 with rates established through October 2016 but not formally effective until certain governmental reviews are finalized. We expect completion of these reviews and official publication of Chilquinta Energía’s distribution rates in the first quarter of 2013, with tariff adjustments going into effect retroactively from November 2012. Their next review is scheduled to be completed, with tariff adjustments also going into effect, in November 2014 for transmission, and again for distribution in November 2016.

The components of tariffs above for Luz del Sur are reviewed and adjusted every four years. Their next review is scheduled to be completed, with tariff adjustments also going into effect, in November 2013.

The table below shows the total utilities revenues in Sempra Energy’s Consolidated Statements of Operations for each of the last three years. The revenues include amounts for services rendered but unbilled (approximately one-half month’s deliveries) at the end of each year.

TOTAL UTILITIES REVENUES AT SEMPRA ENERGY CONSOLIDATED(1)
(Dollars in millions)
		Years ended December 31,
		2012		2011		2010
Natural gas revenues		$	3,873	$	4,489	$	4,491
Electric revenues			4,568		3,833		2,528
Total		$	8,441	$	8,322	$	7,019
(1)	Excludes intercompany revenues.

As we discuss in Note 14, the natural gas supply for SDG&E’s and SoCalGas’ core natural gas customers is purchased by SoCalGas as a combined procurement portfolio managed by SoCalGas. Core customers are primarily residential and small commercial and industrial customers. This core gas procurement function is considered a shared service, therefore amounts related to SDG&E are not included in SoCalGas’ Consolidated Statements of Operations.

We provide additional information concerning utility revenue recognition in “Regulatory Matters” above.

Energy-Related Businesses

Sempra South American Utilities

Sempra South American Utilities generates revenues from providing electric construction services. They recognize revenues when services are provided in accordance with contractual agreements.

Sempra Mexico

Sempra Mexico’s Termoeléctrica de Mexicali generates revenues from selling electricity and/or capacity to the California Independent System Operator (ISO), governmental, public utility and wholesale power marketing entities. These revenues are recognized as the electricity is delivered and capacity is provided. Sempra Mexico’s pipeline operations recognize revenues from the sale and transportation of natural gas as deliveries are made and from fixed capacity payments. Sempra Mexico also recognizes revenues from (1) the sale of LNG and natural gas as deliveries are made to counterparties and (2) from reservation and usage fees under terminal capacity agreements, nitrogen injection service agreements and tug service agreements. It reports revenue net of value added taxes in Mexico. Sempra Mexico’s revenues also include net realized gains and losses and the net change in the fair value of unrealized gains and losses on derivative contracts for natural gas.

Sempra Renewables

Sempra Renewables generates revenues from the sale of solar power pursuant to power purchase agreements. They recognize revenues when the power is delivered.

Sempra Natural Gas

Sempra Natural Gas generates revenues from selling electricity and/or capacity from its Mesquite Power facility to the California ISO, governmental, public utility and wholesale power marketing entities. These revenues are recognized as the electricity is delivered and capacity is provided. In each of 2011 and 2010, Sempra Natural Gas’ electricity sales to the DWR accounted for a significant portion of its revenues. This contract ended September 30, 2011. Related to its LNG terminal and marketing operations, Sempra Natural Gas recognizes revenues from the sale of LNG and natural gas as deliveries are made to counterparties, as well as revenues from reservation and usage fees. Sempra Natural Gas also records revenues from contractual counterparty obligations for non-delivery of cargoes. Sempra Natural Gas recognizes revenue on natural gas storage and transportation operations when services are provided in accordance with contractual agreements for the storage and transportation services. Sempra Natural Gas revenues also include net realized gains and losses and the net change in the fair value of unrealized gains and losses on derivative contracts for power and natural gas.

OTHER COST OF SALES

Other Cost of Sales primarily includes

§	pipeline capacity marketing costs, and pipeline transportation and natural gas marketing costs incurred at Sempra Natural Gas;

§	electric construction services costs at Sempra South American Utilities; and

§	management service fees at Sempra Mexico.

The costs at Sempra South American Utilities are related to the energy-services companies in South America that we discuss in Note 3.

OPERATION AND MAINTENANCE EXPENSES

Operation and Maintenance includes operating and maintenance costs, and general and administrative costs, which consist primarily of personnel costs, purchased materials and services, and rent. SDG&E’s and SoCalGas’ Operation and Maintenance includes litigation expense, which is shown separately on Sempra Energy’s Consolidated Statements of Operations.

FOREIGN CURRENCY TRANSLATION

Our operations in South America and our natural gas distribution utility in Mexico use their local currency as their functional currency. The assets and liabilities of their foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the year. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings (unless the operation is being discontinued), but are reflected in Comprehensive Income and in Accumulated Other Comprehensive Income (Loss), a component of shareholders’ equity.

To reflect the fluctuations in the values of functional currencies of our South American investments, which were accounted for under the equity method prior to April 6, 2011, the following adjustments were made to the carrying value of these investments (dollars in millions):

			Upward (downward) adjustment to investments
Investment		Currency	2011(1)		2010
Chilquinta Energía		Chilean Peso	$	(10)	$	34
Luz del Sur		Peruvian Nuevo Sol		―		5
(1)	As discussed in Note 3, the cumulative foreign currency translation adjustment balances totaling $54 million in Accumulated Other Comprehensive Income (Loss) as of April 6, 2011 were reclassified to net income as a result of the gain on the remeasurement of our equity method investments in Chilquinta Energía and Luz del Sur during the second quarter of 2011.

Smaller adjustments have been made to other operations where the U.S. dollar is not the functional currency. We provide additional information concerning these investments in Note 4.

Currency transaction gains and losses in a currency other than the entity’s functional currency are included in the calculation of Other Income, Net, at Sempra Energy as follows:

	Years ended December 31,
(Dollars in millions)	2012		2011		2010
Currency transaction gain	$	9	$	11	$	4

TRANSACTIONS WITH AFFILIATES

Loans to Unconsolidated Affiliates

Sempra South American Utilities has a U.S. dollar-denominated loan to Camuzzi Gas del Sur S.A., an affiliate of the segment’s Argentine investments, which we discuss in Note 4. At December 31, 2012, the loan has an $18 million principal balance outstanding plus $7 million of accumulated interest at a variable interest rate (7.31 percent at December 31, 2012). In June 2012, the maturity date of the loan was extended from June 2012 to June 30, 2013. The loan was fully reserved at December 31, 2012 and 2011.

Investments

At December 31, 2011, Sempra Energy (at Parent and Other) had an investment in bonds issued by Chilquinta Energía that were remarketed in 2012 as we discuss in Note 5.

Other Affiliate Transactions

Sempra Energy, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Amounts due to/from affiliates are as follows:

AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
		December 31,
		2012		2011
SDG&E
Current:
Due from SoCalGas		$	37	$	2
Due from various affiliates			2		65
		$	39	$	67

Due to Sempra Energy		$	19	$	14

Income taxes due from Sempra Energy(1)		$	12	$	97

SoCalGas
Current:
Due from Sempra Energy		$	24	$	23
Due from various affiliates			―		17
		$	24	$	40

Due to SDG&E		$	37	$	2


Income taxes due from Sempra Energy(1)		$	99	$	17
(1)	SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from the companies’ having always filed a separate return.

Revenues from unconsolidated affiliates at SDG&E and SoCalGas are as follows:

Transactions with Rockies Express Pipelines LLC

Sempra Rockies Marketing, a subsidiary of Sempra Natural Gas, has an agreement for capacity on the Rockies Express Pipeline through November 2019. For each of the years ended December 31, 2012, 2011 and 2010, Sempra Rockies Marketing recorded cost of sales of $78 million related to this agreement. The capacity costs are offset by revenues from releases of the capacity to RBS Sempra Commodities LLP (RBS Sempra Commodities) prior to 2011, and to J.P. Morgan Ventures starting in 2011, as well as other third parties.

Transactions with RBS Sempra Commodities

In 2008, our commodities-marketing businesses, previously wholly owned subsidiaries of Sempra Energy, were sold into RBS Sempra Commodities, a partnership jointly owned by Sempra Energy and The Royal Bank of Scotland. Several of our segments have engaged in transactions with RBS Sempra Commodities. As a result of the divestiture of substantially all of RBS Sempra Commodities’ businesses, as we discuss in Note 4, transactions between our segments and RBS Sempra Commodities were assigned over time to the buyers of the joint venture businesses. The assignments of the related contracts were substantially completed by May 1, 2011. Amounts in our Consolidated Financial Statements related to these transactions are as follows:

AMOUNTS RECORDED FOR TRANSACTIONS WITH RBS SEMPRA COMMODITIES
(Dollars in millions)
		Years ended December 31,
		2011(1)		2010
Revenues:
SoCalGas		$	―	$	14
Sempra Mexico			37		82
Sempra Natural Gas			7		184

Cost of natural gas:
SDG&E		$	―	$	3
SoCalGas			―		36
Sempra Mexico			74		193
Sempra Natural Gas			3		177
(1)	With the exception of Sempra Mexico, whose contract with RBS Sempra Commodities expired in July 2011, amounts only include activities prior to May 1, 2011, the date by which substantially all the contracts with RBS Sempra Commodities were assigned to buyers of the joint venture businesses.

RESTRICTED NET ASSETS

Sempra Energy Consolidated

As we discuss below, the California Utilities have restrictions on the amount of funds that can be transferred to Sempra Energy by dividend, advance or loan as a result of conditions imposed by various regulators. Additionally, certain other Sempra Energy subsidiaries are subject to various financial and other covenants and other restrictions contained in debt and credit agreements described in Note 5 and in other agreements that limit the amount of funds that can be transferred to Sempra Energy. At December 31, 2012, Sempra Energy was in compliance with all covenants related to its debt agreements.

At December 31, 2012, the amount of restricted net assets of wholly owned subsidiaries of Sempra Energy, including the California Utilities discussed below, that may not be distributed to Sempra Energy in the form of a loan or dividend is $5.3 billion. Although the restrictions cap the amount of funding that the various operating subsidiaries can provide to Sempra Energy, we do not believe these restrictions will have a significant impact on our ability to access cash to pay dividends.

As we discuss in Note 4, $107 million of Sempra Energy’s consolidated retained earnings balance represents undistributed earnings of equity method investments at December 31, 2012.

Significant restrictions of subsidiaries include

§	Wholly owned Mobile Gas has long-term debt instruments containing restrictions relating to the payment of dividends and other distributions with respect to capital stock. Under these restrictions, net assets of approximately $116 million are restricted at December 31, 2012.

§	91-percent owned Bay Gas has long-term debt instruments containing restrictions relating to the payment of dividends and other distributions if Bay Gas does not maintain a specified debt service coverage ratio. Bay Gas had no restricted net assets at December 31, 2012.

50-percent owned and unconsolidated Fowler Ridge 2 Wind Farm (Fowler Ridge 2) and Cedar Creek 2 Wind Farm (Cedar Creek 2) have debt agreements which require each joint venture to maintain reserve accounts in order to pay the projects’ debt service and operation and maintenance requirements. As a result of these requirements, total joint venture net assets of approximately $35 million at Fowler Ridge 2 and $29 million at Cedar Creek 2 are restricted at December 31, 2012. We discuss Sempra Energy guarantees associated with these requirements in Note 5.

Mesquite Solar 1 and Copper Mountain Solar 1 have long-term debt agreements that require the establishment and funding of project accounts to which the proceeds of loans, project revenues and other amounts are deposited and applied in accordance with the debt agreements. These long-term debt agreements also limit Mesquite Solar 1’s and Copper Mountain Solar 1’s ability to incur liens, incur additional indebtedness, make acquisitions, pay cash dividends and undertake certain actions, while also requiring maintenance of certain debt ratios. Under these restrictions, net assets totaling $35 million are restricted at December 31, 2012.

§	Peru and Mexico require domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $35 million at Luz del Sur and $61 million at Sempra Energy’s consolidated Mexican subsidiaries as of December 31, 2012.

§	50-percent owned and unconsolidated Gasoductos de Chihuahua has long-term debt agreements which require the joint venture to maintain reserve accounts to meet debt service requirements. As a result, total joint venture assets of $19 million are restricted at December 31, 2012.

California Utilities

The CPUC’s regulation of the California Utilities’ capital structures limits the amounts that are available for dividends and loans to Sempra Energy. At December 31, 2012, Sempra Energy could have received combined loans and dividends of approximately $660 million from SDG&E and approximately $917 million from SoCalGas.

The payment and amount of future dividends for SDG&E and SoCalGas are at the discretion of their board of directors. The following restrictions limit the amount of retained earnings that may be paid as common dividends or loaned to Sempra Energy from either utility:

§	The CPUC requires that SDG&E’s and SoCalGas’ common equity ratios be no lower than one percentage point below the CPUC authorized percentage of each entity’s authorized capital structure, which at December 31, 2012 was:

§	49 percent at SDG&E

§	48 percent at SoCalGas.

§	The FERC requires SDG&E to maintain a common equity ratio of 30 percent or above.

§	The California Utilities have a combined revolving credit line that requires each utility to maintain a ratio of consolidated indebtedness to consolidated capitalization (as defined in the agreement) of no more than 65 percent, as we discuss in Note 5.

Based upon these restrictions, at December 31, 2012, SDG&E’s restricted net assets were $3.6 billion and SoCalGas’ restricted net assets were $1.3 billion and could not be transferred to Sempra Energy.

In December 2012, the CPUC issued a final decision in SDG&E’s and SoCalGas’ cost of capital proceeding. Among other things, this decision set both SDG&E’s and SoCalGas’ authorized common equity ratios at 52 percent of each entity’s total capital structure, effective January 1, 2013, as we discuss in Note 14. Based upon the same restrictions noted previously, as of January 1, 2013, $4.0 billion of SDG&E’s and $1.5 billion of SoCalGas’ net assets are restricted and may not be transferred to Sempra Energy.

Correspondingly, as of January 1, 2013, Sempra Energy could have received a combination of loans or dividends on common stock of approximately $200 million from SDG&E and $698 million from SoCalGas.

OTHER INCOME, NET

Other Income, Net on the Consolidated Statements of Operations consists of the following:

OTHER INCOME, NET
(Dollars in millions)
		Years ended December 31,
		2012		2011		2010
Sempra Energy Consolidated:
Allowance for equity funds used during construction		$	96	$	99	$	57
Investment gains(1)			41		22		35
Gains (losses) on interest rate and foreign exchange instruments(2)			10		(14)		(24)
Regulatory interest income, net(3)			1		2		1
Sundry, net(4)			24		21		71
	Total	$	172	$	130	$	140
SDG&E:
Allowance for equity funds used during construction		$	71	$	80	$	43
Regulatory interest income, net(3)			2		2		―
Losses on interest rate instruments(5)			―		(1)		(34)
Sundry, net			(4)		(2)		1
	Total	$	69	$	79	$	10
SoCalGas:
Allowance for equity funds used during construction		$	25	$	19	$	14
Regulatory interest (expense) income, net(3)			(1)		―		1
Sundry, net			(7)		(6)		(3)
	Total	$	17	$	13	$	12
(1)	Represents investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)	Sempra Energy Consolidated includes Otay Mesa VIE and additional instruments.
(3)	Interest on regulatory balancing accounts.
(4)	Amount in 2010 includes proceeds of $48 million from a legal settlement.
(5)	Related to Otay Mesa VIE.

NOTE 2. NEW ACCOUNTING STANDARDS

We describe below recent pronouncements that have had or may have a significant effect on our financial statements. We do not discuss recent pronouncements that are not anticipated to have an impact on or are unrelated to our financial condition, results of operations, cash flows or disclosures.

SEMPRA ENERGY, SDG&E AND SOCALGAS

Accounting Standards Update (ASU) 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRSs)” (ASU 2011-04): ASU 2011-04 amends Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures, and provides changes in the wording used to describe the requirements for measuring fair value and disclosing information about fair value measurement. ASU 2011-04 results in common fair value measurement and disclosure requirements under both U.S. GAAP and IFRSs.

ASU 2011-04 expands fair value measurement disclosures for Level 3 instruments to require

§	quantitative information about the unobservable inputs

§	a description of the valuation process

§	a qualitative discussion about the sensitivity of the measurements

We adopted ASU 2011-04 on January 1, 2012 and it did not affect our financial position, results of operations or cash flows. We provide the required disclosure in Note 11.

ASU 2011-05, “Presentation of Comprehensive Income” (ASU 2011-05), ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12), and ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (ASU 2013-02): ASU 2011-05 amends ASC Topic 220, Comprehensive Income , and eliminates the option to report other comprehensive income and its components in the statement of changes in equity. The ASU allows an entity an option to present the components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements.

ASU 2011-05 does not change the items that must be reported in other comprehensive income, when an item of other comprehensive income must be reclassified to net income, or the earnings per share computation.

ASU 2011-12 defers the requirement to separately present on the face of the statement of operations or statement of comprehensive income reclassification adjustments for items that are reclassified from other comprehensive income to net income.

ASU 2013-02 requires an entity to present, either on the face of the statement of operations or in the notes to financial statements, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts.

We adopted ASU 2011-05 on January 1, 2012 and have elected to present the components of net income and other comprehensive income in two separate, but consecutive, statements for all periods presented. We will adopt ASU 2013-02 on January 1, 2013 as required and do not expect it to affect our financial position, results of operations or cash flows. We will provide the additional disclosure in our 2013 interim financial statements.

ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11) and ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” (ASU 2013-01): In order to allow for balance sheet comparison between U.S. GAAP and IFRSs, ASU 2011-11 requires enhanced disclosures related to financial assets and liabilities eligible for offsetting in the statement of financial position. An entity will have to disclose both gross and net information about financial instruments and transactions subject to a master netting arrangement and eligible for offset, including cash collateral received and posted.

ASU 2013-01 clarifies that the scope of ASU 2011-11 applies to derivatives, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions.

We will adopt ASU 2011-11 and ASU 2013-01 on January 1, 2013 as required and do not expect them to affect our financial position, results of operations or cash flows. We will provide the additional disclosure in our 2013 interim financial statements.

ASU 2012-02, “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02): ASU 2012-02 amends ASC Topic 350, Intangibles – Goodwill and Others , to provide an option to first make a qualitative assessment of whether it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount before applying the quantitative impairment test. An entity is required to perform the quantitative test only if it determines that it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount.

We adopted ASU 2012-02 for our annual impairment testing of indefinite-lived intangible assets at Sempra Mexico, which comprise all of our indefinite-lived intangible assets, as of October 1, 2012. We determined that it is not more likely than not that the fair value of the indefinite-lived intangible assets is less than their carrying amount, therefore adopting ASU 2012-02 did not affect our financial statements.

NOTE 3. ACQUISITION AND INVESTMENT ACTIVITY

We consolidate assets and liabilities acquired as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.

SEMPRA SOUTH AMERICAN UTILITIES

Chilquinta Energía and Luz del Sur

On April 6, 2011, Sempra South American Utilities acquired from AEI its interests in Chilquinta Energía in Chile and Luz del Sur in Peru, and their subsidiaries. Prior to the acquisition, Sempra South American Utilities and AEI each owned 50 percent of Chilquinta Energía and approximately 38 percent of Luz del Sur. Upon completion of the acquisition, Sempra South American Utilities owned 100 percent of Chilquinta Energía and approximately 76 percent of Luz del Sur, with the remaining shares of Luz del Sur held by institutional investors and the general public. As part of the transaction, Sempra South American Utilities also acquired AEI’s interests in two energy-services companies, Tecnored S.A. and Tecsur S.A. The adjusted purchase price of $888 million resulted from valuing the net assets in Chile, Peru and other holding companies at $495 million, $385 million and $8 million, respectively. We paid $611 million in cash ($888 million less $245 million of cash acquired and $32 million of consideration withheld for a liability related to the purchase).

As part of our acquisition of AEI’s interest in Luz del Sur, we were required to launch a tender offer to the minority shareholders of Luz del Sur to purchase their shares (up to a maximum 14.73 percent interest in Luz del Sur). In September 2011, we purchased 18,918,954 additional Luz del Sur shares for $43 million in settlement of the mandatory public tender offer, bringing Sempra South American Utilities’ ownership to 79.82 percent.

Chilquinta Energía owned 85 percent of Luzlinares S.A. (Luzlinares) through October 31, 2012. On November 26, 2012, Chilquinta Energía purchased the remaining 15-percent ownership interest of Luzlinares for $7 million in cash.

We allocated the original purchase price for Chilquinta Energ í a and Luz del Sur on a preliminary basis in the second quarter of 2011. In the third and fourth quarters of 2011, we adjusted the preliminary allocation for additional assets and liabilities identified, including an $11 million premium related to long-term debt at Chilquinta Energ í a . The retrospective application of these adjustments to prior quarters was de minimus. There were no further adjustments through April 2012, the end of the measurement period. The following table summarizes the consideration paid in the acquisition and the recognized amounts of the assets acquired and liabilities assumed, as well as the fair value at the acquisition date of the noncontrolling interests:

PURCHASE PRICE ALLOCATION
(Dollars in millions)
			At April 6, 2011
								Other
				Chilean		Peruvian		holding
				entities		entities		companies		Total
Fair value of businesses acquired:
	Cash consideration (fair value of total
	consideration)		$	495	$	385	$	8	$	888
	Fair value of equity method
	investments immediately prior to
	the acquisition			495		385		2		882
	Fair value of noncontrolling interests			37		242		―		279
Total fair value of businesses acquired				1,027		1,012		10		2,049

Recognized amounts of identifiable assets
	acquired and liabilities assumed:
		Cash		219		22		4		245
		Property, plant and equipment		555		931		―		1,486
		Long-term debt		(305)		(179)		―		(484)
		Other net assets (liabilities) acquired		44		(223)		6		(173)
Total identifiable net assets				513		551		10		1,074
Goodwill			$	514	$	461	$	―	$	975

Our results for the year ended December 31, 2011 include a $277 million gain (both pretax and after-tax) related to the remeasurement of equity method investments, included as Remeasurement of Equity Method Investments on our Consolidated Statement of Operations. We calculated the gain as the difference between the acquisition-date fair value ($882 million) and the book value ($605 million) of our equity interests in Chilquinta Energía and Luz del Sur immediately prior to the acquisition date. This book value of our equity interests included currency translation adjustment balances in Accumulated Other Comprehensive Income (Loss). The valuation techniques we used to allocate the purchase price to the businesses included discounted cash flow analysis and the market multiple approach (enterprise value to earnings before interest, taxes, depreciation and amortization (EBITDA)). Our assumptions for these measures included estimated future cash flows, use of appropriate discount rates, market trading multiples and market transaction multiples. Discount rates used reflect consideration of risk free rates, as well as country and company risk. Methodologies used to determine fair values of material assets as of the date of the acquisition included

§	the replacement cost approach for property, plant and equipment; and

§	goodwill associated primarily with the value of residual future cash flows that we believe these businesses will generate, to be tested annually for impairment. For income tax purposes, none of the goodwill recorded is deductible in Chile, Peru or the United States.

For substantially all other assets and liabilities, our analysis of fair value factors indicated that book value approximates fair value. We valued noncontrolling interests based on the fair value of tangible assets and an allocation of goodwill based on relative enterprise value.

Our Consolidated Statement of Operations includes 100 percent of the acquired companies’ revenues, net income and earnings from the date of acquisition, including $1.1 billion, $160 million and $135 million, respectively, from the date of acquisition for the year ended December 31, 2011. These amounts do not include the remeasurement gain.

Following are pro forma revenues and earnings for Sempra Energy had the acquisition occurred on January 1, 2010, which primarily reflect the incremental increase to revenues and earnings from our increased ownership and consolidation of the entities acquired. Although some short-term debt borrowings may have resulted from the actual acquisition in 2011, we have not assumed any additional interest expense in the pro forma impact on earnings below, as the amounts would be immaterial due to the low interest rates available to us on commercial paper. The pro forma amounts do not include the impact of the increased ownership in Luz del Sur resulting from the tender offer completed in September 2011 discussed above.

		Years ended December 31,
(Dollars in millions)		2011		2010
Revenues		$	10,379	$	10,277
Earnings(1)			1,079		1,062
(1)	Pro forma earnings for 2010 include the $277 million gain related to the remeasurement of equity method investments, and accordingly, pro forma earnings for 2011 exclude the gain.

The companies use their local currency, the Chilean Peso or the Peruvian Nuevo Sol, as their functional currency, and we account for them as discussed above in Note 1 under “Foreign Currency Translation.”

We provide additional information about Sempra South American Utilities’ investments in Chilquinta Energía and Luz del Sur in Note 4.

SEMPRA MEXICO

Acquisition of Mexican Pipeline and Natural Gas Infrastructure

On April 30, 2010, Sempra Mexico completed an acquisition resulting in the purchase of the Mexican pipeline and natural gas infrastructure assets of El Paso Corporation for $307 million ($292 million, net of cash acquired).

The acquisition consists of El Paso Corporation’s wholly owned natural gas pipeline and compression assets in the Mexican border state of Sonora and its 50-percent interest in Gasoductos de Chihuahua, a joint venture with PEMEX, the Mexican state-owned oil company. The acquisition has enabled us to expand our natural gas infrastructure business in Mexico. The joint venture operates two natural gas pipelines and a propane system in Mexico. The pipeline assets are supported substantially by long-term contracts.

The following table summarizes the consideration paid in the acquisition and the recognized amounts of the assets acquired and liabilities assumed:

(Dollars in millions)		At April 30, 2010
Cash consideration (fair value of total consideration)		$	307
Recognized amounts of identifiable assets acquired and liabilities assumed:
	Investment in equity method investee		256
	Other net assets acquired		33
Total identifiable net assets			289
Goodwill(1)		$	18

(1)

The goodwill, which represents the residual of the consideration paid over the identifiable net assets, is assigned to the Sempra Mexico segment and is attributed to the strategic value of the transaction. None of the goodwill recorded is deductible in Mexico for income tax purposes.

Included in our Consolidated Statements of Operations are revenues and earnings of $6 million and $21 million, respectively, for the period May 1, 2010 to December 31, 2010 related to the assets acquired from El Paso Corporation. Pro forma impacts on revenues and earnings for Sempra Energy had the acquisition occurred on January 1, 2009 were additional revenues of $3 million and earnings of $7 million in 2010.

SEMPRA RENEWABLES

We provide information about investment activity at Sempra Renewables in Note 4.

SEMPRA NATURAL GAS

Willmut Gas Company

In May 2012, Sempra Natural Gas acquired 100 percent of the outstanding common stock of Willmut Gas Company (Willmut Gas), a regulated natural gas distribution utility serving approximately 20,000 customers in Hattiesburg, Mississippi, in order to expand Sempra Natural Gas’ service area in the Southeast United States. Willmut Gas was purchased for $19 million in cash and the assumption of $10 million of liabilities. Included in the acquisition was $17 million in net property, plant and equipment. As a result of the acquisition, we recorded $10 million of goodwill.

The results of operations for Willmut Gas are included in our Consolidated Statements of Operations beginning from the date of acquisition, including revenues of $10 million and negligible earnings for the year ended December 31, 2012. Pro forma impacts on revenues and earnings for Sempra Energy had the acquisition occurred on January 1, 2011 were additional revenues of $7 million and negligible earnings in 2012 and additional revenues of $21 million, and negligible earnings for 2011.

Rockies Express

We discuss Sempra Natural Gas’ investment in Rockies Express Pipeline LLC (Rockies Express) in Note 4.

SEMPRA COMMODITIES

In 2010 and early 2011, Sempra Energy and The Royal Bank of Scotland plc (RBS) sold substantially all of the businesses and assets within RBS Sempra Commodities, a partnership formed in 2008.

We provide additional information concerning RBS Sempra Commodities and the sale transactions in Notes 4 and 5.

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

We generally account for investments under the equity method when we have an ownership interest of 20 to 50 percent. In these cases, our pro rata shares of the entities’ net assets are included in Investments on the Consolidated Balance Sheets. These investments are adjusted for our share of each investee’s earnings or losses, dividends, and other comprehensive income or loss.

The carrying value of unconsolidated entities is evaluated for impairment under the U.S. GAAP provisions for equity method investments.

We summarize our investment balances and earnings below:

EQUITY METHOD AND OTHER INVESTMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		Investment at December 31,
		2012		2011
Sempra Mexico:
Gasoductos de Chihuahua		$	340	$	302
Sempra Renewables:
Auwahi Wind			72		11
Cedar Creek 2 Wind Farm			93		95
Fowler Ridge 2 Wind Farm			47		50
Flat Ridge 2 Wind Farm			291		146
Mehoopany Wind Farm			89		88
Sempra Natural Gas:
Rockies Express Pipeline LLC			361		800
Parent and other:
RBS Sempra Commodities LLP			126		126
Other			8		11
Total equity method investments			1,427		1,629
Other(1)			89		42
Total		$	1,516	$	1,671
(1)	Other includes Sempra South American Utilities' $11 million in real estate investments at both December 31, 2012 and 2011, and Sempra Natural Gas' $74 million and $21 million investment in industrial development bonds at Mississippi Hub at December 31, 2012 and 2011, respectively.

EQUITY METHOD INVESTMENTS ON THE CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Years ended December 31,
		2012		2011		2010
Earnings (losses) recorded before income tax:
Parent and other:
Impairments		$	―	$	(16)	$	(305)
Other equity losses			―		(8)		(9)
Total RBS Sempra Commodities LLP		$	―	$	(24)	$	(314)
Sempra Natural Gas:
Impairment		$	(400)	$	―	$	―
Income tax make-whole payment received			41		―		―
Other equity earnings			47		43		43
Total Rockies Express Pipeline LLC		$	(312)	$	43	$	43
Sempra Renewables:
Cedar Creek 2 Wind Farm		$	(4)	$	(2)	$	―
Fowler Ridge 2 Wind Farm			(3)		(4)		1
Flat Ridge 2 Wind Farm			1		―		―
Sempra Natural Gas:
Elk Hills Power			―		―		(13)
Parent and other:
Other			(1)		(4)		(9)
Total other		$	(7)	$	(10)	$	(21)

Earnings (losses) recorded net of income tax:
Sempra South American Utilities:
Sodigas Pampeana and Sodigas Sur		$	―	$	(1)	$	(44)
Chilquinta Energía(1)			―		12		33
Luz del Sur(1)			―		12		41
Sempra Mexico:
Gasoductos de Chihuahua			36		29		19
		$	36	$	52	$	49
(1)	These investments were accounted for under the equity method until April 6, 2011, when they became consolidated entities upon our acquisition of additional ownership interests.

Our share of the undistributed earnings of equity method investments was $107 million and $78 million at December 31, 2012 and 2011, respectively. The December 31, 2012 and 2011 balances do not include remaining distributions of $126 million associated with our investment in RBS Sempra Commodities, which we expect to receive from the partnership as it is dissolved, as we discuss below.

Equity method goodwill related to our unconsolidated subsidiary located in Mexico is included in Investments on the Sempra Energy Consolidated Balance Sheets and its functional currency is U.S. dollars. These amounts are:

§	$65 million at December 31, 2012

§	$64 million at December 31, 2011

We discuss our equity method investments below.

SEMPRA SOUTH AMERICAN UTILITIES

As discussed in Note 3, on April 6, 2011, Sempra South American Utilities acquired from AEI its interests in Chilquinta Energía in Chile and Luz del Sur in Peru, and their subsidiaries. Prior to the acquisition, Sempra South American Utilities and AEI each owned 50 percent of Chilquinta Energía and approximately 38 percent of Luz del Sur. Chilquinta Energía and Luz del Sur are consolidated effective April 6, 2011 and are no longer recorded as equity method investments.

Sempra South American Utilities owns 43 percent of two Argentine natural gas utility holding companies, Sodigas Pampeana and Sodigas Sur. As a result of the devaluation of the Argentine peso at the end of 2001 and subsequent changes in the value of the peso, Sempra South American Utilities reduced the carrying value of its investment by a cumulative total of $270 million as of December 31, 2012. These noncash adjustments, based on fluctuations in the value of the Argentine peso, did not affect earnings, but were recorded in Comprehensive Income and Accumulated Other Comprehensive Income (Loss). The Argentine economic decline and government responses (including Argentina’s unilateral, retroactive abrogation of utility agreements early in 2002) continue to adversely affect the operations of these Argentine utilities. In 2002, Sempra South American Utilities initiated arbitration proceedings at the International Center for the Settlement of Investment Disputes (ICSID) under the 1994 Bilateral Investment Treaty between the United States and Argentina for recovery of the diminution of the value of its investments that has resulted from Argentine governmental actions. In September 2007, the tribunal awarded us compensation of $172 million, which included interest up to the award date. In January 2008, Argentina filed an action at the ICSID seeking to annul the award. In June 2010, the Annulment Committee granted Argentina’s petition for annulment of the award. This action did not impact our earnings, as we did not record the original award pending assurance of collectability. On November 3, 2010, Sempra South American Utilities resubmitted arbitration proceedings against Argentina before the ICSID on the same and similar grounds as the 2002 filing, and following submission of each party’s pleadings, a hearing on the claim was held in April 2012. The parties filed post-hearing briefs in June 2012, and we are awaiting a decision from the ICSID tribunal.

In a separate but related proceeding related to our political risk insurance policy, we negotiated a $48 million settlement that was collected in September 2010. The proceeds from the settlement are reported in Other Income, Net, on the Consolidated Statement of Operations for the year ended December 31, 2010.

In December 2006, we decided to sell our Argentine investments, and we continue to actively pursue their sale. We adjusted our investments to estimated fair value, recording a noncash impairment charge to 2006 earnings of $221 million. In September 2010, we concluded that, although the ICSID claim had been annulled, rate increases sought in Argentina would continue to be delayed. We believe this continued uncertainty has impacted the fair value of our net investment in the two Argentine companies, and recorded a noncash impairment charge of $24 million in the third quarter of 2010. The Sodigas Pampeana and Sodigas Sur fair value was significantly impacted by unobservable inputs (Level 3) as defined by the accounting guidance for fair value measures, which we discuss in Note 1 under “Fair Value Measurements.” The inputs included discount rates and estimated future cash flows. Such cash flows considered the value of those businesses with positive cash flows, the value of the non-operating assets, and the probability-weighted value of anticipated rate increases, considering both the timing and magnitude of such increases. In the fourth quarter of 2010, based on our continuing intention to sell the investments and recent comparable transactions in the Argentine energy market, we recorded an additional noncash impairment charge of $20 million. We determined the fair value using the recent comparable transactions (Level 2). Also in the fourth quarter of 2010, we recorded an income tax benefit of $15 million related to the impairment charges. These pretax adjustments to fair value are reported in Equity Earnings, Net of Income Tax, while the related tax benefit is reported in Income Tax Expense on the Consolidated Statement of Operations for the year ended December 31, 2010.

SEMPRA MEXICO

Sempra Mexico owns a 50-percent interest in Gasoductos de Chihuahua, a joint venture with PEMEX. The joint venture operates two natural gas pipelines and a propane system in northern Mexico. Sempra Mexico acquired its investment in Gasoductos de Chihuahua as part of the purchase of Mexican pipeline and natural gas infrastructure assets that we discuss in Note 3.

SEMPRA RENEWABLES

Sempra Renewables accounts for its investments in all of the following projects using the equity method.

During 2012 and 2011, Sempra Renewables invested $291 million and $146 million, respectively, in a joint venture with BP Wind Energy, a wholly owned subsidiary of BP p.l.c., to develop the 470-MW Flat Ridge 2 Wind Farm project near Wichita, Kansas, which became operational in December 2012. In December 2012, Sempra Renewables received a $148 million return of investment from Flat Ridge 2.

During 2012 and 2011, Sempra Renewables invested $20 million and $88 million, respectively, in a joint venture with BP Wind Energy to develop the 141-MW Mehoopany Wind Farm project near Wyoming County, Pennsylvania, which became operational in December 2012. In 2012, Sempra Renewables received a $17 million return of capital from Mehoopany Wind.

During 2012 and 2011, Sempra Renewables invested $62 million and $11 million, respectively, in a joint venture with BP Wind Energy to develop the 21-MW Auwahi Wind project in the southeastern region of Maui, a project that was previously wholly owned by Sempra Renewables. The project became operational in December 2012.

In October 2010, Sempra Renewables invested $209 million to become an equal partner with BP Wind Energy to develop the 250-MW Cedar Creek 2 project near New Raymer, Colorado, which became operational in June 2011. Upon obtaining a construction loan in December 2010, the joint venture returned $96 million of Sempra Renewables’ investment.

During 2009, Sempra Renewables invested $235 million to become an equal partner with BP Wind Energy to develop the 200-MW Fowler Ridge 2 project near Indianapolis, Indiana, which became operational in December 2009. In August 2010, Sempra Renewables received a $180 million return of capital from Fowler Ridge 2.

We discuss Cedar Creek 2 and Fowler Ridge 2 further in Note 5.

SEMPRA NATURAL GAS

Sempra Natural Gas owns a 25-percent interest in Rockies Express, a partnership that operates a natural gas pipeline, the Rockies Express Pipeline (REX), that links producing areas in the Rocky Mountain region to the upper Midwest and the eastern United States. In November 2012, Kinder Morgan Energy Partners L.P. (KMP) sold its 50 percent interest in Rockies Express, as part of a larger asset group, to Tallgrass Energy Partners, L.P. (Tallgrass). Phillips 66 owns the remaining interest of 25 percent. Our total investment in Rockies Express is accounted for as an equity method investment. We made investments in Rockies Express of $65 million in 2010 and $625 million in 2009.

The general partner of KMP is Kinder Morgan, Inc. (KMI). As a condition of KMI receiving antitrust approval from the Federal Trade Commission (FTC) for its acquisition of El Paso Corporation, KMI agreed to divest certain assets in its natural gas pipeline group. Included in the asset group, as noted above, was KMP’s interest in Rockies Express. KMP recorded remeasurement losses during 2012 associated with these operations (classified as discontinued operations by KMP). We have recorded impairments of our partnership investment in Rockies Express of $300 million ($179 million after-tax) in the quarter ended June 30, 2012 and an additional $100 million ($60 million after-tax) in the quarter ended September 30, 2012, which are included in Equity Earnings (Losses), Before Income Tax – Rockies Express Pipeline LLC on the Consolidated Statements of Operations. Our remaining carrying value in Rockies Express as of December 31, 2012 is $361 million. We recorded the write-downs as a result of our estimate of fair value for our investment at the reporting date and our conclusion that the impairments are other-than-temporary, as required by U.S. GAAP. We discuss the fair value measurement of our investment in Rockies Express in Note 11.

For income tax purposes, upon KMP’s sale of its 50-percent interest in Rockies Express, the partnership was considered terminated under federal tax law and a new partnership immediately formed which triggered a restart of depreciation method on the partnership’s remaining tax basis of its tangible assets. As required by the LLC agreement, KMP made a cash make-whole payment to Sempra Natural Gas of $41 million in November 2012 which was recorded as equity income from Rockies Express.

The 550-MW Elk Hills Power (Elk Hills) plant is located near Bakersfield, California. On December 31, 2010, Sempra Natural Gas sold its 50-percent interest to Occidental Petroleum Corporation, Inc. for a cash purchase price plus year-end cash distribution totaling $179 million. In connection with the sale, Sempra Natural Gas recorded a $10 million pretax loss that is included in Equity Earnings (Losses), Before Income Tax — Other on the Consolidated Statement of Operations for the year ended December 31, 2010.

RBS SEMPRA COMMODITIES

RBS Sempra Commodities is a United Kingdom limited liability partnership formed by Sempra Energy and RBS in 2008 to own and operate the commodities-marketing businesses previously operated through wholly owned subsidiaries of Sempra Energy. We and RBS sold substantially all of the partnership’s businesses and assets in four separate transactions completed in July, November, and December of 2010 and February of 2011. We account for our investment in RBS Sempra Commodities under the equity method, and report our share of partnership earnings and other associated costs in Parent and Other.

We recorded no equity earnings or losses related to the partnership for the year ended December 31, 2012. Pretax equity losses from RBS Sempra Commodities were $24 million and $314 million for the years ended December 31, 2011 and 2010, respectively. The partnership income that is distributable to us on an annual basis is computed on the partnership’s basis of accounting, IFRS, as adopted by the European Union. For the year ended December 31, 2012, there was no distributable income or loss on an IFRS basis. For the years ended December 31, 2011 and 2010, our share of distributable income (loss), on an IFRS basis, was $(30) million and $53 million, respectively. Included in our pretax equity losses are impairment charges of $16 million ($10 million after-tax) in 2011 and $305 million ($139 million after-tax) in 2010. The impairment charges are included in Equity Earnings (Losses), Before Income Tax – RBS Sempra Commodities LLP on the Consolidated Statements of Operations. We discuss the fair value measurement of our investment in the partnership in Note 11.

Distributions received in 2010 for proceeds from the sale transaction completed in July 2010 were approximately $1 billion, including distributions of 2009 partnership income attributable to the businesses sold, which were $134 million of the $198 million in distributions we received in April 2010 discussed below. Distributions in 2010 for the proceeds from the sale transactions completed in November and December 2010 were $849 million.

In April 2011, we and RBS entered into a letter agreement (Letter Agreement) which amended certain provisions of the agreements that formed RBS Sempra Commodities. The Letter Agreement addresses the wind-down of the partnership and the distribution of the partnership’s remaining assets. In accordance with the Letter Agreement, we received distributions of $623 million in 2011. These distributions included sales proceeds and our portion of 2010 distributable income totaling $651 million, less amounts to settle certain liabilities that we owed to RBS of $28 million. We received cash distributions of earnings from the partnership of $198 million in 2010. We received no such cash distributions in 2012. The investment balance of $126 million at December 31, 2012 reflects remaining distributions expected to be received from the partnership in accordance with the Letter Agreement. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 15 under “Other Litigation.” In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership.

In connection with the Letter Agreement described above, we also released RBS from its indemnification obligations with respect to items for which J.P. Morgan Chase & Co. (JP Morgan), one of the buyers of the partnership’s businesses, has agreed to indemnify us.

NOTE 5. DEBT AND CREDIT FACILITIES

COMMITTED LINES OF CREDIT

At December 31, 2012, Sempra Energy Consolidated had an aggregate of $4.1 billion in committed lines of credit to provide liquidity and to support commercial paper and variable-rate demand notes, the major components of which we detail below. Available unused credit on these lines at December 31, 2012 was $3.2 billion.

Sempra Energy

In March 2012, Sempra Energy entered into a $1.067 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share. The facility replaced the $1.0 billion credit agreement that was scheduled to expire in 2014.

Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. The actual ratio at December 31, 2012, calculated as defined in the agreement, was 54.7 percent. The facility also provides for issuance of up to $635 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit.

At December 31, 2012, Sempra Energy had $54 million of letters of credit outstanding supported by the facility.

Sempra Global

In March 2012, Sempra Global entered into a $2.189 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 25 lenders. No single lender has greater than a 7-percent share. The facility replaced the $2.0 billion credit agreement that was scheduled to expire in 2014.

Sempra Energy guarantees Sempra Global’s obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter.

At December 31, 2012, Sempra Global had $825 million of commercial paper outstanding supported by the facility. At December 31, 2012 and 2011, respectively, $300 million and $400 million of commercial paper outstanding was classified as long-term debt based on management’s intent and ability to maintain this level of borrowing on a long-term basis either supported by this credit facility or by issuing long-term debt. This classification has no impact on cash flows.

California Utilities

In March 2012, SDG&E and SoCalGas entered into a combined $877 million, five-year syndicated revolving credit agreement expiring in March 2017. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $658 million, subject to a combined limit of $877 million for both utilities. It also provides for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $200 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. The facility replaced the $800 million combined credit agreement that was scheduled to expire in 2014.

Borrowings under the facility bear interest at benchmark rates plus a margin that varies with market index rates and the borrowing utility’s credit ratings. The agreement requires each utility to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. The actual ratios for SDG&E and SoCalGas at December 31, 2012, calculated as defined in the agreement, were 48.0 percent and 38.7 percent, respectively.

Each utility’s obligations under the agreement are individual obligations, and a default by one utility would not constitute a default by the other utility or preclude borrowings by, or the issuance of letters of credit on behalf of, the other utility.

At December 31, 2012, SDG&E and SoCalGas had no outstanding borrowings supported by the facility. Available unused credit on the line at December 31, 2012 was $658 million at both SDG&E and SoCalGas, subject to the combined limit on the facility of $877 million.

GUARANTEES

RBS Sempra Commodities

As we discuss in Note 4, in 2010 and early 2011, Sempra Energy, RBS and RBS Sempra Commodities sold substantially all of the businesses and assets within the partnership in four separate transactions. In connection with each of these transactions, the buyers were, subject to certain qualifications, obligated to replace any guarantees that we had issued in connection with the applicable businesses sold with guarantees of their own. The buyers have substantially completed this process with regard to all existing, open positions, except for one remaining position expected to terminate by January 2014. For those guarantees which have not been replaced, the buyers are obligated to indemnify us in accordance with the applicable transaction documents for any claims or losses in connection with the guarantees that we issued associated with the businesses sold. We provide additional information in Note 4.

At December 31, 2012, RBS Sempra Commodities no longer requires significant working capital support. However, we have provided back-up guarantees for a portion of RBS Sempra Commodities’ remaining trading obligations. A few of these back-up guarantees may continue for a prolonged period of time. RBS has fully indemnified us for any claims or losses in connection with these arrangements, with the exception of those obligations for which JP Morgan has agreed to indemnify us. We discuss the indemnification release in Note 4. We discuss additional matters related to our investment in RBS Sempra Commodities in Note 15.

Other Guarantees

Sempra Renewables and BP Wind Energy currently hold 50-percent interests in Fowler Ridge 2 and Cedar Creek 2. After completion of these projects and obtaining term financing in 2010, proceeds from the term loans were used to return $180 million and $96 million, respectively, of each owner’s joint venture investment. The term loan of $348 million obtained by Fowler Ridge 2 expires in August 2022, and the $275 million term loan obtained by Cedar Creek 2 expires in November 2023. The term loan agreements require Sempra Renewables and BP Wind Energy to return cash to the projects in the event that the projects do not meet certain cash flow criteria or in the event that the projects’ debt service and operation and maintenance reserve accounts are not maintained at specific thresholds. Sempra Renewables recorded liabilities of $3 million in 2011 and $9 million in 2010 for the fair value of its obligations associated with the cash flow requirements, which constitute guarantees. The liabilities are being amortized over their expected lives. The outstanding loans are not guaranteed by the partners.

WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on the total short-term debt outstanding at Sempra Energy were 0.72 percent and 0.93 percent at December 31, 2012 and December 31, 2011, respectively. The weighted average interest rates at December 31, 2012 and 2011 include interest rates for commercial paper borrowings classified as long-term, as we discuss above.

LONG-TERM DEBT

The following tables show the detail and maturities of long-term debt outstanding:

LONG-TERM DEBT
(Dollars in millions)
		December 31,
		2012		2011
SDG&E
First mortgage bonds:
	6.8% June 1, 2015	$	14	$	14
	5.3% November 15, 2015		250		250
	1.65% July 1, 2018(1)		161		161
	5.85% June 1, 2021(1)		60		60
	3% August 15, 2021		350		350
	6% June 1, 2026		250		250
	5% to 5.25% December 1, 2027(1)		150		150
	5.875% January and February 2034(1)		176		176
	5.35% May 15, 2035		250		250
	6.125% September 15, 2037		250		250
	4% May 1, 2039(1)		75		75
	6% June 1, 2039		300		300
	5.35% May 15, 2040		250		250
	4.5% August 15, 2040		500		500
	3.95% November 15, 2041		250		250
	4.3% April 1, 2042		250		―
			3,536		3,286
Other long-term debt (unsecured unless otherwise noted):
	5.9% Notes June 1, 2014		130		130
	5.3% Notes July 1, 2021(1)		39		39
	5.5% Notes December 1, 2021(1)		60		60
	4.9% Notes March 1, 2023(1)		25		25
	5.2925% OMEC LLC loan
	payable 2013 through April 2019 (secured by plant assets)		345		355
Capital lease obligations:
	Purchased-power agreements		178		180
	Other		7		13
			784		802
			4,320		4,088
Current portion of long-term debt			(16)		(19)
Unamortized discount on long-term debt			(12)		(11)
Total SDG&E			4,292		4,058

SoCalGas
First mortgage bonds:
	4.8% October 1, 2012		―		250
	5.5% March 15, 2014		250		250
	5.45% April 15, 2018		250		250
	5.75% November 15, 2035		250		250
	5.125% November 15, 2040		300		300
	3.75% September 15, 2042		350		―
			1,400		1,300
Other long-term debt (unsecured):
	4.75% Notes May 14, 2016(1)		8		8
	5.67% Notes January 18, 2028		5		5
Capital lease obligations			4		11
			17		24
			1,417		1,324
Current portion of long-term debt			(4)		(257)
Unamortized discount on long-term debt			(4)		(3)
Total SoCalGas			1,409		1,064

LONG-TERM DEBT (Continued)
(Dollars in millions)
		December 31,
		2012		2011
Sempra Energy
Other long-term debt (unsecured):
	6% Notes February 1, 2013		400		400
	8.9% Notes November 15, 2013, including $200 at variable rates after fixed-to-floating
	rate swaps effective January 2011 (8.05% at December 31, 2012)		250		250
	2% Notes March 15, 2014		500		500
	Notes at variable rates (1.07% at December 31, 2012) March 15, 2014		300		300
	6.5% Notes June 1, 2016, including $300 at variable rates after fixed-to-floating
	rate swaps effective January 2011 (4.64% at December 31, 2012)		750		750
	2.3% Notes April 1, 2017		600		―
	6.15% Notes June 15, 2018		500		500
	9.8% Notes February 15, 2019		500		500
	2.875% Notes October 1, 2022		500		―
	6% Notes October 15, 2039		750		750
	Employee Stock Ownership Plan Bonds at variable rates payable on demand November 1, 2014(1)		―		8
Market value adjustments for interest rate swaps, net (expire November 2013 and June 2016)			19		16
Sempra Global
Other long-term debt (unsecured):
	Commercial paper borrowings at variable rates, classified as long-term debt
	(0.62% weighted average at December 31, 2012)		300		400
Sempra South American Utilities
Other long-term debt (unsecured):
Chilquinta Energía
	2.75% Series A Bonds October 30, 2014(1)		86		24
	4.25% Series B Bonds October 30, 2030(1)		224		202
Luz del Sur
	Bank loans 6.2% to 6.75% payable 2013 through December 2016		31		41
	Notes at 4.75% to 7.09% payable 2013 through October 2022		284		185
Sempra Renewables
Other long-term debt (secured):
	Loan at variable rates payable 2013 through December 2028, including $83 at 4.54%
	after floating-to-fixed rate swaps effective June 2012 (2.82% at December 31, 2012)(1)		111		―
	Loans at 2.24% to 2.26% payable 2013 through January 2031		286		―
Sempra Natural Gas
First mortgage bonds (Mobile Gas):
	4.14% September 30, 2021		20		20
	5% September 30, 2031		42		42
Other long-term debt (unsecured unless otherwise noted):
	Notes at 2.87% to 3.51% payable 2013(1)(2)		17		24
	9% Notes May 13, 2013		1		1
	8.45% Notes payable 2013 through December 2017, secured		25		29
	4.5% Notes July 1, 2024, secured(1)		74		21
	Industrial development bonds at variable rates (0.15% at December 31, 2012)
	August 15, 2037, secured(1)		55		55
			6,625		5,018
Current portion of long-term debt			(705)		(60)
Unamortized discount on long-term debt			(8)		(9)
Unamortized premium on long-term debt			8		7
Total other Sempra Energy			5,920		4,956
Total Sempra Energy Consolidated		$	11,621	$	10,078
(1)	Callable long-term debt.
(2)	Classified as long-term debt based on management's intent and ability to convert the debt to equity upon maturity.

MATURITIES OF LONG-TERM DEBT(1)
(Dollars in millions)
								Total
						Other		Sempra
						Sempra		Energy
		SDG&E		SoCalGas		Energy		Consolidated
2013		$	10	$	―	$	721	$	731
2014			140		250		970		1,360
2015			274		―		70		344
2016			10		8		796		814
2017			10		―		649		659
Thereafter			3,691		1,155		3,400		8,246
Total		$	4,135	$	1,413	$	6,606	$	12,154
(1)	Excludes capital lease obligations and market value adjustments for interest rate swaps.

Various long-term obligations totaling $6.3 billion at Sempra Energy at December 31, 2012 are unsecured. This includes unsecured long-term obligations totaling $254 million at SDG&E and $13 million at SoCalGas.

CALLABLE LONG-TERM DEBT

At the option of Sempra Energy, SDG&E and SoCalGas, certain debt is callable subject to premiums at various dates:

CALLABLE LONG-TERM DEBT
(Dollars in millions)
							Total
					Other		Sempra
					Sempra		Energy
	SDG&E		SoCalGas		Energy		Consolidated
2013	$	105	$	―	$	343	$	448
2014		124		―		224		348
2015		266		―		―		266
2016		―		8		―		8
2017		75		―		―		75
after 2017		176		―		―		176
Total	$	746	$	8	$	567	$	1,321
Callable bonds subject to make-whole provisions	$	2,900	$	1,400	$	4,837	$	9,137

In addition, the OMEC LLC project financing loan discussed in Note 1, with $345 million of borrowings at December 31, 2012, may be prepaid at the borrowers’ option.

FIRST MORTGAGE BONDS

The California Utilities issue first mortgage bonds which are secured by a lien on utility plant. The California Utilities may issue additional first mortgage bonds upon compliance with the provisions of their bond agreements (indentures). These indentures require, 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 $3.6 billion of first mortgage bonds at SDG&E and $863 million at SoCalGas at December 31, 2012.

Mobile Gas also issues first mortgage bonds secured by utility plant.

In March 2012, SDG&E publicly offered and sold $250 million of 4.30-percent first mortgage bonds maturing in 2042.

In September 2012, SoCalGas publicly offered and sold $350 million of 3.75-percent first mortgage bonds maturing in 2042.

INDUSTRIAL DEVELOPMENT BONDS

SDG&E

In September 2012, SDG&E remarketed $161 million of industrial development variable rate demand notes at a fixed rate of 1.65 percent maturing in 2018 and $75 million of variable rate demand notes at a fixed rate of 4.00 percent maturing in 2039. The bonds were originally issued as insured, auction-rate securities, the proceeds of which were loaned to SDG&E, and are serviced with payments on SDG&E first mortgage bonds that have terms corresponding to those of the industrial development bonds that they secure.

Sempra Natural Gas

To secure an approved exemption from sales and use tax, Sempra Natural Gas has incurred through December 31, 2012, $254 million ($53 million in 2012, $84 million in 2011, $42 million in 2010, and $75 million in 2009) out of a maximum available $265 million of long-term debt related to the construction and equipping of its Mississippi Hub natural gas storage facility. After a redemption of $180 million in December 2011, the debt balance remaining at December 31, 2012, is $74 million. The debt is payable to the Mississippi Business Finance Corporation (MBFC), and we recorded bonds receivable from the MBFC for the same amount. Both the financing obligation and the bonds receivable have interest rates of 4.5 percent and are due on July 1, 2024.

OTHER LONG-TERM DEBT

Sempra Energy

In March 2012, Sempra Energy publicly offered and sold $600 million of 2.30-percent notes maturing in 2017. In September 2012, Sempra Energy publicly offered and sold $500 million of 2.875-percent notes maturing in 2022.

Sempra South American Utilities

Chilquinta Energía has outstanding Chilean public bonds denominated in Chilean Unidades de Fomento. The Chilean Unidad de Fomento is a unit of account used in Chile that is adjusted for inflation, and its value is quoted in Chilean Pesos. In 2009, Parent and Other purchased $50 million of 2.75-percent bonds which were eliminated in consolidation until their remarketing in October 2012.

Luz del Sur has outstanding corporate bonds which are denominated in the local currency. During 2012, Luz del Sur publicly offered and sold additional bonds, as follows:

2012 ISSUANCES OF LONG TERM DEBT – LUZ DEL SUR
(Dollars in millions)
	Amount at
Month Issued	Issuance		Interest Rate	Maturity Date
February	$	21	5.97%	February 8, 2017
February		9	6.34%	February 8, 2019
July		25	5.44%	July 6, 2019
October		30	5.25%	October 29, 2022
December		30	4.75%	December 14, 2020

Sempra Renewables

In June 2012, Sempra Renewables obtained a $117 million variable rate loan, the proceeds of which were applied to construction costs of the Copper Mountain Solar 1 project. The loan is payable semi-annually and fully matures in December 2028. To partially moderate its exposure to interest rate changes, Sempra Renewables has also entered into floating-to-fixed interest rate swaps maturing December 2028. As of December 31, 2012, the amount of the loan outstanding is $111 million, of which $83 million has an interest rate that is effectively fixed at 4.54 percent. The remaining balance of $28 million bears interest at rates varying with market rates (2.82 percent at December 31, 2012).

In September 2011, Sempra Renewables entered into a loan agreement with the U.S. Department of Energy (DOE) to borrow up to $337 million, which includes $7 million of accrued interest. Sempra Renewables took draws of $253 million in November 2012 at 2.26 percent and $33 million in December 2012 at 2.24 percent, the proceeds of which were applied to construction costs of the Mesquite Solar 1 project. The loan is payable semi-annually and fully matures in January 2031.

INTEREST RATE SWAPS

We discuss our fair value interest rate swaps and interest rate swaps to hedge cash flows in Note 10.

NOTE 6. FACILITIES UNDER JOINT OWNERSHIP

San Onofre Nuclear Generating Station (SONGS) and the Southwest Powerlink transmission line are owned jointly by SDG&E with other utilities. SDG&E’s interests at December 31, 2012 were as follows:

				Southwest
(Dollars in millions)	SONGS			Powerlink
Percentage ownership		20	%		91	%
Utility plant in service	$	351		$	330
Accumulated depreciation and amortization		65			198
Construction work in progress		115			11

SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of each project and participates in decisions concerning operations and capital expenditures.

SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Consolidated Statements of Operations.

SONGS DECOMMISSIONING

Objectives, work scope, and procedures for the dismantling and decontamination of SONGS’ three units must meet the requirements of the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA), the U.S. Department of the Navy (the land owner), the CPUC and other regulatory bodies.

SDG&E’s asset retirement obligation related to decommissioning costs for the SONGS units was $558 million at December 31, 2012. That amount includes the cost to decommission Units 2 and 3, and the remaining cost to complete the decommissioning of Unit 1, which is substantially complete. The remaining work on Unit 1 will be completed when Units 2 and 3 are decommissioned. Southern California Edison Company (Edison), the operator of SONGS, updates decommissioning cost studies every three years. Rate recovery of decommissioning costs is allowed until the time that the costs are fully recovered and is subject to adjustment every three years based on the costs allowed by regulators. Collections are authorized to continue until 2022. The most recent cost study was approved by the CPUC in July 2010. SDG&E’s share of decommissioning costs under the approved study is approximately $768 million in 2008 dollars and $880 million escalated to 2012 dollars.

In December 2012, SDG&E, along with Edison, filed a joint application for the 2012 decommissioning cost study. SDG&E’s updated estimated share of decommissioning costs under the application is approximately $860 million.

Unit 1 was permanently shut down in 1992, and physical decommissioning began in January 2000. Most structures, foundations and large components have been dismantled, removed and disposed of. Spent nuclear fuel has been removed from the Unit 1 Spent Fuel Pool and stored on-site in an independent spent fuel storage installation (ISFSI) licensed by the NRC. The decommissioning of Unit 1 remaining structures (subsurface and intake/discharge) will take place when Units 2 and 3 are decommissioned. The ISFSI will be decommissioned after a permanent storage facility becomes available and the DOE removes the spent fuel from the site. The Unit 1 reactor vessel is expected to remain on site until Units 2 and 3 are decommissioned.

SONGS OUTAGE, INSPECTION AND REPAIR ISSUES

We discuss the current SONGS outage, inspection and repair issues and related regulatory matters in Note 14.

SPENT NUCLEAR FUEL

SONGS owners are responsible for interim storage of spent nuclear fuel generated at SONGS until the DOE accepts it for final disposal. Spent nuclear fuel has been stored in the SONGS Units 1, 2 and 3 spent fuel pools and in the ISFSI, as follows:

§	Movement of all Unit 1 spent fuel to the ISFSI was completed in 2005.

§	Spent fuel for Unit 2 is being stored in both the Unit 2 spent fuel pool and the ISFSI.

§	Spent fuel for Unit 3 is being stored in both the Unit 3 spent fuel pool and the ISFSI.

A second ISFSI pad, completed in 2009, provides sufficient storage capacity to allow for the continued operation of SONGS through 2022.

The amounts collected in rates for SONGS’ decommissioning are invested in externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations. These trusts are shown on the Sempra Energy and SDG&E Consolidated Balance Sheets at fair value with the offsetting credits recorded in Regulatory Liabilities Arising from Removal Obligations.

The following table shows the fair values and gross unrealized gains and losses for the securities held in the trust funds. We provide additional fair value disclosures for the trusts in Note 11.

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
				Gross		Gross		Estimated
				Unrealized		Unrealized		Fair
		Cost		Gains		Losses		Value
As of December 31, 2012:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies (1)		$	147	$	9	$	―	$	156
Municipal bonds (2)			57		6		―		63
Other securities (3)			121		10		(1)		130
Total debt securities			325		25		(1)		349
Equity securities			249		292		(2)		539
Cash and cash equivalents			20		―		―		20
Total		$	594	$	317	$	(3)	$	908
As of December 31, 2011:
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		$	157	$	13	$	―	$	170
Municipal bonds			72		5		―		77
Other securities			76		3		(1)		78
Total debt securities			305		21		(1)		325
Equity securities			246		227		(5)		468
Cash and cash equivalents			11		―		―		11
Total		$	562	$	248	$	(6)	$	804
(1)	Maturity dates are 2013-2043.
(2)	Maturity dates are 2013-2111.
(3)	Maturity dates are 2013-2112.

The following table shows the proceeds from sales of securities in the trusts and gross realized gains and losses on those sales.

SALES OF SECURITIES
(Dollars in millions)
		Years ended December 31,
		2012		2011		2010
Proceeds from sales(1)		$	723	$	715	$	351
Gross realized gains			21		75		11
Gross realized losses			(13)		(52)		(11)
(1)	Excludes securities that are held to maturity.

The increase in sales in 2011 as compared to 2010 was predominantly due to a restructuring of investments within the trusts to achieve a more broadly diversified asset mix. Within the fixed income portfolio, we reduced the allocation to U.S. Treasury debt-securities, while increasing holdings of other fixed income securities, including corporate and municipal bonds, and investments in mortgage- and asset-backed securities. We restructured the international equity portfolio to invest in both developed and emerging market equity securities. In 2012, we continued to restructure the investments within the trusts to achieve a more broadly diversified asset mix, including investments in global fixed income securities. Additionally, we shifted to more active fund managers, which also contributed to higher sales proceeds.

Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on the Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.

Customer contribution amounts are determined by the CPUC using estimates of after-tax investment returns, decommissioning costs, and decommissioning cost escalation rates. Changes in investment returns and decommissioning costs may result in a change in future customer contributions.

We discuss the impact of asset retirement obligations in Note 1. We provide additional information about SONGS in Notes 14 and 15.

NOTE 7. INCOME TAXES

Reconciliation of net U.S. statutory federal income tax rates to the effective income tax rates is as follows:

RECONCILIATION OF FEDERAL INCOME TAX RATES TO EFFECTIVE INCOME TAX RATES

	Years ended December 31,
	2012		2011		2010
Sempra Energy Consolidated
U.S. federal statutory income tax rate	35	%	35	%	35	%
Utility depreciation	6		3		6
State income taxes, net of federal income tax benefit	(1)		2		―
Tax credits	(7)		(1)		(3)
Allowance for equity funds used during construction	(4)		(2)		(3)
Non-U.S. earnings taxed at lower statutory income tax rates	(4)		(8)		(12)
Adjustments to prior years’ income tax items	(1)		―		(3)
Utility repairs expenditures	(8)		(1)		(2)
Self-developed software expenditures	(5)		(3)		(5)
Mexican foreign exchange and inflation effects	1		(1)		2
Variable interest entities	(1)		―		1
Life insurance contracts	(7)		―		―
Impact of change in income tax law	―		―		2
Impact of impairment of an equity method investment	―		―		(2)
Other, net	2		(1)		1
Effective income tax rate	6	%	23	%	17	%
SDG&E
U.S. federal statutory income tax rate	35	%	35	%	35	%
Depreciation	4		4		5
State income taxes, net of federal income tax benefit	4		5		4
Allowance for equity funds used during construction	(4)		(4)		(3)
Adjustments to prior years’ income tax items	(3)		―		(3)
Utility repairs expenditures	(4)		(1)		(2)
Self-developed software expenditures	(3)		(3)		(2)
Variable interest entity	(1)		(1)		1
Impact of change in income tax law	―		―		1
Other, net	(1)		(1)		(3)
Effective income tax rate	27	%	34	%	33	%
SoCalGas
U.S. federal statutory income tax rate	35	%	35	%	35	%
Depreciation	7		6		5
State income taxes, net of federal income tax benefit	3		4		4
Utility repairs expenditures	(12)		―		―
Self-developed software expenditures	(9)		(7)		(6)
Allowance for equity funds used during construction	(2)		(2)		(1)
Impact of change in income tax law	―		―		3
Other, net	(1)		(3)		(2)
Effective income tax rate	21	%	33	%	38	%

In 2011 and 2012, non-U.S. earnings taxed at lower statutory income tax rates than the U.S. are primarily related to operations in Mexico, Chile and Peru. In 2011, the earnings in Chile and Peru include the impact of the $277 million remeasurement gain related to our acquisition of controlling interests in Chilquinta Energía and Luz del Sur, which was non-taxable. We discuss this gain further in Note 3.

In 2010, the non-U.S. earnings taxed at lower statutory income tax rates than the U.S. are primarily related to operations in Mexico, the Netherlands and the U.K. The earnings in the Netherlands and the U.K. are related to our investment in RBS Sempra Commodities. In 2010, the earnings activity for RBS Sempra Commodities reflected the following related to the sale of our share of our investment in the joint venture (as discussed in Note 4):

§	approximately $150 million of a total $175 million non-U.S. gain on sale of the businesses and assets within the joint venture was non-taxable; and

§	approximately $40 million of non-U.S. earnings from the operations of the joint venture and approximately $25 million of the non-U.S. gain on sale of the businesses and assets within the joint venture were net of income tax paid by the partnership.

Utility repairs expenditures significantly affecting the effective income tax rates for Sempra Energy Consolidated, SDG&E and SoCalGas in 2012 are due to a change in the income tax treatment of certain repairs that are capitalized for financial statement purposes. The change in income tax treatment of certain repairs for electric transmission and distribution assets, which applied to SDG&E, was made pursuant to an Internal Revenue Service (IRS) Revenue Procedure providing a safe harbor for deducting certain repairs expenditures from taxable income when incurred for tax years beginning on or after January 1, 2011. A $22 million benefit for SDG&E related to the 2011 U.S. federal income tax return filed in the third quarter of 2012 is included in Adjustments to Prior Years’ Income Tax Items in the table above. The change in income tax treatment of certain repairs expenditures for gas plant assets, which applied to SoCalGas, was made pursuant to an IRS Revenue Procedure, which allows, under an Internal Revenue Code section, such expenditures to be deducted from taxable income when incurred.

Life insurance contracts significantly affect the effective tax rate for Sempra Energy Consolidated in 2012 primarily due to our decision in the second quarter of 2012 to hold life insurance contracts kept in support of certain benefit plans to term. Previously, we took the position that we might cash in or sell these contracts before maturity, which required that we record deferred income taxes on unrealized gains on investments held within the insurance contracts.

The CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which results in impacting the current effective income tax rate. Therefore, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the effective income tax rate. The following items are subject to flow-through treatment:

§	repairs expenditures related to a certain portion of utility plant fixed assets

§	the equity portion of AFUDC

§	a portion of the cost of removal of utility plant assets

§	self-developed software expenditures

§	depreciation on a certain portion of utility plant assets

We use the deferral method for investment tax credits (ITC). For certain solar and wind generating assets being placed into service during 2011 and 2012, we have elected to seek cash grants rather than ITC for which the projects also qualify. Accordingly, cash grant accounting is required to be applied. Grant accounting for cash grants is very similar to the deferral method of accounting for ITC, the primary difference being the recording of a cash grant receivable instead of an income tax receivable.

Under the deferral method of accounting for ITC and under grant accounting for cash grants, we record a deferred income tax benefit, on day one, which is reflected in income tax expense by recording a deferred income tax asset during the year the renewable energy assets are placed in service. This deferred income tax asset results from the day-one difference in the income tax basis and financial statement basis of the renewable energy assets, referred to as the day-one basis difference. The financial statement basis of the assets is reduced by 100 percent of the ITC or grant expected; U.S. federal income tax basis is reduced by only 50 percent for both ITC and grants; and state income tax basis is reduced 50 percent for grants and not at all for ITC.

Cash grants are generally expected to be collectable in cash shortly after a project is constructed. Conversion of ITC to cash is generally dependent on reducing income tax payments and thus the existence of a U.S. federal net operating loss (NOL) carryforward can result in delaying this conversion.

The geographic components of Income Before Income Taxes and Equity Earnings of Certain Unconsolidated Subsidiaries at Sempra Energy are as follows:

	Years ended December 31,
(Dollars in millions)	2012		2011		2010
U.S.	$	442	$	1,011	$	448
Non-U.S.		501		712		339
Total	$	943	$	1,723	$	787

The components of income tax expense are as follows:

INCOME TAX EXPENSE (BENEFIT)
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
Sempra Energy Consolidated
Current:
U.S. Federal	$	(36)	$	76	$	69
U.S. State		(6)		(3)		(3)
Non-U.S.		144		149		30
Total		102		222		96
Deferred:
U.S. Federal		(63)		176		(18)
U.S. State		3		43		32
Non-U.S.		20		(45)		27
Total		(40)		174		41
Deferred investment tax credits		(3)		(2)		(4)
Total income tax expense	$	59	$	394	$	133
SDG&E
Current:
U.S. Federal	$	(109)	$	(59)	$	69
U.S. State		14		6		52
Total		(95)		(53)		121
Deferred:
U.S. Federal		255		253		75
U.S. State		30		36		(21)
Total		285		289		54
Deferred investment tax credits		―		1		(2)
Total income tax expense	$	190	$	237	$	173
SoCalGas
Current:
U.S. Federal	$	(73)	$	(6)	$	43
U.S. State		24		19		26
Total		(49)		13		69
Deferred:
U.S. Federal		136		128		108
U.S. State		(6)		5		2
Total		130		133		110
Deferred investment tax credits		(2)		(3)		(3)
Total income tax expense	$	79	$	143	$	176

We show the components of deferred income taxes at December 31 for Sempra Energy, SDG&E and SoCalGas in the tables below:

DEFERRED INCOME TAXES FOR SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
	December 31,
	2012		2011
Deferred income tax liabilities:
Differences in financial and tax bases of depreciable and amortizable assets	$	3,710	$	2,360
Regulatory balancing accounts		770		456
Unrealized revenue		3		13
Loss on reacquired debt		9		12
Property taxes		46		43
Difference in financial and tax bases of partnership interests		118		152
Other deferred income tax liabilities		55		30
Total deferred income tax liabilities		4,711		3,066
Deferred income tax assets:
Investment tax credits		67		22
Equity losses		16		16
Net operating losses		1,898		811
Compensation-related items		156		140
Postretirement benefits		587		361
Other deferred income tax assets		90		34
State income taxes		58		58
Bad debt allowance		8		8
Litigation and other accruals not yet deductible		7		5
Deferred income tax assets before valuation allowances		2,887		1,455
Less: valuation allowances		128		82
Total deferred income tax assets		2,759		1,373
Net deferred income tax liability	$	1,952	$	1,693
Our policy is to show deferred income taxes of VIEs on a net basis, including valuation allowances. See table “Amounts Associated with Otay Mesa VIE” in Note 1 for further information.

DEFERRED INCOME TAXES FOR SDG&E AND SOCALGAS
(Dollars in millions)
	SDG&E				SoCalGas
	December 31,				December 31,
	2012		2011		2012		2011
Deferred income tax liabilities:
Differences in financial and tax bases of
utility plant and other assets	$	1,947	$	1,152	$	938	$	632
Regulatory balancing accounts		344		230		439		236
Loss on reacquired debt		4		5		7		8
Property taxes		32		30		15		14
Other		22		19		―		1
Total deferred income tax liabilities		2,349		1,436		1,399		891
Deferred income tax assets:
Net operating losses		446		―		34		―
Postretirement benefits		137		115		370		161
Investment tax credits		16		17		14		16
Compensation-related items		14		15		48		39
State income taxes		31		24		18		18
Litigation and other accruals not yet deductible		38		33		21		22
Hedging transaction		1		―		7		7
Other		4		3		9		8
Total deferred income tax assets		687		207		521		271
Net deferred income tax liability	$	1,662	$	1,229	$	878	$	620
Our policy is to show deferred income taxes of VIEs on a net basis, including valuation allowances. See table “Amounts Associated with Otay Mesa VIE” in Note 1 for further information.

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

NET DEFERRED INCOME TAX LIABILITY
(Dollars in millions)
	Sempra Energy
	Consolidated				SDG&E				SoCalGas
	2012		2011		2012		2011		2012		2011
Current (asset) liability	$	(148)	$	173	$	26	$	62	$	(3)	$	44
Noncurrent liability		2,100		1,520		1,636		1,167		881		576
Total	$	1,952	$	1,693	$	1,662	$	1,229	$	878	$	620

At December 31, 2012, Sempra Energy has recorded a valuation allowance against a portion of its total deferred income tax assets, as shown above in the “Deferred Income Taxes for Sempra Energy Consolidated” table. A valuation allowance is recorded when, based on more-likely-than-not criteria, negative evidence outweighs positive evidence with regard to our ability to realize a deferred income tax asset in the future. Of the valuation allowances recorded to date, the negative evidence outweighs the positive evidence primarily due to cumulative pretax losses in various U.S. state and non-U.S. jurisdictions resulting in a deferred income tax asset related to NOLs, as discussed below, that we currently do not believe will be realized on a more-likely-than-not basis. At both Sempra Energy and SDG&E, deferred income taxes for variable interest entities are shown on a net basis. Therefore, a valuation allowance of $108 million at December 31, 2012 and $116 million at December 31, 2011 related to variable interest entities is not reflected in the tables above. Of Sempra Energy’s total valuation allowance of $128 million at December 31, 2012, $20 million is related to non-U.S. NOLs, $100 million to U.S. state NOLs and $8 million to other future U.S. state deductions. Of Sempra Energy’s total valuation allowance of $82 million at December 31, 2011, $14 million is related to non-U.S. NOLs, $8 million to other future non-U.S. deductions, and $60 million to U.S. state NOLs. The total valuation allowance increased in 2012 primarily due to the increase in the valuation allowance established for U.S. state NOLs. We believe that it is more-likely-than-not that the remainder of the total deferred income tax asset is realizable.

At December 31, 2012, Sempra Energy’s non-U.S. subsidiaries had $71 million of unused NOLs available to utilize in the future to reduce Sempra Energy’s future non-U.S. income tax expense related to our holding companies in Denmark, Mexico, the Netherlands and Spain. The carryforward periods for our non-U.S. unused NOLs are as follows: $11 million does not expire and $60 million expires between 2013 and 2027. As of December 31, 2012, our Mexican subsidiaries have NOLs of $162 million, of which $142 million have been utilized on a consolidated level. These NOLs are subject to recapture between 2013 and 2017 if the Mexican subsidiary that generated them does not have sufficient taxable income itself to realize them within 5 years. These NOLs expire between 2016 and 2022. Sempra Energy’s U.S. subsidiaries had $2.2 billion of unused U.S. state NOLs, primarily in Alabama, California, Connecticut, District of Columbia, Indiana, Louisiana, Minnesota, New Jersey, New York and Oklahoma. These U.S. state NOLs expire between 2013 and 2032. We have not recorded deferred income tax benefits on a portion of Sempra Energy’s total non-U.S. and state NOLs because we currently believe they will not be entirely realized on a more-likely-than-not basis, as discussed above. Sempra Energy’s consolidated U.S. subsidiaries had $4.7 billion of unused U.S. federal consolidated NOLs (the 2011 NOL of $2.1 billion expires in 2031 and the 2012 NOL of $2.6 billion expires in 2032). We have recorded deferred income tax benefits on these NOLs, in total, because we currently believe they will be realized on a more-likely-than-not basis.

At December 31, 2012, SDG&E had $1.3 billion of unused U.S. federal NOLs (the 2011 NOL of $78 million expires in 2031 and the 2012 NOL of $1.2 billion expires in 2032). We have recorded deferred income tax benefits on these NOLs, in total, because we currently believe they will be realized on a more-likely-than-not basis. As of December 31, 2012, SoCalGas had a $96 million unused U.S. federal NOL, which expires in 2032. We have recorded a deferred income tax benefit on this NOL, in total, because we currently believe it will be realized on a more-likely-than-not basis.

At December 31, 2012, Sempra Energy had not recognized a U.S. deferred income tax liability related to a $2.9 billion basis difference between its financial statement and income tax investment amount in its non-U.S. subsidiaries. This basis difference consists of $2.9 billion of cumulative undistributed earnings that we expect to reinvest indefinitely outside of the U.S., which includes the $0.3 billion gain related to the remeasurement of equity method investments in Chilquinta Energía and Luz del Sur that we discuss in Note 3. These cumulative undistributed earnings have previously been reinvested or will be reinvested in active non-U.S. operations, thus we do not intend to use these earnings as a source of funding for U.S. operations. It is not practical to determine the hypothetical unrecognized amount of U.S. deferred income taxes that might be payable if the cumulative undistributed earnings were eventually distributed or the investments were sold. U.S. deferred income taxes would be recorded on $2.9 billion of the basis difference related to cumulative undistributed earnings if we no longer intend to indefinitely reinvest all, or a part, of the cumulative undistributed earnings.

Following is a summary of unrecognized income tax benefits for the years ended December 31:

SUMMARY OF UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	Sempra Energy
	Consolidated						SDG&E						SoCalGas
	2012		2011		2010		2012		2011		2010		2012		2011		2010
Total	$	82	$	72	$	97	$	12	$	7	$	5	$	5	$	―	$	8
Of the total, amounts related to tax
positions that, if recognized, in
future years, would:
decrease the effective tax rate	$	(81)	$	(72)	$	(76)	$	(12)	$	(7)	$	(5)	$	(5)	$	―	$	(1)
increase the effective tax rate		16		7		5		12		7		5		4		―		―

Following is a reconciliation of the changes in unrecognized income tax benefits for the years ended December 31:

RECONCILIATION OF UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	2012		2011		2010
Sempra Energy Consolidated:
Balance as of January 1	$	72	$	97	$	94
Increase in prior period tax positions		2		7		29
Decrease in prior period tax positions		(1)		(26)		(4)
Increase in current period tax positions		10		3		5
Settlements with taxing authorities		(1)		(9)		(9)
Expirations of statutes of limitations		―		―		(18)
Balance as of December 31	$	82	$	72	$	97
SDG&E:
Balance as of January 1	$	7	$	5	$	14
Increase in prior period tax positions		1		―		―
Decrease in prior period tax positions		―		―		(3)
Increase in current period tax positions		4		2		3
Settlements with taxing authorities		―		―		(9)
Balance as of December 31	$	12	$	7	$	5
SoCalGas:
Balance as of January 1	$	―	$	8	$	11
Increase in prior period tax positions		―		2		5
Increase in current period tax positions		5		―		―
Settlements with taxing authorities		―		(10)		―
Expirations of statutes of limitations		―		―		(8)
Balance as of December 31	$	5	$	―	$	8

It is reasonably possible that within the next 12 months unrecognized income tax benefits could decrease due to the following:

POSSIBLE DECREASES IN UNRECOGNIZED INCOME TAX BENEFITS WITHIN 12 MONTHS
(Dollars in millions)
	At December 31,
	2012		2011		2010
Sempra Energy Consolidated:
Expiration of statutes of limitations on tax assessments	$	(7)	$	(7)	$	(6)
Potential resolution of audit issues with various
U.S. federal, state and local and non-U.S. taxing authorities		(10)		―		(35)
	$	(17)	$	(7)	$	(41)
SDG&E:
Potential resolution of audit issues with various
U.S. federal, state and local and non-U.S. taxing authorities	$	(5)	$	―	$	―
SoCalGas:
Expiration of statutes of limitations on tax assessments	$	―	$	―	$	(5)
Potential resolution of audit issues with various
U.S. federal, state and local taxing authorities		(4)		―		―
	$	(4)	$	―	$	(5)

Amounts accrued for interest expense and penalties associated with unrecognized income tax benefits are included in income tax expense in the Consolidated Statements of Operations for the years ended December 31 as follows:

INTEREST EXPENSE AND PENALTIES ASSOCIATED WITH UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	Sempra Energy
	Consolidated						SDG&E						SoCalGas
	2012		2011		2010		2012		2011		2010		2012		2011		2010
Interest expense (benefit)	$	―	$	(3)	$	4	$	―	$	―	$	3	$	―	$	(1)	$	1
Penalties		―		(1)		―		―		―		―		―		―		―

Amounts accrued at December 31 on the Consolidated Balance Sheets for interest expense and penalties associated with unrecognized income tax benefits are as follows:

ACCRUED INTEREST EXPENSE AND PENALTIES ASSOCIATED WITH UNRECOGNIZED INCOME TAX BENEFITS
(Dollars in millions)
	Sempra Energy
	Consolidated				SDG&E				SoCalGas
	2012		2011		2012		2011		2012		2011
Interest expense	$	3	$	3	$	1	$	1	$	1	$	1
Penalties		3		3		―		―		―		―

INCOME TAX AUDITS

Sempra Energy is subject to U.S. federal income tax as well as to income tax of multiple state and non-U.S. jurisdictions. We remain subject to examination for U.S. federal tax years after 2008. We are subject to examination by major state tax jurisdictions for tax years after 2005. Certain major non-U.S. income tax returns from 2006 through the present are open to examination.

In addition, we have filed state refund claims for tax years back to 1998, and PE has filed state refund claims for tax years back to 1993. The pre-2006 tax years are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these years.

SDG&E and SoCalGas are subject to U.S. federal income tax as well as income tax of state jurisdictions. They remain subject to examination for U.S. federal years after 2008 and by major state tax jurisdictions for years after 2005.

NOTE 8. EMPLOYEE BENEFIT PLANS

We are required by applicable U.S. GAAP to:

§	recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the statement of financial position;

§	measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year (with limited exceptions); and

§	recognize changes in the funded status of pension and other postretirement benefit plans in the year in which the changes occur. Generally, those changes are reported in other comprehensive income and as a separate component of shareholders’ equity.

The detailed information presented below covers the employee benefit plans of Sempra Energy and its principal subsidiaries.

Sempra Energy has funded and unfunded noncontributory defined benefit plans, including separate plans for SDG&E and SoCalGas, which collectively cover substantially all domestic and certain foreign employees, and members of the Sempra Energy board of directors who were participants in a predecessor plan on or before June 1, 1998. The plans generally provide defined benefits based on years of service and either final average or career salary.

Chilquinta Energía, which was acquired by Sempra Energy in 2011, has an unfunded contributory defined benefit plan covering all employees hired before October 1, 1981 and an unfunded noncontributory termination indemnity obligation covering all employees. The plans generally provide defined benefits to retirees based on date of hire, years of service and final average salary.

Sempra Energy also has other postretirement benefit plans (PBOP), including separate plans for SDG&E and SoCalGas, which collectively cover all domestic (except Willmut Gas) and certain foreign employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. Other postretirement benefits include medical benefits for retirees’ spouses.

Chilquinta Energía also has two noncontributory postretirement benefit plans which cover substantially all employees – a health care plan and an energy subsidy plan that provides for reduced energy rates. The health care plan includes benefits for retirees’ spouses and dependents.

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

§	health care cost trend rates

§	mortality rates

§	rate of compensation increases

§	termination and retirement rates

§	utilization of postretirement welfare benefits

§	payout elections (lump sum or annuity)

§	lump sum interest rates

We review these assumptions on an annual basis prior to the beginning of each year and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions. We use a December 31 measurement date for all of our plans.

In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra Energy maintains dedicated assets, including investments in life insurance contracts, which totaled $510 million and $478 million at December 31, 2012 and 2011, respectively.

PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

Benefit Plan Amendments Affecting 2012

Effective January 1, 2012, the pension plan death benefit for represented employees at SoCalGas was enhanced to the full value of the benefit that the participant would have received had the employee terminated employment and taken a distribution of their benefit. Effective October 1, 2012, the death benefit for represented employees at SDG&E was similarly enhanced. This increased the benefit obligation by approximately $8 million for Sempra Energy Consolidated, $1 million for SDG&E and $7 million for SoCalGas .

Effective January 1, 2012, SoCalGas’ represented employees with less than 15 years of service now receive a defined dollar benefit to cover postretirement medical benefits. This amendment was the result of the ratification on March 1, 2012 of the SoCalGas union collective bargaining agreement (CBA) covering wages, hours, working conditions and medical and other benefit plans effective January 1, 2012 through September 30, 2015. The amendment resulted in a remeasurement of the SoCalGas other postretirement benefit liability as of February 29, 2012. The effect of this plan change as of December 31, 2012 was a decrease in the recorded liability for other postretirement benefits of $53 million at each of Sempra Energy Consolidated and SoCalGas.

Effective January 1, 2012, the postretirement plans amended in 2011, as discussed below, were amended to effectively reverse the 2011 amendment as the increase in employer contributions was no longer required to maintain grandfathered status under the Patient Protection and Affordable Care Act (PPACA), discussed below, due to a restructuring of benefits provided under the plans. The 2012 amendment resulted in a decrease in the recorded liability for other postretirement benefits of approximately $3 million for Sempra Energy Consolidated, $2 million for SDG&E and $1 million for SoCalGas.

Benefit Plan Amendments Affecting 2011

Effective January 1, 2011, for certain postretirement health plans, the employer contribution was increased to maintain the grandfathered retiree plan status under the PPACA discussed below. This increased the benefit obligation by approximately $4 million for Sempra Energy Consolidated, $2 million for SDG&E and $1 million for SoCalGas .

Benefit Obligations and Assets

The following three tables provide a reconciliation of the changes in the plans’ projected benefit obligations and the fair value of assets during 2012 and 2011, and a statement of the funded status at December 31, 2012 and 2011:

PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
Sempra Energy Consolidated	2012		2011		2012		2011
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net obligation at January 1	$	3,406	$	3,124	$	1,160	$	1,139
Service cost		90		83		25		31
Interest cost		162		168		52		65
Plan amendments		8		―		(56)		4
Actuarial loss (gain)		374		224		(25)		(42)
Contributions from plan participants		―		―		15		15
Benefit payments		(217)		(177)		(56)		(59)
Acquisitions		―		20		―		5
Foreign currency adjustments		―		(2)		―		―
Settlements		(19)		(34)		―		―
Federal subsidy (Medicare Part D)		―		―		―		2
Net obligation at December 31		3,804		3,406		1,115		1,160

CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1		2,332		2,354		778		746
Actual return on plan assets		339		(23)		97		4
Employer contributions		123		212		39		72
Contributions from plan participants		―		―		15		15
Benefit payments		(217)		(177)		(56)		(59)
Settlements		(19)		(34)		―		―
Fair value of plan assets at December 31		2,558		2,332		873		778
Funded status at December 31	$	(1,246)	$	(1,074)	$	(242)	$	(382)
Net recorded liability at December 31	$	(1,246)	$	(1,074)	$	(242)	$	(382)

PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
SDG&E	2012		2011		2012		2011
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net obligation at January 1	$	981	$	949	$	182	$	175
Service cost		28		28		7		7
Interest cost		45		49		9		10
Plan amendments		1		―		(2)		2
Actuarial loss (gain)		87		27		(5)		(5)
Settlements		―		(1)		―		―
Transfer of liability to other plans		―		(19)		―		(2)
Contributions from plan participants		―		―		6		7
Benefit payments		(75)		(52)		(12)		(12)
Net obligation at December 31		1,067		981		185		182

CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1		712		713		106		99
Actual return on plan assets		99		(7)		13		(1)
Employer contributions		45		69		13		15
Transfer of assets to other plans		―		(10)		―		(2)
Settlements		―		(1)		―		―
Contributions from plan participants		―		―		6		7
Benefit payments		(75)		(52)		(12)		(12)
Fair value of plan assets at December 31		781		712		126		106
Funded status at December 31	$	(286)	$	(269)	$	(59)	$	(76)
Net recorded liability at December 31	$	(286)	$	(269)	$	(59)	$	(76)

PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
SoCalGas	2012		2011		2012		2011
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net obligation at January 1	$	2,017	$	1,786	$	921	$	920
Service cost		53		46		16		22
Interest cost		99		99		41		53
Plan amendments		7		―		(54)		1
Actuarial loss (gain)		245		171		(19)		(46)
Contributions from plan participants		―		―		9		9
Benefit payments		(120)		(107)		(41)		(45)
Settlements		(2)		(4)		―		―
Transfer of liability from other plans		―		26		―		5
Federal subsidy (Medicare Part D)		―		―		―		2
Net obligation at December 31		2,299		2,017		873		921

CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1		1,443		1,456		658		632
Actual return on plan assets		213		(12)		83		4
Employer contributions		47		95		23		55
Transfer of assets from other plans		―		15		―		3
Settlements		(2)		(4)		―		―
Contributions from plan participants		―		―		9		9
Benefit payments		(120)		(107)		(41)		(45)
Fair value of plan assets at December 31		1,581		1,443		732		658
Funded status at December 31	$	(718)	$	(574)	$	(141)	$	(263)
Net recorded liability at December 31	$	(718)	$	(574)	$	(141)	$	(263)

The actuarial losses for pension plans in 2012 were primarily due to a decrease in the weighted average discount rate and the rate used to convert monthly annuity-type benefits to a lump sum benefit payment.

The actuarial gains for other postretirement plans in 2012 resulted from several factors, including updated census data and actual claims costs, premiums and retiree contributions for 2012, expected gains on 2013 claims costs based on 2013 renewal premium rates, changes in retirement rate assumptions and the move to an Employer Group Waiver Plan (EGWP) for all represented employees of SoCalGas effective February 29, 2012. An EGWP is an alternative means of providing the existing pharmacy benefit, discussed below. The actuarial gains were partially offset by the impact of a lower discount rate for the obligation remeasurement on February 29, 2012 discussed above and a lower discount rate at the December 31, 2012 measurement date.

The actuarial losses for pension plans in 2011 were primarily due to a decrease in the weighted average discount rate and the rate used to convert monthly annuity-type benefits to a lump sum benefit payment.

The actuarial gains for other postretirement plans in 2011 resulted from a decrease in assumed participation rates and claims costs, and the impact of the adoption of the EGWP effective January 1, 2012 for all employees except SoCalGas union employees, partially offset by actuarial losses from a decrease in the weighted average discount rate.

Net Assets and Liabilities

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 investment gains and losses, which we defer and recognize in pension and other postretirement benefit costs over a period of years. Sempra Energy Consolidated (except for SDG&E) and SoCalGas use the asset smoothing method for their pension and other postretirement plans. This method develops an asset value that 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 in conjunction with an expected long-term rate of return to determine the expected return-on-assets component of net periodic cost. SDG&E does not use the asset smoothing method, but rather recognizes realized and unrealized investment gains and losses during the current year.

The 10-percent corridor accounting method is used at Sempra Energy, SDG&E and SoCalGas. Under the corridor accounting method, 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.

We recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets or liabilities, respectively; unrecognized changes in these assets and/or liabilities are normally recorded in accumulated other comprehensive income (loss) on the balance sheet. The California Utilities and Mobile Gas record regulatory assets and liabilities that offset the funded pension and other postretirement plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on agreements with regulatory agencies. At Willmut Gas, pension contributions are recovered in rates on a prospective basis, but are not recorded as a regulatory asset pending recovery.

The California Utilities record annual pension and other postretirement net periodic benefit costs equal to the contributions to their plans as authorized by the CPUC. The annual contributions to the pension plans are limited to a minimum required funding amount as determined by the Internal Revenue Service. The annual contributions to the other postretirement plans are equal to the lesser of the maximum tax deductible amount or the net periodic cost calculated in accordance with U.S. GAAP for pension and other postretirement benefit plans. Mobile Gas records annual pension and other postretirement net periodic benefit costs based on an estimate of the net periodic cost at the beginning of the year calculated in accordance with U.S. GAAP for pension and other postretirement benefit plans, as authorized by the Alabama Public Service Commission. Any differences between booked net periodic benefit cost and amounts contributed to the pension and other postretirement plans for the California Utilities are disclosed as regulatory adjustments in accordance with U.S. GAAP for regulated entities.

The net liability is included in the following captions on the Consolidated Balance Sheets at December 31:

	Pension Benefits				Other Postretirement Benefits
(Dollars in millions)	2012		2011		2012		2011
Sempra Energy Consolidated
Current liabilities	$	(31)	$	(31)	$	(1)	$	(2)
Noncurrent liabilities		(1,215)		(1,043)		(241)		(380)
Net recorded liability	$	(1,246)	$	(1,074)	$	(242)	$	(382)
SDG&E
Current liabilities	$	(5)	$	(3)	$	―	$	―
Noncurrent liabilities		(281)		(266)		(59)		(76)
Net recorded liability	$	(286)	$	(269)	$	(59)	$	(76)
SoCalGas
Current liabilities	$	(4)	$	(4)	$	―	$	―
Noncurrent liabilities		(714)		(570)		(141)		(263)
Net recorded liability	$	(718)	$	(574)	$	(141)	$	(263)

Amounts recorded in Accumulated Other Comprehensive Income (Loss) as of December 31, 2012 and 2011, net of income tax effects and amounts recorded as regulatory assets, are as follows:

AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
	Pension Benefits				Other Postretirement Benefits
	2012		2011		2012		2011
Sempra Energy Consolidated
Net actuarial loss	$	(96)	$	(92)	$	(6)	$	(8)
Prior service credit		1		1		―		―
Total	$	(95)	$	(91)	$	(6)	$	(8)
SDG&E
Net actuarial loss	$	(12)	$	(11)
Prior service credit		1		1
Total	$	(11)	$	(10)
SoCalGas
Net actuarial loss	$	(4)	$	(6)
Prior service credit		1		1
Total	$	(3)	$	(5)

The accumulated benefit obligation for defined benefit pension plans at December 31, 2012 and 2011 was as follows:

	Sempra Energy Consolidated				SDG&E				SoCalGas
(Dollars in millions)	2012		2011		2012		2011		2012		2011
Accumulated benefit obligation	$	3,530	$	3,176	$	1,041	$	962	$	2,080	$	1,845

Sempra Energy has unfunded and funded pension plans. SDG&E and SoCalGas each have an unfunded and a funded pension plan. The following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets as of December 31:

(Dollars in millions)	2012		2011
Sempra Energy Consolidated
Projected benefit obligation	$	3,544	$	3,150
Accumulated benefit obligation		3,295		2,958
Fair value of plan assets		2,558		2,332
SDG&E
Projected benefit obligation	$	1,025	$	944
Accumulated benefit obligation		1,003		928
Fair value of plan assets		781		712
SoCalGas
Projected benefit obligation	$	2,275	$	1,987
Accumulated benefit obligation		2,057		1,818
Fair value of plan assets		1,581		1,443

Net Periodic Benefit Cost, 2010-2012

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

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OTHER COMPREHENSIVE INCOME
(Dollars in millions)
	Pension Benefits						Other Postretirement Benefits
Sempra Energy Consolidated	2012		2011		2010		2012		2011		2010
Net Periodic Benefit Cost
Service cost	$	90	$	83	$	83	$	25	$	31	$	26
Interest cost		162		168		167		52		65		57
Expected return on assets		(155)		(144)		(143)		(53)		(48)		(46)
Amortization of:
Prior service cost (credit)		3		4		4		(4)		―		(1)
Actuarial loss		47		34		30		12		17		8
Regulatory adjustment		(29)		43		19		7		7		7
Settlement charge		8		13		―		―		―		―
Total net periodic benefit cost		126		201		160		39		72		51

Other Changes in Plan Assets and Benefit Obligations
Recognized in Other Comprehensive Income
Net loss (gain)		19		23		(12)		(6)		7		(1)
Amortization of prior service credit		―		―		―		―		―		1
Amortization of actuarial loss		(9)		(10)		(10)		―		―		―
Total recognized in other comprehensive income		10		13		(22)		(6)		7		―
Total recognized in net periodic benefit cost and other comprehensive income	$	136	$	214	$	138	$	33	$	79	$	51

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OTHER COMPREHENSIVE INCOME
(Dollars in millions)
	Pension Benefits						Other Postretirement Benefits
SDG&E	2012		2011		2010		2012		2011		2010
Net Periodic Benefit Cost
Service cost	$	28	$	28	$	27	$	7	$	7	$	6
Interest cost		45		49		47		9		10		9
Expected return on assets		(47)		(46)		(40)		(8)		(8)		(5)
Amortization of:
Prior service cost		2		1		1		4		4		4
Actuarial loss		14		9		12		―		―		―
Regulatory adjustment		6		31		13		1		2		2
Settlement charge		1		1		―		―		―		―
Total net periodic benefit cost		49		73		60		13		15		16

Other Changes in Plan Assets and Benefit Obligations
Recognized in Other Comprehensive Income
Net loss		2		1		2		―		―		―
Amortization of actuarial loss		(1)		(1)		(1)		―		―		―
Total recognized in other comprehensive income		1		―		1		―		―		―
Total recognized in net periodic benefit cost and other comprehensive income	$	50	$	73	$	61	$	13	$	15	$	16

NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OTHER COMPREHENSIVE INCOME
(Dollars in millions)
	Pension Benefits						Other Postretirement Benefits
SoCalGas	2012		2011		2010		2012		2011		2010
Net Periodic Benefit Cost
Service cost	$	53	$	46	$	46	$	16	$	22	$	18
Interest cost		99		99		98		41		53		46
Expected return on assets		(96)		(85)		(90)		(44)		(40)		(40)
Amortization of:
Prior service cost (credit)		2		2		2		(7)		(4)		(4)
Actuarial loss		23		17		10		11		17		7
Settlement charge		1		1		―		―		―		―
Regulatory adjustment		(36)		12		6		5		5		5
Total net periodic benefit cost		46		92		72		22		53		32

Other Changes in Plan Assets and Benefit Obligations
Recognized in Other Comprehensive Income
Net loss (gain)		(4)		2		―		―		―		―
Amortization of actuarial loss		(1)		(1)		(1)		―		―		―
Total recognized in other comprehensive income		(5)		1		(1)		―		―		―
Total recognized in net periodic benefit cost and other comprehensive income	$	41	$	93	$	71	$	22	$	53	$	32

The estimated net loss for the pension plans that will be amortized from Accumulated Other Comprehensive Income (Loss) into net periodic benefit cost in 2013 is $11 million for Sempra Energy Consolidated, $1 million at SDG&E and a negligible amount at SoCalGas. Negligible amounts of prior service credit for the pension plans will be similarly amortized in 2013.

The estimated net loss for the PBOP plans that will be amortized from Accumulated Other Comprehensive Income (Loss) into net periodic benefit cost in 2013 is $1 million for Sempra Energy Consolidated.

Negligible amounts of estimated prior service credit for the other postretirement benefit plans will be amortized from Accumulated Other Comprehensive Income (Loss) into net periodic benefit cost in 2013 at Sempra Energy Consolidated.

Patient Protection and Affordable Care Act of 2010

The PPACA was enacted in March 2010. The key aspects of this legislation affecting Sempra Energy’s cost of providing retiree medical benefits are

§	Availability of subsidies from the Early Retiree Reinsurance Program (ERRP)

§	Mandatory coverage for adult children until age 26 beginning in 2011

§	Changes to the Prescription Drug Plan and Medicare Advantage programs beginning in 2011 and extending through 2020

§	Loss of the tax free status of the Retiree Drug Subsidy (RDS) beginning in 2013

§	Availability of coverage through health care exchanges beginning in 2014

§	Excise tax on high-cost plans, as defined in the legislation, beginning in 2018

In determining the projected benefit obligation for our other postretirement benefit plans, we took mandatory coverage for adult children, changes to the Prescription Drug Plan and Medicare Advantage programs, and availability of health care exchanges into consideration in the development of future claims costs and health care trend rates as of December 31, 2012 and 2011. Subsidies received through the ERRP are being reflected when received. We measured loss of the tax free status of RDS separately, as we discuss in “Medicare Prescription Drug, Improvement and Modernization Act of 2003” below.

We determined the impact of the excise tax provision separately for each of Sempra Energy’s plans. With the exception of SoCalGas’ represented employees and Mobile Gas, we provide most of our employer subsidy in the form of a defined dollar benefit. Once the premium exceeds our stated benefit level, the retirees pay the difference between the premium amount and the subsidy. Under this arrangement, our obligation doesn’t change with the excise tax, since by 2018 the premium both before and after inclusion of the excise tax will exceed our defined dollar benefit.

SoCalGas’ union retirees are provided a subsidy as a percentage of the premium. For those retirees, we estimated an increase in SoCalGas’ and Sempra Energy’s obligations as of December 31, 2010 for the excise tax. However, it is likely that some retirees will move to less expensive plans as a result of the excise tax and lower Sempra Energy’s composite plan cost. The net effect of the increase in obligation from the excise tax, partially offset by the lower composite plan cost, was estimated to be $31 million.

Mobile Gas offers only a pre-age 65 plan. As such, future retirees will only have a limited period when the excise tax may apply. All current retirees will no longer be eligible for benefits once the excise tax is effective in 2018.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

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. As a result of the ratification of the SoCalGas CBA on March 1, 2012, described above, there was a change in medical plans offered for post-age 65 medical benefits. SoCalGas now administers the Medicare Part D benefit through an EGWP. The EGWP allows a plan sponsor to contract with a Medicare Part D sponsor to receive the benefit of the subsidy through reduced premiums. We have determined that benefits provided to certain participants actuarially will be at least equivalent to Medicare Part D. Due to this election of an EGWP for SoCalGas’ represented employees effective February 29, 2012, and the same election for all other employees on January 1, 2012, we are no longer entitled to a tax-exempt subsidy that reduces our accumulated postretirement benefit obligation under our plans and reduces our net periodic cost in future years.

Assumptions for Pension and Other Postretirement Benefit Plans

Benefit Obligation and Net Periodic Benefit Cost

Except for the Chilquinta Energía plans, we develop the discount rate assumptions based on the results of a third party modeling tool that develops the discount rate by matching each plan’s expected cash flows to interest rates and expected maturity values of individually selected bonds in a hypothetical portfolio. The model controls the level of accumulated surplus that may result from the selection of bonds based solely on their premium yields by limiting the number of years to look back for selection to 3 years for pre-30-year and 6 years for post-30-year benefit payments. Additionally, the model ensures that an adequate number of bonds are selected in the portfolio by limiting the amount of the plan’s benefit payments that can be met by a single bond to 7.5 percent.

We selected individual bonds from a universe of Bloomberg AA-rated bonds which:

§	have an outstanding issue of at least $50 million;

§	are non-callable (or callable with make whole provisions);

§	exclude collateralized bonds; and

§	exclude the top and bottom 10 percent of yields to avoid relying on bonds which might be mispriced or misgraded.

This selection methodology also mitigates the impact of market volatility on the portfolio by excluding bonds with the following characteristics:

§	The issuer is on review for downgrade by a major rating agency if the downgrade would eliminate the issuer from the portfolio.

§	Recent events have caused significant price volatility to which rating agencies have not reacted.

§	Lack of liquidity is causing price quotes to vary significantly from broker to broker.

We believe that this bond selection approach provides the best estimate of discount rates to estimate settlement values for our plans’ benefit obligations as required by applicable U.S. GAAP.

We develop the discount rate assumptions for the plans at Chilquinta Energía based on 10-year Chilean government bond yields and the expected local long-term rate of inflation. This method for developing the discount rate is required when there is no deep market for high quality corporate bonds.

Long-term return on assets is based on the weighted-average of the plans’ investment allocation as of the measurement date and the expected returns for those asset types.

The significant assumptions affecting benefit obligation and net periodic benefit cost are as follows:

WEIGHTED-AVERAGE ASSUMPTIONS

		Pension Benefits				Other Postretirement Benefits
		2012		2011		2012		2011
WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE
BENEFIT OBLIGATION AS OF DECEMBER 31:
Discount rate		4.04	%	4.95	%	4.09	%	5.11	%
Rate of compensation increase		(1)		(1)		(1)		(1)

WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET
PERIODIC BENEFIT COST FOR YEARS ENDED DECEMBER 31:
Sempra Energy Consolidated
Discount rate		(2)		(3)		(4)		(5)
Expected return on plan assets		7.00	%	7.00	%	6.96	%	6.25	%
Rate of compensation increase		(6)		(6)		(1)		(1)
SDG&E
Discount rate		(7)		(7)		5.05	%	5.05	%
Expected return on plan assets		7.00	%	7.00	%	6.81	%	6.69	%
Rate of compensation increase		(8)		(8)		N/A		N/A
SoCalGas
Discount rate		(9)		(9)		5.15	%	5.15	%
Expected return on plan assets		7.00	%	7.00	%	7.00	%	7.00	%
Rate of compensation increase		(6)		(6)		(1)		(1)
(1)	4.50% for nonqualified pension plans and Executive Life plan. Qualified pension and other postretirement benefit plans, excluding the Executive Life plan, use an age-based table. 3.50% to 5.00% for the funded pension plan for SoCalGas' represented participants and 3.50% to 9.50% for all the other funded pension plans' participants using an age-based formula.
(2)	In addition to rates for SDG&E and SoCalGas plans, 4.93% for Mobile Gas pension plan, 4.40% for Directors’ plan, 4.70% for other unfunded plans, and 4.90% for Sempra Energy funded plan.
(3)	In addition to rates for SDG&E and SoCalGas plans, 5.14% for Mobile Gas pension plan, 4.40% for Directors’ plan, 4.70% for other unfunded plans, and 4.90% for Sempra Energy funded plan.
(4)	In addition to rates for SDG&E and SoCalGas plans, 4.10% for the Executive Life Plan, 4.88% for Mobile Gas, and 4.65% for Sempra Energy.
(5)	In addition to rates for SDG&E and SoCalGas plans, 4.10% for the Executive Life Plan, 4.80% for Mobile Gas, and 4.65% for Sempra Energy.
(6)	4.50% for the unfunded pension plans. 3.50% to 5.00% for the funded pension plan for SoCalGas’ represented participants and 3.50% to 8.50% for all the other funded pension plans’ participants using an age-based formula.
(7)	4.70% for the unfunded pension plan. 4.80% for the funded pension plan.
(8)	4.50% for the unfunded pension plan. 3.50% to 8.50% for the funded pension plan using an age-based formula.
(9)	4.70% for the unfunded pension plan. 5.05% for the funded pension plan.

Health Care Cost Trend Rates

Assumed health care cost trend rates have a significant effect on the amounts that we report for the health care plan costs. Following are the health care cost trend rates applicable to our postretirement benefit plans:

		2012	2011
ASSUMED HEALTH CARE COST TREND RATES AT DECEMBER 31:
Health care cost trend rate		(1)	10.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)		(2)	5.00	%
Year that the rate reaches the ultimate trend		2020	2019
(1)	10.00% for pre-65 retirees and 8.25% for retirees aged 65 years and older. For Mobile Gas, the health care cost trend rate is assumed to be 8.00%.
(2)	5.00% for pre-65 retirees and 4.75% for retirees aged 65 years and older. For Mobile Gas, the rate to which the cost trend rate is assumed to decline is assumed to be 5.00%.

A one-percent change in assumed health care cost trend rates would have the following effects:

	Sempra Energy
	Consolidated				SDG&E				SoCalGas
	1%		1%		1%		1%		1%		1%
(Dollars in millions)	Increase		Decrease		Increase		Decrease		Increase		Decrease
Effect on total of service and interest
cost components of net periodic
postretirement health care benefit cost	$	8	$	(8)	$	1	$	(1)	$	7	$	(7)
Effect on the health care component of the
accumulated other postretirement
benefit obligations	$	114	$	(88)	$	9	$	(7)	$	102	$	(78)

Plan Assets

Investment Allocation Strategy for Sempra Energy’s Pension Master Trust

Sempra Energy’s pension master trust holds the investments for the pension and other postretirement benefit plans. We maintain additional trusts as we discuss below for certain of the California Utilities’ other postretirement plans. Other than index weight, the trusts do not invest in securities of Sempra Energy.

The current asset allocation objective for the pension master trust is to protect the funded status of the plans while generating sufficient returns to cover future benefit payments and accruals. We assess the portfolio performance by comparing actual returns with relevant benchmarks. Currently, the pension plans’ asset allocations are

§	41 percent domestic equity

§	27 percent international equity

§	5 percent high yield credit

§	12 percent intermediate credit

§	14 percent long credit

§	1 percent cash

The asset allocation of the plans is reviewed by our Plan Funding Committee and our Pension and Benefits Investment Committee (the Committees) on a regular basis. When evaluating strategic asset allocations, the Committees consider many variables, including:

§	long-term cost

§	variability and level of contributions

§	funded status

§	a range of expected outcomes over varying confidence levels

We maintain allocations at strategic levels with reasonable bands of variance. When asset class exposure reaches a minimum or maximum level, we generally rebalance the portfolio back to target allocations, unless the Committees determine otherwise.

Rate of Return Assumption

The expected return on assets in our pension plans and other postretirement benefit plans is based on the weighted-average of the plans’ investment allocations to specific asset classes as of the measurement date, except for the assets in the SDG&E other postretirement benefit plan. We arrive at a 7.0 percent expected return on assets by considering both the historical and forecasted long-term rates of return on those asset classes. The forecasts are developed using a build-up method that considers real risk-free interest rates, inflation rates and asset class specific risk premiums. We expect a return of between 7.0 percent and 10.0 percent on equity securities and between 3.0 percent and 6.0 percent for fixed-income securities.

The expected return on assets in the SDG&E other postretirement benefit plan is based on the weighted-average of the expected return on plan assets held in the Voluntary Employee Beneficiary Association (VEBA) trusts designated for non-collectively bargained benefits and the expected return on plan assets held in all other trusts. The expected return on assets in the VEBA trusts is based on the weighted-average of the expected return on equity securities, as described above, and a 4.0 percent expected return on fixed income securities, which are all invested in tax-exempt municipal bonds.

Concentration of Risk

Plan assets are fully diversified across global equity and bond markets, and other than what is indicated by the target asset allocations, contain no concentration of risk in any one economic, industry, maturity or geographic sector.

Investment Strategy for SoCalGas’ Other Postretirement Benefit Plans

SoCalGas’ other postretirement benefit plans are funded by cash contributions from SoCalGas and current retirees. The assets of these plans are placed in the pension master trust and other VEBA trusts, as we detail below. The assets in the VEBA trusts are invested at an allocation identical to the pension master trust, 70 percent equities/30 percent fixed income, using primarily index funds. This allocation has been formulated to best suit the long-term nature of the obligations.

Investment Strategy for SDG&E’s Other Postretirement Benefit Plan

SDG&E’s postretirement health plans are funded by cash contributions from SDG&E and current retirees. The assets are placed in the pension master trust and the collectively bargained VEBA trust. Assets in the pension master trust are invested according to the pension master trust’s asset allocation as detailed above. Assets in the VEBA trust for non-collectively bargained postretirement health and welfare benefit plans are taxable and therefore have a different asset allocation strategy. These assets are invested with a target asset allocation of 70 percent equities/30 percent fixed income, with a large portion of the bond portfolio placed in actively managed tax-exempt municipal bonds. The equity portfolio is indexed.

Fair Value of Pension and Other Postretirement Benefit Plan Assets

We classify the investments in Sempra Energy’s pension master trust and the trusts for the California Utilities’ other postretirement benefit plans into:

§	Level 1, for securities valued using quoted prices from active markets for identical assets;

§	Level 2, for securities not traded on an active market but for which observable market inputs are readily available; and

§	Level 3, for securities and investments valued based on significant unobservable inputs. Investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and other postretirement benefit plan trusts.

Equity Securities — Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.

Fixed Income Securities — Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks.

Registered Investment Companies — Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices.

Common/Collective Trusts — Investments in common/collective trust funds are valued based on the redemption price of units owned, which is based on the current fair value of the funds’ underlying assets.

Private Equity Funds — Investments in private equity funds do not trade in active markets. Fair value is determined by the fund managers, based upon their review of the underlying investments as well as their utilization of discounted cash flows and other valuation models.

Real Estate — Real estate investments are valued on the basis of a discounted cash flows approach, which includes the future rental receipts, expenses, and residual values for the highest and best use of the real estate from a market participant view as rental property.

The methods described are intended to produce a fair value calculation that is indicative of net realizable value or reflective of future fair values. However, while management believes the valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

We provide more discussion of fair value measurements in Notes 1, 2 and 11. The following tables set forth by level within the fair value hierarchy a summary of the investments in our pension and other postretirement benefit plan trusts measured at fair value on a recurring basis.

The fair values of our pension plan assets by asset category are as follows:

FAIR VALUE MEASUREMENTS — SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		At fair value as of December 31, 2012
PENSION PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
SDG&E (see table below)		$	530	$	241	$	6	$	777
SoCalGas (see table below)			1,074		485		13		1,572
Other Sempra Energy
Equity securities:
Domestic(1)			77		―		―		77
Foreign			54		―		―		54
Registered investment companies			2		―		―		2
Fixed income securities:
Domestic municipal bonds			―		3		―		3
Foreign government bonds			―		5		―		5
Domestic corporate bonds(2)			―		37		―		37
Foreign corporate bonds			―		13		―		13
Common/collective trusts(3)			―		2		―		2
Other types of investments:
Private equity funds(4) (stated at net asset value)			―		―		2		2
Total other Sempra Energy(5)			133		60		2		195
Total Sempra Energy Consolidated(6)		$	1,737	$	786	$	21	$	2,544

		At fair value as of December 31, 2011
PENSION PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
SDG&E (see table below)		$	466	$	244	$	7	$	717
SoCalGas (see table below)			919		484		15		1,418
Other Sempra Energy
Equity securities:
Domestic(1)			72		―		―		72
Foreign			45		―		―		45
Foreign preferred			1		―		―		1
Registered investment companies			1		―		―		1
Fixed income securities:
Domestic municipal bonds			―		2		―		2
Foreign government bonds			―		5		―		5
Domestic corporate bonds(2)			―		36		―		36
Foreign corporate bonds			―		12		―		12
Common/collective trusts(3)			―		6		―		6
Other types of investments:
Private equity funds(4) (stated at net asset value)			1		―		2		3
Total other Sempra Energy(7)			120		61		2		183
Total Sempra Energy Consolidated(6)		$	1,505	$	789	$	24	$	2,318
(1)	Investments in common stock of domestic corporations.
(2)	Bonds of U.S. issuers from diverse industries, primarily investment-grade.
(3)	Investments in common/collective trusts held in Sempra Energy’s Pension Master Trust.
(4)	Investments in venture capital and real estate funds.
(5)	Excludes cash and cash equivalents of $1 million.
(6)	Excludes cash and cash equivalents of $14 million at both December 31, 2012 and 2011.
(7)	Excludes cash and cash equivalents of $1 million and transfers payable to other plans of $7 million.

FAIR VALUE MEASUREMENTS — SDG&E
(Dollars in millions)
		At fair value as of December 31, 2012
PENSION PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
Equity securities:
Domestic(1)		$	307	$	―	$	―	$	307
Foreign			215		―		―		215
Foreign preferred			2		―		―		2
Registered investment companies			6		―		―		6
Fixed income securities:
Domestic municipal bonds			―		12		―		12
Foreign government bonds			―		22		―		22
Domestic corporate bonds(2)			―		147		―		147
Foreign corporate bonds			―		52		―		52
Common/collective trusts(3)			―		8		―		8
Other types of investments:
Private equity funds(4) (stated at net asset value)			―		―		6		6
Total investment assets(5)		$	530	$	241	$	6	$	777

		At fair value as of December 31, 2011
PENSION PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
Equity securities:
Domestic(1)		$	283	$	―	$	―	$	283
Foreign			178		―		―		178
Foreign preferred			1		―		―		1
Registered investment companies			4		―		―		4
Fixed income securities:
Domestic municipal bonds			―		9		―		9
Foreign government bonds			―		25		―		25
Domestic corporate bonds(2)			―		139		―		139
Foreign corporate bonds			―		48		―		48
Common/collective trusts(3)			―		23		―		23
Other types of investments:
Private equity funds(4) (stated at net asset value)			―		―		7		7
Total investment assets(6)		$	466	$	244	$	7	$	717
(1)	Investments in common stock of domestic corporations.
(2)	Bonds of U.S. issuers from diverse industries, primarily investment-grade.
(3)	Investments in common/collective trusts held in Sempra Energy’s Pension Master Trust.
(4)	Investments in venture capital and real estate funds.
(5)	Excludes cash and cash equivalents of $4 million.
(6)	Excludes cash and cash equivalents of $4 million and transfers payable to other plans of $9 million.

FAIR VALUE MEASUREMENTS — SOCALGAS
(Dollars in millions)
		At fair value as of December 31, 2012
PENSION PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
Equity securities:
Domestic(1)		$	622	$	―	$	―	$	622
Foreign			436		―		―		436
Foreign preferred			4		―		―		4
Registered investment companies			12		―		―		12
Fixed income securities:
Domestic municipal bonds			―		24		―		24
Foreign government bonds			―		44		―		44
Domestic corporate bonds(2)			―		297		―		297
Foreign corporate bonds			―		105		―		105
Common/collective trusts(3)			―		15		―		15
Other types of investments:
Private equity funds(4) (stated at net asset value)					―		13		13
Total investment assets(5)		$	1,074	$	485	$	13	$	1,572

		At fair value as of December 31, 2011
PENSION PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
Equity securities:
Domestic(1)		$	558	$	―	$	―	$	558
Foreign			351		―		―		351
Foreign preferred			1		―		―		1
Registered investment companies			8		―		―		8
Fixed income securities:
Domestic municipal bonds			―		18		―		18
Foreign government bonds			―		49		―		49
Domestic corporate bonds(2)			―		275		―		275
Foreign corporate bonds			―		96		―		96
Common/collective trusts(3)			―		46		―		46
Other types of investments:
Private equity funds(4) (stated at net asset value)			1		―		15		16
Total investment assets(6)		$	919	$	484	$	15	$	1,418
(1)	Investments in common stock of domestic corporations.
(2)	Bonds of U.S. issuers from diverse industries, primarily investment-grade.
(3)	Investments in common/collective trusts held in Sempra Energy’s Pension Master Trust.
(4)	Investments in venture capital and real estate funds.
(5)	Excludes cash and cash equivalents of $9 million.
(6)	Excludes cash and cash equivalents of $9 million and transfers receivable from other plans of $16 million.

The fair values by asset category of the postretirement benefit plan assets held in the pension master trust and in the additional trusts for SoCalGas’ postretirement benefit plans and SDG&E’s postretirement benefit plans (PBOP plan trusts) are as follows:

FAIR VALUE MEASUREMENTS — SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		At fair value as of December 31, 2012
OTHER POSTRETIREMENT BENEFIT PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
SDG&E (see table below)		$	87	$	38	$	1	$	126
SoCalGas (see table below)			213		514		2		729
Other Sempra Energy
Equity securities:
Domestic(1)			5		―		―		5
Foreign			1		―		―		1
Foreign preferred			1		―		―		1
Registered investment companies			3		1		―		4
Fixed income securities:
Domestic corporate bonds(2)			―		2		―		2
Foreign government bonds			―		1		―		1
Foreign corporate bonds			―		1		―		1
Total other Sempra Energy			10		5		―		15
Total Sempra Energy Consolidated(3)		$	310	$	557	$	3	$	870

		At fair value as of December 31, 2011
OTHER POSTRETIREMENT BENEFIT PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
SDG&E (see table below)		$	47	$	24	$	1	$	72
SoCalGas (see table below)			176		390		3		569
Other Sempra Energy
Equity securities:
Domestic(1)			6		―		―		6
Foreign			3		―		―		3
Fixed income securities:
Domestic corporate bonds(2)			―		4		―		4
Foreign government bonds			―		1		―		1
Foreign corporate bonds			―		1		―		1
Total other Sempra Energy(4)			9		6		―		15
Total Sempra Energy Consolidated(5)		$	232	$	420	$	4	$	656
(1)	Investments in common stock of domestic corporations.
(2)	Bonds of U.S. issuers from diverse industries, primarily investment-grade.
(3)	Excludes cash and cash equivalents of $3 million, all of which is held in SoCalGas PBOP plan trusts.
(4)	Excludes transfers payable to other plans of $1 million.
(5)	Excludes cash and cash equivalents of $122 million, $86 million and $36 million of which is held in SoCalGas and SDG&E
	PBOP plan trusts, respectively.

FAIR VALUE MEASUREMENTS — SDG&E
(Dollars in millions)
		At fair value as of December 31, 2012
OTHER POSTRETIREMENT BENEFIT PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
Equity securities:
Domestic(1)		$	32	$	―	$	―	$	32
Foreign			23		―		―		23
Registered investment companies			32		―		―		32
Fixed income securities:
Domestic municipal bonds(2)			―		3		―		3
Domestic corporate bonds(3)			―		15		―		15
Foreign government bonds			―		2		―		2
Foreign corporate bonds			―		5		―		5
Common/collective trusts(4)			―		1		―		1
Registered investment companies			―		12		―		12
Other types of investments:
Private equity funds(5) (stated at net asset value)			―		―		1		1
Total investment assets		$	87	$	38	$	1	$	126

		At fair value as of December 31, 2011
OTHER POSTRETIREMENT BENEFIT PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
Equity securities:
Domestic(1)		$	24	$	―	$	―	$	24
Foreign			16		―		―		16
Registered investment companies			7		―		―		7
Fixed income securities:
Domestic municipal bonds(2)			―		4		―		4
Domestic corporate bonds(3)			―		12		―		12
Foreign government bonds			―		2		―		2
Foreign corporate bonds			―		4		―		4
Common/collective trusts(4)			―		2		―		2
Other types of investments:
Private equity funds(5) (stated at net asset value)			―		―		1		1
Total investment assets(6)		$	47	$	24	$	1	$	72
(1)	Investments in common stock of domestic corporations.
(2)	Bonds of California municipalities held in SDG&E PBOP plan trusts.
(3)	Bonds of U.S. issuers from diverse industries, primarily investment-grade.
(4)	Investment in common/collective trusts held in PBOP plan VEBA trusts.
(5)	Investments in venture capital and real estate funds.
(6)	Excludes cash and cash equivalents of $36 million, all of which is held in SDG&E PBOP plan trusts, and transfers payable to other plans of $2 million.

FAIR VALUE MEASUREMENTS — SOCALGAS
(Dollars in millions)
		At fair value as of December 31, 2012
OTHER POSTRETIREMENT BENEFIT PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
Equity securities:
Domestic(1)		$	118	$	―	$	―	$	118
Foreign			84		―		―		84
Registered investment companies			11		―		―		11
Broad market funds			―		316		―		316
Fixed income securities:
Domestic municipal bonds			―		5		―		5
Domestic corporate bonds(2)			―		57		―		57
Foreign government bonds			―		8		―		8
Foreign corporate bonds			―		20		―		20
Common/collective trusts(3)			―		107		―		107
Registered investment companies			―		1		―		1
Other types of investments:
Private equity funds(4) (stated at net asset value)			―		―		2		2
Total investment assets(5)		$	213	$	514	$	2	$	729

		At fair value as of December 31, 2011
OTHER POSTRETIREMENT BENEFIT PLANS - INVESTMENT ASSETS			Level 1		Level 2		Level 3		Total
Equity securities:
Domestic(1)		$	107	$	―	$	―	$	107
Foreign			67		―		―		67
Registered investment companies			2		―		―		2
Fixed income securities:
Domestic municipal bonds			―		3		―		3
Foreign government bonds			―		9		―		9
Domestic corporate bonds(2)			―		52		―		52
Foreign corporate bonds			―		18		―		18
Common/collective trusts(3)			―		308		―		308
Other types of investments:
Private equity funds(4) (stated at net asset value)			―		―		3		3
Total investment assets(6)		$	176	$	390	$	3	$	569
(1)	Investments in common stock of domestic corporations.
(2)	Bonds of U.S. issuers from diverse industries, primarily investment-grade.
(3)	Investments in common/collective trusts held in PBOP plan VEBA trusts.
(4)	Investments in venture capital and real estate funds.
(5)	Excludes cash and cash equivalents of $3 million, all of which is held in SoCalGas PBOP plan trusts.
(6)	Excludes cash and cash equivalents of $86 million, all of which is held in SoCalGas PBOP plan trusts, and transfers receivable from other plans of $3 million.

The investments of the pension master trust allocated to the pension and postretirement benefit plans classified as Level 3 are private equity funds and represent a percentage of each plan’s total allocated assets as follows at December 31:

	Private Equity Funds
	2012				2011
(Dollars in millions)	SDG&E	SoCalGas	All Other	Sempra Energy Consolidated	SDG&E	SoCalGas	All Other	Sempra Energy Consolidated
PENSION PLANS
Total Level 3 investment assets	$6	$13	$2	$21	$7	$15	$2	$24
Percentage of total investment assets	1%	1%	1%	1%	1%	1%	-%	1%
OTHER POSTRETIREMENT BENEFIT PLANS
Total Level 3 investment assets	$1	$2	$-	$3	$1	$3	$-	$4
Percentage of total investment assets	1%	-%	-%	-%	1%	-%	-%	1%

The following table provides a reconciliation of changes in the fair value of investments classified as Level 3:

LEVEL 3 RECONCILIATIONS
(Dollars in millions)
	Private Equity Funds
		SDG&E		SoCalGas		All Other		Sempra Energy Consolidated
PENSION PLANS
Balance as of January 1, 2011	$	8	$	17	$	2	$	27
Realized gains		1		1		―		2
Purchases		―		1		―		1
Sales		(2)		(4)		―		(6)
Balance as of December 31, 2011		7		15		2		24
Unrealized gains		2		4		―		6
Sales		(3)		(6)		―		(9)
Balance as of December 31, 2012	$	6	$	13	$	2	$	21
OTHER POSTRETIREMENT BENEFIT PLANS
Balance as of January 1, 2011	$	1	$	4	$	―	$	5
Sales		―		(1)		―		(1)
Balance as of December 31, 2011		1		3		―		4
Sales		―		(1)		―		(1)
Balance as of December 31, 2012	$	1	$	2	$	―	$	3

Derivative Financial Instruments

In accordance with the Sempra Energy pension investment guidelines, derivative financial instruments are used by the pension master trust’s equity and fixed income portfolio investment managers. Equity index future contracts are typically used to equitize cash. Foreign currency exchange transactions are used primarily to purchase foreign currency denominated shares or to hedge underlying exposure to foreign currency. Fixed income futures and options may be used as substitutes for certain types of fixed income securities.

Future Payments

We expect to contribute the following amounts to our pension and other postretirement benefit plans in 2013:

	Sempra Energy
(Dollars in millions)	Consolidated		SDG&E		SoCalGas
Pension plans	$	154	$	57	$	69
Other postretirement benefit plans		27		11		11

The following table shows the total benefits we expect to pay for the next 10 years to current employees and retirees from the plans or from company assets.

	Sempra Energy Consolidated				SDG&E				SoCalGas
			Other				Other				Other
	Pension		Postretirement		Pension		Postretirement		Pension		Postretirement
(Dollars in millions)	Benefits		Benefits		Benefits		Benefits		Benefits		Benefits
2013	$	318	$	46	$	92	$	6	$	190	$	35
2014		315		48		92		7		194		38
2015		315		53		91		8		192		41
2016		319		56		87		9		195		45
2017		312		61		84		10		191		48
2018-2022		1,411		345		392		57		835		264

PROFIT SHARING PLANS

Under Chilean law, Chilquinta Energía is required to pay all employees either (1) 30 percent of Chilquinta Energía’s taxable income after deducting a 10 percent return on equity, allocated in proportion to the annual salary of each employee or (2) 25 percent of each employee’s annual salary, with a maximum mandatory profit sharing of 4.75 months of Chile’s legal minimum salary. Chilquinta Energía has elected the second option but calculates the profit sharing amounts with actual employee salaries instead of the legal minimum salary, resulting in a higher cost. The amounts are paid out each pay period. Chilquinta Energía recorded annual profit sharing expense of $6 million for 2012 and $5 million for 2011 related to this plan.

Under Peruvian law, Luz del Sur is required to pay their employees 5 percent of Luz del Sur’s taxable income, paid once a year and allocated as follows: 50 percent based on each employee’s annual hours worked and 50 percent based on each employee’s annual salary. Luz del Sur recorded annual profit sharing expense of $10 million for 2012 and $9 million for 2011 related to this plan.

SAVINGS PLANS

Sempra Energy offers trusteed savings plans to all domestic employees. Participation in the plans is immediate for salary deferrals for all employees except for the represented employees at SoCalGas, who are eligible upon completion of one year of service. Subject to plan provisions, employees may contribute from one percent to 50 percent of their regular earnings, subject to annual IRS limits, when they begin employment. After one year of the employee’s completed service, Sempra Energy makes matching contributions. Employer contribution amounts and methodology vary by plan, but generally the 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.

As of September 1, 2012 for the Sempra, SDG&E and Mobile Gas savings plans and October 1, 2012 for the SoCalGas savings plan, employer contributions are invested based upon each employee’s investment elections in effect at the time of contribution. Prior to that, employer contributions were initially invested in Sempra Energy common stock, but the employee could transfer the contribution to other investments. Contributions are invested in Sempra Energy common stock, mutual funds and/or institutional trusts. Prior to the termination of the ESOP discussed below, employer contributions for substantially all plans were partially funded by the ESOP.

Contributions to the savings plans were as follows:

(Dollars in millions)	2012		2011		2010
Sempra Energy Consolidated	$	34	$	32	$	31
SDG&E		16		14		14
SoCalGas		15		14		13

The market value of Sempra Energy common stock held by the savings plans was $1.1 billion and $883 million at December 31, 2012 and 2011, respectively.

EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)

Sempra Energy terminated the ESOP effective June 30, 2012, as all ESOP debt was paid and all shares were released from the ESOP Trust as of that date. Prior to the plan’s termination all contributions to the ESOP Trust (Trust) were made by Sempra Energy; there were no contributions made by the participants. The Trust was used to fund part of the retirement savings plan described above. As Sempra Energy made contributions, the ESOP debt service was paid and shares were released in proportion to the total expected debt service. We charged compensation expense and credited equity for the market value of the released shares. Dividends on unallocated shares were used to pay debt service and were applied against the liability. The shares held by the Trust were unallocated and consisted of 0.2 million shares of Sempra Energy common stock with a fair value of $8 million at December 31, 2011.

ESOP debt was paid down by a total of $57 million during the last three years when 868,173 shares of Sempra Energy common stock were released from the Trust in order to fund employer contributions to the Sempra Energy savings plan trust. Interest on the ESOP debt was a negligible amount in 2012 and 2011, and $2 million in 2010. Dividends used for debt service consisted of a negligible amount in 2012, and $1 million in each of 2011 and 2010.

NOTE 9. SHARE-BASED COMPENSATION

SEMPRA ENERGY EQUITY COMPENSATION PLANS

Sempra Energy has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra Energy. 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

§	dividend equivalents

Eligible California Utilities employees participate in Sempra Energy’s share-based compensation plans as a component of their compensation package.

At December 31, 2012, Sempra Energy had the following types of equity awards outstanding:

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, and expire 10 years from the date of grant. Vesting and/or the ability to exercise may be accelerated upon a change in control, in accordance with severance pay agreements or upon eligibility for retirement. Options are subject to forfeiture or earlier expiration when an employee terminates employment.

Restricted Stock Units: Substantially all restricted stock unit awards vest in Sempra Energy common stock at the end of four-year performance periods based on Sempra Energy’s total return to shareholders relative to that of market indices. If Sempra Energy’s total return to shareholders exceeds the target levels established under the 2008 Long Term Incentive Plan for awards granted beginning in 2008 and each year since, up to an additional 50 percent of the number of granted restricted stock units may be issued. If Sempra Energy’s total return to shareholders is below the target levels, shares are subject to partial vesting on a pro rata basis. Restricted stock units may also be service-based; these are generally exercisable at the end of four years of service. Vesting is subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control, in accordance with severance pay agreements or upon eligibility for retirement. Dividend equivalents on shares subject to restricted stock units are reinvested to purchase additional shares that become subject to the same vesting conditions as the restricted stock units to which the dividends relate.

Restricted Stock: Prior to 2009, substantially all restricted stock awards were performance-based and vested at the end of four-year performance periods based on Sempra Energy’s total return to shareholders relative to that of market indices. Restricted stock awards that are service-based are generally exercisable at the end of four years of service. Vesting is subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control, in accordance with severance pay agreements or upon eligibility for retirement. Holders of restricted stock have full voting rights. They also have full dividend rights; however, dividends paid on restricted stock held by officers are reinvested to purchase additional shares that become subject to the same vesting conditions as the restricted stock to which the dividends relate.

The Sempra Energy 2008 Long Term Incentive Plan for EnergySouth, Inc. Employees and Other Eligible Individuals (the Plan) authorizes the issuance of up to 302,478 shares of Sempra Energy common stock. In connection with the acquisition of EnergySouth, Inc. in October 2008, we adopted the Plan to utilize the shares remaining available for future awards under the 2008 Incentive Plan of EnergySouth, Inc. (the Prior Plan). All awards outstanding under the Prior Plan at the time of the acquisition were canceled, and the holders were paid the merger consideration in accordance with the terms of the merger agreement. The Plan provides for the grant of substantially the same types of share-based awards (other than incentive stock options) that are available under the Sempra Energy 2008 Long Term Incentive Plan.

SHARE-BASED AWARDS AND COMPENSATION EXPENSE

We measure and recognize compensation expense for all share-based payment awards made to our employees and directors based on estimated fair values on the date of grant. We recognize compensation costs net of an estimated forfeiture rate (based on historical experience) and recognize the compensation costs for non-qualified stock options and restricted stock and stock units 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. Substantially all awards outstanding are classified as equity instruments, therefore we recognize additional paid in capital as we recognize the compensation expense associated with the awards.

As of December 31, 2012, 1,896,949 shares were authorized and available for future grants of share-based awards. Our practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases.

Total share-based compensation expense for all of Sempra Energy’s share-based awards was comprised as follows:

SHARE-BASED COMPENSATION EXPENSE ― SEMPRA ENERGY CONSOLIDATED
(Dollars in millions, except per share amounts)
	Years ended December 31,
	2012		2011		2010
Share-based compensation expense, before income taxes	$	40	$	44	$	34
Income tax benefit		(16)		(18)		(13)
Share-based compensation expense, net of income taxes	$	24	$	26	$	21

Net share-based compensation expense, per common share
Basic	$	0.10	$	0.11	$	0.09
Diluted	$	0.10	$	0.11	$	0.08

Sempra Energy Consolidated’s capitalized compensation cost was $4 million in each of 2012 and 2011 and $3 million in 2010.

We classify the tax benefits resulting from tax deductions in excess of the tax benefit related to compensation cost recognized for stock option exercises as financing cash flows.

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. Expenses and capitalized compensation costs recorded by SDG&E and SoCalGas were as follows:

SHARE-BASED COMPENSATION EXP ENSE ― SDG&E AND SOCALGAS
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
SDG&E:
Compensation expense	$	8	$	8	$	9
Capitalized compensation cost		3		3		2
SoCalGas:
Compensation expense	$	7	$	9	$	8
Capitalized compensation cost		1		1		1

SEMPRA ENERGY NON-QUALIFIED STOCK OPTIONS

We use a Black-Scholes option-pricing model (Black-Scholes model) to estimate the fair value of each non-qualified stock option grant. The use of a valuation model requires us to make certain assumptions about selected model inputs. Expected volatility is calculated based on the historical volatility of Sempra Energy’s stock price. We base the average expected life for options on the contractual term of the option and expected employee exercise and post-termination behavior.

The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected life assumed at the date of the grant. No new options were granted in 2012 or 2011, and the weighted-average per-share fair value for options granted in 2010 was $7.92. To calculate this fair value, we used the Black-Scholes model with the following weighted-average assumptions:

	2010
Stock price volatility	19%
Risk-free rate of return	2.6%
Annual dividend yield	2.8%
Expected life	5.5 years

The following table shows a summary of the non-qualified stock options as of December 31, 2012 and activity for the year then ended:

NON-QUALIFIED STOCK OPTIONS

					Weighted-
			Weighted-		Average
	Shares		Average		Remaining		Aggregate
	Under		Exercise		Contractual Term		Intrinsic Value
	Option		Price		(in years)		(in millions)
Outstanding at December 31, 2011		4,630,971	$	47.85
Exercised		(1,876,303)	$	41.77
Forfeited/canceled		(53,550)	$	58.62
Outstanding at December 31, 2012		2,701,118	$	51.86		4.6	$	52

Vested or expected to vest, at December 31, 2012		2,696,259	$	51.85		4.6	$	51
Exercisable at December 31, 2012		2,174,018	$	52.03		4.3	$	41

The aggregate intrinsic value at December 31, 2012 is the total of the difference between Sempra Energy’s closing stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for non-qualified stock options exercised in the last three years was

§	$45 million in 2012

§	$23 million in 2011

§	$22 million in 2010

The total fair value of shares vested in the last three years was

§	$4 million in 2012

§	$7 million in 2011

§	$8 million in 2010

The $0.5 million of total compensation cost related to nonvested stock options not yet recognized as of December 31, 2012 is expected to be recognized over a weighted-average period of 1.0 years.

We received cash from option exercises during 2012 totaling $78 million. There were no realized tax benefits for the share-based payment award deductions in 2012 over and above the $16 million income tax benefit shown above.

SEMPRA ENERGY RESTRICTED STOCK AWARDS AND UNITS

We use a Monte-Carlo simulation model to estimate the fair value of the restricted stock awards and units. Our determination of fair value is affected by the volatility of the stock price and the dividend yields for Sempra Energy and its peer group companies. The valuation also is affected by the risk-free rates of return, and a number of other variables. Below are key assumptions for 2012, 2011 and 2010 for Sempra Energy:

	2012	2011	2010
Risk-free rate of return	0.6%	1.5%	2.1%
Annual dividend yield	3.4%	3.0%	2.8%
Stock price volatility	27%	27%	26%

Restricted Stock Awards

We provide below a summary of Sempra Energy’s restricted stock awards as of December 31, 2012 and the activity during the year.

RESTRICTED STOCK AWARDS

			Weighted-
			Average
			Grant-Date
	Shares		Fair Value
Nonvested at December 31, 2011		24,276	$	46.51
Granted		18,487	$	57.81
Vested		(18,074)	$	44.30
Nonvested at December 31, 2012		24,689	$	56.59
Vested or expected to vest, at December 31, 2012		24,689	$	56.59

Total compensation cost of $1 million related to nonvested restricted stock awards not yet recognized as of December 31, 2012 is expected to be recognized over a weighted average period of 2.0 years. The weighted-average per-share fair value for restricted stock awards granted in 2011 was $52.96.

The total fair value of shares vested in the last three years was

§	$1 million in 2012

§	$28 million in 2011

§	$4 million in 2010

Restricted Stock Units

We provide below a summary of Sempra Energy’s restricted stock units as of December 31, 2012 and the activity during the year.

RESTRICTED STOCK UNITS

				Weighted-
				Average
				Grant-Date
		Units		Fair Value
Nonvested at December 31, 2011			3,292,512	$	43.08
Granted			927,734	$	50.17
Vested			(608,348)	$	52.86
Forfeited			(76,624)	$	45.34
Nonvested at December 31, 2012(1)			3,535,274	$	43.21
Vested or expected to vest, at December 31, 2012			3,468,170	$	43.15
(1)	Each unit represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For substantially all restricted stock units, up to an additional 50% of the shares represented by the units may be issued if Sempra Energy exceeds target performance conditions.

The total fair value of shares vested in 2012 was $32 million.

The $27 million of total compensation cost related to nonvested restricted stock units not yet recognized as of December 31, 2012 is expected to be recognized over a weighted-average period of 2.5 years. The weighted-average per-share fair values for restricted stock units granted were $42.35 in 2011 and $44.44 in 2010.

NOTE 10. DERIVATIVE FINANCIAL INSTRUMENTS

We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk and benchmark interest rate risk. We may also manage foreign exchange rate exposures using derivatives. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that our asset values may fall or our liabilities increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not presented below.

We record all derivatives at fair value on the Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in other comprehensive income (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the settlements of derivative instruments as operating activities on the Consolidated Statements of Cash Flows.

In certain cases, we apply the normal purchase or sale exception to derivative accounting and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.

HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that a given future revenue or expense item may vary, and other criteria.

We may designate an interest rate derivative as a fair value hedging instrument if it effectively converts our own debt from a fixed interest rate to a variable rate. The combination of the derivative and debt instruments results in fixing that portion of the fair value of the debt that is related to benchmark interest rates. Designating fair value hedges is dependent on the instrument being used, the effectiveness of the instrument in offsetting changes in the fair value of our debt instruments, and other criteria.

ENERGY DERIVATIVES

Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business.

The California Utilities use natural gas energy derivatives, on their customers’ behalf, with the objective of managing price risk and basis risks, and lowering natural gas costs. These derivatives include fixed price natural gas positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.

SDG&E is allocated and may purchase congestion revenue rights (CRRs), which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Consolidated Statements of Operations.

Sempra Mexico and Sempra Natural Gas may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: liquefied natural gas (LNG), natural gas transportation, power generation, and Sempra Natural Gas’ storage. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico also uses natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its Mexican distribution operations. These derivatives, which are recorded as commodity costs that are offset by regulatory account balances and recovered in rates, are recognized in Cost of Natural Gas on the Consolidated Statements of Operations.

§	From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel.

We summarize net energy derivative volumes as of December 31, 2012 and 2011 as follows:

		December 31,
Segment and Commodity		2012	2011
California Utilities:
SDG&E:
	Natural gas	25 million MMBtu	35 million MMBtu	(1)
	Congestion revenue rights	30 million MWh	19 million MWh	(2)

Energy-Related Businesses:
Sempra Natural Gas:
Electric power		1 million MWh	5 million MWh
Natural gas		36 million MMBtu	20 million MMBtu
Sempra Mexico - natural gas		1 million MMBtu	1 million MMBtu
(1)	Million British thermal units
(2)	Megawatt hours

In addition to the amounts noted above, we frequently use commodity derivatives to manage risks associated with the physical locations of our customers, assets and other contractual obligations, such as natural gas purchases and sales.

INTEREST RATE DERIVATIVES

We are exposed to interest rates primarily as a result of our current and expected use of financing. We periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We utilize interest rate swaps typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, which are typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings.

Interest rate derivatives are utilized by the California Utilities as well as by other Sempra Energy subsidiaries. Although the California Utilities generally recover borrowing costs in rates over time, the use of interest rate derivatives is subject to certain regulatory constraints, and the impact of interest rate derivatives may not be recovered from customers as timely as described above with regard to natural gas derivatives. Accordingly, interest rate derivatives are generally accounted for as hedges at the California Utilities, as well as at the rest of Sempra Energy’s subsidiaries. Separately, Otay Mesa VIE has entered into interest rate swap agreements to moderate its exposure to interest rate changes. This activity was designated as a cash flow hedge as of April 1, 2011.

The net notional amounts of our interest rate derivatives as of December 31, 2012 and 2011 were:

		December 31, 2012			December 31, 2011
(Dollars in millions)		Notional Debt		Maturities	Notional Debt		Maturities
Sempra Energy Consolidated(1)		$	6-369	2013-2028	$	15-305	2013-2019
SDG&E(1)			285-345	2019		285-355	2019
(1)	Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

FOREIGN CURRENCY DERIVATIVES

We are exposed to exchange rate movements primarily as a result of our Mexican subsidiaries, which have U.S. dollar denominated receivables and payables (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. These subsidiaries also have deferred income tax assets and liabilities that are denominated in the Mexican peso, which must be translated into U.S. dollars for financial reporting purposes. From time to time, we may utilize short-term foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage the risk of exposure to significant fluctuations in our income tax expense from these impacts.

FINANCIAL STATEMENT PRESENTATION

The following tables provide the fair values of derivative instruments, without consideration of margin deposits held or posted, on the Consolidated Balance Sheets as of December 31, 2012 and 2011:

DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2012
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
Derivatives designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
	Interest rate instruments(3)	$	7	$	12	$	(19)	$	(64)
	Commodity contracts not subject to rate recovery		1		―		―		―
	Total	$	8	$	12	$	(19)	$	(64)
SDG&E:
	Interest rate instruments(3)	$	―	$	―	$	(17)	$	(64)

Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
	Interest rate instruments	$	8	$	40	$	(8)	$	(35)
	Commodity contracts not subject to rate recovery		117		15		(116)		(27)
	Associated offsetting commodity contracts		(102)		(12)		102		12
	Commodity contracts subject to rate recovery		30		35		(35)		(1)
	Associated offsetting commodity contracts		(4)		―		4		―
	Total	$	49	$	78	$	(53)	$	(51)
SDG&E:
	Commodity contracts subject to rate recovery	$	28	$	35	$	(33)	$	(1)
	Associated offsetting commodity contracts		(3)		―		3		―
	Total	$	25	$	35	$	(30)	$	(1)
SoCalGas:
	Commodity contracts subject to rate recovery	$	2	$	―	$	(2)	$	―
	Associated offsetting commodity contracts		(1)		―		1		―
	Total	$	1	$	―	$	(1)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
		December 31, 2011
									Deferred
									credits
			Current				Current		and other
			assets:				liabilities:		liabilities:
			Fixed-price		Investments		Fixed-price		Fixed-price
			contracts		and other		contracts		contracts
			and other		assets:		and other		and other
Derivatives designated as hedging instruments			derivatives(1)		Sundry		derivatives(2)		derivatives
Sempra Energy Consolidated:
	Interest rate instruments(3)	$	5	$	11	$	(17)	$	(65)
SDG&E:
	Interest rate instruments(3)	$	―	$	―	$	(16)	$	(65)

Derivatives not designated as hedging instruments
Sempra Energy Consolidated:
	Interest rate instruments	$	8	$	41	$	(7)	$	(36)
	Commodity contracts not subject to rate recovery		156		72		(148)		(94)
	Associated offsetting commodity contracts		(120)		(68)		120		68
	Commodity contracts subject to rate recovery		28		8		(62)		(24)
	Associated offsetting commodity contracts		(10)		(2)		10		2
	Total	$	62	$	51	$	(87)	$	(84)
SDG&E:
	Commodity contracts subject to rate recovery	$	22	$	8	$	(55)	$	(24)
	Associated offsetting commodity contracts		(5)		(2)		5		2
	Total	$	17	$	6	$	(50)	$	(22)
SoCalGas:
	Commodity contracts subject to rate recovery	$	6	$	―	$	(7)	$	―
	Associated offsetting commodity contracts		(5)		―		5		―
	Total	$	1	$	―	$	(2)	$	―
(1)	Included in Current Assets: Other for SoCalGas.
(2)	Included in Current Liabilities: Other for SoCalGas.
(3)	Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

The effects of derivative instruments designated as hedges on the Consolidated Statements of Operations and on Other Comprehensive Income (OCI) and Accumulated Other Comprehensive Income (AOCI) for the years ended December 31 were:

FAIR VALUE HEDGE IMPACT ON THE CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
			Gain (loss) on derivatives recognized in earnings
			Years ended December 31,
		Location	2012		2011		2010
Sempra Energy Consolidated:
	Interest rate instruments	Interest Expense	$	6	$	9	$	10
	Interest rate instruments	Other Income, Net		3		13		(11)
	Total (1)		$	9	$	22	$	(1)
SoCalGas:
	Interest rate instrument	Interest Expense	$	―	$	1	$	6
	Interest rate instrument	Other Income, Net		―		(3)		(4)
	Total (1)		$	―	$	(2)	$	2
(1)	There has been no hedge ineffectiveness on these swaps. Changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt.

CASH FLOW HEDGE IMPACT ON THE CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
		Pretax gain (loss) recognized in OCI							Gain (loss) reclassified from AOCI into earnings
		(effective portion)							(effective portion)
		Years ended December 31,							Years ended December 31,
			2012		2011		2010	Location		2012		2011		2010
Sempra Energy Consolidated:
	Interest rate instruments(1)	$	(22)	$	(42)	$	―	Interest Expense	$	(9)	$	(8)	$	(12)
	Interest rate instruments		―		―		―	Other Income, Net(2)		―		―		10
								Equity Earnings (Losses),
	Interest rate instruments		(10)		(32)		2	Before Income Tax: Other		(6)		(5)		(1)
	Commodity contracts not subject							Cost of Natural Gas, Electric
	to rate recovery		(1)		―		―	Fuel and Purchased Power		―		―		―
	Commodity contracts not subject							Equity Earnings (Losses),
	to rate recovery							Before Income Tax: RBS
			―		―		1	Sempra Commodities LLP		―		―		21
	Total	$	(33)	$	(74)	$	3		$	(15)	$	(13)	$	18
SDG&E:
	Interest rate instruments(1)	$	(16)	$	(40)	$	―	Interest Expense	$	(5)	$	(5)	$	(7)
SoCalGas:
	Interest rate instrument	$	―	$	―	$	―	Interest Expense	$	(2)	$	(3)	$	(5)
(1)	Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. There was a negligible amount of ineffectiveness related to these swaps.
(2)	Gains reclassified into earnings due to changes in cash requirements and associated impacts on forecasted interest payments, primarily related to proceeds received from RBS Sempra Commodities. See Note 4.

Sempra Energy Consolidated expects that losses of $14 million, which are net of income tax benefit, that are currently recorded in AOCI (including $9 million in noncontrolling interests) related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts that are currently outstanding mature. The Sempra Energy Consolidated amount includes $9 million at SDG&E in noncontrolling interest related to Otay Mesa VIE.

SoCalGas expects that losses of $1 million, which are net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings.

For all forecasted transactions, the maximum term over which we are hedging exposure to the variability of cash flows at December 31, 2012 is approximately 16 years and 7 years for Sempra Energy and SDG&E, respectively. The maximum term of hedged interest rate variability related to debt at Sempra Renewables’ equity method investees is 18 years.

We recorded $2 million of hedge ineffectiveness in 2012, and negligible hedge ineffectiveness in 2011 and 2010.

The effects of derivative instruments not designated as hedging instruments on the Consolidated Statements of Operations for the years ended December 31 were:

UNDESIGNATED DERIVATIVE IMPACT ON THE CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
			Gain (loss) on derivatives recognized in earnings
			Years ended December 31,
		Location	2012		2011		2010
Sempra Energy Consolidated:
	Interest rate and foreign
	exchange instruments(1)	Other Income, Net	$	10	$	(14)	$	(34)
	Commodity contracts not subject	Revenues: Energy-Related
	to rate recovery	Businesses		7		30		47
	Commodity contracts not subject	Cost of Natural Gas, Electric
	to rate recovery	Fuel and Purchased Power		―		1		(29)
	Commodity contracts not subject
	to rate recovery	Other Operation and Maintenance		1		1		2
	Commodity contracts subject	Cost of Electric Fuel
	to rate recovery	and Purchased Power		69		(14)		(102)
	Commodity contracts subject
	to rate recovery	Cost of Natural Gas		(2)		(2)		(9)
	Total		$	85	$	2	$	(125)
SDG&E:
	Interest rate instruments(1)	Other Income, Net	$	―	$	(1)	$	(34)
	Commodity contracts not subject
	to rate recovery	Operation and Maintenance		―		―		1
	Commodity contracts subject	Cost of Electric Fuel
	to rate recovery	and Purchased Power		69		(14)		(102)
	Total		$	69	$	(15)	$	(135)
SoCalGas:
	Commodity contracts not subject
	to rate recovery	Operation and Maintenance	$	1	$	1	$	1
	Commodity contracts subject
	to rate recovery	Cost of Natural Gas		(2)		(2)		(5)
	Total		$	(1)	$	(1)	$	(4)
(1)	Amounts for 2010 and 2011 are related to Otay Mesa VIE. Sempra Energy Consolidated also includes additional instruments.

CONTINGENT FEATURES

For Sempra Energy and SDG&E, certain of our derivative instruments contain credit limits which vary depending upon our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization.

For Sempra Energy, the total fair value of this group of derivative instruments in a net liability position at December 31, 2012 and 2011 is $8 million and $24 million, respectively. As of December 31, 2012, if the credit ratings of Sempra Energy were reduced below investment grade, $8 million of additional assets could be required to be posted as collateral for these derivative contracts.

For SDG&E, the total fair value of this group of derivative instruments in a net liability position at December 31, 2012 and 2011 is $6 million and $11 million, respectively. As of December 31, 2012, if the credit ratings of SDG&E were reduced below investment grade, $6 million of additional assets could be required to be posted as collateral for these derivative contracts.

For Sempra Energy, SDG&E and SoCalGas, some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above.

NOTE 11. FAIR VALUE MEASUREMENTS

Recurring Fair Value Measures

The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 and 2011. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our 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.

The fair value of commodity derivative assets and liabilities is determined in accordance with our netting policy, as we discuss below under “Derivative Positions Net of Cash Collateral.”

The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).

Our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 and 2011 in the tables below include the following:

Nuclear decommissioning trusts reflect the assets of SDG&E’s nuclear decommissioning trusts, excluding cash balances. A third party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Equity and certain debt securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other debt securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).

We enter into commodity contracts and interest rate derivatives primarily as a means to manage price exposures. We primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). All Level 3 recurring items are related to CRRs at SDG&E, as we discuss below under “Level 3 Information.” We record commodity derivative contracts that are subject to rate recovery as commodity costs that are offset by regulatory account balances and are recovered in rates.

§	Investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1).

There were no transfers into or out of Level 1, Level 2 or Level 3 for Sempra Energy Consolidated, SDG&E or SoCalGas during the periods presented, nor any changes in valuation techniques used in recurring fair value measurements.

RECURRING FAIR VALUE MEASURES ― SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
		At fair value as of December 31, 2012
									Collateral
			Level 1		Level 2		Level 3		Netted		Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	539	$	―	$	―	$	―	$	539
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			87		69		―		―		156
Municipal bonds			―		63		―		―		63
Other securities			―		130		―		―		130
Total debt securities			87		262		―		―		349
Total nuclear decommissioning trusts(1)			626		262		―		―		888
Interest rate instruments			―		68		―		―		68
Commodity contracts subject to rate recovery			13		―		61		―		74
Commodity contracts not subject to rate recovery			28		15		―		―		43
Investments			1		―		―		―		1
Total		$	668	$	345	$	61	$	―	$	1,074
Liabilities:
Interest rate instruments		$	―	$	126	$	―	$	―	$	126
Commodity contracts subject to rate recovery			23		9		―		(23)		9
Commodity contracts not subject to rate recovery			6		23		―		(11)		18
Total		$	29	$	158	$	―	$	(34)	$	153

		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Interest rate instruments			―		66		―		―		66
Commodity contracts subject to rate recovery			10		1		23		―		34
Commodity contracts not subject to rate recovery			15		35		―		(2)		48
Investments			5		―		―		―		5
Total		$	590	$	335	$	23	$	(2)	$	946
Liabilities:
Interest rate instruments		$	1	$	124	$	―	$	―	$	125
Commodity contracts subject to rate recovery			61		13		―		(61)		13
Commodity contracts not subject to rate recovery			1		52		―		(4)		49
Total		$	63	$	189	$	―	$	(65)	$	187
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES ― SDG&E
(Dollars in millions)
		At fair value as of December 31, 2012
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	539	$	―	$	―	$	―	$	539
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			87		69		―		―		156
Municipal bonds			―		63		―		―		63
Other securities			―		130		―		―		130
Total debt securities			87		262		―		―		349
Total nuclear decommissioning trusts(1)			626		262		―		―		888
Commodity contracts subject to rate recovery			12		―		61		―		73
Commodity contracts not subject to rate recovery			1		―		―		―		1
Total		$	639	$	262	$	61	$	―	$	962

Liabilities:
Interest rate instruments		$	―	$	81	$	―	$	―	$	81
Commodity contracts subject to rate recovery			23		8		―		(23)		8
Total		$	23	$	89	$	―	$	(23)	$	89

		At fair value as of December 31, 2011
									Collateral
			Level 1		Level 2		Level 3		netted		Total
Assets:
Nuclear decommissioning trusts
Equity securities		$	468	$	―	$	―	$	―	$	468
Debt securities:
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies			92		78		―		―		170
Municipal bonds			―		77		―		―		77
Other securities			―		78		―		―		78
Total debt securities			92		233		―		―		325
Total nuclear decommissioning trusts(1)			560		233		―		―		793
Commodity contracts subject to rate recovery			9		―		23		―		32
Commodity contracts not subject to rate recovery			1		―		―		―		1
Total		$	570	$	233	$	23	$	―	$	826

Liabilities:
Interest rate instruments		$	―	$	81	$	―	$	―	$	81
Commodity contracts subject to rate recovery			61		12		―		(61)		12
Total		$	61	$	93	$	―	$	(61)	$	93
(1)	Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES ― SOCALGAS
(Dollars in millions)
	At fair value as of December 31, 2012
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	1	$	―	$	―	$	―	$	1
Commodity contracts not subject to rate recovery		3		―		―		―		3
Total	$	4	$	―	$	―	$	―	$	4

Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1

	At fair value as of December 31, 2011
								Collateral
		Level 1		Level 2		Level 3		netted		Total
Assets:
Commodity contracts subject to rate recovery	$	1	$	1	$	―	$	―	$	2
Commodity contracts not subject to rate recovery		2		―		―		―		2
Total	$	3	$	1	$	―	$	―	$	4

Liabilities:
Commodity contracts subject to rate recovery	$	―	$	1	$	―	$	―	$	1
Total	$	―	$	1	$	―	$	―	$	1

Level 3 Information

The following table sets forth reconciliations of changes in the fair value of CRRs classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E:

LEVEL 3 RECONCILIATIONS
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
Balance as of January 1	$	23	$	2	$	10
Realized and unrealized gains (losses)		31		32		(16)
Allocated transmission instruments		58		7		8
Settlements		(51)		(18)		―
Balance as of December 31	$	61	$	23	$	2
Change in unrealized gains or losses relating to
instruments still held at December 31	$	17	$	17	$	(9)

SDG&E’s Energy and Fuel Procurement department, in conjunction with SDG&E’s finance group, is responsible for determining the appropriate fair value methodologies used to value and classify CRRs on an ongoing basis. Inputs used to determine the fair value of CRRs are reviewed and compared with market conditions to determine reasonableness. All costs related to CRRs are expected to be recoverable through customer rates. As such, there is no impact to net income from changes in the fair value of these instruments.

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California ISO, an objective source. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. Auction prices range from $(11) per MWh to $12 per MWh at a given location, and the fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 10. Realized gains and losses associated with CRRs are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings.

Derivative Positions Net of Cash Collateral

Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when management believes a legal right of offset exists.

The following table provides the amount of fair value of cash collateral receivables that were not offset in the Consolidated Balance Sheets as of December 31, 2012 and 2011:

	December 31,
(Dollars in millions)	2012		2011
Sempra Energy Consolidated	$	35	$	20
SDG&E		13		10
SoCalGas		3		2

Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments at December 31:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
		December 31, 2012
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Investments in affordable housing partnerships (1)		$	12	$	―	$	―	$	36	$	36
Total long-term debt (2)			11,873		―		12,287		956		13,243
Preferred stock of subsidiaries			99		―		107		―		107
SDG&E:
Total long-term debt (3)		$	4,135	$	―	$	4,243	$	345	$	4,588
Contingently redeemable preferred stock			79		―		85		―		85
SoCalGas:
Total long-term debt (4)		$	1,413	$	―	$	1,599	$	―	$	1,599
Preferred stock			22		―		24		―		24

		December 31, 2011
		Carrying		Fair Value
		Amount		Level 1		Level 2		Level 3		Total
Sempra Energy Consolidated:
Investments in affordable housing partnerships (1)		$	21	$	―	$	―	$	48	$	48
Total long-term debt (2)			9,826		―		10,447		600		11,047
Preferred stock of subsidiaries			99		―		106		―		106
SDG&E:
Total long-term debt (3)		$	3,895	$	―	$	3,933	$	355	$	4,288
Contingently redeemable preferred stock			79		―		86		―		86
SoCalGas:
Total long-term debt (4)		$	1,313	$	―	$	1,506	$	―	$	1,506
Preferred stock			22		―		23		―		23
(1)	Investments in affordable housing partnerships at Parent and Other.
(2)	Before reductions for unamortized discount (net of premium) of $16 million at both December 31, 2012 and 2011, and excluding capital leases of $189 million at December 31, 2012 and $204 million at December 31, 2011, and commercial paper classified as long-term debt of $300 million at December 31, 2012 and $400 million at December 31, 2011. We discuss our long-term debt in Note 5.
(3)	Before reductions for unamortized discount of $12 million at December 31, 2012 and $11 million at December 31, 2011, and excluding capital leases of $185 million at December 31, 2012 and $193 million at December 31, 2011.
(4)	Before reductions for unamortized discount of $4 million at December 31, 2012 and $3 million at December 31, 2011, and excluding capital leases of $4 million at December 31, 2012 and $11 million at December 31, 2011.

We calculate the fair value of our investments in affordable housing partnerships using an income approach based on the present value of estimated future cash flows discounted at rates available for similar investments (Level 3).

We base the fair value of certain of our long-term debt and preferred stock on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). We value other long-term debt using an income approach based on the present value of estimated future cash flows discounted at rates available for similar securities (Level 3).

Non-Recurring Fair Value Measures – Sempra Energy Consolidated

We discuss non-recurring fair value measures and the associated accounting impact on our investments in Rockies Express and RBS Sempra Commodities in Note 4.

Rockies Express

In the full year ended December 31, 2012, we recorded a $400 million pretax impairment of our investment in Rockies Express. In the second quarter of 2012, the noncash impairment charge of $300 million ($179 million after-tax) primarily resulted from the continuing decline in basis differential associated with shale gas production zones coming on line, assumptions related to the re-contracting of the long-term transportation agreements, and the refinancing of the existing project level debt, discussed further below. The fair value measurement was significantly impacted by unobservable inputs (Level 3) as defined by the accounting guidance for fair value measurements, which we discuss in Note 1 under “Fair Value Measurements.” We considered a market participant’s view of the total value for Rockies Express, based on an estimation of the future cash distributions it would be able to generate, adjusted for our 25-percent ownership interest. To estimate future cash distributions, we considered factors impacting Rockies Express’ ability to pay future distributions including:

§	the extent to which future cash flows are hedged by capacity sales contracts and their duration (generally through 2019), as well as the creditworthiness of the various counterparties;

§	Rockies Express’ future financing needs, including the ability to secure borrowings at reasonable rates as well as potentially using operating cash to retire principal;

§	prospects for generating attractive revenues and cash flows beyond 2019, including natural gas’ future basis differentials (driven by the location and extent of future supply and demand) and alternative strategies potentially available to utilize the assets; and

§	discount rates commensurate with the risks inherent in the cash flows.

In the third quarter of 2012, KMI reached an agreement with Tallgrass, which closed in the fourth quarter of 2012, to sell its asset group as mandated by the FTC, which group included its interest in Rockies Express. Events in the third quarter of 2012 related to this agreement also provided us with additional market participant data. We therefore updated our analysis of the fair value of our investment in Rockies Express as of September 30, 2012 to reflect these additional inputs and recorded an additional impairment charge of $100 million ($60 million after-tax). This fair value measurement in the third quarter was based primarily on the Level 2 input. We believe this is useful and reliable information, but we considered that it may be impacted by the FTC’s requirement for KMI to sell its interest in Rockies Express. To reflect this uncertainty, our updated analysis included the less subjective Level 2 market participant input as the primary indicator of fair value, with less weight ascribed to value based on estimated discounted cash flows as discussed above and in the table below. The updates to the cash flow analysis used in determining fair value in the second quarter reflected discussions with Tallgrass as to the strategic direction they are planning to take with their equity partners for Rockies Express, as well as additional discussions with other market participants. As of December 31, 2012, Tallgrass is the operator of Rockies Express.

We believe our analysis forms a reasonable estimate of the fair value of Rockies Express. This estimate includes the material input described above, which was generally observable during the period most relevant to our analysis. Regarding the unobservable inputs, significant uncertainties exist with regard to REX’s ability to secure attractive revenues beyond 2019. Accordingly, our analysis suggests that the fair value of our investment in Rockies Express could be materially different from the value we have estimated at this time. For example, if REX is able to sustain the level of revenues currently generated beyond 2019, the value of our investment in Rockies Express would be materially enhanced and the indicated value of our investment in Rockies Express could be significantly higher. Conversely, if REX is unable to sell its transport capacity at sufficient rates or in sufficient volumes beyond 2019, the fair value of our investment in Rockies Express could be materially lower than our carrying amount. Separately, future events involving REX equity could occur and may also provide additional information regarding the fair value of our investment in REX.

Sempra Natural Gas developed the models and scenarios used to measure the fair value of our investment in REX. This modeling used inputs from external sources as described above and in the table below, as well as internally available data, such as operating and maintenance budgets used for financial planning purposes. External experts that forecast the future price of natural gas at various physical locations were also engaged to help validate certain scenarios and modeling assumptions. The fair value measurements were reviewed in detail by Sempra Natural Gas’ financial management, as well as Sempra Energy’s financial management team.

RBS Sempra Commodities

Parent and Other recorded impairment charges of $16 million in 2011 and $305 million in 2010 to reduce the carrying value of our investment in RBS Sempra Commodities, which we discuss in Note 4. These impairments resulted from adjustments to the carrying value of our investment in the partnership at certain reporting dates. We recorded the $305 million charge ($139 million after-tax) to reduce the investment in the partnership in the third quarter of 2010 because projected cash distributions from RBS Sempra Commodities, including proceeds from the sale of the partnership’s businesses and net of expected transition costs, were not expected to fully recover the goodwill included in the carrying value of our investment in the partnership. We recorded a pretax noncash charge of $16 million ($10 million after-tax) in the third quarter of 2011 to further reduce our investment to reflect the latest estimates of our expected future cash distributions from the partnership, which were impacted by additional amounts incurred to conclude the sales of the partnership’s businesses. In 2011 and 2010, the fair value of our investment in RBS Sempra Commodities was significantly impacted by unobservable inputs (i.e. Level 3 inputs) as defined by the accounting guidance for fair value measurements and described in the table below. The inputs included estimated future cash distributions expected from the partnership, excluding the impact of costs anticipated for transactions that had not closed at the time of fair value measurement.

The following table summarizes significant inputs impacting non-recurring fair value measures related to our investments in REX and RBS Sempra Commodities:

NON-RECURRING FAIR VALUE MEASURES ― SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
					% of
		Estimated		Fair	Fair Value
		Fair		Value	Measure-		Range of
		Value(1)	Valuation Technique	Hierarchy	ment	Inputs Used to Develop Measurement	Inputs
Investment in
Rockies Express		$ 369(2)	Market approach	Level 2	67%	Equity sale offer price	100%


			Probability weighted	Level 3	33%	Combined transportation rate assumption(4)	6% - 78%
			discounted cash flow			Counterparty credit risk on existing contracts	Low
						Operation and maintenance escalation rate	0% - 1%
						Forecasted interest rate on debt to be refinanced	5% - 10%
						Discount rate	8% - 10%
Investment in
RBS Sempra
Commodities		$ 126(3)	Discounted cash flow	Level 3	100%	Future cash distributions	90% - 110%
(1)	At measurement date.
(2)	Estimated fair value does not include $13 million of equity earnings and $21 million of dividend distributions that occurred subsequent to September 30, 2012.
(3)	There have been no earnings or distributions subsequent to September 30, 2011.
(4)	Transportation rate beyond existing contract terms as a percentage of current mean REX rates.

NOTE 12. PREFERRED STOCK

The table below shows the details of preferred stock for SDG&E and SoCalGas. All series of Pacific Enterprises (PE) preferred stock were redeemed during 2011 as we discuss below.

PREFERRED STOCK

			Call/
			Redemption	December 31,
			Price	2012		2011
				(in millions)
Contingently redeemable:
	SDG&E:
	$20 par value, authorized 1,375,000 shares:
	5% Series, 375,000 shares outstanding	$	24.00	$	8	$	8
	4.5% Series, 300,000 shares outstanding	$	21.20		6		6
	4.4% Series, 325,000 shares outstanding	$	21.00		7		7
	4.6% Series, 373,770 shares outstanding	$	20.25		7		7
	Without par value:
	$1.70 Series, 1,400,000 shares outstanding	$	25.085		35		35
	$1.82 Series, 640,000 shares outstanding	$	26.00		16		16
	SDG&E - Total contingently redeemable preferred stock				79		79
	Sempra Energy - Total contingently redeemable preferred
	stock of subsidiary			$	79	$	79

SoCalGas:
$25 par value, authorized 1,000,000 shares:
6% Series, 79,011 shares outstanding				$	3	$	3
6% Series A, 783,032 shares outstanding					19		19
SoCalGas - Total preferred stock					22		22
Less: 50,970 shares of the 6% Series outstanding owned by PE					(2)		(2)
					20		20

	Sempra Energy - Total preferred stock of subsidiary			$	20	$	20

Following are the attributes of each company’s preferred stock. No amounts currently outstanding are subject to mandatory redemption.

SDG&E

§	All outstanding series are callable.

§	The $20 par value preferred stock has two votes per share on matters being voted upon by shareholders of SDG&E and a liquidation preference at par plus any unpaid dividends.

§	All outstanding series of SDG&E’s preferred stock have cumulative preferences as to dividends.

§	The no-par-value preferred stock is nonvoting and has a liquidation preference of $25 per share plus any unpaid dividends.

§	SDG&E is authorized to issue 10 million shares of no-par-value preferred stock (both subject to and not subject to mandatory redemption).

SDG&E is currently authorized to issue up to 25 million shares of an additional class of preference shares designated as “Series Preference Stock.” The Series Preference Stock is in addition to the Cumulative Preferred Stock, Preference Stock (Cumulative) and Common Stock that SDG&E was otherwise authorized to issue, and when issued would rank junior to the Cumulative Preferred Stock and Preference Stock (Cumulative). The stock’s rights, preferences and privileges would be established by the board of directors at the time of issuance.

SDG&E’s outstanding preferred securities are classified as contingently redeemable because they contain a contingent redemption feature that allows the holder to elect a majority of SDG&E’s board of directors if dividends are not paid for eight consecutive quarters, and such a redemption triggering event is not solely within the control of SDG&E. They are therefore presented separate from and outside of equity in a manner consistent with temporary equity.

SOCALGAS

§	None of SoCalGas’ outstanding preferred stock is callable.

§	All outstanding series have one vote per share, cumulative preferences as to dividends and liquidation preferences of $25 per share plus any unpaid dividends.

SoCalGas currently is 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 liquidation value. The preference stock would rank junior to all series of preferred stock. Other rights and privileges of the stock would be established by the board of directors at the time of issuance.

PACIFIC ENTERPRISES

On June 30, 2011, PE redeemed all five series of its outstanding preferred stock for $81 million. Each series was redeemed for cash at redemption prices ranging from $100 to $101.50 per share, plus accrued dividends up to the redemption date of an aggregate of $1 million. The redeemed shares are no longer outstanding and represent only the right to receive the applicable redemption price, to the extent that shares have not yet been presented for payment.

PE currently is authorized to issue 10 million shares of series preferred stock and 5 million shares of Class A series preferred stock, both without par value and with cumulative preferences as to dividends and liquidation value. No shares of preferred stock or Class A series preferred stock are outstanding. Class A series preferred stock, when issued, would rank junior to all other series of preferred stock with respect to dividends and liquidation value. Other rights and privileges of each series of the preferred stock and Class A series preferred stock would be established by the board of directors at the time of issuance.

NOTE 13. SEMPRA ENERGY – SHAREHOLDERS’ EQUITY AND EARNINGS PER SHARE

The following table provides the per share computations for our earnings for years ended December 31. Basic earnings per common share (EPS) is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the year. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

EARNINGS PER SHARE COMPUTATIONS
(Dollars in millions, except per share amounts; shares in thousands)
	Years ended December 31,
	2012		2011		2010
Numerator:
Earnings/Income attributable to common shareholders	$	859	$	1,331	$	709

Denominator:
Weighted-average common shares outstanding for basic EPS		241,347		239,720		244,736
Dilutive effect of stock options, restricted stock awards and
restricted stock units		5,346		1,803		3,206
Weighted-average common shares outstanding for diluted EPS		246,693		241,523		247,942

Earnings per share:
Basic	$	3.56	$	5.55	$	2.90
Diluted	$	3.48	$	5.51	$	2.86

The dilution from common stock options is based on the treasury stock method. Under this method, proceeds based on the exercise price plus unearned compensation and windfall tax benefits recognized and minus tax shortfalls recognized are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits are tax deductions we would receive upon the assumed exercise of stock options in excess of the deferred income taxes we recorded related to the compensation expense on the stock options. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. The calculation excludes options for which the exercise price on common stock was greater than the average market price during the period (out-of-the-money options). We had 40,000; 2,083,275 and 2,138,800 of such antidilutive stock options outstanding during 2012, 2011 and 2010, respectively.

During 2012, we had no stock options outstanding that were antidilutive because of the unearned compensation and windfall tax benefits recognized included in the assumed proceeds under the treasury stock method. We had 900 and 9,900 such antidilutive stock options outstanding during 2011 and 2010, respectively.

The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method. Proceeds equal to the unearned compensation and windfall tax benefits recognized and minus tax shortfalls recognized related to the awards and units are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits recognized or tax shortfalls recognized are the difference between tax deductions we would receive upon the assumed vesting of RSAs or RSUs and the deferred income taxes we recorded related to the compensation expense on such awards and units. There were 1,934 antidilutive restricted stock awards and 7,673 antidilutive restricted stock units from the application of unearned compensation in the treasury stock method in 2012. There were no such antidilutive restricted stock awards or units in 2011 or 2010.

Each performance based RSU represents the right to receive between zero and 1.5 shares of Sempra Energy common stock based on Sempra Energy’s four-year cumulative total shareholder return compared to the S&P 500 Utilities Index, as follows:

Four-Year Cumulative Total Shareholder Return Ranking versus S&P 500 Utilities Index(1)		Number of Sempra Energy Common Shares Received for Each Restricted Stock Unit(2)
75th Percentile or Above		1.5
50th Percentile		1
35th Percentile or Below		―
(1)	If Sempra Energy ranks at or above the 50th percentile compared to the S&P 500 Index, participants will receive a minimum of 1.0 share for each restricted stock unit.
(2)	Participants may also receive additional shares for dividend equivalents on shares subject to restricted stock units, which are reinvested to purchase additional units that become subject to the same vesting conditions as the restricted stock units to which the dividends relate.

RSAs have a maximum potential of 100 percent vesting. We include our performance based RSUs in potential dilutive shares at zero to 150 percent to the extent that they currently meet the performance requirements for vesting, subject to the application of the treasury stock method. Due to market fluctuations of both Sempra Energy stock and the comparative index, dilutive RSU shares may vary widely from period-to-period. We include our RSAs, which are solely service-based, in potential dilutive shares at 100 percent.

RSUs and RSAs may be excluded from potential dilutive shares by the application of unearned compensation in the treasury stock method, as we discuss above, or because performance goals are currently not met. The maximum excluded RSUs and RSAs, assuming performance goals were met at maximum levels, were 1,134,456; 4,109,717 and 2,008,413 for the years ended December 31, 2012, 2011 and 2010, respectively.

We are authorized to issue 750,000,000 shares of no-par-value common stock. In addition, we are authorized to issue 50,000,000 shares of preferred stock having rights, preferences and privileges that would be established by the Sempra Energy board of directors at the time of issuance.

There were no shares of common stock held by the ESOP at December 31, 2012, and 153,625 and 504,440 at December 31, 2011 and 2010, respectively. These shares are unallocated and therefore excluded from the computation of EPS.

Excluding shares held by the ESOP, common stock activity consisted of the following:

COMMON STOCK ACTIVITY

		2012	2011	2010
Common shares outstanding, January 1		239,934,681	240,447,416	246,507,865
Savings plan issuance		―	―	560,600
Shares released from ESOP		153,625	350,815	363,733
Stock options exercised		1,876,303	958,126	912,725
Restricted stock issuances		2,580	11,876	―
Restricted stock units vesting(1)		683,416	2,625	―
Shares repurchased(2)		(281,769)	(1,836,177)	(8,108,579)
Common stock investment plan (3)		―	―	217,772
Shares forfeited and other		―	―	(6,700)
Common shares outstanding, December 31		242,368,836	239,934,681	240,447,416
(1)	Includes dividend equivalents.
(2)	In addition to formal common stock repurchase programs which we discuss below, we may also, from time to time, purchase shares of our common stock from restricted stock plan participants who elect to sell a sufficient number of vesting restricted shares to meet minimum statutory tax withholding requirements.
(3)	Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares.

Our board of directors has the discretion to determine the payment and amount of future dividends.

COMMON STOCK REPURCHASE PROGRAMS

On September 11, 2007, our board of directors authorized the repurchase of additional shares of our common stock provided that the amounts expended for such purposes did not exceed the greater of $2 billion or amounts expended to purchase no more than 40 million shares. Purchases may include open-market and negotiated transactions, structured purchase arrangements, and tender offers.

In April 2008, we entered into a share repurchase program under which we prepaid $1 billion to repurchase shares of our common stock to be delivered later in 2008 in a share forward transaction. The $1 billion purchase price was recorded as a reduction in shareholders’ equity, and we received 18,416,241 shares under the program during 2008 based on a final weighted average price of $54.30 per share.

In September 2010, we entered into a share repurchase program under which we prepaid $500 million to repurchase shares of our common stock in a share forward transaction. The program was completed in March 2011 with a total of 9,574,435 shares repurchased at an average price of $52.22 per share. Our outstanding shares used to calculate earnings per share were reduced by the number of shares repurchased when they were delivered to us, and the $500 million purchase price was recorded as a reduction in shareholders ’ equity upon its prepayment. We received 5,670,006 shares during the quarter ended September 30, 2010; 2,407,994 shares on October 4, 2010 and 1,496,435 shares on March 22, 2011.

These share repurchase programs are unrelated to share based compensation as described in Note 9.

NOTE 14. CALIFORNIA UTILITIES’ REGULATORY MATTERS

JOINT MATTERS

General Rate Case (GRC)

The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment. In December 2010, the California Utilities filed their 2012 General Rate Case (GRC) applications to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. Both SDG&E and SoCalGas filed revised applications with the CPUC in July 2011. Evidentiary hearings were completed in January 2012, and final briefs reflecting the results from these hearings were filed with the CPUC in May 2012.

In February 2012, the California Utilities filed amendments to update their July 2011 revised applications. With these amendments, SDG&E is requesting a revenue requirement in 2012 of $1.849 billion, an increase of $235 million (or 14.6 percent) over 2011, of which $67 million is being requested for cost recovery of the incremental wildfire insurance premiums which are not included in the 2011 revenue requirement as set forth in the 2008 GRC. SoCalGas is requesting a revenue requirement in 2012 of $2.112 billion, an increase of $268 million (14.5 percent) over 2011. The Division of Ratepayer Advocates (DRA) is recommending that the CPUC reduce the utilities’ revenue requirements in 2012 by approximately 5 percent compared to 2011.

Because a final decision for the 2012 GRC was not issued in 2012, the California Utilities have recorded revenues in 2012 based on levels authorized in 2011 plus, for SDG&E, consistent with the recent CPUC decisions for cost recovery for SDG&E’s incremental wildfire insurance premiums, an amount for the recovery of 2012 wildfire insurance premiums. We expect a final CPUC decision for the 2012 GRC, which will be made effective retroactive to January 1, 2012, in the first half of 2013.

Cost of Capital

A cost of capital proceeding determines a utility’s authorized capital structure and authorized rate of return on rate base (ROR), which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE). The authorized ROR is the rate that the California Utilities are authorized to use in establishing rates to recover the cost of debt and equity used to finance their investment in electric and natural gas distribution, natural gas transmission and electric generation assets. In addition, a cost of capital proceeding also addresses the automatic ROR adjustment mechanism which applies market-based benchmarks to determine whether an adjustment to the authorized ROR is required during the interim years between cost of capital proceedings.

SDG&E and SoCalGas filed separate applications with the CPUC in April 2012 to update their cost of capital effective January 1, 2013. Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E) also filed separate cost of capital applications with the CPUC. SDG&E proposed to adjust its authorized capital structure by increasing the amount of its common equity from 49.0 percent to 52.0 percent. SDG&E also proposed to lower its authorized ROE from 11.1 percent to 11.0 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.40 percent to 8.15 percent. SoCalGas proposed to adjust its authorized capital structure by increasing the amount of its common equity from 48.0 percent to 52.0 percent. SoCalGas also proposed to increase its authorized ROE from 10.82 percent to 10.9 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.68 percent to 8.44 percent. In addition, SDG&E proposed to continue its currently approved cost of capital adjustment mechanism, which uses a utility bond benchmark. SoCalGas proposed switching from its current cost of capital adjustment mechanism, which is based on U.S. Treasury Bonds, to a mechanism using the same utility bond benchmark as SDG&E. Both SDG&E and SoCalGas proposed adding an “off ramp” provision to the adjustment mechanism as a safeguard to protect against extreme changes in interest rates and to allow the CPUC latitude to suspend the annual mechanism if prudent.

The CPUC issued a ruling in June 2012 bifurcating the proceeding. Phase 1 addressed each utility’s cost of capital for 2013, with a final decision issued in December 2012, details of which follow. Phase 2 addresses the cost of capital adjustment mechanisms for SDG&E, SoCalGas, Edison and PG&E, with a final decision expected in the first half of 2013.

The CPUC’s final decision for Phase 1 authorized the capital structure and rates of returns as outlined in the table below:

COST OF CAPITAL FINAL DECISION RECAP

SDG&E				SoCalGas
Authorized Weighting	Authorized Rate of Recovery	Weighted Authorized ROR		Authorized Weighting	Authorized Rate of Recovery	Weighted Authorized ROR
45.25%	5.00%	2.26%	Long-Term Debt	45.60%	5.77%	2.63%
2.75%	6.22%	0.17%	Preferred Stock	2.40%	6.00%	0.14%
52.00%	10.30%	5.36%	Common Equity	52.00%	10.10%	5.25%
100.00%		7.79%		100.00%		8.02%

These newly authorized rates of returns are effective January 1, 2013 and, when compared to the rates of returns that were in effect through December 31, 2012, will result in a reduction of SDG&E’s and SoCalGas’ annual authorized revenue by $34 million and $22 million, respectively.

SDG&E, SoCalGas, PG&E, Edison and the DRA sponsored a joint stipulation in Phase 2 of the proceeding. As proposed, SDG&E would retain its current cost of capital adjustment mechanism, discussed below, and SoCalGas would implement this same adjustment mechanism. Both utilities would forgo their proposed off-ramp provision. The joint stipulation is unopposed and was accepted into the record of the proceeding at an evidentiary hearing in January 2013. A draft decision was issued on February 22, 2013 approving the joint stipulation as submitted. A final CPUC decision is expected in the second quarter of 2013.

SDG&E’s current, and SoCalGas’ proposed, cost of capital adjustment mechanism benchmark is based on the 12-month average monthly A-rated utility bond yield as published by Moody’s for the 12-month period October through September of each fiscal year. If the 12-month average falls outside of a specified range, then the utility’s authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the mid-point of the specified range. In addition, the utility’s authorized recovery rate for the cost of debt and preferred stock would also be adjusted to their respective actual weighted average cost. Therefore, for intervening years between scheduled cost of capital updates, the utility’s authorized ROR would adjust, upward or downward, as a result of all three adjustments with the new rate going into effect on January 1 following the year in which the benchmark range was exceeded.

Natural Gas Pipeline Operations Safety Assessments

Various regulatory agencies, including the CPUC, are evaluating natural gas pipeline safety regulations, practices and procedures. In February 2011, the CPUC opened a forward-looking rulemaking proceeding to examine what changes should be made to existing pipeline safety regulations for California natural gas pipelines. The California Utilities are parties to this proceeding.

In June 2011, the CPUC directed SoCalGas, SDG&E, PG&E and Southwest Gas to file comprehensive implementation plans to test or replace all natural gas transmission pipelines that have not been pressure tested. The California Utilities filed their Pipeline Safety Enhancement Plan (PSEP) with the CPUC in August 2011. The proposed safety measures, investments and estimated costs are not included in the California Utilities’ 2012 GRC requests discussed above, but the associated cost recovery and return of and on invested capital will be determined as part of the Triennial Cost Allocation Proceeding (TCAP), as we discuss below. The comprehensive plan covers all of the utilities’ approximately 4,000 miles of transmission lines (3,750 miles for SoCalGas and 250 miles for SDG&E) and would be implemented in two phases:

§	Phase 1 focuses on populated areas of SoCalGas’ and SDG&E’s service territories and would be implemented over a 10-year period, from 2012 to 2022.

§	Phase 2 covers unpopulated areas of SoCalGas’ and SDG&E’s service territories and will be filed with the CPUC at a later date.

The total cost estimate for Phase 1, over the 10-year period of 2012 to 2022, is $3.1 billion ($2.5 billion for SoCalGas and $600 million for SDG&E). In their August 2011 filing, the utilities requested the CPUC to authorize funding for the recovery of costs through 2015 of approximately $1.5 billion for SoCalGas, of which $1.2 billion would be capital investment, and $240 million for SDG&E, of which $230 million would be capital investment. After 2015, the utilities proposed to include the costs of the PSEP in their next General Rate Case (for their authorized revenue requirements in 2016). The utilities also proposed that the cost of the program be recovered through a surcharge, rather than by incorporating it into rates. The surcharge would increase over time, as more project work is completed.

In December 2011, the assigned Commissioner to the rulemaking proceeding for the pipeline safety regulations ruled that SDG&E’s and SoCalGas’ TCAP would be the most logical proceeding to conduct the reasonableness and ratemaking review of the companies’ PSEP.

In January 2012, the CPUC Consumer Protection and Safety Division (CPSD) issued a Technical Report on the California Utilities’ PSEP. The report, along with testimony and evidentiary hearings, will be used to evaluate the PSEP in the regulatory process. Generally, the report found that the PSEP approach to pipeline replacement and pressure testing and other proposed enhancements is reasonable.

In February 2012, the assigned Commissioner in the TCAP issued a ruling setting a schedule for the review of the SDG&E and SoCalGas PSEP with evidentiary hearings held in August 2012. SDG&E and SoCalGas expect a final decision in 2013. In April 2012, the CPUC issued an interim decision in the rulemaking proceeding formally transferring the PSEP to the TCAP and authorizing SDG&E and SoCalGas to establish regulatory accounts to record the incremental costs of initiating the PSEP prior to a final decision on the PSEP. The TCAP proceeding will address the recovery of the costs recorded in the regulatory account.

In April 2012, the CPUC issued a decision expanding the scope of the rulemaking proceeding to incorporate the provisions of California Senate Bill (SB) 705, which requires gas utilities to develop and implement a plan for the safe and reliable operation of their gas pipeline facilities. SDG&E and SoCalGas submitted their pipeline safety plans in June 2012. The CPUC decision also orders the utilities to undergo independent management and financial audits to assure that the utilities are fully meeting their safety responsibilities. CPSD will select the independent auditors and will oversee the audits. A schedule for the audits has not been established.

In December 2012, the CPUC issued a final decision accepting the utility safety plans filed pursuant to SB 705.

Natural Gas Pipeline Safety Legislation

In October 2011, the California legislature enacted five separate legislative bills (SB44, SB216, SB705, SB879 and AB56) that address natural gas pipeline safety. Each bill addresses a different aspect of natural gas pipeline safety and imposes requirements on the CPUC and the natural gas pipeline operator. These include such things as the development of a safety plan; installation of automatic shut-off and remote controlled gas valves; emergency response; reporting; ratemaking; and increasing the maximum penalty for gas pipeline safety violations. Much of the legislation is addressed by the utility safety plans reviewed and approved by the CPUC in December 2012, and the California Utilities do not expect that the legislation will have a material impact on their results of operations, financial condition or cash flows.

Utility Incentive Mechanisms

The CPUC applies performance-based measures and incentive mechanisms to all California investor-owned utilities, under which the California Utilities have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties. Both SDG&E and SoCalGas have incentive mechanisms associated with:

§	operational incentives

§	energy efficiency

SoCalGas has additional incentive mechanisms associated with:

§	natural gas procurement

§	unbundled natural gas storage and system operator hub services

Incentive awards are included in our earnings when we receive any required CPUC approval of the award. We would record penalties for results below the specified benchmarks in earnings when we believe it is more likely than not that the CPUC would assess a penalty.

We provide a summary of the incentive awards recognized below.

UTILITY INCENTIVE AWARDS 2010-2012
(Dollars in millions)
	Years ended December 31,
	2012		2011		2010
Sempra Energy Consolidated
Energy efficiency	$	6	$	16	$	15
Unbundled natural gas storage and hub services		3		4		15
Natural gas procurement		6		6		12
Operational incentives		5		3		1
Total awards	$	20	$	29	$	43
SDG&E
Energy efficiency	$	3	$	14	$	5
Operational incentives		2		1		1
Total awards	$	5	$	15	$	6
SoCalGas
Energy efficiency	$	3	$	2	$	10
Unbundled natural gas storage and hub services		3		4		15
Natural gas procurement		6		6		12
Operational incentives		3		2		―
Total awards	$	15	$	14	$	37

Energy Efficiency

The CPUC established incentive mechanisms that are based on the effectiveness of energy efficiency programs. In December 2010, the CPUC awarded $5.1 million and $9.9 million to SDG&E and SoCalGas, respectively, as the final true-up incentive awards for the 2006 – 2008 program period, which amounts incorporated the California Utilities’ petition to correct computational errors. In December 2011, the CPUC awarded $13.7 million to SDG&E and $2.0 million to SoCalGas for their 2009 program year results.

The CPUC issued a final decision in December 2012 adopting a mechanism for the 2010 – 2012 program cycle and approving shareholder awards of $3.3 million for SDG&E and $2.7 million for SoCalGas for their energy efficiency program performance in 2010 under the mechanism. The decision established an annual process for the utilities to obtain awards for their performance in 2011 and 2012. Incentives for the 2011 and 2012 program years would be awarded in 2013 and 2014, respectively.

We expect a final decision on an incentive mechanism for the 2013 – 2014 program period in 2013.

Unbundled Natural Gas Storage and System Operator Hub Services

The CPUC has established a revenue sharing mechanism, effective through 2014, which provides for the sharing between ratepayers and SoCalGas (shareholders) of the net revenues generated by SoCalGas’ unbundled natural gas storage and system operator hub services. SoCalGas is seeking to extend the mechanism through 2015. Annual net revenues (revenues less allocated service costs) under the mechanism are shared on a graduated basis, as follows:

§	the first $15 million of net revenue to be shared 90 percent ratepayers/10 percent shareholders;

§	the next $15 million of net revenue to be shared 75 percent ratepayers/25 percent shareholders;

§	all additional net revenues to be shared evenly between ratepayers and shareholders; and

§	the maximum total annual shareholder-allocated portion of the net revenues cannot exceed $20 million.

Natural Gas Procurement

The California Utilities procure natural gas on behalf of their core natural gas customers. The CPUC has established incentive mechanisms to allow the California Utilities the opportunity to share in the savings and/or costs from buying natural gas for their core customers at prices below or above monthly market-based benchmarks. SoCalGas procures natural gas for SDG&E’s core natural gas customers’ requirements. SoCalGas’ gas cost incentive mechanism (GCIM) is applied on the combined portfolio basis.

In June 2012, SoCalGas applied to the CPUC for approval of a GCIM award of $5.4 million for natural gas procured for its core customers during the 12-month period ending March 31, 2012. SoCalGas expects a CPUC decision in the first half of 2013.

In the first quarter of 2012, the CPUC approved and SoCalGas recorded SoCalGas’ application for its GCIM award of $6.2 million for natural gas procured for its core customers during the 12-month period ending March 31, 2011.

In September 2011, the CPUC approved SoCalGas’ application for its GCIM award of $6 million for natural gas procured for its core customers during the 12-month period ending March 31, 2010.

In January 2010, the CPUC approved a GCIM award of $12 million for SoCalGas’ procurement activities during the 12-month period ending March 31, 2009.

Operational Incentives

The CPUC may establish operational incentives and associated performance benchmarks as part of a general rate case or cost of service proceeding. Through the end of 2011, the California Utilities had operational incentives that applied to their performance in the area of employee safety. Any performance incentives for 2012 and thereafter would be established in the California Utilities’ GRC proceeding, currently pending before the CPUC.

Air Quality and Greenhouse Gas Regulation

The California Legislature enacted Assembly Bill 32 (AB 32) and California Senate Bill 1368 in 2006. These laws mandate, among other things, reductions in greenhouse gas (GHG) emissions and the payment of GHG administration fees annually. The California Air Resources Board (CARB), the agency responsible for establishing the compliance rules and regulations for the regulation of GHG under AB 32, has adopted a number of regulations pursuant to AB 32, including CARB’s GHG administration fees regulation and its GHG emissions trading regulation.

In October 2011, the CARB finalized details of the cap and trade regulation authorized by AB 32. CARB intends to implement its cap and trade program in 2013. Certain legal challenges have been raised by numerous parties regarding the implementation of cap and trade. No injunction has been issued by any court delaying adoption of the cap and trade program and it is proceeding forward.

These legislative and regulatory mandates could affect costs and growth at the California Utilities and at our natural gas-fired power plants in Arizona and Mexico. Any cost impact at the California Utilities is expected to be recoverable through rates. As discussed in Note 15 under “Environmental Issues,” compliance with this and similar legislation could adversely affect our Sempra Natural Gas and Sempra Mexico segments. However, such legislation could also have a positive impact on our natural gas and renewables businesses because of an increasing preference for natural gas and renewables for electric generation, as opposed to other sources.

SDG&E MATTERS

San Onofre Nuclear Generating Station (SONGS)

SDG&E has a 20-percent ownership interest in San Onofre Nuclear Generating Station (SONGS), a 2,150-MW nuclear generating facility near San Clemente, California. SONGS is operated by Edison and is subject to the jurisdiction of the Nuclear Regulatory Commission (NRC) and the CPUC.

In 2005, the CPUC authorized a project to install four new steam generators in Units 2 and 3 at SONGS and remove and dispose of their predecessor generators. Edison completed the installation of these steam generators in 2010 and 2011 for Units 2 and 3, respectively. In January 2012, a water leak occurred in the Unit 3 steam generator which caused it to be shut down. Edison conducted inspection testing and determined that the water leak was the result of excessive wear from tube-to-tube contact. During a planned maintenance and refueling outage on the Unit 2 steam generators in February 2012, inspections found high levels of unexpected wear in some heat transfer tubes of the Unit 2 steam generators. As a result of these findings, Edison has plugged and removed from service all tubes showing excessive wear in each of the steam generators. In addition, Edison has preventively plugged all tubes in contact with the retainer bars or in the area of the tube bundles where tube-to-tube contact occurred. As of the filing date of this report, both Units 2 and 3 remain offline.

Any remedial action that will permit restart of one or both of the Units will need to be approved by the NRC. In March 2012, the NRC issued a Confirmatory Action Letter (CAL) that required NRC permission to restart Unit 2 and Unit 3 and outlined actions that Edison must complete before permission to restart either Unit may be sought. The NRC could also choose to impose additional inspections and assessment processes that could result in significant costs or additional delay. In October 2012, Edison submitted a restart plan to the NRC for Unit 2, proposing to operate Unit 2 at a reduced power level for five months and then shut it down for further inspection. The plan submitted to the NRC does not address Unit 3. It is not clear at this time whether Unit 3 can be restarted without extensive additional repairs, and Edison has not indicated when it believes Unit 3 may be ready to restart operations. The timing of the restart of either of the Units is dependent upon approval by the NRC. The NRC may employ other procedures before making any determination about whether to grant permission pursuant to the terms of the CAL. It is also possible that one or more amendments to the NRC operating license for SONGS might be required (whether or not as a prerequisite to return a Unit to safe operation). There is no set or predetermined time period for such processes, and, accordingly, there can be no assurance about the length of time the NRC may take to review any request to restart submitted by Edison under the CAL or whether any such request would be granted in whole or in part.

Through December 31, 2012, SDG&E’s proportional investment in the steam generators, net of accumulated depreciation, was approximately $179 million. These investment amounts remain subject to CPUC review upon submission of Edison’s final costs for the overall project.

During the unscheduled outage at SONGS, SDG&E has procured replacement power, the cost of which is fully recovered in revenues subject to a reasonableness review by the CPUC. Replacement power costs, in excess of avoided nuclear fuel costs, incurred by SDG&E as a result of the unscheduled SONGS outage (commencing in 2012 on January 31 for Unit 3 and March 5 for Unit 2) through December 31, 2012 were approximately $77 million. Total replacement power costs will not be known until the Units are returned to service.

Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. For the year ended December 31, 2012, SDG&E has recognized (and collected through customer rates) an estimated $199 million of revenue associated with its investment in SONGS and related operating costs. Following is a summary of SDG&E’s December 31, 2012 net book investment, excluding any decommissioning-related assets and liabilities, and its rate base investment in SONGS:

SUMMARY OF SDG&E NET BOOK INVESTMENT AND RATE BASE INVESTMENT IN SONGS(1)
(Dollars in millions)
			Unit 2		Unit 3		Common Plant		Total
Net book investment:
	Net property, plant and equipment, including
	construction work in progress	$	152	$	115	$	120	$	387
	Materials and supplies		―		―		10		10
	Nuclear fuel		―		―		115		115
	Net book investment	$	152	$	115	$	245	$	512

Rate base investment		$	103	$	93	$	79	$	275
(1)	Excludes nuclear decommissioning-related assets and liabilities.

In November 2012, the CPUC issued an Order Instituting Investigation (OII) into the SONGS outage pursuant to California Public Utilities Code Section 455.5 to determine whether Edison and SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires that all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account, with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, will be required to be refunded to customers.

Under Section 455.5, any determination to adjust rates would be made after hearings are conducted in connection with Edison’s next general rate case. If, after investigation and hearings, the CPUC were to require SDG&E to reduce rates as a result of a Unit being out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation. Notwithstanding the requirements of Section 455.5, the CPUC may institute other proceedings relating to the impact of the extended outage at SONGS and its potential effects on rates.

A ruling was issued in January 2013 setting the initial scope and schedule for the OII, which will be managed in phases. The first phase will identify the costs at issue for 2012, with a decision expected by mid-2013. Phase 2 will address the issue of costs remaining in rates, with a decision expected by the end of 2013. Phase 3 will review the steam generator replacement project costs for reasonableness, with a decision expected by the end of 2014. Costs at issue for 2013 would be addressed in a fourth phase of the OII, but a schedule for this phase has not been established.

The steam generators were designed and supplied by Mitsubishi Heavy Industries (MHI) and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. On July 18, 2012, the NRC issued a report providing the result of the inspection performed by the Augmented Inspection Team (AIT). The inspection concluded that faulty computer modeling that inadequately predicted conditions in the steam generators at SONGS and manufacturing issues contributed to excessive wear of the components. The most probable causes of the tube-to-tube wear were a combination of higher than predicted thermal/hydraulic conditions and changes in the manufacturing of the Unit 3 steam generators. This report also identified a number of yet unresolved issues that are continuing to be examined. Edison’s purchase contract with MHI states that MHI’s liability under the purchase agreement is limited to $138 million and excludes consequential damages, defined to include the cost of replacement power. Such limitations in the contract are subject to certain exceptions. In late 2012, Edison submitted invoices on behalf of all owners to MHI in the aggregate amount of $53 million for certain steam generator repair costs incurred, of which MHI has paid $45 million but reserved the right to challenge any of the charges in the invoice. In January 2013, MHI advised Edison that it rejected a portion of the first invoice and required further documentation regarding the remainder of the invoice. Edison expects to continue to invoice MHI for any additional costs incurred.

SDG&E is a named insured on the Edison insurance policies covering SONGS. These policies, issued by Nuclear Electric Insurance Limited (NEIL), cover nuclear property and non-nuclear property damage at the SONGS facility, as well as accidental outage insurance. Edison has placed NEIL on notice of potential claims for loss recovery. In October 2012, Edison submitted to NEIL a Partial Proof of Loss on behalf of Edison, SDG&E and the City of Riverside in connection with the outages of SONGS Units 2 and 3. The NEIL policies contain a number of exclusions and limitations that may reduce or eliminate coverage. SDG&E will assist Edison in pursuing claims recoveries from NEIL, as well as warranty claims with MHI, but there is no assurance that SDG&E will recover all or any of its applicable costs pursuant to these arrangements. We provide additional information about insurance related to SONGS in Note 15.

In light of the aftermath and the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the earthquake and tsunami in March 2011, the NRC plans to perform additional operation and safety reviews of nuclear facilities in the United States. The lessons learned from the events in Japan and the results of the NRC reviews may materially impact future operations and capital requirements at nuclear facilities in the United States, including the operations and capital requirements at SONGS.

Edison is also addressing a number of other regulatory and performance issues at SONGS, and the NRC has required Edison to take actions to provide greater assurance of compliance by SONGS personnel. Edison continues to implement plans and address the identified issues, however a number of these issues remain outstanding. To the extent that these issues persist, it is likely that additional action will be required by Edison, which may result in increased SONGS operating costs and/or materially adversely impacted operations. Currently, SDG&E is allowed to fully offset its share of SONGS operating costs in revenue. If further action is required, it may result in an increase in SDG&E’s Operation and Maintenance expense, with any increase being fully offset in Operating Revenues – Electric.

Power Procurement and Resource Planning

Background—Electric Industry Regulation

California’s legislative response to the 2000 – 2001 energy crisis resulted in the DWR purchasing a substantial portion of power for California’s electricity users. In 2001, the DWR entered into long-term contracts with suppliers, including Sempra Natural Gas, to provide power for the utility procurement customers of each of the California investor-owned utilities (IOUs), including SDG&E. The CPUC allocates the power and its administrative responsibility, including collection of power contract costs from utility customers, among the IOUs. The last of these contracts expires in 2013.

Effective in 2003, the IOUs resumed responsibility for electric commodity procurement above their allocated share of the DWR’s long-term contracts, and the CPUC:

§	directed the IOUs, including SDG&E, to resume electric commodity procurement to cover their net short energy requirements, which are the total customer energy requirements minus supply from resources owned, operated or contracted;

§	implemented legislation regarding procurement and renewable energy portfolio standards; and

§	established a process for review and approval of the utilities’ long-term resource and procurement plans.

This process is intended to identify anticipated needs for generation and transmission resources in order to support transmission grid reliability and to better serve customers.

Renewable Energy

SDG&E is subject to the Renewables Portfolio Standard (RPS) Program administered by both the CPUC and the California Energy Commission (CEC), which requires each California utility to procure 33 percent of its annual electric energy requirements from renewable energy sources by 2020, with an average of 20 percent required from January 1, 2011 to December 31, 2013; 25 percent by December 31, 2016; and 33 percent by December 31, 2020. The CPUC began a rulemaking in May 2011 to address the implementation of the 33% RPS Program.

The 33% RPS Program contains flexible compliance mechanisms that can be used to comply with or meet the 33% RPS Program mandates in 2011 and beyond. The mechanisms provide for a CPUC waiver under certain conditions, including: 1) a finding of inadequate transmission, 2) delays in the start-up of commercial operations of renewable energy projects due to permitting or interconnection or 3) unexpected curtailment by an electric system balancing authority, such as the California Independent System Operator (ISO).

SDG&E continues to procure renewable energy supplies to achieve the 33% RPS Program requirements. A substantial number of these supply contracts, however, are contingent upon many factors, including:

§	access to electric transmission infrastructure;

§	timely regulatory approval of contracted renewable energy projects;

§	the renewable energy project developers’ ability to obtain project financing and permitting; and

§	successful development and implementation of the renewable energy technologies.

SDG&E believes it will be able to comply with the 33% RPS Program requirements based on its contracting activity and, if necessary, application of the flexible compliance mechanisms. SDG&E’s failure to comply with the RPS Program requirements could subject it to a CPUC-imposed penalty of 5 cents per kilowatt hour of renewable energy under-delivery.

Cleveland National Forest Transmission Projects

SDG&E filed an application with the CPUC in October 2012 for a permit to construct various transmission replacement projects in and around the Cleveland National Forest. The proposed projects will replace and fire-harden five transmission lines at an estimated cost of $420 million. The projects are subject to federal review by the U.S. Forest Service (USFS). A joint environmental report (EIR/EIS) will be developed by the CPUC and USFS. SDG&E has requested a CPUC decision approving the transmission projects by the third quarter of 2013. We expect the projects to be in service by 2017.

South Orange County Reliability Enhancement

SDG&E filed an application with the CPUC in May 2012 for a Certificate of Public Convenience and Necessity (CPCN) to construct the South Orange County Reliability Enhancement project. The purpose of the project is to enhance the capacity and reliability of SDG&E’s electric service to the south Orange County area. The proposed project primarily includes replacing and upgrading approximately eight miles of transmission lines and rebuilding and upgrading a substation at an existing site. SDG&E expects a final CPUC decision approving the estimated $473 million project in the second half of 2013. SDG&E obtained approval for the project from the ISO in May 2011. The project is planned to be in service by the second half of 2017.

East County Substation

In June 2012, the CPUC approved SDG&E’s application for authorization to proceed with the East County Substation project, estimated to cost $435 million. The Bureau of Land Management (BLM) issued its record of decision in August 2012. SDG&E expects to begin construction by the second quarter of 2013 and the substation to be placed in service in 2014.

SDG&E Purchase of El Dorado

SDG&E purchased Sempra Natural Gas’ El Dorado gas-fired electric generation plant on October 1, 2011, pursuant to an option to acquire the plant that was exercised in 2007. In accordance with the CPUC’s approval, SDG&E acquired El Dorado (renamed Desert Star Energy Center) at a price equal to the closing book value of the plant upon transfer. SDG&E made a compliance filing with the CPUC in September 2011 stating the book value purchase price as $215 million. The final purchase price was $214 million based on the completion of an independent audit of Sempra Natural Gas’ net book value of the plant as of the close of business on September 30, 2011.

FERC Formulaic Rate Filing

SDG&E submitted its Electric Transmission Formula Rate (TO4) filing with the FERC in February 2013 to be effective September 1, 2013. This proceeding will set the rate making methodology and rate of return for SDG&E’s FERC-regulated electric transmission operations and assets. SDG&E’s TO4 filing is requesting a rate making formula that is essentially the same as currently authorized by the FERC. SDG&E’s TO4 filing is requesting: 1) rates to be determined by a base period of historical costs and a forecast of capital investments and 2) a true-up period which is similar to a balancing account that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including it authorized return on investment.

This TO4 proceeding will also set SDG&E’s authorized ROE on FERC rate base. SDG&E’s current authorized FERC ROE is 11.35 percent and SDG&E’s TO4 filing is proposing a FERC ROE of 11.3 percent. SDG&E expects a decision on its TO4 filing in the second half of 2013.

Incremental Insurance Premium Cost Recovery

In December 2010, the CPUC approved SDG&E’s request for a $29 million revenue requirement for the recovery of the incremental increase in its general liability and wildfire liability insurance premium costs for the July 2009/June 2010 policy period. In its decision approving this cost recovery, the CPUC also authorized SDG&E to request recovery of any incremental insurance premiums for future policy periods through December 31, 2011, with a $5 million deductible applied to each policy renewal period. This approval was in response to a request filed by SDG&E with the CPUC in August 2009 seeking authorization to recover higher liability insurance premiums (amounts in excess of those authorized to be recovered in the 2008 GRC), which SDG&E began incurring commencing July 1, 2009, and any losses realized due to higher deductibles associated with the new policies. SDG&E made the filing under the CPUC’s rules allowing utilities to seek recovery of significant cost increases incurred between GRC filings that meet certain criteria, subject to a $5 million deductible per event.

In December 2011, the CPUC approved SDG&E’s request for an incremental revenue requirement of $63 million for the July 2010/June 2011 policy period. In May 2012, the CPUC approved SDG&E’s request for a $28 million revenue requirement for the first six months of the July 2011/June 2012 policy period.

In the CPUC’s December 2010 decision, discussed above, the CPUC directed SDG&E to include in its 2012 GRC application the amount of the incremental wildfire insurance premiums it would be seeking recovery for in rates subsequent to December 31, 2011. SDG&E’s 2012 GRC application does request $67 million of revenue requirement for cost recovery of wildfire insurance premiums in 2012. As a decision on SDG&E’s 2012 GRC application is pending with the CPUC, and based on the CPUC’s rulings for the recovery of the cost of the incremental wildfire insurance premiums incurred since July 2009, SDG&E’s 2012 revenue through December 31, 2012 reflects the expected recovery of the cost of the incremental wildfire insurance premiums incurred in the current year.

Excess Wildfire Claims Cost Recovery

SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC in August 2009 proposing a new framework and mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. This application was made jointly with Edison and PG&E. In July 2010, the CPUC approved SDG&E’s and SoCalGas’ requests for separate regulatory memorandum accounts to record the subject expenses while the application was pending before the CPUC. Several parties protested the original application and, in response, the four utilities jointly submitted an amended application in August 2010. In November 2011, Edison and PG&E requested to withdraw from the joint utility application due, in part, to the delays in the proceeding. In January 2012, the CPUC granted their requests to withdraw and held evidentiary hearings for SDG&E and SoCalGas. Legal briefs were completed in March 2012.

In December 2012, the CPUC issued a final decision that ultimately did not approve the proposed blanket framework for the utilities but allowed SDG&E to maintain its authorized memorandum account, so that SDG&E may file applications with the CPUC requesting recovery of amounts properly recorded in the memorandum account at a later time, subject to reasonableness review.

SDG&E intends to pursue recovery of such costs in a future application. SDG&E will continue to assess the potential for recovery of these costs in rates. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated as of December 31, 2012, the resulting after-tax charge against earnings would have been up to $190 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated cost to litigate or settle pending wildfire claims. We discuss how we assess the probability of recovery of our regulatory assets in Note 1.

We provide additional information about 2007 wildfire litigation costs and their recovery in Note 15.

SOCALGAS MATTERS

Aliso Canyon Natural Gas Storage Compressor Replacement

In September 2009, SoCalGas filed an application with the CPUC requesting approval to replace certain obsolete natural gas turbine compressors used in the operations of SoCalGas’ Aliso Canyon natural gas storage reservoir, with a new electric compressor station. In April 2012, the CPUC issued a draft EIR for the project concluding that no significant or unavoidable adverse environmental impacts have been identified from the construction or operation of the proposed project. We expect a final EIR and CPUC decision on the estimated $200 million project in 2013.

Advanced Metering Infrastructure

In November 2011, the DRA and The Utility Reform Network (TURN) filed a joint petition requesting that the CPUC reconsider its prior approval of SoCalGas’ advanced metering infrastructure (AMI) project and stay AMI deployment while the CPUC considers the request. The CPUC, which is not obligated to respond to such requests, has taken no action in response to the DRA/TURN petition, and SoCalGas is continuing its deployment of AMI pursuant to the April 2010 CPUC decision approving the project.

NOTE 15. COMMITMENTS AND CONTINGENCIES

LEGAL PROCEEDINGS

We accrue losses for legal proceedings when it is probable that a loss has been incurred and the amounts of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to estimate with reasonable certainty the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed applicable insurance coverage and could materially adversely affect our business, cash flows, results of operations, financial condition and prospects. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.

At December 31, 2012, Sempra Energy’s accrued liabilities for material legal proceedings, on a consolidated basis, were $341 million. At December 31, 2012, accrued liabilities for material legal proceedings for SDG&E and SoCalGas were $329 million and $3 million, respectively. At December 31, 2012, liabilities of $327 million at Sempra Energy and SDG&E were related to wildfire litigation discussed below.

SDG&E

2007 Wildfire Litigation

In October 2007, San Diego County experienced several catastrophic wildfires. Reports issued by the California Department of Forestry and Fire Protection (Cal Fire) concluded that two of these fires (the Witch and Rice fires) were SDG&E “power line caused” and that a third fire (the Guejito fire) occurred when a wire securing a Cox Communications’ (Cox) fiber optic cable came into contact with an SDG&E power line “causing an arc and starting the fire.” Cal Fire reported that the Rice fire burned approximately 9,500 acres and damaged 206 homes and two commercial properties, and the Witch and Guejito fires merged and eventually burned approximately 198,000 acres, resulting in two fatalities, approximately 40 firefighters injured and an estimated 1,141 homes destroyed.

A September 2008 staff report issued by the CPUC’s CPSD reached substantially the same conclusions as the Cal Fire reports, but also contended that the power lines involved in the Witch and Rice fires and the lashing wire involved in the Guejito fire were not properly designed, constructed and maintained. In April 2010, proceedings initiated by the CPUC to determine if any of its rules were violated were settled with SDG&E’s payment of $14.75 million.

Numerous parties have sued SDG&E and Sempra Energy in San Diego County Superior Court seeking recovery of unspecified amounts of damages, including punitive damages, from the three fires. These include owners and insurers of properties that were destroyed or damaged in the fires and government entities seeking recovery of firefighting, emergency response, and environmental costs. They assert various bases for recovery, including inverse condemnation based upon a California Court of Appeal decision finding that another California investor-owned utility was subject to strict liability, without regard to foreseeability or negligence, for property damages resulting from a wildfire ignited by power lines.

In October 2010, the Court of Appeal affirmed the trial court’s ruling that these claims must be pursued in individual lawsuits, rather than as class actions on behalf of all persons who incurred wildfire damages. In February 2011, the California Supreme Court denied a petition for review of the affirmance. No trial date is currently scheduled.

SDG&E filed cross-complaints against Cox seeking indemnification for any liability that SDG&E might incur in connection with the Guejito fire, two SDG&E contractors seeking indemnification in connection with the Witch fire, and one SDG&E contractor seeking indemnification in connection with the Rice fire. SDG&E has entered into settlement agreements with Cox and the three contractors for a total of approximately $824 million. Among other things, the settlement agreements provide that SDG&E will defend and indemnify Cox and the three contractors against all compensatory damage claims and related costs arising out of the wildfires.

SDG&E has settled all of the approximately 19,000 claims brought by homeowner insurers for damage to insured property relating to the three fires. Under the settlement agreements, SDG&E has paid or will pay 57.5 percent of the approximately $1.6 billion paid or reserved for payment by the insurers to their policyholders and received an assignment of the insurers’ claims against other parties potentially responsible for the fires.

The wildfire litigation also includes claims of non-insurer plaintiffs for damage to uninsured and underinsured structures, business interruption, evacuation expenses, agricultural damage, emotional harm, personal injuries and other losses. SDG&E has settled the claims of approximately 5,150 of these plaintiffs, including all of the government entities. Approximately 1,200 of the approximately 1,350 remaining individual and business plaintiffs have submitted settlement demands and damage estimates totaling approximately $1.1 billion. SDG&E does not expect significant additional plaintiffs to file lawsuits given the applicable statutes of limitation, but does expect to receive additional settlement demands and damage estimates from existing plaintiffs as settlement negotiations continue. SDG&E has established reserves for the wildfire litigation as we discuss below.

SDG&E’s settled claims and defense costs have exceeded its $1.1 billion of liability insurance coverage and the approximately $824 million recovered from third parties. It expects that its wildfire reserves and amounts paid to resolve wildfire claims will continue to increase as it obtains additional information.

As we discuss in Note 14, SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of its reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and the amounts recovered from third parties. Accordingly, although such recovery will require future regulatory approval, at December 31, 2012, Sempra Energy and SDG&E have recorded assets of $364 million in Regulatory Assets Arising From Wildfire Litigation Costs on their Consolidated Balance Sheets, including $317 million related to CPUC operations, which represents the amount substantially equal to the aggregate amount it has paid or reserved for payment for the resolution of wildfire claims and related costs in excess of its liability insurance coverage and amounts recovered from third parties. SDG&E will increase the regulatory assets if the estimate of amounts to settle remaining claims increases.

SDG&E will continue to assess the recovery of these excess wildfire costs in rates. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated as of December 31, 2012, the resulting after-tax charge against earnings would have been up to $190 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated cost to litigate or settle pending wildfire claims. We provide additional information about excess wildfire claims cost recovery and related CPUC actions in Note 14 and discuss how we assess the probability of recovery of our regulatory assets in Note 1.

SDG&E’s cash flow may be materially adversely affected due to the timing differences between the resolution of claims and the recoveries in rates, which may extend over a number of years. Also, recovery from customers will require future regulatory actions, and a failure to obtain substantial or full recovery, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s businesses, financial condition, cash flows, results of operations and prospects.

SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of related recoveries in rates and will make appropriate adjustments to wildfire reserves and the related regulatory assets as additional information becomes available.

Since 2010, as liabilities for wildfire litigation have become reasonably estimable in the form of settlement demands, damage estimates, and other damage information, SDG&E has recorded related reserves as a liability. The impact of this liability at December 31, 2012 is offset by the recognition of regulatory assets, as discussed above, for reserves in excess of the insurance coverage and recoveries from third parties. The impact of the reserves on SDG&E’s and Sempra Energy’s after-tax earnings was a decrease of $6 million, $13 million and $20 million for the years ended December 31, 2012, 2011 and 2010, respectively. At December 31, 2012, wildfire litigation reserves were $327 million ($305 million in current and $22 million in long-term). Additionally, through December 31, 2012, SDG&E has expended $128 million (cumulative, excluding amounts covered by insurance and amounts recovered from third parties) to pay for the settlement of wildfire claims and related costs.

Sunrise Powerlink Electric Transmission Line

The Sunrise Powerlink is a new 117-mile, 500-kilovolt (kV) electric transmission line between the Imperial Valley and the San Diego region that was energized and placed in service in June 2012. The Sunrise Powerlink project was approved by the CPUC in December 2008, the BLM in January 2009, and the USFS in July 2010. Numerous administrative appeals and legal challenges have been resolved in favor of the project. Three legal challenges are pending.

In February 2010, project opponents filed a lawsuit in Federal District Court in San Diego alleging that the BLM failed to properly address the environmental impacts of the approved Sunrise Powerlink route and the related potential development of renewable resources in east San Diego County and Imperial County. In July 2012, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court’s grant of the defendants’ motion for summary judgment.

In January 2011, project opponents filed a lawsuit in Federal District Court in San Diego alleging that the federal approvals for construction of the project on USFS land and BLM land violated the National Environmental Policy Act and other federal environmental laws. In June 2012, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court’s denial of plaintiffs’ motion for a preliminary injunction.

In February 2011, opponents of the Sunrise Powerlink filed a lawsuit in Sacramento County Superior Court against the State Water Resources Control Board and SDG&E alleging that the water quality certification issued by the Board under the Federal Clean Water Act violated the California Environmental Quality Act. The Superior Court denied the plaintiffs’ petition in July 2012, and the plaintiffs have appealed.

September 2011 Power Outage

In September 2011, a power outage lasting approximately 12 hours affected millions of people from Mexico to southern Orange County, California. Within several days of the outage, several SDG&E customers filed a class action lawsuit in Federal District Court in San Diego against Arizona Public Service Company, Pinnacle West, and SDG&E alleging that the companies failed to prevent the outage. The lawsuit seeks recovery of unspecified amounts of damages, including punitive damages. In July 2012, the court granted SDG&E’s motion to dismiss the punitive damages request and dismissed Arizona Public Service Company and Pinnacle West from the lawsuit. In addition, more than 7,000 customers’ claims, primarily related to food spoilage, have been submitted directly to SDG&E. The FERC and North American Electric Reliability Corporation (NERC) conducted a joint inquiry to determine the cause of the power failure and issued a report in May 2012 regarding their findings. The report does not include any findings of failure on SDG&E’s part that led to the power failure.

Smart Meters Patent Infringement Lawsuit

In October 2011, SDG&E was sued by a Texas design and manufacturing company in Federal District Court, Southern District of California, and later transferred to the Federal District Court, Western District of Oklahoma, alleging that SDG&E’s recently installed smart meters infringed certain patents. The meters were purchased from a third party vendor that has agreed to defend and indemnify SDG&E. The lawsuit seeks injunctive relief and recovery of unspecified amounts of damages.

SoCalGas

SoCalGas, along with Monsanto Co., Solutia, Inc., Pharmacia Corp., and Pfizer, Inc., are defendants in six Los Angeles County Superior Court lawsuits filed beginning in April 2011 seeking recovery of unspecified amounts of damages, including punitive damages, as a result of plaintiffs’ exposure to PCBs (polychlorinated biphenyls). The lawsuits allege plaintiffs were exposed to PCBs not only through the food chain and other various sources but from PCB-contaminated natural gas pipelines owned and operated by SoCalGas. This contamination allegedly caused plaintiffs to develop cancer and other serious illnesses. Plaintiffs assert various bases for recovery, including negligence and products liability. SoCalGas has settled two of the five lawsuits for an amount that is not significant and has been recorded.

Sempra Natural Gas

Liberty Gas Storage, LLC (Liberty) received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. (Williams) in February 2011 related to a sublease agreement. Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million. Liberty filed a counterclaim alleging breach of contract in the inducement and seeks damages of more than $215 million.

Sempra Mexico

Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its Energía Costa Azul LNG terminal near Ensenada, Mexico. The adjacent property is not required by environmental or other regulatory permits for the operation of the terminal. A claimant to the adjacent property has nonetheless asserted that his health and safety are endangered by the operation of the facility. In February 2011, based on a complaint by the claimant, the new Ensenada Mayor attempted to temporarily close the terminal based on claims of irregularities in municipal permits issued six years earlier. This attempt was promptly countermanded by Mexican federal and Baja California state authorities. No terminal permits or operations were affected as a result of these proceedings or events and the terminal has continued to operate normally. Sempra Mexico expects additional Mexican court proceedings and governmental actions regarding the claimant’s assertions as to whether the terminal’s permits should be modified or revoked in any manner.

The property claimant also filed a lawsuit in July 2010 against Sempra Energy in Federal District Court in San Diego seeking compensatory and punitive damages as well as the earnings from the Energía Costa Azul LNG terminal based on his allegations that he was wrongfully evicted from the adjacent property and that he has been harmed by other allegedly improper actions.

Additionally, several administrative challenges are pending in Mexico before the Mexican environmental protection agency (SEMARNAT) and/or the Federal Tax and Administrative Courts seeking revocation of the environmental impact authorization (EIA) issued to Energía Costa Azul in 2003. These cases generally allege that the conditions and mitigation measures in the EIA are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines. Also, there are two real property cases pending against Energía Costa Azul in which the plaintiffs seek to annul the recorded property titles for parcels on which the Energía Costa Azul LNG terminal is situated and to obtain possession of different parcels that allegedly sit in the same place. Sempra Mexico expects further proceedings on each of these matters.

In July 2012, a Mexicali state court issued a ruling declaring the purchase contract by which Termoeléctrica de Mexicali (TDM) acquired the property on which the facility is located to be invalid, on the grounds that the proceeding in which the seller acquired title was invalid. TDM has appealed the ruling, and it is not enforceable while the appeal is pending. In accordance with Mexican law, TDM remains in possession of the property, and its operations have not been affected.

In October 2012, a competitor for one of the two contracts awarded by the Mexican Federal Electricity Commission (Comisión Federal de Electricidad, or CFE) for the construction and operation of a natural gas pipeline in Sonora filed an amparo in the Mexican federal district court in Mexico City, challenging the tender process and the award to us. The competitor, a subsidiary of Fermaca, Sásabe Pipeline, S. de R.L. de C.V., filed suit against 11 different governmental authorities, including the CFE, the President of Mexico, and the Mexican Energy Ministry. Sásabe Pipeline, which was the second-place bidder, alleges CFE discriminated against it in the bidding process, including by failing to accept its comments on the bid guidelines. In February 2013, we were notified that Guaymas Pipeline S. de R. L. de C.V., another subsidiary of Fermaca, filed another, similar amparo challenging the process by which the second of the two contracts was awarded, although it did not submit a bid for the project. No dates have yet been set for the constitutional hearings, and Sempra Mexico’s contracts remain in place.

Other Litigation

In August 2007, the U.S. Court of Appeals for the Ninth Circuit issued a decision reversing and remanding certain FERC orders declining to provide refunds regarding short-term bilateral sales up to one month in the Pacific Northwest for the December 2000 to June 2001 time period. In December 2010, the FERC approved a comprehensive settlement previously reached by Sempra Energy and RBS Sempra Commodities with the State of California. The settlement resolves all issues with regard to sales between the DWR and Sempra Commodities in the Pacific Northwest, but potential claims may exist regarding sales in the Pacific Northwest between Sempra Commodities and other parties. The FERC is in the process of addressing these potential claims on remand. Pursuant to the agreements related to the formation of RBS Sempra Commodities, we have indemnified RBS should the liability from the final resolution of these matters be greater than the reserves related to Sempra Commodities. Pursuant to our agreement with the Noble Group Ltd., one of the buyers of RBS Sempra Commodities’ businesses, we have also indemnified Noble Americas Gas & Power Corp. and its affiliates for all losses incurred by such parties resulting from these proceedings as related to Sempra Commodities.

Sempra Energy and several subsidiaries, along with three oil and natural gas companies, the City of Beverly Hills, and the Beverly Hills Unified School District, were defendants in toxic tort lawsuits filed beginning in 2003 in Los Angeles County Superior Court by approximately 1,000 plaintiffs. These lawsuits claimed that various emissions resulted in cancer or fear of cancer. In November 2006, the court granted the defendants’ summary judgment motions based on lack of medical causation for the 12 initial plaintiffs scheduled to go to trial first. The court also granted summary judgment excluding punitive damages. In June 2010, a settlement as to Sempra Energy and its subsidiaries was reached for an amount that was not significant and was recorded. The settlement was finalized in August 2012.

As described in Note 4, we hold a noncontrolling interest in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. In March 2012, RBS received a letter from the United Kingdom’s Revenue and Customs Department (HMRC) regarding a value-added-tax (VAT) matter related to RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan. The letter states that HMRC is conducting a number of investigations into VAT tax refund claims made by various businesses related to the purchase and sale of carbon credit allowances. The letter also states that HMRC believes it has grounds to deny RBS the ability to reduce its VAT liability by VAT paid during 2009 because it knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. In September 2012, HMRC issued an assessment of £86 million for the VAT paid in connection with these transactions and identified several options for responding, including requesting a review by HMRC and appealing to an independent tribunal. HMRC indicated that the assessment was issued on a protective basis as discussion about the issues is continuing.

We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, product liability, property damage and other claims. California juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.

Resolved Matters

We discuss certain commitments remaining from an energy crisis matter resolved prior to 2010 below under “Other Commitments.”

The following is a description of the 2010 litigation settlements relating to California energy crisis matters.

Energy Crisis Litigation Settlement

In 2010, Sempra Energy, RBS Sempra Commodities and Sempra Natural Gas reached a comprehensive settlement with the State of California to resolve substantially all of their remaining litigation arising out of the 2000 – 2001 California energy crisis for a total payment of $410 million. The matters resolved include the settlement of multiple actions brought by the DWR and other parties with respect to the validity, pricing and operation of Sempra Natural Gas’ contract with the DWR and the settlement of the FERC refund and manipulation proceedings against RBS Sempra Commodities. The FERC approved both settlements in December 2010.

The payment of $410 million was funded largely from previously recorded reserves and receivables at RBS Sempra Commodities. Sempra Energy also recorded an additional pretax charge of $159 million in the first quarter of 2010 to provide for the remainder of the settlement, including $139 million at Sempra Natural Gas and $20 million at Sempra Commodities. The amount at Sempra Commodities was reduced by $11 million pretax in the fourth quarter of 2010 to reflect a receipt in January 2011 from an unrelated party that had a joint liability for the claim. In January 2011, Sempra Natural Gas paid $130 million to the DWR under the terms of the settlement agreement.

CONTRACTUAL COMMITMENTS

Natural Gas Contracts

Natural Gas

SoCalGas has the responsibility for procuring natural gas for both SDG&E’s and SoCalGas’ core customers in a combined portfolio. SoCalGas buys natural gas under short-term and long-term contracts for this portfolio. Purchases are from various producing regions in the southwestern U.S., U.S. Rockies, and Canada and are primarily based on published monthly bid-week indices.

SoCalGas transports natural gas primarily under long-term firm interstate pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments with interstate pipeline companies for firm pipeline capacity under contracts that expire at various dates through 2028.

Sempra Natural Gas’ and Sempra Mexico’s businesses have various natural gas purchase agreements to fuel natural gas-fired power plants and capacity agreements for natural gas storage and transportation.

At December 31, 2012, the future minimum payments under existing natural gas contracts and natural gas storage and transportation contracts were:

Sempra Energy Consolidated
		Storage and
(Dollars in millions)		Transportation		Natural Gas(1)		Total(1)
2013		$	135	$	547	$	682
2014			124		105		229
2015			94		13		107
2016			59		13		72
2017			55		13		68
Thereafter			294		28		322
Total minimum payments		$	761	$	719	$	1,480
(1)	Excludes amounts related to LNG purchase agreements as discussed below.

SoCalGas
(Dollars in millions)	Transportation		Natural Gas		Total
2013	$	116	$	422	$	538
2014		105		19		124
2015		75		1		76
2016		40		1		41
2017		36		1		37
Thereafter		158		―		158
Total minimum payments	$	530	$	444	$	974

Total payments under natural gas contracts were:

	Years ended December 31,
(Dollars in millions)	2012		2011		2010
Sempra Energy Consolidated	$	1,345	$	1,991	$	2,097
SoCalGas		1,222		1,810		1,936

LNG

Sempra Natural Gas has various purchase agreements with major international companies for the supply of LNG to the Energía Costa Azul and Cameron terminals. The agreements range from short-term to multi-year periods and are priced using a predetermined formula based on natural gas market indices.

Although these contracts specify a number of cargoes to be delivered, under their terms, customers may divert certain cargoes, which would reduce amounts paid under the contracts by Sempra Natural Gas. As of December 31, 2012, if all cargoes under the contracts were to be delivered, future payments under these contracts would be

§	$565 million in 2013

§	$650 million in 2014

§	$687 million in 2015

§	$721 million in 2016

§	$758 million in 2017

§	$11.3 billion in 2018 – 2029

The amounts above are based on forward prices of the index applicable to each contract from 2013 to 2022 and an estimated one percent escalation per year beyond 2022. The LNG commitment amounts above are based on Sempra Natural Gas’ commitment to accept the maximum possible delivery of cargoes under the agreements. Actual LNG purchases in 2012, 2011 and 2010 have been significantly lower than the maximum amount possible.

Purchased-Power Contracts

For 2013, SDG&E expects to receive 2 percent of its customer power requirements from renewable energy contracts under DWR allocations. The remaining requirements are expected to be met as follows:

§	SONGS: 3 percent

§	Long-term contracts: 31 percent (of which 17 percent is provided by renewable energy contracts expiring on various dates through 2038)

§	Other SDG&E-owned generation (including Palomar, Miramar Energy Center, Desert Star Energy Center and Cuyamaca Peak Energy Plant) and tolling contracts (including OMEC): 50 percent

§	Spot market purchases: 14 percent

The long-term contracts expire on various dates through 2038.

Chilquinta Energía and Luz del Sur also have purchased-power contracts, expiring on various dates extending through 2027, which cover most of the consumption needs of the companies’ customers. These commitments are included under Sempra Energy Consolidated in the table below.

At December 31, 2012, the estimated future minimum payments under long-term purchased-power contracts (not including the DWR allocations for SDG&E) were:

		Sempra
		Energy
(Dollars in millions)		Consolidated		SDG&E
2013		$	1,257	$	405
2014			1,275		383
2015			1,349		372
2016			1,385		372
2017			1,397		368
Thereafter			10,978		3,999
Total minimum payments(1)		$	17,641	$	5,899
(1)	Excludes purchase agreements accounted for as capital leases and amounts related to Otay Mesa VIE, as it is consolidated by Sempra Energy and SDG&E.

Payments on these contracts represent capacity charges and minimum energy purchases. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. Excluding DWR-allocated contracts, total payments under purchased-power contracts were:

	Years ended December 31,
(Dollars in millions)	2012		2011		2010
Sempra Energy Consolidated	$	1,205	$	918	$	314
Sempra South American Utilities		824		572		―
SDG&E		381		346		314

Operating Leases

Sempra Energy, SDG&E and SoCalGas have operating leases on real and personal property expiring at various dates from 2013 through 2054. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from one percent to six percent at both Sempra Energy and SDG&E and one percent to five percent at SoCalGas. The rentals payable under these leases may increase by a fixed amount each year or by a percentage of a base year, and most leases contain extension options that we could exercise.

The California Utilities have an operating lease agreement for future acquisitions of fleet vehicles with RBS Asset Finance, Inc. with an aggregate maximum lease limit of $125 million, $95 million of which has been utilized.

Rent expense for all operating leases totaled:

	Years ended December 31,
(Dollars in millions)	2012		2011		2010
Sempra Energy Consolidated	$	74	$	77	$	85
SDG&E		20		18		20
SoCalGas		26		35		40

At December 31, 2012, the minimum rental commitments payable in future years under all noncancelable operating leases were as follows:

	Sempra
	Energy
(Dollars in millions)	Consolidated		SDG&E		SoCalGas
2013	$	78	$	20	$	29
2014		77		20		29
2015		71		19		29
2016		66		19		27
2017		64		18		25
Thereafter		572		21		198
Total future rental commitments	$	928	$	117	$	337

Capital Leases

Utility Fleet Vehicles

The California Utilities entered into agreements with U.S. Bancorp Equipment Finance in 2009 and with RBS Asset Finance, Inc. in 2010 to refinance existing fleet vehicles. These are capital leases, and as of December 31, 2012, the related capital lease obligations were $11 million at Sempra Energy, including $7 million at SDG&E and $4 million at SoCalGas. As of December 31, 2011, the related capital lease obligations were $24 million at Sempra Energy, including $13 million at SDG&E and $11 million at SoCalGas.

At December 31, 2012, the future minimum lease payments and present value of the net minimum lease payments under these capital leases are as follows:

		Sempra
		Energy
(Dollars in millions)		Consolidated		SDG&E		SoCalGas
2013		$	7	$	4	$	3
2014			3		2		1
2015			1		1		―
Total minimum lease payments		$	11	$	7	$	4
Present value of net minimum lease payments(1)		$	11	$	7	$	4
(1)	Excludes negligible amounts of interest.

The 2012 annual amortization charge for the utility fleet vehicles was $13 million at Sempra Energy, including $7 million at SDG&E and $6 million at SoCalGas. The 2011 annual amortization charge for the utility fleet vehicles was $15 million at Sempra Energy, including $7 million at SDG&E and $8 million at SoCalGas. The 2010 annual amortization charge for the utility fleet vehicles was $17 million at Sempra Energy, including $6 million at SDG&E and $11 million at SoCalGas.

Power Purchase Agreements

SDG&E has two power purchase agreements with peaker plant facilities that went into commercial operation in June 2010 and are accounted for as capital leases. The entities that own the peaker plant facilities are VIEs of which SDG&E is not the primary beneficiary. As of December 31, 2012, capital lease obligations for these leases, each with a 25-year term, were valued at $178 million. SDG&E does not have any additional implicit or explicit financial responsibility to these VIEs.

At December 31, 2012, the future minimum lease payments and present value of the net minimum lease payments under these capital leases for both Sempra Energy Consolidated and SDG&E were as follows:

(Dollars in millions)
	2013	$	24
	2014		24
	2015		24
	2016		24
	2017		24
	Thereafter		419
	Total minimum lease payments(1)		539
	Less: estimated executory costs		(89)
	Less: interest(2)		(272)
	Present value of net minimum lease payments(3)	$	178
(1)	This amount will be recorded over the lives of the leases as Cost of Electric Fuel and Purchased Power on Sempra Energy’s and SDG&E’s Consolidated Statements of Operations. This expense will receive ratemaking treatment consistent with purchased-power costs.
(2)	Amount necessary to reduce net minimum lease payments to present value at the inception of the leases.
(3)	Includes $2 million in Current Portion of Long-Term Debt and $176 million in Long-Term Debt on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets at December 31, 2012.

The annual amortization charge for the power purchase agreements was $2 million for 2012, $2 million for 2011 and $1 million in 2010.

Construction and Development Projects

Sempra Energy has various capital projects in progress in the United States, Mexico and South America. Sempra Energy’s total commitments under these projects are $1.1 billion, requiring future payments of $592 million in 2013, $230 million in 2014, $128 million in 2015, $30 million in 2016, $17 million in 2017 and $80 million thereafter. The following is a summary by segment of contractual commitments and contingencies related to the construction projects.

SDG&E

At December 31, 2012, SDG&E has commitments to make future payments of $379 million for construction projects that include

§	$192 million for the engineering, material procurement and construction costs associated with the East County Substation project;

§	$165 million related to nuclear fuel fabrication and other construction projects at SONGS; and

§	$22 million for infrastructure improvements for natural gas transmission and distribution operations.

SDG&E expects future payments under these contractual commitments to be $229 million in 2013, $36 million in 2014, $11 million in 2015, $24 million in 2016, $17 million in 2017 and $62 million thereafter.

SoCalGas

At December 31, 2012, SoCalGas has commitments to make future payments of $129 million for construction and infrastructure improvements for natural gas transmission and distribution operations, pipeline integrity and the advanced metering infrastructure project. The future payments under these contractual commitments are expected to be $76 million in 2013, $15 million in 2014, $14 million in 2015, $6 million in 2016 and $18 million thereafter.

Sempra South American Utilities

At December 31, 2012, Sempra South American Utilities has commitments to make future payments of $78 million for construction projects that include $70 million for the construction of the Santa Teresa hydroelectric power plant at Luz del Sur. The future payments under these contractual commitments are expected to be $70 million in 2013 and $8 million in 2014.

Sempra Mexico

At December 31, 2012, Sempra Mexico has commitments to make future payments of $279 million for the construction of an approximately 500-mile natural gas transport pipeline. The future payments under these contractual commitments are expected to be $139 million in 2013 and $140 million in 2014.

Sempra Renewables

At December 31, 2012, Sempra Renewables has commitments to make future payments of $183 million for the construction of Mesquite Solar 1 and Copper Mountain Solar 2 facilities. The future payments under these contractual commitments are expected to be $50 million in 2013, $30 million in 2014 and $103 million in 2015.

Sempra Natural Gas

At December 31, 2012, Sempra Natural Gas has commitments to make future payments of $29 million primarily for natural gas storage projects. The future payments under these contractual commitments are expected to be $28 million in 2013 and $1 million in 2014.

GUARANTEES

At December 31, 2012 Sempra Renewables has provided guarantees to its wind farm joint ventures aggregating a maximum of $80 million with an associated aggregated carrying value of $2 million, primarily related to purchased power agreements. In addition, Sempra Renewables has provided guarantees aggregating a maximum of $158 million with an associated aggregated carrying value of $10 million at December 31, 2012 to certain wind farm joint ventures for debt service and operation of the wind farms, which we discuss in Note 5.

As of December 31, 2012, SDG&E and SoCalGas did not have any outstanding guarantees.

DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL

The Nuclear Waste Policy Act of 1982 made the DOE responsible for the disposal of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. This cost will be recovered through SONGS revenue unless SDG&E is able to recover the increased cost from the federal government.

In June 2010, the United States Court of Federal Claims issued a decision granting Edison and the SONGS co-owners damages of approximately $142 million to recover costs incurred through December 31, 2005 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from SONGS. Edison received payment from the federal government in the amount of the damage award in November 2011. In January 2012, Edison refunded SDG&E $28 million for its respective share of the damage award paid. SDG&E recorded a $10 million reduction of nuclear power expenses, a $15 million reduction of its nuclear decommissioning balancing account and a $3 million reduction in nuclear plant. Edison, as operating agent, filed a lawsuit against the DOE in the Court of Federal Claims in December 2011 seeking damages for the period from January 1, 2006 to December 31, 2010 for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel. Additional legal action would be necessary to recover damages incurred after December 31, 2010.

OTHER COMMITMENTS

SDG&E

In connection with the completion of the Sunrise Powerlink project, the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink. The future payments for these contractual commitments are expected to be approximately $3 million per year, subject to escalation of 2 percent per year, for 58 years. At December 31, 2012, the present value of these future payments of $117 million has been recorded as a regulatory asset as the amounts represent a cost that will be recovered from customers in the future, and the related liability was $114 million.

In July 2012, SDG&E received $85 million from Citizens Sunrise Transmission, LLC (Citizens), a subsidiary of Citizens Energy Corporation. For this payment, under the terms of the agreement with Citizens, SDG&E will provide Citizens with access to a segment of the Sunrise Powerlink transmission line known as the Border-East transmission line equal to 50 percent of the transfer capacity of this portion of the line for a period of 30 years. After the 30-year contract term, the transfer capability will revert to SDG&E. SDG&E will amortize deferred revenues from the use of the transfer capability over the 30-year term, and depreciation for 50 percent of the Border-East transmission line segment will be accelerated from an estimated 58-year life to 30 years.

Sempra Natural Gas

Additional consideration for the settlement discussed above in “Legal Proceedings – Resolved Matters – Energy Crisis Litigation Settlement” included an agreement that, for a period of 18 years beginning in 2011, Sempra Natural Gas would sell to the California Utilities, subject to annual CPUC approval, up to 500 million cubic feet (MMcf) per day of regasified LNG from Sempra Mexico’s Energía Costa Azul facility that is not delivered or sold in Mexico at the California border index minus $0.02 per MMBtu.

We discuss reserves at Sempra Energy and SDG&E for wildfire litigation above in “Legal Proceedings – SDG&E – 2007 Wildfire Litigation.”

ENVIRONMENTAL ISSUES

Our operations are subject to federal, state and local environmental laws. We also are subject to regulations related to hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. These laws and regulations require that we investigate and correct the effects of the release or disposal of materials at sites associated with our past and our present operations. These sites include those at which we have been identified as a Potentially Responsible Party (PRP) under the federal Superfund laws and similar state laws.

In addition, we are required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate our businesses. The related costs of environmental monitoring, pollution control equipment, cleanup costs, and emissions fees are significant. Increasing national and international concerns regarding global warming and mercury, carbon dioxide, nitrogen oxide and sulfur dioxide emissions could result in requirements for additional pollution control equipment or significant emissions fees or taxes that could adversely affect Sempra Natural Gas and Sempra Mexico. The California Utilities’ costs to operate their facilities in compliance with these laws and regulations generally have been recovered in customer rates.

We generally capitalize the significant costs we incur to mitigate or prevent future environmental contamination or extend the life, increase the capacity, or improve the safety or efficiency of property used in current operations. The following table shows (in millions) our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:

		Years ended December 31,
		2012		2011		2010
Sempra Energy Consolidated(1)		$	92	$	144	$	76
SDG&E			77		130		64
SoCalGas			12		13		10
(1)	In cases of non-wholly owned affiliates, includes only our share.

Fluctuations at SDG&E and Sempra Energy from 2010 to 2012 were primarily due to mitigation activities on the Sunrise Powerlink project. We have not identified any significant environmental issues outside the United States.

At the California Utilities, 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 us or resolved during the last three years include (1) investigation and remediation of the California Utilities’ manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by the California Utilities at sites for which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS. The requirements for enhanced fish protection and restoration of 150 acres of coastal wetlands for the SONGS mitigation are in process and a 150-acre artificial reef was completed in 2008. The table below shows the status at December 31, 2012, of the California Utilities’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:

		# Sites		# Sites
		Completed(1)		In Process
SDG&E
Manufactured-gas sites			3		―
Third-party waste-disposal sites			2		―
SoCalGas
Manufactured-gas sites			39		3
Third-party waste-disposal sites			4		2
(1)	There may be on-going compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring.

We record environmental liabilities at undiscounted amounts when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and cleanup proceed, we make adjustments as necessary. The following table shows (in millions) our accrued liabilities for environmental matters at December 31, 2012:

				Waste		Former Fossil-		Other
		Manufactured-		Disposal		Fueled Power		Hazardous
		Gas Sites		Sites (PRP)(1)		Plants		Waste Sites		Total
SDG&E(2)(3)		$	―	$	―	$	0.8	$	0.6	$	1.4
SoCalGas(3)			14.2		0.5		―		1.2		15.9
Other			2.4		1.1		―		0.8		4.3
Total Sempra Energy		$	16.6	$	1.6	$	0.8	$	2.6	$	21.6
(1)	Sites for which we have been identified as a Potentially Responsible Party.
(2)	Does not include SDG&E’s liability for SONGS marine mitigation.
(3)	This includes $0.7 million at SDG&E and $15.9 million at SoCalGas related to hazardous waste sites subject to the Hazardous Waste Collaborative mechanism approved by the CPUC in 1994. This mechanism permits California’s IOUs, including the California Utilities, to recover in rates 90 percent of hazardous waste cleanup costs and related third-party litigation costs, and 70 percent of the related insurance-litigation expenses for certain sites. In addition, the California Utilities have the opportunity to retain a percentage of any recoveries from insurance carriers and other third parties to offset the cleanup and associated litigation costs not recovered in rates.

We expect to pay the majority of these accruals over the next three years. In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached an agreement with the California Coastal Commission to mitigate the damage to the marine environment caused by the cooling-water discharge from SONGS. At December 31, 2012, SDG&E’s share of the estimated mitigation costs remaining to be spent through 2050 is $10 million, which is recoverable in rates.

We discuss renewable energy requirements and greenhouse gas regulation in Note 14.

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. This insurance provides $375 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $12.2 billion of secondary financial protection (SFP). If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $375 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. SDG&E’ s contribution would be up to $47 million. This amount is subject to an annual maximum of $7 million, unless a default occurs by any other SONGS owner. If the SFP is insufficient to cover the liability loss, SDG&E could be subject to an additional assessment.

The SONGS owners, including SDG&E, also have $2.75 billion of nuclear property, decontamination, and debris removal insurance. In addition, the SONGS owners have up to $490 million insurance coverage for outage expenses and replacement power costs due to accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks, then $2.8 million per week for up to 110 additional weeks. There is a 12-week waiting period deductible. These insurance coverages are provided through NEIL, a mutual insurance company. Insured members are subject to retrospective premium assessments. SDG&E could be assessed up to $9.7 million.

The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act). The industry aggregate loss limit for property claims arising from non-certified acts of terrorism is $3.24 billion. This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.

We provide additional information about SONGS in Note 14.

CONCENTRATION OF CREDIT RISK

We maintain credit policies and systems to manage our 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. We grant credit to utility customers and counterparties, substantially all of whom are located in our service territory, which covers most of Southern California and a portion of central California for SoCalGas, and all of San Diego County and an adjacent portion of Orange County for SDG&E. We also grant credit to utility customers and counterparties of our other companies providing natural gas or electric services in Mexico; Chile; Peru; southwest Alabama; and Hattiesburg, Mississippi.

When they become operational, projects owned or partially owned by Sempra Natural Gas, Sempra Renewables, Sempra South American Utilities and Sempra Mexico place significant reliance on the ability of their suppliers and customers to perform on long-term agreements and on our ability to enforce contract terms in the event of nonperformance. We consider many factors, including the negotiation of supplier and customer agreements, when we evaluate and approve development projects.

NOTE 16. SEGMENT INFORMATION

We have six separately managed reportable segments, as follows:

1.	SDG&E provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.

2.	SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California.

3.	Sempra South American Utilities operates electric transmission and distribution utilities in Chile and Peru, and owns interests in utilities in Argentina. We are currently pursuing the sale of our interests in the Argentine utilities, which we discuss further in Note 4 above.

Sempra Mexico develops, owns and operates, or holds interests in, natural gas transmission pipelines and propane and ethane systems, a natural gas distribution utility, electric generation facilities (including wind), a terminal for the import of LNG, and marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico.

5.	Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.

Sempra Natural Gas develops, owns and operates, or holds interests in, a natural gas-fired electric generation plant, natural gas pipelines and storage facilities, natural gas distribution utilities and a terminal for the importation and export of LNG and sale of natural gas, all within the United States.

Sempra South American Utilities and Sempra Mexico comprise our Sempra International operating unit. Sempra Renewables and Sempra Natural Gas comprise our Sempra U.S. Gas & Power operating unit.

We evaluate each segment’s performance based on its contribution to Sempra Energy’s reported earnings. The California Utilities operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC. The California Utilities’ operations are based on rates set by the CPUC and the FERC. We describe the accounting policies of all of our segments in Note 1.

During the fourth quarter of 2012, Sempra Mexico initiated a public debt offering process through one of its subsidiaries. We discuss this offering in Note 18. The subsidiary issuing the debt was previously included in Parent and Other. As a result of our anticipated debt issuance, we revised the manner in which we make resource allocation decisions to our Sempra Mexico segment and assess its performance. As a result, we have reclassified certain amounts from Parent and Other, which contains interest and other corporate costs and certain holding company activities, to our Sempra Mexico segment. Losses reclassified from Parent and Other to Sempra Mexico as a result of the restatement were $13 million in 2011 and $22 million in 2010. In accordance with U.S. GAAP, the historical segment disclosures have been restated to be consistent with the current presentation.

Sempra Natural Gas’ sales to the DWR, under a 10-year contract that expired September 30, 2011, comprised 6 percent of our revenues in 2011 and 8 percent of our revenues in 2010.

The following tables show selected information by segment from our Consolidated Statements of Operations and Consolidated Balance Sheets. We provide information about our equity method investments by segment in Note 4. Amounts labeled as “All other” in the following tables consist primarily of parent organizations and the former commodities-marketing businesses of RBS Sempra Commodities, as we discuss in Note 4.

SEGMENT INFORMATION
(Dollars in millions)
	Years ended December 31,
	2012				2011				2010
REVENUES
SDG&E	$	3,694	38	%	$	3,373	34	%	$	3,049	34	%
SoCalGas		3,282	34			3,816	38			3,822	43
Sempra South American Utilities		1,441	15			1,080	11			1	―
Sempra Mexico		605	6			736	7			827	9
Sempra Renewables		68	1			22	―			9	―
Sempra Natural Gas		931	10			1,632	16			2,009	22
Adjustments and eliminations		(2)	―			(2)	―			(5)	―
Intersegment revenues(1)		(372)	(4)			(621)	(6)			(709)	(8)
Total	$	9,647	100	%	$	10,036	100	%	$	9,003	100	%
INTEREST EXPENSE
SDG&E	$	173			$	142			$	136
SoCalGas		68				69				66
Sempra South American Utilities		32				34				8
Sempra Mexico		8				19				26
Sempra Renewables		22				13				7
Sempra Natural Gas		98				80				92
All other		251				233				243
Intercompany eliminations		(159)				(125)				(142)
Total	$	493			$	465			$	436
INTEREST INCOME
SoCalGas	$	―			$	1			$	1
Sempra South American Utilities		15				22				7
Sempra Mexico		2				1				1
Sempra Renewables		6				―				―
Sempra Natural Gas		55				34				36
All other		4				―				3
Intercompany eliminations		(58)				(32)				(32)
Total	$	24			$	26			$	16
DEPRECIATION AND AMORTIZATION
SDG&E	$	490	45	%	$	422	43	%	$	381	44	%
SoCalGas		362	33			331	34			309	36
Sempra South American Utilities		56	5			40	4			―	―
Sempra Mexico		62	6			63	6			62	7
Sempra Renewables		16	1			6	1			2	―
Sempra Natural Gas		93	9			103	11			96	11
All other		11	1			11	1			16	2
Total	$	1,090	100	%	$	976	100	%	$	866	100	%
INCOME TAX EXPENSE (BENEFIT)
SDG&E	$	190			$	237			$	173
SoCalGas		79				143				176
Sempra South American Utilities		78				42				―
Sempra Mexico		73				37				64
Sempra Renewables		(63)				(28)				(24)
Sempra Natural Gas		(157)				72				44
All other		(141)				(109)				(300)
Total	$	59			$	394			$	133

SEGMENT INFORMATION (Continued)
(Dollars in millions)
		At December 31 or for the years ended December 31,
		2012				2011				2010
EARNINGS (LOSSES)
SDG&E(2)		$	484	56	%	$	431	32	%	$	369	52	%
SoCalGas(2)			289	34			287	22			286	40
Sempra South American Utilities			164	19			425	32			69	10
Sempra Mexico			157	18			192	14			116	17
Sempra Renewables			61	7			7	1			9	1
Sempra Natural Gas			(241)	(28)			115	9			71	10
All other			(55)	(6)			(126)	(10)			(211)	(30)
Total		$	859	100	%	$	1,331	100	%	$	709	100	%
ASSETS
SDG&E		$	14,744	40	%	$	13,555	41	%	$	12,077	40	%
SoCalGas			9,071	25			8,475	25			7,986	26
Sempra South American Utilities			3,310	9			2,981	9			796	3
Sempra Mexico			2,591	7			2,502	8			2,616	9
Sempra Renewables			2,439	7			1,210	4			599	2
Sempra Natural Gas			5,145	14			5,738	17			6,132	20
All other			818	2			442	1			1,776	6
Intersegment receivables			(1,619)	(4)			(1,654)	(5)			(1,751)	(6)
Total		$	36,499	100	%	$	33,249	100	%	$	30,231	100	%
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E		$	1,237	42	%	$	1,831	64	%	$	1,210	59	%
SoCalGas			639	22			683	24			503	24
Sempra South American Utilities			183	6			110	4			―	―
Sempra Mexico			45	2			16	―			15	1
Sempra Renewables			717	24			248	9			123	6
Sempra Natural Gas			131	4			157	6			207	10
All other			4	―			4	―			4	―
Intercompany eliminations(3)			―	―			(205)	(7)			―	―
Total		$	2,956	100	%	$	2,844	100	%	$	2,062	100	%
GEOGRAPHIC INFORMATION
Long-lived assets(4):
United States		$	22,698	85	%	$	21,405	85	%	$	19,841	87	%
Mexico			2,219	8			2,189	9			2,219	10
South America			1,790	7			1,542	6			705	3
Total		$	26,707	100	%	$	25,136	100	%	$	22,765	100	%

Revenues:
United States		$	7,711	80	%	$	8,521	85	%	$	8,504	94	%
South America			1,441	15			1,080	11			1	―
Mexico			495	5			435	4			498	6
Total		$	9,647	100	%	$	10,036	100	%	$	9,003	100	%
(1)	Revenues for reportable segments include intersegment revenues of:
	$8 million, $46 million, $108 million and $210 million for 2012, $6 million, $53 million, $300 million and $262 million for 2011, and $6 million, $44 million, $327 million and $332 million for 2010 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2)	After preferred dividends.
(3)	Amount represents elimination of intercompany sale of El Dorado power plant in 2011, as we discuss in Note 14.
(4)	Includes net property, plant and equipment and investments.

NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED)

SEMPRA ENERGY
(In millions, except for per share amounts)
		Quarters ended
		March 31		June 30		September 30		December 31
2012
Revenues		$	2,383	$	2,089	$	2,507	$	2,668
Expenses and other income		$	2,026	$	2,141	$	2,178	$	2,359

Net income		$	251	$	74	$	290	$	305
Earnings attributable to Sempra Energy		$	236	$	62	$	268	$	293

Basic per-share amounts(1):
Net income		$	1.04	$	0.31	$	1.20	$	1.26
Earnings attributable to Sempra Energy		$	0.98	$	0.26	$	1.11	$	1.21
Weighted average common shares outstanding			240.6		241.1		241.7		242.0

Diluted per-share amounts(1):
Net income		$	1.02	$	0.30	$	1.18	$	1.23
Earnings attributable to Sempra Energy		$	0.97	$	0.25	$	1.09	$	1.18
Weighted average common shares outstanding			243.8		246.3		245.8		247.6
2011
Revenues		$	2,434	$	2,422	$	2,576	$	2,604
Expenses and other income		$	2,091	$	1,836	$	2,188	$	2,198

Net income		$	260	$	494	$	319	$	308
Earnings attributable to Sempra Energy		$	254	$	503	$	289	$	285

Basic per-share amounts(1):
Net income		$	1.08	$	2.06	$	1.33	$	1.28
Earnings attributable to Sempra Energy		$	1.06	$	2.10	$	1.21	$	1.19
Weighted average common shares outstanding			240.1		239.4		239.5		239.8

Diluted per-share amounts(1):
Net income		$	1.08	$	2.05	$	1.32	$	1.27
Earnings attributable to Sempra Energy		$	1.05	$	2.09	$	1.20	$	1.18
Weighted average common shares outstanding			241.9		240.8		241.9		241.8
(1)	Earnings per share are computed independently for each of the quarters and therefore may not sum to the total for the year.

Revenues decreased in each of the first three quarters in 2012 compared to the same quarters in 2011, primarily due to the following:

§	decreases at Sempra Natural Gas of $175 million, $240 million and $164 million in the first, second and third quarters of 2012, respectively, compared to 2011 primarily due to decreased power sales resulting from the end of the DWR contract as of September 30, 2011; and

§	decreases at SoCalGas in the first, second and third quarters of 2012 compared to 2011, mainly due to lower natural gas prices, as we discuss below; offset by

§	$338 million in the first quarter of 2012 from Chilquinta Energía and Luz del Sur, which we consolidated starting in April 2011; and

an increase at SDG&E in the third quarter of 2012 compared to the same quarter in 2011 primarily due to higher authorized revenues from electric generation and electric transmission, and an increase in the cost of power purchased to replace power scheduled to be generated and delivered to SDG&E from SONGS.

In the second quarter of 2012, Expenses and Other Income were negatively impacted by $300 million and Net Income and Earnings Attributable to Sempra Energy were negatively impacted by $179 million from an impairment charge to write down our investment in Rockies Express, as we discuss in Note 4. Expenses and Other Income were negatively impacted by $100 million and Net Income and Earnings Attributable to Sempra Energy were negatively impacted by $60 million from an impairment to further write down Rockies Express in the third quarter of 2012.

In the second quarter of 2012, Earnings Attributable to Sempra Energy were impacted by $54 million from an income tax benefit primarily associated with the decision to hold life insurance contracts that are kept in support of certain benefit plans to term.

In the third quarter of 2012 compared to the same quarter in 2011, Net Income and Earnings Attributable to Sempra Energy were favorably impacted by $38 million due to an income tax benefit resulting from a change in the income tax treatment of certain repairs expenditures that are capitalized for financial statement purposes.

In the fourth quarter of 2012 compared to the same quarter in 2011, Net Income and Earnings Attributable to Sempra Energy were favorably impacted by $32 million due to an income tax benefit resulting from a change in the income tax treatment of certain repairs expenditures that are capitalized for financial statement purposes.

In the second quarter of 2011, Expenses and Other Income, Net Income and Earnings Attributable to Sempra Energy were impacted by a $277 million gain (both before and after tax) resulting from the remeasurement of our equity method investments related to Sempra South American Utilities’ acquisition of additional interests in Chilquinta Energía and Luz del Sur on April 6, 2011, as we discuss in Note 3. Earnings Attributable to Sempra Energy were impacted by $11 million in the third quarter of 2011 and $24 million in the fourth quarter of 2011 from higher earnings from the acquisition of the additional interests in Chilquinta Energía and Luz del Sur.

We discuss quarterly fluctuations related to SDG&E and SoCalGas below.

SDG&E
(Dollars in millions)
	Quarters ended
	March 31		June 30		September 30		December 31
2012
Operating revenues	$	834	$	780	$	1,092	$	988
Operating expenses		656		611		822		796
Operating income	$	178	$	169	$	270	$	192

Net income	$	112	$	101	$	188	$	114
Earnings attributable to noncontrolling interests		(6)		(5)		(12)		(3)
Earnings		106		96		176		111
Dividends on preferred stock		(1)		(1)		(2)		(1)
Earnings attributable to common shares	$	105	$	95	$	174	$	110
2011
Operating revenues	$	840	$	697	$	868	$	968
Operating expenses		677		584		658		699
Operating income	$	163	$	113	$	210	$	269

Net income	$	94	$	53	$	136	$	172
(Earnings) losses attributable to noncontrolling interests		(4)		19		(21)		(13)
Earnings		90		72		115		159
Dividends on preferred stock		(1)		(1)		(2)		(1)
Earnings attributable to common shares	$	89	$	71	$	113	$	158

Net Income and Earnings for the first and second quarters of 2012 were favorably impacted by $12 million and $7 million, respectively, related to higher allowance for equity funds used during construction from the Sunrise Powerlink investment.

In the third quarter of 2012 compared to the same quarter in 2011, Revenues for SDG&E increased due to higher authorized revenues from electric generation and electric transmission, and an increase in the cost of power purchased to replace power scheduled to be generated and delivered to SDG&E from SONGS.

In the third quarter of 2012 compared to the same quarter in 2011, Net Income and Earnings for SDG&E were favorably impacted by a $43 million reduction in 2012 income tax expense primarily due to a change in income tax treatment for certain repairs expenditures that are capitalized for financial statement purposes.

In the fourth quarter of 2012 compared to the same quarter in 2011, Net Income and Earnings were negatively impacted by $43 million from lower revenues for incremental wildfire premiums.

SOCALGAS
(Dollars in millions)
	Quarters ended
	March 31		June 30		September 30		December 31
2012
Operating revenues	$	880	$	720	$	728	$	954
Operating expenses		761		625		609		867
Operating income	$	119	$	95	$	119	$	87

Net income	$	66	$	54	$	71	$	99
Dividends on preferred stock		―		(1)		―		―
Earnings attributable to common shares	$	66	$	53	$	71	$	99
2011
Operating revenues	$	1,056	$	876	$	844	$	1,040
Operating expenses		937		773		709		911
Operating income	$	119	$	103	$	135	$	129

Net income	$	68	$	60	$	81	$	79
Dividends on preferred stock		―		(1)		―		―
Earnings attributable to common shares	$	68	$	59	$	81	$	79

SoCalGas’ Operating Revenues and Operating Expenses for the first, second and third quarters of 2012 decreased by $163 million, $147 million and $83 million, respectively, compared to the same periods in 2011 due to lower natural gas prices. In the fourth quarter of 2012, Operating Revenues and Operating Expenses decreased by $53 million from lower natural gas volumes.

In the fourth quarter of 2012 compared to the same quarter in 2011, SoCalGas’ Net Income and Earnings were favorably impacted by $45 million from a lower effective tax rate primarily due to a change in the income tax treatment of certain repairs expenditures that are capitalized for financial statement purposes.

NOTE 18. SUBSEQUENT EVENT

Sempra Mexico Debt Offering

On February 14, 2013, Sempra Mexico publicly offered and sold $306 million (U.S. dollar equivalent) of 6.3-percent notes maturing in 2023 with a U.S. dollar equivalent rate of 4.12 percent after entering into a cross-currency swap for U.S. dollars at the time of issuance. Sempra Mexico also publicly offered and sold $102 million (U.S. dollar equivalent) of variable rate notes, maturing in 2018, which after a floating-to-fixed cross-currency swap for U.S. dollars at the time of issuance, carry a U.S. dollar equivalent rate of 2.66 percent. The notes and related interest are denominated in Mexican Pesos, and the interest rate for the variable rate notes is based on the Equilibrium Interbank Interest Rate plus 30 basis points. Sempra Mexico will use the proceeds of the notes for capital projects, including the development of natural gas pipelines, and repayment of intercompany debt.

GLOSSARY


2010 Tax Act	Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010	CPUC	California Public Utilities Commission
2012 Tax Act	American Taxpayer Relief Act of 2012	CRE	Comisión Reguladora de Energía (Energy Regulatory Commission) (Mexico)
AB 32	California Assembly Bill 32	CRRs	Congestion revenue rights
AFUDC	Allowance for funds used during construction	DOE	U.S. Department of Energy
AIT	Augmented Inspection Team	DRA	Division of Ratepayer Advocates
AMI	Advanced Metering Infrastructure	DWR	California Department of Water Resources
AOCI	Accumulated other comprehensive income (loss)	EBITDA	Earnings before interest, taxes, depreciation and amortization
AROs	Asset retirement obligations	Ecogas	Ecogas Mexico, S de RL de CV
ARTA	American Recovery and Reinvestment Tax Act of 2009	Edison	Southern California Edison Company
ASC	Accounting Standards Codification	EGWP	Employer Group Waiver Plan
ASU	Accounting Standards Update	EIA	Environmental impact authorization
Bay Gas	Bay Gas Storage Company, Ltd.	EIR	Environmental impact report
Bcf	Billion cubic feet	Elk Hills	Elk Hills Power
Black-Scholes Model	Black-Scholes option-pricing model	EMA	Energy Management Agreement
BLM	Bureau of Land Management	EPA	Environmental Protection Agency
CAL	Confirmatory Action Letter	EPS	Earnings per common share
Cal Fire	California Department of Forestry and Fire Protection	ERRP	Early Retiree Reinsurance Program
California Utilities	San Diego Gas & Electric Company and Southern California Gas Company	ESOP	Employee stock ownership plan
CARB	California Air Resources Board	FERC	Federal Energy Regulatory Commission
CARE	California alternate rates for energy	Flat Ridge 2	Flat Ridge 2 Wind Farm
CBA	Collective bargaining agreement	Fowler Ridge 2	Fowler Ridge 2 Wind Farm
CEC	California Energy Commission	FTA	Free Trade Agreement
Cedar Creek 2	Cedar Creek 2 Wind Farm	FTC	Federal Trade Commission
CFE	Comisión Federal de Electricidad (Federal Electricity Commission) (Mexico)	Gazprom	Gazprom Marketing & Trading Mexico
CFTC	U.S. Commodity Futures Trading Commission	GCIM	Gas Cost Incentive Mechanism
Chilquinta Energ í a	Chilquinta Energ í a S.A.	GHG	Greenhouse Gas
Citizens	Citizens Sunrise Transmission, LLC	GRC	General Rate Case
CMS 2	Copper Mountain Solar 2	HMRC	United Kingdom's Revenue and Customs Department
CMS 3	Copper Mountain Solar 3	ICSID	International Center for the Settlement of Investment Disputes
CNE	Comisión Nacional de Energía (National Energy Commission) (Chile)	IFRS	International Financial Reporting Standards
Congress	United States Congress	IOUs	Investor-owned utilities
Cox	Cox Communications	IRC	Internal Revenue Code
CPCN	Certificate of Public Convenience and Necessity	IRS	Internal Revenue Service
CPSD	Consumer Protection and Safety Division	ISFSI	Independent spent fuel storage installation

GLOSSARY (CONTINUED)


ISO	Independent System Operator	OTC	Over-the-counter
ITC	Investment tax credits	PBOP	Other postretirement benefit plans
JP Morgan	J.P. Morgan Chase & Co.	PBOP plan trusts	Postretirement benefit plan trusts
J.P. Morgan Ventures	J.P. Morgan Ventures Energy Corporation	PCBs	Polychlorinated biphenyls
KMI	Kinder Morgan, Inc.	PE	Pacific Enterprises
KMP	Kinder Morgan Energy Partners, L.P.	PEMEX	Petroleos Mexicanos (Mexican state-owned oil company)
kV	Kilovolt	PG&E	Pacific Gas and Electric Company
Liberty	Liberty Gas Storage, LLC	PPACA	Patient Protection and Affordable Care Act
LIFO	Last-in first-out inventory	PRP	Potentially Responsible Party
LNG	Liquefied natural gas	PSEP	Pipeline Safety Enhancement Plan
Luz del Sur	Luz del Sur S.A.A.	RBS	The Royal Bank of Scotland plc
Luzlinares	Luzlinares S.A.	RBS SEE	RBS Sempra Energy Europe
MBFC	Mississippi Business Finance Corporation	RBS Sempra Commodities	RBS Sempra Commodities LLP
Mcf	Thousand cubic feet	RDS	Retiree Drug Subsidy
Mehoopany	Mehoopany Wind Farm	RECs	Renewable energy certificates
MHI	Mitsubishi Heavy Industries	REX	Rockies Express Pipeline
Mississippi Hub	Mississippi Hub, LLC	Rockies Express	Rockies Express Pipeline LLC
MMBtu	Million British thermal units (of natural gas)	ROE	Return on equity
MMcf	Million cubic feet	ROR	Rate of return
Mobile Gas	Mobile Gas Service Corporation	RPS	Renewables Portfolio Standard
Mtpa	Million tonnes per annum	RSAs	Restricted stock awards
MW	Megawatt	RSUs	Restricted stock units
MWh	Megawatt hour	SAESA	Sociedad Austral de Electricidad Anonima
NEIL	Nuclear Electric Insurance Limited	SB	Senate Bill
NERC	North American Electric Reliability Corporation	SDG&E	San Diego Gas & Electric Company
NOLs	Net operating losses	SEMARNAT	Mexican environmental protection agency
NRC	Nuclear Regulatory Commission	SFP	Secondary Financial Protection
OCI	Other comprehensive income	Shell	Shell México Gas Natural
OII	Order Instituting Investigation	SoCalGas	Southern California Gas Company
OMB	Office of Management and Budget	SONGS	San Onofre Nuclear Generating Station
OMEC	Otay Mesa Energy Center	SPPR Group	Southwest Public Power Resources Group
OMEC LLC	Otay Mesa Energy Center LLC	SRP	Salt River Project Agricultural Improvement and Power District
OSINERGMIN	Organismo Supervisor de la Inversión en Energía y Minería (Energy and Mining Investment Supervisory Body) (Peru)	S&P	Standard & Poor’s
Otay Mesa VIE	Otay Mesa Energy Center LLC	Tallgrass	Tallgrass Energy Partners, L.P.

GLOSSARY (CONTINUED)


Tangguh PSC	Tangguh PSC Contractors
TCAP	Triennial Cost Allocation Proceeding
TDM	Termoeléctrica de Mexicali
Tecnored	Tecnored S.A.
Tecsur	Tecsur S.A.
The Committee	Pension and Benefits Investment Committee
The Plan	Sempra Energy 2008 Long Term Incentive Plan for EnergySouth, Inc. Employees and Other Eligible Individuals
The Prior Plan	2008 Incentive Plan of EnergySouth, Inc.
TIMP	Transmission Integrity Management Program
TO4	Electric Transmission Formula Rate
Trust	ESOP trust
TURN	The Utility Reform Network
U.S. GAAP	Accounting principles generally accepted in the United States
USFS	United States Forest Service
VaR	Value at Risk
VAT	Value-added-tax
VEBA	Voluntary Employee Beneficiary Association
VIE	Variable interest entity
VNR	Valor Nuevo de Reemplazo (New replacement value) (Chile and Peru)
Williams	Williams Midstream Natural Gas Liquids, Inc.
Willmut Gas	Willmut Gas Company